Shell Spe Papers (1)

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 SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL

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

11491 109245 108161 109506 97754 114791 108540 121272 114790 115247 112854 98583 110907 112259 123202 104161 112947 11647 99963 108515 112037 122554 123538 12075 114869 114870 100710 123147 99484 99728 103575 108206 100880 90213 114550 108358 103576 113917 121840 113313 111403 101099 105604 113358 12025 100525 105406 100034

Chapter CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process Corporate Process 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

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

119835 102244 88765 107101 114886 107095 11638 108496 102798 103242 100739 113333 106391 100393 11582 109684 81481 121670 97886 96021 113314 103041 102672 102412 122241 104467 114034 100517 107633 114103 102970 112876 120428 107201 112558 113461 102876 116243 107647 93805 106151 108765 100574 115034 102745 107954 112907 11408 107673 119722 118128

EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR 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 Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil HP/HT HP/HT HP/HT 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 Minor Reservoirs Project Management

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

99873 115646 122710 99482 109094 100937 108566 110223 12191 114854 95841 118332 90002 115347 110472 106756 100449 105015 100740 109683 109861 11415 93624 100738 12203 101807 11490 122600 128603 96400 101863 110360 128348 121909 110019 12225 110379 109826 12327 114805 102913 105357 111922 101017 113068 113527 118290 121786 11624 111997 11644

Project Management Project Management 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 Development Reservoir Development Reservoir Development 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

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

122553 119098 92795 105784 106178 117951 118798 121891 119156 102389 109246 109011 108651 12344 102310 112940 105764 123563 102650 12550 105797 101880 106170 119030 108307 102467 115204 110316 118173 104580 128350 101070 90320 105973 120170 118712 110306 113703 109284 95498 88761 102471 11536 100953 102266 108947 106144 102730 128363 101033 109943

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 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

SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL

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

81496 110348 111920 113215 11722 113865 113429 103054 115274 102186 113464 117987 99242 11119 12860 12175 12533 115019 100024 111478 83995 11398 103275 118735 128362 108207 109077 109007 112204 118831 108835 108957 115591 100342 112301 94708 97848 95763 11433 115365 11384 123142 121164 101038 99921 100495 90959 102831 105583 108011 102326

Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Safety SPE Forum State of the Nation State of the Nation 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 Unconventional Reservoirs Unconventional Reservoirs Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability

SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL SHELL

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 SPE SPE SPE SPE SPE SPE

98746 112234 110754 102678 102077 122133 107790 107795 104605 107980 115567 102656 101082 12334 101187 101181 116091 111635 116713 112099 102305 106321 107749 102304 98098 104480 109053 115720 88735 108665 109279 99971

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

Section

Subject

Corporate Processes Corporate Processes Mechanism - Capillary and Wettability Mechanism - Difusion Mechanism - Swelling Mechanism - Swelling Modelling - Injection Modelling - Injection Reservoir Description Reservoir Description State of the Nation Workshop Paper PRODML PRODML Shell's Collaborative Work Environments Shell's Data Broker Shell's FEAST Shell's FWPU Shell's FWPU Shell's FWPU Shell's FWPU Shell's FWPU Shell's LEAN Practice Shell's OVT Shell's OVT Shell's OVT Shell's SMART Field Shell's SMART Field Shell's SMART Field Shell's SMART Field Shell's SMART Field Shell's SMART Field Shell's Snake Wells SPE's RTO Snake Wells UBD UBD High Pressure Air Injection - Modelling Chemical Flooding Chemical Flooding Gravity Drainage High Pressure Air Injection Miscible Gas Injection - Process Modelling - Foam Injection Reservoir Management Reservoir Management Thermal processes- GOGD WAG Feasibility

Shell's Carbon Capture Project Shell's Carbon Capture Project Fluid Description Coal Permeability - Coal Permeability - Coal Compositional Geochemical Core Experiments Field Study Storage Capture/Storage Production Data Standards Production Data Standards Suveillence Integrated Characterisation Surveillence Surveillence Surveillence Surveillence Surveillence Teamwork Optimised Testing Optimised Testing Optimised Testing Intelligent Well Suveillence Uncertainty Waterflood Optimisation

Champion West Field Real Time Optimisation Champion West Field Evolution Implementation Impact of Combustion Geomechanical Surfactant Properties Fractured Reservoirs Feasibility Gas blending Heterogeneity Gas Injection Feasibiliy SAG Feasibility Carbonate reservoir Nat. Fractured Reservoirs

Waterflood Management Well Intervention Well Intervention Well Intervention Well Intervention Wettability Modification Compostional Changes Modelling - Discrete Gradient Method Russian Applications Waxy Crudes CO2 Detection Compositional Correlations Downhole Fluid Analysis Hydrogen Sulphide Detection Insitu PVT Variations Methane Detection Production Chemistry Production Chemistry Surfactant Surfactant Properties Acid Treatments Core Testing Modelling - Acid Placement Modelling - Formation Damage Modelling - Invasion Damage Modelling - Naphthenate Formation Scale Analysis Scale Control Scale Management Inflow Performance Insitu Combustion Recovery Modelling - Fractured Carbonate Modelling - History Matching Productivity Improvement Steam Injection Steam Injection Fluid Description Perforation Methods Stimulation Fracture Diagnostics Fracture Stimulation Modelling - Fracture Performance Modelling - Probablistic Production Analysis Pressure Monitoring Reservoir Description Reservoir Description Reservoir Development UBD Reservoir Development Decision Making

Controlled composition Gas Shut-off Water Shut-off Water Shut-off Water/Gas Shut-off Fractured Carbonates Applied Gas Lift Optimisation Deepwater WFT IFT and Miscibility Gas Viscosity OBM Clean-up WFT Integrated Data Downhole Measurement Asphaltenes Heavy-oil IFT Case study Acid Treatment Diversion design Well Productivity Skin Effect

Formation Damage Assessment Horizontal wells Development Integrated Study Steam Injection Acid Treatment Fractured Reservoirs Geochemical Insitu PVT Variations Case Study Surveillence/Analysis Case study Multilayered Reservoirs Inflow Profiling 4D Pilot Klinkenberg-Corrected Permeability UBD China Southern North Sea Niger Delta Uncertainty Management

Decision Making Decision Making Inclusion of Flexibility Workflow Carbonate Transition Zone Downhole Fluid Analysis Downhole Fluid Analysis Formation Evaluation - Heterogeneity Magnetic Imaging Modelling - Heterogeneity Modelling - Near Wellbore Stress Modelling - Outcrop Naturally Fracture Detection Permeability Permeability Prediction Productivity Interpretation Reservoir Architecture Reservoir Architecture Reservoir Architecture Reservoir Architecture Reservoir Architecture SCAL Wettability Determination WFT Gas Reservoir Brunei Modelling - Integrated Asset Sour Reservoir Thin Oil Rim Thin Oil Rim 4D-Seismic Case Study Development Optimisation Development Optimisation Development Optimisation Development Optimisation Gas Lift Optimisation Modelling - Coupled Fracture/Reservoir Modelling - Experimental Design Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Rubust Otimisation Multiple Field Development Phased Development Pressure Management Pressure Management Process Process Produced Water Injection Produced Water Management Production Optimisation Production Optimisation

Development Optimisation Carbonate Reservoir Reservoir Characterisation Reservoir Characterisation Deepwater Deepwater Turbidite Channels Algorithm Carbonate After-Closure Analysis Representative scale From Pore Space Images UBD Fracture Fairways Fracture Fairways Integrated Well Data Integrated Well Data Integrated Well Data Case study NMR Interpretation Optimised Sampling Heterogeneity Chamion West Field Feasibility Draugen Field West Salym Field Deepwater Integrated Teamwork Process Mode Thin Oil Rim Surveillence Fractured Water Injection Steam Injection Karstification Multiple Field Development Development Optimisation Integrated Study Case Study Mutilayered Water Injection Waterflooding Gas Supply GTL Core Testing Automatic Process Control Mature Fields

Production Optimisation Workflow Real Time Reservoir Souring Deepwater Reservoir Souring Reservoir Souring Reservoir Souring Reservoir Souring Shell's Adjoint Simulation Method Simulation Shell's Adjoint Simulation Method Well Placement Optimisation Sour Reservoir South Oman Sour Reservoir Surveillence Draugen Field Surveillence Production Optimisation Thin Oil Rim Concurrent Oil/Gas Wells Waterflood Management Fractures Waterflood Management Well Placement Optimisation Waterflood Optimisation odelling - Adjoint Simulation Method Waterflood Optimisation Optimised Simulation 4D Seismic Intgrated Model Adjoint Based Simulation Assisted HM Adjoint Based Simulation Well Placement Optimisation Analogue Modelling History matching Assisted HM Singular Evolutive Interpolated Kalman Filter Assisted HM Stochastic Framework Convective Heat Transfer Laminar flow Coupled Fracture/Reservoir Model Induced Water Injection fractures Coupled Fracture/Reservoir Model Induced Water Injection fractures Coupled Well/Reservoir Model Feasibility Coupled Well/Reservoir Model Thins Oil Rim Dual Permeability Simulation Transfer Functions Experimental Design Method Review Fractional Flow Analysis Waterflood Gas Potential Gas-Condensate Gas-Oil-Ratio Prediction Gridding Background Grid Approach Gridding Heterogeneity Gridding Upscaling Gridding Upscaling Multiple Reservoirs Unified Fluid Description Naturally Fractured Reservoirs History Matching Naturally Fractured Reservoirs History Matching - Case Study Naturally Fractured Reservoirs Shape Factor Near Wellbore Stress Analytical Network modelling Deepwater Reservoir Non-isothermal Buckley-Leverett Including Tracers Probabilistic Production Forecasting Simplification Real Time Updating Ensemble based Application Reservoir Pressure Estimation Muskat Plot Results Interpretation Shared Earth Modelling Champion Feld Streamline Optimisation Method

Streamline Uncertainty Management Water-Cut Prediction Wellbore Flow Characterisation and Modelling Complex Reservoirs Mechanism Mechanism Mechanism Mechanism Mechanism Mechanisms Produced Water Injection Reservoir Connectivity SAGD Performance Sour Reservoir Waterflood Performance Blow-out Calculations Smarter Fields Digital Fields Gravel Packing Sour Gas Stimulation Waterflood Management 4D Seismic 4D Seismic By-passed Oil Detection CO2 Detection Complex Wells Fracture Diagnostics Fracture Diagnostics Production Allocation PTA/Production Logging Real-Time Monitoring Real-Time Monitoring Real-Time Monitoring Steamflood Monitoring Tidal Pressure Response Water Entry Detection Waterflood Monitoring Well Monitoring In-situ Conversion Process Oil Shale Acid Treatments Completion Optimisation Completion Optimisation Complex Wells Controlled injection Foam flow Fracture Design Fracture Diagnostics

Upscaling Multplie Scenarios Thermal Modelling Carbonate reservoir JG Field Dispersion Fluid Mixing Issues Rock Compaction Steam Injection Steam Injection Steam Injection Productivity Index Uncertainty Management Canada Case Study Pierce Field Change Management Horizontal wells Asia Pacific Deepwater - GOM Feasibility New Techniques Mature Fields Temperature Logging Production Profiling Temperature Data Temperature Transients Subsea Tieback Deepwater Giant Fields Production Impairment WFT Tiltmeters Aquifer Influx Horizontal wells Carbon/Oxygen Logs Brownfield Application Green Rivere Colorado Field Pilots Case Study Openhole Openhole Downhole Control Valves Reservoir Damage Prevention Prediction Fiber Assisted Clean-up

Fracture Diagnostics Gas Coning Control Heavy Oil-in-Water Emulsion Horizontal Well Inflow Performance Lab Testing - Stimulation Lab Testing - Stimulation Lab Testing - Stimulation Liquid Loading Liquid Loading Liquid Loading Perforation Methods Perforation Methods Perforation Methods Sand Control Sand Control Sand Control Sand Control Sand Control Sand Management Sand Production Stimulation Stimulation Analysis - Fractured Water Injector Analysis - Fractured Well Analysis - Horizontal Wells Connected Volume Estimation Connected Volume Estimation HP/HT HP/HT Mini-DST Production Monitoring

State of the Nation Modelling Gas shut-off Under Performance Horizontal wells Behaviour of CO2 and N2 Foams Modelling Modelling Mitigation Mitigation Prediction Limited Entry Optimisation Propellant assisted Associated with Hydraulic fracturing Challenging Conditions Deepwater Expandable Screen Risk Assessment Prediction Acid Treatment Horizontal wells PFO SRT PTA PTA Annular Pressure Buildup Behaviour Gas Condensate Deepwater Optmisation/Automation

Title Reducing CO2 emissions by making cheaper CO2 capture technologies available Reducing CO2 Emissions By Making Cheaper CO2 Capture Technologies Available Capillary Pressure and Wettability Behavior of CO2 Sequestration in Coal at Elevated Pressures Anomalous Diffusion Behavior of CO2 in the Macromolecular Network Structure of Coal and Its Signi Swelling of Coal in Response to CO2 Sequestration for ECBM and Its Effect on Fracture Permeabilit Differential Swelling and Permeability Change of Coal in Response to CO2 Injection for ECBM Simulations for CO2 Injection Projects With Compositional Simulator Injection of Supercritical CO2 into Deep Saline Carbonate Formations, Predictions from Geochemica CO2 and Flue Gas Coreflood Experiments for Enhanced Coalbed Methane Lithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Rese CO2 Geological Storage Field Development: Initial Experiences in an Emerging Industry Carbon Dioxide Capture and Geological Storage: Contributing to Climate Change Solutions The Second Stage Challenge for the PRODML Standards: Adaptive Production Optimization Production Data Standards: The PRODML Business Case and Evolution Evolution of Collaborative Work Environments - Are We Ready for It? Advanced Production Monitoring Integrated Fluid Characterization: Maximising the Value of Fluid Information From Exploration to Pro Production Surveillance and Optimization with Data Driven Models Continuous Well Production Flow Monitoring and Surveillance Implementing Real-Time Production Optimisation in Shell E&P in Europe—Changing the Way We Extensions to and Roll Out of Data Driven Production Surveillance and Optimization Data Driven Surveillance and Optimization Applying LEAN Principles to Achieve Breakthrough Performance Gains From Existing Assets The State of Optimum Value Testing—The Vision and the Reality Optimal Value Testing – Moving From Vision to Reality Moving from Vision to Reality - The State of Optimal Value Testing An Evolution From Smart Wells to Smart Fields Anomaly-Driven Engineering Empowered by a Central Surveillance Center Towards a Framework for Better Decision Making Under Subsurface Uncertainty Multiscale Regularization of Flooding Optimization for Smart-Field Management Smart Fields—Making the Most of our Assets Smart Fields�—Optimizing Existing Fields Smart Snake Wells in Champion West—Expected and Unexpected Benefits From Smart Completio Real-Time Optimization: Classification and Assessment The Snaking Wells in Champion West, Offshore Brunei. Best Practices for ERD Well Construction Changing the Look and Feel of Underbalanced Drilling Underbalanced Drilling In The Reservoir, An Integrated Technology Approach The Modeling Challenge of High Pressure Air Injection Polymer Flooding in Unconsolidated Sand Formations: Fracturing and Geomechanical Consideration Development of Surfactants for Chemical Flooding at Difficult Reservoir Conditions EOR Methods To Enhance Gas Oil Gravity Drainage Burning Reserves For Greater Recovery? Air Injection Potential In Australian Light Oil Reservoirs Gas Blending for Miscible Gasfloods in South Oman Foam Modeling in Heterogeneous Reservoirs Using Stochastic Bubble Population Approach An Integrated Workflow for Gas Injection EOR and a Successful Application to a Heterogeneous San A Dynamic Economic Indicator To Evaluate SAGD Performance First Full Field Steam Injection in a Fractured Carbonate at Qarn Alam, Oman Feasibility Study of WAG Injection in Naturally Fractured Reservoirs

Novel Waterflooding Strategy by Manipulation of Injection Brine Composition Effective Gas-Shutoff Treatments in a Fractured Carbonate Field in Oman Development and First Field Application of a Gel/Cement Water-Shutoff System Water-Shutoff Treatment in Wells With Single-String Multizone Completion Intervals (Brownfields) Shallow Penetration Particle-Gel System for Water and Gas Shut-Off Applications Toward Field-Scale Wettability Modification—The Limitations of Diffusive Transport Enhancement of Oil & Gas Production Using Integrated Network Analysis Development and Application of the Discrete Gradient Method for Non-smooth Non-convex Productio Applicability of Flow Assurance Solutions for Russian Oil & Gas Developments Flow-Assurance Aspects of Subsea Systems Design for Production of Waxy Crude Oils Quantification of Carbon Dioxide Using Downhole Wireline Formation Tester Measurements Reservoir Condition Measurements of Compositional Effects on Gas-Oil Interfacial Tension and Miscib A New Correlation for the Viscosity of Natural Gas Compositional Modeling of Oil-Based-Mud-Filtrate Cleanup During Wireline Formation Tester Sampli Low-Level Hydrogen Sulphide Detection Using Wireline Formation Tester Integration of Geochemical, Mud-Gas, and Downhole-Fluid Analyses for the Assessment of Composi Downhole Measurement of Methane Content and GOR in Formation Fluid Samples Development of Fourier Transform Ion Cyclotron Resonance Mass Spectrometry Protocol for the Analy Rheology of Heavy-Oil Emulsions Measurement of Surfactant-Induced Interfacial Interactions at Reservoir Conditions Phase Behaviour Methods for the Evaluation of Surfactants for Chemical Flooding at Higher Tempera A New Approach to Matrix Sandstone Acidizing Using a Single Step HF System: A Niger Delta Case Effect of Reservoir Mineralogy and Texture on Acid Response in Heterogeneous Sandstones Improved Acid Diversion Design Using a Placement Simulator Formation Damage and Well Productivity Simulation Quantification of Overbalance-Induced Invasive Damage and the Estimation of Equivalent-Skin Effec Thermodynamic Modelling of Naphthenate Formation and Related pH Change Experiments Analysis of Organic Field Deposits: New Types of Calcium Naphthenate Scale or the Effect of Chem Managing Formation-Damage Risk From Scale-Inhibitor Squeeze Treatments in Deepwater, Subsea Improvement of Scale Management Using Analytical and Statistical Tools Choked Flow in HVO Recovery: Injection and Production in Horizontal Wells A Thermal Recovery Method for Medium-Heavy Oil Reservoirs From Data Acquisition to Simulator: Fracture Modeling a Carbonate Heavy-Oil Reservoir (Lower Shu Realistic History Matching of Cyclic Steam Stimulation Performance of Several Groups of Multilatera Increasing Production in a Brownfield With Heavy Crude and Fine Problems by Application of New H Heavy-Oil Recovery By Steam Injection In Fractured Reservoirs Making Sense of the Geomechanical Impact on the Heavy-Oil Extraction Process at Peace River Bas Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Cen Optimisation of Perforation Techniques for Deep, HP Stringer Wells Located in the South of Oman Stimulation of High-Temperature Sandstone Formations From West Africa With Chelating Agent-Base Field Trial Design and Analyses of Production Data From a Tight Gas Reservoir: Detailed Productio Application of Massive Hydraulic Fracturing in C Field Middle Gharif Formation—Case Study Using Reservoir Modeling To Evaluate Stimulation Effectiveness in Multilayered “Tight Gas Reserv Improved Production Profiling Using Thermal Balance and Statistical Modeling in the Pinedale Antic 4D Pressure Pilot To Steer Well Spacing in Tight Gas Improved Permeability Prediction Relations for Low Permeability Sands One Company's First Exploration UBD Well for Characterizing Low Permeability Reservoirs Integrated Development of Changbei Tight Gas Project Underbalanced Drilling and Completion of Sand-Prone Tight Gas Reservoirs in Southern North Sea Developing Marginal Fields In The Niger Delta: Recovery & Economics Can Be Better Than Currentl Improving Lifecycle Project Delivery Through Better Decision-Making Under Uncertainty

The Use of Integrated Decision Making To Embed Sustainable Development Effective Engineering Decision Matrix Lead to 2-fold Improvement in Gas Well’s Productivity Integrated Method for Designing Valuable Flexibility in Oil Development Projects Improving the Quality and Efficiency of Subsurface Workflows Improved Characterization and Modeling of Capillary Transition Zones in Carbonate Reservoirs Downhole Fluid Analysis and Fluid-Comparison Algorithm as Aid to Reservoir Characterization New Downhole-Fluid-Analysis Tool for Improved Reservoir Characterization Applications of NMR Logs and Borehole Images to the Evaluation of Laminated Deepwater Reservoi Recent CSEM Learnings in Deepwater Borneo Simplified Modeling of Turbidite Channel Reservoirs Estimation of Near-Wellbore Alteration and Formation Stress Parameters From Borehole Sonic Data Simulating the Outcrop: Surface To Subsurface Integration of a Carbonate Reservoir, Khuff Formati After-Closure Analysis To Identify Naturally Fractured Reservoirs Finding the Continuum Scale in Highly Heterogeneous Rocks: Example of a Large Touching Vug Car Permeability Predictions Based on Two-Dimensional Pore Space Images Use of a New Rate-Integral Productivity Index in Interpretation of Underbalanced Drilling Data for Re Estimating Percentage of Fracture Fairways Detectible by Seismic Data-Two Case Studies From Om Devising Knowledge-Based Decision Tree for Detection of Fracture Corridors From Dynamic Data in Combining Continuous Fluid Typing, Wireline Formation Testers, and Geochemical Measurements for Improved Interpretation of Reservoir Architecture and Fluid Contacts Through the Integration of D Advanced Mud Gas Logging in Combination With Wireline Formation Testing and Geochemical Fingerp Relative Permeability Measurements and Analyses for a Cluster of Fields in South Oman Wettability-Index Determination by Nuclear Magnetic Resonance Enhancing Formation Testing and Sampling Operations Through the Use of Log-Derived High-Resolu Bubut—A Near Field Exploration Success, Inboard Brunei Application of Critical Technologies Enabling Low-Cost Development of Thin-Bedded Heterogeneous Development of Highly Contaminated Gas and Oil Fields Breakthrough CO2/H2S Separation Technol Appraisal and Development of Thin Oil Rims Using the Smart Field Approach, An Example from Cha First-Pass Screening of Reservoirs with Large Gas Caps for Oil Rim Development Improved Reservoir Management Through Integration of 4D-Seismic Interpretation, Draugen Field, Reservoir Management of West Salym Oil Field Development of World-Class Oil Production and Water Injection Rate and High Ultimate-Recovery W Key Elements of Successful Well and Reservoir Management in the Bonga Field, Deepwater Nigeria Changing the Operation of Oil and Gas Fields From “Harvest to “Process Mode Gannet A: Critical New Reservoir Insight Through Seamless Cross-Discipline Integration An Integrated Approach to Field Surveillance Improves Efficiency in Gas Lift Optimization in Bokor Fi Waterflooding Under Dynamic Induced Fractures: Reservoir Management and Optimization of Fractu Peace River Carmon Creek Project—Optimization of Cyclic Steam Stimulation Through Experiment Integrated Modeling of Karstification of a Central Luconia Field, Sarawak The Integrated Use of New Technology in the Development of the Sakhalin II Project Robust Waterflooding Optimization of Multiple Geological Scenarios An Integrated Approach To Efficiently Unlock the Resource Potential in a Large Cluster of Fields Using Phased Development as Reservoir Management Technique To Improve Efficiency and Reduce Rapid Pressure Support for Champion SE Reservoirs by Multilayer Fractured Water Injection Reservoir Pressure Management Using Waterflooding: A Case Study A Global Gas Distribution Model with Transport Constraints: Methodology and Some Scenarios Pearl GTL - Assuring Success from the Outset Establishing Water Injection Dynamics by Leading-Edge Coreflood Testing Produced Water Management: Is it a Future Legacy or a Business Opportunity for Field Developmen Closing the Loop for Improved Oil and Gas Production Management Increasing Oil Production in a Mature Field by Rigless Intervention–A Multiwell Case Study

Shell Experiences Using Lagosa to Improve Production Operations and Gas Marketing Performance Closed Loop Reservoir Management Use of Nitrate To Mitigate Reservoir Souring in Bonga Deepwater Development, Offshore Nigeria One Year Experience With The Injection of Nitrate To Control Souring in Bonga Deepwater Developm Nitrate-Based Souring Mitigation of Produced Water—Side Effects and Challenges From the Drauge Challenges in Highly Sour Gas Environment Containing Elemental Sulphur Understanding of Oilfield Souring and Effective Monitoring: Two Cases Study Impact of Mutual Solvent Preflush on Scale Squeeze Treatments: Extended Squeeze Lifetime and I Automatic Well Placement Optimization in a Channelized Turbidite Reservoir Using Adjoint Based Sens Achieving the Vision in the Harweel Cluster, South Oman Development of Highly Contaminated Gas and Oil Fields, Breakthrough CO2/H2S Separation Techno Understanding a Teenager: Surveillance of the Draugen Field The Value of Surveillance and Advanced Logging Applications for Brownfield Optimization Concurrent Oil & Gas Development Wells: A Smart Well Solution to Thin Oil Rim Presence in Gas Re Application of Smart, Fractured Water Injection Technology in the Piltun-Astokhskoye Field, Sakhalin The Omar Field (N.E. Syria) is Overcoming Its Mid-Life Crisis Optimal Waterflood Design Using the Adjoint Method Optimization of Smart Wells in the St. Joseph Field Seismically Based Integrated Reservoir Modelling, Lunskoye Field, Offshore Sakhalin, Russian Fede Reservoir Simulation Model Updates via Automatic History Matching With Integration of Seismic I Adjoint-Based Well-Placement Optimization Under Production Constraints History-Matching Considerations of an Analogue Reservoir Model (ARM) A Singular Evolutive Interpolated Kalman Filter for Rapid Uncertainty Quantification Stochastic History Matching of a Deepwater Turbidite Reservoir Convective Heat Transfer for Laminar, Steady-State Flow of Bingham and Power Law Fluids between V Induced Fracturing in Reservoir Simulations: Application of a New Coupled Simulator to a Waterfloo Dynamic Induced Fractures in Waterflooding and EOR An Investigation Into the Need of a Dynamic Coupled Well-Reservoir Simulator Using a Dynamic Coupled Well-Reservoir Simulator to Optimize Production of a Horizontal Well in a Verification and Proper Use of Water-Oil Transfer Function for Dual-Porosity and Dual-Permeability Modelling Subsurface Uncertainties with Experimental Design: Some Arguments of Non-Conformists Recapturing the Value of Fractional Flow Analysis in a Modern Day Water Flood A Semianalytical Method To Predict Well Deliverability in Gas-Condensate Reservoirs A Systematic Methodology for Extrapolating Gas-Oil Ratio During Declining Oil Production Unstructured Coarse Grid Generation for Reservoir Flow Simulation Using Background Grid Approac A Quantitative and Qualitative Comparison of Coarse Grid Generation Techniques for Numerical Sim Reservoir Flow Simulation Using Combined Vorticity-Based Gridding and Multi-Scale Upscaling Vorticity-Based PEBI Grids for Improved Upscaling of Two Phase Flow Dynamic Modeling of Multiple Regionally Extensive Reservoirs Using a Unified Fluid Description History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability P Practical Flow-Simulation Method for a Naturally Fractured Reservoir: A Field Study Thermal and Hydraulic Matrix-Fracture Interaction in Dual-Permeability Simulation Wellbore stress change due to drawdown and depletion: An analytical model and its application Predicting Deepwater Well Behavior Analytical Solution of Nonisothermal Buckley-Leverett Flow Including Tracers Smart Model Simplifications to Speed Up Uncertainty Analysis of Integrated Production System Mod Efficient and Robust Reservoir Model Updating Using Ensemble Kalman Filter With Sensitivity-Based A New Method for Estimating Average Reservoir Pressure: The Muskat Plot Revisited Understanding Dynamic Simulation Results Depositional Modelling of Champion Field, Brunei: Assessing the Impact of Reservoir Architecture Streamline-Based History Matching and Uncertainty--Markov-Chain Monte Carlo Study of an Offshore

Upscaling and 3D Streamline Screening of Several Multimillion-Cell Earth Models for Flow Simulatio Identifying and Filling Western Europe’s Natural-Gas Storage Needs for the Next Decade A Didactic Analysis of Water Cut Trend During Exponential Oil-Decline Application of a New Fully-Coupled Thermal Multiphase Wellbore Flow Model Improved Characterisation and Modelling of Carbonate Reservoirs for Predicting Waterflood Perfor Reservoir Compartmentalisation in the JG Field – Western Desert Egypt Investigation of Field Scale Dispersion Flow Reversal and Mixing Impact of Pore Volume Compressibility on Recovery from Depletion Drive & Miscible Gas Injection The Physics of Steam Injection in Fractured Carbonate Reservoirs: Engineering Development Option Experimental Investigation of Steam Injection in Light Oil Fractured Carbonates Steam Injection into Fractured Carbonates – The Physical Recovery Mechanisms Analyzed and U Dynamic Modelling of Produced Water Reinjection in Depleted Naturally Fractured Gas Fields Using Production Data to Mitigate Reservoir Connectivity Uncertainty The Field Performance of SAGD Projects in Canada Life Cycle of a Depletion Drive and Sour Gas Injection Development: An Example From an A4C Res Integrated Data Analysis and Dynamic Fracture Modelling Key to Understand Complex Waterflood: Ca Validation of Blowout Rate Calculations for Subsea Wells Making Our Mature Fields Smarter—An Industrywide Position Paper From the 2005 SPE Forum Back to the Future—A Retrospective on 40 Years of Digital Oil Field Experience Advances in Horizontal Openhole Gravel Packing Contaminated Gas—Past, Present and Future Stimulation in Asia Pacific Region - Challenges and Opportunities Challenges for Waterflooding in a Deepwater Environment Time-Lapse Feasibility Studies of Two Fields in the Niger Delta New 4D Seismic Monitoring Techniques As Enablers For Effective Smart Fields Identification of Bypassed Oil for Development In Mature Water-Drive Reservoirs Thermal Signature of Free-Phase CO2 in Porous Rocks: Detectability of CO2 by Temperature Loggi Production Surveillance and Optimisation for Multizone Smart Wells With Data Driven Models Optic Fiber Distributed Temperature for Fracture Stimulation Diagnostics and Well Performance Eval Imaging Fractures Using Temperature Transients From Perturbation Analysis--A Novel Surveillance Te Combining Testing-by-Difference, Geochemical Fingerprinting, and Data-Driven Models: An Integrated Case History Review of the Application of Pressure Transient Testing and Production Logging in Mon Application of Real Time Surveillance and Optimisation Tools on a Large Asset Acoustic Surveillance of Production Impairment With Real-Time Completion Monitoring The Power of Real-Time Monitoring and Interpretation in Wireline Formation Testing—Case Studies Mapping Reservoir Volume Changes During Cyclic Steam Stimulation Using Tiltmeter-Based Surfa Tidal Pressure Response and Surveillance of Water Encroachment A Reduced Risk Alternative for Water Entry Detection in High Water Producing Horizontal Wells Waterflood Surveillance in the Mars Field Deepwater GOM: Mississippi Canyon Block 807 Advanced Logging Applications for Brownfield Optimization Reservoir Simulation Study of An In-Situ Conversion Pilot of Green-River Oil Shale Oil Shale ICP – Colorado Field Pilots A High-Success-Rate Acid Stimulation Campaign—A Case History Openhole Completion Options: The Niger Delta Experience Mechanistic Understanding of Rock/Phosphonate Interactions and the Effect of Metal Ions on Inhibito Optimization of Commingled Production Using Infinitely Variable Inflow Control Valves Online Water-Injection Optimization and Prevention of Reservoir Damage Hydraulic Predictions for Polymer-Thickened Foam Flow in Horizontal and Directional Wells An Engineered Fiber for the Fracturing of Unconsolidated Sand in Highly Deviated Wells in the Tali Fi New Results Improve Fracture Cleanup Characterization and Damage Mitigation

New Findings in Fracture Cleanup Change Common Industry Perceptions Gas Coning Control for Smart Wells Using a Dynamic Coupled Well-Reservoir Simulator Innovative Gas Shutoff Method Using Heavy Oil-in-Water Emulsion Analyzing Underperformance of Tortuous Horizontal Wells: Validation With Field Data Cost-Effective Life-Cycle Profile Control Completion System for Horizontal and Multilateral Wells New Insights into Application of Foam for Acid Diversion Modeling and CT-Scan Study of the Effect of Core Heterogeneity on Foam Flow for Acid Diversion Modeling and CT-Scan Study of Foams for Acid Diversion On the Flow Performance of Velocity Strings To Unload Wet Gas Wells A Novel Foamer for Deliquification of Condensate-Loaded Wells Prediction Onset and Dynamic Behaviour of Liquid Loading Gas Wells Limited Entry Perforations in HVO Recovery: Injection and Production in Horizontal Wells Optimized Perforation—From Black Art to Engineering Software Tool Propellant-Assisted Perforating—An Alternative Stimulation Solution in Heavily Karstified Carbonate Innovative Use of Expandable Sand Screens Combined With Propped Hydraulic Fracturing Technology Design and Implementation of a Sand-Control Completion for a Troublesome Shallow Laminated G Screen Development to Withstand 4,000-psi Overbalance, Subhydrostatic Completion in Deepwater Sandface Completion for a Shallow Laminated Gas Pay With High Fines Content Sand Quantification: The Impact on Sandface Completion Selection and Design, Facilities Design an Applying Sand Management Process on the Lunskoye High Gas-Rate Platform Using Quantitative R Prediction of Sand Production Rate in Oil and Gas Reservoirs: Importance of Bean-Up Guidelines A New Technical Standard Procedure To Measure Stimulation and Gravel-Pack Fluid Leakoff Under S Optimizing Diversion and Pumping Rate to Effectively Stimulate Long Horizontal Carbonate Gas Well Application of New Fall-Off Test Interpretation Methodology to Fractured Water Injection Wells Offsh New Analysis of Step-Rate Injection Tests for Improved Fracture Stimulation Design Horizontal Well" Pressure Transient Analysis for Gulf of Mexico Reservoirs (Adapting the Slant Well Use of Advanced Pressure Transient Analysis Techniques To Improve Drainage Area Calculations and Magnetic Resonance in Chalk Horizontal Well Logged With LWD Transient Behavior of Annular Pressure Buildup in HP/HT Wells HP/HT Gas-Condensate Well Testing for Shell's Onyx SW Prospect Mini-DST Applications for Shell Deepwater Malaysia Well-Test Optimization and Automation

Author

Abstract

Theo Klaver, Shell Global Solutions International B.V. Abstract The Royal Dutch Shell Group (Shell) was Theo Klaver, Shell Global Solutions International BV Abstract The Royal Dutch Shell Group (Shell)[1] w Willem-Jan Plug, SPE, Horizon Energy Partners B.V., Saikat Mazumder, SPE, Summary Enhanced coalbed-methane (ECBM) re Saikat Mazumder, Shell Exploration and Production, and Johannes Bruining,Abstract This paper gives an analysis of the Thom Saikat Mazumder, SPE, Amit Karnik, SPE, and Karl Heinz Wolf, SPE, Delft Summary The “swelling of coal by a penetran Saikat Mazumder, Shell International Exploration and Production, Karl HeinzAbstract The matrix volume of coal swells when C S. Hurter, SPE, D. Labregere, and J. Berge, Schlumberger Carbon ServicesAbstract The need for CO2 emissions reduction a C. Taberner, G. Zhang, and L. Cartwright, Shell International Exploration a Abstract Modeling of supercritical CO2 injection in Saikat Mazumder, Shell International Exploration and Production; Karl HeinzAbstract Laboratory core flooding experiments wit B. Norden and A. F�rster, GFZ German Research Centre for Geosciences, Abstract The storage of carbon dioxide (CO2) in s N.J. Jenvey, SPE, R.S. Moen, N. Muller, Shell International Exploration and Abstract Global climate change induced by the rel H. Kheshgi, ExxonMobil; F. Cappelen, Statoil; A. Lee, Chevron; S. Crooksh Abstract Concern about global climate change a Ben Weltevrede, Shell International E&P; Alan Doniger, Energistics; Laure Abstract PRODuction xML (PRODML™) was sta Dave Shipley, Chevron; Ben Weltevrede, Shell International E&P B.V.; Ala Abstract PRODML™ is a set of production data Kent Gryskiewicz, Science Applications International Corporation, and RonaAbstract When Captain Kirk from the “USS E Martijn Hooimeijer and Mohamad Azmi, Shell Global Solutions Abstract An effective and comprehensive integrate Daniel McKinney, Ed Clarke, Hani Elshahawi, Matthew Flannery, Mohamed Ha Abstract Fluid characterisation is critically importan Keat-Choon Goh, Charlie E. Moncur (Shell Global Solutions International Abstract In conventional practice individual well o H. Poulisse, Shell Intl. E&P B.V.; P. van Overschee and J. Briers, IPCOS N.VAbstract In E&P from asset managers to front en Carl Gerrard and Ian C. Taylor, Shell E&P in Europe; Keat-Choon Goh, ShelAbstract In recent years advances in computing a C.E. Moncur, S. Jakeman, L. Berendschot, R. Cramer, J. Briers, F. StroobanAbstract Oil and gas production from a cluster of Ron Cramer, K.-C. Goh, Mike Dolan, and Charlie Moncur, Shell Global SolutAbstract Traditionally individual well oil gas and w Walrick E.J.J. van Zandvoord, Oddbjorn Skilbrei, Wong Sim-Siong, and Je Abstract One of the small assets in Shell Malaysi Hani Elshahawi, Robert H. Hite, and Melton P. Hows, Shell International E&PAbstract Since the turn of the century Shell has h Hani Elshahawi, SPE, Robert H. Hite, SPE, and Melton P. Hows, SPE, Shell Abstract Over the past few years there has been Hani Elshahawi, SPE, Robert H. Hite, SPE, Melton P. Hows, SPE, Shell InteAbstract Over the past few years there has been E. van der Steen, SPE, Brunei Shell Petroleum Abstract This paper discusses the “evolution J.M. Brutz, SPE, Shell Exploration and Production Company Abstract A central surveillance center designed to R.D. Peterson, S. Yawanarajah, D. Neisch, and E. Tabanou, Schlumberger, Abstract The Smart Fields collaboration between M. Lien, U. of Bergen; D.R. Brouwer, SPE, Shell Intl. E&P; T. Mannseth, CI Abstract Smart fields can provide enhanced oil re Smart Fields—Making the Most of our Assets Abstract Intelligent wells and Smart Fields concep Frans G. van den Berg, Shell Intl. E&P B.V. Abstract In a Smart Field the asset staff has the t W. Obendrauf, K. Schrader, N. Al-Farsi, and A. White, SPE, Brunei Shell P Abstract Snake wells are laterally weaving (“s S. Mochizuki, SPE, ExxonMobil; L.A. Saputelli, SPE, Halliburton; C.S. Kab Summary The Real-Time Optimization (RTO) Tec L. Bacarreza, SPE, C. Hornabrook, Chong Chuan Khoo, Harald Nev�y, and Abstract The Champion West field was discovered John Ramalho, Shell E&P Intl. Ltd. Abstract Ever since Shell introduced underbalance John Ramalho, SPE, Shell Intl. E&P Abstract Shell is a major player in the Global dep A.H. de Zwart, D.W. van Batenburg, C.P.A. Blom, A. Tsolakidis, C.A. Glandt, Abstract High Pressure Air Injection (HPAI) is a po Mohamad Khodaverdian, SPE, Tibi Sorop, SPE, Sophie Postif, SPE, Paul Abstract A study was carried out to determine the Julian R. Barnes, Johan P. Smit, and Jasper R. Smit, Shell Global Solutio Abstract The production and properties of two fam P.M. Boerrigter and M.L. Verlaan, Shell International E&P, Rijswijk, The Ne Abstract Conventional displacement methods suc B.L. Hughes and H.K. Sarma, SPE, U. of Adelaide Abstract Air injection is an Enhanced Oil Recover G. Deinum, Petroleum Development Oman, and B. Dindoruk and M. O'Dell, Abstract Sh How to ensure that miscibility of oil and g F. Farshbaf Zinati, R. Farajzadeh, and P.L.J. Zitha, Department of Geotechn Abstract Foam is an attractive option in EOR for i Nobuo Nishikiori, SPE, and Keiichiro Sugai, SPE, Norske AEDC AS; Clas Abstract This study describes an improved engine H. Shin, Shell Canada Ltd., and M. Polikar, U. of Alberta Abstract A new economic indicator called simple R. Penney, S. Baqi Al Lawati, R. Hinai, O. van Ravesteijn, K. Rawnsley, P Abstract Gas Oil Gravity Drainage (GOGD) of the J.C. Heeremans, Delft U. of Technology; T.E.H. Esmaiel, Delft U. of TechnoloAbstract The fundamental aspects of Water Alter

D.J. Ligthelm, SPE, J. Gronsveld, J.P. Hofman, N.J. Brussee, F. Marcelis, anAbstract As brine composition profoundly influence E. Ali, F.E. Bergren, and P. DeMestre, Petroleum Development Oman; E. Biez Summary A giant fractured carbonate field in nor Jip van Eijden and Fred Arkesteijn, Shell Intl. E&P, B.V.; Ihab Akil and Jac Summary Water production in northeast Syria ha Victor E. Uadiale, Schlumberger; Otaru G.Oghie, Shell E&P, U.K.; and Vinc Abstract Due to the stacked nature of reservoirs in Dwyann Dalrymple, Larry Eoff, and Julio Vasquez, Halliburton, and�Jip vaAbstract This paper presents the development of W.M. Stoll, SPE, J.P. Hofman, D.J. Ligthelm, SPE, M.J. Faber, SPE, P.J. va Summary Densely-fractured oil-wet carbonate fie KJ Li, Nort Thijssen, and Ilse Mittendorff, Shell Global Solutions InternationaAbstract For a mature oil field gas and liquid comp Thomas L. Mason, Shell International Exploration and Production; Adil BagirAbstract Production optimization such as optimal g L. Dykhno and A. Mehta, Shell Global Solutions (US) Inc., and MoiseyenkovAbstract Over the past decade flow assurance ap H. Alboudwarej, SPE, Schlumberger; Z. Huo, SPE, Shell Global Solutions (UAbstract Development of deep offshore fields is c N. M�ller, Schlumberger Oilfield Services; H. Elshahawi, Shell Intl. E&P Abstract Carbon dioxide (CO2) occurrence in hyd Daryl S. Sequeira, Subhash C. Ayirala, and Dandina N. Rao, Louisiana StateAbstract Minimum miscibility pressure (MMP) is a P.U. Ohirhian, Department of Petroleum Engineering, U. of Benin, Benin Cit Abstract A new correlation for calculating the visc Faruk O. Alpak, SPE, Hani Elshahawi, SPE, and Mohamed Hashem, SPE, Shell Summary Mi Filtrate Cleanup During Wireline Forma Mohamed Hashem and Hani Elshahaw, Shell; Ryan Parasram, Peter Weinhe Abstract Many development projects will rely on p Hani Elshahawi, SPE, Shell; Melton Hows, SPE, Chengli Dong, SPE, Lali Abstract Identifying compartmentalization quantify Chengli Dong, SPE, Peter S. Hegeman, SPE, and Andrew Carnegie, SPE, SSummary Formation fluid sampling early in the lif W. Schrader and S.K. Panda, Max-Planck-Institute of Coal Research; J.T. AnAbstract One of the most important issues in oilfie Hussein Alboudwarej, Moin Muhammad, and Ardi Shahraki, Schlumberger; She Summary Water is invariably produced with crude Wei Xu, SPE, Subhash C. Ayirala, SPE, and Dandina N. Rao, SPE, LouisianSummary The effect of surface-active chemicals Julian R. Barnes, Johan P. Smit, and Jasper R. Smit, Shell Global Solutio Abstract Accurate laboratory screening of surfacta C. Uchendu, SPE, BJ Services; L. Nwoke, SPE, and O. Akinlade, SPE, SPDAbstract The use of unique or modified HF acid s L.N. Morgenthaler, Shell E&P Co.; D. Zhu, J. Mou, and A.D. Hill, Texas A&M Summary A series of coreflood experiments with Gerard Glasbergen, Halliburton; Marten Buijse, Shell Abstract In matrix-acidizing long intervals diversio Arild Lohne, SPE, IRIS; Liqun Han, SPE, and Claas van der Zwaag, SPE, S Abstract In this paper we describe a simulation mo John Ramalho, Shell E&P International Limited; Zhan Wu, Ravi N. Vaidya, Summary An important premise of underbalanced Murtala A. Mohammed and K.S. Sorbie, Heriot-Watt University, and A.G. Shep Abstract The prediction and prevention of both sod A.G. Shepherd, SPE, G. Thomson, R. Westacott, and K.S. Sorbie, SPE, Heri Abstract Organic field deposits from distinct geog Philip Bogaert, Marcos C. Berredo, Celso Toschi, and Bill Bryson, Shell Bra Summary This paper describes field experience a Michael Scheck and Gill Ross, Shell U.K. Limited Abstract Scale formation in the near-wellbore area A. Burtsev, B. Kuvshinov, E. de Rouffignac, and A.M. Mollinger, Shell Intl. E Abstract The problem of multiphase flows in chok A.H. de Zwart, P. Bakker and C.A. Glandt, Shell International Exploration Abstract The primary recovery of a medium-heavy Georg M.D. Warrlich, SPE, Pascal D. Richard, SPE, Timothy E. Johnson, P Abstract A dedicated appraisal campaign and mod Paul Frantisek Koci and Junaid Ghulam Mohiddin, Shell Intl. E&P Inc. Abstract With 8 billion barrels of bitumen in place Folorunso Afolabi, SPE, Austa Opusunju, SPE, and Jaspers Henri, SPE, Abstract Increasing well production without compr A.P.G. van Heel, Shell International B.V.; J.J. van Dorp, Shell Oman; and P.MAbstract Using analytical results and thermal rese Peter R. McGillivray and Simon Brissenden, Shell Canada Ltd., and StephenAbstract The steam injection rates in the CSS ope P.D. Ting, SPE, and B. Dindoruk, SPE, Shell International E&P Inc., and J. Abstract Fluid properties descriptions are required M.S. Laws, Shell Abu Dhabi BV; A.M.N. Al-Riyami and H.F. Soek, PetroleumAbstract The intra-salt carbonate stringers represe S. Ali, SPE, E. Ermel, SPE, and J. Clarke, SPE, Chevron; M.J. Fuller, SPE Summary Fluids based on chelating agents have M.C. Vincent, SPE, CARBO Ceramics Inc.; Paul Huckabee, SPE, Shell E&PAbstract Field trials of new methodologies produ K. Maamari, S. Hajri, and J. Clark, Petroleum Development of Oman, and J Abstract Massive Hydraulic fracturing technique is S.K. Schubarth, SPE, Schubarth Inc.; J.P. Spivey, SPE, Phoenix Reservoir Abstract Low permeability or “tight gas rese G. Donovan, P.E., SPE, D. Dria, SPE, G. Ugueto, SPE, Shell E&P Co., A. GyAbstract The Pinedale anticline is located in the G E. Quint, M. Singh, P. Huckabee, D. Brown, C.B. Brake, J. Bickley, and B. Abstract Obtaining reliable and accurate formatio F.A. Florence, Texas A&M U.; J.A. Rushing, Anadarko Petroleum Corp.; K. Abstract This work addresses the problem of esti C.K. Woodrow, Shell E&P International Ltd.; D. Elliott, Shell E&P; R. Pickl Abstract This paper describes the use of an unde Guilin Luan, Lin Li, Gary Nettleship, Luc Van Son, and Taco Hoekstra, S Abstract Changbei is a tight onshore gas field loca C.A.M. Veeken, J.F.G. van Velzen, J. van den Beukel, H.M. Lee, R.G. Hakv Abstract This paper describes the application of u Anthony O. Uwaga, SPE, Shell Petroleum Development Company Nigeria LAbstract The main objective of the Marginal Field Shareen Yawanarajah, Jevon Williams, Ken Carrell, and Tom Webb, Shell, Abstract The total value realized from an asset de

M. Kuijper, M. Stephenson, and M. Howard, Shell E&P Abstract The necessity of sustainable developme Linus A. Nwoke, SPE, O. Goke Akinrinmade, SPE, Theophilus P. Ekiyor-Kat Abstract A gas well completed across 60ft interval Abisoye Babajide, SPE, Shell Oil Company, and Richard de Neufville and MiSummary This paper presents an integrated meth R.D. Peterson, S. Yawanarajah, and D. Neisch, Schlumberger, and S. JamesAbstract The authors will show how a unique com S.K. Masalmeh, Shell Abu Dhabi, and I. Abu Shiekah and X.D. Jing, Shell InSummary An oil/water capillary transition zone oft Lalitha Venkataramanan, SPE, Schlumberger; Hani Elshahawi, SPE, DanielSummary In recent years formation-sampling an C. Dong, SPE, and M. O'Keefe, SPE, Schlumberger; H. Elshahawi, SPE, and Summary Downhole fluid analysis (DFA) has eme Michel Claverie, Steve Hansen, Saifon Daungkaew, and Zane Prickett, Schl Abstract Deepwater turbidite reservoirs are comp M. Choo, Shell Exploration and Production Libya GmbH; C. Young, C.T. LingAbstract Controlled Source Electromagnetic (CSE Faruk O. Alpak, SPE, Mark D. Barton, Frans F. van der Vlugt, SPE, Carlos PiAbstract Effective properties can represent fine-sc Bikash Sinha, SPE, Tom Bratton, SPE, Jesse Cryer, Steve Nieting, Schlum Summary Highly depleted reservoirs exhibit sharp Gert-Jan Reijnders, Nasser Al-Mohannadi, Michael P�ppelreiter, Sharon FAbstract Careful gathering and analysis of outcrop Simon Chipperfield, Shell Intl. E&P Inc. Summary After-closure analysis (ACA) in homoge Narayan Nair, SPE, Steven L. Bryant, SPE, and James W. Jennings*, SPE, T Abstract Many of the world's oil fields and aquifers Mathieu Jurgawczynski and Peter A. Lock, Imperial College; X.D. Jing, SP Abstract A model is developed that allows accura P.V. Suryanarayana, Kennedy, and R.N. Vaidya, Blade Energy Partners, andAbstract J The prospect of dynamic reservoir charac Sait Ismail Ozkaya, Baker Atlas GeoScience; Pascal Richard, Petroleum D Abstract This paper discusses the detection of flui S.I. Ozkaya, Baker Atlas; S. Gordon, A. McFarlane, S. Siyabi, S.M. Al-Bus Abstract The subject of this paper is identification 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 Daniel McKinney, Matthew Flannery, and Hani Elshahawi, Shell InternationaAbstract Understanding reservoir architecture is o Mohammed Al-Gharbi, SPE, Petroleum Development Oman, Xudong Jing, SP Abstract During a large water flood study on a clus Wim Looyestijn, SPE, and Jan Hofman, Shell Intl. E&P Summary Knowing the wetting condition of a rese H. Elshahawi, Shell Intl. E&P Inc.; E. Donaghy and C. Guillory, Shell Oil C Abstract WBased Lithofacies Mapping Zulkifli Hj Ahmad, Erma Suryani Hassan, Krishnan Raghavan, Ian Donaldso Abstract Brunei Shell Petroleum (BSP) recently d L. Alessio, C. Howells, J. Chu, S.A. Abbas, B. Wade, and S. Ball, Carigali S Abstract CS Mutiara Petroleum is a Petronas Car Theo Klaver, Shell Global Solutions International B.V. Abstract Description Shell Global Solutions Intern Peter Bakker, Lee Watts, Ravil Salakhetdinov, Yee-Yung Liew, and Brigitte Abstract The economic development of thin oil rim Olugbenga Olamigoke, SPE, and Anthony Peacock, SPE, Shell Petroleum Abstract Many gas reservoirs critical to providing P.L. Mikkelsen, SPE, Consultant; K. Guderian, SPE, Norske Shell; and G. duSummary 4D-seismic interpretation plays a key ro Dmitry Svirsky, Ad Hagelaars, Joost Zegwaard and Howard Mackay, Salym Abstract The West Salym oil field in West Siberia Solomon O. Inikori, SPE, and Bert Coxe, Shell E&P Technology, and Ebene Summary Bo Bonga Field, Offshore Nigeria S. Sathyamoorthy, O. Olatunbosun, D. Sabatini, U. Orekyeh, and E. OlaniyaAbstract Production from the deepwater Bonga tu Ron Cramer, Shell Global Solutions, and George Joel Rodger, P.E., Weathe Abstract In the O&G industry the nature of well an Joanne de Jonge and Jakko van Waarde, Shell UK Abstract The thin oil rim of the Gannet-A turbidite G. Kartoatmodjo, R. Strasser, and F. Caretta, SPE, Schlumberger; M. Jadid Abstract Proper fieldwide production surveillance P.J. van den Hoek, R. Al-Masfry, and D. Zwarts, Shell International Explorati Abstract It is well established within the Industry t Paul Frantisek Koci, SPE, and Junaid Ghulam Mohiddin, SPE, Shell Interna Abstract Peace River Carmon Creek is a 100% Sh M. Kosters, P.F. Hague, R.A. Hofmann, and B.L. Hughes, Sarawak Shell Be Abstract It is well established that some of the ca Mike Gunningham and Chris Varley, Sakhalin Energy Investment Company, A a bstract The Sakhalin II Project the world’s l G.M. van Essen, SPE, M.J. Zandvliet, SPE, P.M.J. Van den Hof, and O.H. Bos Summary Dynamic optimization of waterflooding Martin A. Kraaijveld, Jon B. Hognestad, Ajay Samantray, Pius Udeh, Walee Abstract An integrated study on a cluster of 23 fie Abu Ikponmwosa, Reservoir Engineer, Shell Petroleum Development CompaAbstract The search for optimal development of a Gerald Sommerauer, SPE, and Christoph Zerbst, SPE, Brunei Shell Petrol Summary The Champion field is a large oil field o Anish Phade, SPE, Reliance E&P; and Yash Gupta, SPE, Shell Technology In Abstract As a rule the reservoir pressure depletio J.T. van Berkel and L.P. Roodhart, SPE, Shell International Exploration and Abstract Natural gas resources are unevenly distri Andy Brown, Qatar Shell GTL Limited When completed Pearl GTL will be the world’ L. Costier*, P.J. van den Hoek, C. Davidson, Mei Ding, J.T.M. vanden Berg, Abstract The increasing amounts of water being p Zara Khatib, Technology Marketing Manager, Shell International, ME, Caspi Abstract The volume of produced water worldwide Freek van Dijk and Keat Choon Goh, Shell Global Solutions International Abstract Well and Facility Operations make opera Vivek Garg, ONGC Ltd., Shubhranshu Ashesh, Kapil Seth, Amit Govil, Schl Abstract Reviving production from brown fields is

John D. Hudson, Shell Global Solutions (US), Inc. Abstract The promise of improved production per J.D. Jansen, SPE, Shell Intl. E&P (SIEP) and Delft University of Technol Abstract Closed-loop reservoir management is a Cor Kuijvenhoven, SPE, Andrew Bostock, and Dave Chappell, Shell Intl. E& Summary The Bonga field located in deep water Cor Kuijvenhoven, SPE, Shell Intl. E&P B.V., and Jean Christophe Noirot, Abstract The Bonga field which is located in deep E.A. Vik, SPE, A.O. Janbu, F. Garshol, L.B. Henninge, and S. Engebretsen, Abstract� Currently the application of nitrate/n Magdy Girgis, Shell Global Solutions BACKGROUND To compete with more convention Ardian Nengkoda, Musallam Mandhari, Mohammed Hajri, Hilal Barhi, and L Abstract In the X oilfield Sultanate of Oman water O. Vazquez, SPE, E. Mackay, SPE, K. Sorbie, SPE, Heriot-Watt University Abstract The most common method for preventing David Casti�eira, Faruk O. Alpak, and Detlef Hohl, SPE, Shell Internation Abstract Economic constraints impose stringent li M. O'Dell, SPE, H. Soek, SPE, and S. van Rossem, Petroleum Developme Abstract With high GOR and sour gas in South O Theo Klaver, Shell Global Solutions International BV Abstract Description Shell Global Solutions Intern K. Langaas, SPE, A.D. Grant, N.A. Horvei, A. Cook, H.M. Klokk, and K.B. Fl Abstract Production from Draugen started in 1993 Bababola Akiode, Vikas Bhushan, and Robert Lee, SPE, Shell UK, and ParijAbstract There has been a tremendous growth in Sascha van Putten, SPE, and Marc Naus, SPE, Shell International Explorat Abstract For a number of gas supply projects feed D.J. van Nispen, SPE, J. Hunt, SPE, A. Hartwijk, and A. Trofimov, SPE, Sa Abstract This paper discusses the application of n J. Neidhardt, H. Farran, I. Gonzalez, and P. Vledder, Shell Syria; and Y. D Abstract With an approximate STOIIP of 760 MMb J.F.B.M. Kraaijevanger, Shell Intl. E&P B.V.; P.J.P. Egberts and J.R. Val Abstract We address the problem how to operate G.M. van Essen, SPE, Delft University of Technology (TU Delft); J.D. Janse Abstract The St. Joseph field has been on produc Liz Ross and Kevin King, Sakhalin Energy Investment Co. Ltd.; Gerard Bodew Abstract The Lunskoye Field is a centrepiece of t Yannong Dong, Shell International Exploration and Production Inc., and DeaAbstract Automatic history matching can be use M.J. Zandvliet, SPE, M. Handels, SPE, G.M. van Essen, SPE, Delft UniversitSummary Determining the optimal location of wel E.T. Montague, SPE, Curtin U. of Technology*; D.H. Sherlock, SPE, CSIRO Abstract This paper describes a research program Baosheng Liang, U. of Texas at Austin; Faruk O. Alpak, Shell Intl. E&P Inc Abstract Inherent data and model uncertainties re Faruk O. Alpak, SPE, Florian van Kats, and Detlef Hohl, SPE, Shell Internat Abstract A novel stochastic framework is describe Yildiz Bayazitoglu, Rice University; Paul R. Paslay, Manatee Inc.; and Paul Abstract This paper explains how to model the con B. Hustedt, SPE, D. Zwarts, H.-P. Bjoerndal, SPE, R. Masfry, SPE, and P.J. Summary Water-injection-induced fractures are k P.J. van den Hoek, B. Hustedt, M. Sobera, H. Mahani, R.A. Masfry, J. SnippeAbstract It is well established within the Industry t E.D. Nennie, G.J.N. Alberts, S.P.C. Belfroid, SPE, and E. Peters, TNO, The Abstract Within the research framework of the †E.D. Nennie, SPE, G.J.N. Alberts, SPE, and E. Peters, TNO, The Netherlands Abstract Stabilization and optimization of productio A. Balogun, SPE, Shell E&P, H. Kazemi, SPE, E. Ozkan, SPE, M. Al-Kobais Summary Ac Permeability Reservoirs Kazeem A. Lawal, SPE, Shell Nigeria Exploration & Production Company Abstract As a consequence of limited capability fo H. Mill�n and A. Parker, SPE, Brunei Shell Petroleum Co. Sdn. Bhd. Abstract The Champion Field is located 40 km off Nitin Chowdhury, SPE, Ravi Sharma, Gary A. Pope, SPE, and Kamy Sepehrno Summary A fine-grid simulation is needed to capt Kazeem A. Lawal, Anthony O. Uwaga and Omamoke F. Osoro; Shell Petr Abstract With increasing drive to account for asso M. Evazi Yadecuri, Sharif University of Technology, and H. Mahani, SPE, SheAbstract Reservoir flow simulation involves subdiv P. Mostaghimi Qomi, Sharif University of Technology; H. Mahani, SPE, Shell Abstract Applying upscaling techniques is an und H. Mahani, SPE, M.A. Ashjari, and B. Firoozabadi, Sharif University of TechnAbstract A novel technique for upscaling of detaile M. Evazi, H. Mahani, SPE, K. Hejranfar, and M. Masihi, SPE, Sharif Univers Abstract Highly detailed geological models which Birol Dindoruk, Shell International E&P, and Azhar Al Kindi, Shell E&P Com Abstract A novel approach to perform basin scale Satomi Suzuki, SPE, Stanford U.; Colin Daly, SPE, Schlumberger; Jef Caers,Summary The application of elastic stress simula S.E. Salem, SPE, M. Al-Deeb, SPE, M. Abdou, SPE, and S. Linthorst, SPE, Summary This paper presents the methodology A.P.G. van Heel, Shell Technology Oman, Muscat, Sultanate of Oman; P.M. B Summary The shape factor concept originally int Peter Schutjens (SPE), Boris Kuvshinov, Victor Dunayevsky, Fritz Rambow, Abstract An analytical model is presented to desc Azhar Al Kindi, Shell Abstract In comparison to on-shore or shallow wat Deniz Sumnu-Dindoruk, SPE, Shell E&P, Unconventional Oil, and Birol DindSummary Mass balances for two immiscible fluids Walrick E.J.J. van Zandvoord, Shell Global Solutions Malaysia Sdn Bhd, andAbstract As part of a study to reduce run times of Deepak Devegowda, Elkin Arroyo-Negrete, and Akhil Datta-Gupta, Texas A Abstract Recently Ensemble Kalman Filtering (EnK J.G. Crump, SPE, Shell E&P Company and R.H. Hite, �SPE, Shell Intern Summary This paper describes a new method for Peter Obidike, Shell Nigeria Exploration and Production Company Abstract Reservoir engineering tools applied in de D.F. Hadley, E. Arochukwu, SPE, K. Nishi, SPE, M. Sarginson, H. Salleh, a Abstract Champion is a multi-billion bbl STOIIP oi Marko MauĿec, Sippe Douma, Detlef Hohl, and Jaap Leguijt, Shell E&P In Abstract S Markov Chain Monte Carlo Study o

Ajay K. Samantray, Shell; Qasem M. Dashti, SPE, and Eddie D.C. Ma, KuwaSummary Nine multimillion-cell geostatistical eart N.J. McLeod, SPE, and R.T. Kelly, SPE, RPS Energy Abstract During the past 5 years Western Europe Kazeem A. Lawal and Emmanuel Utin, Shell Petroleum Development CompaAbstract While a number of methods including se S. Livescu, SPE, L.J. Durlofsky, SPE, and K. Aziz, SPE, Stanford Universit Abstract Thermal recovery processes are widely a S.K. Masalmeh and X.D. Jing, Shell Technology Oman Abstract Carbonate reservoirs are highly heteroge Eilard H. Hoogerduijn Strating, SPE, and Willem Postuma, Shell Internation Abstract The JG field is located in the North East A Abraham K. John, SPE, Larry W. Lake, SPE, Steven L. Bryant, SPE, and JaAbstract Dispersivity data compiled over many len Raman K. Jha, Abraham K. John, Steven L. Bryant, and Larry W. Lake, Unive Summary Flow-reversal studies provide insights i Byron Haynes, Jr., Ahmed Abdelmawla and Simon Stromberg, Petroleum Abstract Rock Pore Volume Compressibility (PVC G.T. Shahin Jr, SPE, Shell E&P Technology; R. Moosa, SPE, PDO; B. KharuAbstract Naturally fractured carbonate reservoirs Marco Verlaan, Shell International Exploration and Production, Rijswijk, T Abstract Conventional displacement methods suc Andrey Bychkov, Marco Verlaan, Paul Boerrigter, SPE, Shell International Abstract Conventional displacement methods suc P.-J. Weijermans, SPE, Horizon Energy Partners, and G. Warren, SPE, NA Abstract NAM in the Netherlands is currently con Hong Tang, SPE, Louisiana State University Abstract Even though production data have direct Jaime Jimenez, Shell International Exploration & Production Abstract The rise of the SAGD (steam-assisted gr Byron Haynes, Jr., Naveen Kaura, and Andrew Faulkner (PDO) Abstract A field in South Oman discovered in 197 B. Hustedt, SPE, Shell International Exploration and Production, and J.R. S Abstract The performance of many waterfloods (a P. Oudeman, SPE, Shell International Exploration & Production Abstract Calculating the blowout rate of oil and ga R. Murray, SPE, BP Exploration; C. Edwards, SPE, Shell; K. Gibbons, SP Abstract This paper summarizes the findings of t Ron Cramer, Shell Global Solutions International B.V. Abstract Digital Oil Field Computer Assisted Ope Syed Ali, SPE, Chevron Energy Technology Co., Tommy Grigsby, SPE, and San Summary Technological advancement in horizont E.J. Puik and C. Braithwaite, Shell International Exploration and Production Abstract In an age where there is increasing conce L. Jin, SPE, and M. Seah, Shell Intl. E&P Abstract Oil and gas assets in Shell Asia Pacific r Azhar Al-Kindi, SPE, Shell; Robert Prince-Wright, RISKbytes Inc.; and Joh Summary Big reservoirs in deepwater Gulf of Mex Francesca Osayande and Omuvie Ugborugbo, Shell Petroleum DevelopmenAbstract Time-lapse Feasibility Studies were carri Rodney Calvert and Andrey Bakulin, Shell Intl. E&P Inc. Abstract New 4D seismic methods have been dev Tan Teck Choon, SPE, Sarawak Shell Berhad Abstract An integrated bypassed oil identification S. Hurter, SPE, Shell; A. Garnett, PTC Consulting; and A. Bielinski and A. KoAbstract This study examines the suitability of the K.C. Goh, Shell Global Solutions International B.V.; B. Dale-Pine and I. Abstract The Champion West field was discovere Paul Huckabee, SPE, Shell Exploration and Production Company Abstract This paper summarizes applications of o G.T. Shahin, Shell Development Company, and R.M. Johnston, CalResourc Summary Results of a temperature transient anal Norbert Dolle, Francois Gelin, and Fidelis Tendo, Shell E&P in Europe; Ke Abstract WDriven Models: An Integrated Solution Jeffrey Weiland, Shell Exploration & Production; Mehdi Azari, SPE, Suparm Abstract Proper characterization of a producing we W.E.J.J. van Zandvoord, SPE, Shell Global Solutions Malaysia Sdn. Bhd. Abstract This paper demonstrates the use of real Andrey Bakulin, SPE, Shell Int. E&P Inc, Alexander Sidorov, Boris Kashtan, Abstract Deepwater production is challenged by w H. Elshahawi, SPE, M. Hashem, SPE, and D. McKinney, Shell International Summary Modern wireline formation testers (WFT Jing Du, SPE, Pinnacle Technologies; Simon J. Brissenden and Peter R. McG Summary Surface-deformation measurements ha K. Langaas, SPE, Norske Shell AS; K.I. Nilsen, Norwegian Petroleum DirectSummary A review of the tidal response in petrole O. Ojonah, SPE, Shell Production and Development Co., and J.J. Kohring, Abstract Maximising the potential of a producing w Jeff Weiland, Duane Mikulencak, Shell Offshore Inc., Phil Fox, Suparman, Ga Abstract Waterfloods serve many purposes and th Vikas Bhushan, SPE, Bababola Akiode, SPE, and Robert Lee, SPE, Shell UK Abstract Production logging in high angle and hor Chonghui Shen, SPE, Shell Exploration and Production Company Abstract Shell Oil Company conducted an oil sha Thomas D. Fowler, SPE and Harold J. Vinegar, SPE, Shell Exploration an Abstract The massive size of the oil shale resourc N. Al-Araimi, SPE, Brunei Shell Petroleum Co. Sdn. Bhd. and L. Jin, SPE, ShAbstract A successful acid stimulation campaign w J. Arukhe, SPE, Petro-Canada; L. Nwoke, SPE, Shell; C. Uchendu, SPE, BJAbstract Within the Niger Delta clastic environme Mason B. Tomson, Amy T. Kan, Gongmin Fu, and Dong Shen, Rice University Summary This paper discusses the effects of Ca2 M.M.J.J. Naus, SPE, Delft U. of Technology (DUT); N. Dolle, SPE, Shell In Summary We developed an operational strategy B.�. Bringedal, S.A. Morud, and N.A. Hall, ABB, and G. Huseman, Shell Abstract Waterflood injection on the Shell Bonga Z. Chen , M. Duan, S.Z. Miska, M. Yu, and R.M. Ahmed, University of Tulsa; Summary Foam has proved to be effective and e Matthew Law, George W. Chao, Hafeez A. Alim, Ahmad F. Hashim, Elsamm Abstract This paper discusses the application of fi J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. Van der Bas, SP Abstract It is well documented in the literature tha

J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. van der Bas, SP Abstract This paper summarizes part of the resu A.P. Leemhuis, E.D. Nennie, and S.P.C Belfroid, SPE, and G.J.N. Alberts, Abstract A strong increase in gas inflow due to ga K. Zeidani, SPE and M. Polikar, SPE, University of Alberta Abstract Laboratory investigations were conducted M. Kerem, SPE, Shell E&P B.V.; M. Proot, Shell GSI B.V.; and P. Oudeman Summary This paper presents the results of a pro V. Ogoke, SPE, Shell; C. Aihevba, SPE, Petroleum Development Oman; andAbstract A new cost effective life-cycle profile cont Rouhollah Farajzadeh, SPE, Shell International Exploration and Production, Abstract Foam is widely used to divert acid or aba F. Farshbaf Zinati, R. Farajzadeh, and P.L.J. Zitha, Dept. of Geotechnology, Abstract We present a new 2D analysis based on M.D. Carretero-Carralero, R. Farajzadeh, D.X. Du, and P.L.J. Zitha, Dept. of Abstract In this paper we present a 1D and 2D an P. Oudeman, SPE, Shell Intl. E&P Abstract In depleted gas wells the produced gas D.Orta, S. Ramanchandran, J. Yang, M. Fosdick, T. Salma, J. Long, and J. BlAbstract Continuous increase in worldwide brown S.P.C. Belfroid, SPE, W. Schiferli, SPE, and G.J.N. Alberts, SPE, TNO Sc Abstract As reservoir pressures decrease in matur A. Burtsev, B. Kuvshinov, E. de Rouffignac, and A.M. Mollinger, Shell Intl. E Abstract This paper presents an assessment of th M.R.G. Bell, SPE, and J.B. Davies, SPE, Shell Intl. E&P, and S. Simonian, Abstract While assisting production engineers in m Fergus Robinson, SPE, Sarawak Shell Berhad; Kent C. Folse, SPE, Hallibu Abstract Two gas fields offshore Sarawak Malay Sakamrin Abdul-Rahman, Brunei Shell Petroleum Co. Sdn. Bhd., and DerekAbstract L Oil and gas producers have long been lo J.H. Terwogt, N.S. Hadfield, and A.A. Van Karanenburg, Sarawak Shell BerhAbstract The Shallow Clastics Field operated by George Gillespie, SPE, Weatherford International; Chuck Hinnant, SPE, C Abstract This paper describes challenges test equ Neil S. Hadfield, Jan H. Terwogt, and Aart A van Kranenburg, Sarawak Shell Summary The Shallow Clastics field operated b M.A. Addis, SIEP, M.C. Gunningham, SEIC, Ph. Brassart, SEIC, J. Webers, Abstract Sand Quantification involves predicting th M.C. Gunningham, SPE, Sakhalin Energy Investment Company; M.A. Addis,Abstract S This paper is a case study which describ P.J. van den Hoek, SPE, and M.B. Geilikman, SPE, Shell Intl. E&P B.V. Abstract Most sand production prediction models M. Asadi, ProTechnics; G.S. Penny, CESI Chemical; B.R. Ainley, Chandler En Abstract A group of industry experts have compile Liang Jin and Paul Wong, Shell Intl. E&P, and Brent Sinanan, BJ Services CAbstract Malaysia is a significant gas producer an P.J. van den Hoek, SPE, Shell Intl. E&P B.V.; D. Volchkov, SPE, and G. Bur Abstract It is well established within the Industry t K. Lizak, Shell; K. Bartko, Saudi Aramco; F. Self, G. Izquierdo, and M. Al- Abstract Prehydraulic fracture diagnostic pumpin P.S. Fair, Shell International Exploration and Production Inc. Introduction There are three objectives of this pap Kui-Fu Du, SPE, NAM, The Netherlands Abstract This paper presents several field examp Arve K. Thorsen, SPE, Tor Eiane, SPE, and Holger Thern, SPE, Baker HughAbstract This paper describes geological and petr P. Oudeman, SPE, Shell Int. E&P, M. Kerem, SPE, Shell Int. E&P Summary Pressure buildup caused by fluid therm Arild Foss�, Expro; Derek MacKenzie, Norske Shell; Odd Steinveg and ErAbstract This paper covers the HPHT Gas-Conde S. Daungkaew, J.H. Harfoushian, and B. Cheong, Schlumberger; and O. Akins Abstract Exploration and appraisal campaigns for R. Cramer, Shell Global Solutions; C. Moncur, Shell Global Solutions B.V.; Abstract Much can be done to improve the Well T

utch Shell Group (Shell) was one of the first energy companies to acknowledge the threat of climate change - to call for action by governme Dutch Shell Group (Shell)[1] was one of the first energy companies to acknowledge the threat of climate change - to call for action by govern coalbed-methane (ECBM) recovery combines recovery of methane (CH4) from coal seams with storage of carbon dioxide (CO2). The effic gives an analysis of the Thomas and Windle model which is also proposed to describe anomalous diffusion of CO2 in coal and its relation t welling of coal by a penetrant refers to an increase in the volume occupied by the coal as a result of the viscoelastic relaxation of its highly c olume of coal swells when CO2 / CH4 adsorb on the coal structure. In coalbed gas reservoirs matrix swelling could cause the fracture aper r CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface be undertaken in a greater variety of geo supercritical CO2 injection into a deep saline aquifer from a carbonate formation (calcite and dolomite with minor anhydrite) was performed ore flooding experiments with CO2 N2 and flue gas were carried out on coal in an experimental high P T device under in-situ conditions. T of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from p te change induced by the release of greenhouse gases (notably carbon dioxide) into the atmosphere is a topic of considerable discussion a bout global climate change and the challenges and risks it poses will require sustained efforts to develop understanding and effective solu n xML (PRODMLâ„¢) was started jointly by BP Chevron ExxonMobil Shell and Statoil in early 2005 as a data exchange mechanism to sup ¢ is a set of production data standards initiated by 13 upstream oil and service companies with the industry standards body Energistics (the ain Kirk from the “USS Enterprise gave the command “Bean me up Scotty to his transporter chief in the science fiction television se and comprehensive integrated production-system monitoring framework plays an important role in the Smart Fields philosophy to turn data terisation is critically important to effective reservoir management. Misinterpreting reservoir properties for instance can result in non-optima nal practice individual well oil gas and water production is only measured on a weekly or monthly basis using shared well test facilities. Oil m asset managers to front end operations staff there is a common problem – we are data rich but information poor.�In particular timel ars advances in computing and control technology have enabled real time monitoring surveillance and control of reservoir well and process production from a cluster of wells is conventionally relatively difficult to manage at least partly due to field conditions subsurface uncertaint individual well oil gas and water production is measured periodically e.g. monthly using shared well test facilities. Consequently oil and g small assets in Shell Malaysia E&P has adopted a methodology earlier implemented by Aera in California USA hereafter referred to as LEA rn of the century Shell has had a vision that Optimal Value Testing (OVT) will replace conventional drill stem tests for in-situ measurement st few years there has been a vision that Optimal Value Testing (OVT) will replace conventional drill stem tests for in-situ measurement of d st few years there has been a vision in Shell that Optimal Value Testing (OVT) would some day replace conventional drill stem tests for in-s discusses the “evolution from Smart Well installations to the delivery of a fully integrated “Smart Field. Capabilities were first devel rveillance center designed to conduct routine surveillance on reservoirs wells facilities and subsea systems has been developed. Surveil Fields collaboration between Shell and Schlumberger is developing an Uncertainty Management Framework aimed at reducing both Hydro s can provide enhanced oil recovery through the combined use of optimization and data assimilation. In this paper we focus on the dynam ells and Smart Fields concept have recently been applied in some assets Shell as a solution to increase production reduce deferment and ield the asset staff has the tools processes and skills to maximise the asset lifecycle value and do this on a continuous basis. This involve are laterally weaving (“snaking) extended reach horizontal wells that drain a number of vertically stacked structurally dipping reservoirs Time Optimization (RTO) Technical Interest Group (TIG) has endeavored to clarify the value of real-time optimization projects. RTO projects on West field was discovered in 1975 and named Champion West in 1990. The field is located in the North of the Brunei Offshore sector. P hell introduced underbalanced drilling (UBD) in the offshore environment in 1997 Shell has been looking at ways to reduce the footprint for ajor player in the Global deployment of Managed Pressure Drilling (MPD) technology to reduce drilling prob-lems minimize formation dama ure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep high-pressure light oil reservoirs after waterflooding carried out to determine the geomechanical effects of polymer flooding in an unconsolidated sand reservoir. The work involved laboratory-s ion and properties of two families of anionic surfactants (internal olefin sulfonates and branched C16 17 alcohol-based alkoxy sulfonates) a l displacement methods such as water flooding do not work effectively in densely fractured reservoirs: due to the high fracture permeability is an Enhanced Oil Recovery (EOR) technique with limited exposure in the Asia-Pacific region and no previous application in Australia. Ana re that miscibility of oil and gas is achieved in each reservoir is a fundamental issue for miscible gasfloods involving different oil reservoirs w attractive option in EOR for increasing oil recovery in mature water-flooded reservoirs. In this paper we use stochastic bubble population mo escribes an improved engineering workflow to perform technical evaluation and screening of gas injection EOR. A successful case study de omic indicator called simple thermal efficiency parameter (STEP) was developed to evaluate the performance of a steam-assisted gravity vity Drainage (GOGD) of the Qarn Alam fractured low permeability carbonate reservoir is being enhanced by steam injection in the world's f mental aspects of Water Alternating Gas (WAG) injection are still not well understood. There are a few applications in fractured media and t

mposition profoundly influences reservoir wettability and hence microscopic sweep careful design of injection brine is part of a strategy to im ctured carbonate field in north Oman has both complex geology and complex reservoir-drive mechanisms. The upper densely fractured lay duction in northeast Syria has increased significantly in recent years.�As a result costs per barrel of oil have increased and the field’ tacked nature of reservoirs in the Niger Delta the predominant completion types are dual-string multizone and single-string multi-zone comp presents the development of a particle-gel (PG) system for water shutoff operations. This system combines an organically crosslinked polym actured oil-wet carbonate fields pose a true challenge for oil recovery that traditional primary and secondary processes fail to meet. The diff e oil field gas and liquid compositions tends to change due to the aging of the field because watercut will increase thus may increase the gas ptimization such as optimal gas lift allocation to maximize oil production can be a non-smooth and non-convex optimization problem. In this st decade flow assurance applications have been extremely successful in many offshore deepwater gas and oil project developments whe 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 scibility pressure (MMP) is an important design parameter for enhanced oil recovery processes involving gas injection (carbon dioxide nitro elation for calculating the viscosity of Natural Gas under surface and Reservoir conditions has been developed. The correlation was obtaine eanup During Wireline Formation Tester Sampling opment projects will rely on producing through existing production facilities which may not have been designed for sour hydrogen sulphide ompartmentalization quantifying connectivity and assessing the presence of compositional grading are critically important to reservoir man 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 most important issues in oilfield chemistry is the troublesome occurrence of organic and inorganic solids which may form downhole in the re variably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path stable of surface-active chemicals on oil/water interfacial tension (IFT) and wettability in crude oil/brine-rock systems at reservoir conditions is imp boratory screening of surfactants for their ability to give ultra-low interfacial tensions in oil/brine systems is important as a pre-cursor to labor unique or modified HF acid systems for matrix acidizing within the Niger Delta and some other parts of the world is still the preferred method coreflood experiments with stimulation fluids [hydrochloric acid (HCl) preflush followed by hydrochloric/hydrofluoric acids (HCl/HF) main flu idizing long intervals diversion is essential to obtain good placement of the reactive fluids. Over the years several diversion techniques hav we describe a simulation model for computing the formation damage imposed on the formation during over-balanced drilling. The main par nt premise of underbalanced drilling (UBD) is the productivity improvement it delivers through mitigation of invasive damage. Characterizati on and prevention of both sodium and calcium naphthenate “scales is an important issue in oil production. A broad description of how th d deposits from distinct geographical regions were analysed using a wide range of analytical techniques viz. for cation composition (EDAX describes field experience and lessons learned from bullhead-deployed scale-control operations in a deepwater subsea development in th ion in the near-wellbore area the tubing and in topsides facilities is one of the major challenges associated with oil production and so must m of multiphase flows in chokes presents an interesting problem for steam injection and hydrocarbon production. In both cases it is importan recovery of a medium-heavy oil reservoir with a strong bottom aquifer is generally poor. The introduction of horizontal wells that are drilled a appraisal campaign and modeling study was carried on a heavy-oil fractured Shuaiba field in the north of the Sultanate of Oman to assess n barrels of bitumen in place and more than 30 years of thermal piloting and demonstration projects Peace River offers an excellent growth ell production without compromising reservoir management and well integrity in an environmentally friendly manner is a common objective tical results and thermal reservoir simulations we study the heating of - and oil recovery from - a vertical stack of matrix blocks. The stack is njection rates in the CSS operation for the extraction of the Peace River bitumen can be significantly increased by operating at a pressure a ies descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and t carbonate stringers represent a new oil province located in the south of Oman. To date over 60 wells have been drilled in and around thes ed on chelating agents have been developed for matrix stimulation of high-temperature sandstone formations. These fluids dissolve sizeabl f new methodologies products or technologies are considered to be an effective way to gauge the true value of such innovations.� Howe draulic fracturing technique is widely used to enhance well productivity especially in low permeability reservoirs. Even though MHF is becom ability or “tight gas reservoirs are being developed at an ever increasing rate in the U.S.�The amazing increase in activity in the Ro e anticline is located in the Green River Basin of Southwestern Wyoming USA. The field is the largest tight gas discovery for the onshore re eliable and accurate formation pressures in micro-Darcy rock has been a formidable challenge for tight gas producers. However it is these p ddresses the problem of estimating Klinkenberg-corrected permeability from single-point steady-state measurements on samples from low describes the use of an under balanced drilling (UBD) system in a remote desert exploration well to directly evaluate the hydrocarbon reserv a tight onshore gas field located in North Shaanxi Province Ordos Basin China. Since 1999 Changbei has been produced by sixteen vertic escribes the application of underbalanced horizontal wells to develop some different tight gas reservoirs in the Netherlands section of the S bjective of the Marginal Fields Programme (MFP) initiated by the Federal Government is to enhance indigenous participation in the explorat ue realized from an asset depends on how well it is managed throughout its lifecycle from exploration to early development to abandonmen

sity of sustainable development presents some significant opportunities and challenges to companies in the petroleum sector. They need t ompleted across 60ft interval (with External Gravel Pack (EGP) as sand exclusion option) was successfully tested to 66MMscf/d against 100 presents an integrated method for identifying and inserting valuable flexibility into major projects. It builds upon recent work that (1) docum s will show how a unique combination of real-time R&D coupled with strong asset team project alignment has the potential to result in signi er capillary transition zone often contains a sizable portion of a field’s initial oil in place especially for those carbonate reservoirs with low ears formation-sampling and formation-testing tools have provided a variety of new downhole optical measurements for downhole fluid ana fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir-fluid properties and determining zonal co urbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds.� These Source Electromagnetic (CSEM) is an emerging technology with the potential to provide detailed resistivity images of the subsurface. Follow perties can represent fine-scale geologic heterogeneities in simple full-field reservoir models without having to explicitly model them. A com leted reservoirs exhibit sharply lower pore pressures and horizontal stress magnitudes than does the overlying shaly formation. Drilling thro ering and analysis of outcrop analogue data is a valuable data source for enhancing the understanding of analogue hydrocarbon reservoirs re analysis (ACA) in homogeneous-matrix reservoirs provides a method for extracting critical reservoir information from pre-frac injection te world's oil fields and aquifers are found in carbonate strata. Some of these formations contain vugs or cavities several centimeters in size. F eveloped that allows accurate prediction of the permeability of a core sample of sedimentary rock based solely on two-dimensional image t of dynamic reservoir characterization using flow and pressure data gathered during underbalanced drilling (UBD) is a powerful driver for im iscusses the detection of fluid conductive fracture fairways using seismic data calibrated with BHI or dynamic data. Fault-related fractures d of this paper is identification and mapping fracture corridors in a carbonate field in Oman using a probabilistic approach. A fracture corridor 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 ng reservoir architecture is one of the critical factors in successful appraisal and development of any oil/gas field. Increasing drilling costs a ge water flood study on a cluster of fields in South Oman it became apparent that relative permeability constituted one of the major uncertain he wetting condition of a reservoir at an early stage is crucial for selecting optimum field-development options. Paying insufficient attention t hofacies Mapping ll Petroleum (BSP) recently discovered Bubut (BU) a significant gas accumulation in its mature heartland and close to liquefied natural gas Petroleum is a Petronas Carigali – Shell Malaysia joint operating company formed in 2001 operating since then the PM301 and PM302 e Shell Global Solutions International B.V (“Shell) has been involved for many years in the development of new technologies to separate mic development of thin oil rims associated with large gas caps in multi-stacked reservoirs presents many challenges. In the structurally com eservoirs critical to providing a reliable supply of gas to the Nigeria Gas market have observed or potential oil rims where only a gas-down-to c interpretation plays a key role in the reservoir management of the Draugen field situated offshore Norway. High-quality time-lapse seismic alym oil field in West Siberia is a new development recently brought on stream in this mature petroleum basin. The field contains some two ld, Offshore Nigeria rom the deepwater Bonga turbidite reservoirs was started in November 2005. As with all waterflood and Enhanced Oil Recovery schemes industry the nature of well and reservoir operations are slowly but relentlessly changing. The traditional operations sequence of events is to rim of the Gannet-A turbidite field in the Central North Sea has been produced since 1993 though 11 long horizontal wells supported by a st dwide production surveillance for artificial lift is critical in brown field operations to ensure optimum field production and efficiency. Using app ablished within the Industry that water injection mostly takes place under induced fracturing conditions. Particularly in low-mobility reservoirs Carmon Creek is a 100% Shell owned ultra-heavy oil lease located in north-western Alberta Canada approximately 700 km northwest of E ablished that some of the carbonate fields in the Central Luconia Gas Province Sarawak Malaysia have been subjected to karstification a n II Project the world’s largest E&P project is currently developing 2 oil and gas fields offshore Sakhalin Island off the east coast of m ptimization of waterflooding using optimal control theory has significant potential to increase ultimate recovery as has been shown in variou d study on a cluster of 23 fields in South Oman was performed in the Petroleum Development Oman (PDO) Study Center in order to derive for optimal development of a field involves proper knowledge and implementation of Reservoir management techniques. Drawing from the pion field is a large oil field offshore Negara Brunei Darussalam. This paper discusses the (for us) novel application of water injection-induc e reservoir pressure depletion occurs with a continuous production over a period of time. This leads to high Gas-Oil Ratio and low productio resources are unevenly distributed around the world. Will we be able to grow transport capacity sufficiently quickly to transfer ever-increasin arl GTL will be the world’s largest GTL plant. It is the single largest energy project within the borders of Qatar as well as Shell’s larg ng amounts of water being produced from oilfields and the increasing need or necessity to return it to the reservoir it ori-ginated from are p of produced water worldwide from O&G industry is still increasing at a fast rate about 10% per year. The Water to Oil ratios ranged from <1 cility Operations make operating decisions based on processing huge amounts of data.� However there is a practical limit to the numbe oduction from brown fields is a major focus of activity for oil and gas companies. This paper outlines the workflow and procedures adopted t

e of improved production performance and consistent delivery against market and regulatory commitments is driving the need for better dec reservoir management is a combination of model-based optimization and data assimilation (computer-assisted history matching) also refe a field located in deep water off the Nigerian coast needs pressure support to effectively recover hydrocarbons. The strategy is to inject 300 field which is located in deep water off the Nigerian coast started oil production at the end of 2005. In order to sustain production seawate y the application of nitrate/nitrite is considered one of the most promising souring mitigation solutions during Produced Water Re-Injection ( ompete with more conventionally produced gas wet sour gas is transported from the well head to the gas sweetening units in carbon steel p eld Sultanate of Oman water has been injected since June 2001 for EOR purposes. The water supply sources was used through 4 dedicat mmon method for preventing scale formation is by applying a scale inhibitor squeeze treatment. In this process a scale inhibitor solution is onstraints impose stringent limits on the number of wells that can be drilled in deepwater developments. Thus optimal placement and opera OR and sour gas in South Oman re-injection schemes were considered for the recently discovered reservoirs of the Harweel Cluster in So Shell Global Solutions International B.V (“Shell)[1] has been involved for many years in the development of new technologies to separa rom Draugen started in 1993. In its 14th year Draugen faces declining oil and increasing water production and is around halfway in its prod een a tremendous growth in the number of high-angle and horizontal wells in the past decade. Coupled with the increase in water cut from er of gas supply projects feeding LNG export schemes there exists a challenge that key gas reservoirs have associated underlying oil rims. discusses the application of new technologies and surveillance requirements with particular reference to fractured waterflood developments roximate STOIIP of 760 MMbbls the Omar field is the largest field in Al Furat Petroleum Company's portfolio. The field – located in the Eu the problem how to operate the injectors and producers of an oil field so as to maximize the value of the field. Instead of agressively produc eph field has been on production since September 1981 under natural depletion supported by crestal gas injection. As part of a major redev ye Field is a centrepiece of the Sakhalin II development one of Shell's most significant current projects. Demand for LNG in the nearby Asia history matching can be used to incorporate 4D seismic data into reservoir characterization by adjusting values of permeability and porosity ng the optimal location of wells with the aid of an automated search method can significantly increase a project’s net present value (NPV describes a research program at the Australian Resources Research Centre (ARRC) to establish and use an analogue model to gain insigh a and model uncertainties render the history-matching inverse problem extremely non-unique. Therefore a reliable uncertainty quantificatio hastic framework is described that facilities automatic history matching and uncertainty quantification workflows. The underlying algorithm o xplains how to model the convective heat transfer of Bingham and Power Law fluids across parallel plates. The analysis enables specificati ction-induced fractures are key factors influencing successful waterflooding projects. Controlling dynamic fracture growth can lead to largely ablished within the Industry that water injection mostly takes place under induced fracturing conditions. Particularly in low-mobility reservoirs esearch framework of the “Integrated System Approach Petroleum Production (ISAPP) knowledge center of TNO TU Delft and Shell th and optimization of production are the key challenges for smart well control. In order to compare the effectiveness of different control strate ity Reservoirs quence of limited capability for the acquisition analysis and interpretation of subsurface data uncertainties pervade the Exploration and Pro ion Field is located 40 km offshore Brunei Northern Borneo in a water depth of 10 – 45 m. It has been on production since 1972 and sec simulation is needed to capture the buildup of a condensate bank near wells operating below the dewpoint pressure. However full-field sim sing drive to account for associated gas it has become necessary to have a reliable technique for extrapolating gas-oil ratio (GOR) commo w simulation involves subdivision of the physical domain into a number of gridblocks. This is best accomplished with optimized grid point de scaling techniques is an undeniable demand in reservoir simulation considering the difference between level of details in a geological mode nique for upscaling of detailed geological reservoir descriptions is presented. The technique aims at reducing both numerical dispersion an ed geological models which are primary inputs to reservoir simulator necessitate the reduction of number of grid blocks to be used in the s oach to perform basin scale compositional simulations for a group of Gulf of Mexico reservoirs has been conducted. The main objective of s ation of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistic presents the methodology implementation and results of the dynamic modeling of a naturally fractured carbonate reservoir which consist factor concept originally introduced by Barenblatt in 1960 provides an elegant and powerful upscaling method for fractured reservoir simu l model is presented to describe total stress change at a vertical wellbore due to drawdown and depletion. The model is applied to two rese on to on-shore or shallow water fields there is limited experience in the industry for deepwater well performance prediction. The developmen nces for two immiscible fluids and tracer and convective heat balance form a system of three equations (nonisothermal Buckley-Leverett Pr study to reduce run times of Probablistic Forecasts iterating around complex Integrated Production System Models several simplification o semble Kalman Filtering (EnKF) has gained increasing attention for history matching and continuous reservoir model updating using data fr describes a new method for estimating average reservoir pressure from long-pressure-buildup data on the basis of the classical Muskat plo ngineering tools applied in development planning or operations support ranges from material balance calculations to simulation studies. The s a multi-billion bbl STOIIP oilfield offshore Brunei. It is a mature field with over 250 producing wells. Oil production commenced in 1972 an Chain Monte Carlo Study of an Offshore Turbidite Oil Field

million-cell geostatistical earth models of the Marrat reservoir in Magwa field Kuwait were upscaled for streamline (SL) screening and finite past 5 years Western Europe and the U.K. in particular have undergone a sea change in terms of the number of gas storage projects that h mber of methods including semi-log/linear plot of water cut versus cumulative oil and water-oil ratio versus cumulative oil have been publish overy processes are widely applied for the production of heavy oil and oil sands. Thermal reservoir simulation models however often lack eservoirs are highly heterogeneous and often show oil-wet or mixed-wet characteristics. Both geological heterogeneity and wettability have is located in the North East Abu Gharadig (NEAG) Basin of the Western Desert in Egypt. With first production in 2002 it is the first commer data compiled over many lengths show that values at typical interwell distances are about two to four factors of ten larger than those measu sal studies provide insights into mixing mechanisms in flow through porous media. In these studies the direction of flow is reversed after th olume Compressibility (PVC) data can be misinterpreted during the early life of reservoir development due to the fact that there are minima ctured carbonate reservoirs hold well over 100 billion barrels of heavy oil worldwide. Thermally Assisted Gas Oil Gravity Drainage (TAGOGD al displacement methods such as water flooding do not work effectively in densely fractured reservoirs. In such reservoirs one has to rely on l displacement methods such as waterflooding do not work effectively in densely fractured reservoirs. The high fracture permeability preven Netherlands is currently conducting studies to redevelop the Schoonebeek oil field onshore in the Netherlands. Steam flooding is the env production data have direct responses of reservoir heterogeneity and connectivity they are rarely incorporated into reservoir modeling wor he SAGD (steam-assisted gravity drainage) technology over the last ten years as the leading technology to develop oil sands in-situ is unqu uth Oman discovered in 1978 is an over-pressured sour oil reservoir. Since first oil began in 1982 the field will has gone through three stag mance of many waterfloods (and EOR schemes) is characterized by fluid injection under fracturing conditions. Especially when the geology i he blowout rate of oil and gas wells is commonly one of the first steps in environmental impact assessment contingency planning and eme summarizes the findings of the SPE Forum held in September 2005 on “Making our Mature Fields Smarter.�Participants in the Foru eld Computer Assisted Operations Smart Fields and iFields are some of the names coined by different E&P Companies for processes tha cal advancement in horizontal drilling and openhole completing techniques for soft-rock formations finally has bridged the gap between the here there is increasing concern for safety and the environment why is there such interest in developing gas resources contaminated with h assets in Shell Asia Pacific region formulate challenges and opportunities for improving well productivity through stimulation. Major factors l oirs in deepwater Gulf of Mexico (GOM) typically produce at world-class rates. The scale of investment is likewise world class. The energy Feasibility Studies were carried out for two producing fields in the Niger Delta to assess the probabilities of success of acquiring 4D surveys mic methods have been developed that can greatly improve the sensitivity speed and economy of more continuous monitoring for field con d bypassed oil identification methodology was developed and successfully applied to identify and quantify the presence of bypassed oil opp xamines the suitability of thermal methods especially DTS (Distributed Temperature Sensing) cables (in the annulus or behind casing) to m ion West field was discovered in 1975 offshore Brunei but its oil reserves in a complex web of thin reservoirs were initially deemed too expe summarizes applications of optic fiber (OF) distributed temperature sensing (DTS) technology for hydraulic fracturing stimulation diagnostics a temperature transient analysis of data from Shell’s diatomite steamdrive pilots are used to image hydraulic injection fracture lengths dels: An Integrated Solution to Production Allocation in a Long Subsea Tieback acterization of a producing well has significant impact on asset management. Production schedules from different wells and further infill drilli demonstrates the use of real time well surveillance and optimization tools in the Northern Fields of Petroleum Development Oman LLC (abb roduction is challenged by well underperformance problems that are hard to diagnose early on and expensive to deal with later. Problems a reline formation testers (WFTs) are able to collect a massive amount of data at multiple depths thus helping to quantify changes in rock and eformation measurements have been used for years in oil fields to monitor production waterflooding waste injection steam flooding and c f the tidal response in petroleum reservoirs is given. Tidal response is caused by periodic changes in overburden stress induced by the ocea he potential of a producing well requires knowledge of the fluid types and flow rates entering the wellbore. Optimum and accurate determina serve many purposes and their performance can have major economic impact on the drilling production and management of hydrocarbon ogging in high angle and horizontal wells that produce mixtures of fluid phases is challenging because of the associated complex flow regim mpany conducted an oil shale thermal conduction pilot in the Piceance Basin of Colorado during 1997 and 1998. Six heaters and one prod size of the oil shale resource in the Western USA particularly in the Green River Basin has attracted numerous commercialization attemp l acid stimulation campaign was conducted in 2004 in Brunei Shell Petroleum (BSP). This paper discusses what have been done differently Niger Delta clastic environment horizontal well completions have been widely used with success. Although conventional wells have been ap discusses the effects of Ca2+ Mg2+ and Fe2+ on inhibitor retention and release. Better understanding of phosphonate reactions during in ped an operational strategy for commingled production with infinitely variable inflow control valves (ICVs) using sequential linear programm njection on the Shell Bonga field offshore Nigeria is accomplished via a network of subsea flowlines and 15 subsea injection wells. Maximiz proved to be effective and economical in underbalanced operations (UBO) and is gaining wider applications in many areas. It provides the iscusses the application of fibers for the Frac and Pack application for Brunei Shell Petroleum (BSP). Seven wells with a total of seventeen cumented in the literature that hydraulic fracture treatments although successful often underperform: Frac and Pack completions exhibit po

summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since t rease in gas inflow due to gas coning and the resulting bean-back because of Gas to Oil Ratio (GOR) constraints can severely limit oil prod nvestigations were conducted to examine the effectiveness of heavy oil-in-water emulsion in plugging the near wellbore matrix thereby redu presents the results of a project that was initiated to analyze the inflow performance and inflow distribution of one smart and two problema ffective life-cycle profile control completion system has been developed to solve major problems associated with surveillance and interventi ely used to divert acid or abandon the high permeable layers. In this type of application foam should considerably reduce gas mobility. The n a new 2D analysis based on the recently developed stochastic bubble population foam model focusing on the effect of the core heterogene we present a 1D and 2D analysis of foam development in porous media based upon a new stochastic bubble population foam model and p gas wells the produced gas rate and consequently the velocity will drop to the extent that produced liquids are no longer carried to surface. increase in worldwide brown-field activity and overall depletion of current gas fields has renewed focus on maximizing gas production from pressures decrease in maturing gas wells liquid drop-out forms an increasing restriction on gas production. Even though virtually all of the presents an assessment of the performance of a horizontal well completed by limited-entry perforation (LEP) technique based on reservoir ing production engineers in managing the perforating process Shell recognized the need for an engineering software tool to guide and adv lds offshore Sarawak Malaysia are characterised by heavily karstified carbonate reservoirs.� These reservoirs are typified by significant producers have long been looking for effective sand control methods that allow completion flexibility and improved productivity throughout a w Clastics Field operated by Sarawak Shell targets two shallow gas-bearing reservoirs H1 and H2 at approximately 2 650 ft true vertical d escribes challenges test equipment test program and results in the development of a screen product and contingency fluid-loss control (FL llow Clastics field operated by Sarawak Shell primarily targets two shallow gas-bearing reservoirs H1 and H2 at approximately 2 650 ft true fication involves predicting the volumes of sand which can be produced at the sandface completion and transported to the surface facilities s a case study which describes how Quantitative Risk Assessment (QRA) is applied to sand management in the specific case of Lunskoye production prediction models to date have the capability to indicate whether initial sand production may take place during the lifetime of a re dustry experts have compiled their years of experiences in developing a new technical standard to measure stimulation and gravel-pack flu a significant gas producer and LNG exporter within Asia-Pacific region. Many of the country’s gas fields are offshore carbonate reservoi ablished within the Industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large c fracture diagnostic pumping analysis has recently improved with the use of new analysis techniques such as G-Function derivative plots e three objectives of this paper. The first objective is to present a generalized geometric skin for deviated wells for all angles up to 89.9� presents several field examples of applying two independent methods of increasing tested area estimation and improving reservoir characte escribes geological and petrophysical evaluation of a new structure of a mature field to evaluate the reservoir potential in un-produced rese buildup caused by fluid thermal expansion in sealed annuli of high-presure/high-temperature (HP/HT) wells can have serious consequence covers the HPHT Gas-Condensate Exploration Well 6406/9-1 on the Onyx SW prospect of the Norway Sea in the late spring of 2005 (Figur and appraisal campaigns for deepwater environments are a continuous challenge in today’s operations. Data acquisition in such enviro be done to improve the Well Testing through effective use of minimal electronic instrumentation on the well head and the test separator. The

ange - to call for action by governments; our industry and energy users; and to take action ourselves. Shell’s strategy: to expand our alt change - to call for action by governments; our industry and energy users; and to take action ourselves.� Shell’s strategy: to expand e of carbon dioxide (CO2). The efficiency of ECBM recovery depends on the CO2 transfer rate between the macrocleats via the microcleat sion of CO2 in coal and its relation to matrix swelling. Anomalous (case II super-) diffusion which incorporates the swelling of coal matrix b viscoelastic relaxation of its highly crosslinked macromolecular structure. Projects relating to CO2 sequestration in coal seams suffer a seri welling could cause the fracture aperture width to decrease causing a considerable reduction in permeability. On a unit concentration basis ndertaken in a greater variety of geological environments that has been the case prOnePetro with minor anhydrite) was performed using TOUOnePetro T device under in-situ conditions. These experiments will be able to give an insight into the design of the injection system management co 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 topic of considerable discussion around the world. Shell believes that this debate is over and instead has entered into a debate about wh op understanding and effective solutions while at the same time meeting the growing needs of society for energy. The development and ut a data exchange mechanism to support production optimization within a ‘digital oil field’ context. These companies have been joined ustry standards body Energistics (then POSC) in 2005. In November 2006 PRODML Version 1.0 was released. The focus was on productio ef in the science fiction television series Paramount OnePetro Smart Fields philosophy to turn data into actionable information and therefore valueOnePetro or instance can result in non-optimal well placement completion strategy and facilities design as well as large errors in reserves drainage using shared well test facilities. Oil and gas production from a cluster of wells is hence difficult to manage leading to late diagnosis of prod ormation poor.�In particular timely well-by-well production surveillance and allocation often remains a problem.� Gathering data even control of reservoir well and process; Within the Exploration and Production (E&P) industry these technologies are increasingly being applie eld conditions subsurface uncertainty and the multiphase nature of the we OnePetro st facilities. Consequently oil and gas pro OnePetro a USA hereafter referred to as LEAN." The concept is to increase organization efficiency by applying Toyota manufacturing principles.�T stem tests for in-situ measurement of dynamic reservoir properties such as permeability and drainage volume. The term OVT refers to as a m tests for in-situ measurement of dynamic reservoir properties such as permeability and drainage volume. This vision was that OVT would conventional drill stem tests for in-situ measurement of dynamic reservoir propertie OnePetro t Field. Capabilities were first developed and tested in nearby fields before being applied in the Champion West field. Results and issues w stems has been developed. Surveillance en OnePetro ework aimed at reducing both Hydrocarbon Development Planning cycle time andOnePetro improving th n this paper we focus on the dynamic optimization of injection and production rates during waterflooding. In particular we use optimal cont e production reduce deferment and increase recovery. Smart Field can however only be fully utilized if the three main elements fully integra on a continuous basis. This involves optimisation at several time scales in production reservoir management and development planning. acked structurally dipping reservoirs. This creates multiple drainage points in each sand and effectively achieves a similar drainage pattern optimization projects. RTO projects involve three critical components: People Proc OnePetro OnePetro orth of the Brunei Offshore sector. Phase 3 of this project is the latest development with 20 wells (oil & gas). These Extended Reach Drillin g at ways to reduce the footprint for the equipment required for underbalanced operations. Much of this work involved reducing the size of t prob-lems minimize formation damage and improve reservoir management techniques. The impetus is a recognition that most of the world ght oil reservoirs after waterflooding.� The advantage of air over other injectants like hydrocarbon gas carbon dioxide nitrogen or flue g voir. The work involved laboratory-scale polymer injections in unconsolidated sand blocks to identify the injectivity mechanisms numerical a 7 alcohol-based alkoxy sulfonates) are described for chemical flooding of oil reservoirs at high temperatures and/or high salinities.� Surfa due to the high fracture permeability it is not possible to establish significant pressure differentials across oil bearing matrix blocks to drive oi revious application in Australia. Analogy with successful air injection projects in the USA suggests that it could be a suitable EOR process f ds involving different oil reservoirs with varying fluid properties. This paper reports on all the work done to help decide on how to optimally b use stochastic bubble population model and complex power law rheological model to integrate foam physics into a flow simulator. Foam dis on EOR. A successful case study demonstrates how field data engineering analysis and simulation are integrated to precisely model gas in ormance of a steam-assisted gravity drainage (SAGD) project. Its usefulness as aOnePetro ed by steam injection in the world's first full field development carbonate thermal development. Unlike a normal steam flood the steam is us applications in fractured media and these show potential.[1] This study looks at theOnePetro

