Reservoir engineering handbook tarek ahmed 3e copy

multi-These multicomponent pressure-temperature diagrams are essentiallyused to: • Classify reservoirs • Classify the naturally occurring hydrocarbon systems • Describe the phase behavio

RESERVOIR ENGINEERING

H A N D B O O K

Third Edition

AMSTERDAM.BOSTON.HEIDELBERG.LONDON.NEW YORK.OXFORD PARIS.SAN DIEGO.SAN FRANCISCO.SINGAPORE.SYDNEY.TOKYO

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06 07 08 09 10 11 10 9 8 7 6 5 4 3 2 1 Printed in the United States of America

⬁

This book is dedicated to my children, Justin, Brittany, Carsen, and Jennifer Ahmed

I do hope that at least one of them will grow up to be a petroleum engineer

in the future.

Acknowledgments, xi

Preface to the Third Edition, xiii

Preface to the Second Edition, xiv

Preface to the First Edition, xv

1 Fundamentals of Reservoir Fluid Behavior 1

Classification of Reservoirs and Reservoir Fluids, 1; Problems, 27;

References, 27

2 Reservoir-Fluid Properties 29

Properties of Natural Gases, 29; Behavior of Ideal Gases, 30;

Behavior of Real Gases, 36; Effect of Nonhydrocarbon Components

on the Z-Factor, 44; 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; Methods of Calculating the Viscosity of

Natural Gases, 68; Properties of Crude Oil Systems, 75; Methods of

Calculating Viscosity of the Dead Oil, 115; Methods of Calculating

the Saturated Oil Viscosity, 117; Methods of Calculating the

Viscosity of the Undersaturated Oil, 119; Properties of Reservoir

Water, 124; Problems, 126; References, 133

vii

CONTENTS

3 Laboratory Analysis of Reservoir Fluids 136

Composition of the Reservoir Fluid, 137; Constant-Composition

Expansion Tests, 137; Differential Liberation (Vaporization) Test,

149; Separator Tests, 152; Extrapolation of Reservoir Fluid Data, 164;Laboratory Analysis of Gas Condensate Systems, 171; Problems, 184;References, 188

4 Fundamentals of Rock Properties 189

Porosity, 190; Saturation, 195; Wettability, 199; Surface and

Interfacial Tension, 200; Capillary Pressure, 203; Permeability, 227;

Rock Compressibility, 254; Net Pay Thickness, 260; Reservoir

Heterogeneity, 261; Areal Heterogeneity, 274; Problems, 281;

References, 286

5 Relative Permeability Concepts 288

Two-Phase Relative Permeability, 289; Relative Permeability Ratio,

308; Dynamic Pseudo-Relative Permeabilities, 311; Normalization

and Averaging Relative Permeability Data, 313; Three-Phase RelativePermeability, 320; Problems, 329; References, 330

6 Fundamentals of Reservoir Fluid Flow 331

Types of Fluids, 332; Flow Regimes, 334; Reservoir Geometry, 336;

Number of Flowing Fluids in the Reservoir, 339; Fluid Flow

Equations, 340; Steady-State Flow, 342; Unsteady-State Flow, 373;

Constant-Terminal-Pressure Solution, 384; Constant-Terminal-Rate

Solution, 384; Pseudosteady-State Flow, 413; Principle of

Superposition, 442; Transient Well Testing, 453; Problems, 476;

References, 482

7 Oil Well Performance 484

Vertical Oil Well Performance, 484; Horizontal Oil Well

Performance, 528; Problems, 542; References, 544

8 Gas Well Performance 546

Vertical Gas Well Performance, 546; Horizontal Gas Well

Performance, 577; Problems, 580; References, 581

viii

9 Gas and Water Coning 583

Coning, 584; Coning in Vertical Wells, 587; Breakthrough Time inVertical Wells, 620; After Breakthrough Performance, 624; Coning

in Horizontal Wells, 629; Horizontal Well Breakthrough Time, 638;Problems, 646; References, 648

12 Predicting Oil Reservoir Performance 810

Phase 1 Reservoir Performance Prediction Methods, 811; Phase 2

Relating Reservoir Performance to Time, 850; Problems, 853;

