List of Figures

Figure 1.1 A sketch of a simple petroleum production system 4
Figure 1.2 A sketch of a typical flowing oil well 5
Figure 1.3 A sketch of a wellhead 5
Figure 1.4 A sketch of a casing head 6
Figure 1.5 A sketch of a tubing head 7
Figure 1.6 A sketch of a “Christmas tree” 7
Figure 1.7 A sketch of a surface valve 8
Figure 1.8 A sketch of a wellhead choke 8
Figure 1.9 Uses of offshore flowlines and pipelines 10
Figure 1.10 Safety device symbols 12
Figure 1.11 Safety system designs for surface wellhead flowlines 13
Figure 1.12 Safety system designs for underwater wellhead flowlines 15
Figure 1.13 Safety system design for pressure vessel 15
Figure 1.14 Safety system design for pipeline pumps 16
Figure 1.15 Safety system design for other pumps 16
Figure 3.1 A sketch of a radial flow reservoir model: (A) lateral view, (B) top view 38
Figure 3.2 A sketch of a reservoir with a constant-pressure boundary 39
Figure 3.3 A sketch of a reservoir with no-flow boundaries 40
Figure 3.4 (A): Shape factors for closed drainage areas with low-aspect ratios. (B): Shape factors for closed drainage areas with high-aspect ratios 41
Figure 3.5 Relationship between fracture conductivity and equivalent skin factor 44
Figure 3.6 A reservoir section drained by a multifractured horizontal wellbore 47
Figure 3.7 Fluid low in a fracture to a horizontal wellbore 47
Figure 3.8 Schematic of a typical root well 50
Figure 3.9 Schematic of a reservoir section drained by a fishbone well 51
Figure 3.10 A typical IPR curve for an oil well 54
Figure 3.11 Transient IPR curve for Example Problem 3.2 56
Figure 3.12 Steady-state IPR curve for Example Problem 3.2 56
Figure 3.13 Pseudo-steady-state IPR curve for Example Problem 3.2 57
Figure 3.14 IPR curve for Example Problem 3.3 60
Figure 3.15 Generalized Vogel IPR model for partial two-phase reservoirs 60
Figure 3.16 IPR curve for Example Problem 3.4 62
Figure 3.17 IPR curves for Example Problem 3.5, Well A 64
Figure 3.18 IPR curves for Example Problem 3.5, Well B 65
Figure 3.19 IPR curves for Example Problem 3.6 67
Figure 3.20 IPR curves of individual layers in Example Problem 3.7 71
Figure 3.21 Composite IPR curve for all the layers open to flow in Example Problem 3.7 72
Figure 3.22 Composite IPR curve for Group 2 (Layers B4, C1, and C2) in Example Problem 3.7 72
Figure 3.23 Composite IPR curve for Group 3 (Layers B1, A4, and A5) in Example Problem 3.7 73
Figure 3.24 IPR curves for Example Problem 3.8 75
Figure 3.25 IPR curves for Example Problem 3.9 78
Figure 4.1 Flow along a tubing string 84
Figure 4.2 Darcy—Wiesbach friction factor diagram 86
Figure 4.3 Calculated tubing pressure profile for the Example Problem 4.2 91
Figure 4.4 Flow regimes in gas-liquid flow 96
Figure 4.5 Pressure traverse given by Hagedorn Brown Correltion.xls for Example Problem 4.6 106
Figure 5.1 A typical choke performance curve 112
Figure 5.2 Choke flow coefficient for nozzle-type chokes 113
Figure 5.3 Choke flow coefficient for orifice-type chokes 114
Figure 6.1 Nodes in an oil and gas production system 130
Figure 6.2 Nodal analysis for the Example Problem 6.1 134
Figure 6.3 Nodal analysis for Example Problem 6.4 140
Figure 6.4 Nodal analysis for Example Problem 6.6 145
Figure 6.5 Nodal analysis for Example Problem 6.8 148
Figure 6.6 Nodal analysis for Example Problem 6.9 152
Figure 6.7 Nodal analysis for Example Problem 6.10 153
Figure 6.8 Nodal analysis for Example Problem 6.11 156
Figure 6.9 Nodal analysis for Example Problem 6.12 158
Figure 6.10 Nodal analysis for Example Problem 6.13 160
Figure 6.11 A simplified well structure for root type multilateral wells 162
Figure 6.12 Symbols used to describe a root type multilateral well 162
Figure 7.1 Nodal analysis plot for Example Problem 7.1 181
Figure 7.2 Production forecast for Example Problem 7.1 181
Figure 7.3 Nodal analysis plot for Example Problem 7.2 184
Figure 7.4 Production forecast for Example Problem 7.2 185
Figure 7.5 Production forecast for Example Problem 7.3 189
Figure 7.6 Result of production forecast for Example Problem 7.4 192