ction brine is part of a strategy to improve on oil production in existing and future water flooding projects in both sandstone and carbonate ms. The upper densely fractured layers are produced using the gas/oil gravity-drainage (GOGD) process while the less-fractured lower set oil have increased and the field’s production is currently constrained by the facilities capacity. Production logging tool (PLT) surveys co ne and single-string multi-zone completions. These designs have been adopted to reduce the number of infill wells required for field develop nes an organically crosslinked polymer (OCP) system with non-cement particulates to provide shallow matrix shutoff in openhole or perforat dary processes fail to meet. The difficulty arises from the combination of two unfavorable characteristics: First the dense fracturing frustrate increase thus may increase the gas lift requirement. Also the smaller accumulations near by tend to be developed as satellite to the main f convex optimization problem. In this paper we describe the derivative free Discrete Gradient Method (DGM) with local global and multi-sta s and oil project developments where the cold ambient sea bottom temperature and water depth pose enormous technical challenges. Flow 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 g gas injection (carbon dioxide nitrogen or hydrocarbons). Hence an experimental approach called “vanishing interfacial tension (VIT) eloped. The correlation was obtained by the analysis of experimental Pressure Volume and Temperature (PVT) Data of Gas associated wit OnePetro esigned for sour hydrogen sulphide (H2S) service. This problem is compounded if production is routed to an NGL or GTL facility because ev critically important to reservoir management particularly in deepwater projects where uncertainties are large and mistakes are costly. Com planning decisions. For example in subsea wells flow assurance is a major concern and formation fluid samples from openhole logging he which may form downhole in the reservoir wellbore topsides and/or in pipelines. Asphaltenes are a class of compounds in crude oils defin through the production path stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils ystems at reservoir conditions is important in enhanced oil recovery (EOR) processes. However most of the experimental studies on IFT an is important as a pre-cursor to laboratory core flow tests and surfactant OnePetro he world is still the preferred method for effective stimulation of sandstone reservoirs. The continued success of treatments done with modif hydrofluoric acids (HCl/HF) main flush followed by amonium chloride (NH4Cl) pos OnePetro rs several diversion techniques have been applied resulting in improved zonal coverage. These diversion methods can be divided in mech over-balanced drilling. The main parts modelledOnePetro are n of invasive damage. Characterization and quantification of such damage therefore becomes a prerequisite for assessing the value delive uction. A broad description of how these scales form has been available for some time although most experimental findings are still of a qua s viz. for cation composition (EDAX) diffraction patterns (XRD) thermal profi OnePetro eepwater subsea development in the Campos basin Brazil; specifically this paperOnePetro is a ated with oil production and so must be managed. The objective of scale management is to maximise value with respect to the risks to produ oduction. In both cases it is important to evaluate the maximum possible mass fluxes through a perforation. Several models are used in the n of horizontal wells that are drilled at the top of the oil column has improved the OnePetro OnePetro of the Sultanate of Oman to assess the feasibility of steamassisted gas-oil gravity drainage (SAGOGD) EOR. In this field key to a successf ace River offers an excellent growth opportunity for Shell’s ultra-heavy oil portfolio. In support of this initiative integrated geological and ndly manner is a common objective within the producing companies. This philosophy has led to the development and introduction of many in l stack of matrix blocks. The stack is surrounded by fractures where steam is injected at the top and oil recovered from the base of the frac creased by operating at a pressure above the vertical stress of 13 MPa. To improve the understanding of the CSS extraction process Shell reasing numbers of deep water and subsea production systems and High-Temperature-High-Pressure (HTHP) reservoir fluids have elevate have been drilled in and around these reservoirs that in general are high pressure deep and sour. Fluids within the fields range from a retro ations. These fluids dissolve sizeable amounts of calcite and clays and maintain high levels of dissolved metal in solution over time with min value of such innovations.� However it is difficult and expensive to conduct a rigorous field trial especially in tight multi-layered reservoi ervoirs. Even though MHF is becoming a practice for most of the gas reservoirs OnePetro OnePetro mazing increase in activity in the Rocky Mountain region over the past decade is a testament to this.�Currently there are several “tig ght gas discovery for the onshore region of the United States in the last twenty years (Robinson and Shanley 2004). Gas production is from gas producers. However it is these pressures that give the most unambiguous data to identify unique reserves. They help to determine the measurements on samples from low permeability sands. The original" problem of predicting the corrected or "liquid equivalent" permeability ctly evaluate the hydrocarbon reservoir inflow potential. The integrated sub-surface and well design team planning activity execution and re has been produced by sixteen vertical hydraulically fractured wells through a 'Trial Production Operation' (TPO) facility. Shell signed a revis s in the Netherlands section of the Southern North Sea. Underbalanced well design presented specific issues related to the nature of these igenous participation in the exploration and production of hydrocarbon in the NigerOnePetro OnePetro o early development to abandonment. Decisions in all phases of field life cycle depend on the proper use of uncertain information. Shortcom

n the petroleum sector. They need to consider the consequences of their activity OnePetro OnePetro ully tested to 66MMscf/d against 100MMscf/d design potential due to 3rd party barge handling capacity limitation. Production fell far below e ds upon recent work that (1) documents how errors in estimates can bias the selection of design concepts (2) shows how concept flexibility nt has the potential to result in significant improvements in the execution of Shell’s Hydrocarbon Development (HD) and Integrated Re r those carbonate reservoirs with low matrix permeability. The field-development plan and ultimate recovery may be influenced heavily by h measurements for downhole fluid analysis (DFA). DFA involves an in-situ measurement of optical absorption spectra used to compute prope properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to of thin silt and clay beds.� These reservoir sands vary in thickness from millimete OnePetro OnePetro ity images of the subsurface. Following a string of successes with the deployment of CSEM and drilling performance in DW Borneo in 2004 ving to explicitly model them. A comprehensive simulation study tests the sensitivity of dynamic connectivity in turbidite channel reservoirs to verlying shaly formation. Drilling through such depleted reservoirs can cause severe fluid loss and drilling-induced wellbore instability. Accura of analogue hydrocarbon reservoirs. However information from outcrops is commonly limited to static descriptions i.e. reservoir body dime nformation from pre-frac injection tests. This paper extends the theory and practice of ACA to identify the presence of productive natural fra avities several centimeters in size. Flow of fluids through such rocks depends strongly upon the spatial distribution and connectivity of the v ed solely on two-dimensional image analysis of its pore structure. The only required input data are the areas and perimeters of the pores ob lling (UBD) is a powerful driver for implementation of UBD. The mathematical aspects of this complex ill-posed inverse problem have been namic data. Fault-related fractures display a high degree of clustering at several scales. Fracture cluster within fracture corridors and fractur bilistic approach. A fracture corridor is a tabular sub-vertical fault-related fracture swarm which intersects the entire reservoir and extends la opment. Traditional methods of identifying reservoir compartmentalization such as drillstem tests and extended well tests often become im oir compartmentalization for instance can result in non-optimal well placement completion strategy and facilities design as well as large e /gas field. Increasing drilling costs and environmental challenges has led to the development of alternative appraisal approaches that comp onstituted one of the major uncertainties impacting reserves in the cluster. At the onset of the study only two experimental measurements w ptions. Paying insufficient attention to the wetting condition (e.g. assuming water-wet behavior) may result in incorrect oil-in-place estimates

nd and close to liquefied natural gas (LNG) facilities. The current commercial focus on gas raised the significance of the deep gas-bearing s since then the PM301 and PM302 exploration PSCs. The company enjoyed a 100% exploration success rate in the North Malay basin and ent of new technologies to separate CO2 and H2S from highly contaminated natural gas streams. This program has been significantly accel y challenges. In the structurally complex Champi OnePetro al oil rims where only a gas-down-to (GDT) has been logged. Development of these oil rims must be considered as part of the overall hydro way. High-quality time-lapse seismic surveys conducted in 1990 1998 2001 and 2004 have all shown sharp resolution for the areal and ve basin. The field contains some two bln stb of oil in place. First oil was produced in 2004 and peak production is expected in 2012 at over 1

d Enhanced Oil Recovery schemes ‘world-class’ Well and Reservoir Management (WRM) is the foundation of a successful project. A operations sequence of events is to drill c OnePetro ng horizontal wells supported by a strong aquifer and sizeable gas cap. The original zero development strategy called for zero net-voidage o production and efficiency. Using appropriate processes tools and technology OnePetro Particularly in low-mobility reservoirs large fractures may be induced during the field life. This paper presents a new modeling strategy that approximately 700 km northwest of Edmonton (Fig. 1). It holds nearly eight billion barrels of 7�API oil in place spread over 370 km2. The ve been subjected to karstification as demonstrated by sometimes severe drilling losses. Although significant progress has been made map khalin Island off the east coast of mainland Russia. This is a challenging area for exploration and development with 4.5 Billion BOE (675 M covery as has been shown in various studies. However optimal control strategies often lack robustness to geological uncertainties. We pre PDO) Study Center in order to derive a coherent view on the cluster development as well as to write (waterflood) FPDs for the individual fiel ment techniques. Drawing from the experiences of brown fields in the Southern swamp area various techniques were identified to optimize application of water injection-induced multilayer fractured injection into three shallow reservoirs in the Champion Southeast (CPSE) field. F high Gas-Oil Ratio and low production rates. Thus it is important to manage the pressure of reservoir and stabilize it. For this certain IOR te ntly quickly to transfer ever-increasing volumes of conventional natural gas from locations where it is found to where it is consumed in the 21 s of Qatar as well as Shell’s largest equity investment ever. In spite of the various challenges that are intrinsic to a project of this nature he reservoir it ori-ginated from are posing a challenge to the industry. A fundamental question in Produced Water Reinjection (PWRI) is: “ e Water to Oil ratios ranged from <1 to up to 40 depending on maturity of the field with the lowest ratios generally observed in the Middle Ea here is a practical limit to the number of optimization moves an operator can make (due to: changing operating constraints plant disturbanc workflow and procedures adopted to increase oil production by rigless intervention from seven wells on an offshore platform of a brown fiel

nts is driving the need for better decision makingOnePetro assisted history matching) also referred to as ‘real-time reservoir management’ OnePetro OnePetro carbons. The strategy is to inject 300 000 BWPD of seawater from the start of oil production. During the field development in 1999 it was co order to sustain production seawater injection started from the beginning of the oil production at a rate of 300k bwpd. During the field develo uring Produced Water Re-Injection (PWRI). Norske Shell tested nitrate based souring mitigation as part of a PWRI feasibility study in the D as sweetening units in carbon steel pipelines. Sour gas corrosion can lead to pipeline pinhole leaks which pose hazardous consequences to ources was used through 4 dedicated injection wells at a maximum total rate of 4000 m3/d in early 2003. By end of April 2003 the injection process a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly scale treatments comprise t . Thus optimal placement and operation of wells have a major impact on the project rewards. Well-placement in deepwater developments i ervoirs of the Harweel Cluster in South Oman. With the light oil and very high pressure re-injected associated gas is nearly miscible with th pment of new technologies to separate CO2 and H2S from highly contaminated natural gas streams. This program has been significantly ac on and is around halfway in its production life. The field development with water injection and relatively few wells has proved to be very succ with the increase in water cut from various brownfield environments these high angle wells present us with complex reservoir and producti have associated underlying oil rims. Without due consideration to these oil rims regulator approvals to move ahead with the gas projects ma fractured waterflood developments highlighting specific considerations for the Piltun-Astokhskoye field and the harsh and sensit tfolio. The field – located in the Euphrates Graben 45km SE of DeirEzZor - was discovered in 1987 and holds a maximum undersaturated e field. Instead of agressively producing and injecting fluids at maximum rate aiming at large short term profits we are after optimizing the to as injection. As part of a major redevelopment study the scope for water flooding was addressed using 'smart' completions with multiple inflo Demand for LNG in the nearby Asia-Pacific market and availability of a large (18.2 Tcf GIIP) gas resource underpins the investment decisio g values of permeability and porosity to minimize the difference between the observed impedance change and the predicted impedance cha project’s net present value (NPV) as modeled in a reservoir simulator. This paper has two main contributions: first to determine the effe se an analogue model to gain insight into issues of uncertainty in numerical reservoir simulation. Reported in this paper are the initial finding e a reliable uncertainty quantification framework for predicting reservoir dynamic performance requires multiple reservoir models that match orkflows. The underlying algorithm of the framework combines Design of Experiments (DoE) and Markov Chain Monte Carlo (MCMC) infere es. The analysis enables specification of the fluid properties necessary in order for Bingham or Power Law fluids to prevent or reduce conv c fracture growth can lead to largely improved water-management strategies and potentially to increased oil recovery and reduced operati Particularly in low-mobility reservoirs or when injecting contaminated water (e.g. PWRI) large fractures may be induced during the field life. enter of TNO TU Delft and Shell the necessity of taking the interaction between dynamic reservoir and dynamic well behavior into accoun ectiveness of different control strategies a simulation environment can be used. To study and control the effects of for instance slugging ga

es pervade the Exploration and Production (E&P) business. To minimise investment risks robust development plans premised on adequat n on production since 1972 and secondary recovery by treated seawater injection commenced in some reservoirs in 1984.� In this pape oint pressure. However full-field simulations with a sufficiently fine grid will often not be feasible or will require very long computational times polating gas-oil ratio (GOR) commonly used to quantify gas produced with the oi OnePetro mplished with optimized grid point density and minimized number of gridblocks especially for coarse grid generation from a fine grid geologic level of details in a geological model and level of details that can be handled by reservoir simulators. Upscaling reservoir model involves fir ducing both numerical dispersion and homogenization error generated due to incorporating a coarse computational grid and assigning effec ber of grid blocks to be used in the solution of flow equations. However preparing OnePetro n conducted. The main objective of such an effort has been to integrate reservoirs with potential dynamic communication through a single s stribution than conventional statistical and geostatistical techniques allowing the integration of geomechanical data and models into reserv d carbonate reservoir which consists of a fracture swarm system and high matrix permeability. The focus of this paper is on the description method for fractured reservoir simulation. The shape factor determines the fluid and heat transfer between matrix and fractures when there on. The model is applied to two reservoirs with different fluid-flow properties: OnePetro ormance prediction. The development of deep offshore reservoirs is a high risk exercise: in addition to commercial and environmental expos (nonisothermal Buckley-Leverett Problem with tracers). Tracer component is considered OnePetro OnePetro tem Models several simplification options have been investigated so that probabilistic forecasts can be created in significantly less time tha servoir model updating using data from permanent downhole sensors. It is a sequential Monte-Carlo approach that works with an ensemble the basis of the classical Muskat plot. Current methods for estimating average reservoir pressure require a priori information about the rese alculations to simulation studies. The results from a full 3D complex reservoir simulation study comprise a large amount of data. To better ap production commenced in 1972 and production to date is less than 20% of the oil initially in place.� The feasibility of increasing recovery

streamline (SL) screening and finite-difference (FD) flow simulation. The scaleup strategy consisted of (1) maintaining square areal blocks umber of gas storage projects that have been initiated or reached planning/consent stages. This has been largely in response to concerns o us cumulative oil have been published for extrapolating water cut during oil decline the challenges of internal consistency accuracy and lim ulation models however often lack a comprehensive well modeling capability. Such a capability is required to capture the detailed thermal e heterogeneity and wettability have strong impact on capillary pressure (Pc) and relative permeability (Kr) behaviour which is controlled by uction in 2002 it is the first commercial discovery in the Middle Jurassic Lower Safa Reservoir Units in this basin. Oil and gas are produced ctors of ten larger than those measured on cores. Such large dispersivities may represent significant mixing in the reservoir or they may be direction of flow is reversed after the solute slug has penetrated into the medium (bu OnePetro due to the fact that there are minimal amounts of this data acquired during early reservoir life. This data is typically obtained from uniaxial or Gas Oil Gravity Drainage (TAGOGD) is a new and novel thermal EOR technique which has applicability in selected reservoirs. In conventi In such reservoirs one has to rely on recovery mechanisms like capillary imbibition or gravity to recover oil from the reservoir rock matrix. In he high fracture permeability prevents significant pressure differentials across oil bearing matrix blocks leading to negligible oil drive. In such herlands. Steam flooding is the envisaged process. Large volumes of produced water from this field are to be re-injected in regional depl porated into reservoir modeling workflow among the geological community. In this paper a designed simulation method is proposed to mitig y to develop oil sands in-situ is unquestionable. This despite the youth and questions that still surround this technology. �Therefore a rev eld will has gone through three stages of development during its life.� These can be summarized as follows; pressure depletion pressur tions. Especially when the geology is complex and the mobility of the reservoir is low induced fractures can be of the same order as the wel ent contingency planning and emergency response. The blowout rate is a direct measure for the economic and environmental damage cau Smarter.�Participants in the Forum have granted permission to present this paper on the basis that the authors are neither representing t E&P Companies for processes that promise to use real time Information Technology to radically change the way the Oil and Gas business lly has bridged the gap between the drilling and completion disciplines.�The success achieved with openhole gravel packing has created gas resources contaminated with high concentrations of H2S and CO2? This paper traces the history of contaminated gas production and y through stimulation. Major factors limiting the activity in the past include: Various types of reservoirs Mixed success rate Operational diff s likewise world class. The energy industry's drive to invest in enhanced oil recovery from deepwater basins is sustainable in a world of vol s of success of acquiring 4D surveys. The two fields are located within onshore Niger Delta. Agbada field is located on land 100km North W e continuous monitoring for field control. They will increase the range of fields that OnePetro ify the presence of bypassed oil opportunities in mature water-drive reservoirs in an offshore field in Malaysia. A 3D reservoir static model w n the annulus or behind casing) to monitor the fate of injected CO2 for emissions OnePetro OnePetro rvoirs were initially deemed too expensive to develop. �Field development was slow due to reservoir complexity and technology limitation ulic fracturing stimulation diagnostics and well performance evaluation in unconventi OnePetro hydraulic injection fracture lengths angles and heat injectivities into the low-permeability formation. The Phase I pilot is a limited-interval in

m different wells and further infill drilling in a field depend on the effectiveness and the pattern of the production drive mechanism. Whether t leum Development Oman LLC (abbreviated as PDO in the rest of this paper). TheOnePetro u ensive to deal with later. Problems are amplified by reliance on few complex wells with sophisticated sand control media. New downhole da lping to quantify changes in rock and fluid properties along the wellbore to define hydraulic flow units and to understand the reservoir archi aste injection steam flooding and cyclic steam stimulation (CSS). They have been proved to be a very effective way to monitor field operati erburden stress induced by the ocean tide; the “tidal efficiency factor is derived by two different approaches and is in line with a recent w re. Optimum and accurate determination of multiple phase fluid entry requires two primary measurements: 1) holdup or the cross-sectional n and management of hydrocarbon reservoirs. The primary purpose of the Mars (Mississippi Canyon 807) waterflood in the deepwater of th of the associated complex flow regimes that radically change the physics and technology of measurement. Depending on the borehole devia and 1998. Six heaters and one producer were arranged in a single unconfined hexagonal seven spot pattern to test the viability of the Shellâ numerous commercialization attempts from indus OnePetro ses what have been done differently best practices and learning. What is different in this campaign from previous ones? Detailed design gh conventional wells have been applied to drain reservoirs in Niger-Delta extensively in recent years horizontal wells have also gained ac g of phosphonate reactions during inhibitor squeeze treatments has direct implication on how to design and improve scale inhibitor squeeze s) using sequential linear programming (SLP). The optimization algorithm requires instantaneous and derivative information. We propose a d 15 subsea injection wells. Maximizing water injection volume is an important OnePetro OnePetro tions in many areas. It provides the desired flexibility in controlling pressure profile and equivalent circulating density (ECD). However the k even wells with a total of seventeen fracturing treatments in this study are on a multilayered unconsolidated formation where sand control is rac and Pack completions exhibit positive skin values and traditional hydraulic fracture completions show discrepancies between the placed

a Joint Industry Project active since the year 2002. It is well documented in the liteOnePetro onstraints can severely limit oil production and reservoir drive energy. In this paper we will use a coupled reservoir-well model to demonstra e near wellbore matrix thereby reducing gas (and water) coning or eliminating gas leakage to the surface. Experiments at micro- and macro tion of one smart and two problematic conventional long and tortuous horizontal wells in Brunei. Following a detailed hydraulic analysis of ated with surveillance and interventions in horizontal and TAML level 2 multilater OnePetro nsiderably reduce gas mobility. The nature of the gas and the surfactant may influence foaming behavior and thus the efficiency of the foam on the effect of the core heterogeneity. In the frame of the model presented in a parent paper in the conference we assume that the bubble bubble population foam model and provide a detailed experimental validation. We present systematic experiments consisting of the co-injec ids are no longer carried to surface. The liquids accumulate in the well bore increasing the sand face pressure. This further reduces the inf on maximizing gas production from existing wells. In most gas wells water and/or OnePetro tion. Even though virtually all of the world’s gas wells are either at risk of or suffering from liquid loading the modeling of liquid loading b (LEP) technique based on reservoir and well simulation of a typical HVO reservoir e.g. Peace River field and theoretical calculations. The ering software tool to guide and advise them.� It needed to address selecting the optimum perforating system for given well and formatio reservoirs are typified by significant porosity and permeability heterogeneities such that large fluid loss zones are commonly encountered w d improved productivity throughout a well’s lifecycle. This paper discusses the many challenges encountered during the planning and co pproximately 2 650 ft true vertical depth (TVD). An appraisal/early-producer well with a deviated wellbore was drilled through the H1 H2 tar nd contingency fluid-loss control (FLC) pill formulation to withstand 4 600-psi burst resistance pressure. In maturing deepwater fields such nd H2 at approximately 2 650 ft true vertical depth (TVD). An appraisal early-producer well was drilled with a deviated wellbore through the transported to the surface facilities for different operational scenarios. Sand quantification estimation is still novel in the industry and this p ent in the specific case of Lunskoye to minimise risk of failure while maximising prOnePetro OnePetro ake place during the lifetime of a reservoir but they are unable to predict whethe OnePetro OnePetro sure stimulation and gravel-pack fluid leakoff under static conditions. This method details step-by-step procedure for making fluids and mea elds are offshore carbonate reservoirs. The exploitation of these reserves involves drilling horizontal wells for maximizing reservoir contact a g conditions. Particularly when large volumes of very contaminated water are injected –either for voidage replacement or disposal- large f such as G-Function derivative plots after-closure analysis and step-rate tests. ThiOnePetro OnePetro d wells for all angles up to 89.9� extending Cinco’s slant well solution to smaller bed sizes where the line source approximation is no on and improving reservoir characterisation based on utilising the entire well tes OnePetro ervoir potential in un-produced reservoir zones. The well was drilled in a carbonate with variations in rock quality and with minor sub-faulting ells can have serious consequences such as casing failure or tubing collapse. To determine whether mitigation was required for a HP/HT d Sea in the late spring of 2005 (Figure 1 and 2). The well test design and execution is presented in the paper including; up front planning jo ions. Data acquisition in such environments requires reservoir information of the highest quality before expensive development plans can be well head and the test separator. The purpose of this paper is to describe Shell tools and experiences using the resulting real time data to e

hell’s strategy: to expand our alternative energies portfolio while investing in advanced CO2 solutions in order to improve our ability to m .� Shell’s strategy: to expand our alternative energies portfolio while investing in advanced CO2 solutions in order to improve our ab the macrocleats via the microcleats to the coal matrix. Diffusive transport of CO2 in the small cleats is enhanced when the coal is CO2-we porates the swelling of coal matrix by the sorption of CO2 occurs due to coupling of diffusion and relaxation mechanisms. The relaxation pr estration in coal seams suffer a serious setback in terms of injectivity loss resulting from the swelling of coal. Volumetric swelling associated bility. On a unit concentration basis CO2 causes greater degree of coal matrix swelling compared to CH4. Much of this difference is attribut

he injection system management control of the operations and the efficiency of an ECBM project. Although the experience gained by the o ge. The CO2SINK project is a R&D project mainly supported by the European commission the German Federal Ministry of Education and R has entered into a debate about what we can do about it. Therefore as part of Shell’s integrated carbon management plan (which inclu or energy. The development and utilization of technologies to capture and then store CO2 in underground formations offer significant pote These companies have been joined by Aspentech ConocoPhillips Euriware Halliburton InfoSys Invensys Kongsberg Intellifield Matriko leased. The focus was on production optimization processes which could produce results implementable within a day. The domain was from

as large errors in reserves drainage volume and production rate predictions. Characterisation of reservoir fluids based on a single technique ge leading to late diagnosis of production problems and slow and conservative handling of production constraints. FieldWare Production U a problem.� Gathering data even real time data from wells and facilities hasn’t been an issue but validating the data and relating th ologies are increasingly being applied throughout all phases of oil and gas field development and production. Arguably least attention has b

Toyota manufacturing principles.�This is achieved through continuous improvement of processes while minimizing waste. Before implem olume. The term OVT refers to as any testing method that yields fit-for-purpose results at the lowest cost and HSE impact. In more pragma me. This vision was that OVT would be safer less costly and friendlier to the environment but the key impediment to OVT was the concern

ion West field. Results and issues with the component Projects are discussed. The creation of a�“Smart Field team with representa

g. In particular we use optimal control theory in order to find an optimal well management strategy over the life of the reservoir that maxim he three main elements fully integrate technology process and resources. However Smart Fields is not only about automation. It is about gement and development planning. Shell has a programme of technology development and implementation on a global scale to achieve thi achieves a similar drainage pattern to a multilateral well at a fraction of the cost and technical complexity. The wells are completed with mu

gas). These Extended Reach Drilling (ERD) wells are designed as “snake wells penetrating the reservoir several times in order to crea work involved reducing the size of the separator (volume) and modularising the UBD kit by stacking and containerising. As UBD takes a fo a recognition that most of the world’s mature hydrocarbon reservoirs are in the lower end of the depletion cycle and an increasing num as carbon dioxide nitrogen or flue gas is its availability at any location.� HPAI has been successfully applied in the Williston Basin for m e injectivity mechanisms numerical analyses for fracture prediction and geomechanical modeling of the formation to examine the potential ures and/or high salinities.� Surfactant properties measured include oil/water micro-emulsion phase behaviour obtained using new glass s oil bearing matrix blocks to drive oil from matrix rock towards producers. In such reservoirs one has to rely on natural mechanisms like cap it could be a suitable EOR process for onshore light oil fields in Australia; no evaluation has been conducted to date. Using open file data to help decide on how to optimally blend available gas such that miscibility can be achieved in all reservoirs with appropriate focus on the fi hysics into a flow simulator. Foam displacement is examined in layered reservoirs with and without isolating shale barrier between the layers integrated to precisely model gas injection EOR. This workflow can be adaptable for any type of reservoir and can be utilized as a fast-trac

normal steam flood the steam is used as a heating agent to enhance the existing gravity drainage mechanisms and project has proved to

s in both sandstone and carbonate reservoirs and in combination with follow-up EOR projects. The following results were found: (1) Forma ss while the less-fractured lower set of layers is subjected to waterflooding. The production from the GOGD layers is through vertical and ho uction logging tool (PLT) surveys combined with a reservoir study showed that good-quality sands were not properly swept by the water pr f infill wells required for field development. However they come with a disadvantage in regard to carrying out a successful intervention when matrix shutoff in openhole or perforated completions. The PG system can be considered as an alternative to standard cement squeeze oper : First the dense fracturing frustrates an efficient waterflood; second because of the oil-wetness the water pressure exceeds the oil pressu developed as satellite to the main facilities. Analysing the entire upstream supply chain in an integrated manner compared to looking at th DGM) with local global and multi-start search options for non-convex and non-smooth gas lift production optimization. Results of numerical enormous technical challenges. Flow Assurance encompasses a broad range of technical areas including management of solids such as h 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 œvanishing interfacial tension (VIT) has been developed to determine gas-oil miscibility based on the fundamental definition of zero gas-o re (PVT) Data of Gas associated with Nigerian Crude oil. The study was divided into parts. The first part covered a pressure range of 144 ps

o an NGL or GTL facility because even a tiny amount of H2S may dictate a prohibitively expensive upgrade. Detecting the presence of H2S large and mistakes are costly. Compositional grading has been known for over 50 years but the topic received little attention until the 1980 d samples from openhole logging help operators optimize investment in both upstream and downstream facilities. When a formation fluid s ass of compounds in crude oils defined in solubility terms that under certain conditions are known to precipitate and deposit. This may lead 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 the experimental studies on IFT and contact angles have been conducted at ambient conditions and using stock tank crude oils. In this stu

ccess of treatments done with modified HF systems in this area are due to its ability to mitigate the rapid spending of the active acid with cla

ion methods can be divided in mechanical methods such as the use of balls to seal the perforations and chemical methods such as gelled f

uisite for assessing the value delivered by UBD. Several methods are available to quantify damage. In this work we use a novel approach perimental findings are still of a qualitative nature. In this paper we present an equilibrium thermodynamic model for predicting naphthenat

alue with respect to the risks to production from scale balanced against the cost downtime and potential damage from any treatment. Chem on. Several models are used in the oil industry for this purpose e.g. Ashford (1974) [1] Sachdeva et al. (1984) [2] and Perkins (1993) [3].

EOR. In this field key to a successful SAGOGD is a well-connected fracture network which was investigated by a dedicated appraisal cam s initiative integrated geological and reservoir modeling of two project areas was conducted. The key objectives were to improve predictive elopment and introduction of many innovative technologies and strategies into the oil and gas industries. The need to improve brown field p recovered from the base of the fracture system. We compare fine-grid single-porosity simulations with coarse-grid dual-permeability simul f the CSS extraction process Shell Canada designed and implemented a monitoring program over the most recently drilled production pad HTHP) reservoir fluids have elevated the importance of fluid properties. Like rock properties fluid properties can vary significantly both aeri s within the fields range from a retrograde gas condensate to light oil. The stringers are geologically heterogeneous and commonly have low d metal in solution over time with minimal precipitation. A series of field samples from high-temperature (149�C) sandstone reservoirs in a ecially in tight multi-layered reservoirs and proper design and analyses are critical to accurately interpret the results. �In multi-layered res

½Currently there are several “tight gas plays in the U.S. that involve the commingling of multiple intervals in order to gain economic via anley 2004). Gas production is from very tight stacked clastic reservoirs that are Upper Cretaceous in age with productive intervals in exce serves. They help to determine the drainage areas as well as appropriate well spacing for tight gas reservoirs. A 4D pressure pilot was des d or "liquid equivalent" permeability (i.e. referred to as the Klinkenberg-corrected permeability) has been under investigation since the early m planning activity execution and results are discussed with an assessment of the added value realized. The lessons learnt will be used to n' (TPO) facility. Shell signed a revised development PSC with PetroChina in 2005 and is the first IOC having production operation in the Or ssues related to the nature of these reservoirs. The construction and production experience to date is evaluated and compared against simi

e of uncertain information. Shortcomings in uncertainty management are primarily a problem of organizing work processes providing acces

imitation. Production fell far below expectation when the well was hooked-up to the gas plant with maximum production of 20MMscf/d at 10 pts (2) shows how concept flexibility can improve the project performance and (3) usefully illustrates the probability distribution of outcome evelopment (HD) and Integrated Reservoir Management (IRM) global processes in Shell’s Deepwater Gulf of Mexico fields.�The so very may be influenced heavily by how much oil can be recovered from the transition zone. This in turn depends on a number of geological tion spectra used to compute properties such as hydrocarbon composition and gas/oil ratio (GOR). Abrupt changes in these fluid properties oir fluids enables sealing barriers to be proved and compositional grading to be quantified; this information cannot be obtained from conven

performance in DW Borneo in 2004 CSEM data was acquired over a number of similar structures in 2006. Proprietary inversion techniques ivity in turbidite channel reservoirs to a large number of stratigraphic and engineering parameters. Simulations performed using geologically g-induced wellbore instability. Accurate and reliable estimates of horizontal stresses can provide an early warning of impending drilling probl escriptions i.e. reservoir body dimension and geometry. Figure 1 Permo-Triassic Section exposed at Jebel Al Akhdar. Visible is a large-sca e presence of productive natural fractures. Natural fractures are important to identify before conducting a stimulation treatment because th distribution and connectivity of the vugs. Enhanced oil recovery processes such as enriched gas drives and groundwater remediation efforts reas and perimeters of the pores observed in for example an SEM image. The hydraulic radius approximation is used to estimate the indiv l-posed inverse problem have been the subject of research in the past decade. This paper focuses on practical field implementation of UB within fracture corridors and fracture corridors are clustered within fracture fairways which are overall equivalent to fault zones. We compa s the entire reservoir and extends laterally for several tens or hundreds of meters.� The only direct indicator of fracture corridors are bore extended well tests often become impractical in deepwater settings with costs approaching the costs of new wells and emissions becoming nd facilities design as well as large errors in reserves drainage volume and production rate predictions. Downhole fluid analysis along with c ive appraisal approaches that compliment the more costly and traditional methods such as the drill stem or production test. Therefore the c y two experimental measurements were available that had been acquired with the currently recommended approach of wettability restoratio ult in incorrect oil-in-place estimates and in unexpected dynamic behavior (e.g. under-waterflooding). A novel method is presented to deter

gnificance of the deep gas-bearing sequence which was first identified in 1983. It took another 20+ years before the full potential of the Uppe ss rate in the North Malay basin and is now rapidly transitioning into a development venture.� A total of six discoveries were made since program has been significantly accelerated in recent years and major milestones have been achieved. The program focuses on technology

nsidered as part of the overall hydrocarbon maturation plans for the reservoir. Maturation studies of this type can take a long time and may sharp resolution for the areal and vertical definition of the water movement toward the producing wells. Excellent reservoir properties with r uction is expected in 2012 at over 100 000 stb per day. Whilst the field is in an early development stage it is crucial that reservoir managem

foundation of a successful project. A comprehensive WRM plan was defined for Bonga very early in the project and its implementation from

trategy called for zero net-voidage of gas through re-injection of produced gas into the gas cap. A full gas cap blowdown is currently being

sents a new modeling strategy that combines fluid-flow and fracture-growth (fully coupled) within the framework of an existing ‘standardâ in place spread over 370 km2. The Carmon Creek Project targets possibly about half of that oil for development by cyclic steam stimulation icant progress has been made mapping and predicting these karstification features on seismic there is quite some uncertainty left on the e opment with 4.5 Billion BOE (675 Million tonnes oil equivalent) of oil and gas in place. This paper will outline how new technologies have as s to geological uncertainties. We present an approach to reduce the effect of geological uncertainties in the field-development phase known aterflood) FPDs for the individual fields. The study combined conventional and state-of-the-art workflows and was conducted by a large integ chniques were identified to optimize the value of a project aimed at further development of the field; these include phased development fo Champion Southeast (CPSE) field. Fractured water injection means that the bottomhole injection pressure is allowed to exceed the formatio d stabilize it. For this certain IOR techniques are employed; waterflooding being one of them. This paper discusses waterflooding as a solu nd to where it is consumed in the 21st century and for how long? On a world scale the crucial question for now is not how much gas there re intrinsic to a project of this nature Shell and Qatar Petroleum are confident in their ability to manage construction successfully. Pearl GT ed Water Reinjection (PWRI) is: “How clean is clean ? or perhaps even more succinct : “How clean is fit for purpose ? There is no generally observed in the Middle East. In this paper average volumes of produced water worldwide per nations and per companies are pre erating constraints plant disturbances or interactions fundamental process delays and dynamics and the remoteness of wells).� Autom an offshore platform of a brown field located off the west coast of India. The field under study was discovered in 1987 and put on product

field development in 1999 it was concluded that Bonga was expected to suffer from reservoir souring and that mitigation would be necessa of 300k bwpd. During the field development it was concluded that seawater injection in Bonga would result in reservoir souring and that miti of a PWRI feasibility study in the Draugen field. Prior to the pilot the application of both nitrite and nitrate had been tested on Draugen usin h pose hazardous consequences to people wild life and pollution to the environment. Corrosion is usually controlled through chemical inhib 03. By end of April 2003 the injection water source was switched to produce water and separated at in line separator. The production wells mmonly scale treatments comprise the following stages: preflush main scale inhibitor pill overflush tubing displacement and shut-in follow ement in deepwater developments is a challenging optimization problem. Manual approaches to its solution can be cumbersome even with ociated gas is nearly miscible with the reservoir oils. A program of study was planned to coincide with further appraisal and bringing some of is program has been significantly accelerated in recent years and major milestones have been achieved. The program focuses on technolo few wells has proved to be very successful. This paper shows how well and reservoir surveillance has been set-up in the Draugen field. Inte with complex reservoir and production management challenges. Fit for purpose production logging technology is helping to provide a better move ahead with the gas projects may be delayed and can erode project value. In order to optimize the development of both oil and gas hy and the harsh and sensit nd holds a maximum undersaturated oil column of more than 500m with two original oil-water contacts of 3750 and 3778 meters subsea. Th profits we are after optimizing the total value (e.g. discounted oil volume) over the whole lifecycle of the field. An essential tool in tackling th smart' completions with multiple inflow control valves (ICVs) in the wells to be drilled for the redevelopment. Optimal control theory was used rce underpins the investment decision in a challenging offshore environment. Robust suites of seismically-constrained integrated reservoir ge and the predicted impedance change while remaining as close as possible to the initial geological model. To perform the history matchin tributions: first to determine the effect of production constraints on optimal well locations and second to determine optimal well locations u ed in this paper are the initial findings from history matching the production response of an Analogue Reservoir Model (ARM) and its numeri multiple reservoir models that match field production data. It has been previously demonstrated that the ensemble Kalman filter technique c v Chain Monte Carlo (MCMC) inference techniques. A generic singular-value decomposition technique creates a Response Surface Model Law fluids to prevent or reduce convection and thus minimize Wellbore heat transfer. The paper gives the analytical convective heat transfe sed oil recovery and reduced operational costs (well-count and water-treatment-facilities reduction) thereby enhancing the project economic may be induced during the field life. This paper presents a new modeling strategy that combines fluid-flow and fracture-growth (fully couple d dynamic well behavior into account when optimizing a producing asset is investigated. To simulate dynamic phenomena in the well and in e effects of for instance slugging gas coning and wax deposition both reservoir dynamics and the dynamics of multi-phase well flow have

opment plans premised on adequate understanding of uncertainties are critical. Experimental Design (ED) complemented with Response reservoirs in 1984.� In this paper we present an analytical approach for estimating relative permeability end-points from production/injec equire very long computational times. A semianalytical method has been developed that can be used to predict the gas- and condensate-pr

generation from a fine grid geological model. In any coarse grid generation proper distribution of grid points which form basis of numerica pscaling reservoir model involves first constructing a coarse grid by employing gridding algorithms and then computing average properties f mputational grid and assigning effective permeability to coarse grid blocks respectively. In particular we consider implicit-pressure explicit-sa

c communication through a single sensible initialization model in the simulator. In the past some of these reservoirs were modeled stand al hanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagat us of this paper is on the description of the dynamic single-media model that was used to history match the production. The challenges in pr een matrix and fractures when there is a difference in pressure or temperature between matrix blocks and the surrounding fractures. An ap

ommercial and environmental exposure the sparsity of early exploration data compounds with the inherent geological complexity of turbidit

created in significantly less time than running many iterations around a full model. This was achieved through smart model simplification i. proach that works with an ensemble of reservoir models. Specifically the method utilizes cross-covariances between measurements and m re a priori information about the reservoir and assume homogeneous reservoir properties or use empirical extrapolation techniques. The ne a large amount of data. To better appreciate the result of the calculations simulation packages make use of various visualization tools such The feasibility of increasing recovery through a major waterflooding programme is currently under evaluation. Potential incremental oil recov

(1) maintaining square areal blocks over the oil column (2) upscaling to the largest areal-block size (200 x 200 m) compatible with 125-acre en largely in response to concerns over the security of gas supply in a market where indigenous gas production is declining at the same tim nternal consistency accuracy and limited areas of application have remained unresolved. These make the application of the methods threa red to capture the detailed thermal effects that occur in the wellbore. These effects can be important as they impact wellbore pressure and r) behaviour which is controlled by the pore size distribution interfacial tension and interactions between rock and fluids as well as the satu this basin. Oil and gas are produced from the tidally influenced estuary channel deposits in the Lower Safa A Unit and oil from the massive ixing in the reservoir or they may be a result of convective spreading driven by permeability heterogeneity. The work in this paper uses the i

is typically obtained from uniaxial or hydrostatic tests using conventional core acquired during the appraisal phase of the reservoir. This artic ty in selected reservoirs. In conventional isothermal GOGD vertical fractures cause the gas-oil contact in the fracture system to advance ah oil from the reservoir rock matrix. In oil-wet or mixed-wet fractured carbonates only gravity drainage remains a feasible process. However lo eading to negligible oil drive. In such reservoirs one has to rely on natural mechanisms like capillary imbibition or gravity to recover oil from re to be re-injected in regional depleted Zechstein fractured carbonate gas fields. Estimates of injection rates and volumes are required fo mulation method is proposed to mitigate reservoir connectivity uncertainty. This proposed method is more accurate and efficient by integrati his technology. �Therefore a review of most of the existing operations in Canada has been undertaken (32 pads in 8 different operations follows; pressure depletion pressure maintenance with sour separator gas plus sweet make-up re-injection pressure maintenance with sou can be of the same order as the well spacing which has a significant (in general undesired) impact on both areal sweep and vertical confor omic and environmental damage caused by a blowout and an indicator for the effort required to regain control over the well. Hence a simula he authors are neither representing the views of the SPE nor of the participants’ companies. We are delivering smarter fields in order ge the way the Oil and Gas business is run and is so doing enable significant business benefit. The Digital Oil Field(DOF) has been the sub penhole gravel packing has created a mainstay completion technique that has been used in deepwater developments in Brazil and West Af of contaminated gas production and explores the reasons why it has now become a focus for many countries. The paper also addresses th Mixed success rate Operational difficulties Cost structure: coil tubing cost overruns the overall stimulation cost Weather conditions. Stimu asins is sustainable in a world of volatile oil prices and increasing demand for energy. However project economics will continue to depend o d is located on land 100km North West of Port Harcourt Nigeria. The field was discovered in 1960 and has been producing since 1965. To

laysia. A 3D reservoir static model was first built as part of the geological review. Reservoir performance review was carried out in conjunct

complexity and technology limitations.�� The current phase of development of the Champion West reservoirs uses long horizontal sna

e Phase I pilot is a limited-interval injection test. In Phase II steam is injected into two 350-ft upper and lower zones through separate hydra

duction drive mechanism. Whether the reservoir displays partial aquifer influx or is waterflooded the flow profile of produced/injected water

nd control media. New downhole data is required for better understanding and prevention of completion and formation damage. We introdu nd to understand the reservoir architecture. They are being used routinely in a wide range of applications spanning pressure and mobility p effective way to monitor field operations and save money for operators wishing to avoid unwanted surface breeches casing failures and ex roaches and is in line with a recent well test in the Ormen Lange gas field. For small geomechanical pertubations like the tidal effect we sh 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 07) waterflood in the deepwater of the GOM is to increase recovery efficiency in three main reservoirs. In addition the waterflood helps main nt. Depending on the borehole deviation the velocity and fluid holdup of different phases can change dramatically for a given flow rate. In ttern to test the viability of the Shell’s proprietary in-situ conversion process (ICP) in oil shale under field conditions and to substantiate

om previous ones? Detailed design Detailed well-by-well review for first round candidate selection. Fundamental data collection (well data horizontal wells have also gained acceptance as a proven reservoir management and well completion method. Production improvement fac and improve scale inhibitor squeeze treatments for optimum scale control. Putting various amounts of metal ions in the inhibitor pill adds an erivative information. We propose a workflow in which the production engineer relies on measurements to determine the flow rate and press

ating density (ECD). However the knowledge of rheology and hydraulics of polymer-thickened foams is still limited. This paper summarizes ated formation where sand control is a part of well management during the production life of the wells. Previous techniques of open hole ex w discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited

d reservoir-well model to demonstrate that oil production can be increased by using controlled inflow from a gas cone as a natural lift.� Th ce. Experiments at micro- and macro-scale levels were performed to: a) provide a detailed understanding of emulsion flow and blocking me wing a detailed hydraulic analysis of these wells a good match with field measurements was obtained. Simulation results show that the pro

r and thus the efficiency of the foam. In this paper an experimental study of the behavior of CO2 and N2 foams in granular porous media us nference we assume that the bubble generation kinetics is dependent on layer permeability. We present experiments consisting of co-inject xperiments consisting of the co-injection of N2 gas and surfactant solution in homogenous sandstone cores varying the liquid and gas injec ressure. This further reduces the inflow so that more liquid collects and eventually the flow dies down completely.� This phenomenon is

ding the modeling of liquid loading behavior is still quite immature and the prediction of the minimum stable gas rate not very reliable. Many eld and theoretical calculations. The issues that are primarily covered in the LEP simulation work address the comparison of horizontal LEP g system for given well and formation properties and work at log resolution to eliminate problems experienced with existing packages that u zones are commonly encountered while drilling the reservoir section.� The drilling strategy for the subsea development wells called for th ountered during the planning and completion of two wells in the Egret Field in Brunei operated by Brunei Shell Petroleum (BSP) how the c e was drilled through the H1 H2 targets and a completion design consisting of a cased and perforated commingled completion inside 9-5/ In maturing deepwater fields such as Shell Ursa/Princess where depleted reservoir pressures are significantly below the hydrostatic press with a deviated wellbore through the H1/H2 targets and a completion design consisting of a cased perforated and commingled completion s still novel in the industry and this paper describes its application in completion selection and design facilities design and operation and fa

procedure for making fluids and measuring leakoff under static conditions. Stimulation and gravel-pack fluids are defined for the purpose of s for maximizing reservoir contact and hydrocarbon drainage. Many of these wells experience drilling mud damage. One of the challenges age replacement or disposal- large fractures may be induced over time. Unfortunately not much work has been carried out to date to provid

e the line source approximation is not a valid assumption. The second objective of this paper is to extend the slant well solution to layered re

ck quality and with minor sub-faulting occurring. Gamma Resistivity Density Neutron and Image services were used in the horizontal part itigation was required for a HP/HT development annular pressures in an appraisal well were studied with a dedicated field test which cons aper including; up front planning job design technology selection and review of the test results vs. the objectives for the well test. The pap expensive development plans can be put in place. New technology real time monitoring and integrated reservoir data are essential to under sing the resulting real time data to enable well test optimization and automation. 1.0 Introduction The purpose of well testing is to period

ns in order to improve our ability to manage emissions from our hydrocarbon business. Measures to manage future emissions will include d solutions in order to improve our ability to manage emissions from our hydrocarbon business. Measures to manage future emissions will inc enhanced when the coal is CO2-wet. Indeed for water-wet conditions the small fracture system is filled with water and the rate of CO2 sor ation mechanisms. The relaxation process is related to the transition of coal from glassy to a rubbery state i.e. to swelled coal. For reasons coal. Volumetric swelling associated with CO2 sorption on coal has a significant influence on the fracture porosity and permeability of the c H4. Much of this difference is attributable to the differing sorption capacity that coal has towards carbon dioxide and methane. This condition

ugh the experience gained by the oil industry represents a valuable starting point several problems are still to be studied and solved before Federal Ministry of Education and Research and the German Federal Ministry of Economics and Technology targeted at developing an in arbon management plan (which includes renewable energy sources and fossil fuel efficiency improvements) we are currently investigating s und formations offer significant potential for reducing CO2 emissions. This paper is based on the outcomes of an IPIECA workshop to adv ensys Kongsberg Intellifield Matrikon OSISoft P2ES Pioneer Petroleum Experts Schlumberger TietoEnator and Weatherford. Energisti e within a day. The domain was from perforations through to start of processing on the surface.� The objective was to enable plug and p

ir fluids based on a single technique or technology such as mud-gas logging wireline logging PVT or wellsite chemistry is standard in mos constraints. FieldWare Production Universe (FW PU) is a software application developed by Shell International Exploration & Production an ut validating the data and relating this data to individual well production rates in a coherent consistent and timely manner and then taking pr ction. Arguably least attention has been given to asset operations where the rewards are actually harvested. “Smart technologies can

le minimizing waste. Before implementation an assessment of the pilot asset revealed fragmented efforts and inefficient collaboration betw st and HSE impact. In more pragmatic terms an OVT is any pressure transient test in which live hydrocarbons do not have to be produced mpediment to OVT was the concern that the quality of the results might be inadequate for the difficult development decisions that we face.

œSmart Field team with representation from Petroleum Engineering Well Engineering IT Control and Automation Data Management/Ap

er the life of the reservoir that maximizes an objective function (e.g. recovery or net present value). Optimal control requires the determinat ot only about automation. It is about making available the three key ingredients needed to efficiently operate any piece of equipment: reliable tion on a global scale to achieve this vision. Introduction Shell has implemented Smart Fields� concepts in several fields around the wor ty. The wells are completed with multiple hydraulically controlled interval control valves (ICV) and external casing packers or swellable pack

ervoir several times in order to create multiple drainage points snake well develop oil rim reservoirs. All the wells are of different horizontal d containerising. As UBD takes a foothold in low-cost operating areas Shell has actively looked at ways to not only reduce the footprint but pletion cycle and an increasing number of horizontal wells are left with un-cemented completions. In addition to access new untapped rese y applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their asset formation to examine the potential of shear failure and containment loss during flooding. Laboratory tests under polyaxial conditions indica behaviour obtained using new glassware-based procedures appropriate for higher reservoir temperatures.� The results obtained relate to rely on natural mechanisms like capillary imbibition or gravity to recover oil from the matrix reservoir rock. In Middle-East fractured carbonat ucted to date. Using open file data high level screening criteria are used in this study to identify prospective petroleum basins and an indiv voirs with appropriate focus on the first reservoirs to be flooded. These studies have resulted in an investment decision to undertake a misci ing shale barrier between the layers and in stochastically distributed permeability fields. It is demonstrated that in isolated layers foam prop oir and can be utilized as a fast-track screening workflow for gas injection EOR. The target for this study was the Gyda reservoir located in

hanisms and project has proved to be viable based on encouraging pilot results. The elegance of the thermally assisted - GOGD is that the

owing results were found: (1) Formation water with higher salinity level correlates to a higher content of multivalent cations. This causes the OGD layers is through vertical and horizontal wells completed in a thin fracture oil rim. Gas conformance control is a challenge in many of the e not properly swept by the water probably because of poor connectivity in the reservoir.�It was anticipated that these unswept sands cou g out a successful intervention when water break through occurs. Water breakthrough and high basic sediments and water (BS&W) are pr e to standard cement squeeze operations repairing casing leaks sealing off thief zones and addressing lost-circulation zones. The OCP s ater pressure exceeds the oil pressure inside the matrix blocks thus inhibiting spontaneous imbibition of water. In the past decade using a d manner compared to looking at the individual elements is becoming increasingly important in the current business because the system n optimization. Results of numerical experiments with published petroleum industry test problems show that the four variants of DGM are ca ing management of solids such as hydrates wax asphaltenes to avoid blockages in subsea equipment and multiphase transport of produc 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 undamental definition of zero gas-oil interfacial tension (IFT) at miscibility. In this study gas-oil interfacial tensions were measured between covered a pressure range of 144 psia to 4100 psi and a temperature range of 130oF – 220oF. The second part consist of the study of N

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 eceived little attention until the 1980’s when sufficiently advanced analytical methods became available to assess the phenomenon. Ind m facilities. When a formation fluid sample is taken from a well drilled with oil-based mud (OBM) sample contamination by the OBM filtrate ecipitate and deposit. This may lead to very expensive remediation and treatment operations. Over the years much research has been carrie es in which submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy-oil production systems sing stock tank crude oils. In this study live and stock-tank crude oils have been used at reservoir conditions to make IFT and dynamic con

d spending of the active acid with clays and silicates; prevent matrix unconsolidation in the near wellbore region and the subsequent precipit

d chemical methods such as gelled fluids. In the design of matrix acid treatments placement models that predict the zonal coverage of the

his work we use a novel approach that combines dynamic microscale reservoir simulations calibrated to special core tests to model the ex mic model for predicting naphthenate partitioning and precipitation in an oil/brine immiscible system from some chosen initial conditions (i.e.

al damage from any treatment. Chemical treatments to mitigate against scale and to dissolve scale are frequently applied and costly. Shell U . (1984) [2] and Perkins (1993) [3]. This paper explains physical principles behind these theories and outlines their range of applicability. T

igated by a dedicated appraisal campaign which included drilling one vertical and 3 near-horizontal wells. BHI sonic and resistivity logs wer jectives were to improve predictive modeling capability of cyclic steam stimulation (CSS) projects by history matching two groups of CSS m . The need to improve brown field productivity has given birth to many innovative technologies such as short-medium radius drilling 4D sei coarse-grid dual-permeability simulations (where the matrix-fracture interaction is modelled via shape-factors). We independently validate t most recently drilled production pads. This program included microseismic surface time-lapse seismic (2D and sparse 3D) a time-lapse 3D erties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper we have studied the effects of gr erogeneous and commonly have low permeability. They are being developed in a phased manner that will involve miscible gas injection. Th 149�C) sandstone reservoirs in a West African formation bear carbonate concentrations ranging from 2% to 37% (w/w). The effects of m et the results. �In multi-layered reservoirs the production from individual frac stages must often be evaluated with production logs - this ad

tervals in order to gain economic viability.�The Pinedale Anticline of southwestern Wyoming is one of these areas. The Pinedale Anticlin age with productive intervals in excess of 6000 feet. The large productive intervals require multiple hydraulic fracture stages to complete. T ervoirs. A 4D pressure pilot was designed and installed to measure pressure drop at two observation wells equipped with pressure gauges. n under investigation since the early 1940s — in particular using the application of "gas slippage" theory to petrophysics by Klinkenberg.1 ed. The lessons learnt will be used to optimize the subsequent exploration and appraisal drilling activities and in the longer term optimizatio aving production operation in the Ordos Basin the second largest Basin in China. The main reservoir is a thin and fairly complex braided ch valuated and compared against similar wells drilled offshore UK. Also the benefits of the underbalanced horizontal well concept are reviewe

ing work processes providing access to consistent information and managing projects across organizational boundaries. A key critical succ

mum production of 20MMscf/d at 100% maximum choke opening. This necessitated a workover to replace suspected faulty Tr-ScSSSV. Th e probability distribution of outcomes. It involves: (1) developing and evaluating a base case design (2) exploring the outcomes this design ter Gulf of Mexico fields.�The solution embodies technology enablers (Scenario and Options Evaluation Decision Support Systems Co depends on a number of geological and petrophysical properties that influence the distribution of initial oil saturation (Sor) against depth an upt changes in these fluid properties with depth may be markers for reservoir compartmentalization. However hydrocarbon differences can ion cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy which can prov

006. Proprietary inversion techniques indicated the possible presence of a shallow surface resistive body while hinting at the presence of sl lations performed using geologically realistic sector models at multiple levels of stratigraphic resolution show that dynamic connectivity is go y warning of impending drilling problems that may be mitigated by appropriate drilling fluid design and drilling practices. We have developed ebel Al Akhdar. Visible is a large-scale layer cake-type carbonate ramp made up of thin but laterally extensive units. The formation has been a stimulation treatment because their presence may require designs that differ from conventional matrix treatments. Literature shows that n and groundwater remediation efforts like soil venting operations depend on the amount of hydrodynamic dispersion of such rocks. Selecting imation is used to estimate the individual pore conductances. Prior to this stereological corrections are used to convert apparent pore geom practical field implementation of UBD reservoir characterization and the problems that consequently arise. Interpretation of data from UBD equivalent to fault zones. We compared the location and spacing of fracture fairways from image logs with seismic faults and lineaments an dicator of fracture corridors are borehole image logs. Unlike openhole logs and other borehole measurements image logs are available onl new wells and emissions becoming increasingly undesirable. Thus compartments often have to be identified by some other means. Indiv Downhole fluid analysis along with complementary techniques including geochemical mud-gas and pressure analyses provide valuable ins m or production test. Therefore the challenge of obtaining sufficient reservoir and fluid data from complex wells in short time frames and at ed approach of wettability restoration and a combination of steady state and centrifuge experiments. Therefore the team proposed to core A novel method is presented to determine the wettability of rocks from nuclear-magnetic-resonance (NMR) data. The method is based on th

s before the full potential of the Upper Miocene (TB3.1-TB3.3) sequence in this area became apparent as part of the evaluation of the deep of six discoveries were made since 2002 within the PM301 block. The nature of these discoveries: modest size stacked pay fluvio-marine he program focuses on technology solutions that are critical to develop (stranded) contaminated hydrocarbon gas and oil fields. Several ke

type can take a long time and may lead to restrictions on the availability (quantity and timing) of the gas volumes to the market. This poses Excellent reservoir properties with relatively few high-rate wells and an expected recovery factor exceeding 60% make Draugen one of the it is crucial that reservoir management and data acquisition processes are put in place to allow efficient future field development and optim

project and its implementation from start-up has demonstrated tremendous value. More than 220 MMstb have been produced as of Marc

as cap blowdown is currently being planned to commence in 2008. In order to predict field behaviour in this high production rate environme

mework of an existing ‘standard’ reservoir simulator. We demonstrate the coupled simulator by applications to five-spot pattern flood elopment by cyclic steam stimulation (CSS). There are growth plans for a significant increase in oil production over the next five years. The quite some uncertainty left on the exact size and occurrence of these features. Furthermore there is little known about the impact of karstifi utline how new technologies have assessed and realized the Project’s potential. Integrated Reservoir Modeling utilizing modern seismi the field-development phase known as robust optimization (RO). RO uses a set of realizations that reflect the range of possible geological and was conducted by a large integrated team over a period of three years. The study was conducted in four phases: screening full field m ese include phased development focus on areas of highest potential implementation of reservoir surveillance accelerated production lowe re is allowed to exceed the formation’s fracture pressure. Thereby an unpropped fracture is created which propagates depending on th er discusses waterflooding as a solution for a pressure management program. This work represents results of the strategic IOR program in for now is not how much gas there is overall but the transport capacity linking regions with high gas resources to regions with a high consu construction successfully. Pearl GTL is a fully integrated upstream/downstream world-scale project in Ras Laffan Industrial City 80 km nor lean is fit for purpose ? There is no universal correct answer to this question as it depends on specific variables largely intrinsic properties r nations and per companies are presented a case for change in management of produced water is made Shell’s integrated water ma he remoteness of wells).� Automatic Process Control enhances the speed and accuracy with which decisions can be made and is essen covered in 1987 and put on production in 1994. The main reservoir is Middle Eocene carbonate deposit which is characterized by the prese

and that mitigation would be necessary. Initial data gathering indicated that the H2S content resulting from reservoir souring was not expect ult in reservoir souring and that mitigation was necessary. Initially the selected strategy for Bonga seawater injection was to control reservo ate had been tested on Draugen using a Souring Mitigation Cabinet (SMC) specially developed to mimic the microbial activity in the near we ally controlled through chemical inhibition in combination with frequent batching and pigging programs. In the presence of elemental sulphur ine separator. The production wells suddenly turned to produced high H2S while the well injectivity decline around 50% and levels have ca ng displacement and shut-in followed by back-production of the well. For some years the industry has applied mutual solvent chemicals in tion can be cumbersome even with good use of engineering judgment: (a) There often exist many combinations of well locations subject to ther appraisal and bringing some of the reservoirs onto production. After five years of study and simultaneously three years of development d. The program focuses on technology solutions that are critical to develop (stranded) contaminated hydrocarbon gas and oil fields. Severa een set-up in the Draugen field. Interesting features of this set-up are Structured and automatic data integration. Information providers for hnology is helping to provide a better understanding of fluid movement enabling higher confidence decision making leading to successful in development of both oil and gas hydrocarbon resources a novel concurrent oil and gas development concept is proposed. In this concept

f 3750 and 3778 meters subsea. The oil production almost exclusively originates from two sandstone formations: the Cretaceous sheet-like field. An essential tool in tackling this optimization problem is the adjoint method from optimal control theory. Starting from a base case res ent. Optimal control theory was used to optimize monetary value over the remaining producing life of the field and in particular to select the ally-constrained integrated reservoir models were generated to evaluate short- medium- and long-term subsurface uncertainties. Previous q odel. To perform the history matching efficiently an adjoint method is used to compute the gradient of the data mismatch and a quasi-Newto o determine optimal well locations using a gradient-based optimization method. Our approach is based on the concept of surrounding the w eservoir Model (ARM) and its numerical representation in a finite difference simulation model. The ARM is a large-scale physical model com ensemble Kalman filter technique can be used for this purpose. In this technique an ensemble of reservoir models is evolved by means of creates a Response Surface Model (RSM) from a DoE-based selection of simulations. Ensuing RSM serves as a rapid proxy to full-physics e analytical convective heat transfer flow solution for the Bingham material and Power Law fluids and uses this to determine example Nuss eby enhancing the project economics. The primary tool that reservoir engineers require to guarantee an optimal waterflood field implement ow and fracture-growth (fully coupled) within the framework of an existing ‘standard’ reservoir simulator. We demonstrate the couple amic phenomena in the well and in the reservoir a dynamic multiphase well simulation tool (OLGA) and a dynamic multiphase reservoir sim amics of multi-phase well flow have to be taken into account in such a simulation environment. In this paper we use a dynamic coupled well

ED) complemented with Response Surface Method (RSM) which uses a statistical proxy equation to model the response (dependent varia ility end-points from production/injection data as a starting point for sensitivity studies on the applicability and value of expanding water floo predict the gas- and condensate-production rates from such wells accurately and that has some advantages over the pseudopressure app

points which form basis of numerical gridblocks is a challenging task. We show that this can be effectively achieved by generating a backg hen computing average properties for coarse grid blocks. Although various techniques have been proposed for each of these steps one ha consider implicit-pressure explicit-saturation (IMPES) scheme where homogenization error impacts the accuracy of the coarse grid solution

se reservoirs were modeled stand alone and the current information has forced us to connect multiple reservoirs that are connected laterall stribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However the challenge lies in estim the production. The challenges in properly quantifying the separate effects of matrix and fracture within the framework of a single-media mo nd the surrounding fractures. An appropriate specification of the shape factor is therefore critical for accurate modeling. Since its introducti

ent geological complexity of turbiditic formations making any performance prediction and therefore development planning highly uncertain

hrough smart model simplification i.e. selected simplifications where these were expected not to hurt the results and surface and subsurfac nces between measurements and model parameters estimated from the ensemble. For practical field applications the ensemble size needs cal extrapolation techniques. The new method applies to heterogeneous reservoirs and requires no information about reservoir or fluid prop se of various visualization tools such as 2D plots or 3D displays. Properties such as water cut and sweep arrays can be visualized with the 2 ation. Potential incremental oil recovery is 8%. Significant capital investment (up to 140 new wells and 10 new jackets) will be required to re

0 x 200 m) compatible with 125-acre well spacing (3) upscaling to less than 1 million gridblocks for SL screening and (4) upscaling to less oduction is declining at the same time as consumption is on the increase.� In addition EU directives will require member States to mainta he application of the methods threatening to the associated estimates of oil reserves and investments on water-handling facilities. In this p they impact wellbore pressure and temperature and thus production and injection. We recently developed a fully-coupled black-oil thermal n rock and fluids as well as the saturation history. Capillary pressure data are essential input in both static and dynamic modelling of hetero afa A Unit and oil from the massive braided fluvial channels in the Lower Safa C Unit. At first the field was believed to consist of one single ty. The work in this paper uses the idea of flow reversal to resolve the ambiguity between convective spreading and mixing. We simulate flo

isal phase of the reservoir. This article presents a case study from a cluster of reservoirs in Southern Oman that highlights the importance n the fracture system to advance ahead of the gas-oil contact within the matrix blocks causing the oil in these blocks to become mobile. Th ains a feasible process. However low permeabilities result in low gravity drainage production rates with high remaining oil saturation. EOR bibition or gravity to recover oil from the matrix rock. In Middle East fractured carbonates the matrix rock is commonly oil-wet or mixed wet a n rates and volumes are required for reservoir selection and pumping requirements. This paper demonstrates a methodology which perm re accurate and efficient by integrating production data with reasonable computational cost. This method applied on a North Africa shallow en (32 pads in 8 different operations) which includes an analysis of their current performance and particularities trying to understand what tion pressure maintenance with sour separator gas plus sour makeup gas injection from other fields The field produces from the A4C unit both areal sweep and vertical conformance. Therefore fluid injection needs to be actively managed and surveyed in order to design an appr ontrol over the well. Hence a simulator was developed to estimate blowout rates. This simulator was validated for field cases by comparing are delivering smarter fields in order to add value to our business – there are many facets to this value beyond reservoir well process an tal Oil Field(DOF) has been the subject of much publicity and further development over recent years. However there was also much DOF-r developments in Brazil and West Africa to deliver reliable high-rate well completions. The technology also has been an enabler for heavy-o ntries. The paper also addresses the significant technical commercial and safety challenges that face developments of contaminated gas f on cost Weather conditions. Stimulation activities have been picked up since 2004 with encouraging successes. Among them are succes economics will continue to depend on accurate risk assessment risk-mitigation strategies and more fundamentally progressive deployme has been producing since 1965. To date some 66 wells have been drilled in the field. It has a STOIIP of about 1.5 billion barrels. Current es

e review was carried out in conjunction with material balance and average fluid contact movement calculations to understand the drive mec

t reservoirs uses long horizontal snake wells which create multiple drainage points in sands effectively achieving a similar drainage pattern

lower zones through separate hydraulic fractures. Temperature response of both pilots is monitored with 16 logging-observation wells. A pe

w profile of produced/injected water as well as the reservoir pressure permeability fluid saturations and formation compaction are useful to

and formation damage. We introduce Real-Time Completion Monitoring (RTCM) a new non-intrusive surveillance method for identifying im ns spanning pressure and mobility profiling vs. depth fluid sampling downhole fluid analysis (DFA) interval pressure-transient testing (IPTT ce breeches casing failures and excessive subsidence because of production. This paper demonstrates that more information can be extr rtubations like the tidal effect we show that a simplified coupling of geomechanics and fluid flow is possible. The coupling is easy to implem or the speed at which the available phase is flowing.� Recent industry developments in production logging have addressed these fundam n addition the waterflood helps maintain reservoir pressure in selected sands which minimizes compaction and subsequent well failure. Su ramatically for a given flow rate. In this paper we present field examples illustrating the use of advanced logging technology and measurem field conditions and to substantiate the in-house experiments that produced high quality crude. The pilot succeeded in meeting all of the int

ndamental data collection (well data pressure formation fluids - water and oil mineralogy data and lab tests…). Data management syste method. Production improvement factors (compared to conventional wells) of two or higher is not uncommon. To make decisions on the corr metal ions in the inhibitor pill adds another degree of freedom in squeeze design especially in controlling return concentrations and squeeze to determine the flow rate and pressure values and on models to determine the derivative information (i.e. the changes in flow rates as a re

still limited. This paper summarizes the significant effects of polymer on foam rheology and presents a hydraulic model that simulates aque Previous techniques of open hole external gravel packing and cased hole Internal Gravel Packing (IGP) for controlling formation sand were 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

m a gas cone as a natural lift.� This model was developed in the knowledge centre Integrated System Approach Petroleum Production (I g of emulsion flow and blocking mechanism b) set criteria for controlling an emulsion penetration depth before it breaks down and seals a Simulation results show that the problems in the conventional wells were not as severe as those interpreted from the measurements of distr

2 foams in granular porous media using X-ray Computed Tomography is reported. In the experiments gas is forced through natural porous m t experiments consisting of co-injection of N2 gas and surfactant solution in layered cores with layering parallel and to the flow directions. T ores varying the liquid and gas injection rates. During the experiments X-ray computed tomography (CT) scans were used to map locally th ompletely.� This phenomenon is known as liquid loading. Velocity strings are a commonly applied remedy to liquid loading in gas wells.

able gas rate not very reliable. Many wells start liquid loading at gas rates well above the values predicted by classic steady state prediction s the comparison of horizontal LEP injector with conventionally perforated liner for a generic reservoir; the role of the sand-screen in LEP de ienced with existing packages that use input values averaged across the reservoir. After consultation with staff engineers the tool was crea bsea development wells called for the use of a solid drill-in liner as a contingency should major losses be encountered while drilling the rese ei Shell Petroleum (BSP) how the challenges were addressed and the best practices identified for future operations. Sand-control techniq commingled completion inside 9-5/8-in. casing was implemented. The sand-face completion design consisted of a large-OD expandable sa nificantly below the hydrostatic pressure of a seawater column a modified screen design was required since screen products currently avail orated and commingled completion inside 95/8-in. casing was implemented. The sandface-completion design consisted of a large-outsideacilities design and operation and facilities risk evaluation with reference to a high rate gas field development. The estimation of sand prod

luids are defined for the purpose of this technical standard as fluids used to enhance production from oil and gas wells by fracturing or acid ud damage. One of the challenges in stimulating long horizontal wells with open-hole completion is the placement of stimulation fluids for e as been carried out to date to provide methodologies for predicting and measurement of the size of waterflood-induced fractures. This cont

d the slant well solution to layered reservoirs without reservoir crossflow i.e. no significant vertical permeability between individual layers wit

ces were used in the horizontal part of the well in addition to Magnetic Resonance. To achieve the best possible real-time wellbore placeme th a dedicated field test which consisted of running a pressure/temperature memory gauge in a casing/casing annulus of a well and testing objectives for the well test. The paper also addresses how health safety and environmental considerations were handled. Traditional well reservoir data are essential to understand such reservoirs. Another challenge presented by thinly bedded reservoirs is the presence of verti e purpose of well testing is to periodically determine oil gas and water flows for accounting reporting and surveillance purposes. Hydrocar

nage future emissions will include developing new technologies to capture and store CO2 underground. The pursuit of Carbon Capture and s to manage future emissions will include developing new technologies to capture and store CO2 underground. The pursuit of Carbon Captu d with water and the rate of CO2 sorption and CH4 desorption is affected by slow diffusion of CO2. This work investigates the wetting behav ate i.e. to swelled coal. For reasons of easy reference we present a shortened derivation of the Thomas and Windle model which was orig re porosity and permeability of the coal. Two coal samples differing in rank were used for volumetric strain measurements. With CO2� th dioxide and methane. This condition in a coal reservoir would lead to differential swelling. Differential swelling will have consequences in ter

still to be studied and solved before CO2 improved deep coalbed methane production may be operationally feasible. These are all related nology targeted at developing an in situ laboratory for CO2 storage. Its aims are to advance the understanding of the processes involved in nts) we are currently investigating several sites and geologic formations across the globe for their suitability in the long-term storage of CO2 mes of an IPIECA workshop to advance understanding of the role of CO2 capture and geologic storage and strategies to improve its perf oEnator and Weatherford. Energistics� has stewardship of PRODML and fosters further development. There is significant industry intere objective was to enable plug and play integration of current upstream applications while supporting a variety of optimization processes. In

wellsite chemistry is standard in most E&P operations. Integrated approaches involving multiple tools and technologies are still relatively new ational Exploration & Production and Shell Global Solutions International that provides continuous real time estimates of well-by-well oil wa nd timely manner and then taking prompt action is a challenge.�Traditional routine well testing simply provides a series of snap-shots of ested. “Smart technologies can significantly increase value here provided they are properly focused and implemented and integrated in

orts and inefficient collaboration between different disciplines supporting Well &�Reservoir Management. In general cycle times between arbons do not have to be produced directly to surface. Currently we have three types of well tests in our OVT toolbox - wireline formation te evelopment decisions that we face. Definitions of OVT vary but in general it may be defined as any testing method that yields fit-for-purpo

Automation Data Management/Application Facility Engineering and Production Engineering is seen as a key enabler for a successful Sm

mal control requires the determination of a potentially large number of (groups of) well rates for a potentially large number of time periods. rate any piece of equipment: reliable performance data an integrated suite of tools to turn these data to information and operational adviso epts in several fields around the world in recent years to increase production and increase recovery. In each case the value is achieved onl al casing packers or swellable packers. In addition the completion includes permanent downhole gauges (PDHG) and distributed temperat

the wells are of different horizontal lengths as can be seen in Figure 1 and 2. The objective of this paper is to present the learning and be to not only reduce the footprint but also the unit operating cost driven mainly by the need for experienced expatriate personnel to man the dition to access new untapped reserves requires venturing into deeper water depths and the exploitation of deeper tight gas reservoirs ea perators for application in their assets.� Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservo sts under polyaxial conditions indicate that near-wellbore fracturing and permeability increase in unconsolidated sands occurs at net injectio es.� The results obtained relate to oil/water interfacial tension behaviour and give the “operating window of the surfactants in terms o k. In Middle-East fractured carbonates the matrix rock is commonly oil-wet or mixed wet and only gravity drainage remains a feasible proce ctive petroleum basins and an individual candidate reservoir is examined through a simulation study. Key issues in the application of the tec tment decision to undertake a miscible gasflood already in 2005 whereas initial production from four reservoirs had only started in March 2 ed that in isolated layers foam propagates faster in the high permeability layer and sweeps the low permeability layer only modestly. In com y was the Gyda reservoir located in the southern part of Norwegian North Sea in the Norwegian Continental Shelf. The reservoir is of heavi

hermally assisted - GOGD is that the fracture network is both used for distribution of steam and recovery of the oil. The number of wells can

multivalent cations. This causes the (sandstone) reservoir wettability to be more oilwet; (2) The field-observed temporary reduction in waterc control is a challenge in many of these wells because the gas breakthrough occurs for a variety of reasons: downward movement of fractur ipated that these unswept sands could contribute to production if the watered-out sands were shut off. A newly developed gel/cement has b ediments and water (BS&W) are problems associated with fields having strong aquifer drive mechanisms. As a result most exploration and g lost-circulation zones. The OCP system which comprises the fluid portion of the PG system easily penetrates into the formation matrix. of water. In the past decade using a new class of surfactants enhanced oil recovery (EOR) researchers have studied the options to chemic rent business because the system bottlenecks could shift from year to year. Integrated network analysis will look at the impact of changes that the four variants of DGM are capable algorithms. Although the DGM is best suited for non-smooth and non-convex optimization problem and multiphase transport of produced reservoir fluids to a host facility. The high cost of remediation and limited accessibility for intervention 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 al tensions were measured between CO2 and a live crude oil from a depleted Louisiana oil field at varying pressures and at reservoir tempe econd part consist of the study of Natural Gas Viscosity at 15 psia in the temperature range 130oF – 220oF. Comparison of the equation

asibility of a project and determining if an offset discovery can be produced without a facility upgrade can economically make or break a pro able to assess the phenomenon. Individually geochemistry downhole fluid and mud gas analyses have provided valuable insights into com e contamination by the OBM filtrate is a critical factor for the accurate measurement of the sample pressure/volume/temperature (PVT) prop years much research has been carried out on asphaltenes. Yet the exact chemical nature of these species still remains unknown. The deter operate heavy-oil production systems knowledge of the realistic viscosities of the emulsified heavy oil under the actual production condition itions to make IFT and dynamic contact angle measurements using the drop shape analysis (DSA) and dual-drop dual-crystal (DDDC) tech

e region and the subsequent precipitation of acid reaction by-products within specific well applications. This success has brought about mod

at predict the zonal coverage of the fluids are of great help. These models improve the understanding of the complex processes and will he

o special core tests to model the extent of invasive damage and its impact on flowback during production. The approach is based on specia m some chosen initial conditions (i.e. naphthenate initial concentration in oil brine pH and [Ca2+] etc). This model has with some assumptio

requently applied and costly. Shell U.K. Limited Production Chemistry has applied two methods in order reach the goal of an optimised scal outlines their range of applicability. The task of the study is to choose a model that would provide the most general and accurate description

s. BHI sonic and resistivity logs were run to understand static fracture characteristics; dynamic behavior was assessed with DSTs and PLTs story matching two groups of CSS multilateral wells and develop a history matched physical representation that not only validates empiric short-medium radius drilling 4D seismic water and fines control artificial lifting pressure maintenance and deep penetrating damage remo actors). We independently validate the simulation results with new analytical results for the recoveries due to thermal expansion and temper 2D and sparse 3D) a time-lapse 3D VSP a surface tiltmeter array and InSAR. Joint interpretation of these data with production data has a er we have studied the effects of gravity using experimental data available for five live oil and condensate systems (at high pressure and te will involve miscible gas injection. This paper describes the strategy that was developed by Petroleum Development Oman to optimize perfo 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 aluated with production logs - this additional expense accentuates the need to carefully design the field trial and thoroughly analyze the resu

f these areas. The Pinedale Anticline completions pose a particularly complex problem when attempting to evaluate the “best method aulic fracture stages to complete. Time-lapsed production analyses are performed to optimize well spacing and to characterize the gas bea ells equipped with pressure gauges. The pressure gauges enable pressure monitoring along the wellbore (in space) and over time hence th ry to petrophysics by Klinkenberg.1 In the first part of our work the applicability of the Jones-Owens4 and Sampath-Keighin5 correlations f s and in the longer term optimization of subsequent field development activities. The vision is effectively to inflow test all available hydroca a thin and fairly complex braided channel sandstone formation with low 5% average porosity low 0.7mD average permeability and high >85 horizontal well concept are reviewed. Introduction Most gas fields in the Southern North Sea produce from the Rotliegend sandstone form

tional boundaries. A key critical success factor is also strong inter-disciplinary decision-making in all decision domains. Recognising this in

ce suspected faulty Tr-ScSSSV. The post re-entry performance following the replacement of the Tr-ScSSSV was also poor as the well cou exploring the outcomes this design might generate (3) identifying opportunities for flexible design and (4) evaluating and selecting the mo ation Decision Support Systems Collaborative Environments) and organizational change (Intelligent Workflows Research and Developm oil saturation (Sor) against depth and on the rock and fluid interactions that control the residual oil saturation (Sor) capillary pressure and r wever hydrocarbon differences can be identified reliably only when the significance of uncertainties from measurement and the oil-based m optical spectroscopy which can provide estimates of filtrate contamination gas/oil ratio (GOR) pH of formation water and a hydrocarbon c

y while hinting at the presence of slightly elevated resistivities at depth. An exploration well campaign was carried out over the prospect late show that dynamic connectivity is governed by large-scale architectural parameters such as meander belt size net-to-gross and degree of rilling practices. We have developed a new multifrequency inversion algorithm for the estimation of maximum and minimum horizontal stres ensive units. The formation has been subdivided into six composite sequences (KS1 shown in red to KS6 shown in dark blue). The main fac x treatments. Literature shows that naturally fractured reservoirs are very susceptible to formation damage and require stimulation treatmen c dispersion of such rocks. Selecting a representative scale to measure permeability and dispersivity in such rocks can be crucial because t used to convert apparent pore geometries and various hydraulic corrections are applied to account for converging–diverging flow paths. ise. Interpretation of data from UBD is made difficult by transducer errors operational transients and noise in data. It is therefore often very ith seismic faults and lineaments and estimated the percentage of fracture fairways that can be detected by seismic attribute maps. Correla ments image logs are available only from a limited number of wells. It is necessary to utilize indirect indicators to identify and map fracture ntified by some other means. Individual formation-pressure measurements downhole fluid analysis (DFA) and geochemistry are known to essure analyses provide valuable insights into reservoir architecture. Each analytic method relies on different fluid traits and has its own limi x wells in short time frames and at manageable costs has pushed game changing improvements to both mud logging and wire line testing erefore the team proposed to core five wells and embarked on a large scale special core analysis (SCAL) program covering all predomina R) data. The method is based on the additional nuclear relaxation that fluids experience when in direct contact with the rock surface. Reduc

as part of the evaluation of the deep high-pressure (HHP) play. Well Bubut-2 (BU-2) subsequently (re-)discovered significant gas volume in dest size stacked pay fluvio-marine transitional geological setting high heterogeneity partially sub-seismic resolution creates a range of te arbon gas and oil fields. Several key technical challenges in the development of highly contaminated gas & oil fields have been overcome

s volumes to the market. This poses a serious challenge to maintaining gas supply and meeting contractual obligations. Field performance ding 60% make Draugen one of the best performing fields offshore Norway. The field has a simple geology; however the reservoir structure nt future field development and optimise oil recovery. The paper focuses on four main aspects of the West Salym development: project man

stb have been produced as of March 2009 from 13 subsea producers and reservoir pressures have been maintained by water injection fro

this high production rate environment and maximise oil and gas recovery significant effort has gone into the static and dynamic re-modellin

applications to five-spot pattern flood models addressing various aspects that often play an important role in waterfloods: shortcut of injecto uction over the next five years. The purpose of this study was to optimize CSS well configuration and steaming strategy for each distinct re e known about the impact of karstification on GIIP and water breakthrough. For the field with the largest discovered GIIP in the Central Luc oir Modeling utilizing modern seismic processing and interpretation to evaluate short medium- and long-term subsurface uncertainties and ect the range of possible geological structures honoring the statistics of the geological uncertainties. In our study we used 100 realizations o in four phases: screening full field modelling infra-structure development and FDPs for the 6 large fields and the writing of appraisal / deve llance accelerated production lower operating cost etc. Reservoir management is an ongoing continuous cradle-to-grave process which d which propagates depending on the injection water’s leakoff rate into the formation. The project is part of a larger secondary recovery ults of the strategic IOR program in a mature field showing importance and influence of each decision made during project implementations sources to regions with a high consumption but insufficient local gas resources like North America Europe and East Asia. To analyze the ga Ras Laffan Industrial City 80 km north of Doha Qatar. It will have the capacity to produce 140 000 barrels a day (b/d) of GTL products – g variables largely intrinsic properties of a reservoir its produced fluids and the contaminants that eventually end up in the produced water. P de Shell’s integrated water management strategy principles and applications are discussed supported by field cases impact of new te decisions can be made and is essential for optimization.� However the advantages of automatic process control are often underestimate which is characterized by the presence of vugs dissolution channels fractures (both vertical and horizontal) and hence high permeability

om reservoir souring was not expected to exceed 50 parts per million(volume-based) [ppm(v)] in the gas phase. Initially nanofiltration to red ater injection was to control reservoir souring with biocide and handle low levels of H2S with sour service materials and scavenging facilities the microbial activity in the near well reservoir. From this pre-study the dosage of nitrate was selected based upon bio-available carbon an n the presence of elemental sulphur corrosion rate can exceed 30 mm/y. Most of the mitigation methods designed to manage and maintain line around 50% and levels have caused concern for on going Field Development scenarios. Meanwhile in opposite in Y oilfield when disc applied mutual solvent chemicals in the preflush stage of such treatments to (i) avoid emulsion formation or water blocking thus avoiding sl binations of well locations subject to investigation; (b) There is need to optimize operational constraints for every well-placement scenario; (c neously three years of development and two years of production from a Phase 1" project a Phase 2 production and miscible gas injection d rocarbon gas and oil fields. Several key technical challenges in the development of highly contaminated gas & oil fields have been overcom ntegration. Information providers for the important subsurface risks and uncertainties have been mapped which has resulted in a better und sion making leading to successful interventions. Production logging in high angle and horizontal wells that produce mixtures of fluid phases oncept is proposed. In this concept the gas cap and oil rim are produced simultaneously from the start of production through a single well c

ormations: the Cretaceous sheet-like shallow marine Lower Rutbah (RUL) and the Triassic coastal fluvial plane Mulussa F (MUF) formation. heory. Starting from a base case reservoir simulation run this extremely efficient method makes it possible to compute the sensitivities of th e field and in particular to select the optimal number of ICVs the optimal configuration of the perforation zones and the optimal operationa subsurface uncertainties. Previous quantitative reservoir mModelling efforts were hampered by the existence of shallow gas over the crest o he data mismatch and a quasi-Newton method is used to compute the search direction. Compared to other approaches that use the time-la on the concept of surrounding the wells whose locations have to be optimized by so-called pseudowells. These pseudowells produce or inj is a large-scale physical model comprising two intersecting synthetic sandstone channels encased within an impermeable acrylic matrix. Th rvoir models is evolved by means of a stochastic nonlinear filtering procedure to agree with the observed production data. An efficient varian rves as a rapid proxy to full-physics reservoir simulation. The data integration and uncertainty quantification framework extends current wor uses this to determine example Nusselt numbers. The analysis is similar to the analysis by Batchelor for linear viscous fluids. Applications a n optimal waterflood field implementation is an appropriate modeling tool which is capable of handling the dynamic fracturing process in co mulator. We demonstrate the coupled simulator by applications to a model five-spot pattern flood model and to a number of actual field cas d a dynamic multiphase reservoir simulator (MoReS) have been used. Both simulators have been coupled using an explicit scheme. The dy aper we use a dynamic coupled well-reservoir simulator to identify instabilities of a field case and test a control strategy to mitigate gas conin

model the response (dependent variable) as a function of independent variables (uncertainties) is a common method for studying subsurfac y and value of expanding water flooding to the rest of the Champion field. A significant volume of special core analysis data is available ho tages over the pseudopressure approach. The semianalytical method includes the effects of capillary number (high velocity) and non-Darcy

vely achieved by generating a background grid that stores grid point spacing parameter. Spacing (L) can be described by Poisson's equatio osed for each of these steps one has to be aware of strengths and weaknesses of each technique before attempting to apply them. In this accuracy of the coarse grid solution of the pressure equation. To reduce the homogenization error we employ the new vorticity-based gridd

eservoirs that are connected laterally. Performance of three Gulf of Mexico (GOM) reservoirs was assessed using basin-wide compositiona However the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing the limited the framework of a single-media model become the major objective of the study. A brief description of the static model (which consists of the urate modeling. Since its introduction many different values for the shape factor have been proposed in the literature among which the we

velopment planning highly uncertain. Prediction of a well performance is generally a twofold matter: predicting the initial rate of the well and

e results and surface and subsurface system dependencies. Based on a representative field model a 35x reduction in run time was achiev pplications the ensemble size needs to be kept small for computational efficiency. However this leads to poor approximations of the cross-c rmation about reservoir or fluid properties. The idea of the method is to estimate from the pressure derivative the first few eigenvalues of th p arrays can be visualized with the 2D or 3D displays respectively. These plots enable an understanding of the result of a reservoir simulatio 10 new jackets) will be required to realise this opportunity. It is therefore important to capture the full range of possible subsurface scenario

screening and (4) upscaling to less than 250 000 gridblocks for FD flow simulation. Chevron’s in-house scaleup software program SCP will require member States to maintain a certain minimum volume of gas stocks in some form of storage (to mitigate against supply interrup on water-handling facilities. In this paper based on an investigation of internal/practical consistency and the physics of fluid flow a didactic ed a fully-coupled black-oil thermal multiphase wellbore flow model and implemented it into Stanford’s General Purpose Research Sim tic and dynamic modelling of heterogeneous carbonate reservoirs. Drainage Pc is generally used for initialising reservoir static models while was believed to consist of one single hydrocarbon column. However based on production behavior and additional well information it became reading and mixing. We simulate flow reversal tests for tracer transport in several permeability realizations using particle tracking simulation

man that highlights the importance of using PVC to determine reserves associated with both the primary depletion and miscible gas injectio n these blocks to become mobile. The addition of heat in the fractures generates additional hydrocarbon gas cap lowers the viscosity of the high remaining oil saturation. EOR methods have the potential to improve GOGD drainage rate and ultimate recovery. Especially for shallo k is commonly oil-wet or mixed wet and only gravity drainage remains a feasible process. However permeabilities are usually low <10 mD nstrates a methodology which permits injection rate and volume predictions to be made in a simple spreadsheet model based on historical d applied on a North Africa shallow marine reservoir includes following four steps. 1. A Folded Plackett-Burman design (FPBD) is used to cularities trying to understand what makes a SAGD project successful and what determines its performance. Moreover SAGD’s perfo he field produces from the A4C unit of the Ara Group intra salt carbonates. A carbonate reservoir totally encased in salt.�� No water ha surveyed in order to design an appropriate injection strategy over time. We have analyzed historical injection/production injection step-rate alidated for field cases by comparing calculated blowout rates with estimates based on observable phenomena such as flame length and he e beyond reservoir well process and production management.�What may not be so clear is how to apply these smart technologies to owever there was also much DOF-related activity over prior decades in which oil companies made their operations’ progressively sma lso has been an enabler for heavy-oil developments [American Petroleum Inst. (API) gravity < 20� y > 0.934] in Brazil and the North Sea developments of contaminated gas fields. In many cases fields with high CO2 contamination cannot be developed economically without the successes. Among them are successful hydraulic fracture stimulation in STOS and sandstone matrix acid stimulation campaigns in Brunei a ndamentally progressive deployment of evolving technologies in brownfield deepwater secondary-recovery projects. Details of well geome about 1.5 billion barrels. Current estimate of undeveloped hydrocarbon reserves stand at Expectation Volume of 285 MMbbl and 0.8 Tscf. H

ulations to understand the drive mechanism and to estimate the current fluid contacts. Performance matching was carried out with an analyt

achieving a similar drainage pattern of several conventional wells.� The snake wells intersect up to 4 kilometers of reservoir intervals wit

h 16 logging-observation wells. A perturbation analysis of the nonlinear pressure diffusion and heat-transport equations indicates that at a p

d formation compaction are useful to properly evaluate the overall sweep efficiency. This information is more crucial in a field with multi-laye

surveillance method for identifying impairment in sand-screened completions that utilizes acoustic signals sent via the fluid column. These s rval pressure-transient testing (IPTT) and microfracturing. Because of the complex tool strings and the elaborate operational aspects involv es that more information can be extracted from surface-deformation measurements by inverting the surface deformation for the volumetric d sible. The coupling is easy to implement in a standard reservoir simulator by introducing a porosity varying in phase with the tide. Simulation gging have addressed these fundamental requirements of measurement with multiple probe technology that differentiate between Oil Holdup tion and subsequent well failure. Surveillance of the waterflood through carbon/oxygen logging of the formation through compaction loggin d logging technology and measurement techniques for well & reservoir surveillance in a mature field setting. Realizing value through surveil t succeeded in meeting all of the intended objectives. The history match of the production data however encountered some technical chal

tests…). Data management system allowing for quick access to well production history data. A design tool (Stim2001) for detailed candid mon. To make decisions on the correct completion type to select it is important to be aware of the many sand control issues and the relativ g return concentrations and squeeze life. Phosphonate reactions during squeeze treatments involve a series of self-regulating reactions wit .e. the changes in flow rates as a result of a change in an ICV setting). Such a model typically would be a steady-state wellbore simulator i

hydraulic model that simulates aqueous and polymer-based foam flow in directional and horizontal wellbores. Experimental studies on the for controlling formation sand were challenged by reduced flow efficiency of the wells. The recent development of Expandable Sand Screen estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 20

m Approach Petroleum Production (ISAPP) of TNO TU Delft and Shell and is based on a commercially available dynamic multiphase well s h before it breaks down and seals a porous medium. In these experiments well-characterized oil-in-water emulsions were injected into etch eted from the measurements of distributed temperature sensing systems (DTSs). It is also demonstrated that the compartmentalized compl

s is forced through natural porous media initially saturated with a surfactant solution a process known as SurfactantAlternatingGas (SAG). parallel and to the flow directions. The cores are obtained by combining two porous media chosen from Benteimer and Berea sandstone a ) scans were used to map locally the fluid saturations with high spatial and temporal resolution. Introduction Foam is an excellent acid dive medy to liquid loading in gas wells. By installing a small diameter string inside the tubing the flow area is reduced which increases the velo

ed by classic steady state prediction models such as Turner. The loading point is strongly dependent on inclination angle flow regime transi he role of the sand-screen in LEP design during HVO production and the analysis of the pressure drops through the LEP hardware. Modell ith staff engineers the tool was created in Excel to test functionality and later transformed into a desktop application.� It includes a perfo e encountered while drilling the reservoir section. This strategy stands opposed to using a pre-drilled liner.� The use of a drill-in liner how re operations. Sand-control techniques such as an extension packing and hydraulic fracturing were evaluated to help minimize the risk of f nsisted of a large-OD expandable sand screen with 150 micron weave across the 2 zones. Upon completion the reservoirs were cleaned u since screen products currently available were limited to <3 500 psi. FLC pill formulations also required modification because they were only design consisted of a large-outside-diameter (OD) expandable sand screen with a 150-�-weave opening across the two zones. Upon co pment. The estimation of sand production volumes for openhole and cased and perforated completions is presented for the high rate gas w

l and gas wells by fracturing or acidizing and fluids used to place filtration media to control formation sand production from oil and gas wells placement of stimulation fluids for effective zonal coverage and generating wormholes to pass the damaged zone. Placing gelled acid throu erflood-induced fractures. This contrasts to the vast amount of work that has been done for stimulation (e.g. propped) fractures. Injection F

eability between individual layers within the reservoir. The third objective of this paper is to present a methodology for the analysis of high an

possible real-time wellbore placement reservoir navigation and continuous follow-up on the horizontal log interpretation was performed duri casing annulus of a well and testing the well several times during a 3-month period after which the gauge was retrieved and the data were ions were handled. Traditional well testing methods and equipment have evolved over the years adapting to changing requirements. This h ed reservoirs is the presence of vertical heterogeneity and varying layer flow properties. Wireline formation testers have been commonly us nd surveillance purposes. Hydrocarbon allocation provides official reports of well and reservoir production for lease owners petroleum rev

. The pursuit of Carbon Capture and Storage (CCS) technologies allows Shell to play an important and leading role towards addressing the ground. The pursuit of Carbon Capture and Storage (CCS) technologies allows Shell to play an important and leading role towards address work investigates the wetting behavior of coal using capillary pressures between CO2 and water measured continuously as a function of w s and Windle model which was originally derived to describe diffusion in polymers. Analysis of the model equation shows that super-diffusio in measurements. With CO2� the high-rank Selar Cornish coal showed a maximum volumetric strain of 1.48% corresponding to an ave welling will have consequences in terms of porosity / permeability loss with serious implication for the performance and implementation of ca

nally feasible. These are all related to the heterogeneous nature of the pore structure of coal and in particular the presence of fractures. Mo standing of the processes involved in underground CO2 storage evaluate applicable monitoring techniques and provide operational experie bility in the long-term storage of CO2 using technology and experience from over 30 years of safely transporting and injecting CO2 in oil and e and strategies to improve its performance and prospects. It considers CO2 capture and geological storage as a potential option for redu nt. There is significant industry interest in implementing digital oil field strategies. Corporate and government initiatives anticipate significant ariety of optimization processes. In 2007 the PRODML community now expanded to 23 companies worked on extensions addressing pro

d technologies are still relatively new to the industry but Shell through its FEAST (Fluid Evaluation and Sampling Technology) global centre time estimates of well-by-well oil water and gas production. FieldWare PU estimates are based on data driven models constructed and upd y provides a series of snap-shots of a well's performance which may or may not reflect the production during the intervening period.�Err d and implemented and integrated into the facilities daily operations. The successful implementation of smart applications requires new wa

ent. In general cycle times between identification of problems and closing them out were long and below corporate standards. The pilot pro r OVT toolbox - wireline formation testing (WFT) closed system testing with cleanup and repeat surges and injection testing. Our recent ex sting method that yields fit-for-purpose results with the lowest cost and Health Safety and Environmental (HSE) impact. In more pragmatic

as a key enabler for a successful Smart Field development.