References, 854

13 Gas Reservoirs 855

The Volumetric Method, 856; The Material Balance Method, 859;

Material Balance Equation as a Straight Line, 874; AbnormallyPressured Gas Reservoirs, 880; Problems, 906; References, 908

14 Principles of Waterflooding 909

Factors to Consider in Waterflooding, 910; Optimum Time toWaterflood, 915; Effect of Trapped Gas on Waterflood Recovery,917; Selection of Flooding Patterns, 927; Overall RecoveryEfficiency, 932; I Displacement Efficiency, 934; II Areal SweepEfficiency, 985; III Vertical Sweep Efficiency, 1041; Methods ofPredicting Recovery Performance for Layered Reservoirs, 1058;

Waterflood Surveillance, 1069; Problems, 1085; References, 1094

15 Vapor-Liquid Phase Equilibria 1096

Vapor Pressure, 1096; Equilibrium Ratios, 1099; Flash Calculations,1103; Equilibrium Ratios for Real Solutions, 1107; EquilibriumRatios for the Plus Fraction, 1120; Applications of the Equilibrium

Ratio in Reservoir Engineering, 1122; Equations of State, 1154;

Applications of the Equation of State in Petroleum Engineering,1194; Splitting and Lumping Schemes of the Plus-Fraction, 1207;

Problems, 1225; References, 1229

16 Analysis of Decline and Type Curves 1235

Decline-Curve Analysis, 1235; Type-Curve Analysis, 1264;

Much of the material on which this book is based was drawn from thepublications of the Society of Petroleum Engineers (SPE) Tribute is due

to the SPE and the petroleum engineers, scientists, and authors whohave made numerous and significant contributions to the field of reser-voir engineering This book reflects my style of teaching during mytenure at Montana Tech of the University of Montana and my under-standing of the subject of reservoir engineering I would like to thank all

my former students at Montana Tech for putting up with me and myEgyptian temper; it was fun I am sure they will remember that I did mybest to teach them reservoir engineering and my sincere desire to helpthem with their careers

I hope that my friends and colleagues in academia will enjoy this tion of the book I know most of them were so surprised to see me cross-ing the line and joining the “dark side” after years of teaching at MontanaTech, but surprisingly, I am enjoying the dark side very much, so youguys take it easy on me next time Thanks to Dr Bob Chase, Dr TomBlasingame, Dr J Tiab, and Dr F Civan for their constructive (I think)criticism and discussions

edi-I would also like to express my deep thanks to Anadarko PetroleumCorporation for granting me permission to publish this book and, inparticular, Bob Daniels, Senior VP for International Exploration andProduction, and Mark Pease, Senior VP for North America Explorationand Production

xi

ACKNOWLEDGMENTS

For the past 31⁄2years, I have had the pleasure of knowing and workingwith Anadarko’s Chief Technical Engineer, Scott Albertson I alwaysenjoy our “painful” early-morning technical discussions, as well asexchanging ideas and bouncing mathematical derivations off him, evenwhen his mind is floating somewhere in la-la land Scott is capable ofexhibiting many different facial expressions that he has mastered over theyears, and they are, indeed, more powerful than words Usually, many ofhis facial expressions can give me the clue, the light, and perhapsthe answer to my question (seldom, but remotely possible, in the neigh-borhood of P-1) I would like also to thank my friend, Senior Staff Reser-voir Engineer, Brian Roux, for sharing his considerable knowledgeand experience with me and for reading the first few pages of the manu-script (I think he has read the first 7 pages) at Landry’s The truth is thatScott and Brian are two of the brightest engineers that I have ever workedwith

I would like to thank Aydin Centilmen for helping me learn VIP ware; I owe him a big lunch at Taco Bell for that I also would like tothank the following engineers for their support and technical advice:chief engineer, Steve Martin; Julie Struble (only 5 feet tall, but a purepowerhouse); Tom Bergstresser (Tom is not an engineer; he has a PhD inGeology, but nobody is perfect, of course); manager of CBM group, BradMiller; senior reservoir engineer, Walt Dobbs; acquisitions manager,Craig Walter; manager of EOR group, Dane Cantwell; and senior engi-neering advisor, Frank Lim

soft-I would like to thank the editorial staff—in particular, Christine Brandt

of SPI Publisher Services—for their work and professionalism Lastly,this edition of the book could not have been completed without my spe-cial friend, Wendy I would like to thank Wendy for her superb typing,hard work, and encouragement

