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| موضوع: كتاب Drilling Fluids Processing Handbook الأحد 20 مارس 2022, 12:44 am | |
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أخواني في الله أحضرت لكم كتاب Drilling Fluids Processing Handbook ASME
و المحتوى كما يلي :
CONTENTS Biographies xvii Preface xxiii 1 Historical Perspective and Introduction 1 1.1 Scope 1 1.2 Purpose 1 1.3 Introduction 2 1.4 Historical Perspective 4 1.5 Comments 11 1.6 Waste Management 13 2 Drilling Fluids 15 2.1 Drilling Fluid Systems 15 2.1.1 Functions of Drilling Fluids 15 2.1.2 Types of Drilling Fluids 16 2.1.3 Drilling Fluid Selection 17 2.1.4 Separation of Drilled Solids from Drilling Fluids 20 2.2 Characterization of Solids in Drilling Fluids 25 2.2.1 Nature of Drilled Solids and Solid Additives 25 2.2.2 Physical Properties of Solids in Drilling Fluids 26 2.3 Properties of Drilling Fluids 31 2.3.1 Rheology 32 2.4 Hole Cleaning 38 2.4.1 Detection of Hole-Cleaning Problems 38 2.4.2 Drilling Elements That Affect Hole Cleaning 40 2.4.3 Filtration 45 2.4.4 Rate of Penetration 47 2.4.5 Shale Inhibition Potential/Wetting Characteristics 51 2.4.6 Lubricity 52 2.4.7 Corrosivity 53 2.4.8 Drilling-Fluid Stability and Maintenance 54 v2.5 Drilling Fluid Products 54 2.5.1 Colloidal and Fine Solids 54 2.5.2 Macropolymers 55 2.5.3 Conventional Polymers 56 2.5.4 Surface-Active Materials 57 2.6 Health, Safety, and Environment and Waste Management 58 2.6.1 Handling Drilling Fluid Products and Cuttings 58 2.6.2 Drilling Fluid Product Compatibility and Storage Guidelines 58 2.6.3 Waste Management and Disposal 62 References 66 3 Solids Calculation 69 3.1 Procedure for a More Accurate Low-Gravity Solids Determination 70 3.1.1 Sample Calculation 73 3.2 Determination of Volume Percentage of Low-Gravity Solids in Water-Based Drilling Fluid 77 3.3 Rig-Site Determination of Specific Gravity of Drilled Solids 78 4 Cut Points 81 4.1 How to Determine Cut Point Curves 85 4.2 Cut Point Data: Shale Shaker Example 90 5 Tank Arrangement 93 5.1 Active System 94 5.1.1 Suction and Testing Section 94 5.1.2 Additions Section 95 5.1.3 Removal Section 95 5.1.4 Piping and Equipment Arrangement 96 5.1.5 Equalization 98 5.1.6 Surface Tanks 99 5.1.7 Sand Traps 100 5.1.8 Degasser Suction and Discharge Pit 102 5.1.9 Desander Suction and Discharge Pits 102 5.1.10 Desilter Suction and Discharge Pits (Mud Cleaner/ Conditioner) 103 5.1.11 Centrifuge Suction and Discharge Pits 103 5.2 Auxiliary Tank System 104 5.2.1 Trip Tank 104 5.3 Slug Tank 105 5.4 Reserve Tank(s) 105 vi Contents6 Scalping Shakers and Gumbo Removal 107 7 Shale Shakers 111 7.1 How a Shale Shaker Screens Fluid 113 7.2 Shaker Description 116 7.3 Shale Shaker Limits 118 7.3.1 Fluid Rheological Properties 119 7.3.2 Fluid Surface Tension 120 7.3.3 Wire Wettability 120 7.3.4 Fluid Density 120 7.3.5 Solids: Type, Size, and Shape 120 7.3.6 Quantity of Solids 121 7.3.7 Hole Cleaning 121 7.4 Shaker Development Summary 121 7.5 Shale Shaker Design 122 7.5.1 Shape of Motion 123 7.5.2 Vibrating Systems 133 7.5.3 Screen Deck Design 134 7.5.4 g Factor 136 7.5.5 Power Systems 140 7.6 Selection of Shale Shakers 143 7.6.1 Selection of Shaker Screens 145 7.6.2 Cost of Removing Drilled Solids 145 7.6.3 Specific Factors 146 7.7 Cascade Systems 148 7.7.1 Separate Unit 150 7.7.2 Integral Unit with Multiple Vibratory Motions 150 7.7.3 Integral Unit with a Single Vibratory Motion 152 7.7.4 Cascade Systems Summary 152 7.8 Dryer Shakers 153 7.9 Shaker User’s Guide 154 7.9.1 Installation 155 7.9.2 Operation 156 7.9.3 Maintenance 157 7.9.4 Operating Guidelines 158 7.10 Screen Cloths 159 7.10.1 Common Screen Cloth Weaves 160 7.10.2 Revised API Designation System 167 7.10.3 Screen Identification 174 7.11 Factors Affecting Percentage-Separated Curves 174 7.11.1 Screen Blinding 176 7.11.2 Materials of Construction 177 7.11.3 Screen Panels 178 Contents vii7.11.4 Hook-Strip Screens 180 7.11.5 Bonded Screens 180 7.11.6 Three-Dimensional Screening Surfaces 180 7.12 Non-Oilfield Drilling Uses of Shale Shakers 181 7.12.1 Microtunneling 181 7.12.2 River Crossing 182 7.12.3 Road Crossing 182 7.12.4 Fiber-Optic Cables 182 8 Settling Pits 183 8.1 Settling Rates 183 8.2 Comparison of Settling Rates of Barite and Low-Gravity Drilled Solids 186 8.3 Comments 187 8.4 Bypassing the Shale Shaker 188 9 Gas Busters, Separators, and Degassers 189 9.1 Introduction: General Comments on Gas Cutting 189 9.2 Shale Shakers and Gas Cutting 192 9.3 Desanders, Desilters, and Gas Cutting 192 9.4 Centrifuges and Gas Cutting 193 9.5 Basic Equipment for Handling Gas-Cut Mud 193 9.5.1 Gravity Separation 195 9.5.2 Centrifugal Separation 195 9.5.3 Impact, Baffle, or Spray Separation 195 9.5.4 Parallel-Plate and Thin-Film Separation 196 9.5.5 Vacuum Separation 196 9.6 Gas Busters 196 9.7 Separators 197 9.7.1 Atmospheric Separators 197 9.7.2 West Texas Separator 198 9.8 Pressurized Separators 199 9.8.1 Commercial Separator/Flare Systems 199 