Figure 7.7 Completion models of a multi-stage fractured horizontal oil well in the Upper Eagle Ford: (A) one fracture created from each cluster of perforations, and (B) three fractures/branches created from each cluster of perforations 193
Figure 7.8 Production forecast by reservoir simulation for a multi-stage fractured horizontal well in a shale oil reservoir 193
Figure 8.1 A semi-log plot of q versus t indicating an exponential decline 204
Figure 8.2 A plot of Np versus q indicating an exponential decline 205
Figure 8.3 A plot of log(q) versus log(t) indicating a harmonic decline 205
Figure 8.4 A plot of Np versus log(q) indicating a harmonic decline 206
Figure 8.5 A plot of relative decline rate versus production rate 206
Figure 8.6 Procedure for determining a- and b-values 207
Figure 8.7 A plot of log(q) versus t showing an exponential decline 208
Figure 8.8 Relative decline rate plot showing exponential decline 209
Figure 8.9 Projected production rate by an exponential decline model 209
Figure 8.10 Relative decline rate plot showing harmonic decline 210
Figure 8.11 Projected production rate by a harmonic decline model 211
Figure 8.12 Relative decline rate plot showing hyperbolic decline 212
Figure 8.13 Relative decline rate shot showing hyperbolic decline 212
Figure 8.14 Projected production rate by a hyperbolic decline model 213
Figure 9.1 Wellhead-tubing-packer relation 220
Figure 9.2 Effect of tension stress on tangential stress 223
Figure 9.3 Tubing–packer relation 228
Figure 9.4 (A) Ballooning and (B) buckling effects 229
Figure 9.5 Teeth on mechanical packers 233
Figure 9.6 Schematic of a tension packer 234
Figure 9.7 A sketch of a compression packer 234
Figure 9.8 Wireline-set tubing retrievable packer. Left: set with plug in place; Right: set with tubing connected and plug retrieved 235
Figure 9.9 Tension/compression-set versatile landing 236
Figure 9.10 Sketch of a hydraulic-set single-string packer 237
Figure 9.11 An oil-swellable packer is being run in a casing string 238
Figure 9.12 Typical packer-rating envelope 240
Figure 10.1 A typical vertical separator 245
Figure 10.2 A typical horizontal separator 246
Figure 10.3 A typical horizontal double-tube separator 246
Figure 10.4 A typical horizontal three-phase separator 247
Figure 10.5 A typical spherical low-pressure separator 248
Figure 10.6 Water content of natural gases 260
Figure 10.7 Flow diagram of a typical solid desiccant dehydration plant 262
Figure 10.8 Flow diagram of a typical glycol dehydrator 264
Figure 10.9 Gas capacity of vertical inlet scrubbers based on 0.7-specific gravity at 100°F 267
Figure 10.10 Gas capacity for trayed glycol contactors based on 0.7-specific gravity at 100°F 269
Figure 10.11 Gas capacity for packed glycol contactors based on 0.7-specific gravity at 100°F 270
Figure 10.12 The required minimum height of packing of a packed contactor, or the minimum number of trays of a trayed contactor 271
Figure 11.1 Double-action stroke in a duplex pump 276
Figure 11.2 Single-action stroke in a triplex pump 276
Figure 11.3 Elements of a typical reciprocating compressor 281
Figure 11.4 Cross-section of a centrifugal compressor 282
Figure 11.5 Basic pressure–volume diagram 283
Figure 11.6 Flow diagram of a two-stage compression unit 288
Figure 11.7 Fuel consumption of prime movers using three types of fuel 290
Figure 11.8 Fuel consumption of prime movers using natural gas as fuel 291
Figure 11.9 Effect of elevation on prime mover power 291
Figure 11.10 Darcy-Wiesbach friction factor chart 299
Figure 11.11 Stresses generated by internal pressure p in a thin-wall pipe, D/t>20 310
Figure 11.12 Stresses generated by internal pressure p in a thick-wall pipe, D/t<20 310
Figure 11.13 Calculated temperature profiles with a polyethylene layer of 0.0254 M (1 in.) 319
Figure 11.14 Calculated steady-flow temperature profiles with polyethylene layers of various thicknesses 320
Figure 11.15 Calculated temperature profiles with a polypropylene layer of 0.0254 M (1 in.) 321
Figure 11.16 Calculated steady-flow temperature profiles with polypropylene layers of various thicknesses 321
Figure 11.17 Calculated temperature profiles with a polyurethane layer of 0.0254 M (1 in.) 322
