Schlumberger Spe Papers

Nov-09 NOTES: The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetro The papers relating to reservoir engineering have been catergorised for inclusion on the

reservoirengineering.org.uk website

The affiiations searched were;

BP Shell Chevron ConocoPhillips Marathon Total Schlumberger Imperial College, London Heriot Watt University, Edinburgh (Anywhere in Article) Total

Total number of papers published post 2005

Total No Papers 551 575 482 191 55 255 1130 95 235

Reservoir Engineering Related 175 279 238 68 37 129 563 53 175

3569

1717

10,000 35% of papers published categorised

Organisation SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

Paper Source No. SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE IPTC

115707 116422 116424 121970 108540 115247 98617 108528 102968 112259 98945 112365 119506 113843 107445 99720 98142 117622 112021 123773 103329 104755 107101 110968 111512 117066 126063 103900 109591 115485 99994 11556 110833 103242 100739 116501 121414 112977 102240 106375 11239 109539 123423 100393 108097 102571 110511 11582

Chapter CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 Corporate Process Drilling Drilling Drilling EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR Flow Assurance Flow Assurance Flow Assurance Flow Assurance Flow Assurance Flow Assurance Flow Assurance Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE IPTC SPE SPE SPE SPE

122562 99386 109684 123430 89704 111911 108494 81481 120988 114702 115429 100937 11268 116098 118893 97886 101219 117164 110364 115499 101084 100865 11573 115622 12886 120468 120947 114058 122844 112434 122845 98220 114255 107993 100112 101401 100516 108994 126075 105069 117233 110401 118434 11395 97889 117682 12536 117689 103841 120423 102460

Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Giant Field Giant Field Giant Field Giant Field Giant Field Giant Field Giant Field Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil


SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE SPE SPE SPE IPTC SPE

104163 104520 116746 105327 104046 117285 117562 107636 115609 103997 116243 121755 121759 106054 107108 120817 106712 98318 93805 107277 100182 121695 122197 113487 108075 120161 117570 120749 125237 126160 102956 119481 119140 119927 103865 123296 103250 90630 105681 90690 120424 11528 112303 11545 109565 115825 103987 110067 102569 12328 121223

Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT Lab Testing Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs


SPE SPE SPE IPTC IPTC IPTC SPE SPE SPE IPTC IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE

101257 105262 101129 11537 11765 12502 106100 101897 116328 11622 12253 121945 108566 108925 105014 120407 97224 100351 101718 116591 119690 118380 110277 102888 110223 102256 110752 109848 102572 121923 120443 101343 101286 101913 115836 101126 102435 122585 109972 126044 116092 126094 95841 101721 102588 104013 105427 118895 103284 105456 102562

Low Permeability Reservoirs Low Permeability Reservoirs Minor Reservoirs Minor Reservoirs Project Management Project Management Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description


SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE

116068 117073 110304 112385 107192 115822 110301 110803 89177 107241 120813 101176 93974 118152 100740 109683 11488 104018 11350 120691 100738 102456 102413 101556 101151 12029 104041 12225 126064 120803 99317 123711 122339 122421 102557 11594 100984 101491 121489 117633 112223 99469 109260 112209 102439 116218 120664 116528 99338 107702 103028

Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Development Reservoir Development Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management


SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE

108693 108737 98198 93444 110927 122338 105797 102084 99288 11718 101779 120433 99882 12665 102148 122768 119172 119165 110412 105700 112923 120050 126095 110219 119732 111457 99445 120552 102111 117445 99575 107853 107356 104015 106251 119352 103188 121612 112926 96260 123087 101138 107907 11205 66365 118709 101013 118979 117370 101674 95498

Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling


SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE IPTC IPTC SPE SPE SPE SPE SPE SPE IPTC SPE

115881 102549 107471 119132 121392 93324 100131 119605 121275 121488 106181 107511 122186 95750 100403 118909 96571 118850 105041 116063 102715 99240 11772 122478 100024 115712 100607 101310 101140 114027 117963 107119 100992 103589 105362 12108 115504 126158 93057 112429 110813 11262 11745 102159 104017 104021 115816 116914 90024 11971 122604

Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance SPE Forum State of the Nation State of the Nation State of the Nation Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence


SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE IPTC SPE

112221 11171 115976 121696 119361 94708 101886 110634 110064 116474 116286 102351 103757 11433 105166 114337 117892 111174 120558 102309 113600 107985 103232 103327 114974 103202 122934 117704 103514 119636 12368 126066 110103 106094 102544 12364 112476 112862 101720 102583 100834 110240 11630 84219 120744 126070 126061 102653 96722 12668 106050

Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability


SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE

107979 112438 117061 119825 122307 103822 112435 125336 122514 108126 107604 112171 99419 118292 112442 114768 121204 121415 113562 101722 119300 115556 119635 107730 100572 105657 98338 100524 102677 119586 11150 11347 102326 110068 107662 102788 100556 102167 109909 109969 121888 98188 100321 106225 102469 106317 110696 106264 106043 102570 102405

Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability


SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE IPTC SPE SPE

98746 122018 12183 119351 104202 106854 113553 114961 112077 120800 123008 120799 110960 113918 103617 104629 116370 120049 105022 106400 102241 112488 104099 120508 101278 112432 113698 111538 119639 121931 121964 110978 112491 105541 117518 105542 128606 112456 105758 107297 121093 121834 121912 12448 98151 12581 123495 112050 12385 107440 102185

Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability


SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE

112904 100944 104239 92715 102242 98315 101087 90383 106272 107978 115525 115528 98221 98357 105127 106321 106442 112419 116601 116775 109911 104610 106444 115558 104627 102681 107966 111431 98055 105367 112176 101420 109860 105134 110576 116969 104059 120515 123115 102575 123555 114594 109279 113650 118148 110873 116003 114127 115478 90992 101475

Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE

103223 105271 107967 103040 102106

Well Testing Well Testing Well Testing Well Testing Well Testing

Section Integrity Integrity Integrity Management Modelling - Injection Reservoir Description Storage Storage Workshop Paper PRODML ERD Field Re-development Horizontal Well CO2 Injection CO2 Source Heterogeneity Multilateral Sidetracks SAGD Optimisation Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Asphaltene Deposition Lab Testing Lab Testing Modelling - Integrated Asset Modelling - Well/Network Wax/Asphaltenes Waxy Crudes CO2 Detection CO2 Detection Core Testing Correlations Correlations Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Hydrogen Sulphide Detection

Subject

Modelling - Integrated Compositional Field Study

Capture/Storage Production Data Standards World Record Dumbarton Field Longest in World

Oligocene Vicksburg Formation Gas Condensate Easterm Venezuela Gas Shut-off Undeveloped Reservoirs Water Shut-off Water Shut-off Water Shut-off Water Shut-off Water Shut-off Water Shut-off Water Shut-off Risk Assurance Horizontal Pipes Inclined Pipes Production Alllocation San Manuel Asset Risk Reduction Deepwater WFT WFT Asphaltene Deposition Gas Condensate Gas Condensate Asphaltenes Case Study Continuous Log Neural Network Modelling OBM Clean-up Reservoir Architecture Reservoir management Reservoir management WFT

Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Methane Detection Modelling - Asphaltene Precipitation Modelling - Compositional Modelling - EOS Modelling - Fluid Analysis Modelling - Neural - Network Optical Fluid Analysis Phase Envelope Construction Production Chemistry PVT Analysis PVT Data PVT Data Sampling Sampling Sampling Sampling Sampling Acid Treatments Chelating Technology Core Testing Halite Inhibition Injection Water Quality Modelling - Formation Damage Perforation Induced Performation Damage Scale Control Scale Management Scale Management Scale Management Sulfate Stripping Modelling - History Matching Modelling - Streamline Modelling - Streamline Reservoir Performance Surveillence Surveillence Waterflood Management Artificial Lift Artificial Lift EOR/IOR EOR/IOR Minor Reservoirs Reservoir Description Reservoir Description

Downhole Fluid Analysis Gas Condensate Integrated Data Integrated Data Optical Spectroscopy Pressure Measurements Pressure/insitu Fluid measurements Downhole Measurement Development Impact Downhole Fluid Analysis Insitu PVT Variations Fluid comparison Algorithm Downhole Fluid Analysis Downhole Fluid Samples Non-Isothermal Heavy-oil Onsite Downhole Analysis WFT Carbonate Reservoir Contamination Detection Gas Condensate Multiphase Multiphase Meter Deep Wells Algyo Field Acid Treatment Horizontal Well Injectivitvity Naphthenate Induced Removal Stimulated Wells Case Study Intelligent Well Strontium Sulfate Gyda Field Identifying Flow Regions Fracture Characterisation Sabiriyah field Modelling - Heterogeneity Automation Waterflood Surveillence Cavity Pumps Downhole Heaters Assisted Gravity drainage SAG Development Carbonate Reservoir WFT

Reservoir Development Reservoir Development Stimulation Surveillence Thermal Recovery Well Testing Well Testing Acid Treatments Data Acquisition Exploration Process Fluid Description Fracturing Fluid Fracturing Fluid Lab Testing Perforation Methods Permanent DH Pressure Monitoring Propped Fracturing Stimulation Stimulation Surfactant Fracturing Water Block Prevention Water PH measurement Asphatene Precipitation Completion Completion/Stimulation Development Optimisation Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracturing Fracturing Horizontal Well Stimulation Horizontal Well Stimulation Horizontal Well Stimulation Horizontal Wells Modelling - Reservoir Performance Modelling - Single well Performance Modelling - Streamline Production Optimisation Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Development Reservoir Management Reservoir Performance Surveillence Surveillence

Horizontal wells Steam Injection Chemical Treatment Production Logging Development Multiphase Meter Multiphase Meter Gas Condensate India Insitu PVT Variations

Acid Fracturing Coiled-Tubing-Conveyed Gas Well Vietnam Acid treatment

Laboratory Determination Capillary Flow Horizontal wells Horizontal wells Challenges Case study Impact of Pressure Depletion Microseismic Data Hybrid Fracturing Fiber Assisted Acid treatment Case Study Propped Fracturing Carbonate Reservoir Production Forecasting Optimised Completions Fluvial Reservoir Heterogeneity Formation Evaluation Fracture Characterisation Integrated Study Naturally Fractured Reservoirs Pressure Measurements Pressure Measurements WFT Heterogeneity Horizontal wells Reservoir Architecture Formation Evaluation Logging

Transition Zones Well Intervention Development Strategy Stimulation Decision Making Decision Making Borehole Image Interpretation Capillary Pressure Deep Electromagnetic Data Depositional Environment Depositional Environment Depositional Environment Downhole Fluid Analysis Downhole Fluid Analysis Flow Unit Characterisation Flow Unit Characterisation Formation Evaluation Formation Evaluation Formation Evaluation Formation Evaluation Formation Evaluation Formation Evaluation Formation Evaluation - Enhanced description Formation Evaluation - Heterogeneity Formation Evaluation - Heterogeneity Formation Evaluation - Heterogeneity Formation Evaluation - Heterogeneity Formation Evaluation - Heterogeneity Formation Evaluation - Horizontal Injectors Formation Evaluation - Integrated Well Data Formation Evaluation - Unconsolidated Geomechanical Geo-Modelling Geostatistics Geostatistics Heterogeneity Heterogeneity LWD Interpretation LWD Interpretation LWD Interpretation Mechanism - Stress Orientation Modelling - Geomechanical Properties Modelling - Near Wellbore Stress Multi-Layered Reservoir Multi-Layered Reservoir Multi-Layered Reservoir Natural Fracture Characterisation Natural Fracture Characterisation Natural Fracture Characterisation Natural Fracture/Fault Characterisation Naturally Fractured Reservoirs

Carbonate Reservoir Water Shut-off Heterogeneity Mini Fracturing

Case Study Carbonate Reservoir Heterogeneity Borehole Images Borehole Images Integrated Well Data Reservoir Characterisation Reservoir Characterisation Carbonate Reservoir Deltaic Reservoir LWD LWD LWD vs Gamma Ray Shaly Sand Analysis Shaly Sand Analysis Workflow Carbonate and Clastic Reservoirs Carbonate Reservoir Deepwater Perforation Selection Turbidites LWD Modelling Cambrian Reservoirs Deepwater Carbonate Reservoirs Channel Deposition Kharaib Field Formation Evaluation Methods NMR Mediterranean Reservoirs

Horizontal Wells Prediction Algorithm PLT Interpretation PLT Interpretation PLT Interpretation Borehole Seismic Formation Evaluation Integrated Study Borehole Images Maloichskoe

Near Wellbore Flow Properties Near Wellbore Flow Properties Near Wellbore Flow Properties Near Wellbore Stress NMR Interpretation NMR Interpretation NMR Interpretation NMR Interpretation NMR Logging Oil Interval Detection PLT Interpretation Porosity/Permeability Analysis Productivity Interpretation Reservoir Architecture Reservoir Architecture Reservoir Architecture Reservoir Connectivity Reservoir Properties Residual Oil Saturation WFT WFT WFT WFT Integrated Study Uncertainty Management Artificial Lift EOR/IOR Gas Lift Optimisation Heterogeneity Heterogeneity Low Pressure Gas Methodology Modelling - Coupled Surface/Reservoir Model Modelling - Coupled Surface/Reservoir Model Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Produced Water Management Produced Water Management Production Optimisation Production Optimisation Productivity Improvement Reserves Evaluation Value of Information

Downhole Monitoring Downhole Monitoring Integrated Well Data Fractured Clastics Optimised WFT Sampling

Formation Evalustion Horizontal Wells Carbonate Reservoirs UBD Fracture Fairways Integrated Well Data Integrated Well Data Downhole Fluid Analysis PLT Interpretation Pulsed Neutron Decay Deltaic Reservoir Optimised Sampling Stress/Permeability Measurment Supercharging Betty Field Heterogeneity Selection Criteria Mature Fields Surveillence Well Placement Well Placement Optimisation Wellsite Compression Life of Field Production Optimisation SMART wells Development Optimisation Gas Lift Optimisation Production Optimisation Production Optimisation Steam Injection Uncertainty Management Workflow

XJG Fields Gas Lift Optimisation Mature Fields Integrated Study Lower Vicksburg Sands Framework

Well Placement Optimisation Well Placement Optimisation Well Placement Optimisation Well Placement Optimisation Well Placement Optimisation Well Placement Optimisation Adjoint Based Simulation Analytical Model Analytical Reservoir Model Analytical Well Performance Assisted HM Assisted HM Assisted HM Assisted HM Assisted HM Compaction Modelling Complex Physics Modelling Complex Physics Modelling Complex Well Modelling Complex Well Modelling Complex Well Modelling Complex Well Modelling Coupled Reservoir/Geomechanical Model Coupled Thermal/Composional Model Decline Curve analysis Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Spacing pPediction Gridding Heterogeneity Modelling Inflow Performance Injectivity Productivity Index Material Balance Material Balance Mature Field History Match Mechanism Modelling - Experimental Design Modelling data Multipoint Flux Approximation Naturally Fractured Reservoirs Naturally Fractured Reservoirs Naturally Fractured Reservoirs

LWD Interpretation LWD Interpretation Production Potential maps Real Time Pressure Data Selection Criteria Thin Oil Rim Well Placement Optimisation SAGD Single Layer Multilayered Reservoirs Adjoint Based Simulation Adjoint Based Simulation Artificial Intelligence Experimental Design Method Face Recognition Technique Analytical Heavy Oil Phase-Component Partitioning Thin Oil Rim

3 Phase Model 3 Phase Clean-up Model Fractured Horizontal Wells Gas Condensate Geometry Horizontal Wells Non-Darcy/Perforation Flow Probablistic Productivity Index Transverse Fractures Neural Networks Optimisation Temperation Prediction Complex Mature Reservoirs Uncertainty Management Diffusion and Convection Experience Capillary data Upscaling Dual Porosity Model Applicability Gas Oil Displacement History Matching

Naturally Fractured Reservoirs Naturally Fractured Reservoirs Naturally Fractured Reservoirs Naturally Fractured Reservoirs Numerical - Conceptional Prediction Uncertainty Proxy Modeling Scale Modelling Shared Earth Modelling Steamflood Modelling Streamline Streamline Type Curve Forecasting Uncertainty Management Uncertainty Management Wellbore Flow Wellstream Composition Wellstream Composition Mechanism Mechanism Mechanism Mechanism - Transition zone flow UBD Wellbore Stability Smarter Fields EOR Techniques Province Comparison Well Intervention By-passed Oil Detection By-passed Oil Detection By-passed Oil Detection Complex Wells Complex Wells Complex Wells Condensate Banking Detection Data Acquisition Data Acquisition Downhole Monitoring Downhole PH Measurement Formation Damage Detection Fracture Diagnostics Fracture Diagnostics Gas Entry Detection Inflow Performance Inflow Profiling Inflow Profiling Inflow Profiling Inflow Profiling Multiphase Metering Naturally Fracture Detection Pemanent Downhole Gauge

Multiple Reservoirs Streamlines Streamlines Streamlines Production Optimisation PUNQ-S3 Problem Production Optimisation Streamlines PEBI Grid Adaptive Mesh Refinement Multicomponent Well Placement Ensemble based Application Ranking GeoModels Annuus and Tubing Flow Black-Oil Delumping Black-Oil Delumping Effect of Wettability Fines Migration Non-Dacy Flow Carbonate Reservoirs Margham Field Stress Patterns Change Management Russia UKCS vs Alaska North Slope Zonal Isolation Mature Fields Pulse Neutron Logs Downhole Flowrates Inflow Profiling PLT Multiphase Flowmeters Challenging Conditions Challenging Conditions Multiple Reservoirs Optical Spectroscopy Microseismic Monitoring Temperature Log Analysis SAGD - Horizontal Wells Pulse Neutron Logs Pulse Neutron Logs Temperature Data Tracers Downhole Feasibility

Performance Prediction PLT Interpretation Pressure Monitoring Production Monitoring Real-Time Monitoring Real-Time Monitoring Reservoir Pressure/GOR Monitoring SAGD Monitoring Sand Production Sandface Monitoring Theif Zone Dectection Value of Information Virtual Metering Water Entry Detection Water Entry Detection Water Entry Detection Water Front Tracking Waterflood Waterflood Coal Coalbed Methane Coalbed Methane Completion Strategies Fracture Design Fracture Design Reservoir Description Reservoir Modelling SAG State of the Nation Stimulation Acid Treatments Artificial Lift Artificial Lift Artificial Lift Completion Optimisation Completion Optimisation Completion Optimisation Completion Optimisation Completion Optimisation Completion Optimisation Complex Wells Complex Wells Complex Wells Complex Wells Complex Wells Complex Wells Complex Wells ESP ESP Fracture Design Fracture Design

Assessment Challenging Conditions Greater Burgan Field Temperature Data Case Study WFT Tempreture Data Tiltmeters Temperature Sensors Completion Design Borehole Images Opportunistic/Guaranteed Horizontal wells Horizontal wells Resistivity Measurement LWD Electromagnetic Surveys Electromagnetic Surveys Perforation Testing Completion Optimisation Indirect Fracturing Horizontal Wells Heterogeneity Horizontal Well Characterisation Well Optimisation Petroleum Engineering Advances Refracturing Production Optimisation ESP's SAGD ESP Staircase Lifting Horizontal Wells Manati Gas Filed Multilayered Reservoirs Near Wellbore Stress

Carbonate Reservoir Complex Reservoirs Downhole Control Valves Downhole Control Valves Downhole Control Valves Intervention Production Performance Perforation Methods Performance Analysis Acid Fracturing Candidate selection

Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics

Fiber Assisted Fiber Assisted Fiber Assisted Fiber Assisted Flowback Aids Formation Modulus Contrast Fracture Fluid Fracture Fluids Optimisation Fracture Geometry Fracture Propagation Height Control Horizontal Well Application Mature Fields Multifrac Horizontal Wells Multistage Multistage Horizontal Wells Multistage Horizontal Wells Multistage Horizontal Wells Optimisation Performance Criteria Proppant Transport Samara Area Reservoirs Simultaneous Fracturing Sliding Sleeve Application Sliding Sleeve Applocation Soft Formations Surfactant Fracturing Surfactant Fracturing Surfactant Fracturing Surfactant Fracturing Acid Fracturing Clean-up Completion Optimisation Damage Analysis Deviation Surveys Fiber Assisted Fracture Conductivity Fracture Geometry Fracture Geometry Fracture Geometry Gas Condensate Gas Condensate High Permeability Formations Long-Term Rate Effects Low-Conductivity Microseismic Monitoring Proppant Flowback Refracture Reseridual Saturation Sonic Anisotropy

Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Dignostics Gas Lift Systems Gas Production Horizontal Well Horizontal Well Horizontal Well Intelligent Well Intelligent Well Intelligent Well Intelligent Well Intelligent Well Lab Testing - Fracturing Modelling - Flow Assurance Modelling - Well Productivity Modellling - Sanding Prediction Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Production Optimisation Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control

State of the Nation Water Injector Fracturing Fracture Geometry Theory High rate wells Novel Open hole Novel Open hole OBM Effect Complex Wells Downhole Control Valves ESP's Production Optimisation Uncertainty Management Heterogeneity Productivity Improvement Heterogeneity Carboate Reservoir Case study Coiled Tubing Dynamic UB Negative Skin Factors Orientation Productivity Improvement Skin Variation Quantified UnderBalanced

SMART Completions Albacora Field Completion Optimisation Complex Wells Failure Failure Mitigation Failures Gravel Pack Gravel Pack Gravel Pack Gravel Pack Gravel Pack Gravel Pack Modelling Gravel Packing Optimisation Perforate/Gravel Pack Perforation Method Screen Technology Screenless Completions Screens

Sand Management Sand Production Sand Production Sand Production Sand Production Sand Production Sand Production State of the Nation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Optimisation Water Blocking Water Control/Stimulation Zonal Isolation Analysis - Closed Chamber Tests Analysis - Horizontal Wells Analysis - Multi-Fractured Wells Analysis - Multilayer Reservoir Analysis - Naturally Fractured Reservoir Analysis - Radius of Investigation Analysis - Real Time Evaluation Deconvolution Exploration Wells Fracture Diagnostics Mini-DST MiniDST Interpretation Multiphase Metering Multiphase Metering Multiphase Metering Multiphase Metering Multiphase Metering Multiphase Metering Multiphase Metering

Sarir Field Accurate Pediction Case Study Effect of water-Cut Mature Fields Wellbore Stability Wellbore Stability Acid treatment Acid Fracturing Acid Fracturing Acid Fracturing Acid Fracturing Acid treatment Acid Treatment Acid Treatment Acid Treatment Acid Treatment Acid Treatment Acid Treatment Acid Treatment Chelating Agent Application Combined Treatments Diversion Techniques Foam Fracturing Heterogeneity Restimulation Surfactant Fracturing Surfactant Fracturing Mature Fields Gas Reservoirs Sufactant Treatment CBL Interpretation Carbonate Reservoir Stacked Reservoirs Layer Properties Partial Penetration Reserve Estimation

Design and Interpretation Image Log Deepwater Gas Challenging Conditions Gas Condensate Heavy Oil Reliability Validation

Multiphase Metering Numerical Modelling Production Analysis State of the Nation Streaming Potential Measurement

Full Field Simulations Integral Derivative Function Advances in Interpretation and Measurement Technology Application

Title Assessing Long-Term CO2 Containment Performance: Cement Evaluation in Otway CRC-1 Stress Estimation at the Otway CO2 Storage Site, Australia CO2 Storage - Managing the Risk Associated With Well Leakage over Long Timescales Optimizing CO2 Injection and Storage: A New Approach Using Integrated Asset Modeling Simulations for CO2 Injection Projects With Compositional Simulator Lithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Rese CO2 Sequestration - A Safe Transition Technology CO2 Storage Geomechanics for Performance and Risk Management Critical Issues in CO2 Capture and Storage: Findings of the SPE Advanced Technology Workshop ( Production Data Standards: The PRODML Business Case and Evolution World-Record ERD Well Drilled From a Floating Installation in the North Sea Dumbarton Field, UKCS: Rapid Redevelopment of a Complex, Mature North Sea Asset Using New Ro How Continuous Improvement Lead to the Longest Horizontal Well in the World EOR Potential of the Michigan Silurian Reefs Using CO2 Quebrache--A Natural CO2 Reservoir: A New Source for EOR Projects in Mexico Oligocene Vicksburg Thin-Bed Production Optimization Derived From Oil-Based Mud Imaging: A Ca Simulation Study of Re-Entry Drilling for Gas/Condensate Reservoir Development Applicability and Optimization of SAGD in Eastern Venezuela Reservoirs Challenging Chemical Gas Shut Off In a Fractured Carbonate Reservoirâ€”Case Studies Recovery of Bypassed Reserves Above Top Packer Using Innovative Cement Packer and Through Tu Production Improvement Water Shut-Off for White Tiger Field Case Study in Water Shutoff Fluid Placement Using Straddled Through-Tubing Inflatable-Packers Te Water-Shutoff Treatment in Wells With Single-String Multizone Completion Intervals (Brownfields) Successful Water Shut-off in Open Hole Horizontal Well Using Inflatables Innovative Water-Shutoff Solution Enhances Oil Recovery From a West Venezuela Sandstone Reser Horizontal Water Shut-Off for Better Production Optimization and Reservoir Sweep Efficiency (Case Successful Utilization of Fiber Optic Telemetry Enabled Coiled Tubing for Water Shut-off on a Horizon A Holistic Approach to Production Assurance Characterization of Oil/Water Flows in Horizontal Pipes Characterization of Oil/Water Flows in Inclined Pipes A Rigorous Well Model To Optimize Production From Intelligent Wells and Establish the Back-Allocat Integration of Production and Process Facility Models in a Single Simulation Tool - PEMEX E&P San Impact of Flow Assurance in the Development of a Deepwater Prospect Flow-Assurance Aspects of Subsea Systems Design for Production of Waxy Crude Oils Quantification of Carbon Dioxide Using Downhole Wireline Formation Tester Measurements First Field Application of Downhole CO2 Measurement in Asia Pacific Core Flood Investigation Into Asphaltene Deposition Tendencies in the Marrat Reservoir, South East Tools To Manage Gas/Condensate Reservoirs; Novel Fluid-Property Correlations on the Basis ofï¿½ New Modified Black-Oil Correlations for Gas Condensate and Volatile Oil Fluids Asphaltene Gravitational Gradient in a Deepwater Reservoir as Determined by Downhole Fluid Analy Reservoir Fluid Characterization Using Downhole Fluid Analysis in Northern Kalimantan, Indonesia Continuous Downhole Fluid Log Powered by an Integrated Approach Reveals Reservoir Fluid Complex Application of Artificial Neural Networks to Downhole Fluid Analysis Compositional Modeling of Oil-Based Mud-Filtrate Cleanup During Wireline Formation Tester Sampli New Downhole Fluid Analysis (DFA) Technologies Supporting Improved Reservoir Management Applying Downhole Fluid Analysis and Wireline-Formation-Testing Techniques in Reservoir Manage Advanced Formation Testing in OBM Using Focused Fluid Sampling for Producibility Evaluation in Ma Low-Level Hydrogen Sulphide Detection Using Wireline Formation Tester

Integration of Fluid Log Predictions and Downhole Fluid Analysis How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs? Integration of Geochemical, Mud-Gas, and Downhole-Fluid Analyses for the Assessment of Composi Fluid Identification Challenges in the Near Critical Fluids: Case Studies in Malaysia Hydrocarbon Compositional Gradient Revealed by In-Situ Optical Spectroscopy Pressure Measurement and Pressure Gradient Analysis: How Reliable For Determining Fluid Density Integration of In-Situ Fluid Measurements for Pressure Gradients Calculations Downhole Measurement of Methane Content and GOR in Formation Fluid Samples Modeling the Effect of Asphaltene on the Development of the Marrat Field EOS-Based Downhole Fluid Characterization Advanced Compositional Gradient Analysis Downhole Fluid Analysis and Fluid-Comparison Algorithm as Aid to Reservoir Characterization Application of Artificial Neural Networks to Downhole Fluid Analysis Enhanced Characterization of Multi-Phase Downhole Fluid Samples Using a Full Spectrum Weighted Practical and Robust Isenthalpic/Isothermal Flashes for Thermal Fluids Rheology of Heavy-Oil Emulsions Reservoir Fluid Analysis Using PVT Express Downhole Fluid Analysis Integrating Insitu Density and Viscosity Measurements - Field Test from In-Situ Density and Viscosity Measured by Wireline Formation Testers Fluid Sampling in Carbonates-Challenges and Best Practices Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination Wireline Gas-Condensate Sampling: A Unique, Proven Solution An Innovative Multiphase Sampling Solution at the Well Site to Improve Multiphase Flow Measureme Sampling With Multiphase Flowmeter in Northern Siberiaâ€”Condensate Field Experience and Sensiti Reaction of Simple Organic Acids and Chelating Agents With Calcite Novel Chelating-Based Technology Application in Complex and Heterogeneous Injector Wells in the A Sandstone Cores as Reaction Vessels: Synthesis of Calcium Carbonate Particles for Artificial Formati Mechanistic Study of Chemicals Providing Improved Halite Inhibition Taking Advantage of Injectivity Decline for Sweep Enhancing during Waterflood with Horizontal Inject Mechanisms, Parameters, and Modeling of Naphthenate-Soap-Induced Formation Damage New Fundamental Insights into Perforation-Induced Formation Damage Perforation Damage Removal by Underbalance Surge Flow First Application of Scale Inhibitor During Hydraulic Fracturing Treatments in Western Siberia Optimization of a Scale Treatment in the Uinta Basinâ€”A Case History Impact of Intelligent Wells on Oilfield Scale Management Techniques Used To Monitor and Remove Strontium Sulfate Scale in UZ Producing Wells Impact of In-Situ Sulfate Stripping on Scale Management in the Gyda Field Optimal Region Delineation in a Reservoir for Efficient History Matching Fracture Lineament Validation using Streamline Simulation in a Giant Middle East Field: An Innovati Streamline Simulation for Reservoir Management of a Super Giant: Sabiriyah Field North Kuwait Ca Managing Water and Gas Production Problems in Cantarell: A Giant Carbonate Reservoir in Gulf of Automatic Surveillance System for Large Gas Fields With Multifrequency Measurements Tracking Interwell Water Saturation in Pattern Flood Pilots in a Giant Gulf Oil field Pattern Balancing and Waterflood Optimization of a Super Giant: Sabiriyah Field, North Kuwait, a C Producing Extra-Heavy Oil from the Orinoco Belt, Cerro Negro Area, Venezuela, Using Bottom-Drive Feasibility of using Electrical Downhole Heaters in Faja Heavy Oil Reservoirs Microwave Assisted Gravity Drainage of Heavy Oils Horizontal Alternating Steam Drive Process for the Orinoco Heavy Oil Belt in Eastern Venezuela Development of Small Size-Heavy-Oil Field With Innovative Technology Characterization of Complex Carbonate Heavy Oil Reservoirâ€”A Case Study A Technique for Measuring Permeability Anisotropy and Recovering PVT Samples in a Heavy Oil Rese

Developing Heavy Oil Field By Well Placement - A Case Study Optimizing Horizontal-Well Steam-Stimulation Strategy for Heavy-Oil Development Smart Chemical Systems for the Stimulation of High-Water-Cut Heavy Oil Wells Horizontal-Well-Production Logging Experience in Heavy-Oil Environment With Sand Screen: A Cas Thermal Simulation and Economic Evaluation of Heavy-Oil Projects Case Study in Venezuela: Performance of Multiphase Meter in Extra Heavy Oil Methodology of Calibration for Nucleonic Multiphase Meter Technology for SAGD Extra Heavy Oil Investigation of a New Single-Stage Sandstone Acidizing Fluid for High-Temperature Formations Formation Testing and PVT Sampling in Low-Permeability, High-Pressure Gas Condensate Reservoir Successful Application of Exploration Lessons Learnt To Deliver Stretch HT/HP Well Delivery Objecti Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Cen A New Shear-Tolerant High-Temperature Fracturing Fluid New Fracturing Fluid for High Temperature Reservoirs Laboratory Evaluation of an Innovative System for Fracture Stimulation of High-Temperature Carbon Coiled-Tubing-Conveyed Perforating for High-Pressure/High-Temperature Environment in Mexico Ma First High Pressure and High Temperature Digital Electric Intellitite Welded Permanent Down Hole M Case Study from 12 Successful Years of High Temperature Fracturing in Bach Ho Field Offshore Vie Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New Sa Stimulation of High-Temperature Sandstone Formations From West Africa With Chelating Agent-Base Successful Application of High-Temperature Viscoelastic Surfactant (VES) Fracturing Fluids Under Wettability Alteration for Water-Block Prevention in High-Temperature Gas Wells Laboratory Measurement of pH of Live Waters at High Temperatures and Pressures Recent Developments in the Deposition of Colloidal Asphaltene in Capillary Flow: Experiments and Optimizing Horizontal Completions in the Cleveland Tight Gas Sand Horizontal Well Completion and Stimulation Techniques--A Review With Emphasis on Low-Permeabil The key challenges for Optimization of a Tight Gas Field Developments Using a Multi-Domain Integr Observations From Tight Gas Reservoir Stimulations in the Rocky Mountain Region Reservoir Pressure Depletion and Water Flooding Influencing Hydraulic Fracture Orientation in Low-Pe Characterization of Hydraulically-Induced Fracture Network Using Treatment and Microseismic Data Application of Hybrid Fracture Treatment to Tight Gas Sands in East Texas Cotton Valley Sands Benefits of the Novel Fiber-Laden Low-Viscosity Fluid System in Fracturing Low-Permeability Tight Increasing Reservoir Contact by Combining Mechanical Diversion and Unique Stimulation Chemistry Multiple Transverse Fracturing in Horizontal Open Hole Allows Development of a Low-Permeability R Multiple Proppant Fracturing Treatments Unleashed High Gas Rate From an Openhole Horizontal Tig Horizontal Drilling Application To Recover Incremental Oil in Low-Permeability Carbonate Reservoirs, Well Production Forecast in a Tight Gas Reservoirâ€”Closing the Loop With Model-Based Prediction Uinta Basin Single-Well Model to Optimize Tight Gas Completions Numerical Simulation of Thick, Tight Fluvial Sands Fracturing Previously Bypassed Highly Laminated Tight Gas Sands, A Production Optimization Case A New Formation-Evaluation Technique for the Lower Tertiary in South Texas--Predicting Production Fracture and Sub-Seismic Fault Characterization for Tight Carbonates in Challenging Oil-Based Mu Multidisciplinary Approach and New Technology Improve Carbonate Reservoir Evaluation Applied Natural Fracture Characterization Using Combination of Imagery and Transient Information A Case Study: Using Wireline Pressure Measurements to Improve Reservoir Characterization in Tig A Case Study: Using Wireline Pressure Measurements To Improve Reservoir Characterization in Ti Best Practices for Formation Testing in Low Permeability Reservoirs Field-Development Case Study: Production Optimization Through Continuous Multidisciplinary Reser Horizontal Wells in Tight Gas Sands--A Method for Risk Management To Maximize Success Low Porosity Fractured Reservoir Characterization For Exploration and Horizontal Drilling Data Acquisition and Formation Evaluation Strategies in Anisotropic, Tight Gas Reservoirs of the Su Optimum Logging Programs in Tight Sands

Identification and Characterization of Transition Zones in Tight Carbonates by Downhole Fluid Analys Successful Innovative Water-Shutoff Operations in Low-Permeability Gas Wells Stepping on Development of Small and Medium Size Oilfields through Horizontal Wellsâ€”The Way Mini Fracturing: A New Horizon of Breakthrough Integrated Technology for Small Fields Analysis of Multicriteria Decision-Making Methodologies for the Petroleum Industry Judgment Elicitation Process for Decision-Making in the Oil and Gas Industry The Importance of Hole Quality for Effective Image Log Interpretation Clearly Demonstrated in an Ei Application of NMR T2 Relaxation for Drainage Capillary Pressure in Vuggy Carbonate Reservoirs Characterization of Reservoir Heterogeneity Through Fluid Movement Monitoring With Deep Electr Integration of borehole image log enhances conventional electrofacies analysis in dual porosity carbo Reconstructing Sedimentary Depositional Environment With Borehole Imaging and Core: A Case Stu Sedimentary Facies Computation and Stratigraphic Analyses Using Well Logs, Borehole Images and C New Downhole-Fluid-Analysis Tool for Improved Reservoir Characterization Reservoir Fluid Characterization Using Downhole Fluid Analysis in Northern Kalimantan, Indonesia Porosity Partitioning and Flow Unit Characterization From an Integration of Magnetic-Resonance Flow Unit Characterization and Geo-modeling of a Structurally Complex Fluvio-deltaic Reservoir usi A New-Generation LWD Tool With Colocated Sensors Opens New Opportunities for Formation Evalu New Developments in Sourceless Logging-While-Drilling Formation Evaluation: A Case Study From S Why the LWD and Wireline Gamma Ray Measurements May Read Different Values in the Same Wel Development of Water Saturation Error Analysis Charts for Different Shaly Sand Models for Uncertain Development of Water Saturation Error Analysis Charts for Different Shaly Sand Models for Uncertain A New Workflow for Comprehensive Petrophysical Characterization of Carbonate Reservoirs Drilled Enhanced Reservoir Description in Carbonate and Clastic Reservoirs Case Study of Permeability, Vug Quantification, and Rock Typing in a Complex Carbonate Applications of NMR Logs and Borehole Images to the Evaluation of Laminated Deepwater Reservoi Integration of Borehole Imaging, Open Hole Logs, Nuclear Magnetic Resonance/Modular Dynamic Tes Evaluation of Low-Resistivity-Pay Deepwater Turbidites Using Constrained Thin-Bed Petrophysical A Formation Evaluation in Thin Sand/Shale Laminations Formation Evaluation of Horizontal Water Injectors Drilled in Thick Carbonate Reservoirs: Behind-C Integration of Production, Pressure Transient and Borehole Images in Horizontal Wells Drilled in C Specialized Techniques for Formation Testing and Fluid Sampling in Unconsolidated Formations in Geomechanics Insight Into Discrepancies of Core to Image Log Discontinuities and Implications for Exploration Potential of Sinuous (Channellike) Events in Late Cretaceous of Al-Khafji Field, Middle E Understanding a Reservoir: 3D Geological Modelling Using Scenario-Based Approach and Conventio Frequentist Meets Spatialist: A Marriage Made in Reservoir Characterization and Modeling Methods for Real-Time and High-Resolution Formation Evaluation and Formation Testing of Thinly Be NMR Petrophysics in Thin Sand/Shale Laminations Successful Application of New LWD Platform Provides Integrated Real-Time Formation Evaluation in Improving LWD Image and Formation Evaluation by Utilizing Dynamically Corrected Drilling-Derive From Issues to Solutions â€“ Introducing the Multi Function Logging While Drilling Tool for Reservoi Stress Reorientation Around Horizontal Wells Prediction of Rock Mechanical Parameters for Hydrocarbon Reservoirs Using Different Artificial Intel Estimation of Near-Wellbore Alteration and Formation Stress Parameters From Borehole Sonic Data Characterization of Multilayer Reservoir Properties Using Production Logs Characterization of Commingled Reservoir Properties With Production Logs Evaluation of Commingled Reservoir Properties Using Production Logs An Approach to Fracture Characterization Using Borehole Seismic Data Integrated Fracture Study using Formation Micro Imager, Stoneley Waves and Formation Evaluation R Continuous Fracture Modeling of a Carbonate Reservoir in West Siberia Characterization of Fractures and Faults From High-Resolution Image Logs To Optimize the Geologi Application of an Integrated Approach for the Characterization of a Naturally Fractured Reservoir i

Determination of In-Situ Two-Phase Flow Properties Through Downhole Fluid Movement Monitoring The Impact of the Downhole Formation Tester with Comprehensive Data Integration in Pre-Khuff Hyd An Investigation of Near-Wellbore Flow Properties Using Sonic Scanner Measurements and Interval Radial Profiling for Completion Effectiveness With New Sonic Measurement in the Gulf of Thailand Porosity With Nuclear Magnetic Resonance in Naturally Fractured Clastics Reservoirs in the Devoni Using the Continuous NMR Fluid Properties Scan to Optimize Sampling with Wireline Formation Test The Application of NMR Logs for the Evaluation of Gas Reservoirs With Low Salinity Formation Wate Porosity Determination From NMR Log Data: The Effects of Acquisition Parameters, Noise, and Inver Advances in NMR Logging Optimization of the Prediction of Hydrocarbon-Producing Zones Through Integration of Petrophysical Comprehensive Reservoir Characterization with Multiphase Production Logging A New Porosity Partitioning-Based Methodology for Permeability and Texture Analysis in Abu Dhabi Simulation of Inflow While Underbalanced Drilling With Automatic Identification of Formation Param Utilizing Real Time Logging While Drilling Resistivity Imaging to Identify Fracture Corridors in a high Combining Continuous Fluid Typing, Wireline Formation Testers, and Geochemical Measurements for Improved Interpretation of Reservoir Architecture and Fluid Contacts Through the Integration of D Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity Characterization of Reservoir Properties Using Production Logs Remaining Oil Investigation in a High Recovery Oilfield Development and Use of Improved Wireline Formation Tester Technologies in the Challenging Deltai Enhancing Formation Testing and Sampling Operations Through the Use of Log-Derived High-Resolu Direct Measurements of Minimum Horizontal Stress, Permeability, and Permeability Anisotropy in a Si A Method for Analysis of Pressure Response With a Formation Tester Influenced By Supercharging Field Development Plan by Optioneering Process Sensitive to Reservoir and Operational Constraints Reducing Uncertainty Through Downhole Fluid Analysis: A Field Case Study Selection Criteria for Artificial Lift Technique in Bokor Field New Life for a Mature Oil Province via the Integration of Improved Recovery Methods An Integrated Approach to Field Surveillance Improves Efficiency in Gas Lift Optimization in Bokor Fi Differentiating Well Placement Expectations in Saudi Arabia with Production from Stringer Sand Rese Implementing the Optimum Well Placement Strategy for Horizontal Injectors Drilled in Highly Hetero Improved Production in Low-Pressure Gas Wells by Installing Wellsite Compressors An Integrated Computer Based Method to Maximize Infill Drilling, Sidetracking, and Workover Potent Flaring, Gas Injection and Reservoir Management Optimization: Preserving Reservoir Energy Maximi Coupling a Reservoir Simulator With a Network Model to Evaluate the Implementation of Smart Well Integrated Optimization of Field Development, Planning, and Operation A New Approach to Gas Lift Optimization Using an Integrated Asset Model Identifying the Improved-Oil-Recovery Potential for a Depleted Reservoir in the Betty Field, Offshore An Approach for Production Enhancement Opportunities in a Brownfield Redevelopment Plan Energy Balance in Steam Injection Projects Integrating Surface-Reservoir Systems A Successful Process for Embracing Uncertainty and Mitigating Risk - From Geological Understandi Breaking the Barriers-The Integrated Asset Model From Reservoir Through Process, From Today to Tomorrowâ€”The Integrated Asset Model Integration of Production and Process Facility Models in a Single Simulation Tool Integrated Studies on a Conveyor Beltâ€”A New Concept of Study Workflows Based on Stochastic Pr Production Diagnostics and Water Control for the XJG Fields, South China Sea The Integrated Approach to Formation Water Management: From Reservoir Management to Protectio Production Enhancement for Khafji Field Using Advanced Optimization Techniques Horizontal Well Best Practices to Reverse Production Decline in Mature Fields in South China Sea Transforming Data Into Decisions To Optimize the Recovery of the Saih Rawl Field in Oman A Unique Workflow for Reserves Evaluation in Lower Vicksburg Sands Better Valuation of Future Information Under Uncertainty

Latest Generation Horizontal Well Placement Technology Helps Maximize Production in Deep Water T Brenda Field Development: A Best Practice in Horizontal Well Placement Leading to Optimal Reservo Closing the Loop Between Reservoir Modeling and Well Placement and Positioning Using Real-Time Pressure Data for Well Placement Planning Unlocking the Potential of Mature Fields - An Innovative Filtering and Analysis Approach to Identify Optimizing Horizontal Well Placement and Reservoir Inflow in Thin Oil Rim Improves Recovery and Ex Adjoint-Based Well-Placement Optimization Under Production Constraints A New Analytical Model for the SAGD Production Phase Generalized Analytical Solution for Reservoir Problems With Multiple Wells and Boundary Condition Semi-analytical Solution for Multiple Layer Reservoir Problems with Multiple Vertical, Horizontal, De 3D Field-Scale Automatic History Matching Using Adjoint Sensitivities and Generalized Travel-Time I Fast and Efficient Sensitivity Calculation Using Adjoint Method for 3 Phase Field-Scale History Match Innovative Approach to Assist History Matching Using Artificial Intelligence Experimental Design and Response Surface Models as a Basis for Stochastic History Matchâ€”A Nig History Matching Using Face-Recognition Technique Based on Principal Component Analysis Analytical Solutions for the Radial Flow Equation With Constant-Rate and Constant-Pressure Bounda A General Unstructured Grid, Parallel, Fully Implicit Thermal Simulator and Its Application for Large Efficient General Formulation Approach For Modeling Complex Physics Using Production Logs to Calibrate Horizontal Wells in Reservoir Simulation Integrating Advanced Production Logging and Near-Wellbore Modeling in a Maximum- Reservoir-Con Using a Discritized Well Model to Simulate Production Behavior in Horizontal or Multi-Lateral Wells Complex Well Modeling Workflow Enabling Full Field Optimization and Forward Decisions 3D Reservoir Geomechanical Modeling in Oil/Gas Field Production A New Thermal-Compositional Reservoir Simulator with a Novel Equation Line-Up" Method" Effective Use of Production Surveillance Tool in Forecasting Future Production Fracture Impact of Yield Stress and Fracture-Face Damage on Production With a Three-Phase 2D M Numerical Investigation on Hydraulic Fracture Cleanup and Its Impact on the Productivity of a Gas Numerical Modeling of Multiple Hydraulically Fractured Horizontal Wells (MHFHW) New Approach to Simulating Multicomponent Fluids Flow to Hydraulic Fractured Well Hydraulic-Fracture Modeling With Bedding Plane Interfacial Slip Explicit Simulation of Multiple Hydraulic Fractures in Horizontal Wells Modeling Non-Darcy Flow and Perforation Convergence for Vertically Fractured Wells A Bayesian Production Analysis Technique for Multistage Hydraulically Fractured Wells Design Criteria for Improved Performance of Fractured Wells Modelling of Transverse Hydraulic Fracturing 2D Modeling of Hydraulic Fracture Initiating at a Wellbore With or Without Microannulus The Application of Artificial Neural Networks With Small Data Sets: An Example for Analysis of Fract Incorporation of Static and Dynamic Constraints in Optimum Upscaling: A Field Case Study Unconventional Reservoir Modeling of a Gas Field in the Nile Delta of Egypt Prediction of Temperature Propagation Along a Horizontal Well During Injection Period IPI Method: A Subsurface Approach to Understand and Manage Unfavorable Mobility Waterfloods Material Balance Analysis in Complex Mature Reservoirs - Experience in Samarang Field, Malaysia Pressure and PVT Uncertainty in Material-Balance Calculations History Match of an Old Waterflood: Dealing Wth Decades Worth of Data From Hundreds of Wells Two-Phase Multicomponent Diffusion and Convection for Reservoir Initialization The Pains and Gains of Experimental Design and Response Surface Applications in Reservoir Simula A Systematic Approach to Incorporate Capillary Pressure-Saturation Data Into Reservoir Simulation Multipoint Flux Approximations via Upscaling Why Dual Porosity Models are not Applicable for Simulation of the Near-Wellbore Zone of Gas Conde Simulation of Gas/Oil Displacements in Vuggy and Fractured Reservoirs History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability P

Multiple Reservoir Simulations Integration: An Alternative to Full Field Simulation in the North Kuwai A Three-Phase Compressible Dual-Porosity Model for Streamline Simulation Implicit 1-D Transport Solvers For a Streamline Simulator For Fractured Reservoirs Multiscale Mimetic Solvers for Efficient Streamline Simulation of Fractured Reservoirs Conceptual Models for Fast Tracking Decision Making in the Reservoir Management Quantifying Uncertainty for the PUNQ-S3 Problem in a Bayesian Setting With RML and EnKF Proxy Modeling in Production Optimization The Application of Streamline Reservoir Simulation Calculations to the Management of Oilfield Scale Real Time Integration of Reservoir Modeling and Formation Testing Simulation Study of Steamflooding With Horizontal Producers Using PEBI Grids Acceleration of Streamline Simulation Using Adaptive Mesh Refinement Along Streamlines Thermodynamically Consistent Analytical Approach for Streamline Simulations of Multicomponent H Selection of Infill Drilling Locations Using Customized Type Curves Assessing the Uncertainty in Reservoir Description and Performance Predictions With the Ensemble Ranking of Geostatistical Reservoir Models and Uncertainty Assessment Using Real-Time Pressure Modeling Well Inflow Control With Flow in Both Annulus and Tubing Black-Oil Delumping Techniques Based on Compositional Information from Depletion Processes Black Oil Delumping: Running Black Oil Reservoir Simulations and Getting Compositional Wellstream A Quantitative Model for the Effect of Wettability on the Conductivity of Porous Rocks Fines Migration Evaluation in a Mature Field in Libya Applicability of the Forchheimer Equation for Non-Darcy Flow in Porous Media Understanding the Pressure Gradients Improves Production From Oil/Water Transition Carbonate Z Reservoir Focused Underbalanced Applications in the Margham Field In Situ Stress Pattern and Its Impact in Drilling High- Angle Wells in Gulf of Suez, Egypt Making Our Mature Fields Smarterâ€”An Industrywide Position Paper From the 2005 SPE Forum Current Status of Enhanced Recovery Techniques in the Fields of Russia U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces Zonal Isolation Modeling and Measurementsâ€”Past Myths and Today's Realities Practical Steps for Successful Identification and Production of Remaining Hydrocarbons Reserves in The Use of Pulsed Neutron Measurements for Determination of Bypassed Pay: A Multi-Well Study Using the Optimal Through-Casing Measurement to Maximize Oil Recovery: A Case Study From The Permanent Real-Time Downhole Flowrate Measurements in Multilateral Wells Improve Reservoir Moni A Novel Solution to Flow Profiling With an Improved Production-Logging Tool In Short String Section Pushing the Envelope for Production Logging in Extended Reach Horizontal Wells in Chayvo Field, The Identification of Condensate Banking With Multiphase Flowmetersâ€”A Case Study Improved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate En Improved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate En An Innovative Multi-Reservoir Permanent Downhole Monitoring System Through A Single Well Real-Time Downhole pH Measurement Using Optical Spectroscopy Surveillance and Diagnostics of Permanent Bottomhole Gauge Data Coupled With Geomechanical Mo New Analytical Techniques To Help Improve Our Understanding of Hydraulically Induced Microseismic â€œDon't Let the Temperature Log Fool You: False Indications of Height Containment From Case Stu Real Time Diagnostics of Gas Entries and Remedial Shut-off in Barefoot Horizontal Wells Predicting the Flow Distribution on Total E&P Canada's Joslyn Project Horizontal SAGD Producing We Inflow Profiles Obtained With Pulsed Neutron Logs in Subcritical-Velocity Wells Determination of Reservoir Inflow With Pulsed Neutron Logs Under Subcritical Flow Conditions Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fib Using Chemical Tracers for Flow Profiling a Subsea Horizontal Well with an Open Hole Gravel Pack Well Surveillance With a Permanent Downhole Multiphase Flowmeter Characterization of Fracture Dynamic Parameters to Simulate Naturally Fractured Reservoirs Permanent Downhole Gauge: A Need or A Luxury?

From Data Monitoring to Performance Monitoring Production Logging Low Flow Rate Wells with High Water Cut Observations from a Fieldwide Pressure Data Acquisition Campaign in the Wara Formation of the Gre A Successful Application of Fiber-Optic-Enabled Coiled Tubing With Distributed Temperature Sensin Real Time Production Monitoring Uncovers Potential for Recovery Optimization, Field Case Study, W The Power of Real-Time Monitoring and Interpretation in Wireline Formation Testingâ€”Case Studies Monitoring Multilayered Reservoir Pressures and Gas/Oil Ratio Changes Over Time Using Permanent Monitoring SAGD Steam Injection Using Microseismicity and Tiltmeters Monitoring Production From Gravel-Packed Sand-Screen Completions on BPâ€™s Azeri Field Wells U Completion Design for Sandface Monitoring of Subsea Wells Detecting Thief Zones in Carbonate Reservoirs by Integrating Borehole Images With Dynamic Meas Real-Time Production--A Virtual Dream or Reality? The Case of Remote Surveillance of ESP and Mu Production Performance Monitoring Workflow A Reduced Risk Alternative for Water Entry Detection in High Water Producing Horizontal Wells Determination of Water-Producing Zones While Underbalanced Drilling Horizontal Wellsâ€”Integrati Resistivity Through Casing Measurement Successfully Applied To Improve Oil Recovery And Water S An Innovative Approach in Tracking Injected Water Front in Carbonate Reservoir off Shore Abu Dhab Imaging Injected Water flood Fronts Between Wells in a Complex Carbonate Reservoir: Designing C Constraining Interwell Water Flood Imaging With Geology and Petrophysics: An Example From the M First Laboratory Perforating Tests in Coal Show Lower-Than-Expected Penetration Cleat Characterization in CBM Wells for Completion Optimization Application of Indirect Fracturing for Efficient Stimulation of Coalbed Methane A Field Study in Optimizing Completion Strategies for Fracture Initiation in Barnett Shale Horizontal W Effect of Layered Heterogeneity on Fracture Initiation in Tight Gas Shales Maximizing Energy at Coalface for Coalbed Methane Fracturing Operations Use of Horizontal Well Image Tools to Optimize Barnett Shale Reservoir Exploitation A Workflow for Integrated Barnett Shale Gas Reservoir Modeling and Simulation Effects of Well Placement and Intelligent Completions on SAGD in a Full-Field Thermal-Numerical M Coalbed- and Shale-Gas Reservoirs Barnett Shale Refracture Stimulations Using a Novel Diversion Technique Optimizing Well Productivity by Controlling Acid Dissolution Pattern During Matrix Acidizing of Carbo Case Study: First Successful Offshore ESP Project in Saudi Arabia Pushing the Boundaries of Artificial Lift Applications: SAGD ESP Installations at Suncor Energy, Can Staircase Lifting of Oil Using Venturi Principle: A New Artificial-Lift Technique Selection of an Adequate Completion Type is the Key to Successful Reserves Recovery. Case History of The Challenges and Advantages of Openhole Completions in the Manati Gas Field Multiple-Layer Completions for Efficient Treatment of Multilayer Reservoirs Dipole Radial Profiling and Geomechanics for Near Wellbore Alteration Detection to Improve Producti Production Tubing String Design for Optimum Gas Recovery Optimized Tubing-String Design Modeling for Improved Recovery Application of a Maximum Reservoir Contact (MRC) Well in a Thin, Carbonate Reservoir in Kuwait Succeeding With Multilateral Wells in Complex Channel Sands Using Down-Hole Control Valves to Sustain Oil Production From the First Maximum Reservoir Contact On Reservoir Fluid-Flow Control With Smart Completions Case Study: The Use of Downhole Control Valves to Sustain Oil Production from the First Maximum R Horizontal Open Hole, Dual-Lateral Stimulation, Using a Multilateral Entry with High Jetting Tool Experimental and Numerical Study on Production Performance: Case of Horizontal and Dual-Lateral Development of an Integrated Solution for Perforation, Production and Reservoir Evaluation Survival Analysis: The Statistically Rigorous Method for Analyzing Electrical Submersible Pump Sy Long Term Evaluation of an Innovative Acid System for Fracture Stimulation of Carbonate Reservoirs Horizontal Fracture Stimulation Success in the Alpine Formation, North Slope, Alaska

Fiber-Laden Fracturing Fluid Improves Production in the Bakken Shale Multi-Lateral Play Fiber-Based Fracture Fluid Technology a First for Oil Reservoirs in Western Siberia Field Trials of Fiber Assisted Stimulation in Saudi Arabia: An Innovative Non-Damaging Technique fo Fiber-Laden Fluid: Applied Solution for Addressing Multiple Challenges of Hydraulic Fracturing in We Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties Effect of Formation Modulus Contrast on Hydraulic Fracture Height Containment A Faster Cleanup, Produced Water-Compatible Fracturing Fluid: Fluid Designs and Field Case Studi Optimizing Fracturing Fluids From Flowback Water Maximizing Effective Fracture Half-Length to Influence Well Spacing Novel Frac-and-Pack Technique for Selective Fracture Propagation A Novel Approach to Fracturing Height Control Enlarges the Candidate Pool in the Ryabchyk Format Application of a Highly Efficient Multistage Stimulation Technique for Horizontal Wells Stimulating High-Water-Cut Wells: Results From Field Applications Efficient Multifractured Horizontal Completions Change the Economic Equation in Latin America Thr Continuous Pumping, Multistage, Hydraulic Fracturing in Kitina Field, Offshore Congo, West Africa Successful Multistage Horizontal Well Fracturing in the Deep Gas Reservoirs of Saudi Arabia: Field Successful Multistage Hydraulic Fracturing Treatments Using a Seawater-Based Polymer-Free Flui Successful Continuous, Multi-Stage, Hydraulic Fracturing Using a Seawater-Based Polymer-Free Flu Optimized Hydrualic Fracturing for the Gandhar Field Production Performance Design Criteria for Hydraulic Fractures Quantifying Proppant Transport for Complex Fractures in Unconventional Formations Particularities of Hydraulic Fracturing in Dome-Type Reservoirs of Samara Area in the Volga-Urals Ba Simultaneous Hydraulic Fracturing of Adjacent Horizontal Wells in the Woodford Shale Novel Technology Replaces Perforating and Improves Efficiency During Multiple Layer Fracturing Op A Study of Fracture Initiation Pressures in Cemented Cased-Hole Wells Without Perforations Semiphenomenological Model of Hydraulic Fracturing in Granular Media Optimization of a Visco-Elastic Surfactant (VES) Fracturing Fluid for Application in High-Permeabilit Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System Enables Commercial Produc Fracture Stimulation Utilizing a Viscoelastic-Surfactant-Based System in the Morrow Sands in Sout Overcoming Excessive Fluid Loss in Tip-Screen-Out Stimulations of Depleted, High-Permeability Res Fracturing Technology for 4% Porosity Libyaâ€™s Reservoir: Application of Correct Diagnostic and An Integrated Evaluation of Successful Acid Fracturing Treatment in a Deep Carbonate Reservoir Ha New Results Improve Fracture Cleanup Characterization and Damage Mitigation Optimizing the Completion of a Multilayer Cotton Valley Sand Using Hydraulic-Fracture Monitoring a Comparative Analysis of Damage Mechanisms in Fractured Gas Wells Borehole Deviation Surveys are Necessary for Hydraulic Fracture Monitoring Evaluation of the Proppant-Pack Permeability in Fiber-Assisted Hydraulic Fracturing Treatments for The Texture of Acidized Fracture Surfaces: Implications for Acid Fracture Conductivity Complex Fracture Geometry Investigations Conducted on Western-Siberian Oilfields at Rosneft Co A New Environmentally Acceptable Technique for Determination of Fracture Height and Width Hydraulic Fracture Geometry Investigation for Successful Optimization of Fracture Modeling and Ove Production Forecasting in a Limited-Data Environment: Evolving the Methodology in the Yamburgsk Correcting Underestimation of Optimal Fracture Length by Modeling Proppant Conductivity Variation Fracture Propagation in High-Permeability Rocks: The Key Influence of Fracture Tip Behavior Acid Fracturing of Deep Gas Wells Using a Surfactant-Based Acid: Long-Term Effects on Gas Produc Evaluation and Optimization of Low-Conductivity Fractures Evidence of a Horizontal Hydraulic Fracture From Stress Rotations Across a Thrust Fault Prediction of Long-Term Proppant Flowback in Weak Rocks Effect of Production Induced Stress Field on Refracture Propagation and Pressure Response Hydraulic Fracturing and Filtration in Porous Medium Differential Cased Hole Sonic Anisotropy for Evaluation of Propped Fracture Geometry in Western Si

New Findings in Fracture Cleanup Change Common Industry Perceptions Eliminating the Poroelastic Problems Associated with Water Injection in the Kikeh Deep Water Deve Using Open and Cased Hole Sonic Anisotropy and Geomechanics Modeling for Hydraulic Fracturing E Hydraulic Fracture Offsetting in Naturally Fractured Reservoirs: Quantifying a Long-Recognized Proc Auto, Natural, or In-Situ Gas-Lift Systems Explained A Critical Review of Completion Techniques for High-Rate Gas Wells Offshore Trinidad Application of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia Successful Case History of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia A Case Study of Oil-Based Mud Effect on Horizontal-Well Productivity Slim Intelligent Completions Technology Optimize Production in Maximum Contact, Expandable Line First Applications of Inflow Control Devices (ICD) in Open Hole Horizontal Wells in Block 15, Ecuador Integrating ESPs with Intelligent Completions: Options, Benefits and Risks Intelligent Completions Technology Offers Solutions to Optimize Production and Improve Recovery in Insurance Value of Intelligent Well Technology Against Reservoir Uncertainty Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities Managing Production in Maturing Assets: Increasing Intervention Success by Combining Production Forecasting the Productivity of Thinly Laminated Sands with a Single Well Predictive Model Geomechanical Characterization of a Sandstone Reservoir in Middle Eastâ€”Analysis of Sanding Pre Effective Matrix Acidizing in Carbonate Reservoirâ€”Does Perforating Matter? Productivity Increase Using the Combination of Formation Isolation Valve and Dynamic Underbalance Coiled-Tubing Perforation and Zonal Isolation in Harsh Wellbore Conditions Dynamic Underbalanced Perforating Application Increases Productivity in the Mature High-Permeabil Overbalanced Perforating Yields Negative Skins in Layered Reservoir Oriented Perforation in Dual Completion Wells: A Real Case in East Texas New Perforating Technique Improves Well Productivity and Operational Efficiency Quantifying Skin Variation for Underbalanced Perforating Improved Method for Underbalanced Perforating With Coiled Tubing in the South China Sea Modeling Air and Water Perforator Swell for Better Risk Management Novel Perforating Job Design Triples Well Productivity Flow Performance of Perforation Tunnels Created With Shaped Charges Using Reactive Liner Techn Overcoming Near Wellbore Damage Induced Flow Impairment with Improved Perforation Job Design Reduced Water Production and Increased Oil Production Using Smart Completions and MPFM Case Sand Control Completions for the Development of Albacora Leste Field Magnolia Deepwater Experience--Frac Packing Long, Perforated Intervals in Unconsolidated Silt Res TAML Level 3 tri-lateral with Sand Control application for Saudi Aramco Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Devel Novel Through Tubing Sand Control Solution for Failed Gravel Pack - Alpha Well - 4L Case Study Sand Control Completion Failures: Can We Talk the Same Language? A Step Change in Openhole Gravelpacking Methodology: Drilling-Fluid Design and Filter-Cake Rem Greater Plutonio Openhole Gravel-Pack Completions: Fluid Design and Field Applications Complex Through-Tubing Gravel-Pack Operation Increases Production on a Well in the Heidrun Fiel Openhole Gravel Packing With Exposed Shales: Waterpack Case Histories From Underground Gas St Gravel Packing Long Openhole Intervals With Viscous Fluids Utilizing High Gravel Concentrations: T Integrated Approach to Modeling Gravel Packs in Horizontal Wells Openhole Gravel Packing With Oil-Based Fluids: Implementation of the Lessons Learned From Past Effective Perforating and Gravel Placement: Key to Low Skin, Sand Free Production in Gravel Packs Effective Perforating and Gravel Placement: Key to Low Skin, Sand-Free Production in Gravel Packs Determination of Optimum Perforation Design and Sanding Propensity in Long Horizontal Wells Bas ICD Screen Technology in Stag Field to Control Sand and Increase Recovery by Avoiding Wormhole Screenless Completions as a Viable Through-Tubing Sand Control Completion The Search for Alternative to Screen: Is Permeable Cement a Viable Option?

Case Study: The Application of a Sand Management Solution for the Sarir Field in Libya Practical Approach to Achieve Accuracy in Sanding Prediction Sandingâ€”Not As It First Appeared Effect of Water Cut on Sand Productionâ€”An Experimental Study Bokor--A New Look at Sand Production in a Mature Field Influence of Rock Failure Characteristics on Sanding Behavior: Analysis of Reservoir Sandstones An Integrated Wellbore Stability and Sand-Production Prediction Study for a Multifield Gas Develop Lessons Learned From Using Viscoelastic Surfactants in Well Stimulation Small-Scale Fracture Conductivity Created by Modern Acid-Fracture Fluids Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas Field Trial of a New Non-Damaging Degradable Fiber-Diverting Agent Achieved Full Zonal Coverage d Successful Application of Innovative Fiber-Diverting Technology Achieved Effective Diversion in Ac Use of Novel Acid System Improves Zonal Coverage of Stimulation Treatments in Tengiz Field Optimization of Acid Stimulation for a Loosely Consolidated Brazilian Carbonate Formation--Multidi A Novel Stimulation Technique for Horizontal Openhole Wells in Carbonate Reservoirs--A Case Study Sandstone Matrix Stimulation Can Improve Brownfield Oil Production When the Chemistry and Proce Development and Field Application of a New Hydrogen Sulfide Scavenger for Acidizing Sour-Water In Successful Stimulation of Thick, Naturally-Fractured Carbonates Pay Zones in Kazakhstan Matrix Acidizing of Carbonate Reservoirs Using Organic Acids and Mixture of HCl and Organic Acids An Innovative Acid Stimulation Technique for Reviving Dead Wells in the Ghawar Field of Saudi Arabi An Alternative Solution to Sandstone Acidizing Using a Nonacid Based Fluid System With Fines-Migr Combining Acid- and Hydraulic-Fracturing Technologies Is the Key to Successfully Stimulating the Or Chemical Diversion Techniques Used for Carbonate Matrix Acidizing: An Overview and Case Historie Foam Fracturing: New Stimulation Edge in Western Siberia The Effect of Pore-Scale Heterogeneities on Carbonate Stimulation Treatments Restimulation: Candidate Selection Methodologies and Treatment Optimization Case Study: Application of a Viscoelastic Surfactant-Based CO2 Compatible Fracturing Fluid in the New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas Pr Optimized Stimulation Solutions for a Mature Field in Kazakhstan Preventive Treatment for Enhancing Water Removal from Gas Reservoirs by Wettability Alteration High-Water-Cut Wells Stimulation Combined Viscoelastic Surfactant Reliability of Cement Bond Log Interpretations Compared to Physical Communication Tests Between A New Approach for Interpreting Pressure Data To Estimate Key Reservoir Parameters From Closed Challenges Encountered During a Comprehensive Test Analysis for a Horizontal Well in a Thin, Carbo A Unique Methodology for Evaluation of Multi-Fractured Wells in Stacked-Pay Reservoirs Using Com Identifying Layer Permeabilities and Skin Using a Multi-Layer Transient Testing Approach in a Comp Pressure Transient Analysis of Partially Penetrating Wells in a Naturally Fractured Reservoir Radius of Investigation for Reserve Estimation From Pressure Transient Well Tests Real-Time Evaluation of Pressure Transients: Advances in Dynamic Reservoir Monitoring An Investigation of Recent Deconvolution Methods for Well-Test Data Analysis Advanced Methods to Design and Interpret Exploration Well Tests---Two Case Studies Estimating Fracture Permeability and Shape Factor by Use of Image Log Data in Welltest Analysis Mini-DST Applications for Shell Deepwater Malaysia A New Method for Gas Well Deliverability Potential Estimation Using MiniDST and Single Well Mode Extending the Range of Multiphase Metering to Challenging High Water Cut Gas-Lifted Wells: TOTAL Testing Gas Condensate Wells in Northern Siberia With Multiphase Flowmeters Improving Reservoir Characterization Using Accurate Flow-Rate History Reliability of Multiphase Flowmeters and Test Separators at High Water Cut Field Validation Processes for Multiphase Wet Gas Surface Well Testing Solutions: Example From t High-Accuracy Wet-Gas Multiphase Well Testing and Production Metering Production Well Testing Optimization Using Multiphase Flow Meters (MPFM)

Field Experience in Multiphase Gas-Well Testing: The Benefit of the Combination of Venturi and G Linking Well-Test Interpretations to Full Field Simulations Application of the Î²-Integral Derivative Function to Production Analysis A Digital Pressure Derivative Technique for Pressure Transient Well Testing and Reservoir Characteri Streaming Potential Applications in Oil Fields

Author

Abstract

Matteo Loizzo, SPE, Schlumberger Carbon Services and Sandeep Sharma, Abstract CO2 geological storage is about pumping T. Bï¿½rard, B. K. Sinha, SPE, Schlumberger; P. van Ruth, T. Dance, Coo Abstract We present an estimation of the full stre Y. Le Guen, J. Le Gouevec, R. Chammas, B. Gerard, and O. Poupard, Oxa Abstract One of the major challenges associated w A. Primera, W. Sifuentes, and N. Rodrï¿½guez; SPE, Schlumberger Abstract The reduction of greenhouse gas emissi S. Hurter, SPE, D. Labregere, and J. Berge, Schlumberger Carbon ServicesAbstract The need for CO2 emissions reduction a B. Norden and A. Fï¿½rster, GFZ German Research Centre for Geosciences, Abstract The storage of carbon dioxide (CO2) in s M. Sengul, Schlumberger Carbon Services Abstract Fossil fuel fired plants are responsible fo T. Bï¿½rard, L. Jammes, B. Lecampion, SPE, C. Vivalda, and J. Desroche Abstract Controlling the trapping of CO2 in the su S. Imbus, Chevron Energy Technology Co.; F.M. Orr, Stanford U.; V.A. Kuu Abstract Carbon dioxide capture and storage (CC Dave Shipley, Chevron; Ben Weltevrede, Shell International E&P B.V.; Ala Abstract PRODMLâ„¢ is a set of production data A. Hjelle, SPE, T.G. Teige, SPE, K. Rolfsen, K.J. Hanken, SPE, and S. Hern Abstract The well 34/8-A-6 AHT2 was drilled from Ukpe John, SPE, Schlumberger; Ian Tribe, SPE, Schlumberger; Jim MansonAbstract The Dumbarton Field operated by Maer Kumud Sonowal and Bjarne Bennetzen, Maersk Oil Qatar AS; Patrick Won Abstract Maersk Oil Qatar AS (MOQ) completed d Brian Toelle and Larry Pekot, Schlumberger Data & Consulting Services, a Abstract The Guelph Formation historically know Heron Gachuz Muro, Sergio Berumen Campos, and Luis O. Alcazar Cancin Abstract CO2 injection is one of the most efficient D.L. Fairhurst, B.W. Reynolds, S. Indriati, and M.D. Morris, SPE, Schlum Abstract The Oligocene Vicksburg formation in S S. Luo, SPE, Schlumberger, and M.A. Barrufet, SPE, Texas A&M U. Abstract Gas-condensate reservoirs usually exhi Josï¿½ Antonio Piï¿½a R., Josï¿½ Luis Bashbush, Edgar Alexander Ferna Abstract The work presented in this paper describ Hamed Al-Sharji, Ali Ehtesham, Bela Kosztin, and Clement Edwards, PDO; Abstract This paper discusses the gas shut-off tre Wong Chun Seng and Suhaila Wahib, Petronas Carigali; Choo Der Jiun an Abstract West Lutong is a mature field with 8 roun Keng Seng Chan, Schlumberger Well Services; Duong Danh Lam and Aleksey Abstract Oil production from some of wells in the W Redha Kelkouli, SPE, and Maen Razouqi, SPE, Schlumberger, and Saeed AlAbstract Most of the wells in Sabriya Field (Northe Victor E. Uadiale, Schlumberger; Otaru G.Oghie, Shell E&P, U.K.; and Vinc Abstract Due to the stacked nature of reservoirs in Faisal F. Al-Shahrani, Zulfiqar A. Baluch, Nashi M. Al-Otaibi, Saudi Aramco Abstract Water shut-off treatment (WSOT) using Goran Andersson, SPE, PetroBoscan; Gregg Molesworth, SPE, Chevron TecAbstract With the discovery of new fields becomin Alaa A. Dashash, Ibrahim Al-Arnaout, Saad M. Al-Driweesh, Saudi Aramco; Abstract Water production is a major problem for Ahmed Al-Zain, Jorge Duarte, Surajit Haldar, Saad Driweesh, Ahmed Al-J Abstract Water control is the key to prolong well li D. Gonzalez and A. Jamaluddin, Schlumberger Abstract Due to the large potential reserves incre M. Vielma, SPE, Schlumberger; S. Atmaca, SPE, C. Sarica, SPE, and H. Zha Summary The dynamic characteristics of oil/wate S. Atmaca, SPE, C. Sarica, SPE, H.-Q. Zhang, SPE, and A.S. Al-Sarkhi, UnivSummary Oil/water flow is a common occurrence T. Graf, SPE, S.P. Graf, SPE, P. Evbomoen, SPE, and C. Umadia, SPE, S Abstract The installation of intelligent wells to imp Fernando L. Morales/Schlumberger; Juan Cruz Velï¿½zquez/Schlumberge Abstract Traditionally in the upstream business op Doris L. Gonzalez and Abul K.M. Jamaluddin, Schlumberger; Trond SolbakkeAbstract In deepwater production systems extrem H. Alboudwarej, SPE, Schlumberger; Z. Huo, SPE, Shell Global Solutions (UAbstract Development of deep offshore fields is c N. Mï¿½ller, Schlumberger Oilfield Services; H. Elshahawi, Shell Intl. E&P Abstract Carbon dioxide (CO2) occurrence in hyd Saifon Daungkaew, SPE, Jack Harfoushian, SPE, and Boon Cheong, SPE Sch Abstract The inherent uncertainty in establishing r N.H.G. Rahmani, SPE, J. Gao, SPE, and M.N. Ibrahim, SPE, Schlumberger;Abstract Asphaltene precipitation can have profou Adriana P. Ovalle, M-I Swaco; Chris P. Lenn, Schlumberger; and William D. Summary Certain fluid properties are required for A.H. El-Banbi, Schlumberger, and K.A. Fattah and M.H. Sayyouh, Cairo U. Abstract Several authors have shown the applica Oliver C. Mullins and Soraya S. Betancourt, Schlumberger-Doll Research; Abstract The fluids in large reservoirs can be in e Andry Halim, Pertamina, and Nicolas Orban, Elin Haryanto, and Cosan Aya Abstract Fluid identification is an important objecti Moyosore Okuyig and Ahmed Berrim, ADMA-OPCO, and ChengGang Xian Abstract Fluid characterization quantifies the rese Peter Hegeman, SPE, and Chengli Dong, SPE, Schlumberger; and Nikos Varot Summary Reservoir characterization and asset m F.O. Alpak, SPE, H. Elshahawi, SPE, and M. Hashem, SPE, Shell Intl. E&P, Abstract Miscible oil-based mud (OBM) filtrate co Jesï¿½s A. Caï¿½as, Evie Freitas, A. Ballard Andrews, Oliver C. Mullins, a Abstract This paper describes a new Downhole Fl M. Khalil and K.K. Maamari, SPE, Petroleum Development Oman, and R.R. Abstract The Gharif anCase Studies T. Beaiji, Saudi Aramco; M. Zeybek, Schlumberger; A. Crowell, R. Akkurt, a Abstract Wireline formation testing provides form Mohamed Hashem and Hani Elshahaw, Shell; Ryan Parasram, Peter Weinhe Abstract Many development projects will rely on p

Julian Y. Zuo, SPE, Oliver C. Mullins, SPE, Chengli Dong, SPE, Dan Zhan Abstract Reservoir fluids frequently reveal comple C.S. Kabir, SPE, Chevron ETC and J.J. Pop, SPE, Schlumberger Summary Collection and analysis of gas/condens Hani Elshahawi, SPE, Shell; Melton Hows, SPE, Chengli Dong, SPE, Lali Abstract Identifying compartmentalization quantify Ko Ko Kyi andï¿½Norfadilah Yahaya, PETRONAS Carigali; Saifon DaungkaAbstract Reservoir fluid identification plays a cruc Go Fujisawa, SPE, Soraya S. Betancourt, SPE, Oliver C. Mullins, Torleif T Summary This paper presents a case study of a N R.R. Jackson, A. Carnegie, and F.X. Dubost, SPE, Schlumberger Abstract Pressure-depth plots have been used fo F.X. Dubost, A.J. Carnegie, O.C. Mullins, M.O. Keefe, S. Betancourt, and J Abstract Reservoir fluids often show complex com Chengli Dong, SPE, Peter S. Hegeman, SPE, and Andrew Carnegie, SPE, SSummary Formation fluid sampling early in the lif T. Yi, A. Fadili, M. Ibrahim, SPE, Schlumberger; B.S. Al-Matar, SPE, Kuwai Abstract This paper describes the study of the effe Julian Y. Zuo, SPE, Dan Zhang, Francois Dubost, SPE, Chengli Dong, SPE Abstract Downhole fluid analysis (DFA) together w Jesï¿½s Caï¿½as, SPE, Julian Pop, SPE, Francois Dubost, SPE, Schlumber Abstract Steep gradients are common in gas cond Lalitha Venkataramanan, SPE, Schlumberger; Hani Elshahawi, SPE, DanielSummary In recent years formation-sampling an Peter Hegeman, SPE, and Chengli Dong, SPE, Schlumberger, and Nikos Varot Abstract Reservoir characterization and asset man R.J. Butsch, SPE, C.W. Morris, SPE, and K.T. Pinto, SPE, Schlumberger Abstract Formation testers are commonly used to Terry W. Stone, Schlumberger, and James S. Nolen, Consultant Abstract This paper describes in detail computatio Hussein Alboudwarej, Moin Muhammad, and Ardi Shahraki, Schlumberger; She Summary Water is invariably produced with crude I.A. Khan, K. McAndrews, J.P. Jose, and A.K.M. Jamaluddin, Schlumberger, Abstract Representative reservoir fluid sampling & Mosleh Khalil, Huda Rumhi, SPE, Petroleum Development Oman, Mahaly Ran Abstract The new generation of wireline formation Michael O'Keefe, SPE, Sophie Godefroy, Ricardo Vasques, Anne Agenes, SAbstract A downhole density-viscosity (D-V) sens Ahmed Dawoud, ADCO, John Zaggas, SPE, Schlumberger, and Sammy HaAbstract A heterogeneous carbonate reservoir can Michael Oâ€™Keefe, SPE, Schlumberger; Kï¿½re Otto Eriksen, SPE, and St Summary A new generation of sampling technolo A. Paul, SPE, Schlumberger Abstract Wireline pressure testers and reservoir f F. Hollaender, SPE, J.J. Zhang, B. Pinguet, SPE, V. Bastos, SPE, E. Delva Abstract Representative reservoir fluid sampling a Vitaliy Afanasyev, Bertrand Theuveny, SPE, Sylvain Jayawardane, Alexand Abstract Multiphase well testing has been acknow L. Li, SPE, and H.A. Nasr-El-Din, SPE, Texas A&M University, and F.F. Cha Abstract Acid stimulation of deep wells is a difficul Martin Urraca, SPE, Schlumberger, and Ferenc Udvari, MOL Abstract The geologically complex Algyo field disc Michael J. Fuller, Schlumberger Abstract Generally matrix acidizing fluids for sand Hua Guan, SPE, M-I SWACO Production Technologies; Richard Keatch, OMS Abstract This paper investigates the application of Bedrikovetsky, P. and Muhammad A. W., U of Adelaide; Chang G., SchlumbeAbstract Injectivity formation damage with waterflo S. Sarac, SPE, F. Civan, SPE, The University of Oklahoma Summary Naphthenate-soap deposition and the r Juliane Heiland, Brenden Grove, Jeremy Harvey, Ian Walton and Andrew MaAbstract Shaped charge perforating subjects the f P. Bolchover, Schlumberger Cambridge Research, and I.C. Walton, SPE, Abstract In cased completions perforations prov K. Cheremisov, SPE, D. Oussoltsev, SPE, and K.K. Butula, SPE, SchlumberAbstract Problems related to inorganic scale preci Leonardo Maschio, Bilu Cherian, Bernhard Lungwitz, Michael Tyndall, and Abstract The precipitation and accumulation of sca V. Kavle, S. Elmsallati, E. Mackay, and D. Davies, Heriot-Watt U. Abstract The main challenge facing the oil indust Jamal Al-Ashhab and Hassouneh Al-Matar, ZADCO, and Shahril Mokhtar, S Abstract Scale deposition in completion strings is E. Mackay, K. Sorbie, and V. Kavle, Heriot-Watt U.; E. Sï¿½rhaug and K. MeAbstract While barium stripping is commonly obs S. Yadav, Marathon Oil Company; R. Heim, Schlumberger; S. Bryant, UT AuAbstract In a large field history matching is genera Abdullah A. Al-Najem, Jamil S. Al-Thuwaini, and Abdulatif Al-Omair, Saudi Abstract With the advancement in streamline sim Ibrahim, Muhammad N., SPE, Schlumberger Oilfield Services; Clark, RobertAbstract This paper discusses the incorporation o T.S. Daltaban, Schlumberger Consultant, and A. Miguel Lozada, P. Antonio Abstract Located in the Gulf of Mexico Cantarell F M. Mota, SPE, O.M. Campos, SPE, H. Escalona, and L.D. Teran, Schlumbe Abstract This paper presents the results of an aut Zahid Bhatti, SPE, Yousof Al Mansoori, PSE, Saber El Sembawy, Volker Va Abstract Peripheral water flooding has been the p Clark, Robert A. Jr., SPE, BP; Lantz, James, AAPG, BP; Karami, Hossein, Abstract This paper outlines the successful integra M.A. Ramos and J.C. Brown, Petrï¿½leos de Venezuela S.A.; M. Rojas, O. Summary The traditional means of artificial lift pro Raï¿½l Rodrï¿½guez, Josï¿½ Luis Bashbush and Adafel Rincï¿½n, SPE, S Abstract The Orinoco Belt (Faja) in Venezuela con Berna Hascakir, METU; Cagdas Acar, Schlumberger; Birol Demiral, UTP; a Abstract Conventional EOR methods like steam-i Edgar A. Fernandez R. and Josï¿½ Luis Bashbush, Schlumberger Abstract The Orinoco Heavy Oil Belt (Faja) has be Raj Deo Tewari and Mirghani Malik, GNPOC; Mohamed Ahmed Hassan IdrisAbstract Exploration and development of Heavy o Afzal Iqbal, John Smith, Ali Reza Zahedi, Deemer Arthur, and Falah M. Al Abstract The Paleocene/Eocene age 1st Eocene R Achourov V., SPE, Schlumberger, and Khamitov I. and Yatsenko V., SPE, R Abstract Wireline formation testers provide the m

Pan You li, Luo Hui Hong, and Abdel Mageed Sharara, CNPCIS, and Siva Abstract Fula is a heavy oil field located in Muglad Shanqiang Luo, SPE, and Andy Baker, SPE, Schlumberger Abstract T Oil Development Mohamed Ahmed Samir and Islam Elnashar, Scimitar, and Mathew Samue Abstract The Nukhul formation in the Gulf of Suez Ricardo U. Oosthuizen, Ahmed Al Naqi, and Khalaf Al-Anzi, Kuwait Oil Co. Abstract B Oil Environment With Sand Screen: A E.R. Rangel-German, SPE, Natl. Autonomous U. of Mexico and Secretary o ï¿½ Abstract Many recent hydrocarbon discoveri Ana Marin, PDVSA, Onerazan Bornia, and Bruno Pinguet, Schlumberger Abstract The objective is to present accurately the Bruno PINGUET, Philippe PECHARD, Elsie GUERRA - SCHLUMBERGER, Abstract: Metering of bitumen produced by Steam H.A. Nasr-El-Din, M. Al-Anazi, and A. Al-Zahrani, Saudi Aramco, and Math Abstract Sandstone acidizing is very challenging b Vladislav Achourov, SPE, Schlumberger; German I. Kaledin, SPE, AchimgazAbstract Formation and fluids evaluation of hetero Suresh Kumar, Gujarat State Petroleum Co., and Sami Affes, IPM Schlumb Abstract Much work has already been undertaken P.D. Ting, SPE, and B. Dindoruk, SPE, Shell International E&P Inc., and J. Abstract Fluid properties descriptions are required Mike Parris, Andrey Mirakyan, Carlos Abad, Yiyan Chen, and Fred Mueller, Abstract The extent of crosslinking a polymeric fra C. Abad, A. Mirakyan, M. Parris, Y. Chen, and F. Mueller, Schlumberger Abstract The extent of crosslinking a polymeric fra H.A. Nasr-El-Din and A. Al-Zahrani, Saudi Aramco, and J. Still, T. Lesko, a Abstract Acid fracturing is the commonly applied s Nestor Molero, Sergio Garcia, and Eduardo Zavala, Schlumberger, and Javi Abstract In Pressure/HTemperature Environment Muhammad Shafiq, SPE, Schlumberger; Omar Al-Faraj, Adnan A. Al-KanaanAbstract This paper describes an innovative and r S. Jain, A. Prestridge, P. Dellorusso, and N.C. Nghi, Schlumberger, and D. Abstract This paper presents the results of proppe S.A. Ali, SPE, and C.W. Pardo, SPE, Chevron Energy Technology Co., and ZAbstract The wells in an oil field in East Venezue S. Ali, SPE, E. Ermel, SPE, and J. Clarke, SPE, Chevron; M.J. Fuller, SPE Summary Fluids based on chelating agents have Cristian Fontana and Enrique Muruaga, Tecpetrol S.A., and Daniel Perez, Abstract The San Jorge Basin is characterized by M.K.R. Panga and Y.S. Ooi, Schlumberger Well Services; P.L. Koh, U. Tekn Abstract This paper presents the development of S.G. Mathews and B. Raghuraman, Schlumberger; D.W. Rosiere and W. Wei Abstract This paper describes a new technique fo Alexander D. Wilson, SPE, Edo S. Boek, SPE, Hemant K. Ladva, SPE, and Abstract The aggregation and deposition of aspha M.L. Samuelson, SPE, T. Akinwande, SPE, and R. Connell, SPE, Schlumberg Abstract This paper describes an efficient multista Valdo Ferreira Rodrigues and Luis Fernando Neumann, Petroleo Brasileiro Abstract ThPermeability Carbonates Ahmed Aly, American University in Cairo-Schlumberger and Lee Ramsey, S Abstract As gas demand rises and operators turn Erik Borchardt, Schlumberger; Jessica Cavens and Craig Wieland, EnCana Introduction Unconventional tight gas reservoirs a S. Kuzmina, SPE, Rosneft, K.K. Butula, SPE, Schlumberger and A. Nikitin, Abstract Hydraulic fracture azimuthal orientation d Wenyue Xu, Joï¿½l Le Calvez, Marc Thiercelin, Schlumberger Abstract Large amount of gas are being produced Abu M. Sani, Sergey V. Nadezhdin, Ruben Villarreal, Thierry Chabernaud, Abstract Hydraulic fracture treatments are necess M. Bulova, SPE, K. Nosova, SPE, D. Willberg, SPE, and J. Lassek, SPE, S ï¿½ AbstraPermeability Tight Gas Formations Christian P. Veillette and Jerome J. Cuzella, Enduring Resources, and Fre Abstract The Edwards Limestone in South Texas Alberto Casero, SPE, ENI US; Loris Tealdi, SPE, ENI Congo; Roberto Luis Abstract During the past decade multiple transve Khay Kok Lee, SPE, Schlumberger, andï¿½Chunchun Xu, SPE, Gang Chen,Abstract Guang'an gas field in Sichuan Province Thanh Tran, CACT, China; David Barge, Saudi Arabian Texaco; and Stan In Abstract The Ratawi Oolite carbonate reservoir in F.O. Iwere, SPE, H. Gao, SPE, and B. Luneau, Schlumberger Abstract This paper presents a closed-loop reserv B. Cherian, SPE, A. Aly, SPE, S. Denoo, SPE, L. Maschio, SPE, and D. So Abstract In this paper we will present an integrate F.O. Iwere and J.E. Moreno, Schlumberger, and O.G. Apaydin, EOG Resou Summary This paper presents several workflows D.L. Fairhurst, SPE, Schlumberger; M.E. Semmelbeck, SPE, Escondido Reso Abstract Highly laminated tight gas sand sequenc John C. Rasmus, SPE, John P. Horkowitz, SPE, Thierry Chabernaud, SPE, Summary Th Predicting Permeabilit Bingjian Li, Schlumberger; Mishari Al-Awadi, Kuwait Oil Company;ï¿½Ch Abstract Evaluating natural fractures in tight carbo Moyosore Okuyiga, Ahmed Berrim, Ragab Shehab, ADMA-OPCO; Sammy Ha Abstract Wireline formation testing in low permeab Noureddine Bounoua, Sonatrach DP, and George Dozier, Philippe MontaggioAbstract A majority of the worldâ€™s oil and gas r R. A. Schrooten, BP America; E.C. Boratko, H. Singh, D.L. Hallford, Schlu Abstract Improving recovery in tight gas reservoirs R.A. Schrooten, BP America; E.C. Boratko, H. Singh, and D.L. Hallford, S Abstract Improving recovery in tight gas reservoirs Peter Weinheber and Edward Boratko, Schlumberger; Kilamba Diogo ContreAbstract The data provided by wireline formation t Hector Ruiz, SPE and Phil Poettmann, SPE, Schlumberger; Tatiana KryuchkSummary This paper presents a field-developmen Jason Baihly, Dee Grant, Li Fan, and Suhas Bodwadkar, Schlumberger Summary In general successful applications of h E. Sokolov, JSC Russneft, and G. Makarytchev and E. Troitskaya, Schlumb Abstract Yurubcheno-Takhomskaya oil and gas a H.J. de Koningh, SPE, and S.H. Al-Mahrooqi, SPE, Petroleum Developmen Abstract In a time of declining production and incr M.Tchambaz, SPE, Schlumberger Abstract High potential of tight sands (quartzitic sa

Chenggang Xian, Schlumberger; Ahmed Dawoud, ADCO; Andrew Carnegie,Abstract S In tight carbonate reservoirs several fact Hassan Chaabouni, SPE, Philippe Enkababian, SPE, and Keng Seng Chan,Abstract S Water production from gas producing we R.D. Tewari, SPE, and M. Malik, SPE, GNPOC, and S. Naganathan, SPE, Abstract Maximization of recovery from anisotrop C.H. Sia, SPE, Azhar M. Ali, SPE, and N. Ezalina Hamzah, SPE, PETRONAS Abstract This paper presents a case history of a s Lev Virine SPE, and Derek Murphy SPE, Schlumberger Ltd. Abstract Decision-making within the petroleum ind Lev Virine, SPE, Schlumberger Abstract Decision-making related to oil and gas e Saud Jumah, Khaled Saleh, and Haitham I. Al-Mayyan, Kuwait Oil Co., and Mi Abstract The objective of supplying real time LWD J. Ouzzane, M. Okuyiga, N. Gomaa, Adma Opco; R. Ramamoorthy, D. Rose,Abstract Capillary pressure curves are a fundame Lang Zhan, SPE, and Fikri Kuchuk, SPE, Schlumberger; S. Mark Ma, SPE, Abstract Cores open hole logs formation testers Christian Perrin/Schlumberger, Mohamad Rafiq Wani/KGOC, Mahmood Akba Abstract Electrofacies based on conventional logs Chandramani Shrivastva and Sanchita Ganguly, Schlumberger, and Zuber Abstract Establishing the depositional sedimentar Taofeek Ogunyemi, Philippe Montaggioni, SPE, and Ibtissam Boubakeur, ScAbstract The Triassic reservoirs of the eastern Sa C. Dong, SPE, and M. O'Keefe, SPE, Schlumberger; H. Elshahawi, SPE, and Summary Downhole fluid analysis (DFA) has eme Andry Halim, Pertamina, and Nicolas Orban, Elin Haryanto, and Cosan Aya Abstract Fluid identification is an important object Aditi Pal, Kapil Seth, and Udit Guru, Schlumberger, and R.R. Tiwari and D Abstract The petrophysical evaluation of carbona Varun Sharma, Sagnik Dasgupta, Arathi. L. Mahesh, and Sachin Sharma, Schl Abstract The Lower Tipam sandstone reservoir of Thomas J. Neville, SPE, Schlumberger; Geoff Weller, SPE, and Ollivier F Summary A new logging-while-drilling (LWD) tool E. Mirto, SPE, G. Weller, SPE, T. el-Halawani, SPE, J. Grau, SPE, M. Berheid Abstract Radioactive chemical logging sources h A. Mendoza, SPE, U. of Texas at Austin; D.V. Ellis, Schlumberger DollAbstract Many concerns have been expressed re Samiha S. El-Sayed, SPE, and Ahmed M. Daoud, Schlumberger, and El-Saye Abstract Quantifying the uncertainty in the volume Samiha S. El-Sayed, SPE, Cairo University Abstract ï¿½ Quantifying the uncertainty in the vo Asbjorn Gyllensten, Mohamed Ibrahim Al-Hammadi, Emhemed Abousrafa, AAbstract One of the top concerns for carbonate re Zohreh Movahed, Shahid Beheshti University Abstract The reservoir is composed of a mixture o N. Gomaa, A. Al-Alyak, D. Ouzzane, O. Saif, and M. Okuyiga, ADMA OPCO,Abstract This case study demonstrates a new me Michel Claverie, Steve Hansen, Saifon Daungkaew, and Zane Prickett, Schl Abstract Deepwater turbidite reservoirs are comp A.M. Daoud, SPE, M. Eisa, SPE, R. El-Mahdy, SPE, and M. Emam, SchlumbAbstract Specifying the perforation intervals and e R. Bastia, A. Tyagi, and K. Saxena, Reliance Industries Ltd. and T. Klimen Abstract Bed Petrophysical Analysis Chanh Cao Minh and Isabel Joao, Schlumberger, and Jean-Baptiste Cla Abstract Formation evaluation in thin sand-shale l S.M. Ma and A.A. Al-Hajari, Saudi Aramco, and P. Butt and S. Crary, Schlu ABSTRACT Formation evaluation (FE) of horizon Taofeek Ogunyemi, Philippe Montaggioni, SPE, Atmane Azzougen, SPE, andAbstract The economical viability of the Cambrian Richard R Jackson, Ilaria De Santo, Peter Weinheber, SPE, Schlumberger, Em Abstract Wireline formation testing (WFT) and flui Jiang YiMing, Sandeep Chakravorty, andï¿½J. Robert Marsden, Schlumber Abstract Renewed interest in fractures and faults i Kalyan Chakraborty and Mubarak Al-Hajeri, Kuwait Gulf Oil Co., and Jayant Abstract Stratigraphic trapping mechanism plays a Layla Saleh Al Muhairi, Maria Teresa Ribeiro, Agung Dharmawan, and Mo Abstract A Geological Model was built and an Unc Y. Z. Ma, SPE, Schlumberger; A. Seto, SPE, Pengrowth Corp.; and E. Gom Abstract As a branch of spatial statistics geostatis M. Claverie, Schlumberger; S. Aboel-Abbas, C.S. Mutiara; and H. Harfoush Abstract Thinly bedded reservoirs are increasingl C.C. Minh, Schlumberger, and P. Sundararaman, Chevron Abstract We use nuclear magnetic resonance (NM Aristides Orlandi Neto, SPE, and Dhruba Dutta, SPE, Schlumberger, and S Abstract As the global power scenario changes w G.A. Bordakov, A.V. Kostin, J. Rasmus, D. Heliot, SPE, Schlumberger;and Summary The paper illustrates the improvements Khalid H. Al-Azmi, SPE, Hamdah Al-Enezi, SPE, Rohitkumar Kotecha, and Abstract The Greater Burgan Field consists of thr Vasudev Singh, SPE, Nicolas P. Roussel, SPE, and Mukul M. Sharma, SPE,Abstract U The production and injection of fluids in a A. Abdulraheem, KFUPM, M. Ahmed and A. Vantala, Schlumberger, and T. Abstract Rock mechanical parameters of reservo Bikash Sinha, SPE, Tom Bratton, SPE, Jesse Cryer, Steve Nieting, Schlum Summary Highly depleted reservoirs exhibit sharp B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, SPE, Schlumberger Abstract This paper presents the results of an inv B.D. Poe Jr., SPE, W.K. Atwood, SPE, J. Kohring, SPE, and K. Brook, SPE Abstract This paper presents the results of an inv B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, SPE, Schlumberger Abstract This paper presents the results of an inv Pradyumna Dutta, Sunil Kumar Singh, and Jarrah Al-Genai, Kuwait Oil Co Summary The Najmah Sargelu and Marrat reser Essam A.E.A. Bassim and Kaoru Yamaguchi, Arabian Oil Company, Ltd., a Abstract The carbonate reservoirs in Gulf of Suez O. Pinous, Schlumberger; Abdel M. Zellou, Gary Robinson, and Ted Royer, Abstract The field is located in the southeastern p Sandeep Chakravorty, Schlumberger Middle East S.A.; Jean-Louis Lesueur, Abstract The oil-bearing Upper Jurassic Arab rese O. Pinous, Schlumberger; E.P.Sokolov and S.Y.Bahir, Russneft; Abdel M. ZeAbstract The Maloichskoe field is located in the s

Fikri Kuchuk, SPE, and Lang Zhan, SPE, Schlumberger; S. Mark Ma, SPE, Abstract In this paper we present a novel method Hussain A. Al-Jeshi, Charles Bradford, Saudi Aramco; Murat Zeybek, Schlu Abstract The process of defining the fluid and res Cosan Ayan and Mario Petricola, Schlumberger, and Philip Knight and BrunoAbstract Wireline Formation Tester (WFT) pretest Long Jiang and Keith Schilling, Schlumberger; Jim Logan, Chevron OffshoreAbstract Acoustic measurements have long been Omar Aguirre and Juan Carlos Glorioso, Repsol YPF, Jeannette Morales a Abstract We have validated with superior results t Chanh Cao Minh, Peter Weinheber, Wich Wichers, and Adriaan Gisolf, Schlumb Abstract One of the most important objectives of f M. Claverie, D. Maggs, and M. Van Steene, Schlumberger, and D. WestacottAbstract The analysis of shaly sand gas reservoir H.N. Bachman, SPE, S. Crary, SPE, R. Heidler, and J. LaVigne, SPE, Schl Abstract An ongoing challenge for nuclear magne Robert Freedman, Schlumberger Oilfield Services Distinguished Author Series articles are general d Franco Vittore and Javier Pompei, Repsol YPF, and Oscar Ortiz and Anthon Abstract Up to now different petrophysical method Ahmed S. Al-Muthana, SPE, and S.M. Ma, SPE, Saudi Aramco; M. Zeybek, Abstract Currently many of the producers are ho S. Al Arfi, ADCO, and D. Heliot, J. Li, X. Zhan, and D. Allen, Schlumberger Abstract A new methodology for porosity and perm Torsten Friedel, George Mtchedlishvili, Hans-Dieter Voigt, and Frieder Hï¿½ Summary Underbalanced drilling (UBD) is defined Taher El Gezeery, SPE, Kuwait Oil Company, Fawaz Al Saqran, Kuwait Oil Abstract The Minagish structure in southwest corn Hani Elshahawi, Shell; Lalitha Venkataramanan, Schlumberger; Daniel McK Summary Identifying compartmentalization and u Chengli Dong, SPE, Schlumberger; Hani Elshahawi, SPE, Shell; Oliver C Abstract Understanding reservoir architecture is c Soraya S. Betancourt, Francois X. Dubost, and Oliver C. Mullins, Schlumbe Abstract Compartmentalization is perhaps the sing B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, Schlumberger Abstract This paper presents the results of an inve Mike Burke, SPE, and M. Bremeier, SPE, Wintershall Libya; Mohamed Sheba Abstract Residual oil estimations are mainly based Nicolas Orban, Cosan Ayan, and Mario Ardila, Schlumberger Abstract Many sedimentary features of gas fields H. Elshahawi, Shell Intl. E&P Inc.; E. Donaghy and C. Guillory, Shell Oil C Abstract WBased Lithofacies Mapping Ayan C. and Achourov V., SPE, Schlumberger, Alpatov A., SPE, Sibneft-KhaAbstract Waterflood management requires the op R. Banerjee, SPE, R.K.M. Thambynayagam, SPE, and J. Spath, SPE, Schlum Abstract Interpretation of pressure transient tests E. Kasap, Schlumberger; G.J. Sanza, and M.I. Ali, Petronas Carigali; T. Fr Abstract A revised Field Development Plan (FDP) J.M. Muruais, SPE, Schlumberger, and A.A. Young, SPE, Anzon Australia Lt Abstract One of the challenges that operating com Mahmoud A. Wahba, Maharon Jadid, Ibrahim B. Subari, and M. Nazli B. AbuAbstract As production declines and watercut inc W. Gaviria, SPE, and J.G. Flores, SPE, Schlumberger, and J. Lorenzon, SPE, Abstract Breathing new life into a mature oil field G. Kartoatmodjo, R. Strasser, and F. Caretta, SPE, Schlumberger; M. Jadid Abstract Proper fieldwide production surveillance Phil Warran, SPE, Nidal Mishrafi, SPE, and Saleh M. Dossari, SPE, Saudi Abstract Saudi Arabia is blessed with the worldâ€ Abdel Nasser Abitrabi B., Ali Rabba, Waleed Amoudi, and Abdallah M. BehaiAbstract Targeting thin sand bodies while drilling a N. Behl, K.E. Kiser, and J. Ryan, Schlumberger IPM Abstract Production from low-pressure gas wells Torsten Friedel, Ramiro Trebolle, Stephen Flew, William Belfield, Juergen Abstract A novel workflow methodology that cove J. Moreno, A. Badawy*, G. Kartoatmodjo, H. AlShuraiqi, F. Zulkhifly, L. Ta Abstract Reservoir management is a standard ind A. Alvarez, E. Guerra, A. Gammiero, C. Velasquez, J. Perdomo, and R. H Abstract Pursuing new alternatives to develop an B. GÅ±yagÅ±ler, SPE, Chevron, and K. Ghorayeb, SPE, Schlumberger Abstract Field management (FM) is the simulation Fernando Gutierrez, Aron Hallquist, Mack Shippen and Kashif Rashid, Sch Abstract One of the most common methods of inc T. Friedel, SPE, Schlumberger; G.J. Sanza, M.I. Ali, and A. Embong, SPE, Abstract A reservoir simulation model calibrated w Antonio Cuauro, SPE, Schlumberger, Mohd Izat Ali, Maharon Bin Jadid, SP Abstract Betty is an oil field discovered in 1968 an E. Valbuena, J.L. Bashbush, and A. Rincon, Schlumberger Abstract Steam injection projects consume consid Emad Elrafie, Isabelle Zabalza-Mezghani, Tariq Abbas, Saudi Aramco, Yako Abstract Integrated reservoir studies aim at synerg ï¿½ystein Tesaker, Alf Midtbï¿½ ï¿½verland, and Dag Arnesen, StatoilHydr Abstract The objective of this paper is to highlight A. Howell, Schlumberger Information Solutions; M. Szatny, Aspen Technology Abstract Simulation technology from reservoir thr Fernando L. Morales and Juan Cruz Velï¿½zquez, Schlumberger, and Aar Abstract Traditionally in the upstream business op T. Graf, R. Dandekar, and C. Amudo, SPE, Schlumberger Abstract With multi-processor cluster computing Zhizhuang Jiang and Zhang Tao, ConocoPhillips, China Inc., and Khong Ch Abstract The China National Offshore Oil Corpora Jose G. Flores, SPE, and Jon Elphick, SPE, Schlumberger, and Francisco LAbstract The production of large volumes of water M.A. Al-Khaldi and E.O. Ghoniem, Al-Khafji Joint Operations, and A.A. Jam Abstract The gas lift by limited capacity of 25 M You Hongqing, Wei Ping, Tian Xiang, Xu Xiang Dong, Lian JiHong, Thanh TrAbstract The Huizhou 6S and 3S oil fields in the P G.C. Dozier, SPE, Schlumberger, and P. Giacon, SPE, Petroleum Develop Abstract This paper will illustrate the collaborative Li Fan, Ronald B. Martin, Baljit Sehbi, Keith W. Owen, W.K. Atwood, and J Abstract This paper presents a unique workflow fo M. Prange, SPE, Schlumberger-Doll Research; M. Armstrong, SPE, Cerna, Eco Abstract In conditions of high demand for rigs and

Raphael Altman, Paolo Ferraris, and Fabricio Filardi, Schlumberger Abstract This account describes how advanced w Ken Halward, Joe Emery, and Rod Christensen, Oilexco; Daniel Bourgeois aAbstract In 2006 Oilexco North Sea Limited deve N. Liu, Chevron ETC, and Y. Jalali, SPE, Schlumberger Abstract We present a methodology of converting M. Parker, Kerr McGee; R.N. Bradford, Callon Petroleum; and C. Corbett, Abstract Well placement decisions are routinely m Patrick W. von Pattay, SPE, Jeff Hamer, SPE, and Ralf Strasser, SPE, Sch Abstract This paper presents an innovative filterin G. Kartoatmodjo, C. Bahri,* A. Badawy,* N. Ahmad, J. Moreno, B. Wu, F. Zu Abstract Planning of infill drilling in oil rim reservo M.J. Zandvliet, SPE, M. Handels, SPE, G.M. van Essen, SPE, Delft UniversitSummary Determining the optimal location of wel M. Nukhaev, V. Pimenov, A. Shandrygin, and V. Tertychnyi, Schlumberger Abstract Steam chamber (SC) control during stea G. Busswell, SPE, R. Banerjee, SPE, R.K.M. Thambynayagam, SPE, and J.Abstract We present a set of new analytical solut J. Phillip Gilchrist, Geoff Busswell, Raj Banerjee, Jeff Spath and R.K. Mi Abstract We present new semi-analytical solutions A.M. Daoud, SPE, and L. Vega, SPE, Texas A&M U. Abstract Conditioning geologic models to product Ramez Azmy, SPE, Ahmed M. Daoud, SPE, Khaled A. Fattah, SPE, and M.H. Abstract Adjoint method-based sensitivity for field J.S. Al-Thuwaini, Saudi Aramco; G. Zangl, Schlumberger; and R. Phelps, S Abstract The study objective is to investigate the C. Amudo, Chevron Australia Pty. Ltd.; T. Graf, Schlumberger; N.R. Harris, Abstract With the increasing acceptance of stoch S. Yadav, Schlumberger Abstract This paper presents a novel methodolog Torsten Friedel, SPE, Schlumberger, and Hans-Dieter Voigt, SPE, Freiberg UAbstract T Sensitive Permeability Xundan Shi and Yih-Bor Chang, Chevron; Mathieu Muller and Eguono Obi, Abstract We describe the construction of a gener H. Cao and P.I. Crumpton, Schlumberger, and M.L. Schrader, Chevron En Abstract This paper describes a general formulati Y. Wang, SPE, J. Moreno, SPE, and J.H. Harfoushian, SPE, Schlumberger Abstract Horizontal wells often present a substan S. Mubarak, N.I. Al-Afaleg, and T.R. Pham, Saudi Aramco, and M. Zeybek a Abstract T Contact (MRC) Well Yuandong Wang, SPE, Dan Shan, SPE, and Robin N. Heim, SPE, SchlumbAbstract Horizontal and multi-lateral wells have be Ghazi D. Al-Qahtani, Emad A. Elrafie, Raja T. Abbas, Clara E. Ikuku, and Abstract The application of Complex Wells (CW) Nick Koutsabeloulis, SPE, and Xing Zhang, SPE, Schlumberger Reservoir Abstract The pore pressure stress state and geo C.K. Huang, Y.K. Yang*, M.D. Deo, University of Utah Abstract In a thermal-compositional reservoir sim Samuel Aderemi, SPE, and Kingsley Akpara, SPE, Schlumberger InformatioAbstract Decline curve analysis is a graphical pro R. Barati, SPE, University of Kansas; R.D. Hutchins, SPE, T. Friedel, SP Summary The fracture-propagation process perfo T. Friedel, Schlumberger Data & Consulting Services Abstract To exploit the substantial tight-gas resou Arash Soleimani, SPE, Schlumberger; Byung Lee, SPE, Saudi Aramco; andAbstract Horizontal wells with multiple fractures a O. Dinariev, IFZ RAS; A. Shandrygin, SPE, D. Rudenko, SPE, and V. Terty Abstract High accurate reservoir simulation is req H. Gu, SPE, E. Siebrits, SPE, and A. Sabourov, SPE, Schlumberger Abstract Interfacial slip is one of the mechanisms H. Sadrpanah, SPE, Schlumberger, and T. Charles and J. Fulton, Total E&P Abstract This paper presents explicit simulation H. Huang, Georgia Inst. of Technology, and J.A. Ayoub, Schlumberger Abstract Non-Darcy flow reduces the productivity o Leonardo Vega, Schlumberger, DCS Abstract Wells in tight gas reservoirs are often com B.D. Poe Jr., SPE, Schlumberger Abstract This paper presents the results of an inv Olivier Liï¿½tard, Consultant, and Jerome Maniï¿½re and Mark Norris, Sch Abstract The expansion of horizontal well technolo S.G. Cherny, V.N. Lapin, and D.V. Chirkov, Institute of Computational Te Abstract The goal of this paper is to investigate th D. Kaviani, SPE, Texas A&M U.; T.D. Bui, SPE, Schlumberger; J.L. Jensen*,Summary Artificial neural networks (ANNs) have b Majid Mohammadpour Faskhoodi*, SPE, Harun Ates, SPE, and Tono Soeriawina Abstract To predict future reservoir performance a Ahmed Daoud, SPE, Osama Hegazy, Yasser Hazem, Mohamed Lotfy, SamirAbstract Y Gas reservoirs in the Nile Delta of Egypt Guohua Gao, SPE, Chevron Corp.; and Younes Jalali, SPE, Schlumberger Summary This paper presents a mathematical mo J.J. Elphick, SPE, and L.J. Marquez, SPE, Schlumberger, andï¿½M. Amaya,Abstract Oil viscosities of about 2 cP and above ( T. Bui, SPE, Schlumberger; M. Bandal, SPE, and N. Hutamin, SPE, Petronas; Abstract In this paper we present the results of a Carlos A. Garcia and Jose R. Villa, U. Central de Venezuela Abstract Original Oil In Place (OOIP) calculations N. Belova and L. Berul, Schlumberger, and A. Sentyuriyev, NOVA TechnologIntroduction The main objective of the mature field Hadi Nasrabadi, Imperial College London, and Kassem Ghorayeb and AbbasSummary We present formulation and numerical C. Amudo, SPE, Chevron Australia Pty Ltd; T. Graf, SPE, and R. Dandekar Abstract With the dearth of easy oil in the industry Y. Wang, SPE, Schlumberger; M. Bandal, SPE, Petronas; J. Moreno, SPE, Abstract The Capillary-saturation function plays a R. Potsepaev, C.L. Farmer, and A.J. Fitzpatrick, Schlumberger Abstract This paper investigates the control volum D.Rudenko, A.Shandrygin and A.Zyryanova, SPE, Schlumberger Abstract The peculiarities of retrograde condensat C.A. Kossack, SPE, Schlumberger Abstract The presence of vugs in a naturally fract Satomi Suzuki, SPE, Stanford U.; Colin Daly, SPE, Schlumberger; Jef Caers,Summary The application of elastic stress simula

Kassem Ghorayeb, SPE, Manoch Limsukhon, SPE, Schlumberger, Qasem D Abstract The North Kuwait Jurassic Complex cons A. Kozlova, Schlumberger Moscow Research; F. Bratvedt, Schlumberger Inf Abstract Streamline methods as a reservoir simul Nikolay Andrianov, Kyrre Bratvedt, and Artyom Myasnikov, Schlumberger Abstract Naturally fractured reservoirs can be see J.R. Natvig and B. Skaflestad, SINTEFï¿½ICT; F. Bratvedt and K. Bratvedt, Abstract Advances in reservoir characterization a David O. Ogbe, SPE, Fabian O. Iwere, SPE, Linda Boukhelifa, SPE, Erni Abstract Conceptual models are used to solve spe Guohua Gao, SPE, Chevron Corp.; Mohammad Zafari, SPE, Schlumberger;Summary a The well known PUNQ-S3 reservoir mo G. Zangl, SPE, and T. Graf, SPE, Schlumberger, and A. Al-Kinani, SPE, Min Abstract Proxy models are becoming more widel Tharwat Fawzy, Schlumberger, and Eric Mackay, Heriot-Watt University Abstract Inorganic scales precipitate in oilfield sys Adriaan GISOLF, Francois DUBOST Julian ZUO, Schlumberger, Stephen Abstract The increasing complexities of newly disc K. Gonzalez, J.L. Bashbush, and A. Rincon, Schlumberger Abstract Steamflood with conventional vertical we Nikolay Andrianov and Kyrre Bratvedt, Schlumberger Abstract Streamline methods have become an eff Olga Podgornova, Artyom Myasnikov, and Kyrre Bratvedt, Schlumberger; Abstract One of the most challenging problems fo A. Al-Kinani, G. Nunez, M. Stundner, G. Zangl, and O. Iskandar, SPE, Sch Abstract This paper discusses a new workflow to Mohammad Zafari, SPE, Schlumberger; and Albert C. Reynolds, SPE, U. of Summary Recently the ensemble Kalman Filter ( S. Yadav, Schlumberger, and S.L. Bryant and S. Srinivasan, U. of Texas at Abstract This paper presents a novel approach to K. Neylon, SPE, Schlumberger; E. Reiso, StatoilHydro ASA; J.A. Holmes, Abstract We present a model for well inflow contr Kassem Ghorayeb, SPE, and Jonathan Holmes, SPE, Schlumberger Summary Black-oil reservoir simulation still has w Kassem Ghorayeb, SPE, and Manoch Limsukhon, SPE, Schlumberger, and Abstract The North Kuwait Jurassic Complex (NK Bernard Montaron, SPE, Schlumberger Abstract Reservoir rock wettability is an important Kaibin Qiu, Schlumberger; Yousef Gherryo and Mohamed Shatwan, AGOCOAbstract ( An experimental study was conducted on H. Huang, SPE, and J. Ayoub, SPE, Schlumberger Abstract The subject of non-Darcy flow in hydraul A.J.G. Carnegie, Schlumberger Abstract Worldwide carbonate oil-water transitio J. Capps and R. Khamatdinov, Margham Dubai Establishment; and S. ShayeAbstract The Margham gas field discovered in the Dhruba J. Dutta, SPE, Ahmed Abu El Fotoh, and Dedi Juandi, Schlumberge Abstract Borehole instability in most of the cases R. Murray, SPE, BP Exploration; C. Edwards, SPE, Shell; K. Gibbons, SP Abstract This paper summarizes the findings of t A.N. Shandrygin, SPE, Schlumberger, and A. Lutfullin, State Commissio Abstract Russia is one of the main oil producing c J.A. Walker, SPE, ConocoPhillips Alaska Inc.; D.O. Ogbe, SPE, Schlumberge Abstract Alaskaâ€™s North Slope and the United Simon James, SPE, and Linda Boukhelifa, SPE, Schlumberger Summary Over the past 10 years several papers M. Claverie, SPE, Schlumberger; N.A. Malek, SPE, Petronas Carigali; and Abstract After more than 20 years of exploitation Jeffrey Grant, Dale May and Keith Pinto, Schlumberger Abstract Pulsed neutron measurements have bee M. Van Steene, SPE, B. Herold, SPE, D. J. Dutta, SPE, Y. Abugren, S. Hos Abstract Accurate time-lapse saturation informatio M. Zakharov, Schlumberger; S.H. Eriksen, Hydro Oil & Energy; and I. Raw, Abstract During the last decade intelligent well co Koksal Cig and Ihsan Gok, Schlumberger Abstract The new production logging tool string a D.E. Fitz, ExxonMobil Upstream Research Co.; Angel Guzmï¿½n-Garcia, Exx Abstract Production logging and flow profile interp B.C. Theuveny, P.D. Maizeret, N.S. Hopman, and S. Perez, Schlumberger Oil Abstract The identification of condensate banking K.D. CONTREIRAS and F. VAN-Dï¿½NEM, Sonangol P & P; P. WEINHEBER, Abstract The combination of low permeability oil b K.D. Contreiras and F. Van-Duinem, Sonangol P & P; P. Weinheber, A. GisolAbstract The combination of low permeability oil b Abdullatif Al-Omair, SPE, Orji O. Ukaegbu, SPE, and Muhammed Alshafie, Abstract This paper describes an innovative Dow B. Raghuraman, SPE, and M. O'Keefe, SPE, Schlumberger; K.O. Eriksen, SP Summary A new downhole pH sensor has been d R.A. Holicek, J. Adachi, L.A. Viloria, A.I. Mese, and Y. Traore, Schlumberg Abstract With increasing availability of real-time do Leo Eisner, Schlumberger Cambridge Research; Tomas Fischer and ZuzanaAbstract A multistage hydraulic fracture treatment George C. Dozier, Schlumberger Abstract Fracture height prediction and evaluation A. Al-Behair, Saudi Aramco, S. Malik and M. Zeybek, Schlumberger, A. Al-H Abstract Accurate diagnostics of wellbore fluid ent P. Krawchuk, SPE, and M.A. Beshry, Total E&P Canada, and G.A. Brown, Abstract During the start-up and early operation o B.D. Poe Jr., SPE, and R.J. Butsch, SPE, Schlumberger Abstract This paper addresses some recent deve B.D. Poe Jr. and R.J. Butsch, Schlumberger Abstract This paper presents some recent develop H. Huebsch, M. Moss, and T. Trilsbeck, EnCana, and G. Brown, S. Rogers, Abstract Fiber-optic systems are able to generate Ali Bakhshi, SPE, Woodside Energy Ltd; Peter Scaife, Tracerco; and Ian M Abstract This paper presents the first case study M. Webster, SPE, and S. Richardson, SPE, BP Exploration; C. Gabard-Cuo Summary Flow rate and fluid type (phase) are two Hassan Bahrami, Sharif University of Technology; Jamal Siavoshi, Husky Abstract Fractures identification is essential durin Chen Jiun Horng @ Chris; Norbashinatun Salmi Nordin; M Azrul Nuriyadi; 0

Michael Stundner and Gustavo Nunez, Schlumberger, and Frank Mï¿½ller NiAbstract The availability of accurate performance K. I. Ojukwu, M.I. Khalil, J. Clark, H. Sharji, Petroleum Development Oman Abstract Production logging low flow rate wells is Anil Ambastha, SPE, Chevron; Qasem Dashti, SPE, Kuwait Oil Company; PiAbstract The Wara reservoir has been producing f P.E. Parta, SPE, A. Parapat, R. Burgos, SPE, J. Christian, SPE, and A. J Abstract In this paper we present a field example K.M. Hanafy, SPE, GUPCO, and T.A. Elsherif, SPE, Schlumberger Abstract With the dramatic increase in oil prices H. Elshahawi, SPE, M. Hashem, SPE, and D. McKinney, Shell International Summary Modern wireline formation testers (WFT G.A. Brown, SPE, Schlumberger Abstract Early identification of differential depletio S.C. Maxwell , J. Du, J. Shemeta, U. Zimmer, N. Boroumand, and L.G. Griff Summary A combination of microseismic and surf I.D. Pinzon, SPE, J.E. Davies, SPE, BP, F. Mammadkhan, SPE, and G.A. Abstract BP is developing its Azeri field using dev S. Mackay, SPE, J. Lovell, SPE, D. Patel, SPE, F. Cens, SPE, and S. Esca Abstract The expense of subsea well intervention Bingjian Li1, Hamad Najeh2, Jim Lantz3, Mansoor Ali Rampurawala4, Ihs Abstract One of the key issues in creating a good B. Theuveny, A. Kosmala, P.-D. Maizeret, and R.K. Sagar, Schlumberger OilfAbstract A A Virtual Dream or Reality? The Case M. Stundner, SPE, and G. Nunez, SPE, Schlumberger Abstract The availability of accurate production vo O. Ojonah, SPE, Shell Production and Development Co., and J.J. Kohring, Abstract Maximising the potential of a producing w P.J. Gauthier and H. Hussain, Petroleum Development Oman; J. Bowling, B Abstract The paper presents a novel logging appr Dhruba J Dutta, SPE, Schlumberger and Abdallah B Badr, SPE, Agiba Pet Abstract Improvement of oil recovery and reductio M. M. Amer, O. Al-Farisi,T. Hiraiwa, M. Attia, A. Al-Habshi, SPE, ADMA-OP Abstract For pressure maintenance purpose perip Zahid Bhatti, Mohamed Shuaib, ADCO, Michael Wilt, Cyrille Levesque, Sc Abstract In the paper we will briefly review the pil Malalla Al Ali, Volker Vahrenkamp, Saber Elsembawy, and Zahid Bhatti, AD Abstract Time-lapse cross-well electromagnetic (E P.M. Snider, SPE, Marathon Oil Co.; I.C. Walton, SPE, Schlumberger; T.K Summary Worldwide Coal Bed Methane (CBM) re Mohammad Ali (ONGC), Arpana Sarkar (Schlumberger), Rajiv Sagar (Schlum Abstract Fracture systems comprise the primary f T.N. Olsen, T.R. Bratton, A. Donald, R. Koepsell, and K. Tanner, Schlumber Abstract Propped hydraulic fracture stimulation ha A.A. Ketter and J.R. Heinze, Devon Energy, and J.L. Daniels and G. Water Summary The Barnett shale is an unconventiona R. Suï¿½rez-Rivera, SPE, and S.J. Green, SPE, TerraTek Inc.; J. McLennanAbstract Hydraulic fracturing is the requisite meth Abbas Mahdi, Schlumberger; Mike Yu, EnCana Corp.; and Doug Pipchuk, CAbstract Nitrogen coiled tubing fracturing is the pr G. Waters, SPE, Schlumberger; J. Heinze, SPE, R. Jackson, SPE, and A. K Abstract Horizontal wells represent a growing per C. Du, SPE, X. Zhang, SPE, B. Melton, D. Fullilove, B. Suliman, SPE, S. G Abstract The Mississippian Barnett Shale reservo F. Akram, SPE, Schlumberger Canada Ltd. Abstract Estimated at 2.5 trillion barrels Canada h Creties D. Jenkins, SPE, DeGolyer and MacNaughton, and Charles M. BoyeDistinguished Author Series articles are general d D.I. Potapenko, S.K. Tinkham, B. Lecerf, C.N. Fredd, M.L. Samuelson, M.R.Abstract Gas production from the unconventional F.F. Chang, SPE, and M. Abbad, Schlumberger Abstract The chemical nature of carbonate rocks Ahmed R. Al Zahrani, SPE, Redha H. Al-Nasser, SPE, and Timothy W. Col Abstract The Electrical Submersible Pump (ESP) F. Gaviria, SPE, SUNCOR, and R. Santos, SPE, O. Rivas, SPE, and Y. Luy Abstract The need for high-temperature electric s Siddhartha Gupta, Schlumberger Abstract Artificial lift systems are now being consid Sergey Ryzhov, SPE, Vladimir Malyshev, SPE, Shlumberger, and Tatyana K Abstract The Sporyshevskoye oil field developme A. Calderon, SPE, A.F. Aragï¿½o, SPE, and C.M. Chagas, SPE, PETROBR Abstract The offshore northeast Brazil Manati fiel Gary Rytlewski, Schlumberger Abstract A new method of completing multiple-laye Surej Subbiah/Schlumberger; Wielemaker.E/Schlumberger; Joia P/Petrom Abstract Cartojani is a mature oil field with deplet B.D. Poe Jr., SPE, Schlumberger Abstract This paper presents the results of an inv B.D. Poe Jr., SPE, Schlumberger Abstract This paper presents the results of an inv M. Kabir, KOC; S. Ingham, Schlumberger; D. Sibley, K. Osman, A.K. Amba Abstract Mauddud reservoir in the Greater Burgan Liu Song, Li Jianping, and Lv Dingyu, CNOOC, and Jeffrey Kok and Shim Abstract The lower Minghuazhen is a shallow-wa S.M. Mubarak, T.R. Pham, and S.S. Shamrani, SPE, Saudi Aramco, and M. Abstract This paper describes a case-study detail T.S. Ramakrishnan, Schlumberger-Doll Research Summary Poor displacement efficiency in hydroca S.M. Mubarak, T.R. Pham, and S.S. Shamrani, SPE, Saudi Aramco, and M. Summary This paper describes a case study that Jose R. Amorocho, J. Ricardo Solares, Abdulmohsin Al-Mulhim, and Ali Al Abstract The number of multilateral gas producer Mohammed M. Amro, SPE, and Mohamed S. Benzagouta, SPE, King Saud Abstract Univ Current drilling technology is moving tow J. Jaua and O. Rivas, SPE, Schlumberger, and A. Mejï¿½as, Repsol YPF Abstract As a result of the increasing emphasis o W.J. Bailey, SPE, Schlumberger-Doll Research; I.S. Weir, U. West of Eng Summary A rigorous statistical methodology using F.O. Garzon, H.M. Al-Marri, J.R. Solares, and C.A. Franco Giraldo, SPE, Abstract Acid Fracturing has been a successful m Tim S. Schneider, David O. Uldrich, and Richard Hodge, ConocoPhillips Co Abstract The Alpine field located on the North Slop

A. Powell, Headington Oil Co., O. Bustos, W. Kordziel, T. Olsen, D. Sobern Abstract Since the horizontal lateral Bakken dolom D. Oussoltsev, SPE, K. K. Butula, SPE, and A. Klyubin SPE, Schlumberger, Abstract Successful hydraulic fracturing in various Maytham I. Al-Ismail, SPE, Moataz M. Al-Harbi, SPE, and Abdulaziz K. A Abstract Acid fracturing has been part of Saudi Ar S. Sitdikov, SPE, A. Serdyuk, and A. Nikitin, SPE, Rosneft, and A.Yudin, Abstract This paper describes successful implem Paul R. Howard, Sumitra Mukhopadhyay, Nita Moniaga, Laura Schafer, Sc Abstract Flowback aids are usually surfactants or Hongren Gu, SPE, and Eduard Siebrits, SPE, Schlumberger Summary Much study has been conducted on the Daren Bulat, SPE, Talisman Energy Inc., and Yiyan Chen, Matthew K. Gra Abstract Natural gas reservoir development contin S.M. Rimassa, SPE, P.R. Howard, SPE, and K.A. Blow, SPE, SchlumbergerAbstract As mature fields produce larger quantities Bilu Cherian, SPE, Schlumberger; Kirk Fields, SPE, and Seth Crissman, SP Abstract The key to the success of a tight-gas fiel O. Hidalgo, Schlumberger Well Services; O. Gonzï¿½lez and V. Gonzï¿½le Abstract Frac-pack is a pervasively used complet A.V. Yudin and K.K. Butula, Schlumberger, and Y.V. Novikov, OAO Tomskne Abstract The productive pay of the low permeabilit Majdi Al Mutawa, SPE, Bader Al Matar, SPE, and Yousef Abdul Rahman, SPAbstract In the recent years horizontal well techno R. Arangath, SPE, Schlumberger, and J.F. Obamba, SPE, P. Saldungaray, Abstract A common scenario in many mature oil Pedro Saldungaray, Schlumberger; Efrain Huidobro Salas, Pemex; Sebast Abstract Latin America hasnâ€™t escaped the ge Alberto Casero, SPE, and Giamberardino Pace, SPE, Eni E&P; Brad MaloneAbstract Many West Africa offshore fields are mat J.R. Solares, SPE, C.A. Franco, SPE, H.M. Al-Marri, SPE, and H.A. Al-J Abstract One of the key strategies in Saudi Aramc Tomislav Bukovac, Rafik Belhaouas and Daniel Perez, SPE, Schlumberger; Abstract Offshore operations are extremely expen Tomislav Bukovac, Rafik Belhaouas and Daniel Perez, SPE, Schlumberger; Abstract CuFree Fluid System, Executed from a S Rajiv Sagar, Schlumberger; A.K. Pandey, Durga Prasad, A.K. Vinod ONGC, Abstract Gandhar is one of ONGCâ€™s major bro B.D. Poe Jr., SPE, Schlumberger, and J.F. Marique, SPE, Consultant Abstract This paper presents the results of an inv T.N. Olsen, T.R. Bratton, and M.J. Thiercelin, Schlumberger Abstract Since the widespread proliferation micro A.N. Parfenov, SPE, S.S. Sitdikov, SPE, O.V. Evseev, SPE, and V.A. Shash Abstract The majority of hydraulic fracturing work George Waters, Barry Dean, and Robert Downie, Schlumberger, and Ken KeAbstract Hydraulic fracturing of horizontal wells in G. Rytlewski and J. Lima, Schlumberger, and B. Dolan, Petrogulf Abstract A new method of completing multiple laye G.L. Rytlewski and J.M. Cook, Schlumberger Abstract A new method of completing multiple-lay Olga Alekseenko, Schlumberger Abstract Petroleum engineers have faced the pro P.F. Sullivan, B. Gadiyar, R.H. Morales, R. Hollicek, D. Sorrells, and J. Le Abstract Visco-Elastic Surfactant (VES) fluids are M.E. Semmelbeck, W.E. Deupree, and J.K. von Plonski, SPE, Escondido Resou Abstract A novel carbon dioxide- (CO2-) emulsifi Vibhas J. Pandey and Tarik Itibrout, SPE, Schlumberger; Larry S. Adams, Abstract This paper discusses the selection criter P. Parra, E. Miquilena, A. Sï¿½nchez, and A. Peï¿½a, Schlumberger Well Abstract T Permeabili Generation Viscoelastic Flu Areiyando Makmun, Schlumberger, and Fathi Issa and Gadalla Hameed, Si Abstract Offshore A drilling program on North Rag Qasem Dashti, SPE, Mir Kabir, SPE, Raju Vagesna, SPE, Feras Al-RuhaimaAbstract This paper presents the process of candi J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. Van der Bas, SP Abstract It is well documented in the literature tha Jason Baihly, Schlumberger; Andrew Coolidge and Steven Dutcher, Devon; aAbstract Microseismic hydraulic fracture monitorin Torsten Friedel, George Mtchedlishvili, Aron Behr, Hans-Dieter Voigt, and Fr Abstract Productivity impairment in tight-gas forma P. Bulant, Charles U.; L. Eisner, Schlumberger Cambridge Research; I. PÅ Summary Significant errors in the calculated azim M.N. Bulova, SPE, A.N. Cheremisin Jr., SPE, K.E. Nosova, SPE, J.T. Lasse Abstract Permeability Formations C. Malagon, SPE, M. Pournik, SPE, and A.D. Hill, SPE, Texas A&M UniversiSummary In an acid-fracturing treatment fracture A. Nikitin and A. Shirnen, Rosneft, and J. Maniere, Schlumberger Abstract The generalization of Hydraulic fracturing R.R. McDaniel, SPE, and J.F. Borges, SPE, Hexion Specialty Chemicals, a Abstract For years radioactive tracers have been Alexey Nikitin, SPE, Rosneft-Yuganskneftegaz; Alexey Yudin, SPE, SchlumbAbstract The focus of our research is on a remote Y. Shumakov, A.A. Burov, and K.K. Butula, SPE, Schlumberger, and I.A. Abstract Though there are many proven ways of A.H. Akram, SPE, and A. Samad, SPE, Schlumberger Abstract A study was carried out to forecast the p V.M. Entov, Inst. for Problems in Mechanics, Russian Academy of Scienc Abstract Pressure distribution at the tip of a hydra H.A. Nasr-El-Din, SPE, S. Al-Driweesh, SPE, and K. Bartko, SPE, Saudi A Abstract The deep tight carbonate formations in J.F. Manrique, SPE, Occidental Oil and Gas Corp., and B.D. Poe Jr., SPE, Abstract This paper presents the results of an inv S.C. Maxwell, U. Zimmer, R. Gusek, and D. Quirk, Pinnacle Technologies Summary Microseismic imaging of a hydraulic-fra G.R. Aidagulov and M. Thiercelin, Schlumberger, and V.N. Nikolaevskiy, S.MAbstract Proppant flowback is an extremely impor X. Weng and E. Siebrits, Schlumberger Abstract In this work the propagation of an orthog Smirnov N.N., Kisselev A.B., Nikitin V.F., and Zvyaguin A.V., Moscow M.V. Abstract The practical problem arises in enhancin A. Nikitin and A. Pasynkov, Rosneft YNG, and G. Makarytchev, J. Maniere Abstract In a waterflooded reservoir hydrocarbon

J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. van der Bas, SP Abstract This paper summarizes part of the resu Tamara Webb, Jusni Omar, Murphy Oil Corporation, Saifon Daungkaew, LeeAbstract Kikeh Field is a deepwater project locate Almeida, C.M.C. de, Schlumberger; Melo, R.L.C., Petrobras; Holzberg, B. Abstract Hydraulic fracturing plays a very importa R.G. Jeffrey and X. Zhang, SPE, CSIRO Petroleum, and M. Thiercelin, S Abstract Offsets along the hydraulic fracture path Adam Vasper, SPE, Schlumberger Summary The terms auto natural and in-situ gas S.D. Cooper, S. Akong, K.D. Krieger, A.J. Twynam, F. Waters, and R. Morris Abstract BP Trinidad and Tobago (bpTT) has been K. M. Al-Naimi, SPE, B. O. Lee, SPE, K. M. Bartko, Saudi Aramco, S. K. Ke Abstract Horizontal completion technology has pro K. M. Al-Naimi, B. O. Lee, S. M. Shourbagi, Saudi Aramco, S. K. Kelkar, M Abstract Horizontal completion technology has pro Hassan Chaabouni, Schlumberger, Pierre Baux, Dasa Manalu, Muhammad So Abstract Completing horizontal wells with openhol Muhammad Shafiq and Athar Ali, SPE, Schlumberger; and Haider Al-Haj, Abstract This paper describes an innovative comp E. Davila, R. Almeida, I. Vela, J. Pazos, and K. Coello, Petroamazonas;ï¿ Abstract Horizontal wells are superior in productio M.A. Ali, SPE, and M. Shafiq, SPE, Schlumberger Abstract Intelligent completions have been in com Mohammed A. Abduldayem, SPE, Saudi Aramco, Muhammad Shafiq, SPE, Abstract Sch This paper describes an innovative comp E.A. Addiego-Guevara, SPE, and M.D. Jackson, SPE, Department of Earth Abstract Significant challenges remain in the deve L. Casas and J.L. Miskimins, Colorado School of Mines, and A. Black and S Abstract The design and subsequent results of a R. North, SPE, C.P. Lenn, SPE, and I. Stowe, SPE, Schlumberger Abstract A new processing workflow has been en Saifon Daungkaew, Michel Claverie, Boon Cheong, Steve Hansen, Richar Abstract As the cost of exploration wells continue M. A. Mohiuddin, Schlumberger, M. M. Najem, Y. R. Al-Dhaferi, H. A. BajunaiAbstract Sanding problems are often observed in Kirk M. Bartko, Saudi Aramco, and Frank F. Chang, Larry A. Behrmann, and Abstract It is well known that in cased-hole compl Achille Tiribelli, Giovanni Luca Minneci, and Ahmed Daoud, Groupement Abstract The transition from completion to produc M.I. Omar, SPE, A. Md Ali, SPE, and Z. Ali, Petronas Carigali Sdn. Bhd., Abstract Coiled tubing has been widely used worl M. Medina, SPE, Helix RDS; G. Morantes, SPE, and J. Morales, PDVSA; a Abstract Located in Eastern Venezuela the Santa Italo Pizzolante, Steve Grinham, Tian Xiang, and Jihong Lian, CACT Oper Abstract China National Offshore Oil Corporation Cesar Gama, David Gerez, and Paul A. Babasick, SPE, Schlumberger, and Abstract Fracturing is an important technique for s Al-Marri Faisal and Hassan Ibrahim Khalil, ADMA-OPCO, and Alan Salsma Abstract A major challenge identified by ADMA OP Lang Zhan, SPE, Fikri Kuchuk, SPE, Jim Filas, SPE, Dhani Kannan, SPE, Abstract Reliable estimates of post perforation da Graeme Rae, Mohd. Bakri Yusof, and Juanih Ghani, Talisman, and Shahril Abstract In Malaysia coiled tubing (CT) conveyan C. Han, Michael H. Du, and Ian C. Walton, SPE, Schlumberger Abstract A detonated shaped charge fired from a p Hanaey Ibrahim, SPE, and Sameer Balushi, Petroleum Development Oman,Abstract Well productivity is driven by establishing D.C. Atwood, SPE, W. Yang, SPE, B.M. Grove, SPE, L.A. Behrmann, SPE; Abstract We report on a series of laboratory flow e Hanaey Ibrahim SPE, Ali Harrasi, Petroleum Development Oman, Alan Sal Abstract Optimal well productivity is achieved by e Mohammad S. Al-Shenqiti, Alaa A. Dashash, Ibrahim H. Al-Arnaout, Saad MAbstract Saudi Aramco's drilling strategy witnesse C.A. Pedroso, SPE, E.M. Sanches, and N.S. Oliveira, Petrobras, and I.J. Abstract The Campos Basin in Brazil is one of the Luke F. Eaton, SPE, and W. Randall Reinhardt, SPE, ConocoPhillips; J. S Summary ConocoPhillips is developing the Magn Ibrahim Refai, SPE Saudi Aramco, Anwar Assal, SPE Schlumberger, Jere Abstract A number of the wells reach there econom George Colwart, SPE, Robert C. Burton, SPE, Luke F. Eaton, SPE, and R Summary ConocoPhillips is developing the Magn I.O. Yahaya, A. Opusunju, B. Ajaraogu, G. Agbogu, O. Williams, and C. U Abstract Alpha field is situated in SPDCâ€™s OM Brian T. Wagg, SPE, and Jonathan L. Heseltine, SPE, C-FER Technologies Abstract Several operators have recently launched Matthew Law, George W. Chao, Hafeez Ab Alim, and Elsamma Samuel, SchlAbstract The major trend of completion method in Kevin Whaley, Colin Price-Smith, Allan Twynam, and David Burt, BP ExploratAbstract Initial Open Hole Gravel Pack (OHGP) co Ina H. Stroemsvik, Kjell Tore Nesvik, SPE, Frode Vik, and Karin Stene, S Abstract Well Heidrun A-45 located in the Norwe A. Zanchi, Stogit; G. Ripa, M. Colombo, and G. Ferrara, SPE, Eni E&P; and Abstract One of the major challenges in undergro M. Tolan, BG Group, and R.J. Tibbles, J. Alexander, P. Wassouf, L. Schafer Abstract Openhole gravel packing is one of the m Samyak Jain, SPE, Rajesh Chanpura, SPE, Renato Barbedo, and Marcos Abstract Gravel packing has routinely been used E.P. Ofoh and M.E. Wariboko, Nigerian Petroleum Development Co., F.E. UwAbstract A large majority of the recent deepwate Samyak Jain, SPE, Raymond Tibbles, and Jock Munro, SPE, Schlumberger,Abstract Cased-hole gravel packing is commonly Shahryar Saebi, SPE, Samyak Jain, SPE, Raymond Tibbles, SPE, and Joc Abstract Cased-hole gravel packing is commonly J. S. Andrews, SPE, H. Bjï¿½rkesett, SPE, J. Djurhuus, StatoilHydro; I. C Abstract Gjï¿½a is an oil and gas field located off S. Wibawa, S. Kvernstuen, Schlumberger, and A. Chechin, J. Graham, and Abstract This paper presents the first installation M.R. Wise and R.J. Armentor, Chevron, R.A. Holicek, B.R. Gadiyar, M.D. Abstract Screenless sand control completions pro B. Vidick, SPE, S. James, SPE, and B. Drochon, SPE, Schlumberger Abstract The search for a cost-effective alternativ

K. Qiu, SPE, Schlumberger; Y. Gherryo and M. Shatwan, SPE, AGOCO, LibyAbstract Sand production from the Sarir field beca K. Qiu, J.R. Marsden, J. Alexander, and A. Retnanto, Schlumberger, and This paper was also presented as SPEï¿½100948 Ahmed Abulsayen and Abdulwahab Enneamy, VEBA (Libya), and Kaibin Qi Abstract This paper described a case study involv Bailin Wu, SPE, and Chee P. Tan (Now with Schlumberger Oilfield Support Summary It is commonly acknowledged in the pe Abdullah Kasim, SPE, Petronas Carigali; and Frank Wijnands, SPE, and S Summary Although the stacked reservoirs of the B J. Heiland, SPE, and M.E. Flor, Schlumberger Abstract During production of hydrocarbons the B. Wu, SPE, CSIRO Petroleum; Nulwhoffal Arselan Mohamed, SPE, Petronas Abstract This paper presents a geomechanical st Hisham A. Nasr-El-Din, SPE, Saudi Aramco, and Mathew Samuel, SPE, SchSummary Viscoelastic surfactant systems are use M. Pournik, C. Zou, C. Malagon Nieto, M.G. Melendez, D. Zhu, and A.D. Hi Abstract The effects of acid solutions injected into G. Zaeff and C. Sievert, SPE, ConocoPhillips, and O. Bustos, SPE, A. Galt Abstract The goal of an acid fracture treatment is J. Ricardo Solares, SPE, J.J. Duenas, SPE, Moataz Al-Harbi, SPE, Abdul Abstract Acid fracturing has been an integral part J. Ricardo Solares, SPE, Moataz Al-Harbi, SPE, Abdulaziz Al-Sagr, SPE Abstract Acid fracturing has been an integral part M.A.P. Albuquerque, SPE, Schlumberger; A.G. Ledergerber, SPE, Chevron; Abstract Between December 2003 and February B. Lungwitz, SPE, Schlumberger; R. Hathcock, SPE, K. Koerner, SPE, D. Byr Abstract The Macaï¿½ formation (Cretaceous ag Hai Liu, SPE, Chad Coston, and Mohamed Yassin, SPE, Schlumberger; ShaSummary Effective matrix acidizing in Kuwaitâ€™ Yin-Chong Yong and Karim Saaikh, Brunei Shell Petroleum; Joao Queiros Abstract Improving oil and gas production from th H.A. Nasr-El-Din, SPE, and M. Zabihi, SPE, Saudi Aramco, and S.K. Kelka Abstract In treating sour water injectors in carbon R. Arangath, SPE, Schlumberger; K.W. Hopkins, Aral Petroleum Capital; D Abstract Stimulation of carbonate reservoirs is ofte F.F. Chang, SPE, Schlumberger; H.A. Nasr-El-Din, SPE, Texas A&M UniversiAbstract Hydrochloric acid is the most commonly u Surajit Haldar, SPE, Ahmed A. Al-Jandal, SPE, Saad M. Al-Driweesh, Mufe Abstract The Uthmaniyah field is one of the bigges Rafael Rozo, SPE, and Javier Paez, Petrominerales; Alberto Mendoza, SPEAbstract The Caballos formation is thick laminate Rafael Rozo and Javier Paez, Petrominerales; Alberto Mendoza, Ecopetrol; Abstract The Orito field in the south of Colombia w Frank F. Chang and Xiangdong Qiu, Schlumberger, and Hisham A. Nasr-El- Abstract The purpose of matrix treatments in carb D. Oussoltsev, I. Fomin, K.K. Butula, and K. Mullen, SPE, Schlumberger, andAbstract The majority of oil exploited from Russia Murtaza Ziauddin, SPE, and Emmanuel Bize, SPE, Schlumberger Abstract Most carbonate reservoirs are heterogen L.P. Moore, SPE, and H. Ramakrishnan, SPE, Schlumberger Abstract Restimulation of existing wells represents O. Bustos, Y. Chen, M. Stewart, K. Heiken, and T. Bui, Schlumberger, and P Abstract CO2 based fluids are commonly used to K. Hughes and N. Santos, SPE, Chevron, and R.E. Arias and S.V. Nadezhd Abstract Historically carbon dioxide (CO2)â€“foa S.A. Utegalyev and S.K. Duzbayev, KazMunaiGas RD, and K. Kulbatyrov a Abstract Well stimulation techniques like hydrau Mohan K.R. Panga andï¿½Suzylawati Ismail, Schlumberger Well Services; Abstract Water blocks and condensate drop out n Majdi Al Mutawa, Bader Al Matar, SPE, and Abdulaziz Abdulla Dashti, SP Abstract Dual completed wells producing from the Douglas Boyd, Salah Al-Kubti, Osama Hamdy Khedr, Naeem Khan, and KholAbstract Two classes (sonic and ultrasonic) of cem N.M.A. Rahman, SPE, Schlumberger, and M.S. Santo and L. Mattar, SPE, FAbstract A new technique for analyzing and model A.K. Ambastha, SPE, and M. Anderson, SPE, Chevron Corp.; H. Gandhi, SPE Abstract Mauddud reservoir in the Greater Burgan J.F. Manrique, Occidental Oil and Gas Corporation, and B.D. Poe Jr., Schl Abstract We present a unique methodology desig Moustafa Eissa, Sameer Joshi, and Kamaljeet Singh, SPE, Schlumberger Abstract Conventional pressure transient testing u K. Slimani, Sonatrach; D. Tiab, U. of Oklahoma; and K. Moncada, SchlumbeAbstract Often and for many reasons the wellbore Fikri J. Kuchuk, SPE, Schlumberger Abstract Although it is often used in pressure tran C. Contreras, SPE, S. Bodwadkar, SPE, and A. Kosmala, SPE, SchlumbergAbstract Reservoir engineers operating in mature M. Onur, SPE, and M. Cinar,* SPE, Istanbul Technical University; D. Ilk, Summary In this work we present an investigatio A.J.G. Carnegie, Schlumberger; Stephen Ball, Premier Oil Vietnam; Pierre Abstract T Two Case Studies Hassan Bahrami, Sharif University of Technology; Jamal Siavoshi, Husky Abstract The identification of fractures is essential S. Daungkaew, J.H. Harfoushian, and B. Cheong, Schlumberger; and O. Akins Abstract Exploration and appraisal campaigns for N.Karthik Kumar, SPE, Sameer Joshi, SPE and Raj Banerjee, SPE, Schl Abstract This paper presents techniques for interp David Costa; Total ABK, Jean-Paul Couput, Total; Florian Hollaender, Bru Abstract Flow metering using conventional separa B. Theuveny, Schlumberger; I.A. Zinchenko, Yamburggazdobycha Gazprom Abstract A number of tests were performed in Yam E.J. Pinilla, SPE, C.H. Pardo, SPE, L.M. Warlick, SPE, and Y.M. Al-Shoba Abstract Well testing is one of the most effective m Kelechi Isaac Ojukwu, Petroleum Development Oman, and John Edwards, Abstract The use of multiphase flowmeters (MPF B. Theuveny, Y. Shumakov, and A. Zhandin, Schlumberger, and I. Zinchen Abstract Surface welltesting of Gas-Condensate w D.I. Atkinson, Schlumberger Cambridge Research; ï¿½. Reksten, 3-Phase Summary Dedicated wet-gas flowmeters are now M. Metwalli Hassan and M. Bekkoucha, ADCO, and M. Abukhader, SchlumbAbstract Production testing using portable Multiph

B.G. Pinguet, G. Roux, and N. Hopman, Schlumberger Abstract Faisal M. Al-Thawad, SPE, and Jim S. Liu, SPE, Saudi Aramco, and Raj B Abstract D. Ilk, N. Hosseinpour-Zonoozi, S. Amini, and T.A. Blasingame, Texas A&M Abstract A.F. Veneruso, SPE, and J. Spath, SPE, Schlumberger Abstract M.-Y. Chen, B. Raghuraman, SPE, I. Bryant, SPE, and M. Supp, Schlumber Abstract

Using multiphase flowmeters in field ope The objective of this study was to investi In this work we present the application o The pressure derivative has become the Two successful field tests of streaming p

cal storage is about pumping a reactive fluid underground and ensuring it doesn't find a way back to the atmosphere for a very long time â€ an estimation of the full stress state between 0.5 and 2.1 km depth at the Otway CO2 storage pilot site Australia where the Cooperative R major challenges associated with CO2 geological storage is the performance of the confining system over long timescales. In particular the on of greenhouse gas emissions in order to decelerate the global warming process could be achieved through the emerging process of geo r CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface be undertaken in a greater variety of geo of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from p ired plants are responsible for the one third of the carbon dioxide (CO2) emissions which thought to be a major contributor to the current r he trapping of CO2 in the subsurface i.e. storage containment is of fundamental importance for a safe geological storage of carbon dioxide ide capture and storage (CCS) is emerging as a key technology for greenhouse gas (GHG) mitigation. The Society of Petroleum Engineers ¢ is a set of production data standards initiated by 13 upstream oil and service companies with the industry standards body Energistics (the /8-A-6 AHT2 was drilled from the Visund Field Floating Production and Drilling Unit (FPDU) in the North Sea and set on production in Octo rton Field operated by Maersk Oil North Sea in Block 15/20 has a number of drilling and well placement challenges which hampered deve Qatar AS (MOQ) completed drilling the world record BD-04A well in May 2008 offshore Qatar. This was the successful outcome of engineeri Formation historically known as the Brown Niagaran is a Silurian age formation in the Michigan Basin containing hundreds of pinnacle ree on is one of the most efficient methods used to improve oil recovery and as world statistics shows its use has increased recently. Under a ene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick nsate reservoirs usually exhibit complex flow behavior due to the near-wellbore condensate bank build-up when bottomhole pressure drops esented in this paper describes the evaluation and stepwise optimization process for a Steam-Assisted Gravity Drainage (SAGD) project us iscusses the gas shut-off treatments carried out in a fractured carbonate field in north Oman and also describes the good practices and less g is a mature field with 8 rounds of field development campaigns and close to 40 years of production. Currently only 50% of total strings are n from some of wells in the White Tiger field producing from a fissured Basement reservoir; have been impaired by excessive water produc wells in Sabriya Field (Northern Kuwait) produce from reservoirs where multiple layers are opened to production. Problems related to non-d tacked nature of reservoirs in the Niger Delta the predominant completion types are dual-string multizone and single-string multi-zone comp off treatment (WSOT) using through tubing bridge plug (TTBP) in open hole completion has been employed for the first time in a dead horiz covery of new fields becoming less common and the continued development of brownfields water control is becoming increasingly essentia uction is a major problem for any oil and gas field. If not properly managed unwanted water production will seriously impact the economics ol is the key to prolong well life for economical and efficient oil recovery. When water reaches certain levels oil production profitability decre arge potential reserves increased global demand for oil and high oil price exploration & development in deepwater and more challenging a mic characteristics of oil/water flow systems have not been understood fully. The need for improved designing methods has led researchers ow is a common occurrence during production and transportation of petroleum fluids through pipes. Understanding of oil/water pipe flow be tion of intelligent wells to improve the economics of production is now common practice.ï¿½These wells allow the access to marginal reser in the upstream business operational decisions are made separately at the reservoir production and surface facility levels using only their er production systems extreme pressure and temperature conditions multipart sub-sea networks complex reservoir characteristics and va nt of deep offshore fields is costly. As such accurate information is required before a decision can be made on the feasibility of prospect de ide (CO2) occurrence in hydrocarbon bearing formations presents a challenge to the valuation and subsequent prospect development of th t uncertainty in establishing reservoir connectivity has always been an issue for reservoir management. Standard correlation methods using precipitation can have profound effects on oil production during miscible flooding heavy oil recovery or even primary depletion. Even thoug d properties are required for studies related to management of gas/condensate reservoirs or prediction of condensate reserves. Often thes hors have shown the applicability of modified black oil (MBO) approach for modeling gas condensate and volatile oil reservoirs. It was show large reservoirs can be in equilibrium - especially if conditions conducive to convective mixing prevail. A large vertical column of reservoir h cation is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Kal cterization quantifies the reservoir phase behavior fluid compositional changes throughout the reservoir and changes in fluid properties as characterization and asset management require comprehensive information about formation fluids. Obtaining this information at all stages o based mud (OBM) filtrate contamination poses a major challenge to the acquisition of representative fluid samples using wireline formation escribes a new Downhole Fluid Analysis technology (DFA) being implemented in Latin America for improved reservoir management. DFA is Case Studies mation testing provides formation pressures high quality samples and fluid identification/characterization. In addition it can provide informa opment projects will rely on producing through existing production facilities which may not have been designed for sour hydrogen sulphide

uids frequently reveal complexities in hydrocarbon columns. Fluid compositional grading is usually caused by gravitational forces thermal g and analysis of gas/condensate-fluid samples presents considerable challenges. This is because downhole sampling of a gas/condensate ompartmentalization quantifying connectivity and assessing the presence of compositional grading are critically important to reservoir man uid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. Gas condensate reservoir is well know presents a case study of a North Sea appraisal well in which a vertical fluid-composition variation missed by a conventional pressure-grad epth plots have been used for over thirty years to evaluate fluid density fluid contacts and pressure compartmentalization in formation teste uids often show complex compositional behaviors in single columns in equilibrium due to combinations of gravity capillary and chemical for fluid sampling early in the life of a well ensures that vital information is available for timely input to field planning decisions. For example in escribes the study of the effect of asphaltene precipitation and deposition on the development of the Marrat field using a compositional sim uid analysis (DFA) together with wireline formation testing tools provides real-time measurements of reservoir fluid properties such as comp nts are common in gas condensate and volatile oil reservoirs but they are also present in heavy oils reservoirs. There are numerous public ears formation-sampling and formation-testing tools have provided a variety of new downhole optical measurements for downhole fluid ana aracterization and asset management require comprehensive information about formation fluids. Obtaining this information at all stages of sters are commonly used to obtain fluid samples and measure formation pressure during openhole logging operations. Accurate identificati describes in detail computational techniques and formulations for constructing a phase envelope and/or subsequent isenthalpic/isothermal f variably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path stable ve reservoir fluid sampling & characterization has become increasingly important as the exploration activities are moving into the ever-chal neration of wireline formation testing fluid analyzer presented in this paper integrates in-situ optical fluid analysis device with a oscillating me density-viscosity (D-V) sensor is introduced that provides a real time direct measurement of in-situ density and viscosity at reservoir conditi eous carbonate reservoir can be partly evaluated using OH logs but not fully. Even if production testing is used for evaluation important det eration of sampling technology is introduced that allows a wireline formation tester (WFT) to sample reservoir fluids in open hole with levels ssure testers and reservoir fluid sampling tools have for quite some time now been considered viable alternatives to well testing. These to tive reservoir fluid sampling and characterization has become increasingly important over the years. With exploration appraisal and develop well testing has been acknowledged worldwide as a state-of-the-art technology for metering stream of oil gas and water without prior phase ion of deep wells is a difficult task mainly because of high reaction rate and the high corrosion rate induced by strong acids. One way to ad cally complex Algyo field discovered in 1965 is the largest hydrocarbon occurrence in Hungary consisting of more than 40 oil-and-gas-bea matrix acidizing fluids for sandstone are executed in the field only after core tests qualify their ability to remove damage. However most core nvestigates the application of halite inhibitors and the mechanisms associated with salt formation and inhibition. Several new chemistries (tw mation damage with waterflooding using sea/produced water has been widely reported in the North Sea the Gulf of Mexico and the Campo ate-soap deposition and the related formation damage in petroleum reservoirs are investigated by means of laboratory-scale experimental a rge perforating subjects the formation to shock-loading and large impact stresses causing damage to the rock surrounding the perforation t ompletions perforations provide the essential link between the wellbore and the reservoir. Productivity of the completion is promoted by op ated to inorganic scale precipitation are common in oil fields across Russia. The predominantly calcium carbonate scale rapidly precipitates ation and accumulation of scale deposits is a major concern for production companies in the Uinta Basin. Since 2003 conventional hydrauli hallenge facing the oil industry is to reduce development costs while accelerating recovery while maximising reserves. One of the key enab ition in completion strings is becoming a threatening problem to produce and safely operate wells completed in the Upper ZAKUM (UZ) oil f m stripping is commonly observed in sandstone reservoirs where seawater mixes with formation water that may be rich in calcium strontiu ld history matching is generally performed first at the field level then at regional level followed by individual well history matching. This pap vancement in streamline simulation technology in modeling fractured reservoir and streamline associated well allocation factors now it can discusses the incorporation of Streamline simulation into the Reservoir Management Processes of the super giant Sabriyah oil field. For the he Gulf of Mexico Cantarell Field is the worldâ€™s second largest carbonate field which has been on production since 1979. After the imple presents the results of an automatic surveillance system implemented by PEMEX for one of Mexicoâ€™s largest gas fields.ï¿½ Activo Integ ater flooding has been the preferred pressure maintenance tool for many gulf carbonate reservoirs over the past 30 years. Due to uneven s utlines the successful integration of subsurface water handling well surveillance and production operations teams across the North Kuwait onal means of artificial lift production for vertical and deviated wells in the Orinoco oil belt in eastern Venezuela used to be rod pumping and Belt (Faja) in Venezuela contains one of the largest resources of heavy and extra-heavy oil in the world. Due to the production decline of co al EOR methods like steam-injection are usually not cost effective for deep wells and wells producing from thin pay zones due to excessive Heavy Oil Belt (Faja) has been exploited under primary recovery techniques using mainly horizontal fishbone and multilateral wells. This c and development of Heavy oil fields in Muglad Basin in Northern Africa started with conventional vertical wells and as time progressed this m ne/Eocene age 1st Eocene Reservoir is the shallowest producing interval of Wafra Field in the Partitioned Neutral Zone (PNZ) Saudi Arabi mation testers provide the measurements for the determination of formation pressure gradient in-situ effective oil mobility profile in-situ dow

avy oil field located in Muglad basin in Sudan. Aradeiba reservoir in the field consists of highly heterogeneous sandstone that is thinly bedde

ormation in the Gulf of Suez is highly fractured depleted reservoir producing 9 to 10 API gravity heavy oil at water cuts up to 98%. Stimulat nment With Sand Screen: A Case Study From Kuwait ecent hydrocarbon discoveries in the Gulf of Mexico are heavy and extra-heavy oils. Additionally given the imminent decline of lighter crude e is to present accurately the performance of the combination of a venturi and multi energy gamma ray in a case study in Venezuela. The fo bitumen produced by Steam-Assisted Gravity Drainage (SAGD) induces many issues arising from high operating temperatures (150-200 C cidizing is very challenging because of the complex reactions that occur between the multiple-stage treatment fluids and the formation mine nd fluids evaluation of heterogeneous and over pressured retrograde gas condensate low-permeability but high-reserves potential reservoir has already been undertaken by various operators throughout the industry to explore frontier areas and drill into ever-deeper geological hor ies descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and of crosslinking a polymeric fracturing gel can significantly contribute to the success or failure of a hydraulic fracturing treatment.ï¿½ In certai of crosslinking a polymeric fracturing gel can significantly contribute to the success or failure of a hydraulic fracturing treatment.ï¿½ In certai ng is the commonly applied stimulation technique in low permeability carbonate reservoirs. Achieving adequate fracture length is challengin Temperature Environment in Mexico Marine describes an innovative and reliable firstï¿½ High Pressure High Temperature digital electric permanent monitoring solution with state-of-the resents the results of propped fracturing operations conducted in the past 12 years in the Bach Ho (White Tiger) field offshore Vietnam. Hig n an oil field in East Venezuela have a bottomhole static temperature of approximately 230ï¿½F and varied mineralogical composition from ed on chelating agents have been developed for matrix stimulation of high-temperature sandstone formations. These fluids dissolve sizeabl ge Basin is characterized by multilayer formations requiring proppant fracturing as a completion method in order to achieve oil production at presents the development of a chemical system for water-block prevention in gas/condensate wells. The chemical system alters the forma describes a new technique for measuring pH on live formation water samples in the laboratory at high temperature and pressure. The techn tion and deposition of asphaltenic material in reservoir rock are significant problems in the oil industry and can adversely affect the producib describes an efficient multistage horizontal openhole completion technique as an alternative to conventional openhole or cemented and per ity Carbonates and rises and operators turn to tight gas reservoirs for new supplies the need to optimize the capacity and recovery potential from this type ntional tight gas reservoirs are made economical through effective stimulation techniques. Hydraulic fracture mapping combined with an incture azimuthal orientation depends on stress distribution in the formation and is considered to coincide with the maximal horizontal stress nt of gas are being produced from unconventional tight-gas sand reservoirs (e.g. Cotton Valley Fm. Lobo Fm. Taylor Sand Fm. and Wilco acture treatments are necessary to ensure the best deliverability of tight gas from east Texas Cotton Valley Sands.ï¿½ Historically these trea ity Tight Gas Formations s Limestone in South Texas often requires stimulation to be commercially productive. The relatively low permeability high Youngâ€™s Mod past decade multiple transverse fracturing in horizontal wells has been applied so successfully in onshore low-permeability reservoirs that it as field in Sichuan Province whose discovery was officially announced by CNPC in August 2005 is a large-scale gas reservoir that has in e Oolite carbonate reservoir in the Partitioned Neutral Zone (PNZ) is located between Kuwait and Saudi Arabia and has been a prolific oil prod presents a closed-loop reservoir study in tight gas fluvial sands of the giant Jonah gas field located in the northwestern part of the Greater G r we will present an integrated single well modeling (SWM) technique to predict reservoir and completion performance for a Uinta basin dev presents several workflows for constructing adequate flow models of a tight gas field located in Wyoming. The numerical flow models were nated tight gas sand sequences remain prolific targets worldwide and have often been bypassed using standard petrophysical analysis and Grained Sandstones natural fractures in tight carbonate reservoirs during the exploration and early development stages is critical in order to reduce geological un mation testing in low permeability carbonate reservoirs of the UAE has been challenging with frequent tool plugging extended pumping time the worldâ€™s oil and gas reserves are locked in tight â€œunconventional reservoirs. Without the presence of fractures (natural or hydra covery in tight gas reservoirs typically mandates infill drilling programs. Characterization of reservoir pressure depletion and sand body cont covery in tight gas reservoirs typically mandates infill drilling programs. Characterization of reservoir pressure depletion and sand body cont vided by wireline formation testers (WFT) is critical to the evaluation and understanding of petroleum reservoirs. Pretest pressures gradien presents a field-development case study of a low-permeability turbidite reservoir in Russia. The giant Priobskoye field contains 30ï¿½API c successful applications of horizontal wells have been limited to high-permeability reservoirs and unconventional formations such as coal c -Takhomskaya oil and gas accumulation zone (YTZ) located in the western part of the Siberian platform is known as a really challenging ex declining production and increasing demand geoscientists are challenged more and more often to develop new techniques and strategies al of tight sands (quartzitic sandstones) makes these non-conventional reservoirs a priority for oil companies during next decades. Due to nu

onate reservoirs several factors make it difficult to estimate reserves in transition zones. In particular underestimation of reserves sometime uction from gas producing wells characterized by low productivity and low reservoir pressure zones can prematurely kill wells leading to a co n of recovery from anisotropic small and medium size oil fields is a daunting task for operators. Development strategies and concepts imple resents a case history of a slickline propellant stimulation treatment performed in a well at the Penara and North Lukut field which is a sma aking within the petroleum industry is a complex process involving extensive analysis of multiple objectives based on a variety of diverse crit aking related to oil and gas exploration and production relies on objective data analysis as well on subjective judgment of experts. Expert jud e of supplying real time LWD or FE information (Logging While Drilling and Formation Evaluation) should be to enable the client to make qu essure curves are a fundamental input to reservoir simulators both from the standpoint of initializing fluid saturations and from the perspecti hole logs formation testers pressure transient tests and production logs are usually used to assess reservoir heterogeneity. A common lim s based on conventional logs are found as strongly correlated to core lithofacies thin section microfacies and petrophysical measurements the depositional sedimentary environment is the most important task for exploration geologists to model the reservoir heterogeneities. Inte reservoirs of the eastern Sahara province represent one of the main oil and gas accumulations in Algeria. This clastic succession correspon fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir-fluid properties and determining zonal co cation is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Ka ysical evaluation of carbonate reservoirs in terms of predicting the hydrocarbon potential is trivial. However it is difficult to correctly predict ipam sandstone reservoir of Miocene age in the Jaipur oilfield lies within a highly folded and faulted Assam-Shelf basin in the north eastern ging-while-drilling (LWD) tool that combines traditional measurements of gamma ray propagation resistivity gamma-gamma density and th e chemical logging sources have been used in the E&P industry for many years to help operators obtain valuable information about their re erns have been expressed regarding discrepancies between LWD (Logging-While-Drilling) and WL (Wireline) GR (natural gamma ray) resp the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and hence fying the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and h op concerns for carbonate reservoir evaluation is the effect of rock texture on permeability capillary pressure and relative permeability. Rece ir is composed of a mixture of dolomite limestone anhydrite and shale interstratified with sandstones member. The sandstone is predomin udy demonstrates a new method to compute continuous permeability and estimate reservoir rock type from logs in a complex heterogeneo urbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds.ï¿½ These he perforation intervals and evaluating the productivity of thin-bedded sands and shales is crucial for well completion cost optimization. This physical Analysis valuation in thin sand-shale lamination seeks first to determine sand resistivity volume fraction and porosity. Afterwards saturation and volu on evaluation (FE) of horizontal injectors drilled in water swept reservoirs involves different physical understanding of log responses to fluid ical viability of the Cambrian sandstone reservoirs in the Hassi Messaoud field is closely linked to the presence of fractures. Natural or hydr mation testing (WFT) and fluid sampling has long been used for determination of reservoir pressure evaluation of fluid type from in-situ den erest in fractures and faults in a giant carbonate oilfield offshore Abu Dhabi involves such aspects as their origin nature orientation and im trapping mechanism plays a critical role for hydrocarbon entrapment within the Middle-Late Cretaceous reservoirs in the Al-Khafji area. 3D Model was built and an Uncertainty Assessment approach was used to better understand the reservoir behaviour. Conceptual models were of spatial statistics geostatistics is commonly used to model geologic facies and petrophysical properties. The spatial characteristics of geo ed reservoirs are increasingly a target of offshore exploration in the Malay Basin. These reservoirs exhibit heterolithic interbedding with verti lear magnetic resonance (NMR) logging to help with the petrophysical evaluation of thin sand-shale laminations. NMR helps to 1) detect thi al power scenario changes with increased demand for oil and gas remote and challenging (deepwater offshore high pressure-high temper illustrates the improvements in logging while drilling (LWD) images and subsequent formation evaluation by using a new methodology for d Burgan Field consists of three sub fields (Ahmadi Burgan and Magwa). Drilling commenced in this field in 1938 and it went on stream in 1 on and injection of fluids in a reservoir results in reorientation of stresses. This phenomenon has been supported by field studies and micro anical parameters of reservoir rocks play an extremely important role in solving problems related to almost all operations in oil or gas produc leted reservoirs exhibit sharply lower pore pressures and horizontal stress magnitudes than does the overlying shaly formation. Drilling thro presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliv presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliv presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliv ah Sargelu and Marrat reservoirs are the main Jurassic reservoirs in Kuwait. These fractured-carbonate reservoirs that have moderate-to-lo ate reservoirs in Gulf of Suez area have complex geological structure due to the existence of fractures associated with faults. Thus fracture ocated in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial ing Upper Jurassic Arab reservoirs of an offshore Abu Dhabi fractured carbonate field (Abu Al Bukhoosh) have been producing for more tha hskoe field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin wher

we present a novel method for in situ estimation of two-phase transport properties of porous media using time-lapse resistivity pressure a s of defining the fluid and reservoir properties of a hydrocarbon discovery represents a significant challenge to the industry. The practice of p rmation Tester (WFT) pretest success ratio (good versus tight pressure points) has been traditionally low in East Kalimantan-Indonesia over asurements have long been used to evaluate rock properties in the near-wellbore region and these methods are well documented. Compre idated with superior results that the direct measurement of porosity using Nuclear Magnetic Resonance (NMR) in Naturally Fractured Clast most important objectives of fluid sampling using wireline formation testers (WFT) is to ensure that representative samples of the different flu s of shaly sand gas reservoirs with low and variable formation water salinity presents specific challenges. These formations usually exhibit lo challenge for nuclear magnetic resonance (NMR) well logging is that the quality and utility of the data depend on the acquisition sequence Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent de ifferent petrophysical methodologies have been developed to improve the success rate in selecting oil intervals in the Gulf of San Jorge Ba many of the producers are horizontal wells and a considerable number of them are equipped with smart complex completions. Evaluating the odology for porosity and permeability analysis in Carbonates with Inter-granular and Macro porosity is presented. This methodology uses NM nced drilling (UBD) is defined as a drilling operation in which the pressure of the circulating drilling fluid is lower than the pore pressure of th h structure in southwest corner of Kuwait is a multi reservoir field. One of the potential reservoirs is the Mishrif formation. Developed as a lim compartmentalization and understanding reservoir structure are of critical importance to reservoir development. Traditional methods of iden ng reservoir architecture is critically important to effective reservoir management. Misinterpreting reservoir compartmentalization for instan ntalization is perhaps the single biggest risk factor in deepwater petroleum production. Downhole fluid analysis (DFA) is a new tool to reduce resents the results of an investigation involving the development of a reliable and accurate methodology for establishing the stabilized deliv estimations are mainly based on special analysis of representative core samples (SCAL). In high recovery oil fields where remaining oil sat entary features of gas fields are multilayered deltaic thinly laminated shaly sandstones consisting of channel and bar sands with limited la hofacies Mapping management requires the optimization of hydraulic fracture placement. The lack of direct stress measurements (vertical distribution and dire n of pressure transient tests conducted in a dynamic environment like drilling is challenging. One of the difficulties arises due to phenomen eld Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operationa challenges that operating companies face during any oil field development project is to deal with the uncertainty associated with the data ac on declines and watercut increases wells are often converted from gas lift to electrical submersible pumps (ESPs).ï¿½ ESPs are an attract ew life into a mature oil field is a challenge that has been facing national and private oil companies for almost as long as the oil industry has dwide production surveillance for artificial lift is critical in brown field operations to ensure optimum field production and efficiency. Using app a is blessed with the worldâ€™s largest onshore and offshore reservoirs. Currently Saudi Aramco is aggressively pursuing production increm in sand bodies while drilling across heterogeneous sandstone reservoir is a major challenge that requires integrated reservoir engineering from low-pressure gas wells was improved by widespread/extensive installation of well site compression in the Waddell Ranch Project. The kflow methodology that covers the entire cycle of field development maximizes the production potential and can increase reserves in stacke anagement is a standard industry practice to maximize oil recovery; however in mature fields the full potential is often not realized. Unlike g w alternatives to develop and produce sands B1 and B4 together belonging to the reservoir VLG-3729 of Moporo Field located in western gement (FM) is the simulation workflow through which predictive scenarios are carried out to assist in field development plans surface facili most common methods of increasing production in oil fields is through the continuous injection of lift gas into the tubing.ï¿½ The injected gas simulation model calibrated with 25 years of production history was used to determine a cost effective reservoir management and productio oil field discovered in 1968 and produced since 1978. With the objective of rejuvenating the asset a multidisciplinary optimization team was tion projects consume considerable amounts of energy to generate steam.ï¿½ï¿½ Understanding where the heat goes at various times and servoir studies aim at synergizing all disciplines to form a reservoir understanding and best strategy to field development. Handling uncerta e of this paper is to highlight the necessary steps for the successful use of integrated asset modeling. It presents the full workflow for optim technology from reservoir through process facility has advanced so much that field development strategies can be developed within a new in the upstream business operational decisions are made separately at the reservoir production and surface facility levels using only their rocessor cluster computing modular stochastic workflows and a dedicated project team the turn-around time for project execution has bee ational Offshore Oil Corporation (CNOOC) Shell and ConocoPhillips China Inc. (COPC) are partners in the development of the XJG oil fi on of large volumes of water is common in wells producing from strong aquifer reservoirs such as most of the fields in the Oriente basin of t by limited capacity of 25 MMSCF/D was introduced for Khafji field in 1988 which could successfully sustain target rate until mid of 2004. A 6S and 3S oil fields in the Pearl River Basin Offshore South China Sea are mature fields which have produced 40% to 60% of their origina will illustrate the collaborative approach taken by an integrated team (operator and service company) charged to demonstrate within a one presents a unique workflow for gas reserves evaluation in fields with commingled production from several low permeability reservoirs. The w of high demand for rigs and other scarce equipment it may be appropriate and more advantageous for a client to agree to a forward contr

t describes how advanced well placement technology helped to optimize horizontal well position and maximize hydrocarbon production in d exco North Sea Limited developed the Brenda field in the Central North Sea. A total of over 8000 ft of horizontal section has been drilled in a methodology of converting standard reservoir models to maps of production potential for screening regions that are most favorable for we ment decisions are routinely made on the basis of simulation models that are created before production operations begin. Real-time downh presents an innovative filtering and analysis approach to identify candidates for sidetracking in mature water flooded fields.ï¿½ It targets byp infill drilling in oil rim reservoirs is a challenging task. In the case of thin oil rims with large gas caps early gas breakthrough and gas cycling ng the optimal location of wells with the aid of an automated search method can significantly increase a projectâ€™s net present value (NPV mber (SC) control during steam-assisted gravity drainage (SAGD) has a great impact on the efficiency of heavy oil and natural bitumen reco t a set of new analytical solutions to the single layer reservoir problem both in real time and Laplace space.ï¿½The solutions are derived a new semi-analytical solutions to the multiple layer reservoir problem both in real-time and Laplace space. Assuming a vertically stacked sys g geologic models to production data is generally done in a Bayesian framework. The commonly used Bayesian formulation and its impleme hod-based sensitivity for field-scale history matching with large number of parameters suffers from several limitations. First the CPU time de bjective is to investigate the use of Artificial Intelligence (AI) methods to accelerate the history matching process. A new criterion for measu reasing acceptance of stochastic workflows in mainstream reservoir engineering studies many frameworks have been developed to assist presents a novel methodology of history matching using the face recognition technique based on Principal Component Analysis which is cu Permeability e the construction of a general unstructured grid parallel fully-implicit simulator for complex physics associated with heavy oil thermal recov describes a general formulation for phase-component partitioning that can accommodate any number of phases and components any com wells often present a substantial challenge in reservoir simulation. In a recent field review we experienced difficulties modeling long horizont

nd multi-lateral wells have become increasingly important and represent a growing percentage of production wells. They are used to maxim tion of Complex Wells (CW) as a component of an optimized field development strategy at single well sector model and or small scale mult essure stress state and geological structures as well as their evolution during an oil/gas field life have widespread influence on implications -compositional reservoir simulator pressures saturations temperature and compositions in all the existing phases must be solved. When t ve analysis is a graphical procedure used for analyzing declining production rates and forecasting future performance of oil and gas wells. T re-propagation process performed with polymer-based fracturing fluids is applied commonly to increase the productivity of producing wells he substantial tight-gas resources worldwide hydraulic fracturing is for many cases economically a viable option. However despite the sta wells with multiple fractures are becoming more prevalent in the Industry. They are especially beneficial in carbonate plays where acid and fr te reservoir simulation is required to better describe multiphase fluids flow to hydraulic fractured wells and improve the development of gasp is one of the mechanisms that can alter the growth of a hydraulic fracture when it encounters weak planes or natural fractures. In shallow presents explicit simulation of hydraulic fractures in horizontal wells to predict the fracture behaviour and post-fracture production profile le ow reduces the productivity of fractured and frac and pack wells and causes erroneous results if ignored when analyzing well test data.1 Cu t gas reservoirs are often completed with multiple stages of hydraulic fracturing. Eventually each stage contributes to the commingled well p presents the results of an investigation concerning the development of more accurate predictive and interpretive models of the boundary-do on of horizontal well technology over the last twenty years has led to the parallel increase of the number of hydraulic fracturing treatments in this paper is to investigate the near-wellbore phenomena with respect to fracture initiation. The 2D numerical model was developed which eural networks (ANNs) have been used widely for prediction and classification problems. In particular many methods for building ANNs hav ture reservoir performance and uncertainties associated a series of reservoir simulation runs are required. It is now a common practice to g rs in the Nile Delta of Egypt are characterized vertically by its thin beds of sands and shale and laterally by severe variations in facies. Thes presents a mathematical model describing the variation of temperature along the length of a horizontal well during the process of water inje es of about 2 cP and above (under downhole conditions) are common and often exhibit poor end-point mobility ratios when displaced by wa r we present the results of a material balance study for a mature field in East Malaysia. The field consists of several stacked sands and is h n Place (OOIP) calculations based on material balance methods are strongly influenced by data uncertainty. Although some research is ava n objective of the mature fields development optimization is the value adding through extension of field life. While elaborating field developm nt formulation and numerical solution of two-phase multicomponent diffusion and natural convection in porous media. Thermal diffusion pre arth of easy oil in the industry the importance of consistency in quantifying uncertainties and assessing their impact on investment decision y-saturation function plays an important role in describing fluid distribution and modeling flow in reservoir simulation. In our full field review nvestigates the control volume method with multipoint flux approximation (MPFA) applied to the discetization of â€“div(K(x)grad u) = f(x) the ities of retrograde condensation in the near wellbore region in naturally fractured formation were studied with the use of dual-porosity/dual p ce of vugs in a naturally fractured reservoir can be a significant source of reserves.ï¿½ These vugs can be connected to the fracture system ation of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistic

uwait Jurassic Complex consists of five fields each with three identified reservoirs within the naturally fractured Jurassic carbonate formatio methods as a reservoir simulation tool have generated a great deal of interest in petroleum engineering because of the capability to calculat ctured reservoirs can be seen as a set of low permeability matrix rock blocks and a high permeability network of fracture channels. This rep reservoir characterization and modeling have given the industry improved ability to build detailed geological models of petroleum reservoirs models are used to solve specific problems in selected sectors of reservoirs; study production mechanisms; understand behavior of a partic nown PUNQ-S3 reservoir model represents a synthetic problem which was formulated to test the ability of various methods and research gr els are becoming more widely used as they can simplify highly complex processes with reasonable accuracy. Especially in risk analysis wh ales precipitate in oilfield systems - downhole in the reservoir in the production flow tubing and in surface facilities - because of thermodyn ng complexities of newly discovered reservoirs coupled with the increasing cost structure of field development mandate significantly improve with conventional vertical wells results in poor vertical sweep efficiency and steam breakthroughs when it is applied to heavy oil reservoirs.ï methods have become an efficient technology for reservoir simulation. The key assumption of the method is that the pressure field can be u most challenging problems for reservoir simulation is the computation of a multicomponent flow of compressible fluids in porous media with m discusses a new workflow to stochastically estimate the performance of infill locations in a mature oil or gas field. Usually performance evalu he ensemble Kalman Filter (EnKF) has gained popularity in atmospheric science for the assimilation of data and the assessment of uncerta presents a novel approach to analyze the quasi-continuous pressure data for ranking high-resolution geostatistical reservoir models and u a model for well inflow control devices (ICDs) that includes the effects of an annulus in which the flow between the ICDs is open or partially eservoir simulation still has wide application in the petroleum industry because it is far less demanding computationally than compositional s uwait Jurassic Complex (NKJC) consists of five fields each with three identified reservoirs within the naturally fractured Jurassic carbonate ock wettability is an important parameter to consider for oil recovery optimization. The great majority of sandstone formations is known to be ntal study was conducted on the mature Messla field to investigate the mechanism of fines migration and its contribution in formation dama of non-Darcy flow in hydraulically fractured wells has generated intense debates recently. One aspect of the discussion concerns the inertia carbonate oil-water transition zones contain vast amounts of producible oil. Yet traditional approaches to open-hole formation evaluation m gas field discovered in the Emirate of Dubai (U.A.E.) in 1982 was heralded as a major discovery of its time and to this day still remains stability in most of the cases is a direct reflection of earthâ€™s in situ stress state. It is well known that the stress distribution around the w summarizes the findings of the SPE Forum held in September 2005 on â€œMaking our Mature Fields Smarter.ï¿½Participants in the Foru e of the main oil producing country in the world with very long history of the oil industry. In one's time in former Soviet Union a lot of attention s North Slope and the United Kingdom North Sea were petroleum frontiers in the truest sense around 1960 when industry gained access t ast 10 years several papers have been published discussing the long-term mechanical durability of the cement sheath. The customary pro han 20 years of exploitation many of the thick and prolific reservoirs of the Malay basin are depleted. However field studies indicate that la ron measurements have been used since the early 1960s to measure porosity and sigma through casing. Since the formation sigma respon e-lapse saturation information is the key to making the right decisions on completion strategy maximizing oil recovery and reducing water c st decade intelligent well completions have evolved to become engineered solutions widely used for both monobore and multilateral horizo oduction logging tool string and interpretation technique were established in order to solve the surveillance limitations in the short string sect ogging and flow profile interpretations are necessary to properly assess completion performance and interpret pressure buildup data in Cha ation of condensate banking has always been a challenge. Furthermore large productivity losses can result from the absence of early dete ation of low permeability oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with for ation of low permeability oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with for describes an innovative Down Hole Permanent Monitoring System (PDHMS) that allows real-time monitoring of bottom-hole pressure and te nhole pH sensor has been developed to provide an in-situ pH measurement of formation water at reservoir conditions and results are pres ing availability of real-time downhole measurements in completions more and more uses of these data are evolving. A deepwater field in th hydraulic fracture treatment was performed on a producing well in a mature tight gas field in West Texas and induced microseismic activity ght prediction and evaluation is critical in understanding the effectiveness of a fracturing treatment. Volumetrically fracturing must adhere to gnostics of wellbore fluid entry is crucial for the understanding of well performance paramount for reservoir characterization purposes as w tart-up and early operation of horizontal steam assisted gravity drained (SAGD) wells it is important to understand the flow distribution of b addresses some recent developments in a production logging technique that uses Pulsed Neutron log measurements to evaluate the forma resents some recent developments in a production logging technique that utilizes Pulsed Neutron log measurements for the evaluation of th ystems are able to generate a temperature log along an optical fiber using a laser source and analysis of the backscattered light. This pape presents the first case study on using chemical tracers for flow profiling a subsea horizontal well with an open hole gravel pack lower comple and fluid type (phase) are two of the most fundamental parameters needed to characterize well performance. Traditional methods of estima entification is essential during exploration drilling and well completion of naturally fractured reservoirs since they have a significant impact o

lity of accurate performance information throughout the production system is fundamental to optimization of the economic potential of the re ogging low flow rate wells is difficult because mechanical spinners have a small dynamic range in slow moving fluids. Low flow rates in hori servoir has been producing for over 60 years and its pressure has slowly decreased over the years now below saturation pressure in some r we present a field example where pressure and distributed temperature measurements enabled understanding of reservoir characteristics amatic increase in oil prices oil operators are not only concerned about oil production but also they are aiming at the optimum oil productio reline formation testers (WFTs) are able to collect a massive amount of data at multiple depths thus helping to quantify changes in rock and ication of differential depletion in stacked reservoir sands before water or gas breaks through is the key to optimal reservoir drainage. How tion of microseismic and surface-deformation monitoring with an array of tiltmeters was used to monitor the warm-up phase of a steam-assi oping its Azeri field using deviated gravel-packed sand-screen completions producing from the multilayered Pereriv B C and D reservoirs. R e of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity drainage an ey issues in creating a good reservoir model in carbonate reservoirs is the identification of the horizontal permeability conduitsâ€” â€œthief Dream or Reality? The Case of Remote Surveillance of ESP and Multiphase Flowmeters lity of accurate production volumes at the well level and throughout the production network is fundamental to the workflows that target the he potential of a producing well requires knowledge of the fluid types and flow rates entering the wellbore. Optimum and accurate determina resents a novel logging approach used to identify water producing zones while under-balanced drilling (UBD) horizontal wells. This approac t of oil recovery and reduction in water-cut in a matured field requires precise time lapse saturation monitoring. Behind casing resistivity an maintenance purpose peripheral wells have been used to inject sea water into a carbonate reservoir offshore Abu Dhabi. The injected wate we will briefly review the pilot design and demonstrate the utility of applying the EM imaging to the pilot. We will also show the benefit of th cross-well electromagnetic (EM) surveys are used to monitor two types of fluid injection (Water Injection and Water Alternating Gas) in a gia Coal Bed Methane (CBM) resources are huge estimated at 3 000 to 9 000 Tcf. The worldwide production from CBM is dominated by US p stems comprise the primary flow path within coal bed methane (CBM) reservoirs. These fractures also called as cleats define the reservoir raulic fracture stimulation has been one of the primary completion methods for coalbed methane wellbores for more than twenty years. How tt shale is an unconventional gas reservoir that currently extends over an estimated 54 000 sq miles. In an effort to improve well economics acturing is the requisite methodology for completing nano-darcy matrix permeability tight gas shales. Commercial success in producing thes led tubing fracturing is the predominant method for completing and stimulating dry coalbed methane (CBM) formations such as the Horses wells represent a growing percentage of the drilling activity in low permeability reservoirs within the United States.ï¿½ With effective stimulat ippian Barnett Shale reservoirs have opened a new era for US gas production. Many reservoir characterization efforts have been made and 2.5 trillion barrels Canada has the worldâ€™s largest share of ultra-heavy oil and bitumen resources. While shallow heavy oil reserves are Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent dev tion from the unconventional Barnett Shale reservoir now exceeds 3 Bcf/d which is more than 5% of total U.S. dry gas production. Typically al nature of carbonate rocks makes acidizing an effective matrix stimulation technique. Acid dissolves carbonates at high reaction rate to cre al Submersible Pump (ESP) a form of artificial lift technology has proven to be a durable solution for delivering the required rates from Sau r high-temperature electric submersible pump (ESP) systems is growing as the oil industry matures. Canada's nonconventional oil reserves ystems are now being considered of extreme importance as the reserves across the globe are depleting and the wells are unable to flow na hevskoye oil field development started in 1995. In 2002 by the time when all the designed vertical wells had been drilled practically all the r e northeast Brazil Manati field is located in the Camamu Bay with water depths less than 50 m. The sandstone gas reservoirs in this field ha od of completing multiple-layer formations has been successfully tested in the United States and Canada. This new method places sliding sl a mature oil field with depleted reservoir pressure supported by an aquifer in the deeper Cretaceous horizon. The Cartojani structure is loc presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells servoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with â€œgood porosity.ï¿½ Mat Minghuazhen is a shallow-water delta-plain sedimentary-deposit reservoir sand in Bohai Bay China. It has relatively heavy oil in place that describes a case-study detailing planning completion testing and production of the first Maximum Reservoir Contact (MRC) Multilateral (M acement efficiency in hydrocarbon formations is often caused by the natural variation in the mobility of fluids across the reservoir strata. His describes a case study that details the planning completion testing and production of the first maximum reservoir contact (MRC) multilat of multilateral gas producers drilled in the Ghawar field has significantly increased over the past few years as part of the reservoir developm ng technology is moving towards maximum reservoir contact (MRC) by means of extended-reach horizontal and multilateral wells in all type of the increasing emphasis on reducing operating costs and minimizing deferred production a new system was designed for perforating wel statistical methodology using survival analysis (SA) was developed and applied to electrical submersible pump (ESP) system performance ring has been a successful method to stimulate the Khuff Carbonate wells of Saudi Arabia since the beginning of the gas development prog eld located on the North Slope of Alaska was developed using open-hole horizontal completions drilled along the maximum principle stress

rizontal lateral Bakken dolomite play began in 1999 in eastern Montana more than 330 wells have been permitted and more than 200 wells hydraulic fracturing in various risky" oil reservoirs has been the biggest challenge for fracturing engineers in the Western Siberia basin as a ng has been part of Saudi Aramcoâ€™s gas development strategy to maximize productivity from for vertical wells in the Khuff carbonates o describes successful implementation of degradable fiber-laden fluids for hydraulic fracturing in one of the largest oilfield in Western Siberia. ds are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the gas reservoirs y has been conducted on the effect of formation Youngâ€™s modulus and in situ stress on hydraulic fracture height containment in layered reservoir development continues at a record pace in North America. Additionally reservoir pressure depletion and declining quality of reserv elds produce larger quantities of water operators and service companies find themselves challenged with disposing flowback and produced he success of a tight-gas field development program in a fluvial environment is to understand the reservoirâ€™s deliverability and what the s a pervasively used completion technique in wells targeting high permeability poorly consolidated and depleted sandstone formations locat ve pay of the low permeability Ryabchyk formation in the mature fields of Western Siberia is separated from underlying water zones by a w years horizontal well technology evolved in the Middle East field development strategies becomes favored over vertical and deviated wells scenario in many mature oilfields is to have most of the wells producing hydrocarbons with high water cuts. These wells are commonly not ca hasnâ€™t escaped the general industry trend of finding reserves in ever challenging environments. Complex geology and low permeabil Africa offshore fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their key strategies in Saudi Aramcoâ€™s optimum gas development project is drilling single and multilateral wells to achieve maximum reservoir erations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment emphasis is System, Executed from a Supply Vessel; Black Sea Offshore one of ONGCâ€™s major brownfields discovered in 1983 and located in Gujarat. The Field produces approximately 30 000 bopd and is on presents the results of an investigation of the design and analysis of the boundary-dominated flow production performance of a vertically fra despread proliferation micro-seismic fracture mapping it has been observed that some naturally fractured formations exhibit a non planar o y of hydraulic fracturing work in Russia is being done in the Western Siberian basin where operators and service companies have gathered acturing of horizontal wells in shale gas reservoirs is now an established commercially successful technique.ï¿½ The evolution of the comp od of completing multiple layer wells has been successfully tested in the Piceance basin for Petrogulf Corporation. This new method placed hod of completing multiple-layer tight gas wells is being investigated. The main concept is to place sliding sleeve valves in the casing string engineers have faced the problem of hydraulic fracturing in soft rock formations for many years. However existing programs used with soft r ic Surfactant (VES) fluids are polymer-free fluids that generate viscosities suitable for fracturing operations without the use of polymer add rbon dioxide- (CO2-) emulsified viscoelastic surfactant (VES) fluid system has recently been used to improve the Olmos production in the C discusses the selection criteria design methodology and analysis of hydraulic fracturing treatments pumped using a solids-free liquid CO2 Generation Viscoelastic Fluid: Successful Case Histories in West Venezuela drilling program on North Raguba field in Libya has been suspended since the current wellâ€™s performance in this area was not promising resents the process of candidate well selection design execution and evaluation that lead to the successful implementation of acid fracturi cumented in the literature that hydraulic fracture treatments although successful often underperform: Frac and Pack completions exhibit po c hydraulic fracture monitoring is having a major impact in how wells are being completed in tight sand reservoirs.ï¿½ This existing technolo mpairment in tight-gas formations is a typical phenomenon for fractured wells. Processes responsible for this behavior are related to the ch errors in the calculated azimuth and other parameters of a monitored fracture can be caused by not performing accurate borehole deviatio ity Formations fracturing treatment fracture conductivity is created by differential etching of the fracture surface by the acid; without nonuniform dissolution ization of Hydraulic fracturing in West Siberia and the increase of job size over the recent year can impact the field development strategy. T adioactive tracers have been used in combination with standard industry logging tools to gain valuable insight about the fracture height (nea f our research is on a remote oilfield in western Siberia currently in the initial stages of development. There are two producing horizons of J re are many proven ways of predicting productivity in hydraulically fractured wells in medium-permeability oil reservoirs there is still no sim s carried out to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir using a nume stribution at the tip of a hydraulic fracture is a key element for controlling fracture propagation. In low-permeability formations under downho ght carbonate formations in Saudi Arabia are ideally suited for acid fracturing treatments. Various types of acids such as regular in-situ gell presents the results of an investigation of the design and analysis of low conductivity fractures. The mathematical model used in this work is mic imaging of a hydraulic-fracture stimulation showed significant fracture reorientation across a thrust fault. Fracture orientations were ident wback is an extremely important phenomenon in hydraulic fracturing technology and may cause severe problems for well completion. Vario the propagation of an orthogonal fracture and reopening along the initial fracture during a refracture treatment is studied by taking into acco al problem arises in enhancing oil recovery and is relevant to hydraulic fracturing process and subsequent frontal displacement of fluids from ooded reservoir hydrocarbon recovery optimization is impacted by well spacing and hydraulic fracture extent. An excessive fracture length m

summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since t s a deepwater project located in Malaysia. The development plan for this field requires fifteen water injectors eighteen producers and one acturing plays a very important role in these mature and complex geology fields located onshore northeast Brazil â€“ Carmï¿½polis and Siri g the hydraulic fracture path have been observed in mapping of mined fractures and attempts have been made to reproduce their effects o auto natural and in-situ gas lift all refer to artificial lift systems that use gas from a gas-bearing formation to gas lift a well. The gas lift gas and Tobago (bpTT) has been developing highrate gas fields in Trinidad & Tobago since 1999 and has six high rate gas fields currently on p ompletion technology has progressed dramatically over the last six years with the latest technical barriers being eclipsed with open-hole tec ompletion technology has progressed dramatically over the last six years with the latest technical barriers being eclipsed with open-hole tec horizontal wells with openhole sections or non-cemented liners is a common practice. This type of openhole wells is preferred to maximize r describes an innovative completion solutions with reservoir monitoring and control completion technologies that allows commingled oil produ wells are superior in production and recovery to conventional wells however they are subjected to early water coning towards the heel (wate ompletions have been in commercial use for over ten years. Application of intelligent completions technology has evolved from interventiondescribes an innovative completion solution with state-of-the-art reservoir monitoring and control completion technologies that allows comm hallenges remain in the development of optimized control techniques for intelligent wells particularly with respect to properly incorporating and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandsto essing workflow has been engineered to combine reservoir deliverability defined by production logging (PL) measurements with nodal anal of exploration wells continue to escalate we need more than ever to evaluate each well quickly and efficiently to improve the appraisal proc blems are often observed in fields after a period of relatively smooth operation. These occurrences usually coincide with an increase in dep own that in cased-hole completions productivity is enhanced by maximizing shaped charge penetration and shot density while minimizing pe on from completion to production often requires the well to be killed immediately after perforation is completed thus exposing the formation g has been widely used worldwide to perform perforating and zonal isolation operation due to the ability in intervening highly deviated and l astern Venezuela the Santa Ana Field is part of the most important gas province of Venezuela: Anaco District. Its main productive zones are nal Offshore Oil Corporation (CNOOC) Chevron and ENI the field operator are partners in the development of the HZ oil and gas fields o an important technique for stimulating production in low-permeability formations and requires special consideration in designing the preced enge identified by ADMA OPCO is the time delay and subsequent lostï¿½production between a well being completed with the drilling rig un imates of post perforation damage skin are important for designing remedial solutions and productivity enhancement operations. Underbala coiled tubing (CT) conveyance is used to optimize underbalanced perforating especially for rig-related operations. Well trajectory tempera shaped charge fired from a perforating string or perforating gun will not only perforate its targets but also possibly cause excessive damage ivity is driven by establishing a clean connection through the near wellbore zone of drilling and completion induced permeability impairment n a series of laboratory flow experiments comparing the productivity of perforations created with reactive liner charges against those created productivity is achieved by establishing a clean connection to the wellbore through the near wellbore zone of drilling and completion induce co's drilling strategy witnessed a change in the last few years by drilling horizontal and extended reach maximum reservoir contact (MRC) w s Basin in Brazil is one of the most challenging areas for completions in the world due to the lack of formation consolidation the large perce illips is developing the Magnolia field with a tension-leg platform (TLP) in 4 674 ft of water at Garden Banks Block 783 in the Gulf of Mexico the wells reach there economical production limit and are consequently abandoned or mothballed until viable solutions are available to enh illips is developing the Magnolia field with a tension leg platform (TLP) in 4 674 ft of water at Garden Banks Block 783 in the Gulf of Mexico s situated in SPDCâ€™s OML 22 in the eastern part of the Niger delta belt some 60kM NW of Port Harcourt. The field discovered in 1986 ators have recently launched a new industry-wide initiative on sand control reliability. The aim of the initiative is to gain a better understandi end of completion method in offshore reservoirs with sand control requirement is Horizontal Open Hole Gravel Packing (OHGP).ï¿½ Thoug Hole Gravel Pack (OHGP) completions that have been installed in Greater Plutonio to date have all achieved complete annular packs and z n A-45 located in the Norwegian Sea was completed in an unconsolidated sandstone reservoir that required sand control. The lower zone major challenges in underground gas storage wells in Italy is to maximize the sand layers exposure by drilling slanted or sub-horizontal wells ravel packing is one of the most popular completion techniques due to its high reliability along with the ability to deliver high-productivity we king has routinely been used as a sand control method in open-hole horizontal wells. With the advances in drilling technology in recent year jority of the recent deepwater developments in West Africa require sand control applications. Openhole gravel packing is the preferred san gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depend gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depend n oil and gas field located off the Norwegian Coast that is due to be developed with subsea infrastructure tied back to a floating production f presents the first installation of nozzle-based passive inflow control devices (ICD) for Apache Corporation in Australasia. This recent technol sand control completions provide a cost-effective means of completing wells in the Gulf of Mexico by eliminating the need to have a rig on l for a cost-effective alternative to screens has been intensive in the sand control field. Different systems have been proposed in the past inc

ction from the Sarir field became a major concern for AGOCO at the end of the 1980s when ESPs were introduced to the field. The sanding presented as SPEï¿½100948 at the 2006 SPE International Oil & Gas Conference and Exhibition in China held in Beijing 5-7 December 20 escribed a case study involved an investigation in a field in Libya where massive unexplained fill had been reported accompanying obstruc only acknowledged in the petroleum industry that water cut increases sand-production risk and a number of possible mechanisms have be he stacked reservoirs of the Bokor field offshore Sarawak Malaysia are prone to sand production the field-development team did not opt a duction of hydrocarbons the formation is subjected to increasing levels of effective stress resulting from the reduction in pore pressure. In presents a geomechanical study on the potential of wellbore instability and sand production for a multi-field gas development in offshore Pe c surfactant systems are used in the industry for several applications. Initially the application was focused on low-friction and solids-suspen of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture co an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetra ng has been an integral part of Aramcoâ€™s gas development strategy for the vertical wells in the Khuff carbonates over the last several ye ng has been an integral part of Aramcoâ€™s gas development strategy for the vertical wells in the Khuff carbonates over the last several ye ecember 2003 and February 2005 eight wells were stimulated in Tengiz field in Kazakhstan using a viscoelastic diverting acid system to ev ¿½ formation (Cretaceous age Campos Basin Brazil) is predominantly an oolitic and oncolitic grainstone and packstone limestone with a b matrix acidizing in Kuwaitâ€™s horizontal openhole wells is a big challenge. Reservoir heterogeneity and the length of the horizontal wells m il and gas production from the Brown Fields is now more important than ever to the operating companies as the oil price remains record hig our water injectors in carbonate formations in Saudi Arabia sulfide scavenging prevention of sulfur and iron sulfide precipitation is a major of carbonate reservoirs is often considered a routine operation. When the reservoirs are thick (more than 200 m) the stimulation process is m acid is the most commonly used acid for carbonate acidizing due to its low cost and high dissolving power. However there are two major d iyah field is one of the biggest sub fields and older producing sections in the giant Ghawar structure. A few wells have been dead for someti s formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy.ï¿½ ld in the south of Colombia was initially put on production in 1969 and has produced continuously since then. The most prolific reservoir is e of matrix treatments in carbonate reservoirs is to increase connectivity of a formation with the wellbore in the entire zone of interest. Succe y of oil exploited from Russian oilfields today comes from the Volga-Urals and Western Siberian basin where large-scale fracturing and coil nate reservoirs are heterogeneous at multiple-length scales.ï¿½ These heterogeneities strongly influence the outcome of acid stimulation tre n of existing wells represents a vast underexploited resource. A successful refracturing treatment is one that creates a fracture having highe luids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water carbon dioxide (CO2)â€“foamed fracturing fluids were used to stimulate wells in the Waltman field in Wyomingâ€”due to the low formation lation techniques like hydraulic fracturing which can involve large financial investments call for a basin- or reservoir-specific approach to m s and condensate drop out near the wellbore in a gas reservoir can cause rapid production decline. The liquid (water/condensate) is trappe ted wells producing from the mature carbonate formation in northern Kuwait are encroached by injected water from adjacent wells presentin (sonic and ultrasonic) of cement bond log tools are run in tandem as part of ZADCOâ€™s standard cement evaluation program. The effect que for analyzing and modeling the pressure data from both flow and buildup periods in closed chamber tests (CCT) has been developed. servoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with â€œgood porosity.ï¿½ Mat a unique methodology designed for evaluation and optimization of multi-fractured wells in stacked pay reservoirs using commingled produc l pressure transient testing using a pressure gauge positioned at a fixed depth in a well has historically been the main source of permeabi or many reasons the wellbore does not completely penetrate the entire formation yielding a unique early-time pressure behavior. Some of th s often used in pressure transient testing radius of investigation still is an ambiguous concept and there is no standard definition in the pet ngineers operating in mature fields across the world struggle to get necessary reservoir data to make their exploitation plans more realistic.ï k we present an investigation of recent deconvolution methods proposed by von Schroeter et al. (2002 2004) Levitan (2005) and Levitan e

ation of fractures is essential during exploration drilling and well completion of naturally fractured reservoirs since they have a significant im and appraisal campaigns for deepwater environments are a continuous challenge in todayâ€™s operations. Data acquisition in such enviro presents techniques for interpretation of Mini-Drill Stem Test (MiniDST) for establishing commingled Absolute Openhole Flow Potential (AOF ng using conventional separation-based technologies in low-pressure high gas rate environments typical of gas-lifted wells is a very difficult tests were performed in Yamburggasdobycha Gazprom's fields in Northern Siberia area to evaluate the performance of multiphase flowme is one of the most effective means to characterize hydrocarbon reservoirs under dynamic conditions. Such characterization of reservoirs is multiphase flowmeters (MPFM) for well test measurements is increasingly becoming a standard practice replacing conventional test separat ltesting of Gas-Condensate with multiphase flowmeters is still considered a challenge for production metering. Traditional means of well tes wet-gas flowmeters are now commercially available for the measurement of gas and liquid flow rates and offer a more compact measurem esting using portable Multiphase Flow Meters (MPFM) was implemented in ADCO Field â€œB with objectives to quantify the water and gas

phase flowmeters in field operations has now become a widely accepted practice especially in the range of Gas Volume Fraction (GVF) of 0 e of this study was to investigate a workflow where well test data could be used more effectively in history matching of full-field reservoir sim we present the application of the Î²-integral derivative function for the interpretation and analysis of production data. The Î²-derivative functio e derivative has become the primary interpretation tool for diagnosing well and reservoir behavior. In many situations however the derivativ sful field tests of streaming potential measurements in oil fields have been carried out: one in a horizontal oil production well and one in a ve

e atmosphere for a very long time â€“ possibly centuries. Potable aquifers and other permeable formations (e.g. hydrocarbon deposits) mus Australia where the Cooperative Research Centre for Greenhouse Gas Technologies is conducting a large-scale demonstration project. T er long timescales. In particular the occurrence of CO2 leakage through existing wells could not only defeat the purpose of storage but also hrough the emerging process of geological CO2 storage. Also in terms of Enhanced Oil Recovery (EOR) the injection of CO2 as a pure com ndertaken in a greater variety of geological environments that has been the case previously. Often when the storage reservoirs are saline aq missions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK project is a R&D p a major contributor to the current rise in the Earth's surface temperature. Reducing CO2 atmospheric concentrations by capturing emiss geological storage of carbon dioxide. During CO2 injection increasing fluid pressure temperature variations and chemical reactions betwe The Society of Petroleum Engineers (SPE) Applied Technology Workshop (ATW) on OnePetro CO2 ustry standards body Energistics (then POSC) in 2005. In November 2006 PRODML OnePetro V h Sea and set on production in October 2005. The well was drilled to 9082 m/29796 ft measured depth and has an Along Hole Depth (AH t challenges which hampered development during the 80â€™s and 90â€™s when operated by the previous owner. These include formatio the successful outcome of engineering efforts to increase extended reach capabilitie OnePetro containing hundreds of pinnacle reefs. These reefs discovered primarily during the 1970s have produced nearly half a billion barrels of pri se has increased recently. Under a high crude oil price scenario field applications of enhanced oil recovery (EOR) processes are becoming d stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered une up when bottomhole pressure drops below the dew point.ï¿½Such an accumulation of condensate liquid in the near-wellbore region forms Gravity Drainage (SAGD) project using a representative sector model from a field with fluid and reservoir characteristics from an eastern Ve escribes the good practices and lessons learnt from a number of jobs. In addition to the technical analysis the paper also addresses the ec urrently only 50% of total strings are flowing. OnePetro impaired by excessive water production. Excess water not only reduced the artificial lift efficiency but also imposed various damages to the roduction. Problems related to non-desired water production are drastically affecting the oil production and have been an ongoing concern. ne and single-string multi-zone completions. These designs have been adopted to reduce the number of infill wells required for field develop oyed for the first time in a dead horizontal well in one of the onshore fields in Saudi Arabia. It was successfully applied by setting an inflatabl rol is becoming increasingly essential to enhancing oil recovery. Water control operations are especially challenging in under-pressured rese will seriously impact the economics of a project through lost hydrocarbon production reserves recovery and ever increasing treatment costs vels oil production profitability decreases dramatically and even goes to negative. One feasible option in this case is a rigless water shut-off n deepwater and more challenging areas around the world have become a key target for the majority of oil and gas Exploration and Product gning methods has led researchers toward its continuous investigation. The objective of this study was to characterize oil/water flow through derstanding of oil/water pipe flow behaviors is crucial to many applications including design and operation of flow lines and wells separation s allow the access to marginal reservoirs for which dedicated production might not be economic and also accelerate the recovery.ï¿½Sen urface facility levels using only their respective knowledge experience and engineering tools without limited coordination between them so lex reservoir characteristics and various fluid phases flowing from the reservoir rock to the surface could promote production interruption du ade on the feasibility of prospect development. Such sets of information include the reservoir fluid characterization and flow assurance data sequent prospect development of the hydrocarbons. Corrosion is a major concern effecting capital and operational expenditures since the p Standard correlation methods using logs cores and seismic data are sometimes inadequate whereas an extended production test may be even primary depletion. Even though asphaltene OnePetro of condensate reserves. Often these studies must begin before laboratory data become available or possibly when laboratory data are not nd volatile oil reservoirs. It was shown before that MBO could adequately replace compositional simulation in many applications. In this work A large vertical column of reservoir hydrocarbons offers a unique laboratory to investigate potential gravitational grading. Asphaltenes are kn the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer m and changes in fluid properties as a result of production and injection processes. High-quality fluid data are critical for reliable modeling re aining this information at all stages of the exploration and development cycle is essential for field planning and operation. Traditionally fluid id samples using wireline formation testers (WFTs). A sound understanding of the physics of OBM filtrate clean-up and identification of firstoved reservoir management. DFA is a unique process in fluid characterization for improving fluid sampling reservoir compartmentalization e

n. In addition it can provide information for reserve assessment and producibility estimation. ï¿½ï¿½ï¿½ In this paper we present compre esigned for sour hydrogen sulphide (H2S) service. This problem is compounded if production is routed to an NGL or GTL facility because ev

ed by gravitational forces thermal gradients OnePetro hole sampling of a gas/condensate fluidâ€”unlike its oil counterpartâ€”does not guarantee the retrieval of a single-phase fluid. The same is critically important to reservoir management particularly in deepwater projects where uncertainties are large and mistakes are costly. Com as condensate reservoir is well known for its complex behaviour due to the nature of a near critical fluid. The reservoir pressure and temper sed by a conventional pressure-gradient-analysis method was observed in situ in real time by a new fluid-composition analyzer using visible mpartmentalization in formation tester pressure surveys. However in the Niger Delta region and other offshore deepwater environments man of gravity capillary and chemical forces. Frequently non equilibrium or non stationary state conditions are also encountered for instance du planning decisions. For example in subsea wells flow assurance is a major concern and formation fluid samples from openhole logging he arrat field using a compositional simulation modOnePetro servoir fluid properties such as compositions of four or five components/groups OnePetro servoirs. There are numerous publications (Creek 1985 Lars Hï¿½ier 2000 Montel 2002 Firoozabadi 1999 Ghorayeb 2003 Fujisawa measurements for downhole fluid analysis (DFA). DFA involves an in-situ measurement of optical absorption spectra used to compute prope ning this information at all stages of the exploration and development cycle is essential for field planning and operation. Traditionally fluid in ging operations. Accurate identification of the produced fluid usually depends on the OnePetro ana subsequent isenthalpic/isothermal flash calculations that are practical for multiphase fluids in a non-isothermal environment.ï¿½ These me through the production path stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils tivities are moving into the ever-challenging environment around the world. ProperOnePetro analysis device with a oscillating mechanical sensor providing downhole densi OnePetro OnePetro sity and viscosity at reservoir conditions using a wireline formation tester (WFT). OnePetro s used for evaluation important details can often be overlooked such as indivi OnePetro OnePetro ervoir fluids in open hole with levels of filtrate contamination that are in many cases below measurable limits. Also the time required on sta alternatives to well testing. These tools are widely used to identify reservoir fluids and obtain representative samples for laboratory analyses h exploration appraisal and development activities moving into marginal fields and more challenging environments accurate fluid characte il gas and water without prior phase separation and provides in many cases much more accurate picture of the transient evolution of flow a uced by strong acids. One way to address these problems is to use simple organic acids and chelating agents. Unlike HCl the reaction of o ng of more than 40 oil-and-gas-bearing layers. The Ap-13 is one of the biggest reservoirs and encompasses a myriad of challenges: it is a emove damage. However most cores that are used come from sandstone quarries and the cores are largely clean and undamaged (and no hibition. Several new chemistries (two inorganic compounds and one organic nitrogen-based product) have been identified which provide im a the Gulf of Mexico and the Campos Basin in Brazil. OnePetro s of laboratory-scale experimental and theoretical studies. Experiments were carried out in three directions to understand and quantify the n he rock surrounding the perforation tunnel. This damage can lead to reduced productivity and to an enhanced risk of sand production both o of the completion is promoted by optimizing perforation characteristics such as geometry phasing and density but unfortunately it is restric carbonate scale rapidly precipitates from the produced water and causes reduction in reservoir permeability restricts fluid flow in tubing an n. Since 2003 conventional hydraulic fracturing treatments with scale inhibitor pumped simultaneously as an additive have been offered to t mising reserves. One of the key enabling technologies in this area is intelligent well completions.ï¿½Downhole inflow control devices allow leted in the Upper ZAKUM (UZ) oil field. Calcite or Calcium Carbonate (CaCO3) scale mostly found in the upper part of the production strin that may be rich in calcium strontium and barium ions this paper presents evidence for in situ sulphate stripping in a sandstone reservoir idual well history matching. This paper presents a novel methodology for delineating multiple reservoir regions for the purpose of efficient hi d well allocation factors now it can be used as an effective tool to validate fracture lineament through visualization of streamline-based flow uper giant Sabriyah oil field. For the Middle East region streamline simulation has particular significance due to the magnitude of reserves roduction since 1979. After the implementation of Nitrogen injection peak production has reached to more than 2 million stb/d in early 2000 ™s largest gas fields.ï¿½ Activo Integral Burgos (AIB) is a typical example of large gas field where production declined due to gas-loading ba the past 30 years. Due to uneven sweep and pressure distribution this technique has given way to pattern floods in several gulf fields. As ions teams across the North Kuwait asset to significantly improve the operating procedure for waterflooding the Sabiriyah Mauddud field. T ezuela used to be rod pumping and top-drive progressive cavity pumps (PCPs) particularly for wells with production rates ranging from 200 . Due to the production decline of conventional light crude projects must focus on increasing the recovery of heavy and extra-heavy oils us om thin pay zones due to excessive heat loss to the overburden.ï¿½ For such wells minimizing heat losses can be achieved by using micro shbone and multilateral wells. This cold development can only recover between 6% and 9 % of the considerable original oil in place existing wells and as time progressed this matured into drilling of horizontal and high angle wells. Typically drilling challenges in this area include d ed Neutral Zone (PNZ) Saudi Arabia and Kuwait. Characterization of this heavy oil reservoir is challenging due to observed variations in oil fective oil mobility profile in-situ downhole fluids analysis (DFA) as well as taken PVT samples and maintaining them in single phase condit