9.8.2 Pressurized, or Closed, Separators: Modified Production Separators 200 9.8.3 Combination System: Separator and Degasser 202 9.9 Degassers 202 9.9.1 Degasser Operations 203 9.9.2 Degasser Types 205 9.9.3 Pump Degassers or Atmospheric Degassers 207 9.9.4 Magna-VacTM Degasser 207 9.10 Points About Separators and Separation 209 References 210 viii Contents10 Suspension, Agitation, and Mixing of Drilling Fluids 213 10.1 Basic Principles of Agitation Equipment 213 10.2 Mechanical Agitators 214 10.2.1 Impellers 215 10.2.2 Gearbox 222 10.2.3 Shafts 222 10.3 Equipment Sizing and Installation 223 10.3.1 Design Parameters 223 10.3.2 Compartment Shape 226 10.3.3 Tank and Compartment Dimensions 226 10.3.4 Tank Internals 226 10.3.5 Baffles 227 10.3.6 Sizing Agitators 227 10.3.7 Turnover Rate (TOR) 228 10.4 Mud Guns 232 10.4.1 High-Pressure Mud Guns 233 10.4.2 Low-Pressure Mud Guns 233 10.4.3 Mud Gun Placement 234 10.4.4 Sizing Mud Gun Systems 235 10.5 Pros and Cons of Agitation Equipment 237 10.5.1 Pros of Mechanical Agitators 238 10.5.2 Cons of Mechanical Agitators 238 10.5.3 Pros of Mud Guns 238 10.5.4 Cons of Mud Guns 238 10.6 Bernoulli’s Principle 239 10.6.1 Relationship of Pressure, Velocity, and Head 240 10.7 Mud Hoppers 244 10.7.1 Mud Hopper Installation and Operation 246 10.7.2 Mud Hopper Recommendations 248 10.7.3 Other Shearing Devices 250 10.8 Bulk Addition Systems 250 10.9 Tank/Pit Use 253 10.9.1 Removal 253 10.9.2 Addition 254 10.9.3 Suction 254 10.9.4 Reserve 255 10.9.5 Discharge 255 10.9.6 Trip Tank 255 References 255 11 Hydrocyclones 257 11.1 Discharge 261 11.2 Hydrocyclone Capacity 265 Contents ix11.3 Hydrocyclone Tanks and Arrangements 266 11.3.1 Desanders 267 11.3.2 Desilters 268 11.3.3 Comparative Operation of Desanders and Desilters 269 11.3.4 Hydrocyclone Feed Header Problems 269 11.4 Median (D50) Cut Points 270 11.4.1 Stokes’ Law 271 11.5 Hydrocyclone Operating Tips 276 11.6 Installation 278 11.7 Conclusions 279 11.7.1 Errata 281 12 Mud Cleaners 283 12.1 History 286 12.2 Uses of Mud Cleaners 288 12.3 Non-Oilfield Use of Mud Cleaners 291 12.4 Location of Mud Cleaners in a Drilling-Fluid System 291 12.5 Operating Mud Cleaners 292 12.6 Estimating the Ratio of Low-Gravity Solids Volume and Barite Volume in Mud Cleaner Screen Discard 293 12.7 Performance 295 12.8 Mud Cleaner Economics 297 12.9 Accuracy Required for Specific Gravity of Solids 300 12.10 Accurate Solids Determination Needed to Properly Identify Mud Cleaner Performance 300 12.11 Heavy Drilling Fluids 301 13 Centrifuges 303 13.1 Decanting Centrifuges 303 13.1.1 Stokes’ Law and Drilling Fluids 308 13.1.2 Separation Curves and Cut Points 308 13.1.3 Drilling-Fluids Solids 310 13.2 The Effects of Drilled Solids and Colloidal Barite on Drilling Fluids 311 13.3 Centrifugal Solids Separation 313 13.3.1 Centrifuge Installation 316 13.3.2 Centrifuge Applications 316 13.3.3 The Use of Centrifuges with Unweighted Drilling Fluids 317 13.3.4 The Use of Centrifuges with Weighted Drilling Fluids 317 x Contents13.3.5 Running Centrifuges in Series 318 13.3.6 Centrifuging Drilling Fluids with Costly Liquid Phases 320 13.3.7 Flocculation Units 320 13.3.8 Centrifuging Hydrocyclone Underflows 321 13.3.9 Operating Reminders 321 13.3.10 Miscellaneous 321 13.4 Rotary Mud Separator 321 13.4.1 Problem 1 322 13.5 Solutions to the Questions in Problem 1 324 13.5.1 Question 1 324 13.5.2 Question 2 324 13.5.3 Question 3 324 13.5.4 Question 4 325 13.5.5 Question 5 325 13.5.6 Question 6 325 13.5.7 Question 7 325 13.5.8 Question 8 325 13.5.9 Question 9 326 13.5.10 Question 10 326 14 Use of the Capture Equation to Evaluate the Performance of Mechanical Separation Equipment Used to Process Drilling Fluids 327 14.1 Procedure 330 14.1.1 Collecting Data for the Capture Analysis 330 14.1.2 Laboratory Analysis 330 14.2 Applying the Capture Calculation 331 14.2.1 Case 1: Discarded Solids Report to Underflow 331 14.2.2 Case 2: Discarded Solids Report to Overflow 331 14.2.3 Characterizing Removed Solids 331 14.3 Use of Test Results 332 14.3.1 Specific Gravity 332 14.3.2 Particle Size 332 14.3.3 Economics 333 14.4 Collection and Use of Supplementary Information 334 15 Dilution 335 15.1 Effect of Porosity 337 15.2 Removal Efficiency 338 15.3 Reasons for Drilled-Solids Removal 339 15.4 Diluting as a Means for Controlling Drilled Solids 340 15.5 Effect of Solids Removal System Performance 341 Contents xi15.6 Four Examples of the Effect of Solids Removal Equipment Efficiency 342 15.6.1 Example 1 343 15.6.2 Example 2 344 15.6.3 Example 3 346 15.6.4 Example 4 347 15.6.5 Clean Fluid Required to Maintain 4%vol Drilled Solids 347 15.7 Solids Removal Equipment Efficiency for Minimum Volume of Drilling Fluid to Dilute Drilled Solids 348 15.7.1 Equation Derivation 349 15.7.2 Discarded Solids 350 15.8 Optimum Solids Removal Equipment Efficiency (SREE) 351 15.9 Solids Removal Equipment Efficiency in an Unweighted Drilling Fluid from Field Data 354 15.9.1 Excess