The Handbook on Solids Control and Drilling Waste Management
King Cobra Venom Shaker
HS-3400 STD XP Centrifuge
Ideal Mud Tank System
Slider Tank
Vor tex Dr yer
VSM 300 Shaker
VSM Multi-Sizer Separator
Mud Coolers
Air Conveyor
Hot Oil Thermal Desorption
HS-2172L Centrifuge
EnviroVac
Cuttings Injection
Shaker Screens
SpaceSaver VTS
MA-RG Agitator
This document contains proprietary and confidential information which belongs to National Oilwell Varco, L.P., L.P., its affilia tes or subsidiaries (all collectively referred to here in after as “NOV”). It is loaned for limited purposes only and remains the property of NOV. Reprodction, in whole or in part or use of this design or distribution of this information to others is not permi tted without the express wri tten consent of NOV. This document is to be retur ned to NOV upon request and in any event upon completi on of the use for which it was loaned . This document and the informa tion contained and represented herein is the copyrighted proper ty of NOV.
www.nov www .nov.com/Bran .com/Brandt dt www.nov www .nov.com/FluidCo .com/FluidControl ntrol
4310 N Sam Houston Pkwy East Houston, Texas 77032 United States Phone: 713 482 0500 Fax: 713 482 0699
[email protected] [email protected]
© 2012 National Oilwell Varco D391001161-MAN-001 Rev. 07
PREFACE
Solids control equipment removes drilled solids from drilling fluid, reduces waste haul-off and reduces the dilution required to maintain good mud properties. Manufactured by National Oilwell Varco is one of the largest manufacturers of solids control equipment in the world.
This Handbook will cover Brandt Products and the services offered by NOV FluidControl. We hope you will find this Handbook useful in your work.
BACKGROUND
In 2009, National Oilwell Varco purchased Spirit Drilling and Completion Fluids and Spirit Mining and Minerals. This was further complemented by the acquisition of Ambar Drilling Fluids one year later. In mid-2010, the Fluids Business units were combined with Brandt Solids Control/Waste Management Leasing to form NOV FluidControl. NOV FluidControl supplies a combination of drilling fluids, completion fluids, minerals and solids control/waste management services.
Tel: Fax: E-mail:
(713) 482-0500 (713) 482-0695
[email protected] [email protected]
Website: w www.nov.com/FluidControl ww.nov.com/FluidControl www.nov.com/Brandt U
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TABLE TAB LE OF CONTENTS CONTENTS U
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FLUID MANAGEMENT MANA GEMENT TECHNOLOGY ........................................ ................................................................ ................................. ......... 13 1.1 Introduction Introduction ................................................. .......................................................................... ................................................. ................................. ......... 13 1.1.1 Origins of Fluids Management Management Technology Technology ............................................... ................................................. 13 DRILL ING FLUIDS ................................................................ ......................................................................................... .......................................... ................. 14 2.1 Introduction Introduction ................................................. .......................................................................... ................................................. ................................. ......... 14 2.1.1 Functions of a Drilling Fluid............................................... ....................................................................... .......................... 14 2.1.2 Components of a Drilling Fluid ......................... .................................................. .......................................... ................. 17 2.1.3 Relationship Relationship of Fluid Properties Properties ............................................................ ................................................................. ..... 18 2.1.4 Selection of a Drilling Fluid Types of Drilling Fluids ................................... ................................... 23 2.1.5 The Nature of Drilled Solids Common Terminology .......................... ................................... ......... 27 ECONOMICS................................................. ......................................................................... ................................................. .......................................... ................. 30 3.1 Benefits of Solids Removal by Mechanical Mechanical Separation Separation ......................................... ......................................... 30 3.1.1 Reduced Total Solids ............................... ........................................................ ................................................. .......................... 30 SEPARATION SEPAR ATION B ASICS ......................................... .................................................................. ................................................. ................................. ......... 33 4.1.1 Particle Size and Equipment Equipment Used to Measure.......................................... .......................................... 35 4.2 Separation Separation by Settling ...................................................... .............................................................................. ..................................... ............. 37 4.2.1 Stokes’ Law.......................................... ................................................................... ................................................. ............................. .....38 4.3 Separation Separation by Size ........................................................... ................................................................................... ..................................... ............. 39 4.3.1 Separation by Filtration ............................................. ..................................................................... ................................. ......... 39 4.3.2 Separation by Screening Screening ....................................... ............................................................... ..................................... ............. 43 4.3.3 API Screen Screen Designation Designation ................................................ ........................................................................ ............................. ..... 43 4.3.4 Screening Surfaces.................................. ........................................................... ................................................. .......................... 45 GUMBO SEPARATORS SEPAR ATORS ............................................... ........................................................................ ................................................. .......................... 51 SHAL E SHAK ERS .................................................... ............................................................................. ................................................. ............................. ..... 52 6.1 Introduction Introduction ................................................. .......................................................................... ................................................. ................................. ......... 52 Rig Shakers ............................................... ....................................................................... ................................................. .............................................. ..................... 54 Fine Screen Shakers ............................................................. ...................................................................................... .......................................... ................. 57 6.1.1 Screen Tensioning Tensioning Mechanisms ....................................... ............................................................... .......................... 59 6.1.2 Vibrator Mechanisms Mechanisms ................................................ ........................................................................ ................................. ......... 59 6.1.3 Maintenance Maintenance ................................................ ......................................................................... .............................................. .....................59 6.1.4 General Guidelines Guidelines ............................................... ....................................................................... ..................................... ............. 60 6.2 Shale Shaker Product Line and Options .......................................... ............................................................... ..................... 60 6.2.1 Optional Upgrade Kit for Linear Motion Shakers........................................ ........................................ 60 6.2.2 Mini Cobra 2-Panel ....................................................... ............................................................................... ............................. ..... 61 6.2.3 Mini Cobra 3-Panel ....................................................... ............................................................................... ............................. ..... 62 6.2.4 Cobra ............................................... ........................................................................ ................................................. ................................. ......... 62 6.2.5 King Cobra ................................................................ ........................................................................................ ................................. ......... 63 6.2.6 King Cobra II .................................................... ............................................................................. .......................................... ................. 64 6.2.7 King Cobra Venom................................................ ........................................................................ ..................................... ............. 65 3
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6.2.8 VSM 300 Shale Shaker................................................. ......................................................................... ............................. ..... 66 Features ................................................. .......................................................................... ................................................. ..................................... ............. 68 Benefits .............................................. ...................................................................... ................................................. .......................................... ................. 68 Balanced elliptical motion ............................ ..................................................... ................................................. ................................. ......... 68 Effective removal of sticky, sticky, hydrated clays............................................... ............................................................ ............. 68 Adjustable Adjustable G-force G-force ...................................... ............................................................... ................................................. ................................. ......... 68 Adjustments Adjustments in G-force G-force to adapt adapt to changes changes in drilling conditions conditions ......................... ......................... 68 Integrated Integrated scalping deck (3 screens) ............................................................... .................................................................... ..... 68 Reduces the need for (and subsequent costs and weight) upstream scalping shakers and/or gumbo equipment................................................ ........................................................................ .......................... 68 Integrated Integrated drying deck (2 screens optional) .......................................................... .......................................................... 68 Reduces mud losses by creating a dry solids discharge ....................................... 68 Pneumoseal Pneumoseal clamping system.............................................. ...................................................................... ................................. ......... 68 Screens are properly secured to the basket b asket for quick, easy screen changes........ 68 Variable frequenc f requency y drive (VFD) control .................................................... ................................................................. ............. 68 Soft starting, fingertip adjustments of motor speed and matching G-force to operating conditions................................................................. ......................................................................................... ............................. .....68 6.2.9 NOV Automated Automated Shaker Control ............................... ....................................................... ................................. ......... 68 6.2.10 VSM Multi-Sizer Multi-Sizer .................................................. .......................................................................... ..................................... ............. 70 6.2.11 Cascade Shakers................................... ............................................................ ................................................. .......................... 73 LCM-3D/CM-2 Cascade ........................................................... ................................................................................... ............................. .....73 6.2.12 LCM-3D/King Cobra Cascade................................................. .................................................................. ................. 73 GAS CONTROL ................................................ ......................................................................... ................................................. ..................................... ............. 74 7.1 Introduction Introduction ................................................. .......................................................................... ................................................. ................................. ......... 74 7.2 Mud Gas Separator Separator ..................................................... .............................................................................. .......................................... ................. 74 7.2.1 Mud Gas Separator Separator Operational Operational Guidelines Guidelines .............................................. .............................................. 75 7.3 Atmospheric Atmospheric Degasser Degasser ................................................ ......................................................................... .......................................... ................. 75 Installation Installation ............................................... ........................................................................ ................................................. ..................................... ............. 75 7.4 Vacuum Degassers Degassers...................................................................... .............................................................................................. ..........................76 7.4.1 Installation Installation ................................................ ......................................................................... ................................................. .......................... 77 7.4.2 Maintenance Maintenance ................................................ ......................................................................... .............................................. .....................77 7.5 Degasser Product Line ............................ ..................................................... ................................................. ..................................... ............. 78 HYDROCYCLONES .............................................. ....................................................................... ................................................. ................................. ......... 79 8.1 Introduction Introduction ................................................. .......................................................................... ................................................. ................................. ......... 79 8.2 Operation Operation ................................................ ......................................................................... ................................................. ..................................... ............. 82 Cut Point ................................................. .......................................................................... ................................................. ..................................... ............. 82 Rope versus Spray Discharge.............................................. ...................................................................... ................................. ......... 83 8.3 Desanders Desanders ............................................... ........................................................................ ................................................. ..................................... ............. 84 8.3.1 Installation Installation ................................................ ......................................................................... ................................................. .......................... 84 8.3.2 Guidelines ................................................ ......................................................................... ................................................. .......................... 85 8.3.3 Maintenance Maintenance ................................................ ......................................................................... .............................................. .....................85 8.4 Desilters .............................................. ...................................................................... ................................................. .......................................... ................. 86 4
8.4.1 Installation .................................................................................................. 87 8.4.2 Guidelines .................................................................................................. 87 8.4.3 Maintenance ..............................................................................................88 9 MUD CLEANERS AND CONDITIONERS ....................................................................... 89 9.1 Introduction ........................................................................................................... 89 9.1.1 Applications................................................................................................ 91 9.1.2 Installation .................................................................................................. 92 9.1.3 General Guidelines .................................................................................... 93 9.1.4 Maintenance ..............................................................................................94 9.1.5 Mud Conditioner Product Line.................................................................... 95 10 CENTRIFUGES ............................................................................................................... 96 10.1 Decanting Centrifuge ............................................................................................ 96 10.1.1 Separation Process..................................................................................96 10.1.2 Dewatering............................................................................................. 100 10.2 CENTRIFUGE MODELS (S EE APPENDIX I - CENTRIFUGE CHART ) ........................ 101 10.2.1 HS-3400 Centrifuge ............................................................................... 101 10.2.2 HS-2000 Centrifuge ............................................................................... 102 10.2.3 HS-1960 Centrifuge ............................................................................... 102 10.2.4 HS-2172................................................................................................. 103 10.3 Drying Centrifuges .............................................................................................. 105 10.3.1 Vortex Dryer...........................................................................................107 10.3.2 Mud 8 and 10 ......................................................................................... 107 11 CENTRIFUGAL PUMPS ............................................................................................... 108 11.1 Introduction ......................................................................................................... 108 11.2 Understanding Pump Performance Curves......................................................... 108 11.3 How to Select a Pump......................................................................................... 109 11.3.1 Pump Speed .......................................................................................... 109 11.3.2 Total Head Required .............................................................................. 109 11.3.3 Flow Rate ...............................................................................................109 11.3.4 Specific Gravity ...................................................................................... 109 11.3.5 Procedure for Selecting the Pump Impeller Size and Horsepower Requirements ...................................................................................................... 109 11.4 Net Positive Suction Head (npsh) ....................................................................... 110 11.5 Formulas ............................................................................................................. 110 11.6 Details to Remember about Centrifugal Pumps .................................................. 111 CONVERT FROM .................................................................................................................... 111 CONVERT TO..........................................................................................................................111 MULIPL Y BY............................................................................................................................ 111 12 MUD MIXING – AGITATORS AND MUD GUNS ........................................................... 112 12.1 Introduction ......................................................................................................... 112 12.2 Mechanical Agitators...........................................................................................112 12.2.1 Selection of Agitator Size and Quantity .................................................. 112 5
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12.3 Mud guns ............................................................................................................ 117 12.4 Sand Traps.......................................................................................................... 117 12.5 Tank/Pit Use........................................................................................................118 12.5.1 Removal................................................................................................. 118 12.5.2 Addition .................................................................................................. 118 12.5.3 Reserve.................................................................................................. 121 12.5.4 Discharge ............................................................................................... 121 12.5.5 Trip Tank................................................................................................121 12.6 Auxiliary Equipment ............................................................................................ 121 12.7 Agitation/Mixing . ................................................................................................ 122 MUD TANK SYSTEMS.................................................................................................. 123 WASTE MANAGEMENT ............................................................................................... 125 14.1 Cuttings Storage ................................................................................................. 125 14.1.1 Brandt Transfer System (BTS) ............................................................... 126 14.1.2 Catch Tanks/Shale Sloops ..................................................................... 127 14.1.3 Cuttings Boxes/Skips ............................................................................. 127 14.1.4 FreeFlow Slider Tank ............................................................................. 128 14.2 Cuttings Transfer.................................................................................................129 14.2.1 Brandt FreeFlow System........................................................................ 129 14.2.2 Screw Conveyors ...................................................................................133 14.2.3 Vacuum Units.........................................................................................134 14.3 Cuttings Treatment and Disposal ........................................................................ 135 14.3.1 Cuttings Injection (CI) (Note: Some call this Cuttings Re-Injection) ..... 135 14.3.2 Bioremediation ....................................................................................... 142 14.3.3 Drying Shakers ...................................................................................... 143 14.3.4 Dewatering. ............................................................................................ 145 14.3.5 Thermal Desorption................................................................................151 14.3.6 Waste Management Services ................................................................ 157 BUL K STORAGE AND HANDLING ............................................................................. 159 MUD CONDITIONING EQUIPMENT ............................................................................. 159 INSTRUMENTATION .................................................................................................... 159 17.1 Introduction ......................................................................................................... 159 17.2 Programmable Logic Controller (PLC) ................................................................ 159 17.3 Variable Frequency Drive (VFD) ......................................................................... 160 PRODUCT LISTING ...................................................................................................... 160 18.1 Gumbo Removal ................................................................................................. 160 18.2 Mud Gas Separator ............................................................................................. 160 18.3 Shaker Header....................................................................................................160 18.4 Rig Shakers.........................................................................................................160 18.5 Primary Shakers..................................................................................................160 18.6 Cascade Shakers................................................................................................160 18.7 Shaker Screens................................................................................................... 160 6
18.8 18.9 18.10 18.11 18.12 18.13 18.14 18.15 18.16 18.17
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Mud Cleaners......................................................................................................161 Mud Conditioners ................................................................................................ 161 Degassers ......................................................................................................... 161 Desanders ......................................................................................................... 161 Desilters ............................................................................................................ 161 Centrifuges ........................................................................................................ 161 Drying Shakers.................................................................................................. 161 Centrifugal Dryers.............................................................................................. 161 Dewatering Units ............................................................................................... 161 W ASTE M ANAGE MENT ......................................................................................... 162 18.17.1 Cutting Transport ................................................................................. 162 18.17.2 Cuttings Storage .................................................................................. 162 18.17.3 Cuttings Treatment...............................................................................162 18.18 Mud Tanks.........................................................................................................162 18.19 Agitators ............................................................................................................ 162 18.20 Mud Mixing Equipment ...................................................................................... 163 18.21 Auxiliary Equipment........................................................................................... 163 APPENDICES ............................................................................................................... 165 19.1 Appendix A - Pre-Well System Selection Checklist ............................................. 165 19.1.1 Well Design ............................................................................................ 165 19.1.2 Drilling Program ..................................................................................... 165 19.1.3 Equipment and Vendor Capability.......................................................... 165 19.1.4 Logistics ................................................................................................. 165 19.1.5 Environmental Issues.............................................................................165 19.1.6 Economics .............................................................................................165 19.2 Appendix B – Mud Engineering 19.2.1 ............................................................ 166 19.2.3 Recommended Range of Properties for Dispersed Mud System ............. 167 19.2.4 Water-Based Mud PV & YP Values @ 120 °F. ....................................... 168 19.2.5 Recommended Range of Properties for Non-Dispersed Mud System . 169 19.2.6 Recommended Range of Properties for Non-Aqueous Mud Systems .... 170 19.3 Appendix C - Standard Mud Calculations ............................................................. 170 19.3.1 Mud Volume ............................................................................................ 170 19.3.2 Circulation Data....................................................................................... 171 19.3.3 Solids Determination ............................................................................... 171 19.4 Appendix D - Solids Control Evaluation Calculations............................................ 172 19.5 Appendix E - Field Calculations of Solids Discharges .......................................... 174 19.5.1 Field Calculations to Determine Total Solids Discharge ........................... 174 19.6 Appendix F - Solids Control Performance Evaluation ............................................ 175 19.7 Appendix G - Conversion Constants and General Information .............................. 179 19.7.1 Conversion Constants .............................................................................. 179 19.7.2 pH of Mud Additives in 10% Water Solution............................................ 180 19.7.3 Specific Gravity and Mohs Hardness of Common Mud Components ...... 181 7
19.7.4 Pounds of Drill Solids Generated per Hole Size ...................................... 182 19.7.5 Percent Solids versus Mud Weight for Water-Based Muds ..................... 183 19.7.6 Base Exchange Capacities of Clay Minerals* ......................................... 183 19.8 Appendix H - G-Force Derivation .......................................................................... 184 19.9 Appendix I - Centrifuge Charts 19.9.1 US Units ......................................... 185 19.9.2 Metric Units ............................................................................................. 186 19.10.1 Flow Rate Data for HS-3400 .................................................................. 187 19.10.2 PSA of Centrifuge Feed Sample ........................................................... 188 19.10.3 PSA of Centrifuge Effluent Sample ........................................................ 189 19.11 Appendix K - Shale Shaker Product Line ............................................................. 190 19.12 Appendix L - Screen Tables for Brandt Shakers .................................................. 192 19.12.1 BHX Cobra/LCM 3D .............................................................................. 192 19.12.2 VSM 100 ................................................................................................ 193 19.12.3 VSM 300 ............................................................................................... 194 19.12.4 Venom Series........................................................................................ 195 19.13 Appendix M - Sieve Comparison Table............................................................... 196 19.14 Appendix N - Mud Weight Conversion Table ....................................................... 197 19.15 Appendix O - Glossary......................................................................................... 198 19.16 Appendix P - Well Site Services .......................................................................... 224 Company Profile.................................................................................................. 224
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TABLE OF CONTENTS FOR FIGURES
Figure 2-1. Pressurized Mud Balance ....................................................................................... 17 Figure 2-2. Basic Mud Balance...………………………………………………………………….….18 Figure 2-3. Marsh Funnel and Cups .......................................................................................... 19 Figure 2-4. Rotational Viscometer ............................................................................................. 20 Figure 2-5. Filter Presses .......................................................................................................... 21 Figure 2-6. Retorts .................................................................................................................... 21 Figure 2-7. Sand Content Sets .................................................................................................. 22 Figure 2-8. Mechanical Degradation of Drilled Solids ................................................................ 28 Figure 2-9. Surface Area Issues . ............................................................................................... 29 Figure 2-10. Effect of Specific Surface Area on Viscosity ......................................................... 29 Figure 4-1. Particle Diameter and Sequential Solids Removal .................................................. 36 Figure 4-2. Settling Pit ............................................................................................................... 37 Figure 4-3. Stokes’ Law ............................................................................................................. 38 Figure 4-4. Vertical Pressure Leaf Filter .................................................................................... 40 Figure 4-5. Filter Press .............................................................................................................. 41 Figure 4-6. Duplex Filter ........................................................................................................... 42 Figure 4-7. Screen Label ........................................................................................................... 43 Figure 4-8. Pretensioned Screen . .............................................................................................. 46 Figure 4-9. 8-Mesh Screen ........................................................................................................ 46 Figure 4-10. Two 8-Mesh Screens ............................................................................................ 47 Figure 4-11. Shape of Opening ................................................................................................. 48 Figure 5-1. Gumbo Separator .................................................................................................... 51 Figure 5-2. 1” Chain .................................................................................................................. 51 Figure 5-3. 6 Mesh Chain/Screen .............................................................................................. 51 Figure 6-1. Shakers ................................................................................................................... 52 Figure 6-2. Elliptical Unbalanced Motion ................................................................................... 53 Figure 6-3. Circular Motion ........................................................................................................ 53 Figure 6-4. Linear Motion .......................................................................................................... 53 Figure 6-5. Standard Rig Shaker ............................................................................................... 54 Figure 6-6. Screens Used on Rig Shakers ................................................................................ 55 Figure 6-7. Reading a Particle Size Analysis (PSA) Graph ....................................................... 56 Figure 6-8. King Cobra and VSM Shakers ................................................................................ 57 Figure 6-9. Screens Used on Fine Screen Shakers .................................................................. 57 Figure 6-10. Screens and Orientation ....................................................................................... 58 Figure 6-11. Mini Cobra 2-Panel ............................................................................................... 61 Figure 6-12. Mini Cobra 3-Panel ............................................................................................... 62 Figure 6-13. Cobra .................................................................................................................... 62 Figure 6-14. King Cobra ............................................................................................................ 63 Figure 6-15. King Cobra II ......................................................................................................... 64 Figure 6-16. King Cobra Venom . ............................................................................................... 65 Figure 6-17. VSM 300 ............................................................................................................... 66 Figure 6-18. VSM Multiple Units . ............................................................................................... 67 Figure 6-19. VSM Fitted with Vent Hoods ................................................................................. 67 Figure 6-20. VSM Multi-Sizer ………………………………………………………………………...70 Figure 6-21. Constant-G Control…………………………………………………………………..…72 Figure 6-21. LCM-3D/CM-2 Cascade ........................................................................................ 73 Figure 6-22. LCM-3D/King Cobra Cascade ............................................................................... 73 Figure 7-1. Mud Gas Separator . ................................................................................................ 74 Figure 7-2. Atmospheric Degasser ............................................................................................ 75 U
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Figure 7-3. DG-10 (Vertical Degasser) ...................................................................................... 76 Figure 7-4. VG-1 (Horizontal Degasser) .................................................................................... 76 Figure 7-5 Venturi that Pulls Mud into Degasser ....................................................................... 76 Figure 7-6. Typical Degasser Rig-Up ........................................................................................ 77 Figure 8-1. Hydrocyclone Diagram ............................................................................................ 79 Figure 8-2. Pressure Changes with Mud Weight ....................................................................... 80 Figure 8-3. Pressure Gauge on the Manifold ............................................................................ 81 Figure 8-4. Cones in Spray Discharge ...................................................................................... 82 Figure 8-5. A Few Cones in Spray Discharge ........................................................................... 83 Figure 8-6. Rope Discharge (Plugged Flow) ............................................................................. 83 Figure 8-7. Desander ................................................................................................................ 84 Figure 8-8. Desilter .................................................................................................................... 86 Figure 8-9. Desilter Using Radial Feed ..................................................................................... 86 Figure 8-10. Typical Rig Layout for Cyclones ............................................................................ 88 Figure 9-1. The Original Mud Cleaner ....................................................................................... 89 Figure 9-2. Mud Conditioner . ..................................................................................................... 89 Figure 9-3. Screens Used on Mud Cleaner/Conditioner ............................................................ 90 Figure 10-1. Decanting Centrifuge ............................................................................................ 96 Figure 10-2. G-Force Algorithm . ................................................................................................ 96 Figure 10-3. Weighted Water-Base Mud ................................................................................... 97 Figure 10-4. Unweighted Water-Base Mud ............................................................................... 98 Figure 10-5. Weighted Non-Aqueous Mud ................................................................................ 99 Figure 10-6. Dewatering Water-Based Mud: Dewatering and Clarification Process ................ 100 Figure 10-7. HS-3400 Centrifuge ............................................................................................ 101 Figure 10-9. HS-2000 Centrifuge ............................................................................................ 102 Figure 10-10. HS-1960 Centrifuge .......................................................................................... 103 Figure 10-11. HS-2172 Centrifuge .......................................................................................... 104 Figure 10-12. Vortex Dryer ...................................................................................................... 105 Figure 10-13. Vortex Dryer Flow Process ............................................................................... 105 Figure 10-14. Mud 10 .............................................................................................................. 106 Figure 11-1. Specific Gravity Formula ..................................................................................... 108 Figure 12-1. Mechanical Agitator . ............................................................................................ 112 Figure 12-2. Mud Gun ............................................................................................................. 117 Figure 12-3. API Drawing showing Sand Trap ........................................................................ 117 Figure 12-4. TurboShear Unit .................................................................................................. 119 Figure 12-5. High Pressure Shear Unit (HP Shear Unit) ......................................................... 120 Figure 12-6. Agitator Blade Types and Flow Schemes ........................................................... 121 Figure 13-1. Rapid Mud Tank System ..................................................................................... 124 Figure 13-2. Ideal Mud Tank System ...................................................................................... 124 Figure 14-1. Brandt Transfer System (BTS) ............................................................................ 126 Figure 14-2. The BTS can safely Transport Waste Slurry to Trucks. ...................................... 121 Figure 14-3. Shale Sloop ....................................................................................................... 1127 Figure 14-4. Skip and Cuttings Box ......................................................................................... 122 Figure 14-5. Stackable Containers .......................................................................................... 122 Figure 14-6. Skip Turner ......................................................................................................... 123 Figure 14-7. FreeFlow Slider Tank .......................................................................................... 124 Figure 14-8. FreeFlow Air Conveyor ....................................................................................... 125 Figure 14-9. Slider Tanks Arranged on Boat ........................................................................... 125 Figure 14-10. Slider Tank ........................................................................................................ 126 Figure 14-11. Slider Tank Cut-Away ....................................................................................... 132 U
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Figure 14-12. Installation of Slider Tanks ............................................................................... 127 Figure 14-13. Screw Conveyors .............................................................................................. 133 Figure 14-14. Vacuum Transfer System (VTS) ....................................................................... 128 Figure 14-15. Cuttings Injection (CI) Unit ................................................................................ 135 Figure 14-16. Typical Offshore CI Installation ......................................................................... 139 Figure 14-17. Cuttings Injection Options ................................................................................. 136 Figure 14-18. Drying Shakers ................................................................................................. 143 Figure 14-19. Dewatering Diagram for Water-Base Muds ....................................................... 148 Figure 14-20. Brandt Dewatering Unit ..................................................................................... 142 Figure 14-21. Typical Dewatering Field Operation .................................................................. 148 Figure 14-22. Indirect Thermal Desorption Unit - THOR ......................................................... 151 Figure 14-23. Hot Oil Thermal Desorption Unit ....................................................................... 151 Figure 14-24. THOR System ................................................................................................... 153 Figure 14-25. THOR System Processing Capacity ................................................................. 157 Figure 14-26. Typical Cleaning Equipment ............................................................................. 158 U
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T ABLES U
Table 2-1 Visualizing Ranges of Common Fluids in Centipoises………………………………….19 Table 2-1 Micron Size Range of Common Materials……………………………………………… 27 Table 2-2 Common Field Terminology of Particle Size............................................................. 28 Table 3-1 Mud Dilution Chart …………………………………………………………………………31 Table 4-1 Vertical Pressure Leaf Filter …………………………………...............................40 Table 4-2 Filter Press - Features and Benefits……………………………………………………..41 Table 4-3 Duplex Filter - Features and Benefits ……………………………………………………42 Table 4-4 API RP 13 C Screen Designation………………………………………………………..44 Table 6-1 King Cobra Shaker with Optional VFD Controller ……………………………………...60 Table 6-2 Features & Benefits King Cobra Venom ……………………………………………..65 Table 6-3 Features & Benefits VSM 300…………………………………………………………..68 Table 6-4 Features & Benefits VSM Multi-Sizer…………………………………………………..71 Table 7-1 Degasser Product Line……………………………………………………………………78 Table 8-1 Pressure Changes as Mud Weight Changes…………………………………………..80 Table 8-2 Hydrocyclone Capacities (@ 75 feet of head)………………………………………….81 Table 8-3 Typical Cut Point Ranges for Various Sized Cones……………………………………82 Table 10-1 Mud Conditioner Product Line…………………………………………………………..95 Table 10-2 HS-1960 Features and Benefits………………………………………………………...96 Table 10-3 HS-2172 - Features and Benefits……………………………………………………..103 Table 11-1 Conversion Factors Used with Centrifuge Pumps……………………………….…111 Table 12-1 Agitator Selection……………………………………………………………………….112 Table 12-2 Hopper Flow Rate for 6" NOV Mud Hopper………………………………………….118 Table 13-1 Mud Tank Systems — Features and Benefits……………………………………….118 Table14-1 CI System………………………………………………………………………………...141 Table 14-2 Dewatering Chemicals for Drilling Fluids (Kemira) …………………………………. 150 Table 14-3 THOR System — Weights and Dimensions……………………………………….….156 U
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1
FLUID MANAGEMENT TECHNOLOGY 1.1 Introduction Fluid management technology is the application of scientific knowledge, engineering principles, and operational experience to the design, formulation, treatment, and disposal of drilling fluids. It requires combining the principles of geology, chemistry, and physics to achieve planned results to fluids-related problems. This technical focus on drilling fluids properties and how to best control them has been the basis for the development of an entire segment of the oilwell drilling industry. 1.1.1 Origins of Fluids Management Technolo gy Since the recorded beginnings of rotary drilling techniques, some form of drilling “mud” has been used. In approximately the mid -1920’s the industry began to understand the importance of drilling fluids and their specific properties. Early drilling fluids were simple mixtures of native clays and water designed to help seal permeable formations. In 1926, the first patent for the use of heavy minerals to increase mud weight to control sub-surface pressure was issued. Higher mud weights required greater viscosity and Wyoming bentonite became the preferred agent to increase fluid viscosity. Since that time, drilling fluids have become more complex and expensive. A sophisticated, synthetic based mud may cost 100 times more than a simple water-based fluid. As drilling fluids become more complex, an engineered approach to fluid formulation and proper treatment to maintain specific fluid properties is required. Mud treatment falls into one of two categories – addition of commercial materials and removal of undesirable contaminants. Each will be covered in detail in this handbook. While it is outside the scope of this book to provide a detailed history of drilling fluids and solids control innovations, we should mention the driving forces that propel today’s technological advancement. These are: Higher drilling efficiency • Lower project cost • • Reduced environmental impact These drivers form the basis for fluids management technology. Today, the environmental impact of drilling operations is very important. This has led to the increased use of “closed loop” mud systems to maintain greater control on liquid and solids discharges on land locations and offshore operations. More and more rigs have to meet “zero discharge” regulations where liquid and solid wastes must be completely controlled and monitored. Solids control and waste management are important now and will continue to grow in importance in the future. NOV will continue to work with customers to keep the environment safe for this generation and future generations. NOV has provided the equipment required to meet these objectives and will continue to develop improved equipment that will further reduce the negative environmental effects of drilling.
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2
DRILLING FLUIDS 2.1
Introduction
Mud is the common name for drilling fluid. While it is outside the scope of this handbook to offer a detailed discussion of drilling fluids, a brief outline of the general characteristics of drilling fluids is included to establish the basic relationships between drilling mud and solids control. Similarly, any discussion of solids control would be incomplete without establishing an understanding of the nature of mud solids — their size, shape and composition.
2.1.1 Functions of a Drilling Fluid
The mud system in a drilling operation performs many important functions. These include: Cleaning beneath the bit • • Carrying drilled solids from the bottom of the hole to the surface Suspending cuttings when circulation is stopped • • Allowing removal of cuttings by the surface system Controlling formation pressures • Promoting borehole stability • Cooling the bit and lubricating the drill string • Helping support the weight of the drill string • Allowing accurate information to be obtained from the well • Minimizing environmental impact • Cleaning beneath the bit
To maximize drilling efficiency, the drilling fluid must utilize the hydraulic horsepower from the main mud pumps to sweep cuttings from the bottom of the hole as soon as they are dislodged and allow the cutters to continue to be in contact with the formation. If the cuttings are not removed, they will be ground into smaller particles and adversely affect drilling rate, mud properties, and project costs. Carrying drilled solids from the bottom of the hole to the surface
Once cuttings are removed from beneath the bit, the fluid must transport them toward the surface. Factors which influence cuttings movement are annular velocity, cuttings size and shape, and the fluid properties. Suspending cuttings when circulation is stopped
Circulation of the drilling fluid is routinely interrupted to add additional drill pipe, change bits, log, etc. The drilling fluids must be able to suspend cuttings and weighting material while circulation is stopped, but should begin to flow easily when circulation is resumed. Properties which affect cuttings suspension are the density, viscosity and gel strength of the mud, and the density of the solids in the mud.
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Allowing removal of cuttings by the surface system
Once the mud circulates back to the surface, it is desirable to remove as many of the cuttings as possible. Usually, this is accomplished with mechanical solids control equipment, such as shale shakers, hydrocyclones and centrifuges. The drilling fluid should be formulated to maximize the efficiency of the removal equipment. Controlling formation pressures
The column of mud in the wellbore must provide enough hydrostatic pressure to balance formation pressures. The hydrostatic pressure (the pressure while the fluid is not being circulated) at any point in the wellbore depends on the depth and the density of the drilling mud. The formula used to determine the hydrostatic pressure is: P = 0.052 x D X ρ Where: P = pressure, in psi D = depth, in feet ρ = mud weight, in lbs. per gallon
Consideration must be given to how the circulation of the drilling fluid affects the pressure in the wellbore. The flow of fluid through the annulus exerts additional pressure. The total pressure at any point in the wellbore is the sum of the hydrostatic pressure and the pressure required to maintain circulation at that point. This total pressure is often expressed as ECD, the Equivalent Circulating Density. This is the drilling fluid density that would be required to produce the same pressure under static conditions (while there is no fluid movement). ECD is calculated as follows: ECD = {(Σ Pa) / (0.052)(TVD)} + ρ Where: ECD = equivalent circulation density, lb/gal, ppg Σ Pa = sum of friction loss in all annular intervals, psi
TVD = true vertical depth (or height), ft ρ = fluid density, ppg
15
Since this is a solids control equipment handbook, a few short cuts will be taken in order to show the importance of mud weight. An example problem will show how the real mud weight is affected by the actual pumping of the fluid, as the fluid comes up the annulus. For example; (This manual will not delve into the calculation of the additional pressure required to circulate the fluid through the annulus, except to note that each interval of different diameters must be considered separately.) Given the following TVD = 9,600 FT ρ = 15.3 ppg Total frictional pressure loss in the annulus = 90 psi The ECD can be calculated for the well geometry and for the mud weight of 15.3 ppg. ECD = [(90)/(0.052)(9600)] + 15.3 ppg = ECD = 0.18 ppg + 15.3 ppg = ECD = 15.48 pp g ECD and surge and swab pressures during trips are very sensitive to the fluid properties of the drilling fluid. As viscosity increases, ECD and surge and swab pressures increase. Increases in viscosity are caused by chemical imbalances or solids control problems; either an increase in solids content, or an increase in the concentration of colloidal particles. Also, higher viscosities increase the frictional pressure loss within the drill string, reducing the hydraulic horsepower available at the bit. U
Promoting borehole stability
Many formations become unstable when exposed to freshwater-based fluids. Inhibitive fluids such as those based on saltwater, natural or synthetic oils, or those containing polymers, are often required to drill them. Cooling the bit and lubricating the drill string
Downhole temperatures can exceed 400°F (204°C). The contact of the bit with the bottom of the hole and of the rotating drill string with the hole and casing generate additional heat. The drilling fluid lubricates and cools the points of contact, extending the life of the bit and drill string. Helping support the weight of the drill string
The fluid in the wellbore exerts a buoyant force on the drill string, reducing the effective weight that must be suspended from the derrick and handled by the hoisting system. Allowing accurate information to be obtained from the well
The drilling fluid must permit electric logging and not interfere with the analysis of drilled samples.
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Minimizing environmental impact
Both the fluid itself and the cuttings generated from the well must be dealt with when drilling is completed. The Cuttings may be contaminated with oil or other chemicals and have to be treated before they can be disposed of. The base fluid also may be considered a pollutant. Some disposal alternatives are: recycling for future use, cuttings re-injection, thermal desorption and stabilization. Of the 10 functions listed, the following are generally considered most important: 1. The removal of cuttings from the bottom of the hole and carrying them to the surface. 2. The control of subsurface pressures. The pressure provided by the fluid must exceed formation pressure to prevent the flow of formation fluids into the wellbore. 3. Stabilization of the wellbore. Fluid density, filtration rates, and filter cake characteristics affect wellbore stability. 4. The cooling and lubrication of the drill string. 5. Environmental protection. Increasing emphasis on the reduction of drilling waste volume greatly reduces the cost of the measures required to avoid polluting the environment. This is not to say that the other functions are unimportant. The relative importance of all of the functions of drilling fluids depends upon the specific circumstances of each drilling operation. 2.1.2 Components of a Drilling Fluid Almost all wells are drilled with a liquid drilling fluid. These fluids range from fresh water to exotic and costly synthetic-based fluids. Although they may be very different, they all have a liquid phase in which solids, and sometimes another liquid, are dispersed.
The liquid phase of the mud is the continuous phase, the part that allows the mud to flow freely throughout the circulating system. The liquid phase may be water, oil (diesel or mineral), a synthetic base fluid, or a combination of these. The solid p hase is the discrete phase of the mud; it is dispersed in the continuous phase. Mud solids may be classified by source (commercial or drilled), reactivity (reactive or nonreactive), size (listed later in this chapter), or density (high or low gravity).
Figure 2-1. Pressurized Mud Balance
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Figure 2-2. Basic Mud Balance
2.1.3 Relationship of Fluid Properties
The ability of a drilling fluid to perform its functions depends on various fluid properties, most of which are measurable and affected by solids control.
Density is a measure of the weight of the mud in a given volume, and is frequently
referred to as mud weight. The instrument used to measure density is the mud balance. A pressurized mud balance (Figure 2-1) will produce the correct mud weight even if the mud is gas cut but most rigs use the basic mud balance (Figure 2-2). Both instruments consist of a constant volume cup with a lever arm and rider calibrated to read four different scales: density of the fluid in lbs/gal (water = 8.34 lbs/gal) and pressure gradient in psi/1000 ft (water = 433 psi/1000 ft), pounds per cubic foot (water = 62.4 lbs/ft) or specific gravity. The density of mud can be expressed as specific gravity. Specific gravity is the ratio of a material’s density to the density of water. Pure water has a specific gravity of approximately 1.0. A material twice as dense as water would have a specific gravity of 2.0. Barite is generally used to increase mud density and is called “a high gravity” solid. API specification barite has an average specific gravity of 4.20, while “low gravity” solids have an average specific gravity of 2.6.
Viscosity is a measure of resistance to flow and is one of the most important physical
properties of drilling mud. Increasing the concentration of solids or the total surface area of the solids in a fluid increases its viscosity. Viscosity can be measured in several ways.
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Figure 2-3. Marsh Funnel and Cups Funnel Viscosity provides information about how mud behaves at low flow rates, such
as surface pits and across shaker screens. The higher the funnel viscosity is, the thicker the fluid. Funnel viscosity is routinely measured with a Marsh Funnel and mud cup at the drilling site (Figure 2-3). The person measuring the viscosity fills the funnel with a sample of mud and allows it to flow from the tip of the funnel while measuring the time in seconds it takes to fill the cup to one quart. The funnel viscosity is recorded in seconds per quart. Plastic Viscosity measures the portion of a mud’s flow resistance caused by the
mechanical friction between the suspended particles and by the viscosity of the continuous liquid phase. In practical terms, plastic viscosity (PV) depends on the size, shape, and concentration of solid particles in fluid (Figure Table 2-1). For example, an increasing concentration of drilled solids particles will increase the plastic viscosity. Plastic viscosity is measured with a rotational viscometer (Figure 2-4) and is expressed in centipoises (grams per centimeter-seconds). PV is determined by subtracting the 300 dial reading of the viscometer from the 600 dial reading as shown: 600 reading – 300 reading = PV
Table 2-1 Viscosi ty Ranges of Common Flui ds in Centipo ises Centipoises
Product
1-15
Anti -Freeze
16-100
Corn Oil
101-1000
Motor Oil
1001-2500
Corn Syrup
2501-5000
Honey
Abov e 5000
Mol asses
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Figure 2-4. Rotational Visc ometer
Yield Point is a measure of attractive forces between suspended solid particles in a liquid
while it is being circulated. It measures the positive and negative attractive forces between the solid particles in a fluid. Yield point (YP) is also measured with a rotational viscometer and expressed in lbs/100 ft 2. Internationally, yield point is measured in dynes/cm². YP is obtained by subtracting the PV from the 300 dial reading of the viscometer as shown below: 300 reading – PV = YP
Gel Strength is a measure of mud’s inter-particle attractive forces in a liquid at rest.
Gel strength gives an indication of the amount of gelation that will occur when circulation ceases and the mud remains static for a period of time. Gel strengths are routinely measured 10-seconds and 10-minutes after stirring the fluid and are reported as 10-second and 10-minute gels. A difference between these two figures may indicate progressive gels, that is, gelation that gains strength over time. Gel strength is measured with the rotational viscometer and is expressed in lbs/100 ft 2. The mud sample is stirred for 15 seconds at 600 rpm and after the 10 seconds or 10 minute time interval, the rotor is moved at 3 RPM and the maximum dial reading is recorded as the 10-second or 10-minute gel strength. Internationally, gel strength is measured in dynes/cm². Filtration or Wall-Cake - Mud liquid seeps into porous formations leaving a layer of mud solids on the exposed formation surface. This layer of mud solids is called filter cake or wall-cake. The filter cake forms a barrier and reduces further filtration. This process is referred to as filtration, or fluid loss. The instrument used to measure fluid loss due to filtration is a filter press (Figure 2-5).
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Figure 2-5. Filter Presses
A piece of filter paper is placed on the screen, the cell is assembled, filled, sealed and 100 psi pressure is applied. The volume of fluid flowing from the sample in 30 minutes is measured and recorded in milliliters, ml or cubic centimeters, cc. Examination of the filter cake on the paper provides an indication of the quality of the cake being deposited in the hole. Cake thickness is recorded in units of 1/32s of an inch.
So lids Content Solids content is the volume percentage of the total solids in the mud. To determine the solids content of a mud containing weight material, a mud container in the retort is filled with a measured volume of mud (Figure 2-6). The mud is heated to boil off the liquid. The percentage of the liquid distilled off is measured in a glass cylinder. The percent by volume of solids and liquids (oil and water) are obtained and recorded on the mud check report. The total solids from the retort and mud weight are used to calculate the low and high gravity solids content.
If the mud does not contain oil or weight material, such as barite or hematite, the low gravity solids can be determined without a retort. One can weigh the mud sample and use the algorithm, Vs = (7.5)( ρ-8.34), to calculate the percent solids; where Vs is percent solids and ρ is mud weight in pounds per gallon.
