Reservoir Engineering Handbook

reser-CLASSIFICATION OF RESERVOIRS AND RESERVOIR FLUIDS Petroleum reservoirs are broadly classified as oil or gas reservoirs.These broad classifications are further subdivided depending

References 1159

APPENDIX 1165 INDEX 1177

Second Edition

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Ahmed, Tared H., Reservoir engineering handbook / Tarek Ahmed.

1946-p.cm.

Includes bibliographical references and index.

ISBN 0-88415-770-9 (alk paper)

1 Oil reservoir engineering 2 Oil fields 3 Gas reservoirs I Title.

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To my gorgeous wife Shanna, And my beautiful children

Jennifer Justin Brittany Carsen

FLUID BEHAVIOR 1

Classification of reservoirs and reservoir fluids 1

Pressure-temperature diagram 2

Oil reservoirs 4

Gas reservoirs 10

Undefined petroleum fractions 24

Problems 27

References 28

2 RESERVOIR-FLUID PROPERTIES 29

Properties of natural gases 29

Behavior of ideal gases 30

Behavior of real gases 36

Effect of nonhydrocarbon components of the Z-factor 44

Nonhydrocarbon adjustment methods 45

The Wichert-Aziz correction method 45

Correction for high-molecular weight gases 49

Direct calculation of compressibility factors 54

Compressibility of natural gases 59

Gas formation volume factor 65

Gas viscosity 67

Specific gravity of the solution gas 76

Gas solubility 77

Bubble-point pressure 86

Oil formation volume factor 92

Isothermal compressibility coefficient of crude oil 98

Oil formation volume factor for undersaturated oils 103

Crude oil density 106

Crude oil viscosity 108

Methods of calculating viscosity of the dead oil 109

Methods of calculating the saturated oil viscosity 111

Methods of calculating the viscosity of the undersaturated oil 112

Surface/interfacial tension 115

Properties of reservoir water 118

Water formation volume factor 118

Water viscosity 119

Gas solubility in water 119

Water isothermal compressibility 120

Problems 120

References 126

3 LABORATORY ANALYSIS OF RESERVOIR FLUIDS 130

Composition of the resevoir fluid 131

Extrapolation of resevoir fluid data 158

Correcting constant-composition expansion data 158

Correcting differential liberation data 160

Correcting oil viscosity data 161

Correcting the separator tests data 163

Laboratory analysis of gas condensate systems 165

Recombination of separator samples 165

Constant-composition test 168

Constant-volume depletion (CVD) test 170

Problems 178

References 182

4 FUNDAMENTALS OF ROCK PROPERTIES 183

Porosity 184

Absolute porosity 184

Effective porosity 185

Saturation 189

Average saturation 191

Wettability 193

Surface and interfacial tension 194

Capillary pressure 197

Capillary pressure of reservoir rocks 200

Capillary hysteresis 203

Permeability 221

The Klinkenberg effect 228

Averaging absolute permeabilities 235

Weighted-average permeability 236

Harmonic-average permeability 239

Geometric-average permeability 243

Absolute permeability correlations 244

Rock compressibility 248

Net pay thickness 254

Resevoir heterogeneity 255

Vertical Heterogeneity 256

Areal heterogeneity 268

Problems 273

References 278

5 RELATIVE PERMEABILITY CONCEPTS 280

Two-phase relative permeability 281

Drainage process 285

Imbibition process 286

Two-phase relatie permeability correlations 286

1 Wyllie and Gardner correlation 288

2 Torcaso and Wyllie correlation 289

3 Pirson’s correlation 289

Dynamic pseudo-relative permeabilities 301

Normalization and averaging realtive permeability data 304

Three-phase relative permeability 310

Three-phase relative permeability correlations 312

Wyllie’s correlations 313

Stone’s model I 314

Stone’s model II 316

The Hustad-Holt correlation 316

Problems 319

References 320

6 FUNDAMENTALS OF RESERVOIR FLUID FLOW 321

Types of fluid 322

Flow regimes 324

Resevoir geometry 326

Number of flowing fluids in the resevoir 329

Fluid flow equations 330

Darcy’s Law 331

Steady-state flow 332

Linear flow of incompressible fluids 333

Linear flow of slightly compressible fluids 339

Linear flow of compressible fluids (gases) 341

Unsteady-state flow 363

Basic transient flow equation 365

Radial flow of slightly compressible fluids 370