Figure 11.18 Calculated steady-flow temperature profiles with polyurethane layers of four thicknesses 322
Figure 12.1 Temperature and spinner flowmeter-derived production profile 330
Figure 12.2 Notations for a horizontal wellbore 332
Figure 12.3 Measured bottom-hole pressures and oil production rates during a pressure drawdown test 336
Figure 12.4 Log-log diagnostic plot of test data 337
Figure 12.5 Semi-log plot for vertical radial flow analysis 337
Figure 12.6 Square-root time plot for pseudo-linear flow analysis 338
Figure 12.7 Semi-log plot for horizontal pseudo-radial flow analysis 338
Figure 12.8 Match between measured and model calculated pressure data 339
Figure 12.9 Gas production due to channeling behind the casing 340
Figure 12.10 Gas production due to preferential flow through high-permeability zones 340
Figure 12.11 Gas production due to gas coning 341
Figure 12.12 Temperature and noise logs identifying gas channeling behind casing 341
Figure 12.13 Temperature and fluid density logs identifying a gas entry zone 342
Figure 12.14 Water production due to channeling behind the casing 342
Figure 12.15 Preferential water flow through high-permeability zones 343
Figure 12.16 Water production due to water coning 343
Figure 12.17 Prefracture and postfracture temperature logs identifying fracture height 344
Figure 12.18 Spinner flowmeter log identifying a watered zone at bottom 345
Figure 12.19 Calculated minimum flow rates with the Turner et al. model and test flow rates 346
Figure 12.20 The minimum flow rates given by the Guo et al. model and the test flow rates 352
Figure 12.21 Schematic of formation damage due to fines migration 353
Figure 12.22 Region of formation damage around a wellbore 360
Figure 12.23 Region of formation damage around a hydraulic fracture 360
Figure 13.1 Typical acid response curves 372
Figure 13.2 Wormholes created by acid dissolution of limestone 377
Figure 13.3 PVbt curves 378
Figure 13.4 Conductivity of Acid fractures 382
Figure 13.5 Example of pre- and post-treatment PLT data 385
Figure 14.1 Illustration of the hydraulic fracturing process 390
Figure 14.2 Rock deformation under uniaxial loading 391
Figure 14.3 Three fracture modes 393
Figure 14.4 General state of stress in 3D space 395
Figure 14.5 Concept of effective stress applied to rock grains 397
Figure 14.6 Common fault regimes 398
Figure 14.7 Schematic view of various hydraulic fracture types 401
Figure 14.8 Schematic of fracturing fluid leakoff regions 403
Figure 14.9 The PKN fracture geometry 409
Figure 14.10 The KGD fracture geometry 412
Figure 14.11 Typical fracture geometry predicted by a lumped-parameter model 416
Figure 14.12 Fracture geometry predicted by two types of P3D models 417
Figure 14.13 Fracture height migration from a P3D fracture model 417
Figure 14.14 Stress variation vs distance away from a semi-infinite crack 420
Figure 14.15 Potential stress shadowing effects on fracture propagation in a stage with 3 perforation clusters from a horizontal well: (A) without stress shadowing and (B) with stress shadowing 420
Figure 14.16 Complex fracture network simulated by an unconventional fracture model 421
Figure 14.17 Nonplanar fracture geometry 422
Figure 14.18 Surface treating pressure responses from a typical fracturing treatment 429
Figure 14.19 Net pressure response based on the Nolte-Smith analysis 430
Figure 14.20 Illustration of fracture tortuosity and multiple fractures in the near-wellbore area 433
Figure 14.21 Schematic of a typical rate step-down test 434
Figure 14.22 Illustration of a typical step-rate test 435
Figure 14.23 A typical minifrac test 436
Figure 14.24 A sample plot of pressure vs square root of time 438
Figure 14.25 A sample plot of pressure vs time on log-log scale 439
Figure 14.26 A sample plot of pressure vs G-function time 440
Figure 14.27 A typical borate crosslinked gel sample 445
Figure 14.28 Apparent viscosity vs time at different shear rates for a typical borate crosslinked gel 448
Figure 14.29 Visual chart for evaluating the roundness and sphericity of particle grains 450
Figure 14.30 Effect of effective closure stress on proppant pack conductivity for various types of proppants 451