Drilling Fluid Built 356 15.10 Estimating Solids Removal Equipment Efficiency for a Weighted Drilling Fluid 357 15.10.1 Solution 358 15.10.2 Inaccuracy in Calculating Discard Volumes 360 15.11 Another Method of Calculating the Dilution Quantity 361 15.12 Appendix: American Petroleum Institute Method 361 15.12.1 Drilled Solids Removal Factor 361 15.12.2 Questions 362 15.13 A Real-Life Example 362 15.13.1 Exercise 1 362 15.13.2 Exercise 2 364 15.13.3 Exercise 3 365 15.13.4 Exercise 4 365 15.13.5 General Comments 366 16 Waste Management 367 16.1 Quantifying Drilling Waste 367 16.1.1 Example 1 368 16.1.2 Example 2 368 16.1.3 Example 3 369 16.1.4 Example 4 370 16.1.5 Example 5 371 16.1.6 Example 6 372 16.2 Nature of Drilling Waste 372 16.3 Minimizing Drilling Waste 374 16.3.1 Total Fluid Management 375 16.3.2 Environmental Impact Reduction 377 xii Contents16.4 Offshore Disposal Options 377 16.4.1 Direct Discharge 378 16.4.2 Injection 378 16.4.3 Collection and Transport to Shore 380 16.4.4 Commercial Disposal 380 16.5 Onshore Disposal Options 382 16.5.1 Land Application 382 16.5.2 Burial 386 16.6 Treatment Techniques 391 16.6.1 Dewatering 391 16.6.2 Thermal Desorption 395 16.6.3 Solidification/Stabilization 397 16.7 Equipment Issues 399 16.7.1 Augers 400 16.7.2 Vacuums 402 16.7.3 Cuttings Boxes 403 16.7.4 Cuttings Dryers 406 References 412 17 The AC Induction Motor 413 17.1 Introduction to Electrical Theory 413 17.2 Introduction to Electromagnetic Theory 421 17.3 Electric Motors 423 17.3.1 Rotor Circuits 424 17.3.2 Stator Circuits 425 17.4 Transformers 427 17.5 Adjustable Speed Drives 429 17.6 Electric Motor Applications on Oil Rigs 432 17.6.1 Ratings 432 17.6.2 Energy Losses 433 17.6.3 Temperature Rise 434 17.6.4 Voltage 435 17.7 Ambient Temperature 435 17.8 Motor Installation and Troubleshooting 438 17.9 Electric Motor Standards 439 17.10 Enclosure and Frame Designations 441 17.10.1 Protection Classes Relating to Enclosures 443 17.11 Hazardous Locations 444 17.12 Motors for Hazardous Duty 449 17.13 European Community Directive 94/9/EC 451 17.14 Electric Motors for Shale Shakers 454 17.15 Electric Motors for Centrifuges 459 Contents xiii17.16 Electric Motors for Centrifugal Pumps 459 17.17 Study Questions 460 18 Centrifugal Pumps 465 18.1 Impeller 465 18.2 Casing 467 18.3 Sizing Centrifugal Pumps 470 18.3.1 Standard Definitions 471 18.3.2 Head Produces Flow 479 18.4 Reading Pump Curves 480 18.5 Centrifugal Pumps Accelerate Fluid 484 18.5.1 Cavitation 485 18.5.2 Entrained Air 486 18.6 Concentric vs Volute Casings 488 18.6.1 Friction Loss Tables 490 18.7 Centrifugal Pumps and Standard Drilling Equipment 491 18.7.1 Friction Loss and Elevation Considerations 491 18.8 Net Positive Suction Head 503 18.8.1 System Head Requirement (SHR) Worksheet 506 18.8.2 Affinity Laws 506 18.8.3 Friction Loss Formulas 507 18.9 Recommended Suction Pipe Configurations 508 18.9.1 Supercharging Mud Pumps 510 18.9.2 Series Operation 512 18.9.3 Parallel Operation 513 18.9.4 Duplicity 513 18.10 Standard Rules for Centrifugal Pumps 513 18.11 Exercises 514 18.11.1 Exercise 1 514 18.11.2 Exercise 2: System Head Requirement Worksheet 515 18.11.3 Exercise 3 517 18.11.4 Exercise 4 517 18.12 Appendix 518 18.12.1 Answers to Exercise 1 518 18.12.2 Answers to Exercise 2: System Head Requirement Worksheet 518 18.12.3 Answers to Exercise 3 520 18.12.4 Answers to Exercise 4 520 19 Solids Control in Underbalanced Drilling 521 19.1 Underbalanced Drilling Fundamentals 521 19.1.1 Underbalanced Drilling Methods 523 xiv Contents19.2 Air/Gas Drilling 523 19.2.1 Environmental Contamination 524 19.2.2 Drilling with Natural Gas 525 19.2.3 Sample Collection While Drilling with Air or Gas 526 19.2.4 Air or Gas Mist Drilling 527 19.3 Foam Drilling 529 19.3.1 Disposable Foam Systems 529 19.3.2 Recyclable Foam Systems 530 19.3.3 Sample Collection While Drilling with Foam 532 19.4 Liquid/Gas (Gaseated) Systems 532 19.5 Oil Systems, Nitrogen/Diesel Oil, Natural Gas/Oil 535 19.5.1 Sample Collection with Aerated Systems 535 19.6 Underbalanced Drilling with Conventional Drilling Fluids or Weighted Drilling Fluids 536 19.7 General Comments 537 19.7.1 Pressurized Closed Separator System 538 19.8 Possible Underbalanced Drilling Solids-Control Problems 539 19.8.1 Shale 539 19.8.2 Hydrogen Sulfide Gas 540 19.8.3 Excess Formation Water 540 19.8.4 Downhole Fires and Explosions 540 19.8.5 Very Small Air- or Gas-Drilled Cuttings 541 19.8.6 Gaseated or Aerated Fluid Surges 541 19.8.7 Foam Control 542 19.8.8 Corrosion Control 542 Suggested Reading 542 20 Smooth Operations 547 20.1 Derrickman’s Guidelines 548 20.1.1 Benefits of Good Drilled-Solids Separations 549 20.1.2 Tank and Equipment Arrangements 549 20.1.3 Shale Shakers 550 20.1.4 Things to Check When Going on Tour 552 20.1.5 Sand Trap 552 20.1.6 Degasser 553 20.1.7 Hydrocyclones 554 20.1.8 Hydrocyclone Troubleshooting 557 20.1.9 Mud Cleaners 558 20.1.10 Centrifuges 560 20.1.11 Piping to Materials Additions (Mixing) Section 561 20.2 Equipment Guidelines 562 20.2.1 Surface Systems 562 Contents xv20.2.2 Centrifugal Pumps 572 20.3 Solids Management Checklist 577 20.3.1 Well Parameters/Deepwater Considerations 577 20.3.2 Drilling Program 579 20.3.3 Equipment Capability 579 20.3.4 Rig Design and Availability 580 20.3.5 Logistics 580 20.3.6 Environmental Issues 580 20.3.7 Economics 581 Appendix 583 Glossary 585 INDEX A AC, see Alternating current Adjustable speed drive benefits and disadvantages, 431–432 components, 430 functions, 429–430 torque versus rpm load characteristics, 430–431 types used with induction motors, 431 Agitators baffles American Petroleum Institute guidelines, 565 round tank baffling, 227 square tank baffling, 227 components, 214–215 design parameters compartment shape, 226 impeller selection, 223–225 internal piping, 226 overview, 223 tank and compartment dimensions, 226 gearbox, 222 impellers, see Impeller pros and cons, 237–238 purpose, 213–214 shafts, 222–223 sizing, 227–232 Air pycnometer, density of weighting material measurement, 29 Alternating current, direct current comparison, 414 American Petroleum Institute dilution calculation, 361–362 equipment guidelines centrifugal pumps, 572–577 surface systems, 562–572 Fluid Loss Test, 46 shaker screen designation system API number, 168–171 flow capacity, 171–173 identification tag contents, 173–174 manufacturer’s designation, 167 nonblanked area, 173 Ampere-turn definition, 423 Annular velocity, hole cleaning effects, 40–41 API, see American Petroleum Institute Apparent power, definition, 419–420 ASD, see Adjustable speed drive 651Augers, waste handling, 400–402 AV, see Annular velocity Average particle density, measurement, 28–29 B Bailing, see Shale inhibition Balanced elliptical motion shale shaker, principles, 132–133 Barite cost analysis, 11 mud cleaner low-gravity solids volume/barite volume ratio estimation in screen discard, 293–294 recovery via centrifugation, 314 settling rate, 186–187 shale shaker discard calculation, 75–76 size distribution in drilling fluid, 284–285 Bentonite, viscosity control, 55 Bernoulli’s principle, 239 Bingham Plastic model overview, 33–34 rotary viscometer data application, 37–38 yield point conversion, 43–44 Burial, see Land disposal, drilling waste C Capacitance, calculation, 416, 421 Capture analysis calculations, 331–332 data collection, 330 economics unweighted fluids, 333 weighted fluids, 333–334 laboratory work, 330 removed solid characterization particle size, 332 specific gravity, 331–332 supplementary information, 334 definition, 327 equation, 327–329 Carrying capacity index, calculation, 43 Cascade shale shaker advantages, 148–150 design integral unit multiple vibratory motions, 150 single vibratory motion, 152 separate unit system, 150 high solids loading, 149, 152 historical perspective, 148 screen mesh, 153 Casson model, 35 CCI, see Carrying capacity index Centrifuges applications unweighted drilling fluids, 317 weighted drilling fluids, 317–318 barite recovery, 314 bowl shape, 315 capture analysis, see Capture costs, 320, 322–326 cut points, 308–310 decanting centrifuge components and principles, 303, 305, 307, 314–315 652 IndexDerrickman’s guidelines, 560–561 drilled solids effects on drilling fluids, 311–313 flocculation units, 320 gas cutting problems, 193 g force calculation, 315–316 hydrocyclone underflow centrifugation, 321 installation, 316 motors, 459 operating guidelines, 321 overflow, 313–314 pump, see Pumps rotary mud separator, 321–322 separation limits, 308 series centrifugation, 318–319 suction and discharge pits, 103–104 traditional centrifuging, 314–315 underflow, 313–314 Chip hold-down pressure, rate of penetration relationship, 50 Circular motion shale shaker, principles, 127–128 Conductance, screens, 167, 171–173 Corrosion control, 53–54 mechanisms, 53 Costs capture analysis unweighted fluids, 333 weighted fluids, 333–334 centrifuging drilling fluids, 320, 322–326 dilution, 364 drilled solids removal, 145–146 estimation, 11–12 mud cleaner use, 297–299 solids management checklist, 581 waste management, 13 Current properties, 413 wire capacity by gauge, 142–143 Cut point centrifuges, 308–310 curve generation discard, 88–89 feed, 85–86 plotting, 89–90 shale shaker example, 90–92 underflow, 86 hydrocyclones, 261, 269–276, 282, 283–284 overview, 81–84 Cuttings boxes, waste handling, 403–404 Cuttings dryers installation, 411–412 legislation, 408–409 oil retention, 406–409 operation, 411 removed fluid processing, 410–411 volume reduction, 406 Cuttings, see Drilled solids D DC, see Direct current Degasser American Petroleum Institute guidelines, 566 combination separator and degasser, 202 Derrickman’s guidelines, 553–554 Magna-Vac degasser, 207 mechanisms, 193, 195–196, 203 Index 653Degasser (continued) operation variables, 203, 205 pump degassers, 207 purpose, 202 suction and discharge pit, 102 top equalization, 563 treatment calculations, 208 