Introduction Brunei offshore waters are known to be rich in oil accumulations

ntially large number of time periods. However the optimal number of well groups and time steps is not known a priori. Moreover taking the o information and operational advisories and a cadre of appropriately skilled professionals that use the information to make the right decisio each case the value is achieved only if the solution applied covers the three main elements namely technology process and people. Succe es (PDHG) and distributed temperature sensing (DTS). Seven of these smart snake wells have been successfully drilled in Champion West

per is to present the learning and best practices gained after drilling 5 of these snake oil wells during Champion West phase 3a. Best pract ed expatriate personnel to man the equipment. Recent introduction of new or improved tools and equipment combined with growing recogn on of deeper tight gas reservoirs each with its own challenges. This paper describes the process involving rigorous pre-screening planning boratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteris solidated sands occurs at net injection pressures limited to 2.0 MPa. These findings were applied to fracture modeling. Geomechanical mod window of the surfactants in terms of their optimal salinity and ability to solubilise oil in the micro-emulsion. The phase tests also give inform ty drainage remains a feasible process. However permeabilities are usually low <10 mDarcy resulting in low gravity drainage production ra ey issues in the application of the technique are discussed as are directions for implementation in Australia. Air injection involves the contin servoirs had only started in March 2004. Main components of this paper are: (1) Design of experiments for a wide spectrum of fluids (from n meability layer only modestly. In communicating layers sweep efficiency is improved significantly due to cross flow. In stochastic random pe ental Shelf. The reservoir is of heavily faulted heterogeneous shallow marine sandstone. As the measure of heterogeneity a Dykstra-Parson

y of the oil. The number of wells can therefore be kept to a minimum compared to conventional matrix steam floods. Whereas the primary p

served temporary reduction in watercut during breakthrough of so-called “Designer Waterflood water in a Middle Eastern sandstone rese ons: downward movement of fracture gas/oil contact (fracture-oil-rim thinning) gas breakthrough via high-conductivity fractures (fracture ga A newly developed gel/cement has been used to shut off the watered-out sands in a cost-effective manner.�The gel/cement system com ms. As a result most exploration and production companies have learned to manage water production up to a tolerable limit which is depen enetrates into the formation matrix. It has proven successful in the oil industry with more than 350 jobs performed around the world. The ad have studied the options to chemically revert the wettability of carbonate rock without drastically decreasing the oil-water interfacial tension is will look at the impact of changes on the entire network over the entire time period with the aim to determine the optimal timing of develop and non-convex optimization problems it can also be used to locate reasonable solutions for smooth convex gas lift optimization problems. d limited accessibility for intervention of subsea equipment has highlighted the importance of developing robust flow assurance solutions in s 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 ng pressures and at reservoir temperature (238oF) using the pendant drop and capillary rise techniques to determine the MMP. The gas-oil 220oF. Comparison of the equation formulated for the first part of this work with experimental PVT viscosity of gave an average absolute er

an economically make or break a project. Traditionally operators have relied on well tests to determine H2S levels. In addition to the expens e provided valuable insights into compositional grading but each analytical method relies on different fluid traits and has different implication sure/volume/temperature (PVT) properties. A technique of monitoring sample contamination from OBM filtrate uses optical means to monito es still remains unknown. The determination of asphaltene molecular weight distributions in conjunction with the identification of compound nder the actual production conditions is necessary. This study is an attempt to investigate the effect of water content pressure and tempe dual-drop dual-crystal (DDDC) techniques respectively. Yates reservoir rock and fluids and two types of surfactants (nonionic and anionic)

This success has brought about modifications to the acid system and new applications for various well scenarios. This paper discusses the

f the complex processes and will help to improve the design of matrix-acid treatments. For studying diversion effects correct modeling of th

on. The approach is based on special tests conducted on the reservoir core and a dynamic microsimulator" to model invasion during drilling. his model has with some assumptions been applied to both model and real naphthenate system. This model describes two types of naph

reach the goal of an optimised scale management system. These are Environmental Scanning Electron Microscopy/Energy Dispersive X-R ost general and accurate description of a multiphase flow that can be used for implementation in a reservoir simulator. It is concluded that e

r was assessed with DSTs and PLTs. Fracture models were built with forward modeling algorithms using Shell’s fracture modeling softw ation that not only validates empirical models but can be deployed to optimize CSS designs for full field development. Detailed geological and deep penetrating damage removal acid system. Minimising fines migration and improving high water cut well productivities via improve ue to thermal expansion and temperature-induced viscosity reduction. Our dual-permeability results show that the early-time heating of the hese data with production data has allowed us to build a conceptual model of the geomechanical response of the reservoir and its effect on ate systems (at high pressure and temperature) considering impact of fluid characterization effects. Under isothermal conditions and in the a Development Oman to optimize perforation techniques. Perforations were required to by-pass the drilling induced impaired zone to enable e samples were studied using coreflood and slurry reactor experiments. Linear coreflood test data show dramatic increases in the formation rial and thoroughly analyze the resulting data to extract as much value as possible.� This paper will provide a detailed comparison of we

g to evaluate the “best method of stimulation because as many as twenty-two separate stimulation treatments are placed in up to 70 d cing and to characterize the gas bearing reservoirs. �Production logs are also run to determine the effectiveness of the hydraulic fracturin e (in space) and over time hence the name 4D pressure pilot. Two wells were drilled with one in the maximum horizontal stress direction (a nd Sampath-Keighin5 correlations for estimating the Klinkenberg-corrected (absolute) permeability from single-point steady-state measure ly to inflow test all available hydrocarbon reservoirs while drilling thereby generating a pseudo reservoir inflow profile as a function of depth D average permeability and high >85% Net to Gross. Potential heterogeneities were identified by well test analysis. Presently these heterog rom the Rotliegend sandstone formation that is of Permian age and deposited in both aeolian and fluvial setting. The Rotliegend reservoirs

cision domains. Recognising this in Shell within the development-planning phase of the field life cycle we have developed two key program

SSSV was also poor as the well could only deliver 53MMscf/d at 100% choke opening. The poor performance was suspected to be as a res (4) evaluating and selecting the most valuable flexibility to incorporate into the design. It embodies a paradigmatic change in the way desig Workflows Research and Development and new Business Models) The solution consists of a Smart WorkFlow System (SWS) an Uncert ation (Sor) capillary pressure and relative permeability characteristics as a function of initial oil saturation. � Because of the general lac m measurement and the oil-based mud (OBM) filtrate have been taken into account. Recently an algorithm called the fluid-comparison algo rmation water and a hydrocarbon composition in four groups: methane (C1) ethane to pentane (C2–5) hexane and heavier hydrocarbon

as carried out over the prospect late in 2006 but rather than encountering the expected hydrocarbon pay the well encountered a near surfa elt size net-to-gross and degree of depositional storey amalgamation; and stratigraphic parameters that describe the shale architecture at imum and minimum horizontal stress magnitudes by use of cross-dipole dispersions. Borehole sonic data for the case study presented in th 6 shown in dark blue). The main facies types are: 1 graded peloidal oolitic packstones to grainstones 2 mottled and rooted mudstones 3 g age and require stimulation treatments to account for this issue. The historical problem however has been to confidently characterize the re such rocks can be crucial because the connected vug lengths can be longer than typical core diameters. Large touching vug (centimeter-s converging–diverging flow paths. These various corrections are the principal and crucial differences between our approach and previous oise in data. It is therefore often very difficult to interpret the reservoir characteristics from the instantaneous productivity index (PI). In this p d by seismic attribute maps. Correlation with flow profiles lost circulation and water breakthrough and productivity index was necessary to d dicators to identify and map fracture corridors such as lost circulation step flow profiles water breakthrough or seismic lineaments. This fits FA) and geochemistry are known to provide important information about reservoir architecture. When these powerful methods are combine erent fluid traits and has its own limitations. With systematic integration of different methods the synergy delivers a more accurate characte oth mud logging and wire line testing technologies. In the past interpretation of wireline formation testing data (e.g. static pressure gradien AL) program covering all predominant rock types in order to get a better handle on the relative permeability characteristics. This paper pre contact with the rock surface. Reduction of oil relaxation time away from its bulk value is generally known as a qualitative wettability indicato

iscovered significant gas volume in the deep stacked pay sequence. The gas discovery forms part of a phased Bubut-Danau development mic resolution creates a range of technical and economical challenges. The application of a number of specific technologies notably to res as & oil fields have been overcome with new technologies developed by Shell. These challenges include: contaminant separation at minima

tual obligations. Field performance of selected oil rim reservoirs in the Niger Delta have been analysed and presented in this work. The ma ogy; however the reservoir structure is relatively uncertain because of the low number of well penetrations for calibrating the structure. Fortu est Salym development: project management well and reservoir surveillance reservoir management and petroleum resources maturation.

en maintained by water injection from the start of production in 13 subsea high rate water injectors allowing high field production rates to be

to the static and dynamic re-modelling of the reservoir.� This effort has demonstrated that over the production life complexity of the high

ole in waterfloods: shortcut of injector and producer fracture containment reservoir sweep. We also demonstrate that induced fracture dime teaming strategy for each distinct reservoir area by deploying previously improved and history matched simulation models1. A full field stati st discovered GIIP in the Central Luconia Province karstification was seen as the largest contributor to GIIP uncertainty. GIIP uncertainty wa g-term subsurface uncertainties and to support development planning and reservoir management. The results have been combined into a our study we used 100 realizations of a 3D reservoir in a fluvial depositional environment with known main-flow direction. We optimized the ds and the writing of appraisal / development plans for the remaining 17 fields. This paper describes the workflow and learnings of the study ous cradle-to-grave process which targets depletion of reservoirs in a way that maximizes recovery and return on investment. Hydrocarbo part of a larger secondary recovery implementation scheme and future efforts to increase economic oil production and ultimate recovery in made during project implementations. The reservoir into consideration is a sandstone reservoir which was producing under a solution gas dr pe and East Asia. To analyze the gas situation in the world a gas distribution model was constructed. The model predicts the timing and am els a day (b/d) of GTL products – gasoil naphtha kerosene normal paraffin and lubricants base oils – as well as 120 000 barrels of oil ally end up in the produced water. PWRI for reservoir management purposes must find the balance between injector plugging and the exte orted by field cases impact of new technology applications on gross water production is illustrated value of beneficial use of produced wate ess control are often underestimated; hence the discipline is under-staffed and under-utilized. Process Control also plays a crucial role in p ontal) and hence high permeability streaks that provide conduits for early water breakthrough. This has been primarily responsible for the d

s phase. Initially nanofiltration to reduce the sulfate level in the seawater was identified to mitigate reservoir souring but because of the high e materials and scavenging facilities topside. The maximum H2S the existing facilities could handle was set at 50 ppm (v). The decision to based upon bio-available carbon and the required stoichiometric concentration of nitrate. During the PWRI pilot corrosion rates were meas s designed to manage and maintain the integrity of carbon steel downhole tubing and pipelines present in itself some of the toughest techni e in opposite in Y oilfield when discovered the field was found to be sour hence production facilities were designed for sour service. Occa n or water blocking thus avoiding slow well clean-up and also (ii) for enhancing adsorption of the scale inhibitor onto the formation rock. Th or every well-placement scenario; (c) The optimization process has to be repeated for a variety of geologic realizations; (d) Presence of com oduction and miscible gas injection development has been approved by shareholders and has started. The Phase 2 development is one of t d gas & oil fields have been overcome with new technologies developed by Shell. These challenges include: contaminant separation at min d which has resulted in a better understanding of the value of surveillance activities. Integration of laboratory data production well test resu hat produce mixtures of fluid phases is challenging because of the associated complex flow regimes that radically change the physics and te of production through a single well conduit. As a result significant cost benefits can be realized (i.e. one concurrent smart well can potentiall

l plane Mulussa F (MUF) formation. The Omar Field is formed by an elongated high relief tilted horst block which is internally compartmen ble to compute the sensitivities of the total (lifecycle) value with respect to all (time-dependent) well control variables in one go at a cost les n zones and the optimal operational strategies for the ICVs. A gradient-based optimization technique was implemented in a reservoir simula ence of shallow gas over the crest of the structure which masked the seismic response in the crestal area of the reservoir. This impacted th her approaches that use the time-lapse seismic data to infer saturation and pressure directly this method uses a finite-difference black-oil s. These pseudowells produce or inject at a very low rate and thus have a negligible influence on the overall flow throughout the reservoir. n an impermeable acrylic matrix. The initially oil-saturated model was waterflooded via the upper channel and the injected water was dyed b d production data. An efficient variant of the ensemble Kalman filter namely Singular Evolutive Interpolated Kalman Filter (SEIKF) is applie ation framework extends current working practice by sampling Bayes' posterior parameter probability distribution with a rigorous MCMC met linear viscous fluids. Applications are the reduction of heat transfer to minimize trapped annular pressures or to reduce heat loss from prod he dynamic fracturing process in complex reservoir grids. We have developed a new modeling strategy that combines fluid flow and fractur and to a number of actual field cases (waterfloods produced water disposal) worldwide. In these field cases validity checks were carried ed using an explicit scheme. The dynamic well simulator the dynamic reservoir simulator and the coupled dynamic well-reservoir simulator control strategy to mitigate gas coning and wax deposition. The dynamic simulation environment has been developed within the research fr

mmon method for studying subsurface uncertainties. In this paper current applications of ED to subsurface modelling are evaluated from fu al core analysis data is available however the representativeness of this data is limited due to differences between reservoir and laboratory umber (high velocity) and non-Darcy flow. The new method has been implemented in a compositional-reservoir simulator and verified with fi

n be described by Poisson's equation ( ) where the local density of grid points is controlled by a variable source term (G). This source term c re attempting to apply them. In this paper we focus on different gridding methods and evaluate their performances. Three main grid genera employ the new vorticity-based gridding that generates a non-uniform coarse grid with high resolution at high vorticity zones. In addition to c

ssed using basin-wide compositional dynamic simulation approach. Like many reservoir simulation projects at the initial phase of this projec ormation and fracturing the limited applicability of the elasticity assumption and the latent uncertainty in the structural geometry of faults. T he static model (which consists of the development of matrix and fracture models as well as the method to integrate them) is also presented n the literature among which the well-known Warren-Root and Kazemi shape factors. The aim of this paper is to show that the selection of

edicting the initial rate of the well and the longevity of the well. Historical information is often extremely useful in such an exercise. In a Deep

35x reduction in run time was achieved. At each stage in the simplification process the results were compared with the full model and the las o poor approximations of the cross-covariance matrix resulting in loss of geologic realism. Specifically the updated parameter field tends to vative the first few eigenvalues of the pressure-transient decay modes. These values are characteristic of the reservoir and fluid properties g of the result of a reservoir simulation run. In some cases the results are easy to understand and appreciate for example increasing well co nge of possible subsurface scenarios early in the study. A fundamental first step in the integrated modelling workflow has been to develop a

use scaleup software program SCP was used for scaleup. SCP employs a single-phase flow-based process for upscaling nonuniform 3D e (to mitigate against supply interruption). This paper reviews the outlook for gas storage across Western Europe and in particular the U.K d the physics of fluid flow a didactic analysis of water cut models derivable from popular oil rate models of Arps Li and Horne as well as the ™s General Purpose Research Simulator (GPRS). The model computes pressure temperature and oil water and gas phase fractions alon tialising reservoir static models while imbibition Pc is used to model secondary and tertiary recovery processes. The objective of this paper additional well information it became apparent that the field was highly compartmentalized in the vertical and horizontal domain. Since then ons using particle tracking simulations (free from numerical dispersion) on three-dimensional high resolution models at the field scale. We s

y depletion and miscible gas injection. The cluster is being developed in a phased approach. The key objective of each phase is to gather d gas cap lowers the viscosity of the oil and accelerates conventional GOGD as seen in the 220 cp heavy-oil Qarn Alam field in Oman. Pilo timate recovery. Especially for shallow fractured reservoirs it may be attractive to inject steam to improve oil rate and recovery. Heating of t meabilities are usually low <10 mD resulting in low gravity drainage production rates with high remaining oil saturation and/or capillary hold eadsheet model based on historical measured gas production rates and volumes. The paper describes how to convert an analytical gas p t-Burman design (FPBD) is used to generate typical reservoir facies models using multipoint geostatistics method. Then reservoirs propertie mance. Moreover SAGD’s performance has been compared with the performance of CSS (cyclic steam stimulation) the other leading i encased in salt.�� No water has been produced to-date from this reservoir.� The reservoir oil column is overlain by a gas cap and th ection/production injection step-rate and fall-off test data of an existing complex waterflood in the Pierce field North Sea. The mental subs omena such as flame length and heat release rates. This limited validation to onshore and platform well blowouts which are usually govern apply these smart technologies to mature fields with a legacy infrastructure and long production history.� Participants felt that maturity i r operations’ progressively smarter using a combination of IT instrument engineering telecommunications and change management. > 0.934] in Brazil and the North Sea that otherwise would have been uneconomical. This article discusses where the industry started how developed economically without the introduction of new technology to both reduce costs and the amount of energy required to separate CO id stimulation campaigns in Brunei and Malaysia. Recently stimulation in carbonate gas reservoirs brought new successes. This paper dis very projects. Details of well geometry and design optimizations may prove to be minor sensitivities in high-cost deepwater developments; Volume of 285 MMbbl and 0.8 Tscf. However the field is experiencing high water cut and declining production. Agbada Field is covered by s

ching was carried out with an analytical 1D 2-phase Buckley-Leverett model to assess the potential scope of recovery with additional develo

4 kilometers of reservoir intervals with total depth of up to 8 kilometers and are divided into several zones with external casing packers or sw

nsport equations indicates that at a permeability of approximately 0.1 md or less heat transport in the diatomite tends to be dominated by th

more crucial in a field with multi-layered reservoirs having different permeability pressures and structure. Data acquisition should be schedu

ls sent via the fluid column. These signals are carried by tube waves that move borehole fluid back and forth radially across the completion elaborate operational aspects involved in wireline formation testing success requires detailed upfront planning and procedural design as w ace deformation for the volumetric deformation at the reservoir level using the inversion techniques from the literature so that the areal dist ng in phase with the tide. Simulations show very good agreement with the theory. The observation of the tidal response in petroleum reserv that differentiate between Oil Holdup (Yo) Gas Holdup (Yg) and Water Holdup (Yw) as well as providing multiple spinners for revealing stra ormation through compaction logging and of the individual reservoir layers through multi-rate production logging is critical to the success of ting. Realizing value through surveillance using the appropriate technology is the common thread that binds these well intervention example er encountered some technical challenges and hindered the full interpretation of test results. This paper presents the results and findings o

n tool (Stim2001) for detailed candidate selection damage diagnosis fluid system selection and job design. QA/QC and compatibility tests y sand control issues and the relative strengths/weaknesses of the systems available. Production hotspots arising from partially plugged sc eries of self-regulating reactions with calcite and other minerals. However excess calcite does not improve the retention of phosphonate du e a steady-state wellbore simulator including choke models to represent the ICVs and inflow models to represent the near-well reservoir flow

bores. Experimental studies on the rheology of polymer-enhanced foam were conducted using a specially designed flow-through rotational opment of Expandable Sand Screen (ESS) combined with fracturing treatment could not control produced sand due to failure in perforation roject (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006 which indicated that the poly

available dynamic multiphase well simulation tool (OLGA) and a dynamic multi-phase reservoir simulator (MoReS). In order to give a proof er emulsions were injected into etched-glass micro-models and micro-models packed with glass beads. The effect of droplet-to-pore size ra d that the compartmentalized completion with inflow control valves (ICVs) in the smart well has added value because the well would not be

as SurfactantAlternatingGas (SAG). The CO2 was either under sub- or super-critical conditions whereas N2 remained under subcritical cond m Benteimer and Berea sandstone and sintered glass with large permeability contrast. X-ray computed tomography (CT) scans are used to ction Foam is an excellent acid diversion agent for matrix acidizing operations. It is inherently non-damaging and often low cost allowing ea s reduced which increases the velocity and restores liquid transport to surface. The disadvantage of the velocity string is the increase in fric

inclination angle flow regime transitions and the interaction between tubing outflow behavior and the reservoir IPR. In the paper the behav through the LEP hardware. Modelling of the injection scenario with LEP’s has shown that in high permeability contrast reservoirs at cr p application.� It includes a perforating system database built from published API data.� This is not ideal since API Section I data are er.� The use of a drill-in liner however necessitates perforating.� Typically completions in such reservoirs are acid stimulated to max aluated to help minimize the risk of fines plugging because of the high fines content (10 to 15%). To minimize well interventions while maxim etion the reservoirs were cleaned up through a temporary well clean-up and test facility to test productivity and evaluate integrity of the dow modification because they were only validated to 1 000 psi in the current laboratory test apparatus. A series of burst tests were conducted o ning across the two zones. Upon completion the reservoirs were cleaned up through a temporary well-cleanup and test-facility to test produ s is presented for the high rate gas wells along with the workflow used for the selection and optimisation of the completion design based on

nd production from oil and gas wells respectively. The procedure considers filter paper medium natural core and synthetic core as the thre aged zone. Placing gelled acid through coiled tubing has been the standard practice to clean up the wellbore. Due to the low pumping rate (e.g. propped) fractures. Injection Fall-Off (IFO) test analysis offers a cheap way to infer the dimensions of induced fractures from welltests

thodology for the analysis of high angle well pressure transient tests. This paper compares the high angle and horizontal well solutions sho

og interpretation was performed during drilling. For the first time a low gradient Magnetic Resonance (MR) while drilling technology was dep uge was retrieved and the data were read out. First of all comparison of the magnitude of the observed annular pressures with the burst an ing to changing requirements. This has resulted in requirements for more complex data gathering over a shorter time with much stricter env ion testers have been commonly used to acquire formation pressures pressure and reservoir fluid samples for a number of decades. Many ion for lease owners petroleum revenue tax purposes and management reports as well as feeding into hydrocarbon reserve figures and r

eading role towards addressing the need for an increasing worldwide demand for energy while at the same time dealing with the need to re nt and leading role towards addressing the need for an increasing worldwide demand for energy while at the same time dealing with the ne ured continuously as a function of water saturation at in-situ conditions. To facilitate the interpretation of the coal measurements we also ob el equation shows that super-diffusion is only a transitional effect. i.e. there is (1) an initial phase in which the relaxation process dominates n of 1.48% corresponding to an average pore pressure of 13 MPa. A matrix swelling coefficient (Cm ) of 1.77� 10–4�� MPa–1 w rformance and implementation of carbon sequestration projects. Coal can be understood as a macromolecular cross-linked polymeric stru

rticular the presence of fractures. More specifically a number of questions need to be addressed e.g. what are the conditions under which ues and provide operational experience which all contribute to the development of harmonized regulatory frameworks and standards for C sporting and injecting CO2 in oil and gas operations. This talk will illustrate some of the technical challenges that can be expected during th torage as a potential option for reducing future emissions of Greenhouse Gases (GHGs) from the extraction of resources the production a ment initiatives anticipate significant sustained improvements in recovery and operating efficiencies while maintaining safe operations. This orked on extensions addressing production reporting the use of a common “flow network model and into “smart wells. This paper

Sampling Technology) global centre of expertise is routinely implementing such integrated approaches for fluid characterisation. For exam driven models constructed and updated from production well tests and real time production data. This paper will discuss two extensions o during the intervening period.�Errors are typically spread across the wells and reservoirs through a reconciliation process comparing estim smart applications requires new ways of working and different skill sets of the operators and support engineers. This is a particular challeng

w corporate standards. The pilot project yielded almost immediate benefits.�WRM cycle times were reduced by an average of 60% throu and injection testing. Our recent examples of closed system tests and wireline formation tests have convinced us that we can get compara al (HSE) impact. In more pragmatic terms an OVT is any pressure transient test in which live hydrocarbons do not have to be produced dir

known to be rich in oil accumulations. Not all of them are straightforward economic discoveries. In the case of Champion West (CW) �th

known a priori. Moreover taking these numbers too large slows down the optimization process and increases the chance of achieving a su nformation to make the right decisions. Introduction All smart projects strive towards the implementation of actions on or changes in the as hnology process and people. Successful introduction of Smart Fields� in an asset therefore needs to cover all three aspects: reliable co ccessfully drilled in Champion West as of April 2006 and three more are planned during the remainder of 2006. The well design not only fa

hampion West phase 3a. Best practices refers to those developed during the project that have resulted in: ����• ��� ment combined with growing recognition that the primary value driver for the application underbalanced drilling is dynamic reservoir charact ing rigorous pre-screening planning execution and feedback of learning de-veloped that enables fast implementation of underbalanced dri n and to assess the burn characteristics of the crude/reservoir rock system.� The ensuing estimation of the potential incremental recover ture modeling. Geomechanical modeling suggests large-scale shear failure in the sand and in the bounding shale during polymer flooding. on. The phase tests also give information on the quality of the micro-emulsions obtained where low viscosity and absence of gels is desirabl in low gravity drainage production rates with high remaining oil saturation and/or capillary holdup. EOR techniques such as steam injection alia. Air injection involves the continuous injection of high-pressure air into the reservoir. The oxygen in the air reacts with the reservoir crud for a wide spectrum of fluids (from near-critical systems to black oil systems) using miscible sour gas-blends while minimizing cost and the cross flow. In stochastic random permeability field foam injection increases the liquid recovery by a factor of two in comparison to gas injec e of heterogeneity a Dykstra-Parson’s coefficient1 (VDP) of more than 0.8 has been measured from core plug data. For the purpose o

team floods. Whereas the primary production performance of the Qarn Alam under cold GOGD is only expected to recover 3-5 % of the oil

r in a Middle Eastern sandstone reservoir with highly saline formation water was interpreted to be caused by an oil bank ahead of the slug o gh-conductivity fractures (fracture gas breakthrough) zonal-isolation failure at the wellbore (mechanical gas breakthrough) and increasing g ner.�The gel/cement system combines the properties of two shutoff techniques: • Cement for mechanically strong perforation shutoff. 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 performed around the world. The addition of particulates to the OCP system resulted in synergistic results. The PG system provides (1) leak asing the oil-water interfacial tension. These chemicals termed wettability modifiers" (WMs) effectively reverse the sign of capillary pressur ermine the optimal timing of developments of new fields to identify bottlenecks in the network and evaluate options for removal of these bo nvex gas lift optimization problems. Introduction It is generally assumed that optimization opportunities in the oil and gas industry are smoo robust flow assurance solutions in such severe operating environments. The operating environment that exists in many Russian gas and o 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 to determine the MMP. The gas-oil ratios have also been varied (both on molar and volumetric basis) widely in the high-pressure and highsity of gave an average absolute error of 1.55% a maximum absolute error of 5.366% and a standard Deviation of 1.29. To test the genera

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 id traits and has different implications. When these analytic methods are systematically combined and consistently applied the synergy del filtrate uses optical means to monitor the buildup of both color- and methane-absorption signals during sampling. The technique provides re with the identification of compound classes is a major challenge in the prediction of asphaltene problems with petroleum fluids. Fourier-Tra water content pressure and temperature (i.e. operating conditions on the viscosity of live heavy-oil emulsions). Two heavy oil samples fro of surfactants (nonionic and anionic) in varying concentrations have been used at reservoir conditions of 82�F and 700 psi (27.8�C an

cenarios. This paper discusses the successful application of a unique sandstone acidizing process that uses a single acid stage (no preflus

ersion effects correct modeling of the diversion methods in a placement simulator is essential. We have developed such a fluid placement s

or" to model invasion during drilling. Special core tests designed to measure effects of overbalanced exposure to drilling fluids are first cond model describes two types of naphthenate experiment viz. (i) full naphthenate precipitation and (ii) simpler “pH change experiments w

n Microscopy/Energy Dispersive X-Ray (ESEM/EDX) and Principal Component Analysis (PCA). ESEM/EDX can be used to determine if sc voir simulator. It is concluded that existing models are very restricted. They are applicable to particular cases where the phase transition be

g Shell’s fracture modeling software (SVS Fracture-Solution). They are based on fracture characterization that integrates the well data w development. Detailed geological models were created over two pad areas providing a geological framework large enough to have realist er cut well productivities via improved treatment fluid designs detailed candidate selection along with enhanced pumping methods are som ow that the early-time heating of the matrix cannot be captured using a constant shape-factor. We analytically derive the time-dependent (tr nse of the reservoir and its effect on the production process. Dynamic reservoir simulations for Pad 40 were done with the aim to obtain a p er isothermal conditions and in the absence of recharge gravitation will dominate. However gravitational effects are not always significant g induced impaired zone to enable effective stimulation of the reservoir and enhanced inflow performance. It was planned to perforate unde dramatic increases in the formation permeability after treatment with the chelating agent-based fluid. The improvement in permeability is as provide a detailed comparison of well productivity in the Pinedale Anticline as a function of proppant type and subinterval.� Well productio

treatments are placed in up to 70 discrete sand intervals over a gross interval up to 6 000 feet thick. Evaluations are further complicated b fectiveness of the hydraulic fracturing and to identify water entry points that may lead to premature completion failures. Typical wells produc ximum horizontal stress direction (aligned with the hydraulic fracture azimuth) and one perpendicular to this orientation. Each well was plac m single-point steady-state measurements is investigated. We also provide an update to these correlations using modern petro-physical dat inflow profile as a function of depth without the uncertainty of drilling induced formation damage. To achieve this objective the available un st analysis. Presently these heterogeneities cannot be accurately predicted by geological and seismic interpretation. For the Changbei field al setting. The Rotliegend reservoirs are characterized by a large variability. The average porosity varies between 8% and 18% with peak po

we have developed two key programmes for New Projects that integrate decision-making under uncertainty with technologies to mitigate ris

mance was suspected to be as a result of nearwellbore damage caused by the LCM-pill that was used during the re-entry. Integrated Produ radigmatic change in the way designers deal with uncertainty: instead of basing a design on fixed assumptions and then testing its sensitivi WorkFlow System (SWS) an Uncertainty Management Tool (UMT) and a Smart Collaborative Environment (SCE) all applied in the contex on. � Because of the general lack of relevant experimental data and the insufficient physical understanding of the characteristics of the t hm called the fluid-comparison algorithm (FCA) was developed to address this issue. The FCA propagates uncertainties in optical measure 5) hexane and heavier hydrocarbons (C6+) and carbon dioxide (CO2). For single-phase assurance it is possible to detect gas liberation (

ay the well encountered a near surface and resistive hydrate layer. Good quality but water-bearing reservoir was encountered at the target t describe the shale architecture at multiple scales e.g. shale drape coverage and frequency of occurrence. We demonstrate how to rapid 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 mottled and rooted mudstones 3 graded oolitic grainstones 4 cross-bedded oolitic grainstones. een to confidently characterize the reservoirs pre-frac in terms of both the reservoir quality and the deliverability mechanism (fractures vs. m s. Large touching vug (centimeter-scale) Cretaceous carbonate rocks from an exposed rudist (caprinid) reef buildup at the Pipe Creek Out etween our approach and previous methods based on two-dimensional images. Finally Kirkpatrick’s effective medium approximation is eous productivity index (PI). In this paper we introduce a parameter known as the Rate Integral Productivity Index (RIPI) which borrows fro roductivity index was necessary to determine fraction of fluid conductive seismic faults and fracture corridors from borehole images. The res ough or seismic lineaments. This fits well into a Bayesian scheme to infer the cause from the manifestations. The conditional probability of h hese powerful methods are combined systematically and applied to data sets the resulting synergy delivers a much more accurate and rob y delivers a more accurate characterization of the reservoir. In this paper we link traditional and novel fluid analysis methods to build a mor g data (e.g. static pressure gradient analysis and downhole fluid analyses) PVT and geochemical fingerprinting have provided major inputs bility characteristics. This paper presents a case study of using a properly measured set of relative permeability data to replace the previou n as a qualitative wettability indicator assuming external factors to be negligible and/or invariant from one experiment to another. Through d

phased Bubut-Danau development with FID planned for 2011. BSP’s successful implementation of Techlog module K-MOD to model p specific technologies notably to reservoir characterization are seen key to unlock the potential of these discovered volumes.� Technical e: contaminant separation at minimal energy consumption and losses at minimum capital investment. This paper will present these challe

and presented in this work. The main factors that influence oil rim performance are highlighted and oil recovery trends have been establish ns for calibrating the structure. Fortunately the 4D-seismic interpretations have largely compensated for this shortcoming by providing impr nd petroleum resources maturation. In the project management section the multi-disciplinary integrated team approach implemented in the s

wing high field production rates to be sustained. Well and reservoir performance data obtained during the first three years of production an

roduction life complexity of the high quality reservoir has been underestimated leading to inadequate historical data acquisition and integra

monstrate that induced fracture dimensions can be very sensitive to typical reservoir engineering parameters such as fluid mobility mobility simulation models1. A full field static model was built comprising over 400 wells. More detailed static sector models were also built for eac GIIP uncertainty. GIIP uncertainty was large with a 40% difference between high and low cases despite a long history of production. The fie results have been combined into a fully integrated production system model from each reservoir to the LNG plant and Oil Export Terminal. ain-flow direction. We optimized the rates of the eight injection and four production wells over the life of the reservoir with the objective to m workflow and learnings of the study. Introduction The� cluster of fields in South Oman holds a significant near-term growth potential thr d return on investment. Hydrocarbon was encountered in the Ogbotobo field between depths of 4755 (X sand) to 8684 (Z sand) ft tvss; how production and ultimate recovery in the whole Champion field. The main boundary condition for the rapid water injection project is the use as producing under a solution gas drive & a very weak aquifer for about 5 years. During the course of production reservoir pressure decrea The model predicts the timing and amount of gas shortfall (the difference between demand and available supply) as well as depletion of reco – as well as 120 000 barrels of oil equivalent a day of ethane liquefied petroleum gas (LPG) and condensate. The project is being develop ween injector plugging and the extent of induced fractures [1] for which duty the available simulation models have been found to be wantin e of beneficial use of produced water is demonstrated overall considerations for effective water management are introduced and the questi Control also plays a crucial role in plant safety and availability as stable wells or facilities are operated more frequently within the design wi s been primarily responsible for the decline in oil production. The average water cut in the field is 80%. The offshore platform on which the r

voir souring but because of the high capital-expenditure (CAPEX) costs it was dropped and because there were no other proven mitigation s set at 50 ppm (v). The decision to control reservoir souring with biocide and handle H2S at surface was re-evaluated in 2003 and it was c WRI pilot corrosion rates were measured continuously Downstream (D/S) the Water Injection (WI) pumps in the High Pressure (HP) system in itself some of the toughest technical challenges. This paper outlines specific corrosion challenges related to the use of sulphur solvents; were designed for sour service. Occasional monitoring confirmed high H2S levels to prevail but also showed an alarming increase with time inhibitor onto the formation rock. This paper discusses the effect of a mutual solvent preflush on scale inhibitor squeeze lifetime and also o ogic realizations; (d) Presence of complex sub-seismic geologic architecture may render workflows that solely rely on seismic data obsolete. The Phase 2 development is one of the largest petroleum development projects ever undertaken in Oman. This paper describes the strateg lude: contaminant separation at minimal energy consumption and losses at minimum capital investment. This paper will present these cha ratory data production well test results and model-based-rates are enablers for improved production allocation to individual wells. “Data t radically change the physics and technology of measurement. Depending on the borehole deviation the velocity and fluid holdup of differe concurrent smart well can potentially replace two conventional dedicated oil and gas wells). Reservoir simulation has demonstrated the abi

ock which is internally compartmentalised. Originally the field produced naturally at a peak net oil rate of some 80kbpd but production dec rol variables in one go at a cost less than that of an extra reservoir simulation run. These sensitivities can be used in an optimization loop t as implemented in a reservoir simulator equipped with the adjoint functionality to compute gradients of an objective function with respect to rea of the reservoir. This impacted the evaluation of structure and reservoir properties from seismic. To address this a new 3D-survey was a od uses a finite-difference black-oil reservoir simulator to ensure that the material balance and flow equations are honored. Two ancillary iss verall flow throughout the reservoir. The gradients of NPV over the lifespan of the reservoir with respect to flow rates in the pseudowells are el and the injected water was dyed blue to allow the displacement process to be recorded on video. Production rates pressures water cuts ated Kalman Filter (SEIKF) is applied to the multi-model history-matching problem in this work. This novel technique operates in three steps tribution with a rigorous MCMC method using the Metropolis-Hastings algorithm. This improves uncertainty estimates in the history-matchin ures or to reduce heat loss from production fluids containing hydrates The most important conclusion is that the influence of gel strength on y that combines fluid flow and fracture growth in one reservoir simulation. Dynamic fractures are free to propagate in length and height-direc cases validity checks were carried out comparing our results with available surveillance data. These applications address various aspects led dynamic well-reservoir simulator have been used to simulate a realistic test case which consists of a horizontal well with three inflow sec een developed within the research framework of the 'Integrated System Approach Petroleum Production' knowledge center of TNO TU Delf

ace modelling are evaluated from fundamental principles- mathematical and physical consistencies of the proxy equations as well as robus ces between reservoir and laboratory conditions. The cores might also have changed properties such as wettability depending upon coring eservoir simulator and verified with fine-grid compositional simulation results for both lean and rich gas-condensate fluids. Pressures satura

source term (G). This source term can be based on different grid point density indicators such as permeability variations fluid velocity or th rformances. Three main grid generation techniques are considered: permeability-based (PB) flow-based (FB) and vorticity-based (VB) grid high vorticity zones. In addition to control numerical dispersion we use Dual Mesh Method (DMM) which uses different grids to solve pres

cts at the initial phase of this project “isolated performance prediction of the subject reservoirs was considered mainly due to unknown n the structural geometry of faults. The integration of historical production data and well-test permeability into geomechanical fracture mode to integrate them) is also presented. Both matrix and fracture systems play an important role in the production mechanism of the reservoir aper is to show that the selection of the appropriate shape factor should not only depend on the shape" and dimensions of matrix blocks b

seful in such an exercise. In a Deepwater field in the Gulf of Mexico understanding the behavior of existing wells and reasons for their histo

pared with the full model and the last step was to compare the probabilistic results between the full and simplified model. The probabilistic a the updated parameter field tends to become scattered with a loss of connectivities of extreme values such as high permeability channels a of the reservoir and fluid properties but not of the pressure history or well location in the reservoir. The smallest eigenvalue is used to extra ciate for example increasing well count you may likely recover more oil. In some other cases surprises may be resolved by investigating th ling workflow has been to develop an� understanding of the depositional and tectonic history of the field in order to create static models

ocess for upscaling nonuniform 3D grids. Several iterations of scaleup were made to optimize the result. Sensitivity tests suggest that a un rn Europe and in particular the U.K. which historically has been cushioned from such needs due to its supply of domestic gas from the Nor of Arps Li and Horne as well as the Flowing Material Balance is carried out. This culminated in the development of an internally consistent water and gas phase fractions along the wellbore as a function of time and includes treatments for slip between fluid phases heat losses cesses. The objective of this paper is to present an improved reservoir characterisation and modelling procedure for predicting waterflood l and horizontal domain. Since then multiple data sources have been leveraged in order to obtain better compartment definitions: 3D seismi ution models at the field scale. We show that convective spreading even without local mixing can result in dispersion-like mixing zone grow

bjective of each phase is to gather data from the different reservoirs to assess if a miscible gas injection project would be feasible. Permane avy-oil Qarn Alam field in Oman. Pilot results in the Qarn Alam field support the commerciality of this process and a first-of-it’s-kind ste ve oil rate and recovery. Heating of the matrix will result in oil expansion reduction of viscosity solution gas drive and steam stripping of inte g oil saturation and/or capillary holdup. Thermal EOR methods have the potential to improve the gas oil gravity drainage (GOGD) rate and u how to convert an analytical gas productivity index solution for dual-porosity systems to a water injectivity index. The conversion was valid cs method. Then reservoirs properties (i.e. porosity permeability and saturation) are populated among different facies. The different scenari eam stimulation) the other leading in-situ technology for oil sands. The main finding of this work is that geology and reservoir properties ar olumn is overlain by a gas cap and the reservoir fluid exhibits a strong compositional gradient which impacts the degree of richness required ce field North Sea. The mental subsurface model that emerged from this data analysis was further developed through a series of dynamic f l blowouts which are usually governed by critical outflow conditions at surface i.e. ambient pressure is considerably less than the wellbore y.� Participants felt that maturity in itself made a challenge for deployment and enforces the need for effective Change Management. De ications and change management. The intent of this document is to chronicle some of the learning’s from DOF’s history initially fro ses where the industry started how technology has evolved and the lessons learned that are being applied to increase the application env nt of energy required to separate CO2 from methane and then sequester it safely below ground. For H2S contaminated gas fields the cha ght new successes. This paper discusses what have been done to identify and capture opportunities through collaborated efforts.� Best high-cost deepwater developments; however rig rate has a major impact on economics. The assessment required to minimize the number o uction. Agbada Field is covered by several vintages of 2D lines and one vintage of higher quality 3D seismic data that was acquired in the 1

pe of recovery with additional development. Together with dynamic production data animation on 2D maps a good view of the production-d

es with external casing packers or swellable packers.� Each zone is then equipped with an inflow control valve and pressure and tempera

atomite tends to be dominated by thermal diffusivity and pressure diffusion is dominated by the ratio of thermal expansion to fluid compres

e. Data acquisition should be scheduled and compared to baseline data such as a baseline pulsed neutron capture production or compact

forth radially across the completion layers. Such tube waves are capable of “instant testing of the presence or absence of fluid commun lanning and procedural design as well as real-time operational and interpretational support. It is becoming increasingly critical for operating m the literature so that the areal distribution of volumetric deformation can be identified. This leads to a better understanding of reservoir be e tidal response in petroleum reservoirs is an independent information provider [i.e. it provides information in addition to the (average) pres g multiple spinners for revealing stratified velocities travelling inside highly deviated completions. Pulsed-neutron (PNL) technology provide n logging is critical to the success of the Mars field. The program has consisted of obtaining time-lapse logging and reservoir pressures com inds these well intervention examples together. The first field example illustrates the effective use of a compact integrated production logg r presents the results and findings of a new history match study of the pilot. This simulation succeeded in achieving a good match of the pro

sign. QA/QC and compatibility tests aiming to obtain high success rate. In Brunei Shell a self-raising rig (BIMA) with a coil-tubing unit on b ots arising from partially plugged screens are often a problem giving rise to the challenge of installing rugged sand face completions which ove the retention of phosphonate due to the surface poisoning effect of Ca2+. The squeeze can be designed so that maximum squeeze life epresent the near-well reservoir flow in the various zones. The parameters of the model need to be updated regularly using real-time meas

ally designed flow-through rotational viscometer and pipe viscometers with different concentrations of hydroxyethylcellulose (HEC) polymer. ed sand due to failure in perforation techniques. An improved idea of perforating only the lower side of deviated wells using minimum visco y 2006 which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stres

or (MoReS). In order to give a proof of principle we have implemented a PID feedback controller which controls the gas fraction in a well b The effect of droplet-to-pore size ratio droplet stability oil and surfactant type and concentration were studied through visualization experim alue because the well would not be producing from over half of the reservoir section without the smart completion. Introduction Brunei Sh

s N2 remained under subcritical conditions in all experiments. Alpha Olefin Sulfonate (AOS) surfactant was used as foaming agent. We foun omography (CT) scans are used to visualize and quantify local fluid distributions and differentiate foam propagation in the different layers. F aging and often low cost allowing easily recursive treatments in case of an unsuccessful operation. Foam is resistant to strong and rapid de e velocity string is the increase in frictional pressure drop constraining production. Hence an optimal velocity string has to be selected such

servoir IPR. In the paper the behavior of different natural gas wells and of an air-water test setup are analyzed. Simulations were performe permeability contrast reservoirs at critical flow conditions perforations located in zones with permeability variation between 10 000 and 1 00 t ideal since API Section I data are an unreliable predictor of performance into stressed rock but this is the only published data allowing dir eservoirs are acid stimulated to maximise productivity.� Complete stimulation of the reservoir section is very difficult to achieve using acid imize well interventions while maximizing data gathering an intelligent-well completion using surface-controlled sub-surface variable chokes vity and evaluate integrity of the downhole sand-exclusion installation. Fines production possibly due to a failure of the expandable screens eries of burst tests were conducted on a wire-wrap screen design direct wrapped to 4-in. base pipe. The objective was to determine if the sc cleanup and test-facility to test productivity and evaluate the integrity of the downhole sand-exclusion installation. Fines production possibly n of the completion design based on these estimates. The optimum completion aims to delay the onset of sand to surface for the first 18 ye

core and synthetic core as the three filtering options. The paper also includes step-by-step example calculations of viscosity controlled leak llbore. Due to the low pumping rate stimulation results have been limited. A change was initiated aiming to have the acid pass the damaged s of induced fractures from welltests.� This paper presents a new methodology for IFO test analysis of fractured waterflood wells. This m

gle and horizontal well solutions showing Cinco’s slant well solution is valid provided the bed is sufficiently thick. As a practical matter th

R) while drilling technology was deployed in a virgin carbonate horizontal well on the Norwegian Continental Shelf. The MR Service was run d annular pressures with the burst and collapse ratings of the casings shows that annular pressure buildup is a serious consideration in casi a shorter time with much stricter environmental and safety constraints. Coupled with increased needs for more accurate reservoir data for p ples for a number of decades. Many hardware technologies and interpretation methods have been developed to acquire better quality reserv o hydrocarbon reserve figures and reservoir simulations which are used for major field decisions e.g. where to drill the next out-step well. S

ame time dealing with the need to reduce global emissions. No single universal policy or technology will solve the CO2 challenge. Therefor at the same time dealing with the need to reduce global emissions. No single universal policy or technology will solve the CO2 challenge. T the coal measurements we also obtain capillary pressure curves for unconsolidated-sand samples. For medium- and high-rank coal the p ch the relaxation process dominates (2) a transition phase that exhibits anomalous diffusion and (3) a long time phase that shows the typic 1.77� 10–4�� MPa–1 was calculated for this Selar Cornish coal. The low-rank Warndt Luisenthal coal exhibited higher strain o olecular cross-linked polymeric structure. An experimental effort has been made to measure the differential swelling effect of CO2 / CH4 on

what are the conditions under which the fluid in the micro-pores of the coal is displaced by the CO2 in the presence of competitive adsorptio ory frameworks and standards for CO2 geological storage. The preparatory phase of the project involved a baseline geological site explora nges that can be expected during the implementation lifecycle (from site exploration to closure) of such projects and is based upon our lea action of resources the production and use of fuels and the generation of electricity. In doing so it examines: roles CO2 capture and geolo le maintaining safe operations. This will require robust trustworthy implementation of measurement optimization and automation technolo nd into “smart wells. This paper authored by experienced members of the PRODML community explains the evolution from a concept

s for fluid characterisation. For example advanced mud-gas logging data can be used for fluid facies prediction and picking sampling points paper will discuss two extensions of FieldWare PU data driven techniques. The first extension is to apply the data driven models for produc conciliation process comparing estimated well productions and actual metered sales on a weekly or monthly basis. This paper describes th ngineers. This is a particular challenge in mature assets where the operational style has become embedded through time. Fieldware Produ

educed by an average of 60% through co-location of key disciplines and work standardization.�This enabled the existing well production nvinced us that we can get comparable data quality to a conventional test. Injection testing aimed at determining drainage volume is still re bons do not have to be produced directly to surface. Our OVT toolbox currently includes three types of well tests – wireline formation testin

ase of Champion West (CW) �the field was more or less accidentally discovered in 1975 by an out step development well from the Cha

reases the chance of achieving a sub-optimal solution. We investigated the use of multi-scale regularization methods to achieve grouping n of actions on or changes in the asset to be constantly measured and evaluated to support better decision-making. This constant flow of r o cover all three aspects: reliable corporate and real time data an integrated suite of tools to turn these data to information and a cadre of a of 2006. The well design not only facilitates initial clean-up but is used for reservoir management purposes and to manage gas and water b

in: ����• ����reduction of costs by reducing trouble time (Non Productive Time) ����• ���ï drilling is dynamic reservoir characterization creates a window of opportunity to move this initiative forward. This paper presents the conce mplementation of underbalanced drilling (UBD) and integrated technologies into “Brown Field areas and new business opportunities in â of the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical mo ding shale during polymer flooding. These are expected to affect both the fracture containment and the vertical-hole integrity. Finally fractur osity and absence of gels is desirable.� The surfactants described are promising for EOR and can be produced in commercial quantities. techniques such as steam injection and miscible gas injection have the potential to improve GOGD rates and recoveries: - In shallow fractu the air reacts with the reservoir crude consuming 5-10 % of the Original-Oil-In-Place (OOIP) and generating flue gases in-situ. This creates ends while minimizing cost and the time spent on the experiments. (2) Acquisition interpretation of the data (3) Utilization of the data for res tor of two in comparison to gas injection. Introduction Foam is an excellent mobility control agent for Enhanced Oil Recovery (EOR) proces m core plug data. For the purpose of building a tool that can be utilized for gas injection EOR study a five-step workflow has been impleme

expected to recover 3-5 % of the oil in place studies to date indicate that the recovery factor� under steam injection at 18 000 tonne per

d by an oil bank ahead of the slug of injected water; (3) The oil bank results from improved sweep by wettability modification to more waterw gas breakthrough) and increasing gas saturation in the matrix (matrix gas breakthrough). An integrated multidisciplinary team studied well a hanically strong perforation shutoff. • Gel for excellent matrix shutoff. The gel used as “mix water of the cement will be squeezed i 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 lts. The PG system provides (1) leakoff control for shallow penetration into the rock matrix and (2) squeeze-pressure properties. The slurry f reverse the sign of capillary pressure at the prevalent saturation. With the oil pressure exceeding the water pressure the capillary pressure uate options for removal of these bottlenecks. This analysis can also be used to underpin investment decisions to help optimise the produc in the oil and gas industry are smooth and convex problems each with a single optimum which can be located using local optimization alg at exists in many Russian gas and oil fields - both offshore and onshore - poses similar technical challenges. This paper notionally classifies 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 widely in the high-pressure and high-temperature optical cell to examine the compositional path effects on IFT and miscibility. Detailed comp Deviation of 1.29. To test the general validity of the new equation the equation was used to solve two problems for which solutions by the c

S scavenging. Many days of flow may be required in order to sufficiently passivate the metals so that an accurate H2S concentration can be consistently applied the synergy delivers a much more accurate and robust picture of the reservoir and the fluids therein. In this paper we sampling. The technique provides real-time analysis of sample contamination. Methane detection is essential for condensates and lightly co ms with petroleum fluids. Fourier-Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) is a technique well-suited for this pu ulsions). Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the f 82�F and 700 psi (27.8�C and 4.8 MPa). The dynamic oil/water IFT was found to be a strong function of oil composition temperatur

uses a single acid stage (no preflush or postflush is required) making multiple stage treatments much simpler while still achieving both eco

developed such a fluid placement simulator (FPS) that contains models for the different diversion methods. In this paper we will give an o

posure to drilling fluids are first conducted. Inputs to the simulation model are based on careful interpretation of the core-test results and th mpler “pH change experiments where no precipitation occurs. In order to predict naphthenate precipitation the theory suggest that we n

EDX can be used to determine if scale is actually formed in the well or near wellbore area. Several wells in a Shell field showed a decline in cases where the phase transition between the liquid and gas phases is absent. A rigorous description of a multiphase flow with a phase tra

zation that integrates the well data with 3D seismic field kinematic structural evolution and the regional understanding established by Petro mework large enough to have realistic boundary conditions including impact of surrounding wells. The geological models were imported into nhanced pumping methods are some of the many innovations that have yielded positive results in aged field production enhancement. Bef ytically derive the time-dependent (transient) shape-factor that captures the heating of the blocks for all time-scales. When this transient sha were done with the aim to obtain a predictive model. A dilation model from previous simulation work for Cold Lake CSS was applied on the b al effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characteriza ce. It was planned to perforate under-balanced to apply the highest perforation phasing to leave minimum gun debris in hole and to pull gu he improvement in permeability is ascribed to the removal of carbonate minerals and soluble clays without secondary metal precipitation. S e and subinterval.� Well production has been normalized by many parameters including reservoir kh kh∆P kh*(Pr2-Pf2) Φh and also

valuations are further complicated by variation in permeability exceeding two orders of magnitude and pore pressures increasing from 0.44 pletion failures. Typical wells produce relatively small amounts of water usually less than 5 percent by volume. It is nearly impossible to de this orientation. Each well was placed at approximately 660 ft from an existing producing well corresponding to a conventional 10-acre pat ons using modern petro-physical data. In the second part of our work we propose and validate a new "microflow" model for the evaluation hieve this objective the available under balance drilling operating parameters and drilling fluids were proactively controlled. This allowed th nterpretation. For the Changbei field development a dual lateral well with two 2000m horizontal sections has been selected. Some 50 wells between 8% and 18% with peak porosities ranging from 22-26% while the average permeability varies between 0.01 mD and 100 mD. In p

ainty with technologies to mitigate risks and skills and workflows to implement them. In the first programme we streamline the activities in

during the re-entry. Integrated Production Modelling (IPM) simulation using various sensitivities on FTHP skin factors and screen plugging p mptions and then testing its sensitivity to risks the approach recognizes risks in the design process and thereby develops valuable flexibility ment (SCE) all applied in the context of new collaborative work practices.�The authors will elaborate how this integrated solution enable anding of the characteristics of the transition zone modeling both the static and dynamic properties of carbonate fields with large transition ates uncertainties in optical measurement and contamination into uncertainties in fluid properties such as color composition and GOR. Th is possible to detect gas liberation (bubblepoint) or liquid dropout (dewpoint) while pumping reservoir fluid to the wellbore before filling a sa

rvoir was encountered at the target depth. This disappointment was the first CSEM negative test in the basin and vindicates the need for fur ence. We demonstrate how to rapidly generate effective properties at multiple geologic scales incorporating the effect of channel architectu 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

erability mechanism (fractures vs. matrix) before committing to these design specifications. This paper presents the results of a simulator u ) reef buildup at the Pipe Creek Outcrop in Central Texas were studied at three different scales. Single-phase airflow and gas-tracer experim ™s effective medium approximation is used to find the effective value of the hydraulic conductances of the individual pores. The method has ivity Index (RIPI) which borrows from the theory of rate-transient analyses. The mathematical and physical basis of RIPI and its relationship idors from borehole images. The results showed seismic fault maps from one of the two fields detected more than 90 percent of all fracture ions. The conditional probability of having a fracture corridor given an indirect indicator such as mud loss is calculated from wells with image vers a much more accurate and robust picture of the reservoir. In this paper we review a number of case studies in which we have success luid analysis methods to build a more complete interpretation of the reservoir fluids and provide greater insight into reservoir architecture. T erprinting have provided major inputs for reservoir modeling related to reservoir continuity. However none of these tools or data sets provide meability data to replace the previously used analogue database and hence reduce uncertainties of waterflood recovery predictions. The ex ne experiment to another. Through detailed modeling of the NMR response this concept has been developed further to provide a quantitati

Techlog module K-MOD to model poor-quality and missing log intervals in well BU-1 and the “Back-to-Basics way of working resulted discovered volumes.� Technically in the early stages the seismic attribute-based prediction of gas sand using a simultaneous inversio This paper will present these challenges and introduce new technologies that can help to reduce project development cost by as much as

recovery trends have been established. In addition a generic simulation model has also been developed to analyse oil rim dynamics and a r this shortcoming by providing improved lateral control for refining the reservoir-simulation models. All of the 4D interpretations conducted eam approach implemented in the sub-surface asset and field operations teams is highlighted.� In combination with technology support

he first three years of production and information from 4 D seismic shot in early 2008 are now used to optimize the planning and drilling of a

istorical data acquisition and integration efforts particularly in the low oil price world in the late 90s. This paper describes how all available

eters such as fluid mobility mobility ratio 3D saturation distribution (in particular shockfront position) positions of wells (producers injector ector models were also built for each distinct geological area and translated into elements of symmetry thermal simulation models. The cho e a long history of production. The field has been on production since 1987 and more than 60 % of the GIIP have been produced to date. F LNG plant and Oil Export Terminal. The Lunskoye field which is being developed with the highest capacity gas wells in Russia has used th the reservoir with the objective to maximize the average net present value (NPV). We used a gradient-based optimization method in which ficant near-term growth potential through active waterflood implementation and later through polymer flood recovery (Fig.1). The cluster de X sand) to 8684 (Z sand) ft tvss; however the major reservoir is the Y (OWCs Ca. 5500 – 5821 ft tvss) which accounts for over 75% of th pid water injection project is the use of existing infrastructure with the exception of three new water pipelines and nine new wells. This paper oduction reservoir pressure decreased substantially and went below the bubble point pressure. Waterflooding was considered as the most e supply) as well as depletion of recoverable gas resources for the various regions in the world for a 100-year period. To reduce the complex ensate. The project is being developed in two phases with the first phase expected to start up around the end of the decade. It is making g odels have been found to be wanting as they do not adequately describe leak-off dynamics. Recognizing this constraint Shell decided that ement are introduced and the question whether produced water can become an opportunity and a value creation rather than a legacy in any more frequently within the design window. Stable operation results in fewer shutdowns less breakdown maintenance less deferment less f The offshore platform on which the rigless operations were carried out posed a special challenge due to its proximity to two water injector pl

here were no other proven mitigation techniques available it was decided to operate without mitigation. The strategy for this project was to as re-evaluated in 2003 and it was concluded that there would be a risk that the maximum allowable H2S content in the facilities (i.e. 50 pp ps in the High Pressure (HP) system and after three months testing significant increases in corrosion rates were seen. These were though ated to the use of sulphur solvents; frequent pigging and inspection programs; corrosion monitoring the use of lined carbon steel materials wed an alarming increase with time casting doubts on future integrity assurance. As the materials used in the X and down stream receiving inhibitor squeeze lifetime and also on well clean up time. It builds on a previous publication that introduced a recent model to simulate the im solely rely on seismic data obsolete. We developed an adjoint-based optimization algorithm that rapidly identifies alternative optimal well-pla an. This paper describes the strategies employed by the team responsible for developing the reservoirs of the Harweel Cluster. The origina t. This paper will present these challenges and introduce new technologies that can help to reduce project development cost by as much a ocation to individual wells. “Data-to-information work processes have been mapped and automated as a natural part of the collaborative he velocity and fluid holdup of different phases can change dramatically for a given flow rate. We present examples that encompass variou simulation has demonstrated the ability of concurrent wells to enable simultaneous oil and gas production with minimal impact on oil recove

of some 80kbpd but production declined rapidly because of the lack of any pressure support. Following the implementation of water injectio an be used in an optimization loop to iteratively improve well controls. We implemented the adjoint method and an associated optimization n objective function with respect to control parameters. For computational reasons an initial optimization study was performed on a sector m address this a new 3D-survey was acquired in 2003 in an east-west direction to undershoot the shallow gas deposits. The Pre-Stack Time ations are honored. Two ancillary issues were important in obtaining a match.� First it was necessary to convert the map of change in re to flow rates in the pseudowells are computed using an adjoint method. These gradients are used subsequently to approximate improving d duction rates pressures water cuts etc were recorded and used to history match the reservoir simulation model. The simulation model wa vel technique operates in three steps: resampling forecasting and assimilation. Unlike the ensemble Kalman filter where the members of t inty estimates in the history-matching mode and provides a unified platform for scenario management and analysis in the forecast uncertai that the influence of gel strength on convective heat transfer rate in oil industry applications is quite strong. Another conclusion is that the te propagate in length and height-direction with respect to poro- and thermoelastic stresses acting on the fracture. A prototype simulator for co pplications address various aspects that often play an important role in waterfloods such as short-cut of injector and producer vertical fractu a horizontal well with three inflow sections located in a thin oil rim. A number of scenarios are investigated that play a crucial role during diffe ' knowledge center of TNO TU Delft and Shell. This simulator has been validated with field data of a horizontal well located in a thin oil rim

he proxy equations as well as robustness in modelling uncertainties. Within the context of modelling and mitigating subsurface uncertainties wettability depending upon coring method cleaning etc. In order to screen the value of expanded water flooding a performance review of ondensate fluids. Pressures saturations relative permeabilities viscosities and densities calculated with the semianalytical method are in

eability variations fluid velocity or their combination e.g. vorticity where they can be extracted from reference fine grid. Once background g d (FB) and vorticity-based (VB) gridding. We apply all three methods to some 2D heterogeneous models and simulate two-phase flow on t ich uses different grids to solve pressure and saturation equations. The coarse grid generated from vorticity is used for computation of pres

s considered mainly due to unknown lateral connectivity and the differences in the discovery dates. In later years there was a need to pred y into geomechanical fracture modeling is a practical way to reduce such uncertainty. We propose to combine geostatistical algorithms for h oduction mechanism of the reservoir. History matching for 20 years of production was done successfully in a single-media model through an and dimensions of matrix blocks but should also take into consideration the character of the dominant underlying physical recovery mecha

sting wells and reasons for their historical deviations from prediction has formed a major input into the design of the next Phase developmen

simplified model. The probabilistic analysis was based on a Monte Carlo simulation (Latin Hypercube). The result of this study will help ope uch as high permeability channels and low permeability barriers which are of special significance during reservoir characterization. We pro smallest eigenvalue is used to extrapolate the long-time behavior of the transient to estimate the final reservoir pressure. The second eigen may be resolved by investigating the underlying principles of fluid flow through the grid blocks. Because of the complexity of some reservoir eld in order to create static models that capture the range of uncertainty in geometry and� properties of the reservoirs. Data from core w

t. Sensitivity tests suggest that a uniform scaled-up grid overestimates breakthrough time compared to the fine model and the post-breakth supply of domestic gas from the North Sea. The paper considers the changes that might be expected to happen as indigenous gas is deple elopment of an internally consistent water cut model applicable during exponential decline of oil production. The development supports an p between fluid phases heat losses to the reservoir and general variations of fluid properties with temperature and pressure. The purpose o procedure for predicting waterflood performance of a Cretaceous carbonate reservoir in the Middle East. We focus on the characterisation compartment definitions: 3D seismic logs PVT data geochemical fingerprinting repeat pressure surveys and production data. The bound lt in dispersion-like mixing zone growth with large dispersivities because of permeability heterogeneity. But for such cases the dispersivity e

project would be feasible. Permanent downhole pressure gauges have been utilized to monitor reservoir performance from the depletion p ocess and a first-of-it’s-kind steam injection project is being implemented. The economic success of the Qarn Alam project depends on gas drive and steam stripping of intermediate hydrocarbon components. Solution gas drive and steam stripping effects potentially become m gravity drainage (GOGD) rate and ultimate recovery. For shallow fractured reservoirs it is feasible to inject steam into the fracture system ivity index. The conversion was validated using rigorous dual-porosity simulations and sensitised to a broad range of matrix and fracture p ifferent facies. The different scenarios of reservoir properties represent geological uncertainties. 2. The recovery factor of each model is co geology and reservoir properties are by far the most dominant features for a successful SAGD operation. SAGD targets must be reservoir acts the degree of richness required for a sour miscible gas.� Development drilling and the construction of facilities proceeded with all we eloped through a series of dynamic fracture propagation simulations. While the data analysis was a relatively standard procedure the fractu considerably less than the wellbore pressure just upstream of the outflow. For subsea wells blowing out against the substantially higher pre effective Change Management. Deployment and Change Management are seen as the major challenges facing the creation of Smart Fie ™s from DOF’s history initially from a Shell E&P perspective as this is the author’s bias. However it is hoped that this will spark sim plied to increase the application envelope and reliability of this completion method.�The review covers advances in openhole-drilling tech 2S contaminated gas fields the challenges appear even greater. The extreme corrosiveness and toxicity of H2S requires the application of hrough collaborated efforts.� Best practices and learnings leading to the success will be shared. Some of the high lights of the practices nt required to minimize the number of injectors and ensure their proper placement logically takes more time than exotic choices of injection smic data that was acquired in the 1993. Kolo Creek field is located within the swamp 110km South West of Port Harcourt Nigeria. The fie

aps a good view of the production-drainage–water influx pattern progression with time was obtained enabling a first pass identification of

ntrol valve and pressure and temperature sensors to allow monitoring and optimization of the recovery process from that zone.� Historica

thermal expansion to fluid compressibility. Under these conditions the temperature observed at a logging-observation well is governed by a

ron capture production or compaction logs. There should also be plans to monitor specific wells over the life of the project to observe and

resence or absence of fluid communication across the completion and are sensitive to changes occurring in sand screens gravel sand per ing increasingly critical for operating and service company experts to remotely monitor and interpret WFT surveys in real time through Webbetter understanding of reservoir behavior and also provides additional data for integration into coupled reservoir simulation modeling. This ion in addition to the (average) pressure and its derivative from a well test]. The implementation of the tidal effect in a normal reservoir simu d-neutron (PNL) technology provides two services related to measuring water production: 1) the Water Flow Log (WFL) measures the spee logging and reservoir pressures combined with reservoir modeling. Data has been obtained in the injection producing and monitor intervals compact integrated production logging tool that incorporates several technological advances and best practices to address complex produc in achieving a good match of the production data by the identification of (1) borehole reflux heat loss and (2) production impairment from sc

rig (BIMA) with a coil-tubing unit on board is used to overcome the limitations due to weather. A combined pumping procedure (coiled tubing ugged sand face completions which again could also compromise production. When it comes to selecting a sand face completion strategy igned so that maximum squeeze life is achieved by forming a low solubility phase in the formation. Addition of Ca2+ Mg2+ and Fe2+ in the ated regularly using real-time measurements and production tests and we discuss the impact of different smart-well instrumentation levels

droxyethylcellulose (HEC) polymer. Correlations have been developed for rheological parameters of aqueous- and polymer-based drilling fo deviated wells using minimum viscosity fluids and minimum amount of pad with limited proppant sand concentration resulted in low net pres ure encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture. The new results prese

controls the gas fraction in a well by changing its wellhead choke or inflow control valve (ICV) settings on a realistic test case. We introduc studied through visualization experiments. It was observed that blockage happened because of size exclusion. Also the blockage was acce completion. Introduction Brunei Shell Petroleum (BSP) is a keen implementer of wells with sophisticated trajectories for achieving maximum

was used as foaming agent. We found that injection of gas following a slug of surfactant can considerably reduce gas mobility and promote h propagation in the different layers. From both the model and the experiments we conclude that foam is primarily generated in the high-perm m is resistant to strong and rapid deformations encountered in porous media and in some cases to the contact with hydrocarbons.1 Foam ocity string has to be selected such that liquid loading is delayed over a long period with a minimal impact on production. This requires accu

nalyzed. Simulations were performed using both commercially available software and dedicated dynamic models. The onset of liquid loadin variation between 10 000 and 1 000 mD have the same maximum injection rate. If the wells from Peace River perform similar to the Impe s the only published data allowing direct comparison between systems. The tool calculates depth of fluid invasion stress-corrected penetra is very difficult to achieve using acid diversion techniques in a karstic environment due to the large variability in the permeability. �Propell ntrolled sub-surface variable chokes for internal gas-lift and surface controlled sub-surface fixed chokes was proposed. Another design cha a failure of the expandable screens commenced almost immediately upon well bean-up and steadily increased to the extent that the well w objective was to determine if the screen could withstand at least 4 600 psi without damage. The wire-wrap design selected to improve the p stallation. Fines production possibly caused by a failure of the expandable screens steadily increased to the extent that the well was deem of sand to surface for the first 18 years of production whilst maintaining high gas productivity (>300mmscf/d/well). The selection of continge

lculations of viscosity controlled leakoff coefficient and wall building coefficient. Introduction Filtration control of stimulation and gravel pack g to have the acid pass the damaged zone and generate wormholes through effective diversions. This paper describes the application of ac of fractured waterflood wells. This methodology derives the dimensions of induced fractures and the extent to which these are contained to

ciently thick. As a practical matter the standard horizontal well is rare. Most of the horizontal wells drilled in the Gulf of Mexico (GoM) are be

ental Shelf. The MR Service was run to obtain porosities (incl. partitioning of movable and bound fluids) HC saturations and permeability e up is a serious consideration in casing design. Such design is to be based on theoretical models for annular pressure buildup. The data acq r more accurate reservoir data for prospect evaluation this has put a higher emphasis on upfront planning and improved technical performa loped to acquire better quality reservoir information. Dual packer wireline formation testers offer an alternative an additional way to selective here to drill the next out-step well. Surveillance is key to determining well and reservoir behaviour and ensuring optimal well productivity an

ll solve the CO2 challenge. Therefore various CCS solutions will need to be considered within a portfolio of measures to reduce global CO2 logy will solve the CO2 challenge. Therefore various CCS solutions will need to be considered within a portfolio of measures to reduce glob r medium- and high-rank coal the primary drainage capillary pressure curves show a water-wet behavior. Secondary forced-imbibition expe ong time phase that shows the typical square root of time behavior of an ordinary diffusion process. The significance of the transition phase enthal coal exhibited higher strain of 1.6% and a matrix swelling coefficient (Cm ) of 8.98�10–5 MPa–1 was calculated. The rank dep ntial swelling effect of CO2 / CH4 on this macromolecular structure and to theoretically translate that effect in terms of porosity and permeab

e presence of competitive adsorption; what is the role of compositional heterogeneity and fracture anisotropy of coal for the injection design 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 projects and is based upon our learning both in recent CO2 sequestration projects and the industrial analogue of CO2 Enhanced Oil Reco mines: roles CO2 capture and geologic storage may play over the next century extending from the current assessment of this technology fa ptimization and automation technologies. Version 1.0 of the PRODML standard released in 2006 enables a range of production optimizatio plains the evolution from a concept to “do something about production data into a well-defined series of interoperable services with a d

ediction and picking sampling points for formation testing; PVT data can be calibrated against mud logging data; and downhole fluid analysi ly the data driven models for production optimization. The second extension is the case where no shared test facility for well-by-well produc nthly basis. This paper describes the development and application of a new tool FieldWare* PRODUCTION UNIVERSE * (PU) which esti dded through time. Fieldware Production Universe “PU is an application developed within the Royal Dutch Shell Group (“Shell). Re

enabled the existing well production to significantly exceed targeted production and a clear reduction in overall field decline has been obser etermining drainage volume is still relatively immature as we have executed only one injection test to date. However there has been consid well tests – wireline formation testing (WFT) closed system testing with cleanup and repeat surges and injection testing. Our recent exam

step development well from the Champion Main field drilled for gas lift supply. Fortunately the well discovered oil a new field was discove

zation methods to achieve grouping of the control settings of the wells in both space and time. Starting out with a very coarse grouping the sion-making. This constant flow of real time data also serves to calibrate the subsurface and production system models that are critical to E data to information and a cadre of appropriately skilled professionals that use the information to make the right decisions to control and opt oses and to manage gas and water breakthrough. Throughout the well life variable ICVs are used to achieve equal drawdown along the we

me) ����• ����reduction bit off-bottom circulation times ����• ����increase of bit on-bottom ward. This paper presents the conceptual framework to replace large manpower intensive surface equipment with a combination of down-h and new business opportunities in “Green Field devel-opment. This begs the question; what is Managed Pressure Drilling technology a equires fit-for-purpose numerical modeling.� Typically the flue gas generated in-situ by combustion leads to in an immiscible gas drive w vertical-hole integrity. Finally fracture predictions underscore the importance of the geomechanical considerations on determining the fractu produced in commercial quantities. Different IOS products are available with different carbon chain cuts (with range C15 to C28) allowing m es and recoveries: - In shallow fractured reservoirs it is possible to inject steam in the fracture system. Steam will condense as long as it con ating flue gases in-situ. This creates a gas drive process and acts to re-pressurize the reservoir. The process does not require water as a m data (3) Utilization of the data for reservoir engineering/design calculations using a consistent approach for a cluster of sour reservoir fluids nhanced Oil Recovery (EOR) processes such as gas (nitrogen carbon dioxide etc.) or steam injection [1-8]. Due to its unique microstructu ve-step workflow has been implemented: High resolution vertical geologic modeling to capture heterogeneity Flow-based rock typing to m

steam injection at 18 000 tonne per day will be in the range 20-35 % with Oil Steam Ratio of 0.16 -0.3 m3 oil /tonne of steam. The learning f

ettability modification to more waterwet state. The interpretation was confirmed by laboratory experiments; (4) Experiments in limestone cor multidisciplinary team studied well and reservoir performance and openhole (OH) and cased-hole logs to diagnose the source of higher-tha er of the cement will be squeezed into the matrix creating a shallow matrix shutoff. The cement will remain in the perforation tunnel as a ri 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 eze-pressure properties. The slurry filtrate (OCP) is thermally activated. After exposure to the targeted bottomhole temperature of the well i ater pressure the capillary pressure becomes the driving force for oil expulsion from the matrix and into the fracture system. Previous publi cisions to help optimise the product slate and analyse trade-offs between for example energy efficiency production and overall recovery. located using local optimization algorithms such as LP SLP or SQP. In reality a large number of optimization opportunities such as gas lif nges. This paper notionally classifies Russian fields based upon their expected flow assurance issues and challenges and describes issues 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 n IFT and miscibility. Detailed compositional measurements of both vapor and liquid phases were carried out using a gas chromatograph a roblems for which solutions by the complex Charts of Carr et al (which have not been curve fitted )were available. The first problem from the

n accurate H2S concentration can be determined. Wireline formation testers have historically been regarded as a non-viable alternative. In the fluids therein. In this paper we review two case studies in which we have combined multiple techniques for the assessment of compos ential for condensates and lightly colored crude oils; for such fluids the color buildup becomes difficult to detect but the high methane cont s a technique well-suited for this purpose due to its unmatched resolution and the possibility of providing information otherwise not availab samples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil/water emulsion nction of oil composition temperature and showed a slight dependence on pressure. An attempt has been made to explain the dynamic be

simpler while still achieving both economic and technical targets for the well. It covers the non-formation stimulation treatment of several we

ods. In this paper we will give an overview of the different diversion methods and their application. Further we will discuss the implementa

ation of the core-test results and thus are calibrated to observation. Details of the approach were presented earlier by Suryanarayana et al itation the theory suggest that we need to know (a) the partition coefficient of the naphthenic acid HA between the oil and the water phase

s in a Shell field showed a decline in barium figures and consequently were considered to produce in a scaling regime. ESEM/EDX analysis f a multiphase flow with a phase transition does not seem feasible. The possibility of a phase transition introduces a large uncertainty in the

understanding established by Petroleum Development Oman’s (PDO) long-term activities in the area. This integration makes the fractu geological models were imported into CMG’s STARS thermal reservoir simulator and a relatively fine grid was extended over each proje field production enhancement. Before 1996 Mud acid was the common Hydrofluoric acid (HF) system for damage removal in Niger Delta ime-scales. When this transient shape-factor is used in combination with an analytically derived viscosity correction (to capture the effect o Cold Lake CSS was applied on the basis of the monitoring analysis and incorporated into the simulations together with a relative-permeabili grading is sensitive to characterization methodology for some systems experimental data from a specially designed centrifuge system is e um gun debris in hole and to pull guns to surface to verify charges had fired and that the reservoir was amenable to future reservoir manag out secondary metal precipitation. Slurry reactor tests elucidated the kinetics of mineral dissolution in mechanically ground field samples. Tr kh∆P kh*(Pr2-Pf2) Φh and also compared by well location to determine the degree to which those techniques provide similar conclusio

pore pressures increasing from 0.44 psi/ft to 0.83 psi/ft. The analysis of “tight gas reservoirs has been the topic of many SPE papers volume. It is nearly impossible to detect such small watercuts with conventional methods of production analysis. However a probabilistic pr onding to a conventional 10-acre pattern. Twenty pressure sensors were distributed over the 6 000 ft productive interval. One well showed s microflow" model for the evaluation of an equivalent liquid permeability from gas flow measurements. This work is based on a more detailed oactively controlled. This allowed the rig crew to manage the inflow while drilling and near well bore skin damage reducing the uncertainty s has been selected. Some 50 wells will be drilled from 3-well clusters over a period of 9-years this allows continuous subsurface learning between 0.01 mD and 100 mD. In parallel the compressive strength of the formation material shows drastic variations as well i.e. between

mme we streamline the activities involved in planning the field development. This includes simplifying project management responsibilities

P skin factors and screen plugging predicted that the poor performance was more from surface than from subsurface issues. Requests to in thereby develops valuable flexibility that increases the expected value of projects. A case study of an oil platform development in the Gulf o e how this integrated solution enables the asset teams to optimize their expenditure of scarce resources on the right reservoir scenarios and carbonate fields with large transition zones remains an ongoing challenge. In this paper we first review the transition-zone definition and the as color composition and GOR. The output of the FCA is the probability that two fluids are statistically different. Real-time application of th 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

basin and vindicates the need for further development of processing and interpretation methodologies. This paper will present the key CSEM ating the effect of channel architecture and reservoir connectivity into simple dynamic models. Use of simple dynamic models in conjunction g shoe. In addition the Modular Dynamic Tester (MDT) (�Schlumberger) minifrac tests were performed at three depths in shale thus yiel

presents the results of a simulator used to analyze the mini-frac after-closure period to identify the presence of natural fractures. The simula phase airflow and gas-tracer experiments were conducted on 2.5 in. diameter by 5 in. long cores (core-scale) and 5- to 10-ft-radius well test e individual pores. The method has been applied to several data sets including consolidated North Sea reservoir sandstones outcrop san ical basis of RIPI and its relationship to the instantaneous PI are presented. The behavior of RIPI and its implications for reservoir characte more than 90 percent of all fracture fairways. The fault map could be effectively used for well planning and simulation and in combination w s is calculated from wells with image logs. Some indirect indicators have no direct link to image logs and a Bayesian inference has to be us e studies in which we have successfully combined continuous fluid/facies mapping pressure-gradient measurements DFA and geochemis insight into reservoir architecture. This leads to improved understanding of structural history hydrocarbon migration and entrapment reserv ne of these tools or data sets provide hydrocarbon distributions or fingerprints during the drilling process of a given well; only after the well h erflood recovery predictions. The experimental programme followed a recommended procedure of wettability restoration and a combination eloped further to provide a quantitative wettability index. It is based on a model for the microscopic distribution of the crude oil and the wettin

-to-Basics way of working resulted in an exploration success story in Brunei. Well BU-2 was drilled mid-late 2007 principally to test the dee sand using a simultaneous inversion technique was the key enabler for exploration success allowing to map the presence of coal versus ct development cost by as much as 40% compared to conventional technologies Application External studies (Steiner 2005) estimate a glo

ed to analyse oil rim dynamics and assess the impact on oil and gas recovery for a range of sub-surface uncertainties. A range of alternate d of the 4D interpretations conducted so far have indicated the need for simulation-model changes such as modified reservoir volumes in cer ombination with technology support from world-class technical expert groups this allows effective implementation of surveillance and reserv

ptimize the planning and drilling of additional wells as part of the Phase 2 development drilling project. Bonga is a ‘brownfield’ that is

s paper describes how all available subsurface data have been (re-)analysed and integrated resulting in a range of realistic dynamic reserv

ositions of wells (producers injectors) and geological details (e.g. flow baffles). The results presented in this paper are expected to also ap thermal simulation models. The choice of design parameters and handling of uncertainties were addressed in a phased manner. First the GIIP have been produced to date. For the redevelopment study that kicked off in 2007 a 2006 repeat 3D seismic swath study gave informa city gas wells in Russia has used the latest sand failure prediction software which can quantify sand production so that gas production is based optimization method in which the gradients are obtained with an adjoint formulation. We compared the results of the RO procedure to ood recovery (Fig.1). The cluster development strategy addresses 23 clastic fields with a significant STOIIP base. A large integrated team o s) which accounts for over 75% of the total field STOIIP. Production commenced from Ogbotobo in 1998 and to date various drilling campa lines and nine new wells. This paper describes the following: • Reservoir setting and production history. • Water injection philosophy. ooding was considered as the most suitable remedy to restore the reservoir pressure and well productivity considering all the parameters. -year period. To reduce the complexity of the problem the world is split into only ten regions. In each region demand supply and recoverab he end of the decade. It is making good progress and is overall more than 50% complete.| The project is currently in full swing both offshor g this constraint Shell decided that there is a need for unambiguous empirical data that do not suffer from the limitations associated with co creation rather than a legacy in any field development is addressed. Introduction “There are alternative sources for energy. There are maintenance less deferment less flaring lower operational cost and sometimes even higher ultimate recovery.� The impact of process its proximity to two water injector platforms. The injection water accumulation in the drainage area covered by the wells of this platform bec

The strategy for this project was to let the reservoir sour and handle the H2S with sour-service materials and scavenging facilities topside. T 2S content in the facilities (i.e. 50 ppm(v)) might be exceeded during the life time of the project. Given the positive experience with the inject ates were seen. These were thought to be related with the addition of nitrate to the Produced Water (PW). To investigate this more closely use of lined carbon steel materials and some case histories. The paper also addresses the challenges associated with well acidizing on su in the X and down stream receiving facilities are not to be NACE 175 souring compliant and consider H2S released are hazard for safety. S ced a recent model to simulate the impact of a surfactant on improved inhibitor retention which used data derived from laboratory experime identifies alternative optimal well-placement scenarios for a given geologic realization. Adjoint-based gradients approximate the sensitivities of the Harweel Cluster. The original vision has been bolstered by substantial near field discoveries during the last five years. The appraisal ect development cost by as much as 40% compared to conventional technologies� Application External studies (Steiner 2005) estima as a natural part of the collaborative work environment between the platform and the offices. Use of time-lapse seismic. Draugen acquired nt examples that encompass various reservoir management objectives well optimization and flow profiling.� Surveillance logs were acqu on with minimal impact on oil recovery. The proposed concept can significantly impact the portfolio of available gas reservoirs by delivering a

g the implementation of water injection from 1991 onwards a plateau production of around 60-70kbopd was achieved for some five years (19 hod and an associated optimization algorithm in our in-house reservoir simulator. In addition to conventional well control options based on th n study was performed on a sector model which showed promising results. Introduction St. Joseph is a mature oil field located 135km offs w gas deposits. The Pre-Stack Time Migration and Pre-Stack Depth Migration seismic results show the reservoir image is greatly improved y to convert the map of change in reflection coefficients to a map of change in impedance.� Second it was necessary to characterize the equently to approximate improving directions (i.e. directions to move the wells to achieve an increase in NPV) on the basis of which impro on model. The simulation model was built using Roxar’s Nextwell software and populated with the rock and fluid properties of the ARM alman filter where the members of the model ensemble are operated by forecasting and assimilation in SEIKF the members of the model and analysis in the forecast uncertainty quantification mode. The stochastic framework is tested for robustness and efficiency on a real field ong. Another conclusion is that the temperature differential required to initiate flow can be appreciable in practical applications and this mea racture. A prototype simulator for contained fractures was tested successfully. We have extended the coupled simulator to incorporate nonc injector and producer vertical fracture containment and reservoir sweep. We also demonstrate that induced fracture dimensions can be ve d that play a crucial role during different stages of the well’s lifetime: naturally occurring phenomena e.g. coning and production dynam orizontal well located in a thin oil rim suffering from gas coning and containing a crude which has a high tendency to wax. With the help of th

d mitigating subsurface uncertainties major shortcomings of the ED and their implications for decision-making are highlighted. These includ er flooding a performance review of the Champion water flood reservoirs was carried out using reservoir engineering analytical techniques th the semianalytical method are in excellent agreement with the results of fine-grid compositional simulations. Coarse-grid simulations with

rence fine grid. Once background grid is generated advancing front triangulation and then Delaunay tessellation are invoked to form the fin els and simulate two-phase flow on the constructed grids. Then we compare their obtained global and local results. Fluid cuts at producer is icity is used for computation of pressure and the reference fine grid is used for updating saturation explicitly. The most strong point of the m

ater years there was a need to predict the unified system performance based on surveillance data and to be able to test the possibility of th mbine geostatistical algorithms for history matching with geomechanical elastic simulation models for developing an integrated yet efficient in a single-media model through an iterative process between static and dynamic models to ensure the consistency between the two mode underlying physical recovery mechanisms. We will show that by taking into account the dominant physical recovery mechanism the appar

esign of the next Phase development wells. While the new technologies that are emerging for deepwater primarily encompass the areas of

The result of this study will help operating companies to perform uncertainty analyses on their 1-2 years forecasts based on integrated prod g reservoir characterization. We propose a novel approach to overcome this limitation of the EnKF through a ‘covariance localization’ servoir pressure. The second eigenvalue can be used to estimate the quality of the estimate. Numerical tests of the method show that it est e of the complexity of some reservoir models a systematic approach may be necessary to understand what is going on in the system. Deve of the reservoirs. Data from core well logs seismic and outcrop analogues have been integrated to produce depositional models highlight

the fine model and the post-breakthrough fractional flow also remains higher than in the fine model. However preserving high-flow-rate lay happen as indigenous gas is depleted and an ever increasing reliance is placed on imports from potentially less stable areas of the world.ï ction. The development supports an exponential function of oil-cut vs production time. Using both hypothetic and field examples applicabili erature and pressure. The purpose of this paper is to validate and test the coupled wellbore-reservoir model for challenging and realistic cas t. We focus on the characterisation of multi-phase fluid flow properties in particular the capillary pressure characteristics in both drainage a eys and production data. The boundaries between the reservoir compartments are defined by a combination of faults and stratigraphic hete But for such cases the dispersivity estimated on flow reversal is zero. With local mixing (diffusion or core scale dispersion) the dispersivity v

oir performance from the depletion phase and to aid in the forecasting of oil recovery for the miscible gas injection projects. The reservoir pre f the Qarn Alam project depends on the ability to credibly predict steam requirements and oil production.� Two key oil production mechan tripping effects potentially become more important than the viscosity reduction. We experimentally investigated the physical mechanisms in ject steam into the fracture system in the process known as Thermally Assisted GOGD (TAGOGD). Steam will condense as it contacts coo road range of matrix and fracture properties. It was found that injectivity in the fractured Zechstein carbonate is constrained by the effective recovery factor of each model is computed by using a commercial black oil simulator. A polynomial response surface of recovery factor and on. SAGD targets must be reservoir areas with average thickness above 15 m good vertical communication and no thief zones. Moreover i on of facilities proceeded with all well tubulars and facilities constructed out of carbon steel. Operation of the plant and wells occurs with hig tively standard procedure the fracture modeling part was far from trivial and included simulations using a stand-alone fracture-modeling too t against the substantially higher pressures at seabed this does not apply. The blowout rate is determined by the total system performance 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 er it is hoped that this will spark similar historic learning’s from other Shell individuals and other E&P companies and that these though s advances in openhole-drilling techniques that eliminate hole tortuosity gravel-pack fluids that can reduce rig time and enhance well produ y of H2S requires the application of state-of-the art technology and operating procedures. There is simply no room for mistakes. sulfur mana me of the high lights of the practices include: Opportunity identification and detailed design ��������•��� ime than exotic choices of injection patterns. With such major constraints in mind an optimal design for wells and materials has to take pre est of Port Harcourt Nigeria. The field was discovered in 1961 but started production in 1973. It has a STOIIP of 495 MMSTB and an FGIIP

nabling a first pass identification of bypassed oil opportunities. Well performance data were then used to estimate the likely local fluid conta

rocess from that zone.� Historically for long horizontal wells the effective control of production profile and effective tracking of production

ng-observation well is governed by a dimensionless quantity that depends on the perpendicular distance between the observation well and

he life of the project to observe and optimize the reservoir performance characterize the reservoir response and in the case of waterfloode

ng in sand screens gravel sand perforations and possibly reservoir. The part of the completion that has different impairment from its neighb T surveys in real time through Web-based systems. The importance of meeting all rock and fluid data-acquisition objectives cannot be over reservoir simulation modeling. This paper shows the results of mapped reservoir volume changes from two cyclic steam injection projects u idal effect in a normal reservoir simulator gives us the opportunity to study complex multiphase situations and to evaluate the potential of th Flow Log (WFL) measures the speed of the water flow while 2) the Three-Phase Holdup Log (TPHL) confirms the available multi-phase ho ion producing and monitor intervals of several Mars wells and proven to be vital to the evaluation of waterflood efficiency and the predictio practices to address complex production logging requirements. The example demonstrates the added value of this new tool in terms of bein nd (2) production impairment from scale build-up and the proper adjustment of well skin effects in the model. It also confirmed that the ICP p

ed pumping procedure (coiled tubing and bull-heading) was implemented to best-fit individual well condition. Close cooperation among diffe ing a sand face completion strategy several operators have a number of concerns. This paper examines sand control options (barefoot sta tion of Ca2+ Mg2+ and Fe2+ in the pill solution at 0.1 to 1 molar ratios significantly improves the retention of phosphonate. Alternatively th nt smart-well instrumentation levels on the updating process. We simulated the performance of this production-optimization strategy in a re

ueous- and polymer-based drilling foams. On the basis of the experimental results of foam rheology and a steady-state momentum balance oncentration resulted in low net pressure build up. These challenges were prevailed over by the application of a new fiber technology in wh the fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness.

on a realistic test case. We introduce a strategy to find an optimal production set point for this controller and the benefits of using downhole clusion. Also the blockage was accelerated due to droplets coalescence as a result of high shear rate or surfactant adsorption on the porou ed trajectories for achieving maximum reservoir exposure. The aim is to drain oil from stacked sand bodies that cannot be produced econom

y reduce gas mobility and promote higher liquid recovery at the experimental conditions investigated. Foaming of CO2 builds-up a lower pre primarily generated in the high-permeability layers where it propagates at a much higher speed than in the low permeability layer. The prop e contact with hydrocarbons.1 Foam is also an excellent mobility control agent that has been widely used to improve sweep efficiency in mis ct on production. This requires accurate methods to predict pressure drop in the velocity string as well as tubing-velocity string annulus. Th

ic models. The onset of liquid loading and the dynamic behavior of a flooded well during a restart were predicted. These were then compare ce River perform similar to the Imperial D-36 HWCSS LEP wells from Cold Lake then the expected gross production performance that thes d invasion stress-corrected penetration and crushed zone properties at log resolution.� An inflow profile and IPR curves are then genera bility in the permeability. �Propellant-assisted perforating was considered as it achieves effective stimulation diversion equally across the s was proposed. Another design challenge was that conventional wire-wrapped screens would have insufficent clearance to accommodate ncreased to the extent that the well was deemed unproducible to the facilities.� The failure of the first well caused a re-evaluation of the s rap design selected to improve the pressure rating was substantially heavier than what has been used in traditional sand-control completion o the extent that the well was deemed unproducible to the facilities. A re-evaluation of the sand-exclusion method that included more exte scf/d/well). The selection of contingency sandface completions is also discussed along with mitigation measures in the event of unexpected

ontrol of stimulation and gravel pack fluids is key for the appropriate fluid design and engineering. Failure to optimize fluid loss can lead to p paper describes the application of acid/diversion systems and pumping schedules to improve acid coverage. The selection of in-situ crosslin tent to which these are contained to the target injection layer. Furthermore the paper focuses on the application of this methodology to a wa

d in the Gulf of Mexico (GoM) are better approximated by the deviated well model because they transect all beds within the reservoir to ens

HC saturations and permeability estimates. Fluid saturations based on traditional methods and the MR were evaluated and compared by nular pressure buildup. The data acquired with the test serve to validate these models. The data demonstrate that in general the theoretic ng and improved technical performance together with extensive use of advanced fluid data gathering methodologies. This paper demonstr native an additional way to selectively straddle a section of a reservoir and provide the capability to conduct controlled local production and ensuring optimal well productivity and integrity. Routine well testing is an established procedure. Wells are for the most part manually dive

o of measures to reduce global CO2 emissions while assisting a transition towards a low-carbon energy future. Shell seeks to position itself portfolio of measures to reduce global CO2 emissions while assisting a transition towards a low-carbon energy future. Shell seeks to positio or. Secondary forced-imbibition experiments show that the medium-rank coal becomes CO2-wet as the CO2 pressure increases. High-rank significance of the transition phase depends on the parameters in particular the size of the coal particles between the cleats. Introduction Pa–1 was calculated. The rank dependence of swelling holds true in this set of experiments. Repeat volumetric strain measurement on the ect in terms of porosity and permeability. A unique feature of this work is that real time permeability measurements were done to see the tru

tropy of coal for the injection design and the efficiency of the sequestration in relation to the swelling and shrinkage characteristics of coal; h lls as well as the acquisition of a geophysical baseline and geochemical monitoring in Ketzin located near to Berlin Germany. The target s nalogue of CO2 Enhanced Oil Recovery. These include: establishing initial screening criteria; developing appraisal and piloting techniques; ent assessment of this technology family; risk management to ensure safe and secure geologic storage drawing from understanding and p les a range of production optimization use cases to handle an information hierarchy which includes time series data. This lays a foundation es of interoperable services with a defined future path.� A practical approach to the implementation of an integrated production optimiza

ng data; and downhole fluid analysis can provide fluid property measurements real time during sampling. Integration ensures that the evalu d test facility for well-by-well production testing is available and wells can only be tracked by monitoring changes in commingled production TION UNIVERSE * (PU) which estimates real time well production rates from simple field measurements and provides online reconciliation l Dutch Shell Group (“Shell). Real time signals from individual wells e.g. tubing head pressure are processed by numerical “data dr

overall field decline has been observed.�The key conclusion is that LEAN�practice originally directed towards manufacturing operatio ate. However there has been considerable design work that makes us believe that this technology is also promising. Our experiences with nd injection testing. Our recent examples of closed system tests and wireline formation tests have proven to us that we can get comparable

covered oil a new field was discovered and the discovery well was renamed to Champion West -1. Through various appraisal campaigns

out with a very coarse grouping the resolution is subsequently refined during the optimization. The regularization is adaptive in that the mu n system models that are critical to EP asset management. Evaluation of the business impact of Smart Fields concepts and technologies ha he right decisions to control and optimise the asset behaviour at surface and in the reservoir. The business impact of Smart Fields� was hieve equal drawdown along the well bore leading to a significant increase in reserves by delaying gas breakthrough. In addition some un

���increase of bit on-bottom time ����•���� improved ability to clean the hole resulting in trouble-free trip pment with a combination of down-hole and surface tools and equipment having the same functionality but improved efficiency which enab naged Pressure Drilling technology and what is the relationship with underbalanced drilling? The International Association of Drilling Contra eads to in an immiscible gas drive where the stripping of volatile components is a key recovery mechanism.� HPAI has therefore in som siderations on determining the fracture dimensions and containment. Sensitivity analyses also point to the significance of bounding several s (with range C15 to C28) allowing matching of the IOS to the temperature salinity and crude oil type of reservoirs.� In addition both IO team will condense as long as it contacts cooler matrix rock resulting in a steam front that develops in a stable way through the fracture sy ocess does not require water as a mobility control agent; a significant advantage in water-scarce Australia. It could also replace hydrocarbon for a cluster of sour reservoir fluids (4) Recommendations based on the experimental data and calibrated simulation models. Introduction [1-8]. Due to its unique microstructure foam dramatically reduces gas mobility and considerably improves the vertical and areal reservoir sw eneity Flow-based rock typing to model fluid displacement in detail Application of a commercial optimizer for adjustment of fault transmiss

m3 oil /tonne of steam. The learning from the Pilot has not only helped understand the subsurface uncertainties but also provided significant

ts; (4) Experiments in limestone core plugs demonstrate similar wettability modification if the sulphate ion content in the invading brine is fa to diagnose the source of higher-than-expected gas/oil ratio (GOR) in several GOGD wells. The most important logs in this work were mem main in the perforation tunnel as a rigid seal. This system showed superior shutoff performance in the laboratory compared to normal cemen 0s it was estimated that only 35% success was achieved worldwide in water shutoff remediation. This low success rate is due to poor diagn ottomhole temperature of the well it forms a three-dimensional gel structure. The transition time from slurry to gel is controlled by the cross the fracture system. Previous publications on chemical wettability modification focused on the performance of different chemical wettability cy production and overall recovery. Overall it supports the activity known as strategic or investment planning. Recent studies confirm that in ization opportunities such as gas lift optimization gas transportation and blending are usually non-convex optimization problems. The chall nd challenges and describes issues that are in common between deepwater production and oil and gas developments in Russia.� We al 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 ed out using a gas chromatograph and densities of both phases were measured using a digital densitometer. The experimental results indi available. The first problem from the Handbook of Natural Gas Engineering by Katz et al gave a viscosity of 1.58cp while the new equation

arded as a non-viable alternative. In this paper we are challenging this historical concept. By using carefully designed laboratory experiment ques for the assessment of compositional grading in different settings. We demonstrate that new technologies combined with real-time mon o detect but the high methane content of these fluids makes possible a reliable methane-based OBM-contamination monitoring algorithm. ng information otherwise not available from more traditional bulk elemental analysis methods. We have designed a preliminary analytical pro ompositions. Live oil/water emulsions were prepared in a concentric cylinder shear cell using synthetic formation water under predetermine een made to explain the dynamic behavior of IFT using a four stage mechanistic model involving induction diffusion kinetic barrier and equ

stimulation treatment of several wells using this single-step method and also describes a successful approach to improving the productivity

ther we will discuss the implementation of the models in a comprehensive FPS. We will show how this simulator can be used to optimize p

ented earlier by Suryanarayana et al. (2007). In this paper we apply this approach to two field cases and use the results to quantify the dam between the oil and the water phases Kow; (b) the pKa of the naphthenic acid in water; and (c) the solubility product KCaA2 (or other simil

scaling regime. ESEM/EDX analysis clearly showed that there was no scale formation in the well or near wellbore area enabling continued introduces a large uncertainty in the flow parameters. This uncertainty essentially exceeds differences between predictions of existing appr

ea. This integration makes the fracture models more realistic than purely stochastic fracture models that only honor the statistical field data. e grid was extended over each project area. All available historical production injection pressure and temperature data were used in histor for damage removal in Niger Delta at large. Retarded acids like fluoboric acid were introduced and applied with mixed results. Also high w ty correction (to capture the effect of the temperature profile inside a matrix-block) the coarse-grid dual-permeability simulations accurately s together with a relative-permeability-hysteresis model. A good match of the injection and production volumes and injection wellhead press ally designed centrifuge system is essential for calibration and as well as for quantification of these forces. Numerical studies were perform amenable to future reservoir management activities. Simulations were carried out to predict penetration depths in the formation using newl echanically ground field samples. Treatment with acidic chelant fluids generated high levels of dissolved calcium silicon and aluminum tha echniques provide similar conclusions.� In addition to describing how these field results influence proppant selection in the Pinedale Anti

een the topic of many SPE papers over the past twenty years.�Several have presented data indicating the broadness of the permeabili analysis. However a probabilistic production analysis method simultaneously modeling flowmeter and temperature can take advantage of t ductive interval. One well showed significant depletion in the majority of the sands whereas the other displayed very little depletion. This pr his work is based on a more detailed application of similar concepts employed by Klinkenberg. In fact we can obtain the Klinkenberg result n damage reducing the uncertainty to optimize the reservoir information acquired. The activity was executed in Q3 2007. Inflow testing in a ws continuous subsurface learning during development. Two years ramp up has been planned reaching plateau production of 3bcm/a (290 astic variations as well i.e. between 10 bar and 1000 bar. A significant portion of the Rotliegend reservoirs are characterised as tight gas de

roject management responsibilities managing subsurface uncertainties more effectively and enabling work to be done more collaboratively

m subsurface issues. Requests to investigate the surface network got initial pushback as the flowline was pigged before hook-up. The popu l platform development in the Gulf of Mexico demonstrates the method. Introduction Standard Design Process Leads to Losses. As observ s on the right reservoir scenarios and most relevant sources of risk such as reservoir continuity or channel sand/shale geometries all drive he transition-zone definition and the current limitations in modeling transition zones. We describe the methodology recently developed bas different. Real-time application of the FCA can optimize capture of downhole-fluid samples and generation of a continuous downhole-fluid lo ntially increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer.