Figure 14.31 Photo of 20/40-mesh proppant samples 452
Figure 14.32 Schematic of equipment layout for a typical fracturing treatment 453
Figure 14.33 Photo of a typical high-pressure pump 454
Figure 14.34 Photo of a typical blender 455
Figure 14.35 Photo of a typical manifold trailer 456
Figure 14.36 Photo of a typical data van 457
Figure 14.37 Proppant silos 457
Figure 14.38 Photo of fracturing equipment layout at well site 458
Figure 14.39 Up close view of fracturing equipment layout at well site 458
Figure 14.40 Relationship between fracture conductivity and equivalent skin factor 461
Figure 14.41 An illustration of the propped and unpropped fractures 465
Figure 14.42 An illustration of stress calibration 467
Figure 14.43 An illustration of fracture growth in width and length and proppant placement 469
Figure 14.44 Iteration procedure to determine the pumping time 472
Figure 14.45 Calculated slurry concentration 474
Figure 14.46 An illustration of treatment cost, posttreatment production and NPV vs treatment size 479
Figure 14.47 Typical components of a frac-pack completion 481
Figure 14.48 A typical frac plug 484
Figure 14.49 Illustration of multistage completion using the plug and perf method 485
Figure 14.50 A typical frac sleeve system 486
Figure 14.51 Typical net pressure matching with a pseudo-3D fracture model 491
Figure 14.52 Four flow regimes that can occur in hydraulically fractured reservoirs 492
Figure 14.53 Earth deformation created from a hydraulic fracture 493
Figure 14.54 Illustration of microseisms induced during hydraulic fracturing 494
Figure 14.55 Effects of horizontal well spacing and orientation on reservoir drainage 494
Figure 15.1 Nomenclature of a tubing string in a horizontal well 506
Figure 15.2 Calculated tension profiles in the workover string for Example Problem 15.1 508
Figure 16.1 A diagrammatic drawing of a sucker rod pumping system 516
Figure 16.2 Sketch of three types of pumping units: (A) conventional unit; (B) Lufkin Mark II Unit; (C) air-balanced unit 517
Figure 16.3 The pumping cycle: (A) plunger moving down, near the bottom of the stroke; (B) plunger moving up, near the bottom of the stroke; (C) plunger moving up, near the top of the stroke; (D) plunger moving down, near the top of the stroke 518
Figure 16.4 Two types of plunger pumps. (A) Tubing pump and (B) Rod pump 519
Figure 16.5 Polished rod motion for (A) conventional pumping unit and (B) air-balanced unit 519
Figure 16.6 Definitions of conventional pumping unit API geometry dimensions 522
Figure 16.7 Approximate motion of connection point between pitman arm and walking beam 523
Figure 16.8 Sucker rod pumping unit selection chart 538
Figure 16.9 A sketch of pump dynagraph 542
Figure 16.10 Pump dynagraph cards: (A) ideal card; (B) gas compression on down-stroke; (C) gas expansion on upstroke; (D) fluid pound; (E) vibration due to fluid pound; (F) gas lock 543
Figure 16.11 Surface dynamometer card: (A) ideal card (stretch and contraction); (B) ideal card (acceleration); (C) three typical cards 545
Figure 16.12 Strain-gage–type dynamometer chart 546
Figure 16.13 Surface to down hole cards derived from surface dynamometer card 546
Figure 17.1 Configuration of a typical gas lift well 550
Figure 17.2 A simplified flow diagram of a closed rotary gas lift system for single intermittent well 551
Figure 17.3 A sketch of continuous gas lift 553
Figure 17.4 Pressure relationship in a continuous gas lift 553
Figure 17.5 System analysis plot given by GasLiftPotential.xls for the unlimited gas injection case 556
Figure 17.6 System analysis plot given by GasLiftPotential.xls for the limited gas injection case 557
Figure 17.7 Well unloading sequence. (A) initial condition, (B) gas enters the first valve, (C) gas enters the second valve, (D) gas enters the last valve, and (E) unloaded condition 575
Figure 17.8 Flow characteristics of orifice-type valves 576
Figure 17.9 Unbalanced bellow valve at its closed condition 577
Figure 17.10 Unbalanced bellow valve at its open condition 578
Figure 17.11 Flow characteristics of unbalanced valves 578
Figure 17.12 A sketch of a balanced pressure valve 579
Figure 17.13 A sketch of a pilot valve 580