vacuum effects on entrained gas, 205 vacuum-tank degassers, 205–207 Delta connection, three-phase power, 417–418 Density equation, 69 Derrickman’s guidelines centrifuges, 560–561 degassers, 553–554 equipment checklist, 552 hydrocyclones, 554–558 mud cleaners, 558–560 piping to mixing section, 561–562 sand traps, 552–553 shale shakers, 550–551 tank and equipment arrangements, 549–550 Desander American Petroleum Institute guidelines, 568 gas cutting problems, 192–193 hydrocyclone arrangement, 267–269 suction and discharge pit, 102–103 Desilter American Petroleum Institute guidelines, 568 gas cutting problems, 192–193 historical perspective, 8 hydrocyclone arrangement, 268–269 suction and discharge pit, 103 Dewatering, waste treatment, 391–394 Dilution American Petroleum Institute method for calculation, 361–362 calculation examples, 362–366 cost analysis, 364 definition, 335 examples, 335–336 porosity effects, 337–338 rationale, 339–341 solids removal equipment efficiency, see Solids removal equipment efficiency volume increase factor calculation, 361 Dilution volume, calculation, 23–24 Direct current, alternating current comparison, 414 Disaggregation, definition, 5 Drilled solids associated problems, 2, 548 centrifugation, see Centrifuges characteristics overview, 25–26 physical properties, 26–31 checklist for management, see Solids management checklist commercial solids, 310 definition, 3 economic impact, 2–3 effects on drilling fluids, 311–313 history of management, 4–11 removal overview, 3–4, 20–25 654 Indexrationale, 339–341, 548–549 safety in handling of cuttings, 58 Drilled solids removal factor, calculation, 361–362 Drilling fluid circulating system, 22–23 dilution, see Dilution drilled solids removal overview, 3–4, 20–25 functions, 15–16 rheology, 32–38 selection considerations, 17, 20 stability and maintenance, 54 types and classification, 16–19 viscosity maintenance, 30 Drilling fluid products colloidal and fine solids, 54–55 conventional polymers, 56–57 hazard classification, 59–61 macropolymers, 55–56 safety in handling, 58 storage, 58 surface-active materials, 57–58 waste management and disposal, 62–65 Drilling waste, see Waste management Dryer shaker, principles, 153–154 DSRF, see Drilled solids removal factor E Einstein equation, particle effects on effective velocity, 30 EIR, see Environmental impact reduction Electromagnetic theory, 421–423 Environmental impact reduction, waste minimization, 377 F Fann Reading, calculation, 35–38 Flame propagation, definition, 448 Flashpoint, definition, 447 Flocculation, applications, 320 Flow rate centrifugal pump selection with standard drilling equipment, 491 friction losses, 472–479, 490–491 hydrocyclones, 260–261 shale shaker selection, 146–148 velocity calculation, 98 Fluid limit, shale shaker, 118–119 G Gas buster design, 196–197 mechanisms, 193, 195–196 Gas cutting bottom-hole pressure loss, 189–191 equipment effects centrifuge, 193 desander, 192–193 desilter, 192–193 shale shaker, 192 mud density adjustment, 191 mud handling equipment, see Degasser; Gas buster; Separators problems, 189 pump output reduction calculation, 194 separation guidelines, 209–210 Index 655g factor calculation, 136–139 definition, 136 relationship to stroke and speed of rotation, 140 shale shaker design considerations, 137–140 g force, calculation for centrifuges, 315–316 Gumbo conveyor, historical perspective, 11 definition, 31 emergency removal, 107 formation, 107 scalping shakers, 107–109 transport, 31 H Herschel-Bulkley model, 34 Hole cleaning decision algorithm, 39 drilling element effects carrying capacity, 42–44 cuttings characteristics, 44 drill string eccentricity, 45 flow rate/annular velocity, 40–41 hole angle, 50 overview, 40 pipe rotation, 45 rate of penetration, 44 rheology, 41–42 filtration, 45–47, 50 problem detection, 38 Hydrocyclones, see also Mud cleaners advantages and limitations, 279–281 arrangements desanders, 267–269 desilters, 268–269 capacity, 265–266 capture analysis, see Capture centrifugal forces, 257 components, 257–258 countercurrent spiraling streams, 260 cut points, 261, 270–276, 282, 283–284 Derrickman’s guidelines, 554–558 discharge rope discharge, 264–265 spray discharge, 261–264 feed header problems, 269 flow rates, 260–261 installation, 278–279 motors, 459 operating guidelines, 276–278 plugging, 558 pressure relationship with mud weight, 258–259, 555 principles, 257–259 siphon breaker, 261 sizing, 260, 281–282 tanks, 266 troubleshooting, 280, 557–558 underflow centrifugation, 321 Hydrogen, burns, 447 Hydrogen sulfide, control in underbalanced drilling, 540 I Ignitable mixture, definition, 447–448 Impeller axial flow impellers, 221 656 Indexcontour impellers, 222 design, 215–217, 466 diameter formulas, 507 displacement values, 229 head equation, 465, 467 power transmission, 215 prerotation of fluid in suction piping, 466 radial flow impellers, 217–220 rotational velocity determination, 467 turnover rate determination