Figure 2-6. Retor ts 21
Sand
Sand is any particle larger than 74 microns when referring to solids control separation. Therefore, the sand content of a mud is simply the amount of solids too large to pass through a US Test Sieve 200-mesh screen. This is determined with a sand content set (Figure 2-7) by washing a measured amount of mud through the 200-mesh screen in the kit. The amount of solids that does not pass through the screen is measured as percent by volume and is recorded as percent sand. API Barite may contain as much as 3% weight percent of particles larger than 74 microns. Since the screen can’t differentiate between drill solids and barite, the addition of fresh barite often increases the measured sand content.
Figure 2-7. Sand Content Sets Chemical Properties
Chemical properties is a broad category and includes pH, alkalinity, chlorides, calcium content, salt content, and other factors that affect drilling mud performance. Some of these chemical properties can be controlled through the use of mud additives that thicken, thin, precipitate, disperse, emulsify, lubricate or otherwise affect the mud depending on specific drilling needs. For example, caustic soda can be added to some muds in order to increase the pH, thereby increasing dispersant effectiveness and reducing corrosion. Chemical changes such as these are used to fine tune drilling mud properties. Electrical Properties
Electrical properties are routinely measured in an oil-based (non-aqueous) fluid. The resistively of a mud is controlled to permit improved evaluation of electrical logs. Resistively is measured by determining the resistance to the flow of an electric current through a fluid sample, and is recorded in ohms. Stability is determined by measuring the voltage across two electrodes submerged in the sample of oil-based mud (diesel, mineral or synthetic). When the dial or digital value reaches a maximum, that value becomes the ES (Electrical Stability) of the mud sample. The higher the ES the more stable the invert emulsion, and the more stable the invert mud.
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2.1.4 Selection of a Drilling Fluid Types of Drilling Fluids
Drilling fluids are generally categorized as “water-base”, “oil- base”, or synthetic-base, and as “weighted” or “unweighted” muds. Here is a list of the most common mud types, followed by a brief description of each type: Water-Base Mud (WBM)
A.
Spud Mud
B.
Natural mud
C.
Chemically-Treated Mud
D.
1.
Lightly Treated Chemical Mud
2.
Highly Treated Chemical Mud
3.
Low Solids Mud
4.
Polymer Mud (Non Dispersed Muds)
5.
Calcium Treated Mud
6.
Silicate Treated Muds
Saltwater Mud - Sea Water Mud or Saturated Salt Mud Oil-Base Mud (OBM); or Non Aqueous Fluids (NAFs)
1.
Diesel
2.
Mineral
3.
Synthetic-Base Mud (SBM) a.
Olefin
b.
Ester
c.
Others
Water-base muds (WBM) have water as the liquid phase and are used to drill most of the wells in the world because water is usually available and water-base fluids are relatively simple and inexpensive. Non Aqueous Fluids (NAFs) contain diesel, mineral or synthetic oil as the continuous liquid phase and are used for wells that require maximum hole protection. NAFs are usually much more expensive than WBM and therefore are used only when there is a specific need. NAFs keep the hole in gauge, reduce friction and minimize the risk of stuck pipe in crooked or high angle holes especially where hydratable formation is being drilled. Synthetic-base muds are subsets of NAFs. Synthetic-based fluids contain a synthesized liquid phase and share many properties with NAFs, but have the advantage of reduced environmental impact. Synthetic-base muds typically are very expensive, making solids control critical. 23
Any mud to which barite or another weighting agent is added to control its density is called a weighted fluid. Controlling mud density over 9.5 – 10.0 ppg while retaining desirable properties requires the use of an inert weighting agent. The most common weight material used is barite (barium sulphate – BaSO 4). Other weight materials used are hematite (iron oxide – Fe 2O3) and galena (lead sulphide - PbS). The American Petroleum Institute (API) sets standards for mud products such as barite. The API recommends that barite has a minimum specific gravity of 4.20, but this could change as high quality material becomes less available at acceptable cost. At the 2007 API Standardization meetings in Ft. Worth, Texas, the API committee that handles drilling fluids discussed the possibility of having two API specifications for weight material, one for a barite specification at 4.20 and another at 4.10. The API 4.10 barite would be used on wells where the mud weight would be low, which would save the high quality barite for critical wells that would require high mud weights. Unweighted mud refers to any mud which has not had barite added for density control. This mud type of fluid, when water-based has a density of less than 10 lbs/gal. The solids in unweighted mud are drilled solids from the wellbore plus commercial additives. Typical Applications Spud Mud is used to start the drilling of a well and continues to be used while drilling
the first few hundred feet of hole. Spud mud is usually an unweighted water-base mud, made up of water and natural solids from the formation being drilled. It may contain some commercial clay, added to increase viscosity and improve wall-cake building properties. Natural Mud (sometimes called “native” mud) is usually unweighted water-base mud
which contains mostly drilled solids. Some bentonite and small amounts of chemicals may be used to improve filter cake quality and help prevent hole problems. This mud is often used after spud mud. Often, natural mud is used to drill the first few thousand feet of hole, where only minor hole problems are expected. Chemically Treated Mud is water-base mud which contains chemicals to control physical and chemical properties. Bentonite is usually added to help control viscosity and fluid loss. Barite (weight material) may be added to increase density. This mud is used where more severe hole problems are expected. Lightly Treated Chemical Mud is usually unweighted water-base mud.
It is used where minor hole problems are expected, such as sloughing or caving of the walls of the hole. Highly Treated Chemical Mud is usually weighted, water-base mud that contains
larger amounts of chemicals, bentonite, additives, and barite to maintain strict control of viscosity, fluid loss, chemical properties, and density. Water-muds treated with lignosulfonates or lignite are commonly called “lignosulfonate mud” or “lignite” mud. These muds are used where moderate-to-severe hole problems are expected or high subsurface pressures occur. Of all the water-base mud types, these are the most expensive to maintain. As mud density is increased and potential hole problems (such as stuck drill pipe) become more of a risk, the removal of drilled solids by mechanical solids control equipment becomes increasingly important. 24
Low Solids Muds are water-base muds containing less than 10 % drilled solids; 1–5%
is a normal range. Generally speaking, the lower the solids content in the mud, the faster the bit will drill. Low solids muds can be expensive to maintain because the solids, chemicals, and fluid loss properties have to be kept very close to prescribed levels.
Polymer Muds are special types of low solids mud which contain synthetic materials
and polymers designed to provide inhibition and control viscosity and fluid loss.
Calcium Treated Muds are special water-base muds, usually weighted, which have
lime or gypsum. Calcium Treated Muds are normally used to prevent shale and clay formations from swelling or sloughing - problems which could lead to stuck pipe or the loss of the hole.
Saltwater Muds contain a high concentration of salt. They may be weighted or
unweighted. Saltwater muds often are used to minimize washouts or hole enlargement in water-sensitive formations.
Sea Water Muds contain sea water as the continuous phase and, usually, only sea
water is used for dilution. They may be weighted or unweighted. These muds are used offshore and in bay areas where fresh water is not readily available.
Saturated Salt Muds (sometimes called brine fluids) contain as much salt as can be
dissolved in the water phase. This mud type often is used to drill through salt formations so the fluid will not dissolve the salt formation. If fresh water mud is used, greatly enlarged holes would result, usually leading to hole trouble. In some cases, Mixed Salt Muds are used when drilling through complex, soluble salt formations.
“True” Non Aqueous Fluid (NAFs) contains a liquid phase with more than 95% by
volume diesel or mineral oil and five percent or less water by volume emulsified within the oil. These muds often use asphaltic type materials suspended in the liquid for controlling viscosity and fluid loss. “True” NAFs provide good hole protection, especially in troublesome shale formations, and also increase drill string lubrication. Not many of these muds are used today due to fire hazards.
Invert Emulsion NAFs is an oil-base mud in which the liquid phase is 60–90% diesel or
mineral oil with 10–40% water emulsified within the oil. An invert mud can be formulated with mineral oil or other low environmental risk oil substitutes when needed. In this mud, water and chemicals are used together to control viscosity and fluid loss. Invert emulsion muds provide good hole stability and are the most commonly used NAFs. 25
Synthetic-Based Mud are subsets of the non-aqueous fluids (NAFs) and are invert
emulsion muds that use a synthesized liquid base. Some common synthetic base fluids include linear alpha olefins (LAO), straight internal olefins (IO), polyalphaolefins (PAO), paraffin oils, vegetable oils, esters, and ethers. This base fluid is combined with water, viscosifiers, weighting material and other additives to produce a stable, useful drilling fluid. These type NAFs produce excellent wellbore stability, improved drilling rates, good hole cleaning, excellent cuttings integrity and reduced torque. The major benefit of these NAFs over traditional NAFs is the reduced environmental impact of cuttings and liquid mud. Currently, the synthetic-based NAF coated drill cutting meets U.S. offshore environmental requirements and may be discharged. Olefin based NAFs must meet a ≤ 6.9 w/w % retained oil on cuttings (ROC) while Ester- Based fluids must meet ≤ 9.4 w/w % ROC. These NAFs also provide additional health and safety benefits — higher flash points, lower vapor production and reduced eye and respiratory irritation. Effects of Fluid Selection on Solids Control/Waste Management Practices
The drilling mud is a major factor in the success of any drilling program, and the key to any effective mud system is good solids control. Solids control techniques will vary considerably depending on the type of mud being used. For example, with many unweighted water-base muds, the loss of fluids along with the drilled solids may be economically insignificant, allowing simple solids control techniques. In the case of mud that contains expensive chemical additives and/or barite, especially oil-base or synthetic muds, sophisticated solids control techniques must be utilized to minimize overall costs. In addition, environmental costs of haul-off and disposal may require sophisticated solids control techniques. Spud Mud and Natural Mud require little treatment with solids control equipment other
than coarse mesh shaker screens and Desanders. Fluid properties are controlled through the addition of water and commercial clays. Lightly Treated Muds use varying degrees of mechanical solids control equipment and
are usually maintained by adding water and commercial clays. If the fluid density is increased and or costly chemical additions are required, removal of drilled solids by mechanical solids control equipment becomes increasingly important. Low Solids Muds also known as Polymer Muds require sophisticated solids removal
systems. Partially Hydrolyzed Polyacrylamide (PHPA) treated muds often are difficult to screen because this mud type can have a high funnel viscosity. Centrifuges often are used after fine screen shakers to help maximize fine solids removal. Calcium Treated Muds are special water-base muds, usually weighted, which have
lime or gypsum added. Calcium Treated Muds normally are used to prevent shale formations from swelling or sloughing – problems which can lead to stuck pipe or a lost hole.
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Silicate Treated Muds are water-base muds containing silicate from sodium or
potassium silicate sources. These muds are highly inhibitive and give the wellbore chemical stability. Saltwater Muds, Sea Water Muds and Saturated Salt Muds use varying degrees of
mechanical solids control equipment. Lightly treated muds require little solids control equipment; fluid properties are often controlled through the addition of water and commercial clays. If the fluid density is increased and/or costly chemical additions are required, removal of drilled solids by mechanical solids control equipment becomes increasingly important. With all salt muds, screen blinding can occur when salt dries and cakes on the shaker and mud conditioner screens. Fresh water may be used to clean the screens, but it must be used very carefully because too much fresh water can upset the chemical balance of this mud. When sea water mud is being used, only sea water should be used to rinse or wash the screens in solids control equipment. 2.1.5 The Nature of Drilled Solids Common Terminology Mud solids are the commercial solids added to control fluid properties and the formation solids which are picked up while drilling. Aside from the minor quantities of drilled solids tolerated to increase the density of unweighted muds, drilled solids are detrimental to drilling fluid performance. They increase viscosity, density and filter cake thickness and require dilution which increases the volume of excess mud produced while drilling. The unit of measurement generally used to describe the size of drilling fluid solid particles is the micron (µ). A micron is one thousandth (0.001) of a millimeter, or approximately 0.00003973 of an inch. Table 2-1 provides a list of common items and their size in microns.
Table 2-2 Micron Size Range of Common Materials Cement Dust (Portl and) 3-100 µ
Talcum Powder
5-50 µ
Red Blood Corpuscles
7.5 µ
Finger Tip Sensitivity
20 µ
Human Sight (visible to eye)
35-40 µ
Human Hair
17-181 µ
Cigarette (diameter)
7520 µ
One inch
25,400 µ
Mud solids can range in size from less than one micron to larger than a human fist. Their average size is less than 40 microns. As indicated below, mud solids are classified solely on the basis of their size. Their composition is irrelevant. A clay particle 100 μ in diameter is classified as sand.
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Table 2-3 Common Field Terminology of Partic le Size
Item/Classific ation
Partic le Size — Diameter in Microns
Cuttings
Larger than 500 µ
Sand
74-500 µ
Silt
2-74 µ
Clay
Smaller than 2 µ
It is important to note that commercial solids added to the mud system, such as barite, can be and will be removed from the mud system solids control equipment. For example, barite can contain up to 3% (weight) solids larger than 74 microns. If the shale shakers are dressed with screens that remove solids 74 microns and larger, as weight material is added to the mud system, the shakers can remove some of the barite being added. Solid particles of size less than 2 microns (equivalent spherical diameter) are called colloidal solids. This definition can be found in the International Standards Organization ISO/CD 13501, par. 3.1.17. Because of extremely small size, these solids largely defy direct removal by mechanical devices that rely on screening or gravitational forces . U
Effects o f Particl e Size
As they travel to the surface, drilled solids particles are continuously reduced in size by collisions with other particles and by the grinding action of the drilling assembly. Abrasiveness of mud solids is determined by particle shape and hardness. See Appendix G item 20.7.3 for a listing of specific gravity and Mohs hardness for many common mud components. Drilled solids can be round, needle shaped, angular, platelets, spherical and cubic. Figure 2-8 illustrates the degradation of drilled solids. Particles become less abrasive with wear as the most abrasive corners are removed and their size is diminished. Size tends to stabilize in the silt size range at approximately 15–20 microns.
Figure 2-8. Mechanical Degradation of Drilled Soli ds 28
Particles smaller than 15 microns are much less abrasive than larger solids, and the smaller-sized solids have little effect on drilling equipment. Barite particles, which are not as hard as most drilled solids, generally are less abrasive than similarly sized drilled solids. Other weighting materials, such as hematite, are generally harder and more abrasive than barite. Specific surface area, as it relates to various shapes and sizes of solids, is another important consideration. Specific surface area refers to the surface area per unit of weight or volume. Figure 2-9 lists examples how surface area greatly increases per unit of mass: 1) as particle size decreases, and 2) as particles become less spherical.
Figure 2-9. Surface Area Issues
Surface area adsorbs or “ties-up” water. The more surface area, the more water adsorbed. As the particle size decreases toward the colloidal size, the relative effect of the water coating increases. The specific surface area has a pronounced effect on viscosity. (Figure 2-10) Bentonite
Drill Solids
(Large Surface Area)
(Moderate Surface Area)
y t i s o c s i V g n i s a e r c n I
Increasing % Solids
Figure 2-10. Effect of Specific Surface Area on Viscosity
This graph shows the effects large surface area has on viscosity; the larger the surface area, the greater the viscosity. Formations composed of clays that easily disperse will degrade into small particles and cause viscosity increases. These clays will have “wetter” separations when removed by solids control equipment than clays that don't disperse/degrade easily. Bentonite disperses easily into colloidal solids and adsorbs much more water than most solids types. Hence bentonite builds viscosity at relatively low concentrations. 29
3
ECONOMICS
3.1
Benefits of Soli ds Removal by Mechanic al Separation
Drilling fluid is unavoidably contaminated with drilled solids during the drilling process. It is impossible to prevent their becoming part of the drilling fluid. Solids control is one of the most important phases of mud control and it is a constant issue, every day, on every well. It is much less expensive to remove solids mechanically than to control them with dilution. The benefits of solids removal by mechanical separation are twofold; 1) reduced total mud solids and 2) reduced dilution requirements. 3.1.1 Reduced Total Solids
The presence of large amounts of drilled solids in a drilling mud always increases drilling cost. Drilled solids decrease the life of pump parts and decreases drilling efficiency by interrupting drilling for pump repairs. Continued recirculation of drilled solids causes them to be reduced in size and increases their negative effects on drilling performance. The greatest impact of excessive mud solids is seen in reduced ROP.
The higher the drilled solids content, the lower the penetration rate. If mud solids are
not properly controlled, the mud’s density can increase above its desired level and the mud can get so thick that it becomes extremely difficult or even impossible to pump. Since the earliest days of the oilfield, drillers have been trying to combat high solids content through the use of settling pits. However, some drilled solids are so finely ground that they remain in suspension. This results in increased mud viscosity and gel strength which, in turn results in larger particles also remaining in suspension. Removing cuttings through settling alone is ineffective. Solids control equipment was developed in order to more effectively remove unwanted solids from drilling mud. A variety of devices (which will be discussed in detail in Chapter 4 of this handbook) are available which mechanically separate the solids particles from the liquid phase of the mud. Thus the driller, depending on the particular situation and equipment used, can regulate to a fine degree the amount and size of solids particles that are removed from or tolerated in the mud. Effective use of a well-designed solids control system with adequate fluid handling capacity reduces the cost of maintaining mud properties at desired levels, reduces the environmental impact of drilling, improves penetration rates, improves hole conditions and thereby reduces the risk of stuck pipe and extends the life of bits and pump parts. 3.1.2 Reduc ed Dilutio n Requir ements
The usual method of coping with increasing drilled solids content is dilution, reducing the concentration of solids by additional liquid. This is a costly process because it requires the use of additional drilling fluid additives to convert the added liquid to drilling fluid with the desired properties.
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The higher the drilled solids content, the greater the dilution required. For example, the addition of one barrel of drilled solids to a fluid in which drilled solids content is being controlled at 5% by volume requires 20 barrels of dilution. If drilled solids content were being controlled at 8%, the required dilution would be 11.5 barrels. In the case of an oil-based mud, oil must be used for dilution – which can become extremely expensive. The most effective approach is to use mechanical solids control equipment to remove as much of the drilled solids as possible and then treat what is left with appropriate amounts of chemicals and dilution. The Mud Dilution Chart (Table 3-1) can be used to approximate the amount of dilution that can be eliminated by use of solids removal equipment. For example, suppose a drilling engineer required that no more than 5% solids were to be maintained in an unweighted mud. The chart shows that at 5%, each barrel of mud would contain about 45 pounds of drilled solids. If for example, the solids control equipment on a given rig was removing 1 ton (2000 lbs) of solids per hour, then the equipment would save 2000 ÷ 45 = 44.4 barrels of dilution per hour. If the chemicals and additives were worth only $10 per barrel, the mud treating costs would be reduced by approximately $444 per hour! Over the life of a drilling operation, $444 per hour is a very significant cost savings. Table 3-1. Mud Dilution Chart
Mud Weight (lb/gal) to be Maintained
Drilled Solids % by volume
Pounds of 2.6 Specific Gravity Solids per Barrel of Mud
Barrels of Water Requir ed to dilut e one ton of Solids and Maintain Mud Weight
8.5 8.6 8.7 8.8 8.9 9 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 10
1.2 2.0 2.7 3.5 4.2 5.0 5.7 6.5 7.2 8.0 8.7 9.5 10.2 11.0 11.7 12.4
11 18 25 31 38 45 52 59 66 72 79 86 93 100 106 113
183 113 81 64 52 44 39 34 31 28 25 23 22 20 19 18
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The same procedure can be used to show reduced dilution requirement in weighted mud. When heavily weighted muds (16–18 lbs/gal) are being used, drilling usually proceeds more slowly and less drilled solids are removed per hour. However, if approximately 5% drilled solids are allowed in the mud, each barrel of mud still contains roughly 45 pounds of drilled solids. Therefore, if the solids control equipment were removing even a pencil-sized stream of solids which would amount to 45 pounds per hour, then 45 ÷ 44.4 ≈ 1 barrel of dilution saved per hour. With the high cost weighted mud (usually a minimum of $40+ per barrel for lightly treated water-based mud), the solids removal equipment would be saving at least $40 per hour. Over an average operation of 20 hours per day, this represents a savings of approximately $800 per day. If the maximum amount of drilled solids were reduced to 3%, the cost savings would double to approximately $1600 per day. The expense of the dilution liquid is a major factor in evaluating the advantages of reduced dilution requirements. Oil obviously is much more costly than water, but water can be expensive if it has to be trucked to a remote drilling location. The disposal of “waste” mud often is a very significant factor in total dilution costs. Reliance on dilution to control solids content can result in the addition of so much extra liquid that the volume of mud exceeds the capacity of the active mud pits. When this happens, whole mud must be discarded into waste or reserve pits. Appropriate use of solids control equipment in place of dilution lessens the volume of the mud system and can eliminate the need to discard excess mud and permit the use of smaller surface systems. Under some conditions, solids control equipment virtually can eliminate waste liquid mud through the use of “closed” mud systems. In these systems the liquid phase is recycled, which can be extremely beneficial with costly oilbase or polymer fluids, especially offshore or where environmental concerns prohibit disposal of liquid waste. In these cases the cost of hauling away waste away for disposal also is eliminated. See Appendix C for more examples of how solids control equipment can save money.
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4
SEPARATION BASICS
The goal of modern solids control systems is to reduce overall well costs by prompt, efficient removal of drilled solids while minimizing the loss of liquids. Since the size of drilled solids varies greatly — from cuttings larger than one inch in diameter to submicron size — several types of equipment can be used, depending upon the specific situation. The fundamental purpose for solids removal equipment is to remove as many unwanted drilled solids as possible. The end result is reduced mud and waste disposal costs. To reach this goal, each piece of equipment will remove a portion of the solids, either by screening or centrifugal force. Each type of equipment is designed to separate particles of a particular size range or a specific mass from the liquid. Also to operate effectively, each type of equipment must be sized, installed, operated and maintained properly. The efficiency of the solids control system can be evaluated by comparing the final volume of mud accumulated while using the equipment, to the volume of mud that would result if drilled solids were controlled only by dilution. That is, final volume with solids control equipment/final volume if no solids control equipment X 100 = % efficiency. The efficiency of solids removal equipment and/or systems used can be evaluated in two ways: 1.
Efficiency of drilled solids removal
2.
Efficiency of liquid conservation
The greater percentage of drilled solids removed, the higher the removal efficiency. For example, desilters can remove large quantities of solids but at the cost of significant losses of liquid; sometimes 80% of the volume of the waste stream will be liquid. By contrast, a properly operating shale shaker or centrifuge typically removes 1 barrel or less of mud with each barrel of solids (about 50% liquid waste), and this depends on the size of the drilled cuttings. In some instances the solids discharged from a linear motion shaker will contain less than 20% liquid (volume %). Most solids control systems include several types of equipment connected in a series. Each stage of processing removes finer particles than the stage preceding it and its effectiveness depends upon the proper functioning of the upstream equipment. •
Gumbo Box (primarily for offshore use)
Mud Gas Separator
Shale Shakers (could include scalping shakers)
Degasser
Mud Cleaner/Conditioner
Desander
Desilter
Centrifuge(s)
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Some drilling situations require the use of a device called the Gumbo Box. A Gumbo Box removes sticky clays or gumbo by utilizing a moving screen or chain rather than a vibrating screen. The moving screen or chain filters the mud and separates the sticky clays or gumbo from the mud as the mud returns form the wellbore. The Gumbo Box is primarily used on offshore rigs and especially in the Gulf of Mexico where the gumbo formations are prevalent. When drill gas is encountered, the rig will divert the mud flow from the wellbore to a mud gas separator. The mud gas separator has no moving parts and removes entrained gas. The gas is separated and sent to a flare for safe disposal away from the rig. The mud is then sent to a Gumbo Box or to the shale shakers for further processing. The next piece of equipment used to separate solids from the mud is usually a device which uses a vibrating screen called a Shale Shaker . This device uses mechanical energy to separate cuttings larger than the screen openings from the mud. The separated cuttings carry an adhered film of mud. In the mud adhering to the solids are fines that are eliminated from the system as the cuttings are discharged. The more retention time of the mud on the screens the lower the concentration of mud adhering to the drill solids. Screens should always be sized to prevent excessive losses of whole mud over the end of the shaker. NOV recommends selecting screens so that the fluid flow covers 75%-80% of the screening areas, e.g. on a four-panel shale shaker one would select the size of screens so that three screens are covered with fluid. By using this recommendation, the fluid end point and solids separation point would occur at the end of the third screen. The last screen would be used to remove excess mud from the solids before they are discharged from the shaker. Some rigs use as many as 10 shale shakers. The optimum number of shakers depends on the rate of penetration, hole size and flow rates encountered. Hydrocyclones are used to remove the sand-sized and silt-sized drill solids that were
not removed by the shale shakers. Hydrocyclones with a cone diameter of 6 to 12 inches are called Desanders and those with a cone diameter of less than 6 inches are called Desilters. These units should normally be sized to process 125% of the maximum flow rate used for drilling. Sometimes a screen is used below a hydrocyclone to “dry-out” the cone’s discharge to minimize the loss of fluid. The hydrocyclone and vibrating screen device is called a mud cleaner (mud cleaner = hydrocyclones + orbited motion shakers) or mud conditioner (mud conditioners = hydrocyclones + linear motion shaker). If a location must be “pit-less”, then the screens are essential to minimize the liquid waste volume. In the late 90’s many rigs let the desanders and desilters sit idle due to the use of better shale shakers and better screens. As stated earlier, hydrocyclones are sized to handle 125% of the maximum drilling fluid flow but many rigs will have only 50% of the cones operating properly at any given time. Many rig hands ignore the cyclones. They don’t service them, and without all the cones working properly, solids are left in the mud to potentially become fines later. Centrifuges are normally used to separate light solids from heavy solids. A centrifuge
can be used to remove drill solids from an un-weighted mud. This operation has the centrifuge running at high speed removing as much solids as possible to keep the mud weight as low as possible. The solids are discharged and the liquid is returned to the mud system. Sometimes we enhance this process with chemicals and we call this dewatering. 34
When a drilling fluid has a liquid phase that is expensive, e.g. non aqueous fluids (synthetic-based mud), one can process the system with two centrifuges. One centrifuge would be used to separate the heavy dense solids (weight material) from the liquid of the mud, returning the heavy dense solids (weight material) to the mud system. The effluent from the first would be stored in a tank and then processed by a second centrifuge removing solids and returning the liquid to the mud system. This doesn’t remove the colloidal fines but does remove solids that might degrade into colloidal fines over time. The best way to reduce colloidal fines is to process a small portion of the mud system discarding the effluent and keeping the heavy dense solids (weight material). The effluent discarded then would be replaced with clean base fluid. This process reduces the colloidal content and brings the rheological properties back into reasonable ranges.
4.1.1 Parti cle Size and Equi pment Used t o Measur e
Modern drilling rigs may be equipped with many different types of mechanical solids removal devices depending on the application and requirements of a particular project. Each device has a specific function in the solids control process. Equipment commonly utilized and the effective removal range for shown in the graphic “ Particle Diameter and Sequential Solids Removal”. (Figure 4-1)
Particle size analysis can be done by screening solids (normally done for larger solids; 700 microns and larger) or using electronic devices that measure solids from 700 microns to less than one micron.
When screening solids one could use either of two types of sieves as shown in Appendix M; US Sieve Series or the Tyler Standard Sieve Series. Both sets of sieve will work. A shaking device is use to help separate solids at each sieve. After separating the solids, each size of solid in each sieve is weighed and the distribution of the solids by size is put into a table for review.
There are several providers of electronic devices for measuring the small end of the particle size spectrum encountered while drilling (700 microns to less than one micron). For example a typical particle size analysis (PSA) one can review the data shown in Appendix J, 20.10.2 & 20.10.3. The centrifuge PSA data is shown for the centrifuge feed and effluent. It is obvious the centrifuge is removing solids based on the comparison of the two data sheets.
35
Figure 4-1.Particl e Diameter and Sequential Solid s Removal
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4.2
Separation by Settling
Using vibrating screens to remove drilled solids from mud uses only one characteristic of solids particles - their size. Another factor which affects separation is particle density. Solids control devices which take advantage of particle size and particle density speed up the settling process by application of centrifugal force. These devices utilize Stoke’s Law as the basis for their operation. Stoke’s Law defines the relationship of factors governing the settling velocity of particles in a liquid. Larger, heavier particles settle more rapidly in less dense and viscous fluids and increased acceleration speeds up the process.
Figure 4-2. Settling Pit
Settling pits, (Figure 4-2) hydrocyclones, and centrifuges all utilize this principle in their
operation. Settling pits use the force of gravity to separate solids. The larger and/or heavier a solid is, the faster it will settle through the fluid in a settling pit. The process can be accelerated only by reducing the viscosity of the fluid in the pit or by flocculating the solids, causing them to chemically clump together. Settling pits often are large and require closure or remediation when drilling is completed. The reduction in waste mud achieved through efficient solids control greatly reduces the waste fluid remediation costs. A sand trap is a settling tank usually the first compartment of the first pit in the mud system. The shale shakers would normally sit on top of the sand trap and the shakers would discharge into the sand trap. After the mud goes through a Gumbo Box (if used), the mud gas separator (if used) and the shale shakers it enters the sand trap. The sand trap is a compartment that is not agitated. The sand trap allows large solids to settle out of the mud; solids that might have by-passed the shaker screens or solids that passed through a torn screen. The sand trap removes the large solids that might plug cyclones or other downstream equipment.
37
The fluid overflows at the top of the sand trap tank into the next compartment, which should be the degasser suction pit. The sand trap should have a slanted bottom and a quick-opening, quick-closing dump valve or gate so that settled solids can be discharged with minimum mud loss. If one uses an inexpensive drilling fluid along with poor performing shakers, e.g. orbital shakers, in an area where waste volume is not a critical issue, the sand trap normally will be dumped often -- once or twice an hour. This is especially true when drilling surface hole on a land well.
4.2.1 Stokes’ Law
Figure 4.3. Stokes’ Law
Stokes’ law (Figure 4-3) was developed for determining the settling rate of spherical particles in liquid. The modified equation is shown above and the original equation is shown below: F = 6πμνR Where F = the force applied to the sphere by the liquid, in dynes μ = the fluid viscosity, Poise ν = the particle velocity, cm/sec R = is the radius of the sphere, cm
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4.3
Separation by Size
4.3.1 Separation by Filtration
NOV FluidControl is a leading provider of oilfield filtration equipment and services, specializing in the treatment and analysis of wellbore clean-up, completion fluids, gravelpack carrier fluids, work-over fluids, brines and produced water treatment. Provided with the proper information, NOV’s staff of filtration specialists can work with customers to develop and implement a successful filtration project plan. Such information includes:
o o o
Fluid type Flow rates Types of contaminant Output requirements (type of testing required) NTU (nephelometric turbidity units) TSS (total suspended solids) TOG/TPH (total oil & grease or total petroleum hydrocarbons)
NOV supplies duplex cartridge and bag filter units that can handle flow rates of 42 to 840 gallons per minute (159-3180 liter/min). Cartridge elements with nominal and absolute ratings range from 1-100 microns can provide solids removal efficiencies of up to 99.9%. Diatomaceous earth (DE) filtration units which are used for higher solids laden fluids also are available and can handle flow rates from 84 to 630 gallons per minute (318-2386 liter/min) per unit. DE units are the industry standard for removing solid particulate from completion fluids. Vertical-pressure leaf filters and filter press DE units are also available.
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Figure 4-4. Vertical Pressure Leaf Filter
Table 4-1 Vertical Pressure Leaf Filter - Features and Benefits
Features
Benefits
Closed system
Provides minimum-risk operation
Quick wash down of leafs (< 10 minutes)
Minimizes downtime
Semi-automatic cleaning without opening
Eliminates labor-intensive work
Laminar flow through filter vessel
Offers high efficiency
High through puts, low NTU levels
Reduces the use of polish filters
Small footprint
Minimizes required deck space
All wetted parts stainless steel 316L
Minimizes rust & therefore reduces maintenance
Large filtration area systems
Effective in treating heavy brines
Pneumatically-controlled
Facilitates easy operation
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Figure 4-5. Filter Press Table 4-2 Filter Press - Features and Benefits
Features
Benefits
Recessed plates (with gasket)
Provides drip-free plates & system
Pneumatic/hydraulic closing system
Offers automatic opening and closing of unit
Unique filter cloth design
Provides a low NTU effluent and high flow rate
All wetted parts stainless steel and Polypropylene
Minimizes rust and reduces maintenance
Uses powdered filter media
Produces a clear filtrate
Large filtration area systems
Effective in treating heavy brines at high throughputs
Closed system with drip-free construction
Delivers increased safety and environment friendliness
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Figure 4.6. Duplex Filt er
Table 4.3. Duplex Filter - Features and Benefits
Features
Benefits
Individual, Serial or parallel operation
Provides flexible service, as needed
Stainless steel 316L construction
Affords less maintenance
Small footprint
Minimizes required deck space
High flow rate achievable
Suitable for seawater filtration during injection jobs
Utilization of swing bolts and nuts
Facilitates quick opening of unit
All valves are four (4) inches in diameter
Provides easy operation from the front of the unit
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4.3.2 Separation by Screening One method of removing solids from drilling mud is to pass the mud through a vibrating screen and removing solids larger than the screen openings. Particles too large to pass through the screen are separated from the mud and discharged off the screen surface by the vibration of the shaker. Basically, a screen acts as a filtering device. The shale shaker uses G-force, in the form of some type motion, to remove the separated solids from the screen. The purpose of vibrating the screen in solids control equipment is to transport the cuttings off the screen and increase the liquid handling capacity of the screen. This vibrating action causes rapid separation of whole mud from the oversized solids, reducing the amount of mud lost with the solids. For maximum efficiency, the solids on the screen surface must travel in a predetermined pattern - spiral, elliptical, orbital or linear motion - in order to increase particle separation efficiency and reduce blockage of the screen openings. The combined effect of the vibration and the screen surfaces result in the separation and removal of oversized particles from drilling mud.
4.3.3 API Sc reen Des ig nat io n The American Petroleum Institute (API), comprised of operators and service companies, prepared a document that outlined how screens should be tested and labelled for oilfield use. This new document, API Recommended Practice (RP) 13C, was adopted internationally and became ISO 13501 in December 1, 2005. All screens that are API RP 13C (ISO 13501) compliant must follow a specific testing and labelling procedure. The following items are included on the new screen labelling protocol in this specific order: 1) API Screen Designation (this text must be twice the size of any other text on the label) 2) Opening size in parenthesis 3) Conductance 4) Non-blanked area 5) Conforms to API RP13C 6) Manufacturer’s name 7) Manufacture’s designation 8) Country of origin 9) Lot, date, order number 10) Bar code An example of the screen label is shown in Figure 4-7. Figur e 4-7. Screen Label
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NOV manufactures and markets API RP 13C/ISO 13501 compliant screens. API screen testing is conducted in-house at the Conroe manufacturing facility. The API requires three test data on the screen label, screen cut point, conductance and non-blanked area. The screen cut point is expressed as the API Screen Number or API Screen Designation. The API screen number designation is empirically determined by the test procedures described in Clause 9 of API RP 13C (Table 4-4). This method determines the D100 separation potential of a given screen compared to the separation potential of an equivalent ASTM test sieve, using aluminum oxide test media on a Tyler “RoTap.” The use of the term “D100 Separation Potential" allows for performance variations due to diverse factors including solids loading, fluid viscosity, shaker dynamics, drilled solid consistency and shape. D100 Separation Potential is a function of screen composition and construction only. Table 4-4. API RP 13C Screen Design ation
D100 Separation, μm > 3075,0 to 3675,0 > 2580,0 to 3075,0 > 2180,0 to 2580,0 > 1850,0 to 2180,0 > 1550,0 to 1850,0 > 1290,0 to 1550,0 > 1090,0 to 1290,0 > 925,0 to 1090,0 > 780,0 to 925,0 > 655,0 to 780,0 > 550,0 to 655,0 > 462,5 to 550,0 > 390,0 to 462,5 > 327,5 to 390,0 > 275,0 to 327,5
D100 Separation and API Screen Number API s cr een # D100 Separation, μm API 6 > 231,0 to 275,0 API 7 > 196,0 to 231,0 API 8 > 165,0 to 196,0 API 10 > 137,5 to 165,0 API 12 > 116,5 to 137,5 API 14 > 98,0 to 116,5 API 16 > 82,5 to 98,0 API 18 > 69,0 to 82,5 API 20 > 58,0 to 69,0 API 25 > 49,0 to 58,0 API 30 > 41,5 to 49,0 API 35 > 35,0 to 41,5 API 40 > 28,5 to 35,0 API 45 > 22,5 to 28,5 API 50 > 18,5 to 22,5
API scr een # API 60 API 70 API 80 API 100 API 120 API 140 API 170 API 200 API 230 API 270 API 325 API 400 API 450 API 500 API 635
Conductance, measured in units of kilodarcies/mm, defines the ability of a Newtonian fluid to flow through a unit area of screen in laminar flow with all other variables being equal. The procedure is described in Clause 8 in API RP 13C. Conductance is only one variable among many that determines the actual "flow capacity" of a given screen in field use. Flow capacity of a shaker screen is the rate at which a screen can process drilling fluid and drilled solids. It is a function of many variables including: a) shale shaker configuration; b) shale shaker design; c) shale shaker motion; d) drilling fluid rheology; e) solids loading; f) particle size distribution; g) screen opening size; h) screen construction. Screens having an API designation of < 40 are not tested for conductance because the screens are too porous to contain a constant head of oil for measuring the conductance. The non-blanked area of a screen describes the net unblocked area in square feet or square meters available for the passage of fluid; generally, more un-blanked area, the better. For specific details of the above test procedures please refer to API RP 13C. 44
4.3.4 Screening Surfaces
Screening surfaces used in solids control equipment are generally made of woven wire screen cloth in many different sizes and shapes. Screens may be constructed with one or more layers. Non-layered screens have a single layer, fine-mesh, screen cloth (reinforced by coarser backing cloth) mounted on a screen panel. These screens have openings that are regular in size and shape. Layered screens have two or more fine mesh screen cloths, usually of different mesh (reinforced by coarser backing cloth), mounted on a screen panel. These screens have openings that vary greatly in size and shape. To increase screen life, especially in the API 120 - 200 screens, manufacturers have incorporated two design changes: 1.
A coarse backing screen to support fine screens
2.
Pretension screen panels.
The most important advance has been the development of pretension screen panels. Similar panels have been used on mud cleaners since their introduction, but earlier shakers did not possess the engineering design to allow their use successfully. With the advent of modern, linear-motion shakers, pretension screen panels have extended screen life and justified the use of fine (API 200 or finer) screens on the shale shakers at the flowline. The panels consist of a fine screen layer and a coarse backing cloth layer bonded to a support grid. (Figure 4-8) The screen cloths are pulled tight, or tensioned, in both directions during the fabrication process for proper tension on every screen. The pretension panel is then held in place in the bed of the shaker.
Figure 4-8. Pretension Screen
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Fine screens may be reinforced with one or more coarse backing screens. The cloth also may be bonded to a thin, perforated metal sheet. This extra backing protects the fine screen from being damaged and provides additional support for heavy solids loads. The screens equipped with a perforated plate may be available with several size options for the perforation to allow improved performance for a given situation. Most manufacturers limit themselves to one support grid opening size to reduce inventory and production costs. The opening size is typically 1” for maximum mechanical support. NOV provides screen panels with a variety of openings to allow rig personnel to choose the desired mechanical support and a total open area for their application.
Mesh is defined as the number of openings per linear inch. Mesh can be measured by starting at the center of one wire and counting the number of openings to a point one inch away. This figure shows an eight (8) mesh screen. The industry also uses rectangular mesh screens, which has made counting the mesh sizes more complicated. Figure 4-10 shows two screens having the same mesh count, 8-mesh screens.
The API stopped using the word mesh in 2005 and started using the API screen numbers (designation) as discussed in ISO 13501, first edition, 2005-12-01 and API RP 13C, third edition, December 2004.
Figur e 4-9. 8-Mesh Screen
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Screen Cloth
There are several types of wire cloth used in the manufacture of oilfield screens. The most common of these are Market Grade and Tensile Bolting. Both of these are square mesh weaves, differing in the diameter of wire used in their construction. Market Grade cloths use larger diameter wires and are more resistant to abrasion and wear. Tensile Bolting cloths use smaller diameter wire and have a higher conductance. Since screen selection is a compromise between screen life, liquid capacity and particle separation, both types are widely used. Screen Opening Size versus Mesh Coun t
Size of opening is the distance between wires in the screen cloth and is usually measured in fractions of an inch or microns. Mesh count is the number of openings per inch starting at the center of one wire and going out one inch. The figure below shows two screens having the same mesh count, 8-mesh screens.
Figur e 4.10. Two 8-Mesh Screen
Screens of the same mesh may have different sized openings depending on the diameter of the wire used to weave the screen cloth. Smaller diameter wire results in larger screen openings, with larger particles passing through the screen. The larger the diameter of the wire having the same mesh, the smaller the particles that will pass through the screen. Also, normally the larger the diameter of the wire used in the weaving process, the longer the screen cloth will last. As stated earlier, in 2005 the industry stopped using mesh as a means of describing a screen.
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Shape of Opening The shape of the opening is determined by the screen’s construction. Screens with the same number of horizontal and vertical wires per inch produce square-shaped openings and are referred to as square mesh screens. Screens with a different number of horizontal and vertical wires per inch produce oblong - or rectangular - shaped openings and are referred to as rectangular (or oblong) mesh screens. This is illustrated in Figure 4-11. Screen openings and mesh are not discussed in comparing screens; instead comparisons are based on conductance as described in API RP 13C.