To make the third edition of this textbook as complete as possible,

I have included the following: a new chapter on decline curve and typecurve analysis, a section on tight and shallow gas reservoirs, and water-flood surveillance techniques

Many of my colleagues have provided me with valuable tions and suggestions that I have included through the textbook to make

recommenda-it more comprehensive in treating the subject of reservoir engineering

PREFACE TO THE THIRD EDITION

I have attempted to construct the chapters following a sequence that

I have used for several years in teaching three undergraduate courses

in reservoir engineering Two new chapters have been included in thissecond edition; Chapter 14 and 15 Chapter 14 reviews principles ofwaterflooding with emphasis on the design of a waterflooding project.Chapter 15 is intended to introduce and document the practical applica-tions of equations of state in the area of vapor-liquid phase equilibria

A comprehensive review of different equations of state is presented with

an emphasis on the Peng-Robinson equation of state

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

PREFACE TO THE FIRST EDITION

xv

Naturally occurring hydrocarbon systems found in petroleum voirs are mixtures of organic compounds that exhibit multiphase behav-ior over wide ranges of pressures and temperatures These hydrocarbonaccumulations may occur in the gaseous state, the liquid state, the solidstate, 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

C H A P T E R 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

multi-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) The corresponding 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)

inten-At the critical point, the corresponding pressure and temperatureare called the critical pressure pc and critical temperature Tc of themixture

• 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:

• 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 thatquality lines, which are approximately equally spaced characterizethis black oil phase diagram Following the pressure reduction path asindicated by the vertical line EF on Figure 1-2, the liquid shrinkagecurve, as shown in Figure 1-3, is prepared by plotting the liquid volumepercent 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.

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:

Ordinary Black Oil

in reservoir Dew-Point Curve

B G

F

A

80 70 60 50 40 30 20 10 0

Figure 1-2.A typical p-T diagram for an ordinary black oil.

Residual Oil

E

F 100%

6 Reservoir Engineering Handbook

E

Bubble-point Curv

e

Dew-point Curve Separator Conditions

0%

Pressure

Figure 1-5.Oil-shrinkage curve for low-shrinkage oil.

• 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

• 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 closetogether 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:

• 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

Pressure path

in reservoir Critical point

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

Residual Oil

E

F 100%

8 Reservoir Engineering Handbook

C E

0

0

5 10 20 30 40 50 60 70 90 80

Figure 1-8.A schematic phase diagram for the near-critical crude oil.

• 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

the hydrocarbon mixture is identified as a near-critical crude oil.Because all the quality lines converge at the critical point, an isother-mal pressure 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 bub-ble-point The shrinkage characteristic behavior of the near-criticalcrude oil is shown in Figure 1-9 The near-critical crude oil is charac-terized by a high GOR in excess of 3,000 scf/STB with an oil forma-tion volume factor of 2.0 bbl/STB or higher The compositions of near-critical oils are usually characterized by 12.5 to 20 mol%heptanes-plus, 35% or more of ethane through hexanes, and theremainder methane

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

Fundamentals of Reservoir Fluid Behavior 9

E

F 100%

0%

Pressure

Figure 1-9.A typical liquid-shrinkage curve for the near-critical crude oil.

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

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 the reservoir fluid, the reservoir is classified as a retrograde condensate reservoir This category of gas reservoir is a unique type

gas-of hydrocarbon accumulation in that the special thermodynamicbehavior of the reservoir fluid is the controlling factor in the develop-ment and the depletion process of the reservoir When the pressure

is decreased on these mixtures, instead of expanding (if a gas) orvaporizing (if a liquid) as might be expected, they vaporize instead ofcondensing

Consider that the initial condition of a retrograde gas reservoir is represented by point 1 on the pressure-temperature phase diagram of Figure 1-11 Because the reservoir pressure is above the upper dew-pointpressure, the hydrocarbon system exists as a single phase (i.e., vaporphase) in the reservoir As the reservoir pressure declines isothermallyduring production from the initial pressure (point 1) to the upper dew-point pressure (point 2), the attraction between the molecules of the lightand heavy components causes them to move further apart further apart

Pressure path

in reservoir Retrograde gas

1 2

3

4

40 30 20 15 10

5 0

G C

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

As this occurs, attraction between the heavy component moleculesbecomes more 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 thanenter the liquid phase The vaporization process continues until the reser-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

pres-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 and 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

100

0

Pressure

Maximum Liquid Dropout

Figure 1-12.A typical liquid dropout curve.

