Properties of Oils and Natural Gases

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Contributions in Petroleum Geology and EngineeringSeries Editor: George V. Chilingar, University of Southern CaliforniaVolume 1: Geologic Analysis of Naturally Fractured ReservoirsVolume 2: Applied Open-Hole Log AnalysisVolume 3: Underground Storage of Natural GasVolume 4: Gas Production EngineeringVolume 5: Properti es of Oil s and Natural GasesVolume 6: Introduction to Petroleum Reservoir AnalysisVolume 7: Hydrocarbon Phase BehaviorVolume 8: Gas Reservoir Engineering

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Contributions m Petroleum Geology and Engineering

Volume 5

Properties of Oils and Natural Gases

Copyright 1989 by Gulf Publishing Company, Houston,Texas. Al rights reserved. Printed in the United States of... Ainerica. This book, or parts thereof, may not be

reproduced in any form wi thout permission of thepublisher.

Library of Congress Cataloging-in-Publication DataPedersen, K. S. (Karen Schou)

Properties of oils and natural gases/K. S. Pedersen, A.Fredenslund & P. Thomassen.

p. cm.-(Contributions in petroleum geology &engineering; v. 5)Ineludes index.

ISBN 0-87201-588-21. Petroleum-Analysis. 2. Gas, Natural-Analysis.

1. Fredenslund, Aage, 1941- . n. Thomassen, P. (Per) ,1950- III. Title. IV. Series.TP691.P42 1989

665.5-dcl9 88-24659CIP

ISBN 0-87201-066-X (series)

Nomenclature

l' I r. Iv~ -, ,-ti,1 ;:,r r , \Contents ~~:~i\\'\' i: .\ ............................................ ~ir'~.-;./

Introduction 11. Petroleum Reservoir Fluids 4

Petroleum Reservoir Flu id Constituents, 4; Classification of PetroleumReservoir Fluids, 4; Hydrocarbon Fractions, 8; Residue, 9.

2. Compositional Determinations 10Gas Chromatography and TBP Distillation, 10; Properties of Hydro-carbon Fractons, 22; Internal Consistency o fAnalytical Data, 30; Ex-perimental Extension beyond C20+, 35.

3. Oil and Gas Property Measurements 39Sampling, 39; Flash Separation and Compositional Analysis, 39; PVTMeasurements, 40; Black Oil Equipment, 40; Gas Condensate Equip-ment, 54; Volatile Fluid Equipment, 60; Measurement of Viscosity, 63;Surface Tension, 66.

4. Composition and Property Data 695. Equations of State 79

Types of Equations of State, 79; Cubic Equations of State, 81; TheSRK-EquatioiJ of State, 82; Phase Densities, 89.

6. Flash Calculations 99Two-Phase (P,T)-Flash, 100; Multi-Phase (P,T)-Flash, 104; (P,H) or(P,S)-Flash Calculations, 105; Three-Phase (P,T)-Flash with a LiquidWater Phase, 108; Simplified Two-Phase (P,T)-Flash, 109; Phase Enve-lope Calculations, 112.

7. Characterization Procedures 114Classification of the Constituents of Oil and Gas Mxtures, 114; TBPFractions, 114; The TBP Residue, 116; Characterization Procedures,120; Grouping of Pseudocomponents, 124; Calculation of the Ideal GasHeat Capacity, 126.

8. Simulation of PVT-Experiments 130Constant Mass Expansion, 130; Differential Liberation, 131; ConstantVolume Depletion, 135; Separator Test, 140; Summary of Results of thePVT-Simulations, 140.

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9. Comparison Between Experimental and PredictedThermodynamic Properties 141Dew and Bubble Points (Phase Envelopes), 141; Flash Results, 144;Densities, 144; Enthalpy, 151; Summary of the Results of Thermody-namic Properties, 154.

10. Tuning of EOS-Parameters 155The Needs for Tuning, 155; Parameters Available for Tuning, 155; Ex-amples on the Dangers of Tuning, 156; The Molecular Weight of thePlus-Fraction as a Tuning Parameter, 166; Recommendations Regard-ing Tuning, 169.

1l. Viscosity 172Definition of Viscosity,172; Kinetic Gas Theory, 172; ViscosityCorrela-tions, 173; The ViscosityCorrelation of Lohrenz et al., 173; Calculationof the Viscosity Using Corresponding States Theory, 175; Comparisonwith Experimental Results, 181.12. Thermal Conductivity 187Kinetic Gas Theory, 187; Calculation of the Thermal Conductivity Us-ing Corresponding States Theory, 188; Comparison with ExperimentalObservations, 194.13. Surface Tension 196Estimation of the Surface Tension Using the Macleod-Sugden Correla-tion, 196; Estimation of the Surface Tension from the Viscosity, 199;Comparison with Experimental Observations, 202.14. Wax Formation and Inhibition 208Wax Composition, 208; Computation of WaxFormation, 208; WaxIn-hibitors, 214; Comparisons Between Calculated and Experimental Re-sults, 217.15. Gas Hydrates 220Types of Hydrates, 220; Hydtate Computation, 223; Hydrate Inhibi-tors, 228; Comparison with Experimental Observations, 230.

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16. Simulation of Miscible Gas Injection 234Process Description, 234; Calculation ofthe Minimum Miscibility Pres-sure (MMP), 238; Cell-to-Cell Simulation, 241; Comparison of Calcu-lated and Experimentally Determined MMP's, 246.Index 249

vi

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Nomenclature

Equation of state parameterConstant defined in Equation 15;18Constants def ined in Equations 5-54 and 5-55Constants def ined in Equation 11-6Aromatics (Chapter 1)Constant def ined in Equation 5-23Constant def ined in Equation 7-13Surface area (Chapter 13)Constant def ined in Equation 13-15Constant def ined in Equation 15-5Constant def ined in Equation 13-3Parameters def ined in Equations 5-51 through 5-53Coefficients defined in Equation 5-86API gravity (141.5/SG-131.5)Equation of state parameterConstant def ined in Equation 15-18Parameters def ined in Equations 5-59 through 5-62Constantdef ined in Equation 7-13Constant def ined in Equation 5-24Constant def ined in Equation 13-15Constant def ined in Equation 15-5Shrinkage factor (defined in Equation 3-2)Parameters def ined in Equations 5-57 and 5-58Coefficients defined in Equation 5-87Constant def ined in Equation 13-5Peneloux parameter def ined in Equation 5-39Parameters def ined in Equations 5-68 through 5-73Constants def ined in Equations 13-16 and 13-17Crit ical point (Chapter 1)Constant def ined in Equation 5-46Density correlation factor def ined in Equation 5-86Adsorption coefficient (Chapter 15)Function def ined in Equation 7-47Carbon numberMolar heat capaci ty at constant pressureMolar heat capacity at constant volumeDensity correlation factor at standard conditions (Chapter 5)Density correlation factor at actual conditions (Chapter 5)

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CO -C3: .Parameters defined in Equations 5-64 through 5-67 K: Watson Characterization factor (Chapter 7)C-C4: Coefficients of ideal gas heat capacity polynomial Equation K: Constan t defined in Equation 15-215-36 and Equat ions 7-43 through 7-46 1-17: Constants defined in Equation 12-18C7+: Hydrocarbons with 7 and more carbon atoms L: Length of capillary tube Equation 3-10 (D: Diameter (Chapter 3) L: Mean free pass between two molecules (DL: Differential liberation m: Function of the acen tr ic fac tor defined in Equation 5-16e-e3: Functions defined in Equations 6-54 and 6-56 m: Constant defined in Equation 5-46e-e6: Parameters defined in Equat ions 5-79 through 5-84 m: Number of pseudocomponentsEOS: Equation of State M: Molecular weight of inhibi to r d iv ided by molecularEo-E3: Parameters defi ned in Equat ions 5-75 through 5-78 weigh t of waterE : Fugacity MMP: Minimum miscibility pressure (E : Funct ion defined in Equat ion 12-12 Mr: r 'th sta tist ica l moment defined in Equation 7-40E : Function defined in Equat ion 12-36 MW: Molecular weightEj: Funct ion defined in Equat ion 12-24 n: Refractive index (Chapter 7) (fx,o: Funct ion defined in Equation 12-22 n: Number of moles Equat ion 3-5 and Chapter 6FA: Function defined in Equat ion 12-21 ( n: Constan t defined in Equat ion 5-45 (F: Distribution function (Chapter 7) , Number of discrete components (Chapter 7): (FCMP: First contact minimum miscibility pressure N: Naphthenes (Chapter 1)F: Funct ion defined in Equation 11-41 N: Stage number (Chapter 3) (

F2: Function defined in Equat ion 11-41 N: Number of components (Chapter 6)g: Gravitational acceleration NCOMP: Number of componentsg: Funct ion def ined in Equation 6-26 NSTEP: Total number of f lash stagesg2: Funct ion defined in Equation 6-28 ' P: Paraffins (Chapter 2)G: Gibbs energy P: Probability function defined in Equation 7-17GOR: Gas/o il ra tio [PJ: Parachor (Chapter 13)h.: Funct ion defined in Equat ion 12-27 PVT: Pressure, volume, temperaturehj: Funct on def ined in Equation 12-25 q,,: Funct ion defined in Equation 6-46hx.o: Function defined in Equat ion 12-23 q,s: Function defined in Equation 6-47H: Function defined in Equat ion 3-11 qo: Funct ian defined in Equation 6-45H: Molar enthalpy q: Heat Ilow per unit area (Chapter 12)H: Funct ion def ined in Equation 6-23 r: Crystal radius (Chapter 14)HTAN: Function def ined in Equat ion 11-41 r: Distance f rom lat tice wal l (Chapter 15)1: Characterization Factor defined in Equations 7-21 and 7-22 r*: Cri tica l rad ius (Chapter 14)1: Variable used to def ine continuous distribution (Chapter 7) R: Gas constantIp: Quadrature point (Chapter 7) R: Parameter defined in Equation 7-27i-h: Coefficients defined in Equation 11-38 Rs: Solution gas/oi l rat io (defined in Equat ion 3-3)J : Phase number (Chapter 6) s: Number of quadrature points (Chapter 7)k: Constant defined in Equation 6-9 s: Mole f ract ion in salid phasek: Boltzmann's constant (Chapter 14) . s: Inhibitor concentra tion (Chapter 15)kj: Binary interaction coefficient S: Standard Conditions (normally 15C and 1 atm)k-k7: Canstants defined in Equat ion 11-40 S: EntropyK: Equilibrium ratio (vapor mole fraction/liquid mole fraction) SG: Specific GravityK: Constant defined in Equation 5-45 SRK: Soave-Redlich -Kwongviii ix


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I l .T: Temperature 17: Viscosity ;~'\ ~ ,T: Average temperature defined in Equation 15-8 17: Parameter entering into Equation 7-17 .\;:;- =' rT*: Transition temperature defined in Chapter 6 17: Mole fraction of continuous components (Chapter 7) '.