Constant-terminal-pressure solution 374

Constant-terminal-rate solution 374

The E-function solution 375

The dimensionless pressure drop (Pd) solution 383

Radial flow of compressible fluids 392

The m(p)-solution method (exact-solution) 395

The pressure-squared approximation method (p2-method) 398

The pressure-approximation method 400

Pseudosteady-state flow 403

Radial flow of slightly compressible fluids 409

Radial flow of compressible fluids (gases) 418

Pressure-squared approximation method 419

Pressure-approximation method 419

Skin factor 420

Turbulent flow factor 426

Principle of superposition 431

Effects of multiple wells 432

Effects of variable flow rates 435

Effects of the reservoir boundary 438

Accounting for pressure-change effects 442

Transient well testing 442

Drawdown test 443

Vertical oil well performance 473

Productivity index and IPR 473

Vogel’s method 482

Saturated oil reservoirs 483

Undersaturated oil reservoirs 485

Wiggins’ method 491

Standing’s method 494

Fetkovich’s method 498

The Klins-Clark method 514

Horizontal oil well performance 515

Method I 516

Method II 517

Horizontal well productivity under steady-state flow 519

Borisov’s method 520

The Giger-Reiss-Jourdan method 520

Joshi’s method 521

The Renard-Dupuy method 522

Horizontal well productivity under semisteady-state flow 527

Problems 529

References 531

8 GAS WELL PERFORMANCE 533

Vertical gas well performance 533

Region I High-pressure region 536

Region II Intermediate-pressure region 537

Future inflow performance relationships 559

Horizontal gas well performance 562

Problems 566

References 568

9 GAS AND WATER CONING 569

Coning 570

Coning in vertical wells 573

Vertical well critical rate correlations 573

The Meyer-Garder correlation 574

The Chierici-Ciucci approach 581

The Hoyland-Papatzacos-Skjaeve methods 593

Critical rate curves by Chaney et al 597

Chaperson’s method 604

Schols’ method 605

Breakthrough time in vertical wells 606

The Sobocinski-Cornelius method 606

The Bournazel-Jeanson method 609

After breakthrough performance 610

Coning in horizontal wells 615

Horizontal well critical rate correlations 616

Chaperson’s method 616

Efros’ method 620

Problems 632

References 634

10 WATER INFLUX 636

Classification of aquifers 637

Degree of pressure maintenance 637

Outer boundary conditions 639

Flow regimes 639

Flow geometries 639

Recognition of natural water influx 640

Water influx models 641

The pot aquifer model 642

Schilthuis’ steady-state model 645

Hurst’s modified steady-state model 649

The Van Everdingen-Hurst unsteady-state model 653

The edge-water drive 654

Bottom-water drive 677

The Carter-Tracey water influx model 703

Fetkovich’s method 707

Problems 713

References 716

11 OIL RECOVERY MECHANISMS AND THE MATERIAL BALANCE EQUATION 717

Primary recovery mechanisms 718

The gravity-drainage-drive mechanism 730

The combination-drive mechanism 735

The material balance equation 736

Basic assumptions in the MBE 751

The MBE as an equation of a straight line 753

The straight-line solution method to the MBE 755

Case 1 Volumetric undersaturated-oil resevoirs 755

Case 2 Volumetric saturated-oil reservoirs 760

Case 3 Gas-cap-drive reservoirs 762

Case 4 Water-drive reservoirs 766

The pot-aquifer model in the MBE 768

The steady-state model in the MBE 769

The unsteady-state model in the MBE 770

Tracy’s form of the material balance equation 774

Problems 778

References 781

12 PREDICTING OIL RESERVOIR PERFORMANCE 782

Phase 1 Reservoir performance prediction methods 783

Instantaneous gas-oil ratio 783

The resevoir saturation equations 789

to time 822

Problems 825

References 826

13 GAS RESERVOIRS 827

The volumetric method 828

The material balance method 831

Volumetric gas reservoirs 832

Form 1 In terms of p/z 833

Form 2 In terms of Bg 838

Water-drive gas reservoirs 840

Material balance equation as a straight line 842

Abnormally pressured gas reservoirs 847

Effect on gas production rate on ultimate recovery 853

Problems 854

References 856

14 PRINCIPLES OF WATERFLOODING 857

Factors to consider in waterflooding 858

Reservoir geometry 859

Fluid properties 859

Reservoir depth 859

Lithology and rock properties 860