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

hep-as 15.5% These chep-ases 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

This behavior can be justified by the fact that several quality linesare crossed very rapidly by the isothermal reduction in pressure At thepoint where the liquid ceases to build up and begins to shrink again, the

Pressure path

in reservoir Near-Critical Gas

% Liquid

1 2

3 Separator

30 20 15 10

5 0

Fundamentals of Reservoir Fluid Behavior 13

100

2

1 50

Pressure

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

reservoir goes from the retrograde region to a normal vaporizationregion

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 producedfrom the surface separators This is caused by a sufficient decrease

in the kinetic energy of heavy molecules with temperature drop andtheir subsequent change to liquid through the attractive forces betweenmolecules

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

14 Reservoir Engineering Handbook

with the gas from a dry-gas reservoir is water A phase diagram of adry-gas reservoir is given in Figure 1-16 Usually a system having

a gas-oil ratio greater than 100,000 scf/STB is considered to be adry 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 conveniently used to roughly define the compositional boundaries thatseparate different types of hydrocarbon systems

Liquid

Gas

Separator

Pressure Depletion at Reservoir Temperature C

75 50 25 5 0

Two-phase Region

Temperature

B A

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 onthe reservoir and operating conditions to which they are subjected Thequalitative 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 overthe years These properties provide vital information for calculating the

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.)

thermodynamic properties of pure components, as well as their mixtures.The most important of these properties are:

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

erties that were generated by analyzing the physical properties of

26 condensates and crude oil systems These generalized propertiesare given in Table 1-1

Ahmed (1985) correlated Katz-Firoozabadi-tabulated physical ties with the number of carbon atoms of the fraction by using a regres-sion model The generalized equation has the following form:

proper-θ = a1+ a2n + a3n2+ a4n3+ (a5/n) (1-1)where θ = any physical property

n= number of carbon atoms, i.e., 6 7 ., 45

a1–a5= coefficients of the equation and are given in Table 1-3

Undefined Petroleum Fractions

Nearly all naturally occurring hydrocarbon systems contain a quantity

of heavy fractions that are not well defined and are not mixtures of cretely identified components These heavy fractions are often lumpedtogether and identified as the plus fraction, e.g., C7+fraction

dis-A proper description of the physical properties of the plus fractionsand other undefined petroleum fractions in hydrocarbon mixtures isessential in performing reliable phase behavior calculations and com-positional modeling studies Frequently, a distillation analysis or achromatographic analysis is available for this undefined fraction.Other physical properties, such as molecular weight and specific gravity, may also be measured for the entire fraction or for variouscuts of it

To use any of the thermodynamic property-prediction models, e.g.,equation of state, to predict the phase and volumetric behavior of com-plex hydrocarbon mixtures, one must be able to provide the acentric fac-tor, along with the critical temperature and critical pressure, for both thedefined and undefined (heavy) fractions in the mixture The problem ofhow to adequately characterize these undefined plus fractions in terms oftheir critical properties and acentric factors has been long recognized inthe petroleum industry Whitson (1984) presented an excellent documen-tation on the influence of various heptanes-plus (C7+) characterizationschemes on predicting the volumetric behavior of hydrocarbon mixtures

by equations-of-state

(text continued on page 24)

Reservoir Engineering Handbook

Table 1-1 Generalized Physical Properties

Fundamentals of Reservoir Fluid Behavior

Reservoir Engineering Handbook

Fundamentals of Reservoir Fluid Behavior

(table continued on next page)

Reservoir Engineering Handbook

Fundamentals of Reservoir Fluid Behavior