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1:11:id:int:j:k:L:mix:M:N:o :o :p :pure:r:R :RA:ref:rep:res:res:S:spec:a:tr:V:vap:w:wt:x:y :..

Phase numberPhase numberIdealInternalComponent indexComponent indexLiquidMixtureMethaneComponent identificat ion number (Chapter 16)Reference state (Chapter 6)Reference component (Chapters 11 and 12)Separator conditions (Chapter 2)Pure componentReduced s tate (property at actual conditions/property at criticalconditions)Reference conditions (normally 15C and 1 atm)Racket (Equation 5-43)Reference stateRepulsiveReservoir conditionsResidual (Chapter 5)Solid phase (Chapter 14)Specified valueSurface tensionTranslationalVaporVaporWaterWeight percentX-directionY-directionPseudo state (Chapter 5)Dilute gas (Chapter 11)

xii

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IntroductionTraditionally, chemical and petroleum engineers engaged in production

of oil and natural gas from reservoirs have not devoted much interest to de-tails regarding the properties and composit ions of the hydrocarbon fluidsproduced. Design of production schemes and equipment was mainly based

, on experience. This was, however, insufficient considering the enormous in-vestments required for oil and gas exploration and production. Today pro-duction systems and equipment undergo detailed engineering analyses andcareful design 1:0 optimize the amount of hydrocarbons produced and mini-mize the operating costs and investment.

Analysis and design of oil and gas production faci li ties and schemes re-quire thorough knowledge of the thermodynamic and physical properties ofhydrocarbon fluids. To know how much gas and how much oi~aratorproduces under given conditions, it is necessary to know the vapor- liquidequilibrium relationships and the_d~~siti es of the mixture. Understanding

. the flow processes in the reservoir requires knowledge of viscosity and SUT-face tension. Heat exchanger design requires knowledge ofthe thermal con-ductivi ty of the f lowing fluids. Other examples abound.

It would, naturally, be best if knowledge ofthe above mentioned proper-ties was available from experimental observations. Those are, however, im-possible to measure for all hydrocarbon fluids in all relevant conditions. Thechief objective of this book is, therefore, to describe in detail how to usemathematical models to accurately predict transport properties (viscosityand thermal conductivity), surface tensions, and thermodynamic properties(density, enthalpy and phase equilibria) of naturally occurr ing oil and gasmixtures. The book isintended for the design (chemical or petroleum) engi-, neer in the oil and gas related industry.

The models described in this book are the results of a collaborative re-, search and development project executed by three part ies: Statoil a.s., theNorwegian state oil company, Calsep A/S, a Danish engineering consultingcompany, and the Department of Chemical Engineering at the Technical

, Universty ofDenmark. The research project was carr ied out on three levels.The basic level concerns the description of the oil or gas. Detailed compo-

sitional analyses of Statoil's North Sea oils were performed, including chro-matography, TBP-distillation, and others. The analyses were checked for in-ternal consistency by, for example, computing and measur ing the average

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2 Properties of Oils and Natural Gases

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rnolecular weight of the residue. The end result of this basic level researchwas a highly detailed and-cornpared with earli er work-rnuch irnprovedanalytical description of the hydrocarbon rnixtures.

The second level of research concerns the developrnent of irnproved corre-lations of Te, P and w (critical ternperature, pressure and acentric factor)for the hydrocarbon fractions as a function of the rnolecular weight andother properties. In addition, procedures for est irnating (characterizing)the cornposition of the C20+ residue were developed.The third level concerns choice of equation of s tate, viscosity rnodel, etc.by cornparing rneasured and predicted properti es. This level of research in-eludes fur ther developrnent of the rnodels by, for exarnple, irnprovernent othe mixing rules. It also ineludes applicat ion of the rnodels to sirnulate rnac-roscopic processes such as flash operations, wax forrnation, and reservoir oilgas miscibility.

There is a great de al of interplay between the three levels ofresearch. Theavailability of correct and detai led cornpos it ional analyses is a necessarycondition for developing meaningful and sound improvements in the corre-lations of Te, Pe, and w in the equations of sta te. Sound models for Te, Pe,and w are needed to furnish good predictions of densit ies and dew pointsusng an equation of state. Improvements and adjus tments continued on allthree levels throughout the research project.

Because the models presented in this book are based on the most detai ledand correct analytical information possible, the predict ive capacity of themodels isvery high. Although the models were developed almost exelusivelyon the basis of data for North Sea reservoir f luids, they may also be appliedwith confidence to petroleum reservoir f luids from other regions. I t is alsoimportant to realize that, although highly detailed analyti cal data were re-quired to deve lop the models, it is notnecessary to have th same degree ofdetail avai lable in order to use the models.

The book isdivided into four par ts. The f irst par t (up to Chapter 4) intro-duces and describes oil s and gases. Different types of oi ls are described inChapter 1, and laboratory methods for composit ional and property mea-surements are given in Chapters 2 and 3. Chapter 4 lis ts compositional datafor several hydrocarbon mixtures, and extensive data ineluding densi ties ,dew point s, viscosi ties , and others are given.The second part (Chapters 5-10) describes the modeling of the thermody-namic properties such as densi ties, dew points, and flash separations. Fromthe many different models available, the Soave-Redlch-Kwong equa tion ofstate was chosen as t he basic model for these propert ies. I t isshown in Chap-ters 8 and 9 that this model (when modified s lightly using the volume trans-lation concept) gives results that are in excellent agreement with experimen-tal values. The choice of the Soave-Redlich-Kwong equat ion of state is,however, somewhat arbitrary. Equally good results could have been ob-

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Introduction 3

tained with, for example, the Peng-Robinson equation of state. It should beemphasized, however, that the characterization procedure ofPedersen et al.described in Chapter 7 in detail, is tied to the chosen equation of state, al-though the principIes may be applied with any equation of state. The flashcalculat ion procedure described in Chapter 6 can be used in conjunctionwith any equation of state.

The third part of the book (Chapters 11-13) describes newly developedcorrelations for predict ing the transport propert ies (viscosi ty and thermalconductivity) and surface tension of hydrocarbon mixtures. The transportproper ty models are based on the principIe of corresponding states, and maybe applied to both gaseous and liquid phases. One of the surface tension cor-relations is elosely tied to the viscosity correlation.

The last pa rt of the book (Chapters 14-16) describes some novel, impor-tant applications of the mode ls developed in this work: wax formation inpipelines , gas hydrate formation, and s tudies of miscible gas injection pro-cesses.The intent has been as complete a presentation as poss ible. Thus, manydetailed experimental da ta are l isted, and all deta ils regarding the devel-oped models are given so that they may be readi ly applied, based on themater ial given in this book.


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Chapter 1Petroleum Reservoir Fluids

PETROLEUM RESERVOIR FLUID CONSTITUENTSPetroleum reservoir fluids are mult i-component mixtures, consisting pri-

marily of hydrocarbons belonging to one of the following three classes:Paraffns (or alkanes) consist of chains of hydrocarbon segments (e.g., -CH2or -CH3). The molecules may be unbranched (normal paraffins), or

branched (iso-paraffins). The atoms are connected by single bonds. Meth-ane (CH4 ) is the simplest paraffin and it is also, on molar basis, the mostcommon constituent of petroleum reservoir fluids.

Naphthenes (or cycloalkanes) are hydrocarbons similar to the paraffins, butdiffering from these by containing one or more cyclic structures. The ele-ments of the cyclic structure (e.g. , -CH2) are connected by single bonds,and usually six carbon atoms are joined in a ring structure.

Aromatcs are hydrocarbons containing one or more ring structures similarto benzene (C6H6). The atoms are connected by aromatic double bonds.Polycyclic aromatic compounds (or asphalthenes), like naphthalene(CIOH8) and anthracene (CI4HIO), may also be presentoIn addition to hydrocarbons, the non-hydrocarbons nitrogen (N2), carbon

dioxide (C02) , and hydrogen sulfide (H2S) are often found in petroleummixtures. Finally, petroleum mixtures may contain helium, mercury, andmetal-organic compounds. These will not be covered in this work. Table 1-1shows some physical properties of common petroleum reservoir fluid con-stituents. The molecular structures of some of these components are shownin Figure 1-1.

CLASSIFICATION OF PETROLEUM RESERVOIR FLUIDSPetroleum reservoir fluids may be classified as gases, gas condensates, vol-atile oils, or black oils.