neous sandstone that is thinly bedded unconsolidated bearing typical heavy oil. Bentiu reservoir is composed of massive sandstone unco

oil at water cuts up to 98%. Stimulation is required to enhance oil production and extend the life of the field. An inherent problem with these

the imminent decline of lighter crude oil fields such as Cantarell (the primary Me OnePetro n a case study in Venezuela. The focus will be on practical information knowledge sharing to overcome all classical problems due to fluid b operating temperatures (150-200 C) steam presence in the gas phase foaming emulsio OnePetro atment fluids and the formation minerals. Such reactions are more likely to occur at elevated temperatures and can result in potentially dam but high-reserves potential reservoirs requires use of advanced formation evaluation techniques. The Achimovskaya formation of Urengoisk drill into ever-deeper geological horizons. High pressures and temperatures in theOnePetro reasing numbers of deep water and subsea production systems and High-Temperature-High-Pressure (HTHP) reservoir fluids have elevate lic fracturing treatment.ï¿½ In certain case OnePetro lic fracturing treatment.ï¿½ In certain cases excessive crosslinking while the fluid is in the tubulars can result in friction pressures that are t dequate fracture length is challenging due to the fast acid spending rates and high leakoff resulting from these treatments. The problem is e

monitoring solution with state-of-the-art intellitite welded system that allows bottom hole pressure and temperature in real time in JFYN-01 g ite Tiger) field offshore Vietnam. High temperatures (>275oF) and closure stress (>8 000 psi) combined with the fact that fracturing has to b ried mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in th ations. These fluids dissolve sizeable amounts of calcite and clays and maintain high levels of dissolved metal in solution over time with min in order to achieve oil production at commercial levels. As fields are arriving to a mature stage they require continuous improvements with he chemical system alters the formation wettability to intermediate gas wet conditions thereby decreasing the capillary forces and enhancin mperature and pressure. The technique involves adding pH sensitive dyes to pressurized single phase water samples collected using a for nd can adversely affect the producibility of OnePetro onal openhole or cemented and perforated lateral completions.ï¿½ The application focuses on openhole (OH) completions in the Cleveland

nd recovery potential from this type of reservoir has risen. In this environment a multidomain integrated process enables the data and activ cture mapping combined with an in-depth knowledge of reservoir geology and geomechanics can give a better understanding to the effectiv e with the maximal horizontal stress azimuth. The knowledge of the hydraulic fracture orientation is of critical importance in field developmen bo Fm. Taylor Sand Fm. and Wilcox Fm. etc.) and shale gas-bearing formations (e.g Barnett Fayetteville Marcellus Woodford etc.). The ley Sands.ï¿½ Historically these treatments have been performed using a wide variety of techniques using a range of fluids including slick w

permeability high Youngâ€™s Modulus presence of natural fractures minimal stress OnePetro OnePetro re low-permeability reservoirs that it is becoming the standard completion practice in many areas. The reasons for the success of this techn rge-scale gas reservoir that has in excess of 100 billion m3 of natural gas reserves. The main sandstone reservoir in the Guangâ€™an field rabia and has been a prolific oil producer in the area. Several billion barrels of oil from this reservoir has been produced within the PNZ. As e northwestern part of the Greater Green River Basin Wyoming. It produces gas from the micro-darcy fluvial channel sandstones of the Up on performance for a Uinta basin development program. This technique has proven to be vital in the economic success of wells in the Uinta ng. The numerical flow models were built by integrating seismic petrophysical geological and engineering data including hydraulic fracture tandard petrophysical analysis and simple porosity cut-off technique. The problem becomes more acute in marginal tight gas reservoirs. Th OnePetro OnePetro ical in order to reduce geological uncertainty and determine well trajectory in future horizontal drilling. Challenges are often found in both ac ol plugging extended pumping time and multiple trips out of the hole. At the same time there are increasing demands of various types of f esence of fractures (natural or hydraulic) these tight reservoirs with matrix permeabilities usually less than 0.1md and porosities between 3 ssure depletion and sand body continuity are fundamental to determining the economic viability of these projects. An elusive challenge has ssure depletion and sand body continuity are fundamental to determining the OnePetro OnePetro servoirs. Pretest pressures gradients and mobilities are generally regarded as essential inputs to the reservoir evaluation model. However riobskoye field contains 30ï¿½API crude in laminated sandstones of 0.1 to 20 md at a depth of approximately 2 500 m. The complex geolo ventional formations such as coal chalk and shale. Conversely few tight-gas-sandstone reservoirs that require stimulation have realized s is known as a really challenging exploration object. The main reservoirs are located in Riphean carbonates made up of single p.u. porosity elop new techniques and strategies for evaluation and appraisal of increasingly comp OnePetro anies during next decades. Due to numerous fo OnePetro

nderestimation of reserves sometimes occurs because the formation oil can be more mobile than expected. The measurement of mobility o prematurely kill wells leading to a considerable loss in recoverable reserves. In soOnePetro pment strategies and concepts implemented in large fields generally are not appropriate for small and medium size fields. Inappropriate stra nd North Lukut field which is a small oil field operated by PETRONAS Carigali OnePetro ves based on a variety of diverse criteria. As part of the decision-making process companies often convert non-monetary criteria to common ctive judgment of experts. Expert judgment often considered to be less and accurate than objective data analysis. Nevertheless it is still one ld be to enable the client to make quick accurate decisions on the formations being drilled thus reducing and minimizing the geological unc d saturations and from the perspective of predicting dynamic reservoir behavior. Traditionally this input has been obtained from special core servoir heterogeneity. A common limitation of these techniques is that they do not provide two-dimensional spatial information of reservoir c s and petrophysical measurements (f/k and MICP) as long as the carbonate pore system remains simple. Once dual porosity is present it i el the reservoir heterogeneities. Interpretation of borehole images has been the key to better understanding of the sedimentary environment ia. This clastic succession corresponds to fluvial estuarine and shallow marine deposits characterized by common lateral and vertical facie properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to n the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer m ever it is difficult to correctly predict the fluid flow in the absence of proper characterization of the different flow units encountered in these re am-Shelf basin in the north eastern part of India. The analysis of this mature field carries a lot of interest not only because the sands within vity gamma-gamma density and thermal-neutron porosity with measurements unique to the LWD arena including neutron capture spectro n valuable information about their reservoirs. Until recently much of the information obtained using these sources could not be obtained w reline) GR (natural gamma ray) responses in various wells. It has been suggestedOnePetro that luating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the field n evaluating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the ssure and relative permeability. Recent advances in log analysis combined with new logging sensors that are sensitive to carbonate rock tex member. The sandstone is predominantly poorly consolidated and quartz rich. Much of the sand is medium grained although coarser sand is rom logs in a complex heterogeneous Middle Eastern carbonate reservoir.ï¿½ The 795 ft conventionally cored interval consists of interbed of thin silt and clay beds.ï¿½ These reservoir sands vary in thickness from millimeter to meters in thickness.ï¿½ The reservoirs are highly p ell completion cost optimization. This requires the accurate identification of hydr OnePetro

osity. Afterwards saturation and volume are simple Archie applications. Resistivity anisotropy techniques can provide estimates of sand res erstanding of log responses to fluid flow and distribution than that FE of oil producers drilled in dry oil intervals. In reservoirs swept with wate esence of fractures. Natural or hydraulically induced fractures control hydrocarbon productivity due to the low porosity low matrix permeab luation of fluid type from in-situ densities identification of fluid contacts and inter-reservoir connectivity. Fluid sampling and downhole forma eir origin nature orientation and impact on productivity of Lower Cretaceous hydrocarbon reservoirs. Studies identified a conundrum with r s reservoirs in the Al-Khafji area. 3D seismic data are acquired aiming at to delineate the stratigraphic and possible strati-structural traps an behaviour. Conceptual models were used to constrain the number of realizations OnePetro all of es. The spatial characteristics of geostatistical methods in variogram kriging and stochastic simulation have made them the tools of choice bit heterolithic interbedding with vertical heterogeneity and a wide range of layer flow properties. This paper describes methods of real-time minations. NMR helps to 1) detect thin beds 2) determine fluid type and if hydrocarbon is present 3) establish the hydrocarbon type and vo offshore high pressure-high temperature high-an OnePetro n by using a new methodology for depth and survey measurements corrections. LWD depth measurements are often considered inaccurat d in 1938 and it went on stream in 1946. Most ofOnePetro th supported by field studies and micro-seismic observations. This paper presents a study of stress reorientation around horizontal wells. Stres ost all operations in oil or gas production.ï¿½ A continuous profile of these parameters along the depth is essential to analyze these problem verlying shaly formation. Drilling through such depleted reservoirs can cause severe fluid loss and drilling-induced wellbore instability. Accura e for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements. e for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements. e for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements. e reservoirs that have moderate-to-low porosity were deposited in an inner- to midramp warm marine environment. The fracture systems pla ssociated with faults. Thus fracture characterization of this complicated area is very important to understand the reservoir behavior and he field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomi h) have been producing for more than thirty years. All the available informations indicate that the producing layers subdivided into Upper an was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limeston

ng time-lapse resistivity pressure and flow rate data from a permanent downhole Electrode Resistivity Array (ERA) and pressure and a pr nge to the industry. The practice of performing a drill stem test (DST) over a significant reservoir interval and attributing the properties of the w in East Kalimantan-Indonesia over decades despite technological advances.ï¿½ One possible reason has been postulated as alteration o hods are well documented. Comprehensive characterization of the wellbore rock relies OnePetro o (NMR) in Naturally Fractured Clastics Reservoirs of very low porosity (â‰ˆ 3.5%) in the Devonian of the Bolivian Sub-Andean reveals info sentative samples of the different fluids encountered in the formation are obtained. Usually the wireline or LWD petrophysical logs will guide s. These formations usually exhibit low resistivity contrast between water and hydrocarbon zones and high apparent clay content. Calculate epend on the acquisition sequence inversion parameters and the logging environment. Some modern NMR logging sequences are intende technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recogniz ntervals in the Gulf of San Jorge Basin oilfields. These methodologies have been successful only in a limited number of cases and a solutio complex completions. Evaluating the performance of these horizontal producers is critically important for improved reservoir management. C esented. This methodology uses NMR log data and electrical image data when avail OnePetro is lower than the pore pressure of the target formation of interest. The most widely recognized benefit of UBD is the reduction of formation d Mishrif formation. Developed as a limestone sedimented in a mid-ramp environment it generally consists of fine-grained packstones to wac opment. Traditional methods of identifying reservoir compartmentalization such OnePetro OnePetro oir compartmentalization for instance can result in non-optimal well placement completion strategy and facilities design as well as large e nalysis (DFA) is a new tool to reduce uncertainty associated with reservoir connectivity. Fluid data from DFA logs and various laboratory ana y for establishing the stabilized deliverability performance of multi-layer commingled reservoir systems using multi-rate production log measu ery oil fields where remaining oil saturations approach residual oil saturations it is possible to test these estimations using Pulsed Neutron hannel and bar sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations

ements (vertical distribution and direction) in the South Priobskoe field in western Siberia has created the need to determine the orientation e difficulties arises due to phenomenon known as supercharging which is caused by mud filtrate invasion. The supercharging results in an i sensitive to reservoir and operational constraints and uncertainties. This so called â€œOptioneering process was an iterative multidisciplina ertainty associated with the data acquired in the exploration and appraisal phases which can be ultimately used to forecast reservoir behav mps (ESPs).ï¿½ ESPs are an attractive alternative since they can achieve lower bottom hole flowing pressures.ï¿½ This can accelerate prod lmost as long as the oil industry has been in existence. Oil production from mature fields accounts for approximately 70% of the worldwide production and efficiency. Using appropriate processes tools and technology production surveillance is able to be conducted in efficient ma gressively pursuing production increment ventures one of the main components being the development of stringers which are present amon es integrated reservoir engineering formation evaluation geological and geophysical contributions.ï¿½ The objective of this paper is to exem n in the Waddell Ranch Project. The Project was implemented in three phases over a period of three years beginning in June 2000.ï¿½A and can increase reserves in stacked reservoirs. The approach will potentially reduce associated costs risks and uncertainties in spite of c otential is often not realized. Unlike greenfield developments mature oil fields deal with existing infrastructure and fluid export schemes with of Moporo Field located in western Venezuela different exploitation schemes were evaluated where intelligent completions have been high ld development plans surface facility design/de-bottlenecking uncertainty/sensitivity analysis and instantaneous/lifetime revenue optimizat into the tubing.ï¿½ The injected gas reduces the bottomhole pressure thereby allowing more oil to flow into the well.ï¿½ The optimal amou reservoir management and production strategy which optimises future recovery from an oil rim reservoir in the Betty Field offshore Malaysi tidisciplinary optimization team was built. The standard practices for production enhancement opportunities include logging nodal analysis e the heat goes at various times and places during OnePetro th ield development. Handling uncertainty and risk using probabilistic approach i OnePetro presents the full workflow for optimzing production and injection cycle times with the help of a simplified reservoir model (SRM) through the egies can be developed within a new systematic workflow using existing applications from many E&P departments. Detailed production da urface facility levels using only their respective knowledge experience and engineering tools without limited coordination between them so d time for project execution has been significantly reduced.ï¿½ Using these concepts it is now possible to conduct integrated studies succe in the development of the XJG oil fields in the South China Sea. The XJG fields are in a mature production phase and challenge COPC (th of the fields in the Oriente basin of Ecuador and neighboring Maraï¿½ï¿½n and Putuma OnePetro ustain target rate until mid of 2004. Artificial Lift is part of the long term production sustainability solutions for Khafji Field necessitated by the produced 40% to 60% of their original oil in place since 1991. Currently the field production is rapidly declining and water production is incre harged to demonstrate within a one-year time period measurable improvement in well productivity in the Saih Rawl field of Oman. Althou al low permeability reservoirs. The workflow was originally developed for gas reserves evaluation of the Lower Vicksburg (LV) sands and the r a client to agree to a forward contract for a service to be performed at a future date at some specified price. In this case the service provid

aximize hydrocarbon production in deep water turbidite reservoirs. The deep reading directional electromagnetic tool a latest-generation LW orizontal section has been drilled in three horizontal production wells all within Palaeocene-aged Balmoral turbidite sandstones below a Sel egions that are most favorable for well placement.ï¿½A technique is developed to apply this method to the problem of field development wh operations begin. Real-time downhole pressure data and surface flow rate information can provide a significant set of calibration informat ater flooded fields.ï¿½ It targets bypassed reserves to improve production and ultimate recovery from such fields at once.ï¿½ The method ly gas breakthrough and gas cycling can cause serious problems especially in a co-mingled production environment and heterogeneous ge projectâ€™s net present value (NPV) as modeled in a reservoir simulator. This paper has two main contributions: first to determine the effe f heavy oil and natural bitumen recovery. An optimal production rate and corresponding bottomhole temperature and pressure should be ma ace.ï¿½The solutions are derived assuming a cuboid shaped reservoir using a method of integral transforms.ï¿½The method can be appl e. Assuming a vertically stacked system of layers an analytic solution within each layer can be derived using a method of integral transform ayesian formulation and its implementation have difficulties in three major areas particularly for large scale field applications. First the CPU ral limitations. First the CPU time depends on the data points which are large for any brown fields of long history; second it requires large m process. A new criterion for measuring the deviation of the simulation mode OnePetro OnePetro orks have been developed to assist in the history match of reservoir models. This pape OnePetro pal Component Analysis which is currently used in computer vision applications. During history matching the spatial reservoir parameters at

sociated with heavy oil thermal recovery. The primary focus of the simulator is on the physics associated with steam injection and Steam Ass phases and components any component existing in any phase and requires no special ordering of phases or components. This type of fo ed difficulties modeling long horizontal wells due to the combined complexity of the wells and the reservoir. This reservoir is located in an off

ction wells. They are used to maximize the well to reservoir contact and improve oil recovery in a cost efficient manner. This is especially tru ector model and or small scale multi-well level is generally well understood.ï¿½ InOnePetro widespread influence on implications for wel OnePetro ing phases must be solved. When this equation system is solved implicitly a sy OnePetro e performance of oil and gas wells. This is achieved by curve fitting the past production performance using the rate-time data and extrapolat the productivity of producing wells especially in tight gas formations. The fracture-cleanup process is complex and may suffer from the pre able option. However despite the state of the art techniques such as multiple fracturing of horizontal wellbores the gas recovery from thes n carbonate plays where acid and fracture stimulation can be used to improve productivity the technique can be used for tight reservoirs an nd improve the development of gas-condensate field. In recent years numerous research efforts were focused on the developing efficient n anes or natural fractures. In shallow or over-pressured formations interfacial slip between formation bedding planes is possible when the ef nd post-fracture production profile leading to an optimum design and maximum production enhancement. The paper demonstrates the adv d when analyzing well test data.1 Current practices to quantify the non-Darcy flow effect in a vertically fractured well are mostly based on th contributes to the commingled well production. This paper presents a stochastic analytic production analysis technique for multistage hydra erpretive models of the boundary-dominated flow performance of vertically fractured wells located in closed rectangularly bounded reservoir r of hydraulic fracturing treatments in highly deviated wells. The non colinearity of the wellbore axis and of the fracture plane has initially ind erical model was developed which takes into account the interaction of steel casing cement and surrounding rock and allows for a curved any methods for building ANNs have appeared in the last 2 decades. One of the continuing important limitations of using ANNs however is ed. It is now a common practice to generate OnePetro by severe variations in facies. These challenges in the static modeling have a strong impact in the dynamic modeling which can be summa well during the process of water injection. The model is obtained from a theoretical treatment accounting for both mass transfer and heat tr mobility ratios when displaced by water in fields under waterflood or with active aquifers.This causes a triple hit on the recovery factor: Poo s of several stacked sands and is highly faulted resulting in a complex system of several compartmentalized reservoirs. The drive mechani ainty. Although some research is available in literature usually the effects of data uncertainty on material balance calculations are rarely con fe. While elaborating field development additions an operating company meets a number of problems falling into two categories: The prob orous media. Thermal diffusion pressure diffusion and molecular diffusion are included in the diffusion expression from thermodynamics o their impact on investment decisions have become very crucial in management decisions. This has seen the stocks of both experimental d ir simulation. In our full field review a systematic procedure was developed to OnePetro ation of â€“div(K(x)grad u) = f(x) the equationdescribing fluid flow through anisotropic porous media. The permeability tensor K(x) is allowe d with the use of dual-porosity/dual permeability models and the direct numerical simulation based on the â€œSugar Cube19 representation be connected to the fracture system or be isolated in matrix material which constitutes a triple porosity system.ï¿½ The modeling of the disp stribution than conventional statistical and geostatistical techniques allowing the integration of geomechanical data and models into reserv

actured Jurassic carbonate formation. These reservoirs contain multiple fluid t OnePetro OnePetro because of the capability to calculate fluid flow in multi-million cell geological models with reasonable CPU times. Recently streamline simu twork of fracture channels. This representation is conventionally described by a dual porosity model which is the one used in the present w gical models of petroleum reservoirs. These models are characterized by complex shapes and structures with discontinuous material prope sms; understand behavior of a particular proces OnePetro of various methods and research groups to quantify the uncertainty in the prediction of cumulative oil production. Previous results reported uracy. Especially in risk analysis where complex relationships between the uncertaint OnePetro ce facilities - because of thermodynamic changes that affect the flowing brines. These changes may be induced by temperature or pressure pment mandate significantly improved and timelOnePetro it is applied to heavy oil reservoirs.ï¿½ï¿½ Th OnePetro d is that the pressure field can be updated relatively less frequently and the saturations can be transported along the streamlines defined b essible fluids in porous media with mass exchange between phases. In this work we consider a streamline method for two phase compres gas field. Usually performance evaluations for infill wells are conducted using either much generalized statistical methods or numerical simu data and the assessment of uncertainty in forecasts for complex large-scale problems. A handful of papers have discussed reservoir chara eostatistical reservoir models and uncertainty assessment. Real time monitoring of pressures through permanent down-hole gauges is a re etween the ICDs is open or partially obstructed by the presence of packers and we describe the application of this model in a full-field simu omputationally than compositional simulation. But a principal limitation of black OnePetro aturally fractured Jurassic carbonate formation. These reservoirs contain multiple fluid types (gas-condensate and volatile oil) at near-critical andstone formations is known to be strongly water-wet. In contrast most carbonate reservoir rocks are believed to be mixed-wet or oil-wet nd its contribution in formation damage. In the study an advanced laboratory test prog OnePetro OnePetro f the discussion concerns the inertia resistance factor or the so-called beta factor Î² in the Forchheimer equation and whether the beta facto to open-hole formation evaluation often fail to predict how much oil should flow from them or even the location of the free water levels. A ts time and to this day still remains the largest onshore gas field in Dubai. This reservoir is characterized by a relatively low-porosity over-p the stress distribution around the wellbore induces deformation depending on many factors ranging from wellbore pressure history and roc Smarter.ï¿½Participants in the Forum have granted permission to present this paper on the basis that the authors are neither representing ormer Soviet Union a lot of attention was paid to oil recovery problems. Unfortunattelly the unfavorable economic climate of the late 1980-s 1960 when industry gained access to both areas. Exploration of these two petroleum provinces progressed almost simultaneously with bot cement sheath. The customary procedure is to use a model to predict potential failure scenarios and to subsequently design a sealant mat owever field studies indicate that large volumes of hydrocarbons remain located OnePetro ng. Since the formation sigma response is proportional to the salinity of the format OnePetro OnePetro ng oil recovery and reducing water cut. This paper presents a case study from the Bahariya Formation a heterogeneous fluvio-marine chan oth monobore and multilateral horizontal wells. However a clear understanding of zonal or lateral branch flow contributions still remains an i ce limitations in the short string section of the dual completion wells. The logging program was initiated in Kuwait Sabriyah Field where ther terpret pressure buildup data in Chayvo Field. With a lateral reach in excess of 8 km acquiring production logging data is difficult.ï¿½ Mem esult from the absence of early detection of a condensate bank in the near well bore OnePetro ironments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is cont ironments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is cont oring of bottom-hole pressure and temperature of two stacked reservoirs using one vertical observation well in a Saudi Aramco field. Perma voir conditions and results are presented for two wells in the Norwegian Sea. The measurement technique for use with wireline formationare evolving. A deepwater field in the Gulf Of Mexico (GOM) consisting of numerous wells with permanent bottomhole gauges has been on as and induced microseismic activity was monitored from a nearby observation well. The objective of this microseismic monitoring campaign metrically fracturing must adhere to mass balance equations. Therefore proppant placed in the fracture must be accounted for in the creat voir characterization purposes as well as the key element for identifying remedi OnePetro understand the flow distribution of bitumen and water along the horizontal reservoir interval. If this distribution is understood the distribution measurements to evaluate the formation inflow into a wellbore in which one or more of the completed intervals may be located in the annulu easurements for the evaluation of the formation inflow into a wellbore of which one or more of the completed intervals may be located in th of the backscattered light. This paper details a novel application of this technology using an optic fiber embedded in a 1/8th inch slickline ca open hole gravel pack lower completion in Enfield field Australia. The principle of the technology involves positioning a number of different ance. Traditional methods of estimating these parameters particularly for real-time detection and diagnosis of production anomalies have b ince they have a significant impact on flow contribution. There are different OnePetro OnePetro

on of the economic potential of the reservoir. Without this understanding a company's field development and operational decisions may not moving fluids. Low flow rates in horizontal wells means the fluid holdups in the stratified flow are very sensitive to the wellbore inclination an w below saturation pressure in some structurally-high areas where gas cap has increased in size compared to very small initial gas caps in t rstanding of reservoir characteristics and fluid movement causing production hindrance in an offshore horizontal well. The field example com aiming at the optimum oil production. Optimization of an oil producer is not easy as it might seem to be. Moreover oil price increase prom lping to quantify changes in rock and fluid properties along the wellbore to define hydraulic flow units and to understand the reservoir archi y to optimal reservoir drainage. However hitherto it has not been possible to monitor reservoir pressure changes in individual layers after a the warm-up phase of a steam-assisted-gravity-drainage (SAGD) well pair. A sequence of microseismic events was recorded with signal ch red Pereriv B C and D reservoirs. Restricted wellhead access high rates and differential depletion of the different reservoir intervals limit c g reservoir connectivity drainage and flow assurance. For those wells requiring sand control an additional constraint is that sandface sens l permeability conduitsâ€” â€œthief zonesâ€” if any. In the Sabriyah field in Kuwait dynamic measurements showed evidence of thief zones

ental to the workflows that target the optimization of the economic potential of the reservoir. Without an accurate understanding of productio re. Optimum and accurate determination of multiple phase fluid entry requires two primary measurements: 1) holdup or the cross-sectional UBD) horizontal wells. This approach will work in mixed-wet reservoirs and is particu OnePetro OnePetro itoring. Behind casing resistivity an important member of the comprehensive analysis behind casing services suite provides the required a fshore Abu Dhabi. The injected water preferentially follows the path of the of higher permeability zones since injection is done into formatio t. We will also show the benefit of the optimized casing material on the resolution of the crosswell EM resistivity images and describe the m and Water Alternating Gas) in a giant field in the Middle East. Cross-well EM data will help optimize sweep efficiency identify bypassed pa on from CBM is dominated by US production of 1.6 Bcf/year where an estimated 20 000 wells are in production from CBM reservoirs. Wyo called as cleats define the reservoir character and fluid flow potential. Cleats are commonly mutually orthogonal and occur perpendicular or ores for more than twenty years. However direct fracturing of coal seams has been notoriously inefficient. High fracture pressures in coal se an effort to improve well economics and to reduce the number of surface locations in populated areas the number of wells being drilled an mmercial success in producing these reservoirs depends to a large extent on successful hydraulic fracturing.ï¿½ There is growing evidence BM) formations such as the Horseshoe Canyon in the Western Canadian Sedimentary basin. A typical well has an average of 20 pay zone d States.ï¿½ With effective stimulation techniques these wells have demonstrated favorable economics compared to vertical wells in the sa rization efforts have been made and completion practices established to help understand the Barnett Shale reservoirs. The borehole image While shallow heavy oil reserves are extracted from pit mines deeper reserves can only be extracted through wells. Production of these res technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized al U.S. dry gas production. Typically Barnett Shale wells exhibit a rapid production decline following the initial hydraulic fracture stimulation arbonates at high reaction rate to create flow channels (wormholes"). The high reaction rate often needs to be reduced to allow wormholes elivering the required rates from Saudi Aramco fields. Therefore this form of artificial lift was selected to increase production rate from one nada's nonconventional oil reserves are estimated at just over 1 trillion barrels an OnePetro g and the wells are unable to flow naturally. Over the years a number of artificial lift techniques have evolved as a result of extensive researc had been drilled practically all the reserves of the main reservoirs within the production targets were put into production. There emerged a dstone gas reservoirs in this field have net pays with a thickness greater than 300 m and an average true vertical depth (TVD) of 1 400 m. a. This new method places sliding sleeve valves in the casing string and completes the well with normal cementing operations. The sliding s orizon. The Cartojani structure is located in the central alignment of the Moesic Platform. It is a monocline with large dimensions and low lay lls to optimize gas recovery in wells that produce free liquids in conjunction with the gas.ï¿½ Particularly important in this work has been the lls to optimize gas recovery in wells that produce free liquids in conjunction with the gas.ï¿½ Particularly important in this work has been the one with â€œgood porosity.ï¿½ Matrix permeability is low and natural fracture density can be quite variable in this reservoir.ï¿½ Thus this re has relatively heavy oil in place that is high in viscosity. With the understanding OnePetro ervoir Contact (MRC) Multilateral (ML) and Smart Completion (SC) deployment in Ghawar Field.ï¿½ The well was drilled and completed as uids across the reservoir strata. Historically completions with cemented casing packers conformance controlling fluids/gels and selective um reservoir contact (MRC) multilateral (ML) and smart completion (SC) deployment in Ghawar Field Saudia Arabia. A well was drilled an ars as part of the reservoir development strate OnePetro ontal and multilateral wells in all types and shapes. Horizontal and Multilateral applications become more commonplace to improve the well em was designed for perforating wells lifted with electrical submersible pumps (ESPs). The purpose of this project was to develop and apply e pump (ESP) system performance data. The approach extracts unbiased information from performance data and permits lifetime modeling ginning of the gas development program. Various types of acid systems including conventional emulsified and surfactant-based have been along the maximum principle stress and dominant fault orientation (northwest/southeast). Open-hole completions were considered the best

n permitted and more than 200 wells are now producing. The lateral play began in Richland County Montana and the success there is now s in the Western Siberia basin as a significant number of the oil-bearing formations in the basin are located near a water zone. These hydra rtical wells in the Khuff carbonates over the last several years. During acid fracturing the wormholes created by the reaction with the format e largest oilfield in Western Siberia. Placement advantage of fiber-assisted fluid already becomes obvious after initial campaign of four fract d water blocks. As the gas reservoirs being stimulated become tighter the perceived value of these additives has grown. This value must be acture height containment in layered formations. It has been well documented that in situ stress contrast is the dominant parameter controlli letion and declining quality of reserves have resulted in escalating drilling completion and workover costs per unit of gas produced. This in th disposing flowback and produced water to reduce costs handling the logistics of getting enough water to hydraulically fracture the well a voirâ€™s deliverability and what the optimum fracture half-length is as a function of geological setting and stress state.ï¿½ The application a depleted sandstone formations located in Bachaquero Tï¿½a Juana and Lagunillas fields in West Venezuela. This technique combines stim from underlying water zones by a weak stress barrier. Operating and service companies alike applied various techniques to prevent the bre red over vertical and deviated wells offering the advantage of maximized reservoir contact higher production rates and better access to res cuts. These wells are commonly not considered as good candidates for matrix stimulation. Water based treating fluids would enter prefere Complex geology and low permeability are the common denominator in todayâ€™s environment. Developing reserves under these condition tain the economic operation of their valuable assets. Large quantities of reserves OnePetro OnePetro wells to achieve maximum reservoir contact to maximize well productivity. This strategy has proven very successful over the past few years ure. In this environment emphasis is placed on OnePetro hi OnePetro pproximately 30 000 bopd and is on decline. A joint team from ONGC and Schlumberger carried out a rigorous process of candidate select uction performance of a vertically fractured well located in a closed rectangularly bounded reservoir.ï¿½ The solution for dimensionless prod ed formations exhibit a non planar or complex set of micro seismic events. This OnePetro d service companies have gathered significant amount of experience and knowledge. The sweeping success of hydraulic fracturing in West ique.ï¿½ The evolution of the completion technique has reached the point that OnePetro OnePetro orporation. This new method placed sliding sleeve valves in the casing string and completed the well with normal cementing operations. The g sleeve valves in the casing string and complete the well with normal cementing operations. The sliding sleeves would then be opened o r existing programs used with soft rock formations often do not provide satisfactory treatment designs. Difficulties emerge because hydrau ons without the use of polymer additives.ï¿½VES fluids do not form polymer filter-cake and thus viscous resistance of the fluid flowing th prove the Olmos production in the Caterina SW field in Texas. The reservoir is chOnePetro mped using a solids-free liquid CO2 foam-based visco-elastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast

mance in this area was not promising. Well Raguba E-97 in this area was not producing OnePetro ssful implementation of acid fracturing treatment in Marrat field. The acid fracturing treatment is quite challenging due to presence of high p rac and Pack completions exhibit positive skin values and traditional hydraulic fracture completions show discrepancies between the placed eservoirs.ï¿½ This existing technology is being utilized in new and innovative ways to provide operators a clearer picture of the fracture dev or this behavior are related to the characteristics of the porous media and are OnePetro rforming accurate borehole deviation surveys for hydraulic fracture monitoring (HFM) and neglecting the effects of the deviating borehole tra

acid; without nonuniform dissolution along the fracture face the fracture will close after pumping ceases and little lasting conductivity will b act the field development strategy. The correct estimation of the fracture dimension is critical to maximize the recovery factor of heterogeneo nsight about the fracture height (near-wellbore vertical coverage) of proppant-packed fractures. The existing tracer technology has a numbe here are two producing horizons of Jurassi OnePetro lity oil reservoirs there is still no simple practical production forecasting methodology for hydraulically propped fracturing stimulations for t sandstone reservoir using a numerical model. The fracture was explicitly modeled as a set of high-conductivity cells. At the gas velocitie rmeability formations under downhole reservoir conditions a severe pressure drop occurs at the tip of the fracture and a lag zone develops of acids such as regular in-situ gelled and emulsified acids have been used in order to achieve optimum fracture length and conductivity. hematical model used in this work is a practical alternative to estimate the degree of stimulation by means of a Stimulation Index (SD) and f ault. Fracture orientations were identified through a combination of alignment of event locations polarization of the seismic waves and injec problems for well completion. Various models have been developed to predict the onset of proppant flowback but the physics of the phenom atment is studied by taking into account the production induced stress field surrounding the initial fracture. It is shown that the propagation p nt frontal displacement of fluids from subterranean environment. Entrapment of residual fluid by the displacing one lowers down the displac xtent. An excessive fracture length may lead to an earlier than desired increase in water cut. Uncertainty in propped fracture dimension is re

a Joint Industry Project active since the year 2002. It is well documented in the literature that hydraulic fractures although successful often ctors eighteen producers and one gas injector to be completed in more than 4 300 ft of water depth. In order to maintain the oil production ast Brazil â€“ Carmï¿½polis and Sirizinho Fields â€“ on the revitalization of the oil production. The purpose of this work is to demonstrate th en made to reproduce their effects on fracture growth using numerical hydraulic fracture models. Such offsets have long been recognized as on to gas lift a well. The gas lift gas is produced downhole and bled into the production tubing via an auto gas lift valve designed for gas ope ix high rate gas fields currently on production with several more in planning stages. All of the wells require sand control and this has resulte rs being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing op rs being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing op hole wells is preferred to maximize reservoir productivity. Some questions that always come up for this type of wells are: will it be necessary ies that allows commingled oil production from multi-laterals wells in Shaybah inside expandable liner.Slim intelligent completions technolog water coning towards the heel (water can breakthrough anywhere in the well not only at the heel due to permeability (K) variation and proxi ology has evolved from intervention-less completion for sub-sea wells to new applications where intelligent completions are delivering better etion technologies that allows commingled oil production from quad laterals wells in Abqaiq field. Many intelligent completions wells have be th respect to properly incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if w permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on h PL) measurements with nodal analysis evaluation. This allows the effects of vari OnePetro ciently to improve the appraisal process and avoid unnecessary expenditure. At the same time an accurate reservoir characterization is the ally coincide with an increase in depletion water cut or changes in the artificial lift mechanism used to produce the hydrocarbon. Sanding is and shot density while minimizing perforation damage.ï¿½ However in tight carbonate reservoirs creating deep and clean perforations may pleted thus exposing the formation to potentially damaging kill fluid. To obtain a perforation tunnel with maximum productivity this transition in intervening highly deviated and long section of horizontal wells under live condition where slickline and E-line have difficulties. This pap District. Its main productive zones are the Merecure and San Juan formations which are sandstones characterized by their high permeabiliti pment of the HZ oil and gas fields operating as the CACT Operators Group (CACT) in the South China Sea. The HZ fields are stacked thin onsideration in designing the preceding perforating job. Aligning the perforations along the direction of maximum geological stress known a ing completed with the drilling rig until it is acidï¿½stimulated using a multi purpose barge and put on production. Some wells inï¿½ADMA O enhancement operations. Underbalanced perforating (UBP) which is widely used in well completions induces transient fluid flow that provid operations. Well trajectory temperatures and fluids can create uncertainties on both depth control and the accuracy of hydrostatic cushion so possibly cause excessive damage or swell to its carrier. Comprehensive understanding of the post-perforating conditions of the perforato on induced permeability impairment commonly referred to as the â€œnear wellborOnePetro liner charges against those created with conventional liner charges. Three of the tests involved shots into an outcrop carbonate rock called ne of drilling and completion induced permeability impairment commonly referred to as the â€œnear wellbore damaged zone. This connect maximum reservoir contact (MRC) wells. One of the objectives behind this strategy is to improve the well productivity by maximizing oil prod mation consolidation the large percentage of fines present in the reservoir the heavy oil the low frac gradients the low net-to-gross ratio th nks Block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50â€“60ï¿½ maximum hole viable solutions are available to enhance there production to an economically feasible level. The Hawtah field (see Figure 1) discovered in t nks Block 783 in the Gulf of Mexico. The wells produce primarily from thick fine-grained Pleistocene reservoirs. Because of the long length court. The field discovered in 1986 currently has 9 wells completed and 13 drainage points. Well A-4L is one of the completed intervals on iative is to gain a better understanding of Sand Control Completion (SCC) syste OnePetro Gravel Packing (OHGP).ï¿½ Though gravel packing is a proven method to stabilize the well bore controlling sand and maximizing product eved complete annular packs and zero mechanical skin factors resulting in well productivity indices that are significantly greater than expe quired sand control. The lower zone was completed OnePetro rilling slanted or sub-horizontal wells through several shale bodies to obtain high gas rate performances during the production and the injec ability to deliver high-productivity wells. Currently there are two techniques used for gravel placement one utilizing low-viscosity carrier fluid s in drilling technology in recent years horizontal wells with lengths ranging from 2 000 to 6 000 ft have become more common. Executing th gravel packing is the preferred sand control technique adopted by many operators in this region. It is considered one of the proven metho a cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels which act as conduits between the reservoir and cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels which act as conduits between the reservoir and t e tied back to a floating production facility. Nine horizontal oil producers and four S-shaped gas producers are planned and all will require so n in Australasia. This recent technology was simultaneously applied in a production well and a water injection well and served as a demons minating the need to have a rig on location. To date six screenless completions have been performed for a major operator in the Gulf of Me have been proposed in the past including various solutions based on permea OnePetro

introduced to the field. The sanding severely impaired the performance of field and consequently led to significant economic loss. AGOCO na held in Beijing 5-7 December 2006. Abstract Sand production is a major concern for many operators. It can impact production cause e een reported accompanying obstruction of production for majority of production wells since the onset of production indicating possible sand er of possible mechanisms have been proposed. This paper presents the results of a series of laboratory perforation-collapse tests aimed a field-development team did not opt a priori for gravel packs in every well. While OnePetro m the reduction in pore pressure. In weak but consolidated sandstones this can lead to shear failure in the rock surrounding the perforatio eld gas development in offshore Peninsular Malaysia. The objectives of the study were 1) to develop strategies to maintain mechanical and sed on low-friction and solids-suspension (fracturing and CT-cleanout) characteristics of the fluid. In the last 4 years the application of visco e laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. We conducted a series o oir to the wellbore. Depth of penetration of live acid is the critical factor in determining the success of an acid-fracturing treatment. Depth of carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. Durin f carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. Duri coelastic diverting acid system to evaluate the effectiveness of this system in achieving diversion and zonal coverage in large limestone re ne and packstone limestone with a bottomhole static temperature (BHST) of about 150ï¿½F. The formation permeability often exceeds on d the length of the horizontal wells make acid placement and diversion difficult particularly in high-water-cut (WC) wells in which water has b s as the oil price remains record high. Matrix stimulation is often preferred as it could generate additional production gain with relatively low d iron sulfide precipitation is a major requirement during acidizing treatmen OnePetro n 200 m) the stimulation process is much more complex because factors such as reservoir heterogeneity damage to each zone matrix min wer. However there are two major drawbacks associated with using concentrated HCl solutions in deep wells. The first is its high reaction ra ew wells have been dead for sometimes due to high water cut (60 to 80%). In all cOnePetro m 20 mD to as high as one Darcy.ï¿½ However the production from this formation OnePetro is oft then. The most prolific reservoir is the Caballos Formation a thick (250 ft avg.) laminated sandstone located at a depth of 6100 to 7500 ft in the entire zone of interest. Successful matrix treatments depend on the uniform distribution of the treating fluid over the entire interval. W where large-scale fracturing and coiled tubing operations have been on-going for the past six years.ï¿½ In the mainly brown fields tertiary re e the outcome of acid stimulation treatments which are routinely performed to improve well productivity.ï¿½ However most previous studies that creates a fracture having higher fracture conductivity and/or penetrating an area of higher pore pressure than the previous fracture. Re ons that are more sensitive to water treatments (high capillary pressure swelling clays etc). In particular the Frontier Formation located in B yomingâ€”due to the low formation permeability and rock propertiesâ€”and have been proven effective but still not perfect. Limitations on t - or reservoir-specific approach to maximize production. Integrated solutions use a performance-based process that integrates petrophysic e liquid (water/condensate) is trapped near the wellbore due to strong capillary forcOnePetro d water from adjacent wells presenting a challenge for the operating company. Greater oil demand coupled with limited surface water handli ment evaluation program. The effectiveness of these tools and their evaluations are often challenged and are not regarded as a replacemen r tests (CCT) has been developed. It can be used for estimating the key reservoir parameters such as reservoir pressure permeability and one with â€œgood porosity.ï¿½ Matrix permeability is low and natural fracture density can be variable in this reservoir.ï¿½ Thus this reservo reservoirs using commingled production. The specialized diagnostic procedures are based on rate-transient analyses and uses historical pr y been the main source of permeability and skin estimation in formations. However if a well is completed as a multi-layer commingled produ y-time pressure behavior. Some of the main reasons for partial penetration in both fractured and unfractured formations are to prevent or d e is no standard definition in the petroleum literature. The pressure diffusion corresponds to an instantaneous propagation of the pressure s eir exploitation plans more realistic.ï¿½ Pressure transients are the most effective way to understand the dynamic behavior of the reservoir. 2004) Levitan (2005) and Levitan et al. (2006) and Ilk et al. (2006a b). These works offer new solution methods to the long-standing deco

oirs since they have a significant impact on flow contribution. There are different methods to characterize these systems based on formatio ions. Data acquisition in such environments requires reservoir information of the highest quality before expensive development plans can be olute Openhole Flow Potential (AOFP) in deep water exploration wells in India. These gas bearing reservoirs are vertically heterogeneous w of gas-lifted wells is a very difficult operation. Owing to low retention times of the gas the quality of separation and existing instrumentation e performance of multiphase flowmeters in gas-condensate reservoir applications. The remoteness of the operation and the roughness of w uch characterization of reservoirs is as accurate as the data used for interpretati OnePetro e replacing conventional test separators. These MPFMs are usually tested and calibrated in laboratory controlled flow loops using idealized etering. Traditional means of well testing have been deployed for years and used consistently for reservoir and production management. Ho nd offer a more compact measurement solution than does the traditional separator approach. The interpretation models of traditional multip ctives to quantify the water and gas production evaluate the performance of slugging/intermittent wells for procurement actions evaluate th

of Gas Volume Fraction (GVF) of 0 to 85%. There is still some doubt about the performance of this type of device especially in the High (9 ory matching of full-field reservoir simulation models and also in situations where existing simulation models could be used in well test interp duction data. The Î²-derivative function was recently proposed for the analysis and interpretation of pressure transient data [Hosseinpour-Zo any situations however the derivative of the measured pressure data is uninterpretable or worse misinterpreted because of various artifac al oil production well and one in a vertical water injection well. Pressure transients were created and the streaming potentials generated by

ns (e.g. hydrocarbon deposits) must also be protected against CO2 contamination. Wells are generally recognized as a weak spot in CO2 arge-scale demonstration project. This estimation is the first step of a geomechanical study on seal integrity. One principal stress is assume feat the purpose of storage but also badly affect human health or the environment. Indeed cement degradation and casing corrosion in inje ) the injection of CO2 as a pure component or as part of a mixture has proved to increase the productivity of oil and gas reservoirs. Optimiz the storage reservoirs are saline aquifers exploration data for proposed injection sites are extremely sparse. The special behaviour of CO2 ge. The CO2SINK project is a R&D project mainly supported by the European commission the German Federal Ministry of Education and R c concentrations by capturing emissions at the sourceâ€”power plants or chemical unitsâ€”and then storing them in subsurface reservoirs tions and chemical reactions between fluids and rocks inherently affect the state of stress inside the reservoir and in its surroundings. Besi

and has an Along Hole Depth (AHD) reach of 7593 m/24911 ft which is a world record for Extended Reach Drilling (ERD) from a floating vious owner. These include formation instability directional-drilling control issues and thin complex reservoirs which are poorly imaged on s

ced nearly half a billion barrels of primary oil. Over 700 reefs make up the northern trend and more than 300 reefs have been located in the very (EOR) processes are becoming economic in todayâ€™s environment. The natural CO2 sources come to be an excellent opportunity b are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences alo id in the near-wellbore region forms a ring that may significantly reduce the gas relative permeability and consequently the well productivit r characteristics from an eastern Venezuela formation. Due to the complexity and number of variables involved in the process SAGD pres sis the paper also addresses the economic value of the campaign. Oil production from this field with complex geology and reservoir mecha

so imposed various damages to the oil zones. Since 2002 a joint industrial project was set up to study the feasibility of performing water s and have been an ongoing concern. The exclusion of this water represents a challenging task by itself especially in case of multiple zones i f infill wells required for field development. However they come with a disadvantage in regard to carrying out a successful intervention when ssfully applied by setting an inflatable bridge plug (TTBP) in the 6 1/8 open hole at 10 600 ft at 88 ï¿½ and capping it with cement and gel u challenging in under-pressured reservoirs with openhole completions such as in the Boscan field in West Venezuela. Gravel-packed slotte and ever increasing treatment costs. It may cause major economic and operational problems for several reasons. It requires increased cap n this case is a rigless water shut-off treatment which involves an intensive process starting from candidate selection and finishing with pos oil and gas Exploration and Production Companies. Development activities in the deepwater face significant challenges.ï¿½ Of particular co o characterize oil/water flow through experimental data. The tests were conducted in a 2-in. horizontal test section using tap water and min on of flow lines and wells separation and interpretation of production logs. In this study the oil/water pipe flow was experimentally investiga also accelerate the recovery.ï¿½Sensors flow-control and other devices can be used to manage the production from the commingled rese mited coordination between them sometimes bypassing important considerations from other components of the overall production system o d promote production interruption due to the formation and deposition of hydrocarbon solids such as asphaltene wax and hydrates anywhe acterization and flow assurance data. The subject of this paper is to demonstrate the importance of accurate and representative fluid charac operational expenditures since the presence of CO2 can cause corrosion failures. Carbon dioxide also denotes an issue for health safety a an extended production test may be too expensive or non feasible. Increasingly geochemical techniques are being deployed to determine

ossibly when laboratory data are not available. Correlations to estimate values of these properties have been developed that are based sole on in many applications. In this work a new set of MBO PVT correlations was developed. The four PVT functions (oil-gas ratio Rv solution tational grading. Asphaltenes are known to exist in crude oils as a colloidal suspension but which had not been well characterized in the lab d with two downhole fluid analyzer modules helped understand reservoir fluid characteristics identify production zones and optimize perfora a are critical for reliable modeling reservoir-engineering calculations and performance predictions and for subsequent economic analysis. C ng and operation. Traditionally fluid information has been obtained by capturing samples and then measuring the pressure/volume/tempera e clean-up and identification of first-order impact parameters is of paramount importance for the design of new generation WFT probes tha ng reservoir compartmentalization evaluation and support flow assurance analysis. It combines known and new fluid identification sensors

½ In this paper we present comprehensive formation evaluation case histories with formation testing utilizing a focused sampling probe in w o an NGL or GTL facility because even a tiny amount of H2S may dictate a prohibitively expensive upgrade. Detecting the presence of H2S

of a single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality large and mistakes are costly. Compositional grading has been known for over 50 years but the topic received little attention until the 1980 . The reservoir pressure and temperature in such reservoirs are very close to the critical point and therefore small changes in reservoir con d-composition analyzer using visible near-infrared (NIR) spectroscopy. For optimal oil production assessing the spatial variation of fluid pro shore deepwater environments many reservoirs are multilayered and highly variable in terms of connectivity permeability and fluid properti e also encountered for instance due to thermal forces acting. Recognizing these behaviors downhole is a complex process that requires a d samples from openhole logging help operators optimize investment in both upstream and downstream facilities. When a formation fluid s

i 1999 Ghorayeb 2003 Fujisawa 2004 Elshahawi 2005 and Kabir 2006) that have dealt with complex fluid columns showing compositi tion spectra used to compute properties such as hydrocarbon composition and gas/oil ratio (GOR). Abrupt changes in these fluid properties and operation. Traditionally fluid information has been obtained by capturing samples and then measuring the pressure/volume/temperatu

thermal environment.ï¿½ These methods were designed especially for heavy oil applications and use in numerical simulators.ï¿½ The meth nt during the production of heavy oils where steam is used to reduce the viscosity of heavy oil or in cases in which submersible pumps are

limits. Also the time required on station to clean up before sampling is significantly reduced in comparison to conventional sampling metho tive samples for laboratory analyses. In order to recover uncontaminated samples fluid is first pumped out of the formation into the wellbore nvironments accurate fluid characterization becomes more critical. This can be said for the formation tester DST and multiphase sampling re of the transient evolution of flow and more accurate picture of the volumes and rates especially in cases of condensate and heavy oil en agents. Unlike HCl the reaction of organic acids with calcite is reversible and the reaction products can precipitate at certain conditions. The asses a myriad of challenges: it is a depleted (180 bars reservoir pressure at 2400 m) layered dirty sandstone reservoir with a low permeab rgely clean and undamaged (and not representative of the sandstone conditions in actual producing wells). This study proposes novel appli ave been identified which provide improved halite inhibition. Their inhibition performance was studied and compared with commercially ava

ons to understand and quantify the naphthenate-soap-deposition problem. Static bottle tests were conducted to determine the precipitation anced risk of sand production both of which are undesirable. The impact stresses fracture sand grains in the vicinity of the perforation tunne density but unfortunately it is restricted by the perforation damage zoneâ€”a region of low permeability material surrounding the perforation ability restricts fluid flow in tubing and perforation fails electric submersible and rod pumps and plugs surface equipment. Local industry off as an additive have been offered to this region. This service proved to be very effective in the Permian Basin using borate crosslinked fractu wnhole inflow control devices allow for the flexible operation of non-conventional wells.ï¿½ By placing sensors and control valves at the res he upper part of the production string and Celestite or Strontium Sulphate (SrSO4) mostly found in the lower part of the production string a e stripping in a sandstone reservoir.ï¿½The formation brine composition suggests that a moderate to severe barite scaling tendency will re egions for the purpose of efficient history matching. Ideally the regions in a reservoir should be independent in terms of their effect on the o isualization of streamline-based flow pattern and injection allocation between each injector and producers. Such capability has made stream ce due to the magnitude of reserves and scale of development.ï¿½ Streamline simulation brings immediate added value due to its ability to ore than 2 million stb/d in early 2000s. Field is now on decline and currently one of the major challenges is to monitor the advancing fluid le ction declined due to gas-loading backpressure and reduced permeability in the target formation. The fast decline of the gas wells during th tern floods in several gulf fields. As these new floods are established it is important to understand the water saturation between wells to pro ding the Sabiriyah Mauddud field. This effort required a new way of managing this reservoir in NK: a multifaceted approach of balancing voi th production rates ranging from 200 to 600 barrels of oil per day (BOPD) of extra-heavy oil (8ï¿½API gravity and viscosities of 2 000 cp at a ery of heavy and extra-heavy oils using thermal and non-thermal methods. Steam-based thermal recovery processes are more efficient in lo ses can be achieved by using microwave heating assisted gravity drainage.ï¿½ In this study the feasibility of this method was investigated. iderable original oil in place existing in the area. Owing to the high viscosities widely different formation thicknesses and heterogeneities fou ing challenges in this area include drilling of very reactive shaleâ€™s shallow kick off depths and high build rates. Unconsolidated sandsto ing due to observed variations in oil viscosity heterogeneity related to complex mineralogy a possible dual porosity system and the presen ntaining them in single phase condition for lab analysis interval pressure transient testing (IPTT) for characterizing of permeability anisotrop

mposed of massive sandstone unconsolidated and traped very high viscous oil. Production performance of vertical wells indicates that the r

eld. An inherent problem with these wells is poor acid placement during matrix acidizing especially in reservoirs with high-permeability cont

e all classical problems due to fluid behavior met by multiphase metering device in extra heavy oil including classical separator. Heavy and

res and can result in potentially damaging precipitation reactions. In conventional acid treatments fluid is usually pumped in multiple stages chimovskaya formation of Urengoiskoe field is one of Russiaâ€™s giant low-permeability gas condensate fields. The main objectives of the

HTHP) reservoir fluids have elevated the importance of fluid properties. Like rock properties fluid properties can vary significantly both aeri

result in friction pressures that are too high and may prohibit the treatment from achieving the design goals.ï¿½ With titanium (Ti) or zircon these treatments. The problem is exacerbated when treating high temperature formations and compounded with the difficulty of providing a

emperature in real time in JFYN-01 gas well. Permanent down hole system provide bottom hole pressures and temperatures during the pro with the fact that fracturing has to be performed from a vessel make the execution of fracturing treatments operationally difficult and challen le damage have been reported in these wells. Currently various formulations of mud acids organics acids and solvents are used to treat d metal in solution over time with minimal precipitation. A series of field samples from high-temperature (149ï¿½C) sandstone reservoirs in a uire continuous improvements with regards to fracturing techniques. Typically viscous polymer based fluid had being used with acceptable ng the capillary forces and enhancing the clean up of trapped water at low drawdown pressures. Five different chemicals (A1-A5) are evalu water samples collected using a formation tester and spectroscopically determining the pH in the laboratory at reservoir conditions. Water c

e (OH) completions in the Cleveland tight gas sand of the Texas panhandle. Horizontal wells have been drilled extensively in this low perme

d process enables the data and activities of multiple domains to be integrated for single-well completion optimization and field geocellular an a better understanding to the effectiveness of reservoir stimulation. Massive hydraulic fractures from two wells in the Rocky Mountain region tical importance in field development planning including well spacing pattern water injectors location that will lead to desired line drive me ville Marcellus Woodford etc.). These plays are partly technology driven and partly economics driven. Modern well log evaluation techniqu ing a range of fluids including slick water linear gel crosslinked polymers and CO2 emulsions. Most of the productive sands are associated

reasons for the success of this technique vary but the two main reasons are related to the undisputed effectiveness of hydraulic fracturing a e reservoir in the Guangâ€™an field Xujiahe formation mainly consists of Xu-2 Xu-4 and Xu-6 formation. The lithology of the Xu-6 forma s been produced within the PNZ. As the fields mature the easy produced oil in the high permeability intervals is diminished by increasing wa luvial channel sandstones of the Upper Cretaceous Lance Formation after multistage hydraulic fracturing. Single sand body pay zones wou nomic success of wells in the Uinta Basin.ï¿½ The integrated SWM involves the development of a petrophysical and a mechanical stress m ring data including hydraulic fracture data. The reservoirs consist of several sand units over a gross thickness of 4 000 ft in a fluvial deposit e in marginal tight gas reservoirs. The high cost of hydraulic fracturing increases the need for an effective and useable petrophysical model

hallenges are often found in both acquiring the adequate data and assessment of the fractures/sub-seismic faults in the oil based mud bore asing demands of various types of formation testing measurements to satisfy various reservoir evaluation objectives. Thus the complexity o han 0.1md and porosities between 3-10PU do not produce commercially. While hydraulic fracturing is widely used to improve the economic e projects. An elusive challenge has been to gather fit for purpose pressure data in these tight formations due to the nature of the rock and t

eservoir evaluation model. However acquiring this data in low permeability reservoirs can prove challenging. There is no stable flowing pres mately 2 500 m. The complex geology lack of reservoir information and lack of technology availability caused a 20-year gap between disco t require stimulation have realized sustained success with horizontal completions. One example of such success is the Cleveland Sand of n ates made up of single p.u. porosity dolomites. Prospective drilling of the territory demonstrated high heterogeneity of this formation. Prospe

ted. The measurement of mobility of the different phases throughout the transition zone which is affected significantly by complex rock hete

edium size fields. Inappropriate strategies and methodologies of exploitation affect the overall recoveries and economics of the project. This

ert non-monetary criteria to common monetary equivalents i.e. assigning costs allocations regarding public response to a proposed project a analysis. Nevertheless it is still one of the most common ways in which decisions are made in the petroleum company. By improving judgm ng and minimizing the geological uncertainty and maximizing or increasing the well bore exposure in the desired structure.ï¿½ During the co has been obtained from special core analysis (SCAL) from a limited amount of cores due to time and cost. Rock typing is often used to help nal spatial information of reservoir characteristics. For example cores and logs have excellent vertical resolutions but very small lateral rad le. Once dual porosity is present it is found that neural network using conventional logs can not distinguish 2 rock types having the same ra ding of the sedimentary environment in the study area in Krishna-Godavari basin (KG basin) along the east coast of India. The present stud by common lateral and vertical facies changes that are responsible for uncertainties in the modeling of the reservoir heterogeneities. A reali oir fluids enables sealing barriers to be proved and compositional grading to be quantified; this information cannot be obtained from conven d with two downhole fluid analyzer modules helped understand reservoir fluid characteristics identify production zones and optimize perfora nt flow units encountered in these reservoirs. The process of identifying the flow units becomes non-trivial in the presence of extensive diag st not only because the sands within the formation are hydrocarbon bearing but also because of the complexities associated with its evalua a including neutron capture spectroscopy and capture cross section opens up new opportunities for formation evaluation on LWD. The co se sources could not be obtained with any other method. While the potential risks involved with the use of such sources have always been

urface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent net res and surface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent n at are sensitive to carbonate rock texture have led to an improved workflow for petrophysical analysis of carbonates. The authors have earlie um grained although coarser sand is common in the lowermost thick sandstone units. Both anhydrite and carbonate cements are present w lly cored interval consists of interbedded limestones and dolomites with anhydrite cement and features a wide variety of textures.ï¿½ In som ness.ï¿½ The reservoirs are highly permeable but the silt and clay laminations affect the reservoir permeability in each layer resulting in ch

s can provide estimates of sand resistivity and volume fraction but good results depend on the choice of the anisotropic shale point. The sa ervals. In reservoirs swept with water effects of rock electrical anisotropy on logging-while-drilling (LWD) apparent resistivity measurements he low porosity low matrix permeability and heterogeneous sedimentological characteristics of these fluvial deposits. Fracture corridors and Fluid sampling and downhole formation fluid analysis measurements also provide information for assessment of fluid complexity composit Studies identified a conundrum with respect to core and image log correlation of discontinuities: fractures and faults seen on electrical imag nd possible strati-structural traps and their associated reservoir setting. Seismic attribute analysis of 350 sq. km. of 3D seismic data of Al-Kh

ave made them the tools of choice for reservoir modeling. Such techniques are especially useful to characterize the reservoir connectivity a per describes methods of real-time and high-resolution formation evaluation and formation testing used to characterize such reservoirs. Th tablish the hydrocarbon type and volume and finally 4) determine the permeability of the sands (as opposed to that of the sand-shale syste

ments are often considered inaccurate and therefore not as reliable for well-to-well correlations correlations with data acquired with wireline

tation around horizontal wells. Stress reorientation has been calculated for different scenarios and patterns of horizontal injection and produ s essential to analyze these problems which include wellbore stability sand production fracturing reservoir compaction and surface subsid g-induced wellbore instability. Accurate and reliable estimates of horizontal stresses can provide an early warning of impending drilling probl -rate production log measurements.ï¿½ Both linear and non-linear systems are addressed in this paper providing a basis for the analysis o -rate production log measurements.ï¿½ Both linear and non-linear systems are addressed in this paper providing a basis for the analysis o -rate production log measurements.ï¿½ Both linear and non-linear systems are addressed in this paper providing a basis for the analysis o nvironment. The fracture systems play a significant role in production in these reservoirs and it is essential to identify areas of high fracture stand the reservoir behavior and hence assigning the best completion intervals for the producing wells. In this paper we developed a work sts mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties o ing layers subdivided into Upper and Lower Arab are fractured to varying extents. As a result a better understanding of the fracture netwo eservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservo

Array (ERA) and pressure and a production logging tool. The primary objective of this Fluid Movement Monitoring (FMM) setup and experim and attributing the properties of the produced fluid to a single reservoir fluid compartment is problematic. Overlooking the variation in fluid p has been postulated as alteration of near-wellbore formation properties during drilling operations.ï¿½ The relatively tight gas sands are dril

he Bolivian Sub-Andean reveals information till now incoherent compared with core data. As it is well known when the rock does not have p or LWD petrophysical logs will guide the sample acquisition program. This typically means that resistivity and nuclear logs are used to infer igh apparent clay content. Calculated water saturations are high and need to be accurately split between clay-bound capillary-bound and f NMR logging sequences are intended to be applicable over a wide range of environments and include measurements of transverse relaxat sed. Written by individuals recognized to be experts in the area these articles provide key references to more definitive work and present mited number of cases and a solution that has field-wide applicability has been lacking. This project attempts to optimize previous results us r improved reservoir management. Conventional production logging tools cannot meet the challenges of logging horizontal wells especially

f UBD is the reduction of formation damage by minimizing the drilling-mud leakoff and fines migration into the formation. It also facilitates th ts of fine-grained packstones to wackstones that is highly bioturbated. The average thickness is about 300 ft with an average Net of 170ft in

nd facilities design as well as large errors in reserves drainage volume and production rate predictions. Downhole fluid analysis along with c DFA logs and various laboratory analyses are studied to elucidate hydrocarbon composition variations in large reservoir sand bodies. This p sing multi-rate production log measurements. Both linear and non-linear systems are considered in this work providing a basis for the anal e estimations using Pulsed Neutron Decay (PND) logging to monitor water saturation changes. Such monitoring techniques can identify inco log data and performing correlations among nearby wells proved to be inconclusive in identifying gas reservoirs owing to their thin beds hig

he need to determine the orientation and magnitude of the least principal stress. The presence of impermeable shales between producing s n. The supercharging results in an increase in sandface pressure which is above the reservoir pressure. Therefore any calculation of initial cess was an iterative multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir pro tely used to forecast reservoir behaviour hydrocarbon recovery and production. This particularly applies to marginal fields where uncertain ssures.ï¿½ This can accelerate production and improve recovery. This paper outlines the workflow used for candidate screening completio pproximately 70% of the worldwide oil production. Unfortunately more often than not mature oil fields equate to high cost and low producti able to be conducted in efficient manner. These tools play an important role in well diagnostics to cater for appropriate production optimizat of stringers which are present among all the major offshore oil fields. One of the technology contributions to Saudi Aramcoâ€™s effort is pr The objective of this paper is to exemplify geosteering challenges when drilling horizontal power water injector across Permian eolian sands ears beginning in June 2000.ï¿½A total of 63 wells have been tested with well site compression; there are now 52 permanently installed co risks and uncertainties in spite of complex geological structures and drainage patterns. The new workflow encompasses planning from co ucture and fluid export schemes with capacities designed for peak production sometimes decades ago and/or different production technique telligent completions have been highlighted. A pilot well with inflow control valves (ICVs) was proposed with the goal of maximizing the well ntaneous/lifetime revenue optimization from a hydrocarbon field. This involves among others the usage of reservoir simulators surface-ne into the well.ï¿½ The optimal amount of lift gas to inject into individual wells depends on a number of factors including inflow performance r in the Betty Field offshore Malaysia. The reservoirs consist of good quality sands in a coastal depositional environment with an anticlinal s ities include logging nodal analysis and well engineering technologies. Usually the older the field the more challenging to achieve addition

d reservoir model (SRM) through the set up of an integrated asset model (IAM) to validate the SRM results and control the actual production epartments. Detailed production data from many sources can be used within simulation models to give a good representation of future fiel mited coordination between them sometimes bypassing important considerations from other components of the overall production system o to conduct integrated studies successively in a continuous chain of studies as if they were on a conveyor belt.ï¿½ For example field deve tion phase and challenge COPC (the field operator) with surface fluid handling capacity issues as a result of high water cuts. Additionally th

s for Khafji Field necessitated by the increase of field water cut and depletion of reservoirs.ï¿½ In order to make up for production decline in clining and water production is increasing. However through reservoir surveillance data geologic and reservoir modeling significant recove he Saih Rawl field of Oman. Although the field has been producing for more than five years the results shown are based on a one-year ap Lower Vicksburg (LV) sands and the paper illustrates the key steps in the methodology. Developing Lower Vicksburg sands has been a gre price. In this case the service provider is contractually bound to provide the service at the pre-agreed price within a specified time window

magnetic tool a latest-generation LWD (Logging While Drilling) measurement was the technology differentiator for optimizing well placemen ral turbidite sandstones below a Sele shale cap rock. To maximize reserves recovery the horizontal drainholes not only had to cut as much he problem of field development where field production profile moves through successive phases of buildup plateau and decline.ï¿½This r ignificant set of calibration information early in the life of the reservoir. In this paper we describe a method for comparing a set of assumed uch fields at once.ï¿½ The method is based on production engineering concepts it is very time efficient and requires only a minimum of da environment and heterogeneous geological conditions. For the last years high resolution geological models have been widely used to plan tributions: first to determine the effect of production constraints on optimal well locations and second to determine optimal well locations u perature and pressure should be maintained to improve SAGD cumulative oil recovery and the steam-oil ratio. SAGD optimization work inc sforms.ï¿½The method can be applied to calculate the pressure as a function of position and time when using any continuous function to d using a method of integral transforms. We fully account for crossflow between layers by coupling these analytic solutions together and solv cale field applications. First the CPU time increases quadratically with increasing model size thus making it computationally expensive for f ng history; second it requires large memory to save the gridblock pressure and saturation per each time step used in the forward model. Th

g the spatial reservoir parameters at grid blocks are adjusted in order to obtain a simulated response close to the observed response. This i

with steam injection and Steam Assisted Gravity Drainage (SAGD) and to simulate such models efficiently using parallel processing. The s ases or components. This type of formulation is desirable for flexibility in reservoir simulation but has not previously been used in commerc oir. This reservoir is located in an offshore field that produces oil from a relatively thin oil rim. The reservoir also contains a large gas cap tha

fficient manner. This is especially true for offshore fields where these wells are used to drain large areas with limited platform capacities. Co

ng the rate-time data and extrapolating it to predict future performance with the primary aim of estimating reservoir remaining reserves and omplex and may suffer from the presence of a yield stress non-Newtonian fluid in place and both mechanical and hydraulic damage to the llbores the gas recovery from these reservoirs is frequently unsatisfactory. Poor reservoir rock quality strong stress dependency in perme e can be used for tight reservoirs and multiple compartments or anisotropic reservoirs with high permeability contrasts. Reliable evaluations ocused on the developing efficient numerical scheme for full-field simulation and have been facing the problem of tremendous computation dding planes is possible when the effective normal stress on the bedding interfaces is low. Fracture height growth could be hindered or stop nt. The paper demonstrates the advantages of using explicit numerical simulation in contrast to analytical modeling.ï¿½ Conventionally a actured well are mostly based on the work of Guppy et al. 2-6 where simple empirical correlations were developed in the form of apparent d alysis technique for multistage hydraulically fractured wells*. Based on Bayesâ€™s theorem the new technique integrates production perfo sed rectangularly bounded reservoirs.ï¿½ In particular improvements in the characterization of the dimensionless productivity index of verti of the fracture plane has initially induced significant tortuosity effects and premature proppant screenouts. The length of the perforated inte unding rock and allows for a curved path of the fracture. The model incorporates an effective finite-difference numerical method for solving mitations of using ANNs however is their poor ability to analyze small data sets because of overfitting. Several methods have been propos

amic modeling which can be summarized in the following points. First the vertical sequence of sands and shale leads to the difficulty in dete ng for both mass transfer and heat transfer between a horizontal well and a reservoir. The treatment is 1D linear in the wellbore and 1D radia iple hit on the recovery factor: Poor displacement efficiency Poor areal sweep Poor vertical sweep This is made worse by reservoir hete alized reservoirs. The drive mechanisms of these reservoirs range from strong gas cap drive to strong water influx or combinations of these l balance calculations are rarely considered and quantified in most studies. This work presents an approach to properly quantify and accoun alling into two categories: The problems associated with the quality and quantity of initial data (ID). Very often when the development hist expression from thermodynamics of irreversible processes. The formulation and the numerical solution are used to perform initialization in n the stocks of both experimental design and response surface techniques in the E&P industry rise significantly as an alternative to the mo

he permeability tensor K(x) is allowed to have discontinuities. Transmissibility coefficients are obtained from local numerical flow experiment e â€œSugar Cube19 representation of the fractured porous media. Serious spatial inhomogeneity of the saturation distribution in porous m system.ï¿½ The modeling of the displacement of oil from the vugs can not be made with conventional dual porosity reservoir simulators sinc hanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagat

PU times. Recently streamline simulation has been applied to fractured reservoirs at the geo-scale. However these simulations have been hich is the one used in the present work. More precisely the porosities and absolute permeabilities at each point of a reservoir are considere es with discontinuous material properties that span many orders of magnitude. Models that represent fractures explicitly as volumetric objec

roduction. Previous results reported on this project suggest that the randomized maximum likelihood (RML) method gives a biased characte

induced by temperature or pressure changes or by mixing of incompatible brines. While much work has been performed to study the effec

rted along the streamlines defined by the velocity field. The efficiency of the solution method along the streamlines is very important for the mline method for two phase compressible multicomponent flows in hydrocarbon reservoirs. We prove that even with standard PVT procedur tatistical methods or numerical simulation. Both approaches have a significant drawback; the prior being quick however very often lacking i pers have discussed reservoir characterization applications of the EnKF which can easily and quickly be coupled with any reservoir simulat permanent down-hole gauges is a recent development. A robust procedure to effectively use the enormous amount of data recorded by the ation of this model in a full-field simulator. Flow in an open or partially obstructed annulus requires looped flowpaths to be modeled within th

nsate and volatile oil) at near-critical conditions. Multiple scenario production forecasts are required to prepare an optimal development pla believed to be mixed-wet or oil-wet to some degree with a non-uniform distribution of the wettability in the reservoir.ï¿½ Despite the importa

equation and whether the beta factor Î² for a proppant pack should be constant over the range of flow rates of practical interests. The proble e location of the free water levels. A theory applying capillary pressure scanning curves shows how changing water saturations and variatio ed by a relatively low-porosity over-pressured highly fractured and faulted carbonate. Production of the native retrograde gas condensate m wellbore pressure history and rock strength to the trajectory orientation. A stress direction map is generated for the GoS from observation he authors are neither representing the views of the SPE nor of the participantsâ€™ companies. We are delivering smarter fields in order economic climate of the late 1980-s and economic shocks during the period of well-known events in the country in 1990-s caused the rapid ssed almost simultaneously with both emerging as significant sources of oil and gas. Both provinces entered the 1960â€™s with no oil pro o subsequently design a sealant material that will not fail under the expected conditions. The predictive models are either analytical or finite-

a heterogeneous fluvio-marine channel deposit in the Western Desert Egypt. All the wells considered in this paper showed significant wate h flow contributions still remains an issue. Several SPE papers covering the issue have been published recently. This paper presents the en in Kuwait Sabriyah Field where there are two major producing formations: Mauddud Carbonate and Burgan Sandstone Formations. The we on logging data is difficult.ï¿½ Memory logging with conventional production logging tools via coiled tubing and a hydraulic tractor was em

sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the fl sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the fl well in a Saudi Aramco field. Permanent monitoring of pressure and temperature enables reservoir engineers to assess the performance o que for use with wireline formation-sampling tools uses pH-sensitive dyes that change color according to the pH of the formation water. To ent bottomhole gauges has been on a surveillance and diagnostic program for over 3 years. Pressure transient analysis of shut-ins give key s microseismic monitoring campaign was to determine the overall geometry of the hydraulically induced fractures in the Canyon sandstone e must be accounted for in the creation of fracture height width and length. In many cases excessive fracture height generation is at the e

bution is understood the distribution of steam injected either at the heel or toe of the steam injector can be adjusted to optimize the startup tervals may be located in the annulus between the casing and tubing strings above the end of the tubing.ï¿½ Of particular importance in thi pleted intervals may be located in the annulus between the casing and tubing strings above the end of the tubing. Of particular importance mbedded in a 1/8th inch slickline cable to calculate the inflow distribution of multi-zone gas wells with velocity strings. EnCanaâ€™s multi-z es positioning a number of different tracer materials each at specific locations along the length of lower completions prior to lowering down osis of production anomalies have been limited by sampling frequency and data quality. This paper presents field-test results of a new type

t and operational decisions may not permit the maximization of economic value and may undermine the accuracy of the reserves estimates ensitive to the wellbore inclination and the high water cut means a small proportion of the flowing liquid will be oil. At what point do these com red to very small initial gas caps in these areas. A peripheral water injection project is being considered to maintain the pressure above bub orizontal well. The field example comprises a horizontal well in the South China Sea that was completed as an openhole monobore oil prod . Moreover oil price increase promoted for technology improvement and set the unconventional techniques of the past to be conventional nd to understand the reservoir architecture. They are being used routinely in a wide range of applications spanning pressure and mobility p changes in individual layers after a well has been put on production without installing an intelligent completion or performing a multirate infl c events was recorded with signal characteristics that suggested deformation associated with thermal expansion of the wellbore in addition he different reservoir intervals limit conventional production logging possibilities so BP has chosen to install permanent fiber-optic distribute nal constraint is that sandface sensors must be deployed on a separate completion run. The objective of a recent engineering developmen ents showed evidence of thief zones in the Mauddud formation. Early water breakthrough has occurred in some wells. Previous studies ind

accurate understanding of production volumes the companyâ€™s field development and operational decisions may not support the maxim ts: 1) holdup or the cross-sectional area in the well occupied by the phase of interest and 2) velocity or the speed at which the available p

rvices suite provides the required answer by acquiring deep resistivity information through casing for subsequent formation evaluation. A tim since injection is done into formation water below oil water contact. Though the sea water front movement in the reservoir has been estima esistivity images and describe the methods employed for monitoring the fluid flow and show preliminary results of the modeling process. Thi eep efficiency identify bypassed pay and predict fluid-related issues such as water breakthrough by providing an image of the resistivity di roduction from CBM reservoirs. Wyomingâ€™s Powder River Basin (PRB) alone has 12 000 wells in production with an estimated 50 000 m thogonal and occur perpendicular or at very high angles to the bedding. The standard suites of logs such as density/neutron gamma ray a t. High fracture pressures in coal seams coal cleating and natural fractures can lead to shear slippage and inefficient non-planar fracturing the number of wells being drilled and completed has rapidly increased. With this change in development strategy operators and service co uring.ï¿½ There is growing evidence that initiating hydraulic fractures from horizontal wellbores is often difficult and requires abnormally hig well has an average of 20 pay zones that are stimulated individually. The coal cleats are fractured by pumping nitrogen at high rates throug s compared to vertical wells in the same reservoir due to the much larger hydraulic fracture surface area that is created. In order to achieve hale reservoirs. The borehole image interpretation drilling-induced fractures and conductive/healed fractures reveals stress regime orienta rough wells. Production of these reserves requires methods such as steam-assisted gravity drainage (SAGD) and cyclic steam simulation ( ed. Written by individuals recognized as experts in the area these articles provide key references to more definitive work and present speci initial hydraulic fracture stimulation treatment so that within 5 years an operator is normally faced with a well producing below its economi s to be reduced to allow wormholes to penetrate deep into the reservoir hence extending the effective wellbore drainage radius. The wormh o increase production rate from one of the offshore fields while optimizing offshore producing facilities. This offshore field has favourable co

lved as a result of extensive research and ground work. All the systems have proven their worth by increasing the productivity of the field by t into production. There emerged a necessity to develop the oil-water zones and marginal areas zones with poor reservoir properties and m ue vertical depth (TVD) of 1 400 m. The original development project for this field did not include sand control for the initially forecasted prod cementing operations. The sliding sleeve valves are opened one at a time to fracture layers independently without perforating. Completion ne with large dimensions and low layer inclinations. The main hydrocarbon accumulation is found in the Sarmatian formation (Base Cretaceo y important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required y important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required ble in this reservoir.ï¿½ Thus this reservoir must be exploited using horizontal wells in all areas.ï¿½ In areas where fractures may not be d

he well was drilled and completed as a proof of concept. It was completed as a trilateral and was equipped with a SC that encompasses sur controlling fluids/gels and selective perforations have been used to mitigate the disparities in water encroachment over the reservoir interva Saudia Arabia. A well was drilled and completed as a proof of concept. It was set up as a trilateral and was equipped with an SC that encom

e commonplace to improve the well productivity by providing maximum reservoir contact minimizing operating costs lowering the pressure his project was to develop and apply a new concept for well completion involving ESP systems tubing-conveyed perforating (TCP) drillstem e data and permits lifetime modeling with parameter combinations employing all available data. The analysis explicitly accounts for ESPs th ed and surfactant-based have been used in an attempt to achieve optimum fracture length and conductivity.ï¿½ Acids used for these treatm mpletions were considered the best completion option based on rock mechanics improved profile surveillance and cost. The original Alpine

ntana and the success there is now accelerating the transfer of technology to the North Dakota side of the Bakken trend and is attracting s ated near a water zone. These hydraulic fracturing difficulties created a niche for technologies that offer fracture-geometry control without sa ated by the reaction with the formation results in excessive fluid loss. Controlling fluid loss is one of the key objectives in acid fracturing trea us after initial campaign of four fracturing treatments. It demonstrated good proppant carrying capabilities and allowed decrease of polymer itives has grown. This value must be balanced with the cost of the additives which can be significant in slickwater fracturing treatments. Th is the dominant parameter controlling fracture height growth and that Youngâ€™s modulus contrast is less important. However a recent s sts per unit of gas produced. This in turn forced industry to focus on increasing efficiency by refining completion processes and field operati er to hydraulically fracture the well as well as complying with stricter governmental regulations. As produced water is recycled and used in fr nd stress state.ï¿½ The application and appropriate modification of basin best practices and the application of technology for reservoir chara zuela. This technique combines stimulation and sand production control in a single treatment by placing a short and wide fracture which by arious techniques to prevent the breakthrough of hydraulic fractures into the underlying water zone but so far without clear success. The p uction rates and better access to reserves. However most of these horizontal wells are completed openhole with little alternatives for stimul d treating fluids would enter preferentially into zones with high water saturations leaving oil zones untreated with a final result of increasing oping reserves under these conditions with conventional vertical wells is in most cases uneconomical. In this setting horizontal wells have c

y successful over the past few years as the majority of the horizontal gas producers have yielded excellent results with open-hole completio

igorous process of candidate selection fracture design and implementation of fit-for-purpose technologies. 10 candidate wells were select The solution for dimensionless productivity index of a finite-conductivity vertically fractured well in a closed rectangularly bounded reservoir

ccess of hydraulic fracturing in Western Siberia organically expanded to projects in Tymen-Pechora and Volga-Urals basin. Both basins are

h normal cementing operations. The sliding sleeves were opened one at a time to fracture layers independently without perforating. The va ng sleeves would then be opened one at a time to fracture layers independently without perforating. The possibility of high fracture initiation Difficulties emerge because hydraulic fracturing in soft rock involves development of a plastic zone near the fracture surface where rocks p ous resistance of the fluid flowing through the rock matrix primarily governs fluid loss.ï¿½This has historically limited the application to fract

Sand reservoirs located in Southeast New Mexico (SENM).ï¿½ The wells discussed in the paper were completed in various Morrow Sand in

hallenging due to presence of high pressure/high temperature and high asphaltene content in the crude oil which renders the situation even w discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited s a clearer picture of the fracture development.ï¿½ This information can be combined with other fracture diagnostic techniques and along w

e effects of the deviating borehole trajectory. For common HFM geometries a 2ï¿½ deviation uncertainty of the positions of monitoring or tre

s and little lasting conductivity will be created. Despite this critical role of differential etching in the creation of fracture conductivity little is k e the recovery factor of heterogeneous reservoir developed with water flood. Three main uncertainties exist: fracture height half-length and sting tracer technology has a number of safety and environmental issues that must be addressed when using this technology as part of a fra

propped fracturing stimulations for the gas and gas-condensate wells in the Western Siberian Arctic sector. The candidate selection proce nductivity cells. At the gas velocities normally encountered in hydraulic fracture proppant packs non-Darcy pressure drops dominate and he fracture and a lag zone develops due to fluid cavitation. Properly taking into account the controlling parameters of tip behavior has resul um fracture length and conductivity. Acids used for these treatments were based on 28 wt% HCl. A mixture of 15 wt% HCl and 9 wt% formic ns of a Stimulation Index (SD) and for evaluating the efficiency of wells with low conductivity hydraulically induced fractures. We utilize the d ation of the seismic waves and injection details. Stimulation below the fault indicated a near-horizontal fracture geometry. Above the fault a wback but the physics of the phenomenon has still to be understood to predict the amount of proppant flowback during the life of a well. In re. It is shown that the propagation pressure of the orthogonal fracture quickly increases to above the closure stress on the initial fracture du placing one lowers down the displacement quality leaving most of residual viscous fluid in porous matrix. The present paper provides the da y in propped fracture dimension is related to the distribution of stresses and elastic properties as well as fluid leak off. Those factors have s

ractures although successful often underperform: Frac and Pack completions exhibit positive skin values and traditional hydraulic fractur n order to maintain the oil production target for this field the water injection rate should double the target oil rate. To achieve this water mus ose of this work is to demonstrate the benefits of applying an integrated analysis for a hydraulic fracturing evaluation that is performed using ffsets have long been recognized as sites of restricted width in the fracture channel potentially leading both to significant pressure drops an o gas lift valve designed for gas operations. The value of auto gas lift is probably easier to demonstrate than for other types of intelligent we uire sand control and this has resulted in five sandface completion types (Open Hole Gravel Pack Cased Hole Frac Pack Cased Hole Grav tured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of tured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of ype of wells are: will it be necessary to cleanup the mud and filtercake from the openhole section before or while starting production? Will th lim intelligent completions technology has been successfully installed in Shaybah field operated by Saudi Aramco. Included in the descriptio permeability (K) variation and proximity of water traps). Furthermore conventional completions do not handle effectively heterogeneity or p ent completions are delivering better wells through improved efficiency productivity and hydrocarbon recovery with fewer wells both offshore ntelligent completions wells have been successfully installed in Abqaiq operated by Saudi Aramco. Included in the description are equipmen model-based and are effective only if the model can be used to predict future reservoir behavior with no uncertainty. Recently developed sch ss the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to act

rate reservoir characterization is the key to successful reservoir development. This is especially true in thinly laminated reservoirs which exh roduce the hydrocarbon. Sanding is detrimental to optimum field development and therefore information about the possible advent and ext ng deep and clean perforations may still not be enough to generate the desired productivity.ï¿½ Therefore the wells are often stimulated by maximum productivity this transition requires an optimal cleanup and the removal of the perforation damages. A new underbalanced orient and E-line have difficulties. This paper presents case history of coiled tubing perforating and zonal isolation evolution in infill well at Resak f aracterized by their high permeabilities (100 - 500 md) and low pressures (1200 - 2200 psi). The wells in Anaco District are normally perfora Sea. The HZ fields are stacked thin high-permeability sandstone reservoirs interlayered with low-permeability layers. The shallower layers maximum geological stress known as the preferred fracture plane (PFP) provides significant opportunities to improve the efficiency of the f oduction. Some wells inï¿½ADMA OPCO fields that are perforated using conventional perforating techniquesï¿½will not produce until stim nduces transient fluid flow that provides an opportunity for quantifying the formation parameters. However the skin factor can rarely be estim the accuracy of hydrostatic cushion before firing the guns. The conventional method of correlating the CT on depth involves two CT runs th erforating conditions of the perforator or perforator system is required if such damage and potential retrievability risks are to be avoided. In p

nto an outcrop carbonate rock called Indiana Limestone. Three of the tests involved shots into an outcrop sandstone rock called Berea San ellbore damaged zone. This connection through the damaged zone is usually achieved by perforating and the effectiveness of this connectio l productivity by maximizing oil production and minimizing water production. The paper will demonstrate the challenges and successes of re adients the low net-to-gross ratio the low bottomhole temperatures and the requirement for pressure maintenance. The development of the ells with 50â€“60ï¿½ maximum hole angles. The wells are completed using dry trees from the TLP and are produced primarily from massive h field (see Figure 1) discovered in the late 1980s is located 180 km south of Riyadh the capital of Saudi Arabia (figure 1). Hawtah is one o eservoirs. Because of the long lengths of the producing reservoirs and large variations in sand-grain sizes/permeabilities premium screens w s one of the completed intervals on the S7000E horizon. Production from this interval began in April 1997 and oil recovery averaged 2000 S

olling sand and maximizing productivity it entraps the filtercake formed by the reservoir drilling fluid.ï¿½ This results in low production rate at are significantly greater than expected. The success of the Greater Plutonio OHGP completions has been attributed primarily to the rigoro

during the production and the injection cycles. This challenge has a significant effect in selection of the completion technique in these wells one utilizing low-viscosity carrier fluids and low gravel concentration. In this technique the gravel is placed in two waves commonly called Alp become more common. Executing these open-hole gravel-pack jobs (alpha-beta packs) has been a challenge. Although scattered attempts considered one of the proven methods of sand control from both reliability and productivity standpoints and allows access to larger reserve conduits between the reservoir and the wellbore for hydrocarbon production. This project presents a system approach for removal of perfo conduits between the reservoir and the wellbore for hydrocarbon production. This project presents a system approach for removal of perfor rs are planned and all will require some form of sand prevention. Extensive rock mechanical work using Statoilâ€™s finite element modelin ection well and served as a demonstration of its potential benefits in the development of Stag oilfield. Located offshore in the North-West s or a major operator in the Gulf of Mexico. Each of the six treatments provided significant cost savings as well as excellent return on investm

significant economic loss. AGOCO recognized that it was facing a major challenge in terms of understanding potential sanding risk for Sa rs. It can impact production cause erosion in downhole and surface facilities require additional separation and disposal and lead to signifi production indicating possible sanding issues for this field. To investigate this problem relevant data from different sources and different d ry perforation-collapse tests aimed at demonstrating and quantifying the water-cut effect on perforation failure and sand production. The lab

the rock surrounding the perforations and the borehole. Sand production in weakly consolidated formations is generally assumed to be a ategies to maintain mechanical and time-dependent stabilities of extended reach wells and 2) to assess sand production risk in the develo last 4 years the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants ha reatment. We conducted a series of acid fracture conductivity tests using a protocol that mimics the fluxes in a hydraulic fracture both in th n acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate leakoff and stimulation rate. Acid reaction rate is a fu eally suited for acid fracturing. During acid fracturing the wormholes created by the reaction results in excessive fluid loss. Controlling fluid deally suited for acid fracturing. During acid fracturing the wormholes created by the reaction results in excessive fluid loss. Controlling fluid onal coverage in large limestone reservoirs. The viscoelastic diverting acid system was pumped through coiled tubing in three of these wel ation permeability often exceeds one darcy. The mineralogy is composed of calcite (98 to 99%) with about 1% halite and < 1% quartz; ther -cut (WC) wells in which water has broken through as a result of high-permeability streaks or natural fractures. Furthermore acid penetratio al production gain with relatively low level of investment. In the recent acidizing campaign in Brunei a particular challenge was the flowback

y damage to each zone matrix mineralogical composition and pressure regimes of each zone need to be taken into consideration. The pr wells. The first is its high reaction rate with carbonate rocks which limits acid penetration in the formation. The second is its corrosivity to w

cated at a depth of 6100 to 7500 ft that has produced (30 to 45 ï¿½API crude) for over 35 years with production peaking at 66 000 BOPD. eating fluid over the entire interval. When fluids are pumped into a well they naturally tend to flow into the zone with the highest permeability In the mainly brown fields tertiary recovery methods such as water-flooding are implemented to maintain financial viability of the well stock. ï¿½ However most previous studies reported in the literature have focused on investigating the effects of injection rate temperature and fl ssure than the previous fracture. Refracturing requirements are different in highly permeable formations (high fracture conductivity) as com the Frontier Formation located in Bighorn Basin Wyoming has seen a variety of stimulation fluids used over the past years with varying d but still not perfect. Limitations on the amount of proppant placed near water zones and formation damage from polymer residuals were the process that integrates petrophysical and reservoir characterization expertise with production and completion knowledge by developing a

ed with limited surface water handling facilities increased the importance of stimulating this type of challenging wells due to the drastic perm d are not regarded as a replacement for reservoir inter-zonal communication tests performed between producing reservoirs on every well. C eservoir pressure permeability and skin. There are two aspects of the proposed approach - straight-line analysis and modeling. A novel app this reservoir.ï¿½ Thus this reservoir must be exploited using horizontal wells.ï¿½ Recently a 2 270 ft long horizontal well has been drilled sient analyses and uses historical production data (rates and cumulative) and the results from production logs to; 1) determine the flow rate d as a multi-layer commingled producer then this conventional approach makes it difficult to measure the permeability and skin of individua tured formations are to prevent or delay the intrusion of unwanted fluids into the wellbore i.e. water coning.ï¿½ A similar early-time pressur neous propagation of the pressure signal in the entire spatial domain when a flow rate or pressure pulse is applied to the sandface (beginni e dynamic behavior of the reservoir.ï¿½ Loss of production and cost of acquiring data versus the benefits has always been a classical mana n methods to the long-standing deconvolution problem and make deconvolution a viable tool for well-test and production-data analysis. How

ze these systems based on formation properties and fluid flow behaviour such as logging and testing. Pressure-transient testing has long be expensive development plans can be put in place. New technology real time monitoring and integrated reservoir data are essential to under rvoirs are vertically heterogeneous with high permeability. MiniDSTâ€™s are conducted using the inflatable straddle packer system of wire paration and existing instrumentation is often doubtful leading to an under-estimate of liquid rates. An aggravating factor is that such wells ar he operation and the roughness of winter weather conditions combined with the complexity of the fluid compositions create unique challenge

ontrolled flow loops using idealized fluids in steady state conditions. However for high water-cut high gas-volume-fraction and low pressure oir and production management. However it can be difficult to compare data sets obtained with different measurement devices. Multiphase pretation models of traditional multiphase flowmeters emphasize the liquid rate measurements and have been used to well test and meter m for procurement actions evaluate the production test data measured by the conventional test separators and improve the testing duration a

e of device especially in the High (92-96%) or Very High GVF (96-98%) ranges. Most of the purchasers put a cut off in the GVF range of 85 dels could be used in well test interpretation. The need to effectively use information available from well test analysis in full-field simulation sure transient data [Hosseinpour-Zonoozi et al (2006)] and we demonstrate that the Î²-integral derivative and its auxiliary functions can be terpreted because of various artifacts collectively termed noise. While various noise-smoothing techniques have been used there are valid e streaming potentials generated by these transients were measured by arrays of permanent electrodes placed in the boreholes.ï¿½The ele

recognized as a weak spot in CO2 storage where containment can break down. This is because cement steel and elastomers can be cor grity. One principal stress is assumed vertical and of magnitude equal to the weight of the rock above calculated from the density log data. radation and casing corrosion in injection production or abandoned wells can create preferential channels over time allowing migration of C ty of oil and gas reservoirs. Optimization techniques have been applied independently to the reservoir and surface models leading to nonparse. The special behaviour of CO2-water/brine systems (mutual solubility and chemical reactivity) adds complex processes such as dry-o Federal Ministry of Education and Research and the German Federal Ministry of Economics and Technology targeted at developing an in oring them in subsurface reservoirs is thought by many scientists to be a reliable solution until emission-free energy sources are developed servoir and in its surroundings. Besides the mechanical properties of the rocks exposed to CO2 may be altered. The impact of the resulting

Reach Drilling (ERD) from a floating installation.ï¿½ The 34/8-A-6 AHT2 is also the longest Down hole Instrumentation and Control System rvoirs which are poorly imaged on seismic. Reservoir overburden is fast drilling formations with hard stringers. The field pore-pressure grad

300 reefs have been located in the southern portion of the basin many of which have produced more than 5 MM bbls of oil. The EOR pote ome to be an excellent opportunity because of its low cost. Since 60 years ago 2500 km2 of carbonate formations containing CO2 were dis aminated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disburs nd consequently the well productivity.ï¿½Also when reservoir pressure drops below the dew point a big portion of condensate liquid will r involved in the process SAGD presents multiple challenges from the design and analysis phases to its final implementation. The objective omplex geology and reservoir mechanism was negatively affected by gas breakthroughs in several wells. The constraints on gas handling ca

the feasibility of performing water shutoff treatments in the open-hole completion oil wells. The study involved evaluation of a high tempera specially in case of multiple zones interval simultaneously producing and where completion of the wells restricts considerably the convoyed g out a successful intervention when water break through occurs. Water breakthrough and high basic sediments and water (BS&W) are pr nd capping it with cement and gel using coiled tubing (CT). Historically it has been difficult if not possible to perform mechanical water sh est Venezuela. Gravel-packed slotted liners and standalone premium screens are common completion methods in this field. Dual injection al reasons. It requires increased capacity of water separation and handling facilities decreases hydrocarbon production and results in large date selection and finishing with post-treatment well performance analysis. This kind of operation becomes more challenging for horizontal w cant challenges.ï¿½ Of particular concern are the effects of produced fluid hydrocarbon solids (i.e. asphaltene wax and hydrates) precipita est section using tap water and mineral oil (density=0.85 g/cm3 and viscosity=15 cp) with superficial velocities ranging from 0.025 to 1.75 m pe flow was experimentally investigated for different inclination angles (0ï¿½ ï¿½1ï¿½ ï¿½2ï¿½ and â€“5ï¿½). A total of 324 tests were co roduction from the commingled reservoirs and optimize the recovery. Traditional methods for production optimization and back-allocation o s of the overall production system outside of their specific domain. For example a common practice in the oil industry is to generate a prod phaltene wax and hydrates anywhere in the production system. These are flow assurance key risk factors that create significant impact on urate and representative fluid characterization and resulting flow assurance data on optimum facility and production method design for deve denotes an issue for health safety and the environment (HSE) and is readily absorbed by elastomer seals weakening the resistance of tho es are being deployed to determine reservoir connectivity based on the compositional differences in the reservoir fluid. In a number of reser

been developed that are based solely on commonly available field data. These properties are the dewpoint pressure of the reservoir fluid c functions (oil-gas ratio Rv solution gas-oil ratio Rs oil formation volume factor Bo and gas formation volume factor Bg) were investigate not been well characterized in the laboratory until recently. In this paper we review a gravitational gradient of asphaltenes in a reservoir and oduction zones and optimize perforation zone selection. Relying only on open hole log data and performing correlations among nearby well or subsequent economic analysis. Compartmentalization and spatial variations of fluid composition are two primary factors that cause majo suring the pressure/volume/temperature (PVT) properties in a laboratory. More recently downhole fluid analysis (DFA) during formation tes of new generation WFT probes that can operate in OBM filtrate environments with enhanced efficiency. Analytical as well as numerical mo and new fluid identification sensors which allow real time monitoring of a wide range of parameters as GOR fluorescence apparent densit

ilizing a focused sampling probe in wells drilled with Oil Base Muds (OBM) in mature fields. Due to OBM and low mobility sections a new fo ade. Detecting the presence of H2S early in the life of a discovery can help to accurately assess the feasibility of a project and determining

wnhole separation. Given this reality the pressure/volume/temperature (PVT) analysis of any fluid sample with an equation-of-state (EOS) m eceived little attention until the 1980â€™s when sufficiently advanced analytical methods became available to assess the phenomenon. Ind efore small changes in reservoir condition will result in a change of fluid properties considerably. As a result there exists a broad spectrum o sing the spatial variation of fluid properties is as vital as assessing the spatial variation of formation properties. Conventional wireline triplectivity permeability and fluid properties. Such complexity and reservoir heterogeneity means conventional pressure-depth plot and pressure s a complex process that requires a greater number of data points fluid samples and associated laboratory analysis. Pressure gradients w m facilities. When a formation fluid sample is taken from a well drilled with oil-based mud (OBM) sample contamination by the OBM filtrate

lex fluid columns showing compositional gradients for columns in thermodynamic equilibrium or under steady state conditions. Montel et al. upt changes in these fluid properties with depth may be markers for reservoir compartmentalization. However hydrocarbon differences can ring the pressure/volume/temperature (PVT) properties in a laboratory. More recently downhole fluid analysis (DFA) during formation testin

numerical simulators.ï¿½ The methods are based on a fluid characterized by pressure and temperature dependent K-values.ï¿½ Although es in which submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy-oil production systems

son to conventional sampling methods. Formation-fluid sampling has always been adversely affected by mud-filtrate contamination which out of the formation into the wellbore until real-time downhole monitoring of the fluid in the tool flowline ensures it is clean. The reservoir flu ster DST and multiphase sampling and fluid characterization environments with the most challenging area in recent years arguably being th ses of condensate and heavy oil environment where traditional means of measurements are impaired by the difficulty to separate the phas precipitate at certain conditions. The precipitant may form on the rock surface and act as a barrier and ultimately stop the reaction of the ac dstone reservoir with a low permeability of approximately 15 mD containing saturated oil. The 122ï¿½C temperature complex mineralogy lls). This study proposes novel applications of straightforward chemistry to synthesize calcium carbonate particles that damage the porosity nd compared with commercially available inhibitors. Salt deposition in high salinity brines can cause blockages to production and process s

ucted to determine the precipitation rate for various pH and temperature conditions. Microscopy investigations were carried out to verify the n the vicinity of the perforation tunnel resulting in a zone of reduced permeability called the crushed zone. Additionally the impact stresses material surrounding the perforation tunnel and created by the impact of the shaped charge jet on the rock fabric. Perforating underbala urface equipment. Local industry offers a number of inhibitors to prevent scale deposition. Although regular and planned injection of inhibito asin using borate crosslinked fracturing treatments (with scale inhibitor concentrations as low as 5 gal/mgal). However these design criteria sensors and control valves at the reservoir face engineers can monitor reservoir and well performance in real time analyse data make de ower part of the production string are the common type of scales encountered in Upper ZAKUM producing wells. Injection seawater (rich in severe barite scaling tendency will require inhibitor concentrations in the range of 10-50 ppm to control scale but in practice concentrations ndent in terms of their effect on the objective function. Otherwise perturbing one variable to improve the match in a particular region may adv rs. Such capability has made streamline based history matching very attractive and more reliable in expediting history matching of simulatio ate added value due to its ability to handle high-resolution full three-dimensional models with hundreds of thousands to millions of cells inc s is to monitor the advancing fluid levels at wells and control the unexpected fluid breakthroughs. Hence the design and intelligent well man st decline of the gas wells during their first year of production drove a change from reactive into proactive management tactic to monitor the water saturation between wells to properly manage the sweep and recovery. In 2007 ADCO initiated water injection (WI) and WAG pilots to ltifaceted approach of balancing voidage with injection conducting extensive surveillance/analysis within the reservoir to assess the efficac ravity and viscosities of 2 000 cp at a reservoir temperature of 133ï¿½F). After 1995 with the implementation of horizontal drilling technolog ery processes are more efficient in low pressure reservoirs; however due to their depth the initial pressures of the reservoirs in the Faja are ility of this method was investigated.ï¿½ Heavy oil samples from conceptual reservoirs (Bati Raman (9.5 API) Garzan (12 API) and Camurlu thicknesses and heterogeneities found the implementation of different thermal recovery methods is necessary. This project covers a feasi build rates. Unconsolidated sandstones and interbedded shaleâ€™s are sensitive to mud weight and are prone to lost circulation. First few dual porosity system and the presence of fractures at varying scales. This case study of the 1st Eocene reservoir characterization in the ste aracterizing of permeability anisotropy and in-situ minimum horizontal stress estimations. Pressure and fluid samples are obtained by settin

e of vertical wells indicates that the reservoirs are facing problems of low productivity bottom water conning and sand production. In his circ

eservoirs with high-permeability contrasts. Conventional acidizing results in the stimulation of water zones and misses targeted oil zones. Th

ing classical separator. Heavy and Extra-Heavy Oil represents more than 50% of the worldwide oil reserves and large efforts have been sp

s usually pumped in multiple stages of pre-flush main fluid and over flush. The drawback of conventional sandstone acidizing treatments is ate fields. The main objectives of the pilot phase of the exploration projects in the Achimovskaya formation are reducing reservoir and fluid u

erties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper we have studied the effects of gr

oals.ï¿½ With titanium (Ti) or zirconium (Zr) crosslinked gels which are known to be prone to irreversible shear degradation early crosslink nded with the difficulty of providing adequate corrosion control. In addition the health safety and environmental implications of acid handlin

res and temperatures during the producing life of the well both in flowing and shut in conditions which allows to optimize production and flow nts operationally difficult and challenging. More than 60 treatments have been performed in over 40 wells placing over 3 million lbm of prop acids and solvents are used to treat these wells with mixed results. A novel chemical system has been developed for the stimulation of h 149ï¿½C) sandstone reservoirs in a West African formation bear carbonate concentrations ranging from 2% to 37% (w/w). The effects of m uid had being used with acceptable results for proppant transport and fracture placement; however these fluids are known to generate unde ifferent chemicals (A1-A5) are evaluated in this study for their ability to prevent water block formation at high temperature. Adsorption/deso atory at reservoir conditions. Water chemistry and pH are important inputs for scale and corrosion modeling. Due to the lack of standard lab

drilled extensively in this low permeability gas reservoir to enhance productivity.(5) While the increased contact area offers a potential for e

optimization and field geocellular and simulation modeling. Through this process various development scenarios for completions and drillin wells in the Rocky Mountain region were mapped in real time with a 3-D stimulation viewer software package. One well employed techniqu hat will lead to desired line drive mechanism optimized reservoir drainage and maximized recovery factor. That information is not less critic Modern well log evaluation techniques and completion methods are required to yield economic wells. In some cases microseismic monitori the productive sands are associated with nearby water sands that are often intersected by the hydraulic fractures as their heights grow whic

effectiveness of hydraulic fracturing as a production enhancement technique and the relatively low cost of pumping services in onshore area ion. The lithology of the Xu-6 formation which is the main reservoir section where the lithology mainly consists of fine-medium feldspar-qua ervals is diminished by increasing water cut. Considerable by-passed oil remains in the tighter and lower quality intervals. These oil reserves g. Single sand body pay zones would not be commercially attractive. Rigorous reservoir modeling and simulation workflows were employed ophysical and a mechanical stress model calibrated from offset nearby wells to match well production and fracturing treatments response.ï¿ ckness of 4 000 ft in a fluvial depositional environment. Reservoir rock permeabilities are in the microdarcy range. The overpressured reserv e and useable petrophysical model for an accurate productivity indication of the target interval. The pressure to avoid non-economical comp

smic faults in the oil based mud borehole environment. This paper summarizes part of the experience learned from the use of an optimal da on objectives. Thus the complexity of the wireline formation testing (WFT) has dramatically risen and continues to rise. It requires an effectiv idely used to improve the economic viability of wells and fields to that matter the presence of natural fractures plays the same role in impro s due to the nature of the rock and the granularity of the data necessary. This case study summarizes results for a wireline pressure data co

ging. There is no stable flowing pressure during the pretest build-up times can be long and the confidence level of the final pressure is often aused a 20-year gap between discovery and development. The initial pilot development was halted after poor drilling success thus the ope success is the Cleveland Sand of north Texas and the Oklahoma Panhandle. Very recently some success with horizontals has been obse terogeneity of this formation. Prospective wells drilled to this formation tests results vary from 0 to more than 600 m3 oil per day. The article

ed significantly by complex rock heterogeneity can only be accomplished by selective flow measurements. To use openhole sampling tools

s and economics of the project. This is further complicated in tight viscous and sand incursion prone formations. This paper discusses abo

ublic response to a proposed project. However this approach has many limitations related to recognizing the companyâ€™s true financial p oleum company. By improving judgment elicitation process particularly in the case of multi-criteria decision-making it is possible to improve desired structure.ï¿½ During the course of drilling an 8 well Horizontal drilling program for the Kuwait Oil Company (K.O.C.) in the Burgan F st. Rock typing is often used to help map the available capillary pressure data to the reservoir layers. Borehole nuclear magnetic resonanc esolutions but very small lateral radii of investigation and the pressure transient tests have a large lateral radius of investigation but very p uish 2 rock types having the same range of porosity but different porosity-permeability relation. The dual porosity system is illustrated by stro ast coast of India. The present study aims at reconstructing sedimentary depositional environment with the help of image logs and cores an he reservoir heterogeneities. A realistic identification of the depositional environment is critical to the delineation and prediction of the best q ion cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy which can prov oduction zones and optimize perforation zone selection. Relying only on open hole log data and performing correlations among nearby wel ial in the presence of extensive diagenesis process affecting the original depositional texture. The conventional triple combo logs gives an a mplexities associated with its evaluation. The complexities in general relate to a heterogeneous reservoir with complex mineralogy varying w rmation evaluation on LWD. The compact design of the new-generation LWD tool greatly increases the likelihood that measurements will b e of such sources have always been known more awareness in the industry has led to increased efforts towards the reduction or even elim

ainty in reservoir areal extent net reservoir thickness porosity and hydrocarbon saturation. In this work a methodology is presented to ass ncertainty in reservoir areal extent net reservoir thickness porosity and hydrocarbon saturation. In this work a methodology is presented to carbonates. The authors have earlier described an approach to estimating permeability in carbonates from borehole NMR logs and electric d carbonate cements are present within the sandstone with the anhydrite dominating in the uppermost units. The basal sand syones are oft a wide variety of textures.ï¿½ In some intervals the depositional textures are preserved in others they are highly altered by diagenesis.ï¿½ meability in each layer resulting in changes in the well productivity and sweep properties. We illustrate the applications of NMR borehole im

of the anisotropic shale point. The same shale point should be used in the determination of sand porosity. Difficulties will arise when anisotro D) apparent resistivity measurements (attenuation and phase shift) could be significant. These effects need to be considered in resistivity log vial deposits. Fracture corridors and permeable fault zones also represent a major risk of water breakthrough from the underlying aquifer in ssment of fluid complexity compositional grading and acquisition of samples for input to PVT studies. Many deepwater reservoirs compris s and faults seen on electrical image logs cannot always be discerned as to whether they are of natural or drilling-induced origin. Cross-ref 0 sq. km. of 3D seismic data of Al-Khafji oil field shows number of sinuous (channel-like) events in the north and north-east of the main Khaf

racterize the reservoir connectivity and sweep efficiency. However geostatistical modeling methods do not always make an accurate infere to characterize such reservoirs. The formation evaluation of thinly bedded reservoirs has several objectives: identify the layers that may c osed to that of the sand-shale system). Formation evaluation in thin sand-shale laminations starts with their detection. NMR vertical resolut

ions with data acquired with wireline measurements and formation layer thickness determinations. The reasons for these inaccuracies gene

erns of horizontal injection and production wells. Horizontal wells are increasingly being used for production and waterflooding. Long-term in voir compaction and surface subsidence.ï¿½ The mechanical parameters can be divided into three main groups viz. elastic parameters s y warning of impending drilling problems that may be mitigated by appropriate drilling fluid design and drilling practices. We have developed providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective ial to identify areas of high fracture density. It has been observed that fractures associated with certain faults have facilitated the flow in the In this paper we developed a workflow of integrating formation micro imager Stoneley waves and petrophysical analysis for better fracture me zones. The reservoir properties of the matrix are generally negligible and the production potential of wells is mostly associated with natur understanding of the fracture networks and their relationship with major and sub-seismic faults in this field is now critical to optimize infill dri us vugs in some zones. The reservoir properties of the matrix are generally negligible and the production potential of wells is mostly associa

Monitoring (FMM) setup and experiment is to provide in-situ measurements required to determine multiphase flow properties such as relat c. Overlooking the variation in fluid properties that can and do exist in what appears to be a homogeneous reservoir on a typical log analysi he relatively tight gas sands are drilled with significant overbalance due to a mix of depleted and virgin zone layers using oil based mud sys

own when the rock does not have paramagnetic elements the porosity measured with the NMR is not affected by the minerals within the m y and nuclear logs are used to infer basic fluid types caliper log is used to verify that the borehole is suitable for sampling and NMR logs ar en clay-bound capillary-bound and free water. In addition to these reservoir characterization problems we observe effects caused by the dr measurements of transverse relaxation (T2) polarization (T1) and diffusion (D). But compromises are inevitable for any given NMR techniq o more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent adv mpts to optimize previous results using an integrated petrophysical characterization workflow. The geological complexity of the Estancia Ch f logging horizontal wells especially in multiphase flow. A new logging tool has been specifically designed to better characterize fluid flow in

to the formation. It also facilitates the possibility for reservoir characterization during drilling. The purpose of this paper is to present (1) how 300 ft with an average Net of 170ft in the upper layers. An average porosity value will be around 15% and permeability ranges between 0.00

Downhole fluid analysis along with complementary techniques including geochemical mud-gas and pressure analyses provide valuable ins n large reservoir sand bodies. This procedure was applied in the Deepwater Tahiti field in the Gulf of Mexico uncovering a large concentratio work providing a basis for the analysis of reservoirs that exhibit Darcy and non-Darcy flow respectively. An extension of the conventional nitoring techniques can identify inconsistencies leading to possible adjustments in recovery strategies and eventual improvements in ultima servoirs owing to their thin beds high shale content and variable formation water resistivity. Missing gas-bearing formations translates into

meable shales between producing sands complicates fracturing design and field development to maximize recovery. Permeability and perm . Therefore any calculation of initial pressure and permeability must take into account the supercharging effect. We present an algorithm th e options developed by reservoir production drilling and facilities engineering and ranked by economics. The process specifically involved f s to marginal fields where uncertainties such as geology (static information) and reservoir drive mechanism (dynamic information) may impa d for candidate screening completion selection and ESP system design of the first such conversion on the Bokor Field offshore East Mala equate to high cost and low productivity making mature fields unattractive when competing for resources with other options in a companyâ€ for appropriate production optimization for the field.ï¿½ The Bokor field is located 45 km off the coast of Sarawak East Malaysia. The rese ns to Saudi Aramcoâ€™s effort is proactive geo-steering using Directional and Deep Resistivity technology to maximize the net sand delive njector across Permian eolian sandstone reservoirs with high degree of structural and reservoir uncertainty. The integrated reservoir manag are now 52 permanently installed compressors. The candidates were selected by testing the wells in the low-pressure area and additional kflow encompasses planning from concept selection to preparation of well proposals during the implementation work. Scalable to any given and/or different production techniques.ï¿½ Substantial increases in producing gas-oil ratios and water production can occur over the lifetime with the goal of maximizing the well oil production avoiding cross-flow minimizing operational risks and well interventions(coil-tubing operat e of reservoir simulators surface-network simulators process-modeling simulators and economics packages.ï¿½ï¿½ï¿½ We present a co actors including inflow performance tubing and surface hydraulics.ï¿½ Additionally careful consideration must be given to operating constra onal environment with an anticlinal structure terminated at the crest with a growth fault. The history match confirmed that A6.0 reservoir unl more challenging to achieve additional reserves. This paper outlines an integrated approach for achieving these opportunities reducing the

ults and control the actual production performance. A discusson of the theory of the IAM as well as the steps to set up a SRM and IAM are e a good representation of future field wide behavior. In this paper a fictional case study of a reservoir that has been producing for some 12 s of the overall production system outside of their specific domain. For example a common practice in the oil industry is to generate a prod yor belt.ï¿½ For example field development planning studies for ten reservoirs some with history of more than 20 years have been genera ult of high water cuts. Additionally there are no more slots available in the existing platforms for infill drilling. Typical completions include sa

to make up for production decline in Khafji Field and to sustain the field target rate and defer large investments associated with exploration eservoir modeling significant recoverable oil was identified in shaly sandstone reservoirs and attic structural locations of clean sandstone re s shown are based on a one-year application of a systematic approach to field optimization. This process is the dynamic integration of histo wer Vicksburg sands has been a great challenge to all operators in the region not only because of the high drilling and completion cost but rice within a specified time window regardless of the prevailing price and availability. This paper presents a mathematically consistent fram

entiator for optimizing well placement in a number of deep water horizontal wells. The new directional measurement is highly sensitive to re inholes not only had to cut as much of the good reservoir sand as possible but as the Brenda field depends on water drive as its main prod dup plateau and decline.ï¿½This results from successive drilling and commissioning of wells at a prescribed frequency (e.g. quarterly) un hod for comparing a set of assumed reservoir parameters especially the presence of a connected aquifer and its size with a set of simula and requires only a minimum of data which makes it in most cases more suitable than other methods. The approach provides a filtering c odels have been widely used to plan new wells trajectories. However the dynamic behavior of the reservoirs was widely ignored. These effe o determine optimal well locations using a gradient-based optimization method. Our approach is based on the concept of surrounding the w il ratio. SAGD optimization work includes simulation results and real-time data monitoring. Existing analytical models1 2are mainly dedicate n using any continuous function to describe the production rate of a point source. Successive integration of the point source solution can b analytic solutions together and solving for the flux field at the layer interfaces. The time evolution of these flux fields is governed by a Volter ng it computationally expensive for field applications with large number of parameters; second the sensitivity coefficients that define the rel step used in the forward model. Third it is computationally expensive as it requires solving the Adjoint system of equations backward in tim

ose to the observed response. This implies that the optimization problem can be prohibitively large and inefficient. In order to circumvent thi

ntly using parallel processing. The simulator solves component material balance energy balance and mass equilibrium equations for comp ot previously been used in commercial simulators due to its complexity and inefficiencies in both memory and speed. Here we describe an e oir also contains a large gas cap that provides the dominant energy for reservoir recovery. The reservoir is composed of interbedded shallo

s with limited platform capacities. Commonly a horizontal well trajectory undergoes undulations that may result in special wellbore flow dyna

ng reservoir remaining reserves and/or remaining productive life. The effective use of the forecast techniques: Empirical Fetkovich Locke hanical and hydraulic damage to the matrix near the fracture face. A previously published fast-and-robust single-well model was applied to s strong stress dependency in permeability hydraulic and mechanical damage caused by the fracturing process and inertial non-Darcy flow ability contrasts. Reliable evaluations of stimulation performance are required for field development planning. As such pressure transients a problem of tremendous computational resources used to simulate realistic hydraulic fracture details for better and more reliable production o ht growth could be hindered or stopped by interfacial slip when a vertical hydraulic fracture propagates in such formations. An interfacial sl cal modeling.ï¿½ Conventionally analytical methods and software are used to forecast post-fracture production rates to evaluate the prof developed in the form of apparent dimensionless fracture conductivity as a function of the true dimensionless conductivity and the inertia re chnique integrates production performance data production logs and prior information to arrive at the most probable description of the res ensionless productivity index of vertically fractured wells in closed rectangularly bounded reservoirs during boundary-dominated flow have b uts. The length of the perforated interval has therefore been reduced to the acceptable minimum. Although operational problems have been rence numerical method for solving a system of coupled differential equations: 1D equations of power law fluid flow along the fracture trajec Several methods have been proposed in the literature to overcome this problem. On the basis of our study we can conclude that ANNs tha

nd shale leads to the difficulty in detecting a single gas-water contact in the field. Second the vertical heterogeneity leads to the use of fine D linear in the wellbore and 1D radial in the reservoir. A numerical algorithm for reservoir temperature calculation is proposed and an analyt This is made worse by reservoir heterogeneity. The commonly used concepts of productivity index (PI) and injectivity index (II) are not partic water influx or combinations of these. Fourteen material balance models were built and the results analyzed. This study shows that proper in oach to properly quantify and account for the impact of reservoir pressure and PVT data uncertainty on material balance calculations under ry often when the development history counts more than 20 years some well data for instance formation pressures become unavailable. n are used to perform initialization in a 2D cross section. We use both homogeneous and layered media without and with anisotropy in our c nificantly as an alternative to the more traditional uncertainty analysis. Whilst there are papers describing experimental design workflows an

rom local numerical flow experiments (transmissibility upscaling) for each cell face. Monotonicity of the solution matrix is discussed and a ve e saturation distribution in porous matrix blocks was demonstrated. Dual porosity/permeability models are obviously unable to reproduce sp ual porosity reservoir simulators since triple porosity system â€œisolated vugs are not part of the formulation. The simulation of oil producti stribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However the challenge lies in estim

wever these simulations have been limited to two-phase incompressible systems. Commercial application of streamline methods to fractur ach point of a reservoir are considered to be those of two interpenetrating continua the matrix and the fractures one. It is also assumed that actures explicitly as volumetric objects pose a particular challenge to standard simulation technology with regard to accuracy and computatio

ML) method gives a biased characterization of the uncertainty. A major objective of this paper is to show that this is incorrect. With a correct

s been performed to study the effect of thermodynamic changes such as pressure decrease or temperature increase on scale precipitation

streamlines is very important for the overall efficiency of the method. In this work the acceleration of the saturation transport using adaptive at even with standard PVT procedures performed at each time step at each spatial point streamline technology maintain its better scaling a g quick however very often lacking in accuracy the latter being very accurate however usually very complex in setup and computation. The e coupled with any reservoir simulator. Neither adjoint code nor specific knowledge of simulator numerics is required for implementation of t mous amount of data recorded by theses monitoring systems has been proposed and tested on a synthetic case. Geostatistical simulation ed flowpaths to be modeled within the well. We describe the extension to the formulation of the well model together with considerations to en

prepare an optimal development plan for the complex. Current compartmentalization understanding based on geological and engineering da he reservoir.ï¿½ Despite the importance of this parameter there is currently no proven quantitative logging technique that can provide a con

ates of practical interests. The problem was highlighted in a recent discussion by Batenburg and Milton-Tayler1 and the reply by Barree and nging water saturations and variations in levels of mixed wettability systematically control the differences in the pressures of the invading m e native retrograde gas condensate occurs primarily from three major formations: Shuaiba Kharaib and Lekhwair in the Thamama limestone nerated for the GoS from observations of borehole breakout detected in multi-arm-caliper logs and other log data base viz. electrical Image are delivering smarter fields in order to add value to our business â€“ there are many facets to this value beyond reservoir well process an e country in 1990-s caused the rapidly decline of the number of new EOR projects. EOR technologies started to develop in direction of swee ntered the 1960â€™s with no oil production but by the end of the 20th century the provinces combined had delivered almost 50 billion ba models are either analytical or finite-element models. The analytical models can only be applied to relatively simple situations that require a

n this paper showed significant water production. To identify the main water-producing zones and the bypassed oil all the wells were logged recently. This paper presents the engineered solution for a TAML level 5 dual-lateral horizontal well that was drilled and completed in the O gan Sandstone Formations. The wells were completed with dual production strings due to distinct fluid and reservoir properties in these form bing and a hydraulic tractor was employed.ï¿½ However due to the wear experienced by the coil high cost and poor data quality at low flo

esponse is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result. The Pinda forma esponse is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result. The Pinda forma gineers to assess the performance of the reservoir in areas such as flood front movement and pressure support maintenance. In this well a to the pH of the formation water. To make a real-time pH measurement the dye is injected into the formation fluid being pumped through th ansient analysis of shut-ins give key performance indicators (KPIs) such as permeability-height (kh) skin (s) and current average reservoir fractures in the Canyon sandstone formation. Information and results initially derived from the microseismic interpretation were used to pro racture height generation is at the expense of fracture width and length creation. As a result in fracture treatments where excessive height

n be adjusted to optimize the startup and early operation of the SAGD pair. Total E&P Canada permanently installed optical fiber along thei g.ï¿½ Of particular importance in this work is the capability of determining the formation inflow profile in the well in cases where the well outf he tubing. Of particular importance in this work is the capability of determining the formation inflow profile in the well in cases where the we locity strings. EnCanaâ€™s multi-zone gas wells in the Deep Basin of Western Canada are often completed with production tubing landed completions prior to lowering downhole. The tracers are selected to be soluble in either crude oil or water. Upon well start up oil samples sents field-test results of a new type of downhole multiphase flowmeter which confirm the value of permanent downhole metering. The met

accuracy of the reserves estimates. Present digital oilfield technology gives the production engineers all the data needed to monitor proce will be oil. At what point do these compounding affects limit the ability of current technology to measure low oil flows? This paper explores t d to maintain the pressure above bubble point and improve oil recovery from the flank areas. However limited information is available conce d as an openhole monobore oil producer using a slotted liner. The well began production with an initial oil rate of 1 800 bbl/d. Oil production iques of the past to be conventional nowadays. This boom in technology application permitted high margin of investments to optimize wells ns spanning pressure and mobility profiling vs. depth fluid sampling downhole fluid analysis (DFA) interval pressure-transient testing (IPTT pletion or performing a multirate inflow performance relationship (IPR) test. This paper describes a technique allowing individual layer pres pansion of the wellbore in addition to events apparently associated with induced fracturing in the reservoir. Integration of the microseismic nstall permanent fiber-optic distributed temperature monitoring systems with its sand screens and to use these systems to monitor productio of a recent engineering development program was to create a new deployment system that directly addressed these constraints. Instead of in some wells. Previous studies indicated that it was very challenging to detect the thinly layered thief zones using conventional openhole lo

ecisions may not support the maximum economic value of the reservoir and can undermine the accuracy of the reserves estimates. With cu or the speed at which the available phase is flowing.ï¿½ Recent industry developments in production logging have addressed these fundam

ubsequent formation evaluation. A time lapse saturation figure could be generated immediately after the acquisition which is extremely instru ent in the reservoir has been estimated indirectly via numerical reservoir simulator successes of direct methods have been limited by the in results of the modeling process. This crosswell EM technique which has been successfully employed and proven in other geographical area oviding an image of the resistivity distribution between boreholes in time lapse. This paper explores the influence of a high quality backgrou oduction with an estimated 50 000 more wells to be drilled in the next 10-15 years. The production rate from CBM reservoirs is low perhap ch as density/neutron gamma ray and resistivity define some of the petrophysical properties of the coal layers but the nature and extent of and inefficient non-planar fracturing which significantly underperforms the stimulation potential compared to conventional clastic rock fractur t strategy operators and service companies alike have had to search for innovative solutions to overcome challenges faced in horizontal co difficult and requires abnormally high treating pressures.ï¿½ In this paper we show that the combination of high stiffness significant elastic umping nitrogen at high rates through coiled tubing (CT) into perforations isolated by straddle assembly.ï¿½ Currently energy that can be de a that is created. In order to achieve optimum horizontal well stimulation the lateral section must be characterized and the perforation place tures reveals stress regime orientation fracture morphology and their orientations. The interpreted results guide the design of horizontal w SAGD) and cyclic steam simulation (CSS) (Butler 1991). ï¿½Optimal well placement defines the propagation of steam within the reservoir a re definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances a well producing below its economic threshold. To keep up with current gas demand operators have moved to an aggressive horizontal dri ellbore drainage radius. The wormholes created by a retarded acid are deep but thin. During production the flux through the thin wormhole This offshore field has favourable conditions for ESP application producing from carbonate reservoir with no anticipated fines production lo

easing the productivity of the field by many folds. But each of these artificial lift systems has economic and operating limitations that elimina with poor reservoir properties and minor reservoirs in order to maintain the production rates. Application of horizontal drilling allowed achie ontrol for the initially forecasted production rates. However the possibility of expanding the gas production rates of each well to more than 1 ntly without perforating. Completions using these casing valves are called Treat And Produce (TAP) Completions and have a unique design Sarmatian formation (Base Cretaceous Paleorelif) at the depth of 1100 to 1150 m. Currently the main productive horizons are sands from th ss than that which would be required to continuously transport and unload liquids from the well.ï¿½ Sub-critical velocities are often encounte ss than that which would be required to continuously transport and unload liquids from the well.ï¿½ Sub-critical velocities are often encounte areas where fractures may not be dominant it is crucial to achieve maximum reservoir contact (MRC) through the well architecture.ï¿½ To t

ped with a SC that encompasses surface remotely controlled hydraulic tubing retrievable advanced system coupled with pressure and temp roachment over the reservoir interval. Recently completion technologies using downhole valves which allow production and injection contr was equipped with an SC that encompassed a surface-remotely-controlled hydraulic-tubing-retrievable advanced system coupled with a pre

erating costs lowering the pressure drawdown and maximizing profitability. This paper presents the results of a numerical study performed onveyed perforating (TCP) drillstem testing (DST) and chemical treatment of the formation by using standard equipment and techniques. alysis explicitly accounts for ESPs that are still operational at the time of the study thus removing a historical source of statistical bias. The ivity.ï¿½ Acids used for these treatments have been typically formulated with 28-wt% HCl and have been used successfully to increase prod eillance and cost. The original Alpine field development plan did not include hydraulic fracture stimulation based on the reservoir characteriz

the Bakken trend and is attracting several new and existing operators to the area. Different drilling and completion techniques have been tr fracture-geometry control without sacrificing proppant-pack conductivity. The conventional approach is based on net pressure control. This key objectives in acid fracturing treatments to be able to create longer and wider fractures and hence maximize well productivity. Alternatin es and allowed decrease of polymer load without increasing risk of premature screenout. Fibers proved to be reliable for successful placem slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric microemu less important. However a recent study pointed out that modulus contrast can have significant implications on fracture geometry and propp mpletion processes and field operations to make wells commercially viable. Strategies such as multiple-zone commingled completions the s uced water is recycled and used in fracturing applications each cycle of re-used water returns with a more complex chemical make up than tion of technology for reservoir characterization can shorten the learning curve of an operator in the development of a basin.ï¿½ Numerous g a short and wide fracture which bypasses the near-wellbore damage while gravel-packing the zone of interest. This paper describes a no so far without clear success. The paper describes a technique of physical barrier placement and tailoring fracturing fluid systems to contro hole with little alternatives for stimulation water shutoff or workover treatments. A very challenging task to stimulate long openhole sections eated with a final result of increasing overall water production. However if the water production mechanism is understood and the appropria n this setting horizontal wells have come to mitigate the problem however in most unfavorable conditions where oil and gas are found in tig

ent results with open-hole completions in particular. Consequently most of the planned future wells will be drilled as open-hole horizontal c

gies. 10 candidate wells were selected and the target zone was the GS-3A reservoir. 10-15ft above the GS-3A was a water bearing sand. M sed rectangularly bounded reservoir and the corresponding pseudosteady state shape factor of this type of well and reservoir completion un Volga-Urals basin. Both basins are geologically lithologically and stratigraphically vastly different from West Siberia. Adding the difference

endently without perforating. The valves have a unique design feature which allows an unlimited number of valves to be placed in a single w e possibility of high fracture initiation pressures is identified as the main risk with this approach. This paper will discuss the theoretical an r the fracture surface where rocks partly lose their cohesion. This study has developed a more appropriate model for fracture design which rically limited the application to fracturing reservoirs with low permeabilities. A new VES fracturing fluid has been developed for use in high

ompleted in various Morrow Sand intervals around 10 500 ft with an average Bottom Hole Static Temperature (BHST) of 190oF.ï¿½ Wellbo

oil which renders the situation even more difficult because of fluid incompatibility issues. The formation tends to produce oil with asphaltene ctive fracture clean-up is often cited as a likely culprit. This paper presents some of the results of an investigation of fracture clean-up mech diagnostic techniques and along with sound engineering practices can have a profound impact on how wells are completed.ï¿½ï¿½ï¿½ï¿

y of the positions of monitoring or treatment well surveys can cause more than a 40o uncertainty of the inverted fracture azimuths. Furtherm

ion of fracture conductivity little is known about the texture of the fracture surface created during acid fracturing or about the dependence o exist: fracture height half-length and azimuth. Commercial fracture models provide length estimate once a reliable estimate of height is know using this technology as part of a fracturing treatment. These issues along with regulations concerning the transportation of radioactive ma

ctor. The candidate selection process including production prediction is at an infant development stage and is additionally hampered by Darcy pressure drops dominate and the apparent proppant permeability is one or two orders of magnitude lower than the Darcy permeabi parameters of tip behavior has resulted in more accurate and robust fracture propagation models. However the situation is still unclear in hi ure of 15 wt% HCl and 9 wt% formic acid was used in wells completed with super Cr-13 tubulars. A high pH borate gel was pumped in stage ly induced fractures. We utilize the dimensionless productivity index solution (JD) for finite-conductivity vertically fractured wells in closed re racture geometry. Above the fault a near-vertical fracture geometry was observed. A change in fault orientation was supported by difference lowback during the life of a well. In particular determining whether the proppant flowback will stop after a few days of production or will con osure stress on the initial fracture due to the fracture penetrating into the higher stress region which leads to fracture reopening along the in . The present paper provides the data on hydraulic fracture simulation accounting for accumulation of damages in elastoviscoplastic mediu s fluid leak off. Those factors have strong implication on proppant distribution especially when larger size proppant are used. Although the l

ues and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production fra oil rate. To achieve this water must be injected into the formation at fracturing pressures. The completion campaign started with three wat g evaluation that is performed using a workflow including time-lapse Sonic Anisotropy and Flexural Waveform Dispersion Analysis (open ho both to significant pressure drops and to proppant bridging as fluid and slurry move through the restrictions. New modeling results are prese than for other types of intelligent well because it provides a direct replacement for conventional gas lift equipment compressors and pipeli d Hole Frac Pack Cased Hole Gravel Pack Stand Alone Screen and Orientated Perforating). Based on the experience and field performan ed. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation has lead to the operational benefits of multiple ed. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation has lead to the operational benefits of multiple e or while starting production? Will the filtercake disperse and get removed while producing the well and applying drawdown to the formation di Aramco. Included in the description are equipment selection design and development details installation procedures and â€œlessons le handle effectively heterogeneity or permeability contrasts exposed along the sand face. The ICD controls and interrogates more optimally b covery with fewer wells both offshore and on land. Intelligent completions have proven their value in managing production from multilateral uded in the description are equipment selection design and development details installation procedures and â€œlessons learned after ins uncertainty. Recently developed schemes which update models with data acquired during the optimization process are computationally ve provide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes place

hinly laminated reservoirs which exhibit vertical heterogeneity and a wide range of flow properties. Therefore it is critical to combine high re n about the possible advent and extent of sanding will be helpful in planning for completions and facilities. The study presented in this pape ore the wells are often stimulated by a matrix acidizing treatment after the perforating.ï¿½ A prevalent mind set in the industry is that acid dis mages. A new underbalanced oriented perforating technique has been successfully implemented in Algeria. It combines the use of a format tion evolution in infill well at Resak field one of the gas field operated by Malaysia National E&P Company Petronas Carigali Sdn Bhd. Sin n Anaco District are normally perforated using conventional static underbalanced techniques. The productivity of these wells was evaluated eability layers. The shallower layers generally have better permeability and were developed first while the deeper lower-permeability reserv ies to improve the efficiency of the fracture job maximizing ultimate production from the well. Wells are frequently completed with multiple niquesï¿½will not produce until stimulated with acid.ï¿½A new perforating technique has been deployed that creates clean low skin perfora er the skin factor can rarely be estimated reliably from pressure data acquired in the current UBP operations if without flowing on surface in CT on depth involves two CT runs the first to run a memory gamma ray (GR) and casing collar locator (CCL) and the second run for the actu evability risks are to be avoided. In practice the perforating design engineers do not have a well-established analytical tool to help them und

p sandstone rock called Berea Sandstone. Four different charge types were tested including one standard (conventional) charge and three nd the effectiveness of this connection is the result of the perforating system selection the well environment in which the perforating job is e the challenges and successes of reducing produced water by using smart completions and how multiphase flow meters (MPFM) helped in aintenance. The development of the Albacora Leste Field in the ultra deep water Campos Basin was a key component of Brazilâ€™s drive are produced primarily from massive fine-grained Pleistocene reservoirs. These reservoirs require sand control to prevent sand production di Arabia (figure 1). Hawtah is one of several small fields located along the Hawtah Trend (others are Ghinah Hazmiyah Nisalah and Umm es/permeabilities premium screens with shunt tubes in conjunction with cased-hole frac packs have been used to complete the wells. The t 97 and oil recovery averaged 2000 STB/D. Sand production was anticipated under normal drawdown from production onset and as such the

½ This results in low production rate and consequently leads to the requirement of high drawdown pressure. ï¿½Hence it is imperative that th been attributed primarily to the rigorous design and field application of the fluid systems used at all stages of the well from drilling the reserv

completion technique in these wells which require an effective and reliable sand control for long term and open-hole and large tubular siz d in two waves commonly called Alpha/Beta packing. The second method utilizes a viscous carrier fluid and high concentrations of gravel in allenge. Although scattered attempts have been made to separately understand different parts of the gravel-pack process the industry still l and allows access to larger reserves through fewer wells. Since most of these reservoirs contain reactive shale streaks they require synt stem approach for removal of perforation damage effective gravel placement and packing of the perforation tunnels. It was found that surg stem approach for removal of perforation damage effective gravel placement and packing of the perforation tunnels. It was found that surg g Statoilâ€™s finite element modeling method suggests that oriented perforations can prevent sand production in the horizontal wells. This w ocated offshore in the North-West shelf of Australia Stag field is a shallow and unconsolidated glauconitic sandstone reservoir with a top an s well as excellent return on investment for the operator. Screenless completions are an integrated solution that involve many field-proven

anding potential sanding risk for Sarir and that it was necessary to design and implement a sandface completion and sand management st ion and disposal and lead to significant economic loss. On the other hand precautionary but unnecessary sand prevention will mean unwa om different sources and different domains (i.e. wireline logs laboratory test data drilling data well data and field data) were integrated to failure and sand production. The laboratory perforation-collapse tests were conducted on weak sandstones obtained from downhole and o

ations is generally assumed to be a two-step process with the shear failure being the first step and the transport of the sand out of the per s sand production risk in the development wells and eliminate unnecessary downhole sand control. The data required for the study include: ate stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. xes in a hydraulic fracture both in the main flow direction along the fracture and in the fluid loss direction. In our tests the injection rate into ulation rate. Acid reaction rate is a function of several factors the most important of which is the reservoir temperature. Yet another concern excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsif excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsi gh coiled tubing in three of these wells and bullheaded in five other wells for comparison between both methods of placement. Pre- and pos out 1% halite and < 1% quartz; therefore the formation is a potential candidate for acid stimulation. This limestone is atypical because of it ctures. Furthermore acid penetration is limited by the large surface area of the horizontal wellbore and this is exacerbated by the relatively articular challenge was the flowback of tubing pickling and spent acids and neutralization of the spent acid on the surface. A series of effec

be taken into consideration. The presence of natural fractures makes the entire treatment more complex. Acid placement and diversion ne on. The second is its corrosivity to well tubulars. Hence organic acids become viable material for matrix acidizing to alleviate these two prob

roduction peaking at 66 000 BOPD. The permeability varies from 20 to 200 mD with streaks exceeding one Darcy. At different times in the p he zone with the highest permeability or least damage. Field experiences showed that there is no assurance of complete zone coverage with in financial viability of the well stock. In many areas however production wells do not benefit enough from the water flood or the injection s of injection rate temperature and fluid properties and few have focused on the influence of rock properties on stimulation treatments.ï¿½ T s (high fracture conductivity) as compared to low permeable ones (moderate fracture conductivity). Understanding these basic differences is d over the past years with varying degrees of success. When dealing with water sensitive formations a common practice has been to use o age from polymer residuals were the main drawbacks. A never ending quest for efficiency and higher production rates called for different op mpletion knowledge by developing and refining more complete interpretation and completion models based on comprehensive data. This p

lenging wells due to the drastic permeability contrast across the pay zones. Typically the treating fluid in a matrix treatment flows into high p producing reservoirs on every well. Consequently the value of continuing to run these tools was raised by management. In response the re e analysis and modeling. A novel approach is taken to develop the analytical solutions and procedures for both liquid and gas wells. Approxi long horizontal well has been drilled in an area interpreted to have high fracture density.ï¿½ A comprehensive test program including flowin n logs to; 1) determine the flow rates for each individual stage in a multi-fractured well 2) apply rate-transient solutions that use rate-norma he permeability and skin of individual layers. Greater Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan ha ning.ï¿½ A similar early-time pressure behavior may be due to the presence of plugged perforations. Drilling problems associated with high e is applied to the sandface (beginning of a drawdown or injection) of a well. However the initial pressure propagation is not diffusive but it p ts has always been a classical management dilemma.ï¿½ With the advent of digital oilfield technology the pressure and hence the deterior st and production-data analysis. However there exists no study presenting an independent assessment of all these methods revealing and

ressure-transient testing has long been recognized as a reservoir characterization tool. Although welltest analysis is a recommended techniq reservoir data are essential to understand such reservoirs. Another challenge presented by thinly bedded reservoirs is the presence of verti able straddle packer system of wireline formation tester. A MiniDST transient sequence consists of a single or multiple flow periods induced gravating factor is that such wells are often producing at high water-cuts thus leading to significant uncertainty on oil rates. To solve such m ompositions create unique challenges to the successful acquisition of well test data. The paper discusses the challenges and potential ben

as-volume-fraction and low pressure unstable flow these controlled conditions are far from reality which can lead to unforeseen errors in the t measurement devices. Multiphase flow meters have been proved for multiphase production metering by many operation companies world been used to well test and meter mostly liquid-rich flow streams. These models were not developed for the measurement of gas flow rates s and improve the testing duration and strategy. The program included in addition a set of elements to qualify the multiphase meters results

put a cut off in the GVF range of 85-92% following the type of technology. These criteria are often based on past experience or special cas l test analysis in full-field simulation has long been recognized. However only limited benefit could be obtained by reconciliation of the analy e and its auxiliary functions can be used to provide the characteristic signatures for unfractured and fractured wells. The purpose of this pa ues have been used there are valid concerns that smoothing procedures may adversely affect the well-test interpretation. In contrast meas placed in the boreholes.ï¿½The electrodes are partially insulated from the other completion components but nonetheless record high signa

ent steel and elastomers can be corroded by CO2 and the ageing process will be accelerated by any defects in the cement sheath. It is th alculated from the density log data. The vertical stress gradient is on average 22.01 MPa/km. Extended leak-off test data a borehole wall e els over time allowing migration of CO2 from the reservoir to shallower formations (e.g. aquifers) and/or to the surface. In this paper a risk and surface models leading to non-optimal solutions due to the non-dynamic integration between models. A recent trend of the industry is th s complex processes such as dry-out salting-out chemical reactions to the dynamic model. Simulation in these situations is one of few me nology targeted at developing an in situ laboratory for CO2 storage. Its aims are to advance the understanding of the processes involved in n-free energy sources are developed and viable.ï¿½The current options for captured CO2 utilization are; Enhanced Oil Recovery (EOR) E e altered. The impact of the resulting deformations on seal integrity must therefore be assessed in order to properly manage containment pe

Instrumentation and Control System (DIACS) installation worldwide with the lower isolation packer set at 8560 m / 28084 ft measured dep ngers. The field pore-pressure gradient is at 9.07ppg EMW but mud density needed for wellbore stability is greater than 11.6ppg. This resu

han 5 MM bbls of oil. The EOR potential of these fields is believed to be significant. Few of these fields have been waterflooded and only fiv formations containing CO2 were discovered in North of Mexico. The Quebrache region contains several occurrences of natural CO2 that h luation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin high-q g portion of condensate liquid will remain in the reservoir and will not be produced. Many condensate reservoirs have been producing with final implementation. The objective of this investigation was to understand the impact of key parameters in the process specific to the selec . The constraints on gas handling capacity resulted in shutting-in a number of high GOR wells. These wells were required to be treated to s

volved evaluation of a high temperature polymer base water shut-off fluid for deep penetration of the fissure formation and a micro-fine cem s restricts considerably the convoyed down-hole tools configuration ï¿½ This paper covers water shut off case history of an oil producer tha ediments and water (BS&W) are problems associated with fields having strong aquifer drive mechanisms. As a result most exploration and ble to perform mechanical water shut-off in open horizontal well as inflatables are quite sensitive to be set in open hole. This paper shows methods in this field. Dual injection combined with permanent water shutoff (WSO) gels or relative permeability modifiers to control water p rbon production and results in large amounts of produced water that need to be disposed in an environmentally friendly manner. Some field mes more challenging for horizontal wells with open hole completion. Well A a horizontal open hole producer with 2 440 ft of reservoir conta haltene wax and hydrates) precipitation and their potential to disrupt production due to deposition in the near-wellbore regions and product locities ranging from 0.025 to 1.75 m/s. Data were acquired on flow patterns pressure drop phase fraction and droplet size as a function o €“5ï¿½). A total of 324 tests were conducted in a 0.0508-m (2-in.) ID 21.1-m (69.6-ft) long test section using tap water and mineral oil with s n optimization and back-allocation of complex well configurations such as nodal analysis work only for a static problem.ï¿½ They cannot the oil industry is to generate a production forecast derived from a reservoir-based model without taking into account surface facility constr ors that create significant impact on field development planning especially when dealing with marginal deposits having varying fluid charac production method design for development of offshore fields. In this study fluid characteristics and flow assurance aspects of a live waxy als weakening the resistance of those seals and compromising the integrity of the fluid samples and the safety of equipment and personne reservoir fluid. In a number of reservoirs around the world carbon dioxide (CO2) is a critical gas composition. Examples from two such res

oint pressure of the reservoir fluid changes in the surface yield of condensate as reservoir pressure declines and changes in the specific g volume factor Bg) were investigated. According to our knowledge no other correlation for calculating oil-gas ratio exists in the petroleum li nt of asphaltenes in a reservoir and a simple theory is shown to apply. The corresponding downhole and laboratory analyses are consistent ming correlations among nearby wells may be inconclusive since the channel sands under study have limited lateral extent and hard to corre two primary factors that cause major and expensive differences between predicted and actual performance in the oil field. Furthermore diff analysis (DFA) during formation testing has provided real-time fluid information. However the extreme conditions of the downhole environm . Analytical as well as numerical models reported in the formation testing literature rely predominantly on simplifying assumptions in terms o GOR fluorescence apparent density fluid composition (CH4 C2 C3-C5 C6+ CO2) free gas and liquid phases detection saturation pres

M and low mobility sections a new focused sampling device was utilized for effective formation testing and sampling purity. One case history asibility of a project and determining if an offset discovery can be produced without a facility upgrade can economically make or break a pro

le with an equation-of-state (EOS) model demands that the results are verified with independent measurements. Our analyses of many sa able to assess the phenomenon. Individually geochemistry downhole fluid and mud gas analyses have provided valuable insights into com sult there exists a broad spectrum of reservoir fluids in this reservoir condition. Identifying reservoir fluid in the zones of interest is extreme perties. Conventional wireline triple-combination measurements showed that the interval of interest was uniform and free of noticeable imp al pressure-depth plot and pressure gradient analysis of wireline pressure data is not easy and identification of in-situ fluid type can be diffi tory analysis. Pressure gradients with wireline formation testers are traditionally used to evaluate fluid density fluid contacts and layer con e contamination by the OBM filtrate is a critical factor for the accurate measurement of the sample pressure/volume/temperature (PVT) prop

teady state conditions. Montel et al. (2002) discuss processes that arise from recent charging of these reservoirs which are not in equilibriu wever hydrocarbon differences can be identified reliably only when the significance of uncertainties from measurement and the oil-based m nalysis (DFA) during formation testing has provided real-time fluid information. However the extreme conditions of the downhole environme

e dependent K-values.ï¿½ Although these procedures may be extended to more general N-phase systems the paper gives full details for a operate heavy-oil production systems knowledge of the realistic viscosities of the emulsified heavy oil under the actual production condition

by mud-filtrate contamination which introduces errors into the laboratory measurements of fluid properties and requires analytical methods t ensures it is clean. The reservoir fluid is then captured in sampling bottles or chambers. Gas-condensate sampling has always been the tri rea in recent years arguably being the multiphase environment. Multiphase flow meters have been accepted for several years now by the in by the difficulty to separate the phases.ï¿½ Furthermore in-line multiphase flowmetering brings significant benefits to the ease of deployme ultimately stop the reaction of the acid with the rock. Recently chelating agents have been introduced as stimulation fluids. The advantage temperature complex mineralogy poor consolidation and a wide range of sources of potential formation damage make any stimulation a e particles that damage the porosity of clean sandstone cores (in core flow tests); the study includes reactions carried out under controlled c ckages to production and process systems requiring remedial action often on short notice. Current commercial halite inhibitors are only eff

gations were carried out to verify the growth of naphthenate-soap particles under different pH conditions. Core-flow tests were conducted to ne. Additionally the impact stresses plus the outward traveling shock wave severely weaken the rock matrix by de-bonding the cohesive int rock fabric. Perforating underbalanced has become the primary means of removing perforation damage and maximizing productivity tho ular and planned injection of inhibitors into producing and injector wells is the most common method of scale precipitation prevention no su mgal). However these design criteria and formulation of the scale treatments had to be changed significantly to be effective in the typical Uin in real time analyse data make decisions and modify the completion without physical intervention to optimise reservoir and asset perform cing wells. Injection seawater (rich in Sulphate) and formation water (rich in Strontium ions) mix in the reservoir and/or wellbore under varyin scale but in practice concentrations < 5 ppm are adequate.ï¿½Investigation of the produced brine compositions has revealed that this is d match in a particular region may adversely affect the match in other regions. Full independence of regions within a reservoir is not possible pediting history matching of simulation project. The objectives of the study are to improve the history match by validating fracture lineament s of thousands to millions of cells incorporating large amounts of field and well events over substantial operation periods be they historical the design and intelligent well management is key IOR option to Cantarellâ€™s late field life management. This paper presents the result ve management tactic to monitor the field and to select candidates for workovers.ï¿½ However the large number of wells in AIB (approxima ter injection (WI) and WAG pilots to test the recovery strategy. The pilot employs advanced geophysical and modeling tools to measure form n the reservoir to assess the efficacy of various courses of action and most significantly adjusting various teamsâ€™ â€œkey performance tation of horizontal drilling technologies for the construction of wells in unconsolidated sandstones electrical submersible pumps (ESPs) be res of the reservoirs in the Faja are relatively high in the range of 600 to 1 500 psi with viscosities typically greater than 2 000 cp. For the a 5 API) Garzan (12 API) and Camurlu (18 API)) in south east Turkey were used.ï¿½ Using a novel graphite core holder packed with crushed cessary. This project covers a feasibility study considering the Horizontal Alternating Steam Drive (HASD) process geared to increase the r e prone to lost circulation. First few horizontal wells were drilled with traditional technology of positive displacement motor with Silicate mud e reservoir characterization in the steam flood pilot area will improve our understanding of the range and distribution of formation properties fluid samples are obtained by setting a rubber packer and small diameter probe. The packer hydraulically isolates a small part of the forma

ning and sand production. In his circumstance CNPCIS set itself a daunting task of tripling the production in less than a year. Horizontal we

s and misses targeted oil zones. The high viscosity and low mobility of the Issran field heavy oil in contrast with the strong mobility and low

erves and large efforts have been spent to overcome difficulties related to this kind of oil production. Venezuela has pone of the largest rese

al sandstone acidizing treatments is that the success rate is generally low due to the uncertainty associated with the fluid-formation interact on are reducing reservoir and fluid uncertainties confirmation of technical and commercial feasibilities construction of a pilot gas processin

er we have studied the effects of gravity using experimental data available for five live oil and condensate systems (at high pressure and te

le shear degradation early crosslinking in the tubulars can substantially reduce the final gel strength even to the degree that near wellbore nmental implications of acid handling at surface and shortage of hydrochloric acid in certain regions must also be considered to fully apprec

llows to optimize production and flow above dew point in deep high pressure and high temperature wells where intervention is very expensiv lls placing over 3 million lbm of proppant with a success rate greater than 85%. The wells targeted were both injector and producer wells. Th n developed for the stimulation of high-temperature sandstone reservoirs. By introduction of unique chemical mechanisms the new sands m 2% to 37% (w/w). The effects of matrix treatment using a chelating agent-based system on these field samples were studied using coreflo se fluids are known to generate undesired effects such as uncontrollable height growth significant proppant pack damage lengthy clean up t high temperature. Adsorption/desorption characteristics of these chemicals and temperature stability are also investigated for long-term p ling. Due to the lack of standard laboratory techniques for such measurements at high temperatures and pressures current practice involve

contact area offers a potential for enhancing well productivity and overall well economics additional stimulation is usually required. Conven

scenarios for completions and drilling locations can be systematically and rigorously analyzed. Case studies from North America and the M ckage. One well employed techniques standard to the area â€“while some experimental fracture techniques were tested on the other. A gen or. That information is not less critical for infill drilling fracturing ï¿½oldï¿½ wells re-fracturing fracturing of sidetracks and the knowledge o n some cases microseismic monitoring campaigns are performed in these various low permeability environments to improve the understand fractures as their heights grow which results in high water production and a subsequent significant reduction in produced gas. An integrate

of pumping services in onshore areas. Success and industry eagerness for process/cost optimization have contributed to many technologic consists of fine-medium feldspar-quartzite sand lithic feldspar-quartzite sand the pore type dominated by inter-granular small inter-granula quality intervals. These oil reserves cannot be produced efficiently and economically by vertical wells through primary or secondary method simulation workflows were employed to build a 3D flow model from geology geophysics petrophysics and engineering data and interpretat nd fracturing treatments response.ï¿½ The SWM is coupled with the development of NPV optimization models for each well.ï¿½ Tools for t rcy range. The overpressured reservoirs become economically viable only by hydraulic fracturing. Two major challenges of modeling the fiel ssure to avoid non-economical completions continues to leave hydrocarbons bypassed. Using recent advances in logging technology and p

earned from the use of an optimal dataset in addition to a workflow on fracture characterization for tight deep carbonate reservoirs in Kuwait ntinues to rise. It requires an effective solution to significantly reduce the largely extended rig time due to heavy WFT programs and operati actures plays the same role in improving the flow mechanics. As an industry there are many tools available which characterize the propert esults for a wireline pressure data collection campaign on twenty wells where more than 120 pressure measurements were taken in the Wa

nce level of the final pressure is often uncertain. These issues are painted on the ever-present backdrop of supercharging that can limit the er poor drilling success thus the operator invested in 3D-seismic acquisition and an integrated multidisciplinary reservoir modeling and sim ess with horizontals has been observed in the Bossier and Cotton Valley Sands of East Texas and north Louisiana. Horizontal wells are com than 600 m3 oil per day. The article describes efforts made on a new exploration approach elaboration based on an integral analysis of th

nts. To use openhole sampling tools for these flow measurements it is essential to differentiate between water-base mud (WBM) filtrate and

rmations. This paper discusses about number of small fields located in Muglad basin wherein oil accumulation is found in multiple layers of

g the companyâ€™s true financial performance in comparison to quality safety environmental concerns and other factors. When nominal on-making it is possible to improve quality of critical decisions. Different technique can be used to elicit judgment from individual experts an Oil Company (K.O.C.) in the Burgan Field Kuwait it became apparent that there was a need for clearer and better quality real time log inform orehole nuclear magnetic resonance (NMR) has been demonstrated to provide pore size distribution information and methods exist in the l ral radius of investigation but very poor vertical resolution. Constructing an appropriate simulation model requires rescaling the data and th porosity system is illustrated by strong leaching (i.e. dissolution) overprinting the primary interparticle porosity of a grainstone and respons the help of image logs and cores and other available data set. Data analysis and integration of borehole images in 9 wells of the study area lineation and prediction of the best quality reservoir facies so that optimized exploitation of the reservoir can be achieved. This paper descri optical spectroscopy which can provide estimates of filtrate contamination gas/oil ratio (GOR) pH of formation water and a hydrocarbon c ming correlations among nearby wells may be inconclusive since the channel sands under study have limited lateral extent and hard to corr entional triple combo logs gives an average response when logged against diagenetically altered zone thus overlooking or under-estimating r with complex mineralogy varying water salinities across the field which makes the visualization of a conceptual geological model in the pr likelihood that measurements will be made before the onset of significant invasion. The colocation of resistivity- and neutron-based sensors s towards the reduction or even elimination of the use of chemical sources where possible. A new Logging-While-Drilling (LWD) tool has b

a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the commonly us work a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the common om borehole NMR logs and electrical images and have earlier studied the relationship between NMR T2 distributions and capillary pressur units. The basal sand syones are often shaly and silty. The sandstone porosity value range from 9% to 26% with typical values being from 2 re highly altered by diagenesis.ï¿½ Vugs are developed in several intervals.ï¿½ Computation of permeability from porosity alone yields sca he applications of NMR borehole images and wireline formation testing technology in oil-base mud to evaluating the lithology the geometry

y. Difficulties will arise when anisotropy is not caused by sand-shale laminations when no sand-shale point exists or when the nearby thick eed to be considered in resistivity log interpretation. In this study LWD resistivity modeling work was conducted to study relationships betwe hrough from the underlying aquifer in horizontal wells. The identification and characterization of open fractures and conductive faults is of cr Many deepwater reservoirs comprise of young turbiditic formations which even at great depths remain unconsolidated or only weakly ceme l or drilling-induced origin. Cross-reference with cores from the same sections allows such discrepancies to be reconciled: in an example ca orth and north-east of the main Khafji Structure in Tayarat Formation of Late Cretaceous age. The present study utilizes twenty two well data

not always make an accurate inference of reservoir properties from well-logs to a reservoir model because of the stationarity and ergodicity ctives: identify the layers that may contain hydrocarbons verify productivity and fluid types with formation testing and sampling calculate n their detection. NMR vertical resolution is mainly controlled by the antenna aperture that is in the case of a high-resolution antenna 6 in. o

reasons for these inaccuracies generally originate from the traditional practice that LWD depth is purposely made equal to the drillerâ€™s d

ction and waterflooding. Long-term injection into these wells can result in the creation of fractures that grow over time. The effect of fractures in groups viz. elastic parameters strength parameters and in-situ stresses.ï¿½ Even the profile of in-situ stresses with depth is estimated rilling practices. We have developed a new multifrequency inversion algorithm for the estimation of maximum and minimum horizontal stres nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and we nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and we nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and we faults have facilitated the flow in the Jurassic reservoirs. Identification of faults and associated fractures mainly has been on the basis of 3D ophysical analysis for better fracture characterization and selecting the best perforation intervals for a producing well. This workflow is appli wells is mostly associated with natural fractures and vugs. The presented study was our first project in Russia where a complete integrated eld is now critical to optimize infill drilling and produce the remaining reserves. The present paper focuses on the characterization of differen n potential of wells is mostly associated with natural fractures and vugs. The presented study was our first project in Russia where a compl

phase flow properties such as relative permeabilities and capillary pressures. Continuous monitoring of oil displacement by injected water i ous reservoir on a typical log analysis can lead to incorrect assumptions about the economic value of the hydrocarbon discovery the produc zone layers using oil based mud systems. To further investigate possible near formation alteration an extensive evaluation program was un

affected by the minerals within the matrix and the tool answers mainly to the contained fluids in the pores of the rock. This peculiar characte table for sampling and NMR logs are used to gauge if permeability is sufficient for a sample to be taken. However these logs are not able t we observe effects caused by the drilling process such as gas dissolution in OBM filtrate and time-lapse effects between LWD and Wirelin nevitable for any given NMR technique. For example the overall acquisition time is dictated by operating at reasonable" logging speeds so he general readership of recent advances in various areas of petroleum engineering. Introduction This summary of the state of the art in ogical complexity of the Estancia Cholita Field which is mostly due to limited lateral continuity and small reservoir bed thickness particularly ed to better characterize fluid flow in horizontal wells. Advanced sensors provide better resolution among gas oil and water and cover more

e of this paper is to present (1) how to use the inflow data for the evaluation of formation properties and (2) how to cope with the uncertain d permeability ranges between 0.001â€“17 mD. The oil in the Mishrif is highly viscous and production is normally enhanced by fractures in

essure analyses provide valuable insights into reservoir architecture. Each analytic method relies on different fluid traits and has its own limi xico uncovering a large concentration variation of asphaltenes. These asphaltene nanoparticles are shown to be colloidally suspended in th y. An extension of the conventional Selective Inflow Performance analysis is presented in this paper to obtain estimates of the formation an and eventual improvements in ultimate recovery. The recovery strategy for As Sarah oilfield in Libya has been based on SCAL. PND loggin s-bearing formations translates into lost productivity while perforating water zones can have detrimental effects on well performance. Moreo

ize recovery. Permeability and permeability anisotropy at different depths are unknown variables that affect well completion and reservoir m g effect. We present an algorithm that takes into account the supercharging effect in analysis of pressure transient tests acquired with a sin s. The process specifically involved first generating a series of unconstrained production options which then considered drilling reach and a ism (dynamic information) may impact significantly the estimation of reserves and result in the termination of the project during the appraisa the Bokor Field offshore East Malaysia.ï¿½ A brief description of each methodology is outlined potential benefits and challenges are discu s with other options in a companyâ€™s portfolio of investments. The re-development project presented in this and its companion paper1 (S of Sarawak East Malaysia. The reservoir sands are highly unconsolidated at the top of the structure and gaining consolidation with depth.ï¿ ogy to maximize the net sand delivered from each well. The drilling of development wells in sand stringers involves very thin and sinuous ta nty. The integrated reservoir management team has utilized the geological and seismic impedance to locate a power water injector in the s he low-pressure area and additional wells highlighted by the Moving Domain study.ï¿½Compressors were installed on successful test cand ntation work. Scalable to any given size of hydrocarbon prospect and number of infill wells the computational method incorporates cross-d roduction can occur over the lifetime of the field. Falling reservoir pressures cause not only a drop in manifold pressures and the need for a well interventions(coil-tubing operations) leading to better reservoir management.ï¿½ To evaluate the intelligent completion technology an kages.ï¿½ï¿½ï¿½ We present a comprehensive portable flexible and extensible FM framework completely decoupled from surface and s n must be given to operating constraints including cost handling capacities compression requirements and the availability of lift gas.ï¿½ In ch confirmed that A6.0 reservoir unlike all others in the field which co-exist within a stacked sequence is surprisingly isolated from the surr g these opportunities reducing the risk on oil recovery associated with the various enhancement initiatives. The objectives of this paper are

steps to set up a SRM and IAM are presented in this paper. The steps are described in context of an actual field operation. A WAG cycle op hat has been producing for some 12 years will be examined. The wells are all producing into a sub-sea manifold and then tied back via a 6 the oil industry is to generate a production forecast derived from a reservoir-based model without taking into account surface facility constr ore than 20 years have been generated within one year. The three main enabling technologies for the rapid execution of integrated studies ling. Typical completions include sand-control devices such as gravel packs and fracture packs inside 9 5/8-in casing with zones separated

stments associated with exploration and drilling new wells as well as commissioning new facility expansions Production Optimization and d ural locations of clean sandstone reservoirs. As a result a comprehensive portfolio of prospects has been built for a robust development pr ss is the dynamic integration of historical data and new information technologies and engineering diagnostics to systematically identify la igh drilling and completion cost but also due to the high risk and uncertainty involved in the process. To make wise investments in such a d ts a mathematically consistent framework using decision trees conditional probabilities and Monte Carlo simulation to appropriately value f

measurement is highly sensitive to reservoir boundaries and therefore gives early warning of conditions requiring steering adjustments while ends on water drive as its main production mechanism it was essential the wells were placed as close as possible to the top of the reservoi cribed frequency (e.g. quarterly) until the total well â€˜budgetâ€™ for the field is exhausted and eventual termination of wells as they reach fer and its size with a set of simulation models to assist with well placement decisions. In the South Timbalier 316 block a delineation we The approach provides a filtering concept to select all wells that might have bypassed reserves in their drainage area and provides a step voirs was widely ignored. These effects are related for instance to interference phenomena which directly impact the optimum number of in on the concept of surrounding the wells whose locations have to be optimized by so-called pseudowells. These pseudowells produce or inj ytical models1 2are mainly dedicated to describing the ability of a reservoir to drain heated oil and do not depict all details of real SAGD pro on of the point source solution can be performed to calculate the average bottom hole pressure of a well. These equations are applicable se flux fields is governed by a Volterra integral equation. Within a multiple layer reservoir scenario our semi-analytical solutions are applicab sitivity coefficients that define the relationship between reservoir properties and the production response typically depend on either the numb system of equations backward in time per each forward time step which is usually of high magnitude in case of field scale applications of lon

nefficient. In order to circumvent this problem a set of multiple geologically plausible permeability realizations or the training images for a g

mass equilibrium equations for component mole fractions saturation temperature and pressure using the Newton-Raphson method. Externa y and speed. Here we describe an efficient natural-variable-based general formulation approach which handles general partitioning of phas is composed of interbedded shallow marine-ridge sands with some coarsening-up sequences. A typical horizontal well in this field has pe

y result in special wellbore flow dynamics. In addition technologies such as intelligent completions can be used to regulate flow from variou

niques: Empirical Fetkovich Locke & Sawyer and Analytical Transient solutions for oil and gas wells/Reservoirs using a production surveil st single-well model was applied to study the important parameters involved in the fracture-cleanup process. This three-phase 2D model pro process and inertial non-Darcy flow effects were considered to be key parameters for poor performance in previous studies. A further one ning. As such pressure transients are often used and can be successful tight reservoirs where transient flow regimes can be used to obse better and more reliable production optimization. Most of the existent numerical models are based on 3D computational grid that is used for in such formations. An interfacial slip model has been developed and implemented in a pseudo-three-dimensional (P3D) hydraulic fracture production rates to evaluate the profitability of fracturing. The availability of analytical software that is simple and fast has been the rational onless conductivity and the inertia resistance factor. However based on the parameter matrices of their numerical analysis restrictions were most probable description of the reservoir/completions. After validating results with a numerical reservoir simulator we systematically used ng boundary-dominated flow have been made using a mathematically rigorous model for pseudosteady state flow.ï¿½ This model has been ugh operational problems have been solved this way the net pressure response while successfully fracturing did not obey any of the existin aw fluid flow along the fracture trajectory and 2D equations of the linear elasticity for rock massif. The model predicts and evaluates the nea udy we can conclude that ANNs that use radial basis functions (RBFs) can decrease the error of the prediction effectively when there is an

eterogeneity leads to the use of fine gridding especially in the vertical direction to accurately simulate the fluid flow in the reservoir. Third the alculation is proposed and an analytical solution is derived on the basis of some realistic assumptions. The analytical solution can be used t and injectivity index (II) are not particularly useful when the mobility ratio is high since they require the use of a nominal drainage radius whe zed. This study shows that proper integration of all pressure production and geological data is critical in defining reservoir compartmentaliza material balance calculations under different drive mechanisms and using different material balance methods. This study allows reservoir en ion pressures become unavailable. Well logs and well tests can be missing if not properly archived. Moreover the data may be complete without and with anisotropy in our calculations. Numerical examples for a binary mixture of C1/C3 and a multicomponent reservoir fluid are g experimental design workflows and the different methods of generating response surface models for reservoir simulation studies there is

solution matrix is discussed and a version of the method that provides an M-matrix is described. Convergence and numerical flux consistenc re obviously unable to reproduce spatial condensate distribution in near wellbore zone of the reservoir but after proper tuning these models ation. The simulation of oil production from triple porosity reservoirs requires the development of composite porosity composite relative pe However the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing the limited

ion of streamline methods to fractured reservoirs often requires the modeling of at least three compressible fluid phases. Flow simulation o actures one. It is also assumed that the flow occurs in fractures only i.e. the matrix permeability is equal to zero. Mass transfer between m h regard to accuracy and computational efficiency. We present a new simulation approach based on streamlines in combination with a new

that this is incorrect. With a correct implementation of the RML method within a Bayesian framework we show that RML does an adequate

ature increase on scale precipitation it is only recently that a body of work has been developed on the impact that the dynamics of brine mix

e saturation transport using adaptive mesh refinement (AMR) along streamlines is investigated. The refinement strategy is based on the mu hnology maintain its better scaling ability than traditional finite difference/volume technologies. However we went further and have treated t plex in setup and computation. The presented workflow is a new approach to infill well performance prediction that combines speed and re cs is required for implementation of the EnKF. Moreover data are assimilated (matched) as they become available; a suite of plausible rese etic case. Geostatistical simulations involve generating multiple equi-probable fine scale depictions of the reservoir heterogeneity each ho del together with considerations to ensure that the resulting equations have a Jacobian matrix that is invertible and explain the necessary mo

ed on geological and engineering data led to 24 isolated segments for which up to 24 separate simulation models can be potentially built. B ng technique that can provide a continuous wettability log. A detailed analysis of a new model for the conductivity of reservoir rock called the

Tayler1 and the reply by Barree and Conway2 regarding paper SPE 893253 in the JPT in August 2005. To properly assess all the argumen es in the pressures of the invading mud filtrate and formation oil to result in the following unusual yet often observed behavior: 1) negative Lekhwair in the Thamama limestone. Commercial production from the field commenced in late 1984 with good performance being attribute log data base viz. electrical Images and sonic logs. In vertical wells the maximum tangential stress around borehole can produce breako e beyond reservoir well process and production management.ï¿½What may not be so clear is how to apply these smart technologies to arted to develop in direction of sweep efficiency improvement by cheap agents. Nevetheless by now the very intereresting EOR experience d had delivered almost 50 billion barrels of oil equivalent to markets in Europe and the United States. Alaskaâ€™s North Slope started pr vely simple situations that require a simplified set of input data. In these cases the results are consistent with those of finite-element model

passed oil all the wells were logged using a through-casing formation resistivity tool. One well was also surveyed with pulsed neutron captu t was drilled and completed in the Oseberg Sï¿½r field in December 2005. The solution combines hydraulic flow control valves with advanc and reservoir properties in these formations. Water injection was implemented in Mauddud Formation in late 2000 after a successful waterf cost and poor data quality at low flow rates this technique was abandoned after initial logging efforts. Development of a state-of-the-art ele

time would result. The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low doub time would result. The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low doub support maintenance. In this well a multi-reservoir dual gauge system was deployed to monitor pressure and temperature in two stacked ca mation fluid being pumped through the tool flowline and the relevant visible wavelengths in an optical detector are used to record the dye sig n (s) and current average reservoir pressure (Pave); the KPIs are summarized on a quarterly basis and compared with historical trends to c smic interpretation were used to provide the operator with recommendations for reservoir management such as drilling patterns new well p treatments where excessive height growth is believed to have occurred premature screenouts are usually the result of insufficient fracture

ently installed optical fiber along their first Joslyn SAGD production well to monitor the temperature profile continuously during startup and p the well in cases where the well outflow velocity is less than that required to continuously transport and unload liquids from the well.ï¿½ Sub le in the well in cases where the well outflow velocity is less than that required to continuously transport and unload liquids from the well. Su pleted with production tubing landed near the lowest perforated interval to act as a velocity string and lift produced water to surface. This co ater. Upon well start up oil samples are taken at the surface over a short period of time. These samples are analysed to determine tracer pr manent downhole metering. The meter contains only three sensors but is capable of direct multiphase-flow-rate and cut measurements witho

all the data needed to monitor process parameters and fluid production under the assumption that deviation from any target would be detec low oil flows? This paper explores this question by analyzing production logs from wells with water cuts as high as 99%. The horizontal wel imited information is available concerning Wara reservoir heterogeneity. Shut-in of all Wara producers provided an â€œonce-in-a-lifetime op oil rate of 1 800 bbl/d. Oil production quickly dropped to 1 000 bbl/d and gradually declined to 200 bbl/d. During this period the gas oil ratio ( gin of investments to optimize wells/fields production and gave production/reservoir engineers a good hand in obtaining better data for dec rval pressure-transient testing (IPTT) and microfracturing. Because of the complex tool strings and the elaborate operational aspects involv hnique allowing individual layer pressures or gas/oil ratios (GOR) to be monitored continuously during production. The technique employs voir. Integration of the microseismic data with volumetric strain inverted from the measured surface deformation indicates a discrete deform these systems to monitor production rates and changes over time. The optic fiber has been installed on the periphery of the sand-screen essed these constraints. Instead of individual gauges on mandrels digital sensors were miniaturized and distributed along a single spoolab ones using conventional openhole logs. This paper describes a methodology of recognizing the different types of thief zones in the Mauddu

y of the reserves estimates. With current Digital Oilfield technology it is possible to measure production volumes at the well level and at inte gging have addressed these fundamental requirements of measurement with multiple probe technology that differentiate between Oil Holdup

acquisition which is extremely instrumental to take an immediate decision. The technology is well known in the industry and already proven methods have been limited by the injection volume and environmental effects. Direct spatial measurement of the injected sea water front w nd proven in other geographical areas is being implemented first time in UAE. The EMI technology is being deployed in southern part of a c influence of a high quality background geologic model in constraining the interwell results and providing a higher resolution image of the on from CBM reservoirs is low perhaps 50-100 mcf/day. Various completion methods are being evaluated and new technologies are being de l layers but the nature and extent of cleating often remains poorly defined from these logs and by using standard log evaluation methods. A d to conventional clastic rock fracture stimulation. In 2003 the concept of indirect fracturing was introduced to significantly increase Coalbed me challenges faced in horizontal completions. Inefficient fracture initiation is the largest reoccurring problem encountered when completing n of high stiffness significant elastic anisotropy and coupled elastic property and horizontal stress development in tight gas shale reservoi .ï¿½ Currently energy that can be delivered to the coalface of these dry CBM wells has been limited by the friction pressure through (CT). E aracterized and the perforation placement customized to account for reservoir changes along the wellbore.ï¿½ In most cases evaluation is l ults guide the design of horizontal wells to control hydraulic fracture directions and intensities. Conventional logs and cores have been used ation of steam within the reservoir and the resulting flow of crude. SAGD recovery methods require tremendous amounts of steam in order neral readership of recent advances in various areas of petroleum engineering. Introduction Annual natural-gas production from coalbedoved to an aggressive horizontal drilling and completion program.ï¿½ Additionally in an effort to increase the productivity of existing wells a n the flux through the thin wormholes can be so high that high pressure gradient occurs. Therefore the optimized wormhole geometry shoul h no anticipated fines production low GOR low temperature low bubble point pressure and high API gravity. All new installations were car

nd operating limitations that eliminate it from consideration under certain operating condition. However all the conventional artificial lift syste n of horizontal drilling allowed achievement of the above tasks.ï¿½ Horizontal completions resulted in not only enhancement of individual w ion rates of each well to more than 1 MMm3/D ï¿½increased the associated sand production risk and led to the need for evaluatingï¿½ the mpletions and have a unique design feature in the valves that allows a theoretically unlimited number of valves to be placed in a single well oductive horizons are sands from the lower Sarmatian (Basal Sarmatian). The facies variation can be seen both vertically and horizontally o -critical velocities are often encountered in low productivity gas wells that produce liquids whether the wellbore liquids are produced directly -critical velocities are often encountered in low productivity gas wells that produce liquids whether the wellbore liquids are produced directly hrough the well architecture.ï¿½ To this end a tri-lateral MRC well with a mother bore and two laterals has been recently drilled in this reser

em coupled with pressure and temperature monitoring system. The SC provides isolation and down hole control of commingled production allow production and injection control over multiple zones have become available. The central idea is that downhole control may be used t advanced system coupled with a pressure- and temperature-monitoring system. SC provides isolation and downhole control of commingled

ults of a numerical study performed to determine the production performance of dual opposed laterals compared to horizontal wells. With a andard equipment and techniques. The concept was developed after identifying the opportunity to optimize operations in wells where the ab orical source of statistical bias. The analysis uses Kaplan-Meier (KM) (Kaplan and Meier 1958) and Cox proportional hazards (CPHs) (Cox n used successfully to increase production from the Khuff carbonates. Although acid fracture treatments create significant conductivity enh n based on the reservoir characterization. Well performance had proven to be economic in this Jurassic marine sandstone without hydrauli

completion techniques have been tried since the start of the play with different degrees of success. In June of 2005 a new technique was in based on net pressure control. This can be achieved using low-viscosity fluids such as viscoelastic systems oil-based systems or reduced maximize well productivity. Alternating stages of polymer pad with diesel emulsified acid for deeper penetration and in-situ gelled acid a poly to be reliable for successful placement of 10/14-mesh size Intermediate Strength Proppants (ISP) at concentration up to 1000 kgPA and hig g nonionic to amphoteric microemulsion and oil-wetting components. Determining the best additive for a specific reservoir is not a simple ions on fracture geometry and proppant placement (Smith et al. 2001). To expand on this topic we consider the combined effects of modulu zone commingled completions the selection of fluids and additives to maximize hydraulic fracture effective length and conductivity and flui ore complex chemical make up than before. Therefore the usable lifetime of the recycled water is shortened or requires expensive cleaning elopment of a basin.ï¿½ Numerous completion strategies (Limited Entry high rate limited entry and various Pin-point Stimulation Techniqu interest. This paper describes a novel and economical frac-and-pack technique which consists of pumping a sand plug with the downhole ng fracturing fluid systems to control fracture net pressure development that combined is used to mitigate fracture height growth. The meth to stimulate long openhole sections effectively due to poor acid distribution especially in reservoirs with high permeability streaks that requir sm is understood and the appropriate fluids are selected then stimulating producer wells with high water cuts can be a rewarding operatio ns where oil and gas are found in tight formations fracture stimulation needs to be added to the equation. Conventional multistage fracturing

be drilled as open-hole horizontal completions. Nonetheless due to the highly complex nature of the Khuff carbonate reservoir some wells

GS-3A was a water bearing sand. Most of the candidate wells were primarily in an area of the reservoir that had experienced poor recovery of well and reservoir completion under boundary-dominated flow conditions has been developed and utilized in this study. The mathematic

West Siberia. Adding the difference in the maturity of the fields with significantly depleted reservoirs high asphaltene and paraffin oil conten

r of valves to be placed in a single well without incremental reductions to the ID thus allowing normal cementing operations. A control line is paper will discuss the theoretical and experimental study that was conducted to assess the viability of the cemented sliding sleeve concept ate model for fracture design which takes into account processes in the plastic zone for the special case of soft rock that is a cohesionless has been developed for use in high permeability reservoirs and successfully pumped in the Gulf of Mexico.ï¿½The fluid exhibits enhanced

rature (BHST) of 190oF.ï¿½ Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive

tends to produce oil with asphaltene content when the flowing bottomhole pressure is drawn below the Asphalting Onset Pressure (AOP). A estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 20 w wells are completed.ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ This paper discusses the completion design methodology execution and results from two o

nverted fracture azimuths. Furthermore if the positions of the injection point and the receiver array are not known accurately and the veloci

acturing or about the dependence of this texture on the acidizing conditions. To study this important aspect of the acid-fracturing process w e a reliable estimate of height is known. This is evident for 2D model which requires a direct knowledge of the height but also for p3D model the transportation of radioactive materials have impacted the application of this technology in international markets. This paper will describ

ge and is additionally hampered by the lack of or ambiguity in the reservoir and production data. This is particularly true for the Yamburg ude lower than the Darcy permeability measured at single phase low-rate conditions. This is particularly true if a liquid phase is also flowing ver the situation is still unclear in high permeability formations because the formation fluid can invade the tip zone where the pressure dro pH borate gel was pumped in stages to reduce leak-off and maintain the bottomhole pressure at values greater than the fracturing pressur vertically fractured wells in closed rectangular bounded reservoirs and their corresponding pseudo-steady state shape factors under bounda entation was supported by differences in the microseismic-signal characteristics and the treatment-injection data. This difference in fracture a few days of production or will continue at a given rate during the well's life is a key issue when selecting an appropriate completion metho ds to fracture reopening along the initial fracture plane (called in-plane frac hereafter). A dual-frac PKN model is developed to predict the gr damages in elastoviscoplastic medium as well as the effect of inhomogenity of porous media properties on fracture propagation. After hydra e proppant are used. Although the latter could lead to more conductive fractures they could also bridge at the wellbore impeding both later

ngth and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit. The main results presented ion campaign started with three water injector wells. The initial results were not as expected i.e. after pumping 1000 bbls of treated seawat veform Dispersion Analysis (open hole and cased hole) which main objectives consisted on the generation of a horizontal stress map for the ons. New modeling results are presented that quantify these and other effects of offsets by using a coupled 2D hydraulic fracture model. Of equipment compressors and pipelines and the ancillary equipment they require. An estimated 60 auto gas lift systems have been installed n the experience and field performance open-hole gravel packing has become the preferred option. The techniques used in completing thes the operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings more efficien the operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings more efficien applying drawdown to the formation? Will the remaining filtercake impair well productivity? The paper presents the case of a gas producin ation procedures and â€œlessons learned after installation of the fully hydraulic tubing-retrievable advance completion system with digital p s and interrogates more optimally both rock and fluid properties in the reservoir hence delaying early water breakthrough. This early water anaging production from multilateral wells horizontal wells with multiple zones and wells with heterogeneous reservoirs using a single wellb s and â€œlessons learned after installation of the fully hydraulic tubing-retrievable advanced completion system with digital permanent dow ion process are computationally very expensive. We suggest that simple reactive control techniques triggered by permanently installed do ere monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure

efore it is critical to combine high resolution formation evaluation logs and formation tests to predict the well performance prior to the produ es. The study presented in this paper characterizes the geomechanic behavior of a field in which sanding problems are expected after depl ind set in the industry is that acid dissolves the perforation debris and creates wormholes that bypass the perforating and other near wellbo eria. It combines the use of a formation isolation valve (FIV) to keep damaging completion fluid off the formation immediately after perforatio ny Petronas Carigali Sdn Bhd. Since the beginning of Resak Field production coiled tubing has been used to perforate numbers of infill w ctivity of these wells was evaluated using nodal analysis techniques coupled with perforating performance simulations. The quality and amo e deeper lower-permeability reservoirs have been developed more recently. The lower-permeability reservoirs are generally of lower poros frequently completed with multiple tubing strings (up to four in some cases) sensor lines control lines or other hardware that can be dama that creates clean low skin perforationsï¿½and allows the well to be produced at commercial rates while waiting for the multipurpose barg tions if without flowing on surface in sufficient time. The reasons are that (a) the flow rate after an UBP continuously varies during the surge CCL) and the second run for the actual perforation. The underbalanced condition calculated based on wellbore fluid displacement is often de shed analytical tool to help them understand post-perforating behavior of perforators. They have to rely on their own experiences and previo

dard (conventional) charge and three different designs of reactive liner charges. Among all charges the only difference of note was the desi ment in which the perforating job is executed and what happens to the perforations after shooting and before they are used for production or hase flow meters (MPFM) helped in getting better results to allow faster decision making. In one of the challenging areas in Ghawar field wh key component of Brazilâ€™s drive to achieve petroleum self sufficiency by 2006. Because of the challenges presented by the heavy oil a d control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high-rate long-life com hinah Hazmiyah Nisalah and Umm Jurf). The Trend runs approximately 30 km east to west and 50 km north to south. Production in Hawta n used to complete the wells. The third well A1ST1BP1 was completed using the same techniques as were used successfully on the first om production onset and as such the well was completed with sand-control measures in place. After about ten years of production a signifi

ure. ï¿½Hence it is imperative that the filter cake be removed uniformly to ensure lower drawdown pressure and even flow distribution throu es of the well from drilling the reservoir through to the gravel pack itself and subsequent completion. An integrated approach was adopted fo

and open-hole and large tubular size to minimize friction losses. Until now standard open-hole gravel packing was the common completion and high concentrations of gravel in conjunction with alternative path screens which mitigate problems caused by unpredicted downhole ev avel-pack process the industry still lacks a tool that accurately models the complete process and aids in successfully designing these jobs. tive shale streaks they require synthetic/oil-based drilling fluids (S/OB). Considering that the openhole gravel packing in the industry deals ration tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the conn ation tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the conne duction in the horizontal wells. This was offered as an alternative to mechanical sand control in the long horizontal wells due to traverse sev tic sandstone reservoir with a top and bottom sealing shale. The reservoir pressure is low and it contains heavy and viscous oil of 19ï¿½ AP ution that involve many field-proven technologies such as reservoir characterization perforating coiled-tubing intervention matrix acidizing

ompletion and sand management strategy for more than 400 wells in the field. It was decided to apply a particular systematical approach te ary sand prevention will mean unwarranted reduction in productivity. Reliable sanding prediction analysis thus provides a basis for designs ta and field data) were integrated to generate a Mechanical Earth Model (MEM). This model provided the descriptions of the rock strengths ones obtained from downhole and outcrop. The tests were performed under simulated in-situ effective stresses and drawdown conditions. W

transport of the sand out of the perforations and up to the surface being the second step. Existing sand production prediction models hav e data required for the study include: 1) in-situ stresses including magnitude and orientation and formation pressure 2) mechanical and pe stic properties of the treating fluids. This is because of the ability of surfactant monomers to associate and form rod-shaped micellar structu n. In our tests the injection rate into the fracture is much higher than in many previous tests and the fluid loss flux is controlled to match fie ir temperature. Yet another concern in acid fracturing in long carbonate intervals is attaining the necessary diversion to ensure that multiple and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid a polymer-based system are used to control exc r and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid a polymer-based system are used to control exc methods of placement. Pre- and post-job production logs acquired in five wells provided analysis of changes in the production profiles. In o is limestone is atypical because of its textureâ€”a granular aggregation of carbonate particles poor cementation and a moderate-to-low ro this is exacerbated by the relatively small injection rate imposed by the use of coiled tubing (CT). To make matters worse formation damag acid on the surface. A series of effective methodologies for the stimulation of offshore multiï¿½layer sandstone oil reservoirs was implement

ex. Acid placement and diversion need to be carefully designed and optimized to effectively stimulate the wells by reducing the skin factor t acidizing to alleviate these two problems. Though organic acids provide the benefit of retardation and low corrosivity their low dissolving ca

one Darcy. At different times in the past attempts were made to hydraulically fracture one or more of the sands using a variety of different ance of complete zone coverage without proper diversion. Therefore diversion is recommended in all treatments especially in extended rea om the water flood or the injection scheme is not optimized.ï¿½ A consequence of reservoir pressure depletion is the increase in filtrate lea rties on stimulation treatments.ï¿½ This study primarily explores the influence of pore scale heterogeneities on stimulation treatments.ï¿½ S erstanding these basic differences is essential to a successful restimulation. In the past candidate selection methodology has focused on u common practice has been to use oil-based fluids. However fluids of this nature can have detrimental effects on gas zones with low reserv oduction rates called for different options. One of those options was the recently developed CO2 viscoelastic surfactant (VES) fluid system. sed on comprehensive data. This process includes the current service standard of design execution and evaluation but goes far beyond

n a matrix treatment flows into high permeability sections and/ or high water saturation thief zones" resulting in higher water cut due to the o by management. In response the reliability of these tools and their interpretations for determining the existence of poor behind casing ceme or both liquid and gas wells. Approximate solutions for the early-time and late-time pressure behavior are derived from the rigorous solution ensive test program including flowing and static pressure surveys modified isochronal test two buildup tests and FloScan Imager (FSI) lo nsient solutions that use rate-normalized-pressures and superposition-in-time to evaluate response accordingly to the fracture flow periods ng Company (GNPOC) in Sudan has several wells that commingle production from the Aradabia Bentiu-2 and Bentiu-3 formations. These lling problems associated with high mud losses when the well encounters fractures often prevent well penetration of the total formation thic e propagation is not diffusive but it propagates like a wave with a finite speed. If we have a pressure gauge at a distance we will only start the pressure and hence the deterioration in well deliverability can be continuously and cost effectively monitored.ï¿½ This paper illustrates of all these methods revealing and discussing specific features associated with the use of each method in a unified manner. The algorithm

t analysis is a recommended technique for fracture evaluation but its use is still not well understood. Analysis of pressure transient data pr ed reservoirs is the presence of vertical heterogeneity and varying layer flow properties. Wireline formation testers have been commonly us ngle or multiple flow periods induced using a downhole pump followed by a pressure buildup. The objectives of a MiniDST are sampling es ertainty on oil rates. To solve such metering challenges with a large majority of their wells operating above 95% gas fraction under metering es the challenges and potential benefits of deployment in line multiphase flowmeters in the difficult operating environment of Northern Siber

can lead to unforeseen errors in the field. Recent experience shows that in certain conditions the various types of multiphase flowmeters re by many operation companies worldwide. However in artic environmental conditions like those of Yamburgskoe gas-condensate field with r the measurement of gas flow rates particularly those of wet gas. A new interpretation is described that allows a traditional multiphase flow qualify the multiphase meters results before use and considered parallel testing with conventional separators to allow fair comparison of res

d on past experience or special cases which could be several years old. A split in terms of naming is even commonly accepted in the multip btained by reconciliation of the analytical well test model with the numerical full-field model. We present a more complete approach where a ctured wells. The purpose of this paper is to demonstrate the application of the production data" formulation of the Î²-derivative function (i.e test interpretation. In contrast measurements from new pressure gauge systems can now provide the stability and resolution required to ch ts but nonetheless record high signal-to-noise ratio responses. These field experiments have demonstrated that the streaming potentials ari

efects in the cement sheath. It is therefore of critical importance to understand and characterize fluids and solids across the caprock. This h leak-off test data a borehole wall electrical image and dipole sonic log data in the CO2 injector CRC-1 are used to constrain principal horiz or to the surface. In this paper a risk-based approach is proposed for well integrity and confinement performance management. The approa ls. A recent trend of the industry is the integration of sub-surface and surface simulators to have a better representation of the fluid producti n in these situations is one of few means of assessing an injection site and testing various scenarios. The accurate description of physics an standing of the processes involved in underground CO2 storage evaluate applicable monitoring techniques and provide operational experie e; Enhanced Oil Recovery (EOR) Enhanced Coal Bed Methane Recovery (ECBM) Enhanced Gas Recovery (EGR) Food processing app to properly manage containment performance and leakage-incurred risks. The analysis starts with the construction and the calibration of a

at 8560 m / 28084 ft measured depth. The well includes three hydraulically operated flow valves which are used as down hole chokes to y is greater than 11.6ppg. This resultant high overbalance and other issues such as hole cleaning complex directional profile ECD manage

have been waterflooded and only five have experienced CO2 injection. An ongoing US Department of Energy project is studying the use o al occurrences of natural CO2 that have been discovered during exploration of oil fields. The CO2 that has been naturally trapped in carbona nated sequences; many thin high-quality sands have been overlooked. These sections can now be discerned using microresistivity measu reservoirs have been producing with vertical wells.ï¿½This paper presents a practical strategy of rejuvenating gas-condensate reservoir p s in the process specific to the selected area and to understand the effects on the recovery factor in these reservoirs which have previously wells were required to be treated to shut-off source of the gas breakthrough in order to restore oil production. Challenges faced in shutting of

sure formation and a micro-fine cement system for sealing off the water entries. Based on this study a cost-effective chemical treatment me ff case history of an oil producer that has shown according to the production data an increasing water production figures. The nature of wat ms. As a result most exploration and production companies have learned to manage water production up to a tolerable limit which is depen set in open hole. This paper shows that this type of water shut-off in open hole is feasilble and very effective. This will open the doors to ap meability modifiers to control water production in these completions has traditionally produced inconsistent results. This method can fail to c mentally friendly manner. Some fields in Saudi Arabia use water injection for reservoir pressure maintenance which makes water productio ucer with 2 440 ft of reservoir contact was drilled and completed in November 2000. The last well production profile was determined by a F e near-wellbore regions and production tubulars. Besides hydrocarbon solids other production hindrance elements include wellbore fluid lo tion and droplet size as a function of flow patterns and were used in characterization of the flow and performance evaluation of an oil/wate sing tap water and mineral oil with superficial velocities ranging from 0.025 to 1.75 m/s. The experimental results include observations of flo r a static problem.ï¿½ They cannot account for the dynamic changes that occur in time in the connected system of reservoirs and wellbore g into account surface facility constraints that could lead to unrealistic approximations. Restrictions in compression power or pump capacity deposits having varying fluid characteristics. To reduce the risk we have adopted a systematic approach to evaluate the potential impact of w assurance aspects of a live waxy crude oil from offshore West Africa is investigated. Experimental work included determination of the wax e safety of equipment and personnel. The conventional procedure to evaluate the CO2 content in a hydrocarbon bearing formation is to tak osition. Examples from two such reservoirs one from the Browse Basin in Australia and the other from the Malay Basin in Malaysia will be d

clines and changes in the specific gravity of the reservoir gas as reservoir pressure declines. No correlations based solely on field data hav oil-gas ratio exists in the petroleum literature. Alternatively oil-gas ratio (needed for material balance and reservoir simulation calculations of d laboratory analyses are consistent; asphaltenes exist in these crude oils in nanoaggregates. The corresponding asphaltene gradients prov mited lateral extent and hard to correlate. Several layers are potential pay zones and may contain oil or gas. However water zones and seco ance in the oil field. Furthermore different depletion/development levels and injection and production processes of different reservoir zones conditions of the downhole environment limit the DFA-tool measurements to only a small subset of the fluid properties provided by a laborat n simplifying assumptions in terms of the compositions of flowing fluid phases. These models characteristically assume single-component p id phases detection saturation pressure as well WBM & OBM filtrate differentiation and pH which is key for real time contamination monito

nd sampling purity. One case history demonstrates confirming remaining oil saturation. Conventional open hole and Nuclear Magnetic Reso an economically make or break a project. Traditionally operators have relied on well tests to determine H2S levels. In addition to the expens

rements. Our analyses of many samples show that a good correspondence exists between the PVT-derived gradient and that obtained fro e provided valuable insights into compositional grading but each analytical method relies on different fluid traits and has different implication d in the zones of interest is extremely challenging especially when it is associated with overpressured low porosity shaly sandstone reservo s uniform and free of noticeable impermeable layers. A resistivity log showed an approximate oil/water contact (OWC). Wireline pressure tes ation of in-situ fluid type can be difficult. There is also mounting evidence for the presence of compositional gradients in the hydrocarbon co density fluid contacts and layer connectivity in exploration settings. This information is today supplemented by downhole fluid analysis (DFA sure/volume/temperature (PVT) properties. A technique of monitoring sample contamination from OBM filtrate uses optical means to monito

eservoirs which are not in equilibrium but still undergoing for instance a flux of the light components that diffuse. Formation testers supply m measurement and the oil-based mud (OBM) filtrate have been taken into account. Recently an algorithm called the fluid-comparison algo nditions of the downhole environment limit the DFA tools to measuring just a small subset of the fluid properties provided by a laboratory. Ne

ems the paper gives full details for a 3-phase oil/gas/water system.ï¿½ Any number of hydrocarbon components may be present and water nder the actual production conditions is necessary. This study is an attempt to investigate the effect of water content pressure and tempe

es and requires analytical methods to back-calculate the measured properties to approximate the uncontaminated reservoir fluid. The ability ate sampling has always been the trickiest because even little traces of contamination may render the sample useless. Besides that the too pted for several years now by the industry. Their use in permanent or well testing applications has been growing rapidly. In many cases mu ant benefits to the ease of deployment especially in harsh regions such as the one encountered in Northern Siberia. One of the past challe s stimulation fluids. The advantage for chelating agents is they can complex with calcite and form water-soluble products. Different mathem on damage make any stimulation a challenging and detailed process. Water injection is one the most commonly used exploitation method actions carried out under controlled conditions as well as within the pore space of sandstone cores. In the controlled reactions solutions of c mmercial halite inhibitors are only effective at high concentrations (250 â€“ 5 000 ppm). Therefore a more efficient salt inhibitor would need

. Core-flow tests were conducted to generate naphthenate-soap particles and to determine the permeability impairment caused by subsequ atrix by de-bonding the cohesive inter-granular cementation leading to the creation of a zone of reduced strength called the damage zone. age and maximizing productivity though the mechanism by which it does so is still not very well understood. Underbalance perforating also scale precipitation prevention no successful attempt to enhance scale prevention in conjunction with a stimulation treatment has been docu antly to be effective in the typical Uinta Basin gas well environment: low permeability (<0.1 md) multi-layered commingled gas reservoirs. T ptimise reservoir and asset performance.ï¿½They provide the ability to independently control each valve individually from the surface to m eservoir and/or wellbore under varying conditions resulting into Strontium Sulfate Scale formation in downhole equipment. While CaCO3 sca positions has revealed that this is due to much lower sulphate concentrations in the produced brine mix than would be expected purely fro ns within a reservoir is not possible unless they are separated by zero permeability streaks or sealing faults. The proposed approach isolate atch by validating fracture lineaments and then optimize Injection-Production Ratio (IPR). This study involves the conversion of a finite differ operation periods be they historical (i.e. history-matching phase) immediate (i.e. on-going) or in the future (i.e. prediction phase).ï¿½ This t ment. This paper presents the results of numerical investigation into the water and gas production problems under different reservoir hetero e number of wells in AIB (approximately 2000 active wells) and the fact 95% of data is manually captured made the implementation of autom and modeling tools to measure formation properties at the wells and between wells; this paper discusses the WI pilot. Among the novel tec ous teamsâ€™ â€œkey performance indicators (KPIs) to align injection and production allowables with sound reservoir management princip rical submersible pumps (ESPs) became an alternative to handle higher production volumes (Ramos and Rojas 2001). More recently top-d ally greater than 2 000 cp. For the above reasons it is important to decrease the pressure of the reservoirs with primary production techniqu ite core holder packed with crushed limestone premixed with crude oil and water effects of operational parameters like heating time and wa D) process geared to increase the recovery efficiency of heavy oil within the Faja reservoirs. The process is based on a repetitive pattern us isplacement motor with Silicate mud. Many of these wells faced hole cleaning challenges leading to pack off â€“excessive back reaming an distribution of formation properties which is critical for management of the current pilot project. This study presents several aspects of an i lly isolates a small part of the formation from the hydrostatic pressure while the probe enables communication between the tool and format

n in less than a year. Horizontal wells were considered as best option for improving the productivity in this small to medium sized heavy oil

trast with the strong mobility and low viscosity of the formation water makes the problem even more pronounced. To temporarily plug the w

nezuela has pone of the largest reserve of HO and EHO with more than currently 1.5 trillion of oil in place. Different set of technologies and

ated with the fluid-formation interactions. This paper presents the results of a laboratory investigation of a single-stage sandstone acidizing construction of a pilot gas processing plant (UKPG) and startup of a pilot gas and condensate production. The initial formation evaluation in

ate systems (at high pressure and temperature) considering impact of fluid characterization effects. Under isothermal conditions and in the a

ven to the degree that near wellbore proppant transport is compromised and the treatment may screenout.ï¿½ On the other hand a Ti or Z st also be considered to fully appreciate the challenges imposed by acid fracturing operations. The industry has successfully tried different

s where intervention is very expensive. The down hole gauge system is connected from wellsite to gas plant through SCADA which allows to both injector and producer wells. The post treatment results have been excellent with an average increase in Productivity Index (PI) of grea emical mechanisms the new sandstone acidizing system (1) reduces the multiple stages in traditional sandstone acidizing to one stage; (2 samples were studied using coreflood and slurry reactor experiments. Linear coreflood test data show dramatic increases in the formation pant pack damage lengthy clean up times and high friction pressures. In recent times polymer-free viscoelastic surfactant-based (VES) flu are also investigated for long-term prevention of water blocks. Contact angle and air-brine imbibition tests are conducted to determine we d pressures current practice involves flashing the single phase water sample analyzing the flashed water and gas phases and then using

mulation is usually required. Conventional OH or cemented and perforated completion alternatives have had various operational and logistic

udies from North America and the Middle East show applications of this process in two different environments one mature and one emergi ques were tested on the other. A general east-west orientation of planar fracture geometry was found with a maximum fracture event length g of sidetracks and the knowledge of hydraulic fracture orientation of the water injectors well that are fractured by the mere injection process onments to improve the understanding of the induced fracture network and to go beyond the simple assumption of a symmetric bi-wing frac uction in produced gas. An integrated engineering process of reservoir and production analyses was used to evaluate the stimulation treatm

ave contributed to many technological improvements in the multistage completion process allowing sequentially executing several fracturing by inter-granular small inter-granular and intra-granular dissolved pore. The porosity generally ranges from 4âˆ’10%with permeability range hrough primary or secondary methods. Without different techniques of drilling and completion most of the oil in the low permeability interval and engineering data and interpretation. The stacked multi-pay tight gas sandstone reservoirs and their overpressured conditions were mo models for each well.ï¿½ Tools for the validation of the SWM such as production logs pressure measurements and formation micro-image major challenges of modeling the field are reservoir upscaling and appropriate representation of the hydraulic fractures. A streamline-based dvances in logging technology and production optimization modeling the thinly laminated gas bearing permeable sands can be discerned fr

deep carbonate reservoirs in Kuwait. In the process of exploration and development of these particular reservoirs oil-based mud has been o heavy WFT programs and operation issues and at the same time maintain data quality and achieve even better data quality to fully satis lable which characterize the properties of a created hydraulic fracture from both the predictive and evaluative standpoint. This is important i measurements were taken in the Wamsutter Field Wyoming. The observations presented in this case study serve as a model for what can

of supercharging that can limit the dataâ€™s utility or in some cases invalidate the results. New generation formation testing tools that e ciplinary reservoir modeling and simulation effort. The subsequent development was based on oriented waterflooding patterns and massive h Louisiana. Horizontal wells are commonly two to four times more expensive to drill and complete than offset vertical wells yet they are the n based on an integral analysis of the structural seismic and borehole data. First of all this is seismic profiling on the regular orthogonal grid

n water-base mud (WBM) filtrate and connate water thereby avoiding any negative impact on the oil initially in place (OIIP) calculation and o

mulation is found in multiple layers of late cretaceous deposits. The formations are heterogeneous unconsolidated with higher viscosity and

s and other factors. When nominal factors are involved it may be practical for decision-makers to rely on intuition and experience to guide judgment from individual experts and group of experts. A judgment elicitation workflow includes interviewing of experts comparing subjecti nd better quality real time log information to enable the Drilling team to make quick decisions on were to place the well within the structure. formation and methods exist in the literature to derive primary drainage capillary pressure data from the NMR log. In carbonates however i el requires rescaling the data and that may introduce significant uncertainties. To address these limitations we explored the use of electrod orosity of a grainstone and responsible for an increase of one order of magnitude in permeability. The dissolution is observed by patchy fea e images in 9 wells of the study area present a detailed insight into the different architectural elements of the sedimentary environment envi can be achieved. This paper describes a methodology that was used to generate a depositional model in the Lower to Upper Triassic rese rmation water and a hydrocarbon composition in four groups: methane (C1) ethane to pentane (C2â€“5) hexane and heavier hydrocarbon mited lateral extent and hard to correlate. Several layers are potential pay zones and may contain oil or gas. ï¿½However water zones and hus overlooking or under-estimating diagenetic features occurring in micro scale.ï¿½ It becomes imperative to look at both micro and macro onceptual geological model in the presence of a complex structure a real challenge. The objective of the study was thus to characterize the esistivity- and neutron-based sensors also means that key measurements are being made at the same depth at the same time and on a sim ging-While-Drilling (LWD) tool has been developed using innovative technology to provide a complete suite of formation evaluation measu

en hole logs using the commonly used empirical and theoretical shaly sand models. This technique is based on development of water satu m open hole logs using the commonly used empirical and theoretical shaly sand models. This technique is based on development of water T2 distributions and capillary pressure curves in carbonates. Additional enhancements have been made to this workflow to include estimates 26% with typical values being from 22% to 24% substantially better than the interbedded carbonate units with typical value of 12% to 15%. P ability from porosity alone yields scatter of a factor of 700.ï¿½ Rock typing using only conventional logs was unsatisfactory due to the poor p valuating the lithology the geometry and the net producible fraction of these reservoirs: We demonstrate that the partitioning of NMR T2 d

oint exists or when the nearby thick sand-shale is not representative of the sand-shale in the laminations. In producing fields that have und nducted to study relationships between true formation resistivity and LWD tool responses. In situations where the time-consuming resistivity ctures and conductive faults is of critical importance for the completion decisions in this field. Whole cores enable a comprehensive descrip unconsolidated or only weakly cemented. Experience has shown when sampling fluids from such formations sand grains and solids tend t s to be reconciled: in an example case it was observed that a large number of fractures seen on the images were absent in the cores. This ent study utilizes twenty two well data in the crestal part of the Khafji structure to generate a semi-regional facies log which is turn up-scaled

use of the stationarity and ergodicity assumptions and the multiscale of subsurface heterogeneities. This often causes incorrect frequency s on testing and sampling calculate net pay thickness and uncertainty range. The evaluation is complex because of bed geometry and lithol of a high-resolution antenna 6 in. or 15 cm. Within that distance NMR tools will cumulatively measure all layers of shales and all layers of s

sely made equal to the drillerâ€™s depth which is a static pipe length measurement made by tape at the surface. There is almost always a

ow over time. The effect of fractures on reservoir sweep and on problems such as early water breakthrough is largely controlled by fracture situ stresses with depth is estimated using logs with elastic parameters as an essential input.ï¿½ The focus of this work is on the prediction imum and minimum horizontal stress magnitudes by use of cross-dipole dispersions. Borehole sonic data for the case study presented in th n estimates of the formation and well completion properties such as effective permeability radial flow steady state damage /stimulation skin n estimates of the formation and well completion properties such as effective permeability radial flow steady state damage /stimulation skin n estimates of the formation and well completion properties such as effective permeability radial flow steady state damage /stimulation skin mainly has been on the basis of 3D-/2D-seismic data image logs cores and thin sections. The Greater Burgan field consists of the Burga roducing well. This workflow is applied on well NWO-1 in the Northwest October Concession in the Gulf of Suez area over the carbonate re Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the fo es on the characterization of different types of fractures and faults identified on high-resolution image logs recorded in this field. The objecti irst project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach

oil displacement by injected water in all the permeable zones was conducted in a carbonate reservoir in Saudi Arabia. The field experimen e hydrocarbon discovery the production facilities required to produce the resource and the predicted ultimate recovery. Recent advances in xtensive evaluation program was undertaken using new generation sonic logs WFT-multi-probe interval pressure transient testing (IPTT) a

es of the rock. This peculiar characteristic of the NMR response in these low porosity reservoirs with complex and variable lithology becom n. However these logs are not able to capture variations in the hydrocarbon column to allow the operator to ensure that all representative flu e effects between LWD and Wireline logs. NMR measurements of porosity bound fluid volume pore size distribution and direct fluid identi g at reasonable" logging speeds so full polarization of long T1 fluids is rarely achieved. Additionally the inversion process creates interdepe his summary of the state of the art in nuclear-magnetic-resonance (NMR) well-logging technology is aimed at nonspecialists who would like reservoir bed thickness particularly in the Castillo Formation makes layer-by-layer correlation difficult. Several other factors add to the com g gas oil and water and cover more cross sectional areas of a wellbore for enhanced characterization of multiphase flow regimes. The new

d (2) how to cope with the uncertainty of the results. An in-house multiphase reservoir simulator is used for the simulation of the formation r normally enhanced by fractures in the upper Mishrif layers as they act as the main permeability conduit for the main storage below. The se

erent fluid traits and has its own limitations. With systematic integration of different methods the synergy delivers a more accurate characte wn to be colloidally suspended in the crude oil in agreement with recent laboratory results and settle preferentially lower in the oil column in obtain estimates of the formation and well completion properties such as effective permeability radial flow steady state damage /stimulation s been based on SCAL. PND logging in producing wells has generally confirmed forecast saturations1 and only slight adjustments to the ini l effects on well performance. Moreover the limited lateral extent of these relatively tight gas sands leads to extremely depleted reservoirs a

fect well completion and reservoir management decisions. A set of wireline formation evaluation tools were used for microfracturing (stress re transient tests acquired with a single or multiple probe formation tester. The solution is obtained by successive integral transforms to the then considered drilling reach and anti-collision limitations and finally had the appropriate facilities and regional evacuation constraints impo on of the project during the appraisal phase.ï¿½ The context of this case study is the appraisal phase in the development of two fields with ial benefits and challenges are discussed and an assessment is presented of the life-cycle economics leading to final recommendation. Va d in this and its companion paper1 (SPE 104034) looked at the technical and business opportunities for two main re-development compone d gaining consolidation with depth.ï¿½ Almost all intervals are produced in non-commingled production mode with dual string arrangements ers involves very thin and sinuous targets. These targets are the channel sand stringers and contain a substantial amount of hydrocarbons. ocate a power water injector in the southwestern flank of the field to support pressures during production from offset wells.ï¿½ Seismic impe re installed on successful test candidates in phases one and two. Phase three involved expanding the project to test the remaining 39 gas ational method incorporates cross-disciplinary software (geomodeling and seismic packages) as well as reservoir production completion a anifold pressures and the need for artificial lifting technologies but potentially may also lead to the necessity of flaring associated gas if no a intelligent completion technology an Integrated Asset Model (IAM) was implemented. This model was divided in two sections: the first secti pletely decoupled from surface and subsurface simulators. The framework has a clearly defined interface for simulators and external FM alg and the availability of lift gas.ï¿½ In traditional gas lift optimization projects a gathering network model is used to calculate the optimal amo is surprisingly isolated from the surrounding aquifers. Prior to its premature shut-in oil production reached 5000 bopd. However a drastic d ves. The objectives of this paper are to present (i) how using numerical simulation to support and improve the strategies for production enha

tual field operation. A WAG cycle optimization workflow for the Snorre field has been created to demonstrate the advantages of using the S manifold and then tied back via a 60km flow line and riser system. The reservoir is in severe decline with field production well below the o g into account surface facility constraints that could lead to unrealistic approximations. Restrictions in compression power or pump capacity apid execution of integrated studies are cluster computing and unique modular workflows that are based on stochastic concepts. Clusters h 9 5/8-in casing with zones separated by packers and produced commingled through sliding sleeve doors (SSDs). In the past few years mor

ions Production Optimization and de-bottlenecking of the existing production system was found to be the best cost effective solution.ï¿½ ï¿ en built for a robust development program. Horizontal wells were utilized to improve oil recovery in shaly sands and to reduce water coning nostics to systematically identify layer-by-layer key parameters affecting productivity and to optimize performance based on â€œpresent make wise investments in such a difficult environment it is crucial to understand the real value of the remaining reserves. The outcome of o simulation to appropriately value future information today. We assume that the client company and the service provider share information

requiring steering adjustments while drilling horizontal wells maximizing well position in the reservoir. This paper shows how thin oil rims fa s possible to the top of the reservoir to ensure a greater long term field life and given the thin oil column reduce the volume of attic oil. Gen al termination of wells as they reach prescribed abandonment criteria.ï¿½ This method in general results in an irregular well placement pa Timbalier 316 block a delineation well penetrated the steeply dipping B4 reservoir near the oil/water contact. Based on a comparison of do drainage area and provides a step by step analysis to verify quantify and locate these bypassed reserves.ï¿½ Further it provides a compr ly impact the optimum number of infill wells during the concept selection in a field development stage. High resolution geological models tog s. These pseudowells produce or inject at a very low rate and thus have a negligible influence on the overall flow throughout the reservoir. ot depict all details of real SAGD processes. In the present work a new analytical model of the SAGD production regime is described. The i ll. These equations are applicable to partially penetrating vertical horizontal and fractured wells and take into account superposition effec emi-analytical solutions are applicable to partially penetrating vertical horizontal deviated and fractured wells where fractures can have inf typically depend on either the number of model parameters or the number of data points; and third the calculation of the prior covariance m case of field scale applications of long history. Lastly the solver used for solving the Adjoint system of equations needs to be efficient for lar

zations or the training images for a given depositional environment are obtained. These realizations could be quite different yet they are not

e Newton-Raphson method. External heat sources and sinks are included in source terms to model the energy interaction with over-burden handles general partitioning of phase-component consumes no extra memory and only has a small amount of CPU overhead. This gener al horizontal well in this field has perforation intervals of about 1 200-2 900 ft penetrating depositional sequences from the bottom up and

be used to regulate flow from various perforation intervals or producing laterals. Our recent field studies required the simulation of special w

eservoirs using a production surveillance tool that manages multi-wells effectively in less time is discussed. The last three techniques-typeess. This three-phase 2D model proved useful for assessing the significance of reservoir capillary pressure broken-gel viscosity yield stres e in previous studies. A further one related to the cleanup of the cross-linked fracturing fluid with its non-Newtonian characteristics was ra nt flow regimes can be used to observe and define the various impacting factors of stimulation such as fracture length conductivity orienta D computational grid that is used for the whole reservoir with grid refining in fracture domain and couldnâ€™t completely account all phenom imensional (P3D) hydraulic fracture simulator. In the model the width deformation of a fracture with interfacial slip is calculated using a disp mple and fast has been the rationale for using analytical methods in the past. However computer technology has enabled us to run nume numerical analysis restrictions were also imposed on the variables for the correlations to be valid. In this paper the same problem of non-D ir simulator we systematically used the new technique to investigate the effect of data availability i.e. the number of production logs and du state flow.ï¿½ This model has been used to develop predictive and analysis graphical design charts of the dimensionless productivity index uring did not obey any of the existing 2D models (PKN KGD or Radial). As a consequence job designs remained impossible and optimum odel predicts and evaluates the near-wellbore fracture pinching effect as a function of fracture trajectory perforation misalignment angle ce ediction effectively when there is an underlying relationship between the variables. We have applied this and other methods to determine th

e fluid flow in the reservoir. Third the lateral variation in facies forces to use different saturation functions at different parts of the reservoir. T The analytical solution can be used to generate the temperature profile in a horizontal injection well for any assumed distribution of injection se of a nominal drainage radius whereas a two-fluid system with a moving fluid is more appropriate. The novel concept of the injectivity pro defining reservoir compartmentalization and in analyzing the results of material balance (MB) analysis. In particular analysis of the reservo thods. This study allows reservoir engineers properly select the most suitable material balance method when uncertainty on reservoir press oreover the data may be complete but the formerly used methodologies (e.g. the use of well cluster metering units) and instrumentation m a multicomponent reservoir fluid are presented. Results show a strong effect of natural convection in species distribution. Results also show reservoir simulation studies there is also a growing need to share practical examples of the lessons learned in constructing experimental de

gence and numerical flux consistency of the scheme for uniform permeability tensor are studied. This discretization scheme is applied to re but after proper tuning these models can be used for the simulation of the well production profile in naturally fractured reservoir and of the flo osite porosity composite relative permeabilities and composite capillary pressure relationships. These composite curves can be generated ormation and fracturing the limited applicability of the elasticity assumption and the latent uncertainty in the structural geometry of faults. T

ible fluid phases. Flow simulation of fractured reservoirs is commonly performed using a dual porosity model. The dual porosity system is m al to zero. Mass transfer between matrix and fractures is modeled by empirically determined transfer functions. Fracture permeabilities can reamlines in combination with a new multiscale mimetic pressure solver with improved capabilities for complex fractured reservoirs. The mu

we show that RML does an adequate job of sampling the a posteriori distribution for the PUNQ problem. In particular the true predicted oil p

mpact that the dynamics of brine mixing in the reservoir has on scale precipitation in situ. Much of this work has been conducted using finite

nement strategy is based on the multi-scale wavelet techniques. The one-dimensional solution is decomposed into a set of coarse-grid cell r we went further and have treated the thermodynamics in terms of Koldoba & Koldoba approach7. The model allows for receiving phase e ediction that combines speed and reasonable accuracy. The workflow generates a set of key performance indicators of existing wells derive e available; a suite of plausible reservoir models (the ensemble set of ensemble members or suite or realizations) is continuously updated the reservoir heterogeneity each honoring the data available. The simulated pressure responses from these realizations could be quite dif ertible and explain the necessary modifications to the techniques used to solve the resulting linear system. The effect of simulating flow in b

on models can be potentially built. Because of global production targets and constraints these models cannot be run in isolation. A multiple nductivity of reservoir rock called the â€˜connectivity equationâ€™ is provided in the paper.ï¿½ Similar to Archie's law this simple model has