Figure 4-11. Shape of Opening
Screen Plugging and Blin ding Screen plugging and blinding, while present to some degree on shale shakers fitted with coarser screens, is most frequently a problem with fine screen shakers. If the screen openings plug with near-size particles or if the openings become coated over, the throughput capacity of the screen can be drastically reduced and flooding (loss of whole mud) of the screen may occur. Plugging can often be controlled by adjusting the vibratory motion or deck angle, but it normally is a temporary remedy. Changing to a finer screen often presents a better, more permanent solution. Screen blinding can be caused by sticky formation solids, un-hydrated polymers added to the mud system; or grease or other substances that block screen openings. Screen blinding requires that the screens be washed to open the screen openings. This cleaning may be accomplished with a high pressure water hose or, in the case of plugging caused by oil, grease, pipe dope, asphalt or oil-base mud, using a solvent to free the plug. Stiff brushes should not be used to clean fine screens because of the fragility of the screen cloth. 48
When plugging or blinding occurs, whole mud losses can result and something must be done quickly. Screen washing should be tried first. If this doesn’t solve the problem, the use of finer screens should be tried. The life of fine screens varies widely. It can be maximized by following these general precautions: •
Keep screens clean
•
Handle screen carefully when installing
•
Keep screens properly tensioned
•
Do not overload screens
•
Do not operate dry shakers
Screen Capacit y
Screen capacity, or the volume of mud which will pass through a screen without flooding, varies widely depending on shaker model and drilling conditions. Drilling rate, mud type, weight, viscosity, bit type, formation type and screen mesh all affect capacity to some degree. Drilling rate affects screen capacity because increases in drill solids loading, reduces the effective screen area available for mud throughput. The conductance of the screen in use also is directly related to shaker capacity because, in general (but not always), the lower the conductance, the lower the throughput. Increased viscosity, usually associated with an increase in percent solids by volume and/or increase in mud weight, has a markedly adverse effect on screen capacity. As a general rule, for every 10% increase in viscosity, there is a 2–5% decrease in throughput capacity. Mud type also has an effect on screen capacity. Higher viscosities generally associated with oil-base and invert emulsion mud usually result in lower screen throughput than would be possible with a water-base mud (WBM) of the same mud weight. Some mud components, such as polymers in WBM, also have an adverse effect on screen capacity. As a result, no fine screen can offer a standard throughput for all operating conditions. Due to the many factors involved in drilling conditions, mud characteristics and features of certain models, screen handling capacities can range from 50 to 800 gpm. Multiple units, most commonly dual or triple units, are used for higher circulation rates. Cascade shaker arrangements, with coarse-screened scalping shakers installed upstream of the fine screen shakers, also can increase throughput. 49
Three-Dimensio nal Screen Panels
Three-dimensional screen panels were developed to increase screen capacity without increasing the size or number of shale shakers. These corrugated shaker screens:
• Provide more screen area if the screens are flooded • Should always be flooded to realize full benefit of handling capacity • Can plug easily on the up and down slope of the screen’s corrugations 3-D screen panels increase the usable screen area of a screen panel by corrugating the screen surface, similar to the surface of a pleated air filter or oil filter. 3-D screen panels are most effective when installed as the submerged, feed-end screen on a linear-motion shaker to take full advantage of the additional screen area. Past the fluid end point, a three-dimensional screen tends to “channel” the drilled solids and increase solids bed depth and the amount of liquid carried off the screen surface. Using a flat screen at the discharge end of the shaker eliminates channeling, increases cuttings dryness and decreases fluid loss. Standardization The American Petroleum Institute (API) approved the recommended practice (RP) 13C, third edition December 2004 for shale shaker screens used in the oil field. The API RP 13C has an ISO equivalent, ISO 13501, first edition 2005-1201. NOV manufactures and markets API RP 13C compliant screens for the oil industry.
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5
GUMBO SEPARATORS
A Gumbo Chain® (Figure 5-1) is recommended as the first step in drilled solids removal especially where young unconsolidated formations are present such as in the Gulf of Mexico. The NOV Gumbo Chain can process high volumes of drilling fluid while removing gumbo and sticky clays that would blind rig shakers. The optional integrated flow divider can feed up to eight shakers from one Gumbo Chain, eliminating additional equipment and allowing for a compact instillation. The Gumbo Chain may be easily bypassed. The Gumbo Chain can be fitted various sized chain opening in accord with the customer’s requirements. The units can be single or dual with various sized chain openings, in accord with the customer's requirements, and can handle from 1500 to 3800 gallons per minute.
Figure 5-1. Gumbo Separator
Figur e 5-2. 1” Chain
Figur e 5-3. Six (6) Mesh Chain/Scr een 51
6
SHALE SHAKERS 6.1
Introduction
The most important solids control piece of equipment is the shale shaker. Without proper screening of the drilling fluid, reduced efficiency and effectiveness of downstream solids control equipment on the rig is almost a certainty. The shale shaker, in various forms, has played a prominent role in oilfield solids control schemes for decades. Shakers have evolved from small, relatively simple devices capable of running only the coarsest screens, to the models of today. Modern, high-performance shakers are able to use API 150 screens or finer while drilling top hole. The evolutionary process has taken us through four distinct eras of shale shaker technology and performance. (Figure 6-1)
Figu re 6-1. Shale Shakers
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These eras of oilfield screening development may be defined by the types of motion produced by the machines: • • • •
Elliptical, “unbalanced” design Circular, “balanced” design. Linear, “straight-line” design Elliptical, balanced and tuned
The unbalanced (unbalanced means the vibratory motion is not consistent throughout the bed of the shaker) elliptical motion machines have a downward slope. (Figure 6-2) This slope is required to properly transport cuttings across the screen and off the discharge end. This downward slope reduces fluid retention time and limits the capacity of this design. Optimum screening with these types of shakers is usually in the API 30 to 40 screens (400–600 micron) range.
Figure 6-2. Ellipti cal Unbalanced Motion
The next generation of machine, introduced in the late 1960s and early 1970s, produces a balanced, or circular, motion. (Figure 6-3) The consistent, circular vibration allows adequate solids transport with the basket in a flat, horizontal orientation. This design often incorporates multiple decks to split the solids load and to allow finer API screens, such as API 80 to 100 (137–196 micron) screens.
Figure 6-3. Circular Mot ion
The linear or straight-line motion shakers are some of the best shakers in the oilfield. Linear motion (Figure 6-4) is developed by a pair of eccentric shafts rotating in opposite directions. Linear motion provides superior cuttings conveyance and is able to operate at an uphill slope to provide improved liquid retention. Better conveyance and longer fluid retention allow the use of API 200 (74 microns) screens while drilling upper hole.
Figure 6-4. Linear Moti on 53
The balanced elliptical and tuned elliptical shakers are the latest improvements in shale shakers. The elliptical and tuned motion gently clears the screen of solids and allows for a flat or slightly inclined bed. The VSM 300 shaker was the first balance elliptical shaker on the market. Today, shale shakers typically are separated into two categories: Rig Shakers and Fine Screen Shakers. Rig Shakers The rig shaker is the simpler of two types of shale shakers. A rig shaker (also called “Primary Shale Shaker” or “Coarse Screen Shaker”) is the most common type of solids control equipment found on drilling rigs. Unless it is replaced by a fine screen shaker, the rig shaker should be the first piece of solids control equipment that the mud flows through after coming out of the hole. It is usually inexpensive to operate and simple to maintain.
Figure 6-5. Standard Rig Shaker
Standard rig shakers (Figure 6-5) generally have certain characteristics in common: • Single rectangular screening surface — usually about 4’ x 5’ (1.2 meter x 1.5 meter) in size. Some designs have utilized dual screens, dual decks and dual units in parallel to provide more efficient solids separation and greater throughput. Depending on the particular unit and screen used, capacity of rig shakers can vary from 100–1600 gpm (379-6056 liter/min). • A low-thrust horizontal vibrator mechanism, using eccentric weights mounted above, or central to, the screen basket. Vibration supports to isolate the screen basket from its skid. • • Skid with built-in mud box (sometimes called a “possum belly”) and a bypass mechanism. Method of tensioning screen sections. • Rig shakers are generally adequate for top-hole drilling and for shallow and intermediate depth holes when backed up by other solids control equipment like Desanders, Desilters and a Centrifuge. NOV still markets the Brandt Tandem and Standard shakers for selected projects. Screen sizes commonly used with rig shakers range from API screen 10 to 45 (2071 μ to 370.5 μ. Figure 6-6 shows example curves of the particle sizes separated by rig shakers using coarse screens. Let’s focus on one screen size on the graph and discuss what the graph tells us. If we select the API 10 screen, the one to the far right, we can see that the screen removes all solids (100%) larger than about 2071 microns. The screen will remove about 50% of solids that are about 1100 microns in size. 54
Figure 6-6. Screens Used on Rig Shakers
A typical solid separation graph for an API 70 screen used in the field with a waterbased mud is shown in Figure 6-7. This graph will be used to explain how graphs are read.
The y-axis indicates the percentage of the solid particles removed by the screen. The separation curve shows that all particles larger than 212 microns (μ) are removed (refer to the Figure). A vertical line drawn, or imagined, from the point where the graphed line crosses a horizontal line from the 100% point on the y-axis intersects the horizontal x-axis, which represents particle size, at 212 μ. At 90% y-axis, 90% of all particles are removed and 10% remain in the mud. Following the same procedure as discussed above, we start at the left at 90% on the y-axis, and draw, or imagine, a horizontal line to the right to a point where it intersects the graphed line. A vertical line drawn from that point to the x-axis indicates that 90% of the 58 μ particles are removed and 10% are left in the mud. Similarly, the graph indicates that half of the 35 μ particles are removed and 50% are retained. 55
Reading the Screen Graph 100%
100% of solids > 212 μ are removed
90%
90% of solids 58μ are removed
80% n e e r c S y b d e v o m e R s e l c i t r a P %
70% 60% 50%
50% of solids 35 μ are removed
API 70
40% 30% 20%
20% of solids 25 μ are removed
10% 0% 1
10
100
1000
10000
Part icle Size (microns)
Figur e 6-7. Reading a Parti cle Size Analysi s (PSA) Graph
Fine screen shakers are preferred for deeper holes and for expensive mud systems. These shakers can utilize coarse to fine screens, ranging from API 40 to API 450. During normal drilling operations the screen selection for a fine screen shaker will be in the range of API 100 to API 200. When a weighted mud is used, care may be required to avoid the removal of too much barite. API specifications allow as much as 3% of the weight material to be over 74 microns. The loss of this material may be preferable to the retention of more drilled solids resulting from a change to screens with larger openings. Barite ground finer is available at additional costs, but limiting the larger particles unavoidably increases the concentration of smaller particles which can pose viscosity and other problems. Another example of reading a PSA is shown in Appendix J 19.10.2. A centrifuge processing mud was reducing the mud weight from 8.9 ppg (feed) to 8.6 ppg (effluent). By the reduction in mud weight one knew the centrifuge was working. Using the PSA data one can evaluate the size of solids being removed. The example shows the PSA for the feed and the effluent. Comparing the two PSA’s one can conclude that about 25% of the solids larger than 15.56 microns were removed by the centrifuge.
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Figure 6-8. King Cobra and VSM Shakers
Fine Screen Shakers
The fine screen shaker is the more complex and versatile of the two types of shale shakers. Fine screen shakers are designed for greatly improved vibratory efficiency compared to that of simple rig shakers. They vibrate in linear or elliptical motion in a manner that extends screen life with finer screens. Fine screen shakers are versatile pieces of equipment that can be used with any mud. The chart below (Figure 6-9) shows typical separation curves for several commonly used screens. Screens Used on Fine Screen Shakers 100%
API 100
90% 80% n e e r c S y b d e v o m e R s e l c i t r a P %
API 120 70% 60% 50%
API 140
40% 30% API 170
20% 10% 0% 10
100
1000
API 200
Particle Size (microns)
Figur e 6-9. Screens Used o n Fine Screen Shakers
Because fine screen shakers have a wide variety of designs, they have a few characteristics in common. The various designs are differentiated by screen orientation and shape, screen tensioning mechanism, placement and type of vibrator and other special features. 57
Horizontal Deck, Single Screen
Sloped Deck, Triple Screen Sloped Deck, Single Screen
Horizontal Deck, Double Screen
Mixed Deck, Double Screen
Figure 6-10. Screens and Orientation
Single deck, single screens (horizontal deck single screen and sloped deck single screen) are the simplest design, with all mud passing over one screen of uniform mesh. This type of shaker requires efficient vibrator mechanisms to function properly under all possible drilling conditions and requires high throughput (conductance) per square foot of screen cloth. Units with screens placed in parallel (mixed deck double screen and sloped deck triple screen) have two or more screen sections acting as one large screen so that no cuttings can fall between them. All screen sections should be the same API screen, since the coarsest screen section determines the unit’s screening capability. Shakers with screens stacked in series (horizontal deck double screen) have a coarse screen above a finer screen, with the finer screen controlling the final size of solids being removed. The operating theory is that the top screen will remove some of the cuttings from the mud to reduce the load on the bottom screen and increase screening efficiency.
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6.1.1 Screen Tensioning Mechanisms Shakers are designed to use either a hook strip or a rigid panel (pretension) screen. Hook strip screens are made without a rigid frame and can prematurely fail if allowed to operate with uneven tension. The shaker manufacturer instructions for screen installation should be followed, but the following steps usually apply: Inspect the supports and tension rails to be sure they are in good condition • and clean Position the panel on the deck and inspect the screen to be sure it lays flat • • Install both rails loosely to the hook strip • Push one side of the screen against the positioning blocks, if present; and tighten the screen against these blocks • Evenly tighten the tension bolts on the other side Torque to manufacturer’s recommended setting • Pretension screen panel installation should proceed as per the manufacturer’s instructions. Panel screens usually can be installed or replaced much quicker than a hook strip screen since the cloth already is tensioned and the mechanical devices lock the panel with much less manual effort. Pretension screen also will outperform hook strip screens using the same screen material. 6.1.2 Vibrator Mechanisms Vibrator mechanisms vary widely in design and placement and greatly affect the capacity of fine screen shakers. Most modern shakers utilize balance elliptical, tuned elliptical or linear motion vibration with the vibrator mechanism mounted above the screen bed. One important advantage of linear motion is positive conveyance of cuttings across the screen surface even when the surface is at a positive angle. This generally allows the use of an uphill sloped screen deck, greatly increasing throughput capacity and cuttings dryness. Most vibrators are electrically operated, although a few are hydraulically operated. In some units the vibration-inducing eccentric weights are separated from the drive motor, while in others the eccentric weights and motor form an integral part of the assembly. In some units, the nature of the vibratory motions can be easily modified to take advantage of specific solids-conveying characteristics, but most units have a fixed vibratory motion. 6.1.3 Maintenance Because of their greater complexity and use of finer screens, fine screen shakers require more attention than rig shakers. Nonetheless, their more effective screening capabilities justify the higher operating cost. This is especially true when expensive mud systems are used. Besides periodic lubrication, fine screen shakers require the same minimum maintenance as rig shakers. During trips: Wash down screens. • Check screen tension (if hook-strip). • • Shut down shaker when not drilling to extend screen life. Dump and clean possum belly. Try to do this when changing out a mud so the • solids can be removed from the mud system. In addition, frequent checks must be made for screen plugging and blinding, screen flooding and broken screens. All will occur more frequently on fine screen shakers than on coarse mesh rig shakers. 59
6.1.4 General Guidelin es General guidelines for operating shale shakers include the following: Use the finest screen capable of handling the full volume from the flowline • under the particular drilling conditions. This will reduce solids loading on downstream equipment, therefore improving their efficiency. Several screen changes, normally to progressively finer screens over the course of the hole, are quite common. • Large cuttings which settle in the mud box (possum belly) of the shaker should never be dumped into the mud system. Dump the solids into the sump or waste pit. Small vacuum pumps also can be used to remove settled solids for proper disposal. All mud should be screened unless lost circulation material is added to the mud • or if special sized particulate is being added to the mud system for a specific reason. All make-up mud hauled in from other locations should be screened before use. Unless water sprays are absolutely necessary to control screen blinding, water • should not be used on the screen surface while drilling. Water sprays tend to wash smaller cuttings through the screen which would otherwise be removed by their clinging to larger particles (piggy-back effect). For a more complete analysis of different types of screens and shakers, ask your local NOV representative for copies of the latest Product Bulletins/Brochures for the specific shaker installed on your rig.
6.2
Shale Shaker Product Line and Options
6.2.1 Optional Upgrade Kit for Linear Motion Shakers All NOV linear motion shakers can be ordered with an upgrade kit that adds a variable frequency drive (VFD) controller so rig hands can change the speed of the vibratory motors to give varying G-force. By varying the G-force one can extend screen life by reducing the G’s as hole size and solids loading decrease (Table 6-1).
Table 6-1. King Cobra Shaker w ith Optional VFD Controller
Setting
G’s
Hole Section
NORMAL
6.1
Production
HIGH
6.7
Intermediate
MAXIMUM
7.3
Top
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6.2.2 Mini Cobra 2-Panel
The Mini Cobra 2-Panel is a two panel, linear-motion shaker that shares many parts with other Cobra series shakers; including screens, screen support material and hammerwedge screen fasteners. (Figure 6-11) This simplifies inventory requirements for contractors using Cobra series shakers.
Figur e 6-11. Mini Cobr a 2-Panel
Multiple units can be supplied on a single skid and feature a common feed tank. The single skid and common feed tank arrangement helps reduce installation time and cost, while ensuring a balanced flow to each shaker. The Mini Cobra 2-Panel generates 6.4 G’s of efficient linear motion while rapidly removing drilled solids, saving valuable drilling fluid and reducing drilling waste. NOV’s hammerwedge design makes screen changing simple. The heat, chemical and corrosion resistant hammerwedge can be installed and removed easily using only a hammer or pry bar. NOV’s exclusive BHX Venom screen is field repairable, extending the service life of the screen. The reusable plug forms a tight, leak-proof seal. The basket design sets the feed end at 0º and the discharge panels at +5º. These basket angles minimize liquid pool depths which reduces fluid weight on the screens. The screen deck is adjustable. The flat screening surface distributes fluid evenly across the shaker. The low weir height of 15 inches (386 mm) allows the Mini Cobra 2-Panel to fit on smaller land rigs where flow line slope is critical. The Mini Cobra 2-Panel has 16.8 square feet (1.6 mm²) of screen area.
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6.2.3 Mini Cobra 3-Panel The Mini Cobra 3-Panel is a three panel linear motion shaker that shares many parts with other Cobra series shakers, including the screens, screen support material and hammerwedge screen fasteners. (Figure 6-12) This simplifies inventory requirements for contractors using Cobra series shakers.
Figur e 6-12. Mini Cobr a 3-Panel
The Mini Cobra 3-Panel has 25.5 square feet (24.4 mm²) of screen area. The low weir height of 24 inches (610 mm) allows the Mini Cobra 3-Panel to fit on smaller land rigs where flowline slope is critical. Multiple units can be supplied on a single skid and feature a common feed tank. The single skid and common feed tank arrangement helps reduce installation time and cost while ensuring a balanced flow to each shaker. The Mini Cobra 3-Panel generates 6.6 G’s of efficient linear motion, rapidly removing drilled solids, while saving valuable drilling fluid and reducing drilling waste.
6.2.4 Cobra The Cobra shaker is a three panel linear motion shaker that shares many parts with other Cobra series shakers, including screens, screen support material and hammerwedge screen fasteners (Figure 6-13). For contractors with Cobra series shakers in their fleet, this simplifies inventory requirements.
Figur e 6-13. Cobr a
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With minimal replacement parts, Cobra shakers provide years of dependable, economical service. Performance is exceptional; detrimental drilled solids are removed with efficient linear motion and 5.4 G’s. Mud loss is minimized and cuttings dryness is enhanced with NOV’s patented drying deck and the new flow diverter plate. The drying deck also saves space by reducing the overall footprint. Dual Cobra shakers have a common back tank, reducing installation time and cost, while ensuring a balanced flow to each shaker. The drive system is simple, reliable, low maintenance and field proven. NOV’s heat, chemical and corrosion resistant hammerwedges are used to secure the pretension screens to the shaker deck. The pretension screens are field repairable. The screen plug forms a tight, leak-proof seal. The Contour Plus basket design mounts the feed end panel at 0º and the other panels inclined at +5º. This minimizes liquid pools and reduces undue weight on the screens. The weir height is 41” and can be modified to 37” if necessary. With features like Contour Plus and the NOV patented drying deck, cobra shakers save valuable fluids, remove more detrimental drilled solids, extend screen life and optimize screen coverage. 6.2.5 King Cobra The King Cobra shaker is a four-panel, linear-motion shaker that shares many parts with other Cobra series shakers, including the screens, screen support material and hammerwedge screen fasteners (Figure 6-14) The King Cobra shaker is recognized as the industry leader for cost-effective performance. Multiple units can be supplied on a single skid and feature a common feed tank. This feature reduces installation installatio n time and cost, while ensuring a balanced flow to each shaker. Performance is exceptional; detrimental drilled solids are removed with efficient linear motion using field repairable pretension screens. Mud loss is minimized and cuttings dryness is enhanced with the Brandt patented drying deck and flow diverter tray. The drying deck also saves space by reducing the overall footprint.
Figure 6-14. King Cobra
The weir height is 41” (104 cm) cm) and can be modified to 37” (94cm) if necessary. The King Cobra generates 6.1 G’s of efficient linear motion rapidly removing drilled solids, while saving valuable drilling fluid and reducing drilling waste. The heat, chemical and corrosion resistant hammerwedges are used to secure the pretension screens to the shaker deck. The pretension screens are field repairable. The screen plug forms a tight, leak-proof seal. 63
6.2.6 King Cobra II
The King Cobra II has several unique automated features (see Figure 6-15). 6-1 5). This shaker can handle more flow than other shakers without losing fluid because the unit can monitor fluid levels on the shaker and can optimize its configuration automatically. Features of the King Cobra II include: • • • •
•
•
•
Automatic bed angle angle adjustment adjustment increases increases flow capacity. capacity. Automatic G-force increase increase at high fluid loading. loading. Requires less rig hand involvement than other shakers. Reduces mud cost – minimizes mud losses while handling large flow rates. Reduces screen cost – promotes longer screen life by keeping screens flooded. Operational simplicity – dual motion (elliptical or linear) capability at the flip of a switch. Has manual override.
Figur e 6-15. 6-15. Kin g Cobr a II
The King Cobra II operates optimally because the deck angle is adjusted automatically (patented) to keep fluid flow at the end of the third shaker screen as the flow rate changes. If the shaker becomes overloaded and the shaker basket reaches maximum tilt, the unit will automatically provide a boost in G-force (7.3 G’s). The increase in G’s will temporarily help clear the screen of solids and then will automatically return to normal operation. All these automated features allow rig hands to stay out of the shaker room for extended periods when the system is operating because the system system is self-adjusting. The unit also promotes longer screen life since screens are constantly covered with fluid. Four pretension field repairable screens are used and the shaker shares common parts with the other Cobra series shakers: including screens, screen support material and hammerwedge screen fasteners. The shaker has a dual motion drive system, linear or tuned elliptical and a manual override of the automated features for operational simplicity. This set of features provides a unique combination of optimized performance, extended screen life, reduced worker exposure, operational simplicity and reduced losses of whole mud. Fluid loss is minimized and cuttings dryness is enhanced with NOV’s patented drying deck and flow diverter tray. The drying deck saves space by reducing the overall footprint. NOV’s heat, chemical and corrosion resistant hammerwedges are used to secure the pretension screens to the shaker deck. The pretension screens are field repairable; the screen plug forms a tight, leak-proof seal. 64
6.2.7 King Cobra Venom Venom The King Cobra (KC) Venom (Figure 6-16) has several features that are utilized by all KC models. The basic shaker basket and back tank will be basic to all KC shakers and customers will be given the opportunity to select options as needed for their specific drilling conditions. The Venom has several unique features as shown in Table 6-2.
Figure 6-16. King Cobra Venom Table 6-2 6-2.. Features Features & Benefits f or t he King Cobra Venom Shaker Shaker
Features
Benefits
Unique, rugged basket design
Provides improved energy transfer from the shaker basket to the screen, thus improving solids separation Few replacement parts Requires only a small parts inventory, thus enabling cost savings to be realized Linear motion (available in all configurations) Rapidly separates and discharges solids Tuned elliptical motion (available on models configured with the dual motion option) Dual motion configuration
Patented drying deck Exclusive shaker screen deck angles (0º, +5º, +5º, +5º) Low weir height of 34.5 inches (876 mm) Modular back tank design
Easily removes large, sticky hydrated clays and other troublesome solids Allows the user to select the vibration motion that bests fits the drilling situation Reduces mud losses Keeps the mud pool volume small, thereby increasing screen life Enables installation on a wide variety of rigs, including those where space is limited Provides reduced tank volume which decreases solids settling Offers bolt-on link sections (no welding required) for multiple-shaker configurations Provides adjustable, stainless steel weir gates with a bottom feed to reduce solids settling Prolonged shaker life
New epoxy and glass flake paint system Utilization of VNM series screens
Improved wiring harness
Eliminates the need for crown rubbers 2 2 Offers 34.5 ft (3.1 m ) of screening area Utilizes screens that are repairable Eliminates screen leakage and mud by-pass via individually sealed screens Keeps wires securely attached to bed
Redesigned screen wedge
Permits easier installation using a pry bar
New basket, skid and possum belly
Makes interchanging parts easy
Pushbutton (pneumatic) single-point deck angle adjustment mechanism
Allows quick and easy deck angle angle adjustments 65
6.2.8 VSM 300 300 Shale Shak er The VSM 300 was the world’s first balanced elliptical motion, low profile, cascade shaker. The VSM 300 delivers dramatic increases in throughput capacity through unique vibratory motion and screen deck layouts (see Figure 6-17). The VSM 300 is the ultimate shaker for all drilling applications!
Figure 6-17. VSM 300
The VSM 300 offers improved flexibility by employing variable ‘G’ force using a Variable Frequency Drive (VFD). Simply at the push of a button, the VSM can be operated at 4, 6 or 8 G’s – thereby allowing the operator to contend with variable flow rates, fluctuating fluid conditions and drilling breaks without the need to stop or bypass the unit. The VSM 300’s unique drive motion delivers significant improvements in the transportation of sticky hydrated clays – often encountered when drilling top hole sections with water based fluids. The use of integral secondary drying technology, demonstrates NOV’s commitment to delivering cost effective, environmentally responsible solutions to the oil industry. The VSM 300 is an extremely simple machine to operate; maintenance requirements are minimal and screens can be changed in two-to-three minutes by one operator. The VSM 300 uses genuine NOV screens. These screens provide exceptional capacity and unsurpassed life. The screens are clamped into the unit with the pneumoseal air inflatable clamping system. Supplied with a highly effective integral scalping deck, deployment of the VSM 300 reduces the need for upstream scalping shakers, thereby removing the cost and weight burden. Significant benefits also are derived from incorporation of a novel 7º ‘Through Ramp’ on the lower (primary) deck. The balanced elliptical drive system along with the 7º ‘Through Ramp’ provides excellent solids conveyance even when reactive formations are encountered. The VSM 300 employs ‘Integral Drying Modules’ whereby appreciable savings in fluids can be achieved by drying the solids on the shaker itself, without the need for expensive secondary ‘High G’ drying equipment. The reduction in fluid discharge delivers immediate cost and environmental benefits. 66
With due consideration of HSE requirements, the VSM 300 can be assembled on site to produce multiple units, thereby reducing installation time and cost (Figure 6-18).
Figure 6-18. Multiple VSM Units
NOV’s proven shallow header tank system is used to optimize flow distribution across multiple units. The shakers also can be fitted with hoods to vent any noxious fumes away from rig personnel. (Figure 6-19)
Figur e 6-19 VSM 300 Fitted w ith Vent Hoods
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Table 6-3. Featur es & Benef its of VSM 300
Features
Benefits
Balanced elliptical motion
Effective removal of sticky, hydrated clays
Adjustable G-force
Adjustments in G-force to adapt to changes in drilling conditions
Integrated scalping deck (3 screens)
Reduces the need for (and subsequent costs and weight) upstream scalping shakers and/or gumbo equipment • 1.9 m² (20.5 ft²) screen area
Integrated drying deck (2 screens optional)
Reduces mud losses by creating a dry sol ids discharge •
0.3 m² (3.0 ft²) screen area
Pneumoseal clamping system
Screens are properly secured to the basket for quick, easy screen changes
Variable frequency drive (VFD) control
Soft starting, fingertip adjustments of motor speed and matching G-force to operating conditions
6.2.9 NOV Automated Shaker Contr ol
NOV was the first company to supply the industry with a shale shaker that can automatically adjust to changing drilling conditions. Automated Shaker Control (ASC) is designed to optimize the VSM 300 operating efficiency and to remove personnel from the shaker house environment. The VSM 300 also is the quietest high specification shaker on the market with single shakers generating a maximum noise level of 67 dBa and a complete multi shaker package being as low as 73 dBa. The system monitors fluid levels within the header tank and each shale shaker. Using these levels, the system automatically controls the mudflow to each shaker and brings on or off-line the optimum number of shakers for the volume of drilling mud being processed. The main advantages gained when utilizing the ASC are listed below: •
Expensive whole mud losses over the shaker screens are prevented.
•
Screen life is maximized.
•
•
Personnel exposure to the hazardous environment within the shaker house is minimized. Rig personnel are automatically alerted when screens fail, minimizing the recirculation of separable solids. 68
The shaker house can be an unpleasant working environment and can foster an aversion to monitoring and adjusting the shale shakers as attentively as desired. ASC makes these adjustments automatically, relieving operators from the task of continually monitoring and making adjustments as flow rates, viscosity, or the solids content of the drilling fluid changes. Efficient solids control is assured by automatic adjustments in response to changing conditions. Audible and visual alarms notify personnel of the need for shaker attention. The operator can easily isolate a shaker for minor maintenance or screen changing. Screen displays in the shaker room can be networked to other terminals on the rig. An optional system offers remote/ manual control utilizing the hydraulic control station and hydraulically actuated feed chutes. ASC is proprietary to VSM 300 shale shakers and is applicable to both floating and fixed installations. ASC can enhance solids control efficiency and rig economics. ASC can detect screen failures or screen plugging by monitoring the change in process capacity of each shaker. Timely screen cleaning reduces liquid losses, while prompt screen replacement minimizes contamination of the drilling fluid. Rig personnel are freed from tedious shaker monitoring and can spend their time on more productive tasks.
6.2.9.1 ASC Func tio nali ty When flow rate or viscosity increases 1. More shakers are brought on line automatically. 2. The G force is automatically boosted for all shakers for a set amount of time. 3. If still more throughput is required, the beach length is automatically reduced, preventing mud loss from shakers. When flow rate or viscosity decreases 1. The number of operating shakers would automatically be decreased, so that the fluid level is maintained at its optimum for each shaker. 2. Finer screens will be fitted on the shakers, thus improving solids control efficiency and reducing drilling fluid dilution. Screens within the non-running shakers need not be compromised. 3. Excessively long beach lengths are automatically avoided, diminishing the negative effects of non-wetted screen surfaces.
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6.2.10 VSM Multi-Sizer
In 2009 NOV introduced the VSM Multi-Sizer, a new and innovative shale shaker (Figure 6-20). The reliable, operator friendly VSM® Multi-Sizer separator provides high performance and flexibility for modern-day drilling practices. The VSM Multi-Sizer separator is the first to introduce Constant-G Control® to provide optimum performance to meet drilling rates and separation efficiency.
Figur e 6-20. VSM Mult i-Sizer
“ In-Series” Operating Mode
The primary function of the VSM Multi-Sizer separator, while in the in-series mode, is to collect lost circulation and/or wellbore stabilization materials. In this mode, each of the three screening decks is equipped with screens of differing API designations. The Scalping Deck is outfitted with screens for coarse solids removal. Primary Deck 1 is outfitted with API-designated screens that allow for the collection of the desired recoverable solids, such as lost circulation or wellbore stabilization materials. The desired material is conveyed off the screens of Primary Deck 1 and into a collection trough. The trough is angled to route the collected material down two recovery trough sections of the machine and into the sump and active mud system. Primary Deck 2 is outfitted with APIdesignated screens that allow for the removal of low-gravity solids and other fines. “ In-Parallel” Operating Mode
The primary function of the VSM Multi-Sizer separator, while in the in-parallel mode, is to maximize screening capacity and throughput. The Scalping Deck is outfitted with screens for coarse solids removal, while Primary Deck 1 and Primary Deck 2 are outfitted with screens of the same API designation. An adjustable overflow weir routes any overflow from Primary Deck 1 to Primary Deck 2. This adjustable weir enables control of the fluid endpoint on Primary Deck 1. Once the desired fluid endpoint is reached on Primary Deck 2, flow is maximized. When operating in the in-parallel mode, the built-in recovery trough on the end of Primary Deck 1 is closed, allowing for the discharge of solids. The design of this trough allows the user to easily switch between collection and disposal modes, with no special tools. Composite Materials
National Oilwell Varco® has designed the Brandt® VSM Multi-Sizer separator to provide an improved power-to-weight ratio by the use of composite materials (patent-pending) throughout the vibration basket. This provides an improved g-force rating without the need for increased horsepower requirements. Composite materials also provide exceptional corrosion resistance in high fluid flow areas. 70
The VSM Multi-Sizer separator features balanced elliptical motion to effectively separate solids from liquid. Screen changes are quickly facilitated with the field-proven Pneumoseal™ clamping and sealing system. (See Table 6-4) The HVAC hood, a standard feature on the VSM Multi-Sizer separator, routes hazardous fumes away from the unit and into a ventilation system.
Features Constant G Control
“In-parallel” operational mode “In-series” operational mode
Manual flow diverter Pneumoseal clamping and sealing system Three-screening decks design (scalping, first primary, second primary) 6.79 m² (73.08 ft²) of screening area Built-in recovery trough on first primary deck Balanced elliptical motion
Finely-tuned motor weight balancing
Vibratory drive system
Scalping deck allows inspection of the first primary deck system Shallow header tank design Low spare parts inventory HVAC hood Automated Shaker Control (optional)
Benefits Maintains a constant g-force during variable liquid/solids loading conditions. Improves flow capacity, constant solids conveyance and finer screening capability. Doubles the effective screening area for increased capacity of fine solids removal. Allows for finer screening and higher flow rates Allows for classification of solids by using screens of varying API designations on each respective deck. Allows for the recovery of designer solids, including lost circulation material (LCM). Allows for easy switching between “in-series” and “in-parallel” operational modes by a single operator with no tools required Ensures screens are properly secured to shaker basket; allows for quick and easy screen changes Increased screening area - allows for higher flo w, allows for classification of solids
Highest available amount of screening area on the market Easy switching between the collection and disposal of solids in the different modes: “In-series” collection and “In-parallel” collection Easy removal of large, sticky, hydrated clays and other troublesome solids; Improved solids conveyance in situations where reactive formations encountered; Minimizes solids degradation: Improves screen life, minimizes likelihood of screen blinding Optimal solids conveyance by providing a consistent balancedelliptical motion and stroke profile under varying basket loading conditions; Different sized weight compensate for the differing distances of elliptical motions, thus maintaining balance Field proven, 8-bearing drive system with cylindrical roller bearings and a short shaft design, offering unsurpassed reliability and performance (10 years proven the VSM 300 shaker) Designed and sized to allow for quick and easy inspection of first primary deck screen’s condition Even distribution of drilling fluid to all separators in the system Cost Savings Routes hazardous fumes away from the unit and into a ventilation system for safe transfer away from personnel Automatic optimizing of shaker utilization during varying flow conditions (unneeded shakers are brought offline); Increases screen life by keeping screens wet with fluid
Table 6-4. Features & B enefit s VSM Multi-Sizer
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6.2.10.1 Cons tant G-Contro l
Constant-G Control® (CGC) is a patented technology developed to maintain an optimal G-force rating on Brandt® shaker products during varying liquid/solids loading conditions. (Figure 6-21) CGC maximizes shaker screen performance, solids conveyance and throughput while enhancing screen life. CGC is an industry first that sets a new standard in separator performance. Figure 6-21. Constant G-Contro l
How CGC Work s
On a conventional shaker, G-force drops as weight on the basket increases, due to the fact that motor rpm and force is constant. This causes the unit to be less efficient while loaded and reduces its ability to process drilling fluids. With the addition of an accelerometer on the basket tied to the VFD operating the motors, the VFD is able to constantly monitor the basket G-force and adjust the motor speed in order to maintain the G-force at predetermined set points, depending on fluids and solids loading on the basket. The basket will run at a lower G-force and reduce wear on screens and components, while operating with little solids loading. When loading becomes more extreme and higher G’s are needed to process all of the drilling fluid, the basket will automatically ramp up to a higher G-force. Constant-G Control is a standard feature on the new Brandt VSM Multi-Sizer separator. CGC is also available as a performance upgrade option on the Brandt King Cobra family of shakers and the VSM-300 shaker. CGC can be easily installed via retrofit kit on existing King Cobra and VSM-300 shakers already in operation in the field.
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6.2.11 Cascade Shakers A cascade shaker removes coarser solids before the drilling fluid flows to a second shaker situated directly under the first. The top shaker can utilize any motion, circular, elliptical or linear and the bottom shaker usually utilizes linear motion. The motion, however, can be selected based on specific drilling needs or customer preference. Normally, one uses a non-linear motion scalping shaker (top shaker) to remove the sticky drill solids that tend to plug screen area. NOV can make any combination cascade shaker desired. Currently we market the LCM-3D/CM-2 (the CM-2 is the top shaker) and the LCM-3D/King Cobra models. LCM-3D/CM-2 Cascade The LCM-3D/CM-2 uses circular motion on the top scalping deck of the CM-2 and linear motion on the LCM-3D bottom deck. (Figure 6-22)
The CM-2 deck has 22.5 square feet of screening area provided by three hook strip screens and has a deck angle of 0º. The circular motion helps remove sticky solids before they reach the fine screens mounted on the LCM-3D deck. Figure 6-22. LCM-3D/CM-2 Cascade
The Contour plus LCM-3D uses four rigid pretension screens with a screen area of 33.4 square feet. The basket angle is adjustable from -5º to +5º. The linear motion bottom deck removes solids efficiently. Mud loss is minimized and cuttings dryness is enhanced with NOV’s patented drying deck and flow diverter tray. The drying deck also saves space by reducing the overall footprint. The CM-2 basket and the LCM-3D baskets generate 4.2 and 5.4 G’s, respectively. The LCM-3D shaker was the precursor to the Cobra family of shakers. Many of the features of the Cobra series shakers are used by the LCM-3D shaker; including the screens, screen support material, screen plugs and hammerwedge screen fasteners.
6.2.12 LCM-3D/King Cobra Cascade The LCM-3D/King Cobra Cascade shaker has the King Cobra shakers scalping the large solids using elliptical motion. The shakers have a combined deck area of 66.8 ft², which improves handling capacity (Figure 6-23). Both use four repairable pretension screens. The scalping shaker provides 6.5 nominal G’s and the primary shaker provides 6.1 nominal G’s. Figur e 6-23. LCM-3D/Kin g Cobra Cascade
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7
GAS CONTROL 7.1 Introduction
The drilling industry specifically searches for crude oil and natural gas. So drilling through a gas bearing formation is common and expected. The equipment necessary to handle a gas flow is designed into the drilling plan and the rig. There are two basic types of degassing equipment; flowline degassers and mud pit degassers. The NOV flowline degasser, called the Mud Gas Separator (MGS), handles all of the flow from the wellbore before any of the mud reaches the mud pits and the solids control equipment. The mud pit degassers are positioned right after the shale shakers. These units are designed to handle all of the mud flow from the wellbore and remove the entrained gas left in the mud after the fluid flows through the MGS. Brandt markets four mud pit degasser models. The majority of gas is removed by the MGS and more gas escapes when the mud goes over the shaker screens. If gas cut mud is evident at the shale shakers personnel should minimize their time around the shale shakers. 7.2
Mud Gas Separator
The mud from the flowline is directed to the mud gas separator to remove any large volumes of gas encountered while drilling. (See Figure 7-1.) To protect personnel, the removed gas is directed to a remote location and is vented and flared.
Figure 7-1. Mud Gas Separator
The MGS can handle hazardous gas and conforms to ASME and NACE specifications. They can be modified to fit specific rig conditions.
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7.2.1 Mud Gas Separator Operational Guidelin es •
• •
•
•
Mud and gas are diverted from the flowline through a choke and into the MGS. Gas is released as the mud impacts the internal baffles. “Free” gas collects at the top of the MGS and is vented a safe distance from the rig for flaring or discharge to the atmosphere. Mud, being heavier than gas, remains at the bottom of the MGS and is maintained at a specific level (mud leg). The mud returns then goes to the shale shakers and then to the active mud system where Brandt degassers remove additional entrained gas.
7.3 Atmo sph eric Degas ser
The gas-cut mud is pumped to the spray chamber of the atmospheric degasser at high velocity through a disc valve. The mud strikes the inside wall of the spray chamber with enough force to drive most of the entrapped gas out of the mud. The removed gas is usually discharged to the atmosphere at pit level, or it can be routed to a safe place and the degassed mud returned to the active system. These devices are simple to operate and maintain, but their effectiveness is often limited by the ability of the centrifugal pump to handle gas-cut mud. The NOV VG-ATM can process about 700 gpm (2650 liter/min). (See Figure 7-2.)
Figure 7-2. Atm ospheric Degasser
Installation
Atmospheric degassers are placed in the mud tank right after the shale shaker tank and consist of an elevated spray chamber and a submerged centrifugal pump. The unit takesup very little space. 75
7.4 Vacuum Degassers
Vacuum-type degassers separate gas bubbles from drilling mud by spreading the gas cut mud into thin layers and then drawing off the gases with a vacuum pump. Vacuum degassers normally are skid-mounted and installed on top of the mud tanks. NOV offers horizontal and vertical models based on the arrangement of equipment on the specific rig. The various models can process from 500 to 1200 gpm (1942 to 4542 liter/min) of mud. (See Figure 7-3 and 7-4)
Figur e 7-3. DG-10 (Verti cal Degasser)
Figur e 7-4. VG-1 (Horizont al Degasser)
The vacuum models use a centrifugal pump and Venturi to produce an efficient eductor that feeds the degasser with mud. The Venturi generates a negative pressure that pulls the mud into the degasser (Figure 7—5). A separate vacuum unit on the degasser helps remove the entrained gas. A float inside the degasser actuates a vacuum breaker to allow air into the unit as the mud level fluctuates. We decided to leave the floats out of the above pictures for clarity purposes only. Figure 7-5. Venturi that Pulls Mud int o Degasser 76
The centrifugal pump must take suction from a pit that contains degassed mud. The suction of the centrifugal pump and Venturi can be as much as 25 feet apart. The feed pipe for the vacuum degasser takes feed from the downstream mud pit adjacent to the sand trap (see Figure 7-6).
DG-10 Vacuum Degasser one per 1000 GPM @ 9 ppg one per 700 GPM @ 12.5 ppg Line lengths not to exceed 20 feet
High overflow equalization
Bottom equalization
Gas-Cut Mud Sandtrap #1
Gas-Cut Mud Degasser Suction
Degassed Mud
Figure 7-6. Typical Degasser Rig-Up
7.4.1 Installation Actual placement of the degasser and related pump will vary with the design of the degasser, but these recommendations may be used as a general rule: Install a screen in the inlet pipe to the degasser to keep large objects • from being drawn into the degassing chamber. Locate the screen about one foot above the pit bottom and in a well-agitated area. There should be a high equalizer between the suction and discharge • compartment. The equalizer should be kept open to allow backflow of processed mud to the suction side of the degasser. Route the liquid discharge pipe to enter the next compartment or pit • below mud level to prevent aeration. Install the gas discharge line to safely vent the separated gas to the • atmosphere or to a flare line. 7.4.2 Maintenance
Maintenance of degassers varies considerably depending on make and model. In general, the following guidelines apply: If a suction screen is in place be sure it is not plugged. • Routinely lubricate any pumps and other moving parts and check for • wear. Change vacuum pump oil with SAE 30 or 40W “non-detergent” every six • months. 77
Keep all discharge lines open and free from restrictions, such as caused by solids buildup around valves. • If the degasser utilizes a vacuum, keep it at the proper operating level, according to the manufacturer’s recommended range for the mud weight and process rate. • Check all fittings for air leaks. If the unit uses a hydraulic system, check it for leaks, proper oil level and absence of air in the system. •
7.5 Degasser Product Line NOV offers a basic mud gas separator, an atmospheric degasser and four models of vacuum degasser. (See Table 7-1.) Table 7-1. Degasser Product Line Model
Capacity GPM
Liters/Min
Mud Gas Separator
1200
4542
DG-5
500
1893
DG-10
1000
3785
DG-12
1200
4542
VG-1
1000
3785
VG-ATM
700
2650
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8 HYDROCYCLONES 8.1
Introduction
Hydrocyclones (also referred to as cyclones or cones) are simple mechanical devices without moving parts. They are designed to speed up the settling process. Feed energy is transformed into centrifugal force inside the cyclone to accelerate particle settling in accordance with Stokes’ Law. In essence, a cyclone is a miniature settling pit which allows very rapid settling of solids under controlled conditions. Hydrocyclones are important in solids control systems because of their ability to efficiently remove particles smaller than the finest screens used on shakers. They are also uncomplicated devices, which make them easy to use and maintain. Although cones are easy to monitor, the real issue is will the rig hands put out the effort to keep the units operating correctly? The feed pressure should match the mud weight (4 x mud weight, ppg = pounds per square inch) and the cones need to be operating in spray discharge. A hydrocyclone consists of a cylindrical/conical shell with a small opening at the bottom for underflow discharge (See figure 8-1), a larger opening at the top for liquid discharge through an internal “vortex finder” and a feed nozzle on the side of the body near the cylindrical (top) end of the cone.