for sizing, 228–232 Inductance, definition, 415 Induction motors, see Motors Inductive reactance, calculation, 416 Ingress protection code, motor enclosures, 443–444, 446 IP, see Ingress protection code J Jet hopper, American Petroleum Institute guidelines, 570–571 K Kindling temperature, definition, 447 L Land disposal, drilling waste burial cells, 386 chemical content limits, 387 depth or placement, 387–388 leakage and leaching, 389–391 moisture content, 388–389 concerns, 374 land application, 382–386 Laser granulometry, particle size distribution measurement, 27 LCM, see Lost circulation material LGS, see Low-gravity solid Linear motion shale shaker, principles, 9–10, 128–132 Lost circulation material, mud treatment, 55 Low-gravity solid barite discarded by shale shaker, 75–76 measurement, 29, 70–77 mud cleaner low-gravity solids volume/barite volume ratio estimation in screen discard, 293–294 settling rate, 186–187 volume calculation, 69–70, 77–78 Lubricity drilling solids removal advantages, 52–53 rate of penetration effects, 51 M Magna-Vac degasser, 207 MBT, see Methylene blue test Mesh, counting, 160 Meter model, 34–35 Methylene blue, clay test, 21 Motors adjustable speed drive, see Adjustable speed drive alternating current induction motor advantages, 424, 429–430 ambient temperature effects on performance, 435–437 centrifuges, 459 Index 657Motors (continued) electromagnetic theory, 421–423 enclosures, 441–443 energy losses, 433–434 frame dimension nomenclature, 442 hazardous duty European Community regulations, 450, 453–454 explosion risks, 444–448 international nomenclature, 451–452 location designations, 449–451 horsepower calculation, 424 hydrocyclones, 459 induction motor performance characteristics, 423 ingress protection code, 443–444, 446 installation and troubleshooting, 438 ratings, 432–433 rotor, 423 rotor circuits, 424–425 shale shakers, 454–457, 459 standards, 439–441 stator, 423 stator circuits, 425, 427 temperature rise, 434–435 voltage imbalance, 435–436 Mud, see Drilling fluid Mud cleaners applications, 288–291 arrangement, 291–292 cut point curves, 284 Derrickman’s guidelines, 558–560 economics, 297–299 heavy drilling fluids, 301–302 historical perspective, 9, 283, 286–288 low-gravity solids volume/ barite volume ratio estimation in screen discard, 293–294 operation, 292–293 performance, 295–297 specific gravity accuracy requirements, 300–301 Mud ditch, American Petroleum Institute guidelines, 569–570 Mud guns American Petroleum Institute guidelines, 565–566 eductors, 234 high-pressure mud guns, 233 low-pressure mud guns, 233–234 placement, 234–235 pros and cons, 237–239 pump suction sites, 232–233 purpose, 213–214 sizing, 235–237, 254 Mud hoppers eductor, 246 guidelines for use, 248–250, 570–571 installation and operation, 246–248 low-pressure mud hoppers, 244–245 venturi utilization, 245 Mud premix systems, American Petroleum Institute guidelines, 571 Mud processing circle, 31 Mud pump, supercharging mud pumps, 510–512 658 IndexMud tank separator, 197–198 N Net positive suction head, calculation, 503–506 NPSH, see Net positive suction head O Offshore disposal, drilling waste collection and transport to shore, 380 commercial services, 380–382 concerns, 373–374 direct discharge, 378 injection, 378–380 Ohm’s law, 414 Opening size determination for screens, 160–161 screen performance correlation, 161 P Partially hydrolyzed polyacrylamide shale encapsulation, 56–57 shale shaker interactions, 118–119 Particle size capture analysis, 332 distribution measurement, 27 PHPA, see Partially hydrolyzed polyacrylamide Piping agitator tanks, 226 Bernoulli’s principle, 239 Derrickman’s guidelines for piping to mixing section, 561–562 friction losses, 472–479, 489–491 pressure and velocity relationship, 240–243 suction pipe configurations, 509–511 surface circulation system, 96, 98 Plastic viscosity, mud density relationship, 21–22 Possum belly, dumping, 188 Power definition, 414 power triangle, 420 three-phase power, 416–419 Power factor, definition, 420 Power Law model overview, 34 rotary viscometer data application, 36–37 yield point conversion, 43–44 Power mud, pumping, 102 Power supply current capacity by wire gauge, 142–143 motor current requirements by horsepower rating, 142–143 shale shakers, 140–143 Prehydration, clay, 250 Pressure head relationship, 258 mud weight relationship in hydrocyclones, 258–259, 555 velocity relationship in piping, 240–243 Pressure tank, functions, 250 PSD, see Particle size distribution P-tank, see Pressure tank Index 659Pumps casing concentric versus solute casings, 488–489 cutwater, 469–470 design, 468–469 functions, 467–468 gap size, 469 centrifugal pumps affinity laws, 506–507 American Petroleum Institute guidelines, 572–577 cavitation, 485–486 entrained air, 486–488 friction losses formulas, 507–508 piping, 472–479, 489–491 guidelines, 513–514 head pressure and flow, 479–480 net positive suction head calculation, 503–506 