To properly assess all the arguments and to get a better understanding of the state-of-the-art on non-Darcy flow in porous media in genera ften observed behavior: 1) negative pressure gradients 2) water-like gradients significantly above the free water level 3) significant shifts i ith good performance being attributed to the highly developed and connected fracture network. The original reservoir pressure was in the ra round borehole can produce breakouts and their orientation indicates the direction of minimum in situ horizontal stress (Sh).ï¿½ In the case apply these smart technologies to mature fields with a legacy infrastructure and long production history.ï¿½ Participants felt that maturity i e very intereresting EOR experience has been accumulated in the country. It is likely that EOR- produced oil in Russia has not already reach Alaskaâ€™s North Slope started producing oil at about the same time as the United Kingdom North Sea in the mid to late 1970â€™s. Ala nt with those of finite-element models. More complex situations can be simulated with finite-element models but the input data requirements

surveyed with pulsed neutron capture logs. Based on the log results depleted zones were identified and the intervals contributing most to aulic flow control valves with advanced downhole two-phase flow and density measurement provided by a Venturi-based flowmeter with a ga n late 2000 after a successful waterflood pilot program. The wells having water injection are mostly located in the short string section of the Development of a state-of-the-art electrically powered tractor combined with new surface read out array mini-spinners and optical gas and a

mation mobilities are in the low double or single-digits saturation pressure is usually within a few hundred psi of formation pressure and bor mation mobilities are in the low double or single-digits saturation pressure is usually within a few hundred psi of formation pressure and bor e and temperature in two stacked carbonate reservoirs. The standard dual-gauge system mandrel architecture requires below packer insta tector are used to record the dye signal and calculate pH with 0.1-unit accuracy. The pH of a formation fluid alters as the sample is brough compared with historical trends to check well performance. For the fields studied the KPIs have proved valuable not only for production mo such as drilling patterns new well placement and completion practices. Microseismic events were located with a newly developedï¿½ loca ally the result of insufficient fracture width. This unfortunate circumstance creates an operational strain and productivity underperformance fo

le continuously during startup and production. Initial steam circulation and production occurred in 2004. The acquired data shows that large unload liquids from the well.ï¿½ Sub-critical velocities are commonly encountered in low productivity gas wells that produce liquids whethe and unload liquids from the well. Sub-critical velocities are commonly encountered in low productivity gas wells that produce liquids whethe t produced water to surface. This completion technique makes spinner production logs impossible to run without initially performing a wellsit are analysed to determine tracer presence. The presence of one or a combination of unique tracers within the oil sample along with the kn ow-rate and cut measurements without slip models even in highly deviated recirculating flow. The physics basis and flow loop tests are dis

ation from any target would be detected with just monitoring the data collected. Then any good" decision for improvement or optimization w as high as 99%. The horizontal well examples show that stratified flow regimes as expected from flow loop publications vary hugely with c rovided an â€œonce-in-a-lifetime opportunity to carry out a fieldwide pressure data acquisition campaign. Over a period of six months (Nov During this period the gas oil ratio (GOR) steadily increased from 200 scf/bbl to 2 200 scf/bbl. To arrest production decline a chemical trea hand in obtaining better data for decision making. The most important part of well/field production optimization is identifying candidates and elaborate operational aspects involved in wireline formation testing success requires detailed upfront planning and procedural design as w production. The technique employs the use of a rigorous near-well nodal reservoir pressure and thermal model to analyze permanently insta ormation indicates a discrete deforming region near the toe of the well. The volumetric strain also shows another region near the heel of the on the periphery of the sand-screen shroud effectively installing it in the gravel-packed annulus. When the gravel pack is completed the fibe nd distributed along a single spoolable bridle. In addition a novel inductive coupling mechanism was developed to pass power and data from t types of thief zones in the Mauddud carbonate reservoirs using high-resolution image logs with calibration from core and dynamic measur

volumes at the well level and at intermediate outlets of the production facilities. However for many fields this isnâ€™t a cost effective solut that differentiate between Oil Holdup (Yo) Gas Holdup (Yg) and Water Holdup (Yw) as well as providing multiple spinners for revealing stra

n in the industry and already proven beneficial in many occasions. In favorable conditions this is the most effective methods available to da ent of the injected sea water front within the reservoir is important to evaluate the efficiency of pressure maintenance by peripheral water in eing deployed in southern part of a complex carbonate reservoir in the middle-east where an uneven flood front advance has been observe a higher resolution image of the ongoing flooding processes. The classic EM inversion process determines a coarse (3 to 5 m resolution) and new technologies are being developed with the aim of increasing production rates. Considering this interest and activity level little atte standard log evaluation methods. A CBM well may often penetrate multiple reservoir zones (seams) and properly characterizing the cleats ced to significantly increase Coalbed methane (CBM) fracturing efficiency by initiating fractures in lower stress clastic rock adjacent to coal s oblem encountered when completing horizontal Barnett shale wells. These difficulties have manifested themselves as high-fracture initiation elopment in tight gas shale reservoirs results in complex near-wellbore stress concentrations not observed in isotropic rocks.ï¿½ Using fini the friction pressure through (CT). Efforts to increase the energy have involved increasing CT size and increasing surface horsepower.ï¿½ E re.ï¿½ In most cases evaluation is limited to a gamma ray measurement while-drilling (MWD) ï¿½tool and periodically mud log.ï¿½ While onal logs and cores have been used to classify lithofacies and estimate petrophysical and geomechanical properties for well positioning and mendous amounts of steam in order to get the crude to flow. Costs to generate and inject steam in a SAGD pad are significant. Finding way atural-gas production from coalbed- and shale-gas reservoirs in the US is approximately 2.7 Tscf which represents 15% of total natural-gas se the productivity of existing wells and book additional reserves at reduced cost operators have restimulated their older vertical wells with optimized wormhole geometry should be functions of reservoir properties such as permeability and pressure as well as fluid types such as o ravity. All new installations were carried out without interrupting the ongoing production target. The project has completed a four-years oper

all the conventional artificial lift systems have a common feature. The energy added to the lift the fluid from the wellbore is lost in the proces ot only enhancement of individual well production rates but also significantly improved the oil recovery. This goal was achieved through opt ed to the need for evaluatingï¿½ the best sand-control solution while considering the cost/benefit ratio. This paper explains why an openhol f valves to be placed in a single well without incremental reductions to the internal diameter (ID). This near full bore feature allows normal ce een both vertically and horizontally on a well-to-well basis even though the wells are very closely spaced. Sands have different oil retainer c wellbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore.ï¿½ The produced liquids considere wellbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore.ï¿½ The produced liquids considere as been recently drilled in this reservoir achieving about 5 000 ft of reservoir contact.ï¿½ This paper details the process followed to achieve

e control of commingled production from the laterals. Using the variable positions flow control valve the well was managed to improve and hat downhole control may be used to adjust flow distributions along the wellbore to correct undesired fluid-front movement. In this paper w and downhole control of commingled production from the laterals. The well was managed to improve and sustain oil production by eliminatin

ompared to horizontal wells. With a total section exposed to the reservoir equal in both types an experimental model has been built for the mize operations in wells where the above equipment and operations are required. This paper summarizes practical experience gained durin x proportional hazards (CPHs) (Cox 1972) modeling to determine statistical significance of explanatory variables (EVs). Methods developed s create significant conductivity enhancement in treated wells their etched fracture length is typically short because of the high speed at wh marine sandstone without hydraulic fracturing until drilling the CD2-37 well in 2003. The poor reservoir quality found in the southwestern e

une of 2005 a new technique was introduced utilizing chopped fibers within the fracturing gel slurry to help suspend proppant in the slurry b tems oil-based systems or reduced polymer systems. The fluid systems can then further be pumped as linear gel pad stages with cross-lin tration and in-situ gelled acid a polymer-based system have been extensively used in most fracture treatments in an attempt to control exc ncentration up to 1000 kgPA and higher with only 3.0 kg/m3 (25lb/1000gal) guar polymer loading a feat previously only achievable with 3.6 a specific reservoir is not a simple matter for the end user and the existing literature is full of conflicting claims as to which one may be mo sider the combined effects of modulus contrast and in situ stress contrast on fracture geometry. A pseudo 3D (P3D) hydraulic fracture simula tive length and conductivity and fluid recycling/handling are but a few strategies employed. Additionally operating companies have been se ened or requires expensive cleaning or dilution with fresh water to make it a viable solvent base for fracturing fluids. This paper describes th arious Pin-point Stimulation Techniques) were implemented with an appropriate data collection strategy to evaluate and compare well perfor ping a sand plug with the downhole tool set for circulation to isolate a bottom set of perforations followed by conventional frac-and-pack. W ate fracture height growth. The method consists of pumping a predetermined mixture of specialty solid materials. The case study clearly dem high permeability streaks that require effective diversion techniques. The efficiency of chemical diverting agents in terms of flow distribution er cuts can be a rewarding operation. The treatment can be carried out while providing favorable economics to the entire operation. The n. Conventional multistage fracturing techniques including perforating fracture stimulating and isolating stages with a composite bridge plug

huff carbonate reservoir some wells have experienced complications during the drilling phase and encountered unexpected reservoir challe

that had experienced poor recovery primarily because of poor permeability. There were unique challenges posed by the Gandhar candidat tilized in this study. The mathematical model described in this paper has been used to develop predictive and analysis graphical design ch

gh asphaltene and paraffin oil content varying the hydrocarbon properties it is understandable that the extensive knowledge gained in West

ementing operations. A control line is connected to sequential valves. When the bottom valve opens the control line becomes pressurized a he cemented sliding sleeve concept by attempting to minimize and predict fracture initiation pressures. Finite Element Analysis (FEA) wa se of soft rock that is a cohesionless granular impermeable medium. The real problem of hydraulic fracturing in an elastoplastic medium ha xico.ï¿½The fluid exhibits enhanced fluid efficiency while still maintaining the high proppant pack conductivity associated with the lack of p

sive of low-pressured water sensitive formations high rock Youngsâ€™ Modulus and unpredictable occurrence of water-bearing zones lead

Asphalting Onset Pressure (AOP). An engineering solution was urgently needed to enhance the productivity of wells and to mitigate the asp roject (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006 which indicated that the poly y execution and results from two offset wells.ï¿½ The first well was completed with a two stage hydraulic fracture treatment while the succ

not known accurately and the velocity model is artificially adjusted to locate perforations on assumed positions several milliseconds discrep

pect of the acid-fracturing process we developed a new surface profilometer to measure the surface profile of a rock sample accurately and of the height but also for p3D model where the height is indirectly obtained from coupling stress profile and fluid flow. Fracture azimuth is tra onal markets. This paper will describe a new patent-pending technology that can generate valuable data on propped fracture height as wel

s is particularly true for the Yamburgskoe gas condensate field where the wells are completed in a series of medium- and low-permeability y true if a liquid phase is also flowing. The apparent permeability of the proppant is a function of: Gas velocity (hence: rate and flowing p the tip zone where the pressure drops below the far-field pore pressure. Moreover the assumptions of the Carter leak-off model do not app s greater than the fracturing pressure of the formation. A new generation of viscoelastic surfactant-based acid was implemented in the field dy state shape factors under boundary-dominated flow conditions.ï¿½ Designing the optimum stimulation fracture treatment in this case is m tion data. This difference in fracture geometry was attributed to rotations in the direction of minimum principal stress which is consistent wit ng an appropriate completion method. The development of a model allowing a quantitative prediction of this process is therefore a very vita model is developed to predict the growth of the two intersecting fractures in a variable stress field and the associated pressure response in on fracture propagation. After hydraulic fracture formation terminated the cleanup procedure begins. Fracturing fluid is evacuated from the at the wellbore impeding both lateral and vertical extent. Differential cased hole sonic anisotropy (DCHSA) combines the use of cross-dip

culprit. The main results presented in this paper were obtained using a modified conductivity cell to allow polymer concentration via leako umping 1000 bbls of treated seawater at rates from 7 to 14.5 bpm surface pressures were still within the pressure limit of 3000 psi given b ion of a horizontal stress map for the studied area and an accurate measurement of the hydraulic fracture heights on the borehole wells tog pled 2D hydraulic fracture model. Offsets are geometrically characterized by their angle with respect to the main fracture direction and by th gas lift systems have been installed at the time of writing of this paper most of them in the Scandinavian sector of the North Sea. Several e techniques used in completing these high rate gas wells as open-hole gravel packs have included both water-packs and shunt-packs. The uating to time savings more efficient fractures faster cleanup and less safety hazards. Conventional methods of cementing a liner in place uating to time savings more efficient fractures faster cleanup and less safety hazards. Conventional methods of cementing a liner in place presents the case of a gas producing horizontal well in Indonesia completed with a perforated liner. The target reservoir is a clean sandston nce completion system with digital permanent down hole monitoring system. Intelligent completions allows individual lateral testing allocatio ater breakthrough. This early water breakthrough causes reduction in potential hydrocarbon recovery; the operation of the ICD is minimizin eous reservoirs using a single wellbore. Their capability to restrict water or gas production and improve ultimate recovery has helped optim n system with digital permanent down hole monitoring system. Intelligent completions will allow individual lateral testing and allocation of pr riggered by permanently installed downhole sensors can enhance production and mitigate reservoir uncertainty across a range of producti were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e. a lower fluid pressure region close to the fracture tip

well performance prior to the production test. We present an integrated and structured approach for calculating the productivity of a lamina ng problems are expected after depletion increase in water cut and installation of ESPs to optimize production. To accomplish this task a 3 he perforating and other near wellbore damage therefore perforating design is not important as long as it serves the purpose of puncturing t ormation immediately after perforation and a perforating technique that utilizes the dynamic underbalanced method which cleans perforatio used to perforate numbers of infill wells with low success ratio. The reservoir characteristics with high formation pressure and BHT followed nce simulations. The quality and amount of data was recognized to be limited. However a qualitative diagnosis of these results indicated tha servoirs are generally of lower porosity and higher compressive strength. Drilling-mud-filtrate invasion also tends to be deeper. Deep-penetr or other hardware that can be damaged during perforation. The traditional approach of hiring a workover rig to remove the completion prior ile waiting for the multipurpose barge and in some cases eliminate the need for stimulation. This new perforating technique utilizes a uniqu continuously varies during the surge; (b) the skin factor may decrease substantially during the flow period because the mud cake invaded f ellbore fluid displacement is often deemed insufficient to create effective cleanup of the perforations. This paper outlines a solution to these on their own experiences and previous perforating histories to roughly estimate the swell or damage conditions of similar perforators. In this

only difference of note was the design and composition of the liner. All other charge design parameters were kept constant. For both rock t efore they are used for production or injection. In the depleted oil field under study a typical completion is perforated using large diameter h challenging areas in Ghawar field where the water will reach the wellbore much faster via the reservoir's fractures. Using the smart completi lenges presented by the heavy oil and the large geographical extension of the reservoir the decision was made to develop the field with ho help ensure high-rate long-life completions the producing zones are frac packed. The average perforated interval during the initial comple north to south. Production in Hawtah comes from the Unayzah sandstone and consists of Arabian super light (50ï¿½ API) sweet crude oil. were used successfully on the first two wells. The A1ST1BP1 completion failed during initial unloading allowing unacceptable rates of san out ten years of production a significant amount of sand was observed during routine sampling of the well. This condition resulted in the clo

sure and even flow distribution throughout the producing interval of the well.ï¿½ A review of the completion methodology in poorly sorted u integrated approach was adopted for the design of the fluid systems involving extensive formation damage and fluid compatibility testing. To

packing was the common completion in a single sand body however in presence of shales open-hole expandable screens with annular barr caused by unpredicted downhole events. In this paper we present a new approach for gravel packing long high angle openhole intervals w n successfully designing these jobs. This paper presents a pseudo-3D modeling tool which models the complete gravel-pack process and a gravel packing in the industry deals primarily with water based fluid environments new challenges for gravel packing of the associated we ation tunnels and improved the connectivity to the reservoir. Guidelines to surging the formation and executing the perforation packing job ar tion tunnels and improved the connectivity to the reservoir. Guidelines to surging the formation and executing the perforation packing job are horizontal wells due to traverse several shale and sand bodies of varying quality. Perforation tunnels with optimal â€œstructural stability fo s heavy and viscous oil of 19ï¿½ API - 9 cP. This causes sand production high water cut wormhole development and requirement for artifi tubing intervention matrix acidizing resin consolidation optimized fracturing with proppant flowback control and fines migration prevention

a particular systematical approach termed as Sand Management Solution (SMS) to properly address the sanding issues it was facing whic is thus provides a basis for designs that achieve appropriate sand management strategies and maximization of economic production and o e descriptions of the rock strengths and in-situ stresses in the reservoir formation. Somewhat surprisingly the model backed up by the cor tresses and drawdown conditions. Water was introduced into the flowing stream of either oil or gas at various stages of the tests to simulate

d production prediction models have focused on predicting the onset of sanding by predicting the drawdown at which failure of the formatio ion pressure 2) mechanical and petrophysical properties of the formations transected by the wellbore and 3) properties of drilling fluid and nd form rod-shaped micellar structures under certain conditions. Viscoelastic surfactant-based acid systems have been used in Saudi Arab id loss flux is controlled to match field fluid loss rates. We studied three commonly used acid fracturing fluidsâ€”an acid viscosified with poly sary diversion to ensure that multiple sets of perforations are adequately stimulated. Because of their high solubility and highly fractured/vu sed system are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad. The ased system are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad. Th nges in the production profiles. In one of the wells the formation was stimulated first with 15% HCl through coiled tubing and then with the mentation and a moderate-to-low rock strength. Core analysis and rock mechanics assessment revealed that much of the rock is weak an ake matters worse formation damage in horizontal wells is usually very deep as a result of long exposure times. This paper discusses the a dstone oil reservoirs was implemented. The chemistry and art of four different acidizing methods involving Tubing Pickling Bullheading Div

he wells by reducing the skin factor to the lowest possible value in each zone. At the same time the selected optimum acid system placeme ow corrosivity their low dissolving capacity may still limit the wormhole penetration leading to insufficient stimulation of the formation. Theref

e sands using a variety of different (water- and oil-based) fluids. However many of the wells indicated positive skin factors following the fra eatments especially in extended reach and multi-lateral wells. Diversion techniques can be classified as mechanical or chemical.ï¿½ Mech depletion is the increase in filtrate leak-off of drilling completion as well as stimulation fluids. The sensitivity of the formation to wellbore fluid ties on stimulation treatments.ï¿½ Some results on the influence of core scale heterogeneities are also presented. Core samples from eigh ction methodology has focused on underperforming wells. This simplistic approach has yielded disappointing results and has led to a comm effects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier com lastic surfactant (VES) fluid system. It has recently been employed to eliminate the disadvantages of the traditional polymer-based fluid. Th and evaluation but goes far beyond basic well stimulation which has historically used limited data. Another important feature of the integra

lting in higher water cut due to the over stimulation of the water zones instead of the oil bearing zones. The objective of the present field cas istence of poor behind casing cement quality and possibly hydraulically communicating layers was critically and systematically examined by e derived from the rigorous solution and are used for developing the basis for the straight-line analysis. A derivative function is utilized to as p tests and FloScan Imager (FSI) log has been carried out to evaluate this well. The material discussed in this paper provides a good basis ordingly to the fracture flow periods 3) estimate reservoir and fracture effective properties and 4) evaluate the completion efficiency. The fie u-2 and Bentiu-3 formations. These formations are highly variable in terms of the reservoir properties oil types and pressure regimes. A sele penetration of the total formation thickness. Penetration in naturally fractured reservoirs is usually minimal (10 to 20%) but with the right mu uge at a distance we will only start to detect a pressure change (drop or increase) after a few seconds or minutes even if we have a perfec monitored.ï¿½ This paper illustrates how real-time data can be used to make decisions on when to invest in pressure transient tests and wh d in a unified manner. The algorithms used in this study for evaluating the von Schroeter et al. and Levitan methods represent our independ

nalysis of pressure transient data provides dynamic reservoir properties such as average permeability fracture storativity and fracture cond ion testers have been commonly used to acquire formation pressures pressure and reservoir fluid samples for a number of decades. Many ctives of a MiniDST are sampling estimation of reservoir properties such as permeability (k) skin(s) radial extrapolated pressure (p*) and e ove 95% gas fraction under metering conditions and water cuts often higher than 90 % TOTAL ABK has evaluated different well testing & m ating environment of Northern Siberia. The reduced logistics and the ability to monitor in real time the true evolution of the gas and conden

us types of multiphase flowmeters react quite differently to the measurement challenges of transient flows in high water cut and high gas vo burgskoe gas-condensate field with low ambient temperature and production rate regulation restrictions this process had to be revalidated t allows a traditional multiphase flowmeter to operate in a dual mode either as a multiphase meter or as a wet-gas meter in 90 to 100% gas ators to allow fair comparison of results. More than 50 wells were tested during this campaign. All these wells were selected carefully to rep

en commonly accepted in the multiphase business between Multiphase Flow Meter and Wet Gas Meter. With the recent dedicated Gas M a more complete approach where a more integrated approach using a common model is advocated. . The benefits of such a workflow can ation of the Î²-derivative function (i.e. the Î²-integral derivative) for the purpose of estimating reservoir properties contacted in-place fluid an tability and resolution required to characterize/quantify complexities of the well/reservoir system which may otherwise have gone unnoticed ated that the streaming potentials arising from pressure transients can be measured accurately under borehole conditions.ï¿½Numerical me

and solids across the caprock. This has the triple aim of: verifying the soundness of the complex cementing engineering process evaluating are used to constrain principal horizontal stress orientation and magnitudes. Consistency of the stress model is then checked against the o formance management. The approach based on Performance and Risk Management methodology (P&RTM) serves as a decision suppor r representation of the fluid production/injection taking into account the constantly changing interaction between systems. The integrated a e accurate description of physics and chemistry in numerical simulation tools is fundamental for understanding processes as well as design ues and provide operational experience which all contribute to the development of harmonized regulatory frameworks and standards for C covery (EGR) Food processing applications Mineral products Fertilizer manufacture Algae growth promoter Enhanced plant growth. The construction and the calibration of a Mechanical Earth Model of the site through joint analysis of geologic seismic logging drilling and lab

h are used as down hole chokes to optimize the production from the separate zones in the reservoir. Subsea developments in combinatio plex directional profile ECD management at high ROPs can lead to inefficient motor drilling. The soft formations also create limitations for

Energy project is studying the use of CO2 in enhanced oil recovery operations at the Charlton 30/31 reef which is located in Michiganâ€™s as been naturally trapped in carbonate formations in this region is present in concentrations that can exceed 90% purity. Due to the high co scerned using microresistivity measurements in oil-based mud systems and new high-resolution cutoffs can be employed. A production pr enating gas-condensate reservoir production through multilateral sidetrack reentry drilling technology.ï¿½ Simulation studies show that reen se reservoirs which have previously produced with primary recovery mechanisms. The study touches upon the effect of the component gro tion. Challenges faced in shutting off these gas zones included: 1) Poor cement bond behind the liner shoe. 2) Massive fractures resulting i

cost-effective chemical treatment method was progressively developed. In 2005 the treatments were performed through-tubing with and wi roduction figures. The nature of water problem and the fact that the targeted section is located in-between multiple oil producer zones revea p to a tolerable limit which is dependent on the water handling capacity of the installed facilities and also the economic cutoff limits for the ective. This will open the doors to apply similar techniques to liven dead horizontal wells in other fields. Introduction Excess water productio ent results. This method can fail to change the well production profile and possibly damage oil-producing layers. This paper will discuss the ance which makes water production and handling a necessity even at a relatively early stage of some of these fields life cycle. As drilling te uction profile was determined by a Flow Scan Image (FSI) log which showed 51% of water cut and the entry of most of the water was from e elements include wellbore fluid loading fluid slugging inorganics corrosion erosion and emulsions. All these elements adversely affect p rformance evaluation of an oil/water model. A high-speed video camera was used to identify flow patterns and measure droplets and ten c al results include observations of flow patterns and phase distributions and measurements of water holdups and pressure gradients. A high ed system of reservoirs and wellbore.ï¿½Once multiphase flow occurs both the change of the fluid mobility in the reservoir and the change ompression power or pump capacity for example could impose significant limitations over the well and surface network performance that c h to evaluate the potential impact of asphaltene and wax precipitation and deposition. In this field case two distinct layers of hydrocarbon d rk included determination of the wax appearance temperature (WAT) and rheological studies which included pour point gel strength and sh drocarbon bearing formation is to take fluid samples downhole or on surface during a well test and send the fluids to the laboratory for analy he Malay Basin in Malaysia will be discussed in this paper. The CO2 content can vary from very low concentrations in one zone to significan

ations based solely on field data have been published for any of these properties. The field data required are initial producing gas/condens d reservoir simulation calculations of gas condensate and volatile oil reservoirs) had to be generated from a combination of laboratory exper esponding asphaltene gradients provide a stringent and new method to test reservoir connectivity (as opposed to compartmentalization) wh gas. However water zones and secondary gas cap formation in a few layers are also common. Nonetheless unexpected fluid production s ocesses of different reservoir zones or compartments not only motivate more variations of fluid properties also trigger contacts migration a uid properties provided by a laboratory. Nevertheless these tools are valuable in predicting other PVT properties from the measured data. T istically assume single-component phases in the case of two-phase immiscible formulation or a two-/three-component hydrocarbon phase ey for real time contamination monitoring at the well ï¿½site with the objective of representative sampling and reservoir compartmentalizatio

en hole and Nuclear Magnetic Resonance (NMR) logs were run for formation evaluation and fluid saturations. Gas and remaining oil satura H2S levels. In addition to the expenses associated with a well test there is the ever-present issue of H2S scavenging. Many days of flow m

erived gradient and that obtained from wellbore-flow modeling of production-test data. Older-generation formation testers (those from before id traits and has different implications. When these analytic methods are systematically combined and consistently applied the synergy del ow porosity shaly sandstone reservoir. It becomes difficult and at times impossible to definitively identify different types of formation fluids fr ontact (OWC). Wireline pressure testing identified three different pressure gradients corresponding to gas oil and water all in hydraulic co onal gradients in the hydrocarbon columns of some reservoirs â€“ this raises questions about the conventional approach to pressure gradie nted by downhole fluid analysis (DFA) measurements to reveal possible reservoir fluid heterogeneities. Although these fluid complexities ha filtrate uses optical means to monitor the buildup of both color- and methane-absorption signals during sampling. The technique provides re

at diffuse. Formation testers supply a wealth of information to observe and predict the state of fluids in petroleum reservoirs through detaile hm called the fluid-comparison algorithm (FCA) was developed to address this issue. The FCA propagates uncertainties in optical measure operties provided by a laboratory. Nevertheless these tools are valuable in predicting other PVT properties from the measured data. These

mponents may be present and water may exist as a liquid and/or a vapor.ï¿½ The presence of non-volatile and/or non-condensable hydroca water content pressure and temperature (i.e. operating conditions on the viscosity of live heavy-oil emulsions). Two heavy oil samples fro

ntaminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance that p ample useless. Besides that the tool pumps gas into the wellbore during the cleanup phase raising issues of well control. Another importan growing rapidly. In many cases multiphase flow meters have replaced the separator for flow rate evaluation but some fundamental needs hern Siberia. One of the past challenges of multiphase well testing has been the ability to collect representative fluid samples for analysis.ï¿ -soluble products. Different mathematical models were developed to describe reaction of organic acids (both simple organic acids and poly ommonly used exploitation method because of its favorable results. Sustained injection rate with delimited surface pressure is necessary to e controlled reactions solutions of calcium chloride are mixed with solutions containing one of a variety of soluble inorganic or organic carb re efficient salt inhibitor would need to reduce both treatment level and production downtime. The inhibition performance of three new chem

bility impairment caused by subsequent deposition of these particles in porous media under flowing conditions and different pH values. A po d strength called the damage zone. As a result the damage zone extends to a greater depth than the crushed zone. This weakened damag tood. Underbalance perforating also serves to remove some or all of the comminuted sand grains that fill the perforation tunnel immediate stimulation treatment has been documented. This paper describes the first application of a combined scale inhibitor and hydraulic fracturing yered commingled gas reservoirs. Typically a well completed and placed on production without any scale inhibitor in the Uinta Basin may s ve individually from the surface to maximise oil production and/or minimise formation water and/or gas production.ï¿½However they may a nhole equipment. While CaCO3 scales are possible to be removed by the use of common acids and wireline tools Strontium Sulphate sca ix than would be expected purely from dilution of seawater with the formation brine.ï¿½The question this paper addresses is what has caus aults. The proposed approach isolates least correlated and most sensitive regions within a reservoir. The least correlation criterion ensures t olves the conversion of a finite difference black oil Dual-Porosity Dual-Permeability (DPDP) history matched model into a Dual-Porosity Sing ure (i.e. prediction phase).ï¿½ This technology can be used to guide and optimize development strategy. By incorporating streamline techno ems under different reservoir heterogeneity conditions pertinent to Cantarel Field. For this purpose some of the typical problem wells have d made the implementation of automatic surveillance particularly challenging. We introduced an automatic surveillance solution that synch es the WI pilot. Among the novel techniques applied is the crosswell electromagnetic method which measures the interwell resistivity distrib sound reservoir management principles. An innovative unified information management system was used to monitor voidage replacement r nd Rojas 2001). More recently top-drive PCPs have also been installed to produce extra-heavy oil at high rates. Hybrid artificial lift technol oirs with primary production techniques to facilitate the economical implementation of steam injection based methods. The initial production parameters like heating time and waiting period as well as rock and fluid properties like porosity permeability wettability salinity and initial ss is based on a repetitive pattern using horizontal wells acting alternatively as oil producers and steam injectors. The recovery mechanism ck off â€“excessive back reaming and stuck pipe incidences uneven build rates via sliding in interbedded formation leading to high borehole udy presents several aspects of an integrated approach to characterize the 1st Eocene reservoir. The approach includes the quantification a nication between the tool and formation. This conventional technique is well suited for thick and permeable formations. However for difficult

his small to medium sized heavy oil field and controlling the sand production due to low drawdown pressure and increased exposure the re

onounced. To temporarily plug the water zones and effectively stimulate oil zones with chemical diversion a new surfactant-based chemistr

ce. Different set of technologies and methodologies have been used to overcome the technical production and monitoring challenges in thes

a single-stage sandstone acidizing fluid designed to address some of the problems associated with conventional sandstone acidizing fluids on. The initial formation evaluation in the first two â€œAchimgaz vertical wells included an extended formation logging suite followed by form

er isothermal conditions and in the absence of recharge gravitation will dominate. However gravitational effects are not always significant

out.ï¿½ On the other hand a Ti or Zr crosslinked gel which crosslinks substantially after exiting the perforations may not have sufficient prop ustry has successfully tried different methods to deal with each or a combination of these problems. However none of them fully address a

plant through SCADA which allows to monitor well performance in real time.This data are used for history matching deliverability and transit ase in Productivity Index (PI) of greater than 5 times. This study discusses the properties of the various hydrocarbon-producing zones in th sandstone acidizing to one stage; (2) minimizes precipitations by delayed and stabilized reaction mechanisms; (3) provides homogeneous dramatic increases in the formation permeability after treatment with the chelating agent-based fluid. The improvement in permeability is as coelastic surfactant-based (VES) fluid systems have been introduced in the industry as an improvement over polymer-based fluid. Neverthe sts are conducted to determine wettability alteration before and after treatment with the chemicals. The results show that chemical A5 give er and gas phases and then using water chemistry models to predict pH at reservoir conditions. Uncertainties in the thermodynamic mode

had various operational and logistic issues that have minimized efficiency and production impact. The system applied involves the use of a

ments one mature and one emerging. The case from North America illustrates a use of the proposed process in a high-volume field develo th a maximum fracture event length of 800 feet. The planer fracturing scheme is consistent with low amounts of acoustic anisotropy recorde ctured by the mere injection process. It is also known that re-fracturing and pore pressure re-distribution will re-orient the stress field not on sumption of a symmetric bi-wing fracture system. To better characterize the induced fracture network a semi-analytical pseudo 3-D geome ed to evaluate the stimulation treatment carried out for several offset wells throughout the field. The analyses determined the fracture geome

uentially executing several fracturing treatments in a single pumping operation. Nevertheless the high direct and indirect costs and the risks om 4âˆ’10%with permeability ranges of 0.241âˆ’1.116 mD showing a medium porosity and low permeability characteristics. Small reservoi he oil in the low permeability intervals will be left unrecovered. A combination of horizontal drilling with geosteering tools and technology for r overpressured conditions were modeled and the hydraulic fractures properties were derived from matching initial well performance. The m rements and formation micro-imager (FMI) have not only been crucial in model validation but also in order to: Evaluate production contrib aulic fractures. A streamline-based flow model was used to upscale geological features. Some practical assumptions were made to apply t ermeable sands can be discerned from clay dispersed in silt and sand. A true net height can now be obtained.ï¿½ Through production optim

reservoirs oil-based mud has been used in the drilling process due to the concerns of wellbore stability. Acoustic images and core was acq even better data quality to fully satisfy planned objectives. A recent well (Well B in this paper) drilled offshore Abu Dhabi for ADMA-OPCO uative standpoint. This is important in understanding the impact these properties have in increasing the production from a specific wellbore. tudy serve as a model for what can be achieved in similar fields using these techniques. The conditions and limits of pressure data applicab

eration formation testing tools that extend the range of pretest rates and volumes have greatly improved the quality of WFT data acquired in waterflooding patterns and massive hydraulic fracturing together with an artificial-lift system equipped with permanent pressure and rate m offset vertical wells yet they are theoretically capable of up to three to five times the production. Higher gas prices have lead to potentially b ofiling on the regular orthogonal grid with the employment of modern seismic techniques and technologies and also the study of the distrib

ally in place (OIIP) calculation and on development decisions. In principle pressure gradients from traditional open-hole point pressure mea

nsolidated with higher viscosity and strong aquifer support. Some formations are tighter too. Field performance is marred by exponential ris

on intuition and experience to guide their decisions. However when multi-criteria exist simplistic intuitive process may not be applicable in w wing of experts comparing subjective expert judgment with results of objective data analysis for example related to geological uncertainty o place the well within the structure. This short paper will show the step change bought about in 3 of the wells drilled and the success and b NMR log. In carbonates however it has been pointed out that variations exist in the relationship between pore body size and pore throat s ons we explored the use of electrode resistivity array (ERA) measurements in a carbonate formation for reservoir characterization. The ERA dissolution is observed by patchy feature on core. Similarly this high level of heterogeneity can be observed downhole by borehole imaging f the sedimentary environment envisaged. This study helps in static modeling of the reservoir with better understanding of process sedimen in the Lower to Upper Triassic reservoirs of the Rhourde El-Khrouf field based on subsurface data from six wells including well logs boreho 5) hexane and heavier hydrocarbons (C6+) and carbon dioxide (CO2). For single-phase assurance it is possible to detect gas liberation ( gas. ï¿½However water zones and secondary gas cap formation in a few layers are also common. Nonetheless unexpected fluid producti ative to look at both micro and macro scale heterogeneity for evaluation of such reservoirs which has a direct impact on the production and study was thus to characterize the reservoir at wellbore level and conduct realistic inter-well and reservoir-scale geo-modeling for improved depth at the same time and on a similar volume of the formation. These features ensure that all measurements are essentially seeing the sa suite of formation evaluation measurements without having to use a chemical radioactive logging source. The use of a non-chemical radio

based on development of water saturation error analysis charts for the commonly used water saturation models (Simandoux Indonesian W ue is based on development of water saturation sensitivity charts for the most commonly used water saturation models (Simandoux Indones to this workflow to include estimates of relative permeability by modeling invasion of mud filtrate utilizing a fluid flow model in combination w s with typical value of 12% to 15%. Permeabilities over 2 Darcies have been measured in this field. The carbonate can have higher permea was unsatisfactory due to the poor permeability estimation.ï¿½ The effect of geological complexity on the log based prediction is overcome ate that the partitioning of NMR T2 distribution is a robust method for calculating independent volumes of clay silt and sand. We present the

ns. In producing fields that have undergone several waterfloods water resistivity is often unknown in the swept thick sands and might not be where the time-consuming resistivity modeling/inversion is not available LWD apparent attenuation is found to be more representative to tru res enable a comprehensive description of fractures (morphology and type) over the cored sections of the reservoir. Meso-scale fractures c ations sand grains and solids tend to become mobilized and flow with the fluid being sampled. In some circumstances where significant form ages were absent in the cores. This paper describes how geomechanical analyses have been used to address factors leading to the develo al facies log which is turn up-scaled using seismic attribute map. As the area is not covered by any well or other form of data a variogram a

s often causes incorrect frequency statistics of reservoir properties which typically exhibit a non-Gaussian distribution. As a result estimatio because of bed geometry and lithology. The reservoir beds are often thinner than the resolution of the formation evaluation logs. They exhi all layers of shales and all layers of sands regardless of their individual thicknesses. Because NMR relaxation time in shales is much faster

he surface. There is almost always a difference between the actual measured depth (MD) of the LWD sensor downhole and this static pipe

ough is largely controlled by fracture / stress reorientation. A systematic study of stress reorientation around horizontal wells and well pattern cus of this work is on the prediction of elastic parameters and their variation with the depth of a given reservoir. For an isotropic medium th ta for the case study presented in this paper was acquired by a cross-dipole sonic tool in a deepwater well offshore Louisiana in the Gulf o eady state damage /stimulation skin effect and non-Darcy flow coefficient.ï¿½ In the specific case where the deliverability performance of a eady state damage /stimulation skin effect and non-Darcy flow coefficient.ï¿½ In the specific case where the deliverability performance of a eady state damage /stimulation skin effect and non-Darcy flow coefficient.ï¿½ In the specific case where the deliverability performance of a er Burgan field consists of the Burgan Magwa and Ahmadi structures. The four main reservoir units in the Greater Burgan field are the Wa f of Suez area over the carbonate reservoir. The well was drilled on the peak of anticlinal feature created by fault propagation fold of a norm servoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs proce gs recorded in this field. The objective of this study is to provide a more detailed fracture network to explain the present-day reservoir behav a fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of B

n Saudi Arabia. The field experiment was divided into two stages: 1) Selection of the well location coring and logging experimental setup a imate recovery. Recent advances in wireline formation testers have enabled the determination of several fluid properties including fluid com l pressure transient testing (IPTT) and coring. A Sonic Scanner* survey was conducted in Tunu field to investigate possible nearby formatio

mplex and variable lithology become fundamentally beneficial at the time of determining an immediate porosity value with less uncertainty i r to ensure that all representative fluids are sampled. The most important information a continuous fluids type and property log is still not w ze distribution and direct fluid identification can be applied to resolve the challenges mentioned above. We demonstrate the use of NMR da inversion process creates interdependencies between T1 T2 and D. These effects conspire to introduce inaccuracies in the reported poros med at nonspecialists who would like to gain some knowledge of the formation-evaluation capabilities of NMR logging tools. The objective Several other factors add to the complexity of petrophysical evaluations these include: alteration of petrophysical properties in certain zone f multiphase flow regimes. The new tool is also more compact to pass through intervals that have high dog legs. In this paper we will briefly

for the simulation of the formation reservoir-fluid flow during UBD. The model incorporates discrete consideration of the well with appropria t for the main storage below. The second Mishrif layer unit 2 (M9 & M8) is a fairly high porous peloidal packstone to grainstones sequence

y delivers a more accurate characterization of the reservoir. In this paper we link traditional and novel fluid analysis methods to build a mor eferentially lower in the oil column in accord with the Boltzmann distribution. Relevant fluid features in this case the asphaltene concentrati ow steady state damage /stimulation skin effect and non-Darcy flow coefficient. In the specific case where the deliverability performance of and only slight adjustments to the initial strategy have been necessary to achieve a recovery factor greater than 40% at the end of the platea ds to extremely depleted reservoirs alternating with layers with virgin zone pressures. As a consequence the depleted layers face a significa

were used for microfracturing (stress tests) at several sand and shale formations. The stress tests were performed by isolating 1 m of format uccessive integral transforms to the governing equations and to the associated initial and boundary conditions. Thus a complex phenomeno regional evacuation constraints imposed. To achieve this history-matched numerical reservoir models were first run within the framework of n the development of two fields with heterogeneous thin shaly sand sequences where potential sand discontinuity exists. The fields are loc leading to final recommendation. Various lift technologies were considered to replace the existing gas lift system accounting for fluid prope two main re-development components. The first component aims to beat the natural production decline curve via the implementation of a m mode with dual string arrangements.ï¿½ Most strings require artificial lift due to low reservoir pressures and viscous fluid properties.ï¿½ Ga ubstantial amount of hydrocarbons. Optimal well placement is a requirement for these very thin reservoirs in order to drain them in a cost e n from offset wells.ï¿½ Seismic impedance indicated that the target area comprises of beds with high degree of lateral and vertical heteroge project to test the remaining 39 gas wells in the area by leasing compressors. This was done to reduce capital cost take advantage of hig reservoir production completion and drilling software. Linkage between the disciplines is close and conducted iteratively operating in par ssity of flaring associated gas if no appropriate compression facilities are available. Metering and surveillance facilities as well as reservoir m ivided in two sections: the first section involves the reservoir model using a reservoir simulator which includes the representation of the ICV e for simulators and external FM algorithms. Any black-box simulator or algorithm may become a part of the system by simply adhering to th is used to calculate the optimal amount of lift gas to inject into each well based on static boundary conditions at the reservoir and processin ed 5000 bopd. However a drastic decline in reservoir pressure caused the evolution of a large secondary gas cap and a steeply increasing ve the strategies for production enhancement opportunities identified by the standard screening exercises in a brown field and (ii) how to op

strate the advantages of using the SRM and IAM technology. The optimization process is performed using a SRM able to run a simulation ru with field production well below the original design capacity of the production system and surface facilities. Hence further development opti ompression power or pump capacity for example could impose significant limitations over the well and surface network performance that c d on stochastic concepts. Clusters have been deployed because of its established advantage in improving performance which in this case t s (SSDs). In the past few years more and more horizontal wells have been drilled and completed with expandable sand screens and premiu

he best cost effective solution.ï¿½ ï¿½For that purpose general optimization and gas lift allocation models have been built and applied for K y sands and to reduce water coning in thin remaining oil columns. Horizontal drilling best practices were applied during well planning and dr performance based on â€œpresent-state analyses. In doing so the program has produced some of the highest productivity wells in the fie emaining reserves. The outcome of a reserves evaluation depends on the amount and quality of the data the knowledge and experience o e service provider share information on reservoir uncertainty. The presence of multivariate reservoir uncertainties typically makes such valu

his paper shows how thin oil rims faulted reservoirs and those with highly variable structure were able to be developed more efficiently. By r n reduce the volume of attic oil. Generally the location of the top reservoir is visible on seismic but with significant sub-seismic variations in ults in an irregular well placement pattern as it attempts to conform to both time-invariant reservoir properties (e.g. permeability field which ntact. Based on a comparison of downhole pressure data with data from simulation models the operator concluded that a connected aqui rves.ï¿½ Further it provides a comprehensive method to develop a production forecast for a potential sidetrack.ï¿½ It also presents a set of High resolution geological models together with reservoir simulation models using parallel computing allow a more sophisticated workflow to verall flow throughout the reservoir. The gradients of NPV over the lifespan of the reservoir with respect to flow rates in the pseudowells are roduction regime is described. The initial stage of oil production is considered before SC reaches the production well. The model accounts ake into account superposition effects in multi-well and multi-rate scenarios. Notably regarding fractured wells we are able to accurately m d wells where fractures can have infinite or finite conducting properties. Using the principle of superposition our model fully accounts for inte calculation of the prior covariance matrix (or its inverse) can be time consuming and memory intensive. We propose a fast and robust ada quations needs to be efficient for large-scale applications. We propose an efficient and fast approach for sensitivity calculation based on th

ld be quite different yet they are not completely random. In spite of their differences there are characteristic geological patterns which occ

energy interaction with over-burden and under-burden rocks.ï¿½ The solution procedure and the treatment of phase transition to achieve s mount of CPU overhead. This general formulation approach was developed as part of a next generation reservoir simulation project (DeBau equences from the bottom up and produces from multiple formations. Wells are placed close to the oil-water contact sufficiently far from th

s required the simulation of special wellbore dynamic behavior specific to horizontal/multi-lateral wells. It is a significant challenge to capture

sed. The last three techniques-type-curves require good understanding of the reservoir model as well as the parameters controlling the well sure broken-gel viscosity yield stress formation damage and fracture conductivity on low-permeability-gas-reservoir production with studi on-Newtonian characteristics was rarely taken into account before and is the subject of the current paper. For this purpose an enhanced fracture length conductivity orientation etc. This project investigates the modeling and interpretation of pressure transient responses of m â€™t completely account all phenomenon within reasonable computational time. New approach for simulation of multiphase multicompone erfacial slip is calculated using a displacement discontinuity (DD) method. An interface crossing criterion (Renshaw and Pollard 1995) is use nology has enabled us to run numerical models with nearly the same speed. Although analytical methods have been continuously improvin is paper the same problem of non-Darcy flow in a vertically fractured well is revisited for the cases of rate-controlled drawdown tests. We a he number of production logs and duration of production period on the accuracy of the results. Introduction The process of inferring reservo the dimensionless productivity index for improved fracture stimulation design and evaluation. Other issues investigated in this work were th remained impossible and optimum pumping schedules were typically established by trial and error within a given reservoir. The present pa perforation misalignment angle cement/formation properties stress contrast and fracturing fluid parameters. The model developed has a and other methods to determine the factors controlling and related to fracture spacing in the Lisburne formation northeastern Alaska. By c

s at different parts of the reservoir. The dynamic behavior of pressure and production performance from few wells (total seven wells) produc ny assumed distribution of injection profile along the length of the well including injection profile that is uniform skewed toward the heel or e novel concept of the injectivity productivity index (IPI) has been developed to consider a pair of wells comprising an injector and producer In particular analysis of the reservoir production behavior and the fluid contact movement over time is essential in narrowing the uncertaint when uncertainty on reservoir pressure and PVT data is significant. In this work two different methodologies are proposed. First a sensitiv etering units) and instrumentation may have an adverse influence on the accuracy of production WC injected water and formation pressur ecies distribution. Results also show that there are at least two main rotating cells at steady state: one in the gas cap and one in the oil col rned in constructing experimental designs and using response surface models to interrogate the experimental design outcomes. After exte

scretization scheme is applied to reservoir simulation on 3D structured grids with distorted geometry highly anisotropic media and discontin rally fractured reservoir and of the flow picture in the near wellbore zone in general. Introduction Near wellbore zones are very important are composite curves can be generated from properly designed laboratory experiments on representative cores or by history matching fine grid n the structural geometry of faults. The integration of historical production data and well-test permeability into geomechanical fracture mode

model. The dual porosity system is modeled by using two coupled grids: one for matrix and one for fracture. The interaction between the two nctions. Fracture permeabilities can differ in orders of magnitude which results in very different flow velocities in different parts of the reser omplex fractured reservoirs. The multiscale solver approximates the flux as a linear combination of numerically computed basis functions de

In particular the true predicted oil production lies within the band of predictions generated with the RML method and is not biased. We also

ork has been conducted using finite difference simulators which are handicapped with regard to these calculations in that numerical disper

mposed into a set of coarse-grid cell values and a set of solution details which indicate the smoothness of the solution. This decomposition model allows for receiving phase equilibrium curves and other thermodynamic functions in analytical form thus it achieves the thermodyna ce indicators of existing wells derived from historic dynamic data (fluid production rates pressures etc.) static data (reservoir properties et ealizations) is continuously updated to honor data without rematching data assimilated previously. Because of these features the method is these realizations could be quite different yet the responses are not completely random. In spite of their differences there are patterns w em. The effect of simulating flow in both the annulus and the tubing was investigated in two case studies involving ICDs: a synthetic case an

cannot be run in isolation. A multiple reservoir simulations coupling controller that dynamically apportions global production targets among d o Archie's law this simple model has only two parameters: An exponentï¿½ called the conductivity exponent ï¿½ and the water connectivity

arcy flow in porous media in general literature concerning the theoretical basis of the Forchheimer equation and experimental work on the ree water level 3) significant shifts in the measured pressure potentials between the lower and upper part of the transition zone 4) gradie inal reservoir pressure was in the range of +/- 7300 psi; however the past decade has seen a marked decline in both pressure and associa orizontal stress (Sh).ï¿½ In the case of deviated wells a stress-tensor diagram defines Sh direction with reasonable accuracy provided wel y.ï¿½ Participants felt that maturity in itself made a challenge for deployment and enforces the need for effective Change Management. De d oil in Russia has not already reached its peak level and that it will increase above the current production rates because of improvement o ea in the mid to late 1970â€™s. Alaska North Slope (ANS) and UK North Sea oil production rates were approximately equal in 1980 but U dels but the input data requirements are far greater. Typically in the modeling papers little information is included on how the input data is o

and the intervals contributing most to the water production were isolated. Water cut was significantly reduced. In some wells the saturation a Venturi-based flowmeter with a gamma ray source and detector. Real-time data were used to optimize the settings of the downhole chok ted in the short string section of the dual completions. The monitoring of the water breakthroughs and finding the bypassed oil became cruc mini-spinners and optical gas and array resistivity water holdup sensors provided a viable logging alternative with a 40 000 ft cable specifi

ed psi of formation pressure and borehole stability indicates that the wells must be drilled with oil base mud. In the course of several penetr ed psi of formation pressure and borehole stability indicates that the wells must be drilled with oil base mud. In the course of several penetr itecture requires below packer installation of the gauges which in turn increases the risk of leakage in the electric lines of the system. In this fluid alters as the sample is brought to surface from the high-temperature and -pressure conditions downhole owing to acid gases and salt d valuable not only for production monitoring but also as an investigative tool for larger-scale problems such as compaction subsidence de ated with a newly developedï¿½ location technique based on S-wave back-azimuth. While originally a couple of hundreds of induced events and productivity underperformance for wells. Various methods have been used to evaluate fracture height prior to the fracture treatment. Th

The acquired data shows that large temperature gradients exist across the wellbore during startup and early production which is consisten s wells that produce liquids whether they are produced directly from the formation and/or condensed well fluids water and hydrocarbons. T as wells that produce liquids whether they are produced directly from the formation and/or condensed well fluids water and hydrocarbons. n without initially performing a wellsite operation to lift the tubing shoe above the reservoir requiring either a workover rig or a snubbing unit. hin the oil sample along with the known location of each tracer downhole allows qualitative information to be generated about fluid flow in ics basis and flow loop tests are discussed. Introduction Well monitoring surveillance and problem diagnosis are critical parts of the produ

n for improvement or optimization would be taken based on this data. However the answer to questions such as "how good is the decision loop publications vary hugely with changing inclination. The ability to measure low oil rates and small holdups in this stratified flow is determ n. Over a period of six months (Nov. 2006-May 2007) 127 static bottom-hole pressure (SBHP) surveys 26 pressure buildup (PBU) tests (in production decline a chemical treatment to remove suspected emulsions and polymers during drilling was conducted. Immediate post trea ization is identifying candidates and to recognize potentials we need to have efficient reservoir/production data. Because the whole proces lanning and procedural design as well as real-time operational and interpretational support. It is becoming increasingly critical for operating l model to analyze permanently installed distributed temperature measurements. By modeling a range of typical flowing scenarios we demo s another region near the heel of the well although the area is too far from the microseismic observation well for any associated microseism he gravel pack is completed the fiber responds to the reservoir temperature plus the effect of Joule-Thomson warming of the flowing oil cau veloped to pass power and data from the upper to the lower completion. In a recent subsea deployment in the SouthEast Asia such a coup tion from core and dynamic measurements and by integrating image logs with nuclear magnetic resonance (NMR) and conventional openh

ds this isnâ€™t a cost effective solution. Building non-parametric (Artificial Intelligence) production rate models based on pressure and temp g multiple spinners for revealing stratified velocities travelling inside highly deviated completions. Pulsed-neutron (PNL) technology provide

ost effective methods available to date for saturation monitoring as being the deepest through casing measurement in terms of radial investi maintenance by peripheral water injection also considered an important step in tuning simulator parameters and optimizing the Field Deve od front advance has been observed in different reservoir units. ï¿½It has been observed that water front has advanced much faster in the mines a coarse (3 to 5 m resolution) resistivity distribution from a basic initial static reservoir model built from logs. This study refines the mod is interest and activity level little attention has been paid to the CBM completion fundamentals. Perforating is a critical part of this process nd properly characterizing the cleats will help in determining which of these seams should be completed to optimize the production. In addit stress clastic rock adjacent to coal seams and allowing these induced fractures to connect and grow into the coal seams. This paper presen hemselves as high-fracture initiation and propagation pressures which lead to low injection rates and high treating pressures. These losses ved in isotropic rocks.ï¿½ Using finite element analysis (FEA) and numerical modeling with continous mechanics and transverse anisotrop ncreasing surface horsepower.ï¿½ Economics and logistics practically limit the pipe size to 2 7/8 in. for deeper wells and 3ï¿½ in. for shallo nd periodically mud log.ï¿½ While these tools can identify significant structural changes and hydrocarbon shows along the lateral they pro al properties for well positioning and reserve calculations. The seismic survey is not only interpreted for structure horizons and faults but als AGD pad are significant. Finding ways to use steam more effectively in these operations should result in increased production efficiency and represents 15% of total natural-gas production. Approximately 1.7 Tscf of this gas comes from more than 40 000 coalbed gas wells comple ulated their older vertical wells with demonstrable success. This success is providing compelling opportunities to enhance refracture treatm sure as well as fluid types such as oil or gas. To generate wormholes of various diameters and penetration depths different acid types and ect has completed a four-years operating cycle while continuously maintaining the field production rate with an acceptable ESP failure and r

om the wellbore is lost in the process and cannot be utilized for some other operation. This paper describes a new technique of artificial lift This goal was achieved through optimization of the development system and improved development of oil-water zone reserves and the res This paper explains why an openhole gravel-pack completion was the best option in spite of some challenges such as large vertical net pay ear full bore feature allows normal cementing operations to be preformed with a special cement wiper plug. A control line is connected betwe d. Sands have different oil retainer capacity and flow from clean to dirtier sands. The lower most units comprise of unconsolidated sands tha ï¿½ The produced liquids considered in the analysis can be water and/or liquid hydrocarbons. This paper presents an optimization techniqu ï¿½ The produced liquids considered in the analysis can be water and/or liquid hydrocarbons. This paper presents an optimization techniqu ails the process followed to achieve this milestone for the first time in Kuwait. A multi-disciplinary team consisting of Geology Petrophysics

e well was managed to improve and sustain oil production by eliminating water production. Monitoring the rate and the flowing pressure in re id-front movement. In this paper we address several technical issues related to downhole controls. We consider a single system comprisin d sustain oil production by eliminating water production by use of the variable-positions flow-control valve. Monitoring the rate and the flowin

mental model has been built for the purpose of studying the production performance of the abovementioned well configurations. Production es practical experience gained during the development and deployment of this system. Introduction During the completion process of a we ariables (EVs). Methods developed to facilitate EV factor collapsing are also discussed (the partitioning of levels of each factor into nonemp hort because of the high speed at which acid spends upon contact with the high temperature reservoir. The quest to increase the effective h r quality found in the southwestern edge of the field required stimulation to produce at economic rates. A hydraulic fracture treatment was p

elp suspend proppant in the slurry both during the fracture pumping and also during fracture closure. The primary goal was to be able to cre s linear gel pad stages with cross-linked proppant stages with or without the use of materials for fracture height-growth control (HGC). The Y eatments in an attempt to control excessive leak-off during the treatment. The vertical well treatments target several reservoir sub-layers wit previously only achievable with 3.6-4.2 kg/m3 (30-35lb/1000gal) gel loading in similar geological conditions.ï¿½ In addition to reducing dam g claims as to which one may be most appropriate. This paper compares four different flowback aids: microemulsion two water-wetting flow o 3D (P3D) hydraulic fracture simulator with a rigorous layered modulus formulation is used in this study. The fracture height calculated bas operating companies have been seeking other cost-control measures including reducing the number of additives in fracture fluids and min uring fluids. This paper describes the process to properly design fracturing fluids using flowback and produced water. The importance of flo o evaluate and compare well performance. Micro seismic data tracer logs and pump-in data were used to calibrate and constrain appropr ed by conventional frac-and-pack. When this procedure is followed the fracture is forced to propagate along the upper intervals. This novel materials. The case study clearly demonstrates the challenges encountered in the attempt to increase the fracture half-length in order to imp g agents in terms of flow distribution and uniform coverage is limited when it comes to treat such complex wells with long openhole intervals omics to the entire operation. The key fluid for treating high water cut wells is a Viscoelastic fluid that provides self-diversion from water to stages with a composite bridge plug have been applied in some cases with limited success. The time consumed in the completion operatio

untered unexpected reservoir challenges which has kept them from achieving their production targets. These wells require stimulation to re

ges posed by the Gandhar candidate wells. Earlier attempts to fracture wells had been unsuccessful. In addition the water bearing sand pos ve and analysis graphical design charts of the dimensionless productivity index and pseudosteady state shape factors for use in improved h

xtensive knowledge gained in Western Siberia can not be translated to the less frequent but well engineered and planned stimulation camp

e control line becomes pressurized and transfers this pressure to a piston in the valve immediately above. This piston squeezes a C-ring an Finite Element Analysis (FEA) was conducted to estimate the stresses in the cement and formation near the wellbore with sliding sleeve uring in an elastoplastic medium has been represented in the model as brittle hydraulic fracture growth in a quasielastic medium. The medi uctivity associated with the lack of polymer damage.ï¿½ In this paper laboratory test results for the new fluid are presented along with thr

urrence of water-bearing zones lead to the selection of foamed VES fluids.ï¿½ This technology was successfully applied in the Morrow San

tivity of wells and to mitigate the aspheltene deposition issue by allowing the wells to produce above the AOP. The option of acid fracturing w y 2006 which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stres ulic fracture treatment while the successive offset was completed via a single-stage fracture treatment.ï¿½ The evaluation tools utilized to de

ositions several milliseconds discrepancies between measured and modelled SH-P-wave traveltime differences may appear along the rece

ofile of a rock sample accurately and rapidly and used the instrument to characterize fracture surfaces after acidizing. The profilometer mea and fluid flow. Fracture azimuth is traditionally provided by the horizontal stress anisotropy from open hole sonic logging. Unfortunately in W a on propped fracture height as well as insight into propped fracture width. In this new technology a non-radioactive tagging additive is inco

es of medium- and low-permeability reservoirs. Some wells cannot maintain stable production rates and have either been shut-in or are on s velocity (hence: rate and flowing pressure) Ratio of free liquid rate to gas rate Stress on the proppant Type of proppant Thus a he Carter leak-off model do not apply in this zone. This work presents a fundamental study of fracture tip behavior in high permeability form d acid was implemented in the field. A short term production evaluation based on the initial production (post flowback) from these wells cou n fracture treatment in this case is more heavily weighted on the achievable Stimulation Index (SD) for a given set of reservoir parameters ncipal stress which is consistent with observed differences in the injection pressures. Introduction The effectiveness of hydraulic-fracture s this process is therefore a very vital task. In this paper we present a quantitative model to predict proppant flowback. The model is based o he associated pressure response in order to obtain an insight into the refracture process. The modeling results show that a refracture treatm acturing fluid is evacuated from the well and fracture being displaced by the oil and gas flow under the influence of pressure differential. Th HSA) combines the use of cross-dipole shear sonic analysis carried out before and after hydraulic fracturing and adequately supported by o

ow polymer concentration via leakoff and measurements of flow initiation gradients. The paper will discuss the experimental set-up and s e pressure limit of 3000 psi given by the Floating Production Storage and Offloading (FPSO) facilities. However the injection rate was decr re heights on the borehole wells together with a representative Mechanical Earth Model (MEM). In these mature fields an accurate evaluat he main fracture direction and by their length. Quantitative comparisons on fracture length width and injection pressure are made for sever an sector of the North Sea. Several papers have discussed this technology but so far none has presented a rigorous analysis or solution of h water-packs and shunt-packs. The experiences gained from these operations have now become part of BPâ€™s open-hole gravel pack b ethods of cementing a liner in place perforating fracturing and repeating the process for the number of stages required can be very time co ethods of cementing a liner in place perforating fracturing and repeating the process for the number of stages required can be very time co target reservoir is a clean sandstone reservoir. The horizontal drain is 1155 feet (ft) long. The reservoir permeability is ranging between 0.1 ows individual lateral testing allocation of production rates to optimize each lateral contribution and the overall commingled well rate. Along w he operation of the ICD is minimizing reserves left behind. If water breaks through in a well without ICD these hydrocarbons are lost and ca e ultimate recovery has helped optimize overall drilling completion and production costs. Electric Submersible Pumps play a key role in pro al lateral testing and allocation of production rates to optimize each lateral contribution and the overall commingled well rate. Along with rea certainty across a range of production scenarios. We assess the implementation of an intelligent horizontal well in a thin oil rim reservoir in ssure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from th

alculating the productivity of a laminated clastic reservoir and we illustrate the method with a field example from Malaysia. A single well pred duction. To accomplish this task a 3D full field model was created. First several 1D Mechanical Earth Models (MEMs) were developed. Th it serves the purpose of puncturing through the casing.ï¿½ This paper presents recent research that looks into the impact of perforating on ced method which cleans perforations with more efficiency than conventional static underbalanced perforating method. In addition a passiv ormation pressure and BHT followed by high CO2 H2S production and improper well clean up contributed in the increase of operational risk gnosis of these results indicated that the static underbalanced condition and the shaped charges used were not enough to effectively clean lso tends to be deeper. Deep-penetration perforating charges are required to perforate past the damaged zone. Experience indicates that u er rig to remove the completion prior to perforating is in many cases not cost effective leading to foregone opportunities to extend producti erforating technique utilizes a unique job design process and specificï¿½equipment to ensure the guns are detonated in the correct environ od because the mud cake invaded filtrates and particulate pore plugging are progressively removed at the vicinity of the sandface region; ( his paper outlines a solution to these challenges. For a CT perforation campaign in the South China Sea a CT string equipped with fiber op nditions of similar perforators. In this paper we analyze the failure modes of continuously phased perforators for both gas well and oilwell ap

were kept constant. For both rock types the reactive liner charges produced perforations with lower productivity than the baseline conventi is perforated using large diameter high shot density tubing conveyed (TCP) guns with deep penetrating charges shot underbalanced using fractures. Using the smart completion with the conventional rate testing (the plant's testing facility) required longer time to reach the best po as made to develop the field with horizontal openhole gravel packs for both producers and injectors. Fifteen production wells and eleven inje ted interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft. The typical production-casing str er light (50ï¿½ API) sweet crude oil. Hawtah field is a mature and depleted reservoir and in order to maintain economical levels of producti allowing unacceptable rates of sand production. The well was worked over and the tubing with eight control lines and a premium-sand-con well. This condition resulted in the closure of the well for high sand production. To restore production from the well current economic realitie

tion methodology in poorly sorted unconsolidated sands with high fines content in Brunei also indicates that the situation is not much differe age and fluid compatibility testing. To translate the robust design into a fluid system which can be applied effectively in the field a thorough

xpandable screens with annular barriers and blanks between each section of sand is the only completion option except in fine sand environ ong high angle openhole intervals without the need for alternative flow path screens but retaining the advantages of high gravel concentratio complete gravel-pack process and accounts for fluid flow and gravel settling in different flow paths. The presented simulator tracks the fluid gravel packing of the associated wells are thus introduced. A significant level of progress has been made in recent years towards overcom cuting the perforation packing job are presented. This study also discusses the current practices commonly employed in cased-hole gravel cuting the perforation packing job are presented. This study also discusses the current practices commonly employed in cased-hole gravel p ith optimal â€œstructural stability for the given inherent material strength of the formation rock can be achieved by targeting perforations in velopment and requirement for artificial lift increase drainage area and improve sweep efficiency. In the early stage of field development a ntrol and fines migration prevention. The proper candidate selection treatment design treatment execution production management and c

he sanding issues it was facing which involved prediction prevention monitoring and if required remediation activities. The first step in the ation of economic production and overestimates or underestimates of sanding risk increase the chances of serious economical loss. This r gly the model backed up by the core laboratory test data observations from core inspection and thin section analyses revealed the rocks t arious stages of the tests to simulate water cut. The failure and sand-production processes were observed and recorded using a borescope

wdown at which failure of the formation will start. A further development are models which try to predict the total volume which can be expe and 3) properties of drilling fluid and its interaction with shale formations. The likelihood of wellbore instability and sand production for the de stems have been used in Saudi Arabian fields in matrix acid stimulation and in leakoff control acids during acid-fracturing treatments. These fluidsâ€”an acid viscosified with polymer an emulsified acid system and an acid viscosified with surfactantsâ€”at elevated temperatures of igh solubility and highly fractured/vugular nature carbonate reservoirs in the Permian Basin show excellent response to acid fracturing trea ernating stages of polymer pad. These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity a ernating stages of polymer pad. These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity a ough coiled tubing and then with the viscoelastic diverting acid system bullheaded down the production tubing; production logs were acqui ed that much of the rock is weak and potentially prone to deconsolidation after acid stimulation. Weakening of the rock matrix often leads re times. This paper discusses the application of a new viscoelastic-surfactant (VES)-based self-diverting acid system for stimulation of mo ng Tubing Pickling Bullheading Diversion and Coiled Tubing placement were used. Stimulation of over forty wells utilizing different acid sys

cted optimum acid system placement and diversion techniques need to be applicable in the field in a simple manner without impacting the stimulation of the formation. Therefore opportunity exists to mix HCl with an organic acid to achieve productivity enhancement by optimizin

positive skin factors following the fracture treatments irrespective of the fluid system used. In at least one case a well stopped producing af s mechanical or chemical.ï¿½ Mechanical control of treating fluid placement can be accomplished by coiled tubing with an inflatable packer vity of the formation to wellbore fluids the impact of the wettability changes and near wellbore damage is not fully evaluated on all formation presented. Core samples from eight different carbonate rocks were selected for the study. Samples were characterized for mineralogy tex inting results and has led to a common misconception that restimulations â€œdonâ€™t work. Production statistics of a well alone may not ce of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence c e traditional polymer-based fluid. This VES-CO2 fluid system combines the benefits of viscoelastic surfactant-based fluidâ€”such as low for other important feature of the integrated solutions is a proper risk assessment based on available data. Often especially in old fields inform

The objective of the present field case study was to place the stimulation fluid equally throughout all intervals of the oil bearing layers while t cally and systematically examined by a dedicated team of ZADCO and Schlumberger technical professionals. The criteria used to judge the A derivative function is utilized to ascertain if the data contains any portion of reservoir-dominated flow. Two synthetic data examples are pre d in this paper provides a good basis for evaluating long-term production potential of horizontal wells exploiting tight and thin reservoirs with ate the completion efficiency. The field examples presented in the paper demonstrates the application of the production optimization metho l types and pressure regimes. A selective inflow performance (SIP) test was carried out during production logging (PL) jobs in some of these al (10 to 20%) but with the right mud it can reach 50% and in some cases 100%.ï¿½ Such well completions are referred to as limited-entry or minutes even if we have a perfect pressure gauge with 0.0 psi resolution. After the initial propagation pressure starts to diffuse or propag t in pressure transient tests and when a test is run how to minimize the downtime.ï¿½ The case studies presented here are for wells on el an methods represent our independent implementations of their methods based on the material presented in their papers not the original a

racture storativity and fracture conductivity. An infusion of geological knowledge helps reducing uncertainty associated with any well-test int ples for a number of decades. Many hardware technologies and interpretation methods have been developed to acquire better quality reserv dial extrapolated pressure (p*) and estimating AOFP. AOFP is an important gas well flow parameter and is used to determine the commercia evaluated different well testing & monitoring strategies based on multiphase metering use. A compact dual-energy gamma-ray Venturi mu rue evolution of the gas and condensate wells provide an in-depth view of the actual well performance. The evolution of the real dynamics

ws in high water cut and high gas volume fractions (GVF).ï¿½ Some meters can be unreliable in measuring oil rates in certain conditions wh this process had to be revalidated and the operational capabilities confirmed with all of the logistical challenge of this environment. A numb a wet-gas meter in 90 to 100% gas. The new interpretation model was developed for a commercially available multiphase flowmeter consis e wells were selected carefully to represent anomalies that need to be investigated for possible proactive actions. Some of these wells were

r. With the recent dedicated Gas Mode developed by Schlumberger it is now possible to test both gas and oil wells with the same hardwar The benefits of such a workflow can be summarized as follows: â€¢ï¿½ï¿½ Improved well test interpretation by using simulation models tha operties contacted in-place fluid and reserves. Our main objective is to introduce a new practical tool for the analysis/interpretation of the p may otherwise have gone unnoticed. In this paper we endeavor to reconcile the advances in well-test interpretation and in measurement te orehole conditions.ï¿½Numerical methods have been developed to interpret these measurements to offer distributed characterization of ma

ting engineering process evaluating the capacity of cement to provide short-term zonal isolation and providing measures that can be used model is then checked against the occurrence of breakouts using a mechanical earth model built along CRC-1 well. We conclude that the m &RTM) serves as a decision support tool. The major steps are (i) identifying the system and the sources of degradation through characteriz between systems. The integrated approach has been used to integrate multiple reservoirs with common and advanced surface facilities to tanding processes as well as designing appropriate injection or mitigation strategies. We present simulations of CO2 injection into saline a ory frameworks and standards for CO2 geological storage. The preparatory phase of the project involved a baseline geological site explora omoter Enhanced plant growth. The capture and storage of CO2 continues to accelerate as new projects are initiated and existing projects gic seismic logging drilling and laboratory test data. Such a model consistently describes ambient stresses fluid pressures and poro-mec

Subsea developments in combination with ERD wells can increase oil production and lower total development cost. The drilling progress w ormations also create limitations for push-the-bit rotary steerable systems to deliver the required directional performance to land wells. To o

ef which is located in Michiganâ€™s Otsego County. This field was discovered in 1974 by Shell and produced 2.6 million bbls of oil during it ceed 90% purity. Due to the high concentrations of CO2 some wells were shut-in 60 years ago others have been developed for CO2 prod can be employed. A production prediction model is critical to enhance the chance of success. The model used here employs a petrophy ½ Simulation studies show that reentry drilling through vertical wells can help break the condensate bank damage and significantly increas upon the effect of the component grouping for fluid characterization. A preliminary work consisted of reducing the original 14 components ide hoe. 2) Massive fractures resulting in loss circulation. 3) Uncertainty with fractures volume estimation. 4) Fracture shut-off in open-hole sect

erformed through-tubing with and without isolation packers. Two Candidate wells were having 6.5 open-hole size at approximately 4 200 m en multiple oil producer zones revealed the necessity of a complex thru tubing zonal isolation solution before performing the water shut-off so the economic cutoff limits for the wells in question. The reason for this type of water management is the lack of confidence in the water s Introduction Excess water production in oil well is always a cause of concern. There are many side effects of this bad water production: It a g layers. This paper will discuss the development implementation and results of an innovative solution for water shutoff that was engineere of these fields life cycle. As drilling technology advanced in the past years horizontal wells became the norm in many fields managed by Sa entry of most of the water was from the toe of the horizontal section. Based on economical and technical feasibility fiber optic telemetry ena All these elements adversely affect production assurance in deepwater systems and are key risk factors in assessing deepwater developme ns and measure droplets and ten conductivity probes were used to obtain phase distributions. This paper provides new experimental data dups and pressure gradients. A high-speed video system was used to observe the mixing status between oil and water and to determine th bility in the reservoir and the change of the choke performance cannot be correctly addressed.ï¿½Moreover the large number of uncertain surface network performance that could impact long term field management plans if they are not properly identified and solved. PEMEX E& two distinct layers of hydrocarbon deposits are considered marginal from reserves point of view; the upper deposit is a gas condensate lay uded pour point gel strength and shear-dependent viscosity measurements under both dead and live oil conditions. The wax deposition te the fluids to the laboratory for analysis. Both methods are compromised by the reactive nature of CO2 whose concentration can change si ncentrations in one zone to significantly high in others in the same field. In addition accurate quantification of CO2 from reservoir fluid samp

ed are initial producing gas/condensate ratio from the first-stage separator initial stock-tank liquid gravity in ï¿½API specific gravity of the in m a combination of laboratory experiments and elaborate calculation procedures using EOS models. In previous work we found that Whits posed to compartmentalization) which is key to the efficient economic development for many deepwater projects. ï¿½ Introduction In the eless unexpected fluid production such as water or excessive gas is an undesirable outcome. A formation tester equipped with an extra la es also trigger contacts migration and unexpected injection fluids channeling or breakthrough. A large number of Downhole Fluid Analysis ( properties from the measured data. These predictions can be used in real time to optimize the sampling program to help evaluate completio ree-component hydrocarbon phase in cases of black-oil/extended black-oil formulations. In turn compositional interactions are entirely neg g and reservoir compartmentalization analysis. This process is not limited to light fluid evaluation or sandstones. The combination of DFA F

rations. Gas and remaining oil saturation were obtained from 3D NMR analysis. Sampling lab results and real time analysis of gas composit S scavenging. Many days of flow may be required in order to sufficiently passivate the metals so that an accurate H2S concentration can be

formation testers (those from before 1990) although yielding comparable results had larger error bars because of system limitations in rep consistently applied the synergy delivers a much more accurate and robust picture of the reservoir and the fluids therein. In this paper we different types of formation fluids from the well logs alone. This paper presents challenges of fluid identification process during the explora as oil and water all in hydraulic communication. However the pressure testing did not indicate a gradient in hydrocarbon composition. Flu ntional approach to pressure gradient analysis and uncertainties in inferring fluid properties and contacts from pressure gradients. In this c Although these fluid complexities have been largely recognized conventional pressure-depth plot and pressure gradient analysis are still pe sampling. The technique provides real-time analysis of sample contamination. Methane detection is essential for condensates and lightly co

petroleum reservoirs through detailed pressure and fluid analysis measurements. With the correct understanding of fluid characteristics in t ates uncertainties in optical measurement and contamination into uncertainties in fluid properties such as color composition and GOR. Th ties from the measured data. These predictions can be used in real time to optimize the sampling program help evaluate completion decisi

ile and/or non-condensable hydrocarbon components is treated. Introduction Reservoir simulators require a robust means to evaluate both ulsions). Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the

itions is a significant advance that provides accurate fluid information for characterization of the reservoir flow assurance facility design pr ues of well control. Another important factor to consider if the dew point is close to the formation pressure is that pressure drawdown has to ation but some fundamental needs from operators were not addressed properly such as the ability to collect representative samples for ph entative fluid samples for analysis.ï¿½ The paper presents a solution to this problem and results obtained in number of well tests performed (both simple organic acids and polycarboxylic acids) with calcite. All of these models were described in detail and compared with each othe ted surface pressure is necessary to maintain the operational and economical advantages; however formation damage severely impacts th of soluble inorganic or organic carbonates and the reaction generates calcium carbonate particles. The resulting particles were characteriz tion performance of three new chemicals and two commercial products were evaluated under static conditions along with performance asse

ditions and different pH values. A power-law expression was proposed and verified for the precipitation rate of the naphthenate-soap particle rushed zone. This weakened damage zone is an important factor in crushed zone removal and in the onset of sand production. An essentia fill the perforation tunnel immediately after penetration of the rock by the shaped charge jet. Predictions of the required underbalance to re cale inhibitor and hydraulic fracturing treatment in Western Siberia. It allowed the operator to place significant amount of scale inhibitor with ale inhibitor in the Uinta Basin may show signs of scale buildup in as little as 30 days. The effects of the scale accumulation can be seen ev production.ï¿½However they may also be used to address other produced water management issues such as inorganic scale control.ï¿½ reline tools Strontium Sulphate scale requires special techniques to remove chemically and/or mechanically and present the most challeng is paper addresses is what has caused this reduction in sulphate concentration. The formation brine Mg/Ca ratio is < 0.1.ï¿½Over geolog e least correlation criterion ensures that there is a minimal effect of changing one parameter in one region to the responses from the other r hed model into a Dual-Porosity Single-Permeability (DPSP) streamline simulation model and history match results are improved. Based on . By incorporating streamline technology into existing and new reservoir development planning we are able to demonstrate significant bene me of the typical problem wells have been identified from the production data as well as well registries and their sector models have been ex atic surveillance solution that synchronizes the data collected daily in more than 200 wells. Conventional production tools including Nodal m easures the interwell resistivity distribution between observation wells at the pilots. Interwell resistivity data can be used to infer the water sa ed to monitor voidage replacement ratio (VRR) to provide a basis for pattern balancing. Extensive surveillance operations provides the data gh rates. Hybrid artificial lift technologies such as bottom-drive progressive cavity pumping which combine features of the ESP and the PC ased methods. The initial production of heavy and viscous oils can be accelerated by the adequate use of downhole heaters that by provid ability wettability salinity and initial water saturation were studied.ï¿½ Introduction Crude oils whose API gravity smaller than 20 are called injectors. The recovery mechanism is a combination of horizontal steam flooding between wells and cyclic steam stimulation of each of the d formation leading to high borehole tortuosity. It is significant to note that due to these difficulties one of the planned horizontal wells was s pproach includes the quantification and distribution of the evaporite minerals and porosity analysis of a possible dual porosity system and e ble formations. However for difficult conditions such as laminated formations or formations with low matrix permeability and formations satu

sure and increased exposure the reservoir. This paper discusses about comprehensive geological study identification of target oil pools w

on a new surfactant-based chemistry has been introduced. When mixed in brine it forms a high viscous gel. The gel maintains its viscosity

on and monitoring challenges in these lifted or pumped wells. Petroleos de Venezuela (PDVSA) at the opposite of Canada companies is cu

nventional sandstone acidizing fluids. The application of the fluid system is sandstone reservoirs with bottom hole static temperatures great mation logging suite followed by formation testing and downhole PVT sampling achieved using a wireline formation tester (WFT) that had a

al effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characteriza

orations may not have sufficient proppant transport capability to complete the treatment successfully. Varying treatment conditions such as wever none of them fully address all of the challenges discussed. This paper describes a detailed laboratory evaluation of an innovative s

y matching deliverability and transit testing. Included in the paper are equipment selection design development details installation proced hydrocarbon-producing zones in the Bach Ho field. A general discussion of reservoir properties and damage mechanisms is included whic anisms; (3) provides homogeneous dissolution of formation; (4) has a much lower emulsion and sludge tendency than conventional fluids he improvement in permeability is ascribed to the removal of carbonate minerals and soluble clays without secondary metal precipitation. S t over polymer-based fluid. Nevertheless VES were known up to now for their limitation to withstand elevated temperatures. Detail laborato e results show that chemical A5 gives the best wettability alteration at high temperature with minimum formation damage. The improvemen tainties in the thermodynamic models for formation waters at high temperature and pressure as well as uncertainties associated with the fla

system applied involves the use of a series of mechanical openhole packers deployed on the production liner with a frac port located betwe

rocess in a high-volume field development and the value of applying new technology to optimize the process until it reaches a â€œSMART ounts of acoustic anisotropy recorded. Increasing treating and bottom hole pressures with time observed in this study indicate fracture leng n will re-orient the stress field not only in the near well bore area but also in the far field. Theoretical modeling and world experience sugges semi-analytical pseudo 3-D geomechanical model was developed based on considerations of the conservation of injected fluid mass and t lyses determined the fracture geometry: fracture length fracture conductivity and permeability. The results were then used to calibrate a log

direct and indirect costs and the risks associated with offshore operations have traditionally been limiting factors in spreading this technology bility characteristics. Small reservoir pore throat structure and low permeability nature of the rocks makes normal gas production with conve eosteering tools and technology for precise lateral placement in the low permeability reservoirs in addition to a low fluid loss drilling fluid sys hing initial well performance. The model was calibrated with well and field performance data through 2006. The calibrated model was used der to: Evaluate production contributions based on backpressure Evaluate drainage area (from multiple production logs) Understand geo l assumptions were made to apply this technology in our study. Multiple models were generated using different upscaling scenarios and tec ained.ï¿½ Through production optimization modeling it is possible to assess the economic viability of completing and stimulating highly lam

Acoustic images and core was acquired in the early stages of the field development. After the invention of a micro-resistivity imaging tool it shore Abu Dhabi for ADMA-OPCO penetrated the main three reservoirs and presented a rare opportunity to address these challenges and production from a specific wellbore. Typically we characterize these hydraulically induced fractures in terms of fracture height length width and limits of pressure data applicability in this environment are set forth. In tight gas reservoirs new generation wireline tools which employ

the quality of WFT data acquired in low permeability reservoirs. Job design and planning has always been important for the proper acquisit with permanent pressure and rate monitoring for evaluation and real-time production enhancement. The optimization of operational practice gas prices have lead to potentially better economics for horizontal wells (Mulder et al. 1992). However research shows that in practice ma ies and also the study of the distribution of fractures in-situ (directly in the location of the deposition) with the integrated use of equipment a

tional open-hole point pressure measurements should help define accurate fluid gradients and contacts. However this procedure is inadequ

rmance is marred by exponential rise of water cut due to adverse mobility and lifting through ESP. Production is affected due to poor influx i

e process may not be applicable in which case a more detailed and robust process is required. The process of multicriteria decision-making le related to geological uncertainty performing reality checks making a decision and reviewing and evaluation of the judgments. Proper us wells drilled and the success and benefits realized by using long gauge PDC bits combined with a specialized short bearing pack motors n en pore body size and pore throat size. NMR is believed to reflect the former while the latter controls capillary pressure. Hence the applica reservoir characterization. The ERA was installed on tubing in a barefoot well rather than permanently cemented outside the casing as in p rved downhole by borehole imaging tool. The heterogeneous porosity map from the image tool is then converted into a single curve represe r understanding of process sedimentology that controls the reservoir properties of sands. The study area has been interpreted from Lower six wells including well logs borehole images cores and the regional knowledge of the basin. Structural and sedimentary dip analyses we is possible to detect gas liberation (bubblepoint) or liquid dropout (dewpoint) while pumping reservoir fluid to the wellbore before filling a sa netheless unexpected fluid production such as water or excessive gas is an undesirable outcome. A formation tester equipped with an ext direct impact on the production and water injection scheme of such reservoirs. The NMR data and image based secondary porosity estima oir-scale geo-modeling for improved oil-field development by means of a comprehensive interdisciplinary approach. The Jaipur area is ma ements are essentially seeing the same amount of invasion thus removing a major complication in conventional LWD interpretation. Introd ce. The use of a non-chemical radioactive source significantly reduces the environmental and operational risks normally involved with tradi

models (Simandoux Indonesian Waxman & Smits Dual Water and Effective Medium) due to the uncertainty in the different input parame uration models (Simandoux Indonesian Waxman & Smits Dual Water and Effective Medium) due to the uncertainty in the different input p g a fluid flow model in combination with array resistivity logs. Analyzing relative permeability in conjunction with formation permeability and c carbonate can have higher permeability calculated1 from flow tests as a result of fractures within the carbonate. Borehole imaging provid he log based prediction is overcome by including pore size distribution data from a combination of NMR and borehole electrical image logs. f clay silt and sand. We present the experimental set-up and the application of a novel method to calculate the thin sand fraction of a lamin

swept thick sands and might not be representative of the water in the unswept thin sands. As discussed previously NMR offers useful insi und to be more representative to true formation resistivity than the apparent phase shift resistivity thus can be used in formation water satu he reservoir. Meso-scale fractures can also be identified oriented and characterized (open vs. cemented) on high resolution borehole imag circumstances where significant formation solids and sand are mobilized deposition of suspended solids can result in the premature ending ddress factors leading to the development of drilling-induced features in a borehole and to explain why some fractures on the electrical ima or other form of data a variogram analysis followed by sequential indicator simulation method was used to derive a facies model between T

an distribution. As a result estimation of the hydrocarbon in-place and recoverable reserves can be grossly inaccurate and hundreds of mill ormation evaluation logs. They exhibit a silty lithology and fine grain texture and require high quality borehole resistivity images to characte xation time in shales is much faster than in the productive sands thin sand-shale laminations appear on NMR logs with the characteristic bi

ensor downhole and this static pipe measurement because downhole the drillpipe is subject to an environment that is not representative of

und horizontal wells and well patterns will allow an operator to (a) select candidate wells for fracturing (b) choose appropriate operating con servoir. For an isotropic medium there are two independent elastic parameters viz. Youngâ€™s modulus and Poissonâ€™s ratio.ï¿½ Ge well offshore Louisiana in the Gulf of Mexico (GOM). The logged interval spans 1 000 ft below the casing shoe. In addition the Modular Dyn re the deliverability performance of a vertically fractured well is considered estimates of the effective fracture half-length and average fractu re the deliverability performance of a vertically fractured well is considered estimates of the effective fracture half-length and average fractu re the deliverability performance of a vertically fractured well is considered estimates of the effective fracture half-length and average fractu he Greater Burgan field are the Wara Mauddud Burgan Third and Burgan Fourth sands. The deeper reservoirs--namely the Lower Creta d by fault propagation fold of a normal fault that located nearby the well. The main objective was to determine the structural geology feature special technique of BKZ logs processing 2) Spectral imaging and high-resolution inversion of the seismic data 3) structural analysis of th lain the present-day reservoir behavior. A uniform classification scheme of fracture types was devised and specific properties namely dens wells using a special technique of BKZ logs processing 2) Spectral imaging and high-resolution inversion of the seismic data 3) structural

ng and logging experimental setup and completion designs cleanup production profiles pressure transient buildup tests water injection an al fluid properties including fluid compositions in real time. In addition mini-DST or Interval Pressure Transient Testing (IPTT) can be carrie investigate possible nearby formation alteration followed by MDT*-multi-probe IPTT. ï¿½The Sonic Scanner dipole radial profiling showed

porosity value with less uncertainty in comparison to the one from conventional logging tools such as the Neutron the Density and the Son ds type and property log is still not widely used in the industry. Modern NMR logging tools can deliver â€“ in addition to conventional porosit We demonstrate the use of NMR data to calculate total and effective porosity and volume of irreducible water in productive reservoir sands e inaccuracies in the reported porosity. We investigate the influence of acquisition parameters inversion parameters and noise on the dete f NMR logging tools. The objective is to explain the basic measurement principles and interpretations needed to understand NMR formatio rophysical properties in certain zones near faults variation of tuffaceous material content formation damage invasion of drilling fluids zon dog legs. In this paper we will briefly review the new technologies available today for production logging with examples of evaluating horizo

nsideration of the well with appropriate time-varying UBD boundary conditions. Capillary forces which facilitate countercurrent imbibition of t packstone to grainstones sequence that is highly fractured at the upper 15 feet of the layerâ€™s â€œdual porosity system. The fracture cor

luid analysis methods to build a more complete interpretation of the reservoir fluids and provide greater insight into reservoir architecture. T his case the asphaltene concentration gradient are then integrated in a geologic model and used to predict crude oil properties and DFA lo ere the deliverability performance of a vertically fractured well is considered estimates of the effective fracture half-length and average fract ter than 40% at the end of the plateau phase. However recent infill drilling allowed for the first time an investigation of recovery efficiency in the depleted layers face a significant overbalance while drilling with an oil-base mud system. Given these complexities fluid identification

performed by isolating 1 m of formation using the dual packer module of the wireline formation tester (WFT) and creating a hydraulic fractur ditions. Thus a complex phenomenon can be modeled using some valid simplifying assumptions with sufficient accuracy for the purpose o were first run within the framework of an infill well-location optimization software package. Then drilling constraints were imposed with drillin discontinuity exists. The fields are located in the Intra-Latrobe formations of the Gippsland Basin offshore Australia. Accurate field descriptio ft system accounting for fluid properties well depths productivity index and economic benefit.ï¿½ Ultimately ESPs were selected. A rigoro curve via the implementation of a massive infill drilling program; the second component aims to maintain production through the integration and viscous fluid properties.ï¿½ Gas lift is the artificial lift method used in the field. The field gas source is supplied from a nearby field and irs in order to drain them in a cost effective manner. Conventional well placement has met with limited success in stringers and thus resulte egree of lateral and vertical heterogeneity.ï¿½ The team decided first to drill the well utilizing a conventional logging while drilling (LWD) tool e capital cost take advantage of higher gas prices at the time and gather data for proper design and sizing of the compressors. Followin onducted iteratively operating in parallel instead of the common sequential and decoupled approach. The method has been successfully te llance facilities as well as reservoir management infrastructure are often basic and represent the technology available at the time of the pla cludes the representation of the ICVs through the multi-segment wells option; the second section represents the fluid flow in the well and p f the system by simply adhering to the FM interface which is discussed in this paper. The FM framework capabilities are demonstrated on ditions at the reservoir and processing facility.ï¿½ However as reservoir conditions change over time lift gas requirements will change as wi ary gas cap and a steeply increasing producing gas-oil ratio. The recovery factor for this reservoir stands at 25% significantly less than for th es in a brown field and (ii) how to optimize redevelopment plan for maximum recovery. First several increased well production opportunitie

ng a SRM able to run a simulation run in a matter of minutes and hence being suitable for sensitivity analysis and optimization. The optimize es. Hence further development options are being investigated for this asset.ï¿½A new nearby reservoir has been discovered. A reservoir surface network performance that could impact long term field management plans if they are not properly identified and solved. PEMEX E& ng performance which in this case translates into a significant reduction in simulation times.ï¿½ A modular workflow enables the various tas xpandable sand screens and premium screens. Most of the wells produce 10 000 to 15 000 BFPD using electrical submersible pumps (ESP

els have been built and applied for Khafji field as presented by Ghoniem et al1 2. This paper is an extension to the previous papers for Kh applied during well planning and drilling executions such as optimum well designs specific LWD/MWD tool selections low fluid loss drilling e highest productivity wells in the fieldâ€™s history. Oman has developed into a fast-paced fracturing arena with challenges similar to th ta the knowledge and experience of the evaluators and the methodology and workflow used during the evaluation process. Although we d certainties typically makes such valuations non-trivial and mostly intractable to current modeling schemes. We demonstrate the approach w

o be developed more efficiently. By reducing uncertainties about the reservoir the new technology helped optimize production eliminate sid significant sub-seismic variations in the top reservoir topography. Therefore to help optimal well placement Oilexco used a new deep and d erties (e.g. permeability field which may be nonuniform) and time-varying properties (e.g. pressure and saturation field).ï¿½As such it is a or concluded that a connected aquifer was present and estimated its size. This information was sufficient for the operator to know that the detrack.ï¿½ It also presents a set of criteria to select the most suitable well to sidetrack.ï¿½ Finally it allows leveraging all associated uncer ow a more sophisticated workflow to optimize horizontal well placement. Interactive well planning was initially used to optimize the horizonta to flow rates in the pseudowells are computed using an adjoint method. These gradients are used subsequently to approximate improving d oduction well. The model accounts for mass and heat transfer during the process of heavy oil recovery and establishes a significant correla ed wells we are able to accurately model the case of a finite conductivity fracture with non-Darcy flow as well as those of infinite conductiv tion our model fully accounts for interference effects between wells as well as multiple rate effects. Using solutions in Laplace space we are . We propose a fast and robust adaptation of the Bayesian formulation for inverse modeling that overcomes much of the current limitations or sensitivity calculation based on the Adjoint method to overcome much of the current limitations. First we use a commercial finite differenc

ristic geological patterns which occur in theses realizations. Such patterns could be extracted out by means of a mathematical tool called P

ment of phase transition to achieve stable non-linear iterations are discussed. The simulator is verified by comparing results from problem N reservoir simulation project (DeBaun et al. 2005) for â€œnext generation is the ability to accommodate fluid models currently used in rese -water contact sufficiently far from the gas-oil contact to reduce the effects of gas coning and channeling. Due to the large heterogeneity of

is a significant challenge to capture such behavior in a simulation model. This paper covers the following issues of horizontal/multi-lateral w

s the parameters controlling the well behaviour. To effectively use any of these techniques for forecasting future production it is imperative t -gas-reservoir production with studied permeabilities ranging from 0.005 to 5 md. The observed trends may not carry over to nanodarcy res er. For this purpose an enhanced three-phase cleanup numerical model is developed. A generalised non-Newtonian fluid flow model for of pressure transient responses of multiple hydraulic fractured horizontal wells (MHFHW) using a numerical reservoir model. After validating mulation of multiphase multicomponent steady state flow around the hydraulic fractured well is proposed. The approach is based on the split (Renshaw and Pollard 1995) is used to determine if the hydraulic fracture crosses a particular bedding plane during height growth. Two int ds have been continuously improving there are a number of parameters and effects which are not fully taken into consideration by these ate-controlled drawdown tests. We argue that the relationships between the apparent fracture conductivity and the true conductivity is a func tion The process of inferring reservoir/completion parameters from the commingled production data in a multistage hydraulically fractured g ues investigated in this work were the development of a general relationship for evaluating the pseudosteady state shape factor of a vertica hin a given reservoir. The present paper offers the required equations to correctly design transverse fracturing treatments or collinear fractu meters. The model developed has a limitation: it does not take into account the leakoff and pore pressure changes in near-wellbore zone d ormation northeastern Alaska. By comparing the RBF results with those from other ANN methods we find that the former method gives a

few wells (total seven wells) producing from this field show severe vertical discrepancy in pressure gas and water production. This adds a uniform skewed toward the heel or the toe or exhibits some discontinuity (e.g. leakoff into a high permeability streak or fracture). This pap comprising an injector and producer and replaces the use of II and PI. The IPI method helps to quantify waterflood issues in the presence o essential in narrowing the uncertainty in the parameters used in the model. In building the MB model two new techniques were proposed an ogies are proposed. First a sensitivity analysis was conducted using generated realizations of reservoir pressure and PVT data to evaluate jected water and formation pressure measurements. The problems associated with decision supporting instruments e.g. a 3D dynamic m n the gas cap and one in the oil column. Introduction Proper initialization is an important aspect of reliable reservoir simulations. The use mental design outcomes. After extensively applying these concepts for over 18 months in identifying the major sub-surface uncertainties ex

ghly anisotropic media and discontinuities in the permeability tensor. Simulation results are presented and compared with results from other wellbore zones are very important areas of the formation because they account for well deliverability. So the ability of precise and reliable sim ores or by history matching fine grid single porosity simulations.ï¿½ Kossack et al1 discussed this for water-oil systems.ï¿½ Since the displa y into geomechanical fracture modeling is a practical way to reduce such uncertainty. We propose to combine geostatistical algorithms for h

ure. The interaction between the two continua is modeled using matrix-fracture transfer functions. Until now there were no mathematical m ocities in different parts of the reservoir. This circumstance is advantageous for simulating the reservoir numerically with the streamline met erically computed basis functions defined over a coarsened simulation grid consisting of collections of cells from the geological model. Here

L method and is not biased. We also apply the ensemble Kalman Filter (EnKF) method to the PUNQ data set and show that this method als

calculations in that numerical dispersion effects can be orders of magnitude greater than physical dispersion. The introduction of chemical r

of the solution. This decomposition is recursively applied to the resulting representation until the coarsest mesh level is reached. From this orm thus it achieves the thermodynamic agreement of system and greatly reduces the required computing resources. Introduction In recen static data (reservoir properties etc.) and predicted data (simplified production forecasts). The wells are then grouped according to the sim use of these features the method is far more efficient for history matching dynamic data than automatic history matching based on optimiza eir differences there are patterns which occur in theses simulated responses. Such patterns can be identified by means of a mathematical s involving ICDs: a synthetic case and a sector of a North Sea field model. Results showing significant differences between the inflow profile

s global production targets among different reservoirs is used for the purpose.ï¿½ Compositions from different reservoirs are needed for su nent ï¿½ and the water connectivity parameter Cw. Under some conditions Cw can be equal to zero and the equation becomes identical to

ation and experimental work on the identification of flow regimes is reviewed. These areas of work provide insights into the applicability of th part of the transition zone 4) gradients implying an oil-density different to that which is expected. Supercharging effects are shown to be un decline in both pressure and associated production with todayâ€™s reservoir pressure averaging in the range of +/- 1800 psi. With such a reasonable accuracy provided wells cover wide range of deviation angle and azimuth The current study indicates that Sh in GoS is aligne effective Change Management. Deployment and Change Management are seen as the major challenges facing the creation of Smart Fie on rates because of improvement of economic situation in the country on the one hand and increasing of mature fields on the other hand. e approximately equal in 1980 but UK North Sea oil production has exceeded that of the Alaska ANS by more than 40% in recent years. T s included on how the input data is obtained. Because of this several papers have been published that have proposed ways to obtain the in

uced. In some wells the saturation analysis revealed that the stacked reservoir zones had variable levels of depletion and that the depletio e the settings of the downhole chokes to obtain a balanced production from the two horizontal wellbores. The completion provides the capa nding the bypassed oil became crucial for the field development. Understanding of the reservoir required logging these sections. The conve rnative with a 40 000 ft cable specifically manufactured to avoid splice induced weakness.ï¿½ This new logging technology detects and mea

mud. In the course of several penetrations of the Pinda formation a number of attempts were made to acquire representative formation sam mud. In the course of several penetrations of the Pinda formation a number of attempts were made to acquire representative formation sam e electric lines of the system. In this paper we describe an innovative and potentially reliable digital permanent monitoring solution that use wnhole owing to acid gases and salts coming out of solution and changes in water-chemistry equilibria. To obtain an accurate pH the meas such as compaction subsidence depletion and fines migration. This paper summarizes case histories from two fields where reduction in k ouple of hundreds of induced events per stage were mapped this new processing technique leads to the detection and location of several t ht prior to the fracture treatment. These methods can be as simple as height estimates based on sensitivity studies of fracture height growt

early production which is consistent with data from the observation wells. The injector-producer interval between SAGD wells was modele ell fluids water and hydrocarbons. This paper presents a sub-critical velocity analysis that has been implemented in a Pulsed Neutron prod well fluids water and hydrocarbons. This paper presents a sub-critical velocity analysis that has been implemented in a Pulsed Neutron pro er a workover rig or a snubbing unit. Running a slickline containing an optical fiber to the bottom of the tubing and producing the well up the n to be generated about fluid flow in the well. Chemical tracers for flow profiling were chosen for ENA03L1 an oil well intersecting a numbe agnosis are critical parts of the production business and many production parameters are monitored in the process. Of these flow rate and

s such as "how good is the decision?" or "how does the production engineer know that it is operating at the best performance possible?" is oldups in this stratified flow is determined by the physical distance of the production logging sensors from the top of the hole the geometric 26 pressure buildup (PBU) tests (including buildup tests for 2 active wells of the interference test program) and 3 interference tests were c was conducted. Immediate post treatment production increased to 2 200 bbl/d but dropped dramatically and stabilized at pretreatment rate on data. Because the whole process starts with formation inflow performance which determines how far we can go with this formation witho ing increasingly critical for operating and service company experts to remotely monitor and interpret WFT surveys in real time through Webof typical flowing scenarios we demonstrate that distributed temperature measurements respond to changes in production caused by deplet n well for any associated microseismicity to be recorded. The central portion of the well pair did not have significant deformation indicating omson warming of the flowing oil caused by the pressure drop (drawdown) in the near-wellbore region. Thermal mixing of the oil with flow fro in the SouthEast Asia such a coupler was attached to the top of a sensor bridle and both deployed as part of an openhole gravelpack com nce (NMR) and conventional openhole logs. The Mauddud carbonates are Early Aptian in age and consist of grainstones wackstones and

models based on pressure and temperature measurements has proven to be a valid and cost effective solution. Several processes are nec d-neutron (PNL) technology provides two services related to measuring water production: 1) the Water Flow Log (WFL) measures the spee

easurement in terms of radial investigation. The case study presented in the paper describes a successful water shutoff operation and impr meters and optimizing the Field Development Plan (FDP). Although there is strong water salinity contrast between the injected and original nt has advanced much faster in the highly permeable upper reservoir units as compared to lower reservoir units. In order to understand the rom logs. This study refines the model by adding variable resolutions to encompass the small-scale heterogeneities common to carbonate ing is a critical part of this process especially considering the PRB development migration from single-coal open-hole completions into mu to optimize the production. In addition through better seam characterization a technical basis for a preferred completion method (horizont o the coal seams. This paper presents several examples of the application of indirect fracturing for the stimulation of coal seams in the Roc igh treating pressures. These losses reduce the efficiency of proppant placement and stimulation. As drilling activity has increased over the mechanics and transverse anisotropic elasticity we provide insights on the stress concentration resulting from various conditions of stress (n deeper wells and 3ï¿½ in. for shallow wells using CT fracturing technique. This paper discusses the development of a technique which initi bon shows along the lateral they provide little stratigraphic information no natural fracture information and no stress information. One log structure horizons and faults but also analyzed for 3D property evaluations such as lithofacies distribution discrete fracture network and s increased production efficiency and improved financial return on these projects. By strategically placing steam injectors and by controlling t an 40 000 coalbed gas wells completed in at least 20 different basins. The remaining 1.0 Tscf comes from more than 40 000 shale gas wells unities to enhance refracture treatment coverage by targeting bypassed and ineffectively stimulated zones in additional vertical wells and e ion depths different acid types and volumes have to be used. Acidizing for optimized productivity requires first determining what is desired with an acceptable ESP failure and run life. So far 41% of the originally installed ESP systems are operating more than 4 years and 20% a

ribes a new technique of artificial lift which uses the concept of venturi to lift the fluid to the surface. A high velocity power fluid is used to cre oil-water zone reserves and the reserves contained in the zones with poor reservoir properties. The use of the horizontal completion allows enges such as large vertical net pays and high hydrostatic pressures of the sodium formate-based reservoir drill-in fluid and the sodium-po ug. A control line is connected between sequential valves. When the bottom valve opens the control line becomes pressurized and transfer omprise of unconsolidated sands that are thinly distributed. These unconsolidated sands are normally completed using cased hole gravel pa er presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellb er presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellb consisting of Geology Petrophysics Geophysics Drilling and Service Company was instrumental in utilizing state-of-the-art 3D seismic int

e rate and the flowing pressure in real time allowed producing the well optimally. The appraisal and acceptance loop of the completion has e consider a single system comprising the reservoir the completion the measurement and the feedback algorithm that adjusts flow-control e. Monitoring the rate and the flowing pressure in real time allowed for optimal well production. The appraisal and acceptance portions of th

oned well configurations. Production performance in both systems has been compared using numerical and physical model. Results have uring the completion process of a well certain operations are performed to enable the well to produce by creating an unobstructed flow path of levels of each factor into nonempty subsets of statistically similar response) so that an acceptable degree of parsimony is achieved. Ess The quest to increase the effective half-length of the fracture and enhance production led to the search for novel effective technologies capa A hydraulic fracture treatment was performed resulting in a 200% production increase. Over the past three years a stimulation program has

he primary goal was to be able to create a more even distribution of proppant in the created fracture while reducing the polymer requiremen height-growth control (HGC). The Yaraynerskoe oilfield case study documents the fiber assisted fracturing fluid technology used with HGC arget several reservoir sub-layers with varying degrees of porosity and permeability contrast. These layers are often divided by lithological st ions.ï¿½ In addition to reducing damage with lower polymer concentrations other advantages of degradable fiber usage were anticipated t microemulsion two water-wetting flowback additives and an oil-wetting additive. Careful laboratory testing was done to look at surface tensi y. The fracture height calculated based on uniform modulus versus layered modulus under the same in situ stress contrast conditions is co of additives in fracture fluids and minimizing disposal costs of produced waters by recycling and by using them as the base for completion an oduced water. The importance of flowback water analysis is highlighted for optimizing fluid performance downhole. Recent developments in d to calibrate and constrain appropriate fracture evaluation models (P3D and 3D).ï¿½ Rate-transient production analysis techniques togeth long the upper intervals. This novel technique is particularly useful for wells with water-producing zones near the bottom of the target zone he fracture half-length in order to improve the fracture treatment and the increasingly difficult task of simultaneously controlling fracture heigh ex wells with long openhole intervals (see Fig. 1). This paper illustrates a case history where an innovative technique was used on stimulatin provides self-diversion from water to oil bearing formations. At the same time this same fluid can be used on long intervals to divert matrix onsumed in the completion operations extends over weeks making wells uneconomical. In addition the prolonged time over which the frac

These wells require stimulation to regain their productivity but the available choices to achieve effective stimulation in horizontal open hole c

addition the water bearing sand posed a risk to successful execution; the fracture had to be contained within the zone of interest. High Pres shape factors for use in improved hydraulic fracture stimulation design and evaluation.ï¿½ Example applications of the dimensionless prod

eered and planned stimulation campaigns in the Volga-Urals basin. This paper presents a summary of the knowledge gained in Samara fie

e. This piston squeezes a C-ring and makes the ID smaller. At the end of the fracture treatment to the lower valve a dart is dropped during near the wellbore with sliding sleeve. FEA was used to adjust valve parameters that increased tensile stress in the cement and formation. U in a quasielastic medium. The medium resistance to fracture development is determined by variable apparent fracture toughness which is w fluid are presented along with three high-permeability case histories.ï¿½The estimated reservoir permeabilities were as high as 167 mD

ccessfully applied in the Morrow Sands in Eddy County of SENM.ï¿½ Fracture geometry analysis using surface treating pressures radio-ac

AOP. The option of acid fracturing was evaluated and found to be feasible to alleviate the problems. The paper details an optimization wor ure encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture. The new results prese ¿½ The evaluation tools utilized to determine the resultant fracture attributes include microseismic hydraulic fracture monitoring hydraulic fra

erences may appear along the receiver array. These traveltime discrepancies may then be misinterpreted as an effect of TI anisotropy and

fter acidizing. The profilometer measures the distance to the rock surface with a laser device that measures distance with an accuracy of 0 le sonic logging. Unfortunately in West Siberia at depth of 2500-3000 meters there is negligible tectonic and open hole sonic dipole did no n-radioactive tagging additive is incorporated into the resin coating of the proppant. This non-hazardous environmentally safe coated prop

d have either been shut-in or are on intermittent production. Factors may include low reservoir quality reservoir pressure and specific prod pant Type of proppant Thus apparent proppant permeability will vary with distance from the wellbore increasing towards the tip of the tip behavior in high permeability formations. We consider a steadily propagating fracture taking into account the flow within the fracture filtr post flowback) from these wells could not clearly distinguish between the benefits obtained from the viscoelastic diverting acid versus the in a given set of reservoir parameters and job sizes and on optimization of the flow rate and cumulative production. We discuss the reasons f effectiveness of hydraulic-fracture stimulations is critical for optimal economic production of tight gas. Deformation associated with fracturin pant flowback. The model is based on treating both the proppant pack and the reservoir as poroelastoplastic media. It allows for solid produ results show that a refracture treatment can undergo three distinct periods of fracture growth: ï¿½ï¿½ï¿½ï¿½Period I: Dominant orthogona nfluence of pressure differential. The quality of fracture cleanup determines in the long run the effectiveness of oil recovery measures. Frac uring and adequately supported by other logs (ultra-sonic cement evaluation) to infer the change in anisotropy; the latter anisotropy includes

cuss the experimental set-up and some of the artifacts that had to be removed prior to ensuring more reliable data.ï¿½The results highligh However the injection rate was decreased with increase in pressure and skin factor was found to be increased. Another observation was th e mature fields an accurate evaluation of the hydraulic fracturing operations is vital to enhance the effectiveness of the fracturing treatment jection pressure are made for several offset angles and lengths. Large increases in net pressure and associated increases in overall fractur ed a rigorous analysis or solution of the wellsâ€™ production from a gas lift perspective. This paper presents the basic theory behind auto of BPâ€™s open-hole gravel pack best practices. The paper details the completion evolution in BPâ€™s offshore Trinidad and Tobago high stages required can be very time consuming with added expense of removing the frac plugs with coiled tubing after the operations have be stages required can be very time consuming with added expense of removing the frac plugs with coiled tubing after the operations have be permeability is ranging between 0.1 and 5 millidarcies (mD) An engineered oil-based mud was used as drill-in fluid to prevent any damage overall commingled well rate. Along with real time monitoring sustainability of well rate will be extended by timely reacting to any changes to these hydrocarbons are lost and cannot be drained subsequently. This paper covers the design and application of new open hole sand fac mersible Pumps play a key role in producing from oil wells that are incapable of producing naturally at commercially viable rates. ESPs are c ommingled well rate. Along with real time monitoring sustainability of well rate will be extended by timely reacting to any changes to reservo ntal well in a thin oil rim reservoir in the presence of reservoir uncertainty and evaluate the benefit of using two completions in conjunction w opagation trends as expected from three-dimensional modeling. Introduction Since the inception of the hydraulic fracturing technique as a

ple from Malaysia. A single well predictive model incorporates logs rock and PVT data and formation tests to build a flow simulation model Models (MEMs) were developed. These 1D MEMs were calibrated using drilling data laboratory measurements well tests and other field m oks into the impact of perforating on matrix acid stimulation.ï¿½ Large scaled single-shot perforating tests were conducted using real shape orating method. In addition a passive gun-orienting system was used to optimize the perforating process and enhance the wellâ€™s perfor ed in the increase of operational risks and challenges. Several failures reported in the past was carefully analyzed to determine the actual ro were not enough to effectively clean the perforation tunnel and surpass the near wellbore damaged zone. Dynamic underbalanced perfora ed zone. Experience indicates that underbalance perforation provides better productivity compared to overbalance perforation. Although co one opportunities to extend production by perforating new intervals or reperforating existing producing zones. With casingless completions are detonated in the correct environment to createï¿½a dynamic underbalance immediately after perforating. Laboratory tests show how th the vicinity of the sandface region; (c) the crashed layer of the perforation tunnels is cleaned up. The existing pressure transient analysis me a a CT string equipped with fiber optic cable inside was used coupled with a bottomhole assembly capable of measuring both bottomhole t ators for both gas well and oilwell applications. Important factors concerning carrier serviceability are discussed. A method based on energy

oductivity than the baseline conventional charge. The reduction in the normalized Productivity Ratio (PRn) ranged from 29% to 66%. Furthe charges shot underbalanced using the classic â€œshoot and pull technique. After shooting before the guns are pulled the well is killed. P ired longer time to reach the best possible setting for the downhole flow control valves to achieve the optimum flow rate. Using the combina een production wells and eleven injector wells were drilled and completed in the field. As a result of the perceived technical complexity of th ft. The typical production-casing string for the wells consists of 10 3/4-in. casing with an 8 1/16-in. production liner. Drift diameter through th aintain economical levels of production a combination of several technologies is being applied. Due to the poor natural production from the ontrol lines and a premium-sand-control screen with shunt tubes were retrieved/fished from the well with minimal problems. The retrieved sc m the well current economic realities favored through tubing intervention. Two major types of through tubing remedial sand control solutions

that the situation is not much different from above demanding to lower production drawdowns while delivering production quotas.ï¿½ The d effectively in the field a thorough fit for purpose QA/QC system for all drilling and completion fluids was developed requiring extensive fl

n option except in fine sand environment. In this paper we present experimental data of shale stabilizer treated-brine and three open-hole vantages of high gravel concentration slurries. This is supported by 2 field case histories from a field in India where two gas wells were drill presented simulator tracks the fluid flow and gravel concentration from the wellhead down through the workstring crossover ports open-h de in recent years towards overcoming the challenges through new developments in fluids application tools and techniques. These develo only employed in cased-hole gravel packing to pack perforation tunnels and the potential limitations of these practices. Incomplete packing nly employed in cased-hole gravel packing to pack perforation tunnels and the potential limitations of these practices. Incomplete packing chieved by targeting perforations in the most stable direction with respect to the in-situ stress field. For high angle wells this normally equate e early stage of field development a reservoir failure was observed. A documented investigation indicated that the failure mode appeared to ution production management and co-ordination of all services are essential to the success of the screenless completion. In this paper the

diation activities. The first step in the SMS was to obtain a clear understanding of the cause and the mechanism for the sand production. Th es of serious economical loss. This raises the question of how accurate and reliable sanding predictions might be achieved without overcom ection analyses revealed the rocks to be extremely hard and strong and therefore highly unlikely to sand. These findings contradicted with ed and recorded using a borescope in real time. The results showed that the effect of water cut on perforation strength and sand productio

the total volume which can be expected to be produced by assessing the geometrical extend of the failed zone. These volumetric estima ability and sand production for the development wells was assessed using in-house developed wellbore stability and sand production predic ng acid-fracturing treatments. These surfactants were used to provide diversion during acidizing of vertical long horizontal and multilateral tantsâ€”at elevated temperatures of 200ï¿½F and 275ï¿½F. The acid fracture conductivity apparatus is similar to a standard API fracture co lent response to acid fracturing treatments. However inadequate diversion can leave substantial portions of the reservoir untreated. Differe s with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make ver rs with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make ver tubing; production logs were acquired after each treatment. The results from comparison of pre- and post-job production logs clearly sho ening of the rock matrix often leads to borehole instability and loss of wellbore integrity at the anticipated drawdown required to meet comp ng acid system for stimulation of more than 20 horizontal openhole wells in carbonate reservoirs in Kuwait. The application also deployed a forty wells utilizing different acid systems and procedures resulted in noticeably different production gains. The short and long term results a

simple manner without impacting the overall treatment logistics. The use of a hydrochloric acid system containing a viscoelastic surfactant s oductivity enhancement by optimizing the wormhole penetration and profile. Organic acids that are utilized in stimulating carbonate formati

ne case a well stopped producing after being treated. A core study revealed that despite the relatively low clay content in the formation the oiled tubing with an inflatable packer or with conventional straddle packers or ball sealers.ï¿½ Although mechanical techniques are very eff s not fully evaluated on all formations and fields. It is though evident that the volumes of wellbore fluids lost to the reservoir impact final prod ere characterized for mineralogy texture fabric porosity and density distribution using Nuclear Magnetic Resonance (NMR) Computed Tom on statistics of a well alone may not offer an effective restimulation candidate selection methodology. Other parameters such as high BHP (r the reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits actant-based fluidâ€”such as low formation damage superior proppant transport and low friction pressuresâ€”with carbon dioxide advantag Often especially in old fields information is out of date limited or unavailable. Combining together available pieces of information throug

rvals of the oil bearing layers while temporary protect the zones suspected to be mainly contributing with water from the stimulation fluid us onals. The criteria used to judge the usefulness of these logs was the present or not of communication behind casing as determined by the Two synthetic data examples are presented to illustrate the process. ï¿½Important contributions made in this study are as follows: The an ploiting tight and thin reservoirs with reservoir pressures close to the bubble-point pressure. Test data interpretation highlights successful de of the production optimization methodology in practice. The approach permits quantification of the reservoir and fracture properties on a lay on logging (PL) jobs in some of these wells and it indicated that the productivity index (P.I.) of the individual layers varies widely ranging from etions are referred to as limited-entry restricted-entry or partially penetrating wells. The transient flow behavior in these types of completions pressure starts to diffuse or propagates as diffusion and we start to observe pressure change at a given space and time above the pressu s presented here are for wells on electrical submersible pumps in various types of reservoirs across Latin America. The paper briefly discu ted in their papers not the original algorithms implemented by von Schroeter et al. and Levitan. Three synthetic cases and one field case a

nty associated with any well-test interpretation. The static properties of naturally fractured reservoirs such as fracture distribution fracture a loped to acquire better quality reservoir information. Dual packer wireline formation testers offer an alternative an additional way to selective is used to determine the commerciality of discovered prospects. We use a two step approach in establishing commingled AOFP of gas wel dual-energy gamma-ray Venturi multiphase flow meter (MPFM) was selected and placed under field trial to assess whether this technology The evolution of the real dynamics of the wells stabilization after a change of choke can be observed and monitored accurately with the in-

ring oil rates in certain conditions which leads to inaccurate estimation of the wells' potential and associated uncertainty in plans for product hallenge of this environment. A number of recommendations to prevent and mitigate the impact of the hydrate and document major benefits vailable multiphase flowmeter consisting of a venturi and a dual-energy composition meter. This combination results in excellent predictions e actions. Some of these wells were tested more than once to qualify and validate the production test results by the MPFM. Production test

and oil wells with the same hardware. The focus put in the past few years on a combination of robust and simple measurements (Venturi an ation by using simulation models that have been built using geological geophysical petro-physical and dynamic data. â€¢ï¿½ï¿½ Improv or the analysis/interpretation of the production data using a new diagnostic rate and pressure drop diagnostic function. This paper provides nterpretation and in measurement technology. Specifically we describe a new technique for differentiating well-test-pressure data the digita er distributed characterization of matrix permeability at various depths of investigation and effective fracture transmissibility. While streamin

oviding measures that can be used to predict the evolution of cement and casing over the long term. This paper will focus on an in-depth e CRC-1 well. We conclude that the maximum horizontal stress direction is oriented N141 +/- 9oE. To first order principal horizontal stress m s of degradation through characterization and system analysis; (ii) quantifying their criticity through modeling in terms of probability and sev n and advanced surface facilities to properly model the fluid flow behavior of the asset. Different injection variables facilities well completio ations of CO2 injection into saline aquifers with a fully compositional code that has been expanded and enhanced to include specific pheno ed a baseline geological site exploration and the drilling in 2007 of one injection and two observation wells as well as the acquisition of a ge cts are initiated and existing projects confirm the development scenarios.ï¿½ A crucial element in CO2 storage is reliable monitoring of CO sses fluid pressures and poro-mechanical and strength properties of the formations. It is linked to a reservoir model to achieve initial equil

opment cost. The drilling progress was 108 m/day from seabed to total depth according to the Rushmore drilling performance definition an nal performance to land wells. To overcome these drilling challenges a new point-the-bit rotary steerable system with a high dogleg capabi

duced 2.6 million bbls of oil during its primary production phase from a reservoir that may be typical of the other reefs in these trends. The r have been developed for CO2 production intended for industrial uses and some others as a source of gas lift operations in nearby heavy o odel used here employs a petrophysically consistent high-resolution permeability estimate fracture geometry prediction and formation pre nk damage and significantly increase well productivity. Sensitivity analysis of fluid type reservoir permeability lateral length and reentry d ucing the original 14 components identified in the existing Pressure/Volume/Temperature (PVT) analysis into 2 and 3 pseudocomponents an ) Fracture shut-off in open-hole sections. 5) Treatment execution under sub-hydrostatic conditions. To overcome these challenges a robust

-hole size at approximately 4 200 meter TD and 150 deg C reservoir temperature. The water cut were 95% in one well and 30% in the othe efore performing the water shut-off treatment. Temporary coiled tubing conveyed straddle system was created using two thru tubing inflatab the lack of confidence in the water shutoff remedial operations. From a survey carried out in the early 90s it was estimated that only 35% s cts of this bad water production: It adds to oil production cost by way of increased lifting separation and disposal cost. It leads to scaling for water shutoff that was engineered for the complex completion methods mentioned. The solution involves three key stages; the tempora norm in many fields managed by Saudi Aramco especially in the giant Ghawar filed the largest oil filed in the world. Some of these wells st al feasibility fiber optic telemetry enabled coiled tubing (CT) was selected for an accurate and effective way to isolate the water producing in in assessing deepwater developments.ï¿½ The production assurance risk factor can create game-changing impact on field development p per provides new experimental data on pressure drop holdup phase distribution and droplet-size distribution in oil/water flows that can lead en oil and water and to determine the flow patterns at various flow conditions. Quick closing valves were used to measure the phase holdup over the large number of uncertainties from reservoir to wellbore behavior that influence the performance of those advanced wells cannot rly identified and solved. PEMEX E&P San Manuel complex produces in excess of 276 mmscf/d and 13 100 BOPD from 10 fields (mostly g pper deposit is a gas condensate layer and the lower is a black oil layer.ï¿½ Because of marginal reserves mono-bore commingle productio oil conditions. The wax deposition tendency of the dead crude oil was also investigated. The experimental data were used for a case study t whose concentration can change significantly by reaction with formation waters mud filtrates etc. before reaching an analysis facility. Optim on of CO2 from reservoir fluid samples can be difficult especially if some water is also present in the collected samples. This is due to the n

y in ï¿½API specific gravity of the initial reservoir gas reservoir temperature and selected values of reservoir pressure. The dewpoint pres previous work we found that Whitson and Torp method for generating Modified Black Oil (MBO) PVT properties yielded best results when c er projects. ï¿½ Introduction In the past a presumption of fluid homogeneity in the reservoir prevailed. In part this assumption was made b tion tester equipped with an extra large diameter probe and two downhole fluid analyzer modules was used to identify reservoir fluids in new umber of Downhole Fluid Analysis (DFA) stations coupled with several DFA directed sampling stations throughout all interested zones towa program to help evaluate completion decisions and to understand flow-assurance issues. The petroleum industry has devoted much effo sitional interactions are entirely neglected or represented through simplistic empirical correlations. Such conventional models are deemed s dstones. The combination of DFA Fluid Mapping with pressure measurements has shown to be very effective for compartmentalization cha

d real time analysis of gas compositions are also compared for verification and confidence. ï¿½ Two field examples in low porosity/low mob n accurate H2S concentration can be determined. Wireline formation testers have historically been regarded as a non-viable alternative. In

because of system limitations in repeatability of both pressure and depth measurements. We developed a yield/temperature correlation to the fluids therein. In this paper we review two case studies in which we have combined multiple techniques for the assessment of compos tification process during the exploration/appraisal campaign in such reservoirs offshore Malaysia where the operator needs to gather as m ent in hydrocarbon composition. Fluid was sampled and analyzed in real time by a wireline fluid-sampling-analyzing tool string that included s from pressure gradients. In this contribution using several field examples we discuss and review formation pressure measurement techn ressure gradient analysis are still performed with traditional straight line regression schemes. This process may however be misleading as f ential for condensates and lightly colored crude oils; for such fluids the color buildup becomes difficult to detect but the high methane cont

rstanding of fluid characteristics in the reservoir reserve calculations and adequate development plans can be prepared. Additionally flow b as color composition and GOR. The output of the FCA is the probability that two fluids are statistically different. Real-time application of th am help evaluate completion decisions and understand flow assurance issues. The petroleum industry has devoted much effort to develop

uire a robust means to evaluate both the state of a multi-component multi-phase fluid and the vapor-liquid equilibrium (VLE).ï¿½ In contras samples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil/water emulsion

oir flow assurance facility design production strategies and defining reserves. The application of this new focused sampling technology is re is that pressure drawdown has to be controlled while pumping â€“ this is imperative in order to be able to sample the fluid at downhole r collect representative samples for phase-behavior characterization. Moreover metering accuracies has been questionable in many cases (a ed in number of well tests performed in Russia complemented with experiences from operations in other countries. This paper documents detail and compared with each other. The mechanism of calcite dissolution includes acid dissociation mass transfer and surface reaction. rmation damage severely impacts the injection trend. Conventional stimulation systems such as acid outsidephase emulsion and regular m e resulting particles were characterized using both light scattering and scanning electron microscopy (SEM). The reaction rate and size distr nditions along with performance assessment after aging. Both sea salt and pharmaceutical-grade sodium chloride were used in the tests. Al

ate of the naphthenate-soap particles. The parameters of the rate equation were correlated with respect to pH and temperature. This also a nset of sand production. An essential first step in modeling perforation clean-up is to characterize the extent and magnitude of both the perm s of the required underbalance to remove the damage zone or remove the comminuted fill are at best uncertain. In this paper we describe ficant amount of scale inhibitor within the propped fracture and into the adjacent formation. The case history delineates the detailed samplin scale accumulation can be seen everywhere from an exaggerated production decline to scale deposition on production equipment. This pa such as inorganic scale control.ï¿½ This paper describes the potential risks posed specifically to intelligent completions by scale deposi ically and present the most challenges to achieve complete removal. This work will describe ZADCO scale management strategy to monito Mg/Ca ratio is < 0.1.ï¿½Over geological time frames the reservoir rock and formation brine will come into chemical equilibrium the Mg/Ca on to the responses from the other regions. Further since the regions are least correlated with each other each region can be history matc tch results are improved. Based on field-wide streamline flow patterns map the field is divided into several independent regions. Within the able to demonstrate significant benefits and added value. This paper will conclude with an analysis and discussion of some of the results a nd their sector models have been extracted from the calibrated full field model. The vertical resolution for these sectors has been increased al production tools including Nodal modeling Turnerâ€™s equation Decline Curve Analysis or Pressure Survey were individually validated ata can be used to infer the water saturation distribution because of the sharply different electrical resistivity between injected water and oil b eillance operations provides the data necessary to monitor individual pattern balance watercut performance optimize areal sweep efficiency bine features of the ESP and the PCP systems have recently been successfully evaluated in the Orinoco belt to exploit extra-heavy oil rese of downhole heaters that by providing energy to the vicinity of the well decrease oil viscosity and increase the oil production rate. A conseq API gravity smaller than 20 are called heavy oil that can be produced by using thermal recovery techniques.ï¿½ In these techniques heat is clic steam stimulation of each of the horizontal wells in the pattern. Properly implemented HASD could be more efficient than classical cycli f the planned horizontal wells was sidetracked thrice after stuck pipe incidences and finally completed as a 30 deg deviated well with an AF possible dual porosity system and evaluation of permeability using a new porosity partitioning technique. Data used in this study includes c trix permeability and formations saturated with high viscosity fluids or fractured limestones application of a single probe technique is limited

y identification of target oil pools well design selection of fit for purpose technologies and the complete well placement cycle including de

s gel. The gel maintains its viscosity when contacting water and breaks down when contacting oil thus temporarily plugging the zones of hig

opposite of Canada companies is currently producing most of the Heavy Oil from cold and therefore non thermal production methods due to

ottom hole static temperatures greater than 200ï¿½F. Core flow tests demonstrated that the single acid system minimized the potential for p e formation tester (WFT) that had a dual packer to test a large area of open hole. Formation testing and sampling objectives were: reservoir

grading is sensitive to characterization methodology for some systems experimental data from a specially designed centrifuge system is e

arying treatment conditions such as mixwater composition and temperature tubular shear rate and transit time and reservoir temperature p oratory evaluation of an innovative solid-based acid fracturing system to address the above-stated limitations of conventional systems. Exte

velopment details installation procedures and â€œlessons learned after installation of the fully welded digital permanent down hole monito mage mechanisms is included which demonstrates the potential for stimulation and the associated benefits. The methodology adopted in t e tendency than conventional fluids as well as lower corrosion rate; and (5) stimulates sandstone reservoirs at high temperature by effectiv out secondary metal precipitation. Slurry reactor tests elucidated the kinetics of mineral dissolution in mechanically ground field samples. Tr evated temperatures. Detail laboratory studies proved that a novel VES high temperature (HT) version was also feasible for the given condi ormation damage. The improvement in water block removal after treatment with A5 is tested by injecting gas into brine-saturated cores at uncertainties associated with the flash process and possible precipitation of salts can propagate as errors into scale and corrosion models

n liner with a frac port located between each set of packers and a process of subsequent multistage stimulation of the entire interval.ï¿½ Th

ocess until it reaches a â€œSMART-factory-like workflow. With our new process new technology can be integrated with adaptive modificati d in this study indicate fracture length growth for each stage. 11 and 12 stages were chosen for the two well completion program based on deling and world experience suggest that the hydraulic fractures do re-orient under the influence of pore pressure changes because of fluid ervation of injected fluid mass and the mechanic interactions both between fractures and injected fluid as well as among the fractures. The ults were then used to calibrate a log-derived permeability and stress models. An advanced petrophysical analysis using these models impr

factors in spreading this technology to offshore applications. Sometimes the misplaced perception of hydraulic fracturing as risky and cost es normal gas production with conventional perforations very restrictive and will require proppant fracturing stimulation treatments to produ on to a low fluid loss drilling fluid system have resulted in significant incremental oil recovery that would not be produced by existing or addit 06. The calibrated model was used to forecast well performance estimate reserves; investigate optimal well spacing and infill-well patterns le production logs) Understand geological setting and production mechanism Detect scaling problems and optimize treatment solutions U different upscaling scenarios and techniques. The models were set up with the same boundary conditions (injector/producer pairs injection/ ompleting and stimulating highly laminated interval.ï¿½ In this paper we will show a case study from a South Texas tight gas sand field. Se

n of a micro-resistivity imaging tool it was used in combination with the acoustic imaging for integrated and enhanced formation evaluation w ity to address these challenges and implement a newly proposed solution. The tested intervals contain multiple thin zones which make it d erms of fracture height length width and conductivity. These fracture characteristics are estimated using a variety of techniques including neration wireline tools which employ extremely precise pretest mechanisms can achieve the required data acquisition objectives more effic

een important for the proper acquisition of formation test data. Several new options made available through the enhanced capabilities of the e optimization of operational practices and introduction of fit-for-purpose technologies enabled a production increase from an intermittent hu research shows that in practice many of these wells typically produce only 10 to 30% more than offset vertical wells. With costs more than th the integrated use of equipment and technology of formation micro-scanners and dipole sonic tools. This new approach consists on high

. However this procedure is inadequate to identify and characterize the transition zones. Supercharging capillary effects changing wettabil

uction is affected due to poor influx in tighter formations through conventional wells. This behavior is limiting the producing life of existing we

cess of multicriteria decision-making starts with eliciting judgment concerning corporate decision-making policy in particular identifying leve aluation of the judgments. Proper use of judgment elicitation techniques together with objective data analysis will lead to significantly better cialized short bearing pack motors not only in the quality of the real time and recorded logs but in the over all bore hole quality as well. Intro apillary pressure. Hence the applicability of NMR derived capillary pressure curves in carbonates has been questioned. In a well in a comp cemented outside the casing as in previous applications. This notable difference introduced particular issues in the ERA data acquisition an onverted into a single curve representing the secondary porosity. This secondary porosity log is added to the conventional logs as input of t ea has been interpreted from Lower to Upper Cretaceous. The major lithofacies identified are sandstone (massive laminated and cross-bed al and sedimentary dip analyses were performed both on borehole images and oriented full-bore core photos that provided at least twice as uid to the wellbore before filling a sample bottle. In this paper a new DFA tool is introduced that substantially increases the accuracy of the ormation tester equipped with an extra large diameter probe and two downhole fluid analyzer modules was used to identify reservoir fluids in ge based secondary porosity estimation recorded in this well were used for partitioning the porosity into micro meso and macro porosity.ï¿ ary approach. The Jaipur area is mainly characterized by a Tertiary terrigenous sedimentary sequence comprising of fluvial to deltaic depos ventional LWD interpretation. Introduction A new-generation LWD tool has been developed that integrates measurements of gamma ray p nal risks normally involved with traditional LWD tools. The data delivered by this service include not only the traditional measurements suc

ertainty in the different input parameters to each model separately. Both analytical and numerical error analysis techniques were used to dev he uncertainty in the different input parameters to each model separately. Both analytical and numerical error analysis techniques were used on with formation permeability and capillary pressure leads to new insights in log-based rock typing for comparison with Special Core Analys carbonate. Borehole imaging provided is a new way of the characteristics of reservoirs drilled with oil-base-mud. Complicated structures we and borehole electrical image logs.ï¿½ï¿½ This data is sufficient to partition the porosity according the pore size compute permeability an ulate the thin sand fraction of a laminated reservoir from NMR free fluid volume.ï¿½ The results of this method are compared to the sand co

ed previously NMR offers useful insights into the petrophysics of thin sand-shale laminations. Typically 1D high-resolution data is acquired can be used in formation water saturation estimation. An alternative measurement of formation fluid saturation is by pulse neutron (PN) afte d) on high resolution borehole images over the entire open-hole section. When combined with pressure transient analyses and production ds can result in the premature ending of formation testing and sampling jobs or require multiple trips into the well to acquire the required sam some fractures on the electrical images were also seen in the cores whilst others were not. This method allows differentiation between natu d to derive a facies model between Tayarat and Bahra Formation of Lower Cretaceous age. A volume extraction method was used to extrac

ssly inaccurate and hundreds of millions of barrels of hydrocarbons can be lost or fictitiously added in a reservoir model. An accurate reserv rehole resistivity images to characterize their geometry. The exploration well offers the best chance to evaluate the prospect but operationa NMR logs with the characteristic bimodal relaxation distribution. The thin laminations are often below the resolution of conventional logs th

onment that is not representative of the derrick (e.g. varying drilling mechanical conditions and temperature changes). Here we demonstra

b) choose appropriate operating conditions to avoid early water breakthrough and achieve better reservoir sweep (c) choose the right time w ulus and Poissonâ€™s ratio.ï¿½ Generally logging data consisting of density compressional and shear wave velocities are used to estima g shoe. In addition the Modular Dynamic Tester (MDT) (ï¿½Schlumberger) minifrac tests were performed at three depths in shale thus yiel cture half-length and average fracture conductivity may be derived from the analysis.ï¿½ In cases where the multi-rate deliverability tests a cture half-length and average fracture conductivity may be derived from the analysis.ï¿½ In cases where the multi-rate deliverability tests a cture half-length and average fracture conductivity may be derived from the analysis.ï¿½ In cases where the multi-rate deliverability tests a reservoirs--namely the Lower Cretaceous Ratawi and Minagish limestone--and the Jurassic Marrat formation contain significant oil reserves ermine the structural geology features (i.e. fractures) its orientation and the diagenetic features (i.e. vugs) using formation micro imaging to mic data 3) structural analysis of the field 4) construction of the reservoir properties model 5) construction of the fracture distribution mode nd specific properties namely density orientation apertures and porosity of each fracture type wherever applicable were generated. The on of the seismic data 3) structural analysis of the field 4) construction of the reservoir properties model 5) construction of the fracture dis

sient buildup tests water injection and subsequent production of all injected water and collection of all relevant data that include time-lapse ansient Testing (IPTT) can be carried out at Downhole Fluid Analysis (DFA) stations to provide more representative and accurate mobility/p anner dipole radial profiling showed some radial property change at several zones.ï¿½ The altered zone radial extent was quantified. ï¿½Th

e Neutron the Density and the Sonic where there is a need to assume variable values of density and transit time for the matrix. To corrob €“ in addition to conventional porosity and permeability information â€“ a continuous fluid log of oil gas water and OBM filtrate (OBMF) at m e water in productive reservoir sands and in shales to validate the petrophysical model. We also present a method based on NMR analysis n parameters and noise on the determination of porosity from NMR data. A key focus is on fluids exhibiting the extremes of T1 T2 or D suc needed to understand NMR formation-evaluation techniques and to discuss a few examples of these methods. Introduction of pulsed-NM mage invasion of drilling fluids zones with viscous oil low and variable formation water salinity. During this study a two step petrophysical g with examples of evaluating horizontal wells with barefoot smart completions diagnosing water entries flow profiles and fluid break-throug

cilitate countercurrent imbibition of the drilling mud into the formation are taken into account. The production rates during UBD depend on ual porosity system. The fracture corridors within the layer improve permeability thereby making it a good potential for horizontal well placem

insight into reservoir architecture. This leads to improved understanding of structural history hydrocarbon migration and entrapment reserv edict crude oil properties and DFA logs for all hydraulically connected sections of the reservoir. Predicted and newly acquired DFA log data m acture half-length and average fracture conductivity may be derived from the analysis. In cases where the multi-rate deliverability measurem nvestigation of recovery efficiency in swept but previously un-drilled parts of the reservoir. Higher than expected the remaining oil saturatio ese complexities fluid identification and pressure measurements have a significant impact in resolving key uncertainties of such reservoirs.

FT) and creating a hydraulic fracture by injecting drilling fluid using the downhole pump. Combination of the wireline dual packer and stand sufficient accuracy for the purpose of test design or interpretation. The rationale for the initial and boundary conditions deployed here which constraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-rese re Australia. Accurate field description and reserves estimation was critical for the outcome of the full field development project. Logging-wh ately ESPs were selected. A rigorous selection process identified three trial wells on the crest of the shallow â€Ãâ€™ sands.ï¿½ These w in production through the integration of Improved Oil Recovery (IOR) methodologies. A multi-disciplinary team studied and recommended t e is supplied from a nearby field and compression facilities in Bokor.ï¿½ However with ageing compressors and fluctuation in gas availabili success in stringers and thus resulted in low production figures. PeriScope has persistently proven that a proactive well placement technolo onal logging while drilling (LWD) tool to geosteer the well in the horizontal section.ï¿½ The LWD was unable to trace the sand while drilling a zing of the compressors. Following studies were carried out as part of the project: 1) Compare the response of wells in high-pressure a he method has been successfully tested in a brown field with 165 stacked reservoirs. Reserves increased significantly compared to the offs ology available at the time of the platform installation. The current paper discusses optimization techniques using dynamic simulation with a sents the fluid flow in the well and pipelines from the couple point to the sink including the artificial lift system (Electrical Submersible Pump rk capabilities are demonstrated on several examples involving diversified production strategies and multiple surface/subsurface simulators gas requirements will change as will operating constraints.ï¿½ The design of the processing facilities will need to accommodate these cha s at 25% significantly less than for the best reservoirs in the field. After more than a decade shut-in secondary and tertiary recovery metho reased well production opportunities were identified based on the standard methodology. Then to reduce uncertainties and risks associate

alysis and optimization. The optimized WAG injection and production cycle is then carried forward to an IAM in order to accurately determine ir has been discovered. A reservoir simulation model has been constructed for the new discovery. This second reservoir is a gas condensa rly identified and solved. PEMEX E&P San Manuel complex produces in excess of 276 mmscf/d and 13 100 BOPD from 10 fields (mostly g ular workflow enables the various tasks in an integrated study to be assigned to project team members facilitates the flow of task outcomes g electrical submersible pumps (ESPs). In these commingled completions the water cut rises from a few percent to 80% to 90% within the

ension to the previous papers for Khafji Field cited above.ï¿½ The optimization approach presented in this paper is based on a field-wide pr D tool selections low fluid loss drilling fluids real-time geosteering data monitoring and the cleaning of the pay zone during completions were arena with challenges similar to those encountered in the tight gas fields of south Texas in the United States. Well productivity is highly d e evaluation process. Although we deal with dry gas reservoirs the challenge lies in the difficulty of solving relatively simple equations that re es. We demonstrate the approach with an example involving a decision to be made for a marginal asset on where to place an injector well re

ed optimize production eliminate sidetracks and minimize well construction cost and risk. One of the main challenges of maintaining a horiz ent Oilexco used a new deep and directional LWD measurement in the Bottom Hole drilling Assembly in order to map the relative position o d saturation field).ï¿½As such it is a well placement strategy governed purely by reservoir drainage objectives rather than infrastructure cons ent for the operator to know that the well would not be needed as a water injector and to justify a sidetrack from the downdip location to an ows leveraging all associated uncertainties by linking the economic analysis to a Monte Carlo simulation which is critical for a sound manag nitially used to optimize the horizontal well location within the 3-D reservoir model ensuring a smooth trajectory near placement to the curre equently to approximate improving directions (i.e. directions to move the wells to achieve an increase in NPV) on the basis of which impro and establishes a significant correlation between production rate and the dynamic of SC evolution. The model that was developed was com as well as those of infinite conductivity. The generality of our method allows any continuous function of position and time to be used to treat ng solutions in Laplace space we are able to model naturally fractured reservoirs wellbore storage non-Darcy flow factors as well as consta omes much of the current limitations and is well suited for large-scale field applications. Our approach is based on a generalized travel time we use a commercial finite difference simulator ECLIPSE as a forward model which is general and can account for complex physical beh

eans of a mathematical tool called Principal Component Analysis. These characteristic geological patterns can then be combined in differen

by comparing results from problem No. 3 of the Fourth SPE Comparative Solution Projectsï¿½ and a cyclic steam injection case with other c e fluid models currently used in reservoir simulation as well as models that will be developed in the future. With this general formulation app g. Due to the large heterogeneity of reservoir properties in different layers complexity of the geological feature and the dynamics within th

ng issues of horizontal/multi-lateral well simulation. Special horizontal well flow dynamics exist that are associated with undulations in the w

g future production it is imperative to determine the dominant flow regime from the production data. This paper focuses on concepts that e may not carry over to nanodarcy reservoirs such as the gas shales. The three phases included gas water and fracturing gel. Introduction non-Newtonian fluid flow model for porous media is derived and implemented in a reservoir simulator capturing the yield stress of commo ical reservoir model. After validating the numerical model using an analytical solution applied to a simpler reservoir/well model complex res The approach is based on the splitting the thermodynamic and hydrodynamic problems of multiphase and multicomponent fluids flow. It is plane during height growth. Two interface properties of a coefficient of friction and a shear stiffness required by the model are defined an y taken into consideration by these methods and therefore result in unrealistic production forecasts. These factors include non-Darcy effe ty and the true conductivity is a function of time and that the restrictions on variables can be relaxed. In addition the issue of flow converge a multistage hydraulically fractured gas well involves the solution of an inverse problem. Such inverse problems for production analysis are t eady state shape factor of a vertically fractured well in a closed rectangularly bounded reservoir along with a review of appropriate applicat cturing treatments or collinear fractures with short perforation intervals. As compared to previous models it only replaces the line source an ure changes in near-wellbore zone during fracturing treatment. However we believe that this limitation is not essential as it does not affect th find that the former method gives a substantially smaller error than many of the alternative methods. For example the errors in predicted fra

s and water production. This adds another challenge in the dynamic modeling and leads to dividing the field into three main reservoirs that a eability streak or fracture). This paper also presents comparison of temperature profiles obtained with the analytical solution given in this pa y waterflood issues in the presence of poor mobility. This paper will cover three main areas: The simple background theory of IPI. The con o new techniques were proposed and successfully used: moving linear regression for generating the input pressure for the MB model pro pressure and PVT data to evaluate their effect on material balance calculations. Second a more robust approach was proposed using exp ng instruments e.g. a 3D dynamic model or reservoir engineering analysis used for elaboration of recommendations. This paper illustrate able reservoir simulations. The use of the Gibbs segregation condition generally cannot provide reliable initialization in hydrocarbon reservo e major sub-surface uncertainties explaining observed production performance and in prescribing additional development options for fifteen

nd compared with results from other two-point and multipoint flux approximations. 1. Introduction. The two-point flux approximation (TPFA) the ability of precise and reliable simulation of the fluids flow inside of these zones is very important to forecast the production profile and fie ater-oil systems.ï¿½ Since the displacement of oil from vugs by gas involves very different mechanisms from water-oil systems and is very c mbine geostatistical algorithms for history matching with geomechanical elastic simulation models for developing an integrated yet efficient

now there were no mathematical models of dual porosity three-phase compressible flow for streamline simulators. To realize this model it w numerically with the streamline method [1 4 6 7 8 9 11 17 18 21]. Indeed in the streamline method the transport part is solved along a set o ells from the geological model. Here we use a mimetic multipoint flux approximation to compute the multiscale basis functions. This metho

a set and show that this method also gives a reasonable quantification of the uncertainty in performance predictions with an uncertainty ra

rsion. The introduction of chemical reaction calculations into streamline simulation models presents a very significant opportunity for improv

st mesh level is reached. From this multi-resolution representation of the solution an adaptive grid is constructed by thresholding of negligib ng resources. Introduction In recent years the streamline simulation methodology has attracted a lot of attention from the research and the re then grouped according to the similarity of their KPIs. The production profiles of the wells within the same group are combined to a type c history matching based on optimization algorithms. Moreover the set of realizations provides a way to evaluate the uncertainty in reservoir entified by means of a mathematical tool called Principal Component Analysis. The classical face recognition technique is then used to ra differences between the inflow profiles of horizontal wells with and without packers in the annulus are presented. Introduction Advanced we

ifferent reservoirs are needed for surface facility design and operation. ï¿½Compositional simulation is prohibitively computationally expens nd the equation becomes identical toï¿½ Archie's law in its simplest form (n = m = ï¿½). However in the general case the model is fundame

de insights into the applicability of the Forchheimer equation to conventional oilfield flow tests for proppant packs. Models for flow beyond th rcharging effects are shown to be unimportant to the discussion. Both wells drilled with water based mud and oil based mud are considere range of +/- 1800 psi. With such a marked reduction in reservoir pressure coupled with complex geology intricate vertical and deviated fra dy indicates that Sh in GoS is aligned along two major trends. The main NNE â€“ SSW trend with average orientation of N10degE exists in ges facing the creation of Smart Fields. During the Forum it became apparent that companies do not have a common vision of what a tru of mature fields on the other hand. The paper presents an overview of EOR field experiences in former Soviet Union and Russia for the las y more than 40% in recent years. The UK North Sea and ANS share similar areal sizes and other similarities but differ in several key area have proposed ways to obtain the input data in particular the mechanical parameters of the set cement. Because typically these papers ha

ls of depletion and that the depletion was not necessarily related to the distance to the original oil-water contact. In these wells the water sh s. The completion provides the capability to control and measure in real time flow contributions from both laterals and is the first installation d logging these sections. The conventional wireline logging was regarded as a difficult and unsafe operation due to complicated nature of th logging technology detects and measures stratified flow and lower flow rate fluid entry than conventional axial symmetric production logging

cquire representative formation samples but were stymied due to either excessive drawdowns that corrupted the fluid or by excessive conta cquire representative formation samples but were stymied due to either excessive drawdowns that corrupted the fluid or by excessive conta manent monitoring solution that uses the state-of-the-art welded system that aims to eliminate the risk of leakage. Included in the paper ar To obtain an accurate pH the measurement must be made downhole at reservoir conditions. Unlike potentiometric methods in which foulin from two fields where reduction in kh over time and increasing skin over time led to a more in-depth study of the reservoir geomechanics. T e detection and location of several thousands of events per stage. This increase of mapped microseismic events provides following insights ivity studies of fracture height growth for different fluids pumping rates etc. using a derived rock stress profile within a fracturing simulator

al between SAGD wells was modeled with a thermal reservoir model to understand the influence of fluid viscosity water cut and permeabili plemented in a Pulsed Neutron production logging technique in order to have the capability to reliably evaluate the formation inflow into wel mplemented in a Pulsed Neutron production logging technique in order to have the capability to reliably evaluate the formation inflow into we ubing and producing the well up the annulus for a short period allows the temperature profile of the well to be measured and therefore the L1 an oil well intersecting a number of fault blocks in the south of the Enfield field to: Provide direct proof of fluid flow from different fault the process. Of these flow rate and fluid type (phase) are two of the most fundamental measurements. Over the years many instruments h

the best performance possible?" is not easy because a reference for comparison is needed. Performance efficiency can be defined as the m the top of the hole the geometric size of the sensors and the measurement resolution of the sensor at high water cut. These specificatio am) and 3 interference tests were conducted. Each interference test involved one active well and 3-6 observation wells. This paper describ ly and stabilized at pretreatment rates soon after. Formation of emulsions and asphaltenes were believed to be the cause of the production r we can go with this formation without having production problems such as; water conning erosion induced by solid production etc. In this T surveys in real time through Web-based systems. The importance of meeting all rock and fluid data-acquisition objectives cannot be over nges in production caused by depletion in individual reservoir layers. We also show that in addition to flow rate determination layer pressure e significant deformation indicating poor steam conformance during this warm-up phase. A comparison of the temporal response of the mic Thermal mixing of the oil with flow from below only occurs once the flow has passed through the sand-screen wire-wrap. Thus a direct meas part of an openhole gravelpack completion. Standard packers and gravel-pack service tools were used. The system became activated whe sist of grainstones wackstones and mudstones deposited in a ramp setting. Observations from production logging tool (PLT) and productio

solution. Several processes are necessary to measure and validate oil production at the well level as follows: Virtual Rate Measurement (V Flow Log (WFL) measures the speed of the water flow while 2) the Three-Phase Holdup Log (TPHL) confirms the available multi-phase ho

sful water shutoff operation and improved oil recovery from the Bahariya formation in the western desert Egypt. The well was drilled in early st between the injected and original reservoir water in this field resistivity-based methods can be affected by variations in the reservoir rock oir units. In order to understand the horizontal and vertical fluid flow behavior an inverted 5-spot water injection pilot pattern is being implem erogeneities common to carbonate reservoirs. Incorporating geological data derived from seismic attributes core descriptions and detailed coal open-hole completions into multi-zone cased-hole completions Whereas the industry has substantial knowledge of perforating charac eferred completion method (horizontal well hydraulic fracture open hole or cavity) can be ascertained. High cleat density in coal seams is a stimulation of coal seams in the Rockies. This paper evaluates production results fracture pressure analysis as well as micro seismic result illing activity has increased over the past couple of years fracture-initiation problems are now a substantial source of expense and downtim g from various conditions of stress (normal and reverse faulting) and material properties.ï¿½ We also provide a simplified methodology for f velopment of a technique which initially eliminates the CT friction limits on transferring energy to coalface.ï¿½ A large-volume pressure puls and no stress information. One log evaluation tool that is being used more frequently in horizontal wells is the formation imager.ï¿½ It produ on discrete fracture network and stress field. On the operation side longer horizontal wells are drilled and massive multistage multicluster steam injectors and by controlling the amount of steam injected it may be possible for these results to be achieved. A study was conducte m more than 40 000 shale gas wells completed in five primary basins. While the pace of coalbed-gas drilling is starting to slow shale gas c nes in additional vertical wells and even some horizontal wells. Because of the heterogeneous nature of this unconventional gas reservoir t res first determining what is desired wormhole pattern. Currently the numerical models focus on computer rendered wormholing pattern by ating more than 4 years and 20% are operating in the range of 3-4 years run life. The cumulative average run life of operating ESPs is 2.7 y

gh velocity power fluid is used to create drawdown at the throat of a surface venturi and this pressure drawdown is transmitted downhole by e of the horizontal completion allows development of the reserves which would have never been possible to produce with vertical wells beca rvoir drill-in fluid and the sodium-potassium formate completion brine. Compared with other alternatives such as cased hole gravel-pack o e becomes pressurized and transfers the bore pressure to a piston in the valve immediately above. This piston squeezes a Cring and make ompleted using cased hole gravel pack. In order to select optimal completions it required both identification and estimation of the radial ext depth design that will keep the wellbore continuously unloaded of produced liquids yet result in the maximum gas recovery possible under depth design that will keep the wellbore continuously unloaded of produced liquids yet result in the maximum gas recovery possible under lizing state-of-the-art 3D seismic interpretation LWD resistivity at bit real-time imaging and distance to boundary measurements to place t

ceptance loop of the completion has been closed by having this well completed put on production and tested. Approval of the concept was k algorithm that adjusts flow-control devices with quantitative models for each of the components. Both pressure and flow-rate control syste praisal and acceptance portions of the completion process were achieved when this well was completed put on production and tested. The

al and physical model. Results have proven that the dual-lateral well configuration accelerates the oil recovery by 90% in the early stage of y creating an unobstructed flow path for the oil and lifting it to the surface. This process is intended to realize actual production that measure egree of parsimony is achieved. Essential definitions necessary for preliminary data structure are also covered. We demonstrate the practi or novel effective technologies capable of achieving this goal. One such technology is the solid acid system which was field tested for the fir ee years a stimulation program has evolved with improvements in candidate selection performance and predictability. Future plans include

le reducing the polymer requirement for the fracturing gel slurry. A secondary goal was to use slugs of the fiber to bridge at the fracture entr ring fluid technology used with HGC materials as a significant improvement in HGC solution. This technology combination additionally enha rs are often divided by lithological streaks that make vertical communication challenging. Hence in many instances acid fracturing ends up o dable fiber usage were anticipated to be proven after proppant fractures geometries and production parameters (including PI and Jd) evalu ng was done to look at surface tension and contact angle for each flowback aid using the recommended concentrations. Imbibition and drain situ stress contrast conditions is compared. The results are analyzed and explained based on fracture mechanics fundamentals as well a g them as the base for completion and fracturing fluids. Because of the uncertainty of the produced water impurity composition and concen downhole. Recent developments in proper selection of fluid additives and viscosifiers for slickwater and crosslinked fluids are discussed. W oduction analysis techniques together with statistical data techniques were incorporated to evaluate stimulation techniques (proppant & flui near the bottom of the target zone because it induces selective growth of the fracture along the upper intervals and mitigates the risk of gr ultaneously controlling fracture height growth. In addition to the risk of the post-frac increase in water-cut the uncontrolled fracture height gr ve technique was used on stimulating a naturally completed horizontal well that experienced a production drop to zero shortly after the com ed on long intervals to divert matrix stimulation treatments from stimulated to un-stimulated intervals or from high permeability intervals to prolonged time over which the frac fluid remains in the formation before being flowed back often affects well productivity. This paper descr

stimulation in horizontal open hole completions have traditionally been limited at best. Previous stimulation attempts with coiled tubing have

within the zone of interest. High Pressure and high temperature operations posed additional challenges that had to be addressed. For Frac pplications of the dimensionless productivity index and pseudosteady state shape factor solutions developed in this work are provided for fra

the knowledge gained in Samara fields of the Volga-Urals basin with emphasis on the results obtained and highlighting the differences with

ower valve a dart is dropped during the flushing operation. This dart lands on the C-ring and seals the bore inside the sliding sleeve. Pressu ress in the cement and formation. Unstressed cement tests were then conducted on a variety of sliding sleeve valve shapes to verify the F parent fracture toughness which is a function of the fracture length and is found from the analysis of energy dissipation in the plastic zone. rmeabilities were as high as 167 mD and reservoir heights ranged from 30 -90 feet.ï¿½In all cases the entire propped fracture design was s

surface treating pressures radio-active tracers and production data showed height growth containment and longer effective fracture half-le

he paper details an optimization workflow and integrated evaluation process that improve the treatment performance. Detailed fluid system the fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. ulic fracture monitoring hydraulic fracture surface treating pressure-history matching and tracer and production log interpretation in additio

ed as an effect of TI anisotropy and use of such an anisotropic model may lead to the mislocation of the detected fracture(s).ï¿½ The unce

sures distance with an accuracy of 0.001 in. The rock sample is mounted on a servo-table that automatically moves the sample in selectable c and open hole sonic dipole did not provide obvious fracture orientation. Fracture height growth affect mostly fracture job size and cost. He environmentally safe coated proppant can be transported and applied without any of the restrictions associated with radioactive tracers. O

reservoir pressure and specific production conditions. A reliable methodology for selection of candidate wells for stimulation treatments wa ore increasing towards the tip of the fracture where liquid ratio and velocity are lower. This variation of permeability was explicitly modele ount the flow within the fracture filtrate leak-off across the fracture faces and kinetics of filter cake growth. The flow within the reservoir due coelastic diverting acid versus the in-situ gelled acid.1 However the wells treated with viscoelastic surfactant based acid did clean out in a s oduction. We discuss the reasons for and alternatives to conductivity impairment within the fracture; fracture cleanup width changes cond Deformation associated with fracturing results in small-magnitude microearthquakes that can be used to image the stimulated fracture netwo astic media. It allows for solid production from the proppant pack but also from the formation itself in case the fracture was created in a very ¿½ï¿½Period I: Dominant orthogonal fracture propagation. It exhibits a rapid pressure increase due to the stress increase at the tip of the o ness of oil recovery measures. Fracturing fluid being left entrapped in the fracture decreases its effective oil collecting area. Thus stability a otropy; the latter anisotropy includes the creation of a propped width. While the methodology has been used in carbonates very few cases

reliable data.ï¿½The results highlight the crucial role played by the filter cake and present new data that would significantly change the com creased. Another observation was that the formation was not fractured at pressures exceeding the expected closure stress. Possible expla ctiveness of the fracturing treatments and improve the production results. Multiple hydraulic fracturing operations were evaluated in five diffe ssociated increases in overall fracture volume are shown which can result in increased treatment costs slower fracture growth and shorter esents the basic theory behind auto gas lift and how to apply it. The components of the theory are well known and commonly used in nodal ™s offshore Trinidad and Tobago high rate gas fields and the relative performance of these completion types from sand control and well prod d tubing after the operations have been completed. When drilling a horizontal well there are two preferred completion options. First the ho d tubing after the operations have been completed. When drilling a horizontal well there are two preferred completion options. First the ho drill-in fluid to prevent any damage to the reservoir. A carbonate particle-based filtercake was used to create a thin and reliable filter cake. W by timely reacting to any changes to reservoir and well conditions. Using variable positions flow control valve early water breakthrough can pplication of new open hole sand face completion architectures equipped with Inflow Control Device technology (first in Ecuador) in Block 15 mmercially viable rates. ESPs are commonly used in wells which cannot lift the oil to surface due to low reservoir pressure high water cut y reacting to any changes to reservoir and well conditions. Using variable-position flow control valves early water breakthrough can be del sing two completions in conjunction with surface and downhole monitoring. Three control strategies are tested. The first is a simple passive hydraulic fracturing technique as a means to improve productivity of oil and gas wells the hydraulic fracturing community has determined c

sts to build a flow simulation model at the resolution of the petrophysical analysis. By calibrating the high resolution flow model with dynamic ements well tests and other field measurements. The calibrated rock mechanical properties from the 1D MEMs were distributed in the 3D ts were conducted using real shaped charges to perforate carbonate core samples under downhole conditions.ï¿½ Acid was then injected i ss and enhance the wellâ€™s performance. The new technique was applied in 2003 to horizontal Well-1 which was drilled by in the Tadrar y analyzed to determine the actual root cause prior to coming up with the proper job design and operational procedures. CTU with 1.5 CT r e. Dynamic underbalanced perforating coupled with high performance charges was selected as the technology that would improve product verbalance perforation. Although conventional underbalance perforation can be performed using pipe-conveyed or tubing-conveyed perfora ones. With casingless completions even this option is not available. A downhole orienting and imaging platform has the unique capability t rating. Laboratory tests show how this fast acting dynamic underbalance created across the perforated interval is used to cleanï¿½perforati isting pressure transient analysis methods to determine the skin were almost exclusively developed with an assumption that the skin factor able of measuring both bottomhole temperature internal and external CT pressure and in addition casing collar locator. The primary object scussed. A method based on energy conservation is used to establish a swell model to predict the post-detonation conditions of the perfora

n) ranged from 29% to 66%. Furthermore the reactive liner charges produced characteristic â€œdynamic overbalance conditions in the we guns are pulled the well is killed. Perforation and kill related damage severely impacts these wells leading to high skin and rapid productio ptimum flow rate. Using the combination of smart completion and portable MPFM (Multiphase Flow Meter) resulted in reducing the water cu perceived technical complexity of the development and requirement to maximize completion efficiency the operator chose to maximize th uction liner. Drift diameter through the tapered production casing is 9 1/2 and 6 1/2 in. respectively. The 6 1/2-in. drift diameter allows using he poor natural production from the vertical cased and perforated completions in Hawtah and little associated gas electrical submersible pu h minimal problems. The retrieved screens had collapsed around the perforated base pipe. The well was reperforated new screens run and ubing remedial sand control solutions were considered namely mechanical and screen-less (chemical consolidation) methods. A proprietary

livering production quotas.ï¿½ The lower drawdown extends the integrity of sand control completion jewelry reduces water influx fines mig as developed requiring extensive fluids testing and reporting at the well site. The paper describes in detail the reservoir completion philoso

er treated-brine and three open-hole gravel packing case histories from one UGS field in Italy. In the three case studies the wells were grave India where two gas wells were drilled with an oil-based drill-in fluid and gravel packed with a viscous water-based fluid. The packing mech workstring crossover ports open-hole and screen-washpipe annuli and then back to the surface through the washpipe and casing-workstr tools and techniques. These developments have resulted in successful gravel packing of wells drilled with oil-based (OB) fluids which hav hese practices. Incomplete packing of perforation tunnels is mostly encountered in gravel-pack jobs completed with brine as the carrier fluid ese practices. Incomplete packing of perforation tunnels is mostly encountered in gravel-pack jobs completed with brine as the carrier fluid high angle wells this normally equates to shooting in the vertical plane through the well path. Over a decade of production experience with th d that the failure mode appeared to be wormhole-like failure2. To date there have been several failures with similar characteristics occurred nless completion. In this paper the common sequence of events for a screenless completion is presented as well as the key technologies

chanism for the sand production. This knowledge was required because attempts to run new completion designs without knowing the cause might be achieved without overcomplicating the analyses and without requiring complex lab and field data that in most instances will be u d. These findings contradicted with initial impression and previous expectation on this sandstone that it should have been sand-prone forma oration strength and sand production depends on the mineralogical composition of the sandstone and the degree of residual water saturatio

ailed zone. These volumetric estimates of sand production are often based on rock mechanical models which predict the extent of a yielde stability and sand production prediction tools. Mud weight stability profiles showing the variation of lower and upper bound mud weights wi cal long horizontal and multilateral wells. They were used in sour environments where hydrogen sulfide levels reached nearly 10 mol%. Th similar to a standard API fracture conductivity cell but with a capacity to hold core samples that are 3 in. long in the leakoff direction. The lo ns of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical a e or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highe te or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the high d post-job production logs clearly show a change in the production profile after the stimulation with the viscoelastic diverting acid system w d drawdown required to meet completion objectives. The two exploratory wells in this study were cased with a perforation density of abou wait. The application also deployed a new nonparticulate material that forms a highly viscous plug when it contacts water and that degrades ns. The short and long term results are correlated with the stimulation procedures and practices. The present paper describes a comparison

containing a viscoelastic surfactant system that allows upon acid spending the development of viscosity in situ has shown that significant s zed in stimulating carbonate formations include formic acetic and more recently citric and lactic. Selecting a suitable organic acid for a spe

ow clay content in the formation the critical velocity was less than one cc/min. Moreover the retained matrix permeability after performing a mechanical techniques are very effective they are more expensive and time consuming than chemical techniques and they are often not a lost to the reservoir impact final productivity. It equally affects the possibility to flow the well back after stimulation treatment. Hydraulic fractu c Resonance (NMR) Computed Tomography (CT) scanning Scanning Electron Microscopy (SEM) mercury injection as well as resistivity m her parameters such as high BHP (remaining reservoir energy) recoverable reserves f-h1 and favorable response to original fracture jobs ( ronmental and economical benefits of using a water-based fracturing fluid a novel visco-elastic surfactant based CO2-compatible high foa uresâ€”with carbon dioxide advantages of enhanced cleanup and better hydrostatic pressure. This fluid was recently selected for the fractur vailable pieces of information through the structured process helps put together the â€œbig picture which subsequently provides the suppo

h water from the stimulation fluid using two different types of viscoelastic surfactant (VES) polymer free diversion systems placed with coile behind casing as determined by the physical test. For the twenty-eight wells examined twenty-five of the cement log interpretations matched n this study are as follows: The analysis procedure is simple enough to implement in a spreadsheet but is more accurate than the curren nterpretation highlights successful development of inflow and tubing performance relationships bubble-point pressure estimation as well as voir and fracture properties on a layer-by-layer or frac stage-by-stage by evaluating the production well history as an extended drawdown a ual layers varies widely ranging from 1.5 to 15 b/d/psi. This illustrated the need for a method to estimate the permeability and skin of each l havior in these types of completions is different and more complex compared to that of a fully penetrating well. This paper proposes a met en space and time above the pressure gauge resolution and natural background noise which could be as high as 0.1 psi. One of the consta tin America. The paper briefly discusses the three pillars of digital oilfield; technology processes and people and how they work together to synthetic cases and one field case are considered for the investigation. Our results identify the key issues regarding the successful and pra

ch as fracture distribution fracture aperture matrix block size and fracture porosity can be obtained from processing of Image Log data. Si native an additional way to selectively straddle a section of a reservoir and provide the capability to conduct controlled local production and shing commingled AOFP of gas wells. First we conduct a multiple station MiniDST run and interpret the data to estimate reservoir paramet al to assess whether this technology could reduce the uncertainty on oil production by removing any impact of imperfect separation. 20 tests nd monitored accurately with the in-line Venturi â€“ Dual Energy gamma ray multiphase flowmeter. The importance of the hydrate detection

ated uncertainty in plans for production optimization. For example the inaccuracies in measured oil rates could be greater than the gain exp ydrate and document major benefits of multiphase well testing are based on the accumulated operational experience from the operations of ation results in excellent predictions of the gas flow rate; the liquid rate prediction is made with acceptable accuracy and no additional meas sults by the MPFM. Production test results were carefully analized and compared with the results of test separators for fair evaluation and in

nd simple measurements (Venturi and gamma ray) in multiphase flow-metering solutions for any type of well based on the advantages and b d dynamic data. â€¢ï¿½ï¿½ Improved history matching of simulation models by incorporating transient pressure data. â€¢ï¿½ï¿½ Use com nostic function. This paper provides the following contributions for the analysis and interpretation of gas production data using the Î²-integra ng well-test-pressure data the digital pressure derivative technique. This approach produces the most accurate and representative dp/dt cu ture transmissibility. While streaming potentials have been observed in many laboratory rock experiments we believe these are the first str

his paper will focus on an in-depth evaluation of the annular material on the Otway CRC-1 well that is being used to inject CO2 in the CO2C t order principal horizontal stress magnitudes both follow a linear trend with depth. Results indicate minimum horizontal and maximum horiz eling in terms of probability and severity and (iii) establishing a risk mitigation plan. This methodology is based on experience in material a on variables facilities well completion number of wells have been included in the analysis and numerical reservoir simulation models have enhanced to include specific phenomena such as drying-out and salting-out. The examples illustrate the importance of pre-injection studie lls as well as the acquisition of a geophysical baseline and geochemical monitoring in Ketzin located near to Berlin Germany. The target s 2 storage is reliable monitoring of CO2 migration behavior and storage volumes. An innovative seismic monitoring techniques has recently servoir model to achieve initial equilibrium and also to further simulate the coupled transport chemical and mechanical processes occurring

re drilling performance definition and the payback time for this well was less than two months. Experiences gained on this well indicate th le system with a high dogleg capability has been utilised for successful landing of these wells into reservoir sections without need for pilot h

he other reefs in these trends. The reservoir is composed of a limestone matrix with low porosity and low permeability that contains irregula gas lift operations in nearby heavy oil fields. Recently a plan of acquisition of information and studies to evaluate the CO2 proven reserves ometry prediction and formation pressure. The methodology identified several sands as commercial that have been bypassed in offsets w eability lateral length and reentry drilling time on production performance is conducted.ï¿½Results show that multilateral reentry drilling r into 2 and 3 pseudocomponents and comparing the stability and results using both fluid characterizations to attain reasonable running time overcome these challenges a robust chemical shut off methodology had to be innovated. This methodology consisted of the following main p

95% in one well and 30% in the other well. It was found that these two wells certainly had big difference in fluid injectivity and original desig created using two thru tubing inflatable packers isolating the top and bottom perforated zones in order to provide both proper zonal isolation 0s it was estimated that only 35% success was achieved worldwide in water shutoff remediation. This low success rate is due to poor diagn d disposal cost. It leads to scaling in wellbore tubing flow lines and processing facilities. It also leads to corrosion and degradation of com olves three key stages; the temporary isolation of the producing layers the permanent shutoff of the water zones and the effective cleanup in the world. Some of these wells started cutting water and as the water cut increased the need to perform rigless water shutoff was neede way to isolate the water producing interval reduce water cut and enhance oil production. The advanced and intelligent CT enables real tim nging impact on field development planning especially when dealing with marginal deposits having variable fluid characteristics. In this pap bution in oil/water flows that can lead to better modeling and design of dispersed systems. Moreover the new data provide new information used to measure the phase holdups and to demonstrate the slippage between oil and water with the water cut to water holdup ratio. The e nce of those advanced wells cannot be accurately dealt with using traditional approaches. A process is introduced that creates the most a 3 100 BOPD from 10 fields (mostly gas and condensates but also oil fields) through 69 wells using 6 process facilities and its corresponding es mono-bore commingle production was thought to be an option. Also in-situ gas lifting is considered to be a favorable option. Commingl al data were used for a case study to demonstrate the effect of live oil data versus dead oil data on the subsea system design and operatin re reaching an analysis facility. Optimizing the fluid sample acquisition program to match existing fluid complexities is impossible without rea llected samples. This is due to the nature of CO2 which easily reacts with water the source of which could be mud filtrate or formation wate

servoir pressure. The dewpoint pressure correlation is based on data of 615 samples of gas condensates with worldwide origins. The other roperties yielded best results when compared with compositional simulation. This method (and the others available in the literature such as In part this assumption was made because dynamic calculations performed on reservoir models had difficulty accounting for any but the m sed to identify reservoir fluids in newly drilled wells. Two fluid analyzers were placed above and below the downhole pump module. The fluid hroughout all interested zones toward a â€˜Continuous Downhole Fluid Logâ€™ is essential to reveal fluid complexities effectively and eff eum industry has devoted much effort to developing computational methods to model phase behavior. Two approaches are prevalentâ€”sim h conventional models are deemed sufficient for pre-job planning and interpretation of measurements acquired in formations subject to wate ective for compartmentalization characterization. The ability of thin barriers to hold off large depletion pressures has been established as th

eld examples in low porosity/low mobility zones are presented showing the identification of mobile fluids. It is shown that the existence of mo arded as a non-viable alternative. In this paper we are challenging this historical concept. By using carefully designed laboratory experiment

ed a yield/temperature correlation to fill in the information void for reservoirs that fall within the bounds of measured data over a large geogr ques for the assessment of compositional grading in different settings. We demonstrate that new technologies combined with real-time mon e the operator needs to gather as much information and as quickly as possible to make immediate operation decisions and Field Developm ng-analyzing tool string that included the fluid-composition analyzer. This tool analyzes petroleum fluid and gives concentrations for four grou mation pressure measurement techniques and data quality and compare conventional and advanced methods of pressure gradient analysis ess may however be misleading as fluid compositional changes and compartmentalization give distortions in the pressure gradients which o detect but the high methane content of these fluids makes possible a reliable methane-based OBM-contamination monitoring algorithm.

can be prepared. Additionally flow barriers may then be revealed as across such barriers fluid may appear different. In order to test for the different. Real-time application of the FCA can optimize capture of downhole-fluid samples and generation of a continuous downhole-fluid lo has devoted much effort to developing computational methods to model phase behavior. Two approaches are prevalentâ€”simple correlati

uid equilibrium (VLE).ï¿½ In contrast to black oil and compositional PVT calculations thermal fluid VLE needs to account for water vapor.ï¿ ompositions. Live oil/water emulsions were prepared in a concentric cylinder shear cell using synthetic formation water under predetermine

new focused sampling technology is presented in four case studies from wells drilled on the Norwegian continental shelf. A wide range of for ble to sample the fluid at downhole reservoir conditions and to minimize change in phase characteristics and composition of the fluid sampl been questionable in many cases (at very high GVF or in wet gas conditions high pressure or /and high temperature). This paper focuses er countries. This paper documents new type of sampling device that allows collection of samples determination of in-situ volumetric ratios mass transfer and surface reaction. The chelating effect of organic acids/chelating agents were also considered. Association reactions of a utsidephase emulsion and regular mud acids have been used in the past on Algyo injector wells to improve injectivity by targeting the possib EM). The reaction rate and size distribution of calcium carbonate particles varies depending on the temperature stir rate chemistry of the c m chloride were used in the tests. All three new chemicals showed improved inhibition efficiency over the two commercially available produc

t to pH and temperature. This also allowed the determination of the critical pH value for the onset of naphthenate-soap precipitation. The re xtent and magnitude of both the permeability and strength impairment. An indirect measure of the amount of permeability impairment create uncertain. In this paper we describe the development of mathematical models that predict the pore pressure in the rock surrounding the p story delineates the detailed sampling and pretreatment analysis of several oil fields with high-water-cut wells. In some of the fields as man on on production equipment. This paper outlines the learning procedure and present designs testing and monitoring results from scale treat lligent completions by scale deposition. The potential benefits to scale management that ICVs such as control of scaling brine production cale management strategy to monitor and remove Strontium Sulfate scale in Upper Zakum producing wells. A scale prediction simulator is u to chemical equilibrium the Mg/Ca and Na/Ca ratios in the brine being dependent on the respective ratios in the rock matrix.ï¿½However er each region can be history matched independently and simultaneously. The most sensitive criterion increases the effectiveness of histo eral independent regions. Within these regions the fluid flow patterns between individual producers and injectors are also identified by the g d discussion of some of the results accrued from the incorporation of streamline technology in the case under review.ï¿½ These include: R r these sectors has been increased to be able to track the fluid movements with a greater precision and heterogeneities at different levels i e Survey were individually validated and subsequently implemented as a sequence of automated routines to process the data over the ent vity between injected water and oil bearing reservoir rock. By allowing an evaluation of the water distribution long before the injected fronts nce optimize areal sweep efficiency by adjusting injection and production allowables assist in planning water shutoff operations and desig co belt to exploit extra-heavy oil reserves economically. A typical completion assembly includes a multisensor gauge to obtain downhole pre ase the oil production rate. A consequential advantage of using downhole heaters as a preamble to a steam injection process is that they a es.ï¿½ In these techniques heat is injected into the formation which reduces the oilâ€™s viscosity and results in a higher production rate be more efficient than classical cyclic steam injection and more effective than direct steam flooding. In contrast to the Steam Assisted Grav as a 30 deg deviated well with an AFE over run of 300%. Taking leaf from experience of horizontal drilling in Muglad basin rotary steerable s e. Data used in this study includes conventional open-hole well logs borehole images nuclear magnetic resonance (NMR) logs Elemental of a single probe technique is limited. Under these conditions the small packer may not be able to isolate the zone may miss a thin zone or

te well placement cycle including detailed analysis on the drilling and steering challenges while placing horizontal well through reactive shale

emporarily plugging the zones of high water saturation. When mixed in acid the new system will stimulate and divert automatically based o

n thermal production methods due to historical reasons. Recently Orocual field in Monagas Northern (Venezuela) was put in production a c

system minimized the potential for precipitation due to secondary and tertiary reactions. This system did not cause sand deconsolidation a sampling objectives were: reservoir evaluation formation pressure profiling direct measurements of mobility (effective permeability) down

ally designed centrifuge system is essential for calibration and as well as for quantification of these forces. Numerical studies were perform

sit time and reservoir temperature pose difficult challenges to routinely achieving the optimal crosslinking state.ï¿½ Conditions such as offsh ations of conventional systems. Extensive laboratory studies which included acid capacity etching patterns conductivity measurements so

digital permanent down hole monitoring system. Using HPHT permanent system will increase recovery factor and allows producing the wel efits. The methodology adopted in the design execution and evaluation of the fracturing treatments is discussed. Discussion on the rig-up voirs at high temperature by effective damage removal and further matrix dissolution. Acid solubility ion concentration and mineralogical echanically ground field samples. Treatment with acidic chelant fluids generated high levels of dissolved calcium silicon and aluminum tha was also feasible for the given conditions of this high temperature formation. Since the reservoir temperature exceeded the technical limits o g gas into brine-saturated cores at different pressure gradients and measuring volume of displaced brine. Higher volumes of brine clean u ors into scale and corrosion models. It is proposed that the direct pH measurement on live water samples described here be used as an ad

mulation of the entire interval.ï¿½ The multistage OH completions have resulted in better connection to the reservoir compared to convention

e integrated with adaptive modification to the factory mode. This approach will identify the development process that will result in the highes well completion program based on data from an open hole logging and geomechanics. Some experimental fracturing techniques were tes e pressure changes because of fluid production and water injection. Field sector formation pressure distribution makes the fracture offset fro as well as among the fractures. The hydraulically stimulated volume is represented by a horizontally expanding ellipse containing a simplifie al analysis using these models improved the identification and characterization of potential movable water zones. A perforation scheme was

hydraulic fracturing as risky and costly operation prevented rather than encouraged its application in marginal offshore oilfields. Recent inc ring stimulation treatments to produce the gas economically. The conventional method to complete the wells in the Xujiahe formation is to d not be produced by existing or additional vertical wells. The success has led to new opportunity for horizontal drilling and horizontal sidetrac well spacing and infill-well patterns. Production for old wells and infill wells completed during 2007 and 2008 which was not included in the and optimize treatment solutions Understand limited entry Identify water producing zones Develop commingling production strategy Sin ns (injector/producer pairs injection/production rates etc.) and their results were compared with the fine-grid geocellular-model results. Pse South Texas tight gas sand field. Several wells were evaluated using micro-resistivity imaging.ï¿½ From this an enhanced high-resolution pe

nd enhanced formation evaluation which allowed reduced coring for a cost saving. The paper explains the advantages and limitations of ea multiple thin zones which make it difficult to predict reservoir fluid types from openhole logs or pressure gradients alone. An extensive Dow ng a variety of techniques including pressure transients production transients micro-seismic and various other techniques. However the a ata acquisition objectives more efficiently than long-established methods. However wellbore conditions and data acquisition procedures can

ough the enhanced capabilities of the new generation of tools makes packer/probe and parameter selection even more critical. Additionally ion increase from an intermittent hundreds of BOPD to more than 75 000 BOPD in a period of 3.5 years. The exploitation strategy of this pi vertical wells. With costs more than double those of vertical wells the economics is obviously unfavorable. This paper discusses ways to id This new approach consists on high-potential zone localization controlled by the disintegrated levee-like stromatolithic constructions which

capillary effects changing wettability and saturations and pressure variations from production and/or injection effects all play a role in com

ting the producing life of existing wells resulting into decline in production and causing significant bypassed and undrained oil. Horizontal w

g policy in particular identifying levels of risk tolerance. By interviewing key decision-makers and reviewing historical decision making policy alysis will lead to significantly better decisions related to oil and gas exploration and production. Introduction Uncertainty assessment in th er all bore hole quality as well. Introduction It was long recognized by the drilling hands in the 30â€™s and 40â€™s that running casing in een questioned. In a well in a complex carbonate reservoir extensive log and core data has been acquired. We explore the correlation bet ssues in the ERA data acquisition and interpretation but also provided flexibility for device installation and operation. Furthermore the ERA o the conventional logs as input of the neural network model. Then neural network can discriminate between 2 rock types with same range e (massive laminated and cross-bedded) shale (thin laminated and slumped) siltstone (laminated) and heterolithics (thin alternation of san photos that provided at least twice as many dips than borehole images. Facies logs were derived from the integration of core calibrated elec ntially increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer. as used to identify reservoir fluids in newly drilled wells. Two fluid analyzers were placed above and below the downhole pump module. The micro meso and macro porosity.ï¿½ Borehole image logs have been interpreted in terms of defining the connectivity of the features seen o comprising of fluvial to deltaic deposits overlying the Precambrian metamorphic Basement. The reservoir is oil bearing without a gas cap. Th tes measurements of gamma ray propagation resistivity gamma-gamma density and thermal-neutron porosity with additional measureme y the traditional measurements such as gamma ray resistivity density and neutron porosity but also measurements not previously availa

nalysis techniques were used to develop these charts and hence used as a forward tool to quantify the uncertainty in the hydrocarbon satu error analysis techniques were used to develop these charts and hence used as a forward tool to quantify the uncertainty in the hydrocarbo omparison with Special Core Analysis (SCAL) data. This workflow is presented in the form of a case study of a carbonate well in the UAE. T ase-mud. Complicated structures were resolved utilizing the dip data gathered with such techniques. Fractures were characterized for their a pore size compute permeability and assess the rock types independently of mineralogy facies and other variables.ï¿½ The results are va method are compared to the sand counts from a high resolution borehole image and from core images.ï¿½ This comparison reveals the effe

1D high-resolution data is acquired to estimate sand volume fraction porosity and permeability and 3D fluids data is used to evaluate the turation is by pulse neutron (PN) after well completion. New technologies have been developed to characterize formation saturation through e transient analyses and production data borehole image logs provide invaluable information on the enhanced fracture conductivity the com o the well to acquire the required samples and fluid profiling stations. To limit excessive sanding and solids production and mitigate problem d allows differentiation between natural and drilling-induced fractures when core is absent. The geomechanical analyses involved using var xtraction method was used to extract channel events and integrate into the modeling process to visualize and track channels. Present study

reservoir model. An accurate reservoir characterization should include not only the realistic description of the spatial continuity but also the valuate the prospect but operational and economical constraints do not permit to core or test every potential reservoir. Therefore a real-tim he resolution of conventional logs that have a typical vertical resolution of 6 to 12 in. or 15 to 30 cm. This makes fluid typing in the centimet

ature changes). Here we demonstrate the applications of the method which allows dynamic drillerâ€™s depth correction for the effects of d

oir sweep (c) choose the right time window for fracturing (d) improve the design of multiple fractures in single horizontal well. Poroelastic sim r wave velocities are used to estimate these parameters.ï¿½ However these data provide dynamic elastic properties which are different fro ed at three depths in shale thus yielding two minimum horizontal stress magnitudes. The borehole sonic data were suitable for the inversion e the multi-rate deliverability tests are performed under boundary dominated flow conditions conventional deliverability analysis techniques e the multi-rate deliverability tests are performed under boundary dominated flow conditions conventional deliverability analysis techniques e the multi-rate deliverability tests are performed under boundary dominated flow conditions conventional deliverability analysis techniques mation contain significant oil reserves but are of less importance. However a recent successful exploratory well in the Arifjan prospect which s) using formation micro imaging tool. Also to quantify the effectiveness of fractures as fluid conduit mainly in the carbonate reservoirs eith tion of the fracture distribution model using the Continuous Fracture Modeling approach (CFM). A comprehensive description is available on ver applicable were generated. These fracture properties were used as input to upgrade the existing reservoir model to study their influenc el 5) construction of the fracture distribution model using the Continuous Fracture Modeling approach (CFM). The final geologic model ser

elevant data that include time-lapse pressure production and injection profiles and resistivity; and 2) Interpretation of all the data acquired presentative and accurate mobility/permeability distributions of reservoir layers7 for reservoir characterization. In this paper examples illust radial extent was quantified. ï¿½The MDT-IPTT tests quantified the virgin zone effective gas permeability and permeability anisotropy as w

ransit time for the matrix. To corroborate that the obtained effective NMR porosity is the best to be easily and truthfully correlated to true fo water and OBM filtrate (OBMF) at multiple depths of investigation. The radial fluid profiling allows discrimination of OBMF versus native oil. nt a method based on NMR analysis to estimate net producible pay and its uncertainty. We apply fluid typing from NMR Relaxation and Diffu ting the extremes of T1 T2 or D such as light hydrocarbons gas water at high temperature or heavy oil. We make this investigation by thr ethods. Introduction of pulsed-NMR logging tools in the 1990s provided the industry with unique even revolutionary new methods for an this study a two step petrophysical evaluation workflow was developed. The first step considers the application of quick-look log analysis t s flow profiles and fluid break-through. Production flow profiles are also used for identifying geological features such as super permeable zo

uction rates during UBD depend on the formation properties and the drilling conditions. The inflow information is analogous to transient test d potential for horizontal well placement. It was impossible to reach the observed production rates from matrix without one or two major flui

on migration and entrapment reservoir connectivity and fluid contact levels. This in turn enables better well placement and more effective d and newly acquired DFA log data matched for the first production well establishing that the penetrated sands are likely connected mitigat he multi-rate deliverability measurements are obtained under boundary dominated flow conditions conventional deliverability analysis techn expected the remaining oil saturations lead to the suspicion that cased hole saturation logs in producing wells may underestimate overall re key uncertainties of such reservoirs. The main challenges faced during formation testing in the reservoirs studied have been a) laminated l

f the wireline dual packer and standard probe modules provided estimates of permeability and permeability anisotropy in sands. Formation ary conditions deployed here which are unique to a supercharged system is explained in detail. Introduction Pressure measurement play ace coupling system for multiple-reservoir models. Uncertainties in the reservoir characteristics and in the facilities/evacuation schemes wer ld development project. Logging-while-drilling logs wireline logs and wireline formation tester pressure data identified a number of potentia hallow â€Ãâ€™ sands.ï¿½ These wells are currently produced through gravel packed dual string completions.ï¿½ Candidates were elimina y team studied and recommended the implementation of a program to drill a massive number of infill wells in a portion of Block 10 operate sors and fluctuation in gas availability it is critical to effectively allocate lift gas to the most prolific producers.ï¿½ One of the main challenge a proactive well placement technology can be translated into maximum reservoir contact minimum well-bore tortuosity and a facilitator for o able to trace the sand while drilling across the heterogeneous sandstone reservoir. The team decided to abandon the hole and sidetrack the response of wells in high-pressure area and low-pressure areas of the reservoir to wellhead compression. 2) Feasibility study investigate ed significantly compared to the offset field development plan (FDP) while water production was significantly reduced. The optimized draina ues using dynamic simulation with a coupled surface to reservoir model to show how flaring affects gas injection on field scale. The extens stem (Electrical Submersible Pump ESP) through a network simulator. Both sections were coupled taking an intermediate point between th ltiple surface/subsurface simulators. One real field case that requires advance/complicated development logic is also presented. Introductio will need to accommodate these changes while taking into account the power requirements for compression and treatment processes.ï¿½ B condary and tertiary recovery methods investigated in this study included dump flooding from adjacent reservoirs gas re-injection and water ce uncertainties and risks associated with proposed activities full field numerical simulation model was run and results were reconciled. Thi

IAM in order to accurately determine the well performance and the reservoir production. The IAM couples the modeling results from reservo second reservoir is a gas condensate system much smaller than the existing reservoir and located 90 kms to the east. The current develo 3 100 BOPD from 10 fields (mostly gas and condensates but also oil fields) through 69 wells using 6 process facilities and its corresponding facilitates the flow of task outcomes between project team members and creates enormous flexibility during project execution by permitting w percent to 80% to 90% within the first 2 years of production. Typically sidetracks are drilled before water cut reaches 96% using the exis

his paper is based on a field-wide production planning solution which is achieved by combining steady-state multiphase network simulation he pay zone during completions were applied to maximize reserve recovery and successfully reverse the fieldâ€™s production decline. Intr States. Well productivity is highly dependent on hydraulic fracturing effectiveness and operating practices. Understanding the resultant hyd ng relatively simple equations that result from a combination of complicated reservoir and production characteristics. As a result a wide ran on where to place an injector well relative to a fault. The example considers the value to the client of a future measurement of the degree o

ain challenges of maintaining a horizontal wellbore inside a thin hydrocarbon bed is the uncertainty of formation dip. Inside a hydrocarbon b n order to map the relative position of the drainhole to the overlying roof shales. As the reservoir top and internal shale layers were mapped ctives rather than infrastructure considerations which may favor a more regular and orderly well spacing pattern.ï¿½ We illustrate this meth ack from the downdip location to an updip location. When the updip sidetrack well was drilled reservoir rock quality was below the minim n which is critical for a sound management decision. Whereby the approach tackles the four most critical factors how much data are need ajectory near placement to the current oil-water contact and steer away from the gas cap to delay gas breakthrough. The wells were then tr n NPV) on the basis of which improving well locations can be determined. The main advantage over previous approaches such as finite-dif model that was developed was compared with simulation done by commercial reservoir simulation software. position and time to be used to treat either pressures or fluid fluxes on the boundaries. Also using solutions in Laplace space we are able Darcy flow factors as well as constant well pressure production. We present case two case studies comparing our solutions with that gene based on a generalized travel time inversion and utilizes the adjoint method for computing the sensitivity of the travel time with respect to r an account for complex physical behavior that dominates most field applications. Second the production data misfit is represented by a sing

ns can then be combined in different combinations to obtain the new plausible realization. The goal is then to find the weights used to comb

clic steam injection case with other commercial simulators. We also demonstrate the performance and parallel scalability of the simulator vi re. With this general formulation approach we can model most reservoir physics with a single unified code base rather than custom one-o feature and the dynamics within the horizontal wellbore it is very challenging to reproduce the actual production profile in the simulation m associated with undulations in the wellbore trajectory and consequent fluid holdups. This can result in certain dynamic flow behavior which

is paper focuses on concepts that enable engineers determine the dominant flow regime from diagnostic plots generated from rate-time da ter and fracturing gel. Introduction Hydraulic fracturing has been used as a successful technology to increase productivity by means of sig capturing the yield stress of common polymer gel. The model is applied to typical cleanup scenarios. Using the model it can be shown th er reservoir/well model complex reservoirs are simulated and pressure transient response signatures obtained. Sensitivities of key reservoi and multicomponent fluids flow. It is also assumed that conductive fracture could be described by 2D surface in 3D permeable formation. Ad quired by the model are defined and the application of the Renshaw and Pollard criterion and the DD method is explained. The direct effe hese factors include non-Darcy effects along the fracture multiphase flow condensate banking flow convergence and reservoir layering a addition the issue of flow convergence near the perforation tunnels is also discussed. A comparative study of the relative effect of flow con oblems for production analysis are typically undetermined and can lead to instability and nonuniqueness in the solution. To deal with the sit with a review of appropriate applications of the apparent wellbore radius concept to vertically fractured wells in finite reservoirs.ï¿½ Example s it only replaces the line source and linear flow assumptions (a consequence of colinearity and long perforated intervals) by the point sour s not essential as it does not affect the quality of results obtained and can be eliminated easily. Several different scenarios of fracture initiat r example the errors in predicted fracture spacing for the Lisburne formation with conventional ANN methods are approximately 50 to 200%

field into three main reservoirs that are completely isolated with each has different reservoir and production characters. Due to these challe he analytical solution given in this paper and those obtained with a numerical reservoir simulator with temperature option (ECLIPSE) which e background theory of IPI. The consequences of IPI for breakthrough sweep and even sanding. The implication of IPI for an example wa nput pressure for the MB model production-derived relative permeability data for MB prediction. Applying these techniques resulted in a w st approach was proposed using experimental design and analysis of variance to systematically evaluate the influence of reservoir pressure ommendations. This paper illustrates the authorsâ€™ approach to the mature field development optimization and providing an example fro initialization in hydrocarbon reservoirs. This is caused in part by the effect of thermal diffusion (caused by the geothermal temperature gra onal development options for fifteen reservoirs situated in four different fields that are at different stages of maturation it has been possible

two-point flux approximation (TPFA) is used in commercial reservoir simulators due to its simplicity and the optimization of linear solvers to orecast the production profile and field development management. In case of gas condensate formation first of all this means to sufficiently from water-oil systems and is very complex the simulation of this process must be studied separately. This paper describes a numerical s eveloping an integrated yet efficient fracture modeling tool. This paper presents an integrated approach to history matching of naturally frac

simulators. To realize this model it was necessary to reformulate the matrix and fracture pressure equations. Conventional transfer function transport part is solved along a set of one-dimensional streamlines and the corresponding time step used for the update of the solution can ultiscale basis functions. This method has limited sensitivity to grid distortions.ï¿½The multiscale technology is very robust with respect to fin

ce predictions with an uncertainty range similar to the one obtained with RML. Introduction We consider conditioning models to production

ery significant opportunity for improving the accuracy of such calculations. While numerical dispersion effects for immiscible calculations (eg

nstructed by thresholding of negligible details. Then a second-order finite volume method is used on the obtained adaptive grid. The perfor attention from the research and the oil and gas industry. The reason for this interest lies in the necessity to model detailed reservoir geolog ame group are combined to a type curve that is described by the most likely production profile and an associated uncertainty range. A data evaluate the uncertainty in reservoir description and performance predictions. Here we establish a firm theoretical relation between random ognition technique is then used to rank the geostatistical reservoir models. The simulated pressure data from the multiple realizations is an esented. Introduction Advanced well completion solutions are becoming increasingly common in both onshore and offshore hydrocarbon r

prohibitively computationally expensive for a multi-scenario production performance study for the NKJC. Black oil reservoir simulation is com general case the model is fundamentally different from Archie's law because in the connectivity equation resistivity is only a function of the

ant packs. Models for flow beyond the Forchheimer regime are also suggested. Introduction The effect of non-Darcy flow as one of the mo d and oil based mud are considered. It is shown how it is usually possible to produce oil from a zone which has a water-like pressure grad gy intricate vertical and deviated fracture networks undefined faulting regimes and retrograde fluid-phase behavior the task of optimizing age orientation of N10degE exists in most of the region.The second trend is aligned NE â€“ SW and observed locally at the central eastern have a common vision of what a truly Smart Field will look like and this contributes to the difficulty of assigning a value to â€œSmartness.ï¿ Soviet Union and Russia for the last 25 years an analysis of recent efforts and discusses briefly on perspectives for conventional and new larities but differ in several key areas including government policy. This paper examines exploration and development history resource acc t. Because typically these papers have addressed only one or two parameters however the proposed methods are inconsistent. This paper

contact. In these wells the water shutoff leaves oil behind and a different completion strategy was recommended. The results from the res oth laterals and is the first installation of its type. This capability is critical for production and reservoir optimization. Additional value of the te ation due to complicated nature of the production strings and the risk of wireline logging tool entangling. The earlier practice was to utilize th al axial symmetric production logging tools in ERD well bores.ï¿½ The equipment has recorded production logs to a measured depth of 9 77

upted the fluid or by excessive contamination levels that rendered the samples unsuitable for laboratory analysis. Clearly a more flexible sol upted the fluid or by excessive contamination levels that rendered the samples unsuitable for laboratory analysis. Clearly a more flexible sol of leakage. Included in the paper are the design criteria deployment methodology and the â€œlessons learned from installation of this fully entiometric methods in which fouling of electrode surfaces by oil and mud is a potential problem the dye technique is robust because the d udy of the reservoir geomechanics. The geomechanical characterization of the reservoir allows for further insight into the behavior increase ic events provides following insights into reservoir management. First initial gaps in located seismicity appear to be artifacts owing to the m s profile within a fracturing simulator to the most robust methods of direct measurement using passive seismic monitoring of fracture events

viscosity water cut and permeability on fluid flow and the fiber optic measured temperature response. By varying the injector-producer res valuate the formation inflow into wells in which the velocities are so low that no other production logging methodology is possible.ï¿½ Coupl evaluate the formation inflow into wells in which the velocities are so low that no other production logging methodology is possible. Coupled to be measured and therefore the inflow distribution of the well can be calculated. Determining the inflow distribution of multi-zone gas we roof of fluid flow from different fault blocks; Improve understanding of well clean up of a horizontal well especially the contribution from the Over the years many instruments have been used to collect and process flow data including production-logging tools surface-test separa

nce efficiency can be defined as the ratio between theoretical result from a model or test results and the actual results achieved. A Producti at high water cut. These specifications are tested by the challenging logging objectives for the wells described in this paper. The logging da bservation wells. This paper describes a systematic methodology to select wells to test on a fieldwide basis test design exercise data acqu ed to be the cause of the production decline. However with inadequate information the diagnosis was inconclusive. Consequently a fiber-o uced by solid production etc. In this paper we are illustrating the various steps that we have taken to optimize a well producing from natura cquisition objectives cannot be overstated given the high cost of offshore operations and the implications of obtaining false or misleading in w rate determination layer pressure changes smaller than 10 psi can be detected by changes in the measured temperature profile as long of the temporal response of the microseismic deformation with the surface uplift suggests a lag between periods of accelerated seismic de creen wire-wrap. Thus a direct measure of each individual reservoir drawdown is obtained from the difference between the fiber-measured t The system became activated when a mating inductive coupler was landed as part of the upper completion. Surface indication of landing w tion logging tool (PLT) and production data indicated that there are a few thief zones in different levels within the vertical Mauddud sequenc

llows: Virtual Rate Measurement (VRM): ensuring accuracy of the volumes at the well level. Back Allocation: focussing on accuracy of the onfirms the available multi-phase holdups. When water velocity and water holdup are measured and when changes in phase behaviour due

Egypt. The well was drilled in early 2006 followed by logging and testing and was put on production immediately after completion. During t ed by variations in the reservoir rock cementation factor while cased hole logs can be affected by environmental effects such as hydrochlori njection pilot pattern is being implemented. The pilot will address the issues of the uneven sweep efficiency bypassed oil and effectiveness utes core descriptions and detailed log analyses into the static model helps optimize the EM inversion and increases the resolution of the r tial knowledge of perforating characteristics in sandstones and to a lesser extent carbonates almost nothing is known about perforating in High cleat density in coal seams is an essential requirement for better fluid flow in CBM reservoirs. The primary cleat direction and its relatio lysis as well as micro seismic results and frac tracer analysis for quantifying the effectiveness of indirect fracturing for the stimulation of CB tial source of expense and downtime. This field study examines 256 horizontal Barnett shale wells in an effort to identify the causes of thes ovide a simplified methodology for first-pass calculation of these stress concentrations and thus for predicting the potential for problems du ce.ï¿½ A large-volume pressure pulse is released downhole during the fracturing process to create an order of magnitude change in availab is the formation imager.ï¿½ It produces electrical images of the borehole that provide detailed structural information such as faulting and n and massive multistage multicluster hydraulic fracturing treatments (HFT) are executed. Various well placement and HFT schemes are per be achieved. A study was conducted to examine several completion strategies and to test with the use of a simulation model what the exp rilling is starting to slow shale gas continues to be one of the hottest plays in the US and drilling is expanding rapidly especially in the sout this unconventional gas reservoir the restimulation of horizontal wells is problematic and operators have demonstrated limited success us ter rendered wormholing pattern by pre-selected acid formulation and volume from past experiences and cost consideration. However it is ge run life of operating ESPs is 2.7 years and that of failed ESPs is 1.74 years. To maintain required production target an effective ESP rep

rawdown is transmitted downhole by pressure tappings. The drawdown lifts the fluid through the production tubular in a stepwise manner. T le to produce with vertical wells because of poor economics. Another crucial achievement resulting from horizontal completions was the mo s such as cased hole gravel-pack or frac-pack completions the openhole gravel-pack option has several advantages such as eliminating th s piston squeezes a Cring and makes the ID smaller. At the end of the fracture treatment to the lower valve a dart is dropped during the flus ation and estimation of the radial extent of the near-wellbore mechanical alteration that might cause near-wellbore permeability impairment. ximum gas recovery possible under those conditions.ï¿½ The optimization can be performed for a single completion operation during the pr ximum gas recovery possible under those conditions.ï¿½ The optimization can be performed for a single completion operation during the pr boundary measurements to place this first MRC well for the Kuwait Oil Company (KOC) entirely within the thin target zone.ï¿½ Real-time d

ested. Approval of the concept was achieved when the anticipated benefits were realized by monitoring the actual performance of the well. pressure and flow-rate control systems are discussed. Downhole control is modeled for electrical reversible hydraulic and unidirectional h d put on production and tested. The concept was approved when the anticipated benefits were realized during monitoring of the performan

covery by 90% in the early stage of production compared to the horizontal well. Thus the oil recovery using dual-lateral remains higher tha alize actual production that measures up to the forecasted potential of the well. After a well is constructed a communication tunnel is creat covered. We demonstrate the practical utility of this methodology on a comprehensive data set to enable unbiased and conclusive appraisa tem which was field tested for the first time in the world in a Saudi Aramco gas producer. The material is pumped as an inert solid which hy d predictability. Future plans include continuing to stimulate candidate wells by incorporating horizontal completion technologies that are mo

he fiber to bridge at the fracture entry face and divert the treatment into new fracture planes thereby improving the completion efficiency of ology combination additionally enhances fracture placement success. As the treatments significantly differ from the regular fiber assisted ap y instances acid fracturing ends up over-stimulating the highest reservoir quality zones and by-passing or under-stimulating the other zones ameters (including PI and Jd) evaluation. Analyses of the fracturing treatments have been performed based on bottomhole pressure gauge concentrations. Imbibition and drainage tests were done which allowed calculating the capillary pressures for the three additives. Drainage e mechanics fundamentals as well as the coupled fluid pressure effect in hydraulic fracturing. One important finding is that low-modulus laye er impurity composition and concentration it is extremely challenging to make a fracturing fluid compatible with produced water. Together w d crosslinked fluids are discussed. We will describe in detail how the salinity biological activity and scaling tendency of these waters can im mulation techniques (proppant & fluid volumes) and to validate the differences/ similarities observed between micro-seismic and fracture-pro intervals and mitigates the risk of growing the fracture into the water-producing zone. A case study of a frac-and-pack performed in a Lagun t the uncontrolled fracture height growth into the water zone is also considered to be a major cause of premature screen-outs. This is partic on drop to zero shortly after the completion in 2004 due to formation damage and incomplete cleanup. This technique combined mechanica r from high permeability intervals to low permeability intervals. These features are unique and inherent to its nature and the particular brea s well productivity. This paper describes the experience of three operators in Latin America that have implemented a new completion system

tion attempts with coiled tubing have yielded modest improvements mainly due to difficulty in accessing the long deep and high pressure/te

that had to be addressed. For Fracture containment Schlumbergerâ€™s Sonic Scanner tool provided rock mechanical stress data that wa oped in this work are provided for fracture stimulation design.ï¿½ A production optimization strategy is presented in this paper based on the

and highlighting the differences with the Western Siberian approach to hydraulic fracturing. Samara area is characterized with relatively low

ore inside the sliding sleeve. Pressure is then increased until the next valve is pumped open. When this valve opens the next control line is g sleeve valve shapes to verify the FEA study and to select the best valve shape. Openhole and perforated casing fracture initiation pres ergy dissipation in the plastic zone. The dependence of the apparent fracture toughness on input parameters and fracture width at the frac entire propped fracture design was successfully placed.ï¿½ Introduction Visco-elastic surfactants have been used in oil and gas wells fo

t and longer effective fracture half-lengths.ï¿½ Results also indicated successful stimulation past the cement squeezed intervals and tempo

performance. Detailed fluid system used in the treatment is discussed in details including the application of polymer-free viscoelastic surfac s of excessive filter cake thickness. Experimental data demonstrate that flow along the fracture would encounter lower yield stress when the oduction log interpretation in addition to production analysis.ï¿½ The results from each well are compared and contrasted and a plan for po

e detected fracture(s).ï¿½ The uncertainty of the relative positions between the monitoring and treatment wells can have a cumulative non-

cally moves the sample in selectable increments (typically 0.025 in.). With this device the surface of a standard API fracture-conductivity sa mostly fracture job size and cost. Height growth has also shown to be a cause of premature wellbore screen out. Fracture half-length and o associated with radioactive tracers. Once the proppant is placed in the well a gamma spectroscopy logging tool is used together with a fast

e wells for stimulation treatments was clearly needed. This paper describes the comprehensive methodology derived from integrated ana of permeability was explicitly modeled in the proppant pack by dividing it into segments and calculating the permeability in each segment. A wth. The flow within the reservoir due to leak-off is described by the 2D pressure diffusion equation. The formation is elastic and fracture gro ctant based acid did clean out in a shorter period of time. The main objective of this study was to compare the â€œlong term production re acture cleanup width changes conductivity degradation with time and stress effects are discussed. Field evidence indicates how these effe image the stimulated fracture network. Microseismic images can be used to map the fracture orientation complexity associated with interac se the fracture was created in a very weak reservoir formation. According to this model the fluid and rock skeleton are considered as two in he stress increase at the tip of the orthogonal fracture. ï¿½ï¿½ï¿½ï¿½Period II: Reopening of the initial fracture. This period shows a relativ e oil collecting area. Thus stability and quality of displacement of fracturing fluid is of key importance to provide free way for the oil and gas used in carbonates very few cases of its application in turbidites have been documented. Differential cased hole sonic anisotropy (DCHSA

t would significantly change the common industry practice of relying simply on an average polymer concentration factor.1-3 It is shown tha ected closure stress. Possible explanations for such behaviour were: (1) the development of a â€œtemperature sensitive emulsion in the re perations were evaluated in five different boreholes providing a diagnosis of the expected versus the measured fracture heights. It was obse slower fracture growth and shorter overall fracture length development compared with a straight fracture. Introduction Mapping of full-siz known and commonly used in nodal analysis and conventional gas lift design. Properly combining these components enables an auto gas l pes from sand control and well productivity standpoints. Characteristics of bp Trinidad & Tobagoâ€™s High-Rate Gas Fields Currently the ed completion options. First the horizontal section can be completed open-hole or with slotted/preperforated liner. In these completions effe ed completion options. First the horizontal section can be completed open-hole or with slotted/preperforated liner. In these completions effe reate a thin and reliable filter cake. While drilling this well it was believed that reservoir damage was minimized. It was also believed that th valve early water breakthrough can be delayed to increase recovery factor. Monitoring the flowing pressure in real time allows producing th hnology (first in Ecuador) in Block 15. The design and well preparation prior to completion operations and results are presented for two type w reservoir pressure high water cut and high back pressure from surface facilities or a combination of all three. As large oilfields around the early water breakthrough can be delayed to increase recovery. Monitoring the flowing pressure in real time allows producing the well at opti ested. The first is a simple passive approach using a fixed control device to balance inflow along the well sized prior to installation. The se cturing community has determined certain containment mechanisms that influence fracture growth (i.e. in-situ stress stress gradients rock

h resolution flow model with dynamic test data from a formation tester Interval Pressure Transient Test (IPTT) the model can be used to pre D MEMs were distributed in the 3D model using Gaussian sequential simulation technique. The populated 3D model was then used to perfo nditions.ï¿½ Acid was then injected into the perforations to create wormholes.ï¿½ The acid injectivity was measured and the wormhole patt 1 which was drilled by in the Tadrart sandstone formation of the Berkine basin. After successful results in this well the operator adopted its onal procedures. CTU with 1.5 CT reel was used to convey 140 ft of 2-7/8 gun due to crane and platform deck loading limitation. The small hnology that would improve productivity in the challenging wells of Santa Ana. This technology has been applied in similar scenarios across onveyed or tubing-conveyed perforation (TCP) depth uncertainties and the time requirement for TCP service in thin reservoir zones makes platform has the unique capability to orient guns along the PFP for optimal fracturing efficiency while simultaneously avoiding damage to co nterval is used to cleanï¿½perforation tunnels and produce low to zero damage perforation tunnels1-2. This paper describes how this new h an assumption that the skin factor remains constant during a test. The conventional analyses do not represent the underlying physics of th ng collar locator. The primary objective of the job was to ensure that the perforation was performed with maximum under-balance but not ex detonation conditions of the perforator. The model takes the total expendable energy from the explosives into account relates it to the ener

mic overbalance conditions in the wellbore in a system configuration which produced dynamic underbalance for the conventional charge. W ding to high skin and rapid production decline. The challenge in this field is to identify the most effective perforating system and job executio er) resulted in reducing the water cut (WC) form 20% to 0% maintaining the same required average oil rate (Fig. 1) and enabled better res the operator chose to maximize the integration of the services by bundling their acquisition from a single integrated services supplier rath e 6 1/2-in. drift diameter allows using common-sized screens and packers. The wells are generally completed with a 4 1/2 ï¿½ 3 1/2-in. tape ciated gas electrical submersible pumps (ESPs) have been used in Hawtah to enhance production since early 1990â€™s. Existing wells a s reperforated new screens run and a second frac pack pumped. When laying down the washpipe after the second frac pack erosion mar onsolidation) methods. A proprietary HDR squeeze pack technique (mechanical method) was identified as the best solution that meets post

welry reduces water influx fines migration and increases recovery factors and reserves.ï¿½ The Brunei Shell Petroleumâ€™s (BSP) Tali a etail the reservoir completion philosophy drilling and completion fluidsâ€™ systems and overall operational practices used in the Greater P

ee case studies the wells were gravel packed using shale stabilizer treated-brine in open-hole made up of sand layers containing shale with ater-based fluid. The packing mechanisms and efficiencies in these applications have been verified with downhole gauge analysis as well a gh the washpipe and casing-workstring annulus. In the open-hole section flow through the different annuli is considered and fluid is distribu with oil-based (OB) fluids which have yielded well productivities which in many instances exceeded those completed in water-based drill mpleted with brine as the carrier fluid (water packs). The proposed technique involves surging the perforations prior to the gravel-pack opera mpleted with brine as the carrier fluid (water packs). The proposed technique involves surging the perforations prior to the gravel-pack opera ade of production experience with this technique on the Norwegian Continental Shelf (NCS) confirms that oriented perforating can be a goo with similar characteristics occurred in Stag field. Water injection post wormhole-like failure has been reported very inefficient as the water ted as well as the key technologies involved from perforating to production. Each of the six case histories are examined in detail and will sh

n designs without knowing the cause of the sand and understanding the risks had been proved costly and would be likely to fail. To this en ata that in most instances will be unavailable or the acquisition of which will incur unwanted delays and costs. This paper presents the cas should have been sand-prone formation. Facing these apparent inconsistencies the investigation moved beyond an initial focus of sanding he degree of residual water saturation. The effect is most significant for sandstones with high clay content and low residual water saturation

which predict the extent of a yielded zone using various constitutive material laws. This assumes that all material from a yielded zone wil er and upper bound mud weights with depth were developed for typical vertical wells. Critical mud weight contour plots which show the varia e levels reached nearly 10 mol%. They were also utilized in gas wells to reduce acid leakoff and create deep fractures in dolomitic carbona . long in the leakoff direction. The long cores allow for better control of leakoff as the acid creates wormholes into the core samples. In thes id fracture stimulations. Chemical and mechanical means of diversion have been used with varying degrees of success. Likewise there ha cturing ends up stimulating the highest reservoir quality zones with minimal contribution from the other zones in many cases. Field trials inv cturing ends up stimulating the highest reservoir quality zones with minimal contribution from the other zones in many cases. A pilot involvi iscoelastic diverting acid system with a significant increase in production from the least prolific zones. Conclusions from this field trial ar d with a perforation density of about 5 shots per foot (spf) over relatively large perforated intervals spanning 180 ft and 269 ft respectively. t contacts water and that degrades when mixed with oil in the formation. The new fluid system is pumped before the acid treatment to effec esent paper describes a comparison of procedures and production gains during these acid stimulation treatments. The cost logistics and op

y in situ has shown that significant skin reductions can be obtained provided the proper placement techniques are used. However in certai ting a suitable organic acid for a specific acidizing treatment is more difficult due to complex thermodynamic equilibrium and reaction kinetic

atrix permeability after performing a static leakoff test (500-psi differential for 30 minutes) was less than 5% regardless of the fluid used. Fro techniques and they are often not applicable or not effective in wells with open-hole completion. More importantly mechanical means diver timulation treatment. Hydraulic fracturing treatments have become the most popular completion method in Russia and foam-based fracturin cury injection as well as resistivity measurements chemical testing etc.ï¿½ Each sample was then classified into a Reservoir Rock Type (R e response to original fracture jobs (IP) could play an equally important role if not greater in determining the success of restimulation. In fa ant based CO2-compatible high foam quality (>60%) fluid was proposed as the main fracturing fluid. This paper will discuss the first applica was recently selected for the fracturing treatments on three wells. Initial production from these wells was observed in the range of 5 to 7 MM ch subsequently provides the support for engineering decisions. Case histories discussed in this paper illustrate how distributed teams of

diversion systems placed with coiled tubing (CT) providing effective plugging of the layers producing water and providing a uniform stimula e cement log interpretations matched the communication test results. One well which communicated had 10 feet of apparent good cement w but is more accurate than the currently available methods. Calculating influx rates during the drawdown period is not an essential part of th point pressure estimation as well as quantification of reservoir parameters.ï¿½ This paper describes unique challenges encountered in inter l history as an extended drawdown and in combination with direct physical measurements of the flow rates and flowing pressures. Such a u e the permeability and skin of each layer. This information was needed for reservoir model calibration well productivity prediction low produ ng well. This paper proposes a method for identifying on the pressure and pressure derivative curves the unique characteristics of the diff as high as 0.1 psi. One of the constant background noises is the effect of tidal forces. In this work we present new formulae for radius of in eople and how they work together to achieve continuous reservoir and production optimization.ï¿½ Reservoir analysis for wells on electrical es regarding the successful and practical application of each method. In addition we show that with proper care and attention in applying th

m processing of Image Log data. Simulation of naturally fractured reservoirs needs defining fracture permeability shape factor and fracture duct controlled local production and interference as well as to enable the capture of reservoir fluids. Formation permeability anisotropy skin e data to estimate reservoir parameters (k s and p*). We also compute non-Darcy flow coefficient (D) using Swift & Kiel expression and the act of imperfect separation. 20 tests were performed considering 15 wells over a period of 10 days to assess MPFM performance and repe importance of the hydrate detection and mitigation processes is essential in the performance of successful tests in the Siberian gas well en

s could be greater than the gain expected from a stimulation or restoration. An inaccurate measure of oil rate also leads to a poor reconciliat al experience from the operations of various multiphase flowmeters in the area. Most of the gas condensate wells in the Yamburgskoe gasble accuracy and no additional measurements. The wet gas and low-liquid-volume-fraction interpretation model is described together with th t separators for fair evaluation and interpretation of wellâ€™s behaviour. The comparison indicated that the multiphase meter results were r

well based on the advantages and benefits of theï¿½ industry recognized Vx* Technology.ï¿½ In this paper we will review the benefit of th pressure data. â€¢ï¿½ï¿½ Use common data models like fluid (PVT) and SCAL data. Existing commercial well test and near wellbore mod s production data using the Î²-integral derivative function: Schematic diagrams of various production data functions using the Î²-integral der accurate and representative dp/dt curve by incorporating knowledge of both reservoir and pressure-gauge physics. This technique is efficien nts we believe these are the first streaming potential transients to be measured in an oil field. The field experiment results together with for

eing used to inject CO2 in the CO2CRC pilot geological storage project. The evaluation will draw on the design and job data and on a detai imum horizontal and maximum horizontal stress gradients on average equal to 15.98 and 18.13 MPa/km respectively corresponding to a n s based on experience in material aging and risk assessment of complex systems like nuclear structures where probabilistic simulations a al reservoir simulation models have been integrated with a network. As CO2 is captured it is transported and re-injected to neighbor reservo he importance of pre-injection studies as the wrong injection strategy may severely impact injectivity putting the project in jeopardy. Introdu ear to Berlin Germany. The target saline aquifer is the Triassic Stuttgart Formation situated at about 630â€“710 m (2070â€“2330 ft) that is monitoring techniques has recently been awarded a U.S. Department of Energy (DOE) project that will examine the application of time-lap and mechanical processes occurring during CO2 injection operations and the subsequent re-equilibration. The predicted stress path allows

ences gained on this well indicate that even longer wells can be drilled from subsea locations in the near future. Introduction The Visund voir sections without need for pilot holes or mechanical sidetracks. Additionally a new LWD tool that allows monitoring of the distance and d

w permeability that contains irregular dolomitized intervals. These dolomitized zones with higher porosity and permeability control the flow o evaluate the CO2 proven reserves has been designed. In addition analysis of wells deliverability of these natural CO2 reservoirs located at have been bypassed in offsets with the old cutoffs.ï¿½ Over a two-year drilling program data gathered from several field example well how that multilateral reentry drilling represents a very promising technology for developing medium/low permeability gas-condensate reserv ons to attain reasonable running times in the simulation process. Once the fluid behavior was successfully recreated and the model was se ogy consisted of the following main pillars: a) Utilize various reservoir diagnostics tools to identify fractures and sources of high GOR. b) Use

in fluid injectivity and original designed treatment was modified on site. This paper summarizes key lessons learnt including tool and packe o provide both proper zonal isolation and accurate treatment placement. The post water shut off treatment showed up to 70% water flow red ow success rate is due to poor diagnosis wrong selection of water shutoff solutions and how complicated the well completion is with respec to corrosion and degradation of completion and flow lines. It imparts higher hydrostatic pressure on the formation as water is heavier than ter zones and the effective cleanup of the isolated producing layers. The results of ten water control treatments are presented here. The a orm rigless water shutoff was needed due to the high demand and high cost of workover rigs. This paper will highlight the methodology eq d and intelligent CT enables real time downhole measurements via fiber optic telemetry system. The system consists of surface readouts in able fluid characteristics. In this paper we will review and provide a synopsis of some of these production hindrance elements. Consequen e new data provide new information on droplet sizes that can have significant impact on separator design. Data comparisons were performe ater cut to water holdup ratio. The experimental results of flow pattern transitions water holdups and pressure gradients are compared aga s introduced that creates the most accurate well model of an intelligent completion accounting for all effects influencing the pressure beha ocess facilities and its corresponding pipeline network. Built more than 25 years ago this PEMEX E&P facility originally designed for much to be a favorable option. Commingling of live crude oil with a gas stream may lead to precipitation of asphaltenes resulting from changes in subsea system design and operating procedures. The case study indicated if dead oil data was utilized the subsea system design and ope omplexities is impossible without real-time analysis. Recently NIR (near-infrared) spectroscopy has enabled the real time analysis of the C uld be mud filtrate or formation water. As a result in a well drilled with water based mud (WBM) contamination needs to be mitigated in sam

es with worldwide origins. The other two correlations are based on 851 lines of constant-volume-depletion data from 190 gas-condensate sa rs available in the literature such as Coatsâ€™ and Walshâ€™s) requires the use of data from PVT laboratory experiments and proper con fficulty accounting for any but the most basic of fluid compositional gradients. The conclusion followed â€œif it canâ€™t be modeled why d he downhole pump module. The fluid analyzers monitored downhole oil based mud filtrate contamination free gas presence water or oil flo fluid complexities effectively and efficiently. In this paper we highlight a successful â€˜continuous downhole fluid logâ€™ case to address wo approaches are prevalentâ€”simple correlations and equation-of-state (EOS) models. However in recent years artificial-neural-network cquired in formations subject to water-base mud (WBM) filtrate contamination. Dynamics of flow in OBM filtrate contaminated formations is s ressures has been established as the gradual variation of hydrocarbon quality in biodegraded oils. In addition heavy oils can show large co