This paper will present the key CSEM experiences in DW Borneo to date highlighting on the pros and cons of a still promising and evolving mple dynamic models in conjunction with effective properties principally geologically based pseudo-relative permeabilities significantly acc ed at three depths in shale thus yielding two minimum horizontal stress magnitudes. The borehole sonic data were suitable for the inversion

ence of natural fractures. The simulation results are distilled into a field implementation methodology for determining the extent of natural fra scale) and 5- to 10-ft-radius well tests (field-scale). Zhang et al. (2005) studied a 10 in. diameter by 14 in. high sample (bench-scale). Vertica a reservoir sandstones outcrop sandstones outcrop carbonates and carbonates from Middle East oil and gas fields. The permeabilities of s implications for reservoir characterization are discussed. RIPI de-noises the data and scales the problem such that the trends in data are and simulation and in combination with fracture corridor clustering density and transmissivity data from borehole image logs and pressure t d a Bayesian inference has to be used to find the conditional probability through an intermediate indicator. For example the probability of ha measurements DFA and geochemistry for a reservoir-continuity assessment in a diverse range of geological settings including a wide rang on migration and entrapment reservoir connectivity and fluid contact levels. This in turn enables better well placement and more effective of a given well; only after the well has reached final depth and LWD and e-logs have been obtained can one begin to speculate on such ma ability restoration and a combination of steady-state and centrifuge experiments. When the experimental data became available they were bution of the crude oil and the wetting state of the rock at any given overall saturation. The method requires an NMR measurement on a sam

-late 2007 principally to test the deeper and highly overpressured distal topset play in Bubut and also to re-assess the hydrocarbon presen o map the presence of coal versus water and gas sands. Now success through the development phase requires the application of the follo udies (Steiner 2005) estimate a global (recoverable) resource of some 500 B boe (= 3000 tcf) as per bar chart figure 3 below of gas that i

uncertainties. A range of alternate development strategies has been considered. Experimental design was used to obtain oil recovery corre as modified reservoir volumes in certain areas revised fault transmissibilities and improved relative permeability characteristics. Integration mentation of surveillance and reservoir management activities in the field. In the reservoir surveillance section an overview of the field surve

Bonga is a ‘brownfield’ that is not immune to normal well and asset integrity issues and declines in well injectivity and productivity. Ab

n a range of realistic dynamic reservoir models and how the remaining uncertainty was dealt with during the selection of the optimum furthe

n this paper are expected to also apply to (part of) EOR operations (e.g. polymer flooding). 1. Introduction Water injection will generally res ssed in a phased manner. First the smallest possible element of symmetry simulation model and the most efficient discrete fracture realizat D seismic swath study gave information on the 2006 Gas Water Contact. Good quality 3D seismic attribute data enabled identification of ka roduction so that gas production is optimized while minimizing sand production. Production performance is enhanced using the latest perfo ed the results of the RO procedure to two alternative approaches: a nominal-optimization (NO) and a reactive-control approach. In the reacti OIIP base. A large integrated team of PE staff have spent 3 years to address and progress the major fields therein to FDP. The Cluster cons 8 and to date various drilling campaigns have been carried out to optimize development of the field. So far 14 wells have been drilled in the ory. • Water injection philosophy. • Design considerations for fractured water injection including: o Pressure requirement to design for vity considering all the parameters. Various waterflooding plans were designed on the basis of areal & vertical sweep efficiencies and reser gion demand supply and recoverable gas resources of the various countries are pooled. Transportation of gas by pipelines or LNG tankers is currently in full swing both offshore and onshore. Offshore activities include drilling wells and constructing offshore platforms and pipeline om the limitations associated with commercially available coreflood services. A coreflood rig was designed and built featuring an accurate native sources for energy. There are no alternatives to fresh water Can Produced Water from Oil & Gas activities become an alternative? Av recovery.� The impact of process instabilities on overall well or facility performance are often not recognized; a single trip may wipe out m ered by the wells of this platform became evident through current temperature anomalies and salinity contrast between the formation water

s and scavenging facilities topside. The facilities were designed to handle a maximum level of 50-ppm(v) H2S. As detailed design progress e positive experience with the injection of nitrate in other seawater floods throughout the industry nitrate was selected as the mitigation met W). To investigate this more closely the SMC was modified by including a dedicated Low Pressure (LP) Corrosion Sidestream Monitoring (C associated with well acidizing on sulphur corrosion in surface and subsurface operations CORROSION MANAGEMENT IN SOUR ENVIRO H2S released are hazard for safety. Starting December 2005 production chemistry and reservoir study have initiated an integrated H2S Mon ta derived from laboratory experiments. The focus of this paper will be to consider the impact of the mutual solvent on well clean up time an adients approximate the sensitivities of a suitable objective function with respect to well locations. These sensitivities guide the iterative sea ng the last five years. The appraisal challenges the emerging study results and reservoir pressure and production performance have requi ernal studies (Steiner 2005) estimate a global (recoverable) resource of some 500 B boe (= 3000 tcf) as per bar chart figure 3 below of ga me-lapse seismic. Draugen acquired seismic of excellent quality in 1998 2001 and 2004. The data has been a key enabler to understand th ing.� Surveillance logs were acquired in these wells to obtain key inputs for production optimisation identifying bypassed oil and evaluati ailable gas reservoirs by delivering a cost effective technology solution.� Especially for reservoirs with water drive as the dominant drive

was achieved for some five years (1994-1997) declining to the current net oil production of 20 kbopd. Despite the structural complications t onal well control options based on the well’s pressure or total rate we have also implemented smart well control options which allow the a mature oil field located 135km offshore Sabah Malaysia. The oil initially in place (STOIIP) is estimated at 630 MMstb of which 83% is loc reservoir image is greatly improved and there is improved confidence in the seismic signal that allows it to be used for the definition of rock it was necessary to characterize the noise in observed seismic impedance change data to prevent overmatching of the data. All the proced n NPV) on the basis of which improving well locations can be determined. The main advantage over previous approaches such as finite-dif rock and fluid properties of the ARM.� The initial history matching attempt did not yield a good match.� The model was unable to mat SEIKF the members of the model ensemble are selected in the main orthogonal directions of a functional space described by an approxim ustness and efficiency on a real field case. A history matching study is carried out for a complex deepwater turbidite reservoir involving multi practical applications and this means the study indicates only a small gel strength should be sufficient to prevent convection. The gel stren oupled simulator to incorporate noncontained fractures. The new simulator called FRAC-IT handles fracture-length and -height growth by e duced fracture dimensions can be very sensitive to typical reservoir engineering parameters such as fluid mobility mobility ratio 3D saturat a e.g. coning and production dynamics e.g. shut-in. The results of dynamic well simulations dynamic reservoir simulations and coupled w tendency to wax. With the help of the simulation environment it was possible to understand the production instabilities observed in this wel

making are highlighted. These include inconsistency and non-uniqueness of proxy models violation of basic theoretical physics non-preser r engineering analytical techniques to generate reservoir fractional flow. The field’s performance to fractional flow was matched using a lations. Coarse-grid simulations with gridblock sizes on the order of 200 ft coupled with the semianalytical method in gridblocks with wells

ssellation are invoked to form the final (coarse) gridblocks. This algorithm is quite flexible allowing choice of the gridding indicator and thus cal results. Fluid cuts at producer is employed as global performance indicator and saturation distribution error as local indicator. We show citly. The most strong point of the method is that dual mesh method has been incorporated onto non-uniform grid structure. This combinatio

to be able to test the possibility of the connectivity of the multiple reservoirs and reservoir segments. In addition to the surveillance product eveloping an integrated yet efficient fracture modeling tool. This paper presents an integrated approach to history matching of naturally frac e consistency between the two models. Different sets of relative permeability curves (for matrix and fracture systems) were generated to pro ical recovery mechanism the apparent discrepancies in the shape factor values reported in the literature can be overcome. We derive a ge

er primarily encompass the areas of drilling and completions and subsea systems technologies addressing subsurface uncertainties are al

s forecasts based on integrated production system models with the right level of simplification. The forecast and the uncertainties can then ugh a ‘covariance localization’ method that utilizes sensitivities that quantify the influence of model parameters on the observed data tests of the method show that it estimates average reservoir pressure accurately even when the reservoir is heterogeneous or when partia what is going on in the system. Developing these interpretation skills require hands-on assignment of reservoir simulation problems and coa oduce depositional models highlighting uncertainties in reservoir architecture as they would impact potential waterflood recovery. Two broad

owever preserving high-flow-rate layers in a nonuniform scaled-up model was key to matching the front-tracking behavior of the fine model. tially less stable areas of the world.� Consideration is given to the drivers that apply to the identification of any gas storage project and in hetic and field examples applicability and performance of the derived model are demonstrated and compared with six of the popular water odel for challenging and realistic cases. The thermal wellbore model is first validated through comparison to field data for three-phase flow i re characteristics in both drainage and imbibition and their assignments in reservoir simulation models. We show that for modelling initial sa nation of faults and stratigraphic heterogeneities. Although clear in places some compartment boundaries can only be defined from non-geo e scale dispersion) the dispersivity value on flow reversal is non-zero and also much larger than typical core values. Layering in permeability

s injection projects. The reservoir pressure in one of the reservoirs producing in the depletion phase has declined faster than expected and .� Two key oil production mechanisms are heat transport through the fractures and into the matrix and subsequent gas cap generation d stigated the physical mechanisms involved. We present the results of a laboratory study in which reservoir core with light crude oil at reserv eam will condense as it contacts cooler matrix rock resulting in a steam front that develops in a stable way through the fractures. Conductiv bonate is constrained by the effective permeability of the fracture system and is relatively insensitive to matrix permeability and fracture spa ponse surface of recovery factor and modeling parameters is generated as a proxy of flow responses. A Monte Carlo Simulation Bayes Met tion and no thief zones. Moreover if the geological conditions are known the SAGD process has to be operated properly as lack of operati of the plant and wells occurs with high regard to the risks of sour high pressure service and with no integrity or corrosion has been observe a stand-alone fracture-modeling tool and a more sophisticated coupled dynamic fracture propagation – reservoir simulator both being ined by the total system performance from inflow at sand face to outflow at seabed. To validate the blowout rate calculations under these con have a common vision of what a truly Smart Field will look like and this contributes to the difficulty of assigning a value to “Smartness.ï¿ P companies and that these thoughts and lessons be used to “grow towards a more comprehensive view. Winston Churchill said “S uce rig time and enhance well productivity and improvements in downhole tools that have or potentially will reduce risk while reducing com ly no room for mistakes. sulfur management is also an issue that requires new approaches as planned developments will double globally tra ½ï¿½ï¿½ï¿½ï¿½ï¿½â€¢ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ Detailed well-by-well review for first round candidate selection. ����� wells and materials has to take precedence. Accepting this as a given additional more common challenges would then follow. The waterf TOIIP of 495 MMSTB and an FGIIP of 1.3 TCF. Total Oil production to date is 254MMstb representing 45% of the STOIIP; and there has be

o estimate the likely local fluid contacts in the area or sand layers of the completions. The inferred fluid contacts defining the identified bypa

e and effective tracking of production from individual zones have been problematic.� Poor tracking of production will adversely impact ov

e between the observation well and the hydraulic fracture divided by the square root of time. Using this dependence a novel method is deve

nse and in the case of waterflooded reservoirs monitor the performance of the waterflood. Multi-rate multi-zone production logging and pre

s different impairment from its neighbors will carry tube waves with modified signatures (velocity attenuation) and also would produce a refle cquisition objectives cannot be overstated given the high cost of offshore operations and the implications of obtaining false or misleading in two cyclic steam injection projects using tiltmeter-based surface deformation measurements. Introduction In the past fifty years oil compan s and to evaluate the potential of the tidal response as a reservoir-surveillance method. The case studies presented here focus on the poss onfirms the available multi-phase holdups. When water velocity and water holdup are measured and when changes in phase behaviour due aterflood efficiency and the prediction of the waterflood front. A monitoring logging program has been conducted in the Mars area since 199 alue of this new tool in terms of being able to obtain a comprehensive flow diagnosis in an environment where a conventional production log odel. It also confirmed that the ICP performance observed in laboratory could be used as a good proxy for ICP in field. Introduction The Gr

tion. Close cooperation among different parties (Well services Subsurface technology teams Operation services and Service providers e es sand control options (barefoot standalone pre-drilled liner / screens or slotted liners gravel pack and expandables) for the Niger-Delta a tion of phosphonate. Alternatively these metal ions can be dissolved from the formation while an acidic inhibitor pill is in contact with the for oduction-optimization strategy in a reservoir simulator. Some numerical aspects of the algorithm and problems encountered during impleme

d a steady-state momentum balance equation a foam-flow hydraulics model was developed to predict pressure profile ECD foam velocity ation of a new fiber technology in which fiber is used (1) to transport higher sand concentration to the fracture and (2) to control the sand flo s of excessive filter cake thickness. Experimental data demonstrate that flow along the fracture would encounter lower yield stress when the

r and the benefits of using downhole ICVs in comparison to the wellhead choke are investigated. Simulation experiments show that a PID c r surfactant adsorption on the porous medium. Furthermore emulsion droplet size distribution emulsion viscosity and oil droplets-to-water i es that cannot be produced economically via separate dedicated wells. These wells have long reservoir sections of up to 3 km with undulat

oaming of CO2 builds-up a lower pressure drop over the core at both low and high pressures than N2. Both gases require a certain penetra the low permeability layer. The propagation of foam in the low permeability layer requires that the pressure gradient is higher than the capil d to improve sweep efficiency in miscible gas steam and surfactant-based EOR.2 An advantage of foam is that it can avoid the dispersion o as tubing-velocity string annulus. The available methods to predict pressure drop in annuli for gas-liquid flow are modifications of methods t

predicted. These were then compared to actual production data. The influence of the reservoir parameters and of the tube inclination were o ss production performance that these wells will have under LEP conditions will be around 16 m3/day per perforation.� These results are i ofile and IPR curves are then generated.� The analysis can be repeated for multiple guns to compare relative performance; for example mulation diversion equally across the entire perforated interval.� Modelling work indicated that fracture lengths of five feet or more would p ufficent clearance to accommodate intelligent-well completions. A feasibility study recommended a combination of expandable sand screen t well caused a re-evaluation of the sand exclusion method employed which included more extensive core analysis and the completion type n traditional sand-control completions. Initial burst tests with available 316L material averaged 4 600 psi. Two sets of additional burst tests w sion method that included more extensive core analysis and the types of wells that would be suitable for development of the H1/H2 reservoi measures in the event of unexpected sand production. The impact of the sand quantification on surface facilities design is discussed based

e to optimize fluid loss can lead to premature screen-outs or inefficient fluid displacement. This may ultimately jeopardize overall well object age. The selection of in-situ crosslinked and particulate diverters through laboratory testing is described as well as the implementation of a plication of this methodology to a waterflood offshore Sakhalin in the Russian far East. The methodology is based on an exact solution to t

t all beds within the reservoir to ensure complete drainage of the reservoir. Since shales dividing the reservoir into multiple vertical compart

R were evaluated and compared by core data enhancing the understanding of the measurement and the reservoir. For post-processing the nstrate that in general the theoretical models overpredicted pressure buildup in the annulus. This overprediction was more pronounced at h ethodologies. This paper demonstrates how the above was addressed for the Onyx SW and how the results compared with the set goals. duct controlled local production and interference as well as to enable the capture of reservoir fluids. Formation permeability anisotropy skin are for the most part manually diverted to a gravity separator or multi-phase meter and oil water and gas phases are measured discreetly

y future. Shell seeks to position itself as part of the solution to the climate change issue. The United Nations Intergovernmental Panel on Cl energy future. Shell seeks to position itself as part of the solution to the climate change issue. The United Nations Intergovernmental Pane CO2 pressure increases. High-rank coal is CO2-wet during primary imbibition. The imbibition behavior is in agreement with contact-angle m es between the cleats. Introduction Stress induced diffusion plays an important part in many engineering applications such as polymer sc olumetric strain measurement on the same Warndt Luisenthal coal core shows higher volumetric strain values for all pressure steps. A volu asurements were done to see the true effect of differential strain from CH4 saturated coal core flooding experiments. Introduction Coal mat

d shrinkage characteristics of coal; how does the mobile and the immobile water in the coal affect the exchange process. These questions ear to Berlin Germany. The target saline aquifer is the Triassic Stuttgart Formation situated at about 630–710 m (2070–2330 ft) that is g appraisal and piloting techniques; building appropriate reservoir models; designing fit-for-purpose injection wells; assessing containment r e drawing from understanding and past experiences; public perception policy and regulatory frameworks that pose opportunities and barrie e series data. This lays a foundation for adaptive optimization involving interaction between applications and data stores from multiple vendo of an integrated production optimization “analytic environment will then be described illustrated by a richly detailed and broad-based rea

ng. Integration ensures that the evaluation objectives are addressed using the most optimal technologies and workflows maximises the valu g changes in commingled production flows. For the optimization functionality the FieldWare PU data driven well models allow the prediction nts and provides online reconciliation against bulk measurements and export meters.�The novel aspect of the technique is that it uses dy processed by numerical “data driven models to estimate three phase flow from individual wells. Total production from the facility is recon

cted towards manufacturing operations is a highly effective way to overcome performance issues in existing assets and can be replicated g so promising. Our experiences with OVT over the past few years suggest that the wireline formation tester solution is the best answer in a l n to us that we can get comparable data quality to a conventional DST. Injection testing aimed at determining drainage volume is still relat

hrough various appraisal campaigns the complexity of the field became evident (very erratic charge in stacked (some 100) reservoirs in 10

ularization is adaptive in that the multi-scale parameterization is chosen based on the gradients of the objective function. Results for the nu Fields concepts and technologies has demonstrated value in several areas: 8% Ultimate recovery increase (5% gas and 10% oil); 10% In ness impact of Smart Fields� was evaluated in Shell based on implementations to date and on industry estimates. The benefits will vary breakthrough. In addition some unexpected benefits materialized from the use of smart completions: In one case the smart completion en

he hole resulting in trouble-free trips ����•���� trouble free casing runs ����• ����the dee but improved efficiency which enable a reduced footprint. It illustrates how the functionality of the 4-phase separator can be replaced by co ational Association of Drilling Contractors (IADC) defines Managed Pressure Drilling as “an adaptive drilling process used to precisely co nism.� HPAI has therefore in some instances been modeled as an isothermal flue gas drive employing an Equation of State (EOS) meth he significance of bounding several key parameters for fracture prediction. These include sand-shale stress contrast fluid quality and TSS c reservoirs.� In addition both IO carbon chain (degree of branching) and the degree of sulfonation influence the surfactant properties of a stable way through the fracture system. Heating of the matrix will result in oil expansion reduction of viscosity gas drive and stripping effe ia. It could also replace hydrocarbon (HC) miscible floods freeing cleaner HC gases for energy use. Ideally the process is suited to deep h ted simulation models. Introduction A recently discovered cluster of reservoirs in the South of Oman consists of 8 different fields containing es the vertical and areal reservoir sweep efficiency [1-4]. The ability to reduce fluid mobility forms the basis of profile correction used to imp zer for adjustment of fault transmissibility to assist and accelerate the process of history match Inclusion of gas miscible modeling with a si

ainties but also provided significant insight into the engineering design and operational issues which are being managed right upfront during

on content in the invading brine is far in excess of the calcium ion content. Based on these results the following conclusions were drawn: (1 mportant logs in this work were memory-production-logging-tool (MPLT) surveys used to identify the sources of gas production and formation boratory compared to normal cement squeeze techniques. Selective perforation of the hydrocarbon zones will re-establish the oil productio ow success rate is due to poor diagnosis wrong selection of water shutoff solutions and how complicated the well completion is with respec urry to gel is controlled by the crosslinker concentration of the OCP system and is not altered by the addition of the particles wellbore fluids ance of different chemical wettability modifiers for a chosen rock/oil/brine system. In some cases they demonstrated an almost full oil recov nning. Recent studies confirm that integrated network analysis helps to bring production closer to the technical potential of the wellhead pla vex optimization problems. The challenge in most production optimization opportunities is not dealing with non-linearity but as noted by Rock developments in Russia.� We also demonstrate the applicability of lessons learnt from the deepwater to Russian oil and gas field produ 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 meter. The experimental results indicated that the gas-oil interfacial tensions measured at various gas-oil ratios at reservoir temperature alt ty of 1.58cp while the new equation gave 1.157cp. The second problem from Ikoku’s book (Natural Gas Production Engineering) gave

ully designed laboratory experiments; we have studied the H2S scavenging effects of different metals. The tests were conducted for differe ologies combined with real-time monitoring and control and a more integrated evaluation approach produce a more robust interpretation of 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 designed a preliminary analytical protocol with this objective in mind. It involves the sample preparation (e.g. sulfur selective chromatograph ormation water under predetermined pressure temperature and shear conditions. The stability of live emulsions was investigated using a on diffusion kinetic barrier and equilibrium stages. The significant difference observed between the advancing contact angles of live oil (55

proach to improving the productivity of high water cut wells with severe fines-damaged gravel packs by this system. Unique experiences ac

simulator can be used to optimize placement and diversion. Validation of the models will be presented based on the analysis of two case hi

d use the results to quantify the damage and its impact on production. The two field cases are discussed in detail. Both relative permeability ubility product KCaA2 (or other similar solubility parameter) of the naphthenate deposit. In the simpler pH change experiments we only req

r wellbore area enabling continued production and avoiding shutting in these wells. Single ion analysis is often not accurate enough to dem between predictions of existing approaches. For this reason it is sufficiently to analyze flows within the framework of the simplest theory. Su

only honor the statistical field data. Interdisciplinary collaboration during data acquisition and all stages of the modeling assured that only t emperature data were used in history matching. Steam-induced reservoir dilation explicit fracturing and relative permeability hysteresis wer plied with mixed results. Also high water cut stimulation was limited to only 30% water cut while wells with higher water cut could not benefit -permeability simulations accurately reproduce the fine-grid single-porosity simulations and analytical results. Introduction With fine-grid si olumes and injection wellhead pressures for the early cycles was achieved using a single well model. Simulation of the later cycles requires es. Numerical studies were performed using a calibrated EOS description based on the fluid samples taken at a selected point of each res n depths in the formation using newly developed in-house software and the results were compared with those from an industry-recognised p d calcium silicon and aluminum that remained in solution over time. For comparison conventional mineral acid treatment of the field samp oppant selection in the Pinedale Anticline this paper will describe many aspects of field trial planning as well as the proper handling of data

ng the broadness of the permeability distribution which may be encountered when developing these reservoirs.[1 2 3]�The broadness o emperature can take advantage of the high contrast between the heat capacity of gas and water and therefore provide good estimates of th splayed very little depletion. This pressure data together with open-hole and production log data core data and geologic models was used e can obtain the Klinkenberg result as an approximate form of our result. Our theoretical "micro-flow" result is given as a rational polynomia cuted in Q3 2007. Inflow testing in a known 'non damaged state' while drilling exploration and appraisal wells in desert areas remote from h g plateau production of 3bcm/a (290mmscf/d) in 2008 to help fulfill strongly increasing gas demand from Beijing1. Development drilling com rs are characterised as tight gas defined in this paper as having an average in-situ air permeability of less than 1 mD. Up to the 90’s th

work to be done more collaboratively. Using a tool that was co-developed with Schlumberger we have been able to make visible to the key s

as pigged before hook-up. The popular steer was to acidize the near wellbore region for skin damage removal. Production gain predicted by Process Leads to Losses. As observed in practice the standard approach to the design of major development projects is a deeply technica nnel sand/shale geometries all driven by group consensus.�The collaborative environment improves execution of the HD and IRM proc ethodology recently developed based on extensive experimental measurements and numerical simulation for modeling both static and dyn on of a continuous downhole-fluid log representing the fluid complexity in the reservoir. In addition by identifying abrupt changes in fluid pro tion with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: C1 ethane (C2) p

ons of a still promising and evolving technology in what is still a challenging area. ative permeabilities significantly accelerates the simulation workflow. We show that a statistical distribution of the recovery factor can be pro 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

determining the extent of natural fracturing and the formation reservoir quality. This methodology is also applied to a field case study to ver n. high sample (bench-scale). Vertical permeability in the bench-scale varied from 100 darcies to 10 md and in the core-scale averaged 2.5 d and gas fields. The permeabilities of this entire data set range from 0.5-1377 mD which covers a significant portion of the range of permeab lem such that the trends in data are more obvious enabling robust interpretation of UBD data and increasing the confidence in calls made borehole image logs and pressure transient analysis. Seismic maps from the other field could detect only half of the fracture fairways and in or. For example the probability of having a fracture corridor given step flow profile is calculated from the conditional probability of having mu ogical settings including a wide range of field sizes structural environments reservoir lithologies and oil types. Particular emphasis is place r well placement and more effective development planning. We highlight three case studies in which we have successfully combined variou n one begin to speculate on such matters as reservoir continuity. Until recently standard mud gas logging technologies did not offer the reso l data became available they were reviewed and numerically interpreted using the state-of-the art simulation techniques. This has led to se ires an NMR measurement on a sample containing two reservoir fluids (i.e. brine and crude oil). Multiacquisition schemes including diffusio

o re-assess the hydrocarbon presence and reservoir quality of the sequence already penetrated by BU-1. The Bubut prospect is a simple 3 e requires the application of the following technologies: Neural-net based seismic facies aimed at resolving lateral heterogeneity at field sc bar chart figure 3 below of gas that is ‘contaminated’ by the previously defined levels H2S and/or CO2. These resources will require

was used to obtain oil recovery correlations for each development strategy which has proven to be a useful first pass screening tool to make meability characteristics. Integration of the 4D-interpretation results has greatly improved the various Draugen reservoir-simulation models section an overview of the field surveillance program is provided and experience of using surveillance technologies in West Siberia such as

in well injectivity and productivity. Ability to respond swiftly to these issues is part of the Bonga WRM Plan. This paper presents key elemen

g the selection of the optimum further field development plan. The key to success in this study has been the seamless cross discipline integ

ion Water injection will generally result in rapid injectivity decline unless it takes place under induced fracturing conditions. This is illustrated ost efficient discrete fracture realization were determined. The next phase involved optimization of the well configuration and steaming strate ute data enabled identification of karst features that were incorporated in reservoir modelling. This together with the good reservoir surveilla ce is enhanced using the latest perforating optimization software. In the Piltun-Astokh field Smart Water Injectors are used to allocate wate active-control approach. In the reactive approach each production well is shut in when production is no longer profitable. The NO procedure ds therein to FDP. The Cluster consists of green and brown fields characterised by high gross liquid production rapid watercut developmen far 14 wells have been drilled in the field while infill drilling is expected to commence in 2010. This paper will present how phased develop Pressure requirement to design for fractured water injection. o Simulation of fracture growth and containment and resulting conclusions. †vertical sweep efficiencies and reservoir voidage compensation using material balance. The fractional flow saturation profiles mobility ratio n of gas by pipelines or LNG tankers is driven by the transport cost of gas between the regions and mainly depends on distance and topogra cting offshore platforms and pipelines. Onshore the detailed design is nearing completion whilst procurement activities are in full swing. On ed and built featuring an accurate automated high injection pressure capability and a much extended test duration. This test rig has since activities become an alternative? Availability of and access to fresh water is one of the world's most pressing challenges that made many b ognized; a single trip may wipe out months of optimization benefits. To achieve the full potential of process control in Oil and Gas Productio ntrast between the formation water and the accumulated injection water (the relevant calculation is explained later in the paper) in the vicini

) H2S. As detailed design progressed and more field data became available doubts were raised on the suitability of this approach. The str e was selected as the mitigation method and injection started directly at the beginning of the waterflood at the end of 2005.� As such Bon Corrosion Sidestream Monitoring (CSM) system. The results obtained in the CSM system verified the results obtained in the HP corrosion m N MANAGEMENT IN SOUR ENVIRONMENT In sour environment in the absence of elemental sulphur corrosion mitigation for carbon and have initiated an integrated H2S Monitoring and implemented a Mitigation Program by improving H2S onsite measurement and method revis tual solvent on well clean up time and the model is used to demonstrate the effect of a mutual solvent in quickly bringing wells back to full o e sensitivities guide the iterative search with improving directions that progressively maximize the ultimate recovery. The main advantage of production performance have required only minor adjustment to the original development concept. Introduction to the Asset The Harweel as per bar chart figure 3 below of gas that is ‘contaminated’ by the previously defined levels H2S and/or CO2. These resources will r been a key enabler to understand the water flood and to manage the reservoir. This paper shows how visualisation methods and discipline i dentifying bypassed oil and evaluating potential for additional perforations. Where necessary production logs were integrated with pulsed n h water drive as the dominant drive mechanism (i.e. reservoirs with a strong aquifer) a concurrent oil and gas development is attractive. Th

espite the structural complications the injector-producer connectivity in the laterally extensive RUL sands could be established rather confid t well control options which allow the separate control of individual inflow intervals. Special adaptations of the optimization algorithm were re d at 630 MMstb of which 83% is located in the main reservoir package in the Northwest Flank. These reservoir units dip at an angle of appr t to be used for the definition of rock property distribution. In parallel to the seismic interpretation a detailed evaluation of velocities core a matching of the data. All the procedures are illustrated with an application to a reservoir in the Gulf of Mexico. Introduction The objective o evious approaches such as finite-difference or stochastic-perturbation methods is that the method computes improving directions for all wel h.� The model was unable to match the preferential flow of water along the lower channel. It was discovered later that the lower channel onal space described by an approximation to the error-covariance matrix. This enhanced sampling strategy embedded into the resampling s ater turbidite reservoir involving multiple geologic realizations. Within the context of the study the stochastic framework delivered (a) a comp to prevent convection. The gel strength does not need to be so large as to interfere with pumping. Another conclusion is a formulation for th cture-length and -height growth by evaluating a fracture-propagation criterion on the basis of a Barenblatt (1962) condition. The solution of id mobility mobility ratio 3D saturation distribution (in particular shockfront position) positions of wells (producers injectors) and geologic reservoir simulations and coupled well-reservoir simulations are presented and an overview is given of the cases where the results of the c ion instabilities observed in this well and to determine a control strategy to stabilize and optimize its production. The results of the coupled w

asic theoretical physics non-preservation of the correlation between variables that are known to be inherently related non-controllability of fractional flow was matched using a set of Water-Oil relative permeability curves generated by Corey exponents and Buckley-Leverett / We cal method in gridblocks with wells yielded production rates as accurate as fine-grid simulations with gridblock sizes on the order of 2 ft. Th

ce of the gridding indicator and thus providing the possibility of comparing the grids generated with different indicators and selecting the bes n error as local indicator. We show that FB and VB gridding which are dynamic methods are superior to PB gridding which is a static meth niform grid structure. This combination removes the need to solve the full fine grid for two-phase flow modeling resulting in a less computati

addition to the surveillance production data we have also gathered data based on basinwide analysis and geochemisty that focused on re h to history matching of naturally fractured reservoirs which includes (1) fracture trend prediction through elastic stress simulation; (2) geosta ure systems) were generated to properly simulate the fluid movement in the reservoir. The results indicate an excellent history match that i e can be overcome. We derive a general expression for the shape factor that not only captures existing shape factor expressions but also

sing subsurface uncertainties are also rapidly surfacing. The understanding of some of the major subsurface challenges such as compacti

ecast and the uncertainties can then be used to assist in investment decisions and stakeholder management. Making the wrong forecast ma el parameters on the observed data. These sensitivities are used in the EnKF to modify the cross-covariance matrix in order to reduce unw voir is heterogeneous or when partial-flow barriers are present. Examples with real data show that the behavior predicted by the theory is ac servoir simulation problems and coaching by more experienced reservoir engineers. Some cases that give insight to strategies in understan ential waterflood recovery. Two broad types of reservoir interval have been recognised: stacked shoreface parasequences which form the

-tracking behavior of the fine model. The scaled-up model was coarsened in areas of low average layer flow because less refinement is nee on of any gas storage project and in particular the conversion of a depleted natural gas field. Consistent and systematic screening criteria a mpared with six of the popular water cut models including those of Ershagi and Omoregie Liu Warren and Purvis. Besides its simplicity th n to field data for three-phase flow in a long well with both vertical and inclined sections. Close agreement between the model and field data We show that for modelling initial saturation distribution in the reservoir assigning saturation functions based on permeability or porosity cla es can only be defined from non-geological data sources. Understanding these heterogeneities and compartment boundaries is essential fo core values. Layering in permeability while increasing the convective contribution to transport also enhances mixing by providing larger are

s declined faster than expected and can be attributable to either lower than expected oil in place volume or a lower the expected PVC. Obvio nd subsequent gas cap generation due to thermal volatilization of the oil. The process mechanisms involved in TAGOGD were validated thr voir core with light crude oil at reservoir conditions is heated to steam temperature. From these experiments and separate PVT measuremen way through the fractures. Conductive heating of the matrix will result in oil expansion viscosity reduction solution gas drive and stripping ef matrix permeability and fracture spacing. This behavior was verified by calculation of a dual-porosity pseudo skin factor.�Partially fractu Monte Carlo Simulation Bayes Method (MCSBM) estimates the uncertainty of recovery factors and derives the posterior probabilities for m operated properly as lack of operational excellence can be detrimental to the performance of any SAGD project. SAGD operations are bad egrity or corrosion has been observed to-date. The field produced under depletion starting in 1982 through oil and gas cap expansion mech €“ reservoir simulator both being in-house software tools. The combined analysis was used to develop a better understanding of the water out rate calculations under these conditions data were collected on high rate well flow through an annulus against elevated surface pressur ssigning a value to “Smartness.�There is a tendency to assign value to discrete technologies as opposed to the holistic full project va e view. Winston Churchill said “Study history study history. In history lies all the secrets. Looking at DOF through the lens of one person y will reduce risk while reducing completion cycle time. This review also will briefly examine a possible replacement technology. Introductio developments will double globally traded volumes over the next ten year. The paper will outline the advantages and disadvantages of dispo idate selection. ��������•�������� Fundamental data collection is vital. A data managemen nges would then follow. The waterflood-study team for the deepwater Ursa/Princess field in the GOM has spent appreciable time and effor 45% of the STOIIP; and there has been no gas production. This field is also experiencing declining production and high water cut. It is also c

contacts defining the identified bypassed oil were further calibrated with fluid contacts seen in recent wells and crosschecked with 3D seism production will adversely impact overall management and ultimate recovery from a reservoir.� One solution is to fully utilize surface and

dependence a novel method is developed for imaging hydraulic-fracture geometry and relative heat injectivity from the temperature history

ulti-zone production logging and pressure transient testing are two excellent methods to achieve these goals. Introduction Production in Ma

ation) and also would produce a reflection from the boundary where impairment changes. The method relies on permanent acoustic sensors ns of obtaining false or misleading information. The main objective of real-time monitoring remains to assure that the planned data are acqu on In the past fifty years oil companies and individual researchers have studied surface deformation caused by the fluid injection into or wi es presented here focus on the possibility of observing water in the near-well region of a gas well. Introduction The main objective of this w en changes in phase behaviour due to variations in wellbore deviation are factored water inflow quantification is attainable. The conclusion onducted in the Mars area since 1996 with initial baseline surveys to the present day monitoring surveillance program. The logging program where a conventional production logging toolstring would not have provided the data to meet this objective. The particular logging tool descr for ICP in field. Introduction The Green River formation in Colorado Utah and Wyoming USA is the largest oil shale basin in the world. It h

on services and Service providers etc.) 6000 bpdoe of initial gain was achieved by this campaign in Brunei with high success rate (no failu expandables) for the Niger-Delta a high activity region in openhole applications. Typical key learning is presented. The openhole completio inhibitor pill is in contact with the formation minerals. Both BHPMP and DTPMP returns were significantly extended by the addition of metal blems encountered during implementation are discussed. The performance of the algorithm was tested in two reservoir settings. In both ca

pressure profile ECD foam velocity and foam quality along a vertical/inclined/horizontal wellbore. For practical applications a simulator ha acture and (2) to control the sand flow back during production as well. Since this technology is physical rather than chemical the proppant f ncounter lower yield stress when the breaker is delivered directly to the filter cake as opposed to randomly distributed. The data also indicat

ation experiments show that a PID controller is an effective means to prevent a full gas breakthrough and moreover can be used to increa n viscosity and oil droplets-to-water interfacial tensions increased as the surfactant content decreased resulting in higher capillary pressure sections of up to 3 km with undulations of up to 40 m. Some of them are equipped with distributed temperature-sensing technology for mo

Both gases require a certain penetration depth to develop into foam. This length is longer for N2 (larger entrance effect) and increases with g sure gradient is higher than the capillary entry pressure for the layer. The new stochastic population balance foam model reproduces rather m is that it can avoid the dispersion of the chemicals needed to reduce the interfacial tension and to enable the recovery of residual oil. The flow are modifications of methods to predict wet gas pressure drop in tubing. These modifications are usually based on assumptions which

ers and of the tube inclination were of special interest. The influence of dynamic disturbances on the stability are not taken into account by r perforation.� These results are in line with the production performance observed in pad D-36 and also in line with our simulations.� T relative performance; for example to assess whether incremental production predicted for a superior system justifies additional expenditur e lengths of five feet or more would propagate from each perforation tunnel.� Such large propagation lengths greatly increased the proba bination of expandable sand screens (ESS) and propped hydraulic fracturing in a cased-hole environment. Two wells were planned in whic ore analysis and the completion types that would be suitable for development of the H1/H2 reservoirs.� From this review the operator an . Two sets of additional burst tests were conducted with Alloy 625 screens on 25 Chrome base pipe to meet injector material requirements. development of the H1/H2 reservoirs was initiated. From this review the operator and a service/engineering company were able to develop facilities design is discussed based on a probabilistic approach along with the operational procedures identified to manage this sand. The

mately jeopardize overall well objectives. In 2002 a Task Group was formed to develop a standard testing method and procedure to measu as well as the implementation of a unique mixing system. Several case histories are presented illustrating the effectiveness of the fluid sys gy is based on an exact solution to the fully transient elliptical fluid flow equation around a closing fracture with changing conductivity face s

servoir into multiple vertical compartments provide the impetus for drilling a high angle transect instead of a horizontal well penetrating a sin

e reservoir. For post-processing the MR data were integrated and interpreted together with the other measurements performed in the well d rediction was more pronounced at higher temperatures (and pressures) than at lower temperatures which could not be explained by mech esults compared with the set goals. The application of the latest technologies in Gas-Condensate well testing was used on this job. Experie mation permeability anisotropy skin factor vertical connectivity and zonal productivity index are additional reservoir information that can be gas phases are measured discreetly. Tests are periodically conducted for example once a month or once a week. The duration of purge a

tions Intergovernmental Panel on Climate Change (IPCC) has identified CO2 capture and storage (CCS) as the most promising for the rapid ted Nations Intergovernmental Panel on Climate Change (IPCC) has identified CO2 capture and storage (CCS) as the most promising for t s in agreement with contact-angle measurements. Hence we conclude that imbibition tests provide the practically relevant data to evaluate ng applications such as polymer sciences biomedical applications and possibly in diffusion processes in hydrates. It is of interest to investi values for all pressure steps. A volumetric strain of 1.9% corresponding to a mean pore pressure of 14 MPa was measured. This confirms t experiments. Introduction Coal matrix is heterogeneous and is characterized by three different porosity systems - micropore mesopore and

xchange process. These questions can be answered by means of downscaled laboratory experiments that are capable of accurately descri 0–710 m (2070–2330 ft) that is made of siltstones and sandstones interbedded by mudstones. A comprehensive borehole logging prog ction wells; assessing containment risks; and determining monitoring requirements. These projects are particularly challenging in today's so ks that pose opportunities and barriers for CO2 capture and geologic storage and;�initiatives and strategies to advance CO2 capture an and data stores from multiple vendors. Such optimization is important both for situations with low-frequency changes such as waterfloods richly detailed and broad-based real life case study as deployed by Chevron. The strategy that current members have set for the next thre

s and workflows maximises the value of information and improves operational decision-making. The interpretative workflow also involves i iven well models allow the prediction of the changes to overall and individual well production as a result of changes to individual well produc ct of the technique is that it uses dynamic data-driven models to describe the production process together with a new well test methodolog al production from the facility is reconciled to individual wells using these estimates. These flow estimates change the traditional process of

sting assets and can be replicated globally across diverse operating environments. This paper will reveal new information from field operat ter solution is the best answer in a large proportion of our cases. We will therefore focus in this paper on describing its strengths weakness mining drainage volume is still relatively immature as we have executed only one injection test to date. However there has been considera

stacked (some 100) reservoirs in 10 fault blocks). Many field development plans (FDP) were drafted but none of them executed because

objective function. Results for the numerical examples studied indicate that the regularization may lead to significantly different optimum st ease (5% gas and 10% oil); 10% Increased production; Reduced development risk and uncertainty; Other important benefits include impr try estimates. The benefits will vary with the character of the asset and are larger for new fields than for mature fields since reservoir contro n one case the smart completion enabled the clean-up of the initially uncompleted toe significantly increasing total recovery from the well.

½ï¿½ï¿½â€¢ ����the deepest SMART completion in the world The 350 days campaign was delivered 49 days earlier than plann ase separator can be replaced by combining inline phase separation a gas buster and down-hole multiphase metering. Furthermore it desc drilling process used to precisely control the annular pressure profile throughout the well bore. The objectives are to establish the down-ho ing an Equation of State (EOS) methodology.� This approach however neglects combustion and its effects on both displacement and sw ress contrast fluid quality and TSS content fluid rheology and effective viscosity in the formation and the filtercake properties in the presen fluence the surfactant properties of the IOS mixture formed which provides a means for tailoring an IOS surfactant for optimal performance viscosity gas drive and stripping effects. - In deeper reservoirs GOGD under miscible conditions becomes an option. Injection gas that is m eally the process is suited to deep high-temperature light oil reservoirs and is applicable to both secondary and tertiary recovery. The Coo nsists of 8 different fields containing 10 reservoirs. All the reservoirs are carbonate reservoirs at 3.5 to 5.5 km deep embedded in salt. The r asis of profile correction used to improve water- or steam-flooding in highly heterogeneous (layered) formations [7]. Foam has also been use on of gas miscible modeling with a simplified 1D Todd and Longstaff representation of phase mixing A combined engineering and economic

e being managed right upfront during design. Energy consumption in the full field development of this project is reduced by banking on the b

ollowing conclusions were drawn: (1) Designer Waterflooding may increase the Ultimate Recovery of oil by at least a few percent; (2) There rces of gas production and formation-microimager (FMI) logs used for fracture identification and characterization. This paper illustrates the nes will re-establish the oil production. The shutoff zones can be reopened later in the well’s life when artificial lift has been installed. Th 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 dition of the particles wellbore fluids or variations in lithology (sandstone dolomite limestone shale etc). Bullheading the PG system into emonstrated an almost full oil recovery from core plugs. Little attention however has been given to the mechanism underlying the transpor chnical potential of the wellhead platforms. An example showed 10 % acceleration of 15 years Oil Production and 5 % increased recovery o th non-linearity but as noted by Rockafellar1: “The great watershed in optimization isn't between linearity and non-linearity but between er to Russian oil and gas field production. 1. Introduction Many operating units in Ural Povolgie Tatarstan Bashkorstan and West Siberia 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 il ratios at reservoir temperature although displaying different relationships with pressure converged to almost the same end-point pressur Gas Production Engineering) gave a viscosity of 1.178cp while the new equation gave 1.177cp. The study of Gas viscosity at atmospheric

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 uce a more robust interpretation of the fluids and yield insights into reservoir architecture. Introduction Sage and Lacey (1938) define comp vital input to the design of production facilities. Conventionally GOR is measured at a PVT laboratory and it may take many weeks before (e.g. sulfur selective chromatography and derivatization) in combination with FT-ICR MS. Initial data show that the predominant compounds emulsions was investigated using a fully visual pressure/volume/temperature (PVT) cell while viscosities were measured using a precalibra vancing contact angles of live oil (55�) and stock-tank oil (154�) clearly indicates the need to use live oils at reservoir conditions to det

this system. Unique experiences acquired during the field trials carried out within the Niger Delta using this system are evaluated. The resu

based on the analysis of two case histories. In an acid treatment the fluid diversion design is often based on guidelines rules-of-thumb an

d in detail. Both relative permeability and permanent-damage effects are described. The dramatic effects of invasion on cleanup and long-te pH change experiments we only require the first two of these parameters i.e. Kow and pKa. Using the naphthenate model without precipita

is often not accurate enough to demonstrate what is happening downhole e.g. if seawater breakthrough (SWB) has occurred or not. PCA ramework of the simplest theory. Such a theory is presented in this report. We derive simple relations to estimate critical flow parameters an

of the modeling assured that only the features relevant to the dynamic behavior of the reservoir were modeled while at the same time the g relative permeability hysteresis were important aspects of the overall physical representation. Common physical parameters for dilation/reth higher water cut could not benefit from production increase via acidising. Common diverters such as water seeking polymer foam pad an esults. Introduction With fine-grid single-porosity models (SP) for fractured reservoirs being computationally prohibitive in terms of compute imulation of the later cycles requires a full pad dynamic model constraint by monitoring data if the heterogeneous steam distribution sugge aken at a selected point of each reservoir. Comparisons of measured data and calibrated model show that the EOS model quantitatively (w those from an industry-recognised package of a major Service Provider. In addition the performance of commercial shaped charge perfora 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 s well as the proper handling of data to assist in the design of future trials. This paper will review the following topics: -��� Design o

servoirs.[1 2 3]�The broadness of the permeability distribution often over two orders of magnitude in breadth poses a statistical proble erefore provide good estimates of the water and gas production profiles even in small watercut wells. This paper describes the technique u data and geologic models was used to construct detailed static and dynamic models. The resulting history matched models were used to e sult is given as a rational polynomial in terms of the Knudsen number (the ratio of the mean free path of the gas molecules to the character wells in desert areas remote from hydrocarbon processing and export infrastructure helps to reduce overall project risk. In low permeability m Beijing1. Development drilling commenced August 2005 and is now a three rig operation. As of end June five wells have been completed ess than 1 mD. Up to the 90’s the preferred method of developing these types of tight gas reservoirs was through massive hydraulic fra

een able to make visible to the key stakeholders/decision-makers fit for purpose work plans track milestones and action items as well as c

moval. Production gain predicted by PROSPER model simulation if the predicted skin damage is removed was however marginal. In an att opment projects is a deeply technical process that focuses on the highly complex physical arrangement of the system. Indeed the major ele s execution of the HD and IRM processes through establishment of a common real-time team view.�This view increases transparency o ion for modeling both static and dynamic properties in capillary transition zones. We then address how to calculate initial-oil-saturation dist dentifying abrupt changes in fluid properties that occur with depth the FCA may in some circumstances be an assay for reservoir compartm ps to five groups: C1 ethane (C2) propane to pentane (C3–5) C6+ and CO2. These spectrometers together with improved composition

tion of the recovery factor can be produced within hours instead of days by combined use of Monte Carlo simulation and a simple dynamic 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

o applied to a field case study to verify the practicality of the technique. Unlike previous mini-frac-analysis methods this approach identifies and in the core-scale averaged 2.5 darcies. The field-scale permeability was estimated to be 500 md from steady state airflow and pressure cant portion of the range of permeabilities that are relevant in reservoir engineering. In 80% of the cases the permeabilities predicted by ou easing the confidence in calls made regarding reservoir characteristics. Application of RIPI to field data is illustrated through several exampl ly half of the fracture fairways and indirect indicators from dynamic data had to be used to identify and map fracture fairways. Introduction T conditional probability of having mud losses given a step flow profile and probability of having a fracture corridor given mud losses. Condit l types. Particular emphasis is placed on comparing the strengths and limitations of the different techniques in revealing reservoir architectu e have successfully combined various fluid-based techniques for improved reservoir characterization. Introduction Determining connectivity ng technologies did not offer the resolution and sensitivity necessary to provide quantitative hydrocarbon description. However recent devel lation techniques. This has led to several insights that were missed in earlier field studies which used a set of simplified correlation function cquisition schemes including diffusion effects make the interpretation more robust but a normal NMR acquisition suffices as can be made w

1. The Bubut prospect is a simple 3-way fault/dip closed structure with the prospective reservoir section consisting of multiple stacked reser olving lateral heterogeneity at field scale and improving the understanding of the ranges of drainage areas for development wells Low resist CO2. These resources will require specific technologies to develop these fields economically. The bulk of these resources are in the Middle

eful first pass screening tool to make assessments of the likely oil recovery range from a specific oil rim reservoir. The oil recovery trends ob augen reservoir-simulation models enabling improved forecast and reserves estimates as well as better business decisions. Effects on field chnologies in West Siberia such as hi-end logging wireline formation testing specialised core analysis and geochemical fluid analysis is de

an. This paper presents key elements of successful WRM in Bonga. These include people factor and cross discipline integration Smart Fie

n the seamless cross discipline integration that enabled� maximum extraction of information from the available data. The same discipline

acturing conditions. This is illustrated in Fig. 1-2 1-2 comparing matrix injection of fine-filtered seawater (Fig. 1 1) with fractured injection of h ell configuration and steaming strategy for each field area (based on approximate Net Present Value NPV). The final phase entailed uncer ether with the good reservoir surveillance data made this field the ideal candidate for studying different aspects of karstification that are also er Injectors are used to allocate water into multiple layers to optimize reservoir recovery. In addition extended reach wells are tapping into u longer profitable. The NO procedure is based on a single realization. In our study the NO procedure is performed on each of the 100 realiz oduction rapid watercut development (>80%) variable well performance and marked pressure decline. The fields are medium to small salt per will present how phased development aspect of reservoir management techniques have been applied to maximizing the value of the Og nment and resulting conclusions. • Design considerations for the multilayer fractured water injector wells including: o Selected drilling asp ow saturation profiles mobility ratio and frontal advance equations were kept in mind while proposing these plans. By implementation of th nly depends on distance and topography. Several scenarios were tested for demand and recoverable gas resources using public data. Sup ement activities are in full swing. Onshore construction involving more than 35 000 workers is gaining momentum as the plant takes shape est duration. This test rig has since 2007 been field tested at two oilfields main findings being: ��������-��� ssing challenges that made many believe that this is more serious than the climate change challenge. Half the world's population is living w ess control in Oil and Gas Production requires change management; Process Control technology skills need to be used throughout the who ained later in the paper) in the vicinity of the wells taken up for time-lapse survey. Thus the challenge was to study the flow dynamics so tha

e suitability of this approach. The strategy to let the reservoir sour and handle the H2S at surface was re-evaluated in 2003. It was found tha at the end of 2005.� As such Bonga is one of the first waterfloods where nitrate is being used to prevent reservoir souring the main appl esults obtained in the HP corrosion monitoring system in place on Draugen. The results of the Draugen PWRI pilot also showed that the ad corrosion mitigation for carbon and low alloy steels is controlled by applying appropriate inhibition program. In most cases continuous injec nsite measurement and method revision adopted instrument calibration accuracy established frequent surveillance teams investigated the n quickly bringing wells back to full oil production. A field example is presented for a deepwater field in West Africa where intervention costs te recovery. The main advantage of the adjoint method is that it provides sensitivities with only one forward (reservoir) and one backward (a oduction to the Asset The Harweel Cluster is a new oil province that has recently been brought on stream by Petroleum Development Oma and/or CO2. These resources will require specific technologies to develop these fields economically. The bulk of these resources are in the sualisation methods and discipline integration have maximized the information of the 4D surveys and how this has been used to improve th n logs were integrated with pulsed neutron capture and spectroscopy measurements to enhance our understanding. In one of the example nd gas development is attractive. The main conclusions for this type of reservoir are:� A relatively high gas offtake rates (up to 10% GIIP

ds could be established rather confidently and recoveries in excess of 55% should eventually be achievable. Predicting water-flood efficienc of the optimization algorithm were required to allow the inclusion of inequality constraints on well control (pressure and rate constraints). W eservoir units dip at an angle of approximately 20 degrees to the NW and have a strongly layered internal architecture with only limited (ver ailed evaluation of velocities core and well-log information was undertaken to provide input into an in-house probabilistic model-based seis exico. Introduction The objective of automatic history matching is to obtain a reservoir simulation model that honors observed production putes improving directions for all wells in only one forward (reservoir) and one backward (adjoint) simulation. The process is repeated until n overed later that the lower channel had become inadvertently fractured during fabrication of the model. Although incorporating the fracture egy embedded into the resampling step improves the filter stability and delivers rapid convergence. SEIKF is applied to a three-dimension stic framework delivered (a) a complete description of the high-impact model parameters dominating the quality of the match (b) multiple m her conclusion is a formulation for the way in which Power Law parameters influence convective heat transfer of the fluid and hence identifi att (1962) condition. The solution of the 5D problem is computed by use of a tuned Broyden (1965) approach. We demonstrate the capabil (producers injectors) and geological details (e.g. flow baffles faults). The results presented in this paper are expected to also apply to (pa the cases where the results of the coupled simulations are significantly more accurate in comparison to stand-alone well or reservoir simula duction. The results of the coupled well-reservoir simulations are presented and the phenomena that are most likely to cause the production

erently related non-controllability of input variables under-estimation of the impact of uncertainties and the challenge of constructing (inter ponents and Buckley-Leverett / Welge theory. This match leading to an estimation of the likely uncertainty range in end point relative perme dblock sizes on the order of 2 ft. The method was tested for single-layer multilayer and multiwell gas-condensate reservoirs and was foun

rent indicators and selecting the best. In this paper the capabilities of approach in generation of unstructured coarse grids from fine geolog o PB gridding which is a static method. Based on this analysis we then concentrate on FB and VB griddings and investigate their performa odeling resulting in a less computationally demanding and more accurate upscaling technique. To evaluate the method we run two-phase s

and geochemisty that focused on reservoir compartmentalization. Such data confirmed well responses and helped us to initialize the reserv elastic stress simulation; (2) geostatistical population of fracture density based on a fracture trend model; (3) fracture permeability modelin ate an excellent history match that is also followed by the success in the blind tests of newly drilled wells. Significant improvement was obta shape factor expressions but also allows extensions to recovery mechanisms requiring a dual permeability approach. The paper is organi

rface challenges such as compaction compartmentalization and completion failures has naturally evolved as new related technologies ev

ment. Making the wrong forecast may be a problem but making the wrong assessment of its uncertainties or not providing them at all could iance matrix in order to reduce unwanted influences of distant observation points on model parameter updates. In particular streamline-ba ehavior predicted by the theory is actually observed. We expect the method to have value in reservoir limits testing in making consistent es ive insight to strategies in understanding the simulation output and making good engineering decisions are discussed in this paper. Introdu ace parasequences which form the majority of Champion reservoirs. In general these comprise a gradational succession from basal offsho

flow because less refinement is needed in these areas to still match the flow behavior of the fine model. The final ratio of pre- to post-scale t and systematic screening criteria are used to identify the best storage candidates. The status of the UK’s current natural gas field por and Purvis. Besides its simplicity the proposed model consistently performs better and shows robustness. Although the form of the propos ent between the model and field data is obtained. Complex wells containing multiple branches are then simulated including a steam-water c based on permeability or porosity classes alone is not adequate. Moreover the petrophysical correlations often used for clastic reservoirs (e mpartment boundaries is essential for optimizing the field development. Like so many fields the JG field proved to be more complex than ini ances mixing by providing larger area in the transverse direction for diffusion to act. This suggests that in-situ mixing is an important phenom

or a lower the expected PVC. Obviously having lower oil volumes in place would greatly impact the economics of a miscible gasflood deve lved in TAGOGD were validated through laboratory experiments while the field forecast model results were validated by history matching p ents and separate PVT measurements the effects of thermal expansion of oil gas liberation and initial water saturation are investigated. Th n solution gas drive and stripping effects. No viscous pressures are building up and steam drive does not occur. For reservoirs containing v eudo skin factor.�Partially fractured models also demonstrate that some matrix pore space which was capable of producing gas canno ives the posterior probabilities for modeling parameters. 3. The facies models are changed by using a probability perturbation method whi D project. SAGD operations are badly compromised by lack of steam mainly but also by long boiler shutdowns and by losing confined injec ugh oil and gas cap expansion mechanism.� The field was shut-in in 1986 awaiting gas injection.� In 1993 sour separator gas combin a better understanding of the waterflood performance. The main improvement compared to previous work was the integration of the data a us against elevated surface pressures resembling subsea blowout conditions. A comparison of the measured rates with the calculated rate opposed to the holistic full project value associated with the business process that has been improved by the application of that technology DOF through the lens of one person’s experience is hardly history but may give some clues regarding how to do “it and how not to eplacement technology. Introduction Completion reliability and the potential to achieve significantly higher sustainable production rates are antages and disadvantages of disposal options from blocking Acid Gas Injection (AGI) and the application of new sulfur products such as su collection is vital. A data management system allows quick access to well production history data. ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½â€¢ï¿½ï¿ has spent appreciable time and effort evaluating various potential challenges affecting the surface and subsurface aspects of the developme uction and high water cut. It is also covered by several vintages of 2D lines and one vintage of higher quality 3D seismic data that was acqu

ells and crosschecked with 3D seismic features where possible. Bypassed oil-in-place volumes were calculated using the saturation-initialize

olution is to fully utilize surface and downhole pressure data and multirate well tests to generate data driven models to determine zonal inflo

ctivity from the temperature history of the pilot. The azimuth of the Phase I hydraulic fracture is determined to be 14� � 2 N-NE. The a

goals. Introduction Production in Mars field in the Gulf of Mexico began in 1996 and peaked in June of 2000 at 208 000 B/D of oil and 217

elies on permanent acoustic sensors performing acoustic soundings at the start of production and then repeating these measurements durin ssure that the planned data are acquired according to pre-established procedures and contingency plans. However even in developed rese aused by the fluid injection into or withdrawal from the reservoir. These studies focus mainly on three areas. The first area of study is how to duction The main objective of this work is to investigate whether the tidal pressure response in petroleum reservoirs can be used for reserv ication is attainable. The conclusions and claims of this technique are validated against the results of an advanced production logging tool ( lance program. The logging program has had two purposes. The primary purpose of the program has been to monitor the “sea water w ve. The particular logging tool described in this paper provides a recording of holdup and velocity profiles along the vertical diameter of the gest oil shale basin in the world. It has been estimated that oil resource within the Green River formation is in the range of 500 to 1 100 billi

unei with high success rate (no failure on single well was recorded). Confidence level of acid stimulation in Shell Asia Pacific region has be presented. The openhole completions are preffered over casedhole completions in the relatively high transmissibility reservoirs of the Nige ly extended by the addition of metal ions (e.g. Ca2+ and Fe2+). The addition of Mg2+ may increase the long-term return concentration wh in two reservoir settings. In both cases the optimization resulted in accelerated oil production compared to conventional surface-controlled

practical applications a simulator has been developed and validated by experimental flow-loop data obtained from the Advanced Cuttings T rather than chemical the proppant flowback is controlled without specific shut-in time temperature or pressure constraints. The use of fibe mly distributed. The data also indicate that a smaller breaker amount delivered directly into the filter cake is more effective at reducing the yi

nd moreover can be used to increase the produced oil rate by tuning ICV settings to achieve an optimal well gas fraction. Results show tha esulting in higher capillary pressure across the trapped oil droplet. The effect of oil type rock permeability injection velocity and wettability perature-sensing technology for monitoring the inflow distribution and some have smart completions to control inflow from different reservo

entrance effect) and increases with growing gas velocity. Moreover the ultimate liquid recovery by CO2 foam is always lower than by N2 foa nce foam model reproduces rather well the main features of foam motion in heterogeneous cores containing a surfactant. Core floods com ble the recovery of residual oil. Therefore the costs derived from those chemicals are considerably reduced.3 Modelling and laboratory stu usually based on assumptions which are strictly valid only for single-phase flow. Their validity for gas-liquid flow is questionable. Hence to a

ability are not taken into account by the classic prediction models. Systems with high permeable reservoirs are less able to cope with disturb so in line with our simulations.� The calculations performed here do not take into account any skin damage effects that potentially could ystem justifies additional expenditure. The user can also test the sensitivity of inflow performance to perforating system performance and i lengths greatly increased the probability of connecting the completion directly to karstic features in the reservoir to provide enhanced inflow ent. Two wells were planned in which three oil reservoirs would be completed and produced commingled using one gas reservoir as a lift g ½ From this review the operator and a service/ engineering company were able to develop a sand-exclusion method that combined severa meet injector material requirements. The FLC formulation was modified from conventional design to enhance the pressure response. The la ering company were able to develop an innovative sand-exclusion method that combined several new technologies. To date four wells h dentified to manage this sand. The operational evaluation is based on a Quantitative Risk Analysis (QRA) of the facilities and wells which h

ng method and procedure to measure and quantify static fluid loss from stimulation and gravel-pack fluids. The Task Group comprised a cro ing the effectiveness of the fluid systems and mixing process in improving well productivity and job economics. A stimulation campaign was re with changing conductivity face skin and multiple reservoir mobility zones. It also captures the case that during closure the fracture gene

of a horizontal well penetrating a single compartment this paper provides insight into the impact of shales dividing the reservoir into non-com

easurements performed in the well delivering an accurate and consistent reservoir description. First part of the horizontal part of the well wa ich could not be explained by mechanical factors such as casing ballooning. The influence of these factors was quantified by analyzing the esting was used on this job. Experiences from this were later used as the basis for other gas-condensate prospects including those in the R nal reservoir information that can be obtained from a mini-Drill Stem Test (mini-DST) and a Vertical Interference Test (VIT). Pressure transi nce a week. The duration of purge and test periods are usually fixed for example 30 minutes to purge the test separator and eight hours to

S) as the most promising for the rapid reduction of global emissions - by up to 55% by 2100. As the bridge to a more sustainable ener e (CCS) as the most promising for the rapid reduction of global emissions - by up to 55% by 2100[2]. As the bridge to a more sustainable e practically relevant data to evaluate the wetting properties of coal. Introduction Geological sequestration (Orr 2004) of CO2 is one of the v n hydrates. It is of interest to investigate its importance in CO2 induced swelling of coal in carbon sequestration applications. The swelling" MPa was measured. This confirms the process of sequential swelling. A unique feature of this work is that real-time permeability measurem systems - micropore mesopore and macropore. The macropores are the cleats which are sub-vertically oriented to the bedding plane in c

hat are capable of accurately describing the coupled process of multiphase flow competitive adsorption and geo-mechanics. In the laborat omprehensive borehole logging program was performed consisting of routine well logging to which an enhanced logging program was adde particularly challenging in today's society where information is easily accessible by the public yet policy and regulations are still evolving. Ba ategies to advance CO2 capture and geologic storage by reducing cost and risk �and developing sound regulatory and policy framewor ency changes such as waterfloods and for those requiring agility such as compliance with pipeline liquefied natural gas and power-gener members have set for the next three years will be outlined. This covers expansion of the “footprint of PRODML (reflecting the need for

nterpretative workflow also involves integrating advanced mud-gas logging technology data with formation testing Geochemical and PVT d of changes to individual well production chokes lift-gas rates or other similar set-points. Well setpoints are then computed for optimizing oi ther with a new well test methodology for capturing the data to build the initial models. Well tests include a deliberate disturbance to the pro es change the traditional process of periodically routing a well’s production to a test separator; individual well flow information is availab

al new information from field operations and demonstrates two technical contributions: detecting events from ongoing field surveillance act n describing its strengths weaknesses and opportunities. Our applications of this technology are still evolving and there are clearly more is However there has been considerable design work that makes us believe that this technology is also promising. Our experiences with OV

ut none of them executed because the oil development costs were too high (too many platforms and too many wells). Developing the CW

to significantly different optimum strategies but may result in a similar cumulative oil production. Introduction We consider the seconda ther important benefits include improved HSE. Ultimately Shell is aiming for Smart Fields to contribute to bottom line benefits of some $35 r mature fields since reservoir control by eg. smart wells can only be built in at the start of a project. On average the following estimates are easing total recovery from the well. In another case the smart completion mitigated the risk from a potentially bad cement job saving a cem

delivered 49 days earlier than planned and below budget. Total cumulative drilling length was of 34 km. This performance allowed the Well phase metering. Furthermore it describes how massive surface snubbing systems are being replaced with down-hole isolation systems and ectives are to establish the down-hole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. In a s effects on both displacement and sweep.� Furthermore the EOS approach cannot predict if and when oxygen breakthrough at produce he filtercake properties in the presence of polymer. This paper is intended to provide a geomechanical perspective on the generally comple surfactant for optimal performance. 1.������ Introduction In chemically enhanced oil recovery (EOR) the mobilisation of r es an option. Injection gas that is miscible with the oil will result in swelling and viscosity reduction both increasing oil mobility and therefore dary and tertiary recovery. The Cooper-Eromanga Basin Carnarvon Basin (Barrow Island) and the Surat-Bowen Basin were identified as th .5 km deep embedded in salt. The reservoirs are all very similar carbonate slabs of about 100 m thick and generally have low permeability ( mations [7]. Foam has also been used for gas blocking in oil wells [5] and of acid diversion in matrix stimulation operations [2]. In these near ombined engineering and economic approach to establish gas injection strategy. The results of this case study confirmed the capability of

oject is reduced by banking on the benefit from co-generation of power and steam. Utilisation of co-generation will minimise CO2 emission

l by at least a few percent; (2) There is scope for further improvement in oil production by flood front stabilization by adding low concentratio erization. This paper illustrates the work carried out in horizontal openhole and vertical cased-hole completions to shut off the undesirable en artificial lift has been installed. The system was tested in the field in two wells. In the first field trial 84 m of perforations (gross) was sque 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 c). Bullheading the PG system into the well allows easy placement and calculation of treatment volume. The limited and controlled leakoff mechanism underlying the transport of the chemical into the matrix block and to the proper scaling of laboratory results to reservoir size. Th uction and 5 % increased recovery of 15 years Gas Production. Introduction An integrated business development modelling approach is oft earity and non-linearity but between convexity and non-convexity. The impact of non-convexity on optimization problems and the multiple o tan Bashkorstan and West Siberia are today celebrating their 40th and 50th anniversaries since first production and are now entering into a 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 almost the same end-point pressure at zero-IFT. In spite of the large variations in the initial mixture compositions only negligible changes i udy of Gas viscosity at atmospheric pressure (15psia) also yielded an equation. Comparison of calculated Gas viscosity of this equation wit

nce of water in order to quantify H2S scavenging effects. We have also identified all the components in the formation tester string which cou Sage and Lacey (1938) define compositional grading as “variations in the composition of the liquid phase of natural reservoirs which ar 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 ow that the predominant compounds in the asphaltene samples investigated were species in the mass range of 200-1100 Daltons containin s were measured using a precalibrated high-pressure capillary viscometer. Viscosities were measured at least in three different flow rates a ive oils at reservoir conditions to determine in-situ reservoir wettability. Anionic surfactant altered the weakly water-wet behavior of live oil to

his system are evaluated. The results demonstrate a significant increase in incremental hydrocarbon production for normally high risk low

ed on guidelines rules-of-thumb and an intuitive idea on how diversion works." Simulators are not used usually because they are not avail

s of invasion on cleanup and long-term production are illustrated demonstrating the incremental value of UBD in these cases. Damage can naphthenate model without precipitation we studied the effect of varying parameters on the degree of pH change predicted at equilibrium in

gh (SWB) has occurred or not. PCA is a powerful tool with which one can resolve subtle yet significant changes in produced water and thus estimate critical flow parameters and transported fluxes. These relations provide a relatively simple evaluation of steam injection and hydro

modeled while at the same time the geological details of matrix and fracture models were captured sufficiently in the simulator. Simulations w n physical parameters for dilation/re-compaction fractures permeability/porosity transforms vertical to horizontal permeability ratios and re water seeking polymer foam pad and benzoic acid ball sealers packers and gel acid have been applied for water control during HF treatm nally prohibitive in terms of computer time and memory the simulation of oil recovery from fractured reservoirs typically requires a dual-perm rogeneous steam distribution suggested by the monitoring data becomes significant. Introduction Peace River is a 100% Shell Canada-ow hat the EOS model quantitatively (within desired limits) and qualitatively described the observed equilibrium fluid grading behavior of the flui f commercial shaped charge perforators in full bore Harweel core was evaluated under pseudo downhole conditions. A series of tests with a same period of time which is indicative of secondary precipitation. The effectiveness of the chelant fluid for stimulation of this high temper owing topics: -��� Design of the field trial -��� Efforts to minimize variables -��� Well selection to promote valid o

n breadth poses a statistical problem when trying to simply compare production response of one set of data to another in a given field.� This paper describes the technique used to improve the production flow profiling supporting its assertions with case study results. Introduct ory matched models were used to evaluate numerous well densities and patterns. This formed the basis for the two wells per quarter quarte f the gas molecules to the characteristic flow length (typically the radius of the capillary)). The following contributions are derived from this w erall project risk. In low permeability reservoirs over balance drilling induced near wellbore reservoir inflow impairment has historically deliv une five wells have been completed of which four are tested and connected to the processing facility. The drilling outcomes have broken re s was through massive hydraulic fraccing. During the 90’s the emphasis shifted to horizontal drilling. This proved successful in tight gas

tones and action items as well as capture “as-is thinking work-in-progress data/documents and team decisions throughout the life cycl

ved was however marginal. In an attempt to address the issues a multi-disciplinary team to tackle the problem starting with the less expens of the system. Indeed the major elements of the platform the risers the tiebacks and so on can be combined in literally millions of ways s This view increases transparency of technical work allows for real-time updates on progression of the risk mitigation plan and allows for p to calculate initial-oil-saturation distribution in the carbonate fields by reconciling log and core data and taking into account the effect of res be an assay for reservoir compartmentalization. In this paper we briefly review the theory of the FCA. The strengths and limitations of the together with improved compositional algorithms now make possible a quantitative analysis of reservoir fluid with greater accuracy and rep

o simulation and a simple dynamic model with effective properties. Recovery factors estimated via our simplified modeling method agree w re we could estimate the minimum horizontal stress magnitude by use of both the MDT minifrac tests and inversion of borehole sonic data.

s methods this approach identifies natural fractures that are material to production and allows the engineer to distinguish them from “fis om steady state airflow and pressure transient tests. In the bench and core scales a connected path of vugs dominates flow and tracer con s the permeabilities predicted by our method are within a factor of two of the measured values and the predictions are within a factor of thre s illustrated through several examples. Data acquisition processing and preparation for UBD reservoir characterization are discussed. In p map fracture fairways. Introduction Two common types of natural fractures are diffuse layer bound fractures and fault related fracture corrid re corridor given mud losses. Conditional probability graphs are constructed for continuous variables such as water cut gross rates and inje ques in revealing reservoir architecture especially vertical-permeability barriers. We present a number of unambiguous cases for which mu troduction Determining connectivity at the reservoir scale remains the elusive goal for predicting long-term production profiles. Characteriza n description. However recent developments in advanced mud gas extractors and improved analytical detectors have increased the sensitiv set of simplified correlation functions/parameters for the cluster of fields without adequate special core analysis data calibration. Based on cquisition suffices as can be made with all available NMR tools (wireline and while-drilling). The new NMR-based method has been verified

consisting of multiple stacked reservoir-seal pairs.� BU-2 is a vertical well located 7 km offshore in a water depth of 17.4 m (Fig. i). The as for development wells Low resistivity pay analysis geared towards understanding of both static (saturation net-to-gross) and dynamic (p of these resources are in the Middle East Canada CIS Asia and Australia. In general one could say that the predominantly H2S contamin

reservoir. The oil recovery trends obtained from the simulation study have been found to be consistent with actual oil rim performance. The r business decisions. Effects on field reservoir management have included revising the water-injection strategy converting a producer to an and geochemical fluid analysis is described. The reservoir management section concentrates on several technical aspects of West Salym d

ross discipline integration Smart Fields� capability ‘live’ WRM Plan and monitoring good understanding of subsurface applicatio

available data. The same discipline integration led to a thorough understanding of the critical remaining uncertainties in the project and a ta

(Fig. 1 1) with fractured injection of heavily contaminated production water (Fig. 2 2). In the former case regular acidizations are required to PV). The final phase entailed uncertainty analysis for the optimized design concepts and determining P15 P50 and P85 forecasts for each aspects of karstification that are also relevant to the other fields in the area. Important questions are when did karstification occur what is its ended reach wells are tapping into undrained areas of the field to recover additional reserves reducing the environmental footprint. The fiel performed on each of the 100 realizations in the set individually resulting in 100 different NO-production strategies. The control strategies w The fields are medium to small salt withdrawal-related structures often with stacked reservoirs varying oil quality (7-400cP) and low to med d to maximizing the value of the Ogbotobo field. The development strategy also include the implementation of an early “production/dril ells including: o Selected drilling aspects (well trajectory drill-in fluid formation evaluation casing scheme). o Completion design considera ese plans. By implementation of the most appropriate plan the reservoir pressure was maintained 150 psi above the bubble point pressur gas resources using public data. Supply and demand predictions are from USA Government Agencies. Gas transport capacities between th momentum as the plant takes shape. The recruitment of operational staff and the development of detailed operational procedures and othe ½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½-����Steady-state conditions can only be achieved in long term exposure windows ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ Half the world's population is living without access to clean water (UN report). The growing demand and competing needs for fresh water res need to be used throughout the whole projects lifecycle and integrated with the various processes from field development planning to survei as to study the flow dynamics so that additional perforations in the bypassed section yield water-free oil and so that very little scope is left f

-evaluated in 2003. It was found that H2S levels are likely to exceed 50 ppm(v). Since then a new strategy with mitigation was adopted. Se ent reservoir souring the main application so far has been to reduce H2S in already sour fields. This paper presents the experience gained PWRI pilot also showed that the addition of nitrate to the PW was efficient to control near-well reservoir souring. However as mentioned a ram. In most cases continuous injection of inhibitors and pigging activities are considered to be adequate for mitigating corrosion. Several fa surveillance teams investigated the caused of souring by Sulphur Isotope methodology for both X and Y field and monitor the produce soli West Africa where intervention costs are high and any negative impact of squeeze treatments can have a significant associated deferred oil c ard (reservoir) and one backward (adjoint) simulation rendering computational costs affordable for field applications. The adjoint method in am by Petroleum Development Oman (PDO). The Cluster is composed of 8 different fields containing 10 reservoirs as shown on Figure 1. A he bulk of these resources are in the Middle East Canada CIS Asia and Australia. In general one could say that the predominantly H2S c ow this has been used to improve the reservoir simulation model. The paper provides clear examples of how surveillance is supporting res nderstanding. In one of the examples a compact integrated production logging tool comprising an array of spinners and holdup probes was gh gas offtake rates (up to 10% GIIP/year) can be achieved with limited reduction in oil recovery. Oil rim recovery is a function of how fast th

able. Predicting water-flood efficiency in the Mulussa F 3D sand channel labyrinth turned out more complicated. As a matter of fact it was d (pressure and rate constraints). We applied the optimization algorithm to a number of cases and found interesting non-trivial solutions to al architecture with only limited (vertical) communication between layers. Sand porosities and permeabilities are good in the oil column gen ouse probabilistic model-based seismic inversion (1). This fundamental work was used to: construct an integrated and fully consistent stru el that honors observed production history and is geologically plausible. Although dynamic data from the wells such as pressure gas oil rat tion. The process is repeated until no further improvements are obtained. The method is applied to three waterflooding examples. Introduct Although incorporating the fracture system into the simulation model significantly improved the quality of the history match the character of EIKF is applied to a three-dimensional proof-of-concept waterflooding case where reservoir permeability is calibrated to production data. Acc e quality of the match (b) multiple models honoring the historical production data (c) reduced uncertainty ranges for the history-matching p ansfer of the fluid and hence identification of the parameters which need to be measured in order to characterize the convection of the fluid roach. We demonstrate the capabilities of the coupled simulator by showing its application to a complex reservoir-simulation model. The fra er are expected to also apply to (part of) EOR operations (e.g. polymer flooding). 1. Introduction Water injection will generally result in rapi stand-alone well or reservoir simulations. For gas coning it is shown that the coupled simulator has much faster pressure transients after ga e most likely to cause the production instabilities observed in the field are identified. In production optimization the current status is to use s

the challenge of constructing (interpolating) realistic simulation models from an ED output. Although ED is consistent with statistical princip nty range in end point relative permeabilites of Water-Oil curves mobility ratio and to calculate the expected production profile and ultimate ondensate reservoirs and was found to give accurate results. Introduction The prediction of well deliverability in gas-condensate reservoirs

ctured coarse grids from fine geological models are illustrated using a highly heterogeneous test case. Flexibility of algorithm to gridding ind ddings and investigate their performances in greater details. While FB gridding uses fluid velocity as grid blocks density indicator VB griddin ate the method we run two-phase simulation using different 2D test cases. Our results indicate that the non-uniform DMM is more accurate

and helped us to initialize the reservoir correctly. Along with the analysis of the particular case to be discussed here the reasons behind the el; (3) fracture permeability modeling integrating fracture density matrix permeability and well-test permeability; and (4) numerical flow simu s. Significant improvement was obtained compared to the previous model in simulating water production that comes from the aquifer to the bility approach. The paper is organized as follows. First we briefly review the shape factors presented in the literature. We then derive the

olved as new related technologies evolved. Technological advances in the area of 4D seismic have enhanced the understanding of undergr

es or not providing them at all could seriously affect the reputation. Introduction Throughout the petroleum industry forecasting is a key bu updates. In particular streamline-based analytic sensitivities are easy to compute require very little extra computational effort and can be ob mits testing in making consistent estimates of average reservoir pressure from permanent downhole gauges and in characterizing complex are discussed in this paper. Introduction As a reservoir engineer first contact with reservoir simulation especially with large dynamic mode ational succession from basal offshore-transition zone heterolithics to amalgamated low angle cross-stratified sandstones of the lower shore

. The final ratio of pre- to post-scaleup grid sizes was 6:1 for SL and 21:1 for FD simulation. Several checks were made to verify the accura UK’s current natural gas field portfolio is considered along with specific examples of fields that may make attractive propositions for conv ss. Although the form of the proposed model is here limited to exponential oil rate decline the principles can easily be extended to other oi simulated including a steam-water case with vaporization and condensation. The general conclusion from this work is that the new model is s often used for clastic reservoirs (e.g. Leverett J-function) may not be applicable to carbonate reservoirs without careful pore-type examin proved to be more complex than initially expected. It is argued that extensive data gathering in particular in the early field development is n-situ mixing is an important phenomenon affecting the transport of solutes in permeable media even at large scales. Dispersivity values inc

onomics of a miscible gasflood development. Therefore renewed focus on proper evaluation of the PVC from the latest emerging core data were validated by history matching pilot performance data. A fully integrated workflow of fracture characterization integrated reservoir physic water saturation are investigated. The experiments are interpreted numerically by detailed modelling of the observed production. The results ot occur. For reservoirs containing viscous oil the viscosity reduction effects are most important. When steam is injected in light oil reservo as capable of producing gas cannot be effectively accessed by injected water volumes. The converted water injectivity index combined w probability perturbation method which reduces the error between observed pressure data and simulation prediction. Different from tradition tdowns and by losing confined injectors early on in the process which lead to splitting big pads into smaller ones. Finally as long as the st In 1993 sour separator gas combined with sweet make-up gas was re-injected as a pressure maintenance project to keep the reservoir pre ork was the integration of the data analysis and the dynamic modeling work rather than looking at each data source individually. In combina asured rates with the calculated rates demonstrated that the rates could be predicted with a high accuracy provided the mechanical conditio by the application of that technology. The essential foundations for a Smart Field are:�People and Skills effective Data Management a ing how to do “it and how not to do “it. This paper will trace DOF historic developments from the author’s personal perspective her sustainable production rates are two major drivers that have led to openhole horizontal gravel packing (OHHGP) acceptance as a main on of new sulfur products such as sulfur cement (which is resistive to corrosive environments) enhanced asphalt (for hardwearing road app ¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½â€¢ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ Design tool (software) for final candidate selection fluid system selection and ubsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process starting from the reservoir u uality 3D seismic data that was acquired in 1997. For each of these fields it was desired to determine whether time-lapse signals will be de

culated using the saturation-initialized 3D static model.�� The methodology had been successfully applied in reviewing 14 highly matu

iven models to determine zonal inflow zonal interactions and flow across inflow control valves and to compute ICV settings for optimum re

ined to be 14� � 2 N-NE. The azimuth of the Phase II upper hydraulic fracture is determined to be 16� � 2 N-NE in the northern h

2000 at 208 000 B/D of oil and 217 MMscf/D of gas. The deepwater Mars field is a prime candidate for secondary recovery since the predic

repeating these measurements during the life of the well. Thus it could be thought of as “miniaturized 4D seismic and “permanent lo s. However even in developed reservoirs unexpected circumstances arise requiring immediate response and modifications to the preplan eas. The first area of study is how to measure the surface deformation. The three most common methods used to measure the surface def m reservoirs can be used for reservoir surveillance in particular to detect saturation changes in the near-well region (e.g. to detect water e n advanced production logging tool (APLT) utilizing multiple spinners and multiple probes and comparisons of the advantages and disadvan een to monitor the “sea water waterflood saturation fronts with carbon/oxygen logging and integrate this data into the reservoir models. es along the vertical diameter of the borehole cross-section. The direct measurements of the fluid velocity and holdup enhance the capabilit n is in the range of 500 to 1 100 billion barrels of recoverable oil using a cut-off of 15 gallons per ton (gpt) (Bartis 2005). The Piceance Bas

n in Shell Asia Pacific region has been elevated through this stimulation campaign. Lessons learnt and best practices established will be pa ransmissibility reservoirs of the Niger Delta as they will allow higher well productivity to be attained and their greater inflow area is also adva e long-term return concentration which is important for some wells where a higher inhibitor return concentration is needed. The laboratory s d to conventional surface-controlled production. However accelerated production did not always result in higher ultimate recovery compare

ained from the Advanced Cuttings Transport Facility of Tulsa University Drilling Research Project. The effects of polymer concentration bac pressure constraints. The use of fiber technique prevents sand falling down from perforations and ensures the ESS running smoothly. This t e is more effective at reducing the yield stress effects than a larger breaker amount delivered randomly in the slurry. Alternative breaker mat

l well gas fraction. Results show that the coupled simulations could be significantly more accurate in comparison to stand-alone well or rese lity injection velocity and wettability alteration were also studied. The results showed that emulsions carrying more viscous oils could resist control inflow from different reservoir sections and to assist with well cleanup. Interpretation of the DTS traces indicated inflow-performance

foam is always lower than by N2 foam. The possible mechanisms explaining the observed differences in foaming behavior of the two gases aining a surfactant. Core floods combined with CT scan imaging provide valuable specific information about the effect of heterogeneity for b uced.3 Modelling and laboratory studies are needed to improve the performance of foam in the field. In the last years several models were uid flow is questionable. Hence to assess the validity of the methods a field test was designed and executed. The results were compared w

oirs are less able to cope with disturbances. This leads to higher critical rates for those systems. This corresponds to data from field observa amage effects that potentially could occur when LEP’s are applied in the field. Calculated total pressure drops across the LEP hardwar erforating system performance and input assumptions.� If system performance is critical this may encourage laboratory tests under repre reservoir to provide enhanced inflow performance.� Another significant benefit was that perforation and stimulation would take place in a d using one gas reservoir as a lift gas source.� Expandable sand screens would be installed across the perforated intervals inside a cem usion method that combined several new technologies needed to effectively complete this reservoir. To date four wells have been comple ance the pressure response. The last test results averaged over 5 100 psi. Comprehensive before and after measurements and slot inspe echnologies. To date four wells have been completed with the new sand-exclusion method and well configuration chosen to address the A) of the facilities and wells which helped identify operational changes to further reduce the ‘as built’ low risk operation. This use of

ds. The Task Group comprised a cross-functional team of operators suppliers and academics which worked under the guidance and directi nomics. A stimulation campaign was executed in 2006 to utilize the systems selected in long open-hole horizontal carbonate gas wells. To m that during closure the fracture generally shrinks from adjacent geological layers. It is demonstrated that the analyses based on the storage

es dividing the reservoir into non-communicating layers. The presence of even two shales dividing a reservoir into three noncommunicating

t of the horizontal part of the well was drilled with conductive drilling fluid and the latter part with non-conductive drilling fluid. Lab measurem ors was quantified by analyzing the transient pressure response of the annulus. Neither could permanent leakoff of completion fluids explai e prospects including those in the Russian sector of the Barents Sea. This paper focuses in particular on Fluid Sampling Surface Well Tes rference Test (VIT). Pressure transient analysis of a mini-DST data however in such reservoirs is challenging due to the associated uncerta he test separator and eight hours to test the well. The manual well testing process is subject to error and uncertainty – the wrong well m

ge to a more sustainable ener s the bridge to a more sustainable energy system it is therefore a key solution for combating climate change - among a portfolio of solutions on (Orr 2004) of CO2 is one of the viable methods to stabilize the concentration of greenhouse gases in the atmosphere and to satisfy the K estration applications. The swelling" of coal by a penetrant is caused by an increase in the volume occupied by the coal as a result of the vi hat real-time permeability measurements were done under unconstrained conditions. Permeabilities were measured reducing the pore pres y oriented to the bedding plane in coal. The cleat system consists of the face cleats continuous throughout the reservoir and butt cleats w

n and geo-mechanics. In the laboratory conditions have been simulated to match pressure and temperature at depths of 800 to 1000 m. Un nhanced logging program was added for one well that record nuclear magnetic resonance and borehole resistivity images predominantly to and regulations are still evolving. Based on our own experience we suggest that an integrated technical evaluation is critical for the accura und regulatory and policy frameworks to encourage development of options for deep reductions in CO2 emissions. Introduction Concer uefied natural gas and power-generation customer-export schedules that may cycle within a day. PRODML V1.0 provides a means of trans of PRODML (reflecting the need for a clear understanding of business drivers for end-users and for developers) functionality (supporting a

on testing Geochemical and PVT data to predict fluid properties in unsampled wells. Understanding reservoir fluid properties ahead of the are then computed for optimizing oil and gas production subject to various well and overall production constraints. Data driven techniques e a deliberate disturbance to the production to determine the dynamic characteristics of a well.�The models do not require underlying phy idual well flow information is available all the time and tests are performed only when necessary to validate or update PU models. A more ad

s from ongoing field surveillance activities such as well tests and real time meter monitoring and dispatching a continuous flow of modeling volving and there are clearly more issues to resolve than with a conventional drill stem test. However by drawing on our increasing breadth promising. Our experiences with OVT over the past several years suggest that the wireline formation tester solution is the best answer in a

oo many wells). Developing the CW oil and gas accumulations as a gas field only (i.e. forgoing the oil) was never acceptable to the Brunei

oduction We consider the secondary recovery phase of a heterogeneous oil reservoir where water is injected into the reservoir for pressu to bottom line benefits of some $350�mln per year. Benefits vary with the character of the asset or type of project. In selected deepwate average the following estimates are used: 8% Ultimate recovery increase (5% gas and 10% oil); 10% Increased production; Reduced d entially bad cement job saving a cement repair job or more likely a sidetrack. In another well the flexibility of the design enabled the effecti

This performance allowed the Well Construction team to achieve the Shell Global EP Rig of the Fleet award twice in 3 years. Introductio ith down-hole isolation systems and proposes replacing current intrusive and high maintenance BHA equipment with low-cost rotary steerab pressure profile accordingly. In a sense managed pressure drilling covers all drilling since management of pressure is the goal of all drillin en oxygen breakthrough at producers occurs.� Combustion can be included in a limited fashion in simulations at the expense of extra c perspective on the generally complex problem of polymer flooding in unconsolidated formations containing viscous oil. The work also offers recovery (EOR) the mobilisation of residual oil saturation is achieved through surfactants that generate a sufficiently (ultra) low crude oil/wa increasing oil mobility and therefore improving the GOGD rates. Miscibility further adds the advantages of single-phase flow at high effectiv at-Bowen Basin were identified as the most prospective. The simulation study conducted for ‘Reservoir A’ in the Cooper Basin indica nd generally have low permeability (1 to 10 md). Probably related to their position in the salt some of the reservoirs are at hydrostatic press mulation operations [2]. In these near-wellbore applications foam is particularly attractive because it is inherently non-damaging and low cost se study confirmed the capability of the described workflow to model gas injection EOR for the heterogeneous sandstone reservoir. Potentia

eration will minimise CO2 emission and reduce gas import.� The project will be under construction from 2007 with full rate steam injectio

bilization by adding low concentration polymer to the optimised slug; (3) If future EOR projects are planned a Designer Waterflooding pre-f mpletions to shut off the undesirable gas flow successfully. The horizontal wells identified with poor zonal isolation behind the liner were treat 4 m of perforations (gross) was squeezed off with the gel/cement in a single attempt. After reperforation of the top and the middle zone the 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 e. The limited and controlled leakoff into the matrix during the PG system squeeze results in a controlled depth of invasion. Selective perfora aboratory results to reservoir size. The present study aims to demonstrate that imbibition after wettability modification is diffusion-limited. To velopment modelling approach is often used in energy master planning studies where the focus is on the commercial value of oil & gas and mization problems and the multiple optima it implies are well acknowledged in the oil and gas industry2. Buitrago et al3 reported a successf oduction and are now entering into a difficult period of late life field production. At the same time many new field developments with signific 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 mpositions only negligible changes in VIT miscibility pressures from 6142 to 6216 psig (1.2% maximum difference) were observed thereby ed Gas viscosity of this equation with experimental PVT viscosity gave an average absolute error of 2.74% maximum absolute error of 4.5%

he formation tester string which could lead to scavenging. These parts were then redesigned and manufactured with the upgraded metals. phase of natural reservoirs which are continuous through significant ranges in elevation. Therefore the requirements for compositional grad describe the development of an in-situ GOR measurement technique which uses the optical properties of methane and oil components in c ange of 200-1100 Daltons containing various functionalities including nitrogen- sulfur- and oxygen-heterocycles. It was possible to see clea at least in three different flow rates at the testing conditions. In addition to live-oil emulsion studies the stability and droplet size distribution akly water-wet behavior of live oil to strongly oil-wet (165�). It was also able to alter the strong oil-wet behavior of stock tank oil to less oil

oduction for normally high risk low reward wells and remarkable stimulation cost reduction via reduced chemical volumes less equipment r

usually because they are not available. However the use of a diversion simulator will show that many of the guidelines and intuitive ideas

of UBD in these cases. Damage can be modeled as an equivalent skin based on the saturation and permeability profiles within the zone of H change predicted at equilibrium in the oil/naphthenic acid/brine system. We also applied the model to examine the sensitivities of the vari

hanges in produced water and thus predict injection water breakthrough earlier and with higher accuracy. PCA was used in one case to pro aluation of steam injection and hydrocarbon production without significant loss of accuracy. Preliminary simulation results to illustrate the flo

iently in the simulator. Simulations were run in dual porosity dual permeability thermal mode in Shell's dynamic simulator (MoReS). The res horizontal permeability ratios and relative permeability hysteresis were used for both pads. Each pad area maintained its own unique geolo d for water control during HF treatment. However no particular diversion method had shown consistent results in the Niger Delta reservoir w ervoirs typically requires a dual-permeability formulation (DP). In such DP models the matrix-fracture interaction is modelled via shape-fact e River is a 100% Shell Canada-owned heavy oil property located in Northern Alberta as shown in Figure 1. The Shell Canada’s Peace ium fluid grading behavior of the fluids tested. First equipment was calibrated using synthetic fluid systems as shown in Ratulowski et al.1 T le conditions. A series of tests with agreed procedures were carried out to compare perforation performance in actual core compared to tha d for stimulation of this high temperature formation was confirmed through increased formation permeability and high levels of dissolved mi ¿½ Well selection to promote valid offset comparisons -��� Data handling techniques to minimize bias -��� Production log

f data to another in a given field.�We will quantify the significance of this and present statistical evaluations documenting the probability ns with case study results. Introduction Productive intervals in the field are stacked-lenticular tight sands with porosity ranging from 6 to 12% s for the two wells per quarter quarter section application for the center of the field which was approved by the Wyoming Oil and Gas Conse contributions are derived from this work: Validation and extension of the correlations proposed by Jones-Owens and Sampath-Keighin for ow impairment has historically delivered inconclusive inflow data resulting in higher project uncertainty and higher costs. UBD reservoir ch The drilling outcomes have broken records on horizontal reservoir section length for onshore development in China and for the highest singl g. This proved successful in tight gas fields in the UK sector of the Southern North Sea where the (sub)horizontal drainholes connected prod

am decisions throughout the life cycle. In the second programme we have developed a company-wide methodology that brings Smart Field

roblem starting with the less expensive surface network clean-up drew a decision matrix. Dismantling and inspection of the flowline connec mbined in literally millions of ways sizes and locations at different times. Both to simplify this process and because physical design focuse risk mitigation plan and allows for playback and critique of decisions in the context of an evolving shared earth framework. Rework is mini taking into account the effect of reservoir wettability and its impact on petrophysical interpretations. The effects of relative permeability and The strengths and limitations of the technique for an improved understanding of reservoir architecture and fluid complexities are presented r fluid with greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time thus ext

simplified modeling method agree well with observed recovery factor distributions of turbidite channel reservoirs with significant production h nd inversion of borehole sonic data. The results of the two techniques are consistent providing encouragement for further validation of the m

neer to distinguish them from “fissures that are open only during injection and are not a production mechanism. Introduction Motivation vugs dominates flow and tracer concentration breakthrough profile. Tracer transport showed immediate breakthrough times and a long tail i predictions are within a factor of three in over 90% of the cases. The method requires minimal data manipulation and computation when co characterization are discussed. In particular the importance of filtering de-noising and identifying and excluding operationally induced tran ures and fault related fracture corridors. The subject of this paper is characterization and mapping of fracture corridors which are sub-vertic ch as water cut gross rates and injection rates. Threshold values are defined for these variables such that the probability of having a fractur f unambiguous cases for which multiple data streams might be viewed as being somewhat redundant. More-ambiguous cases in which the erm production profiles. Characterization of reservoir architecture and the fluids therein is the biggest challenge in achieving this goal. In add etectors have increased the sensitivity reliability and accuracy of mud gas fingerprinting. Thus during the drilling of a given well mud gas f analysis data calibration. Based on the new results the field’s relative permeability characteristics are divided into two categories linked MR-based method has been verified extensively on core data against standard wettability tests. Application to NMR logs is in progress. Intro

water depth of 17.4 m (Fig. i). The well targeted three objective intervals (Fig. ii): - the highly overpressured (>18kPa/m) Deep B sands be uration net-to-gross) and dynamic (permeability) parameters Multiple realisation 3D modelling using stochastic simulation guided by techn hat the predominantly H2S contaminated fields can be found in the northern Americas (Canada) the Middle East (Abu Dhabi Kuwait Oma

with actual oil rim performance. The result of this work is therefore useful for quick screening of oil rims for technical and economic feasibilit strategy converting a producer to an injector repositioning a development well and drilling an appraisal well. Introduction The Draugen fie al technical aspects of West Salym development such as well pattern and reservoir stress alignment application of highly deviated wells as

erstanding of subsurface application of integrated production modelling intervention readiness and effective well integrity management. Th

uncertainties in the project and a tailor made surveillance plan that aims at rapidly reducing these. Introduction The Gannet A field (equity

regular acidizations are required to keep up well injectivity (in spite of the high water quality) whereas in the latter case injectivity remains 15 P50 and P85 forecasts for each area. Experimental Design and Monte Carlo simulations were applied to further reduce the runs require en did karstification occur what is its morphology and most importantly what is its impact on ultimate recovery? Dynamic history matching the environmental footprint. The field will also be developed with the latest in Smart Field technology for well and reservoir management us n strategies. The control strategies were applied to each realization from which the average NPVs the standard deviation the cumulative-d oil quality (7-400cP) and low to medium fault density. To date only a small percentage of the STOIIP has been recovered. This marks theï¿ ation of an early “production/drilling appraisal campaign also known as the “parallel engineering philosophy where production runs me). o Completion design considerations (cleanout perforating sand control selectivity “smartness other). o Material selection. One psi above the bubble point pressure resulting in daily production rate of about 13000 bopd with water injection rate of about 15000 bpd . Th Gas transport capacities between the regions were modeled using total export capacity of gas exporting regions. In the low and mid case sc led operational procedures and other systems required by the permanent organisation that will run the operational plant are also progressin osure windows ��������-����Leak-off dynamics at high dP cannot be extrapolated from experiments at low competing needs for fresh water resources from aquifers ground water rivers and lakes for domestic agricultural and industrial use as we ield development planning to surveillance and optimization.� This paper will provide the following examples: automatic control of produ and so that very little scope is left for water encroachment even after prolonged production. Open hole logs were studied for locating barrie

egy with mitigation was adopted. Several operators had verified that nitrate injection is an effective mitigation technique to control H2S deve aper presents the experience gained with the nitrate injection during the first period of the Bonga waterflood. Issues like logistics and how to r souring. However as mentioned above the corrosion rates increased logarithmically when nitrate was used. At the same time a few ppm e for mitigating corrosion. Several factors are considered important; inhibitor availability (residual); pigging frequency effective corrosion mo Y field and monitor the produce solid. Overall its improved business performance HSE awareness saving the plant upgrade cost and fina a significant associated deferred oil cost. A scale inhibitor squeeze design in which a mutual solvent is deployed in the preflush should acco applications. The adjoint method in our implementation operates in local search mode. Our algorithm is applied to two different geologicall 0 reservoirs as shown on Figure 1. All the reservoirs are deep intra-salt carbonate reservoirs. Three reservoirs are hydrostatically pressured d say that the predominantly H2S contaminated fields can be found in the northern Americas (Canada) the Middle East (Abu Dhabi Kuwa of how surveillance is supporting reservoir management and production optimisation in the field. Introduction The Draugen Field is located of spinners and holdup probes was conveyed with tractor in a horizontal well. Besides conveyance in this horizontal well the challenge invo m recovery is a function of how fast the oil rim migrates into the gascap itself mainly driven by gas offtake rate reservoir permeability and aq

plicated. As a matter of fact it was demonstrated that the resolution achievable by static reservoir modelling was not sufficient to predict the d interesting non-trivial solutions to some optimal waterflood design problems that would not easily have been found otherwise. In this pa lities are good in the oil column generally deteriorating down flank into an aquifer which has a weak direct influx into the main reservoir se n integrated and fully consistent structural and stratigraphic hierarchical framework in the lateral and vertical domain; update the view of th e wells such as pressure gas oil ratio (GOR) and water oil ratio (WOR) provide useful information for reservoir characterization in tradition e waterflooding examples. Introduction Determining the location of wells is a crucial decision during a field-development plan because it ca f the history match the character of the water cut development was dependant upon the relative permeability curve used. It has been well d is calibrated to production data. Accuracy and convergence of history match as well as the uncertainty of dynamic predictions yielded by th nty ranges for the history-matching parameters and (d) a quantitative measure of reliability for different measurement types. The outcome o aracterize the convection of the fluid. 1 Introduction For several decades packer fluids have been available with varying degrees of insulatio x reservoir-simulation model. The fracture modeling is used to history match an injectivity test in a five-spot injection pattern using produced r injection will generally result in rapid injectivity decline unless it takes place under induced fracturing conditions (e.g. 1 2). Important risks a ch faster pressure transients after gas breakthrough than the dynamic reservoir simulator. Therefore the coupled well-reservoir simulator sh mization the current status is to use separate dynamic well and reservoir models. In case of significant reservoir-well interaction this approac

D is consistent with statistical principles its description of reservoir physics is not satisfactory. In its present form reservoir complexities are cted production profile and ultimate oil recovery.� Combined with the available SCAL data and a good understanding of past flood perfor rability in gas-condensate reservoirs is a complex problem. Once the pressure falls below the dewpoint a condensate bank builds up near

Flexibility of algorithm to gridding indicator is demonstrated using vorticity permeability variation and velocity. Quality of the coarse grids is e d blocks density indicator VB gridding combines velocity and permeability variation in gridding according to its definition and takes advantag non-uniform DMM is more accurate than the uniform DMM due to using vorticity-based grids. The speed-up achieved in the computation is

ussed here the reasons behind the graded oil/gas reservoirs will also be discussed and will be provided to highlight the broader implication eability; and (4) numerical flow simulation and history matching. All of these implementations are incorporated into a single forward modelin n that comes from the aquifer to the wells through a complex fracture network. The results were achieved through various sensitivity analyse n the literature. We then derive the general expression for the (single-phase) matrix-fracture shape factor. Subsequently we analytically de

anced the understanding of underground water movement and the distribution of depletion patterns. And while fault density position exten

eum industry forecasting is a key business process. If the uncertainties are not well understood this could have severe consequences. The a computational effort and can be obtained using either a finite difference or streamline-based flow simulator. We show that the effect of th auges and in characterizing complex reservoirs. Introduction Several different methods of interpreting pressure-buildup data to obtain aver especially with large dynamic models reveals that knowing the underlying fluid flow equations does not necessarily translate to an understa atified sandstones of the lower shoreface zone. Correctly considering stacking patterns and degree of vertical connectivity between sands is

ecks were made to verify the accuracy of scaleup. These include comparison of pre- and post-scaleup fractional-flow curves in terms of bre make attractive propositions for conversion over the next 5-15 years. The technical and economic criteria that will play a key role in these de s can easily be extended to other oil production decline trends. Introduction Besides the traditional focus of applying water cut data for res om this work is that the new model is capable of simulating a wide variety of complex coupled reservoir-wellbore phenomena. Introduction rs without careful pore-type examination and core analysis/calibration. A novel procedure is described to derive imbibition capillary pressur ar in the early field development is essential in helping to timely identify and properly define such complexities. Introduction The Abu Ghara large scales. Dispersivity values increase with scale mainly because of the increase in the correlation in the permeability field but they coul

C from the latest emerging core data from appraisal wells in a this reservoir has indicated that although the originally assumed PVC was wit erization integrated reservoir physics and static and dynamic modeling has enabled uncertainties and risks involved in developing the Qar he observed production. The results show that connate water has a big impact on the gas drive and distillation process and as a conseque steam is injected in light oil reservoirs solution gas drive and stripping effects potentially become dominant. In this paper we analyse the e d water injectivity index combined with other nonlinear repressurisation relative permeability and water viscosity effects were combined w n prediction. Different from traditional methods the objective of this step is to mitigate connectivity uncertainty by integrating production dat aller ones. Finally as long as the steam chamber can grow the ultimate recovery of a SAGD operation can be expected to be in the order nce project to keep the reservoir pressure from dropping further.� Upon expansion of the production station to take production from othe data source individually. In combination a consistent explanation of the observed reservoir behavior was achieved. This has resulted in chan cy provided the mechanical condition of the tubulars is properly taken into account. Default assumptions for the hydraulic roughness of the Skills effective Data Management and Industry Wide Standards appropriate Hardware and Systems Architecture.�High quality data is a e author’s personal perspective and tease-out the issues then and now providing an insight into where we have been where we are no ng (OHHGP) acceptance as a mainstay deepwater-completion method. Interval lengths in excess of 2 500 ft are now fairly common. In Jan d asphalt (for hardwearing road applications) and sulfur fertilizer (with 15% greater yields). Indeed the application of new sulfur technology selection fluid system selection and job design. ��������•�������� QA/QC and compatibili process starting from the reservoir up to the topsides injection facilities. Reservoir-sweep efficiency and reservoir-pressure distribution logica whether time-lapse signals will be detectable and to ascertain the optimum time in which to carry out a time-lapse monitor survey. The histor

y applied in reviewing 14 highly matured water-drive oil reservoirs with small to large initial gas caps. The emphasis of this paper is to descr

compute ICV settings for optimum reservoir management.�� FieldWare Production Universe (FW PU) is a software application develo

16� � 2 N-NE in the northern half of the pilot and estimated to increase to 21� � 2 in the southern half of the pilot. The azimuth o

secondary recovery since the predicted primary recovery has limited aquifer support. Monitoring the waterflood with casedhole logs is critic

ed 4D seismic and “permanent log in an individual wellbore. In the meantime repeated conventional wireline measurements can be perf nse and modifications to the preplanned job procedures. Unexpectedly low or high mobilities probe plugging unanticipated fluid types the p ds used to measure the surface deformation are optical-instrument leveling surveys or global positioning system (GPS) surveys (Brink et a r-well region (e.g. to detect water encroachment toward a gas well). The literature seems sparse in this area. Also our approach of simplifi ons of the advantages and disadvantages of each technology as a standalone water entry recognition solution are offered. The results of th this data into the reservoir models. A second purpose has been to monitor strain as a result of reservoir compaction and to monitor the effe ty and holdup enhance the capability of the petrophysicist to determine an accurate downhole flow profile. Three sensor arrays consisting o pt) (Bartis 2005). The Piceance Basin in Colorado is the largest single deposit in the Green River formation accounting for two-thirds of the

best practices established will be passed to future campaigns. We would like share our belief that acidization is still a good means for stimu heir greater inflow area is also advantageous in solutions where scaling can occur like in water injection for pressure maintenance.� We ntration is needed. The laboratory squeeze simulations were compared to return data obtained from squeeze treatments performed on two in higher ultimate recovery compared to the conventional case. In such situations the benefits of either short-term production optimization

ffects of polymer concentration backpressure and wellbore trajectory on foam hydraulics were studied extensively using the simulator. Res es the ESS running smoothly. This technique enabled Brunei Shell Petroleum to cost effectively complete the highly deviated wells with stim n the slurry. Alternative breaker materials are explored and additional data are also presented to estimate the yield stress effect for fluid flow

mparison to stand-alone well or reservoir simulations. In current operations ICVs are mostly used to completely shut down well segments th rrying more viscous oils could resist higher pressures due to the combined effects of capillarity and viscosity. Also conditioning the medium traces indicated inflow-performance problems in the long conventional producers whereas the smart wells were observed to be flowing ov

n foaming behavior of the two gases are discussed in detail. 1. INTRODUCTION Foam in porous media is a gas-liquid mixture with a contin bout the effect of heterogeneity for better design of acid diversion operations. 1. Introduction Foam is a highly efficient acid diversion agent the last years several models were developed to describe the development of foam in porous media. Rossen et al.4 5 advocated the foams cuted. The results were compared with various approaches to describe wet gas flow in an annulus. This allowed selection of the best appro

rresponds to data from field observations. A maximum in the critical velocity is observed around an inclination of 50� with a critical rate 40 sure drops across the LEP hardware have shown that the liquid flow is limited by the ability of the reservoir to deliver the necessary amoun courage laboratory tests under representative conditions to verify penetration and inflow. Developing the tool highlighted fundamental short nd stimulation would take place in a single operation thereby reducing the HS&E risk associated with handling acid while saving rig time. T the perforated intervals inside a cemented 9-5/8-in. casing.� With a skin of less than +1 on all completed intervals the productivity of bo o date four wells have been completed with the new well configuration and sand-exclusion method chosen to address the completion needs after measurements and slot inspections were done; the data were used in Finite Element Analysis to finalize the detailed screen design. N configuration chosen to address the completion needs. These have been tested and to date have proved to be operating satisfactorily. This ’ low risk operation. This use of sand quantification for completion design and for QRA of facilities forms a new capability and an extens

orked under the guidance and direction of an ISO Committee. The focus was to develop simple yet accurate methods which could be readi horizontal carbonate gas wells. To maximize the results the following have been practiced: Clean up and test the wells after completion t t the analyses based on the storage and linear flow regimes can be integrated into one analysis in order to reduce error bounds. The meth

ervoir into three noncommunicating layers can decrease the expected productivity of a high angle well by as much as 50%. Next a method

nductive drilling fluid. Lab measurements for the two mud filtrates were performed to understand the influence of the two different drilling flu nt leakoff of completion fluids explain the discrepancy between theory and test. Leakoff of the annular fluids which was seen to dominate p on Fluid Sampling Surface Well Testing and Subsea equipment. As several service companies were involved on this particular job we have nging due to the associated uncertainties such as layer flow compartments and flowing fluid viscosity. This paper discusses the use of integ and uncertainty – the wrong well may be put on test the wrong instrumentation may be used the instrumentation range may be incorrec

ange - among a portfolio of solutions including renewable energies energy efficiency and biofuels In order to achieve deeper reductions in the atmosphere and to satisfy the Kyoto protocol. The main storage options are depleted oil and gas reservoirs (Shtepani 2006; Pawar et a pied by the coal as a result of the viscoelastic relaxation of its highly crosslinked macromolecular structure. Although the macro molecular n e measured reducing the pore pressure from 16 to 1 MPa at constant flow rate. Although measured permeability increased with increasing hout the reservoir and butt cleats which are discontinuous and terminate against the face cleat.

ature at depths of 800 to 1000 m. Under those conditions the injected CO2 remains supercritical. Upto now the results show that dewatering e resistivity images predominantly to better characterize the storage formation. A core analysis program carried out on reservoir rock and cap al evaluation is critical for the accurate long-term fate assessment of CO2 geological storage sites. Motivation for CO2 Capture and Storage 2 emissions. Introduction Concern about global climate change and the challenges and risks it poses will require sustained efforts to de DML V1.0 provides a means of transferring data between applications incorporated in simple common use cases. However it did not addre velopers) functionality (supporting above all a focus on “usability – ensuring that PRODML expands while remaining accessible and q

servoir fluid properties ahead of the actual sampling operation enables smart decisions while drilling and logging which can save millions of onstraints. Data driven techniques for well characterization using commingled production data will be illustrated in three particular productio models do not require underlying physical or process models predetermined multiphase flow correlations compositional data or well/piping/ ate or update PU models. A more advanced version of PU PU-RTO also allows the use of the models for real time production optimisation.