Fluid saturations 861

recovery 865

First theory 865

Second theory 866

Selection of flooding patterns 875

Irregular injection patterns 875

Irregular injection patterns 875

Peripheral injection patterns 876

Regular injection patterns 878

Crestal and basal injection patterns 879

Overall recovery efficiency 880

I Displacement efficiency 881

II Areal sweep efficiency 932

III Vertical sweep efficiency 989

Calculation of vertical sweep efficiency 997

Methods of predicting recovery performance for layered reservoirs 1006

Simplified Dykstra-Parsons method 1006

Modified Dykstra-Parsons method 1010

Craig-Geffen-Morse method 1013

Problems 1016

References 1024

15 VAPOR-LIQUID PHASE EQUILIBRIA 1026

Vapor pressure 1026

Equilibrium ratios 1029

Flash calculations 1033

Campbell’s method 1051

Winn’s method 1051

Katz’s method 1052

Applications of the equilibrium ratio in reservoir engineering 1052

Dew-point pressure 1053

Bubble-point pressure 1055

Separator calculations 1058

Density calculations 1072

Equations of state 1084

The Van der Waals equation of state 1084

Redlick-Kwong equation of state 1092

Soave-Redlick-Kwong equation of state and its modifications 1098

Modifications of the SRK EOS 1108

Peng-Robinson equation of state and its modifications 1112

Applications of the equation of state in petroleum engineering 1124

Determination of the equilibrium ratios 1124

Determination of the dew-point pressure 1125

Determination of the bubble-point pressure 1128

Three-phase equilibrium calculations 1129

Vapor pressure from equilibrium of state 1135

Much of the material on which this book is based was drawn from thepublications of the Society of Petroleum Engineers Tribute is due to theSPE and the petroleum engineers, scientists, and authors who have madenumerous and significant contributions to the field of reservoir engineer-ing I would like to express my appreciation to a large number of my col-leagues within the petroleum industry and academia who offered sugges-tions and critiques on the first edition; special thanks go to Dr WenxiaZhang with TotalFinaElf E&P USA, Inc, for her suggestions and encour-agements I am also indebted to my students at Montana Tech of the Uni-versity of Montana, whose enthusiasm has made teaching a pleasure; Ithink! Special thanks to my colleagues and friends: Dr Gil Cady, Profes-sor John Evans; and Dr Margaret Ziaja for making valuable suggestionsfor the improvement of this book I would like to acknowledge andexpress my appreciation to Gary Kolstad, Vice President and GeneralManager with Schlumberger, and Darrell McKenna, Vice President withSchlumberger; for their continued support.

I would like to thank the editorial staff of Butterworth-Heinemann andGulf Professional Publishing for their concise and thorough work Igreatly appreciate the assistance that Karen Forster has given me during

my work on the second edition

xiii

ACKNOWLEDGMENTS

I have attempted to construct the chapters following a sequence that Ihave used for several years in teaching three undergraduate courses inreservoir engineering Two new chapters have been included in this sec-ond edition; Chapter 14 and 15 Chapter 14 reviews principles of water-flooding with emphasis on the design of a waterflooding project Chapter

15 is intended to introduce and document the practical applications ofequations of state in the area of vapor-liquid phase equilibria A compre-hensive review of different equations of state is presented with anemphasis on the Peng-Robinson equation of state

xiv

PREFACE TO THE SECOND EDITION

This book explains the fundamentals of reservoir engineering and theirpractical application in conducting a comprehensive field study Chapter

1 reviews fundamentals of reservoir fluid behavior with an emphasis onthe classification of reservoir and reservoir fluids Chapter 2 documentsreservoir-fluid properties, while Chapter 3 presents a comprehensivetreatment and description of the routine and specialized PVT laboratorytests The fundamentals of rock properties are discussed in Chapter 4 andnumerous methodologies for generating those properties are reviewed.Chapter 5 focuses on presenting the concept of relative permeability andits applications in fluid flow calculations