It is shown that the existence of mobile oil could have been missed without effective formation testing practices.ï¿½ The third field exampl ully designed laboratory experiments; we have studied the H2S scavenging effects of different metals. The tests were conducted for differe

of measured data over a large geographic area. Correlating CO2 with formation temperature was a stepping stone to the yield/temperature r ologies combined with real-time monitoring and control and a more integrated evaluation approach produce a more robust interpretation of ation decisions and Field Development Plans (FDP). First part of this paper demonstrates an integration of available data including mud log nd gives concentrations for four group compositions (C1 C2â€“C5 C6+ and CO2) gas/oil ratio (GOR) and qualitative information regardin ethods of pressure gradient analysis and fluid contact determination. The interpretation techniques compared include traditional pressure-d ns in the pressure gradients which lead to erroneous interpretations of fluid contacts or pressure seals. Hence the models imposed on the ontamination monitoring algorithm. Gas/oil ratio (GOR) is an important property of crude oil and it is a vital input to the design of productio

ppear different. In order to test for the existence of such barriers pressure or fluid differences in their context must be assessed. Formation on of a continuous downhole-fluid log representing the fluid complexity in the reservoir. In addition by identifying abrupt changes in fluid pro hes are prevalentâ€”simple correlations and equation-of-state (EOS) models. However in recent years artificial neural network (ANN) techn

needs to account for water vapor.ï¿½ It is common in thermal simulation to use correlated or tabular hydrocarbon component K-values whic ormation water under predetermined pressure temperature and shear conditions. The stability of live emulsions was investigated using a

continental shelf. A wide range of formation fluids and permeabilities are examined in both oil-based and water-based drilling fluids. Results s and composition of the fluid sample. Despite advancements in the field of Downhole Fluid Analysis (DFA*) there have been ample instanc h temperature). This paper focuses on the Multiphase Active Sampling Device Service (MASS) a fluid sampling and analysis service that c rmination of in-situ volumetric ratios and determination of dry gas properties that can minimize an uncertainty propagated by the incorrect in nsidered. Association reactions of acetate ion with calcium ion are important for reactions of acetic acid with calcite. They cannot be ignored ove injectivity by targeting the possible sources of damage such as iron compounds calcite hydrocarbons clays and sand; however the e perature stir rate chemistry of the carbonate species and the concentrations (and concentration ratio) of calcium brine and carbonate spec e two commercially available products. The retention property for one of the three new chemicals was evaluated using two different core ma

phthenate-soap precipitation. The results of the particle-size experiments were described by a particle-growth equation and the parameters nt of permeability impairment created by the perforating process is obtained from perforation flow experiments where the post-shot produc essure in the rock surrounding the perforation tunnel as the wellbore pressure drops during for example a dynamic underbalance operatio wells. In some of the fields as many as 26% of the production wells experience scale-related problems. Up to 33% of electrical submersib d monitoring results from scale treatments together with a case study from the Uinta Basin. Introduction The purpose of a scale inhibition tr s control of scaling brine production and effective scale inhibitor placement are described. Calculations are performed for a North Sea fiel ells. A scale prediction simulator is used to identify wells with high scaling risk. Scale Risk Matrix (SRM) is being developed to classify the s ios in the rock matrix.ï¿½However when seawater is injected this equilibrium is disturbed.ï¿½Since the Mg/Ca ratio for seawater is ~ 3 t increases the effectiveness of history matching. In order to delineate reservoir regions that can be history matched independently principa injectors are also identified by the generated streamlines. In addition an injector efficiency software is used to calculate actual water contri under review.ï¿½ These include: Reduced cycle time leading to many more iterations of the entire decision-making workflow. Faster scen d heterogeneities at different levels introduced. In addition the models have utilized dual porosity dual permeability option to particularly han nes to process the data over the entire field. The data was then analyzed using a self-organizing-map engine to automatically identify wells ution long before the injected fronts reach producers or observers a better and more rapid understanding of the pilot arises from the crossw water shutoff operations and design new completions. Waterflooding the Cretaceous Mauddud reservoir is in an early stage of operations ensor gauge to obtain downhole pressures temperatures and vibration amplitudes of the system and to detect power-cable current leaks; eam injection process is that they accelerate early production and reservoir pressure decline while the equipment associated with steam inj d results in a higher production rate (Conaway 1999). Hot-fluid injection in-situ combustion and thermal stimulation are the thermal recover contrast to the Steam Assisted Gravity Drainage process (SAGD) HASD uses single horizontal wells cyclically switching between injection a g in Muglad basin rotary steerable system (RSS) has been deployed to drill horizontal well in Umm Bareira field. This field is shallow highly c resonance (NMR) logs Elemental Capture Spectroscopy (ECS) logs formation pressure measurements and routine core analysis. The p e the zone may miss a thin zone or in a formation with very low permeability and/or high fluid viscosity the contact area with the packer ma

horizontal well through reactive shales and channel sand environment.The paper also discusses about various completion strategies the re

ate and divert automatically based on in-situ gellation mechanism related to acid spending; thus achieving uniform distribution. In addition t

enezuela) was put in production a cluster with extra heavy oil reaching gravity from 8.6 to 11 API and with a viscosity range from 6 Pa.s to m

d not cause sand deconsolidation and maintained the integrity of sandstone cores. Corrosion tests conducted for low-carbon steel and 13 C obility (effective permeability) downhole PVT sampling for hydrocarbons confirmation and full laboratory studies of formation fluids before

es. Numerical studies were performed using a calibrated EOS description based on the fluid samples taken at a selected point of each res

g state.ï¿½ Conditions such as offshore wellbore temperature profiles and viscous heating in smaller diameter tubing can further complicate erns conductivity measurements solubility of reaction products reaction kinetics and corrosion tests were conducted at temperatures up to

factor and allows producing the well at optimum rate; i.e. above dew point pressure.Ultimately PDHMS will limit the future interventions. C discussed. Discussion on the rig-up of the fracturing vessel and the necessary modifications for efficient operation is also included. A review on concentration and mineralogical analyses indicate that the sandstone formation in this well has high content of iron-bearing minerals a d calcium silicon and aluminum that remained in solution over time. For comparison conventional mineral acid treatment of the field samp ature exceeded the technical limits of even this HT fluid simulations indicated that a series of cool-down brine stages would allow the applic ne. Higher volumes of brine clean up and lower flow initiation pressure gradient are observed after the treatment. Introduction The accum es described here be used as an additional input for the water chemistry models to improve confidence in their predictions. This will allow fo

he reservoir compared to conventional cased-hole staged completions. Significantly increased completion efficiencies have been realized in

process that will result in the highest recoveries while maximizing the net present value from the asset. Alternatively the case from the Midd ental fracturing techniques were tested including longer pump times larger sand volumes high viscosity fracture fluids re-fracturing for re-o ribution makes the fracture offset from maximal stress direction towards injection wells and this effect of local stress reorientation is more lik anding ellipse containing a simplified fracture network consisting of two sets of vertical planar fractures perpendicular to one another. This m ter zones. A perforation scheme was proposed to minimize intersecting the water sands. Several stimulation techniques based on the rock m

arginal offshore oilfields. Recent increases in oil prices and the success in onshore applications have encouraged the use of hydraulic fractu wells in the Xujiahe formation is to drill vertical or slightly slanted wellbore cased with 5.5 casing perforate and carry out proppant fracturing zontal drilling and horizontal sidetracking targeting low permeability reservoirs in mature fields. Introduction The South Umm Gudair (SUG) d 2008 which was not included in the model calibration is compared with our previously forecasted results. The comparison shows that the a mmingling production strategy Since a typical completion in the Uinta Basin may contain multiple producing sands (as many as 30) optim e-grid geocellular-model results. Pseudofluid properties (low viscosity) and a very long time scale had to be used because of the low permea this an enhanced high-resolution petrophysical analysis was created. This image-enhanced evaluation of reservoir properties was combine

the advantages and limitations of each image dataset and describes how the acoustic and micro-resistivity images are complementary to ea e gradients alone. An extensive Downhole Fluid Analysis (DFA) program was needed for fluid types and contacts determination. A multidisci us other techniques. However the ability to fully characterize natural fractures in terms other than pure qualitative (number of fractures obse and data acquisition procedures can greatly influence the quality and limits of data application. A field description operational lessons learn

ction even more critical. Additionally the challenges of the low permeability environment require specific attention to real time quality control s. The exploitation strategy of this pilot area demonstrated commercially sustainable production from the reservoir and will form the basis fo ble. This paper discusses ways to identify and manage risks when planning drilling and completing horizontal wells in tight-sandstone form e stromatolithic constructions which are more exposed to fractured formation due to high silification in the southern and northern slopes of t

njection effects all play a role in complicating interpretation of the pressure measurement data. In addition gauge effects depth errors form

ssed and undrained oil. Horizontal wells with state-of-art completion both in openhole and cased holed with suitable artificial lift techniques

ing historical decision making policy it is possible to identify and quantify an organizations strategic preferences and overall objectives. Suc uction Uncertainty assessment in the petroleum industry can be performed based objective information such as using analogs or actual pro and 40â€™s that running casing in vertical wells could be very problematic. One of the first theoretical attempts to explain what was happe ired. We explore the correlation between NMR and mercury injection porosimetry through laboratory experiments on core samples from a v nd operation. Furthermore the ERA measurements were carried out in conjunction with low-salinity water injection and production in the sam tween 2 rock types with same range of porosity but different porosity-permeability relation. Introduction It is nowadays common practice to heterolithics (thin alternation of sand/silt and shale). The vertical association of these facies in conjunction with azimuthal variation in dip pa he integration of core calibrated electrical borehole image analysis results with open-hole log data using neural network techniques. Deposit tion with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: C1 ethane (C2) p ow the downhole pump module. The fluid analyzers monitored downhole oil based mud filtrate contamination free gas presence water or o he connectivity of the features seen on the image. This is then used to define a high-resolution connectivity index. An integrated approach u r is oil bearing without a gas cap. The clay typing and the salinities of water bearing zone have an important bearing on the hydrocarbon sa porosity with additional measurements unique to the LWD arena including neutron capture spectroscopy and measurement of formation ca measurements not previously available in LWD such as formation capture cross section (sigma) and elemental analysis from neutron capt

uncertainty in the hydrocarbon saturation due to the uncertainty in the petrophysical and electrical rock properties. Fifteen wells with 1300 tify the uncertainty in the hydrocarbon saturation due to the uncertainty in the core and shale properties. Fifteen wells with 1300 shaly sand udy of a carbonate well in the UAE. The workflow will be reviewed in its entirety with particular emphasis on the relationship between log roc actures were characterized for their aperture (open or closed) intensity of fracturing and directional attributes. In addition to structural detai ther variables.ï¿½ The results are validated by comparison to core derived properties and formation tester mobilities.ï¿½ Incorporation of th ¿½ This comparison reveals the effect of the lamination geometry on the formation evaluation. We illustrate the effects of thin silt and clay

D fluids data is used to evaluate the hydrocarbon type and content in the thin sands. However shallow depth of investigation slow logging s acterize formation saturation through casing i.e. behind-casing-analysis (BCA) which includes PN and casedhole resistivity. Logging long h hanced fracture conductivity the completion optimization and the reservoir management for sustaining long term production in these comple lids production and mitigate problems of plugging during sampling operations the conventional approach has been to reduce the pressure hanical analyses involved using various logs to generate single- and multi-well Mechanical Earth Models (MEMs) describing rock stresses a e and track channels. Present study infers a possible definition of facies inside sinuous events and their exploration potential. Porosity estim

of the spatial continuity but also the sound inference of the reservoir properties from fine-scale well-logs to coarse-scale reservoir models. T ential reservoir. Therefore a real-time evaluation must identify with certainty the prospects to test. The sequence of real-time formation eva s makes fluid typing in the centimeter-thick sands problematic from conventional logs. Also formation pressure or sampling tools could hit-a

s depth correction for the effects of drillstring weight downhole friction weight on bit thermal expansion residual rig heave and tide. Anoth

ingle horizontal well. Poroelastic simulations show that the maximum stress trajectories tend to align along injection wells and across produ stic properties which are different from static values especially in case of Youngâ€™s modulus.ï¿½ To get continuous rock samples throug c data were suitable for the inversion of cross-dipole dispersions at three depths in shale as well as at a depth in a highly depleted sand res nal deliverability analysis techniques may also be employed to derive estimates of the reservoir drainage area in addition to the well and res nal deliverability analysis techniques may also be employed to derive estimates of the reservoir drainage area in addition to the well and res nal deliverability analysis techniques may also be employed to derive estimates of the reservoir drainage area in addition to the well and res ory well in the Arifjan prospect which is located on the eastern flank of the Greater Burgan field has opened up a large area that was previo ainly in the carbonate reservoirs either in Thebes or Mokattam Formation via Stoneley waves derived from processing result of sonic measu rehensive description is available on a previous publication1. The final geologic model served as a basis to select the locations for the new servoir model to study their influence on reservoir production. The relationship of the faults from the images with the seismic faults and the CFM). The final geologic model served as a basis to select the locations for the new wells. The new locations were proposed in the zones w

terpretation of all the data acquired from different sources development of algorithms/software to compute the movement of the injected flu ation. In this paper examples illustrate how the use of this technology helped Saudi Aramco effectively address these challenges. Introduc ility and permeability anisotropy as well as gave a fair idea of the open hole skin factor.ï¿½ Combination of the results gave altered zone rad

ily and truthfully correlated to true formation porosity core data information are available. The key to obtain a reliable and precise measurem mination of OBMF versus native oil. Additionally within the hydrocarbon column the NMR measurements can be used to provide continuou ping from NMR Relaxation and Diffusion maps to quantify small volumes of gas present in the water zone.ï¿½ This analysis enables us to c il. We make this investigation by three methods. The first method is to calculate a porosity sensitivity curve as a function of T1 T2 and D fo n revolutionary new methods for analyzing reservoir fluids rocks and fluid/rock interactions. The introduction of this technology came at a plication of quick-look log analysis techniques specially the Ratio" methodology and the free fluid and permeability indexes (NMR) with th eatures such as super permeable zones or fractures. Well performance evaluation shows that the integration of the flow profiles well perfor

mation is analogous to transient test data and can be used for the estimation of the reservoir-model parameters. With the progression of the matrix without one or two major fluid conductive fracture corridors. The main storage Mishrif layer unit 3 (M7 & M6) is within a 15% porosit

r well placement and more effective development planning. We highlight three case studies in which we have successfully combined variou sands are likely connected mitigating compartmentalization risk. This DFA log prediction protocol offers a new method to optimize wireline entional deliverability analysis techniques may also be employed to derive estimates of the reservoir drainage area in addition to the well an g wells may underestimate overall reservoir oil saturations. In order to enhance understanding of the recovery process a research program rs studied have been a) laminated low mobility and thin formations with varying water salinity b) high depletion resulting in extreme overba

ility anisotropy in sands. Formation microimagery data were used before and after stress tests to obtain information on least-principal-stres duction Pressure measurement plays an important role in reservoir management. Because of its dynamic nature pressure measurement pr e facilities/evacuation schemes were addressed by quantifying their impact on the ultimate recovery efficiency. During the optioneering exe data identified a number of potential hydraulically isolated hydrocarbon-bearing sands. During data acquisition the degree of uncertainty as letions.ï¿½ Candidates were eliminated due to wellbore dogleg severity and suspect gravel pack integrity.ï¿½ Reservoir simulations indicate ells in a portion of Block 10 operated by Petrobras Energia Peru S.A. in the Talara area of Peru to improve recoveries in a column of over 2 cers.ï¿½ One of the main challenges is to better utilize the lift gas consumption for the wells with unpredictable gas supply which creates si -bore tortuosity and a facilitator for optimal production. Due to the uncertainty that is inherently present in the distribution of the channel san abandon the hole and sidetrack the well with a new lateral utilizing directional and deep resistivity (DDR) while drilling to improve geosteer on. 2) Feasibility study investigated the field wide compression by use of Central Compression System. 3) This was followed by a stud cantly reduced. The optimized drainage pattern for the whole field also revealed significant future workover potential in shallower reservoirs s injection on field scale. The extensive study was conducted for a thin oil rim Brownfield at the upper limit of the current handling facilities. ng an intermediate point between the ESP and ICVs as a coupled node. The differences using a stand alone model and a coupled model nt logic is also presented. Introduction FM is the simulation workflow through which predictive scenarios are carried out to assist in field dev sion and treatment processes.ï¿½ By including the reservoir and processing components in an integrated model together with the gathering eservoirs gas re-injection and water injection based on an extensive prior screening exercise. The limited prospective increase in reserves run and results were reconciled. This was followed by incorporation of the surface facility constraints to identify bottlenecks. The compariso

es the modeling results from reservoir and well model with the surface facility network and process plant model. The coupling and integratio kms to the east. The current development plan shows six wells drilled and brought into production over an 18 month period. Reservoir 2 i ocess facilities and its corresponding pipeline network. Built more than 25 years ago this PEMEX E&P facility originally designed for much ring project execution by permitting tasks to be swapped between members.ï¿½ Furthermore introducing statistical methods to data handl ater cut reaches 96% using the existing producing well slots. Production logs (PL) are routinely run to evaluate zonal fluid production for res

state multiphase network simulation with a nonlinear multivariate optimization technique called Genetic Algorithm (GA) through a newly dev e fieldâ€™s production decline. Introduction The Huizhou Oil Fields are located in the Pearl River Mouth Basin South China Sea approxim ces. Understanding the resultant hydraulic fracture effectiveness is increasingly complicated by the changing mechanical and reservoir pro aracteristics. As a result a wide range of answers may be obtained from the same data set and frequent revision of the reserves number b future measurement of the degree of compartmentalization caused by this fault. We conclude that when faced with the possibility of obtainin

rmation dip. Inside a hydrocarbon bed real time resistivity images often yield dips that are more representative of stratigraphic features rath internal shale layers were mapped geosteering personnel had the ability to make changes to the directional plan to allow the well to be pla pattern.ï¿½ We illustrate this methodology for the case of a strong water-drive reservoir to be developed by horizontal wells under primary oir rock quality was below the minimum for a commercial completion. This brought into question the viability of any hydrocarbon storage ca cal factors how much data are needed how much resources are required how long will it take to come to a decision and what will be the c breakthrough. The wells were then translated into the dynamic simulation model where a detailed modeling of both reservoir inflow and well evious approaches such as finite-difference or stochastic-perturbation methods is that the method computes improving directions for all wel

utions in Laplace space we are able to model naturally fractured reservoirs wellbore storage non-Darcy D-factors as well as constant wel mparing our solutions with that generated using a commercial finite difference simulator. We find excellent accuracy with huge gains in mode ty of the travel time with respect to reservoir parameters such as porosity and permeability. The sensitivity calculations depend on the numb n data misfit is represented by a single generalized travel time misfit per well thus effectively reducing the number of data points into one pe

hen to find the weights used to combine the characteristic geological patterns such that difference in the historical data and the simulated re

parallel scalability of the simulator via testing a large scale SAGD model with 9 horizontal well-pairs. Introduction Numerical simulation of th ode base rather than custom one-off extensions of a more limited one. Currently we have tested and validated our approach on standard b roduction profile in the simulation model. For example an unfavorable combination of a sump (variation in depth) in the well trajectory and

ertain dynamic flow behavior which affects pressure and consequently production near the toe. Interference between individual laterals in

c plots generated from rate-time data and/or numerical iterative method. Once we are able to establish the dominant flow regime we can n ncrease productivity by means of significantly increased contact between the wellbore and the producing formation. To propagate an open f Using the model it can be shown that the residing non-recoverable gel (typically 50%) decreases the fracture conductivity and hence the btained. Sensitivities of key reservoir/well/fracture properties are investigated and a result of each case is presented. Finally an actual case rface in 3D permeable formation. Additional coordinate system inside fracture allows to simulate the heterogeneous internal structure of fra method is explained. The direct effect of bedding plane interfacial slip is on fracture height growth and width deformation but because of th onvergence and reservoir layering and geometry; they can be realistically simulated using explicit fracture modeling. The use of numerica udy of the relative effect of flow convergence vs. flow in the perforation tunnels is also presented to allow a quick assessment of the most d s in the solution. To deal with the situation we resort to production logs and data-independent prior information that can limit the â€œplausi wells in finite reservoirs.ï¿½ Example applications of the dimensionless productivity index and pseudosteady state shape factor solutions de erforated intervals) by the point source and radial flow ones. The new model therefore combines both radial fracture and flow geometries in different scenarios of fracture initiation and propagation were considered. We modeled the initiation and propagation of the fracture through ethods are approximately 50 to 200% larger than those obtained with RBFs. With a method that predicts fracture spacing more accurately w

tion characters. Due to these challenges we developed an unconventional approach to model this field and estimate its gas in place that h mperature option (ECLIPSE) which shows that the analytical solution yields reasonable temperature propagation profiles along the wellbore implication of IPI for an example waterflood field Casabe which has these challenges and required a new understanding of the waterflood ing these techniques resulted in a well-behaved model and a realistic production profile. ï¿½ Introduction The Samarang field is located o e the influence of reservoir pressure and PVT data on material balance calculations in an optimal and integrated fashion. In both methodolo zation and providing an example from the Schlumberger Consulting Services practice. The project was completed within a 4ï¿½-month tim d by the geothermal temperature gradient) which cannot be neglected in some cases; thermal diffusion might be the main phenomenon affe s of maturation it has been possible to capture many useful lessons. These lessons will both strengthen the benefits and ease the pains of

the optimization of linear solvers to the structure of TPFA matrices [3]. The TPFA is inconsistent with an O(1) error in flux if grids are not K n first of all this means to sufficiently describe condensate bank accumulation around wellbore zone. Condensate blockage of gas-condensa This paper describes a numerical scale-up technique to provide the composite properties and curves to be used in gas-oil displacements in h to history matching of naturally fractured reservoirs which includes (1) fracture trend prediction through elastic stress simulation; (2) geosta

tions. Conventional transfer function has been incorporated as a source/sink term not only in the streamline saturation equations (as it was ed for the update of the solution can be chosen independently for each streamline. Therefore there is no global time step restriction which logy is very robust with respect to fine-scale models containing geological objects such as fractures and fracture corridors. The methodolog

er conditioning models to production data in a Bayesian framework and wish to generate a suite (ensemble) of models which represent a co

ffects for immiscible calculations (eg water displacing oil) can be countered by pseudoisation of the relative permeability functions in finite d

e obtained adaptive grid. The performance of the resulting multi-resolution scheme on a synthetic and a real reservoir model is studied usi y to model detailed reservoir geology. This is motivated for example by important applications in gas condensate flows and modeling of CO ssociated uncertainty range. A data-driven expert system is used to identify and capture the correlations of the parameters such as geogra theoretical relation between randomized maximum likelihood and the ensemble Kalman filter. Although we have previously generated reser a from the multiple realizations is analogous to â€œtraining set of faces while the recorded or the historical data is the â€œface which nee onshore and offshore hydrocarbon reservoirs. Two main advanced well installations are inflow control devices (ICDs) and the flow control va

. Black oil reservoir simulation is computationally far less demanding than compositional simulation. It does not though provide the detailed n resistivity is only a function of the water volume fraction. Cw is shown to account for water connectivity effects in the pore network. These

of non-Darcy flow as one of the most critical factors in reducing the productivity of hydraulically fractured high rate wells has been docume which has a water-like pressure gradient and low formation resistivity.ï¿½The theory is supported by detailed analysis of examples from flow ase behavior the task of optimizing production is particularly difficult. All these factors coupled with the relatively conventional well geometr served locally at the central eastern and south-western part of GoS with an average orientation of N50degE. Most studies of the structural ssigning a value to â€œSmartness.ï¿½There is a tendency to assign value to discrete technologies as opposed to the holistic full project va spectives for conventional and new EOR methods. The main EOR experiences reviewed are chemical flooding (and flow diverting technolo d development history resource access and government take for the ANS and UK North Sea petroleum provinces using information avai methods are inconsistent. This paper critically reviews the published information and highlights the strengths and weaknesses of the previou

ommended. The results from the resistivity and nuclear measurements are discussed in detail with respect to environmental effects. This c timization. Additional value of the technology is demonstrated by the analysis of acquired downhole data. Productivity Indices are obtained The earlier practice was to utilize the workover rig and to remove the two production strings before performing any wireline logging in the w on logs to a measured depth of 9 775 m at a true vertical depth of 2 613 m. Comparison of cumulative flow rates from the array mini-spinn

analysis. Clearly a more flexible solution was required. In this paper we review the learnings from previous attempts in the Pinda. We show analysis. Clearly a more flexible solution was required. In this paper we review the learnings from previous attempts in the Pinda. We show learned from installation of this fully welded PDHMS. Introduction Reservoir monitoring is a key tenet for enhancing reservoir performance e technique is robust because the dye is isolated from the formation fluid and is injected into the sample only when a measurement is made er insight into the behavior increased knowledge of the production history and allows for estimation of subsidence and compaction effects d appear to be artifacts owing to the monitoring geometry not shear shadow as commonly interpreted. The additional located microseismic e eismic monitoring of fracture events during an injection test. As the industry comes closer to what is believed to be direct measurement of fr

By varying the injector-producer reservoir temperatures until the model temperature matches the measured distributed fiber optic temperat methodology is possible.ï¿½ Coupled with the numerical modeling of the Pulsed Neutron production log evaluation test pit measurements g methodology is possible. Coupled with the numerical modeling of the Pulsed Neutron production log evaluation test pit measurements of low distribution of multi-zone gas wells now becomes a simple slickline operation with no tubing shift required. Additional benefits are the de especially the contribution from the toe of the well; and Detect the location of water breakthrough. Results showed that within four hours on-logging tools surface-test separators and surface multiphase flowmeters but none of these provides a complete information solution. P

e actual results achieved. A Production Performance System (PPS) based on workflows can be implemented to calculate key performance scribed in this paper. The logging data also illustrates other dynamic fluid behavior that can reveal oil and water entry; for example a burst of asis test design exercise data acquisition program execution and observations and conclusions reached from this data set. Over the dura nconclusive. Consequently a fiber-optic-enabled coiled tubing string along with real-time bottomhole pressure and temperature gauges wer ptimize a well producing from naturally fractured carbonate reservoir with active water drive using a combination of modern technologies in ns of obtaining false or misleading information. The main objective of real-time monitoring remains to assure that the planned data are acqu easured temperature profile as long as there is no breakthrough of gas or water. The model is also used to define the limits of the technique n periods of accelerated seismic deformation followed by an associated period of accelerated uplift a few days later. This timing suggests th rence between the fiber-measured temperature and the geothermal temperature in the flowing reservoir intervals. Given the reservoir draw etion. Surface indication of landing was provided by incorporating mechanical feedback into the lower assembly. With the coupler componen within the vertical Mauddud sequence. A previous core study shows that the fractures in Mauddud formation are short (<10 cm) and concen

cation: focussing on accuracy of the volumes at outlets of the facilities. To minimize the error in the volumetric measurements at both ends en changes in phase behaviour due to variations in wellbore deviation are factored water inflow quantification is attainable. The conclusion

mediately after completion. During the production time of little more than one year the oil rate decreased by 70% with 84% water-cut. This nmental effects such as hydrochloric acid effect commonly seen in carbonate reservoirs after stimulation. This technique that utilizes open ency bypassed oil and effectiveness of stylolites across different units. The pilot results and observed data will be used in the simulation to and increases the resolution of the resulting inverted model. Introduction A few years after the discovery of a giant complex carbonate rese othing is known about perforating in coal. Predictions of perforation characteristics such as depth of penetration are based on correlations primary cleat direction and its relation with the in-situ horizontal stress directions define the fluid flow potential through the cleats and such i t fracturing for the stimulation of CBM reservoirs. From this data we present guidelines for when and where indirect fracturing is applicable n effort to identify the causes of these near-wellbore issues and to offer corrective solutions for future completions. The goal of this study is dicting the potential for problems during fracture initiation.ï¿½ Modeling near-wellbore effects in horizontal completions in anisotropic shale rder of magnitude change in available energy at the fracture face compared to current dynamic fracturing processes. The additional energy al information such as faulting and natural fracturing.ï¿½ The images can also be used to estimate the stress state along the lateral via the p acement and HFT schemes are performed. The microseismic (MS) has played an important role in understanding the estimation of hydraul of a simulation model what the expected production and steam requirements for these strategies would be. The simulation model examin anding rapidly especially in the south-central US (the Barnett shale and its equivalents) the Appalachian basin and numerous Rocky Moun ve demonstrated limited success using current stimulation techniques. This paper describes a new fracture diversion technique particularly nd cost consideration. However it is important to first rationalize the targeted productivity from the specific reservoir have specific properties oduction target an effective ESP replacement program is a core element of field production strategy. Therefore several measures such as r

tion tubular in a stepwise manner. The power fluid coming out from the other end of the venturi is used to drive a turbine which generates p horizontal completions was the more efficient use of existing wells. Poor vertical producers were sidetracked; the vertical wells released du al advantages such as eliminating the need to run a liner which requires good cementing isolation at the top; eliminating the cost of perfora lve a dart is dropped during the flushing operation. This dart lands on the squeezed C-ring and seals the bore inside the sliding sleeve. Pre r-wellbore permeability impairment. The near-wellbore alteration characterized by radial profiling of formation shear can be correlated with e completion operation during the productive life of the well or for a series of periodic well interventions during the productive life of the well e completion operation during the productive life of the well or for a series of periodic well interventions during the productive life of the well the thin target zone.ï¿½ Real-time decision-making was possible due to seamless integration of all data and interpretation from various disc

the actual performance of the well. Leveraged knowledge from this pilot has provided an insight into SC capabilities and implementation. M rsible hydraulic and unidirectional hydraulic valves. The design methodology for different valve systems is described and the disadvantages during monitoring of the performance of the well. Leveraged knowledge from this pilot has provided an insight into SC capabilities and imp

using dual-lateral remains higher than that of horizontal well as water cut increases. Production performance for both configurations become ed a communication tunnel is created from the casing into the reservoir through which formation fluids will flow into the well. For this purpo e unbiased and conclusive appraisal of ESP performance thereby resolving a common concern about comparative-system reckoning. The s pumped as an inert solid which hydrolyzes and converts to acid when exposed to water and heat resulting in heterogeneous etching and completion technologies that are more conducive to multiple fracture technology. This paper presents the evolution of the candidate selecti

proving the completion efficiency of the treatment. Lastly it was hoped that the introduction of the fiber which would dissolve shortly after pl er from the regular fiber assisted application in tight gas formations a series of experiments had to be performed to ensure full compatibility or under-stimulating the other zones. Consequently the zonal contribution from these wells is not optimal. A pilot involving use of a new deg ased on bottomhole pressure gauges data and well-supported with direct fracture geometry estimation obtained by using differential cased ures for the three additives. Drainage tests were performed on 1â€“3 and 0.1 mD cores. Capillary tube rise testing was also done as a check rtant finding is that low-modulus layers can also contain fracture height. The results from this study can be applied to hydraulic fracturing tre ible with produced water. Together with the need to gel produced water the demand for more conductive fractures along with the capacity ing tendency of these waters can impact fluid performance. Other factors including organics and suspended solids will be included in the d ween micro-seismic and fracture-propagation model predicted lengths.ï¿½ This paper demonstrates how reservoir characterization and co frac-and-pack performed in a Lagunillas field well with a water contact 40 ft below the target zone is reviewed. The intervention rendered an premature screen-outs. This is particularly true in cases when largemesh-size intermediate strength proppants are used. The systematic ap This technique combined mechanical and chemical diversion using selective openhole completion allowing the wellbore mechanical segme to its nature and the particular break mechanism making them suitable for selective placement and uniform zone coverage even for bull h plemented a new completion system to overcome the time consuming and productivity limitations of conventional completions described ab

the long deep and high pressure/temperature zones requiring treatment. Bullhead treatments at high injection rates have also yielded simi

rock mechanical stress data that was used to design the fracture to be contained within the zone of interest and not break into the water be resented in this paper based on the dimensionless productivity index solution for a vertically fractured well under pseudosteady state flow co

ea is characterized with relatively low temperature high permeability low pressure laterally and vertically restrained dome type sandstone a

valve opens the next control line is pressurized squeezing the next C-ring. The main feasibility issue with this cemented sliding sleeve co orated casing fracture initiation pressures were calculated as a function of rock properties and far field stresses on the rock. An openhole c meters and fracture width at the fracturing fluid front has been established. It reflects the specific feature of the granular medium deforming ve been used in oil and gas wells for fracturing stimulation for over ten years1.ï¿½During this time the technology has evolved from a nich

ment squeezed intervals and temporary liner tie-backs run in to overcome lower pressure constraints.ï¿½ Finally lower friction pressures h

n of polymer-free viscoelastic surfactant based fluids. Also a surveillance program was implemented to monitor and evaluate the acid treatm ncounter lower yield stress when the breaker is delivered directly to the filter cake as opposed to randomly distributed. The data also indicat ed and contrasted and a plan for potential future completions is discussed.ï¿½ï¿½ The microseismic event growth and fracture treating pre

nt wells can have a cumulative non-linear effect on inverted fracture parameters. Introduction Over the years a large number of hydraulic

standard API fracture-conductivity sample can be scanned in a few hours and a digitized profile image can be obtained. This digital image i reen out. Fracture half-length and orientation can have a significant impact on the effectiveness of pressure maintenance and flood efficien ging tool is used together with a fast neutron source to activate the tagging additive. The additive then becomes temporarily radioactive emi

dology derived from integrated analysis of the fracturing treatments performed between 2003 and 2005 in the Yamburgskoe gas-condensa the permeability in each segment. As a result of this modeling the impact of increased fracture length on productivity was found to be mor formation is elastic and fracture growth is based on Linear Elastic Fracture Mechanics. Results show that the tip zone can be either a recir are the â€œlong term production results obtained from five wells treated with the surfactant-based acid with off-set wells treated with in-situ d evidence indicates how these effects affect the fracture conductivity affecting deliverability and inflow performance. A practical performan n complexity associated with interaction with pre-existing fractures and to assess the temporal development of the fracture geometry (Warp ck skeleton are considered as two interpenetrating continua. The Mohr-Coulomb yield criterion with the non-associated plasticity rule written fracture. This period shows a relatively flat pressure since the stress at the fracture tip is nearly constant. ï¿½ï¿½ï¿½ï¿½Period III: Extensio provide free way for the oil and gas flow. However in frontal displacement of a more viscous fluid by a less viscous one from porous mediu ased hole sonic anisotropy (DCHSA) can be determined from analysing cross-dipole shear sonic data acquired before and after hydraulic fr

centration factor.1-3 It is shown that contrary to the current method that calculates an average polymer concentration the polymer in pra perature sensitive emulsion in the reservoir matrix (2) the effect of temperature in viscosity of our seawater crude (3) near wellbore damage easured fracture heights. It was observed that the geomechanical modeling predictions for some possible natural barriers due to higher valu re. Introduction Mapping of full-size hydraulic fractures during and after mining provides the ultimate ground truth for fracture geometry. Su e components enables an auto gas lifted wellâ€™s performance to be calculated and downhole equipment to be correctly sized and located High-Rate Gas Fields Currently there are six high rate gas fields that are being operated by bpTT in Trinidad & Tobago: Amherstia Flambo rated liner. In these completions effective stimulation along the horizontal wellbore is almost impossible. The second completion system ca rated liner. In these completions effective stimulation along the horizontal wellbore is almost impossible. The second completion system ca nimized. It was also believed that there would be no need to cleanup the mud and filtercake left in the hole and that the well would cleanup sure in real time allows producing the well at optimum rate; i.e. above bubble point pressure. Ultimately intelligent completions will limit the nd results are presented for two types of formations e.g. consolidated and non-consolidated. Detailed simulation models were performed an ll three. As large oilfields around the world mature ESPs will play a major role in maintaining production from these fields. In order to combi me allows producing the well at optimum rate; i.e. above bubble point pressure. Ultimately intelligent completions will limit the water handli ell sized prior to installation. The second and third control strategies are reactive employing intelligent completions that can be controlled f in-situ stress stress gradients rock mechanical properties frac-fluid rheology injection rate etc.). However predicting which variable or va

IPTT) the model can be used to predict the well performance. We investigate several key characteristics of thinly laminated reservoirs that ed 3D model was then used to perform a coupled geomechanical simulation to evaluate the changes in stress with time and production. Th s measured and the wormhole patterns through perforations generated by different perforating designs were compared using CT scans.ï¿ in this well the operator adopted its use in 2005 for two additional wells Well-2 and Well-3. The paper describes the application of the new m deck loading limitation. The small CT size and large gun conveyance required extra precaution since the presence of gun shock during pe n applied in similar scenarios across the industry in recent years although no documentation was found on its use in such low pressure env ervice in thin reservoir zones makes wireline-conveyed perforation an attractive method. However where multiple zones must be perforated multaneously avoiding damage to complex downhole completions without the expense of workover. This technology enables the enhanced This paper describes how this new perforating technique was used in two ADMA OPCOï¿½wells to wireline perforate in multiple runs a car epresent the underlying physics of the surge flow and lead to loss of useful information from the skin variations. Few SPE papers have inves maximum under-balance but not exceeding a safe drawdown on the formation and risking collapse of the perforation tunnels. With 1 000 p s into account relates it to the energy consumed by the functional and nonfunctional processes and describes the relationship of energy d

ance for the conventional charge. We conclude that the reactive liner charges tested are detrimental to productivity in naturally perforated c perforating system and job execution method to achieve good well productivity over an extended period of time. Modeling software is utilize rate (Fig. 1) and enabled better reservoir management. The results from this experience as will as other experiences have been utilized in gle integrated services supplier rather than contracting the required well construction services in a discrete manner as had been traditionall leted with a 4 1/2 ï¿½ 3 1/2-in. tapered-tubing string. Premium screens with shunt tubes are used on the wells because of the long deviate e early 1990â€™s. Existing wells are standard 9-5/8 vertical cased wells with perforations through the thin producing interval with ESP set r the second frac pack erosion marks indicated an apparent second screen failure. A detailed examination of both A1ST1BP1 frac-pack jo as the best solution that meets post intervention production requirements and also affords completion longevity. Total cost of deployment to

i Shell Petroleumâ€™s (BSP) Tali asset strategy has been driven towards highly deviated wells with Open Hole Gravel Packs.ï¿½ OHGP re onal practices used in the Greater Plutonio OHGP completions. It also discusses the fluids design phase of the project and the QA/QC proc

of sand layers containing shale without negative impact on completion time. Introduction Underground gas storage (UGS) services in Italy h downhole gauge analysis as well as mass balance calculations. Both wells are producing sand free with hydrocarbon production that met uli is considered and fluid is distributed based on the frictional resistances of the respective annuli. The simulator calculates the bed height hose completed in water-based drilling fluid environments. Currently techniques and fluid systems are available for gravel packing with eith ations prior to the gravel-pack operation followed by pumping the gravel slugs in a nondamaging carrier fluid in concentrations ranging from ations prior to the gravel-pack operation followed by pumping the gravel slugs in a nondamaging carrier fluid in concentrations ranging from at oriented perforating can be a good sand prevention measure in suitable fields. Despite this track record and the rock mechanical analysi eported very inefficient as the water passes through to producer via the wormhole channel and does not sweep any oil. Overall horizontal in es are examined in detail and will show that screenless completions provide effective through-tubing sand control in a variety of well conditi

nd would be likely to fail. To this end a SMS was implemented in Sarir field. The work started from geomechanical reservoir characterizatio d costs. This paper presents the case of a sanding study for the Messla field in Libya; a field that has produced oil for more than 30 years. T ed beyond an initial focus of sanding risk evaluation and sandface completion optimization. The final results revealed that the problems facin nt and low residual water saturation and is less significant for clean sandtones or those with high residual water saturation. The experiment

all material from a yielded zone will be produced as sand. Combining a model for a volumetric estimate of sand failure with a model for tra ht contour plots which show the variation of lower and upper bound mud weights with wellbore azimuth and deviation angle for preventing m deep fractures in dolomitic carbonate reservoirs (250 to 275ï¿½F). In addition they were successfully employed to stimulate seawater injec holes into the core samples. In these tests acid was pumped through the fracture for contact times ranging from 15 to 60 minutes. After th rees of success. Likewise there have been many attempts made in retarding the reaction rates of hydrochloric acids in high temperature e ones in many cases. Field trials involving the use of a new degradable fiber technology designed to achieve effective acid diversion during zones in many cases. A pilot involving the use of a new degradable fiber technology designed to achieve effective acid diversion during aci Conclusions from this field trial are that viscoelastic diverting acid systems can achieve full zonal coverage in stimulating large limestone nning 180 ft and 269 ft respectively. Hence adequate diversion of acid into the desired zones was a technical challenge. In addition the c ed before the acid treatment to effectively prevent the acid from stimulating high-water-saturation sections. The field results show significan reatments. The cost logistics and operational constraints due to specific Brunei offshore environment and conditions will also be discussed

niques are used. However in certain cases where natural fractures are dominant diversion effects can be noticed but are not optimal. An e amic equilibrium and reaction kinetics. The reactions between organic acids and carbonate are less understood than those of HCl with carb

5% regardless of the fluid used. From this testing it was concluded that the reduction in the permeability was due to the mechanical pluggin mportantly mechanical means diverts treatment fluids from the wellbore; however there is no control once the fluid enters the formation. C in Russia and foam-based fracturing fluids seems to be a possible solution to the above problems. Foam though has evaded application ssified into a Reservoir Rock Type (RRT) which is primarily based on the porosity spatial distribution (PSD) in the carbonate.ï¿½ Each RRT g the success of restimulation. In fact studies have shown that selecting poor or underperforming wells for restimulation is likely to result in his paper will discuss the first application of this visco-elastic based fluid on wells in Park County Wyoming. This paper will discuss stimula s observed in the range of 5 to 7 MMcf/D significantly greater than neighboring wells' gas rates of 2 MMcf/D stimulated with polymer-based er illustrate how distributed teams of experts use improved models to develop solutions for old wells and future development that focuses o

ater and providing a uniform stimulation fluid coverage across the entire pay zone. Subsequent production rates showed substantial oil prod d 10 feet of apparent good cement with the remainder poor. Its cement log suffered from eccentralization which negatively affected the cem n period is not an essential part of the analysis or modeling. Thus any noise in the data would not aggravate the accuracy of calculations. que challenges encountered in interpreting transient pressure data from this horizontal well due to multi-phase flow and short production tim tes and flowing pressures. Such a unique procedure provides a great advantage since parameters such as; permeability (keffective) fractu well productivity prediction low productivity diagnosis and remedial action selection. Two solutions were proposed to GNPOC; use the conve the unique characteristics of the different flow regimes resulting from these types of completions and to obtain various reservoir parameters resent new formulae for radius of investigation in radial-cylindrical reservoirs and new techniques for general systems. The new formulation ervoir analysis for wells on electrical submersible pumps (ESP) is challenging due to the restrictions imposed by the downhole equipment.ï¿ per care and attention in applying these methods deconvolution can be an important tool for the analysis and interpretation of variable rate

meability shape factor and fracture porosity in the fracture model. However in most simulation studies due to high uncertainties in estimat mation permeability anisotropy skin factor vertical connectivity and zonal productivity index are additional reservoir information that can be sing Swift & Kiel expression and then use an analytical pseudo-steady state equation to establish single point AOFP for each of the tested z ssess MPFM performance and repeatability in a wide range of conditions. In most cases it was found that the meterâ€™s performance co sful tests in the Siberian gas well environment. The paper details the methodology of the comparison of the well test rates of gas and cond

rate also leads to a poor reconciliation factor and poor estimation of reserves. By resolving these inaccuracies and allocating oil correctly to nsate wells in the Yamburgskoe gas-condensate field are flowing with liquid unloading issues in a slug flow regime that can be observed and n model is described together with the multiphase flowmeter. Examples of applying this model to data collected on flow loops are presented the multiphase meter results were relevant and accurate. In conclusions the water cut measured by MPFM was almost three times more th

aper we will review the benefit of the combination of Venturi and gamma ray fraction meter and its application to gas well testing. Today th rcial well test and near wellbore modeling software packages were used to carry out this task. These packages provide engineering interfa ta functions using the Î²-integral derivative formulation (type curves). Analysis/interpretation of production data using the Î²-integral derivati ge physics. This technique is efficient and straightforward to implement and may be used on both real-time and recorded data. No modificat experiment results together with forward and inverse modeling studies indicate many possible applications of transient streaming potential

design and job data and on a detailed analysis of the high-resolution 3D cement imaging log to characterize the cement and ensure the lon m respectively corresponding to a normal stress regime. Introduction Warming of the climate system in relation with the radiative forcing o es where probabilistic simulations are performed. It accounts for all stakes involved in well integrity management and enables the full integr d and re-injected to neighbor reservoirs as an enhancement process for productivity or for storage purpose. After proving the feasibility of f utting the project in jeopardy. Introduction Selection planning construction and management of CO2 storage sites are still in its infancy. On 0â€“710 m (2070â€“2330 ft) that is made of siltstones and sandstones interbedded by mudstones. A comprehensive borehole logging prog l examine the application of time-lapse (4D) seismic technology and advanced reservoir simulation to optimize CO2 EOR operations.ï¿½W n. The predicted stress path allows the evaluation of the mechanical stability of both cap-rock and faults (which may bound the reservoir pe

r future. Introduction The Visund field is located in block 34/8 in the North Sea 150 km west of Norway (Figure 1 2 3). The field was dis ws monitoring of the distance and direction to formation boundaries up to 15 ft away from the wellbore has been used to proactively guide t

y and permeability control the flow of fluids through these reservoirs. This project utilized 4D seismic reservoir simulation and a new well d ese natural CO2 reservoirs located in the southwestern portion of Tampico has been carried out. In order to understand better this field a red from several field example wells were analyzed. These are presented here to illustrate how production data was utilized to continuous permeability gas-condensate reservoirs.ï¿½ Introduction Gas-condensate fields have significant industry importance.ï¿½The profitability ully recreated and the model was set up a sensitivity analysis was conducted using thermal simulation. The parameters analyzed were verti es and sources of high GOR. b) Use of flowing cross-linked polymer gel combined with a ringing type of cross-linked polymer gel as a capp

sons learnt including tool and packer conveyance mixing and pumping of water shut-off fluids under offshore rig and wellsite conditions. It ent showed up to 70% water flow reduction from the targeted layer has been achieved. Introduction Fulfilling requirement such as limited o ed the well completion is with respect to the zone of interest to be treated. Field X 1 2 which consists of a large gas cap and a 100-ft total e formation as water is heavier than oil thus reducing the pressure available for carrying oil to the surface. In many cases high water produc eatments are presented here. The average water cut was reduced to 30% from 88% and oil production was increased by an average of 300 er will highlight the methodology equipment and procedure used in the first rigless horizontal WSO in South Ghawar area by Coiled Tubing stem consists of surface readouts including dynamic interpretation software fiber optic cable and bottom-hole sensors which provides Cas on hindrance elements. Consequently we will discuss how some of these elements can affect the field development planning by utilizing a n. Data comparisons were performed against the data of Trallero (1996). Three probabilistic distributions were tested for fully dispersed flow ressure gradients are compared against predictions of the Zhang and Sarica (2006) model. The model performance is analyzed based on th fects influencing the pressure behavior in the wellbore and in the reservoir.ï¿½This model is used for optimization over all static and dynam acility originally designed for much higher gas and liquid rates than the current ones faced several slug and counter-pressure problems ar sphaltenes resulting from changes in composition.ï¿½ Changes in pressure and temperature can also take the system across the boundarie the subsea system design and operating procedures would be considerably more conservative than if live oil data was the basis of the de abled the real time analysis of the CO2 content in downhole fluid samples. This paper describes a new method for using DFA (Downhole Flu mination needs to be mitigated in samples captured for the purpose of quantification of CO2 in a given reservoir. This paper presents field e

n data from 190 gas-condensate samples also with worldwide origins. Introduction Correlation equations for gas condensates based on r oratory experiments and proper construction of EOS models. We used Whitson and Torpâ€™s method to generate our database of the MB â€œif it canâ€™t be modeled why do I need to know about it? It turns out what you do not know can hurt you. There is a growing realization n free gas presence water or oil flow at selected depths. The surveys identified the downhole fluids and clarified oil gas and water bearing nhole fluid logâ€™ case to address complexities of reservoir fluids in a complex carbonate reservoir. The â€˜continuous downhole fluid Logâ ecent years artificial-neural-network (ANN) technology has been applied successfully to many petroleum-engineering problems including th filtrate contaminated formations is significantly more complex. A time-dependent coupling between fluid dynamics and phase behavior con ddition heavy oils can show large compositional variation due to variations in source rock charging but without fluid mixing [1]. Using this m

practices.ï¿½ The third field example of formation testing with low porosity as well as low resistivity is provided for the identification of mobil The tests were conducted for different concentrations of H2S at a pre-defined flowrate and in the presence of water in order to quantify H2S

ping stone to the yield/temperature relationship. This approach is applicable for the analysis of both single-reservoir and multireservoir samp uce a more robust interpretation of the fluids and yield insights into reservoir architecture. Introduction Sage and Lacey (1938) define comp n of available data including mud logs gas chromatography gas wetness ratio well logs formation pressure and DST in order to determine and qualitative information regarding heavy-end content and stock-tank crude density. The analyzer showed that the hydrocarbon fluid in a pared include traditional pressure-depth graphical methods the excess-pressure method and statistical tests. Depth dependent fluid prope Hence the models imposed on the pressure data to calculate pressure gradients need to incorporate a rigorous mathematical approach to vital input to the design of production facilities. Conventionally GOR is measured at a PVT laboratory and it may take many weeks before

ntext must be assessed. Formation tester data must therefore be treated by means of a systematic analysis so that different sources of inf dentifying abrupt changes in fluid properties that occur with depth the FCA may in some circumstances be an assay for reservoir compartm artificial neural network (ANN) technology has been successfully applied to many petroleum engineering problems including the prediction

drocarbon component K-values which are dependent on pressure and temperature1 rather than predict these from an EOS.ï¿½ Although m emulsions was investigated using a fully visual pressure/volume/temperature (PVT) cell while viscosities were measured using a precalibra

d water-based drilling fluids. Results from focused sampling are compared directly with conventional sampling in the same reservoir zones. FA*) there have been ample instances of recovering contaminated gas-condensate samples. This paper discusses an innovative techniqu sampling and analysis service that can be provided with the Vx* multiphase metering technology with the objective of collecting representati rtainty propagated by the incorrect input of key fluid parameters in the computation algorithm of multiphase flowmeter. Not only does this st with calcite. They cannot be ignored even at low acetic acid concentrations. Strong inorganic acid HCl can increase the conversion of orga ns clays and sand; however the effectiveness of these treatments has had a limited effective time frame of a few months with suspected of calcium brine and carbonate species. This technique is also applied in actual core tests where a sandstone core saturated in calcium bri valuated using two different core materials. The test results showed a satisfactory amount of adsorption under favourable pH conditions. Co

rowth equation and the parameters of the equation were correlated with respect to pH. The core-flow experiments proved the occurrence o iments where the post-shot production flow is compared to an idealized flow measurement in the virgin rock. Direct measurement of the ex e a dynamic underbalance operation. From this we calculate the magnitude and duration of the induced surge flow. The third stage in the s. Up to 33% of electrical submersible pumps (ESP) failures are related to inorganic scales. Further the candidate selection process provide n The purpose of a scale inhibition treatment is to prevent the formation of inorganic scale deposits such as sulphate and carbonate scales s are performed for a North Sea field with a barite scaling risk and the cost benefit - specifically to scale management - of using ICVs is ev is being developed to classify the scale risk in each well. The Chlorides content the percentage sea water in the produced water the produ he Mg/Ca ratio for seawater is ~ 3 to re-equilibrate an ion exchange mechanism causes magnesium to be retained from the brine phase o ory matched independently principal component analysis (PCA) of the Hessian matrix has been done. The Hessian matrix summarizes the used to calculate actual water contribution of each injector to each producer from the well allocation file generated by the streamline simula cision-making workflow. Faster scenario analyses and decision-making. Better understanding of intra-reservoir communication. Better und ermeability option to particularly handle the matrix contribution to the production anomalies. Because the gas cap continues to advance the ngine to automatically identify wells where fluid loading impedes production. Daily production rates were also computed using nodal models ng of the pilot arises from the crosswell electromagnetic technique. In this paper we briefly describe the pilot design describe the detailed g voir is in an early stage of operations. Water injection commenced in 12 of 17 predrilled waterflood patterns in 2000. These wells were drille o detect power-cable current leaks; a four-pole motor; a protector; a 4:1-ratio gear box; and the PCP. The functional design of the bottom-dr equipment associated with steam injection including steam boilers insulated pipes and proper facilities are designed ordered installed and stimulation are the thermal recovery methods (Prats 1982). Microwave heating is a thermal stimulation method and in the past microwave clically switching between injection and production phases. The steam chamber generated while each well is injecting is laterally driven by t eira field. This field is shallow highly unconsolidated and heavy oil with viscosity nearly 350 cp. This methodology of drilling has resulted int nts and routine core analysis. The porosity partitioning model allows the core porosity-permeability relationship to be reproduced from logs the contact area with the packer may be too small to let the fluid flow. To help overcome this technique of Wireline Formation Tester (WFT)

various completion strategies the results of well placement value of using new technology lessons learnt and cost /production analysis. T

ng uniform distribution. In addition the new acid system has a unique inherent property to limit acid penetration in high water saturation zon

th a viscosity range from 6 Pa.s to more than 20 Pa.s at line conditions. As per fact this new production cluster did not have any data and

ducted for low-carbon steel and 13 Cr coupons demonstrated that the fluid had lower corrosion rates. Introduction Sandstone acidizing is a y studies of formation fluids before the production phase of the field. Rig time constraints were one of the main issues for the extended form

aken at a selected point of each reservoir. Comparisons of measured data and calibrated model show that the EOS model quantitatively (w

ameter tubing can further complicate the task.ï¿½ Various chemical means have been employed to tune the crosslinking temperature for sp ere conducted at temperatures up to 300oF. The studies demonstrate that the new system results in heterogeneous etching and wormholin

S will limit the future interventions. Completion Design: JFYN-01 was completed with 4-1/2 tubing during June 2007. Permanent Down Ho operation is also included. A review of the treatments indicates that the majority of them are conducted at a flow-rate of 20-25 bbl/min (bpm h content of iron-bearing minerals and a moderate content of sensitive clays. Results of core flooding tests conducted on the damaged fiel eral acid treatment of the field samples generated high levels of metals in solution that declined over the same period of time which is indica n brine stages would allow the application of this fluid at this temperature (280F). The characteristic of the fluid allowed the treatment to be c treatment. Introduction The accumulation of water near the wellbore or fracture face can decrease the relative permeability of oil/gas.[1in their predictions. This will allow for more efficient selection of completion materials and planning for scale treatment and mitigation. In th

on efficiencies have been realized in all areas of the Cleveland tight gas sand resulting in reduced completion costs and reduced overall co

Alternatively the case from the Middle East shows the application in a gas-condensate tight gas reservoir in an emerging area. The challen y fracture fluids re-fracturing for re-orientation using temporary degradable fiber plugs between stages and plugging of stages with ball se local stress reorientation is more likely to occur in low permeable formations with low diffusivity and low stress orientation anisotropy. A num perpendicular to one another. This model provides a mathematically-equivalent description of the process of hydraulic fracture propagation ation techniques based on the rock mechanical model of the sands were evaluated. These included treatment with slick water crosslinked p

ncouraged the use of hydraulic fracturing in offshore applications. This study documents the successful effort of taking these techniques to ate and carry out proppant fracturing treatments. Fracturing treatments in vertical wells yield mixed results mainly due to strong heterogene tion The South Umm Gudair (SUG) and South Fuwaris (SF) fields are located in the PNZ between Kuwait and Saudi Arabia. The fields wer ts. The comparison shows that the actual well production of most of the wells is close to our forecasted results. The production-validated res ucing sands (as many as 30) optimizing the completion strategy may be a challenging task.ï¿½ Completions are designed to optimize the be used because of the low permeability of the sands. The fluid recovery and injected fluid breakthrough times for the flow models and the of reservoir properties was combined with production modeling. The production performance was simulated for each interval and used for r

vity images are complementary to each other. The paper also presents how different datasets gives partial contribution to the overall geolog contacts determination. A multidisciplinary team between the operator and the service company was organized to carefully consider of the qualitative (number of fractures observed open or closed) has been limited in application and often only address conductivity. Based on ca escription operational lessons learned data quality observations and conclusions are presented. This case study represents a statistically

attention to real time quality control and evaluation of the test data as it is acquired. In this paper we discuss best practices for formation te e reservoir and will form the basis for full field development. Introduction The Priobskoye field located in the central part of west Siberia w rizontal wells in tight-sandstone formations to improve success. Evidence has shown that shortcuts and blanket approaches do not work us he southern and northern slopes of the Madrinskiy and Irkineevo-Katangskiy rifts respectively. Besides highly productive may turn out to be

on gauge effects depth errors formation thicknesses and fluid density contrasts yield potentially large uncertainties in interpretation of gra

with suitable artificial lift techniques were considered as one of the IOR option for maximizing well productivity in these thinly bedded heavy

ferences and overall objectives. Such findings can then be used in the multicriteria decision analysis process to further distinguish a compa such as using analogs or actual production data as well as by interviewing experts [1 2 3]. Traditionally expert judgment considered to be attempts to explain what was happening down hole by Macdonald and Lubinsky in 1951 (Ref#1) gave rise to the â€œCrooked-Hole Formu periments on core samples from a variety of carbonate rock types. We further investigate the feasibility of determining primary drainage cap er injection and production in the same well. It was found that the ERA voltages near a source electrode showed unique characteristics that It is nowadays common practice to run conventional logs at all wells such as gamma ray density spontaneous potential neutron and indu tion with azimuthal variation in dip patterns and image texture led to identification of different architectural elements of the system. The sedi neural network techniques. Depositional environments were then determined from correlations based on logs stacking patterns facies asso ps to five groups: C1 ethane (C2) propane to pentane (C3â€“5) C6+ and CO2. These spectrometers together with improved composition nation free gas presence water or oil flow at selected depths. The surveys identified the downhole fluids and clarified oil gas and water bea vity index. An integrated approach using the NMR and the image is being proposed to identify such high permeability streaks that can expla rtant bearing on the hydrocarbon saturation computation. Based on the available core data production data and the volumetric computatio py and measurement of formation capture cross section (Weller et al. 2005). The EcoScope multifunction LWD service integrates all of thes lemental analysis from neutron capture spectroscopy used to compute formation mineralogy.ï¿½An entirely new LWD measurement has a

properties. Fifteen wells with 1300 shaly sand points from Alam Bewab formation in Western desert of Egypt were used as our data base . Fifteen wells with 1300 shaly sand points from Alam Bewab formation in Western desert of Egypt were used as the data base in generat on the relationship between log rock texture and permeability capillary pressure and relative permeability. Introduction Many of the giant c butes. In addition to structural details the Oil base mud imaging provided quantitative resistivity of invaded zone measurement in oil-base-m ter mobilities.ï¿½ Incorporation of the pore size information into the log based interpretation reduces the scatter in computed permeability to trate the effects of thin silt and clay laminations on wireline formation tests and on the productivity and flow profile of a production test. The

epth of investigation slow logging speed and sometimes unfavorable signal-to-noise ratios limit the applicability of the NMR technique. In casedhole resistivity. Logging long horizontal intervals of BCA services is different from logging vertical wells. First of all the issue of vertical ong term production in these complex reservoirs. Wells with high fracture density usually correlate with high production rates as long as the ch has been to reduce the pressure drawdown and limit pump speed and flow rates. To increase tolerance to solids production during samp s (MEMs) describing rock stresses and rock mechanical properties. Using uniaxial compressive strengths (UCS) tensile strengths rock stre r exploration potential. Porosity estimation using seismic attributes as well as borehole data provides most likely reservoir properties exist in

to coarse-scale reservoir models. The latter can be achieved through appropriate inference of frequency statistics coupled with spatial stati sequence of real-time formation evaluation described here consists of the following steps. Wellsite petrophysical analysis of: porosity vo ressure or sampling tools could hit-and-miss the thin sands. In contrast since gas oil and water have different properties fluid typing techn

residual rig heave and tide. Another significant inaccuracy source is a standard practice of calculating borehole position from stationary s

ong injection wells and across production wells. The extent of stress reorientation varies depending on the injection rates reservoir pressure get continuous rock samples throughout the depth of the reservoir and conduct triaxial tests to determine the static values of these paramet a depth in a highly depleted sand reservoir. There was one depth in shale above the depleted sand where we could estimate the minimum h e area in addition to the well and reservoir parameters that can be obtained in a transient flow analysis.ï¿½ Applications of the analyses rep e area in addition to the well and reservoir parameters that can be obtained in a transient flow analysis.ï¿½ Applications of the analyses rep e area in addition to the well and reservoir parameters that can be obtained in a transient flow analysis.ï¿½ Applications of the analyses rep ened up a large area that was previously considered to be nonproductive. It has been noticed that there is excellent correlation between the m processing result of sonic measurement. This is combined with the petrophysical interpretation using the elemental spectral device data is to select the locations for the new wells. The new locations were proposed in the zones with the most intensive development of a network ages with the seismic faults and the fractures were also studied.ï¿½ Interpretation of high-resolution image data from 24 wells indicates the ations were proposed in the zones with the most intensive development of a network of natural fractures (according to the model). The drilli

ute the movement of the injected fluid through the reservoir and the inversion of multi-source and multi-physics measurements. This monit address these challenges. Introduction The modular design of advanced formation testers provides accurate pressure profiles and makes n of the results gave altered zone radius altered zone permeability virgin zone permeability and anisotropy on a comparative basis between

tain a reliable and precise measurement of porosity through NMR in these complex environments is based on the optimum selection of the ts can be used to provide continuous logs of oil viscosity and gas-oil ratio (GOR). With this information acquired before the sampling operat ne.ï¿½ This analysis enables us to calculate the fluids composition in the invaded zone and to improve the accuracy of density porosity eve rve as a function of T1 T2 and D for multiple acquisition modes. The second method is to invert simulated NMR echo data. Lastly we com uction of this technology came at an opportune time. It coincided with rapidly declining production after the 1970s drilling boom and the ne permeability indexes (NMR) with the aim to evaluate those intervals of major potential in the well. The following step consists of a detailed a ration of the flow profiles well performances and all other reservoir data provided improved reservoir characterization and better well produc

ameters. With the progression of the drilling process the amount of available inflow data increases and allows for a sequential history-matc 3 (M7 & M6) is within a 15% porosity layer that is 10-15 ft thick and contains a large volume of oil. Previous wireline image studies carried o

e have successfully combined various fluid-based techniques for improved reservoir characterization. Introduction Determining connectivity s a new method to optimize wireline logging. Introduction Knowledge of reservoir architecture is critical to successful development planning ainage area in addition to the well and reservoir parameters that can be obtained in a transient flow analysis. Applications of the analyses re covery process a research program was undertaken to investigate the true post aquifer sweep remaining oil saturation. Included in this pro epletion resulting in extreme overbalance for some layers in new wells c) possible formation damage while drilling d) cable creep while sta

information on least-principal-stress direction.ï¿½ Challenges created by the harsh working environments in western Siberia were address ic nature pressure measurement provides essential information on well productivity and dynamic reservoir description both in exploration a ciency. During the optioneering exercise more than 100 unconstrained options for seventeen stacked reservoirs were identified from the p uisition the degree of uncertainty associated with some of these intervals was perceived as significant for the estimation of oil in place and ty.ï¿½ Reservoir simulations indicate the three ESPs will add approximately 2.8 million barrels incremental oil production over 10 years with ove recoveries in a column of over 2 500 ft of shaly sands with absolute permeabilities not higher than 1 md and with average well spacing dictable gas supply which creates significant instability in the field.ï¿½ï¿½ Hence fieldwide gas lift optimization is one of the main initiatives in the distribution of the channel sands the prediction of the azimuth of channel meander can now be confidently solidified with new deep a R) while drilling to improve geosteering and optimizing of well placement.ï¿½ The DDR measurements provide remote detection of bed bou m. 3) This was followed by a study to determine the economics of well site compression versus central compression system. 4) Finan ver potential in shallower reservoirs maximizing contingency and lifetime value of infill wells. Introduction Stacked reservoirs are a commo mit of the current handling facilities. Two gas injectors in the gas cap aid the reservoir energy by re-injecting a portion of the produced gas. alone model and a coupled model were analyzed. Given that in both models the main constraints are handled in different ways the calcula s are carried out to assist in field development plans surface facility design/de-bottlenecking uncertainty/sensitivity analysis and instantane ed model together with the gathering network static boundary conditions become dynamic enabling a true system-wide optimization that gr ed prospective increase in reserves highlighted the need for a technically sound but also financially feasible solution. Since the current facili identify bottlenecks. The comparison between standard analysis and the new approach gave a more reliable platform for predicting field pe

t model. The coupling and integration allows investigating the impact of changes in one model to all the other models and hence also handl r an 18 month period. Reservoir 2 is a marginal development the viability of producing this reservoir will depend on quantification of the re acility originally designed for much higher gas and liquid rates than the current ones faced several slug and counter-pressure problems ar ng statistical methods to data handling history-matching and risk analysis streamlines the activities and reduces the turn-around time for th valuate zonal fluid production for reservoir management and to screen for suitable candidates to perform water control operations during ES

Algorithm (GA) through a newly developed and commercially available optimization application called Avocet Gas Lift OptimizerTM. The pr h Basin South China Sea approximately 190 km southeast of Hong Kong (Figures 1). Agip Chevron and Texaco signed the contract in 198 nging mechanical and reservoir properties related to depletion and intralayer communication (crossflow). Gas is produced in the Saih Ra nt revision of the reserves number becomes unavoidable. However it has been our experience that the accuracy can be greatly improved th n faced with the possibility of obtaining new and useful information in the future our methodology provides a quantitative valuation framewor

entative of stratigraphic features rather than structure defining reservoir boundaries (from surrounding conductive shale beds). The deep-re tional plan to allow the well to be placed in the optimal location at the top of the reservoir often within 2 ft of the roof without reservoir exit. ed by horizontal wells under primary production.ï¿½Specifically we examine how the field production profile and recovery factor is affected a bility of any hydrocarbon storage capacity in the northern portion of the field. As soon as the updip sidetrack well was logged a â€œwhat-i to a decision and what will be the certainty of the output.ï¿½ Recapitulating the approach presented here allows selecting candidates for ing of both reservoir inflow and well bore hydraulics were used to optimize the flow at well completion level. An iterative process was used t putes improving directions for all wells in only one forward (reservoir) and one backward (adjoint) simulation. The process is repeated until n

cy D-factors as well as constant well pressure production also all within a full field multi-well scenario.ï¿½Our method therefore provides nt accuracy with huge gains in model building and execution times. Our solution is suitable for a number of applications. These include pres ty calculations depend on the number of wells integrated which can be orders of magnitude less than the number of data points or the mod he number of data points into one per well. Third we solve the Adjoint system of equations backward in time in larger time step that is equiv

historical data and the simulated response is reduced. Therefore the history matching problem is now reduced to optimization problem in a

roduction Numerical simulation of thermal processes such as steam flooding steam assisted gravity drainage (SAGD) and cyclic steam s alidated our approach on standard black-oil and compositional models thermal steam model and 4-phase 4-component Todd-Longstaff mo n in depth) in the well trajectory and fluid holdups may prevent the toe from producing. The dynamics are difficult to capture without direct pr

erence between individual laterals in a well. The use of inflow control devices such as intelligent completions with regulating valves that reg

the dominant flow regime we can now decide which of these techniques to be used. Finally the concepts were applied to field rate-time d g formation. To propagate an open fracture into a reservoir fracturing fluids have been used to provide the two main functions of initiating a racture conductivity and hence the production potential of a fractured gas well. This coincides with experiences in the field where these p is presented. Finally an actual case where seven transversal fractures of a long horizontal well is modeled using a sector of the full field res terogeneous internal structure of fracture and account the details of the exchange process between fracture and reservoir.ï¿½ Relative perm width deformation but because of the coupling effects in hydraulic fracturing the entire fracture geometry and fracture pressure will be affec ure modeling. The use of numerical modeling enables the user to utilize detailed reservoir properties and to simulate the flow from matrix t w a quick assessment of the most dominant factor. Introduction Non-Darcy flow is relevant to fractured and frac and pack wells in two aspe rmation that can limit the â€œplausible models that satisfy the commingled production data. We make use of Bayesâ€™s theorem to integr eady state shape factor solutions developed in this work are provided for fracture stimulation design. Fracture Design Using Dimensionless dial fracture and flow geometries instead of the conventional Radial model where linear flow (orthogonal to the wellbore axis) is assumed. d propagation of the fracture through the narrow channel (microannulus) along cement-rock interface as well as along the misaligned perfor fracture spacing more accurately we were able to identify more reliably the effects on the spacing of such factors as bed thickness litholo

and estimate its gas in place that honors both static and dynamic data. First we used the concept of initialization by enumeration instead o opagation profiles along the wellbore. The effects of injection rate and the injection profile are analyzed and a quick in-situ injection pattern new understanding of the waterflood. Introduction With typical end-point relative permeabilities and downhole water viscosities[1] any field on The Samarang field is located offshore in Sabah East Malaysia. The field was discovered in 1972 and began production in midâ€“197 tegrated fashion. In both methodologies different material balance methods were used and computed OOIP were compared to reference v completed within a 4ï¿½-month timeframe. Optimization of development envisages the following job types: Elaboration of methodology o might be the main phenomenon affecting compositional variation in hydrocarbon reservoirs especially for near-critical gas/condensate rese n the benefits and ease the pains of applying these concepts in reservoir simulation studies. Introduction The ability of a simulation model t

n O(1) error in flux if grids are not K-orthogonal [8 15]. K-orthogonality means that flux can be consistently approximated using only the pres ndensate blockage of gas-condensate wells in porous formation has been widely recognized as an important problem and was deeply stud o be used in gas-oil displacements in triple porosity systems.ï¿½ Displacements in dual and triple porosity gas-oil systems are dependent on elastic stress simulation; (2) geostatistical population of fracture density based on a fracture trend model; (3) fracture permeability modelin

mline saturation equations (as it was in incompressible case) but also in the pressure equation. The dual porosity model has been impleme no global time step restriction which is the case for finite difference simulation. This work is a further development of methods proposed in fracture corridors. The methodology is very flexible in the choice of the coarse grids introduced to reduce the computational cost of each p

ble) of models which represent a correct sampling of the conditional probability density function (pdf). By predicting future reservoir perform

tive permeability functions in finite difference models it is difficult to control numerical dispersion for miscible displacements - eg seawater (

a real reservoir model is studied using two-phase incompressible and three-phase black oil compressible data. It is shown that the use of th ondensate flows and modeling of CO2 sequestration based on the detailed geological models created by modern modeling tools; such mod s of the parameters such as geographic locations well spacing reservoir properties and the group membership (equivalent to type curve). T we have previously generated reservoir characterization examples where the method worked well here we also provide examples where th rical data is the â€œface which needs to be recognized form the training set. The method attempts to identify the geostatistical reservoir m evices (ICDs) and the flow control valves (FCVs). An ICD is a screen which passively regulates inflow so that high-velocity flow regions are c

oes not though provide the detailed compositional information necessary for surface process modeling. We demonstrate that using a blac y effects in the pore network. These effects are encoded in the expression of Cw with three terms linked respectively toï¿½ 1-the â€˜super-

ed high rate wells has been documented extensively with examples of field cases3-7. The inertia resistance factor or the so-called beta facto ailed analysis of examples from flow simulations which recreate the well known field cases referred to above. Guidelines are presented o relatively conventional well geometries have made this field an ideal candidate for underbalanced directional technology. In early 2006 an degE. Most studies of the structural and tectonic history of the GoS have identified two age significant orientations for this extensional rift. T opposed to the holistic full project value associated with the business process that has been improved by the application of that technology flooding (and flow diverting technologies in particular) gas injection thermal recovery process microbiological and unconventional EOR. In m provinces using information available to the public.ï¿½This analysis shows that government policies and the lack of a gas market have gths and weaknesses of the previous approaches. Subsequently the paper presents new measurement methods and data analysis techniq

ect to environmental effects. This case study demonstrates that through-casing formation resistivity measurements provide more robust an a. Productivity Indices are obtained for each of the two laterals without any production loss associated with shutting down the other lateral b orming any wireline logging in the well. This operation was not only costly and time consuming but also pausing the production from Burgan flow rates from the array mini-spinner analysis to the logging-while-drilling derived cumulative permeability-thickness product has enabled th

ous attempts in the Pinda. We show the pre-job modeling that was done to predict the required flow rates and the anticipated drawdowns. U ous attempts in the Pinda. We show the pre-job modeling that was done to predict the required flow rates and the anticipated drawdowns. U for enhancing reservoir performance and extending the ultimate recovery of oil and gas reservoirs. Managing reservoir pressure plays a ma e only when a measurement is made. The technique has been applied successfully to both oil-based and water-based drilling muds with su subsidence and compaction effects during future pressure transient tests. Introduction Innovations in technology in the last 10 years have b he additional located microseismic events show greater fracture system length and height thus confirming the effectiveness of the treatmen eved to be direct measurement of fracture height the level of trust increases as well. Both temperature logs and radioactive tracers have b

ured distributed fiber optic temperature it is possible to calculate the fluid viscosity in the inter-well region and consequently the flow distrib g evaluation test pit measurements of the annular flow water velocities with the Pulsed Neutron logging technique have been reliably and a valuation test pit measurements of the annular flow water velocities with the Pulsed Neutron logging technique have been reliably and accu quired. Additional benefits are the detection of crossflow on shut-in and the measurement of flowing bottomhole pressure when a gauge is r esults showed that within four hours of the initial clean up all oil soluble tracers were detected providing positive confirmation that the inter s a complete information solution. Production logs provide flow information as a function of depth but only intermittently in time. In addition

ented to calculate key performance indicators comparing the actual performance versus targets models or base case and identifying perfo d water entry; for example a burst of bubbles created by local turbulence. These practical examples from North Oman show what can be ac ed from this data set. Over the duration of the campaign an increasing pressure trend was observed in almost all wells slated for PBU and essure and temperature gauges were used to acquire distributed temperatures and pressures of the entire horizontal section of the wellbore mbination of modern technologies in combination with real time production monitoring systems we were able to double this well production w ssure that the planned data are acquired according to pre-established procedures and contingency plans. However even in developed rese d to define the limits of the techniqueâ€™s operating envelope. Increases in the flowing layer GOR will decrease the layersâ€™ fluid visco w days later. This timing suggests the creation of a fracture network and related seismic deformation which then fills with steam and starts r intervals. Given the reservoir drawdown the flow rate can then be calculated. Thus installing the fiber outside the sand-screens gives a un ssembly. With the coupler components in position the tubing hanger was landed into the horizontal tree. Upon activation of the electrical pe ation are short (<10 cm) and concentrated in diagenetically cemented layers. The fractured thin layers are believed to be the principal type o

metric measurements at both ends of the production network both processes should be reconciled. The reconciliation procedure allows th ication is attainable. The conclusions and claims of this technique are validated against the results of an advanced production logging tool (

ed by 70% with 84% water-cut. This significant fall in oil output with sharp early water break through a common phenomenon in this mature n. This technique that utilizes open hole Pulsed Neutron Sigma measurement of Logging While Drilling (LWD) enables petrophysicists to d ata will be used in the simulation to design an optimum development scheme for the lower reservoir units in the southern part of the field. T ry of a giant complex carbonate reservoir in the Middle East Giant Field A (Fig. 1) peripheral water flooding was successfully initiated to ma netration are based on correlations developed for sandstones. This paper will describe the first known laboratory-testing program to invest tential through the cleats and such information can be used to select the completion method. In this study full waveform sonic log with mo here indirect fracturing is applicable and just as important where indirect fracturing is not appropriate. Introduction: The latest production d ompletions. The goal of this study is to recommend an optimized completion strategy to minimize these near-wellbore problems increase st tal completions in anisotropic shales is straightforward.ï¿½ However the calculations require a larger set of material properties (4 elastic co ng processes. The additional energy is dissipated by increasing the surface cleat area exposed. The development of the technique and field tress state along the lateral via the presence and orientation or absence of drilling induced fractures.ï¿½ With this information important c erstanding the estimation of hydraulic fracturing stimulated reservoir volume (ESV) and fracture intensities. In spite of this tremendous effo d be. The simulation model examined multiple well pairs to see these results in a full-field environment. To assess the financial impact of th n basin and numerous Rocky Mountain basins. Outside the US more than 40 countries have investigated the potential of coalbed gas re ture diversion technique particularly adapted for horizontal well refracture stimulation. During the treatment a fracture diversion system (FD ic reservoir have specific properties such as permeability and pressure then to determine the wormhole pattern required to achieve the we erefore several measures such as replacement of underperforming ESP systems and upsizing of the pumps have been implemented. Furt

o drive a turbine which generates power as a result. This power is used to operate the inlet compressor thus the cycle being completed. Aft acked; the vertical wells released due to drilling of horizontal boreholes were recompleted; the number of shut-in wells reduced. Introductio e top; eliminating the cost of perforating long intervals; reducing the number of operations; and saving more than 10 days of rig time. Introd e bore inside the sliding sleeve. Pressure is then increased until the next valve is pumped open. When this valve opens the next control lin mation shear can be correlated with the skin effect and reservoir productivity index. Due to the nature of the formation formation damage is during the productive life of the well for which the tubing string setting depths are selected. The wellbore liquid-loading mechanism in a sub during the productive life of the well for which the tubing string setting depths are selected. The wellbore liquid-loading mechanism in a sub and interpretation from various disciplines.ï¿½ Internet-based platform was extensively used in this project.ï¿½ Local formation dip change

C capabilities and implementation. Moreover it has set the stage for other developments within Saudi Aramco. Background Haradh forms is described and the disadvantages of hydraulic systems are discussed. In particular it is shown that in conjunction with an automated fee n insight into SC capabilities and implementation. Moreover it has set the stage for other developments within Saudi Aramco. Background

ance for both configurations becomes equal in case of complete water production. However the numerical model shows that the dual-later will flow into the well. For this purpose one of the most effective techniques is tubing-conveyed perforating (TCP) a technology that consis comparative-system reckoning. The paper concludes that SA suitably applied to properly censored data is essentially the only reliable met ulting in heterogeneous etching and increased conductivity. Among the key factors supporting a field trial of the product was the fact that it o he evolution of the candidate selection process and a review of reservoir characterization as a result of the significant production improveme

which would dissolve shortly after placement would improve proppant retention within the hydraulic fracture and impede flowback into the h performed to ensure full compatibility with formation fluid resin-coated proppants and treating fluids. Characteristics such as leakoff behav al. A pilot involving use of a new degradable fiber technology designed to achieve effective acid diversion during acid fracturing was recentl obtained by using differential cased hole sonic anisotropy measurements. As it is common for most formations in Western Siberia to have h se testing was also done as a check of the core flood testing capillary pressures. This provided several different methods to determine capi be applied to hydraulic fracturing treatments in formations with moderate to significant modulus contrast. The mechanisms studied in this w e fractures along with the capacity to create sufficient fracture geometry has led to the development of a unique surfactant-based system r ended solids will be included in the discussion. Laboratory examples will be shown to demonstrate the importance of following a systematic ow reservoir characterization and completion understanding via the use of calibrated fracture propagation models and production analysis to iewed. The intervention rendered an increase in well production rate from 27 to 173 net barrels per day with a reduction in water cut from 2 ppants are used. The systematic application of the technique resulted in the increase of the average measured net pressure from 14 to 27 wing the wellbore mechanical segmentation into six small intervals based on petrophysical and reservoir evaluation so that the selected sec iform zone coverage even for bull heading operations.ï¿½ The paper presents the experiences with this Viscoelastic fluid used in nine dif nventional completions described above. The new completion system is run as part of the production liner does not require cementing and

njection rates have also yielded similar modest well productivity enhancements because of the inability to achieve effective diversion. Cons

rest and not break into the water bearing sand above. It also provided the maximum stress direction to determine the preferred orientation p ell under pseudosteady state flow conditions. Introduction A number of technical articles have appeared in the literature concerning the us

y restrained dome type sandstone and carbonate reservoirs that are located in tectonically active high stress environment. Although correc

with this cemented sliding sleeve concept was the possibility of high fracture initiation pressure through the cement and into the formation w stresses on the rock. An openhole condition was considered the best approximation to the opened sliding sleeve valve in regards to fractur e of the granular medium deforming and closes the equation set of the problem. Semianalytic solutions are obtained. First there is the area echnology has evolved from a niche application in gravel packing2 to a mainstream range of applications where clean proppant packs and

½ Finally lower friction pressures helped in designing economical fracture stimulations for mature wellbores thereby generating an opportu

monitor and evaluate the acid treatment. The first candidate well was fractured in June of 2006 achieving an increment of production from mly distributed. The data also indicate that a smaller breaker amount delivered directly into the filter cake is more effective at reducing the yi vent growth and fracture treating pressures over time revealed how the fracture propagated.ï¿½ In the first well the microseismic and treati

years a large number of hydraulic fracture treatments have been monitored to determine fracture geometries.1 2 3ï¿½ The fracture geome

can be obtained. This digital image is used to characterize the etched surface topography quantitatively. We have measured the etched-fra sure maintenance and flood efficiency. A review of world publication of direct fracture geometry measurement has shown the validity of seis ecomes temporarily radioactive emitting characteristic gamma rays that are visible to the logging toolâ€™s spectrometer. The detected gam

5 in the Yamburgskoe gas-condensate field. The analysis revealed a series of correlations and elaborated an engineering approach that on productivity was found to be more significant than in simpler modeling where one permeability value is used for the entire proppant pac hat the tip zone can be either a recirculation zone in which the formation fluid enters the fracture and then get expelled back into the forma with off-set wells treated with in-situ gelled acids. This paper provides for the first time long term production data evaluation following acid f performance. A practical performance criterion that focuses on conductivity improvement is used to improve performance of fractured wells ment of the fracture geometry (Warpinski et al. 1998; Sleefe et al. 1995; Dobecki 1983). The actual fracture performance can then be used t non-associated plasticity rule written in terms of the Terzaghi effective stress is used to describe the flow of a solid matrix connected with th t. ï¿½ï¿½ï¿½ï¿½Period III: Extension of the initial frac and the orthogonal frac. It exhibits steeper pressure increase (tip screen-out like pre less viscous one from porous medium by applying pressure differential the Rayleigh-Taylor or Saffman-Taylor instability of the interface cou cquired before and after hydraulic fracturing. From analysis of other log data such as the ultra-sonic cement evaluation tool it is possible to

er concentration the polymer in practice concentrates only in the filter cake. It is also shown that the filter cake thickness compared to the ater crude (3) near wellbore damage caused by fines from the injected water blocking the near wellbore region. When a second injectivity t le natural barriers due to higher values of minimum horizontal stress (Sh) are in concordance with the fracture height measurements. This p round truth for fracture geometry. Such hydraulic fractures have been mapped in coal 1 2 3 welded tuff 4 5 hard rock 6 7 and shallow fractu ent to be correctly sized and located. Introduction Auto natural and in-situ gas lift systems use gas from a gas-bearing formation or gas ca nidad & Tobago: Amherstia Flamboyant Immortelle Kapok Mahogany and Cannonball. There are three other fields in the planning phase . The second completion system cased/perforated liner requires cementing the production liner and running multiple isolation systems to e . The second completion system cased/perforated liner requires cementing the production liner and running multiple isolation systems to e ole and that the well would cleanup by itself easily once it started producing. After disappointing production results from this well zero prod intelligent completions will limit the water handling at the surface minimize future intervention and concurrently increase the recovery facto mulation models were performed and discussed with the Client prior to the drilling operations. The models are run using nodal analysis soft from these fields. In order to combine intelligent completion with ESPs several factors need to be considered. This paper will evaluate diffe ompletions will limit the water handling at the surface and concurrently increase the recovery factor in heterogeneous fractured and fissured completions that can be controlled from the surface. The second strategy opens or closes the completions according to well water cut and f ever predicting which variable or variables have a decisive impact is still unclear and highly controversial. The work presented in this study

cs of thinly laminated reservoirs that affect the well productivity such as vertical communication between layers. In particular we examine th stress with time and production. The rock mechanical properties and stresses needed to perform sanding analysis were sampled along th s were compared using CT scans.ï¿½ It was found that clean perforations promote not only higher acid injectivity but also initiate straighter describes the application of the new technique to three horizontal wells of the Berkine basin and the evaluation of the related productivity in the presence of gun shock during perforation may affect the CT integrity. Therefore supporting perforating software was run in advanced to d on its use in such low pressure environments. This paper describes how dynamic underbalanced perforating was deployed successfully w e multiple zones must be perforated the conventional wireline approach can only perforate the first zone underbalance (with the completion is technology enables the enhanced production from wells that may otherwise have been uneconomical. The technique was applied during eline perforate in multiple runs a carbonate reservoir which then producedï¿½more than 2500 bbl/day oil before acid stimulation. ï¿½A fast iations. Few SPE papers have investigated the variable skin condition with a simple hyperbolic function for a constant rate drawdown. The he perforation tunnels. With 1 000 psi initial underbalance to remove perforation damage the well would then remain balanced to avoid fluid escribes the relationship of energy distribution among them. A criterion is proposed to establish the serviceability of the perforators. Analytic

productivity in naturally perforated completions. Background The perforating of oil and gas wells with shaped charge perforators has been d of time. Modeling software is utilized to predict the Productivity Ratio (PR) for different perforating systems considering gun size charge ty er experiences have been utilized in a recent major increment in the Ghawar field that was mainly developed using multilateral MRC wells e ete manner as had been traditionally done in the Campos Basin. Horizontal openhole gravel packs as planned for the development of Alb he wells because of the long deviated intervals. The frac-pack" stimulation treatments are pumped at rates of 27 to 40 bbl/min with a viscoel thin producing interval with ESP set in the same casing. Due to the low productivity of this type of completion and high water cut a work-ove tion of both A1ST1BP1 frac-pack jobs was conducted in conjunction with laboratory collapse and erosion testing of the premium screens. C ngevity. Total cost of deployment to recover 0.75MMbbl of oil was USD$0.650M compared to projected USD$5.0M for possible hoist re-entr

en Hole Gravel Packs.ï¿½ OHGP requires a high quality mud filter cake to be maintained throughout drilling and placement of the gravel pa e of the project and the QA/QC processes implemented in the field. Finally the paper presents the well productivity data from the wells comp

gas storage (UGS) services in Italy are gaining in importance because these operations allow gas companies to maintain a strategic reserv th hydrocarbon production that met or exceeded operator expectations with zero mechanical and extremely low rate dependent skins. Intr simulator calculates the bed height based on equilibrium velocity model which constitutes the alpha wave part of the packing. During the b available for gravel packing with either a water-based (WB) or an oil-based gravel packing fluid. Both approaches have been practiced in r fluid in concentrations ranging from 1 to 3 ppa. These slugs range from 5 to 7 bbl and are pumped intermittently between stages of the co fluid in concentrations ranging from 1 to 3 ppa. These slugs range from 5 to 7 bbl and are pumped intermittently between stages of the com ord and the rock mechanical analysis performed the Gjï¿½a project team wanted to conduct laboratory tests to confirm its applicability and t sweep any oil. Overall horizontal injection wells performance in the field was poor with injection rates typically dropping quickly with consta nd control in a variety of well conditions. Screenless completions have been proven effective in reservoirs from 10 to 60 ft in thickness at d

mechanical reservoir characterization including geomechanics core laboratory test and mechanical earth model building sanding prediction oduced oil for more than 30 years. This field experiences massive sanding from some wells but experiences no problems with other wells. T ults revealed that the problems facing the field were other than conventional sanding and formation failure and that they involved some rat al water saturation. The experimental results are discussed on the basis of the chemical interaction between water and rocksâ€”capillary st

te of sand failure with a model for transport of solids in a fluid might eventually lead to a realistic sanding rate prediction. Existing sand pro and deviation angle for preventing mechanical wellbore instability were developed for various formations. In addition a drilling fluid design m employed to stimulate seawater injectors and disposal wells where the bottomhole temperature was in the range of 100 to 150ï¿½F. More t ging from 15 to 60 minutes. After the fracture surfaces were carefully characterized with a surface profilometer the fracture conductivity wa ochloric acids in high temperature environments. Recently there has been a large number of highly successful acid fracture treatments in th hieve effective acid diversion during acid fracturing was recently implemented. The trials were conducted in a matrix acid and in an acid frac e effective acid diversion during acid fracturing was recently implemented. The pilot comprised field trials in a number of wells with similar r verage in stimulating large limestone reservoirs whether conveyed by coiled tubing or bullheaded from surface. The use of viscoelastic div chnical challenge. In addition the crude oil was heavy (17 to 21ï¿½API) and compatibility with the stimulation fluids was a concern. In this ns. The field results show significant improvement in post-stimulation production owing to effective diversion and water-production control c nd conditions will also be discussed. Post-treatment production gain is correlated with the efficiency and timing of the flowback process. Us

be noticed but are not optimal. An enhanced system that contains temperature-degradable fibers has been used in Kazakhstan. Such syst derstood than those of HCl with carbonate rocks. Organic acid/carbonate systems are complicated because of the presence of CO2 organic

y was due to the mechanical plugging of the kaolinite or disrupted mica in the pore throats. This reduction in the matrix permeability creating nce the fluid enters the formation. Chemical diversion can be achieved through placing a viscous fluid foam or gel to lower the penetration o am though has evaded application in the region until recently. Absence of foam to this point is mostly due to equipment requirements and SD) in the carbonate.ï¿½ Each RRT represents a group of carbonate rocks with similar porosity spatial distribution and is expected to exhibi for restimulation is likely to result in worse outcomes than random selection of workover candidates. Studies performed to date have conc ing. This paper will discuss stimulation with the new fluid and how pin-point pressure measurement enabled the operator to make informed cf/D stimulated with polymer-based fluid. Introduction ï¿½ï¿½ï¿½ï¿½ï¿½ The Waltman-Cave Gulch field complex is located on the northe d future development that focuses on ultimate productivity throughout well or reservoir productive life regardless of boundaries between va

on rates showed substantial oil production increase and water production decrease 360% and 40% respectively. Background In the Sabriy n which negatively affected the cement bond log interpretation. Two wells with long intervals of excellent cement on logs suffered behind ca avate the accuracy of calculations. The complete analytical solution for modeling the entire CCT data will allow one to investigate possible -phase flow and short production time.ï¿½ Impact of derivative shape on model selection is also discussed.ï¿½ The effects of analysis met h as; permeability (keffective) fracture length (Xf effective) conductivity (kfbf)effective and dimensionless conductivity (CfDï¿½ or FCD) can proposed to GNPOC; use the conventional technique of isolating each layer and testing it separately or carry out a commingled multi-layer obtain various reservoir parameters such as vertical and horizontal permeability fracture properties and various skin factors. Both naturall neral systems. The new formulation takes into account the production rate from the system formation thickness and gauge resolution. It is osed by the downhole equipment.ï¿½ Our work presented here focuses on developing workflows and interpretation techniques for this uniq is and interpretation of variable rate/pressure reservoir performance data. Introduction Applying deconvolution for well-test and production

due to high uncertainties in estimating fracture permeability and shape factor values these parameters are initially assumed in the model a nal reservoir information that can be obtained from a mini-Drill Stem Test (mini-DST) and a Vertical Interference Test (VIT). Pressure transi e point AOFP for each of the tested zones. Second we extend routine forward modeling and incorporate features such as scaled permeabil hat the meterâ€™s performance compares favorably with that of the test separator located in line. Furthermore the high-frequency high-re f the well test rates of gas and condensate against traditional means of measurement presently deployed in Siberia. It is based on a rigorou

uracies and allocating oil correctly to wells it is possible to invest in right opportunities thereby saving unnecessary expenditure. The factors ow regime that can be observed and monitored accurately with multiphase flow meters. The importance of slug flow regime identification rel ollected on flow loops are presented with comparison to reference flow rates. The data from the Sintef and NEL flow loops show an error (i PFM was almost three times more than those measured by test separators. This ratio is matched well with the actual field water volumes. Th

ication to gas well testing. Today the use of the entire information of a gamma ray spectrum gamma ray (more than 2 rays) allows a real-ti ackages provide engineering interfaces to the simulator that make their respective workflows easy. However there were a number of situati on data using the Î²-integral derivative formulation. Introduction This work introduces the new Î²-integral derivative functions (Î²[qBDdiB(tB me and recorded data. No modifications to gauges or other hardware are necessary. The technique enables analysts to customize the differ ions of transient streaming potentials in oil and gas fields for reservoir characterization and reservoir monitoring. Streaming Potential In res

terize the cement and ensure the long-term risk of containment breach is minimized. The essentially unpredictable nature of fault-free risk n relation with the radiative forcing of anthropogenic long-lived greenhouse gases in the atmosphere is beyond debate. In this process car agement and enables the full integration of uncertainties as part of risk estimation. The methodology presented here greatly improves com ose. After proving the feasibility of facilities for CO2 injection as EOR process or storage the integrated approach has shown a more comp torage sites are still in its infancy. Only a few industrial scale projects are operating over the last 5 years such as Sleipner (Norway) In Sala omprehensive borehole logging program was performed consisting of routine well logging to which an enhanced logging program was adde optimize CO2 EOR operations.ï¿½Well design cementing completions techniques and long life cycle mechanical integrity assurance are s (which may bound the reservoir penetrate the cap-rock or intercept wells). The stability of wells in formations experiencing strain is also in

ay (Figure 1 2 3). The field was discovered in 1986 and production started in 1999. The Visund field is an oil & gas field with a water dept has been used to proactively guide the wells along the thin oil reservoir units/sands. These tools also enabled the wells to be placed as clos

eservoir simulation and a new well drilled into the reef to provide greater understanding of the CO2 EOR potential for this and all of the Silur der to understand better this field a geological model was built and its dynamic behavior and potential was examined through several well te tion data was utilized to continuously adjust and calibrate the high-resolution petrophysical model. The incremental revenue from the adde stry importance.ï¿½The profitability of gas-condensate field development depends on both gas and condensate production profiles. Two The parameters analyzed were vertical well spacing injection steam rate well flowing pressure and horizontal length of the well pair. The e f cross-linked polymer gel as a capping fluid. c) Utilize an on-fly mixing system that enables volume and concentration adjustment as pluggi

fshore rig and wellsite conditions. It also shares a method of post treatment production evaluation and suggests operational change to impr lfilling requirement such as limited outside diameter (OD) due to the production tubing restrictions or high expansion ratio conformance due of a large gas cap and a 100-ft total vertical depth (TVD) oil column was developed with the single-string multizone completion design. Due ce. In many cases high water production from the formation results in dead wells. All these concerns make the water shut-off a matter of hi was increased by an average of 300 BOPD per well through the application of this water shut-off solution. In one particular well two previo outh Ghawar area by Coiled Tubing (CT) intervention to isolate the water producing zone at the toe of the well with a through tubing inflatab m-hole sensors which provides Casing Collar Locator (CCL) readings Distributed Temperature Survey (DTS) temperature internal and ex development planning by utilizing a field example. Introduction Flow assurance refers to the ability of a multiphase production system to tr s were tested for fully dispersed flows. A Sauter mean-diameter (SMD) analysis was conducted across the pipe diameter. Droplet-size data performance is analyzed based on the experimental observations and the modeling considerations. Recommendations are presented for fu optimization over all static and dynamic uncertainties to derive an interaction strategy with the intelligent well that maximizes oil production.ï g and counter-pressure problems arising from over- and under-capacity of in its current surface infrastructure. This work describes how a te ake the system across the boundaries of asphaltene and wax. Being able to predict the formation of solid deposits along the whole productio live oil data was the basis of the design. For a marginal field these differences could be the difference between an economical field and an method for using DFA (Downhole Fluid Analysis) in the real-time determination of the CO2 amount in the MDT* (Modular Dynamic Formatio servoir. This paper presents field examples from the Asia Pacific region where a new generation Wireline Formation Tester (WFT) tool toge

ons for gas condensates based on readily available field data have been developed. The correlations can be used to predict dewpoint press to generate our database of the MBO PVT curves used in developing our correlations after matching the PVT experimental results with an rt you. There is a growing realization that fluids indeed are often heterogeneous in the reservoir;[1-3] this after all is earth science where litt d clarified oil gas and water bearing zones. Some zones were identified to have gas and possible oil presence. Few stations which were cl e â€˜continuous downhole fluid Logâ€™ provided significant clues and answers to a broad range of reservoir issues including compartment m-engineering problems including the prediction of PVT behavior. ANN technology can recognize patterns in data adjust dynamically to cha d dynamics and phase behavior constitutes the governing physics of OBM filtrate clean-up process. Therefore for OBM filtrate environment without fluid mixing [1]. Using this method we present field DFA data acquisitions and integrate into numerical simulation modeling to conce

rovided for the identification of mobile oil. Flow was enabled from low mobility zones along with low rate pumpout that would not be possible nce of water in order to quantify H2S scavenging effects. We have also identified all the components in the formation tester string which cou

gle-reservoir and multireservoir samples which is particularly useful when rapid assessment is needed over large regions. Introduction The Sage and Lacey (1938) define compositional grading as â€œvariations in the composition of the liquid phase of natural reservoirs which ar ssure and DST in order to determine fluid types in a well where an expected reservoir fluid is oil. The result from a systematic integrated res owed that the hydrocarbon fluid in an oil-bearing zone was not vertically homogeneous but instead had a vertical variation. The samples c tests. Depth dependent fluid property variation from fluid gradients PVT properties and EOS-models are compared and discussed. Guidel rigorous mathematical approach to respect all data available so as to follow an objective assessment of reserves and reservoir architectur and it may take many weeks before the laboratory can provide this critical information. In this paper we describe the development of an in-s

alysis so that different sources of information lead to an integrated preferably consistent conclusion. Downhole fluid analysis in conjunction be an assay for reservoir compartmentalization. In this paper we briefly review the theory of the FCA. The strengths and limitations of the g problems including the prediction of PVT behavior. ANN technology can recognize patterns in data adjust dynamically to changes infer g

these from an EOS.ï¿½ Although more limited in the range of pressure and temperature where the correlation or table is valid i.e. away fro s were measured using a precalibrated high-pressure capillary viscometer. Viscosities were measured at least in three different flow rates a

mpling in the same reservoir zones. This study also gives insight into the cleanup dynamics of invaded filtrate and explores the different fac er discusses an innovative technique successfully applied in the North Sea to acquire clean gas-condensate samples. Firstly a well-kick a e objective of collecting representative samples isolating and analyzing each fluid phase and providing data from the analysis as input to th ase flowmeter. Not only does this state-of-the-art device allows to capture fluid samples for carrying out basic Pressure-Volume-Temperatur can increase the conversion of organic acids. More concentrated CaA+ can be obtained because of large amount of calcium ion due to the me of a few months with suspected rock disintegration in the near-wellbore area. Through virtual geochemical simulation and laboratory te dstone core saturated in calcium brine is exposed to a solution of the soluble carbonate species and generates calcium carbonate solid (da under favourable pH conditions. Core floods using field core materials were conducted to evaluate the chemical squeeze packages. No for

xperiments proved the occurrence of formation damage caused by naphthenate-soap precipitation and subsequent deposition. The permea rock. Direct measurement of the extent of the crushed and damaged zones and the degree to which strength and permeability damage oc d surge flow. The third stage in the analysis investigates the mechanisms through which the damage zone is removed. As a result of thes candidate selection process provided ground for detailed lab testing to optimize the inhibitor type and volumes required for the first scale-in h as sulphate and carbonate scales throughout the production system. Typically if formation water enters the production system scaling ca e management - of using ICVs is evaluated.ï¿½These calculations demonstrate that intelligent completions significantly reduce the scale in ater in the produced water the production rate the percentage water cut and scaling index are the main parameters that are used to calcula be retained from the brine phase onto the rock and in return calcium is released from the rock into the brine phase.ï¿½This is confirmed The Hessian matrix summarizes the sensitivity of the objective function at a given step of the history matching to permeability at the grid blo generated by the streamline simulator. This paper documents the procedure on improving water cut matches by validating fracture lineame eservoir communication. Better understanding of producer â€“ injector relationships. Development planning for both producers and injecto e gas cap continues to advance the models have been further calibrated to capture this advance more accurately in black oil and composi e also computed using nodal models automatically updated with operational data for each well. The integration of tasks including production e pilot design describe the detailed geological model and show results from the initial set of baseline and time lapse EM data sets from the rns in 2000. These wells were drilled on an inverted nine-spot pattern with spacing of 250 acres per well to quickly provide coverage over th he functional design of the bottom-drive PCP facilitates the handling of viscous and abrasive fluids increases the flow rate and diminishes t are designed ordered installed and commissioned. This paper analyzes the effects of downhole heaters as a stimulation method through n method and in the past microwave radiation has been used in many areas of the petroleum industry (Bjorndalen and Islam 2004). Microw well is injecting is laterally driven by the pressure differentials created by adjacent producers forming a sweeping front between wells. Inject thodology of drilling has resulted into significant improvement in drilling performance saving days and cost and eliminating stuck pipe incide ionship to be reproduced from logs by incorporating dual porosity information. The integration of NMR logs and image logs used in the poro of Wireline Formation Tester (WFT) with dual packer module is used. This wireline conveyed straddle packer has the capability of hydraulic

rnt and cost /production analysis. Team work communication knowledge sharing and deployment of fit for purpose technologies has resul

etration in high water saturation zones while enhancing deeper penetration in high oil saturation layers. Conventional acid treatments have

cluster did not have any data and PDVSA could only use conventional storage tanks to try to estimate the liquid flow rate with no possibilit

ntroduction Sandstone acidizing is a complex operation because the treatment involves flow and reactions in porous media where the react he main issues for the extended formation evaluation program defining logging and testing scope. In addition to traditional downhole samp

hat the EOS model quantitatively (within desired limits) and qualitatively described the observed equilibrium fluid grading behavior of the flui

e the crosslinking temperature for specific treating conditions.ï¿½ These methods involve addition of chemicals to control the crosslinking ki terogeneous etching and wormholing in both limestone and dolomite rocks. In addition this material exhibits increased fluid efficiency as co

g June 2007. Permanent Down Hole Monitoring System were sought in consideration to meet reservoir and production main objectives bu at a flow-rate of 20-25 bbl/min (bpm) with a maximum proppant concentration in the range of 8-10 ppa (lbm of proppant added to 1 gal. of ests conducted on the damaged field cores show that both mud acid and organic clay acid systems show secondary damage on the forma same period of time which is indicative of secondary precipitation. The effectiveness of the chelant fluid for stimulation of this high temper e fluid allowed the treatment to be confined in the limited layer thickness between weak barriers avoiding growth into water - or non - produ e relative permeability of oil/gas.[1-5] This restriction to flow of oil/gas due to increase in water saturation is known as water block. The sou cale treatment and mitigation. In this paper we present results of laboratory pH measurements on formation water samples from two offsh

pletion costs and reduced overall completion timeframes. Introduction Geology Completion Strategies Cleveland Formation The Clevela

oir in an emerging area. The challenge in this case is in collecting adequate necessary data early enough to plan for optimal development. and plugging of stages with ball sealers. Perforation entry by stage was effective and some stages could possibly be eliminated to save co stress orientation anisotropy. A number of complex fracture geometry orientation investigations were performed on low permeable formatio ss of hydraulic fracture propagation and the characteristics of the induced fractures. Using microseismic datasets obtained during hydraulic atment with slick water crosslinked polymer hybrid (combination of slick water and crosslinked gel) CO2-based emulsions and viscoelastic

effort of taking these techniques to the offshore environment. Transverse fracturing with multistage completion conceptâ€” with properly en lts mainly due to strong heterogeneity in the lateral section of the reservoirs. The concept of drilling horizontal wells has been developed in ait and Saudi Arabia. The fields were discovered in 1966 and 1957 respectively and put on production in the 1960s. Locations of the fields a results. The production-validated results of this closed-loop study clearly demonstrate that well production and field performance can be for etions are designed to optimize the production from each stimulation stage.ï¿½ This is achieved by calibrating the pre-stimulation injection t gh times for the flow models and the geocellular model were then compared. The flow model with the most reasonable volumetrics and flow ated for each interval and used for recommendations on completion strategies.ï¿½ Additional pay intervals normally bypassed were perfor

ial contribution to the overall geological understanding of the field. More importantly the case study shows that the combination of both ima ganized to carefully consider of the challenges mentioned above identify the source problems and recommend a solution. The solution invo address conductivity. Based on case studies from Cambro-Ordovician tight sandstone reservoirs of the Hassi Messaoud field in Algeria th case study represents a statistically significant collection of detailed pressure data in a partially developed complex tight formation gas fiel

scuss best practices for formation testing in low permeability reservoirs with examples from the US Land area and an offshore carbonate fo n the central part of west Siberia was discovered in 1982. The field was divided into two license areas: northern and southern as shown in d blanket approaches do not work usually in these completion environments. A multitude of lithological and depletion possibilities exist as ris highly productive may turn out to be the highly fractured streaks and sections controlled by the regional and zonal fault zones. Such localiza

uncertainties in interpretation of gradient data. Downhole pH measurement embodied within Downhole Fluid Analysis (DFA) procedure ha

uctivity in these thinly bedded heavy oil field with objective for tapping the bypassed oil and delaying the water production while controlling th

ocess to further distinguish a companyâ€™s priorities and requirements. This paper examines different multicriteria decision making metho y expert judgment considered to be less accurate than objective data analysis due to inherited biases. However recent research shows that ise to the â€œCrooked-Hole Formula. This basically recognized that a hole did not necessarily drill straight or in gauge and that the drift dia of determining primary drainage capillary pressure information from borehole NMR data and comment on the effect of tar or heavy hydroca showed unique characteristics that represented local formation heterogeneity. Although the new technology can be used at any scale the f ntaneous potential neutron and induction tools since engineering progresses combined all these probes in one single tool. Cost is negligibl al elements of the system. The sediment paleotransport direction is governed by the rifting episodes that have subdivided the KG Basin into n logs stacking patterns facies associations and dip data. These results show that the fluvial reservoirs of the Rhourde El-Krouf field are c together with improved compositional algorithms now make possible a quantitative analysis of reservoir fluid with greater accuracy and rep s and clarified oil gas and water bearing zones.ï¿½ Some zones were identified to have gas and possible oil presence. Few stations which permeability streaks that can explain the production performance or the water injection behavior at a later stage of development of the field data and the volumetric computation at wellbore level using ELANPlusTM the field portrayed oil occurrence in a unique pattern when visua on LWD service integrates all of these measurements in a single collar optimized to: Minimize measurement distance to bit. Improve real-t tirely new LWD measurement has also been introduced with the tool making it possible for the first time to determine formation density wi

Egypt were used as our data base in generating these error analysis charts. The uncertainty in input data was assumed from ï¿½ 5 to ï¿½ re used as the data base in generating these sensitivity charts. The uncertainty in input data was assumed from ï¿½ 5 to ï¿½ 15%. The res lity. Introduction Many of the giant carbonate fields of the Middle East are undergoing Enhanced Oil Recovery (EOR) via water flood gas in ded zone measurement in oil-base-mud environment. It helped to understand invasion profiles which generally is a function of permeability e scatter in computed permeability to a factor of less than 10.ï¿½ The assumptions and principles of the log analysis method were validated flow profile of a production test. The dynamic reservoir information obtained from these measurements enables to understand the fluid flow

plicability of the NMR technique. In this paper we first demonstrate the variability of sand resistivity volume fraction and porosity output de wells. First of all the issue of vertical resolution in horizontal wells is not as critical. Secondly the gravity effect on the tool orientation is diffe high production rates as long as the dominant fracture strike is close to the direction of the maximum in-situ horizontal stress (ÏƒH). Wells w nce to solids production during sampling operations various filter and pump options are available for the different probe focused probe and hs (UCS) tensile strengths rock stresses and estimates of cooling in the boreholes by the circulating drilling fluid it was demonstrated that ost likely reservoir properties exist in shallow Tayarat Formation. The depth converted and extracted sinuous bodies along with possible por

y statistics coupled with spatial statistics. An application of using both spatial and frequency statistics in a real reservoir modeling example rophysical analysis of: porosity volumes of clay minerals and fluids permeability based on the combination of GR spectroscopy element different properties fluid typing techniques that exploit all NMR relaxation times (T1 and T2) and diffusion (D) offer new ways to determine th

g borehole position from stationary survey points typically taken every 90 feet (ft) using the minimum curvature method. Neglecting the comp

he injection rates reservoir pressure production rates in-situ stress contrast distance between wells and orientation of the wells with respe e the static values of these parameters is extremely expensive.ï¿½ Consequently static values of Youngâ€™s modulus and Poissonâ€™s re we could estimate the minimum horizontal stress magnitude by use of both the MDT minifrac tests and inversion of borehole sonic data. ¿½ Applications of the analyses reported in this paper demonstrate the use of the analyses to evaluate the inflow performance measureme ¿½ Applications of the analyses reported in this paper demonstrate the use of the analyses to evaluate the inflow performance measureme ¿½ Applications of the analyses reported in this paper demonstrate the use of the analyses to evaluate the inflow performance measureme is excellent correlation between the fractures observed in cores and image logs and those predicted from the converted component of the the elemental spectral device data and other conventional open hole logs to provide a comprehensive petrophysical formation evaluation. t intensive development of a network of natural fractures (according to the model). The drilling was associated with significant losses of drilli age data from 24 wells indicates the presence of an organized fracture network within the Arab reservoirs. The impact of such fracture syste s (according to the model). The drilling was associated with significant losses of drilling mud that was an indirect indication of presence of s

-physics measurements. This monitoring experiment was achieved through an integrated interpretation of different data sets such as transie ccurate pressure profiles and makes it possible to capture representative samples using DFA. The applications of wireline formation testing opy on a comparative basis between different zones.ï¿½ Moreover the results from both dipole radial profiling and MDT-IPTT indicated tha

sed on the optimum selection of the acquisition parameters for the tool like the polarization time the echo-spacing and the use of a fit-for-p acquired before the sampling operation it is easier to ensure that a full suite of representative samples are acquired and that we do not indu the accuracy of density porosity even when LWD and Wireline logs are combined. We also show how the NMR measurement of gas volum ted NMR echo data. Lastly we compare real NMR log data porosities with other porosity logs in fields exhibiting long T1 constants. In all thr the 1970s drilling boom and the need for new tools to evaluate the more complex reservoirs being explored and developed. Pulsed-NMR ollowing step consists of a detailed analysis in the zones where water production forecast has been identified to calculate a formation wate aracterization and better well production strategies. Introduction With technology development oil producers and water injectors are being

allows for a sequential history-match procedure. Statistical analysis of the inverse problem can then be utilized to determine the optimal lev ious wireline image studies carried out identified these layers and their corresponding fractures but because most of the studied wells were

troduction Determining connectivity at the reservoir scale remains the elusive goal for predicting long-term production profiles. Characteriza to successful development planning.1 Indeed history matching of production data is extremely useful for understanding the reservoir.2 How lysis. Applications of the analyses reported in this paper demonstrate the use of the analyses for evaluation of the inflow performance of co ing oil saturation. Included in this program are: special core investigations using preserved and restored state core material; analysis of pore while drilling d) cable creep while station logging. Several different approaches have been recently launched to increase the success ratio o

ents in western Siberia were addressed by detailed risk assessment job planning and real-time quality control and decision-making. The u voir description both in exploration and exploitation scenarios. Static pressure data can be used to compute formation fluid density and cont reservoirs were identified from the perspective of infill drilling pressure maintenance by gas injection and/or waterflooding high pressure ga or the estimation of oil in place and prediction of reservoir behaviour. This uncertainty was addressed by a comprehensive wireline downho ntal oil production over 10 years without significant watercut increase. A contingency gas lift system above to mitigate lost production during 1 md and with average well spacing already in the order of 20 Acre. A second objective for the study team consisted of evaluating the techn mization is one of the main initiatives for production enhancement in the Bokor Field.ï¿½ Venturi orifice type valves were installed in selected onfidently solidified with new deep and directional electromagnetic measurements. By detecting the upper and lower conductive shale boun provide remote detection of bed boundaries around the wellbore.ï¿½ This technique has been used successfully in other analogous sandsto ral compression system. 4) Financial study was carried out to determine the economics of leasing versus purchasing the well site compr on Stacked reservoirs are a common occurrence among subsurface hydrocarbon accumulations. In them each wellbore penetrates many p ting a portion of the produced gas. The study showed that flaring over longer periods of time potentially caused a rapid decline in reservoir handled in different ways the calculated liquid production trend is different for each model. The stand alone model is constrained by maximu y/sensitivity analysis and instantaneous/lifetime revenue optimization from a hydrocarbon field. Traditionally the FM functionality has been ue system-wide optimization that greatly enhances field planning strategies in the area of reservoir management. A case study is presented ible solution. Since the current facilities were not intended for any pressure maintenance or enhanced oil recovery scheme a number of tec liable platform for predicting field performance. Results also added valued information for optimizing further infill drilling targets. Lessons lea

other models and hence also handles the proper propagation of constraints throughout the system. Introduction Coupling a full field reser ill depend on quantification of the reservoir uncertainty and finding a cost effective development strategy with existing processing facilities. g and counter-pressure problems arising from over- and under-capacity of in its current surface infrastructure. This work describes how a te reduces the turn-around time for the various tasks. Introduction Integrated study workflows that are underpinned by the more traditional d m water control operations during ESP changeout workover operations. Quantitative PL evaluation in these deviated high-flow rates high-

vocet Gas Lift OptimizerTM. The present work therefore represents the introduction of a new optimization platform for Khafji crude product nd Texaco signed the contract in 1983 and they discovered nine prolific oil fields by the year of 1989. First production in this area was from t w). Gas is produced in the Saih Rawl field from two distinct main reservoirs: the Barik and Miqrat formations. The Barik formation at dept accuracy can be greatly improved through sound engineering practice and workflow. This paper illustrates a robust process to quantify the r es a quantitative valuation framework. This framework could lead for example to novel ways of setting up contract terms. Introduction Trad

onductive shale beds). The deep-reading azimuthal electromagnetic measurement helped in early detection of neighboring conductive bed ft of the roof without reservoir exit. The Brenda wells have proved to be well positioned using these new geosteering techniques. Initial flow ofile and recovery factor is affected as the irregular well placement approach driven by drainage objectives is applied compared to a fixed track well was logged a â€œwhat-if reservoir model was run to simulate a no-hydrocarbon-reservoir scenario in the northern portion of th here allows selecting candidates for sidetracking in mature water flooded fields based on a minimum of data time efficiently which allows m evel. An iterative process was used to maximize the well production by balancing the pressure drop along the horizontal section in order to m tion. The process is repeated until no further improvements are obtained. The method is applied to three waterflooding examples. Introduct

¿½Our method therefore provides a powerful alternative to simulation in terms of reservoir modeling. We present a comparison of our so r of applications. These include pressure/rate transient interpretation rapid field development studies and integration with real-time software he number of data points or the model parameters. The adjoint sensitivities can be computed from the pressure and water saturation distribu time in larger time step that is equivalent to the time of severe changes in pressure and saturation due to the changing of well conditions or

educed to optimization problem in a much smaller parameter space. The number of parameters to be optimized is reduced to the number o

rainage (SAGD) and cyclic steam stimulation plays an important role in design of a thermal project. The frequent use of simulation results ase 4-component Todd-Longstaff model. We describe our natural variable based nonlinear system which incorporates general phase-comp e difficult to capture without direct production logging and the use of special options of the simulator. In this study appropriate technologies

etions with regulating valves that regulate production from specific perforated intervals/laterals.ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½

pts were applied to field rate-time data. Introduction Decline curve analysis (DCA) as one of the methods of production rate-time data ana the two main functions of initiating and propagating the fracture and transporting propping agents along the fracture. Guar gum is the earlies periences in the field where these parameters are frequently lower than anticipated. Results of the study further indicate that within the fra led using a sector of the full field reservoir simulation model (geological/structural) where the results are interpreted and discussed. Fractur cture and reservoir.ï¿½ Relative permeability and non-Darcy effects in fracture and formation and non-uniform fracture conductivity could be y and fracture pressure will be affected. The simulation results based on the interfacial slip model are compared with the fracture height and nd to simulate the flow from matrix to fracture as it occurs in the reservoir. Numerical simulation of fractures is even more essential for hor and frac and pack wells in two aspects. As shown in the numerical analysis of Holditch and Morse 1 in terms of well performance the effec use of Bayesâ€™s theorem to integrate prior information production logs and commingled production performance data into reservoir/comp acture Design Using Dimensionless Productivity Index There have been a number of technical articles that have appeared in the literature al to the wellbore axis) is assumed. The theoretical diagnostic (Nolte) plot is in perfect agreement with actual job responses i.e. a positive well as along the misaligned perforation. We also investigated different geometries of microannulus development and made conclusions o uch factors as bed thickness lithology structural position and degree of folding. By comparing performances of all the methods we tested

itialization by enumeration instead of the conventional approach of initialization by equilibration that requires accurate detection of gas-wate and a quick in-situ injection pattern-recognition method is proposed. Finally examples are given to show the practical application of the the wnhole water viscosities[1] any field with downhole oil viscosity greater than about two will have an end-point mobility ratio[2] greater than and began production in midâ€“1975. By the end of 2004 nearly 400 MMSTB of oil had been produced from 18 sand sequences with the m OOIP were compared to reference values from a conceptual reservoir model with known PVT data and simulated reservoir pressure. A MAT pes: Elaboration of methodology of ID quality control; Creation of a program of idle low-productive or high-WC wells rehabilitation; Build or near-critical gas/condensate reservoirs (Ghorayeb et al. 2003). Generally temperature increases with increasing burial depth because h n The ability of a simulation model to satisfactorily explain the past reservoir performance underpins its reliability to predict the future reserv

tly approximated using only the pressure difference between two neighboring control volumes. The property of K-orthogonality is lost if the m ortant problem and was deeply studied. The references1 3 5 7 8 10 16 18 can be noted among several dozens of articles published as relat ty gas-oil systems are dependent on the magnitude of gravity and viscous forces capillary pressure in the matrix rock composition of the in el; (3) fracture permeability modeling integrating fracture density matrix permeability and well-test permeability; and (4) numerical flow simu

al porosity model has been implemented into a streamline simulator. This tool has its main application in the high resolution reservoir mode velopment of methods proposed in [19 16] and [2]. We are concerned with the efficient solution of saturation transport along streamlines. T ce the computational cost of each pressure solve. This can have a large impact on iterative modeling workflows. Introduction Modern rese

y predicting future reservoir performance with each realization we obtain a characterization of the uncertainty in predicted performance. Bo

scible displacements - eg seawater (with a Sulphate concentration) displacing formation water (with a barium or strontium concentration) wh

le data. It is shown that the use of the AMR technique for realistic test cases can provide up to a five-fold acceleration compared to the solu y modern modeling tools; such modeling may require large number of computational cells often several tens millions. In this regard conven mbership (equivalent to type curve). This expert system can then be applied to any location in the field in order to determine the most likely g we also provide examples where the performance of EnKF does not provide a reliable characterization of uncertainty. Introduction Our m dentify the geostatistical reservoir models which show reasonable match in the dominating patterns in the simulated pressure data with th o that high-velocity flow regions are choked back resulting in a more uniform inflow profile along the well. The screen acts as a flowpath bet

. We demonstrate that using a black oil delumping method based primarily on the compositional information generated when simulating the d respectively toï¿½ 1-the â€˜super-connectivityâ€™ of micro pores in micritic grains for carbonate rocks or the super-connectivity created

nce factor or the so-called beta factor b a parameter in the Forchheimer equation for quantifying the non-Darcy flow effect is now routinely above. Guidelines are presented on how to interpret traditional open hole pressure measurements in a carbonate oil-water transition zone ctional technology. In early 2006 an underbalanced coiled-tubing campaign was commenced to optimize productivity. This paper discusses rientations for this extensional rift. The early to middle Miocene rifting responded to a Sh direction of N55-60degE (rift-climax). The younge by the application of that technology. The essential foundations for a Smart Field are:ï¿½People and Skills effective Data Management a ological and unconventional EOR. Introduction The problem of enhanced oil recovery is particularly pointed in Russia today: for the last 25s and the lack of a gas market have played a crucial role in the production history of the Alaska North Slope.ï¿½ Introduction Exploration t methods and data analysis techniques to determine cement mechanical parameters in sufficient detail to allow them to be implemented in

asurements provide more robust answers compared to neutron measurements in the studied environment. The deeper depth of investigati with shutting down the other lateral branch. Data analysis indicated a decrease of the Productivity Index for one of the two horizontal wellbor pausing the production from Burgan Formation. The new logging string and interpretation technique were developed to survey the short str lity-thickness product has enabled the evaluation of the completion methodology.ï¿½ Based on the production log analysis the new comple

es and the anticipated drawdowns. Ultimately a two-step solution was used. We first ran a high efficiency pretest-only WFT in order to quick es and the anticipated drawdowns. Ultimately a two-step solution was used. We first ran a high efficiency pretest-only WFT in order to quick aging reservoir pressure plays a major role in optimizing the field performance. Saudi Aramcoâ€™s strategic surveillance program calls for d water-based drilling muds with successful measurements even in mixed oil/water flows. Multiple measurements of pH at a single samplin chnology in the last 10 years have brought new components into well completions that allow better and faster interpretation of reservoir par ng the effectiveness of the treatment. We also show that the upward component of the vertical propagation is more developed than the dow logs and radioactive tracers have been used on a regular basis by the fracturing industry to evaluate fracture height containment (or the lac

on and consequently the flow distribution along the producing well. Injector-producer temperature which dictates the bitumen viscosity was technique have been reliably and accurately measured to as low as 3 ft/min (0.05 ft/s).ï¿½ï¿½ Introduction A production logging techniqu chnique have been reliably and accurately measured to as low as 3 ft/min (0.05 ft/s). Introduction A production logging technique that utilize omhole pressure when a gauge is run at the end of the slickline. The process is cost effective less risky than conventional production loggi g positive confirmation that the intervals tagged including the toe of the well were contributing to the overall production. Using tracers for f nly intermittently in time. In addition production-logging tools are complicated especially those designed for deviations beyond 45ï¿½ from

s or base case and identifying performance deviation on time in order to avoid undesired lost production. PPS includes an events managem m North Oman show what can be achieved in low flow rate wells with high water cut with todayâ€™s technology. Included also is an explana almost all wells slated for PBU and interference tests. This observation was made possible due to multiple SBHP recordings in these wells ire horizontal section of the wellbore. Results of the pressure survey revealed that the well was receiving insufficient pressure support from able to double this well production without entraining any problems in addition capturing pressure transient data which enabled us to manip s. However even in developed reservoirs unexpected circumstances arise requiring immediate response and modifications to the preplan decrease the layersâ€™ fluid viscosity resulting in a change in flow rate together with a decrease in flowing fluid temperature due to the Jo hich then fills with steam and starts to expand over a period of a few days. In a related paper (Du et al. 2007) stress changes associated w outside the sand-screens gives a unique direct measurement of individual reservoir layer drawdowns enabling the effects of differential de . Upon activation of the electrical penetrator high-resolution temperature data were then immediately available across the length of the san re believed to be the principal type of thief zone. Another type of thief zone is associated with better-developed vuggy porosity. This study sh

e reconciliation procedure allows the comparison of the data coming from two different sources. By using this procedure engineers can de n advanced production logging tool (APLT) utilizing multiple spinners and multiple probes and comparisons of the advantages and disadvan

ommon phenomenon in this mature field required a proper shutoff operation. The present example discusses in detail the reason in choosin (LWD) enables petrophysicists to distinguish and determine injected water separately from formation water independent of Archie-based r ts in the southern part of the field. The current dynamic simulations predicted that the injected water will reach producers after 7 to 10 years ding was successfully initiated to maintain pressure. Recently it appears that reservoir complexity has led to uneven sweep. ADCO is curre laboratory-testing program to investigate shaped charge penetration in coal targets. We will describe mechanical properties of the coals tes udy full waveform sonic log with monopole and flexural waveform and high resolution electrical image log data from CBM wells in Jharkhan ntroduction: The latest production data indicates that natural gas production from subsurface coal seams averaged 4.7 BCF/day in 20051. T near-wellbore problems increase stimulation coverage and decrease unplanned completion expenses. In 2005 19% of the stages in horiz et of material properties (4 elastic constants) as well as in-situ stresses and reservoir pressure. ï¿½Introduction Successful production of velopment of the technique and field tests results will be discussed. Introduction The Horseshoe canyon dry coal formations have been co ¿½ With this information important completion decisions can be made such as: lateral isolation need stimulation staging requirements perf es. In spite of this tremendous effort and progress a systematic methodology appears lacking in the literature to integrate the variety of inf To assess the financial impact of these strategies a fiscal model was developed that evaluated SAGD project costs and then examined the ated the potential of coalbed gas resulting in commercial projects in Australia Canada China and India. No commercial shale-gas projects ent a fracture diversion system (FDS) is used to create a temporary bridge within the active fracture networks. That results in differential pr e pattern required to achieve the well deliverability. Finally the acid formulation and volume can be determined to generate the desired worm umps have been implemented. Furthermore Dismantle Inspection and Failure Analysis (DIFA) of pulled ESP systems were conducted to e

thus the cycle being completed. After startup effectively no energy is used up to keep operating the system. The system is of immense e of shut-in wells reduced. Introduction Use of the vertical wells is a traditional and well-known method of hydrocarbon field development.ï¿½ more than 10 days of rig time. Introduction The Manati field is located in the southern portion of the Bahia state and approximately 10 km o this valve opens the next control line is pressurized squeezing the next C-ring. The main feasibility issue with this cemented sliding sleeve the formation formation damage is expected to be one of the main challenges to counter the observed decreasing production. A new dime e liquid-loading mechanism in a sub-critical velocity production system has been considered in the analysis using a mechanistic wellbore ou e liquid-loading mechanism in a sub-critical velocity production system has been considered in the analysis using a mechanistic wellbore ou oject.ï¿½ Local formation dip changes were computed and well trajectory revised in real time due to such integration. The process used in t

ramco. Background Haradh forms the southwest part of the Ghawar oil field located about 80 kms onshore from the Arabian Gulf in the E n conjunction with an automated feedback control hydraulic valves will oscillate. Computations also show that all other factors remaining eq within Saudi Aramco. Background Haradh forms the southwest portion of the Ghawar oil field approximately 80 km onshore from the Arab

ical model shows that the dual-lateral accelerates the oil recovery by 10% compared to the horizontal well performance. Nevertheless the r ing (TCP) a technology that consists of a set of tubing-deployed guns that are activated by a primer or firing head and detonate shaped ch a is essentially the only reliable method of evaluating ESP system performance (and other types of time-to-event data). Introduction The c of the product was the fact that it offered the prospect of overcoming the traditional challenges that are always associated with acid fractur the significant production improvements gained from hydraulic fracturing. We will also present how the Alpine full field model predictions ha

cture and impede flowback into the horizontal leg of the wellbore. The results from this new technique have been encouraging; with an estim haracteristics such as leakoff behavior viscosity development settling rate for large-sized proppants and fiber degradation in static and dyn on during acid fracturing was recently implemented in several gas producers. The pilot comprised field trials in wells with similar reservoir ch mations in Western Siberia to have high degree of lamination and multiple shaly layers inside producing zone pilot well-candidates for the pr different methods to determine capillary forces for the flowback aids. In addition fluid loss testing was done to determine if the flowback ad t. The mechanisms studied in this work can also partially explain some recent results from microseismic or tiltmeter mapping that show mor a unique surfactant-based system relatively insensitive to most produced waters and even to some high-density brines. Fluid chemistry m mportance of following a systematic approach. Ultimately this paper focuses on how to optimize well performance using recycled waters in s n models and production analysis tools have enabled the evaluation of the technology used and the acceleration of the learning curve to ac with a reduction in water cut from 25% to 9%. In contrast two wells in the same field and with very similar characteristics which were frac-a easured net pressure from 14 to 27 bars at the end of the main treatment indicating fracture containment within the pay zone. The containe evaluation so that the selected sections can individually be stimulated evenly and inflow contribution from the entire openhole section can his Viscoelastic fluid used in nine different mature producer wells with preï¿½treatment water cuts ranging from 32% to 94%. One additiona ner does not require cementing and provides positive mechanical diversion at specified intervals so fracturing and stimulations can be pum

to achieve effective diversion. Consequently Saudi Aramco field tested an innovative new completion technology that provided the ability to

determine the preferred orientation plane for perforating. Oriented perforating assisted in achieving lower fracture breakdown pressures. Fr d in the literature concerning the use of the dimensionless productivity index as a measure for improved fracture stimulation design under b

stress environment. Although correct candidate selection and fracture design the degree of the pre-stimulation formation damage has prov

the cement and into the formation without perforated holes. Significant laboratory testing was conducted that predicted fracture initiation pre ng sleeve valve in regards to fracture initiation. Full-scale stress frame tests were conducted using sandstone blocks with far field stress a are obtained. First there is the area of input parameters where the effect of plasticity on fracture geometry is significant. Secondly fracture ons where clean proppant packs and gravel packs are desired3.ï¿½In the latest form presented here a VES fluid utilizing a new surfactant

bores thereby generating an opportunity to recover otherwise bypassed hydrocarbon reserves. Introduction In the recent past several pape

ving an increment of production from 2 798 BOPD to 5 353 BOPD maintaining the same wellhead pressure. The field results showed a sign e is more effective at reducing the yield stress effects than a larger breaker amount delivered randomly in the slurry. Alternative breaker mat first well the microseismic and treating pressure results of the first stage showed height growth into the proposed zone to be targeted by the

metries.1 2 3ï¿½ The fracture geometry is determined from microseismic events observed from a monitoring borehole. Usually only a single

We have measured the etched-fracture-surface profile for a wide range of acidizing conditions. The etched-surface characteristics depend ement has shown the validity of seismic methods and tilt indicators for tight rock such as carbonates and tight sandstone. However all expe ™s spectrometer. The detected gamma ray response not only identifies the presence of the proppant but in addition the strength of the re

ated an engineering approach that reduced the assumptions in the estimation of hydraulic fracturing efficiency particularly for the wells tha e is used for the entire proppant pack. The variation of apparent proppant permeability along the length of the fracture and its impact on w en get expelled back into the formation or is completely filled with fracturing fluid. When the pressure at the tip is higher than the far-field p ction data evaluation following acid fracturing using surfactant-based acids. It also compares the performance of two main acid systems bas prove performance of fractured wells. We use guidelines for choosing from the available fracture stimulation alternatives to focus on the tec ure performance can then be used to better engineer the stimulation to optimize drainage (Mayerhofer et al. 2005). Hydraulic fractures are w of a solid matrix connected with the pore pressure gradient. The influence of proppant properties rock properties in-situ stress fracture w ure increase (tip screen-out like pressure response) as the stress at the tip increases when the in-plane fracture propagates past the initial Taylor instability of the interface could bring to formation and growth of â€œfingers of gas penetrating the bulk fluid. The growth of fingers a ment evaluation tool it is possible to infer change in anisotropy which can indicate the creation of a propped fracture. In this paper the res

ter cake thickness compared to the fracture thickness plays a critical role in creating significant yield stress effects which could be either a region. When a second injectivity test on the second well was conducted again ï¿½the injected rate was not able to create fracture even acture height measurements. This paper describes the applied methodology for one of these evaluated boreholes (Carmï¿½polis Field) wh 4 5 hard rock 6 7 and shallow fractures in soil.8 Some of these experiments included monitoring instruments to measure fracture pressure m a gas-bearing formation or gas cap to lift an oil-producing zone artificially as shown in Figs. 1 and 2. Unlike conventional gas lift in which ee other fields in the planning phase. The six producing gas fields contain multiple stacked and faultsegmented reservoirs with recoverable nning multiple isolation systems to effectively treat different sections of the wellbore. Multiple coiled tubing trips and multiple rig-up and rig-d nning multiple isolation systems to effectively treat different sections of the wellbore. Multiple coiled tubing trips and multiple rigup and rig-do tion results from this well zero production was achieved a decision was taken to investigate the effect of the mud on well productivity cons currently increase the recovery factor for MRC (Maximum Reservoir Contact) wells. Introduction Field History:The Shaybah field discover els are run using nodal analysis software and include the reservoir simulation grid. A-priori simulations explored several scenarios to addre idered. This paper will evaluate different options to combine ESPs with intelligent completions and review their respective limitations benefi eterogeneous fractured and fissured carbonate reservoirs for MRC (Maximum Reservoir Contact) wells. Introduction Saudi Aramcoâ€™s A ons according to well water cut and flow rate and individual downhole rate and phase measurements obtained from a surface multiphase flo al. The work presented in this study addresses part of this issue with a laboratory controlled hydraulic fracturing test performed on a large b

n layers. In particular we examine the effects of clay silt and sand laminations geometry on the reservoirs productivity. For that purpose we ding analysis were sampled along the well trajectories from the 3D model. Sand production prediction analysis was subsequently undertake injectivity but also initiate straighter and more dominant wormholes while the un-removed perforation debris causes the wormhole to start w aluation of the related productivity increase vs. the conventional perforating method. Introduction In 1981 the operator started its explorati ng software was run in advanced to optimize gun selection where both operational risks and production objectives were taken into consider orating was deployed successfully while pushing the limits of its application envelope. To obtain a dynamic underbalanced condition in such e underbalance (with the completion fluid weighted accordingly) while subsequent zones could only be perforated balanced at best. A new p . The technique was applied during a pre-fracturing perforating job for Total E&P USA Inc. (Total) in their Bethany field located in east Texa il before acid stimulation. ï¿½A fast acting memory recorder was run with the guns to record pressure transients in the well bore at the time for a constant rate drawdown. The constant rate drawdown assumption is not suitable for the UBP as the flow rate varies along with the ch d then remain balanced to avoid fluid invasion on the new perforations. The secondary objective was to avoid an additional CT run for corre iceability of the perforators. Analytical results from the model are compared with the data collected from surface tests. The results indicate

haped charge perforators has been carried out by the industry since the 1940â€™s. Throughout this period of time charge performance ha ems considering gun size charge type shot density reservoir characteristics and the well conditions at the time of shooting. The optimal g loped using multilateral MRC wells equipped with downhole smart completions and surface MPFMs. Introduction The well is located in an planned for the development of Albacora Leste were already an established and successful completion technique in the Campos Basin. H es of 27 to 40 bbl/min with a viscoelastic-surfactant (VES) carrier fluid. Washpipe-conveyed downhole-pressure and -temperature gauges a etion and high water cut a work-over program was initiated by Saudi Aramco in the late 90s to re-complete these wells as horizontal produ on testing of the premium screens. Collapse testing revealed that the screen lost sand control at less than 1 000 psi. The collapse rating sta USD$5.0M for possible hoist re-entry. This paper details the deployment process of this Novel solution that has successfully restored produ

illing and placement of the gravel pack. Traditional methods with acid to breakdown filter cake have been proven ineffective as they cause productivity data from the wells completed to date. Introduction The Greater Plutonio Development is a 5 field deepwater project located in

panies to maintain a strategic reserve of natural gas to alleviate possible reductions in supply from imports and to prevent critical situations mely low rate dependent skins. Introduction Openhole gravel packing is one of the most popular completion techniques particularly in dee ave part of the packing. During the beta wave dehydration packing is achieved with fluid leaking off into the screen-washpipe annulus. The pproaches have been practiced in various regions in the world. A common and critical element of both approaches is the proper assessme ermittently between stages of the completion fluid to minimize cost. The carrier fluid by virtue of its viscosity and mechanical suspension ca rmittently between stages of the completion fluid to minimize cost. The carrier fluid by virtue of its viscosity and mechanical suspension cap tests to confirm its applicability and also to optimize perforating parameters. An extensive laboratory test program was conducted on repres ypically dropping quickly with constant injection pressure. Increase in injection pressure to bring the injection rate up is limited due to the low rs from 10 to 60 ft in thickness at depths from 4 000 to 10 500-ft true vertical depth in casings from 3-1/2 to 9-5/8-in. and in oil and gas res

th model building sanding prediction and evaluation and a detailed review of sanding history to understand the severity of the sanding risk nces no problems with other wells. This variation made the Messla field an ideal candidate for a detailed sanding and geomechanics invest ure and that they involved some rather interesting and misleading phenomena such as precipitation of salt from production tubing scale s ween water and rocksâ€”capillary stress and relative permeability. It is concluded that water-saturation-induced rock-strength reduction is th

ng rate prediction. Existing sand production prediction models tend to assume that the formation disintegrates into sand grains the momen . In addition a drilling fluid design methodology that can be used for quick and reliable determination of the optimum mud design (weight ty he range of 100 to 150ï¿½F. More than 250 wells (oil gas water injectors and disposal wells) were treated with viscoelastic surfactant-bas ometer the fracture conductivity was measured at increments of closure stress up to a maximum closure stress of 6 000 psi.ï¿½ï¿½ï¿½ï¿ cessful acid fracture treatments in the Permian Basin incorporating a combination of new polymer-free self-diverting acid combined with an d in a matrix acid and in an acid fracturing treatments which were designed and pumped with alternating stages of acid and fiber-laden poly ls in a number of wells with similar reservoir characteristics and multiple porosity lobes. The fracturing treatments were designed and pump surface. The use of viscoelastic diverting acid systems allows oil recovery from the most damaged zones. Oil recovery from these damage mulation fluids was a concern. In this paper we demonstrate the fluid selection process and its field implementation supported by integratio ersion and water-production control compared with wells in which a conventional polymer-diversion technique was used in the past with no c d timing of the flowback process. Use of computer-based virtual laboratory tool for the fluid selection coreflow laboratory testing for the fluid

een used in Kazakhstan. Such systems are shown to successfully divert and stimulate effectively even when natural fractures are dominan use of the presence of CO2 organic ligands and potential precipitation of the reaction products; the organic salts of calcium and magnesiu

on in the matrix permeability creating a very high fracture face skin that would account for the higher skin factors following fracture treatmen oam or gel to lower the penetration of treatment fluid in the created wormholes and their surrounding matrix or a particulate carrying fluid w due to equipment requirements and logistic complexity. A hydraulic fracturing treatment based on foam as the main proppant carrier fluid eff istribution and is expected to exhibit similar behavior to fluid flow and therefore to acid dissolutions.ï¿½ The 8 carbonate rocks investigate tudies performed to date have concluded that no selection criteria can be universally applied to every situation; rather that the selection me abled the operator to make informed decisions to define fracturing/completion strategy. We also present the additional benefits of incorpora eld complex is located on the northeast flank of the Wind River Basin 50 miles west-northeast of Casper Wyoming (Kuuskraa et al. 1996) regardless of boundaries between various technical disciplines. Cases of application for fracturing in Nurzhanov field Kazakhstan are disc

pectively. Background In the Sabriyah field of northern Kuwait the wells are usually completed with a dual completion string which provide t cement on logs suffered behind casing communication. The reasons for this remain unresolved but are a source of constant discussion. P will allow one to investigate possible test durations for CCTs and also to refine the parameters determined from approximate analyses. The sed.ï¿½ The effects of analysis methodologies based on specific flow regimes vs. total model fitting single- vs. multi-phase production trea s conductivity (CfDï¿½ or FCD) can now be obtained for each individual fracture stage. In addition to the effective properties the methodolo carry out a commingled multi-layer transient (MLT) test with a PL tool. In an MLT test in addition to the normal PL runs individual pressure nd various skin factors. Both naturally fractured and unfractured (homogeneous) reservoirs have been investigated. For unfractured and ho hickness and gauge resolution. It is shown that the conventional radius of investigation formula (Earlougher 1977) for radial-cylindrical sys nterpretation techniques for this unique environment. Having sensors downhole provides operators with an opportunity to get pressure draw volution for well-test and production data analysis is important because it provides the equivalent constant rate/pressure response of the we

s are initially assumed in the model and they are usually tuned during history matching which can be time consuming and also affect other h rference Test (VIT). Pressure transient analysis of a mini-DST data however in such reservoirs is challenging due to the associated uncerta e features such as scaled permeability data rock types and hydraulic flow units through interpretation of Nuclear Magnetic Resonance (NMR hermore the high-frequency high-resolution output of the meter allowed the operator to assess well efficiency and stability and to understan ed in Siberia. It is based on a rigorous mass balance approach which enables to consider properly the mass transfer effects when comparin

nnecessary expenditure. The factors that affect multiphase flowmeter measurement can range from excessive gas-volume-fraction low line of slug flow regime identification relates to the selection of stable flow intervals for surface sampling and further recombination factor deter and NEL flow loops show an error (including the reference meter error) in the gas flow rate better than ï¿½ 2% reading (95% confidence in th the actual field water volumes. The GOR measurements were varying from one well to another but majority of wells showed more gas pr

ay (more than 2 rays) allows a real-time or an a posteriori quality control and improvement of the overall performance of the meter in any typ ever there were a number of situations where manual intervention and workarounds were necessary. We would like to propose an easy to al derivative functions (Î²[qBDdiB(tBDdB)] and Î²[pBDdiB(tBDdB)]) â€” where these functions are defined to identify the transient transition bles analysts to customize the differentiation based on the measured-data quality without a need for subjective smoothing algorithms. Exam onitoring. Streaming Potential In reservoir rocks there exists a thin charged double layer at the interface between the rock matrix and the w

npredictable nature of fault-free risk â€“ i.e. the unplanned events in a job otherwise designed and executed to the highest standards â€“ alw beyond debate. In this process carbon dioxide (CO2) alone contributes to 60 percent of the total greenhouse gases. Carbon capture and s resented here greatly improves common approaches based on â€œFeatures Events and Processes as it quantifies risk levels. It provides d approach has shown a more comprehensive solution that could be used for the design and further optimization of this type of projects. An such as Sleipner (Norway) In Salah (Algeria) and Weyburn (Canada)1 2 3. New challenges exist also for CO2 Enhanced Oil Recovery pro nhanced logging program was added for one well that record nuclear magnetic resonance and borehole resistivity images predominantly to mechanical integrity assurance are currently subject of many R&D projects. Industry expertise also is being tapped in CO2 projects across mations experiencing strain is also investigated. In addition an accurate Mechanical Earth Model contributes to optimizing well construction

an oil & gas field with a water depth of 335 m (1100 ft). The depth of the main reservoir is between 2900-3000 mTVD with a maximum p nabled the wells to be placed as close to the reservoir roof shales as possible to maximize stand-off from the waterleg and hence increase o

R potential for this and all of the Silurian reefs in Michigan. Introduction Recently the price oil broke $100 per barrel for the first time. The in as examined through several well tests. Results of the interpretation of these tests showed excellent results associated with a reservoir of g incremental revenue from the added pay exceeded the cost of this new methodology and enhanced the economic viability of the field. Th ndensate production profiles. Two major reservoir engineering problems associated with gas-condensate reservoir development are: (1) p rizontal length of the well pair. The effect on the oil recovery from the angle of dip in the reservoir and the orientation of the well pair with reg concentration adjustment as plugging progression dictates. d) Utilize matrix diagnostics plot along with modified hall plot in real-time to con

uggests operational change to improve the production. Introduction White Tiger Field in offshore Vietnam is producing from a highly fissure gh expansion ratio conformance due to the large inside diameter (ID) of the producing casing through tubing inflatable packers (TTIP) tech ng multizone completion design. Due to the presence of a strong aquifer in this field water production started early and some of the wells w ake the water shut-off a matter of high importance and concern. There are several techniques being used to reduce or eliminate water prod on. In one particular well two previous water control treatments using a conventional water shutoff technique including a relative permeabil he well with a through tubing inflatable packer and a cement cap topped with mud push and high viscosity gel to reduce the cement slumpin (DTS) temperature internal and external CT pressure measurements. Permanent zonal isolation utilizing an inflatable packer with a ceme a multiphase production system to transport produced fluids from the reservoir rock trough perforatiuons wellbores flowlines and facilities t the pipe diameter. Droplet-size data were used to evaluate existing models such as Hinze (1955) Kubie and Gardner (1977) Angeli and He ommendations are presented for future model improvement. Introduction Two-phase liquid/liquid pipe flow is defined as the simultaneous t well that maximizes oil production.ï¿½ Furthermore the back-allocation algorithm is calibrated and trained on the proxy model of the well cture. This work describes how a team of reservoir production and process engineers developed and implemented a data simulation and d deposits along the whole production system from downhole to production facilities becomes progressively more important as water depth between an economical field and an abandoned field. Introduction Waxy crude oils pose unique production and transportation related chal e MDT* (Modular Dynamic Formation Tester) flow line. Extensive laboratory data from a research grade spectrometer and shop data with th ne Formation Tester (WFT) tool together with an advanced Downhole Fluid Analyzer (DFA) was used to quantify CO2 in real time as well as

an be used to predict dewpoint pressures decreases in surface condensate yields after reservoir pressure has decreased below dewpoint p e PVT experimental results with an EOS model. For each one of the four PVT parameters we used 1850 values obtained from PVT analys s after all is earth science where little is homogenous. A variety of factors can lead to hydrocarbon compositional grading including gravity [ esence. Few stations which were clearly identified as oil were perforated and produced oil/dry oil with natural flow. The survey helped optim ervoir issues including compartmentalization fluid compositional variation unexpected identification of oil oil reserve assessment and gas ns in data adjust dynamically to changes infer general rules from specific cases and accept a large number of input variables. An ANN arc refore for OBM filtrate environments accuracy of conventional formulations in representing the actual physics of flow is limited. We have c merical simulation modeling to conceptually evaluate the impact of fluid composition / properties gradation and compartmentalization in the p

pumpout that would not be possible with traditional probe and pumpout devices. The final field example of water sweep evaluation in high he formation tester string which could lead to scavenging. These parts were then redesigned and manufactured with the upgraded metals.

over large regions. Introduction The presence of a compositional gradient in reservoirs containing hydrocarbon columns has long been rec phase of natural reservoirs which are continuous through significant ranges in elevation. Therefore the requirements for compositional grad sult from a systematic integrated reservoir characterization performed later however has found that the reservoir fluid is gas condensate. T d a vertical variation. The samples captured by the wireline sampling tool were sent to a laboratory for compositional analysis that confirmed re compared and discussed. Guidelines are presented on how to interpret wireline pressure measurements in multilayered siliclastic reserv of reserves and reservoir architectures. This paper presents a method to use combined repeated pressure and in-situ fluid measurements t describe the development of an in-situ GOR measurement technique which uses the optical properties of methane and oil components in c

ownhole fluid analysis in conjunction with pressure gradient analysis is simultaneously analyzed to reflect and make deductions concerning The strengths and limitations of the technique for an improved understanding of reservoir architecture and fluid complexities are presented djust dynamically to changes infer general rules from specific cases and accept a large number of input variables. An ANN architecture ca

relation or table is valid i.e. away from meta-stable/critical regions and with non-complex fluids the reduced functionality and monotonicity a at least in three different flow rates at the testing conditions. In addition to live-oil emulsion studies the stability and droplet size distribution

iltrate and explores the different factors that affect performance of the focused sampling technique. An important consequence of achievin ensate samples. Firstly a well-kick and under-balance drilling simulator was used to calculate how much gas could be safely pumped into t data from the analysis as input to the Vx* acquisition software data to obtain more accurate flow rates. The collection of phase representat basic Pressure-Volume-Temperature measurements and compositional analysis at wellsite in real-time provisioning two major tasks but an ge amount of calcium ion due to the reaction by HCl and calcite. The order of reaction between organic acid/chelating agents and calcite ne hemical simulation and laboratory testing a novel chelating system was identified as the most suitable technology to efficiently stimulate the nerates calcium carbonate solid (damage) throughout the length of the core from the injection face. The final permeabilities of cores subjec chemical squeeze packages. No formation damage was observed both oil and brine permeabilities have recovered following the chemical

subsequent deposition. The permeability impairment in core-flow experiments was described by a new differential model. The applications trength and permeability damage occurred has received very little attention. In this paper new methods are described to directly determine t one is removed. As a result of these calculations we are able to predict the surge rate (and associated underbalance) required to remove olumes required for the first scale-inhibited hydraulic fracturing application in the Novogodnee field. The pilot project wells that were hydrau rs the production system scaling can be initiated by the pressure/temperature drop or mixing of incompatible water fractions. This scale dep tions significantly reduce the scale inhibitor chemical costs while improved scale inhibitor placement is achieved. 1. Introduction Inflow co parameters that are used to calculate the overall scaling risk for a certain string. The wells classified as high scaling risk wells are included e brine phase.ï¿½This is confirmed by lower than expected magnesium concentrations in the produced brine.ï¿½The impact of the calcium tching to permeability at the grid block level. The eigenvectors obtained during the PCA are suitably scaled and appropriate grid block volum atches by validating fracture lineaments. This novel procedure involves the tracking of water saturation and Time of Flight (TOF) of injected nning for both producers and injectors. This paper also demonstrates where streamline technology should fit within the overall reservoir ma accurately in black oil and compositional modes. The prediction of the models has been controlled by the available analytic techniques to a egration of tasks including production data gathering and standardization monitoring reporting and alarm functionality was a key element f d time lapse EM data sets from the water injection pilot. The images highlight the influence of background geological constraints on the flow l to quickly provide coverage over the major portion of the reservoir. Surveillance data indicates the reservoir is relatively well connected. Pa eases the flow rate and diminishes the operational costs. Further advantages of this application include the complete elimination of tubing w ers as a stimulation method through the use of a numerical model of a representative field in the Ayacucho area of the Orinoco Oil Belt. The Bjorndalen and Islam 2004). Microwave irradiation applications include inspecting coiled tubing and line pipe (Stanley 2001) as a treatmen sweeping front between wells. Injectors are converted to producers (and vice versa) providing heat directly to the zones where production w ost and eliminating stuck pipe incidences. Well has been completed openhole with sand control strategy using standalone screen with two ogs and image logs used in the porosity partitioning model provides a well log based permeability that has a good correlation with core plug acker has the capability of hydraulically isolating a minimum of one meter of formation. The dual packer can be set repeatedly at different lo

t for purpose technologies has resulted in a five fold increase in production through horizontal wells compared to vertical wells with no sand

Conventional acid treatments have a low success rate in the Nukhul formation. More than 50% of the stimulated oil wells turned into 100%

the liquid flow rate with no possibility to be able to get the gas production because no separator were able to work in these conditions. How

ns in porous media where the reactive chemicals contact a wide range of minerals.1 The formation may contain various amounts of quartz ddition to traditional downhole sampling methods like low-shock PVT sampling (which allowed taking gas samples above the dewpoint) new

ium fluid grading behavior of the fluids tested. First equipment was calibrated using synthetic fluid systems as shown in Ratulowski et al.1 T

emicals to control the crosslinking kinetics such as pH buffers crosslinker concentration and competing ligands to temporarily bind the me hibits increased fluid efficiency as compared to conventional acid fracturing systems with the potential of achieving heterogeneously etched

ir and production main objectives but not limited to: Real time down hole pressure temperature data Update reservoir model Transient tes a (lbm of proppant added to 1 gal. of clean fluid) and proppant quantities of 60 000 to 80 000 lbm per treatment. High leak-off limits higher p ow secondary damage on the formation core sample during the acid preflush. Additionally mud acid shows further damage after the treatm d for stimulation of this high temperature formation was confirmed through increased formation permeability and high levels of dissolved mi ng growth into water - or non - productive zones resulting in reduced fluid and proppant volumes. Field implementation proved also to be su on is known as water block. The sources for excess water in the formation could be water based fluids used in drilling completion matrix o mation water samples from two offshore Gulf of Mexico wells for pressures to 20 000 psi and temperatures to 242ï¿½F. Results are compare

Cleveland Formation The Cleveland formation was discovered in the mid-1950â€™s while exploring for the deeper Morrow reservoirs.ï¿½

gh to plan for optimal development. Our case shows the value of collecting the key data early in a complex tight gas environment and how uld possibly be eliminated to save cost. There is not a direct correlation between pump time sand volume and stage height. Ball sealers we erformed on low permeable formation of Siberia to understand the phenomena. This included acoustic measurements and micro-seismic m c datasets obtained during hydraulic treatments in several tight formations together with measured wellbore pressure and treatment parame 2-based emulsions and viscoelastic fluids. A high-rate hybrid treatment was selected because of the fracture geometry it would generate: b

mpletion conceptâ€” with properly engineered design of well trajectoryâ€”can make the difference between the economic success or failure i rizontal wells has been developed in the Guangâ€™an field with the intention to tackle the large resource potential within the wide sand dis n the 1960s. Locations of the fields are shown in Fig. 1. The SUG field has been producing from the Lower Cretaceous age Ratawi Oolite c on and field performance can be forecasted using reservoir modeling and simulation in a highly heterogeneous reservoir. Rigorously-constru brating the pre-stimulation injection tests on these stages using theoretical fracturing models such as pseudo-3D (P3D).ï¿½ Pressure histor ost reasonable volumetrics and flow characteristics was chosen for the numerical simulation study. The producing wells are hydraulically fra vals normally bypassed were perforated and hydraulically stimulated.ï¿½ We compared production data from offset wells that used standa

ows that the combination of both image data sets provides a much better and more complete picture of fractures in the wellbore with limited mmend a solution. The solution involved the economically viable replacement of the drilling fluid with a low solid content fluid prior to the wi e Hassi Messaoud field in Algeria this paper describes methods that can be used to fully characterize natural fractures in terms commonly ed complex tight formation gas field collected with new generation wireline technology. Operational interpretation and application recomm

d area and an offshore carbonate formation in West Africa. We show the pitfalls that can arise with incorrect test design as well as the impr northern and southern as shown in Fig. 1. This paper discusses the reservoir-management optimization of the southern license area with nd depletion possibilities exist as risks that need to be identified and managed through appropriate application of integrated drilling and com and zonal fault zones. Such localization of the highly productive sections within the huge oil-and-gas-bearing territory allows hoping for the

e Fluid Analysis (DFA) procedure has dramatically improved the situation. Downhole pH measurements utilizing robust pH dyes the princip

water production while controlling the sand production. This paper discusses about the challenges in planning and executing cycles of real

multicriteria decision making methodologies including the multi-attribute utility theory (MAUT) the simple multi-attribute rating technique (S However recent research shows that subjective expert judgment can be accurate as long as it is properly elicited [4 5 6]. In other words the e ght or in gauge and that the drift diameter of the hole could be significantly less that the diameter of the it that drilled it. on the effect of tar or heavy hydrocarbon on the validity of the technique. We also explore methods to improve the accuracy of the results. logy can be used at any scale the focus was on characterizing formation heterogeneity within the length of the ERA string in the vertical dir s in one single tool. Cost is negligible compared to valuable information that these logs can bring in term of rock characterization (porosity m at have subdivided the KG Basin into a complex array of horst and graben structures. The lower cretaceous formations in the study area hav s of the Rhourde El-Krouf field are characterized by large variations from laterally extensive bodies with good interconnectedness and high n r fluid with greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time thus ext ble oil presence. Few stations which were clearly identified as oil were perforated and produced oil/dry oil with natural flow. The survey help ter stage of development of the field. Based on the porosity partitioning technique an improved permeability estimate is made. The producti ence in a unique pattern when visualizing the â€õil down toâ€™ i.e. OWC oil-shale contact (OSC) and wells with residual oil saturation. Th ment distance to bit. Improve real-time data-transmission rates. Improve service reliability. Minimize use of chemical nuclear sources. Th me to determine formation density without the use of a chemical logging source. A case study is presented of a well situated in a field in so

ata was assumed from ï¿½ 5 to ï¿½ 15%. The results showed a significant range of uncertainty in hydrocarbon saturation estimate from ï¿½ med from ï¿½ 5 to ï¿½ 15%. The results showed a significant range of uncertainty in hydrocarbon saturation estimate from ï¿½ 2% reaching covery (EOR) via water flood gas injection and/or combinations of both to improve ultimate oil recovery. The advance of fluid fronts in fields enerally is a function of permeability in carbonate and sandstone reservoirs and helped reservoir engineers and petrophysicists to understa e log analysis method were validated in the lab through extensive characterization of the pore system over a range of scales.ï¿½ Data from enables to understand the fluid flow behaviour and potential productivity in such a reservoir. These techniques reduce the uncertainty of hy

ume fraction and porosity output depending on the input parameters. Next we show the complementary aspects of the resistivity anisotrop effect on the tool orientation is different. Data quality could also be different when logging long intervals of the casedhole resistivity because -situ horizontal stress (ÏƒH). Wells with low fracture density or dominant fracture strike oriented oblique or perpendicular to ÏƒH generally sh e different probe focused probe and dual packer tools - as well as enhancements to improve pump performance in the presence of high so illing fluid it was demonstrated that mud pressures alone were insufficient to cause the observed artificial fractures. However thermal effec uous bodies along with possible porosity profile not only provide a rapid inside into the geology but also indicate further exploration potentia

n a real reservoir modeling example is presented. Facies probability maps were derived from geologic propensity analysis coupled with wellnation of GR spectroscopy elemental yields nuclear and sonic porosity and array resistivity logs. Identification of thin beds and computa n (D) offer new ways to determine the fluid type in thin layer sands. From the bimodal relaxation distribution of the laminated sand-shale sy

vature method. Neglecting the complex borehole shape between survey stations can lead to a systematic error in determining the borehole

nd orientation of the wells with respect to the in-situ maximum/minimum stress. Some general rules of thumb are derived about stress reorie gâ€™s modulus and Poissonâ€™s ratio obtained from laboratory testing on rock samples acquired from selected intervals are used to cali nd inversion of borehole sonic data. The results of the two techniques are consistent providing encouragement for further validation of the m the inflow performance measurements of commingled multi-layer reservoirs obtained using multi-rate production logs. Introduction The an the inflow performance measurements of commingled multi-layer reservoirs obtained using multi-rate production logs. Introduction The an the inflow performance measurements of commingled multi-layer reservoirs obtained using multi-rate production logs. Introduction The an om the converted component of the zero-offset vertical seismic profile (VSP). After registration of the z-component image with the converted petrophysical formation evaluation. The study reveals that the highest average fracture density is over (Layer-A & B) at the upper most inte ciated with significant losses of drilling mud that was an indirect indication of presence of significantly fractured zones. The wellbore image rs. The impact of such fracture systems on mature carbonate reservoirs can range from very restricted to conduit for fluid flow. The exact im n indirect indication of presence of significantly fractured zones. The wellbore image FMS that was recorded in the well showed a good leve

of different data sets such as transient drawdown/injection and drawdown/buildup tests 3D deep resistivity production and injection profile cations of wireline formation testing have been discussed in a number of publications concerning DFA and IPTT. Representative samples a rofiling and MDT-IPTT indicated that formation alteration not necessarily increases with overbalance.ï¿½ The results quantified nearby form

ho-spacing and the use of a fit-for-purpose T2 cutoff time tailored for this type of reservoirs. Furthermore it will be demonstrated that the ef are acquired and that we do not indulge in needless over sampling. When NMR data is acquired after the sampling operation the continuou he NMR measurement of gas volume in the invaded zone can be correlated to sonic measurements for quantitative fluid substitution. We id xhibiting long T1 constants. In all three cases we show how porosity is under- or over- estimated beyond the expected accuracy based on plored and developed. Pulsed-NMR logging tools brought a wealth of new and unique formation-evaluation applications and this technolo ntified to calculate a formation water resistivity profile along the well. Preliminary results of the study confirm that combining this methodol ducers and water injectors are being drilled horizontally many multilaterally. These wells maximize borehole contact with the target reservoir

utilized to determine the optimal level of parameterization that is justified by the quality and quantity of the measured data. This paper high cause most of the studied wells were vertical the fracture corridors could not be properly related to presence of faults in the field. This pape

erm production profiles. Characterization of reservoir architecture and the fluids therein is the biggest challenge in achieving this goal. In add or understanding the reservoir.2 However in high-cost arenas where expensive production facilities must be in place prior to production of f tion of the inflow performance of commingled multi-layer reservoirs using multi-rate production log measurements. Introduction The analys state core material; analysis of pore size distribution and fluid typing through nuclear magnetic resonance (NMR) measurements; surface a ched to increase the success ratio of wireline formation testers (WFTâ€™s) in getting reliable pressures and fluid analysis including real-tim

control and decision-making. The use of the acquired stress and permeability data to optimize the number of wells well patterns selection pute formation fluid density and contacts. Pressure transient data on the other hand is crucial for estimating permeability heterogeneities a d/or waterflooding high pressure gas production horizontal wells and production enhancement work. Based on typical costs and economic y a comprehensive wireline downhole fluid analysis (DFA) program consisting of multiple pumping stations over the reservoir intervals. The ve to mitigate lost production during ESP downtime ensures economic viability.ï¿½ Finally the ESPs are designed to provide the utmost rel am consisted of evaluating the technical feasibility for a massive waterflood project including a preliminary design of the surface facilities ne ype valves were installed in selected wells on one of the platforms as a pilot project and extended to a fieldwide campaign.ï¿½ The Venturi per and lower conductive shale boundaries the wells can be steered in this very challenging environment of channel sands. In the past two cessfully in other analogous sandstone reservoirs of Saudi Arabia to ensure maximum reservoir contact. The results of using this approach ersus purchasing the well site compressors. The results and conclusion of project were: 1) Reservoir technologies like Moving Domain s m each wellbore penetrates many prospective reservoirs that can range depending on the field size and number of reservoirs from a few caused a rapid decline in reservoir energy and thus shortens the life of the field. This in turn causes the deferral of a substantial amount of one model is constrained by maximum liquid rate and minimum bottom hole pressure (BHP) while the BHP constraints on the coupled mod nally the FM functionality has been distributed among the reservoir simulator(s) the network simulator(s) and the â€œcontroller that coupl nagement. A case study is presented that illustrates how this concept is applied to an oil field during the conceptual design stage for life of fi oil recovery scheme a number of technical limits arose due to space and weight constraints on the platform. Furthermore fluid separation a ther infill drilling targets. Lessons learned and recommendations for future development campaigns on other fields were established. After 6

troduction Coupling a full field reservoir simulation model with a surface facility network model allows for more accurate computation of hyd gy with existing processing facilities. The Business Development Team has suggested a number of possible options for developing this new cture. This work describes how a team of reservoir production and process engineers developed and implemented a data simulation and nderpinned by the more traditional deterministic concepts have a number of drawbacks because of the requirement for continuous dataflow hese deviated high-flow rates high-water-cut environments is challenging because of the uncertainty and inaccuracy of fluid holdup data ac

on platform for Khafji crude production and its results with a particular focus to: Building a comprehensive network model for Khafji Field (i st production in this area was from the Huizhou 1S field in 1990 followed by Huizou 6S field in 1991 and Huizhou 3S field in 1995. There are mations. The Barik formation at depths from 4500 to 4900 m is composed of stacked sandstone packages with varying shale content sepa es a robust process to quantify the reserves in the LV reservoirs. This unique workflow includes sound data management and consistent an up contract terms. Introduction Traditionally companies providing services to the oil industry have had a list price for their services while c

ction of neighboring conductive beds and the distance to these beds. This ensured that the wellbore was drilled parallel to the structure an w geosteering techniques. Initial flow testing of the wells was very positive with combined rates of over 26 400 BOPD with minimal reservoir ves is applied compared to a fixed spacing approach.ï¿½For both cases an identical field footprint is simulated that is the same number cenario in the northern portion of the field. This reduction represented approximately 25% of the reservoir hydrocarbon pore volume. The m data time efficiently which allows making the right management decision to unlock some of the potential of these kind of fields at attractive g the horizontal section in order to maximize oil production and minimize gas-oil-ratios at well and field level. As a result the number of drain e waterflooding examples. Introduction Determining the location of wells is a crucial decision during a field-development plan because it ca

We present a comparison of our solutions with that generated using a commercial finite difference simulator for a variety of problems in te nd integration with real-time software. Introduction Over the years reservoir simulation has become standard practice in the oil and gas indu ressure and water saturation distribution that is readily available from the numerical simulator. For solving the inverse problem we utilize an o the changing of well conditions or introducing new infill wells rather than using the forward model time steps. This approach reduces the c

ptimized is reduced to the number of dominating geological patterns present. The new realization is automatically constrained to the given

e frequent use of simulation results in the reservoir engineering decision-making process indicates confidence in reservoir simulation techni h incorporates general phase-component partitioning. We analyze the complexity of our model and explain implementation details required this study appropriate technologies were applied to solve this problem. Production logging was implemented on four wells. The results reve

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿

ods of production rate-time data analysis has advanced significantly over the past years. This paper starts with the basic theories of Declin the fracture. Guar gum is the earliest example of an aqueous viscous fluid used during the injection. The fracturing fluid must be viscous to y further indicate that within the fracture gel saturations gradually increase towards the fracture tips. Contrary to the assumption made in e interpreted and discussed. Fracture characteristics have been approximately estimated by comparing real well test pressure buildup analy niform fracture conductivity could be taken account as well. Proposed model can be used for simulation of the steady-state multiphase mul ompared with the fracture height and pressure measured from a fracturing treatment with tracer logs as well as with the fracture length infe tures is even more essential for horizontal wells. In addition to removing skin and increasing the equivalent wellbore radius fracturing in ho terms of well performance the effect of non-Darcy flow reduces the productivity; and in terms of well test interpretation ignoring the non-Da erformance data into reservoir/completion models for each fracture stage. The outline of our paper is as follows. First we provide a brief m that have appeared in the literature since beginning in at least 1998 concerning the use of the dimensionless productivity index as a measu actual job responses i.e. a positive however extremely low slope (almost constant net pressure all along the pad stage). Such a behaviour velopment and made conclusions on the most probable situation for different formation conditions. We conducted the comparative analysis mances of all the methods we tested we observed that some methods that performed well in one test did not necessarily do as well in anoth

uires accurate detection of gas-water contact. The initial pressures are obtained from MDT (Modular Dynamic Tester) data and the water sa w the practical application of the theoretical model. Introduction Use of horizontal wells for injection purposes is now commonplace. This is d-point mobility ratio[2] greater than one. This adverse mobility ratio gives poor displacement efficiency poor vertical sweep efficiency and p from 18 sand sequences with the main reservoirs being the J K and M sands (Fig. 1). The major sand bodies were deposited in a shallow simulated reservoir pressure. A MATLAB-based program with graphical user interface was coded for this purpose1. Application of the prop high-WC wells rehabilitation; Building of a 3D full-field geological and dynamic models being able to serve for development optimization a th increasing burial depth because heat flows from the Earthâ€™s interior toward the surface. The temperature profile or geothermal gradi reliability to predict the future reservoir performance. Unfortunately simulation models are not unique and this undermines the credibility of

perty of K-orthogonality is lost if the medium is anisotropic and the local frame of reference is nonaligned with the principal axes of the perm dozens of articles published as related to this problem. The retrograde condensate drop in the near wellbore regions in a naturally fractured he matrix rock composition of the injection gas and rate of component diffusion in the porous media.ï¿½ Fine grid single porosity simulatio eability; and (4) numerical flow simulation and history matching. All of these implementations are incorporated into a single forward modelin

n the high resolution reservoir modeling domain for analyzing geological uncertainty model ranking and screening and dynamic model calib ration transport along streamlines. To this end we propose to use an implicit method. This eliminates the CFL restriction on the time step w orkflows. Introduction Modern reservoir characterization methods and 3D geological modeling are leading the industry to routinely build ve

rtainty in predicted performance. Both the rejection algorithm and Markov chain Monte Carlo (MCMC) are theoretically sound sampling proc

arium or strontium concentration) which may lead to scaling in the reservoir (BaSO4 or SrSO4 precipitation). Streamline simulation reduces

d acceleration compared to the solution of the same numerical method on a uniform grid. The proposed technique is implemented in a com l tens millions. In this regard conventional 3D finite difference methods suffer from two drawbacks numerical smearing and loss of computa order to determine the most likely group membership of a potential infill well. The classification of an infill well to a group is hereby not nece of uncertainty. Introduction Our main interest is in characterizing the uncertainty in reservoir description and reservoir performance predic the simulated pressure data with the recorded pressure data. This approach mimics the â€œface recognition or the â€œvoice recognition l. The screen acts as a flowpath between the annulus and the tubing; flow from the reservoir enters the annulus and passes through the scr

ation generated when simulating the laboratory depletion process (CVD CCE DL) overcomes the main limitation of black oil reservoir simu s or the super-connectivity created by shale in shaly sandstones 2- wettability effects in meso/macro pores and 3-the low connectivity of v

n-Darcy flow effect is now routinely measured for proppant packs. Nevertheless how to derive the beta factor b from experimental data is s carbonate oil-water transition zone to determine the free water level and the locations where oil should flow and on how to improve on th e productivity. This paper discusses the reservoir results generated by the implementation of underbalanced technology. Past reservoir perf 55-60degE (rift-climax). The younger stress fields of the Late Miocene and Pliocene times rotated progressively counterclockwise to a N15â Skills effective Data Management and Industry Wide Standards appropriate Hardware and Systems Architecture.ï¿½High quality data is a nted in Russia today: for the last 25-30 years the tendency is from slow to steady decline of the oil recovery factors in the fields. In Fig.1 a dy ope.ï¿½ Introduction Exploration of the Alaska North Slope and UK North Sea petroleum provinces progressed almost simultaneously w to allow them to be implemented in any laboratory with appropriate equipment. The predictions using data from the new measurement met

ent. The deeper depth of investigation is extremely valuable as the wells cannot be logged under dynamic conditions and fluid reinvasion i for one of the two horizontal wellbores. The successful installation of the two-phase flowmeter in an intelligent completion is a significant m re developed to survey the short string section of the dual string completions without utilizing a rig. The logging operation consisted of conv duction log analysis the new completion methodology appears to have restricted flow from the higher permeability intervals while permitting

y pretest-only WFT in order to quickly gather formation pressure data and mobility data. This data was then used to design the sampling str y pretest-only WFT in order to quickly gather formation pressure data and mobility data. This data was then used to design the sampling str tegic surveillance program calls for monitoring pressure support and flood front advancement by utilizing permanent downhole monitoring t asurements of pH at a single sampling station demonstrate that the method is robust and repeatable. These measurements have been com faster interpretation of reservoir parameters. These parameters are critical as new reserves are increasingly difficult to exploit and high-pote tion is more developed than the downward component resulting in vertical connection of the first three stages of the stimulation. Second t acture height containment (or the lack thereof). However the information from these tools may be quite misleading when planning a fracture

h dictates the bitumen viscosity was found to be the main parameter controlling flow in the injector-producer region. The results highlight th ction A production logging technique that utilizes Pulsed Neutron log measurements to evaluate the wellbore outflow and formation inflow i duction logging technique that utilizes Pulsed Neutron log measurements to evaluate the wellbore outflow and formation inflow in multilayer y than conventional production logging and the slickline can be safely employed where there is significant surface pressure. The paper use verall production. Using tracers for flow profiling horizontal well provides the following benefits: Enables flow position to be verified in long h d for deviations beyond 45ï¿½ from vertical in which sophisticated hardware with arrays of sensors must be combined with empirical slip m

n. PPS includes an events management and knowledge base system that allows not only detecting events but also identifying possible reas hnology. Included also is an explanation of why these logs were acquired. In some cases it was to diagnose non-productive intervals for pla ple SBHP recordings in these wells. The linearly-increasing pressure trend had to be taken into account in the analyses of the buildup tests ng insufficient pressure support from the water injector which in turn was causing gas cap expansion. The distributed temperature survey i sient data which enabled us to manipulate these success story with the rest of the wells in that field. Introduction The sole purpose of this p nse and modifications to the preplanned job procedures. Unexpectedly low or high mobilities probe plugging unanticipated fluid types the p wing fluid temperature due to the Joule-Thomson effect. Consequently layers where the GOR increases identifying early gas breakthrough 2007) stress changes associated with the volumetric strain are used to examine potential geomechanical failure zones that match the obse enabling the effects of differential depletion to be monitored over time. This paper outlines the completion technology used to install the fibe vailable across the length of the sandface which was an industry first for a subsea producing well. No additional penetrations were required eloped vuggy porosity. This study shows both fractured and vuggy porosityâ€“related types of thief zones can be potentially detected throug

ng this procedure engineers can detect discrepancies that affect future decisions. The sum of all these processes working together in a wo ons of the advantages and disadvantages of each technology as a standalone water entry recognition solution are offered. The results of th

usses in detail the reason in choosing resistivity behind casing acquisition and time lapse formation evaluation to monitor present saturation water independent of Archie-based resistivity method. Also this technique provides a new methodology to calculate cementation factor (m). l reach producers after 7 to 10 years. However the decision on field developments have to be taken early enough to avoid the slumping of ed to uneven sweep. ADCO is currently testing pattern-based flooding technologies to improve sweep efficiencies at two pilot studiesâ€”the echanical properties of the coals tested and penetration results for different shaped charges (of different designs) shot at various stress co og data from CBM wells in Jharkhand India have been integrated in a bid to identify the ideal candidates for completion. Coal seams for be ms averaged 4.7 BCF/day in 20051. This number is almost certainly an underestimation of the actual contribution of natural gas production f In 2005 19% of the stages in horizontal wells examined encountered near-wellbore difficulties. This field study inspects the major contribu roduction Successful production of hydrocarbons (gas and oil) from tight shale and sand reservoirs strongly depends on successfull hydrau on dry coal formations have been commercially exploited since late 2000. From the beginning it was clear the Horseshoe Canyon CBM play mulation staging requirements perforation cluster design and spacing.ï¿½ Images can also identify offset well hydraulic fractures when the erature to integrate the variety of information and obtain accurate reservoir characterizations. In this paper we present an integration workfl project costs and then examined the incremental cost and value of each of the completion strategies. Results show that although using stea a. No commercial shale-gas projects currently exist outside of the US but work continues to identify both new shale-gas reservoirs and to a tworks. That results in differential pressure increase and causes treatment redirection to understimulated intervals along the lateral. This tec rmined to generate the desired wormhole pattern. The discussion in this paper takes a first step toward the goal of designing matrix acidizin d ESP systems were conducted to evaluate the root cause of the failures and remedial actions were implemented to prevent such occurrenc

ystem. The system is of immense economic benefit as the operating expenditures are low. Also this system uses zero-cost air as power flui hydrocarbon field development.ï¿½ However application of horizontal completions can significantly enhance the efficiency of the hydrocar hia state and approximately 10 km offshore where water depth varies from 35 to 50 m.. This area is extremely environmental sensitive (Fig. ue with this cemented sliding sleeve concept was fracture initiation pressure through the cement and into the formation without perforated h decreasing production. A new dimension has been added to sonic measurements providing measurements in several dimensions: axial r ysis using a mechanistic wellbore outflow model.ï¿½ A commingled reservoir inflow performance model was utilized in the analysis to evalu ysis using a mechanistic wellbore outflow model.ï¿½ A commingled reservoir inflow performance model was utilized in the analysis to evalu h integration. The process used in this project to place a complex well entirely in a thin target would be applicable to all thin reservoirs that

hore from the Arabian Gulf in the Eastern Province of Saudi Arabia (Figure-1). Haradh field consists of three increments where the initial pr w that all other factors remaining equal these oscillations occur most easily in low-permeability zones. For unidirectional hydraulic valves w mately 80 km onshore from the Arabian Gulf in the Eastern Province of Saudi Arabia (Fig. 1). Haradh field consists of three increments: Th

ell performance. Nevertheless the results of the experimental runs indicate higher recovery values at early production stage compared to th firing head and detonate shaped charges. These charges create holes in the casing that allow formation fluids to freely flow into the wellbor e-to-event data). Introduction The critical importance of ESP system performance to field economics and deliverability has been well docum always associated with acid fracturing such as excessive acid leak-off shallow acid penetration fast spending due to the temperature effe Alpine full field model predictions have impacted the candidate selection process and discuss the stimulation design history that includes fra

ave been encouraging; with an estimated 24% improvement in average well productivity since the fiber designs have been implemented. A nd fiber degradation in static and dynamic conditions were determined in various laboratory tests. This engineering work allowed fiber based ials in wells with similar reservoir characteristics and multiple porosity lobes. The treatments were designed and pumped with alternating sta zone pilot well-candidates for the project were specifically selected to have complex geology including several layers of sandstones and sh done to determine if the flowback additives could improve fluid loss. All the flowback aids demonstrated low surface tension (~30 dyne/cm) or tiltmeter mapping that show more fracture height containment than that predicted by commonly used P3D hydraulic fracturing simulators gh-density brines. Fluid chemistry modifications employed to enhance performance allowed for reductions in mix-water and fluid-handling co rformance using recycled waters in stimulation applications. Introduction The exploration and production (E&P) industry in the United State celeration of the learning curve to achieve significant impact on gas production rates and downhole flowing pressures. Introduction The foc lar characteristics which were frac-and-packed conventionally rendered 100% and 63% water cuts respectively. Another application of this nt within the pay zone. The contained fractures manifest a 4 times liquid and 3.2 times higher average oil production compared to the produ om the entire openhole section can be maximized win one continuous operation. The treatment used the advanced emulsified acid technol ng from 32% to 94%. One additional case in presented on a newly drilled producer that was perforated and completed very close to a wat cturing and stimulations can be pumped effectively to their targeted zone. The system has also been designed so all of the fracturing or sti

echnology that provided the ability to selectively fracture stimulate multiple zones along the horizontal section. Field trials have yielded exce

r fracture breakdown pressures. Fracturing fluids for high temperature (320 degF) operations were selected. Well design and equipment w d fracture stimulation design under boundary-dominated flow conditions.ï¿½ One of the first investigations that specifically pertained to this

mulation formation damage has proven to be significantly different from the comparative formations in Western Siberia hydraulic fracturing h

d that predicted fracture initiation pressure to be near openhole fracture initiation pressure. To confirm the laboratory testing Petrogulf agree ndstone blocks with far field stress applied. The base case was set up using 4-1/2-in diameter casing cemented in one block and then perf etry is significant. Secondly fracture behavior depends on the typical magnitude of friction forces on fracture sides but it depends also on th VES fluid utilizing a new surfactant has been formulated and optimized for high permeability operations.ï¿½ Fluid Rheology Viscosity of

tion In the recent past several papers1-9 have been written about stimulation practices in the SENM Morrow.ï¿½ These formations of Pen

ure. The field results showed a significant improvement on post-fracture production and flowing pressure at both wellhead and bottomhole. n the slurry. Alternative breaker materials are explored and additional data are also presented to estimate the yield stress effect for fluid flow proposed zone to be targeted by the second stage treatment.ï¿½ Lessons learned from the first subject well were then incorporated into the

oring borehole. Usually only a single (closest) monitoring borehole is used since other boreholes are too distant and signals at them are con

ched-surface characteristics depend strongly on the acidizing conditions including acid type and strength velocity in the fracture leakoff ra d tight sandstone. However all experiments on soft sandstones such as found in West Siberian have shown more limited results. Given t but in addition the strength of the response is proportional to the amount of the additive/proppant that is present in the fracture thereby pro

ficiency particularly for the wells that were completed but were unable to maintain stable production. Although the certainty of the final sta of the fracture and its impact on well productivity are discussed in this paper. A comparison of predicted well productivity is also made with t the tip is higher than the far-field pore pressure a pressure wave propagates ahead of the tip with severe consequences on fracture propa mance of two main acid systems based on field data. The evaluation of acid fracturing treatments with in-situ gelled acid systems and surfac ation alternatives to focus on the technical merit of each technique and their application for improving fracture efficiency and deliverability a et al. 2005). Hydraulic fractures are formed generally through tensile fracturing resulting from injection of pressurized fluids and tend to form k properties in-situ stress fracture width and flow rate on proppant flowback is studied to determine the controlling parameters. It is shown e fracture propagates past the initial fracture tip. The in-plane fracture length growth is significantly slowed. Two field cases from the Barnet e bulk fluid. The growth of fingers and their further coalescence could not be described by the linear analysis. Growth of fingers causes irre pped fracture. In this paper the results from a DCHSA and hydraulic fracture campaign in a Western Siberian oil field are presented. In thi

ress effects which could be either avoided through adequate design or used to estimate the resulting productivity loss. Introduction A J was not able to create fracture even though the injected pressure was above the breakdown pressure. After analyzing the injectivity data an boreholes (Carmï¿½polis Field) where the data evidences suggest a singular fracturing propagation for two different and unexpected case ments to measure fracture pressure and width at some distance from the injection point.4 7 9 Physical mapping by mining provides fracture Unlike conventional gas lift in which gas is pumped down the annulus from surface an auto gas lift well has a downhole gas zone completi mented reservoirs with recoverable reserves ranging from 80 bcf to 1.5 tcf.1 Detailed discussions of the reservoir characteristics for most o ng trips and multiple rig-up and rig-down of the stimulation equipment is required. These multi-stage horizontal completions take weeks to c ng trips and multiple rigup and rig-down of the stimulation equipment is required. These multi-stage horizontal completions take weeks to co of the mud on well productivity consecutive interventions were planned to remove one potential damage mechanism at a time and investiga History:The Shaybah field discovered in 1968 in the Rub' al-Khali desert of Saudi Arabia is approximately 13 km (8 miles) wide and 64 km explored several scenarios to address and compare different uncertainty issues flow conditions well rates and pressure drawdowns both in w their respective limitations benefits and risks. Introduction Intelligent completions An intelligent completion combines permanent downh Introduction Saudi Aramcoâ€™s Abqaiq field is located about 19 miles (30 kilometers) southwest of Dhahran.The field is a northeast-sou tained from a surface multiphase flowmeter and alternating zonal well tests. The third strategy proportionally chokes the completions as incr acturing test performed on a large block of Colton sandstone. Physical model tests are of great value to determine the relevant phenomena

irs productivity. For that purpose we comment on the information from borehole electrical images NMR logs single probe and dual packer nalysis was subsequently undertaken using a field proven sanding prediction model that accounts for scale effects associated with different ebris causes the wormhole to start with a more deviated pattern.ï¿½ In the paper the required perforating design to create clean perforatio 81 the operator started its exploration activity in block 403 of Algeria. The area is located in the Berkin basin on the Sahara platform and c objectives were taken into consideration. Coiled tubing forces simulation was also used to determine the ability of the gun assemblies to be mic underbalanced condition in such a low pressure environment the shot density had to be reduced to 2.5 spf raising concerns about its perforated balanced at best. A new perforating system designed to generate a large dynamic underbalance with a static overbalance was ir Bethany field located in east Texas. ï¿½The job addressed the dual objectives of orienting the perforations along the PFP while simultan ansients in the well bore at the time of perforating. The subsequent acid matrix job onï¿½these wells further improved productivity.ï¿½ This he flow rate varies along with the changes in the skin (during clean-up) and the wellbore pressures. We present a general formula to handle avoid an additional CT run for correlation thus saving rig time. The objectives were met and this new approach to coiled tubing operations m surface tests. The results indicate that the model can reasonably predict the perforator swell and damage after detonation and as such wi

riod of time charge performance has improved significantly due to improvements in the case and liner geometries explosive materials line the time of shooting. The optimal gun system is run with gas lift on to establish underbalance conditions at the time of shooting for immedia troduction The well is located in an area surrounded by reservoir's faults and fractures; it was drilled as a multi-lateral oil producer with four n technique in the Campos Basin. However the Albacora Leste wells were amongst the longest attempted in the basin and due to the com pressure and -temperature gauges and radioactive tracers are used to help analyze the treatment results. This paper will discuss screen-se lete these wells as horizontal producers using various sand control techniques. While converting from vertical cased and perforated wells an 1 000 psi. The collapse rating stated by the manufacturer was greater than 7 000 psi. The erosion tests demonstrated that inflow from su that has successfully restored production from Well A-4L. Introduction Well Alpha-4 is a dual string producer with the long string (Alpha-4L

en proven ineffective as they cause highly conductive wormholes that contribute the majority of production.ï¿½ The acid can also react with 5 field deepwater project located in Block 18 offshore Angola (Figure 1). All 43 planned development wells are subsea in water depths ran

rts and to prevent critical situations in the gas distribution system. Currently the drilling activity in Italy is growing as mature depleted gas fie letion techniques particularly in deepwater developments with high transmissibility due to its ability to deliver reliable high productivity well the screen-washpipe annulus. The simulator also models fluid flow through complex flow paths like crossover ports pressure attenuators s approaches is the proper assessment of potential plugging of the sand control screens during installation and subsequent displacement p osity and mechanical suspension capability ensures that the gravel enters the perforations. This technique was successfully implemented i sity and mechanical suspension capability ensures that the gravel enters the perforations. This technique was successfully implemented a st program was conducted on representative core and outcrop material. Five modified API RP 19B Section IV tests were performed to asses ction rate up is limited due to the low formation frac pressure. ICD technology was sought in effort to mitigate these dynamic challenges. It h 1/2 to 9-5/8-in. and in oil and gas reservoirs at rates of up to 600 BOPD 1750 BFPD or 3.5 MMSCFD and in wells deviated as high as 42o.

tand the severity of the sanding risk and sanding mechanism. Based on this knowledge sanding management and remedial completion me d sanding and geomechanics investigation aimed at optimizing completions and production and at dramatically reducing the current sanding salt from production tubing scale spalling of borehole wall with drawdown and cavings bridge (cavings might fall into and become wedged nduced rock-strength reduction is the most significant factor governing perforation failure and sand production. Although perforation failure

egrates into sand grains the moment yield or failure occurs and that these grains are taken up by the fluid flow at the time when failure occu the optimum mud design (weight type and chemistry) was developed for the fields. Critical drawdown and critical reservoir pressure profile ated with viscoelastic surfactant-based acid systems. The acid was placed either by bullheading by using coiled tubing with or without a tra ure stress of 6 000 psi.ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ In this paper we present the result self-diverting acid combined with an existing acid-oil emulsion technology. This paper will discuss a combination of technologies which ha g stages of acid and fiber-laden polymer based pad fluid. The significant viscosity increase achieved in the pad by the addition of fibers and eatments were designed and pumped with alternating stages of acid and fiber-laden polymer based pad fluid. The significant viscosity incre nes. Oil recovery from these damaged zones was not previously achieved with conventional stimulation methods owing to the tendency for plementation supported by integration of mechanical rock testing core-flow and solids migration tests using preserved core. Results indica nique was used in the past with no consideration for water-production control in high-WC cases. The new technique has been selected as t reflow laboratory testing for the fluid optimization at downhole conditions and evaluation of fine migration tendencies were investigated befo

when natural fractures are dominant. This paper presents experiences with different types of acid placements and diversion techniques in ganic salts of calcium and magnesium. Therefore more testing and modeling are needed to better understand these reactions. This paper

n factors following fracture treatments. To eliminate the fracture face skin created during the fracture treatment a new treatment incorporati atrix or a particulate carrying fluid which creates a filter cake on the surface of the wormholes.ï¿½ This filter cake results in temporary skin as the main proppant carrier fluid effectively reduces the amount of liquid pumped overall provides better fluid-loss control and aids in post½ The 8 carbonate rocks investigated in this study represent 6 different RRTs. Each carbonate type was treated with reactive fluids.ï¿½ Two tuation; rather that the selection methodology for workover candidates must be customized to fit particular situations. This paper explores th the additional benefits of incorporating existing dipole sonic tool information to calibrate â€œin-situ stress Youngâ€™s Modulus and Poiss er Wyoming (Kuuskraa et al. 1996) Figure 1. Production from this complex was established in 1959 from Lance formation. The full extent o urzhanov field Kazakhstan are discussed. Introduction A total of seven wells were selected for hydraulic fracturing in theï¿½ Nurzhano

dual completion string which provides the mean to access both Mauddud carbonate formation and underlaying Burgan sandstone formation e a source of constant discussion. Possible explanations for the mismatch between cement evaluation log interpretation and the physical te ed from approximate analyses. The presented technique is also applicable for analyzing drillstem test (DST) data as long as the flowing flu gle- vs. multi-phase production treatment and assumptions regarding effective well length on the computed values of reservoir parameters e effective properties the methodology allows for estimation of the drainage area and skin for unfractured zones and fracture half-length an normal PL runs individual pressure transient stations are also recorded at the top of each contributing layer. ï¿½The MLT test measures th nvestigated. For unfractured and homogeneous formations a spherical or hemispherical flow regime occurs prior to the radial flow regime w gher 1977) for radial-cylindrical systems which is given as (Equation) yields very conservative estimates and it could be as high as 30 to h an opportunity to get pressure drawdown and buildup data when the ESP starts and stops.ï¿½ For the wells we monitor 10% of these uns ant rate/pressure response of the well/reservoir system affected by variable rates/pressures (von Schroeter et al. 2002 2004; Levitan 2005;

e consuming and also affect other history match parameters. Reservoir simulation results and predictions might be inaccurate if the values nging due to the associated uncertainties such as layer flow compartments and flowing fluid viscosity. This paper discusses the use of integ Nuclear Magnetic Resonance (NMR) and wireline petrophysics into a model. The model is built in two different ways. One is based on num ciency and stability and to understand the behavior of the gas lift system. It was shown that such wells have a tendency to behave erratically mass transfer effects when comparing flowrates at different measurements conditions of pressure and temperature. The presence of hydra

essive gas-volume-fraction low line pressures solids and unsteady flow. In 2007 an in-situ comparison was made of two types of multipha d further recombination factor determination. This information is also extremely important for well completion design. There is good agreem ¿½ 2% reading (95% confidence interval) at line conditions; the absolute error (including the reference meter error) in the measured total l majority of wells showed more gas production by the phase tester compared with test separators specially for the low potential unsteady we

performance of the meter in any type of conditions. This statement will be presented through a campaign of tests done in South America. F We would like to propose an easy to use software that can provide a complete workflow for regular use. Introduction The link between rese d to identify the transient transition and boundary-dominated flow regimes from production data analysis. We have utilized two different for bjective smoothing algorithms. Examples are presented using field measurements to illustrate the technique. Introduction The pressure de e between the rock matrix and the water in the pores. The matrix surface is usually negatively charged and the water is positively charged.

uted to the highest standards â€“ always requires a number of mitigation measures to minimize the residual risk of CO2 leaks. This paper w nhouse gases. Carbon capture and storage (CCS) is recognized as a means to reduce CO2 releases in the atmosphere significantly. CCS is s it quantifies risk levels. It provides useful and reliable tools to support decisions for well integrity management strategies or emergency pla imization of this type of projects. Analysis of reservoir properties as permeability temperature etc. is also taken into account in order to ass for CO2 Enhanced Oil Recovery projects. Although decades of experience exist in a few specific basins and geological environments the n e resistivity images predominantly to better characterize the storage formation. A core analysis program carried out on reservoir rock and cap being tapped in CO2 projects across Europe and in Australia including four major EU proposals under the Framework Program Six and th butes to optimizing well construction and stimulation operations. Profiles of stresses and mechanical properties along a planned-well traject

00-3000 mTVD with a maximum pore pressure of 434 bar. The field is 24 Km long and 4 Km wide. With this shape of the field ERD wells m the waterleg and hence increase overall oil recovery. Distance and direction to boundary data displays are intuitive to interpretation allowin

0 per barrel for the first time. The increase in oil price seen in the last few years has refocused attention on oil productive reservoirs. This is sults associated with a reservoir of good permeability high conductivity large drainage radius etc. According to the geology of this region a he economic viability of the field. This integrated process of measurement analysis prediction evaluation and model adjustment enables ate reservoir development are: (1) possible drastic drop in gas productivity when pressure drops below dew point pressure (2) loss of con e orientation of the well pair with regard to the direction of dip were also briefly analyzed. The conclusion presents a highly improved config modified hall plot in real-time to continually estimate flowing gel volume. e) Deploy a fit-for-purpose gel placement assembly for treatment u

am is producing from a highly fissured granite Basement formation. Basement consists of igneous crystalline rocks characterized by petrogr ubing inflatable packers (TTIP) technology conveyed with Coiled Tubing has evolved to the point to become an established alternative for th arted early and some of the wells were shut-in due to lift problems associated with the water production. A sidetrack option was considered ed to reduce or eliminate water production: 1. Chemical techniques like resins epoxies polymer gels etc. to plug the water producing feat nique including a relative permeability modifier (RPM) had left the well producing 100% water. The new solution reduced the water cut to 2 ity gel to reduce the cement slumping effect. Introduction Some horizontal wells started to produce less oil rate due to increasing water pro ng an inflatable packer with a cement plug above the packer was successfully performed using CT conveyed fiber optic system. The availa s wellbores flowlines and facilities to the sales point in a predictable manner over the life of the project (as per DeepStar). Plugging due to e and Gardner (1977) Angeli and Hewitt (2000) and Kouba (2003). An empirical correlation to predict the SMD profile of droplets across the flow is defined as the simultaneous flow of two immiscible liquids in pipes. Oil/water flow in pipes is a common occurrence in petroleum pro ined on the proxy model of the well model. Introduction Intelligent wells are wells that have installed monitoring devices to record the pro mplemented a data simulation and analysis workflow to identify the well-network-process systemâ€™s major bottle necks and made recom vely more important as water depths increase.ï¿½ This paper describes the impact of flow assurance considerations in a deepwater Gulf o ction and transportation related challenges1. Variation in temperature is the dominant factor affecting the waxy crude oil properties. Below a spectrometer and shop data with the downhole tool support the new methodology. Multiple interpretation algorithms have been developed f quantify CO2 in real time as well as acquire high quality PVT samples. As the analyses of hydrocarbon samples from previous exploration

ure has decreased below dewpoint pressure and decreases in reservoir-gas specific gravity at reservoir pressures below dewpoint pressure 50 values obtained from PVT analysis of eight gas condensate fluid samples and 1180 values obtained from PVT analysis of five volatile oil positional grading including gravity [4] thermal gradients [5] biodegradation [6] active charging water washing and leaky seals. Most of thes atural flow. The survey helped optimize perforation zone selection avoided unwanted fluid production and helped the operator to find and p oil oil reserve assessment and gas compositional analysis to understand its origin and potential contact migration. We stress the need for a umber of input variables. An ANN architecture can allow for continuous improvement by expanding the training database with new data. In t physics of flow is limited. We have constructed a numerical model for the OBM filtrate clean-up within the framework of an equation-of-state n and compartmentalization in the productivity of some Latin America reservoirs. Introduction Exploration wells provide a narrow window o

e of water sweep evaluation in high permeabilitiy/mobility zones demonstrates using formation testing as a means of reservoir monitoring. I ufactured with the upgraded metals. This enhancement to wireline formation testers helps the technology to encompass a wider spectrum o

ocarbon columns has long been recognized since Sage and Lacey (1939) published their seminal work. Segregation of asphaltenes causes requirements for compositional grading are that the reservoir is interconnected and that fluid properties such as gas/oil ratio (GOR) saturat reservoir fluid is gas condensate. The second part shows an extensive application of Downhole Fluid Analyzer (DFA) in the Wireline Form ompositional analysis that confirmed the variation determined by the downhole analysis. Both results identified the heterogeneity of hydroca ents in multilayered siliclastic reservoirs perform connectivity and compositional gradient assessment. We describe how to improve on thes ure and in-situ fluid measurements to provide a simple model of vertical fluid distributions looks at the different regression schemes that ca of methane and oil components in crude oil. With this technique GOR can be measured downhole in real time when the sample is taken

ct and make deductions concerning the correct state of fluids in complex fluid columns. As part of the process different reservoirs need to b nd fluid complexities are presented in two case studies. DFA DFA involves the in-situ measurement of optical absorption spectra of downh ut variables. An ANN architecture can allow for continuous improvement by expanding the training database with new data. In this paper we

uced functionality and monotonicity are valuable characteristics for robustness.ï¿½ Other methods exist for calculating thermal fluid VLE.ï¿ stability and droplet size distribution of STO emulsions were also determined. Experimental results indicated that the inversion point for the

important consequence of achieving negligible contamination is the ability to accurately measure fluid properties in-situ. Reduced cleanup h gas could be safely pumped into the wellbore. This coupled with continuous downhole monitoring of well hydrostatic pressure addressed The collection of phase representative samples also opens the opportunity for a full recombination PVT study to be performed using the im provisioning two major tasks but an essential task for any type of well testing device that opens the opportunity for sample recombination i acid/chelating agents and calcite needs to be more carefully considered rather than one. Proton attack controls the reaction rate of chelating echnology to efficiently stimulate the Ap-13 reservoir and overcome the inherent extreme conditions. Three injector wells were treated with e final permeabilities of cores subjected to this treatment exhibit damage compared to before the treatment which is likely due to the precipi ve recovered following the chemical treatments. A lower dosage (10â€“50 ppm) was required for the new chemical as compared with conve

differential model. The applications presented in this study provide insights for understanding the mechanism and magnitude of naphthenat are described to directly determine the extent of the strength and permeability damage caused by shaped-charge penetration. The crushed d underbalance) required to remove the damage zone. Moreover we predict the perforation skin that results from incomplete removal of the e pilot project wells that were hydraulically fractured with the addition of scale inhibitor yielded a threefold increase in productivity and simila atible water fractions. This scale deposition yields to a variety of problems ranging from plugging the formation pores/proppant pack and pe achieved. 1. Introduction Inflow control valves (ICVs) are emerging as a very promising technology for minimising water production and o high scaling risk wells are included on a monitoring list for periodical scale checks by running gauge cutters on slickline. Scale samples ar d brine.ï¿½The impact of the calcium release into seawater as it is displaced through the hot reservoir is to cause precipitation of calcium s aled and appropriate grid block volume cut-offs are defined such that the resultant regions are neither too large (which increases interaction and Time of Flight (TOF) of injected water along streamlines its respective main contributing injectors fracture/matrix cells carrying the flow uld fit within the overall reservoir management processes: How the streamline simulation technology fits into reservoir management workf he available analytic techniques to avoid any unrealistic estimates. Analytic studies of the paper present the ranges of critical flowrates and m functionality was a key element for the successful and efficient management of gas-loading problems at the field scale. Milestones achie nd geological constraints on the flow. Introduction Applying peripheral water flooding for pressure maintenance was commenced after few y ervoir is relatively well connected. Pattern VRR pressures and watercuts were somewhat out of balance prior to engaging in this effort. Now the complete elimination of tubing wear by eliminating the need for a rod string greater torque capacity lower surface maintenance cost lo cho area of the Orinoco Oil Belt. The study has been divided in three parts. The first part relates to the use of downhole heaters in thick san pipe (Stanley 2001) as a treatment of waste-water/oil emulsion (Vega et al 2002) and for saturation monitoring (Honarpour et al 1996).ï¿ tly to the zones where production will occur gradually extending the steam chambers to the entire reservoir region. Thus the impact of stea y using standalone screen with two swell packers for addressing the future reservoir management requirements like intervention for isolatin as a good correlation with core plug data. Introduction The 1st Eocene reservoir of wafra filed is located in the Divided Zone (DZ) Saudi Ar can be set repeatedly at different locations on a single trip in the well. Using these modules pressures real-time formation fluid identificatio

mpared to vertical wells with no sand production. The paper illustrates how integration of different disciplines led to successful well placemen

stimulated oil wells turned into 100% water producers. The new stimulation treatment fluids and placement techniques improved oil product

ble to work in these conditions. However it was essential to PDVSA in this early phase of the development to review the performance of th

y contain various amounts of quartz clays (aluminosilicates such as kaolinite or illite) or alkaline aluminosilicates such as feldspars and ze s samples above the dewpoint) new approaches for logging and testing techniques were applied for the first time in Russia during this job.