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Petroleum Reservoir Fluids 5Table 1-1

Physical Properties of Some Common Pet roleum Reservo ir F luidConstituents

1 Density g/cm3)Melting Point Normal Boiling at 1 atm and

eomponent Formula (Oe) Point (Oe) 15eParaffinsMethane CH. - 184 - 161.5 -Ethane C2Ha - 172 - 88.3 -Propane C3Ha - 189.9 - 42.2 -n-Butane C.HlO - 135 - 0.6 -Iso-Butane C.HlO - 145 - 10.2 -n-Pentane CSH'2 - 131.5 36.2 0.626n-Hexane CaH'4 - 94.3 69.0 0.659Iso-octane CaH,a - 107.4 99.3 0.692n-Decane C,oH22 - 30 174.0 0.730NaphthenesCyclopentane CSHlO - 93.3 49.5 0.745Methyl cyclo-pentane CaH'2 - 142.4 71.8 0.754Cyclohexane CaH'2 6.5 81.4 0.779AromaticsBenzene CaHa 5.51 80.1 0.885Toiuene C7Ha - 95 110.6 0.867o-Xylene CaH'0 - 29 144.4 0.880Naphthalene C,oHa 80.2 217.9 0.971

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Table 1-2 shows typical molar compositions of mixtures belonging to eachof the four classes. For each composition, the last hydrocarbon is markedwith a + . It indicates that heavier components are contained in this frac-tion also. In addition to the composition, the state of a f luid is also deter-mined by the temperature and pressure.

The differences in the molar compositions between each of the fourclasses of reservoir fluids are naturally reflected in differences in the fluid.properties. Figure 1-2 shows schematically typical phase envelopes for eachclass. Each phase envelope corresponds to a fixed overall composition. Atthe temperatures and pressures inside the phase envelope, two phases (usu-


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6 Properties 01 Oil s and Natura l GasesP A R AF F I NS : HIH-C-H

H I H, . IH - C - C - C - HI I IH H HI s o - B u t a n eH H H H H H H H H H- C - C - C - C - C - C - C - C - C - C - HI I I I I I I I I l'H H H H H H H H H Hn - D e c a n e

HIH - C - HIHM e t h a n eN A P H T H E N E S :

HIH-C -HH tH, / \~, C C ' HH J - - H/ \ . \H H HM e t h y lC y c l o p e n t a n e

A R O MA T l C S :HICH - C ' ~C - H

11 IH- C ' t C - HIH

H / H'cH-./,~H C C \ jH -- ' I HH}' /(.HCH . . . . . . . H

H HI I~ C , _ / C ~H-C '\: ' C - HI 11 IH - C ~ /t , t : C - H~C \:7'I IH HC y c l o h e x a n e B e n z e n e Na p h t h a l e n e

Figure 1-1. Examples of hydrocarbon molecular structures.

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T E MP E RAT UR E -Figure 1-2. Phase envelopes for reservoir f lu ids. e is the cri tica l point.

Petroleum Reservo ir F lu ids 7

Table 1-2Typ ical Molar Composit lons o f Pet ro leum Reservo lr F lu ids

Gas Volatile BlackComponent Gas Condensate 011 OilN2 0.3 0.71 1.67 0.67e 0 2 1.1 8.65 2.18 2.11e , 90.0 70.86 60.51 34.93e 2 4.9 8.53 7.52 7.00e 3 1.9 4.95 4.74 7.82e . +n 1.1 2.00 4.12 5.48e s i+n 0.4 0.81 2.97 3.80C, +n 6+: 0.3 0.46 1.99 3.04e 7 0.61 2.45 4.39e a 0.71 2.41 4.71e 9 0.39 1.69 3.21e l O 0.28 1.42 1.79e l l 0.20 1.02 1.72e ' 2 0.15 12+: 5.31 1.74c., 0.11 1.74c., 0.10 1.35c., 0.07 1.34c., 0.05 1.06e l ? 17 +: 0.37 1.02c., . 1.00c., 0.90e 20 20+: 9.18

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ally gas and l iquid) are found. Outside the phase envelope only one phase(usually gas or liquid) exists. Coming from the single phase region, the phaseenvelope represents the conditions where the first trace of a second phasemay be observed. The phase envelope consists of a bubble-point branch anda dew-point branch separated by the critical point, C. The bubble-pontbranch is the one at the lower temperature and higher pressure. At the bub-ble-point branch the newly formed phase can be seen as a gas bubble. Whenreaching the dew-point branch from the single-phase region the first sign ofa second phase will be the formation of a liquid drop. The bubble pointbranch lies between the two-phase region and the single-phase liquid re-gion. Similarly, the dew-pont branch is bounded by the two-phase regionand the s ingle-phase gas region. At the cri tical point, two identi cal phasesare in equilibr ium. In the near cri tical two-phase region, the two phases inequilibr ium are almost identical. In the near critical single phase region it ishard to tell whether the phase is a gas or a liquid, and the expression su-percritical Huid is often used. The point in Figure 1-2 marked by Tres, Pros

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8 Properties o f Oi ls and Natura l Gases

represents typical reservoir conditions. At those conditions the gas is singlephase gas, and so i s t he gas condensate. The volatile oil and the black oil areboth single phase liquids. I f a t constan t temperature the pressure is reducedas indicated by a vert ical line in Figure 1-2 the gas wil l remain single phasegas. Al iquid phase wil l a t some stage prec ip itate f rom the gas phase, but thel iquid phase wil l disappear i f the pressure is further reduced . Precipitationof a liquid phase from a gaseous mixture as a resuIt of a reduced pressure iscalled retrograde condensation. The pressure interval where two phases ex-ist is called the retrograde reg ion . When the pressure is reduced, a secondphase isa lso formed at some stage f rom a volat ile oi l, and from a black oil.The second phase isa gas phase, and contains prmarily lighter components.In a black oil some of the mixture components are so heavy that they willremain in a liquid form even at very low pressures.

The highest temperature at the phase envelope of a given mixture iscalledthe criconden therm, and the highest pressure is called the cricondenbar.

HYDROCARBON FRACT IONS

While the lighter constituents of petroleum reservo ir fluids are well-de-fined ind ividual components, the heav ier (C7 +) hydrocarbon fractions aremixtures of different components. Each carbon number fraction representsthe hydrocarbon mixture having i ts normal boiling point within a giventemperature interval ; the carbon number cIassifica tion is just used for con-venience. As is seen from Table 1-1, hydrocarbons of a d if ferent chemcals tructure but with the same number of carbon atoms may have very differ-ent normal boiling points. A carbon number fraction in Table 1-1 may,therefore, contain hydrocarbons with varying numbers of carbon atoms.From molar compositions like those given in Table 1-2 it isnot possible to tellwhether the components of a given C7+-fract ion are main ly paraff inic (P),naphthenic (N), or aromatic (A) components. As described in Chapter 2,components < ClO may be quantitatively identif ied. A PNA-analysis maygive a rough idea of the dominant molecular structures within the heavierhydrocarbon fractions. Aromat ics have a lower molecular weight than theparaf fins and the naphthenes with the same number of carbon atoms. Paraf-fins and naphthenes on the other hand have a lower density than the aro-matics with the same number of carbon atoms. Measurements of the aver-age molecular weight and the density of each hydrocarbon fraction are,therefore, of great significance in the characterization procedure (see Chap-ter 7), which is performed in order to simulate the propertes of a given pe-troleum reservoir fluido

Petroleum Reservoir Fluids 9

RESIDUE

The plus fractions of the petroleum mixtures of Table 1-2 consist of thehydrocarbons with a normal boilng point above a certain temperature. Theusual technique for separating heavy hydrocarbon fractions is a TBP-distil-lation as descr ibed in Chapter 2. The d isti llat ion process cannot always becontinued untillOO % of the petroleum mixture is distilled off. At some stagein the process, the tempera tu re may have risen to a leve where a furthertempera tu re r ise wil l cause cracking of the remaining molecules. The tern-perature where the distillation process isstopped depends on the distillationpressure and the sample quantity. This is reflected in the examples on com-positional data given in Table 1-2 where the last hydrocarbon number frac-t ion var es from C5 to C19 Components as heavy as Cs o may be present inthe TBP-resid~e at a concentra tion that inf luences the overall behavior ofthe reservo ir f luido The average molecular weight and the density of theTBP-residue may be measured, and this is importan t information used in thecharacterization procedures described in Chapter 7.

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Chapter 2Compositional DeterminationsFor oil and gas mixtures , the phase behavior and physical propert ies such

as densities, viscosities, and enthalpies are uniquely determined by the stateof the sys tem, i.e., the temperature, pressure, and the composition. In sirnu-lating the phase behavior and physical properties of complex hydrocarbonmixtures accurately, i t is necessary to have detai ed and accurate cornposi-tional information for each mixture.

GAS CHROMATOGRAPHY AND TBP DISTILLATIONTradit ionally, composit ional data in the oil industry have only been re-

ported to C7 +, the compositional information being mainly based on lowtemperature fractionate distillation data. This level is inadequate for accu-rate modeling ofthe phase equilibrium and physical properties ofthe hydro-carbon mixtures.

In recent years , new methods have been developed for exper imental ly de-termining the composition of hydrocarbon mixtures. These methods yield afar more accurate and detai led descript ion of the hydrocarbon systems andare described in this chapter.