ching a continuous flow of modeling planning and remediation tasks to keep pace with events. Introduction Late 2007 one of the Shell Ma y drawing on our increasing breadth of experience future value of information decisions about doing in-situ dynamic measurements will mo ster solution is the best answer in a large proportion of our cases. We will therefore focus in this paper on describing its strengths weakness

was never acceptable to the Brunei regulator or Brunei Shell. An FDP was started in 1998 but execution was terminated after major drilling

injected into the reservoir for pressure maintenance and sweep improvement. We consider a scenario with multiple injectors and multiple ype of project. In selected deepwater fields the value of a smart well can be a combination of better recovery and avoidance of re-entry cost % Increased production; Reduced development risk and uncertainty; Other important benefits include improved HSE. Ultimately Shell is lity of the design enabled the effective shutoff of water bearing zones that were drilled because of slight departures from the planned well tr

award twice in 3 years. Introduction The Champion West structure is 12 km long by 3 km wide with depths varying between 2 000 – 4 0 uipment with low-cost rotary steerable systems non-intrusive MWD systems and the development of non-return valves (NRVs) that are com ent of pressure is the goal of all drilling activities. However there is general industry agreement that Managed Pressure Drilling is an umbrel imulations at the expense of extra computational time and complexity.� In the available literature combustion is taken generally into acco ng viscous oil. The work also offers some insights into the critical issues that must be examined in such situations to avoid catastrophic failu a sufficiently (ultra) low crude oil/water interfacial tension (IFT) to give a capillary number large enough to overcome capillary forces and allo s of single-phase flow at high effective relative permeability and reduced interfacial tension thereby reducing re-imbibition effects and increa oir A’ in the Cooper Basin indicated the potential for spontaneous ignition and propagation of a stable combustion front within the reserv e reservoirs are at hydrostatic pressures whereas others are close to lithostatically pressured. Because of slight differences in charge histo herently non-damaging and low cost allowing easily recursive treatments in case of an unsuccessful operation [1-4]. The evaluation and im neous sandstone reservoir. Potential gas channeling in high permeability streaks and an improved displacement by gas was precisely mod

om 2007 with full rate steam injection reached by late 2009. The paper not only discusses how the project addresses the reservoir manage

ned a Designer Waterflooding pre-flush is recommended to obtain more favourable oil desaturation profiles and savings on polymer costs; isolation behind the liner were treated with an innovative gel gas-shutoff procedure. The merits of this procedure outweighed those of other of the top and the middle zone the well produced at a strongly reduced water cut (i.e. 25 to 33% compared with 60 to 62% before the trea arted early and some of the wells were shut-in due to lift problems associated with the water production. A sidetrack option was considered depth of invasion. Selective perforation of the oil zones re-establishes the desired hydrocarbon production from the targeted interval. The P y modification is diffusion-limited. To this end the recovery profiles for spontaneous capillary imbibition as well as for imbibition after wettab he commercial value of oil & gas and related value streams in the market while balancing the costs of production transport processing and Buitrago et al3 reported a successful implementation of a random search method with clustering. They reported a reduction of some 14% i new field developments with significant gas and oil reserves are currently under way in Russia in very remote locations on-shore West and 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 difference) were observed thereby establishing the compositional path independence of the VIT technique. The compositional analyses of 4% maximum absolute error of 4.5% and a standard deviation of 1.07%. Introduction The viscosity of natural Gas is an important parame

ufactured with the upgraded metals. This enhancement to wireline formation testers helps the technology to encompass a wider spectrum o requirements for compositional grading are that the reservoir is interconnected and that fluid properties such as gas/oil ratio (GOR) saturat of methane and oil components in crude oil. With this technique GOR can be measured downhole in real time when the sample is taken erocycles. It was possible to see clear differences between asphaltene field samples and solubility fractions. Further work should target the stability and droplet size distribution of STO emulsions were also determined. Experimental results indicated that the inversion point for the behavior of stock tank oil to less oil-wet (<135�). The nonionic surfactant was able to alter the water-wet live oil system to intermediate-w

chemical volumes less equipment requirements and shorter job times. Also included are a thorough analysis of actual candidate selection

of the guidelines and intuitive ideas are wrong or at least incomplete; this will be illustrated with example calculations. Introduction Optimu

rmeability profiles within the zone of invasion. Because the saturation and permeability effects are a function of location along the productiv examine the sensitivities of the various parameters on the final pH. The comparison between the model predictions and experiment at a hig

y. PCA was used in one case to prove that there was seawater breakthrough occurring in a well although the reservoir model did not suppo simulation results to illustrate the flow of a wet steam (i.e. two-phase fluid) through the choke are also discussed. Introduction In most hea

ynamic simulator (MoReS). The results are fully integrated model scenarios that can be compared quantitatively with all other PDO fracture ea maintained its own unique geological petrophysical and fluid properties in line with observed field trends. Excellent history matches (ai results in the Niger Delta reservoir with Darcy permeability. Additives selections were sometime generic and in many cases there was no sp teraction is modelled via shape-factors [1 2]. In a thermal setting the matrix-fracture interaction comprises both hydraulic interaction (mode re 1. The Shell Canada’s Peace River development covers an area of approximately 37 000 hectares. A total of 7 billion barrels of ~9 A 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 ance in actual core compared to that from industry recognized API RP19B Section 1 tests in cement. The paper will provide an assessmen bility and high levels of dissolved minerals. Introduction Typically the purpose of acidizing a carbonate formation is to remove near-wellbo ze bias -��� Production logging of wells – calibration and timing -��� Detailed comparison of production data normalize

uations documenting the probability of obtaining two similar data sets with respect to permeability when broad distributions exist. We then s with porosity ranging from 6 to 12% and permeability in the submicrodarcy to 20 microdarcy range with an average value of 4 microdarcie by the Wyoming Oil and Gas Conservation Commission. Similar data gathering activities have been initiated in other parts of the field to for es-Owens and Sampath-Keighin for low permeability samples. Development and validation of a new "microflow" model which correctly rep and higher costs. UBD reservoir characterization information may be used to reduce subsequent well flow testing activities which in turn l ent in China and for the highest single gas well productivity in the Ordos Basin. During this initial phase of development a number of lessons orizontal drainholes connected productive natural fracture networks. In the late 90’s underbalanced drilling (UBD) was introduced in fir

methodology that brings Smart Fields elements into project design planning. It identifies the most appropriate technologies to mitigate opera

nd inspection of the flowline connections to the variable choke housing revealed the source of the poor performance. Materials that were us and because physical design focuses on engineering the usual approach assumes that major parameters are known. Most obviously the d ed earth framework. Rework is minimized the efficiency and effectiveness of technical and business reviews are improved and best prac effects of relative permeability and imbibition capillary pressure curves on oil recovery in heterogeneous reservoirs with large transition zon nd fluid complexities are presented in two case studies. DFA DFA involves the in-situ measurement of optical absorption spectra of downh 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

servoirs with significant production history. Introduction Simplifying the reservoir modeling process by developing a quantitative method to r gement for further validation of the multifrequency inversion of cross-dipole dispersions to estimate horizontal stresses. Even though the ov

mechanism. Introduction Motivation for Identifying Natural Fractures. Identifying the presence of natural fractures is important for a broad r breakthrough times and a long tail in the tracer concentrations characterized by multiple plateaus in concentrations. Neither flow nor tracer nipulation and computation when compared to approaches that require three-dimensional imaging and/or full solution of the Navier-Stokes e excluding operationally induced transients is described. Limitations imposed by the data gathering methods are highlighted. It is shown that acture corridors which are sub-vertical tabular fracture swarms with several meters to tens of meters lateral extent intersecting entire reserv hat the probability of having a fracture corridor is more than 0.5 if the indicator is greater than the threshold value. Good indicators of fractu More-ambiguous cases in which the multiple data streams are required to make a robust assessment of key reservoir properties are also allenge in achieving this goal. In addition to 3D seismic imaging drill stem testing and extended well tests were traditionally the only availab he drilling of a given well mud gas fluid fingerprints or fluid facies can be correlated within a given well and mapped to subsurface structur re divided into two categories linked to rock types thus significantly reducing the uncertainty range. In this paper we will also highlight the pr ion to NMR logs is in progress. Introduction Importance of Wettability Determination. Wettability relates to the relative attraction of the rock

sured (>18kPa/m) Deep B sands below 3450m ss � - the normal pressured Intermediate A sequence (~2600 – 3400m ss) and - the s ochastic simulation guided by techniques borrowed from Experimental Design. In addition to technical challenges critical to unlocking the ddle East (Abu Dhabi Kuwait Oman Saudi Arabia Qatar) and the Caspian regions (Kazakhstan Russia). The indicated size exclude reso

for technical and economic feasibility to support key business decisions before embarking on costly detailed studies if eventually required well. Introduction The Draugen field is located 100 km offshore Norway. The field has excellent reservoir characteristics that have enabled pplication of highly deviated wells as an alternative to hydraulic fracturing and management of water injection under fracturing conditions. Th

ective well integrity management. The paper concludes on key learnings applicable to future deepwater waterflood projects. Introduction B

oduction The Gannet A field (equity owned 50% Shell U.K. Limited and 50% by Esso Exploration and Production UK Limited) is a mature o

in the latter case injectivity remains constant over years (in spite of the low water quality). However important risks associated with waterflo ied to further reduce the runs required for each phase. Although different optimum CSS designs were determined for each geological area covery? Dynamic history matching and synthetic seismic data provided a means to sense check assumptions for karst dimensions and ass well and reservoir management using tools such as Fieldware. Longer term 4-D seismic using whale friendly seismic will be implemente standard deviation the cumulative-distribution functions and the probability-density functions were determined. The RO results displayed a s been recovered. This marks the� cluster with high development potential for large-scale waterflood. The study was undertaken to supp philosophy where production runs parallel with the design of the permanent facilities thus improving the economic of the project. Introduc s other). o Material selection. One of the main conclusions is that fracture growth and containment is not a major issue in soft high-perme njection rate of about 15000 bpd . The estimated oil recovery is about 52 % and breakthrough is expected to occur about 7 years after the s regions. In the low and mid case scenarios shortfall of gas starts early for North America East Asia and Europe in the period 2015 (low ca operational plant are also progressing well. Upstream the project involves the offshore development of a North Field block to produce arou extrapolated from experiments at low dP ��������-����Filtercake permeability depends on the permeability agricultural and industrial use as well as for generating power is leading to serious overexploitation of this non-renewable resource. For exa amples: automatic control of producer wells to prevent coning and/or gas breakthrough automatic control of injection wells to control wate logs were studied for locating barriers for injection water. Additional perforations in the bypassed pays were planned taking a composite pic

gation technique to control H2S development. However to date the main application for nitrate had been the reduction of H2S in already-so ood. Issues like logistics and how to ensure nitrate is applied correctly are discussed in more detail. In addition laboratory testing executed used. At the same time a few ppm nitrite was seen in the nitrate treated PW water. The addition of biocide resulted in an instantaneous de ng frequency effective corrosion monitoring protocol and rigorous inspection program. Corrosion monitoring tools are located in high risk ar ing the plant upgrade cost and finally now days in November 2008 the H2S level from X Field become traces and the area is safe for full f eployed in the preflush should account for the following phenomena: mutual solvent propagation diminishing mutual solvent efficiency due s applied to two different geologically complex channelized turbidite reservoirs to identify alternative optimal locations for a new injector-prod ervoirs are hydrostatically pressured and seven are lithostatically pressured. These reservoirs are collectively called the Harweel Cluster be the Middle East (Abu Dhabi Kuwait Oman Saudi Arabia Qatar) and the Caspian regions (Kazakhstan Russia). The indicated size exclu uction The Draugen Field is located 100 km offshore mid-Norway.� The field has excellent reservoir characteristics that have enabled a his horizontal well the challenge involved detecting minor oil entries in a very high water cut scenario. Two examples relate to the effective u e rate reservoir permeability and aquifer strength. Placing the horizontal leg close to the GOC is advantageous to maximize the time that th

ling was not sufficient to predict the water-flood efficiency meaningfully. As a consequence a statistical infill campaign was launched with a ve been found otherwise. In this paper we also present a self-contained elementary derivation of the adjoint method which is different from rect influx into the main reservoir see Walsh et al. (1996). The St. Joseph field has been on production since 1981. Until 1996 the recovery rtical domain; update the view of the depositional setting taking into account variations in provenance and relative sea-level; define the pe reservoir characterization in traditional history matching the resolution of an estimate obtained from this type of data is typically poor. The o ield-development plan because it can affect a project’s NPV significantly. Well placement is often posed as a discrete optimization prob ability curve used. It has been well documented that different relative permeability curves are used to model fluid flow through porous medi of dynamic predictions yielded by the final model ensemble are used as criteria to evaluate the performance of SEIKF. The outcome of the measurement types. The outcome of the multi-realization history matching study reveals a better reservoir connectivity and an increased ne able with varying degrees of insulation against heat transfer. Usually this is done either to prevent heat loss from building large collapse pres pot injection pattern using produced water. The coupled-simulation results and the field-data interpretation show a very good match. The ou onditions (e.g. 1 2). Important risks associated with waterflooding under induced fracturing conditions are related to potential unfavorable are e coupled well-reservoir simulator should be used to simulate gas breakthrough and to optimize production using gas coning control. For sm eservoir-well interaction this approach gives a non-realistic production forecast. This project gives a clear indication that when using a coupl

sent form reservoir complexities are apparently too overwhelming for reliable modelling or optimisation by the proxy models. Consequently d understanding of past flood performance an ability to forecast future production was obtained.� The work presented forms the first pha a condensate bank builds up near the wellbore which reduces the relative permeability to gas. This may cause a significant decline in the

ocity. Quality of the coarse grids is evaluated by comparing their two-phase flow simulation results to those of fine grid and uniform coarse g g to its definition and takes advantages of both. Therefore although performance of FB and VB griddings are comparable in many cases � d-up achieved in the computation is significant depending on the complexity of model and degree of upscaling. Introduction Flow in porou

d to highlight the broader implications of field observations as well as some of the ideas presented in the literature. Introduction It has been orated into a single forward modeling process and iterated in the automatic history-matching scheme. To obtain a history match on a reserv ed through various sensitivity analyses of fracture conductivity and by fine-tuning relative permeability curves that are based on the eight roc or. Subsequently we analytically derive a new shape factor that captures the transient in pressure/temperature diffusion processes. To com

d while fault density position extent direction and transmissibility remain a large uncertainty in most GOM fields the application of state-of

uld have severe consequences. Therefore uncertainty identification and quantification is an important element of any forecast process. Furth ulator. We show that the effect of the covariance localization is to increase the effective ensemble size. But key to the success of the sensit pressure-buildup data to obtain average reservoir pressure have been proposed (Muskat 1937; Horner 1967; Miller et al. 1950; Matthews e necessarily translate to an understanding of the results of a dynamic simulation result. With simpler one or two dimensional models it may b ertical connectivity between sands is important to the success of a waterflood. tidally-dominated sediments comprising tidal channel fill or b

ractional-flow curves in terms of breakthrough time and post-breakthrough curve shape cross-sectional permeabilities global porosity histo a that will play a key role in these decisions are listed and discussed.� Comparison is made between the UK and other countries on a gl us of applying water cut data for reserves estimation reservoir surveillance and management the need to comply with increasingly stringen wellbore phenomena. Introduction Thermal recovery processes such as steam flooding steam assisted gravity drainage (SAGD) and dow to derive imbibition capillary pressure curves from the primary drainage Pc curves taking into account of wettability and fluid trapping. The re lexities. Introduction The Abu Gharadig basin in the Western Desert of Egypt (Fig 1) was generally considered to be a mature basin with ov n the permeability field but they could also apparently appear to do so because the Fickian model fails to capture the mixing zone growth co

the originally assumed PVC was within the uncertainty range it was at the high range of the data and some of the measured data was skew risks involved in developing the Qarn Alam field to be managed in a scenario based design approach. Introduction The Qarn Alam field is illation process and as a consequence enhances the oil recovery. Introduction The connected fracture network in densely fractured reserv nant. In this paper we analyse the effect of the different recovery mechanisms. We discuss the results of stack simulations for light oils and viscosity effects were combined with surface pump curve and wellbore head/friction calculations to construct a spreadsheet capable of pr rtainty by integrating production data instead of forcing history match. 4. Similar to step 2 another polynomial response surface between u can be expected to be in the order of 60 to 70%. The cOSR (cumulative Oil-Steam- Ratio) can fluctuate between 0.30 and 0.50 with the h station to take production from other nearby sour oil fields more sour gas was added to the gas injection stream in 2004.�� Plans are s achieved. This has resulted in changes in the day-to-day water injection management and is deemed to play a key role in longer-term dev s for the hydraulic roughness of the tubulars lead to over-estimates of the blowout rates and consequently worst case estimates for the env Architecture.�High quality data is a fundamental building block of Smart Fields and it needs to be treated as an asset managed effective ere we have been where we are now and what can be practically achieved. Definition of DOF for Oil/Gas Fields from Reservoir to Point-of 500 ft are now fairly common. In January 2003 the latest world-record horizontal gravel pack was completed with a length of 8 305 ft (2531 application of new sulfur technology has the potential to turn a global surplus of sulfur into valuable new products. With many hundreds of t ½ï¿½ï¿½ï¿½ QA/QC and compatibility tests aiming to obtain high success rate. Combine equipment (self-raising rig and barge) with pumpi reservoir-pressure distribution logically dictated injection-well designs and injection-pump sizing. Subsurface risks such as reservoir sourin me-lapse monitor survey. The history matched dynamic simulation models for each field were converted to acoustic properties through a su

e emphasis of this paper is to describe how it can be applied to locate bypassed oil. Although the field concerned had undergone 8 previous

PU) is a software application developed by Shell International Exploration & Production and Shell Global Solutions International with signif

thern half of the pilot. The azimuth of the lower hydraulic fracture averages 19� � 4. The hydraulic fractures are found to be symmetric

terflood with casedhole logs is critical to improving the performance and increasing the overall volume recovery of the Mars field. The ability

wireline measurements can be performed to assess the completion permeability. Motivation Completions lie at the heart of deepwater prod gging unanticipated fluid types the presence of multiple phases and excessive fluid contamination are but a few examples of such circums g system (GPS) surveys (Brink et al. 2002); interferometric synthetic aperture radar (InSAR) (Brink et al. 2002); and tiltmeter-based surface area. Also our approach of simplified coupling of geomechanics and fluid flow for small geomechanical effects and the possibility to imple olution are offered. The results of this research along with the inclusion of two Niger Delta case studies address the viability of a possible r compaction and to monitor the effects of the waterflood on the rate of strain. This data is used to help determine wellbore integrity and ultim le. Three sensor arrays consisting of six optical probes six electrical probes and five spinners are spread across the wellbore on retractable tion accounting for two-thirds of the Green River oil shale resource. In the heart of the Piceance Basin oil shale thickness exceeds 1000 ft a

ation is still a good means for stimulating well productivity but it has to be carried our properly. Introduction Stimulating of existing oil and g n for pressure maintenance.� Wells drilled and completed with a fully integrated study were profitable emphasing that planning drilling a queeze treatments performed on two wells located in a sandstone reservoir in Saudi Arabia. The sandstone formation contains significant am short-term production optimization (accelerating production) or long-term reservoir management (maximizing recovery) should be weighed

extensively using the simulator. Results show significant impact of polymer on foam hydraulics. When 0.5% volume to volume (v/v) HEC po te the highly deviated wells with stimulation and sand control. In presence of the fiber higher proppant concentrations up to 9 ppa could be 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

mpletely shut down well segments that experience gas coning. We show that by keeping these ICVs open in a controlled way the - otherwis osity. Also conditioning the medium with pre-flush solutions predictably affected the depth to which an emulsion may penetrate into a porou wells were observed to be flowing over at approximately their full length. Inadequate well cleanup was thought to be the primary cause of the

a is a gas-liquid mixture with a continuous liquid phase wetting the rock whereas a part or all of the gas is made discontinuous by thin liquid highly efficient acid diversion agent for matrix stimulation operations. It is inherently non-damaging and low cost allowing easily recursive tr ossen et al.4 5 advocated the foams fractional flow models and Patzek6-10 developed the population balance models. The bubble populati allowed selection of the best approach with an accuracy comparable to the accuracy of methods to predict pressure drop in tubing. Factor

nation of 50� with a critical rate 40% higher than for a vertical well. To solve this relations found from flooding experiments are used to m voir to deliver the necessary amount of fluid to the LEP. The simulation results show that for a steam injection flow rate of 42 m3/day per pe e tool highlighted fundamental shortcomings in the industry’s understanding of perforation such as: how the crushed zone is formed an andling acid while saving rig time. Two successful field trials totalling three wells will be presented in detail to illustrate this application for eted intervals the productivity of both wells has been excellent. The success has been attributed to the unique combination of ESS and hyd sen to address the completion needs.� These have been tested and to date have proven to be operating satisfactorily. This paper will re inalize the detailed screen design. No traditional mechanical burst of the screen occurred. Most influential factors were slot size/geometry a ed to be operating satisfactorily. This paper will review the evaluation that led to the revised sandface-completion design the field implemen orms a new capability and an extension to the existing use of sand prediction technologies. Introduction Hydrocarbon production comprising

urate methods which could be readily implemented in the laboratory or the field. This work resulted in the development of a new Standard I and test the wells after completion to get initial productivity. Bullheading acid to increase pumping rate. Use a mixing-on-the-fly unit in lim r to reduce error bounds. The method is applied to a number of examples in a waterflood offshore Sakhalin. Here start-up of injection wells

by as much as 50%. Next a methodology for interpreting high angle well tests is introduced that attempts to address the problems of non-un

uence of the two different drilling fluid types on the MR measurements. In the absence of oil based mud filtrate invasion the MR data show uids which was seen to dominate pressure development during a previous test in a well with a cement shortfall between casings does not volved on this particular job we have only included some general and limited content for the other services involved. Introduction The Ony his paper discusses the use of integrated reservoir information obtained from Downhole Fluid Analyzers (DFA) borehole images and nume trumentation range may be incorrect and instrumentation may be dysfunctional. After the well test is complete the final result may be goo

rder to achieve deeper reductions in CO2 emissions there will need to be new technologies brought to the market to enable a ‘Kyoto 2†eservoirs (Shtepani 2006; Pawar et al. 2004) deep (saline) aquifers (Kumar et al. 2005; Pruess et al. 2003; Pruess 2004) and unmineable c ure. Although the macro molecular network structure does not dissolve the penetrant is almost universally termed as "solvent". Thus a coal rmeability increased with increasing pore pressure under unconstrained swelling in-situ permeability will actually decrease because of frac

ow the results show that dewatering will be an essential step for successful ECBM combined with a CO2 sequestration process. Introducti carried out on reservoir rock and caprock included measurements of helium porosity nitrogen permeability and brine permeability. Carbon d vation for CO2 Capture and Storage It has been well established that as the global economy continues to grow energy demand will keep p s will require sustained efforts to develop understanding and effective solutions while at the same time meeting the growing needs of socie use cases. However it did not address the task of accommodating changes to the physical configuration of the network such as the additio ds while remaining accessible and quick to pick up for new developers) support and governance. Introduction Major energy companies em

d logging which can save millions of dollars in operational costs. The sampling process can be optimized in terms of where and when to sam ustrated in three particular production estimation scenarios: (1) individual well production with no shared well testing facility (2) production s compositional data or well/piping/equipment details.�This has made the models quick to set-up and easy to maintain. FieldWare PRO or real time production optimisation. To get from research to a fully implemented and sustainably used product is a lengthy and sometimes

ction Late 2007 one of the Shell Malaysia E&P assets was chosen as a pilot to implement "LEAN" methodology earlier implemented by Ae situ dynamic measurements will more often include this cheaper safer and more environmentally friendly option. Introduction The focus o n describing its strengths weaknesses and opportunities. Our applications of this technology are still evolving and there are clearly more i was terminated after major drilling problems were encountered. The last FDP is being executed in a phased approach. The current FDP

with multiple injectors and multiple producers of which the well rates can be controlled individually. Ideally the injected water will displace t overy and avoidance of re-entry costs. Smart Fields Concept The Smart Fields concepts grew out of the thinking that guided the developm improved HSE. Ultimately Shell is aiming for Smart Fields� to contribute to the bottom line benefits in the order of hundreds millions US departures from the planned well trajectory. Through modification of the planned segmentation an expensive re-drill was avoided. The sma

epths varying between 2 000 – 4 000 m. Reservoir pressures range from 200-600 bar with a temperature range of 80-120�C. It consis on-return valves (NRVs) that are compatible with through bore solutions to optimise data gathering while drilling. The paper postulates that e aged Pressure Drilling is an umbrella term that refers to drilling activities conducted in a closed loop system. Conventional overbalanced dr mbustion is taken generally into account under quite simplified conditions. This paper addresses the role that combustion plays on the incre situations to avoid catastrophic failures and highlights the existing technological gaps in the current predictive capabilities. Introduction So to overcome capillary forces and allow the oil to flow1. However reservoirs have different characteristics (crude oil type temperature and w ucing re-imbibition effects and increasing ultimate recovery from inhomogeneous reservoirs. To assess the benefit of these EOR methods s le combustion front within the reservoir; hence it is a potentially good candidate for EOR by air injection. Given the ‘high’ oil price an e of slight differences in charge history the fluid properties vary from a retrograde gas condensate to black oil with moderate GOR (185 m� eration [1-4]. The evaluation and implementation of foam processes rely on experiments modeling and numerical reservoir simulations. Th lacement by gas was precisely modeled by the workflow. Injection strategies such as WAG SWAG and gas injection have been screened

ect addresses the reservoir management challenges of this complex recovery mechanism but will address some of the engineering and ope

files and savings on polymer costs; (4) In case of seawater injection into reservoirs with formation water of low salinity level removal of mul procedure outweighed those of other proposed solutions: targeted placement a strong full-blocking gel to fill up channels behind the liner in ared with 60 to 62% before the treatment) and an increased oil production (i.e. 3 000 BOPD compared with 1 000 BOPD before the treatm . 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 tion from the targeted interval. The PG system can be easily washed out of the wellbore as compared to cement which must be drilled out as well as for imbibition after wettability modification are calculated. The results are then used to compare with the data of Amott cell imbibi oduction transport processing and storage. It provides a structured framework for analysis across the whole energy value chain in order to reported a reduction of some 14% in gas lift for the same amount of oil production i.e. a better utilization of gas lift. Gomez et al4 reported remote locations on-shore West and East Siberia offshore Arctic and in the Far East seas. Large hydrocarbon reserves have been discove 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 ique. The compositional analyses of gas and oil phases at different gas-oil ratios showed that the gas phase is predominantly CO2 while th f natural Gas is an important parameter that occurs in the equations for single and multiphase flow in Petroleum Reservoirs in equations fo

y to encompass a wider spectrum of functionalities. In this paper we will review the choice of materials the verification test procedures an such as gas/oil ratio (GOR) saturation pressure API Saturation/Aromatics ratio gas mole fraction etc. vary with elevation. The magnitude eal time when the sample is taken and without requiring phase separation. Downhole GOR has many advantages over the conventional G ons. Further work should target the correlation of this information with the precipitation of asphaltenes from problematic fluid samples. Intro cated that the inversion point for the STO emulsions was approximately 60% water cut (volume) and the average droplet size was increasin -wet live oil system to intermediate-wet (82�) while it did not affect the strongly oil-wet behavior of stock tank oil system. The oil-wet beh

nalysis of actual candidate selection criteria fluid chemistry actual job design and operational issues during execution of treatments. Key te

le calculations. Introduction Optimum fluid placement and complete zonal coverage is essential in a successful matrix-acid treatment. This

ction of location along the productive length and a function of time we obtain time-dependent and spatially dependent equivalent skin. The l predictions and experiment at a higher brine pH value is overall satisfactory. Background and Introduction The development of acidic som

gh the reservoir model did not support this and single ion analysis did not give a clear message. The subsequently undertaken scale dissolv discussed. Introduction In most heavy oil recovery scheme’s steam is injected into the reservoir to lower the viscosity of the oil thereb

ntitatively with all other PDO fractured Shuaiba fields facilitating management’s technical decision making on the EOR strategies for the rends. Excellent history matches (aided by experimental design) of injection and production volumes injection wellhead pressures estimate c and in many cases there was no specific focus to the common enemies of effective well production “fines migration. In 1996 the first H ses both hydraulic interaction (modelling the fluid exchange between matrix and fractures) as well as thermal interaction (modelling the ene es. A total of 7 billion barrels of ~9 API oil is trapped in a 30 m thick semi-consolidated sand layer buried at a depth of about 600 m. The por nsates (properties ranging from 27 API/1 000 scf/stb GOR to 57 API/27 000 scf/stb GOR). �Diagnostic plots based on bulk fluid propertie he paper will provide an assessment of the predictive capabilities of the software packages in light of these laboratory tests on Harweel core formation is to remove near-wellbore damage and to produce “wormholes to increase the permeability of the critical matrix. However b arison of production data normalized with six methods to determine whether consistent conclusions can be reached -��� Statistica

broad distributions exist. We then compare the size of the sample set necessary to quantify stimulation effectiveness using production alo h an average value of 4 microdarcies. Water saturations vary from 30 to 60% with comparably low water production. Condensate ratio with iated in other parts of the field to formulate a comprehensive field-wide spacing plan. Gauge configuration was designed to collect daily pr microflow" model which correctly represents gas flow in low permeability core samples. This model is also applied as a correlation for predic low testing activities which in turn lowers project costs speeds up the field appraisal process and reduces waste. Introduction A venture i of development a number of lessons have been learned on both technical (for example reservoir heterogeneity and borehole stability) and o d drilling (UBD) was introduced in first instance to avoid the frequent drilling problems associated with total losses into these natural fracture

priate technologies to mitigate operational risks and enables their application. The methodology referred to as Smart Fields Initial Screenin

performance. Materials that were used during the flowline laying/pigging (marine rope and hand gloves) were left in the flowline creating se ers are known. Most obviously the design process normally takes the price of oil as given; in fact senior management typically requires tha eviews are improved and best practices are captured for global re-use. The business model establishes a foundation for both Shell and S s reservoirs with large transition zones are assessed. It is shown that a proper description of relative permeability and capillary pressure cu optical absorption spectra of downhole fluids. These spectra are used for fluid identification (oil water and gas phase) and to quantify the l all basis. Field-based fluid characterization is now possible. In addition a new measurement is introduced--in-situ density of reservoir fluid.

eveloping a quantitative method to represent a range of fine-scale geologic heterogeneities within relatively simple full-field reservoir model zontal stresses. Even though the overburden stress is expected to increase with depth both the maximum (SH max) and minimum (Sh min

l fractures is important for a broad range of reasons. On a field scale realizing the presence of natural fractures can impact reserves estima ncentrations. Neither flow nor tracer transport can be explained at these scales by the standard continuum equations (Darcy’s law or 1D or full solution of the Navier-Stokes equations and is much more accurate than primitive empirical methods such as the Kozeny-Carman eq hods are highlighted. It is shown that the ability of RIPI to reduce noise in raw PI data allows trends to be read more easily. The use of RIPI eral extent intersecting entire reservoir (Figure 1). A remarkable aspect of fault related fractures is nested clustering. Fractures cluster within old value. Good indicators of fracture corridors include mud losses step flow profiles and water fingering in horizontal wells. High gross rat of key reservoir properties are also presented. Using Fluids To Understand Reservoir Architecture Identifying compartmentalization and th sts were traditionally the only available methods for detecting compartmentalization and flow boundaries. However in deepwater or similar s and mapped to subsurface structural features such as faults and seals or different hydrocarbon bearing intervals. By providing this during t is paper we will also highlight the procedure that was used to generate the new SCAL experimental dataset and the analysis that has been s to the relative attraction of the rock to either water or oil and thus has a strong impact on the dynamic properties of the rock. Wettability r

e (~2600 – 3400m ss) and - the shallow L80 reservoirs (~1650m ss). The reservoir architecture is made up of thin interbedded sandsto l challenges critical to unlocking these volumes is the economical optimisation of the cluster development within a consistent portfolio man sia). The indicated size exclude resources that could be accessed via H2S / CO2 Enhanced Oil Recovery (EOR). The application of the ne

ailed studies if eventually required subject to the complexity of the situation and decision required. Introduction Many gas reservoirs critic oir characteristics that have enabled a field development with a minimal number of appraisal and development wells given the areal size of ction under fracturing conditions. The petroleum resources maturation section describes how the reservoir management activities result in t

waterflood projects. Introduction Bonga Main located in OML118 offshore Nigeria (Figure 1) is the first major deepwater field1 operated b

Production UK Limited) is a mature oil and gas field in the central North Sea. Approximately 200mmstb of oil-in-place was contained in a 50f

portant risks associated with waterflooding under induced fracturing conditions are related to potential unfavorable areal and vertical sweep. determined for each geological area the modeling results can be generalized as follows: Horizontal well near the base of the reservoir is t mptions for karst dimensions and associated reservoir properties. As a result this detailed study work has not only reduced the uncertainty in friendly seismic will be implemented to identify infill drilling locations. For the future in this sub-Arctic environment the opportunities includ rmined. The RO results displayed a much smaller variance than the alternatives indicating an increased robustness to geological uncertain . The study was undertaken to support further development decisions to identify the value of remaining reserves including growth and SFR e economic of the project. Introduction The southern swamp asset is made up of four producing catchments areas with four flow stations. ot a major issue in soft high-permeable formations. The main challenge is in drilling the—in some cases—demanding well trajectories an ed to occur about 7 years after the start of waterflood. The results were not only a total reversion but also an increasing production profile th d Europe in the period 2015 (low case) to 2035 (mid case) and is caused by the low indigenous gas resources and by insufficient imports. a North Field block to produce around 1.6bn cubic feet a day of gas. The offshore scope includes 22 development wells two unmanned we eability depends on the permeability of the flooded core ��������-����Membrane tests (Barkman-Davidso his non-renewable resource. For example in the United States current electricity production from fossil fuels and nuclear energy requires 3 ntrol of injection wells to control water flooding and prevent fracturing capacity and surge controls for compressor networks control applica were planned taking a composite picture of all facets of data available. The result is the sustenance of incremental production till date. This

n the reduction of H2S in already-sour fields and the experience for the use of nitrate from the start of the water-injection scheme was limit addition laboratory testing executed to define an appropriate nitrate injection rate under Bonga conditions are also presented. After several cide resulted in an instantaneous decrease in nitrite and corrosion rates to background levels. The result clearly indicates that bacterial activ oring tools are located in high risk areas (low flow regimes) . These locations are determined by appropriate flow modelling programs. traces and the area is safe for full field development. Introduction In the X field Sultanate of Oman water has been injected since June 20 ishing mutual solvent efficiency due to interaction with the fluid phases impact of the mutual solvent on scale inhibitor retention due to incre mal locations for a new injector-producer pair given existing operational and well constraints. Ensuing results demonstrate that the adjoint-b ctively called the Harweel Cluster because they form a cluster of reservoirs near the first reservoir to be discovered (in 1997). The reservoirs an Russia). The indicated size exclude resources that could be accessed via H2S / CO2 Enhanced Oil Recovery (EOR). The application of characteristics that have enabled a field development with a minimal number of appraisal and development wells given the areal size of the wo examples relate to the effective use of pulsed neutron spectroscopy measurements reservoirs. Finally one of the examples involves oxyg tageous to maximize the time that the oil section of the well is exposed to the oil rim. Given the time dependency a relatively large tubing s

nfill campaign was launched with a focus to infill the existing major gaps between the MUF wells and secondly to establish a line drive wate djoint method which is different from but equivalent to the well-known derivation based on the Lagrange formalism. Introduction We focus since 1981. Until 1996 the recovery mechanism was natural depletion under gravity drainage. At the end of 1995 the field had produced 1 and relative sea-level; define the petrophysical parameters for the rock property model which underpins the inversion. The results of the m s type of data is typically poor. The only way to improve the resolution in such cases is to integrate additional data that can provide more con osed as a discrete optimization problem (Yeten 2003) (i.e. involving integers as decision variables). Solving such problems is an arduous ta odel fluid flow through porous media as opposed to fracture and fracture-matrix flow This ARM provides a unique opportunity to test the ap ance of SEIKF. The outcome of the proof-of-concept studies quantitatively demonstrates that SEIKF exhibits rapid convergence in the doma oir connectivity and an increased net-sand volume compared to the maximum a-posteriori (MAP) prediction attained by a commercial assist oss from building large collapse pressures in drilling fluids trapped between casing strings; to prevent cooling of shut-in production fluids con on show a very good match. The outcome of the injection test led to an appropriate waterflood-management strategy adapted to the specifi e related to potential unfavorable areal and vertical sweep. These risks can be managed if one has a proper understanding of dynamic indu ion using gas coning control. For small time scale phenomena order of less then one day the well and reservoir transients overlap. Simula r indication that when using a coupled simulation on a real field case a better understanding of the instabilities and therefore a more accur

by the proxy models. Consequently it is recommended that the application of ED be limited to situations where a simple understanding of th e work presented forms the first phase in the assessment of the value in expanding water flooding throughout the Field.�� In essence ay cause a significant decline in the well productivity and dominate the pressure- and production-rate behavior. The difficulty arises in captu

ose of fine grid and uniform coarse grid. Results demonstrate the robustness and attractiveness of approach as well as relative quality/perf s are comparable in many cases �VB has benefit of producing coarse grid blocks with more uniform permeability and fluid properties dis scaling. Introduction Flow in porous media such as flow occurring in aquifers and hydrocarbon reservoirs is strongly influenced by propert

e literature. Introduction It has been realized that compositional PVT variations between fluids do not necessitate achieving thermodynamic o obtain a history match on a reservoir model we jointly perturb the large-scale fracture trend and local-scale geostatistical fluctuations of fr rves that are based on the eight rock types defined for the reservoir. In conclusion the single-media model used in this study can successf erature diffusion processes. To compare and contrast the impact of the various shape factors we consider three cases of increasing compl

OM fields the application of state-of-the-art seismic processing and simulation technologies is believed to be a major contributor towards th

ement of any forecast process. Furthermore forecasting can only be properly done when it is an integrated effort of all disciplines. An Integr But key to the success of the sensitivity-based covariance-localization is its close link to the underlying physics of flow compared to a simpl 1967; Miller et al. 1950; Matthews et al. 1954; Dietz 1965) in the past and in recent years some new techniques have appeared in the litera e or two dimensional models it may be easy but when working with a full field 3D simulation model some experience help the understanding ents comprising tidal channel fill or bar complexes set in a background of mud to sand-dominated tidal flat facies have been recognised. Fo

l permeabilities global porosity histograms porosity/permeability clouds visual comparison of heterogeneity and earth-model and scaled-u n the UK and other countries on a global basis and discussion is included regarding the alternative uses of such depleted fields which may p to comply with increasingly stringent regulatory requirements for disposal of produced water is fast becoming another key driver for reliabl d gravity drainage (SAGD) and downhole electrical heating are essential for the production of heavy oil and oil sands and they are also un wettability and fluid trapping. The results lead to an improved understanding of capillary pressure characteristics in carbonate reservoirs in sidered to be a mature basin with over 95% of the oil and gas fields in Upper Cretaceous Abu Roash Bahariya and Kharita sandstone rese o capture the mixing zone growth correctly at early times. The results and approach shown here could be used to differentiate between dis

ome of the measured data was skewing the average. A new look at the material balance and simulation results verified that PVC and not a r ntroduction The Qarn Alam field is a highly fractured carbonate field that lies atop a salt diapir in Northern Oman. The 6 km long and 3 km e network in densely fractured reservoirs has a strong impact on reservoir displacement mechanisms. Conventional displacement methods of stack simulations for light oils and for a range of fracture spacings with reference to our previous results on viscous oils. We compare sing onstruct a spreadsheet capable of predicting long term injectivity on an individual well basis. A large number of wells were screened and opt nomial response surface between updated recovery factor and modeling parameters is generated by using perturbed reservoir models. MC e between 0.30 and 0.50 with the higher end values associated with high quality reservoirs (mainly oil content) excellent operations and la n stream in 2004.�� Plans are developing to change the composition of the injection gas stream to achieve higher H2S levels so that o play a key role in longer-term development strategies. Introduction The field geometry is characterized by two salt diapirs that are penet ntly worst case estimates for the environmental and economical damage caused by a blowout. Introduction The number which is invariably ated as an asset managed effectively with staff assigned to ensure the integrity of the data management systems. The key processes are Gas Fields from Reservoir to Point-of-Sale To provide context for this analysis it is appropriate to define what DOF is aspiring to achieve. DO eted with a length of 8 305 ft (2531 m) in the Captain field in the North Sea (Wehunt et al. 2003). During the early 1990s the development products. With many hundreds of tcf of contaminated gas resources worldwide there is no doubt the industry will rise to the challenge and elf-raising rig and barge) with pumping procedure (coiled tubing and bull-heading) to best-fit individual well condition. Close cooperation (W rface risks such as reservoir souring and hydrate formation dictated materials selection and completions design. This paper addresses th d to acoustic properties through a suitable rock model and resultant acoustic impedances were calculated. Synthetic seismograms were su

oncerned had undergone 8 previous phases of development campaigns application of the approach had led to identification of a substanti

al Solutions International with significant involvement and support from Brunei Shell Petroleum Company Sendirian Berhad(BSP) for robus fractures are found to be symmetric around both injectors with an estimated length of 200 ft. Increased steam injection after the first year

ecovery of the Mars field. The ability to acquire carbon oxygen data for monitoring sea water injection and sigma data for reservoir fluid cha

ns lie at the heart of deepwater production and present a large portion of the overall well cost. Great multidisciplinary effort is invested upfro but a few examples of such circumstances that would require real-time decision making and procedural modifications. Real-time decisions . 2002); and tiltmeter-based surface deformation monitoring (Davis et al. 2001 2000). Each technique has advantages and disadvantagesâ l effects and the possibility to implement this in a normal reservoir simulator has not (to our knowledge) been discussed in the literature. S s address the viability of a possible lower cost alternative for water entry quantification in near-horizontal wells that potentially have a highe determine wellbore integrity and ultimately to predict wellbore failure. It also provides calibration data for the compaction model used in rese ad across the wellbore on retractable arms that can be opened and closed with a hydraulic sub to better locate holdup interfaces. This collec oil shale thickness exceeds 1000 ft and has an average richness of 25 gpt resulting in a resource density of up to 2.5 million barrels per acr

ction Stimulating of existing oil and gas producing wells and of new wells is one of the means to maximizing production potentials without re e emphasing that planning drilling and completion as a discrete system performing drill-in-fluids QA/QC ensuring a stable hole and that al one formation contains significant amounts of iron-bearing minerals. Introduction Mineral scale formation is a persistent problem in oil and mizing recovery) should be weighed. Introduction Smart Wells. The introduction of smart completions in the oil industry has significantly inc

0.5% volume to volume (v/v) HEC polymer is added to aqueous foam bottomhole pressure (BHP) and foam density are significantly increas concentrations up to 9 ppa could be used successfully even with linear guar gel. This promotes the net pressure build up which is vital for fr tion A Joint Industry Project (JIP) active since 2002 was created with the goal of studying fracture clean-up and using the mechanisms unc

en in a controlled way the - otherwise undesirable - phenomenon of gas coning can be used to increase oil production. Introduction: Gas C emulsion may penetrate into a porous medium. Surfactant and alkaline-based pre-flush solutions may enhance an emulsion penetration de ought to be the primary cause of the problematic inflow performance of the conventional wells. A detailed hydraulic analysis of two problema

is made discontinuous by thin liquid films called lamellae [1-3]. Foam has been widely used to block the high-permeability layers and divert low cost allowing easily recursive treatments in case of an unsuccessful operation. Foam has also been widely used as a mobility control a alance models. The bubble population models take into account explicitly the evolution of bubble density and are the most suitable to descr edict pressure drop in tubing. Factors affecting the accuracy were identified. Comparison with a field case provided further proof for the valid

flooding experiments are used to modify the current prediction models. Based on the current work an adaptation to the Turner equation wh ection flow rate of 42 m3/day per perforation the expected net oil production rate of the LEP with a sand-screen in Peace River reservoir is a : how the crushed zone is formed and removed; the role played by pressure dynamics; the sensitivity of penetration and tunnel quality to for detail to illustrate this application for propellant-assisted perforating. The data presented includes pre-job planning execution and post-job i unique combination of ESS and hydraulic fracturing. Introduction The Egret field is located 43 km offshore in 60 meters water depth. The ating satisfactorily. This paper will review the evaluation that led to the sand-face completion design the field implementation of the design ial factors were slot size/geometry and pill formulation. Introduction Ursa-Princess Waterflood Development Overview The Ursa and Prince ompletion design the field implementation of the design and the key installation success factors that were required. Results and a summary Hydrocarbon production comprising oil gas and condensate is frequently accompanied by unwanted production components. Scale waxe

he development of a new Standard ISO 13503-41. This Standard provides for consistent methodology to measure fluid loss of stimulation a Use a mixing-on-the-fly unit in limited barge space. Learn from previous jobs to improve subsequent ones by optimising pumping proced halin. Here start-up of injection wells was accompanied by regular IFO testing in order to monitor fracture growth over time. The interpreted

s to address the problems of non-uniqueness associated with well angle and average bed thickness. Finally several example analyses are

d filtrate invasion the MR data show better agreement with saturations from core confirming the quality and reliability of the MR data. Comp shortfall between casings does not play a significant role in this fully cemented and sealed annulus. This left (1) the properties of the comp ces involved. Introduction The Onyx South West exploration well 6406/9-1 was the second well to be drilled within licence PL 255 (Table 1 s (DFA) borehole images and numerical simulation models to minimize these uncertainties. A systematic pressure transient analysis metho complete the final result may be good bad or suspect hence results are usually subject to a manual validation process. This begs a numb

he market to enable a ‘Kyoto 2’ type-agreement. Authorities such as the International Energy Agency the European Union Commiss 03; Pruess 2004) and unmineable coalbeds (Reeves 2001). Laboratory studies and recent pilot field tests (Mavor et al. 2004; Pagnier et al ally termed as "solvent". Thus a coal-solvent bond will replace a coal-coal hydrogen bond or any other weaker bond only if the new coal-solv ll actually decrease because of fracture closure in a constrained coal. To validate the permeability swelling relationship both permeability m

O2 sequestration process. Introduction The injection of carbon dioxide (CO2) in coalbeds is one of the more attractive options of all underg lity and brine permeability. Carbon dioxide injection started in 2008 and will last for about 2 years. The paper focuses on the integrated app to grow energy demand will keep pace. With growth in economic activity and energy use worldwide greenhouse gas emissions (and speci e meeting the growing needs of society for energy. Development and utilization of technologies to capture and then store carbon dioxide (C n of the network such as the addition of a well or a sensor without having to manually reconfigure applications. Such changes are common duction Major energy companies embarked on innovative production technological initiatives beginning early in this decade driven by mark

d in terms of where and when to sample and how many samples to collect; and the quality of the fluids collected can be substantially impro d well testing facility (2) production from multiple subsea wells sharing a single tie-back pipeline and (3) production from individual subsurfa d easy to maintain. FieldWare PRODUCTION UNIVERSE is now fully operational and used for well-by-well production surveillance and mo product is a lengthy and sometimes arduous task. Across the industry most operators can think of at least one system that has been “ro

hodology earlier implemented by Aera in California and originating from Toyota's manufacturing plants. The asset consists of five mature oi dly option. Introduction The focus of this paper is dynamic well testing as implemented in exploration and appraisal wells. The industry has volving and there are clearly more issues to resolve than with a conventional drill stem test. However by drawing on our increasing breadth

phased approach. The current FDP is different from previous plans in the fact that it relies on (a) a novel well concept (b) smart well techn

ally the injected water will displace the remaining oil in the reservoir on its way from the injection wells to the production wells. Rock hetero e thinking that guided the development and success of Smart Wells. Figure 1 illustrates the essence of the Smart Field vision. Value is crea in the order of hundreds millions US dollars per year. Shell has a number of programmes ongoing to implement Smart Fields� into the e ensive re-drill was avoided. The smart snake wells have thus been a key enabler for the economic development of the Champion West field

ture range of 80-120�C. It consists of highly stratified/laminated reservoirs with erratic fluid fill; narrow elongated fault blocks; and thin oi e drilling. The paper postulates that every piece of equipment is driven by a functional need has an impact on efficiency and therefore cost a stem. Conventional overbalanced drilling sits at one end of the Managed Pressure Drilling spectrum and underbalanced drilling at the other e that combustion plays on the incremental recovery of HPAI.� Numerical simulations were conducted in a 3D model with real geological edictive capabilities. Introduction Some of the unconsolidated sand formations both onshore and offshore contain high viscosity oil and mig s (crude oil type temperature and water composition) and the structures of added surfactant(s) have to be tailored to these conditions to ac he benefit of these EOR methods simulation techniques should be capable of modelling the impact of these processes on GOGD. We pres . Given the ‘high’ oil price and maturity of Australia’s oil provinces significant value is associated with EOR. Air injection is poten ck oil with moderate GOR (185 m�/m�) as shown in Table 1. Fluids from reservoirs A B D E G I and J are black oils from H a volatile d numerical reservoir simulations. This work is mainly concerned with the modeling and numerical simulation of foam. Several foam models d gas injection have been screened by the model leading to a conclusion in relatively short period of time. Introduction The Gyda Field is lo

ess some of the engineering and operational challenges that are being managed. Introduction Qarn Alam Field is located in central Oman s

of low salinity level removal of multivalent cations from the seawater should be considered to avoid the potential risk that the reservoir bec o fill up channels behind the liner inert particles to control fluid loss of the full-blocking gel to small fractures and the formation matrix and d with 1 000 BOPD before the treatment). The oil production declined to 2 000 BOPD over a year; the water cut gradually increased over tha 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 o cement which must be drilled out. The temperature range of the PG system is 80 to 350�F. To date more than 54 jobs have been perf are with the data of Amott cell imbibition experiments. It is confirmed that in both cases the cumulative recovery is initially proportional to the whole energy value chain in order to focus on the key business opportunities. The same approach can be used for a smaller section of the n of gas lift. Gomez et al4 reported a successful implementation of the Tunneling Method to solve a five variable history-matching problem. carbon reserves have been discovered offshore on the Arctic shelf and Far East seas with estimates of approximately 72% natural gas 24 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 hase is predominantly CO2 while the CO2 in the liquid phase continuously increased with pressure which indicates condensing drive chara etroleum Reservoirs in equations for single and multiphase flow in tubing and transmission to the market place.

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 . vary with elevation. The magnitude in grading of these properties can vary greatly depending on the geological and geochemical history o advantages over the conventional GOR measurement techniques. It does not require tampering with the sample which helps the operator om problematic fluid samples. Introduction High oil prices and diminishing supplies warrant a smarter use of the remaining oil resources i e average droplet size was increasing with water content. For all measured cases viscosities varied with temperature according to an Arrhe ock tank oil system. The oil-wet behavior observed for live oil using surfactants indicates the possibility that these surfactants develop contin

uring execution of treatments. Key technical and economical performance indicators including skin factors production rates specific produc

ccessful matrix-acid treatment. This is especially true for long intervals with a high degree of permeability heterogeneity. Without effective fl

ally dependent equivalent skin. The equivalent skin can then be used in field-scale reservoir models to compare various drilling and develop ction The development of acidic sometimes biodegraded crudes in different parts of the world may lead to naphthenate problems during oi

bsequently undertaken scale dissolver and scale squeeze not only saved the well from scaling up but also led to a significant production ga lower the viscosity of the oil thereby increasing its productivity. Key is the distribution of steam in the reservoir and its optimal use to mobili

making on the EOR strategies for the fields. Introduction Five oil fields located in the Ghaba Salt Basin (GSB) in North Oman and producing jection wellhead pressures estimated production bottom-hole pressures and temperature profiles were achieved not only for the entire Pad œfines migration. In 1996 the first Hydrogen delayed retarded HF acid was successfully pumped in Shell Petroleum Development Compan hermal interaction (modelling the energy and heat exchange between matrix and fractures). This implies that in a thermal DP simulation two at a depth of about 600 m. The porosity varies between 27-30% and the permeability between 10-2 000 mD. The high viscosity of the Pea ic plots based on bulk fluid properties for reservoir fluid equilibrium grading tendencies have been constructed based on interpreted results ese laboratory tests on Harweel core samples as well as a comparison of the actual perforation performance of the evaluated charges. 1. B ility of the critical matrix. However because of the rapid reaction between hydrochloric acid (HCl) and carbonates diverting agents such as n be reached -��� Statistical analyses to determine whether statistically significant conclusions can be drawn with a high degree of

on effectiveness using production alone with the sample size required when using reservoir simulation. The reservoir simulation analysis p er production. Condensate ratio with an API gravity of 52 is 8 to 10 bbl/MMscf (Eberhard and Mullen 2003). Numerous faults exist in the reg tion was designed to collect daily pressures in numerous sands without compromising future production. Combining existing systems offere o applied as a correlation for prediction of the equivalent liquid permeability in much the same fashion as the Klinkenberg model although o ces waste. Introduction A venture in South West Algeria aims to explore and develop low matrix permeability gas reservoirs as part of its s geneity and borehole stability) and organizational aspects (building a drilling operation in China from scratch managing HSE in a different c otal losses into these natural fractures. However significant productivity gains were also observed and this became a key driver to apply the

d to as Smart Fields Initial Screening uses a structured process to match the appropriate Smart Fields integrated solutions to the specific n

were left in the flowline creating secondary choke (restriction) along the flowline initially and later pushed down to the choke inlet. The rem r management typically requires that designers across the company all use the same value for oil in their evaluations. Equally important the es a foundation for both Shell and Schlumberger to share the project risk and reward as the solution progresses from sandbox to prototype rmeability and capillary pressure curves including hysteresis based on experimental special-core-analysis (SCAL) data has a significant im and gas phase) and to quantify the level of OBM-filtrate contamination (Mullins et al. 2000). In addition optical spectroscopy is invaluable do ced--in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides importa

vely simple full-field reservoir models is one way to reduce reservoir modeling cycle-time. Coarse-scale full-field simulations can include the um (SH max) and minimum (Sh min) horizontal stresses obtained from the inversion of borehole sonic data are significantly smaller in the d

ractures can impact reserves estimation initial well rates production declines and planned well locations. With respect to well completions um equations (Darcy’s law or 1D convection dispersion equation). However interpreting field-scale measurements with standard contin ods such as the Kozeny-Carman equation. Aside from giving insight into the influence of pore structure on permeability our method offers e read more easily. The use of RIPI for static and dynamic characterization of super-matrix features (such as fractures thief zones etc.) is il d clustering. Fractures cluster within fracture corridors and fracture corridors are clustered within fracture fairways. The nested clustering as ng in horizontal wells. High gross rates and water cut are also good indicators but injection rates and sweep in vertical well are not very relia ntifying compartmentalization and the presence of fluid-flow barriers and unraveling reservoir architecture are critically important to reservoi . However in deepwater or similar settings full-scale testing is inordinately expensive and environmentally taxing. Moreover interpretation g intervals. By providing this during the drilling process anomalies observed in these fluid facies logs can be investigated in more detail dur aset and the analysis that has been done to arrive at this conclusion. The simulation effort and the subsequent analysis have reduced the u c properties of the rock. Wettability ranges from pure water-wet (through intermediate-wet or neutral) to oil-wet. Sandstone reservoirs have

made up of thin interbedded sandstones and shales of inner neritic origin and outer shelfal facies (latter mostly in the Deep B sequence). Th ent within a consistent portfolio management framework. This is done by using modelling at various levels: 3D modelling at field level testin ry (EOR). The application of the newly developed technologies will be in the area of contaminated gas fields. With new technologies highly

roduction Many gas reservoirs critical to providing a reliable supply of gas to the Nigeria Gas market have observed or potential oil rims wh opment wells given the areal size of the field. The lack of well control for the structural mapping has resulted in a relatively high degree of un voir management activities result in the maturation of the field petroleum resources to reserves and improvement of oil recovery. Technology

st major deepwater field1 operated by Shell in West Africa in partnership with ExxonMobil Total and Agip and under Production Sharing Co

f oil-in-place was contained in a 50ft thick oil rim with approximately 300 Bscf of� GIIP within a 140ft thick gas cap at the crest of the field

nfavorable areal and vertical sweep. These risks can be managed if one has a proper understanding of dynamic induced fracture behaviour ell near the base of the reservoir is the optimum well type for CSS at Peace River. Well spacing less than 75 meters appears more attractiv s not only reduced the uncertainty in GIIP and ultimate recovery for the field but will also help to improve understanding of the impact of kars environment the opportunities include acquiring seismic under ice Arctic (ice resistant) jack-up drilling rigs for year-round drilling and develo d robustness to geological uncertainty. Moreover the RO procedure significantly improved the expected NPV compared to the alternative m g reserves including growth and SFR opportunities and to create life cycle development plans. Key challenges to unlock the value of the clu ments areas with four flow stations. These catchment areas are Opukushi made up of opukushi opukushi north and Ajatiton fields with a es—demanding well trajectories and running the “smart completions in these wells with small tolerances. Introduction The Champion o an increasing production profile that was declining over the years. Introduction This paper discusses about a case study based on the re sources and by insufficient imports. In the high case scenario which includes large volumes of tight gas shortfalls would be much later i.e. evelopment wells two unmanned wellhead platforms in about 30 metres of water and two 30-inch pipelines running about 60 km to shore. O ½Membrane tests (Barkman-Davidson) fail to produce representative filtercake properties Although the test rig performed satisfactorily pros fuels and nuclear energy requires 39% of all freshwater withdrawals. With the global growth in the next 20 years the total electricity consum ompressor networks control applications for the suppression of slugs and higher level process control applications where the applicatio cremental production till date. This work has opened new avenues for application to other wells on different platforms. The same methodolo

he water-injection scheme was limited. This paper presents a detailed evaluation of the potential for reservoir souring resulting from biogen ns are also presented. After several months of operation the Minox unit to remove the bulk of the oxygen broke down and oxygen control wa t clearly indicates that bacterial activity resulting from the addition of nitrate was the causative agent of the increased corrosion seen in the riate flow modelling programs. ter has been injected since June 2001 for enhanced oil recovery purposes. Initially Umm Er Radhumma (UeR) water featuring high H2S le scale inhibitor retention due to increased rock surface area available for adsorption and impact of mutual solvent on saturation dependent esults demonstrate that the adjoint-based sensitivities can be effectively used to find optimal well locations. In the field simulation models th discovered (in 1997). The reservoirs generally have low permeability (0.1 to 10 md) and they contain a wide range of fluid properties from r Recovery (EOR). The application of the newly developed technologies will be in the area of contaminated gas fields. With new technologies ment wells given the areal size of the field.� The lack of well control for the structural mapping has resulted in a relatively high degree of u y one of the examples involves oxygen activation for positive identification of water movement behind pipe. Creating value through surveilla pendency a relatively large tubing size improves oil recovery. This also enables the desired gas offtake rate to be achieved late in field life.

condly to establish a line drive waterflood pattern while investigating the merits of a dense five spot. The results of this infill drilling campaig e formalism. Introduction We focus on the problem of designing an optimal waterflood for an oil field. We limit ourselves to the situation wh nd of 1995 the field had produced 105 MMstb out of the total ultimate recovery estimated at 230 MMstb. Average pressure had fallen from 7 s the inversion. The results of the model-based inversion formed the basis of the detailed static models and analysis of key subsurface un onal data that can provide more constraints especially at the areas far from wells. Seismic data have much better spatial coverage than pro ving such problems is an arduous task; therefore well locations often are determined manually. However several automated well-placemen s a unique opportunity to test the applicability of published fracture relative permeability models by using these in history matching the produ hibits rapid convergence in the domain of model parameters. In terms of accuracy and uncertainty reduction SEIKF performs comparable to tion attained by a commercial assisted history-matching software. A well-by-well analysis of the most probable model reveals that the match oling of shut-in production fluids containing hydrates and paraffins; or to keep injection fluids hot (early steam well applications). Achieving r ment strategy adapted to the specific reservoir conditions and in terms of production to a net oil-production increase of 50 to 100%. The fie oper understanding of dynamic induced fracture behaviour as a function of parameters such as injection rate voidage replacement reservo reservoir transients overlap. Simulations show that the coupled simulator is essential for an accurate prediction of the well-reservoir interac abilities and therefore a more accurate production forecast and a better control strategy can be designed. Introduction With increasing kno

s where a simple understanding of the effect of a controllable variable on a dependent variable is required or where the range of uncertainti ghout the Field.�� In essence the work recaptures the value of analytical methods within the workflow of present-day project developm ehavior. The difficulty arises in capturing this near-wellbore phenomenon accurately because it is a two-phase flow problem with large chang

oach as well as relative quality/performance of grids generated by using different indicators. Introduction Practical handling of detailed geo permeability and fluid properties distribution. This in turn yields more accurate global and local results and reduces application of sophistica oirs is strongly influenced by property variations that occur on all scales from the pore scale (tens or hundreds of microns) to the field scale

ecessitate achieving thermodynamic equilibrium. The overwhelming evidences for dynamic communication have led to the hypothesis that th -scale geostatistical fluctuations of fracture densities rather than perturbing permeability calibrated from fractures. This strategy enables us odel used in this study can successfully simulate the behavior of a naturally fractured reservoir. The model has shown that it can produce ex der three cases of increasing complexity. First we consider pressure/temperature diffusion in a single 1D matrix block following a step chan

to be a major contributor towards the mitigation of such. Reservoir sand quality and fluid properties have typically dictated certain comple

ted effort of all disciplines. An Integrated Production System Model which includes the reservoir wells and surface facilities linked to an Int physics of flow compared to a simple distance-dependent covariance function as used in the past. This flow-relevant conditioning leads to a chniques have appeared in the literature (Mead 1981; Hasan and Kabir 1983; Kabir and Hasan 1996; Kuchuk 1999; Chacon et al. 2004). La experience help the understanding of the result from the development scheme modeled. For example a look at the simulation grid for a res lat facies have been recognised. For these sediments channel sand geometry orientation and internal permeability anisotropy are crucial t

neity and earth-model and scaled-up volumetrics. The scaled-up models were screened using the 3D SL technique. The results helped in of such depleted fields which may present a (competitive) alternative to the use of depleted fields for gas storage such as CO2 sequestrati coming another key driver for reliable forecasts of water production. Clearly for making robust investment decisions on water-handling facili and oil sands and they are also under investigation for the in situ upgrading of oil shales. Under any of these recovery processes a key to acteristics in carbonate reservoirs in particular the contact angle distributions and hysteresis behaviour in both drainage and imbibition. Thi ahariya and Kharita sandstone reservoirs. Shell Egypt N.V. (52% (operator) Apache 48%) however continued to explore for deeper targets be used to differentiate between displacement and sweep efficiency in field scale displacements to ensure accurate representation of dispe

results verified that PVC and not a reduction in OOIP was the root cause of the difference in performance estimates and the observed rese ern Oman. The 6 km long and 3 km wide field forms a relatively high-relief anticline with a N-NE by S–SW orientation. The reservoir is rela onventional displacement methods such as water flooding do not work effectively: due to the high fracture permeability it is not possible to e lts on viscous oils. We compare single-porosity simulations of a fracture-matrix stack system with dual-permeability simulations. The dual-p mber of wells were screened and optimized using this practical tool. This methodology can be readily applied to other water disposal proje sing perturbed reservoir models. MCSBM derived the conditional probability of modeling parameters and probability distribution of recovery ontent) excellent operations and large pads; while operations at the lower end values have usually a combination of operational issues sm o achieve higher H2S levels so that the injected gas will become miscible with the A4C oil.� This is designed to further increase oil recove ed by two salt diapirs that are penetrating the reservoir formation leading to two connected accumulations (North Pierce and South Pierce). tion The number which is invariably attached to potential or actual blowouts is the blowout rate. In the first place the blowout rate is a mea nt systems. The key processes are built on this foundation and deliver the business result.�These processes are supported by detailed what DOF is aspiring to achieve. DOF is the deployment of people processes and technology in pursuit of production safety and technica g the early 1990s the development of enhanced drilling and fluids technology led to advances in extended-reach and horizontal drilling (Re ndustry will rise to the challenge and develop these resources in an economic and safe manner. But it will require the application of radical n well condition. Close cooperation (Well services Production technologists Service providers etc.) during implementation. Game change in ns design. This paper addresses the challenges primarily affecting the design of the deepwater subsea-injection wells. In addition to the we ed. Synthetic seismograms were subsequently generated for several time steps and analyzed for production-induced 4D signals. The impac

ad led to identification of a substantial number of potential recovery opportunities for further development consideration. The approach can

ny Sendirian Berhad(BSP) for robust data driven modelling in an production operations setting that provides continuous real time estimates

d steam injection after the first year of pilot operations caused what is interpreted to be horizontal fractures toward the west in the G cycle a

nd sigma data for reservoir fluid changes combined with multi-rate production logging and testing is essential in reducing unnecessary risks

ultidisciplinary effort is invested upfront to design them right. This contrasts with the production stage where little information is available to d modifications. Real-time decisions may include acquiring more pressure data points extending sampling depths to several zones extendin has advantages and disadvantages—and in some cases two or even all three can be used in combination to get the required precision sp ) been discussed in the literature. Several authors have derived a tidal efficiency factor but a review and comparison study seems to be mi al wells that potentially have a higher risk of encountering sensor damage due to loose sand and/or debris. Other candidate wells that would r the compaction model used in reservoir simulation. Selected Mars well examples are described in detail to highlight the results of time-lap locate holdup interfaces. This collection of sensor arrays all integrated into a single sonde makes it possible to accurately detect and mea y of up to 2.5 million barrels per acre (Figure 1) (Picha et al. 2008). That is by far the most dense hydrocarbon resource in the world (Damm

zing production potentials without requiring extra facilities and drilling new wells. A synergized stimulation process among a geographical re C ensuring a stable hole and that all engineers take active roles to make proactive decisions / choices that can impact operations are keys on is a persistent problem in oil and gas production especially in older reservoirs with increased water production and drawdown. Inhibitor s n the oil industry has significantly increased the scope for control of commingled production. ICVs allow for the adjustment of inflow in each

oam density are significantly increased while foam quality and velocity are greatly decreased. The polymer effects are more pronounced in pressure build up which is vital for fracturing treatment in high permeability reservoir. Eleven fracturing treatments on five different wells hav n-up and using the mechanisms uncovered to devise methods that would allow the production to benefit from the full length of the fracture

e oil production. Introduction: Gas Coning Control Gas coning is a phenomenon where the gas-oil-contact (GOC) of a reservoir slowly mov nhance an emulsion penetration depth significantly. However the emulsion may break down and emplace at a desired depth within a porou d hydraulic analysis of two problematic conventional wells and one smart well was requested by BSP to understand the inflow problems in t

high-permeability layers and divert the injected fluid for instance acid to the damaged/unswept layers [4-7]. In these applications foam red n widely used as a mobility control agent in Enhanced oil Recovery (EOR) as a profile correction agent [1-6]. The description of foam behav y and are the most suitable to describe transient foam flow. However traditionally the bubble population models involve many parameters th e provided further proof for the validity of the approach. This result is not only relevant for velocity string design it is important for all annula

daptation to the Turner equation which takes the inclination effects into account is proposed. For the observed natural gas wells and for th -screen in Peace River reservoir is around 4.8 m3/day/perf. Overall it can be concluded that injection through LEP’s is feasible and pro penetration and tunnel quality to formation and system parameters; and how jet perforators perform in targets other than sandstone.� T b planning execution and post-job inflow performance analysis.� The result was three world-class low-drawdown wells each capable of hore in 60 meters water depth. The field consists of stacked sand formations (mainly gas and some oil-rim reservoirs) broken up by faults i e field implementation of the design and the key installation success factors that were required. Results and a summary of best practices fr ment Overview The Ursa and Princess Fields brought online in 1999 and 2003 respectively are part of the Mars basin located in the Missis ere required. Results and a summary of best practices from the initial installations also will be summarized. Introduction Sarawak Shell production components. Scale waxes and asphaltenes precipitation and formation are addressed by the use of inhibitors or through well in

o measure fluid loss of stimulation and gravel-pack fluid under static conditions. Stimulation fluids are defined for the purpose of this docum ones by optimising pumping procedures. Clean up and flow test right after stimulation to evaluate results. 7 wells were stimulated in the re growth over time. The interpreted fracture dimensions were compared with predicted dimensions using a recently developed in-house wa

nally several example analyses are provided illustrating pressure analysis of high angle wells. These examples support the applicability of t

and reliability of the MR data. Comparison of the MR T2 distribution and volumetric with image data indicates that even fine variations in roc is left (1) the properties of the completion fluids differing from the properties of the base fluid (water) and (2) temporary leakoff to near-wellb drilled within licence PL 255 (Table 1). The first well 6406/5-1 in the Tott East prospect was drilled in 2002 to intersect sands of the Middle†ic pressure transient analysis method for mini-DSTs is also introduced. Reservoir parameters obtained from mini-DSTs in thinly laminated d lidation process. This begs a number of questions related to well test optimization and automation: - When should the well be re-tested

ency the European Union Commission for Research and the US Department of Energy predict that new technologies will include hydrogen sts (Mavor et al. 2004; Pagnier et al. 2005) demonstrate that CO2 injection has the potential to enhance CH4 production from coal seams. eaker bond only if the new coal-solvent bond is thermodynamically favored. If intramolecular bonding in the coal contributes significantly to ng relationship both permeability measurements under unconstrained conditions and volumetric strain measurements were used. � Intr

more attractive options of all underground CO2 storage possibilities: the CO2 is stored combined with simultaneous recovery of coalbed me paper focuses on the integrated approach of combining lithological and petrophysical data from both laboratory and well logging analysis pr eenhouse gas emissions (and specifically CO2 emissions) will also increase as illustrated in Figure 1 from work reported by the IEA. re and then store carbon dioxide (CO2) in underground formations offer significant potential for reducing CO2 emissions. IPIECA convene ications. Such changes are commonplace. In 2007 the PRODML work group focused on managing changes in production network configu early in this decade driven by market needs for increased production coupled with increasingly challenging producing opportunities. This s

collected can be substantially improved. Because each technique has its strengths and limitations integration is far more valuable than rely ) production from individual subsurface zones of a multi-zonal extended reach Smart Well. FieldWare Production Universe FieldWare Prod -well production surveillance and monitoring at many of Shell’s production facilities worldwide both onshore and offshore.�The applic ast one system that has been “rolled out but not been fully adopted and has “died before it delivered it’s full value. Reasons for f

The asset consists of five mature oil fields in shallow waters offshore East Malaysia:�The subsurface is relatively complex and some 200 nd appraisal wells. The industry has continued to use the term “drill stem testing (DST) to refer to these types of tests despite the fact th by drawing on our increasing breadth of experience future value of information decisions about doing in-situ dynamic measurements will mo

el well concept (b) smart well technology and (c) extended reach drilling. Now only a single new platform and 20 wells from there are plann

to the production wells. Rock heterogeneities will however influence the path of the injected water. The water will mainly flow in the high p the Smart Field vision. Value is created through execution of the ‘value loop’ repeating the cycle of measuring modeling decision-m mplement Smart Fields� into the existing and new assets. In existing fields a suite of technologies is implemented called Foundation tha lopment of the Champion West field and we expect they will continue to add further value over the lifetime of the wells. Introduction The C

w elongated fault blocks; and thin oil rims (10-100m) with a high degree of compartmentalisation. There are over 1000 reservoirs in the Cha act on efficiency and therefore cost and may offer opportunity for enabling add-ons if the underbalanced drilling process is viewed from a dif underbalanced drilling at the other end. In conventional drilling bottom hole pressure is managed by controlling the density of the drilling f d in a 3D model with real geological features.� In order to capture more realistically the physics of the combustion front a reservoir simul re contain high viscosity oil and might be considered for polymer flooding to improve recovery. Flooding in unconsolidated sand could lead be tailored to these conditions to achieve an ultra low IFT.� In addition a promising surfactant must satisfy other important criteria includ hese processes on GOGD. We present in this paper a general dual permeability method that can handle GOGD as well as different mutua ated with EOR. Air injection is potentially suitable for Australian onshore application. The process warrants further evaluation and considera nd J are black oils from H a volatile oil from C a critical fluid and from F a gas condensate. Development of the cluster takes place in a ph ation of foam. Several foam models have been proposed in the last three decades including semi-empirical models [9] fractional flow mode e. Introduction The Gyda Field is located in Block 2/1 270 km southwest of the city of Stavanger Norway 43 km north of the Ekofisk Cent

am Field is located in central Oman south of the western Hajar Mountains. This large oil accumulation is trapped in shallow Cretaceouslimes

e potential risk that the reservoir becomes more oilwet which will result in reduced sweep. Introduction In the past decade injection of brine ures and the formation matrix and displacement with an already-cured gel that could be washed out of the wellbore. Significant drops in th ater cut gradually increased over that period to 56%. In the second well full shutoff was achieved but oil production could not be resumed fo nd lack of infill opportunities cement-water shutoff and re-perforation intervention in the wells was adopted. The objective of the cement-w e more than 54 jobs have been performed with this system. This paper presents case histories methodology of job designs and results ob ecovery is initially proportional to the square root of time. Imbibition after wettability modification however takes approximately 1 000 times be used for a smaller section of the energy value chain for example when the focus is only on the upstream sector. In this sector all individ e variable history-matching problem. David Goldberg with respect to calculus based optimization wrote5: “Many practical parameter sp of approximately 72% natural gas 24% oil and 4% condensate [1]. How can these ageing and new gas and oil fields be optimally developed 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 ich indicates condensing drive characteristics of CO2 to be responsible for miscibility development in the selected reservoir case. The dens

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 eological and geochemical history of the reservoirs. One must distinguish compositional grading from the fluid property changes commonly 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 use of the remaining oil resources including more extensive use of fluid combinations that have not been valued as highly in the past. Som h temperature according to an Arrhenius relation while viscosities did not indicate any variation with flow rate (shear) within the range of tes hat these surfactants develop continuous oil-wet paths for potential mixed wettability development. Thus this study is of practical significan

rs production rates specific productivity indices treatment costs indicate that this system has certainly and successfully increased the appl

ty heterogeneity. Without effective fluid diversion the injected fluids will follow the path of least resistance and will only stimulate the zones

compare various drilling and development options. The use of these results in designing an optimal drilling and completion plan to lock in th d to naphthenate problems during oil production1-11. These naphthenate deposits have become an increasing flow assurance problem due

lso led to a significant production gain. In another case it was possible to calculate if SWB had occurred or not much more accurately. Befo servoir and its optimal use to mobilize as much oil as possible (high Oil-Steam ratios). Efficient steam distribution control in standard compl

(GSB) in North Oman and producing from fractured low permeability limestones of the Cretaceous Shuaiba formation have been studied to achieved not only for the entire Pad A and B groups of wells but also for the individual wells. In summary a predictive CSS simulation mod ell Petroleum Development Company Nigeria (SPDC) wells. Nicholas et al 2001 published the performance of this system in SPE paper no that in a thermal DP simulation two kinds of shape-factors are required: hydraulic shape-factors and thermal shape-factors. Since a shape0 mD. The high viscosity of the Peace River bitumen between 20 000-100 000 cp makes the injectivity very low. An important feature of th ructed based on interpreted results and sensitivities to model parameters estimated. The potential use of centrifuge data was investigated ance of the evaluated charges. 1. Background The Harweel Cluster currently consists of 10 different reservoirs all of which have their own arbonates diverting agents such as ball sealers viscoelastic surfactant diverters and foams (Coulter and Jennings 1997) are used to direc can be drawn with a high degree of confidence The results of this study will also be compared to other published field trials to examine wel

The reservoir simulation analysis presented in the paper demonstrates a process for use in multiple layered reservoirs for evaluating stim 03). Numerous faults exist in the region adding to the complexity of the reservoirs and creating over pressured gas zones in wells whose n n. Combining existing systems offered by two contractors into an integrated package mounted external to the casing enabled us to acquire t s the Klinkenberg model although our new model is substantially more theoretical (and robust) as compared to the Klinkenberg correction ability gas reservoirs as part of its stakeholder’s corporate strategy. Tight (tight�=�<1millidarcy) gas reservoirs are usually complex ratch managing HSE in a different culture)2. After a summary of the development concept selection and the status of the project execution his became a key driver to apply the same UBD technology in tight gas fields in the Dutch sector of the Southern North Sea. This paper des

integrated solutions to the specific needs of the project. This is done for all key components of the production system. The new ways of wo

ed down to the choke inlet. The removal of these materials left in the flowline and the clean-up of the choke improved production from 53 to ir evaluations. Equally important the design process typically works with a best estimate of the original oil in place (OOIP). In short the stan ogresses from sandbox to prototype to commercialization.�The authors will also elaborate on critical success factors in such a new colla sis (SCAL) data has a significant impact on the field-performance predictions especially for heterogeneous reservoirs with transition zones optical spectroscopy is invaluable downhole when determining hydrocarbon composition (e.g. amount of methane ethane propane) and th re and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes

full-field simulations can include the presence of sub-seismic channel architecture by means of connectivity factors implemented in terms o data are significantly smaller in the depleted sand than in the overburden shale. However both the horizontal stress magnitudes increase ag

ns. With respect to well completions fractured reservoirs may necessitate a special stimulation approach. Because fractured reservoirs ten measurements with standard continuum equations suggested that a strongly connected path of vugs did not extend past a few feet. In parti on permeability our method offers the potential of permitting permeability predictions to be made using drill cuttings in situations where it i ch as fractures thief zones etc.) is illustrated. The limitations of the approach and future trends are discussed. Introduction When drilling u e fairways. The nested clustering aspect provides a means of utilizing seismic data to map fracture corridors. Unlike fracture corridors layer eep in vertical well are not very reliable. The predictive power of indirect indicators improves drastically if two or more indicators favour a fra re are critically important to reservoir management. Misinterpreting flow compartmentalization can result in large errors in production param ally taxing. Moreover interpretation of well test responses in turbidite and onlapping channel reservoirs can be highly non-unique due to the n be investigated in more detail during formation evaluation sample collection and geochemical fingerprinting techniques. In addition by s sequent analysis have reduced the uncertainty in relative permeability by a factor of three resulting in a significant improvement in the robus oil-wet. Sandstone reservoirs have a tendency toward being water-wet to neutral whereas carbonates are often neutral to oil-wet. Howeve

mostly in the Deep B sequence). The reservoir sands are expected to have a large lateral extent.� BU-2 encountered gas in all three obj els: 3D modelling at field level testing different geological concepts and the associated key uncertainties; those are then scaled up into an in fields. With new technologies highly contaminated gas fields can be economically developed to remove the contaminants from the hydroca

ve observed or potential oil rims where only a gas-down-to (GDT) has been logged. Development of these oil rims must be considered as p ulted in a relatively high degree of uncertainty for both the top reservoir structure and the in-place volume. Therefore interpretation of the fie ovement of oil recovery. Technology opportunities for innovative wells permanent downhole metering and enhanced oil recovery processes

p and under Production Sharing Contract with NAPIMS. Water depths at Bonga ranges from 3100 to 3800 ft. The Lower to Upper Miocene

thick gas cap at the crest of the field. Figure 1 shows the original and the 2006 fluid contacts as well as the positioning of the 11 horizontal p

dynamic induced fracture behaviour as a function of parameters such as injection rate voidage replacement reservoir fluid mobility and res an 75 meters appears more attractive in the higher reservoir quality areas compared to the current assumption of 150 meters. In summary e understanding of the impact of karstification on reservoir performance of other Miocene carbonate fields. Introduction The studied field is igs for year-round drilling and developing low-cost facilities which can withstand the ice or even be installed subsea under ice. Overview o NPV compared to the alternative methods (on average 9.5% higher than using reactive-control and 5.9% higher than the average of the N enges to unlock the value of the cluster was to provide a clear scope maturation plan for each field by understanding surface and subsurfac ushi north and Ajatiton fields with a central flow station located at Opukushi. The Benisede catchment area is made up of Benisede Akono ances. Introduction The Champion Southeast (CPSE) field is part of the larger Champion field which is the largest known offshore oil accu about a case study based on the real field data but the names of the field different blocks in the field and wells have been changed due t shortfalls would be much later i.e. past 2070. North America has relatively large indigenous resources and imports relatively low amounts nes running about 60 km to shore. Onshore gas-processing facilities will treat the sour rich wellhead gas to produce a clean (sulphur-free) est rig performed satisfactorily prospects for further development were identified leading to a hardware upgrade and quality monitoring ins 20 years the total electricity consumption of the water and wastewater sectors will increase by 33% (WBCSD Water Scenarios to 2025 20 ol applications where the application of automated control technology has improved production surveillance management and optimizatio rent platforms. The same methodology with further refinement can bring excellent results in a very cost-effective manner. The strategy ado

servoir souring resulting from biogenic reservoir souring in the Bonga field and the work done to predict H2S levels. The paper focuses on t n broke down and oxygen control was done with chemical oxygen scavenger only. With this different mode of operation the effectiveness o the increased corrosion seen in the Draugen PW treated for re-injection. It was concluded that the increase in corrosion rates most likely w

a (UeR) water featuring high H2S levels in this area was used for this as obtained from 6 water supply wells (WSW) through 4 dedicated ual solvent on saturation dependent relative permeability functions and phase mobilities. These aspects are discussed in the paper and the ns. In the field simulation models the optimization derived well locations lead to a higher ultimate oil recovery compared to a manual optim wide range of fluid properties from retrograde gas condensate to black oil with moderate GOR as shown in Table 1. The Cluster is being de ed gas fields. With new technologies highly contaminated gas fields can be economically developed to remove the contaminants from the h ulted in a relatively high degree of uncertainty for both the top reservoir structure and the in-place volume.� Therefore interpretation of th ipe. Creating value through surveillance is the common thread that binds these well intervention examples together. Introduction North Se rate to be achieved late in field life. Active monitoring and surveillance of the oil rim movement is essential to maximize recovery.� For

e results of this infill drilling campaign (executed in 2005-2006) and a new 600-fold high-resolution seismic survey gave a multi-disciplinary We limit ourselves to the situation where the well configuration and well types are given so the only degree of freedom left is the way the inje . Average pressure had fallen from 7.3 MPa to 4.1 MPa. Since May 1996 production has been supported by crestal gas injection. Gas is in s and analysis of key subsurface uncertainties. Results of the improved property models were upscaled and fed into the well inflow models much better spatial coverage than production data. We have chosen to history match the change in seismic impedance that is computed from er several automated well-placement optimization methods are available in the literature. They can be classified broadly into two categories these in history matching the production response between the reservoir simulation model and the physical model. Introduction The ARM ction SEIKF performs comparable to a conventional ensemble Kalman filter. SEIKF promises a rapid and reliable framework for history mat obable model reveals that the match is comparable or superior to the ones delivered by the commercial tool. The field test outcome demons steam well applications). Achieving reliable insulating performance often is critical to the longevity and economic viability of wells that need s ction increase of 50 to 100%. The field example shows how the coupled-simulator technology can be used to achieve optimized waterfloodn rate voidage replacement reservoir fluid mobility and reservoir / injection fluid mobility ratio3. In order to enable building and using such ediction of the well-reservoir interaction during these small time scale phenomena. Introduction Production instabilities are undesirable and ed. Introduction With increasing knowledge and new technologies more complex reservoirs with respect to location and dimensions can be

ed or where the range of uncertainties is well known within a narrow interval. These include production/injection management ‘model-ba flow of present-day project developments. Introduction The Champion Field is structurally and stratigraphically complex containing over 5 phase flow problem with large changes in relative permeability and hence the equations are highly nonlinear and do not lend themselves to

on Practical handling of detailed geological models has long been a serious challenge for reservoir simulation and management. Efficient co nd reduces application of sophisticated upscaling techniques and full-tensor permeability upscaling. Introduction With no doubt reservoir s ndreds of microns) to the field scale (kilometre). Examples of such property variations include heterogeneity of the porous media e.g. porosi

on have led to the hypothesis that the thermodynamically unexplained variations in PVT properties amongst the studied GOM reservoirs ca fractures. This strategy enables us to preserve the geological/geomechanical consistency throughout the history-matching process. The ge del has shown that it can produce excellent results in a very practical way. The methodology described in this paper is suitable for other nat D matrix block following a step change in the boundary conditions. Next we consider isothermal gas/oil gravity drainage from a homogeneo

ve typically dictated certain completion designs for wells and a certain operating philosophy. Another example of advanced technology imp

and surface facilities linked to an Integrated Activity Plan is a key enabler to integrate the different disciplines and optimize the result. Unce flow-relevant conditioning leads to an efficient and robust approach for history matching and continuous reservoir model updating avoiding uchuk 1999; Chacon et al. 2004). Larson (1963) revisited the Muskat method and put it on a firm theoretical ground for a homogeneous cyl a look at the simulation grid for a reservoir shown in Figure 1.0 can be intimidating but this need not be so as a systematic approach enhan permeability anisotropy are crucial to predicting fluid flow. The results of the sedimentological review have been used to create a series of

SL technique. The results helped in bracketing the flow behavior of different earth models and evaluating the model that better tracks the hi as storage such as CO2 sequestration. Introduction The storage of gas in many Western European countries has over the past 5 years ta nt decisions on water-handling facilities it is critical to have reliable methods of predicting associated water production. There are several c f these recovery processes a key to efficient reservoir management and process optimization is the ability to perform accurate reservoir sim in both drainage and imbibition. This paper also presents a mathematical model for implementing both drainage and imbibition capillary pre ntinued to explore for deeper targets in its North East Abu Gharadig Exploration License in particular in the Jurassic Safa sandstones overly ure accurate representation of dispersive mixing in reservoir simulation and to guide upscaling workflows. The flow reversal concept motiva

ce estimates and the observed reservoir performance. By using a new lower average PVC the observed reservoir pressure is found to be c “SW orientation. The reservoir is relatively compact dome-shaped structure with a maximum oil column of 165 m. The main oil bearing rese ure permeability it is not possible to establish significant pressure differentials across oil bearing matrix blocks to drive oil from matrix rock in permeability simulations. The dual-permeability modeling requires special techniques to capture transient effects. Introduction The connecte applied to other water disposal projects targeting depleted naturally fractured or matrix only gas fields. Introduction The Schoonebeek oil d probability distribution of recovery factors. Both derived probabilities are compared with initial models. Sensitivity analysis shows that reco ombination of operational issues smaller oil content and shale baffles (poor vertical connectivity). Introduction From 1985 to 1987 the gove signed to further increase oil recovery. The purpose of this paper is to present the development history of this sour oil reservoir along with p ns (North Pierce and South Pierce). Seismic control is relatively poor and only major geological features such as large faults are well localiz first place the blowout rate is a measure for the damage caused by a blowout since there is a direct relation with: The loss of reserves T processes are supported by detailed workflows with corresponding enabling technologies.�The business processes and workflows requi it of production safety and technical integrity improvement by timely effective and sustained use of sufficient good production informatio ded-reach and horizontal drilling (Restarich 1992 1993; Jones et al. 1997).�Screen-only completions became a favored completion mod ill require the application of radical new technology and an integrated approach across the full value chain. It won’t be for the faint hear g implementation. Game change in acid stimulating carbonate horizontal gas wells. Hydraulic fracturing in STOS has significantly improve -injection wells. In addition to the well cost several other underlying factors have played an influential role in defining the boundary condition ction-induced 4D signals. The impact of various levels of random noise on the 4D response was also evaluated. The results from both of th

nt consideration. The approach can be applied for systematic identification of bypassed oil opportunities in water-drive reservoirs where det

ides continuous real time estimates of well-by-well production.� Applied to the Champion West multizonal wells the FieldWare PU mode

res toward the west in the G cycle and the east in the M cycle. These features are imaged to be at least 100 and 160 ft respectively along

sential in reducing unnecessary risks of well intervention. Many of the Mars wells produce from multiple reservoir layers so multi-rate produc

ere little information is available to detect problems optimize the inflow and prevent expensive workovers. Incomplete gravel packing deve ng depths to several zones extending or shortening sampling times and repeating microhydraulic fracture reopening/closure cycles as wel tion to get the required precision spatial coverage and temporal resolution. Only tilt data measured by tiltmeters is used to analyze the cas d comparison study seems to be missing. ris. Other candidate wells that would benefit from these concepts include those producing with large water cut where high water holdup and ail to highlight the results of time-lapse monitoring of the waterflooded reservoirs. A comparison of log data with simulation modeling predict ssible to accurately detect and measure the flowrates of each phase even in very high water-cut wells with trace oil and high gross flowrate ocarbon resource in the world (Dammer 2005).

n process among a geographical region would benefit each individual asset in the organizational structure that was introduced to the region hat can impact operations are keys to success for a typical completion method. Small independents that operate marginal oil wells will find production and drawdown. Inhibitor squeezes are commonly used to deposit a suitable scale inhibitor in the formation. During an inhibitor sq for the adjustment of inflow in each individual zone; see Fig. 1. Efficient use of ICVs requires the capability to measure the inflow from each

mer effects are more pronounced in vertical wells than in horizontal wells. Simulation results also indicate that it is possible to use foam to c eatments on five different wells have been performed with excellent results. Introduction Oil and gas industry in Brunei Darussalam started t from the full length of the fracture placed. This would either boost revenue by increasing production or decrease cost by placing smaller si

act (GOC) of a reservoir slowly moves towards a well as a result of oil drawdown.� In case of horizontal or deviated wells this is often a z ce at a desired depth within a porous medium as a result of applying low pH solutions. Unconsolidated cores withstood 42 500 kPa/m (1 88 understand the inflow problems in the conventional producers and to confirm the justification for smart completions. Because the initial kic

[4-7]. In these applications foam reduces the gas mobility by trapping a large part of the gas. Moreover the foam reduces the liquid mobility 1-6]. The description of foam behavior in porous media relies on macroscopic modeling. Although many works have been devoted to foam models involve many parameters that have been hard to obtain in the laboratory. Recently Zitha10 11 proposed a stochastic bubble popula g design it is important for all annular flow processes in wells such as flow around a stinger drill pipe tool or coiled tubing string. Introducti

bserved natural gas wells and for the airwater experiments the modified Turner equation predicts the observed loading points within 20% ac hrough LEP’s is feasible and production through LEP’s in their current configuration is possible if the formation properties are simila targets other than sandstone.� This lack of understanding has contributed to technology stagnation sub-optimal well performance poor w-drawdown wells each capable of delivering 200 MMscf/d providing well capacity that met or exceeded expectations.� The propellant rim reservoirs) broken up by faults into multiple blocks. The first production from three gas wells occurred in November 2003 transported vi and a summary of best practices from the initial installations will also be summarized. Introduction Sarawak Shell’s Shallow Clastics f the Mars basin located in the Mississippi Canyon area offshore Louisiana Gulf of Mexico in 3 850 ft of water (Figure 1). The primary prod ed. Introduction Sarawak Shell’s Shallow Clastics field consists primarily of two shallow gas-bearing reservoirs H1 and H2 at app e use of inhibitors or through well interventions. Water is addressed through water handling and re-injection and whilst an undesirable part

efined for the purpose of this document as fluids used to enhance production from oil and gas wells by fracturing or acidizing. Also gravel-p ults. 7 wells were stimulated in the campaign. Significant gain has been achieved through progressively optimising pumping procedures. In ng a recently developed in-house waterflood fracture simulator. The fracture lengths as interpreted from IFO test analysis appeared to be sy

xamples support the applicability of this high angle pressure analysis technique through the early arrival of the late time reservoir pseudo-ra

icates that even fine variations in rock quality and lithology are reliably resolved by the MR data. Prior to logging old core data was used to d (2) temporary leakoff to near-wellbore fracture systems through the microannuli between cement sheaths and casings as explanations fo 02 to intersect sands of the Middle–Lower Jurassic Garn Ile and Tofte formations2. Well 6406/9-1 Onyx SW was planned as a vertical e from mini-DSTs in thinly laminated deepwater reservoirs are then compared with other available static and dynamic reservoir information su - When should the well be re-tested? Some wells are tested too often some wells are not tested enough. What is the optimum? - What

w technologies will include hydrogen fuels cells clean coal technology and storage of CO2 below ground – in deep saline formations or re e CH4 production from coal seams. This technology can be used to sequester large volumes of CO2 thereby reducing emissions of industr the coal contributes significantly to its structural integrity then strong coal - solvent bonding should disrupt such a structure which results in measurements were used. � Introduction Maturation of coalbed methane (CBM) production operations in some basins the emergence

multaneous recovery of coalbed methane (CBM). Among all the fossil fuels when combusted methane emits the least amount of CO2 per boratory and well logging analysis predominantly for the reservoir/storage section of the Ketzin site. This method was successfully applied in om work reported by the IEA. ng CO2 emissions. IPIECA convened an international workshop in October 2003 to advance understanding of the role of CO2 capture and anges in production network configuration and in the capabilities of system components. The result enables optimization and reporting arch ging producing opportunities. This step change was heralded with terms such as integrated instrumented future and digital. There was no

gration is far more valuable than relying on any single source for interpretation. Ultimately no technique is used in isolation and no interpre Production Universe FieldWare Production Universe (FW PU) is a data driven modelling application developed by Shell to address fundame onshore and offshore.�The application of PU has helped increase production through improved monitoring resolved hydrocarbon alloca ered it’s full value. Reasons for failure are many but often centre around support and delivery of true benefit to end users. This paper d

e is relatively complex and some 200 producing strings are operated connected to some 100 different reservoirs. Facilities are generally old ese types of tests despite the fact that many modern exploratory and appraisal tests use a dedicated production string rather than a drill str -situ dynamic measurements will more often include this cheaper safer and more environmentally friendly option. Introduction The focus o

rm and 20 wells from there are planned to develop the field. With this “smart FDP 15 years after discovery the CW field became the l

e water will mainly flow in the high permeability channels which causes only part of the oil to be produced. Recently smart fields concepts of measuring modeling decision-making and controlling to get the maximum amount of hydrocarbons out of the reservoirs in the most cos mplemented called Foundation that provides both enhanced monitoring and optimisation of production and provides the data and models me of the wells. Introduction The Champion West field discovered in 1975 is situated offshore Brunei in a water depth of 40 to 50�m. T

are over 1000 reservoirs in the Champion West area. Due to the nature of the vertically stacked structurally dipping reservoirs it was reco drilling process is viewed from a different perspective. Introduction It has been pointed out many times and by as many folks that underba ontrolling the density of the drilling fluid to maintain well bore pressure profile above the pore-pressure throughout the well bore. Underbala e combustion front a reservoir simulator with dynamic gridding capabilities was used.� Kinetic parameters were based on the combustion in unconsolidated sand could lead to “fracture propagation. Although such formations typically have high permeability in the order of se satisfy other important criteria including low rock retention compatibility with the polymer to be used compatibility with hard water (if presen e GOGD as well as different mutually interacting processes expected to occur when EOR techniques are applied to fractured reservoirs. nts further evaluation and consideration as an alternative to accepted EOR techniques. Introduction Air injection was first introduced as a ent of the cluster takes place in a phased manner with a shared central facility. Details of the strategies employed to mature the reservoirs a rical models [9] fractional flow models [10 11] population balance model [12-15] and percolation theory [16]. Recently Zitha [17] examine way 43 km north of the Ekofisk Centre and 28 km south-east of the Ula Field. The water depth is around 65 to 70 meters (Fig.-1). The produ

trapped in shallow Cretaceouslimestone units at a depth of around 200-400m sub sea. The anti-clinal structure is a result of a deep salt dia

In the past decade injection of brines with well-selected ionic composition in sandstone and carbonate reservoirs has been developed into the wellbore. Significant drops in the GORs of these wells resulted in sustained oil-production increases. This is a step change in the ability production could not be resumed for reasons that are not fully understood. Introduction Waterdrive either natural or through water injectio ted. The objective of the cement-water shutoff was to ensure that the perforations which were flushed were completely sealed off and iso ology of job designs and results obtained from laboratory evaluations. Introduction Water drive either natural or through water injection i er takes approximately 1 000 times longer than spontaneous capillary imbibition into a water-wet medium. The slow recovery observed in t ream sector. In this sector all individual elements in the oil & gas upstream supply chain are typically modelled in isolation using simulation p 5: “Many practical parameter spaces have little respect for the notion of a derivative and the smoothness it implies. Theorists interested and oil fields be optimally developed and operated to ensure uninterrupted production while simultaneously reducing downtime equipment 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 e selected reservoir case. The density-pressure plots showed the evidence of approach to critical mixture formation near VIT miscibility. Thi

efined utility for wireline formation testers in approaching well test functionalities. Introduction H2S is an extremely hazardous toxic compo he fluid property changes commonly observed in vertically stacked reservoirs. For instance the fill/spill mechanism at work in many stacked 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 en valued as highly in the past. Some of the issues associated with using non-conventional fluids are organic deposits such as asphaltenes w rate (shear) within the range of tested flow rates. Measured viscosities also increased as pressure decreased below the bubblepoint of the s this study is of practical significance in cases where the surfactant-induced wettability alterations to either intermediate-wet or mixed-wet

and successfully increased the application envelope for unique HF treatments within sandstone reservoirs. Introduction The use of HF sys

ce and will only stimulate the zones with the highest permeability or the least damage.� To place the injected fluids more uniformly the i

ng and completion plan to lock in the value of UBD is demonstrated for the two field cases. Introduction Three distinct advantages of UBD easing flow assurance problem due to deposition and process disruption in production facilities1 6 8 9. A general view of the deposition me

d or not much more accurately. Before the statistical analysis the suspicion was that 18 wells had undergone SWB and subsequently were tr istribution control in standard completions passing through the multi-sand (i.e. high permeability contrast) reservoir is extremely difficult. Hig

aiba formation have been studied to assess the feasibility to implement EOR techniques. The subject field (Field B) contains very viscous o ary a predictive CSS simulation model has been developed and validated by history matching two areas of the Peace River field. The mode ance of this system in SPE paper no 56527. After this success the drive and confidence to stimulate high water cut increased. The solution ermal shape-factors. Since a shape-factor is dependent on the underlying physical process that it models (and not only on the shape and di y very low. An important feature of the reservoir is the Basal Transition Zone (BTZ) located at the base. It has a sufficiently high water satura of centrifuge data was investigated as an additional fluid characterization tool to construct more realistic reservoir fluid models for graded re eservoirs all of which have their own distinct characteristics. In general the reservoirs are deep highly pressured and contain sour light hyd 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 published field trials to examine well populations data consistency and to assess whether studies in similar reservoirs carry similar findings

ayered reservoirs for evaluating stimulation effectiveness.�The process requires significantly fewer field tests than if production rates we essured gas zones in wells whose nearby offsets encounter normally pressure zones at similar depths. Pore pressure variability with depth d o the casing enabled us to acquire this data while still allowing for hydraulic-fracture completion and normal production in the future when m pared to the Klinkenberg correction model. Introduction The gas slippage phenomenon typically occurs in the laboratory when gas flow ex y) gas reservoirs are usually complex with high stratigraphic and/or reservoir quality uncertainty. Tight gas developments require in-depth un d the status of the project execution this paper provides some of the learnings so far and how they have been used to further improve proje Southern North Sea. This paper describes the experience to date offshore The Netherlands. Setting the Scene The average permeability c

uction system. The new ways of working are enabled by bringing together -- in one room or virtually -- skilled people for multidisciplinary dis

hoke improved production from 53 to a realistic production potential rate of 127MMscf/d at 100% choke opening. The production rate increa oil in place (OOIP). In short the standard approach to design is a technical process that generally does not explore in detail the consequenc success factors in such a new collaborative R&D setting. Introduction This joint Shell-Schlumberger project is a multi-year staged capa eous reservoirs with transition zones. Introduction The reservoir interval from the oil/water contact (OWC) to a level at which water saturati of methane ethane propane) and the GOR a parameter that plays an important role in the design of surface facilities (Mullins et al. 2005a; combined in a package that includes the optical spectrometers and measurements of fluid resistivity pressure temperature and fluorescen

ivity factors implemented in terms of effective properties and derived from representative full-detail and coarse-scale sector model simulatio ontal stress magnitudes increase again in the shale below the depleted sand. Such rapid variations in horizontal stress magnitudes cause l

h. Because fractured reservoirs tend to produce from a relatively small reservoir volume (i.e. the fractures) these formations can be highly d not extend past a few feet. In particular the tracer experiment in the field scale can be modeled accurately using an equivalent homogene g drill cuttings in situations where it is not possible to recover intact core. Another possible future application is to use downhole borehole im ussed. Introduction When drilling underbalanced in permeable reservoir rock the return fluid carries reservoir fluids and hence it is presum idors. Unlike fracture corridors layer-bound fractures are pervasive and their spacing is controlled by mechanical layer characteristics such f two or more indicators favour a fracture corridor. If the wells with fracture corridor indicators are aligned in WNW or NW the dominant frac t in large errors in production parameters such as drainage volume flow rates well placement sizing of facilities and completions equipme can be highly non-unique due to the complex architecture of such reservoirs. Today novel techniques such as Downhole Fluid Analysis (DF printing techniques. In addition by systematically combining and integrating these fundamentally different data streams a much more robus significant improvement in the robustness of the development plans. Introduction The subject cluster consists of 23 fields and is located in are often neutral to oil-wet. However there are too many exceptions to make reliable assumptions. Moreover the wettability is likely to vary

U-2 encountered gas in all three objectives and a total of some 190m net pay was logged (Fig. iii). Reservoir quality is best in the L80 with e s; those are then scaled up into an integrated surface-subsurface nodal network model to optimise the development of the discoveries as w e the contaminants from the hydrocarbon gas and re-injection of the contaminants. Since conventional technologies become less economic

ese oil rims must be considered as part of the overall hydrocarbon maturation plans for the reservoir. Maturation studies of this type can take e. Therefore interpretation of the field structure is largely dependent upon 3D-seismic surveys conducted in 1990 1998 2001 and 2004 a nd enhanced oil recovery processes are also reviewed. Introduction The West Salym field is located in West Siberia 120 kilometers south

800 ft. The Lower to Upper Miocene Bonga reservoirs are interpreted as stratigraphically / structurally trapped mud rich unconfined turbidite

the positioning of the 11 horizontal producers. The Gannet A Upper Tay reservoir consists of high quality deep-water turbidite sandstones

ment reservoir fluid mobility and reservoir / injection fluid mobility ratio . In order to enable building and using such an understanding as pa umption of 150 meters. In summary a series of predictive CSS simulation models primarily for horizontal wells have been developed. Hea ds. Introduction The studied field is a mature carbonate gas field located offshore Sarawak Malaysia approximately 175 km north-northwe alled subsea under ice. Overview of Sakhalin II Project Sakhalin Energy Investment Company (SEIC) is the operator of the Sakhalin II De 9% higher than the average of the NO strategies). Introduction In this paper we consider the secondary-recovery phase of a petroleum res nderstanding surface and subsurface controls leading up to a development concept selection and culminating later with the roll out of 23 fie area is made up of Benisede Akono and opomoyo fields and the flowstation is located in Benisede. The Tunu catchment area is made up s the largest known offshore oil accumulation in Negara Brunei Darussalam a small oil-rich state on the north coast of the island of Borneo and wells have been changed due to the restrictions. The Leon field is located in deltaic region of the river Azlean. It is an offshore field with s and imports relatively low amounts of gas but the local supply shortfall will be huge when its own resources are fully depleted. Both East A s to produce a clean (sulphur-free) lean gas feedstock for the GTL plant and treated ethane LPG condensate and pure elemental sulphu e upgrade and quality monitoring instrumentation that is expected to produce even better results in imminent field tests. It is expected that th BCSD Water Scenarios to 2025 2005). The petroleum industry is also impacted by the availability cost and quality of water at many point ance management and optimization.�� The role of Process Control in Exploration and Production Historical perspective Most engi -effective manner. The strategy adopted for the project included well diagnostics followed by intervention to increase oil production and red