ms as shown in Ratulowski et al.1 Then real reservoir fluids were used ranging from black oils to condensates (properties ranging from 27 A

g ligands to temporarily bind the metal crosslinker.ï¿½ Blended crosslinkers containing a single Group 4 (Ti Zr) metal with different organic f achieving heterogeneously etched half-lengths that approach the length-scale achieved with traditional proppant fracturing operations. Th

pdate reservoir model Transient testing Interference testing during planned shut-in Stability monitoring Frac operations monitoring Monit atment. High leak-off limits higher proppant concentrations and volumes. Higher rates are desirable but are limited due to limitation of equip ows further damage after the treatment. In contrast the new fluid system shows consistent damage removal during the treatment with the bility and high levels of dissolved minerals. Introduction Typically the purpose of acidizing a carbonate formation is to remove near-wellbo mplementation proved also to be successful in terms of operational simplicity reduced clean up time and consequently work over rig cost s used in drilling completion matrix or fracture treatments; cross flow of water to dry gas zones or water imbibition into tight zones.[6] The e es to 242ï¿½F. Results are compared to predictions from two commercial thermodynamic models that use the flashed gas and water analy

or the deeper Morrow reservoirs.ï¿½ It can be found in Ochiltree and Lipscomb Counties in the North Eastern Texas panhandle as well as

lex tight gas environment and how early collection can impact the development later and avert costly decisions. Also the special nature an me and stage height. Ball sealers were not an optimum method for closing off a stage for fracturing but there is evidence that degradable fib measurements and micro-seismic monitoring. Though the main purpose was to optimize fracture geometry by evaluating the measured an bore pressure and treatment parameters as the input the modeling analysis yields information of the induced fracture network including fra acture geometry it would generate: bigger width longer length and minimal height growth. The first new well came on production with a sig

en the economic success or failure in the field development of low-permeability reservoirs. This study used multidisciplinary and integrated a ce potential within the wide sand distribution and highly heterogeneous gas-bearing formation. Implementing the horizontal wells concept a wer Cretaceous age Ratawi Oolite carbonate reservoir. Current production is still under primary recovery assisted by bottomwater drive and eneous reservoir. Rigorously-constructed reservoir model(s) help us test and determine optimal production techniques to maximize field pro eudo-3D (P3D).ï¿½ Pressure history matching of fracturing data and production data provides the feedback information necessary to valida producing wells are hydraulically fractured with multiple stages. Single-well and sector models were used to determine the ultimate fracture a from offset wells that used standard petrophysical analysis to the results of the newer wells with the high-resolution analysis.ï¿½ï¿½ The

ractures in the wellbore with limited core calibration. Smaller scale faults which are usually not detected or poorly imaged on seismic can b low solid content fluid prior to the wireline formation testing operations. A new wireline formation tester technology the Extra Large Diamete atural fractures in terms commonly used for hydraulic fractures. With the application of combined imagery packages along with analyses of erpretation and application recommendations for wireline pressure measurements in the tight gas environment are included. Introduction W

rrect test design as well as the improvements brought by the latest tools when correctly configured. While there is usually confidence in the n of the southern license area with proved stock-tank oil in place of more than 6 billion barrels (Amoco Report 1996). Throughout a period lication of integrated drilling and completion technologies. Each risk may require different drilling and completion considerations in order to s earing territory allows hoping for the realization of the opportunity of the recovery of reserves of the entire region by limited number of high f

utilizing robust pH dyes the principle behind Litmus paper have been successfully utilized in differentiating between WBM filtrate and form

lanning and executing cycles of real time well site well placement completion perforation and artificial lift selection. Lessons learnt and resu

le multi-attribute rating technique (SMART) and the analytic hierarchy process (AHP). This paper presents an independent review and com y elicited [4 5 6]. In other words the experts need to be asked proper questions in a proper order. The judgment elicitation process should be it that drilled it. mprove the accuracy of the results. Our study shows the following: Under favorable conditions it is possible to derive primary drainage cap h of the ERA string in the vertical direction and about 100 ft laterally around the wellbore. The scale of the investigated formation heterogen m of rock characterization (porosity mineralogy for instance) and fluid content (gas water and oil saturation). Statistical methods such as ne ous formations in the study area have been interpreted to be of fluvio-deltaic setting with good sands development in channels and delta dis good interconnectedness and high net-to-gross ratios to multi-storey ribbon bodies with poor interconnectedness and low net-to-gross ratio ween wells for the first time thus extending the application of fluid profiling from a single-well to a multiwall basis. Field-based fluid characte oil with natural flow. The survey helped optimize perforation zone selection avoided unwanted fluid production and helped the operator to fin bility estimate is made. The production results confirm the findings of this study. Introduction In order to link log data to the hydraulic prope wells with residual oil saturation. The pattern appeared unusual in a homogeneous clastic reservoir. The OWC depth in the reservoir show se of chemical nuclear sources. The new-generation LWD tool is currently available in a 6ï¿½-in. collar size with a total length of 26 ft (Fig nted of a well situated in a field in southern Italy inside an environmentally sensitive national park. Because of the location of the well it ha

ocarbon saturation estimate from ï¿½ 0.3% reaching to ï¿½ 85% in some models.ï¿½ General water saturation error analysis charts were ation estimate from ï¿½ 2% reaching to ï¿½ 75% in some models.ï¿½ General water saturation sensitivity charts were developed for each . The advance of fluid fronts in fields undergoing EOR typically varies within the formation layers with permeability usually being the control eers and petrophysicists to understand response of reservoir formation tester measurements for formation pressure and reservoir fluid mob ver a range of scales.ï¿½ Data from a variety of methods including MICP lab NMR BET surface area thin section analysis continuous vug hniques reduce the uncertainty of hydrocarbon volume and productivity computations in a highly laminated deepwater reservoir.ï¿½ The fiel

y aspects of the resistivity anisotropy and NMR techniques. Since several are the same or determined independently using both datasets e of the casedhole resistivity because the tool requires physical contact between the measurement pads and the casing. In this paper all the or perpendicular to ÏƒH generally show poor production rates. This paper discusses case studies of fracture and fault characterization from ormance in the presence of high solids content. Such approaches are not always successful. In this contribution we describe an innovative al fractures. However thermal effects around the borehole were an additional major contributing factor to many of the observed fractures a indicate further exploration potential particularly in the north-eastern part of the main Al-Khafji field. Introduction During Cretaceous times

ropensity analysis coupled with well-log data and used for constraining the model to honor the facies spatial association of the reef comple ntification of thin beds and computation of sand-count from an electrical borehole resistivity imager. Validation of the wellsite petrophysical ution of the laminated sand-shale system it is often possible to determine a cutoff to separate the two components. Porosity in the sand co

tic error in determining the borehole position. We consider using continuous inclination and azimuth measurements along with stationary su

humb are derived about stress reorientation around horizontal wells and conditions favoring/opposing the reorientation have been analyzed m selected intervals are used to calibrate the dynamic data obtained from logs.ï¿½ However since the rock layers vary in their properties w gement for further validation of the multifrequency inversion of cross-dipole dispersions to estimate horizontal stresses. Even though the ov roduction logs. Introduction The analysis of the effect of a variable flow rate production history on the pressure transient performance of a roduction logs. Introduction The analysis of the effect of a variable flow rate production history on the pressure transient performance of a roduction logs. Introduction The analysis of the effect of a variable flow rate production history on the pressure transient performance of a omponent image with the converted image for various prominent reflectors the discontinuities in the reflectors in the converted-component (Layer-A & B) at the upper most interval of Thebes Formation around 2.2 fractures/ft and (Layer-C) at the bottom around 1.77 fractures/ft. T actured zones. The wellbore image FMS that was recorded in the well showed a good level of correspondence between the model forecas o conduit for fluid flow. The exact implications depend on the type of fracture filling geometry connectivity and density.ï¿½ The fractures o ded in the well showed a good level of correspondence between the model forecast and the actual result. The well contains interval of num

vity production and injection profiles openhole log and core measurements. This approach is new to the industry and the first field experim and IPTT. Representative samples are important especially for reservoir and petrophyiscal evaluation in the early stages of exploration. Ide ½ The results quantified nearby formation alteration showed this as a possibility and can further help in selecting the best perforation strate

e it will be demonstrated that the effects of nuclear diffusion on the transversal relaxation time distribution (T2 mode) primarily caused by g e sampling operation the continuous logs of viscosity and GOR can be calibrated with WFT data to provide fluid information in places whe quantitative fluid substitution. We identify gas in thin and shaly reservoirs from NMR standalone fluid typing and present examples of succ nd the expected accuracy based on random noise alone. The results are discussed in terms of what measures can be taken to identify and tion applications and this technology has grown rapidly since its inception. Today major service companies (e.g. Baker Hughes Halliburt onfirm that combining this methodology with local experience layer-by-layer correlations formation pressures data log analysis and supple hole contact with the target reservoir in order to achieve the goal of optimizing oil recovery. Vertical wells are drilled only for formation evalua

he measured data. This paper highlights (1) the use of a reservoir simulator to derive the inflow of fluids in heterogeneous reservoirs and ence of faults in the field. This paper aims at showing how effective Logging While Drilling (LWD) resistivity images based on laterolog prin

allenge in achieving this goal. In addition to 3D seismic imaging drill stem testing and extended well tests were traditionally the only availab st be in place prior to production of first oil history matching for facilities design is precluded. The connectivity of the producing units through surements. Introduction The analysis of the effect of a variable flow rate production history on the pressure transient performance of a well nce (NMR) measurements; surface and downhole analysis of oil composition verses depth; and finally a program of production and injection s and fluid analysis including real-time monitoring of each survey by reservoir engineers. This paper describes the development path and re

ber of wells well patterns selection of water injectors and fracture design is discussed. Introduction In-situ stress magnitude and direction ating permeability heterogeneities and average reservoir pressure. Traditionally pressure transient testing took the form of Drill Stem Test ased on typical costs and economic rank the high potential unconstrained production options for each reservoir were determined. After imp ons over the reservoir intervals. The program conclusively identified multiple independent hydrocarbon-bearing sand intervals and assisted e designed to provide the utmost reliability by meeting Bokorâ€™s challenging conditions. Introduction The Bokor field is located offshore ary design of the surface facilities necessary to collect process and inject seawater. The third objective consisted of investigating the techni fieldwide campaign.ï¿½ The Venturi orifice allows constant injection flow rates (critical flow) with a differential pressure across the orifice eq t of channel sands. In the past two years Directional and Deep resistivity technology has delivered over 110 000ft of challenging reservoir t . The results of using this approach were very encouraging and a net to gross of 62% was achieved. It can be concluded from the results t technologies like Moving Domain study helped in candidate selection. 2) The compressor project has been a success with an average i nd number of reservoirs from a few into the hundreds. Technical and reservoir management considerations usually make every wellbore ca e deferral of a substantial amount of oil production. Further analysis was conducted investigating ways to extend the life of field. A solution is BHP constraints on the coupled model is calculated dynamically by the production system. In this case the stand alone reservoir model lead s) and the â€œcontroller that couples reservoir simulators to surface facility network simulators.1 The reservoir simulator provides embedd conceptual design stage for life of field forecasting.ï¿½ Introduction Optimization of oil and gas production occurs in various Reservoir Man orm. Furthermore fluid separation and export constraints had to be taken into account. Consequently the reservoir management plan requi other fields were established. After 6 months of implementation and monitoring the proposed initiatives have achieved some 13% increase

or more accurate computation of hydrocarbon recovery since both system imposed constraints (fluid flow from the reservoir and surface con sible options for developing this new reservoir; Option 1 involves tying in the new reservoir to the existing sub-sea infrastructure. Option 2 i mplemented a data simulation and analysis workflow to identify the well-network-process systemâ€™s major bottle necks and made recom requirement for continuous dataflow throughout the study and the sequential nature of the tasks.ï¿½ Where the continuous dataflow canno nd inaccuracy of fluid holdup data acquired with conventional technology. Recently PL data acquired with local probe holdup sensors have

sive network model for Khafji Field (including wells and production facilities). Demonstrating production gain by the use of advanced optimiz d Huizhou 3S field in 1995. There are currently 7 platforms and an FPSO which are producing oil and gas from 10 fields. New efforts were p ges with varying shale content separated by relatively thin heteroliths (sandstone/shale mixtures) of 3 to 7 m thickness. These heteroliths data management and consistent analysis processes that allow for iterations among different methodologies aimed at minimizing the uncert a list price for their services while client oil companies have waited until they had a need for a service before getting a quote. In conditions

as drilled parallel to the structure and inside the â€˜sweet spotâ€™ away from non-productive layers. As reservoirs become more challengi 26 400 BOPD with minimal reservoir drawdown. It is expected that the use of the new logging methods will result in more effective and unifo simulated that is the same number of wells type of wells production programs and abandonment criteria are applied; also both follow the oir hydrocarbon pore volume. The model results clearly indicated that this was not a reasonable model and gave the operator confidence t al of these kind of fields at attractive ROI and NPV. Introduction The world energy demand is continuously increasing while the number of evel. As a result the number of drainage points needed to effectively recover the existing oil was reduced from 20 to 4 realizing 75% of the ield-development plan because it can affect a projectâ€™s NPV significantly. Well placement is often posed as a discrete optimization prob

mulator for a variety of problems in terms of accuracy and speed.ï¿½We find amazing accuracy with massive gains (factors>300) in CPU ti ndard practice in the oil and gas industry for the management of oil and gas reservoirs. Typically such simulators are based on numerical m ng the inverse problem we utilize an iterative minimization algorithm based on efficient singular value decomposition. Prior information is inc steps. This approach reduces the computational effort and memory allocated for the sensitivity calculation. Fourth we use an iterative spa

omatically constrained to the given geological environment since it is a combination of its characteristic features. Also this approach can de

idence in reservoir simulation techniques. Since thermal simulation started in the early 1970â€™s many papers have been published for m lain implementation details required to minimize and in some cases eliminate CPU and memory overheads. We conclude with the validatio ented on four wells. The results revealed that some perforation intervals do not contribute to production. It also exposed allocation problems

¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï

arts with the basic theories of Decline Curve Analysis based on the assumption that â€œwhatever causes controlled the trend of a curve in he fracturing fluid must be viscous to allow the transport of the proppant during the injection and it must have the ability to be broken easily Contrary to the assumption made in analytical studies there is no sharp interface between the residual gel and the reservoir fluids after the real well test pressure buildup analysis from field and simulation results. Introduction The field studied is a carbonate formation in the Jura n of the steady-state multiphase multicomponent flow to hydraulic fracture of any arbitrary shape. Excellent agreement with commercial dyn well as with the fracture length inferred from post-fracturing production analysis. In this field case a T-shaped fracture was considered likel lent wellbore radius fracturing in horizontal wells enhances the production by improving the vertical communication between the reservoir st interpretation ignoring the non-Darcy flow effect would yield either a shorter fracture length or a lower conductivity. Field examples illustra s follows. First we provide a brief mathematical description of the statistical foundation of the method and the analytical flow model. Second nless productivity index as a measure for improved fracture stimulation design under boundary-dominated flow conditions.ï¿½ One of the fi g the pad stage). Such a behaviour cannot be interpreted with the responses of the previous models (steep slopes either positive - PKN - o conducted the comparative analysis of pressure drops and fracture width reductions for different types of fracture propagation.ï¿½ We also d not necessarily do as well in another test. This suggests that while RBF can be expected to be among the best methods there is no â€œ

namic Tester) data and the water saturation are obtained from the petrophysical analysis in initial wells and populated in the reservoir to hon rposes is now commonplace. This is because maturing fields produce increasing amounts of water and horizontal wells enable disposal of poor vertical sweep efficiency and poor areal sweep efficiency. These three factors combine to give a very low recovery factor. Any attempt d bodies were deposited in a shallow nearâ€“shore marine environment during the late Miocene to early Oligocene eras. The field is situated his purpose1. Application of the proposed methodologies allowed to determine and quantify the most significant parameters that influence m erve for development optimization and elaboration of a program of well intervention. Upon analysis of development history and accountin perature profile or geothermal gradient is related to the thermal conductivity of a body of rock and the heat flux. Thermal conductivity is no nd this undermines the credibility of forecasted results. To mitigate this impact on business decisions the reservoir engineer conducts seve

d with the principal axes of the permeability tensor or the grid structured or unstructured is non-orthogonal with an isotropic permeability ten lbore regions in a naturally fractured formation has been investigated to a lesser degree meanwhile a lot of gas condensate fields in the wor ½ Fine grid single porosity simulations are made with a compositional simulator to determine the rate of oil recovery from the fractures ma orated into a single forward modeling process and iterated in the automatic history-matching scheme. To obtain a history match on a reserv

screening and dynamic model calibration using production data. This paper describes the mathematical model for three-phase compressi e CFL restriction on the time step which is inherent to explicit methods at the price of possibly introducing more numerical diffusion. The nu ing the industry to routinely build very large and detailed geological models. These models currently may range in size from 10 to 100 millio

re theoretically sound sampling procedures but they are too computationally inefficient for practical applications (Liu and Oliver 2003). Olive

tion). Streamline simulation reduces the numerical errors for both miscible and immiscible displacement - so making the scaling calculations

technique is implemented in a commercial reservoir simulator. Introduction This paper encompasses fast and accurate numerical simulati erical smearing and loss of computational efficiency. Finite difference methods based on IMPES approach have the limitation on the time st fill well to a group is hereby not necessarily unique; the expert system might classify an infill well into several groups and assign a probabilit n and reservoir performance predictions in order to optimize reservoir management. To do so ognition or the â€œvoice recognition technique which are already being successfully applied in their respective domains. Introduction In annulus and passes through the screen into the tubing. An FCV allows active and remote control of inflow or outflow in different zones alon

n limitation of black oil reservoir simulation in the NKJC.ï¿½ The method enables the composition and component molar rates of a producin ores and 3-the low connectivity of vuggy porosity.ï¿½ï¿½ This model is compared with published data and is shown to correctly account for

a factor b from experimental data is still controversy. In a recent issue of the JPT in August 2005 there was a discussion by Batenburg and M d flow and on how to improve on these interpretations by performing more advanced formation testing procedures some of which are bas nced technology. Past reservoir performance of wells drilled overbalanced will be compared with current results for this field case. Recovery essively counterclockwise to a N15â€“25degE direction that persisted into early-late Pleistocene time. The dominant in situ stress orientatio Architecture.ï¿½High quality data is a fundamental building block of Smart Fields and it needs to be treated as an asset managed effective ery factors in the fields. In Fig.1 a dynamics of oil recovery factors over time is presented for the period 1970-2007 derived by averaging th progressed almost simultaneously with both emerging as significant sources after events in the 1970â€™s led to sharp oil price shocks . A ata from the new measurement methods have been verified at the field level through evaluation of actual wells. Finally the methods have b

mic conditions and fluid reinvasion is always present. Moreover in view of increasingly high rig rates and limited rig availability the simple elligent completion is a significant milestone corresponding to the general trend in the industry to improve inflow control and the understand logging operation consisted of conveying the production logging tool with a coiled tubing through the short string section of the dual comple ermeability intervals while permitting flow from lower permeability intervals. The methods used to plan and execute these production logging

hen used to design the sampling string which was a combination of an inflatable dual packer with focused probe. We discuss the decision p hen used to design the sampling string which was a combination of an inflatable dual packer with focused probe. We discuss the decision p g permanent downhole monitoring through a network of dedicated key observation wells. The subject field is a carbonate anticline that has ese measurements have been compared with numerical simulations using a multiphase chemical-equilibrium model that uses laboratory an ingly difficult to exploit and high-potential hydrocarbon reservoirs have problems which must be quickly diagnosed and remedied. New comp stages of the stimulation. Second the high density of located microseismic events allows us to define the velocity of the fracture system pro misleading when planning a fracture treatment due to the inherent assumption made when analyzing the log data. The major assumption is

ducer region. The results highlight the need for distributed temperature measurements in SAGD wells to facilitate understanding of the temp llbore outflow and formation inflow in multilayer commingled reservoirs has been presented in Refs. 1 and 2.ï¿½ The multiphase flow and p ow and formation inflow in multilayer commingled reservoirs has been presented in Refs. 1 and 2. The multiphase flow and pressure travers ant surface pressure. The paper uses case studies validated by spinner log comparisons to demonstrate that slickline fiber optic distributed flow position to be verified in long horizontal wells; and Comparatively inexpensive when compared to horizontal well production log costs. st be combined with empirical slip models to cope with nonuniform and unsteady flows. Nevertheless production-logging tools are routinely

nts but also identifying possible reasons for them based on historic data and artificial intelligent models. Our objective is to provide recomm nose non-productive intervals for planning a water shutoff while in others it was to learn more about fault-water channeling and reservoir be t in the analyses of the buildup tests to avoid interpreting wrong boundary conditions. Wellbore dynamics also initially affected some pressu The distributed temperature survey indicated excessive gas production from the toe of the horizontal section as a result of this expansion th oduction The sole purpose of this paper is to illustrate that sometimes operating companies under/over estimate their producing formations gging unanticipated fluid types the presence of multiple phases and excessive fluid contamination are but a few examples of such circums s identifying early gas breakthrough or fingering can also be detected using distributed temperature monitoring. The theoretical models ar al failure zones that match the observed locations of microseisms. Together the volumetric strain computed stress changes and failure zo on technology used to install the fibers along the sand screens and shows the data and results obtained where reservoirs with different pres dditional penetrations were required in the tree. Development of this system required coordination from the operator because of the multipl es can be potentially detected through integration of high-resolution image logs with PLT NMR and conventional logs. In addition methodo

e processes working together in a workflow is defined as â€œProduction Performance Monitoring (PPM). The objective of this paper is to p olution are offered. The results of this research along with the inclusion of two Niger Delta case studies address the viability of a possible

luation to monitor present saturation profile. Comparison between original and present water saturation level immediately detects the deplet o calculate cementation factor (m). Successful application of this technique in an offshore Abu Dhabi carbonate reservoir is presented here rly enough to avoid the slumping of water from upper to lower units and loss of reserves in the lower units. Early imaging of the injected wat fficiencies at two pilot studiesâ€”the water injection (WI) and water alternating gas (WAG) pilotsâ€”to monitor the under-swept lower units o nt designs) shot at various stress conditions. CT scan and cutaway imaging of the perforation tunnels will also be discussed. Tests were co es for completion. Coal seams for best production potential are identified through cleat density characterization. In this paper we show how ntribution of natural gas production from coal seams because in many basins especially in the west conventional clastic completions are in eld study inspects the major contributors to fracture initiation specifically focusing on cemented vs. uncemented laterals horizontal-stress a ongly depends on successfull hydraulic fracturing and the generation of a large fracture surface area.ï¿½ Maximizing fracture surface area a ar the Horseshoe Canyon CBM play was a unique CBM play it is set apart by consisting of a dry under pressured coal. The coal therefore d set well hydraulic fractures when they are intersected.ï¿½ This too can drive perforating and completion strategies as well as future infill we per we present an integration workflow that incorporates seismic interpretations and attributes borehole image and log interpretations core esults show that although using steam effectively in these strategies may not yield the highest recovery it does improve the expected value h new shale-gas reservoirs and to add incremental shale-gas production in existing reservoirs. Given that worldwide coalbed-gas resources d intervals along the lateral. This technique enables both fracture diversion without mechanical intervention and when enhanced with micro the goal of designing matrix acidizing jobs in carbonates for delivering targeted productivity. Using a mathematical model a sensitivity anal lemented to prevent such occurrences in future. Increasing Motor Lead Extension cable thickness utilization of tandem seals and new well

tem uses zero-cost air as power fluid. It is a space efficient package which can be used on offshore locations as well. The paper describes hance the efficiency of the hydrocarbon recovery. Horizontal drilling is particularly attractive when it comes to produce reserves from oil-wat emely environmental sensitive (Fig. ï¿½1) The field was discovered in 2000 through a prospect based on the seismic interpretation The re to the formation without perforated holes. Significant laboratory testing was conducted which predicted fracture initiation pressure to be sim ments in several dimensions: axial radial azimuthal. The radial measurements provide now the opportunity to determine whether the near w was utilized in the analysis to evaluate the fluid inflow of multilayer gas reservoirs that may produce liquids in conjunction with the gas. Intr was utilized in the analysis to evaluate the fluid inflow of multilayer gas reservoirs that may produce liquids in conjunction with the gas. Intr applicable to all thin reservoirs that must be exploited through horizontal wells.ï¿½ Technical contributions discussed in this paper include e

three increments where the initial production started in May 1996 from Increment-1 followed by Increment-2 and 3 in April 2003 and Janua For unidirectional hydraulic valves we also illustrate novel anticipatory control algorithms that prevent overshooting. For communicating lay eld consists of three increments: The initial production started in May 1996 with Increment-1 followed by Increment-2 and -3 in April 2003 a

arly production stage compared to the numerical mode results. Such results confirm that dual-lateral wells are more efficient compared to th n fluids to freely flow into the wellbore. When formation characteristics such as permeability skin and reservoir pressure are uncertain a d nd deliverability has been well documented (Allis and Capps 1984; Upchurch 1990; Brookbank 1996). What has been missing however is a pending due to the temperature effect and corrosion. However a solid acid system also reduces the health safety and environmental (HSE ation design history that includes fracture fluid changes resulting from core analyses. Introduction The reservoir mechanism impeding maxi

designs have been implemented. Additional benefits have been realized like elimination of chokes cutting out due to sand production and a ngineering work allowed fiber based fluids technology to be extended to moderate permeable oil reservoirs (1-20 md) and relatively cool fo ned and pumped with alternating stages of acid and fiber-laden polymer based pad fluid. The viscosity increase achieved in the pad by the several layers of sandstones and shaly strikes. This requires the fracture to intersect layers of sandstone and provide optimum connection f low surface tension (~30 dyne/cm) but each was different in terms of surface wettability and adsorption in the rock. In all cases the flowbac d P3D hydraulic fracturing simulators based on averaged modulus. Introduction Because fracture height is recognized as one of the critica ns in mix-water and fluid-handling costs shortened flowback/cleanup time and provided equal or improved post-fracture production respon n (E&P) industry in the United States generates approximately 210 bbls/day in produced water (Arnold et al. 2004). Other reports suggest t ing pressures. Introduction The focus of this paper is in the Piceance Basin which is located in western Colorado and is an elongated stru pectively. Another application of this technique refers to frac-and-pack of wells with long perforated intervals where early wellbore screen-ou oil production compared to the production before the fracturing treatment. The new fracturing method when compared to the conventional f he advanced emulsified acid technology to achieve deep penetration and better etched fracture conductivity. Viscoelastic surfactant self-dive d and completed very close to a water zone that was successfully stimulated without any increase in produced water cut. Treatments prese esigned so all of the fracturing or stimulation treatments along the horizontal wellbore can be pumped in one continuous operation thus min

ection. Field trials have yielded excellent and highly promising results which compared favorably with the performance of non-stimulated off

ected. Well design and equipment was considered for high pressure operations (10 000 psi surface pressure) Using this process 10 wells w ns that specifically pertained to this subject was reported by Valko and Economides1.ï¿½ Subsequently a number of other investigators2-5

estern Siberia hydraulic fracturing has proven again to be a successful stimulation method. Carbonate reservoirs that constitute some 50%

he laboratory testing Petrogulf agreed to place two of these casing valves in a well in the Piceance basin to measure the fracture initiation p emented in one block and then perforated in the preferred fracture plane. Another sandstone block had a sliding sleeve valve cemented in cture sides but it depends also on the fracturing fluid rheology. This new model of hydraulic fracturing in a granular medium is an improvem s.ï¿½ Fluid Rheology Viscosity of a VES fluid is created by self-assembly of surfactant molecules in an aqueous solution.ï¿½Hydrophob

orrow.ï¿½ These formations of Pennsylvanian age are deposited erratically on the Northwest Shelf of the Delaware Basin with the most pr

e at both wellhead and bottomhole. A post-fracture pressure buildup test indicated a fracture linear flow with a fracture half length of 105 ft te the yield stress effect for fluid flow across the filter cake from the reservoir into the fracture. Introduction A Joint Industry Project (JIP) a well were then incorporated into the completion design of the offset well to optimize its overall completion efficiency.ï¿½ The second well w

o distant and signals at them are considerably attenuated. To drill a new borehole in a close vicinity of the treatment borehole is too expensi

th velocity in the fracture leakoff rate and rock type. Results for typical acid-fracturing fluids and conditions are presented along with recom shown more limited results. Given the uncertainties in effective Fracture geometry and the negative impact that they could have on the field s present in the fracture thereby providing insight on fracture width. Since the additive only responds when stimulated by the neutron source

lthough the certainty of the final stabilized production rate remains a challenge for the production and stimulation engineer recent produc ed well productivity is also made with the use of a constant permeability value for the proppant in numerical and analytic simulators. We wi ere consequences on fracture propagation. Finally the total energy consumption (which determines the net pressure) is primarily dissipated n-situ gelled acid systems and surfactant-based acid systems suggest that there was no significant variation in the design and the execution acture efficiency and deliverability and include the use of higher breaker concentrations lower polymer loads and use of proppant with bett f pressurized fluids and tend to form orthogonal to the minimum-principal-stress direction. Knowledge of this fracture orientation as well as e controlling parameters. It is shown that when a severe proppant flowback problem occurs the closure stress around the wellbore is signifi ed. Two field cases from the Barnett Shale are evaluated by comparing the model prediction to the pressure response. The model predictio alysis. Growth of fingers causes irregularity of the mixing zone. The present study investigates analytically numerically and experimentally Siberian oil field are presented. In this field the common well development practice consists of multiple large job fracturing treatments rang

productivity loss. Introduction A JIP active since 2002 was set up with the goal of studying fracture clean-up and using the mechanisms fter analyzing the injectivity data another mechanism related to poroelastic stress was postulated. Poroelastic stress is a transient localized r two different and unexpected cases: (i) a preferential down going fracture propagation for one of the fracturing operations apparently induc mapping by mining provides fracture geometry details that cannot be obtained in other ways but does not often reveal the overall extent of th has a downhole gas zone completion from which gas is bled into the tubing at a controlled rate. The flow of gas into the production tubing reservoir characteristics for most of these fields can be found in several earlier publications.2 3 The reservoirs in these fields are generally izontal completions take weeks to complete at high costs and elevated risks. Ultimately the high completion costs or the lack of production zontal completions take weeks to complete at high costs and elevated risks. Ultimately the high completion costs or the lack of production e mechanism at a time and investigate the effect on well performance. Upon the completion of all the intervention steps the well started to p tely 13 km (8 miles) wide and 64 km (40 miles) long. The surface terrain is comprised of salt flat areas known as sabkhahs and mountainou tes and pressure drawdowns both in the pre-planning and final installation of the completion. The final design incorporates a removable ho mpletion combines permanent downhole sensors and flow control devices which allow the operator to monitor evaluate actively manage an Dhahran.The field is a northeast-southwest trending elongated anticline with a south dome. The field contains six oil-bearing carbonate rese nally chokes the completions as increased completion water cut is measured using downhole multiphase flowmeters. A cost-benefit analys o determine the relevant phenomena of hydraulic fracture propagation because they allow for measurements that are unavailable in the field

logs single probe and dual packer wireline formation testers and production well tests. The workflow is fast to implement as it can be acc ale effects associated with different perforation size and sand grain diameter and plasticity effects that modify the strength behavior of sand ng design to create clean perforations is discussed for low permeability gas reservoirs.ï¿½ The effect of perforating with acid in the wellbore basin on the Sahara platform and close to the Tunisian border as shown in Fig. 1. In the same area several important oil discoveries inclu e ability of the gun assemblies to be safely conveyed into the target sands. In addition to that one of the unique features from the gun asse o 2.5 spf raising concerns about its effect on well productivity. Two wells were selected for this field trial. They were perforated using a TCP/ ance with a static overbalance was used to perforate new wells for the development project to maximize well productivity per well expenditu ations along the PFP while simultaneously avoiding the parallel completion which if perforated would open a communication path between rther improved productivity.ï¿½ This paper will show the perforating strategy execution requirements post jobï¿½monitoring and the final r present a general formula to handle the skin variation resulting from the UBP and other surge flow tests. This formula extends the applicat pproach to coiled tubing operations was found to be effective. Not only was there significant saving of rig time the wells performed superior age after detonation and as such will be a useful tool that shortens the required time to develop future perforators. Introduction A perforatin

geometries explosive materials liner composition and manufacturing processes. All of these improvements have aimed to produce a bette s at the time of shooting for immediate perforation clean-up. The under balance just prior to the time of shooting is managed using a perma a multi-lateral oil producer with four laterals and planned to be completed with smart completion (Fig.2) which consist of one Permanent D ted in the basin and due to the combination of the ultra deep water and limited sediment thickness had significantly lower frac gradients th s. This paper will discuss screen-selection philosophy in silt/very-fine-sand reservoirs carrier-fluid selection perforation strategy and ability vertical cased and perforated wells to single horizontal producers has helped to improve production multilateral wells are needed in Hawta sts demonstrated that inflow from supercharged reservoirs into the wellbore could erode holes in the premium screen. Revised operational p oducer with the long string (Alpha-4L) completed on the S7000E horizon. Production from this conduit prior to close in for sand production w

on.ï¿½ The acid can also react with sensitive clays in sandstone resulting in secondary and tertiary precipitations.ï¿½ Additionally acid reac wells are subsea in water depths ranging from 1200 to 1500m. Of the 43 wells 20 are producers and 23 are injectors. The development drill

s growing as mature depleted gas fields are transformed into UGS sites and the storage/drainage area of the existing fields is increased by deliver reliable high productivity wells.1 2 Current techniques used for gravel packing horizontal wells include Alpha/Beta 3 Alpha/Alpha4 an ssover ports pressure attenuators shifting tools etc. Thus it can be used to evaluate the impact of different tools and fluid configurations o ion and subsequent displacement processes since the screen installation often must be accomplished with solids-laden fluids (conditione que was successfully implemented in Abu Cluster field in west Malaysia. This reservoir had extremely high permeability (1.5 to 3 Darcy) wit que was successfully implemented at the Abu Cluster field in west Malaysia. This reservoir had extremely high permeability (1.5 to 3 Darcy) on IV tests were performed to assess the influence of static and dynamic wellbore pressure conditions and wellbore fluid on perforation cle igate these dynamic challenges. It has showed good results and further investigation is ongoing. The paper describes the processes in del nd in wells deviated as high as 42o. The technique can also be applied in different wellbore configurations to target pay behind casing and a

gement and remedial completion measures were devised that would minimize economic loss caused by sanding and optimize hydrocarbon matically reducing the current sanding without having to enter into a lengthy data acquisition programme or time-consuming modelling. In thi might fall into and become wedged in the openhole forming a bridge with no material beneath). The investigation concluded that installing duction. Although perforation failure is a prerequisite for sand production the failure does not always lead to sand production. Introduction

uid flow at the time when failure occurs. However in reality the failure-characteristics of sandstone and the pick-up of the failed material by and critical reservoir pressure profiles for assessing sand production potential in the fields were established. Sand production was found no ng coiled tubing with or without a tractor. In some cases these treatments included stages of emulsified or regular acids.ï¿½ All these wells In this paper we present the results obtained from a series of experiments with these fluids using Indiana limestone and dolomite core sam mbination of technologies which has recently been applied successfully in the Strawn formation in Terrell County Texas. It will also focus on the pad by the addition of fibers and its particulate bridging mechanism would plug off the just stimulated zones effectively thus diverting th d fluid. The significant viscosity increase achieved in the pad by the addition of fibers and its particulate bridging mechanism would plug off methods owing to the tendency for stimulation fluids to migrate to the most permeable zones. Viscoelastic diverting acid systems are mo using preserved core. Results indicate a high dependency of the mechanical strength on acid type. Based on the laboratory results an opt w technique has been selected as the standard stimulation practice in most horizontal openhole carbonate wells in Kuwait. n tendencies were investigated before the treatment. The results were compared with the one from other operators in the same environmen

ements and diversion techniques in the thick carbonate reservoirs of western Kazakhstan. Pretreatment and post-treatment production data erstand these reactions. This paper discusses the required information to properly design an organic acid or HCl plus organic acid treatmen

eatment a new treatment incorporating a pre-pad of acid viscosified with a solids free visco-elastic surfactant was developed. By incorporatin filter cake results in temporary skin effect which alters the injection profile. Gelled and foamed acids are also being used as a means of imp er fluid-loss control and aids in post-treatment flowback. Foam fracturing causes less damage to the formation and proppant pack therefore s treated with reactive fluids.ï¿½ Two different sets of coreflow tests were performed on 6 ï¿½ 1.5 inch plugs. The first set of experiments in lar situations. This paper explores the common traits shared by fields likely to have underexploited restimulation potential and suggests met ess Youngâ€™s Modulus and Poissonâ€™s ratio. Finally a production history match is conducted on wells treated with the new fluid. Intro m Lance formation. The full extent of the Lance sands in the Cave Gulch (shallow) structural accumulation was rediscovered in 1994. The p raulic fracturing in theï¿½ Nurzhanov field all of which have been treated. Triassic formations in Kazakhstan were not considered as a targ

rlaying Burgan sandstone formation (see Fig. 1). Mauddud formation is a thin low permeability carbonate layer with an average permeability og interpretation and the physical test results are explored. Introduction Evaluation of cement integrity and its ability to prevent fluid and ga DST) data as long as the flowing fluid does not reach the surface. Introduction Due to economics time constraints and environmental issu uted values of reservoir parameters emphasize the attention required to obtain meaningful interpretation from horizontal well tests.ï¿½ FSI ed zones and fracture half-length and conductivity for the hydraulically fractured reservoir layers. The methodology is applicable to all types layer. ï¿½The MLT test measures the flow rate and wellbore pressure above each producing layer for different surface flow rates during the curs prior to the radial flow regime whenever the penetration ratio is twenty percent or less.ï¿½ A half-slope line on the pressure derivative i es and it could be as high as 30 to 50% lower. Radius of investigation if fundamental for understating of the tested volume; i.e. how much wells we monitor 10% of these unscheduled events provided much coveted reservoir information without having to stop the production int eter et al. 2002 2004; Levitan 2005; Levitan et al. 2006; Ilk et al. 2006a b; Kuchuk et al. 2005). With the implementation of permanent pres

ns might be inaccurate if the values of fracture properties in the model are not reliable. This paper shows using image log data associated w his paper discusses the use of integrated reservoir information obtained from Downhole Fluid Analyzers (DFA) borehole images and nume different ways. One is based on numerical simulator and another based on cumulative permeability-thickness product for the gas bearing z ave a tendency to behave erratically at very high frequency leading to fast and significant variations of the well productivity that could not b emperature. The presence of hydrates despite the extremely low water content of the effluent is detected by the multiphase flowmeter whic

was made of two types of multiphase flow meters and two separators to determine the most appropriate well test device for X Field in the S etion design. There is good agreement between the slug frequencies obtained with nodal simulations and the actual dynamic measuremen meter error) in the measured total liquid flow rate at line conditions was better than ï¿½ 2 m3/h (< ï¿½ 300 B/D: 95% confidence interval). y for the low potential unsteady wells. In terms of oil production rate the difference between the phase testers and test separators was ma

gn of tests done in South America. First of all we will show how the entire information of a gamma ray spectrum permits a quality control in r Introduction The link between reservoir simulation and well testing has been growing steadily for several years. Raghavan et al1 . have re is. We have utilized two different formulations â€” Î²[qBDdiB(tBDdB)] is used for "rate decline" analysis (based on q/Dp functions) and Î²[pB nique. Introduction The pressure derivative as described by Bourdet et al. has become the primary tool for diagnosing well and reservoir b and the water is positively charged. When the water moves under a pressure gradient an electrical current is generated. This electric curren

dual risk of CO2 leaks. This paper will show that the adoption of a number of them on Otway (e.g. excess volumes and CO2-resistant ceme the atmosphere significantly. CCS is the process whereby CO2 emitted by massive stationary point sources such as fossil fuel-fired power gement strategies or emergency plans. To that purpose mitigation actions such as characterization/inspection remediation (workover) des so taken into account in order to asses the viability of the CO2 optimal injection and storage strategy while minimizing cost. Finally integrat s and geological environments the need for CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface carried out on reservoir rock and caprock included measurements of helium porosity nitrogen permeability and brine permeability. Carbon d the Framework Program Six and the Australian CO2CRC Otway Project. These projects address pertinent issues in CO2 capture and stor operties along a planned-well trajectory allow designing a drilling operation that will maximize subsequent hydraulic isolation of the well by o

ith this shape of the field ERD wells drilled both to the North and to the South will increase drainage area and thereby the total recovery fro are intuitive to interpretation allowing better geosteering decisions without compromising ROP and drilling efficiency. Within six months six

n on oil productive reservoirs. This is particularly true within the US where the transportation costs associated with delivering the product to t ording to the geology of this region and the geochemical signatures observed the CO2 of Quebrache field has an inorganic origin. This pap ion and model adjustment enables the operator in South Texas to make timely completion decisions as well as set-pipe decisions. This pr w dew point pressure (2) loss of condensate trapped throughout the reservoir at the end of exploitation.ï¿½The loss of productivity in gas-c on presents a highly improved configuration for the SAGD well-pair array that resulted in trebling the oil recovery attained by the initial well a placement assembly for treatment under Sub-hydrostatic conditions. Introduction The giant fractured carbonate field was discovered in 196

alline rocks characterized by petrography heterogeneity because they were formed in different tectonic activities in their geological evolution ome an established alternative for the oilfield operators proving to be capable of effective zonal isolation on a broad range of applications (m . A sidetrack option was considered as a means of bringing these wells back on production but was not used because of the absence of a etc. to plug the water producing features. 2. Using bridge plugs cement plugs and other mechanical devices to stop water production. ï¿½ w solution reduced the water cut to 25% resulting in a gain in oil production of 300 BOPD. This innovative solution was established as a stan s oil rate due to increasing water production. Basic horizontal well completion in South Ghawar was 4 ï¿½ - 3 ï¿½ tubing of an existing verti veyed fiber optic system. The availability of CCL temperature and differential pressure readings enabled precise depth control proper pack (as per DeepStar). Plugging due to organic or inorganic materials degrades producibility of wells. Some of the flow hindrances are categoriz e SMD profile of droplets across the pipe cross section was developed for flow pattern of dispersed oil in water (o/w) and water. Log-norma ommon occurrence in petroleum production especially for old oil field and for enhanced oil recovery (EOR) with water injection (cold or hot) monitoring devices to record the production behavior in the completion in the wellbore and at the wellhead and allow conclusions on the major bottle necks and made recommendations of several low cost optimization alternatives to overcome them. The projectâ€™s results o considerations in a deepwater Gulf of Mexico development project. This study is based on experimental measurements of asphaltene and w e waxy crude oil properties. Below a certain temperature called the wax appearance temperature (WAT) the wax crystallizes out of the liqu n algorithms have been developed for CO2 quantification and verified in the laboratory. Several log examples are given demonstrating succ samples from previous exploration wells within the same regions had shown significant variation in CO2 content new and improved sampl

pressures below dewpoint pressure. A value of dewpoint pressure is essential data for any reservoir study. A reasonably accurate estimat from PVT analysis of five volatile oil fluid samples. The samples were selected to cover a wide range of fluid composition condensate yield ashing and leaky seals. Most of these mechanisms cause fluid disequilibrium in the reservoir and thus become very difficult to model. In ad nd helped the operator to find and produce oil in a complex setup. Introduction In developed and ageing fields it is essential to understand t migration. We stress the need for an integrated and a multidisciplinary approach to fluid characterization to increase data acquisition effici raining database with new data. In this paper we present the application of ANN technology to DFA. We demonstrate this with an ANN mod he framework of an equation-of-state (EOS) compositional fluid-flow simulator. Our numerical framework simultaneously honors the physics on wells provide a narrow window of opportunity for collecting hydrocarbon samples to make development decisions; therefore obtaining hi

s a means of reservoir monitoring. Introduction Recent advances in wireline formation testers enabled the determination of several fluid pr y to encompass a wider spectrum of functionalities. In this paper we will review the choice of materials the verification test procedures an

Segregation of asphaltenes causes compositional grading in oil (20â€“30ï¿½API) columns. In contrast compositional grading in light-hydro such as gas/oil ratio (GOR) saturation pressure API Saturation/Aromatics ratio gas mole fraction etc. vary with elevation. The magnitude Analyzer (DFA) in the Wireline Formation Tester (WFT) tool to conclusively identify reservoir fluid types and their properties in-situ and in rea entified the heterogeneity of hydrocarbon fluid in the interval. This paper also briefly covers the measurement principle of the analyzer and We describe how to improve on these interpretations by performing more advanced formation testing procedures; some of which are based different regression schemes that can be imposed on pressure data to calculate fluid gradients with their associated uncertainties and concl eal time when the sample is taken and without requiring phase separation. Downhole GOR has many advantages over the conventional G

ocess different reservoirs need to be well delineated through appropriate statistical similarity tests of pressure gradients and fluid analysis optical absorption spectra of downhole fluids. These spectra are used for fluid identification (oil water and gas phase) and to quantify the l base with new data. In this paper we present the application of ANN technology to DFA. We demonstrate this with an ANN model that uses

t for calculating thermal fluid VLE.ï¿½ A thermodynamically rigorous method presented by Brantferger Pope et al.2 discusses a Newton-typ cated that the inversion point for the STO emulsions was approximately 60% water cut (volume) and the average droplet size was increasin

properties in-situ. Reduced cleanup time allows for efficient reservoir fluid profiling whereby multiple zones can be scanned sequentially in r well hydrostatic pressure addressed well control concerns. In the Wireline toolstring that was used for the operation 450 c.c. sample bottle T study to be performed using the improved recombination ratio at line conditions from the multiphase flow meter. This dedicated multiphase portunity for sample recombination involving improved phase ratio surface samples and full functional capacities of portable laboratory. No controls the reaction rate of chelating agent with calcite at low pH values. Ligand attack limits the rate at high pH while water attack can dom hree injector wells were treated with this technology and now two years later stable injection rates at optimum surface pressures are still m ent which is likely due to the precipitation of calcium carbonate solids. This method for damage generation has ramifications in the screenin w chemical as compared with conventional treatment levels. The lower treatment level provides the potential to reduce cost treatment inter

anism and magnitude of naphthenate-soap-induced formation damage and help in taking proper measures to avoid the formation damage ed-charge penetration. The crushed zone permeability impairment is characterized using thin section analysis and the strength damaged zo sults from incomplete removal of the damaged zone and for the first time we are able to determine how the skin depends on the degree an d increase in productivity and similar initial fluid production rates. The scale-inhibited wells did though provide sustained rates over a 3-mon mation pores/proppant pack and perforations to the reduction of pipe diameters. Typical scale deposits found in the Uinta basin are shown r minimising water production and optimising hydrocarbon recovery.[1-6] However they also have the potential to address other produced utters on slickline. Scale samples are collected and sent to the lab for analysis and scale type identification. The category of strings with a s s to cause precipitation of calcium sulphate this process resulting in the observed sulphate stripping. This analysis is supported by the fie o large (which increases interactions between regions) nor too small (implying ineffective history matching). The proposed technique has b racture/matrix cells carrying the flow fracture cells to be connected and/or disconnected with other fracture cells and where fracture/matrix c ts into reservoir management workflows. Where this technology fits into reservoir management workflows. What are the general benefits d t the ranges of critical flowrates and their sensitivity to some key parameters like realistic permeability ranges of the Cantarel Field and the s at the field scale. Milestones achieved with this implementation included the automatic identification of problematic wells and a reconciliati enance was commenced after few years of the discovery of field A a giant complex carbonate reservoir in the middle-east. Although this str e prior to engaging in this effort. Now individual waterflood pattern balance is significantly improved and the field-wide VRR is ~1. Sound re lower surface maintenance cost lower load and horsepower requirements and lower frictional losses. The application of bottom-drive PC use of downhole heaters in thick sands stimulating both vertical and horizontal wells in the reservoir. The second one evaluates the tempora monitoring (Honarpour et al 1996).ï¿½ Microwaves are also used for monitoring phase behavior and measuring multiphase flow (Rogers et voir region. Thus the impact of steam is not that of a simple well stimulation but also achieves an effective sweep in the vicinity of the prod rements like intervention for isolating the high water cut intervals in the horizontal section and better productivity and avoiding life cycle risk d in the Divided Zone (DZ) Saudi Arabia and Kuwait (Fig. 1). Currently a large scale Steamflood pilot (LSP) consisting of sixteen 2.5 acre real-time formation fluid identification PVT samples permeability and flow rate estimations can all be evaluated in detail. Within the vast R

nes led to successful well placement enhanced production with sand and water management in heavy oil environment. Introduction Fula O

ent techniques improved oil production and lowered WCs. Water cut before acid treatment ranged from 90% to 98%. After the treatment w

ment to review the performance of the field and get access to the oil water and gas flow rates. In these challenging conditions and after tryi

osilicates such as feldspars and zeolites as well as carbonates (calcite dolomite ankerite) and iron-based minerals (hematite and pyrite). e first time in Russia during this job. These were the combination of inflatable straddled dual packer wireline formation tester with nuclear m

nsates (properties ranging from 27 API/1 000 scf/stb GOR to 57 API/27 000 scf/stb GOR). ï¿½Diagnostic plots based on bulk fluid propertie

4 (Ti Zr) metal with different organic ligands with different binding strengths have been employed to achieve crosslinking at two temperature l proppant fracturing operations. This paper will demonstrate the applicability of the novel solid-based acid fracturing treatment. Additionally

g Frac operations monitoring Monitor water Monitor flowing pressure above dew pressure (Ppwf>Pd) Minimize intervention Minimizing of are limited due to limitation of equipment on the fracturing vessel. Zones targeted are both the Oligocene (sandstone) and the naturally fra moval during the treatment with the highest regained permeability. Geochemical simulations also show that more skin reduction is obtaine formation is to remove near-wellbore damage and to produce â€œwormholes to increase the permeability of the critical matrix. However b nd consequently work over rig cost savings. Overall the use of polymer-free fluids improved well productivity. Design laboratory studies tem r imbibition into tight zones.[6] The excess water is trapped in the formation due to high capillary pressure in the porous rock and viscous f use the flashed gas and water analysis data as inputs. The setup can also measure the sensitivity of pH to pressure and temperature. Comp

astern Texas panhandle as well as Ellis County in Western Oklahoma covering an area of about 650 square miles with estimated total rese

ecisions. Also the special nature and cost of mobilization and limited equipment introduce a need for more stringent early collection of data there is evidence that degradable fiber plugs could be a cost saving option between stages. This paper outlines in more detail the observati metry by evaluating the measured and matching of modeled fracture parameters the importance of fracture orientation for reservoir develop duced fracture network including fracture spacing and associated confining stress contrast. The results indicate a vertically contained develo w well came on production with a significantly low water-gas-ratio (WGR) from a first-year average of 483 bbl/MMscf for the offset wells to 1

sed multidisciplinary and integrated approach to design and execute the treatments involving reservoir production optimization and fractur enting the horizontal wells concept at the same time confronted with the challenge that involves drilling completion and stimulation measur y assisted by bottomwater drive and an edgewater drive from the eastern side of the reservoir. A structure map of SUG is shown in Fig. 2. F ion techniques to maximize field production goals. It can be confidently used to reduce field development risk and maximize profits. Introdu back information necessary to validate the models and improve predictability thus improving the quality of decisions made subsequently.ï¿½ ed to determine the ultimate fracture properties that were used in the final simulation model. First local grid refinement was used to represe igh-resolution analysis.ï¿½ï¿½ The results indicated that actual field production increased and paid out the increased fracture stimulation co

d or poorly imaged on seismic can be interpreted on images with definition of vertical displacement through the integration of well correlatio echnology the Extra Large Diameter module (XLD) was also recommended to replace the dual-packer at a broad permeability range. The ery packages along with analyses of both pressure and production transient data we now have the means to both understand the long-term onment are included. Introduction Wamsutter Field refers to a large continuous tight formation gas (TFG) accumulation in the Washakie an

hile there is usually confidence in the mobility data from high permeability reservoirs the numbers generated from low permeability reservoirs Report 1996). Throughout a period of 20 years 71 exploration wells were drilled on the basis of 2D-seismic and log correlation of lenticula mpletion considerations in order to succeed. There is simply no recipe for repeat success. A detailed method is presented to identify unde e region by limited number of high flowrate wells with the natural recovery drive. Introduction Yurubcheno-Takhomskaya oil and gas accum

ating between WBM filtrate and formation water. The downhole fluid analyzers LFA* and CFA* successfully helped determine the level of the

ift selection. Lessons learnt and results of the well placement along with cost/production analysis will be presented. Production results to da

nts an independent review and comparison of each method while highlighting how each method can be applied for evaluating different type dgment elicitation process should be properly designed for the particular problem. There are two types of biases: cognitive and motivationa

ssible to derive primary drainage capillary pressure curves from borehole NMR data in carbonate reservoirs Caution should be exercised in he investigated formation heterogeneity is comparable to grid sizes used in current reservoir simulations. Models were developed to identify ion). Statistical methods such as neural network are used to classify the logs responses (i.e. log typing) into a number of electrofacies. If go evelopment in channels and delta distributaries. The upper cretaceous formations are more of shallow marine setting with sand developmen ectedness and low net-to-gross ratios. This integrated approach using high resolution image logs and full-bore core photos provided a much all basis. Field-based fluid characterization is now possible. In addition a new measurement is introduced--in-situ density of reservoir fluid. duction and helped the operator to find and produce oil in a complex setup. Introduction In developed and aging fields it is essential to und o link log data to the hydraulic properties of carbonate reservoirs the oil industry is seeking better methods for characterizing the carbonates he OWC depth in the reservoir showed variations across the field suggesting the presence of a fault network which also controlled the hydr r size with a total length of 26 ft (Fig. 1). The tool is rated to operate at up to 20 000 psi and 300ï¿½F. Other collar sizes are also under dev ause of the location of the well it has not been possible to use radioactive logging sources for formation evaluation. As a result fully evalua

aturation error analysis charts were developed for each model based on the above mentioned database and validated mathematically. The ity charts were developed for each model based on the above mentioned database and validated mathematically. These charts can be ea ermeability usually being the controlling factor. Decades of experience with routine and special core analysis surveillance logging and produ ion pressure and reservoir fluid mobility. Introduction The structural style of the fields in this area is complex. Precise information on the str hin section analysis continuous vuggy porosity analysis from the core slab minpermeametry and other advanced research methods are inc ed deepwater reservoir.ï¿½ The field example used in this paper is a turbidite sand from North West Borneo.ï¿½ The techniques demonstr

ndependently using both datasets ensures more plausible results in thin beds than either stand-alone technique could provide. Field examp and the casing. In this paper all these issues are summarized. The BCA logs are integrated with results of the LWD modeling and producti ture and fault characterization from a combination of borehole images with production and pressure transient data to provide an explanation ntribution we describe an innovative solution to unconsolidated sanding problems during sampling and advanced fluid profiling and its prac to many of the observed fractures and consideration of borehole cooling provided a good match between predicted induced fractures and t oduction During Cretaceous times the eastern part of the Arabian plate was covered by extensive carbonate platforms which are the reser

patial association of the reef complex. Careful examination of frequency statistics helped to detect the estimation biases in the initial geostat lidation of the wellsite petrophysical analysis and the borehole image within two hours of recording the logs and design of the wireline testin omponents. Porosity in the sand component can then be estimated separately and with it the hydrocarbon pore volume. Conventional high

asurements along with stationary surveys to correct these errors. We provide comparisons of LWD images before and after the depth and

e reorientation have been analyzed in detail. Implications for waterflood sweep efficiency are discussed. Introduction In-situ stresses in res rock layers vary in their properties with depth a realistic estimation of static elastic values of the rock is still a challenge.ï¿½ The problem is zontal stresses. Even though the overburden stress is expected to increase with depth both the maximum (SH max) and minimum (Sh min ressure transient performance of a well under Darcy flow conditions has conventionally been accomplished using the convolution of the var ressure transient performance of a well under Darcy flow conditions has conventionally been accomplished using the convolution of the var ressure transient performance of a well under Darcy flow conditions has conventionally been accomplished using the convolution of the var lectors in the converted-component image revealed fracture swarms that could be traced away from the wellbore. This technique of proces e bottom around 1.77 fractures/ft. These fractures were proved to be of good fluid conduit based on both Stoneley waves and the petrophy ondence between the model forecast and the actual result. The well contains interval of numerous fractures and large vugs. Eventually the vity and density.ï¿½ The fractures observed on the images have been classified into continuous and discontinuous open continuous and d ult. The well contains interval of numerous fractures and large vugs. Eventually the well showed a good production results and currently is

he industry and the first field experiment for direct in situ determination of two-phase flow properties. The key outcome of this field experime n the early stages of exploration. Identifying any variations in reservoir fluid properties such as fluid composition gas-oil ratio (GOR) pH de selecting the best perforation strategy. Introduction In the tight and laminated sands of East Kalimantan Indonesia obtaining pressures w

on (T2 mode) primarily caused by gas are not significant in these reservoirs since an underestimate of the porosity was not noticed with r ovide fluid information in places where WFT did not sample. Here we show through several examples how continuous NMR fluid scan logs ping and present examples of successful sampling with wireline tester in these elusive reservoirs. The various examples presented in this p asures can be taken to identify and minimize these errors. Introduction The main challenge in obtaining quality down hole NMR data is the anies (e.g. Baker Hughes Halliburton and Schlumberger) offer NMR logging services. Historical Perspective The potential value of NM ssures data log analysis and supplementary information helps improve predictions of oil bearing zones in the Estancia Cholita Field. Introd s are drilled only for formation evaluation purposes or for special situations such as infill drilling. Horizontal wells bring new opportunities as

s in heterogeneous reservoirs and (2) its coupling with gradient-based optimization techniques for determination of unknown reservoir para ivity images based on laterolog principle were useful in real time to identify the different layers within the Mishrif reservoir and establish the

sts were traditionally the only available methods for detecting compartmentalization and flow boundaries. However in deepwater or similar s ctivity of the producing units throughout the field is a major uncertainty and risk factor that behooves conventional as well as novel analytic ure transient performance of a well under Darcy flow conditions has conventionally been accomplished using the convolution of the varying a program of production and injection testing to monitor oil saturation changes in a new well aquifer swept zone. The planning and first res scribes the development path and results from the new techniques: i) extra-large diameter probe ii) elliptical probe iii) the openhole driller

n-situ stress magnitude and direction and their vertical and lateral variations might be needed for various reasons in a reservoir.ï¿½ï¿½ Hyd sting took the form of Drill Stem Testing (DST) or conventional well testing where the well is put under test for a relatively long duration. Whil reservoir were determined. After imposing the drilling constraints all reservoirs were then coupled to account for surface facility constraints. bearing sand intervals and assisted critical interpretation of the sand continuity particularly the semi-continuous distribution of fluid composit The Bokor field is located offshore Sarawak Malaysia and is operated by Petronas Carigali Sdn Bhd (PCSB) with gas lift as a primary syst consisted of investigating the technical feasibility for miscible gas flooding into an equally tight reservoir together with the facilities to collect ential pressure across the orifice equal to 10% or more of the upstream pressure. Benefits include constant injection rate with constant inje r 110 000ft of challenging reservoir to Saudi Aramco. This has also been an enabler for multi-segment collaborations and is now seen as a p can be concluded from the results that the DDR technology is an effective way to efficiently drill and place water injector wells. It has the po as been a success with an average initial uplift of 102 MCFD per well for 52 successful Judkins wells tested. 3) Although the gas product ons usually make every wellbore capable of producing from only a limited completion interval. Hence the main objective should be to optim o extend the life of field. A solution is proposed to enhance the ageing infrastructure and modifying the current reservoir management practi the stand alone reservoir model leads to an optimistic production profile.ï¿½ These results show the advantage in the use of an IAM taking eservoir simulator provides embedded management tools for its subordinate wells. In the case of multiple reservoirs and surface facility net ion occurs in various Reservoir Management cycles depending on the timescale involved in the decision-making process (Fig. 1). Figure 1 he reservoir management plan required a field-wide optimization of the scheduled activities in order to identify bottlenecks in the gas handlin have achieved some 13% increase in the total oil production; savings 14 MMUS$ by reducing the number of infill wells planned and creati

w from the reservoir and surface constraints) can be considered simultaneously. The integrated asset model (IAM) comprises of a coupled ng sub-sea infrastructure. Option 2 is to install a complete new flow line from the sub-sea template of the new reservoir and run this directl major bottle necks and made recommendations of several low cost optimization alternatives to overcome them. The projectâ€™s results o here the continuous dataflow cannot be guaranteed the progress of the study is severely affected.ï¿½ This is particularly true for tasks that th local probe holdup sensors have successfully diagnosed well production and provided guidance for workover operations to reduce water

gain by the use of advanced optimization techniques (e.g.GA) to sustain field quota. Optimally distributing limited gas lift availability to Kha s from 10 fields. New efforts were put in the exploration activity with the drilling of exploration and appraisal wells in the period of 2002-5 re o 7 m thickness. These heteroliths are believed to provide pressure barriers to the various flow units observed in the Barik formation. The ogies aimed at minimizing the uncertainty and improving accuracy in the results. The paper also highlights some common pitfalls and mistak before getting a quote. In conditions of high demand (and premium price) for rigs and other scarce equipment it may be more advantageous

s reservoirs become more challenging to develop the use of advanced technology often helps minimize risk. When fields are developed wi will result in more effective and uniform drainage of the Brenda reservoir sands while minimizing the chance of premature water influx. Intr eria are applied; also both follow the â€˜floor to ceillingâ€™ well placement strategy in the reservoir which field experience suggests is advis and gave the operator confidence to sidetrack the well directly to the west to a slightly downstructure position whereby a successful com sly increasing while the number of newly explored fields is declining regardless of the effort taken and technology invested into exploration d from 20 to 4 realizing 75% of the total infill potential. This paper describes the workflow for optimization of horizontal well performance d osed as a discrete optimization problem (Yeten 2003) (i.e. involving integers as decision variables). Solving such problems is an arduous ta

ssive gains (factors>300) in CPU times for fracture problems in particular. Introduction Reservoir simulation is an essential tool for the m mulators are based on numerical methods such as the finite difference or finite element method. The advantage of such an approach is tha ecomposition. Prior information is incorporated using an approximation of the square root of the inverse of the prior covariance calculated u tion. Fourth we use an iterative sparse matrix solver LSQR for solving the Adjoint system of equations which shows high stability for field-s

features. Also this approach can depict patterns of geological continuity consisting of strongly connected curvi-linear geological objects suc

y papers have been published for models with structured grids (Coats 1980; Chien 1989; Mifflin 1991; Watts 1996).ï¿½ In recent years sev eads. We conclude with the validation of our approach and performance comparisons and analysis (all against standard implementations) f . It also exposed allocation problems in the historical production data. This information was used to validate the performance of some wells

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ The simulation of these issues requires special techniques such as the us

es controlled the trend of a curve in the past will continue to govern its trend in the future in a uniform manner and proceed to detailed expla have the ability to be broken easily after the injection to maintain high conductivity in the fracture during the production phase. To accompli gel and the reservoir fluids after the cleanup. The new non-Newtonian fluid flow implementation allows for more detailed investigations of is a carbonate formation in the Jurassic horizon in Saudi Arabia. It has been on development since 1945. Two predominant layers exist in t ent agreement with commercial dynamic simulators was achieved for gas condensate flows simulation. Significant decrease in computation shaped fracture was considered likely to be generated based on the observed field measurements and there is a good match in fracture he mmunication between the reservoir layers and by connecting all the layers to the wellbore. This can practically be modelled using explicit f conductivity. Field examples illustrating the impact of non-Darcy flow have been extensively documented in the literature.1 7-10 nd the analytical flow model. Second we illustrate the technique using a well in a Rocky Mountain tight gas reservoir. Third we validate the ed flow conditions.ï¿½ One of the first investigations that specifically pertains to this subject is one reported by Valko and Economides1.ï¿½ eep slopes either positive - PKN - or negative - KGD and Radial). An actual well documented treatment in the North Sea validates the pro of fracture propagation.ï¿½ We also modeled fracture propagation for different perforation phasing angles.ï¿½ Based on the results of num g the best methods there is no â€œbest universal method for all the cases and testing different methods for each case is required. Noneth

and populated in the reservoir to honor the seismic and the production data. Second we used low vertical permeability to simulate the vertic d horizontal wells enable disposal of large volumes of fluid. Therefore disposal objectives can be met with a fewer number of wells. This is i ery low recovery factor. Any attempt to increase the recovery from these fields requires an understanding of the behavior of the wells and re Oligocene eras. The field is situated at the crest of a rollover anticline and is characterized by a series of northeast-southwest trending faul gnificant parameters that influence material balance calculations. Interestingly the most important parameter was the selected material bala development history and accounting for the full-field 3D model outcomes we suggested to the operating company the following ways of ma eat flux. Thermal conductivity is not necessarily uniform because it depends on the mineralogical composition of the rock the porosity and he reservoir engineer conducts several equally probable simulations to capture the range of uncertainties. Left unchecked the number of sim

nal with an isotropic permeability tensor. In this paper we discuss multipoint flux approximation (MPFA) methods. These are designed to gi t of gas condensate fields in the world are being developed today. By now the only paper14 regarding this particular problem has been pub f oil recovery from the fractures matrix rock and vugs.ï¿½ These results are then matched with dual porosity compositional simulations wh o obtain a history match on a reservoir model we jointly perturb the large-scale fracture trend and local-scale geostatistical fluctuations of fr

al model for three-phase compressible dual porosity model for a streamline simulator and compares the results and run times of the stream ng more numerical diffusion. The numerical method can be further accelerated with the use of adaptive mesh refinement along streamlines y range in size from 10 to 100 million grid cells and are growing. This has resulted in a steadily increasing gap between flow simulation capa

lications (Liu and Oliver 2003). Oliver et al. (1996) and Kitanidis (1986) independently proposed the randomized maximum likelihood (RML)

- so making the scaling calculations much more accurate. The objective of this paper is to study the application of a streamline simulator t

ast and accurate numerical simulation of large geological models. The requirement is to to simulate multimillion cell geological models on a ach have the limitation on the time step due to CFL condition in their explicit part. In the case of complex heterogeneous structures of reserv veral groups and assign a probability of occurrence for each of the groups. A Monte Carlo routine is then applied to forecast the performanc

spective domains. Introduction In order to build a model of the reservoir data from different sources such as conceptual geological mod ow or outflow in different zones along the wellbore or in the individual branches of multibranch wells. To optimize the design and operation o

omponent molar rates of a producing well from a black oil reservoir simulation to be accurately reconstituted. Full computational advantages and is shown to correctly account for most situations including 'non-Archie' rocks such as low resistivity pay in carbonates strongly oil-wet r

was a discussion by Batenburg and Milton-Tayler1 and the reply by Barree and Conway2 regarding paper SPE 893253 on whether the beta procedures some of which are based upon new technology.ï¿½ Introduction Large economically viable reserves of oil are widely thoug results for this field case. Recovery and potential reserve gains will also be discussed. Specific production targets and metrics that were se he dominant in situ stress orientation trend identified in this study therefore is mainly controlled by this younger stress field of the GoS rifti ated as an asset managed effectively with staff assigned to ensure the integrity of the data management systems. The key processes are 1970-2007 derived by averaging the values of oil recovery factors from a significant number of matured fields. The data fields from differen €™s led to sharp oil price shocks . Alaskaâ€™s oil production has been the state governmentâ€™s single biggest source of revenue for m al wells. Finally the methods have been used to demonstrate the mechanical durability of flexible cement systems aged at high temperature

nd limited rig availability the simple nature of the processing and interpretation of the through-casing formation resistivity log enables fast de ve inflow control and the understanding of flow contributions in multilateral wells. This solution for flow control and measurement can be app ort string section of the dual completions. Flow profiles and water entries were confidently obtained in many wells with the new interpretatio nd execute these production logging programs and the integration of the interpretations into the pressure-transient analysis for the complex

ed probe. We discuss the decision process that governed the choice of pump displacement unit probe and packer. We pay particular atten ed probe. We discuss the decision process that governed the choice of pump displacement unit probe and packer. We pay particular atten eld is a carbonate anticline that has been under peripheral water injection since the start up of production. The reservoir is fairly heterogene ibrium model that uses laboratory analysis of collected water samples as input. pH is a key parameter in water chemistry and is critical for c diagnosed and remedied. New components provide tremendous amounts of downhole information which can be measured continuously in he velocity of the fracture system propagation along both the horizontal and the vertical directions. On average the fracture system propaga e log data. The major assumption is of a vertical fracture propagating from the wellbore. Nevertheless in a tectonically stressed environme

facilitate understanding of the temperature response over time. The analysis demonstrates that it is possible to determine the flow profile fr nd 2.ï¿½ The multiphase flow and pressure traverse models utilized in those studies generally assume steady flow conditions in the wellbo multiphase flow and pressure traverse models utilized in those studies generally assume steady flow conditions in the wellbore and in gener e that slickline fiber optic distributed temperature sensor measurements are a viable method for performing reservoir surveillance in multi-zo horizontal well production log costs. This case study recounts the design installation analysis results and subsequent learnings of the proj roduction-logging tools are routinely used to update reservoir models and diagnose problems. In some cases problems are discovered whe

Our objective is to provide recommendations on how a PPS should be implemented to improve well productivity as well as standardize pro lt-water channeling and reservoir behavior. Introduction For over a decade operators have developed thin hydrocarbon accumulations with s also initially affected some pressure buildup tests and were later circumvented by the use of a downhole shut-in tool (DHST) to limit the p ction as a result of this expansion thus limiting liquid production. The combination of gas rates with oil and water production has also create r estimate their producing formations but they do not actually recognize that they have this problem. Specially if the development plan inclu but a few examples of such circumstances that would require real-time decision making and procedural modifications. Real-time decisions onitoring. The theoretical models are supported by real well examples where the calculation of different layer pressures caused by depletio puted stress changes and failure zones could be used to calibrate a geomechanically linked reservoir simulator. Introduction Steam inject d where reservoirs with different pressures are commingled through gravel-packed sand-screens. Thermal models of the near-well environm m the operator because of the multiple vendors involved in the project. They supervised multiple qualification and system integration tests pe ventional logs. In addition methodologies of estimating fracture permeability and porosity-related permeability based on logs are also propo

). The objective of this paper is to provide recommendations on how the PPM process should be properly implemented as an automated w s address the viability of a possible lower cost alternative for water entry quantification in near-horizontal wells that potentially have a highe

level immediately detects the depleted zones and the degree of depletion across perforated intervals indicates the interval contributes mos rbonate reservoir is presented here. Introduction In peripheral water injection wells it is difficult to know the preferential pass of the injected its. Early imaging of the injected water from the injection well into the reservoir is paramount in assessing the success of the pilot and future onitor the under-swept lower units of one of the main reservoirs in this field which are not being swept with the peripheral flood. Although p ill also be discussed. Tests were conducted under dry and saturated conditions. The preliminary experiments reported here indicate that sh rization. In this paper we show how compressional and shear slowness variation and Stoneley waveform transmission coefficient analysis nventional clastic completions are inadvertently hydraulically connected to adjacent coal seams that are or will be contributing significant a emented laterals horizontal-stress anisotropy perforation strategy cementing strategy and stimulation design. The paper offers statistics o ½ Maximizing fracture surface area and volume of impacted reservoir requires the existence of textural heterogeneity at a reservoir scale (e pressured coal. The coal therefore does not require dewatering before production. The coal consists of multiple thin seams ranging from 10 strategies as well as future infill well placement. ï¿½ This paper describes how formation images have been used to implement changes e image and log interpretations core analysis HFT and microseimic data to construct reservoir models and discrete fracture networks that it does improve the expected value of these projects. This paper describes the process operational control and financial analysis used to at worldwide coalbed-gas resources are estimated to exceed 9 000 Tscf and shale-gas resources are estimated to exceed 16 000 Tscf it is tion and when enhanced with microseismic monitoring real-time optimization of the fracturing treatment. Refracture stimulation case stud athematical model a sensitivity analysis is conducted to determine the preferred dissolution patterns for different formation permeability and zation of tandem seals and new wellhead penetrators are also expected to further enhance the ESP run life. New applications to minimize E

ations as well. The paper describes the individual components of the system and the calculations involved therein. The economic and tech mes to produce reserves from oil-water zones and marginal zones that are nor economic when drilled out by vertical wells. Horizontal well dr on the seismic interpretation The reservoir is constituted by the tabular fluvial sands of the Sergi Formation caped by the shales of Itaï¿½p racture initiation pressure to be similar to that encountered in openhole or even lower. Fracture initiation pressures were closely monitored nity to determine whether the near wellbore experienced any alteration. The sonic data was processed to extract a very reliable compressio uids in conjunction with the gas. Introduction A production tubing string setting depth optimization analysis has been developed to evaluate uids in conjunction with the gas. Introduction A production tubing string setting depth optimization analysis has been developed to evaluate ns discussed in this paper include effective utilization of LWD data to make real-time geo-steering decisions in a thin target process for rea

ent-2 and 3 in April 2003 and January 2006 respectively. Increment-1 was initially developed using mainly vertical wells while Increment-2 vershooting. For communicating layered systems a front movement equation is derived using perturbation techniques. This technique prov y Increment-2 and -3 in April 2003 and January 2006 respectively. Increment-1 was developed initially by use of mainly vertical wells while

lls are more efficient compared to the horizontal wells where the optimum horizontal length is exceeded. Details of the optimum horizontal eservoir pressure are uncertain a drillstem test (DST) may be performed after perforating the well. With the implementation of high-accura What has been missing however is agreement as to what constitutes the most appropriate methodology for analyzing the wealth of perform alth safety and environmental (HSE) risk caused by conventional acid exposure to both personnel and production equipment. Placement of eservoir mechanism impeding maximum well deliverability was initially considered to be dominated by reservoir damage from brine imbibiti

ng out due to sand production and associated wellbore fill clean out lower polymer requirements reducing gel costs and a reduction in prem oirs (1-20 md) and relatively cool formations (76â€“95ï¿½C) where fracturing treatments are regularly designed for tip-screenout treatment ncrease achieved in the pad by the addition of fibers and its bridging mechanism plugged off the just stimulated zones effectively thus dive e and provide optimum connection for hydrocarbons flow to the wellbore by evenly distributing proppant throughout the height of the fractur n in the rock. In all cases the flowback aids reduced capillary pressure to similar levels 70% lower than water alone. One of the water-wettin ht is recognized as one of the critical factors that can determine the success or failure of a hydraulic fracturing treatment many studies have ved post-fracture production response. This paper focuses on a description of the fluid chemistry and performance along with numerous fra et al. 2004). Other reports suggest that for every barrel of oil produced in the United States 10 barrels (bbl) of produced water is generated n Colorado and is an elongated structural depression trending northwest â€“ southeast (Fig. 1). The Basin is characterized by a series of hi vals where early wellbore screen-out may occur due to proppant bridging of the annular volume between the screen and the casing. Conve hen compared to the conventional fractures placed in the past resulted in the decrease the post-frac water cut from 75 to 46% while at alm ivity. Viscoelastic surfactant self-diverting Acid (VES diverting acid) was used as the chemical diverter to assure good zonal coverage acros oduced water cut. Treatments presented include both cases in which fluids are bull-headed and placed through coiled tubing. The case his n one continuous operation thus minimizing the associated risks and optimizing the efficiencies of both the personnel and equipment neede

e performance of non-stimulated offset wells. It is well-known in the industry that fracture stimulating horizontal open-hole completions with

ssure) Using this process 10 wells were successfully hydraulically fractured. Unfortunately wells produced lower than expected; unforesee a number of other investigators2-5 have developed interpretation models and analyses that employ the dimensionless productivity index a

reservoirs that constitute some 50% of the oil bearing rock in the area have seen the first acid fracturing treatments performed including th

n to measure the fracture initiation pressure and test the functionality of the valves. Introduction In multiple-layer reservoirs requiring stimu d a sliding sleeve valve cemented in place. Water was used to fracture these blocks and the fracture initiation pressures were measured. G n a granular medium is an improvement over existing models because traditional brittle fracture models do not take into account the specific an aqueous solution.ï¿½Hydrophobic tails of surfactants associate and orient to create rod shaped structures commonly referred to as mic

he Delaware Basin with the most prolific hydrocarbon bearing region lying largely in the Southeastern part of Chaves County Western part

with a fracture half length of 105 ft high conductivity of 19 600 md-ft and an equivalent skin value of -5. The success accelerated the applic tion A Joint Industry Project (JIP) active since 2002 was created with the goal of studying fracture clean-up and using the mechanisms unc on efficiency.ï¿½ The second well was hydraulically fracture stimulated with a single stage treatment.ï¿½ The completion design changes in

he treatment borehole is too expensive. Often although the observation or the treatment well are not strictly vertical they are assumed to be

tions are presented along with recommendations for fluid systems that create the smallest-scale differential etching. Introduction Acid fract pact that they could have on the field development Rosneft decided to invest inï¿½ a field research study denominated Fracture Geometry hen stimulated by the neutron source the logging process can be completed free of any of the timing constraints associated with the half-life

stimulation engineer recent production results showed that hydraulic propped fracturing can bring many wells to economical production. rical and analytic simulators. We will show that using a constant proppant permeability value results in an estimate of optimal fracture leng net pressure) is primarily dissipated in viscous flow within the fracture leak-off flow across the filter cake and seepage flow induced by lea ation in the design and the execution of both the viscoelastic and in-situ gelled acid treatments. Among the 5 wells treated with surfactant-ba oads and use of proppant with better resistance to stress (conductivity and permeability). Field examples and applications are provided for f this fracture orientation as well as other aspects of the fracture geometry is important to optimally designing the stimulation to maximize t stress around the wellbore is significantly altered. In some cases the fracture width at the wellbore is decreased leading to the cessation o sure response. The model prediction agrees well with the observed pressure response and surface tiltmeter observations. The production-i ally numerically and experimentally the instability of the displacement of viscous fluid by a less viscous one from porous medium and evalu large job fracturing treatments ranging from 100 to 300 tons using large sized proppant. It is generally believed that a high stress barrier a

clean-up and using the mechanisms uncovered to devise methods that would allow the production to benefit from the full length of the frac elastic stress is a transient localized stress increase caused by fluid injection into porous media. Possible explanations have been looked i acturing operations apparently induced by two joined factors - a fault acting as a barrier to the hydraulic fracture up going dissemination and ot often reveal the overall extent of the hydraulic fracture and furthermore only the propped part of the fracture can be easily mapped. ï¿½M ow of gas into the production tubing is controlled by a downhole flow control valve with a capability to adjust the flow area from surface by hy servoirs in these fields are generally characterized as fine sand with D50 varying from 50 to 125 microns uniformity coefficient (D40/D90) etion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit. This paper will discuss th etion costs or the lack of production due to ineffective stimulation make many reservoirs uneconomical to exploit. This paper will discuss the tervention steps the well started to produce. A pressure buildup test performed one month after the intervention showed that the well was p known as sabkhahs and mountainous sand dunes (up to 200 meters high). Because of its rugged character the field is developed from the design incorporates a removable housing ICD hardware this allows on-site nozzle changes to create relevant delta P to enhance well perfo onitor evaluate actively manage and optimize the performance of the well and field. Initial application of intelligent completions was in subntains six oil-bearing carbonate reservoirs and has three gas-bearing carbonate reservoirs (Figure-1). Abqaiq field has a modest natural wat e flowmeters. A cost-benefit analysis demonstrates that reactive control strategies always yield a neutral or positive return whereas a pass ments that are unavailable in the field. However one cannot generally correlate their results directly to field applications due to scaling issue

is fast to implement as it can be accomplished quickly and efficiently after the well is drilled in time for planning the well completion and pro modify the strength behavior of sands surrounding open holes and perforations during drawdown and production. The sanding tendency pr f perforating with acid in the wellbore as the completion fluid is also examined.ï¿½ The implications and suggestions to safely apply the tech everal important oil discoveries including Rhourde Messaoud Bir Rebaa North Bir Rebaa West and Bir Rebaa South West were made bet e unique features from the gun assemblies was the selection of electronic firing head over a conventional or standard drop ball mechanism. They were perforated using a TCP/DST string which allowed the well to be tested immediately after perforating. Details of the diagnosis p e well productivity per well expenditure. A multilayer production evaluation of one of the wells perforated with the dynamic underbalance me pen a communication path between reservoirs with different pressures. Introduction The potential of fracturing techniques to enhance produ post jobï¿½monitoring and the final results. This is the first fully documented case of thisï¿½perforating technique being used in a carbonate s. This formula extends the applications of a classic convolution algorithm to include variations in the skin and flow rates. New analytical sol g time the wells performed superior to existing wells and were brought into production sooner than planned. This technology has elevated perforators. Introduction A perforating project manager has to carefully plan a perforating job for both maximized system performance and m

ments have aimed to produce a better quality charge more suitable for a given completion type. In many instances particularly for natural co shooting is managed using a permanent down hole gauge installed in the completion string. The first well completed using this new method ) which consist of one Permanent DownHole pressure & temperature Monitoring System (PDHMS)and three hydraulic flow control valves (F significantly lower frac gradients than previously experienced. The challenges of minimizing placement pressures accurate modeling of gr ction perforation strategy and ability to frac across shale intervals. The paper also will cover the effectiveness of achieving a frac pack with ultilateral wells are needed in Hawtah to achieve and maintain economical production rates from these wells. In addition sand control solutio mium screen. Revised operational procedures were used in six subsequent frac packs without any additional failures and zero-to-negative rior to close in for sand production was 2900 bopd on choke 52/64. The main objectives for intervention on Alpha-4L were: To clean out sa

cipitations.ï¿½ Additionally acid reacts with the screen metal causing variation in opening tolerances which is unacceptable for these poorly are injectors. The development drilling programme began in 2005 with the aim of drilling and completing 15 wells prior to first oil in 2007. Al

of the existing fields is increased by contacting the laminated sands. In Italy one of the major challenges in UGS projects is to perform an e clude Alpha/Beta 3 Alpha/Alpha4 and Alternate Path packing.5 The first two techniques use a low viscosity carrier fluid (typically brine) with erent tools and fluid configurations on the success of the job and subsequently optimize the job design. The paper also presents two case h with solids-laden fluids (conditioned oil-based mud) in the wellbore due to logistical challenges and economics. An OB carrier fluid was re igh permeability (1.5 to 3 Darcy) with sand production a major concern. Several jobs were completed with the above mentioned technique y high permeability (1.5 to 3 Darcy) with sand production a major concern. Several jobs were completed with the above mentioned techniq and wellbore fluid on perforation clean-up and PI. In addition two tests were conducted on field core material in order to evaluate the sandi aper describes the processes in delivering the tailor-made ICD system i.e. completion modeling in the reservoir grid to simulation analysis ns to target pay behind casing and also zones that are located behind both tubing and casing. Introduction A sand control completion is re

sanding and optimize hydrocarbon production. This paper provides details of implementation of this SMS in the Sarir field and demonstra or time-consuming modelling. In this study sanding prediction analyses were conducted using a technique that combines easily measurab vestigation concluded that installing sand control facilities were unnecessary which otherwise would have cost millions of dollars without co d to sand production. Introduction Sand production in the petroleum industry is a phenomenon of solid particles being produced together w

the pick-up of the failed material by fluid flow are a very complex process and very little research effort has been dedicated to the morpho hed. Sand production was found not to be a major problem in the early stage of production. However depletion in reservoir pressure and w or regular acids.ï¿½ All these wells responded positively to the treatment. There were no operational problems encountered during pumpin ana limestone and dolomite core samples. Among the findings:ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ ell County Texas. It will also focus on what is being done to mitigate the affect of high temperature on hydrochloric acidâ€™s reaction rate. I d zones effectively thus diverting the new stage of acid into the non-stimulated porous zones. These fibers degrade and hydrolyze with tem bridging mechanism would plug off the just stimulated zones effectively thus diverting the new stage of acid into the non-stimulated porous astic diverting acid systems are more effective in achieving diversion than coiled-tubing-conveyed methods using conventional linear acid s sed on the laboratory results an optimized fluid system was selected that showed the best compromise for maintaining rock integrity fluid ate wells in Kuwait. er operators in the same environment and reservoir conditions. Review of post acidizing results came up with recommendations and lesson

and post-treatment production data have been analyzed to evaluate the effectiveness of the treatments in terms of skin reduction or produ cid or HCl plus organic acid treatment. In additional to reaction kinetics data such as carbonate dissolving capacity at reservoir temperature

ctant was developed. By incorporating this stage into the fracturing treatments the retained matrix permeability was increased to +/- 30% re e also being used as a means of improving acid placement by combining stimulation and diversion in one step.ï¿½ï¿½ Diversion is a critica mation and proppant pack therefore improving the productivity of the well. A variety of reservoirs and the impact of foam fracturing is descr plugs. The first set of experiments involved determination of the evolution of permeability with porosity for the RRT.ï¿½ In these experiments mulation potential and suggests methodologies that should be applied to various field types. The case histories illustrated in this paper will h wells treated with the new fluid. Introduction In the Big Horn Basin northeastern Wyoming there are several different fields that have been s ion was rediscovered in 1994. The production boundaries of Waltman-Cave Gulch are not yet established. Current development priorities a hstan were not considered as a target for hydraulic fracturing before. Part of it is contributed to low success of hydraulic fracturing on other

e layer with an average permeability of 20 md and porosity of 22%. The formation contains large amount of natural fractures and produces and its ability to prevent fluid and gas migration in the annular space behind casing is a challenge. Historically three measures are evaluate e constraints and environmental issues there has been increased interest in short-term tests for determining key parameters such as reser n from horizontal well tests.ï¿½ FSI data was instrumental in interpreting effective length of the well. Overall this test program yielded infor methodology is applicable to all types of reservoirs however most of our field experience has taken place in the evaluation and optimization fferent surface flow rates during the infinite-acting phase. These individual layer flow rates and pressure transients are used to calculate the ope line on the pressure derivative is the unique characteristic identifying the presence of the spherical flow. This straight line can be used t f the tested volume; i.e. how much reservoir volume is investigated for a given duration of a transient test? For exploration wells the reserv out having to stop the production intentionally.ï¿½ For the scheduled pressure transient events the data acquisition rates were actively chan e implementation of permanent pressure and flow-rate measurement systems the importance of deconvolution has increased because it is

ws using image log data associated with welltest analysis in order to determine dynamic fracture parameters such as fracture permeability a s (DFA) borehole images and numerical simulation models to minimize these uncertainties. A systematic pressure transient analysis metho kness product for the gas bearing zones using average reservoir pressure and temperature for the whole zone of interest. The success of the well productivity that could not be captured by conventional means and could potentially lead to erroneous results as well as sub-optima ed by the multiphase flowmeter which therefore provides also confirmation of the hydrate build up curve. The challenges to collect represen

e well test device for X Field in the Sultanate of Oman. X Field wells are artificially lifted and have a high water cut of 80%. The reconciliatio nd the actual dynamic measurements from the meter â€“ an impossible task for conventional measurements based on separator or batch p 300 B/D: 95% confidence interval). This new interpretation model offers a significant advance in the metering of wet-gas multiphase flows a testers and test separators was marginal in high potential wells and between 20-40% higher by MPFM in low potential wells. These finding

pectrum permits a quality control in real time and allows tracking of fluid composition change over time. Then we will focus on high producin al years. Raghavan et al1 . have reviewed its development in their work . They found that there are three broad areas where there are grow (based on q/Dp functions) and Î²[pBDdiB(tBDdB)] is used for "pressure" analysis (based on Dp/q functions). The application (i.e. the use o ol for diagnosing well and reservoir behavior.1 It provides the basis for modern well-test interpretation methodology and has become a custo ent is generated. This electric current is the source of the streaming potential. Experimental Installations Two separate experiments have b

s volumes and CO2-resistant cement system) have been essential in achieving the containment objectives. Introduction Cement slurries a rces such as fossil fuel-fired power plants is captured transported and permanently stored underground. Along with capacity and injectiv pection remediation (workover) design improvement or monitoring are valued based on a cost/benefits ratio. Moreover updating risk asses hile minimizing cost. Finally integrated asset modeling also shows the flexibility to represent different types of settings such as CO2 source hat CO2 injection into the subsurface be undertaken in new environments (offshore and in a greater variety of basin settings) and at volume lity and brine permeability. Carbon dioxide injection started in 2008 and will last for about 2 years. The paper focuses on the integrated app ent issues in CO2 capture and storage such as site selection storage monitoring and verification techniques developing local CO2 storag nt hydraulic isolation of the well by optimizing the wellbore condition. Similar information along existing wells helps to control hydro-fracture p

ea and thereby the total recovery from the field. The Visund Floating Production and Drilling Unit (FPDU) is located centrally on the field. T ng efficiency. Within six months six wells were delivered including three sidetracks (One top hole and two horizontal sections). All wells pen

iated with delivering the product to the point-of-sale is significantly less than imported products.ï¿½ Due to the decrease in exploration activ ld has an inorganic origin. This paper discusses the evaluation of potential supply of CO2 of Quebrache reservoirs for EOR projects in the as well as set-pipe decisions. This process is becoming a useful tool for further exploitation of the mature Oligocene Vicksburg formation of ï¿½The loss of productivity in gas-condensate reservoirs due to near wellbore condensate dropout is well discussed in the literature.[1 2 3 ecovery attained by the initial well arrangement. Introduction The SAGD process has been considered from the beginning of the thermal E arbonate field was discovered in 1964 and came on stream three years later. The field has 7 reservoir layers (A to G) and multiple subunits

activities in their geological evolution. Since being formed to recent the basement rocks of the Cuulong basin have been strongly affected b n on a broad range of applications (multiple zones stimulation water/gas shut off zonal production evaluationâ€¦etc) where accurate select used because of the absence of a gas gathering facility for the field. As a result of production decline and lack of infill opportunities cemen evices to stop water production. ï¿½Definition of problem The well was completed as an â€œS shape open hole producer with approximat ve solution was established as a standard practice for water shutoff in the Boscan field. Introduction The Boscan field lies 40-km southwes ½ - 3 ï¿½ tubing of an existing vertical wellbore and 6 1/8 inches open hole completions. Production flow profile is needed to determine the d precise depth control proper packer inflation and optimization of the cement design. This paper highlights the application of a CT equipp of the flow hindrances are categorized below: Inorganic elements Scales Elemental sulfur Liquid loading Hydrocarbon/water loading n water (o/w) and water. Log-normal distribution was the best probabilistic distribution for representing the data for fully dispersed systems. OR) with water injection (cold or hot). Moreover two-phase liquid/liquid flow is common in the process and petrochemical industries. Althoug head and allow conclusions on the inflow behavior from the reservoir.ï¿½ These monitoring devices are located either directly at the comp me them. The projectâ€™s results of implemented recommendations increased production in excess of 2 000 BOPD with no additional inve measurements of asphaltene and wax precipitation of a hydrocarbon fluid when contacted with gas condensate from another zone. The ev T) the wax crystallizes out of the liquid solution. The precipitation of the wax components out of the oil is responsible for the changes in the mples are given demonstrating successful CO2 detection and subsequent confirmation of the measured concentrations by the laboratory d 2 content new and improved sampling procedures together with advanced DFA measurements were required to accurately measure and qu

tudy. A reasonably accurate estimate of dewpoint pressure for a specific reservoir fluid is necessary in situations in which laboratory data ar fluid composition condensate yield reservoir temperature and pressure. The data points were generated by extracting the PVT properties become very difficult to model. In addition reservoir compartmentalization leads to discontinuous compositional contrasts but in turn identif g fields it is essential to understand the reservoir and fluid characteristics for optimum reservoir management. A common method is to integ on to increase data acquisition efficiency and minimize measurement uncertainty. The approach has integrated drilling fluid optimization ne e demonstrate this with an ANN model that uses the DFA-tool measurements of fluid composition as input and produces predictions of gas/ k simultaneously honors the physics of multi-component fluid flow and the thermodynamics of phase behavior. The numerical model was ve ent decisions; therefore obtaining high-quality samples and performing an adequate fluid scanning along the hydrocarbon column is impera

the determination of several fluid properties including fluid compositions in real time. The applications of wireline formation testing has bee s the verification test procedures and the laboratory test results. In addition we will discuss options for the design of the downhole tool in ord

compositional grading in light-hydrocarbon (> 35ï¿½API) columns occurs for near-critical fluids or more appropriately for fluids close to th . vary with elevation. The magnitude in grading of these properties can vary greatly depending on the geological and geochemical history o and their properties in-situ and in real time in the second well drilled in a different fault block. In this case the use of WFT together with DFA ement principle of the analyzer and discusses the impacts and benefits brought about by the new technology. The concept of flexible fluid s ocedures; some of which are based upon new and emerging technology. Introduction Formation pressure profiles have long been used as associated uncertainties and concludes on an optimal fit approach. This data integration then allows making assessments and quality cont advantages over the conventional GOR measurement techniques. It does not require tampering with the sample which helps the operator

essure gradients and fluid analysis of the different zones (Kabir 2006). In this paper a novel methodology is presented to account for nonand gas phase) and to quantify the level of OBM-filtrate contamination (Mullins et al. 2000). In addition optical spectroscopy is invaluable do e this with an ANN model that uses the DFA tool measurements of fluid composition as input and produces predictions of gas/oil ratio (GOR

Pope et al.2 discusses a Newton-type entropy maximization algorithm combined with a Gibbs stability test to yield the number of phases.ï¿½ e average droplet size was increasing with water content. For all measured cases viscosities varied with temperature according to an Arrhe

nes can be scanned sequentially in real time to quantify the fluid properties at a much higher resolution than traditional sampling methods. D he operation 450 c.c. sample bottles were used for collecting the fluid. These bottles were positioned on the top end of the toolstring and th ow meter. This dedicated multiphase fluid sampling and analysis system combined with Vx technology provides a comprehensive and accu apacities of portable laboratory. Not only does this state-of-the-art device allows to capture fluid samples bridging the gap in fluid sampling high pH while water attack can dominantly influence the calcite dissolution at extremely low concentration. The combination of these two a ptimum surface pressures are still maintained. These favorable results have widened the potential application of the technology to oil and g ion has ramifications in the screening of a variety of stimulation fluids including acids and scale inhibitors. Introduction In the execution of ential to reduce cost treatment intervals and production downtime. Moreover there is the opportunity for the new product to be batch squee

ures to avoid the formation damage caused by naphthenate-soap deposition. nalysis and the strength damaged zone is characterized using a Scratch-Tester. These methods allow the quantitative assessment of both d w the skin depends on the degree and rate of underbalance. 1.ï¿½Introduction A perforation is created by the impact into rock of the high rovide sustained rates over a 3-month monitoring period compared to rapid decline in production on the non-inhibited wells. At the same tim found in the Uinta basin are shown in the Figs. 1 and 2. Scaling in the upper production system (tubing surface facilities) can be easily con potential to address other produced water management issues such as inorganic scale control while the operation of the ICV and may in ion. The category of strings with a scale thickness less than 0.25 are treated with a chemical scale dissolver the wells containing scale thic This analysis is supported by the field data and by reactive transport calculations.ï¿½Implications are drawn for scale management in this a ng). The proposed technique has been successfully tested in a fluvial depositional environment. In order to test the robustness of the appr ure cells and where fracture/matrix cells require permeability enhancement or reduction. After improving the history match level Injection P ws. What are the general benefits derived from incorporating and using this technology in reservoir management. When the streamline te anges of the Cantarel Field and the location and length of the perforation intervals relative to the fluid levels. The numerical results show th problematic wells and a reconciliation of the production rates measured at the gathering stations with rates calculated at the well level. Th in the middle-east. Although this strategy has been successful there is evidence of an uneven sweep due to reservoir complexity. These c d the field-wide VRR is ~1. Sound reservoir surveillance and waterflood management procedures implemented within a diverse group of tea The application of bottom-drive PCPs in the Cerro Negro area has resulted in production rates of up to 1 000 BOPD of extra-heavy oil with e second one evaluates the temporary application of downhole heaters in horizontal wells for a limited period of time to accelerate productio asuring multiphase flow (Rogers et al 1988; Ashton et al 1994). Furthermore microwaves are used in various technological and scientific tive sweep in the vicinity of the producers while decreasing oil viscosity and improving oil drainage. This project is based on the numerical s oductivity and avoiding life cycle risks. Well produced 1300 bopd which is 5 times higher than vertical well and more so make production sig LSP) consisting of sixteen 2.5 acre inverted 5-spot patterns is being installed. This will be the first multi-pattern steam flood of a carbonate r evaluated in detail. Within the vast Russian oil and gas fields environment with different geology and wellbore and fluids conditions the tec

oil environment. Introduction Fula Oilfield is located on central structutre belt of Fula depression in Muglad Basin which consists 3 main blo

90% to 98%. After the treatment water cuts lowered to the range from 40% to 75% and post-oil production increased by as much as three

challenging conditions and after trying other multiphase meters said to work in Extra Heavy Oil PDVSA found that the only solution was Ve

ased minerals (hematite and pyrite). Recent studies on matrix stimulation have strongly emphasized the importance of secondary and tertiar eline formation tester with nuclear magnetic resonance (NMR) logging in a single logging string and the use of two downhole pumps also in

ic plots based on bulk fluid properties for reservoir fluid equilibrium grading tendencies have been constructed based on interpreted results

eve crosslinking at two temperature ranges so that early viscosity for proppant transport can be developed.ï¿½ Mixed metal crosslinkers s acid fracturing treatment. Additionally the paper will highlight some of the unique challenges of placing a solid-based acid system in the form

Minimize intervention Minimizing of production interruptions Equipment Selection: To qualify and have a reliable HPHT Digital Electric ga ne (sandstone) and the naturally fractured Basement. Propped fracturing has been found to be very successful in the Oligocene whereas d w that more skin reduction is obtained with the new fluid than with the other conventional acid systems tested. Introduction The oil field is ility of the critical matrix. However because of the rapid reaction between hydrochloric acid (HCl) and carbonates diverting agents such as tivity. Design laboratory studies temperature simulations confirmed by downhole measurements field implementation and results of the firs re in the porous rock and viscous fingering of gas through water. The presence of clays migrating fines reservoir heterogeneity and the o to pressure and temperature. Comparison of the laboratory pH measurement to real-time in situ downhole pH measurements made on the

quare miles with estimated total reserves of over 1TCFg(Figure 1). The Cleveland is characterized as a fine-grained tight-gas formation wi

ore stringent early collection of data (e.g. formation evaluation core fluid geomechanics etc.) that impacts our development before we sta outlines in more detail the observations from hydraulic fracture mapping in this area. Regional Background This area of study includes 300 ure orientation for reservoir development was even more significant. The results undeniable indicate that a significant deviation of the field ndicate a vertically contained developing fracture network with anisotropic spacing and moderate confining stress contrast. The fracture net 3 bbl/MMscf for the offset wells to 135 bbl/MMscf for the new well. The first-year gas from this new well was more than double that of the of

production optimization and fracturing engineers from the early stages of well planning to construction. The multilayer Foukanda field loca completion and stimulation measures. This paper describes a case history of how a multi-stage technique was used to stimulate a poor-pe re map of SUG is shown in Fig. 2. From initial field development to 2003 field production was predominantly from several high permeable l nt risk and maximize profits. Introduction Tight sand reservoirs account for most of the gas production in the US Rockies and their develop of decisions made subsequently.ï¿½ This process is continuous and models are updated or changed according to the geological and petro grid refinement was used to represent the fracture properties. Then a parametric study was conducted to establish the effective global cell the increased fracture stimulation cost. Production logs acquired across entire intervals confirmed that portions of the field produced from h

ugh the integration of well correlation and cross sections. The output from this study provides an essential database for well completion dec at a broad permeability range. The combination of drilling fluid displacement XLD utilization and the two-pump configuration proved to be m ns to both understand the long-term impact of natural fracturing by associating quantitative properties that characterize both their locally ob G) accumulation in the Washakie and Red Desert Basins of the Greater Green River Basin located in southwest Wyoming. Discovered in th

ated from low permeability reservoirs is often suspect: pretest volumes are typically very low and there is no stable flowing pressure. In the e smic and log correlation of lenticular sandstones. The exploitation of the field had been postponed because most of the wells showed poor ethod is presented to identify understand and manage risk associated with horizontal wells drilled in tight-gas-sandstone reservoirs. The m eno-Takhomskaya oil and gas accumulation zone (YTZ) located in the western part of the Siberian platform (Fig.1) was identified in 1973 w

ully helped determine the level of the anticipated water cut oil compositions and gravity and GOR throughout the transition zone allowing a

presented. Production results to date have been remarkable with productivity improvement factor varying 3-4 folds compared to vertical we

applied for evaluating different types of decisions within the petroleum industry. This paper also creates discussion around heuristic intuitiv of biases: cognitive and motivational. Cognitive biases show up in the way we process information. In other words they are distortions in th

oirs Caution should be exercised in zones containing tar or heavy oil Laboratory studies on core can be used to enhance the accuracy of t s. Models were developed to identify stratified permeability heterogeneities from the time-lapse ERA voltages. The stratified heterogeneity e into a number of electrofacies. If good correspondences exist between on one hand these electrofacies and on the other hand both geolo marine setting with sand developments mostly in tidal channels bars and sandy flats. The study helped in understanding the heterogeneitie ull-bore core photos provided a much more robust reservoir model than would be obtained from traditional approach based solely on open-h ced--in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides importa nd aging fields it is essential to understand the reservoir and fluid characteristics for optimum reservoir management.ï¿½ A common metho ods for characterizing the carbonates. This lead to the development of a method of carbonate rock classification keeping in mind the followin twork which also controlled the hydrocarbon entrapment. These faults were not easily identifiable from seismic interpretation; the discrete fa Other collar sizes are also under development to allow the tool to be deployed in a wider variety of hole sizes. Array propagation resistivity m n evaluation. As a result fully evaluating the reserves has been an ongoing challenge for the operator. In addition because of the move tow

e and validated mathematically. These charts can be easily used to predict the uncertainty in hydrocarbon saturation estimate due to uncer hematically. These charts can be easily used to predict the uncertainty in hydrocarbon saturation estimate due to uncertainty in the input da alysis surveillance logging and production logging have confirmed the critical role permeability plays in hydrocarbon recovery and Masalmeh mplex. Precise information on the structural dip and fault pattern in the subsurface is mandatory to plan development / infill wells successful advanced research methods are included. A key result of this study is that a relatively simple method for log derived permeability and rock rneo.ï¿½ The techniques demonstrated here are also applicable to the analysis of other categories of thinly bedded shaly sand reservoirs.

echnique could provide. Field examples of a straightforward case with a well-defined anisotropic shale point as well as a difficult case with s of the LWD modeling and production data while underbalanced drilling to provide more accurate formation evaluation. nsient data to provide an explanation for ambiguous production observations and well test data. Examples of completion optimization utilizin advanced fluid profiling and its practical application for deepwater exploration and appraisal operations using several field examples. Susp en predicted induced fractures and those seen in the image logs and cores. Such cooling-induced artificial fractures were found to be comm onate platforms which are the reservoir rock for the major hydrocarbon fields in the Arabian Gulf. Aggradations of carbonates in extensive s

stimation biases in the initial geostatistical model. An enhanced reservoir modeling workflow with inference coupling spatial and frequency c ogs and design of the wireline testing and sampling program. A modular wireline formation tester is used to measure accurate in-situ pres bon pore volume. Conventional high-resolution permeability from NMR is limited to one antenna aperture. If the sand layer thickness is less

ages before and after the depth and survey corrections to illustrate how the measurement errors affect formation dips interpreted from the im

. Introduction In-situ stresses in reservoirs have a large influence on several aspects of reservoir development such as hydraulic fracturing still a challenge.ï¿½ The problem is more prominent in limestone rocks compared to sandstone rocks.ï¿½ Further shear velocity data is no um (SH max) and minimum (Sh min) horizontal stresses obtained from the inversion of borehole sonic data are significantly smaller in the d hed using the convolution of the varying flow rate and pressure history of the well to evaluate the transient performance.ï¿½ This relationsh hed using the convolution of the varying flow rate and pressure history of the well to evaluate the transient performance.ï¿½ This relationsh hed using the convolution of the varying flow rate and pressure history of the well to evaluate the transient performance.ï¿½ This relationsh e wellbore. This technique of processing the VSP data to identify fracture clusters could form a bridge between surface and borehole data a th Stoneley waves and the petrophysical interpretation. The two layers A and B were recommended to be tested and the DST (Drill Steam T ures and large vugs. Eventually the well showed a good production results and currently is one of the best producers in the field. As such w scontinuous open continuous and discontinuous closed types. The Upper Arab reservoirs contain significantly more open than closed fractu d production results and currently is one of the best producers in the field. As such we recommend application of the described integrated a

e key outcome of this field experiment is a full verification of the permanent downhole resistivity array and pressure sensor experimental se position gas-oil ratio (GOR) pH density and viscosity and pressure-volume-temperature (PVT) behavior is crucial for production strategie n Indonesia obtaining pressures with Wireline Formation Testers has always been difficult.ï¿½ This naturally affects the success of sampli

f the porosity was not noticed with regard to the one from cores. Additionally with the aim of obtaining a better correlation among cores and how continuous NMR fluid scan logs can help to: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½- ï¿½ï¿½ï¿½ï¿½select and optimize pretest and sample po various examples presented in this paper describe practical petrophysical methods used to improve the formation evaluation of shaly gas re g quality down hole NMR data is the extremely limited time available to acquire it. For a modest logging speed of 900 feet per hour and a sa spective The potential value of NMR logging was first recognized in the 1950s leading to development of nuclear-magnetic-logging (NML in the Estancia Cholita Field. Introduction The Gulf of San Jorge Basin situated in the central Patagonia region of Argentina is an extensio ntal wells bring new opportunities as well as challenges for reservoir characterization and management. Since they have maximized reservo

rmination of unknown reservoir parameters. The simulation-while-drilling approach proposed is fully automated and can be set up on a know e Mishrif reservoir and establish the relationship between the fracture corridors and the intersected faults in a long horizontal well that posed

. However in deepwater or similar settings full-scale testing is inordinately expensive and environmentally taxing. Moreover interpretation nventional as well as novel analytic approaches. Reservoir compartmentalization (the inverse of connectivity) impacts all production strategi using the convolution of the varying flow rate and pressure history of the well to evaluate the transient performance. This relationship is pre ept zone. The planning and first results of this program are presented in this publication including available field data. It is expected that th ptical probe iii) the openhole driller iv) cable creep correction and v) extra-extra high displacement pump unit. We will present each project

s reasons in a reservoir.ï¿½ï¿½ Hydraulic fracture design fracture containment fracture orientation water injection design and flood manag st for a relatively long duration. While this is an excellent way to meet test objectives environmental and cost consideration does not allow u count for surface facility constraints. In the final analysis five sidetrack wells reaching 12 new drainage points (NDP) over 10 reservoirs wer tinuous distribution of fluid composition and gas-oil ratio versus depth. The DFA data was pre-processed in real time enabling more accurat PCSB) with gas lift as a primary system for lift.ï¿½ Bokor is currently operating with production restriction due to insufficient lift gas and othe together with the facilities to collect and inject the gas. Both injection projects required consideration of the processing needs for the increm tant injection rate with constant injection pressure and therefore increased production flow stability a critical operational constraint in dual s ollaborations and is now seen as a premium well placement service within Saudi Arabia. This paper will highlight how these innovative tech ce water injector wells. It has the potential to reduce the number of injector wells drilled thus cutting cost and meeting the production goals sted. 3) Although the gas production increased significantly the decline rate has also increased indicating that we have accelerated gas p he main objective should be to optimize not only the areal drainage pattern but also the vertical scheme. This makes the process highly com current reservoir management practices at low cost. It was shown that the elimination of flaring does not only help in protecting the environm vantage in the use of an IAM taking into account the network constraints to obtain more accurate results. To evaluate the performance of t ple reservoirs and surface facility networks the controller manages the boundary-conditions exchange needed to couple different models and n-making process (Fig. 1). Figure 1: Reservoir Management cycles The Field Management cycle is a multidisciplinary practice which invo entify bottlenecks in the gas handling capacity. Simultaneously with the model study shut-in wellsâ€™ production potentials were re-tested ber of infill wells planned and creating an additional ultimate oil recovery of 4.98 MMstb. In the future implementation of all opportunities w

model (IAM) comprises of a coupled system of reservoir simulation models with surface facility network models. The purpose of coupling is t he new reservoir and run this directly to the existing platform. But how do these options effect reservoir management and surface facilities me them. The projectâ€™s results of implemented recommendations increased production in excess of 2 000 BOPD with no additional inve This is particularly true for tasks that require data consistency in for example the process of data collection property population of static mo workover operations to reduce water cuts and provide substantial incremental oil production. Additionally caliper data associated with the lo

ing limited gas lift availability to Khafji Field to enhance production while taking into multiple well and field constraints. Introduction Khafji aisal wells in the period of 2002-5 resulting in another significant discovery and the commercialization of two previously discovered fields. G bserved in the Barik formation. The Barik formation produces gas of varying richness from most of its units with a high condensate conten ts some common pitfalls and mistakes normally made today in the reserves evaluation process for low permeability reservoirs which shoul pment it may be more advantageous for the client to acquire a forward contract for a service to be performed at a future date at some speci

e risk. When fields are developed with horizontal wells it is desirable to maximize well position inside the reservoir layer since the rate of inc ance of premature water influx. Introduction The Brenda field is located in the Outer Moray Firth Basin located 190 kilometers northeast of ch field experience suggests is advisable for bottom water-drive reservoirs.ï¿½ We observe a marked improvement in field recovery factor position whereby a successful completion was made. Without this â€œquick-response reservoir model the well may have been sidetracke technology invested into exploration as C.J.ï¿½ Campbell and J.H.ï¿½ Laherrï¿½re1 explained.ï¿½ Thus the E&P companies are coming b ion of horizontal well performance during the field development planning stage of an offshore oil rim brownfield. The field is highly constrain ving such problems is an arduous task; therefore well locations often are determined manually. However several automated well-placemen

mulation is an essential tool for the management of oil and gas reservoirs. Prediction of pressure-production behaviour under various opera dvantage of such an approach is that a wide variety of physical processes can be modeled in the reservoir e.g. rock layering effects faults g of the prior covariance calculated using a numerically-derived stencil applicable to a wide class of covariance models. Our proposed approa which shows high stability for field-scale applications. We demonstrate the power and utility of our approach using synthetic and pseudo fi

d curvi-linear geological objects such as channels or fractures unlike the variogram based two-point statistical covariance models. This ap

Watts 1996).ï¿½ In recent years several papers describe general simulators using unstructured grids (Beckner 2001; Debaun 2005; Beckne against standard implementations) for various types of field case studies. Introduction In numerical simulation formulation normally refers date the performance of some wells and to calibrate other wells that exhibit different production profiles. Some simulator options such as mu

s special techniques such as the use of a discritized well model. A discritized well is represented by multiple segments along the path of the

anner and proceed to detailed explanation of the DCA associated models available in most production decline surveillance tools. There is cl g the production phase. To accomplish these tasks crosslinkers (such as borates and zirconates) and delayed breakers (either oxidizers or s for more detailed investigations of fracture cleanup processes and hence an improved understanding of formation damage processes in 5. Two predominant layers exist in this formation C and D. The study herein is limited to the different zones comprising of layer D. Carbon Significant decrease in computational time in comparison with the existent simulators had been achieved. Introduction Hydraulic fracturing there is a good match in fracture height length and pressure between the simulation results using the interfacial slip model and the measu actically be modelled using explicit flow simulation. The above considerations are demonstrated in the simulation study conducted for mu ed in the literature.1 7-10 gas reservoir. Third we validate the results using a coarsegrid numerical reservoir simulation model. Finally we use simulator-generated da orted by Valko and Economides1.ï¿½ Since that time a number of researchers2-5 have developed interpretation models and analyses that nt in the North Sea validates the proposed model for a short point source hydraulic fracturing from a horizontal wellbore. Introduction Hydra es.ï¿½ Based on the results of numerical experiments we are able to provide some recommendations on how to avoid the worst case of th ds for each case is required. Nonetheless through this study we were able to identify several candidate methods and thereby narrow the w

cal permeability to simulate the vertical variations in sand-shale sequence. This also helps in reducing the severity of the phases being not i th a fewer number of wells. This is important in offshore operations in which well numbers are limited because of slot constraints on the pla g of the behavior of the wells and reservoir as the water front moves through the reservoir. The IPI concept was developed to help this unde of northeast-southwest trending faults. This fault system divides the main producing area into sub-parallel fault blocks. The fluid properties i meter was the selected material balance method used to compute the OOIP. More accurate results were obtained using the traditional grap g company the following ways of making improvements to development: Well intervention programs for selected wells; Rearrangement o position of the rock the porosity and the presence of water or gas. Therefore differences in thermal conductivity between adjacent lithologi s. Left unchecked the number of simulation runs can easily become unmanageable. Experimental design ED and the associated response

methods. These are designed to give a correct discretization of the flow equations for general non-orthogonal grids as well as for general o his particular problem has been published. Moreover the gas condensate flow in fractured porous media has been studied only in several pa rosity compositional simulations which create the composite matrix properties. These composite properties can then be used in full field d -scale geostatistical fluctuations of fracture densities rather than perturbing permeability calibrated from fractures. This strategy enables us

e results and run times of the streamline-based approach with a conventional dual porosity grid-based commercial simulator. The results fro mesh refinement along streamlines [2]. We show that the proposed technique can be useful when one needs to estimate the flow pattern i ng gap between flow simulation capability and the desire to build geologic-scale reservoir simulation models. In addition to sheer size stron

domized maximum likelihood (RML) method to generate an approximate sampling of the a posteriori pdf. Two different proofs (Oliver 1996;

pplication of a streamline simulator that has the appropriate chemistry modelling capabilities to realistic reservoir scenarios. The calculations

timillion cell geological models on a standard computer within hours or less. Such requirements are dictated by e.g. uncertainty analysis a heterogeneous structures of reservoir the smallest cell size defines the time step. This can render the CPU time for simulation impractical. n applied to forecast the performance of the infill locations honoring the respective probability of occurrence of each type curve. The presen

such as conceptual geological model well logs well test seismic and production logs are incorporated. There are multiple equi-probable g optimize the design and operation of wells with these installations their behavior must be represented in reservoir simulation tools. Simula

uted. Full computational advantages of black oil modeling are obtained while preserving the reservoir details required for an accurate predic pay in carbonates strongly oil-wet rocks and the dual water model for shaly sands.ï¿½ A good correlation between Cw - obtained from a c

er SPE 893253 on whether the beta factor Î² for a proppant pack should be constant over the range of flow rates of practical interests. The able reserves of oil are widely thought to remain in the oil/water transition zones of limestone carbonate reservoirs around the world. Such ion targets and metrics that were set to evaluate success were completely fulfilled in the first few wells in this multi-well campaign. Introduc s younger stress field of the GoS rifting. In situ stress directions have strong impact in drilling high angle wells in GoS. Proper placement of nt systems. The key processes are built on this foundation and deliver the business result.ï¿½These processes are supported by detailed d fields. The data fields from different regions of Russia had been used for this analysis. gle biggest source of revenue for more than 20 years .ï¿½ These petroleum provinces both emerged and matured with similar timing ove nt systems aged at high temperatures for one year; this is the first time that such data have been presented on these systems. Introduction

mation resistivity log enables fast decisions. These examples from the Western Desert illustrate how analysis behind casing provides critic ontrol and measurement can be applied effectively in both multilateral wells and monobore wells designed for commingled production from many wells with the new interpretation technique. This paper presents the history of the short string logging operations in the North Kuwait F re-transient analysis for the complex completions of multi-layered reservoirs are discussed.ï¿½ Examples illustrating data quality and interp

and packer. We pay particular attention to the unique pump configurations that were required to effectively manage the drawdowns when u and packer. We pay particular attention to the unique pump configurations that were required to effectively manage the drawdowns when u on. The reservoir is fairly heterogeneous with areal variations in permeability and reservoir architecture. The reservoir was primarily develop n water chemistry and is critical for corrosion and scale studies. Accurate downhole pH measurement allows a more-accurate selection of a h can be measured continuously in real time.Well completions are becoming increasingly complex as new technologies develop. Completio verage the fracture system propagates horizontally at 12â€“15 ft/min eastward. The observed hydraulic fracture systems propagated slowe n a tectonically stressed environment where the maximum principal stress is not always an overburden the assumption of a vertical fractur

ssible to determine the flow profile from the distributed temperature measurement and thus optimize the injection of steam into the heel or t steady flow conditions in the wellbore and in general require that a sufficient flow rate or outflow velocity exists to continuously transport the nditions in the wellbore and in general require that a sufficient flow rate or outflow velocity exists to continuously transport the produced well ming reservoir surveillance in multi-zone gas wells with velocity strings in Western Canada. Utilizing fiber optic measurements in these wells nd subsequent learnings of the project. cases problems are discovered when using these tools that would never be diagnosed on the basis of surface measurements (Lenn et al.

oductivity as well as standardize process and data management. To fulfill this objective the paper will address the following topics: brief intr hin hydrocarbon accumulations with horizontal wells for maximum reservoir contact to enhance recovery. These wells have introduced new ole shut-in tool (DHST) to limit the phase segregation effect. The transient analyses revealed different flow regimes from infinite-acting radi nd water production has also created tight emulsions further hindering production performance. It was concluded that the high gas product ecially if the development plan includes designing for utilizing an artificial lift method that it involves some capital investments beside rese modifications. Real-time decisions may include acquiring more pressure data points extending sampling depths to several zones extendin nt layer pressures caused by depletion is confirmed by shutting in the well and observing the resulting crossflow with permanently installed d imulator. Introduction Steam injection for reservoir stimulation is an important factor for the economic development of heavy-oil reservoirs. mal models of the near-well environment are described and used to analyze the data and to obtain the flow profile and reservoir layer pressu tion and system integration tests performed over the 2-yr development period to ensure ultimate success in the subsea deployment. Field eability based on logs are also proposed. The log-estimated permeability determined using this approach fits better with the production profi

rly implemented as an automated workflow to improve well productivity as well as to standardize process and data management. To fulfill th al wells that potentially have a higher risk of encountering sensor damage due to loose sand and/or debris. Other candidate wells that would

dicates the interval contributes most of the produced water. In the present example the cased-hole resistivity acquisition shows departure (l the preferential pass of the injected water either it goes down or up dip especially in heterogeneous carbonate reservoirs. Production Logg g the success of the pilot and future field development issues. It is anticipated that this tomographic Cross-well Electro-magnetic (EM) resi with the peripheral flood. Although pattern flooding leads to more efficient and faster recovery some potential drawbacks include greater co ments reported here indicate that shaped charge penetration in coal is significantly less than expected considering the targetâ€™s density m transmission coefficient analysis are used to interpret the variation in cleat density. The cleat density is further validated from the fracture or will be contributing significant amount of gas to the production stream. The production contribution from these adjacent coal seams is o design. The paper offers statistics on which changes have had the greatest effect on stimulation placement. These problems can cost ope heterogeneity at a reservoir scale (e.g. the presence of mineralized fractures preferential depositional fabric) and a favorable orientation o multiple thin seams ranging from 10 â€“ 30 seams per well. The coal seam thickness ranges lies between 0.1 and 2.5 meters. ( Fig 1 â€“ H e been used to implement changes to the completion process in horizontal Barnett shale wells.ï¿½ Stimulation staging and perforation plac and discrete fracture networks that are then upscaled to dual-porosity reservoir models for numerical simulation. The application of this wor ontrol and financial analysis used to design and validate the SAGD model. The study focuses on a completion strategy that demonstrates a stimated to exceed 16 000 Tscf it is clear that tremendous potential exists for future growth (Kawata and Fujita 2001). Reservoir Fundame nt. Refracture stimulation case studies are presented in which this novel diversion technique is successfully applied to horizontal Barnett Sh different formation permeability and pressure. It examines the conventional matrix acidizing practices and provides an idea on how the trea life. New applications to minimize ESP failures due to human intervention and ensure proper equipment handling during installations are b

ved therein. The economic and technical comparison of this system with the conventional methods is also enlisted. Introduction The ventur t by vertical wells. Horizontal well drilling brings about the improved productivity and therefore enhanced recovery for low-permeability reser ation caped by the shales of Itaï¿½pe Formation and sealed laterally at north and east by the shales of Morro do Barro Formation which w n pressures were closely monitored during several field installations and confirmed that perforations were not needed to initiate fractures in to extract a very reliable compressional shear and Stoneley. Dispersion analysis confirmed the presence of alteration to the formation. Dipo ysis has been developed to evaluate the optimum tubing string setting depth design to use for a multilayer commingled gas reservoir that pr ysis has been developed to evaluate the optimum tubing string setting depth design to use for a multilayer commingled gas reservoir that pr sions in a thin target process for real-time calculation of distance to the top (or bottom) and dip changes based on LWD data and effectiven

ainly vertical wells while Increment-2 was developed with horizontal wells. The subsequent MRC ML wells and Smart Completion installatio tion techniques. This technique provides the zone of influence of wellbore flow-control devices and illustrates the maximal benefit that may by use of mainly vertical wells while Increment-2 was developed with horizontal wells. The subsequent MRC/ML wells and SC installations

d. Details of the optimum horizontal well length are presented. The paper provides also advantages of drilling dual-lateral wells compared to h the implementation of high-accuracy pressure and temperature gauges this testing method can help determine reservoir characteristics u for analyzing the wealth of performance data that are collected. The manner in which the available data are scrutinized analyzed qualified production equipment. Placement of this material in the Khuff was a significant challenge due to the high fracture gradients encountered in t eservoir damage from brine imbibition based on core work comparing brine-based and oil based drilling fluids.1 Based on the 2005 core stu

ng gel costs and a reduction in premature screenouts. Bakken Geologic Description: Montana vs North Dakota The Bakken is a Mississip designed for tip-screenout treatments requiring fracture geometry control maximizing proppant pack permeability by increasing mesh size an mulated zones effectively thus diverting the new stage of acid into the unstimulated porous zones. The fibers degrade and hydrolyze with t t throughout the height of the fracture. Thus degradable fiber-assisted fluid must be utilized as conventional fracturing fluids may not suspe water alone. One of the water-wetting additives had much stronger adsorption in the core material than the other additives. The microemulsi cturing treatment many studies have been conducted on the effects of formation Youngâ€™s modulus in situ stress fracture toughness an erformance along with numerous fracture treatment applications with a variety of mix-waters. Introduction Recent strategies in gas reservoi (bbl) of produced water is generated (Khatib and Verbeek 2002). Even though some of this material can be managed at the well site many sin is characterized by a series of high plateaus and deep valleys.ï¿½ The primary target of this study focuses on the Williams Fork Format n the screen and the casing. Conventional frac-and-pack of twenty wells in these fields with perforated intervals exceeding 90 ft rendered a ater cut from 75 to 46% while at almost no impact in average oil rate. The paper provides a summary of the solution which allowed the ope o assure good zonal coverage across each stimulation stage. Greatly increasing the effectiveness of the treatments the combination of tech through coiled tubing. The case histories included in the paper illustrate the pre and post treatment production results obtained. All are ch the personnel and equipment needed to perform the work. The conclusions will show the operational efficiencies and reliability of this nove

orizontal open-hole completions with conventional methods is a challenging endeavor and that often times results are disappointing. Nevert

ced lower than expected; unforeseen in-situ emulsions are suspected as the cause for the production impairment. In this paper we will desc e dimensionless productivity index as the basis for improved fracture stimulation design.

g treatments performed including the introduction of various diverter methods in the area. The success of the pilot project is addressed as i

tiple-layer reservoirs requiring stimulation operators seek to balance the quality and the cost of the stimulations vs. potential well production tiation pressures were measured. Good agreement between predictions and measurements was obtained and the results indicated that h do not take into account the specific rheology of soft rocks and poorly predict fracture geometry. Newer elastoplastic models are unclosed b uctures commonly referred to as micelles.ï¿½ Entanglement of these flexible micelles imparts viscosity to the solution as shown in Figure 1

art of Chaves County Western part of Lea County and the remaining occupying most of the Eddy County as shown by the shaded region o

The success accelerated the application of the treatment in other candidate wells chosen from the initial study. Introduction The Marrat re n-up and using the mechanisms uncovered to devise methods that would allow the production to benefit from the full length of the fracture ½ The completion design changes incorporated in the second well showed some positive effects on the microseismic fracture geometry and

ctly vertical they are assumed to be perfectly vertical and no borehole deviation survey (i.e. the measurements of the borehole inclination a

ntial etching. Introduction Acid fracturing is a well-stimulation process in which acid dissolution along the face of the hydraulically induced f dy denominated Fracture Geometry Investigation to validate various method offered by the service industry. Two basic methods were tested nstraints associated with the half-life of presently used radioactive tracers and can be repeated as often as desired. The additive used in th

ny wells to economical production. Introduction Candidate selection and accurate post-fracturing productivity prediction was a main chall an estimate of optimal fracture length that is too short. Introduction A numerical simulator was used to forecast the productivity of a hydr ke and seepage flow induced by leak-off in the reservoir. The flow within the reservoir due to leak-off is described by the 2D pressure diffus he 5 wells treated with surfactant-based acid 4 of them showed better long-term production performance over a 2-3 year period compared es and applications are provided for fracture stimulation evaluation and optimization. This paper also introduces a way to evaluate and opti signing the stimulation to maximize the reservoir drainage pattern of the well. One way to deduce the orientation of a hydraulic fracture is th ecreased leading to the cessation of solid production while in others continuous production is maintained. It is shown that the selection of p meter observations. The production-induced stress has significant implications on refracture design and candidate selection and they are dis one from porous medium and evaluates characteristic size of entrapment zones. Both miscible and immiscible displacement was investigat believed that a high stress barrier above and below reservoir interval will facilitate the bridging of proppants and will cause an artificial bar

enefit from the full length of the fracture placed. This would either boost revenue by increasing production or decrease cost by placing sma ble explanations have been looked in details using pressure transient data and it supports the theory of poroelastic effect. Then the remedia fracture up going dissemination and a rock formation weakness caused by open natural fractures and induced fractures in the zone below racture can be easily mapped. ï¿½Monitoring the fracture growth by other methods can help fill in missing information. For example micros ust the flow area from surface by hydraulic or electric means. The use of downhole flow control valves means that auto gas lift belongs to th ns uniformity coefficient (D40/D90) of 4.5 to 15 sorting coefficient (D10/D95) of 23 to 95 and fines content (D < 44 microns) of 14 to 47%. o exploit. This paper will discuss the new completion designed specifically for open-hole fracturing of both sandstone and carbonate reserv o exploit. This paper will discuss the new completion designed specifically for open-hole fracturing of both sandstone and carbonate reserv rvention showed that the well was producing with a damage skin value of zero. The different interventions the laboratory results and the ef cter the field is developed from the flat sabkhahs necessitating highly directional drilling to reach the targets. The oil in the Shu'aiba format levant delta P to enhance well performance just after the well has been drilled and uses the real time data from the final logging operations of intelligent completions was in sub-sea wells to complete and produce multiple horizons from a single wellbore without the need of interven bqaiq field has a modest natural water drive that has been augmented with a peripheral water injection program. al or positive return whereas a passive model-based strategy can yield negative returns if the reservoir behavior is poorly understood. Whi eld applications due to scaling issues. Their ultimate purpose is to provide a benchmark for numerical models that may represent the essen

planning the well completion and production tests. The high resolution simulation model permits to conduct further engineering studies whe roduction. The sanding tendency predicted from sanding analysis was corroborated with field observations. This was also used to calibrate suggestions to safely apply the technique of perforating with acid are discussed. Introduction The purpose of matrix acidizing in cased an Rebaa South West were made between 1981 and 1995. The geological features in this region are characterized by two main fault system al or standard drop ball mechanism. This tool utilized coded sequence created fromvariation of surface pump rate to generate its firing com erforating. Details of the diagnosis planning execution and evaluation phases of this project are described. The resulting gas production an with the dynamic underbalance method produced a zero skin value in the 9-md layer and a -0.97 skin value in the 1600-md layer. Convent cturing techniques to enhance production in low-permeability formations is increased if the perforations are aligned with the preferred fractu technique being used in a carbonate reservoir and the first time thisï¿½technique has been used in Abu Dhabi.ï¿½ Background ADMA OPC in and flow rates. New analytical solutions have been derived for both homogeneous and heterogeneous reservoirs based on the general c nned. This technology has elevated CT standard operation onto a higher level in Malaysia. Introduction Talisman Malaysia Ltd. (TML) opera aximized system performance and minimized risk associated with incidents such as perforating gun carriers stuck downhole. Maximized pe

instances particularly for natural completions it is desirable to maximize penetration depth while at the same time minimizing damage to t ell completed using this new method showed improved production of 4 times what was expected compared to similar wells in the field perfo three hydraulic flow control valves (Fig.3) with three packers (Fig.4). This completion was not run due to due to some operational problems t pressures accurate modeling of gravel placement rat hole mitigation and injection well clean-up all had to be addressed. The solutions d veness of achieving a frac pack with premium screens with shunt tubes on the basis of downhole-pressure and â€“temperature and radioac wells. In addition sand control solutions are required to safely deploy several branches off one main vertical well. This paper will describe the tional failures and zero-to-negative completion skins. This paper will discuss the failure modes of the two frac-pack/premium-screen sand f on Alpha-4L were: To clean out sand from the wellbore and Apply remedial sand control technique and restore sand free production to re

hich is unacceptable for these poorly sorted high fines content sands. The objective of this paper is to present the results of the application g 15 wells prior to first oil in 2007. All the 5 fields produce from poorly consolidated Oligocene turbidite reservoirs and consequently sand co

es in UGS projects is to perform an effective reliable and highly productive sand control completion in metric sand and shale interlayer. Slan sity carrier fluid (typically brine) with a low gravel concentration (typically 1.0 ppa). In both techniques initial packing takes place in the lower The paper also presents two case histories of gravel-pack jobs in long horizontal wells where the simulator was successfully used to desig conomics. An OB carrier fluid was recently used for openhole gravel packing of a well in Okpoho field offshore Nigeria. The application res ith the above mentioned technique and perforation packing factors improved from 10 to 40 lb of gravel per foot of perforations. Discussion o d with the above mentioned technique and perforation packing factors improved from 10 to 40 lb of gravel per foot of perforations. Discussi aterial in order to evaluate the sanding propensity of oriented perforations under conditions approximating those predicted during pressure d reservoir grid to simulation analysis of various scenario and sensitivities. Solution to tight product delivery time the ICD completion installati tion A sand control completion is required when there is a probability of formation sand production during the life of a well. The key factors

MS in the Sarir field and demonstrates that a systematical approach is required when addressing sanding issues in giant mature fields such que that combines easily measurable lab data log data and analytical calculations with empirical methods that are supported by the result ve cost millions of dollars without correctly addressing the real problem that this field was facing. The study highlighted the importance of a particles being produced together with reservoir fluids. Conceptually this process may be divided into three stages: failure of the rocks sur

t has been dedicated to the morphological description of rock failure. Using an endoscope camera it was possible to observe the failure b depletion in reservoir pressure and water-cut can significantly increase sand production risk. Introduction The multi-field development cons oblems encountered during pumping these acids even when low-permeability reservoirs were treated. Because these acid systems do not ½ ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ 1. The fracture conductivity created did not show a general increase with acid contact time a ydrochloric acidâ€™s reaction rate. It will further develop improvements in reservoir characterization and pay zone determination which has bers degrade and hydrolyze with temperature and time thus leaving the reservoir undamaged. This paper discusses the planning and desig acid into the non-stimulated porous zones. These fibers degrade and hydrolyze with temperature and time thus leaving the reservoir undam ods using conventional linear acid systems. Introduction Tengiz field is a large carbonate reservoir located in Kazakhstan. Producing in e for maintaining rock integrity fluid efficiency zonal coverage and fluid compatibility. Both wells responded well to the prescribed treatme

p with recommendations and lesson learnt for future campaigns. This effort will certainly enhance the success ratio of the sandstone acidizin

s in terms of skin reduction or productivity index increase. Introduction Hydrocarbon wells producing from carbonate reservoirs are often sti ng capacity at reservoir temperature and pressure solubility of reaction products and the effect of HCl to organic acid ratio are needed to b

eability was increased to +/- 30% resulting in a negligible fracture face skin. The productivity of fracturing treatments performed using this t e step.ï¿½ï¿½ Diversion is a critical step to ensure the success of matrix acid treatments. Understanding how chemical diverters interact w he impact of foam fracturing is described and analyzed in this paper from typical shallow gas to challenging deep oil reservoirs using nume r the RRT.ï¿½ In these experiments the core was treated at high injection rates with a fluid of low reactivity.ï¿½ Injection at a high flow rate istories illustrated in this paper will highlight the various treatment parameters optimized for successful restimulation. The conclusions of thi eral different fields that have been stimulated with a variety of techniques and fracturing fluids. An operator in the Big Horn basin has recent ed. Current development priorities are defining the deep Frontier Muddy and Cloverly reservoirs and extending the Cave Gulch (shallow) a cess of hydraulic fracturing on other formations including Jurassic horizons in the same Nurzhanov field and also to general consideration

nt of natural fractures and produces 23-25ï¿½ API gravity oil. Due to the lack of nature water influx the formation has been under water floo rically three measures are evaluated to check for isolation between reservoir units: (1) pressure testing (2) physical communication tests b ining key parameters such as reservoir pressure permeability skin and fluid properties. Closed chamber tests (CCTs) are attractive due to verall this test program yielded information that was critical in managing sustained production from this well characterizing the effects of the e in the evaluation and optimization of stacked-pay tight permeability reservoirs and low conductivity fractures where other forms of convent e transients are used to calculate the individual layer properties. GNPOC decided to go in for the MLT testing option and two wells were ana flow. This straight line can be used to calculate spherical permeability and spherical skin values.ï¿½ These parameters are then used to es est? For exploration wells the reservoir volume investigated is one of the main objectives of running drillstem test (DST) or production tests. a acquisition rates were actively changed to ensure sufficient high quality data.ï¿½ Also the length of the test was decided in real time to ma volution has increased because it is now possible to process the well test/production data simultaneously and obtain the underlying well/res

eters such as fracture permeability and shape factor for reservoir simulation. In this study sensitivity analysis has also been performed on fr ic pressure transient analysis method for mini-DSTs is also introduced. Reservoir parameters obtained from mini-DSTs in thinly laminated d ole zone of interest. The success of single well simulation has given us the capability to forecast total AOFP for multiple zones using commin neous results as well as sub-optimal well performance. The field test proves that the multiphase metering solution used in this trial can be . The challenges to collect representative samples of condensate and gas to ensure proper set-up of the multiphase flowmeter and thus th

h water cut of 80%. The reconciliation factor (also known as the back allocation factor) before this well test campaign was 0.54. The compar ments based on separator or batch processing of the liquid. Surface well testing to control changes of reservoir parameters PVT compositio etering of wet-gas multiphase flows and yields the possibility of high accuracies to meet the needs of gas-well testing and production allocat in low potential wells. These findings helped in optimizing reconciliation and allocation of the water and gas production. In addition to the ab

Then we will focus on high producing gas wells clean-up that have been successfully tested using the Vx technology in Gas Mode in 2005. ee broad areas where there are growing industry interests: 1. The use of numerical models to predict the effect of the geological model upo ns). The application (i.e. the use of Î²[qBDdiB(tBDdB)] or Î²[pBDdiB(tBDdB)]) is essentially a matter of preference â€” there is no substanti ethodology and has become a customary and requisite feature in commercial well-test interpretation software.2â€“6 In many situations how s Two separate experiments have been undertaken in shallow producing oil fields in Indiana U.S.A. to test the utility and reliability of elect

ves. Introduction Cement slurries are exposed to a number of phenomena during mixing and placement that can lead to set cement prope nd. Along with capacity and injectivity containment is agreed to be a primary function in geological storage performance. It must be eviden ratio. Moreover updating risk assessment with incoming data allows for an evolving vision of risk levels to optimize interventions in time. T pes of settings such as CO2 source (reservoir and/or fossil fuel power plants) types of reservoirs and network scenarios. Introduction Glob ety of basin settings) and at volumes much larger than have ever been injected into the subsurface. In this paper we focus on injection int paper focuses on the integrated approach of combining lithological and petrophysical data from both laboratory and well logging analysis pr niques developing local CO2 storage sites from hydrogen- and power-generation plants and industry training. In our paper framework o wells helps to control hydro-fracture propagation when injectivity enhancement is required. The Mechanical Earth Model can be used to dev

U) is located centrally on the field. The Visund North satellites consist of two wells tied back to the FPDU with a 9 km long subsea pipeline. wo horizontal sections). All wells penetrated more reservoir sand than prognosed and all were drilled faster than prognosed. Initial productio

e to the decrease in exploration activity brought about by the low prices of the preceding decades few new oil fields have been located withi e reservoirs for EOR projects in the North of Mexico. The main region studied contains estimated proven reserves of 1.9 Tscf of CO2; howe e Oligocene Vicksburg formation of South Texas. Introduction The Vicksburg formation in South Texas has been exploited since the 192 well discussed in the literature.[1 2 3 4] Reentering wells to gain additional production is not new.ï¿½Since the mid-1950â€™s oil compan from the beginning of the thermal Enhanced Oil Recovery (EOR) applications as one of the most effective recovery methods based on the ayers (A to G) and multiple subunits within each layer. The upper layers A B C D and E1/E2 are more intensely fractured than lower layers E

basin have been strongly affected by different alteration processes. These processes changed not only the composition petrophysical char uationâ€¦etc) where accurate selective fluid placement is essential for the success of the job. However the biggest challenge remains the no nd lack of infill opportunities cement-water shutoff and re-perforation intervention in the wells was adopted. The objective of the cement-w open hole producer with approximately 2675 ft of reservoir contact. Out of this 1600 ft was placed horizontally at the top 50 ft reservoir while e Boscan field lies 40-km southwest of Maracaibo Venezuela and covers an area of approximately 660 km2 produces a 10.5ï¿½API gravi w profile is needed to determine the water producing intervals and come up with the best method to isolate that section. The production pro lights the application of a CT equipped with fiber optic advanced technology on a rigless water shut-off job. The paper also discusses the w oading Hydrocarbon/water loading in the wellbore Liquid banking in the near-wellbore region Liquid slugging in the wellbore/flowlines H he data for fully dispersed systems. The empirical correlation gave acceptable results. More data are needed to validate the results. Model nd petrochemical industries. Although the accurate prediction of oil/water flow is essential oil/water flow in pipes has not been explored as m e located either directly at the completion at the wellhead or along the tubing string or in combination of all.ï¿½These devices can measur 2 000 BOPD with no additional investment and reduced the assetâ€™s operational cost by more than USD$ 600 000 USD a year. This si ndensate from another zone. The evaluation is performed using multiphase thermal-hydraulic behavior in an Integrated Production Model (IP responsible for the changes in the waxy crude oil properties including the gelation of oil and an increase in viscosity. When the fluid tempe d concentrations by the laboratory data. Introduction In the development of deepwater prospects and other capital intensive exploration an quired to accurately measure and quantify CO2 concentrations in a number of reservoirs with varying fluid compositions. In this paper opera

ituations in which laboratory data are not available or before laboratory data are obtained. Laboratory measurements of dewpoint pressure ted by extracting the PVT properties of each sample at six different separator conditions. We then used multi-variable regression techniques ositional contrasts but in turn identifying these discontinuities may provide a means to identify compartments.ï¿½ Since many of these phy ement. A common method is to integrate all existing information on reservoir rock fluid and production data. These range from seismic geo egrated drilling fluid optimization new technology utilization operation best practices and real-time quality control and decision making. Su put and produces predictions of gas/oil ratio (GOR) a key PVT property used in real time to monitor a formation-tester sampling job. The AN havior. The numerical model was verified against analytical solutions for zeroth-order models for which analytical solutions exist. Simulation g the hydrocarbon column is imperative whether the prospect is in deep water or on the continental shelf. That is one can obtain a continuo

of wireline formation testing has been discussed in a number of publications concerning Downhole Fluid Analysis (DFA)1-4. It has been sho he design of the downhole tool in order to optimize sample recovery. We feel that this is a new level of refined utility for wireline formation te

e appropriately for fluids close to the spinodal curve (Lira-Galeana 1992). Equilibrium between gravitational and chemical forces of various eological and geochemical history of the reservoirs. One must distinguish compositional grading from the fluid property changes commonly e the use of WFT together with DFA has allowed identification and PVT property determination of a full range of downhole fluids including g ology. The concept of flexible fluid sampling is particularly important because it enables operators to make sampling decisions on the basis ure profiles have long been used as important tools for determination of reservoir pressure evaluation of fluid type from in-situ densities ide aking assessments and quality control of the different measurements and conclusions about the relevant reservoir heterogeneities. The me he sample which helps the operator maintain the fluid in a single phase during and after sampling. It also can aid in fingerprinting oils from d

ogy is presented to account for non-linearity in pressure gradients due to varying fluid density. We examine two field cases in which compos optical spectroscopy is invaluable downhole when determining hydrocarbon composition (e.g. amount of methane ethane propane) and th ces predictions of gas/oil ratio (GOR) a key PVT property used in real time to monitor a formation tester sampling job. The ANN also provid

est to yield the number of phases.ï¿½ Other methods include those discussed by Agarwal et al.3 which are based on successively calling a h temperature according to an Arrhenius relation while viscosities did not indicate any variation with flow rate (shear) within the range of tes

han traditional sampling methods. Downhole fluid analysis (DFA) can thus provide an additional source of information in the process of reve n the top end of the toolstring and the pump module was at the bottom. The basic principle used was that after cleaning up the pump was provides a comprehensive and accurate set of fluid properties for improved flow-rate measurement accuracy compared to conventional syst es bridging the gap in fluid sampling in a multiphase environment but also supplements for carrying out real-time compositional analysis and ion. The combination of these two attacks affects the reaction rate at moderate pH values. It is difficult to determine the overall diffusion coe cation of the technology to oil and gas wells and laboratory testing has been optimized through virtual geochemical simulation. Furthermore rs. Introduction In the execution of stimulation fluids for subterranean applications the two primary fluids that are most often injected down r the new product to be batch squeezed into the reservoir providing prolonged protection against salt deposition. Introduction Sodium chlo

e quantitative assessment of both damage zones . The implications of the results for productivity impairment and sand production will be di ed by the impact into rock of the high-velocity jet from a shaped-charge explosive.ï¿½This jet punches a hole at speeds sufficiently rapidly non-inhibited wells. At the same time the wells treated with scale inhibitor have provided not only sustained production but also a fourfold r surface facilities) can be easily controlled by the continuous injection of scale inhibitors. However the prevention of scale at the reservoir le he operation of the ICV and may in turn be affected by these produced water management issues.ï¿½This paper aims to demonstrate the solver the wells containing scale thicker than 0.25 are treated with downhole cleaning tools run on Coiled Tubing. In 2005 ten wells severe rawn for scale management in this and similar fields with high formation water calcium concentrations. Introduction The Gyda field lies o er to test the robustness of the approach zero transmissibility faults were deliberately created in the simulation study. The approach could s g the history match level Injection Production Ratios (IPR) are optimized and considerable amount of incremental oil production is obtained nagement. When the streamline technology should be considered in reservoir management. Introduction Reservoir management strateg vels. The numerical results show the impact of the small scale and large scale heterogeneities including in particular the channeling on the ates calculated at the well level. This surveillance methodology offers new perspectives for the proactive management of wellbore liquid-loa due to reservoir complexity. These complications have led to the introduction of pattern-based flooding technology and the establishment of mented within a diverse group of teams that have performance goals aligned with â€œbest practice has resulted in effectively re-balancing o 1 000 BOPD of extra-heavy oil with 50% lower horsepower requirements in comparison to those of conventional top-drive PCP systems. I period of time to accelerate production and pressure decline followed by a full implementation of a Steam Assisted Gravity Drainage (SAGD various technological and scientific fields in order to heat dielectric and on occasions non-dielectric materials (Haque 1999; Zlotorzynski 1 s project is based on the numerical simulation results from a representative model from one of the Faja main blocks using Eclipse Thermal ll and more so make production significant from the field. This paper highlights the learning curve of horizontal well drilling completion and pattern steam flood of a carbonate reservoir in the Middle East. Fig. 2 shows the locations of the LSP Steamflood project. Oil was first disc ellbore and fluids conditions the technique of combining probe and dual packer modules in one string and running the tool on TLC (tough lo

glad Basin which consists 3 main blocks -Fula-1 Fula Central and Fula North. Three reservoirs have been found by the exploratory and app

ction increased by as much as three- to eightfold. This study assesses the performance of the placement techniques and fluids used in the

found that the only solution was Venturi - multi energy gamma ray combination. This multiphase technology broke the extra heavy oil para

importance of secondary and tertiary reactions in determining the success of sandstone acidizing treatments.2-5 However for acid-sensitiv use of two downhole pumps also in a single string. The quality of sampling was controlled by application of downhole fluid analysis techniq

ructed based on interpreted results and sensitivities to model parameters estimated. The potential use of centrifuge data was investigated

ped.ï¿½ Mixed metal crosslinkers such as aluminum and Zr have also been formulated for this same purpose. This paper examines the di a solid-based acid system in the formation and the engineering steps taken to mitigate these challenges. Finally application limitations of th

e a reliable HPHT Digital Electric gauge system for gas wells below system was selected with Intellitite Welded connection. Introduction P ccessful in the Oligocene whereas different types of treatments like propped fracturing acid fracturing and acidizing have been tried in the B ested. Introduction The oil field is located in Maracaibo Venezuela.ï¿½The BHST in wells ranges from 220 oF to 240oF.ï¿½Most of the w arbonates diverting agents such as ball sealers viscoelastic surfactant diverters and foams (Coulter and Jennings 1997) are used to direc mplementation and results of the first VES HT fluid application in the El Tordillo field are presented in this paper. Four different zones were s s reservoir heterogeneity and the other forms of formation damage such as wettability alterations can increase the severity of trapping.[1] hole pH measurements made on the same formation water with a formation tester showed good agreement. This is an example of the imple

fine-grained tight-gas formation with clean sands often found to be interbedded with thin shale streaks at depths ranging from 6 500 to 8 5

pacts our development before we start the project. This project illustrates the challenges of the developments in a new environment where th und This area of study includes 3000 vertical feet of fluvial and marine sands located in the Rocky Mountain region of the United States. (F at a significant deviation of the field sector fracture azimuth from maximal regional stress exists. It was discovered that the degree of deviati ning stress contrast. The fracture network extension toward the maximum horizontal stress is however limited. This information is then used was more than double that of the offset wells average (163 MMscf versus 65 MMscf) and 88% higher than that of the best offset well. The p

The multilayer Foukanda field located 52km offshore from Pointe Noire Congo has a low permeability and virgin target that was conside que was used to stimulate a poor-performing horizontal well that was completed open-hole. The technique used a selective openhole comp antly from several high permeable layers M4 to M12 of the Ratawi Oolite carbonate reservoir commingled in both vertical and horizontal w in the US Rockies and their development is the core business of the US West Geomarket. Every well must be hydraulically fractured in mul ccording to the geological and petrophysical setting. After the wells are completed the use of production logs in stacked pay reservoirs ena to establish the effective global cell properties that are required to simulate the flow of hydrocarbons along the hydraulic fracture without us portions of the field produced from horizons that were previously bypassed.ï¿½ This process is useful for any highly laminated tight gas san

tial database for well completion decisions fracture reservoir modeling infill drilling plan and future horizontal well placement. Introduction o-pump configuration proved to be major operational factors in reducing the overall job duration rig time and smoothly achieving the requir hat characterize both their locally observed (in-well) and far-field properties. Introduction Large oil and gas accumulations have been discov outhwest Wyoming. Discovered in the 1950s it encompasses 1 700 square miles and is one of the largest tight gas resources in North Ame

s no stable flowing pressure. In the examples the WFT probe results are compared and validated with subsequent mobility measurements m ause most of the wells showed poor productivity index. Also 13 of the wells were dry holes. In 2002 the operator decided to acquire 900 sq ght-gas-sandstone reservoirs. The method will address all of the complex subjects that need to be considered for the successful placement form (Fig.1) was identified in 1973 while drilling the Kuyumbinskaya parametric well (K-1) which discovered the accumulation of gas with d

ughout the transition zone allowing a more reliable estimation of hydrocarbon in place and better well placement and production strategies. T

ng 3-4 folds compared to vertical wells. The paper illustrates how integration of different disciplines with focused efforts led to successful we

s discussion around heuristic intuitive as well as other mental strategies that exist placing focus on their individual strengths and weakness her words they are distortions in the way we perceive reality. There are many forms of cognitive bias but they can be separated into a few

e used to enhance the accuracy of the results from borehole NMR data Results from borehole NMR can be more representative of actual r ages. The stratified heterogeneity estimated from the ERA measurements was compared to and verified by open hole logs and core analys s and on the other hand both geological facies and petrophysical properties then these electrofacies are considered as valid reservoir roc in understanding the heterogeneities in the petrophysical properties of different sand bodies encountered in the study area. The control of s al approach based solely on open-hole logs. Introduction The wells studied are located in the Rhourde El Khrouf (RKF) field of the Berkine re and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes management.ï¿½ A common method is to integrate all existing information on reservoir rock fluid and production data. These range from s ification keeping in mind the following key objectives and needs. Robust permeability analysis from logs Understand reservoir productivity seismic interpretation; the discrete fault network of the area was analyzed by a process of automated fault identification. Though the differen sizes. Array propagation resistivity measurements and neutron-based measurements including neutron porosity neutron capture spectrosc In addition because of the move towards high angle and horizontal wells wireline formation evaluation acquisition has been at times rep

on saturation estimate due to uncertainty in the input data. In addition it can be considered as a useful screening tool to select the best sat ate due to uncertainty in the input data. In addition it can be considered as a useful screening tool to select the best saturation model to be hydrocarbon recovery and Masalmeh et al. (2003) examine the effect relative permeability and capillary pressure play in EOR. Several autho development / infill wells successfully. The areas that appear to have low dips turn out to have steep dips hence cause the wells to miss the or log derived permeability and rock type analysis in carbonates first developed in high porosity limestones can be successfully applied in t hinly bedded shaly sand reservoirs. Introduction Recent advances in NMR technology and signal processing have focused on measuring

point as well as a difficult case with multiple shale points are used to demonstrate the new workflow. In general we see improvements in the ation evaluation. es of completion optimization utilizing this integrated approach are also presented. 1. Introduction Although it is widely admitted that the pre using several field examples. Suspended solids pass through an inline filter sensor module where the particles are trapped and deposited cial fractures were found to be common in most of the wells where images were available mainly located within dense zones. Since fractur adations of carbonates in extensive shallow-water areas have been dominant where many fields are prolific producers. Previous studies in

nce coupling spatial and frequency characteristics of the geologic propensity and well-log data was developed which resulted in a more rea ed to measure accurate in-situ pressures in potential reservoir rock and to establish fluid gradients and identify contacts. Additionally local e. If the sand layer thickness is less than that distance the determined permeability of the sand-shale system will underestimate the true pe

ormation dips interpreted from the images. We demonstrate how improved accuracy allows filtering out the artifacts and provides more deci

opment such as hydraulic fracturing and growth of injection well fractures. This paper describes changes to these in-situ stresses induced b ¿½ Further shear velocity data is not always available from well logs making the problem more difficult.ï¿½ An extensive experimental prog data are significantly smaller in the depleted sand than in the overburden shale. However both the horizontal stress magnitudes increase ag ent performance.ï¿½ This relationship is presented in integral form in Eq. 1 and has been utilized for quite a long time1 in the analysis of the ent performance.ï¿½ This relationship is presented in integral form in Eq. 1 and has been utilized for quite a long time1 in the analysis of the ent performance.ï¿½ This relationship is presented in integral form in Eq. 1 and has been utilized for quite a long time1 in the analysis of the etween surface and borehole data and improve confidence in predicting fracture swarms away from the wellbore and also assist in planning e tested and the DST (Drill Steam Test) results proved the higher productivity than layer C which confirms the outcome from our integrated est producers in the field. As such we recommend application of the described integrated approach for modeling complex fractured reservo icantly more open than closed fractures while Lower Arab reservoirs appear to have equal proportions of closed and open fractures. Open lication of the described integrated approach for modeling complex fractured reservoirs in the other fields of Russian Federation. Introducti

nd pressure sensor experimental setup for estimating in-situ layer relative permeabilities and capillary pressure and monitoring water movem or is crucial for production strategies completion and facilities planning. Advancements in wireline formation testersâ€™ aide in overcoming turally affects the success of sampling and downhole fluid analysis performed subsequently after the probe pressure measurements.ï¿½ U

a better correlation among cores and NMR porosities it has been used a specific high resolution acquisition and processing method achiev and optimize pretest and sample points ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½- ï¿½ï¿½ï¿½ï¿½identify compositional oil gradients ï¿½ï¿½ï¿½ï¿½ï formation evaluation of shaly gas reservoirs in fresh formation water and demonstrate how the NMR data can be integrated into an existin speed of 900 feet per hour and a sampling interval of 18 inches each depth level of NMR data is measured in only six seconds. An equival nt of nuclear-magnetic-logging (NML) tools in the early 1960s. NML tools had many limitations and eventually were retired from service in th ia region of Argentina is an extensional basin developed over continental crust of Paleozoic age (Fig. 1). It is irregularly shaped being elong Since they have maximized reservoir contacts much more information is provided about reservoir characteristics and reservoir behavior du

omated and can be set up on a known or totally unknown reservoir model introducing an iterative and automatic updating process of the re s in a long horizontal well that posed a risk to data acquisition with standard wireline pipe conveyed logging. Introduction The Minagish (MN

ally taxing. Moreover interpretation of well test responses in turbidite and onlapping channel reservoirs can be highly non-unique due to the tivity) impacts all production strategies and therefore mandates the use of all sources of information that may help unravel reservoir comple performance. This relationship is presented in integral form in Eq. 1 and has been utilized for quite a long time1 in the analysis of the transie able field data. It is expected that the program once complete will lead to a better understanding of the depletion mechanism and help imp p unit. We will present each project and its impact on the improvement of WFT tester success ratio in such challenging environments. Intro

ter injection design and flood management fault activity wellbore stability casing design stress dependent rock properties reservoir subsi d cost consideration does not allow us to use these techniques as often as necessary. Wireline formation testers remove many of the restri points (NDP) over 10 reservoirs were designed. This infill drilling scheme will increase current reserves by 128%. Furthermore a gas injecti d in real time enabling more accurate preliminary hydrocarbon volume estimation as well as establishing with more confidence the perforat n due to insufficient lift gas and other constraints. Accordingly the Bokor Project Management Team (BPMT) which is an alliance between P the processing needs for the incremental oil water and gas production. Traditional optimization technologies were also revisited including itical operational constraint in dual string completions.ï¿½ The wells in which the valves have been installed show better stability in gas lift i highlight how these innovative technologies have impacted the stringer sand reservoir development in multiple offshore oil fields of Saudi A st and meeting the production goals. Introduction Eolian and fluvial channel sand deposits are significant petroleum exploration targets in m ating that we have accelerated gas production with some addition in reserves. 4) Central Compression system with an estimated project . This makes the process highly complex and iterative and thus represents a complex multidimensional optimization problem. In the curren only help in protecting the environment but is also attractive when there is an increase in energy demand. Introduction Optimization of gas s. To evaluate the performance of the smart well several sensitivities to the coupled model were made changing the opening valves positi eeded to couple different models and potentially tops-up with some global management tools that account for the coupling of the different m multidisciplinary practice which involves detailed numerical modeling of each system component and analysis of the economic impact of sig production potentials were re-tested in order to gather additional data and a water dumpflood pilot was implemented. Introduction and Fiel mplementation of all opportunities will produce sufficient information for optimizing infill drilling and work-over campaigns on Betty Field. The

models. The purpose of coupling is to balance a reservoir simulation model with the response of the surface facilities. The IAM consists of th management and surface facilities performance? Evaluation is achieved by constructing an integrated asset model of the entire field allo 2 000 BOPD with no additional investment and reduced the assetâ€™s operational cost by more than USD$ 600 000 USD a year. This si tion property population of static model and calibration of dynamic model. In the case of data collection information and data are gathered caliper data associated with the local probe sensors is used to gauge completion diameter and to help verify perforation depth. Performin

eld constraints. Introduction Khafji field lies in the Arabian Gulf 40 km east of Al-Khafji city Saudi Arabia (Fig. 1).The field is composed of f two previously discovered fields. Geological Overview Huizhou 6S and 3S oil fields are located in Pearl River Mouth basin South China S nits with a high condensate content produced from layers that are producing currently below dewpoint. On the other hand the Miqrat form permeability reservoirs which should prove highly beneficial to the petroleum industry. In fact the workflow would be useful toward obtainin rmed at a future date at some specified price. A natural question that arises is: what is the value to the client of entering into such a forward

e reservoir layer since the rate of increase in hydrocarbon production increases as horizontal length in the reservoir increases. We show an located 190 kilometers northeast of Aberdeen Scotland. Figure 1 shows the location of the Moray Firth Basin within the North Sea environ mprovement in field recovery factor as manifested by a higher and/or longer plateau for the case of irregular well placement.ï¿½The gain r l the well may have been sidetracked to the south resulting in a less-than-optimal well location. Introduction The implementation of perm us the E&P companies are coming back to their brown fields re-evaluating the remaining potentials as C.ï¿½ Sbiti stated in an interview with wnfield. The field is highly constrained with gas production which constitutes about 90% of the total field production. Crestal gas re-injection er several automated well-placement optimization methods are available in the literature. They can be classified broadly into two categories

ction behaviour under various operating conditions allows among other benefits proper investment decisions to be made. In order to make oir e.g. rock layering effects faults geomechanics etc. While such simulators will continue to play a crucial role for reservoir engineers it is riance models. Our proposed approach is computationally efficient and more importantly the CPU time scales linearly with respect to model roach using synthetic and pseudo field examples. The synthetic examples show the robustness and efficiency of our sensitivity calculation a

atistical covariance models. This approach mimics the face recognition" or the "voice recognition" technique which are already being succe

eckner 2001; Debaun 2005; Beckner 2006; Liu 2007). These papers noted that unstructured grids reduced simulation cycle-time significant mulation formulation normally refers to the equations and variables used to model the physical process and the numerical methods and tec Some simulator options such as multi-segment wells and PLT reporting have been applied to facilitate this calibration process. With this ca

tiple segments along the path of the wellbore. This option provides flexibility in the control of appropriate parameters by segment to properly

decline surveillance tools. There is clarification on when and where to reinitialise time to zero on the data points and also a discussion on ho elayed breakers (either oxidizers or enzymes) are added typically to the fluid (Economides and Nolte 2000). Injection of the viscous fracturi ng of formation damage processes in fractured wells. Furthermore the model enables the design of more successful fracture treatments in ones comprising of layer D. Carbonate reservoirs are inherently heterogeneous in nature in part due to the environments in which they are ed. Introduction Hydraulic fracturing has been proven to be one of the most effective methods for improvement of well deliverability in gas c nterfacial slip model and the measured data. A hydraulic fracturing simulator that includes an interfacial slip model can be used to better si simulation study conducted for multiple fracturing of a new horizontal well in the Dunbar Field operated by TOTAL E&P UK PLC. The obje

nally we use simulator-generated data to systematically investigate the effect of data availability i.e. the number of production logs and the pretation models and analyses that employ the dimensionless productivity index as the basis for improved fracture stimulation design. Dire izontal wellbore. Introduction Hydraulic fracturing of deep enough and highly deviated wells is known to potentially propagate transverse fra on how to avoid the worst case of the fracture initiation scenario. Introduction One of the main objectives of the hydraulic fracturing is to im methods and thereby narrow the work required to find a suitable ANN. In petroleum engineering and geosciences the number of data is

he severity of the phases being not in equilibrium due to the initialization by enumeration. Third we used fine gridding to capture the heterog ecause of slot constraints on the platform. In terms of pressure maintenance horizontal wells are also attractive. In saturated reservoirs in cept was developed to help this understanding. The concept was then applied to the mature waterflood in Casabe to gain new insights for th el fault blocks. The fluid properties in the field vary vertically with oil density gradually increasing from 35-37 ï¿½API in the deeper reservoirs e obtained using the traditional graphical method (F-We vs. Et) for volumetric oil reservoirs with minimal pressure and PVT data uncertainty. or selected wells; Rearrangement of existing water injection patterns within the development cells; Redistribution of water injection betwe nductivity between adjacent lithologies can result in a horizontal temperature gradient. Horizontal temperature gradients in some offshore fie gn ED and the associated response surface methodologies RSM offer a cost-effective and efficient way to assess the impact of uncertain

ogonal grids as well as for general orientation of the principal directions of the permeability tensor. A number of MPFA methods have been d a has been studied only in several papers4 6 12 15 17 and there is limited number of papers2 13 related to well testing in gas condensate fo erties can then be used in full field dual porosity simulations of fractured and vuggy reservoirs to correctly predict the oil recovery.ï¿½ The pr fractures. This strategy enables us to preserve the geological/geomechanical consistency throughout the history-matching process. The ge

ommercial simulator. The results from the streamline simulator for dual porosity show good agreement with those produced by a commercia needs to estimate the flow pattern in the reservoir quickly e.g. for ranking of geological models. Introduction The most common model for dels. In addition to sheer size strong heterogeneity in the geological models may create computational problems. Geological models may u

f. Two different proofs (Oliver 1996; Reynolds et al. 1999) have been presented which show that the RML method samples the posterior pro

eservoir scenarios. The calculations performed demonstrate where and under what conditions scale precipitation takes place in situ in the

ated by e.g. uncertainty analysis applications where an engineer wishes to test as many variations of a geological model as possible. A p CPU time for simulation impractical. Fully implicit finite difference schemes may use longer time steps but they deal with larger matrixes and nce of each type curve. The presented approach has been successfully applied for infill well selection in a statistical field development stud

d. There are multiple equi-probable geostatistical models possible each constrained to the given conditioning data. Continuous pressure da n reservoir simulation tools. Simulation tools that focus purely on the near-well region and wellbore flow can be used to design this type of a

etails required for an accurate prediction of well and reservoir behavior. Comparison of results obtained from a compositional model to those ion between Cw - obtained from a combination of wireline logs - and wettability measured on cores is found on data from a Middle East carb

ow rates of practical interests. The so-called non-Darcy flow in porous media occurs if the flow velocity becomes large enough so that Darc e reservoirs around the world. Such zones can have vertical extents of significantly more than 100ft. This is perhaps not surprising given th n this multi-well campaign. Introduction The Margham onshore gas field is a limestone reservoir that was first put on production in the early wells in GoS. Proper placement of well trajectory with respect to in situ stress reduces instability in drilling. The paper exhibits example of d processes are supported by detailed workflows with corresponding enabling technologies.ï¿½The business processes and workflows requi

and matured with similar timing over the past 40 years and government agencies for both provinces offer reliable public information.ï¿½T nted on these systems. Introduction The effect of pressure and temperature changes on the integrity of the cement sheath was demonstra

nalysis behind casing provides critical information to maximize oil production and facilitate water shutoff decisions. Introduction The field stu ed for commingled production from different reservoirs where accurate production allocation is a critical issue. Introduction Intelligent comp ing operations in the North Kuwait Fields and highlights the improved coiled tubing conveyed logging tool string and the recent interpretation es illustrating data quality and interpretation are provided. Introduction Chayvo wells have long sail sections at angles greater than 70ï¿½

vely manage the drawdowns when using the probe and also to allow sufficient flow rate when using the dual packer. We conclude with a su vely manage the drawdowns when using the probe and also to allow sufficient flow rate when using the dual packer. We conclude with a su The reservoir was primarily developed with horizontal well completions that intersect varying pressure zones caused by the steepness of th llows a more-accurate selection of appropriate completion materials and more-effective planning for scale treatment and inhibition. Introduc ew technologies develop. Completions may include downhole flow control fiber optic sensors sand-count devices or even multiphase flow c fracture systems propagated slower toward the west resulting in an asymmetric fracture with twice shorter western wing.Vertical propagati the assumption of a vertical fracture may be incorrect. Where this is true the indication of height control seen in these log types may be a

e injection of steam into the heel or toe of the injector well. Introduction The Joslyn field is situated west of the Athabasca River in Alberta y exists to continuously transport the produced well liquids to the surface.ï¿½ Multiphase flow velocities that are insufficient to continuously t nuously transport the produced well liquids to the surface. Multiphase flow velocities that are insufficient to continuously transport the produ optic measurements in these wells reduces operating costs and should ultimately lead to increased efficiency of reservoir stimulation pract

surface measurements (Lenn et al. 1998). A traditional method of flow analysis relies on routine periodic production testing through a separ

ddress the following topics: brief introduction of previous work processes and workflows descriptions technology available real-time enviro y. These wells have introduced new intervention challenges that have been addressed by the development of new technologies such as co ow regimes from infinite-acting radial flow to dual-layer and radial composite with or without sealing faults. From the SBHP data maps hav concluded that the high gas production from the toe could not be selectively shutoff or controlled in the horizontal openhole slotted liner com me capital investments beside reservoir management considerations. In this paper we are going to show how the cooperation between ex ng depths to several zones extending or shortening sampling times and repeating microhydraulic fracture reopening/closure cycles as wel ossflow with permanently installed distributed temperature monitoring. These models along with continuously monitored temperature profile development of heavy-oil reservoirs. Monitoring steam-chamber growth is critical to optimize heavy-oil recovery confine the stimulation to th ow profile and reservoir layer pressures. The use of permanently installed fiber-optic distributed temperature monitoring systems on its Aze ss in the subsea deployment. Field results showed that the mating inductive couplers provided high efficiency of power transmission so tha h fits better with the production profile and can then be used to evaluate the thief zones in a more quantitative manner.

s and data management. To fulfill this objective the paper will address the following topics: brief introduction of current work practice proce ris. Other candidate wells that would benefit from these concepts include those producing with large water cut where high water holdup and

stivity acquisition shows departure (lowering) of resistivity values against some perforated intervals. The zones were isolated after identificat arbonate reservoirs. Production Logging Tool (PLT) provides the injection profile along the perforated intervals or open hole where PLT refle oss-well Electro-magnetic (EM) resistivity technique will provide sufficient imaging information to track the water flood movement between w tential drawbacks include greater costs and higher local pressures which could induce uneven flows. Detailed pattern flood modeling helpe considering the targetâ€™s density and strength. The authors will provide insight into what may be the reasons for these unexpected resul is further validated from the fracture analysis using micro-resistivity image logs. Cleat orientation can be determined from the detailed struct from these adjacent coal seams is often masked by the fact that early in productive life of these clastic completions when the bottom hole p ment. These problems can cost operators an additional 25% per stage or more. Using these optimized strategies has reduced by 74% the n abric) and a favorable orientation of these with respect to the in-situ stresses(1).ï¿½ Field evidence from microseismic monitoring(2 3 4 5 6 een 0.1 and 2.5 meters. ( Fig 1 â€“ Horseshoe Canyon CBM log ) The production rates from these CBM wells dictates that a efficient drilling ulation staging and perforation placement strategies now utilize this information.ï¿½ In addition actual stimulation pressure responses and mulation. The application of this workflow in field studies has revealed important observations and provided better understanding of the rese mpletion strategy that demonstrates a strong potential to reduce SOR and ultimately operational cost. Incremental financial analysis is includ d Fujita 2001). Reservoir Fundamentals Coals are sedimentary rocks containing more than 50 wt% organic matter whereas shales conta fully applied to horizontal Barnett Shale wells. This paper demonstrates how real-time hydraulic fracture monitoring has enabled operators t nd provides an idea on how the treatment design can be improved. Introduction Acidizing oil and gas wells has frequently been viewed as nt handling during installations are being pursed. In addition tandem ESP completions and different types of wellhead penetrators are being

so enlisted. Introduction The venturi consist of a converging tube which is an efficient device in converting pressure head to velocity head a d recovery for low-permeability reservoirs. Horizontal completion in the oil-water zones reduces the rate of watering out and leads to longer e Morro do Barro Formation which were deposited in the space created by the erosive unconformity of the Tinharï¿½ Canyon of Rio da Ser e not needed to initiate fractures in the formations. This paper describes TAP Completions how the TAP valves work and how the valves p e of alteration to the formation. Dipole radial profiling then demonstrated that in fact a 5 inch altered zone was present in the unconsolidate er commingled gas reservoir that produces formation or wellbore condensed liquids.ï¿½ The multiphase flow and pressure traverse models er commingled gas reservoir that produces formation or wellbore condensed liquids.ï¿½ The multiphase flow and pressure traverse models based on LWD data and effectiveness of Internet-based platform for communication and decision-making process. Background Burgan F

ells and Smart Completion installations in Increment-2 were part of a proof of concept project to test and evaluate the impact of these techn trates the maximal benefit that may be obtained through downhole control thus providing a ready comparison with the cost of completion. MRC/ML wells and SC installations in Increment-2 were part of a proof-of-concept project to test and evaluate the impact of these technolo

rilling dual-lateral wells compared to the horizontal wells exceeding the optimum lengths. Introduction Recent advances in the capabilities determine reservoir characteristics under production conditions. In wells that will not naturally flow unpredictable results may be obtained. B a are scrutinized analyzed qualified and presented is influential to timely economic and accurate well and field design. This paper shows h fracture gradients encountered in this complex reservoir. Previous attempts to place proppant in other wells with similar reservoir characte fluids.1 Based on the 2005 core study results avoiding exposure to brine or any other water based fluids was the standard mode of operat

h Dakota The Bakken is a Mississippian/Devonian age boundary layer rock. There are differences between the productive Bakken Formatio meability by increasing mesh size and proppant concentration. The first five treatments performed have pushed the limits of the technology fibers degrade and hydrolyze with temperature and time so no reservoir damage occurs. This paper discusses the planning and design pr ional fracturing fluids may not suspend proppant for required time period and proppant settling during fracture closure results in considerab he other additives. The microemulsion and the oil-wetting additive had improved fluid loss in a fully formulated fracturing fluid. In spite of the in situ stress fracture toughness and layer interfaces on hydraulic fracture height containment in layered formations (Smith et al. 2001; Sim on Recent strategies in gas reservoir development in North America have been focused to refine completion processes and to increase effic n be managed at the well site many operators in the United States seek offsite management options for their waste. Offsite disposal compa ocuses on the Williams Fork Formation of the Mesaverde Group.ï¿½ The Williams Fork is a thick section of shale sandstone and coal dep intervals exceeding 90 ft rendered a 40% early wellbore screen-out rate. The early wellbore screen-out rate was reduced to 12% in a sampl f the solution which allowed the operating company to proceed with successful fracturing activity in the Ryabchyk formation. Introduction F treatments the combination of technologies allowed successful stimulation of the well with 20:1 permeability contrast. The last stabilized m oduction results obtained. All are characterized by the fluid usage contributing to the stimulation being uniformly conveyed across the oil-b ficiencies and reliability of this novel completion system as well as analyze the cost benefits and production increases that have been obse

mes results are disappointing. Nevertheless the completion technology tested by Saudi Aramco proved capable of overcoming most of the c

mpairment. In this paper we will describe the technology and processes brought to the project. Current results and impairment issues will als

of the pilot project is addressed as it sets a milestone in carbonate stimulation in the Volga-Urals basin. Introduction To understand the par

ulations vs. potential well production. One of the important parameters affecting production is the number of layers fractured during a single ned and the results indicated that high fracture initiation pressure is unlikely to be an issue with this completion method. Introduction Pe elastoplastic models are unclosed because the size of the plastic zone is undefined. Also they usually are finite element models and canno to the solution as shown in Figure 1.ï¿½ A variety of surfactant types can be used for formulating VES fluids including anionic surfactants

ty as shown by the shaded region of Fig. 1.ï¿½ It is estimated that these formations hold in excess of 10 Tcf of gas and 100 million barrels

al study. Introduction The Marrat reservoir in Magwa field of the Greater Burgan area has been producing since 1984 under a combination t from the full length of the fracture placed. This would either boost revenue by increasing production or decrease cost by placing smaller si microseismic fracture geometry and resultant production.ï¿½ An integrated analysis approach can provide an improved understanding of t

rements of the borehole inclination and azimuth which are then used to calculate the borehole trajectory) is done. Commonly monitoring ge

e face of the hydraulically induced fracture is expected to create lasting conductivity after fracture closure. However conductivity after fractu stry. Two basic methods were tested and combined: wellbore logging and passive seismic. Wellbore logging is used to obtain an estimate o n as desired. The additive used in this technology has been selected for a number of reasons not the least of which is its very short half-life

uctivity prediction was a main challenge in the recent stimulation campaigns of the Neocomian formation (Fig. 1) in the Yamburgskoe gas to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir. The fracture was explicitly described by the 2D pressure diffusion equation. The formation is elastic and fracture growth is based on linear elastic fracture mechanics. ce over a 2-3 year period compared to their offset wells. In the short-term (nearly 3 months production) 2 wells treated with viscoelastic acid troduces a way to evaluate and optimize the financial performance of fracture treatments. The financial criteria link the well deliverability or entation of a hydraulic fracture is through alignment of microseismic-event locations. Additionally microseismic-signal attributes such as th ed. It is shown that the selection of proppant properties is an efficient way to control flowback but obviously the requirement in terms of stre candidate selection and they are discussed for various reservoir scenarios. Introduction Previous work by Mack and Elbel1-2 showed that miscible displacement was investigated. Extensive direct numerical simulations allowed to investigate the sensitivity of the displacement proc pants and will cause an artificial barrier.ï¿½ Planar 3D models that incorporate stress detail moduli width calculation 2D flow proppant trac

on or decrease cost by placing smaller size treatments that would still deliver the same production as the larger less effective treatments. poroelastic effect. Then the remedial action was selected to overcome poroelastic behaviour in the Kikeh field. The operation procedure and nduced fractures in the zone below this fault â€“ resulting in almost 25 m of reservoir missed and (ii) the propagation of the hydraulic fractu ng information. For example microseismic monitoring provides information about fracture extent and orientation and monitoring fracture int means that auto gas lift belongs to the category of intelligent or smart wells. Auto gas lift systems can generate significant value by: 1. Incr tent (D < 44 microns) of 14 to 47%. From a sand size distribution standpoint based on available guidelines in the literature gravel packing oth sandstone and carbonate reservoirs. This innovative field proven system greatly increases the effectiveness of fracturing operations by oth sandstone and carbonate reservoirs. This innovative field proven system greatly increases the effectiveness of fracturing operations by ons the laboratory results and the effect of each taken step on well productivity are discussed in this paper. Overall results of the interventio rgets. The oil in the Shu'aiba formation is Arabian Extra Light with an average API of 42ï¿½ and a solution GOR (Gas-Oil-Ratio) of 750 SCF ata from the final logging operations. The real time logs were then evaluated while the well was drilled and used to refine the final simulatio wellbore without the need of intervention. Additional cost of the intelligent well completions was easily justified when compared to extremely

behavior is poorly understood. While reactive control strategies enhance production and mitigate reservoir uncertainty they may not delive odels that may represent the essential physics of the process. Many laboratory-scaled hydraulic fracturing tests on physical models have b

uct further engineering studies whenever required such as designing the injection and production test for multi-layer reservoirs and water o ons. This was also used to calibrate the 3D model and formulate a completion strategy to minimize sand production for the life of the field. T pose of matrix acidizing in cased and perforated wells in a carbonate reservoir is to create wormholes that extend the effective wellbore dra aracterized by two main fault systems: one main fault system that runs parallel to the northeast-southwest El Bourma regional fault and a se pump rate to generate its firing command providing reliable gun activation where as the drop ball mechanism in the past was found to have ed. The resulting gas production and zero perforation skin represented more than a two-fold productivity increase compared with the targe value in the 1600-md layer. Conventional underbalanced perforation employing multiple wireline runs could not achieve these low skin valu are aligned with the preferred fracture plane (PFP). The PFP is aligned with the maximum formation stress minimizing the forces that act to Dhabi.ï¿½ Background ADMA OPCO producing wells which are located offshore are matrix stimulated with acid prior to production. The s reservoirs based on the general convolution formula. The new solutions are applied to an integrated interpretation workflow to invert the s Talisman Malaysia Ltd. (TML) operates more than 130 wells in South China Sea. Previous perforating techniques on these oil gas produce riers stuck downhole. Maximized performance usually requires use of more powerful shaped charges or higher shot density of shaped charg

e same time minimizing damage to the rock matrix caused by the violent jet penetration event. For maximized penetration depth it is well kn ared to similar wells in the field perforated using the shoot pull and kill technique. Additional wells perforated using this technique show simi due to some operational problems and the well was completed with conventional completion consisting of one packer 4- 1/2 tailpipe and 7 ad to be addressed. The solutions developed to meet these multiple challenges will be presented in this paper. Introduction With an area o ure and â€“temperature and radioactive-tracer information and will discuss revised operational practices that resulted in zero- to negative-s cal well. This paper will describe the history of the well HWTH-34 and workoverâ€™s performed during its life span. It will also discuss the wo frac-pack/premium-screen sand failures workover planning and execution to remove tubing with multiple control lines and fish screens w d restore sand free production to recover remaining oil Sand production in various wells in the Niger Delta is often a result of low overburd

present the results of the application of a clean up fluid containing a chelating agent and an enzyme to dissolve the filter cake formed by the eservoirs and consequently sand control is required in all development wells. Each of the 5 fields is composed of multiple stacked reservoi

etric sand and shale interlayer. Slanted or sub-horizontal wells with open-hole through the reservoir can accomplish high production rates h itial packing takes place in the lower part of the horizontal well until the bottom is packed all the way to the toe (called the Alpha Wave) if ci ator was successfully used to design and execute the job. These case histories highlight the design methodology and show how with prope offshore Nigeria. The application resulted in the best producer in the field. This paper details the steps taken through the design and execu per foot of perforations. Discussion of the placement and production data is presented. Sand-free production has been achieved with reduc vel per foot of perforations. Discussion of the placement and production data is presented. Sand-free production has been achieved with red ng those predicted during pressure depletion. The laboratory conditions required to induce sand production were quite extreme and vastly e y time the ICD completion installation and performance evaluation is also discussed. Introduction Stag field background and reservoir cha ng the life of a well. The key factors that dictate the need for sand control are rock properties and well dynamics such as Unconfined Compr

ng issues in giant mature fields such as Sarir. Introduction Sanding is a major concern for AGOCO. Sand production can destroy electrical ods that are supported by the results from previously run rigorous and advanced numerical code. The result of this integration is a sanding udy highlighted the importance of a thorough investigation of the mechanism and source of sanding rather than premature conclusions bas hree stages: failure of the rocks surrounding an open hole or perforation detachment of sand grains from the failed materials and transpor

was possible to observe the failure behavior and sand transport during sanding experiments in different types of sandstones. Two different n The multi-field development consists of four gas fields located in Malay Basin South China Sea (Figure 1). The fields with varying volume Because these acid systems do not contain polymers there was no need to flow back water injectors. The spent acid in oil and gas wells wa al increase with acid contact time and in fact decreased at higher contact times with some fluid systems. This suggests that optimal times o d pay zone determination which has been improved by the utilization of resistivity imaging logs. Some examples presented contain informat er discusses the planning and design processes leading to the successful implementation of the technology the experience during the stim me thus leaving the reservoir undamaged. This paper discusses the planning and design processes leading to the successful implementat ocated in Kazakhstan. Producing intervals in the wells can be as long as 800 m at depths varying from 3800 m to 5500 m producing 47ï¿ onded well to the prescribed treatment: Well A tested an 269 ft measured depth (MD) or 194 ft true vertical depth (TVD) perforated interval o

ccess ratio of the sandstone acidizing treatments. Significance: Developed lessons learnt to increase the success ratio of sandstone stimula

m carbonate reservoirs are often stimulated with small quantities of hydrochloric acid and in most of the cases relevant increases in hydroc o organic acid ratio are needed to better design field treatments. Recommendations are given on what and how laboratory evaluation shou

ng treatments performed using this technique resulted in negative skin factors and production ratios that exceeded expectations. Introductio ng how chemical diverters interact with the formation rock and fluid is the key to selecting the proper product for a specific treatment. It is th ging deep oil reservoirs using numerous fluid systems such as foamed visco-elastic surfactants to stable- and super-foams. Introduction M vity.ï¿½ Injection at a high flow rate ensured uniform dissolution of the medium.ï¿½ Porosity was monitored by analysis of the effluent and p restimulation. The conclusions of this paper are based on our work in selecting restimulation candidates as well as published results of othe ator in the Big Horn basin has recently been using a polymer-free viscoelastic surfactant-based fracturing fluid that is compatible with carbon xtending the Cave Gulch (shallow) accumulation to the southeast and northwest. The Waltman-Cave Gulch complex is located on the Waltm d and also to general considerations of poorly understood formation deliverability. Fracturing treatments discussed in this paper were urge

ormation has been under water flooding since 1997 in order to sustain the reservoir pressure and field production. However water breakthr (2) physical communication tests between formations and (3) cement bond log interpretation. Pressure tests are restricted to localized are er tests (CCTs) are attractive due to their simplicity reliability and reduced impact on the environment. However the existing methods used well characterizing the effects of the natural fractures on production behavior as well as quantifying reserves for this tight reservoir. Introdu ctures where other forms of conventional reservoir characterization techniques are technically difficult and/or cost-prohibitive. The optimizat esting option and two wells were analyzed. In the first well MLT testing showed that one of the layers had a very high permeability compare ese parameters are then used to estimate vertical permeability anisotropy index and skin.ï¿½ï¿½ï¿½ For a naturally fractured formation t stem test (DST) or production tests.ï¿½Therefore how far pressure may diffuse (radius of investigation) during a transient test is very impo e test was decided in real time to make sure that the test was long enough to meet the objectives but not too long to increase the cost witho ly and obtain the underlying well/reservoir model (in the form of a constant rate pressure response). New methods of analyzing well-test da

lysis has also been performed on fracture permeability fracture porosity and matrix block size in real simulation models in order to show im from mini-DSTs in thinly laminated deepwater reservoirs are then compared with other available static and dynamic reservoir information su OFP for multiple zones using commingled approach. Furthermore we also included production tubular and choke in our simulation model fo ing solution used in this trial can be used successfully and is presenting a reliable alternative or complement to conventional test separators he multiphase flowmeter and thus the correct computation of gas and condensate rates are presented and a number of solutions are descr

est campaign was 0.54. The comparison was made on twelve wells producing to X Field station. Each well was tested for 12 hours in series eservoir parameters PVT composition and production back-allocation performance is one of the key parts of gas-condensate field developm s-well testing and production allocation applications without the use of separators. Introduction There has been considerable focus in rece gas production. In addition to the above findings phase testers helped in reservoir management decisions and optimization of testing durat

Vx technology in Gas Mode in 2005. Exceptional results against conventional test separator have been presented in previous paper (Ref [10 e effect of the geological model upon the well test response 2. The conditioning of geo-statistically generated geologic models to well test preference â€” there is no substantive difference in the application of these functions. Some analysts prefer the "pressure" analysis format b tware.2â€“6 In many situations however the derivative of the measured data is uninterpretable or worse mis-interpreted because of variou o test the utility and reliability of electrode arrays to measure streaming potential. Vertical Well Cemented Arrays Electrode arrays were per

nt that can lead to set cement properties that are very different from their design value. Density control problems (both for continuous and ba age performance. It must be evidenced that CO2 will and indeed does remain within the intended repository. In particular seal integrity mu s to optimize interventions in time. This approach is successfully applied leading to recommendations for safer and more efficient design m etwork scenarios. Introduction Global warming is becoming one of the most important problems of the mankind. Precipitations have been r this paper we focus on injection into saline aquifers al-though the discussion and results presented herein may be useful for certain aspec boratory and well logging analysis predominantly for the reservoir/storage section of the Ketzin site. This method was successfully applied in training. In our paper framework of CO2 sequestration and vital aspects such as; site selection reservoir characterization modeling of st cal Earth Model can be used to develop operating envelopes for well placement hydraulic fracturing and CO2 injection that best ensure co

DU with a 9 km long subsea pipeline. The well in this case history is a world record ERD well drilled from a floating installation. In the early ster than prognosed. Initial production testing was higher than expectation. Introduction This paper uses a case study to highlight the benef

ew oil fields have been located within the US. Many existing fields are older and these have significant potential for enhanced oil recovery. O n reserves of 1.9 Tscf of CO2; however this volume could be extended to larger amounts associated to areas under study. The CO2 from Q xas has been exploited since the 1920s and is still a prolific producer with over 20 Bcf per year average rate (Fig. 1). The play has seen bo nce the mid-1950â€™s oil companies have reentered old wells and drilled sidetracks to bypass formation damage or wellbore mechanica ve recovery methods based on the ever present gravitational segregation effects using steam injection and the favorable reduction in oil vi ensely fractured than lower layers E3/E4 F and G reservoirs. Initial production from the reservoirs (1967 to 1970) was by natural depletion

the composition petrophysical characteristics but also were principal causes creating good reservoir properties of some granitoid baseme he biggest challenge remains the nonï¿½productive time due to the tools reliability especially in harsh HPHT (high-pressure high temperat ted. The objective of the cement-water shutoff was to ensure that the perforations which were flushed were completely sealed off and iso ontally at the top 50 ft reservoir while the remaining footage was drilled slanted across the same reservoir for evaluation purposes (Fig. 1). km2 produces a 10.5ï¿½API gravity asphaltic oil from the upper Eocene Boscan (Misoa) Formation with a live oil viscosity ranging from 2 late that section. The production profile indicated that water production is from the toe of the horizontal open hole section. Job Objective an ob. The paper also discusses the water shut-off (WSO) job design and execution challenges. Introduction Drilling horizontal wells become d slugging in the wellbore/flowlines Hydrocarbon solids Asphaletenes Waxes Hydrates Dimondoids Heavy oil/emulsions Among all th eeded to validate the results. Model comparisons revealed that none of the models could represent the experimental data accurately. This p in pipes has not been explored as much as gas/liquid flow. Models developed for gas/liquid systems cannot be readily used in liquid/liquid o f all.ï¿½These devices can measure the pressure temperature and the flow rate.ï¿½Although technically possible the latter is rarely used n USD$ 600 000 USD a year. This simulation tool also proved to be very valuable for early identification of well optimization opportunities st n an Integrated Production Model (IPM) that provides system deliverability predictions through the lifetime of the project coupled with aspha se in viscosity. When the fluid temperature falls below the WAT there is the possibility of wax deposition on the tubing/pipelines. Wax depos ther capital intensive exploration and production projects understanding the nature of hydrocarbon fluids in terms of chemical and physical uid compositions. In this paper operational considerations and challenges of acquiring high quality PVT samples for different reservoir fluids

measurements of dewpoint pressure and other gas properties of 615 gas condensates with worldwide origins were used to develop a dewpo multi-variable regression techniques to calculate our correlation constants. The new correlations were validated using the generalized mate ments.ï¿½ Since many of these physics mechanisms that produce compositional variation are time dependent the existence of fluid distrib data. These range from seismic geological and petrophysical data core analysis well tests and production data. However in complex reser lity control and decision making. Such an approach ensured reliable rock and fluid data thus minimizing technical risks and maximizing the rmation-tester sampling job. The ANN also provides an uncertainty estimation of its outputs as a quality-assurance indicator. We compare A analytical solutions exist. Simulation results exhibited close agreement with the analytical predictions and with field data for the time depend lf. That is one can obtain a continuous downhole fluid log. This log records (vertical) composition variation along with some indications of c

Analysis (DFA)1-4. It has been shown that compartmentalization and compositional variation can be positively identified. This evaluation ca efined utility for wireline formation testers in approaching well test functionalities. Introduction H2S is an extremely hazardous toxic compo

onal and chemical forces of various hydrocarbon components results in a variable saturation pressure in a fluid column (Schulte 1980; Riem he fluid property changes commonly observed in vertically stacked reservoirs. For instance the fill/spill mechanism at work in many stacked range of downhole fluids including gas retrograde gas volatile oil and black oil. This suggests a number of compartments in such complex ake sampling decisions on the basis of real-time fluid-analysis results rather than a predetermined job plan. Introduction It is known that so of fluid type from in-situ densities identification of fluid contacts and differential depletion and inter-reservoir connectivity. Pressure profiles nt reservoir heterogeneities. The method is illustrated with a published case study [1] from a North Sea appraisal well where a large compo o can aid in fingerprinting oils from different layers and provides early indications of GOR that can be compared to PVT lab results. Both th

mine two field cases in which compositional gradients were observed with both downhole fluid analysis measurements and pressure gradien of methane ethane propane) and the GOR a parameter that plays an important role in the design of surface facilities (Mullins et al. 2005a; r sampling job. The ANN also provides an uncertainty estimation of its outputs as a quality assurance indicator. We compare ANN results w

are based on successively calling a (P T) flash in order to match a given total enthalpy simultaneously solving an energy balance equation w rate (shear) within the range of tested flow rates. Measured viscosities also increased as pressure decreased below the bubblepoint of the

of information in the process of revealing complex reservoir architectures. Introduction An accurate description of reservoir fluid properties at after cleaning up the pump was stopped for a couple of minutes allowing the fluid to be stationary in the tool flowline thereby letting any uracy compared to conventional systems. Overview Multiphase flow meters (MFM) have been accepted now by the oil industry (Ref. [11] [1 real-time compositional analysis and basic Pressure-Volume-Temperature (PVT) measurements at wellsite allowing to compute improved f o determine the overall diffusion coefficient of reactants or products if multiple types of calcium species are present at moderate pH values. geochemical simulation. Furthermore the operational risk of stimulation treatment is reduced where no cores are available such as old well ds that are most often injected downhole are either hydraulic fracturing fluids or matrix acidizing fluids.ï¿½ In hydraulic fracturing the fluid is eposition. Introduction Sodium chloride is the most common salt present in formation waters. For high salinity brines (>200 000 mg/L) or fo

ment and sand production will be discussed. 1. Introduction Shaped-charge perforating subjects the rock to extensive pressures and impa a hole at speeds sufficiently rapidly that the displacement of the rock is achieved by the creation of a large number of microfractures exten ained production but also a fourfold reduction in operating cost confirming the success of the pilot project. Introduction The prerequisite con prevention of scale at the reservoir level (such as reservoir matrix fracture surface and proppant filled fracture) is more challenging due to th This paper aims to demonstrate the possible benefits that can be added to scale management as result of using ICV technology.ï¿½It also d Tubing. In 2005 ten wells severely scaled with Strontium Sulphate were mechanically treated using Coiled Tubing Mills and motor high Introduction The Gyda field lies on the north-eastern margin of the North Sea Central Trough on the Norwegian Continental Shelf 270 mulation study. The approach could successfully delineate the regions across the faults. Introduction The objective of history matching is to ncremental oil production is obtained. Introduction In a naturally fractured reservoir a representative fracture model is essential for achievin tion Reservoir management strategies have evolved over the last sixty years from the days of purely analytic and analog approaches to th g in particular the channeling on the fluid breakthrough problem. The findings and the critical assessment concerning the impact of cavities e management of wellbore liquid-loading problems in large fields with very limited data stream. The early-stage diagnosis of problems enab echnology and the establishment of the water injection (WI) and WAG pilots in the underswept lower units of the reservoir. The benefits of s resulted in effectively re-balancing this major waterflood. This effective integration of teams retains the flexibility to adjust for an ongoing d nventional top-drive PCP systems. Introduction The Orinoco oil belt is located on the northern side of the lower Orinoco River in eastern Ve m Assisted Gravity Drainage (SAGD) process. The third part of the paper covers basic economical analyses perfor ed using estimated capi aterials (Haque 1999; Zlotorzynski 1995). Thus processes such as the drying and heating of minerals and inorganic products the carbothe main blocks using Eclipse Thermal applied to medium thickness sands in the 20-50 net ft range. A five-horizontal well array set up was use rizontal well drilling completion and production of viscous oil field in Muglad basin. Introduction Umm Bareira is a small heavy oil field in Mu teamflood project. Oil was first discovered in the 1st Eocene in 1954 and full scale development began in 1956. The 1st Eocene has produ and running the tool on TLC (tough logging conditions) has been applied successfully to a thinly reservoirs formations with low permeability

en found by the exploratory and appraisal wells in the area. Bentiu formation is the main reservoir in Fula Oilfield with massive lose sand an

nt techniques and fluids used in the stimulation of the Nukhul formation based on field data. It also quantifies the economical added value r

ology broke the extra heavy oil paradigm related to multiphase technology to measure flow rates accurately and a comparative test were ca

ments.2-5 However for acid-sensitive aluminosilicates these reactions are especially important because they occur at much shorter time-sc n of downhole fluid analysis techniques. Comprehensive pre-job planning close cooperation with drilling and operating companiesâ€™ rep

of centrifuge data was investigated as an additional fluid characterization tool to construct more realistic reservoir fluid models for graded re

urpose. This paper examines the disadvantages of these strategies and describes the development and deployment of a high-temperature . Finally application limitations of the system will be discussed. Introduction Hydrochloric acid (HCl) is widely used to stimulate oil and gas

Welded connection. Introduction Permanent Down Hole Monitoring System real-time reservoir and production monitoring system helps op nd acidizing have been tried in the Basement with limited success. Finally the lessons learned and the experiences gained in this field are s m 220 oF to 240oF.ï¿½Most of the wells have numerous perforated intervals stretching up to 1000 ft (of which up to 500 ft is perforated).ï¿ nd Jennings 1997) are used to direct some of the acid flow away from large channels that may form initially and take all of the subsequent a is paper. Four different zones were successfully treated in the first well application at various reservoir conditions presenting a wide range o increase the severity of trapping.[1] Experimental studies by Kamath and Laroche [7] and Mahadevan and Sharma[8 9] have shown that r ment. This is an example of the implementation of the chain of custody concept which compares a measurement made downhole with that m

at depths ranging from 6 500 to 8 500 ft TVD.ï¿½ Permeability ranges between 0.03 md and 1.1md while porosity values lie between 4% a

ments in a new environment where the services and technology have not matured to the North America levels. A key conclusion of the paper ntain region of the United States. (Figure 1) The formation contains natural fractures laterally restricted lenticular sandstones and tight britt discovered that the degree of deviation from the regional preferred fracture azimuth is affected by water injection and reservoir fluid producti mited. This information is then used as the input of the model to carry out forward simulations and provide detailed information of time-depe han that of the best offset well. The polymer concentration was lowered to ensure better and earlier cleanup. On the next well drilled in the a

y and virgin target that was considered noncommercial after discouraging results of two wells. Based on the production results of three case ue used a selective openhole completion tool that can allow the wellbore mechanical isolation into four intervals based on reservoir evaluat gled in both vertical and horizontal wells. Permeability from these layers range from 300 to 1 000 md. Beginning in 2004 new horizontal and ust be hydraulically fractured in multiple stages to obtain economic production. Field developments have been based on designs and foreca on logs in stacked pay reservoirs enables the use of rate-&-pressure transient analysis and history matching techniques to evaluate fracture ong the hydraulic fracture without using the local grid refinements. Production and pressure performance over a long period of time were com or any highly laminated tight gas sand sequence and is of widespread applicability. Previously bypassed intervals can now be assessed and

zontal well placement. Introduction The fractured Jurassic tight and deep carbonate reservoirs including Janmah-Sargelu (NJ-SR) and Mar e and smoothly achieving the required objectives. As the results a record job including 27 DFA stations (16 with samples) 2 mini-frac stati gas accumulations have been discovered in tight sandstone reservoirs of the Algerian Paleozoic sedimentary basins over the past fifty years est tight gas resources in North America. The field area has produced 2 TCF from over two thousand wells since discovery in the late 1950

ubsequent mobility measurements made with inflatable dual packers. Introduction All probe type formation testing tools utilize the same pri operator decided to acquire 900 sq. km of 3D survey in the area where the wells showed higher productivity indices. The 3D seismic allow idered for the successful placement and completion of a horizontal well including reservoir description (both static and dynamic) well desig ered the accumulation of gas with daily flowrate of 200 thousand cubic meters under the clastic Vendian sediments in the carbonate depos

acement and production strategies. This process yields considerable cost savings especially by avoiding expensive production tests. Introd

focused efforts led to successful well placement sand and water management in heavy oil environment and also oil production from tight fo

r individual strengths and weaknesses. Intuitive and Formalized Approaches for Multicriteria Decision-Making Multicriteria decision-making ut they can be separated into a few groups: Behavioral biases influence how we form our beliefs. An example is the illusion of controlling s

n be more representative of actual reservoir properties in vuggy carbonates than those obtained from SCAL measurements on core plugs o d by open hole logs and core analyses. The final heterogeneous reservoir model from ERA was subsequently applied to a numerical simula are considered as valid reservoir rock types (RRT). The electrofacies defined from conventional logs at each well are then propagated into a ed in the study area. The control of sedimentary depositional environment in spatial distribution of sand bodies and their geometries is bette El Khrouf (RKF) field of the Berkine Algerian basin (Figure-1). Oil was first discovered in this field in the early to mid 90s in the Triassic Argi combined in a package that includes the optical spectrometers and measurements of fluid resistivity pressure temperature and fluorescen production data. These range from seismic geological and petrophysical data core analysis well tests and production data.ï¿½ However in gs Understand reservoir productivity by studying the linkage between log data to hydraulic properties of the carbonate reservoir Permeabil ult identification. Though the difference in the OWC encountered in the wells could be explained based on the sealing faults barriers picked n porosity neutron capture spectroscopy and formation capture cross section are colocated in the top half of the tool with the highest mea acquisition has been at times replaced by LWD. The new LWD tool allowed the operator to not only improve efficiency but also brough

screening tool to select the best saturation model to be used depending on the input data uncertainty. Introduction The electric log in the o ect the best saturation model to be used depending on the input data uncertainty. Introduction The electric log in the oil industry is the mos pressure play in EOR. Several authors Gyllensten et al. (1999) and Haro (2004) have proposed various methods for estimating permeabilit ps hence cause the wells to miss the targeted reservoirs or oil column even if they have penetrated the reservoir. To get to the reservoir suc nes can be successfully applied in this lower porosity (10 - 20 p.u.) carbonate.ï¿½ This gives us confidence to project that the method coul essing have focused on measuring reservoir fluids volumes and properties in-situ and on identifying reserves in thinly laminated reservoirs

general we see improvements in the estimation of the hydrocarbon in place; however not all thin beds offer large hydrocarbon volumes. In

ough it is widely admitted that the presence of fractures (natural and hydraulic) is directly linked to the production of the hydrocarbon trapped particles are trapped and deposited allowing fluid with little or no particles to pass through the formation tester tool. This results in greater r ed within dense zones. Since fractures in these dense zones play an important role in communication between different reservoirs the abilit olific producers. Previous studies in the Arabian Gulf (Al-Fares et al.1998) critically investigate the Cretaceous platform edge consisting of w

eloped which resulted in a more realistic model. The history match and production performance forecast using the new model was straightfo identify contacts. Additionally local formation permeability is estimated from analyses of pretests and is used to verify the productivity of th ystem will underestimate the true permeability of the sands. Using a fluid flow model we show that the permeability of the sand component

the artifacts and provides more decisive and accurate identification of geologic features. We show how using the corrected 3D position imp

s to these in-situ stresses induced by fluid injection or production in horizontal wells. In-situ stresses around a wellbore are altered because ï¿½ An extensive experimental program was carried out first to obtain the static values of elastic parameters of reservoir rock samples at re ontal stress magnitudes increase again in the shale below the depleted sand. Such rapid variations in horizontal stress magnitudes cause l ite a long time1 in the analysis of the transient pressure behavior of oil and gas wells. ite a long time1 in the analysis of the transient pressure behavior of oil and gas wells. ite a long time1 in the analysis of the transient pressure behavior of oil and gas wells. (1) The dimensionless wellbore pressure at any poin wellbore and also assist in planning of future surface seismic and 3D VSP surveys. ms the outcome from our integrated study. Introduction NWO-1 well drilled in Northwest October Concession is located at the central tecto modeling complex fractured reservoirs in the other fields of Russian Federation. Introduction The field was discovered back in 1974 by the of closed and open fractures. Open fractures show a dominant NE-SW strike direction for most of the wells both in the Upper and Lower Ar ds of Russian Federation. Introduction The Maloichskoe field was discovered back in 1974 by the exploration well 2 which was drilled in th

ressure and monitoring water movement inside the formation. This allowed multiphase characterization of the formation around the measur ation testersâ€™ aide in overcoming the challenges brought by complex and heterogeneous reservoirs. obe pressure measurements.ï¿½ Until recently higher temperatures six inch hole size and Oil Based Mud (OBM) limited the use of dual p

tion and processing method achieving continuous porosity measurements with a dynamic vertical resolution of 22 inches more suitable to itional oil gradients ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½- ï¿½ï¿½ï¿½ï¿½identify fluid differences that highlight potential reservoir compartmental ata can be integrated into an existing petrophysical analysis improving the accuracy of results in this challenging environment. ured in only six seconds. An equivalent NMR measurement on a single core sample in the lab is allotted minutes or even hours to achieve a ntually were retired from service in the late 1980s. In spite of these limitations laboratory research conducted to support NML logging antic ). It is irregularly shaped being elongated in the east-west direction. The main filling of the basin occurred during the Late Jurassic and Cret acteristics and reservoir behavior during production or injection. This information is valuable for better understanding thus managing the re

automatic updating process of the reservoir model. Introduction In recent years UBD has become a popular technology. Originally applied ing. Introduction The Minagish (MN) field in West Kuwait is a North-South trending anticline (Fig.1) with hydrocarbons contained in six ma

can be highly non-unique due to the complex architecture of such reservoirs. Today novel techniques such as Downhole Fluid Analysis (DF at may help unravel reservoir complexities. One key and relatively new technology that is increasingly exploited for reservoir characterization g time1 in the analysis of the transient pressure behavior of oil and gas wells. Equation (1) The dimensionless wellbore pressure at any po e depletion mechanism and help improve ultimate recovery of As Sarah field. Some of the methodologies described in this paper may be of uch challenging environments. Introduction The predominant sedimentary features in the reservoirs we focus are very thinly laminated sha

dent rock properties reservoir subsidence and obtaining data for coupled geomechanical and fluid flow simulation are common reasons.ï¿½ on testers remove many of the restrictions imposed upon by conventional well tests and require special models. While the theory of pressur by 128%. Furthermore a gas injection scheme identified as the optimum plan for A6.0 reservoir will increase current reserves by 28%. Field ng with more confidence the perforating strategy over the main producing intervals. For the first two wells of the field appraisal campaign sa PMT) which is an alliance between PCSB and Schlumberger is tasked with developing initiatives to improve field performance. One such i ogies were also revisited including the hydraulic fracturing of the infill wells to attain initial productivity gains of 25% with respect to that of c alled show better stability in gas lift injection rates and casing head pressure as compared to previous installed â€œconventional valves.ï¿½ multiple offshore oil fields of Saudi Arabia. Introduction With the growing demand for energy pressure is mounting to improve recovery fac ant petroleum exploration targets in many basins around the world.ï¿½ The quality of sand and stratigraphic hydrocarbon trapping mechanis on system with an estimated project cost of $12 million was found uneconomical. 5) Individual well site compression was more economic optimization problem. In the current standard industry practice the full production potential of these reservoirs is often not realized becaus nd. Introduction Optimization of gas handling operations is one of the key elements to increase total oil recovery from thin oil reservoir field changing the opening valves position at the beginning of the forecast. An increment in the cumulative oil production was observed when th nt for the coupling of the different models. The different models involved in the coupled scheme might have substantially different FM capab nalysis of the economic impact of significant capital expenditure projects. During this cycle various field development strategies are evaluat implemented. Introduction and Field Overview The Betty field is located 40 km offshore Miri in the Baram Delta area of Sarawak Malaysia -over campaigns on Betty Field. The application of this innovative approach to brownfields helped identifying new opportunities which have

face facilities. The IAM consists of three distinct parts: The reservoir model the well model and the surface facility model. These three mod asset model of the entire field allowing the reservoir through facilities interaction to be evaluated in detail. Introduction Everybody want n USD$ 600 000 USD a year. This simulation tool also proved to be very valuable for early identification of well optimization opportunities st n information and data are gathered and screened.ï¿½ If data are not consistent or missing those data are flagged to exhibit a problem for verify perforation depth. Performing production logging in this challenging environment requires detailed prejob planning and careful job e

bia (Fig. 1).The field is composed of several reservoirs for sweet crude. The most prolific ones are 1st and 2nd Bahrain sand. Where a stro rl River Mouth basin South China Sea which is a continental margin sedimentary basin formed during the rifting of the South China Sea in t. On the other hand the Miqrat formation found at depths >5100 m produces lean or dry gas. The combination of relatively low and heter low would be useful toward obtaining correct reserves estimations for virtually any low permeability gas field where production from several client of entering into such a forward contract? In this paper we address this question in the case where the service to be performed provid

he reservoir increases. We show an example of how advanced well placement technology was successful in doubling hydrocarbon producti h Basin within the North Sea environment. Both oil and gas are produced from the Outer Moray Firth Basin from both Paleocene and Jurass gular well placement.ï¿½The gain reveals the large impact that may result from the systematic use of automatic history-matching technique duction The implementation of permanent downhole pressure gauges (PDGs) has provided a new source of highly valuable pressure tran C.ï¿½ Sbiti stated in an interview with the Petroleum Economist2.ï¿½ Today already ~70% of the world oil production is coming from brown d production. Crestal gas re-injection is ongoing as a pressure maintenance effort. Most wells are completed in commingle horizontal wells. classified broadly into two categories. The first category consists of local methods such as finite-difference-gradient (FDG) (Bangerth et al. 2

cisions to be made. In order to make such a prediction one must construct a reservoir model. History matching observed behaviour of the r ucial role for reservoir engineers it is well known that to use these tools requires much time and expertise. Indeed even for a well trained en scales linearly with respect to model size making it particularly well-suited for large-scale field applications.ï¿½ We demonstrate the power ciency of our sensitivity calculation approach compared to the perturbation. The pseudo-field example has 10 years of production history w

nique which are already being successfully applied in their respective domains. The proposed technique has been successfully tested in a f

ced simulation cycle-time significantly via integration with geologic models. On the other hand unstructured grids can achieve accurate geo and the numerical methods and techniques used to solve the discrete system of nonlinear and linear equations. In reservoir simulation the his calibration process. With this calibration history matching becomes a more guided process and the resulting model is more consistent

e parameters by segment to properly simulate the different issues that arise with horizontal/multi-lateral wells.ï¿½ In addition local grid refin

a points and also a discussion on how to determine the dominant flow regime from the production data. The sequential and systematic appli 00). Injection of the viscous fracturing fluid results in fluid loss to the matrix and filter-cake formation. Filter cakes with high polymer concen re successful fracture treatments in tight-gas reservoirs. Introduction Evaluation of postfracture performance has been the subject of ex the environments in which they are deposited and their subsequent diagenetic alteration. Layer D in this region is characterized by contras ovement of well deliverability in gas condensate formation. Carlson and Maer1 and Settari et. al2 showed that loss in well productivity due to l slip model can be used to better simulate fracturing in coalbed methane and other formations where slip between bedding planes is possib d by TOTAL E&P UK PLC. The objectives of the study were to assess the feasibility of fracturing to determine the optimum number of par

number of production logs and the duration of the production period on the accuracy of the computed reservoir/completion parameters. Pr ed fracture stimulation design. Direct field applications of this fracture stimulation design technique have been reported in the literature for o potentially propagate transverse fractures the wellbore axis not being contained in the fracture plane. In order to prevent the initiation of se es of the hydraulic fracturing is to improve the natural connection of the wellbore to the reservoir. Near-wellbore effects play a key role in es geosciences the number of data is limited in many cases because of expense or logistical limitations (e.g. limited core poor borehole con

d fine gridding to capture the heterogeneous variation in property. To reduce the CPU time for running one single fine grid model we divided attractive. In saturated reservoirs in which voidage replacement is fundamental to achieve a good recovery factor horizontal wells help ach n Casabe to gain new insights for the field redevelopment plan. 5-37 ï¿½API in the deeper reservoirs to 19 ï¿½API in the shallow reservoirs. Most reservoirs have an initial gas cap with the ratio of gas cap pressure and PVT data uncertainty. In those cases with moderate to significant water influx and gas cap and some uncertainty on pressure edistribution of water injection between the development cells. Field Brief The field is being developed since 1970. A total of 1419 wells we rature gradients in some offshore fields can be observed because of a constant water temperature (approximately 4ï¿½C) in different depth ay to assess the impact of uncertainties on business decisions. The method also helps to identify the major parameters that have the most

mber of MPFA methods have been developed during recent years such as [1 2 5 8 10]. In most cases MPFA methods lead to good results d to well testing in gas condensate formation. y predict the oil recovery.ï¿½ The process described can be applied to any triple porosity reservoir where gas is invading the fracture-matrix he history-matching process. The geomechanically simulated fracture trend model is calibrated to both production data and the reservoir geo

with those produced by a commercial finite difference simulator with order of magnitude improvement in simulation time. Introduction Strea uction The most common model for describing naturally fractured reservoirs where fractures can be considered small compared with the ty problems. Geological models may use very small cells have highly contrasting reservoir properties and often have a lower proportion of ac

ML method samples the posterior probability density function (pdf) correctly if data are linearly related to the model; however no rigorous the

recipitation takes place in situ in the reservoir and what the resulting impact on the chemical composition of the produced brine will be. This

a geological model as possible. A proven numerical method for simulation of large geological models is the streamline method [1-10]. The ut they deal with larger matrixes and in addition may smear the solutions a lot. The main advantage of conventional streamline methodolog n a statistical field development study for YPF in the Argentinean San Jorge Basin. Introduction Despite the long production history with m

oning data. Continuous pressure data obtained from down hole pressure gauges can be used to identify and rank these geostatistical rese w can be used to design this type of advanced well. In these tools the well models can be very sophisticated taking account of flow in the an

from a compositional model to those obtained from a black oil model using black oil delumping shows excellent agreement. This study sho und on data from a Middle East carbonate reservoir.

becomes large enough so that Darcyâ€™s law8 for the pressure gradient and the flow velocity i.e. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ is is perhaps not surprising given that the associated rock tends to have relatively low permeability (<20 mD).ï¿½Typical open hole measu as first put on production in the early 1980â€™s. Originally it produced a high condensate yield along with the gas; however as the reservo ing. The paper exhibits example of directional sensitivity of well trajectory and successful drilling campaign based on the developed stress m ess processes and workflows required to manage a mature field appear to be similar for many operators.ï¿½ The majority of the technolog

ffer reliable public information.ï¿½The comparison of the two provinces is analyzed and conclusions are presented. Each section of this pa f the cement sheath was demonstrated experimentally many years ago (Goodwin and Crook 1992; Jackson and Murphey 1993). More rece

decisions. Introduction The field studied in this paper is located in the Western Desert of Egypt. It has been producing oil since 1992 from issue. Introduction Intelligent completions have developed over recent years with increasing functionality to meet specific applications. Nor ol string and the recent interpretation technique in order to overcome the problems due to completion restrictions. Introduction The improve ctions at angles greater than 70ï¿½ over several kilometers followed by a horizontal section of 1-3 kilometers extent.ï¿½ These wells inters

dual packer. We conclude with a summary of recommendations and lessons learned for sampling in such an environment. Introduction Th dual packer. We conclude with a summary of recommendations and lessons learned for sampling in such an environment. Introduction Th ones caused by the steepness of the reservoir and the heterogeneous nature of the matrix. In this particular portion of the field an observa ale treatment and inhibition. Introduction The main objectives of formation-water sampling in exploration wells are to obtain information reg unt devices or even multiphase flowmeters. However as wells become more advanced there is one tool that has yet to be replaced â€“ the orter western wing.Vertical propagation speed of fracture propagation is similar in sandstone layers however it slowdown in the vicinity of sh ol seen in these log types may be a mirage. This paper describes through case studies the unique problems of evaluating fracture height in

st of the Athabasca River in Alberta Canada; Fig. 1. The McMurray formation interval is a 50 m thick high-permeability (~5 000 md) sand sit that are insufficient to continuously transport the produced well liquids to the surface are referred to in this work as sub-critical velocities. In to continuously transport the produced well liquids to the surface are referred to in this work as sub-critical velocities. In the discussions pr ciency of reservoir stimulation practices. Introduction Temperature logs were the first type of production logging sensors employed in the o

c production testing through a separator and back allocation of production over the intervals between tests. Restricted access to a test sepa

echnology available real-time environment automated workflow application recommendations and potential benefits. Introduction Every m ent of new technologies such as coiled tubing logging and wireline tractors. As these fields age their water cuts have increased due to wate ults. From the SBHP data maps have been made to assist in identifying compartments. One interference test showed anisotropy which cou horizontal openhole slotted liner completion to perform an effective stimulation program and treatï¿½the tight viscous emulsions. ï¿½ Introd ow how the cooperation between experts form service providers and operating companies with the assistance of real time reservoir and pro ure reopening/closure cycles as well as real-time permeability composition or anisotropy interpretation to determine optimum transient dur uously monitored temperature profiles can be used to refine reservoir models and thus improve overall field recovery. Introduction There i ecovery confine the stimulation to the reservoir and identify bypassed regions. Steam injection results in geomechanical strains associated ature monitoring systems on its Azeri reservoir has allowed BP to acquire early time-surveillance data adding significant value by reducing ciency of power transmission so that industry standard power settings were sufficient to power a bridle with one sensor per joint of screen. T titative manner.

ction of current work practice processes and workflows descriptions technology available real time environment automated workflow app ter cut where high water holdup and water velocity would likely be encountered downhole. Once the water producing zones are identified w

zones were isolated after identification of the intervals that showed considerably lower resistivity values. This is considered as an indication ervals or open hole where PLT reflects the near borehole environment only. Neutron capture cross section (Sigma) logging has been in us he water flood movement between wells. The most favorable conditions to acquire reliable formation resistivity distribution information EMI etailed pattern flood modeling helped develop an optimum strategy for maximizing reserves and production especially in the lower two oil b reasons for these unexpected results and recommend a path forward for shaped charge testing designs predictive tools and how to optim determined from the detailed structural evaluation of the fractures seen in the high resolution resistivity image. Maximum horizontal stress completions when the bottom hole producing pressure (BHPP) is at itâ€™s highest very little gas will be desorbing from these adjacently c strategies has reduced by 74% the number of stages in which fracture-initiation difficulties have been encountered. Introduction The Barne m microseismic monitoring(2 3 4 5 6) indicates that in some tight gas fields a broad lateral spread of microseismic events is measured durin M wells dictates that a efficient drilling and completion model be adopted in order to be economic. The current model that is utilized is the we stimulation pressure responses and microseismic activity are compared to those predicted from image logs.ï¿½ Infill drilling strategies takin ded better understanding of the reservoirs. This integration workflow demonstrates an effective methodology for capturing the essential cha cremental financial analysis is included to examine the impact of choosing any such strategy. Introduction Many SAGD reservoir computer s rganic matter whereas shales contain less than 50 wt% organic matter. Methane is generated from the transformation of this organic matte monitoring has enabled operators to make informed decisions that influence fracture geometry increase lateral coverage and improve ga wells has frequently been viewed as art than science. Many laboratory researches have been conducted trying to expand and enhance the es of wellhead penetrators are being pursued to reduce rig utilization increase producing life and minimize failures. Introduction Saudi Ara

ng pressure head to velocity head and a diverging tube converts velocity head to pressure head. The two are combined to form a Venturi tu of watering out and leads to longer economic life of the wells. By and large drilling of horizontal wells as an element of the field developmen he Tinharï¿½ Canyon of Rio da Serra age. At east and south the Mutï¿½ fault (north-south) and yet another northeast-southwest fault seal P valves work and how the valves performed. Information on a TAP Completion with 6 layers is presented in detail and an overview of all in ne was present in the unconsolidated sands. Using the sonic data mechanical properties and stresses were calculated. The unconfined com e flow and pressure traverse models that are commonly utilized in production systems analysis models generally assume that steady flow co e flow and pressure traverse models that are commonly utilized in production systems analysis models generally assume that steady flow co king process. Background Burgan Field the worldâ€™s largest sandstone oil field lies 35 km south of Kuwait City near Ahmadi Kuwait an

d evaluate the impact of these technologies on reservoir well performance and overall reservoir management strategies. As a result of the p parison with the cost of completion. Introduction Two of the common problems that plague waterfloods are poor sweep efficiency and low c valuate the impact of these technologies on reservoir and well performance and on overall reservoir-management strategies. As a result of

Recent advances in the capabilities of the systems and applications have proved multilateral drilling and completion to be a truly revolutiona edictable results may be obtained. Because commercial production rates need to be guaranteed techniques have been implemented such and field design. This paper shows how we can extract the full profundity of useful information that inhabits even a moderately sized data s wells with similar reservoir characteristics resulted in premature screenout. Nevertheless the first worldwide field trial of the new technology ds was the standard mode of operation. For this reason diesel based fracture fluids were used to perform the first three fracture stimulation

een the productive Bakken Formation in Richland County Montana which is in a fairly small confined area and primarily homogeneous vers e pushed the limits of the technology in regard to proppant size type concentration and fracture fluid gel loading. Combining this solution w scusses the planning and design processes leading to the successful implementation of the technology and the excellent post-stimulation acture closure results in considerable part of net pay being under stimulated. The laboratory testing on large size ISP proppant suspension mulated fracturing fluid. In spite of the low capillary pressures the additives had little effect on clean-up or return permeability on cores above ed formations (Smith et al. 2001; Simonson et al. 1978; Daneshy 1978; van Eekelen 1982; Warpinski et al. 1982 1998; Teufel and Clark 19 etion processes and to increase efficiency in field operations to make wells commercially viable. Reservoir pressure depletion and declining r their waste. Offsite disposal companies must comply with state and federal laws including the Resource Conservation and Recovery Act (R n of shale sandstone and coal deposited in a coastal plain environment encompassing 2 000 to 3 000 ft.ï¿½ The sandstone reservoirs hav rate was reduced to 12% in a sample of twenty eight wells with the new technique. The average production rate increased from 2 to 135 BO Ryabchyk formation. Introduction Failure to contain fracture height growth during hydraulic fracturing treatments often renders uneconomic ability contrast. The last stabilized measurement indicates sustained natural production of 10 000 bopd which is five times the field average uniformly conveyed across the oil-bearing portion of the reservoir and away from the watered out intervals. A description of the well candi ction increases that have been observed. Introduction Operating companies are continuously pushing to improve hydrocarbon recovery a

capable of overcoming most of the challenges associated with horizontal fracturing and effective stimulation of the long horizontal section w

esults and impairment issues will also be presented. Field Overview Gandhar is one of ONGCâ€™s major onshore brownfields discovere

Introduction To understand the particularities of hydraulic fracture stimulation it is of extreme importance to understand the difference in th

er of layers fractured during a single stage. Stimulating multiple layers in a single stage is not ideal since layers with lower fracture gradient ompletion method. Introduction Perforating cemented casing is the most common method of completing vertical wells in multiple layer tig are finite element models and cannot be used for the calculation of practical fracture designs because of time limitations. This work is only fluids including anionic surfactants cationic surfactants and zwitterionic surfactants4.ï¿½The new VES fluid presented here utilizes a sp

10 Tcf of gas and 100 million barrels of oil and/or condensate.ï¿½ In terms of rock type the Morrow Sands can be broadly classified in 2 gr

ng since 1984 under a combination of rock and fluid expansion drive with low amount of reported water production. Lack of adequate aquife decrease cost by placing smaller size treatments that would still deliver the same production as the larger less effective treatments. It is w vide an improved understanding of the fracture behavior within a field.ï¿½ This improved knowledge of the fracture system can lead to optim

y) is done. Commonly monitoring geophonesâ€™ orientation is determined from back-azimuths of P waves generated by the perforation sh

re. However conductivity after fracture closure is created by acid only if the fracture face is nonuniformly etched by the acid so that parts o gging is used to obtain an estimate of wellbore fracture height. It combines temperature log immediately after Minifrac or after Frac and Cas east of which is its very short half-life after being irradiated. By the time the logging process is complete and the well is ready to be placed in

on (Fig. 1) in the Yamburgskoe gas condensate field. This crucial process is difficult and time consuming. In this case it was further comp eservoir. The fracture was explicitly modeled as a set of high-conductivity cells. The impact of condensate dropout was modeled in both th on linear elastic fracture mechanics. This work provides new insight for fracture propagation in highly permeable sandstones and allows us 2 wells treated with viscoelastic acid showed no difference in production performance compared to their offset wells. Introduction Saudi Ar criteria link the well deliverability or well potential (technical limits) to the fracture costs (or total well costs or OPEX). Optimization is achieve seismic-signal attributes such as the polarization direction of S- (shear-) waves and relative amplitudes of the P- and S-waves also can be usly the requirement in terms of strength depends on the downhole conditions. Introduction Proppant flowback is a term used to describe th by Mack and Elbel1-2 showed that production from a fractured well causes the stresses surrounding the fracture to decrease over time as t e sensitivity of the displacement process to variation of values of the main governing parameters. Taking into account non-linear effects in fl th calculation 2D flow proppant tracking and bridging criteria are available to the industry but do need extensive set of accurate parameters

the larger less effective treatments. It is well documented in the literature that hydraulic fractures often underperform: Frac and Pack comp h field. The operation procedure and the result obtained after injecting Viscoelastic fluids at fracturing rates are discussed in this paper. This e propagation of the hydraulic fracturing through a 10 m thick shale bed resulting in an unique hydraulic fracture covering two different reser ientation and monitoring fracture intersection with offset wells or boreholes provides growth rate data that can be used to obtain the ultimate enerate significant value by: 1. Increasing oil production rates through the use of a cost-effective artificial lift system. 2. Mitigating the effect nes in the literature gravel packing and frac packing are the preferred sand control techniques.4 5 As of mid 2006 approximately 50 high-r ctiveness of fracturing operations by segmenting the lateral and producing mechanical isolation points in the wellbore using the high perform tiveness of fracturing operations by segmenting the lateral and producing mechanical isolation points in the wellbore using the high perform per. Overall results of the interventions will be shown and a complete solution for bringing new openhole horizontal wells into production will on GOR (Gas-Oil-Ratio) of 750 SCF/STB. The presence of a large overlying gas cap and a relatively weak aquifer dictated the use of horiz and used to refine the final simulation model prior to completion installation in the ground. The ICD completion architecture was successful stified when compared to extremely high cost and risk of intervention in sub-sea wells. Today intelligent well completions are being used o

voir uncertainty they may not deliver the optimum possible solution. Proactive control techniques which additionally incorporate data from d ing tests on physical models have been conducted1-6 where limited consideration of scaling differences was given in the design and interp

or multi-layer reservoirs and water or gas coning studies. Introduction These Deepwater turbiditeshallow marine to lower coastal plain rese d production for the life of the field. The completion strategy optimizes the production using ESPs while minimizing sand production. Introdu hat extend the effective wellbore drainage area1 2.ï¿½ There have been many laboratory studies on wormhole propagation influenced by flu st El Bourma regional fault and a second system having a northwest-southeast direction. These systems were probably generated during t anism in the past was found to have some operational difficulties. Lastly this paper also mentions the proper selection of zonal isolation m ty increase compared with the target reservoir average well production. These results demonstrate the effectiveness of the technique under ould not achieve these low skin values over this wide range of permeabilities. Background Because the HZ fields consist mostly of stacked ess minimizing the forces that act to close the fracture. Other advantages include lower injection pressures to break the fracturing job mini ed with acid prior to production. The matrix acid stimulation is carried out using a barge outfitted for this purpose. Due to the barge logistics a nterpretation workflow to invert the skin variation as well as other formation parameters from pressure measurements. A field example whe echniques on these oil gas producers and water injectors did not produce to their full potential. Studies indicated that the main cause for th higher shot density of shaped charges which consequently inflicts more damage to the perforator carrier or gun. Examples of serious dam

mized penetration depth it is well known that increasing liner material density optimizing the charge geometry to yield a jet of optimal veloc ated using this technique show similar higher than expected results. This paper reviews the job design criteria job execution requirement g of one packer 4- 1/2 tailpipe and 7" tubing and PDHMS. To reduce the WC the well was produced at high rates (Fig.5). After one year of s paper. Introduction With an area of 141 km2 (34 842 acres) and OOIP of around 3 800 million barrels(1) the giant Albacora Leste field is s that resulted in zero- to negative-skin completions across long perforated intervals which continue to produce sand-free after extreme re its life span. It will also discuss the latest achievement deploying Saudiâ€™s first TAML Level 3 multilateral completion of a tri-lateral well. tiple control lines and fish screens with shunt tubes from close-tolerance casing and procedural revisions developed to successfully frac-pa elta is often a result of low overburden pressure changes in the mechanical properties of the reservoir or poor completion methods. These

issolve the filter cake formed by the drilling mud.ï¿½ Use of enzyme breaker and chelating agent used in the clean up fluid helps to promot mposed of multiple stacked reservoirs separated by shales. The formation sands are high permeability (Kaverage between 800 to 1500md)

accomplish high production rates however the well architecture and completion can pose limitations for the application of the most commo he toe (called the Alpha Wave) if circulation can be maintained. This part is dominated by settling of the gravel up to an equilibrium height w thodology and show how with proper calibration the simulator can be an effective design tool and significantly increase the success rate of aken through the design and execution stages of the treatment incorporating the lessons learned from two previous applications of the OB ction has been achieved with reduced drawdown across the sandface and production rates as high as 5 000 BOPD. Introduction Sand pro oduction has been achieved with reduced drawdown across the sandface and production rates as high as 5 000 BOPD. Introduction Sand ion were quite extreme and vastly exceed the production scenario for the planned oil wells in the field. However the cell geometry boundar g field background and reservoir challenges The Stag field operated by Apache Energy is a reservoir within the M. Australis formation at 2 ynamics such as Unconfined Compressive Strength (UCS) Youngâ€™s Modulus porosity production rate and drawdown. Sand productio

nd production can destroy electrical submersible pumps (ESP) erode completion hardware and surface equipment and block flowlines and esult of this integration is a sanding analyses tool that uses input parameters such as rock strength geostresses and particle size to: acco her than premature conclusions based initial and potentially misleading evidence. It also highlighted how the integration of information from om the failed materials and transportation of the sand grains into the wellbore and to the surface. It costs oil companies tens of billions of U

types of sandstones. Two different failure behaviors of perforation-sized cavities were identified in these experiments. These failure patter ure 1). The fields with varying volumes of gas in place are to be developed as a group to optimize development cost and achieve economy o he spent acid in oil and gas wells was lifted from the treated wells in a very short period of time. Finally wells treated with surfactant-based s. This suggests that optimal times of acid exposure in acid fracturing treatments exist. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ 2. There xamples presented contain information from radioactive tracers and production logs which are fundamental to understanding how good zo logy the experience during the stimulation treatment execution and the excellent post-stimulation results. A production logs was run in the a ading to the successful implementation of the technology the experience during the stimulation treatment execution and the excellent post3800 m to 5500 m producing 47ï¿½API oil with an average of 16% hydrogen sulfide (H2S) in the gas with 11 600-psi reservoir pressure cal depth (TVD) perforated interval on natural flow at approximately 600 barrels oil per day (BOPD) with a productivity index (PI) of 2 bbl/D

e success ratio of sandstone stimulations. Introduction Sandstone acidizing is possibility the most complicated stimulation method as it inv

e cases relevant increases in hydrocarbon production are obtained. Because the chemical reactions involved are simple the results are alm and how laboratory evaluation should be carried out to obtain this information. Introduction Oil and gas companies are developing carbona

t exceeded expectations. Introduction The Caballos formation and reservoir is an asymmetric anticline with an orientation of N-NE to S-SW oduct for a specific treatment. It is the intent of this paper to provide a technical overview of mechanical and chemical diverters used in the o e- and super-foams. Introduction Modern fracturing treatments were introduced in Russia by the end of 90-s. In the following years proppa ored by analysis of the effluent and permeability was monitored by the pressure drop across the cores. The second set involved determinin as well as published results of other operators. Application of the correct candidate selection methodology to a particular field type will inev g fluid that is compatible with carbon dioxide (CO2). For the two applications referenced on this paper foam with high foam quality (70% qu ulch complex is located on the Waltman Anticline a north-south trending asymmetric fold of Laramide age. The fold is bound on the west by nts discussed in this paper were urged to prove or disprove the formation potential. Thirty percent of the wells in this formation were contr

production. However water breakthrough becomes an issue as soon as the water flooding was started. This is confirmed by the production e tests are restricted to localized areas of the casing such as the casing / liner shoe and squeeze perforations. Communication tests regard However the existing methods used for analyzing this kind of test data are based on the Horner method using the approximate rates durin erves for this tight reservoir. Introduction The Mauddud reservoir is a thin underdeveloped low permeability carbonate reservoir unit withi nd/or cost-prohibitive. The optimization methodology allows evaluation of the fracture performance efficiency in terms of the reservoir respo ad a very high permeability compared to the other layers. It depleted much faster and had early water breakthrough. Consequently a water s For a naturally fractured formation the type curves of the pressure and pressure derivative reveal that the combination of partial penetration ) during a transient test is very important for exploration well testing. Introduction The challenge in estimating reserves from pressure trans ot too long to increase the cost without additional benefits.ï¿½ Thus with real-time technology we were able to overcome the shortcomings o w methods of analyzing well-test data in the form of a constant-rate drawdown system response and production data in the form of a consta

mulation models in order to show importance of accurate determination of fracture parameters. Introduction Naturally fractured reservoirs d and dynamic reservoir information such as petrophysical data core analysis well tests nd choke in our simulation model for well deliverability estimation. Our technique has resulted in immense saving in rig time and cost since ment to conventional test separators for flow metering in low-pressure high water cut wells under gas lift providing operational flexibility and and a number of solutions are described. A discussion of the validity of samples for full reservoir fluid characterization provides insights on t

well was tested for 12 hours in series using an existing inline MPFM a low pressure production test separator a second mobile MPFM a 14 rts of gas-condensate field development in Russia. A number of multiphase welltesting operations have been successfully performed recen has been considerable focus in recent years on the development of new flow-measurement techniques for application to surface well testing ons and optimization of testing duration and frequency per well testing remote wells slugging/intermittent wells due to system back pressur

presented in previous paper (Ref [10]) with a maximum error of 2-3% for the gas. The current paper will also put a special emphasis on the nerated geologic models to well test response and 3. The history matching of numerical models to observed well test data. The first has be efer the "pressure" analysis format because of the similarity with pressure transient analysis while others are more comfortable with "rate d se mis-interpreted because of various artifacts of the measuring and differentiating process collectively termed noise.7â€“9 Various algorith d Arrays Electrode arrays were permanently installed in a water injection well and oil production well in a Mansfield sandstone reservoir in

roblems (both for continuous and batch mixing) contamination channeling and fluid loss can and do cause slurry dilution/concentration an ository. In particular seal integrity must not be impaired by the mechanical effects associated with storage operations . Forecasting such eff or safer and more efficient design maintenance and monitoring strategies. mankind. Precipitations have been reduced considerably and the sea level and ocean temperature have risen. One of the most likely cause rein may be useful for certain aspects of CO2-EOR. Special properties of CO2 (or gas mixtures in which it is the dominant component) enh method was successfully applied in two wells with extensive core data. In the third well where few core data exist the section was charact voir characterization modeling of storage and long term leakage monitoring techniques will be illustrated. Introduction The prospect of g nd CO2 injection that best ensure containment while achieving injectivity and capacity requirements. Introduction The climate of the Earth

m a floating installation. In the early pre-planning phase the well was planned as a separate costly subsea development drilled by a separ s a case study to highlight the benefits of using Point the bit RSS the latest LWD tool technologies and process for redevelopment of an oth

potential for enhanced oil recovery. One producing area that could benefit considerably from EOR techniques is the Silurian reef trends of th areas under study. The CO2 from Quebrache field could be the beginning of a new era of EOR projects in Mexico. A field example of poten rate (Fig. 1). The play has seen both productivity increases and declines depending on gas prices and technology drivers. Since the mid-1 ation damage or wellbore mechanical problems and to exploit new zones saving the cost of drilling entirely new wells.[5 6] In this study w and the favorable reduction in oil viscosities within the reservoir. It has been reported that recovery factors could reach up to 60% in the are 7 to 1970) was by natural depletion supported by gas injection in the A reservoir unit starting 1968. After this initial period of gas injection w

roperties of some granitoid basement bodies. Some main alteration processes are volume shrinkage due to the crystallization of magma la HPHT (high-pressure high temperature) environment and challenging well-bores configuration (High inflation ratioâ€¦etc). The recently deve were completely sealed off and isolated and subsequently re-perforated shallower. After slurry placement and squeezing it is important to ir for evaluation purposes (Fig. 1). with a live oil viscosity ranging from 200-400 cp at reservoir conditions. The reservoir dips to the southwest and ranges from 5000 to 9000 ft open hole section. Job Objective and Design The objective of the operation is to shut off the water production zone by plugging back the l ion Drilling horizontal wells become the norm in many Saudi Aramco fields. As horizontal wells mature oil rate is reduced due to increasing Heavy oil/emulsions Among all the above factors asphaltenes are the relatively least understood flow assurance aspects. Traditional pr experimental data accurately. This paper provides significant insight into oil/water flows in horizontal pipes. The results are significant for the nnot be readily used in liquid/liquid ones due to significant differences between them. The oil/water systems usually have large difference in ally possible the latter is rarely used at the completion level and rather situated at the well head.ï¿½The monitoring devices deliver the me of well optimization opportunities strategic planning and informed decision making considering the size of the full well-surface facility syste me of the project coupled with asphaltene and wax thermodynamic models. The Perturbed Chain - Statistical Associating Fluid Theory (PC-S n on the tubing/pipelines. Wax deposition will reduce the effective flow area and may lead to complete pipeline blockage. Deposited wax will ds in terms of chemical and physical properties phase behavior spatial distribution and hydraulic and thermodynamic communication are o samples for different reservoir fluids under varying conditions are also discussed. Introduction The first generation Downhole Fluid Analyze

igins were used to develop a dewpoint-pressure correlation based on initial producing gas/condensate ratio initial stock-tank oil gravity and validated using the generalized material balance equation calculations with data generated from a compositional reservoir simulator. These endent the existence of fluid distributions can depend on relative rates of fluid movement. Both convection and diffusion generally cause re ion data. However in complex reservoirs despite the number of wells drilled in a development scenario correlating / integrating such data i g technical risks and maximizing the economic value of the hydrocarbon assets. Introduction Fluid characterization strongly affects in-place -assurance indicator. We compare ANN results with those from the algorithms used by DFA tools. d with field data for the time dependence of contamination during sampling. A rapid approximate response surface based model which can ion along with some indications of compartments or connectivity. Testing well production is a common way to obtain fluid samples but usua

ositively identified. This evaluation can have significant impact on facility sizing and economics of field development of new reservoirs. In add n extremely hazardous toxic compound that occurs in a number of natural and industrial environments. Naturally it can be found in coal pit

n a fluid column (Schulte 1980; Riemens et al. 1988; Wheaton 1991). According to Hirschberg (1988) the time to reach such an equilibrium mechanism at work in many stacked reservoirs results in each reservoir filling up by petroleum spiraling up from deeper reservoirs via faults r of compartments in such complex reservoirs. Introduction Reservoir fluid identification plays a crucial role in reservoir characterization an an. Introduction It is known that some oil reservoirs show a fluid compositional variation across relatively short vertical intervals. Such rese ervoir connectivity. Pressure profiles and fluid density gradients provide valuable information for reservoir evaluation and management and appraisal well where a large compositional gradient has been observed with in-situ fluid measurements. An equation of state is elaborated mpared to PVT lab results. Both the OBM contamination monitoring and the GOR algorithms work well for most crude oils. However for he

measurements and pressure gradients. An equation of state model is used to describe the fluid column according to a simple fluid equilibrium urface facilities (Mullins et al. 2005a; Mullins et al. 2005b; Dong et al. 2003; Fujisawa et al. 2004). GOR is roughly correlated with fluid densi dicator. We compare ANN results with those from the algorithms used by DFA tools. Introduction Reservoir fluid properties such as hydroc

solving an energy balance equation and Rachford-Rice equation and a hybrid of the above. Algorithms discussed in this paper have been te reased below the bubblepoint of the sample as lighter hydrocarbon components evolved. The measured viscosities increased as much as 5

scription of reservoir fluid properties is critical in all stages in the life of an oil or gas field. It is required in exploration to ascertain the true na the tool flowline thereby letting any contaminants present in the fluid to settle down. The pump was then restarted to slowly push the clean d now by the oil industry (Ref. [11] [12] [26] [28]). All MFM as other devices (Coriolis Ultrasonic Separatorsâ€¦) by construction are measu site allowing to compute improved flow rates with MPFM. Hence it provisions two major tasks: the fluid sampling required for any type of w are present at moderate pH values. More research is needed to determine the kinetics of the reaction of chelating agents with calcite at low cores are available such as old wells or when timing is a constraint as in exploration wells. Introduction The economical exploitation of Alg ¿½ In hydraulic fracturing the fluid is intended to create macroscopic channels (fractures) intended to bypass any damage in the near-wellb salinity brines (>200 000 mg/L) or formation waters containing sodium chloride close to saturation there is potential for sodium chloride dep

ck to extensive pressures and impact stresses which fracture sand grains in the vicinity of the perforation tunnel and thus create a zone of r arge number of microfractures extending through grains of sand (Pucknell & Behrmann[1]). The radial displacement of the rock creates a r ct. Introduction The prerequisite condition for the formation of scale is supersaturation of the scaling minerals in the produced or injected w acture) is more challenging due to the lack of accessibility. To overcome this problem a scale inhibitor squeeze treatment was developed to lt of using ICV technology.ï¿½It also investigates the potential risks posed to intelligent completions by the deposition of scale.ï¿½ The tec Coiled Tubing Mills and motor high pressure rotating tool with Sterling Beads* and Polymer as the cleaning fluid. Most of the job objectives e Norwegian Continental Shelf 270 km (168 miles) southwest of Stavanger and 43 km (27 miles) northeast of Ekofisk Centre.ï¿½The offsh e objective of history matching is to build a reservoir model that integrates available data and yields production forecasts that are accurate. acture model is essential for achieving a good history match and a confident field forecasting. Normally fracture models are generated stoch nalytic and analog approaches to the days when computers started to be employed.ï¿½ Currently numerical approaches solve the multi-d nt concerning the impact of cavities their fill including foam; formation of radial barriers to control the advance of the fluid levels around the ly-stage diagnosis of problems enables the operator to make decisions in record turn-around times and extends the productive life of the we its of the reservoir. The benefits of pattern flooding are more efficient and faster recovery. The potential drawbacks are greater costs and h flexibility to adjust for an ongoing development of this super giant field. The Sabiriyah Field The Sabiriyah field was discovered in the 1950 he lower Orinoco River in eastern Venezuela. It covers an area of approximately 20 850 square miles and contains the countryâ€™s larges yses perfor ed using estimated capital and operating expenses with oil production curves from each case to assist in the comparison of the and inorganic products the carbothermic reduction of metal oxides mineral leaching coal liquefaction the production of active carbon spe -horizontal well array set up was used as the model to assess this fairly new thermal recovery technique. During the investigation different s areira is a small heavy oil field in Muglad basin. Three exploratory and appraisal wells have been drilled in the field. Three hydrocarbon bea in 1956. The 1st Eocene has produced only 4% of OOIP and primary recovery is not expected to exceed 10%. The oil API in this heavy oil rs formations with low permeability and unconsolidated formations saturated by high viscosity fluids (heavy oils). In this paper application

a Oilfield with massive lose sand and average viscosity is about 1536.39 cp at 500C. Aradeiba is the second reservoir with stratified uncons

ntifies the economical added value resulting from the usage of the surfactant-based systems with respect to conventional matrix stimulation

tely and a comparative test were capable to demonstrate when it was possible from a reference point of view that the overall uncertainty of

e they occur at much shorter time-scales than for the non-acid reactive minerals. The presence of acid-sensitive aluminosilicates may domi g and operating companiesâ€™ representatives and real-time decision-making during data acquisition led to the successful completion of t

c reservoir fluid models for graded reservoirs (or reservoirs with high grading potential) have also been investigated. Introduction Grading in

d deployment of a high-temperature fracturing fluid system that has shown to overcome those issues. Introduction Achieving the design flu widely used to stimulate oil and gas wells in carbonate formations to improve the rate of hydrocarbon production. It is also used to stimulat

oduction monitoring system helps operators achieve better well productivity by identifying trends throughout the producing life of a well or fie experiences gained in this field are shared. Introduction The Bach Ho field is located in the South China Sea 120 kms south-east of the po f which up to 500 ft is perforated).ï¿½The mineralogy varies from interval to interval with 4-16% CaCO3 6-18% clays (mainly kaolinite) 5 ally and take all of the subsequent acid volume. Fredd and Fogler (1998a 1998b 1998c) have proposed the use of ethylenediaminetetraac onditions presenting a wide range of permeability and temperatures. Introduction The oil producing sands of the San Jorge Basin store imp and Sharma[8 9] have shown that removal of water from the formation occurs in two stages: an initial displacement stage where water is e surement made downhole with that made in the laboratory on the same sample using the same technique to validate the representativenes

hile porosity values lie between 4% and 14% (Table 1). Initially this area was developed through vertical wells drilled on 640 acre spacing. I

evels. A key conclusion of the paper is that applying the field management process in both environments (North America and the Middle Ea lenticular sandstones and tight brittle sands. The main natural gas reservoir interval is from 5000 to 8500 feet. The productive sands have injection and reservoir fluid production in the sector of the monitored well. Observations regarding the effect of fracture wings length asymm de detailed information of time-dependent fracture propagation including front location fluid pressure fracture width induced porosity and p nup. On the next well drilled in the area the same hybrid treatment was applied only to the portion of the Taylor sand located in the Cotton

n the production results of three cased-hole wells in an analogous field where multiple propped fracturing was applied the operator decided intervals based on reservoir evaluation. Each isolated interval then is individually proppant fracture stimulated in a single operation and onc eginning in 2004 new horizontal and horizontal sidetrack vertical wells targeted the low permeability 50 to 150 md M3b layer. The new hori e been based on designs and forecasts using decline curve analysis and single well analytical methods which assume no interference betw hing techniques to evaluate fracture and reservoir properties.ï¿½ The use of these tools early in the drilling program has resulted in change e over a long period of time were compared. Effective permeability and pore-volume calculation yielded the best results and they were used intervals can now be assessed and completed effectively and economically. This process will further add to the reserve base of tight gas.ï¿

g Janmah-Sargelu (NJ-SR) and Marrat (MR) in the northern Kuwait (Figure 1) are considered unconventional ones (Verma et al. 2007). Th s (16 with samples) 2 mini-frac stations and in access of 91 pressure points was achieved. The DFA and samples provided significant answ ntary basins over the past fifty years. The worldwide trend and the drilling plans in Algeria confirm the strategic importance of these unconve ells since discovery in the late 1950's. The primary productive interval is the Almond Formation of the Mesaverde Group comprised of shall

tion testing tools utilize the same principles to measure sand face pressure: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½1. ï¿½ï¿½ï¿½ï¿½The tool with ctivity indices. The 3D seismic allowed the identification of sandbodies with viable pay thickness in two pilot areas. The southern area with both static and dynamic) well design drilling stimulation and production. It will also illustrate consequences of what may happen if these i n sediments in the carbonate depositions of the Riphean. The following exploration effort identified the extensive oil and gas accumulation z

g expensive production tests. Introduction Worldwide carbonate oil-water transition zones contain vast quantities of economically producibl

t and also oil production from tight formations. Introduction Oil continues to be the worldâ€™s major energy resource accounting nearly 4

Making Multicriteria decision-making is a process that can assist an individual and/or an organization to effectively incorporate and evaluate xample is the illusion of controlling something that we cannot influence. Another example is our tendency to seek information even when it

CAL measurements on core plugs of limited dimensions We discuss the impact of the results on input to reservoir simulation and manage uently applied to a numerical simulation that integrated the dynamic fluid flow salt transport and electrode array responses for water front m each well are then propagated into a 3D static model which can be used for dynamic flow simulation. On the other hand more advanced to bodies and their geometries is better understood in the study area with the help of image logs. Introduction The eastern offshore of Indian early to mid 90s in the Triassic Argilo-Grï¿½seux infï¿½rieur" - TAGI reservoirs. These sandstones have been interpreted as fluvial deposit essure temperature and fluorescence that all play a vital role in determining the exact nature of the reservoir fluid. Extensive tests at a pre and production data.ï¿½ However in complex reservoirs despite the number of wells drilled in a development scenario correlating / integra the carbonate reservoir Permeability prediction from logs is always difficult since no logging tool is available which can make direct continu on the sealing faults barriers picked up in the area but the pattern of the depths of OWC OSC and distribution of wells with residual oil sat half of the tool with the highest measure point being less than 16 ft above the bottom of the tool. The conventional stabilized gamma-gamm improve efficiency but also brought with it the possibility of more completely evaluating the diagenetically complex tight carbonate reservo

ntroduction The electric log in the oil industry is the most used tool for in-situ detection of hydrocarbon accumulations. However quantitativ ctric log in the oil industry is the most used tool for in-situ detection of hydrocarbon accumulations. However quantitative measurement of o s methods for estimating permeability from wireline logs and one of the most common is to identify rock types which each have a particular reservoir. To get to the reservoir such wells have to be sidetracked in the right direction so that the missed reservoir or oil pool could be pen ence to project that the method could be applicable to many other carbonates worldwide. Introduction The well in this case study is from a erves in thinly laminated reservoirs thereby extending the range of NMR applications beyond the volumetric estimates of moveable fluids.

offer large hydrocarbon volumes. Introduction The topic of formation evaluation in thin sand/shale laminations has been treated by many a

oduction of the hydrocarbon trapped in the Cambrian reservoirs of the Hassi Messaoud field very little is known about the relationship betw n tester tool. This results in greater reliability and efficiency for formation testing and sampling in unconsolidated formations. Introduction De etween different reservoirs the ability to differentiate between actual and apparent fractures seen in image logs is of significant benefit to un ceous platform edge consisting of well defined progradational features associated with structural highs. These platforms seem to consist of

t using the new model was straightforward. More importantly the new model shows more than 100 million barrels of additional oil in-place c s used to verify the productivity of thin beds identified by formation evaluation techniques. Introduction At the start of an exploration campa permeability of the sand component can be estimated separately. Experiments were conducted to verify the characteristic NMR bimodal re

using the corrected 3D position improves accuracy of the formation thicknesses calculations and therefore improves the reservoir summatio

ound a wellbore are altered because of poroelastic stresses caused by pressure gradients in the reservoir. This stress alteration can result i eters of reservoir rock samples at reservoir conditions of high pressure.ï¿½ Log data consisting of different variables such as density veloc orizontal stress magnitudes cause large fluctuations in the safe mud-weight window. This challenge in drilling through the depleted sand wa

onless wellbore pressure at any point in time (tD) is shown to be a direct function of the varying flow rate and pressure history of the well pri

ession is located at the central tectonic province of Gulf of Suez.ï¿½ It was drilled on the peak of anticline created by a fault-propagation fol was discovered back in 1974 by the exploration well 2 which was drilled in the southern part of the anticline that was delineated by seismic ells both in the Upper and Lower Arab reservoirs. The closed fractures on the other hand are dispersed in their orientations. However mo oration well 2 which was drilled in the southern part of the anticline that was delineated by seismic data. Commercial flow of oil was produce

of the formation around the measurement well to a radial depth of tens of meters.