Gas ChromatographyThe appearance of capil lary columns has enabled separation and quanti-

fication of many more individual components than prevously possible.The compositional description of the reservoir fluid isdone by analyzingseparately samples of the gas and liquid phases, which when recombined inthe correct gas to l iquid ratio will yield the reservoir f luid composition. Thecomposit ional description of the gas phase is carried out in one step: N2 ,CO2, CI-CIO by capil lary column chromatography. The liquid phase com-positional descript ion iscarr ied out in two steps:

1. To CIO+ using capillary columnchromatography.2. From ClO to C20+ using a mini distillation apparatus.10

Compositional Determinations 11

Gas Phase AnalysisA typical natural gas chromatogram isshown in Figure 2-1, obtained us-

ing a Hewlett Packard 5880 gas chromatograph (Figure 2-2).

ou ot-- ; :-, -;~ ~~.. J Z t--Z t--;oUt-- A

65 7 8

1112 16 18

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1

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Zt--t--

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e Figure 2-1. Typical chromatogramand column configuration. Peaknumbers correspond to calibrationnumbers given in Table 2-1.The an-alytical conditions for the organicand inorganic analyses are given inTables 2-2 and 2-3, respectively.From Osjord and Malthe-S0rens-sen, 1983, reprinted from the Jour-nal of Chromatography.

A - - 1 PORAPAKR HMOLSIEVE13X~B

e -jSPLlT 1: 1 00 HWCOT CP S IL51--8The chromatographic separation of oxygen, nitrogen, carbon dioxide,

and approximately 60hydrocarbons from C to CIO+ was achieved by usinga combination of packed and capillary columns. The sample was injectedva two time-programmed loops into packed and capilla ry columns withthermal conductivity and flame-ionization detection. The packed columnswere molecular sieve 13X, Porapak R, and the capillary columns wereChrompack Sil 5 (fused silica). The hydrocarbons were analyzed by split in-jection using the capillary column, and temperature programming startingat 30C, and the permanent gases were analyzed isothermally a t 50C us-ing the packed column in a special compartment outside the main oyen.

III

t


12/132

12 Propert es 01 Ols and Natural Gases

------- -- ~-~~_1'::,,;J:iit'*

Figure 2-2. Hewlett Packard 5880A chromatograph. M.ulti-column rigged for one-step gas analysis.

Through an elaborate cal ibration program, most of the individual com-ponents have been identified. Table 2-1 shows a resulting list of componentsand the quant ity of each component (mole fraction) present in the samplecorresponding to Figure 2-1. Detai ls about the analyses are given in Tables2-2 and 2-3.

This informat ion is usually too deta iled for practical purposes, so thecomposi tiona l informat ion is regrouped. In the present sample , the re-grouped gas phase analysis can be either that shown in Table 2-4 or Table 2-5. Both examples of regrouping will yield satisfactory descriptions of the gasphase composition.

Liquid Phase AnalysisThe liquid hydrocarbon phase, i.e ., the oi l, is a much more complex mix-

ture than is the gas phase. Many more components appear in a typical gaschromatogram ofan oil asshown in Figure 2-3 (Osjord et al., 1985). Consid-erable overlapping ofthe peaks at the higher carbon numbers occurs, whichmakes good quantitat ive determination of the heavercomponents impossi-ble from the gas chromatogram alone.

I U IC IIU Il t l >-iiie..,;:CI D'OC IIelni..C II~aQ ..; EC\I ni

C I I c n:a UI ~iii..:-iZni-t::oioa.Eoo

~s:CI~

W -. . oocnOT (\ JNNNNC )C )C )

Compostonal Determnations

VCOC\ J COCDCOO(() VO - . . C\ J O l, , , , t r i C \ i t r i u : i c x i ' : ' : 6 t r i , , , C \ iCX:>CO , , , , , , , ' T~NI , {)l OVN DO>LOVC\J O >O>O> -.>. ~-...c:..c ..c:-Q5Q) .Q~E E u u

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14 Properties of Oils and Natural Gases

Q).o~VIOle'ceQ)~ .S: E ' o

O . Q)-ijl ~:E c S:E ~:t ~~t:J oE ro ro LOe -.;;:::::ou >1ija.. ,.- ID8~EC'loC._ .. ():'c o1:g 8 E ~ O :; (,Q e : Uj ~ ~ ~ ~ ~ ~~I cu~c. . woT Q) Ero Ol~ S ~ :i c.EQ)_cnQCUU 0)_ .u.cu1'Q;(/)~c'@$oQj~Q) Clo ; 0.'.:':= s t sg ; ~ ~ E g ; ~ '5 . '5 . ~ . .I-LL~~I-CfJCfJCfJ~EI~l ) oE f ea QIl. O Oleo.EroCfJ

s,.f: &. E ~E 2- D :: E

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14/132

16 Ptoperties 01 Oil s and Natural Gases

jected is 0.1 mI with a split ratio of 1:100. The effluent detector is a flameionization type (FID). Further details of the analytical conditions are givenas follows:

Analyt ical Condi tions for Liquid Phase GC AnalysisColumn: Type: fused silica capillary

Liquid phase: Chrompack CP Sil 5Carrier gas: He, = 22 cm/sLength: 50 mInside diameter: 0.23 mmFilm thickness: 0.4 ,tm

Detector: Type: flame ionizationFuel gas: H2, 30 mlminMake up gas: N2, 30 mlminTemperature: 350C

Sampling: Syringe: Hamilton 7001 NSample size: 0:1-0.5 ,tI

Injector: Type: split injectorRatio: 1:100Liner: packed Jennings tubeTemperature: 300C

Oyen: Type: temperature programmedInitial value: + 10C, 2 minRatel: 3/min -> ll5CRate 2: lOo/min -> 300CFinal value: 300C, 60 min. Total time: - 2h

Source: Osjord et al., (1985).

Toproperly quantify the individual components, an internal s tandard ofknown quanti ty isadded to the sample. In this way one may compensate forcolumn losses that are known to occur from carbon numbers of 15 andhigher. The component used as the internal standard is iso-octane, which isnormally not present in naturally occurring oils.

As for the gas sample analysis, a calibration program enables thoroughidentification and quantification of the components present between C2 andCg . Table 2-6 shows a typical example of such an analysis. This detailed ananalysis up to C10+ is normally not needed in practice. Therefore, a regroup-ing of components may be carried out as shown in Table 2-7.

Compostonal Determnatons 1 7Table 2-5

Regrouped Composition of Separator Gas(Corresponds to the Analysis in Table 2-4)

1,,1

Component Mole %Nitrogen 0.66Carbon dioxide 5.65Methane 68.80Ethane 12.86Propane 7.94;-Butane 0.94n-Butane 1.96;-Pentane 0.34n-Pentane 0,42Hexanes 0.22Heptanes 0.15Octanes 0.05Nonanes 0.00Decanes plus 0.00r: 100.00Gas Molecular Weight 23.69

:1 In addition to the weight f ract ions of the collective groups such as theC/s, one may from such a detailed starting point calculate average rnolecu-lar, weights, average density, critical properties, and PNA distributions foreach of the groups up to C10+' See Tables 2-8 and 2-9.Identification of the components in the range CIO to C20on the basis of thechromatogram in Figure 2-3 is seen to be impract ical. Hence the liquidphase analysis is extended beyond CIO+ by a distillation technique.

1,

i~t

Liquid Phase Analysis from CIO to C20+

A mini-dstillation apparatus isshown in Figure 2-4. It is an adaptation ofthe commercially available Fischer HMS 500 automated rnn-dstllatonsystem. The required sample volume isabout 100mI. The distillation proce-dure used is a modifica tion of the ASTM D-2892 procedure for true boilingpoint (TBP) dstllton. The purpose of the mentioned modifications is tonarrow the distillation cut temperatu re ranges so that they correspond tothose of Katz and Firoozabadi (1978).

The distillation procedure results inan analysis as shown in Table 2-10,where the analysis up to C IO is carried out at atmospheric pressure. From CIOto C20+, the distillation is carried out at a vacuum of 20 mm Hg to reducethe temperature level and avoid thermal cracking of the sample.

t-; 1111


15/132

18 Properties o] Oils and Natura l Gases

u~ ---1j~ ~: ~~\ ~ -- -,= ---.3~=~~.,:J' E., '~E Cl., e>- Q u~_31~

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Compositional Determinations 19Table 2-6

Individual Component Report(Peak Numbers Correspond wi th Chromatogram in F igure 2-3 ) .,,~ , t 1':~\I~'< ;:; tl /~ ,Molec- LiquidWeight Mole Volume ular DensityPeak Component % % % Weight (g/cm3)

1 C2 0.007 0.058 0.017 30.070 0.35802 C3 0.072 0.412 0.122 44.097 0.50763 te, 0.051 0.222 0.078 58.124 0.56334 o-e, 0.189 0.816 0.276 58.124 0.58475 2,2-0M-C. 0.000 0.000 0.000 72.151 0.59676 -c, 0.188 0.653 0.257 72.151 0.62467 n-Cs 0.285 0.991 0.386 72.151 0.6309O Light end total 0.792 3.152 1.137 63.092 0.59648 2,2-0M-C, 0.012 0.034 0.015 86.178 0.65399 cv-c, 0.052 0.185 0.059 70.135 0.7502

10 2,3-DM-C, 0.028 0.081 0.036 86.178 0.666211 2-M-Cs 0.165 0.480 0.214 86.178 0.657712 3-M-Cs 0.102 0.298 0.131 86.178 0.668813 n-C6 0.341 0.993 0.440 86.178 0.6638

O Hexanes total 0.699 2.071 0.895 84.745 0.668714 M-CyCs 0.231 0.689 0.262 84.162 0.753415 2,4-0M-Cs 0.015 0.038 0.019 100.205 0.677116 Benzene 0.355 1.140 0.343 78.114 0.884217 Cy-C6 0.483 1.440 0.528 84.162 0.783118 2-M-C6 - 0.000 0.000 0.000 100.205 0.682966 1, 1-0M-Cy-Cs 0.116 0.298 0.131 98.189 0.759019 3-M-C6 0.122 0.307 0.152 100.205 0.691520 1, cis-3-DM-Cy-Cs 0.000 0.000 0.000 98.189 0.749321 1, trans-3-DM-Cy-Cs 0.052 0.133 0.059 98.189 0.753222 1, trans-2-DM-Cy-Cs 0.048 0.122 0.054 98.189 0.755925 n-C7 0.405 1.014 0.504 100.205 0.6880