nomenclature, 471, 479 priming, 484–485 pump curve interpretation, 480–484 selection factors flow rate needed for specific equipment, 491 friction loss and elevation considerations, 491–503 sizing, 470, 491 speed formulas, 507 system head requirement worksheet, 506, 515–519 degassers, 207 gas cutting and output reduction, 194 hydraulic-driven submersible pumps, 405 impeller, see Impeller mud gun suction sites, 232–233 suction pipe configurations baffle plate, 509 duplicity, 513 parallel operation, 513 piping practices, 509–511 series operation, 512–513 submergence levels, 508–509 supercharging mud pumps, 510–512 PV, see Plastic viscosity Pycnometer, low-gravity solid measurement, 70–77 R Rate of penetration drilling fluid parameter effects density, 48–49 filtration, 50 lubricity, 51 overview, 47–48 rheological profile, 50 shale inhibition, 51 solids content, 49–50 hole cleaning effects, 44 Reactive power, definition, 420–421 Real power, definition, 420 Reserve tanks agitation, 254 functions, 105–106 Resistance properties, 413–414 temperature relationship, 460 RMS, see Rotary mud separator ROP, see Rate of penetration Rotor, motors, 423 660 IndexRotary mud separator, principles and uses, 321–322 S Sacks, lifting and handling systems, 251 Sand trap American Petroleum Institute guidelines, 566 applications, 187–188 Derrickman’s guidelines, 552–553 design, 100–102, 183 top equalization, 563 Scalping shakers, gumbo removal, 107–109 Screens, see Shale shaker; Wire cloth Separators atmospheric separators mud tanks, 197–198 West Texas separator, 198–199 mechanisms, 193, 195–196 pressurized separators closed separators, 200–202 combination separator and degasser, 202 flare systems, 199–200 separation guidelines, 209–210 Settling rate barite, 186–187 calculation, 184–186 forces affecting particles, 184–185 low-gravity solids, 186–187 Shaker, see also Shale shaker historical perspective, 6–7, 9 mesh size, 6–7, 9–10 Shale barge, waste handling, 404–405 Shale encapsulators high-molecular-weight polymers, 56–57 mixing guidelines, 56–57 types, 56 Shale inhibition definition, 51 rate of penetration effects, 51 wetting characteristics, 51–52 Shale inhibitors, mechanisms of action, 57–58 Shale shaker applications fiber-optic cables, 182 microtunneling, 181–182 river crossing, 182 road crossing, 182 bypassing, 188 cascade systems, see Cascade shale shaker configurations, 111 cut point curve, see Cut point definition, 111 Derrickman’s guidelines, 550–551 description, 116–117 design elements g factor, 136–140 overview, 122–123 power systems, 140–143 screen deck design, 134–136 shape of motion balanced elliptical motion, 132–133 circular motion, 127–128 classification, 123–124 linear motion, 9–10, 128–131 Index 661Shale shaker (continued) unbalanced elliptical motion, 124–127 vibrating systems, 133–134 dryer shaker, 153–154 flow rate, charts and factors affecting, 112 gas cutting problems, 192 historical perspective, 6, 10, 121–122 importance in drilling fluid system, 111–112 limits factors affecting density of fluid, 120 hole cleaning, 121 plastic viscosity, 119–120 solid quantity, 121 solid types, sizes, and shapes, 120–121 surface tension of fluids, 120 wire wettability, 120 fluid limit, 118–119 solids limit, 118–119 mechanisms, 113–115 motors, 454–457, 459 percentage separated curve generation, 174–176 screens, see also Wire cloth American Petroleum Institute designation system API number, 168–171 flow capacity, 171–173 identification tag contents, 173–174 manufacturer’s designation, 167 nonblanked area, 173 cloth weaves, 160–167 conductance, 167, 171–173 deck design, 134–136 desirable characteristics, 159–160 factors affecting performance blinding, 176–177 bonded screens, 180 hook-strip screens, 180 metal screens, 177 plastic screens, 178 pretensioned panels, 179–180 three-dimensional screen panels, 180–181 open area calculation, 162, 166–167 requirements, 178 selection, 112–113, 145 selection factors costs, 145–146 discharge dryness, 148 flow rate, 146–148 overview, 143–145 rig configuration, 148 screen selection, 112–113, 145 stroke, 463–464 users guidelines installation, 155–156 maintenance, 157–158 operating precautions, 158–159 operation, 156–157 vibrator speed, 463–464 Slip, calculation, 427 Slug tank, functions, 105 Solidification, waste treatment, 397–399 Solids limit, shale shaker, 118–119 662 IndexSolids management checklist drilling program, 579 economics, 581 environmental issues, 580–581 equipment capability, 579–580 logistics, 580 rig design and availability, 580 well parameters/deepwater considerations, 577–579 Solids removal equipment efficiency calculation formulas, 338–339, 341–342 unweighted drilling fluid, 354–357 weighted drilling fluid discard volume calculation, 360 excess drilling fluid generated, 360 overview, 357–358 volume of new drilling fluid built, 358–359 definition, 338 effects on drilling performance 70% efficiency, 347–348 80% efficiency, 346 90% efficiency, 344–346 