Mud (OBM) limited the use of dual packer tools in this environment which could be a better solution depending on the number of test points

ution of 22 inches more suitable to the sampling core interval and to the real petrophysical characteristics of our fields. Introduction The ga ht potential reservoir compartmentalization ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½- ï¿½ï¿½ï¿½ï¿½confirm gas cap existence ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ allenging environment. d minutes or even hours to achieve acceptable data quality. The reason for this contrast is that down hole NMR logs are acquired over hund ducted to support NML logging anticipated many formation-evaluation applications in use today. These applications include estimation of pe ed during the Late Jurassic and Cretaceous mainly lacustrine and fluvial in origin (Fitzgerald et. al. 1990). The Cretaceous-Tertiary bounda nderstanding thus managing the reservoir as a whole. Monitoring and managing horizontal wells to have optimum production/injection is c

pular technology. Originally applied to prevent drilling problems its value for reservoir engineering is now gaining greater importance. Bene th hydrocarbons contained in six major reservoirs ranging in age from Early Jurassic to Late Cretaceous. The oil-bearing Mishrif/Rumaila lim

uch as Downhole Fluid Analysis (DFA) mud-gas analysis and geochemical fingerprinting can be integrated with geologic data to better asse xploited for reservoir characterization is Downhole Fluid Analysis (DFA). DFA enables characterization of the fluid in the oil column creating sionless wellbore pressure at any point in time (tD) is shown to be a direct function of the varying flow rate and pressure history of the well p s described in this paper may be of general interest in the effort to optimise the recovery of hydrocarbons. Field Description The large onsh e focus are very thinly laminated shaly sands composed of 70-80% quartz plus feldspar and clays (kaolinite and illite) in which gas sands ar

simulation are common reasons.ï¿½ Regional stress trends when they exist (and it is not the case in Western Siberia) do not necessarily in models. While the theory of pressure transient analysis is applicable to data obtained by formation tests they require careful formulation to ease current reserves by 28%. Field wide recovery factor will be improved by 9%. Introduction Oilfield development and management deci s of the field appraisal campaign samples were recovered from all the hydrocarbon-bearing intervals and analyzed in the laboratory. The c prove field performance. One such initiative involved the review of the current gas lift system to determine if alternative artificial lift methods ains of 25% with respect to that of current wells but without impacting the completion cost. Based on analytical and numerical analyses it stalled â€œconventional valves.ï¿½ In addition to the Venturi technology an integrated surveillance tool is installed to properly monitor ind is mounting to improve recovery factors and extract as much hydrocarbon as possible from complex and challenging reservoirs. This is cou phic hydrocarbon trapping mechanism plays an important role to the type of wells drilled to produce the hydrocarbons.ï¿½ Power water inje te compression was more economical method for gas production optimization. A total of $850 000 have been spent in three phases over 3 servoirs is often not realized because of poor integration among individual discipline software platforms limitations in hardware and softwar recovery from thin oil reservoir fields. Gas accounts for the majority of the production at the latter stages of development when the gas cap oil production was observed when the cross flow between sands were not allowed. Introduction The VLG-3729 Moporo field is located betw have substantially different FM capabilities and approaches. Potential overlap and conflict might arise between the local single reservoir man development strategies are evaluated to determine optimal system design and operation. Examples include planning of step-out and in-fill am Delta area of Sarawak Malaysia. It was discovered in 1968 and its production started in 1978. The field consists of 22 stacked reservo ifying new opportunities which have been a key factor in the rejuvenating Betty Field. Introduction Brownfields has been defined as matur

ace facility model. These three models are coupled at coupling points each passing the conditions at the coupling point on as a new bound etail. Introduction Everybody wants one but nobody has one. The Integrated Asset Model (IAM) has been the pursuit of many Oil & Gas of well optimization opportunities strategic planning and informed decision making considering the size of the full well-surface facility syste are flagged to exhibit a problem for further usage.ï¿½ However in some severe situations missing or inconsistent data are so detrimental ed prejob planning and careful job execution. Several cases of diagnostic evaluations and different water control operations performed are d

nd 2nd Bahrain sand. Where a strong and an active aquifer provides pressure support and water drive to 2nd Bahrain and to a lesser exten the rifting of the South China Sea in the Late Mesozoic to early Tertiary. The main pay zones where CACT deploys horizontal and multilater mbination of relatively low and heterogeneous permeability along with complex hydraulic fracture height growth makes it necessary to perf field where production from several horizons are commingled without the need of a full field reservoir simulation. In this paper we will use a e the service to be performed provides a measurement of a key reservoir parameter. Knowledge of this parameter will allow an optimal choi

ful in doubling hydrocarbon production rate compared with wells in the same field drilled with conventional technology. Introduction Until re sin from both Paleocene and Jurassic aged sandstone reservoirs. A study was completed on 3D seismic data to predict the presence of res utomatic history-matching techniques and advanced drilling and measurement technologies the two pillars for the implementation of the m urce of highly valuable pressure transient data. In this paper we demonstrate a method to maximize the value of that information through th oil production is coming from brown fields3.ï¿½ Improving both production and ultimate recovery from these fields is critical for growing bey leted in commingle horizontal wells. Successful infill wells must be placed and completed appropriately to reduce gas and therefore maximi ce-gradient (FDG) (Bangerth et al. 2006) simultaneous-perturbation-stochastic-approximation (Bangerth et al. 2003 Spall 2003) and Nelde

matching observed behaviour of the reservoir must validate the parameters of this model. Ideally finite difference numerical simulators are e. Indeed even for a well trained engineer a full history matching study can take months to perform. Also because of the nature of the num ns.ï¿½ We demonstrate the power and utility of our approach using synthetic and field examples. The synthetic examples show the robustn has 10 years of production history with original gas cap oil-water contact with strong aquifer support.Using well log data core data water-cu

e has been successfully tested in a fluvial depositional environment. Introduction The objective of history matching is to build a reservoir m

ured grids can achieve accurate geologic features by using fewer grid blocks and save simulation time dramatically. Liu et al. (2007) describ quations. In reservoir simulation the term formulation has been used to describe one or more of the following items. The fluid descriptions e resulting model is more consistent with the actual performance thus enhancing its predictive power. This paper describes certain special

wells.ï¿½ In addition local grid refinement is often needed to accurately capture the well trajectory and detailed fluid flow and pressure prof

The sequential and systematic application of these concepts in a field case gives consistent and reliable results. This is evident in the resu ilter cakes with high polymer concentration form on the faces of the fracture during the injection. Original fracturing fluid may remain in the f ormance has been the subject of extensive investigations over the past decades. For hydraulically fractured gas wells a number of potent s region is characterized by contrasts in rock properties. Variations in lithology limestone and dolomite zones porosity and permeability con d that loss in well productivity due to condensation can be lessened by fracturing the well. Additional advantage of hydraulic fracturing in ga ip between bedding planes is possible and to improve fracture design and evaluation for such treatments. Introduction Interfacial slip is on etermine the optimum number of parallel fractures and to forecast the production. Fracturing operations are very costly; precise assessme

eservoir/completion parameters. Previous Work Previous studies attempting to give a solution to this problem can be divided into two cate e been reported in the literature for moderate and high permeability reservoirs2-3.ï¿½ Extension of the single phase analyses that have be In order to prevent the initiation of several parallel fractures and to mitigate the risk of premature proppant screenout (as a result of low rate wellbore effects play a key role in establishing this connection and may have a big impact on performance of hydraulic fracturing treatment a e.g. limited core poor borehole conditions or restricted logging suites). Thus the methods used in this study should be attractive in many p

ne single fine grid model we divided it into three different models each represent one reservoir with running each model separately. Both pro very factor horizontal wells help achieve injection volumes commensurate with production volumes in the field. Therefore they are instrume

tial gas cap with the ratio of gas cap volume to oil volume ranging from 0.1 to 3.0. The production history shows that most reservoirs experi p and some uncertainty on pressure and PVT data less accurate original oil in place was obtained when graphical methods were used. Re since 1970. A total of 1419 wells were drilled (Fig. 2). The target interval is the Bashkirian. Now the filed has 417 active producers and 165 i roximately 4ï¿½C) in different depths in the seabed floor. The horizontal temperature gradient causes natural convection that might have a ajor parameters that have the most influencing impact on the business decision. Since the first introduction of experimental design to the o

MPFA methods lead to good results but the maximum principle may be violated and nonphysical pressure oscillations appear for strongly an

re gas is invading the fracture-matrix system. Introduction The presence of vugs in a naturally fractured reservoir can be a significant sourc roduction data and the reservoir geological structure (faults and horizons) by searching for the optimum remote stress condition for elastic s

n simulation time. Introduction Streamline methods have been used for fluid flow analysis since the nineteenth century (Helmoltz [10] and M nsidered small compared with the typical flow length is the dual porosity model [1 4 6 7 8 9 11 17 18 21]. In this approach the complex flow d often have a lower proportion of active cells which are wide distributed thereby producing extremely complex hydraulic connectivity. Tradi

the model; however no rigorous theoretical foundation exists for the method when the relation between data and model is nonlinear which

on of the produced brine will be. This information is key in the planning of management of oilfield scale especially in developments where o

s the streamline method [1-10]. The method employs the traditional pressure-saturation formulation of the flow in porous media [11]. Traditio conventional streamline methodology is the technique of splitting. First as in IMPES approach it solves separately the pressure equation by te the long production history with more than 20 000 wells the current methodology to make decisions still takes a long and costly path con

fy and rank these geostatistical reservoir models. The objective function which measures the mismatch between the simulated and the ob ated taking account of flow in the annulus for example but their capability to model reservoir flow is often limited. Full-field reservoir simulat

xcellent agreement. This study shows that black oil simulation with black oil delumping is a viable alternative to compositional simulation an

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ 0 mD).ï¿½Typical open hole measurements for diagnosing such zones areï¿½pressure surveys byï¿½wireline formation testers (WFT) an with the gas; however as the reservoir pressure decreased so did the condensate rates! Eventually gas was the primary production from th ign based on the developed stress map. Introduction Since the global power scenario changes with increasing demand for oil more and m rs.ï¿½ The majority of the technologies that we require to create Smart Fields are already in place although we did identify seven specific a

re presented. Each section of this paper contains subsections on the ANS and the UK North Sea.ï¿½ Petroleum province definitions were kson and Murphey 1993). More recently this behavior has been modeled by use of both analytical (Thiercelin et al. 1997) and finite-elemen

been producing oil since 1992 from the Bahariya Formation a heterogeneous fluvio-marine channel deposit. In 2006 the oil production sta ity to meet specific applications. Norsk Hydro has been particularly active in implementing innovative intelligent completion solutions to mee strictions. Introduction The improved production logging tool string was utilized in the Mauddud Formation in order to identify the flow profil meters extent.ï¿½ These wells intersect multiple reservoirs at low dip angle that are produced with a single commingled completion and well

uch an environment. Introduction The Pinda formation offshore Angola was laid down in Albian time in the Upper Cretaceous. By this time th uch an environment. Introduction The Pinda formation offshore Angola was laid down in Albian time in the Upper Cretaceous. By this time th cular portion of the field an observation well was planned in the area between the injection and the first production line to monitor the flood n wells are to obtain information regarding the scaling and corrosion potential of the water and to establish the salinity of the water for petro ol that has yet to be replaced â€“ the downhole pressure gauge. Although pressure measurements are nothing new to the oilfield new appli wever it slowdown in the vicinity of shale barriers as expected. Analysis of the source mechanisms of induced seismic events reveals that m blems of evaluating fracture height in tectonically stressed formations. Furthermore it shows that while both temperature and tracer logs ma

h-permeability (~5 000 md) sand situated 60â€“100 m vertical depth below the surface and containing high-viscosity bitumen; Fig. 2. The ov his work as sub-critical velocities. In the discussions presented in this paper it will generally be assumed that the wellbore and the flow path ical velocities. In the discussions presented in this paper it will generally be assumed that the wellbore and the flow path under considerati n logging sensors employed in the oilfield in the 1950â€™s and many papers have been dedicated to their interpretation. Most notable were

sts. Restricted access to a test separator often imposes constraints on when this information can be gathered and the empirical relationshi

ential benefits. Introduction Every morning Production Engineers in any asset have to answer two main questions: are the wells proformin ater cuts have increased due to water encroachment mechanisms like coning flow through natural and hydraulic fractures and short-circuiti ce test showed anisotropy which could be critical in the implementation of a water injection project. Overall the interpretation of the data from tight viscous emulsions. ï¿½ Introduction Understanding reservoir rock and fluid properties and the well location in relation to the fluid co stance of real time reservoir and production monitoring was able maximize oil recovery from a well that was underestimated through identif to determine optimum transient durations. This paper describes several examples of formation tester surveys that have been remotely mo field recovery. Introduction There isno doubt that monitoring layer production and pressures is the key to optimal reservoir drainage in stac n geomechanical strains associated with increased pore pressure thermal-stress changes and dramatic changes in material properties ass adding significant value by reducing the voidage risk to the secondary reserves. Introduction The Azeri-Chirag-Gunashli (ACG) complex of with one sensor per joint of screen. The sandface data were available onshore during the cleanup phase allowing the operator to monitor th

vironment automated workflow application recommendation and potential benefits. Introduction Generally in current operations individua er producing zones are identified water shut-off solutions can be subsequently designed for the purpose of restoring the wellâ€™s oil prod

. This is considered as an indication of rise in oil-water-contact or lengthening of transition zone. In the present case the remedial measure tion (Sigma) logging has been in use in logging industry for cased hole and open hole applications for many years the high energy neutron istivity distribution information EMI require at least one kilometer distance or separation between wells. ï¿½ Prior to the field deployment s tion especially in the lower two oil bearing units of the reservoir (Bhatti et al. 2006). Consequently water injection has been implemented fo ns predictive tools and how to optimize CBM completions. Introduction: CBM Resources Worldwide CBM resources are estimated to be in image. Maximum horizontal stress direction has been computed from acoustic anisotropy evaluation. This maximum stress direction and c e desorbing from these adjacently connected coal seams. But later in the life of these wellbores when the BHPP is significantly reduced th ncountered. Introduction The Barnett shale is a Mississippian marine shelf deposit that lies unconformably on the Ordovician Viola limeston croseismic events is measured during fracturing.ï¿½ The spatial extent of these events defines the region affected by the stimulation treatm urrent model that is utilized is the wells are drilled with coiled tubing drilling rigs cased and cemented. Wireline perforating crews are then d ogs.ï¿½ Infill drilling strategies taking into account the location of offset hydraulic fractures are reviewed as well. Barnett Shale History De dology for capturing the essential characteristics of Barnett Shale gas reservoirs and offers a quantitative means and platform for optimizing on Many SAGD reservoir computer simulation studies have been conducted to understand a reservoirâ€™s response to steam injection. Th transformation of this organic matter by bacterial (biogenic gas) and geochemical (thermogenic gas) processes during burial. The gas is sto se lateral coverage and improve gas recovery. To date more than 20 fracture diversion designs have been successfully placed. The trial we d trying to expand and enhance the knowledge of carbonate matrix acidization. Plenty of mathematical modeling efforts are intended to brid mize failures. Introduction Saudi Aramco discovered the offshore field in 1963 and placed it in natural production from 1966 until 2004. The

wo are combined to form a Venturi tube. As shown in fig 1 it consist of a tube with a constricted throat that produces an increasing velocity a s an element of the field development system ensures increase of recoverable reserves enhances production of marginal reserves and imp other northeast-southwest fault seal the accumulation through the contact with the same shales of Morro do Barro Formation (Filho 2005). ted in detail and an overview of all installations to date. Introduction The US and Canada tight gas market is deploying new methods to effic were calculated. The unconfined compressive strength (approximately 200 to 300 psi) values demonstrated that in fact it concerned very un generally assume that steady flow conditions exist in the wellbore.ï¿½ This in turn generally requires that a sufficient system outflow rate or generally assume that steady flow conditions exist in the wellbore.ï¿½ This in turn generally requires that a sufficient system outflow rate or Kuwait City near Ahmadi Kuwait and covers a surface area of about 320 square miles. The four main reservoir units comprising the Greate

ement strategies. As a result of the proof of concept project Increment-3 was developed with MRC ML wells with SCs. are poor sweep efficiency and low contact factor. By our convention sweep refers to areal displacement. The contact factor is determined b nagement strategies. As a result of the proof-of-concept project Increment-3 was developed with MRC/ML wells with SCs. Modeling was u

completion to be a truly revolutionary and cost-effective solution for the industry. ques have been implemented such as using nitrogen to produce the well which gives good results but is very expensive. Another technique abits even a moderately sized data set through application of what we consider to be the only truly appropriate technique for analyzing time wide field trial of the new technology was successfully implemented. This paper will discuss in detail the design execution post-stimulation rm the first three fracture stimulations. The first fracture stimulation was performed in 2004 on the CD2-37 well in a poor quality area of the

rea and primarily homogeneous versus the productive Bakken in North Dakota which ranges over a large geographic area and can be very el loading. Combining this solution with the use of advanced HGC materials offers unprecedented results in regard to fracture-height contain and the excellent post-stimulation results achieved. Bottomhole pressure gauge data were collected and production logs were run to asce large size ISP proppant suspension by degradable fiber in viscous fluids was performed for this project and described in the paper. Weste r return permeability on cores above 1 mD. There are several implications of these results for the operator. Different flowback additives hav al. 1982 1998; Teufel and Clark 1984; Thiercelin et al. 1989; Wang and Clifton 1990). Because of these studies it is now well known that i oir pressure depletion and declining quality of reserves have escalated drilling completion and workover costs per unit of gas produced. Ma e Conservation and Recovery Act (RCRA) the Environmental Protection Agency (EPA) the Clean Water Act (CWA) and the Safe Drinking ft.ï¿½ The sandstone reservoirs have low permeability and limited areal extent and beds do not correlate from well to well in the pay section tion rate increased from 2 to 135 BOPD whereas the average estimated after-treatment production was 130 BOPD for which this techniqu eatments often renders uneconomical results which drastically alter pay-out time overall hydrocarbon recovery and profitability. Problematic which is five times the field average and three times greater than the best well in the field without requiring artificial lift. Background With m als. A description of the well candidate selection process formation damage identification and the remedial treatment design execution a to improve hydrocarbon recovery a task that is becoming more and more difficult as they are pushed to develop fields in more complex set

ation of the long horizontal section was achieved. Through this technology multiple mechanical isolation points are created in the wellbore u

ajor onshore brownfields discovered in 1983. It is located in the state of Gujarat on the western part of India. More than 560 wells have be

ce to understand the difference in the geological setting and the overall diversity in comparison to Western Siberia where the majority of hyd

e layers with lower fracture gradients may take more of the treatment than planned leaving the higher pressure layers only partially treated. ng vertical wells in multiple layer tight gas reservoirs. Jetting is another method replacing perforating with a recent increase in popularity. T of time limitations. This work is only the first step toward practical hydraulic fracturing design in soft rock formations. The model is supposed ES fluid presented here utilizes a specially formulated zwitterionic surfactant that creates stable micelles with unusual high-temperature sta

nds can be broadly classified in 2 groups that are mostly comprised of ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ (1) a poorly sorted coarse grained to con

production. Lack of adequate aquifer support has caused field reservoir pressures to decline from an initial pressure of 9600 psia to the cur ger less effective treatments. It is well documented in the literature that hydraulic fractures often underperform: Frac and Pack completions he fracture system can lead to optimum completion designs and well spacing.ï¿½ These changes can then themselves be evaluated with t

aves generated by the perforation shots located in the treatment well assuming isotropy and lateral homogeneity of the medium between we

y etched by the acid so that parts of the fracture face that have not been etched deeply serve as pillars to maintain open flow pathways wh after Minifrac or after Frac and Cased Hole Sonic Anisotropy (CHSA) which can be run at any time after frac. The direct estimate of fracture and the well is ready to be placed in production the additive will no longer emit a detectable level of radiation. This paper will describe this t

ing. In this case it was further complicated because the main pool of preselected candidate wells included wells that were either never com ate dropout was modeled in both the reservoir and the proppant pack. To model the pressure drop in the reservoir rock with a vertical un-f ermeable sandstones and allows us to understand some previously unexplained field and laboratory observations. r offset wells. Introduction Saudi Aramco has embarked on an aggressive program to develop its gas fields. The unassociated gas is being ts or OPEX). Optimization is achieved by Net Present Value maximization and by generating an incremental return on investment due to the of the P- and S-waves also can be used to deduce the orientation of the fracture plane associated with each microseism (Zoback and Zin owback is a term used to describe the phenomenon of proppant being produced out of a hydraulically created fracture during treatment clea e fracture to decrease over time as the reservoir depletes and this decrease is greater in the direction parallel to the fracture than normal to g into account non-linear effects in fluids displacement allowed to explain new experimental results on the pear-shape of fingers and period extensive set of accurate parameters. These models will be greatly enhanced by calibration from direct measurements of the fracture geom

underperform: Frac and Pack completions exhibit positive skin values 4 5 and traditional hydraulic fracture completions show discrepancie ates are discussed in this paper. This paper also describes the evaluation of skin after each injectivity test from pressure transient analysis. fracture covering two different reservoirs. Also the minimal horizontal stress directions were evaluated on these five wells. Surprisingly a n at can be used to obtain the ultimate extent.7 9 One common feature which was observed in all of mapping experiments cited above is the al lift system. 2. Mitigating the effects of high water-cut in both well production and start-up. 3. Maintaining tubing-head pressure in subsea w of mid 2006 approximately 50 high-rate gas wells were completed in these six fields with 10 cased and perforated (no sand control) 2 stan n the wellbore using the high performance open-hole packers. The system allows precision placement of fracturing fluids to maximize post-f the wellbore using the high performance open-hole packers. The system allows precision placement of fracturing fluids to maximize post-fr e horizontal wells into production will be proposed. Introduction The Tambora field lies in the swamp environment of the upper Mahakam de weak aquifer dictated the use of horizontal completions to minimize the potential for early gas breakthrough while achieving economically-de mpletion architecture was successfully installed in consolidated sandstone and non-consolidated formations with permeability varying from 2 t well completions are being used onshore and offshore to manage and optimize production improve recovery manage water production b

h additionally incorporate data from downhole reservoir-imaging sensors may yield near-optimal gains. Introduction Intelligent (or smart) w s was given in the design and interpretation of results. Often these tests have shown rather unpredictable often â€œwandering and â€œb

ow marine to lower coastal plain reservoirs are composed of interbedded porous/permeable sands with varying percentages of interbedded minimizing sand production. Introduction Sand production is a major problem in many oil and gas reservoirs worldwide. It can drastically red rmhole propagation influenced by fluid-rock interaction chemistry3 and treatment design (volume concentration and injection rate)4.ï¿½ All ms were probably generated during the Ercynian phase and were reactivated during the Mesozoic period to generate the actual structural se proper selection of zonal isolation method that can withstand the wellbore condition providing adequate isolation whilst able to be retrieved effectiveness of the technique under borderline conditions and promote its application in similar scenarios worldwide. This project shows th e HZ fields consist mostly of stacked thin sandstones sufficient single-well productivity can be achieved by either commingling production f ures to break the fracturing job minimized screen-out effects limitation of micro-annulus effects and the maintenance of casing-to-cement purpose. Due to the barge logistics and the drilling program some wells have to wait some time after drilling is completed (months in some c measurements. A field example where both the skin and flow rate vary demonstrates a successful application of the new solutions and inter indicated that the main cause for the high skins was the perforation damage and/or the overbalanced condition inducing losses of damagin er or gun. Examples of serious damages are overswollen guns and split guns. It is true that all guns will swell after shaped charges are deto

ometry to yield a jet of optimal velocity profile and enhancing manufacturing precision are critical [1]. However all jet perforators produce a n criteria job execution requirements and an evaluation of the results for several wells in this field. Total job costs will also be evaluated. Th high rates (Fig.5). After one year of production the well was worked over the conventional completion was pulled out of hole and a smart c (1) the giant Albacora Leste field is the 4th biggest field in Campos Basin. The field was discovered in 1986. However at that time the dev produce sand-free after extreme reservoir depletion." eral completion of a tri-lateral well. Well History â€“ Introduction HWTH Well No. 34 was drilled to a total depth of 6 662' and completed on ns developed to successfully frac-pack the subsequent Magnolia reservoirs. or poor completion methods. These factors lead to sand production and wellbore instability. Staticâ€™s show that over 60% of the wells in t

n the clean up fluid helps to promote the dissolution of starch and calcium carbonate components used in the drilling fluid mud.ï¿½ Labora (Kaverage between 800 to 1500md) with low viscosity oil (0.5 to 0.8 cP). GOR ranges from 700 to 1100 scf/stb. Formation Sand Particle Si

or the application of the most common effective and reliable sand control completion: gravel packing. Until now standard open-hole gravel e gravel up to an equilibrium height which is controlled by the circulation rate with higher rates leading to lower bed heights. In the Alpha/Be ficantly increase the success rate of gravel-pack jobs in horizontal wells. m two previous applications of the OB carrier fluid. A detailed description of the yard tests conducted in Nigeria and the onsite QA/QC proce 5 000 BOPD. Introduction Sand production is a major problem which has plagued the petroleum industry for many years. Every year the p as 5 000 BOPD. Introduction Sand production is a major problem which has plagued the petroleum industry for many years. Every year th However the cell geometry boundary conditions and stress field in these experiments are not truly representative of the in-situ conditions a within the M. Australis formation at 2230 ft TVD subsea. The average reservoir pressure is currently around 415 psia with rock strength (UC ate and drawdown. Sand production can lead to facility upsets erosion of tubulars production decline and in extreme cases loss of the w

equipment and block flowlines and trunklines. It can also lead to casing failure or borehole collapse. In addition to the costs associated wit stresses and particle size to: account for plasticity effects that modify the strength behaviour of sands surrounding openhole wells and pe w the integration of information from different sources and disciplines were able to correctly identify and address a particular borehole fill pro s oil companies tens of billions of U.S. dollars annually (Acock et al. 2004). Increase in water production in the late life of oil and gas fields

se experiments. These failure patterns resulted in very different shapes of the failed zones and during the experiments very different amoun opment cost and achieve economy of scale. The development plan includes extended reach wells and there is considerable concern regard wells treated with surfactant-based acid systems showed sustained performance for longer times than those treated with other acid system ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ 2. There were large differences in the conductivity created with the three acid systems tested. At 200ï¿½F the a ental to understanding how good zonal coverage was achieved using different techniques. Additionally production analysis has been conduc s. A production logs was run in the acid fractured well to ascertain the effectiveness of the technology. The results are discussed and comp nt execution and the excellent post-stimulation results. Bottomhole pressure gauge data and production logs were run on these wells to asc with 11 600-psi reservoir pressure and an average temperature of 118ï¿½C. Producing media varies from natural fractures and fissures t h a productivity index (PI) of 2 bbl/D/psi good reservoir quality and a negative post-acid skin value (s~ -4). Well B tested a 180 ft MD/TV

plicated stimulation method as it involves complex chemical reactions in the near wellbore matrix1 2 3 4 10 16 . Unlike carbonate acidizing

olved are simple the results are almost guaranteed even when using acid systems with a minimal amount of additives. The main question t companies are developing carbonate reservoirs of deeper and deeper depths in order to meet the demand of increasing worldwide energy

with an orientation of N-NE to S-SW with two domes separated by a fault as shown in Fig 1. The field has an active aquifer that has maintai and chemical diverters used in the oil industry.ï¿½ The various mechanisms by which these chemicals to achieve acid diversion their applic of 90-s. In the following years proppant fracturing became a common completion method for newly drilled and already producing wells for al The second set involved determining the acid breakthrough curves for each of the carbonate types using HCl (hydrochloric acid) as the rea ogy to a particular field type will inevitably lead to a higher success rate of restimulation walkovers and the capture of an underexploited res oam with high foam quality (70% quality) was used where foam quality refers to the percentage ratio of CO2 over the total foamed fluid vol ge. The fold is bound on the west by a high angle reverse fault. The complex produces from three geologically distinct accumulations the W he wells in this formation were contributing 70% of the total production; increased flow from the rest of the wells would greatly improve the

This is confirmed by the production logging results. Once the water is broken through those high permeability streaks or natural fractures t ations. Communication tests regarded as the most definitive method of testing behind casing isolation jeopardize casing integrity are costl d using the approximate rates during the flow period. As such the estimated reservoir parameters are susceptible to significant errors. This ability carbonate reservoir unit within the Greater Burgan field. The matrix permeability is low and consequently the few vertical wells comp iency in terms of the reservoir response and contribution identification of non-fractured zones bypassed zones (zones without a frac) unde eakthrough. Consequently a water shut-off job is planned for this layer. In the second well MLT analysis showed that the upper layer had po he combination of partial penetration and dual-porosity effects yields unique finger prints at early and transition periods. These unique chara mating reserves from pressure transient well test data very often arises in oil and gas explorations as well as in other oil industry application ble to overcome the shortcomings of traditional well testing and address the concerns of both engineers and the management.ï¿½ Case st oduction data in the form of a constant-pressure rate system response have emerged with development of robust pressure/rate (von Schroe

ction Naturally fractured reservoirs differ from homogeneous reservoirs from many points of view: geological petrophysical production and

nse saving in rig time and cost since the workflow allowed delivering answers which enabled us to determine AOFP without resorting to conv providing operational flexibility and additional information of interest to optimize well productivity. Introduction: Field and Wells Description aracterization provides insights on the benefits and limitation of sampling in multiphase flow combined with proper conditioning of the samp

arator a second mobile MPFM a 1440psi separator and a multiphase tracer technique. The objective to determine the most reliable techni been successfully performed recently that show acceptable performance capability and the benefits of this methodology compared to the p or application to surface well testing and flow-measurement allocation in multiphase conditions without separating the phases. This has res nt wells due to system back pressure testing wells located on platforms not equipped with testing facilities easy mobility of the phase mete

also put a special emphasis on the salinity change. Introduction A 3 phase flow measurement requires as minimum information the veloci rved well test data. The first has been the subject of interest for some time. Most well testing software with numerical option focus on this a rs are more comfortable with "rate decline" analysis." termed noise.7â€“9 Various algorithms have been used in an effort to eliminate or reduce the inevitable noise associated with the numerica a Mansfield sandstone reservoir in Indiana. 1 2 A 16-electrode array was cemented into the annulus of each well (Fig. 1). The lowest eight

ause slurry dilution/concentration and chemical incompatibility which in turn can have a major negative effect on the capacity of cement to g ge operations . Forecasting such effects requires a 3-dimensional geomechanical model of the site describing in-situ rock stresses fluid pre

e risen. One of the most likely causes is the emission of anthropogenic greenhouse gases into the atmosphere where carbon dioxide appe h it is the dominant component) enhance several processes when compared to injection or production of hydrocarbon gases. This is not on e data exist the section was characterized successfully by analogy. Introduction Since the publication of the Intergovernmental Panel on C ed. Introduction The prospect of global warming is a matter of genuine public concern. The concentration of carbon dioxide in the atmosp roduction The climate of the Earth is warming with widespread changes in ocean salinity wind patterns precipitation and aspects of extre

sea development drilled by a separate semi-submersible rig. A new technical and economical study showed that this well could be drilled process for redevelopment of an otherwise impossible matured field. The case is the Dumbarton development project which is a redevelop

iques is the Silurian reef trends of the Michigan Basin Figure 1. These reefs occur in the Guelph Formation which is a stratigraphic unit th s in Mexico. A field example of potential EOR application in a mature oil field is shown. Introduction Quebrache Region contains numerous d technology drivers. Since the mid-1990s however the trend has been ever-decreasing productivity and faster rate declines. At the same irely new wells.[5 6] In this study we proposed a practical strategy for rejuvenating vertical well production of gas-condensate reservoirs u ors could reach up to 60% in the areas impacted by the steam. Several SAGD projects have been applied in Canada demonstrating the eff r this initial period of gas injection water injection was implemented in the A C D and E reservoirs (1970 to 1984). Previously unknown frac

ue to the crystallization of magma lavas alteration due to the tectonic activities alteration due to the hydrothermal activities alteration due t ation ratioâ€¦etc). The recently developed TTIP systems are specifically designed to perform reliable zonal isolation in HPHT environment ent and squeezing it is important to ensure that a good cement job has been performed. Operationally the top of cement (TOC) is tagged

st and ranges from 5000 to 9000 ft in depth. Boscan Field is a combination structural/stratigraphic trap. The reservoir sands were deposited duction zone by plugging back the lower zone. Production engineering evaluated all the available techniques to conduct this job with out uti oil rate is reduced due to increasing water production which dictates the need to perform water shut-off jobs to sustain oil production. w assurance aspects. Traditional production hindrances intervention costs and remediation techniques are very costly options for deepwate es. The results are significant for the design of pipelines and separators. Moreover the interpretation of production logs in horizontal wells r ems usually have large difference in viscosities similar densities and more complex interfacial chemistry compared to gas/liquid systems. e monitoring devices deliver the measured data in real-time that allow the on-line analysis of the engineer. However these sensors alone e of the full well-surface facility system. Summary Efficient optimization of large and complex production facilities (involving wells pipeline n stical Associating Fluid Theory (PC-SAFT) equation-of-state (EOS) model1 2 is the thermodynamic tool used to predict asphaltene precipita peline blockage. Deposited wax will also increase the roughness of the solid-liquid interface and thus increase the pressure drop. Therefor hermodynamic communication are of critical importance. Appropriate design of completion and production facilities and optimal planning of generation Downhole Fluid Analyzer (DFA) tool was introduced together with the launch of the new and improved Wireline Formation Teste

atio initial stock-tank oil gravity and specific gravity of the original reservoir gas. This is the first proposed dewpoint-pressure correlation tha positional reservoir simulator. These new correlations depend only on readily available parameters in the field and can have wide applicatio tion and diffusion generally cause reservoir fluids to move towards equilibrium but at very different rates. Diffusion can be very slow across correlating / integrating such data is not always enough to avoid unexpected results. Missing productive intervals in a new well zones with racterization strongly affects in-place-volume recovery-factor injectivity/productivity and welldeliverability calculations [1]. Inaccurate fluid c

nse surface based model which can serve as a pre-job planning or real-time analysis tool was derived from extensive simulations conducte ay to obtain fluid samples but usually does not allow a detailed areal or vertical fluid scanning for compartmentalization gradual variation o

evelopment of new reservoirs. In addition mini-DST or Interval Pressure Transient Testing (IPTT) can be carried out at DFA stations to prov Naturally it can be found in coal pits sulfur springs gas wells and as a product of decaying sulfur-containing organic matter particularly u

he time to reach such an equilibrium (10 million to 1 billion years) is comparable to the geologic time of a typical reservoir. A number of aut up from deeper reservoirs via faults and other pathways by hydraulic leakage from the crest of the underlying reservoir or by capillary leak role in reservoir characterization and hydrocarbon volume estimation. In thick porous and clean reservoirs the process of fluid identificatio ely short vertical intervals. Such reservoirs are of great interest for reservoir engineers and petrophysicists because a proper assessment of r evaluation and management and input to aid decisions about well completion strategies and field production schedules. Modern wireline s. An equation of state is elaborated from a sample and its PVT experimental results and a compositional gradient is parametized using the for most crude oils. However for heavy (dark) oils the contamination prediction from the methane component and the GOR prediction bec

according to a simple fluid equilibrium model. A non-linear pressure gradient regression fit is also examined. The choice and appropriatenes is roughly correlated with fluid density: high-density fluids have a low GOR value and low-density fluids have a relatively higher GOR value. rvoir fluid properties such as hydrocarbon composition GOR density viscosity CO2 content pH and PVT behavior are key factors for su

discussed in this paper have been tested thoroughly in a new reservoir simulator4 over a number of years.ï¿½ They are being used in a ma d viscosities increased as much as 500% because of the presence of emulsions before a sharp drop in viscosity beyond the inversion point

n exploration to ascertain the true nature of a discovery and to assist in defining reserves to value the economic potential. In appraisal phas en restarted to slowly push the clean fluid column into a sampling bottle. Downhole Fluid Analysis (DFA*) was used to constantly monitor the atorsâ€¦) by construction are measuring flow rates at line conditions and therefore the use of PVT data to convert the flow rates at standard sampling required for any type of well testing to optimize well tests and capture of samples for further analyses in a PVT laboratorf after sa of chelating agents with calcite at low-moderate pH values. The details of adsorption complexation and desorption are necessary for investi n The economical exploitation of Algyo field posed challenges because of the individual behavior of its reservoirs thin oil edges and moder ypass any damage in the near-wellbore formation; for comparison matrix acidizing fluids are intended to dissolve near-wellbore damage in is potential for sodium chloride deposition (halite) during production due to the cooling of the reservoir fluids. Salt deposition downhole may

n tunnel and thus create a zone of reduced permeability around the perforation. Perforation flow experiments have increased our understan displacement of the rock creates a residual elastic stress in the far-field undamaged porous medium (known as a â€œstress cage).ï¿½As nerals in the produced or injected water. Supersaturation of a mineral occurs when the mineral concentration in brine exceeds the equilibriu queeze treatment was developed to effectively place a scale inhibitor in the near wellbore region1. A variety of squeeze techniques for app the deposition of scale.ï¿½ The technical feasibility and economic viability of implementing intelligent well technology for scale manageme ning fluid. Most of the job objectives were not completely accomplished due to severe hard scaling conditions. Introduction Upper Zakum fi east of Ekofisk Centre.ï¿½The offshore installation comprises a conventional 6-legged steel jacket which supports integrated production d duction forecasts that are accurate. For these forecasts to be as reliable as possible a necessary condition is to ensure that the model enco fracture models are generated stochastically by using cores FMI and seismic data. These fracture maps should be validated first to assess merical approaches solve the multi-dimensional problems associated with fluid flow in the porous media.ï¿½ One significant breakthrough in vance of the fluid levels around the well; and bottom hole choking to control the gas overproduction problems have also been included into extends the productive life of the wells beyond initial expectations. Introduction Major oil companies are promoting new technologies that p l drawbacks are greater costs and higher local pressures which could induce uneven flows. Detailed pattern flood modeling helped develop yah field was discovered in the 1950â€™s with the drilling of the SA-001 well. Production commenced in 1958. Located in North Kuwait (Fig nd contains the countryâ€™s largest deposits of extra-heavy oil estimated to be 1.2ï¿½1012 barrels of oil in place (OIP). The Cerro Negro se to assist in the comparison of their worth using common economic parameters. Introduction Heavy oil reservoirs are increasingly being the production of active carbon spent carbon regeneration and the surface chemistry modification of carbons are only a few examples of th . During the investigation different scenarios were analyzed to obtain a generalized step-by-step optimization procedure for the process un in the field. Three hydrocarbon bearing layers have been encountered at the shallower depth. Viscosity of the crude oil in field is very high. ed 10%. The oil API in this heavy oil reservoir varies from 14-20ï¿½API. The 1st Eocene is a depletion drive reservoir with partial solution ga eavy oils). In this paper application of interval pressure transient testing done during formation fluid cleaning up from mud filtrate and durin

cond reservoir with stratified unconsolidated paysand and average viscosity around 450 cp at 500C. Bentiu reveroir is prone to sand produc

ct to conventional matrix stimulation fluids. Issran Field Overview The Issran oilfield concession consists of 20 000 acres (Figure 1). It is loc

f view that the overall uncertainty of the entire system (Venturi-Tank) was better than 2%. This extended the new multiphase technology ope

sensitive aluminosilicates may dominate treatment design considerations even though they may be present in small quantities compared to ed to the successful completion of the operation. This paper describes this first successful application of a dual-packer wireline formation t

nvestigated. Introduction Grading in hydrocarbon reservoirs are due to a combination of gravitation diffusion (molecular and/or thermal) an

ntroduction Achieving the design fluid viscosity at in-situ conditions is critical for a number of reasons. Fracture initiation propagation and roduction. It is also used to stimulate water injection wells and disposal wells to increase the formation uptake of the injected fluids. Oil and

out the producing life of a well or field. The fundamental component of this system is the permanent quartz pressure gauge. Schlumberger a Sea 120 kms south-east of the port of Vung-Tau in Vietnam. The field was originally discovered in 1974 but was placed in production only O3 6-18% clays (mainly kaolinite) 5-10% feldspars and siderites in some wells (2-5%). The reservoir pressure in zones ranges between 8 d the use of ethylenediaminetetraacetate (EDTA) chelating agents as the primary active components in fluids used to stimulate limestone a nds of the San Jorge Basin store important hydrocarbon reserves covering an extensive area across South Argentina. The basin-fill was by displacement stage where water is expelled from the core followed by a long-term evaporation stage. The amount of water displaced in the ue to validate the representativeness of the sample as it is transported from downhole to the laboratory. Introduction Water sampling in ex

l wells drilled on 640 acre spacing. In a bid to effectively drain the reservoir it was downspaced to 320 acre and more recently to 160 acres

s (North America and the Middle East) has resulted in significant improvements in production optimization as well as in single-well and field 00 feet. The productive sands have an average porosity of about 7% and permeability is in the micro-Darcy range. The first well was drilled ffect of fracture wings length asymmetry may be also explained by the disturbance of initial stress conditions. The results of this investigatio acture width induced porosity and permeability. Introduction Traditional models assuming single- or bi-wing type of induced fractures have e Taylor sand located in the Cotton Valley sands. It came on line with higher gas production than the offset wells. For the first 6 months tota

g was applied the operator decided to drill an open-hole horizontal well that was to be multi-fractured. The initial 90 days average productio ulated in a single operation and once completed gas is produced from all intervals in a co-mingled manner. The treatment utilized 200 000 to 150 md M3b layer. The new horizontal and horizontal sidetrack wells average 3 031 BOPD and 5% water cut compared to production o which assume no interference between wells. There were also lack of adequate reservoir characterization and little or no integration of the ing program has resulted in changes to completion and production strategies that have resulted in significant cost saving via modifications t the best results and they were used during the history matching of the wellsâ€™ performances. Introduction The subject field is located in dd to the reserve base of tight gas.ï¿½ Introduction Identification of low resistivity from highly laminated sand/shale sequences has been an

tional ones (Verma et al. 2007). The NJ-SR sections are very tight with matrix porosity <5% (Verma et al. 2007) while the MRï¿½section d samples provided significant answers and clues to a broad range of reservoir issues including compartmentalization fluid compositional v rategic importance of these unconventional tight reservoirs for the gas production of the years to come. Recent advances in logging techno esaverde Group comprised of shallow marine sandstones deposited along the western margin of the Cretaceous Seaway. Changing sea-le

¿½1. ï¿½ï¿½ï¿½ï¿½The tool with a probe and packer assembly connected to a pressure measurement gauge via a flowline is positioned pilot areas. The southern area with one reservoir of 3 to 20 md and the central area with three stacked reservoirs of 0.1 to 10 md each se ences of what may happen if these issues are not considered properly. Through this method horizontal-well feasibility and economic results extensive oil and gas accumulation zone with the total square of 20 000 km2 main reserves of which are associated with the Riphean depo

quantities of economically producible oil. In the literature numerous studies have been published on the potential and importance of capilla

nergy resource accounting nearly 40% of primary energy demand. Its occurrence is widespread in all the continents. Commercial oil discov

effectively incorporate and evaluate all known factors and outcomes associated with a required decision. The goal of this process is to prov cy to seek information even when it cannot affect the project. Perceptual biases can skew the ways we see reality and analyze information.

to reservoir simulation and management. Introduction Capillary processes critically affect initial reservoir fluid distribution and petroleum re ode array responses for water front monitoring and multiphase formation property evaluation and confirmed the first pass estimates of the id n the other hand more advanced tools such as borehole imaging tool or Nuclear Magnetic Resonance (NMR) are run on a limited number tion The eastern offshore of Indian peninsula (Figure 1) has become a major exploration target after substantial hydrocarbon discoveries o e been interpreted as fluvial deposits (Turner et al 2001 and Sabaou et al 2003). The field corresponds to an estimated one billion barrels ervoir fluid. Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large numb pment scenario correlating / integrating such data is not always enough to avoid unexpected results.ï¿½ Missing productive intervals in a n ailable which can make direct continuous permeability measurements. Logging tools instead measure a surrogate for it such as a textural e ribution of wells with residual oil saturation areally suggests the presence of a stratigraphic trap within the formation. The 3D seismic volum onventional stabilized gamma-gamma density measurement is located within 8 ft of the bottom of the tool; this provides average and quadr ally complex tight carbonate reservoir through the use of the new measurements. The favourable environmental conditions (low temperatu

accumulations. However quantitative measurement of oil in place is not simple because calculation of the oil saturation of a reservoir from ever quantitative measurement of oil in place is not simple because calculation of the oil saturation of a reservoir from electric log respons types which each have a particular porosity-permeability relationship. The workflow presented here facilitates various forms of rock typing. sed reservoir or oil pool could be penetrated. Geologists assess vertical and lateral changes in the reservoir by identifying and characterizing The well in this case study is from a Middle East carbonate reservoir consisting of interbedded limestones and dolomites with anhydrite cem metric estimates of moveable fluids. Care must be taken to ensure that productive sand units are not discounted by formation evaluation in v

nations has been treated by many authors for the last 30 years. In recent years we have studied experimented applied and refined the inte

s known about the relationship between their properties and spatial distribution with the dynamic measurements of the reservoir. Extensive olidated formations. Introduction Deepwater reservoirs often consist of geologically young turbiditic formations which even at great depths ge logs is of significant benefit to understanding the reservoirs and their interactions. Introduction Faults and fractures are normally interpre These platforms seem to consist of complex internal geometries which have been identified from the seismic signatures of high resolution

on barrels of additional oil in-place compared to the previous geostatistical models and uncertainty evaluation based on the facies scenarios At the start of an exploration campaign the operator wanted to ensure that the hydrocarbon column extent and the productivity of thin bed y the characteristic NMR bimodal relaxation distribution in thin beds and to investigate whether the fraction of sand/shale and the sand por

ore improves the reservoir summation results. As a result we propose a borehole 3D position measurement that is accurate consistent be

oir. This stress alteration can result in reorientation of maximum and minimum stress directions that in turn affect the fracture propagation di rent variables such as density velocity and porosity from the same wells were also obtained. Three artificial intelligence methods viz. Neur drilling through the depleted sand was successfully handled by using special drilling fluid to mitigate seepage losses and the differential stick

e and pressure history of the well prior to that point in time.ï¿½ The integral relationship given in Eq. 1 can be readily evaluated as a summa

ne created by a fault-propagation fold of a normal fault that located nearby well. The formation micro imager Stoneley waves elemental sp cline that was delineated by seismic data. Commercial flow of oil was produced from the carbonate reservoirs of the â€œM horizon that rep d in their orientations. However most of the studied wells in the Upper Arab show a major NW-SE trend perpendicular to the direction of th Commercial flow of oil was produced from the carbonate reservoirs of the â€œM horizon that represents the uppermost portion of the Pale

ending on the number of test points desired.ï¿½ Though the fine laminations of the tight gas sands is a major reason for observing low suc

ics of our fields. Introduction The gas-condensate reservoirs from Devonian age of the Bolivian Sub-Andean that lie between the 3000 and cap existence ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½- ï¿½ï¿½ï¿½ï¿½fill the gaps of missing fluid information in zones where sampling is difficult su

e NMR logs are acquired over hundreds of feet under conditions where the acceptable logging time is dictated by the cost of rig time and th applications include estimation of permeability pore-size distribution free-fluid volume oil viscosity and wettability. The modern phase of 0). The Cretaceous-Tertiary boundary is characterized by an Atlantic marine incursion that generated a regional unconformity above which ve optimum production/injection is challenging especially for multilateral horizontal wells. First of all it is much more difficult to complete ho

w gaining greater importance. Benefits of UBD include the reduction of formation damage by minimizing drilling-mud leakoff and fines migra s. The oil-bearing Mishrif/Rumaila limestone reservoir have been drilled and mostly appraised via wells dedicated to developing the Lower C

ated with geologic data to better assess reservoir continuity and/or compartmentalization before field development commences. From these f the fluid in the oil column creating in essence a continuous downhole fluid log. With a multi-well approach DFA can address the fluid distri te and pressure history of the well prior to that point in time. The integral relationship given in Eq. 1 can be readily evaluated as a summatio ns. Field Description The large onshore As Sarah oil field discovered in 1989 is located in the Sirte basin of eastern Libya. As Sarah field is nite and illite) in which gas sands are not in pressure communication. Figure 1 shows an image log of a 4-meter section where very fine lay

Western Siberia) do not necessarily indicate the prevalent stress direction in a reservoir. In western Siberia low permeability reservoirs are c they require careful formulation to account for additional effects. Specifically formation testers can be used during measurement while dr development and management decisions are usually made under high risk and uncertain conditions that stem from both surface and subsu nd analyzed in the laboratory. The comparison between lab results and DFA provided a benchmark for optimizing the sampling programme ne if alternative artificial lift methods would enhance production.ï¿½ A team was mobilized to identify wells that would benefit from a change analytical and numerical analyses it was found that a massive waterflood would extend the production plateau reached by infill drilling and p ol is installed to properly monitor individual well performance and therefore the field production. The surveillance tools include the real-time d challenging reservoirs. This is coupled with the fact that many of the easy oil and large thick reservoirs of Saudi Arabia have been already hydrocarbons.ï¿½ Power water injector wells are drilled to maintain pressure and improve oil recovery. The success of the water injector de e been spent in three phases over 3 years. Several operational improvements evolved which decreased downtime and cost of maintenan limitations in hardware and software and a generally too serial workflow. Trajectories are typically derived by the drilling engineer to target es of development when the gas cap expands towards the producers. Reservoir pressure is often maintained by means of crestal gas injec LG-3729 Moporo field is located between Zulia and Trujillo states (Western of Venezuela). It was discovered in 1988 by an advanced well (V etween the local single reservoir management tools and the global FM tools. As a consequence of the relative isolation of the different simu clude planning of step-out and in-fill drilling programs analysis of enhanced oil recovery methods and facilities sizing and design. The Prod field consists of 22 stacked reservoirs of varying size and thickness at depths of 7200 to 9650 ft sub-sea. The average water depth is 225 f wnfields has been defined as mature fields in a state of declining production or reaching the end of their productive lives such fields contain

e coupling point on as a new boundary condition for the next model. The reservoir simulation model as a starting point computes the fluid m been the pursuit of many Oil & Gas companies in the last decade. Finally the industry shows signs of achieving the prize of the IAM under e of the full well-surface facility system. Summary Efficient optimization of large and complex production facilities (involving wells pipeline n nconsistent data are so detrimental to study objectives that they can even prevent the continuation of those studies.ï¿½ This is one of the m r control operations performed are discussed in this paper. Introduction XJG oilfields are located offshore in the South China Sea around 1

to 2nd Bahrain and to a lesser extent to 1st Bahrain. In addition four other oil reservoirs are currently active namely Ahmadi limestone B-lim CT deploys horizontal and multilateral well technology were deposited as delta front bar and coalesced stacked fluvial-deltaic channel sand t growth makes it necessary to perform ad hoc multistage hydraulic fracturing treatments and to produce these wells commingled to be co mulation. In this paper we will use a field reserves study as an example to illustrate our unique workflow. The objective was to estimate rem parameter will allow an optimal choice of how to further develop the field. Valuation of the forward contract is non-trivial due to the presence

nal technology. Introduction Until recently the most sophisticated placement of horizontal wellbores in reservoirs was performed using realc data to predict the presence of reservoir quality sand and fluid contacts in the Outer Moray Firth Basin. Application of seismic techniques lars for the implementation of the method described in this study.ï¿½ This method also suggests that the same parametric group used to c value of that information through the appropriate application of pressure transient analysis (PTA) and its incorporation into a full-field num hese fields is critical for growing beyond this level2.ï¿½ The integration of technologies and conceptual approaches as this paper presents to reduce gas and therefore maximize oil production. Among the parameters studied for the field development plan are: type of well well co h et al. 2003 Spall 2003) and Nelder-Mead simplex (Spall 2003) methods. The second category consists of global methods such as simula

difference numerical simulators are used to construct reservoir models. However in order to make full use of such a tool a large amount o o because of the nature of the numerical modeling process issues such as gridding time-stepping and convergence can often become pro synthetic examples show the robustness and efficiency of this algorithm. The field example is from the Goldsmith San Andres Unit (GSAU) i ng well log data core data water-cut and gas-oil ratio history from producing wells; we characterize the permeability at each cell thus dem

ry matching is to build a reservoir model that integrates available data and yields production forecasts that are accurate. During history matc

dramatically. Liu et al. (2007) described a general unstructured grid thermal simulator based on mass variable formulation with the selection owing items. The fluid descriptions of the reservoir and conditions under which the properties are calculated. Examples include black-oil or This paper describes certain special wellbore dynamic behaviors that have not been covered in the literature. It illustrates the challenges of

detailed fluid flow and pressure profiles. This paper discusses the previously mentioned horizontal/multi-lateral well fluid and completion dy

e results. This is evident in the results obtained from different techniques (including dynamic simulation) when compared with production inf l fracturing fluid may remain in the fracture unless the fracture-face filter cake occupies the entire pore space of the propped fracture follow ured gas wells a number of potential damage mechanisms were identified such as hydraulic damage caused by invading fluids during th zones porosity and permeability contrast of two orders of magnitude are common in this region. A typical formation D stratigraphic column vantage of hydraulic fracturing in gas condensate reservoir is reduction of the pressure drawdown that leads to less liquid drop-out. The pre nts. Introduction Interfacial slip is one of the mechanisms that can alter the growth of a hydraulic fracture and can occur when a hydraulic fr ns are very costly; precise assessments must therefore be carried out before the operation takes place.ï¿½ Introduction Hydraulic fractu

roblem can be divided into two categories: allocation and non-linear regression methods. The allocation method1 uses standard techniques single phase analyses that have been commonly employed in previous studies were later extended to consider multiphase flow in an inves ant screenout (as a result of low rate into hence narrow width of each fracture) these wells are cased cemented and perforated over a ver ce of hydraulic fracturing treatment and its effectiveness. Connection of the wellbore to the reservoir is achieved through perforations; theref study should be attractive in many petroleum-engineering contexts in which complex nonlinear relationships need to be modeled by use of

ning each model separately. Both production and pressure data confirms that these reservoirs are completely isolated and no wells are prod he field. Therefore they are instrumental in reservoir management. Finally in terms of recovery horizontal wells are effective in achieving a g

y shows that most reservoirs experienced strong water influx. In 2004 a field review project was initiated to investigate the potential of the f en graphical methods were used. Reservoir pressure uncertainty was the most significant parameter on the material balance calculations. G has 417 active producers and 165 injectors. The oil recovery is driven by water flooding. The Bashkirian contains 7 pay zones. Marked reg natural convection that might have a significant effect on species distribution (Firoozabadi 1999). The combined effects of diffusion (pressur ction of experimental design to the oil industry in the early 90â€™s (Damsleth Egeland Larsen) reservoir engineers have developed and su

re oscillations appear for strongly anisotropic media. In multi-phase flow simulation these oscillatory solutions may lead to spurious gas vap

d reservoir can be a significant source of reserves.ï¿½ï¿½ The recent developments in image log technology are helping to identify that natu remote stress condition for elastic stress-field simulation. The latter is achieved by matching the actually observed structural deformation w

eteenth century (Helmoltz [10] and Muskat [19]). Improvement of the method and application to reservoir simulation were published by a nu . In this approach the complex flow phenomenon in fractured porous media is represented in terms of two interpenetrating continuum medi complex hydraulic connectivity. Traditional finite-difference simulators were not designed to handle such models efficiently. This is particular

n data and model is nonlinear which is the case when the data represent production data. Computational results indicate that the RML meth

especially in developments where options for scale mitigation may be limited. Introduction Water flood is a common method of providing pr

he flow in porous media [11]. Traditionally the governing equations are solved in a sequential manner: one solves the pressure equation fin separately the pressure equation by an implicit method. At this stage one can use rather large time steps. Then the concentrations transpo still takes a long and costly path consisting of testing plugging and stimulation procedures. The authors believe that in parallel to the reserv

h between the simulated and the observed pressure data is used for ranking these models. A certain threshold on the objective function m n limited. Full-field reservoir simulators allow a much more detailed representation of the reservoir flow and some of these simulators conta

native to compositional simulation and fulfills the requirements for multi-scenario production forecasts in the NKJC. Problem Statement Th

¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï wireline formation testers (WFT) and formation resistivity logs acquired in vertical and deviated wells. Typical SCAL measurements made s was the primary production from this field. Because of the depletion being noted an infill drilling campaign was commenced to recover bycreasing demand for oil more and more complex trajectory wells highly deviated and horizontal are being drilled in the areas with minimum ough we did identify seven specific areas where technology advances are recommended. Collaboration and visualization technologies are

Petroleum province definitions were based on political boundaries and mega scale surface features. Geology was used in the ANS definitio ercelin et al. 1997) and finite-element (Bosma et al. 1999) models. Although finite-element models are capable of handling more complex sit

posit. In 2006 the oil production started to decline with a sharp increase in water cut. Four wells were selected by the operator for water shu elligent completion solutions to meet its objectives.1 This implementation commenced in 1998 with natural gas lift on the Troll field using hy ion in order to identify the flow profile mainly to locate the water entry intervals. Mauddud Carbonate Formation in the North Kuwait is consis gle commingled completion and well test interpretation requires accurate estimation of the relative flow rates from each producing reservoir.

he Upper Cretaceous. By this time the separation of African continent from the South American continent was well underway and full marine he Upper Cretaceous. By this time the separation of African continent from the South American continent was well underway and full marine production line to monitor the flood front efficiency and pressure support advancement. This area of the reservoir is fairly steep and the flo sh the salinity of the water for petrophysical evaluation. Formation-water data can also give information about compartments and communi nothing new to the oilfield new applications and analysis based on pressure measurements allow proactive reservoir diagnostics that can b duced seismic events reveals that more than 80% of the representative events have a nonshear component of source mechanisms. This ob both temperature and tracer logs may add value to evaluating fracture effectiveness their results should be validated by a thorough pressur

high-viscosity bitumen; Fig. 2. The overburden thins out towards the eastern edge of the lease which allows the sand to be mined so that th d that the wellbore and the flow path under consideration are essentially vertical but the methodology discussed is not entirely restricted to and the flow path under consideration are essentially vertical but the methodology discussed is not entirely restricted to vertical wells. It is eir interpretation. Most notable were Ramey1 who defined the basic heat transfer equations pertaining to flow and temperature Kunz and T

thered and the empirical relationships used to estimate rate between valid tests are often hampered by errors and uncertainties associated

in questions: are the wells proforming as expected? And if not What is the reason?. Actual production by itself does not say anything about hydraulic fractures and short-circuiting between injectors and producers. The requirement to measure oil inflow in high water cut horizontal all the interpretation of the data from this extensive data acquisition campaign has shed light on reservoir heterogeneities that have been in well location in relation to the fluid contacts is essential to optimize production rates and maximize recovery. Production from a well can be h was underestimated through identification and continuous correction of the productivity index of the well. So by this paper we would like urveys that have been remotely monitored in real time to ensure that all WFT evaluation objectives are met. The power of real-time monitor to optimal reservoir drainage in stacked reservoirs. Knowing which layers are depleting and at what rate is information that can be directly i c changes in material properties associated with heating the reservoir sufficiently to mobilize the heavy oil/bitumen (Collins 2005; McLellan Chirag-Gunashli (ACG) complex of reservoirs are located offshore Azerbaijan in the South Caspian region and extend a total of 48 km alon e allowing the operator to monitor the cleanup in real time. Once the wells are brought online the sandface data will further enhance the int

rally in current operations individual well rates are measured periodically through production well tests of individual wells or estimated base e of restoring the wellâ€™s oil producing capabilities. Introduction It is common knowledge that oil production declines are often associate

present case the remedial measures for water shut-off operation based on time lapse evaluation have enhanced oil recovery from 540 Barr many years the high energy neutrons are emitted into formation and their capture by different elements in formation is measured. Chloride ( ï¿½ Prior to the field deployment simulations were run to confirm the applicability of the technique and define the parameters for the surve r injection has been implemented for these lower units of the reservoir. A detailed multi-year and multi-measurement monitoring plan has be BM resources are estimated to be in the range of 3 000 to 9 000 Tcf. The large land markets in Russia (400-6 000 Tcf) China (1 060-1 240 This maximum stress direction and cleat orientation have been integrated to identify seams that will have better deliverability of fluids. In thi he BHPP is significantly reduced these adjacent coal seams will be contributing more and more to the production stream. Figure 1 shows a ably on the Ordovician Viola limestone/Ellenburger group and is overlain conformably by the Pennsylvanian Marble Falls limestone. The Bar on affected by the stimulation treatment and is often interpreted to represent multiple fracture branches as well as shear movement on preWireline perforating crews are then dispatched to perforate the zones of interest in a rig less operation. The individual coal seams are then st d as well. Barnett Shale History Development of the Barnett Shale in the Ft. Worth basin began in 1981 with the drilling of the Mitchell Ene e means and platform for optimizing shale gas production. Introduction Driven by gas consumption demand and rising oil and gas prices in €™s response to steam injection. These studies normally test parameters such as grid block sizes wellbore length operational control and ocesses during burial. The gas is stored by multiple mechanisms including free gas in the micropores and sorbed gas on the internal surface een successfully placed. The trial wells have included both cemented and uncemented completions with drilled azimuths selected to encou modeling efforts are intended to bridge the gap between the laboratory scale studies and the field implementation. However crossing from r roduction from 1966 until 2004. The primary reservoir is hydraulically supported by natural water influx. The field produces Arabian Medium

at produces an increasing velocity accompanied with reduction in pressure followed by a gradual diverging portion in which the velocity is t uction of marginal reserves and improves economics of the hydrocarbon reservoirs which cannot be developed at a profit by vertical comp o do Barro Formation (Filho 2005). During the drilling of a pilot well a 187-m free-gas reservoir was initially identified. Perforating other ex ket is deploying new methods to efficiently stimulate multiple-layer reservoirs but the most common method remains the same. Most wells a ated that in fact it concerned very unconsolidated sand. Using the mechanical properties together with the possibilities for perforation design at a sufficient system outflow rate or fluid velocity exists to continuously transport any wellbore liquids present in the system to the surface.ï¿ at a sufficient system outflow rate or fluid velocity exists to continuously transport any wellbore liquids present in the system to the surface.ï¿ eservoir units comprising the Greater Burgan Field complex are the Wara Mauddud Burgan Third Sand and Burgan Fourth Sand (4S). Ma

wells with SCs. t. The contact factor is determined by improper displacement in a direction orthogonal to reservoir strata. These are discussed by Herbeck ML wells with SCs. Modeling was used extensively to illustrate the potential benefits of the incremental expenditure of MRC/ML wells with S

s very expensive. Another technique for consistently delivering commercial production rates is to use an artificial lift production method like ropriate technique for analyzing time-to-event data: SA. The objective of any SA is to identify variables that influence survival and to predic e design execution post-stimulation and the long term results from this first trial. It will also provide conclusions and recommendations on t 37 well in a poor quality area of the reservoir on the southwestern edge of the field. The next two stimulation candidates selected in late 200

e geographic area and can be very heterogenic in nature. Fig. 1 shows the geographic extent of the Bakken. The Bakken is organic rich sh s in regard to fracture-height containment where positive net pressures were obtained the first time. These operational results were confirm and production logs were run to ascertain the effectiveness of the new technology. Results from the conducted pilot along with production h and described in the paper. Western Siberia field and degradable fiber-laden fluid provided a good example of how one solution may be a ator. Different flowback additives have a tradeoff of properties and depending on the reservoir selecting one that leaves the formation with e studies it is now well known that in situ stress contrast is the dominant parameter controlling fracture height growth and that Youngâ€™s er costs per unit of gas produced. Many reservoirs that were previously considered marginal are now exploited with an emphasis on maximiz er Act (CWA) and the Safe Drinking Water Act. For instance to discharge into surface water in Pennsylvania and Wyoming the company m e from well to well in the pay section.ï¿½ Wells are completed in up to 12 hydraulic fracturing stages with each stage treating 5-7 sands.ï¿ s 130 BOPD for which this technique was considered successful. A shortcoming of the technique for this application is the fact that the botto ecovery and profitability. Problematic production of water from outside the zone of interest can rarely be reversed. Here the operator incurs ing artificial lift. Background With more than 8% of world reserves Kuwait is blessed with an abundance of oil. However oilfield operators r medial treatment design execution and results is briefly discussed along with the economic impact that such treatments offer to mature oilf o develop fields in more complex settings and with poorer reservoirs properties. Horizontal wells have been a tool widely used to improve bo points are created in the wellbore using specially designed multiple open-hole packers and then selected zones of varying lengths can be

India. More than 560 wells have been drilled in the field to target 13 major sands including the target sand - the GS-3A. The field has 238 o

ern Siberia where the majority of hydraulic fracture operations in Russia have been done so far. Therefore the first part of this paper present

pressure layers only partially treated. Figure 1 is an exaggerated illustration of this affect showing a varying degree of treatment when multip with a recent increase in popularity. These tight gas wells are typically stimulated with a proppant-laden fluid. When numerous productive in formations. The model is supposed to be developed and validated against experimental results or field data. Introduction It is known from s with unusual high-temperature stability.ï¿½Figure 2 presents the fluid rheology as a function of temperature for different levels of surfact

poorly sorted coarse grained to conglomeritic kaolinite-rich quartz and ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ (2) a moderately sorted fine grained qu

itial pressure of 9600 psia to the current average of about 8700 psia over a 15-year period. The reservoir is under saturated and contains h erform: Frac and Pack completions exhibit positive skin values 1 2 and traditional hydraulic fracture completions show discrepancies betwe hen themselves be evaluated with the aforementioned tools to determine their level of success.ï¿½ This continuous improvement process

ogeneity of the medium between wells. Thus the orientation of the geophones in the monitoring well is determined relatively to the position

to maintain open flow pathways when the fracture closes. At the scale at which acid-fracture conductivity is measured in the laboratory the r frac. The direct estimate of fracture height is used to validate the result of a calibrated HF simulator using Net Pressure matching analysis iation. This paper will describe this technology and its use in some detail. It will also present the results of initial field tests that utilized this n

ded wells that were either never completed after drilling or were shut-in for a long period of time; therefore no recent production history or he reservoir rock with a vertical un-fractured well a set of relative permeability curves and the rock beta factor were adequate. In the rock a servations. elds. The unassociated gas is being produced from two main reservoirs: J (sandstone) and K (carbonate). Hydraulic fracturing is used to en ental return on investment due to the optimization steps. In this manner we can financially quantify the engineered options for increasing we h each microseism (Zoback and Zinke 2002). Furthermore if the amount of seismic energy radiated in different directions is measured adeq reated fracture during treatment cleanup or reservoir production. This is often observed in the field and can frustrate expensive stimulation t parallel to the fracture than normal to the fracture. For a low permeability formation having a small contrast between the two horizontal stress he pear-shape of fingers and periodical separation of their tip elements from the main body of displacing fluid. The effects of porous medium measurements of the fracture geometry. DCHSA has proved instrumental in detecting fracture induced anisotropy. Fracture heights were mo

cture completions show discrepancies between the placed propped length and the effective production fracture length.6 Polymer concentra st from pressure transient analysis. Introduction The Kikeh field is located 110 kilometers northwest offshore Sabah East Malaysia in wate on these five wells. Surprisingly a not unique stress direction was obtained. Introduction Carmï¿½polis and Sirizinho oil fields are located ping experiments cited above is the presence of offsets in the hydraulic fracture path resulting from the interaction between the hydraulic fra ng tubing-head pressure in subsea wells. 4. Eliminating the capital cost of gas-compression facilities or gas-transport pipelines. 5. Reducing perforated (no sand control) 2 standalone screens 8 casedhole frac-packs 9 cased-hole gravel packs and 23 open-hole gravel packs. Th f fracturing fluids to maximize post-fracture productivity of the well. The completion system is run as part of an uncemented liner and space fracturing fluids to maximize post-fracture productivity of the well. The completion system is run as part of an uncemented liner and spaced vironment of the upper Mahakam delta six miles south of Badak/Nilam. Tambora is now primarily a gas field although there are small oil rim gh while achieving economically-desirable production rates. The field went on production in July 1998. Shaybah Geology and Tectonic Set ons with permeability varying from 250 mD to about 1D. The hydrocarbons viscosities varied from 5 cP 8 cP to 12 cP (consolidated sands ecovery manage water production back allocate production monitor mechanical integrity of the wellbore and reduce environmental impact

Introduction Intelligent (or smart) wells are equipped with downhole sensors to monitor well and reservoir conditions and with valves to con ble often â€œwandering and â€œbranching fracture propagation which may have resulted from test conditions unlike (or like) field conditio

varying percentages of interbedded silt and clay beds. These reservoir sands vary in thickness from millimeter to meters. The reservoirs san voirs worldwide. It can drastically reduce production rates damage downhole/subsea equipment and surface facilities thus increasing the r ntration and injection rate)4.ï¿½ All the experimental work conducted in the industry inject acid or other reactive fluid into small core sampl d to generate the actual structural setup. The anticlinal oil-bearing structures in this area are elongated in a north-northeast-south-southwes isolation whilst able to be retrieved for future production requirements. The result of those engineering studies managed to overcome the o os worldwide. This project shows the importance of production and perforating diagnosis leveraging technology application and pushing th d by either commingling production from multiple sandstones or by a horizontal well. Because of wellbore placement challenges within a thin e maintenance of casing-to-cement and cement-to-formation bonds. These improvements in combination allow the use of larger proppant s ling is completed (months in some cases) before they are acid stimulated and brought on line. ADMA OPCO are constantly looking for way cation of the new solutions and interpretation methodology. The inferred skin variation allows a complete and detailed quantification of the p ondition inducing losses of damaging fluid to the formation. Coiled tubing has been used as a conveyer to perform underbalance perforatin swell after shaped charges are detonated. However an overswollen gun refers to the swell of the gun that exceeds the specified diametral

owever all jet perforators produce a region of significantly damaged formation material surrounding the perforation tunnel. This is due to the job costs will also be evaluated. The result of this novel perforating technique is a new completion strategy for oil fields in Oman improving was pulled out of hole and a smart completion system was run successfully as originally planned." 1986. However at that time the development of a field challenged by ultra deep water heavy oil and completely unconsolidated sands in a

tal depth of 6 662' and completed on 11-03-1991 as a vertical cased and unperforated oil producer in Unayzah reservoir. The well was then

show that over 60% of the wells in this region were completed with installed IGP usually ranging from 4.5 to 5.5 bore in a 9-5/8 Casing and

in the drilling fluid mud.ï¿½ Laboratory test procedures results field case histories and production results are discussed in detail.ï¿½ Labo scf/stb. Formation Sand Particle Size Distribution Laser Particle Size (LPSA) and sieve analysis was performed on the whole core recover

Until now standard open-hole gravel packing was the most common sand control completion type in a single sand body. It has been well pro o lower bed heights. In the Alpha/Beta technique the circulation rate is kept constant and the packing proceeds from toe-to-heel covering

Nigeria and the onsite QA/QC procedures with screen samples are also included. A simple approach is proposed for quantification of the im try for many years. Every year the petroleum industry spends millions of dollars cleaning sand out of wells repairing problems related to sa dustry for many years. Every year the petroleum industry spends millions of dollars cleaning sand out of wells repairing problems related to esentative of the in-situ conditions around a true perforation in a well. In order to translate the sanding results into a conclusion relating to th und 415 psia with rock strength (UCS) in the range of 0.12-1.03 MPa. Since the commencing field production in 1998 major redevelopment and in extreme cases loss of the well. Currently sand control is the primary completion technique in offshore environments such as the Gu

addition to the costs associated with lost production workovers and the repair of ESPs surface equipment and pipelines operators also surrounding openhole wells and perforations during drawdown to reduce uncertainty and conservatism such as seen in simple elastic mod address a particular borehole fill problem allowing for optimizing field operations field management and workover strategies. Introduction n in the late life of oil and gas fields is inevitable be it a result of water injection or water coning. On average oil companies today produce

he experiments very different amounts of sand were produced and at different rates. It can be assumed that this behavior can also be foun there is considerable concern regarding wellbore stability in drilling the wells its effect on drilling performance and the potential for this to se hose treated with other acid systems. Introduction Matrix acidizing and fracturing treatments have been used to enhance the performance d systems tested. At 200ï¿½F the acids viscosified with polymer or surfactants created much higher conductivity than the emulsified acid s production analysis has been conducted to determine the effective fracture half-length and etched conductivity. Finally a relative compariso The results are discussed and compared in the paper with those from offset conventionally acid fractured wells and the lessons learned thro n logs were run on these wells to ascertain the effectiveness of the technology and the results are discussed in the paper along with product from natural fractures and fissures to matrix flow with average permeability in the range of 1 md to 10 md. Zonal coverage during acid st ~ -4). Well B tested a 180 ft MD/TVD perforated interval with an electric submersible pump (ESP) at stabilized bottomhole pressures at ra

4 10 16 . Unlike carbonate acidizing where the simulation fluids are used to dissolve the rock around the damage materials sandstone acid

unt of additives. The main question that needs to be answered is if the well was properly stimulated. After the stimulation treatment has the and of increasing worldwide energy consumption. Enhancing productivity from these reservoirs poses a challenge in stimulation fluids due

as an active aquifer that has maintained the reservoir pressure at around 1 500 psi during the last 20 years. The main production mechanis o achieve acid diversion their application histories and their limitations are presented. This paper provides guidelines for production engine d and already producing wells for almost all reservoirs with every major oil operator in Western Siberia. Even though most of the formations g HCl (hydrochloric acid) as the reacting fluid.ï¿½ The characteristic pore-volume to breakthroughs (PVBT) and the wormhole velocities we he capture of an underexploited resource. Introduction Selection criteria of refracture candidates from a given set of wells in a field will vary CO2 over the total foamed fluid volume. With such high qualities the amount of water used is minimized as well as potential problems ass ogically distinct accumulations the Waltman (stratigraphic) Cave Gulch (shallow) and Cave Gulch (deep) Figure 2. All the wells discussed he wells would greatly improve the field performance. Field Description The Nurzhanov oil-gasâ€“condensate field is located in the Em

eability streaks or natural fractures the oil production rate is dropped dramastically. The formation damage like organic deposits and scales jeopardize casing integrity are costly and directed at preventing reservoir to reservoir communication. Cement evaluation logs are time effi usceptible to significant errors. This study presents a new systematic approach for interpretation of pressure data from CCTs based on the equently the few vertical wells completed in the 10-20 ft target zone exhibit low or no productivity. In the 1990s 16 horizontal wells were dril d zones (zones without a frac) under-designed fractures low conductivity values (and steps for improving it) re-fracturing candidates and i s showed that the upper layer had poorer permeability as compared to the lower layers. However this layer holds good oil reserves. Hence nsition periods. These unique characteristics are used to calculate several reservoir parameters including the storage capacity ratio interp ell as in other oil industry applications. Thus determining radius of investigation during a pressure transient test becomes critically important s and the management.ï¿½ Case studies are presented where production enhancement opportunities were uncovered as a result of schedu of robust pressure/rate (von Schroeter et al. 2002 2004; Levitan 2005; Levitan et al. 2006; Ilk et al. 2006a b) and rate/pressure (Kuchuk e

gical petrophysical production and economics. We may think of fractured reservoirs as initially homogeneous systems whose physical pro

mine AOFP without resorting to conventional four points deliverability testing. Introduction Deliverability testing of gas wells is based on the duction: Field and Wells Description Monitoring Testing Needs In 1972 a year after the creation of the UAE Federation Total was granted with proper conditioning of the samples. The paper further elaborates on the comparison of the fluid composition between traditional surface

o determine the most reliable technique(s) of measuring oil production rates was accomplished and now the reconciliation factor is 1.03. Th this methodology compared to the parallel production measurement with a traditional gas separator. This novel comparison and qualificatio separating the phases. This has resulted in new technology from the industry for both gas and oil production. Today there are wet-gas flow es easy mobility of the phase meters between different locations replacement of portable test separators and cost optimization. This pape

s as minimum information the velocity for each phase (i.e. 3 velocity measurements) and 2 holdups (i.e. fractions) knowing that the sum of t with numerical option focus on this aspect. There are a number of papers that has been published in the last few years 2 3 4 Currently we

e noise associated with the numerical differentiation of measured data.10 11 Unfortunately these procedures in addition to being cumberso each well (Fig. 1). The lowest eight joints of casing were coated to insulate the casing and prevent short-circuiting of the electrode array thro

effect on the capacity of cement to guarantee hydraulic isolation and can even lead to premature gelling during placement and early job term cribing in-situ rock stresses fluid pressures and the poro-mechanical and strength properties of the formations. This mechanical earth mod

sphere where carbon dioxide appears as one of the main components. As a consequence several mitigation options have arisen in order of hydrocarbon gases. This is not only caused by the specific values CO2 properties exhibit such as density viscosity heat capacity interfa f the Intergovernmental Panel on Climate Change Report (IPCC 2005) geological storage of carbon dioxide (CO2) was recognized in the tion of carbon dioxide in the atmosphere has been increasing since industrialization in the 19th century and consensus is forming that ma s precipitation and aspects of extreme weather. This is very likely forced by the increase in anthropogenic greenhouse gas concentration in

howed that this well could be drilled more economically from the existing Visund FPDU using existing subsea systems.ï¿½The total depth pment project which is a redevelopement of the BP Donan field by Maersk Oil UK. The filed was discovered by 15/20a-4 well in 1987 and

ation which is a stratigraphic unit that has historically been referred to as the Brown Niagaran. The first large commercial scale Niagaran re ebrache Region contains numerous occurrences of natural CO2 that have been discovered during exploration of oil fields. Most CO2 fields nd faster rate declines. At the same time only 12% of the estimated 3 860 Bcf ultimate recoverable designated tight gas in Vicksburg has b ction of gas-condensate reservoirs under depletion through reentry drilling of multilateral branches from existing vertical wells to bypass the ed in Canada demonstrating the efficiency of SAGD for bitumen accumulations. Based on this experience many oil companies have taken 0 to 1984). Previously unknown fracture networks in these layers resulted in rapid water breakthrough. This was followed by GOGD (Gas-O

drothermal activities alteration due to the weathering activities. The inside volume of magma bodies is often shrank when the magma lavas nal isolation in HPHT environment high inflation ratio applications with enhanced differential pressure capabilities through technological ad the top of cement (TOC) is tagged using slick-line in a vertical or deviated well. If the TOC is not at the theoretical depth then a top-up job

The reservoir sands were deposited in a tidal-dominated depositional setting. Boscan Field has a complex stratigraphic framework the inte iques to conduct this job with out utilizing a workover rig and was able to do so as this paper will show. The best available option was found jobs to sustain oil production. are very costly options for deepwater subsea systems due to their remoteness from host platforms. Mechanical removal techniques such a production logs in horizontal wells relies heavily on the flow behavior. Introduction Two-phase liquid/liquid flow can be defined as the simu ry compared to gas/liquid systems. During the simultaneous flow of oil and water a number of flow patterns can appear ranging from fully s eer. However these sensors alone do not constitute an intelligent well.ï¿½Control devices which allow immediate (rig-less) interaction wit n facilities (involving wells pipeline networks process facilities etc.) requires a joint effort of several domain engineers who generally work used to predict asphaltene precipitation. Wax deposition is predicted using a solid solution model. The results of experimental and theoreti ncrease the pressure drop. Therefore it is important to understand waxy crude oil behavior and determine accurate properties so that desig on facilities and optimal planning of reservoir production strategies require detailed characterization of the physical and chemical properties d improved Wireline Formation Testers (WFT) in the early 1990â€™s. Its main objective was to identify in-situ reservoir fluids and to obtain f

ed dewpoint-pressure correlation that does not require some laboratory-measured quantity. Estimation of decreases in producing yields af e field and can have wide applications when representative fluid samples are not available. Introduction In 1973 Spivak and Dixon1 introd s. Diffusion can be very slow across a reservoir (eg. ~100 MYr) many dynamic processes involving reservoir fluids will be faster.[7] On the o e intervals in a new well zones with unexpectedly low / high pressures undesirable fluid production and presence of additional reserves or ty calculations [1]. Inaccurate fluid characterization often leads to high uncertainties and hence affects asset value [2]. Many pressure-main

rom extensive simulations conducted with the compositional numerical model. Our simulation and rapid modeling results compare well with artmentalization gradual variation of hydrocarbon quality or density inversion analysis and is not always feasible for economic or environm

e carried out at DFA stations to provide more representative and accurate mobility/permeability distributions of reservoir layers5 for reservoi aining organic matter particularly under low oxygen conditions. Industrial sources of H2S include petroleum and natural gas extraction and

a typical reservoir. A number of authors have reported field experiences with compositional grading in gas/condensate reservoirs (Creek a erlying reservoir or by capillary leakage. As the source matures with time later petroleum charges become less dense and each reservoir oirs the process of fluid identification is straight forward. Initially the bulk density and neutron porosity logs are used in combination with re ts because a proper assessment of the formation-fluid gradients is critical to optimum hydrocarbon production. There are several different m duction schedules. Modern wireline formation testers are equipped with quartz pressure gauges of high accuracy resolution and repeatabil nal gradient is parametized using the DFA observations at the different depths. A polynomial fit is then given to the distributed pressure meas mponent and the GOR prediction become unreliable because of the color effect. In this paper we describe the methodology for downhole G

ned. The choice and appropriateness of the pressure gradient model that accounts for the observed fluid density changes observed. The re have a relatively higher GOR value. Downhole spectrometers measure optical density (OD) defined as the ratio of incident light energy to PVT behavior are key factors for surface facility design and optimization of production strategies. In most hydrocarbon reservoirs fluid com

ars.ï¿½ They are being used in a mass-variable based conventional and multi-segment well model and also in some circumstances to deter viscosity beyond the inversion point. The variation of viscosity with water content for live emulsion samples indicated that the inversion poin

conomic potential. In appraisal phase it is used to determine layer connectivity and field structure as well as the optimization of well comple *) was used to constantly monitor the flowline. The fluid analyzer was positioned in between the pump and the bottle and as soon as it dete to convert the flow rates at standard conditions is necessary (Ref. [3]). Currently this is not addressed properly by most multiphase supplier analyses in a PVT laboratorf after sample recombination using improved phase ratios. The paper describes deployment of such methodolo desorption are necessary for investigating the mechanism of interfacial reactions of chelating agents and calcite. Introduction Hydrochloric eservoirs thin oil edges and moderate pressure communication via the common aquifer. A detailed general exploitation plan based on wat o dissolve near-wellbore damage in the critical matrix generally considered as 1-1.5 meters radially into the formation from the wellbore. Th luids. Salt deposition downhole may cause substantial wellproductivity impairment and culminate in total flow blockage. Like any other type

ments have increased our understanding of the quantitative amount of permeability damage induced by shaped charge penetration. These nown as a â€œstress cage).ï¿½As the rock decompresses this stress cage causes the failure of the most damaged rock adjacent to the ation in brine exceeds the equilibrium concentration. When brine is supersaturated salts can precipitate out of solution forming scale. The ariety of squeeze techniques for applying scale inhibitors during the stimulation process have been described in prior studies2. It has been s well technology for scale management was studied.ï¿½A case study illustrates how the ICVs may be used for scale management.ï¿½Such ditions. Introduction Upper Zakum field (4th largest known field in the world) operated by ZADCO and located offshore Abu Dhabi. The fiel ch supports integrated production drilling and living quarters.ï¿½Peak oil production topped 20 100 m3/day (126 000 stb/day) during 1993 tion is to ensure that the model encompasses all available data and information. Due to insufficient data the geological petrophysical and f s should be validated first to assess accurate fluid movement in the reservoir. Naturally fractured reservoirs under waterflooding require mo ï¿½ One significant breakthrough in that path of evolution has been the development of the technology of streamline simulation. The applic blems have also been included into the discussions of this paper. Hence the possible conditions for the fluid breakthrough have been ident e promoting new technologies that permit standardization of workflows (or methodologies) for monitoring and optimization of oil and gas pro tern flood modeling helped develop an optimum strategy for maximizing reserves and production especially in the lower two oil bearing uni n 1958. Located in North Kuwait (Figure 1) Sabiriyah Field consists of several stacked pay intervals trapped in a North-South elongated fau oil in place (OIP). The Cerro Negro area is located in the eastern part of the Orinoco belt; it covers 70 square miles with an estimated OIP oil reservoirs are increasingly being developed because of their great potential the necessity to compensate for the decline of conventional rbons are only a few examples of the different processes currently being used or investigated (Bradshaw et al 1999 Andres et al 1998). M zation procedure for the process under the specified fluid and reservoir conditions. Sensitivity analyses were performed considering the rel y of the crude oil in field is very high. Reservoir is highly permeable and unconsolidated. All the wells were tested through swabbing due to it drive reservoir with partial solution gas drive and limited aquifer support. The estimated gross OOIP within the currently delineated field limit aning up from mud filtrate and during downhole fluid identification is described. The main objective of using the formation tester was to take

ntiu reveroir is prone to sand production and water break through very quickly and Aradeiba reservoir is prone to serious sand production a

s of 20 000 acres (Figure 1). It is located 290 km southeast of Cairo and 3 km inland from the western shore of the Gulf of Suez (Figure 2).

the new multiphase technology operating envelope for PDVSA from Gas to Extra Heavy Oil and provided a unique solution and the capabi

sent in small quantities compared to other aluminosilicates. Over the years many different acidizing systems have been developed for spe of a dual-packer wireline formation tester to obtain PVT samples of retrograde gas in the Achimovskaya formation. As a result of the job the

usion (molecular and/or thermal) and convection (compositional and/or thermal) mechanisms.2 3 4 The relative dominance of these mecha

Fracture initiation propagation and resulting dimensions are strongly influenced by the viscosity.ï¿½ Proppant transport also determined b uptake of the injected fluids. Oil and gas wells producing from carbonate formations are generally acidized by matrix acidizing or acid-fractu

artz pressure gauge. Schlumberger is the pioneer in permanent downhole pressure gauge measurement; its first installation dates back to 74 but was placed in production only in 1986. Production is from the Miocene Oligocene and the Basement formations flowing into a Floatin pressure in zones ranges between 800 and 2500 psi and skin varies across the zones.ï¿½The rock permeability varies from 1 mD to 200 m fluids used to stimulate limestone and dolomite formations. By adjusting the composition and pH of these fluids it is possible to customize outh Argentina. The basin-fill was by fluvial deposition during the Cretaceous period. Wells are typically vertical and penetrate several thin la he amount of water displaced in the initial stage depends on the drawdown and the capillary pressure. In formations with high capillary pre Introduction Water sampling in exploration wells is usually done to obtain information regarding the scaling and corrosion potential of the

acre and more recently to 160 acres.ï¿½ With the increase in gas prices operators are constantly seeking ways to optimize the economics

on as well as in single-well and field development planning. Introduction The 2008 BP statistical review of world energy (Fig. 1) highlights t arcy range. The first well was drilled in this region of the Rocky Mountains in 1955. In the late 1990â€™s the discovery of increased product tions. The results of this investigation will be used to further optimize hydraulic fracture design reservoir pressure maintenance including we wing type of induced fractures have been successful in hydraulic fracturing of conventional reservoirs. They are nevertheless short in repres set wells. For the first 6 months total gas produced was 56 MMscf compared with the 40-MMscf average of the offsets and the WGR was

The initial 90 days average production of this Foukanda well was more than 2500bbl/day.ï¿½ This production rate was double the simulated nner. The treatment utilized 200 000 lbm of 20/40-mesh intermediate strength proppant carried with 3 700 bbls of delayed borate crosslinke water cut compared to production of a single completion vertical well in the M3b reservoir which averages only 500 BOPD and 50% water c tion and little or no integration of the geoscience disciplines. This practice continued until recently when denser well spacing and consequen ficant cost saving via modifications to fluid technology proppant selection proppant flowback control methods commingling strategies sca uction The subject field is located in the northwestern Green River basin in Wyoming. It produces gas from the fluvial channel sandstones o d sand/shale sequences has been an exploitive success in recent years. Many proposals are put forth showing offset production that seem t

t al. 2007) while the MRï¿½section has low to moderate matrix porosity (0-20%). The importance of natural fracture to the reservoir produc rtmentalization fluid compositional variation the unexpected identification of oil oil reserve assessment and gas compositional analysis to Recent advances in logging technology such as electrical and acoustic imaging used in combination with production data transient pressu retaceous Seaway. Changing sea-levels resulted in the deposition of a mixed suite of sand silt shale and coals in a complex sequence of

nt gauge via a flowline is positioned at the depth to be tested. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½2. ï¿½ï¿½ï¿½ï¿½The tool is â€œset: ï¿½ï¿½ reservoirs of 0.1 to 10 md each separated by 60-m-thick shale. The reservoirs do not have either free mobile water or aquifer support. Th well feasibility and economic results can be determined. If a horizontal well has been determined to be viable economically this method can e associated with the Riphean depositions (from 0 8 to 1 1 billion years of age) and partially with the Vendian depositions (approximately 0.6

e potential and importance of capillary transition zones [1-8]. In particular several large low permeability carbonate oil reservoirs have trans

he continents. Commercial oil discoveries have been made in quite large number of countries but these reserves are unevenly distributed an

n. The goal of this process is to provide the decision-maker with sufficient information in order to choose an alternative that results in the mo see reality and analyze information. An example of one of the more common perceptual biases is overconfidence. Many project failures orig

oir fluid distribution and petroleum recovery during primary or enhanced production. It is well recognized that accurate reservoir simulation a med the first pass estimates of the identified heterogeneities. Introduction Permeability heterogeneity especially that induced by formation s (NMR) are run on a limited number of wells for cost reasons. These â€œunconventional tools have a much higher spatial resolution: aroun bstantial hydrocarbon discoveries of late. The study area of this work is offshore Krishna â€“ Godavari basin (KG Basin) which has taken th s to an estimated one billion barrels of oil in place which makes it one of the most important oil fields in Algeria. Fluvial deposits are usually ate sensor response in a large number of live-fluid samples. These tests of known fluid compositions were conducted under pressurized and ½ Missing productive intervals in a new well zones with unexpectedly low / high pressures undesirable fluid production and presence of ad a surrogate for it such as a textural estimate from bore hole imaging logs or a pore size estimation from NMR logs. The interplay of multiple he formation. The 3D seismic volume was analyzed to understand the extent of the sand body forming the stratigraphic trap and to define its ol; this provides average and quadrant values and 16-sector images of bulk density and photoelectric factor. Stabilizers are available to sup onmental conditions (low temperature and low mud salinity) made it possible to obtain additional spectral data which was used to correct

the oil saturation of a reservoir from electric log responses is complicated by the presence of clay minerals in the pore network. The comple a reservoir from electric log responses is complicated by the presence of clay minerals in the pore network. The complexity is twofold. Firstl ilitates various forms of rock typing. Marzouk et al. (1997) presented a form of carbonate rock typing based on porosity partitioning that is co voir by identifying and characterizing large-scale depositional events and sequence stratigraphic boundaries across fields. Using borehole-i es and dolomites with anhydrite cement.ï¿½ Seven hundred ninety-five feet of core was recovered.ï¿½ A wide variety of carbonate textures counted by formation evaluation in volumetric estimates of deepwater siliciclastic depositional settings with largely laminated succession of

imented applied and refined the interpretation technique for thin sand/shale laminations using both NMR and triaxial induction (3D inductio

urements of the reservoir. Extensive core analyses have shown that permeability anisotropy at different scales is controlled by the interplay o mations which even at great depths can remain unconsolidated or only weakly cemented. Field experience has shown when sampling fluid s and fractures are normally interpreted using borehole image logs and cores. Cores provide direct observations of fracture distributions an eismic signatures of high resolution seismic data. The Al-Khafji oil field is located in the offshore part of Neutral zone between The Kingdom

uation based on the facies scenarios and other geologic and petrophysical variables confirms the new result. The realization of more subsu ent and the productivity of thin bed reservoirs would be accurately evaluated.ï¿½ The productivity of thin beds is best tested with a formatio tion of sand/shale and the sand porosity could be determined from NMR logs. The results confirmed observations on logs of which we sho

ment that is accurate consistent between wells (regardless of rig type or bottomhole assembly [BHA] configuration) and independent of the

urn affect the fracture propagation direction. The magnitude of reorientation depends on pressure gradients and thus is controlled by injectio ificial intelligence methods viz. Neural Network Fuzzy Logic and Functional Network were used to obtain a continuous profile of static elas page losses and the differential sticking in the depleted sand and overlying shale. We have also performed dipole radial profiling (DRP) of fo

an be readily evaluated as a summation of discrete intervals of time for which the flow rate history is assumed to be piece-wise continuous

ager Stoneley waves elemental spectral device and other conventional open hole logs were logged on the 25th of July 2006 in the explor ervoirs of the â€œM horizon that represents the uppermost portion of the Paleozoic basement2. The discovery has attracted a significant at d perpendicular to the direction of the open fractures. Only two areas within the field show closed fractures oriented in the same direction as ts the uppermost portion of the Paleozoic basement1. The discovery has attracted a significant attention at the time being a first demonstra

major reason for observing low success statistics of communicating with the formation other possibilities have been postulated.ï¿½ One o

dean that lie between the 3000 and 5500 m of depth have been produced by the existence of a thick column of clastics sediments of scarc zones where sampling is difficult such as thin beds poor borehole conditions tight formations and heavy oils. We conclude that the additio

ictated by the cost of rig time and the need for reasonable logging speeds. Signal averaging for better data quality comes at a price either i d wettability. The modern phase of NMR logging can be traced to the initiation of an NMR borehole-logging research project at Los Alamo regional unconformity above which continental and marine sediments were deposited. The basinâ€™s total area is estimated to be about 2 s much more difficult to complete horizontal wells. For example poor cementing jobs can result in unexpected casing/liner shoe leaks. Seco

g drilling-mud leakoff and fines migration into the formation. Additionally it allows for reservoir characterization during drilling. Because the w dedicated to developing the Lower Cretaceous Minagish Oolite main reservoir which are estimated to account for up to 85% of the fieldâ€™

velopment commences. From these fluid property data and geologic models dynamic reservoir models can be built to accurately simulate p ach DFA can address the fluid distribution throughout the reservoir. Because reservoir fluids are typically compositionally graded 3 different be readily evaluated as a summation of discrete intervals of time for which the flow rate history is assumed to be piece-wise continuous as sin of eastern Libya. As Sarah field is estimated to contain over 1Billion bbl STOIIP. Present production from As Sarah is around 90 000 BOP 4-meter section where very fine layering is evident. Vertical heterogeneity on various scales lead to multiple gas/water contacts with extrem

ria low permeability reservoirs are common and they require stimulation for effective injection/production rates. Treatments have evolved fr used during measurement while drilling. However interpretation of the pressure data acquired in this dynamic environment is challenging. t stem from both surface and subsurface unknowns. The optimized field and reservoir management can be achieved through successful un optimizing the sampling programme with DFA for subsequent appraisal wells. Introduction The interpretation of pressure measurements fro lls that would benefit from a change in the artificial lift select the optimum lift method and provide engineering and project management for plateau reached by infill drilling and produce additional reserves. The study also found that to be able to displace oil in the Mogollon formatio veillance tools include the real-time high density data capture system and automation software which enable up-to-the-minute nodal analys s of Saudi Arabia have been already drilled and now smaller thinner and more complex reservoirs are being considered for development. O The success of the water injector depends on how effectively the wells are placed relative to reservoir quality flow direction and structure.ï¿ ed downtime and cost of maintenance and enhanced the profitability of these installations. All these have been listed under the lessons le ved by the drilling engineer to target individual single reservoirs disregarding the opportunities existing in the entire stack. Stacked hydroca ained by means of crestal gas injection which not only helps preserving the total energy of the system but also improves the sweep toward ered in 1988 by an advanced well (VLG-3729) from a neighbor reservoir. See Fig. 1. Six regions are defined by two primary faults and seve elative isolation of the different simulators the resulting FM plans/scenarios are generally suboptimal and tightly integrated to the specific si acilities sizing and design. The Production Optimization cycle involves a thorough analysis of production data using analytical methods and a. The average water depth is 225 ft. The field is operated by a single unmanned production platform that contains 24 well slots with 48 tub r productive lives such fields contain resources that are needed worldwide by the countries they belong to and the world economy. These b

a starting point computes the fluid movement and pressure distribution in the reservoir model passing the information about the pressure a achieving the prize of the IAM under the banner of the â€œDigital Oil Field. From reservoir to facility and from today to the end of field life n facilities (involving wells pipeline networks process facilities etc.) requires a joint effort of several domain engineers who generally work hose studies.ï¿½ This is one of the main reasons of those workflows that significant effort is spent on the data collection phase. Deriving th ore in the South China Sea around 130 km southeast of Hong Kong. These fields are sandstone reservoirs consisting of three anticline stru

ctive namely Ahmadi limestone B-limestone Wara sand and Zubair sand which are commonly referred to as minor reservoirs. In Khafji fie stacked fluvial-deltaic channel sands in early Miocene time. Oil accumulations with low gas saturation and no gas cap are mostly found in 4 uce these wells commingled to be commercially economic. A systematic approach incorporating historical pressure trends by unit and theo w. The objective was to estimate remaining reserves in the LV reservoirs. The scope of the study includes six Lower Vicksburg sands (name act is non-trivial due to the presence of multivariate time-dependent uncertainties.1âˆ’4 At the time when the field development decision wil

eservoirs was performed using real-time azimuthal laterolog measurements and images coupled with a simultaneous correlation of logging n. Application of seismic techniques suggested that an extensive Paleocene-age meandering sand body with a large oil effect anomaly could he same parametric group used to convert standard reservoir models to maps of production potential can be used to convert while-drilling m ts incorporation into a full-field numerical simulation model. A practical application of this technology is demonstrated with an example from approaches as this paper presents one are critical in achieving this goal.ï¿½ Whereby with the ever dwindling reserves base it is of the up pment plan are: type of well well completion options offset from fluid contacts and well orientation. This paper also describes wellbore dyn sts of global methods such as simulated annealing (Beckner and Song 1995) genetic algorithms (Montes et al. 2001 Gï¿½yagï¿½ler et al.

use of such a tool a large amount of reliable data is required. Also a full study including a history-matching analysis may take months to c convergence can often become problematic. Other tools exist which allow engineers to perform â€œquick studies of an oil or gas field. Ty Goldsmith San Andres Unit (GSAU) in West Texas and includes multiple patterns consisting of 11 injectors and 31 producers. Using well log permeability at each cell thus demonstrating the feasibility of our approach for field applications. Introduction Conditioning geological mod

hat are accurate. During history matching model parameters at the grid blocks are adjusted to obtain a simulated response equal to the obs

ariable formulation with the selection of pressure energy and component moles as primary variables. This paper describes a general unstru ulated. Examples include black-oil or compositional models and isothermal or thermal models. The primary variables used in the governing ature. It illustrates the challenges of simulating horizontal wells and how production logging is used to resolve the problem and calibrate the

i-lateral well fluid and completion dynamics and the approach used to simulate them. Simulation results for successful actual field studies a

) when compared with production information. space of the propped fracture following closure (Ayoub et al. 2006). Varying exposure times to fracturing fluid (Seright 2002) cause local pol e caused by invading fluids during the treatment and damage due to the stresses exerted on the fracture face. In addition damage to propp cal formation D stratigraphic column consists of seven zones. Zone 1 at the top of the reservoir; contains the more developed porosity and p eads to less liquid drop-out. The pressure and flow rate behavior of gas condensate is extremely different from the behavior of a two-phase e and can occur when a hydraulic fracture encounters formation bedding planes or natural fractures. For a vertical hydraulic fracture propag .ï¿½ Introduction Hydraulic fracturing is a high-cost operation that if successful can significantly benefit the profitability of a new well. T

method1 uses standard techniques for single-layer reservoirs with allocated production rates and reconstructed bottomhole pressures. The consider multiphase flow in an investigation that also involved the development of a dimensionless productivity index solution for vertically f cemented and perforated over a very short high shot density cluster. A unique transverse fracture of radial geometry is propagated from the chieved through perforations; therefore quality of perforation is critical. Ideal perforation for fracture initiation would have a minimum injecti ships need to be modeled by use of small data sets. Introduction An ANN is â€œan information-processing system that has certain perform

letely isolated and no wells are producing commingled from these reservoirs thus separating them will not have any effect on its performanc al wells are effective in achieving a good volumetric sweep particularly in thick reservoirs in which gravitational forces and stratification tend

d to investigate the potential of the field and to look for opportunities to increase oil and gas recovery. Material balance analysis is a part of the material balance calculations. Gas-oil ratio uncertainty was also significant. Oil and gas gravity and reservoir temperature were less sig n contains 7 pay zones. Marked regularities of reservoir parameters distribution and thickness changes have not been revealed. The absen ombined effects of diffusion (pressure thermal and molecular) and natural convection on compositional variation in multicomponent mixture oir engineers have developed and successfully applied several experimental design workflows to various reservoir engineering studies (Frie

utions may lead to spurious gas vaporization from the oil phase. For the numerical scheme to satisfy the maximum principle it is sufficient t

ology are helping to identify that naturally fractured reservoir rock contains not only matrix and fracture but also the vugs.ï¿½ Oil recovery fro ly observed structural deformation with the simulated one. The smaller-scale fluctuation of fracture density is simultaneously history matche

ir simulation were published by a number of authors (LeBlanc [16] Higgins [11]) but streamline methods were not considered a general pur wo interpenetrating continuum media â€“ matrix and fractures each possessing its porosities pressure phase saturations etc. and interac models efficiently. This is particularly true for fractured reservoirs which are very difficult to manage and to optimize recovery for; see Bock

al results indicate that the RML method generates reasonable characterization of uncertainty for single-phase flow (Oliver et al. 1996; Reyn

is a common method of providing pressure support for oil reservoirs. Certain production problems may arise after water breakthrough. One

ne solves the pressure equation finds the corresponding Darcyâ€™s velocity estimates the time step from the CFL condition and perform ps. Then the concentrations transportation problem is split again into a series of 1D transport problems. These problems can be solved by a believe that in parallel to the reservoir modeling studies YPF can make use of the immense array of well data and the wisdom acquired ov

hreshold on the objective function may then be applied to identify the bounding cases. Appropriate quantiles from the thus qualified model and some of these simulators contain powerful well modeling tools such as multisegment wells (Holmes et al. 1998) which allow the repre the NKJC. Problem Statement The North Kuwait Jurassic Complex (NKJC) a complex of green fields in northern part of Kuwait consists

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ (1) is no longer valid. In Eq. 1 permeability k is an intrinsic property of porou Typical SCAL measurements made on cores taken from such zones include characterization of the bounding imbibition and drainage cap aign was commenced to recover by-passed hydrocarbons. It was determined that underbalanced drilling would be the best technique to use ing drilled in the areas with minimum knowledge with scanty or barely minimum previously drilled data. Enhancing the production to its max on and visualization technologies are enablers and are required in order to integrate across the core business processes and permit people

eology was used in the ANS definition but only political boundaries were used in defining the UK North Sea province. Political boundaries apable of handling more complex situations they are usually used with simplifying assumptions in which case they offer no advantages ove

elected by the operator for water shutoff operations. In each of these the water cut was more than 70%. In each well through-casing resist ural gas lift on the Troll field using hydraulic gas lift valves. For the Fram Vest field an innovative natural gas lift completion was implemente rmation in the North Kuwait is consisted of two large anticlines named as Sabriyah and Raudhatain Fields. Mauddud Carbonate Formation ates from each producing reservoir.ï¿½ Conventional wireline logging is not possible because of the high-hole angle and the long reach.ï¿½

nt was well underway and full marine conditions existed. As a consequence the Pinda was deposited in a shallow marine environment and i nt was well underway and full marine conditions existed. As a consequence the Pinda was deposited in a shallow marine environment and i e reservoir is fairly steep and the flood-front has been observed to advance slowly through the reservoir. ï¿½A dual gauge system was env about compartments and communication in the reservoir and hence can improve the ability to make the right decisions early in developme tive reservoir diagnostics that can be linked to a specific action or set of actions focused on the production enhancement and economic res nent of source mechanisms. This observation implies that the induced microseismic events are directly connected with the created fracture d be validated by a thorough pressure analysis of the injection data for validity. If this critical step is forgone many assumptions of height co

ows the sand to be mined so that the bitumen can be processed; however on the western part of the lease the recovery method is SAGD. discussed is not entirely restricted to vertical wells.ï¿½ It is noted however that laboratory experiments have demonstrated that only slight c irely restricted to vertical wells. It is noted however that laboratory experiments have demonstrated that only slight changes in wellbore incl o flow and temperature Kunz and Tixier2 and Schonblom3 who introduced the interpretation of multi-zone gas wells and Smith and Steffe

errors and uncertainties associated with varying flow conditions and data limitations. Finally surface multiphase flowmeters may have limi

by itself does not say anything about production performance; therefor to answer the first question a comparison versus a production referen il inflow in high water cut horizontal wells has resulted in an evolution in the nature and arrangement of production logging sensors. The ob oir heterogeneities that have been integrated with changes made in a fullfield â€œWara only history-matched simulation model. Backgrou ery. Production from a well can be hindered by the precipitation and deposition of organic solids like asphaltenes and waxes. As background ell. So by this paper we would like to encourage all operating companies to start moving on to the next level of production monitoring and met. The power of real-time monitoring and interpretation will be illustrated through these case studies. Introduction WFT has become a s e is information that can be directly input into the reservoir model. Well tests by their very nature average the buildup pressure in a multila oil/bitumen (Collins 2005; McLellan 2006; Dusseault 2007). This geomechanical deformation may be expressed through seismic deformatio ion and extend a total of 48 km along their axis (Fig. 1). The fields were discovered between 1979 and 1987 and first production occurred in ace data will further enhance the interpretation of flow allocation and reservoir drainage. Introduction Worldwide subsea activity is growing

of individual wells or estimated based on steady state methods. In other cases engineers wait weeks to months after completing back alloc duction declines are often associated with increases in unwanted water production and this is particularly universal in brown fields. Producti

enhanced oil recovery from 540 Barrel to 2250 Barrel oil per day with significant reduction in water cut from 84% to 0.5%. ï¿½ The results w in formation is measured. Chloride (Cl-) by far is the most neutron capturing elements in most reservoir rocks. Sigma measurement (Î£ ) is p d define the parameters for the survey with objectives; 1) to check the sensitivity of EM technique to the reservoir conditions and injected flu measurement monitoring plan has been established to determine the performance of this pilot study including deep reading technologies lik 400-6 000 Tcf) China (1 060-1 240 Tcf) US (700 Tcf) Canada (263-2 700 Tcf) and India (525 Tcf) have the largest reserves. (See Anderso e better deliverability of fluids. In this paper we provide a guideline for selecting a completion methodology in coal bed methane wells based production stream. Figure 1 shows a comparison of the gas release profile between a conventional clastic reservoir rock in a gas expansion ian Marble Falls limestone. The Barnett shale is within the Forth Worth basin and the focus of our study will concentrate on wells within De as well as shear movement on pre-existing discontinuties.ï¿½ When the surface area created by the treatment is large subsequent produc he individual coal seams are then stimulated via the injection of dry nitrogen at high rates through a coiled tubing reel that is equipped with 81 with the drilling of the Mitchell Energy C. W. Slay #1.ï¿½ For the first few years small CO2 or N2 foam treatments were performed as the mand and rising oil and gas prices in the past several years Barnett Shale gas production has gained momentum. The characteristics of th bore length operational control and completion designs. Thermal simulations are significantly more complex than conventional simulations nd sorbed gas on the internal surfaces of the organic matter. Nearly all coalbed gas is considered to be sorbed gas whereas shale gas is a h drilled azimuths selected to encourage either transverse or longitudinal fracture fairway development. With a continuing optimization of th mentation. However crossing from research to the field applications is still dominated by experience rules of thumb and conservatively cop The field produces Arabian Medium crude with an average oil gravity of 30ï¿½ API and 2.7% sulfur by weight.

ging portion in which the velocity is transformed back into the pressure with slight friction loss. If tapping are taken from the inlet and throat o eveloped at a profit by vertical completions. Today the use of horizontal completion is widely spread in the Sibneft fields. The Sporyshevsko tially identified. Perforating other exploratory wells showed a gas/water contact at 1 570 m vertical depth and net pay from 230 to 370 m in a hod remains the same. Most wells are completed with cemented casing. To stimulate the reservoir a plug is set one or more layers are pe he possibilities for perforation design detailed analysis was performed. The analysis showed that the traditional gun selection would not sur esent in the system to the surface.ï¿½ Gas flow velocities that are insufficient to continuously transport the wellbore liquids to the surface ar esent in the system to the surface.ï¿½ Gas flow velocities that are insufficient to continuously transport the wellbore liquids to the surface ar d and Burgan Fourth Sand (4S). Mauddud reservoir is a thin carbonate reservoir with low permeability and variable fracture density.ï¿½ In

a. These are discussed by Herbeck et al. (1976). Here we use the terms sweep and contact factor to simply distinguish efficiencies of recov expenditure of MRC/ML wells with SCs vs. conventional completions (Afaleg et al. 2005; Mubarak et al. 2007). Several authors quantified p

n artificial lift production method like an electrical submersible pump (ESP) to increase the energy of the fluid at the bottom of the well to tran that influence survival and to predict survival probabilities. This is achieved by finding a suitable statistical model that fits the data closely. W clusions and recommendations on the effectiveness of this novel technology and suggest areas of improvement that will help in promoting a ation candidates selected in late 2004 and performed in 2005 were based on the thickness reservoir quality and â€œskin damage assume

kken. The Bakken is organic rich shale which is upper bounded by the dense Lodgepole Limestone and lower bounded by the argellaceous ese operational results were confirmed by production measurements where the average water cut is 50% lower compared to the conventio ducted pilot along with production history comparisons with offset producers will be discussed. ample of how one solution may be applied for various challenges of hydraulic fracturing optimization. This research will present a comprehe g one that leaves the formation with certain wettability may be advantageous. Our testing indicated that understanding the reservoir is impor height growth and that Youngâ€™s modulus contrast is less important. When studying different height-containment mechanisms modulus ploited with an emphasis on maximizing contacted surface area within a single borehole and on minimizing the time to well tie-in and the wo vania and Wyoming the company must do so under a National Pollutant Discharge Elimination System (NPDES) permit or into a publicly o ith each stage treating 5-7 sands.ï¿½ Various fluids proppants and pump schedules were introduced into the pilot program with the aim of s application is the fact that the bottom of the perforated interval is not fractured. High-end frac pack techniques that overcome this issue su reversed. Here the operator incurs the additional expense of water disposal and decreased hydrocarbon inflow at the wellbore. Likewise v e of oil. However oilfield operators recognize that there are many fields where the recovery of the resources are more challenging and requ such treatments offer to mature oilfields. Background Several mature fields are located offshore the coasts of Cameroon Gabon and een a tool widely used to improve both production rates and recovered reserves per wellbore in order to improve the economics of particula

ed zones of varying lengths can be individually treated in accordance with reservoir characteristics and production targets. This paper deta

and - the GS-3A. The field has 238 oil wells 67 gas wells 122 water injectors and 18 gas injectors. Till date the field has produced 24.41 Mm

re the first part of this paper presents a description of the Samara region geology formation properties and characteristics of the oilfields. T

ing degree of treatment when multiple layers are fractured in a single stage. The optimized stimulation isolates each layer during treatment fluid. When numerous productive intervals are present in the same wellbore the wells are usually stimulated in stages. In each stage a se data. Introduction It is known from field data that traditional fracture propagation models for brittle linear-elastic rocks often show discrepa erature for different levels of surfactant package concentration.ï¿½The surfactant package creates useful rheology within concentrations r

a moderately sorted fine grained quartz sandstone containing a mixed layer of clay chlorite and illite.ï¿½ Studies have reported permeabil

oir is under saturated and contains high quality light crude. However production records show frequent asphaltene plugging problems in the mpletions show discrepancies between the placed propped length and the effective production fracture length.3 Polymer damage leading to s continuous improvement process can be repeated for future fieldwide well completion designs in order to achieve an optimum fracture sys

determined relatively to the position of the treatment well at depths corresponding to the perforations. The absolute orientation (in a geogra

ty is measured in the laboratory the texture of the fracture face should have a dominant influence on the resulting fracture conductivity at l ing Net Pressure matching analysis. Passive Seismic monitoring (PSM) is used to obtain direct estimate of height length and azimuth. PSM of initial field tests that utilized this new technology to determine aspects of propped fracture geometry. Introduction Ever since the first us

fore no recent production history or recent measurements of reservoir pressure and other crucial parameters were available. Therefore the a factor were adequate. In the rock adjacent to the propped fracture the gas velocities are low because of the much greater flow areaâ€”tw

e). Hydraulic fracturing is used to enhance gas production from the sandstone reservoir while acid fracturing is used to increase gas produ engineered options for increasing well performance and optimization of the Stimulation Index (SD) while taking into account the associated different directions is measured adequately the so-called focal mechanism or fracture orientation can be computed directly assuming that t can frustrate expensive stimulation treatments and significantly increase well-operations costs because of: a decrease in fracture conducti ast between the two horizontal stresses this production-induced stress change could cause a rotation of the local minimum stress direction g fluid. The effects of porous medium inhomogenity on the instability of fluids displacement were investigated both numerically and experime anisotropy. Fracture heights were modeled with the expected treatment pressures. The outcome proved a valuable methodology that decrea

fracture length.6 Polymer concentration leading to ineffective fracture clean-up is prominent in the list of usual suspects.6-9 In addition it w shore Sabah East Malaysia in water depths of around 1 300m. The formations are sandstone and at 4500 meters deep in water depth of a s and Sirizinho oil fields are located in Sergipe-Alagoas Basin in Northeast Brazil (Figure 1). Discovered in the sixties and quickly put in prim interaction between the hydraulic fractures and discontinuities such as joints or natural fractures. Laboratory experiments have also been c gas-transport pipelines. 5. Reducing platform load requirements caused by gas lift compression. 6. Eliminating the need for annular safety v and 23 open-hole gravel packs. These completions are reviewed below with some examples for each in detail. Additional relevant informa t of an uncemented liner and spaced out based on the required number of stages. Once in place the packers are hydraulically set and fract of an uncemented liner and spaced out based on the required number of stages. Once in place the packers are hydraulically set and fractu field although there are small oil rims to the north (produced before 1990). Tambora field is operated by TOTAL E&P Indonesie as part of th Shaybah Geology and Tectonic Setting:The field is characterized as a gently folded northeast-southwest trending anticline consisting prima 8 cP to 12 cP (consolidated sandstone Well 1) and between 19 cP to 21 cP (non-consolidated formation Well 2). Well 1 in the consolida e and reduce environmental impact all while reducing overall cost by reducing the required number of wells and associated facilities.

oir conditions and with valves to control the inflow of fluids from the reservoir to the well (Robison 1997). This combination of monitoring and onditions unlike (or like) field conditions. This study is one of many research efforts being conducted by an industry-sponsored research gro

imeter to meters. The reservoirs sands may be highly permeable but the silt and clay laminations affect the reservoir vertical permeability i rface facilities thus increasing the risk of well failure. The problems are often observed in fields after a period of relatively smooth operation r reactive fluid into small core samples.ï¿½ The core faces are kept open during fluid injection.ï¿½ The perforating effect is ignored.ï¿½ Und n a north-northeast-south-southwest direction and bounded toward the west and south by the two main normal fault systems. Field-Î± was studies managed to overcome the operational failures in the past and at the same time was able to meet the production objective. Project chnology application and pushing the limit of dynamic underbalanced perforating in order to increase productivity in mature/low pressure as e placement challenges within a thin sandstone unit a horizontal well requires a continuous sandstone body of sufficient length and aerial e on allow the use of larger proppant sizes and lead to a homogeneous bi-wing fracture when shot in 0 to 180 degree phasing. Aligning the gu OPCO are constantly looking for ways to improve efficiency and well productivity. They reviewed how these wells are completed and perfora e and detailed quantification of the perforation quality and cleanup efficiency. The results of this work enable the implement of better strateg r to perform underbalance perforating for many years. CT allows: Ability to displace the wellbore fluid with nitrogen gas to create the unde hat exceeds the specified diametral tolerances and thus cannot be retrieved from the well without costly intervention operations. A split gun

perforation tunnel. This is due to the highly dynamic nature of the perforation event involving impact pressures ranging from tens to hundre egy for oil fields in Oman improving overall well performance. Introduction A key element of how productive a well will be is the effectivenes

ompletely unconsolidated sands in a complex turbiditic reservoir was beyond the technical capacity of our industry. Consequently the deve

nayzah reservoir. The well was then suspended with cement plugs and the wellhead blind flanged. The 7 liner was run and cemented from 6

.5 to 5.5 bore in a 9-5/8 Casing and the production tubing usually 2-3/8 to 3-1/2 size. One of the many challenges therefore for asset owne

ults are discussed in detail.ï¿½ Laboratory tests include the effect of this cleaning up fluid on the filter cake formed by different drilling mud c erformed on the whole core recovered from the exploration and appraisal wells. The results of the analysis conducted on these wells are su

ngle sand body. It has been well proven experienced and fitted the purpose in over twenty years of gas storage activity on existing wells in proceeds from toe-to-heel covering the upper part of the horizontal well (called the Beta Wave) once the Alpha Wave reaches the toe. For

proposed for quantification of the impact of screen plugging test results on field practice. This allows operators to evaluate how much if a lls repairing problems related to sand production and loses additional millions of dollars by restricted production rates. Sand production is a wells repairing problems related to sand production and loses additional millions of dollars from restricted production rates. Sand productio esults into a conclusion relating to the validity of oriented perforating for the field a finite element model was built to reproduce the lab cond uction in 1998 major redevelopment had been undergone to achieve and enhance the fieldâ€™s recovery1. In July 2000 the Stag field reac fshore environments such as the Gulf of Mexico West Africa Brazil Trinidad and South East Asia. However it is predicted that as fields o

ment and pipelines operators also have to manage the separation and disposal of the sand produced with the oil. Sand production from th such as seen in simple elastic models account for scale effects associated with different perforation and borehole diameters provide a si d workover strategies. Introduction The consequence of sanding is well known: obstructing production eroding downhole and surface facil erage oil companies today produce 3 bbl of water for each 1 bbl of oil (Bailey et al. 2000). The effect of water cut on sand production has be

d that this behavior can also be found downhole and we concluded that the different failure behaviors of sandstone could be a geological re mance and the potential for this to severely impact both schedule and budget. Furthermore the potential risk of sand production needs to be n used to enhance the performance of oil gas and water wells for several decades. Water-soluble and acid-soluble polymers have been u nductivity than the emulsified acid system. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ 3.ï¿½The laboratory-scale acid fracture conductivitie uctivity. Finally a relative comparison between the old and new completion methodologies is made taking into account that the new complet d wells and the lessons learned throughout the pilot are also shared. ssed in the paper along with production history comparisons with offset conventionally acid fractured wells and the lessons learned through md. Zonal coverage during acid stimulation of the wells is a key issue because historically most of the acid tends to be injected into the h tabilized bottomhole pressures at rates of 3 600 and 2 500 BOPD. The well exhibited a productivity index (PI) of 2.5 to 4 bbl/D/psi extreme damage materials sandstone acidizing aims at dissolving and dispersing the minerals and damage materials in the pores of the reservoir

er the stimulation treatment has the well reached the ideal producing conditions and has the skin been reduced to the minimum possible com challenge in stimulation fluids due to the increase in bottom hole temperature. The rapid reaction rate between HCl and carbonate limits th

ars. The main production mechanisms being water and solution gas drive. ï¿½ Figure 1: Schematic of Orito Anticline The 250 ft thick res des guidelines for production engineers to optimize the fluid placement. Introduction Matrix acidizing in carbonates provides opportunity no Even though most of the formations have been placed on waterflooding most formations experience an uneven depletion of the reservoir p BT) and the wormhole velocities were obtained for each carbonate by injecting acid at different flow rates.ï¿½ The results of the tests conf a given set of wells in a field will vary depending on the reservoir under question and the prevailing well conditions. To be successful refract ed as well as potential problems associated with clays swelling and change in relative permeability. An additional benefit of CO2-based fluid p) Figure 2. All the wells discussed in this paper are located in Waltman (stratigraphic) accumulation and completed in Lance formation. ondensate field is located in the Embensky region of Atyrau province 170 km south-southeast of Atyrau city. The structure was evaluated

ge like organic deposits and scales has also contributed to the decline of oil production. The ideal solution would be shut off the water break Cement evaluation logs are time efficient cover the majority of the casing and inexpensive compared to communication tests. Their interpre ssure data from CCTs based on the notion of a stepped change in wellbore storage. A schematic is presented in Fig. 1 to illustrate the pro 1990s 16 horizontal wells were drilled whose production performance is discussed in Ref. 1.ï¿½ In 2005 three horizontal wells including o ng it) re-fracturing candidates and identification of remaining well potential deliverability. Introduction Optimization of the productivity of an ayer holds good oil reserves. Hence this well is a good candidate for future side tracking into the upper layer in order to exploit the untappe ng the storage capacity ratio interporosity flow coefficient permeability and pseudo-skin. Equations have been developed for calculating th ent test becomes critically important. It may also be called transient drainage radius. Although it is often used in pressure transient testing r were uncovered as a result of scheduled and unscheduled events on wells producing with ESPs.ï¿½ The results show that more than 70% o 06a b) and rate/pressure (Kuchuk et al. 2005) deconvolution algorithms. In this work we focus on the pressure/rate deconvolution for analy

eneous systems whose physical properties have been deformed or altered during their deposition. As a consequence it is not always easy t

y testing of gas wells is based on theory of transient and pseudosteady flow of gases (Lee 1982). Traditionally different testing procedures UAE Federation Total was granted a concession to develop the Abu Al Bukhoosh field. At that time the reserves to be produced were estim mposition between traditional surface sampling methods and multiphase testing methods. The utilization of the dynamic information obtaine

w the reconciliation factor is 1.03. This paper describes the comparison how the results were analyzed and the comparative error associate is novel comparison and qualification process of multiphase flow meters also provides a better understanding of the aptitude of conventiona ction. Today there are wet-gas flowmeters dedicated to the metering of wet-gas flows and multiphase meters for the metering of multipha ors and cost optimization. This paper presents the experience gained using a mobile multiphase well testing unit for production testing. The

fractions) knowing that the sum of the 3 holdups is equal to 1. Numerous techniques exist to try to achieve these 5 measurements ([Ref [1 e last few years 2 3 4 Currently we are interested in a consistent and integrated workflow for the latter two areas. Corbett et. al.5 . used a n

dures in addition to being cumbersome have undesirable side effects. They can alter the shape of the original data or create false oscillatio t-circuiting of the electrode array through the casing. The electrodes were mounted outside the insulation. They were in electrical contact wi

g during placement and early job termination. It is currently hotly debated whether ten or more meters of competent cement well bonded to mations. This mechanical earth model is coupled to a reservoir model to compute initial conditions at static equilibrium and to further simulat

gation options have arisen in order to reduce the CO2 emissions. One of the most current and important options is Carbon Capture and Sto nsity viscosity heat capacity interfacial tension among others but especially the strongly non-linear variation of these parameters with temp oxide (CO2) was recognized in the public as an important concept for reducing greenhouse gas emissions into the atmosphere. Notwithsta y and consensus is forming that mankind is having a visible impact on the worldâ€™s climate. It is generally acknowledged that the most i nic greenhouse gas concentration in the atmosphere. It is estimated that over 60% of this increase is due to carbon dioxide (CO2) emission

subsea systems.ï¿½The total depth of the well 34/8-A-6 AHT2 is 9082 m. The horizontal reach (slot to TD) is 7484 m and the along hole de vered by 15/20a-4 well in 1987 and appraised by a 15/20a-6 well (a deviated well drilled from the 15/20a-4 surface loacation) in 1990. Produ

large commercial scale Niagaran reef field was the Boyd Field in St. Clair County. Discovered in 1952 the Boyd has produced over 2 MM b oration of oil fields. Most CO2 fields are similar to conventional natural gas fields with the gas trapped in dome-like structures. The most co ignated tight gas in Vicksburg has been produced [1] leaving much to be recovered. Some of this recovery can be enhanced with recently m existing vertical wells to bypass the condensate bank zones.ï¿½ Comprehensive simulation studies using industry-standard reservoir si ce many oil companies have taken this technology as their main technique to be applied in the field to exploit the heavy and extra-heavy o This was followed by GOGD (Gas-Oil-Gravity-Drainage) development (1984 to 1998) which was successful in arresting the decline in the o

ften shrank when the magma lavas crystallized and solidified. This volume shrinkage caused by sudden change of temperature as well as b apabilities through technological advanced component design. The complicated nature of the water problem in northern Kuwait because o theoretical depth then a top-up job is carried out with additional slurry. On the other hand if the TOC is at the theoretical depth then a pres

plex stratigraphic framework the interpretation of which is made particularly difficult by the 1 to 0.6 kilometer well spacing. The field currently The best available option was found to be setting an inflatable packer at the top of water zone in the open hole and cap it with 200 ft of cem

chanical removal techniques such as pigging appear highly risky due to the possibility of stuck pigs. Remediation of organic deposits require uid flow can be defined as the simultaneous flow of two immiscible liquids. It can be encountered in a wide range of industries including the erns can appear ranging from fully separated (or stratified) to fully dispersed ones (Lovick and Angeli 2004). Stratified flow has received mo w immediate (rig-less) interaction with the completions production tubing or well head are needed to react on the recorded events.ï¿½ Th ain engineers who generally work in different engineering departments of the operating company (reservoir production operations and su results of experimental and theoretical flow assurance assessment indicated that the black oil has the propensity for asphaltene precipitatio ne accurate properties so that design of the subsea system may be optimized and operational procedures may be outlined. Flow assuranc he physical and chemical properties of the fluids. In many deepwater and other high cost wells formation tester fluid samples may be the o n-situ reservoir fluids and to obtain fluid fractions i.e. water/oil fractions and to monitor contamination cleaning up process prior to capturin

of decreases in producing yields after the reservoir pressure drops below the dewpoint pressure is necessary for accurate prediction of con n In 1973 Spivak and Dixon1 introduced the Modified Black Oil (MBO) simulation approach. The MBO simulation considers three compone ervoir fluids will be faster.[7] On the other hand convection is fast (~1 MYr) thus if convection occurs oil columns can rapidly move towards d presence of additional reserves or bypassed hydrocarbons are common occurrences in complex reservoirs. At a given location layer or co asset value [2]. Many pressure-maintenance and secondary-and tertiary-recovery projects have failed because inadequate geologic descrip

modeling results compare well with empirical observations made in the field. In particular the rate of change of miscible contamination with s feasible for economic or environmental reasons. Downhole samples define fluid properties that are used throughout field development. D

ons of reservoir layers5 for reservoir characterization. Mature reservoirs can have different objectives and challenges for efficient formation eum and natural gas extraction and refining pulp and paper manufacturing rayon textile production leather tanning chemical manufacturi

gas/condensate reservoirs (Creek and Schrader 1985; Smith et al. 2004; Ghorayeb et al. 2003). Ordinarily the equilibrium approach appea ome less dense and each reservoir fills downward from the top due to buoyancy and displaces the earlier heavier charge. As such there is ogs are used in combination with resistivity logs to identify reservoir fluid type. In clean reservoir density porosity log will overlay neutron po duction. There are several different mechanisms that create fluid compositional gradients. Fluid gradients can be caused by gravitation ther accuracy resolution and repeatability. Theoretically this higher resolution is sufficient for detection and evaluation of small fluid density cha ven to the distributed pressure measurements and the obtained fluid density variations are compared to the fluid model ones. Introduction be the methodology for downhole GOR measurement and we provide details of a decolorization technique to remove the color effect of dar

d density changes observed. The result of the modelled fluid and pressure analisis are compared to actual downhole measurements of the s the ratio of incident light energy to transmitted light energy: OD = log [Equation]...(1) Examples of crude-oil and water spectra in the visib st hydrocarbon reservoirs fluid composition varies vertically and laterally in the formation. Fluids may exhibit gradual changes in compositio

also in some circumstances to determine the state of reservoir grid cells. Background of the Method If sufficient heat is added to liquid wat ples indicated that the inversion point for live emulsions is similar to that of STO samples. The experimental results are also used to analyze

ll as the optimization of well completion and production tests. For development of the field fluid composition is crucial for material selection nd the bottle and as soon as it detected traces of contaminants the sampling bottle was shut off immediately even if it was not completely properly by most multiphase suppliers. Schlumberger has been a leader to bring this into the picture via the synergy of several divisions with ibes deployment of such methodology in Northern Siberia in condensate well tests and offers a number of comparison tests against traditio d calcite. Introduction Hydrochloric acid is commonly used in matrix and acid fracturing treatments in carbonate reservoirs. However applic neral exploitation plan based on water injection/reinjection was prepared at the end of the 1960s and the method proved very suitable. Bec the formation from the wellbore. The field of matrix acidizing can be further divided into the acidizing of carbonate formations and sandston al flow blockage. Like any other type of scale precipitation the halite deposition can bridge in the tubing block the flowline and result in prod

shaped charge penetration. These types of experiments were standardized in the procedures given in API RP19B (Section IV) and tests us most damaged rock adjacent to the perforation tunnel.ï¿½The failed rock collapses into the tunnel where it mixes with the remnants of the e out of solution forming scale. The degree of supersaturation affects precipitation rates and contributes to the scale severity. Factors leadin ribed in prior studies2. It has been shown that most of the scale inhibitors studied were not compatible with the crosslinked fracturing fluid a sed for scale management.ï¿½Such a study that links the use of the intelligent wells and scale management has not been reported previou ocated offshore Abu Dhabi. The field was discovered in early sixties. Oil production started in 1982. Seawater injection to support the rese 3/day (126 000 stb/day) during 1993.ï¿½Gyda is currently operated by Talisman-Energy Norge A/S (61 %) on behalf of DONG (34 %) and a the geological petrophysical and fluid properties of the reservoir are only partly known. History matching is the process by which these mo oirs under waterflooding require more accurate fluid movement forecast to avoid early water breakthrough and to increase sweep efficiency of streamline simulation. The application of streamline (or streamtube) simulation as a tool to aid in reservoir management has generally f fluid breakthrough have been identified and some valid recommendations have been made to improve Cantarell Well Management Practi g and optimization of oil and gas production which are hereby referenced as â€œengineering workflows. They target solutions that help inc cially in the lower two oil bearing units of the reservoir (Ref. 1). Consequently WI pilot has been implemented in the lower units of the reser pped in a North-South elongated faulted anticline with approximately 500 ft. of present-day four-way closure (Figure 2). Present-day closure quare miles with an estimated OIP of 18.5ï¿½109 barrels of extra-heavy oil (Fig. 1). The extra-heavy oil that is currently being produced in sate for the decline of conventional oil production and by the favorable opportunities created by current high oil prices that make these kind w et al 1999 Andres et al 1998). Microwave heating has also been considered as an alternative for carrying out the pyrolysis of biomass ( were performed considering the relative positioning of the horizontal well placement in the reservoir column; different injection sequences; re tested through swabbing due to its viscous nature and productivity was very poor. Exploitation of the field by vertical wells only is not a fe in the currently delineated field limit is more than 10 billion reservoir barrels. A generalized Stratigraphic column for PNZ is given in Fig. 3. T sing the formation tester was to take downhole representative PVT samples of high viscosity fluid in a high invasion wellbore environment in

prone to serious sand production and very low output rate in conventional vertical wells. In order to prevent sand production from both rese

shore of the Gulf of Suez (Figure 2). Most of the heavy oil accumulation occurs within shallow Miocene formations through five reservoir laye

ed a unique solution and the capability to monitor and optimize in real-time the production in this field.

stems have been developed for specific applications. In general the three main drivers for these developments are:6 Retard the acid/min formation. As a result of the job the presence of hydrocarbons was proved formation pressure and mobility profiles were obtained along th

e relative dominance of these mechanisms is in turn dictated by fluid properties and reservoir architectures. For instance the proximity of t

oppant transport also determined by fluid properties is necessary for fracture areal coverage and helps determine well performance. Over zed by matrix acidizing or acid-fracturing treatments. In matrix acidizing treatments a relatively small volume of acid is used to improve the c

nt; its first installation dates back to 1973 in Africa. Since then Schlumberger has installed more than 7 000 permanent gauge systems. Con ment formations flowing into a Floating Production Storage Offshore (FPSO) loading vessel. Average seawater depth is 165 ft. There are 215 meability varies from 1 mD to 200 mD among the zones.ï¿½The main formation damage mechanisms were identified as fines migration (8 se fluids it is possible to customize the chelant solutions and target specific well conditions to achieve maximum wormhole formation with a vertical and penetrate several thin laminated layers of thickness ranging between one to eight meters. (Figs. 1 and 2) Furthermore imprec In formations with high capillary pressure and low drawdown a high saturation of water is left in the formation after gas breakthrough crea caling and corrosion potential of the water understand reservoir connectivity and establish the salinity of the water for petrophysical evaluat

ng ways to optimize the economics of wells in this area; maximizing the production potential of the well while minimizing completion costs. H

w of world energy (Fig. 1) highlights the volumes of proved natural gas reserves at the end of 2007 and shows where they are located. Of p s the discovery of increased production by fracturing lenticular sands has made this a profitable area. Due to the nature of these tight sands r pressure maintenance including well spacing and well pattern and water flooding strategy. Introduction Hydraulic propped fracturing is con They are nevertheless short in representing the complex nature of induced fractures in unconventional reservoirs with preexisting fractures.1 ge of the offsets and the WGR was 147 bbl/MMscf compared with 397 bbl/MMscf.

ction rate was double the simulated rate of a vertical well and opened a wide range of further developments both in Foukanda and in other 00 bbls of delayed borate crosslinked fracturing fluid. The whole pumping treatment took less than five hours to complete. The tested stabili ges only 500 BOPD and 50% water cut. The SUG field currently produces 65 000 BOPD and 10 MMcf/D with 58% water cut from 65 active denser well spacing and consequent possible reservoir pressure depletion at future infill locations became subjects of investigation. These ethods commingling strategies scale inhibition and drilling locations.ï¿½ Over all the application of appropriate evaluation tools based on rom the fluvial channel sandstones of the Upper Cretaceous Lance formation at drilling depths ranging from 11 000 to 12 500 ft. The Lance howing offset production that seem to defy standard log analysis and cut-offs. They show water production from saturation calculation that m

ural fracture to the reservoir production varies depending on the formation and its matrix porosity level. In the better porosity layers in Middl and gas compositional analysis to understand its origin and potential contact migration. The wireline formation testing results have added ith production data transient pressure analysis and fracture stimulation techniques have opened new horizons in the characterization and t and coals in a complex sequence of tidally-dominated deposition. This large stratigraphic trap is draped over the Wamsutter Arch a structur

ï¿½ï¿½The tool is â€œset: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½a. ï¿½ï¿½ï¿½ï¿½The probe/packer assembly is mobile water or aquifer support. The production wells usually decline very rapidly without pressure support and the recovery factor was es viable economically this method can consistently provide a solution as to what the best completion type (vertical or horizontal) is to recover ndian depositions (approximately 0.6 billion years old). The discovery of oil and gas presence in the rocks of such age in this region of the S

y carbonate oil reservoirs have transition zones on order 50 meters in height. Considering that some of these fields have been produced for

reserves are unevenly distributed and bulk of reserves is located in Middle East countries. They hold nearly half of the worldâ€™s known re

e an alternative that results in the most feasible and optimal outcome. Traditionally many decisions involving multiple objectives and trade-o onfidence. Many project failures originate in our tendency to be more certain than we should be that a certain outcome will be achieved. Pr

d that accurate reservoir simulation and management requires a quantitative model of the spatial distribution of reservoir storage and flow pr specially that induced by formation stratification is very important in all aspects of reservoir engineering processes from well placement to uch higher spatial resolution: around 6 inches for NMR and 0.16 inches for borehole imaging (FMI*) opposed to about 2 to 3 feet for conve basin (KG Basin) which has taken the centre stage after major oil and gas discoveries in thick clastic successions from Mesozoic to Cenozo Algeria. Fluvial deposits are usually difficult to map and characterized in detail because of the high frequency of lateral facies changes and re conducted under pressurized and heated conditions to simulate reservoir conditions. In addition several field examples are presented to fluid production and presence of additional reserves or bypassed hydrocarbons are common occurrences in complex reservoirs.ï¿½ At a gi NMR logs. The interplay of multiple properties of the rock such as pore size distribution and texture influence the permeability to the extent he stratigraphic trap and to define its morphology. Iterative analyses of the seismic attributes suggested the possible geometry of the sand b actor. Stabilizers are available to support use in hole sizes ranging from approximately 8 to 10 in. Future developments of the tool will extend al data which was used to correct the neutron porosity measurement for lithology effects despite the presence of dolomite. The results

als in the pore network. The complexity is twofold. Firstly the clay geometry probably influences the conduction of the electric logs. Second ork. The complexity is twofold. Firstly the clay geometry probably influences the conduction of the electric logs. Secondly the clay minerals sed on porosity partitioning that is consistent with the Dunham Classification (Dunham 1962 Embry and Klovan 1971). Amaefule et al. (19 aries across fields. Using borehole-image data they also define and determine the orientation of smaller depositional features to understan A wide variety of carbonate textures is present.ï¿½ In some intervals depositional textures ranging from grainstones to mudstones are pres with largely laminated succession of rock layers of varying thicknesses. This issue is becoming increasingly important in Miocene turbidite fa

R and triaxial induction (3D induction) data on numerous occasions. To keep the paper readable we have broken the topic into three parts

scales is controlled by the interplay of depositional facies and fracture systems in this field. The design execution and economic aspects of nce has shown when sampling fluids from such formations sand grains and solids tend to become mobilized and flow with the fluid being s ervations of fracture distributions and information on rock properties and can be used to calibrate image logs to help geologists and petrop Neutral zone between The Kingdom of Saudi Arabia and the State of Kuwait in the Arabian Gulf as shown in Figure 1. The field has been p

esult. The realization of more subsurface resource has implications for future field development to target unswept oils in the reservoir. Intro n beds is best tested with a formation tester with inflatable packers and formation fluid pump-out. Therefore the petrophysical and geologic servations on logs of which we show case examples of thin sand-shale laminations that are water-bearing oil-bearing and gas-bearing res

onfiguration) and independent of the drilling mode. Using this new measurement significantly improves the quality of the formation evaluatio

nts and thus is controlled by injection/production rate and pore pressure in the reservoir [Zhai and Sharma 2007]. Stress reorientation arou ain a continuous profile of static elastic parameters along the depth.ï¿½ The results obtained from these approaches were compared using l med dipole radial profiling (DRP) of formation shear slownesses using the measured cross-dipole dispersions at three depths in shale and on

umed to be piece-wise continuous as a series of constant flow rate steps.ï¿½ This concept is expressed mathematically with Eq. 2 and ha

the 25th of July 2006 in the exploratory well NWO-1 of the Northwest October Concession located offshore Gulf of Suez Egypt for Arab covery has attracted a significant attention at the time being a first demonstration of the productive potential of West Siberian basement3. I res oriented in the same direction as the open fractures. This fact tends to confirm the interpretation of complex structural trends in these zo n at the time being a first demonstration of the productive potential of West Siberian basement2. In the next few years a series of medium

es have been postulated.ï¿½ One of the possibilities is the alteration of near formation properties due to drilling fluid invasion.ï¿½ Some me

olumn of clastics sediments of scarce to null primary intergranular porosity but with an important development of secondary porosity for fiss vy oils. We conclude that the addition of the continuous NMR fluid properties log to existing methods is beneficial to formation tester sampl

data quality comes at a price either in loss of vertical resolution (i.e. a cost in data value) a need to log slower (i.e. a financial cost) or both. gging research project at Los Alamos Natl. Laboratory in 1978. The goal of this project was in part to build and test a borehole NMR loggi total area is estimated to be about 200 000 km2 of which 70 000 km2 (35%) are of petroleum bearing interest." pected casing/liner shoe leaks. Second well intervention operations such as production logging (PL) and water shutoff have to be conduct

zation during drilling. Because the wellbore pressure is lower than that of the reservoir there is a permanent inflow of reservoir fluids durin count for up to 85% of the fieldâ€™s oil reserves. Mishrif is a tight layered fractured reservoir of Cenomanian-Turonian (Upper Cretaceous

can be built to accurately simulate production and help select optimal reservoir management policies. This paper includes examples in whi y compositionally graded 3 different compartments are often filled with different fluids. Thus DFA can identify compartments.4 Acquisition o med to be piece-wise continuous as a series of constant flow rate steps. This concept is expressed mathematically with Eq. 2 and has comm rom As Sarah is around 90 000 BOPD and is nearing the end of its plateau phase. As Sarah field structure is a northward dipping fault-bloc ltiple gas/water contacts with extremely depleted and virgin zones in the same well thus resulting in very high over-balance; commonly in e

n rates. Treatments have evolved from skin bypass to large scale fracturing operations. Lack of knowledge on stress magnitude along the w ynamic environment is challenging. Direct pressure measurement obtained from a formation tester is that of the supercharged zone. There n be achieved through successful uncertainty management. Uncertainty management has two main aspects: minimizing uncertainty followe ation of pressure measurements from a wireline formation tester is a key step in the appraisal phase of most oil or gas field developments. eering and project management for execution. The objectives for the project were defined as: Improve economics due to improved recove displace oil in the Mogollon formation it would be necessary to inject gas at pressures in excess of 3 000 psi. The approach and methodolo nable up-to-the-minute nodal analysis update and gas lift diagnostics. This paper demonstrates the role of field surveillance practice and rig eing considered for development. One of these developments is of Khafji stringers on structure flanks of several offshore fields. uality flow direction and structure.ï¿½ Therefore it is essential to characterize the eolian and fluvial channel sand depositional system. ave been listed under the lessons learned part of the paper. Introduction Waddell Ranch Project is located in the Permian Basin in Crane n the entire stack. Stacked hydrocarbon reservoirs are characterized by a varying number of reservoirs with different properties and charac but also improves the sweep towards the producers. Gas cap expansion is controlled via injection to provide a stable front advancement of ined by two primary faults and several secondary faults which have compartmentalized the field.ï¿½ The depths vary from 15000 and 1700 nd tightly integrated to the specific simulators used in the workflow.2 Furthermore since the FM functionality is basically independent of the n data using analytical methods and numerical simulation tools such as nodal analysis. Additionally well tests and production logs are perfo at contains 24 well slots with 48 tubing strings. In the Betty field some producing reservoirs have experienced high recovery efficiency whi to and the world economy. These brownfields are generally more than 30 years old and account for 67-72% of worldâ€™s production1. Th

the information about the pressure and fluid saturation at the subsurface coupling point (well locations in the reservoir model) to the well mo d from today to the end of field life the IAM promises multi-discipline answers. This paper is intended to serve as a road map for the deve ain engineers who generally work in different engineering departments of the operating company (reservoir production operations and su e data collection phase. Deriving the static model is the first major attempt in integrated studies to achieve consistency between all the diffe oirs consisting of three anticline structures bearing black oil. Discovered in 1984 the XJG fields are stacked reservoirs producing from the

to as minor reservoirs. In Khafji field there are approximately a hundred wells which are already completed with gas lift injection system. E and no gas cap are mostly found in 4-way-dip closures which are associated with basement highs. In some cases the traps are also associa cal pressure trends by unit and theoretical assumptions validated by indirect field evidence to onsite decision-making has resulted in the p es six Lower Vicksburg sands (namely A sand B sand C sand D sand E sand and F sand) found in less than 100 wells. It needs to be po n the field development decision will be made the client will be in possession of two types of information not initially known. The first is know

simultaneous correlation of logging while drilling propagation resistivity patterns. Real-time laterolog images indicate how the borehole traje with a large oil effect anomaly could be mapped within an area that became to be known as the Brenda field (Figure 2). This oil effect anom an be used to convert while-drilling measurements to the expected production potential of the well as the well is being drilled.ï¿½This metho demonstrated with an example from the South Timbalier 316 field. The South Timbalier 316 field is located in U.S. Federal waters offshor windling reserves base it is of the up most importance to extract all available production from existing fields within the economic limits. In b is paper also describes wellbore dynamic behavior that has not been extensively covered in the literatures. It illustrates the challenges of pl es et al. 2001 Gï¿½yagï¿½ler et al. 2002 Yeten et al. 2003) and neural networks (Centilmen et al. 1999). The first category is generally ve

ching analysis may take months to carry out. Therefore there is a need for an alternative tool that honours the physics of fluid flow and at uick studies of an oil or gas field. Typically such methods are either based on material balance (Tracy1 Reudelhuber and Hinds2 Hobson rs and 31 producers. Using well log data and water-cut history from producing wells; we characterize the permeability distribution thus dem duction Conditioning geological models to production data is an important step in reservoir modeling to build a reliable model to be used in

imulated response equal to the observed data. This implies that the optimization problem can be quite large potentially equal to the numbe

his paper describes a general unstructured grid fully-implicit thermal simulator based on a nature variable formulation. The first section des mary variables used in the governing equations. There are two basic approaches natural variable based or mass variable based. The implic solve the problem and calibrate the model for better predictive power. Introduction Horizontal wells play an increasingly important role in in

for successful actual field studies as well as semi-synthetic examples are presented. Introduction Horizontal and multi-lateral wells have b

g fluid (Seright 2002) cause local polymer-concentration changes along the fracture. Thus breakers are seldom distributed uniformly and th e face. In addition damage to proppant pack reducing the conductivity and the associated non-Darcy flow effects which cause additional s the more developed porosity and permeability is the most prolific and does not typically require stimulation. In contrast zones 2 and 3 are ent from the behavior of a two-phase gas or oil reservoir. A number of published papers have documented the peculiarities of gas condensa r a vertical hydraulic fracture propagating in a formation with horizontal bedding planes the fracture height is directly related to the interfacia nefit the profitability of a new well. There are however high associated risks that are result of the large number of variables that must be co

nstructed bottomhole pressures. The allocated production rates at times when there are no production logs are computed by linear interpola uctivity index solution for vertically fractured wells in closed cylindrical and rectangularly bounded reservoirs2.ï¿½ The extension of the dim dial geometry is propagated from the central cluster which can be considered as a source point. To design such fracturing jobs and to inter iation would have a minimum injection pressure drop initiate only a single bi-wing fracture and generate a fracture with minimum tortuosity ssing system that has certain performance characteristics in common with biological neural networks (Fausett 1994). On the basis of the â€

not have any effect on its performance. This work summarizes the workflow we developed in the dynamic modeling of this field the history m tational forces and stratification tend to undermine sweep. Measurement of injection profile in horizontal wells is also a common requireme

aterial balance analysis is a part of that integrated study. The objective of the material balance analysis is to investigate the drive mechanis reservoir temperature were less significant. Introduction Material balance is a simple and one of the most important reservoir engineering have not been revealed. The absence of geological and geophysical regularities in distribution of parameters and the absence of impermea variation in multicomponent mixtures in porous media have been investigated for single-phase systems (Riley and Firoozabadi 1998; Ghor s reservoir engineering studies (Friedmann White Amudo Graf Salhi â€¦). A typical workflow features the following steps: 1. Uncertainty F

e maximum principle it is sufficient that the discrete operator is represented as an M-matrix. An MPFA scheme which guarantees an M-matr

but also the vugs.ï¿½ Oil recovery from vugs is highly dependent on the geology and the fluid flow situation.ï¿½ The mechanism of oil recov sity is simultaneously history matched through the probability perturbation method of Caers (Caers 2003; Hoffman and Caers 2005; Caers 2

s were not considered a general purpose reservoir simulation technology. During the 1960-1990â€™s the reservoir simulation community phase saturations etc. and interacting via the so-called transfer functions (see e.g. [13]). Recently the three phase compressible dual po d to optimize recovery for; see Bockel-Rebelle et al. (2005). About 60% of the world's conventional oil reserves are contained in carbonate

phase flow (Oliver et al. 1996; Reynolds et al. 1999; Liu and Oliver 2003). Our first objective is to show that contrary to a previous claim (Flo

arise after water breakthrough. One particular problem is that of scale formation. This paper will consider one of the mechanisms which con

rom the CFL condition and performs the saturation transport step over this time step. The streamline method takes advantages of the know These problems can be solved by any available methods. Because of such splitting the CPU time requirement is significantly reduced. The ell data and the wisdom acquired over one century of production history to produce a set of innovative practices to boost the efficiency of th

ntiles from the thus qualified models may be used for the assessment of uncertainty in the future flow performance. However the noise o s et al. 1998) which allow the representation of multilateral topology the presence of inflow control devices multiphase flow wellbore stora

in northern part of Kuwait consists of five fields each with three identified reservoirs (Najmah/Sargelu Upper and Middle Marrat and Lowe

ility k is an intrinsic property of porous media. To describe the nonlinear flow situation a quadratic term was included by Dupuit9 and Forchh ounding imbibition and drainage capillary pressure and relative permeability curves (with associated end points).ï¿½The answers being sou g would be the best technique to use to avoid lost circulation problems in these very depleted formations (as low as ~1200 psi at 11 000 ft in Enhancing the production to its maximum level is the reason though the drilling uncertainty is being pushed to a limit that causes unexpecte siness processes and permit people working with these processes to assimilate the huge and diverse volumes of data and information. In

Sea province. Political boundaries were chosen such that government fiscal and environmental policies are consistent for each province. h case they offer no advantages over analytical models. Indeed Bosma et al. (1999) used the analytical model and results from Thiercelin e

. In each well through-casing resistivity was acquired. A pulsed neutron capture (PNC) tool was run in one of the wells. On the basis of this gas lift completion was implemented using this field proven technology repackaged for a more efficient safe and environmentally friendly c ds. Mauddud Carbonate Formation is located below Tuba Carbonate and above Lower and Upper Burgan Sandstone Formations. These fo h-hole angle and the long reach.ï¿½ Wireline logging using typical tractors is not practical either because they do not provide enough tracti

a shallow marine environment and is rich in carbonates and is frequently highly dolomitized. In such complex reservoirs the acquisition of q a shallow marine environment and is rich in carbonates and is frequently highly dolomitized. . ï¿½A dual gauge system was envisioned in an observation well to monitor in real time the change in pressure and pressure gradient as th he right decisions early in development planning. Later in the production cycle formation-water data can be used to differentiate produced c ion enhancement and economic reserves exploitation. Terms such as â€œdigital oilfield â€œsmart wells or â€œreal-time have become co connected with the created fracture and represent movement of the injected fluids. Introduction Canyon sandstone formation of West Texa one many assumptions of height control as indicated by a temperature log alone may in fact conceal an excessive height growth environm

ase the recovery method is SAGD. 1 This method requires injection of steam into an upper horizontal well creating a steam chamber and have demonstrated that only slight changes in wellbore inclination can have a dramatic effect on the types of flow and flow regimes exhibited only slight changes in wellbore inclination can have a dramatic effect on the types of flow and flow regimes exhibited in the system. As pre one gas wells and Smith and Steffensen4 who discussed the impact of the Joule-Thomson effect5. The temperature log faded in importan

multiphase flowmeters may have limitations when gas/oil ratio (GOR) is high because of the high volume of associated gas that evolves from

mparison versus a production reference is needed. As each well has its own properties it is not fair to compare wells among themselves or w production logging sensors. The objective of production logging is to measure the hold-up and velocity of each phase along the horizontal d atched simulation model. Background and Study Objectives The Wara reservoir is the uppermost sandstone interval of the Greater Burga haltenes and waxes. As background the characteristics of these hydrocarbon solids are presented in Reference 1 and a brief description is level of production monitoring and re-estimate their initial assumptions to calculate how much recoverable oil they left behind. This paper Introduction WFT has become a standard part of the evaluation program of most newly drilled wells but the objectives vary from offshore age the buildup pressure in a multilayered system. Therefore if one wishes to measure individual layer pressures only two options are curre xpressed through seismic deformation and the release of seismic energy as fractures adjust to the strain field (Maxwell et al. 2003) and also 1987 and first production occurred in 1980.ï¿½ The Azeri field constitutes the south-eastern culmination of the structure and is being develo Worldwide subsea activity is growing rapidly. Infield Energy Data Analysts (2008) forecast subsea expenditure to increase by 65% to USD 10

months after completing back allocation to obtain estimated oil rates for each well with the disadvantage that this method does not provide y universal in brown fields. Production logging provides a viable means of detecting and measuring downhole oil gas and water entry espe

om 84% to 0.5%. ï¿½ The results were encouraging enough for the operator to reinvestigate the production performance and identify wells rocks. Sigma measurement (Î£ ) is proportional to dissolved chloride ions in formation water; hence it is related to formation water salinity. T reservoir conditions and injected fluids and 2) to carry out actual EM tool simulation and check the quality of tool response. The study conc luding deep reading technologies like cross-well electromagnetic surveys. The WI pilot was designed to determine sweep efficiency in the t the largest reserves. (See Anderson et al. 2003 for extensive discussions of many aspects of CBM production and reserves.) The worldwi ogy in coal bed methane wells based on cleat density stress direction cleat orientation and wellbore stability. Introduction CBM reservoirs tic reservoir rock in a gas expansion drive system and the unconventional desorption from a coal seam. With few exceptions almost all Co y will concentrate on wells within Denton Wise and Tarrant counties which form the core area. The Barnett in the core area ranges from 3 eatment is large subsequent productivity is often prolific (2).ï¿½ Unfortunately other field experience also indicates problems initiating frac ed tubing reel that is equipped with a fracturing isolation tool. The dry coal has not responded well to any other form of stimulation.ï¿½ The m treatments were performed as the well count slowly increased into the 20s.ï¿½ From the mid 1980s to the first half of the 1990s massive momentum. The characteristics of the Barnett Shale reservoir can be typically described as extremely low permeability (100â€“600 nano-Da mplex than conventional simulations and require more iterations processing power and computer memory to run. As a result SAGD reserv sorbed gas whereas shale gas is a combination of sorbed gas and free gas. Coalbed-gas reservoirs contain an orthogonal fracture set cal With a continuing optimization of the described refracturing technique these FDS designs and placement strategies have evolved to the po es of thumb and conservatively copying previous successes in the geographical vicinity.1 2 In sandstone acidizing the acid-rock reaction c

are taken from the inlet and throat of the venturi tube and this pressure differential is applied to an entrapped fluid column then the fluid co he Sibneft fields. The Sporyshevskoye oil field has been one where horizontal wells are in massive use and have been recognized as a key h and net pay from 230 to 370 m in a reservoir with very good petrophysics proprieties. The evaluation of those data increased the initial res ug is set one or more layers are perforated and then the layer(s) are stimulated as a stage. This practice is repeated multiples times until a aditional gun selection would not surpass the skin and that in fact if would require deep penetrating charges with big hole (to minimize sand he wellbore liquids to the surface are referred to in this work as sub-critical velocities. In this research effort as well as in the discussion pr he wellbore liquids to the surface are referred to in this work as sub-critical velocities. In this research effort as well as in the discussion pr and variable fracture density.ï¿½ In the past 16 horizontal wells were drilled in the 1990s to exploit this reservoir. However interpretation of

mply distinguish efficiencies of recovery in the two orthogonal directions. In a laterally heterogeneous system or when bedding planes exh . 2007). Several authors quantified potential gains from the use of such wells and completions in field developments (Yeten et al. 2002; Sal

fluid at the bottom of the well to transfer them to the surface. Acid treatment is a stimulation process used to bypass a damaged area in th al model that fits the data closely. We then examine variables included in the model and finally make predictions about ESP system perfor ovement that will help in promoting a step change in acid fracturing industry worldwide. uality and â€œskin damage assumed to be present from using brine-based drilling fluids. The initial stimulation results were encouraging. L

lower bounded by the argellaceous Three Forks. In the thermally mature window the organic rich shale generates and expels oil into the ad % lower compared to the conventional treatments. Increases in productivity allowed up to a 37% increase in oil flow rate. Introduction Initia

is research will present a comprehensive story supported by technical analyses. Introduction and Background Fibers in various forms or c understanding the reservoir is important in selecting the appropriate flowback aid. Introduction: Flowback aids should in theory be critically containment mechanisms modulus contrast is often considered separately from stress contrast to isolate the effect of each parameter. In re ing the time to well tie-in and the workover cost per zone. Strategies such as multiple-zone commingled completions continuous multistage (NPDES) permit or into a publicly owned treatment work (POTW). Typical costs associated with disposal range from $0.30 to $10/bbl for in nto the pilot program with the aim of understanding the impact of the stimulation treatment by accounting for variability (reservoir heterogen hniques that overcome this issue such as use of shunt tubes were found to render higher normalized oil production rates. Introduction Fra n inflow at the wellbore. Likewise vertical growth into a gas cap is equally undesirable from the standpoint of decreased primary recovery. rces are more challenging and required the use of advanced technologies. One of the flagrant examples is the challenging Mauddud forma e coasts of Cameroon Gabon and Congo in water depths ranging from 9 m to 95 m. These fields were discovered in the early 1960s and improve the economics of particular projects or make them commercially viable in extreme cases. Over the last two decades many develo

production targets. This paper details the planning and design processes leading to the implementation of the first field trial experience an

date the field has produced 24.41 Mmt of oil and 8.48BCM of gas. The production is on decline as seen from production history plot (Figure

and characteristics of the oilfields. This includes a geological overview reserves distribution drilling and completion practices and productio

solates each layer during treatment. ulated in stages. In each stage a selected number of production intervals are perforated or jetted and then the stimulation treatment is pum ar-elastic rocks often show discrepancies between calculated parameters and field observations when they are used with soft rock formatio ful rheology within concentrations ranging from 3.5% to 6%.ï¿½The exact surfactant concentration depends on the bottom hole temperatu

½ Studies have reported permeabilities ranging from 0.1 mD to 1 mD based on pressure buildup analysis and matrix porosities ranged from

asphaltene plugging problems in the production strings. Recent laboratory studies indicate a high asphaltene flocculation onset pressure of ength.3 Polymer damage leading to ineffective fracture clean-up is prominent in the list of usual suspects.3-6 In addition it was surmised th r to achieve an optimum fracture system within the targeted intervals.ï¿½ï¿½ï¿½ Introduction The Cotton Valley sand is an abundant cons

he absolute orientation (in a geographical coordinate system) of the monitoring array and of the observed microseismic event hypocenters

e resulting fracture conductivity at least at low closure stresses--if the fracture faces are smooth only a narrow slit will remain when the frac e of height length and azimuth. PSM Acquisition must be done during hydraulic fracturing from the nearest well. The main goal of this study Introduction Ever since the first use of hydraulic fracturing the oil industry has wanted information about the geometry of what wascreated

meters were available. Therefore the method envisioned had to be based on frequently available informationâ€”the openhole logs that are e of the much greater flow areaâ€”two orders of magnitude lower than those around a wellbore and non-Darcy flow is not an issue. In

uring is used to increase gas production from the carbonate reservoir.1 2 The K-formation is a deep and high temperature gas reservoir un taking into account the associated costs into a financial model. e computed directly assuming that the coseismic deformation results from a shear failure mechanism (Zoback and Zinke 2002). Additionally of: a decrease in fracture conductivity. The proppant portion removed can no longer hold open the fracture near the wellbore. exposing d f the local minimum stress direction by 90ï¿½ (i.e. parallel to the initial frac instead of normal to it as in the virgin formation). As a result a r gated both numerically and experimentally. It was demonstrated that definite inhomogenity could essentially stabilize displacement. Introduc a valuable methodology that decreased the operational and production risks that are associated with hydraulic fracturing using large propp

of usual suspects.6-9 In addition it was surmised that the concentrated polymer has significant yield stress and its effect on fracture fluid c 500 meters deep in water depth of approx. The main reservoirs are 400 meters thickness and the reservoir pressure is approximately 5000 d in the sixties and quickly put in primary production at the beginning of the seventies the waterflooding began trying to restore reservoir pre atory experiments have also been carried out to better understand the role of discontinuities on the hydraulic fracture path.ï¿½ These expe minating the need for annular safety valves in places where they are required in conventional gas lift environments. 7. Allowing nonassociate in detail. Additional relevant information to BP Trinidad & Tobago field developments maybe found in the literature.6-14 Cased and Perfora ackers are hydraulically set and fracturing treatments are pumped in separate stages but as a single continuous operation. By eliminating ce ckers are hydraulically set and fracturing treatments are pumped in separate stages but as a single continuous operation. By eliminating cem y TOTAL E&P Indonesie as part of their operations in Indonesiaâ€™s East Kalimantan region. In the same region TOTAL is also operating st trending anticline consisting primarily of cretaceous age sandstones shales and carbonates. The reservoir consists of ruddist build-ups t ion Well 2). Well 1 in the consolidated formation is flowing with equipment ESP and its initial production was about 4000 BOPD dry oil cur ells and associated facilities.

