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 () 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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