100% efficiency, 343–344 overview, 341–343 minimum volume of drilling fluid to dilute drilled solids determination discarded solids, 350–351 equation derivation, 349–350 optimum solids-removal efficiency equation, 349 optimum value, 351–354 Specific gravity accuracy requirements for mud cleaners, 300–301 average specific gravity calculation, 77–78 capture analysis, 331–332 definition, 28 rig-site determination for drilled solids, 78–79 SREE, see Solids removal equipment efficiency Stabilization, see Solidification Stator, motors, 423 Stereopycnometer, density of weighting material measurement, 29 Stokes’ law, settling rate calculation, 184–186, 271–276, 307–308 Surface circulation system active system additions section, 95 centrifuge suction and discharge pits, 103–104 degasser suction and discharge pit, 102 desander suction and discharge pit, 102–103 desilter suction and discharge pit, 103 equalization, 98–99 piping and equipment arrangement, 96, 98 removal section, 95–96 sand traps, 100–102 suction and testing section, 94–95 surface tanks, 99 overview, 93, 253 reserve tanks, 105–106 Index 663Surface circulation system (continued) slug tank, 105 trip tank, 104–105 Surface systems, American Petroleum Institute guidelines, 562–572 Suspended solids, calculation, 70 System head requirement worksheet, 506, 515–519 T Tanks agitators, 226–227 American Petroleum Institute guidelines, 572 Derrickman’s guidelines, 549–550 hydrocyclones, 266 pressure tanks, 250 reserve tanks, 105–106, 255 slug tank, 105 trip tank, 104–105, 255, 572 TFM, see Total fluid management Thermal desorption, waste treatment, 395–397 Three-phase circuit features, 414–415 power, 416–419 TOR, see Turnover rate Total fluid management, waste minimization, 375–377 Transformers constant-potential transformers, 428 counter-electromotive force, 428 functions, 427–428 ideal properties, 428 stepdown versus stepup transformers, 428 turn ratio, 428 Trip tank, functions, 104–105, 255 Triplex mud pumps, features, 510–512 Turnover rate American Petroleum Institute guidelines, 565 determination for agitator impeller sizing, 228–232 Turn ratio, transformers, 428 U UBD, see Underbalanced drilling Unbalanced elliptical motion shale shaker, principles, 124–127 Underbalanced drilling definition, 521 solids control air/gas drilling recycling versus flaming, 523–524 environmental contamination, 524–525 natural gas, 525–526 sample collection, 526–527 mist systems, 527–528 conventional or weighted drilling fluids, 536–537 fluid types, 523 foam drilling disposable foam systems, 529–530 recyclable foam systems, 530–532 sample collection, 532 liquid/gas systems oil systems, 535 664 Indexoverview, 532–534 sample collection, 535–536 overview, 522–523 pressurized closed separator system, 538–539 problems corrosion control, 542 downhole fires and explosions, 540–541 excess formation water, 540 fluid surges, 541 foam control, 542 hydrogen sulfide, 540 shale, 539–540 small cuttings, 541 waste management, 537–538 V Vacuum transfer sysems, 402–403 VIF, see Volume increase factor Viscoelasticity definition, 32 types, 32 Viscosity drilling fluid maintenance, 30 equation, 33 measurement, 36–37 shear rate relationship, 32–33 Voltage, properties, 413 Volume increase factor, calculation, 361 W Waste management contents of drilling waste, 372–373 drilling fluid products, 62–65 drilling waste contaminants, 383–385 equipment augers, 400–402 cuttings boxes, 403–404 cuttings dryers installation, 411–412 legislation, 408–409 oil retention, 406–409 operation, 411 removed fluid processing, 410–411 volume reduction, 406 hydraulic-driven submersible pumps, 405 pneumatic system, 405–406 shale barge, 404–405 vacuums, 402–403 land disposal burial cells, 386 chemical content limits, 387 depth or placement, 387–388 leakage and leaching, 389–391 moisture content, 388–389 concerns, 374 land application, 382–386 minimization of drilling waste environmental impact reduction, 377 total fluid management, 375–377 offshore disposal collection and transport to shore, 380 commercial services, 380–382 concerns, 373–374 direct discharge, 378 injection, 378–380 Index 665Waste management (continued) quantification of drilling waste, 367–372 treatment dewatering, 391–394 solidification, 397–399 thermal desorption, 395–397 underbalanced drilling waste, 537–538 Water dewatering for waste treatment, 391–394 vapor pressure, 504–505 Weighting agents, discard costs, 12 West Texas separator, 198–199 Wire copper wire size required to limit line voltage drop, 142–143 current capacity by wire gauge, 142–143 Wire cloth conductance, 167, 171–173 market grade and tensile bolting cloth shaker screen characteristics, 166 mesh counting, 160 opening size determination, 160–161 sieve designations of National Bureau of Standards, 162–165 Work, definition, 414 Wye connection, three-phase power, 417–418 Y Yield point, conversion between models, 43–44
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