Figure 17.14 A sketch of a throttling pressure valve 580
Figure 17.15 A sketch of a fluid-operated valve 581
Figure 17.16 A sketch of a differential valve 582
Figure 17.17 A sketch of combination valve 583
Figure 17.18 A flow diagram to illustrate procedure of valve spacing 584
Figure 17.19 Illustrative plot of BHP of an intermittent flow 592
Figure 17.20 Intermittent flow gradient at midpoint of tubing 592
Figure 17.21 Example Problem 17.8 schematic and BHP buildup for slug flow 594
Figure 17.22 Three types of gas lift installations. (A) open installation, (B) semi-closed installation, and (C) closed installation 595
Figure 17.23 Sketch of a standard two-packer chamber. (A) full system sketch, and (B) sketch of standing valve 596
Figure 17.24 A sketch of an insert chamber 597
Figure 17.25 A sketch of a reserve flow chamber 597
Figure 18.1 A sketch of an ESP installation 604
Figure 18.2 An internal schematic of centrifugal pump 605
Figure 18.3 A sketch of a multistage centrifugal pump 605
Figure 18.4 A typical characteristic chart for a 100-stage ESP 607
Figure 18.5 A sketch of a hydraulic piston pump 611
Figure 18.6 Sketch of a PCP system 616
Figure 18.7 Rotor and stator geometry of PCP 617
Figure 18.8 Four flow regimes commonly encountered in gas wells 620
Figure 18.9 A sketch of a plunger lift system 622
Figure 18.10 Sketch of a hydraulic jet pump installation 630
Figure 18.11 Working principle of a hydraulic jet pump 631
Figure 18.12 Example jet pump performance chart 632
Figure 19.1 Schematic of a typical subsea pipeline system 640
Figure 19.2 Typical flooding, cleaning, and gauging pig train 641
Figure 19.3 Typical dewatering pig train 644
Figure 19.4 Typical vacuum drying pressure plot 645
Figure 20.1 Hydrate forming conditions of natural gases 650
Figure 20.2 Water content of natural gases 653
Figure 20.3 Gas hydrate curve with different amount of methanol inhibition 655
Figure 20.4 Methanol in gas phase as a function of methanol in liquid phase 657
Figure 21.1 Pressure dependence of asphaltene solubility in crude oil 673
Figure 21.2 Laser power as a function of pressure 675
Figure 21.3 Schematic diagram of refractometer 676
Figure 21.4 Relationship between solubility parameter and RI (K=RI21RI2+2image) for n-alkanes and aromatics 677
Figure 21.5 Live oil RI changes as a function of pressure 678
Figure 21.6 de Boer crude oil supersaturation plot 679
Figure 21.7 Schematic of the corrosion process 686
Figure 21.8 Schematic of classical severe slugging formation process. (A) Liquid fall back, (B) liquid slug accumulation and production, (C) gas enters the riser, and (D) gas blowdown. 691
Figure 21.9 Pipeline inlet pressure as a function of time for severe slugging flow 692
Figure 21.10 Pipeline outlet pressure as a function of time for severe slugging flow 693
Figure 21.11 Outlet gas mass flowrate as a function of time for severe slugging flow 693
Figure 21.12 Upwards and downwards inclined pipeline profiles 694
Figure 21.13 Required total gas flow for stable flow in flowline for different water cut 695
Figure 22.1 Pipeline deposits that could obstruct or retard flow through a pipeline 702
Figure 22.2 Some spheres used in the pipeline pigging operations 703
Figure 22.3 (A) A foam pig (B) An ideal foam big cleaning the pipeline 704
Figure 22.4 Some mandrel pigs used in pipeline pigging operations 705
Figure 22.5 Some solid cast pigs used in pipeline pigging operations 705
Figure 22.6 An ultrasonic inspection tool 706
Figure 22.7 Application of gel pigs in pipeline pigging operations 707
Figure 22.8 A typical configuration of pig launcher for liquid services 708
Figure 22.9 A typical configuration of pig receiver for liquid services 708
Figure 22.10 A typical configuration of pig launcher for gas services 709
Figure 22.11 A typical configuration of pig receiver for gas services 709
Figure 22.12 Some mandrel pigs used in pipeline pigging operations 711
Figure 22.13 Some bi-directional pigs used in pipeline pigging operations 712
Figure 22.14 Pig with multilipped conical cups 713
Figure 22.15 A special pig for spraying corrosion inhibitor 714
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