H2S levels. The paper focuses on the selection of nitrate as a mitigation method. Introduction The Bonga field (Fig. 1) lies on the continen ode of operation the effectiveness of the nitrate as souring mitigation method was expected to be affected. Additional laboratory experiment ease in corrosion rates most likely was Microbiologically Influenced Corrosion (MIC). Details of the PWRI pilot and the observed effects whe

wells (WSW) through 4 dedicated injection wells at a maximum total rate of some 3900 m3/d reached in April 2003. By end of April 2003 are discussed in the paper and the model is used to demonstrate their impact on a squeeze treatment. Particular attention is paid to the re covery compared to a manual optimization approach. The algorithm yields multiple alternative well-placement scenarios within a shorter am n in Table 1. The Cluster is being developed in a phased manner with a shared central facility. The purpose of Phase 1 was to gather data t remove the contaminants from the hydrocarbon gas and re-injection of the contaminants. Since conventional technologies become less ec me.� Therefore interpretation of the field structure is largely dependant upon 3D seismic surveys conducted in 1990 1998 2001 and 200 les together. Introduction North Sea oil and gas production from mature basins face some particular challenges against a backdrop of prod ntial to maximize recovery.� For reservoirs with gas cap expansion as the dominant drive mechanism a concurrent oil and gas develop

mic survey gave a multi-disciplinary team the challenge to improve in identifying more attractive targets while reducing the downside drilling ee of freedom left is the way the injector and producer wells are operated. The waterflood design we are looking for should be optimal in the ed by crestal gas injection. Gas is injected into the reservoir for two reasons: disposal of produced gas from St. Joseph and neighbouring fie and fed into the well inflow models and dynamic models to improve productivity estimates long-term reservoir performance prediction and mic impedance that is computed from the time-lapse seismic data. The change in seismic impedance is highly sensitive to changes in satur classified broadly into two categories. The first category consists of local methods such as finite-difference-gradient (FDG) (Bangerth et al. 2 sical model. Introduction The ARM project is a unique experimental program between CSIRO Petroleum and Curtin University of Technolo nd reliable framework for history matching and naturally lends itself to uncertainty quantification. Introduction The optimazation of a reservo tool. The field test outcome demonstrates the reliability expediency rigor and computational efficiency of our stochastic history-matching a conomic viability of wells that need such fluids. The insulation usually is achieved by reducing or eliminating the packer fluid’s natural c sed to achieve optimized waterflood-management strategies and increased oil recovery. Introduction Waterflooding is often applied to incre r to enable building and using such an understanding as part of field development planning and of reservoir management we developed an ction instabilities are undesirable and play a crucial role in the production lifetime and ultimate recovery of any reservoir. These instabilities c t to location and dimensions can be explored. This brings new challenges in e.g. exploration drilling and production. Furthermore existing r

njection management ‘model-based’ control algorithms for ‘intelligent’ completions business planning and similar areas of th aphically complex containing over 500 separate Miocene reservoirs within elongated fault block structures (Figure 1). The Miocene reservoi inear and do not lend themselves to analytical solutions. The high velocity of the gas near the wellbore results in a high capillary number w

lation and management. Efficient coarsening of the fine-scale model is a potential choice to alleviate the problem and has been addressed roduction With no doubt reservoir simulation is one of the most effective tools for reservoir engineers. Nowadays numerical simulation of oi eity of the porous media e.g. porosity hydraulic conductivity or permeability1 2 3. Reservoir simulation is often used to capture quantitative

ongst the studied GOM reservoirs cannot mean absolute compartmentalization and in this paper we show the evidence of such a behavior he history-matching process. The geomechanically simulated fracture trend model is calibrated to both production data and the reservoir geo in this paper is suitable for other naturally fractured reservoirs especially in the Middle East area where a significant difference between co gravity drainage from a homogeneous stack. We compare fine-grid single-porosity simulations (in which the matrix is finely gridded and in w

xample of advanced technology implementation in GOM multi reservoir setting is the deployment of an integrated field-planning tool linkin

plines and optimize the result. Uncertainty analysis such as Monte Carlo techniques will however take a considerable amount of time due reservoir model updating avoiding much of the problems in traditional EnKF associated with instabilities parameter overshoots and loss o etical ground for a homogeneous cylindrical reservoir. Some of the existing techniques depend on knowledge of the reservoir size and shape so as a systematic approach enhance the understanding and use of such a complex model. ave been used to create a series of 2D cross sectional dynamic simulation models covering the range of depositional environments and a

g the model that better tracks the historical performance data. By initiating the full-field history-matching process with the geologic model th untries has over the past 5 years taken on an increased level of importance and scale both in terms of the volume of overall capacity and t ater production. There are several correlations in the literature and commercial packages dedicated to fitting water cut trends during oil dec lity to perform accurate reservoir simulations. Although the current generation of flow simulators is able to model thermal effects within the r drainage and imbibition capillary pressure functions in dynamic reservoir simulation. This model takes into account the complex pore size d the Jurassic Safa sandstones overlying the Paleozoic basement (Fig. 2). This perseverance paid of with the 2001 NEAG JG-1 well which a s. The flow reversal concept motivates a new line of inquiry for lab and field scale experiments. 1. Introduction Dispersion is the in-situ mix

d reservoir pressure is found to be consistent with new material balance and reservoir simulation results. This approach has clearly provide of 165 m. The main oil bearing reservoirs the Shuaiba and Kharaib formations are separated by a very low permeability oil bearing zone c locks to drive oil from matrix rock into the fracture system. In densely fractured reservoirs one relies on mechanisms like capillary imbibition nt effects. Introduction The connected fracture network in densely fractured reservoirs has a strong impact on reservoir displacement mecha Introduction The Schoonebeek oilfield (onshore NE Netherlands) was abandoned in 1996 for economic reasons after having produced 4 Sensitivity analysis shows that recovery factor heavy hitters of updated models are significantly different from initial models. MCSBM show duction From 1985 to 1987 the government of Alberta represented by AOSTRA built the Underground Test Facility (UTF) whose purpose of this sour oil reservoir along with presenting the development approach that has been taken for injecting sour gas to increase oil recovery s such as large faults are well localized. Geologically Pierce consists of many turbiditic sand-shale sequences adding to the complexity. Sin ation with: The loss of reserves The amount of hydrocarbons released to the environment the size of the area affected and the cost of c ess processes and workflows required to manage a mature field appear to be similar for many operators.� The majority of the technolog fficient good production information. DOF is inherently multi-disciplinary e.g. Production Instrument Reservoir Engineer Petroleum Tech became a favored completion mode for completing in long openhole soft-rock formations with wells providing the capability to deliver high ain. It won’t be for the faint hearted. Disadvantaged resources The volume of hydrocarbons discovered over the last 100 years shows a ng in STOS has significantly improved gas production. Sandstone matrix acidizing campaigns in 2004 brought 9000 boepd of gain in assets le in defining the boundary conditions for the injectors design. Background Industry-wide experience in the execution and the operation of valuated. The results from both of these studies demonstrated that even in the presence of significant random noise production induced 4

s in water-drive reservoirs where detailed dynamic simulation is not justified. It furnishes a comparatively quick fit-for-purpose approach to id

zonal wells the FieldWare PU models built using surface and downhole test data and an understanding of well performance� provides re

100 and 160 ft respectively along the hydraulic fracture azimuth. These conclusions are compared to tiltmeter data microseismic data a

reservoir layers so multi-rate production logging and well testing surveys are valuable methods to estimate the layer flowrates pressures p

rs. Incomplete gravel packing development of hot spots" in screens destabilization of the annular pack fines migration sand screen plugg ure reopening/closure cycles as well as real-time permeability composition or anisotropy interpretation to determine optimum transient dur tiltmeters is used to analyze the case studies in this paper. The second area of study is forward modeling to predict the subsidence. Two m

ter cut where high water holdup and water velocity would likely be encountered downhole. Once the water producing zones are identified w ata with simulation modeling predictions demonstrates the benefit of the data acquisition and evaluation methods. Discussion is focused on with trace oil and high gross flowrates. The second and third field examples in this paper illustrate the use of a fit-for-purpose oxygen activa

ure that was introduced to the region in Late 2003.� Acid stimulation in Shell Asia Pacific region has not been very active compared to oth at operate marginal oil wells will find openhole completion on horizontal wells useful to enhance production rates.� Even the majors will a the formation. During an inhibitor squeeze treatment a predetermined volume of the inhibitor solution is pumped into the formation and foll ility to measure the inflow from each zone. Using downhole instrumentation this can be done directly with downhole flowmeters or more in

te that it is possible to use foam to create a pressure profile within the narrow window between continuously changing pore-pressure and fr dustry in Brunei Darussalam started as early 1930’s where wells were mostly explored onshore and shallow marine environment. The f decrease cost by placing smaller size treatments that would still deliver the same production as the larger less effective treatments. It is w

tal or deviated wells this is often a zonal phenomenon which occurs at a limited amount of perforations and is referred to as ‘cresting†cores withstood 42 500 kPa/m (1 880 psi/ft) for a long period of time. Emulsions were optimized to seal cores with different permeabilities fo completions. Because the initial kickoff and cleanup are highly transient processes (Mantecon et al. 2004) a transient multiphase-flow sim

the foam reduces the liquid mobility by reducing the gas mobility in flowing fraction of foam [8]. Foams have been also used to improve the y works have been devoted to foam the study of the effect of core media heterogeneity has been minimal. A variety of methods have been proposed a stochastic bubble population (SBP) model based on the following main postulates: (a) foam rheology is described by the Hersch ool or coiled tubing string. Introduction When there is sufficient reservoir energy and gas wells can be produced at medium to high rates co

served loading points within 20% accuracy. Introduction Liquid loading that is the process when the gas is no longer able to lift liquid to the if the formation properties are similar to Cold Lake. Potential adverse impact of skin damage under Peace River conditions could invalidate sub-optimal well performance poor decision making in the area of sandface completions and undue belief in the value of allegedly perform ed expectations.� The propellant-assisted perforating technique applied in three subsea wells in heavily karstified carbonate reservoirs ed in November 2003 transported via a 25-km multiphase gas pipeline at 70-bar backpressure to a processing platform (AMDP06). Three o rawak Shell’s Shallow Clastics field consists primarily of two shallow gas-bearing reservoirs H1 and H2 at approximately 2 650 ft TVD f water (Figure 1). The primary producing interval in both fields consists of an unconsolidated turbidite amalgamated sheet sand with evide earing reservoirs H1 and H2 at approximately 2 650 ft TVD. These reservoirs are laterally extensive covering an area of 200 km2 with an e ction and whilst an undesirable part of the production stream it is seen as an inevitable component for the continued production of hydrocar

racturing or acidizing. Also gravel-pack fluids are defined as fluids used to place filtration media to control formation sand production from o y optimising pumping procedures. Indication of diversion was observed compared to previous practices. Stimulation cost is less than that of IFO test analysis appeared to be systematically lower than the predicted ones and a number of explanations for this difference are present

of the late time reservoir pseudo-radial flow found in the well tests. In addition an example well exhibiting a loss of layers (i.e. reservoir pe

logging old core data was used to refine the constants used in the Timur-Coates MR permeability equation. MR permeability showed chan aths and casings as explanations for the observed overprediction. Therefore estimates on the basis of pure water properties considering th nyx SW was planned as a vertical exploration well with a HTHP pressure regime. The HPHT conditions in the well were marginal; however and dynamic reservoir information such as petrophysical data core analysis well tests production logs and single probe wireline formation gh. What is the optimum? - What are the minimum purge and test times for a given well at a given point-in-time? - What can be done t

d – in deep saline formations or redundant reservoirs or for enhanced oil recovery. Considerable attention is being focused on CO2 stora ereby reducing emissions of industrial CO2 as a greenhouse gas (Plug 2007). The efficiency of CO2 sequestration in coal seams strongly d upt such a structure which results into coal swelling. A CO2 molecule placed between the polymer chains of coal disrupts partly the origina ons in some basins the emergence of injection schemes for enhanced coalbed methane (ECBM) and carbon sequestration of greenhouse

emits the least amount of CO2 per unit of energy released. Therefore the zero option of CO2 sequestration and production of methane lea method was successfully applied in two wells with extensive core data. In the third well where few core data exist the section was charact

ding of the role of CO2 capture and geologic storage and strategies to improve its performance and prospects. The workshop brought to bles optimization and reporting architectures and data management processes to adapt to changes faster with less effort and fewer errors. ed future and digital. There was no question that the changes in the world of managing production operations would require new procedur

is used in isolation and no interpretation is worked in a vacuum without adequately understanding the geological setting and the fluid sourc eloped by Shell to address fundamental gaps in the management and surveillance of oil and gas production operations. The development b itoring resolved hydrocarbon allocation problems through real time reconciliation allowed an increase in time between well tests and reduc e benefit to end users. This paper discusses Shell’s experience with PU and it’s application for real time production optimisation o

eservoirs. Facilities are generally old (up to 30+ years) and the asset has suffered from several years of relatively poor reservoir surveillance oduction string rather than a drill string. Following industry convention however we will be using the words drill stem test and conventional dly option. Introduction The focus of this paper is the use of dynamic well testing in exploratory and appraisal wells. Historically the industry

scovery the CW field became the largest undeveloped hydrocarbon resource in Brunei and will support Brunei’s oil and gas productio

ced. Recently smart fields concepts have been proposed as a means to improve control over the water front through detailed adjustments out of the reservoirs in the most cost- effective way. � The concept of ‘Smartness’ is not just about introducing new technology b and provides the data and models for surveillance and reservoir management. In new fields elements of Smart Fields� are evaluated a in a water depth of 40 to 50�m. The area extent of the field is about 12 x 4 km. Although more than 30 wells have been drilled including

turally dipping reservoirs it was recognized at an early stage that a fundamental change from the standard well design was required. Due to s and by as many folks that underbalanced drilling is not a new technology. In its simplest form it is “making hole with cable tool rigs. Th hroughout the well bore. Underbalanced drilling on the other hand the well bore pressure profile is intentionally kept below the pore-pressu eters were based on the combustion tube laboratory experiments.� The impact of combustion on residual oil sweep efficiency and predic e high permeability in the order of several Darcies the minute quantities of impurity and solids present in the injection fluid can plug the san mpatibility with hard water (if present) thermal and hydrolytic stability acceptable cost/performance balance and commercial availability in s are applied to fractured reservoirs. 1. Introduction The connected fracture network in densely fractured reservoirs has a strong impact on re r injection was first introduced as a secondary recovery technique in 19791 (Buffalo Field) to improve upon primary recovery in deep high t employed to mature the reservoirs are given by O’Dell et al1. Implementation of miscible gas injection from day one of full production se ry [16]. Recently Zitha [17] examined the strengths and limitations of the available models. In order to capture more realistically the physics d 65 to 70 meters (Fig.-1). The production license was awarded in 1977 and the field was discovered in November 1979. Gyda was declared

structure is a result of a deep salt diaper with significant crestal faulting and fracturing. The field was discovered in 1972 and placed on prim

reservoirs has been developed into an emerging IOR technology aiming for improved microscopic sweep efficiency with reduction in remai s. This is a step change in the ability to manage detrimental gas production in this field and is expected to lead to further opportunities for im ther natural or through water injection is probably the most important recovery mechanism for oil production from oil-bearing rocks.�In a were completely sealed off and isolated and subsequently re-perforated shallower. After slurry placement and squeezing it is important to natural or through water injection is probably the most important recovery mechanism for oil production from oil-bearing rocks. Consequen um. The slow recovery observed in the case of imbibition after wettability modification is in excellent agreement with the assumption that in delled in isolation using simulation programs. Analysing the upstream supply chain in an integrated manner compared to looking at the ind hness it implies. Theorists interested in optimization have been too willing to accept the legacy of the great eighteenth and nineteenth-centu usly reducing downtime equipment redundancy and minimizing operating and capital expenses? Whilst these are not new questions espec 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 re formation near VIT miscibility. This experimental study confirms the robustness of the VIT technique for accurate quick and cost-effectiv

n extremely hazardous toxic compound that occurs in a number of natural and industrial environments. Naturally it can be found in coal pit mechanism at work in many stacked reservoirs results in each reservoir filling up by petroleum spiraling up from deeper reservoirs via faults mpared to PVT lab results. Both the OBM contamination monitoring and the GOR algorithms work well for most crude oils. However for he ganic deposits such as asphaltenes emulsions separation problems and high viscosities. Analytical chemistry can play a significant role in reased below the bubblepoint of the sample as lighter hydrocarbon components evolved. The measured viscosities increased as much as 5 ither intermediate-wet or mixed-wet can result in improved oil recovery through the lowering of both capillary and adhesion forces. Introduc

oirs. Introduction The use of HF systems for stimulating sandstone reservoirs has come a long way within the Niger Delta area. Several for

injected fluids more uniformly the injection profile needs to be changed by diverting the flow from one zone to another. Fig. 1 shows an illu

n Three distinct advantages of UBD technology can combine to lower the unit technical cost of a project: Reduction in overbalanced-drillin A general view of the deposition mechanisms across the spectrum of naphthenate “scales from sodium rich emulsions to calcium naph

gone SWB and subsequently were treated with scale squeezes. With this analytical technique the number of wells thought to have SWB wa st) reservoir is extremely difficult. Higher-permeability sands usually act as a thief zones with respect to the tighter sands open in the same w

eld (Field B) contains very viscous oil (16 API 550 cP) in a low permeability (5-20mD) limestone matrix. Based on observations of high fract s of the Peace River field. The model is suitable for sensitivity studies of geological petrophysical and fluid properties. It is also capable of gh water cut increased. The solution to high water cut wells productivity enhancement was accomplished in 2001 through detailed candidat ls (and not only on the shape and dimensions of a matrix-block) hydraulic- and thermal shape-factors should a priori be regarded as indepe It has a sufficiently high water saturation (greater than 30%) to allow fluid injection at initial conditions with reservoir temperature of 16.7 deg c reservoir fluid models for graded reservoirs (or reservoirs with high grading potential) have also been investigated. Introduction Grading in ressured and contain sour light hydrocarbons. Over 60 wells have been drilled in and around these fields. The initial wells have a shallow 1 ally and take all of the subsequent acid volume. Fredd and Fogler (1998a 1998b 1998c) have proposed the use of ethylenediaminetetraac milar reservoirs carry similar findings.� This paper will summarize the conclusions that are consistent between numerous tight gas field st

eld tests than if production rates were used alone.�Multiple production logs were utilized over several producing months in selected well Pore pressure variability with depth does not follow a linear pattern with intervals in the normal range bounded by layers in the geopressure rmal production in the future when monitoring objectives were met. Obtaining pressure data with dozens of permanent gauges is expensive s in the laboratory when gas flow experiments are conducted at low pressures. Gas slippage is defined as the condition where the mean fre as developments require in-depth understanding of all reservoir units reserves and gas mobility to reduce the project risk. This is especially e been used to further improve project delivery with a focus on technical aspects. Introduction A PSC was signed between PetroChina and e Scene The average permeability cutoff used to define tight gas in the Southern North Sea is 1 mD or 10 times higher than the tight gas cu

skilled people for multidisciplinary discussions to jointly interpret the information to make fast good decisions to improve project delivery and

opening. The production rate increased to 150MMscf/d at 98% choke size as the well cleaned up after seven months. This paper demonstr not explore in detail the consequences of the major variations in two of the prime drivers of value of any project. The actual conditions that project is a multi-year staged capability upgrade that will focus on developing right-time workflows for production optimization including s C) to a level at which water saturation reaches irreducible is referred to as the capillary transition zone. Fig. 1 illustrates a typical capillary tr 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 essure temperature and fluorescence that all play a vital role in determining the exact nature of the reservoir fluid. Extensive tests at a pre

coarse-scale sector model simulations (Fig. 1). High-resolution sector model simulations are performed to capture an accurate representati orizontal stress magnitudes cause large fluctuations in the safe mud-weight window. This challenge in drilling through the depleted sand wa

res) these formations can be highly susceptible to damage (Cippolla et al. 1988). The literature shows that the use of foamed treatments (C ately using an equivalent homogeneous porous medium with a dispersivity of 0.5 ft. In our measurements permeability decreased with sca ation is to use downhole borehole imaging technology to provide an image with the appropriate resolution thereby allowing in situ permeabi servoir fluids and hence it is presumed a signature of the reservoir being drilled. Moreover the signature is available while drilling which a echanical layer characteristics such as porosity and layer thickness (1 2). The boundary between layer-bound fractures and fracture corrido d in WNW or NW the dominant fracture corridor directions in this particular field the likelihood of having a fracture corridor increases.� F f facilities and completions equipment and production prediction. Traditionally drillstem testing or extended well tests are the preferred met uch as Downhole Fluid Analysis (DFA) mud-gas analysis and geochemical fingerprinting can be integrated with geologic data to better asse nt data streams a much more robust picture of the reservoir fluid distribution becomes clear. Introduction Traditionally mud gas analysis h onsists of 23 fields and is located in the south of Oman Fig.1. The fields in the cluster are characterised as green and brown. By “brown eover the wettability is likely to vary over the reservoir and possibly also over time as a result of changing saturations during production. In

ervoir quality is best in the L80 with excellent porosities of 20-26%.� Volumetric reward however is only modest due to the limited vertica evelopment of the discoveries as well as the near field potential remaining prospects. Introduction CS Mutiara Petroleum is a Petronas Ca echnologies become less economic at increasing percentages of contaminant the new technologies are specifically targeted at high conce

aturation studies of this type can take a long time and may lead to restrictions on the availability (quantity and timing) of the gas volumes to t ed in 1990 1998 2001 and 2004 and the associated seismic time-to-depth conversion work. The latter three surveys included 4D-seismic n West Siberia 120 kilometers south west of Surgut (Fig. 1) and is a part of the Salym group of oil fields developed by Salym Petroleum Dev

rapped mud rich unconfined turbidite systems in a mid-lower slope setting. Sediments were deposited during major sea level low stands wh

y deep-water turbidite sandstones of Eocene age in a large low relief structural/stratigraphic trap.� The high reservoir quality (porosity 3

using such an understanding as part of field development planning and of reservoir management we developed an ‘add-on’ fracture tal wells have been developed. Heavily aided by experimental design a unique phased modeling workflow was applied to optimize well de approximately 175 km north-northwest of Bintulu in a water depth of 280 ft.� The field was discovered in 1969 and is the largest gas field is the operator of the Sakhalin II Development offshore Sakhalin Island which is located off the east coast of Russia north of Japan (Fig. 1 y-recovery phase of a petroleum reservoir using waterflooding. In this case a number of injection and production wells are drilled to preserv inating later with the roll out of 23 field development plans. The study started in Oct 2003 and by end 2005 delivered 6 value-assured FDPs e Tunu catchment area is made up of Tunu and Kanbo fields and the flowstation is located in Tunu while the Ogbotobo catchment area ha e north coast of the island of Borneo (Fig. 1). The CPSE field is located in 10 to 45 m water depth at a distance of approximately 40 km nort ver Azlean. It is an offshore field with water depth ranging from 20-40 m .This field was discovered in 1985 and put on production in 1993. T urces are fully depleted. Both East Asia and Europe have low recoverable gas resources and high imports. Europe is strategically located to densate and pure elemental sulphur as a by-product. In its enormous scale and complexity the onshore project is equivalent to some of th nent field tests. It is expected that the now gleaned information will provide much improved input for simulators modelling fractured injection t and quality of water at many points along their ‘value chain’. Relatively large volumes of fresh water are used as raw material as c on Historical perspective Most engineers and managers confuse Process Control with Instrumentation; i.e. they think Process Control is on n to increase oil production and reduce the water cut. Production logging was carried out to identify the flow profile. This was followed by pu

nga field (Fig. 1) lies on the continental slope in the southern part of the Niger Delta some 120 km offshore southwest of Warri in Nigeria ed. Additional laboratory experiments also reported in this paper were performed and did not indicate any issue with respect to the predicte RI pilot and the observed effects when applying nitrate are discussed in this paper. Because of the negative side-effects observed when app

d in April 2003. By end of April 2003 the injection water source was switched to produced water as separated in the in-line separator at the . Particular attention is paid to the reservoir wettability and the importance of the shape of the relative permeability curves in determining th ement scenarios within a shorter amount of time compared to a single optimal location found through manual optimization. Introduction De ose of Phase 1 was to gather data to determine whether a miscible gasflood would be feasible in some of these reservoirs. Phase 2 tentativ ntional technologies become less economic at increasing percentages of contaminant the new technologies are specifically targeted at high ducted in 1990 1998 2001 and 2004 and the associated seismic time to depth conversion work1.� The latter three surveys included 4D hallenges against a backdrop of production from platform and subsea wells in a challenging offshore environment.� These offshore field d m a concurrent oil and gas development is less attractive. It is however still feasible and should still be considered.

while reducing the downside drilling results observed during the infill campaign. A combination of the new structural data with a regional geo e looking for should be optimal in the lifecycle sense i.e. it should maximize the lifecycle integral Equation (1) where the integrand is a we rom St. Joseph and neighbouring fields and reservoir pressure maintenance.� A feasibility study completed in the second quarter of 200 servoir performance prediction and to support development planning and reservoir management. This paper summarises all of the refinem highly sensitive to changes in saturation and pressure in the reservoir; these changes can then be related to the porosity and permeability1 ce-gradient (FDG) (Bangerth et al. 2006) simultaneous-perturbation-stochastic-approximation (Bangerth et al. 2003 Spall 2003) and Nelde um and Curtin University of Technology that has been devised to investigate issues relating to uncertainty in reservoir simulations of channe ction The optimazation of a reservoir development strategy is measured by its robustness under the influence of uncertainty. In addition to e y of our stochastic history-matching and recovery forecasting framework. Introduction Motivation. Optimalilty of a reservoir development str ating the packer fluid’s natural convection which would otherwise amplify heat transfer across the fluid. For a non-insulating fluid the co Waterflooding is often applied to increase the recovery of oil in mature reservoirs or to maintain the reservoir pressure above bubblepoint in t voir management we developed an ‘add-on’ fracture simulator to our existing in-house reservoir simulator4. In the past several atte of any reservoir. These instabilities can arise from or be governed by the interaction between the well and the reservoir.1 Production instabil d production. Furthermore existing reservoirs require new insights to be able to increase its ultimate recovery. Dedicated simulation software

ness planning and similar areas of the E&P business characterised by continuous data and where the independent variables could be engin es (Figure 1). The Miocene reservoirs were deposited in a shallow-marine to costal-plain environment in the Champion delta system.� Th results in a high capillary number which may increase the relative permeability of the gas significantly and add to the complexity and nonli

e problem and has been addressed by several researchers. Original grids may be coarsened to generate structured or unstructured grids e Nowadays numerical simulation of oil reservoirs plays an important role in petroleum science and engineering. The main input to reservoir s is often used to capture quantitatively and represent the effect of heterogeneities on displacement performance on the reservoir scale. Res

ow the evidence of such a behavior. Subject reservoirs contained fundamentally different fluids exhibiting an areal compositional grading in roduction data and the reservoir geological structure (faults and horizons) by searching for the optimum remote stress condition for elastic s e a significant difference between core-derived permeability and well-test-derived permeability exists. Introduction This paper presents the h the matrix is finely gridded and in which the fractures are explicitly represented) with coarse-grid dual-permeability simulations (in which th integrated field-planning tool linking individual reservoir models to a surface facility network model. This tool manages overall system flow

e a considerable amount of time due to the high number of iterations around the integrated model. Using Monte Carlo in a post processor us es parameter overshoots and loss of geologic continuity. We illustrate the power and utility of our approach using both synthetic and field ap edge of the reservoir size and shape and assume homogeneous properties (Horner 1967; Miller et al. 1950; Matthews et al. 1954; Dietz 19

of depositional environments and a range of connectivity scenarios. The main conclusion of this study is that water is the preferred injection

process with the geologic model that most closely matched the field performance in the screening stage the amount of history matching w the volume of overall capacity and the number of storage sites that are in operation. This trend appears set to continue over the coming de fitting water cut trends during oil decline. In general these correlations can be divided into three main classes: (1) using fractional flow theor to model thermal effects within the reservoir the wellbore flow models linked with these simulators often lack comprehensive thermal capab nto account the complex pore size distribution and wettability characteristics in carbonates as observed in experimental special core analysi h the 2001 NEAG JG-1 well which at a depth of 3 250 mbdf found three oil-bearing channel sands in the tidally influenced estuary deposits duction Dispersion is the in-situ mixing of chemical components as they are transported through porous media. It results from the combine

s. This approach has clearly provided vital information to underpin the recoverable reserves associated with the miscible gas injection. Intro y low permeability oil bearing zone called the Hawar. The crest of the Shuaiba is located at 212 mss and the original oil water contact is ~3 mechanisms like capillary imbibition or gravity to recover oil from the matrix reservoir rock. Fractured carbonate reservoirs are commonly oi act on reservoir displacement mechanisms. Once a gas cap is established in the fracture system the oil will drain down the matrix rock driv mic reasons after having produced 40 million m3 (250 million bbl) of its 160 million m3 (1 billion bbl) STOIIP from 597 vertical�wells. Due nt from initial models. MCSBM shows that the production updated modeling parameters have smaller uncertainty ranges than the prior unce Test Facility (UTF) whose purpose was to prove the SAGD concept. The first SAGD pilot was run from 1987 to 1990 under the name of Ph ing sour gas to increase oil recovery in this remote South Oman reservoir. Introduction The purpose of this paper is to present the develop ences adding to the complexity. Since 1999 the field has been developed under depletion drive with gas re-injection. In 2004 water injectio of the area affected and the cost of clean-up operations after the event (Oudeman 2005) The complexity of the efforts to regain control ov rs.� The majority of the technologies that we require to create Smart Fields are already in place although we did identify seven specific a Reservoir Engineer Petroleum Technologist Process Engineer Telecoms Information Technology Chronology and Associated Learning†roviding the capability to deliver high production rates (Ghiselin 1996; Harrison et al. 1990; Marestad et al. 1996).�This technique is still b ered over the last 100 years shows a golden age in the 1960s and 1970s where over 600 Bln bbloe were discovered in the decades (see Fi ought 9000 boepd of gain in assets in Brunei and Malaysia with high success rate (no failure was recorded). Confidence level of stimulatio n the execution and the operation of waterflood projects in deepwater environments is relatively limited. With relatively few analogs the Ursa random noise production induced 4D changes should be observable if the monitor seismic survey is acquired in or beyond 2006. These res

y quick fit-for-purpose approach to identify further development opportunities and furnish input for the planning of detail dynamic simulation w

of well performance� provides regularly validated estimates of zonal production rates using real time surface and downhole data. Using

tiltmeter data microseismic data and a simulation history match of pilot performance. Microseismic events recorded in the pilot are appare

ate the layer flowrates pressures permeabilities skin factor of individual layers and distance to and type of boundaries. A surveillance log

fines migration sand screen plugging near-wellbore damage crossflow differential depletion compartmentalization compaction represe to determine optimum transient durations. This paper describes several examples of formation tester surveys that have been remotely mo ng to predict the subsidence. Two methods are used: numerical modeling and analytical/semianalytical modeling. Numerical modeling for re

er producing zones are identified water shut-off solutions can be subsequently designed for the purpose of restoring the well’s oil prod methods. Discussion is focused on best practices learned during the 12 year program how log responses have helped verify modeling par se of a fit-for-purpose oxygen activation technique for positive identification of water movement behind pipe. It is not uncommon to find chan

not been very active compared to other regions. The cause of the relatively low stimulation activity varies. Major factors that limit the stimula ion rates.� Even the majors will agree that prevention based on experience and sound engineering practices is better than cure for most s pumped into the formation and followed by injecting another volume of brine or diesel to place the inhibitor further away from the wellbore with downhole flowmeters or more indirectly through “soft sensing (i.e. through interpretation of pressure and temperature data from su

ously changing pore-pressure and fracture pressure gradients which is not possible with conventional fluids. Those responsible for hydrauli d shallow marine environment. The fields straddle along the coastline about 120 kilometers from Bandar Seri Begawan to Kuala Belait. Tali F ger less effective treatments. It is well documented in the literature that hydraulic fractures often underperform: Frac and Pack completions

and is referred to as ‘cresting’ (Figure 1). At a certain moment in the production life of a gas coning well the gas-oil-contact will reac cores with different permeabilities for the purpose of field application. A novel cost-effective sealant that uses heavy oil-in-water emulsion t 04) a transient multiphase-flow simulator was used for modelling. The wells were simulated from initial startup until early in their production

have been also used to improve the oil recovery of some fields [9-11]. The success of a foam application relies on the properties of rock and al. A variety of methods have been proposed for modeling of foam flow and displacement in porous media. These models include fractiona rheology is described by the Herschel-Bulkley12 model i.e. below the yield stress it does not flow and above the yield stress it obeys a po produced at medium to high rates co-production of liquids is seldom a problem even at high liquid to gas ratio’s (LGR). Although the liq

as is no longer able to lift liquid to the surface is a major limiting production factor for maturing gas wells. Solutions such as gas lift soap inje ce River conditions could invalidate our conclusions; this should be confirmed by the testing of LEPs in the field. Introduction Studies show elief in the value of allegedly performance-enhancing perforating services. The work also brought into focus critical issues such as the indu avily karstified carbonate reservoirs has proven that this technique can offer a highly effective stimulation method across the entire perforat essing platform (AMDP06). Three oil rims in the Egret field were confirmed by an appraisal well in Q4 2003. The main objectives of their de d H2 at approximately 2 650 ft TVD. These reservoirs are laterally extensive covering an area of 200 sq km with an estimated gas in place amalgamated sheet sand with evidence of pressure communication through the hydrocarbon leg. Aquifer support does not exist within this vering an area of 200 km2 with an estimated gas �in place (GIP) in excess of 2 Tcf. The reservoirs are made up of a sequence of highly he continued production of hydrocarbons in many fields. For these production components co-production with the hydrocarbons is accepte

rol formation sand production from oil and gas wells. The objective of this document which is based on the ISO 13503-4 is to provide a sta Stimulation cost is less than that of using coiled tubing. Background In Malaysia under the Production Sharing Contract (PSC) with Petron ations for this difference are presented in the paper. 1.�� Introduction Injection Fall-Off (IFO) test analysis offers one of the cheapest

ting a loss of layers (i.e. reservoir permeability thickness (kh)) with production and the restoration of reservoir kh with remedial stimulation su

ation. MR permeability showed changes in reservoir quality. Values will be calibrated when Timur-Coates constants are derived from the cor pure water properties considering the annulus to be a perfectly pressure-tight vessel can be considered a worst-case estimate for pressure s in the well were marginal; however it was designed and executed as if under full HPHT conditions. Maximum anticipated surface pressure and single probe wireline formation tests in order to obtain accurate interpretation results of highest consistency. Field examples will be dis oint-in-time? - What can be done to ensure that the quality of the test result is adequate? - What performance indicators can be put in-p

ntion is being focused on CO2 storage with the desire to reduce the cost of capture and storage below 25 $/t CO2. Shell has a special team questration in coal seams strongly depends on the coal type the pressure and temperature conditions of the reservoir (Siemons et al. 2006 ins of coal disrupts partly the original structure if the sorption takes place in locations where the available volume between the chains is sma carbon sequestration of greenhouse gases has led to renewed focus on the behavior of coalbed reservoir properties under these conditions

ration and production of methane leads to greater utilization of coalbed resources for both their sequestration ability and energy content. Th e data exist the section was characterized successfully by analogy. Introduction Since the publication of the Intergovernmental Panel on C

ospects. The workshop brought together experts from academia business governments and intergovernmental and nongovernmental o ter with less effort and fewer errors. PRODML has therefore become a tool which can be used in implementing robust trustworthy optimizat erations would require new procedures new technologies and new data solutions for acquisition processing and analysis. This situation le

geological setting and the fluid sourcing migration and trapping mechanisms. Introduction Fluid properties are obviously key parameters ction operations. The development background and early operational experience of FW PU within the Shell Group are described in Poulisse n time between well tests and reduced travel to field locations.� The availability of real time production data is a key enabler for future sm or real time production optimisation on the Nelson platform in the UK sector of the North Sea . The paper describes PU how the application

relatively poor reservoir surveillance low levels of (well and facility) intervention activity and slow response to performance anomalies part ords drill stem test and conventional test interchangeably throughout this paper. This type of testing in which we flow the hydrocarbons direc praisal wells. Historically the industry called this a drill stem test but most modern exploratory and appraisal tests use a dedicated productio

t Brunei’s oil and gas production (340 mln Boe) for the next 20 years. Peak oil production is expected end-2006 to be around 50 000 b

r front through detailed adjustments of the injection and production rates in time using a combination of model-based flooding optimization about introducing new technology but focuses on inventive ways of using and integrating existing technologies. Smart Fields now use dow of Smart Fields� are evaluated and implemented from the start (eg. Ref. 1). Smart Fields� Concept The Smart Fields� concepts gr 30 wells have been drilled including a number of appraisal sidetracks less than 20 percent of the estimated reserves have been produced s

ard well design was required. Due to the high number of stacked reservoirs the multilateral concept was not an option because of cost and œmaking hole with cable tool rigs. The next evolution was rotary air drilling followed by air hammer drilling; underbalanced techniques design ntionally kept below the pore-pressure of all the exposed formations in the well bore. In be-tween these two extremes are various technique dual oil sweep efficiency and predicted project lifetime is presented by comparing isothermal EOS-simulations and multi-component combu n the injection fluid can plug the sand face over time and lead to fracturing if the injection rate is to be maintained [1]. Even in the absence o ance and commercial availability in sufficient quantities. Because of the well-established relationship between the micro-emulsion phase be reservoirs has a strong impact on reservoir displacement mechanisms. Conventional displacement methods such as water flooding do not pon primary recovery in deep high temperature low relief low permeability reservoirs. Since its first application air injection has been appli on from day one of full production sets this project apart from others in the world where miscible gas injection is mostly used as a tertiary or apture more realistically the physics of foam motion in porous media Zitha [17] developed a new stochastic bubble population (SBP) foam November 1979. Gyda was declared commercial in 1986 and PDO was approved by Norwegian authorities in June 1987 and production co

scovered in 1972 and placed on primary production in 1975. The 16� API oil with a viscosity of 220cP has been produced from the 29% p

ep efficiency with reduction in remaining oil saturation as result (Tang and Morrow 1997 1999 2002; Maas et al 2001; Webb et al 2003 a to lead to further opportunities for improved gas management and well performance in this field and other fields where the GOGD recovery ction from oil-bearing rocks.�In a layered reservoir this will cause water breakthrough in the high-permeability layers leaving oil behind i ent and squeezing it is important to ensure that a good cement job has been performed. Operationally the top of cement (TOC) is tagged n from oil-bearing rocks. Consequently water is produced together with the oil. Generally oil production decreases with the maturity of an a eement with the assumption that in the absence of significant spontaneous imbibition the WM to unfold its action must first diffuse into th nner compared to looking at the individual elements is becoming increasingly important in the current business because the system bottle eat eighteenth and nineteenth-century mathematicians who painted a clean world of quadratic objective functions ideal constraints and eve these are not new questions especially for the Russian gas and oil industry with its breadth of experience in these areas that has been acc 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 or accurate quick and cost-effective determination of gas-oil miscibility conditions. 1. Introduction Minimum miscibility pressure (MMP) is

Naturally it can be found in coal pits sulfur springs gas wells and as a product of decaying sulfur-containing organic matter particularly u up from deeper reservoirs via faults and other pathways by hydraulic leakage from the crest of the underlying reservoir or by capillary leak for most crude oils. However for heavy (dark) oils the contamination prediction from the methane component and the GOR prediction bec emistry can play a significant role in the characterization of complex fluid systems such as crude oil and ensure optimal utilization of reservo d viscosities increased as much as 500% because of the presence of emulsions before a sharp drop in viscosity beyond the inversion point illary and adhesion forces. Introduction The addition of surfactants to the injection water can lower oil/water IFT and alter the wettability of

hin the Niger Delta area. Several formulations and trials with Mud Acid systems have been improved upon via the new HF system which ha

zone to another. Fig. 1 shows an illustration of a successful diversion treatment. An FPS was used to simulate the flow profile in two zones w

t: Reduction in overbalanced-drilling problems Reduced formation damage Dynamic reservoir evaluation while drilling However in low-c dium rich emulsions to calcium naphthenate deposits was recently put forward by Sorbie et al.11. This work took the view that in order to p

er of wells thought to have SWB was reduced from 18 to 3 with 3 more where SWB is expected soon. Due to this the amount of scale squ the tighter sands open in the same wellbore. This results in poor injection profile due to the appearance of preferential steam paths. Conseq

Based on observations of high fracture density in all Shuaiba fields in the GSB and following the successful SAGOGD pilot project in the ne luid properties. It is also capable of assessing impact of well configuration spacing steam quality and steaming strategy. Introduction Pea d in 2001 through detailed candidate selection recipes design and pumping method1. The need to reduce the cost of the retarded HF acid hould a priori be regarded as independent quantities that are not necessarily equal.�� There has been much discussion about (hydra ith reservoir temperature of 16.7 degree C. The pressure cycle steam drive process 1979-19901 made use of the BTZ for steam injection. C nvestigated. Introduction Grading in hydrocarbon reservoirs are due to a combination of gravitation diffusion (molecular and/or thermal) an ds. The initial wells have a shallow 13.3/8 surface casing a long 9.5/8 production casing and a cemented 7 liner over the reservoir section. d the use of ethylenediaminetetraacetate (EDTA) chelating agents as the primary active components in fluids used to stimulate limestone a between numerous tight gas field studies in the region and highlight changes to fracture treatments which have consistently improved well

al producing months in selected wells and are crucial to the production history match process.�A wide variety of proppant products are in ounded by layers in the geopressured zones. For this reason individual production intervals must be hydraulically fractured in isolation with ns of permanent gauges is expensive but we are convinced that given the significant impact on estimating gas in place recoverable gas dr as the condition where the mean free path of the gas molecules is no longer negligible compared to the average effective rock pore throat ce the project risk. This is especially true in new country entries for exploration where well sequencing decisions are critical to effective app as signed between PetroChina and Shell in 1999 to develop the Changbei Gas Field this was followed by an extensive evaluation and app 10 times higher than the tight gas cutoff of 0.1 mD used onshore USA. The difference is due to the much higher offshore Europe well cost w

sions to improve project delivery and enable better field performance. Introduction As the E&P sector increasingly taps the world’s “

seven months. This paper demonstrates how good PROSPER modelling integrated decision matrix and persistence on sound engineering y project. The actual conditions that prevail however almost never equal point forecasts that have been assumed for design whether one production optimization including solutions that integrate the shared earth model with real-time production and drilling information in a ‘ Fig. 1 illustrates a typical capillary transition zone in a homogeneous reservoir interval within which both the oil and water phases are mobil is roughly correlated with fluid density: high-density fluids have a low GOR value and low-density fluids have a relatively higher GOR value. ervoir fluid. Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large numb

to capture an accurate representation of the geologic detail. Coarse-scale and high-resolution sector model simulations are used together drilling through the depleted sand was successfully handled by using special drilling fluid to mitigate seepage losses and the differential stick

hat the use of foamed treatments (Cippolla et al. 1988) 100 mesh and low gel loadings can be used to stimulate these reservoirs effective ts permeability decreased with scale while vug connectivity and multi-scale effects associated with vug connectivity decreased with increa n thereby allowing in situ permeability estimation without the need for core samples. Introduction Permeability is arguably the most impor re is available while drilling which allows discrimination between progressively exposed reservoir sections. If unraveled this signature gives bound fractures and fracture corridors is arbitrary and fuzzy since the width and fracture spacing near faults depend on mechanical characte g a fracture corridor increases.� Final result shows most fracture corridors are located on the southern and northern flanks of the field wit ded well tests are the preferred methods to test for compartmentalization in exploratory wells. However in a deepwater well or similar settin ated with geologic data to better assess reservoir continuity and/or compartmentalization before field development commences. From these on Traditionally mud gas analysis has consisted of a basic low efficiency mud gas extractor coupled to a slow low resolution GC-FID gas d as green and brown. By “brown we refer to high gross liquid production rapid water cut development variable well performance and m ng saturations during production. In current practice wettability is poorly known; if identified at all it is determined on a few core samples a

nly modest due to the limited vertical relief at this level. The Intermediate A interval estimated to contain about 90% of the total volumes ha Mutiara Petroleum is a Petronas Carigali – Shell Malaysia joint operating company formed in 2001 operating since then the PM301 and e specifically targeted at high concentrations of contaminants (>30%). The new technologies aim for efficiencies above 85 % where efficien

y and timing) of the gas volumes to the market. This poses a serious challenge to maintaining gas supply and meeting contractual obligation r three surveys included 4D-seismic interpretations of the water encroachment into the reservoir; the most recent survey was acquired as a developed by Salym Petroleum Development N.V. (SPD) - a 50:50 joint venture between Shell Salym Development B.V. and OAO NK Evik

uring major sea level low stands where submarine fans were supplied with coarse clastics via the major slope canyon systems. The predom

The high reservoir quality (porosity 30% permeability 1-3 D Net-to-Gross 70-95%; Figure 2) and absence of apparent structural features th

eveloped an ‘add-on’ fracture simulator to our existing in-house reservoir simulator. In the past several attempts were made to addr flow was applied to optimize well design and steaming strategy. Some of the suggested design components are already being tested at Pea d in 1969 and is the largest gas field in the Central Luconia Gas Province with a GIIP of 6 to 7 Tscf over an area of 90.5 km2 (Figure 1). The ast of Russia north of Japan (Fig. 1). Formed in 1994 to operate Sakhalin II Project Sakhalin Energy Investment Company Ltd. (Sakhalin roduction wells are drilled to preserve a steady reservoir pressure and sweep the reservoir. The use of smart wells expands the possibilities 005 delivered 6 value-assured FDPs for the large fields in Phase 1 covering 2/3rd of� STOIIP. The remaining satellite fields were pursued le the Ogbotobo catchment area has Ogbotobo and Agbaya as fields with the flowstation located in Ogbotobo. Production from the Southe istance of approximately 40 km north of Bandar Seri Begawan the capital of Negara Brunei Darussalam. This paper focuses on the rapid i 85 and put on production in 1993. The field is sub-divided in four blocks namely LA LB LC and LD. Blocks LA and LB produce high quality rts. Europe is strategically located to import gas from various regions but may find itself in competition with East Asia for pipeline gas. Key u re project is equivalent to some of the largest oil refineries in the world. The project is based on proprietary Shell GTL technology underpinn mulators modelling fractured injection. 1. Introduction Injectivity decline is a major issue in most water floods on a global basis some 80% o water are used as raw material as cooling water in power and processing plants for steam generation or as potable water for domestic use i.e. they think Process Control is only about the video screens in the control room and the associated computers.� However Process Co flow profile. This was followed by pulsed neutron logging where ever required in order to determine the hydrocarbon saturation in the cased

ore southwest of Warri in Nigeria with water depths ranging from 950 to 1500 m. The reservoirs are Lower/Upper Miocene in age and are any issue with respect to the predicted souring. Introduction The Bonga field lies on the continental slope in the southern part of the Niger D tive side-effects observed when applying nitrate to PW Norske Shell re-evaluated the requirement to mitigate souring with nitrate. The test

arated in the in-line separator at the central X processing facility. The increasing H2S levels have caused concern for future production scen ermeability curves in determining the clean up time for a well and the benefit that a mutual solvent may bring in overcoming slow clean up anual optimization. Introduction Decisions about well configuration constitute a fundamental component of reservoir development plans. S of these reservoirs. Phase 2 tentatively (now approved and under development) involved full field primary development in several reservoirs gies are specifically targeted at high concentrations of contaminants (>30%). The new technologies aim for efficiencies above 85 % where he latter three surveys included 4D seismic interpretations of the water movement through the reservoir; the most recent survey was acquir vironment.� These offshore field developments often consist of long horizontal wells with subsea completions resulting in a high cost of w considered.

w structural data with a regional geological well correlation fully and iteratively integrated with dynamic well information and production data ation (1) where the integrand is a weighted sum of field rates Equation . Here the weights are denoted by the letter and the field rates by th mpleted in the second quarter of 2006 concluded that water injection was not only feasible but also required to safeguard developed reserve paper summarises all of the refinements undertaken as part of the new model building including the improvement in the seismic data the i ed to the porosity and permeability1. Automatic history matching problems are typically formulated as the minimization of the difference be h et al. 2003 Spall 2003) and Nelder-Mead simplex (Spall 2003) methods. The second category consists of global methods such as simula y in reservoir simulations of channelised fields and their seismic expression1. The ARM program is designed to integrate aspects of seismic uence of uncertainty. In addition to economic unknowns uncertainties in reservoir characterization constitute a large component of the finan malilty of a reservoir development strategy is measured by its robustness under the influence of uncertainty. Uncertainties around the subsur uid. For a non-insulating fluid the convection amplification factor the Nusselt number can be as large as ten or more. Insulating also is ach voir pressure above bubblepoint in the case of green fields. Even though often unnoticed water injection frequently is taking place under in simulator4. In the past several attempts were made to address the coupled problem of reservoir simulation and induced fracture growth. C nd the reservoir.1 Production instabilities can be subdivided into two groups. Firstly the naturally occurring dynamical phenomena such as c overy. Dedicated simulation software tools can offer these new insights by helping to understand production instabilities and test new contro

ndependent variables could be engineered for the desired objectives. n the Champion delta system.� The coastal-plain and shallow-marine reservoirs include tidal-channel and upper to lower shoreface sand and add to the complexity and nonlinearity of the problem. Also near very-high-rate gas-production wells non-Darcy flow further increases

e structured or unstructured grids each having pros and cons. As long as structured grid works well it is preferable to unstructured one. Ho eering. The main input to reservoir simulator is the geological details of reservoir obtained by geologists and reservoir engineers. These geo ormance on the reservoir scale. Reservoir simulation also provides a useful tool for managing reservoir performance and evaluating the imp

ng an areal compositional grading in addition to vertical grading that cannot be explained using depth cross plots. Available tools were not a remote stress condition for elastic stress-field simulation. The latter is achieved by matching the actually observed structural deformation w troduction This paper presents the methodology implementation and results of the dynamic modeling of a naturally fractured carbonate re permeability simulations (in which the matrix-fracture interaction is modeled by shape factors). In the third step we consider gas-oil gravity d

s tool manages overall system flow parameters thus enhancing the predictability of the field performance. The focus of this paper is to ad

g Monte Carlo in a post processor using a simplified set of equations could lead to ignoring key system dependencies unless the simplificat ach using both synthetic and field applications. Introduction In recent years there has been a paradigm shift from attempting to ‘history m 950; Matthews et al. 1954; Dietz 1965). Such methods may result in uncertain predictions when reservoir data are unavailable or reservoir

s that water is the preferred injection fluid for all of the Champion field reservoir intervals studied. Water typically gives a 15-20% (absolute)

e the amount of history matching was minimized and the time and effort required were reduced. The application of unrealistic changes to s set to continue over the coming decade with indications from a number of sources including governments and the industry that there will b asses: (1) using fractional flow theory in which relative permeability functions are approximated to establish water cut (or water-oil ratio) va n lack comprehensive thermal capabilities. This may limit simulation accuracy for many cases. Thus there is a need for the development va in experimental special core analysis (SCAL) measurements. Furthermore how to assign imbibition Pc for the different porosity and perme he tidally influenced estuary deposits of the Lower Safa A. A 6m net (20ft) oil-bearing channel sand tested 4 100 bbl/d of 36�API oil with a s media. It results from the combined effects of molecular diffusion and fluid velocity gradients (Taylor 1953). The recovery efficiency of pro

with the miscible gas injection. Introduction Rock Pore Volume Compressibility (PVC) data can be misinterpreted during the early life of res d the original oil water contact is ~375 mss. Fracturing occurs throughout all zones and is believed to be contiguous and in hydraulic comm rbonate reservoirs are commonly oil wet or mixed wet and the main production mechanism is gravity. Once a gas cap is established in the l will drain down the matrix rock driven by gravity and into the fracture system below the fracture GOC or at matrix flow barriers. In the fractu OIIP from 597 vertical�wells. Due to advances in heavy oil recovery technologies Schoonebeek is now a candidate for re-development. ncertainty ranges than the prior uncertainty ranges which means the production update reduces parameters uncertainty. The updated recov 1987 to 1990 under the name of Phase A. �This ‘proof of concept’ pilot consisted of three short well pairs closely spaced (50 m in this paper is to present the development and performance history of a pressure maintenance project of a sour oil (H2S & CO2) reservoir d as re-injection. In 2004 water injection was introduced in South Pierce with the dual objective to give additional pressure support and better ity of the efforts to regain control over the well. More difficult to quantify in case of an actual blowout is the impact of issues such as nega ough we did identify seven specific areas where technology advances are recommended. Collaboration and visualization technologies are onology and Associated Learning’s In the following the term “Digital Oil Field is used throughout for consistency even though the t al. 1996).�This technique is still being used successfully in West Africa the North Sea and lower-pressured gas sands in the Gulf of Mex e discovered in the decades (see Fig. 1). During this time many of the more difficult hydrocarbon discoveries were put to one side for later ded). Confidence level of stimulation in Shell Asia Pacific region has been elevated. Lessons learnt and best practices established will be p With relatively few analogs the Ursa and Princess fields are set to embark on major facilities expansion and subsea development. The aim quired in or beyond 2006. These results will be discussed.

anning of detail dynamic simulation where the remaining opportunities scope is large. Introduction The objective is to identify the location o

e surface and downhole data. Using this tool inflow control valve settings are suggested to the user in order to optimize production on a dai

ents recorded in the pilot are apparently not diagnostic of heat delivery to the formation.

pe of boundaries. A surveillance logging program has been conducted in the Mississippi Canyon Block 807 area since 2004 with initial base

rtmentalization compaction represent a typical list of challenges that are extremely difficult to decipher based on just several permanent pre urveys that have been remotely monitored in real time to ensure that all WFT evaluation objectives are met. The power of real-time monitor modeling. Numerical modeling for reservoir compaction and surface subsidence usually involves the finite element method (FEM). Researc

e of restoring the well’s oil producing capabilities. Introduction It is common knowledge that oil production declines are often associate ses have helped verify modeling parameters and on justification of future activities. Introduction The Mars Field (Figure 1) consists of six O pipe. It is not uncommon to find channels behind pipe that allow communication due to poor cement quality. Any successful water shut-off re

s. Major factors that limit the stimulation activity include: Various success rate Fewer non-stimulated wells from which stimulation candidat ractices is better than cure for most sand control problems. A common score card item irrespective of the category of well owner is to delive bitor further away from the wellbore and allowing it to react with the existing rock. During production following a squeeze treatment the inhib ssure and temperature data from surface and downhole sensors in combination with models for pressure and temperature drop over the we

uids. Those responsible for hydraulic optimization and well control in managed-pressure drilling/UBO where foam is used will find this paper Seri Begawan to Kuala Belait. Tali Field (Fig. 1) is a small field which is about 10 sq km in size 2 km from the coastline. With unconsolidate erform: Frac and Pack completions exhibit positive skin values 1 2 and traditional hydraulic fracture completions show discrepancies betwe

ning well the gas-oil-contact will reach the well and a gas breakthrough will occur. Upon breakthrough the well will experience a high gas inf t uses heavy oil-in-water emulsion to block the near wellbore region has been developed. Emulsion flow behavior and methods controlling i startup until early in their production life which included mud removal and stabilized wellbore flow. In both of the conventional wells calcula

n relies on the properties of rock and the foam itself. These include parameters such as surfactant concentration surfactant adsorption on r edia. These models include fractional flow modeling population balance model and percolation models. The foam fractional flow model was above the yield stress it obeys a power-law (b) foam rheology is mainly controlled by the bubble density and (c) the bubble generation is a as ratio’s (LGR). Although the liquid slips through the gas effectively the gas-liquid mixture tends to behave like a single phase liquid flo

. Solutions such as gas lift soap injection velocity string or plunger lift are required to solve this problem. Accurate predictions of the onset the field. Introduction Studies show that heavy oil constitutes a strategic option for the industry to increase reserves by tapping into at leas ocus critical issues such as the industry’s dependence on API Section I data - as a result of which we continue to be hoodwinked by †n method across the entire perforated interval in such an environment.� Additionally its usage eliminates the need for conventional sep 2003. The main objectives of their development were to contribute to the corporate production targets and to maximize sub-surface data acq q km with an estimated gas in place (GIP) in excess of 2 Tscf. The reservoirs are comprised of a sequence of highly laminated sand and sh er support does not exist within this sand; instead the primary recovery mechanisms are depletion drive and compaction. This lack of pressu re made up of a sequence of highly laminated sand and shale deposits with significant sand-size variability and high fines content. Being hig on with the hydrocarbons is accepted practice. Since the earliest days sand has been treated differently by the engineering community (Su

the ISO 13503-4 is to provide a standard procedure for measuring stimulation and gravel-pack fluid leakoff under static conditions2. This s Sharing Contract (PSC) with Petronas Sarawak Shell Berhad together with its equity partners are under contract to develop and produce n analysis offers one of the cheapest ways to determine the dimensions of induced fractures. Unfortunately hardly any work has been carrie

ervoir kh with remedial stimulation substantiates this work.

s constants are derived from the core plugs from this well. Introduction The Oseberg field is located in the northern part of the North Sea 1 d a worst-case estimate for pressure buildup and a safe basis for design. Introduction Pressure buildup in tubing-casing or casing-casing a ximum anticipated surface pressure with anticipated reservoir fluids to surface was deemed to be less than 690 bar. Anticipated bottom ho nsistency. Field examples will be discussed which show that smaller scale pressure transient tests often have an advantage over full scale rformance indicators can be put in-place to maximize test quality? - What can be done to automate the entire well test process from dete

25 $/t CO2. Shell has a special team working on the CO2 Capture Project (CCP) Joint Industry Project. For the CCP Shell carries out studie of the reservoir (Siemons et al. 2006a 2006b) and the interfacial interactions of the coal/gas/water system (Gutierrez-Rodriguez et al. 1984 e volume between the chains is smaller than the actual volume of the CO2 molecule. The similarities in structure between coal and glassy oir properties under these conditions. Cleat permeability of coal is the most important parameter for coalbed methane production. Being no

ration ability and energy content. The revenue of methane (CH4) production can offset the expenditures of the storage operations (Wolf et a f the Intergovernmental Panel on Climate Change Report (IPCC 2005) geological storage of carbon dioxide (CO2) was recognized in the

vernmental and nongovernmental organizations to consider CO2 capture and geological storage as a potential option for reducing future e menting robust trustworthy optimization and automation processes. Several example use-cases are included to illustrate how PRODML can ssing and analysis. This situation led the founders of what became the PRODML initiative to realize an opportunity to leverage each others

rties are obviously key parameters to understanding the economic viability of opportunities within the E&P industry. Their variability and dis hell Group are described in Poulisse et al. [1] and Cramer et al. [2]. Using data driven models FW PU essentially provides a “virtual thre on data is a key enabler for future smart optimization and intelligent diagnostics.�PU is a foundation element for Shell’s Smart Fields er describes PU how the applications were implemented some of the challenges faced during the implementation and the changes that hav

nse to performance anomalies partly caused by �more focus on the much higher value big assets. Net oil production was declining rapid hich we flow the hydrocarbons directly to surface while measuring the rate and the pressure is one of the major tools petroleum engineers h aisal tests use a dedicated production tubing string rather than the drill string. Following industry convention however we will be using the w

cted end-2006 to be around 50 000 barrel per day some 20% of Brunei's export. Gas production will support LNG sales for many years. V

model-based flooding optimization and model updating.[1 2] For the optimization part these “closed-loop reservoir management strate nologies. Smart Fields now use downhole wireless communication advanced modeling software remote sensing and control devices and te pt The Smart Fields� concepts grew out of the thinking that guided the development and success of Smart Wells. Figure 1 illustrates the ated reserves have been produced so far. The field consists of a number of elongated fault blocks. In the vertical sequence each fault is ma

s not an option because of cost and complexity. Conventional horizontal wells were also considered however the concept was not attractiv g; underbalanced techniques designed primarily to improve rate of penetration in hard formations. Mist and foam drilling were technologica two extremes are various techniques used to con-trol the annular pressure profile and overcome constraints im-posed as a result of the equ ulations and multi-component combustion runs. Introduction High Pressure Air Injection (HPAI) is generally defined as a process in which c maintained [1]. Even in the absence of any fines and solids contaminants in the fluid the high in-situ oil viscosity and low polymer mobility co etween the micro-emulsion phase behaviour and IFT2 it is common in the industry to screen surfactants and their formulations for low IFT th hods such as water flooding do not work effectively: due to the high fracture permeability it is not possible to establish significant pressure d plication air injection has been applied successfully technically and economically as both a secondary and tertiary (Double Displacement P ection is mostly used as a tertiary or sometimes secondary oil recovery method. This paper deals with the PVT-related work that was perfor astic bubble population (SBP) foam model with the main features described below: Foam is a complex fluid characterized by a yield stress ties in June 1987 and production commenced in June 1990. Gyda has been developed with an integrated steel production drilling and qu

P has been produced from the 29% porosity low permeability (5-14mD) limestone.� . During the primary production period from 1975 to 1

Maas et al 2001; Webb et al 2003 and McGuire et al 2005). Recently some evidence of the beneficial impact of injection of brines with wel her fields where the GOGD recovery mechanism is used. Introduction The giant fractured carbonate field was discovered in 1964 and cam meability layers leaving oil behind in the unswept layers. Generally oil production decreases with the maturity of an asset while the water p 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 decreases with the maturity of an asset while water production increases. For 1999 the worldwide daily water production associated with o d its action must first diffuse into the porous medium. In any diffusion process the time scale is linked to the square of the length scale of t business because the system bottlenecks could shift from year to year [1]. For these integrated studies one typically considers the oil & ga functions ideal constraints and ever present derivatives. The real world of search is fraught with discontinuities and vast multimodal noisy nce in these areas that has been accumulated over more than 50 years they are becoming critical in many existing and new areas of explo 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 imum miscibility pressure (MMP) is an important process optimization parameter for miscible gas injection projects. MMP is defined as the

aining organic matter particularly under low oxygen conditions. Industrial sources of H2S include petroleum and natural gas extraction and erlying reservoir or by capillary leakage. As the source matures with time later petroleum charges become less dense and each reservoir mponent and the GOR prediction become unreliable because of the color effect. In this paper we describe the methodology for downhole G d ensure optimal utilization of reservoirs and even refinery stocks. This is particularly relevant in the study of asphaltene samples from hydro viscosity beyond the inversion point. The variation of viscosity with water content for live emulsion samples indicated that the inversion poin water IFT and alter the wettability of the rock/oil/brine system and hence improve oil recovery. However these interfacial rock/fluid interacti

on via the new HF system which has shown proof of true matrix stimulation within hydrocarbon producing wells in this particular basin.1 Th

mulate the flow profile in two zones with different permeabilities: 200mD and 50mD. Initially most of the fluid enters the 200mD interval but

ion while drilling However in low-cost drilling environments such as land operations in the Middle East and in North America drilling-enab work took the view that in order to prevent naphthenate soap problems we needed to develop a view of both the basic mechanism(s) throu

Due to this the amount of scale squeezes in one campaign was reduced from 18 to 6. Shell U.K Limited’s operations in the North Sea of preferential steam paths. Consequently many sands cannot be effectively steamed and produced. �In order to provide and to contro

ssful SAGOGD pilot project in the nearby Field A (also a Shuaiba reservoir and only 8km away – Ikwumonu et al. 2007) SAGOGD was e steaming strategy. Introduction Peace River is 100% Shell owned heavy oil property located in north-western Alberta Canada approximate uce the cost of the retarded HF acid introduced in 1996 and also improve acidising performance especially in high water cut wells fines dom been much discussion about (hydraulic) shape-factors in the literature [3-15]. Although they have typically been treated as constant time-in use of the BTZ for steam injection. Currently cyclic steam stimulation is employed to extract the oil using closely spaced horizontal wells dri usion (molecular and/or thermal) and convection (compositional and/or thermal) mechanisms.2 3 4 The relative dominance of these mecha ed 7 liner over the reservoir section. They are completed with a 3.1/2 tubing some of which have a permanent downhole pressure gauge (Fi fluids used to stimulate limestone and dolomite formations. By adjusting the composition and pH of these fluids it is possible to customize ich have consistently improved well productivity and profitability in these reservoirs. Introduction In many ways a field trial resembles a leg

e variety of proppant products are investigated and compared to expected performance from published specifications.�This paper will a draulically fractured in isolation with other intervals to assure effective treatment. Such complexities in the fracturing methodologies require ng gas in place recoverable gas drainage area and ultimately well spacing it is cost effective. Introduction Vast amounts of gas bearing r e average effective rock pore throat radius — i.e. the gas molecules tend to "slip" on the surfaces of the porous media. This effect yields a decisions are critical to effective appraisal of discovered gas bearing structures aiming to optimize appraisal value from ideally only one app by an extensive evaluation and appraisal period of two years preparing a development plan. Appraisal activities carried out included fractur h higher offshore Europe well cost which forces field developments to aim for a one order of magnitude or more higher well capacity and ra

ncreasingly taps the world’s “easy oil and gas reserves the need to develop resources in more difficult operating environments is be

d persistence on sound engineering practice led to improved gas production meeting gas supply commitments and eliminating further unne n assumed for design whether one refers to the price of oil the amount in the reservoir the time and cost of construction etc. The general ction and drilling information in a ‘risk-based distributed decision framework.’�The primary aim of the program is to help optimize t h the oil and water phases are mobile. The balance of capillary and buoyancy forces controls this so-called capillary transition zone during th have a relatively higher GOR value. Downhole spectrometers measure optical density (OD) defined as the ratio of incident light energy to ate sensor response in a large number of live-fluid samples. These tests of known fluid compositions were conducted under pressurized and

model simulations are used together for quantifying the impact of channel architecture. The goal here is to apply Monte Carlo techniques dir page losses and the differential sticking in the depleted sand and overlying shale. We have also performed dipole radial profiling (DRP) of fo

o stimulate these reservoirs effectively. The literature also shows the disastrous results that can arise when damage-prevention steps are no g connectivity decreased with increasing scale. We concluded that approximately 5 ft could be considered the representative scale for the la meability is arguably the most important petrophysical property of a reservoir rock and the ability to predict its value without time-consuming ns. If unraveled this signature gives us information about the reservoir that is otherwise not easily available with the immediacy with which ults depend on mechanical characteristics of the layers intersected by the fault (Figure 2). Fault related fractures seem to be more abundan n and northern flanks of the field with a relatively low degree of fracturing in creastal area. Orientation of fracture corridors from indirect ind in a deepwater well or similar setting these techniques are inordinately expensive and are also environmentally unfriendly. Moreover inter velopment commences. From these fluid property data and geologic models dynamic reservoir models can be built to accurately simulate p o a slow low resolution GC-FID gas analyzer. Data from these systems were of poor quality and limited applicability beyond an inconsistent ent variable well performance and marked pressure depletion. The fields are small to medium salt withdrawal related structure often with st etermined on a few core samples and variation in 3D is hardly known. The purpose of the NMR wettability research is to take a first step to

n about 90% of the total volumes has relatively low average porosities of only 5 to 10%.� Nevertheless the NMR signature as well as th perating since then the PM301 and PM302 exploration PSCs. The company has enjoyed so far a 100% exploration success rate in the Nor ciencies above 85 % where efficiency is expressed as a percentage of hydrocarbon sales gas divided by the hydrocarbon feed stream. (Lo

y and meeting contractual obligations. st recent survey was acquired as a combined high-resolution and 4D survey. Reservoir management for Draugen uses a full-field reservoir Development B.V. and OAO NK Evikhon (a subsidiary of Sibir Energy plc).

slope canyon systems. The predominantly channelized reservoirs are comprised of fine-grained amalgamated channel sands massive sa

ce of apparent structural features that could significantly influence the flow of water and hydrocarbons in the reservoir have historically led t

several attempts were made to address the coupled problem of reservoir simulation and induced fracture growth. Common approaches can ents are already being tested at Peace River. Introduction Historically various thermal recovery schemes have been piloted at Peace River an area of 90.5 km2 (Figure 1). The field is an elongated carbonate build-up of Miocene age. The first 3D seismic data over the field were a nvestment Company Ltd. (Sakhalin Energy) is a unique partnership drawing upon global oil and LNG expertise and experience. The current smart wells expands the possibilities to manipulate and control fluid-flow paths through the oil reservoir. The ability to manipulate (to some d maining satellite fields were pursued in Phase 2 and delivered 17 FDP’s by the end of 2006 covering the remaining 1/3rd of STOIIP. F botobo. Production from the Southern swamp started in 1976 from the Opukushi and Benisede fields while production from Tunu was 1995 m. This paper focuses on the rapid implementation of a pressure maintenance scheme using multilayer fractured water injection and related cks LA and LB produce high quality crude oil and they contribute about 73% of total oil production from the field. LD block is mainly a gas p ith East Asia for pipeline gas. Key uncertainties are recoverable gas resources demand and transport capacities causing a supply shortag ary Shell GTL technology underpinned by 15 years of operational experience at the GTL plant in Bintulu Malaysia. Although Pearl GTL is a ods on a global basis some 80% of injection targets are being met. The 20 % shortfall is largely due to a mismatch between water quality a or as potable water for domestic use. The refining and petrochemicals facilities are typically the largest users of fresh water (>98%). On the omputers.� However Process Control is the rationale behind the visible systems (instruments and valves) and the strategy about realizin hydrocarbon saturation in the cased hole environment. Integration of data from open hole logs production logs and pulsed neutron spectro

ower/Upper Miocene in age and are interpreted as stratigraphically/structurally trapped mud-rich unconfined-turbidite systems in a mid-/low pe in the southern part of the Niger Delta some 120 km offshore South West of Warri in Nigeria with water depths ranging from 950 to 1200 mitigate souring with nitrate. The testing during the PWRI pilot showed a low tendency to develop SRB activity probably because of the low V

d concern for future production scenarios as the materials used in the X field subsequent processing facilities at down stream facilities are y bring in overcoming slow clean up times. The model is then used to demonstrate how the preflush stage of given specific field squeeze de nt of reservoir development plans. Such decisions involve the number of wells to be drilled well patterns the well locations well trajectories ry development in several reservoirs together with gasflood development in one reservoir. Major Project Maturation The development team m for efficiencies above 85 % where efficiency is expressed as a percentage of hydrocarbon sales gas divided by the hydrocarbon feed stre ; the most recent survey was acquired as a combined high-resolution and 4D survey. 4D seismic has been very important for the reservoir m mpletions resulting in a high cost of well interventions and technical challenges in the conveyance of logging tools.� The importance of su

well information and production data indicates that the recovery in the MUF formation could well be optimized through a more deterministic by the letter and the field rates by the letter . The subscripts and refer to “oil and “water while the superscripts “prod and “inj ired to safeguard developed reserves and to realize additional oil recovery from the field. A large redevelopment project is planned to facilita provement in the seismic data the insight into the stratigraphic changes the hierarchical framework the rock property model the probabilis he minimization of the difference between actual and predicted data. Thus the choice of an effective minimization algorithm is critical. In a r sts of global methods such as simulated annealing (Beckner and Song 1995) genetic algorithms (Montes et al. 2001 G�yag�ler et al. gned to integrate aspects of seismic and reservoir engineering through the construction of a laboratory-scale model of sand bodies with flo stitute a large component of the financial risk. The practice of forecasting hydrocarbon recovery performance through dynamic reservoir mod nty. Uncertainties around the subsurface model constitute a significant component of the financial risk along with economically rooted factor as ten or more. Insulating also is achieved to a lesser degree by reducing the static thermal conductivity of the fluid when possible (e.g. chan n frequently is taking place under induced-fracturing conditions. The rock fracturing has a strong influence on the water injectivity and the ar lation and induced fracture growth. Common approaches can be grouped into fully implicit simulators (Tran et al.5) where both fluid flow eq ng dynamical phenomena such as coning and slugging. Secondly the production dynamical phenomena such as shut-in clean-up and ga ction instabilities and test new control strategies to avoid them and to optimize production. The field under investigation has most of its well

and upper to lower shoreface sands. Figure 2 shows the Champion field stratigraphic summary. The field was discovered in 1970 and wen s non-Darcy flow further increases the complexity and nonlinearity. The combined effects of relative permeability capillary number and no

s preferable to unstructured one. However when the physical domain is highly heterogeneous and geometrically complex structured grids and reservoir engineers. These geological data are integrated to build a fine scale/grid model of the reservoir that represents geological fea performance and evaluating the impact of alternative development scenarios and recovery mechanisms on ultimate oil recovery. A primary

ross plots. Available tools were not able to ‘representatively’ model the observed grading behavior even within the same target zone ly observed structural deformation with the simulated one. The smaller-scale fluctuation of fracture density is simultaneously history matche of a naturally fractured carbonate reservoir of an oil field in the Middle East. The study is part of the field’s Reservoir Management and rd step we consider gas-oil gravity drainage of the same stack model but now under steam injection. In this case steam is injected at the t

nce. The focus of this paper is to address the challenges associated with performance prediction for deepwater wells and the techniques us

dependencies unless the simplification is done smartly. A study was therefore performed to find practical solutions to significantly speed up m shift from attempting to ‘history match’ a single reservoir model to generating a suite of realizations consistent with all dynamic data oir data are unavailable or reservoir heterogeneity exists. The inverse time plot by Kuchuk (1999) is essentially a modification of Horner’

typically gives a 15-20% (absolute) higher oil recovery factor than gas. The impact of the sedimentology review and modelling is that it will

pplication of unrealistic changes to the geologic model to match production history was also avoided. The study suggests that single realiz nts and the industry that there will be a need to devote increased effort and resources in the future to fulfill these demands.� This paper blish water cut (or water-oil ratio) variation with oil recovery (1-4) (2) using Arps’ model and its modifications for example semi-log wat re is a need for the development validation and testing of comprehensive thermal wellbore flow models that are coupled to reservoir simula for the different porosity and permeability classes will be examined and its impact on modelling waterflooding performance and remaining o ed 4 100 bbl/d of 36�API oil with a 1 300 scf/bbl GOR (Ref 1). The JG discovery was brought on production in 2002 and as such constitu 953). The recovery efficiency of processes like miscible gas or chemical flooding depends partly on the mixing which an injected slug unde

nterpreted during the early life of reservoir development due to the fact that there are minimal amounts of this data acquired during early re e contiguous and in hydraulic communication with a very active aquifer. The initial oil saturation is about 95% and initial water saturation is Once a gas cap is established in the fracture system the oil will drain down the matrix rock driven by gravity and into the fracture system at f r at matrix flow barriers. In the fracture system the oil forms a (thin) rim that can be produced. Production rates achieved with a GOGD proc ow a candidate for re-development. The medium gravity 25�API 160 cp paraffinic oil is contained in the Bentheim (Lower Cretaceous eters uncertainty. The updated recovery factors have wider uncertainty ranges (18 percent) compared with initial recovery factors (15 percen ort well pairs closely spaced (50 m in horizontal length and 25 m apart). The success of this pilot led to a joint venture between AOSTRA and f a sour oil (H2S & CO2) reservoir developed in the Ara Salt in South Oman (Figure 1).� This reservoir has undergone three stages of de ditional pressure support and better sweep downdip of the oil producers. The water injection project consists of a series of highly deviated (h s the impact of issues such as negative publicity loss of reputation and credibility. A representative example is the infamous 1979 blowout o on and visualization technologies are enablers and are required in order to integrate across the core business processes and permit people ut for consistency even though the term did not come into use until the millennium. DOF has evolved over the last 40 years as follows: -ï¿ ssured gas sands in the Gulf of Mexico shelf.�But partly because of the huge variance in formation types and lack of shale isolation this veries were put to one side for later consideration. However the progressive decline in new discoveries indicates that many of the world’ d best practices established will be passed to future campaign. Stimulation is still a good means for increasing well productivity to get more o n and subsea development. The aim is to deliver a high rate of specific-quality water through four subsea-injection wells into a vast and larg

objective is to identify the location of bypassed oil development opportunities in and to estimate the potential recovery scope without resort

rder to optimize production on a daily basis through the use of mathematical optimization routines taking into account all available data. The

807 area since 2004 with initial baseline surveys to monitor and to optimize the production performance of the field and to inspect the water

based on just several permanent pressure and temperature gauges. 1 2 Many problems can be identified by production logging but it is cos met. The power of real-time monitoring and interpretation will be illustrated through these case studies. Introduction WFT has become a s ite element method (FEM). Researchers use either the FEM or nonlinear FEM (Plischke 1994; Abdulraheem et al. 1993; Chin et al. 1993; B

duction declines are often associated with increases in unwanted water production and this is particularly universal in brown fields. Producti ars Field (Figure 1) consists of six OCS leases in the Mississippi Canyon Area – Blocks 762 763 806 807 850 and 851 – located in th ality. Any successful water shut-off requires good zonal isolation and such flow behind pipe techniques offer a clear diagnostic value. Measu

ells from which stimulation candidates could be selected Operational difficulties (as conventional offshore CT operations normally it is time he category of well owner is to deliver best-in class producers that quickly pay back investment capital. Introduction Openhole completions owing a squeeze treatment the inhibitor is slowly desorbed or dissolved into the formation water. Earlier efforts have focused on describing re and temperature drop over the wellbore and the valves). All these measurements require occasional calibration based on surface produc

here foam is used will find this paper useful for practical design applications. Introduction During foam- drilling operations predicting such p m the coastline. With unconsolidated and high permeability sand most of the wells here encounter the danger of formation breakdown and mpletions show discrepancies between the placed propped length and the effective production fracture length.3 Polymer damage leading to

e well will experience a high gas inflow. Largely for three reasons this is an undesired phenomenon. Firstly because the gas phase may sta w behavior and methods controlling its propagation rate into a porous medium will be presented. Introduction Across Canada thousands of oth of the conventional wells calculated flow rates and pressures agreed with the available well test measurements. Simulation results have

entration surfactant adsorption on rock foam propagation in porous media (foam strength/stability) and reservoir heterogeneity (and wetta The foam fractional flow model was first introduced by Rossen et al. [2 7-8]. The implicit assumption of foam incompressibility makes this m ty and (c) the bubble generation is a simple stochastic process involving only two parameters to describe bubble generation so that the kine behave like a single phase liquid flowing to surface where the phases can be separated and processed. This changes when the reservoir

m. Accurate predictions of the onset of the liquid loading process allow for better planning and choosing the right countermeasure. Currently ease reserves by tapping into at least 12 trillion barrels of in-place heavy hydrocarbons worldwide. We target the present work to increase re we continue to be hoodwinked by ‘record breaking’ penetration performance into concrete targets – and the lack of performance me ates the need for conventional separate acid stimulation saving rig time and costs while reducing HS&E risks. nd to maximize sub-surface data acquisition to aid a field development study update. To ensure that the well could flow against the 70 bar b nce of highly laminated sand and shale deposits with significant sand-size variability and high fines content. Being highly unconsolidated do and compaction. This lack of pressure support led the operator to develop plans for four high-rate subsea water injection wells (two in the P ility and high fines content. Being highly unconsolidated downhole sand exclusion is mandatory. The primary drive mechanism is a depletio y by the engineering community (Suman 1925); it is excluded commonly at the cost of reduced hydrocarbon production. Recently sand p

akoff under static conditions2. This standard procedure excludes the use of fluids that react with porous media. Fluid Preparations Certain er contract to develop and produce natural gas resources. Under the PSC framework gas produced will be supplied under a gas sales contr ely hardly any work has been carried out to date in order to provide a methodology for interpreting the pressure transient data of fractured w

he northern part of the North Sea 130 km NW of Bergen Norway. The sea depth in the area is 100 metersi. p in tubing-casing or casing-casing annuli is in general undesirable. Although casing design should take into account high pressures at the than 690 bar. Anticipated bottom hole static temperatures were anticipated in excess of 150�C. This well was drilled using a semi subme n have an advantage over full scale well tests testing in terms of providing detailed layer flow behavior vertical connectivity and flow potentia he entire well test process from determining which well needs to be tested automatically putting that well on test minimizing durations au

For the CCP Shell carries out studies manages projects and the team is involved evaluating opportunities for deployment of the technolog em (Gutierrez-Rodriguez et al. 1984; Gutierrez-Rodriguez and Aplan 1984; Orumwense 2001; Keller 1987). It can be expected that in highl n structure between coal and glassy polymers have led to the perception (Ritger et al.1) that CO2 penetration has many analogous features albed methane production. Being normal to the bedding plane and orthogonal to each other the face and butt cleats in coal seams are usua

of the storage operations (Wolf et al.13 14 15). oxide (CO2) was recognized in the public as an important concept for reducing greenhouse gas emissions into the atmosphere. Notwithsta

potential option for reducing future emissions of greenhouse gases (GHGs) produced in the extraction of resources the production and us luded to illustrate how PRODML can be applied. Introduction The production system of an oil field changes during its life. Wells are added opportunity to leverage each others efforts by defining and achieving a supplier-neutral framework of standards. This framework would ena

&P industry. Their variability and distribution within a field will have enormous impacts on facility design well count and operation expense. essentially provides a “virtual three phase meter for each well. Earlier references to the potential use of virtual meters includes for exam element for Shell’s Smart Fields initiative.� Introduction This paper is intended to introduce the Shell’s PRODUCTION UNIVERS ementation and the changes that have had to be made resulting in a PU becoming a sustainable part of the “way we do business. Intro

Net oil production was declining rapidly. To kick-start the Well &�Reservoir Management (W&RM) improvement effort a high level Leade e major tools petroleum engineers have used to decide how best to develop hydrocarbon resources. Even under the best scenarios howev tion however we will be using the words drill stem test and conventional test interchangeably throughout this paper. This type of testing in w

pport LNG sales for many years. Vision Early on in the Project Lifecycle (1999) the vision was agreed to develop the CW field from the

ed-loop reservoir management strategies rely on optimal control theory which has been proposed before as a flooding optimization method e sensing and control devices and telemetry to transmit the huge amount of data gathered. For example Production Universe Shell proprie Smart Wells. Figure 1 illustrates the essence of the Smart Field vision. Value is created through execution of the ‘Value Loop’ repea he vertical sequence each fault is made of multiple stacked thin sands interbedded with shale layers. In total the vertical sequence contain

owever the concept was not attractive due to the large number of wells required to drain all the key sands. and foam drilling were technological tweaking to mitigate water influx to the well bore and to aid in hole cleaning while primarily drilling with aints im-posed as a result of the equivalent circulating density of the mud system. Seen from Shell’s perspective Managed Pressure D rally defined as a process in which compressed air is injected into a high gravity high pressure oil reservoir1.� The oxygen in the injected iscosity and low polymer mobility could instigate fracture propagation if the injection rate is sufficiently large. The principal concerns about and their formulations for low IFT through laboratory-based oil / water phase behaviour tests3 4.� This approach works well for tests ca ble to establish significant pressure differentials across oil bearing matrix blocks to drive oil from matrix rock into the fracture system. In den and tertiary (Double Displacement Process DDP West Hackberry2 3) EOR process over a variety of reservoir scenarios in both vertical an he PVT-related work that was performed to ensure that each reservoir gets the appropriate gas quality required for miscible conditions. An fluid characterized by a yield stress and above the yield stress by a power law behavior. Its rheology can be described using a Herchel-B ated steel production drilling and quarters (PDQ) platform. Liquid and gas processing capacity is 70 000 stb/d and 54 mmscf/d respectively

ary production period from 1975 to 1995 the first year showed a large peak in oil mainly from emptying of the fracture network with a minor

mpact of injection of brines with well-selected ionic composition from historical field data was published (Robertson 2007). In-house resea eld was discovered in 1964 and came on stream 3 years later. The field has seven reservoir layers—A through G—and multiple subunits w maturity of an asset while the water production increases.� For 1999 the worldwide daily water production associated with oil production h 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 y water production associated with oil production has been reported as 33 million m� or roughly three barrels of water for every barrel of o the square of the length scale of the medium. Therefore it would take up to 1 000 times longer (an equivalent of 200 years) before the sa one typically considers the oil & gas supply chain starting from wellhead platforms via multi-phase pipeline to a production platform then t ntinuities and vast multimodal noisy search spaces…. For larger dimension problems (~100 variables) the most popular global optimizat any existing and new areas of exploration and production. Addressing similar questions in deepwater exploration and production with its ch 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 on projects. MMP is defined as the lowest pressure at which injection gas becomes miscible with the crude oil to form a single phase throug

eum and natural gas extraction and refining pulp and paper manufacturing rayon textile production leather tanning chemical manufacturi ome less dense and each reservoir fills downward from the top due to buoyancy and displaces the earlier heavier charge. As such there is be the methodology for downhole GOR measurement and we provide details of a decolorization technique to remove the color effect of dar y of asphaltene samples from hydrocarbon systems. The challenge in this case is to identify the exact species in the asphaltenes responsib ples indicated that the inversion point for live emulsions is similar to that of STO samples. The experimental results are also used to analyze these interfacial rock/fluid interactions are sensitive to temperature and pressure in addition to being time dependent. Therefore the resu

ng wells in this particular basin.1 This particular HF acid system has been very successful and widely applied with tremendous improveme

fluid enters the 200mD interval but after diversion the flow is divided equally over both zones. Various diversion methods such as viscous

t and in North America drilling-enabling savings from UBD are often marginal and the cost of UBD operations becomes an inhibiting factor f both the basic mechanism(s) through which they formed and a thermodynamic model to quantitatively describe their formation. An outline

d’s operations in the North Sea have benefited considerably from the use of PCA and ESEM/EDX. Introduction Scale formation in the �In order to provide and to control the uniform steam flow distribution from the wellbore to the reservoir the steam flow rate should depen

monu et al. 2007) SAGOGD was evaluated as a suitable EOR technique for Field B. For this thermal EOR technique to work successfully estern Alberta Canada approximately 700 km northwest of Edmonton (Fig. 1). It holds approximately 8 billion barrels of 7�API oil in plac ally in high water cut wells fines dominated zones and heavy crude led to more critical look at design philosophy recipe selection pumping lly been treated as constant time-independent quantities it follows from its definition that a shape-factor is essentially a time-dependent qu g closely spaced horizontal wells drilled from a central pad. The wells stay above the BTZ to limit water production and to optimally use the e relative dominance of these mechanisms is in turn dictated by fluid properties and reservoir architectures. For instance the proximity of t anent downhole pressure gauge (Figure 1) to help assess reservoir connectivity1. The Cluster is being developed in a phased manner. The se fluids it is possible to customize the chelant solutions and target specific well conditions to achieve maximum wormhole formation with a ny ways a field trial resembles a legal court trial.� Evidence must be carefully examined and opposing arguments should be considered

specifications.�This paper will aid engineers working in multi-layered reservoirs understand the complexity of the evaluation process an he fracturing methodologies require an effective method of assessing flow contribution both by phase and flow rate of each productive laye ction Vast amounts of gas bearing rocks with permeabilities of only a few micro-Darcy were known to exist in North America for decades. It e porous media. This effect yields an overestimation of the measured gas permeability compared to the true absolute permeability if it were aisal value from ideally only one appraisal well. activities carried out included fracturing of existing and newly drilled vertical wells and drilling/testing of horizontal wells to allow a developme or more higher well capacity and raised ultimate recovery to generate economic returns. Typically the initial well capacity offshore Europe s

difficult operating environments is becoming self-evident as is the increasing importance of unconventional resources (e.g. heavy oil tight

itments and eliminating further unnecessary expenditures ($600 000 on stimulation). �Delayed gas recovery was eliminated by this effort ost of construction etc. The general rule as demonstrated by experience in many fields of design is that the forecast is 'always' wrong" as d m of the program is to help optimize the operating performance and value of E&P assets through the implementation of integrated surveillan ed capillary transition zone during the primary-drainage process of oil migrating into an initially water-filled reservoir trap. Because the wate 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 re conducted under pressurized and heated conditions to simulate reservoir conditions. In addition several field examples are presented to

to apply Monte Carlo techniques directly to reservoir simulation by assuming probability density functions for uncertain variables (Fig. 2). Mo med dipole radial profiling (DRP) of formation shear slownesses using the measured cross-dipole dispersions at three depths in shale and on

en damage-prevention steps are not taken (Cippolla et al. 1988). As a result there is a definite need to identify natural fractures before a st ed the representative scale for the large-touching-vug carbonate rocks at the Pipe Creek Outcrop. Introduction Carbonate strata may conta dict its value without time-consuming and expensive laboratory measurements would obviously be of great practical value. As the permeabi able with the immediacy with which UBD operations provide it. The prospect of unraveling this signature and thus improving reservoir knowl fractures seem to be more abundant on one side of the fault in Figure 2. In this particular case the occurrence of fractures only on one sid of fracture corridors from indirect indicators must be estimated from nearby image fracture corridors or seismic faults or from dominant fractu nmentally unfriendly. Moreover interpretation of well-test responses in turbidite and multichannel reservoirs can be complicated by the comp can be built to accurately simulate production and help select optimal reservoir management policies. This paper includes examples in whi applicability beyond an inconsistent identification of the presence of hydrocarbons (e.g. Whittaker 1991). However developments over the drawal related structure often with stacked reservoirs. In general the majority of the fields are continuous Gharif clastic reservoirs at a depth bility research is to take a first step toward alleviating these shortcomings by developing the results of recent work into a practical tool for us

ss the NMR signature as well as the RCI pressures and the successful recovery of 3 gas samples all indicate the likely mobility of gas.� exploration success rate in the North Malay basin with a total of eight discoveries six of which in PM301 and is now rapidly transitioning i by the hydrocarbon feed stream. (Losses are due to fuel gas and hydrocarbons left in the contaminant stream)

or Draugen uses a full-field reservoir-simulation model (FFM) based on a geological model with numerous faults. Replicating the dynamic co

amated channel sands massive sands and overbank deposits. The development of the Bonga field was based on five stacked reservoirs (

n the reservoir have historically led to the so-called ‘tank-model’ (Figure 3). Since 1993 70mmstb of oil has been produced through

re growth. Common approaches can be grouped into fully implicit simulators (Tran et al.) where both fluid flow equations and geomechanica es have been piloted at Peace River including in-situ combustion steam drive steam foam steam assisted gravity drainage (SAGD) and C 3D seismic data over the field were acquired in 2002 15 years after first production. The gas-bearing interval can be split into two main unit pertise and experience. The current shareholders are Gazprom 50% plus one share Shell 27.5% Mitsui 12.5% and Mitsubishi 10%. Shell The ability to manipulate (to some degree) the progression of the oil/water front provides the possibility to search for a control strategy that ng the remaining 1/3rd of STOIIP. For evaluation of capital intensive waterflood developments the operating asset team required that the su while production from Tunu was 1995 and from Ogbotobo in 1998. The drilling and production challenges from the Benisede and Opukushi f fractured water injection and related design and completion considerations for the water-injection wells to arrest the faster-than-anticipated the field. LD block is mainly a gas producer. The gravity of oil in LA and LB blocks is 35.3 and 37.2 deg API respectively with the solution G capacities causing a supply shortage. For North America East Asia and Europe the lack of recoverable gas resources is most sensitive an u Malaysia. Although Pearl GTL is around 10 times the size of Bintulu (14 700 b/d) the scale-up is being achieved by replicating smaller un a mismatch between water quality and recipient reservoir. Where targets are being achieved however it is often doubtful whether reservoi users of fresh water (>98%). On the other hand this industry also co-produces large volumes of water along with oil and gas production. Re alves) and the strategy about realizing process objectives.� Design decisions are made when devising the control strategy; if the level in a on logs and pulsed neutron spectroscopy helped in identifying depleted zones and zones of bypassed oil. Through-tubing isolation plugs (w

fined-turbidite systems in a mid-/lower-slope setting. The reservoirs are composed of fine-grained amalgamated channel sands derived from ater depths ranging from 950 to 1200 m. The main 702 reservoir which is expected to deliver over half of the recoverable reserves is comp ctivity probably because of the low VFA concentration in the PW. Consequently it was decided to terminate the application of nitrate to PW

acilities at down stream facilities are reported not to be Natl. Assn. of Corrosion Engineers (NACE) 175 compliant. This needs to be address ge of given specific field squeeze designs may be adapted to ensure optimum efficiency in terms of chemical usage minimised deferred oil the well locations well trajectories well controls etc. All these parameters have a significant impact on the amount of oil that can be recov t Maturation The development team followed a program called opportunity realization. Most of the major oil producing companies have sim divided by the hydrocarbon feed stream. (Losses are due to fuel gas and hydrocarbons left in the contaminant stream.) een very important for the reservoir management on Draugen1 2 4. An overview map of the Draugen Field is shown in Figure 1. The reserv ging tools.� The importance of surveillance for field management and further brownfield development cannot be underestimated even th

mized through a more deterministic instead of the previously adopted statistical infill drilling approach. Introduction The Omar field STOIIP e superscripts “prod and “inj refer to “production and “injection respectively. We note that the weights which are given func elopment project is planned to facilitate water flooding. The total scope of the project includes the installation of a new platform for offshore l e rock property model the probabilistic inversion the well inflow modelling and the dynamic simulation. Introduction The Lunskoye Field is nimization algorithm is critical. In a recent comparison of several gradient-based minimization methods Zhang and Reynolds2 showed that es et al. 2001 G�yag�ler et al. 2002 Yeten et al. 2003) and neural networks (Centilmen et al. 1999). The first category is generally ve -scale model of sand bodies with flow characteristics that can be monitored and modelled and that can be scaled to reflect fluid flow behav ance through dynamic reservoir modeling is therefore an integral component of risk analysis and uncertainty reduction strategies. Emerging long with economically rooted factors. The practice of forecasting recovery performance through dynamic modeling is an integral componen of the fluid when possible (e.g. changing from water based to oil based). In order to achieve partial or complete reduction of convection ins ce on the water injectivity and the areal distribution of the fluids in the reservoir. A qualitative example of the impact of the fracture orientatio Tran et al.5) where both fluid flow equations and geomechanical equations are solved at the same time on the same numerical grid and cou na such as shut-in clean-up and gas lift heading. Figure 1 displays the time and spatial scales for different naturally occurring and productio der investigation has most of its wells drilled with long laterals in a thin oil rim which have a strong tendency to gas-cone. Gas coning is a ph

eld was discovered in 1970 and went on production in 1972. Based on the fault structure and reservoir properties the Champion area is tra rmeability capillary number and non-Darcy flow need to be accurately modeled to estimate the gas-condensate-well deliverability accurate

metrically complex structured grids may fail to well capture the complex features unless very fine grid is used. This contributes to the need ervoir that represents geological features and heterogeneities at different length scales. The fine scale features have significant impact on r on ultimate oil recovery. A primary input to the reservoir simulator is the geological model of the reservoir commonly built as one or more g

or even within the same target zone where hydrocarbon fluids can move laterally. As a result the creation of a single EOS model mimicking sity is simultaneously history matched through the probability perturbation method of Caers (Caers 2003; Hoffman and Caers 2005; Caers 2 d’s Reservoir Management and Long Term Development Plan (LTDP). The overall objective of the study is to obtain a representative m n this case steam is injected at the top and oil recovered from the base of the fracture system. Again we compare fine-grid single-porosity

epwater wells and the techniques used to mitigate such challenges as related to GOM fields. Introduction Technological advancements’

al solutions to significantly speed up the analysis time without compromising on accuracy. The IPM Integrated Production System Modelling ons consistent with all dynamic data and prior geologic information. Predicting future reservoir performance with these multiple realizations entially a modification of Horner’s method (1967) and works well in reservoirs that can be treated as infinite during the time of the test. T

gy review and modelling is that it will enable early selection of water as the injection fluid. This means that surface engineering work can foc

he study suggests that single realizations of “best-guess geostatistical models are not guaranteed to offer the best history match and pe ulfill these demands.� This paper examines the current picture across Western Europe in the context of these trends and discusses how ifications for example semi-log water cut versus oil recovery and (3) observed trends for example linear water cut versus oil recovery. Wh that are coupled to reservoir simulators. This is the overall goal of the work described in this paper. Over the last few decades there have oding performance and remaining oil saturation distributions assessed. Introduction The complexity of carbonate reservoirs and the import duction in 2002 and as such constitutes the first commercial discovery in the Lower Safa Reservoir Units in the Abu Gharadig basin. Includin mixing which an injected slug undergoes. For example Solano et al. (2001) performing a range of one dimensional and two dimensional s

of this data acquired during early reservoir life. This data is typically obtained from uniaxial or hydrostatic tests using conventional core acqu t 95% and initial water saturation is connate water. The matrix porosity is high (~30%) while the matrix permeability ranges between 5 md-2 vity and into the fracture system at flow barriers. In the fracture system the oil forms a (thin) rim that can be produced. Production rates ach n rates achieved with a GOGD process are often low due to low matrix rock permeabilities capillary hold-up and re-imbibition effects. Capil n the Bentheim (Lower Cretaceous) reservoir which consists of a 30 m thick multi-Darcy shallow marine sandstone. The structure is a hea ith initial recovery factors (15 percent). This is understandable because the updated geological models honoring production data may be mo joint venture between AOSTRA and industry. This resulted in the first commercial pilot built from 1990 to 1992 in the same facility called Ph ir has undergone three stages of development with potential for miscible sour gas injection.� These stages are as follows; pressure deple sists of a series of highly deviated (horizontal) injector-producer pairs surrounding the South Pierce salt diapir. Each well pair approximately mple is the infamous 1979 blowout of Ixtoc-1 in the Gulf of Mexico (Lugo 1981) which led to an oil spill of an estimated 3.5 million barrel (Fi siness processes and permit people working with these processes to assimilate the huge and diverse volumes of data and information. In ver the last 40 years as follows: -��������� Electronic instrumentation on the wells and RTU/SCADA (“devices ypes and lack of shale isolation this completion method experienced high failure rates as dirtier more laminated reservoir sands were comp indicates that many of the world’s major hydrocarbon basins have been discovered and it is now getting progressively more difficult to easing well productivity to get more oil at this high oil price time but it has to be carried our properly. Although some success was achieved a-injection wells into a vast and largely thirsty reservoir. Ursa and Princess reside 100 miles south/southeast of the Mississippi River mout

ential recovery scope without resorting to detailed dynamic simulation. In the field studied full dynamic simulation was considered too resou

g into account all available data. The system also provides early warning to the field management team of any wells deviating from well rese

of the field and to inspect the waterflood progress. This approach allows reservoir characterization without requiring zonal isolation. It also h

d by production logging but it is costly and not in real time. Let us take the problem of underperforming wells in the Gulf of Mexico1 2. “ Introduction WFT has become a standard part of the evaluation program of most newly drilled wells but the objectives vary from offshore heem et al. 1993; Chin et al. 1993; Bruno and Bovberg 1992; Hamilton et al. 1992; Lewis and Sukirman 1993). The analytical/semianalytica

y universal in brown fields. Production logging provides a viable means of detecting and measuring downhole oil gas and water entry espe 6 807 850 and 851 – located in the Gulf of Mexico about 130 miles southeast of New Orleans. The leases were acquired in 1985 and 19 ffer a clear diagnostic value. Measurements and interpretation using this technique in two different settings are presented and discussed. I

ore CT operations normally it is time consuming especially rigging time crane usage boat/vessel availabilities and weather down time) Cos Introduction Openhole completions (Figure 1) are the most basic completion types in Niger Delta and are only used in very competent form r efforts have focused on describing what happens and when to resqueeze (Hong and Shuler 1988; Rogers et al. 1990). More recent paper calibration based on surface production tests where ideally the flow rates of each individual layer should be tested. In addition to measure

drilling operations predicting such parameters as BHP foam flow velocity foam density and foam quality is a major challenge. Unlike inco danger of formation breakdown and premature sand out which make sand control a requirement during their production lifetime. Historica 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

stly because the gas phase may start to dominate production which will deem the well to be uneconomical. Secondly the inflow of gas ma uction Across Canada thousands of gas wells leak substantial amount of gas to the surface. The 2002 survey of the Alberta Energy and Uti asurements. Simulation results have shown longer producing intervals than those derived from the DTS traces. The main reason for this cou

d reservoir heterogeneity (and wettability). The physico-chemical properties of the injected gas can also play an important role in efficiency o foam incompressibility makes this model unsuitable when pressure changes are relatively high in comparison with the backpressure. Moreo e bubble generation so that the kinetics of foam generation obeys a simple exponential growth function. When applied to transient foam th d. This changes when the reservoir depletes the reservoir pressure drops and the produced gas rates decline. The velocity at which the ga

the right countermeasure. Currently the most widely used model is still the classic Turner criterion which is based on a force balance on a arget the present work to increase reserves and production from a typical heavy oil reservoir e.g. Shell Canada’s Peace River asset. Q – and the lack of performance metrics in poorly negotiated long-term perforating service contracts. As a result Shell has initiated resear

e well could flow against the 70 bar back pressure an artificial lift technique was needed in the completion configuration as the current platfo ent. Being highly unconsolidated downhole sand exclusion is mandatory. The primary drive mechanism is a depletion drive based on the w ea water injection wells (two in the Princess field and two in the Ursa field) to enhance production in the main producing sand. Eight direct imary drive mechanism is a depletion drive based on the weak aquifers seen in existing fields in the area. The Shallow Clastics reservoirs o arbon production. Recently sand production accompanying hydrocarbon production has gained acceptance in some sectors of the industr

media. Fluid Preparations Certain aspects of sample preparation and handling may affect properties of a fluid. During all procedures step be supplied under a gas sales contract to the MLNG plants as shown in Figure 1. Long horizontal wells are drilled where there are no comp ressure transient data of fractured water injection wells. This contrasts to the vast amount of work that has been carried out in the area of p

e into account high pressures at the casing head (e.g. caused by leakage or thermal expansion of the annular fluids) high-pressure differe well was drilled using a semi submersible drilling rig. The Geological objectives for the well were to test the Middle and Lower Jurassic; Ga ertical connectivity and flow potential in thinly bedded environments. It will also be noted that the radius of investigation of a mini-DST is lim ell on test minimizing durations automatically validating the test result and electronically sending the result to recipient systems and then

ties for deployment of the technologies within Shell. Shell also provides the Vice Chairman for this initiative and has several key-players wor 87). It can be expected that in highly fractured coal systems the wetting behavior positively influences the efficiency of ECBM recovery. It is ation has many analogous features that are observed for organic sorbents penetrating into glassy polymers. In other words the application nd butt cleats in coal seams are usually subvertically oriented. Thus changes in the cleat permeability are primarily controlled by the prevaili

ons into the atmosphere. Notwithstanding technology the understanding of the storage geometry from the near surface to below the storag

of resources the production and use of fuels and the generation of electricity. Four sessions examined: the roles that CO2 capture and nges during its life. Wells are added and removed and gathering and injection systems and other facilities are modified and often expande tandards. This framework would enable energy companies to apply their expertise to innovate and compete using commercial product solut

well count and operation expense. Thus a full understanding of their physical-chemical behavior is warranted prior to any final investment of virtual meters includes for example van der Geest [4] which is based on physical models. A brief reference to using data driven models Shell’s PRODUCTION UNIVERSE project at a high level and share some of the experiences and findings of the first phase of the devel the “way we do business. Introduction Shell Exploration & Production in Europe operates a wide range of assets from new greenfield

provement effort a high level Leadership Intervention Workshop was conducted to identify and agree overall improvement priorities and a ' ven under the best scenarios however drill stem tests tie up expensive equipment for many days (or weeks) and are a major source of safe ut this paper. This type of testing in which we flow the hydrocarbons directly to surface while measuring the rate and the pressure is one of t

d to develop the CW field from the new platform as a “Smart Field and it was selected as the first candidate for implementation of “

re as a flooding optimization method by various authors.[3-7] However optimal control is computationally expensive and detailed manage e Production Universe Shell proprietary software is capable of continuously monitoring well production behavior and fine-tuning large dyna on of the ‘Value Loop’ repeating the cycle of measuring modeling decision-making and controlling to get the maximum amount of h n total the vertical sequence contains more than 100 individual reservoirs isolated by shale layers.

cleaning while primarily drilling with an aerated fluid. In the mid to late 1980’s drilling high angle or horizontal boreholes to maximize ex s perspective Managed Pressure Drilling is a basket of drilling techniques that can be adapted to solve drilling related problems reduce for voir1.� The oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide an arge. The principal concerns about fracturing during flooding pertain to length control and vertical containment. The fracture length must be his approach works well for tests carried out at room temperature and slightly higher but at higher temperatures there may be safety issues ock into the fracture system. In densely fractured reservoirs one relies on mechanisms like capillary imbibition or gravity to recover oil from eservoir scenarios in both vertical and horizontal flooding modes. Full-field air injection projects have been developed as recently as 19964 equired for miscible conditions. An important boundary condition for the miscible gasflood projects in the cluster is that the combined cluste can be described using a Herchel-Bulkley type of model where the constitutive parameters depend mainly on the bubble density also referr 0 stb/d and 54 mmscf/d respectively. Oil is piped to the Ekofisk Centre via a 20 inch pipeline tied into a T-junction with the Ula pipeline and

of the fracture network with a minor contribution from fluid expansion due to pressure reduction. At the end of the first year production had

(Robertson 2007). In-house research on this subject covered a broad range of disciplines including core flow and Amott imbibition experi through G—and multiple subunits within each layer. The upper layers A C D and E1/E2 are more intensely fractured than lower layers th ction associated with oil production has been reported as 33 million m3 or roughly 3 bbl of water for every barrel of oil (Bailey et al. 2000). at the theoretical depth then a pressure test is performed to confirm that the perforations are squeezed off. For intervals behind the sleeve e barrels of water for every barrel of oil (Bailey et al. 2000). The United States petroleum industry generates 2.4 billion m� of water annua quivalent of 200 years) before the same recovery is obtained from a meter-scale matrix block as is obtained from a centimeter-scale plug in eline to a production platform then through a network of pipelines to the export facilities. Bottlenecks that arise in the upstream supply chai ) the most popular global optimization algorithm is the GA6 7 8. Although the impact of non-smoothness in optimization problems is well a xploration and production with its challenging subsea environment and limited accessibility for intervention operations led to the birth of a n 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 ude oil to form a single phase through dynamic mass transfer interactions between oil and gas. When CO2 or any injected gas contacts the

ather tanning chemical manufacturing and waste disposal. The Hydrogen Sulfide (H2S) content of subsurface hydrocarbon reservoirs has er heavier charge. As such there is a tendency for the average API gravity GOR and bubble point to increase in successively deeper reser 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 pecies in the asphaltenes responsible for precipitation. Early identification of problematic fluids may aid process design and help to plan for ental results are also used to analyze and evaluate the performance of an ESP system when water cut increases and causes emulsion in a ime dependent. Therefore the results of the laboratory tests conducted at ambient conditions cannot be representative of rock/fluid interac

pplied with tremendous improvements in reservoirs previously stimulated with other mud acid systems. However field applications have sh

diversion methods such as viscous fluids foams ball sealers particulates and the maximized pressure differential and injection rates tech

rations becomes an inhibiting factor for wider implementation because the promise of production enhancement and dynamic reservoir char describe their formation. An outline mechanism for the formation of naphthenate deposits was presented previously by Rousseau et al.9. S