The fundamental mathematical expressions that are used to describethe reservoir fluid flow behavior in porous media are discussed in Chap-ter 6, while Chapters 7 and 8 describe the principle of oil and gas wellperformance calculations, respectively Chapter 9 provides the theoreticalanalysis of coning and outlines many of the practical solutions for calcu-lating water and gas coning behavior Various water influx calculationmodels are shown in Chapter 10, along with detailed descriptions of thecomputational steps involved in applying these models The objective ofChapter 11 is to introduce the basic principle of oil recovery mechanismsand to present the generalized form of the material balance equation.Chapters 12 and 13 focus on illustrating the practical applications of thematerial balance equation in oil and gas reservoirs

xv

PREFACE TO THE FIRST EDITION

xvi

Naturally occurring hydrocarbon systems found in petroleum voirs are mixtures of organic compounds which exhibit multiphasebehavior over wide ranges of pressures and temperatures These hydro-carbon accumulations may occur in the gaseous state, the liquid state, thesolid state, or in various combinations of gas, liquid, and solid.

reser-These differences in phase behavior, coupled with the physical ties of reservoir rock that determine the relative ease with which gas andliquid are transmitted or retained, result in many diverse types of hydro-carbon reservoirs with complex behaviors Frequently, petroleum engi-neers have the task to study the behavior and characteristics of a petrole-

proper-um reservoir and to determine the course of future development andproduction that would maximize the profit

The objective of this chapter is to review the basic principles of voir fluid phase behavior and illustrate the use of phase diagrams in clas-sifying types of reservoirs and the native hydrocarbon systems

reser-CLASSIFICATION OF RESERVOIRS AND RESERVOIR FLUIDS

Petroleum reservoirs are broadly classified as oil or gas reservoirs.These broad classifications are further subdivided depending on:

1

FUNDAMENTALS OF RESERVOIR FLUID

BEHAVIOR

• The composition of the reservoir hydrocarbon mixture

• Initial reservoir pressure and temperature

• Pressure and temperature of the surface production

The conditions under which these phases exist are a matter of erable practical importance The experimental or the mathematical deter-minations of these conditions are conveniently expressed in different

consid-types of diagrams commonly called phase diagrams One such diagram

is called the pressure-temperature diagram.

Pressure-Temperature Diagram

Figure 1-1 shows a typical pressure-temperature diagram of a component system with a specific overall composition Although a dif-ferent hydrocarbon system would have a different phase diagram, thegeneral configuration is similar

These multicomponent pressure-temperature diagrams are essentiallyused to:

• Classify reservoirs

• Classify the naturally occurring hydrocarbon systems

• Describe the phase behavior of the reservoir fluid

To fully understand the significance of the pressure-temperature grams, it is necessary to identify and define the following key points onthese diagrams:

dia-• Cricondentherm (T ct )—The Cricondentherm is defined as the

maxi-mum temperature above which liquid cannot be formed regardless ofpressure (point E) The corresponding pressure is termed the Cricon-dentherm pressure pct

• Cricondenbar (p cb )—The Cricondenbar is the maximum pressure above

which no gas can be formed regardless of temperature (point D) Thecorresponding temperature is called the Cricondenbar temperature Tcb

• Critical point—The critical point for a multicomponent mixture is

referred to as the state of pressure and temperature at which all sive properties of the gas and liquid phases are equal (point C) At thecritical point, the corresponding pressure and temperature are called thecritical pressure pcand critical temperature Tcof the mixture

inten-• Phase envelope (two-phase region)—The region enclosed by the

bub-ble-point curve and the dew-point curve (line BCA), wherein gas andliquid coexist in equilibrium, is identified as the phase envelope of thehydrocarbon system

• Quality lines—The dashed lines within the phase diagram are called

quality lines They describe the pressure and temperature conditions forequal volumes of liquids Note that the quality lines converge at thecritical point (point C)

• Bubble-point curve—The bubble-point curve (line BC) is defined as

the line separating the liquid-phase region from the two-phase region

• Dew-point curve—The dew-point curve (line AC) is defined as the

line separating the vapor-phase region from the two-phase region

In general, reservoirs are conveniently classified on the basis of thelocation of the point representing the initial reservoir pressure piand tem-perature T with respect to the pressure-temperature diagram of the reser-voir fluid Accordingly, reservoirs can be classified into basically twotypes These are:

Fundamentals of Reservoir Fluid Behavior 3

• Oil reservoirs—If the reservoir temperature T is less than the critical

temperature Tcof the reservoir fluid, the reservoir is classified as an oilreservoir

• Gas reservoirs—If the reservoir temperature is greater than the critical

temperature of the hydrocarbon fluid, the reservoir is considered a gasreservoir

2 Saturated oil reservoir When the initial reservoir pressure is equal to

the bubble-point pressure of the reservoir fluid, as shown on Figure 1-1

by point 2, the reservoir is called a saturated oil reservoir

3 Gas-cap reservoir If the initial reservoir pressure is below the

bubble-point pressure of the reservoir fluid, as indicated by bubble-point 3 on Figure 1-1, the reservoir is termed a gas-cap or two-phase reservoir, in whichthe gas or vapor phase is underlain by an oil phase The appropriatequality line gives the ratio of the gas-cap volume to reservoir oil volume.Crude oils cover a wide range in physical properties and chemicalcompositions, and it is often important to be able to group them intobroad categories of related oils In general, crude oils are commonly clas-sified into the following types:

• Ordinary black oil

• Low-shrinkage crude oil

• High-shrinkage (volatile) crude oil

• Near-critical crude oil

The above classifications are essentially based upon the propertiesexhibited by the crude oil, including physical properties, composition,gas-oil ratio, appearance, and pressure-temperature phase diagrams

1 Ordinary black oil A typical pressure-temperature phase diagram for

ordinary black oil is shown in Figure 1-2 It should be noted that

quali-ty lines which are approximately equally spaced characterize this

black oil phase diagram Following the pressure reduction path as cated by the vertical line EF on Figure 1-2, the liquid shrinkage curve,

indi-as shown in Figure 1-3, is prepared by plotting the liquid volume cent as a function of pressure The liquid shrinkage curve approxi-mates a straight line except at very low pressures When produced,ordinary black oils usually yield gas-oil ratios between 200–700scf/STB and oil gravities of 15 to 40 API The stock tank oil is usuallybrown to dark green in color

per-2 Low-shrinkage oil A typical pressure-temperature phase diagram for

low-shrinkage oil is shown in Figure 1-4 The diagram is characterized

by quality lines that are closely spaced near the dew-point curve Theliquid-shrinkage curve, as given in Figure 1-5, shows the shrinkagecharacteristics of this category of crude oils The other associatedproperties of this type of crude oil are:

• Oil formation volume factor less than 1.2 bbl/STB

• Gas-oil ratio less than 200 scf/STB

• Oil gravity less than 35° API

• Black or deeply colored

Fundamentals of Reservoir Fluid Behavior 5

Residual Oil

E

F 100%

Figure 1-4.A typical phase diagram for a low-shrinkage oil.

• Substantial liquid recovery at separator conditions as indicated bypoint G on the 85% quality line of Figure 1-4

3 Volatile crude oil The phase diagram for a volatile (high-shrinkage)

crude oil is given in Figure 1-6 Note that the quality lines are close

together near the bubble-point and are more widely spaced at lowerpressures This type of crude oil is commonly characterized by a highliquid shrinkage immediately below the bubble-point as shown in Fig-ure 1-7 The other characteristic properties of this oil include:

Fundamentals of Reservoir Fluid Behavior 7

Residual Oil

E

F 100%

Figure 1-6.A typical p-T diagram for a volatile crude oil.

Residual Oil

E

F 100%

0%

Pressure

Figure 1-7.A typical liquid-shrinkage curve for a volatile crude oil.