. This combination of monitoring and control technology has the potential to significantly improve oil recovery (Algeroy et al. 1999; Glandt 20 an industry-sponsored research group called FAST (Fracturing Acidizing Stimulation Technology) a consortium formed within the Petrole

t the reservoir vertical permeability in each layer. As a result there are significant vertical heterogeneities in theseis types of reservoirs. It is period of relatively smooth operation. These occurrences usually coincide with an increase in depletion water cut or changes in the artificia perforating effect is ignored.ï¿½ Under such testing configuration the rock dissolution pattern goes from face dissolution to dominant worm normal fault systems. Field-Î± was discovered in 1986 with evidence of hydrocarbons in the Tadrart sandstone formation (Lower Devonian/ et the production objective. Project Result After performing the coiled tubing operation by isolating J10.2 with inflatable bridge plug and per oductivity in mature/low pressure assets. Introduction Perforating can be defined as the process of connecting the well with the reservoir by body of sufficient length and aerial extent that is not geologically complicated laterally. When commingling production from multiple zones 180 degree phasing. Aligning the guns along the PFP is therefore an important step in attaining the optimal perforation for fracturing as des ese wells are completed and perforated to see if any improvements are possible. ADMA OPCO completion requirements Fig.1 for the produ able the implement of better strategies for well completions and production optimization as well as correct inputs of nodal analysis. Introdu with nitrogen gas to create the underbalance required Faster running in hole and pulling out hole compared to drill pipe Cheaper daily rate y intervention operations. A split gun is one that is fractured with a crack extending from one shot exit hole to adjacent shot exit holes which

essures ranging from tens to hundreds of kilobars applied in less than a millisecond. This damaged material is believed to contain a â€œcr ctive a well will be is the effectiveness of the perforations. The perforation creates the path for the formation fluid to flow from reservoir to the

our industry. Consequently the development was delayed until 2002 to enable Petrobras to develop the necessary technology and expertis

7 liner was run and cemented from 6661â€™ to 4907â€™ with 100% circulation. WORKOVER No. 1: was completed on 10-30-93. Cemen

challenges therefore for asset owner in the Niger Delta includes managing production while avoiding formation sand production; for very cl

ake formed by different drilling mud composition.ï¿½ Field case histories comprise of the gravel packing of the oil producer well and subseq sis conducted on these wells are summarized in Table 1. These results are typical of all producing formations in the Greater Plutonio Devel

storage activity on existing wells in the central part of one UGS field in Italy. In order to have high gas rate performances the new infilling w he Alpha Wave reaches the toe. For typical Alpha Wave height designs used in these treatments (barely covering the screens) pressure inc

operators to evaluate how much if any screen-plugging can be expected with the particular conditioned OBM as the screens are run in ho oduction rates. Sand production is a common occurrence in highly unconsolidated (soft highly permeable) formations which produce oil g ted production rates. Sand production is a common occurrence in highly unconsolidated (soft highly permeable) formations which produce was built to reproduce the lab conditions. This model correctly predicted the conditions required for sand failure as observed in the lab. This ery1. In July 2000 the Stag field reached its peak rates in excess of 30 000 BOPD. Late that year a failure occurred in the reservoir between wever it is predicted that as fields onshore deplete a new sand control market will emerge. The majority of cased-hole sand control compl

with the oil. Sand production from the Sarir field was first recorded in the mid-1970s when sand fills were discovered during workover oper nd borehole diameters provide a significant improvement and predictive capability over simple empirical methods provide the above accu eroding downhole and surface facilities and demanding additional process and exposal cost. It will be quite straightforward to detect and id water cut on sand production has been a major concern in the petroleum industry. It has been observed on many occasions in the field that

f sandstone could be a geological reason for the different severity of sanding problems in various oilfields. Using image analysis of thin sec l risk of sand production needs to be assessed prior to completing the wells. The production experience from the nearby fields has been mi acid-soluble polymers have been used in these treatments to increase the viscosity of the treatment fluids and hence enhance diversion du tory-scale acid fracture conductivities measured in these experiments do not agree with the predictions of the Nierode-Kruk correlation. Int g into account that the new completion practices have only been applied in full combination since 2004. Background The Permian Basin in

lls and the lessons learned throughout the pilot. Introduction Saudi Aramco is among the acid fracturing industry leaders and one of the m e acid tends to be injected into the higher permeability layers or the first-stimulated zones. In an attempt to overcome this problem and ach ex (PI) of 2.5 to 4 bbl/D/psi extremely good reservoir quality (average 500-md) and a negative post-acid skin value (s~ -4). Background

aterials in the pores of the reservoir formation. For this reason the stimulation results using the known standard acid fluid formulations for d

educed to the minimum possible compatible with the type of reservoir from whi between HCl and carbonate limits the penetration of HCl into the formation especially at low pumping rates. The reaction of HCl often need

Orito Anticline The 250 ft thick reservoir is a massive sand with interbedded shale and carbonates deposited in a marine environment. Th n carbonates provides opportunity not only to remove or by pass damage in the vicinity of the wellbore but to also improve the near-wellbor n uneven depletion of the reservoir pressure hence new improvements in hydraulic fracturing to increase fracture conductivity are actively d es.ï¿½ The results of the tests confirm the original hypothesis that the response of the carbonate rock to acid depends on the RRT it belon conditions. To be successful refracturing treatments must result in longer and/or more conductive propped fractures or expose more net pa dditional benefit of CO2-based fluid is that it provides a weak acidic (low pH) environment that prevents even further common problems ass nd completed in Lance formation. u city. The structure was evaluated for deep drilling by seismic exploration in 1958. Exploratory drilling started in 1963. The field was disco

on would be shut off the water breakthough intervals and then stimulate the oil bearing intervals only. However conventional isolation tools communication tests. Their interpretations however occasionally do not predict behind casing communication creating a perception of unre esented in Fig. 1 to illustrate the process of CCTs. This is essentially equivalent to drillstem tests (DSTs) when the formation fluid does not g 05 three horizontal wells including one tri-lateral as discussed in Ref. 2 have been drilled to further exploit this tight reservoir.ï¿½ This pape Optimization of the productivity of an oil or gas well is a process of evaluating all of the available practical completion and operating conditio ayer in order to exploit the untapped reserves in this layer. In this paper we will discuss the MLT testing technique introduce a workflow f ve been developed for calculating the skin for three partial completion cases: top center and bottom. The analytical solution was obtained b used in pressure transient testing radius of investigation still is an ambiguous concept and there is no standard definition in the petroleum e results show that more than 70% of wells can benefit from stimulation potentially increasing production up to 300%.ï¿½ To make proactiv ressure/rate deconvolution for analyzing well-test data. For over a half century pressure/rate deconvolution techniques have been applied

consequence it is not always easy to match the behavior of these systems specifically to forecast their production during simulation.

ionally different testing procedures like flow-after-flow isochronal and modified isochronal are used to estimate parameters required to pro reserves to be produced were estimated at 194 MMstbo the field having an expected life span of 15 to 20 years. Today after 36 years an n of the dynamic information obtained from the multiphase flowmeter to complement the understanding of the reservoir performance is discu

and the comparative error associated with each technique. anding of the aptitude of conventional means to collect rate in the case of wet gas wells in Northern Siberia. meters for the metering of multiphase liquid flows. The common approach to wet-gas measurement relates gas and liquid flows to a pseu sting unit for production testing. The challenges presented by the nature of these operations and the requirements for successful well tests

eve these 5 measurements ([Ref [1 2 and 9]). Meanwhile a multiphase flowmeter is measuring at line conditions the different flowrates; th wo areas. Corbett et. al.5 . used a numerical model of braided fluvial reservoirs to calculate well test responses. A â€œgeo-skin concept wa

original data or create false oscillations at late times and during infinite-acting radial flow. The current practice is to use centuries-old analyti n. They were in electrical contact with the cement but not with the metal casing. The casing was perforated with oriented perforations so as

f competent cement well bonded to casing and formation would degrade during the expected isolation timeframe for CO2 geological seque tic equilibrium and to further simulate the stress path rock deformations and potential rock failure associated with CO2 injection . The initia

nt options is Carbon Capture and Storage (CSS) where the CO2 is captured and separated from energy-related sources transported and fin iation of these parameters with temperature and pressure4.For instance in the range of 80 to 90 bar (at 35ï¿½C) the density and viscosity ons into the atmosphere. Notwithstanding technology the understanding of the storage geometry from the near surface to below the storag erally acknowledged that the most important environmental impact of fossil fuel burning is an increased global warming from the buildup o ue to carbon dioxide (CO2) emissions alone[i]. Carbon Capture and Storage (CCS) that is the capture of CO2 from industrial and energy-re

TD) is 7484 m and the along hole depth (AHD) reach is 7593 m - a world record reach from a floating installation. (Figure 4 5 6) Low fric a-4 surface loacation) in 1990. Production from these two wells commence in 1992 untill 1997; at this point a total of 15.3 mmstb oil was pro

the Boyd has produced over 2 MM bbls of oil and over 21 BCF of gas. From the mid 1940â€™s through the 1960â€™s a number of public n dome-like structures. The most common reservoir lithologies are sandstones and dolomite with mudstone and anhydrite being the most c very can be enhanced with recently developed high-resolution technology. The decision on whether to set pipe or complete a particular zo using industry-standard reservoir simulator ECLIPSEï¿½ (trade mark of Schlumberger) were conducted to investigate the potential of this exploit the heavy and extra-heavy oil accumulations. In Venezuela a considerable amount of heavy oil in place has been mapped but to d ssful in arresting the decline in the oil production. Following a simulation study in 1996 it was decided to implement a line-drive waterflood w

n change of temperature as well as by viscosity increase during the times that these magma lavas crystallized and resulting in the formation oblem in northern Kuwait because of the fact that the targeted sections are usually located in-between multiple oil producer zones revealed at the theoretical depth then a pressure test is performed to confirm that the perforations are squeezed off. For intervals behind the sleeve

eter well spacing. The field currently produces ~ 115 000 BOPD. Figure 1 shows the geographic location of the Boscan field. Since its disc en hole and cap it with 200 ft of cement and 300 ft of gel plug. The cement in conjunction with gel plug must be carefully designed to reduce

mediation of organic deposits requires relatively short-duration solvent soaking operations followed by removal through exposure to turbulen wide range of industries including the oil industry where it commonly occurs in the production and transportation of oil and water during the 004). Stratified flow has received more attention during the past decades because of its low phase velocities and well defined interface. On eact on the recorded events.ï¿½ Those devices can be in the simplest case an on-off tool to close in part or entirely a completion.ï¿½More ervoir production operations and surface facilities). However the analysis and decisions made by those departments are generally made i ropensity for asphaltene precipitation caused by pressure depletion during primary production. Simulation results revealed that the downho es may be outlined. Flow assurance and phase behavior of waxy crude oils may be predicted; however the prediction of these properties n tester fluid samples may be the only source of fluid properties and/or robust enough for economic screening. Therefore it is imperative th cleaning up process prior to capturing fluid samples1. This was done by the application of optical principles for continuous analysis of fluids

essary for accurate prediction of condensate reserves. The reduction in surface yields can be as much as 75% during the primary productio simulation considers three components (dry gas oil and water).ï¿½ The main difference between the conventional black-oil simulation and l columns can rapidly move towards equilibrium.[8] In high cost arenas such as areas of deepwater development one of the biggest imped voirs. At a given location layer or compartment reservoir fluids may change with time; water encroachment secondary gas cap formation/g ecause inadequate geologic description and lack of reliable rock and fluid data [1]. Compartmentalization and fluid spatial & temporal varia

hange of miscible contamination with time has been found empirically to vary as t5/12. For the first time modeling has been shown to give e sed throughout field development. Downhole Fluid Analysis technology (DFA) is a concept rather than a specific tool. Currently DFA relies

nd challenges for efficient formation evaluation and reservoir management. As gas cap expands and active aquifer water moves in hetereg ather tanning chemical manufacturing and waste disposal. The Hydrogen Sulfide (H2S) content of subsurface hydrocarbon reservoirs has

rily the equilibrium approach appears to explain gradients observed in the field. In reality however heat flux can potentially prevent attainin er heavier charge. As such there is a tendency for the average API gravity GOR and bubble point to increase in successively deeper reser y porosity log will overlay neutron porosity log in water zone. In hydrocarbon bearing zone density and neutron porosity logs will start crossi s can be caused by gravitation thermal gradients biodegradation water washing multiple reservoir charges and leaky seals. Because it is evaluation of small fluid density changes and pressure variations within individual wells â€“ this capability potentially leads to some new ap o the fluid model ones. Introduction Recently developed wireline technologies involving downhole fluid analysis measurements through opt que to remove the color effect of dark oils from the methane oil and base channels in a downhole optical fluid analyzer tool. This technique

ual downhole measurements of the pressure profile and insitu fluid logs. In particular pressures and densities calculated from the multiple s de-oil and water spectra in the visible and near-infrared (NIR) regions are shown in Fig. 1. These spectra have three important features. Fir xhibit gradual changes in composition caused by gravity or biodegradation or they may exhibit more abrupt changes due to structural or str

sufficient heat is added to liquid water it boils.ï¿½ If more heat is added then the liquid will disappear and all water will exist in a vapor pha ental results are also used to analyze and evaluate the performance of an ESP system when water cut increases and causes emulsion in a

sition is crucial for material selection of well completion and surface flowlines flow assurance design of process control and production fac diately even if it was not completely full. For this set-up to work the volume of flowline between the pump and the bottle had to be enough t the synergy of several divisions within Schlumberger being each expert in knowledge of phase behavior and sampling techniques. A generi of comparison tests against traditional well testing and fluid analysis methodologies. A recap of lessons learnt captures the best practices o arbonate reservoirs. However application of HCl in deep wells is a concern because of its high reactivity and sludging tendencies when the e method proved very suitable. Because of the depletion of the field a sustained injection rate with delimited surface pressure is necessar f carbonate formations and sandstone formations of which the chemistry of acidizing fluids varies significantly.ï¿½ Carbonate formations ar block the flowline and result in production decline. Even in relative low water-cut wells dramatic halite buildup is still experienced in some p

API RP19B (Section IV) and tests using a slightly modified test protocol are routinely performed in the authorsâ€™ flow laboratory in Rosha ere it mixes with the remnants of the perforation jet to form a fill of loose debris. Figure 1 shows a cartoon of a perforation immediately afte to the scale severity. Factors leading to supersaturation are: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½1. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½Increased min with the crosslinked fracturing fluid and this resulted in low gel strength even at inhibitor concentrations of 5 ppm or less. Therefore the scal ment has not been reported previously.ï¿½ Figs. 1 and 2 illustrate some of the issues that may affect the performance of production tubin awater injection to support the reservoir pressure started in 1984. Water breakthrough started in 1990. Strontium Sulfate (SrSO4) scale wa %) on behalf of DONG (34 %) and Norske AEDC A/S (5 %).ï¿½It was originally operated by BP Norway Ltd. and when it came on stream ng is the process by which these model properties are modified in order to fit the production data. The general strategy is to start at field lev ugh and to increase sweep efficiency. The knowledge of fluid movement in the matrix and fracture and how injectors and producers are per ervoir management has generally found much favor today in the areas of waterflood performance analysis geological model screening or e Cantarell Well Management Practices. Also included in these investigations is the Double Displacement Process modeling (DDP) to ident s. They target solutions that help increasing asset recovery factors and knowledge capture by transforming data into decisions at the right ti ented in the lower units of the reservoir. A detailed multi-year and multi measurement monitoring plan has been established to determine th sure (Figure 2). Present-day closure has been modified slightly by a recent structural tilt which occurred after the trap was filled with oil. To il that is currently being produced in the area has gravity values ranging between 6 ï¿½and 10ï¿½API with an average value of 8.5ï¿½API high oil prices that make these kinds of projects more profitable. Countries like Canada Russia and Venezuela are directing their efforts t rrying out the pyrolysis of biomass (Miura et al 2000; Kriegerbrockett 1994) coal (Monsef-Mirzai et al 1992; 1995) oil shales (El Harfi et a umn; different injection sequences; varying the duration of each injection cycle; various injection rates; and lengths of the horizontal reach o field by vertical wells only is not a feasible concept. Therefore it has been decided to drill horizontal well and complete openhole which will c column for PNZ is given in Fig. 3. The reservoir mainly consists of dolomitized packstones and grainstones deposited under arid to semi-a gh invasion wellbore environment in three exploration wells of a new remote field. Use of dual packer for PVT sampling and single probe an

vent sand production from both reservoirs to delay water production from Bentiu formation and increase productivity and enhace the reserv

ormations through five reservoir layers as illustrated in Figure 3. Upper and lower dolomite formations are produced thermally through huff-a

opments are:6 Retard the acid/mineral reactions for deeper acid penetration Make the acid less aggressive to well completions and Av obility profiles were obtained along the tested sublayers of Achimovskaya formations and high-quality PVT fluid samples were acquired. Thi

ures. For instance the proximity of the reservoir fluid to its critical point at reservoir temperature and pressure has been known to impact the

s determine well performance. Overcoming the various demands on a gel formed from a single organometallic crosslinker is difficult to achi ume of acid is used to improve the conductivity of the area adjacent to the wellbore. In acid fracturing treatments however the acid is used

000 permanent gauge systems. Continual performance improvement has yielded the most reliable track record in the industry. awater depth is 165 ft. There are 215 wells in the White Tiger field which are mostly directionally drilled up to 70 degrees angle. There are a were identified as fines migration (80-90% production decline after treatment) and CaCO3 scales mainly due to loss of workover fluids. maximum wormhole formation with a minimal volume of solvent. Control over reaction kinetics is vital when acidizing carbonate formations a Figs. 1 and 2) Furthermore imprecise clay volume determination uncertainty in the lithology rock texture structure and formation damage rmation after gas breakthrough creating a water block. A long time is required in such a situation to recover gas production by evaporation f the water for petrophysical evaluation. Corrosion potential of the water is important for material selection for tubing pipeline and process

while minimizing completion costs. Horizontal wells have been drilled extensively in the Cleveland area as a result of this among other reas

shows where they are located. Of particular interest are the volumes of proved reserves in the Middle East. By far the largest volumes resid ue to the nature of these tight sands - wells can be located in closer proximity without lowering the production rates of neighboring wells. W n Hydraulic propped fracturing is considered a very conventional way to effectively stimulate oil and gas wells in low to mid permeability form eservoirs with preexisting fractures.1 2 3 4 5 This is because the otherwise straightforward propagation of a simple wing-like hydraulic fractu

ents both in Foukanda and in other analogue fields in the offshore Congo. Introduction The Foukanda Marine field is located 20 km to the hours to complete. The tested stabilized measurement indicates natural production of gas at 5.8 mmscf/day which is more than 20-times as D with 58% water cut from 65 active wells out of which 25 wells are horizontal and horizontal sidetrack (HST) wells. All wells are on artificial me subjects of investigation. These investigations have been carried out with numerical simulation models constructed based on integratio propriate evaluation tools based on geological setting and appropriate information gathering has resulted in production increases of up to 30 rom 11 000 to 12 500 ft. The Lance formation consists of several hundred feet of stacked lenticular sands and siltstones floodplain shales on from saturation calculation that may be in the 70 or 80 percentile ranges. On top of this these laminated sequences may be found in wh

In the better porosity layers in Middle MR good production from matrix was detected by production logs run in many wells. However in the ormation testing results have added direct values to reservoir evaluation and development. In this paper a best operating practice for simila orizons in the characterization and the production of the challenging tight reservoirs of Algeria. Geology Located about 800 km South-South over the Wamsutter Arch a structural up-lift dividing the Great Divide Basin to the north and the Washakie Basin to the south (Figure 1). Th

½ï¿½The probe/packer assembly is pushed up against one side of the borehole while hydraulic pistons provide anchoring on the opposite s port and the recovery factor was estimated to be only 3% if a waterflooding program was not implemented. Also the knowledge of maximum e (vertical or horizontal) is to recover reserves and enhance recovery efficiency in tight-gas-sandstone reservoirs. ks of such age in this region of the Siberian platform was a big surprise since there were no preconditions for the formation of the HC depo

hese fields have been produced for decades much (up to half) of the remaining oil is in the transition zone. Consequently it is a necessity

early half of the worldâ€™s known reserves. Oil industry has progressed tremendously since its inception. Technological development has im

olving multiple objectives and trade-offs are made intuitively by a decision-maker without sophisticated analysis or examination. This style of certain outcome will be achieved. Probability and belief biases are related to how we judge the likelihood that something will happen. This s

ution of reservoir storage and flow properties. In carbonates reservoirs basic petrophysical properties (e.g. porosity absolute permeability processes from well placement to enhanced oil recovery applications. The stratified and interwell heterogeneities dictate fluid movement a pposed to about 2 to 3 feet for conventional tools. It has been shown that further post-processing of FMI image can evaluate physical size o ccessions from Mesozoic to Cenozoic in various depositional setting. The Krishna-Godavari basin is located in the central part of the easte uency of lateral facies changes and difficulty in identifying individual sand packages of channel and overbank deposits with similar geologic eral field examples are presented to illustrate applicability in different environments. Introduction Reservoir-fluid samples collected at the e es in complex reservoirs.ï¿½ At a given location layer or compartment reservoir fluids may change with time; water encroachment second uence the permeability to the extent to which pore throats are plugged with cement or other materialsï¿½ Numerous studies have shown th the possible geometry of the sand body. Using the log interpretation an isochore was prepared as per the evolved morphology of the sand developments of the tool will extend this range. Adjacent to the stabilizer are two diametrically opposed ultrasonic standoff sensors. These presence of dolomite. The results of the formation evaluation studies are presented together with an analysis of the impact on operationa

nduction of the electric logs. Secondly the clay minerals have ability to conduct electricity through ion-exchange reactions.1 The convention ric logs. Secondly the clay minerals have ability to conduct electricity through ion-exchange reactions.1 The conventional interpretation tec d Klovan 1971). Amaefule et al. (1993) describe a more generalized rock typing method based on the Flow Zone Indicator (FZI) that deline r depositional features to understand stratigraphically controlled reservoirs. Dip Analysis done using manually computed orientations of geo m grainstones to mudstones are preserved.ï¿½ In other intervals the depositional texture is highly altered by diagenesis.ï¿½ This is illustrat gly important in Miocene turbidite fans of the North Western Sabah province of Borneo where many wells logs indicate sequences domina

ave broken the topic into three parts. First we discussed the NMR petrophysics in thin sand/shale laminations (Cao Minh and Sundararama

execution and economic aspects of hydraulic fracturing to improve well productivity by limiting the effect of permeability anisotropy in the C bilized and flow with the fluid being sampled. In some circumstances where significant formation solids and sand are mobilized the depositi e logs to help geologists and petrophysicists estimate formation porosities and permeabilities. In the geomechanics domain cores are used wn in Figure 1. The field has been producing since 1958 mostly from Lower to middle Cretaceous carbonate sequences. The upper Cretace

t unswept oils in the reservoir. Introduction Probability and statistical applications have seen significant progress in the last two centuries. B fore the petrophysical and geological logs evaluations should deliver a list of â€œmini-DST depths and achieve the dual objectives of prob ing oil-bearing and gas-bearing respectively. In each case the NMR detection was verified against imaging logs and the fluid type in the s

the quality of the formation evaluation.

ma 2007]. Stress reorientation around vertical wells and around fractured vertical wells have been studied in great detail [Elbel et al 1993; approaches were compared using log inputs.ï¿½ The strengths of each of these approaches are also discussed.ï¿½ sions at three depths in shale and one in highly depleted sand. Analysis of radial profiles in the two orthogonal directions indicates plastic yi

ed mathematically with Eq. 2 and has commonly been used as the basis for correlating the effects of a variable flow rate history on the press

fshore Gulf of Suez Egypt for Arabian Oil Company Ltd (AOC). The well was deviated to a maximum of 58.6 degrees and the logged sec ential of West Siberian basement3. In the next few years a series of medium and small size oilfields with pre-Jurassic reservoirs have been complex structural trends in these zones indicated from seismic and production data. The faults identified on the images were subdivided in next few years a series of medium and small size oilfields with pre-Jurassic reservoirs have been found in the southeastern part of the bas

o drilling fluid invasion.ï¿½ Some mechanisms that can cause damage due to OBM invasion are: i. Emulsion blocking â€“ emulsions may fo

opment of secondary porosity for fissures and fractures taking place during the characteristic tectonics of this region. The lithology of these D beneficial to formation tester sampling and pretesting operations in reservoirs with complex fluids distributions. Introduction Traditionally re

lower (i.e. a financial cost) or both. The definitions of â€œacceptable data quality or â€œreasonable logging speeds are not universal. NM build and test a borehole NMR logging tool that would overcome the limitations of the NML tools. The Los Alamos experimental tool used s

nd water shutoff have to be conducted via either a coil tubing unit (CTU) or tractors. CTUâ€™s limitation is that it canâ€™t reach far. Tracto

anent inflow of reservoir fluids during UBD and possibly an outflow of drilling mud into the formation because of countercurrent imbibition ( manian-Turonian (Upper Cretaceous) age developed over an asymmetrical anticline dipping from east to west the top of the formation was

This paper includes examples in which we integrate pressure gradient PVT mud-gas geochemical and downhole fluid analyses with availa entify compartments.4 Acquisition of representative reservoir fluid samples is essential at the early stages of exploration. Ideally fluids wou hematically with Eq. 2 and has commonly been used as the basis for correlating the effects of a variable flow rate history on the pressure tr ure is a northward dipping fault-block bounded by a major fault to the south. Internal fault compartments are common throughout the field a y high over-balance; commonly in excess of 6000 psi and occasionally up to 10000 psi differential pressure. The shale quantity and thin-be

dge on stress magnitude along the wellbore affects stimulation design and achieving optimum hydraulic fracture placement. Stress direction at of the supercharged zone. Therefore any interpretation of the data must take this effect into account. It is possible to account for superc ects: minimizing uncertainty followed by estimating risks from remaining uncertainty. Minimizing uncertainty reduces the risks and improves most oil or gas field developments.ï¿½ï¿½ï¿½ In cases where the reservoir structure is reasonably simple geological geophysical and pe economics due to improved recovery and production of heavy crude from shallow reservoirs through ESPs and re-allocation of currently co 0 psi. The approach and methodologies developed for this project can be used to give new life to mature oil provinces around the world. In of field surveillance practice and rigorous gas lift optimization workflow can improve the efficiency of production operations. Introduction Th of several offshore fields. nnel sand depositional system. cated in the Permian Basin in Crane County Texas. It started production in the early 1930â€™s and covers more than 1400 active wells in with different properties and characteristics including Areal and vertical extent of the individual reservoirs Hydrocarbon type and propertie ovide a stable front advancement of aquifer and gas cap maximizing oil recovery before breakthrough of a secondary fluid at the wells. Pro he depths vary from 15000 and 17000 ft initial pressure of 7500 psi net thickness from 400 to 500 ft porosity from 10 to 15% and effective nality is basically independent of the simulatorsâ€™ brand the details of the physics being modeled and the mathematical approaches utili l tests and production logs are performed to gain a better understanding of well characteristics and behavior. This information is used to ide ienced high recovery efficiency while in others the recovery has remained relatively low. One objective of a recent field redevelopment plan -72% of worldâ€™s production1. The Betty field was discovered in 1968 by the Betty-1 well 40km offshore from Lutong in the Baram Delta

n the reservoir model) to the well models (conditions at sandface). In the well model the information about the conditions at the coupling po to serve as a road map for the development and adoption of the IAM into the culture of Oil & Gas Operating Companies. Years from now n ervoir production operations and surface facilities). However the analysis and decisions made by those departments are generally made i eve consistency between all the different disciplines involved in the study.ï¿½ In deterministic based workflow the static model is the compr cked reservoirs producing from the XH formation of mid-Miocene age. The low GOR oil varies from 26ï¿½ to 40ï¿½ API saturating usually

leted with gas lift injection system. Even though many remaining gas lift wells are still producing naturally with lower rate some others are c ome cases the traps are also associated with sand layer pinch-outs. The reasons for drilling horizontal wells are predominantly based on th ecision-making has resulted in the placement of more effective fracture treatments in an operationally efficient manner. The results of thes ss than 100 wells. It needs to be pointed out here that any analysis results presented in this paper do not represent the results from the rea n not initially known. The first is knowledge of how the field has performed up to the time of the measurement (passive learning) and the sec

ages indicate how the borehole trajectory is positioned relative to the reservoir structure whether the BHA is drilling up or down structure3. a field (Figure 2). This oil effect anomaly suggested hydrocarbons were present within the Paleocene channel sands that had no structural c e well is being drilled.ï¿½This method has been described in a separate study but that study was limited to the problem of placing a well in cated in U.S. Federal waters offshore Louisiana in the Gulf of Mexico. The discovery well A1 was drilled into the distal end of a deepwate elds within the economic limits. In brown fields the capital investment of infrastructure are already in place.ï¿½ Reclaiming idling wells by s es. It illustrates the challenges of placing and optimizing production along the horizontal section of the wells and how an efficient control of 9). The first category is generally very efficient requires only a few forward reservoir simulations and increases NPV at each iteration. How

ours the physics of fluid flow and at the same time offers a solution many orders quicker. Analytical solutions are fast and provide a broad u Reudelhuber and Hinds2 Hobson and Mrosovsky3) or decline curve analysis techniques (Johnson and Bollens4 Power and Pishny5 Arp e permeability distribution thus demonstrating the feasibility of our approach for large-scale field applications. Introduction Conditioning ge build a reliable model to be used in predicting the reservoir performance and in proposing the optimum field development plan. Conditionin

arge potentially equal to the number of grid blocks. It is not efficient to search a parameter space that is so large and this has been the ban

ble formulation. The first section describes the mathematical formulation used in simulator solution procedure primary variable selection fl d or mass variable based. The implicit and explicit treatment of different nonlinear terms with respect to different variables. We can have ful y an increasingly important role in increasing the well drainage area and consequently enhancing well production. For many offshore fields

zontal and multi-lateral wells have become increasingly important and represent a growing percentage of production wells. They are used t

seldom distributed uniformly and the break of the concentrated fluid is seldom complete. At the end of a fracture treatment there is norma low effects which cause additional inertial pressure drops were also attributed as causes of possible productivity impairment. However ation. In contrast zones 2 and 3 are classified as tight reservoir thereby restricting hydrocarbon production when commingled at existing dr ed the peculiarities of gas condensate mixtures inflow to well: condensate bank accumulation because of condensate drop-out stripping an ght is directly related to the interfacial slip between bedding planes. The mechanisms of height containment have been studied since the ea number of variables that must be considered in the planning and design process. In order to accurately forecast the post-production rates i

ogs are computed by linear interpolation of the observed percent contributions of each stage. If there is only one production log available it voirs2.ï¿½ The extension of the dimensionless productivity analyses for multiphase flow applications reported in Ref. 2 also verified the rela sign such fracturing jobs and to interpret pressure responses while pumping and after shut-in it seemed obvious at first sight that the so-cal e a fracture with minimum tortuosity (turning smoothly from the plane containing the perforation axes into the Preferred hydraulic Fracture P ausett 1994). On the basis of the â€œuniversal approximation theorem with a sufficient number of hidden nodes multilayer neural networks

ic modeling of this field the history match approach we used to calibrate the model and finally the suggested optimum development plan to al wells is also a common requirement for assessing the efficiency of drilling or completion process cleanup or stimulation process and inje

is to investigate the drive mechanism and parameters of each reservoir unit and their effect on the fluid recovery. Some results of the MB a ost important reservoir engineering tools. Calculations require production/pressure data PVT data and aquifer parameters so that original meters and the absence of impermeable seals between pays hampers the assessment of a pay-based reserves depletion. s (Riley and Firoozabadi 1998; Ghorayeb and Firoozabadi 2000a).The results from these references show the importance of natural convec the following steps: 1. Uncertainty Framing 2. Screening parameters 3. Constraining uncertainty ranges 4. Risk Analysis Following a brief

cheme which guarantees an M-matrix has been sought by various research groups [5 7 12-14]. In this work we propose a new MPFA schem

ion.ï¿½ The mechanism of oil recovery from vugs in a triple porosity system is dependent on the location of the vugs and connections of the ; Hoffman and Caers 2005; Caers 2007). The methodology is presented on a synthetic reservoir application. Introduction The modeling of

the reservoir simulation community mainly focused on the finite difference/finite volume computational schemes. This approach has certain e three phase compressible dual porosity model has been implemented into a streamline simulator [19 16]. That model has been compared eserves are contained in carbonate reservoirs which trend to be more naturally fractured than sandstone reservoirs. To improve recovery fa

hat contrary to a previous claim (Floris 2001) RML gives a reasonable characterization of the uncertainty in predicted performance for the

er one of the mechanisms which contribute to scale formation â€“ that of incompatible brine mixing. This mechanism occurs if the injected w

ethod takes advantages of the knowledge that usually the pressure field may be updated much less frequently than the CFL limitation requ rement is significantly reduced. The developments of streamline method in last decade can be found in a number of papers26 10 12 13. A practices to boost the efficiency of their current operations. Therefore a statistical approach based on the power of emerging computing too

performance. However the noise or the outliers in the pressure data could seriously affect accuracy in ranking of the models and hence th ices multiphase flow wellbore storage cross flow and friction effects. For an example of the multisegment well model being used to repres

Upper and Middle Marrat and Lower Marrat) within the naturally fractured Jurassic carbonate formation. These reservoirs contain multiple fl

was included by Dupuit9 and Forchheimer10 to generalize the flow equation i.e. ï¿½ï¿½ï¿½ ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ d points).ï¿½The answers being sought relate to questions such as: 1) Where are depths of the following contacts? Some use definitions s (as low as ~1200 psi at 11 000 ft in some areas) and to minimize formation damage so that the maximum production could be realized. B hed to a limit that causes unexpected drilling problems resulting in high NPT; the expenditure goes beyond expectation involving multiple si olumes of data and information. Introduction and Context During the past decade the concept of the Smart Field has developed from a

es are consistent for each province. The UK North Sea area at approximately 120 000 square miles is very similar to the ANS area of appr model and results from Thiercelin et al. (1997) as a benchmark for their finite-element model and showed good agreement between the tw

one of the wells. On the basis of this data immediately after the resistivity run a decision was made about which zones had the highest wat safe and environmentally friendly completion system. Several intelligent wells were completed on the Oseberg field with long reach highl an Sandstone Formations. These formations are independent from each other and separated with clear petrophysical signatures. Mauddu se they do not provide enough tractive force to reach the toe of the well.ï¿½ Conventional coiled tubing conveyed logging was also not prac

mplex reservoirs the acquisition of quality formation tester samples is crucial to the reservoir evaluation. In this paper we wish to discuss lea

pressure and pressure gradient as the flood front advances through the wellbore. The changes in fluid gradients will provide an accurate wa n be used to differentiate produced connate water from aquifer- or injection-water breakthrough. Ideally water samples from exploration we lls or â€œreal-time have become commonplace and indicate that we have become increasingly efficient in our acquisition processing and n sandstone formation of West Texas contains significant resources of the tight gas however the existing reservoirs require stimulation by n excessive height growth environment and lead to premature screenouts. Introduction Much of Algeriaâ€™s future oil and gas recovery w

well creating a steam chamber and reducing the viscosity of the bitumen. The bitumen and condensed steam then flow by gravity down into es of flow and flow regimes exhibited in the system. As previously discussed in situations where the outflow velocities are sub-critical the w mes exhibited in the system. As previously discussed in situations where the outflow velocities are sub-critical the wellbore liquids are not c e temperature log faded in importance with the advent of the spinner flowmeter mainly due to the relative ease of spinner log interpretation

of associated gas that evolves from the liquid stream as it flows up the well complicating the determination of oil and water volumes. On p

ompare wells among themselves or with a neighbour asset as it could lead to wrong conclusion .The production reference should be defined of each phase along the horizontal drain which is especially challenging when the water cut is high. From these measurements and the tot dstone interval of the Greater Burgan field and is separated from the Burgan sands (Third Sand Upper Third Sand Middle Third Sand Low Reference 1 and a brief description is presented below: Asphaltenes are high molecular weight aromatic organic substances that are soluble able oil they left behind. This paper will follow a simple flow starting with field general information features summary of the well of scope d ut the objectives vary from offshore deepwater exploration and appraisal wells to old cased-hole and development wells later in the life of a pressures only two options are currently available. One can install an intelligent completion and shut-in each zone periodically to obtain a bu n field (Maxwell et al. 2003) and also may result in surface expansion or subsidence (Davis et al. 2000). Monitoring the microseismic activity of the structure and is being developed by a consortium of oil companies with BP as operator. The main producing formations are the Pere diture to increase by 65% to USD 106 billion in 2008â€“2012 from a total of USD 68 billion during the period 2003â€“2007. Coupled with the

ge that this method does not provide a continuous production rate estimation which is essential for production monitoring and reservoir surv wnhole oil gas and water entry especially with the recent technological advances that significantly augment confident answers. The determ

ction performance and identify wells where this technique could be meaningfully utilized. The current analysis and workflow offers a fairly go related to formation water salinity. Therefore Î£ measurement provides information about salinity of reservoir fluid independent of electrica lity of tool response. The study concluded; 1) cross-well EM resistivity technique is well suited for tracking the water front in the current rese o determine sweep efficiency in the targeted reservoir units while assessing the impact of injected fluids on low permeability subunits and m duction and reserves.) The worldwide production from CBM is dominated by the US production of 1.6 Bcf/year. An estimated 20 000 wells bility. Introduction CBM reservoirs have dual permeability system characterized by low permeability matrix part connected by high permea . With few exceptions almost all Coalbed methane (CBM) completions require some sort of enhancement process to enable optimized eco rnett in the core area ranges from 300 to 500 ft in thickness. Permeabilities range from 0.00007 to 0.0005 md with porosities that range from lso indicates problems initiating fractures.ï¿½ For example the capacity of pumping equipment or the safe pressure rating of the tubulars c y other form of stimulation.ï¿½ The lack of success of more traditional stimulation methods is deemed to be damage toï¿½ the dry under p the first half of the 1990s massive hydraulic fracture treatments averaging 600 000 gallons of crosslinked gelled fluid and 1 400 000 pound w permeability (100â€“600 nano-Darcys) low porosity (2â€“6%) and moderate gas adsorption (gas content 50â€“150 scf/ton). The genera ory to run. As a result SAGD reservoir simulations are typically limited in scope. These limitations result in the use of simpler models that m ontain an orthogonal fracture set called cleats that are oriented perpendicular to the bedding and provide the primary conduit for fluid flow. G ent strategies have evolved to the point where they are consistently exhibiting fracture diversion as evidenced by movement of microseismic ne acidizing the acid-rock reaction chemistry is extremely complex.3 4 Nonetheless the dissolution reactions of sandstone constituents are

apped fluid column then the fluid column will rise in the conduit under the application of the pressure differential. After a certain amount of r and have been recognized as a key enhanced recovery method in the field. Specifics of the geology and development history of the Spory of those data increased the initial reserves forecast for the Manati field making it the largest gas reservoir in the north-northeast Brazilian re ce is repeated multiples times until all the layers are stimulated. Most wells are flowed within 24 hours to remove the treating fluids from the ges with big hole (to minimize sand production). A proper gun system was selected based on the analysis. To improve the wells productivity effort as well as in the discussion presented in this paper concerning the optimization model it has generally been assumed that the wellbo effort as well as in the discussion presented in this paper concerning the optimization model it has generally been assumed that the wellbo reservoir. However interpretation of the production performance of these 16 wells has been compromised by controversy as to whether all

ystem or when bedding planes exhibit anisotropy poor areal displacement efficiency is expected. That is for a given economically accepta evelopments (Yeten et al. 2002; Saleri et al. 2006). Haradh-A12 is the first MRC/ML well to be equipped with SC in Ghawar field. It was dril

sed to bypass a damaged area in the near wellbore region of the formation to increase the flow path and clean the perforations to increase predictions about ESP system performance for well- and field-planning purposes. The structure of this article is as follows: First we outline

ulation results were encouraging. Logistics is a large obstacle at Alpine due to â€œice road only access for fracture stimulation equipment

generates and expels oil into the adjacent carbonate matrix which provides the storage capacity for the oil. Some major and minor fracturin se in oil flow rate. Introduction Initially the technology has been developed as fiber assisted transport system to reduce proppant settling tim

ground Fibers in various forms or compositions have been utilized in the oilfield business for decades whether to promote structural integ ck aids should in theory be critically important in either moderate permeability reservoirs for oil or low permeability reservoirs for gas (tight g te the effect of each parameter. In reality formation layers of different moduli are likely to have different in situ stresses (Teufel and Clark 19 completions continuous multistage hydraulic fracturing of horizontal wells and selection of additives and fluids to maximize hydraulic fract al range from $0.30 to $10/bbl for injection or cavern disposal to $15 to $22/bbl for solidification and burial in a landfill (Puder 2007). Opera g for variability (reservoir heterogeneity). Data was collected to characterize the reservoir by understanding the state of stress and the poss l production rates. Introduction Frac-and-pack was first implemented in Venezuela in the early 1960s 1. Small scale stimulations were perf oint of decreased primary recovery. In Western Siberia where highly conductive Tip Screen Out1 (TSO) treatments and large mesh size (12 s is the challenging Mauddud formation in the Sabriyah field in Northern Kuwait where in the last decade a couple of attempts at drilling ho discovered in the early 1960s and are still on production. The wells are draining mature reservoirs that require a relatively large amount of r the last two decades many developments have enabled accelerated growth in horizontal well applications. Drilling has led the way with cu

n of the first field trial experience and lessons learned during deployment of the completion and implementation of the stimulation treatment

from production history plot (Figure 1).

completion practices and production methodology and stimulation objectives.

then the stimulation treatment is pumped. After the stimulation an isolation plug is typically set via wireline and then the next stage is perfo hey are used with soft rock formations. One of the characteristic examples of these is first of all the disparity between the calculated and ob pends on the bottom hole temperature and desired fluid viscosity. Fluid Breaker The VES fluid can break to water-like viscosity by exposu

sis and matrix porosities ranged from 6 to 20% though the 6 to 8% range is more prevalent.ï¿½ It is generally believed that the lateral shift

altene flocculation onset pressure of 6200 psia for the Magwa oil. This finding suggests the urgent need to implement an appropriate reserv ts.3-6 In addition it was surmised that the concentrated polymer has significant yield stress and its effect on fracture fluid clean-up was mod ton Valley sand is an abundant consolidated sand formation located throughout East Texas North Louisiana and South Arkansas.ï¿½ The

ed microseismic event hypocenters can however be obtained only from the assumed positions of the receivers and the perforations. There

narrow slit will remain when the fracture closes and conductivity will be low while if the fracture surfaces are particularly rough large pathw est well. The main goal of this study was to validate each methodâ€™s effectiveness and to construct a calibrated fracture model for the p ut the geometry of what wascreated.The desired geometry is most often referred to as propped length width and height. Early efforts focus

mationâ€”the openhole logs that are commonly used in the Russian oil field i.e. the spontaneous potential gamma-ray neutron and resist n-Darcy flow is not an issue. In the proppant pack however the high velocity of gas and the presence of liquid means that the apparen

d high temperature gas reservoir underlying the giant Ghawar oil field in the eastern region of Saudi Arabia. This formation is a heterogeneo

Zoback and Zinke 2002). Additionally the relative amount of various failure mechanisms such as fracture dilation also can be extracted thr cture near the wellbore. exposing downhole equipment to a higher risk of mechanical damage by the proppant entrained by the fluid to the the virgin formation). As a result a refracture treatment may initiate a fracture orthogonal to the initial propped fracture. As this orthogonal fr ially stabilize displacement. Introduction In case of pressure differential in fluid surpassing a definite value a fracture could develop in poro ydraulic fracturing using large proppant sizes. Introduction In Western Siberia hydraulic fracturing has evolved from being a method to byp

ress and its effect on fracture fluid clean-up was modeled using a modified reservoir simulator.10 However the existence of yield stress eff voir pressure is approximately 5000 psi. This discovery in Block K was made in August 2002 with production initiated in August 2007. With began trying to restore reservoir pressure and well productivity. In the nineties the production profile of those fields showed a steep decline raulic fracture path.ï¿½ These experiments provide valuable information because the conditions of the experiment such as the applied stre ronments. 7. Allowing nonassociated gas to be produced without recompleting the well. 8. Eliminating interventions for resizing or replacing e literature.6-14 Cased and Perforated (C&P) Completions This technique was applied in deeper reservoirs with relatively high strength UC ntinuous operation. By eliminating cementing requirements natural fractures are undamaged and easily stimulated during pumping operatio inuous operation. By eliminating cementing requirements natural fractures are undamaged and easily stimulated during pumping operation me region TOTAL is also operating Tunu Peciko Bekapai Handil and Sisi-Nubi fields. TOTAL is the major contributor for gas production in ervoir consists of ruddist build-ups that vary laterally into barrier and shelf slope facies3. While matrix porosity is generally high with an ave n was about 4000 BOPD dry oil currently the water cut raised slowly from 1.5% about 24%. Well 2 required well conditioning and performin

overy (Algeroy et al. 1999; Glandt 2005). However considerable challenges remain in the formulation of control strategies to operate the va onsortium formed within the Petroleum Engineering Department at the Colorado School of Mines. The group performs practical research in

es in theseis types of reservoirs. It is widely known that the conventional logs may not be able to detect these thinly bedded reservoirs due t water cut or changes in the artificial lift mechanism used to produce the hydrocarbon. The potential of sand production is dependent on va m face dissolution to dominant wormhole wormhole ramification and eventually a more uniformed dissolution as the ratio of flow rate to rea ndstone formation (Lower Devonian/Gedinian) which is one of the main reservoirs of this field. Field-Î² was discovered in 2002. It is located 2 with inflatable bridge plug and perforating J10.1 with deep penetration gun the well managed to be produced at 22.7 MMSCF/D & stabiliz necting the well with the reservoir by creating a tunnel which goes through the casing cement sheath and the reservoir rock. The main obje ing production from multiple zones drilling through the thin sandstones at deviation and/or drilling with a larger bit size increases the amoun mal perforation for fracturing as described by Behrmann and Nolte (1998): ï¿½ï¿½ï¿½ï¿½An ideal perforation for fracture initiation would on requirements Fig.1 for the producing wells often require 2 inch carrier perforating guns to be run through tubing and shot in 7 inch casing ect inputs of nodal analysis. Introduction Pressure transient testing (PTT) is often used to obtain reservoir properties such as reservoir pre ared to drill pipe Cheaper daily rate compared to perforating with the rig. There are two conventional types of CT perforation methods; ole to adjacent shot exit holes which is also unacceptable. The risk associated with either an overswollen or split gun is extremely high and

terial is believed to contain a â€œcrushed zone of reduced permeability which is detrimental to flow performance [2]. Therefore it has been tion fluid to flow from reservoir to the wellbore. When the perforations are left damaged or plugged inflow will suffer over the life of the well.

e necessary technology and expertise to meet these challenges. In 1998 the appraisal well 4-RJS-477 was drilled and put on an extended

was completed on 10-30-93. Cement was drilled out and well cleaned to 6563' (PBTD). The Unayzah reservoir was perforated with 4-1/2" T

rmation sand production; for very clear reasons which include erosion of downhole surface equipments and the high cost of handling produ

of the oil producer well and subsequent treatment with the proposed clean up fluid. Introduction In an attempt to maximize hydrocarbon p ations in the Greater Plutonio Development. The LPSA data for the main reservoir the Plutonio O73 are shown in Figure 2. The majority of

ate performances the new infilling wells have to be drilled contacting several sand bodies and consequently several shale interlayers (whos covering the screens) pressure increase during the Alpha Wave is negligible although the pressure rise during Beta Wave can be substan

d OBM as the screens are run in hole and during subsequent displacement processes so that the operator can decide whether further con ble) formations which produce oil gas or water. In some situations small quantities of formation sand can be produced with minimal proble rmeable) formations which produce oil gas or water. In some situations small quantities of formation sand can be produced with minimal d failure as observed in the lab. This agreement provided validation of the operatorâ€™s general sand prediction methodology and gave go ure occurred in the reservoir between a horizontal water injector and a horizontal producer some 2130 ft apart. Both wells were completed w ty of cased-hole sand control completions are installed in new wells. The most common method is to install a filtering media i.e. screens an

re discovered during workover operations. At that time the issue was not considered to be a major problem but that changed at the end of al methods provide the above accuracies without needing complex or extensive lab programmes to determine advanced rock mechanics p quite straightforward to detect and identify sanding problem if massive sand is produced to surface. However situation is quite different if it i d on many occasions in the field that initiation of sand production coincides with water breakthough (Veeken et al. 1991; Bruno et al. 1996).

lds. Using image analysis of thin sections the different failure behavior could be linked to petrographical rock properties and a predictive m from the nearby fields has been mixed1. An integrated geomechanics study for the multi-fields was therefore conducted to assess wellbore ids and hence enhance diversion during matrix acidizing treatments. High-viscosity fluids are needed during acid-fracturing treatments to re of the Nierode-Kruk correlation. Introduction Acid fracturing is a well stimulation process in which acid dissolution along the face of the hyd . Background The Permian Basin in West Texas USA is renowned for its prolific carbonate reservoirs. Covering an area in excess of 86 00

ng industry leaders and one of the most experienced operators using this technology in deep high pressure and temperature carbonate ga t to overcome this problem and achieve diversion the injected acid conveyed by coiled tubing was spotted in front of all producing interva id skin value (s~ -4). Background The most important factors contributing to the success or failure of matrix treatments are the correct fl

tandard acid fluid formulations for different reservoir formations and for different wells in the same reservoir can vary widely. Optimization of

ates. The reaction of HCl often needs to be retarded by gelling 1 emulsifying 2 or adding viscoelastic surfactants.3 In addition to the high rea

posited in a marine environment. The variation in the vertical lithology subdivides the reservoir into four distinct flow units or layers A B C a but to also improve the near-wellbore permeability by creating large flow channels (wormholes) with the acid dissolution.ï¿½ The chemistry e fracture conductivity are actively discussed. Adding to the issue is evidence in fracture impairment through poor fracture and wellbore clea o acid depends on the RRT it belongs to. In other words rock samples with similar PSD exhibit similar trends in PVBT.ï¿½ The significance ped fractures or expose more net pay thickness to the wellbore (establishing linear flow into the wellbore) as compared to the well condition even further common problems associated with clay swelling. The negative effects of using higher pH fluids in the Frontier formation in the

started in 1963. The field was discovered in 1964. Exploration work was carried out in 1964 to 1978. Tectonically it is hosted in a salt dome

owever conventional isolation tools and stimulation techniques will not work in this case because the Mauddud formation is usually comple ication creating a perception of unreliability. Determining the confidence which can be placed upon cement log interpretations is an objectiv when the formation fluid does not get produced at the surface. The flow period is the one when the downhole valve X is open and the wellh ploit this tight reservoir.ï¿½ This paper discusses challenges encountered during testing and analysis of the first horizontal well drilled in the al completion and operating condition scenarios that can be applied to a well to achieve maximum productivity. The objective is to significant ng technique introduce a workflow for the analysis and then will discuss the results of the analyses for two examples from GNPOC. Based he analytical solution was obtained by combining the partially penetrating well model in a homogeneous reservoir with the pseudo-steady mo standard definition in the petroleum literature. For instance it is defined at http://www.glossary.oilfield.slb.com/ as the calculated maximum n up to 300%.ï¿½ To make proactive decisions and act on the recommendations generated from these production enhancement opportunit ution techniques have been applied to well-test pressure and rate data as a means to obtain the constant-rate behavior of the system (Hutc production during simulation.

estimate parameters required to provide deliverability estimates. The turbulent or non-Darcy flow effects close to the wellbore which appea 20 years. Today after 36 years and a cumulative production of 510 MMstbo oil is still being produced and will continue to be for many yea of the reservoir performance is discussed. Introduction Recent advances in the wet gas multiphase well testing have recently enabled the

elates gas and liquid flows to a pseudo-gas flow rate" calculated from the standard single-phase equations. This addresses the need for gas quirements for successful well tests are reviewed. The importance of well testing experience and multiphase flow metering expertise is high

conditions the different flowrates; therefore it is necessary to associate two other measurements for PVT Conversion from line to standard c sponses. A â€œgeo-skin concept was developed from these data to be used in a full-field model. He and Chambers6 presented a methodol

actice is to use centuries-old analytical techniques developed by Newton and Stirling for interpolating digitally sampled data. When viewed ted with oriented perforations so as not to damage the electrodes and the connecting cables. After perforation electrical current leaked thro

imeframe for CO2 geological sequestration wells (1 000â€™s to 10 000 years). This is because competent cement although reactive if exp ciated with CO2 injection . The initial state of stress is amongst the key parameters controlling the stress perturbation a rock mass can sust

-related sources transported and final storage in a proper location. There are two important scenarios for storing CO2 emissions namely t 35ï¿½C) the density and viscosity of CO2 increases by a factor greater than 2 while for methane the change is of the order of a few perc the near surface to below the storage reservoir is mandatory. Another prerequisite for a successful operating storage project is the detailed d global warming from the buildup of greenhouse gases in the atmosphere. This warming occurs when the added greenhouse gases trap m f CO2 from industrial and energy-related sources transport and injection into the subsurface for long term sequestration purposes is a via

nstallation. (Figure 4 5 6) Low friction factors in relation to torque were experienced by the use of an optimum well profile. Good hole cle oint a total of 15.3 mmstb oil was produced. In 1995 there was a planned Phase 2 development consisting of replacing the two producers w

h the 1960â€™s a number of publications addressed the regional stratigraphy and paleogeography of the Silurian in the Michigan and Illino tone and anhydrite being the most common sealing rocks. Carbon dioxide occurs naturally as a result of geologic processes in large often set pipe or complete a particular zone usually is made once the logging run is complete.ï¿½During the standard logging run the analyst w ed to investigate the potential of this technology in different reservoirs.ï¿½Sensitivity analysis was also done to evaluate the effect of fluid t in place has been mapped but to date limited areas have been developed. Because of the nature of oil contained in these accumulations o implement a line-drive waterflood with horizontal wells in those layers considered to be sparsely fractured. Because GOGD is not effective

allized and resulting in the formation of individual micro fractures and misco-vugs in granitoid rocks. These micro-pore types can be only be multiple oil producer zones revealed the necessity of a complex zonal isolation solution before performing the water shut-off treatment. An o d off. For intervals behind the sleeve as in the case of Field X ascertaining the TOC is technically impossible because the perforations are b

n of the Boscan field. Since its discovery by the Richmond Exploration Company in 1947 the Boscan field has had over 800 wells drilled w must be carefully designed to reduce the chance of cement slumping. Coiled Tubing Forces were simulated in order to determine if CT can

emoval through exposure to turbulent flow. However these intensive operations require a high degree of Health and Safety Executive (HSE portation of oil and water during the later years of production. When heterogeneous fluids are flowing together they are characterized by th ities and well defined interface. On the other hand fully dispersed flow can be modeled as a single-phase flow provided that the dispersion rt or entirely a completion.ï¿½More sophistication offers a surface-controlled flow control valve that can restrain the inflow from the comple e departments are generally made independently rather than using a common approach. Thus most of the decisions have a limited influen on results revealed that the downhole commingling with gas condensate is expected to significantly intensify the asphaltene precipitation co r the prediction of these properties is often very difficult. The difficulty arises from the fact that heavy wax components of the crude oil are n eening. Therefore it is imperative that representative and high quality formation fluid samples are collected early in any exploration or appra les for continuous analysis of fluids in the WFT flowline. The first generation of DFA tools had a visible and near-infrared absorption spectro

as 75% during the primary production of a gas condensate. This reduction must be taken into account in the prediction of ultimate recoverie onventional black-oil simulation and the MBO simulation (also called Extended Black-Oil) lies in the treatment of the liquid in the gas phase velopment one of the biggest impediments to unraveling fluid complexities in the reservoir is to obtain sufficient data. The new technology o ment secondary gas cap formation/gas cap expansion reservoir re-pressurization are some of the reasons of changing fluid characteristics on and fluid spatial & temporal variations are two primary factors that cause major and expensive difference between predicted and actual p

modeling has been shown to give essentially the same results as empirical observations. The agreement between our model and common a specific tool. Currently DFA relies on near-infrared spectroscopy (NIR) and new novel approaches. The details of NIR application for DFA

ctive aquifer water moves in heteregenous systems formation pressure profiles can be more complicated. Evaluation of saturations/remaini surface hydrocarbon reservoirs has a profound impact on completion design and on project economics in general. The need for accurate de

t flux can potentially prevent attaining true equilibrium in a hydrocarbon column because of the temperature gradient in a reservoir (Pederse crease in successively deeper reservoirs. If on the other hand the charge entering the trap is denser than the existing hydrocarbon column neutron porosity logs will start crossing over each other. A very large density and neutron porosity log crossover together with high value of r arges and leaky seals. Because it is difficult to predict the existence of fluid gradients a priori it is prudent to determine the magnitude of th ity potentially leads to some new applications and interpretation techniques for formation pressure data. These new applications could inclu analysis measurements through optical spectroscopy refractometry and fluorescence have shown how to reveal non homogeneous fluid d al fluid analyzer tool. This technique significantly improves real-time contamination monitoring and GOR prediction results for dark oils. Intr

nsities calculated from the multiple sources of information pressure and fluids are compared to direct actual measurements. The reservoir a have three important features. First hydrocarbons have a characteristic mode around 1700 nm that is measured to estimate fluid compos rupt changes due to structural or stratigraphic compartmentalization. DFA. DFA techniques including contamination monitoring compositio

nd all water will exist in a vapor phase.ï¿½ If sufficient heat is added to a liquid water and oil mixture it will also boil and at first three phase ncreases and causes emulsion in a well. Introduction As an oilfield ages the rate of water production increases. With enough shear force

process control and production facilities. Later during the exploitation of the reserves it is necessary to understand fluid behavior during th mp and the bottle had to be enough to fill at least one bottle. This was achieved by adding extra sample chambers in the string which served r and sampling techniques. A generic software solution to address the needs of our customers has been proposed from Heavy Oil to Conde learnt captures the best practices of the methodology to ensure optimized utilization of the technique. The paper focuses on the sampling y and sludging tendencies when the acid contacts asphaltic crude oils. In addition concentrated HCl-based acids are very corrosive to well imited surface pressure is necessary to maintain the operational and economical advantages. These parameters are disrupted with the evo icantly.ï¿½ Carbonate formations are generally fully acid-soluble; as such the chemistry of the acids used for carbonate stimulation is large buildup is still experienced in some parts of the world due to rapid salt deposition. Although salt deposition is generally easier to remove tha

uthorsâ€™ flow laboratory in Rosharon Texas (Bakker et al. 2003). In a perforation flow experiment the permeability of a cylindrical rock co oon of a perforation immediately after it is created.ï¿½ The perforation tunnel is filled with a loosely packed debris of high permeability (1â€ ¿½ï¿½ï¿½ï¿½ï¿½ï¿½Increased mineral concentration; ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½2. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½Changes in tempe of 5 ppm or less. Therefore the scale inhibitors in this study were introduced into the pre-pad of a fracturing job. In a properly executed trea he performance of production tubing and how better access to downhole information can improve the ability to deliver flow assurance. Strontium Sulfate (SrSO4) scale was observed in 1991. Since 1991 there has been an increase in scale related problems such as interfere y Ltd. and when it came on stream in July 1990 it was the deepest hottest and lowest permeability oilfield in the North Sea[1]. Gyda rec general strategy is to start at field level and work down to progressively more detailed matching. A reasonable match is first obtained at the f how injectors and producers are performing and their relationships are crucial in achieving good history match and prediction under waterflo lysis geological model screening or ranking geological model upscaling and in field-level history matching exercisesl. The essential or ma nt Process modeling (DDP) to identify the amount of oil recovery by the ongoing Nitrogen injection using complex sectors that incorporate r ing data into decisions at the right time.ï¿½ Examples of application in offshore assets have been abundantly described in the last five year as been established to determine the pilot performance which includes deep reading technologies like electromagnetic surveys. The main d after the trap was filled with oil. To date the major oil pay intervals in the Sabiriyah field occur between 7 100-8 300 ft. drilling depth and in with an average value of 8.5ï¿½API and viscosities of 2 000 to 5 000 cp at a reservoir temperature of 130ï¿½F. To exploit these extensive enezuela are directing their efforts to develop this kind of unconventional oil reservoirs. ï¿½The technology to produce heavy and extra-hea 1992; 1995) oil shales (El Harfi et al 2000; Chanaa et al 1994) and various organic wastes (Holland 1992; 1995). These materials are in and lengths of the horizontal reach of the wells. The results of this investigation can be used as a reference to optimize the performance of l and complete openhole which will provide maximum reservoir contact and also enable to delay the water production and control the sand ones deposited under arid to semi-arid conditions on a shallow very gently dipping low to moderate energy inner shelf or ramp setting in a r PVT sampling and single probe and vertical observation probe together provided possibility to estimate permeability anisotropy in spite of

e productivity and enhace the reservoir recovery factor operator decided to drill horizontal wells. Another important driving force behind drilli

re produced thermally through huff-and-puff steam injection while the Nukhul formation is cold produced. The primary challenge to comme

ressive to well completions and Avoid undesirable reactions that could result in formation damage. Traditionally hydrofluoric (HF) acid-ba VT fluid samples were acquired. This provided valuable information for future testing appraisal drilling and field development planning. Fur

ssure has been known to impact the sharpness of the gradient. And the presence of nearby conductivity variations (such as the existence o

metallic crosslinker is difficult to achieve (Fig. 1).ï¿½ Ideally the crosslinking could be triggered instantaneously just after the fluid exits the p eatments however the acid is used to etch a created fracture which penetrates deep into the formation. In such treatments the injected ac

k record in the industry. up to 70 degrees angle. There are also 3 horizontal wells. The oil-bearing horizons in the White Tiger field are found in 3 main reservoirs: nly due to loss of workover fluids. Currently various formulations of mud acid organic clay acid and solvents are being used to treat the hen acidizing carbonate formations at high temperatures at which high reaction rates can overwhelm some treatment fluids. For compariso ure structure and formation damage are all aspects that represent a major challange in managing reservoirs in the San Jorge Gulf Basin. T over gas production by evaporation of the liquid. For drawdowns greater than capillary pressure water does not pose a problem.[4 10] Th on for tubing pipeline and process equipment. Scaling potential is critical for the selection of an optimal development strategy to prevent sc

as a result of this among other reasons with a significant upward trend in horizontal versus vertical completions in the past four to five year

ast. By far the largest volumes reside in areas where in the past our focus has been on oil but we need to change our focus now to how to uction rates of neighboring wells. Wells are currently drilled on 10 acre density. Much of the area uses directional drilling from pad wells to re wells in low to mid permeability formations. The operators in Western Siberia in general and in particular Rosneft-Yuganskneftegas use hyd of a simple wing-like hydraulic fracture tends to interact with nearby preexisting natural fractures.6 7 8 9 10 11 12 There are indications of m

Marine field is located 20 km to the north of the Kitina platform and 52km to the west of the city of Pointe Noire. Average water depth is aro day which is more than 20-times as compared to the pre-frac gas rate. The success of this project which is the very first in East Asia is co HST) wells. All wells are on artificial lift with electrical submersible pump (ESP) systems. SF field development has historically focused on t dels constructed based on integration of results from multidisciplinary teams. The models comprise a 3-D geocellular model which captures d in production increases of up to 30% above the previous baseline with significant improvement in well economics.ï¿½ Introduction ï¿½ï¿ ds and siltstones floodplain shales and minor coals that were deposited in a broad alluvial plain. The reservoirs consist of several sand un ated sequences may be found in what are considered marginal reservoir rock even by todayâ€™s standard and higher anticipated natural g

s run in many wells. However in the tighter layers of MRï¿½and particularly in NJ-SR fractures are more important for providing the needed a best operating practice for similar reservoirs will be presented. Introduction The evolution of wireline formation testing technologies inclu y Located about 800 km South-Southeast of the capital Algiers (Figure 1) the Hassi-Messaoud field was discovered in 1956. With an origina kie Basin to the south (Figure 1). The combination of deposition structure and diagenesis control reservoir presence and quality and ultim

provide anchoring on the opposite side. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½b. ï¿½ï¿½ï¿½ï¿½The rubber packer ted. Also the knowledge of maximum in-situ stress orientation allowed creating a geomechanical model for proper well placement. Conseq servoirs. ons for the formation of the HC deposits both in ancient times at that moment of time based upon the concepts of 1970es. As a result of the

one. Consequently it is a necessity to understand what fluids will be produced if the transition zone is swept or if there is movement of the O

n. Technological development has impacted all gamut of activities viz exploration and production in substantial manner. General technologic

nalysis or examination. This style of decision-making relies primarily on various mental simplification techniques by each individual in determ d that something will happen. This set of biases can especially affect cost and price estimates. Social biases are related to how our socializ

e.g. porosity absolute permeability capillary pressure residual oil saturation resistivity and relative permeability) vary significantly horizon rogeneities dictate fluid movement and waterflooding efficiency thus significantly affecting hydrocarbon recovery. This is particularly true in I image can evaluate physical size of the fracture aperture as small as a few hundred micron1. Beside Newberry2 introduced a technique c cated in the central part of the eastern passive continental margin of India. The structural grain of the basin is northeast-southwest. The bas rbank deposits with similar geological characteristics. Only an integrated approach combining data from different sources can help reduce t rvoir-fluid samples collected at the early stage of exploration and development provide vital information for reservoir evaluation and manage h time; water encroachment secondary gas cap formation/gas cap expansion reservoir re-pressurization are some of the reasons of chang ½ Numerous studies have shown that there is no direct relationship between the porosity and the permeability of the carbonate system. To the evolved morphology of the sand and was used for modeling the sub zones. The rock types were modeled geo-statistically to define the ultrasonic standoff sensors. These provide a 16-sector ultrasonic borehole image when the tool is rotating and allow for a caliper measurem analysis of the impact on operational efficiency and environmental and operational safety as a result of not having to use a chemical loggin

xchange reactions.1 The conventional interpretation technique will not give accurate water saturations for the shaly sand formations as it a The conventional interpretation technique will not give accurate water saturations for the shaly sand formations as it assumed that the onl Flow Zone Indicator (FZI) that delineates rock types from poro-perm relationships. Grotsch et al. (1998) have presented a rock typing schem nually computed orientations of geological features from the images provide the attitude of the structural and the depositional framework. In ed by diagenesis.ï¿½ This is illustrated in Fig. 1 which shows the results of core mineralogy analysis core based Dunham classification and ells logs indicate sequences dominated by thinly laminated layers with low resistivity contrast between sand and shale layers.ï¿½ These bed

ations (Cao Minh and Sundararaman 2006).1 Next we presented a graphical method to analyze resistivity anisotropy in thin sand/shale fo

t of permeability anisotropy in the Cambrian reservoirs of Hassi Messaoud field have been studied by many authors. These topics are parti and sand are mobilized the deposition of suspended solids can result in the premature ending of formation testing and sampling jobs or re omechanics domain cores are used primarily for lab tests and image logs are widely used to identify stress directions through the analyses nate sequences. The upper Cretaceous sequence has not been well explored although it produces oil west of the Al-Khafji area onshore in

progress in the last two centuries. Broadly speaking Bayesian statistics was more commonly used in the nineteenth century while frequen d achieve the dual objectives of probing the productivity of thin sands while avoiding tests in zones without flow potential. The petrophysics a ging logs and the fluid type in the sands was determined from multi-dimensional NMR analysis. The derived hydrocarbon volume was then

ied in great detail [Elbel et al 1993; Siebrits et al 1998; Warpinski et al 1990; Zhai et al 2007]. Based on this past work we know that in th discussed.ï¿½ ogonal directions indicates plastic yielding or stiffening of rock in the near-wellbore region. While plastic yielding increases the shear slowne

ariable flow rate history on the pressure transient behavior of a well with the solution for a constant flow rate inner boundary condition. (2)

of 58.6 degrees and the logged section was drilled with an 8.5 inch drill bit. The abundance of natural fracture was expected to contribute b h pre-Jurassic reservoirs have been found in the southeastern part of the basin (e.g. Archinskoe Chkalovskoe Urmanskoe Gerasimovskoe ed on the images were subdivided into major and minor ones depending on their scale and relationship with seismic faults present in the fie d in the southeastern part of the basin (e.g. Archinskoe Chkalovskoe Urmanskoe Gerasimovskoe and others). In all of these fields oil was

ulsion blocking â€“ emulsions may form between the filtrate formation fluids and connate water. ii. Relative permeability effects â€“ most pr

f this region. The lithology of these Devonian formations is characterized mainly by shoreface sediments; quartzitic sandstones litharenites butions. Introduction Traditionally resistivity and nuclear logs are used to estimate porosity Î¦ and water saturation Sw prior to WFT operati

ogging speeds are not universal. NMR logging optimization requires making trade-offs between data value data quality and time. One of us os Alamos experimental tool used strong permanent magnets and performed pulsed-NMR spin-echo measurements like those used in mo

n is that it canâ€™t reach far. Tractors work the best in cased hole or open holes with reservoir rocks of having high compressional stress. F

ecause of countercurrent imbibition (Friedel and Voigt 2004). The inflow rates can be obtained by balancing injected and produced fluids. Th o west the top of the formation was unconformable everywhere. Three main fault patterns were observed defining three structural periods

downhole fluid analyses with available geological and geophysical data for the identification of flow barriers evaluation of connectivity acro es of exploration. Ideally fluids would be analyzed in their existing conditions i.e. in the formation; however a detailed analysis of the fluid in e flow rate history on the pressure transient behavior of a well with the solution for a constant flow rate inner boundary condition. Equation ( s are common throughout the field and are in communication. A roughly north-south trending major fault divides the field into eastern and w sure. The shale quantity and thin-beds very often results in conventional logs giving wrong fluid determination therefore fluid analysis using

fracture placement. Stress direction is also critical for well placement and to achieve optimum drainage in a reservoir exploited with wells s . It is possible to account for supercharging effect through numerical simulation. Such models would need a complex initialization process a inty reduces the risks and improves project economics. Uncertainty can be managed by integrating multi-discipline multi-scale data and util mple geological geophysical and petrophysical interpretations provide a limit to the uncertainty regarding fluids in place fluid contacts and SPs and re-allocation of currently consumed lift gas to other existing wells Introduce a new artificial lift technology to Bokor Field and prove e oil provinces around the world. Introduction The Block 10 (Lote X) of Petrobras Energia Peru S.A. (PESA) is located in the Talara basin oduction operations. Introduction The Bokor field is located in the Baram Delta Sarawak East Malaysia.ï¿½ It was discovered in 1970. Th

vers more than 1400 active wells in an area about 80 000 acres.ï¿½The project includes 47 fields which have produced over 400 million b oirs Hydrocarbon type and properties Reservoir quality and drive mechanism Optimum production and reservoir management strategy O of a secondary fluid at the wells. Production after breakthrough of gas and/or water involves handling and re-circulating (in the case of gas) orosity from 10 to 15% and effective permeability from 50 to 500 md. It represents the most prolific and potential field from Maracaibo Basin d the mathematical approaches utilized in these simulators the usage of independent and unified FM framework provides a new horizon of avior. This information is used to identify problem wells and opportunities for increasing production. Examples include well workovers zonal of a recent field redevelopment planning study was to investigate and resolve these recovery efficiency anomalies and to identify areas wh hore from Lutong in the Baram Delta. A 24-slot drilling platform BEPD-A was installed in 1978 from which 9 development wells were drilled.

out the conditions at the coupling point (sandface) is used as a boundary condition in order to compute the fluid rates or the pressure at the ating Companies. Years from now new graduates to the industry will have IAM training as part of their Oil & Gas company inductions and e departments are generally made independently rather than using a common approach. Thus most of the decisions have a limited influen kflow the static model is the compromise between geophysical petrophysical sedimentological geological and engineering modeling.ï¿½ ¿½ to 40ï¿½ API saturating usually unconsolidated sandstones with average porosity of 25% and permeability measured in the Darcy plus

ly with lower rate some others are currently being shut in. Thus the most effective wells for gas lift operation were defined by performing lo wells are predominantly based on the following two considerations: Firstly after over 15 years of high rate oil production these fields have g efficient manner. The results of these efforts yielded the highest producing well in the fieldâ€™s history in an area of known depletion; the ot represent the results from the real study. These are strictly for demonstrating the workflow process. Introduction The Lower Vicksburg sa ement (passive learning) and the second is the information gained from the measurement itself (active learning). In this paper we develop

HA is drilling up or down structure3. This azimuthal measurement sensitivity although strong is reading shallow (several inches only). Tradit annel sands that had no structural closure and therefore suggested stratigraphic trapping conditions1. In 2002 Oilexco North Sea Limited d to the problem of placing a well in a dedicated drainage area.ï¿½The current study describes the methodology of sequential well placeme ed into the distal end of a deepwater turbidite fan. The turbidite mass transport phenomenon provided for the elimination of fines leaving a ace.ï¿½ Reclaiming idling wells by sidetrackingï¿½ is an attractive investment option which also allows the application of new technology in wells and how an efficient control of completion and depletion levels is used to optimize and accelerate oil production in an aging oil rim field creases NPV at each iteration. However these methods can get stuck in a local optimal solution. The second category can in theory avoid

tions are fast and provide a broad understanding of the reservoir dynamics. The equations applicable to laminar flow of fluids in a porous d Bollens4 Power and Pishny5 Arps6). While such approaches require very lightweight workflows and can be extremely useful they are ba ations. Introduction Conditioning geological models to production data typically requires the solution of an inverse problem. Such inverse p field development plan. Conditioning the geological or the static model to production data is typically known as â€œHistory Matching which

s so large and this has been the bane of traditional methods of history matching. Further the history matched model must not only reprodu

cedure primary variable selection fluid property calculation and heat loss model. The second section presents comparison of simulation re different variables. We can have fully implicit formulation (FULLIMP) implicit pressure and explicit saturation and mole fraction formulation production. For many offshore fields highly deviated or horizontal wells are absolutely necessary to drain large areas from a limited numbe

of production wells. They are used to maximize well to reservoir contact and to improve oil recovery in a cost efficient manner. This is espec

a fracture treatment there is normally a shut-in period to allow fracture closure during which fluid continues to leak off into the reservoir. Alt productivity impairment. However these effects are not solely responsible for potential productivity impairment in tight-gas reservoirs. Ma tion when commingled at existing drawdown conditions with other more productive layers. Zones 4 and 5 exhibit better rock quality than 2 a of condensate drop-out stripping and non-Darcy effects and etc which canâ€™t be described on the basis of so called â€œblack oil techniq ment have been studied since the early times of hydraulic fracturing research both experimentally and theoretically. It is well known now tha forecast the post-production rates it is essential that they are calculated using a reliable methodology that adequately represents both the

only one production log available it keeps the percent contributions of each stage constant. Spivey2 presents a concise and clear discussio ported in Ref. 2 also verified the relationship between the dimensionless productivity index (expressed in terms of the pressure drawdown b obvious at first sight that the so-called Radial model was the best suited to the case owing to the fracture geometry. Over the past twenty y o the Preferred hydraulic Fracture Plane (PFP)) at an achievable fracture initiation pressure (Economides and Nolte 2000). You may ask ho en nodes multilayer neural networks (Fig. 1) are able to predict any unknown function (Haykin 1999). ANNs are widely used in prediction an

ested optimum development plan to increase its reserves. Introduction South El-Manzala field is one of the fields in the Delta of Egypt. It is nup or stimulation process and injection or recovery process. Injection profile in horizontal wells can be estimated with â€œproduction logg

recovery. Some results of the MB analysis will be aquifer parameters so that original oil in place and drive mechanisms can be quantified. Data quality is an important issue in material balan eserves depletion. ow the importance of natural convection which in some cases overrides diffusion and results in a uniform composition. Natural convection s 4. Risk Analysis Following a brief introduction of the reservoirs the outline of this paper mirrors the above typical steps in an experimenta

work we propose a new MPFA scheme based on local transmissibility upscaling which we call the transmissibility upscaling method (TU-me

n of the vugs and connections of the vugs to the fracture system.ï¿½ These vugs can be connected to the fracture system or be isolated in ation. Introduction The modeling of the density and pattern of fracture distributions can take different approaches depending on the origin a

schemes. This approach has certain limitations for flow simulation at the geo-scale. There are many complicated geological multiwell model 16]. That model has been compared with the results produced by a commercial finite difference simulator and much better scaling with resp e reservoirs. To improve recovery factors it is essential to have a thorough understanding of the depletion and displacement processes. Fra

nty in predicted performance for the PUNQ-S3 problem; our second objective is to compare the quantification of uncertainty obtained with R

mechanism occurs if the injected water contains ions which react with ions in the formation water to precipitate inorganic scale â€“ thus ma

equently than the CFL limitation requires for the transport equation. One specifies at which time instants the pressure equation should be so n a number of papers26 10 12 13. Another point in the calculations is the flash procedure. As a rule such specific procedure uses cubic equ he power of emerging computing tools for data mining can assist YPF to recognize patterns and develop methodologies which are strong en

n ranking of the models and hence the uncertainty assessment. Therefore rather than calculating the objective function based on the full pr ent well model being used to represent ICDs in field case reservoir simulations see Henriksen et al. (2006). A former restriction of the multi

These reservoirs contain multiple fluid types at near critical conditions (both gas-condensate and volatile oil) with average temperature pre

¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ ing contacts? Some use definitions borrowed from Desbrandes and Gualdron[1]. Free Water Level FWL (location where there is zero cap mum production could be realized. Between 2006 and 2007 an 11-well coiled-tubing (CTD) underbalanced drilling (UBD) campaign was ini ond expectation involving multiple side tracks or abandonment of the well in worst case. In all the brown fields those are now being develop Smart Field has developed from a twinkle in the eye of the visionaries in our industry to a position where several operators notably BP C

very similar to the ANS area of approximately 130 000 square miles. Alaska North Slope The Alaska North Slope (ANS) petroleum provin ed good agreement between the two models. Formation creep which can potentially induce large strains in the cement sheath was also di

out which zones had the highest water saturation and needed to be isolated. This was done by setting a bridge plug. The same rig was used Oseberg field with long reach highly deviated wells having flow control of two to three zones with hydraulic flow control valves. Norsk Hydro r petrophysical signatures. Mauddud Formation containing no natural pressure support has a production history of more than 40 years. Th conveyed logging was also not practical because of the friction produced in the long-reach wells.ï¿½ This left two possibilities: coiled tubing

In this paper we wish to discuss learnings from previous attempts in the same area the subsequent recommendations that were made and

radients will provide an accurate water arrival time that could be utilized in analytical calculations and to enhance reservoir modeling efforts. water samples from exploration wells should consist of representative uncontaminated formation water which can be difficult and costly to nt in our acquisition processing and interpretation of raw data from field measurements to usable reservoir properties that will be analyzed n ng reservoirs require stimulation by hydraulic fracturing to be produced economically. Due to a complex geological history and low permeab aâ€™s future oil and gas recovery will depend on its ability to effectively use fracture technology to improve the production (eliminate skin) o

steam then flow by gravity down into the producer well that is located 5 m below the injector from which they are pumped to the surface. T tflow velocities are sub-critical the wellbore liquids are not continuously and uniformly transported up the wellbore to the surface.ï¿½ Turner -critical the wellbore liquids are not continuously and uniformly transported up the wellbore to the surface. Turner et al3 identified that there ve ease of spinner log interpretation. One of the major historical problems with temperature log interpretation has been the length of time fo

ation of oil and water volumes. On platforms servicing many wells there may not be enough room to install a meter on each well thus preve

duction reference should be defined well by well taking into account its own constraints or limitations. However production can also be limit om these measurements and the total flow area the oil and water inflow profiles can be calculated. Density measuring gradiomanometers an Third Sand Middle Third Sand Lower and Fourth Sand) by tight limestone Mauddud reservoir. Any fluid communication between the Wara organic substances that are soluble in toluene but are precipitated by alkanes (n-heptane/n-pentane). Generally asphaltenes tend to rema ures summary of the well of scope definition of the production optimization challenge and explanation of the intervention of modern techno evelopment wells later in the life of a field. Given the wide range of applications and combinations each WFT evaluation program is unique. each zone periodically to obtain a buildup pressure which can be costly and results in loss of production during the shut-in. Alternatively one Monitoring the microseismic activity and surface deformation with sensitive seismometers and precise tiltmeters respectively could allow n producing formations are the Pereriv units B C and D which consist of laterally continuous layers of sandstones with excellent intrafield c riod 2003â€“2007. Coupled with the increase in expenditure they forecast a total of 2 408 subsea wells to be installed in the period 2008â€

uction monitoring and reservoir surveillance in real-time. Unfortunately this methodology only sees one side of the process from the sales ment confident answers. The determination of the water entry locations then provides a target for a water shut-off program with the objective

nalysis and workflow offers a fairly good understanding about the reservoirâ€™s production scenario monitoring and future actions for enha servoir fluid independent of electrical resistivity logs and rock cementation factor. ng the water front in the current reservoir conditions 2) the injected fluids create enough resistivity contrast to be easily picked up by the tec on low permeability subunits and monitoring pressure support due to pattern injection. Uneven sweep bypassed oil and residual oil satura Bcf/year. An estimated 20 000 wells are in production from CBM reservoirs. Wyomingâ€™s Powder River Basin has 12 000 wells in product atrix part connected by high permeability orthogonal and sub vertical fractures (with respect to bedding) called cleats. The extended contin ent process to enable optimized economic production. This is partly because of the gas release profile that requires exposure to a much low 05 md with porosities that range from 3 to 5%. The Barnett shale is believed to be its own source rock and is abnormally pressured in this a safe pressure rating of the tubulars can be reached prior to fracturing.ï¿½ Moreover even if or when fracture initiation occurs the treating p o be damage toï¿½ the dry under pressured coal seams. ked gelled fluid and 1 400 000 pounds of sand were the norm. While improving the EUR to approximately 1 Bcf in Denton and Wise Countie ntent 50â€“150 scf/ton). The general Barnett Shale reservoir deposition settings lithofacies natural fracture characterization and production in the use of simpler models that may not represent the true effects of a full pad with multiple well pairs. The combination of these factors i e the primary conduit for fluid flow. Gas diffuses from the matrix into the cleats and flows to the wellbore. In shale-gas reservoirs gas is som enced by movement of microseismic activity and improved lateral coverage. While this engineered fracture diversion technique is ideally su ctions of sandstone constituents are slow and generally considered surface limited they are not affected by the acid injection rate. The mat

ferential. After a certain amount of rise the column is again trapped and the differential is now transferred across it. This causes further rise nd development history of the Sporyshevskoye field The Sporyshevskoye field is a multiple reservoir field comprising 26 stacked pays whic oir in the north-northeast Brazilian region. remove the treating fluids from the reservoir. Operators seek to balance the quality and the cost of the stimulations vs. potential well produ is. To improve the wells productivity deeper penetration and high shot density guns were selected as a perforating method to pass the rad erally been assumed that the wellbore and the flow path under consideration relatively vertical.ï¿½ The methodology discussed in this pape erally been assumed that the wellbore and the flow path under consideration relatively vertical.ï¿½ The methodology discussed in this pape ed by controversy as to whether all of these wells were placed entirely within Mauddud or not.ï¿½ Reference 1 contains more details about

is for a given economically acceptable water cut in the production wells large areas of the reservoir are left with high oil saturation. This m d with SC in Ghawar field. It was drilled and completed as a trilateral selective producer with a surface-controlled variable multipositional hyd

d clean the perforations to increase production. This technique must be implemented after performing corresponding laboratory tests. One o rticle is as follows: First we outline the problems and inconsistencies inherent with existing (non-SA) analysis approaches to ESP perform

s for fracture stimulation equipment and diesel transport to location. These logistic issues along with the increasing diesel fuel costs led the

e oil. Some major and minor fracturing has occurred which can be additional conduits and storage for the generated oil. Fig. 2 shows the pr ystem to reduce proppant settling time in low viscosity fluids1-3. Tight gas formations in North America were the prime target application for

whether to promote structural integrity of a cement system and more recently to combat lost circulation issues and to prevent proppant flo ermeability reservoirs for gas (tight gas or shale). It is conceptually intuitive to argue that reducing the capillary pressure of the fluid in the ne in situ stresses (Teufel and Clark 1984) and the contributions of both must be considered together. With the development of tiltmeter and m nd fluids to maximize hydraulic fracture effective length and conductivity are but a few employed. Other cost-control measures include reduc ial in a landfill (Puder 2007). Operators in the United States have reported that disposal and treatment costs for their produced water excee ding the state of stress and the possible production mechanism (natural fractures or matrix flow).ï¿½ Ideal completions (single stage single 1. Small scale stimulations were performed using crude oil as fracturing fluid with gravel sized to control production of formation sand. Ball s ) treatments and large mesh size (12/18 mesh and larger) Intermediate Strength Proppants (ISP) are regularly pumped fracture height grow e a couple of attempts at drilling horizontal oil producer were mostly unsuccessful and showed very disappointing production figures with h t require a relatively large amount of intervention work such as matrix acidizing water control scale removal and sand consolidation to ma ons. Drilling has led the way with current technology capable of drilling thousands of feet laterally through a hydrocarbon reservoir. Drilling

entation of the stimulation treatment and the post stimulation results. Suggested optimization steps from this successful experience are dis

ine and then the next stage is perforated or jetted. This method of treating multiple production intervals at the same time can result in les parity between the calculated and observed moments of tip screen-out (TSO). Consequently TSO may start either earlier or later than expe eak to water-like viscosity by exposure to liquid hydrocarbons or dilution with reservoir brines.ï¿½Additionally a new encapsulated breake

nerally believed that the lateral shifting of the depositional environment in the Morrow formations of SENM over time has resulted in a comp

to implement an appropriate reservoir management strategy to conserve reservoir energy and to maintain the formation pressure much hig ct on fracture fluid clean-up was modeled using a modified reservoir simulator.7 8 The production simulation indicated clearly that yield stres iana and South Arkansas.ï¿½ The Cotton Valley sand was formed during the late Jurassic period.1ï¿½ The depositional environment was

eceivers and the perforations. Therefore any error in the positioning of the monitoring array or of the perforations is directly projected into e

es are particularly rough large pathways throughout the fracture will be propped open by the large surface asperities and conductivity will be a calibrated fracture model for the particular reservoir under investigation. The results of this investigation will be used to optimize fracture d width and height. Early efforts focused on logging temperature profiles after a frac job. This technique was based on the â€œcooling effect

tial gamma-ray neutron and resistivity and information from common well testing. In most cases these were the only data available in an ce of liquid means that the apparent permeability of the proppant is a function of gas velocity and ratio of free liquid rate to gas rate. Thes

bia. This formation is a heterogeneous reservoir consisting of dolomite and limestone with streaks of anhydrite shale or non-permeable inte

re dilation also can be extracted through-processing technique known as moment-tensor inversion (Gibowicz and Kijko 1994). Most hydrau roppant entrained by the fluid to the wellbore. opped fracture. As this orthogonal fracture propagates away from the initial fracture the production induced stress change diminishes and t lue a fracture could develop in porous medium and start its propagation due to increased fluid flow. This is the so-called hydraulically drive evolved from being a method to bypass skin caused by wellbore damage to becoming a full reservoir management tool. It was only recent

ver the existence of yield stress effect remained controversial.ï¿½ï¿½ This publication presents the early JIP effort that focused on the p ction initiated in August 2007. With recoverable reserves in excess of 400 million barrels of oil it is expected to achieve a plateau productio those fields showed a steep decline and reservoir pressure presented a significant depletion. In 1993 PETROBRAS started a strategic IOR experiment such as the applied stress and sample material properties are better controlled than for field experiments. In addition the entir nterventions for resizing or replacing conventional gas lift equipment. 9. Providing the ability to control gas and water coning (Betancourt et a voirs with relatively high strength UCS in the range of 1 600 to 2 000 psi. A total of ten C&P completions were performed in high rate gas we stimulated during pumping operations. Introduction Over the last two decades many developments have enabled an accelerated growth in stimulated during pumping operations. Introduction Over the last two decades many developments have enabled an accelerated growth in ajor contributor for gas production in the region. Fig. 1 shows a map of the different fields location. The Tambora field produces from a serie orosity is generally high with an average of 25% and does not vary laterally; permeability is facies-dependent and exhibits spatial variability uired well conditioning and performing as expected. The key advantage of using ICD is that it balances the flow across the entire horizontal

f control strategies to operate the valves during production particularly when there is uncertainty associated with the reservoir description. group performs practical research in all areas of oil and gas well stimulation. In the pursuit of enhancing our understanding of fracture heigh

hese thinly bedded reservoirs due to their limited insufficient vertical resolution. Therefore new technology logging services such as tri-axia sand production is dependent on various factors including in-situ stresses pore pressure formation properties depletion water-cut etc. If t lution as the ratio of flow rate to reaction rate increases5. Rock dissolution patterns generated by reactive fluid injection are controlled not o was discovered in 2002. It is located in the western sector of block 403 at a distance of 25 km west from Field-Î±. In this area the Tadrart fo roduced at 22.7 MMSCF/D & stabilized at 48 MMCSF/D (23 % choke size) with total gain of 41MMSCF/D which was higher than the expect nd the reservoir rock. The main objective of perforating is to create a clean tunnel sufficiently long that it reaches the undamaged reservoir. a larger bit size increases the amount of pay zone in contact with the wellbore and thus improves the potential productivity per well. Well pr foration for fracture initiation would have a minimum injection pressure initiate only a single fracture (either a dominant single or bi-wing) a ugh tubing and shot in 7 inch casing in a static underbalance environment around 1000 psi. In many cases after perforating with this metho voir properties such as reservoir pressure formation transmissibility and skin factor. These dynamic properties are very important to estim types of CT perforation methods; Wired CT in which an electric cable will be injected into the CT reel. Standard CT in which a pressure en or split gun is extremely high and should be avoided during perforating job planning and system development. A validated analytical mod

rformance [2]. Therefore it has been an ongoing goal of perforating charge / system design to either prevent this crushed zone from being c w will suffer over the life of the well. The quality of the perforation job design and execution is a major consideration in any completion progr

was drilled and put on an extended well test (EWT). The well was completed with a cased hole gravel pack (CHGP) and the oil production

servoir was perforated with 4-1/2" TCP Guns selectively from 6264' to 6392'. The well was completed with a new ESP with bypass assemb

s and the high cost of handling produced sand.

attempt to maximize hydrocarbon productivity and minimize formation drawdown Horizontal Open Hole Gravel Packing method has been a e shown in Figure 2. The majority of the sands are well sorted with low fines content. There are however some poorly sorted sands with hig

ently several shale interlayers (whose thickness is in the range of 0.5-3.0 m). It is well known that in the presence of shale however the Op se during Beta Wave can be substantial. This is because of the narrow annulus between the screen base pipe and the wash pipe through w

rator can decide whether further conditioning and thus the additional rig time is worth the associated cost. Introduction A significant po can be produced with minimal problems; however in most cases sand production leads to reduced productivity and/or excessive maintene sand can be produced with minimal problems; however in most cases sand production leads to reduced productivity and/or excessive main prediction methodology and gave good confidence in the earlier rock mechanical predictions made for the field. Introduction A rock mecha t apart. Both wells were completed with un-cemented pre-perforated liners. A comprehensive investigation by McDiarmid et al2 led to a conc stall a filtering media i.e. screens and sized gravel or proppant to exclude formation sand and fines from entering the wellbore. Depending

lem but that changed at the end of the 1980s when ESPs were introduced across the field. Some of these ESPs which were installed to su termine advanced rock mechanics properties. The application of this approach to the Messla field and a later comparison of the results to wever situation is quite different if it is not the case. Since it first went on to production in the year 1969 the field has been reported to have ken et al. 1991; Bruno et al. 1996). But on other occasions it has been observed that both events do not relate to each other and sand pro

l rock properties and a predictive model of sandstone failure characteristics was developed. This paper describes the development of the refore conducted to assess wellbore stability and sand production potential in the fields. The data required for the study were obtained from uring acid-fracturing treatments to reduce leakoff rate during acid injection into the fracture. Various chemicals were developed to enhance dissolution along the face of the hydraulically induced fracture is expected to create lasting conductivity after fracture closure.ï¿½ However Covering an area in excess of 86 000 square miles the basin is both vast and diverse in reservoir types and qualities. Even within specific a

sure and temperature carbonate gas bearing reservoirs. The company has continued to optimize and innovate from lessons learned and ex otted in front of all producing intervals. Starting late in 2003 a new approach used a viscoelastic diverting acid system to achieve diversion matrix treatments are the correct fluid selection and the optimum zonal coverage. Less emphasis is commonly placed on carbonate versu

voir can vary widely. Optimization of the sandstone acid stimulation fluids may now be done by numerical simulation of chemical reactions.1

rfactants.3 In addition to the high reaction rate HCl is very corrosive to well tubulars. Expensive corrosion inhibitors can protect the tubulars

distinct flow units or layers A B C and D in ascending order Fig. 2. acid dissolution.ï¿½ The chemistry of carbonate acidizing is much more straight forward than sandstone acidizing.ï¿½ The simplicity results ough poor fracture and wellbore clean-up and post frac workover operation.ï¿½ Efficient well flowback and underbalanced clean-up with co rends in PVBT.ï¿½ The significance of the results to the design of matrix treatments in carbonate reservoirs is discussed. Introduction Car e) as compared to the well conditions that exist prior to restimulation. In light of the above two key important aspects of any restimulation p luids in the Frontier formation in the Big Horn Basin can be found in references such as SPE paper by Lehman et al. Case studies of two w

ectonically it is hosted in a salt dome structure. Nine horizons have been delineated: VIII1 (gas-condensate) VIII2 and VIII3 (gas-oil) and V

auddud formation is usually completed in the short string. It is quite challenging to isolate the water intervals and place the stimulation fluids ment log interpretations is an objective of this task force. Behind casing communication of hydrocarbons via the cemented annular space m wnhole valve X is open and the wellhead valve Y is closed. This flow period resembles a perforation inflow test. In contrast the buildup perio the first horizontal well drilled in the 2005 program. The first Mauddud horizontal ï¿½well of the 2005 program is a 2 270 ft long horizontal w uctivity. The objective is to significantly increase the productivity of the well to maximize the financial performance of multi-fractured wells. F two examples from GNPOC. Based on the success of these cases multi-layer transient testing is estabilished as a preferred testing techniq reservoir with the pseudo-steady model for a naturally fractured reservoir. The interpretation of pressure tests in both systems i.e. fracture b.com/ as the calculated maximum radius in a formation in which pressure has been affected during the flow period of a transient well test. production enhancement opportunities is still a challenge that needs to be addressed. For fields with large numbers of ESP wells a time s nt-rate behavior of the system (Hutchinson and Sikora 1959; Coats et al. 1964; Jargon and van Poollen 1965; Kuchuk et al. 1990; Thompso

s close to the wellbore which appear as rate-dependent or non-Darcy skin requires gas wells to be tested at a number of rates with the abo and will continue to be for many years to come (Fig. 1). In order to achieve such a result extensive continuous efforts have been deploye ell testing have recently enabled the measurement in the field of reliable rates of gas condensate and water in gas and condensate wells. T

ns. This addresses the need for gas measurement in the presence of liquids and can be applied to a limit of liquid flow [or gas volume fract hase flow metering expertise is highlighted. The paper also explains the unique benefits of the multiphase well test data in identifying and e

T Conversion from line to standard conditions (i.e. Pressure and Temperature Sensors). The most common technique used in the industry d Chambers6 presented a methodology to verify and update geostatistically-based full-field reservoir simulation models using numerical we

gitally sampled data. When viewed in the frequency domain these techniques are clearly high-pass and band-pass filters which exaggerat oration electrical current leaked through the perforation holes to the metal casing. The electrical insulation of the casing was imperfect but f

tent cement although reactive if exposed to CO2 has a very low permeability of the order of 0.5 to 5 Î¼D; this low permeability means that s perturbation a rock mass can sustain and yet remain stable. This distance to failure envelope is particularly relevant when it comes to ana

for storing CO2 emissions namely ocean storage and underground geological storage. The first scenario is still a very immature technolog change is of the order of a few percent. The mutual solubility between CO2 and brine affects the injection process and flow properties in th ating storage project is the detailed knowledge of rock and fluid properties that do depend on pressure and temperature conditions. These d the added greenhouse gases trap more of the earthâ€™s outgoing heat radiation. There is a wide consensus from extensive research in erm sequestration purposes is a viable means to keep a significant fraction of emitted CO2 out of the atmosphere. CCS is thus recognized

optimum well profile. Good hole cleaning was obtained with the use of 180 RPM on the drillstring together with maximum allowable flow ra ng of replacing the two producers which were becoming increasing wet with a drier horizontal wells to be drilled to the west of 15/20a-6 we

he Silurian in the Michigan and Illinois Basins. An early lithofacies analysis of the areaâ€™s Silurian was conducted by Melhorn (1958). The f geologic processes in large often high-purity (>90 %) deposits in many sedimentary basins. Several CO2 fields in the United States Hun standard logging run the analyst will view the density porosity output and question the economics. â€œWhat is the porosity cutoff to mak done to evaluate the effect of fluid type reservoir permeability lateral length and reentry drilling time on production performance.ï¿½Resu il contained in these accumulations and their in situ viscosities natural production mechanisms will render low recoveries. Therefore suitab red. Because GOGD is not effective in sparsely fractured reservoir water flooding those layers was expected to substantially increase recov

ese micro-pore types can be only beneficial for reservoir if they had linked together by fractures and microfractures which were formed due ng the water shut-off treatment. An oil producer that has shown -according to the recent production data - an increasing water production fig ssible because the perforations are behind the production tubing. For such single-string selective completions only a pressure test can be p

eld has had over 800 wells drilled with 525 of them currently active. Most of the shut-in wells in the field are located in the south end of the ated in order to determine if CT can get to the target depth without locking-up and that the maximum tensile and compressive loads require

f Health and Safety Executive (HSE) management to execute and involve potentially lengthy downtime. Being able to predict the presence ogether they are characterized by the existence of diverse flow configurations and flow patterns or a geometrical arrangement of the phase se flow provided that the dispersion effective viscosity is properly estimated. There is limited information on the intermediate flow patterns w n restrain the inflow from the completion into the production tubing by choking the fluid flow from between fully open to completely closed. the decisions have a limited influence on the overall performance of the system. In recent years operating oil and gas companies have sta nsify the asphaltene precipitation condition. Results also indicate that wax precipitation will not be an issue during the life of the project. Int ax components of the crude oil are not properly characterized. Critical properties and interaction between these heavy wax components are cted early in any exploration or appraisal campaign. Corrosion is more pervasive in the oil and gas industry than commonly perceived. It att and near-infrared absorption spectrometer for fluid discrimination and a refractometer for free gas detection. Since then other generations o

n the prediction of ultimate recoveries of condensate. A surface-yield correlation has been developed that is a function of a selected reservo atment of the liquid in the gas phase. The MBO approach assumes that stock-tank liquid component can exist in both liquid and gas phases ufficient data. The new technology of Downhole Fluid Analysis (DFA) has proven very useful for the early identification of fluid gradients [9 1 ons of changing fluid characteristics. For certain fluids pressure decline causes thermodynamic changes (such as solids precipitation or sig nce between predicted and actual performance in the oil field [3]. In many matured fields the No. 1 problem is â€œwhere injections fluids s

ent between our model and common field observation motivates use of our model to analyze the more complex WFT probes which have re he details of NIR application for DFA have been described elsewhere [2 3].

ed. Evaluation of saturations/remaining oil determinations becomes quite important for the determination of sweep efficiency in mature reser in general. The need for accurate determination of H2S concentration in the reservoir fluids to be produced is crucial. It may mean higher p

ture gradient in a reservoir (Pedersen and Lindeloff 2003; Hoier and Whitson 2001; Ghorayeb and Firoozabadi 2000a and 2000b; Firoozab han the existing hydrocarbon column filling will occur at the oil/water contact and may not readily mix with the rest of the column. The range ossover together with high value of resistivity suggests that the formation is gas bearing. Normally formation pressure gradients obtained fr nt to determine the magnitude of these gradients by actual measurements. Current wireline formation evaluation is inadequate to determine These new applications could include improved integration of pressure measurements and pressure gradient analysis with reservoir fluid a to reveal non homogeneous fluid distributions in reservoirs [1] [2]. Light and near critical reservoir fluids often exhibit significant continuou R prediction results for dark oils. Introduction Real-time estimation of sample contamination by drilling-mud filtrate is critical for the collectio

actual measurements. The reservoir architecture is revealed. For both cases the fluid column is continuous through the hydrocarbon interva s measured to estimate fluid composition and GOR (Dong et al. 2003). Second hydrocarbon spectra show a continuously increasing absor ontamination monitoring composition measurement and single-phase assurance can provide real-time fluid property information during fo

will also boil and at first three phases are formed.ï¿½ Add more heat yet and one liquid phase will disappear.ï¿½ If the oil is light such as a ncreases. With enough shear force (e.g. flow through a downhole pump or a flow restriction such as a choke valve or orifice) a stable emu

o understand fluid behavior during the production and life of the asset. Reservoir engineering and production strategies are crucially depend chambers in the string which served the dual purpose of increasing the length of the flowline and taking additional big volume fluid samples n proposed from Heavy Oil to Condensate (Ref. [2] [3] [28]). The way to handle this need is very simple and until now only two approaches The paper focuses on the sampling and fluid analysis aspects and utilization of the fluid information for multiphase well testing. The consist sed acids are very corrosive to well tubulars. One way to address these issues is to use organic acids. The two main organic acids that are arameters are disrupted with the evolution of damage in the near wellbore. To diminish this detrimental effect two actions are necessary. Fir ed for carbonate stimulation is largely only varied to a slight extent in order to find the optimum conditions (rate of dissolution) to generate w ion is generally easier to remove than other type of scales by washing with fresh or low-salinity water periodically frequent treatments nece

e permeability of a cylindrical rock core sample is determined both axially and radially before the perforation experiment as well axially thro ked debris of high permeability (1â€“10 Darcies).ï¿½Immediately surrounding the perforation tunnel is a â€œdamaged zone of fractured ro ½ï¿½ï¿½ï¿½ï¿½Changes in temperature pressure or pH; ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½3. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½Mixing of incom ring job. In a properly executed treatment the scale inhibitor should: cover the entire length of the propped fracture (as opposed to a sque ability to deliver flow assurance. e related problems such as interference with producing wells wireline operation and minor production losses. With more than 400 producers lfield in the North Sea[1]. Gyda receives limited aquifer support and is developed by waterflood.ï¿½There are 32 well slots of which curren nable match is first obtained at the field level then at the regional level followed by more rigorous individual well history matching. In this p match and prediction under waterflooding system. hing exercisesl. The essential or main benefit of streamline simulation is the often very dramatic improvement in simulation turn-around time g complex sectors that incorporate radial local grid refinements. ï¿½The findings have been encouraging in terms of extra oil recovery by th dantly described in the last five years.ï¿½ Most of them involve high frequency data streams provided by smart completions that involve larg electromagnetic surveys. The main objectives of the WI pilot project are: 1) determine sweep efficiency in the target reservoir units 2) quali n 7 100-8 300 ft. drilling depth and include various high-productivity Burgan sandstones overlain by a more moderate-permeability shallow-w 30ï¿½F. To exploit these extensive extra-heavy oil reserves economically new drilling and production technology implementations have be ogy to produce heavy and extra-heavy oil is still under accelerated development to meet the challenges to efficiently produce and procure th 1992; 1995). These materials are in general poor receptors of microwave energy so they cannot be heated directly up to the high tempera ence to optimize the performance of the HASD process for sand bodies of medium thickness. ter production and control the sand incursion problem. Geological Setting The development of oil-bearing basins in Sudan is closely associ ergy inner shelf or ramp setting in a gently dipping restricted ramp environment. The presence of minor interbedded evaporites suggests re e permeability anisotropy in spite of difficult and challenging acquisition (operations were done from Geophisika Logging unit due to the fiel

r important driving force behind drilling horizontal wells is to improve the light oil production from Aradeiba reservoir that is crucial for blendin

d. The primary challenge to commercially produce Issran field heavy oil is its mobility. The mobility and resulting productivity are mainly rela

raditionally hydrofluoric (HF) acid-based systems have been used to dissolve aluminosilicates in sandstone formations. These formulations and field development planning. Furthermore comparison between core permeability formation testing fluid mobilities and NMR permeabi

y variations (such as the existence of salt structures) or changes in the overburden thickness may create the temperature differential neede

neously just after the fluid exits the perforations avoiding high friction pressure and degradation resulting from shear in the tubulars and per n. In such treatments the injected acid is consumed by either reacting with the fracture walls or leaking off through the walls of the fracture t

eld are found in 3 main reservoirs: Miocene which is at depths up to 10 000 ft TVD Oligocene which is at depths up to 14 100 ft TVD Na solvents are being used to treat these wells with mixed results. The new sandstone acidizing system is developed to effectively treat mult me treatment fluids. For comparison sandstone reservoirs undergo matrix acidizing treatments to remove damaging aluminosilicate miner rvoirs in the San Jorge Gulf Basin. To make matters worse the low well productivity offers operators only a marginal return on their investm does not pose a problem.[4 10] The slow clean up of water blocks by evaporation can be enhanced by addition of volatile solvents. Succ l development strategy to prevent scale formation by choice of operating conditions to select and deploy scale inhibitors when needed or b

mpletions in the past four to five years (Figure 2).(1)

to change our focus now to how to develop the available gas reserves. Globalization of gas supply and demand has launched tight gas as irectional drilling from pad wells to reduce surface damage. ar Rosneft-Yuganskneftegas use hydraulic fracturing almost without exemption in all new wells as a conventional completion method. Additio 10 11 12 There are indications of microseismic activity being related not just to stress effects but also to actual fluid movement 13 14 and

te Noire. Average water depth is around 100 meters. The field was discovered in 1998 by the well FOKM-1. Production started on June 200 ich is the very first in East Asia is considered to be a major breakthrough in China for PetroChina in particular because the technology has opment has historically focused on the relatively more permeable 20 to 80 md thin-layered Ratawi Limestone interval with minimal conside D geocellular model which captures the properties and heterogeneities of the reservoir that is subsequently upscaled into a dynamic simula l economics.ï¿½ Introduction ï¿½ï¿½ï¿½ The majority of the Uinta Basin is located in northeastern Utah with a small portion in northwest eservoirs consist of several sand units over a gross thickness of 4 000 ft in a fluvial depositional environment. The thickness of individual sa dard and higher anticipated natural gas prices. These are the pay sands that are still only partially exploited and bypassed on an ongoing ba

e important for providing the needed permeability allowing the well to flow. formation testing technologies including new techniques applications and tool reliabilities over the past few years has caused a significant discovered in 1956. With an original oil in place (OOIP) estimated at 41 billion barrels and a total production to date of 5.4 billion barrels or rvoir presence and quality and ultimately dictate well performance and optimal well density. Figure 1: South Central Wyoming Regional Ge

. ï¿½ï¿½ï¿½ï¿½The rubber packer makes a seal against the borehole wall isolating the center probe area from the mud column therefore a for proper well placement. Consequently a multidisciplinary geological and reservoir modeling team helped to define the optimum waterflo

ncepts of 1970es. As a result of the exploration effort taken in 1980-es the structural model of the pre-Vendian units of the YTZ was develo

wept or if there is movement of the OW contact. In addition some authors [2-7] have explained the importance of changing wettability; the t

stantial manner. General technological development in all walks of life resulting in continuous increase in oil demand rise in oil prices and g

chniques by each individual in determining the specific decision of choice. In many cases these techniques or heuristics lead to high quali iases are related to how our socialization affects our judgment. It is impossible to find anyone who manages an oil and gas exploration and

ermeability) vary significantly horizontally vertically and with scale. Understanding these issues is critical to successful reservoir manageme recovery. This is particularly true in carbonates for which reservoir heterogeneity exists at many different scales. Detailed reservoir charact Newberry2 introduced a technique called PoroSpect* that allows porosity mapping of the borehole. Primary (e.g. interparticular porosity) an sin is northeast-southwest. The basin contains thick sequences of sediments with several cycles of deposition ranging in age from Late Car m different sources can help reduce the geological uncertainties." for reservoir evaluation and management. Reservoir-fluid properties such as hydrocarbon composition GOR CO2 content pH density vis n are some of the reasons of changing fluid characteristics. For certain fluids pressure decline causes thermodynamic changes (such as s eability of the carbonate system. To understand the permeability of the reservoir a pore classification method may have to be resorted which odeled geo-statistically to define the spatial heterogeneity and to visualize the distinct compartments within the reservoir. Using single well p ing and allow for a caliper measurement even when sliding. Finally an azimuthal gamma ray measurement device capable of producing 1 not having to use a chemical logging source. Introduction and Geological Setting Understanding the porosity distribution and type within

or the shaly sand formations as it assumed that the only conductive phase in the formation is the interstitial water and considered the rock rmations as it assumed that the only conductive phase in the formation is the interstitial water and considered the rock as insulator. In the p have presented a rock typing scheme based on property cut-offs thin section analysis and high pressure capillary pressure data and poreal and the depositional framework. In the present study logged intervals of studied well present a medium dipping sequence with dip azimut re based Dunham classification and high resolution sequence stratigraphy.ï¿½ The high resolution sequence stratigraphy which recognize and and shale layers.ï¿½ These beds are often too thin to be properly resolved with conventional logging tools. The acquisition of new tech

ivity anisotropy in thin sand/shale formations (Cao Minh et al. 2007).2 Both papers contained many useful references that will not be re-quo

many authors. These topics are particularly well documented by Rahmouni et al (2002) and Guehria et al (2005). Similar patterns in produ tion testing and sampling jobs or require multiple trips into the well to acquire the required samples and fluid profiling stations. Mitigating the ress directions through the analyses of breakouts and drilling induced fractures. For example the Fullbore Formation MicroImager (FMI*) p west of the Al-Khafji area onshore in the SUG and Wafra main fields. 3D seismic survey was acquired in the Al-Khafji where a number of w

he nineteenth century while frequency statistics played a more dominant role in the scientific applications in the twentieth century (Efron 200 out flow potential. The petrophysics and borehole geology analyses therefore had to be completed in near real-time before the wireline form rived hydrocarbon volume was then compared with the results estimated from a full triaxial (3D) induction tool. Permeability of the sand laye

on this past work we know that in the case of uniform depletion in the reservoir i.e. when pressure gradients in the reservoir are small stre

yielding increases the shear slowness stiffening would reduce the shear slowness. Introduction Formation stresses play an important role

rate inner boundary condition. (2) The definitions of the dimensionless variables used in this superposition relationship are given in terms

racture was expected to contribute better reservoir quality over especially the carbonate reservoir rocks of Thebes and Mokattam Formation ovskoe Urmanskoe Gerasimovskoe and others). In all of these fields oil was produced from the basement carbonates and weathering crus with seismic faults present in the field. A total of 8 major and 51 minor faults were observed with a dominant NW-SE strike direction consi others). In all of these fields oil was produced from the basement carbonates and weathering crust. Further investigation on Pre-Jurassic re

tive permeability effects â€“ most pronounced in tight water-wet gas sands where oil based mud filtrate is the third phase introduced into a

s; quartzitic sandstones litharenites micaceous and laminated sandstones together with shaly intervals that can be found in the productive r saturation Sw prior to WFT operations. Castelijns et al. (1999) show the use of NMR continuous permeability k to select test points at the

ue data quality and time. One of us (RA) addressed some of these issues by introducing the idea of â€œeveryday NMR in a recent paper ( measurements like those used in modern laboratory-NMR instruments. The value of these measurements is that they are extremely flexible

having high compressional stress. Failures have been reported while tractoring in open holes with soft formations.

ing injected and produced fluids. This of course would assume that in-situ downhole conditions such as temperature and flowing wellbore ved defining three structural periods: EW and NS faults crossing the field in its central part during the Hith-Shuaiba period; mainly EW fault

riers evaluation of connectivity across faults and prediction of fluid contacts. Downhole Fluid Analysis In recent years formation sampling ever a detailed analysis of the fluid in the rock is not possible today. The closest alternative is the acquisition of downhole fluid samples acco nner boundary condition. Equation (2) The definitions of the dimensionless variables used in this superposition relationship are given in ter t divides the field into eastern and western zones each with distinct saturation pressures. Observed only in the western part of the field are nation therefore fluid analysis using wireline formation testers is a very important step during the open hole evaluation stage. As noted thes

in a reservoir exploited with wells stimulated with long hydraulic fractures. Various techniques exist to determine stress direction and magn eed a complex initialization process and would require data that is not readily available. The ensuing interpretation would be overtly complex ti-discipline multi-scale data and utilizing 3-D numerical models as predictive tools. Then estimating risk from the remaining uncertainty allo g fluids in place fluid contacts and extension of flow units. In other cases the reservoir architecture is more complex and pressure data â€ technology to Bokor Field and prove its value for entire Baram Delta Ensure the knowledge transfer on ESP technology and techniques to ESA) is located in the Talara basin in the northwestern coastal region of Peru (Fig.1) and has an area of 470 sq. Km all onshore. Oil and a.ï¿½ It was discovered in 1970. The field is operated by Petronas Carigali Sdn Bhd. The first phase of development began in 1982/83. The

ch have produced over 400 million bbl of oil and 1.1 Tcf of gas. Six major fields account for 90% of the production from 12 zones ranging in d reservoir management strategy Optimum well type (vertical horizontal multilateral) and completion requirements Fig. 1 illustrates the na d re-circulating (in the case of gas) of large amounts of the secondary phases to continue with the previous oil production rates. Figure 1 sh potential field from Maracaibo Basin. Moporo field has a cumulative production at 320 MMSTB under natural depletion with reservoir tempe amework provides a new horizon of powerful tools enabling the emerging smart field workflows. This paper presents a comprehensive set mples include well workovers zonal isolation artificial lift installations upgrades of field equipment and remedial operations to mitigate flow anomalies and to identify areas where recovery could be improved. This is particularly important since at the present time no infrastructur ch 9 development wells were drilled. Two other structures house the separation facilities and a flare boom. Three â€œRevisit campaigns we

he fluid rates or the pressure at the surface coupling point (e.g. well head) where the well model is linked to the surface facility model. The Oil & Gas company inductions and they will use the technology to solve many pains from production optimization operations surveillance the decisions have a limited influence on the overall performance of the system. In recent years operating oil and gas companies have sta gical and engineering modeling.ï¿½ By definition this is an iterative process until all the disciplines agree to a model that is acceptable with meability measured in the Darcy plus range. Aquifer support is strong helping to sweep hydrocarbons but also causing rapid water breakthro

ration were defined by performing lot of screening using gas lift allocation models. ate oil production these fields have gradually entered into a mature and high-water-cut phase. Oil to water contacts (OWCs) have significan in an area of known depletion; the highest-rate Miqrat production well an overall improvement of zone productivity and a better understa ntroduction The Lower Vicksburg sands in the study area are heterogeneous low permeability and geo-pressured. Economics dictate the earning). In this paper we develop a mathematically consistent framework using decision trees conditional probabilities and Monte Carlo s

shallow (several inches only). Traditional electromagnetic propagation tools (2MHz) are sensitive to electrical anisotropy and bed boundarie In 2002 Oilexco North Sea Limited was awarded licenses to develop blocks 15/25b and 15/25c within the Outer Moray Firth Basin. Betwee hodology of sequential well placement across the entire reservoir therefore complements and completes this prior work.ï¿½ Introduction T for the elimination of fines leaving a blocky unconsolidated sandstone as the reservoir. Between thicker sand-dominated depositional eve the application of new technology into the field at low cost whenï¿½ significant reserves are accessed.ï¿½ However the critical aspect is i oil production in an aging oil rim field. Extensive reservoir simulation on a full field model was utilized for the initial well placement study. In p econd category can in theory avoid this problem but has the disadvantages of not increasing NPV at each iteration and requiring many for

e to laminar flow of fluids in a porous medium were the results of Darcyâ€™s experimental study of the flow characteristics of sand filters. can be extremely useful they are based on very simplistic physics and fail to fully account for transient effects and interference between we an inverse problem. Such inverse problems are usually ill-posed and their solutions suffer from difficulties in existence uniqueness and sta own as â€œHistory Matching which is considered the most time consuming phase in building a reliable model for the field. Thus any reduc

atched model must not only reproduce production data by numerical simulation but it must also be consistent with the geology in true sense

resents comparison of simulation results against other simulators to verify the physical results. Mathematical Formulation The thermal mod ation and mole fraction formulation (IMPES) and implicit pressure and saturation and explicit mole fraction formulation (IMPSAT). Furtherm in large areas from a limited number of platforms. However due to a variety of reasons the entire completed interval may not contribute to

cost efficient manner. This is especially true for offshore fields where these wells are used to drain large areas with limited platform capacit

nues to leak off into the reservoir. Alternatively and especially for tight gas reservoirs the fracture can be forced to close by flowing back so pairment in tight-gas reservoirs. Many tight-gas wells do not respond to hydraulic fracturing as expected. Following the fracturing treatment 5 exhibit better rock quality than 2 and 3 but they still benefit from stimulation. The bottom zones - 6 and 7 - similar to zone 2 and 3 in bein sis of so called â€œblack oil technique.ï¿½ï¿½ So the multicomponent multiphase fluid model is necessary to predict the performance of h heoretically. It is well known now that in-situ stress contrast is the dominant mechanism that affects fracture height growth. It has also been that adequately represents both the large range of influential reservoir parameters and their inherent uncertainty. The most common way

esents a concise and clear discussion of the deficiencies and limitations of the allocation method. The non-linear regression method2 propo n terms of the pressure drawdown between the average reservoir pressure and the sandface flowing pressure ) and the classic transient te ure geometry. Over the past twenty years however it became even more obvious that none of the available fracturing models were matchin es and Nolte 2000). You may ask how to achieve this ideal perforation. To answer this question or at least provide some recommendations NNs are widely used in prediction and classification problems and have numerous applications in geosciences and petroleum engineering i

the fields in the Delta of Egypt. It is located to the North of Cairo and it is about 64.6 Km2. Figs. 1a and b show the location of South El-M e estimated with â€œproduction logging technology but this may require coiled tubing to access the full length of the well. Even with coiled

an important issue in material balance calculations. Uncertainty due to data errors can be found in field production data measured PVT pr

rm composition. Natural convection also can result in increased horizontal compositional variation an effect similar to that in a thermogravi bove typical steps in an experimental design workflow. The paper presents the lessons and experiences distilled from the application of ED a

missibility upscaling method (TU-method). In contrast to upscaling of permeability which is associated with a single control volume (e.g. see

the fracture system or be isolated in matrix material which constitutes a triple porosity system.ï¿½ Several publications2 3 have addressed pproaches depending on the origin and the type of fracture sets and on the ultimate reservoir engineering questions raised. In this paper w

mplicated geological multiwell models that require a large number of grid cells and therefore require either very large (parallel) computing ef or and much better scaling with respect to the number of grid cells and heterogeneity for three-phase compressible dual porosity simulation on and displacement processes. Fractured reservoirs are complex geological structures in which fluids are stored in matrix blocks and flow

cation of uncertainty obtained with RML with the one obtained with the ensemble Kalman filter (EnKF). The PUNQ-S3 reservoir represents

ecipitate inorganic scale â€“ thus making the brines incompatible (Yuan and Todd 1991). For example if sea water which is rich in sulphate

the pressure equation should be solved; between the pressure updates saturations are transported using a frozen velocity field. As the na h specific procedure uses cubic equation of state like for example Peng-Robinson for determining thermodynamic characteristics and equ p methodologies which are strong enough to tackle the aforementioned technical challenges transforming these opportunities in real bottom

bjective function based on the full pressure data only the dominating patterns in the simulated pressure data with the recorded pressure d 06). A former restriction of the multisegment well model was that it could not represent looped flowpaths within a well. Thus while flow in an

le oil) with average temperature pressure and saturation pressure of 275 oF 11000 psia and 5500 psia respectively. Reservoirs flow prop

ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ WL (location where there is zero capillary pressure between oil and water) OWC (as depth increases below the oil zone the location at wh ced drilling (UBD) campaign was initiated from a mother wellbore to drill multilaterals. The drilling plan was to be conducted through the pro fields those are now being developed; the original data quality is very poor or inadequate to extract meaningful results that could be used t re several operators notably BP Chevron Norsk Hydro Saudi Aramco Shell and Statoil have flagship fields where many but probably n

North Slope (ANS) petroleum province is defined as the private municipal State of Alaska and United States federal lands and waters no ns in the cement sheath was also discussed by Bosma et al. (1999) but this will not be addressed in this paper. Both types of models ass

bridge plug. The same rig was used for the logging and the setting of the bridge plug. The water shutoff operations successfully increased ulic flow control valves. Norsk Hydro then turned its attention to flow control of multilateral wells. A completion solution integrating flow contr on history of more than 40 years. The depletion drive mechanism causes the swift pressure decline in the field. Studies indicated that water his left two possibilities: coiled tubing conveyance with a hydraulically powered tractor or wireline logging with a new much more powerful tra

commendations that were made and their implementation. This discussion is informed by the fact that these are low permeability rocks drill

enhance reservoir modeling efforts. r which can be difficult and costly to obtain. The quality of formation-water data is highly dependent on the sampling technique and the type oir properties that will be analyzed not only by absolute value but also by trends frequency and impact on other dependant variables to al geological history and low permeability of the Canyon sandstones in this region (Marin et al. 1993) the hydraulic fracture stimulations are c ove the production (eliminate skin) of its existing moderate permeability reservoirs (ranging from 5.0 - 200mD) and unlock its large reserve b

h they are pumped to the surface. Total E&P Canada installed a pilot horizontal injector/producer pair in their Joslyn field in 2004 as Phase e wellbore to the surface.ï¿½ Turner et al3 identified that there are two transport mechanisms that must be considered in evaluating the tran e. Turner et al3 identified that there are two transport mechanisms that must be considered in evaluating the transport capability of a system ation has been the length of time for a well to stabilize thermally often exceeds the production log duration causing incorrect temperature lo

tall a meter on each well thus preventing continuous flow-rate and cut measurements on each well. This introduces the same type of uncer

owever production can also be limited either by reservoir constraints or process constraints that also need to be included in the Production ity measuring gradiomanometers and full bore spinners are inadequate for characterizing separate phases in stratified flow. One approach d communication between the Wara and Burgan sands has to occur through partially-sealing faults with throws considerably larger than the Generally asphaltenes tend to remain in solution or in colloidal suspension under reservoir temperature and pressure conditions.ï¿½ They of the intervention of modern technologies in overtaking the challenge. Here we are going to focus on one the wells in the field of scope and WFT evaluation program is unique. Some may include only a pressure-gradient survey for reservoir depletion and communication informat n during the shut-in. Alternatively one can perform a multirate IPR test using a production logging tool (PLT) log which again results in loss o tiltmeters respectively could allow the steam injection to be tracked with complementary technologies that respond to different expressions sandstones with excellent intrafield connectivity and permeability interbedded with shaly layers. The reservoirs are part of a multilayered sa s to be installed in the period 2008â€“2012 representing over 60% growth from the period 2003â€“2007 when 1 467 wells were installed. A

side of the process from the sales or delivery point to the wellhead. It is also necessary to evaluate the other side of the process from wel r shut-off program with the objective of restoring oil inflow. Difficulties in acquiring quality data in horizontal flow environments specifically w

onitoring and future actions for enhanced recovery. Introduction The different techniques of reservoir monitoring and maintenance enhanc

ast to be easily picked up by the technique and 3) the flood front progress can be captured by conducting the surveys in a time-lapse mode bypassed oil and residual oil saturation are secondary considerations of the WI pilot study. Production injection saturation and pressure d er Basin has 12 000 wells in production and an estimated 50 000 more wells will be drilled in the next 5-10 years. Wells in this basin are now called cleats. The extended continuous fractures are termed as face cleats and subsidiary shorter length fractures are classified as butt cl hat requires exposure to a much lower pressure in order to desorb and produce the gas but also coal seams are highly susceptible to near nd is abnormally pressured in this area. Commercial production is achieved only with hydraulic-fracture treatments. Before 1997 Barnett s cture initiation occurs the treating pressures can remain high inhibiting the normal progress of the treatment (e.g. low pumping rates are in

ly 1 Bcf in Denton and Wise Counties economics were marginal due to high completion costs and low commodity prices.ï¿½ By 1996 the w ture characterization and production evaluation can be found in Louks et al. (2007) Gale et al. (2007) and Frantz et al. (2005). In order to s. The combination of these factors in reservoir studies limits the results that can be obtained. Our study examined several completion strat . In shale-gas reservoirs gas is sometimes produced through more-permeable sand or silt layers interbedded with the shale through natura ure diversion technique is ideally suited for re-fracture stimulations it is also applicable for stimulation of new wells where the technique en d by the acid injection rate. The materials dissolved by acids are typically the pore lining or filling materials rather than the matrix framework

ed across it. This causes further rise. The process continues until the fluid column reaches the surface. Meanwhile the high pressure and a ld comprising 26 stacked pays which belong to Cretaceous and Jurassic systems (groups of PK AS BS and JS reservoirs). It contains mor

stimulations vs. potential well production. One of the most important parameters affecting production is the number of layers fractured durin perforating method to pass the radial extent of near - well bore mechanical alteration. After perforation the production test showed a 3-fold methodology discussed in this paper as well as the production optimization model in general is not necessarily restricted to use for vertica methodology discussed in this paper as well as the production optimization model in general is not necessarily restricted to use for vertica rence 1 contains more details about production performance of these 16 wells.ï¿½ Thus the objective of this project was to drill a tri-lateral

e left with high oil saturation. This may also be termed as poor â€œload balancing. The literature on the concept of locating missed pockets ontrolled variable multipositional hydraulic system. This paper discusses a closed-loop approach that led to efficient realtime production op

orresponding laboratory tests. One of the biggest disadvantages of using acid in the well is the aggressiveness of these fluids making it imp nalysis approaches to ESP performance analysis. Background on SA is then provided along with an outline of the three main classes of S

increasing diesel fuel costs led the team to consider reviewing alternative fracture fluid systems to determine the impact on well performan

e generated oil. Fig. 2 shows the productive Bakken Middle Member in the Richland County Elm Coulee Field. The â€œBar Trend is a very were the prime target application for this novel technology where low concentration and small mesh size proppant fracture treatments are ty

n issues and to prevent proppant flowback in hydraulic fracture stimulation1. Most recently however the scope of fiber application has vast pillary pressure of the fluid in the near fracture region should improve flowback of the fracturing fluid and reduce the drawdown to produce. h the development of tiltmeter and microseismic mapping services more direct measurements or estimates of hydraulic fracture geometry a cost-control measures include reducing additives in fracture fluids and minimizing disposal costs of produced waters by recycling and using costs for their produced water exceeded $400 MM/yr (Khatib and Verbeek 2002). Finding alternative uses for flowback water in the E&P in al completions (single stage single sand) limited entry techniques and Pin-point Stimulation* techniques were introduced to further unders production of formation sand. Ball sealers were used in long perforated intervals as diversion mechanism to achieve better zone coverage. gularly pumped fracture height growth is additionally considered to be a major cause of premature screen outs. The fracture height growth appointing production figures with higher than expected production of unwanted fluid and completion costs. Since the oil could not be recov moval and sand consolidation to maintain an economic production rate. The reservoirs are made up by several stacked reservoir that initi gh a hydrocarbon reservoir. Drilling technology has evolved to a point where horizontal wells can be constructed at comparable costs to ver

m this successful experience are discussed as a way to further enhance the benefits from the technology in future applications.

als at the same time can result in less than an optimal treatment of the reservoir. The treating fluid downhole will be diverted into each laye start either earlier or later than expected. In the first case the fracture length will be less than planned. This leads to early packoff before the onally a new encapsulated breaker has been developed for the zwitterionic VES described here.ï¿½The encapsulated material uses a po

NM over time has resulted in a complex vertical sequence of sandstone reservoir.ï¿½ It is not uncommon4 to see several vertically discrete

ain the formation pressure much higher than the asphaltene onset pressure to prevent asphaltene deposition within the reservoir in addition ation indicated clearly that yield stress can result in only a fraction of the fracture length contributing to production for a long period of time. H The depositional environment was relatively shallow water regions that left sediments forming barrier bars and lagoonal muds.ï¿½ Storm c

erforations is directly projected into error of the absolute fracture position. We show that the effects on the absolute fracture azimuth may be

ce asperities and conductivity will be high. As the closure stress is increased surface features along the fracture faces may be crushed and on will be used to optimize fracture design pressure maintenance strategy and pattern orientation. Fields and Reservoir Description The P was based on the â€œcooling effect that was created when the fracturing fluid was injected into the formation interval. Although this analysi

se were the only data available in any significant quantity and therefore a thorough analysis of the available testing practices was necessa of free liquid rate to gas rate. These are in addition to the other factors that determine proppant conductivity in single-phase flow:stress on

hydrite shale or non-permeable intervals. This heterogeneity of the K formation makes it an excellent candidate for acid fracturing treatmen

owicz and Kijko 1994). Most hydraulic-fracture microseismic images are recorded with sensors in a single observation well such that the se

uced stress change diminishes and the minimum stress at the fracture tip reverts back to the original direction causing the fracture to turn to s is the so-called hydraulically driven fracture. By nowadays evaluations of hydraulic fractures propagation and growth were based on eithe management tool. It was only recently that the fracturing treatment size increased from an initial 10-20 tons to 150-300 tons1. The proppant

early JIP effort that focused on the process of polymer concentration and its impact on the fracture clean-up behavior. Special effort was un ected to achieve a plateau production rate of 120 000 barrels per day. Kikeh is produced via a Spar and a subsea production system back to PETROBRAS started a strategic IOR project (named PRAVAP) where strategies like increasing water injection rates improvement in the sel d experiments. In addition the entire fracture is more easily exposed for detailed examination. Early lab studies10 11 were concerned with as and water coning (Betancourt et al. 2002). An estimated 60 auto gas lift systems have been installed at the time of writing of this paper were performed in high rate gas wells four in Amherstia four in Flamboyant and two in Immortelle fields. C&P-1 Well: This well was comp ve enabled an accelerated growth in horizontal drilling. Current drilling technologies have pioneered these advancements to such an extent e enabled an accelerated growth in horizontal drilling. Current drilling technologies have pioneered these advancements to such an extent t Tambora field produces from a series of interbedded deltaic sandstones shales coals and locally limestones. These formations are classif endent and exhibits spatial variability. In south Shaybah where SHYB-220 is located typical permeabilities range from 5 to 10 mD. Three-D s the flow across the entire horizontal section; delays early water breakthrough and uniform areal drainage. It is concluded that Inflow Contro

ated with the reservoir description. Inflow control to a well can be â€œpassive or â€œactive (Jansen et al. 2002; Kharghoria 2002). Passive our understanding of fracture height growth and containment mechanisms the experiment attempted to recreate fracture propagation obse

ogy logging services such as tri-axial resistivity high resolution oil-base borehole images and nuclear magnetic resonance (NMR) logs hav operties depletion water-cut etc. If the strength of reservoir rock is low it will require sand control. On the other hand high strength rock is ive fluid injection are controlled not only by the chemistry and the fluid velocity but more so by the heterogeneity of the rock.ï¿½ In a carbon m Field-Î±. In this area the Tadrart formation underlies directly below the hercynian unconformity (Fig. 2) which confirms the progressive ero D which was higher than the expected gain of 35 MMSCF/day (Figure 1). Currently the well is the highest producing well in Resak field with reaches the undamaged reservoir. This process is fundamental to the productivity of the well; however its importance is often overlooked otential productivity per well. Well productivity can be further optimized by applying drilling and completion practices to minimize skin effect f ther a dominant single or bi-wing) and generate a ï¿½ï¿½ï¿½ï¿½fracture with minimum tortuosity (turning from the initiated fracture into the ses after perforating with this method the wells were not able to flow into the production line with a back pressure of more than 1000 psig un operties are very important to estimate hydrocarbon reserve to quantify productivity of a well and to assess the quality of the completion. P . Standard CT in which a pressure activated firing mechanism will be used as part of the toolstring Although these conventional methods lopment. A validated analytical model for predicting perforating gun swell can certainly enhance the effectiveness of both job risk managem

event this crushed zone from being created or to remove it before the well is put on production (or injection as the case may be). onsideration in any completion program.

ack (CHGP) and the oil production pumped to a neighboring platform. This EWT required the deployment of the world's first Electric Subm

with a new ESP with bypass assembly ran on 3-1/2" EUE x 4-1/2" VAM tubing."

e Gravel Packing method has been accepted as a proven standard of completion in the oil and gas industry.1ï¿½ Sand control measures in r some poorly sorted sands with higher fines content which result in the Uniformity Coefficient (D40/D90) ranging from 2 to 16 and the fines

presence of shale however the Openhole expandable screen with annular barriers is the only completion option except in fine sand envir e pipe and the wash pipe through which the carrier fluid must travel and reach to the entry point into the wash pipe for returns to surface. S

cost. Introduction A significant portion of openhole completions in Nigeria are drilled with a synthetic/oil-based drilling fluid (S/OB) due to ductivity and/or excessive maintenence to both downhole and surface equipment. Extreme sand production may also cause catastrophic fa d productivity and/or excessive maintenance of both downhole and surface equipment. Extreme sand production may also cause catastrop he field. Introduction A rock mechanical analysis for the Gjï¿½a field (Figure 1) has concluded that all the wells will require some form of sa on by McDiarmid et al2 led to a conclusion that the failure was caused by high stresses in the reservoir compared to the formation strength. m entering the wellbore. Depending on vicinity-to-water reserves and economics there are three gravel-placement options. In the order of l

ese ESPs which were installed to sustain production rates failed as a direct result of sand influx. Since 1984 most wells in Sarir field have a later comparison of the results to actual field data and observations validated the analyses and methods used. The application and comp the field has been reported to have been experiencing sanding problems. For example the openhole completed well AA04 was reported to ot relate to each other and sand production may initiate before or after water breakthough (Sanfilippo et al. 1995; Skjaerstein et al. 1997). D

r describes the development of the model and the application of this model to formations from an oilfield in the Norwegian Sea. Introducti red for the study were obtained from laboratory and field measurements. The field data from five appraisal wells (study wells) were made a micals were developed to enhance acid diversion by increasing the viscosity of the injected acid. Depending on the viscosifiying agent thes after fracture closure.ï¿½ However conductivity after fracture closure requires that the fracture face is non-uniformly etched by the acid wh and qualities. Even within specific areas and reservoirs the degree of heterogeneity is broad due to the depositional and diagenetic history

nnovate from lessons learned and experience gained from implementing over 200 treatments in the past few years mostly in the Khuff B an ing acid system to achieve diversion. This document discusses the results of the first wells treated with the viscoelastic diverting acid syste ommonly placed on carbonate versus sandstone matrix treatment fluid selection and optimization design. There are certain carbonate rese

al simulation of chemical reactions.17 However it will need a large amount of data not only on detailed mineral compositions of the targeted

on inhibitors can protect the tubulars at high temperatures only for a short period of time. These drawbacks make organic acids such as for

e acidizing.ï¿½ The simplicity results form the fact that the rock is composed of calcite (CaCO3) and/or dolomite (CaMg(CO3)2).ï¿½ Their r and underbalanced clean-up with coiled tubing are experiencing wide implementation in recent years but required further technological imp voirs is discussed. Introduction Carbonate reservoirs are routinely stimulated with acid to improve production.ï¿½ Several experimental and ortant aspects of any restimulation program or attempt are: (i) learn from existing experience in the field or area about restimulation and form Lehman et al. Case studies of two wells are presented on this paper. On the first well after a pressure build up on the Muddy Formation tha

sate) VIII2 and VIII3 (gas-oil) and VIII4 in the Callovian; IX1 (gas) and IX2 (gas-condensate) in the Middle Jurassic; II-T III-T and VI-T (ga

rvals and place the stimulation fluids precisely into the oil bearing intervals unless the entire completion is pulled out and each particular inte via the cemented annular space means expensive remedial cement squeezes to cure the problem. The expense is considerably higher if t ow test. In contrast the buildup period is the one when the downhole valve X is closed and the wellhead valve Y is closed. The closing of th rogram is a 2 270 ft long horizontal well targeting an area interpreted to have high fracture density (see well schematic in Figure 1). The mai formance of multi-fractured wells. From a performance perspective the optimum production and completion would be the one that results i ilished as a preferred testing technique in this complex reservoir environment. e tests in both systems i.e. fractured and unfractured reservoirs is performed using Tiabâ€™s Direct Synthesis (TDS) technique for analyz e flow period of a transient well test. This definition is not completely accurate when we apply an instantaneous source during which pressur arge numbers of ESP wells a time snap of reservoir properties could be periodically obtained to track changes in pressure skin and permea 1965; Kuchuk et al. 1990; Thompson and Reynolds 1986; Baygun et al. 1997). A thorough review and list of the previous deconvolution alg

ed at a number of rates with the above mentioned tests so as to be able to estimate the non-Darcy flow coefficient by separating the mecha ntinuous efforts have been deployed over the years to further develop Abu Al Bukhoosh resources in response to the growing maturity of th ater in gas and condensate wells. The need for inline measurement has been made more acute in the last few years to tackle the following

mit of liquid flow [or gas volume fraction (GVF)] though the accuracy of this approach decreases with decreasing GVF. The accurate determ se well test data in identifying and evaluating various well performance anomalies and how the measurements are used to monitor well prod

mon technique used in the industry to measure flowrates is the Venturi (or differential measurements); all manufacturers are using one or s mulation models using numerical well testing . The authors pointed out the difficulty in history matching during a simulation study due to the

d band-pass filters which exaggerate high frequency noise and distort the true dp/dt curve. The data is typically smoothed by subjectively ch ion of the casing was imperfect but functional as indictated by field test results. Horizontal Well Sand Control Completion A second field e

¼D; this low permeability means that most CO2 will travel by diffusion a very slow process over the length scale of a meter. Cement with a h ularly relevant when it comes to analyzing the stability of long term underground storage or disposal facilities for determining upper bounds

rio is still a very immature technology but environmental concerns have slowed down its development and more knowledge in the area is re on process and flow properties in three ways: CO2 dissolves in the brine increasing its density CO2 dissolves in brine and reacts with wa and temperature conditions. These data serve as an input for reservoir models and decisions on the injection regime as well as decisions o onsensus from extensive research in the last three decades that rapid climate change is already happening that global average temperatu tmosphere. CCS is thus recognized as a promising solution to mitigate climate change.[ii] Along with capacity and injectivity containment is

ther with maximum allowable flow rate. The ERD well has a Down hole Instrumentation and Control System (DIACS) completion with tree be drilled to the west of 15/20a-6 well. Five attempts (wells 15/20b-12 12Z 12Y 12X 1W) were made but all were understood to have be

s conducted by Melhorn (1958). The paleontology petrography and geometry of northeast Illinois Silurian reefs were described by Ingels (1 CO2 fields in the United States Hungary Turkey and Romania have been or are being developed to provide an efficient source for enhance €œWhat is the porosity cutoff to make a well here? The answer is found over years of experience and the school of hard knocks. Typically a on production performance.ï¿½Results show that this technology will be very promising for application in medium/low permeability gas-con der low recoveries. Therefore suitable EOR methods need to be applied to extend the productive life of these reservoirs and increase their ected to substantially increase recovery in those layers. Since 1997 field development and operation has utilized this combination of GOGD

rofractures which were formed due to tectonic activities at later times. The tectonic activities are principally factors making strong and wide - an increasing water production figures was identified as a good candidate for such approach. A temporary straddle system was created u etions only a pressure test can be performed to confirm that the perforations are squeezed off. This paper addresses the planning operatio

are located in the south end of the field that in recent years has experienced a surge in water production. Most of the wells in this particular nsile and compressive loads required at the packer during the operation are within the string capabilities and limitations. The friction coeffici

. Being able to predict the presence and type of trouble zones and dealing with downhole problems is increasingly important as water dep eometrical arrangement of the phases in the pipe. The flow patterns differ from each other in the spatial distribution and the position of the in n on the intermediate flow patterns which lie in between stratified and fully dispersed flows. In this study the gradual flow pattern transitions en fully open to completely closed.ï¿½The artificial lift system is also part of the control devices as for example the production rate can b ting oil and gas companies have started to address this problem and have started to organize multifunctional teams to better analyze their a sue during the life of the project. Introduction The size of the potential reserves drives initial capital expenditure and reservoir appraisal is n these heavy wax components are often calculated by extending the correlations for lighter hydrocarbon components. As such the model stry than commonly perceived. It attacks in one form or another all components at each stage of every hydrocarbon producer. Corrosion c tion. Since then other generations of the DFA tools have been introduced to obtain additional reservoir fluid information. DFA tools today ar

at is a function of a selected reservoir pressure initial stock-tank oil gravity specific gravity of the original reservoir gas and reservoir tempe n exist in both liquid and gas phases under reservoir conditions.ï¿½ It also assumes that the liquid content of the gas phase can be defined y identification of fluid gradients [9 10] and compartmentalization during the Exploration and Appraisal stage.[2 11] DFA is an objective and a s (such as solids precipitation or significant liquid dropout) which can significantly alter well productivity ultimate recovery and project econo blem is â€œwhere injections fluids such as gas and/or water go. The industryâ€™s standard procedure to delineate compartmentalization

omplex WFT probes which have recently become available. Introduction In the development of deepwater prospects and other capital-int

of sweep efficiency in mature reservoirs. Low porosity/low permeability sections can be more challenging to evaluate and these sections c ced is crucial. It may mean higher processing fees or a lower price for the oil or gas. It may also determine if it will be possible to access ex

ozabadi 2000a and 2000b; Firoozabadi 1999). Irreversible thermodynamics appears to explain compositional grading in most systems. In th th the rest of the column. The range of API gravity in a trap initially reflects the maturity of the source rock kitchen during trap filling constra ation pressure gradients obtained from wireline formation tester (WFT) tools greatly help in identifying fluid types. valuation is inadequate to determine the magnitude of fluid compositional gradients. Even multiple sampling with subsequent laboratory an radient analysis with reservoir fluid and thermodynamic models. However such an approach requires good data quality control and data ana ds often exhibit significant continuous variation of hydrocarbon components with depth. This has been illustrated in the literature [3] [4] [5]. mud filtrate is critical for the collection of representative hydrocarbon-fluid samples in wells drilled with OBM. The hydrocarbon sample may b

ous through the hydrocarbon intervals down to the water-oil contacts. Flow barrier locations would be found on the basis of anomalies and d ow a continuously increasing absorption at shorter wavelengths. This absorption (or color) is caused by the higher concentration of aromati e fluid property information during formation testing.1â€“10 DFA helps ensure that representative samples are obtained and allows an unlim

pear.ï¿½ If the oil is light such as a light olive oil or sewing machine oil then the oil will probably vaporize first.ï¿½ On the other hand if the choke valve or orifice) a stable emulsion can be formed. Presence of inorganic solids such as sand clay and corrosion products together

ction strategies are crucially dependent on knowledge of phase behavior and multiphase fluid flow and they rely increasingly on numerical g additional big volume fluid samples. The fluid analyzer also served as a warning device to indicate if there was any undesirable gas-liquid e and until now only two approaches were possible: using published correlations to estimate oil water and gas properties. This simple app multiphase well testing. The consistency of the multiprate well test information is not covered in still paper as the analysis of some condens The two main organic acids that are frequently used in the field are formic acid and acetic acid (Harris 1961; Smith et al. 1970; Chatelain e ffect two actions are necessary. First it is very important that the quality of the injected water is controlled since presence of iron compone ns (rate of dissolution) to generate wormhole structures. ï¿½Wormhole formation depends on the bottomhole temperature and pump rate u riodically frequent treatments necessitate well intervention and cause significant production deferment. This is further complicated with the

ation experiment as well axially through a restricted endplate simulating a perforation entrance hole. The experimental set-up in the authors a â€œdamaged zone of fractured rock grains extending a distance of order 20mm from the perforation tunnel.ï¿½For liquid-saturated rock ½ï¿½ï¿½ï¿½ï¿½ï¿½Mixing of incompatible waters. Carbonate scales and in minor case some sulfate scales are without exception the inorg pped fracture (as opposed to a squeeze treatment which only penetrates into the critical matrix); have thermal stability at formation tempe

sses. With more than 400 producers and more than 350 pressure support water injectors in UZ a solid Well Integrity Management System ere are 32 well slots of which currently 15 are for producers with a further 10 wells dedicated to water injection.ï¿½From the outset it was r dual well history matching. In this paper we briefly present the theoretical basis of optimally delineating the regions in a reservoir for efficie

ement in simulation turn-around time that generally results from simulating very large often multimillion cell geological models incorporating g in terms of extra oil recovery by the use of this IOR technique. This is due to the specific imbibition/re-imbibition capillary hysteresis spre y smart completions that involve large investments and an early vision of the automatic production surveillance system for the entire asset l in the target reservoir units 2) qualitatively assess the impact of injected fluid fluxes vertically across low permeability sub-units within the re ore moderate-permeability shallow-water ramp-carbonate the Mauddud. These reservoirs were normally- pressured at the time of discovery echnology implementations have been significant over the last 10 years particularly the use of horizontal and multilateral wells and the deve to efficiently produce and procure the proper facilities for thermal operations. eated directly up to the high temperatures usually required to achieve total pyrolysis. However microwave-induced pyrolysis is possible if th

ng basins in Sudan is closely associated with the global phenomenon of plate tectonics and particularly with the separation of Africa from S interbedded evaporites suggests restriction was occasionally sufficient for the development of hyper-saline lagoons and sabkhas. The shal ophisika Logging unit due to the field remoteness) and wellbore conditions (well bore stability and high mud filtrate invasion).ï¿½ Introducti

ba reservoir that is crucial for blending and transporting the heavy oil from Bentiu reservoir through the pipeline. Seven horizontals have bee

resulting productivity are mainly related to fracture density and sizes. When fracture density is minimal these reserves are developed therm

one formations. These formulations typically referred to as mud-acid are usually composed of hydrochloric acid (HCl) and HF at various c fluid mobilities and NMR permeabilities acquired in one of the exploration wells is also shown in the paper.

te the temperature differential needed to make thermal effects (i.e. convection) dominant. There is abundant information in open literature

g from shear in the tubulars and perforations.ï¿½ Crosslink the fluid too early and the friction in the tubulars will rise significantly and as it w off through the walls of the fracture then reacting with the carbonate matrix.

s at depths up to 14 100 ft TVD Naturally fractured Basement which is up to 14 800 ft TVD The primary target is the fractured granite bas s developed to effectively treat multi-layered high temperature (200-375oF) reservoirs with long production intervals and complex mineralo ove damaging aluminosilicate minerals and reduce the skin value. The precipitation of silica is thought to be the major reason that sandston ly a marginal return on their investments. In an effort to increase productivity the hydraulic fracturing technique has been adopted since ma y addition of volatile solvents. Successful cases have been reported in literature where solvents have been used to clean up water and con y scale inhibitors when needed or both. Correct water resistivity is important for interpreting openhole wireline logs accurately. In addition a

d demand has launched tight gas as an increasing source of energy. A recent gas presentation sourced Wood Mackenzie as stating that in 2

ventional completion method. Additionally initial and refracturing of wells with 10-15 year of production history as well as fracturing of sidetr o actual fluid movement 13 14 and in some cases indicating a volumetric hydraulic fracturing process 4. Recent efforts have been given to

M-1. Production started on June 2001. In the same year one well was drilled in the reservoir D but due to very poor reservoir characteristic rticular because the technology has proven to be an effective stimulation method to increase well productivity from horizontal wells that are estone interval with minimal consideration given to the low productive low permeable 0.1 to 5 md Ratawi Oolite section. The Ratawi Oolite ntly upscaled into a dynamic simulation model. This flow model is calibrated against historical performance and used for forecasting wells a ah with a small portion in northwest Colorado.ï¿½ This basin is a major depositional basin that subsided during late Cretaceous through Te ment. The thickness of individual sand units ranges from 5 to 50 ft. These geological heterogeneous reservoirs are poorly correlatable over ited and bypassed on an ongoing basis. In tight clay laminated gas sand basins one technique that the completion engineer often uses to

few years has caused a significant change in perspective with regard to understanding reservoir rocks and fluids and their heterogeneities ction to date of 5.4 billion barrels or 13.2% of the OOIP this field is one of the biggest hydrocarbon fields in the world producing from Camb outh Central Wyoming Regional Geologic Setting (Ryder R.T. 1988) Improving recovery in tight gas reservoirs mandates equally tight wel

ea from the mud column therefore allowing hydraulic communication between the flowline and the formation without influence from the mud elped to define the optimum waterflooding patterns from the beginning to avoid drilling more dry holes. The southern area is waterflooded p

Vendian units of the YTZ was developed. It was deemed that the basis of the YTZ is constituted of main massive deposit associated with a

ortance of changing wettability; the transition zones are often increasingly oil wet towards the top. It has been reported that a reduction in oi

n oil demand rise in oil prices and geopolitical reasons have necessitated the technological breakthroughâ€™s in understanding of the res

ues or heuristics lead to high quality decisions however they are often polluted by individual biases and predictable mental errors. In the c ages an oil and gas exploration and production project in complete isolation. Memory biases influence how we remember and recall certain

l to successful reservoir management as reservoirs mature and enhanced recovery methods are planned and implemented. In addition m nt scales. Detailed reservoir characterization is needed to better map the formation heterogeneity for reservoir management. Core experime mary (e.g. interparticular porosity) and secondary (e.g. dissolution vugs or fractures) porosity could then be distinguished and this technique osition ranging in age from Late Carboniferous to Holocene stretching from onland to offshore to deepwater. The basin is divided into sub b

GOR CO2 content pH density viscosity and PVT behavior are key inputs for surface-facility design and optimization of production strate thermodynamic changes (such as solids precipitation or significant liquid dropout) which can significantly alter well productivity ultimate rec ethod may have to be resorted which can explain the production behaviour. The pore system classification would also help in designing a wa hin the reservoir. Using single well predictive modeling the flow units and the petrophysical rock types were defined and the water saturatio ment device capable of producing 16-sector gamma ray images as well as quadrant and average gamma ray measurements is located on porosity distribution and type within a reservoir is the first step in order to accurately quantify reserves and design proper field developmen

stitial water and considered the rock as insulator. In the presence of shale the rock becomes conductive and adds excess conductivity to the sidered the rock as insulator. In the presence of shale the rock becomes conductive and adds excess conductivity to the interstitial water con ure capillary pressure data and pore-throat size distributions. These three forms of rock typing can be supported by the workflow presented i m dipping sequence with dip azimuth towards Southwest. Fracture analysis is one of the most important objectives of borehole imaging in t uence stratigraphy which recognized multiple transgressive system tracts and high stands was based upon recognition of grain size trends g tools. The acquisition of new technology logging services such as tri-axial resistivity high resolution oil-base borehole images and nuclea

eful references that will not be re-quoted here. This paper is the third and last in the series. We will show the thin beds workflow using both

al (2005). Similar patterns in production profiles with high initial production rates followed by a sharp decline have been observed across t fluid profiling stations. Mitigating the impact of mobilized solids and sand grains on formation testing and sampling operations is essentially ore Formation MicroImager (FMI*) provides electrical images that are almost insensitive to borehole conditions and offers quantitative inform n the Al-Khafji where a number of wells have been correlated and calibrated with the Tayarat Formation. In the exploration area to the nort

ns in the twentieth century (Efron 2004). In geoscience and reservoir engineering however spatial statistics has seen more extensive applic ar real-time before the wireline formation tests started. The petrophysical solution was to combine GR Spectroscopy with formation density on tool. Permeability of the sand layers was also computed and compared to that of nearby thick sands. Core data in one well was used to v

dients in the reservoir are small stress reorientation in the reservoir is small. However in high rate wells low permeability reservoirs infill pr

ation stresses play an important role in geophysical prospecting and development of oil and gas reservoirs. Both the direction and magnitud

sition relationship are given in terms of consistent units for slightly-compressible liquid flow analyses with Eqs. 3 through 5 for time flow rate

of Thebes and Mokattam Formations. Since this well NWO-1 was drilled over the peak of anticlinal structure therefore natural fractures wil ent carbonates and weathering crust. Further investigation on Pre-Jurassic reservoir of the SE West Siberia showed that production potent minant NW-SE strike direction consistent with the trend of the major faults interpreted from the seismic data. The majority of these faults are rther investigation on Pre-Jurassic reservoir of the SE West Siberia showed that production potential is mostly related to the basement lime

is the third phase introduced into a two-phase system thereby reducing the relative permeability to gas. This usually results in longer clean

s that can be found in the productive formations of the region (i.e. Huamampampa Icla and Santa Rosa). For e-log interpretation purposes eability k to select test points at the most permeable zones. However what are missing are continuous hydrocarbon type and properties lo

œeveryday NMR in a recent paper (Akkurt et al SPE 2006). Among the recommendations listed for everyday NMR was the use of T1 loggi nts is that they are extremely flexible and can be tailored to fit many different formation-evaluation applications.

ormations.

as temperature and flowing wellbore pressure are continuously measured while drilling which is not always the case. By applying inverse m ith-Shuaiba period; mainly EW faults crossing the field in its central part during the Shuaiba-Ahmadi period; small NS faults in the north EW

In recent years formation sampling and testing tools have seen the introduction of an array of downhole fluid property measurements. Thes ition of downhole fluid samples accompanied by a real time fluid analysis (DFA) while sampling. One of the methods available for downhole position relationship are given in terms of consistent units for slightly-compressible liquid flow analyses with Eqs. 3 through 5 for time flow r y in the western part of the field are â€œtar-mats comprising 10-20ft thick highly viscous oil layers; simulation has confirmed that these ta hole evaluation stage. As noted these conditions are quite challenging for formation testing. Some of these challenges particularly near we

etermine stress direction and magnitude including the use of acoustic logs. However they do need to be calibrated by direct measuremen erpretation would be overtly complex. We have developed a software tool which presents a workflow to analyze data acquired with single o k from the remaining uncertainty allows us to make informed investment decisions. An ideal FDP should not only include recommendations more complex and pressure data â€“both from wireline formation testers and production tests- is an essential item required in order to deter ESP technology and techniques to engineering teams and operational personnel for this first ESP installation in Malaysia The inception of of 470 sq. Km all onshore. Oil and gas has been exploited in Block 10 since the early 1910â€™s mainly from formations of Tertiary age ly development began in 1982/83. The cumulative production of 170MMbl of oil has been produced to date through 47 wells with 97 active pro

production from 12 zones ranging in depth from 2 800 to 10 600 feet.ï¿½Most prolific of the zones are the Grayburg and San Andres that equirements Fig. 1 illustrates the nature of such hydrocarbon accumulation by means of an offshore oil field which spans vertically about 5 ous oil production rates. Figure 1 shows a cross section of a typical thin oil rim reservoir. Fluid breakthrough has a different effect on individ atural depletion with reservoir temperatures range from 280 to 300 ï¿½F and 22 ï¿½API approximately. The field development currently con aper presents a comprehensive set of tools algorithms and frameworks (referred to with FM or FM framework in the following parts of the p remedial operations to mitigate flow assurance issues. During the Operations Efficiency cycle daily monitoring and surveillance activities t at the present time no infrastructure such as a compression system or offshore water treatment facilities is available on the platform. Majo m. Three â€œRevisit campaigns were conducted on the Betty field. The first in 1984 drilled 5 additional wells. The second campaign in 19

ed to the surface facility model. The well model surface boundary condition acts as sink or source term in a surface network which has to b ptimization operations surveillance & asset planning to uncertainty analysis and fiscal determinations. However existing work flows and ap ting oil and gas companies have started to address this problem and have started to organize multifunctional teams to better analyze their a e to a model that is acceptable within all imposed boundary conditions. History-matching is in many cases the most time consuming task in ut also causing rapid water breakthrough in high permeability layers. The shallower formations are prone to sand production so the typical

er contacts (OWCs) have significantly encroached upward leaving thin remaining oil columns and causing high water production from all of productivity and a better understanding of the factors impacting productivity layer-by-layer in the Barik and Miqrat formations. Introduc o-pressured. Economics dictate the need for hydraulically fractured completions and commingled production from multiple zones which com onal probabilities and Monte Carlo simulation such that the future information is appropriately valued today. Such a valuation is intractable u

trical anisotropy and bed boundaries (polarization horns) and read deeper than azimuthal laterolog measurements (a few feet) but this tech he Outer Moray Firth Basin. Between 2003 and 2005 several vertical appraisal wells were drilled to determine the potential of developing th s this prior work.ï¿½ Introduction The current study is a pragmatic approach of linking disparate activities which collectively can have a pro er sand-dominated depositional events a fine shale layer was deposited that separates the Upper B4 from the Lower B4 reservoir horizon. ï¿½ However the critical aspect is if bypassed reserves remain in significant amounts to be economical given the lower investment required the initial well placement study. In parallel geosteering feasibility assessment was conducted and tied to the reservoir simulation results. T ach iteration and requiring many forward reservoir simulations. A rather different approach is proposed by Lui and Jalali (2006) where stan

flow characteristics of sand filters. This combined with the equation of continuity and an equation of state for slightly compressible fluid giv effects and interference between wells. There is clearly a need for an alternative technique that allows very fast model building and executio es in existence uniqueness and stability. To remedy these problems a regularization term in the form of data-independent prior informatio model for the field. Thus any reduction in the time taken for this phase is very important to speed up the modeling process as the majority

istent with the geology in true sense. Most of the work done on this aspect considers the covariance as a measure of geological consistenc

atical Formulation The thermal model described here is based on the assumption that Darcyâ€™s law and instantaneous phase equilibrium tion formulation (IMPSAT). Furthermore different implicitness formulations may be applied to different cells which is referred to as the adap pleted interval may not contribute to production. For some horizontal wells only a small portion of the perforated interval produces. Practice

e areas with limited platform capacities. A typical horizontal well has a large perforated interval and produces from multiple formations. How

e forced to close by flowing back some of the fracturing fluid at controlled rates to prevent disturbing the proppant pack significantly. As a re d. Following the fracturing treatment a typical tight-gas well achieves its maximum gas rate within a few days after stimulation and then ex nd 7 - similar to zone 2 and 3 in being tight are best completed with selective fracture stimulation treatments. A well in this reservoir was se sary to predict the performance of hydraulically fractured well in gas condensate formations. The different approaches are being used for g ure height growth. It has also been shown that fracture growth can be arrested by weak interfaces when the effective normal stress across ncertainty. The most common way of estimating post-fracture production has been to use analytical software such as nodal analysis softw

non-linear regression method2 proposes the use of a multilayer analytical simulator (forward model) coupled with a non-linear regression alg essure ) and the classic transient testing dimensionless wellbore solutions for pseudosteady state flow expressed in terms of the pressure able fracturing models were matching with the observed pressure responses. While pumping such jobs the net pressure was high and alm st provide some recommendations it is necessary to establish fracture initiation mechanisms then estimate conditions resulting in different iences and petroleum engineering including permeability prediction (Aminian et al. 2003) fluid-properties prediction (Sultan and Al-Kaabi 2

d b show the location of South El-Manzala (SEM) field. South El-Manzala field is dissected by ENE striking low angle dip-slip fault that was length of the well. Even with coiled tubing there are practical limits of how far the well can be logged (e.g. currently of the order of 1 to 2 k

d production data measured PVT properties and average reservoir pressure. Usually it is expected that oil and gas production are measu

ffect similar to that in a thermogravitational column (Ghorayeb and Firoozabadi 2001; Nasrabadi et al. 2006). The combined effect of conve distilled from the application of ED and RSM concepts to 15 detailed reservoir studies and at different points in their project maturity spectr

ith a single control volume (e.g. see [9]) transmissibility upscaling procedures apply to a boundary between neighboring control volumes an

ral publications2 3 have addressed the recovery of oil from vugs that are connected to the fracture system. This work concerns isolated vu ng questions raised. In this paper we focus on the modeling of shear fractures which are generated by structural deformation accompanied

her very large (parallel) computing effort or coarsening the model through upscaling. Time step length has to satisfy CFL condition for the ex mpressible dual porosity simulation have been observed. At the same time the possibility to further improvement of the computational effic are stored in matrix blocks and flow occurs in the fractures. It is recognized that state-of-the-art simulation methods based upon dual-porosi

The PUNQ-S3 reservoir represents a synthetic model based on an actual reservoir (Floris et al. 2001; Barker et al. 2001). The problem was

f sea water which is rich in sulphate ions is injected into a reservoir with formation water this is rich in barium ions then barium sulphate m

ing a frozen velocity field. As the name of the method suggests the 3D transport equations for saturations are transformed into a set of 1D modynamic characteristics and equilibrium surfaces. This requires the fulfillment of numerous iteration processes during the calculation ste ng these opportunities in real bottom line results. The goal of the study is to generate sound technical arguments to formulate an innovative

e data with the recorded pressure data are compared. Such dominating patterns can be extracted by means of a mathematical tool called s within a well. Thus while flow in an annulus could be modeled the well segment topology had to be such that there was only one flowpath

a respectively. Reservoirs flow properties range between fracture to matrix dominated flow. Based on available fluid sample analysis from

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½(2) Eq. 2 is commonly known as the Forchheimer equation. In the discussion of elow the oil zone the location at which oil saturation becomes irreducible) SOR (as depth increases below the oil zone the location where was to be conducted through the production tubing to access the by-passed hydrocarbons. The Thamama Limestone group is highly fractur aningful results that could be used to formulate a drilling program one of this being the stress orientation of the area. This is a significant an ip fields where many but probably not all of the Smart Field Technologies have been deployed.ï¿½The development and deployment of th

States federal lands and waters north of the Brooks Range foothills which have been explored to a greater or lesser degree. The ANS ext s paper. Both types of models assume a linear-elastic mechanical behavior. Therefore the response of the cement sheath to strain is dete

ff operations successfully increased the oil production. The purpose of this paper is to demonstrate the potential of the through-casing resis pletion solution integrating flow control of the lateral and main bores together with natural gas lift was implemented on the Troll and Vestflank he field. Studies indicated that water flood with artificial lift would significantly improve the oil recovery in the Mauddud Formation. The focus with a new much more powerful tractor.ï¿½ Examples using both types of conveyance are given here. Production log interpretation in hori

hese are low permeability rocks drilled with oil base mud containing oils that are very close to saturation pressure. We therefore have to de

the sampling technique and the type of drilling mud used in the reservoir zone. Oil-based drilling muds will usually provide good-quality wate t on other dependant variables to allow an optimized production management loop. In other words â€œsmart well data develops a new inte hydraulic fracture stimulations are complex and frequently monitored for induced seismicity (Cipolla et al. 2005). We have analyzed one h 00mD) and unlock its large reserve base in the low-permeability (0.001 â€“ 1mD) Cambro-Ordovician reservoirs specifically the Quartzite o

their Joslyn field in 2004 as Phase I of the reservoir development. During the completion of the SAGD pair of wells in Phase I a fiber optic be considered in evaluating the transport capability of a system for moving liquids upward in the well.ï¿½ï¿½ These are the criteria for mov g the transport capability of a system for moving liquids upward in the well. These are the criteria for moving the liquid film along the wall of on causing incorrect temperature log interpretations while the well is responding to transient shut-in effects. The introduction of permanen

s introduces the same type of uncertainty because of varying flow conditions as found in the test-separator method.

eed to be included in the Production Target definition. The answer to the second question is more complicated as it needs further investigat ses in stratified flow. One approach used is a bulk tracer or radioactive marker technique that is only sensitive to one of the phases anothe throws considerably larger than the Mauddud thickness. In the past SBHP and pressure transient data have been acquired at some wells and pressure conditions.ï¿½ They may start to precipitate once the stability of the colloidal suspension is destabilized which is caused by ne the wells in the field of scope and show how we were able to optimize the well recovery. 1) FIELD GENERAL INFORMATION NR field w pletion and communication information whereas others may seek information on the precise nature of the hydrocarbon fluids and water in t LT) log which again results in loss of production because the well is often shut-in for some time and also needs to be flowed at a reduced r hat respond to different expressions of geomechanical deformation associated directly with steam injection. In some fields this geomechan servoirs are part of a multilayered sandstone anticline with approximately 5 billion barrels of reserves in place. The fieldâ€™s north flank dip when 1 467 wells were installed. A large percentage of these subsea wells will require sand control and multistage completions. Despite th

other side of the process from wellhead to production separator to reconcile both data sources and detect any production measurement e ntal flow environments specifically wells with loose sand and/or debris that potentially damage sensitive spinner and probe sensors are not

onitoring and maintenance enhanced/improved oil recovery evaluation of bypassed oil identification of fluid movement etc. depends prima

ng the surveys in a time-lapse mode. As part of this project lab tests were conducted to choose a material that would limit the attenuation injection saturation and pressure data will be used to calibrate the simulation model. The ultimate goal is to design an optimum field devel 10 years. Wells in this basin are now trending towards a much higher percentage being cased and perforated multizone completions rather gth fractures are classified as butt cleats. As a result of geometry and connectivity variation significant face and butt cleat permeability aniso eams are highly susceptible to near wellbore permeability reduction damage or skin. This is either caused by invasion damage from the drill treatments. Before 1997 Barnett shale wells were completed with massive hydraulic-fracture treatments consisting of crosslinked gelled fl tment (e.g. low pumping rates are insufficient for carrying proppant).ï¿½ Small stages of high viscosity fluids may then be used to facilitate

commodity prices.ï¿½ By 1996 the well count exceeded 300. In 1997 Mitchell Energy began to experiment with Slickwater stimulation treat and Frantz et al. (2005). In order to achieve economical production and enhance productivity a large number of horizontal wells have been y examined several completion strategies and our simulation model calculated the impact of these strategies on oil production and SOR in t edded with the shale through natural fractures or from the shale matrix itself. In some cases natural fractures are healed by a mineral fillin f new wells where the technique enables stimulation of larger wellbore intervals when used in the same fashion as for re-fracture stimulatio als rather than the matrix framework itself. Hence the framework of the sandstone is not significantly altered by the acidizing process. Since

Meanwhile the high pressure and appreciable velocity air leaving the venturi tube drives an Air generator which produces power. This powe S and JS reservoirs). It contains more than 50 distinct oil pools. The reservoirs consist of terrigenous rocks of continental and shallow-water

the number of layers fractured during a single stage. Stimulating multiple layers in a single stage is not ideal since layers with lower fractur the production test showed a 3-fold increment in production compared to the previous best producers in the field. The skin estimation base cessarily restricted to use for vertical wells only.ï¿½ In spite of this fact it has been noted that laboratory experiments have clearly demonstr cessarily restricted to use for vertical wells only.ï¿½ In spite of this fact it has been noted that laboratory experiments have clearly demonstr of this project was to drill a tri-lateral well for maximum reservoir contact in an area where fracture density was interpreted to be low and ther

concept of locating missed pockets of oil goes back to Hurst (1979) and the concept of controlling production was suggested by Rinaldi (19 ed to efficient realtime production optimization.

veness of these fluids making it impossible to perform matrix acidification when an ESP has been installed with a conventional completion utline of the three main classes of SA methodology. We define terminology; in particular the terms â€œsystem and â€œcomponents. We

ermine the impact on well performance versus continued use of diesel based frac fluids. Various fracture fluid systems were reviewed and a

e Field. The â€œBar Trend is a very consistently developed thick clean dolomite zone of 5 to 16 feet with porosity development of 5 to 14 p proppant fracture treatments are typically pumped. These fracture treatments are carried out with low polymer concentration non-crosslink

e scope of fiber application has vastly expanded with additional benefits of degradable fiber-laden slurries being realized as application exp d reduce the drawdown to produce. In practice it is understood that oil and gas reservoirs are very complicated in their wettability. Almost ne ates of hydraulic fracture geometry are available. It has been observed that sometimes the fracture is more contained in height than predict duced waters by recycling and using them as completion and fracture fluids. Time on location and cost of associated equipment is always a ses for flowback water in the E&P industry is both an economic as well as an environmental issue. In an effort to circumvent some of the ex es were introduced to further understand the production enhancement opportunity.ï¿½ This paper focuses on three major formations (Figur m to achieve better zone coverage. After the treatment was performed a screen was washed down through the gravel remaining in the cas en outs. The fracture height growth out of the pay zone and the reduced proppant mass placed because of the premature treatment termin osts. Since the oil could not be recovered economically work to develop these reservoirs was suspended for not saying abandoned. In 200 y several stacked reservoir that initially had different pressures regimes but presently most of them have the same sub hydrostatic pressu nstructed at comparable costs to vertical wells while offering the advantage of higher production rates and better access to reserves. Often t

y in future applications.

nhole will be diverted into each layer depending on the resistance to flow. Depleted intervals low pressure intervals and intervals that fract This leads to early packoff before the desired volume of proppant is placed in the fracture. In the second case when TSO occurs too late th he encapsulated material uses a polyelectrolyte to disrupt the surfactant micelles and lower the fluid viscosity even in dry gas wells where

n4 to see several vertically discrete sandstone reservoir zones in a single well where sandstones may have different trends and detrital and

osition within the reservoir in addition to accelerating oil recovery. One viable approach is to improve oil production. Improved oil production roduction for a long period of time. However the existence of yield stress effect remained controversial until the first publication9 resulting fr ars and lagoonal muds.ï¿½ Storm cuts and organic burrowing also characterize the depositional environment.2ï¿½ The thickness of the Co

he absolute fracture azimuth may be considerable even for wells only slightly deviating from expected positions. Fracture geometry (mainly i

fracture faces may be crushed and eventually at high closure stress the lasting fracture conductivity may depend more on rock strength t ds and Reservoir Description The Priobskoe field one of the largest oilfields in the world is located in Western Siberia. The reservoirs unde mation interval. Although this analysis gave indications of which parts of the interval had accepted fluid it didnot give the desired information

ilable testing practices was necessary. Also the methods of determining reservoir pressure fluid composition and production prediction th ctivity in single-phase flow:stress on the proppant and type of proppant. Thus apparent proppant permeability will vary with distance fro

andidate for acid fracturing treatment. The K-formation is also classified as a moderately permeable to tight gas reservoir which has a poro

gle observation well such that the seismic radiation is measured only in a limited direction. This limited sampling of the radiation pattern cer

ection causing the fracture to turn towards the original fracture orientation as illustrated in Fig. 1. Siebrits et al.3 further extended this work ion and growth were based on either Khristianovich model [1] or Perkins (PKN) model [2]. Both models rely heavily on the elastic (or poroe ons to 150-300 tons1. The proppant size has also been increased to enhance conductivity sometimes using sizes as large as 10/14 mesh.

n-up behavior. Special effort was undertaken to identify and measure directly any flow initiation gradient (FIG) or yield stress effect. A mod a subsea production system back to a Floating Production Storage and Offloading (FPSO) unit. Water injection was required from day one ection rates improvement in the selectivity of water injection profile reducing of wells spacing in fields borders and specially a massive cam studies10 11 were concerned with proving that hydraulic fractures could cross natural fractures in their path. Later studies were concerned d at the time of writing of this paper the majority of them in the Scandinavian sector of the North Sea. Various papers have discussed applic ds. C&P-1 Well: This well was completed in June 2002 targeting 23U/L & 24U-sands in Amherstia at a measured depth of 12 290-13 566se advancements to such an extent that drilling thousands of feet through a thinly bedded hydrocarbon reservoir is not a challenge anymore e advancements to such an extent that drilling thousands of feet through a thinly bedded hydrocarbon reservoir is not a challenge anymore tones. These formations are classified into four main zones: D E F and G. The G reservoir is characterized by its low permeability. Its pro es range from 5 to 10 mD. Three-D seismic data show the Shu'aiba reservoir to contain a number of faults. These faults and fractures have e. It is concluded that Inflow Control Device proven technology is beneficial and successful in Bloque 15 Ecuadorï¿½ï¿½ and its applicatio

al. 2002; Kharghoria 2002). Passive control may be effective if the reservoir geology and drive mechanisms are well understood so that inf o recreate fracture propagation observed at field scale even though a great difference of scales exists between fractures generated in labo

magnetic resonance (NMR) logs have been increasingly used over recent years to help determine an accurate reservoir pay thickness (Ref. he other hand high strength rock is not expected to sand and therefore does not require sand control. Reservoirs with rock strength from m ogeneity of the rock.ï¿½ In a carbonate reservoir the heterogeneity occurs from the deposition and diagenic processes through the geolog which confirms the progressive erosion of the Devonian stratigraphic succession towards the east-northeast direction. The petrophysical c st producing well in Resak field with stable production at 49.8 MMSCCF/D. Introduction This gas producer well was drilled in March 2004 a its importance is often overlooked during completion operations. It was recognized that perforating was an area that could be improved in on practices to minimize skin effect from drilling and completion fluid invasion and by minimizing perforating-induced damage. Permeability ing from the initiated fracture into the PFP) at an achievable fracture initiation pressure. Table 1 shows the tradeoffs between different perfo pressure of more than 1000 psig until they had been acid stimulated. These wells often require several runs of perforating on wireline to c sess the quality of the completion. Pressure transient test is typically conducted in a way that surface flow rate is maintained in a constant o though these conventional methods are deemed efficient in the industry incidents that have a high impact on cost deliverability include P ctiveness of both job risk management and system development. An analytical model of perforating gun swell can help risk management in

tion as the case may be).

ent of the world's first Electric Submersible Pump (ESP) designed for use in ultra deep water. Due to the geological complexity (resulting fro

stry.1ï¿½ Sand control measures in unconsolidated formations without impairing well productivity have been a challenging task from both te 0) ranging from 2 to 16 and the fines content from 1 to 15%. Overall the formation sands are poor to well sorted with low to high fines conten

ion option except in fine sand environments. Due to the need to control fine sand (D50 < 60 Î¼m) without affecting the well performance e wash pipe for returns to surface. Such pressure rise can be problematic in cases where the operating window between downhole circulati

/oil-based drilling fluid (S/OB) due to advantages it offers over water-based fluids. These include higher rate of penetration excellent shale ction may also cause catastrophic failure of the wellbore and/or well and surface equipment. The production of sand is a worldwide problem roduction may also cause catastrophic failure of the wellbore and/or well and surface equipment. The production of sand is a worldwide pro he wells will require some form of sand control measure installed in the reservoir section to prevent sand production. For the long horizonta compared to the formation strength. The high stresses caused wormhole-like failure propagating from the producer to the injector. This cha -placement options. In the order of low-to-high skin the options are: Frac-Pack High Rate Water Pack (HRWP) and Gravel-pack1-3. Each

1984 most wells in Sarir field have been periodically cleaned as a precaution against sanding-related problems. AGOCO the field operato ods used. The application and comparison also disclosed that the approach was not only able to provide results that closely matched field e ompleted well AA04 was reported to have fill up to 1094 ft from TD in September 1971 in a period of 18 months. Sanding in the cased and t al. 1995; Skjaerstein et al. 1997). Despite these inconsistent field observations it is generally accepted that sand-production risk increases

d in the Norwegian Sea. Introduction Sand production is a common and very damaging problem in hydrocarbon production from clastic sal wells (study wells) were made available for this study. Mechanical properties of the reservoir sandstones and shales were established b nding on the viscosifiying agent these systems can be divided into two main categories: polymer-based and surfactant-based. Acid-soluble non-uniformly etched by the acid while the strength of the rock is still maintained at high levels to withstand the closure stress. At low closur e depositional and diagenetic history of the basin. Reservoir heterogeneity complicates every aspect of a wellâ€™s life from drilling to com

t few years mostly in the Khuff B and C reservoirs. The acid fracturing stimulation program has achieved great success in vertical gas produ the viscoelastic diverting acid system and compares their results with those of the conventional methods used previously. Discussion B n. There are certain carbonate reservoirs and completion scenarios that require an optimized fluid and placement strategy such as forma

mineral compositions of the targeted simulation zones but also on nature location and extent of the damage materials in the near wellbore

cks make organic acids such as formic and acetic potentially attractive for stimulating high temperature wells. Organic acids have been us

dolomite (CaMg(CO3)2).ï¿½ Their reaction products are soluble in the spent hydrochloric acid.ï¿½ However the physics and engineering a ut required further technological improvements. The gas operators in contrast have implemented hydraulic fracturing mainly in mid-temper uction.ï¿½ Several experimental and modeling studieson the response of carbonate cores to various acids under varying conditions of injec or area about restimulation and formulate a reservoir specific selection criteria that will capture the key ingredients for the success of restim build up on the Muddy Formation that showed lower than expected reservoir pressure and permeability it was decided to fracture stimulate

ddle Jurassic; II-T III-T and VI-T (gas-oil) in the Triassic. Jurassic productive horizons are found at depths of 2179â€“2320 m and Triassic

is pulled out and each particular interval can be accessed seperately by using a straddle packer. This approach will not only involve the wor e expense is considerably higher if the communication problem is discovered after the well is drilled and the rig has left location. Because o d valve Y is closed. The closing of the downhole valve reduces the effective wellbore storage and increases the chance of capturing the data well schematic in Figure 1). The main purpose of the well is to understand the contribution of the fractures and determine to which extent th etion would be the one that results in the maximum economic benefit to the operator. In practice the optimum completion design and opera

ynthesis (TDS) technique for analyzing log-log pressure and pressure derivative plots. TDS uses analytical equations to determine reservoi aneous source during which pressure may diffuse to a long distance. Therefore to understand the radius of investigation first we look at the hanges in pressure skin and permeability for real time optimization. Introduction One of the main objectives of every operating company is ist of the previous deconvolution algorithms can be found in von Schroeter et al. (2004). The primary objective of applying pressure/rate de

coefficient by separating the mechanical skin component from the total skin factor (st ). All these multirate methods of interpretation require esponse to the growing maturity of the field. A remarkably wide variety of means and techniques have been deployed throughout its develop last few years to tackle the following issues: Mitigation of the carry over in gas line out of conventional separator Increasing need for high

ecreasing GVF. The accurate determination of liquid rates by wet-gas meters is restricted in range. The application and performance of mul ements are used to monitor well production over time. Introduction Accuracy of the flow test results performed by the existing test separator

all manufacturers are using one or several Venturi and most of the time coupled with a density nuclear measurement. The fraction measure during a simulation study due to the large uncertainties associated with reservoir properties in flow simulation models particularly for permea

typically smoothed by subjectively choosing the points used in the calculation a sufficient distance from the point of interest.11 Regardless o Control Completion A second field experiment utilized a 21-electrode array deployed in a horizontal well that was drilled in a thin oil column

th scale of a meter. Cement with a high w/c ratio however could have a much higher permeability less resistance to CO2 aggression and ilities for determining upper bounds to acceptable fluid pressure changes in both the injectivity at the well(s) and the storage capacity of a re

and more knowledge in the area is required. The second scenario geological CO2 storage is currently available through several commercia dissolves in brine and reacts with water forming an acid and H2O dissolves or vaporizes into CO2 removing water from the brine and incre ection regime as well as decisions on the monitoring of long-term CO2 migration after injection. ning that global average temperatures are increasing at unprecedented rates. In parallel CO2 emissions from anthropogenic sources hav pacity and injectivity containment is agreed to be a primary function in geological storage performance. As evidenced by oil gas and even

stem (DIACS) completion with tree separate zones operated by three hydraulically controlled flow valves. This is the longest DIACS comp but all were understood to have been considered at that time to be disappointing. The previous operator then decided to abandon any furth

an reefs were described by Ingels (1963). Joudry (1969) published research on potential dolomitization mechanisms in the Southern Michig ovide an efficient source for enhanced oil recovery projects. On average the global risk of encountering >1% concentrations of CO2 in a ga he school of hard knocks. Typically a â€œRule of Thumb is used and a line is drawn (Fig. 2). Many South Texas partners make their decis n medium/low permeability gas-condensate reservoirs.ï¿½ For actual field implementation a more detailed reservoir simulation study wit these reservoirs and increase their recovery factors. as utilized this combination of GOGD and localized waterflood1.

ally factors making strong and widespread alteration of basement rocks. The basement rocks have been fractured broken and catalazited orary straddle system was created using two through tubing inflatable packers therefore isolating the top and bottom perforated zones in or per addresses the planning operational and the learning from the through-tubing water shutoff campaign successfully carried out on wells w

n. Most of the wells in this particular area are experiencing water cut of 90% or higher. Problem Scope The main production challenges in s and limitations. The friction coefficients were estimated based on the available friction data in offset wells.

increasingly important as water depths increase. This paper describes a production assurance risk study based on asphaltene precipitation distribution and the position of the interface resulting in different flow characteristics such as velocities holdup profiles and pressure grad the gradual flow pattern transitions from stratified flow to dispersed flow are observed and characterized. The water holdups and pressure example the production rate can be reduced to avoid coning and establish production below the critical rate in the moment first signs of b tional teams to better analyze their assets to improve operations and optimize production. However proper workflows and technology must enditure and reservoir appraisal is limited in the case of marginal fields. Reducing the number of flowlines by commingling streams from se on components. As such the model prediction is generally not accurate. Quality experimental data are required to â€œtune theoretical mod hydrocarbon producer. Corrosion costs the American industry nearly $200 billion a year of which the oil industry picks up more than its fair fluid information. DFA tools today are used for such applications as: to evaluate downhole fluid sample contamination2 to measure Gas-O

al reservoir gas and reservoir temperature. The data set included laboratory studies of 190 gas-condensate samples. This is the first propo ent of the gas phase can be defined as a sole function of pressure called vaporized oil-gas ratio Rv (also referred to as rs2).ï¿½ This functio tage.[2 11] DFA is an objective and a vision ultimately to provide a continuous downhole fluid log; it is performed by specific tools such as th ultimate recovery and project economics. In aging reservoirs fluid movements are of constant focus and routine cased hole logs are comm e to delineate compartmentalization is to determine pressure communication. Recent works have shown that a single pressure gradient iden

water prospects and other capital-intensive exploration and production projects understanding the nature of hydrocarbon fluids in terms of c

ng to evaluate and these sections can still have considerable hydrocarbon potential. Although OBM can be challenging for contamination q ine if it will be possible to access existing producing facilities or not and thus the feasibility of a project. The accurate measurement of H2S c

tional grading in most systems. In this study we will assume that thermal diffusion does not play a dominant role in distributing hydrocarbon ck kitchen during trap filling constrained by the capacity of the trap while the range of GOR and the bubble point of oil in a trap reflect the pr uid types. pling with subsequent laboratory analysis is somewhat risky because a variation of fluid properties measured in separate sample bottles mi od data quality control and data analysis since pressure measurement problems supercharging wettability effects and depth measureme ustrated in the literature [3] [4] [5]. With increased drilling in HPHT (high pressure high temperature) and deep offshore settings more and BM. The hydrocarbon sample may become useless if the contamination is too high (typically above 10 to 15% for crude oils or 1 to 3% for g

und on the basis of anomalies and departures of the measured data from the modelled pressure and fluid gradients. Introduction Composi the higher concentration of aromatic molecules and is typically larger for heavier oils. As a result high-density hydrocarbons which have a es are obtained and allows an unlimited number of zones to be evaluated in a â€œfluid scanning mode. The sampling program can be optim

ze first.ï¿½ On the other hand if the oil is heavy and not very volatile then the water will boil away first.ï¿½ If heat continues to be added to t y and corrosion products together with surface-active materials such as asphaltenes and naphthenic acids also enhance the stability of e

they rely increasingly on numerical simulators tuned to pressure/volume/temperature (PVT) laboratory measurements. The presence of co ere was any undesirable gas-liquid segregation in the tool flowline upstream of the sampling bottles. Determination of the drawdown thresh and gas properties. This simple approach leads to acceptable metrological results up to 1500 psia. The upper limit can be extended to 5000 er as the analysis of some condensate to gas ratio between chokes is still ongoing at this stage and will be presented in a separate article. 961; Smith et al. 1970; Chatelain et al. 1976; Dill and Keeney 1978; Crowe et al. 1988; Fredd and Fogler 1998; Huang et al. 2000; Nas ed since presence of iron components as well as other damageinducing elements such as biomass has been revealed on lab analyses. S mhole temperature and pump rate used in their execution.[Fredd 1999]ï¿½ Sandstone formations are generally acid-insoluble (being largely This is further complicated with the availability of fresh or low-salinity water in some areas of the world due to the very large volume require

e experimental set-up in the authorsâ€™ laboratory allows the single-shot perforating of 7-in. diameter 18-in. length samples under downho n tunnel.ï¿½For liquid-saturated rocks the porosity (and density) of the damaged zone is close to that of undamaged rock; for gas-saturate cales are without exception the inorganic oilfield scales that are found in oil wells of Western Siberia. The most common scale deposits foun thermal stability at formation temperature and; have long lasting retention characteristics to ensure sufficient protection time. The efficie

Well Integrity Management System (WIMS)1 was put in place by ZADCO that helps to identify prevent and solve all the problems related t njection.ï¿½From the outset it was recognised by BP that the formation water / injection water mix would lead to a severe scaling tendenc g the regions in a reservoir for efficient history matching. The proposed approach is then demonstrated on three case studies. Description o

cell geological models incorporating highly variable heterogeneities and a long production history in very few hours (sometimes minutes)2 imbibition capillary hysteresis spreading coefficient ranges and high productivity characteristics of the Cantarell Field that will be discussed eillance system for the entire asset life.ï¿½ In onshore brown fields however the implementation of automatic engineering workflows rema w permeability sub-units within the reservoir and 3) determine pressure support due to pattern injection. The pilot will also address the issue y- pressured at the time of discovery. al and multilateral wells and the development of artificial lift systems resulting in new production targets of 2 000 BOPD per well compared

ve-induced pyrolysis is possible if the raw material is mixed with an effective receptor of microwave energy such as carbon (El Harfi et al 2

with the separation of Africa from South America trend. This west and central African Rift System extends from the Benue Trough in Nigeria line lagoons and sabkhas. The shallowing-upward cycles are capped by mud-dominated rocks hardgrounds and exposure surfaces. The a mud filtrate invasion).ï¿½ Introduction There are large reserves and resources of heavy oil present on the Eastern European (Russian) an

ipeline. Seven horizontals have been drilled out of which four of them are in Aradeiba formation and three are placed in Bentiu fiormation.

these reserves are developed thermally. The Nukhul formation is the only reservoir in the field that can be cold produced because of its hig

hloric acid (HCl) and HF at various concentrations. Examples of these traditional HCl:HF formulations include 6:1.5 and 12:3 mud acid syste

ndant information in open literature on examples of graded columns and analyses of the forces thought to be responsible for these observe

lars will rise significantly and as it will be shown later a significantly crosslinked fluid cannot be sheared without permanent damage to the

ary target is the fractured granite basement which is typically oil saturated with a gas cap. The secondary target is the lower Miocene and Ol ion intervals and complex mineralogy. The benefits of the new sandstone acidizing fluid which utilizes a novel chemistry include simplifie o be the major reason that sandstone-acidizing jobs fail to produce the anticipated decrease in skin especially at temperatures > 150ï¿½F chnique has been adopted since many years being in most cases the only method of achieving commercial production levels. A typical Sa been used to clean up water and condensate blocks.[1 2 11-13] However solvent based clean up is temporary as the well has to be retrea wireline logs accurately. In addition analysis related to various environmental aspects like concentration of organic compounds and heavy m

Wood Mackenzie as stating that in 2003 17% of gas was tight gas and 73% was conventional. In 2003 shale accounted for 2% and the rem

history as well as fracturing of sidetracks and fracturing of infill drilled wells are a common practice nowadays. The oilfields are typically dev 4. Recent efforts have been given to map out the pattern of induced fracture networks based on observed microseismic event distribution 13

to very poor reservoir characteristic this level was abandoned and the well was recompleted on the shallower reservoir B4. The low permea uctivity from horizontal wells that are completed open-hole. This opens up a window of hope for the dilemma of many horizontal wells that h wi Oolite section. The Ratawi Oolite in SF is characterized as a thick porous interval with good hydrocarbon saturation a clearly defined o nce and used for forecasting wells and field performance for our clients. Since completion of the integrated studies step-out and infill wells d during late Cretaceous through Tertiary time when the North Horn through Duchesne River Formations were deposited.ï¿½ The basin is servoirs are poorly correlatable over a large area. The sandstones are fine- to medium-grained with porosity ranging from 5 to 14% and pe e completion engineer often uses to assess whether a zone should be attempted for stimulation is to perforate and flow the well. This luxury

and fluids and their heterogeneities. The most significantly innovative development of formation testing technologies is Downhole Fluid Ana ds in the world producing from Cambrian-age sandstone reservoirs with porosities ranging between 3 and 10 PU and matrix permeabilities t eservoirs mandates equally tight well spacing driven by reservoir connectivity permeability well costs and gas prices. Tight gas fields typica

ation without influence from the mudâ€™s hydrostatic pressure. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½c.ï¿½ï¿½ï¿½ The southern area is waterflooded peripherally while the central area is line-drive oriented to avoid premature watering out of production we

massive deposit associated with a gigantic natural reservoir in the Riphean multiple-aged mostly dolomitic vugular-fractured reservoirs co

been reported that a reduction in oil wetness is accompanied by a reduction in irreducible oil saturation (under primary imbibition) and a co

ghâ€™s in understanding of the reservoir complexities and behaviour and this has resulted into a more integrated approach to the manage

d predictable mental errors. In the case of oil and gas exploration and production such biases may possibly lead to very damaging mistake how we remember and recall certain information. An example is hindsight bias (â€œI knew it all along) which can affect judgment elicitation

ed and implemented. In addition many of these reservoirs exhibit variable initial saturations by virtue of being located at different heights (a servoir management. Core experiment open hole wireline logging wireline formation tester pressure build up injection/fall off test and pro be distinguished and this technique has been successfully applied to Gulf Carbonates3. This is of particular interest for carbonate as it is w water. The basin is divided into sub basins by fault-controlled ridges. Sediments accumulated in sub basins more than 5 km thick.

and optimization of production strategies. Formation-tester tools have proved to be an effective way to obtain reservoir-fluid samples for PVT y alter well productivity ultimate recovery and project economics. In aging reservoirs fluid movements are of constant focus and routine ca on would also help in designing a water injection program for such reservoirs. This study uses an integrated approach using the NMR and t were defined and the water saturation in the 3 dimensional spaces was modeled through saturation height function for each of the reservoir ma ray measurements is located only 5 ft above the bottom of the tool. The gamma ray detector uses a very large sodium iodide crystal to a and design proper field development scenarios. Porosity heterogeneities within complex carbonate sequences can cause the potential of a

and adds excess conductivity to the interstitial water conductivity so more than thirty shaly sand models have been developed in the literat onductivity to the interstitial water conductivity so more than thirty shaly sand models have been developed in the literature to get accurate w pported by the workflow presented in this paper and in addition to these methods there is potential to examine a new form of rock typing b t objectives of borehole imaging in the study well. Borehole images were used to identify open and closed fractures. Sand Count analysis p upon recognition of grain size trends bioturbation and surfaces in the core.ï¿½ The transgressive system tracts are characterized by highly oil-base borehole images and nuclear magnetic resonance (NMR) logs as well as acquiring rotary and fullbore cores has increased over rec

w the thin beds workflow using both 3D NMR and 3D induction data. Combining the two dataset provides useful check points to ensure the b

ecline have been observed across the majority of both hydraulically fractured and conventional wells in Hassi Messaoud field. In the majori d sampling operations is essentially a two step process. The first step is to prevent solids mobilization or to limit the amount of production o ditions and offers quantitative information that is particularly useful for fracture analysis. The resulting data are valuable not only for geome n. In the exploration area to the north and northeast of the Al-Khafji field sinuous shaped channel features may be interpreted as possible s

stics has seen more extensive applications in the last half century (Matheron 1962 1965 Journel and Huijbregts 1978 Cressie 1991 Chiles Spectroscopy with formation density and resistivity to provide a rapid and robust evaluation of clay volume porosity hydrocarbon saturatio Core data in one well was used to validate NMR detection porosity permeability and net sand thickness. Introduction Thin beds evaluatio

low permeability reservoirs infill production wells or injection wells for improved oil recovery high pressure gradients can lead to significan

irs. Both the direction and magnitude of these stresses are required in (a) planning for borehole stability during directional drilling (b) hydra

h Eqs. 3 through 5 for time flow rate and wellbore pressure respectively.ï¿½ In the case of an unfractured vertical well the system charact

cture therefore natural fractures will be prone to be discovered due to the peak of folding is considered as one of the highest strain point. T beria showed that production potential is mostly related to the basement limestones that have been significantly affected with secondary pro data. The majority of these faults are closed in nature. mostly related to the basement limestones that have been significantly affected with secondary processes such as dolomitization leaching

s. This usually results in longer cleanup times especially in tight formations. iii. Fines migration â€“ another reason for near wellbore format

a). For e-log interpretation purposes we have classified lithology of the Devonian formations under three main petrofacies: a) quartzitic sand hydrocarbon type and properties logs. For example it is impossible to detect compositionally graded oils from Î¦ Sw and k logs and theref

eryday NMR was the use of T1 logging for porosity where the longest wait time used is approximately 1.5 times the longest desired T1 valu cations.

ays the case. By applying inverse modeling methods (assuming reasonably accurate data) it is now possible to determine reservoir param iod; small NS faults in the north EW trend en-echelon faults in the centre NW-SE faults with a large extension in the south-west part of the

e fluid property measurements. These include optical absorption spectroscopy optical reflectance fluorescence and a few other non-optica the methods available for downhole fluid sampling is via a wireline formation testing and sampling tool (WFT). With current technology it is with Eqs. 3 through 5 for time flow rate and wellbore pressure respectively. In the case of an unfractured vertical well the system characte mulation has confirmed that these tar-mats adversely affect vertical reservoir connectivity. The reservoir comprises clean fluvial reservoir sa ese challenges particularly near wellbore formation alteration have been studied using a multi-probe wireline formation tester (Ayan et al. 2

be calibrated by direct measurements. In this paper the first micro-fracturing operation conducted in western Siberia Russia using a WFT analyze data acquired with single or multiprobe formation testers. The software consists of a new mathematical model coupled with non-lin d not only include recommendations for an optimum development strategy with its implementation plan but the estimated risks involved in e ential item required in order to determine these key parameters. Moreover pressure data complemented with downhole fluid analysis and s llation in Malaysia The inception of this pilot project is considered an important milestone in PCSBâ€™s effort to establish an alternative a nly from formations of Tertiary age lying at depths ranging from 500 ft to 7 000 ft. As of today there are in excess of 5 600 wells drilled in Blo e through 47 wells with 97 active production strings.ï¿½ The field comprises multiple stacked reservoirs in unconsolidated sand. Gravel pac

the Grayburg and San Andres that produce from depths between 2 800 feet and 3 400 feet. CMC / IPMâ€™s performance as the opera field which spans vertically about 5 500 ft with more than 165 individual reservoirs. Existing wellbore trajectories are shown as lines; oil-be ough has a different effect on individual well production depending on the fluids and well type. Highly deviated or horizontal wells experienc The field development currently consists of 96 wells (88 active 5 inactive and 3 abandoned wells) which produce from two separated reser ework in the following parts of the paper) enabling the management functionality required by most conventional fields. Extensibility and fle onitoring and surveillance activities take place based on high-frequency field data collected through SCADA systems. To achieve optimal op es is available on the platform. Major changes would have to be implemented prior to any secondary or tertiary recovery method and would al wells. The second campaign in 1988 drilled 10 additional wells and worked over two existing wells. The third revisit was in 1994 to sidetr

n a surface network which has to be balanced to account for varying fluid flow and pressure conditions in every well in the system. Their in However existing work flows and applications will have to change. The questions are by how much by when at what cost and with what tional teams to better analyze their assets to improve operations and optimize production. However proper workflows and technology must ses the most time consuming task in integrated study workflows.ï¿½ It involves the calibration of the static model to dynamic data and it is t e to sand production so the typical completions are internal gravel packs inside a 95/8-in casing producing through SSDs into 27/8 in or 3

ng high water production from all of the existing wells. Due to reservoir heterogeneity some of the reservoirs exhibit uneven strength of aqu rik and Miqrat formations. Introduction Because much has been published on this field during its development in this paper we divert fro ction from multiple zones which complicates the production data analysis. Due to the low permeability the average reservoir pressure cann day. Such a valuation is intractable using existing deterministic or non-probabilistic numerical modeling schemes. We demonstrate the conc

asurements (a few feet) but this technology typically gives poor well placement results (see figure 1) especially in thin reservoir targets. A n ermine the potential of developing the Brenda field. An initial appraisal well drilled in 1990 by a major oil and gas company indicated a 22 ft t ies which collectively can have a pronounced impact on the efficiency of reservoir drainage and recovery.ï¿½Integration of these activities rom the Lower B4 reservoir horizon. The original mini-basin appears to have been uplifted by deeper salt intrusion leaving the present rese given the lower investment required? This uncertainty makes unlocking the potentials of a brown field is still a reinforcing process.ï¿½ Wh o the reservoir simulation results. These were the basis for the subsurface team to determine the most suitable wellbore trajectories and co by Lui and Jalali (2006) where standard reservoir models are transformed to maps of production potential to screen regions that are most f

ate for slightly compressible fluid gives the diffusivity equation which is the equation for pressure diffusion in porous medium.ï¿½ Solutio very fast model building and execution similar to a material balance or decline curve technique but which is based on solving the same set of data-independent prior information is generally added to the objective function in the inverse problem. Two different approaches to incorp e modeling process as the majority of the development plans should be based on examining it on the model before accepting it for practi

a measure of geological consistency which are insufficient to account forï¿½ strongly connected curvi-linear geological objects such as cha

and instantaneous phase equilibrium are valid. It is also assumed that the aqueous phase contains no components that partition into either ells which is referred to as the adaptive implicit method (AIM). The discretization used for flow and transport terms in the equations. For ex erforated interval produces. Practices have been reported to optimize horizontal well placement drilling completion and stimulation for prod

duces from multiple formations. However there are various factors that may cause part of the perforated interval to not contribute to produc

proppant pack significantly. As a result hydraulic fractures contain partially broken fracturing fluid and residues remain after the breaker re w days after stimulation and then experiences a rapid production decline. Some tight-gas wells in contrast do not show such obvious prod ents. A well in this reservoir was selected to be acid stimulated using a multi-stage open hole completion system with isolation mechanical ent approaches are being used for gas condensate flow to fractured wells. The most popular of them is based on the multicomponent flow s n the effective normal stress across the interface is low. For horizontal bedding planes the normal stress is the vertical overburden stress. In ftware such as nodal analysis software with fracture modeling capabilities or to use specialized hydraulic fracture analytical simulators. Th

pled with a non-linear regression algorithm (Levenberg-Marquardt algorithm) to find values of the individual layer properties that give the be expressed in terms of the pressure drawdown of the system between the initial pore pressure and the sandface flowing pressure (Pi-Pwf) fi the net pressure was high and almost stable throughout the pad stage instead of being high and increasing (PKN) or low and decreasing mate conditions resulting in different scenarios of fracture initiation and identify factors affecting initiation and growth for a given scenario. M es prediction (Sultan and Al-Kaabi 2002) and well-test-data analysis (Osman and Al-Marhoun 2005). Given a basic network structure there

king low angle dip-slip fault that was active since Early Pliocene up to Pleistocene. It dies on the top of the Messinian rocks and divided the .g. currently of the order of 1 to 2 km). â€œInterventionless means of determining the i

at oil and gas production are measured with confidence since industry revenues are based on oil and gas sales and consequently error in p

2006). The combined effect of convection and diffusion on species separation has been the subject of many experimental studies. Separati points in their project maturity spectrum. Though this paper does not purport to have all the answers it attempts to address the painful challe

een neighboring control volumes and relate the flux across the boundary with pressures in the control volumes. Here we apply multipoint tra

em. This work concerns isolated vugs. The definition of â€œisolated vugs used in this paper considers vugs that do not have a connection structural deformation accompanied with fault slip. Recently an application of the elastic stress simulation has been proposed for predicting

as to satisfy CFL condition for the explicit case. The convergence of the non-linear equations for the implicit approach may also require sho provement of the computational efficiency of the streamline simulator has been pointed out in [16]. It is well known that an explicit numerical on methods based upon dual-porosity descriptions may not be able to deliver sufficient resolution of the complex flow patterns that may dev

arker et al. 2001). The problem was set up as a test case to allow various research groups to test their own methodology for the characteriz

barium ions then barium sulphate may precipitate in the formation and/or the production wells. Understanding where and when the scale fo

ns are transformed into a set of 1D equations along streamlines. Note that there are two time scales in the streamline simulation process: t processes during the calculation step and may use a relatively large share of total CPU time consumption. In this paper we propose a spec arguments to formulate an innovative strategy to accelerate the exploitation of oil and gas assets of YPF in the San Jorge Basin Argentina.

means of a mathematical tool called Principal Component Analysis (PCA). Down hole monitoring system yields continuous pressure data o uch that there was only one flowpath from each section of the annulus into the well tubing (Fig. 1a). This restriction limited the usefulness o

available fluid sample analysis from 3 wells in Najmah/Sargelu and 8 wells in Marrat it is assumed that all regions contain gas-condensate (

eimer equation. In the discussion of Batenburg and Milton-Tayler1 and Barree and Conway 2 it was presumed that non-Darcy flow in their e elow the oil zone the location where oil ceases to be mobile) SWI (as depth increases below the oil zone the location where water becom ma Limestone group is highly fractured with the troublesome overlying Nahr Umr shale cap rock which has caused drilling problems in the p n of the area. This is a significant and most important input to forecast the drillability of the well. And in most of the cases the wells are bein development and deployment of these technologies has normally been in Partnership between a major operator and one or more key sup

eater or lesser degree. The ANS extends from the Canadian border on the east and into the Chukchi Sea on the west. The ANS includes t of the cement sheath to strain is determined by the static Youngâ€™s modulus and Poissonâ€™s ratio of the cement through Hookeâ€™s

potential of the through-casing resistivity measurement compared to its nuclear counterpart since its deep depth of investigation gives mor plemented on the Troll and Vestflanken subsea fields. There was a growing understanding that downhole production monitoring was neede the Mauddud Formation. The focus in this article is the production logging applications in the Sabriyah Field. The following part summarize Production log interpretation in horizontal wells is complicated particularly with two-phase (gas-oil) flow down-hole as in Chayvo.ï¿½ Interp

n pressure. We therefore have to design our sample acquisition program with the following considerations: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ ï¿

will usually provide good-quality water samples because the mud filtrate is not miscible with water. Water-based-mud filtrate can contaminat smart well data develops a new integrated workflow that enhances more than one discipline. One such example is the collection of pressur al. 2005). We have analyzed one hydraulic fracture treatment that was carried out in a nearly vertical borehole at depth intervals between 4 servoirs specifically the Quartzite of Hamra. However due to the tectonic history of North Africa hydraulic fracture design execution and e

pair of wells in Phase I a fiber optic distributed temperature system (DTS) was installed in the producer well and the data from this was mon ½ï¿½ These are the criteria for moving the liquid film along the wall of the conduit upward as well as the criteria for suspending and transp oving the liquid film along the wall of the conduit upward as well as the criteria for suspending and transporting entrained liquid droplets in th ects. The introduction of permanently installed fiber optic distributed temperature measurements (DTS) in the late 1990â€™s revived the in

ator method.

plicated as it needs further investigation test and analysis by the production engineer. However independently of the result of the analysis nsitive to one of the phases another is multiple phase-sensitive sensors; each with a high geometric precision and a geometric arrangemen a have been acquired at some wells completed in Wara on a non-routine basis. is destabilized which is caused by the changes in temperature and/or pressure during primary depletion.2 On the other hand asphaltenes ENERAL INFORMATION NR field was discovered in August 2002 in the Western Desert of Egypt (fig-1). This field is producing from the Al he hydrocarbon fluids and water in terms of chemical and physical properties phase behavior and commingling tendencies. Cased-hole su o needs to be flowed at a reduced rate. There is now a third alternative that does not require shutting in the well or reducing flow rate and tion. In some fields this geomechanical deformation also leads to casing deformations and well-integrity problems which may result in ope place. The fieldâ€™s north flank dips steeply at about 35 degrees and has a 1000-m oil column between the gas/oil and water/oil contacts. d multistage completions. Despite the growth in the number of wells the expense of subsea well intervention often leads to insufficient rese

etect any production measurement errors lost production production well test validation etc. to have reliable data for reservoir modeling a spinner and probe sensors are not uncommon. Producing horizontal wells completed in unconsolidated and poorly sorted formation sands

f fluid movement etc. depends primarily on the saturation estimation at different stages of the life of a reservoir. Time lapse monitoring of a

erial that would limit the attenuation at high frequency as much as possible at source and receiver locations. Introduction Peripheral water l is to design an optimum field development scheme for the lower reservoir units in the southern part of the field (Bhatti et al. 2007). Assess orated multizone completions rather than open-hole completions in a single interval. In Canada the Horseshoe Canyon coal is expected to ace and butt cleat permeability anisotropy is prevalent in coal seams ((McCulloh et al. 1974 Mavor at al. 1991 ). Figure 1 displays a schem ed by invasion damage from the drilling fluid completion cement or a mechanical skin caused by hoop stresses around open hole completi ts consisting of crosslinked gelled fluids and large amounts of proppant. Because of difficulties with effectively cleaning up fracture damage fluids may then be used to facilitate fracture initiation and promore less tortuous (i.e. wider) fractures near the wellbore (along with sand slu

ment with Slickwater stimulation treatments.ï¿½ These treatments contained roughly twice the fluid volume of the large crosslinked treatmen umber of horizontal wells have been drilled and massive multistage HFT jobs have been performed. Due to the complex nature of the Barne egies on oil production and SOR in the Athabasca Oil Sands. Advances in technology and computing power now make simulation of a SAG actures are healed by a mineral filling and must be forced open by hydraulic-fracture stimulation. It also is possible to have both shales and fashion as for re-fracture stimulation applications. Introduction The Barnett Shale is a Mississippian-age marine shelf deposit that unconfo ered by the acidizing process. Since the matrix structure is generally intact the entire physical and chemical processes can be modeled by b

or which produces power. This power is used to operate the inlet air compressor. Thus the cycle is completed. Thus this system achieves w cks of continental and shallow-water marine origin. The productive reservoirs formed in different facial settings. Genetically three types of s

ideal since layers with lower fracture gradients or formation pressure may take more of the treatment than planned leaving the higher pres n the field. The skin estimation based on the model compared very well to the measured values during production tests. experiments have clearly demonstrated that only slight changes in the inclination of the wellbore can have a dramatic effect on the types o experiments have clearly demonstrated that only slight changes in the inclination of the wellbore can have a dramatic effect on the types o y was interpreted to be low and therefore matrix permeability was presumed to control the fluid flow.ï¿½ This paper describes the process

uction was suggested by Rinaldi (1987). Recent papers [for an example see Graf et al (2006)] address optimization of intelligent completion

lled with a conventional completion configuration. Acids can attack both metal and elastomeric materials used in ESP systems. œsystem and â€œcomponents. We then present a summary of the extensive data set employed in the analysis. The remainder of the pape

fluid systems were reviewed and a borate cross-linked low polymer loading system was selected based on the high retained permeability r

th porosity development of 5 to 14 percent with an average of about 8.5 percent in this area.ï¿½ It has oil saturations of 60 to 90 percent de polymer concentration non-crosslinked fracturing fluids regularly in order of 1.7-3.0 kg/m3 (15-25 lbs/1000gal). Fiber addition improves the

es being realized as application expands to new areas.ï¿½ Since 2000 fiber-laden slurries2 have been used to improve fracture geometry plicated in their wettability. Almost never are formations pure sandstone. Clays line the pores of most reservoir rock and in the case of shale ore contained in height than predicted by simulators. Some new mechanisms and explanations have been given including the â€œcompos of associated equipment is always a major consideration and processes that would minimize time spent are generally welcomed. To this en n effort to circumvent some of the extra costs operators have reported the use of recycled produced waters in reservoir management proce ses on three major formations (Figure 2): Upper Williams Fork (Porosity (favg) = 7.8% Water Saturation (Sw) = 48% Avg Net = 110 ft) Midd ough the gravel remaining in the casing and additional sand was placed around the screen. Frac-and-pack became a premier completion te e of the premature treatment termination will ultimately also have an impact on the frac productivity. For that purpose many operating and s d for not saying abandoned. In 2006 Kuwait Oil Company (KOC) contracted the service company to revisit this problem and determine if th ve the same sub hydrostatic pressure. The reservoir gross heights range from 80 m to 500 m. The composition of the matrix is mainly sand nd better access to reserves. Often times fewer horizontals are required to develop a field given its larger drainage area. However horizonta

ure intervals and intervals that fracture early will receive more than the designed amount of the stimulation treatment. The remaining inter d case when TSO occurs too late the remaining volume of slurry is insufficient to produce the desired fracture width. Both cases produce su scosity even in dry gas wells where there is neither brine nor liquid hydrocarbon to assist the breaking process.ï¿½ The effectiveness of thi

have different trends and detrital and authigenic compositions.ï¿½ Simply stated a large variation in geologic and petrophysical properties o

production. Improved oil production is required for Marrat wells to increase production and maintain the flowing bottomhole pressure above until the first publication9 resulting from this JIP work was made at the Formation Damage Symposium in Lafayette February 2006. In a se nment.2ï¿½ The thickness of the Cotton Valley sand can grow as large as 1 500 ft.1ï¿½ Changes in stream positions and shorelines due to

ositions. Fracture geometry (mainly its azimuth and length) resulting from such HFM is then used for â€œinfill drilling during which new well

may depend more on rock strength than on the initial etching pattern. In this paper we present an experimental methodology to characteriz Western Siberia. The reservoirs under production are part of Cherkashinskaia set of rock [1 2] composed of shales siltstones and sandston t didnot give the desired information on the location of the proppant that had been pumped. In more recent times the use of radioactive tra

osition and production prediction that have been historically applied in the field had to be compared to understand the possible discrepanc ermeability will vary with distance from the wellbore increasing towards the tip of the fracture where both the liquid-to-gas ratio and the ve

ight gas reservoir which has a porosity ranging from 1 to 25 vol% in the higher porosity sections. These types of porosities coupled with th

sampling of the radiation pattern certainly limits the uniqueness of the fracture-mechanism analysis. However in some projects in which mu

ts et al.3 further extended this work by studying the stress distribution around a producing fracture using a 3D numerical simulator and inve rely heavily on the elastic (or poroelastic) representation for the porous skeleton. The present paper provides the data on hydraulic fracture using sizes as large as 10/14 mesh. This increases the risk of treatment failure (screen-out) that is caused by modeling discrepances/inaccu

nt (FIG) or yield stress effect. A modified conductivity cell was used to allow a series of measurements aimed at clarifying the polymer conc njection was required from day one for pressure maintenance purpose to support producing wells at both the Spar and subsea. Kikeh is pla borders and specially a massive campaign of hydraulic fracturing in all producing wells resulted not only on the attenuation but also on the path. Later studies were concerned with details of the interaction between a hydraulic fracture and a natural fracture and studied conditions arious papers have discussed applications of this technology (Betancourt et al. 2002; Al Kasim et al. 2002; Clarke et al. 2006) but so far no measured depth of 12 290-13 566-ft (9 834-10 292-ft TVD) with 9-5/8-inch casing set at 14 350-ft. The reservoir section was drilled with a reservoir is not a challenge anymore. While horizontal drilling has progressed over the last decade to become the field development method eservoir is not a challenge anymore. While horizontal drilling has progressed over the last decade to become the field development method erized by its low permeability. Its productivity while produced through vertical wells is low and deemed not satisfactory. For this reason deve lts. These faults and fractures have been identified from openhole logs and are most prevalent in the northern part of the reservoir(Ref. SPE 5 Ecuadorï¿½ï¿½ and its application will be considered in other fields. Introduction Bloque 15 is located in the Oriente Basin Amazon jun

isms are well understood so that inflow can be predicted with confidence using reservoir and well models and if the predicted inflow does n between fractures generated in laboratory tests and in field applications. To account for these scaling issues model laws that relate experim

curate reservoir pay thickness (Ref. 1). In addition to these new logging techniques interpretation methods such as Log Enhanced Resoluti Reservoirs with rock strength from moderate to intermediate will benefit most from a sanding prediction study. The completion and operation genic processes through the geological time.ï¿½ It is the nature of the carbonate rocks.ï¿½ But near a wellbore heterogeneity can be furth heast direction. The petrophysical characteristics of the Tadrart sandstone are good with porosity ranging between 12 to 16%; the permeab ucer well was drilled in March 2004 and completed in 4-1/2 monobore completion by penetrating the reservoir ofï¿½ J-10.2 & J-10.1 with Js an area that could be improved in Anaco District well completions. As a result a qualitative evaluation of conventional perforating perform ting-induced damage. Permeability lost through formation damage could be regained through stimulation treatments or by completing the z the tradeoffs between different perforating parameters for non-oriented perforating; oriented perforating avoids many of these tradeoffs. Be al runs of perforating on wireline to complete. Using the equations for underbalance determination3 the optimal static underbalance to clean w rate is maintained in a constant or switched among two or more constant values. Almost all analytical solutions developed for PTT interpr act on cost deliverability include Perforating off depth due to inaccurate depth control Guns not fired due to pressure discrepancies disc n swell can help risk management in at least two respects. First analytical tools such as swell modeling can serve as a supplemental measu

e geological complexity (resulting from a complex turbidity depositional system mainly represented by channels lobes and overbank facies

been a challenging task from both technical and economic perspective since the number of open hole completions have increased significa l sorted with low to high fines content. This particle size distribution data (PSD) combined with the limited amount of whole core data availab

hout affecting the well performance the gravel packing using 40-60 US-Mesh has been considered mandatory as well as the isolation of th window between downhole circulation pressure and the fracturing pressure is narrow. Various hardware and chemistry solutions exist to ov

rate of penetration excellent shale inhibition characteristics gauge hole lubrication while drilling as well as while installing sandface com tion of sand is a worldwide problem. Areas of major problems include the U.S. Gulf Coast Trinidad the North Sea Venezuela Brazil Mala roduction of sand is a worldwide problem. Areas of major problems include the U.S. Gulf Coast Trinidad the North Sea Venezuela Brazil d production. For the long horizontal oil wells that are due to be drilled sub parallel to the dip direction and that will penetrate several sand f he producer to the injector. This characterized by large volumes of sand matrix and fine clay particles being produced where water breakthr (HRWP) and Gravel-pack1-3. Each of these options involves downhole hardware that is primarily conveyed by a rig. However there are ins

problems. AGOCO the field operator investigated the issue and in 1992 the first gravel-pack completion was installed in the Well A to prev e results that closely matched field experience but was also able to predict correctly to the year the onset of sanding in wells. This paper d months. Sanding in the cased and perforated well AA05 had been reported that since 1970 it got fill of 882 ft in four months and up to 906 d that sand-production risk increases as a result of water production.

ydrocarbon production from clastic reservoir rocks. Over the last decades a lot of research by service as well as production companies has ones and shales were established by conducting a number of unconfined compressive strength and triaxial tests on reservoir cores. The lab and surfactant-based. Acid-soluble polymers have been used to increase the viscosity of HCl and to improve its performance (Pabley et a and the closure stress. At low closure stress the etched pattern of the fracture face should have a dominant influence on the resulting fractu a wellâ€™s life from drilling to completion. New technologies and methods have greatly enhanced production by offering data and solution

d great success in vertical gas producers in which post-stimulation multiple-fold rate increases have been consistently realized. More recen ds used previously. Discussion Before December 2003 the predominant procedure for stimulating wells in Tengiz was the use of 15% H placement strategy such as formations with low mechanical integrity and with highly viscous formation fluids. Carbonate reservoirs are sti

mage materials in the near wellbore matrix. In addition reaction products due to the reactions of the stimulation fluids with various mills and

e wells. Organic acids have been used in well stimulation because of their low corrosivity4 and lower reaction rate with the rock. ï¿½Howev

wever the physics and engineering aspects of the carbonate acidizing process is much more complex.1ï¿½ This is because the rock structu aulic fracturing mainly in mid-temperature deep Neocomian and the overpressured high-temperature (above 100ï¿½C) ï¿½deeper Achimov ids under varying conditions of injection rate temperature and concentrations have been reported in the literature 1 2.ï¿½ However few stu ingredients for the success of restimulation and (ii) a thorough understanding of the treatment parameters that govern the success of a rest it was decided to fracture stimulate only the first Frontier formation and as a result of the stimulation the well is producing on average 1 10

ths of 2179â€“2320 m and Triassic horizons at 3109â€“3308 m.