Introduction Scale formation in the near-wellbore area the tubing and in topsides facilities is one of the major challenges associated with o oir the steam flow rate should depend not on the downstream (reservoir) but on upstream pressure alone.� This condition is satisfied if th

EOR technique to work successfully in such a setting as Field B a vertically connected network of natural open fractures with small spacing billion barrels of 7�API oil in place trapped in approximately 30 m thick semi-consolidated sand layer (Fig. 2a) buried at a depth of about hilosophy recipe selection pumping procedures and consideration to trial similar Hydrogen delay retarded HF acid system (SRH-RHF) in 2 r is essentially a time-dependent quantity. This was already emphasized by several authors who derived explicitly time-dependent express production and to optimally use the steam to heat the bitumen. It was found that at a pressure of about 13MPa the injectivity increases dram ures. For instance the proximity of the reservoir fluid to its critical point at reservoir temperature and pressure has been known to impact the developed in a phased manner. The objective of Phase 1 was to gather data from a number of different sources to determine whether a mi maximum wormhole formation with a minimal volume of solvent. Control over reaction kinetics is vital when acidizing carbonate formations a ng arguments should be considered.� Individual pieces of information are seldom 100% convincing; conclusions must be reached from la

mplexity of the evaluation process and give them a process for evaluating stimulation effectiveness in their reservoirs. Introduction Devel nd flow rate of each productive layer. Additionally the method used to estimate layer properties in multi-layer low permeability gas reservo xist in North America for decades. It has only recently become possible to obtain economic production from them using improved hydraulic f true absolute permeability if it were measured using a liquid. For flow in tubes the gas slippage phenomenon has been investigated since

orizontal wells to allow a development well concept to be selected. A joint working group of both parties started to optimize the field develop nitial well capacity offshore Europe should be of the order of 1*106 m3/d (compared to 0.1*106 m3/d onshore USA) while the ultimate recov

onal resources (e.g. heavy oil tight gas ultra deepwater oil and gas). Shell is no different from other operators in this case in finding that lif

ecovery was eliminated by this effort needless to mention the accelerated revenue from the gas supply attributed to this improvement. The t the forecast is 'always' wrong" as demonstrated by observation of the discrepancies between prior point estimates and subsequent reality plementation of integrated surveillance technologies modeling tools decision-support and control systems within key development and pr ed reservoir trap. Because the water-filled rock is originally water-wet a certain threshold pressure must be reached before the capillary pr 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 eral field examples are presented to illustrate applicability in different environments. Introduction Reservoir-fluid samples collected at the e

ns for uncertain variables (Fig. 2). Monte Carlo simulation techniques become very time-intensive when used with high-resolution description sions at three depths in shale and one in highly depleted sand. Analysis of radial profiles in the two orthogonal directions indicates plastic yi

identify natural fractures before a stimulation treatment so that the appropriate design decisions can be made. In the past conventional we duction Carbonate strata may contain vugs or cavities several centimeters in size. A vug can be defined as any pore that is significantly larg eat practical value. As the permeability is entirely controlled by the pore geometry the possibility arises of estimating the permeability from q and thus improving reservoir knowledge is increasingly seen as an important driver for application of UBD. During UBD pressures and rat urrence of fractures only on one side of the fault may be interpreted either as fracture concentration at the hanging wall or within finely layer eismic faults or from dominant fracture strike in different sectors of the field. The dominant fracture orientation is WNW with one NW fault/ f oirs can be complicated by the complex reservoir architecture (Haddad and Cribbs 2002). Thus before the final investment decision on cap This paper includes examples in which we integrate pressure gradient PVT mud-gas geochemical and downhole fluid analyses with availa 1). However developments over the last 10 years have produced a step change in the quality and utility of mud gas data. Advanced mud ga s Gharif clastic reservoirs at a depth of 0.6 to 1.6 km with medium to high fault density. Some fields consist of three reservoir formations: Ma cent work into a practical tool for use in reservoir studies. Wettability is rated as one of the critical uncertainties in many fields particularly th

ndicate the likely mobility of gas.� Logging results from the highly overpressured Deep B sands indicate poor reservoir development with 01 and is now rapidly transitioning into a development venture. Block PM301 and PM302 are located in the Northern-most part of the Peni

us faults. Replicating the dynamic communication across several non-neighbor connections (NNCs) with hundreds of on-lap connections be

as based on five stacked reservoirs (690 702 710/740 740SE and 803) between 6 000 and 10 500 ftss covering over 60 km�. These re

b of oil has been produced through 11 long reach oil producers drilled horizontally into the oil rim from the Gannet A platform.� In order t

d flow equations and geomechanical equations are solved at the same time on the same numerical grid and coupled simulators (Clifford e sted gravity drainage (SAGD) and CSS. At present CSS with injection above fracture pressure is employed to extract the oil most recently terval can be split into two main units: the Upper Reservoir (Zone 1 and Zone 2) and the Lower Reservoir (Zone 3). The two reservoir units ui 12.5% and Mitsubishi 10%. Shell is the Technical Partner on this project. Sakhalin Energy is the operator of the Sakhalin II Project which to search for a control strategy that will result in maximization of ultimate oil recovery. Dynamic optimization of waterflooding using optimal ating asset team required that the subsurface models be robust with relatively long shelf life. Workflows and synergies were built across the s from the Benisede and Opukushi fields were used to prepare a reservoir management plan for the Ogbotobo field. to arrest the faster-than-anticipated pressure depletion in these shallow reservoirs. API respectively with the solution GOR being 80 sm3/sm3 and 88 sm3/sm3 respectively. The oil and water viscosities are around 0.57 and e gas resources is most sensitive and development of unconventional gas resources will be essential to satisfy future demands. Another op g achieved by replicating smaller units such as multiple parallel reactors to minimise technical risk. The Shell proprietary ‘Flawless’ it is often doubtful whether reservoir sweep satisfies projected needs for the very same (mismatch) reasons. Sub-specification water qualilong with oil and gas production. Recently the high price of oil and gas has led to a renewed interest in extending the life of existing fields th g the control strategy; if the level in a vessel is higher than the desired level the control strategy is either to open the valve of the liquid outle oil. Through-tubing isolation plugs (wherever applicable) were placed to isolate water-producing intervals. Oil in bypassed zones was tappe

gamated channel sands derived from the shelf margin to the northeast. The main 702 reservoir which is expected to deliver more than hal of the recoverable reserves is comprised of amalgamated turbidite channels. Typical net reservoir thickness is less than 100 ft with sand po nate the application of nitrate to PW on Draugen and control bacterial activity in the surface facilities with biocide. As nitrate is still promising

compliant. This needs to be addressed further as H2S levels seem to level out and the production system seems to cope with current cond mical usage minimised deferred oil production and extended squeeze life. Introduction Precipitation of inorganic mineral scale in producin n the amount of oil that can be recovered over the lifetime of the field. In this work our focus is well placement optimization. For the particula or oil producing companies have similar programs. There are five stages: assess select define execute and operate. At the boundary betw minant stream.) eld is shown in Figure 1. The reservoir is a low relief anticline with a maximum vertical closure of 50 m that trends north-to-south with an are cannot be underestimated even though the ultimate benefits are not always apparent in advance.� These benefits include for example

ntroduction The Omar field STOIIP of 760 MMstb is located for about 50% in the Cretaceous sheet-like shallow marine Lower Rutbah (RUL at the weights which are given functions of time can have arbitrary sign. This makes it possible to combine oil revenues and water costs in ation of a new platform for offshore living quarters seawater treatment and injection facilities and the drilling of six horizontal water injectors Introduction The Lunskoye Field is located in the Sea of Okhotsk offshore Sakhalin Island (Figure 1). Sakhalin Island is a product of a nor Zhang and Reynolds2 showed that the limited memory Broyden-Fletcher-Goldfarb-Shanno (LBFGS) method3 is relatively efficient for large 9). The first category is generally very efficient requires only a few forward reservoir simulations and increases NPV at each iteration. How be scaled to reflect fluid flow behaviour on a field-scale. The increase in costs associated with the push towards deepwater reservoir produ ainty reduction strategies. Emerging technologies such as geophysical reservoir monitoring (i.e. permanent sensors 4D seismic) and optim ic modeling is an integral component of risk analysis and uncertainty reduction strategies. When rigorously calibrated to geologic geophysi omplete reduction of convection insulating packer fluids have either a high yield point or very high viscosities at low shear rates. Historically the impact of the fracture orientation on the areal sweep is demonstrated in Fig. 1. We show streamlines in two different water-injection-pa on the same numerical grid and coupled simulators (Clifford et al.6) where a standard finite-volume reservoir simulator is coupled to a boun ent naturally occurring and production dynamical phenomena. The values of the time and spatial scales are indicative and based on experi ency to gas-cone. Gas coning is a phenomenon where the gas oil contact of a reservoir slowly moves towards a well as a result of oil drawd

properties the Champion area is traditionally delineated into 3 main areas: CPSE Block 13/14 and CP Main (Figure 1). Water injection in p ndensate-well deliverability accurately. The changes in the gas and condensate viscosity and density near the well may also be important in

s used. This contributes to the need for use of unstructured grid. Unstructured grid generation (UGG) techniques generally entail three steps eatures have significant impact on reservoir performance.1 2 However the fine scale geological model is too detailed to be accommodated oir commonly built as one or more geostatistical realizations and containing petrophysical properties constrained to data of different types a

on of a single EOS model mimicking the behavior of all reservoir fluids with a single PVT model has become a requirement. In order to acco ; Hoffman and Caers 2005; Caers 2007). The methodology is presented on a synthetic reservoir application. Introduction The modeling of study is to obtain a representative model that can be used to improve the reliability of the predictions of future performance for the reservoir we compare fine-grid single-porosity simulations with coarse-grid dual-permeability simulations. We show that in this case the constant (asy

ion Technological advancements’ considerable contribution to the revival of the GOM activities has been noted both in the overall projec

grated Production System Modelling software from Petroleum Experts was used as the tool in this study. Options to increase speed can be nce with these multiple realizations would provide for a measure of uncertainty in model forecasts leading to better reservoir development a infinite during the time of the test. The hyperbola method proposed by Mead (1981) and further developed by Hasan and Kabir (1983) is a

at surface engineering work can focus on water injection scenarios reducing the time required to identify a preferred development plan and

o offer the best history match and performance prediction. Multiple earth models must be built to capture the range of heterogeneity and as of these trends and discusses how these needs may be met. Specific emphasis has been placed on the U.K. which historically has been s ar water cut versus oil recovery. While these methods have been applied extensively none has been found to be sufficiently robust (5) and ver the last few decades there have been many analytical and numerical models presented for nonisothermal wellbore flow. This literature i carbonate reservoirs and the importance of a consistent approach in defining rock types have been a subject of several recent papers (Mar s in the Abu Gharadig basin. Including the discovery well a total of 9 wells and one sidetrack have been drilled to date (Fig 3). The informati dimensional and two dimensional simulations of enriched gas floods show that the recovery difference between the cases studied could b

c tests using conventional core acquired during the appraisal phase of the reservoir. This paper presents a case study from a green field res permeability ranges between 5 md-20 md. Under primary production the reservoir produces on average about 100 m3/day of 16o API “ be produced. Production rates achieved with this GOGD (Gas Oil Gravity Drainage) process are often low due to low matrix rock permeab d-up and re-imbibition effects. Capillary hold-up also negatively impacts ultimate recovery. e sandstone. The structure is a heavily faulted E-W trending anticline with a crestal collapse graben. Primary recovery was characterised honoring production data may be more heterogeneity and have tortuous connectivity. The updated models help capturing the full uncertaint o 1992 in the same facility called Phase B. This pilot had three wells pairs as well which were 70 m apart and had lengths of 500 m. This p tages are as follows; pressure depletion (1982 – 1986) gas injection (1992 – 2004) sour make-up gas injection (2004 – to date). Est diapir. Each well pair approximately covers one quarter of the total South Pierce reservoir area (see Figure 1). Initially water injection uptim of an estimated 3.5 million barrel (Figure 1 from the archives of Emergency Response Division Office of Response Restoration National O olumes of data and information. Introduction and Context During the past decade the concept of the Smart Field has developed from a wells and RTU/SCADA (“devices to digitize serialize and modulate telecommunications signals to a remote computer) -���� aminated reservoir sands were completed (Ali and Dearing 1996). The move from the shelf to deep water was another primary driver in effo etting progressively more difficult to find new and easy forms of conventional resources (see Fig. 2). Fig. 1 Reserves addition per decade. A hough some success was achieved current infrastructure for stimulation in the region still needs to be improved. Introduction Stimulating theast of the Mississippi River mouth in the Mars basin GOM. The Ursa field was discovered in 1990 and has been on production since 19

simulation was considered too resource intensive in view of the large number of reservoirs involved long production history and potentially

of any wells deviating from well reservoir management guidelines.� The intent of this technology is to enable more transparent sustaina

out requiring zonal isolation. It also helps to evaluate where the waterflood has influenced pressure maintenance. The results of the multi-r

g wells in the Gulf of Mexico1 2. “Well performance absorbs large-scale reservoir issues such as compartmentalization as well as chang ut the objectives vary from offshore deepwater exploration and appraisal wells to old cased-hole and development wells later in the life of a 1993). The analytical/semianalytical method refers to the use of the basic solution because of the center of dilation source (Mindlin and Ch

wnhole oil gas and water entry especially with the recent technological advances that significantly augment confident answers. The determ eases were acquired in 1985 and 1988 and the first discovery well was drilled on Mississippi Canyon Block 763 in 1989. Shell and their partn ngs are presented and discussed. Introduction The construction of horizontal wells and subsequent re-entry into horizontal drainholes is to

bilities and weather down time) Cost structure: coil tubing cost overruns overall stimulation cost Weather conditions make stimulation oper are only used in very competent formations which are unlikely to cave in. �These formations are often found deeper than 6000’ altho gers et al. 1990). More recent papers have advanced the knowledge of inhibitor reactions under various production conditions (Benton et al d be tested. In addition to measurement and control hardware smart-well operations require a control strategy. Present operation of smart

lity is a major challenge. Unlike incompressible drilling fluids foam is a compressible high-viscosity non-Newtonian fluid. Temperature pre g their production lifetime. Historically hydraulic fracturing has been applied to low permeability formations as a means of further stimulatio 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

ical. Secondly the inflow of gas may damage topside equipment that is not designed to process large quantities of this phase. Thirdly after survey of the Alberta Energy and Utilities Board indicates more than 3000 orphan wells in Western Canada many of which are leaking gas t traces. The main reason for this could be that the limited flow coming from the toe section in a horizontal well causes a minor temperature

play an important role in efficiency of foam in porous media. The growing concern about the global warming and shortage of energy supply arison with the backpressure. Moreover fractional flow models do not account for the evolution of bubble population and therefore might no . When applied to transient foam the SBP foam model does not require taking into account foam trapping because the yield stress of foam decline. The velocity at which the gas moves upward approaches the terminal velocity at which liquid droplets would fall downward in a stag

ch is based on a force balance on a falling droplet although it is known to not always be correct. In laboratories liquid loading occurs due t Canada’s Peace River asset. Quantitatively it means the development and utilization of technology that can increase the recovery by re s a result Shell has initiated research programs to build a better understanding of perforating phenomena - the results of which will feed ba

on configuration as the current platform infrastructure would not support installation of a gas-lift system. The idea of using one of the main g is a depletion drive based on the weak aquifers seen in existing fields in the area. The Shallow Clastics reservoirs overlay deeper Central L main producing sand. Eight direct vertical access wells from the Ursa TLP and three subsea Princess Wells will directly benefit from the p a. The Shallow Clastics reservoirs overlay deeper Central Luconia carbonate gas reservoirs which are already on production with further fie tance in some sectors of the industry as the fourth component of production stream: oil gas water and sand. In conventional operations sa

f a fluid. During all procedures steps shall be taken to minimize air entrainment into the fluid. The procedure used to prepare the fluid samp are drilled where there are no compartmentalization or baffles in the carbonate reservoirs. In addition the wells are completed with large tub has been carried out in the area of pressure transient analysis for wells with propped fractures. Both pressure transient tests during hydrauli

annular fluids) high-pressure differences always hold the risk of the casing bursting or collapsing at weak points leading to loss of productio t the Middle and Lower Jurassic; Garn Ile Ror/Tofte and Tilje Formations for the presence of Hydrocarbons (see Table 2 for details). The st of investigation of a mini-DST is limited typically within tens of feet. This paper demonstrates using field examples that reservoir boundarie esult to recipient systems and then selecting the next well to test? The purpose of this paper is to discuss Shell E&P experiences and rea

ive and has several key-players working on this project. CCP is an international collaboration among industry governments academics and he efficiency of ECBM recovery. It is generally accepted that the coal structure consists of the macrocleat and fracture system (>50 nm) and mers. In other words the application of theories of sorption behavior of polymers to coals has been proposed. During penetrant transport at re primarily controlled by the prevailing effective horizontal stresses that act across the cleats rather than the effective vertical stress define

the near surface to below the storage reservoir is mandatory. Another prerequisite for a successful operating storage project is the detailed

: the roles that CO2 capture and geologic storage may play over the next century; risk management to ensure safe and secure geolog ies are modified and often expanded. The capability of equipment also changes over time. The changes may be gradual such as a change pete using commercial product solutions from vendors who in turn apply their expertise to innovate and compete. The vision is of a healthy s

arranted prior to any final investment decision. In addition multiple high quality fluid samples within a given reservoir unit yield insights into r eference to using data driven models for virtual metering albeit using a less structured neural network approach is given in Oberwinkler et a ndings of the first phase of the development.�In particular we wish to highlight the PU application as an example of the innovative synthe ange of assets from new greenfield developments through to 30 year old brownfield platforms. Technology continually advances and whilst

verall improvement priorities and a 'LEAN�Breakthrough Team' was formed to spearhead "The Aera Way" of working. This meant that 'F eeks) and are a major source of safety and environmental risks such as flaring of the produced hydrocarbon gases. In our organization cos the rate and the pressure is one of the major tools petroleum engineers use to decide how to develop a hydrocarbon resource. In most sce

candidate for implementation of “Smart Well systems. The plan was to develop the field as a fully integrated remotely controlled and op

lly expensive and detailed management of every individual well of a smart field at every moment in time is economically and technically de behavior and fine-tuning large dynamic production systems in real time. Production Universe has proven that it can instantaneously identif ng to get the maximum amount of hydrocarbons out of the reservoirs in the most cost-effective way. � Fig.1 The Smart Fields� Value

horizontal boreholes to maximize exposure to reservoir rock created the need for further enhancements but for a different purpose; to redu drilling related problems reduce formation damage and or dynamically characterize production reservoirs (while drilling) to enable improved erature to produce carbon dioxide and oxygenated oil-phase products.� The resulting flue gas mixture which primarily consists of carbon nment. The fracture length must be limited to avoid interception with the production wells. Moreover the fracture half-length must be typica eratures there may be safety issues.� Specifically conventional sealed glass tube test methods may be problematic from a laboratory sa bibition or gravity to recover oil from the matrix reservoir rock. In the Middle East fractured carbonates are commonly oil wet or mixed wet a en developed as recently as 19964 5 (Horse Creek) and a range of field pilots and evaluation studies are underway or have been propose e cluster is that the combined cluster has to be self-sufficient in injection gas i.e. no gas will be imported from other sources. This means t nly on the bubble density also referred to as the ‘foam texture’. Since on a large scale foam generation occurs over a large number o T-junction with the Ula pipeline and then on to Teesside in UK. Gas is transported through a dedicated 12 inch pipeline to the Ekofisk Centr

end of the first year production had declined to a very low sustainable rate interpreted to be from gravity drainage from a combination of ga

ore flow and Amott imbibition experiments Colloid Chemistry and Petroleum Engineering. In this paper we describe the major results from o nsely fractured than lower layers the E3/E4 F and G reservoirs. Initial production from the reservoirs (1967 to 1970) was by natural deplet ery barrel of oil (Bailey et al. 2000). The U.S. petroleum industry generates 2.4 billion m3 of water annually (Sustainable Development 2004 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 ates 2.4 billion m� of water annually (DOE 2004). This amounts to an average of 7–8 barrels water per barrel of oil. Khatib et al. report ned from a centimeter-scale plug in a laboratory in 100 days. Consequently unless a significantly faster transport mechanism for the wetta at arise in the upstream supply chain can be a result of: Field composition (gas-liquid) changing over time and increased water content in ess in optimization problems is well acknowledged techniques to face this challenge especially in high dimension are being matured. Acco ion operations led to the birth of a new discipline called “flow assurance (i.e. keeping the flow path open). This original concept of flow a 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 CO2 or any injected gas contacts the reservoir oil at reservoir temperature the interfacial tension between the gas and oil diminishes as the

surface hydrocarbon reservoirs has a profound impact on completion design and on project economics in general. The need for accurate de crease in successively deeper reservoirs. If on the other hand the charge entering the trap is denser than the existing hydrocarbon column al fluid analyzer tool. This technique significantly improves real-time contamination monitoring and GOR prediction results for dark oils. Intr process design and help to plan for later stages of field development. Nevertheless the analysis of complex crude oil samples is a difficult ncreases and causes emulsion in a well. Introduction As an oilfield ages the rate of water production increases. With enough shear force e representative of rock/fluid interactions at real reservoir conditions. Hence the experimental study of time-dependent (dynamic) behavior

However field applications have shown that the performance of this HF system is sensitive to the nature and composition of sandstone for

e differential and injection rates technique (MAPDIR) have been used and are described in the literature.1-3�These methods will be brief

ncement and dynamic reservoir characterization are not properly quantified. Implementation of UBD in Russia Asia and other low-cost area ed previously by Rousseau et al.9. Subsequent studies have used this conceptual mechanism to study deposition in both model and field n

major challenges associated with oil production and so must be managed. The most severe problems are predominantly encountered durin ne.� This condition is satisfied if the flow rate through a perforation reaches its maximum value (i.e. steam velocity equals the sonic veloc

al open fractures with small spacings is critical (cf. Rawnsley et al. 2005). In a low permeability matrix the fractures are critical for distributin (Fig. 2a) buried at a depth of about 600 m and spread over approximately 370 km2. The Bluesky reservoir has been broadly classified into ded HF acid system (SRH-RHF) in 2005. The second Hydrogen delay retarded HF acid system (SRH-RHF) is supplied by another contracto d explicitly time-dependent expressions for the shape-factor for pressure diffusion processes [7-9]. An explicitly time-dependent formulation 13MPa the injectivity increases dramatically. The observed high flow rate cannot be explained by matrix flow alone. Furthermore the injecti ssure has been known to impact the sharpness of the gradient. And the presence of nearby conductivity variations (such as the existence o t sources to determine whether a miscible gas injection project would be feasible in some of these fields. Phase 2 will involve primary deple hen acidizing carbonate formations at high temperatures at which high reaction rates can overwhelm some treatment fluids. For compariso conclusions must be reached from layers of supporting evidence.� The jury must decide the verdict based on the confidence in the evide

heir reservoirs. Introduction Development of the Pinedale Anticline of southwestern Wyoming has continued at an aggressive pace over t i-layer low permeability gas reservoirs (Spivey 2006) requires that accurate flow contribution be measured for each productive layer. Since t om them using improved hydraulic fracture stimulation techniques during well completions. The Pinedale Field located in the Green River menon has been investigated since the end of the nineteenth century. The first study of gas slippage in porous media was conducted by Kl

started to optimize the field development concept in 2004 and identified costs saving potential and generated plans to get this tight gas fiel shore USA) while the ultimate recovery offshore Europe should be of the order of 1*109 m3 (compared to 0.1*109 m3 onshore USA). Henc

erators in this case in finding that lifecycle uncertainties in these developments tend to be harder to understand and manage thus adding c

attributed to this improvement. The paper concludes with Integrated Decision Making Strategy Value of Success and Recommendations fo nt estimates and subsequent reality (de Neufville and Odoni 2003). Note that this fact is not inconsistent with the notion of a most likely esti ems within key development and production processes. Integrated models of reservoir systems are detailed numerical representations th st be reached before the capillary pressure in the largest pore can be overcome and the oil can start to enter the pore. Hence the largest po a have three important features. First hydrocarbons have a characteristic mode around 1700 nm that is measured to estimate fluid compos rvoir-fluid samples collected at the early stage of exploration and development provide vital information for reservoir evaluation and manage

used with high-resolution descriptions of the stratigraphic architecture. We introduce a way to create relative permeability pseudofunctions t ogonal directions indicates plastic yielding or stiffening of rock in the near-wellbore region. While plastic yielding increases the shear slowne

made. In the past conventional well testing such as pressure-buildup tests has been used for determining the reservoir description. How as any pore that is significantly larger than a grain or inside of a grain. This definition includes moldic pores and intra-grain micro porosity. V of estimating the permeability from quantifiable attributes of the pore space. This problem can be addressed at various levels of detail with BD. During UBD pressures and rates at the inlet (injection into drill string and/or concentric gas injection annulus between casing and tie-b he hanging wall or within finely layered Lower Shu’aiba. The distribution of layer bound fractures is not only controlled by mechanical la ntation is WNW with one NW fault/ fracture zone on the western flank of this Field. There are also a few NE fracture corridors from short cut the final investment decision on capital-intensive deepwater developments compartments often have to be identified by some other means downhole fluid analyses with available geological and geophysical data for the identification of flow barriers evaluation of connectivity acro of mud gas data. Advanced mud gas (AMG) technology including offline and well site isotopic measurements now provides data and inter sist of three reservoir formations: Mahwis formation (the Haima group of combro-ordivician age) Al Khlata and Gharif formation (Huashi gro tainties in many fields particularly the Middle East carbonate fields. The ability to obtain wettability information at an early stage of field dev

ate poor reservoir development with low (< 5%) porosities and (residual?) saturations. n the Northern-most part of the Peninsular Malaysia acreage just south of the Malaysia-Thailand joint development area (MTJDA) as shown

h hundreds of on-lap connections between the different reservoirs in the simulation model poses significant challenges. 4D-seismic interpre

s covering over 60 km�. These reservoirs are generally less than 100 ft thick and measured sand porosities ranging from 25 to 35% are

he Gannet A platform.� In order to maintain the position of the oil rim the original Field Development Plan called for zero net gas produc

d and coupled simulators (Clifford et al.) where a standard finite-volume reservoir simulator is coupled to a boundary-element based fractur oyed to extract the oil most recently using closely spaced multi-lateral horizontal wells drilled from a central surface pad. The CSS target is oir (Zone 3). The two reservoir units are separated by a zone of relatively low porosity that forms a field-wide baffle (Zone 2.3). ator of the Sakhalin II Project which is governed by the Production Sharing Agreement signed in 1994 between the Russian Federation an ation of waterflooding using optimal control theory has significant potential to increase ultimate recovery by delaying water breakthrough and and synergies were built across the asset-study team interface to not only deliver quality FDPs but also through embedment ensuring suc botobo field.

ater viscosities are around 0.57 and 0.25 cp at reservoir conditions. satisfy future demands. Another option is an increase of supply from gas exporting regions with very large resources like the Former Sovie e Shell proprietary ‘Flawless’ start-up methodology has been applied from the outset whereby potential novelties and flaws are ident asons. Sub-specification water quali-ty may cause the injected water to predominantly enter highly permeable zones or create large fracture extending the life of existing fields through secondary and tertiary recovery processes (reservoir pressure support waterfloods and enhanc r to open the valve of the liquid outlet stream or to throttle a valve in the incoming stream. The right choice will depend on the process itself s. Oil in bypassed zones was tapped by additional perforations. An innovative approach used to calculate the formation water salinity throu

s expected to deliver more than half of the recoverable reserves comprises amalgamated turbidite channels. The other reservoirs are stac ness is less than 100 ft with sand porosities range from 20 – 37% and multi-Darcy permeabilities. Seawater injection for pressure mainten h biocide. As nitrate is still promising to be applied in PW in other field applications dedicated research has been initiated to learn more abo

em seems to cope with current conditions. Meanwhile in opposite having started production in the early 1970 Y field produces from the S inorganic mineral scale in producing wells is one of the biggest production challenges of the oil and gas industry as oil reservoirs are becom ement optimization. For the particular process of deciding the well locations a net-sand driven “engineering judgment approach is comm e and operate. At the boundary between each stage there is a value assurance review (VAR) challenge covering technical organizational a

hat trends north-to-south with an areal extent of 20 km by 6 km. �The field comprises two Mid-to-Late Jurassic sand reservoirs (Rogn an These benefits include for example optimizing production reducing watercut improving well performance optimizing water injection and s

shallow marine Lower Rutbah (RUL) and some 45% is contained in the Triassic coastal fluvial plane Mulussa F (MUF) formation. The field bine oil revenues and water costs in the lifecycle integral. Well control is modeled with one or more time-dependent well control variables p rilling of six horizontal water injectors and five infill producer wells. Treated seawater will be used as injection fluid at a total rate of 10 000 bb Sakhalin Island is a product of a northward propagating transpressive strike slip fault system. This generated island uplift affecting sedimen method3 is relatively efficient for large history matching problems. Thus in this study the LBFGS method is used for history matching of both creases NPV at each iteration. However these methods can get stuck in a local optimal solution. The second category can in theory avoid h towards deepwater reservoir production means that risks in exploration and development remain significant despite continual technologic nent sensors 4D seismic) and optimal reservoir management (i.e. smart completions) also heavily rely on dynamic modeling. In this perspe usly calibrated to geologic geophysical and historical production information reservoir performance forecasts facilitate optimal reservoir ma osities at low shear rates. Historically this has presented several problems relating to the unknown thermal and mechanical character of thes es in two different water-injection-pattern configurations for two fracture orientations (i.e. line-drive and five-spot geometry and fracture orie ervoir simulator is coupled to a boundary-element based fracture propagation simulator. Both approaches are not standard and currently no s are indicative and based on experience. There are several phenomena which have a certain amount of overlap. In these areas it is expect wards a well as a result of oil drawdown see Figure 1. At a certain moment in the production life of the well the gas oil contact will reach the

Main (Figure 1). Water injection in part of the Champion Main area commenced in 1984 while extension to Block 13/14 and CPSE areas wa ar the well may also be important in some cases. Coarse-grid simulations do not capture these effects accurately near the wells where they

chniques generally entail three steps: grid point insertion triangulation and construction of gridblocks. Insertion of grid points is completely a is too detailed to be accommodated by common reservoirs simulators due to mainly processing time. Although parallel processing is availa nstrained to data of different types and scales. These geological models are typically very fine (contaning 108 grid blocks or even more) be

ome a requirement. In order to accomplish a unified fluid description a stepwise approach was adopted. One of the fluids was considered ation. Introduction The modeling of the density and pattern of fracture distributions can take different approaches depending on the origin a future performance for the reservoir. The specific objective is to match the 20 years of production history and to predict field future performa w that in this case the constant (asymptotic) shape factor provides a good approximation to the heating of the stack. We will show howeve

been noted both in the overall projects executions and in data analysis and decision-making. According to Ildare1 “… the Gulf of Mexic

. Options to increase speed can be grouped into 3 categories: Selection of optimal solver and optimization settings and optimsed design o ng to better reservoir development and management strategies. This effort has been aided by the development of robust and efficient algor ped by Hasan and Kabir (1983) is an empirical technique not based on fundamental fluid flow principles for bounded reservoirs (Kabir and

y a preferred development plan and accelerating project implementation. Introduction The Champion field has been producing oil since 19

e the range of heterogeneity and assess its impact on reservoir flow behavior. Introduction The widespread use of geostatistics during the e U.K. which historically has been self sufficient in gas supply and compared to other European countries enjoyed significantly less storage und to be sufficiently robust (5) and for those not based on the fractional flow theory besides the problem of internal consistency curve-fitt ermal wellbore flow. This literature is reviewed in detail by Livescu et al. (2008) so our discussion here will be brief. The analytical models in ubject of several recent papers (Marzouk et al. 2000; Ramakrishnam et. al. 2000; Leal et. al. 2001; Porrai and Campos 2001; Giot et.al 200 drilled to date (Fig 3). The information of these wells in combination with production and well and reservoir surveillance data significantly im between the cases studied could be up to 8% of the original oil in place depending on the degree of dispersion. Similar observations have

s a case study from a green field reservoir in South Oman for estimating recovery from primary depletion and miscible gas injection proces e about 100 m3/day of 16o API “heavy oil at a GOR of 10 m3/m3. low due to low matrix rock permeability capillary hold-up and re-imbibition effects. Capillary hold-up also reduces ultimate recovery. Both m

Primary recovery was characterised by early aquifer water breakthrough and rapid pressure depletion. Consequently a number of small an els help capturing the full uncertainty ranges for recovery factor. The updated recovery uncertainty as well as reduced modeling parameters art and had lengths of 500 m. This pilot was operated until June 2004 with an ultimate recovery in excess of 65% and an Oil-Steam- Ratio ( gas injection (2004 – to date). Estimated ultimate recovery is 30.6%. Modeling work has indicated that miscible gas injection will increase ure 1). Initially water injection uptime was poor (complicating the data analysis) which was resolved towards the end of 2006. Overall the w of Response Restoration National Ocean Service National Oceanic and Atmospheric Administration) fouling a considerable part of the Tex 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 remote computer) -��������� Electronic instrumentation on the surface process (separators compressors pump er was another primary driver in efforts to increase reliability while maintaining the high flow-rate capability required for project sanction.� g. 1 Reserves addition per decade. Also indicated are some significant sour gas finds. With demand continuing to increase there is now a mproved. Introduction Stimulating of existing oil and gas producing wells and of new wells is one of the means to maximizing production p nd has been on production since 1999. The Princess field was discovered in 2000 and has been producing since December 2003 through a

g production history and potentially low remaining reward as the cumulative recovery efficiency attained has exceeded over 90% of technic

o enable more transparent sustainable and systematic management of smart well production systems through the use of real time data to im

ntenance. The results of the multi-rate multi-zone (MRMZ) production logging and testing combined with saturation trends confirm and prov

mpartmentalization as well as changes in local well skin with time that further comprises of completion perforations and near-wellbore effec evelopment wells later in the life of a field. Given the wide range of applications and combinations each WFT evaluation program is unique. er of dilation source (Mindlin and Cheng 1950) or numerical integration of the Green’s function because of the center of dilation source

ment confident answers. The determination of the water entry locations then provides a target for a water shut-off program with the objective ock 763 in 1989. Shell and their partner BP announced plans in 1993 to develop Mars utilizing a 24-slot tension leg platform (TLP) to be inst entry into horizontal drainholes is today a feasible option with the use of sophisticated directional drilling and measurement-while-drilling tec

er conditions make stimulation operation in conflict with other operations in a limited weather window. And added cost due to waiting for we n found deeper than 6000’ although each reservoir is different.� In the strict sense an openhole completion consists of simply runni production conditions (Benton et al. 1993; Sweeney and Cooper 1993; Lawless et al. 1993; Sorbie et al. 1994; Jordan et al. 1994; Jordan strategy. Present operation of smart wells is based mostly on a “reactive control strategy in which valves are closed in reaction to the br

n-Newtonian fluid. Temperature pressure foam quality foam density flow velocity and rheological parameters vary along the wellbore; in a ons as a means of further stimulation to increase the production rate.1 2 In the recent years hydraulic fracturing for controlling formation sa ct on fracture fluid clean-up was modeled using a modified reservoir simulator.7 8 The production simulation indicated clearly that yield stres

uantities of this phase. Thirdly after breakthrough the gas cap of the oil reservoir will be depleted fast taking away its drive energy. The dif ada many of which are leaking gas to the surface or underground formations. Leakage causes pollution of subsurface waters loss of petrol al well causes a minor temperature disturbance which can be overlooked easily in the DTS traces (Ouyang and Belanger 2006). Good resu

ming and shortage of energy supply has increased the interest in combined geological CO2 storage and Enhanced Oil Recovery applicatio le population and therefore might not be accurate when describing transient motion [3]. Percolation models which take into account the por ng because the yield stress of foam is low and then foam trapping is unlikely to occur.11 This is in good agreement with studies of tracer tr oplets would fall downward in a stagnant gas1 2. This means more liquid will be retained in the casing or tubing. The consequence of liquid

oratories liquid loading occurs due to the drainage of the liquid film which is present at the tubing walls in annular flow (Belt 2008 Westenen that can increase the recovery by relatively uniform deposition of large amounts of heat in a reservoir. One of such technologies is the limit na - the results of which will feed back into the software refining its capabilities and increasing the user’s ability to design and simulate

The idea of using one of the main gas reservoirs as a source of gas lift was investigated and found to be feasible. Another technology cons reservoirs overlay deeper Central Luconia carbonate gas reservoirs which are already on production with further fields in development; the Wells will directly benefit from the planned water flood. The current lack of pressure support in the reservoir sand results in relatively low rec already on production with further fields in development; therefore a gas-processing and gathering system was already in place. Gas from sand. In conventional operations sand production like water production commonly occurred unexpectedly requiring ad hoc modifications in

edure used to prepare the fluid sample shall be documented as follows: a) Description and/or composition of the base fluid; b) Base fluid pr he wells are completed with large tubing size (7.5/8 tubing). The wells are cleaned up using a clean up package; stimulated with acid; furthe ssure transient tests during hydraulic fracture stimulation (called “minifrac tests) (e.g.1) and pressure transient tests during production a

ak points leading to loss of production (Vargo et al. 2002) or in the worst case loss of the well (Nelson 2002). For this reason most operatin bons (see Table 2 for details). The stacked reservoirs were sandstones with intercalated shales belonging to the Fangst and B�t Groups. d examples that reservoir boundaries can be detected when sufficient radius of investigation is achieved. In addition the understanding of l cuss Shell E&P experiences and real time software applications relating to the above well test optimization and automation issues.

dustry governments academics and environmental interest groups focused on developing technology for CO2 capture and geological stora at and fracture system (>50 nm) and the coal matrix (<50 nm). The macrofracture system is initially filled with water and provides the condui osed. During penetrant transport at low or moderate temperatures into the macromolecular network of coal the network density decreases n the effective vertical stress defined as the difference between the overburden stress and pore pressure (Harpalani and Chen 1997). Coa

ating storage project is the detailed knowledge of rock and fluid properties that do depend on pressure and temperature conditions. These d

nt to ensure safe and secure geologic storage drawing from understanding and past experiences; public perception policy and regulato s may be gradual such as a change in compressor efficiency or the performance of a well zone or it may be a step change after equipmen compete. The vision is of a healthy solution marketplace with a vibrant energy company environment all geared to define how to operate an

en reservoir unit yield insights into reservoir fluid grading and compartmentalization; complexities that have to be captured in static and dyn pproach is given in Oberwinkler et al. [3]. A recent paper that touches on the potential for data driven modelling is [22] by Stone. Well three an example of the innovative synthesis of oil and gas operational and technical expertise and state of the art mathematical techniques. His gy continually advances and whilst new development may have the latest technology the business case for large investment on brownfield

Way" of working. This meant that 'Fix-the-Basics' activities and 'LEAN�Process' implementation had to take place in parallel. This article rbon gases. In our organization cost and HSE concerns have driven us to seek better ways to obtain similar reservoir and fluid data. We ha hydrocarbon resource. In most scenarios these drill stem tests tie up expensive equipment for many days and additionally are a major sou

ntegrated remotely controlled and operated field where regular pressure temperature fluid and flow data is continuously gathered and imm

me is economically and technically demanding. Moreover there may not be enough information in the system to determine the optimal prod en that it can instantaneously identify problems in a well increase production and improve well test frequency. It is self-learning system upd ½ Fig.1 The Smart Fields� Value loop concept � Monitoring and Optimising Production in Real Time Production Universe Shell’

s but for a different purpose; to reduce formation damage caused by fluid invasion as a result of the longer exposure time required to drill th irs (while drilling) to enable improved reservoir management. It is also worthy to note that not all Managed Pressure Drilling tech-niques req e which primarily consists of carbon dioxide and nitrogen provides the mobilizing force to the oil downstream of the reaction region sweep e fracture half-length must be typically less than one-third of the distance between the injector and producer to obtain good areal sweep and be problematic from a laboratory safety standpoint at higher temperatures due to the vapour pressures from water and crude oil.� This p re commonly oil wet or mixed wet and the main production mechanism is gravity. Once a gas cap is established in the fracture system the are underway or have been proposed in recent times; these have tended to focus on the use of the process for tertiary recovery including th ed from other sources. This means that the miscible agents need to be a cocktail of associated gas and gas from the only gas condensate r eration occurs over a large number of randomly interconnected pores bubble generation can be treated as a stochastic process. The kineti 12 inch pipeline to the Ekofisk Centre and sold to the Ekofisk Group (Fig.-2). An extension of the license period to 2018 was granted in 2006

y drainage from a combination of gas-oil (GOGD) from the secondary gas cap and oil-water (OWGD) below the fracture gas-oil contact (FG

we describe the major results from our study and indicate where this technology can be most favourably applied. 1967 to 1970) was by natural depletion supported by gas injection in the A reservoir unit from 1968 onward. After this initial period of gas in ally (Sustainable Development 2004).�This amounts to an average 7 to 8 bbl of water per 1 bbl of oil.�Water production within the one ssible because the perforations are behind the production tubing. For such single-string selective completions only a pressure test can be p per barrel of oil. Khatib et al. reported in SPE 73853 that water production within the Shell Group increased from 350 000 m�/D in 1990 r transport mechanism for the wettability modifier is identified or unless viscous forces or buoyancy enable forced imbibition the chemical w time and increased water content in the oil-water liquid stream due to ageing of fields. Increasing use of existing infrastructure for the imple dimension are being matured. According to Clarke9: “Just as “non-linear is understood in mathematics to mean “not necessaril open). This original concept of flow assurance has grown today into an industry-recognized multidisciplinary area that had been successfull 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 en the gas and oil diminishes as the miscibility is approached and the interface between them eventually disappears at miscibility i.e. the inte

in general. The need for accurate determination of H2S concentration in the reservoir fluids to be produced is crucial. It may mean higher p 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 R prediction results for dark oils. Introduction Real-time estimation of sample contamination by drilling-mud filtrate is critical for the collectio mplex crude oil samples is a difficult endeavor due to the presence of an incredible number of compounds [Qian et al. 2001 Panda et al. 2 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 ime-dependent (dynamic) behavior of interfacial properties (IFT and contact angles) at reservoir conditions (high temperature and high pres

re and composition of sandstone formations. The unique formulation of this HF system contains HV Acid and additional proprietary compon

e.1-3�These methods will be briefly discussed in this paper together with a description of how these methods are modeled in the FPS. Be

Russia Asia and other low-cost areas will face similar hurdles. The UBD-implementation predicament is that while we need to prove value t deposition in both model and field naphthenate systems11. Naphthenic acids in hydrocarbons are defined as compounds containing carbo

are predominantly encountered during oil and condensate production where the thermodynamic driving force for scale deposition is caused steam velocity equals the sonic velocity) which is the critical flow condition. This means that providing the flow is critical as long as the pres

he fractures are critical for distributing the heat of the injected steam into the reservoir to reduce the viscosity of the oil. The fractures also n voir has been broadly classified into two intervals poorer quality Estuarine and good quality Deltaic (Fig. 2b). CSS is employed to extract th HF) is supplied by another contractor. SRH-RHF was applied in heavy crude with fines problems and the results of the trial were remarkable explicitly time-dependent formulation however is quite cumbersome for implementation in a reservoir simulator because each grid-block w x flow alone. Furthermore the injection pressure is close to the vertical stress. As part of a strategy to gain a better understanding of the CS y variations (such as the existence of salt structures) or changes in the overburden thickness may create the temperature differential neede s. Phase 2 will involve primary depletion in a number of fields followed by gas injection in some of them and Phase 3 will involve Cluster wid me treatment fluids. For comparison sandstone reservoirs undergo matrix acidizing treatments to remove damaging aluminosilicate miner ased on the confidence in the evidence and various risk thresholds may be applied (“the preponderance of evidence or “beyond a

tinued at an aggressive pace over the past several years.�Massive hydraulic fracturing (MHF) treatments are the only means of stimula ed for each productive layer. Since the method requires multiple measurements over time as an input to the history match consistent meas le Field located in the Green River Basin Wyoming USA is an example of a large gas accumulation in this type of tight reservoir (Figure 1 porous media was conducted by Klinkenberg.1 The Klinkenberg model approximates a linear relationship between the measured gas perm

erated plans to get this tight gas field developed fulfilling both company’s economic requirements. In 2005 a modified PSC was signed to 0.1*109 m3 onshore USA). Hence the challenge has been to boost the well capacity and increase ultimate recovery of these tight gas w

derstand and manage thus adding complexity to the already difficult process of project engineering decision-making. We believe that Smar

f Success and Recommendations for future interventions. Introduction / Problem Statement Multi-rate build-up tests were carried out on GC t with the notion of a most likely estimate which represents a balance between the possible upside and downside values of a parameter. A etailed numerical representations that have been developed by systematic linkage of the interpretations made by various geoscience and e enter the pore. Hence the largest pore throat determines the minimum capillary rise above the free-water level (FWL). As shown schematic s measured to estimate fluid composition and GOR (Dong et al. 2003). Second hydrocarbon spectra show a continuously increasing absor for reservoir evaluation and management. Reservoir-fluid properties such as hydrocarbon composition GOR CO2 content pH density vis

ative permeability pseudofunctions to be used in conjunction with rapid coarse-scale dynamic models which overcome the time-intensive n yielding increases the shear slowness stiffening would reduce the shear slowness. Introduction Formation stresses play an important role

mining the reservoir description. However these techniques often prove costly both in terms of additional equipment requirements and delay ores and intra-grain micro porosity. Vugs are commonly present as leached grains fossil chambers fractures and large irregular cavities. V ssed at various levels of detail with the resulting models requiring varying amounts of microstructural data. At one extreme simple models on annulus between casing and tie-back) and outlet (choke) are usually measured. Downhole conditions (temperature flowing wellbore pres not only controlled by mechanical layers but also structural configuration. Fracture Corridors Detectible By Seismic Data Mapping diffuse f NE fracture corridors from short cuts image logs and well alignment. An inferred corridor is extended in selected direction (WNW or NW) o be identified by some other means. During exploration and early appraisal phases various techniques such as geochemical fingerprinting riers evaluation of connectivity across faults and prediction of fluid contacts. Downhole Fluid Analysis In recent years formation sampling ements now provides data and interpretation suitable for “formation evaluation rather than basic mud compositional assessment (Kand ata and Gharif formation (Huashi group of Carboniferous/Permian age). The oil is medium to heavy and characterised by very low gas conte mation at an early stage of field development is a significant improvement over current practices.

evelopment area (MTJDA) as shown on Figure 1. Geologically the acreage covered by PM301 may be divided into three zones; the Basin

ant challenges. 4D-seismic interpretation of the water influx is important for establishing fault communication and modifying the geological

rosities ranging from 25 to 35% are associated with multi-Darcy permeabilities. Plan called for zero net gas production from the gas cap.� During the life of the field however 120 Bscf of free gas has been produced

o a boundary-element based fracture propagation simulator. Both approaches are not standard and currently not used in the industry mainl ntral surface pad. The CSS target is the Bluesky formation an approximately 30 m thick semi-consolidated sand layer buried at a depth of wide baffle (Zone 2.3). between the Russian Federation and Sakhalin Energy. The Sakhalin II Project comprises the development of two fields: Piltun-Astokhskoye by delaying water breakthrough and increasing sweep as has been shown in various studies (Brouwer and Jansen 2004). However optim o through embedment ensuring successful execution. Fig.2 shows the cluster study work flow. The� study clearly demonstrates that a b

rge resources like the Former Soviet Union and the Middle East but this also requires much higher interregional transport capacities. Introd otential novelties and flaws are identified and addressed. Work on the project began in February 2002 with a scoping study agreed betwee eable zones or create large fractures in unwanted directions. When contemplating PWRI for reservoir management purposes the cost of a re support waterfloods and enhanced oil recovery) developing previously uneconomical or marginally economic fields. These activities hav ce will depend on the process itself and the process objectives of the integrated facility (i.e. the consequences of the strategy upstream or d te the formation water salinity through pulsed neutron logging allowed the identification of zones of injection water breakthrough. Such inter

nnels. The other reservoirs are stacked either above (690) or below (710/740 803) and are generally less-well amalgamated. Net reservoir awater injection for pressure maintenance and sweep is key to the success of the Bonga development. A total of sixteen wells (nine produce has been initiated to learn more about the mechanisms leading to the increased corrosion rates seen when applying nitrate in PW. Introdu

ly 1970 Y field produces from the S (sour) and the H (sweet). Both reservoirs are mature needing artificial lift to sustain high water cut prod s industry as oil reservoirs are becoming more mature and watercuts are increasing. The most common scales are carbonates caused mai neering judgment approach is commonly applied in conventional practice. It is desirable however to execute a more systematic and object e covering technical organizational and other business aspects of an investment opportunity. Following each review there is a formal mana

e Jurassic sand reservoirs (Rogn and Garn) separated by a shale (Lower Spekk) up to 10 m thick that pinches out to the west of the field.ï¿ nce optimizing water injection and sweep efficiency and identifying unswept areas of the field to target with further infill drilling activities.�

ulussa F (MUF) formation. The field is an elongated high relief tilted horst block which is internally compartmentalized. The field is delimite e-dependent well control variables per well. For conventional wells there is just one control variable which can be tubinghead pressure (TH ction fluid at a total rate of 10 000 bbl/d for each injection well. First water is to be injected in 2010 however at the time this study was cond rated island uplift affecting sediment supply to the east Sakhalin shelf from the late Miocene onwards. At the crest of the Lunskoye anticline d is used for history matching of both production and seismic impedance change data. econd category can in theory avoid this problem but has the disadvantages of not increasing NPV at each iteration and requiring many for ficant despite continual technological advances. The understanding of risk and uncertainty in these frontier environments presents a major on dynamic modeling. In this perspective future forecasts of reservoir performance are used to optimize reservoir management decisions. ecasts facilitate optimal reservoir management decisions on correct premises. History matching the calibration of the reservoir model to dyn mal and mechanical character of these non-Newtonian fluids. In the case of Newtonian fluids the solutions to the convection and mechanica five-spot geometry and fracture oriented toward the producer and away from the producer. The density of the streamlines indicates that the es are not standard and currently not used in the industry mainly because reservoir models need to be purpose-built and numerical stabilit f overlap. In these areas it is expected that the well dynamics are strongly influenced by the reservoir dynamics and visa versa. Simulations well the gas oil contact will reach the well and the well will experience high influx of free gas. A second important issue which is causing pro

to Block 13/14 and CPSE areas was planned for 2003 and beyond. A successful drilling campaign of highly deviated/horizontal wells has r accurately near the wells where they matter the most and dominate the production rates. Fine-grid compositional simulations or simulation

nsertion of grid points is completely arbitrary and is the main advantage of UGG. It is well understood that computational grid points have to lthough parallel processing is available nowadays it is not well capable of solving this problem given the fact that geological models are be ng 108 grid blocks or even more) because of significant impact of fine scale features on reservoir flow performance1-3. In practice however

d. One of the fluids was considered as the base fluid and then various EOS tuning parameters were modified to approximate the behavior o pproaches depending on the origin and the type of fracture sets and on the ultimate reservoir engineering questions raised. In this paper w y and to predict field future performance with three flow-simulation models that represent the Low (pessimistic) Medium (most-likely) and H of the stack. We will show however that with a constant (time-independent) shape factor the initial fast heating of the matrix blocks canno

to Ildare1 “… the Gulf of Mexico OCS has re-emerged as a global petroleum frontier. .… The 5 600 active leases in 1992 have risen t

ation settings and optimsed design of the calculation engine of the software. There is often little that can be influenced on this other than cer lopment of robust and efficient algorithms for automatic and assisted history matching 1-3 and availability of greater computational power. T s for bounded reservoirs (Kabir and Hasan 1996). Chacon et al. (2004) develop the direct synthesis technique in which conventional theory

ield has been producing oil since 1972 with current production of less than 20% of the STOIIP. Reserves replacements from infill drilling ar

read use of geostatistics during the last decade has offered us both opportunities and challenges. It has been possible to capture vertical a es enjoyed significantly less storage capacity (as a proportion of annual consumption) than most of its neighbours whilst it faces the greate em of internal consistency curve-fitting by simple polynomial approximation do not result in satisfactory answers in most cases (6). Assump will be brief. The analytical models include among others those of Ramey (1962) Satter (1965) Hasan and Kabir (1994 1999 2002 2007 ai and Campos 2001; Giot et.al 2000; Silva et.al. 2002; Hamon 2002; Masalmeh and Jing 2004). Current practices in general are either bas voir surveillance data significantly improved the understanding of the field. At first the field was believed to consist of one single hydrocarbo spersion. Similar observations have been made by others (Haajizadeh et al. 1998; Jessen et al. 2002; Moulds et al. 2005). Dispersion is a

on and miscible gas injection processes and highlights the importance of using the correct PVC in undersaturated oil reservoirs. The reserv

o reduces ultimate recovery. Both miscible gas injection and steam injection are feasible EOR processes to accelerate the production and

Consequently a number of small and large scale secondary and tertiary EOR methods were employed including cold and hot water injecti well as reduced modeling parameters uncertainties help correct business decisions. Furthermore the updated response surfaces show conf ss of 65% and an Oil-Steam- Ratio (OSR) of 0.42. Since then more than 10 commercial SAGD projects have been operating in Canada m t miscible gas injection will increase the oil recovery factor to 36% (Figure 9). wards the end of 2006. Overall the waterflood response is considered to be effective in terms of increasing the reservoir pressure while the ouling a considerable part of the Texas coastline. Between August 6 and September 13 1979 approximately 24 000-32 000 bbl of oil were re several operators notably BP Chevron Norsk Hydro Saudi Aramco Shell and Statoil have flagship fields where many but probably n ess (separators compressors pumps) acquired by SCADA -��������� Distributed Control Systems starting to rep ity required for project sanction.�Also the capability to expose increased reservoir rock in low-productivity reservoirs has led to higher pro ntinuing to increase there is now a need to consider more difficult resources and hence more ‘expensive to produce’ resources. The e means to maximizing production potentials without requiring extra facilities and drilling new wells. A synergized stimulation process among cing since December 2003 through a subsea tieback to Ursa. The fields have their main reservoirs in common and are in pressure commun

d has exceeded over 90% of technical ultimate recovery. The results of bypassed oil identification however may lead to recommendation fo

hrough the use of real time data to improve the understanding of reservoir behaviour and to allow early intervention to optimize production a

h saturation trends confirm and provide valuable data for the reservoir modeling. Another benefit of the step-rate production testing is the e

perforations and near-wellbore effects. Therefore multiple explanations can be given to the problem. Apparent compartmentalization and ub WFT evaluation program is unique. Some may include only a pressure-gradient survey for reservoir depletion and communication informat use of the center of dilation source over certain reservoir shapes in a poroelastic medium (Geertsma 1966 1973; Segall 1985). Compared

r shut-off program with the objective of restoring oil inflow. Difficulties in acquiring quality data in horizontal flow environments specifically w tension leg platform (TLP) to be installed on Block 807. The TLP was installed in May 1996 in a water depth of 2 940 feet. Production began g and measurement-while-drilling techniques. However a horizontal well is never truly horizontal along its whole length; it varies in true verti

nd added cost due to waiting for weather time. Contractual limitations An initiative of conducting stimulation campaigns in the region was completion consists of simply running the casing directly down into the formation leaving the end of the piping open without any other prot al. 1994; Jordan et al. 1994; Jordan et al. 1995; Jordan et al. 1997; Lawless and Smith 1998; Smith et al. 2000; Collins 2003). The primary c alves are closed in reaction to the breakthrough of water or gas. The present paper proposes a more “proactive strategy to continuously

ameters vary along the wellbore; in addition frictional pressure gradient hydrostatic pressure gradient and acceleration pressure gradient a racturing for controlling formation sand and enhanced productivity in high permeability unconsolidated formations has gained broader accep 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

aking away its drive energy. The difficulty of containing these three negative consequences lies in the relative speed of a gas breakthrough of subsurface waters loss of petroleum resources and expulsion of green house gases into the atmosphere. Companies have reported hu ang and Belanger 2006). Good results from the initial calculations gave enough confidence to continue with the smart well; a more-complic

d Enhanced Oil Recovery applications [12-14]. Although the geological storage of CO2 is considered as an attractive solution for global war dels which take into account the pore level mechanisms for the foam seem unlikely to be useful in transient displacement in large scales be d agreement with studies of tracer transport during foam flow in porous media using X-ray tomography which showed that foam could be tr r tubing. The consequence of liquid accumulation in the well is an increase in the hydrostatical pressure drop over the well. Since the well h

n annular flow (Belt 2008 Westenende 2008). In practice the production decline may also be due to other mechanisms which may be diffic One of such technologies is the limited-entry perforation (LEP) technique originated from the “pin-point method which was commonly ut ’s ability to design and simulate perforating operations - is driving the development of new performance benchmarks and is rethinking

e feasible. Another technology considered was the intelligent completion concept1 2 which allows real time monitoring of pressure and tem with further fields in development; therefore a gas processing and gathering system was already in place.� Gas from all the fields is prod rvoir sand results in relatively low recovery efficiencies. Under the proposed development plan the four injectors are expected to maintain h em was already in place. Gas from all of these fields is produced to the Malaysian Liquified Natural Gas (MLNG) plants at Bintulu East Ma dly requiring ad hoc modifications in order to maintain hydrocarbon production. Sand management like water management before it antici

on of the base fluid; b) Base fluid pre-treatment such as filtration; c) Preparation of the fluid shall be described starting with the base fluid s package; stimulated with acid; further cleaned up before being tied into the production facilities. Tradiitionally coiled tubing has been used fo re transient tests during production after stimulation (that is build-up tests) (e.g.2-5) have been studied extensively. The theories as develop

2002). For this reason most operating companies adhere to annular-pressure-management schemes for onshore and platform wells which g to the Fangst and B�t Groups. Separate by shale intervals (Not Ror) typically formed intra-formational seals. The main objective of th d. In addition the understanding of limitations and advantages will allow the proper selection of test types in order to meet specific objective tion and automation issues.

or CO2 capture and geological storage. The CO2 Capture Team (CCT) conducts Shell’s participation in the CO2 Capture Project (CCP d with water and provides the conduits where the mass flow is dominated by Darcy flow. The coal matrix can be subdivided in mesocleats (fr coal the network density decreases. (Ritger et al.1). Therefore it is asserted that an increase of the penetrant concentration of the network ure (Harpalani and Chen 1997). Coal swelling accompanying CO2 sorption would decrease the permeability of the coal as the volume increa

and temperature conditions. These data serve as an input for reservoir models and decisions on the injection regime as well as decisions o

ublic perception policy and regulatory frameworks that present both opportunities for and barriers against CO2 capture and geologic stora ay be a step change after equipment is overhauled or modified during maintenance. Measurements and reference parameters abound and geared to define how to operate and optimize production in innovative ways with greatly reduced development costs. Savings were project

ave to be captured in static and dynamic models for determining in place volumes and ultimate recovery. Notionally during the exploration a odelling is [22] by Stone. Well three phase oil water and gas production is conventionally measured via the periodic routing of the well to a e art mathematical techniques. Historically the oil and gas production industry has relied on traditional methods for individual well productio e for large investment on brownfield assets is not always clear cut. One such brownfield facility is the Nelson Platform constructed in 1994

to take place in parallel. This article briefly describes the recent journey and reports some of the key results and learnings. Fix-The-Basics milar reservoir and fluid data. We have coined the term Optimal Value Testing (OVT) and defined it as any fit-for-purpose well test with minim ays and additionally are a major source of safety and environmental risks. Flaring of the produced hydrocarbon gas is a common example o

ta is continuously gathered and immediately transmitted to end users for on line monitoring and control. Production allocation was to be a

ystem to determine the optimal production strategy uniquely. Hence we seek to develop management strategies with a restricted number uency. It is self-learning system updating the calibration models using well test and real-time data as they are generated. Shell is currently ime Production Universe Shell’s proprietary software is capable of continuously monitoring well production behaviour and fine-tuning l

ger exposure time required to drill the lateral sections. Today underbalanced drilling has evolved where the primary well control function of t ed Pressure Drilling tech-niques require a closed loop system. Introduction Shell has deployed underbalanced drilling in oil and gas reser-v tream of the reaction region sweeping it to the production wells.� The gas-oil mixture may be immiscible partly or completely miscible.ï¿ ucer to obtain good areal sweep and to ensure that fracture growth will not be detrimental to the pattern sweep regardless of the principal h from water and crude oil.� This paper presents the results of the evaluation of surfactants using improved phase behaviour experimenta ablished in the fracture system the oil will drain down the matrix rock driven by gravity and into the fracture system at flow barriers. In the fr ess for tertiary recovery including the potential of the process for use offshore in the North Sea6 7. One example of the successful applica gas from the only gas condensate reservoir in the cluster. As no additional gas will be imported full voidage replacement in the entire cluste d as a stochastic process. The kinetic of foam generation can thus be described by a simple exponential growth law involving only two unkno e period to 2018 was granted in 2006. Annual oil and gas production to date is shown in Fig.-3. During 1988 and 1989 a total of eight temp

elow the fracture gas-oil contact (FGOC). The reservoir then consists of a matrix with very little drainage and a fracture network with a thin o

y applied. ward. After this initial period of gas injection water injection was implemented in the A C D and E reservoirs (1970 through 984). Previously .�Water production within the one group has roughly increased from 350 000 m3/d in 1990 to more than 1 000 000 m3/d today (Khatib a etions only a pressure test can be performed to confirm that the perforations are squeezed off. This paper addresses the planning operatio ased from 350 000 m�/D in 1990 to more than 1 000 000 m�/D in 2002 (Khatib and Verbeek 2002). The costs associated with handlin able forced imbibition the chemical wettability modification of fractured oil-wet carbonate rock does not provide an economically interesting of existing infrastructure for the implementation of new projects to compensate the production of ageing fields or to increase overall producti ematics to mean “not necessarily linear we intend the term “non-smooth to refer to certain situations in which smoothness (differen nary area that had been successfully applied in offshore deepwater gas and oil prospects of Gulf of Mexico Nigeria Norway and other deep 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 y disappears at miscibility i.e. the interfacial tension becomes zero. Hence a pressure condition of zero gas-oil interfacial tension at reservo

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 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 mud filtrate is critical for the collection of representative hydrocarbon-fluid samples in wells drilled with OBM. The hydrocarbon sample may b ds [Qian et al. 2001 Panda et al. 2007]. There is not a single universally applicable analytical technique that is capable of analyzing all co choke valve or orifice) a stable emulsion can be formed. Presence of inorganic solids such as sand clay and corrosion products together ons (high temperature and high pressures) is necessary for selection and applicability of suitable surfactants for economic field application.

d and additional proprietary components that vary with the conditions of the reservoir. The system has shown to enable a high degree of sil

methods are modeled in the FPS. Besides these diversion methods mechanical isolation devices such as straddle packers or bridge plugs

that while we need to prove value to move the technology forward we also need data that demonstrate value. Analog information can be u ned as compounds containing carboxylic groups attached to saturated cyclic structures.7 10-17 There is a tendency for the naphthenic acid

force for scale deposition is caused by temperature and pressure changes or mixing of incompatible waters. The deposition of scale in pro he flow is critical as long as the pressure in the wellbore is uniform and diameters of the perforations along the well are constant the steam

cosity of the oil. The fractures also need to form a dense enough connected network from the gas cap in the top of the reservoir (formed by g. 2b). CSS is employed to extract the oil most recently using closely spaced multi-lateral horizontal wells drilled from a central pad. Modeli e results of the trial were remarkable. Success rate has been greater than or equal to 300% over conventional mud acid performance on sim imulator because each grid-block would have its own�t=0" corresponding to that moment in time where the pressure (or temperature) in ain a better understanding of the CSS extraction process at Peace River Shell Canada designed and implemented a monitoring program o te the temperature differential needed to make thermal effects (i.e. convection) dominant. There is abundant information in open literature and Phase 3 will involve Cluster wide depletion and gas injection in the remaining fields. A substantial effort has been carried out during co ove damaging aluminosilicate minerals and reduce the skin value. The precipitation of silica is thought to be the major reason that sandston rance of evidence or “beyond a reasonable doubt).� One advantage to a field trial is that it can be carefully designed to eliminate or r

ments are the only means of stimulating production to economically accecptable levels from the “tight gas sands present in this area.ï¿ o the history match consistent measurements and production log analyses are an absolute necessity. The combination of accurate producti n this type of tight reservoir (Figure 1). hip between the measured gas permeability and the reciprocal absolute mean core pressure.2 This model has been a consistent basis for t

n 2005 a modified PSC was signed between PetroChina and Shell and a final investment decision was made in April 2005. Changbei tigh ltimate recovery of these tight gas wells to increase their economic attractiveness for development in the Southern North Sea setting. UK T

sion-making. We believe that Smart Fields solutions help us meet that challenge by providing asset teams with the processes tools and te

build-up tests were carried out on GCG0T with a 3rd party barge due to non-readiness of hooked-up flowline to the gas plant. A maximum ra downside values of a parameter. A ‘most likely’ set of parameters may correctly represent some middle or average value and yet be made by various geoscience and engineering disciplines. These models routinely begin with a comprehensive static reservoir description er level (FWL). As shown schematically in Fig. 2 close to the OWC the oil/water pressure differential (i.e. capillary pressure) is small; there ow a continuously increasing absorption at shorter wavelengths. This absorption (or color) is caused by the higher concentration of aromati GOR CO2 content pH density viscosity and PVT behavior are key inputs for surface-facility design and optimization of production strate

which overcome the time-intensive nature of Monte Carlo methods. In the 3D connectivity workflow proxy models estimate the effective pro ation stresses play an important role in geophysical prospecting and development of oil and gas reservoirs. Both the direction and magnitud

l equipment requirements and delays in well on-line dates. In addition conventional well testing may not be successful in low-permeability r ctures and large irregular cavities. Vuggy pore space can be divided into separate-vugs and touching-vugs depending on vug interconnecti ata. At one extreme simple models such as that of Kozeny-Carman attempt to predict the permeability using knowledge only of the porosity s (temperature flowing wellbore pressure) are also often captured while drilling. In general all of these measurements are time-varying. If th e By Seismic Data Mapping diffuse fractures and subtle faults are two of the goals geophysicist persue. Edge dip azimuth coherency cube n selected direction (WNW or NW) until it reaches the exclusion zone. Exlusion zones include circle of investigation of well tests with radial such as geochemical fingerprinting (Edman et al. 2001; Westrich et al. 1999) can be integrated with geologic data to better assess reserv In recent years formation sampling and testing tools have seen the introduction of an array of downhole fluid property measurements. Thes ud compositional assessment (Kandel et al. 1999; Ellis et al. 1999 2003; Berkman et al. 2003; Stankiewicz et al. 2007). Advances have characterised by very low gas content. Production since 1980 has recovered only a few percents of the cluster volume from mainly vertical

divided into three zones; the Basin Centre Hinge Line and Platform/Southwest Flank areas (Figure 2). Distinct plays exists within each are

cation and modifying the geological model for a viable history match. Iterations of geologic modeling reservoir simulation and seismic forw

Bscf of free gas has been produced for various historic reasons resulting in encroachment of the northern aquifer and upward movement of

rently not used in the industry mainly because reservoir models need to be purpose-built and numerical stability is questionable. Our appr ated sand layer buried at a depth of about 600 m characterized by a wide range of reservoir properties such as oil viscosity vertical to horiz

ent of two fields: Piltun-Astokhskoye primarily an oil field with associated gas and Lunskoye predominantly a gas field with associated con and Jansen 2004). However optimal control strategies often lack robustness to geological uncertainties. By discarding these uncertainties study clearly demonstrates that a blend of conventional methodology and state-of-the-art stochastic techniques can efficiently model water

rregional transport capacities. Introduction Over the past decade many papers have been written to investigate whether gas supply is capa with a scoping study agreed between Shell and Qatar Petroleum. The study was completed in June 2002 and a few months later basic fron management purposes the cost of achieving a minimum required injection water quality (i.e. complexity of water treatment system) must be conomic fields. These activities have required high quality water for injection and or steam generation which in turn contributed to increasin uences of the strategy upstream or downstream of the unit must be considered). Certain control objectives will be conflicting or have differen ction water breakthrough. Such intervals were avoided while adding new perforations. Successful implementation of the above techniques

ess-well amalgamated. Net reservoir thickness is generally less than 100 ft.� Measured sand porosities range from 20 to 37% and are ge A total of sixteen wells (nine producers and seven water injectors) were drilled during the Bonga phase 1 drilling campaign. Another twenty-f when applying nitrate in PW. Introduction The Draugen field The Draugen field is situated in block 6407/9 at Haltenbanken and the platform

cial lift to sustain high water cut production. Currently the S sour wells are equipped with ESPs and the H wells are being gaslifted. Develo scales are carbonates caused mainly by CaCO3 precipitation (due to reservoir pressure depletion) and sulphate scales created by the in ecute a more systematic and objective methodology to identify optimal well locations: an approach that uses all the available information e each review there is a formal management decision procedure to advance the investment opportunity to the next stage of maturity. It is not

nches out to the west of the field.� A structural saddle separates the main northern accumulation (Rogn Main) from the southern extensi with further infill drilling activities.� In this paper we present four examples of reservoir surveillance activities in different mature North S

mpartmentalized. The field is delimited by two main boundary faults and sealed by an erosional unconformity (BKU) which has removed the ch can be tubinghead pressure (THP) bottomhole pressure (BHP) or a rate. For smart wells there are generally more control variables corr ever at the time this study was conducted start of injection was expected to be in October 2009. The horizontal water injectors require a hig At the crest of the Lunskoye anticline top reservoir (Daghinsky Formation) is at a depth of ~1650 m tvdss (Figure 2). The field can be divide

ach iteration and requiring many forward reservoir simulations. A rather different approach is proposed by Lui and Jalali (2006) where stan ntier environments presents a major challenge to the industry. In these environments permeability architecture and reservoir connectivity are e reservoir management decisions. The quality of the oil reservoir model is therefore of essential importance for performing robust and ac ibration of the reservoir model to dynamic (production) data using numerical simulators has been one of the longstanding challenges of for ns to the convection and mechanical performance of the fluids are readily available. For non-Newtonian packer fluids one problem is that t of the streamlines indicates that the fracture orientation changes the areal sweep. In order to achieve optimized water-injection manageme purpose-built and numerical stability is questionable. Our approach as briefly described in 4 uses a ‘standard’ reservoir simulator ynamics and visa versa. Simulations are widely used to predict oil and gas production. The current status of these simulations is to either u mportant issue which is causing production limitations is wax deposition. Wax deposition is a known problem for reservoirs located in cold a

highly deviated/horizontal wells has resulted in a dramatic increase in withdrawal rates from the Champion field and a corresponding declin mpositional simulations or simulations using local grid refinement (LGR) near the wells can be used to obtain an accurate estimate of the we

at computational grid points have to be distributed in the physical domain in a way that these are denser where flow and rock properties are e fact that geological models are becoming finer every day. To tackle this problem a common approach is to upscale fine grid into a coarse erformance1-3. In practice however these fine geological models usually cannot be directly input to reservoir simulator due to memory and

odified to approximate the behavior of all other fluids of interest. In this approach the only varying factor from reservoir to reservoir was the o ng questions raised. In this paper we focus on the modeling of shear fractures which are generated by structural deformation accompanied simistic) Medium (most-likely) and High (optimistic) cases. The dynamic model (or flow-simulation model) is based on a static model that w st heating of the matrix blocks cannot be captured. We show that the new transient shape factor however enables coarse-grid dual-permea

00 active leases in 1992 have risen to 7 600 in 1998. Most if not all offshore geological and geophysical surveys exploration drilling and d

be influenced on this other than certain optimisation settings that are options in the software unless the application is proprietary. Running ty of greater computational power. The Ensemble Kalman Filter (EnKF) is one such promising technique for generating a suite of plausible hnique in which conventional theory is used to derive an average pressure directly from standard log-log plots. Homogeneous properties an

es replacements from infill drilling are becoming increasingly difficult to find so a new approach was called for. In 1997 development focus

s been possible to capture vertical and areal heterogeneities measured by well logs and inferred by the depositional environments in a very eighbours whilst it faces the greatest forecast increase in terms of future gas demand. �� The need for gas storage In western coun answers in most cases (6). Assumption of constant gross liquid production is also an inherent limitation of the three classes. and Kabir (1994 1999 2002 2007) and Livescu et al. (2008). These models are useful in many contexts though they typically include man nt practices in general are either based on petrophysical properties (i.e. porosity permeability and drainage Pc curves) or geological descri to consist of one single hydrocarbon column that in places also extended into the massive braided fluvial channels in the Lower Safa C Un Moulds et al. 2005). Dispersion is also an important effect in water injection where mineral scales are formed by mixing of injected and res

rsaturated oil reservoirs. The reservoir under consideration is part of of a cluster of fields located south of Oman Fig.1. The cluster consists

es to accelerate the production and increase recovery. Steam injection in heavy oil reservoirs is common practice and recently receives mor

d including cold and hot water injection wellbore heating steam injection and in-situ combustion. The redevelopment opportunity propose dated response surfaces show confounded higher order nonlinear effects. Therefore further study based on more detailed design is desire s have been operating in Canada mainly in the Athabasca area while CSS is used only by three operators (Imperial Oil Shell and CNRL)

ing the reservoir pressure while the impact of water injection on areal sweep is problematic. After the start of water injection initially indicatio mately 24 000-32 000 bbl of oil were deposited onshore in Texas mainly on the beaches. To generate an estimate for the blowout rate som ip fields where many but probably not all of the Smart Field Technologies have been deployed.�The development and deployment of th uted Control Systems starting to replace/complement SCADA in the mid-eighties -��������� Subsea Control Syst ctivity reservoirs has led to higher productivity than what has been possible with a conventional vertical or moderately deviated wellbore. In t sive to produce’ resources. These disadvantaged resources can be categorized as follows: (1) remote (far away from the market no ex nergized stimulation process among a geographical region would benefit each individual asset in the organizational structure that was introd mmon and are in pressure communication. The working interest in the Ursa and Princess fields are Shell (45--operator) BP (23%) ExxonM

ver may lead to recommendation for full dynamic modeling where the scope is substantial and risks are considered too high without simula

intervention to optimize production and ultimate recovery.

step-rate production testing is the evaluation of the layer contribution to the total production. This data together with estimated individual res

parent compartmentalization and ubiquitous U-shaped boundaries can be one answer on a “reservoir scale. Yet those boundaries are ra pletion and communication information whereas others may seek information on the precise nature of the hydrocarbon fluids and water in t 966 1973; Segall 1985). Compared to the analytical/semianalytical method the FEM is a general method that can handle complex material

ntal flow environments specifically wells with loose sand and/or debris that potentially damage sensitive spinner and probe sensors are not epth of 2 940 feet. Production began July 8 1996 and peaked in June 2000 at 208 000 BOPD and 217 mmcfd. Mars consists of a series o ts whole length; it varies in true vertical depth along the trajectory. A departure of only a few degrees from the horizontal creates sufficient hi

lation campaigns in the region was started in early 2004. It was hoped that under the new business structure some syndication among the e piping open without any other protective filter. In a broader context the well completion options in open hole can be barefoot with a slotte . 2000; Collins 2003). The primary conclusions from several previous studies (Al-Thubaiti et al. 2004; Kan et al. 2004a; Kan et al. 2004b; To œproactive strategy to continuously optimize the oil production of a well using measured data while honoring constraints on water and gas

and acceleration pressure gradient are coupled. This becomes more complex when polymer is added to the liquid phase (Chen 2005; Chen ormations has gained broader acceptance.3 Sand control and stimulation methods for wells in multilayered unconsolidated formation have roduction for a long period of time. However the existence of yield stress effect remained controversial until the first publication9 resulting fr

elative speed of a gas breakthrough - typically expressed in hours. Unfortunately the industry is increasingly faced with these hard to contai phere. Companies have reported hundreds of leaking producing wells some of which are “wells from hell. For instance two companies with the smart well; a more-complicated case from the modelling point of view. Because the smart well had not been tested in the early sta

an attractive solution for global warming the efficiency (or even feasibility) of the process is not yet established [15]. One major problem is ent displacement in large scales because of large amount of calculations [3]. The population balance approach introduced by Patzek [9] a which showed that foam could be trapped in parts of the domain during steady state flow but no trapped foam was discernible was during tr drop over the well. Since the well head pressure is usually kept constant by the surface facilities the increase in pressure drop over the we

her mechanisms which may be difficult to distinguish. The main mechanisms for the production decline are thought to be: ����â int method which was commonly utilized in the late 60’s as a well completion technique used for hydraulic fracturing [1] [2] [3]. At that ance benchmarks and is rethinking the way perforating services are procured.� Introduction When perforating a well - whether initially f

time monitoring of pressure and temperature from any zone and control of production either individually or commingled without well interve e.� Gas from all the fields is produced to the Malaysian Liquified Natural Gas (MLNG) plants at Bintulu East Malaysia.� Production fro injectors are expected to maintain higher pressures and improve sweep efficiency ultimately resulting in significant incremental recovery. s (MLNG) plants at Bintulu East Malaysia. Production from the Shallow Clastics field is intended to counteract decline from other fields and water management before it anticipates sand production requiring engineering of the completion and facilities to safely handle and dispos

scribed starting with the base fluid such as deionized water tap water source seawater (location) or type of organic fluids; d) Identification nally coiled tubing has been used for the placement of acid. Acid treatment volume used is typically 10 gal/ft which is relatively low. The ge extensively. The theories as developed in Refs.1-5 by now are well-accepted “textbook methodologies. This paper deals with the subje

r onshore and platform wells which prescribe bleeding off pressure through the wellhead once a predetermined pressure level (e.g. 20% o onal seals. The main objective of the Onyx SW well test was to investigate the stacked formations Ile Ror/Tofte and Tilje by conducting a m es in order to meet specific objectives and maximize the full potential use of acquired data for field development plans in thinly laminated de

on in the CO2 Capture Project (CCP) and other external programs. CCT also works internally to apply external learnings and technologies w can be subdivided in mesocleats (from 2 to 50 nm) microcleats (from 0.8 to 2 nm) and the micropores (<0.8 nm). The matrix system is rel netrant concentration of the network can be viewed as an effective decrease of the glass transition temperature (Hsieh et al.2). Structural ch bility of the coal as the volume increase is compensated within the fracture porosity.

ection regime as well as decisions on the monitoring of long-term CO2 migration after injection.

nst CO2 capture and geologic storage; and initiatives and strategies to advance CO2 capture and geologic storage by reducing cost an d reference parameters abound and vary over time for a given production installation. The sensors might include downhole pressure and te opment costs. Savings were projected for first-of-a-kind optimization solutions and even greater savings for optimization solutions adapted

y. Notionally during the exploration and appraisal phases of a project key sub-surface and surface uncertainties are translated into data ac a the periodic routing of the well to a shared test separator the “production well testing process. The duration of the test is normally 6 - 2 methods for individual well production flow monitoring and surveillance.�This provides periodic well test information using test separators elson Platform constructed in 1994 and entering Shell’s portfolio in 2002 following the acquisition of Enterprise Oil. Situated 200 km No

sults and learnings. Fix-The-Basics At the end of the dedicated Leadership Intervention Workshop in November 2007 a plan to improve ke ny fit-for-purpose well test with minimal cost and HSE impact. In an ideal world all tests should be optimal but in our usage the phrase has ocarbon gas is a common example of the high level of such risks. Cost and HSE concerns have driven us to seek better ways to obtain sim

ol. Production allocation was to be automated and the data flow linked to well reservoir and production models to ensure optimal well and r

strategies with a restricted number of degrees of freedom which at the same time maintain the advantages of this new technology. In th ey are generated. Shell is currently running 12 asset programmes in all regions of the world. Beyond technology introduction of Smart Fiel oduction behaviour and fine-tuning large dynamic production systems in real time (Ref. 2). Production Universe has proven that it can instan

the primary well control function of the mud column used in conventional drilling is replaced by a combination of flow and pressure control. alanced drilling in oil and gas reser-voirs since the early 1990’s. The introduction of horizontal drilling in the reservoir in the 1980’s r ible partly or completely miscible.� In some situations the elevated temperature reaction zone may contribute to the incremental recove sweep regardless of the principal horizontal stress orientation in the reservoir. For unconsolidated sands there are currently no theoretical roved phase behaviour experimental methods for higher temperatures (up to 150�C).� Optimal salinities and solubility parameters hav ure system at flow barriers. In the fracture system the oil forms a (thin) rim that can be produced. Production rates achieved with this GOGD e example of the successful application of air injection for secondary EOR is the Medicine Pole Hills (MPH) field1 8. This field is indicative o dage replacement in the entire cluster cannot be maintained. However this will not be a problem when we analyze the cluster as some of th growth law involving only two unknown parameters that can be determined from core flow experiments. The SBP foam model was applied 1988 and 1989 a total of eight template wells was pre-drilled and production started with the maximum capacity of 70 000 stb/d in 1990. Th

e and a fracture network with a thin oil rim below the secondary gas cap and above the fracture oil-water contact (FOWC) figure 1. Primary

voirs (1970 through 984). Previously unknown fracture networks in these layers resulted in rapid water breakthrough. This was followed by han 1 000 000 m3/d today (Khatib and Verbeek 2002). The costs associated with handling produced water are typically proportional to the a per addresses the planning operational and the learning from the through-tubing water shutoff campaign successfully carried out on wells w . The costs associated with handling produced water are typically proportional to the amount of water produced. Consequently costs per b provide an economically interesting opportunity. Introduction Rock fractures provide comparatively highly permeable flow paths through oil fields or to increase overall production. New projects that come on stream typically will use part of the existing facilities which may have su tions in which smoothness (differentiability) of the data is not necessarily postulated. In view of the many non-smooth non-convex optimiza xico Nigeria Norway and other deepwater basins globally. There are many similarities between the severe operating environment in the de on components. As such the model prediction is generally not accurate. Quality experimental data are required to “tune 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 gas-oil interfacial tension at reservoir temperature is the true minimum miscibility pressure for any reservoir crude oil-gas system. The vanis

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 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 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 ue that is capable of analyzing all components of a crude oil but methods are available that allow such materials to be analyzed in quite som y and corrosion products together with surface-active materials such as asphaltenes and naphthenic acids also enhance the stability of e ants for economic field application. Also the selection of a particular laboratory measurement technique to suit the complex experimental e

shown to enable a high degree of silica dissolution without substantially dissolving the carbonate materials or having major clay reactions. F

as straddle packers or bridge plugs to completely isolate an interval are applied. Further coiled tubing is frequently used to place the fluid

e value. Analog information can be used to develop the business case but there is a limited data set because of the perceived high cost of U a tendency for the naphthenic acid to partition between the oil and water phases during production. Once in the water phase the weak acid

aters. The deposition of scale in producing facilities can have a significant economic impact on a field’s CAPEX OPEX revenues and c ong the well are constant the steam flow from the wellbore to the reservoir is uniform. Thus no portion of the reservoir can behave as a thie

n the top of the reservoir (formed by the steam injection) to the FWL to enable gravity-driven oil drainage vertically through the matrix (see ls drilled from a central pad. Modeling Objectives Growth plans being considered cover development across the entire field. Optimizing suc ntional mud acid performance on similar wells and average payback time has been less than twenty days with quantifiable reduction in dam ere the pressure (or temperature) in the fractures surrounding that particular grid-block changes. As we have shown earlier [16] an exact a mplemented a monitoring program over the most recently drilled production pads. We will focus on Pad 40 that consists of ten multi-lateral w ndant information in open literature on examples of graded columns and analyses of the forces thought to be responsible for these observe ffort has been carried out during construction of the Phase 1 wells to optimise the perforation strategy and hence to maximise well producti o be the major reason that sandstone-acidizing jobs fail to produce the anticipated decrease in skin especially at temperatures > 150�F e carefully designed to eliminate or reduce the effect of some variables that could influence the results.� This paper will describe the desi

ht gas sands present in this area.�Each well being completed generally requires between 14 and 22 MHF treatments in order to effectiv he combination of accurate production logging analyses and layer property determination provides the reservoir and production engineering

del has been a consistent basis for the development of methods computing the absolute liquid permeability of a core sample based on a sin

s made in April 2005. Changbei tight gas development is the largest onsho e Southern North Sea setting. UK Tight Gas Experience In the 80’s hydraulic fracturing of deviated wells was the method of choice for

ams with the processes tools and technology that enable them to gain total awareness of their asset’s current and predicted behaviour

wline to the gas plant. A maximum rate of 66 MMscf/d was achieved during the tests due to the handling capacity limitation of the test barge middle or average value and yet be unlikely to occur in practice." ehensive static reservoir description that is further enhanced by fine-tuning the property distribution so as to calibrate the model performanc e. capillary pressure) is small; therefore only the large pores can be filled with oil. As the distance above the OWC increases an increasin the higher concentration of aromatic molecules and is typically larger for heavier oils. As a result high-density hydrocarbons which have a and optimization of production strategies. Formation-tester tools have proved to be an effective way to obtain reservoir-fluid samples for PVT

xy models estimate the effective properties namely 3D connectivity factors which are in turn used for calculating the pseudo-relative perme irs. Both the direction and magnitude of these stresses are required in (a) planning for borehole stability during directional drilling (b) hydra

t be successful in low-permeability reservoirs because these wells may not flow at measurable rates before stimulation. These cost and res ugs depending on vug interconnection. Separate vugs are connected only through interparticle pore networks and do not contribute to perm using knowledge only of the porosity and a single “characteristic length such as the mean pore diameter mean grain size or specific su measurements are time-varying. If the inverse problem is formulated properly these known parameters can deliver the pore pressures perm Edge dip azimuth coherency cube and spectral decomposition (3 4) are among the popular methods for mapping subtle faults and velocity nvestigation of well tests with radial flow horizontal wells with no fracture corridor or a circle around typical matrix producers or injectors. Th eologic data to better assess reservoir continuity and/or compartmentalization before field development commences. From these data and e fluid property measurements. These include optical absorption spectroscopy optical reflectance fluorescence and a few other non-optica ewicz et al. 2007). Advances have occurred for all aspects of mud gas logging: More efficient mud gas extractors that are less impacted b e cluster volume from mainly vertical wells producing commingled on all reservoirs as well as water injectors in the brown fields. This marks

Distinct plays exists within each area and a total of fifteen exploration/appraisal wells have been drilled by various operators; mostly in the B

servoir simulation and seismic forward modeling are generally recommended for consistency between the dynamic model and 4D seismic

rn aquifer and upward movement of the oil rim in the North of the field. As a result several of the long horizontal wells have watered out. To

al stability is questionable. Our approach as briefly described in uses a ‘standard’ reservoir simulator thereby enabling reservoir en such as oil viscosity vertical to horizontal permeability ratio and reservoir thickness. These varying reservoir features are expected to resul

nantly a gas field with associated condensate and an oil rim. Both fields were discovered in the 1980’s. Together the fields contain recov s. By discarding these uncertainties the sensitivity to a possibly large system/model mismatch is not taken into account within the optimizat chniques can efficiently model waterflood behaviour. The Screening Phase In the early stage of the study it was essential first to get a high

vestigate whether gas supply is capable of meeting global demand over the next 50 years (Huntington 2006; ICF Consulting 2005; Internatio 02 and a few months later basic front-end design started in parallel with commercial negotiations. A development and production-sharing ag of water treatment system) must be weighed against achievable incremental reservoir yield. Establishing these minimum quality needs req which in turn contributed to increasing volumes of produced water to the surface. Shell as one actor among many in the world of water has es will be conflicting or have different priorities.� It is also important to consider the dynamics of the process the drifts and changes in th mentation of the above techniques in the seven intervened wells resulted in an increase in the oil production by 53% i.e from 1773 bopd (b

es range from 20 to 37% and are generally associated with high (multi-Darcy) permeabilities. Seawater injection for pressure maintenance 1 drilling campaign. Another twenty-four wells will be drilled in Bonga Main with eight additional “in field opportunity wells which started N 7/9 at Haltenbanken and the platform is operated by A/S Norske Shell E&P (Exploration and Production). Haltenbanken is considered to be

e H wells are being gaslifted. Development plans for the S are currently being progressed. Whilst studies are being conducted on possible re d sulphate scales created by the incompatible mixing of reservoir brine and injected water (normally seawater). Scaling is present in all the uses all the available information e.g. geological characteristics production data from existing wells dynamic model predictions etc. The m o the next stage of maturity. It is not intended to describe the process in this paper. Rather highlights milestones and turning points achiev

ogn Main) from the southern extension (Rogn South) see Figure 2.� The main oil-bearing formation is the Upper Jurassic Rogn which is activities in different mature North Sea reservoirs.� Each example was selected for illustrating the application of a particular surveillance t

mity (BKU) which has removed the Rutbah reservoirs over the crestal part of the structure. A schematic cross section is shown in Figure 1. generally more control variables corresponding to the setting of downhole inflow or outflow devices which can be controlled independently. W rizontal water injectors require a high degree of zonal control because of the laminated nature of the reservoir and historical problems with ss (Figure 2). The field can be divided into six major structural blocks and is penetrated by seven wells. All fault blocks except Block VI are p

by Lui and Jalali (2006) where standard reservoir models are transformed to maps of production potential to screen regions that are most f ecture and reservoir connectivity are key uncertainties which lead to differences in dynamic reservoir performance and estimates of ultimate rtance for performing robust and accurate predictions of recovery potential and in turn making decisions on correct premises. It is very de f the longstanding challenges of forecasting. Conventional history matching is a manual exercise whereby a few reservoir parameters are v packer fluids one problem is that the free convective heat transfer of the fluid (the amplification due to convection) has not been available optimized water-injection management dynamic fracture propagation needs to be estimated properly before the injection controlled during €˜standard’ reservoir simulator thereby enabling reservoir engineers to model induced fracturing around injectors using their ‘standa us of these simulations is to either use a dynamic well model combined with some analytical reservoir model2 or to use a dynamic reservoir oblem for reservoirs located in cold areas or deep water but also for reservoirs containing a crude which has a large tendency to wax. �W

on field and a corresponding decline in reservoir pressure due to limited aquifer support.� As a result there is a need to implement an IO btain an accurate estimate of the well deliverability. However these methods have the disadvantage of large run times especially for full-fie

where flow and rock properties are varying more or their magnitude are large. Thus areas such as near wells high flow regions fractures is to upscale fine grid into a coarse grid model which has equivalent performance. Upscaling is further motivated by the fact that the geolo servoir simulator due to memory and/or processing time constraints. Thus there is a requirement to coarsen or scale up the fine geological m

from reservoir to reservoir was the overall fluid composition as per the measured compositions. After the optimization of the tuning parame structural deformation accompanied with fault slip. Recently an application of the elastic stress simulation has been proposed for predicting del) is based on a static model that was generated through a detailed integrated reservoir characterization study (Al-Deeb et al. 2002; Bahar er enables coarse-grid dual-permeability modeling of thermal recovery processes such that they reproduce fine-grid results. Introduction T

l surveys exploration drilling and development drilling in the U.S. occur primarily in the Gulf of Mexico OCS. The region currently accounts

e application is proprietary. Running multiple simulations of a Monte Carlo analysis simultaneously on multiple computers. This technique is e for generating a suite of plausible reservoir models.4-10 The EnKF samples from multi-dimensional probability density functions (pdf) that g plots. Homogeneous properties and radial symmetry are assumed. Muskat’s original derivation was a wellbore storage model. Larson

ed for. In 1997 development focus was on “halting the decline in production by locating and exploiting remaining undeveloped reserves

depositional environments in a very fine scale with 0.1- to 0.3-m vertical and 20- to 100-m areal resolution (Hobbet et al. 2000; Dashti et al. ed for gas storage In western countries generally natural gas has become a key energy commodity for both the domestic and industrial m of the three classes. xts though they typically include many simplifications such as assuming steady state flow or neglecting spatially varying inflow which rende nage Pc curves) or geological description (facies and depositional environment) or a combination of both. The underlying assumption is that vial channels in the Lower Safa C Unit. However with time it became apparent that the field was highly compartmentalized in the vertical and ormed by mixing of injected and reservoir brines (Sorbie and MacKay 2000; Delshad and Pope 2003) in the underground storage of gase

of Oman Fig.1. The cluster consists of a group of fields discovered between 1996 and 2007. These reservoirs are deep and high pressure

n practice and recently receives more attention in naturally fractured reservoirs1-6. Steam injection in light oil reservoirs is not common alth

redevelopment opportunity proposes to use a new process termed Gravity Assisted Steam Flooding (GASF) which combines low-pressure ed on more detailed design is desired. The method in this paper honors available data without over-tuning geological parameters for history tors (Imperial Oil Shell and CNRL) in the two other Alberta oil sands areas. Therefore over the last decade SAGD has become the preferre

art of water injection initially indications of increasing field rates were recognized. But in the first half of 2006 the producer well A1 on the eas n estimate for the blowout rate some form of nodal analysis is generally applied matching the inflow performance of the well to the vertical development and deployment of these technologies has normally been in Partnership between a major operator and one or more key sup ¿½ï¿½ï¿½ï¿½ Subsea Control Systems from the mid-nineties -��������� Downhole instrumentation from the mid or moderately deviated wellbore. In the mid to late 1990s the horizontal openhole gravel-packing technique was refined with the basic down ote (far away from the market no existing infrastructure) (2) harsh conditions (artic) (3) difficult reservoirs (ultra deep tight formations) and ganizational structure that was introduced to the region in late 2003.� Acid stimulation in Shell Asia Pacific region has not been very activ ell (45--operator) BP (23%) ExxonMobil (16%) and ConocoPhillips (16%). The Yellow reservoir is the main reservoir at both Ursa/Princess

e considered too high without simulation. Most previously published bypassed oil identification techniques relied mainly on a combination o

ogether with estimated individual reservoir layer pressures helps to determine oil reserves and assist in waterflood management. The data a

ir scale. Yet those boundaries are rarely confirmed by 4D seismic or other data. Shale draping is an alternative reservoir-scale scenario tha he hydrocarbon fluids and water in terms of chemical and physical properties phase behavior and commingling tendencies. Cased-hole su od that can handle complex material rheology reservoir geometry and inhomogeneity. Drawbacks include the effort required to adequately

spinner and probe sensors are not uncommon. Producing horizontal wells completed in unconsolidated and poorly sorted formation sands mmcfd. Mars consists of a series of Miocene to Pliocene age turbidite sands deposited within a minibasin bounded by the deeply rooted V m the horizontal creates sufficient highs and lows to result in a flow profile which is challenging to understand. These undulations in a horizo

ucture some syndication among the region during the stimulation campaign would overcome some of the difficulties listed above and benef n hole can be barefoot with a slotted liner screens or gravel pack (Fig. 1 & 3). Standalone screens appear to be well suited to prevent san an et al. 2004a; Kan et al. 2004b; Tomson et al. 2006) of NTMP(aminotri(methylene phosphonic acid))-calcite reaction are: (1) The extent o noring constraints on water and gas production. Optimization Methods. Optimization with the objective to improve the economics of oil or g

o the liquid phase (Chen 2005; Chen et al. 2007; Chen et al. 2005). A comprehensive computer program has been developed to better und red unconsolidated formation have started as early as 1960’s.4 These techniques included stand alone wire-wrapped screen 5 6 in-sit until the first publication9 resulting from this JIP work was made at the Formation Damage Symposium in Lafayette February 2006. In a se

ngly faced with these hard to contain consequences because many mature fields experience gas coning. Also oil is increasingly produced m hell. For instance two companies spent more than C$1.4 million in their unsuccessful attempt to seal a leaky well (Zeidani et al. 2006). C l had not been tested in the early stages of production only the recorded pressures from the permanent downhole pressure gauge (DHPG)

ablished [15]. One major problem is the leakage of the injected CO2 through the walls of abandoned wells or through the cap rock [16]. In th approach introduced by Patzek [9] and further elaborated by Kovsec et al. [10-11] and Falls et al. [12] originates from the principle that foam d foam was discernible was during transient flow.13-17 Analytical solutions of the SPB reconciled the bubble population and the fractional fl crease in pressure drop over the well leads to an increase of the pressure at sand face. In turn an increased pressure at sand face gives ris

are thought to be: ����• ����Film drainage ����• ����System instability ���� ydraulic fracturing [1] [2] [3]. At that time “limited-entry was a term for the practice of limiting the number of perforations in a completion perforating a well - whether initially for remedial reasons or to effect a change in functional specification – the associated design and equ

or commingled without well intervention. Permanently installed electric cables provide power and communication with the downhole senso lu East Malaysia.� Production from Shallow Clastics is intended to counteract decline from other fields and is critical to maintaining the s n significant incremental recovery. nteract decline from other fields and is critical to maintaining the security of the supply to MLNG. Significant log data (Fig. 1) on the Shallo acilities to safely handle and dispose of the sand with the ultimate aim of maximising production and project economics (Sanfilippo et al. 1

ype of organic fluids; d) Identification of mixing apparatus container volume and total volume of fluid prepared; e) Time of mixing (should in gal/ft which is relatively low. The gelled hydrochloric acid (HCl) is mixed in batch tanks. Typically the average horizontal length is 2000 ft an es. This paper deals with the subject of pressure fall-off analysis on fractured water injection wells. In this area the situation is entirely diffe

ermined pressure level (e.g. 20% of the minimum internal yield pressure of the affected casing) is reached. Ror/Tofte and Tilje by conducting a multi-zone DST with each interval being tested separately. Testing of two zones with a third as a continge opment plans in thinly laminated deepwater environments.

xternal learnings and technologies within Shell businesses.� Additionally Shell’s research and development funds and manages a se (<0.8 nm). The matrix system is relatively impermeable and the mass transfer is dominated by diffusion. After a dewatering stage CO2 is perature (Hsieh et al.2). Structural changes induced during this process include swelling microcavity formation and primary phase transition

eologic storage by reducing cost and risk and developing sound regulatory and policy frameworks to encourage development of options fo ht include downhole pressure and temperature gauges distributed temperature systems and other equipment instrumentation throughout th s for optimization solutions adapted from previous successes.

ertainties are translated into data acquisition requirements and it is up to the team to select fit-for-purpose logging suites rock and fluid acq e duration of the test is normally 6 - 24 hours or longer; the test frequency can vary but is typically weekly monthly or even less frequent. Th est information using test separators or multiphase meters sometimes supplemented with real time pressure and temperature data gathere f Enterprise Oil. Situated 200 km North East of Aberdeen Nelson wells produce approximately 6 000 m3 Oil and 450 kSm3 gas per day fro

November 2007 a plan to improve key elements of W&RM�foundation was prepared.�This was done by first carrying out a detailed as mal but in our usage the phrase has come to mean any test in which no significant volume of live hydrocarbons is produced to the surface. us to seek better ways to obtain similar reservoir and fluid data. Within our organization a major international operating company we have

models to ensure optimal well and reservoir management policies were adopted. A technology staircase was used for a stepwise approac

ages of this new technology. In this paper multiscale estimation techniques are utilized to attempt to find the optimal well management le chnology introduction of Smart Fields also requires a dramatic shift in work processes and people. Universe has proven that it can instantaneously identify problems in a well increase production and improve well test frequency. It is self-lea

ination of flow and pressure control. Bottom-hole pressure and return well flow are continuously measured and controlled by means of resp g in the reservoir in the 1980’s resulted in many new challenges. It created the need for a different approach to en-able drilling in deple contribute to the incremental recovery.� In its field implementation the process is initiated simply by injecting air which will spontaneous ds there are currently no theoretically sound techniques to predict the fracture geometry and whether or not a fracture would be contained w linities and solubility parameters have been measured. Two surfactant families have been evaluated both produced by Shell Chemicals: In uction rates achieved with this GOGD (Gas Oil Gravity Drainage) process are often low due to low matrix rock permeabilities capillary hold-u PH) field1 8. This field is indicative of those projects which have been undertaken in the Williston Basin in the Dakotas. The Williston Basin we analyze the cluster as some of the reservoirs are at very high pressure and one gas condensate reservoir is available. Some of the high. The SBP foam model was applied successfully to simulate different core-flow experiments [18 19]. The simulation results showed a rathe capacity of 70 000 stb/d in 1990. The field has been developed with a water injection scheme. Water injection at Gyda commenced in Febru contact (FOWC) figure 1. Primary production performance such as that of Qarn Alam is only expected to recover some 3-5% of the oil in

breakthrough. This was followed by GOGD development (1983 through 1998) which was successful in arresting the decline in the oil produ ater are typically proportional to the amount of water produced.�Consequently costs per barrel of oil produced continue to increase with i n successfully carried out on wells with single-string multizone completions. Introduction Cement-water shutoff intervention behind the slee produced. Consequently costs per barrel of oil produced continue to increase with increasing water production. Ultimately individual wells o hly permeable flow paths through oil reservoirs. In a densely fractured reservoir the permeability contrast between the fracture network and xisting facilities which may have sufficient capacity to handle increase of production from one individual project but will not be adequate fo ny non-smooth non-convex optimization opportunities in the oil and gas industry we have developed and matured several variants of the d vere operating environment in the deepwater and the harsh winter conditions that exist in onshore and shallow water regions in Russia. The equired to “tune 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 voir crude oil-gas system. The vanishing interfacial tension technique (VIT) to determine miscibility is based on this fundamental principle. R

The accurate measurement of H2S concentration in the reservoir fluid can often be critical to completion surface production and process d ble point of oil in a trap reflect the pressure and temperature history of the trap (Stainforth 2004). Compositional grading can be caused by 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 materials to be analyzed in quite some depth although depending on the method used they rarely reveal the whole picture. This motivates t acids also enhance the stability of emulsions (Kokal 2005). Because of the presence of these elements the occurrence of tight emulsions in e to suit the complex experimental environment is essential for reliable results at high pressures and temperatures. Therefore a brief review

als or having major clay reactions. Field and laboratory studies further show that improved performance of the system is widely enhanced by

is frequently used to place the fluid at a desired location in the wellbore. During the design phase of a matrix treatment it is essential to un

cause of the perceived high cost of UBD and questionable effectiveness of the technology in the candidate reservoir. Implementation costs ce in the water phase the weak acids will dissociate in accordance with normal equilibrium. However with the exception of low molecular w

™s CAPEX OPEX revenues and can also compromise the safe operation of valves. Furthermore radiological hazards can arise due to the of the reservoir can behave as a thief zone.� Limited entry perforations (LEPs) are a completion technology that is used to improve stea

ge vertically through the matrix (see Penney et al. 2007 for details). The drained oil then forms a rim in the fractures near the FWL from whi cross the entire field. Optimizing such a development plan requires investigating a host of sensitivities including well configuration placeme ys with quantifiable reduction in damage skin or increased productivity index. This paper reviews the acidising history of Hydrogen delayed have shown earlier [16] an exact analytical transient shape-factor can be derived from “first-principles for the temperature diffusion in 1 40 that consists of ten multi-lateral wells arranged in a “tuning fork configuration as shown in Figure 2. The 500-meter long horizontal se 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 and hence to maximise well productivity. Selection of the correct charge and gun system as well as the optimal deployment technique was t pecially at temperatures > 150�F or in the presence of acid-sensitive clay. Acid treatment of sandstone at high temperatures therefore re ¿½ This paper will describe the design and analyses of a field trial in the Pinedale Anticline and summarize the supporting evidence the jury

2 MHF treatments in order to effectively produce from all potential pay intervals.�Over two million pounds of proppant are often used per eservoir and production engineering teams with much more precise data than surface production data alone maximizing the effective man

ility of a core sample based on a single data point — i.e. single-point steady-state permeability measurement methods. Subsequent work

wells was the method of choice for developing tight gas reservoirs in the Southern North Sea (Ref. 1). Although sound in principle in practi

™s current and predicted behaviour and give them the ability to perform real-time analysis and decision-making. We have found that buildi

capacity limitation of the test barge. Thereafter the well was commissioned to flow through the gas plant after flowline hook-up. The well c

as to calibrate the model performance to the reported historical pressure production and saturation data. Such models are generally const ve the OWC increases an increasing proportion of smaller pores are entered by oil owing to the increasing capillary pressure with height ab density hydrocarbons which have a larger concentration of aromatic molecules have a tan brown or black color while low-density hydroca btain reservoir-fluid samples for PVT analysis. Conventional reservoir-fluid analysis is conducted in a PVT laboratory and it usually takes a

alculating the pseudo-relative permeability functions together with the rock curves. Proxy models are closed-form equations derived by train y during directional drilling (b) hydraulic fracturing for enhanced production and (c) selective perforation for prevention of sanding during pr

ore stimulation. These cost and reservoir limitations have forced the engineer to seek other low-cost methods for determining reservoir prop works and do not contribute to permeability. Touching vugs are independent of rock-fabric and form an interconnected pore system. Cavern eter mean grain size or specific surface (Berryman and Blair 1986; Blair et al. 1996). Although easy to implement the Kozeny-Carman e can deliver the pore pressures permeability and other production related characteristics of the reservoir. This can have significant benefits or mapping subtle faults and velocity or amplitude anisotropy (5 6) for mapping diffuse fractures. A key problem in using seismic faults in fra cal matrix producers or injectors. The radius of the circle is determined from the average zone of influence of fracture fairways which is abo commences. From these data and geologic models reservoir simulations can be performed to best understand oil recovery and subseque escence and a few other non-optical measurements. The spectroscopic DFA technique utilizes optical absorption properties of reservoir flui s extractors that are less impacted by variations in drilling and mud properties. Improvements in gas transfer lines to reduce liquid dropout tors in the brown fields. This marks the cluster with high development potential for large-scale waterflood. Initial screening study establishe

by various operators; mostly in the Basin Centre where the core of the PM301 development sits one in the Hinge Line and two on the Platf

the dynamic model and 4D seismic in accordance with current “best-practice methodology (Lumley and Behrens 1998; Pagano et al. 20

orizontal wells have watered out. To aid the gas cap blowdown planned for 2008 and maximise recovery of remaining oil and gas a major

ulator thereby enabling reservoir engineers to model induced fracturing around injectors using their ‘standard’ reservoir models (sec ervoir features are expected to result in different optimum CSS well configurations and steaming strategies for each geologically unique port

™s. Together the fields contain recoverable hydrocarbon volumes of over 1 billion barrels (150 million tonnes) of crude oil and more than 18 ken into account within the optimization procedure. As a result the optimal control strategy may cease to be optimal or may even result in ve dy it was essential first to get a high level overview of the fields and their underlying uncertainties in order to focus more in-depth work at th

006; ICF Consulting 2005; International Energy Agency 2006). Increasing attention is now also given to the distribution of gas around the w elopment and production-sharing agreement was signed in July 2004. Following completion of FEED and submission of the final developme ng these minimum quality needs requires knowledge of leak-off dynamics in an actual injection system. Current thinking is that chemistry an ong many in the world of water has an important role to play in meeting the emerging water challenges by reducing its consumption of the process the drifts and changes in the underlying equipment and processes the measurement noise and the possible disturbances that can ction by 53% i.e from 1773 bopd (barrel of oil per day) to 2708 bopd. The average water cut of the platform decreased from 80% to 76%.

injection for pressure maintenance and sweep is key to the success of the Bonga development. A total of 16 wells (nine oil producers and s eld opportunity wells which started November 2006.All fluids produced are processed on an FPSO situated centrally in the field and oil is di ). Haltenbanken is considered to be an environmental sensitive area on the Norwegian Continental Shelf (NCS). The water depth varies bet

s are being conducted on possible recovery mechanisms recent reports of sharply increasing H2S levels have caused concerns on HSE an awater). Scaling is present in all the producing areas of the world; however the severity of the scaling tendency varies from field to field as ynamic model predictions etc. The methodology is desired to provide a number of alternative well locations in a short period of time and as milestones and turning points achieved or encountered by the development team will be described. The First Workshop The integrated de

is the Upper Jurassic Rogn which is a generally high quality reservoir consisting of an upwards coarsening sand sequence.� The Garn is plication of a particular surveillance technology to meet a specific objective.� Applying the appropriate measurement tools and techniques

c cross section is shown in Figure 1. The Lower Rutbah consists of well-developed shallow marine and tidal channel sands with a high net-t h can be controlled independently. Well control is not completely free as it should take into account certain operational limits such as rate a eservoir and historical problems with controlling water and gas breakthrough in high permeability streaks. The selected concept for the wate All fault blocks except Block VI are penetrated by at least one well (Figure 1).

