List of Figures

Figure 1.1: A sketch of a petroleum productionsystem.

Figure 1.2: A typical hydrocarbon phase diagram.Figure 1.3: A sketch of a water-drive reservoir.Figure 1.4: A sketch of a gas-cap drive reservoir.Figure 1.5: A sketch of a dissolved-gas drive reservoir.Figure 1.6: A sketch of a typical flowing oil well.Figure 1.7: A sketch of a wellhead.Figure 1.8: A sketch of a casing head.Figure 1.9: A sketch of a tubing head.

Figure 1.10: A sketch of a Christmas tree.Figure 1.11: Sketch of a surface valve.Figure 1.12: A sketch of a wellhead choke.Figure 1.13: Conventional horizontal separator.Figure 1.14: Double action piston pump.Figure 1.15: Elements of a typical reciprocating

compressor.Figure 1.16: Uses of offshore pipelines.Figure 1.17: Safety device symbols.Figure 1.18: Safety system designs for surface wellhead

flowlines.Figure 1.19: Safety system designs for underwater

wellhead flowlines.Figure 1.20: Safety system design for pressure vessel.Figure 1.21: Safety system design for pipeline pumps.Figure 1.22: Safety system design for other pumps.Figure 3.1: A sketch of a radial flow reservoir model:

(a) lateral view, (b) top view.Figure 3.2: A sketch of a reservoir with a constant-

pressure boundary.Figure 3.3: A sketch of a reservoir with no-flow

boundaries.Figure 3.4: (a) Shape factors for various closed

drainage areas with low-aspect ratios.(b) Shape factors for closed drainage areaswith high-aspect ratios.

Figure 3.5: A typical IPR curve for an oil well.Figure 3.6: Transient IPR curve for Example Problem

3.1.Figure 3.7: Steady-state IPR curve for Example

Problem 3.1.Figure 3.8: Pseudosteady-state IPR curve for

Example Problem 3.1.Figure 3.9: IPR curve for Example Problem 3.2.

Figure 3.10: Generalized Vogel IPR model for partialtwo-phase reservoirs.

Figure 3.11: IPR curve for Example Problem 3.3.Figure 3.12: IPR curves for Example Problem 3.4,

Well A.Figure 3.13: IPR curves for Example Problem 3.4,

Well BFigure 3.14: IPR curves for Example Problem 3.5.Figure 3.15: IPR curves of individual layers.Figure 3.16: Composite IPR curve for all the layers

open to flow.Figure 3.17: Composite IPR curve for Group 2 (Layers

B4, C1, and C2).Figure 3.18: Composite IPR curve for Group 3 (Layers

B1, A4, and A5).Figure 3.19: IPR curves for Example Problem 3.6.Figure 3.20: IPR curves for Example Problem 3.7.Figure 4.1: Flow along a tubing string.Figure 4.2: DarcyWiesbach friction factor diagram.Figure 4.3: Flow regimes in gas-liquid flow.

Figure 4.4: Pressure traverse given by HagedornBrownCorreltion.xls for Example.

Figure 4.5: Calculated tubing pressure profile forExample Problem 4.5.

Figure 5.1: A typical choke performance curve.Figure 5.2: Choke flow coefficient for nozzle-type

chokes.Figure 5.3: Choke flow coefficient for orifice-type

chokes.Figure 6.1: Nodal analysis for Example Problem 6.1.Figure 6.2: Nodal analysis for Example Problem 6.4.Figure 6.3: Nodal analysis for Example Problem 6.5.Figure 6.4: Nodal analysis for Example Problem 6.6.Figure 6.5: Nodal analysis for Example Problem 6.8.Figure 6.6: Schematic of a multilateral well trajectory.Figure 6.7: Nomenclature of a multilateral well.Figure 7.1: Nodal analysis plot for Example Problem

7.1.Figure 7.2: Production forecast for Example Problem

7.2.Figure 7.3: Nodal analysis plot for Example Problem

7.2.Figure 7.4: Production forecast for Example Problem

7.2Figure 7.3: Production forecast for Example Problem

7.3.Figure 7.4: Result of production forecast for Example

Problem 7.4.Figure 8.1: A semilog plot of q versus t indicating an

exponential decline.Figure 8.2: A plot of Np versus q indicating an

exponential decline.Figure 8.3: A plot of log(q) versus log(t) indicating a

harmonic decline.Figure 8.4: A plot of Np versus log(q) indicating a

harmonic decline.Figure 8.5: A plot of relative decline rate versus

production rate.Figure 8.6: Procedure for determining a- and b-values.Figure 8.7: A plot of log(q) versus t showing an

exponential decline.Figure 8.8: Relative decline rate plot showing

exponential decline.Figure 8.9: Projected production rate by an

exponential decline model.Figure 8.10: Relative decline rate plot showing

harmonic decline.Figure 8.11: Projected production rate by a harmonic

decline model.Figure 8.12: Relative decline rate plot showing

hyperbolic decline.Figure 8.13: Relative decline rate plot showing

hyperbolic decline.Figure 8.14: Projected production rate by a hyperbolic

decline model.Figure 9.1: A simple uniaxial test of a metal specimen.Figure 9.2: Effect of tension stress on tangential stress.Figure 9.3: Tubingpacker relation.Figure 9.4: Ballooning and buckling effects.