All stimulation treatments were performed in Triassic formation. The heig

pproach will not only involve the workover rig but also impact the production from the lower Burgan sandstone formation as well as formatio d the rig has left location. Because of the importance and criticality of the zonal isolation between oil bearing formations for reservoir manage ses the chance of capturing the data dominated by the reservoir-dominated flow. A typical DST chart is presented in Fig. 2 highlighting the es and determine to which extent they enhance the well productivity. A pressure transient test program was carried out to establish the pote ptimum completion design and operating condition well/reservoir production option used will commonly be the optimum solution indicated on

ical equations to determine reservoir and well characteristics without using type-curve matching. These characteristics are obtained from un s of investigation first we look at the pressure distributions in a 1D radial-cylindrical homogeneous reservoir produced by a fully completed tives of every operating company is to optimize reserves in order to maximize their assets value.ï¿½ For the reservoir engineers in the brow bjective of applying pressure/rate deconvolution is to convert the pressure data response from a variable-rate test or production sequence in

ate methods of interpretation require well tests of quite long durations (Horne and Kuchuk 1988). Kabir (2006) suggested a two step appro een deployed throughout its development to curb the decline in production and extend its life such as phased development secondary rese separator Increasing need for high resolution of GCR measurements to determine changes in fluid properties on choke changes Higher re

application and performance of multiphase meters has been well documented through technical papers and industry forums and after sev ormed by the existing test separators in ADCO fields was an issue rose long time ago. Field reports always indicated that the actual produc

measurement. The fraction measurement techniques are more versatile and we could split them between low energy gamma ray measurem ation models particularly for permeability. This is because of limited core sampling from the reservoir and difference in scale between grid b

the point of interest.11 Regardless of which method of numerical differentiation is used and regardless of the manipulations employed to re that was drilled in a thin oil column within a Cypress formation sandstone reservoir. 3 4 The well was completed openhole with sand screen

resistance to CO2 aggression and more frequent defects related to slurry settling. Defects such as liquid channels in cement can even pro ell(s) and the storage capacity of a repository. Insofar as the stability of faults or the compressive strength of rocks generally depend on all

available through several commercial or pilot projects. Geological storage injects CO2 into either oil or gas reservoirs aquifers or coal beds. oving water from the brine and increasing its salinity as salt concentration increases leading to dry-out and salting-out. In this article we f

ns from anthropogenic sources have also been increasing in the same time frame and these are known to produce a greenhouse effect. . As evidenced by oil gas and even CO2 natural accumulations rock formations can be impervious enough to act as flow barriers over geo

es. This is the longest DIACS completion in the world with the lower isolation packer set at 8560 m. The well is produced at a rate of 2500 or then decided to abandon any further development enhancements and to continue producing the existing wells until it ceased to be profita

mechanisms in the Southern Michigan Basin Reef Trend. In 1969 the first field in the Northern Silurian Reef Trend was discovered leading g >1% concentrations of CO2 in a gas reservoirs is < 1 in 10 and the risk of encountering >20% concentrations of CO2 is < 1 in 100.ï¿½ Ho uth Texas partners make their decisions based on these cutoffs and individual experience. Worthington gives a comprehensive perspective tailed reservoir simulation study with proper geological description and project economic analysis should be conducted to guide the succe

n fractured broken and catalazited at various degrees developing different fracturing systems with different directions. The fracturing and b p and bottom perforated zones in order to provide both proper zonal isolation and accurate treatment placement. TTIP Technology Overvie n successfully carried out on wells with single-string multizone completions. Introduction Cement-water shutoff intervention behind the slee The main production challenges in south Boscan wells are; 1) Surface facility limitations in handling produced water; therefore the volume

dy based on asphaltene precipitation experimental information published in the literature1. Experimental data included evaluation of propen holdup profiles and pressure gradients. These internal-flow structures depend on variables such as flow rates of both liquids pipe geome ed. The water holdups and pressure gradients are measured and analyzed. A simple two-fluid oil/water pipe flow model was proposed by Z al rate in the moment first signs of breakthrough appear. Commingled production from two or more productive horizons is the ideal metho per workflows and technology must be set in place to allow different domain engineers share ideas properly and lead into proper integrated nes by commingling streams from several wells can reduce capital and operational expenditure but may cause problems if the fluids in the s equired to â€œtune theoretical models. In addition to quality and accuracy if flow assurance properties are measured at the representative il industry picks up more than its fair share. The combination of water and carbon dioxide naturally produced or injected for secondary/tertia contamination2 to measure Gas-Oil-Ratio (GOR) and Condensate-Gas-Ratio (CGR) to provide fluid composition i.e. C1 C2-C5 C6+

sate samples. This is the first proposal offered in petroleum literature of a correlation to estimate the decreases in surface yield. o referred to as rs2).ï¿½ This function is similar to the solution gas-oil ratio Rs normally used to describe the amount of gas-in-solution in t erformed by specific tools such as the LFA (Live Fluid Analyzer) which performs spectral analysis of crude oils downhole immediately after re nd routine cased hole logs are common to track such changes. Location of news wells for bypassed/remaining oil is equally important. In ce n that a single pressure gradient identifies a single flow unit can be in gross error [3]. It often indulges accustomed or habituated practices to

e of hydrocarbon fluids in terms of chemical and physical properties phase behavior spatial distribution and hydraulic and thermodynamic

n be challenging for contamination quantification during sampling operation it has been shown that optical spectroscopy can be quite effec The accurate measurement of H2S concentration in the reservoir fluid can often be critical to completion surface production and process d

nant role in distributing hydrocarbon components in the fluid columns studied. ble point of oil in a trap reflect the pressure and temperature history of the trap (Stainforth 2004). Compositional grading can be caused by

sured in separate sample bottles might be caused by differing levels of oil-based-mud (OBM)-filtrate contamination or to some degree of no bility effects and depth measurement errors can make it difficult to acquire representative pressure data and hence limit fluid gradient accu and deep offshore settings more and more fluids with complex phase behavior are met. Crossing the phase envelope of a hydrocarbon fluid to 15% for crude oils or 1 to 3% for gas condensates). In-situ sample OBM contamination can be predicted in real time by a downhole optic

uid gradients. Introduction Compositional variations in reservoir fluids with depth are more common than perhaps normally expected and ha density hydrocarbons which have a larger concentration of aromatic molecules have a tan brown or black color while low-density hydroca The sampling program can be optimized during the job and the operator can decide when where and how many samples to collect. The

½ If heat continues to be added to the system all volatile liquid components will eventually vaporize.ï¿½ If some components in the system acids also enhance the stability of emulsions (Kokal 2005). Because of the presence of these elements the occurrence of tight emulsions in

measurements. The presence of compositional gradients because of fluid migrations or fluids showing near-critical behavior at reservoir tem etermination of the drawdown threshold and controlling the pumping rate ensured that liquid drop-out did not occur in the flowline during the upper limit can be extended to 5000 psia with great care (Ref [2] [3] [6]).1 using experimental and modelled data from an Equation of Sta ll be presented in a separate article. Introduction Comprehensive understanding of the drainage behavior of gas condensate reservoirs in ogler 1998; Huang et al. 2000; Nasr-El-Din et al. 2001). These acids are weakly ionized and slow reacting. Acetic and formic acids are less as been revealed on lab analyses. Second when damage has impact on the injection trend it is important to execute a matrix stimulation tr enerally acid-insoluble (being largely composed of an insoluble quartz matrix) and therefore matrix acidizing intends to dissolve the damagi due to the very large volume required during wash treatments. These issues necessitate preventative measures through chemicals with hal

18-in. length samples under downhole conditions and with the full analysis and control of wellbore dynamics. In a perforation flow experime of undamaged rock; for gas-saturated rocks the porosity of the damaged zone may be much reduced.ï¿½In the damaged zone the pores he most common scale deposits found in operatorâ€™s oilfields is calcium carbonate scale (CaCO3). The uniformity of the finding is obviou ufficient protection time. The efficiency of a scale treatment can be estimated by the scale inhibitor return profile. When the inhibitor concen

and solve all the problems related to lack of integrity in each well. Scale management system is a major part of ZADCO WIMS. In 2001 ZA ld lead to a severe scaling tendency[1].ï¿½The current operator Talisman have sought to review the scale management process to ensu on three case studies. Description of the Method Sensitivity analysis is performed at certain pre-selected pilot-points (or the grid blocks). Du

ry few hours (sometimes minutes)2.ï¿½ Such rapid turn-around times have enabled the performance of numerous strategic analyses on ca Cantarell Field that will be discussed in this paper. omatic engineering workflows remains challenging given the lack of high frequency production data or connectivity. This paper demonstrate . The pilot will also address the issues of uneven sweep bypassed oil and residual oil saturation. The acquired field data will be used to cal

of 2 000 BOPD per well compared to the former 200 BOPD per well. Wells with productivity potentials greater than 1 000 BOPD are typica

ergy such as carbon (El Harfi et al 2000; Abernethy 1976) or certain metal oxides (Monsef-Mirzai et al 1992; 1995).ï¿½ Microwave heating

ds from the Benue Trough in Nigeria to Cameron Chad Central African Republic and Sudan. The evidence for further southeast extension ounds and exposure surfaces. The average porosity is 35% and the average permeability is 250 md over the gross interval. Well log and co the Eastern European (Russian) and Siberian platforms where at least 700 billion bbl is present. Heavy oil and natural bitumen reserves an

ree are placed in Bentiu fiormation. The production performances of all the wells are extremely good year to date. Geological Setting and S

be cold produced because of its high fractures and fissures density. Producing the Nukhul heavy oil through downhole pumps requires 20%

clude 6:1.5 and 12:3 mud acid systems. The use of 9:1 or even 13.5:1:5 mud acid systems has been advocated to allow greater dissolution

t to be responsible for these observed gradings.1 3-9 The approach taken by most of these papers are to compare sector/field data with eq

d without permanent damage to the polymer molecular weight and therefore to the fluid viscosity. Low initial viscosity from crosslinking too

y target is the lower Miocene and Oligocene which are interbedded sandstones saturated with oil. Some of the wells show initial production a novel chemistry include simplified placement process (i.e. single stage) less precipitation tendency reduced tubular and production e pecially at temperatures > 150ï¿½F or in the presence of acid-sensitive clay. Acid treatment of sandstone at high temperatures therefore re rcial production levels. A typical San Jorge Gulf Basin well has an interval of interest located between 800 to 1200 meters with dozens of s mporary as the well has to be retreated with solvents if a water block problem reoccurs. Evaporation of water in the formation can also dec of organic compounds and heavy metals in water is performed. Dissolved organic acids also affect water chemistry because they can influe

shale accounted for 2% and the remaining 8% was coalbed methane (CBM). They projected that in 2010 the portion of gas that was tight ga

adays. The oilfields are typically developed with an inverse nine or seven spot pattern and are under intensive pressure maintenance progra ed microseismic event distribution 13 15. These interpretations were not closely constrained by accounting for the amount of pumped fluid a

lower reservoir B4. The low permeability reservoir D (less than 10 md) was therefore abandoned and only the reservoir B4 and B7 put on p mma of many horizontal wells that have already been drilled but perform poorly. arbon saturation a clearly defined oil-water-contact with abnormally low permeability. Low production rates from past vertical and slant-hole ted studies step-out and infill wells have been drilled and cores logs completion pressure and production have been collected from them. ns were deposited.ï¿½ The basin is bounded on the north by the Laramide east-trending Uinta uplift and the Uinta Basin boundary fault on rosity ranging from 5 to 14% and permeabilities in the range of 0.001 to 0.03 md. Water saturation varies from approximately 30% updip to rforate and flow the well. This luxury does not exist for the tight marginal gas sands discussed here. The risk associated with stimulating a n

technologies is Downhole Fluid Analysis (DFA) which is rapidly advancing and the list of its measurements is expanding commensurately. N nd 10 PU and matrix permeabilities typically less than 10md. The field currently produces approximately 400 000 BOP from more than 700 p nd gas prices. Tight gas fields typically go through multiple rounds of downspacing dependent upon development pace well performance m

ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½c.ï¿½ï¿½ï¿½ï¿½ All internal valves in the tool are closed creating a fixed flowline volume sealed at near hydrostatic mature watering out of production wells. A commingled production completion of the three reservoirs was selected in the central area becaus

mitic vugular-fractured reservoirs covered by Vendian-Lower Paleozoic cap saliferous in the Cambrian interval. The discovery of the accum

(under primary imbibition) and a commensurate increase in the relative permeability of the oil. But when one drills a well with Water-Base

integrated approach to the management of the existing hydrocarbon resources and producing assets. Continual advancement/improvemen

sibly lead to very damaging mistakes. which can affect judgment elicitation.

being located at different heights (above free water level) in the capillary pressure transition zone. Rock types are geological entities usua uild up injection/fall off test and production logging are the conventional methods for characterization of reservoir heterogeneity. Although a cular interest for carbonate as it is well recognized that unlike conventional siliciclastic reservoir carbonates have complex pore system distr sins more than 5 km thick.

btain reservoir-fluid samples for PVT analysis. Conventional reservoir-fluid analysis is conducted in a PVT laboratory and it usually takes a are of constant focus and routine cased hole logs are common to track such changes.ï¿½ Location of news wells for bypassed/remaining o ated approach using the NMR and the micro-resistivity bore hole images for identifying and quantifying the secondary porosity and their imp ght function for each of the reservoir rock types which were later used for HCIIP calculations. As a result of this study the geo-cellular mode very large sodium iodide crystal to achieve high count rates and owing to a focused design the measurement has good azimuthal sensitiv quences can cause the potential of a reservoir to be inaccurately evaluated when only conventional approaches such as density neutron a

s have been developed in the literature to get accurate water saturations taking into account the excess conductivity due to shale.2 3 4 Th ped in the literature to get accurate water saturations taking into account the excess conductivity due to shale.2 3 4 The dependency of th examine a new form of rock typing based on estimates of relative permeability. Carbonate Analysis Workflow The workflow presented has t ed fractures. Sand Count analysis performed using the high-resolution azimuthal data from the borehole image was successful in identifyin em tracts are characterized by highly burrowed packstones and/or wackestones (typical burrower is thalassinoides) capped by a dense bor ullbore cores has increased over recent years. New logging techniques and interpretation methods have been applied to improve the evalua

s useful check points to ensure the best possible interpretation in thin sand/shale formations. A quick review of 3D induction technique is di

Hassi Messaoud field. In the majority of the transient test data performed in horizontal wells the analysis of the pressure derivative reveals or to limit the amount of production of solids and grains. The second step in this approach is to manage the produced solids and sand grains data are valuable not only for geomechanics but for reservoir characterization and fracture network evaluation. Borehole images and match res may be interpreted as possible strati-structural traps at the top of Tayarat Formation. Good porosity is reported at the top of this formatio

uijbregts 1978 Cressie 1991 Chiles and Delfiner 1999). Geostatistics as a major branch of spatial statistics is commonly used to model g ume porosity hydrocarbon saturation and permeability. Produced and delivered on an interactive PC platform this evaluation was complem ss. Introduction Thin beds evaluation problems with well logs have long been recognized studied and solutions proposed since the late 19

sure gradients can lead to significant stress reorientation in the reservoir. In this paper we study stress reorientation around a single produc

y during directional drilling (b) hydraulic fracturing for enhanced production and (c) selective perforation for prevention of sanding during pr

red vertical well the system characteristic length (Lc) is equal to the wellbore radius (rw).

as one of the highest strain point. The combination of formation micro imager Stoneley waves measurement elemental spectral device an nificantly affected with secondary processes such as dolomitization leaching and fracturing4. Following the initial discovery 19 wells have

es such as dolomitization leaching and fracturing3. Following the initial discovery 19 wells have been drilled in the Maloichskoe field and

ther reason for near wellbore formation alteration could be wettability change due to OBM invasion.ï¿½ Such drilling fluids usually have sur

e main petrofacies: a) quartzitic sandstones b) micaceous and laminated sandstones and c) shaly intervals. Sandstones composition is rath ls from Î¦ Sw and k logs and therefore insufficient sampling might result. On the other hand excessive pretests and rig time might have be

.5 times the longest desired T1 value rather than the industry standard requirement of 3 times the longest desired T1. A specific example in

ssible to determine reservoir parameters such as permeability and pore pressure by extracting the productivity signature of the reservoir fr xtension in the south-west part of the field during the Ahmadi-Tayarat period. Most of the faults were generated during the Mutriba-Tayarat p

escence and a few other non-optical measurements. The spectroscopic DFA technique utilizes optical absorption properties of reservoir flui (WFT). With current technology it is possible to obtain contamination-free samples in a very short time.5 Furthermore this technique enable ed vertical well the system characteristic length (Lc) is equal to the wellbore radius (rw). comprises clean fluvial reservoir sands with over 1000ft thickness in places. Porosity ranges from 10% to 14% while permeability ranges u reline formation tester (Ayan et al. 2007). In this study the authors used dipole radial profiling and Interval Pressure Transient Tests (IPTT)

estern Siberia Russia using a WFT is described. The survey was conducted under heavy winter conditions which required special precautio ematical model coupled with non-linear regression methods for solving the inverse problem. It is possible to match the pressure transient d but the estimated risks involved in executing the proposed plan. So the ideal plan would have two parts: optimization and risk assessment ed with downhole fluid analysis and sampling may significantly improve the definition of fluid type and predict fluid behavior. At the top level ™s effort to establish an alternative artificial lift system for offshore production operations. n excess of 5 600 wells drilled in Block 10 and the current production is about 12 500 bopd. Perez Companc S.A. a company that was later in unconsolidated sand. Gravel pack is used as sand control method.ï¿½ The oil is under saturated with 19-20 API in shallow reservoir and

PMâ€™s performance as the operator has been excellent as illustrated by the projectâ€™s exploration exploitation production safety and ajectories are shown as lines; oil-bearing zones are green; gas-bearing zones red; and parts of the encroaching aquifer and the connate w eviated or horizontal wells experience a reduction of the effective producing length as gas and/or water reaches the horizontal section (Figur h produce from two separated reservoirs: B-1 and B-4.ï¿½ B1 sand is under initial conditions with a 3500 STB/d as estimated potential wh ventional fields. Extensibility and flexibility of FM also allows workflows and logic that are difficult/impossible to implement within the prescri ADA systems. To achieve optimal operations efficiency adjustments may be made in existing field equipment. Example control devices inclu tertiary recovery method and would require economic justification. In addition existing fluid export constraints arising mainly from the curre he third revisit was in 1994 to sidetrack 4 wells. There are eight reservoirs that have been targeted and produced. All of the wells are dual s

in every well in the system. Their interaction will ultimativley lead to a newly calculated backpressure of the production system for every we when at what cost and with what benefit?ï¿½Multiple vendors must collaborate to create cross-discipline compatibility and Oil & Gas com per workflows and technology must be set in place to allow different domain engineers share ideas properly and lead into proper integrated tic model to dynamic data and it is the final process in reducing the error and uncertainty in the interpretation and analysis to acceptable lev cing through SSDs into 27/8 in or 3 1/2-in tubing. The deeper more consolidated formations do not require sand control and are completed

rvoirs exhibit uneven strength of aquifer support causing OWCs to tilt after years of production. To reduce and reverse the rapidly declining elopment in this paper we divert from the strict subject line of hydraulic fracture design (i.e. the type and amount of fluids proppant etc.) the average reservoir pressure cannot be accurately determined from well shut-in pressures. Fig. 1 shows an example of measured shut-in schemes. We demonstrate the concept with an example involving a decision to be made on where to place a water injector well relative to a

pecially in thin reservoir targets. A new directional electromagnetic (EM) measurement-while-drilling tool (PeriScope*) provides a simultane and gas company indicated a 22 ft thick porous permeable oil-stained sand. Two appraisal wells drilled by Oilexco in 2003 and 2004 indica y.ï¿½Integration of these activities however requires a good deal of â€˜intelligentâ€™ technologies in the form of systematic data acquisiti alt intrusion leaving the present reservoir at a very steep 45ï¿½slope. The reservoir is highly overpressured exhibiting a pressure gradient is still a reinforcing process.ï¿½ Which means that as soon as potentials are proven to exist resources will be made available to pursue th suitable wellbore trajectories and conformance requirements. At the same time a comprehensive sand production prediction study was car tial to screen regions that are most favorable for well placement. In this paper we present a gradient-based method that is distinct from tho

ion in porous medium.ï¿½ Solution of the diffusivity equation under different boundary condition forms the basis for prediction of bottom ch is based on solving the same set of equations as is done numerically when using a simulator. Analytical solutions to the diffusivity equati . Two different approaches to incorporate the regularization term have been used extensively in reservoir characterization literatures. One o model before accepting it for practi

inear geological objects such as channels or fractures. The proposed approach addresses these concerns. The number of parameters to

components that partition into either of the hydrocarbon phases and that the water component could not reside in the hydrocarbon liquid ph nsport terms in the equations. For example flow terms can be described by two-point flux approximations or by multi-point flux approximatio completion and stimulation for production enhancement1 2 3. Production logging is very important to identify problems with horizontal we

d interval to not contribute to production. Discussed in this paper is one such factor- pressure change in the wellbore due to undulations in w

residues remain after the breaker reacts with the polymer. It has been postulated that fracturing fluids need a minimum pressure gradient to rast do not show such obvious production peaks but instead sustain a flat production profile or exhibit a slowly increasing production rate on system with isolation mechanical diversion and selective fracture ports allowing the fractures to be placed at specific positions along the based on the multicomponent flow simulation that is done using single computational grid for the reservoir and the fracture. For detailed des s is the vertical overburden stress. In shallow formations the normal stress is low and interfacial slip between formation bedding planes is m lic fracture analytical simulators. The advantage of this method is simplicity and speed. However there are a certain aspects of the problem

dual layer properties that give the best fit to the observed well production history and production log data. Discussion of Non-Linear Regres andface flowing pressure (Pi-Pwf) first reported by Ramey and Cobb6. A thorough investigation on the use of the dimensionless productivi asing (PKN) or low and decreasing (KGD or Radial). The reason why current available models are not adapted to the case of point source n and growth for a given scenario. Many experimental and theoretical studies were devoted to this topic and this paper is another attempt to iven a basic network structure there is a wide variety of ANNs that can be produced. For example different methods or criteria used to train

he Messinian rocks and divided the field into two blocks; the northern downthrown block enclosing the main production area of the field.

as sales and consequently error in production data can be considered minimal. However reservoir pressure is uncertain since limited well m

many experimental studies. Separation in a thermogravitational column with both effects has been measured widely (Schott 1973; Costeseq ttempts to address the painful challenges and highlight the benefits of using the technology.

olumes. Here we apply multipoint transmissibility upscaling which arises if we associate a boundary flux with two control volumes sharing th

vugs that do not have a connection to the overall fracture system.ï¿½ Vugs can be interconnected with other vugs in the matrix rock.ï¿½ Su on has been proposed for predicting the pattern of shear/tensile fractures or the pattern of secondary faults and shown promising results (B

plicit approach may also require short time step length. Simulation of geological scale reservoir models with finite difference/finite volume m well known that an explicit numerical method which is used in [16] poses a restrictive CFL constraint on the time step. This constraint is espe complex flow patterns that may develop when a fractured reservoir is produced. Several approaches (e.g. Matthai et al. 2007) have theref

own methodology for the characterization of the uncertainty in reservoir performance predictions given some geologic information on the re

anding where and when the scale forms is important since formation of the scale close to a production well or in the well will reduce the pro

the streamline simulation process: the one determined by the frequency of pressure updates (pressure time step) and the one dictated by on. In this paper we propose a special analytic approach in order to reduce the time required for the flash calculations. Coupled with the com in the San Jorge Basin Argentina. The workflows of interest are identify candidates for infill drilling locations propose a field developmen

m yields continuous pressure data over the life of the well. This could result in an enormous amount of data which can be a serious data h s restriction limited the usefulness of the multisegment well model when investigating wells without packers in the annulus or the effects of

all regions contain gas-condensate (GC) in the Najmah-Sargelu reservoir while Marrat contains both volatile oil (VO) and gas-condensate (F

sumed that non-Darcy flow in their experiments can be described by the Forchheimer equation. According to the convention of the oil and g one the location where water becomes mobile). 2) At any depth in the transition zone what is the oil saturation Soil what proportion (So has caused drilling problems in the past. The drilling conditions would require careful planning since downhole temperatures reached 289ï¿ most of the cases the wells are being drilled without the proper knowledge of stress pattern of the area.ï¿½ The demand of an in-situ stress or operator and one or more key suppliers. Each of the major operators have their own terminology for â€œSmart Fields as listed below.ï¿

Sea on the west. The ANS includes the giant Prudhoe Bay and Kuparuk oil fields among several other fields. The ANS land area is approxim of the cement through Hookeâ€™s law. A correction of dynamic values of Youngâ€™s modulus and Poissonâ€™s ratio is required to be us

eep depth of investigation gives more immunity to reinvasion. The interpretation is fast and hence allows making an almost real-time decisio ole production monitoring was needed in order to draw the full benefit of the intelligent multilateral completions. This resulted in the installatio Field. The following part summarizes the reservoir properties and production history of the field. Sabriyah Field has oil gravity ranging 18-2 w down-hole as in Chayvo.ï¿½ Interpretation with a conventional turbine spinner or a full-bore spinner becomes inaccurate in these cases c

ns: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ ï¿½ï¿½ï¿½ï¿½Keep sampling pressure above the bubble point so that the acquired sample remains rep

r-based-mud filtrate can contaminate water samples because the filtrate is miscible with formation water and chemical reactions can alter t example is the collection of pressure data from permanent down-hole pressure gauges (PDG) to perform pressure transient analysis (PTA) orehole at depth intervals between 4 980 and 6 095 ft. The map view of the treatment and monitoring wells is shown in Fig. 1 along with the lic fracture design execution and evaluation is neither simple nor straightforward. On the contrary this paper will illustrate that depending s

well and the data from this was monitored as the well was put on production. In January 2005 a workover was performed to change the pu e criteria for suspending and transporting entrained liquid droplets in the flow stream upward.ï¿½ It has been observed by Turner et al3 and porting entrained liquid droplets in the flow stream upward. It has been observed by Turner et al3 and Oudeman11 that the flow stream velo in the late 1990â€™s revived the interest in temperature log interpretation and new rigorous thermal models were developed for the interp

ndently of the result of the analysis it should be classified and ranked based on the constraint or discipline responsible for the following acti ecision and a geometric arrangement that allows at least one probe to identify the presence of the lightest phase. This paper describes wha

n.2 On the other hand asphaltenes have been reported to become unstable as a result of fluid blending (co-mingling) of fluid streams3 as 1). This field is producing from the Alamien dolomite of the Alamien carbonate member consists mainly of carbonates with subordinate shale mmingling tendencies. Cased-hole surveys might look for bypassed hydrocarbon zones or have objectives that could not be achieved during n the well or reducing flow rate and it can be performed any time during the life of the well. It is based on the fact that over time the individu y problems which may result in operational problems (Davis et al. 2000; Smith et al. 2006). The combined monitoring of passive seismic an n the gas/oil and water/oil contacts. The south flank dips less steeply (20 degrees) and is suspected of having perched oil/water contacts. V ention often leads to insufficient reservoir information for accurately understanding reservoir connectivity drainage and flow assurance. For

eliable data for reservoir modeling and production forecasting. A combination of traditional techniques and computationally intelligent (non-p d and poorly sorted formation sands can be particularly perilous to production measurements. Although some of the more sophisticated pro

eservoir. Time lapse monitoring of a reservoir is estimated at different wells in the field using incessantly developing and evolving through ca

ons. Introduction Peripheral water flooding as pressure maintenance method was commenced within few years of the discovery of the gian the field (Bhatti et al. 2007). Assessing pilot performance and fine-tuning the modelâ€™s predictive capabilities requires proper surveillanc rseshoe Canyon coal is expected to produce 3 Bcf/day by 2025. With an average rate of 80 000 cf/day per well this corresponds to 37 000 . 1991 ). Figure 1 displays a schematic of cleat network in a coal bed. The permeability of the cleat system is a reservoir property of prima stresses around open hole completions. The matrix permeability of coal is extremely low so the primary transmissibility system is from coal ctively cleaning up fracture damage caused by the crosslinked gel and the high cost of these massive stimulation treatments the wells wer ear the wellbore (along with sand slugs after initiation).ï¿½ This technique helps to lower the treating pressure after fracturing and facilitates

me of the large crosslinked treatments previously pumped but less than 10% of the proppant volume.ï¿½ Well performance was somewhat e to the complex nature of the Barnett reservoirs which is vastly different than that of conventional or other types of unconventional reservoi ower now make simulation of a SAGD pad with multiple well pairs possible so our simulation model was also able to account for the interpla is possible to have both shales and coals interbedded in a single reservoir resulting in gas contributions from both lithologies. ge marine shelf deposit that unconformably lies on the Ordovician-age Viola Limestone/Ellenberger group and is conformably overlain by th mical processes can be modeled by basic fluid flow in porous media coupled with thermodynamic equilibrium among the reactants and produ

pleted. Thus this system achieves which no other existing artificial lift system does. Recirculates power to run itself. Equipment Description ettings. Genetically three types of sediments can be recognized including highly permeable sandstones deltaic distributary channels that in

an planned leaving the higher pressure layers only partially treated. This is becoming more of an issue as development wells are being dri production tests. ave a dramatic effect on the types of flow and flow regimes exhibited in a multiphase flow system. In situations where the outflow velocities ave a dramatic effect on the types of flow and flow regimes exhibited in a multiphase flow system. In situations where the outflow velocities ½ This paper describes the process used to achieve the drilling of about 5 000 ft entirely within the Mauddud reservoir. Geological and Geo

optimization of intelligent completions. To some extent load-balancing problems may be corrected by proper placement of wells if the rese

s used in ESP systems. analysis. The remainder of the paper presents a detailed and sequential SA for a rich data set to demonstrate how parameter interaction fa

d on the high retained permeability results. The six fracture stimulations performed in early 2006 returned incremental rates in excess of 100

oil saturations of 60 to 90 percent depending on its location within the deposition.ï¿½ Generally up dip to the west and southwest in the Rich 000gal). Fiber addition improves the proppant carrying properties that these low viscosity fluid lack. The low viscosity fluids are also allowing

used to improve fracture geometry and enhance production from propped fracture treatments.ï¿½ These particular degradable fibers are c servoir rock and in the case of shale an added complication is the hydrophobic kerogen partially lining the pore surface. Further the prese een given including the â€œcomposite layer effect â€œshear dampening and fracture behavior at layer interfaces for the unexpected hei are generally welcomed. To this end a development project was initiated to provide enhancements to viscoelastic surfactant fluid technolo ters in reservoir management processes (Khatib and Verbeek 2002). Water treatment options have been discussed that include desalinatio (Sw) = 48% Avg Net = 110 ft) Middle Williams Fork (favg = 8.5% Sw = 51% Avg Net = 170 ft) and Lower Williams Fork (favg = 8.9% Sw ack became a premier completion technique in the late 1980s 2 when the use of the tip-screenout (TSO) technique earned worldwide accep r that purpose many operating and service companies in Western Siberia have applied various techniques to prevent the breakthrough of th evisit this problem and determine if the technology had been invented which would allow this suspended reservoir to be developed and achi mposition of the matrix is mainly sandstone however there can be a significant carbonate content that can reach 35%. In the southern portio er drainage area. However horizontal well completion has lagged behind in particular when a stimulation treatment is part of the completion

ation treatment. The remaining intervals will therefore not receive the optimized treatment and well production will be less than optimal. T acture width. Both cases produce suboptimal treatment with poorer fracture conductivity and hence poorer well productivity. Another chara process.ï¿½ The effectiveness of this breaker has been measured in a series of proppant pack conductivity tests demonstrating greater tha

ologic and petrophysical properties often characterize these sands. Drilling and completion of the Morrow wells have been a challenge from

flowing bottomhole pressure above the AOP by reducing the pressure drop taking place in the formation particularly near wellbore. Product in Lafayette February 2006. In a series of lab experiments yield stress measurements ranged from 0 â€“ 17 Pa. This paper builds on the r eam positions and shorelines due to sea level fluctuations caused a large variation in the thickness and aerial extent. 2ï¿½ Sandstones and

œinfill drilling during which new wells are drilled into unfractured (and hopefully undrained) parts of the reservoir. Wrongly estimated fracture

rimental methodology to characterize acid-etched rock surfaces carefully and then relate the fracture-surface features to the measured frac d of shales siltstones and sandstones. 90% of the production for the Priobskoe oilfield comes from AC-10 AC-11 and AC-12. The main foc cent times the use of radioactive tracers has grown in acceptance. Due to the inherent inaccessibility of the downhole environment radioac

understand the possible discrepancies in prediction results. The range of application of the various inflow equations also had to be determ th the liquid-to-gas ratio and the velocity decrease. This variation of permeability was explicitly modeled in the proppant pack by dividin

e types of porosities coupled with the natural fractures present in the zone and the high bottom hole temperatures (250-280F) results in und

wever in some projects in which multiple observation wells are used (Warpinski et al. 2005) the 3D radiation pattern will be measured bette

g a 3D numerical simulator and investigated the size of the stress reversal region as a function of various reservoir properties. Fracture turn ovides the data on hydraulic fracture simulation accounting for accumulation of damages in elastoviscoplastic medium as well as the effect ed by modeling discrepances/inaccuracies. To reduce the uncertainties and improve fracture design information on the geological geomec

aimed at clarifying the polymer concentration process and confirming the presence if any of a yield stress effect. Experimental Apparatu th the Spar and subsea. Kikeh is planned to be developed with 34 wells; 18 oil producers 15 water injectors and 1 gas injector. Water injec y on the attenuation but also on the total reversion and increase of the oil production that was declining for over ten years (Dï¿½ria et al 20 atural fracture and studied conditions that produced crossing blunting or offsetting.12 17 18 21 26 22 24 25ï¿½Offsetting where the fracture 02; Clarke et al. 2006) but so far none has presented a rigorous solution for the performance of such wells. This situation is reflected in the reservoir section was drilled with a water-based fluid. Sand prediction models from the operator and the service company teams had indep ecome the field development method of choice in many cases there have been certain limiting technologies on the completion of horizonta come the field development method of choice in many cases there have been certain limiting technologies on the completion of horizontal ot satisfactory. For this reason development of this field through horizontal openhole drains is necessary to achieve acceptable level of prod orthern part of the reservoir(Ref. SPE#81487 by N.G. Saleri). ed in the Oriente Basin Amazon jungle in Ecuador. The main fields are: Paka Sur Field and the Eden Yuturi Fields. Both are clastic reservo

ls and if the predicted inflow does not change significantly with time during production. The well can then be configured so that hydrocarbo sues model laws that relate experimental parameters of the physical model to field-scale prototype parameters were utilized to perform the

ods such as Log Enhanced Resolution using Borehole Image (SHARP analysis) have been developed to improve the reservoir characteriza study. The completion and operational decisions to prevent or control sanding need to be taken on a well to well basis by considering the in wellbore heterogeneity can be further created by the perforating process.ï¿½ The rock fabric surrounding the perforation tunnel is altered b ng between 12 to 16%; the permeability is in the order of 100-200 md. The reservoir properties are quite homogeneous over the field thus ervoir ofï¿½ J-10.2 & J-10.1 with J-10.2 being perforated leaving J-10.1 un-perforated (Figure 2). Based on the log analysis J-10.2 sand h of conventional perforating performance was done. This evaluation confirmed the link between poor well productivity and perforating and ju on treatments or by completing the zones with deep-penetration perforating to bypass the invasion damage. Fracture stimulation to improve avoids many of these tradeoffs. Bethany Field The Bethany field is located on the Sabine Uplift in extreme east Texas adjacent to the Lou optimal static underbalance to clean up perforations in these reservoir conditions is ~7000 psi. The reservoir pressure in these cases is well solutions developed for PTT interpretation assume a constant skin factor (Earlougher 1977; Lee et al. 2003). Underbalanced perforating due to pressure discrepancies discovered only after CT was retrieved to surface with an additional run being required. Well does not perfo can serve as a supplemental measure to further verify whether existing guns are adequately qualified within their respective ratings and th

channels lobes and overbank facies and the action of later erosive channels) and complex distribution of fluids saturation in the reservoir 7

ompletions have increased significantly over the last several years.2 3 Until recently standalone screens have been utilized for sand contro d amount of whole core data available for 5 fields required the selection of a sand control system capable of providing well bore stabilizatio

ndatory as well as the isolation of the shale sections to avoid reduction on gravel-pack permeability caused by shale erosion during the grav e and chemistry solutions exist to overcome this problem including diverter valves that are activated sequentially creating a new entry point

ell as while installing sandface completion and low maintenance costs (dilution and solids control costs in reactive silt/shale environments) North Sea Venezuela Brazil Malaysia Indonesia China Australia and western Africa. At least some problems are reported in all areas o d the North Sea Venezuela Brazil Malaysia Indonesia China Australia and western Africa. At least some problems are reported in all ar nd that will penetrate several sand formations of varying quality liner completions with oriented perforations (0/180 or 10/350o phasing) we eing produced where water breakthrough. Pulse tests and tracer study indicated that a short circuit had occurred in the reservoir between th eyed by a rig. However there are instances when sand control is performed through-tubing (rigless intervention) for workover or secondary

on was installed in the Well A to prevent sand production. However sand control measures were not applied across the entire field. A geom set of sanding in wells. This paper describes the methods employed in this investigation provides details of the data acquisition and proces 882 ft in four months and up to 906 ft in ten months. To date no sand control or sand management techniques have been implemented on

as well as production companies has been devoted to developing models for sand production prediction. In terms of the sanding problem c xial tests on reservoir cores. The laboratory-measured mechanical properties were then correlated with the properties derived from openho mprove its performance (Pabley et al. 1982; Crowe et al. 1989). As the viscosity of the acid increases the rate of acid spending decreases a nant influence on the resulting fracture conductivity as long as the strength of the rock can withstand the load.ï¿½ As the closure stress is in duction by offering data and solutions that were not available in previous years. Likewise technologies often considered archaic by todayâ€

en consistently realized. More recently acid fracturing stimulation has been implemented also in horizontal producers with equally impressiv ells in Tengiz was the use of 15% HCl conveyed by coiled tubing. Spotting the acid in front of the various reservoir layers provided diversio n fluids. Carbonate reservoirs are stimulated using acid to dissolve the rock matrix to create conductive pathways from the reservoir to the

mulation fluids with various mills and scales in the tubular and in the pumping equipment can also upset the optimized acid formulation; caus

action rate with the rock. ï¿½However they have the following limitations: (1) they cannot be used at high acid concentrations. This is becau

¿½ This is because the rock structure is significantly altered by the dissolution reaction which increases the permeability contrast between bove 100ï¿½C) ï¿½deeper Achimov formation. Cenomanian formations that provide the majority of the gas production had represented a g e literature 1 2.ï¿½ However few studies on the influence of rock properties on the acidization process have been reported 3 4.ï¿½ Previo ers that govern the success of a restimulation job so as to be able to optimize the treatment for maximum rate of return. Advances in the des he well is producing on average 1 100 Mscf/day. On the second well reservoir characterization was fundamental to select the best stimulati

rmed in Triassic formation. The height of the oil part of this reservoir totals 36-75 m. The height of the gas part equals 56 m. The water/oil

dstone formation as well as formation damage associated with the workover operation. Several wells were treated with this approach in the ring formations for reservoir management ZADCOâ€™s policy is to confirm isolation by physical communication tests regardless of the qu presented in Fig. 2 highlighting the flow and buildup periods we are interested in. In this study Dt is the elapsed time since the beginning o was carried out to establish the potential of the well and shed light on the reservoir structure.ï¿½ Different phases of the test program can b be the optimum solution indicated on an economic basis or at least a reasonable melding of the optimum economic and technical options c

characteristics are obtained from unique fingerprints such as flow regime lines and points of intersection of these lines that are found on th rvoir produced by a fully completed vertical well in which after the wellbore storage effect the flow regime is predominantly radial before the r the reservoir engineers in the brown fields (mature fields) the challenge in defining the exploitation strategy is the lack of critical reservoir e-rate test or production sequence into an equivalent pressure profile that would have been obtained if the well were produced at a constant

(2006) suggested a two step approach based on multirate transient drawdown tests followed or preceded by a buildup. Firstly he estimate hased development secondary reservoirs development well activation optimization of production mechanisms use of emerging technolog perties on choke changes Higher repeatability measurements to confirm slow trends Circumventing hydrate formation issues downstream

s and industry forums and after several years of development is maturing (Scheers 2004). Some multiphase measurement techniques can ays indicated that the actual production volumes of

en low energy gamma ray measurement the most common one and electromagnetic measurement. The former is the simplest option to ge d difference in scale between grid block and core permeability. Well test data is ideal for bridging the gap between core and grid block perm

of the manipulations employed to reduce the scatter in the resulting derivative data the analyst is often left with data not entirely representa ompleted openhole with sand screens and a gravel pack. External casing packers subdivided the annulus into three zones. An electrical valv

id channels in cement can even provide direct pathways for CO2 leaks that couldnâ€™t possibly be healed by calcite precipitation during th h of rocks generally depend on all of the three principal in-situ stresses it is necessary to estimate the full stress tensor as a function of de

as reservoirs aquifers or coal beds. CO2 has been used in the oil industry as a method to enhance the recovery of hydrocarbons and this k and salting-out. In this article we first discuss in more detail the impact of mutual solubility for CO2 storage in saline aquifers. Numerical im

wn to produce a greenhouse effect. The greatest contributor to global warming over the past century has been carbon dioxide mostly from ough to act as flow barriers over geological periods of time. Delineating such a seal safeguarding its integrity under operational conditions

he well is produced at a rate of 2500 Smï¿½/day (15700 bbl/day) with production from all zones. Production from the upper zone A would n ing wells until it ceased to be profitable. As a result the field was abandoned in 1997 at this point the final water cut was 71%.

Reef Trend was discovered leading to additional investigations of these reefs.These included works by Mesolello (1974) Shaver (1974) an trations of CO2 is < 1 in 100.ï¿½ However here is the issue: the mean CO2 content of reservoirs with >20% CO2 is 50% CO2.ï¿½ In other gives a comprehensive perspective on the use of these cutoffs.[2] The cutoff number most often used in the Oligocene Vicksburg trend of ld be conducted to guide the successful design and application of this technology. Simulation Model and Parameters A 3-D model of a h

erent directions. The fracturing and breaking did not change the rock composition but they strongly altered the structure texture and particu acement. TTIP Technology Overview The TTIP is run in the well on the end of coiled tubing to the required depth and then inflated depend shutoff intervention behind the sleeve in multizone completions is a solution that is not common due to its low probability of success. Shell

oduced water; therefore the volume of fluid produced is limited. In addition production enhancement is restricted.

l data included evaluation of propensity for asphaltene precipitation of the reservoir fluid. In addition the paper also had supplemental data ow rates of both liquids pipe geometry and physical properties of the liquids involved. The flow characteristics of oil-water mixtures are gen pipe flow model was proposed by Zhang and Sarica (2006) as part of a three-phase unified model. Flat interface was assumed for the strat oductive horizons is the ideal method to accelerate production from a single well.ï¿½Furthermore marginal reservoirs which are destined perly and lead into proper integrated analysis. The following sections of the work describes phase by phase how a team of Schlumberger cause problems if the fluids in the streams are not compatible3. The mixture of the two reservoir fluids could potentially precipitate asphalte are measured at the representative temperature and pressure condition of the production the model is more likely to represent realistic flui duced or injected for secondary/tertiary recovery can trigger severe corrosion in surface and transport (i.e. pipelines) facilities in hydrocarbo composition i.e. C1 C2-C5 C6+ to identify when the flowing pressure falls below saturation pressure to identify compositional grading3

creases in surface yield. be the amount of gas-in-solution in the liquid phase. Whitson and Torp3 presented a procedure to calculate MBO properties from PVT expe de oils downhole immediately after removing the oil from the formation. maining oil is equally important. In certain environments conventional open hole logs may not fully resolve the fluid content of stacked reser customed or habituated practices to take only one sample from several compartments if where have similar pressure gradients. One far mo

n and hydraulic and thermodynamic communication are of critical importance. Fit-for-purpose design of completion and production facilities

ical spectroscopy can be quite effective to overcome contamination challenges6. The challenge can be much more in the case of determini n surface production and process design and is important for many reasons including the following: Determine which (if any) HSE measur

positional grading can be caused by a variety of factors and often indicates a state of non-equilibrium but it can also be observed in equilibr

ntamination or to some degree of nonrepresentative sampling. In addition it is often difficult in practice to justify the extra cost of taking mult a and hence limit fluid gradient accuracy and reliability. hase envelope of a hydrocarbon fluid mixture although often unpredictable in the reservoir is common: saturated oils are accompanied with ted in real time by a downhole optical fluid analyzer tool which is used as a module of a formation testing tool (Mullins and Schroer 2000; S

n perhaps normally expected and have been observed in several reservoirs throughout the world. This phenomenon is not limited to thick re lack color while low-density hydrocarbons have little or no color. Third the absorption spectrum of water is different from that of crude oils; how many samples to collect. The ability of focused-sampling cleanup to supply virtually uncontaminated fluidsâ€”with faster cleanup timeâ

½ If some components in the system are truly non-volatile then there will always be a liquid phase whose presence is independent of the am the occurrence of tight emulsions in the production facilities is quite common. In some cases emulsions may also form in the near-wellbor

near-critical behavior at reservoir temperature must be understood to develop a valid model of the reservoir (Fujisawa et al. 2008). Underst d not occur in the flowline during the critical phase of the operation. This technique yielded very clean samples validated by laboratory ana odelled data from an Equation of State (EOS) software package using data from a PVT report. This requires a competent phase behaviour vior of gas condensate reservoirs in the Siberian region is an essential element of field management. In most cases reservoirs have been p ting. Acetic and formic acids are less corrosive than mineral acids and can be inhibited. ant to execute a matrix stimulation treatment. Among other challenges the Hungarian fields are characterized by their mineralogical comple izing intends to dissolve the damaging minerals that fill line or cement the porosity of the quartz matrix.[Knox 1964]ï¿½ The identity of thes measures through chemicals with halite inhibition properties. However the current commercial available halite inhibitors are only effective at

mics. In a perforation flow experiment the after-shot sample productivity index (PI) is determined in axial flow and sometimes also in radial ¿½In the damaged zone the pores are much smaller than in the virgin rock: many sand grains have micro-fractures and large pore throat he uniformity of the finding is obviously related to the similarity in the widely spread reservoirs in Western Siberia1-2. This is valid for both th rn profile. When the inhibitor concentration is less than a certain threshold the Minimum Inhibitor Concentration (MIC) the scale protection

or part of ZADCO WIMS. In 2001 ZADCO carried out a scale study to evaluate the scale risk in UZ field. It was found that the the maximum cale management process to ensure that any lessons that can be learned from analysis of the earlier stages of production may be applied d pilot-points (or the grid blocks). During the sensitivity analysis both sensitivity coefficients and the Hessian of the objective function are ev

f numerous strategic analyses on candidate assets at speeds which had previously been considered inconceivable and most importantly

onnectivity. This paper demonstrates that new workflows allow the management of sparse multi-frequency data streams in cases as extrem cquired field data will be used to calibrate the simulation model for production injection saturation and pressure data in order to design as

greater than 1 000 BOPD are typically completed with either ESPs or conventional PCPs. To achieve the advantages of both ESP and PCP

1992; 1995).ï¿½ Microwave heating effectiveness depends on several parameters; such as heating period amount and type of matter that

ence for further southeast extension has been destroyed by Tertiary uplift associated with recent rifts in East Africa. The shear zone was ide r the gross interval. Well log and core plug porosity values over 50% are common and measured permeability values range up to 5000 md. y oil and natural bitumen reserves and resources of the Siberian platform comprise one of the three largest accumulations in the world the o

ar to date. Geological Setting and Stratigraphy Being a rift and Cretaceous sedimentary basin Muglad basin is located south of Republic o

ough downhole pumps requires 20% to 30% water cuts (WC). High viscosity and resulting friction pressures hinder the submersible pumpâ

dvocated to allow greater dissolutions of secondary reaction products in low pH environments.2 3 In HCl sensitive formations HCl is replac

o compare sector/field data with equilibrium or steady state gradient models of varying complexities.

nitial viscosity from crosslinking too late may result in a narrow near-wellbore fracture impeding proppant transport. Either crosslinking a si

e of the wells show initial production as high as 10 000 bopd. The drilling practices and other damage mechanisms discussed in the next s reduced tubular and production equipment corrosion and less exposure of hazardous fluids to personnel and the environment at the we e at high temperatures therefore requires a retarded acid. Additionally conventional acid treatment of sandstone formations (such as a mu 800 to 1200 meters with dozens of sand beds ranging from one to four five or eight meters thick many of them strongly laminated1. This p water in the formation can also decrease the permeability due to brine precipitation. Zuluaga et al.[14] have reported 15-30% loss in abso er chemistry because they can influence the pH of the solution. Good quality formation-water data can improve the ability to make the right

0 the portion of gas that was tight gas would increase to 26% whereas conventional gas would decrease to 58%. Shale would only increas

ensive pressure maintenance program. Well spacing is between 500-1000 meter in most oilfields and fracture lengths have been constantl ng for the amount of pumped fluid and mechanical interactions between fracture and injected fluid as well as among nearby fractures.

nly the reservoir B4 and B7 put on production. In the first months of 2007 Foukanda field had a production potential of about 3000-3500 bop

ates from past vertical and slant-hole completions led to disregarding the development potential of this reservoir. A field structure map of SF tion have been collected from them. This provides a unique opportunity for evaluating the quality of our model forecasts â€“ the subject of t the Uinta Basin boundary fault on the east by the north-trending Douglas Creek arch on the west by the Sevier north-trending Charleston es from approximately 30% updip to approximately 60% downdip. The study area situated updip has better reservoir quality and produces a e risk associated with stimulating a non-flowing zone results in bypassed pay of unknown potential. Presented here is a proven technique fo

ents is expanding commensurately. Not only DFA characterize fluid physical and chemical properties also it is being increasingly applied for 400 000 BOP from more than 700 production wells. elopment pace well performance maturation increased reservoir characterization information and technology advancements. This somewh

e volume sealed at near hydrostatic pressure. ï¿½ï¿½ï¿½ï¿½3. A pretest is performed: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ s selected in the central area because it was uneconomic to produce only one reservoir by itself. The initial pilot development was based on

interval. The discovery of the accumulations of HC in the deep Riphean horizons and nonanticlinal deposits in the terrigenous deposits of th

hen one drills a well with Water-Base Mud (WBM) through a transition zone how does one quantify the mobile oil saturation and the associa

Continual advancement/improvement in oil & gas exploration and exploitation practices and better reservoir management has led the indust

ck types are geological entities usually associated with depositional mineralogical or diagenetic attributes. Identifying rock types provide a f f reservoir heterogeneity. Although applications and advantages of these techniques in formation evaluation are well established each has ates have complex pore system distribution. Their complexity lies in the fact that depositional primary pore space is overprinted by both a dia

VT laboratory and it usually takes a long time (months) before the results become available. Also miscible contamination of a fluid sample news wells for bypassed/remaining oil is equally important.ï¿½ In certain environments conventional open hole logs may not fully resolve th the secondary porosity and their impact on the permeability. This technique was validated from the dynamic behaviour of a well and shows t of this study the geo-cellular model of the Lower Tipam reservoir was prepared incorporating a better understanding of the spatial heteroge urement has good azimuthal sensitivity; this enables gamma ray images to be acquired. Efforts to address the four objectives described abo proaches such as density neutron and sonic logs are used. Image logs and surface logging data have been recognized as being essentia

conductivity due to shale.2 3 4 The dependency of the different developed shaly sand models on their input parameters has a great impa shale.2 3 4 The dependency of the different developed shaly sand models on their input parameters has a great impact on choosing the b rkflow The workflow presented has three basic steps and is described in detail by Ramamoorthy et.al. (2008). At each step of this workflow e image was successful in identifying the thin sand beds which are generally overlooked by the conventional logs. The method is capable t assinoides) capped by a dense bored or burrowed surface.ï¿½ï¿½ By contrast the high stands are dominated by high energy deposits (gra e been applied to improve the evaluation of these thin-bedded reservoirs. This paper highlights efforts placed on the use of NMR logging to

eview of 3D induction technique is discussed first. The important point is to understand how sand resistivity and sand volume fraction are de

is of the pressure derivative reveals that production comes from both natural fractures and layered media in a bilinear flow characterized by the produced solids and sand grains by means of filter systems and hardware enhancements which increase tolerance to high solids conten uation. Borehole images and matching cores might be expected to display the same fractures distributions but in practice some fractures is reported at the top of this formation from many wells. Furthermore an unconformity at the top of the Cretaceous sequence may have fac

istics is commonly used to model geologic facies and petrophysical properties in reservoir characterization. The spatial characteristics of ge atform this evaluation was complemented by the equally near-real-time analysis of high-resolution borehole images to identify the thin bed solutions proposed since the late 1970s. In the three decades that followed four techniques have evolved with time: the first is the deconvo

eorientation around a single producing/injecting horizontal well and then address the problem of a pattern of injecting and producing horizo

for prevention of sanding during production. Wellbores drilled through base salt in the GOM are subject to increased risks of hole closure t

ement elemental spectral device and other conventional open hole logs were chosen as the suitable logging suite to characterize the fractu g the initial discovery 19 wells have been drilled in the field and 8 of them produced commercial oil rates. The results of core investigations

drilled in the Maloichskoe field and 8 of them produced commercial oil rates. The results of core investigations and well test analyses show

Such drilling fluids usually have surfactants as additives and an excess amount may change the wettability of water wet particles in the for

vals. Sandstones composition is rather complex except for the massive quartzitic sandstone bodies because quartz volcanic lithics mica a pretests and rig time might have been spent to acquire fluid information in difficult environments such as thin beds washouts near wellbor

est desired T1. A specific example in the paper demonstrated the idea. A natural question is to ask what porosity accuracy to expect from m

ductivity signature of the reservoir from the production data. Although the short time span of the drilling process can give only an insight into erated during the Mutriba-Tayarat period (Turonian to Base Tertiary) but the trap formation of the Minagish field is post-Eocene. The recent

bsorption properties of reservoir fluid in the visible to near-infrared (NIR) range. Optical spectra are obtained in real time and at in situ cond 5 Furthermore this technique enables the acquisition of samples at different depths with unmatchable vertical resolution. Proper sampling p

to 14% while permeability ranges up to 1000mD with an average of approximately 100mD. As Sarah produces under a strong aquifer-driv val Pressure Transient Tests (IPTT) and showed that possible formation damage does not necessarily increase with increasing overbalance

ons which required special precautions and preparation. The data acquired is outlined and an analysis of the results is given.ï¿½ We also le to match the pressure transient data acquired in supercharged environment to deduce values of permeabilities initial pressure and produ : optimization and risk assessment which are also interrelated. However ranking and screening of options for the plan should be done only edict fluid behavior. At the top level of structural complexity lie reservoirs with a high degree of compartmentalization where the thickness o

panc S.A. a company that was later acquired by PESA started operations in the block in December 1996. Paper SPE 104034 provides add h 19-20 API in shallow reservoir and 22-24 API in deeper reservoir.ï¿½ The gas/oil ratios ranges from 100 to 250 scf/bbl.ï¿½ The reservoir

exploitation production safety and maintenance records. Fig 1 below shows the gross oil and gas production from 1980 through 2003. roaching aquifer and the connate water blue. eaches the horizontal section (Figure 2) and in some cases when the breakthrough occurs at the heel the flow along the horizontal section 00 STB/d as estimated potential whereas B4 sand accounts 90% of total production with an initial production from 6000 STB/d. The driven sible to implement within the prescribed set of functionality traditionally provided in reservoir/FM tools. This paper presents an innovative ap ment. Example control devices include choke settings gas lift injection rates production routing and pump/compressor speeds. These dev raints arising mainly from the current regional gas export scheme had to be taken into account for an optimised field-wide reservoir manag produced. All of the wells are dual string completions with 2 or more perforated intervals.

the production system for every well. The system backpressure is then conveyed all the way back through the well model back into the rese line compatibility and Oil & Gas companies will need to pilot evaluate and recommend changes to the resulting IAM technology which wil perly and lead into proper integrated analysis. The following sections of the work describes phase by phase how a team of Schlumberger a tation and analysis to acceptable levels before the model can be used in predictive mode to derive development strategies.ï¿½ Although au uire sand control and are completed with perforations inside 7-in or 9 5/8-in casing. More recently short lateral horizontal sidetrack wells a

ce and reverse the rapidly declining oil production rate is a challenge CACT needs to confront. To significantly improve production efficiency nd amount of fluids proppant etc.) to develop a process for real-time decision-making in a changing environment. We strive to develop re ws an example of measured shut-in pressures in different LV reservoirs. Many wells experienced sanding and casing collapse problems du ace a water injector well relative to a fault in a marginal asset. We examine the value of a future measurement of the degree of compartme

ol (PeriScope*) provides a simultaneous solution for a deep reading and azimuthal measurement. This new measurement is based on nove d by Oilexco in 2003 and 2004 indicated much thicker oil sands up to 60 ft thick with an oil â€“ water contact up to 40 ft deeper then origina the form of systematic data acquisition validation processing and information-extraction to support the process of creating and constructin ured exhibiting a pressure gradient of 0.7 psi/ft. Real-Time Data Transmission During the completion design process the operator decid s will be made available to pursue them â€“ but usually not before. Thus identifying and proving the potentials of a field based on a minimu production prediction study was carried out including laboratory work and mechanical earth modeling to investigate sanding tendency for v ased method that is distinct from those previously mentioned. The adjoint method used in optimal-control theory has been used previously f

s the basis for prediction of bottom hole pressure response of a producing well. These analytical solutions are generally applicable for a sin cal solutions to the diffusivity equation which describes the pressure diffusion in a porous medium for a slightly compressible fluid provide ir characterization literatures. One of these approaches is the Bayesian1-7 and the other is the deterministic.8-11 Both approaches have b

erns. The number of parameters to be optimized is reduced to the number of dominating geological patterns present. Geological continuit

ot reside in the hydrocarbon liquid phase. Balance Equations The governing equations include component material balance equations an ns or by multi-point flux approximations. Similarly transport terms can utilize single-point upstream weighting or multi-point high order weigh identify problems with horizontal well performance. Examples locate the entry points of gas/water for high GOR/water cut wells or identify t

the wellbore due to undulations in well trajectory. Production logs are sometimes used to identify problems with horizontal wells1 2 3 4 5. A

eed a minimum pressure gradient to begin the cleanup process in the proppant pack (May et al. 1997) and this has been verified experime a slowly increasing production rate for several weeks or months.[1] A major potential reason for this behaviour given in previous studies wa aced at specific positions along the wellbore (Al-Naimi et al. 2008). Offset oil producers in the vicinity of this well demonstrate relatively hig oir and the fracture. For detailed description of the flow within fracture computational grid is refined around and within fracture using some s ween formation bedding planes is more likely. Many coal bed methane (CBM) formations are at shallow depth and interfacial slip can have are a certain aspects of the problem that are not considered when using these methods that may influence the results substantially. Produ

. Discussion of Non-Linear Regression Method Spivey2 recognizes that for hydraulically fractured wells four different parameters are typi use of the dimensionless productivity index as a design criteria for fracture stimulation design was performed by Meyer and Jacot5.ï¿½ In t adapted to the case of point source hydraulic fracturing is that they all assume linear flow a legacy of the past of fracturing vertical wells ei and this paper is another attempt to answer this question. Fracture width reduction (so-called pinching effect) is the most critical near-well rent methods or criteria used to train the network produce ANNs that provide different predictions (e.g. the early-stopping and weight-deca

main production area of the field.

sure is uncertain since limited well measurements are usually available and averaging procedures might introduce some uncertainty in the

ured widely (Schott 1973; Costeseque 1982; El Mataaoui 1986). The thermogravitational column consists of two isothermal vertical plates w

with two control volumes sharing the boundary and some other control volumes close to this boundary. This approach is similar to the one

other vugs in the matrix rock.ï¿½ Such a vuggy rock is illustrated in Figure 1 which is a thin section photomicrograph.ï¿½ The blue areas a ults and shown promising results (Bourne and Willemse 2001; Maerten et al. 2002; Bourne et al. 2001). The elastic simulation numerically s

with finite difference/finite volume methods may be impractical due to time constraints. Coarse models can result in numerical smearing of he time step. This constraint is especially severe in the dual porosity case since the flow velocity in fractures is relatively high. One way of r e.g. Matthai et al. 2007) have therefore been taken to accurately describe fracture-fault systems on a grid-block scale e.g. based upon com

some geologic information on the reservoir hard data at well gridblocks and some scattered production data from the first 8 years of produc

well or in the well will reduce the productivity of that well or in extreme cases will cause loss of the well (Mackay and Sorbie 2000). In this p

time step) and the one dictated by the solution of the saturation transport along streamlines (saturation time step). It is apparent that the s h calculations. Coupled with the compositional streamline technique4 the approach further reduces calculation time and thus facilitates the cations propose a field development strategy based on lessons learned from the past in order to know the size of the business from an eco

data which can be a serious data handling issue while using this data. The proposed approach provides a means of condensing the data ers in the annulus or the effects of different packer installations or leakage through packers. In this work we model devices requiring loope

atile oil (VO) and gas-condensate (Figure 1).ï¿½ The model is thus divided into 10 PVT regions based on segments and reservoirs. PVT a

ing to the convention of the oil and gas industry the beta factor Î² is generally deduced experimentally from the slope of the plot of the inver aturation Soil what proportion (Sor_imb) of this is immobile under water imbibition and what is the expected fractional flow of water fw u wnhole temperatures reached 289ï¿½F and there were depleted pressures along with H2S and CO2 in the reservoir. The through-tubing dr ¿½ The demand of an in-situ stress map therefore is extremely important while drilling a deviated high angle well. The situation becomes e â€œSmart Fields as listed below.ï¿½Throughout this paper the term Smart Field has been used based on its use at the SPE Forum and

ields. The ANS land area is approximately 60 000 square miles plus approximately 70 000 square miles of state and federal waters in the ssonâ€™s ratio is required to be used in Hookeâ€™s relationship. The failure point is given by either the tensile strength or the compressiv

s making an almost real-time decision on water shutoff operation so that it can take place immediately after logging. Saturation Measureme etions. This resulted in the installation of Schlumberger downhole flowmeter in Norsk Hydro multilateral well F-29 on the Oseberg Sï¿½r fie ah Field has oil gravity ranging 18-26 ï¿½API GOR varying 60-350 scf/bbl porosity of 18-22% permeability of 15-60 md bubble point pres ecomes inaccurate in these cases causing reliance on the temperature log which is also difficult to interpret since the geothermal gradient is

hat the acquired sample remains representative. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ Ensure that OBM contamination levels are l

r and chemical reactions can alter the true composition. Reservoir water samples are usually collected in open hole with a wireline formati m pressure transient analysis (PTA). Permanent gauge installations feed data to archive systems; the data can then be pulled and analyzed ells is shown in Fig. 1 along with the initial locations of the largest events in the third stage of this treatment. Six injection stages lasting abo paper will illustrate that depending solely on the results of a simple temperature survey can often lead to misinterpretation of data and subs

ver was performed to change the pump which had been found to have insufficient capacity for an electrical submersible pump (ESP). Mon been observed by Turner et al3 and Oudeman11 that the flow stream velocity required to continuously move the liquid film along the condu udeman11 that the flow stream velocity required to continuously move the liquid film along the conduit wall is consistently greater than that odels were developed for the interpretation of DTS data. The combination of permanent installation and continuous temperature curve acqu

ne responsible for the following action to be taken. This procedure helps Asset Teamâ€™s track not only the lost production but also the ac st phase. This paper describes what has been achieved with logging tools and interpretation techniques that utilize the latter approach.

g (co-mingling) of fluid streams3 as well as by gas injection during Improved Oil Recovery (IOR) operations.4-8 Waxes on the other hand a of carbonates with subordinate shales. The unit ranges from 235 to 245 ft thick. 2) RESERVOIR GEOLOGICAL FEATURES Based on core es that could not be achieved during the openhole phase. Regardless of the type of survey performed understanding the exploration and ap n the fact that over time the individual layer flow contributions will change naturally as the reservoir layer pressure changes. Flow distributio ed monitoring of passive seismic and surface deformation provides insight into these mechanisms leading to casing deformations and also having perched oil/water contacts. Voidage support will be achieved by both water and gas injection and effective voidage replacement is c drainage and flow assurance. For those wells requiring sand control an additional constraint is that sandface sensors must be deployed o

and computationally intelligent (non-parametric) modeling methods using Neural Networks (NN) and Self Organizing Maps (SOM) working t some of the more sophisticated production detecting tools such as the APLT provide optimum answers of flow distribution it is necessary t

developing and evolving through casing measurement techniques. The ability to detect hydrocarbon behind casing is therefore vital. Two pa

ew years of the discovery of the giant complex carbonate reservoir in the middle-east region. Although initially quite successful the field has pabilities requires proper surveillance planning and timely data gathering. To efficiently meet the pilot objectives while acquiring high-quality per well this corresponds to 37 000 wells in production. Overall Alberta currently produces 21 Bcf/year but this is predicted to increase to 5 stem is a reservoir property of primary importance because commercial levels of production cannot be obtained unless a well-developed na y transmissibility system is from coal cleats or natural fracture systems. These fracture systems (or cleats) are generally much wider than yo timulation treatments the wells were not as economical as desired. In 1997 large-volume high-rate slickwater fracture-stimulation treatme essure after fracturing and facilitates subsequent pumping of the main treatment (commonly slickwater).ï¿½ However a risk of high viscosity

½ Well performance was somewhat better than the crosslinked jobs but stimulation costs were reduced by approximately 65%.ï¿½ These t her types of unconventional reservoirs it is difficult to obtain a clear understanding and an accurate description of the reservoir. To quickly ac s also able to account for the interplay between well pairs. s from both lithologies. up and is conformably overlain by the Pennsylvanian-age Marble Falls Limestone (Ketter et al. 2006). Formation thickness varies from 200 rium among the reactants and products. For practical purposes the models can be used to design field scale acid stimulation treatment and

to run itself. Equipment Description The major components of this lifting system are: Inlet Air Compressor Surface Venturi Downhole T deltaic distributary channels that incise the flood valley; massive thick mouth bar sandstones and sheet-type shore terraces reservoirs. Th

as development wells are being drilled in more dense spacing increasing the chances of treating some depleted layers. The Treat And Pr

uations where the outflow velocities are sub-critical the wellbore liquids are not continuously and uniformly transported up the wellbore to th uations where the outflow velocities are sub-critical the wellbore liquids are not continuously and uniformly transported up the wellbore to th ddud reservoir. Geological and Geophysical Considerations in Location Selection: The selection criteria for choosing the well location inclu

roper placement of wells if the reservoir is characterized perfectly a priori. And incorrect well placement may be partially compensated by a

nstrate how parameter interaction factor collapsing and appropriate goodness-of-fit measures can be employed to achieve a parsimonious

d incremental rates in excess of 100% over the predictions at sanction. Post-frac production results suggest that vertical communication thr

o the west and southwest in the Richland County deposit the Bakken Middle Member clean portion has the higher oil saturations as calcula low viscosity fluids are also allowing for lower net pressure rate increase resulting in the possibility to place fractures with longer fracture ha

se particular degradable fibers are continually gaining a favorable reputation worldwide as the technology has evolved and the scope of rele the pore surface. Further the presence of liquid hydrocarbons may adsorb and alter the wettability of the reservoir. These factors make it d er interfaces for the unexpected height containment (Warpinski et al. 1998; Barree and Winterfeld 1998; Wolhart et al. 2004). Alternatively viscoelastic surfactant fluid technology which addressed the need for cost control and provided the ability to use various mix-water fluid typ en discussed that include desalination reverse osmosis and â€˜floc â€ñ dropâ€™ methods but trucking costs associated with moving wat ower Williams Fork (favg = 8.9% Sw = 51% Avg Net = 175 ft).ï¿½ Reservoir pore pressure gradients range from 0.42 psi/ft in the Upper W ) technique earned worldwide acceptance as an effective stimulation method for high permeability formations. Modern frac-and-packs invol ues to prevent the breakthrough of the propped fracture but so far without a clear and documented success. This paper describes a combin reservoir to be developed and achieve the planned field production objectives. A task force with team members from both KOC and the ser an reach 35%. In the southern portion of the area considered there are also limestone reservoirs which are often interbedded with sandsto n treatment is part of the completion or has to be applied as a remedial treatment in wells performing below expectations1.

duction will be less than optimal. The industry is searching and experimenting with a variety of methods to stimulate each production inter orer well productivity. Another characteristic discrepancy is underestimation of downhole pressure. Matching of the brittle linear-elastic mod ivity tests demonstrating greater than or equal to 95% retained proppant pack permeability.ï¿½ Laboratory Fluid Loss Measurements To

ow wells have been a challenge from early 1960s where it was considered that the only good Morrow well was the one that was producing n

n particularly near wellbore. Production improvement can be achieved through the acid fracturing as it will be discussed in details in this pap €“ 17 Pa. This paper builds on the results published earlier9 and demonstrates successful strategies that mitigate the yield stress effects to aerial extent. 2ï¿½ Sandstones and shales are intermixed throughout the Cotton Valley group resulting in a highly laminated formation.ï¿½

reservoir. Wrongly estimated fracture azimuth (and its position) can lead to financial losses. Furthermore the borehole deviation are used n

urface features to the measured fracture conductivity. The preliminary results presented here show how statistical properties of the surface-r 10 AC-11 and AC-12. The main focus of this paper is on the AC-11 and AC-12 formations where production development and enhanceme the downhole environment radioactive tracers have represented one of the few viable means for analyzing the placement and flow of vario

ow equations also had to be determined. eled in the proppant pack by dividing the fractureï¿½into segments and calculating the permeability in each segment.

mperatures (250-280F) results in undesirably high leak-off rates during acid fracturing treatments. Regular HCl acid has high leak-off rates t

ation pattern will be measured better allowing for the possibility of more-accurate fracture planes. Nevertheless the observed seismic radia

s reservoir properties. Fracture turning was also studied using a 2D hydraulic fracture model. plastic medium as well as the effect of inhomogenity of porous media properties on fracture propagation. The problem of fluids displaceme ormation on the geological geomechanical and flow setting is required. This includes stress distribution in the wellbore formation elastic p

ess effect. Experimental Apparatus and Methodology The conductivity apparatus consists of two Ohio sandstone cores (~ 0.2 md) conf ctors and 1 gas injector. Water injection will peak at 260 000 BWPD. for over ten years (Dï¿½ria et al 2005). Until 2000 the results of the hydraulic fracturing operations in the Carmï¿½polis field were below th 4 25ï¿½Offsetting where the fracture crossed a natural fracture was observed in many of these laboratory experiments and was recognized ells. This situation is reflected in the software domain (or perhaps reflects it) where most commercially available nodal analysis packages c e service company teams had independently confirmed that this well was a good candidate for a cased and perforated completion with orie ogies on the completion of horizontal wells that have proven to slow that growth. This is primarily the ability to effectively stimulate or fracture gies on the completion of horizontal wells that have proven to slow that growth. This is primarily the ability to effectively stimulate or fracture y to achieve acceptable level of production. Openhole completed reservoirs will lead to higher productivity index but usually damage due to

uturi Fields. Both are clastic reservoir with variable fluid and rock properties. Fluid viscosities varies in the field from ï¿½5 cP 8 cP 12 cP 1

en be configured so that hydrocarbon production (or some other objective function) is maximized by optimizing the inflow profile along the w ameters were utilized to perform the block test and interpret some of the experimental observations7 8 9. The experiment was designed to

o improve the reservoir characterization of these thinly bedded reservoirs (Ref. 2 and 3). After reservoir characterization other frequently a ell to well basis by considering the individual characteristics of each well. The well characteristics include inclination and orientation in the inng the perforation tunnel is altered by the high pressure impact of the jet and the perforation tunnel itself can be filled with rock and charge e homogeneous over the field thus providing optimum candidate wells for the initial evaluation of the new perforating technique. Backgroun d on the log analysis J-10.2 sand has 6.8m TVD net pay with average effective porosity of 15% and permeability of 26md followed by wate ell productivity and perforating and justified the field trials of new technology in this area. Most of the perforating technology developments h age. Fracture stimulation to improve single-well productivity is a risky operation in the HZ fields because the thin pay sandstones often have eme east Texas adjacent to the Louisiana state line as shown in Fig. 1. Bethany was discovered in 1916 and has produced over 1.6 Tcf ga rvoir pressure in these cases is well below this optimal pressure so meeting this requirement is impossible. Also executing a job with such a 2003). Underbalanced perforating has been widely applied to well completion. An UBP induces pressure transient that provides an opport being required. Well does not perform as expected due to insufficient underbalance condition. Guns sanded in due to higher than expect within their respective ratings and therefore will be useful to both perforating job planners and perforating system developers. A second app

of fluids saturation in the reservoir 7 pilot wells were drilled during the planning phase prior to 2002. This pilot program led to a developmen

ns have been utilized for sand control in majority of horizontal completions.4ï¿½ Many of these wells have failed prematurely due to either p ble of providing well bore stabilization in all production wells. Shale Characteristics The deepwater Angola fields are located in shallow imm

sed by shale erosion during the gravel placement. To avoid well internal diameter reduction or high completion cost an intensive laboratory quentially creating a new entry point upstream into the wash pipe 6 light weight gravel which allows lower pump rates for the same alpha-wa

in reactive silt/shale environments).[1] Openhole high-inclination gravel packing is the preferred technique adopted by many operators in problems are reported in all areas of the world where oil and gas is produced. some problems are reported in all areas of the world where oil and gas are produced. ions (0/180 or 10/350o phasing) were ranked higher than more traditional mechanical sand control options. Stand Alone Screen (SAS) solu occurred in the reservoir between the two wells where it took 2 hours 50 minutes to travel from surface to surface. The wormhole dimensio vention) for workover or secondary pay sands4&5. Prior to screenless completions sand control options for these secondary targets have b

plied across the entire field. A geomechanics study conducted in 2004 (Sarir Sanding Study Phase I1) examined seven wells in the south e s of the data acquisition and processing required and demonstrates that accurate sanding predictions can be achieved by focusing effort o hniques have been implemented on a field wide basis for the field. Due to fill in the borehole the production for this field is obstructed to a lo

n. In terms of the sanding problem clastic reservoirs can be divided into three groups according to the strength of the reservoir rocks whic the properties derived from openhole logs. The magnitudes of the in-situ stresses and formation pressure were derived from analysis of op he rate of acid spending decreases and as a result deeper acid penetration can be achieved (Deysarkar et al. 1984). The addition of uncro e load.ï¿½ As the closure stress is increased surface features along the fracture faces may be crushed and the fracture conductivity is more often considered archaic by todayâ€™s fast paced standards continue to pay dividends when properly integrated with the new technology a

ntal producers with equally impressive results. us reservoir layers provided diversion of the acid. Results of laboratory tests in which viscoelastic diverting acid systems were injected thro pathways from the reservoir to the wellbore.[1 2] The conductive channels (â€œwormholes) bypass the damage created during the drillin

the optimized acid formulation; cause adverse reactions with the formation minerals; and further aggravate the overall complex chemistry in

gh acid concentrations. This is because of the limited solubility of their calcium salts. For instance acetic and formic acids are typically used

s the permeability contrast between the treated and the untreated zones.ï¿½ Unless effectively diverted the treated region eventually beco gas production had represented a great challenge for stimulation in Western Siberia untilï¿½last year. Most of these gas fields are in produ have been reported 3 4.ï¿½ Previous studies on the influence of injection rate have shown that characteristic dissolution patterns are obse m rate of return. Advances in the design and evaluation software improved diagnostic techniques etc have played a key role in restimulatio damental to select the best stimulation practice considering the fact that this well was a direct offset form a well drilled and completed in 19

gas part equals 56 m. The water/oil contact has been established at a level of 3168â€“3404 m. The reservoir is fully or partially stratified an

ere treated with this approach in the past but the results showed not to be very cost effective considering the complexity of the operation as munication tests regardless of the quality of cement interpreted from cement bond logs. The policy is applied selectively however. Only ceme elapsed time since the beginning of inflow of fluid and Dtp is the duration of flow period. When Dt > Dtp it indicates a time within the shutent phases of the test program can be summarized as (see Figures 2 and 3). Initial clean-up on full choke followed by a shut-in period to le m economic and technical options considered. An innovative robust and unique production optimization methodology is reported in the pa

n of these lines that are found on the log-log plot of pressure and pressure derivative. It isapplied to both drawdown and buildup tests. Sev me is predominantly radial before the effect of any outer boundary. Note that this may not be true for wells in nonhomogeneous and heterog ategy is the lack of critical reservoir information such as pressure and permeability.ï¿½ Many times old information based on few scattered m he well were produced at a constant rate for the entire duration of the production history. If such an objective could be achieved with some

ded by a buildup. Firstly he estimates reservoir parameters (k s D and p*) with transient data rather than doing the traditional deliverability hanisms use of emerging technologies understanding heterogeneities and replacement and upgrading of equipment. The Abu Al Bukhoos ydrate formation issues downstream of surface production chokes plugging up controls in separators Remote unmanned operations Lower

hase measurement techniques can perform better and the meters provide a more compact solution than the traditional separation approa

he former is the simplest option to get the multiphase meter as less complex as possible. Indeed the high energy gamma ray being already p between core and grid block permeabilities because it samples the reservoir on the scale of the grid block size. The authors recognized th

left with data not entirely representative of the well/reservoir system under investigation. In this paper we describe a new technique for diffe us into three zones. An electrical valve which also recorded the annular and tubing pressure controlled inflow to each zone (Fig. 2). The 21

aled by calcite precipitation during the CO2 attack. Some of the phenomena listed above can be predicted but cannot easily be controlled; full stress tensor as a function of depth. Yet no single measurement technique can solve for all the 6 independent components of the stress

recovery of hydrocarbons and this knowledge has contributed to extending the use of CO2 not only for enhanced oil recovery but also for lo orage in saline aquifers. Numerical implementation of these concepts is presented. Simulations for a pre-injection study for a CO2 injection i

as been carbon dioxide mostly from deforestation and fossil fuel burning. Methane is second and arises from coal deposits leaking natura egrity under operational conditions and verifying whether isolation is effective or not are key objectives in achieving a successful storage pr

ction from the upper zone A would not have been possible without a controlled production from the other zones hence adding value to the al water cut was 71%.

Mesolello (1974) Shaver (1974) and (1977) Huh (1976) and Nurmi (1977). One of the more prolific workers on these structures during th >20% CO2 is 50% CO2.ï¿½ In other words when CO2 is abundant it is frequently so abundant. Furthermore high CO2 concentrations are in the Oligocene Vicksburg trend of South Texas is 15-16% porosity (Fig. 2). More recently there has been success at much lower porosity nd Parameters A 3-D model of a hypothetic field is used in this study.ï¿½The field is produced by natural depletion without considering an

ed the structure texture and particularly the petrophysical characteristics of the basement rocks. The petrophysics characteristics of altere ired depth and then inflated depending on the type of the application being performed and once the desired treatment is pumped the pack its low probability of success. Shell Petroleum Development Company Nigeria and Schlumberger successfully carried out this operation in

restricted.

e paper also had supplemental data of asphaltene precipitation propensity when contacted with gas either in the form of gas injection from s eristics of oil-water mixtures are generally different from gas/liquid systems. The differences in characteristics are caused mainly by the larg interface was assumed for the stratified oil/water flow. The transition from stratified flow to dispersed flow is based on the balance between ginal reservoirs which are destined to be uneconomic with dedicated production could become viable for production.ï¿½The application o hase how a team of Schlumberger and PEMEX specialists with reservoir production and process engineering expertise developed and im could potentially precipitate asphaltene at their commingling point. This problem might occur when fluids of very different densities are mixe more likely to represent realistic fluid behavior. The objective of this paper is to demonstrate the variation in the measured flow assurance .e. pipelines) facilities in hydrocarbon production. Combined with the high temperature pressure and stress associated with drilling comple to identify compositional grading3 to identify reservoir compartmentalization4 5 to measure in-situ pH6 to monitor the cleaning-up proc

ulate MBO properties from PVT experimental data of gas condensate. Coats2 also presented a different procedure for gas condensate fluid

ve the fluid content of stacked reservoirs. In Kalimantan Indonesia it is common to have low resistivity pay zones which can contain signific milar pressure gradients. One far more risky practice is trying to infer PVT properties of formation fluids from pressure gradients based on s

completion and production facilities and optimal planning of reservoir production strategies depend strongly on adequate characterization o

much more in the case of determining small amounts of mobile oil in a gas expanded zone drilled with OBM. A focused sampling device is etermine which (if any) HSE measures must be implemented for dealing with H2S at the various stages of exploration appraisal developm

ut it can also be observed in equilibrated systems when chemical potential gradients are balanced by gravitational potential gradients. Temp

o justify the extra cost of taking multiple samples in a small interval without some indication of fluid variations. It is much more preferable to

saturated oils are accompanied with a phase transition and a gas cap in the reservoir. Interestingly also pressure and temperature ranges ng tool (Mullins and Schroer 2000; Smits et al. 1995; and Crombie et al. 1998). This is accomplished by using a technique of monitoring OB

phenomenon is not limited to thick reservoirs but is observed also over relatively short vertical columns. This is also not only limited to reser er is different from that of crude oils; this enables one to easily identify and quantify the amount of water in the tool flowline. Fluid from the fo ed fluidsâ€”with faster cleanup timeâ€”further ensures optimal DFA results.11 12 Current DFA techniques use the absorption spectroscopy

e presence is independent of the amount of energy in the system.ï¿½ Similarly if components are characterized as non-condensable then ns may also form in the near-wellbore region leading to emulsion blockage of porous media (Kokal et al. 2002). In addition to formation blo

voir (Fujisawa et al. 2008). Understanding the nature and composition of formation water is also critical to the economics of field developm samples validated by laboratory analyses â€“ four out of six bottles were full and pressured-up; two were not completely full but clean. This uires a competent phase behaviour specialist to generate and control the generated fluid data (Ref [2] [3]). A MFM could be located anyw most cases reservoirs have been producing below their dew point over long period due to pressure depletion caused by intense productio

erized by their mineralogical complexity and elevated temperature gradients. Algyo field (sandstone reservoirs of deltaic origin) is not an ex .[Knox 1964]ï¿½ The identity of these damaging compounds can vary from drilling mud particle invasion migratory fines (typically aluminos halite inhibitors are only effective at high concentrations (>250 mg/L). This high MIC (Minimum Inhibitor Concentration) requires high dosag

al flow and sometimes also in radial flow. From the pre- and post perforating flow measurements the core flow efficiency (CFE) of each sam icro-fractures and large pore throats are filled with small fragments (Figure 2).ï¿½This decrease in pore size results in the damaged zone n Siberia1-2. This is valid for both the oil-bearing as well as the water bearing formation that is the source of the injection water that is used entration (MIC) the scale protection becomes ineffective and a retreatment is necessary. However the task of predicting the treatment-life o

It was found that the the maximum Scaling Index (SI) (need to explain what is scale index) for mixtures of UZ formation water and injected stages of production may be applied to ensuring effective scale control to the end of the field life cycle.ï¿½It is the results of that review pro sian of the objective function are evaluated at pilot points. Ideally the points should be located at the points of maximum uncertainty from a

conceivable and most importantly within the defined hours of a typical working day.ï¿½ This has resulted in demonstrable productivity incr

ncy data streams in cases as extreme as those where data is input manually in mature assets.ï¿½ We illustrate this achievement with the e pressure data in order to design as an optimum field development scheme for the lower reservoir units in the southern part of the field. (Re

e advantages of both ESP and PCP production methods and to reduce the lifting cost a bottom-drive PCP system was evaluated for the pr

iod amount and type of matter that will be subjected to the microwave irradiation the cell material that the matter will be placed in (Datta an

East Africa. The shear zone was identified by geophysical means and has been demonstrated to experience right lateral movement in the C eability values range up to 5000 md. The 1st Eocene reservoir has an average depth of about 1000 feet and a gross thickness of about 750 est accumulations in the world the other two being the Western Canada basin and the Eastern Venezuela basin 1. Understanding the natu

basin is located south of Republic of Sudan. Tectonics was complicated by faulting and continuous fault movement and several sub-basins

sures hinder the submersible pumpâ€™s ability to deliver heavy oil to surface when water cut is lower than 10%. Introduction The Nukhul fo

l sensitive formations HCl is replaced with an organic acid such as acetic or formic acid.7 Various methods were suggested to retard the tr

nt transport. Either crosslinking a single organometallic system too early or too late risks premature screenout. (Nolte 1988 Walser 1988 A

mechanisms discussed in the next section restrict most of the wells from producing to their potential from reservoir engineering consideratio nnel and the environment at the wellsite. These benefits ultimately lead to a high success rate of sandstone acidizing and sustained produ sandstone formations (such as a mud acid treatment) involves many stages of fluid which increases the complexity of the treatment. An alt of them strongly laminated1. This productive intervals were formed during the Cretaceous period and is of continental origin covering seve have reported 15-30% loss in absolute permeability due to precipitation. An alternate method to enhance water removal is to increase th improve the ability to make the right decisions early in development planning. These data can give information about compartments and co

se to 58%. Shale would only increase to 3% of the volume and CBM would increase to 13%. With the increased percentage of gas being tig

racture lengths have been constantly increasing within the last few years. Moreover it is also quite common that the ongoing water injection ell as among nearby fractures.

on potential of about 3000-3500 bopd with 6 producer wells (5 in the reservoir B4 and 1 in the B7) and 2 injector wells (2 in B4 and 1 in B7)

eservoir. A field structure map of SF is shown in Fig. 3. In 2004 the first horizontal sidetrack well was successfully completed in the low per model forecasts â€“ the subject of this discussion. The reservoir characteristics of subject fields located in the Greater Green River and Pic he Sevier north-trending Charleston-Nebo thrust (that extends into the basin) and on the south by the Laramide north-trending San Rafael a ter reservoir quality and produces a very small amount of water which is probably water from condensation and rock compaction. The rese sented here is a proven technique for quantifying pay and sizing hydraulic fracture design options. The net height of laminated sand evaluat

so it is being increasingly applied for formation evaluation. Nowadays using WFT it is highly possible to simultaneously characterize extrem

nology advancements. This somewhat haphazard and quite often protracted end-state can lead to less than optimal surface kit footprint pa

ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½a. A piston is pulled back to expand the flowline volume thus reducing the pressure in the flo itial pilot development was based on massive hydraulic fracturing accompanied with a lift system [i.e. electrosumergible pumps (ESPs)] to

osits in the terrigenous deposits of the Vendian in the southern boundary of the zone was predicted. Nonetheless technical capabilities of e

mobile oil saturation and the associated relative permeability? Assuming a typical scenario in which decisions about where or even whether

voir management has led the industry in maximization of the recovery from producing fields and from new oil discoveries too. Most importan

es. Identifying rock types provide a framework for mapping their distribution which in turn helps to define the geometry of reservoir and non ation are well established each has limitations that should not be overlooked. In general these measurements can be divided into two cate re space is overprinted by both a diagenetical and a stress history responsible for dissolution dolomitisation fractures or stylolites for insta

ble contamination of a fluid sample by drilling-mud filtrate reduces the utility of the sample for subsequent fluid analyses. However the amo en hole logs may not fully resolve the fluid content of stacked reservoirs.ï¿½ In Kalimantan Indonesia it is common to have low resistivity p amic behaviour of a well and shows promise in understanding the performance of the water sweep at the later stage of field development. understanding of the spatial heterogeneity flow unit definitions and the fault compartmentalizatio ess the four objectives described above have led to the design of a tool with unprecedented application for formation evaluation. We will dis e been recognized as being essential for correct petrophysical characterization of these reservoirs.

ir input parameters has a great impact on choosing the best and suitable model to be used. The uncertainty in the input parameters for the has a great impact on choosing the best and suitable model to be used. The uncertainty in the input parameters for the different shaly sand 2008). At each step of this workflow there are log displays and cross-plots to check results against available core data. These checks will be tional logs. The method is capable to provide a more accurate estimate of net reserves. Facies or rock type classification using the artificia minated by high energy deposits (grainstone layers cross bedding etc.) rich in macrofossils.ï¿½ Vugs are developed in some intervals.ï¿½ laced on the use of NMR logging to delineate reservoir properties to a finer resolution than convention tools. In addition the use of images a

vity and sand volume fraction are derived and the effects of the input parameters on the results. Next we show how to use NMR to verify th

dia in a bilinear flow characterized by a slope of ï¿½ (m = 0.25) of the Log-Log pressure-derivative plot (Azzouguen et al 2000). rease tolerance to high solids content; such that the presence of solids does not plug the formation tester tool or damage the pump module ons but in practice some fractures interpreted in images are often not to be seen in the cores. Likewise some fractures that are occasiona Cretaceous sequence may have facilitated lateral and or intra-formational migration of hydrocarbon into the Tayarat Formation reservoir uni

tion. The spatial characteristics of geostatistical methods in variogram kriging and stochastic simulation make them the tools of choice for r hole images to identify the thin bed reservoirs with the best productive potential. The following sections describe the workflow and the deta ed with time: the first is the deconvolution of low resolution logs a good account can be found in Looyestijnâ€™s 1982 paper1. The second

ern of injecting and producing horizontal wells. Many cases with varied reservoir properties and stress conditions demonstrate the importanc

t to increased risks of hole closure that might be attributed to the complex and rapidly varying formation stresses. In addition drilling throug

gging suite to characterize the fractured carbonate reservoir rocks. s. The results of core investigations and well test analyses showed that the productive unit â€œM consists of a complex fractured vuggy-po

igations and well test analyses showed that the productive unit â€œM consists of a complex fractured-vuggy-porous type of a reservoir. A p

bility of water wet particles in the formation to oil wet.ï¿½ These particles which are originally immobile may then be mobilized and can cau

ause quartz volcanic lithics mica and minor accessory heavy minerals are present in the rock composition concurrently with thin shale-silt s thin beds washouts near wellbore alterations tight formations etc. where it may be more efficient to utilize NMR data. Hydrocarbon type porosity accuracy to expect from modern NMR acquisition modes over a wide range of inversion parameters and noise."

process can give only an insight into the nearer wellbore vicinity valuable information about the reservoir can be obtained. Productive reser ish field is post-Eocene. The recent Mishrif layering scheme divides the reservoir into 9 geological surfaces (time lines at field scale). There

ained in real time and at in situ conditions and fluid composition is derived from the signature using the proportion of methane (C1) ethane ertical resolution. Proper sampling practices are essential to preserve the composition of the extracted fluid as close as possible to that in th

roduces under a strong aquifer-drive directed from the northern flanks and bottom of the field. The low mobility-ratio of oil and water phase ncrease with increasing overbalance.ï¿½ Some operational aspects of wireline formation testing have been discussed for such environmen

of the results is given.ï¿½ We also discuss how acquired data and results were later used for field management. During the WFT survey t meabilities initial pressure and productivity index. The model is generalized and is equally valid where supercharging effect is not profound. ons for the plan should be done only after taking the risk factors into account. Therefore an iterative procedure is required which generally c mentalization where the thickness of the main flow units is below the resolution of current surface seismic technology and stratigraphical c

96. Paper SPE 104034 provides additional background information on the structural complexity of the block general stratigraphy and the re 00 to 250 scf/bbl.ï¿½ The reservoir is supported by strong water drive however most strings require artificial lift due to low reservoir pressur

oduction from 1980 through 2003.

the flow along the horizontal section may be altogether inhibited. Practices have been reported to optimize well placement drilling comple uction from 6000 STB/d. The driven mechanism has been identified as solution gas and water drive. his paper presents an innovative approach for extensibility and flexibility providing many previously unavailable possibilities for advanced F ump/compressor speeds. These devices are often manipulated through remote actuation which means that the engineer can make an adju optimised field-wide reservoir management plan. A recent full field review[1] confirmed the presence of a strong aquifer drive throughout the

ugh the well model back into the reservoir in order to account for the changed boundary condition imposed by the surface model in the rese resulting IAM technology which will evolve through a number of rounds of deployment. Collaboration that has never been seen before in hase how a team of Schlumberger and PEMEX specialists with reservoir production and process engineering expertise developed and im lopment strategies.ï¿½ Although automated methods exist that assist in the history-matching task the uncertainty reduction in deterministic lateral horizontal sidetrack wells are being completed with expandable sand screens in openhole wells making water control difficult to ac

cantly improve production efficiency of the remaining potential attic oil locations horizontal well is the first priority among various alternative nvironment. We strive to develop reservoir understanding and characterization as elements that constitute the baseline to maximize the su ng and casing collapse problems due to compaction during production which resulted in lower gas recovery. Well histories are quite compli rement of the degree of compartmentalization caused by this fault.

new measurement is based on novel symmetric transmitter-receiver configurations. In favorable conditions such as in thick resistive beds m ntact up to 40 ft deeper then originally encountered on the 1990 appraisal well. Oilexco generated a field development plan based on an in process of creating and constructing new wells based on measurements acquired from existing wells.ï¿½ï¿½ï¿½ One activity is the task o n design process the operator decided to introduce one PDG in each of the final wells (Fig. 1). A high-resolution quartz gauge was position entials of a field based on a minimum of data time efficiently is a key for unlocking these potentials. Target of the Approach Most of the fie o investigate sanding tendency for various completion scenarios on the shallow and deeper reservoirs. Decision and risk analysis complete ol theory has been used previously for optimization of injection and production rates in a fixed-well configuration (Ramirez 1987 Asheim 198

ons are generally applicable for a single well and used widely in the area of well testing.ï¿½The efficiency of analytical models is generally a slightly compressible fluid provide the basis for such a technique. They have been successfully used for well testing applications for many inistic.8-11 Both approaches have been successfully applied for conditioning geological models to production history and comparison betwe

tterns present. Geological continuity is preserved and the optimization problem is formulated in such a manner that geostatistical paramete

nent material balance equations an energy balance equation mass equilibrium equations and saturation and composition constraint equa hting or multi-point high order weighting schemes. gh GOR/water cut wells or identify the non-productive intervals that may need workovers. The challenges and proper production logging me

ems with horizontal wells1 2 3 4 5. Accordingly appropriate technologies can be applied to solve these problem such as shutting off the hig

and this has been verified experimentally (Ayoub et al. 2006). The fracturing process depending upon reservoir-matrix permeability can ca haviour given in previous studies was the fracturing fluid. Commonly cross-linked polymers facilitate hydraulic fracturing treatments the f this well demonstrate relatively high levels of total well production but recent production logging results confirmed that contribution is dom nd and within fracture using some special techniques for proper grid construction. Such approach was used inï¿½ï¿½ papers2 3-6ï¿½ and w depth and interfacial slip can have an important effect on fracture propagation in such formations. In this paper we present a fracture hei ence the results substantially. Production forecasting in horizontal wells suffers even more when using simplistic methods because the ver

s four different parameters are typically available for use as matching parameters i.e. permeability fracture half-length fracture conductivi ormed by Meyer and Jacot5.ï¿½ In that investigation the authors developed a general solution from resistivity theory for computing the dime e past of fracturing vertical wells either open hole or across long perforated intervals. In such cases indeed the flow source is assumed to effect) is the most critical near-wellbore phenomena as it may significantly increase the treating pressure and may result in early screenou the early-stopping and weight-decay methods.) Also two or more neural networks can be combined to produce an ANN with better error pe

ht introduce some uncertainty in the computed reservoir pressure history. PVT data can be also uncertain since some reservoirs have no rep

sts of two isothermal vertical plates with different temperatures separated by a narrow space. The space can be either without a porous med

This approach is similar to the one proposed in [10] with the following major differences: we obtain multipoint flux transmissibility coefficien

otomicrograph.ï¿½ The blue areas are vugs. The elastic simulation numerically simulates the structural deformation of the reservoir by solving linear elasticity equations under given bo

can result in numerical smearing of flood fronts and grid orientation effects may also be observed. tures is relatively high. One way of removing the CFL constraint is the use of an implicit method for the saturation transport along streamline id-block scale e.g. based upon complex gridding schemes in which fractures are represented explicitly either as volumetric grid cells or as

data from the first 8 years of production. Then participants were asked to predict cumulative oil production for 16.5 years of total production

(Mackay and Sorbie 2000). In this paper various scenarios will be considered where modelling of in situ scale precipitation is conducted us

time step). It is apparent that the streamline simulation can be much faster than a conventional sequental method (e.g. IMPES [11]). The g culation time and thus facilitates the modeling process for large reservoirs. the size of the business from an economic point of view identify benefits through optimizing infill locations using data mining methodology.

es a means of condensing the data into few parameters which are nevertheless quite rich because they describe the patterns in the data. rk we model devices requiring looped flowpaths by extending the multisegment well model in a full-field simulator (Schlumberger 2008a 20

on segments and reservoirs. PVT analysis of different samples from the NKJC shows that the hydrocarbon fluids are generally at near-crit

rom the slope of the plot of the inverse of the apparent permeability 1/kapp vs. a dimensional pseudo Reynolds number V/Î¼ (also called th xpected fractional flow of water fw under production? We share our experience from certain Middle East reservoirs of the behavior to be the reservoir. The through-tubing drilling campaign was chosen as the best option because it would reduce risks and the costs associated angle well. The situation becomes exceedingly critical if the drilling is being carried out in a tectonically active region involving multiple fault d on its use at the SPE Forum and it is intended that any of the following terminology could be substituted by the readership.1 2 Operator

es of state and federal waters in the Beaufort and Chukchi Seas. The Alaska North Slope petroleum province corresponds to the portions o he tensile strength or the compressive strength of the cement (using the Mohr-Coulomb failure criterion for the latter) depending on the exp

after logging. Saturation Measurements Behind Casing Three main types of data are used in saturation monitoring: through-casing resistivit well F-29 on the Oseberg Sï¿½r field. The well was completed with flow control of both the main bore and lateral bore with flow measureme bility of 15-60 md bubble point pressure of 300-1900 psia and oil viscosity at the bubble point ranging 2.5-15 cp. Uncertainties of the fluid ty pret since the geothermal gradient is essentially zero in a horizontal well.ï¿½ Interpretation gets more difficult once water breakthrough occu

that OBM contamination levels are low such that samples are of high quality and DFA data is valid. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿

d in open hole with a wireline formation-testing device equipped with a probe or packer module pumpout module and sample chambers. At ata can then be pulled and analyzed on a regular basis to determine reservoir properties such as kh product skin and current reservoir pre ment. Six injection stages lasting about 30 minutes each were utilized to stimulate the six depth intervals ranging between 30 to 100 ft in leng o misinterpretation of data and subsequently inadequate preparation for treatment success. The key to success is in applying multiple tech

rical submersible pump (ESP). Monitoring of the temperatures along the wellbore using the DTS system continued through 2005. move the liquid film along the conduit wall is consistently greater than that required to suspend and lift the entrained liquid droplets upward i wall is consistently greater than that required to suspend and lift the entrained liquid droplets upward in the flow stream. As noted by Turner d continuous temperature curve acquisition overcame problems with early temperature log interpretation by providing large data sets to prop

y the lost production but also the action that needs to be taken in order to reduce it as soon as possible in such a way that a performance m s that utilize the latter approach.

ons.4-8 Waxes on the other hand are also high molecular weight highly saturated organic substances.ï¿½ The formation of wax crystals d OGICAL FEATURES Based on cores Alamein dolomite of R field is a massive hard to very hard dolostone. Mostly it is medium-grain size nderstanding the exploration and appraisal or field-development objectives and translating these into acquisition objectives is essential for s r pressure changes. Flow distribution is monitored using a permanently installed fiber-optic distributed temperature system (DTS). During e ing to casing deformations and also potentially identifies circumstances that may lead to casing failures. The combined monitoring also can d effective voidage replacement is considered critical to optimum reservoir drainage (Fig. 2). The development strategy of the Azeri field re andface sensors must be deployed on a separate completion run. Historically subsea wells have lower total production compared with equi

f Organizing Maps (SOM) working together in a production performance workflow solution can help to overcome these limitations. To do so of flow distribution it is necessary to consider technology and technique that functions with a high degree of reliability in these oftentimes h

hind casing is therefore vital. Two parallel and complementary methodologies have been evolved over the years and numerous patents and

nitially quite successful the field has experienced uneven distribution of water flood front vertical and lateral sweep due to reservoir comple bjectives while acquiring high-quality inter-well data traditional methods were enhanced by the addition of more advanced (deep reading) m but this is predicted to increase to 540 Bcf/year by 2014 with current booked reserves of 263 Bcf. Alberta alone is predicted to have 500 T obtained unless a well-developed natural fracture system is in communication with the wellbore (Mavor et. al. 1994) The degrees of cleating s) are generally much wider than your average pore throat in a clastic rock and therefore are much more susceptible to fluid invasion dama ckwater fracture-stimulation treatments were sought as a less-expensive alternative. Although well performance was not increased drastical ï¿½ However a risk of high viscosity slugs is to leave residue and thus lower the fracture conductivity at its entry point with the wellbore. In

d by approximately 65%.ï¿½ These treatments have become the norm in the Barnett because of the extremely large fracture surface area th cription of the reservoir. To quickly acquire knowledge and guide imminent placement (well spacing and pattern) designs various well spacin

ormation thickness varies from 200 to 800 ft through the reservoir. The productive rock is typically a black organic-rich shale with ultralow p scale acid stimulation treatment and to predict the performance of the stimulated wells. For carbonate acidizing on the other hand the chem

essor Surface Venturi Downhole Tubular and Valves Air Turbine Inlet Air Compressor As shown in the subsequent calculations the prim t-type shore terraces reservoirs. The PK group of reservoirs deposited in the deltaic coastal setting. AS reservoirs are associated with the d

e depleted layers. The Treat And Produce (TAP) Completion system has been developed to allow the efficient treatment of individual layers

mly transported up the wellbore to the surface.ï¿½ Turner et al1 identified that there are two transport mechanisms that must be considered mly transported up the wellbore to the surface.ï¿½ Turner et al1 identified that there are two transport mechanisms that must be considered a for choosing the well location included the results obtained from detailed geophysical petro-physical and sedimentological analysis; and g

may be partially compensated by adjusting wellboresâ€™ flow rates with respect to each other. This is best done by establishing flow-rate

employed to achieve a parsimonious model of the given data. Note that a parsimonious model in this context refers to one containing the m

ggest that vertical communication through the entire reservoir section achieved through fracturing is a dominant mechanism for improved p

the higher oil saturations as calculated from vertical well logs and better permeability as noted by vertical well log resistivity invasion profile ace fractures with longer fracture half lengths and reduced fracture heights improving the possibility to contain the fracture in the pay zone T

gy has evolved and the scope of relevant well-types has expanded. e reservoir. These factors make it difficult without direct measurement to determine the inherent wettability of reservoir. The fact that the co ; Wolhart et al. 2004). Alternatively more advanced numerical models have been developed for hydraulic fracture simulators (Smith et al. 2 ty to use various mix-water fluid types. Viscoelastic Surfactant Fluid Development. Viscoelastic surfactant (VES) fracturing fluid systems ha ng costs associated with moving water to treatment facilities often make this an expensive option for operators (Kaufman et al. 2008 Horn nge from 0.42 psi/ft in the Upper Williams Fork to 0.56 psi/ft in the lower section known as the Cameo.ï¿½ Typical fracture gradients range ations. Modern frac-and-packs involving the use of the TSO technique high proppant concentrations and gelled fracturing fluids were first in cess. This paper describes a combined technique to control fracture height growth through the use of selective placement of artificial barrie members from both KOC and the service company worked closely together to recover the resources in these very challenging environments are often interbedded with sandstone lenses. As these reservoirs have been in production for several decades pressure maintenance is low expectations1.

s to stimulate each production interval independently to optimize gas production from each interval. The difficulty is to find a method that is ching of the brittle linear-elastic model with field data by means of the appropriate choice of effective fracture toughness shows that the valu atory Fluid Loss Measurements To model the fluid loss properties the VES system was injected into 12-inch long sandstone cores at a co

ell was the one that was producing naturally.ï¿½ Poor success of initial fracture-stimulations observed by most operators perhaps contribute

ill be discussed in details in this paper. The planning and execution process of the acid fracturing treatment that was implemented is shown at mitigate the yield stress effects to help restore the effectiveness of the full length of the fracture. In addition it presents the first data char in a highly laminated formation.ï¿½ Sand layers have contiguous thicknesses of only a few inches up to 15 ft.ï¿½ Very fine grained sandsto

e the borehole deviation are used not only the to determine fracture azimuth but also the distance between the treatment and monitoring w

statistical properties of the surface-roughness distribution are related to the fracture conductivity. uction development and enhancement activities have started in 2000. The AC-11 formation consists of laminated oil saturated sandstone. T yzing the placement and flow of various processes and materialsï¿½. Radioactive tracers have been found to be useful in developing inform

each segment.

lar HCl acid has high leak-off rates that hinder acid propagation during fracturing treatments. The rate of leak-off 3 Ct can be determined us

rtheless the observed seismic radiation can be used to at least constrain the orientation of the fracture plane in cases where the data cann

n. The problem of fluids displacement from porous media instability and viscous fingering was addressed in many papers [3-10]. Investigati n in the wellbore formation elastic properties and fluid loss data. Rueda et al.2 discussed considerations for pushing fracturing limits to max

io sandstone cores (~ 0.2 md) confining the proppant pack a metal cell with a movable top piston for controlling the closure stress pressu

he Carmï¿½polis field were below the expectancy. The low reservoir pressure associated with the high costs of the fracturing operations an ory experiments and was recognized as an important feature.23 27 Numerical modeling of fracture growth resulting in offset development is available nodal analysis packages cannot easily model auto gas lift wells. Interestingly the flow control valve technology developed for au and perforated completion with oriented perforating. Tubing conveyed perforating (TCP) assembly consisted of a gross length of 1 301-ft w lity to effectively stimulate or fracture different intervals of the horizontal wellbore particularly in reservoirs that are not naturally fractured. T ty to effectively stimulate or fracture different intervals of the horizontal wellbore particularly in reservoirs that are not naturally fractured. Th vity index but usually damage due to drilling mud is a concern. During the recent years mud systems evolution was remarkable. The objecti

he field from ï¿½5 cP 8 cP 12 cP 19 cP to 21 cP and corresponding API gravities. Figure 1 shows the location of Bloque 15 Ecuador. Ge

imizing the inflow profile along the well using fixed control devices sized prior to installation (e.g. Brekke and Lien 1994; Permadi et al. 199 9. The experiment was designed to perform two tests in one large block. Two conditions for hydraulic fracture propagation were examined:

characterization other frequently asked questions for thinly bedded reservoir are: What is the productivity of a well drilled in this type of r e inclination and orientation in the in-situ stress field and formation strength. lf can be filled with rock and charge debris.ï¿½ Ignoring the heterogeneity caused by perforations can result in major simplification in unders w perforating technique. Background Well-0 was the discovery well of Field-Î². It was drilled as a vertical well and completed with a standa rmeability of 26md followed by water saturation of 37.7%. After 2 years of production gas rates started to decline from 18 MMSCF/D down rforating technology developments have been focused on obtaining deeper penetrations. However few breakthrough advances have been e the thin pay sandstones often have a bottom oil/water contact. Acid stimulation is possible; however the success rate of sandstone acid s 16 and has produced over 1.6 Tcf gas and 53 million barrels liquid from Cretaceous and Jurassic reservoirs. The Cotton Valley reservoirs at ble. Also executing a job with such a high drawdown in these conditions would be dangerous and is not feasible from an operations standpo ure transient that provides an opportunity to evaluate the dynamic formation properties with interpretation methodology of the PTT. A variety sanded in due to higher than expected underbalance Premature firing of guns due to pressure surges. ng system developers. A second application is to special perforating jobs that may require some alterations to an existing perforating system

s pilot program led to a development plan with 16 horizontal producer wells with lateral extensions around 650 m and 14 horizontal injector

ve failed prematurely due to either productivity loss from screen plugging or loss of sand control from screen erosion.ï¿½ Consequently mo ola fields are located in shallow immature sediments which typically have reactive shales that are incompatible with water based fluids. The

pletion cost an intensive laboratory activity was carried out to identify a chemical solution to prevent the problem related to the exposed sh r pump rates for the same alpha-wave dune height as in conventional gravel7 and drag reducing additives that can be used in the carrier flu

que adopted by many operators in this region. Since most of these reservoirs contain reactive shale streaks they require synthetic/oil-bas

ons. Stand Alone Screen (SAS) solutions are perceived to have a higher risk wrt running to TD hole stability and plugging potential along a to surface. The wormhole dimension was calculated to be greater than a 6 inch equivalent diameter. To date there have been several failu s for these secondary targets have been limited. A screenless completion eliminates the need for screen to prevent sand failure. In addition

examined seven wells in the south eastern part of Sarir. It identified the source and severity of the sand production linking the problem to th can be achieved by focusing effort on certain input data targeting and reducing specific uncertainties and by employing pragmatic models tion for this field is obstructed to a lower level which lead to significant economical loss. A geomechanics and sanding study was initiated i

strength of the reservoir rocks which is directly related to their risk for ure were derived from analysis of openhole logs standard leak-off test data coefficient of active earth pressure and qualitative stress inform ar et al. 1984). The addition of uncross-linked polymers to HCl improved acid penetration; however acid placement did not significantly imp and the fracture conductivity is more dependent on the rock strength than on the initial etching pattern.ï¿½ The success of the acid fractur ntegrated with the new technology and enhanced methodology which is constantly developing. Although relatively new with the Permian B

ting acid systems were injected through limestone cores suggested that viscoelastic diverting acid systems would provide diversion during he damage created during the drilling or cementing process or damage created by sustained production. Typical wormhole structures can r

vate the overall complex chemistry involved in the sandstone stimulation process.5 Accordingly the need to have a proper tubing pickling pr

c and formic acids are typically used at concentrations less than 13 and 9 wt% respectively to avoid precipitation of calcium acetate and cal

d the treated region eventually becomes the sink for the acid and leaving other regions not adequately acidized.ï¿½ Therefore one of the m Most of these gas fields are in production since the 80-s and have been significantly depleted with reservoir pressure Pres as low as 12 b teristic dissolution patterns are observed at different injection rates 5 6. These patterns are categorized as face dissolution wormholing an have played a key role in restimulation success during the past ten years as have the technological advances in stimulation fluids and prop m a well drilled and completed in 1993. Accordingly the operator opted to run a dipole sonic imaging tool to have a better estimation of criti

servoir is fully or partially stratified and tectonically screened. The productive horizons are composed of terrigenous rocks the host rocks b

ng the complexity of the operation as well as the production loss from the lower Burgan formation during the workover. Thus an engineering plied selectively however. Only cement barriers between formations where production is planned are tested (Figure 1). Intervals between res p it indicates a time within the shut-in period. The basis of the CCTs lies in the principles of slug tests originally designed for testing water oke followed by a shut-in period to let the reservoir return to its initial pressure Initial 8-hour flow period on 24/64 choke to perform flowing s on methodology is reported in the paper that permits the quantification of the well and reservoir in situ properties on a layer-by-layer zone-b

th drawdown and buildup tests. Several numerical examples are included to illustrate the step-by-step application of the proposed techniqu ls in nonhomogeneous and heterogeneous formations and reservoirs. Nevertheless understanding the fundamental radial flow regime is e nformation based on few scattered measurements is propagated to make important decisions.ï¿½ In case of production engineers the con ective could be achieved with some success then as stated by Levitan the deconvolved response would remove the constraints of conven

han doing the traditional deliverability calculation with four points. Then he uses these parameters to predict future deliverability by forward s of equipment. The Abu Al Bukhoosh oil field is located 80 km offshore Abu Dhabi. It is a large NE-SW anticline affected by NW-SE trendin emote unmanned operations Lowering of risk associated with well testing in gas well operations through elimination of active control system

an the traditional separation approach. It is not surprising that the use of multiphase flowmeters has grown significantly the worldwide num

gh energy gamma ray being already present for density measurement the addition of a second radionuclide or an appropriate chemical sou block size. The authors recognized that well tests would not fully cover the full field model. Therefore they found it useful to calculate proper

we describe a new technique for differentiating well test pressure data called the digital pressure derivative technique (DPDT). The DPDT pr inflow to each zone (Fig. 2). The 21 centralizers acted as electrodes to form an electrode array that spanned the 694-ft-long completion. Ea

ted but cannot easily be controlled; others (such as fluid loss) can hardly be predicted at all. In any case they belong to the class of fault-fre dependent components of the stress tensor at a point and so procedures for in-situ stress estimation at depth must combine complementa

enhanced oil recovery but also for long-term storage. -injection study for a CO2 injection illustrate aspects that are needed for designing monitoring and injection strategies. Injection of CO2 in S

es from coal deposits leaking natural gas pipelines landfills forest fires wetlands rice growing and cattle rising. Nitrous oxide also know in achieving a successful storage project. In particular seal integrity must not be impaired by the mechanical effects of storage operations.

er zones hence adding value to the DIACS completion design Experiences from this well show that even longer wells can be drilled from

orkers on these structures during this time was Gill (1973 1975 1977 and 1979). In 1987 Cercone and Lohmann discussed diagenesis in t rmore high CO2 concentrations are encountered in diverse areas. The scientific study of natural CO2 deposits is still at an early phase. Pr een success at much lower porosity in the range of 8-10%.[3] Obviously if a 16% porosity cutoff was applied routinely then somewhere in ural depletion without considering any pressure maintenance.ï¿½ The simulation model and parameters are described as follows.

petrophysics characteristics of altered basement rocks in the White Tiger (Bach Ho) field change very strongly both with depth and area. Pe sired treatment is pumped the packer is either deflated and retrieved or the running tools are disconnected from the TTIP and the coiled tu essfully carried out this operation in four wells drilled and completed in Field X. The biggest issue associated with cement squeeze in a sing

er in the form of gas injection from surface or downhole commingled gas from another zone. A PC-SAFT equation-of-state (EOS)2 3 based ristics are caused mainly by the large momentum-transfer capacity small buoyancy effects lower free energy at the interface and smaller ow is based on the balance between the turbulent energy of the continuous phase and the surface free energy of the dispersed phase. The for production.ï¿½The application of intelligent completions for such commingling wells allows not only the production and recovery optimi neering expertise developed and implemented a workflow to put together a single integrated well-network-process simulation model and u s of very different densities are mixed. For example a problem may occur when a condensate is mixed with black oil. The density of the ent on in the measured flow assurance properties of a waxy crude oil at actual field conditions and at stock tank conditions. In particular the im tress associated with drilling completing and producing wells such corrosion can cause catastrophic failures of the downhole completions pH6 to monitor the cleaning-up process using downhole pH when sampling formation water in a well drilled with WBM7

procedure for gas condensate fluids. Coats procedure was extended by McVay4 for volatile oil fluids. Walsh and Towler5 also presented a

pay zones which can contain significant amount of hydrocarbons. Also the well known density-neutron separation may not always result in from pressure gradients based on so-called database regardless how much uncertainties of â€˜fittedâ€™ pressure gradients can contain. B

ongly on adequate characterization of the physical and chemical properties of the fluids. In many deepwater and other high cost wells wireli

OBM. A focused sampling device is introduced to overcome this challenge by isolating small amount of filtrate that can mix with sampling lin of exploration appraisal development production and abandonment of a given prospect. Indicate the need for special metallurgical or p

avitational potential gradients. Temperature gradients can also contribute to concentration variation. In light oils with gravity greater than 35

ations. It is much more preferable to perform the sample analysis in situ so that the subsequent sampling program can be optimized in real t

pressure and temperature ranges of 350-400 bars and 80-100C are close to critical temperature of mixtures of hydrocarbons in several se using a technique of monitoring OBM contamination which is based on measuring the change of methane content and color in the flowline

This is also not only limited to reservoirs containing gas condensates or volatile oils but is observed in heavy oil reservoirs as well (Mullins in the tool flowline. Fluid from the formation flows through a probe into a flowline positioned in a tool in the wellbore and is assayed by a do es use the absorption spectroscopy of reservoir fluids in the visible to near-infrared (NIR) region. On the basis of their molecular structure d

acterized as non-condensable then a gas phase will always be present which contains these components. . 2002). In addition to formation blockage and general difficulty in the separation of oil and water in production facilities one of the main dra

to the economics of field development. Chemical analysis of formation or connate water determines the scaling and corrosion potential of p e not completely full but clean. This may be adopted as a standard best practice and is applicable to any Wireline gas-condensate samplin 3]). A MFM could be located anywhere from the well head flowing temperature and pressure up to separator conditions or lower. Figure 1 pletion caused by intense production or simply due to the imbalance between low productivity and production requirements. The experience

ervoirs of deltaic origin) is not an exception (Table 1) and shares the need for a thorough preparation to execute any matrix acidizing treatm n migratory fines (typically aluminosilicate fines) or inorganic scales. Concentration) requires high dosage in continuous injection applications. When the same chemistry is used in squeeze applications the sq

re flow efficiency (CFE) of each sample is calculated. e size results in the damaged zone having a permeability much decreased from that of undamaged rock Pucknell & Behrmann[1].ï¿½Add ce of the injection water that is used for the water flooding. The technological production processes that are prevalent in the local industry sh task of predicting the treatment-life of an inhibitor squeeze is difficult in a multi-layered commingled system due to commingling of different

s of UZ formation water and injected seawater at reservoir conditions is 0.57 for strontium sulfate which is only just above the positive thresh ¿½It is the results of that review process that are presented in this paper. Reservoir Description and Field Development Gyda hydrocarb ints of maximum uncertainty from a flow perspective and also the number points should be kept as low as possible to decrease prohibitively

ed in demonstrable productivity increases wherever the technology is properly positioned and utilized.

illustrate this achievement with the example of Activo Integral Burgos (AIB) the oldest and largest onshore gas-producing basin in Mexico in the southern part of the field. (Ref 2)

PCP system was evaluated for the production of extra-heavy oils. A discussion of the applicability of this artificial lift method and a compariso

the matter will be placed in (Datta and Anantheswaran 2001).

ence right lateral movement in the Cretaceous. All the basins of the Sudanese rift-related system such as the Muglad White Nile Blue Nil and a gross thickness of about 750 feet.1 A structure map is given in Fig. 2 ela basin 1. Understanding the nature of reservoir fluids is essential for the optimization of completion facilities design and reservoir produ

movement and several sub-basins formed result in this large numbers of tensional faults. Structures within these depressions show signific

an 10%. Introduction The Nukhul formation is a depleted fractured dolomite reservoir producing 9 to10 API heavy oil with water cuts up to

hods were suggested to retard the traditional mud acids including the use of buffered-HF systems 8 fluoroboric acid9 and mixtures of esters

eenout. (Nolte 1988 Walser 1988 Almond 1984) Gelling at varying temperatures can be achieved by delivering a crosslinker that has two (

m reservoir engineering considerations. Hydraulic fracturing has been found to be the most effective technique to bypass skin-damage in the stone acidizing and sustained production increase from high temperature sandstone reservoirs. A comprehensive laboratory study which e complexity of the treatment. An alternative approach uses chelating agents combined with acids as the main treatment agent. Chelating s of continental origin covering several formations whose names depend on the geographical area (see Fig. 2). The lithology changes from ance water removal is to increase the volume displaced in the initial stage by decreasing the capillary pressure of the formation. The reduc mation about compartments and communication in the reservoir. Later in the production cycle these data can be used to differentiate produ

creased percentage of gas being tight gas it has become more challenging to produce especially as production moves to more remote are

mon that the ongoing water injection program is above the fracturing pressure hence water injector wells under intensive and long injection

2 injector wells (2 in B4 and 1 in B7).

uccessfully completed in the low permeability Ratawi Oolite reservoir in the SF field. Well test data showed production stabilized at 914 BOP in the Greater Green River and Piceance Basins their static and dynamic modeling workflows and a comparison of the modelsâ€™ and a aramide north-trending San Rafael and northwest-trending Uncompahgre uplifts.ï¿½ The basin is an asymmetrical syncline with the deepes ation and rock compaction. The reservoirs are overpressured with a pressure gradient of approximately 0.7 psi/ft. To honor the pressure gra net height of laminated sand evaluated is compared with post-frac well production data to determine if the additional perforated intervals and

o simultaneously characterize extreme rock and fluid complexities with sufficiently high resolutions so as to greatly aid in reservoir evaluation

than optimal surface kit footprint partial-depletion related completion problems potential over-capitalization and overall systemic inefficien

hus reducing the pressure in the flowline. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½b. Once pressure drops below sand lectrosumergible pumps (ESPs)] to take advantage of the enhanced productivity. The main purpose of the hydraulic fracturing was not only

netheless technical capabilities of exploration at that time did not give the opportunity to meet the challenge of prospecting and exploration

isions about where or even whether to drill a production well need to be rapidly made an efficient reliable method of diagnosing the transit

ew oil discoveries too. Most important is continuous reduction of lifting cost by introducing new technologies. These technologies have redu

e the geometry of reservoir and non-reservoir bodies. This framework is fundamental for creating a static model. Both core and log measure ements can be divided into two categories: static and dynamic. sation fractures or stylolites for instance. However reservoir engineers do not always see the purpose of integrating such high resolution to

nt fluid analyses. However the amount of filtrate contamination can be reduced substantially by use of focused-sampling cleanup introduce t is common to have low resistivity pay zones which can contain significant amount of hydrocarbons.ï¿½ Also the well known density-neutro e later stage of field development.

for formation evaluation. We will discuss here the application of the rich data set produced by this tool for the evaluation of lithology and min

ainty in the input parameters for the different shaly sand models will complicate the interpretation for a specific shaly sand formation as usin ameters for the different shaly sand models will complicate the interpretation for a specific shaly sand formation as using improper model th able core data. These checks will be described for each step. Both routine core analysis (RCAL) data such as porosity permeability and gra type classification using the artificial neural net technique was successful in replicating rock classification. An average quantitative resistivit are developed in some intervals.ï¿½ The other common texture is that of sucrosic dolomite of varying crystal size. Due to this geologic com ools. In addition the use of images and wireline formation testing from the example well provides the appropriate benchmark for improving

e show how to use NMR to verify these two outputs. The third verification is the sand porosity computation. Finally the fourth and last verifi

Azzouguen et al 2000). er tool or damage the pump modules. We will treat each of these aspects individually in the sections which follow. some fractures that are occasionally seen in cores (i.e. core discing) are not seen by images logs. Such fractures are artificial in origin ca the Tayarat Formation reservoir units. An attempt has been made to explore this petroleum system using the newly acquired 3D seismic w

make them the tools of choice for reservoir modeling. Such techniques are especially useful to characterize geologic facies object size pe s describe the workflow and the details of the analysis. stijnâ€™s 1982 paper1. The second is the use of shallow measurements with intrinsic high vertical resolution to enhance the deeper measu

onditions demonstrate the importance of reservoir conditions that in some cases may be manipulated to enhance oil production. Based on t stresses. In addition drilling through highly pressure-depleted reservoirs raises considerable risks of excessive mud loss internal blowout

sts of a complex fractured vuggy-porous type of a reservoir. A presence of opened fractures was determined as a key factor that defines pr

uggy-porous type of a reservoir. A presence of opened fractures was determined as a key factor that defines productive potential of wells.

may then be mobilized and can cause near wellbore formation damage. iv. Plugging by particulates particularly fluid loss control additives

ition concurrently with thin shale-silt laminations over certain intervals. In these formations the petrophysical analysis is affected by strong l utilize NMR data. Hydrocarbon type is usually inferred from well logs or from prior field knowledge. Sometimes large density-neutron separ

meters and noise."

ir can be obtained. Productive reservoir zones and formation properties can be determined provided there is proper flow monitoring at the aces (time lines at field scale). There are two major sequence boundaries with exposure time one at the top of the underlying Rumaila Form

proportion of methane (C1) ethane to propane (C2-5) the hexane plus fraction (C6+) and carbon dioxide (CO2). The gas-oil-ratio (GOR) o luid as close as possible to that in the formation minimizing as much as possible the risk of undesirable phase transitions. Wireline-convey

mobility-ratio of oil and water phases (0.47) and generally homogeneous thick reservoir sequences indicate oil is swept by a favorable gra een discussed for such environments (Ferment et al. 2004) highlighting issues with high differentials probe plugging fine laminations and

agement. During the WFT survey the dual packer and single probe combination also enabled us to conduct interval pressure transient tes upercharging effect is not profound. Background During or immediately after drilling pressure near the wellbore is influenced by mud filtrat ocedure is required which generally converges after several iterations. Converging to an optimized field plan involves identifying the best su mic technology and stratigraphical correlation across wells is very difficult. In this context the use of wireline pressure tests for reservoir cha

lock general stratigraphy and the reservoir management structure put in place by PESA. For the sake of completeness a generalized strat ficial lift due to low reservoir pressures prevailing fluid properties and continuously increasing water cut."

mize well placement drilling completion and workover intervention for such cases1 2 3 4. Artificial lift maybe used to improve the performan

vailable possibilities for advanced FM users. The paper is presented in the following sequence: the big picture depicting the FM framewor that the engineer can make an adjustment from the office and receive quick feedback on the result. a strong aquifer drive throughout the Betty field aquifer energy provided to the reservoirs combined with the favourable mobility ratio resulte

ed by the surface model in the reservoir. hat has never been seen before in the Oil & Gas industry will need to be established if suggested improvements such as $30mn per year eering expertise developed and implemented a workflow to put together a single integrated well-network-process simulation model and us uncertainty reduction in deterministic workflows is a trial-and-error exercise that is subjective and open to varying interpretations.ï¿½ This is s making water control difficult to achieve. ESPs are used in all wells of the field to improve productivity. Typical well production rates are o

st priority among various alternatives. In addition the poor petrophysical properties of shaly layers did not effectively produce oil from vertic ute the baseline to maximize the subsequent hydraulic fracture design and the resulting overall well deliverability. Thus we narrate a proce very. Well histories are quite complicated due to the workovers (add or squeeze perforations refracs commingling etc.). Fig. 2 shows a typ

ns such as in thick resistive beds measurements are able to detect conductive boundaries at distances greater than 15ft.1 The technology ld development plan based on an integrated reservoir model utilizing all well and test data with a sophisticated geophysical model derived ¿½ï¿½ï¿½ One activity is the task of reservoir modeling which has a rich toolbox of methods and techniques.ï¿½Nowadays even during t esolution quartz gauge was positioned on the exterior of the tubing string and exposed to wellbore pressure by a port; then it was connecte rget of the Approach Most of the fields in the world are water flooded.ï¿½ Thus mature water flooded fields cover the highest percentage o Decision and risk analysis completes the full cycle of reservoir engineering well placement and well completion has been rigorously evaluat guration (Ramirez 1987 Asheim 1988 Sudaryanto and Yortsos 2001 Zakirov et al. 1996 Virnovsky 1991 Brouwer and Jansen 2004 Sarm

cy of analytical models is generally judged by accuracy and speed. or well testing applications for many years (Gringarten and Ramey7 Cinco-Ley et al.8 Raghavan9 Al-Khalifah et al.10 Gomes and Reza1 uction history and comparison between the two approaches can be found in the literature.12 13 Unlike the deterministic approach the Baye

manner that geostatistical parameters are consistent in the final history matched model."

n and composition constraint equations. For thermal models where water component could reside in the gas phase the total number of va

es and proper production logging methods for various horizontal well conditions are discussed in the literature4 5 6 7.ï¿½ Once a problem is

problem such as shutting off the high water or gas entry perforations5 6.

reservoir-matrix permeability can cause mechanical damage through various mechanisms including fluid invasion into the reservoir polym hydraulic fracturing treatments the intent being that the polymer will be recovered once production is initiated. In the field only a fraction o s confirmed that contribution is dominated by dolomite section (zone 1). The result of this can lead to inefficient reservoir sweep and reduce used inï¿½ï¿½ papers2 3-6ï¿½ and allowed to account of various phenomenon taking place under gas condensate flow in vicinity of the hy his paper we present a fracture height growth model that takes into account the bedding plane interfacial slip. The model has been implem simplistic methods because the vertical communication caused by fractures is not properly modelled.ï¿½ In recent years numerical simu

cture half-length fracture conductivity and drainage area. However instead of using a rigorous flow model he states that it is often difficult stivity theory for computing the dimensionless productivity index of a vertically fractured well with an arbitrary fracture conductivity distributio deed the flow source is assumed to be a line of either fixed (PKN) or increasing (KGD and Radial) length with orthogonal flow along the fra ure and may result in early screenout. Pinching can be caused by a number of factors. produce an ANN with better error performance or other qualities giving the so-called â€œensemble learning methods a term that covers a

n since some reservoirs have no representative fluid samples for a complete PVT analysis and correlations are used instead for material ba

e can be either without a porous medium or filled with a porous medium. The thermal diffusion in a binary mixture causes one component t

tipoint flux transmissibility coefficients as an adjustment to standard two-point flux transmissibilities and the method of constructing an M-ma

r elasticity equations under given boundary conditions and simultaneously calculates the corresponding stress/strain tensor fields (Bourne

saturation transport along streamlines. This work is devoted to an efficient implicit numerical solution of the saturation transport along strea either as volumetric grid cells or as lower-dimensional objects at the cell faces. The performance of current finite-difference simulators can

on for 16.5 years of total production and characterize the uncertainty in this prediction.

u scale precipitation is conducted using the FrontSim reservoir simulation software (FrontSim 2008) which includes a specialised brine com

ntal method (e.g. IMPES [11]). The goal is to use the least possible number of pressure updates in order to maintain the required accuracy.

ns using data mining methodology. The objective of this paper is to present the methodology and results obtained during the analysis pha

ey describe the patterns in the data. These parameters can then be used for subsequent analysis. Description of method The proposed a simulator (Schlumberger 2008a 2008b). In the previous formulation of the model each segment could have only one outlet. This restriction

rbon fluids are generally at near-critical conditions. Figure 2-a shows a typical PVT diagram from one PVT sample in Marrat. The reservoir t

eynolds number V/Î¼ (also called the Forchheimer graph). The apparent permeability kapp is defined as ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ ast reservoirs of the behavior to beï¿½typically expected from open hole pressure surveys which have been performed in such zones and duce risks and the costs associated with a new well or having to pull existing tubing. The equipment and methods to drill successfully have b active region involving multiple faults and variable degree of displacement of the adjoining structures.ï¿½ While mentioning a stress map w ted by the readership.1 2 OperatorTerminology BPâ€œField of the Future Chevronâ€œi-field Shellâ€œSmart Fields Also during the

ovince corresponds to the portions of Chukchi shelf and Beaufort shelf and the onshore Arctic Slope as shown in Figure 1. The Arctic Slop for the latter) depending on the expected failure mechanism. In general decreasing the Youngâ€™s modulus or increasing the Poissonâ€™

monitoring: through-casing resistivity pulsed neutron capture and neutron inelastic capture measurements. Aulia et al. (2001) provide a co nd lateral bore with flow measurement of the main bore. Applied downhole two-phase flow and density measurement principles were the sa 2.5-15 cp. Uncertainties of the fluid type were eliminated with the extensive zonal sampling in the field. The PVT data illustrates that the oil h fficult once water breakthrough occurs.ï¿½ Array holdup tools of capacitance optical and resistance type have been available for some tim

ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ Minimize time on station such that rig costs and the probability of tool sticking are reduced.

t module and sample chambers. At the start of the sampling process fluids flowing from the formation are largely contaminated with drilling oduct skin and current reservoir pressure. This type of system and workflow has been proven valuable in identifying wells as candidates fo ranging between 30 to 100 ft in length. The well casing in these intervals was perforated and sealed off by packers from previously perforat o success is in applying multiple techniques that can help validate a particular observation from different vantage points. The case in point i

m continued through 2005. he entrained liquid droplets upward in the flow stream.ï¿½ As noted by Turner et al3 as well as from field observations of wellbore liquid unl he flow stream. As noted by Turner et al3 as well as from field observations of wellbore liquid unloading conditions4-11 that the criteria for by providing large data sets to properly identify transient temperature behavior. The natural extension of permanently installed DTS system

e in such a way that a performance monitoring closed loop can be established. As indicated by Othman et al1 with the production incremen

.ï¿½ The formation of wax crystals depends significantly on temperature change. Pressure and composition also affect their formation but n tone. Mostly it is medium-grain sized crystalline fractured and vuggy cquisition objectives is essential for success. Figs. 1 and 2 schematically illustrate the real-time monitoring concept. Real-time data are view emperature system (DTS). During early production a near-wellbore reservoir model is characterized to match the well-bore temperature pro . The combined monitoring also can track fluid movements in the reservoir allowing optimum well and pattern design and subsequent opera opment strategy of the Azeri field requires a good understanding of the production and injection conformance both geographically as well a total production compared with equivalent dry-tree installations and most have less data (Selim 2003). Hence there was a crucial need fo

overcome these limitations. To do so a production volume estimation solution should address the following needs of the Oil & Gas Compan ee of reliability in these oftentimes hostile environments. This paper examines an alternative flow detection solution and provides recomme

he years and numerous patents and articles have been published. Nuclear emission based techniques were the forerunners in this categor

ateral sweep due to reservoir complexity. Detailed simulation modeling was performed to delineate optimum strategy for maximizing reserve of more advanced (deep reading) methods. Selected well-based monitoring methods include well logs and pressure and flow data. Evaluat erta alone is predicted to have 500 Tcf of CBM to be developed equivalent to 83 billion barrels of oil. Approximately another 2 500 CBM well et. al. 1994) The degrees of cleating nature of cleat network and relative connectivity of the cleat system varies from one coal seam to thos e susceptible to fluid invasion damage. In addition the very soft nature of coal means that these fracture systems can be closed down due ormance was not increased drastically with slickwater completion costs were reduced by approximately 65%. In 2002 horizontal wells were t its entry point with the wellbore. In brittle high modulus formations high fracturing initiation and treating pressures generally result from loc

remely large fracture surface area that can be economically generated. The stimulation cost reductions allowed Mitchell to complete the Up pattern) designs various well spacing pilots (e.g. 500 ft 1 000ï¿½ft and 1 500 ft etc.) were drilled and various hydraulic fracturing operatio

ck organic-rich shale with ultralow permeability in the range of 70 to 500 nanodarcy. To attain economically viable production rates hydrauli acidizing on the other hand the chemistry of acid-carbonate dissolution is straight forward especially for the HCl-carbonate reactions. The a

he subsequent calculations the primary concern here is the flowrate and not the pressure. Nominal pressures are required but very high flo reservoirs are associated with the delta tributaries and crevasse splays while the BS reservoirs consist of coastal-deltaic sediments and cr

fficient treatment of individual layers in cemented casehole completions. TAP Completions use special casing valves that isolate individual l

echanisms that must be considered in evaluating the transport capability of a system for moving liquids upward in the well.ï¿½ï¿½ These a echanisms that must be considered in evaluating the transport capability of a system for moving liquids upward in the well.ï¿½ï¿½ These a and sedimentological analysis; and geo-mechanical modeling.

best done by establishing flow-rate control through variable completions. Thus for areal nonuniformity and heterogeneity we expect a rese

ontext refers to one containing the minimum number of significant parameters that adequately represents the data. Finally we conclude tha

dominant mechanism for improved production performance. Connecting the stimulated wells in the full field model (FFM) to all grid cells abo

al well log resistivity invasion profiles.ï¿½ï¿½ Higher production and reserves of these wells reflect these higher oil saturations in the Middle ontain the fracture in the pay zone This proved to be beneficial particularly in reservoir conditions where fracture vertical extension barriers

lity of reservoir. The fact that the composition and surface of the reservoir are heterogeneous in three dimensions further complicates the a ulic fracture simulators (Smith et al. 2001; Siebrits et al. 2001) and the combined effect of height-containment mechanisms can now be stud ant (VES) fracturing fluid systems have been routinely and successfully employed over the last two decades in hydraulic fracturing applicati erators (Kaufman et al. 2008 Horn 2009). Literature has also been documented on the use of untreated recycled waters in high rate low p ¿½ Typical fracture gradients range from 0.5 psi/ft to 0.75 psi/ft and Youngâ€™s Moduli range from 3-7 million psi. nd gelled fracturing fluids were first introduced in Venezuela by Schlumberger in 1996. Since then this technique has become the preferred elective placement of artificial barriers to proppant transport that are placed adjacent to the pay zone adjusted frac fluid systems and pump hese very challenging environments through the use of the latest openhole stimulation technologies available in the market today. An innova al decades pressure maintenance is normally carried out with water injection. The produced oil has a low GOR hence there is no gas injec

he difficulty is to find a method that is efficient effective and cost competitive. The sequential opening of a single productive layer and isola cture toughness shows that the value of the fracture toughness measured in the laboratory can be by order of magnitude less than the in-sit 2-inch long sandstone cores at a constant driving pressure of 1000 psi. The cumulative fluid volume flowing into the core was measured a

y most operators perhaps contributed to this belief.ï¿½ Other completion â€œprinciples which may owe their origin to either hearsay or exp

ment that was implemented is shown in Fig. 1. The detailed steps within this process are listed in Table 1. ddition it presents the first data characterizing flow across the filter cake to simulate flow from the reservoir into the fracture as opposed to c o 15 ft.ï¿½ Very fine grained sandstones siltstones shales and limestones comprise the majority of the rock types found in the Cotton Vall

ween the treatment and monitoring wells. Traditionally in HFM the initial isotropic velocity model is built from sonic logs and/or vertical seism

aminated oil saturated sandstone. The average permeability of AC-11 formation is 8mD and the porosity is 13-16%. The average oil satura und to be useful in developing information in virtually all aspects of drilling completing and producing a well. A particularly popular use of ra

f leak-off 3 Ct can be determined using Eq. 1

plane in cases where the data cannot image the failure-plane orientation accurately. In this paper we present a case study by use of micro

ed in many papers [3-10]. Investigating instability in miscible displacement differs greatly from that in immiscible fluids. The presence of a sm s for pushing fracturing limits to maximize productivity. They derived optimum fracture length width and conductivity as a function of reservo

controlling the closure stress pressure and temperature ports and inlet and outlet ports with valves.ï¿½The cores are cut to shape and pott

costs of the fracturing operations and the low oil prices turned these operations uneconomical during the nineties. After 2000 the increase wth resulting in offset development is not often undertaken. Jeffrey et al.13 considered offset development as a result of sliding on the natura l valve technology developed for auto gas lift has found applications in subsea and deepwater wells using conventional gas lift. The reason sisted of a gross length of 1 301-ft with a net perforation length of 460-ft 4-spf and 180o phased 4-1/2-in guns and a packer. The guns were rs that are not naturally fractured. The use of limited entry and bullheading techniques provides little if any benefit compared to vertical we s that are not naturally fractured. The use of limited entry and bullheading techniques provides little if any benefit compared to vertical wel olution was remarkable. The objectives are to achieve: Very low leakoff to the reservoir by the design of optimized filtercake this will preve

location of Bloque 15 Ecuador. Geologically the Oriente Basin of Ecuadorï¿½ is part of the upper Amazon River drainage system and cov

e and Lien 1994; Permadi et al. 1997). Active control is facilitated by the adjustable inflow control valves (ICVs) installed in intelligent wells. acture propagation were examined: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ i.ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ Fracture #1 extending throu

ctivity of a well drilled in this type of reservoir? What is the connectivity between wells drilled in this type of reservoir? Answers of these qu

esult in major simplification in understanding how carbonate acidizing works in real wells. In a cased-hole completion perforations provide t al well and completed with a standard completion including a 3.5-in. production tubing and a 7-in. packer. Well-0 was perforated in static un to decline from 18 MMSCF/D down to 7 MMSCF/D with gradual increase in water gas ratio up to 10 BBL/MMSCF. This phenomenon was a breakthrough advances have been achieved relating to tunnel quality. The industry has relied solely on static underbalance which is now a he success rate of sandstone acid stimulation is low. All perforation creates a low-permeability crushed zone in the formation around the per oirs. The Cotton Valley reservoirs at Bethany consist of multiple tight gas sands mostly blanket in nature from approximately 8 000 ft to 10 feasible from an operations standpoint. Also after the first run shot with a static underbalance the well will be at balance conditions so any s n methodology of the PTT. A variety of technologies such as slug test (Ramey et al. 1972) closed chamber test (Alexander 1977) surge t

ons to an existing perforating system in order to meet a specific technical requirement. If the job is imminent with little time for engineers to

und 650 m and 14 horizontal injector wells with lateral extensions ranging from 650 m to 800 m. Further analysis added one producer and o

reen erosion.ï¿½ Consequently most of the operators have accepted gravel packing as the sand control means5. mpatible with water based fluids. The experiences from the analogue fields in the basin clearly demonstrate the reactivity of the shales. The

e problem related to the exposed shales. es that can be used in the carrier fluid either throughout the treatment or during the Beta Wave.8

reaks they require synthetic/oil-based drilling fluids (S/OB). Considering that a large majority of the openhole gravel packing experience in

bility and plugging potential along a well path crossing significant intrareservoir shale packages. For Open Hole Gravel Pack (OHGP) compl o date there have been several failures in the field with similar characteristics where biocide tracer confirmed the direct communication betw n to prevent sand failure. In addition it can be done rigless. The technique consists of the following key steps: Optimum perforation phasin

production linking the problem to the occurrence of thin beds and proposed new completion solutions to address the issue and optimize p nd by employing pragmatic models that do not rely on over-complicated measurements and analyses. Introduction The giant Messla field cs and sanding study was initiated in the year 2004 to investigate sanding mechanism and to provide the contingency plan to properly addr

ressure and qualitative stress information relating to the in-situ stress regime. The properties of drilling fluid-shale interactions were derived d placement did not significantly improve (Yeager and Shuchart 1997). Crosslinked acids were introduced in the mid 70â€™s as was cited b ¿½ The success of the acid fracturing process depends highly on the resulting fracture conductivity which is very difficult to predict becaus gh relatively new with the Permian Basin timeline completions in the Strawn formation in Terrell County have endured just such an evolution

stems would provide diversion during the stimulating of limestone reservoirs. Based on this it was decided to apply this system in Tengiz fie n. Typical wormhole structures can range from face dissolution to highly branched ramified wormholes at low- and high-injection rates res

d to have a proper tubing pickling procedure with proper pickling acid fluid had been repeatedly emphasized. Recent marked effort in this re

cipitation of calcium acetate and calcium formate 5 (2) Organic acids have a low dissociation constant. They normally do not react to their f

acidized.ï¿½ Therefore one of the most important factors affecting the success or failure of a matrix acid treatment is the correct downhole rvoir pressure Pres as low as 12 bar. Conventional stimulation techniques including matrix acidizing using hydrochloric and mud acid syst as face dissolution wormholing and uniform dissolution patterns depending on their shape and speed of propagation.ï¿½ By increasing th ances in stimulation fluids and proppants. This paper will focus on the common attributes shared by known successful restimulation candid ol to have a better estimation of critical rock mechanics properties like Youngâ€™s Modulus Poissonâ€™s Ratio and â€œin-situ stress. An terrigenous rocks the host rocks being porous. Open porosity in the host rocks accounts for 14â€“19% and permeability equals 15â€“60

the workover. Thus an engineering solution of stimulating oil bearing intervals but avoiding suspected water breakthough intervals with the ted (Figure 1). Intervals between reservoirs not planned for production are not tested. Since the majority of cement squeeze decisions are originally designed for testing water wells. Ferris and Knowles1 were the early investigators who tried to extract transmissibility to water from on 24/64 choke to perform flowing surveys and attempt to take a bottom hole sample followed by a 2.5-day initial build-up to get a first estim operties on a layer-by-layer zone-by-zone or frac stage-by-stage basis by evaluating the drawdown production performance of the well in

application of the proposed technique. Introduction Over the last four decades naturally fractured reservoirs have been a topic of continuo fundamental radial flow regime is essential to interpreting pressure transient testing and its radius of investigation; i.e. how much reservoir ase of production engineers the continuous degradation in inflow due to skin affects their return on investment.ï¿½ For operations engineer ld remove the constraints of conventional analysis techniques (Earlougher 1977; Bourdet 2002) that have been built around the idea of app

dict future deliverability by forward simulations with an analytic tool. anticline affected by NW-SE trending faults which straddles the border between the United Arab Emirates and Iran. Currently on Total AB h elimination of active control systems and reduction of the volumes of pressurized hydrocarbons contained in the testing systems Perman

wn significantly the worldwide number doubling in little over a 2-year period (Mehdizadeh et al. 2002). Multiphase-flowmeter interpretation

clide or an appropriate chemical source could provide the two energy levels required to do the fraction measurement [Ref 2]. This leads to a ey found it useful to calculate property multipliers around each well and then interpolate multipliers to untested areas in the reservoir.

ve technique (DPDT). The DPDT produces the most accurate and representative dp/dt curve by incorporating knowledge of both reservoir nned the 694-ft-long completion. Each electrode was connected to a single conductor that was linked to the surface acquisition unit so that

e they belong to the class of fault-free risk sometimes called residual risk: events causing sub-standard system performance that cannot be depth must combine complementary datasets.

tion strategies. Injection of CO2 in Saline Aquifers â€˜Saline aquiferâ€™ is understood here as a brine reservoir or geological formation wi

attle rising. Nitrous oxide also known as â€œlaughing gas is third and arises from agricultural practices fuel burning and industrial proces anical effects of storage operations. Indeed rocks and faults permeability may drastically increase as they undergo stress changes and def

ven longer wells can be drilled from subsea locations in the near future. Optimal pre-planning with use of all service companies involved in

Lohmann discussed diagenesis in these reefs. deposits is still at an early phase. Previous work has included documentation of worldwide occurrences of natural CO2 deposits and prelimi pplied routinely then somewhere in the thousands of wells drilled some pay has been bypassed. One solution that has been used prima rs are described as follows.

rongly both with depth and area. Permeability ranges from less than 1mD to hundreds mD. Two principal porosity types that are fractured/m cted from the TTIP and the coiled tubing string is pulled out of the well. HPHT TTI packers enables permanent abandonment of zones in ad iated with cement squeeze in a singlestring multizone completion is the difficulty associated with placement and confirming where the TOC

T equation-of-state (EOS)2 3 based mathematical model was developed using the published information and the modeling results are prese energy at the interface and smaller dispersed-phase droplet size in liquid/liquid flows (Trallero et al. 1997). Therefore the characteristics of energy of the dispersed phase. The inversion point and effective viscosity of the dispersion are estimated using the Brinkman model (1952) the production and recovery optimization for each individual reservoir but also the value maximization of the well.ï¿½Intelligent completion ork-process simulation model and used it to identify and implement several cost effective production optimization opportunities of San Manu with black oil. The density of the entire liquid phase decreases the crude oil solubility parameter decreases and the asphaltenes aggregate tank conditions. In particular the impact of using live versus stock tank oil measurements in the design and operation of the subsea system ailures of the downhole completions or the surface facilities. Carbon dioxide itself is a weakly acidic gas and must first hydrate to carbonic a illed with WBM7

Walsh and Towler5 also presented a procedure to calculate MBO PVT properties from the CVD experiment data. Abdel Fattah et al.6 showe

separation may not always result in water free hydrocarbon production. Coupled with reservoir and fluid complexities above often zones wi ™ pressure gradients can contain. Beside uncertainties of pressure gradients two hydrocarbons can easily have very similar in-situ densiti

ater and other high cost wells wireline formation tester (WFT) fluid samples may be the only source of fluid properties reliable enough for e

filtrate that can mix with sampling line. Lab results of the first field example demonstrated that these objectives were achieved. e need for special metallurgical or process design to deal with certain levels of H2S in the presence of various other mitigating or accentuat

ght oils with gravity greater than 35 degrees API strong compositional grading will often occur where the reservoir fluid is near its critical po

g program can be optimized in real time by comparing observations to predictions. Visible-to-near-infrared (VIS/NIR) absorption spectrosco

xtures of hydrocarbons in several settings. Near critical fluids are then encountered and their description and volumetric behavior is comple ane content and color in the flowline as cleanup with the downhole pump proceeds and progressively larger fractions of formation fluid repla

heavy oil reservoirs as well (Mullins et al 2005 Mullins et al 2007). the wellbore and is assayed by a downhole spectrometer that measures OD as a function of time and wavelength. At any time instant the m e basis of their molecular structure different types of hydrocarbons have vibration absorptions at different wavelengths and a simplified hyd

duction facilities one of the main drawbacks of emulsion formation is an increase in the apparent viscosity of the oil. Viscosity of water-in-oi

e scaling and corrosion potential of produced fluid required for the design of completion and processing facilities (Raghuraman et al. 2007). ny Wireline gas-condensate sampling operation that applies a similar setup and principle. arator conditions or lower. Figure 1 illustrates this. As said previously MFM's request PVT information for conversion this is unavoidable a uction requirements. The experience of northern Siberia has shown that despite that fact significant gas production could be maintained. At

execute any matrix acidizing treatment. Because of the low amount of quartz the first concern for a proper design is to avoid an aggressive

used in squeeze applications the squeeze life is often short due to the high MIC and the poor retention characteristics of the inhibitors. To a

ck Pucknell & Behrmann[1].ï¿½Additionally the damaged zone is partially deconsolidated: its strength is much less than undamaged rock. are prevalent in the local industry should not be neglected in the process of scale forming. The conclusion is further confirmed by thousand em due to commingling of different water types and the challenges involved in the predictability of water production. This paper presents th

is only just above the positive threshold SI of +0.40 for the lowest zone of scale risk to the production problems. This would tend to indicate Field Development Gyda hydrocarbon reserves are contained in Upper Jurassic shallow marine sands.ï¿½Reservoir depth is 3 650 - 4180 as possible to decrease prohibitively high computational cost without unduly compromising the accuracy. In the examples presented in this

ore gas-producing basin in Mexico where workflows were implemented for automatic surveillance and optimization of gas production.ï¿½ T

artificial lift method and a comparison with the top-drive PCP system are presented in this paper.

as the Muglad White Nile Blue Nile Khartoum and the Atbara basins terminate northwards at the Central African Shear Zone. The develo

facilities design and reservoir production strategies.ï¿½ Gas oil ratios saturation pressures and viscosities are among the fluid parameters

thin these depressions show significant variations in age of formation complexity and size. The result of regional stratigraphy study indicat

0 API heavy oil with water cuts up to 98%. The reservoir depth is approximately 2 000 ft. Bottomhole pressure is approximately 200 psi with

roboric acid9 and mixtures of esters and fluorides to generate HF-in-situ by thermal hydrolysis.10 Reactions of some these acid systems w

elivering a crosslinker that has two (or more) organometallic complexes: one that could yield limited crosslinking at a lower temperature for

hnique to bypass skin-damage in the near-well bore region and create a high conductivity conduit for production enhancement. Fracturing w prehensive laboratory study which includes acid solubility tests X-Ray Diffraction (XRD) analysis batch reaction kinetics fines migration t e main treatment agent. Chelating agents are materials that are used to control undesirable reactions of metal ions. In oilfield applications e Fig. 2). The lithology changes from nine sands at the bottom of the well to twelve sands at the top of the productive interval. Many of these ressure of the formation. The reduction of capillary pressure to very low values allows for water block clean up even at low drawdowns. Th ta can be used to differentiate produced connate water from aquifer or injection water breakthrough.

roduction moves to more remote areas and deeper or more difficult well paths.

ls under intensive and long injection schemes are subject to create long fractures as well. Many of the late wells are planned injector wells

wed production stabilized at 914 BOPD and 1% water cut compared to a stabilized production of a vertical well at 100 BOPD and 1% water c omparison of the modelsâ€™ and actual results are presented in the following sections. ymmetrical syncline with the deepest end in the north central (Figure 1) 1. The majority of the study was focused on the Riverbend field an 0.7 psi/ft. To honor the pressure gradient the models were initialized by enumeration of reservoir pressure and fluid saturation and infinites he additional perforated intervals and larger stimulation treatments result in additional value. The methodology to compare production foreca

to greatly aid in reservoir evaluations such as identification of ï¿½compartmentalization fluid spatial variations characterization of hydroca

ation and overall systemic inefficiencies.

½b. Once pressure drops below sand face pressure fluid from the formation will flow into the flowline ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï he hydraulic fracturing was not only to increase the productivity index of the wells but also to provide connectivity between the borehole an

enge of prospecting and exploration of that extremely geologically complicated block of resources called since then the YTZ. This referred

ble method of diagnosing the transition zone is desirable. However the formations are often of mixed and variable wettability. It has observe

gies. These technologies have reduced the finding cost through better exploration and appraisal techniques better drilling and completion p

c model. Both core and log measurements provide a tremendous amount of information to help characterize rock types and their properties

of integrating such high resolution tools in order to build a static reservoir model whose upscaling will strongly reduce its spatial resolution. A

focused-sampling cleanup introduced recently in the next-generation wireline formation testers (Oâ€™Keefe et al. 2008). DFA tools provide ½ Also the well known density-neutron separation may not always result in water free hydrocarbon production. Coupled with reservoir and fl

or the evaluation of lithology and mineralogy porosity and fluid saturations. Evaluation of these properties using a similar suite of measure

pecific shaly sand formation as using improper model that highly depends on these uncertain parameters may result in bypassing the pay z rmation as using improper model that highly depends on these uncertain parameters may result in bypassing the pay zones. uch as porosity permeability and grain density and Special Core Analysis (SCAL) data such as mercury injection capillary pressure (MICP) on. An average quantitative resistivity of invaded zone was derived by laterally averaging all 20 resitivity curves from borehole2 image log. S crystal size. Due to this geologic complexity the quantification of permeability and by extension rock typing from traditional logs and interpr ppropriate benchmark for improving estimation of net producible sand thickness in thinly bedded reservoirs. Passey et al. (Ref. 1) define pe

ion. Finally the fourth and last verification is the volume of hydrocarbon. Although crossvalidation between 3D induction and NMR interpreta

ich follow. ch fractures are artificial in origin caused by either/or the formation and the core material being disturbed or excessively stressed either dur ng the newly acquired 3D seismic well log motifs and seismic modeling of porosity attributes. Problem Definition Structural and Strati-struct

erize geologic facies object size petrophysical property continuity and reservoir connectivity (Journel and Alabert 1988 Jones and Ma 2001

lution to enhance the deeper measurements with poorer vertical resolution as shown in Suau et al. 1984 paper for the first evaluation of thi

enhance oil production. Based on the study some rules of thumb have been proposed about when it is important to consider stress reorien

xcessive mud loss internal blowout and differential sticking (van Oort et al. 2003). Drilling through such depleted sands was accomplished

mined as a key factor that defines productive potential of wells. General information The basement of the field consists mostly of Paleozoic

fines productive potential of wells.

rticularly fluid loss control additives â€“certain additives may cause damage by plugging pore throats in an irreversible manner.

sical analysis is affected by strong limitations in core analysis and log interpretation due to the very low porosity and naturally fractured res metimes large density-neutron separation allows us to distinguish gas from oil but in other cases lithological effects could mask it. Hydroca

ere is proper flow monitoring at the surface. This offers significant benefits in both production optimization and reservoir characterization an e top of the underlying Rumaila Formation and the other at the top of Mishrif (Fig.2). The lower part of the Mishrif consists of homogeneous

ide (CO2). The gas-oil-ratio (GOR) of the fluid is then estimated from the derived composition (Mullins et al 2005a Dong et al 2006 Fujisa phase transitions. Wireline-conveyed formation testing and sampling tools are described in detail elsewhere.6 Figure 1 is a schematic rep

dicate oil is swept by a favorable gravity-dominated displacement. As Sarah oil is a light crude of 38ï¿½ API and formation water has total ch robe plugging fine laminations and depth control. Over the past 20 years in the formations we focus in this study the operational success

nduct interval pressure transient testing (IPTT).ï¿½ These tests were conducted by producing through the dual packer module and monitori wellbore is influenced by mud filtrate invasion and mud cake formation. Considerable studies have been made in this area. A good summa plan involves identifying the best suited activity and then designing that activity to its optimum level. Final risk exposures for the selected a eline pressure tests for reservoir characterization faces two important limitations. On one hand the restricted thickness of the sand bodies l

of completeness a generalized stratigraphic column of Block 10 is included as Figure 2 while Figure 3 shows an arbitrarily selected cross s

aybe used to improve the performance of such wells if water is increasing the fluid column density (and therefore bottom hole flowing pressu

g picture depicting the FM framework and its different building-blocks details of the FM framework building-blocks:

flow-entities and flow-e

h the favourable mobility ratio resulted in excellent sweep efficiency. However one of the reservoirs (A6.0) was found to be almost entirely is

ovements such as $30mn per year per asset for optimization and over $90mn per year in improved Net Present Value (NPV) from planning rk-process simulation model and used it to identify and implement several cost effective production optimization opportunities of San Manu o varying interpretations.ï¿½ This is especially true because no industry-wide rules have been established for the accuracy required of the s y. Typical well production rates are on the order of 10 000 to 15 000 BPFD. Field average water cut at this stage is around 84%. Present Ch

not effectively produce oil from vertical wells. The recent horizontal and multilateral wells in these shaly zones have greatly improved produc liverability. Thus we narrate a process flow that could be adopted as a guideline for field development plans requiring hydraulic stimulation ommingling etc.). Fig. 2 shows a typical well production history in this project. It becomes a real challenge to allocate production by the rese

s greater than 15ft.1 The technology uses the resistivity contrast between an adjacent bed and its orientation in 3D to calculate the distance sticated geophysical model derived from two 3D seismic surveys covering the Brenda field. Reservoir simulations indicated that the Brenda niques.ï¿½Nowadays even during the early stage of exploration and appraisal detailed reservoir models are constructed based on seismic ssure by a port; then it was connected to surface by shielded wiring which provides a continuous readout of gauge pressure once every se elds cover the highest percentage of fields and associated remaining potentials4 which makes them especially attractive. In almost any wa mpletion has been rigorously evaluated. Introduction The field study case is situated in offshore Sabah East Malaysia. After its discovery in 91 Brouwer and Jansen 2004 Sarma et al. 2005 Kraaijevanger et al. 2007). In these applications the parameters to be optimized are usu

Khalifah et al.10 Gomes and Reza11) and are generally applicable to a single well. The application of analytical solutions to full field reservo he deterministic approach the Bayesian approach associates probability distribution to the prior models and is thus considered well-suited

e gas phase the total number of variables for grid cells containing three phases is 2Nc+6 where Nc is the total number of components in t

rature4 5 6 7.ï¿½ Once a problem is identified appropriate measures (such as shut-off gas/water producing intervals) can be taken to reso

id invasion into the reservoir polymer-solids deposition near the fracture face as filter cake forms clay swelling in the case of incompatible nitiated. In the field only a fraction of the injected polymer can be produced during the cleanup process typically up to 50%. Slugs of unbro efficient reservoir sweep and reduced or deferred recovery. condensate flow in vicinity of the hydraulically fractured well. Nevertheless this approach has some certain disadvantages and first of all:ï¿½ ial slip. The model has been implemented in a hydraulic fracture simulator. Interfacial slip affects not only the fracture height but also the fra ¿½ In recent years numerical simulation for hydraulic fracture modeling has been introduced to the industry. Numerical simulation allows d

del he states that it is often difficult to distinguish the effects of fracture conductivity from fracture half-length. This observation leads him to bitrary fracture conductivity distribution as well as providing a more fundamental and theoretical basis for the apparent wellbore radius of ve th with orthogonal flow along the fracture. A new model is herein proposed with both the fracture geometry and flow being radial. Actually

rning methods a term that covers a large variety of methods including stacked generalization and ensemble averaging. An additional probl

ons are used instead for material balance calculations.

ry mixture causes one component to segregate to the hot plate and the other to the cold plate. Because of the density gradient caused by t

the method of constructing an M-matrix is extended so that clusters of faces are used; in our work we consider 3-dimensional grids. The pa

g stress/strain tensor fields (Bourne and Willemse 2001; Maerten et al. 2002; Bourne et al. 2001; Daly and Mueller 2004; Roxar FracPerm R

the saturation transport along streamlines. In this work we employed the implicit CFL numbers in the range of 1 to 20. The numerical meth rrent finite-difference simulators can drop significantly when detailed descriptions and complex matrix-fracture transport processes are introd

hich includes a specialised brine composition and scale precipitation model included to enable such calculations to be made whilst taking ad

r to maintain the required accuracy. Also there is no global restriction on the saturation time step since the latter may vary from one stream

lts obtained during the analysis phase as value promise for field development.

scription of method The proposed approach is analogous to the face recognition technique based on Principal Component Analysis curre have only one outlet. This restriction meant that only device models with a â€œgathering tree topology could be represented and loops we

VT sample in Marrat. The reservoir temperature of 275 oF is 20 oF higher than the critical temperature for this sample. Liquid saturation vs.

s ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ ï¿½ï¿½ï¿½ï¿½ been performed in such zones and report that if supercharging and production/depletion effects are not major complications in the gradie methods to drill successfully have been described in an earlier paper.1 In the referenced paper the basic concepts and procedures for pro ½ While mentioning a stress map we are mainly concerned about the directionality of the minimum stress across the region. lâ€œSmart Fields Also during the past decade there has been an increasing appreciation within the industry that much of the future lies w

s shown in Figure 1. The Arctic Slope has long been considered a petroliferous province . odulus or increasing the Poissonâ€™s ratio of the cement will decrease the stresses induced in the cement sheath and for a given situatio

ents. Aulia et al. (2001) provide a comparison of the applicability of each measurement in different environmental conditions. measurement principles were the same as for BP Harding well PN1.2 Oseberg Sï¿½r Field Description The Oseberg Sï¿½r field operated he PVT data illustrates that the oil has higher viscosities with the increasing depth hence showing the oil quality deterioration1. Figure 1 sho pe have been available for some time [2 4].ï¿½ Recently an array mini-spinner has been introduced that has proven quite useful in better c

ty of tool sticking are reduced.

are largely contaminated with drilling-mud filtrate and are disposed of by pumping into the borehole in the â€œcleanup phase. Optical fluid in identifying wells as candidates for production enhancement 1 for determining depletion and drive mechanisms 2 and for optimizing well p by packers from previously perforated intervals (starting from the deepest depth interval). In order to decrease fluid loss the viscosity of the vantage points. The case in point is hydraulic fracture height and can it be effectively assessed using temperature logs to determine heigh

d observations of wellbore liquid unloading conditions4-11 that the criteria for the translation of entrained liquid droplets in the flow stream g g conditions4-11 that the criteria for the translation of entrained liquid droplets in the flow stream generally provides a better indication of the of permanently installed DTS systems was wireline conveyed fiber optic systems where the distributed temperature sensor can add to com

et al1 with the production increment without spare capacity some oil companies have adapted a process to monitor daily production and l

ition also affect their formation but not to a significant extent.9 Combination of fluid production including oil and water under certain circums

ing concept. Real-time data are viewable by authorized personnel anywhere around the world thus allowing virtual collaboration between fi match the well-bore temperature profile calculated from the thermal model to the early measured DTS data when reservoir layer pressures attern design and subsequent operational improvements including as optimization of steam volumes rates and cycle timing. Finally the pa mance both geographically as well as by formation. Similarly monitoring the gas-oil ratio (GOR) in the producers as well as water injection c Hence there was a crucial need for real-time sandface data a robust mechanism to deploy sensors a reliable connection technique betwe

wing needs of the Oil & Gas Company for: Controlled and secured data collection and preservation (real time remote or manual) Producti tion solution and provides recommendations for the identification of water entry in horizontal flow environments. Two Niger Delta case study

were the forerunners in this category. Thermal Decay time measurements (TDT) and Reservoir saturation estimation using Carbon-Oxygen

mum strategy for maximizing reserves in the lower two oil bearing units of reservoir thereby controlling the process at a more local level (Re and pressure and flow data. Evaluation of a number of advanced geophysical methods led to the selection of the crosswell EM method for i proximately another 2 500 CBM wells/year are estimated in Canada for the next 10 years. By comparison conventional gas production in C m varies from one coal seam to those of the other and have a significant bearing in their production characteristics even in the commingled e systems can be closed down due to mechanical hoop stress in open hole completions. Nowhere is this better exemplified than in a series 65%. In 2002 horizontal wells were experimented with in an effort to increase the wellbore's exposure to the reservoir. The results of the fir g pressures generally result from localized stress concentrations and from the consequent tortuosity associated with small apertures and c

allowed Mitchell to complete the Upper Barnett that is present in Denton and Wise Counties in addition to the Lower Barnett.ï¿½ This incre various hydraulic fracturing operation schemes such as â€œzipper-frac and â€œsimul-frac have been invented and tested (Waters et al. 2

ally viable production rates hydraulic fracture stimulation is a necessity. r the HCl-carbonate reactions. The acid dissociates into hydrogen and its conjugate base ions. The hydrogen ions attack the carbonate to g

ssures are required but very high flowrate are necessary for the working of the system. As such only Centrifugal Compressors suffice the pu t of coastal-deltaic sediments and crevasse splay sandstones. JS11 reservoir is represented all over the entire area by thin marine sands in

asing valves that isolate individual layers one at a time without any interventions. The TAP valves are near full bore and do not require incre

upward in the well.ï¿½ï¿½ These are the criteria for moving the liquid film along the wall of the conduit upward as well as the criteria for su upward in the well.ï¿½ï¿½ These are the criteria for moving the liquid film along the wall of the conduit upward as well as the criteria for su

and heterogeneity we expect a reservoir optimization scheme to prescribe qi (t) for each well i given all of the reservoir information estimat

ts the data. Finally we conclude that SA is the only viable and appropriate unbiased time-to-event methodology for evaluating ESP system

eld model (FFM) to all grid cells above and below the estimated fracture length improved the prediction compared to previous PI or skin adj

e higher oil saturations in the Middle Member and also the sometimes presence of intense natural fracturing in the adjacent brittle upper sh fracture vertical extension barriers are weak or non-existent and the underlying zone is water saturated. In addition the fibers allow for bet

imensions further complicates the analysis. nment mechanisms can now be studied with fewer approximations for hydraulic fracturing conditions. The study of the layered modulus effe ades in hydraulic fracturing applications to improve well productivity.1 The initial VES applications were with the gravel-pack completions in t d recycled waters in high rate low permeability shale reservoirs (Arthur et al. 2009). Water volumes for a typical slickwater hydraulic fractu million psi. echnique has become the preferred option to stimulate unconsolidated sandstones with low reservoir pressures. Currently 40% of stimulati djusted frac fluid systems and pump schedules. These purposely -created barriers are placed prior to the main fracturing treatment by pump ailable in the market today. An innovative technique used for stimulating these horizontal wells was introduced. It combines mechanical and ow GOR hence there is no gas injection for pressure maintenance however the produced gas in used for lifting the oil through gas lift system

of a single productive layer and isolating it from previously opened intervals requires a significant number of downhole operations. These o der of magnitude less than the in-situ value. This fact can be explained by the effect of microcracking and inelasticity near the fracture tip.1 owing into the core was measured as a function of time and the total fluid loss coefficient vs. permeabilities was plotted in Figure 3.ï¿½Also

their origin to either hearsay or experience and that were generally followed by the operators were (a) to fracture-stimulate the wells only w

voir into the fracture as opposed to considering only flow along the fracture length. e rock types found in the Cotton Valley sand interval.ï¿½ Calcite cementation quartz overgrowth and overburden pressure have greatly redu

from sonic logs and/or vertical seismic profiling (VSP) data4. Commonly the velocity model is then adjusted to locate perforation shots to t

y is 13-16%. The average oil saturation is 50-60% with reservoir pressure at 248 bars. The AC-12 formation situated below the AC-11 is ch well. A particularly popular use of radioactive tracers is for the determination of propped fracture height. Fracture height measurement throu

present a case study by use of microseismic imaging to determine the geometry of a hydraulic fracture. A two-stage fracture treatment was

miscible fluids. The presence of a small parameter incorporating surface tension for immiscible fluids allows to determine theoretically the ch conductivity as a function of reservoir parameters and fracture treatment in the context of Siberian oilfields.

The cores are cut to shape and potted along the edges with a rubber sealant using a mold.ï¿½They are saturated under vacuum with 2%

e nineties. After 2000 the increase in water injection rate has restored the reservoir pressure and become one of the main factors to restart nt as a result of sliding on the natural fracture after the hydraulic fracture crossed it. Some fracture design models include a calculation for t ng conventional gas lift. The reasons for using these variable valves are usually their higher pressure ratings their ability to deliver a wider r n guns and a packer. The guns were run with weighted spacers and swivels to orient the guns to perforate on the high and low sides of the any benefit compared to vertical wells. Post production analysis on the deliverability of horizontal wells in reservoirs such as matrix heterog ny benefit compared to vertical wells. Post production analysis on the deliverability of horizontal wells in reservoirs such as matrix heterog of optimized filtercake this will prevent the reservoir damage due to mud invasion Easy removal of the filtercake by applying a minimum d

azon River drainage system and covers an area of approximately 80 000 km2 which is very prolific on production of oil and gas. It is geologi

s (ICVs) installed in intelligent wells. The settings of these valves can be varied to optimize the inflow profile along the well in response to m ï¿½ï¿½ Fracture #1 extending through a flawless section of the block (tip mechanisms); and ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ ii.ï¿½ï¿½ï¿½ï¿½ï

e of reservoir? Answers of these questions allow us to evaluate reservoir recoverable reserves. Traditionally a full scale well test and an in

le completion perforations provide the communication between the wellbore and the reservoir. They are the conduits for treatment fluid inje er. Well-0 was perforated in static underbalanced conditions and tested at 334 standard cubic meters per day (Sm3/d). In May 2003 the op L/MMSCF. This phenomenon was also supported by adjacent well performance which was shut in due to high water production. Nitrogen lif static underbalance which is now a well recognized technique for perforation cleanup. The appropriate level of static underbalance has be zone in the formation around the perforating tunnel to impair the wellâ€™s productivity or injectivity. Perforating damage (skin effect) can be e from approximately 8 000 ft to 10 000 ft in depth. Porosity ranges from 6% to 15% and permeability from 0.01 md to 7.0+ md. Water satu ill be at balance conditions so any subsequent perforating runs will be made at balance and not benefit from an underbalance surge for cle mber test (Alexander 1977) surge test (Simmons 1990) and perforation inflow test (Hawkes and Hategan 2004) have a similar or the sam

nent with little time for engineers to run another round of full qualification tests the engineers or project managers can decide whether the g

analysis added one producer and one injector into a new portion of the reservoir.

ol means5. ate the reactivity of the shales. The initial Open Hole Gravel Pack (OHGP) wells in an offset Angola deepwater block were drilled with oil ba

enhole gravel packing experience in the industry has been in water based drilling fluid environments new challenges emerged for gravel p

en Hole Gravel Pack (OHGP) completions the length of the planned wells (up to 2500 m) would incur both technical and logistical/cost chall rmed the direct communication between several producers and injectors. Water injection post wormhole-like failure is very inefficient as the steps: Optimum perforation phasing and size Near-wellbore consolidation Tip screen out fracturing using proppant flowback control such

to address the issue and optimize production in that part of the field. A Phase II of the study discussed here was initiated by Schlumberger Introduction The giant Messla field is located in the southeast portion of Sirte Basin in Libya approximately 500 km southeast from Bengha he contingency plan to properly address the problem and maximize economic production. The study started with data acquisition. Various w

uid-shale interactions were derived based on a database estabilished for a number of drilling fluids and shales encountered in the basin in ed in the mid 70â€™s as was cited by Metcalf et al. (2000). These acids have much higher viscosity than regular acids or acids containing u ich is very difficult to predict because it inherently depends on a stochastic process and is affected by a wide range of parameters. Most pre have endured just such an evolutionary process. Production from the Strawn Formation in Terrell County increased significantly in the 1990

ded to apply this system in Tengiz field and analyze the results of the stimulation treatments to evaluate their effectiveness. Whenever pos at low- and high-injection rates respectively.[3-8] Besides not creating deeply penetrating wormholes both extreme cases can cause a fa

sized. Recent marked effort in this regard included an analytical modeling of the tubing pickling process and its verification using field acidizi

They normally do not react to their full acid capacity because of the release of CO2 from carbonate dissolution (3) the degree of hydrogen

d treatment is the correct downhole placement of the acid for optimum zonal coverage.2ï¿½ Though over the years there have been many sing hydrochloric and mud acid systems and water based hydraulic propped fracturing treatments using polymers to viscosifyï¿½the frac flu of propagation.ï¿½ By increasing the flow rate from a low to a high value the dissolution pattern changes from a face dissolution to a worm own successful restimulation candidates in the industry. An attempt will be made to highlight the attributes mentioned in this paper through s ™s Ratio and â€œin-situ stress. An additional benefit from such log is the stress profile which is one of the most important parameters to e

% and permeability equals 15â€“60 mD. The oil-saturated thickness totals 7â€“11 m and the gas saturated thickness amounts to 19 m. Th

water breakthough intervals with the current completion in place is highly required." y of cement squeeze decisions are based on the results of physical communication tests the value of continuing to run cement bond logs w extract transmissibility to water from late-time data captured from slug tests by using a straight-line technique. Much later Cooper et al.2 an day initial build-up to get a first estimate of the reservoir pressure and key parameters Modified isochronal test: Three 8-hour flowing and sh oduction performance of the well in combination with direct physical measurements of layered reservoir flow rates and wellbore flowing pre

rvoirs have been a topic of continuous research due to the fact that many producing fields of the world are found in such type of formations. vestigation; i.e. how much reservoir volume if investigated for a given duration of a transient test? For exploration wells the reservoir volum stment.ï¿½ For operations engineers operating artificially lifted systems the main concern is to make sure that equipment is running efficien ve been built around the idea of applying a special time transformation [e.g. the logarithmic multirate superposition time (Agarwal 1980)] to

ates and Iran. Currently on Total ABK field well testing of around 65 oil producers is performed on two test separators. Total ABK wishes to ned in the testing systems Permanent monitoring requirements More of these requirements for wet gas well testing have already been pre

Multiphase-flowmeter interpretation emphasizes the liquid rate measurement and the application of multiphase flowmeters has been predo

measurement [Ref 2]. This leads to a compact and efficient solution. tested areas in the reservoir.

orating knowledge of both reservoir and gauge physics. It is efficient and straightforward to implement and may be used on either real-time o the surface acquisition unit so that there was no requirement for downhole electronics. There were 7 electrodes in each zone at a spacing

d system performance that cannot be engineered away and that may happen even when job is perfectly executed. Mitigation measures mus

reservoir or geological formation with reservoir characteristics (porosity and permeability) with pores filled with brine. The term â€˜salineâ€

s fuel burning and industrial processes (Figure 1). The foremost contributor to increased atmospheric CO2 is fossil fuel combustion for po ey undergo stress changes and deformation[iii]. The mechanical response of the sealing components to the loads induced by well drilling a

of all service companies involved in detail planning and risk identification workshops are a critical factors for success. In the operational ph

of natural CO2 deposits and preliminary assessment of commercial CO2 fields in the USA. This paper discusses the results of the first stud ne solution that has been used primarily in water-based systems has been laminated sand analysis. This type of analysis has been applied

al porosity types that are fractured/micro-fractured and cavernous/micro-cavernous pores can always be observed in the altered granitoid ro manent abandonment of zones in addition to temporary wellbore areas isolation for tubing integrity tests and general pressure testing (Wellh ment and confirming where the TOC would be after the intervention. This by implication makes it difficult to determine if a good cement job h

n and the modeling results are presented in this paper. 7). Therefore the characteristics of gas/liquid flow cannot be applied directly to oil/water flow in most cases. Generally knowledge of the di d using the Brinkman model (1952). The model predictions of the flow pattern transition water holdup and pressure gradient are compared of the well.ï¿½Intelligent completions also can guarantee regulatory requirements to back-allocate production from the wellhead measurem timization opportunities of San Manuel Production System. Project Scope In August 2006 Schlumberger-Mexico was contracted to develop ases and the asphaltenes aggregate. As the field matures oil cross-flow from the higher oil pressure zone into the lower gas pressure reserv and operation of the subsea system will be discussed. Flow Assurance Properties of Waxy Crude Oils The experimental data generated in and must first hydrate to carbonic acid (H2CO3) before becoming acidic and corrosive. The corrosion produces iron carbonate (siderite) sc

ent data. Abdel Fattah et al.6 showed that both Whitson and Torp and Coats procedures provide excellent match with compositional simulat

complexities above often zones with unwanted fluids are perforated. Selectively testing each producing layer to identify fluids using conve asily have very similar in-situ densities but very different compositions consequently very different pressure-volumetemperature behaviors.

luid properties reliable enough for economic screening. Therefore it is imperative that representative high-quality WFT samples are collecte

ectives were achieved. various other mitigating or accentuating factors. Detect the onset and evolution of reservoir souring upon the implementation of water injec

e reservoir fluid is near its critical point. In heavier oils compositional grading can be due to a number of causes or a combination thereof. T

ed (VIS/NIR) absorption spectroscopy is widely used to assist wireline fluid sampling today. Identification of gas oil and water is now well e

n and volumetric behavior is complex. When a critical transition exists in the reservoir the fluid column then changes from a bubble point flu rger fractions of formation fluid replace the OBM filtrate. An accurate value of the GOR is important for many applications including crude-

wavelength. At any time instant the measured OD is a weighted linear combination of the spectra of the undesired OBM filtrate and the des nt wavelengths and a simplified hydrocarbon composition can be quantitatively determined from the NIR spectrum. With the latest DFA tool

sity of the oil. Viscosity of water-in-oil emulsions increases as the water cut increases before the so-called emulsion inversion point beyond

facilities (Raghuraman et al. 2007). It also establishes the salinity for petrophysical evaluation and fingerprints the aquifer for studies on ba

for conversion this is unavoidable and has been similarly required to obtain flow rates at standard conditions with a separator or any other production could be maintained. At these production conditions significant variations of fluids properties can be observed on surface both

oper design is to avoid an aggressive fluid which even though it imparts high rock dissolution (Table 2) may cause severe nearwellbore dec

characteristics of the inhibitors. To address these problems and limitations of the current available chemistries associated with salt remova

is much less than undamaged rock. The perforation tunnel creates a flow path between the reservoir (at pressure pr) and the wellbore (a ion is further confirmed by thousands of samples retrieved from electrical submersible and rod pumps production tubing and downhole sca r production. This paper presents the applications of a phosphino-polyacrylate scale inhibitor (PPASI) in the stimulation of multi zone gas w

oblems. This would tend to indicate that UZ field would not have significant production declines due to scale. .ï¿½Reservoir depth is 3 650 - 4180 m (11 975 â€“ 13 665 ft) subsea initial temperature was 160 ï¿½C at 4 155 m (320 ï¿½F at 13 362 ft) y. In the examples presented in this paper the pilot points are distributed uniformly through out the reservoir. The sensitivity analysis is done

optimization of gas production.ï¿½ The implementation at AIB was divided into three successive phases.ï¿½ The first phase includes an ass

ntral African Shear Zone. The development of the rift basins of southern Sudan is related to the processes that operated not only within cen

ies are among the fluid parameters that determine the economic viability of a field development. Downhole fluid analysis (DFA) is a powerfu

of regional stratigraphy study indicates a major East Africa rift basin appeared and developed in the Late Jurassic to early Cretaceous. Early

ssure is approximately 200 psi with bottomhole temperature of 120F. The heavy oil viscosity is more than 5 000 cp at standard conditions (F

tions of some these acid systems with various clays were discussed by Al-Dhahlan et al.11 In general during sandstone acidizing treatmen

sslinking at a lower temperature for initial proppant transport and the second complex for higher temperatures experienced in the fracture.ï

oduction enhancement. Fracturing was started in the Bach-Ho field as early as 19941. Target zone for fracturing has mostly been the Oligoc ch reaction kinetics fines migration tests core flow tests was conducted on field cores to evaluate and compare the performance of the ne of metal ions. In oilfield applications chelating agents (Frenier et al. 2000) are frequently added to acidic stimulation fluids to prevent precip he productive interval. Many of these sand beds contain hydrocarbons but produce oil water or gas depending on the fluid saturations rela lean up even at low drawdowns. The capillary pressure can be decreased by altering the wettability decreasing the interfacial tension or b

ate wells are planned injector wells or converted fractured producer wells that are accordingly fracture stimulated therefore avoiding signifi

al well at 100 BOPD and 1% water cut. A follow-up horizontal sidetrack was completed in 2005 with similar results. These two wells currentl

s focused on the Riverbend field and some analysis has also been done in the Natural Buttes field.ï¿½ This paper focuses on three major f ure and fluid saturation and infinitesimal vertical permeabilities were entered into the models to prevent gravity equilibrium. Wells are stimu dology to compare production forecasts using a laminated sand analysis and stimulation designs is a useful tool for exploiting bypassed tigh

riations characterization of hydrocarbon-water transition zones injection fluid monitoring and so on. On the other hand the complexity of

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½c. Once the pretest piston stops expanding the flowline the pressure will build-up onnectivity between the borehole and all pay intervals in each of the commingled-lenticular reservoirs. The installation of electronic gauges

d since then the YTZ. This referred both to the capabilities of seismics which could not differentiate some fine features of the geological cro

nd variable wettability. It has observed that the saturation exponent of the famous resistivity-based Archie equation depends on the initial ï¿

ques better drilling and completion practices and have also helped in accelerating the production from mature fields.

erize rock types and their properties. Lately NMR has been proven to provide two fundamental parameters â€“ relaxation time and amplitud

rongly reduce its spatial resolution. Also the pricing of such high resolution tools limited their use to specific tasks (horizontal wells cored ve

Keefe et al. 2008). DFA tools provide results in real time and at reservoir conditions. Current DFA techniques use absorption spectroscopy o uction. Coupled with reservoir and fluid complexities above often zones with unwanted fluids are perforated. Selectively testing each produ

ties using a similar suite of measurements acquired while using wireline-logging tools has been presented previously (Herron et al. 2002). H

rs may result in bypassing the pay zones. In the present paper an approach is proposed to estimate the uncertainty in the calculated wate assing the pay zones. y injection capillary pressure (MICP) and relative permeability curves can be utilized during the workflow. Even though such core data may b curves from borehole2 image log. Separation borehole image resistivity curve from the Induction curves caused by invasion of the formatio ping from traditional logs and interpretation methods does not yield satisfactory results (Fig. 2).ï¿½ One of the primary objectives in this cas oirs. Passey et al. (Ref. 1) define petrophysical thin beds as contiguous units of rocks with thicknesses between 1 in. (2.5 cm) and 2ft (61 cm

een 3D induction and NMR interpretation techniques does not guarantee an accurate evaluation of reserves it does indicate that the results

ed or excessively stressed either during and/or after the coring has taken place. Whilst drilling induced fractures seen by image logs provide Definition Structural and Strati-structural trapping mechanisms play critical roles for hydrocarbon entrapment within Upper Cretaceous reser

nd Alabert 1988 Jones and Ma 2001 Deutsch 2002).

4 paper for the first evaluation of thin gas-bearing sands using well logs2 and Galford et al 1986 paper on tool response enhancement aka

important to consider stress reorientation in a reservoir development plan. Stress reorientation around horizontal wells is an often mention

depleted sands was accomplished in the Ursa field in the GOM using water-based mud with monomer and resin materials that exhibit large

e field consists mostly of Paleozoic carbonates that also include some layers of siliciclastic and volcanic rocks. The overall structure of the f

an irreversible manner.

porosity and naturally fractured reservoir environment. Despite of this the measurement of a reliable porosity with the NMR technique in th gical effects could mask it. Hydrocarbon type can also be interpreted from pressure gradient plots. However a reliable pressure gradient ne

on and reservoir characterization and can also be used to justify UBD. The objective of this paper is to demonstrate the use of a reservoir-s e Mishrif consists of homogeneous mud dominated lithologies which is deposited in a slightly rimmed ramp environment. The upper part sh

t al 2005a Dong et al 2006 Fujisawa et al 2006). Additionally the differences in absorption spectra between reservoir fluid and oil-base m where.6 Figure 1 is a schematic representation of one possible configuration of WFT tool with two DFA modules a pumpout model sample

API and formation water has total chlorides in the region of 148 000 mg/l. SCAL has been performed on a number of occasions throughou n this study the operational success ratio of downhole formation pressure testing (valid test vs. total tests) has remained at an average of 3

he dual packer module and monitoring the pressure at the dual packer as well at the vertically displaced observation probe.ï¿½ The acquire n made in this area. A good summary of the literature on the dynamics of invasion and mud cake formation is presented by Hammond1. In nal risk exposures for the selected activity are estimated and reported whereby potentially high risk aspects are known to the implementatio icted thickness of the sand bodies limits the number of data points and hence the reliability of pressure gradients for fluid identification. The

shows an arbitrarily selected cross section of Block 10 included here to illustrate the severe degree of faulting which is a problem particular

herefore bottom hole flowing pressure); however for mature field artificial lift optimization is challenging without a major workover to lower th

ing-blocks:

flow-entities and flow-entity lists expressions actions instructions balancing strategies procedures fluid system

FM adap

.0) was found to be almost entirely isolated from its aquifer resulting in no discernible pressure support. It was estimated that the volume of

t Present Value (NPV) from planning solutions can be routinely exploited within the average asset. What is needed is a road map for the a mization opportunities of San Manuel Production System. Project Scope In August 2006 Schlumberger-Mexico was contracted to develop ed for the accuracy required of the static and dynamic model before the dynamic model can be used for forecasting. is stage is around 84%. Present Challenges The XJG reservoirs are being developed using two fixed platforms. At this time no additional s

zones have greatly improved production performance and field recovery. The petrophysics and depositional environment of the reservoirs a plans requiring hydraulic stimulation. It is important to first describe the state of understanding of the Saih Rawl field prior to the ongoing d ge to allocate production by the reservoirs.

ation in 3D to calculate the distance to this bed together with its azimuthal orientation with respect to the borehole. In practice inversions a mulations indicated that the Brenda pool could be efficiently depleted with four horizontal production wells three in the east accumulation a ls are constructed based on seismic information tied to well information such as logs cores pretests and longer term tests.ï¿½With the co out of gauge pressure once every second. At the surface these data are temporarily stored on a computer the Acquisition Surface Unit (A specially attractive. In almost any water flood water passes by the oil on a macroscopic scale due to the heterogeneity of the reservoir.ï¿½ East Malaysia. After its discovery in 1971 development began in 1981 with installation of an integrated drilling and production platform. 14 parameters to be optimized are usually well-flow rates bottomhole pressures (BHPs) or choke-valve settings. Because these are not mixed

nalytical solutions to full field reservoir problems where multiple well interference effects and reservoir boundaries are fully accounted for h and is thus considered well-suited for post-data inference and uncertainty assessment by defining a posterior distribution of models and sa

the total number of components in the fluid models excluding water component using natural variable formulation.

ucing intervals) can be taken to resolve the problem and optimize well performance.8 9. Simulation of horizontal wells is very challenging du

swelling in the case of incompatible fluids broken-polymer/fines migration into the reservoir matrix and chemical interactions between the f typically up to 50%. Slugs of unbroken residuals were reported during the post-fracture production and indicate the existence of gel resid

ain disadvantages and first of all:ï¿½ large amount of the grid cells and excessive requirements to the computational resources as sequenc ly the fracture height but also the fracture width and fracturing pressure. The effects and the implications on fracturing treatments are demo dustry. Numerical simulation allows detailed reservoir properties layering pressure-volume-temperature (PVT) and field and well geometr

ength. This observation leads him to construct his flow simulator based on two major tenets: first that the fracture is of infinite conductivity; r the apparent wellbore radius of very low conductivity fractured wells than had existed previously. ï¿½ï¿½ At this point the general concep metry and flow being radial. Actually not so new since Sneddon and Elliot had started to derive it as early as 1946.1 At this time however no

mble averaging. An additional problem is introduced when the data sets are small. This is a common situation in petroleum-engineering and

e of the density gradient caused by temperature and concentration gradients convection flow occurs and creates a concentration difference

onsider 3-dimensional grids. The paper is organized as follows: Section 2 describes our transmissibility upscaling method (TU-method) wit

nd Mueller 2004; Roxar FracPerm Reference Manual 2005). The boundary conditions consist of (1) location/geometry of fault surface (2) s

ange of 1 to 20. The numerical method described so far can be used for an arbitrary discretization of a streamline. We can further accelerat acture transport processes are introduced. Traditional reservoir-modeling workflows have been deterministic with a single best effort" desc

ulations to be made whilst taking advantage of the reduction in numerical dispersion that may be obtained by performing streamline simula

the latter may vary from one streamline to another. For some complex processes much of the computational effort during streamline simu

Principal Component Analysis currently used in computer vision applications . In a face we have pixel illumination as function of space whi could be represented and loops were not permitted. This paper describes how the formulation has been extended effectively to allow any

or this sample. Liquid saturation vs. pressure resulting from a CVD experiment of this PVT sample is shown in Figure 2-b. The sharp increa

ï¿½ï¿½ï¿½ï¿½ï¿½ ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ ot major complications in the gradient interpretations then there are two generic pressure gradients which can be observed in transition zo sic concepts and procedures for proper design of an underbalanced coiled-tubing drilling procedure for a multilateral well are reviewed and ss across the region. ndustry that much of the future lies with the effective management of existing production and the continued development of mature fields.ï¿

ment sheath and for a given situation will decrease the risk of failure. In the modeling papers discussed above there has been little discus

onmental conditions. The Oseberg Sï¿½r field operated by Norsk Hydro is situated 130 km west of the Norwegian coast. The main oil-producing reservoir is th il quality deterioration1. Figure 1 shows typical well logs in Mauddud Formation in Sabriyah Field. The seawater injection water flood progra at has proven quite useful in better characterizing stratified flow in high-angle wells [5]. General Well Description The main oil productive re

he â€œcleanup phase. Optical fluid analyzers or resistivity sensors are typically used to monitor filtrate contamination in real time and samp chanisms 2 and for optimizing well placement.3 Although the monitoring and surveillance of the pressure data allows engineers to see the t crease fluid loss the viscosity of the injected brine was increased by adding low concentration of polymer and CO2. In the beginning of eac temperature logs to determine height containment in a tectonically stressed environment. This paper will illustrate several case studies whe

ed liquid droplets in the flow stream generally provides a better indication of the ability of a well to continuously transport wellbore liquids to t lly provides a better indication of the ability of a well to continuously transport wellbore liquids to the surface. emperature sensor can add to complement or perform measurements not possible with standard production logs including monitoring gas

ess to monitor daily production and lost production. However in some other cases the lack of a Loss Management System and limited Proc

g oil and water under certain circumstances can also form tight and viscous emulsions and thus pose hindrance to well productivity. The em

wing virtual collaboration between field staff and off-site service- and operating-company experts throughout the operation. This paper inclu data when reservoir layer pressures and other parameters are known (i.e. from logs). As the flow profile changes with time the model can th ates and cycle timing. Finally the passive seismic and surface deformation monitoring can also be used to track unwanted steam breakouts roducers as well as water injection conformance is critical for a robust reservoir management strategy. The high-deviation producing wells w reliable connection technique between upper and lower completions and a multidiscipline interpretation strategy to maximize the value of t

al time remote or manual) Production surveillance capitalizing on real-time data acquisition system investment Production allocation proc nments. Two Niger Delta case study wells validate the precision of the measurements against the results of the APLT multi-probe multi-spi

on estimation using Carbon-Oxygen ration have been used regularly since its inception. More recently the resistivity measurement through

he process at a more local level (Ref. 1). The benefits of this process are more efficient and faster recovery. The potential drawbacks are gr ion of the crosswell EM method for interwell saturation monitoring (Bhatti et al. 2007). This paper shows the results of the first time lapse in on conventional gas production in Canada is 5 Tcf/year declining by 2.5% per year. Estimates of world coalbed methane reserves range fr racteristics even in the commingled production scenario. s better exemplified than in a series of papers by Jeffery & Connell 2 3. In this piece of work small horizontal wellbores were drilled in coal s o the reservoir. The results of the first horizontal wells compared to vertical wells were three times the estimated ultimate recovery at twice t sociated with small apertures and changing fracture orientations in the vicinity of the wellbore.ï¿½ Furthermore because of the large inhere

n to the Lower Barnett.ï¿½ This increased EURs by roughly 20% to 25%. Also in the late 1990s Mitchell began to experiment with restimula invented and tested (Waters et al. 2009).

rogen ions attack the carbonate to generate Ca2+ CO2 and H2O. Equation 1 shows acid dissolution of limestone."

ntrifugal Compressors suffice the purpose. Surface Venturi As shown in fig 2 it is a metallic structure of the geometry as shown. It has a co entire area by thin marine sands intercalated with shoreface top carbonate streaks. Most part of the field reserves (over 60%) is associated

ear full bore and do not require incremental reductions of ID and thus allow normal cementing operations. The TAP valves also have unique

upward as well as the criteria for suspending and transporting entrained liquid droplets in the flow stream upward.ï¿½ It has been observed upward as well as the criteria for suspending and transporting entrained liquid droplets in the flow stream upward.ï¿½ It has been observed

of the reservoir information estimated until that point. The smart completion may then be programmed to follow this qi (t) as closely as poss

hodology for evaluating ESP system performance. The analytical process we propose represents the given data parsimoniously and provid

compared to previous PI or skin adjustment techniques. Using this methodology the number of potential fracture stimulation candidates ha

uring in the adjacent brittle upper shale. d. In addition the fibers allow for better proppant distribution throughout the hydraulic fracture. The better final proppant distribution is a resu

he study of the layered modulus effect has been investigated using a finite element method that can rigorously account for different moduli i with the gravel-pack completions in the mid 1980s in the Gulf of Mexico.2 Surfactant-gelled fluid was used to replace the polymer-based flui r a typical slickwater hydraulic fracture treatment can average 715 m3 (6 000 bbl) per stage with 6 to 10 stages per horizontal well. Large tre

essures. Currently 40% of stimulations performed in unconsolidated sandstones for Petroleos de Venezuela S.A. (PDVSA) in West Venezu e main fracturing treatment by pumping a mixture of specialty particles. The method is not unique to Western Siberian conditions and may duced. It combines mechanical and chemical diversion using selective openhole completion along with the VES diverting acid technology. or lifting the oil through gas lift systems. The application of Electrical Submersible Pumps for artificial lift is growing in these fields as the te

er of downhole operations. These operations are typically conducted by multiple interventions using slickline wireline or coiled tubing. Som nd inelasticity near the fracture tip.1 2 Some attempts have been made to develop the model of hydraulic fracture propagation in elastoplas ties was plotted in Figure 3.ï¿½Also shown in Figure 3 is the typical trend for total fluid loss coefficient of crosslinked polymer fluids.ï¿½Th

o fracture-stimulate the wells only when they fall below economic limit and (b) when fracturing avoid usage of water-based fluids since Mor

erburden pressure have greatly reduced the permeability and porosity of the sand layers.ï¿½ Sand porosities range from 2% to 12% with pe

usted to locate perforation shots to their assumedly correct positions4. The velocity model adjustment can be done in a number of ways but

ation situated below the AC-11 is characterized by complex and aerial heterogeneous structure of several sandstone bodies which complic Fracture height measurement through the use of radioactive tracers and subsequent logging runs allow engineers to assessï¿½: Post sti

A two-stage fracture treatment was monitored where a sandstone formation had been stacked vertically by a regional tectonic thrust fault. T

ows to determine theoretically the characteristic shape and width of viscous fingers[7 8] while in miscible fluids theoretical analysis allows t

e saturated under vacuum with 2% KCl prior to use.ï¿½The cell construction begins with placement of the lower core which includes a ga

me one of the main factors to restart the hydraulic fracturing operations. gn models include a calculation for the additional pressure needed to open and force fluid through a fracture branch that is not aligned perp tings their ability to deliver a wider range of gas lift rates as well conditions change the elimination of stability concerns resulting from overs ate on the high and low sides of the casing. The upper completion string consisted of a production seal assembly (stung inside the packer) n reservoirs such as matrix heterogeneous and non-conventional formations showed a direct correlation to the completion and stimulation n reservoirs such as matrix heterogeneous and non-conventional formations showed a direct correlation to the completion and stimulation m e filtercake by applying a minimum drawdown to the formation. This will enable maximum productivity from the reservoir without any potentia

oduction of oil and gas. It is geologically continuous with the Putumayo basin in Colombia and the Maranon basin in Peru separated only b

ofile along the well in response to monitoring data obtained from downhole sensors and to the predictions of reservoir and well models. Acti ½ï¿½ï¿½ï¿½ï¿½ ii.ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ Fracture #2 (normal to fracture #1) intercepting angled filled artificial joints p

nally a full scale well test and an interference test are conducted to determine well productivity and well-to-well connectivity respectively.

e the conduits for treatment fluid injection and reservoir fluid production.ï¿½ For natural completions the perforating job is designed with the er day (Sm3/d). In May 2003 the operator started the drilling phase of Well-1 located 800 m west from Well-0. The original objective of We to high water production. Nitrogen lift operation was performed on adjacent wells but failed to sustain the production. Despite the decline tre level of static underbalance has been extensively researched1 2 3; however more recent investigations4 5 have presented relevant eviden orating damage (skin effect) can be minimized by producing perforating tunnels free of crushed sand particles and other perforating debris. om 0.01 md to 7.0+ md. Water saturation can vary from 20% to 50%. Hydrocarbons are gas-condensate in depletion with partial water supp from an underbalance surge for clean-up. The well log data was evaluated to determine optimal perforating intervals and the applicability o gan 2004) have a similar or the same pressure transient as that of the UBP we discuss in this paper. All these tests essentially share a com

managers can decide whether the gun will survive (be retrievable) by using the modeling tool instead of merely relying on their experiences

pwater block were drilled with oil based mud and the hole was displaced to brine prior to running screens1. Significant problems were initia

ew challenges emerged for gravel packing wells drilled with oil-based fluids.[2] A significant level of progress has been made in recent year

oth technical and logistical/cost challenges in addition to the risks associated with running screens. e-like failure is very inefficient as the water passes through to producer via the wormhole channel and doesnâ€™t sweep any oil. Remedial sing proppant flowback control such as resin-coated proppants and fibers. Fines stabilization

here was initiated by Schlumberger in October 2005 to address a further 25 wells located in three areas (GC1 GC2 and GC3) that were de ately 500 km southeast from Benghazi (see Figure 1). The field operated by AGOCO has been producing for over 30 years and since the rted with data acquisition. Various wireline logs such as microresistivity image log and dipole sonic log were acquired from some of the key

shales encountered in the basin in previous studies. The likelihood of wellbore instability and sand production were assessed using in-hous n regular acids or acids containing uncrosslinked polymers. Two types of crosslinked acids are available. The first type consists of a polyme wide range of parameters. Most predictions of conductivity are made with the empirical correlation developed by Nierode and Kruk.1 This c y increased significantly in the 1990â€™s with the discovery of the Abilene Christian University (ACU) Strawn and Deer Canyon Strawn fiel

their effectiveness. Whenever possible pre- and post-job production logs and pressure transient tests were performed to better evaluate both extreme cases can cause a failure of the matrix integrity in the near-wellbore region. For a given acid system the optimum injection r

and its verification using field acidizing job data6 7. The studies showed that the process again involved the three basic mechanisms namel

olution (3) the degree of hydrogen ion generation decreases with increasing temperature 6 7 and (4) the cost of organic acid is significantly

er the years there have been many products and techniques developed in the industry for acid diversion the preferred ones generally have g polymers to viscosifyï¿½the frac fluid have demonstrated a very low success rate. Proppant fracturing treatments ï¿½though recognized es from a face dissolution to a wormhole and then to a uniform dissolution pattern.ï¿½ In the wormholing regime a maximum permeability i es mentioned in this paper through some well-known case histories. Based on the existing knowledge base on the restimulation identificatio the most important parameters to estimate fracture height growth. Additionally since the four Frontiers members were clearly identified a

ated thickness amounts to 19 m. The oil saturation factor totals 0.51â€“0.67 while the gas saturation amounts to 0.44â€“0.64. The initial fo

ontinuing to run cement bond logs was questioned. Conversely applying the policy of communication tests was costly and time consuming hnique. Much later Cooper et al.2 and Ramey et al.3 developed complete type-curve analysis techniques for estimating reservoir paramete nal test: Three 8-hour flowing and shut-in periods followed by a 6-day extended flow period and a 14-day build-up Pressure Traverse To c r flow rates and wellbore flowing pressures. Methodology The completion and production optimization methodology reported here relies o

are found in such type of formations. These reservoirs differ in geological and petrophysical properties from homogeneous reservoirs. Addit xploration wells the reservoir volume investigated is one of the main objectives of running DST or production tests. Therefore how far pres ure that equipment is running efficiently and to avoid catastrophic failures. uperposition time (Agarwal 1980)] to the test pressure data so that the pressure behavior observed during individual flow periods would be s

est separators. Total ABK wishes to improve the accuracy of testing its production wells by using a multi-phase flowmeter which will allow to as well testing have already been presented in Theuveny et al [1]. The basics of the gas well testing with dual energy gamma â€“ venturi mu

tiphase flowmeters has been predominantly for liquid-rich flow stream allocation and well testing."

nd may be used on either real-time or recorded data. No modifications to gauges or surface hardware are necessary. Furthermore error bo lectrodes in each zone at a spacing of 20 ft. A schematic drawing of the electrode array mounted on the outside of insulated joint sections o

executed. Mitigation measures must be adopted in this case to ensure a robust design. This is especially true for wells entering CO2 storag

ed with brine. The term â€˜salineâ€™ expresses that CO2 storage is planned in reservoirs not intended to be used as fresh water resource

CO2 is fossil fuel combustion for power generation transport industry and domestic use. Energy from fossil fuels has provided a high sta o the loads induced by well drilling and completion CO2 injection and the corresponding effects on the risk of leakage must therefore be as

rs for success. In the operational phase the work in the subsurface team was optimised through using 3D visualisation tools. These 3D too

discusses the results of the first study oriented to evaluate the CO2 proven reserves of Quebrache field and its potential application as EOR s type of analysis has been applied since the early 1990s primarily in turbidite plays[4] and not verified with production. The analysis used

observed in the altered granitoid rocks (figure 1)." and general pressure testing (Wellhead production tubingâ€¦etc) as well as selective acid stimulation and water/ gas control treatments. T to determine if a good cement job has been performed.

ses. Generally knowledge of the distinctive features of oil-water systems together with those of gas/liquid systems can be used in the futu and pressure gradient are compared with the present experimental results. The model performance under different flow conditions is analyz duction from the wellhead measurement to the individual reservoirs for reserves booking. An operator would not accept a predetermined s er-Mexico was contracted to develop an integrated study of San Manuelâ€™s production facility (PEMEXâ€™s Muspac Asset). The project ne into the lower gas pressure reservoir might also lead to precipitation and plugging of the gas sand. The consequences of asphaltene prec The experimental data generated in flow assurance studies are generally used to evaluate potential for solids deposition. This information produces iron carbonate (siderite) scale which can function as a protective layer under elevated temperatures increased pH and low turbu

nt match with compositional simulation results when PVT experimental data are matched with an EOS model and then used to output the M

g layer to identify fluids using conventional surface test equipment is a viable approach but can be costly. In this paper direct pressure and ure-volumetemperature behaviors. Conventionally delineation of reservoir fluids variations in a column required sampling with lab analysis

gh-quality WFT samples are collected early in any exploration or appraisal campaign.

on the implementation of water injection or other enhanced recovery techniques. Determine the price of a unit hydrocarbon produced and i

f causes or a combination thereof. These include water washing evaporative fractionation incompetent sealing shales dynamic charge of

n of gas oil and water is now well established (Smits et al. 1995). Problematic OBM contamination is quantified during sampling jobs using

hen changes from a bubble point fluid to a dew point fluid without encountering a fluid meniscus or contact. Further anomalies may arise als many applications including crude-oil typing and production facilities design. Conventionally GOR is measured in a PVT laboratory by flas

undesired OBM filtrate and the desired formation fluid. Initially the measured spectra are dominated by the OBM filtrate. With increased pu R spectrum. With the latest DFA tool 13 the hydrocarbon composition comprises five groups: methane (C1) ethane (C2) propane to pentan

d emulsion inversion point beyond which the continuous phase changes to water (i.e. water-in-oil emulsion switches to oil-in-water emulsio

erprints the aquifer for studies on basin hydrology. Water composition is important for production strategies involving inhibitor injection wells

ditions with a separator or any other devices. Figure 2 illustrates a generic flow path from line to standard conditions for any MFM and any fl s can be observed on surface both in terms of composition and Condensate/Gas Ratio (CGR).

may cause severe nearwellbore deconsolidation which is increased by the relatively high temperature. Based on previous experience it w

mistries associated with salt removal inhibition and to improve the lifetime of a squeeze treatment a R&D project was initiated to develop n

at pressure pr) and the wellbore (at pressure pw).ï¿½The pressure difference pr-pwï¿½can drive a surge flow either from the wellbore in production tubing and downhole scale sample from surface piping samples and also dozens of production fluid samples from many fields n the stimulation of multi zone gas wells. Specifically described is the monitoring of scale inhibitor return and the design optimization. Geolo

C at 4 155 m (320 ï¿½F at 13 362 ft) and initial pressure was 604.5 bar at 4 155 m (8 768 psia at 13 362 ft).ï¿½Some areas of the reservo rvoir. The sensitivity analysis is done with respect to permeabilities since it is essentially the correlation structure of permeability which quan

.ï¿½ The first phase includes an assessment of the existing data workflow for operation and surveillance process and a standardization eff

es that operated not only within central Africa but also along the western and eastern continental margins. The Sudanese interior basins ar

hole fluid analysis (DFA) is a powerful technique to help identify compositional grading and frequently missed compartmentalization of the de

e Jurassic to early Cretaceous. Early rift sediments interbedded with coarse rift clastics derived from surrounding uplifted basement source

an 5 000 cp at standard conditions (Figure 4) and the reservoir rock is oil wet with high H2S content (up to 9 mole %). The Nukhul formation

during sandstone acidizing treatments the following main precipitation reactions occur that can lead to formation damage.12 13

ratures experienced in the fracture.ï¿½ This approach would manage friction pressures.ï¿½ However the gel would still suffer irreversible d

acturing has mostly been the Oligocene as it has reasonable recoverable reserves does not have water zones nearby like the Miocene and compare the performance of the new sandstone acidizing system with current systems being used in the above oil field. c stimulation fluids to prevent precipitation of solids as the acid spends on the formation. The use of chelating agents is one proposed appro pending on the fluid saturations relative permeabilities rock and fluid characteristics. Presently fluid prediction success rate varies between ecreasing the interfacial tension or by increasing the permeability (or pore radius) of the formation. Penny et al.[5] used a non-water wettin

stimulated therefore avoiding significant water bypass or overshooting of the water front between layers within the formation. The uneven in

ilar results. These two wells currently produce 1300 BOPD and less than 1% water cut. As a result additional development will be impleme

This paper focuses on three major formations (Figure 2): Wasatch (Porosity (favg )= 11% Water Saturation (Sw )= 55% Avg Net = 90 ft) M gravity equilibrium. Wells are stimulated with multiple limited-entry hydraulic fracturing to attain economical gas-production rates. Operator eful tool for exploiting bypassed tight gas. Geographical and Geological Background The geographical setting for this case study is LaSall

On the other hand the complexity of the WFT operation has dramatically risen and continues to rise due to the increase in the types of WFT

he flowline the pressure will build-up to sandface pressure ï¿½ï¿½ï¿½ï¿½4. Multiple pretests may be performed on the same set and when The installation of electronic gauges below the ESPs together with daily monitoring has enabled the operator to evaluate hydraulic fracture

me fine features of the geological cross-section under several trappean and saliferous caps in high-velocity cross-section and to the boreho

ie equation depends on the initial ï¿½oil saturation and varies across the capillary transition zone for mixed-wet and oil-wet reservoirs. Furth

mature fields.

ers â€“ relaxation time and amplitude â€“ that are required for linking pore properties to fluid distribution combined with rock typing.

cific tasks (horizontal wells cored vertical wells for calibration purpose for instance) while today high oil prices should make their use at ent

ques use absorption spectroscopy of reservoir fluids in the visible-to-near-infrared (NIR) range. The formation-fluid spectra are obtained in r ated. Selectively testing each producing layer to identify fluids using conventional surface test equipment is a viable approach but can be co

ed previously (Herron et al. 2002). However the suite of measurements available with this new tool and the fact that many of the measure

e uncertainty in the calculated water saturation from the different shaly sand models due to the uncertainty in the input petrophysical and el

w. Even though such core data may be available only on a few key wells in a given field the fine tuning of parameters based on the detailed caused by invasion of the formations with the oil base mud. Generally the zones with larger invasion have higher mobility and those with m of the primary objectives in this case study was to identify logging technologies and interpretation methods that would improve the predictio between 1 in. (2.5 cm) and 2ft (61 cm) that exhibit a narrow distribution of petrophysical properties but are bounded above and below by ot

rves it does indicate that the results are plausible. What we seek first is to be able to say yes hydrocarbon is indicated by both tools or no

ractures seen by image logs provide important geomechanics data (i.e. pertaining to stress directions stress magnitudes and rock failure) ment within Upper Cretaceous reservoirs in the Al-Khafji area. The newly acquired 3D seismic data were aimed at delineating the stratigraph

on tool response enhancement aka alpha processing4. The third is the sandcount approach from a high-resolution dipmeter â€“ later subs

horizontal wells is an often mentioned but rarely quantified aspect of production planning and reservoir development. Stress reorientation a

and resin materials that exhibit larger fracture propagation pressure than do those of oil-based mud (however the fracture opening pressur

c rocks. The overall structure of the field represents a elongated anticline of an irregular shape that is located northwest of Mezhov arch. Inte

orosity with the NMR technique in these naturally fractured clastics reservoirs has demonstrated to be a viable and reliable alternative this ever a reliable pressure gradient needs sufficient and well-spaced points that might be difficult in thinly laminated beds or where there is a

demonstrate the use of a reservoir-simulation tool coupled with a method for parameter identification through automated reservoir characte amp environment. The upper part shows the occurrence of fine to very fine grained peloidal packstones to grainstones facies deposited in th

etween reservoir fluid and oil-base mud (OBM) or water-base mud (WBM) are used to estimate fluid sample contamination with the drilling modules a pumpout model sample modules containing the sampling bottles and two single-probe modules. On the right side of this figure

n a number of occasions throughout As Sarah fieldâ€™s life and these tests have confirmed the reservoir to be more oil than water wet. Th s) has remained at an average of 30% despite technological innovations in both wireline and drilling. In Table 1 we summarize the main re

observation probe.ï¿½ The acquired pressure and rate data were analyzed as a vertical interference test revealing permeability and perm tion is presented by Hammond1. In the early nineties Goode and Thambynayagam2 developed a model that exploits the pressure transient ects are known to the implementation team and accounted for in economic evaluations. Generating options and screening them to achieve gradients for fluid identification. The error band of formation testers (given by depth accuracy and gauge resolution) becomes of relative im

ulting which is a problem particularly important when investigating the feasibility of re-development opportunities such as waterflooding or m

without a major workover to lower the depth of injection point or changing out to a pump system. When gas oil ratio increases well product

procedures fluid system

FM adaptors to reservoir simulators and surface-network simulators enabling the abstraction of the implementati

It was estimated that the volume of the aquifer was approximately one hundredth of the aquifer in the adjacent reservoirs with about 0.25 b

at is needed is a road map for the adoption and development of these IAMs along with a statement and agreement of the principles that g er-Mexico was contracted to develop an integrated study of San Manuelâ€™s production facility (PEMEXâ€™s Muspac Asset). The project r forecasting. latforms. At this time no additional slots are available for new well locations on either platform. This situation limits infill drilling to accelerate

onal environment of the reservoirs are briefly described as follows. aih Rawl field prior to the ongoing development program in 2004.

Reservoir Characterization. The average characteristics of the Barik a

e borehole. In practice inversions are performed in real time while drilling using both directional EM curves and other LWD resistivity curves lls three in the east accumulation and a fourth in the west accumulation. Reservoir simulations also indicated that the initial production rate nd longer term tests.ï¿½With the commencement of production these models are altered and conditioned to honor observed production dat uter the Acquisition Surface Unit (ASU) (which connects the input data streams from all the various surface and downhole sources) and a e heterogeneity of the reservoir.ï¿½ This might lead to reasonable spots of bypassed reserves which are not accessible through any existin d drilling and production platform. 14 wells were drilled targeting production from reservoir sand at 8000 ft tvdss. An additional drilling platfor ettings. Because these are not mixed-integer problems gradient-based methods are used commonly to solve them and the adjoint method

boundaries are fully accounted for have been presented for porous media with homogeneous and anisotropic permeability by Busswell et. a osterior distribution of models and sampling multiple realizations from this distribution.

ormulation.

orizontal wells is very challenging due to the fact that they often produce from a large interval with substantial heterogeneity in rock properti

chemical interactions between the fracturing fluid and the matrix such as pH alteration or polymer adsorption (Holditch 1979). In addition h d indicate the existence of gel residues inside the fracture after the cleanup process. The incomplete degradation of the polymers in the fra

computational resources as sequence difficulties with grid generation around fracture (especially for complex shape fracture) problems with s on fracturing treatments are demonstrated through a numerical example and a field case study. e (PVT) and field and well geometry to be incorporated into the model. It is therefore possible to model the fluid flow from matrix to fractur

e fracture is of infinite conductivity; and second that the fracture conductivity and the fracture half-length can be merged into a single term ¿½ At this point the general concept of fracture stimulation design using the dimensionless productivity index as a basis has been reasona y as 1946.1 At this time however nobody could imagine that the era of horizontal drilling would eventually come so their difficult mathematic

tuation in petroleum-engineering and geosciences applications in which the cost of data or collection logistics may limit the number of meas

d creates a concentration difference between the top and bottom of the column. Analytical and numerical models have been presented to a

y upscaling method (TU-method) without imposing monotonicity constraints on the solution matrix. Section 3 presents a brief discussion on

ation/geometry of fault surface (2) stress conditions or displacement conditions on the fault surfaces and (3) the remote loads applied to th

treamline. We can further accelerate the method by using the adaptive mesh refinement as described in our previous work [2]. In this work nistic with a single best effort" description of the reservoir and little or no quantitative evaluation of uncertainty in the data and its impact on

ned by performing streamline simulations as opposed to finite difference calculations.

ational effort during streamline simulation is spent on the solution of the 1D transport equations [12]. Therefore a fast numerical method for

llumination as function of space while in a continuous pressure data we have pressure as a function of time. Therefore a shift has been m n extended effectively to allow any number of outlets from a segment thus enabling loops to be incorporated in the ICD model. We apply t

own in Figure 2-b. The sharp increase of liquid-dropout volume immediately below saturation pressure shown in Figure 2-b illustrates a typi

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ (3) ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ after rewriting the Forchheimer equation. Base hich can be observed in transition zones of homogeneous limestones.ï¿½The profile of figure 1 is the most general and it is on this we focu a multilateral well are reviewed and those design concepts were used to formulate the strategies for the project discussed in this paper. Ni

nued development of mature fields.ï¿½What may not be so clear is how to apply smart technologies to mature fields with a legacy infrastru

d above there has been little discussion of how to determine the appropriate parameters that describe the cement mechanical behavior. Th

he main oil-producing reservoir is the Tarbert formation within the Brent group which is of variable reservoir quality with permeabilities rang seawater injection water flood program was designed to reduce the pressure depletion and increase the sweep efficiency. After successful w escription The main oil productive reservoirs in Chayvo lie 8-9 km offshore from the drilling rig location at depths of 2400-2900 m TVDSS (s

ontamination in real time and sample collection into sample chambers begins once specific criteria to ensure representative water-sample e data allows engineers to see the trends such as reduction in kh or increase in skin with time geomechanical analysis must also be perfor er and CO2. In the beginning of each stage the injection rate was increased stepwise up to 45 bbl/min to result in a final wellhead pressure ll illustrate several case studies where solely temperature logs have been used in a tectonically stressed environment to determine fracture

uously transport wellbore liquids to the surface.

uction logs including monitoring gas lift valves6 leak detection7 and detecting flow behind casing/tubing.

anagement System and limited Process Automation does not allow the Prodcution Engineer to take advantage of the information available f

hindrance to well productivity. The emulsification process can be aggravated by the presence of asphaltenes and waxy materials.10

hout the operation. This paper includes several examples of WFT surveys that were monitored and supervised in real time. The cases pres changes with time the model can then be used to predict the reservoir pressures from the change in temperatures. Of course this could b d to track unwanted steam breakouts. Thus combined monitoring of passive seismic and surface deformations offers critical information for The high-deviation producing wells will be mostly completed with sand screens and are capable of up to 50 000ï¿½BOPD flow rates. The m n strategy to maximize the value of those sensors.

estment Production allocation process standardization Production allocation traceability and audit trail Automated consolidation and acc ts of the APLT multi-probe multi-spinner production logging tool. The Challenge Skepticism towards attempting to acquire Production Logg

he resistivity measurement through casing opened new vistas in estimating saturations under suitable conditions efficiently and accurately (

ery. The potential drawbacks are greater costs and higher local pressures which could induce uneven flows. s the results of the first time lapse in the WI pilot where decrease in resistivity due to 4 months of water injection in the lowermost units of th coalbed methane reserves range from 4 416 to 8 556 Tcf with 749 Tcf located within the US. Production of coalbed methane has steadily in

ontal wellbores were drilled in coal seams to degas prior to mining. The wells did not produce adequately from the horizontal open hole wel stimated ultimate recovery at twice the well cost. Horizontal wells offered an economic solution to areas outside the core and reduced the n hermore because of the large inherent anisotropy in tight gas shales near wellbore stress concentrations are considerably more variable th

began to experiment with restimulation treatments.ï¿½ In many cases well performance matched or exceeded the original initial production

limestone."

f the geometry as shown. It has a converging section throat and a diverging section. The metal thickness should be adequate enough to be ld reserves (over 60%) is associated with oil-water zones. Productive reservoirs show mostly good lateral continuity and are underlain by va

s. The TAP valves also have unique helical ports that align to any preferential fracture plane regardless of the orientation of the valve in the

m upward.ï¿½ It has been observed by Turner et al1 and Oudeman9 that the flow stream velocity required to continuously move the liquid f m upward.ï¿½ It has been observed by Turner et al1 and Oudeman9 that the flow stream velocity required to continuously move the liquid f

to follow this qi (t) as closely as possible. In contrast to poor sweep problems among vertical wells to improve contact one may think of ha

given data parsimoniously and provides performance indicators (with confidence bounds) in response to specific questions. At the risk of pre

al fracture stimulation candidates has increased by 200%.

r final proppant distribution is a result of the proppant suspension properties of the fibers that physically prevent the proppant gravitational s

orously account for different moduli in a hydraulic fracture simulator (Smith et al. 2001). Two effects of high-modulus layers on fracture heigh ed to replace the polymer-based fluids in sand-control applications to improve retained pack-permeability and to aid inducing concentration stages per horizontal well. Large treatment volumes for these applications offer a unique opportunity for cost savings if flowback water can

zuela S.A. (PDVSA) in West Venezuela are frac-and-packs. The importance of the frac-and-pack technique relies on the fact that less rig t estern Siberian conditions and may be applied to any formation where height growth is suspected to occur at the expense of fracture extens he VES diverting acid technology. is growing in these fields as the technology that allows these pumps to handle sand production has evolved in the recent years. In the e

ckline wireline or coiled tubing. Some of the new methods are placing more downhole hardware in the ground to reduce interventions. Ot c fracture propagation in elastoplastic media. In particular the analysis of the easier case of impermeable elastoplastic rock is presented in of crosslinked polymer fluids.ï¿½The results indicate that the fluid loss coefficient for the VES system is comparable to that achieved with

age of water-based fluids since Morrow formation is water-sensitive.ï¿½ When opting for option (a) though potential loss of production was

osities range from 2% to 12% with permeabilites <0.01 md.3

an be done in a number of ways but it usually involves fitting of S-P-wave traveltime differences. The S-P-wave traveltime differences which

ral sandstone bodies which complicates HF application. AC-12 is oil saturated highly laminated sandstone with shale streaks in between. T w engineers to assessï¿½: Post stimulation problems such as lower than expected production Design assumptions Possible modification

by a regional tectonic thrust fault. The resulting microseismic-event locations and -signal attributes indicated that there was a significant ch

le fluids theoretical analysis allows to forecast the shape of the tips but does not allow to determine the width of fingers which remains a fr

the lower core which includes a gasket on top to seal against the metal cell lip. The inlet and outlet line dead volumes are filled with wate

cture branch that is not aligned perpendicular to the minimum stress.14 Offset development in natural hydraulic fractures has been modeled tability concerns resulting from oversized orifices and faster annulus unloading during well commissioning. assembly (stung inside the packer) 7-in tubing string downhole pressure gauge and a subsurface safety valve. Four intervals varying from on to the completion and stimulation methods employed and their shortcomings in horizontal applications. Thus the additional economics re n to the completion and stimulation methods employed and their shortcomings in horizontal applications. Thus the additional economics req om the reservoir without any potential need for a stimulation intervention. ï¿½

non basin in Peru separated only by geological arches located north and south east of the basin.

ns of reservoir and well models. Active control can be either â€œreactive or â€œproactive (Kharghoria et al. 2002; Yeten et al. 2004; Aitokhu cepting angled filled artificial joints placed on each side of the centered wellbore (fracture containment) as seen in Figure 1. Fracture tip ar

l-to-well connectivity respectively.

e perforating job is designed with the goal of by-passing the drilling damage in mind by creating deep and clean perforations.ï¿½ In low perm Well-0. The original objective of Well-1 was to appraise the field after the Well-0 discovery. The decision to drill Well-1 as a horizontal well a he production. Despite the decline trend remaining gas reserves are still attractive and having potential to be produced in the future at 85% s4 5 have presented relevant evidence indicating that static underbalance is not the only governing factor in effective perforation cleanup. articles and other perforating debris. Conventional underbalanced perforation methods use static underbalanced pressure (wellbore pressur e in depletion with partial water support. ating intervals and the applicability of the dynamic underbalance perforating technique to these reservoirs. For well number 2 the reservoir b l these tests essentially share a common feature an underbalanced pressure differential between the reservoir and the wellbore which driv

f merely relying on their experiences to make the tough decision. Perforating systems and their damage mechanisms were discussed rece

ns1. Significant problems were initially encountered running screens due to shale instability and as a result the current system in the offset

gress has been made in recent years towards overcoming these challenges through new developments in fluids application tools and tec

oesnâ€™t sweep any oil. Remedial attempts proved to be expensive and ineffective due to the inability to effectively isolate the targeted for

s (GC1 GC2 and GC3) that were deemed to be representative of the whole field. The work covered geomechanical reservoir characterizati ng for over 30 years and since the mid-1980s some wells have suffered massive sanding while others have not. 1 A geomechanics and sa were acquired from some of the key study wells. Geomechanical laboratory tests were carried out on core plugs to determine rock mechanic

duction were assessed using in-house developed wellbore stability and sand production tools. e. The first type consists of a polymer a crosslinker and other acid additives (Saxon et al. 2000). The acid in this case is crosslinked on the eloped by Nierode and Kruk.1 This correlation was based on experiments using 1 inch diameter by 2 to 3 inch long fractured cores with no Strawn and Deer Canyon Strawn fields. Subsequent development of the Strawn over the past decade has resulted in a better understanding

s were performed to better evaluate the results of the stimulations. acid system the optimum injection rate is the rate that creates the longest dominant wormholes for a given volume of acid. Acid systems f

the three basic mechanisms namely surface reaction diffusion and convection and the art of balancing these three fundamental forces e

e cost of organic acid is significantly higher than that of HCl for equivalent mass of rock dissolved.

n the preferred ones generally have to possess the following characteristics: Must not cause permanent damage to the formation. The div g treatments ï¿½though recognized as the more effective stimulation method still encountered the following problems: significant polymer d ng regime a maximum permeability increase can be achieved for a given volume of acid. Therefore the flow rate at the wormholing regime is ase on the restimulation identification process a systematic and comprehensive candidate selection methodology will be presented in this p members were clearly identified a wireline pressure tool was used to take several pressures points across different members. As a result o

mounts to 0.44â€“0.64. The initial formation pressure totals a maximum 34.9 MPa and static temperature 92â€“96oC. The density of the o

ests was costly and time consuming and could not be practically applied to wells covering multiple reservoirs not intended for production. Co es for estimating reservoir parameters from slug tests. Although significant groundwork for a complete straight-line analysis technique for the y build-up Pressure Traverse To compute gradients from the pressure and temperature surveys it is necessary to convert the measured d methodology reported here relies on determination of the completion efficiency in terms of the evaluation of the in-situ reservoir and well pr

om homogeneous reservoirs. Additionally in many oil and gas reservoirs the producing wells are completed as partially penetrating wells; t uction tests. Therefore how far pressure may diffuse (radius of investigation) during a transient test is very important for exploration well tes

ng individual flow periods would be similar in some way to the constant-rate system response. As also stated by Levitan the superposition-ti

-phase flowmeter which will allow to increase the number of well tests and better characterize/follow-up wells instabilities leading to optimize h dual energy gamma â€“ venturi multiphase flowmeters have been shown by Pinguet et al [2] Hopman et al [3] and Guiese et al [8].

re necessary. Furthermore error bounds and a quality control mechanism indicating the end of a transient (i.e. a signal-to-noise ratio test) e outside of insulated joint sections of the sand-screen completion is shown in Fig. 3. Individual screens are joined together to form the com

Schlumberger Spe Papers

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