Figure 8-1. Hydrocyc lone Diagram
Hydrocyclones should be used when the mud does not contain weight material since the cyclones will remove the weight material. When the mud weight gets close to 10 to 11 ppg the cyclones should be shut down. A mud cleaner or mud conditioner, (cyclones mounted over a shale shaker) can be used with weighted mud if the rig shale shakers can’t use fine enough screens to remove most of the drill solids larger than 75 microns. 79
Drilling mud enters the cyclone using energy created by a centrifugal feed pump. The velocity of the mud causes the heavy, coarse solids and the liquid film around them to spiral outward and downward for discharge through the solids outlet (bottom of cone). Light, fine solids and the liquid phase of the mud tend to spiral inward and upward for discharge through the liquid outlet (top of cone). Design features of cyclone units vary widely from supplier to supplier, and no two manufacturers’ cyclones have identical operating efficiency, capacity or maintenance characteristics. In the past, cyclones were commonly made of cast iron with replaceable liners and other wear parts made of rubber or polyurethane to resist abrasion. Newer designs are made entirely of polyurethane, are less expensive, last longer and weigh less. Most well designed oilfield cyclones operate most efficiently when 75 feet of inlet head (±5 ft) is applied to the cone inlet. Centrifugal pumps must be properly sized for cones to operate efficiently. Centrifugal pumps are constant energy (head) devices and not constant pressure devices. Feed head is constant regardless of mud weight; pressure varies with mud weight. (See Figure 8-2.)
∆P = 0.052 x D x ρ P = pressure, pounds per square D = depth, feet ρ = mud weight, pounds per gallon
Where:
Figure 8-2. Pressure Changes with Mud Weight
Table 8-1 shows the relationship of feet of head to psi for various mud weights. Figure 8-3 shows a pressure gauge that is mounted on the manifold showing the various pressures and mud weights needed to maintain 75 feet of head.
Table 8-1. Pressu re Changes as Mud Weigh t Changes
Pressure, psig
Feet Head, ft
Mud Weight, ppg
32.5
75
8.34
35
75
9.0
37
75
9.5
39
75
10.0
41
75
10.5
43
75
11.0
45
75
11.5
80
Figure 8-3. Pressure gauge on Manifold
Head (in feet) = (pounds per square inch)/(0.052)(mud weight in pounds per gallon) Although centrifugal pump theory and sizing exercises are beyond the scope of this text, if you are not able to properly size your centrifugal pump to create 75 feet of inlet head to your set of cyclones, it is highly recommended that you contact the Technical Services Staff at NOV for assistance. Remember, more errors in cyclone applications are made with centrifugal pumps, rather than with the cyclones themselves. The size of oilfield cyclones commonly varies from 2” to 12” (5.08 to 30.48 cm). This measurement refers to the inside diameter of the largest, cylindrical section of the cyclone. In general — but not always — the larger the cone, the coarser it’s cut point and the greater its throughput. Typical cyclone throughput capacities are listed in Table 8-2.
Designation
Table 8-2. Hydrocy clo ne Capacities (@ 75 feet of h ead) Cone Cone Diameter, Flow Rate per Diameter, in cm Cone, gpm
Flow Rate per Cone, l/m
Desilter
2
5.1
10-30
38-114
Desilter
4
10.2
50-65
189-246
Desilter
5
12.7
75-85
284-322
Desander
6
15.2
100-120
379-454
Desander
8
20.3
200-240
757-909
Desander
10
25.4
400-500
1514-1893
Desander
12
30.5
500-600
1893-2771
The internal geometry of a cyclone also has a great deal to do with its operating efficiency. The length and angle of the conical section (and the ratio of cone diameter to cone length), the size and shape of the feed inlet, the size of the vortex finder and the size and adjustment means of the underflow opening all play important roles in a cyclone’s effective separation of solids particles. Operating efficiencies of cyclones may be measured in several different ways, but since the purpose of a cyclone is to discard maximum abrasive solids with minimum fluid loss, both solids and liquid aspects of removal must be considered (A simple technique for comparing the efficiencies of two cyclones is given in Appendix B of this handbook). In a cyclone, larger particles have a higher probability of reporting to the bottom underflow (apex) opening, while smaller particles are more likely to report to the top (overflow) opening. The most common method of illustrating particle separation in cyclones is through a cut point curve. The D50 point is where 50% of a specific particle size is removed from the system and 50% is returned to the system. 81
Table 8-3 shows the approximate cut point ranges for cyclones used with unweighted water-base mud and operated at 75 feet ±5 feet of inlet head. Table 8-3. Typical Cut Point Ranges for Various Sized Cones
Cone Diameter, in
8.2
D50 Cut Point in Drilling Fluid, microns
2
15+
4
35-70
6
70-100
10
90-120
12
200+
Operation
Cut Point Particle separation in cyclones can vary considerably depending on such factors as feed head, mud weight, percent solids, and properties of the liquid phase of the mud. Generally speaking, increasing any of these factors will shift the cut point curve to the right, i.e. only the larger solids would be removed by the cyclone. By itself, the cut point does not determine a cyclone’s overall efficiency because it ignores the liquid loss rate. The amount of fluid in the cone underflow is important; if the solids are too dry, they can cause “roping” or “dry-plugging” of the underflow. In contrast, a cyclone operating with a spray discharge (Figure 8-4 and Figure 8-5) gives solids a free path to exit. A cone operating in spray discharge will remove a significantly greater amount of solids than a cone in “rope” discharge.
Figure 8-4. Cones in Spray Discharge
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Figure 8-5. A few cones in spray dis charge
Rope versus Spray Discharge
Hydrocyclones should not be operated in rope discharge because it will drastically reduce the cone separating efficiency. In a rope discharge, the solids become crowded at the apex, cannot exit freely from the underflow, and become caught by the inner spiral reporting to the overflow. Solids which otherwise would be separated are forced into the overflow stream and returned to the mud system. This type of discharge also can lead to plugged cones and much higher cyclone wear. (See Figure 8-6.)
Figure 8-6. Rope Discharge (Plugged Flow)
While a spraying cyclone appears to discharge more fluid, the benefits of more efficient solids removal and less cone wear outweigh the additional fluid loss. In cases where a dry discharge is required, the underflow from hydrocyclones can be screened or centrifuged to recover the free liquid.
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8.3 Desanders Desanders are hydrocyclones that are 6” or larger in diameter (6”, 8”, 10” or 12” ID). Generally, the smaller the cone, the smaller size particles the cone will separate. Desanders are primarily used to remove the high volumes of solids associated with extremely fast drilling of a large diameter hole where the shakers can’t handle the flow with fine screens. The 10-inch cones can process about 500 gpm.
Figur e 8-7. Desander
Desanders are installed downstream from the shale shakers and degasser (Figure 8-7). The desander removes sand sized particles and larger drilled solids which have passed through the shaker screen and discards them along with some liquid into a waste pit. The partially clean mud is discharged into the next pit downstream. NOV markets 10-inch and 12-inch cones. 8.3.1 Installation When installing a desander, follow these general recommendations: Size the desander to process 110–125% of the total mud circulation rate. • If the estimated maximum rig flow rate is 800 gpm, size the desander to handle 1000 gpm (800 gpm X 125% = 1000 gpm). When using 10-inch cones which handle about 500 gpm, one would need at least two cones to handle the flow. • Keep all lines as short and straight as possible with a minimum of pipe fittings. This will reduce loss of head on the feed line and minimize backpressure on the overflow discharge line. Install a guard screen with approximately ½” openings at the suction to • the desander to prevent large trash from entering the unit and plugging the cones • Do not reduce the diameter of the overflow line from that of the overflow discharge manifold. 84
•
•
•
•
Direct the overflow line downward into the next downstream compartment at an angle of approximately 45°. The overflow discharge line should not be installed in a vertical position - doing so may cause excessive vacuum on the discharge header and pull solids through the cyclone overflow, reducing the cyclone’s efficiency. Keep the end of the discharge line above the surface of the mud to avoid creating a vacuum in the line. Position the underflow trough to easily direct solids to the waste pit. Install a low equalizer line to permit backflow into the desander suction. Operating desanders at peak efficiency is a simple matter, since most desanders are relatively uncomplicated devices.
8.3.2 Guidelines
Here are a few fundamental principles to keep in mind: •
•
•
•
Operate the hydrocyclone unit at the supplier’s recommended feed head (usually around 75 feet). Too low a feed head decreases efficiency, while excessive feed head shortens the life of cyclone wear parts. Check cones regularly to ensure the discharge orifice is not plugged. Run the hydrocyclones continuously while drilling and shortly after beginning a trip for “catch-up” cleaning. Operate the desander with a spray rather than a rope discharge to maintain peak efficiency.
8.3.3 Maintenance
Maintenance of desanders normally entails no more than checking all cone parts for excessive wear and flushing out the feed manifold between wells. Large trash may collect in feed manifolds which could cause cone plugging during operation. Preventive maintenance minimizes downtime, and repairs are simpler between wells than during drilling. Use of desanders is normally discontinued when expensive materials such as barite and polymers are added to a drilling mud, because a desander will discard a high proportion of these materials along with the drilled solids. Similarly, desanders are not generally cost effective when an oil-base mud is in use because the cones also discard a significant amount of the liquid phase.
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8.4
Desilters
A desilter uses smaller hydrocyclones (usually 4” or 5” ID {10.2 cm or 12.7 cm}) than a desander and therefore generally removes smaller particles. Desilter can remove solids in the range of 15 microns and larger. This makes it an important device for reducing average particle size and removing abrasive grit from unweighted mud. The cyclones in desilter units operate on the same principle as the cyclones used on desanders. They simply make a finer cut and the individual cone throughput capacities are less than desander cones. Multiple cones are usually manifold in a single Desilter unit to meet throughput requirements. Desilters should be sized to process 110–125% of the full rig flow rate. The 4-inch cones can process about 60 gpm (227 liters/min). NOV markets a 4-inch cone but will furnish a 5-inch cone based on customer needs. A 2-inch cone called a Microfine Separator can also be supplied. The 2-inch cone can handle about 15 gpm (57 liters/min). Manifolds for cyclones can be in horizontal (Figure 8-8) or circular (radial) design (Figure 8-9), the choice being one of convenience.
Figure 8-8. Desilters
Figure 8-9. Desilt er using radial feed 86
8.4.1 Installation Installation of desilters is normally downstream from the shale shaker, sand trap, degasser and desander, and should allow ample space for maintenance. Here are some fundamentals for installing desilters: Size the desilter to process 110–125% of the total mud circulation rate. • If the estimated maximum rig flow rate is 800 gpm (3028 liters/min), size the desilter to handle 1000 gpm {3785 liters/min} (800 gpm X 125% = 1000 gpm) or {3028 lpm X 125% = 3785 lpm}. When using 4-inch cones (10.2 cm) that process about 60 gpm (227 liters/min) one would need 18 cones. • Take the desilter suction from the compartment receiving fluid processed by the desander. • Do not use the same pump to feed the desander and desilter. If both pieces of equipment are to be operated at the same time, they should be installed in series and each should have its own centrifugal pump. • Keep all lines as short and straight as possible. Install a guard screen with approximately ½” (1.3 cm) openings at the • suction to the desilter to prevent large trash from entering the unit and plugging the cones. • Position the desilter on the pit high enough so the overflow manifold will gravity-feed fluid into the next downstream compartment at an angle of approximately 45°. Remember, no vertical overflow discharge lines. • Keep the end of the discharge line above the surface of the mud to avoid creating a vacuum in the line. • Install a low equalizer line for backflow to the desilter’s suction compartment. • Position the underflow trough to easily direct solids to the waste pit. Running a desander ahead of a desilter takes a big load off the desilter and improves its efficiency. If the drilling rate is slow, and the amount of solids being drilled is only a few hundred pounds per hour, then the desander may be turned off (to save fuel and maintenance costs) and the desilter may be used to remove solids. Appendix C includes a chart to calculate the pounds per hour of solids generated for a range of hole size and rate of penetration. Operating efficiencies of competitive desilters vary widely according to differences in design features. The same technique described in Appendix B for comparing two desanders will work to compare the efficiencies of competing desilters operating on the same rig. 8.4.2 Guidelines To operate desilters at maximum efficiency, follow these basic guidelines: Operate the cones with a spray discharge. Never operate the desilter • cones with a rope discharge since a rope underflow reduces cone efficiency in half or worse, causes cone plugging and increases wear on cones. Use enough cones and adjust the cone underflow openings to maintain a spray pattern. Operate the desilter unit at the supplier’s recommended feet of head. • This is generally about 75 feet of head. Too much energy will result in excessive cone wear. • Check cones regularly for bottom plugging or flooding, since a plugged cone allows solids to return to the mud system. If a cone bottom is 87
plugged, take the cone off line, clean obstruction and replace the cone. If a cone is flooding, the feed is partially plugged or the bottom of the cone may be worn out. •
Run the desilter continuously while drilling and also for a short while during a trip. The extra cleaning during the trip can reduce overload conditions during the period of high solids loading immediately after a trip.
8.4.3 Maintenance
Due to the smaller size of the desilters cyclones, desilters are more likely to become plugged than desander cones, so it is important to inspect them often for wear and plugging. This may generally be done between wells unless a malfunction occurs while drilling. The feed manifold should be flushed between wells to remove trash. Keep the shale shaker well maintained — never bypass the shaker or allow large pieces of material to get into the active system. A desilter will discard an appreciable amount of barite, because barite particles fall within the silt size range. Desilters are not recommended for use with weighted mud. Similarly, since hydrocyclones discard some absorbed liquid along with the drilled solids, desilters are not normally used with oil-base mud, unless another device (centrifuge or mud cleaner/conditioner) is used to remove excess liquid from the discharged solids.
Figure 8-10. Typical Rig Layout for Cyclones
A typical rig lay-out for hydrocyclone equipment is shown. The desander and Desilter use individual centrifugal pumps properly rated for each unit by NOV personnel. The mud pumped to the specific unit is processed and then discharge downstream of the unit. This makes sure the largest solids are removed before the processed fluid is sent downstream for more processing. 88
9 MUD CLEANERS AND CONDITIONERS 9.1 Introduction In many cases, combinations of vibratory screening and settling/centrifugal force are used together to provide an effective separation. The most familiar combination separator is the original Sweco Mud Cleaner (Figure 9-1) or Mud Conditioner (Figure 9-2).
Figure 9-1. The Original Mud Cleaner
Figure 9-2. King Cobra Mud Condit ioner
Mud cleaners were developed in the early 1970s to remove drilled solids from weighted mud without excessive loss of barite and fluid. Mud cleaners also can be beneficial when used in closed systems and other “dry” location” applications. These devices use a combination of desander and desilting hydrocyclones mounted on top of a circular or unbalanced elliptical shaker. The shakers used fine screens (API 120–400) to remove as much liquid from the solids, returning valuable mud additives and liquids back to the active mud system. Remember that this volume of mud returned to the active mud system contains fines. These fines which would have been discharged are now returned to the mud system along with the mud that would have been discharged. To save mud, one also must save fines that can adversely affect mud properties (viscosity and filtration properties). This is a balancing act that the mud engineer and solids control specialist must review on a daily basis. When mud properties get excessive, a centrifuge must be used to remove the fines or some active mud will have to be removed and replaced with fresh fluid so that the fines are removed or diluted.
89
Traditional mud cleaners use multiple - 4” or 5” (10.2 to 12.7 cm) cyclones, mounted over the circular or unbalanced vibrating screens, and are able to effectively process 400–600 gal/minute (gpm) {1514-2271 liters/min}. The process capacity is limited by screen capacity and its ability to discard “dry” solids. With the introduction of linear motion vibrating screens, the capacity of the mud cleaner screen has been greatly increased. This, in turn, allows the use of additional hydrocyclones and higher, overall process capacities. The combination of hydrocyclones and linear-motion vibrating shaker screens will be called a mud conditioner for the remainder of this handbook, to differentiate these machines from earlier mud cleaners. Mud conditioners often combine desander and desilter cones mounted above the screen deck to take full advantage of the higher process capacity, usually 1000–1500 gpm (3785-5678 liters/min). After removal of large cuttings by the rig shakers, feed mud is pumped into the mud cleaner/conditioner’s hydrocyclones with a centrifugal pump sized for the rigs maximum flow rates +25%. The overflow from the cyclones is returned to the mud system. Instead of simply discarding the underflow, the solids and liquid exiting the bottom of the cyclones are directed onto fine screens of the shale shaker. Drilled solids larger than the screen openings are discarded; the remaining solids, including most of the barite in a weighted mud system, pass through the screens and are returned to the active mud system. The cut point (the d 50 value; where 50% of the solids are returned to the active system and 50% of the solids are discharged) and amount of mass solids removed by a mud cleaner/conditioner depends primarily on the fine screens used (Figure 9-3). Since there are many designs of mud cleaners/conditioners available, performance and economics will vary with machine and drilling variables.
Figure 9-3. Screens Used on Mud Cleaner/Condit ioner 90
9.1.1 Appl ic ati on s
Mud cleaners/conditioners should be considered in these applications: 1.
Whenever the application requires finer screens than the existing shaker can handle
2.
Unweighted oil-base mud (OBM)
3.
Expensive polymer systems
4.
When the cost of water is high
5.
Unweighted water-base mud (WBM) with high disposal costs and/or environmental restrictions
6.
When use of lost circulation material requires bypassing the shaker
7.
Workover and completion fluid
Mud cleaners/conditioners are simply a bank of hydrocyclones (4”, 5”, 10” or 12”) mounted over fine screens (How fine? Fine enough so the solids are not too wet – this is a function of the specific wells situation). The question to answer becomes how to achieve the necessary level of screening at the lowest cost. The alternatives are: 1.
Add additional similar shakers to handle the flow rate,
2.
Replace the existing shakers with more efficient units or
3.
Add a mud cleaner/conditioner downstream from the existing shakers.
Any of these may be correct, but a thorough study of the capital cost (the actual cost of new equipment, plus transportation, rig modifications and installation) and the operating cost (screens and other expendables, plus fuel) is necessary to make the proper choice based on customer needs. Salvage of the liquid phase of an unweighted drilling mud often cost-justifies use of a mud cleaner/conditioner when the fluid phase of the mud or disposal is expensive. Compared to desanders and desilters, whose cyclone underflow may discharge as much as 15 bbl of fluid/hr or more, mud cleaners/conditioners can achieve efficient solids removal while returning most liquid back to the active mud system. Use of fine screens (API 200 to 325) significantly improves solids control in any high-value fluid system. An increasingly important application of mud cleaners/conditioners is the removal of drilled solids from unweighted water-base mud in semi-dry form. This system is commonly used in areas where environmental restrictions prohibit the use of earthen reserve pits and expensive vacuum truck waste disposal from steel pits is the alternative. The mud cleaner/conditioner is used to discard drilled solids in semi-dry form which is classified as legal landfill in most areas and is subject to economical dryhaul disposal techniques (dump truck or portable waste containers). 91
When used for this purpose, the screen overflow from the mud cleaner/conditioner often is diverted to a separate steel waste pit for vacuum truck disposal. This may seem counterproductive, but since a vacuum truck can only carry a limited amount of sand because of over-the-road weight restrictions, whenever a vacuum truck must haul normal full-flow desilter waste, the waste must be diluted with rig water to reduce density. The operator is billed for the haulage of a vacuum truck load comprised largely of rig water. On the other hand, since most of the solids are removed in semidry form by the mud cleaner/conditioner screen, the remaining solids in the screen overflow are dilute enough to be hauled away without watering them back. Vacuum truck loads often can be reduced to a small fraction of those required with full-flow desilting. This approach to dry-solids disposal can be carried further by using a centrifuge with a mud cleaner/conditioner to form a “closed” system which eliminates discarding of any fluid. These systems are being used increasingly in areas where liquid mud waste must be hauled a significant distance and is subject to a high disposal fee. In a closed system, underflow from the mud cleaner/conditioner screen is diverted to a holding tank and then centrifuged, which results in disposal of very fine, semi-dry solids and return of liquid to the active system. Such a system virtually eliminates the need for reserve pits, minimizes dilution, eliminates vacuum truck services for disposal of liquid mud and meets environmental constraints when drilling within ecologically sensitive areas. One special mud cleaner/conditioner application is the use of a double-deck unit (scalping shaker over an elliptical or linear motion shaker) for salvage of coarse lost circulation material (LCM). When running LCM, the shale shaker usually is bypassed and drilled solids build up rapidly in the mud, necessitating a high level of dilution and new mud. Use of a two-deck mud cleaner/conditioner allows salvage of the LCM while minimizing the increase in solids content. Within the mud cleaner/conditioner, a coarse top screen is used to pre-screen the mud and remove the lost circulation material. This material is discharged back into the active system for recirculation downhole. The drilled solids, mud additives and liquid phase pass through the top screen onto the lower, finer mesh screen, where the drilled solids are separated out and discarded. The cleaned mud then flows back into the mud system and is re-blended with the salvaged lost circulation materials. Another mud cleaner/conditioner application is the clean-up of workover and completion fluids. In order to reduce costs associated with this expensive task, a mud cleaner running fine screens (API 200 or finer) can be used to remove most of the solids before they reach cartridge type filters. This application can significantly reduce filter replacement costs, reduce downtime in changing filters and allow larger volumes of fluid to be cleaned at a faster rate. 9.1.2 Installation
Installation of the mud cleaner/conditioner is made downstream of the shale shaker and the degasser. The same pump used to feed the rig’s desander or desilter is often reconnected to feed the mud cleaner/conditioner when weight material is added. Most mud cleaner/conditioners are designed to function as desilters on unweighted mud by rerouting the cone underflow or by removing or blanking off the screen portion of the unit. The mud cleaner/conditioner may be used to replace or augment the rig’s desilter during top hole drilling.) 92
Follow these guidelines when installing mud cleaner/conditioners to allow peak efficiency: • Size the mud cleaner/conditioner cyclones to process 110–125% of the full circulating flow rate. • Take the mud cleaner/conditioner suction from the compartment receiving fluid processed by the degasser. When using mud conditioners that have both desander and desilter • cones, use a separate feed pump for the desander cones and another feed pump for the desilter cones. The desander cone suction should be from the degasser discharge compartment. The desilter cone suction should be from the desander discharge compartment. Keep all lines as short and straight as possible. • • Install a guard screen with approximately ½” (1.3 cm) openings at the suction to prevent large trash from entering the unit and plugging the cones. Position the mud cleaner/conditioner on the pit high enough so the • overflow manifold will gravity-feed fluid into the next downstream compartment at an angle of approximately 45°. • Avoid vertical overflow discharge lines from hydrocyclones. 9.1.3 General Guidelin es To operate mud cleaner/conditioners at maximum efficiency, remember these fundamentals: • Operate mud cleaners/conditioners continuously on the full circulating volume to achieve maximum drilled solids removal. • Operate mud cleaners/conditioners within the limits of the screen capacity. A mud cleaner/conditioner with a cyclone throughput of 800 gpm (3028 liters/min) is of little value if the cone underflow exceeds the screen capacity, resulting in flooding and high mud additive losses. Feed the cone underflow to the screen at a single point. Multiple feed • points on the screening surface minimize use of the available screen area and reduce overall capacity and efficiency. • Screen throughput is reduced by increased solids content and viscosity. The cyclone underflow plays a critical role in overall mud cleaner/conditioner efficiency. Do NOT judge screen efficiency simply on the basis of cuttings dryness • or color. The total amount of drilled solids in the discarded material, along with the ratio of barite to drilled solids, must be determined to correctly evaluate economic performance. A technique for measuring and calculating these values is given in • Appendix F of this handbook. Select the number of cones to be operated and the particular mesh • screen to be used according to drilling conditions. As a general rule, use the finest mesh screen possible (to process the full circulating rate) and size the number of cones accordingly. In some instances, a number of cones will have to be blanked off in order for the desired screen to be used. This may involve an experimental determination of the number of cones and screens to optimize performance. In some cases, more than one mud cleaner/conditioner will be needed. The following example illustrates the point: 93
Earlier mud cleaner designs with 12 - 16 cones over a single screen bed have not proven to be practical; the fine screens simply cannot handle the underflow volume from the cones. One exception to this is the mud conditioner; a linear-motion shaker coupled with a manifold of properly designed hydrocyclones yields a high-performance mud conditioner with sufficient capacity for even the largest holes drilled. Follow these general guidelines for correct mud cleaner/conditioner operation: •
•
•
•
•
•
•
Run the mud cleaner/conditioner continuously while drilling and for a short period of time while making a trip for “catch-up” cleaning. Start up the shaker portion of the mud cleaner/conditioner before engaging the feed pump(s). Shut down the feed pump(s) before turning off the vibrating screen portion of the mud cleaner/conditioner. Permit the screen to clear itself. Then rinse the screen with water or oil sprays before shutting down the screen portion of the unit. For peak efficiency, operate the cones with a spray rather than a rope discharge. This is just as important with a mud cleaner/conditioner as with desilters and desanders. Check cones regularly for bottom plugging or flooding, since a plugged cone allows solids to return to the mud system. If a cone bottom is plugged, take the cone offline and clear the plug or obstruction. If a cone is flooding, the feed is partially plugged or the bottom of the cone may be worn out. When a significant amount of barite is added to increase mud weight, shut down the mud cleaner/conditioner for one or two full circulations. This permits the fresh barite to thoroughly mix with the system and reduce losses over the screen. Use low-volume sprays on the screen surface to reduce “piggy-backing” only if 1) this liquid addition to the mud is permissible, and 2) the resultant reduction in barite discard outweighs the resultant reduction in drilled solids discard. This must be determined experimentally on a case-by-case basis. In some cases, adding a small stream of cleaned mud from the hydrocyclone overflow (reflux) provides the same reduction in “piggy-backing” without reducing the overall efficiency of the unit.
9.1.4 Maintenance
Maintenance of mud cleaners/conditioners generally combines the requirements of desilters and those of fine screen shakers: • • •
• • •
Periodic lubrication Check screen tension Inspect the screen to ensure it is free of tears, holes and dried mud before start up. To extend screen life, shut down the unit when not circulating. Check feed manifold for plugging of cyclone feed inlets. Check cyclones for excessive wear and replace parts as necessary. 94
9.1.5 Mud Conditio ner Product Line
NOV offers an assortment of mud conditioner configurations to meet the customers’ requirements as shown in Table 9-1. Table 9 -1. Mud Conditio ner Product L ine
Model
Mini Cobra 2-Panel MC Mini Cobra 3-Panel MC Cobra MC King Cobra MC
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10
CENTRIFUGES 10.1 Decanting Centrifuge
Centrifuges for oilfield applications were introduced in the early 1950s. The early applications used the available industrial decanting centrifuges and for this reason were called decanters in the oilfield. The current oilfield centrifuge has become a very important part of solids control in most solids control systems. Centrifuges continue to increase in use because of low-solids mud and environmental dewatering applications that require higher process volumes, greater clarification, increased solids capacity and additional fine solids removal.
10.1.1 Separation Process
A decanting centrifuge is so named because it decants, or removes, free liquid from a fluid containing solids. A decanting centrifuge consists of a conveyor inside a rotating bowl. (See Figure 10-1.)
Figure 10-1. Decanting Centri fuge
Decanting centrifuges subject the processed fluid to increased “G-forces”, thus accelerating the settling of solids in the fluid. The rotating bowl creates high G-forces (see Figure 10-2) and forms a liquid pool inside the bowl. The centrifuge is usually installed downstream from all other solids control equipment. The G-Force Algorithm is:
G-Force = 0.0000142 x rpm 2 x bowl diameter (inches) OR 2 G-For ce = [ rpm x bowl diameter (inches)] 70414 U
Figure 10-2. G-Force Algo rith m
96
Drilling fluid, (sometimes diluted with water or base oil), is pumped into the bowl through the feed tube. As the bowl rotates, centrifugal force pushes the mud out the feed ports into the bowl. The heavy, coarse particles in the mud are forced against the inner surface of the bowl, where the scraping motion of the conveyor blades moves them toward the solids discharge ports. The light, fine solids tend to remain in suspension in the pools between the conveyor flights and are carried out the overflow ports along with the liquid phase of the mud (see above).The free liquid and finer solids flow toward the cylindrical end of the centrifuge and are removed through the effluent overflow weirs. The heaviest solids settle against the bowl wall, forming a wall cake. These solids are pushed across the drainage deck or beach by the conveyor. The dewatering of the heaviest solids actually takes place on the beach. A gear box controls the relative speeds of the conveyor and bowl. The speed differential controls the rate at which the separated solids are discharged. The bowl and conveyor are rotated at speeds between 1500 and 4000 rpm depending on bowl diameter. In weighted mud applications, feed mud capacity rarely exceeds 25 gpm (95 liters/min). Total liquid throughput may be as high as 40 gpm (152 liters/min), including dilution liquid. Dilution liquid is required to compensate for increasing viscosity, generally associated with increasing mud weight which coincides with a much higher concentration of solids. The raw mud feed rate is substantially decreased as mud weight and solids concentration increases. 10.1.1.1 Weighted Water-Based Mud Appli cation s
In this application, centrifuges are used to process a small portion of the volume circulated from the wellbore to reduce the volume of colloidal-sized particles and thus improve the rheological (viscosity) and filtration properties of the mud. Viscosity and filtration properties can be controlled by discarding a relatively small amount of colloidal size solids and replacing the discarded liquid with fresh make-up water. (See Figure 10-3 for a typical rig-up for a weighted water-based mud system.)
Figur e 10-3. Weight ed Water-Base Mud 97
To remove these colloidal solids, the liquid fraction (the effluent) from the centrifuge is discarded and the underflow which contains the heavy semi-dry solids (predominantly weight material and some drilled solids) is returned to the active system. The centrifuge underflow (heavy solids) should be discharged to a well-stirred spot in the pit for thorough mixing with whole mud before the solids have a chance to settle to the bottom of the pit. This is especially important with a centrifuge, which discharges dry solids. The overflow containing liquid and colloidal solids is discharged to a waste container or the reserve pit for disposal. A centrifuge should be run when the mud viscosity or mud filtration exceeds the operator-established maximums. The maximum and minimum limits should be established as part of the mud program. The viscosity and the filtration rate will creep up when the centrifuge is shut down. Over-centrifuging and under-centrifuging should be avoided as the economics of operation are negatively impacted in either case. When centrifuging a weighted mud, bentonite and chemicals are lost with the discarded overflow and their concentration must be replenished. The amount of replacement bentonite may be calculated exactly from mass balance equations, but a good rule of thumb is to simply add about one sack of bentonite per hour of centrifuge operation. “Under-centrifuging” simply will not achieve the desired mud properties. 10.1.1.2 Unweight ed Water-Based Mud Appli cation s
As part of a “closed loop,” larger high capacity (75–500 gpm) {284-1893 liters/min} centrifuges are used to maximize drilled solids removal. The coarser solids fraction is discarded in dry form, while the liquid and colloidal solids fraction is returned to the mud system. See Figure 10-4 for a typical unweighted water-based mud system.
Figure 10-4. Unweighted Water-Base Mud
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10.1.1.3 Weighted Non Aqueous Fluids (NAFs) Appl icatio ns
In weighted, NAFs applications, a decanting centrifuge should be used to separate the effluent from the drilled solids and weight material. The effluent (containing the base fluid and fines) should be discarded, thus removing the fines that can cause rheology and filtration problems. The weight material and drilled solids are returned to the mud system to a well-stirred spot in the pit for thorough mixing with whole mud before the solids have a chance to settle to the bottom of the pit. Sometimes two centrifuges are used in series, especially when the liquid phase (effluent) is costly (Figure 10-5). The first unit returns the coarse solids fraction (weight material and drilled solids) to the active system, with the effluent, the liquid fraction, being routed to a holding tank. A second centrifuge, often a higher G-Force machine, strips out the heavy solids left in the effluent and discards them, returning the effluent to the active system. The customer makes the choice of how the centrifuge is used based on mud properties. NOV does not recommend returning the effluent from the second centrifuge back to the mud system. This effluent contains the colloidal sized solids that are causing the poor rheological and filtration properties and the effluent should be discarded.
Figure 10-5. Weighted Non-Aqueous Mud
Using centrifuges in series on a weighted non-aqueous mud is not as effective as using a single unit for controlling the viscosity and filtration properties of the mud. The cost of the base fluid will influence how one goes about removing detrimental solids. Usually the coarse solids fraction from the second centrifuge is discarded and the base fluid is retained for re-use. The second centrifuge is used to discharge solids that might grind down into colloidal solids but the effluent returned to the mud system still contains the colloidal sized solids that caused the detrimental mud properties. 99
10.1.1.4 Other Appl icatio ns
Other applications for centrifuges have become more important in recent years because of the centrifuge’s ability to remove free liquid from the solids discharge. As part of a “closed loop,” the decanting centrifuge is used to dewater the underflow from solids control equipment, usually hydrocyclones. One customer even used a big bowl centrifuge to dry the discharge from rig shakers to save fluid and reduce the waste volume discard. Large bowl high speed centrifuges, such as the HS-2172 can process 500 gpm (1893 liters/min) of unweighted mud and allow you the benefit of greater flow rates with extremely good separation which was not possible prior to this machine. Chemical enhancement (through the use of coagulants, flocculants, and other chemicals) is becoming more popular as an economical way to reduce dilution requirements and to reduce overall waste volume for haul-off and disposal. 10.1.2 Dewatering
There are times where one must minimize the fluid associated with discharged solids. A typical lay-out can be seen in Figure 10-6. The industry has dewatered water-based muds for many years. Chemically enhanced centrifuge separation uses a combination of mechanical G-Force and chemicals to remove fines (solids) that can’t be removed by normal mechanical means. The mud is tested to determine which chemical combinations work the best and how much of each chemical will be required for removing solids from the mud. Coagulants, acid and flocculants can be used as needed depending on the chemistry of the mud.
Figure 10-6. Dewatering Water-Based Mud: Dewatering and Clarification Process Typical Layout
The Dewatering engineer will select a specific, in-line mixer and length of “Hose A” depending on the time it takes to make good flocs for separation. Batch processing works the best but continuous processing works and is used the most. When environmental regulations become stricter more process equipment will be added to clarify and purify the treated water before reuse or disposal. 100
Operating Procedures
Operating procedures will vary from model to model, but a few universal principles apply to almost all centrifuges: •
•
•
•
•
Before starting a centrifuge, rotate the bowl or cylinder by hand to be sure it turns freely. Start up the centrifuge before starting the mud feed pump and dilution water feed. Set the raw mud and dilution feed rates according to the manufacturer’s recommendations (usually variable with mud weight). Remember to turn the feed and dilution water off before the machine is stopped. Centrifuges are relatively easy to operate, but they require special skills for repair and maintenance. Rig maintenance of centrifuges is limited to routine lubrication and speed adjustment of the unit.
10.2 CENTRIFUGE MODELS
(S EE A PPENDIX I - CENTRIFUGE CHART )
10.2.1 HS-3400 Centri fug e
Figur e 10-7. HS 3400 Centr ifu ge
In addition to the variable speed drive (VSD), the HS-3400 (Figure 10-7) comes with fully variable speed main and back drive (FVSD). FVSD models use variable speed back drive to adjust scroll (differential) speeds independently. They can automatically compensate for changes in torque that arise from increased solids density or increased solids loading. There also is a belt drive version available which is speed adjustable by changing pulley sheaves and v-belts. The HS-3400 has a bowl diameter of 14 inches (35.6 cm) and a bowl length of 49.5 inches (125.7 cm). The HS-3400 can process 205.7 gpm (779 liters/min) of 9.2 ppg mud or about 4.6 tons of solids per hour making a cut of 0.4 ppg (mud in 9.2 ppg and mud out 8.8 ppg). This data is from a certified test conducted June 19, 2002. The normal operating range for the unit is 100 - 160 gpm (379 – 606 liters/min). 101
10.2.2 HS-2000 Centri fug e The HS-2000 has three models; a cast steel base (C), a modular frame in-line drives (M) and a fixed drive (F). The HS-2000 C weighs 11500 lb (5216 kg) and is very stable (Figure 10-9). Each unit has a different footprint. The HS-2000 C is the shortest in length but the largest in width and height and weighs the most (see Appendix I for details). All three units have 12 port feeds. The HS-2000 F is a fixed drive unit where the C and M are VFD units. The bowl diameter is 18 inches (45.7 cm) and the length is 60 inches (152.4 cm). Each unit can process approximately 300 gpm (1136 liters/min) of water.
Figur e 10-9- HS 2000 Centr ifu ge
10.2.3 HS-1960 Centri fug e This centrifuge is a 19 inch by 60 inch (48.3 cm by 152.4 cm) unit designed with power in mind (Figure 10-10). The 100 hp main drive and 20 hp back drive makes this unit a workhorse. It has more power and more ability to handle high torque which equates to more throughput and better performance. Drilling fluid (mud) is introduced into the feed chamber of the HS-1960 through a feed tube and, with the assistance of built-in “S” shaped accelerators, exits into the bowl through two elongated windows. The HS-1960 centrifuge is able to exert up to 2,684 G’s on the mud. The HS-1960 is equipped with variable frequency drive (VFD) control, which provides a controlled application of motor drive power to the centrifuge components (bowl, conveyor and feed pump). Customized hardware and software packages can be designed to meet specific installation and operational requirements. With a processing capacity (water) of up to 350 gal/min (1325 lit/min), the HS-1960 series centrifuge is able to quickly process high volumes of mud while allowing prescribed mud weights and separation efficiencies to be maintained. This enables the HS-1960 series centrifuge to produce fine cut points at higher flow rates, making it ideal for high-flow applications and critical-conditions solids control. 102
Figur e 10-10. HS 1960 Centrif uge
Table 10-2. HS-1960 Centri fug e Featur es & Benefi ts FEATURES BENEFITS 350 gal/min (1325 lit/min) maximum processing High processing capacity for utilization in hi gh-flow drilling capacity (water) applications and conditions 75:1 ratio planetary gearbox Reduced motor size Feed from solids end Short feed tube with less vibration Variable frequency drive (VFD) control Easy adjustment of bowl, conveyor and feed pump speeds for varying process conditions, torque overload protection Bowl and heads forged of stainless steel Corrosion resistance for long life, smooth operation and low maintenance Stainless steel case High strength and corrosion resistance Tungsten carbide tiles and other wear Abrasion resistance for long life and low maintenance protection items Flush connections Aid in cleaning excess material from inside the case Case gaskets Contain process materials within the case Vibration switch shut-off mechanism Automatically disables operation in situations of high vibration Stainless steel rotating assembly Corrosion resistance for long life, smooth operation and low maintenance Split-case cover Easy access for inspection and maintenance Spherical roller and cylindrical roller main Long life and low maintenance bearings Sturdy WF-beam skid Solid foundation for smooth operation and long bearing life Six epicentric orifices Convey the liquid effluent to the discharge and enable easy adjustment of the pond depth Dual 6 in (152 mm) effluent discharge pipes High-capacity processing
10.2.4 HS-2172 There are three models of the HS-2172 centrifuge. The HS-2172 model (part # A11261) used in Canada has a feed outlet called the “MM” design. The MM type feed is a rectangular opening that allows for large flow rates and consequently processes a large volume of fluid. The model L has the feed entering the machine from the beach side of the centrifuge (Figure 10-11). Both models are 21 inches (53.3 cm) in diameter and 72 inches (182.9 cm) long.
103
Figur e 10-11. HS 2172 Centrif uge
Table 10-3. HS 2172 Features & Benefit s
FEATURES
BENEFITS
550 gal/min (2082 lit/min) maximum processing capacity (water)
High processing capacity for utilization in hi gh-flow drilling applications and conditions
75:1 ratio planetary gearbox
Reduced motor size
Fluid fed from solids end (HS-2172L)
Short feed tube with less vibration
Variable frequency drive (VFD) control
Easy bowl adjustment, conveyor and feed pump speeds for varying process conditions and torque overload protection
Bowl and heads forged of stainless steel
Corrosion resistance for long life, smooth operation and low maintenance
Stainless steel case
High strength and corrosion resistance
Entire scroll fitted with tungsten carbide tiles
Abrasion resistance for maximum operational life and low maintenance
Flush connections
Aid in cleaning excess material from inside the case
Case gaskets
Contain process materials within the case
Stainless steel rotating assembly (HS2172L)
Corrosion resistance for long life, smooth operation and low maintenance
Split-case cover
Easy access for inspection and maintenance
Spherical roller and cylindrical roller main bearings
Offer long life and low maintenance
Sturdy I-beam skid
Solid foundation for smooth operation and long bearing life
Dual 6 in (152 mm) effluent discharge pipes with optional bottom discharge
High-capacity processing
Five epicentric orifices
easy adjustment of pond depth
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10.3 Drying Centrifuges NOV has two distinct designs of drying centrifuges. These devices help reduce the amount of non-aqueous (diesel, mineral or synthetic-based oils) mud left on solids discharged by the drilling rig. Both units perform the same function but are designed differently. The Vortex Dryer is a vertical unit and can be used where vertical space is not limited. (See Figure 10-12 and 10-13.)
Figur e 10-12. Vortex Dryer
Feed solids
Screen
Screen basket basket
Recovered Fluid
Clean soli ds Figure 10-13. Vortex Dryer Flow Process
105
The Mud 10 and Mud 8 are horizontal units and can be positioned where head room is limited. The Mud 10 has a unique feed system that is difficult to plug and easy to work with as shown in Figure 10-14.