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 erformance and estimates of ultimate recovery. This is particularly important in deep-water reservoirs where the understanding of complex c ns on correct premises. It is very desirable to constrain the dynamic model to all available data and reduce uncertainties. The most direct in by a few reservoir parameters are varied until a satisfactory match is achieved. Under time constraints the manual trial-and-error approach convection) has not been available in terms of a correlation model that depends on laboratory-measurable fluid properties. This is because efore the injection controlled during operations and monitored to ensure predictions and reality do not deviate significantly. The tools comm ound injectors using their ‘standard’ reservoir models (sector full-field). Moreover our specific methodology of coupling induced frac odel2 or to use a dynamic reservoir model combined with either lift tables or a steady state well model.3 4 The disadvantage of these mod h has a large tendency to wax. �Wax precipitates from the crude when the temperature of the crude drops below the critical wax solubility

t there is a need to implement an IOR scheme. This study is part of the Champion Waterflooding Study project and is focused upon estima arge run times especially for full-field problems with many producing zones and other complexities. There are numerical errors associated

r wells high flow regions fractures faults etc are potential regions to be gridded finer. Several methods for the grid point insertion have bee motivated by the fact that the geological description of reservoir is uncertain and reservoir engineers have to estimate risk and uncertainty i sen or scale up the fine geological models to coarse simulation models whilst continuing to model the effects of important fine scale flow fe

he optimization of the tuning parameters for those multiple but fundamentally distinct fluids a slight modification to the overall composition on has been proposed for predicting the pattern of shear/tensile fractures or the pattern of secondary faults and shown promising results (B on study (Al-Deeb et al. 2002; Bahar et al. 2001 2003a 2003b; Charfeddine et al. 2002; Ates et al. 2003). The study included the integratio duce fine-grid results. Introduction The modeling of matrix-fracture interaction using shape factors has been an active area of research for

OCS. The region currently accounts for a considerable proportion of the U.S. total domestic oil and natural gas production as well as most n

multiple computers. This technique is already widely used.�� Simplify the model itself to various degrees with the ultimate simplificatio obability density functions (pdf) that are consistent with our prior knowledge of the model parameters. These samples or realizations help s as a wellbore storage model. Larson reinterpreted Muskat’s method and derived relationships showing how Muskat’s plot could be

ng remaining undeveloped reserves using primary depletion rather than economically marginal secondary recovery methods [1]. Since the

on (Hobbet et al. 2000; Dashti et al. 2002; Aly et al. 1999; Haldorsen and Damsleth 1990; Haldorsen and Damsleth 1993). It also has been r both the domestic and industrial market. It is used to supply power and heat to the growing economies of Europe and accounts for a subst

spatially varying inflow which render them unsuitable for use in general simulators. Numerical models are much more general as they pote h. The underlying assumption is that static rock characterisation and the resultant rock-typing scheme remain valid when assigning saturatio ompartmentalized in the vertical and horizontal domain. Since then multiple data sources have been leveraged in order to obtain better com in the underground storage of gases where mixing of the injected and in-situ gas changes the quality of the stored gas (Verlaan 1998) and

ervoirs are deep and high pressure reservoirs with some over-pressured (lithostatically pressured). These reservoirs are carbonate stringer

ht oil reservoirs is not common although there are some examples of steam flooding non-fractured or sparsely fractured reservoirs7. Therm

GASF) which combines low-pressure steam injection with horizontal wells. This 15 million m3 (ca. 95 million bbl) expectation oil developme ng geological parameters for history matching. It also provides guidance for data acquisition to mitigate production prediction risks. 1. Introd ade SAGD has become the preferred in-situ technology for developing oil sand leases mainly in the Athabasca area. Presently the bigges

006 the producer well A1 on the east flank of the salt diapir watered out very quickly and unexpectedly. One possible explanation is an indu erformance of the well to the vertical lift performance (Oudeman 1998). For onshore and platform well surface blowouts the blowout rate is or operator and one or more key suppliers. Each of the major operators have their own terminology for “Smart Fields as listed below.ï¿ wnhole instrumentation from the mid-nineties -��������� Growing emphasis on management of change issues pr que was refined with the basic downhole-tool systems being used today (Foster et al. 1999; Duhon et al. 1988; Chambers et al. 2000).� oirs (ultra deep tight formations) and (4) unfavorable composition (heavy oil). Contaminated gas fields are typically part of that last category acific region has not been very active compared to other regions. The cause of the relatively low stimulation activity varies. Major factors tha main reservoir at both Ursa/Princess and Mars the other major field in the Mars basin. It is a world-class Upper Miocene turbidite reservoir

es relied mainly on a combination of reservoir characterization and observation of oil in open hole or through casing logs.� This paper de

waterflood management. The data acquisition for these wells is being conducted in realtime to optimize the stabilization times for each test

ernative reservoir-scale scenario that can lead to well underperformance. Another wellbore-scale explanation suggests that well productivity mmingling tendencies. Cased-hole surveys might look for bypassed hydrocarbon zones or have objectives that could not be achieved during de the effort required to adequately characterize complex constitutive models and develop stable mesh attributes. The uncertainties involve

d and poorly sorted formation sands can be particularly perilous to production measurements. Although some of the more sophisticated pro sin bounded by the deeply rooted Venus salt body to the southeast and the more tabular Antares salt body to the north and west. The north stand. These undulations in a horizontal well’s trajectory also result in the accumulation of fluids across local water sumps and in gas tr

e difficulties listed above and benefit each operation unit (OU) and asset. In Asia Pacific region various reservoir types exist. In this paper pear to be well suited to prevent sand ingress in high permeability clean formations.� For more poorly sorted sands openhole horizontal calcite reaction are: (1) The extent of NTMP retention by carbonate-rich formation rock is limited by the amount of calcite that can dissolve p to improve the economics of oil or gas production can in general be considered on two different time scales: (1) reservoir management wh

m has been developed to better understand the difference between compressible foam flow and incompressible fluid flow to predict the BH lone wire-wrapped screen 5 6 in-situ sand consolidation with chemicals 7 gravel packing 8 9 oriented perforating 10 and limited applicatio in Lafayette February 2006. In a series of lab experiments yield stress measurements ranged from 0 – 17 Pa. This paper builds on the r

g. Also oil is increasingly produced from reservoirs like thin oil rims that tend to cone easily. a leaky well (Zeidani et al. 2006). Common practice is to use cement to block the formation from which gas leaks to the surface. This proce t downhole pressure gauge (DHPG) were used to validate the model. Calculated flowing bottomhole pressures (FBHPs) agreed with the me

lls or through the cap rock [16]. In this case the foaming of CO2 may temporarily hamper the leakage while other actions are considered. riginates from the principle that foam mobility depends on the bubble density (number of bubble per unit gas volume). The population balan ubble population and the fractional flow concepts. Previous numerical simulation studies showed that the SBP foam model is physically and ased pressure at sand face gives rise to a reduction of the inflow of gas and liquids reducing the gas velocity even further so that more liqu

½System instability ����• ����Flow regime change (Toma 2007). In film drainage the force balance on the liquid f mber of perforations in a completion interval to promote the simultaneous entry of hydraulic fracturing fluid into multiple reservoir zones with n – the associated design and equipment selection decisions are generally made somewhat arbitrarily and are often based on misleading

munication with the downhole sensors and valves. Each well contained two to three interval control valves (ICVs) and four downhole pressu ds and is critical to maintaining the security of the supply to MLNG. Significant log data (Fig. 1) for the Shallow Clastics reservoir were gath

ficant log data (Fig. 1) on the Shallow Clastics field were gathered from the appraisal and development wells of the deeper carbonate gas re roject economics (Sanfilippo et al. 1997; Selfridge et al. 2003). The key obstacle to the widespread adoption of sand management other t

epared; e) Time of mixing (should include mixing time(s) at one or more mixer speed(s)); f) Identification of each component and amount ad erage horizontal length is 2000 ft and the mixing of 20000 gal can take up to 24 hours due to the confined space on the drilling barges and his area the situation is entirely different from the one above in the sense that until recently 6-7 there existed no practical methodology ded

two zones with a third as a contingency was planned to cover the formations of interest. Results from the well logging narrowed this to exe

evelopment funds and manages a separate CO2 storage program. Our goals are to: reduce the cost of capture by 60 to 80% and demon n. After a dewatering stage CO2 is injected and flows through the larger cleats of the coal. Subsequently CO2 is transported through the s mation and primary phase transition requiring rearrangements of each chain segments. Such changes are dominated by relaxational pheno

ncourage development of options for deep reductions in CO2 emissions. This paper summarizes the IPIECA Climate Change Working G pment instrumentation throughout the production facilities. Flowmeters may use different reference temperatures and a single optimization

se logging suites rock and fluid acquisition and analysis programs to address these uncertainties. Accurate fluid models and integration o y monthly or even less frequent. The usual result of a well test is a set of spot readings and totalized or averaged numbers such as oil prod ssure and temperature data gathered from the well between tests.� Since the test separators / multiphase meters are normally shared am 3 Oil and 450 kSm3 gas per day from 33 platform wells and two sub sea tiebacks approximately 60% of gas production is used to power th

ne by first carrying out a detailed assessment to identify gaps and a subsequent Gap Closure plan was executed. One of the key elements carbons is produced to the surface. We have identified three types of tests that would qualify as an OVT – wireline formation tests closed tional operating company we have coined the term Optimal Value Testing (OVT) and defined it as any fit-for-purpose well test with minimal

e was used for a stepwise approach to the introduction of smartness in the operator. This vision was widely advertised supported by oper

find the optimal well management level. These are hierarchical regularization methods where the number of degrees of freedom in the est

ove well test frequency. It is self-learning system updating the calibration models using well test and real-time data as they are generated.

red and controlled by means of respectively pressure while drilling (PWD) measurements and a closed circulating system. Figure 1 illustrat approach to en-able drilling in depleted and fractured reservoirs. Shell initi-ated underbalanced drilling operations with foam1 in 1992 and in injecting air which will spontaneously ignite the oil due to high temperature and pressure conditions in the reservoir.� Air compression fo r not a fracture would be contained within the reservoir. Since the stress contrast between the sands and shales in unconsolidated formation oth produced by Shell Chemicals: Internal olefin sulfonates (IOS) which are part of the ENORDET™ O series and proprietary branched C x rock permeabilities capillary hold-up and re-imbibition effects. Capillary hold-up also negatively impacts ultimate recovery. in the Dakotas. The Williston Basin has been the focus of air injection for secondary recovery for over three decades. The reservoirs in the ervoir is available. Some of the high-pressure reservoirs that are on primary depletion will provide injection gas for those reservoirs that are e simulation results showed a rather good match with fluid partitioning images obtained by X-ray computed tomography (CT) [18 19]. Both ection at Gyda commenced in February 1991 and as of June 2008 there are 15 active production wells and 7 active water injectors. Oil pro

d to recover some 3-5% of the oil in place over any reasonable time frame due to low matrix permeability and high oil viscosity on gravity dra

arresting the decline in the oil production. Following a simulation study in 1996 it was decided to implement a line-drive waterflood with hor produced continue to increase with increasing water production.�Ultimately individual wells or complete fields are abandoned when cash shutoff intervention behind the sleeve in multizone completions is a solution that is not common due to its low probability of success. Shell duction. Ultimately individual wells or complete fields are abandoned when cash flows turn negative because of excessive water production st between the fracture network and the oil-bearing matrix can be significant. In that case the viscous pressure differential across individual l project but will not be adequate for other projects. The drive toward no venting and/or reduced flaring policy which is becoming increasin nd matured several variants of the derivative-free global optimization algorithms10 11 based on the discrete gradient method. The DGM me hallow water regions in Russia. The remote location of fields requiring long-distance hydrocarbon transportation systems are similar to thos 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 sed on this fundamental principle. Rao (1997) first developed and used VIT technique to determine miscibility for a live reservoir crude oil-g

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 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 al the whole picture. This motivates the development of a suite or combination of techniques tailor-made for the oilfield environment. A furthe the occurrence of tight emulsions in the production facilities is quite common. In some cases emulsions may also form in the near-wellbor mperatures. Therefore a brief review of literature on various available measurement techniques for the interfacial properties of IFT and cont

of the system is widely enhanced by cleaner sandstone formations (high – quartz content sandstone) and not so pronounced or consiste

matrix treatment it is essential to understand if diversion is required and which diversion method is effective. Currently selection and design

ate reservoir. Implementation costs are driven by use of the equipment and low usage is driven by a lack of candidate wells. Even after a s with the exception of low molecular weight acids naphthenic acids are relatively insoluble in water.10 The partition coefficient from the oil ph

ological hazards can arise due to the deposition of radioactive elements.1 The objective of scale management is to maximise value with re hnology that is used to improve steam injection uniformity along the length of the well [4]. �This technique originates from the “pin-poi

he fractures near the FWL from which it can be produced (see e.g. Wassing et al. 2008 for details). Obtaining static and dynamic data of t ncluding well configuration placement spacing steam quality steam slug sizes production cycle length etc. Thermal reservoir simulation is idising history of Hydrogen delayed retarded HF acid system (SRH-RHF) details the approach to candidate selection case specific recipe d ples for the temperature diffusion in 1D matrix-blocks (bounded by two parallel fractures) which is valid for all time-scales. In that approach 2. The 500-meter long horizontal sections are completed with slotted liners and cover an area of approximately 1 by 1 km. First injection sta o compare sector/field data with equilibrium or steady state gradient models of varying complexities. optimal deployment technique was therefore of paramount importance. e at high temperatures therefore requires a retarded acid. Additionally conventional acid treatment of sandstone formations (such as a mu rize the supporting evidence the jury may use to select proppant in this field. Background Information During the past five years the indust

unds of proppant are often used per well representing a potential high investment cost to the operator.�The ability to evaluate the increm alone maximizing the effective management of resources. With the cost of proppant representing as much as 30% of total completion cost

rement methods. Subsequent work focused on correlating the parameters of the Klinkenberg model (i.e the Klinkenberg-corrected permea

Although sound in principle in practice problems were experienced caused either by poor cleanup due to fluid incompatibility proppant back

n-making. We have found that building in the elements of smartness early in the project lifecycle fosters the creation of total asset awarenes

nt after flowline hook-up. The well could not produce up to the expected potential as FTHP was 100bar. CITHP built up to 219bar shortly af

a. Such models are generally constructed to evaluate development plans by forecasting production (both rate & composition) pressure a ing capillary pressure with height above the FWL. The height of the transition zone and its saturation distribution is determined by the range lack color while low-density hydrocarbons have little or no color. Third the absorption spectrum of water is different from that of crude oils; VT laboratory and it usually takes a long time (months) before the results become available. Also miscible contamination of a fluid sample

osed-form equations derived by training backprogation neural networks (Haykin 1999) using connectivity factors obtained through flow-simu for prevention of sanding during production. Wellbores drilled through base salt in the GOM are subject to increased risks of hole closure t

ethods for determining reservoir properties. One such option for acquiring these data is the use of a mini-frac injection test conducted before nterconnected pore system. Cavernous breccia fracture and solution-enlarged fracture pore types are examples of touching-vug systems o implement the Kozeny-Carman equation is usually found to be insufficiently accurate for reservoir characterization purposes. The Katz-T r. This can have significant benefits in reservoir characterization production optimization and in justification of UBD. In particular the ability problem in using seismic faults in fracture modeling is that some or most fracture corridors or fracture fairways (clusters of fracture corridors nce of fracture fairways which is about 50 m. The total length of fracture corridors is estimated from image log scan line density. The total n derstand oil recovery and subsequent reservoir management can be put into place to best capture reservoir complexities and nuances ass 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 ansfer lines to reduce liquid dropout. Up to date analytical devices from high resolution gas chromatographs (GCs) to mass spectrometers d. Initial screening study established the development maturity of the fields per reservoir units in terms of primary secondary and potential

the Hinge Line and two on the Platform area testing all three play areas. CSMP has drilled to date eight wells in PM301 discovering and a

and Behrens 1998; Pagano et al. 2000).

y of remaining oil and gas a major (integrated) re-think was necessary to predict field behaviour during late production life in much more de

standard’ reservoir models (sector full-field). Moreover our specific methodology of coupling induced fractures to the reservoir via spec es for each geologically unique portion of the field. The purpose of this study was to determine these optimums.

nnes) of crude oil and more than 18 trillion cubic feet (500 billion cubic meters) of natural gas. The oil reserves equate to more than one yea o be optimal or may even result in very poor performance. Dealing with uncertainty is a topic encountered in many fields related to modeling er to focus more in-depth work at the subsequent stages of the project. Some of the fields had been studied in the years before but these s

o the distribution of gas around the world. The key question is whether we will be able to transport the ever-increasing volumes of gas from l nd submission of the final development plan in May 2006 project authorisation was granted in July 2006. To counter constraints in the engin Current thinking is that chemistry and wettability related effects invalidate the traditional view on mechanistic particulate plugging of permea by reducing its consumption of the scarce fresh water and by capitalizing on the opportunity of using the large volumes of produced water d the possible disturbances that can occur. tform decreased from 80% to 76%. Candidate Selection The objective of the operation was to increase oil production while keeping the wa

of 16 wells (nine oil producers and seven water injectors) were drilled during the Bonga Phase 1 drilling campaign. All fluids produced were ated centrally in the field and oil is directly loaded to tankers. The associated gas is exported through pipelines. Produced water is processe f (NCS). The water depth varies between 240 and 290 meters. Oil and gas is produced from a sandstone reservoir consisting of the Garn a

s have caused concerns on HSE and facility integrity in future operational modes. In order to place this into project perspective a study wa endency varies from field to field as does the degree of difficulty managing the problem from relatively simple low temperature low pressure ons in a short period of time and as a result of a mathematical procedure that (a) performs an efficient intelligent search (b) minimizes pers e First Workshop The integrated development team of seven subsurface and surface staff was formed at the beginning of 2001. An initial o

ng sand sequence.� The Garn is oil-bearing to the west of the platform (Garn West) but is water-bearing over the rest of the field forming e measurement tools and techniques is essential to the success of the well intervention.� Further in some cases the results can be surpr

idal channel sands with a high net-to-gross ratio (~73 %). The full Lower Rutbah thickness typically varies between 120 to 130 m in areas w ain operational limits such as rate and pressure constraints. These operational limits correspond to inequality constraints either directly on . The selected concept for the water injection wells is a horizontal well injecting under fracturing conditions completed with multiple zones.

ased method that is distinct from those previously mentioned. The adjoint method used in optimal-control theory has been used previously f ere the understanding of complex channelised geological systems is restricted by the limited resolution of seismic data and by fewer well p uce uncertainties. The most direct information about the physics of fluid flow in the dynamic model is embedded in the production data. The the manual trial-and-error approach often leads to a single so called best" history-matched model. Often by reason of the ad hoc nature o able fluid properties. This is because of the non-Newtonian nature of the fluids. Consequently the heat transfer has been estimated only from deviate significantly. The tools commonly used to study fracture growth numerically are analytical fracture simulators which often are based ethodology of coupling induced fractures to the reservoir via special connections 4 helped to eliminate most of the numerical instabilities tha 3 4 The disadvantage of these models is the fact that they underestimate the pre-mentioned well-reservoir interactions and therefore give n rops below the critical wax solubility temperature. The crude produced from the field under investigation has a maximum pour point temper

y project and is focused upon estimating a range of relative permeability end-points as a starting point for sensitivity studies. This paper pre ere are numerical errors associated with LGR and these are difficult to assess in general. No comparisons to LGR were made in this work.

for the grid point insertion have been used in reservoir simulation. Local grid refinement (LGR) has been developed with this idea. Cartesia ave to estimate risk and uncertainty in reservoir performance. This requires reservoir simulation for about hundred different realization of res ffects of important fine scale flow features. Upscaling is a mathematical process which aims to replace a detailed description of reservoir r

dification to the overall composition of the base PVT deck was still required. Using this single fluid description (EOS) corporate level predict ults and shown promising results (Bourne and Willemse 2001; Maerten et al. 2002; Bourne et al. 2001). The elastic simulation numerically s 3). The study included the integration of various data/information from the geology geophysics and engineering disciplines using a stochas been an active area of research for over 40 years now and has attracted considerable attention both in the context of single- and multi-pha

ral gas production as well as most new additions to petroleum reserves in the U.S. Having said this when rig rates approach or occasiona

egrees with the ultimate simplification Design of Experiments (DoE) Of course a combination of any of the above is also possible. This pap hese samples or realizations help specify covariances between model parameters and cross-covariances that relate measurements and m ing how Muskat’s plot could be used to estimate average reservoir pressure in a cylindrical homogeneous reservoir. This paper revisits

ary recovery methods [1]. Since then oil prices have risen from US$23 to US$50+ per barrel (average annual US crude oil prices inflation

d Damsleth 1993). It also has been possible to generate a large number of realizations to assess the uncertainty in reservoir descriptions a of Europe and accounts for a substantial portion of the European energy requirement. There is currently no short term practical alternative

are much more general as they potentially allow for transient effects spatial variability slip between phases general property variation etc. main valid when assigning saturation functions (Pc & Kr) in dynamic reservoir modelling. In this paper we will incorporate conventional core veraged in order to obtain better compartment definitions: logs RFT’s PVT samples geochemical fingerprinting of oil samples repeat f the stored gas (Verlaan 1998) and in proposed methods of enhanced natural gas recovery by injecting anthropogenic CO2 (Oldenburg et

se reservoirs are carbonate stringers encased in salt with different cycles of deposition Fig. 2. The reservoir rock is Ara 2 Carbonate (A2C)

parsely fractured reservoirs7. Thermally assisted gas-oil gravity drainage (TA-GOGD) in light oil has not been done before. Burger8 already

lion bbl) expectation oil development is envisioned to require the drilling of some 57 horizontal wells both producers and injectors. As a r production prediction risks. 1. Introduction The goals of this work are 1) reducing modeling parameters uncertainty by integrating dynamic d habasca area. Presently the biggest in-situ operation in Canada Imperial Oil at Cold Lake uses CSS with a production of ~140 kbpd. Sim

One possible explanation is an induced fracture that created a shortcut from the injector to the producer. Note that the shortest lateral dista urface blowouts the blowout rate is often controlled by the sonic outflow conditions since the pressure in the well will exceed atmospheric p “Smart Fields as listed below.�Throughout this paper the term Smart Field has been used based on its use at the SPE Forum and n management of change issues progressively over the last 30 years�� A brief overview of DOF experiences over the last four decad . 1988; Chambers et al. 2000).� The ongoing improvements in drilling equipment drilling and drill-in fluids filter cake downhole tools an are typically part of that last category. As reported elsewhere in literature there is at least 350 tcf of natural gas in place with 10 % H2S or m tion activity varies. Major factors that limit the stimulation activity include: Various success rates. Operational difficulties. Cost structure: C s Upper Miocene turbidite reservoir that stretches across the Mars basin including the Mars field. This 12 000-acre reservoir is charged with

ough casing logs.� This paper described a systematic approach which integrates analysis and inferences from a few techniques to loca

the stabilization times for each test period. Thus the required data is being acquired without recording unnecessary information or convers

ation suggests that well productivity declines with time due to loss of so called “kh where k and h are reservoir permeability and thicknes es that could not be achieved during the openhole phase. Regardless of the type of survey performed understanding the exploration and ap attributes. The uncertainties involved in the rock- and fluid-property measurements might limit the quality of the results from the FEM model

some of the more sophisticated production detecting tools such as the APLT provide optimum answers of flow distribution it is necessary t ody to the north and west. The northeastsouthwest trending basin becomes narrow and more confined within the deeper Miocene interval. T oss local water sumps and in gas traps at local highs along the wellbore which influence the fluid movement into and along the wellbore. Th

s reservoir types exist. In this paper we will discuss an acid stimulation campaign in high permeability oil bearing sand stone reservoirs in B y sorted sands openhole horizontal gravel packs can be used to surround the screen and stabilize the wellbore in a horizontal well.� Adv amount of calcite that can dissolve prior to inhibitor-induced surface poisoning; (2) calcite-surface poisoning effect is observed after approxi cales: (1) reservoir management which involves the long-term saturation response of the reservoir (e.g. optimization of sweep efficiency in

ressible fluid flow to predict the BHP to study the effect of polymer on foam flow hydraulics and to optimize controllable variables during fo perforating 10 and limited application of frac packing techniques.11 The application of sand control methods in Brunei have shown remark €“ 17 Pa. This paper builds on the results published earlier9 and demonstrates successful strategies that mitigate the yield stress effects to

gas leaks to the surface. This process is expensive damages the formation and in many cases as in abandoned wells this practice has f essures (FBHPs) agreed with the measurements. Simulations have shown that the smart completion gives an opportunity to produce the we

hile other actions are considered. gas volume). The population balance model splits gas saturation into flowing and trapped fractions. The introduction of parameters that ma e SBP foam model is physically and mathematically robust. But a detailed comparison of the SBP with experiments is still lacking. In this pa elocity even further so that more liquid is accumulated. The well is said to load up with liquid and flow ceases altogether (or in the best case

age the force balance on the liquid film results in a part of the liquid film with a negative (downwards) velocity. System instability occurs whe uid into multiple reservoir zones with varying in-situ stresses. Few years later the LEP completion technique was introduced in steam-injecti and are often based on misleading input data. The starting point in most cases is a vendor’s catalogue the service provider’s pro

es (ICVs) and four downhole pressure gauges (DHPGs). These technologies facilitated field development planning updates developing an Shallow Clastics reservoir were gathered from the appraisal and development wells of the deeper carbonate gas reservoirs; however core d

wells of the deeper carbonate gas reservoirs; however core data were limited to what could be generated from a single poor-quality core fro option of sand management other than in a few geographical locations has been the inability to predict the volumes of sand expected duri

of each component and amount added; g) The order and method of addition of each component; h) Aging or holding time at temperature ed space on the drilling barges and the number of acid carboys available. Handling and mixing large volume of acid can be a logistical nigh existed no practical methodology dedicated to pressure fall-off analysis on fractured water injectors. The very limited interest in fall-off test a

he well logging narrowed this to execution of a two zone DST from a cost vs. benefit stand point. Key performance indicators One of the m

capture by 60 to 80% and demonstrate that geological storage can be secure. ly CO2 is transported through the smaller cleats and is sorbed in the matrix blocks (Siemons et al. 2006a). Depending on the wettability of are dominated by relaxational phenomena."

e IPIECA Climate Change Working Group’s understanding of the presentations and discussions at the workshop. We are grateful to all peratures and a single optimization system incorporating information from several sources must deal with this variation. Managing this env

urate fluid models and integration of independent data sets become keys to addressing potential problems during the development and pro averaged numbers such as oil production rate watercut gas-oil-ratio and tubing head pressure. The production of a well is then assumed t hase meters are normally shared among a number of wells the actual performance of a well is only measured periodically or on demand.ï¿ of gas production is used to power the platform. All wells produce from the same reservoir and have water cuts of between 10 and 95% with

executed. One of the key elements of the Fix-the-Basics activities was to repair instruments and sensors; a list of over seven hundred W&R T – wireline formation tests closed system tests and injection tests. We will discuss each of these three types of OVT in some detail late it-for-purpose well test with minimal cost and HSE impact. In an ideal world all tests should be optimal but in our usage the phrase has com

widely advertised supported by operator’s management team and also adopted by Shell’s central technology council. The project b

ber of degrees of freedom in the estimation is gradually increased as the optimization proceeds. Multi-scale methods were first applied for

al-time data as they are generated.

circulating system. Figure 1 illustrates the complete UBD system which comprises of the drill pipe circulating system a rotating control dev perations with foam1 in 1992 and in 1993 and 1994 the company conducted trials using multi-phase drilling fluids and the closed loop 4-ph he reservoir.� Air compression for injection is carried out with compressors that are specifically designed for air at the relatively high targe d shales in unconsolidated formations is typically small determination of containment requires a better understanding of the propagation me series and proprietary branched C16 17 alcohol-based anionic surfactants which are part of the ENORDET™ A series.� Both families ts ultimate recovery. hree decades. The reservoirs in the Williston Basin (Buffalo MPH Horse Creek) are low permeability non-fractured carbonate reservoirs. T on gas for those reservoirs that are on miscible gasflood. With proper phasing there will be enough gas for all reservoirs to be gasflooded w uted tomography (CT) [18 19]. Both experiment and simulations in layered cores showed that foam propagates faster in the high permeabil and 7 active water injectors. Oil production has been maintained above 10 000 stb/d by successful application of infill drilling. Water produc

y and high oil viscosity on gravity drainage rates. Recoveries via matrix floods of water polymer or steam were discounted as development

ment a line-drive waterflood with horizontal wells in layers that were considered sparsely-fractured. Because GOGD is not effective in sparse ete fields are abandoned when cash flows turn negative because of excessive water production. The heterogeneous geologic nature of mo its low probability of success. Shell Petroleum Development Company Nigeria and Schlumberger successfully carried out this operation in cause of excessive water production. The heterogeneous geologic nature of most oil reservoirs however provides opportunities to prevent essure differential across individual matrix blocks can be too small to release oil from the blocks under waterflood thus leading to a poor re g policy which is becoming increasingly important. rete gradient method. The DGM method was first introduced by Bagirov12 and studied for different non-smooth optimization problems13 1 portation systems are similar to those that have been applied in the deepwater. Despite the fact that production equipment is relatively more 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 scibility for a live reservoir crude oil-gas system of Rainbow Keg River F Pool in �Canada. The pressure required for miscibility was optim

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 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 for the oilfield environment. A further complication of analyzing multi-component systems such as crude oil fractions is the interpretation of 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 nterfacial properties of IFT and contact angles as well as the pressure and temperature effects on these interfacial properties is provided be

and not so pronounced or consistent in lower quality sandstones. Recent developments and field studies have improved our understanding

ctive. Currently selection and design of a diversion method is often based on general guidelines and rules-of-thumb. Simulators are often n

ck of candidate wells. Even after a successful trial additional candidates require cost benefits of commoditization of the technology. But com e partition coefficient from the oil phase into the water phase (Kow) therefore tends to increase as the molecular weight of the naphthenic a

gement is to maximise value with respect to the risks to production from scale balanced against the cost downtime and potential damage f ique originates from the “pin-point method which was commonly utilized in the late 60’s as the well completion technique used for h

btaining static and dynamic data of the fracture network was hence the main focus of an interdisciplinary study carried out in the PDO Study h etc. Thermal reservoir simulation is a viable tool that can be deployed to explore for the most optimum case. The challenge with such mod date selection case specific recipe design for high water cut wells mechanism of fines/clay migration and control methodology along with o or all time-scales. In that approach we used the analytical relation between time and the (volume-averaged) matrix-block temperature to eli ximately 1 by 1 km. First injection started late September 2002 and three injection and production cycles were completed at the time of this

sandstone formations (such as a mud acid treatment) involves many stages of fluid which increases the complexity of the treatment. An alt During the past five years the industry has completed over 200 wells in the Pinedale Anticline (PDA) utilizing over 500 million pounds of pro

�The ability to evaluate the incremental production benefit associated with the use of one proppant versus another can have a significa uch as 30% of total completion cost (Huckabee et al 2005) accurate production analysis of the fracturing effectiveness can enable significa

e the Klinkenberg-corrected permeability or equivalent liquid permeability (k�) and the Klinkenberg gas slippage factor (bK). Heid et al3 a

o fluid incompatibility proppant back production causing fill and erosion of surface facilities or early water breakthrough due to fracturing int the creation of total asset awareness sooner.

. CITHP built up to 219bar shortly after the interval was shut-in but diminished to FTHP of 100bar once opened up to gas plant at several at

oth rate & composition) pressure and saturation responses of reservoirs under various operational plans. The real value of integration in stribution is determined by the range and distribution of pore sizes within the rock as well as the interfacial-force and density difference betw 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 ble contamination of a fluid sample by drilling-mud filtrate reduces the utility of the sample for subsequent fluid analyses. However the amo

y factors obtained through flow-simulations on fine and coarse-scale sector models. Resulting pseudo-functions are implemented in relative t to increased risks of hole closure that might be attributed to the complex and rapidly varying formation stresses. In addition drilling throug

i-frac injection test conducted before a stimulation treatment. The mini-frac analysis techniques available to provide estimates of the format e examples of touching-vug systems. Touching vugs have multiple origins and have little conformance to depositional models. There is no u aracterization purposes. The Katz-Thompson equation (Katz and Thompson 1986) can yield accurate estimations of the permeability using tion of UBD. In particular the ability to characterize the reservoir during drilling enables the Petroleum Engineer to make immediate use of irways (clusters of fracture corridors) are not detectible as faults by seismic data partly because fracture corridors rarely have an associated age log scan line density. The total number of fracture corridors is estimated from the total length and average length of fracture corridors. T ervoir complexities and nuances associated with almost every deepwater field [e.g. papers on deepwater Gulf of Mexico fields: Typhoon (Ri ained in real time and at in situ conditions and fluid composition is derived from the signature using the proportion of methane (C1) ethane raphs (GCs) to mass spectrometers. Improvements in mud gas extractors have provided the most significant technological advance and o of primary secondary and potential tertiary recovery mechanisms. This enabled the integrated team to embark on data gathering (appraisa

ht wells in PM301 discovering and appraising six discoveries: B.Melati B.Kamelia B.Anggerik B. Zetung Bumi South and B.Kesumba.

late production life in much more detail than was necessary for the initial oil production phase. Since start of production in 1993 the Gann

ed fractures to the reservoir via special connections helped to eliminate most of the numerical instabilities that are generally encountered in ptimums.

serves equate to more than one year of crude oil exports from Russia at the current level of around 4.4 million barrels per day or 660 000 to ed in many fields related to modeling and control. It can essentially be divided into two different strategies which are not mutually exclusive died in the years before but these studies were performed by different teams at a different maturity level of the fields and with different obj

ver-increasing volumes of gas from locations where it is found to where it is used. This paper presents a methodology for combining supply . To counter constraints in the engineering procurement and construction (EPC) contracting business including a shortage of capacity in m nistic particulate plugging of permeable media. The composite chemical landscape depends on the properties of reservoir rock injected flui e large volumes of produced water as an alternative source to fresh or seawater. In this paper Average volumes of produced water world

e oil production while keeping the water and gas production to a minimum. As there was no rig available the operations had to be carried ou

campaign. All fluids produced were processed on a floating production storage and offloading (FPSO) facility situated centrally in the field pelines. Produced water is processed to appropriate standards and disposed of overboard. During the field development it was concluded t ne reservoir consisting of the Garn and the Rogn formations (Figure 1) and is situated at 1610 meters the below seafloor.The bottom-hole t

into project perspective a study was commissioned to both X and Y oilfield to verify H2S trends understand their root cause and predict po simple low temperature low pressure vertical platforms wells to high temperature and pressure where compatibility and thermal stability are ntelligent search (b) minimizes personal bias and (c) automatizes tedious simulation tasks e.g. input preparation simulation post-process at the beginning of 2001. An initial opportunity framing workshop helped the team to become familiar with each other and the subsurface as

ring over the rest of the field forming a regionally active aquifer see Figure 3. Both sands were deposited in a coastal predominantly shore some cases the results can be surprising and lead to unexpected benefits as will be described in one of the following examples.� Fluid f

es between 120 to 130 m in areas without BKU erosion. The Mulussa F1 and F2 (MUF1 MUF2) consist of fluvial channel sands and flood p quality constraints either directly on the control variables or indirectly in terms of certain state variables of the well/reservoir system. Apart f ons completed with multiple zones. It is intended that injection will be into two zones simultaneously alternating between zones several time

ol theory has been used previously for optimization of injection and production rates in a fixed-well configuration (Ramirez 1987 Asheim 198 n of seismic data and by fewer well penetrations because of the high cost of drilling. Accordingly the project sponsors (Chevron and Woods mbedded in the production data. The type of production data in turn is a function of the recovery mechanism. More precisely flowing phase en by reason of the ad hoc nature of the entire process only very little quantitative information could be captured about the uncertainties a ansfer has been estimated only from correlations for Newtonian fluids or from very large convection cell experimental correlations of well pe re simulators which often are based on a single-well model in a simplified reservoir formation. Generally reservoir heterogeneity is reduced most of the numerical instabilities that are generally encountered in the coupled (reservoir flow)-(fracture growth) problem. The current pape voir interactions and therefore give non-realistic production forecast in cases where well-reservoir interactions play a crucial role. n has a maximum pour point temperature which is slightly lower than the reservoir temperature which implies possible wax deposition durin

or sensitivity studies. This paper presents the performance review of the Champion water flood reservoirs using reservoir engineering analy ns to LGR were made in this work. Several investigators have used pseudopressure functions to estimate well deliverability. These method

n developed with this idea. Cartesian local grid refinement1 2 and hybrid local grid refinement3 are two well-known types of LGR. As these t hundred different realization of reservoir that is time consuming and costly even by using coarse grid. Various upscaling techniques includ a detailed description of reservoir rock properties with a coarser scale description4 which has equivalent properties5. In other words the s

iption (EOS) corporate level predictions were performed simultaneously for all three reservoirs and major investment decisions were made The elastic simulation numerically simulates the structural deformation of the reservoir by solving linear elasticity equations under given bo gineering disciplines using a stochastic approach. The static model was developed in a fine-scale grid system of 4.2 million cells that has be the context of single- and multi-phase matrix-fracture modeling (Barenblatt et al. 1960; Warren and Root 1963; Kazemi et al. 1976; Thomas

hen rig rates approach or occasionally exceed $0.5�MM/day a simple technical decision would be faced with the highest degree of scru

the above is also possible. This paper will focus on option 3. Considerations for Simplification Ideally a good Integrated Production System es that relate measurements and model parameters. Instead of computing gradients as in variational methods these covariances and cros eneous reservoir. This paper revisits the ideas underlying Larson’s paper. Similar ideas are shown to hold for heterogeneous reservoirs

annual US crude oil prices inflation adjusted data source: www.inflationdata.com) and a major secondary recovery project with economie

ncertainty in reservoir descriptions and performance predictions (Sharif and MacDonald 2001). These multiple realizations variously accoun y no short term practical alternative to the use of gas for this purpose. Therefore continuation of a steady supply to meet these needs is a p

ses general property variation etc. Such models have been developed by Farouq Ali (1981) Farouq Ali and Abou-Kassem (1989) Stone e we will incorporate conventional core analysis (porosity permeability) thin section and SEM analysis mercury-air capillary pressure (Pc)/ N fingerprinting of oil samples repeat pressure surveys and production data. The boundaries between the reservoir compartments are define g anthropogenic CO2 (Oldenburg et al. 2001).

ervoir rock is Ara 2 Carbonate (A2C) which is mainly dolomite with some Limestone. In this reservoir dolomitization is linked to the productive

been done before. Burger8 already suggested that the increase in temperature in light oil naturally fractured reservoirs would lead to oil ex

oth producers and injectors. As a result of re-development and in particular due to the initial cold depressuring phase the field will produc uncertainty by integrating dynamic data; 2) changing the reservoir connectivity to capture correct uncertainty ranges; 3) developing a flexibl with a production of ~140 kbpd. Similarly CSS is currently the technology used at Shell’s Peace River as SAGD has not shown its prom

r. Note that the shortest lateral distance between the producer A1 and the injector A8z is in the order of 850 ft (with similar vertical offset). F n the well will exceed atmospheric pressure by a factor two or more. This makes accurate modelling of the total system performance less im 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 experiences over the last four decades follows summarizing key learning’s for each era. fluids filter cake downhole tools and screens continue to further expand the application envelope for openhole horizontal gravel packing.ï ral gas in place with 10 % H2S or more and 700 tcf with 10 % CO2 or more. This is roughly 15 % of the total gas still to be produced. The b ational difficulties. Cost structure: Coil tubing cost overruns overall stimulation cost. Weather conditions make stimulation operation in con 12 000-acre reservoir is charged with light-oil type though with slight variations in properties as indicated by the analysis results of the abun

ences from a few techniques to locate bypassed oil in mature water drive reservoirs. They comprise conclusions drawn from average reserv

unnecessary information or conversely not obtaining sufficient data. The combined pressure transient testing and the MRMZ production lo

e reservoir permeability and thickness respectively. The differential depletion model (Phil Fair and Fritz Rambow personal communication) nderstanding the exploration and appraisal or field-development objectives and translating these into acquisition objectives is essential for s y of the results from the FEM model. Also the computation expense required for complex simulations typical of the FEM can make the repe

of flow distribution it is necessary to consider technology and technique that functions with a high degree of reliability in these oftentimes h within the deeper Miocene interval. The geologic age of the Mars formations above 14 000 feet are Pliocene and the deeper reservoirs are M ment into and along the wellbore. This in turn impacts the well’s productivity and other parameters such as skin factor.

il bearing sand stone reservoirs in Brunei. wellbore in a horizontal well.� Advantages of horizontal wells over vertical ones have been well documented.� Specifically in the Nige ning effect is observed after approximately 20 molecular layers of phosphonate surface coverage that retards further calcite dissolution; and . optimization of sweep efficiency in waterflooding) and (2) production optimization which involves the pressure and short-term saturation

mize controllable variables during foam drilling. The model incorporates both aqueous and polymer-based foam rheological parameters tha thods in Brunei have shown remarkable changes in terms of technology used to ensure the treatment capable of controlling the formation s 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

abandoned wells this practice has failed. This could be due to either poor completion jobs or the nature of the formation and its fluids. This es an opportunity to produce the well over the full length. A sensitivity analysis was performed by removing the smart completion from the m

e introduction of parameters that may be difficult to measure experimentally is disadvantageous and it is preferred to use parameters that a xperiments is still lacking. In this paper we present a numerical analysis of the foam flow in the porous media by using the stochastic popu ases altogether (or in the best case some gas continues to bubble upward through a liquid column). Several approaches have been sugge

locity. System instability occurs when the inflow performance relation (IPR reservoir curve) intersects the tubing performance curve (TPC) t ique was introduced in steam-injection wells by Mobil Oil Corp. in 1975 [4]. Mobil Oil Corp. tested this technique in the Tulare formation D a ogue the service provider’s proprietary software or the service provider’s representative conveniently stationed in an office along t

ent planning updates developing an intelligent well field philosophy and also alternative methods for developing oil rims in complex conditio nate gas reservoirs; however core data were limited to what could be generated from a single poor-quality core from the E11-SC1 well. A d

ed from a single poor-quality core from E11-SC1. A dedicated Shallow Clastics appraisal/ early-producer well (E11-SC2) had been drilled wi t the volumes of sand expected during the production period. The volume or rate of sand production determines the erosion rate of the sur

ging or holding time at temperature if required prior to tests; i) Test temperature; j) pH (for aqueous fluids where applicable); k) All other as ume of acid can be a logistical nightmare especially when there are more than 2 horizontal wells that require stimulation per campaign. e very limited interest in fall-off test analysis on fractured water injectors may be well related to the fact that most operators have been tradit

performance indicators One of the most important and basic requirements in the Norwegian and international oil industry is to have control

6a). Depending on the wettability of coal we can distinguish the following gas exchange mechanisms: The coal is water-wet and CO2 and

the workshop. We are grateful to all participants for their efforts and contributions throughout the workshop which together with this public ith this variation. Managing this environment therefore involves accounting for changes in the physical asset represented by the informatio

ems during the development and production life cycle of the field as well as reservoir management and surveillance programs. For examples oduction of a well is then assumed to be uniformly at the tested production rates between well tests other then at various intervals when the asured periodically or on demand.�Typically around 2% of the well monthly production is measured by well testing.�Thus the surveilla ter cuts of between 10 and 95% with an average of 80%; the approximate Gas Oil ratio is 78 m3/m3. Production is assisted through gas lifti

rs; a list of over seven hundred W&RM critical sensors and meters was entered into SAP�(the planning and financial database) for repair ree types of OVT in some detail later but the first and most important step in evaluating the usefulness of any OVT is to understand why we but in our usage the phrase has come to mean any test in which no significant volume of live hydrocarbons is produced to the surface. We

ral technology council. The project became a key demonstrator project for the Shell group for smart field developments and as such recei

cale methods were first applied for solving partial differential equations to speed up convergence8 9. Later through the development of wa

lating system a rotating control device (RCD) a UBD choke manifold a separator and a flare stack or flare pit. In addition non-return valve lling fluids and the closed loop 4-phase separation system. In 1995 Shell successfully drilled the first horizontal underbalanced well using c ned for air at the relatively high target pressures. understanding of the propagation mechanisms at the interface. RDET™ A series.� Both families are suitable for EOR because they have a reduced tendency to form ordered structures/liquid crystals t

on-fractured carbonate reservoirs. There is little structural relief and the primary drive mechanism of liquid and rock expansion results in low for all reservoirs to be gasflooded within a 30-year period. Fluid Sampling and Analysis As for many enhanced oil recovery projects fluid sa pagates faster in the high permeability layers [18]. In this paper we build a novel multi-phase multi-dimension reservoir simulator based on plication of infill drilling. Water production is around 26 000 stb/d as of June 2008 and average production water cut is 68%.

m were discounted as development options due to the pervasive fracturing observed in the field which would encourage the flooding agents

use GOGD is not effective in sparsely fractured reservoirs waterflooding these layers was expected to increase recovery substantially in th eterogeneous geologic nature of most oil reservoirs however provides opportunities to prevent or reduce excessive water production.�In 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 provides opportunities to prevent or reduce excessive water production. In layered reservoirs water production can be managed by eithe waterflood thus leading to a poor recovery. Depending on the wetting state of the matrix and its initial water saturation Swi capillary action

-smooth optimization problems13 14 15. In this paper we use two sets of published gas lift optimization test problems3 16 and created o oduction equipment is relatively more accessible in on-shore locations and interventions are therefore expected to be less expensive the ab 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 ure required for miscibility was optimized in this study by performing gas-oil interfacial tension measurements using the drop shape analysis

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 using a technique of monitoring OBM contamination which is based on measuring the change of methane content and color in the flowline e oil fractions is the interpretation of the analytical data generated and incorporation of the right information into prediction systems of practi . 2002). In addition to formation blockage and general difficulty in the separation of oil and water in production facilities one of the main dra e interfacial properties is provided below.

es have improved our understanding of the chemical behavior of this acid system with various sandstones enabling formulation adjustment

es-of-thumb. Simulators are often not used because they are not available. However in most wells with a heterogeneous permeability profi

oditization of the technology. But commoditization requires widespread uptake of the technology and uptake requires the recognition of the molecular weight of the naphthenic acid decreases. For a single naphthenic acid this mass transfer process is governed by the two main qu

st downtime and potential damage from any treatment. Chemical treatments to mitigate against scale (scale squeezes and continuous chem well completion technique used for hydraulic fracturing [5 6]. The marked improvement in steam profile control led to the extensive applica

y study carried out in the PDO Study Centre. With existing and newly acquired seismic well and interference data and guided by the region case. The challenge with such models is for them to be reasonably well history matched while at the same time retaining their predictive c nd control methodology along with one of the successful approaches to acidise heavy or medium crude. Laboratory quality control also form ged) matrix-block temperature to eliminate time in favour of the volume-averaged matrix-block temperature thus obtaining an exact expres s were completed at the time of this work. The conceptual model based on the joint interpretation of the monitoring data from Pad 40 pointe

e complexity of the treatment. An alternative approach uses chelating agents combined with acids as the main treatment agent. Chelating lizing over 500 million pounds of proppant.� However there is no consensus on the optimal stimulation design with each operator using

versus another can have a significant impact on the profitability of the field development. Several studies have been performed in the past g effectiveness can enable significant cost savings. Production Logging Methodology A typical completion (figure 1) consists of up to 24 fra

as slippage factor (bK). Heid et al3 and Jones and Owens4 proposed two correlations similar in form between bK and k� while Sampath

er breakthrough due to fracturing into the water leg. In the 90’s horizontal drilling became common practice as new drilling technologies

opened up to gas plant at several attempts. Trouble shooting the root causes of this problem by working on the Surface Control Unit did not

ns. The real value of integration in reservoir geoscience and engineering lies in the ability to optimize this coupling between the static and cial-force and density difference between the two immiscible fluids. 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 nt fluid analyses. However the amount of filtrate contamination can be reduced substantially by use of focused-sampling cleanup introduce

unctions are implemented in relatively simpler rapid coarse-scale dynamic models to be employed within Monte Carlo applications. Channe stresses. In addition drilling through highly pressure-depleted reservoirs raises considerable risks of excessive mud loss internal blowout

e to provide estimates of the formation capacity (kh) and indications of the presence of natural fractures include preclosure and post-closur o depositional models. There is no universal method to characterize petrophysical properties of touching-vug reservoirs (Lucia 1999). estimations of the permeability using the porosity and the electrical formation factor. However the requirement of having a measured value Engineer to make immediate use of the knowledge in designing completions that optimize the performance of the well being drilled. Addition corridors rarely have an associated visible fault displacement or they are too small (Figures 2 and 3). The first step in determining how effe verage length of fracture corridors. The difference between the total number and the number of fracture corridors captured by data analysis er Gulf of Mexico fields: Typhoon (Ring et al. 2004); Tahiti (Carreras et al. 2006); and Boris (Coludrovich et al. 2004)]. proportion of methane (C1) ethane to propane (C2-5) the hexane plus fraction (C6+) and carbon dioxide (CO2). The gas-oil-ratio (GOR) o nificant technological advance and offer a step change in sample quality for mud gas systems. Enhancements to mud gas extractors have fo embark on data gathering (appraisal surveillance etc.) aiming at reducing uncertainties and firming up viable life-cycle development option

g Bumi South and B.Kesumba.

tart of production in 1993 the Gannet-A field which is produced from a small-sized platform with very limited space has lived through times

es that are generally encountered in the coupled (reservoir flow)-(fracture growth) problem.

million barrels per day or 660 000 tonnes per day (2007) while the gas reserves represent nearly five years of Russian gas exports to Europ es which are not mutually exclusive: reducing the uncertainty itself using measurements [i.e. history matching (Landa and Horne 1997 Li e el of the fields and with different objectives. The current study provided the first cluster wide attempt for development planning. A multi-disci

methodology for combining supply and demand profiles recoverable gas resources and transport capacities in a single gas distribution mo ncluding a shortage of capacity in many areas and rising prices a contracting strategy was applied aimed at giving access to a wider range perties of reservoir rock injected fluid and its contaminants but also on additives that are always being used to facilitate key processes. As ge volumes of produced water worldwide per nations and per companies are presented case for change in management of produced wat the operations had to be carried out on a Modular Skid Unit (MSU) which constrained the available tools and methods.

) facility situated centrally in the field and oil was loaded directly to tankers (Fig. 2). The associated gas was exported through pipelines. Wa ield development it was concluded that Bonga was expected to suffer from reservoir souring and that mitigation would be necessary. Initially he below seafloor.The bottom-hole temperature is 71�C and the pressure is 165 bars. Oil production started in October 1993 and is pred

stand their root cause and predict possible future H2S scenarios. ompatibility and thermal stability are major concerns1-3 carbonate reservoirs where the precipitation of pseudo scales may cause formation reparation simulation post-processing etc. Optimality and efficiency in the well placement decision process are the main motivations behin th each other and the subsurface assets they were asked to develop. Much of the data available from the exploration play and discovery we

ed in a coastal predominantly shoreface setting.� Porosity ranges from 28 to 32 %; permeability ranges up to 30 Darcy with an average o the following examples.� Fluid flow regimes in vertical deviated and horizontal wells In a system with multiphase flow buoyancy cause

t of fluvial channel sands and flood plain shales with a total thickness of up to 350m. The Mulussa F1 is characterised by a lower net-to-gros of the well/reservoir system. Apart from constraints on individual wells there can also be global constraints dealing with several wells. Exam ernating between zones several times a year. This concept is not feasible without the use of smart technology: each zone will be fitted with

guration (Ramirez 1987 Asheim 1988 Sudaryanto and Yortsos 2001 Zakirov et al. 1996 Virnovsky 1991 Brouwer and Jansen 2004 Sarm ject sponsors (Chevron and Woodside Energy Ltd.) requested that the ARM be designed to mimic a turbidite channel system i.e intersectin nism. More precisely flowing phases and injection/production constraints associated with a given recovery mechanism determine the types e captured about the uncertainties around the reservoir model. Automatic and semi-automatic techniques have been developed to address t experimental correlations of well performance. Absence of a conventional correlation model means that the fluids’ heat transfer proper y reservoir heterogeneity is reduced to a number of horizontal layers with homogeneous properties and a laterally infinite extent. Fracture p e growth) problem. The current paper presents an important application of coupled reservoir flow and induced fracture growth. The focus is ctions play a crucial role. mplies possible wax deposition during production.

rs using reservoir engineering analytical techniques with particular emphasis on Buckley-Leverett displacement theory and Welge displace ate well deliverability. These methods are simple and have been shown to yield useful predictions.

well-known types of LGR. As these grids are based on a Cartesian grid both have the difficulty in aligning the grid lines with complex featur Various upscaling techniques including analytical and numerical with different accuracies and range of applicability have been introduced in nt properties5. In other words the scale-up process replaces the detailed representation of rock properties at a smaller scale with a constan

or investment decisions were made. The predictions were in line with the standalone simulations and most importantly matched actual pro r elasticity equations under given boundary conditions and simultaneously calculates the corresponding stress/strain tensor fields (Bourne ystem of 4.2 million cells that has been upscaled into a coarse-scale grid system of 181 000 cells. The upscaling was performed through a g ot 1963; Kazemi et al. 1976; Thomas et al. 1983; Coats 1989; Ueda et al. 1989; Zimmerman et al. 1993a; Chang 1993; Lim and Aziz 1995;

aced with the highest degree of scrutiny. Competition between well targets for a drilling slot in a rig sequence or a platform well slot could be

a good Integrated Production System Model is constructed to support the Production System Optimisation (PSO) process and Forecast pro ethods these covariances and cross-covariances are utilized to update the models. The increased deployment of permanent downhole se o hold for heterogeneous reservoirs of any shape. A new analysis technique replacing the Muskat plot by a plot of the pressure derivative s

ary recovery project with economies of scale applied to the whole field instead of isolated reservoirs now becomes attractive. A scouting s

ultiple realizations variously account for uncertainties in structure stratigraphy and petrophysical properties. Although impressive the finedy supply to meet these needs is a prerequisite to sound energy management of the continent.

i and Abou-Kassem (1989) Stone et al. (1989 2002) Holmes et al. (1998) Pourafshary et al. (2007) and Livescu et al. (2008). These mod ercury-air capillary pressure (Pc)/ NMR with special core analysis data in particular the imbibition Pc and residual oil saturation. Several e e reservoir compartments are defined by a combination of faults and stratigraphic heterogeneities. Although clear in places some compartm

omitization is linked to the productive intervals.

tured reservoirs would lead to oil expulsion of significant quantities of oil from the matrix blocks into the fracture. The recovery mechanisms

essuring phase the field will produce some 60 to 90 million m3 of water for which the preferred option is disposal via injection into deep un ainty ranges; 3) developing a flexible integrated method to model sedimentary facies connectivity. Stochastic reservoir modeling technolog ver as SAGD has not shown its promise there. Consequently the rise of SAGD a fairly young technology compared to CSS has raised a l

850 ft (with similar vertical offset). For the two well pairs in the south and west water cut was increasing somewhat faster than expected (bu the total system performance less important. This does not apply to blowouts at seabed of subsea wells. The wells blow out against the hyd ted by the readership.1 2 OperatorTerminology BP“Field of the Future Chevron“i-field Shell“Smart Fields Also during the

openhole horizontal gravel packing.�However as with any other evolving technology there are still limitations that must be addressed.� e total gas still to be produced. The bulk of these resources can be found in the Middle East the Caspian region and the Far East. Conside s make stimulation operation in conflict with other operations in a limited weather window. Stimulation related equipment and infrastructure d by the analysis results of the abundant pressure-volume-temperature measurement samples. Because of limited TLP well availability the

clusions drawn from average reservoir fluid contact movement calculations calibration with logged contacts estimation of local area contac

testing and the MRMZ production logging of several of the wells tested in the Mars field will be described in detail to illustrate the monitoring

Rambow personal communication) argues that this loss occurs mainly due to reduction in producing thickness although the exact mechanis cquisition objectives is essential for success. Figs. 1 and 2 schematically illustrate the real-time monitoring concept. Real-time data are view ypical of the FEM can make the repetitive calculations required in inversion modeling impractical. In this paper the semianalytical approach

ee of reliability in these oftentimes hostile environments. This paper examines an alternative flow detection solution and provides recomme cene and the deeper reservoirs are Miocene. Exploratory and appraisal drilling encountered 14 major and 10 minor moderately geopressure such as skin factor.

mented.� Specifically in the Niger Delta horizontal wells have been found to have the potential to dramatically enhance the economics o etards further calcite dissolution; and (3) the consequence of retarded calcite dissolution is that less basic ion CO2- 3 is released into solut pressure and short-term saturation responses (such as water breakthrough) (Rossi et al. 2000). Short-term production optimization can be

sed foam rheological parameters that were obtained using pipe viscometers with different HEC polymer concentrations. Because polymers h apable of controlling the formation sand production as well as maintaining the hydrocarbon production rate.12-16 Implemented sand contro 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

e of the formation and its fluids. This paper introduces a new concept for the use of heavy oil-in-water (HO/W) emulsions as a novel sealant ving the smart completion from the model. Results justified the smart completion because the well would be producing from only half of the

s preferred to use parameters that are measurable experimentally. Recently Zitha [13] developed an alternative population balance theory f media by using the stochastic population balance model and validate the analysis using experiments reported previously by Nguyen et al. everal approaches have been suggested and tried to prevent or delay the loading process such as3 4: The installation of siphon and veloc

e tubing performance curve (TPC) to the left of the minimum in the tubing curve. In practice the liquid drainage point may be to the left or to chnique in the Tulare formation D and E zone sands as a part of continuous-steam injection with vertical wells in the South Belridge field K eniently stationed in an office along the corridor.� All of these resources ultimately refer back to a common data source: API RP-19B Sect

veloping oil rims in complex conditions such as producing against a high-flowing tubing-head pressure. It was decided to include these tech ality core from the E11-SC1 well. A dedicated Shallow Clastics appraisal/early-producer well (E11-SC2) had been drilled with a deviated wel

r well (E11-SC2) had been drilled with a deviated wellbore through the H1/H2 targets and a completion design consisting of a cased and pe etermines the erosion rate of the surface facilities components the sizing of separator vessels and sparging devices the settling tendencies

ds where applicable); k) All other aspects of the fluid preparation which are known to affect the outcome of measurement should be report quire stimulation per campaign. hat most operators have been traditionally unaware that their water injectors are fractured. Only in recent years this situation has started to

ational oil industry is to have control of the activities offshore to act on issues in a proactive manner and to capture experience data. For the

The coal is water-wet and CO2 and CH4 diffuse in the water-filled cleats. The coal is CO2-wet or gas-wet and countercurrent capillary dif

hop which together with this publication is part of an ongoing effort by IPIECA to provide constructive input on key climate change issues asset represented by the information hierarchy and in the data available for the asset. In production optimization a single architecture mus

surveillance programs. For examples the reader is referred to Honarpour et al. (2006) and Nagarajan et al. (2007). er then at various intervals when the well is designated to be closed-in". Sub-normal production rates unstable production or increases in g by well testing.�Thus the surveillance of individual wells is a periodic discontinuous process.� This is not optimal as many well problem oduction is assisted through gas lifting of all the wells. Platform operations staff operate a 14 day two shift system many operations staff ha

ng and financial database) for repair and this workload was completed by Q3 2008. A second major effort that was executed was building t of any OVT is to understand why we perform well tests in the first place. The concept of the Value of Information (VOI) is well known within ons is produced to the surface. We have identified three types of tests that might qualify as an OVT – wireline formation tests closed sys

d developments and as such receives great focus from its top management. Phased Staircase approach With this vision for the CW fie

ater through the development of wavelets multi-scale approaches have also widely been used within inverse problems.[10-13]

lare pit. In addition non-return valves (NRV’s) are installed in the BHA and drill string to prevent flow up the DP1. As part and parcel of orizontal underbalanced well using coiled tubing in Canada2. In 1997 Shell introduced underbalanced drilling in the offshore envi-ronment3

m ordered structures/liquid crystals that are undesirable in reservoirs4 IOS products because they are a complex mixture of surfactants of d

uid and rock expansion results in low primary oil recoveries due to a lack of pressure support. This results in rapidly declining production rat hanced oil recovery projects fluid samples and well-designed experiments with those fluid samples are critical for evaluating and implemen ension reservoir simulator based on the SBP foam model and provide a numerical analysis of foam flow in heterogeneous porous media. W n water cut is 68%.

would encourage the flooding agents to completely bypass the matrix.

increase recovery substantially in those layers. Since 1997 field development and operation have used this combination of GOGD and loca ce excessive water production.�In layered reservoirs with good vertical isolation between the layers water production can be managed e iated with cement squeeze in a singlestring multizone completion is the difficulty associated with placement and confirming where the TOC roduction can be managed by either controlling the injection profile in the injectors (if water is injected) and/or by selectively producing diffe ater saturation Swi capillary action can cause imbibition of water up to a "spontaneous" equilibrium saturation commonly denoted as S sp

on test problems3 16 and created our own test problems10 which have the necessary non-convex and non-smooth features to demonstra xpected to be less expensive the absence of integrated flow assurance strategies could lead to a reduction of up-time and production large 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 ments using the drop shape analysis technique at varying pressures and at reservoir temperature and fluids compositions. Rao and Lee (20

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 ane content and color in the flowline as cleanup with the downhole pump proceeds and progressively larger fractions of formation fluid repla ion into prediction systems of practical relevance to operations. 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

es enabling formulation adjustments to suit various performance enhancement needs2. This apparent success has enabled us to carefully

a heterogeneous permeability profile flow conditions are complex and fluid distributions cannot be predicted without using a numerical sim

take requires the recognition of the value. The accepted practice for executing a "greenfield" development plan is to use a full-field dynamic ess is governed by the two main quantities the oil-water partitions coefficient Kow and the acid dissociation constant Ka. The study is aim

scale squeezes and continuous chemical injection) and to dissolve scale are frequently applied in order to avoid deferment or even loss of p e control led to the extensive application of LEP technique as injection completion scheme in HVO recovery process. Therefore description

ence data and guided by the regional understanding established in PDO a series of matrix and fracture models were built and cycled with ame time retaining their predictive capability. Injection above fracture pressure adds to physical complexities. Addressing this challenge bec . Laboratory quality control also forms part of this paper. ure thus obtaining an exact expression for the transient shape-factor in terms of the (volume-averaged) matrix-block temperature." monitoring data from Pad 40 pointed the way to the required functionality for the reservoir simulation for the CSS process to obtain a good

e main treatment agent. Chelating agents are materials that are used to control undesirable reactions of metal ions. In oilfield applications on design with each operator using different criteria to select proppant.� This trial was specifically designed to determine which proppan

es have been performed in the past which have utilized a comparison of production values to compare the performance of proppants.[1 2 on (figure 1) consists of up to 24 frac stages each of which may have six perforated intervals ranging from 2 to 6 feet in length. Perforating

tween bK and k� while Sampath and Keighin5 proposed a different form of correlation using effective porosity (f) as a third parameter."

practice as new drilling technologies developed and proved to be very successful in several UK Southern North Sea tight gas fields. Table 1

g on the Surface Control Unit did not yield good result. It was then suspected that the Tr-ScSSSV could be the source of the problem. In a b

this coupling between the static and dynamic components at both the appraisal and the development stages. The result of such a workflo

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 focused-sampling cleanup introduced recently in the next-generation wireline formation testers (O’Keefe et al. 2008). DFA tools provide

in Monte Carlo applications. Channelized turbidite reservoirs constitute a suitable and relevant first target for the 3D connectivity workflow a xcessive mud loss internal blowout and differential sticking (van Oort et al. 2003). Drilling through such depleted sands was accomplished

s include preclosure and post-closure methods. -vug reservoirs (Lucia 1999). rement of having a measured value of the electrical formation factor is a disadvantage of this method. nce of the well being drilled. Additionally the evaluation and exploitation of opportunities can occur almost simultaneously with powerful imp he first step in determining how effectively seismic faults represent fracture corridors is to overlay seismic faults on fracture corridor stick plo corridors captured by data analysis is the number of fracture corridors that escaped detection.� This number is used to infill stochastic fra et al. 2004)]. 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 ments to mud gas extractors have focused mainly on constant extraction volume and extraction efficiency. Basic mud extractors or gas trap viable life-cycle development options. In this paper we will highlight only the SCAL uncertainty and its impact on the ultimate recovery. More

mited space has lived through times of low oil price and facility modifications related to additional tie-in of satellite fields. As a result focus o

ears of Russian gas exports to Europe or enough to supply current global LNG demand for four years. atching (Landa and Horne 1997 Li et al. 2003)] and reducing the sensitivity to the uncertainty. In this paper we consider a situation in which development planning. A multi-disciplinary effort went into the screening phase to help identify data gaps and formulate clear appraisal stra

acities in a single gas distribution model. The gas distribution model presented here uses public data and predictions from Government Age ed at giving access to a wider range of contractor resources and creating competition while retaining close control over the areas where pro used to facilitate key processes. As these interactions cannot easily be modelled water qualities are being placed in a actualized perspectiv ge in management of produced water is made Shell’s integrated water management strategy principles and applications particularly i

ols and methods.

was exported through pipelines. Water was processed to appropriate standards and disposed of overboard. Since the beginning of the pro itigation would be necessary. Initially the expected H2S content resulting from reservoir souring was not expected to exceed 50 ppm (v) in t started in October 1993 and is predicted continuing until year 2025. Seawater injection at an average of 40 000 m3/day was initiated in 19

pseudo scales may cause formation damage4 and complex deep seawater completions5 6. ocess are the main motivations behind the work presented here. When it comes to well location optimization several approaches have bee he exploration play and discovery wells was reviewed. It was clear that there was a lot of uncertainty in all aspects of the cluster of reservoir

es up to 30 Darcy with an average of 5 Darcy. The Draugen oil is highly under-saturated with an initial hydrostatic pressure of 165 bar.� ith multiphase flow buoyancy causes the fluids to separate into different phases with a mixing layer in between. Gravity ensures that the lig

characterised by a lower net-to-gross ratio (~22 %) than the Mulussa F2 (~35 %). Connectivity in this thinly bedded (single sand thickness i ints dealing with several wells. Examples can be (equality or inequality) constraints imposed by surface facilities or constraints imposed by nology: each zone will be fitted with an inflow control valve (ICV) and dual downhole pressure gauges to allow remote control. At the time th

91 Brouwer and Jansen 2004 Sarma et al. 2005 Kraaijevanger et al. 2007). In these applications the parameters to be optimized are usu bidite channel system i.e intersecting sinuous channels with varying degrees of connectivity.� This paper presents the reservoir simulati ery mechanism determine the types of available production data. An arbitrary combination of water oil and gas production rate and wellbo s have been developed to address the difficulties associated with history matching and assist reservoir engineers. Optimal simulation workf at the fluids’ heat transfer properties cannot be engineered and quantified based on small laboratory measures of fluid properties such a a laterally infinite extent. Fracture propagation is described using a pseudo-3D description (van den Hoek et al. 1999). For many field deve duced fracture growth. The focus is on demonstrating how dynamic fracture growth around injectors is largely driven by reservoir engineerin

acement theory and Welge displacement efficiency calculations.1-2 These two analytical techniques were applied to generate from the field

ng the grid lines with complex features and boundaries. Modular gridding proposed by Palagi and Aziz4 uniformly distribute the grid points applicability have been introduced in literature to calculate upscaled flow properties mainly absolute permeability. A compehensive review o ies at a smaller scale with a constant and smoothed quantity over the region of interest which contains fewer details at that larger scale. Th

most importantly matched actual production data. g stress/strain tensor fields (Bourne and Willemse 2001; Maerten et al. 2002; Bourne et al. 2001; Daly and Mueller 2004; Roxar FracPerm R pscaling was performed through a grid optimization process using the streamline simulation to maintain a high level of heterogeneity in the a; Chang 1993; Lim and Aziz 1995; Gilman and Kazemi 1983; Beckner et al. 1987 1988; Rossen and Shen 1989; Bech et al. 1991; Bourbi

ence or a platform well slot could be fierce. When available opportunities are comparable in terms of their rate of return on investment and

on (PSO) process and Forecast process. However for 1 – 2 year forecasting usually not the same level of detail is required as for PSO. I loyment of permanent downhole sensors and intelligent well systems that provide a continuous stream of information has made the EnKF a by a plot of the pressure derivative simplifies the determination of average reservoir pressure. It is shown that parameters from analysis of a

ow becomes attractive. A scouting study carried out in 2004 has identified that Champion field could produce an additional 8% of the STO

rties. Although impressive the fine-scale geological models usually run into several millions of cells and current computing technology limi

nd Livescu et al. (2008). These models entail one-dimensional (axial) representations of the wellbore and include coupled conservation equ nd residual oil saturation. Several experimental techniques are available to measure capillary pressure (Pc) curves both in drainage and im ough clear in places some compartment boundaries can only be defined from non-geological data sources. Understanding these heterogen

fracture. The recovery mechanisms that play a role are very similar to those of a light oil steam flood9: Viscosity reduction Distillation Ga

is disposal via injection into deep underground regional depleted Carboniferous and Zechstein gas fields.�It will be important to maintai hastic reservoir modeling technology provides geologists and engineers an efficient way to integrate various types of data for predicting inte gy compared to CSS has raised a lot of questions such as what is its efficiency its ultimate recovery how sound is it what type of reservoi

g somewhat faster than expected (but still a lot slower than for A1) and therefore the water injection rate was decreased recently. So far th s. The wells blow out against the hydrostatic pressure of the water column at the mudline. In most cases this pressure will determine the flo l“Smart Fields Also during the past decade there has been an increasing appreciation within the industry that much of the future lies w

mitations that must be addressed.�One of these has been that the reservoir completed must have a sufficient pressure difference betwee n region and the Far East. Considering less severe levels of contamination even up to about 40 % of the total gas still to be produced can elated equipment and infrastructure of stimulation service present some limitations. Contractual issues. No technical people focusing on s se of limited TLP well availability the high cost of subsea wells and the limitations of the subsea system to handle large water cuts the wate

acts estimation of local area contacts from performance and animation of production data to locate bypassed oil. The robustness of the ap

d in detail to illustrate the monitoring technique and to show the time-lapse changes occurring in the Mars field. The flow pattern of the prod

ckness although the exact mechanisms of flow impairment are still debated. Reduction in permeability is another alternative explanation offe ing concept. Real-time data are viewable by authorized personnel anywhere around the world thus allowing virtual collaboration between fi paper the semianalytical approach is adopted in forward modeling. The third area of study is the inversion of the surface-deformation mea

tion solution and provides recommendations for the identification of water entry in horizontal flow environments. Two Niger Delta case study nd 10 minor moderately geopressured pay bearing sands between 10 000 feet and 19 000 feet sub sea.

amatically enhance the economics of projects. Horizontal wells are placed in the reservoirs precisely to maximize hydrocarbon (oil and gas) ic ion CO2- 3 is released into solution leaving the solution more acidic; therefore more soluble calcium phosphonate solid phases form. T erm production optimization can be performed with simulation models for wellbore flow and near-wellbore reservoir response. The objective

concentrations. Because polymers have been used in different underbalanced foam drilling operations this model will be useful for both aq ate.12-16 Implemented sand control techniques are such as standalone wire wrapped screen in-situ sand consolidation with chemicals co voir into the fracture as opposed to considering only flow along the fracture length.

HO/W) emulsions as a novel sealant in the near wellbore region. The main objective is to eliminate the gas and water leakage from abandon d be producing from only half of the reservoir section if it were completed conventionally. Results of this work have provided enough confide

ernative population balance theory for foam motion in porous media. The principals of this model are as follows: Foam is a complex fluid c eported previously by Nguyen et al. 13 14 and Zitha et al.15 We have used the IMPES method to solve the set of equations provided herein The installation of siphon and velocity strings5 Injection of surfactants to create foams6 Well head compression7 Plunger lift 8 Gas lif

rainage point may be to the left or to the right of the TPC minimum. The system stability is also governed by the pressure drop as is the forc al wells in the South Belridge field Kern County California. Shell introduced LEP completion design in a portion of the South Belridge field mmon data source: API RP-19B Section I test data. The API Subcommittee on Perforating defined the test protocols described in API RP-19

t was decided to include these technologies in the completions. The first well EG-1A was a dual string producer gas lifted using gas from r had been drilled with a deviated wellbore through the H1 H2 targets. �A completion design that consisted of a cased-and–perforated c

design consisting of a cased and perforated commingled completion inside 95/8-in. casing had been implemented. The sandface-completio ging devices the settling tendencies in horizontal flowlines as well as the disposal requirements. The operations in which sand managemen

e of measurement should be reported.

nt years this situation has started to change. Unfortunately one of the consequences of the lack of a dedicated method of analysis is that fa

d to capture experience data. For the Onyx SW well the operator used their KPI system to the fullest in close cooperation and supported by

wet and countercurrent capillary diffusion can take place. The coal is gas-wet and binary diffusion of CO2 and CH4 occurs. Capillary diff

input on key climate change issues. ptimization a single architecture must often support a diverse set of use cases. For example one process might require information for only

t al. (2007). unstable production or increases in gas or water production are typically not detected until the next well test. Historically there have been a is not optimal as many well problems are not detected until a well is re-tested.�Well test conditions may be very different from actual ope hift system many operations staff have worked on the platform from commissioning.

ort that was executed was building the integrated production system models (IPSM's). This is seen as a key requirement for quality decision ormation (VOI) is well known within modern Decision Analysis and has been thoroughly described by Newendorp (1975) and Dunn (1992). wireline formation tests closed system tests and injection tests. In later sections of the paper we will discuss each of these three types o

oach With this vision for the CW field formulated for a 2005 development operator realized that a phased approach of the introduction of s

inverse problems.[10-13]

w up the DP1. As part and parcel of the evolution of this technology a new term “Managed Pressure Drilling (MPD) has taken root and drilling in the offshore envi-ronment3. In the late 1990’s our Research and Development staff also developed and introduced expandab

a complex mixture of surfactants of differing chain lengths and the branched C16 17 alcohol based surfactants because of their randomly b

ts in rapidly declining production rates and a high residual oil saturation due to capillarity. The air injection technique allowed for rapid reser critical for evaluating and implementing a miscible gasflood. In simple terms one of the main advantages of a miscible or near-miscible gas w in heterogeneous porous media. We examine several scenarios concerning the co-injection of liquid (surfactant solution) and gas (N2 CO

this combination of GOGD and localized waterflood. A recent review of production and petrophysical data showed that the fracture spacing water production can be managed either by controlling the injection profile in the injectors (if water is injected) and/or by selectively producin 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 and/or by selectively producing different layers in the producers. In cemented liners perforating is used to connect the well to additional lay turation commonly denoted as S spw . At this saturation however the capillary pressure inside the matrix block coincides with that in the f

d non-smooth features to demonstrate the capabilities of the DGM. We report the results of numerical experiments carried out using four var tion of up-time and production large redundancy of production systems and increased lifecycle costs for remediation and intervention due t 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 uids compositions. Rao and Lee (2002) then extended the VIT technique to an offshore Terra Nova reservoir to determine the injection gas c

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 rger fractions of formation fluid replace the OBM filtrate. An accurate value of the GOR is important for many applications including crude-

sity of the oil. Viscosity of water-in-oil emulsions increases as the water cut increases before the so-called emulsion inversion point beyond

success has enabled us to carefully extend the application of this system to reservoirs previously regarded as non- applicable or HF sensiti

dicted without using a numerical simulator. In this paper several examples will be presented with simulator results that are counter intuitive o

ent plan is to use a full-field dynamic model to determine potential value and to use as input into the final investment decision. However mo ation constant Ka. The study is aimed at using the model to use measured final brine pH (pHf) in “pH change experiments from which w

to avoid deferment or even loss of production. Chemical inhibitor treatments of inorganic scale (carbonate and sulphate) are extensively use very process. Therefore description of sub-critical and critical flows and calculation of maximal allowed flow rates present essential interest

e models were built and cycled with the reservoir simulator. This paper focuses on the fracture characterization and modeling. It exemplifies xities. Addressing this challenge became the primary modeling objective.

) matrix-block temperature." or the CSS process to obtain a good match of historic production and injection data: i) a geomechanical description and ii) relative permeab

of metal ions. In oilfield applications chelating agents (Frenier et al. 2000) are frequently added to acidic stimulation fluids to prevent precip signed to determine which proppant was most cost-effective in wells completed by Shell Rocky Mountain Production. Design of Field Trial

the performance of proppants.[1 2 4 7]�Other studies have incorporated the use of reservoir simulation to remove reservoir properties om 2 to 6 feet in length. Perforating shot density is 3 shots per foot. A 7 inch protection casing is set 600 feet from TD with 4 �’ casin

e porosity (f) as a third parameter."

rn North Sea tight gas fields. Table 1 compares the productivity index (PI) achieved by hydraulic fracturing and horizontal drilling in 3 UK fiel

be the source of the problem. In a bid to improve the well’s productivity and sustain the gas supply commitment a rig re-entry was carri

stages. The result of such a workflow is:

1. a reservoir model that has incorporated all known geological constraints and uncertainties

wavelength. At any time instant the measured OD is a weighted linear combination of the spectra of the undesired OBM filtrate and the des Keefe et al. 2008). DFA tools provide results in real time and at reservoir conditions. Current DFA techniques use absorption spectroscopy o

et for the 3D connectivity workflow as the architectural detail is relatively straightforward and well understood to represent with a parametric depleted sands was accomplished in the Ursa field in the GOM using water-based mud with monomer and resin materials that exhibit large

st simultaneously with powerful implications for decision making and maximizing asset value. mic faults on fracture corridor stick plots from borehole image logs (Figure 4). This will show both the fraction and maximum size of fracture c number is used to infill stochastic fracture corridors and to generate fracture corridor density and permeability maps.

t al 2005a Dong et al 2006 Fujisawa et al 2006). Additionally the differences in absorption spectra between reservoir fluid and oil-base m cy. Basic mud extractors or gas traps are generally positioned in the header tank where an unknown volume of mud gas is trapped in the h mpact on the ultimate recovery. More details of the development plan and cluster risk management can be found in ref [1].

of satellite fields. As a result focus on acquisition interpretation and particularly integration of surveillance data has been variable. The follo

per we consider a situation in which no production data are assumed to be available which rules out any history-matching approach to red ps and formulate clear appraisal strategies. This was built upon the following steps: Seismology: Existing seismic interpretations were inven

nd predictions from Government Agencies of the USA; supply and demand predictions from the EIA (Energy Information Agency 2007) and ose control over the areas where proprietary technology is involved. The approach involves a number of separate lump-sum EPC contracts ng placed in a actualized perspective by resorting to empirical techniques such as core flood tests. Many core flood tests have been under nciples and applications particularly in the Middle East are discussed and supported by field cases Impact of new technology applications o

oard. Since the beginning of the project reservoir souring has been identified as an area of concern in Bonga. Reservoir (e.g. mineralogy expected to exceed 50 ppm (v) in the gas phase but when more data became available it was realised that the reservoir souring may be m of 40 000 m3/day was initiated in 1994 to maintain the pressure in the reservoir. In 2002 significant water production on a continuous basis

ation several approaches have been proposed in the past. These approaches can be classified in different ways (local vs. global; stochasti all aspects of the cluster of reservoirs. The team resolved to come to grips with the uncertainty by defining ranges of parameters and conseq

hydrostatic pressure of 165 bar.� All of the field producers except for A53 are horizontal with completed well lengths ranging from 370 m t between. Gravity ensures that the lighter phase travels at a faster speed than the heavier phase. The difference in velocity between the pha

hinly bedded (single sand thickness is around 5m) 3D labyrinth-type reservoir is affected by extensive faulting with a multitude of throws bel facilities or constraints imposed by reservoir management considerations (e.g. voidage balance constraints). The mathematical optimizat allow remote control. At the time this study was conducted the number of zones was assumed to be limited to four as a result of physical a

parameters to be optimized are usually well-flow rates bottomhole pressures (BHPs) or choke-valve settings. Because these are not mixed paper presents the reservoir simulation modeling component of the ARM project and discusses the various methods and results achieved d and gas production rate and wellbore pressure may constitute the individual components of a production data set. As a direct measure of t engineers. Optimal simulation workflows require conventional assisted history-matching tools to go beyond their core functionality of history y measures of fluid properties such as yield point and shear rates. In the past this has made design and implementation of such fluids some ek et al. 1999). For many field developments under waterflooding fracture propagation is estimated with acceptable error bars using these argely driven by reservoir engineering parameters. It is shown that the degree of induced fracture growth / shrinkage in waterfloods depend

re applied to generate from the field production data the reservoir fractional flow relative permeability end-points mobility ratios and to pre

4 uniformly distribute the grid points in the domain resulting in a coarse uniform Voronoi grid (base grid). Then several local grid systems su meability. A compehensive review of which can be in3-6. fewer details at that larger scale. The need to upscale properties has motivated the development of many different techniques a comprehe

nd Mueller 2004; Roxar FracPerm Reference Manual 2005). The boundary conditions consist of (1) location/geometry of fault surface (2) s a high level of heterogeneity in the reservoir as much as possible (Ates et al. 2003). The main characteristic of this reservoir is the presen Shen 1989; Bech et al. 1991; Bourbiaux et al. 1999). In their 1960 landmark paper Barenblatt et al. introduced the shape factor concept to

eir rate of return on investment and NPV the selection process that follows is quite detailed. It takes into consideration a number of ‘strate

vel of detail is required as for PSO. In addition for Monte Carlo analysis the model can possibly be further simplified without losing the key s of information has made the EnKF an appealing method for sequential model updating.4-10 The capability to maintain ‘live models’ n that parameters from analysis of a long buildup on a reservoir can be used in subsequent buildup tests to shorten the required time of the

roduce an additional 8% of the STOIIP over a period of 28 years if a major secondary recovery project could be put in place. The scouting s

d current computing technology limits us from simulating such multimillion-cell models on practical time scales. This requires a translation o

nd include coupled conservation equations for multiple components (e.g. oil water and gas) an energy equation and a pressure drop relat (Pc) curves both in drainage and imbibition cycles. Mercury injection is frequently used for measuring drainage Pc curves as the technique ces. Understanding these heterogeneities and compartment boundaries is essential for optimizing the field development vis-�-vis differen

Viscosity reduction Distillation Gas drive

ds.�It will be important to maintain water disposal capacity to ensure that water disposal does not restrict oil production. Concern was v rious types of data for predicting inter-well reservoir properties. At the early stage of reservoir exploration well data are usually limited whic ow sound is it what type of reservoirs are better suited for SAGD? Therefore an analysis of the performance of the current operations mus

e was decreased recently. So far the apparent effect is positive though the time frame is too short to have a reliable explanation. Optimal w s this pressure will determine the flowing wellhead pressure of the blowing well. Sonic conditions will not develop at the wellhead and the to ndustry that much of the future lies with the effective management of existing production and the continued development of mature fields.ï¿

ufficient pressure difference between pore pressure and fracture gradient to allow gravel-pack placement.�Devices to lower equivalent c he total gas still to be produced can be labeled as contaminated gas. Obviously these numbers are large enough to attract the attention of . No technical people focusing on stimulation work. to handle large water cuts the waterflood will use relatively few injectors. The proposed base plan has four water injectors: two into Princes

passed oil. The robustness of the approach lies in the integration and use of collaborative evidences from different techniques to come to a

ars field. The flow pattern of the produced water the reservoir sweep the reservoir pressure profile permeability skin damage and fluid sat

s another alternative explanation offered by Pourciau2 although the amount of this reduction (85-90%) is not consistent with laboratory mea wing virtual collaboration between field staff and off-site service- and operating-company experts throughout the operation. This paper inclu sion of the surface-deformation measurements (displacement or tilt) for reservoir parameters (pressure depletion reservoir compaction or

nments. Two Niger Delta case study wells validate the precision of the measurements against the results of the APLT multi-probe multi-spi

maximize hydrocarbon (oil and gas) production. They provide added wellbore exposure to the reservoirs in geometries that allows operators m phosphonate solid phases form. The inhibitor return concentration can be altered by changing the inhibitor concentration in the pill. The a re reservoir response. The objective is to maximize production at a specific moment in time which leads to the use of optimization techniqu

this model will be useful for both aqueous-based and polymer-thickened foam drilling design and operations. The main objectives of this s and consolidation with chemicals conventional gravel pack for cased hole and openhole and Frac-Packing. The optimization of these comp

gas and water leakage from abandoned wells. The process in mind is one where a created emulsion will break near the wellbore or at some work have provided enough confidence to use the same modelling approach in design and operation of future wells with complicated trajec

s follows: Foam is a complex fluid characterized by a yield stress and above the yield stress by power law behavior. Its rheology is describe the set of equations provided hereinafter and obtain water saturation bubble density and water pressure profiles in 1D and 2D. The experi ompression7 Plunger lift 8 Gas lift Work-over to a smaller tubing size etc.� Of these approaches installation of a velocity string i.e

d by the pressure drop as is the force balance across the liquid film. The flow regime change is a separate mechanism and is less determin a portion of the South Belridge field in September 1982 [5]. By Dec. 1984 the LEP technique was used in approximately 400 vertical steam est protocols described in API RP-19B1 to serve a range of purposes.� The Section I test which involves firing a full gun section into a m

producer gas lifted using gas from reservoir BP1. A single trip balanced perforation of three zones followed by a stacked propped-fracture sted of a cased-and–perforated commingled completion inside 9-5/8-in. casing had been implemented. The sand-face completion desig

mplemented. The sandface-completion design consisted of a large-OD expandable sand screen with a 150-�-weave opening across the t perations in which sand management has been adopted have taken a pragmatic view to learn and optimise the facilities design based on ex

edicated method of analysis is that fall-off tests on injectors are generally interpreted in the wrong way even if one realises that they are frac

close cooperation and supported by the corresponding service company systems. The objectives set for the job were clear and concise; ï¿

CO2 and CH4 occurs. Capillary diffusion finds its origin in capillary pressure (Pc ) effects where Pc is defined as the pressure difference be

ss might require information for only the higher levels of the hierarchy while another might require the most detailed information available at

est. Historically there have been a number of approaches using well physical models combined with real time wellhead pressures and tem may be very different from actual operating conditions.� This conventional surveillance and monitoring methodology is premised on the c

key requirement for quality decision making." ewendorp (1975) and Dunn (1992). Simply saying that we need to evaluate VOI to decide how to develop a hydrocarbon resource may sou discuss each of these three types of OVT in some detail but the first step in evaluating the usefulness of any OVT is to understand more fu

sed approach of the introduction of smart well and smart field technologies was the only way to success.

- Phase 1- Introduction of smart

e Drilling (MPD) has taken root and like a tree it has many branches. The International Association of Drilling Contractors (IADC) defines M developed and introduced expandable tubulars to the industry. A global approach to deploy these technologies was initiated in year 2000 wh

actants because of their randomly branched structures.

on technique allowed for rapid reservoir re-pressurisation to provide energy and helped mobilise trapped oil through improved sweep effic es of a miscible or near-miscible gas injection process is the interaction of the injectant with the in-situ fluid. Reservoir simulators require ca urfactant solution) and gas (N2 CO2 etc.) in layered and randomly heterogeneous reservoirs. We show that foam performance i.e. the am

ata showed that the fracture spacing varies significantly both horizontally and vertically. This impacts the GOGD efficiency and recovery fact ected) and/or by selectively producing different layers in the producers. It is essential that the well integrity and cement bond are good to pre to determine if a good cement job has been performed. to connect the well to additional layers. However the reverse process is not as straightforward. Different remedial treatment options are av trix block coincides with that in the fracture and the recovery ceases. Experience has shown that carbonate fields often range from interme

xperiments carried out using four variants of the DGM on these gas lift test problems. Test Problems Unlike other areas of engineering17 th r remediation and intervention due to an increase in the number of blockage incidents.� Offshore developments in the Russian North pre 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 rvoir to determine the injection gas composition required for developing miscibility with the crude oil.

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 many applications including crude-oil typing and production facilities design. Conventionally GOR is measured in a PVT laboratory by flas

d emulsion inversion point beyond which the continuous phase changes to water (i.e. water-in-oil emulsion switches to oil-in-water emulsio

ded as non- applicable or HF sensitive Reservoirs; high risk – low reward or where operators don’t have the confidence to apply such

or results that are counter intuitive or at least show the limitations of generally accepted rules of thumb. Therefore validated simulators are

l investment decision. However modeling is often based on unproved initial assumptions compounded by the lack of UBD well-performanc pH change experiments from which we can back calculate the quantities Kow and Ka. These “pH change experiments are where we all

ate and sulphate) are extensively used worldwide to prevent scale deposition in the near-wellbore area and the tubing of production wells. A flow rates present essential interest for oil industry. Knowledge of these flows is necessary for a proper planning of oil production as well as

ization and modeling. It exemplifies the value of planned multidisciplinary data acquisition and integration combined with utilization of regio

description and ii) relative permeability hysteresis to describe the low water-to-oil ratio during production. A good match will improve the pre

c stimulation fluids to prevent precipitation of solids as the acid spends on the formation. The use of chelating agents is one proposed appro in Production. Design of Field Trial This study compares the production from 446 fracture treatments in 30 new wells completed by Shell b

ation to remove reservoir properties variability from the equation.[3 8]� Still others have used a normalization process for the removal of r 0 feet from TD with 4 �’ casing set from TD to surface. Flow-through composite fracture plugs (Eberhard et al 2003) are used to isol

ng and horizontal drilling in 3 UK fields and shows 2-8 times higher productivity from horizontal wells. The success of the horizontal wells lar

commitment a rig re-entry was carried out to change the suspected faulty Tr-ScSSSV. The TrScSSSV was found not physically damaged w

cal constraints and uncertainties

2. a dynamic model which can accurately predict reservoir performance and provide reliable reserve e

undesired OBM filtrate and the desired formation fluid. Initially the measured spectra are dominated by the OBM filtrate. With increased pu ques use absorption spectroscopy of reservoir fluids in the visible-to-near-infrared (NIR) range. The formation-fluid spectra are obtained in r

stood to represent with a parametric geologically consistent integrated reservoir modeling approach. and resin materials that exhibit larger fracture propagation pressure than do those of oil-based mud (however the fracture opening pressur

tion and maximum size of fracture corridors visible by seismic and the degree of clustering of fracture corridors around fracture fairways. F ability maps.

etween reservoir fluid and oil-base mud (OBM) or water-base mud (WBM) are used to estimate fluid sample contamination with the drilling olume of mud gas is trapped in the headspace chamber and mixed with atmospheric gas (Fig 1). Consequently a standard mud gas extract be found in ref [1].

ce data has been variable. The following section describes how the various data types that are available were re-examined and how an inte

ny history-matching approach to reduce the geological uncertainty. Our study forms part of a larger research project to enable closed-loop m g seismic interpretations were inventorised and QC’d. Obvious problems and inconsistencies were fixed and a first pass estimate of the

ergy Information Agency 2007) and recoverable conventional natural gas resources from the USGS (United States Geological Survey 2000 separate lump-sum EPC contracts for the offshore scope and for most of the onshore scope; while activities in the core GTL area and the ny core flood tests have been undertaken over the past few decades [2] but unfortunately only few sufficiently approximated let alone valid act of new technology applications on gross water production is illustrated. Value of beneficial use of produced water is demonstrated Ov

Bonga. Reservoir (e.g. mineralogy temperature pH and pressure) and fluid characteristics (e.g. composition) were recognized to be favo d that the reservoir souring may be more severe and the final mitigation method included the use of nitrate (Ref. 1). The nitrate injection rate er production on a continuous basis started and in September 2006 50% water cut was reached. The water cut in later field life is expecte

rent ways (local vs. global; stochastic vs. deterministic etc.). An overview of previously proposed methodologies is given here: 1. Mixed inte ng ranges of parameters and consequences of high and low parameter values on production or economic outcome of a development. Some

ed well lengths ranging from 370 m to 395 m.� The Garn West and Rogn South wells are produced through sub-sea installations tied bac ference in velocity between the phases is referred to as slip velocity. This also causes the downhole holdups to be different from the surface

aulting with a multitude of throws below the seismic resolution of ~50 m. The Mulussa F3 formation below the Mulussa F2 has an even lowe raints). The mathematical optimization problem to be solved is to maximize the lifecycle integral by choosing the optimal well control while s mited to four as a result of physical and financial constraints. Currently however the injection wells are planned to be equipped a five-zone s

ettings. Because these are not mixed-integer problems gradient-based methods are used commonly to solve them and the adjoint method ous methods and results achieved during the process of history matching the ARM to the measured production data. This reservoir simulati on data set. As a direct measure of the reservoir response integration of production data to dynamic reservoir models is the primary driver f ond their core functionality of history matching and serve as comprehensive uncertainty management platforms. An integrated platform shou d implementation of such fluids somewhat a “hit or miss proposition. It should be noted that the annulus where the convection occurs is h acceptable error bars using these or similar tools. The major drawbacks are Areal reservoir heterogeneity is not accounted for. Varying p h / shrinkage in waterfloods depends strongly on oil-water mobility ratio and can vary strongly with time because of changing reservoir satur

end-points mobility ratios and to predict the oil recovery in each of the blocks analyzed in this review. It was possible to obtain a reliable un

). Then several local grid systems suitable for specific geological and geometrical feature are constructed independently and placed in the a

ny different techniques a comprehensive reviews of which can be found in Barker and Thibeau6 and Renard and de Marsily7. The upscali

ation/geometry of fault surface (2) stress conditions or displacement conditions on the fault surfaces and (3) the remote loads applied to th eristic of this reservoir is the presence of a complex fracture network within the highly heterogeneous matrix system. Additionally the reserv oduced the shape factor concept to model the (single-phase) fluid transfer between matrix and fractures (1960). The central idea of Barenb

consideration a number of ‘strategic’ parameters which in addition to forecasted initial rate and ultimate recovery include: How m

er simplified without losing the key system interactions. ility to maintain ‘live models’ combined with the ability to assimilate diverse data types and the ease of implementation have resulted s to shorten the required time of the subsequent buildups. Finally estimates for time required for a buildup in homogeneous reservoirs of an

could be put in place. The scouting study indicated that the scale of investment under consideration could be up to 140 new wells 10 new w

scales. This requires a translation of the detailed grids to a coarser computationally manageable level without compromising the gross flow

equation and a pressure drop relationship. Flow from the reservoir into the wellbore (in the case of a production well) provides source term drainage Pc curves as the technique is relatively cheap fast and requires relatively straightforward data interpretation. The measured data eld development vis-�-vis different depletion rates drive mechanism and production optimization. This paper builds upon earlier publishe

strict oil production. Concern was voiced regarding the rate and volume capacities of the Zechstein fractured carbonate in particular as re n well data are usually limited which pose a big challenge of inter-well prediction. Those reservoir properties are then used to compute oil i mance of the current operations must address whether SAGD is the preferred in-situ technology to develop oil sands and under which geolo

ve a reliable explanation. Optimal water injection rates are a subtle balance between voidage induced fracture growth and reservoir hetero t develop at the wellhead and the total system performance will have to be taken into account to obtain an accurate estimate for the blowou nued development of mature fields.�What may not be so clear is how to apply smart technologies to mature fields with a legacy infrastru

nt.�Devices to lower equivalent circulating density to allow the successful packing of longer intervals with tighter pressure spreads are no ge enough to attract the attention of a wide range interested entities from IOCs and NOCs to innovation centers like universities.

four water injectors: two into Princess and two into Ursa. Producing wells will include three Princess subsea wells and four Ursa TLP wells.

m different techniques to come to a conclusion on the location and extent of bypassed oil even in difficult cases where petrophysical fluid in

meability skin damage and fluid saturations will be provided and discussed in detail to highlight the results of the time-lapse monitoring of t

s not consistent with laboratory measurements. Existing sparse data from wells can support any of these scenarios confirming that the prob hout the operation. This paper includes several examples of WFT surveys that were monitored and supervised in real time. The cases pres depletion reservoir compaction or reservoir volume changes) (Dusseault and Rothenburg 2002; Vasco et al. 1998; Fokker 2002; Du and O

ts of the APLT multi-probe multi-spinner production logging tool. The Challenge Skepticism towards attempting to acquire Production Logg

in geometries that allows operators in Niger Delta to maximize hydrocarbon recovery rates and project economics spread out the pressure hibitor concentration in the pill. The ability to control the high inhibitor return may be useful in initial water breakthrough where high inhibitor r s to the use of optimization techniques such as SLP (Handley-Schachler et al. 2000) or sequential quadratic programming (SQP) (Wang et

tions. The main objectives of this study include: (a) measuring the rheological properties of foam with and without polymer (b) creating a m king. The optimization of these completion techniques also has become more important considering the optimum hydrocarbon production w

break near the wellbore or at some pre-determined distance from it in order to provide an effective and stable plug against for instance w f future wells with complicated trajectories and architecture. This modelling approach could also be of value for a more-adequate interpretat

aw behavior. Its rheology is described using the Herchel-Bulkley model. Foam rheology depends essentially on the bubble density. Since o re profiles in 1D and 2D. The experiments used to validate the numerical analysis consist of the co-injection of N2 gas and surfactant soluti s installation of a velocity string i.e. a� small diameter tubing or coiled tubing inside the actual tubing to increase velocity and improve liq

ate mechanism and is less determined by gravity but is more influenced by increased hold up and wave formation. The flow regime change in approximately 400 vertical steam-injection wells. Injection data from LEP wells was in close agreement with the theoretical design maxim lves firing a full gun section into a massive concrete target under ambient conditions was designed as a quality control test and to check fo

wed by a stacked propped-fracture operation prior to installing an expandable sand screen was planned.� The second well EG-1B was ed. The sand-face completion design consisted of a large-OD expandable sand screen with 150 micron weave opening across the 2 zones.

50-�-weave opening across the two zones. Upon completion the reservoirs were cleaned up through a temporary well-cleanup and -test mise the facilities design based on experience. The locations where a sand management philosophy has been adopted typically have moder

even if one realises that they are fractured. Typically such interpretations lead to wellbore storage coefficients that can be up to orders of m

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