Figure 10.1: A typical vertical separator.Figure 10.2: A typical horizontal separator.Figure 10.3: A typical horizontal double-tube

separator.Figure 10.4: A typical horizontal three-phase

separator.

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Figure 10.5: A typical spherical low-pressureseparator.

Figure 10.6: Water content of natural gases.Figure 10.7: Flow diagram of a typical solid desiccant

dehydration plant.Figure 10.8: Flow diagram of a typical glycol

dehydrator.Figure 10.9: Gas capacity of vertical inlet scrubbers

based on 0.7-specific gravity at 100 8F.Figure 10.10: Gas capacity for trayed glycol contactors

based on 0.7-specific gravity at 100 8F.Figure 10.11: Gas capacity for packed glycol

contactors based on 0.7-specific gravityat 100 8F.

Figure 10.12: The required minimum height of packingof a packed contactor, or the minimumnumber of trays of a trayed contactor.

Figure 11.1: Double-action stroke in a duplex pump.Figure 11.2: Single-action stroke in a triplex pump.Figure 11.3: Elements of a typical reciprocating

compressor.Figure 11.4: Cross-section of a centrifugal

compressor.Figure 11.5: Basic pressurevolume diagram.Figure 11.6: Flow diagram of a two-stage

compression unit.Figure 11.7: Fuel consumption of prime movers using

three types of fuel.Figure 11.8: Fuel consumption of prime movers using

natural gas as fuel.Figure 11.9: Effect of elevation on prime mover

power.Figure 11.10: DarcyWiesbach friction factor chart.Figure 11.11: Stresses generated by internal pressure p

in a thin-wall pipe, D=t > 20.Figure 11.12: Stresses generated by internal pressure p

in a thick-wall pipe, D=t < 20.Figure 11.13: Calculated temperature profiles with a

polyethylene layer of 0.0254 M (1 in.).Figure 11.14: Calculated steady-flow temperature

profiles with polyethylene layers ofvarious thicknesses.

Figure 11.15: Calculated temperature profiles with apolypropylene layer of 0.0254 M (1 in.).

Figure 11.16: Calculated steady-flow temperatureprofiles with polypropylene layers ofvarious thicknesses.

Figure 11.17: Calculated temperature profiles with apolyurethane layer of 0.0254 M (1 in.).

Figure 11.18: Calculated steady-flow temperatureprofiles with polyurethane layers of fourthicknesses.

Figure 12.1: A diagrammatic drawing of a sucker rodpumping system.

Figure 12.2: Sketch of three types of pumping units:(a) conventional unit; (b) Lufkin Mark IIunit; (c) air-balanced unit.

Figure 12.3: The pumping cycle: (a) plunger movingdown, near the bottom of the stroke;(b) plunger moving up, near the bottomof the stroke; (c) plunger moving up,near the top of the stroke; (d) plungermoving down, near the top of the stroke.

Figure 12.4: Two types of plunger pumps.Figure 12.5: Polished rod motion for (a) conventional

pumping unit and (b) air-balanced unit.Figure 12.6: Definitions of conventional pumping

unit API geometry dimensions.Figure 12.7: Approximate motion of connection point

between pitman arm and walking beam.Figure 12.8: Sucker rod pumping unit selection chart.Figure 12.9: A sketch of pump dynagraph.

Figure 12.10: Pump dynagraph cards: (a) ideal card,(b) gas compression on down-stroke,(c) gas expansion on upstroke, (d) fluidpound, (e) vibration due to fluid pound,(f) gas lock.

Figure 12.11: Surface Dynamometer Card: (a) idealcard (stretch and contraction), (b) idealcard (acceleration), (c) three typicalcards.

Figure 12.12: Strain-gagetype dynamometer chart.Figure 12.13: Surface to down hole cards derived from

surface dynamometer card.Figure 13.1: Configuration of a typical gas lift well.Figure 13.2: A simplified flow diagram of a closed

rotary gas lift system for singleintermittent well.

Figure 13.3: A sketch of continuous gas lift.Figure 13.4: Pressure relationship in a continuous gas

lift.Figure 13.5: System analysis plot given by GasLift

Potential.xls for the unlimited gasinjection case.

Figure 13.6: System analysis plot given by GasLiftPotential.xls for the limited gas injectioncase.