Figur e 10-14. Mud 10
The dryers reduce and recover base fluid from a variety of feed slurries. In drilling operations, shale shakers can discard drilled cuttings that are up to 20% oil by weight. The dryer can process the cuttings discharged from the shakers and reduces the oil content dramatically. It also can: • Recover valuable base fluid for reuse Reduce solid waste volumes to lessen haulage cost • Meet environmental objectives or guidelines • • Reduce fluid content on cuttings prior to other forms of treatment, thereby increasing waste treatment efficiency. Often, the dryer can meet more than one of these objectives simultaneously. In some applications, it offsets operational cost by saving time, reducing drilling fluid dilution needs or increasing process treatment capacity. Extensive field use of the centrifugal dryer and long term monitoring has proven that it can meet strict environmental discharge criteria. For instance, a dryer system can help operators comply with effluent limitations as mandated by the US Environmental Protection Agency for offshore drilling operations in American waters. 106
The dryers have been used in various applications including thermal desorption pretreatment and bioremediation pre-treatment. Numerous benefits are realized including energy conservation and increased process efficiency. 10.3.1 Vortex Dryer The Vortex dryer uses centrifugal force to recover oil from drilled solids with oil or synthetic-base drilling fluids. A stainless steel screen bowl traps ‘wet’ solids and accelerates them up to 540 G’s with centrifugal force. Liquid is forced through the screen bowl openings. Dry solids are extracted by the angled flights attached to the cone of the bowl. Tungsten carbide protects the flights from abrasive solids and ensures long operational life. In turn, this aids in maintaining a constant gap between the scroll and screen bowl, which is crucial for proper operation. Many units are supplied with a Variable Frequency Drive (VFD) to facilitate soft starting. Instant control by the VFD changes motor speed and thus G-force can be matched to operating conditions. An externally mounted lubrication system circulates clean oil to the differential gear assembly during operation. The lubrication system is electrically interlocked with the main motor starter to prevent machine operation in the event of low or no oil pressure to the gearbox. Each Vortex Dryer system is configured to specific wellsite requirements. Low-profile versions integrate dual augers to remove the solids. These models are ideal for height restrictive installations. Most units come with an overhead crane to facilitate maintenance of the screen bowl and rotating components. Newer units have the lid split in two pieces for easy removal. Vortex Dryer systems have set the standard for offshore operation and feature key elements for successful project completion, including: • Redundancy of critical components • Fit-for-purpose technology Certified operators to assure project success • Every effort has been made to reduce maintenance requirements for the Vortex. Normal wear parts are accessible from the top of the machine; belts can be changed without removing the gear assembly and the entire gear assembly can be removed with little effort. Special materials, such as tungsten carbide and ceramic tiles are applied to high wear areas. 10.3.2 Mud 8 and 10 NOV uses the horizontal Mud 8 and Mud 10 centrifugal dryers on rigs that have adequate horizontal space and limited vertical height. The Mud 8 and Mud 10 generate approximately 155 and 112 G’s respectively. The units are difficult to plug because of their feed tube design. They are dependable under heavy use and require very little maintenance and repair.
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11
CENTRIFUGAL PUMPS 11.1 Introduction Every centrifugal pump should be sized for its specific application. Only one centrifugal pump should be used per piece of solids control equipment. Accurate centrifuge pump selection can occur only with knowledge of system details. It is imperative that accurate information is used for the selection of a pump. The following information is required for selecting the proper pump for a specific application: Fluid temperature • • Specific gravity of fluid (maximum) • Pipe diameter • Length of pipe Fittings (elbows, suction design, etc.) • Elevation flow required • Head required at end of transfer • Type of driver required • Type of power available •
Without the above information, assumptions have to be made that could cause pump failure, high maintenance costs, downtime and/or improper performance.
11.2 Understanding Pump Performance Curves The head vs. flow curves in the Mission Centrifugal Catalog give the performance of the Magnum, 2500 Supreme, Vertical Magnum and Sandmaster pumps at various speeds and with various impeller sizes. The horsepower (HP) rating is based on pumping water with a specific gravity of 1.0. The flow is measured in US liquid gallons per minute (GPM). The total differential head is measured in feet. There also are a series of Efficiency and Net Positive Suction Head Required (NPSHr) lines showing the pump hydraulic efficiency and minimum NPSHr. The performance curves are plotted based on actual test results for each size of pumps running at various RPM with various impeller sizes.
To determine the HP required for your system you will need to determine the highest Specific Gravity (Sp.Gr.) of the fluid being transferred and then multiply the Sp.Gr. by the HP shown on the curve. To determine your Sp.Gr., divide the density of the fluid in pounds per gallon by 8.34 (Figure 11-1) : Specific Gravity = ppg of fluid 8.34 U
Figure 11-1. Specific Gravity Formu la
108
11.3 How to Select a Pump Details one needs to know to properly select a pump are as follows: 11.3.1 Pump Speed This depends on what kind of drive you put on the pump; 3500, 1750 or 1150 RPM for 60 Hz motors and 3000, 1500 or 1000 RPM for 50 Hz motors. Variable speed curves are provided for diesel, belt drive and hydraulic motors. 11.3.2 Total Head Requi red The total head (TH) required is the total of vertical elevation (He) and friction head (Hf) plus the head required at the end of the piping. TH = He + Hf + head required at of the end of piping . Subtract the suction head when the source of supply is above the pump. To calculate Friction Head losses, refer to the latest revision of NOV’s Mission Centrifugal Pump Catalog (document number 0001-0567-90). 11.3.3 Flow Rate Obtain the flow requirement in GPM or cubic meters per hour. 11.3.4 Specific Gravity Obtain the maximum specific gravity of the fluid to be pumped. 11.3.5 Procedur e for Selecting the Pump Impeller Size and Horsepow er Requirements 1. Find the required flow rate on the bottom or the top scale on the pump curve and draw a straight line up or down . 2. Find the total head at the left or right hand scale and draw a straight line to the right or left. Locate the intersection of the above two lines and pick the nearest larger impeller size. Speeds below 2900 RPM select impeller to next larger ¼-inch diameter and for speeds above 2900 RPM select impeller to next larger ⅛-inch diameter. Also, a set of horsepower lines gives you the horsepower requirement for pumping water (It is best to choose a motor size larger than the minimum required). If you pump fluid other than water, you have to adjust the required HP (kW) by multiplying the specific gravity to the HP (kW) rating based on water. Find the total head at the left or right hand scale and draw a straight line to the right or left.
109
11.4 Net Positi ve Suction Head (nps h) Net positive suction head is the useful pressure existing at the suction flange of the pump to push water into the impeller vanes. It is measured in feet of head. It is called NPSH Available (NPSHa). NPSH Required (NPSHr) is read from the pump curve at the designed pump impeller, RPM, and flow rate. NPSH on the curve is the lowest NPSH that will prevent the formation of vapor bubbles which cause cavitation.
Most customers are not concerned about NPSH problems. However, more than 50% of all rigs do have NPSH problems. These problems are due in part to high mud temperatures and poor suction design. You should check your net positive suction head (NPSH). NPSHa = Ha + He - Hf - Hvp
Where: NPSHa = NPSH Available NPSHr = NPSH Required Ha = atmospheric head feet He = elevation head feet (lowest possible liquid level above or below pump center line) Hf = Friction head feet (suction line friction losses) Hvp = Vapor pressure of fluid at pumping temperature (refer to latest revision of NOV Mission Centrifugal Pump Catalog, document number 0001-0567-90) The NPSHr as shown on the curves is the minimum NPSH required by the pumps. If the NPSHa is greater than the NPSHr the pump will perform. If the NPSHa is less than NPSHr then the pump will activate and some changes to the suction conditions are necessary. Possible solutions are reducing the flow rate, increasing the suction pipe size, selecting a larger pump or lowering the pump speed. 11.5 Formulas
To convert Head in feet to pressure in pounds per square inch: PSIG= Feet of head X Specific Gravity 2.31 To convert pressure in pounds per square inch (PSI) to head in feet: Feet of Head = PSIG X 2.31 Specific Gravity of mud Specific gravity of mud: Specific Gravity of Mud = Mud Weight (lbs/gal) 8.34 Horse Power (hp) of motor: Horse Power required = Curve HP X Specific Gravity of Mud
110
11.6 Details to Remember about Centrifugal Pumps 1. Volume leaving pump increases until the volume pumped causes total head losses equal to its impeller output head. 2. It will help in the selection of impeller size if the friction loss curve is plotted on the pump curve — Pressure or Head in Feet. 3. When the pump is running pressure will build up. Pressure developed by the centrifugal pump is always specified as Head in Feet liquid. The relation between PSI and head is shown in 11.5.2 and 11.5.3. When sizing centrifugal pumps, it is crucial to work in feet of head rather than PSI. PSI varies with the fluid weight while Feet of Head is constant. Centrifugal Pump Rotation : Stand at the drive end to determine the pump 4. rotation. A right hand rotation pump turns clockwise looking from the motor end. All the pumps featured in the NOV pump catalog are right hand rotation.
Table 11-1. Conversion Factors used wit h Centrifugal Pumps CONVERT FROM
CONVERT TO
m3/hr m3/min
GPM
4.4
GPM
264
liters/min liters/sec Barrels/day Cubic Feet Kg/cm M3
GPM GPM GPM Gallons PSI Gallons
0.264 15.9 0.02917 7.481 14.223 264
Meters Bars Kg/cm Grams/cu. cm
Feet PSI PSI Sp. Gr.
3.28 14.7 14.2 1.0
BHP = GPM X Feet X Sp. Gr . 3960 x Efficiency U
MULIPLY BY
U
KW = m3/hr x meters x Sp. Gr. 367 x Efficiency U
Efficiency from curve written as 0.XX
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12
MUD MIXING – AGITATORS AND MUD GUNS 12.1 Introduction There are two types of mud mixing devices used on drilling rigs, mechanical agitators and mud guns. Except for the sand trap all compartments in an active mud system must be agitated in order to suspend solids and maintain consistent mud properties throughout the surface system. Suspension of the solids permits their separation by the mechanical solids control equipment. 12.2 Mechanical Agitators Mechanical agitators (Figure 12-1) are the best means of mixing mud pits. Agitators use an electric motor to drive impeller blades which mix the mud in a specific pattern throughout the tank. Given proper tank design, agitator sizing and impeller placement, this method of agitation prevents settling, enhances the efficiency of solids removal devices and maintains a well- blended mud system.
Figure 12-1. Mechanical Agitator
12.2.1 Selectio n of Agit ator Size and Quantit y NOV will select the proper size and number of agitators based on the maximum mud weight expected, the size of the pit and pit function (See Table 12-1). Table 12-1. Agitator Selection Factors to Consi der 1. Maximum mud weight 2. Pit dimensions, L x W x H 3. Pit function; mixing or storage
112
12.2.1.1
Mechani cal Mud Agit ators
Agitators serve the drilling industry with high quality and time-proven mechanical agitation. MA The horizontally mounted MA series agitator has been the industry standard for many years. The rugged design, simplicity and dependability have made the MA agitator the preferred choice of a majority of operators and contractors. MA-RG The skid mounted MA-RG agitator is very compact. The low profile reduces headroom requirements and provides more layout space on top of the tanks. The gearbox is a triple reduction helical-bevel gear drive system that reduces the rotational speed of the motor to drive the impeller(s). Up to 95% mechanical efficiency helps reduce horsepower requirements. MA-RG-LP The MA-RG-LP agitator offers a lower profile version of the MA-RG. This is accomplished by using a base plate instead of the mounting skid to reduce the overall height. Maintenance and reliability are maximized by the triple reduction, helical bevel gearbox driven by an explosion proof motor. MA-RG-C The MA-RG-C agitator uses a C-face motor with a close coupling style. This variation also features a base plate instead of a mounting skid, reducing the overall height. VMA The VMA agitator is vertically mounted, reducing the footprint requirement. It offers a motor with a vertical direct mount to a helical inline gearbox with a drop bearing configuration. VMA-I The VMA-I agitator shares the same design principles as the VMA. The gearbox is equipped with a strong output shaft bearing rather than the drop bearing configuration. HMA AND HMA-RG HMA and HMA-RG agitators are very robust, heavy duty mechanical mixers. The gearbox is a triple reduction helical-bevel gear drive system that reduces the rotational speed of the motor to drive the impeller(s). These agitators are skid mounted and are offered with a 900 rpm or 1200 rpm motor. Impellers
Impellers are available with flat blades (radial flow), contour blades (axial flow) and canted blades (radial/axial flow). The impellers are sized according to tank volume and expected duty. Active mud system compartments - such as solids removal sections, mud mixing sections and slug pits - which need a higher shear force to produce immediate mixing, are another consideration in impeller sizing. For active mud system compartments less than 5 feet high (1.52 meters), a flat blade impeller can be used to induce radial flow patterns in the mud. Properly placed, the impeller will impart some axial flow to the system and suspension will be adequate for more applications. 113
High efficiency contour impellers are best for bulk storage tanks. This variable pitch impeller reduces horsepower requirements and induces less shearing force to the fluid. Canted blades are recommended, depending on the tank depth. Low shear contour blades are ideal for bulk storage and suction compartments. Shafts NOV offers several types of shafts. Mild steel shafts are cut to length and joined to the gearbox output shaft with a rigid coupling. Solid shafts are keyed at the bottom for adjustment of impeller height. A bottom end stabilizer is supplied when tank depths exceed 6 feet. The stabilizer reduces side loading and protects the agitator when auxiliary equipment is carried inside the mud tanks during rig moves. Hollow pipe shafts are available for deep tanks. They are supplied in flanged sections and bolted together making them ideal when lifting height is limited. Most hollow shafts use contour impellers that are bolted in place, further simplifying on-site assembly. Sizing Recommendations Regardless of what style agitator or impeller is used, proper sizing is critical. Impeller sizes are determined by calculating the Turn Over Rate (TOR) for each agitated compartment. TOR is the time required in seconds to completely move the fluid in a compartment and can be calculated by knowing the tank volume and impeller displacement. (See Table 12.3)
Flat Impeller
Canted Impeller
Axial Flo w
Contour Impeller
Radi al Fl ow
Table 12-2. Typical Tur n Over Rate Typical Turn Over Rate (TOR) Per Compartment Shaker
Intermediate
Suction
Reserve
Pill
Canted/Flat Impeller
50-75
50-75
65-85
50-80
40-85
Contour Blade
25-38
25-38
30-42
25-40
N/A
114
Table 12-2. Agitators Features & Benefits
G R A M
A M
P L G R A M
C G R A M
A M V
I A M V
A M H
FEATURES
BENEFITS
Explosion proof motors & starters (optional)
Can be used in a variety of places
Optimal mixing
Lower mud cost
Triple reduction helical gearbox
Quiet, efficient, low operational temperature
95% mechanical efficiency
Reduced horsepower requirement
Small footprint
Requires less space
Helical drive train gearbox
Quiet, efficient, low operational temperature
Robust worm-worm gearbox
Long life
Rugged design
Dependability
Low profile
Less head room
Baseplate mounted & motor direct mounted
Less head room
Double reduction helical gearbox
Smooth vibration free operation
Double/Triple reduction helical gearbox
Smooth vibration free operation
Motor 900 rpm & 1200 rpm
Large Impellers for use in deeper tanks
Specifications and Dimensions Model
Part Number HP
Length
Width
Height
Weight (less the shaft and i mpeller)
MA-3
3696
3
35¼ in (895 mm)
9 16 in (497 mm) 19 ∕
1511 ∕ 16 in (398 mm)
406 lb (184 kg)
MA-5
3705
5
40¼ in (1022 mm)
9 16 in (548 mm) 21 ∕
16¾ in (425 mm)
580 lb (263 kg)
MA-7.5
9740
7.5
1 8 in (1324 mm) 52 ∕
5 8 in (702 mm) 27 ∕
24¼ in (616 mm)
1200 lb (544 kg)
MA-10
3709
10
1 8 in (1324 mm) 52 ∕
5 8 in (702 mm) 27 ∕
24¼ in (616 mm)
1224 lb (555 kg)
MA-15
4442
15
1 8 in (1324 mm) 52 ∕
5 8 in (702 mm) 27 ∕
24¼ in (616 mm)
1320 lb (599 kg)
MA-20
3687
20
61¼ in (1556 mm)
34¼ in (870 mm)
1 8 in (689 mm) 27 ∕
1898 lb (861 kg)
MA-25
3696
25
5 8 in (1743 mm) 68 ∕
39½ in (1003 mm)
7 8 in (784 mm) 30 ∕
3130 lb (1420 kg)
MA-30
8789
30
5 8 in (1743 mm) 68 ∕
39½ in (1003 mm)
7 8 in (784 mm) 30 ∕
3180 lb (1442 kg)
MA-5RG
17511
5
40¼ in (1022 mm)
17 in (432 mm)
17½ in (445 mm)
500 lb (227 kg)
MA-7.5RG
19651
7.5
44 in (1118 mm)
275 / 8 in (702 mm)
177 / 16 in (443 mm)
500 lb (227 kg)
MA-10RG
17507
10
46 3 / 8 in (1178 mm)
26 in (660 mm)
18 in (457 mm)
750 lb (340 kg)
MA-15RG
16857
15
53¼ in (1352 mm)
26 in (660 mm)
195 / 8 in (498 mm)
885 lb (401 kg)
MA-20RG
12548
20
7 8 in (1495 mm) 58 ∕
26 in (660 mm)
2513 / 16 in (656 mm)
1267 lb (575 kg)
MA-25RG
12508
25
7 8 in (1699 mm) 66 ∕
3313 / 16 in (859 mm)
25½ in (648 mm)
2025 lb (918 kg)
MA-30RG
12554
30
7 8 in (1699 mm) 66 ∕
3313 / 16 in (859 mm)
25½ in (648 mm)
2027 lb (919 kg)
MA-40RG
14467
40
70 3 / 8 in (1787 mm)
36 in (914 mm)
263 / 8 in (670 mm)
2350 lb (1066 kg)
115
Specifications and Dimensions Model
Part Number HP
Length
Width
Height
Weight (less the shaft and impeller)
MA-15RG-LP
21544
15
51¼ in (1302 mm)
23 in (584 mm)
14 5 / 8 in (371 mm)
1008 lb (457 kg)
MA-20RG-LP
16980
20
56 in (1422 mm)
26 in (660 mm)
161 / 16 in (408 mm)
1500 lb (680 kg)
MA-25RG-LP
21541
25
67 in (1702 mm)
30 in (762 mm)
17¾ in (451 mm)
2298 lb (1042 kg)
MA-30RG-LP
14571
30
67 in (1702 mm)
30 in (762 mm)
17¾ in (451 mm)
2300 lb (1043 kg)
MA-40RG-LP
14572
40
70 in (1778 mm)
33 in (838 mm)
18 5 / 8 in (473 mm)
2500 lb (1133 kg)
MA-3RG-C
15915
3
34½ in (876 mm)
17 in (432 mm)
5 8 in (295 mm) 11 ∕
326 lb (148 kg)
MA-5RG-C
17044
5
37½ in (952 mm)
17 in (432 mm)
11¾ in (298 mm)
394 lb (179 kg)
MA-7.5RG-C
22806
7.5
40¼ in (1022 mm)
16 in (406 mm)
3 8 in (467 mm) 18 ∕
440 lb (200 kg)
MA-10RG-C
21505
10
45½ in (1155 mm)
21 in (533 mm)
3 8 in (339 mm) 13 ∕
745 lb (338 kg)
MA-15RG-C
22809
15
509 / 16 in (1284 mm)
22 in (559 mm)
14¾ in (375 mm)
880 lb (399 kg)
HMA-25RG (900 RPM)
23072
25
83 in (2108 mm)
399 / 16 in (1005 mm)
37 in (940 mm)
2250 lb (1020.5 kg)
HMA-30RG (1800 RPM)
13041
30
88½ in (2248 mm)
44 in (1118 mm)
339 / 16 in (852 mm)
2950 lb (1338.097 kg)
HMA-40RG (900 RPM)
19135
40
88½ in (2248 mm)
44 in (1118 mm)
37 in (940 mm)
3300 lb (1496.85 kg)
HMA-50RG (1200 RPM)
20866
50
88½ in (2248 mm)
44 in (1118 mm)
37 in (940 mm)
3150 lb (1428.815 kg)
VMA-3
12353
3
20 in (508 mm)
20 in (508 mm)
7 8 in (886 mm) 34 ∕
410 lb (186 kg)
VMA-5
13020
5
20 in (508 mm)
20 in (508 mm)
36½ in (927 mm)
595 lb (270 kg)
VMA-7.5
13021
7.5
20 in (508 mm)
20 in (508 mm)
407 / 16 in (1027 mm)
632 lb (287 kg)
VMA-10
22008
10
22 in (559 mm)
22 in (559 mm)
42 in (1067 mm)
967 lb (439 kg)
VMA-15
21649
15
22 in (559 mm)
22 in (559 mm)
48 5 / 8 in (1235 mm)
1009 lb (458 kg)
VMA-20
16648
20
26 in (660 mm)
26 in (660 mm)
50 5 / 8 in (1286 mm)
1257 lb (570 kg)
VMA-25
13025
25
26 in (660 mm)
26 in (660 mm)
55½ in (1410 mm)
1587 lb (720 kg)
VMA-30
13026
30
26 in (660 mm)
26 in (660 mm)
7 8 in (1445 mm) 56 ∕
1900 lb (862 kg)
VMAI-3
22012
3
20 in (508 mm)
20 in (508 mm)
319 / 16 in (802 mm)
410 lb (186 kg)
VMAI-5
23325
5
20 in (508 mm)
20 in (508 mm)
7 16 in (900 mm) 35 /
535 lb (243 kg)
VMAI-7.5
22010
7.5
20 in (508 mm)
20 in (508 mm)
38¾ in (984 mm)
632 lb (287 kg)
VMAI-10
22008
10
22 in (559 mm)
22 in (559 mm)
39 in (991 mm)
967 lb (439 kg)
VMAI-15
22009
15
22 in (559 mm)
22 in (559 mm)
47 5 / 8 in (1210 mm)
1009 lb (458 kg)
VMAI-20
22004
20
26 in (660 mm)
26 in (660 mm)
3 8 in (1381 mm) 54 ∕
1257 lb (570 kg)
VMAI-25
22003
25
26 in (660 mm)
26 in (660 mm)
5613 / 16 in (1443 mm)
1587 lb (720 kg)
VMAI-30
22006
30
26 in (660 mm)
26 in (660 mm)
59¼ in (1505 mm)
1900 lb (862 kg)
116
12.3 Mud guns For many years, Mud Guns (Figure 12-2) were the sole means of agitation. These devices usually carry mud from a down-stream compartment and spray it at high velocity into an upstream compartment to keep solids suspended. Mud Guns mix only where the gun is pointed, an inefficient process. The mixing effected by mud guns is restricted to the point where the nozzle-spray discharges, leaving dead spots in other areas of the tank. Also, mud guns increase the load on downstream solids control equipment because each nozzle adds 100 - 200 gpm (379 l/m - 757 l/m) of mud into the tank in addition to the normal flow from the well.
Figure 12-2. Mud Gun
12.4 Sand Traps
The sand trap is a settling tank and is usually the first compartment, or the first pit, in the surface system. A shale shaker is normally installed on top of the sand trap and discharges into it. Sand traps serve an important role in solids control by removing large particles and protecting downstream equipment from plugging caused by torn shale shaker screens, by-passed shakers or screens that are poorly sealed to the shaker bed. Particles that are greater than 74 microns (sand sized) can plug cyclones or other downstream equipment. Sand traps should have a top weir over which mud can flow into the next compartment and a slanted bottom, at 45º, with a quick-opening, quick-closing dump valve or gate so that settled solids can be discharged with minimum loss of mud. (See Figure 12-3)
Figure 12-3. API Drawing Showing Sand Trap
117
12.5 Tank/Pit Use The surface mud system consists of the flowline, active tanks, reserve tanks, trip tank, agitators, pump motors, solids removal equipment and gas removal devices. The tanks are classified as: Removal • Addition • Suction • • Reserve Discharge • • Trip Tank 12.5.1 Removal All compartments except the sand trap require proper agitation. Solids control equipment works best when solids loading remains constant. Slugs of solids tend to plug hydrocyclones and centrifuges. 12.5.2 Addi ti on The addition tanks need proper agitation. A mud system is treated with chemicals to alter the mud properties in order to achieve the desired performance characteristics or to increase mud volume. In critical situations, such as well-control problems, it is desirable to mix additives rapidly and thoroughly. NOV provides four- and six-inch hoppers along with a stand-alone shearing unit called TurboShear and a high pressure shearing unit called the HP Shear Unit. The four inch hopper can be equipped with 1” or 1½” nozzle; the 1½” nozzle is standard. The six inch hopper can be equipped with 1 ½”, 2” or 2 ½” nozzle; the 2” nozzle is standard. If one selects 80 feet of head for the inlet feed as shown in Table 12-2, the 1 ½” and 2” nozzles can handle 296 and 531 gpm (1120 and 2010 liters/min), respectively. For example, the six inch (15.2 cm) hopper using the 2” (5.1 cm) nozzle at 80-feet of feed head can handle 7-to-8 100-pound sacks of barite per minute assuming the back pressure is less than 50% of the inlet feed. (See Table 12-2.) Table 12-2. Hopper Flo w Rate for 6" NOV Mud Hopp er Inlet Pressure 1” 1 ½” 2” Feet of Head
2 ½”
50
105
227
403
627
80
130
298
531
830
90
140
317
566
885
100
150
337
600
938
130
167
375
665
1039
A hopper with a jet-venturi operates with a downstream back pressure of up to 50% of the inlet head. That is, if the hopper inlet feed rate is 80 feet of head the downstream elevation and frictional losses must be less than or equal to 40 feet of head (50% of 80 feet of head = 40 feet of head). If downstream elevation and frictional losses are more than 50% of the feet head one only has to increase the feed head to the hopper so that the back pressure is less than 50% of the feed. 118
Venturi sizes are matched to the nozzle size to ensure the greatest feed rate, while providing the highest shear rates. The liquid stream leaving the nozzle expands as it enters the hopper mixing chamber. Additives should be slowly and evenly sifted into the hopper. The additives are sucked into the hopper mixing chamber by the action of the liquid stream leaving the nozzle. Hopper feed rate is a function of additive density. Low density additives having a specific gravity of 2.6 like bentonite (gel), are mixed much slower than high density additives like API barite, which has a specific gravity of 4.20. Tests have shown that with 80 feet of feed head, a six inch hopper with a 2” (5.1 cm) nozzle can handle about eight 100-pound sacks of barite per minute or about 3.5 sacks of gel per minute. There is no reason to mount the hopper on top of the mud tanks since the jet-venturi allows for convenient location of the hopper. Sizing assistance should be requested when extensive piping or elevation is planned for the downstream side of the hopper. NOV provides a dust collector for its hoppers. The dust collector utilizes a 1-½ hp fan and filtration system to greatly reduce the air borne solids, creating a safer working environment. The air inlet is at the bottom of the dust collector and draws the air and dust into the polypropylene bag filter. Accumulated solids can be dislodged from the filter media into the hopper, reducing waste and keeping the process simple. NOV also can provide dual sack tables which allow two men to feed the hopper simultaneously. Contact your NOV representative for more information.
12.5.2.1 TurboShear
A properly designed mud system will have adequate storage and mixing capacity. (See Figure 12-4) In situations where adequate mixing or capacity is lacking, especially when rapid shearing is required, the use of the NOV TurboShear mixing system is recommended. The pre-mix system can mix bentonite and other hard to mix polymers such as CMC (carboxymethyl cellulose), PHPA (partially hydrolyzed polyacrylamide) and XC Polymer (Xanthan gum). The TurboShear mixes best when the fluid is circulated in one pit allowing the chemicals to properly hydrate before pumping into the active mud system or downhole.
Figure 12-4. TurboShear Unit
119
12.5.2.2 High Pressu re Shear Unit (HP Shear Unit)
This unit allows fast hydration and mixing of chemicals which are normally slow to hydrate, chemicals such as bentonite, polymers and lignite (see Figure 12-5). The chemical is mixed via the sack slitting unit or surge tank into the pre-defined pit with an "HP Shear Unit" installed. Suction is then taken from the designated pit through a designated low pressure mud line to a designated super charge pump and high pressure mud pump. The mud is then returned to the pit under high pressure through a designated high pressure line passing through the HP shear unit prior to entering the pit. This system is ideal for pre-hydrating bentonite and for mixing pre-mix mud, the advantage is that fewer chemicals need to be used because they react quicker and better once they have been sheared. NOTE the HP Shear Unit should not be used to shear weighted mud as it will degrade the weighting agent.
Figur e 12-5. High Pr essur e Shear Unit (HP Shear Unit )
120
12.5.2.3 Suction All compartments in this section require proper agitation and the selection of blade type and mixing styles are important. This section contains the tank(s) and/or compartment(s) from which the rig pumps and any charging pumps take suction. A slug/pill tank is usually included in this section. This compartment is used for the preparation of heavy slugs mixed to facilitate trips or viscous pills used to sweep the hole.
Figure 12-6. Agitator Blade Types and Flow Schemes
12.5.3 Reserve These pits require proper agitation. The contour-type agitator impellers give the best agitation and require less horsepower per unit of fluid displaced. These compartments are designed for long term storage of drilling fluids. 12.5.4 Discharge Those tank(s) or pit(s) that hold the drilling waste for discharge/disposal. NOV can provide various containers based on the type of waste generated. Some situations call for a container that can be used with a front-end loader, others might need a truck mounted tank or even the BTS (Brandt Transfer System). 12.5.5 Trip Tank This tank is used to isolate mud from the active mud system for gauging pipe displacement during tripping operations. No agitation is required under normal conditions. 12.6 Auxil iary Equi pm ent Rig Fan/Blower Mud Bucket •
•
121
12.7 Ag it ati on /Mix in g
All compartments in an active mud system other than the sand trap must be agitated in order to suspend solids and maintain uniform mud properties throughout the surface system. Suspension of the solids prevents their settling and permits their separation by mechanical solids control equipment. 12.8 Summary
A homogeneous mud system is a must. Good agitation helps keep the mud system homogeneous and reduces the amount of solids settling on the bottom of the pits. Mechanical agitators are the best means of mixing mud.
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13 MUD TANK SYSTEMS Mud tank systems are a critical component of any drilling operation for maximizing solids control efficiency and effectiveness. NOV markets two complete, flagship mud tank systems: The Ideal Mud Tank System and The Rapid Mud Tank System. Both systems are comprised of two tanks and are complete with all the essential solids control equipment necessary for successful drilling operations. Additionally, optional solids control configurations are available to suit the needs of specific applications. The Ideal system has a total active (operating) capacity of 1318 barrels (total/nominal capacity of 1500 barrels); while The Rapid system has a total active (operating) capacity of 620 barrels (total/nominal capacity of 800 barrels). Table 13-1. Mud Tank Syst ems Features & B enefits FEATURES BENEFITS Vertical, direct-driven centrifugal pumps Minimize the footprint required by the pumps Centrifugal pumps and control manifold Provides easy access for controlling processes installed on a pump porch Each centrifugal pump is located in close Allows for shorter piping runs with less friction proximity to a specific piece of equipment Maximizes horsepower and hydraulic efficiency Caustic barrel telescopes and remains on Allows for quick and easy mobilization and tank during transportation demobilization and also provides a safe way to add caustic to the mud system Vortex breakers at each suction Prevent cavitation of centrifugal pumps Minimal piping inside tanks Allows for proper agitation, thus improving homogenization of the mud Integrated cement and active bypass Prevents equipment contamination Sloped sand trap with integrated mud gun Facilitates quick, easy and thorough cleaning Electrical cable trays Eliminate cable sag Collapsible handrails Provide quick and easy rig-up, rig-down and transportation Mud level sensors (optional) Provide well control Reduce contamination of the drill site Hammerseal piping connections Facilitate quick and easy rig-up and rig-down, while guaranteeing proper alignment Fold-down crossover walks between tanks Facilitate quick and easy rig-up and rig-down, while eliminating the need for a crane lift Easy-access tank compartments Provide quick and easy access to tank compartments for maintenance, inspections, etc.
In addition to the Ideal and Rapid Mud Tank Systems, NOV also markets tubbottom, sloped-bottom and customized mud tank systems. As is the case with the Ideal and Rapid systems, these additional mud tank systems are complete with all the necessary solids control equipment for successful drilling operations. The tub-bottom system’s tank design virtually eliminates dead spots within the tank and ensures homogenization of the fluid. This two-tank system can be thoroughly cleaned without the need to physically enter the tank and has a total active (operating) capacity of 1028 barrels. The sloped-bottom tank design is a tried-and-true design with a bottom slope of four inches. This three-tank system also is easily cleaned and has a total active (operating) capacity of 1300 barrels (207 cubic meters). 123
Finally, NOV also markets customized mud tank systems per customer specifications. These systems typically consist of a custom-designed (per customer specifications) mud tank and all the necessary solids control equipment.
Figur e 13-1. Rapid Mud Tank Sys tem
Figur e 13-2. Ideal Mud Tank System 124
14
WASTE MANAGEMENT For years the basic solids control equipment for unweighted drilling fluid has consisted of the following items: Gumbo removal Mud gas separator Scalping shakers (optional) Primary shale shakers Dryers (optional) Degasser Desanders Desilters Centrifuge Dewatering system (optional) U
U
The equipment for weighted drilling fluid has consisted of the following items: Gumbo removal (if needed, primarily for offshore use) Mud gas separator Scalping shakers (optional) Primary shale shakers Dryers or drying shakers (optional) Degasser Mud cleaner/conditioner (optional) Centrifuges (one or two) Dewatering unit (optional) U
U
Unweighted muds use hydrocyclones and weighted muds use mud cleaners/conditioners (hydrocyclones mounted over a fine screen shale shaker). The industry then added equipment to help reduce mud losses or to dry solids being discharged and thus the industry coined the words “Waste Management.” Waste Management equipment can be sorted into three main categories: Cuttings storage Cuttings transfer Cuttings treatment and disposal
14.1 Cuttings Storage NOV provides several methods of storing drill cuttings or drilling waste to accommodate customer needs. Brandt transfer system (BTS) Catch tanks/shale sloops Cuttings boxes/skips FreeFlow air conveyors and slider tanks
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Figure 14-1. Brandt Transfer System (BTS)
14.1.1 Brandt Transfer System (BTS)
The Brandt Transfer System (BTS) consists of a patented submersible pump and transfer system that can pump drilling wastes and sludge (See Figure 14-1). The pump is available as a stand-alone, semi-portable unit on a traversing rack, mounted on a self-contained tank with integral power pack. The BTS is suitable for offshore, dockside or onshore installations. On land rigs, the BTS can be installed next to a closed loop system to capture discarded drilling waste, thus eliminating the need for backhoes or similar equipment. Once filled, the BTS can safely transport the waste slurry to the trucks that can haul off the waste. This process reduces costs by eliminating much of the need for trucks to stand by and provides a cleaner location (See Figure 14-2).
Figure 14-2. Trucks for Transport
The submersible pump features a unique intake assist head and hydraulic drive motor that easily mixes and moves concentrated slurries. The variable speed hydraulic motor provides flexibility for the handling of different types of waste.
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14.1.2
Catch Tanks /Shale Sloops
NOV catch tanks/shale sloops (See Figure 14-3) are metal containers used to store drilling waste. They come in various sizes to meet customer requirements.
Figure 14-3. Shale Sloop - The tanks have external bracing fo r suppo rt and smoo th interior surface to facilitate unloading
14.1.3
Cuttings Box es/Skips
NOV provides skips and cuttings boxes worldwide. Both types hold about 20-25 barrels (about 10 tons) of drilling waste and can be stacked to save space. North Sea skips are designed to DNV 271 Specifications and are approved by Lloyds register. (See Figure 14-4 and 14-5)
Figur e 14-4
Figur e 14-5 127
In order to ensure quick, safe and efficient emptying of the containers a cuttings box/skip turner is offered (Figure 14-6). The device helps empty the containers quickly and effortlessly.
Figur e 14-6
14.1.4
FreeFlow Slider Tank
The Brandt FreeFlow Slider Tank Storage Unit stores and transfers drilling waste. (See Figure 14-7) The unit design prevents the blockage associated with conventional conical bottom bulk storage tanks. The slider base allows the introduction of a flat bottom tank while eliminating the danger of bridging. Discharge is aided by the Slider Ram and the use of an integrated, controlled 14” (36 cm) discharge screw. The Slider Tank features diverter valves and load cells within the compact frame design which allows for easy installation of multiple tanks. Each tank is filled and emptied in a safe and controlled fashion aided by a PLC-based control system. The design of the Slider Tank allows for easy transportation by road and eliminates any need to modify a supply vessel for offshore transportation. The Slider Tanks have the following features:
•
•
Automated filling and discharge via diverter valves (common inlet and outlet) 82 bbl (13 cubic meters) available volume, 72 bbl (11.4 cubic meters) nominal fill volume
•
109 psi pressure rating
•
Zone 1 classification
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14.2 Cuttings Transfer Cuttings transfer methods are listed as follows: • BTS Brandt FreeFlow System • Air conveyor Slider tank Screw conveyors • • Vacuum units Moyno sludge pump •
14.2.1 Brandt FreeFlow System Brandt’s FreeFlow System is a positive pressure system for the transfer and storage of drilled cuttings. Normally used offshore, it allows cuttings to be transferred from below the shakers to almost any location on the rig. The Brandt FreeFlow consists of an Air Conveyor and Slider Tanks. The Air Conveyor (see Figure 14-8) transports solids from the shakers to the Slider Tanks (see Figure 14-9). Three or four Slider Tanks normally are used to provide temporary storage (in case of supply boats being unable to come alongside the rig or platform due to bad weather) and a further series of slider tanks are fitted onto the back of a supply boat. Transfer of cuttings from the storage tanks can be made directly to the tanks on the supply boat and after docking at the quayside cuttings can be transferred directly into a thermal processing plant. This process eliminates numerous crane lifts and greatly improves the safety of operations.
The system is flexible, as an air conveyor may be used on its own to fill skips, and, unlike competitive systems, FreeFlow can handle both wet and dry cuttings as well as cuttings from water-based and synthetic, oil-based muds. The ability to convey dried cuttings enables the system to be used in conjunction with a vortex or a mud 10 dryer, reducing the volume of cuttings shipped to shore and requiring additional processing by as much as 40%. The system’s ability to convey vertically in excess of 164 ft (50 m) means it also can be used for interfield transfer where drill cuttings from one platform or rig are transferred to another installation for disposal by injection. 14.2.1.1
Brand t FreeFlow Air Conveyor
The Brandt FreeFlow Air Conveyor offers unique features that ensure reliability and consistent performance. The chisel base minimizes bridging, while the integrated 14” (35 cm) screw ensures accurate feed control as cuttings entering the line are metered. The screw generates a series of aerated slugs, which improves pressure control and achieves a consistent flow pattern. Cuttings flow readily into the pipe in an aerated state. Such control minimizes pressure fluctuation, ensuring that pressures are safely controlled and low exit velocities are achieved. A single Air Conveyor can move more than 80 tons/hour of dried solids. The Air Conveyor also can transfer cuttings as much as 164 ft (50 m) 129
vertically, as is often required for inter-field transfers. The unit can transport wet or dry solids. If a cuttings dryer is being used, the processed solids (dry solids) are easily transported by the Air Conveyor.
Figur e 14-8
Figur e 14-9
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14.2.1.2 FreeFlow Slider Tank The Brandt FreeFlow Slider Tank Storage Unit is (see Figure 14-10) used to store and transfer drilling waste. The unit’s design prevents the blockage frequently associated with conventional conical bottom bulk storage tanks. The slider base allows the introduction of a flat bottom tank which removes the danger of bridging. (See Figure 14-11) Discharge is aided by the Slider Ram and the use of an integrated, controlled 14” (35 cm) discharge screw. The Slider Tank features diverter valves and load cells within the compact frame design. This allows for easy installation of multiple tanks. Each tank is filled and emptied in a safe and controlled fashion aided by a PLC-based control system. The design of the Slider Tank allows for easy overland transportation and eliminates the need to modify a dedicated supply vessel for offshore transportation. (See Figure 14-12) The Slider Tanks have the following features: •
• • •
Automated filling and discharge via diverter valves (common inlet and outlet) 82 bbl available volume, 72 bbl nominal fill volume 109 psi pressure rating Zone 1 classification Figur e 14-10
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Figur e 14-11. Slider Tank Cut -Away
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Figur e 14-12
Figure 14-13. Screw Conveyor
14.2.2 Screw Conveyors NOV can supply screw conveyors for any application. (See Figure 14-13) Screw conveyors are available with e-stop kill switches as well as grab lines, which stop the unit in the event of an emergency. A variable speed drive controls the rate of conveyance. The top of the units are fitted with expandable metal covers for feed areas and solids covers for non-feed areas. Screw conveyor size and horsepower requirements will vary with the length of the run, hole size, rate of penetration and flow rate. 133
14.2.3 Vacuum Units The Vacuum Transfer System (VTS) is able to move drilling waste and heavy slurries quickly, quietly and safely to various locations on the rig. (See Figure 14-14) Experience has shown that the vacuum pump is capable of transferring materials up to 30 feet (9.1 m) vertically and 90 feet (27.4 m) horizontally. Modular construction and a stackable design provide installation versatility and adaptability in a variety of situations.
Figur e 14-14
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14.3 Cuttings Treatment and Disposal
The equipment used to treat and dispose of drilling waste is listed below: • • • • • •
Cuttings Injection Bioremediation Drying Shakers Centrifugal Dryers Dewatering Thermal Desorption
Figure 14-15. Cutting s Injecti on (CI) Unit
14.3.1 Cuttings Injection (CI) (Note: Some call this Cutti ngs Re-Injecti on)
NOV has injected several million tons of solids downhole. Down-hole Cuttings Injection (CI) is considered a viable option for disposing of drilling waste. (See Figure-14-15) Tightening of the allowable discharge limits and the increasing cost of landfills/land farms have forced many operators to engage in long term planning for the handling of drilling waste, recognizing that environmental regulations are based upon the cradle-to-grave concept. The operator never escapes responsibility for the cuttings and the chemicals left on them. CI represents the following: •
• • •
The only permanent onsite disposal method that can fully comply with zero discharge to the surface environment. A method that returns cuttings to their native environment. The process does not discharge hydrocarbon waste into the air. An inexpensive process, as compared to many other environmental solutions which are not permanent. 135
Complex modeling techniques have been created to establish fracturing parameters for increased hydrocarbon production in tight and porous, brittle and ductile formations. These models work well as a guide for CI. To utilize the fracture models, an experienced CI subsurface engineer must temper the fracture design with cuttings injection experience to adequately judge how the formations are impacted from injection operations. CI procedures consist of a different set of parameters than what the fracture models were designed for. The fracture models for hydrocarbon simulation were designed for: • •
• • • •
High rates of injection to prevent sand-out. Injection with specific brittle particles that are large when compared to cuttings slurry particles. No distribution of particle size. High fluid horsepower at the formation face. Short duration pumping. Slurry that has low fluid loss is ultimately designed to create the maximum fracture that can be obtained.
Fracture modeling for CI follows these parameters: Cuttings slurry particles are small in size and soft/ductile in nature. The slurry is pumped at low rates for long periods of time. Injection is purposely designed to keep the fluid horsepower low. The slurry generally has a high fluid loss and minimally impacts the formation. Large fractures are undesirable.
Down-hole cuttings injection technology is used by many operators to dispose of drilled cuttings at the rig site. Developing sound slurrification and injection methods has played an important role in expanding the utility of cuttings reinjection. A clear, concise understanding of what happens down hole during the cuttings re-injection operation is critical to successfully implementing this technology and completing a project successfully.
14.3.1.1 Inject ion Proc ess Cuttings from the wellbore are removed from the drilling fluid using conventional solids control equipment, and then transported to the cuttings slurrification system using slides, vacuums or screw conveyors. When the cuttings reach the CI system, they are transformed into a slurry by mixing water with the drilled cuttings at an approximately a 4-to-1 ratio.