• Oil formation volume factor less than 2 bbl/STB

• Gas-oil ratios between 2,000–3,200 scf/STB

• Oil gravities between 45–55° API

• Lower liquid recovery of separator conditions as indicated by point

G on Figure 1-6

• Greenish to orange in color

Another characteristic of volatile oil reservoirs is that the API gravity

of the stock-tank liquid will increase in the later life of the reservoirs

4 Near-critical crude oil If the reservoir temperature T is near the

criti-cal temperature Tcof the hydrocarbon system, as shown in Figure 1-8,the hydrocarbon mixture is identified as a near-critical crude oil.Because all the quality lines converge at the critical point, an isothermalpressure drop (as shown by the vertical line EF in Figure 1-8) mayshrink the crude oil from 100% of the hydrocarbon pore volume at thebubble-point to 55% or less at a pressure 10 to 50 psi below the bubble-point The shrinkage characteristic behavior of the near-critical crude oil

is shown in Figure 1-9 The near-critical crude oil is characterized by ahigh GOR in excess of 3,000 scf/STB with an oil formation volume fac-tor of 2.0 bbl/STB or higher The compositions of near-critical oils areusually characterized by 12.5 to 20 mol% heptanes-plus, 35% or more

of ethane through hexanes, and the remainder methane

Fundamentals of Reservoir Fluid Behavior 9

Figure 1-10 compares the characteristic shape of the liquid-shrinkagecurve for each crude oil type.

Gas Reservoirs

In general, if the reservoir temperature is above the critical ture of the hydrocarbon system, the reservoir is classified as a natural gasreservoir On the basis of their phase diagrams and the prevailing reser-voir conditions, natural gases can be classified into four categories:

tempera-• Retrograde gas-condensate

• Near-critical gas-condensate

• Wet gas

• Dry gas

Retrograde gas-condensate reservoir If the reservoir temperature T

lies between the critical temperature Tc and cricondentherm Tct of thereservoir fluid, the reservoir is classified as a retrograde gas-condensatereservoir This category of gas reservoir is a unique type of hydrocarbonaccumulation in that the special thermodynamic behavior of the reservoirfluid is the controlling factor in the development and the depletionprocess of the reservoir When the pressure is decreased on these mix-

Figure 1-10.Liquid shrinkage for crude oil systems.

tures, instead of expanding (if a gas) or vaporizing (if a liquid) as might

be expected, they vaporize instead of condensing

Consider that the initial condition of a retrograde gas reservoir is resented by point 1 on the pressure-temperature phase diagram of Figure1-11 Because the reservoir pressure is above the upper dew-point pres-sure, the hydrocarbon system exists as a single phase (i.e., vapor phase)

rep-in the reservoir As the reservoir pressure declrep-ines isothermally durrep-ingproduction from the initial pressure (point 1) to the upper dew-pointpressure (point 2), the attraction between the molecules of the light andheavy components causes them to move further apart further apart Asthis occurs, attraction between the heavy component molecules becomesmore effective; thus, liquid begins to condense

This retrograde condensation process continues with decreasing sure until the liquid dropout reaches its maximum at point 3 Furtherreduction in pressure permits the heavy molecules to commence the nor-mal vaporization process This is the process whereby fewer gas mole-cules strike the liquid surface and causes more molecules to leave than

pres-Fundamentals of Reservoir Fluid Behavior 11

Lower Dew-point Curve

4 3

Figure 1-11.A typical phase diagram of a retrograde system.

enter the liquid phase The vaporization process continues until the voir pressure reaches the lower dew-point pressure This means that allthe liquid that formed must vaporize because the system is essentially allvapors at the lower dew point.

reser-Figure 1-12 shows a typical liquid shrinkage volume curve for a

con-densate system The curve is commonly called the liquid dropout curve.

In most gas-condensate reservoirs, the condensed liquid volume seldomexceeds more than 15%–19% of the pore volume This liquid saturation

is not large enough to allow any liquid flow It should be recognized,however, that around the wellbore where the pressure drop is high,enough liquid dropout might accumulate to give two-phase flow of gasand retrograde liquid

The associated physical characteristics of this category are:

• Gas-oil ratios between 8,000 to 70,000 scf/STB Generally, the gas-oilratio for a condensate system increases with time due to the liquiddropout and the loss of heavy components in the liquid

• Condensate gravity above 50° API

• Stock-tank liquid is usually water-white or slightly colored

There is a fairly sharp dividing line between oils and condensates from

a compositional standpoint Reservoir fluids that contain heptanes andare heavier in concentrations of more than 12.5 mol% are almost always

in the liquid phase in the reservoir Oils have been observed with

Maximum Liquid Dropout

Figure 1-12.A typical liquid dropout curve.

