كتاب Drilling Fluids Processing Handbook
منتدى هندسة الإنتاج والتصميم الميكانيكى
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منتدى هندسة الإنتاج والتصميم الميكانيكى
بسم الله الرحمن الرحيم

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نتمنى أن تقضوا معنا أفضل الأوقات
وتسعدونا بالأراء والمساهمات
إذا كنت أحد أعضائنا يرجى تسجيل الدخول
أو وإذا كانت هذة زيارتك الأولى للمنتدى فنتشرف بإنضمامك لأسرتنا
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وشرح لطريقة التنزيل من المنتدى بالفيديو:
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 كتاب Drilling Fluids Processing Handbook

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عدد المساهمات : 17034
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تاريخ التسجيل : 01/07/2009
الدولة : مصر
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Drilling Fluids Processing Handbook
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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
666 Index


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