While the cuttings/water/chemicals are blended, the cuttings are reduced to an acceptable particle size distribution and acceptable rheology by grinding/shearing them into homogeneous mixtures with specially modified centrifugal pumps and mills. When cuttings reach the CRI system, they are transformed into slurry by mixing water with the drilled cuttings at an approximately 4 to 1 ratio. During shale sections higher volumes of water will be required, with slurry building its own viscosity while being processed by the modified centrifugal 136
pump. During shale sections the viscosity injection limits will be reached long before the weight so at this point the slurry should be injected. During sand sections, lower volumes of water will be used with the slurry weight injection range being reached first. During this process a chemical will be used to raise the viscosity to help suspend the particles before the slurry is injected. After homogeneous slurry is prepared and conditioned to site-specific properties, the cuttings slurry is injected through a dedicated conduit, such as the annular space between two strings of casing (annular injection) into the exposed formation. The cutting slurries are pumped at planned rates into the formation. When the pressure increase resulting from the pumping operation exceeds the strength of the exposed formation rock and the natural pore pressure, the formation allows the cutting slurries to flow into the formation. If the rheology/physical properties and pumping methods are correct, the formation will safely hold large amounts of cuttings. Below are some guidelines for slurry injection: Slurry Density 1.15 to 1.4 SG (9.6 to 12.5 ppg) Viscosity 60-80 funnel viscosity while processing shale 80-100 funnel viscosity while processing sand Solids Ratio 15-30% by volume as measured with a retort every 12 hours. Particle Size D90<300 microns % sand <0.25% measured with 50 X 50 US mesh sieve Process Continuous or batch, depending on ROP and fracture propagation behaviour. Injection Rate 1-5 barrel/min (206 – 795 liters/min) depending on ROP, formation and fracture propagation behaviour. 14.3.1.2 Operating Consid erations A variety of operational details must be dealt with to properly plan the project. Successful operations dictate that the majority of the work is done in the planning stage. Some of the details include: • • • • • •
• • •
•
Identification of suitable cuttings disposal/sealing formations Selection of surface equipment Design of the casing program Design of the injection program and contingency planning Plug prevention in the annulus and the formation Preventing slurries from breaching to the surface or fresh water formations The impact on existing or future producing wells Quality control/monitoring of injection procedures Abandonment of disposed waste to ensure that it is permanently entombed Obtaining regulatory approval 137
Characteristics of the subsurface environment, sealing formations, injection zone, slurry properties, drilling plans, subsurface slurry disposal dimensions and other elements directly impact each of these operational considerations. Of the various technical details that must be evaluated, the least understood but among the most important, are those questions associated with downhole considerations: • • • •
• • • • • •
Into what formation can the cuttings slurry be injected? How will the cuttings slurry be contained? In what direction will the cuttings slurry propagate? And how far? How significant of an impact will cuttings slurry have on nearby well bores/formations? How will the cuttings slurry affect existing wells and future drilling plans? What volume of cuttings slurry can be safely disposed of? What forces will be put on well casing? How do we inject the cuttings slurries to minimize formation impact? How do we protect the annulus and the formation? When the formation changes – what does the CI operator do next?
14.3.1.3 Lith olo gy Concerns Accurate description of the various lithologies and the transition depths from one Lithology to another is integral in determining where injection of the cuttings slurry should take place.
The disposal formation must be able to readily accept the cuttings slurry, and also must be massive enough to accommodate the volume of cuttings produced. The target formation should not contain natural fractures or faults that might communicate the slurry to the surface or to formations containing potable water. Additionally, the disposal formation must be associated with some type of seal mechanism that will adequately restrict the slurry to the specified formation interval. Review of mechanical property logs, cores, leak off tests, pore pressures, mud logs and other data from offset wells can be used as a tool when addressing these issues. Fracture modeling, although currently designed for hydrocarbon stimulation operations, have proven useful for estimating the size and shape of the disposal plumes. Seismic data can be utilized for identification of natural vertical fracturing that could make the project fail and can be utilized to define the formation properties, such as fracture rock strengths, pore pressures, and other elements crucial to CI.
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14.3.1.4
Surface Equipm ent Requi rements
The type of surface equipment required to process the drilled cuttings is based on a number of parameters established after addressing downhole considerations. The properties of the cuttings dictate the type of grinding equipment required. Modified centrifugal pumps designed to reduce the size of the cuttings using high shear rates are most effective when processing cuttings from soft, hydratable shale formations. All modified centrifugal pumps are not the same. In those instances where a sizable quantity of hard cuttings will be processed, the use of a mechanical grinder is recommended.
Proven equipment durability, manpower, requirements, utilities, ease of installation/time requirements and contingency plans all must be considered when designing the surface equipment system. Proper system design is important since any downtime for repairs or maintenance can directly impact the drilling process if injection is being done simultaneously. In zero discharge operations, the rig cannot drill if the CI surface equipment is not adequately designed and installed to stay ahead of the drill rate/surge conditions. The cost of CI equipment skyrockets when the drilling progress is negatively impacted. CI is not a service that should be evaluated and selected in the same manner one selects a shale shaker for a rig. A typical offshore installation can be seen in Figure 14-16.
Figure 14-16. Typical Offsho re CI Installation
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14.3.1.5
Casing Prog ram
The casing program is developed after the injection zone and sealing formations have been identified. The cement integrity of the surface casing defines the upper sealing boundary of the injection zone and the top of cement for the intermediate casing string provides the lower boundary. The injection plume takes the path of least resistance and is likely being initiated at the casing shoe. From that point, depending on a variety of conditions, it can extend vertically or horizontally. For this reason, the casing shoe must be set at an adequate depth below the top of the intended injection zone. In theory, the height of the top of the cement for the intermediate casing string is set to make certain that the length of exposed formation will allow for desired downward fracture growth. Experience in designing the subsurface injection profile and related casing/cement programs is paramount to successfully implement the technology. Ignoring the required engineering experience and judgment in this phase of the operation and in later evaluation of formation changes will result in failure.
14.3.1.6 Monitor ing Procedu res No matter how well the project is planned there is always the possibility of a break down resulting in disposal failure. The impact on the existing drilling program, the impact on future wells and the impact on the environment are all at risk if proper quality control of the slurry and the surface operation is not maintained. Quality control should monitor, at minimum, the following: • • • • • •
Pressure impact on nearby wells. Disposal plumes, direction and location. Injection rate, total volume and pressure. Disposal slurry properties, density, viscosity, rheology and particle size. Equipment condition. Experience level of operators/management.
In many cases, a meeting with the appropriate regulatory agencies will not be necessary, but adequate communication is always crucial to gain the agency’s understanding and approval. Obtaining early regulatory input has two primary advantages: • •
Allows the operator to comply with pertinent regulations. Provides the operator with an opportunity to hear concerns of regulatory personnel so that special needs can be addressed and appropriate changes made to the work plan.
Early dialogue makes it possible to resolve concerns and issues while developing the cuttings injection plan. Some of the main components of a Cuttings Injection system are shown in Table 14-1 and downhole injection options are shown in Figure 14-17. 140
Table 14-1 Main Components o f Cutti ngs Injection System COMPONENT
FUNCTION
OPERATED / MONITORED BY
Cuttings screw conveyor
Divert cuttings from cuttings caisson to screw conveyor
Drilling Crew NOV Service Engineer
Vacuum sys tem or FreeFlow s ystem
Transport cuttings from shakers to slurry tank
NOV Engineer/Drilling Crew
CI slurr y tank
Mix cuttings with sea-water and reduce cuttings size
NOV Engineer
CI classific ation shaker
Control slurry particle size to D90 <300 microns
NOV Engineer
CI roller mill
Aid breakdown of hard rock/cemented sands
NOV Engineer
CI holdin g tank
Temporary storage of classified slurry to allow control of rheology prior to injection
NOV Engineer
CI HP injection pu mp
Injection of slurry from holding tank into injection well
NOV Engineer
CI slurry injection line
Dedicated line to selected injection well
NOV Engineer/Drilling Crew
Charge pump
Provides sufficient suction pressure to the high pressure pump
NOV Engineer
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Figure 14-17. Cuttings Inj ection Optio ns
14.3.2 Bioremediation
Land farming is one of the best ways to dispose of drilling waste. The waste is spread over a specific amount of acreage and then fertilizer is spread over the solids to help decompose the waste. The microbes digest the waste into harmless nutrients which benefit the environment. 142
14.3.3 Drying Shakers
A drying shaker is a vibrating screen separator used to remove free liquid from cuttings prior to discharge. (See Figure 14-18) The effluent recovered is either pumped back to the active mud system or to storage for later use or to a centrifuge for further processing. Drying shakers are usually installed to process the cuttings discharged from the primary rig shakers or fine screen shakers. A typical drying shaker is a multi-screen unit, with a feed hopper in place of the traditional back tank. Drying shakers are optimized to provide maximum retention time and cuttings dryness. Large hole sizes or high penetration rates may require more than one drying shaker to provide acceptable cuttings dryness and liquid recovery. Shale shakers often are the cause of excess mud loss during drilling operations, primarily due to screening too fine for drilling conditions and due to the design of some shakers. This mud loss can greatly increase mud costs and site clean-up costs, especially when non aqueous fluids (oil-base muds or synthetic-base muds) are used. The drying shaker is designed to expose wet drilled cuttings to an additional vibrating screen surface and separate some of the bound liquid coating the surface of the solids. The liquid is then returned to the active system or transferred to a storage tank for future use or processed by a centrifuge.
Figure 14-18. Drying Shakers
14.3.3.1
Dryi ng Shaker Design s
The first drying shakers were “high-G” units, operating at 6.5 to 8 Gs. Prevalent thinking was that the additional impact force provided by the higher G-force would improve cuttings dryness. Recent field studies indicate this is not necessarily true. Oil content on cuttings is primarily a function of retention time on the screen surface and the exposure of the cutting to the vibration on the shaker screens. The G-force greatly affects the speed at which cuttings move from the feed end of the screen surface to the discharge end. At 4 Gs, the conveyance rate is close to 1 inch per second, while at 7 Gs the conveyance rate is about 5 inches per second. 143
Given a screen length of 24 inches and operation at 4 Gs, a cutting will take approximately 24 seconds to travel from the feed end of the screen to the discharge end. Increasing the G-force to 7 G’s reduces the exposure time to 6 seconds and will actually increase the amount of oil remaining on the cuttings! This assumes that both shakers having the different G-force have the same fluid end point (place where solids separate from the liquid and the solids leave the end of the shaker). Since the amount of oil remaining on the cutting is a function of exposure time; screen deck length and deck angle will greatly influence cuttings dryness. Screen deck length determines the distance a cutting must travel prior to discharge, and deck angle influences retention time - the longer the screen deck and the more uphill the deck angle, the greater the retention time. However, longer screen decks may not fit the available space and too steep an uphill deck angle will result in cuttings grinding and an unacceptable build-up of fine solids. Field tests indicate the optimum shale shaker dryer design provides about 4–5 Gs of force, with a deck design that is flat at the feed end to reduce cuttings grinding and maximize usable screen area. The discharge screens should be sloped uphill at 2.5°-to-5° to increase retention time and maximize cuttings dryness. The Cobra or the LCM-3D shakers are good drying shakers and both generate approximately 5.4 G’s. 14.3.3.2
Installation
Locate the drying shaker(s) at a lower level from the main linear shakers and other solids control equipment. Feed to the drying shaker should be through an open hopper sized to eliminate solids build-up or plugging. Cuttings should be evenly deposited as close to the feed end of the drying shaker as possible to maximize usable screen area. Provide slides or conveyors to direct “dry” cuttings to solids collection bins or discharge chutes Supply flooded pump suction in the liquid collection tank for transfer by pump to the desired storage or processing tank. The screens on the drying shaker should be finer than the screens on the main shakers to prevent the re-introduction of separated solids to the active system. Adjust the screen deck angle to properly convey solids, reduce liquid loss and prevent cuttings grinding. The liquid recovered from the drilled cuttings will contain base fluid, plus any solids finer than the screen mesh of the drying shaker. The recovered un-weighted liquid should be processed through a decanting centrifuge to remove fine solids before the mud is returned to the active system or storage tank. In some installations, the decanting centrifuge may be eliminated, but only after careful consideration of cuttings size and their effect on fluid properties.
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14.3.4 Dewatering
Dewatering is the final step of a closed loop system and follows the separation process after the shakers, hydrocyclones and centrifuges. The dewatering process can remove colloidal particles down to almost clear fluid by using the correct chemicals and a centrifuge that can generate over 2000 G’s. Waterbased mud easily can be dewatered and this process will be discussed in detail. Dewatering oil-base or synthetic-based mud is not easy and requires an extra step; the invert emulsion has to be broken before the water, oil and solids can be processed. The dewatering process incorporates coagulation and flocculation. Coagulation is electrostatic in nature. As discussed below most water-based solids are negatively charged and a coagulant would mitigate the repulsion charge and cause solids to agglomerate (come together). Flocculation, the uniting of particles in loose, porous groups or flocs, is brought about by the action of high molecular weight materials such as starch or polyelectrolytes chemicals. Most dewatering applications are in zero discharge areas where closed loop systems are required. Dewatering is done, at times, in areas where there are no unusual limitations other than the high cost or perceived negative future liability of off-site disposal. Dewatering policy varies from operator to operator. This variance is related to the corporate policy and to the economics of the application of dewatering. Continued pressure by environmentalists to reduce oilfield waste streams coupled with greater offsite disposal costs will mandate increased use of dewatering while drilling. There is a large volume of literature available on the subject of flocculation of treated clay water slurries (muds). Currently, there are numerous suppliers with a great variety of coagulants and flocculants available to the dewatering practitioner. Most of these suppliers offer technical assistance. Given the variety of products and technical systems, most fluids can be dewatered. The treatment levels required for dewatering vary from area to area due to lithological differences in the formations drilled within any specific region, and will vary due to differences in mud types and mud treatment levels. Laboratory tests and field experience has shown that chemical requirements increase with higher Cation Exchange Capacities (CEC) of the rock being drilled. As the mineral’s CEC value increases so does the amount of product necessary to achieve a floc of acceptable quality. Field experience indicates that dewatering is more difficult in areas that contain highly reactive drilled solids. The pH of a typical water-based mud ranges from 8 to 10 with specialty muds having a pH as high as 12 (example - lime-based muds). Solids in these muds are negatively charged and this charge prevents the solids from agglomerating. This is desirable in drilling but it interferes with solids removal, especially with the removal of fine solids. To remove these small undesirable solids we must make them agglomerate; make them form large dense clusters of solids so that a centrifuge can remove them. The process of agglomerations can require three steps. The first two steps, however, can be omitted with some fluids: 1. Destabilizing the submicron particles so they don’t repel each other. This can be done by adding acid to the mud. The acid lowers the pH and changes the charge of the solids. 145
2. Coagulate the solids, bring the solids together. We can do this by adding inorganic or organic chemicals. 3. Flocculate, bundle or wrap together to create a large dense cluster of solids. 14.3.4.1
The Dewaterin g Proc ess
Specific components are required in order to minimize the amount of chemical to dewater a mud while producing reusable water. One, two or three chemicals may be used to treat a mud. Pilot testing (testing a small portion of the mud) of the mud with acid, coagulant and flocculant helps give direction to the treating process. To dewater a mud we should consider using the following components: 1. A holding tank for storin g mud to be dewatered A complete dewatering system should use a tank type container for mud storage. This tank must be equipped as more than a storage container. The volume of fluid entering the tank must be measured and should enter at a point opposite the suction to maximize blending before dewatering begins. The tank must be equipped with mechanical agitators to ensure adequate blending of treating chemicals, thereby reducing the risk of over treatment. Ideally, the tank should be large enough to accommodate one-third fluid of the surface mud system. Sufficient storage capacity and a well-blended feed stream allow the dewatering system to simultaneously accept fluids from any well site source without disrupting the process. The effectiveness of the dewatering processes after the fluid leaves the tank is largely dependent of proper blending in the tank. If the pH of the mud needs adjusting it should be treated while in the holding tank. Treat slowly with acid and mix thoroughly. Most waterbased muds operate in the 9-to 12-pH range. There are chemicals that can floc solids at almost any pH, but at low pH, the chemicals used are cheaper and the flocs are more stable. Reducing the pH too much also can cause problems. It can reduce the pH of the active mud system to unacceptable levels. The preferred technique is to remove solids while maintaining the pH at the level in the active mud system.
2. Storage tanks for c hemicals Use one tank for acid and another for coagulant. Use two tanks for flocculant because its preparation takes time. One flocculant tank can be used for treating the mud while the other is used for the preparation of another batch of flocculant. 3. Pumps for metering mud volume and chemical treatment The type of pump used to control the feed stream from the storage tank to the flocculation manifold is very important. This importance is magnified when the fluid becomes more difficult to process and at other times when very fine control of chemical dosage is necessary. A variable speed, progressive cavity pump is preferred. Rheological properties of the feed stream are significantly affected by chemical injections, thus effecting manifold pressure. With high solids muds, the 146
viscosity in the flocculation manifold can become so high that a centrifugal pump cannot move the fluid. Unlike centrifugal pumps, progressive cavity pump output is unaffected by viscosity changes and the feed rate remains constant. Without uniform pumping rates, chemical additions must be constantly adjusted and over treatment is likely. Small metering pumps are required for acid, coagulant and flocculant additions.
4. A manifold with in-line mixers
The use of in-line mixers and sufficient residence time after the addition of coagulants and flocculants optimizes chemical usage. Different fluids require different treatments. Thorough mixing of each addition is critical to minimizing chemical usage. The use of in-line mixers of various lengths and a flocculation manifold with various lengths of hose facilitates this operation (Figure 14-19). The manifold should be sized appropriately to provide optimization between residence time and shear. A sample port should be located after each injection port so that the progress of the process can be monitored and treatment levels adjusted as necessary. Excess coagulant or flocculant in the processed centrifuge water is not undesirable because it can cause problems when it is returned to the active mud system. 5. High speed centri fuge
The treated mud should be metered into the centrifuge to facilitate the formation of good flocs just as the mud reaches the centrifuge. This takes time and practice. Here, a combination of science and art play an important role in optimizing the operation.
6. Storage tank for pro cessed water
A storage tank should be used to hold the processed fluid from the centrifuge. This fluid should be tested to make sure the pH and residual chemicals are at the proper values for recycling to the active mud system or disposal.
NOV supplies dewatering units that can remove solids and return good reusable water for drilling. The dewatering technician makes each component work synergistically to remove as many solids from the mud as possible. A typical dewatering diagram is shown in Figure 14-19.
147
Figur e 14-19. Dewatering Diagram for Water-Base Muds
NOV offers several models of dewatering units. A typical Texas unit is shown in Figure 14-20. This unit can be closed-in if weather conditions turn ugly. Each unit can process whole mud, returning reusable water to the mud system as shown in Figure 14-21.
Figur e 14-20. Brand t Dewatering Unit 148
Figure 14-21. Typical Dewatering Field Operation
Processed Mud Solids
Processed water (effluent) is discharged into small tank and then pumped to the active mud system.
There are numerous water-based mud types and each requires different treatment. The recommendations from Kemira, a polymer supplier for various mud types are shown in Table 14-2. One should perform small pilot tests to help select the polymers best suited for specific mud types. Field testing on site with small quantities is still recommended to make sure the polymers perform as required.
149
Table 14-2. An Example of Dewatering Chemicals f or Dril ling Fluids (Kemir a) FLUID TYPE
RECOMMENDED PRODUCTS
RECOMMENDATIONS AND ESTIMATED DOSAGE RANGE
Spud Mud
Coagulants : Cyfloc 6100, 6120, Superfloc C573 or C577 Flocculants: Cyfloc 1146, 1143, Superfloc A100, N100, A110 or C492 (dry products). Cyfloc 5500, 5320 Superfloc A1183 or A1881 or 1849 (emulsion products).
Most Spud muds dewater with a flocculant alone. In some cases, a coagulant might be required. Suggested dosage range for coagulants is 500-5000 ppm. and for flocculants is 200-1,000 ppm. pH reduction and/or dilution may be needed.
Non Dispersed
Coagulants: Superfloc C595, C577 or Cyfloc 6120 Flocculants: Cyfloc 1143, 4010, Superfloc N100 or A100 (dry products). Cyfloc 5500, Superfloc N1986, A1881 or A1849 (emulsion products).
Non-dispersed dewater with a coagulant alone. In some cases a flocculant might be required. Suggested dosage range for a coagulant is 500 - 5000 ppm, and for a flocculant is 200- 500 ppm. pH reduction may be needed and possible dilution.
Non dispersed KCl/PHPA
Coagulants: Superfloc C601, C607, C610 Flocculants: Cyfloc 1146, 1148, Superfloc C492 or C496 (dry products). Superfloc C1592 or 1596 (emulsion products).
Many non-dispersed KCl/PHPA muds dewater with a flocculant alone. In some cases a coagulant might be required. Suggested dosage range for a coagulant is 5000 10000 ppm. and for a flocculant is 200-500 ppm. pH reduction may be needed and possible dilution.
Highly Dispersed
Coagulants : Cyfloc 6000, 6100, Superfloc C521, C610, C573 Flocculants: Cyfloc 1143, 4010, Superfloc N100, A100 or A110 (dry products). Superfloc N1986 or A1849 (emulsion products).
Highly dispersed muds require a coagulant and an anionic or non-ionic flocculant. Suggested dosage range for a coagulant is 5000 – 10000 ppm and for a flocculant is 200 – 500 ppm. pH reduction may be needed and possible dilution
Saturated Salt
Coagulants: Cyfloc 6610, 6620, 6000, Superfloc C515, C517, C521 Flocculants: Cyfloc 1143, 4010 or 4020 Superfloc N100, A100 or A110 (dry products). Superfloc N1986 or A1849 (emulsion products).
Saturated salt muds dewater with a flocculant alone. In some cases, a coagulant might be required. Suggested dosage range for a coagulant is 2000 – 6000 ppm. and for a flocculant is 200 – 500 ppm. pH reduction may be needed and possible dilution
Sildril
Coagulants: Cyfloc 6100, Superfloc C573, C607, C610 Flocculants: Cyfloc 1143, 4010, 4020, Superfloc N100, A100 or A110 (dry products). Superfloc N1986, A1849 (emulsion products).
Sildril muds dewater with a coagulant alone a fter pH correction. In some cases, a flocculant might be required. Suggested dosage range for a coagulant is 2000 5000 ppm and for a flocculant is 200 – 500 ppm. pH reduction is needed and possible dilution
Potassium Silicate
Coagulants: Cyfloc 8500, Superfloc C591, C592, C595 Flocculants: Cyfloc 1143, 4010, 1146, Superfloc N100, A100 or C-492 (d ry products).
Potassium Silicate muds require a coagulant and an anionic or non-ionic flocculant. Suggested dosage range for a coagulant is 100015000 ppm. and for a flocculant is 200-500 ppm. pH reduction may be needed.
Central treatment centers, for drilling fluid blends
Coagulants: Cyfloc 6610, 6620, 6110,6120, Superfloc C515, C517, C573, C577, C607, C610, C7787, C9021 Flocculants: Cyfloc 1143, 4010, 1146, Superfloc N100, A100, C492
Suggested dosage range for coagulants is 500-5000 ppm and for flocculants is 200-1000 ppm. pH reduction and dilution may be needed.
150
14.3.5
Thermal Desorpti on
NOV provides two different types of thermal units that can remove oil and water from drilling waste.
Indirect Thermal Desorption Unit - THOR (See Figure 14-22)
Hot Oil Thermal Desorption Unit (See Figure 14-23)
Custom models are available that can process waste from one ton/hour to 15 tons/ hour. The control system for each unit can operate in manual or automatic mode. A centralized control room contains the necessary electrical switch gear, displays, programmable logic controller (PLC) and remote start/stop controls. A data logging system is provided to maintain records of the operation.
Figur e 14-22. Indir ect Thermal Desorp tio n Unit - THOR
Figure 14-23. Hot Oil Thermal Desorption Unit
The Hot Oil and Indirect Heat thermal units remove most of the hydrocarbon contaminants from the cuttings, including fuel oils to heavy oils. The systems have been uniquely designed and specifically customized for short and long chain hydrocarbons that may be present in drilled cuttings. The equipment can process a wide range of soil sizes from small fine solids (clays) to 4” rock.
151
14.3.5.1 Operation The following discussion will outline how a typical THOR unit works. Before processing, the contaminated cuttings are weighed and placed into a holding hopper equipped with a variable speed auger-feeder that meters the material fed into the rotary dryer at a rate up 10 to metric tons (wet) per hour. The dryer unit is designed to dry and heat the contaminated cuttings indirectly so that burner combustion gases do not come in contact with the cutting or the hydrocarbon/water gas stream. The externally heated rotary dryer is sealed on either end to limit oxygen entering the system and vapor exiting the system. The dryer shell heats the cuttings to between 600-800°F (316-427°C) by conductive heat transfer. A special cleaning system in the dryer shell eliminates caking of solids and keeps the material agitated to allow for even heat transfer. In order to guarantee vaporization of the water and hydrocarbons from the cuttings within the dryer, the cuttings stream must be thoroughly heated to the minimum temperatures required for complete vaporization of all liquid constituents. These temperatures are continuously monitored, regulated and recorded within the UL-approved control room. Retention time within the dryer varies between 20-40 minutes depending on specific clean-up levels required. Processed inert soil leaving the dryer is mixed with recovered water for dust control, cooling and added moisture. The cleaned gases are subsequently quenched and condensed with cooling sprays by means of a shell and tube condenser with cooling tower. The recovered liquid is then passed through an oil/water separator and coalescer. The recovered water is used for re-hydration of the processed cutting, and for make-up water in the cooling tower. The recovered oil is returned to the client for future use, or it can be used in the 20MM BTU primary burners to heat the processes. Processed inert solids discharged from the system can be utilized as road base, fill dirt or used in brick or construction projects. Air emission from the system meet or are below the standards set by the EPA 1990 Clean Air Act for Particulate Matter, SOx, NOx and VOC’s. In fact, the EPA is designating this type of system as BDAT (Best Demonstrated Available Technology) for cleanup of hydrocarbon contaminated soils. NOV thermal units are designed to operate 24 hours per day with scheduled maintenance one day per month. The footprint of this particular installation is approximately 100’x100’ (30m x 30m). 14.3.5.2 General The skid mounted THOR System (See Figure 14-24) is capable of processing 3000+ metric tons per month of oil-based mud drill cuttings containing a maximum of 25% oil, 25% water and 50% solids by volume. The processed solids will have less than 1% TPH when tested with the EPA 8015 protocol or similar. Levels of 0.1% are achievable as a function of higher operating temperature and longer retention time. The system is designed for a maximum solids discharge of 700-800°F (371-427°C), if needed. The area needed for processing is approximately 100 ft x 90 ft (30m x 27m), not including space for raw storage or processed storage. 152
Figur e 14-24. THOR System
14.3.5.3 Feed sys tem The feed mix of oil cuttings is introduced into the system through a vibrating grid to remove 4-inch and larger solids. A feed hopper between the vibrating grid and the feed screw holds the feed mix and prevents the intrusion of air into the dryer drum. A single 24inch variable speed conveyor with slow rotation and precise feeding is used along with a 25 HP VFD controlled feeder screw drive utilizing a dual gearbox arrangement. All are mounted on a separate feeder skid attached to the dryer skid. 14.3.5.4 Dryer Drum Indirect fired with four 5MM BTU/hr burners. Furnace separated into two 10MM BTU/hr zones for better drying control. The furnace length is 30 ft (9.1m). The dryer drum is 7 ft (2.1m) in diameter x 40 ft (12m) long. It is made from a high-strength stainless steel alloy for extended service at elevated temperatures. Angular flights are used to get the material into the drum following the feeder screw. Chains are used to break up the solids and assist with heat conduction. Lifting plates are used in the hot section to roll the material for final drying. A center dam is used to add to retention time. Rock lifting devices are provided adjacent to the center and discharge dams. 40 HP VFD controlled electric motor coupled to a helical gearbox provide variable drum rotation from one to six RPM at full load. An air/gear motor is provided so that drum rotation can be continued should a power failure occur. 153
Piping is provided that allows vapors to be pulled from the feed end or discharge end of the dryer. The firebox is built to withstand 2400°F (1315.55°C) and contains access panels, removable top, flame view ports to check flame trajectory and thermocouples to check firebox, stack and drum skin temperatures. Dual combustion air fans and associated controls, one mounted on each end of the dryer unit, provide air and fuel to the four 5MM BTU/hr burners. Triple layered stainless/composite leaf seals are used to seal each end of the furnace. Triple layered stainless/composite leaf seal, with a water spray fire quench system, are used to make the drum end cover seal at the discharge end of the drum. Furnace stacks are made from a high-strength stainless steel alloy for extended service at elevated temperatures. 14.3.5.5
Solids Discharge and Hydration
A 16-inch screw conveyor is used to remove the solids from the discharge end. A thermocouple is mounted in the discharge end to check discharge dirt temperature. The 16-inch screw conveyor deposits the hot dirt into an 18-inch screw conveyor for transfer to the re-hydration skid. The 18-inch screw conveyor deposits the hot solids into dual 12-in double tipping valves on the re-hydration skid to prevent air intrusion into the dryer. From the double tipping valve the solids enter a dual-shafted pug mill, which mixes water with the solids to cool and re-hydrate the solids. All screw conveyors are oversized to prevent stoppages and designed for hightemperature operation. 14.3.5.6
Vapor Recover y and Condensatio n
A quench tank is used as the initial mechanism to cool the vapor stream and remove entrained solids from the produced gasses. Cooling water is sprayed on the vapor stream in a specially designed quench tank where most of the hydrocarbon vapors are condensed along with some of the water vapor. In addition the entrained solids are removed by the small water droplets produced by the spray system. Re-circulated water is pumped through a series of spray nozzles to provide evaporative cooling in the quench tank and remove the solids. Cooling water is brought to the quench spray system from the weir separator tank and from the recovered water tank after passing through a plate and frame heat exchanger where the re-circulated water is cooled by water from the cooling tower. After passing through the quench tank, the uncondensed gasses move through the shell and tube heat exchanger where additional cooling takes place, bringing the vapor stream to its dew point temperature and condensing more water vapor and uncondensed hydrocarbons. The uncondensed vapors are directed to the oxidation system. The condensed liquids from the quench system and from the condenser are directed to the water treatment system. 154
A cooling tower is used to remove the heat from the system. The cooling tower, heat exchanger, and condenser system is capable of removing 12MM BTU/hr of heat from the system at maximum average dew point temperatures. Normal heat removal requirement is approximately 6.5MM BTU/hr. At 6.5MM BTU/hr heat removal, the cooling tower consumes about 20 gpm of makeup water. An Induced Draft Fan (IDF) moves the vapor and gasses through the system. 14.3.5.7
Oxidatio n syst em
A 5MM BTU/hr burner for thermal oxidation system destroys any remaining uncondensed vapors. The thermal oxidizer unit burns only a small amount of fuel and greatly improves the safety of the system and reduces air emissions to meet local codes. For safety, dual redundant flame arresters provide isolation between the thermal oxidizer and the other upstream systems. 14.3.5.8
Water Treatment System
A simple weir tank is used to make the initial separation of the oily emulsion from the water and the un-emulsified solids. The oily emulsion and the un-emulsified solids are directed to a high speed and high G force centrifuge where the solids are removed from the system. The liquid faction is returned to the water treatment system. A weir tank and a coalescing media oil/water separator are used to remove the recovered oil from the water. The recovered oil is sent to a retention tank for final polishing and settling before it is sent to storage. The water is re-circulated back to the quench system after it is pumped through a plate and frame heat exchanger to remove the heat. Excess water is directed to a recovered water tank where additional cooling takes place. This water is used to re-hydrate the processed solids. 14.3.5.9
Contro l syst em
The skid-mounted, climate-controlled control house is 33.5 ft (10m) long by 8.5 ft (2.6m) wide by 13.5 ft (4m) high. It has dual personnel doors, one on each side of the control house. Controls are furnished for 460-vac/60Hz/3-phase power. A multi-station motor control center provides control for all motors. A 75KVA Delta-Wye transformer and distribution panel provides power for operator controls and lighting. Variable frequency drives are provided for the drum drive, feed augur, induced draft fan and thermal oxidizer dilution air fan. The unit has large windows on one side and adjoining end for observing TDU plant operation. Each system has four data recorders providing 48 analog input channels for recording signals from thermocouples, flow meters, motor amp transmitters and pressure sensors. Optional Ethernet connection for data transfer to PC is available. 155
An operator control panel for motor stop/start push buttons, VFD controls, burner controls, motion detectors, data recording, and valve control is provided. Emergency Stop buttons are strategically placed at the motor control center and burner controls. 14.3.5.10 Utilities Water – 25 gpm maximum peak usage. Electrical power - 500 kW @ 0.8 P.F. Air – 150 ACFM @ 100 psi minimum. Fuel – 12 gallons per ton processed (depends upon moisture content of cuttings).
Table 14-3. THOR System — Weight s and Dim ensio ns Load
Shipping
Weight (lbs)
1 2
Dryer Skid Control Room
99,998 35,000
3
Oil/Water Separator Skid
35,000
4
Condensor Skid
49,000
6
Thermal Oxidizer Skid
40,000
8
Weir Tank
50,000
9
HS3400 Centrifuge & Stand
12,000
Weight (lbs)
Length (in)
Length (in) 590 585 518 510 360 360 185
Width (in)
Width (in)
Height (in)
Height (in)
132 111
152 170
118
159
120
158
120
138
120
108
96
132
Load Distribution (psi) Stands Front (2) Rear (2) 112 69
Load
Operating
1 2
Dryer Skid Control Room
3
Oil/Water Separator Skid
66,834
32
32
4
Condensor Trailer
58,337
28
28
5
Thermal Oxidizer
40,000
480
120
138
5
5
6
Pug Mill
19,750
180
121
120
9
9
8
Weir Tank
150,000
360
120
108
35
35
9
HS3400 Centrifuge & Stand
12,000
185
96
132
4
4
140,000 35,000
156
14.3.5.11
THOR Proc essi ng Capacity
On average 40,000 Tons/ year. The efficiency varies with water content, oil content and makeup of the solids phase. NOV engineering can provide specific efficiencies based on clients estimate of the percentages; however Figure 14-25 can be used as a guideline. Figure 14-25. THOR System Processing Capacity 14 12
THOR™ - 8 Thermal Oil Recovery System Throug hput At 25% Oil Con tam in ati on L evel
10 8 r u o H r e p s n o T
6 4 2 0 0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
32
Water Content %
14.3.6
Waste Management Servic es
NOV can provide several pieces of equipment that can make rig cleanup much easier (Figure 14-26):
Vacuum Units – used to help remove waste from the rig floor and around the rig. Tank cleaning equipment – can clean out the toughest solids from mud tanks.
Hot water pressure washers – used to wash-down equipment.
Diaphragm pump – used to transfer fluids.
Trash compactor – uses compaction to reduce the volume of waste material.
157
Small Vacuum Unit
Small Pressure Washer
Large Pressure Washer
Tank Cleaning System
Figure 14-26. Typical Cleaning Equipment
158
15 BULK STORAGE AND HANDLING NOV can supply the equipment needed to handle the products used for drilling and completion fluids. Big bag handling system. Big bag slitting unit. Bulk control system. Pallet lift system.
16
MUD CONDITIONING EQUIPMENT NOV provides all of the necessary equipment to properly prepare a good mud system for drilling oil and gas wells. Agitators Automated additive system Caustic barrel Centrifugal pumps Choke nipples Mix mixing hoppers Mud buckets Mud tanks Pre-hydration pit Rig blowers Sack cutting system Screw conveyors
17
INSTRUMENTATION
17.1 Introduction NOV utilizes instrumentation to save our customers money and time. Here is a list of items that are controlled or can be by some type of automated electrical device: Shakers – Variable Frequency Drive (VFD) and Single Board computer FreeFlow Air Conveyor – Programmable Logic Controller (PLC) FreeFlow Slider Tank – PLC Centrifuges – VFD – with Touch Screen Human Machine Interface (HMI) Cuttings Injection (CI) – PLC Liquid Additive Units – PLC
17.2 Programmable Logic Controller (PLC) A PLC is programmed to act like a brain for a specific piece of equipment. The PLC keeps equipment working at its highest potential. 159
17.3 Variable Frequency Drive (VFD) NOV utilizes VFD’S on several pieces of equipment, e.g. shale shakers, centrifuges and cuttings transfer systems. The VFD allows one to fine tune equipment performance.
18
PRODUCT LISTING
18.1 Gumb o Removal Gumbo Box (5-foot and 6-foot)
18.2 Mud Gas Separator 18.3 Shaker Header Standard units for multiple shakers Custom made for unique combinations
18.4 Rig Shakers Brandt Tandem Brandt Jr. Tandem Brandt Standard Brandt Jr. Standard
18.5 Primary Shakers Variable G-Force Option Upgrade Kit/Controlled Acceleration/Dual Motion Mini Cobra 2-Panel Mini Cobra 3-Panel Cobra King Cobra King Cobra II King Cobra Venom LCM-3D LCM-3D In-Line 4-Panel LCM-2D VSM 300 Automatic Shaker Control VSM Multi-Sizer
18.6 Cascade Shakers LCM-3D/CM-2 LCM-3D/LCM-3D LCM-3D/King Cobra
18.7 Shaker Screens VNM PXL (VSM 300) Replacement screens for competitor equipment; Derrick, MISWACO, etc…
160
18.8 Mud Cleaners VSM 300
18.9 Mud Conditioners Mini Cobra 2-Panel MC Mini Cobra 3-Panel MC Cobra MC King Cobra MC
18.10
18.11
18.12
18.13
18.14
18.15
18.16
Degassers VG-1 DG-ATM DG-5 DG-10 DG-12 Desanders 10-inch 12-inch Desilters 4-inch 2-inch (micro-fine separator) Centrifuges HS-3400 (3 models in USA & 3 in UK) 1850 (4 models) HS-1960 HS-2000 (3 models – plain, M & FS) HS-2010 HS-2172L Millennium (Canada) Drying Shakers Shakers Cobra King Cobra LCM-3D Centrifugal Dryers Vortex (vertical) Mud 10 or 8 (horizontal) Dewatering Units DWU 150 Northern USA models Automated models Processing and Dewatering tank (Canada) 161
18.17
W AST E M ANAG AN AGEMEN EMENT T
18.17.1
Cutting Transpor Transpor t BTS (Brandt Transfer System) Brandt FreeFlow System • Air Conveyor Conveyor Slider Tank • Screw Conveyor Various sizes are available based on requirements Vacuum Units EnviroVac SpaceSaver VTS (Quiet Pack Option) MiniVac RapidVac
18.17.2
Cuttings Storage BTS Catch Tanks/Shale Sloops Cuttings Boxes/Skips FreeFlow Slider Tank
18.17.3
Cuttings Treatment Cuttings Injection (CI) Bioremediation (site by site) Drying Shakers Cobra King Cobra LCM-3D Centrifugal Dryers Vortex (vertical) Mud 8 & 10 (horizontal) Dewatering Thermal Desorption Indirect Thermal Hot Oil Frictional heat
18.18
18.19
Mud Tanks Tanks Ideal Mud Tank System Rapid Mud Tank System Sloped Bottom Tub Bottom
Ag it ato rs MA-RG Series MA-R6C Series VMA Series
162
18.20
Mud Mixing Equipment
Hopper Venturi Back Pressure Unit Pallet Lift System Automatic sack cutting cutting unit Big Bag Slitting Unit Caustic Barrel Caustic Mixer Sack Handling Unit (with reservoir) Dust Collector plus cyclone Bulk Storage Tank Bulk Control System High Rate Mixer Liquid Additive Skid Pre-Hydration Mixing Tank and Hopper (TurboShear) HP Shear Unit
18.21
Au x il iar y Equi Eq ui pm ent
Safety Cool Rig Blowers • B-150 B-250 • B-400 • Filtration Units • Bag Filter Unit • Cartridge Filter Unit VPL 600 Vertical Leaf Filtration Unit • Portable Power Auxiliary • Diesel Fuel Tanks Distribution Panels Lighting Submersible Pumps Transfer Switches Transformers • Power Systems Diesel Generators Natural Gas Generators Temperature Control Equipment • Air Conditioners Heaters Chillers
163
164
19 APPENDICES 19.1 Appendix A - Pre-Well System Selectio n Checkli st 19.1.1 Well Design
Where is the well being drilled? What type of well is it — wildcat, development, injection, etc. What problems are anticipated?
19.1.2 Drilling Program
What are the bit sizes, casing points, and washout factors? What is the expected rate of penetration and type of bit? What is the mud program? Are there any environmental restrictions? What rig is being considered? Any anticipated hole problems?
19.1.3 Equipment and Vendor Capability
What size and type of solids need to be removed? What equipment is already installed? What is its process rate and expected removal efficiency? Are there sufficient mud compartments? Is the equipment installed properly? What additional equipment is needed? What is expected downtime? What are the power and fuel requirements? What rig modifications are required? What is vendor experience and safety record? Is HSE Plan available?
19.1.4 Logistics
Where is the specific location? Where is the local stock/service base? What on-site spares are required? How many additional people are required? Do they need housing or meals? What personal protective equipment is required?
19.1.5 Environmental Issues
What are the preferred mud treatment and disposal options? Will analytical testing be required?
19.1.6 Economics
What is the estimated mud cost per barrel per interval? What is the equipment acquisition and installation cost? What is the expected operating cost and expected savings? What is the expected disposal and site remediation cost?
165
19.2
Appendi x B – Mud Engineerin g
19.2.1 Hole Capacities To find the capacity of an unlisted hole size, use the following equation: (22/7) (r²) (0.0519) / (42) = bbls/ft Hole Size, inches
Hole Size, cm
Barrels/ft
Linear ft/bbl
Liters per Meter
Linear Meters per Liter
4.750 5.625 5.875 6.000 6.125 6.250 6.625 6.750 6.875 7.375 7.625 7.750 7.875 8.375 8.500 8.625 8.750 9.500 9.625 9.875 10.250 10.625 12.250 13.500 14.750 17.500 26.000
12.065 14.288 14.923 15.240 15.558 15.875 16.828 17.145 17.463 18.733 19.368 19.685 20.003 21.273 21.590 21.908 22.225 24.130 24.448 25.083 26.035 26.988 31.115 34.290 37.465 44.450 66.040
0.0219 0.0307 0.0335 0.0350 0.0364 0.0379 0.0426 0.0442 0.0459 0.0528 0.0564 0.0583 0.0602 0.0681 0.0701 0.0722 0.0743 0.0876 0.0899 0.0947 0.1020 0.1096 0.1457 0.1769 0.2112 0.2973 0.6563
45.649 32.552 29.840 28.610 27.454 26.367 23.466 22.605 21.791 18.936 17.715 17.148 16.608 14.684 14.255 13.845 13.452 11.412 11.118 10.562 9.803 9.123 6.863 5.651 4.734 3.363 1.524
11.4279 16.0259 17.4821 18.2340 19.0016 19.7851 22.2305 23.0773 23.9400 27.5488 29.4481 30.4216 31.4108 35.5261 36.5945 37.6787 38.7788 45.7115 46.9223 49.3915 53.2140 57.1789 76.0065 92.3094 110.1951 155.1152 342.3931
0.0875 0.0624 0.0572 0.0548 0.0526 0.0505 0.0450 0.0433 0.0418 0.0363 0.0340 0.0329 0.0318 0.0281 0.0273 0.0265 0.0258 0.0219 0.0213 0.0202 0.0188 0.0175 0.0132 0.0108 0.0091 0.0064 0.0029
166
19.2.3 Recom mended Range of Prop erties for Dispers ed Mud System These values are in the minimum range and are designed to be indicative of a water-based drilling fluid in very good condition. Dispersed muds refer to mud treated with lignosulfonate. Fast drilling rates where high volumes of drilled solids are incorporated into the fluid may make these minimum values difficult to obtain at the flow line. But, with proper use of solids control equipment and some treatment with chemicals, these properties should be obtainable in the suction pit. The rheology data was collected at 120 ºF.