tanes and heavier concentrations as low as 10% and condensates as high

as 15.5% These cases are rare, however, and usually have very high tankliquid gravities

Near-critical gas-condensate reservoir If the reservoir temperature

is near the critical temperature, as shown in Figure 1-13, the hydrocarbonmixture is classified as a near-critical gas-condensate The volumetricbehavior of this category of natural gas is described through the isother-mal pressure declines as shown by the vertical line 1-3 in Figure 1-13and also by the corresponding liquid dropout curve of Figure 1-14.Because all the quality lines converge at the critical point, a rapid liquidbuildup will immediately occur below the dew point (Figure 1-14) as thepressure is reduced to point 2

Fundamentals of Reservoir Fluid Behavior 13

Liquid

Gas C

0 3

2

1 50

Pressure

Figure 1-14.Liquid-shrinkage curve for a near-critical gas-condensate system.

This behavior can be justified by the fact that several quality lines arecrossed very rapidly by the isothermal reduction in pressure At the pointwhere the liquid ceases to build up and begins to shrink again, the reser-voir goes from the retrograde region to a normal vaporization region

Wet-gas reservoir A typical phase diagram of a wet gas is shown in

Figure 1-15, where reservoir temperature is above the cricondentherm ofthe hydrocarbon mixture Because the reservoir temperature exceeds thecricondentherm of the hydrocarbon system, the reservoir fluid willalways remain in the vapor phase region as the reservoir is depletedisothermally, along the vertical line A-B

As the produced gas flows to the surface, however, the pressure andtemperature of the gas will decline If the gas enters the two-phaseregion, a liquid phase will condense out of the gas and be produced fromthe surface separators This is caused by a sufficient decrease in thekinetic energy of heavy molecules with temperature drop and their subse-quent change to liquid through the attractive forces between molecules.Wet-gas reservoirs are characterized by the following properties:

• Gas oil ratios between 60,000 to 100,000 scf/STB

• Stock-tank oil gravity above 60° API

• Liquid is water-white in color

• Separator conditions, i.e., separator pressure and temperature, lie withinthe two-phase region

Dry-gas reservoir The hydrocarbon mixture exists as a gas both in

the reservoir and in the surface facilities The only liquid associated withthe gas from a dry-gas reservoir is water A phase diagram of a dry-gasreservoir is given in Figure 1-16 Usually a system having a gas-oil ratiogreater than 100,000 scf/STB is considered to be a dry gas

Kinetic energy of the mixture is so high and attraction between cules so small that none of them coalesce to a liquid at stock-tank condi-tions of temperature and pressure

mole-It should be pointed out that the classification of hydrocarbon fluidsmight be also characterized by the initial composition of the system.McCain (1994) suggested that the heavy components in the hydrocarbonmixtures have the strongest effect on fluid characteristics The ternarydiagram, as shown in Figure 1-17, with equilateral triangles can be con-veniently used to roughly define the compositional boundaries that sepa-rate different types of hydrocarbon systems

Fundamentals of Reservoir Fluid Behavior 15

Liquid

Gas Separator

Pressure Depletion at Reservoir Temperature C

75

50

25 5 0

Figure 1-15.Phase diagram for a wet gas (After Clark, N.J Elements of Petroleum Reservoirs, SPE, 1969.)

From the foregoing discussion, it can be observed that hydrocarbonmixtures may exist in either the gaseous or liquid state, depending on thereservoir and operating conditions to which they are subjected The qual-itative concepts presented may be of aid in developing quantitativeanalyses Empirical equations of state are commonly used as a quantita-tive tool in describing and classifying the hydrocarbon system Theseequations of state require:

• Detailed compositional analyses of the hydrocarbon system

• Complete descriptions of the physical and critical properties of the ture individual components

mix-Many characteristic properties of these individual components (inother words, pure substances) have been measured and compiled over theyears These properties provide vital information for calculating the ther-modynamic properties of pure components, as well as their mixtures Themost important of these properties are:

Liquid

Gas Separator

Pressure Depletion at Reservoir Temperature

Figure 1-16.Phase diagram for a dry gas (After Clark, N.J Elements of Petroleum Reservoirs, SPE, 1969.)

Fundamentals of Reservoir Fluid Behavior 17

Figure 1-17.Compositions of various reservoir fluid types.

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