O Unspecified C7 0.171 0.427 0.215 100.205 0.6800O Heptanes total 1.997 5.609 2.267 89.426 0.7542

26 M-Cy-C6 0.918 2.348 1.016 98.189 0.773727 1, 1, 3-TM-Cy-Cs 0.027 0.061 0.031 112.216 0.752628 E-Cy-Cs 0.000 0.000 0.000 98.189 0.770829 2,2,3-TM-Cy-Cs 0.042 0.093 0.050 114.232 0.720030 2,5-DM-C6 0.018 0.039 0.022 114.232 0.697731 2,4-0M-C6 0.000 0.000 0.000 114.232 0.704532 3,3-0M-C6 0.026 0.057 0.031 114.232 0.714133 1, trans-2, cis-3-TM- 0.025 0.056 0.028 112.216 0.7579cvc,34 Toluene 0.958 2.610 0.941 92.143 0.871435 1, 1, 2-TM-Cy-Cs 0.000 0.000 0.000 112.216 0.776936 2,3-DM-C6 0.033 0.073 0.040 114.232 0.716337 2-M-C7 0.137 0.300 0.167 114.232 0.701938 3-M-C7 0.094 0.206 0.113 114.232 0.709939 1 , c is-3-DM-Cy-C6 0.190 0.425 0.211 112.216 0.770140 1, trans-4-DM-Cy-C6 0.072 0.162 0.081 112.216 0.7668

(table continued on next page)


16/132

2 Prop'erties of Oil s and Natural Gases

Table 2-6Continued

Molec- LiquidWeight Mole Volume ular Density

Peak Component % % % Weight (g/cm3)42 Unspecilied 0.028 0.062 0.031 112.216 0.7700

naphthene42 Unspecilied 0.013 0.028 0.014 112.216 0.7700


naphthene43 OM-Cy-C6 0.031 0.069 0.034 112.216 0.770044 1, trans-2-0M-Cy-C6 0.089 0.199 0.098 112.216 0.779945 n-Ca 0.434 0.954 0.526 114.232 0.7065

O Unspecilied C, 0.086 0.190 0.105 114.232 0.7000O Octanes total 3.231 7.957 3.551 101.978 0.7791

46 Unspecilied 0.047 0.094 0.051 126.243 0.7900naphthene

47 2,2-0M-C7 0.009 0.018 0.011 128.259 0.714448 2,4-0M-C7 0.017 0.033 0.020 128.259 0.719249 1, cis-2-0M-Cy-C6 0.024 0.054 0.026 112.216 0.800350 E-Cy-C6 + 1, 1, 0.281 0.599 0.305 118.000 0.79003-TM-Cy-C651 Unspecilied 0.047 0.093 0.051 126.243 0.7900

naphthene52 3,5-0M-C7 0.017 0.034 0.020 128.259 0.726253 2,5-0M-C7 0.003 0.006 0.004 128.259 0.720854 Ethylbenzene 0.114 0.270 0.112 106.168 0.871468 Unspecilied 0.027 0.054 0.029 126.243 0.7900

naphthene55 m- + p-xylene 0.697 1.649 0.687 106.168 0.86.8356 4-M-Ca 0.020 0.039 0.024 128.259 0.724257 2-M-Ca 0.054 0.106 0.064 128.259 0.717358 Unspecilied 0.009 0.018 0.010 126.243 0.7900


naphthene58 Unspecilied 0.007 0.014 0.008 126.243 0.7900naphthene59 Ortho-xylene 0.230 0.545 0.223 106.168 0.884460 3-M-Ca 0.023 0.045 0.027 128.259 0.724261 1-M,3-E-Cy-C6 0.078 0.155 0.083 126.243 0.800062 1-M,4-E-Cy-C6 0.034 0.068 0.037 126.243 0.790063 Unspecilied 0.006 0.013 0.007 126.243 0.7900


naphthene64 n-Cg 0.471 0.923 0.559 128.259 0.7214

O Unspecilied Cg 0.124 0.243 0.148 128.259 0.7200O Nonanes total 2.427 5.241 2.598 116.277 0.7995

Source: Osjord el al. (1985).


Tab le 2-7Gas Co mp on en ts an d Boi li ng Po in t Grou ps u p t o C10+ from CapillaryGC-Analysis

l11

1 111

1::1

.1- 1ILiquid

Molecular DensityComponent Weight % Mole % Volume % Weight (g/cm3)

C, 0.000 0.000 0.000 16.0 0.260C2 0.007 0.058 0.017 30.1 0.358C3 0.072 0.412 0.122 44.1 0.508ic, 0.051 0.222 0.078 58.1 0.563n-C. 0.189 0.816 0.276 58.1 0.5852,2-0M-C3 0.000 0.000 0.000 72.2 0.597te, 0.188 0.653 0.257 72.2 0.625e, 0.285 0.991 0.386 72.2 0.631Hexanes total 0.699 2.071 0.895 84.7 0.669Heptanes total 1.j:l97 5.609 2.267 89.4 0.754Octanes total 3.231 7.957 3.551 102.0 0.779Nonanes total 2.427 5.241 2.598 116.3 0.799Oecanes & 90.853 75.971 89.553 300.3 0.868

heavier 11 I1 1

ISource: Osjord e l a l. (1985).

Table 2-8Dis tr ibut ion of Weight, Mole, an d Volume i n a Cr ude Oi l Sample,

from Capillary GC-AnalysisLiquid

Molecular DensityComponen Weight % Mole % Volume % Weight (g/cm3)

Gas components 0.792 3.152 1.137 63.1 0.596Hexane group 0.699 2.071 0.895 84.7 0.669Heptane group 1.998 5.612 2.263 89.4 0.756Octane group 3.231 7.957 3.551 102.0 0.779Nonane group 2.427 5.241 2.598 116.3 0.799Oecane group 2.483 4.666 2.654 133.6 0.801Undecane group 2.239 3.799 2.388 148.0 0.803Oodecane group 2.569 3.994 2.709 161.5 0.812Tridecane group 3.127 4.479 3.238 175.3 0.827Tetradecane group 3.153 4.172 3.214 189.8 0.840Pentadecane group 3.988 4.890 4.041 204.8 0.845Hexadecane group 3.417 3.937 3.438 217.9 0.851Heptadecane group 4.286 4.577 4.355 235.1 0.842Octadecane group 3.060 3.076 3.099 249.8 0.845Nonadecane group 3.749 3.604 3.756 261.2 0.854Eicosane plus 58.781 34.772 56.664 424.5 0.888

Apparent average molecular weight: 254.0Moiecular weight corrected lor benzene: 251.1Measured density (g/cm3) 15C, 1 at m: 0.856

Source: Osjord el al. (1985).


17/132

22 Propert ies 01Oil s and Natural Gases

Table 2-9PNA Report

Paraffinic, Naphthenic, and Aromatic Contents of the Boili ng PointGroups up to n-Cg

Molecular DensityComponent Weight % Mole % Volume % Weight (g/cm3)

Hexane group 0.647 1.886 0.836 86.2 0.663paraffins

Hexane qroup 0.052 0.185 0.059 70.1 0.750naphthenesHeptane group 0.713 1.787 0.889 100.2 0.686

paraffinsHeptane group 0.930 2.682 1.034 87.1 0.769

naphthenesHeptane group 0.355 1.140 0.343 78.1 0.884

aromaticsOctane group 0.870 1.912 1.054 114.2 0.707

paraffinsOctane group 1.404 3.435 1.556 102.6 0.772

naphthenesOctane group 0.958 2.610 0.941 92.1 0.871

aromaticsNonane group 0.739 1.446 0.877 128.3 0.721

paraffinsNonane group 0.646 1.331 0.699 122.0 0.792

naphthenesNonane group 1.042 2.464 1.022 106.2 0.872

aromaticsSource: Osjord el al. (1985).

Table 2-11 compares compositnal data obtained by gas chromatographyand by dist il lation. There is generally sat is factory agreement. One advan-tage of the analysis by dist illation is, however, that it produces a physica lsample of each hydrocarbon fract ion present in the oil sample.

PROPERTIES OF HYDROCARBON FRACTIONSFor the hydrocarbon fractions (such as CIl), and the residue (e.g., Czo +),it is important not only to know their weight fraction, but also their physical

properties such as densities, molecular weights , and PNA dis tr ibutions.These properties will be different for each oil and may thus help to dist in-guish an oil of one reservoir from that of another reservoir.

Figures 2-5 and 2-6 show plots of the dens ity vs. carbon number for sev-eral North Sea oil samples. There are significant differences in the density

,.I

11,


vs. carbon number profiles, corresponding to different PNA distributions.This i s in agreement with observations by Yarborough et al. (1978).

Similarly, Figure 2-7 shows the molecular weight vs. carbon number forseveral dif ferent oil samples. As observed by Katz and Firoozabadi (1978),the average molecular weights of the hydrocarbon fractions are not signifi-cantly different for the different oils. This can be explained by the fact thateven though the individual molecular structures within each hydrocarbonfraction may vary considerably, from n-paraffins to isomers to cyclic struc-tures, their molecular weights wiJI not be very much different. Differentstructures within a given hydrocarbon fraction have very similar ratios ofhydrogen atoms to carbon atoms, and hence the molecular weights are alsosimilar.lt is t hus feasible to use general, average molecular weights for the frac-tions from Cg to C19. The average values of the molecular weights of Figure2-7 and the average densities of Figure 2-5 are shown in Table 2-12.

Unlike Katz and Fi roozabadi, general, average density values for eachfraction are not used. As shown in Figure 2-6, the density vares considera-bly with the structure (PNA distribution) of the hydrocarbon fraction.