Weight, lb/gal
Plastic Visco sity, cP
Yield Point, lb/100ft
Solids, %
8.5 9.0 9.5 10.0 10.5 11.0 11.5 12.0 12.5 13.0 13.5 14.0 14.5 15.0 15.5 16.0 16.5 17.0 17.5 18.0 18.5 19.0 19.5
6-10 10-12 12-16 14-18 16-20 18-22 20-24 22-26 23-27 25-29 27-31 29-33 31-35 33-37 35-39 37-41 38-42 40-44 42-46 44-48 46-50 48-52 50-54
1-3 4-6 4-6 5-7 5-7 6-8 6-8 7-9 7-9 7-9 8-10 8-10 9-11 9-11 10-12 10-12 11-13 11-13 12-14 12-14 13-15 13-15 14-16
2-4 5-7 8-10 10-12 11-13 13-15 15-17 17-19 19-21 20-22 22-24 24-26 25-27 27-29 29-31 31-33 33-35 34-36 36-38 38-40 40-42 41-43 43-45
167
19.2.4 Water-B ased Mud PV & YP Values @ 120 °F.
168
19.2.5 Recom mended Range of Prop erties for Non-Dispersed Mud System These values are in the minimum range and are designed to be indicative of a water-based drilling fluid in very good condition. Non-dispersed muds are normally muds treated with polymers. Fast drilling rates, where large volumes of drilled solids are incorporated into the fluid; may make these minimum values difficult to maintain at that the flow line. However, with proper use of solids control equipment and chemical treatment, it should be possible to maintain them in the suction pit. The rheology data was collected at 120 ºF. Weight, lb/gal
Plastic Viscosity, cP
Yield Point, lb/100ft
Solids, %
8.5 9.0 9.5 10.0 10.5 11.0 11.5 12.0 12.5 13.0 13.5 14.0 14.5 15.0 15.5 16.0 16.5 17.0 17.5 18.0
5-10 10-15 10-15 10-15 10-20 10-20 10-20 15-20 15-20 15-20 15-20 17-25 17-25 20-30 20-30 25-35 25-35 30-40 30-40 35-50
5-10 5-10 5-10 5-10 5-10 5-10 7-12 7-12 7-12 7-12 8-12 8-12 8-15 8-15 10-15 10-15 10-15 10-15 10-15 10-15
2-4 3-5 5-7 7-9 9-11 11-13 13-14 14-16 16-18 18-20 20-22 22-24 24-26 26-27 28-29 29-31 31-33 33-34 35-36 37-38
169
19.2.6 Recommend ed Range of Pro perties fo r Non-Aqueou s Mud Systems These values are in the minimum range and are designed to be indicative of drilling fluids in good condition. Fast drilling rates, where high large volumes of drilled solids are incorporated into the fluid, may make these minimum values difficult to maintain at that the flow line. However, with proper use of solids control equipment an d appropriate treatment, it should be possible to maintain them in the suction pit. The rheology data was collected at 150 °F. Gels Weight, ppg
Plastic Viscosit y, cP
Yield Point, 2 lb/100 ft
Oil/Water Ratio
Solids, %
10 Sec
10 Min
9
9-14
4-7
70/30
5-7
5-6
9-15
9.5
10-15
4-7
70/30
6-8
6-8
10-16
10
11-16
4-8
70/30
7-9
7-9
10-16
10.5
13-18
5-9
70/30
9-10
7-9
10-18
11
16-21
5-9
75/25
10-12
8-9
11-19
11.5
19-24
6-9
75/25
12-13
8-10
12-20
12
22-26
7-10
75/25
14-16
8-11
12-22
12.5
24-28
8-11
75/25
16-18
8-12
12-24
13
26-29
9-12
75/25
18-20
8-14
14-26
13.5
28-32
10-13
75/25
20-22
8-14
14-26
14
30-34
10-14
80/20
22-24
8-15
15-28
14.5
32-36
10-16
80/20
24-26
8-15
15-28
15
34-38
10-18
80/20
26-28
8-15
15-28
15.5
36-40
11-18
85/15
28-30
8-15
15-29
16
38-40
11-20
85/15
30-32
8-15
15-29
16.5
40-44
11-20
85/15
32-34
8-15
15-30
17
42-46
11-20
85/15
33-35
8-15
15-30
17.5
44-48
11-20
90/10
35-37
8-15
15-30
18
46-50
11-20
90/10
37-39
8-15
15-31
18.5
48-52
11-20
90/10
39-41
8-15
15-31
19
50-54
11-20
90/10
41-43
8-15
15-31
19.3 Appendi x C - Standard Mud Calcu lations 19.3.1 Mud Volume o
Capacity annulus in bbl/ft = [(hole size) 2 - (pipe OD) ²] (0.00097)
Approximate capacity of hole in bbl/1000 ft = (diameter of hole) ² o Pit volume in cu ft = (Length) (Width) (Depth) o Pit volume in bbl = cu ft/5.6 o Hole volume in bbl = [(hole capacity, bbl/ft) (depth, ft)] - pipe displacement (bbl) o Annular volume in bbl = hole volume - capacity and displacement of drill pipe o Total Volume = hole volume + pit volume o
170
19.3.2 Circulation Data
Pump output in barrels per minute (bpm) = bbl/stroke x strokes/minute
o
o
Annular velocity in fpm =
pump output (bpm x 100) U
annular volume (bbl/100 ft) o
Bottoms up in minutes =
annular volume (bbl) U
pump output (bpm) o
Hole cycle in minutes =
pump output (bpm x 100) U
pump output (bpm) o
Mud cycle in minutes =
total volume (bbl) U
U
pump output (bpm) 19.3.3 Solids Determination 19.3.3.1 Low Weight Muds (muds wi thou t weight material or oil) o
Percent solids by volume = (mud weight – water weight)(7.5)
o
Correction for oil: For each 1% oil, add 0.1 to the % solids by volume
o
Correct for NaCl: For each 10,000 ppm salt, deduct 0.3% solids by volume. Ignore if salt content is less than 10,000 ppm. Convert Cl ppm to salt ppm (Cl ppm x 1.65 = salt ppm)
19.3.3.2 Weighted Muds o
Percent by volume desired solids = (mud weight-6)(3.2)
19.3.3.3 Drill Solids per Foot of Hole (assuming S.G. = 2.6) o
Barrels per foot = (hole size + washout) 2(0.00097)
o
Pounds per foot = (barrels per foot)(910.7)
171
19.4 Appendi x D - Solids Contro l Evaluation Calcu lation s A. Average Specific Gravity (SG) of solids in WBM 1. Freshwater muds SGa = (12 x ρ) - Vw Vs 2. Salt water muds SGa = (12 x ρ) - (Vwc x SGw) (100-Vwc) B. Volume percent solids (Vs) in freshwater muds, without weighting material Vs = 7.5 x ( ρ - 8.34) C. Volume percent solids in freshwater muds containing barite, SG = 4.20. Vb = (SGa – 2.6) x Vsc x 0.625 Vlg = Vsc – Vb D. Volume percent solids in freshwater muds containing hematite, SG = 5.10 Vh = (SGa – 2.6) x Vsc x 0.417 Vlg = Vsc – Vh E. Volume percent in muds containing oil >1% or salt >10,000 ppm Vlg = [(Vw x SGwc) + (Vo x SGo) + (Vsc x SGhg)] – (100 x SGm) SGhg - SGlg F. Bentonite and reactive clay corrections CECa = 7.69 x (MBTm) Vlg Vben = Vlg x (CECa – CECds) (CECben–CECds) U
U
U
U
U
U
172
19.4.1 Terms CECa = Average cation exchange capacity (CEC) CECben = CEC of bentonite, typically 60 CECds = CEC of drilled solids, typically 10 Cl = Total chlorides, milligrams/liter (mg/l) Ρ = Mud density, ppg MBTm = Methylene blue test, pound per barrel (ppb) SG = Specific gravity SGa = Average specific gravity of solids SGhgs = Specific gravity of high gravity solids (HGS) SGlgs = Specific gravity of low gravity solids (LGS) SGm = Specific gravity of mud SGo = Specific gravity of oil SGw = Specific gravity of water SGwc = Specific gravity of water, corrected for chlorides Vb = Volume % barite (entered as 50% not 0.50) Vh = Volume % hematite Vhgs = Volume % HGS Vlgs = Volume % LGS Vs = Volume % solids Vsc = Volume % solids, corrected for salt Vw = Volume % water Vwc = Volume % water, corrected for salt
173
19.5 Appendi x E - Field Calculatio ns of Solids Disch arges 19.5.1 Field Calculatio ns t o Determine Total Solids Discharg e Note: This method produces only a quick approximation of solids removal rate and should be used only for unweighted muds, or where quick comparisons need to be made on a mud system to observe the results of conditions change. Are solids removal rates increasing, decreasing, or unchanged? •
•
•
Use a one-quart container and wristwatch to determine how many seconds (R) it takes to collect one quart of slurry from a cyclone underflow or a screen discharge. Use as large a sample volume as feasible; a five gallon sample would be better than a quart sample. Use a mud balance to obtain the density ( ρ) of the slurry in ppg. Mix the sample well before weighing the mud. Use the following equations to calculate the rate of solids removal in pounds per hour. (ρ - 8.34) (1450) = Total Solids Removed in lb /hr U
U
R ρ
= Density of slurry in ppg.
R
= Rate of solids slurry discharge in sec/qt
8.34
= Density of Water, ppg
Example: Given the following data, ρ = 12.3 ppg
R = 8 sec/qt Then (ρ - 8.34) (1450)
=
Total
Solids
Removed
in
(12.3 - 8.34) (1450) = lb/hr 8
Total
Solids
Removed
in
U
U
lb/hr
R
U
U
(3.96) (1450) U
U
=
717.75 lb/hr
8
174
19.6 Appendix F - Solid s Contr ol Perform ance Evaluation There are several methods used to determine economic performance. This appendix describes a method to compare the cost of dilution versus the cost of mechanical solids removal by a centrifuge. It utilizes the concept of a dilution factor (the amount of mud required to maintain a given solids concentration for every barrel of drilled solids that are incorporated into the mud) to determine dilution requirements. This method may be used to determine economic efficiency of any type of solids control equipment. Note: Effluent is defined as the process stream returned to the active mud system. The underflow is defined as the waste stream removed from the mud system and discarded. Example: This is an example for unweighted water-base mud. Given: Feed Rate = 30 gpm Underflow Density ( ρu) = 17.0 ppg Feed Density ( ρf ) = 10.0 ppg Effluent Density ( ρe) = 9.0 ppg Total Low Gravity Solids = 6% Mud Cost = $15/bbl Disposal Cost = $10/bbl Equipment Cost per Day = $600
Note: It is very difficult to determine an accurate mud density of dry solids discharged by a centrifuge unless one uses a gravimetric approach to mud weight. A gravimetric method would be similar to using the Retention of Oil on cuttings (ROC) technique used in the Gulf of Mexico in the USA. This requires a balance and a calibrated sample cup (for the ROC we use a 50 ml retort cup). In the above example we will assume the discharge of solids from the centrifuge is very soupy (not dry) and a regular mud balance was used to obtain the density of the sample collected. This assumption eliminates the possibility of trapped air in the sample.
Feed Rate, Vf = 30 Feed Density, ρ f = 10.0 ppg
Solids Control Equipment (Centrifuge)
Effluent Rate, V e = ? gpm Effluent Density, ρ e = 9 ppg
Underflow Rate, V u = ? gpm Underflow Density, ρ u = 17.0 ppg 175
With the given data determine the follow ing: 1) Determine the Effluent and Underflow Volume Rates. 2) Calculate the Low Gravity Solids Removed per minute. 3) Calculate the equipment effectiveness and cost, compared to dilution 4) Calculate economic benefits 1) Determine the Effluent and Underflo w Volu me Rates. (ρf ρf) (Vf) = (ρu) (Vu) + ( ρe) (Ve); Where: ρf = Feed density of the slurry, ppg ρu = Underflow density, ppg ρe = Effluent density, ppg Vf = Feed rate of slurry, gpm Vu = Underflow volume, gpm Ve = Effluent volume, gpm
Since the feed volume is equal to the underflow volume plus the effluent volume then, Vf = Vu + Ve We can rearrange as follows: Ve = Vf - Vu Then, use this to help solve the equation as shown below, Substitute the (Vf – Vu) for Ve to help eliminate one unknown and solve, (10.0) (30) = (17.0)(Vu) + (9.0) (30 - Vu) = 300 = 17Vu + 9 (30 – Vu) 300 = 17Vu + 270 -9Vu 300-270 = 17Vu – 9Vu 30 = 8Vu 30/8 = Vu Vu = 3.75 gallons per minute underflow rate volume And since Vf = Vu + Ve, and Vf = 30 and Vu = 3.75 then, solve for Ve; 30 = (3.75 + Ve) 30 – 3.75 = Ve = 26.25 gallons per minute Therefore, we have determined the following flow rates: Flow rate, gpm Underflow = 3.75 gpm Effluent = 26.25 gpm
176
Feed Rate, Vf = 30 Feed Density, ρ f = 10.0 ppg
Solids Control Equipment (Centrifuge)
Effluent Rate, V e = 26.25 gpm Effluent Density, ρ e = 9 ppg
Underflow Rate, Vu = 3.75 gpm Underflow Density, ρ u = 17.0
2) Calculate the Low Gravity Solids Removed per mi nute. a) Calculate the low gravity solids in the underflow: Let X = the decimal fraction low gravity solids 17/8.34 = X (2.6) + (1-X) 2.04 = 2.6X + 1 - X 1.04 = 1.6X X = 1.04/1.6 = 0.65 or 65% solids in underflow b) Calculate the low gravity solids removed: 3.75 * 0.65 = 2.44 gallons of low gravity solids removed per minute The low gravity solids removed per minute = 2.44 gpm
3) Calculate the solids contro l equipment cost c ompared to dilution a) Dilution: Assume the 9.0 ppg fluid is the desired fluid mud weight. It contains 6% solids. The equivalent dilution required to treat the solids removed is the volume removed divided by the desired fraction of solids. 2.44/.06 = 40.66 gpm dilution required to match the machines effectiveness or [(40.66 gal/min) (60 min/hr)] / (42) gal/bbl = 58 bbl/hr equivalent dilution Dilution Cost, $ = Volume * (Mud Unit Cost + Disposal Unit Cost) Dilution Cost, $ = 58 bbl/hr * ($15/bbl + $10/bbbl) = $1450/hr $1,450 per hour = equivalent dilution cost b) Mechanical Treatment Cost, $ = [(Liquid Volume Lost) (Mud Unit Cost + Disposal Unit Cost)] + Equipment Cost If we assume the discharged solids contain 35% by volume mud, then (3.75 gpm) (0.35) = 1.3 gallons of liquids lost per minute or, (1.3 gal/min) (60 min/hr) / (42 gal/bbl) = 1.85 bbl/hr liquids lost Mechanical Treatment Cost, $ = [(1.85 bbl/hr) ($15 + $10)] + $600/24hr = $71.25 per ho ur = equipment co st to remove solids 177
4)
Calcu late the econom ic benefits $ = (cost to remove) - (cost to dilute) $ = ($71.25 - $1,450) $ = $(1,378.75) $ in parenthesis ( ) = Savings, Removal compared to Dilution
Therefore, in this example, prompt and continuous removal of drilled solids will save $1,379 per hour with a cost to remove being $71.25 per hour.
178
19.7 Appendix G - Conv ersio n Constant s and General Inform ation 19.7.1 Conversio n Cons tants
Field Units to Metric If you have: Barrels (bbl)
Multipl y by: x 158.987
To get: Liters
Barrels (bbl)
x 0.1589
Cubic Meters
Fahrenheit Degrees
x 0.56-17.8
Celsius Degrees
Feet
x 0.305
Meters (M)
Gallon (gal)
x 8.34
lb
Gallon (gal)
x 0.00379
M3
Gallon (gal)
x 0.1337
ft3
Gallon (gal)
x 3.785
Liters
Cubic Meters
x 0.003785
Gallon (gal)
Barrels (bbl)
x 42
Gallon (gal)
Inches
x 2.54
Centimeters (cm)
M3
x 264.2
gal
M3
x 6.29
bbl
Mile
x 1.61
Km
Mud Weight (lb/ft 3)
x 1.602
Kg/M3
Mud Weight (ppg)
x 0.1198
Kg/L
Mud Weight (ppg)
x 119.83
Kg/M3
Mud Weight (ppg)
x 0.1198
Pounds (lbs)
x 0.000454
Specific Gravity (SG) Metric tons
Pounds (lbs)
x 0.445
Decanewtons (daN)
Pounds (lbs)
x 0.454
Kilograms
Pounds (lbs)
x 454
Grams
Pounds/Barrel (ppb)
x 2.853
Kg/M3
Pounds/in2 (psi)
x 6894.8
Pascals (Pa)
psi
x 0.93105
Kg/cm2
psi
x 0.06895
Bar
Weight (lbs/ft)
x 1.488
Kg/M
179
19.7.2 pH of Mud Add itiv es in 10% Water Solution
Chemical Name
pH
Chrome lignosulfonate
3.7
Quebracho
3.8
Sodium acid pyrophosphate, Na2H2P2O7
4.8
Lignite
5.0
Calcium sulfate, CaSO4·2 H2O, gypsum
6.0
Sodium hexametaphosphate, (NaPO)6
6.0
Calcium Lignosulfonate
7.0
Sodium tetraphosphate, Na6P4O13
7.5
Sodium bicarbonate, NaHCO3, baking soda
8.3
Tetrasodium pyrophosphate, Na4P2O7
9.9
Barium carbonate, BaCO 3
10.0
Sodium carbonate, Na2CO3, soda ash
11.0
Calcium Hydroxide, Ca(OH)2, slaked lime
12.0
Sodium Hydroxide, NaOH, caustic soda
13.0
(10% solutions)
180
19.7.3 Specific Gravity and Mohs Hardness of Common Mud Comp onents Material
Specific Gravity
ppg
ppb
Mohs Hardness
Barite
4.5
37.5
1506
3-3.5
Bentonite
2.4
20.0
840
1-2
Calcium Carbonate
2.7
22.5
945
3
Cement
3.2
26.7
1120
Clays, drilled solids
2.6
21.7
911
Diesel Oil
0.84
7.0
294
Dolomite
2.9
24.2
1016
Fresh Water
1.0
8.34
350
Galena
6.5
54.1
2272
2.5-2.75
Gypsum
2.3
19.2
806
2
API Hematite
5.1
42.5
1785
5-6
Lead
11.4
95.0
3990
Salt
2.2
18.3
769
2.5
Sand (Silica)
2.6
21.7
911
7
4.20
35
1471
API Barite
3.5-4
Note: ppg = pounds/gallon; ppb = pounds/barrel
181
19.7.4 Pounds of Drill Sol ids Generated per Hole Size
Hole Size, inches
Rate of Penetration, ft /hr 10
4.750
30
50
199 598 997 5.625 280 839 1398 5.875 305 915 1525 6.000 319 956 1594 6.125 332 995 1658 6.250 345 1035 1726 6.625 388 1164 1940 6.750 403 1210 2017 6.875 418 1254 2090 7.375 481 1443 2404 7.625 515 1544 2573 7.750 531 1593 2655 7.875 548 1645 2741 8.375 620 1861 3101 8.500 639 1918 3197 8.625 658 1975 3292 8.750 678 2033 3388 9.500 799 2396 3994 9.625 820 2459 4098 9.875 862 2587 4312 10.250 999 2997 4995 10.625 930 2790 4649 12.250 1321 3962 6603 13.500 1612 4836 8060 14.750 1924 5773 9622 17.500 2709 8128 13547 26.000 5981 17942 29904 Note: Assuming gauge hole.
70
90
110
130
150
170
190
210
230
250
1396 1957 2136 2231 2321 2416 2716 2824 2926 3366 3602 3717 3838 4341 4475 4609 4743 5591 5738 6037 6993 6509 9244 11284 13471 18966 41865
1795 2516 2746 2869 2984 3106 3492 3631 3762 4328 4631 4779 4934 5582 5754 5926 6098 7188 7377 7762 8992 8369 11885 14508 17319 24385 53827
2194 3076 3356 3506 3647 3797 4268 4438 4598 5290 5660 5840 6031 6822 7033 7243 7453 8786 9016 9487 10990 10228 14526 17732 21168 29804 65788
2593 3635 3966 4144 4310 4487 5044 5245 5434 6251 6689 6902 7127 8063 8311 8560 8809 10383 10656 11212 12988 12088 17167 20956 25017 35222 77750
2992 4194 4576 4781 4973 5177 5820 6052 6270 7213 7718 7964 8224 9303 9590 9877 10164 11981 12295 12937 14986 13948 19808 24180 28866 40641 89711
3391 4753 5187 5419 5636 5868 6595 6859 7106 8175 8748 9026 9320 10543 10869 11194 11519 13578 13934 14662 16984 15808 22449 27404 32714 46060 101673
3790 5312 5797 6056 6299 6558 7371 7666 7942 9136 9777 10088 10417 11784 12147 12511 12874 15175 15573 16387 18982 17667 25091 30628 36563 51479 113634
4188 5871 6407 6694 6962 7248 8147 8473 8779 10098 10806 11150 11513 13024 13426 13828 14229 16773 17213 18112 20980 19527 27732 33852 40412 56898 125596
4587 6431 7017 7331 7625 7939 8923 9279 9615 11060 11835 12212 12610 14265 14705 15144 15584 18370 18852 19837 22979 21387 30373 37076 44260 62317 137557
4986 6990 7627 7969 8288 8629 9699 10086 10451 12022 12864 13274 13706 15505 15983 16461 16940 19968 20491 21561 24977 23246 33014 40300 48109 67735 149519
182
19.7.5 Percent Solids versu s Mud Weigh t for Water-Based Muds
e m u l o50 v y b40 % , t n30 e t n o20 C s d i l 10 o S
100% Low Gravity Solids (2.6 S.G.)
g e o f s R a n d i l o % S m a t e i x o r A p p
i t i o n C o n d d o o i n G M u d s d l e i F - B a s e W a t e r
o l i d s v i t y S a r G e L o w V o l u m y b f 2 % u m o M i n i m
10
11
12
14
13
15
16
17
18
Dry
Clay
Mud Weight, pounds per gallon
19.7.6 Base Exchange Capacities o f Clay Minerals*
Mineral Mineral
Milliequivalents/100g
Montmorillonite
70-130
Vermiculite
100-200
Illite
10-40
Kaolinite
3-15
Chlorite
10-40
Attapulgite-Sepiolite
10-35
of
* From Grim, and Weaver and Pollard
183
19.8 Appendi x H - G-Force Derivatio n The formula is derived from the centripetal acceleration of the motor weights , Centripetal Acceleration = r ω2, even though the shaker basket is not moving in circular motion around a central axis. To accommodate this difference, the "radius" of the "circular" motion is converted to "diameter" within the centripetal acceleration formula, and then the stroke of the basket is equated to this "diameter". Basket Acceleration
=
1 2
* "Diameter" (now = Stroke) *
2
ω
The proper units for ω are radians which need to be converted from the RPM of the motor and the English units for the acceleration of gravity are ft / sec 2. All the conversion factors are compiled and the final formula links Gs (Gravitational force) to stroke in inches and motor RPM, like this: Basket Acceleration
Gs =
=
Acceleration of Gravity
=
Stroke (inches) * 2 Radians 2 * (32.174 ft / sec )
Stroke (inches) * ft * Radians 2 * (12 inches) * (32.174 ft / sec )
=
Stroke (inches) * ft * ((RPM value) Rev * 2 * pi Radians ) 2 2 2 * (12 inches) * ( minute Revolution ) * (32.174 ft / sec )
=
Stroke (inches) * ft * ((RPM value) Rev * minute * 2 * pi Radians ) 2 * (12 inches) * (minutes * 60 seconds * Revolutions) * (32.174 ft / sec )
=
Stroke (inches) * ft * ((RPM value) Rev * minute * 2 * pi Radians ) 2 2 2 * (12 inches) * (minute * 60 seconds * Revolutions) * (32.174 ft / sec )
=
Stroke * ft * ((RPM value) * 2 * pi ) 2 * 12 * ( 60 seconds ) * (32.174 ft / sec )
=
Stroke * ((RPM value) * 2 * pi ) 2 * 12 * 60 * 32.174
2
2 * (RPM value) * 4 * = Stroke 2
pi
2 * 12 * 60 * 32.174
Gs =
(Stroke in inches) * (Motor 2 RPM) 70414
Or Gs = (Stroke in inches)(Motor RPM) 2(0.0000142) 184
19.9 Appendi x I - Centri fuge Charts 19.9.1 US Units
US Units HS-2172L
HS-1960
HS2000M
HS-3400 VSD (UK)
HS-3400 FS
HS-3400 FVS
16680
20000
15670
034-901 0-016
10849
10547
Manual Number Water Capacity (gpm)
M16730
M22080
M15490
M12958
M09252
M1339
550
350
250
200
200
200
Feed Type
12 port
12 port
4 port
4 port
4 port
Max 3000
2-Elongated Ports Max 3000
Max 3200
Max 4000
Max 3200
Max 3200
Typical 2600-2800 VFD
Typical 2700 VFD
Typical 2800 VFD
Typical 2700-3000 Hydraulic
Typical 2700-3000 VFD
Gearbox Ratio
75:1
75:1
59:1
52:1
Typical 2600 Fixed Electrical 52:1
G-Force
2684
2480
2617
3181
2036
2036
150
125
75
40
40
40
40
40
30
NA
NA
25
5
5
5
10
10
10
16500
12500
7500
6615
4800
6200
21
19.4
18
14
14
14
72
60
60
49.5
49.5
49.5
174
160
172
98
98
124
84
83
41
69
69
69
46
44
47
57
44
59
Part Number
Bowl Speed Drive
Max Drive (Bowl) hp Back Drive (hp) Beach Angle Weight (lbs) Bowl Dia. (in) Bowl Length (in) Length (in) Width (in) Height (in)
52.1
F= Fixed Speed M= Modular Frame (in-line drives) VS= Variable Speed D= Hydraulic FVS= Full Variable Speed (with back drive) L= Left Handed (feed from solids end) VFD’s are rated to match motor and load requirements VFD’s are available for arctic, desert and hazardous area use Typical VFD overall dimensions: 83” H x 76” W x 52” D Typical Weight: 1679 lbs NOTE: These are the latest updates. Some items may change without notice. NOTE: (1) Every centrifuge can remove and return barite to a weighted mud system. The VFD units can change removal functions by a simple dial adjustment. The ideal G-Force is 800-1000 (2) Every centrifuge can dewater solids (remove low gravity solids from a mud). The VFD units can change removal functions by simple dial adjustment The idea G-Force is >1000 (3) The f ixed drive centrifuges require sheave and belt changes to be able to change G-force
185
19.9.2 Metric Units
UK Units
Part Number Manual Number Water Capacity (lpm) Feed Type Bowl Speed
Drive Gearbox Ratio G-Force Max Drive (Bowl) kw Back Drive kw Beach Angle Weight (kg) Bowl Dia. (mm) Bowl Length (mm) Length (mm) Width (mm) Height (mm)
HS-2172L
HS-1960
HS2000M
HS-3400 VSD (UK)
HS-3400 FS
HS-3400 FVS
16680
20000
15670
034-901 0-016
10849
10547
M16730
M22080
M15490
M12958
M09252
M1339
2082
1325
950
757
757
757
12 port
2-Elongated Ports Max 3000
12 port
4 port
4 port
4 port
Max 3200
Max 4000
Max 3200
Max 3200
Typical 26002800 VFD
Typical 2700
Typical 2800
Typical 2700-3000
Typical 2600
Typical 2700-3000
VFD
VFD
Hydraulic
VFD
75:1
75:1
59:1
52:1
Fixed Electrical 52:1
52.1
2684
2480
2617
3181
2036
2036
112
93
56
30
30
30
30
30
22
NA
NA
18
5
5
5
10
10
10
7484
5670
3402
3001
2177
2812
533
493
457
357
357
357
1829
1524
1524
1257
1257
1257
4420
4064
4369
2489
2489
3150
2134
2108
1042
1753
1753
1753
1168
1118
1194
1448
1118
1499
Max 3000
F= Fixed Speed M= Modular Frame (in-line drives) VS= Variable Speed D= Hydraulic FVS= Full Variable Speed (with back drive) L= Left Handed (feed from solids end) VFD’s are rated to match motor and load requirements -VFD’s are available for arctic, desert and hazardous area use Typical VFD overall dimensions: 2108mm H x 1930mm W x 1321mm D Typical Weight: 762 kg NOTE: These are the latest updates. Some items may change without notice. NOTE: (1) Every centrifuge can remove and return barite to a weighted mud system. The VFD units can change removal functions by a simple dial adjustment. The ideal G-Force is 800-1000 (2) Every centrifuge can dewater solids (remove low gravity solids from a mud). The VFD units can change removal functions by simple dial adjustment The idea G-Force is >1000 (3) The fixed drive centrifuges require sheave and belt changes to be able to change G-force
186
19.10 Appendi x J – Centrif uge Perfor mance Data 19.10.1 Flow Rate Data for HS-3400
187
19.10.2 PSA of Centri fug e Feed Sample The feed sample (20.10.2) contained solids as large as 176 microns. After processing the mud with the centrifuge removed most of the solids greater than 15.56 microns (see 20.10.3) were removed. About 25% of the larger solids were removed from the feed sample when you compare
the two samples.
188
19.10.3 PSA of Centr ifug e Effluent Sample
189
19.11 Append ix K - Shale Shaker Produ ct L ine Motor Data Name Mini-Cobra® 2- Panel Mini-Cobra® 3 - Panel Cobra®
Vibration Linear
King Cobra®
Linear Optional Dual Motion Linear & Tuned Elliptical
Linear Linear
Qty. Screens & Deck Type 2 Screens (0°, +5°) 3 Screens (0°, +5°, +5°) 3 Screens (0°, +5°, +5°) 4 Screens (0°, +5°, +5° +5°)
Basket Angle Adjustable -2°to +3° Adjustable 0° to +3° Adjustable -7° to +3° Adjustable -5°to +3°
Screen Type Pretension Repairable Pretension Repairable Pretension Repairable Pretension Repairable
G-Force 6.7 Nominal G’s 6.6 Nominal G’s 5.3 Nominal G’s 6.1 Nominal G’s
Qty
Hp
2
1.5
2
2.5
2
2
2
2.5
2
2.5
6.1 Nominal G’s King Cobra® “Hybrid”
Linear & Tuned Elliptical
4 Screens (0°, +5°, +5° +5°)
Adjustable -5° to +3°
Pretension Repairable
Linear King Cobra Venom
Optional Dual Motion Linear & Tuned Elliptical
VSM Multi-Sizer
Balanced Elliptical
VSM 300®
Balanced Elliptical
LCM-3D/CM-2 Cascade (CM-2 = Belt Drive) LCM-3D/King Cobra Cascade
Upper Basket Circular or Linear Lower Basket Linear
Upper Basket Elliptical Lower Basket Linear
Brandt Tandem Belt Drive
Circular
4 Screens (0°, +5°, +5° +5°)
Adjustable -2° to +2°
Pretension Repairable
Optional CGC* Constant 6.3 Optional CGC* Auto 7.3-8.3 6.1 Nominal G’s
3.5 2
2.5
Optional CGC* Constant 6.3
2
2.5
2
3.5
Optional CGC* Auto 7.3-8.3 3 Screens Scalping Deck (+2°) 4 Screens First Primary Deck (+7°) 4 Screens Secondary Primary Deck (+7°) 3 Screens Scalping Deck (0°) 4 Screens Primary Deck (+7°) 2 Screens Drying Deck (+7°) 2 Screens Scalping Deck (0°) 4 Screens Primary Deck (0°, +5°, +5° +5°) 4 Screens (0°, +5°, +5° +5°) 4 Screens Primary Deck (0°, +5°, +5° +5°) 2 Screens Scalping Deck (0°)
Fixed 0°
Pretension Repairable
CGC* 5.3-6.3-7.3
2
4
NA
Pretension Repairable
CGC* 5.2-6.1-7.6
2
4
Fixed 0°
Hook Strip Single Layer
4.2 G’s
1
1
Adjustable -5° to +5°
Pretension Repairable
6.1 Nominal G’s
2
2.5
Adjustable -5° to +3° Adjustable -5° to +5°
Pretension Repairable Pretension Repairable
6.1 Nominal G’s 6.1 Nominal G’s
2
2.5
2
2.5
4.9 G’s
Fixed 0°
Hook Strip Single Layer
1
5
190
* Constant-G Control® CGC Technology automatically adjusts shaker speed and G Force as solids loading increases and decreases. CGC increases shaker capacity up to 35 % and allows finer screening, 2-3 API classes finer. •
Shakers can be outfitted as multiple units (weir heights may change) sharing a common back tank, which reduces installation time and expenses
•
Shakers in gray shaded area can also be ordered as Mud Conditioners
•
NOV will manufacture older model shakers by special request and will continue servicing all models
•
The Cobra and King Cobra can have optional weir heights of 37” (940mm)
•
An optional manual VFD G-Force Controller is available for three models of the shakers. The VFD allows the operator to tune the G-Force exerted on the shaker bed to one of three settings: NORM, HIGH or MAX
Shaker Dimensions Equipment Name Mini-Cobra® 2- Panel Mini-Cobra® 3 - Panel Cobra® King Cobra® King Cobra® “Hybrid” King Cobra Venom VSM Multi-Sizer
VSM 300® LCM-3D/CM-2 Cascade (CM-2 = Belt Drive) LCM-3D/King Cobra Cascade Brandt Tandem Belt Drive
Deck Area ft² 16.8 25.4 25.4 33.4 33.4 33.4 20.56 26.26 26.26 20.5 26.3 3 22.5
Weir Height in 15 24 41 41 41 34.5
Weir Height Option in NA NA 37 37 37 NA
45
NA
104
74
68
5383
39
NA
108.44
73.62
59.25
5370
33.4 33.4
74
70
119.38
81.00
90.00
9100
33.4 20 20
93
NA
125
80
112
10400
36
NA
79.75
72.00
52.63
2865
Length in 76.67 104.63 94.63 120.25 124.25 120.00
Width in 66.20 66.13 66.13 66.38 70.00 67.00
Height in 39.88 53.00 61.00 66.00 64.00 61.00
Weight lb 2100 3800 3800 4800 5755 4500
191
19.12 Append ix L - Screen Tables for Brandt Shakers 19.12.1 BHX Cobra/LCM 3D BHX Cobr a/LCM 3D XF
Part Number
API #
Small end of Range
< D100 ≤
Large end of Range
Conducta nce Kd/MM
Non-Blanked Open Area ft²
6BHX70-AT
60
231
<268≤
275
2.92
4.95
6BHX84-AT
70
196
<223≤
231
2.32
4.95
6BHX110-AT
80
165
<176≤
196
1.88
4.95
6BHX140-AT
100
137.5
<141≤
165
1.4
4.95
6BHX175-AT
120
116.5
<116.8≤
137.5
1.35
4.95
6BHX210-AT
140
98
<102≤
116.5
0.94
4.95
6BHX230-AT
170
82.5
<94.8≤
98
0.87
4.95
6BHX250-AT
200
69
<78.4≤
82.5
0.72
4.95
6BHX270-AT
230
58
<67.6≤
69
0.64
4.95
6BHX300-AT
270
49
<54.2≤
58
0.43
4.95
6BHX325-AT
325
41.5
<42≤
49
0.36
4.95
6BHX425-AT
400
35
<40.3≤
41.5
0.21
4.95
BHX Cobra/LCM 3D RHD
Part Number
API #
Small end of Range
< D100 ≤
Large end of Range
Conducta nce Kd/MM
Non-Blanked Open Area ft²
6BHX75ATRHD
45
327.5
<328.1≤
390
4.93
4.95
6BHX89ATRHD
50
275
<321.6≤
317.5
3.98
4.95
6BHX105ATRHD
60
231
<255.1≤
275
2.68
4.95
6BHX115ATRHD
70
196
<230.4≤
231
2.55
4.95
6BHX145ATRHD
80
165
< 192.7≤
196
2.18
4.95
6BHX180ATRHD
100
137.5
<164.2≤
165
1.72
4.95
6BHX215ATRHD
100
137.5
<142.7≤
165
1.56
4.95
6BHX255ATRHD
120
116.5
<128.6≤
137.5
1.17
4.95
6BHX280ATRHD
140
98
<101.8≤
116.5
0.99
4.95
6BHX300ATRHD
170
82.5
<83.2≤
98
0.93
4.95
6BHX330ATRHD
200
69
<79.5≤
82.5
0.67
4.95
192
19.12.2 VSM 100 VSM 100 Lig ht Weigh t XF
Part Number
API #
Small end of Range
< D100 ≤
Large end of Range
Conductance Kd/MM
Non-Blanked Open Area ft²
62536FXTD70
60
231
<261.4≤
275
2.95
3.2
62536FXTD84
70
196
<229.2≤
231
2.05
3.2
62536FXTD110
80
165
<187.5≤
196
1.75
3.2
62536FXTD120
100
137.5
<139.1≤
165
1.32
3.2
62536FXTD140
120
116.5
<136.6≤
137.5
1.35
3.2
62536FXTD175
140
98
<113.7≤
116.5
1.15
3.2
62536FXTD210
140
98
<110.4≤
116.5
1.00
3.2
62536FXTD230
170
82.5
<92.7≤
98
0.75
3.2
62536FXTD250
200
69
<80.3≤
82.5
0.71
3.2
62536FXTD270
230
58
<68.6≤
69
0.55
3.2
62536FXTD300
270
49
<49.5≤
58
0.52
3.2
62536FXTD325
325
41.5
<48.0≤
49
0.57
3.2
62536FXTD425
425
35
<40.2≤
41.5
0.21
3.2
VSM 100 Light Weight RHD
Part Number
API #
Small end of Range
< D100 ≤
Large end of Range
Conductance Kd/MM
Non-Blanked Open Area ft²
62535FOTD089
50
275
<323.0≤
317.5
4.17
3.2
62535FOTD115
60
231
<254.0≤
275
3.3
3.2
62535FOTD125
70
196
<216.4≤
231
3.63
3.2
62535FOTD145
80
165
<192.5≤
196
2.62
3.2
62535FOTD180
100
137.5
<162.1≤
165
2.24
3.2
62535FOTD215
120
116.5
<137.4≤
137.5
1.58
3.2
62535FOTD255
140
98
<114.9≤
116.5
1.28
3.2
62535FOTD280
170
82.5
<94.4≤
98
1.10
3.2
62535FOTD330
200
69
<81.3≤
82.5
0.64
3.2
193
19.12.3 VSM 300
VSM 300 Light Weight XF
Part Number
API #
Small end of Range
< D100 ≤
Large end of Range
Conductance Kd/MM
Non-Blanked Open Area ft²
62535FXTD70
60
231
<261.4≤
275
2.95
3.6
62535FXTD84
70
196
<229.2≤
231
2.05
3.6
62535FXTD110
80
165
<187.5≤
196
1.75
3.6
62535FXTD120
100
137.5
<139.1≤
165
1.32
3.6
62535FXTD140
120
116
<136.6≤
137.5
1.35
3.6
62535FXTD175
140
98
<113.7≤
116.5
1.15
3.6
62535FXTD210
140
98
<110.4≤
116.5
1.00
3.6
62535FXTD230
170
82.5
<92.7≤
98
0.75
3.6
62535FXTD250
200
69
<80.3≤
82.5
0.71
3.6
62535FXTD270
230
58
<68.6≤
69
0.55
3.6
62535FXTD300
270
49
<49.5≤
58
0.52
3.6
62535FXTD325
325
41.5
<48.0≤
49
0.57
3.6
62535FXTD425
425
35
<40.2≤
41.5
0.21
3.6
VSM 300 300 Light Weight RHD
Part Number
API #
Small end of Range
< D100 ≤
Large end of Range
Conductance Kd/MM
Non-Blanked Open Area ft²
62735FOTD089
50
275
<323.0≤
327.5
4.17
3.6
62735FOTD115
60
231
<254.9≤
275
3.3
3.6
62735FOTD125
70
196
<216.4≤
231
3.63
3.6
62735FOTD145
80
165
<192.5≤
196
2.62
3.6
62735FOTD180
100
137.5
<162.1≤
165
2.24
3.6
62735FOTD215
120
116.5
<137.4≤
137.5
1.58
3.6
62735FOTD255
140
98
<114.9≤
116.5
1.28
3.6
62735FOTD280
170
82.5
<94.4≤
98
1.10
3.6
62735FOTD330
200
69
<81.6≤
82.5
0.64
3.6
194
19.12.4 19.12.4 Venom Series Series Venom Screens XF
Part Number
API #
Small end of Range
< D100 ≤
Large end of Range
Conductance Kd/MM
Non-Blanked Open Area ft²
6VNM070XF
60
231
<266.8≤
275
4.181
0.5
6VNM084XF
70
196
<227.3≤
231
3.161
0.5
6VNM110XF
80
165
<185.7≤
196
2.584
0.5
6VNM140XF
100
137.5
<153.1≤
165
1.974
0.5
6VNM175XF
120
116
<127.5≤
137.5
2.045
0.5
6VNM210XF
140
98
<106.6≤
116.5
1.451
0.5
6VNM230XF
170
82.5
<90.7≤
98
1.140
0.5
6VNM250XF
200
69
<81.9≤
82.5
1.227
0.5
6VNM270XF
230
58
<66.4≤
69
0.726
0.5
6VNM300XF
270
49
<55.9≤
58
0.587
0.5
6VNM325XF
270
49
<54.9≤
58
0.585
0.5
6VNM425XF
400
35
<39.2≤
41.5
0.343
0.5
Venom Screens RHD
Part Number
API #
Small end of Range
< D100 ≤
Large end of Range
Conductance Kd/MM
Non-Blanked Open Area ft²
6VNM075RHD
45
327.5
<334.2≤
390
4.940
3.6
6VNM089RHD
50
275
<280.1≤
327.5
4.170
3.6
6VNM105RHD
60
231
<254.7≤
275
3.900
3.6
6VNM115RHD
70
196
<230.0≤
231
3.320
3.6
6VNM145RHD
80
165
<192.4≤
196
2.854
3.6
6VNM180RHD
100
137.5
<164.4≤
165
2.464
3.6
6VNM215RHD
100
137.5
<151.5≤
165
2.033
3.6
6VNM255RHD
120
116.5
<117.3≤
137.5
1.700
3.6
6VNM280RHD
140
98
<115.1≤
116.5
1.580
3.6
6VNM300RHD
170
82.5
<91.6≤
98
1.326
3.6
6VNM330RHD
200
69
<69.9≤
82.5
1.006
3.6
195
19.13 19.13 Appendi x M - Sieve Comparis on Table
Two Types of sieves are used to classify particle sizes; the US Sieve Series and the Tyler Equivalent, sometimes called the Tyler Mesh Size or Tyler Standard Sieve Series. The mesh opening sizes for these sieves are given in the Table below. Sieve
Mesh
Openings
US Sieve #
Tyler Equivalent, mesh
mm
microns
inches
-
2.5
8
8000
0.312
-
3
6.73
6730
0.265
3.5
3.5
5.66
5660
0.23
4
4
4.76
4760
0.187
5
5
4
4000
0.157
6
6
3.36
3360
0.132
7
7
2.83
2830
0.111
8
8
2.38
2380
0.0937
10
9
2
2000
0.0787
12
10
1.68
1680
0.0661
14
12
1.41
1410
0.0555
16
14
1.19
1190
0.0469
18
16
1
1000
0.0394
20
20
0.841
841
0.0331
25
24
0.707
707
0.0278
30
28
0.595
595
0.0234
35
32
0.5
500
0.0197
40
35
0.42
420
0.0165
45
42
0.354
354
0.0139
50
48
0.297
297
0.0117
60
60
0.25
250
0.0098
70
65
0.21
210
0.0083
80
80
0.177
177
0.007
100
100
0.149
149
0.0059
120
115
0.125
125
0.0049
140
150
0.105
105
0.0041
170
170
0.088
88
0.0035
200
200
0.074
74
0.0029
230
250
0.063
63
0.0025
270
270
0.053
53
0.0021
325
325
0.044
44
0.0017
400
400
0.037
37
0.0015
196
19.14 19.14 Append Append ix N - Mud Weight Convers ion Table
lb/gal lb/ gal
psi/ftt psi/f
lb/ft lb/ft
Sp gr
Kg/m Kg/ m
lb/ga lb/ gall
psi/ft psi/ ft
lb/ft lb/ ft
Sp gr
K g /m
8.3
0.434
62.4
1.00
999.1
14.1
0.733
105.5
1.70
1689.2
8.5
0.442
63.6
1.02
1018.3
14.3
0.744
107.0
1.72
1713.1
8.7
0.452
65.1
1.05
1042.3
14.5
0.754
108.5
1.75
1737.1
8.9
0.463
66.6
1.07
1066.2
14.7
0.764
110.0
1.77
1761.1
9.1
0.473
68.1
1.10
1090.2
14.9
0.775
111.5
1.80
1785.0
9.3
0.484
69.6
1.12
1114.1
15.1
0.785
112.9
1.82
1809.0
9.5
0.494
71.1
1.14
1138.1
15.3
0.796
114.4
1.84
1832.9
9.7
0.504
72.6
1.17
1162.1
15.5
0.806
115.9
1.87
1856.9
9.9
0.515
74.1
1.19
1186.0
15.7
0.816
117.4
1.89
1880.9
10.1
0.525
75.5
1.22
1210.0
15.9
0.827
118.9
1.92
1904.8
10.3
0.536
77.0
1.24
1233.9
16.1
0.837
120.4
1.94
1928.8
10.5
0.546
78.5
1.27
1257.9
16.3
0.848
121.9
1.96
1952.7
10.7
0.556
80.0
1.29
1281.9
16.5
0.858
123.4
1.99
1976.7
10.9
0.567
81.5
1.31
1305.8
16.7
0.868
124.9
2.01
2000.7
11.1
0.577
83.0
1.34
1329.8
16.9
0.879
126.4
2.04
2024.6
11.3
0.588
84.5
1.36
1353.7
17.1
0.889
127.9
2.06
2048.6
11.5
0.598
86.0
1.39
1377.7
17.3
0.900
129.4
2.08
2072.5
11.7
0.608
87.5
1.41
1401.7
17.5
0.910
130.9
2.11
2096.5
11.9
0.619
89.0
1.43
1425.6
17.7
0.920
132.4
2.13
2120.5
12.1
0.629
90.5
1.46
1449.6
17.9
0.931
133.9
2.16
2144.4
12.3
0.640
92.0
1.48
1473.5
18.1
0.941
135.4
2.18
2168.4
12.5
0.650
93.5
1.51
1497.5
18.3
0.952
136.9
2.20
2192.3
12.7
0.660
95.0
1.53
1521.5
18.5
0.962
138.4
2.23
2216.3
12.9
0.671
96.5
1.55
1545.4
18.7
0.972
139.9
2.25
2240.3
13.1
0.681
98.0
1.58
1569.4
18.9
0.983
141.4
2.28
2264.2
13.3
0.692
99.5
1.60
1593.3
19.1
0.993
142.9
2.30
2288.2
13.5
0.702
101.0
1.63
1617.3
19.3
1.004
144.4
2.33
2312.1
13.7
0.712
102.5
1.65
1641.3
19.5
1.014
145.9
2.35
2336.1
13.9
0.723
104.0
1.67
1665.2
19.7
1.024
147.4
2.37
2360.1
14.1
0.733
105.5
1.70
1689.2
19.9
1.035
148.9
2.40
2384.0
197
19.15 Appendix O - Glos sary Legend + API Bulletin 13C - API Bulletin D11 * IADC Mud Equipment Manual A U
ADSORBED LIQUID The liquid film that adheres to the surfaces of solid particles which cannot be removed. AERATION* The mechanical incorporation and dispersion of air into a liquid. It can be very troublesome in drilling fluids. AIR CUTTING See Preferred Term: AERATION AIR LOCK A condition causing a centrifugal pump to stop pumping due to the presence of air (or gas) in the impeller center that will not let liquid enter (usually caused by aeration). AMPLITUDE + The distance from the mean position to the point of maximum displacement. In the case of a vibrating screen with circular motion, amplitude would be the radius of the circle. In the case of straight-line motion or elliptical motion, amplitude would be one-half of the total movement of the major axis of the ellipse; thus one-half stroke. See related term: STROKE. ANTIFOAM A substance used to prevent foam by greatly increasing the surface tension. Compare: DEFOAMER. APERTURE An opening in a screen surface; the clear opening between wires. See related term: MESH. APEX See Preferred Term: UNDERFLOW OPENING. APEX VALVE See Preferred Term: UNDERFLOW OPENING. API SAND Solids particles in a drilling fluid that are too large to pass through a U.S. Standard 200 Mesh Screen (74 micron openings). See related term: SAND CONTENT. 198
APPARENT VISCOSITY
The viscosity a fluid appears to have on a given instrument at a stated rate of shear. It is a function of the plastic viscosity and the yield point. See also: VISCOSITY, PLASTIC VISCOSITY, and YIELD POINT. AXIAL FL OW*
Flow from a mechanical agitator in which the fluid first moves along the axis of the impeller shaft (usually down toward the bottom of a tank) and them away from the impeller. B U
BACKPRESSURE
The pressure opposing flow from a solids separation device. See related term: DIFFERENTIAL PRESSURE. BAL ANCE (as a Hydrocyc lone)*
To adjust a balanced design hydrocyclone so that it discharges only a slight drop of water at the underflow opening. BAL ANCED DESIGN
(Hydro cy clone)
A hydrocyclone designed so it can be operated to discharge solids when there are solids to separate, but will automatically minimize liquid discharge when there are no separable solids. BAL ANCE POINT (of a Hydro cyc lon e)
That adjustment at which no liquid will be discharged at the underflow opening and at which any increase in size of the opening would result in some liquid discharge. BARITE, BARYTES
Natural barium sulfate, used for increasing the density of drilling fluids. The barite mineral occurs in many colors from white through grays, greens, and reds to black, depending upon the impurities it contains. API standards require a minimum of 4.2 average specific gravity. BARREL (API)
A unit of volume used in the petroleum industry, 42 U.S. gallons. BASKET
That portion of a shale shaker containing the deck upon which the screen(s) is mounted; it is supported by vibration isolation members connected to the bed. BEACH
Area between the liquid pool and the solids discharge ports in a decanting centrifuge or hydrocyclone. BED
Shale shaker support member consisting of mounting skid, or frame with or without bottom flow diverters to direct screen underflow to either side of the skid and mountings for vibration isolation members. 199
BENTONITE
A hydratable colloidal clay, largely made up of the mineral sodium montmorillonite, used in drilling fluids to reduce the filtration rate of a mud and to create viscosity. See related term: GEL. BLADE
See Preferred Term: FLUTE. BLINDING
A reduction of open area in a screening surface caused by coating or plugging. See related terms: COATING, PLUGGING. BLOWOUT
An uncontrolled escape of drilling fluid, gas, oil, or water from the well caused by the formation pressure being greater than the hydrostatic head of the fluid in the hole. BOTTOM (Cycl one)
See Preferred Term: UNDERFLOW OPENING. BOTTOM FLOODING
The operational condition in which whole mud, rather than separated solids, is discharged by a hydrocyclone. BOUND LIQUID
See Preferred Term: ADSORBED LIQUID. BOWL
The outer rotating chamber of a decanting centrifuge.