Figure 13.7: Well unloading sequence.Figure 13.8: Flow characteristics of orifice-type

valves.Figure 13.9: Unbalanced bellow valve at its closed

condition.Figure 13.10: Unbalanced bellow valve at its open

condition.Figure 13.11: Flow characteristics of unbalanced valves.Figure 13.12: A sketch of a balanced pressure valve.Figure 13.13: A sketch of a pilot valve.Figure 13.14: A sketch of a throttling pressure valve.Figure 13.15: A sketch of a fluid-operated valve.Figure 13.16: A sketch of a differential valve.Figure 13.17: A sketch of combination valve.Figure 13.18: A flow diagram to illustrate procedure of

valve spacing.Figure 13.19: Illustrative plot of BHP of an

intermittent flow.Figure 13.20: Intermittent flow gradient at mid-point

of tubing.Figure 13.21: Example Problem 13.8 schematic and

BHP build.up for slug flow.Figure 13.22: Three types of gas lift installations.Figure 13.23: Sketch of a standard two-packer

chamber.Figure 13.24: A sketch of an insert chamber.Figure 13.25: A sketch of a reserve flow chamber.Figure 14.1: A sketch of an ESP installation.Figure 14.2: An internal schematic of centrifugal

pump.Figure 14.3: A sketch of a multistage centrifugal

pump.Figure 14.4: A typical ESP characteristic chart.Figure 14.5: A sketch of a hydraulic piston pump.Figure 14.6: Sketch of a PCP system.Figure 14.7: Rotor and stator geometry of PCP.Figure 14.8: Four flow regimes commonly

encountered in gas wells.Figure 14.9: A sketch of a plunger lift system.

Figure 14.10: Sketch of a hydraulic jet pumpinstallation.

Figure 14.11: Working principle of a hydraulic jetpump.

Figure 14.12: Example jet pump performance chart.Figure 15.1: Temperature and spinner flowmeter-

derived production profile.Figure 15.2: Notations for a horizontal wellbore.

xviii LIST OF FIGURES

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Figure 15.3: Measured bottom-hole pressures andoil production rates during a pressuredrawdown test.

Figure 15.4: Log-log diagnostic plot of test data.Figure 15.5: Semi-log plot for vertical radial flow

analysis.Figure 15.6: Square-root time plot for pseudo-linear

flow analysis.Figure 15.7: Semi-log plot for horizontal pseudo-

radial flow analysis.Figure 15.8: Match between measured and model

calculated pressure data.Figure 15.9: Gas production due to channeling behind

the casing.Figure 15.10: Gas production due to preferential flow

through high-permeability zones.Figure 15.11: Gas production due to gas coning.Figure 15.12: Temperature and noise logs identifying

gas channeling behind casing.Figure 15.13: Temperature and fluid density logs

identifying a gas entry zone.Figure 15.14: Water production due to channeling

behind the casing.Figure 15.15: Preferential water flow through high-

permeability zones.Figure 15.16: Water production due to water coning.Figure 15.17: Prefracture and postfracture temperature

logs identifying fracture height.Figure 15.18: Spinner flowmeter log identifying a

watered zone at bottom.Figure 15.19: Calculated minimum flow rates with

Turner et al.s model and test flow rates.Figure 15.20: The minimum flow rates given by Guo

et al.s model and the test flow rates.Figure 16.1: Typical acid response curves.Figure 16.2: Wormholes created by acid dissolution of

limestone.Figure 17.1: Schematic to show the equipment layout

in hydraulic fracturing treatments of oiland gas wells.

Figure 17.2: A schematic to show the procedure ofhydraulic fracturing treatments of oiland gas wells.

Figure 17.3: Overburden formation of a hydrocarbonreservoir.

Figure 17.4: Concept of effective stress betweengrains.

Figure 17.5: The KGD fracture geometry.Figure 17.6: The PKN fracture geometry.Figure 17.7: Relationship between fracture

conductivity and equivalent skin factor.Figure 17.8: Relationship between fracture

conductivity and equivalent skin factor.Figure 17.9: Effect of fracture closure stress on

proppant pack permeability.Figure 17.10: Iteration procedure for injection time

calculation.Figure 17.11: Calculated slurry concentration.Figure 17.12: Bottom-hole pressure match with three-

dimensional fracturing modelPropFRAC.

Figure 17.13: Four flow regimes that can occur inhydraulically fractured reservoirs.

Figure 18.1: Comparison of oil well inflowperformance relationship (IPR) curvesbefore and after stimulation.

Figure 18.2: A typical tubing performance curve.Figure 18.3: A typical gas lift performance curve of a

low-productivity well.Figure 18.4: Theoretical load cycle for elastic sucker

rods.Figure 18.5: Actual load cycle of a normal sucker rod.Figure 18.6: Dimensional parameters of a

dynamometer card.Figure 18.7: A dynamometer card indicating

synchronous pumping speeds.Figure 18.8: A dynamometer card indicating gas lock.Figure 18.9: Sketch of (a) series pipeline and

(b) parallel pipeline.Figure 18.10: Sketch of a looped pipeline.Figure 18.11: Effects of looped line and pipe diameter

ratio on the increase of gas flow rate.Figure 18.12: A typical gas lift performance curve of

a high-productivity well.Figure 18.13: Schematics of two hierarchical networks.Figure 18.14: An example of a nonhierarchical

network.

LIST OF FIGURES xix

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