Figure 2-4. Fischer HMS 500 mini-distillation equipment modified for continuousdisti llat ion of crude oils.


18/132

24 Properties 01 Oils and Natural Gases

Q)

~cQ)CcoUCQ)~:ceao

' ;' e aNQ) o c.c O l-.:~- .:. lea ..

ID1-E~-

e~u U) + +t ctj U) W , .. a 01 ~ ~ :: ~ ~ : ~ ~ ~ -~ ~ ~u. Cl

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~Q) I ON~~_C' ) O~orow_~ro_C' ) oC' )E ,,,,:~'


19/132

26 Properties o] Oils and Natural Gases0.900.890.880.870.860.85fI )2 0.84U

0- 0.83-r- 0.81(/)Z 0.80wO 0.790.780.770.760.750.74 .8

0.980.96

ifll i 0.94< . - ; :; tf-;.;;:r.,r-------/G/ '--/'---,7 .,' .s :: /,./ //.~/ -------------_ ._ '//' '' '' ..-........///'- -

Aromatic OilsMedi um Paraffinic OilsParaffmic OilsAromatics~~e .h - ~I :':' _Katz & Firoozabadi---------

0.76I I I I I I I I I I I I I I I I I I I I I I9 10 11 12 13 14 15 16 17 18 19 2 0 21 2 2 2 3 24 2 5 26 27 28 29 30C AR B ON N UM B ERFigure 2-6. Density profi les of North Sea oils and condensates.

400380360~ 340O~el 320'S ...

el 300':' - - .~ 280elW 2603: 240o:::j 220'::>o 200~O lBO~ 160

140

~//::~./// // . '/ // .//~


20/132

28 Propert ies 01Oils and Natural Gases

~ 91220_ ;......~k~.J ;tU 8YT MTI


21/132

30 Properties o] Oils and Natural Gases

INTERNAL CONSISTENCY OF ANALYTICAL DATATo this point, most of the analytical data from the gas chromatographic

measurernents and all of the data from the di stillation are available in termsof weight fractions. The molecular weights, therefore, play an importantrole in converting the weight fractons to mole fractions. The molecularweight of the residue is especially important.

The previo LIS section indicates that the molecular weight measurement isdffeul to perform. Often relatively large errors are associated with experi-mentally determined molecular weights. Fortunately, when a distillationanalysis has been performed, it is possible to check the reported weight frac-tions and associated molecular weights of components, hydrocarbon frac-tions, and residue, for consistency. Only an additional measurement of themolecular weight of the whole oil sample is required. .

For example, an analysis by distillation of an oil sample results in the in-formation shown in Tables 2-13 and 2-14. In order to check the consistencyof the reported C20 + molecular weight, the average molecular weight of thewhole sample is calculated as follows:

M W ~ ( ~ w, I M W , J -' (2-1)where w, is the weight fraction and MW the molecular weight of fraction i.

This value may be compared with a measured mean molecular weight forthe whole oil sample. The analysis data are considered internally consistent

Table 2-13Measured and Calculated Molecular Weights and Densities from

Nor th Sea Gas CondensateCondensate c-. c-.Measured molecular

weight (MW) 111 175 319ealculated MWusing elO+ MW 111

ealculated MWusing e20+ MW 111 175Measured density (g/cm3) 0.756 0.825 0.891ealculated densityusing elO+ density (g/cm3) 0.752

ealculated densityusing e20+ density (g/cm3) 0.752 0.826

111'-, ~

1'1:l'),1,

IIII

Compositional Determinations 31if the two values ofoilsample average molecular weights agree to within 2-3 molecular weight units.

In addition, one may back-calculate the values of CI + and C20 + molecu-lar weights, which also must agree closely with the experimentally observedvalues for Co+ and C20+.The average densi ty of the oil sample, p, can also be calculated from thedata for the fraction given in Table 2-14 as follows:

p = E w / E w/p (2-2)Table 2-14

Data for Comput ing Table 2-131 2 3 4 5 6

DensityComponent Weight % MW Mole % g/cm3Gas 4.19 54.8 8.52 4.7 0.~64 7.4es 6.78 72.2 10.45 7.5 0.628 10.8e6 7.97 84.8 10.46 8.8 0.668 11.9e7 15.18 91.5 18.46 16.8 0.738 20.6es 17.05 104.3 18.19 19.0 0.763 22.3e9 9.81 119.0 9.18 10.9 0.783 12.5(elO+) (39.01) . (175) (24.74) (43.3) (0.825) (47.3)elO 7.48 133 6.28 8.4 0.796 9.4el1 5.82 145 4.46 6.5 0.796 7.3e, 4.39 158 3.10 4.9 0.809 5.4c., 4.21 171 2.74 4.6 0.820 5.1c., 3.43 183 2.09 3.8 0.830 4.1c., 2.73 197 1.54 3.0 0.837 3.3c., 1.78 210 0.94 2.0 0.848 2.1c., 1.92 226 0.95 2.1 0.845 2.3c., 1.49 241 0.69 1.7 0.845 1.8c., 1.36 250 0.61 1.5 0.854 1.6e20+ 4.42 319 1.54 4.9 0.891 5.0E 100.00 100.00 111.1 132.9

Colurnn 3 is obtained by: (column l/column 2)/E(col umn l /column 2)Colurnn 4 is obtained by: column 2 x column 3/100Colu rnn 6 is obtained by: c olumn l /co lumn 5ealcu la ted MW using elO+ MW = (4.7 + 7.5 + 8.8 + 16.8 + 19.0 + 10.9 + 43.3) = 111.0Calculated MW u sing e20+ MW = 111.1 (see table)ealculated MW 01 the elO+ Iraction using e20+ MW = 100(8.4 + 6.5 + 4.9 + 4.6 + 3.8+ 3.0 + 2.0 + 2.1 + 1.7 + 1.5+ 4.9)/24.74 = 175ealculated density using elO+ density = 100/(7.4 + 10.8 + 11.9 + 20.6 + 22.3 + 12.5+ 47.3) = 0.752 g/cm3ealculated density using e20+ density = 100/132.9 = 0.752 g/cm3


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32 Propert ies 01Oils and Natural Gaseswhere wis the weight percent of component i and p the density of compo-nent or f raction i.

Again, the calcula ted and measured average oil densi ties should agreeclosely.

Determination of Reservoir Fluid CompositionThe reservoir fluid arriving from the well to the platform isseparated into

a separator l quid and a separator gas a t pla tform separator tempera-ture Tp and pressure Pp' The separator liquid is in turn flashed at ambientconditions (T; and Po) in the laboratory. The principle ofthe two stage flashseparation is shown in Figure 2-11. The pracedure is described in more de-tail in Chapter 3.

The reservoir fluid composition is obtained by combining the analyses ofthe laboratory gas and the stock tank oil, from which the composition of theseparator liquid is determined. The analysis of the separator liquid isin turncombined with the analysis of the separator gas to yield the composition ofthe reservoir fluid (or well stream).

To recombine the previously mentioned analyses correctly, it is necessaryto know the gas-to-liquid ratio, the so-called gas/oil ratio (GOR), both atpla tform and at ambient condit ions. In Chapter 3 i t i sshown how to mea-sure gas/oil ratios in the laboratory. The princple ofthe flash experiment i sshown in Figure 2-11. An example of such data i sgiven in Table 2-15.

Figure 2-11. Principie of two-stageflash of well stream.Gas

Oilr, PpFirst Stage(separatorconditions)

I . Gas~r,Po f-------Oil

FeedSecond Stage(ambientconditions)

.d li

Compostonal Determinatons 33Table 2-15

Composition Analyses, Gas/Oil Ratios, and Formation Volume Factors ofSeparator FluidsStock Tank Stock Tank Separator

Oil Gas GasComponent Mole % Mole % Mole %

Nitrogen 0.00 0.20 0.66Carbon dioxide 0.00 3.96 5.65Methane 0.00 24.86 68.80Ethane 0.20 20.40 12.86Propane 2.14 28.42 7.94;-Butane 1.10 4.78 0.94n-Butane 4.25 10.97 1.96;-Pentane 2.68 2.21 0.34n-Pentane 4.32 2.53 0.42Hexanes 6.66 1.05 0.22Heptanes 11.90 0.54 0.15

. Octanes 13.14 0.10 0.05

. Nonanes 7.73 0.00 0.00Decanes plus 45.89 0.00 0.00E 100.00 100.00 100.00

Gas/oil ratio at separator, GORo = 442 Sm3/m3 separator oilGas/o il rat io a t ambient f lash, GORo = 36.9 Sm3/m3 s tock tank o ilFlash lormation volume lactor 01 separator liquid = 1.165 m3/m3 s tock tank o ilAverage molecular weight 01 the s tock tank o il = 160.4 kg/mole

Basis for the recombination can be, e.g., 1 std m'' of stock tank oi . Thetotal number of moles of each component (or f raction or residue) in this stdrn'' ofs tock tank oil is calculated. The molar volume of an ideal gas at atmo-spheric pressure and OC equals 22.4 m'. The total individual number ofmoles of gas sample corresponding to 1 std m3 of liquid sample may be ob-tained fram:

Moles gas = GOR/ (22.4 x T0/273) (2-3)where GOR is either GORp or GORo [platform (field), or ambient condi-tions, respectively]. From the moles of gas plus the composition of the gassamples, the amounts of individual gas-phase components in both gasstreams can be determined.


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34 Properties 01 Oil s and Natural GasesFinally, the total number of moles of each component from the test sepa-

rator phases are added (seeFigure 2-11) and normalized to yield the compo-sit ion of the recombined fluid, i.e., the fluid in the reservoir .