C U
CAKE THICKNESS
The measurement of the thickness of the filter cake deposited by a drilling fluid against a porous medium most often following the standard API filtration test. Cake thickness is usually reported in 32nds of an inch. See related term: WALL CAKE. CAPACITY
The maximum volume rate at which a solids control device is designed to operate without detriment to separation. See related terms: FEED CAPACITY, SOLIDS DISCHARGE CAPACITY. CASCADE
Fluid movement across a deck, then travelling to the front part of another parallel deck just below the first deck. CAVING
Caving is a severe degree of sloughing. See related term: SLOUGHING. 200
CENTIPOISE (cp) A unit of viscosity equal to 1 gram per centimeter-second. The viscosity of water at 20°C is 1.005 cp. CENTRIFUGAL FORCE That force which tends to impel matter outward from the center of rotation. See related term: G-FORCE. CENTRIFUGAL SEPARATOR A general term applicable to any device using centrifugal force to shorten and/or to control the settling time required to separate a heavier mass from a lighter mass. CENTRIFUGAL PUMP A device for moving fluid by means of a rotating impeller which spins the fluid and creates centrifugal force. CENTRIFUGE A mechanical separator, utilizing the accelerated sedimentation created by a rapidly rotating bowl to separate heavy solids and light solids from a feed slurry. The particles with the greater mass are separated from the lighter solids and leave the machine, as damp solids, via the underflow ports. The lighter solids, both barite and low gravity solids, remain in the liquid and are discharged with the overflow. CERAMICS A general term for heat-hardened clay products which resist abrasion: used to extend the useful life of wear parts in pumps and cyclones. CHOKE An opening, aperture, or orifice used to restrict a rate of flow or discharge. CIRCULATION The movement of drilling fluid from the suction pit through pump, drill pipe, bit, annular space in the hole, and back again to the suction pit. The time involved is usually referred to as circulation time. CIRCULATION RATE The volume flow rate of the circulation drilling fluid, usually expressed in gallons or barrels per minute. CLAY-SIZE, CLAY (Particles) Particles less than 2 microns in diameter are classified as clay-sized particles. COARSE (Solids) Solids larger than 2000 microns in diameter. COATING A condition wherein undersize particles cover the openings of a screening surface by virtue their stickiness. See related term: BLINDING. 201
COLLOIDAL (Solid s)
Commonly used as a synonym for “clay”. Particles that are so small (less than 2 µ) that they do not settle. CONE
See Preferred Term: HYDROCYCLONE. CONTAMINATION
The presence of any foreign material that has an adverse effect upon the desired properties of the drilling fluid. CONTINUOUS PHASE
The fluid phase of a drilling mud, either water or oil. CONVEYOR A mechanical device for moving material from one place to another. In a decanting centrifuge, a hollow hub with flutes designed to move the coarse solids out of the bowl. CROWN
The curvature of a screen deck or the difference in elevation between its high and low points. CUT POINT A general term for the effectiveness of a liquid-solids separation device expressed as the particle size that is removed from the feed stream at a given percentage under specified operating conditions. See related term: MEDIAN CUT. CUTTINGS
Small pieces of formation that are the result of the chipping and crushing action of the bit. Field practice is to call all solids removed by the shaker screen “cuttings,” in spite of the fact that such solids may include sloughed materials. CYCLONE See Preferred Term: HYDROCYCLONE.
D U
DECANTING CENTRIFUGE
A centrifuge is used to process a slurry, as well as separate heavy solids from light solids. SEE OBSERVATION UNDER “CENTRIFUGE” DECK
The shaker deck is the frame used to mount the screens on the shale shaker basket. DEFLOCCULATION
The break-up of flocs of gel structures by use of a chemical thinner or dispersant. 202
DEFOAMER Any substance used to reduce or eliminate foam by reducing the surface tension. Compare: ANTIFOAM. DEGASSER A device that removes entrained gas from a drilling fluid. DENSITY Matter measured as mass per unit of volume expressed in pounds per gallon (lbs/gal), grams per liter (g/l), and specific gravity. Density is commonly referred to as “weight.” DESAND Desanding refers to the removal of API sand sized particles from a drilling fluid. DESANDER A hydrocyclone capable of removing API sand sized particles from a drilling fluid. API sand sized particles are those particles greater than 74 microns. DESILT Desilting refers to the removal of API silt sized particles from mud. Silt sized particles are those between 2-73 microns. DESILTER A hydrocyclone that is capable of removing particles between 2-73 microns from a drilling fluid. SEE ABOVE DIFFERENTIAL PRESSURE (Hydroc ycl one) The difference between the inlet and outlet pressures measured near the inlet and outlet openings of a hydrocyclone. DIFFERENTIAL PRESSURE (Wall ) STICKING Sticking which occurs because part of the drill string (usually the drill collars) becomes embedded in the filter cake, resulting in a non-uniform distribution of pressure around the circumference of the pipe. The conditions essential for differential sticking require a permeable formation and a pressure differential across the filter cake and drill string. DILUENT Liquid added to dilute or thin a drilling fluid. DILUTION Increasing the liquid content of a drilling fluid by addition of water or oil. DILUTION RATIO Ratio of volume of dilution liquid to the volume of raw mud in the feed to a liquid-solids separator. DILUTION WATER Water used for dilution of water-base drilling mud. 203
DIRECT-INDICATING VISCOMETER
See VISCOMETER, DIRECT INDICATING. DISCHARGE SPOUT OR LIP
Extension at the discharge area of a screen. It may be vibrating or stationary. DISPERSANT
Any chemical chemical which promotes promotes dispersion dispersion of of particles in a fluid. fluid. DISPERSE
To separate in minute parts. Bentonite disperses into many smaller particles when hydrated. DISPERS DISPERSION ION (of (of Agg regates )
Disintegration of aggregates. Dispersion increases the specific surface area of solids resulting in an increase in viscosity and gel strength. DIVIDED DECK
A deck having having a screening screening surface surface longitudinally longitudinally divided by partition(s). partition(s). DOUBLE FLUTE
The flutes or leads advancing simultaneously at the same angle and 180° apart. Flutes are contained in centrifuges. DRILLED SOLIDS
Formation particles drilled up by the bit. See related term: LOW SPECIFIC GRAVITY SOLIDS. DRILLING IN
Drilling into the producing formation. DRILLING MUD OR FLUID
A circulating circulating fluid used used in rotary rotary drilling drilling to carry carry cuttings cuttings out of the the hole and perform other functions required in the drilling operation. See related term: MUD. DRILLING OUT
The operation during the drilling procedure when cement is drilled out of the casing before further hole is made or completion attempted. DRILLING RATE
The rate at which hole depth progresses, expressed in linear units per unit of time (including connections) as feet/minute or feet/hour. See related term: PENETRATION RATE. DRY BOTTOM
Referring to a hydrocyclone adjusted in a manner that makes the underflow opening very small and this can causes a dry beach, usually resulting in severe plugging. 204
DRY PLUG
The plugging of the underflow opening of a hydrocyclone caused by operating the cone with the opening closed causing the cone to operate in a dry bottom state. DYNAMIC
The state of being active or in motion opposed to static.
E U
EDUCTOR
An eductor eductor is a device device that uses uses a high velocity velocity jet to create create a vacuum. vacuum. This vacuum draws in liquid or dry material into the fluid (water or drilling mud) for blending. EFFECTIVE SCREENING AREA
The portion of a screen surface available for solids separation. EFFLUENT
See Preferred Term: OVERFLOW. ELASTOMER
Any rubber rubber or rubber-like rubber-like material material (such (such as polyurethane polyurethane). ). ELEVATION HEAD
The pressure created by a given height of fluid. See related term: HEAD. EMULSIFIER or EMULSIFYING EMULSIFYING AGENT
A substance substance used to produce an emulsion emulsion of two two liquids which which ordinarily ordinarily would not mix. EMULSION
A substantially substantially permanent permanent mixture mixture of two or more liquids liquids which do not normally dissolve in each other. They may be oil-in-water or water-in-oil. EQUIVALENT SPHERICAL DIAMETER DIA METER (ESD)
The theoretical dimension usually referred to when the sizes of irregularly shaped small particles are discussed. These dimensions can be determined by several methods, such as: settling velocity, electrical resistance, and light reflection. See related term: PARTICLE SIZE.
F U
FEED, or FEED SLURRY
A mixture of of solids and and liquid liquid entering a liquid-solids liquid-solids separation separation device, device, including dilution liquid if used. 205
FEED CAPACITY
The maximum feed rate that a solids separation device can effectively handle, dependent upon particle size, particle concentration, viscosity, and other variables. See related terms: CAPACITY, SOLIDS DISCHARGE CAPACITY. FEED CHAMBER
The part of a device which receives the mixture of diluents, mud and solids to be separated. FEED HEAD
The pressure (expressed in feet of head) exerted by the drilling fluid in a header. See related term: HEAD. FEED HEADER
A pipe, tube, tube, or conduit conduit to which which two or more hydrocyclon hydrocyclones es are connected and from which they receive their feed slurry. FEED OPENING
See Preferred Term: INLET. FEED PRESSURE
The actual gauge pressure measured as near as possible to, and upstream of, the inlet of a device. FILTER CAKE
Solids that are deposited on on a porous media while under pressure. A typical example would be the cake produced in the standard API fluid loss test. It may also refer to the solids deposited on the wall of the wellbore. See related term: WALL CAKE. FILTER CAKE THICKNESS
A measurement measurement of the solids deposited deposited on on filter paper paper during the standard 3—minute API filter test. Measured and reported in 32nds of an inch. FILTER PRESS
A device used used to determine determine the the fluid loss loss of a drilling drilling fluid. fluid. FILTRATION
The process of separating suspended solids from their liquid by forcing the latter through a porous medium. Two types of fluid filtration occur in a well: dynamic filtration while circulating, and static filtration while the fluid is at rest. FILTRATION RATE
See FLUID LOSS. FINE FINE (Solid s)
Solids 44-74 microns in diameter or sieve size 352-200 square mesh, according to API RP 13C. 206
FINE SCREEN SCREEN SHAK ER A vibrating vibrating screening screening device device designed designed for screening screening drilling drilling fluids fluids through screen cloth finer than 40 mesh. FISHING Operations on the rig for the purpose of retrieving sections of pipe, collars, junk, or other obstructive items which are in the hole and would interfere with further drilling activities. FLIGHT On a decanting centrifuge, one full turn of a spiral helix, such as a flute or blade of a screw-type conveyor. FLOCCULATING AGENT A substance, substance, such as most electrolytes electrolytes and and certain polymers, polymers, that causes flocculation. FLOCCULATION Loose association of particles in lightly bonded groups. In drilling fluids, flocculation results in thickening gelation. Chemical flocculants added to a mud will tend to cause solids to bond together into larger groups for easier removal from the mud. FLOODING The effect created when a screen or centrifuge is fed beyond its capacity. Flooding may also occur on a screen as a result of blinding. FLUID LOSS Measure of the relative amount of fluid (filtrate) forced under pressure through a permeable membrane. For standard API filtration-test filtrati on-test procedure, see API RP 13B. FLUTE The curved metal blade wrapped around a shaft as on a screw conveyor in a centrifuge. FOAM A light frothy frothy mass of of fine bubbles bubbles formed in or on the surface surface of a liquid; usually caused by entrained air or gas. FORMATION DAMAGE The mud particles or mud filtrate that invades a formation reducing the formations permeability, thus reducing hydrocarbon production. FREE LIQUID The layer of liquid that surrounds each separate particle in the underflow of a hydrocyclone. The thickness of this film depends upon the cyclone and the viscosity of the fluid. FUNNEL VISCOSITY The funnel viscosity of a mud relates to the time, in seconds, for a quart of drilling mud to flow out the bottom of a Marsh Funnel. Used in the field as a rough measure of mud viscosity. See related terms: MARSH FUNNEL, APPARENT VISCOSITY. 207
G U
GAS-CUT (Mud)
Drilling fluid containing entrained air or gas. GEAR RATIO
On a decanting centrifuge, the ratio of the outer bowl speed to the difference in speed between the outer bowl and the screw conveyor, normally expressed as the number of revolutions of the outer bowl for a given difference of one complete revolution between the outer bowl and the screw conveyor. GEAR UNIT
On a centrifuge, a reduction device connected to the rotating bowl and driving the conveyor at a slightly different rate. GEL
A term used to designate high colloidal, high-yielding, viscosity-building commercial clays, such as bentonite and attapulgite clays. GEL STRENGTH
The ability or the measure of the ability of a colloid to form gels. Gel strength is a pressure unit usually reported in lbs/100 sq. ft. It is a measure of the same inter-particle forces of a fluid as determined by the yield point under dynamic conditions. GEL STRENGTH, INITIAL
The measured initial gel strength of a fluid is the maximum reading (deflection) taken from a direct-reading viscometer after the fluid has been allowed to sit for 10 seconds. G-FORCE
The acceleration of gravity (32.2 ft/sec/sec, 9.8 m/sec/sec). Increased acceleration due to centrifugal force is usually expressed as multiple of gravitational acceleration:1G, 2G, 3G, 11,000G, etc. GUMBO
Any sticky shale formation encountered while drilling. GUNNING THE PITS
Agitation of the drilling fluid by means of mud guns.
H U
HEAD
Head refers to the height (in feet) of a column of fluid necessary to develop a specific pressure. Feet of head is commonly used to refer to the pressure put out by a centrifugal pump. 208
HIGH SPECIFIC GRAVITY SOLIDS Those solids having a specific gravity greater than 2.6. Barite is the most common, but others such as iron oxide (hematite) or galena (lead sulfide) are also used. See related Term: LOW SPECIFIC GRAVITY SOLIDS. HOOK STRIPS The hooks on the edges of a screen section which accept the tension member. HOPPER See MUD HOPPER. HORSEPOWER A measure of the rate at which work is done. Motor nameplate horsepower is the maximum steady load that the motor can pull without damage. HYDRATION The absorption and/or adsorption of water by a substance. In clays it usually results in swelling, dispersion and disintegration into colloidal particles. HYDROCYCLONE A liquid-solids separation device which utilizes centrifugal force to speed up settling. Drilling fluid is pumped tangentially into a cone and the rotation of the fluid provides centrifugal force to separate particles by mass - the heavier solids being separated from the light solids and liquid. HYDROCYCLONE SIZE The maximum inside working diameter of the conical section of a hydrocyclone.
I U
INERTIA That force which makes a moving particle tend to maintain its position or motion. INHIBITED MUD A drilling fluid having an aqueous phase with a chemical composition that tends to retard and even prevent (inhibit) appreciable hydration (swelling) or dispersion of formation clays and shale’s through chemical and/or physical means is referred to as being an inhibited mud. See INHIBITOR (mud). INHIBITOR (mud) Substances generally regarded as drilling mud contaminants, such as salt and calcium sulfate, are called inhibitors when purposely added to mud so that the filtrate from the drilling fluid will prevent or retard the hydration of formation clays and shales. 209
INLET
The opening through which the feed mud enters a solids control device. INVERT OIL-EMULSION MUD
An invert emulsion is a water-in-oil emulsion in which fresh or salt water is the dispersed phase and diesel, crude, or some other oil is the continuous phase. Water increases the viscosity while oil reduces it.
L U
LEAD
In a decanting centrifuge, the slurry conducting channel formed by the adjacent walls of the flutes or blades of the screw conveyor. LIGNOSULFONATES
Organic drilling fluid additives derived from by-products of the sulfite paper manufacturing process ultilizing coniferous woods. Commonly used as dispersants and anti-flocculants. In high concentrations they may be used for fluid-loss control and shale inhibition. LIQUID *
Fluid that will flow freely, takes the shape of its container. LIQUID-CLAY PHASE
See Preferred Term: OVERFLOW LIQUID DISCHARGE
See Preferred Terms: OVERFLOW (Hydrocyclones); UNDERFLOW (screens). LIQUID FILM
The liquid surrounding each particle discharging from the solids discharge of cyclones and screens. See related term: FREE LIQUID. LOST CIRCULATION
The result of whole mud escaping into a formation, usually in cavernous, fractured, or coarsely permeable beds. Evidenced by the complete or partial failure of the mud to return to the surface while circulating. LOST CIRCULATION MATERIALS (LCM)
Materials added to drilling fluid to control mud loss by bridging or plugging the lost circulation zone. LOW SILT MUD
An unweighted mud that has all the sand and high proportion of the silts removed and has a substantial content of bentonite or other water-lossreducing clays. 210
LOW SOLIDS MUDS
Low solids muds are unweighted water-base muds containing less than 10% drilled solids (1-4% is a normal range). They are used whenever it is desirable to increase penetration rate. In general, the lower solids content in a mud, the greater the penetration rate. LOW SPECIFIC GRAVITY SOLIDS
Drilled solids of various sizes, commercial colloids, salts, lost circulation materials, i.e., all solids in drilling fluid, except barite or other commercial weighting materials. Typical S.G. is 2.6.
M U
MANIFOLD (Cyclone)
A piping arrangement through which liquids, solids or slurries from one or more sources can be fed to or discharged from a solids separation device. MARSH FUNNEL
An instrument used in the field to determine funnel viscosity of a drilling fluid. See related term: FUNNEL VISCOSITY. MASS
The effective weight of a particle; the mass of a particle is dependent on its specific gravity and size. MECHANICAL AGITATOR
A device used to mix, blend, or stir fluids by means of a rotating impeller blade. MEDIAN CUT
In separating solids particles from a specific liquid-solids slurry under specified conditions, the effectiveness of the separation device expressed as the particle size that reports 50% to the overflow and 50% to the underflow. MEDIUM (sol ids)
Particles whose diameter is between 74-250 microns. MESH
The number openings per linear inch in a screen. For example, a 200 mesh screen has 200 openings per linear inch. MESH COUNT
The count is the term most often used to describe a square or rectangular mesh screen cloth. A mesh count such as 30 x 30 (or often 30 mesh) indicates a square mesh, while a designation such as 70 x 30 mesh indicates a rectangular mesh. Shale shaker screens used in the industry are no longer defined by mesh because mesh doesn’t describe the screen as well as the new API RP 13C nomenclature does. 211
MESH EQUIVALENT As used in oilfield drilling applications, the U.S. Sieve number which has the same size opening as the minimum opening of the screen in use. MICRON (µ) A micron is equal to one thousandth of a millimeter; used as a measure of particle size. MUD Mud is the name most commonly used for drilling fluids. Drilling mud circulates cuttings from the hole, provides the pressure required to prevent the flow of formation fluids and performs other vital functions. MUD ADDITIVE Any material added to a drilling fluid to achieve a particular purpose. MUD BALANCE A beam-type balance used to determine mud density. It consists of a base, graduated beam with constant-volume cup, lid, rider, knife edge and counterweight. MUD BOX The feed compartment on a shale shaker into which the mud flow line discharges, and from which the mud is either fed to the screens or is bypassed. Also called the Backtank or Possum Belly. MUD CLEANER A solids separation device which combines hydrocyclones and a fine mesh vibrating screen. Used to recover valuable mud additives and liquids while removing undesirable solids from the fluid. MUD CONE See Preferred Term: HYDROCYCLONE. MUD ENGINEER A technician versed in drilling fluids whose duties are to manage, implement, and maintain the various types of oil well mud programs. MUD FEED Drilling fluid, with or without dilution, for introduction into a liquid-solids separator. MUD GUNS A system of pumps and piping in which drilling mud is pumped through nozzles at a high velocity. Used for mixing, blending and stirring the mud pits. MUD HOPPER A device used for mixing mud chemicals and other products into a fluid stream. It usually consists of a mud jet, an open top hopper, and downstream venturi. MUD HOUSE A structure at the rig used to store and shelter drilling fluid additives. 212
MUD MIXING DEVICES The most common device for adding solids to the mud is the mud hopper. Some other devices for mixing are: eductors, mechanical agitators, electric stirrers, mud guns, and chemical barrels. MUD PIT Earthen or steel storage facilities for the surface mud system. Mud pits which vary in volume and number are of two types: circulating and reserve. Mud testing and conditioning is normally done in the circulating pit system. MUD PUMPS See RIG PUMPS. MUD SCALES See MUD BALANCE. MUD STILL See RETORT.
N U
NEAR SIZE The material very nearly the size of a screen opening, generally considered as plus or minus 25% of the opening.
O U
OBLONG (Mesh) Screen cloth having more wires per inch in one direction than in another. For example, 70 x 30 mesh has 70 wires per inch in one direction and 30 wires per inch in the other direction. (Also called “rectangular” mesh.) OIL-BASE MUD A drilling fluid containing oil as its liquid phase, usually including 1-5% emulsified water. OPEN AREA See PERCENT OPEN AREA. OVERFLOW The discharge stream from a centrifugal separation device that contains a higher percentage of liquids than does the feed. OVERFLOW HEADER In hydrocyclone operation, a pipe into which two or more hydrocyclones discharge their overflow. OVERLOAD To feed separable solids to a separating device at a rate greater than its solids discharge capacity. 213
OVERSIZE (Soli ds)
Particles, in a given situation, that can be separated from the liquid phase by centrifugal force or which will not pass through the openings of the screen in use.
P U
PARTICLE
In drilling mud work, a piece of solid material. PARTICLE SIZE
Particle diameter, usually expressed in microns. See related term: EQUIVALENT SPHERICAL DIAMETER. PARTICLE SIZE DISTRIBUTION
The fraction or percentage of particles of various sizes or size ranges. See related term: SIEVE ANALYSIS. PARTICLE SURFACE AREA
See SPECIFIC SURFACE AREA. PENETRATION RATE
The rate at which the drill bit penetrates the formation, expressed in linear units, i.e., feet/minute or feet/hour. See related term: DRILLING RATE. PERCENT OPEN AREA
Ratio of the area of the screen openings to the total area of the screen surface. PERFORATED CYLINDER
A mechanical centrifugal separator in which the rotating element is a perforated cylinder (the rotor) inside of and concentric with an outer stationary cylindrical case. PERFORATED ROTOR
The rotating inner cylinder of the perforated cylinder centrifuge. PERMEABILITY
Permeability is a measure of the ability of a formation to allow passage of a fluid. PLASTICITY
The property possessed by some solids, particularly clays and clay slurries, of changing shape or flowing under applied stress without developing shear planes or fractures; that is, the ability to deform without breaking. 214
PLASTIC VISCOSITY
Plastic viscosity is a measure of the internal resistance to fluid flow attributable to the amount, type, and size of solids present in a given fluid and the resistance to flow (viscosity) of the liquid itself. When using a direct-indicating viscometer, plastic viscosity is found by subtracting the 300-rpm reading from the 600-rpm reading. PLUGGING (Screen Sur face) The wedging or jamming of openings in a screening surface by particles, preventing passage of undersize material. See related term: BLINDING. POLYMER
A synthetic mud additive used to maintain viscosity, control fluid loss and maintain other desirable mud properties. POLYURETHANE
A high performance elastomer polymer used in the manufacture of hydrocyclones. It offers a unique combination of physical properties, especially abrasion, toughness and resiliency. POOL The reservoir or pond of fluid, or slurry, formed inside the wall of hydrocyclones and centrifuges and in which classification or separation of solids occurs due to the accelerated sedimentation produced by centrifugal force. PORTS
The openings in a centrifuge for entry or exit of materials. Usually applied in connection with a descriptive term, i.e., feed ports, overflow ports, etc. PRESSURE HEAD
Pressure within a system equal to the pressure exerted by an equivalent height of fluid (expressed in feet). See related term: HEAD.
R U
RADIAL FLOW
Flow from a mechanical agitator in which fluid moves away from the axis of the impeller shaft (usually horizontally toward a mud tank wall). RATE OF PENETRATION
See PENETRATION RATE. RAW MUD
Mud, before dilution, that is to be processed by solids removal equipment. RECTANGULAR OPENING (Screen Cloth ) See OBLONG MESH. 215
RETENTION TIME (Screen )
The time any given particle of material is actually on a screening surface. RETENTION TIME (Centri fugal Separator s)
The time the liquid phase is actually in the separating device. RETORT
An instrument used to distill oil, water, and other volatile material in a mud to determine oil, water, and total solids content in volume-percent. Also called “mud still”. RHEOLOGY
The science that deals with deformation and flow of matter. RIG PUMPS (or Mud Pump s)
The reciprocating, positive displacement, high pressure pumps used to circulate drilling fluid through the hole. RIG SHAKER
A general term for a shale shaker using coarse mesh screen. ROPE DISCHARGE
The characteristic underflow of a hydrocyclone operating inefficiently and so overloaded with separable solids that not all the separated solids can crowd out the underflow opening, causing those that can exit to form a slow-moving, heavy, rope-like stream. (Also referred to as “rope” or “rope underflow.”) ROTARY DRILLING
The method of drilling wells that depends on the rotation of a drill bit which is attached to a column of drill pipe. A fluid is circulated through the drill pipe to flush out cuttings and perform other functions. RPM *
Revolutions per minute.
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SALT-WATER MUDS
A drilling fluid containing dissolved salt (brackish to saturated). These fluids may also include native solids, oil, and/or such commercial additives as clays, starch, etc. SAMPLES
Cuttings obtained for geological information from the drilling fluid as it emerges from the hole. They are washed, dried, and labelled to identify the depth at which they were taken. 216
SAND CONTENT The sand content of a drilling fluid is the insoluble solids content retained on a 200-mesh screen. It is usually expressed as the percentage bulk volume of sand in a drilling fluid. This test is an elementary type in that the retained solids are not necessarily silica and may not be altogether abrasive. SAND TRAP The first compartment and the only unstirred compartment in a welldesigned mud system; intended as a settling compartment to catch large solids which may get past the shale shaker. SCREEN CLOTH A type of screening surface, woven in square or rectangular openings. See related term: WIRE CLOTH. SCREENING A mechanical process which accomplishes a separation of particles on the basis of size, through their acceptance or rejection by a screening surface. SCREENING SURFACE The medium containing the openings for passage of undersize material. SCROLL See Preferred Term: FLUTE. SETTLING VELOCITY The velocity a particle achieves in a given fluid when gravity forces equal the friction forces of the moving particle. SHALE Stone of widely varying hardness, color, and compaction that is formed of clay-sized grains. SHALE SHAKER A general term for devices which use a vibrating screen to remove cuttings and other large solids from drilling mud. SHEAR (Shearing Stress) An action, resulting from applied forces, which causes or tends to cause two contiguous parts of a body to slide relatively to each other in a direction parallel to their plane of contact - as in particles within a mud. SIEVE See Preferred Term: TESTING SIEVE. SIEVE ANALYSIS A measurement of particle size and percentage of the amount of material in various particle size groupings. See related term: PARTICLE SIZE DISTRIBUTION. SILT Materials whose particle size generally falls between 2-74 microns. 217
SIZE DISTRIBUTION
See Preferred Term: PARTICLE SIZE DISTRIBUTION. SLOUGHING
A situation in which portions of a formation fall away from the walls of a hole, as a result of incompetent unconsolidated formations, high angle of repose, wetting along internal bedding planes, or swelling of formations caused by fluid loss. See related term: CAVING. SLURRY
A mixture or suspension of solid particles in liquids. SOLIDS
All particles of matter in the drilling fluid, i.e., drilled formation cuttings, barite, etc. SOLIDS CONTENT
The total amount of solids in a drilling fluid as determined by distillation, including both the dissolved and the suspended (or undissolved) solids. The suspended-solids content may be a combination of high and low specific gravity solids and native or commercial solids. Examples of dissolved solids are the soluble salts of sodium, calcium, and magnesium. The total suspended and dissolved solids content is commonly expressed in percent by volume. SOLIDS DISCHARGE
That stream from a liquid-solids separator containing a higher percentage of solids than the feed does. SOLIDS DISCHARGE CAPACITY
The maximum rate at which a liquid-solids separation device can discharge solids without overloading. SPECIFIC GRAVITY
The weight of a particular volume of any substance compared to the weight of an equal volume of water at a reference temperature. SPECIFIC SURFACE AREA
The effective surface area per unit of weight of some sample or grouping of particles of matter, usually expressed in units of area per units of weight such as square feet per pound, or acres per pound, square meters per gram, etc. It provides a valuable indication of the amount of liquid particles can attract and retain on their surface. SPEED
The frequency at which a vibrating screen operates, usually expressed in RPM or CPM; the bowl rpm of a decanting centrifuge; the rotor rpm of a perforated cylinder centrifuge. SPRAY DISCHARGE
The underflow of hydrocyclones when not overloaded with separable solids. 218
SPUDDING IN
The starting of the drilling operation of a new hole. SPUD MUD
The fluid used when drilling starts at the surface, often a thick bentonite lime slurry. SPURT LOSS
The flux of fluids and solids which occurs in the initial stages of any filtration before pore openings are bridged and a filter cake is formed. STROKE
The distance between the extremities of motion; viz., the diameter of a circular motion. See related term: AMPLITUDE. STUCK
A condition whereby the drill pipe, casing, or other devices inadvertently become lodged in the hole. SUMP
A pit or tank into which a fluid drains before recirculation or in which wastes gather before disposal. SURGE LOSS
See Preferred Term: SPURT LOSS. SWABBING
The pressure reduction resulting from the withdrawal of pipe from a hole filled with viscous mud or a balled bit.
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TENSIONING
The stretching of the screening surface within the vibrating shaker frame. TENSION RING
A rigid hoop surrounding a stretched screen cloth used for maintaining screen tension and mounting the screen to a shaker frame. TEST SIEVE
A cylindrical or tray-like container with a screening surface bottom of standard aperture. THINNER
Any various organic agents (tannins, lignins, lignosulfonates, etc.) and inorganic agents (pyrophosphates, tetraphosphates, etc.) that are added to a drilling fluid to reduce its viscosity and/or thixotropic properties. 219
THIXOTROPY
The ability of a fluid to develop gel strength with time. That property of a fluid which causes it to build up a rigid or semi-rigid gel structure if allowed to stand at rest, yet return to a fluid state when agitated. THRUST
The force that pushes on the mud as on a shale shaker screen. TOTAL DEPTH (or TD)
The greatest depth reached by the drill bit. TOTAL HEAD
The sum of all head within a system (Total Head = velocity head + pressure head + elevation head.)
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ULTRA-FINE (Soli ds )
Particles whose diameter is between 2-44 microns. UNDERFLOW (Hydrocyclone)
The discharge stream from centrifugal separators that contains a higher percentage of solids than does the feed. See general term: SOLIDS DISCHARGE. UNDERFLOW (Screen)
The discharge stream from a screening device which contains a greater percentage of liquids than does the feed. UNDERFLOW HEADER
A pipe, tube, or conduit into which two or more hydrocyclones discharge their underflow. UNDERSIZE (Solids)
Particles that will, in a given situation, remain with the liquid phase when subjected to centrifugal force, or will pass through the openings of the screen in use. UNWEIGHTED (Mud)
A drilling fluid which has not had significant amounts of high gravity solids added and whose density is generally less than 10 pounds per gallon.
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VELOCITY HEAD
Head (relating to pressure when multiplied by the density of the fluid) created by the movement of a fluid, equal to an equivalent height of static fluid. 220
VENTURI Streamlining up to a given pipe size following a restriction (as in a jet in a mud hopper) to minimize turbulence and pressure drop. V.G. METER See VISCOMETER, DIRECT-INDICATING. VIBRATING SCREEN A screen with motion induced as an aid to solids separation. VISCOMETER, DIRECT-INDICATING Commonly called a “V-G meter.” The instrument is a rotational-type device powered by means of an electric motor or handcrank, and is used to determine the apparent viscosity, plastic viscosity, yield point, and gel strengths of drilling fluids. The usual speeds are 600 and 300 rpm. See API RP 13B for operational procedures. VISCOSITY The internal resistance offered by a fluid to flow. This phenomenon is attributable to the attractions between molecules of a liquid, and is a measure of the combined effects of adhesion and cohesion to the effects of suspended particles, and to the liquid environment. The greater this resistance, the greater the viscosity. See related terms: APPARENT VISCOSITY, PLASTIC VISCOSITY. VORTEX A cylindrical or conical shaped core of air or vapor lying along the central axis of the rotating slurry inside a hydrocyclone. VORTEX FINDER A hollow cylinder extending axially into the barrel of a hydrocyclone. The overflow exits from the separating chamber through the vortex finder, and the vortex is centered in the hydrocyclone by the hole in the vortex finder, hence the name.
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WALL CAKE The solid material deposited along the wall of the hole resulting from filtration of the fluid part of the mud into the formation. See related terms: CAKE THICKNESS, FILTER CAKE. WALL STICKING See Preferred Term: DIFFERENTIAL PRESSURE STICKING. WATER-BASE MUD The conventional drilling fluid containing water as the continuous phase. WATER FEED Water added for dilution of the mud feed into a centrifugal separator. See related term: DILUTION WATER. 221
WEIGHT (Mud Weight)
In mud work, weight refers to the density of a drilling fluid. This is normally expressed in lbs/gal or specific gravity. See related term: DENSITY.
WEIGHT MATERIAL
Any of the heavy solids (specific gravity of 4.2 or more) used to increase the density of drilling fluids. This material is most commonly barite but can be galena, hematite, etc… In special applications, calcium carbonate is also called a weight material (even though its specific gravity is 2.6).
WEIGHTED (Mud)
A drilling fluid to which heavy solids have been added to increase its density.
WEIGHT UP *
To increase the weight of a drilling mud, usually by the addition of weight material.
WETTING
The adhesion of a liquid to the surface of a solid.
WIRE CLOTH
Screen cloth of woven wire.
WORKOVER FLUID
Any type of fluid used in the workover operation of a well.
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YIELD As applied to drilling mud, a term used to define the quality of a clay by describing the number of barrels of slurry of a given viscosity that can be made from a ton of the clay. YIELD POINT The resistance to initial flow, representing the stress required to start fluid movement. This resistance is due to electrical charges on or near the surfaces of the particles. The values of the yield point and thixotropy, respectively, are measurements of the same fluid properties under dynamic and static states. The Bingham yield value, reported in lbs/100 sq. ft, is determined by the direct-indicating viscometer by subtracting the plastic viscosity from the 300-rpm reading.
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