Example: Recombination of Stock Tank Oil, Stock Tank Gas, and SeparatorGas. Areservoir fluid isflashed at the field separator, and the separator liq-uid is flashed to ambient conditions in the laboratory, yielding a stock tankliquid and an evolved gas. The composition analysis and other experimentalinformation are given in Table 2-15.

From that information, first compute the number of moles in each of thestreams. As a basis, 1 m3 of stock tank oil is chosen.Moles stock tank oil = 860 kg/160.4 kg/mole = 5.36 molesMoles of evolved gas = 36.9 m3/(22.4 moles/m- x 288K/273K)

= 1.56 molesThe volume of gas (Sm3) per 1 rrr' stock tank oil is 442 x 1.165 = 515 Sm3

The number of moles of separator gas is thus:515/ (22.4 x 288/273) = 21.79 moles

The to tal numbe r of mole s of the re servo ir f lu id per m3 stock tank oil isthus:5.36 + 1.56 + 21.79 = 28.71 molesThe number of moles of each component in each stream may now be com-puted by multiplying the mole % given in the compositional analysis by thetotal number of moles in each stream and dividing by 100. The resul ts areshown in Table 2-16.

Finally, the number of moles of each component in the reservoir f luid isobtained by adding the number of moles in each stream:Moles of n-pentane in the reservoir fluid = 0.2316 + 0.0395 + 0.0915

= 0.3626 molesThe mole % of n-pentane in the reservoir fluid = 0.3626 x 100/28.71

= 1.26 mole %The final molar composition of the reservoir fluid is shown in Table 2-17.

ir;

',..ft : ;i -t i:6 10' '

.~jf',y ,~

Compositional Determinations 35Table 2-16Number of Moles of Each Component in Each Separator Stream

Stock Tank Stock Tank SeparatorComponent Oil Gas Gas

Nitrogen - 0.0031 0.1438Garbon dioxide - 0.0618 1.2311Methane - 0.3878 14.9915Ethane 0.0107 0.3182 2.8022Propane 0.1147 0.4434 1.7301i-Butane 0.0590 0.0746 0.2048n-Butane 0.2278 0.1711 0.4271i-Pentane 0.1436 0.0345 0.0741n-Pentane 0.2316 0.0395 0.0915Hexanes 0.3570 0.0164 0.0479Heptanes 0.6378 0.0084 0.0327Octanes 0.7043 0.0016 0.0109Nonanes 0.4143 - -Decanes plus 2.4597 - - ; 5.36 1.56 21.79

The recombination computations are normally performed for composi-tions to C JO +. However, for equation of state calculations computations toC 20+ are preferred. The C JO to C 20+ compositions are normally obtained byextending the recombination result using the distil lation data. Using thesedata, the recombined CJO + -fraction is divided into its appropriate ratios upto C20+.

The result at this stage is a well checked, consistent composition analysisof the reservoir fluido

EXPERIMENTAL EXTENSION BEYOND C20+

In some cases (e.g., dew-point calculations) quantitative extension be-yond C20+ is advantageous.

Breakdown of the C20+ fraction may be obtained by distillation, either athigh temperatures (up to 550C) or at low pressures (- 2 mm Hg). This is avery time consuming and difficult analysis, because the process conditionsare not easly controlled.

-ae


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36 Propert ies o f O il s and Natura l GasesTable 2-17

Reservoir Fluid CompositionMoles inReservoir

Component Fluid Mole %Nitrogen 0.1469 0.51Carbon d ioxide 1.2920 4.50Methane 15.3793 53.57Ethane 3.1311 10.91Propane 2.2882 7.97i-Butane 0.3384 1.18n-Butane 0.8260 2.88i-Pentane 0.2522 0.88n-Pentane 0.3626 1.26Hexanes 0.4213 1.47Heptanes 0.6789 . 2.36Octanes 0.7168 2.50Nonanes 0.4143 1.44Decanes plus 2.4597 8.57r; 28.71 100.00

An example of such analysis is given in Table 2-18. The apparatus used isa modified Fischer HMS 500 distillation apparatus (see Figure 2-4) , operat-ing at 2 mm Hg. The analysis time is 2-3 days. By this distillation it is possi-ble to extend the experimental composition analysis to C30+.There is, however, an empirical method ofextrapolating the experimentalC20 + analysis, described in Chapter 7. This method performs well for mostpurposes and thus saves the time-consuming C20 to C30 + analysis.

Compositional Determinations 37Table 2-18Extended Compositional Datafor a North Sea Gas Condensate

fDensity PNA Distribution, Mole %(g/cm3)

Component Mole % 1 atm, 15C MW P N AN2 0.64CO2 9.16C, 68.8C2 8.43C3 5.11ic, 0.81n-C. 1.45te, 0.52n -C, 0.53C6 0.63C7 0.83 0.741 96 0.50 0.42 0.08Cs 0.95 0.780 107 0.45 0.38 0.17C9 0.52 0.807 121 0.48 0.27 0.25ClO 0.26 0.819 134 0.47 0.30 0.23Cll 0.20 0.810 147 0.56 0.27 0.17C'2 0.17 0.828 161 0.55 0.24 0.21C'J 0.16 0.849 175 0.54 0.22 0.24C,. 0.15 0.857 190 0.49 0.27 0.24C'S 0.11 0.868 206 0.52 0.20 0.28C'6 0.086 0.872 222 0.55 0.19 0.26C17 0.078 0.859 237 0.57 0.20 0.23C,s 0.068 0.854 251 0.70 c. 0.11 0.19C'9 0.050 0.866 263C20 0.046 0.873 339 C20+C2, 0.035 0.876C22 0.025 0.876C23 0.034 0.875C2 0.023 0.877C2S 0.017 0.876C26 0.018 0.878C27 0.014 0.882C28 0.012 0.886C29 0.013 0.889CJO+ 0.047 0.908

,1

38 Properties oj Oils and Natural Gases .'


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REFERENCESKatz, D. L., and Firoozabadi, A., Predicting Phase Behavior of Conden-

sate/Crude-Oil Systems Using Methane Interaction Coeffi cients, lournal01 Peto Techn., Nov. 1978, pp. 1649-1656.

Kratky, O., Leopold, H., and Stabinger, H., Density Determina tion of Liq-uids and Gases to an Accuracy of 10- 6 g/cm'', with a Sample Volume ofonly 0.6 cm, Z. angew. Physik, 4, 1969, pp. 273-277.

Leopold, H., Die Digitale Messung der Dichte von Flssigkeiten,Elektronik, 19, 1970, p. 297.Osjord, E. H., and Malthe-Serenssen, D., Quantitative Analysis of Natural

Gas in a Single Run by the Use of Packed and Capillary Columns,' ]. 01Chromatography, 297, 1983, pp. 219-224.

Osjord, E. H., Renningsen, H. P., and Tau, L., Distribution of Weight,Density, and Molecular Weight in Crude Oil Derived from ComputerzedCapillary GC Analyss,' Journal 01High Res. Chrom. & Chrom. Comm.,8, 1985, pp. 683-690.

Yarborough, L., Applicat ion of a Generalized Equation of State to Petro-leum Reservoir Fluds,' Paper presented at the 176th National Meeting ofthe American Chemical Society, Miami Beach, FL, 1978.

l

111' Chapter 3Oil and Gas Property MeasurementsThis chapter describes some ofthe most commonly used methods for mea-

suring densities, viscosities, saturation points, and other properties of reser-voir fluids. I t isnot possible within one chapter to describe all the relevantmethods in detail. An attempt is made, however, to give the reader an un-derstanding of the methods used to collect the data shown in this book.

SAMPLINGHydrocarbon samples to be analyzed for the previously mentioned prop-

erties are normally collected at the first stage (field) separator. Representa-tive samples of both the separator liquid and the separator gas st reams arecollected. Sarnples may 'al so be obtained from the bottom of the well, so-cal led bottom hole samples. These are, however, not very common as theyare only recommended when taken from undersaturated reservoirs.

Before star ting an extensive analysis i t is important to evaluate the aval-able samples and to choose the sample thought to be the most representativefor the reservoir hydrocarbon fluids. Samples obtained during the most sta-ble separator condit ions are normally chosen. In the laboratory, the satura-t ion pressure (bubble point) of the separator l iquid isdetermined at separa-tor temperature. The sample is considered to be representative if thesa tura tion pressure is equal to the test separator pressure at the samplingtime.

The opening pressure of the corresponding gas phase sample may also bechecked. It should be equal to the separator pressure at sampling time.If both of these pressures agree with the value of the separator pressure,further processing of the samples may take place.

FLASH SEPARATION AND COMPOSITIONAL ANALYSISAfter quali ty control, the separator gas sample may be subjected to corn-

positional analysis as described in Chapter 2. The gas sample flask isheated39

\.


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40 Propertes of Oils and Natural Gasesto separator temperature and left to equilibrate. Figure 3-1 shows a typicalapparatus for this purpose. A sample of the gas is bled through a gas sam-pling valve and injected into the gas chromatograph. From the cornposi-tional analysis it is possible to detect whether the sample has been contami-nated with, for example, air.

In order to analyze the separator liquid sample, which has been collectedunder pressure, it must be stabilized to atmospheric condit ions by a singleflash process. The high-pressure sample container is, therefore, connected toa single-stage flash separator as shown in Figure 3-2. The separator liquidsample is thus a llowed to separate into two phases.

The volume ofthe gas phase is determined. The liquid isallowed to settlein the bo ttom of the flash chamber, after which the liquid is drained andweighed, and its density is determined.

The gas/oil ratio of the separator liquid sample, CORo, may now be cal-culated:

CORo = volume gas (Sm3)/volume oil (Sm3) (3-1)where Sm3 means the volume of fluids a t s tandard condi tions, normally15C and one atmosphere.

The composit ion of the gas and l iquid phases may be determined as de-scribed in Chapter 2.

PVT MEASUREMENTSThis section descr ibes the types of PVT measurements (of ten called PVT

analyses) most commonly performed on reservo ir fluids. In order to studythe propert ies of the reservoir fluid, it is necessary to recombine the separa-tor gas and the separator liquid samples. This is done by mixing the twosamples proportionally to their produced rates (CORp).

There are two main types of PVT equipment available: PVT systems forblack oils and PVT sys tems for gas condensates and volatile fluids. These arediscussed separately.

BLACK OIL EQUIPMENTA typical schematic diagram of a black oil PVT.system is shown in Figure

3-3. The main parts of the system are a mercury pump, a calibrated steelcell, a heating bath with silicone oil, and a precision manometer or deadweight gauge. The principle of operation is as follows:

11

t

;l \f/l./

Figure 3-1. Separator gassample f1ask rigged forchromatographic analysis.

:ti~.;

;~'i:

t;

;1'1

Oil and Gas Property Measurements 41

Figure 3-2. Single stageRuska mode l 2353-803flash separator.

----'

42 Propert ie s o f Oi ls and Natura l Gases Oil and Gas Property Measurements 43


27/132

Q )

oCD

1 . H e a t i n g b a t h wi t h s i l i c o n e o i l2. P V T c e l l ( v o l u me n or ma l l y

0.6 - 1.0 1)3 . V a l v e4 . Gr a d u a t e d me r c u r y p u mp5 . P r e c i s i o n ma n o me t e r6 . C e l l e n t r y v a l v e

Figure 3-3 . Schematic d iagram ofblack oil PVT apparatus.

(0

1 . H e a t i ng b a t h - wi t h s i l i c o n e o i l2 . P V T c e l l3 . l s o l a t i n g v a l ve4 . G r a d u at e d me r c u r y p u mp s ( a ) c e l l ( b ) c ha r g i n g5 . P r e c i s i o n m ~o me t e r s6 . C e l l e n t r y v a l v e7 . H y dr o c a r bo n s amp l i n g b o t t l e o r r e c omb i n at i o n c e l l

Figure 3-4. Black oil PVT apparatus rigged for sample transfer.A ready, recombined sample is charged to the cell at cons tant pressure

through valve 6 at the top of the cell. The cell may be equipped with one ormore windows for monitoring the charging and subsequent operations.

The charging process is performed at the pressure in the sample cylinder.Constant pressure ismaintained using the mercury pumps shown in Figure3-4.

:ff). ,\

: ..~

~.. :~.t :1,j


28/132

44 Properties oi Oils and Natural Gases

(1JE:J~

O ne Pha se

V s

P s Pre ssureFigure 3-5. Black oil bubble point determination.

1. Shrinkage factor, Bo. This is a measure of the ratio of the volume ofthe hydrocarbon system at reservoir conditions to the volume at stocktan k conditions:

Bo = res. m ' ol/Sm ' stock tank oil 3 - 22. Solution gas/oil ratio, Rs. This is a measure of the volume of gas in

solution at given pressures (see also Equation 3-8):Rs = Sm3 gas/Sm ' stock tank oil 3 - 3

3. Density of the reservo ir fluid at different pressures, including the satu-ration pressure:

p = kg of Fluid/rn'' (3-4)4. Real gas deviation factor Z, i.e., compressibility factor, for the gasphase at given pressures and temperatures:

Z = PV/nRT (3 -5)where V is the volume and n the number of moles.

A schematic diagram of the differential depletion experiment is shown inFigure 3-6. The equipment is shown in Figure 3-7.

The reservo ir fluid is, at constant temperature, brought to a pressureabove its saturation pressure. After this, the pressure is brought to a value

Oil and Gas Property Measurements 45Gas off AII gas

displacedr . . . . . . Ga s . tr 'i: Gas: > 1 1 1: Gas.:o vN> ' > Oil11 Oil I 11-> Oil >C l t1 11 - ;;;>~ > ro v> Oil >~ I Oilv v>N > DL 1

P 1 - P sat P2 < Psat P2 < Psat P2 < Psat P3 < P2< PsatFigure 3-6. Schematic representation 01 a differentialliberation experiment.

Figure 3-7. A PVT system used tor differentialliberation analyses. One seesfrom left to right: the motorized pump, PVT cel , and bath gas colection sys-tem withcondensate trapo

46 Properties 01 Oils and Natural Gases Oil and Gas Property Measurements 47


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below the saturation pressure. The system will then be in the two-phase re-gion. After the system has been equilibrated, the gas phase is removed fromthe cell at constant pressure. The gas volume ismeasured with a gasometerand recorded.

The new volume of the oi l is calculated from the readings on the mercurypump before and af ter the discharge of the gas. These readings will also givethe gas phase volume at the given pressure and temperature.

The hydrocarbon system is again brought into the two-phase region, thistime at a lower pressure, and the gas discharge procedure is repeated.

The pressure step intervals are chosen so that 8-10 stages will occur be-tween the saturation pressure and the atmospheric pressure.At the last stage, ca re must be taken to discharge al of the remaining gas,

whereas the residual oil is left in the cell. After the last part of the gas isdischarged, the cell is closed, its internal pressure is increased in steps, andthe resulting ol volumes are recorded. Normally, one records volumes ateach 50 bar up to 300 bar. The plot of these volumes can be extrapolatedback to atmospheric pressure, so that a measure of the res idual oil volume atthe given temperature, which is often that of the reservoir, can be deter-mined.

Then the cell temperature is reduced to 15C, and the oil volume at thistemperature is determined as previously explained. This volume is the refer-ence residual volume.

The oil is then discharged from the cell, and its density s determined asexplained in Chapter 2.

The data recorded in this analysis can be represented as shown in Figure3-8. Ps and Vs are the saturation pressure and volume, respectively; VRT thel iquid volume at one atmosphere and temperature , Ti and VR i s the refer-ence liquid volume at 15C. From these data the shrinkage fac tor of the sys-tem at the saturation pressurernay be calculated:

Bo,s = VSIVR (3-6)The whole Bo-curve (see Figure 3-9) may be calculated as follows: .,

Bo = VIVR (3-7)The solution gas/oil rat io of the reservoir fluid, Rs, at pressure stage N canbe obtained from

NST EPRs = L V gas,nlV R

n ~ N + 1 (3-8)

where NSTEP is the total number of f lash stages and Vgas,n is the volume ofgas (Sm3) liberated at flash stage n. These data can be represented as shownin Figure 3-10.

i~';fttM~

V s.P s

~~

100 200 300Pressure [Bar J

Figure 3-8. Determination of saturation pressure and volume from a differentialdepletion experiment.

~o~

100 200 300P re ss ur o [Bar)

B o .s

o'

Figure 3-9. The differential liberation Bo-factor as function o f p ressure.

The density of the reservo ir fluid at each pressure reduction step can bedetermined from the known density at 15C, the l iquid volume, and thevolume and molecular weight of the gas. The density versus pressure datamay be presented as shown in Figure 3-11.

Deviat ion from ideal gas behavior may be expressed via the compressibil-ity factor, Z, as defined in Equation 3-5. Employing Equation 3-5 twice,


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48 Properties of Oils and fatural Gases

1-

Figure 3-10 . The solutiongas/oil ratio as function ofpressures.o, P sV1cc

P r e s s u r ep Figure 3-11. Oensity 01 reser-voir f luid as funct ion 01 pres-sure.

Ps P r es s ur e

i.e., at two different pressures and temperatures and for the same number ofmoles, will result in:

Z = PVT2Z2/P2V2T\ (3-9)Equation 3-9 relates a compressibility factor at condition 1, where it is

unknown, to the compressibility factor at condition 2, where it is assumed tobe known. Z2 is normal y the compressibility factor at ambient conditions,and it i su sually clase to unity.

Process Simulation by Flash SeparationA three-stage flash can be performed in arder to furnish support data for

process simulation.Such a flash sequence is shown in Figure 3-12.Stage three is the stock tank s tage, where the pressure is one atm and the

temperature is15C. For the other two stages, temperature and pressure canbe chosen as desired.

Oil and Gas Property Measurements 49GAS ( 1 ) GAS ( 2 ) GA S ( S T )

1st S T A G Ep l' T 1 2 n d S T AGEP2,T2 3 r d S T A G EPst' \t

O I L t o s t o c k t a n kFigure 3-12. Three-stage flash separation train.

The two first stages are accomplished in the same PVT cell as was used inthe differential liberation experiment, and the last st age is carried out bytransferring the second stage Huid to a single flash apparatus (see FlashSeparation and Compositional Analysis, discussed earlier). From this ex-periment the overall COR, COR at individual stages, compositions of thegas and liquid phases, properties of the stock tank Huid such as density andmolecular weight (see Chapter 2), and also the Bo factor of the oil can beobtained. Tables 3-1 and 3-2 show a typicallaboratory result of a separatortest experimento

Gas Reinjection Related Analysis

).~In arder to understand the reservoir Huid behavior under gas injection

processes, two different analyses have been designed:l. Swelling test2. Slim tube minimum miscibility pressure determination

Swelling Test. When gas is injected into a reservoir containing an under-saturated ol, the gas can go into solution. This has the effect of swel ing theoil, i.e., the volume of oil becomes larger.

Simulation of this effect can be performed in an ordinary PVT cell, start-ing with the original reservoir Huid in question. Injection gas has been com-pressed into a separate steel bottle.

A srnall, known volume of injection gas is transferred into the PVT cell. Anew saturation pressure is determined using the techniques already de-scribed, and a new saturation volume is recorded. This process is repeateduntil the saturation pressure of the fluid is equal to the estimated injectionpressure of the system.

The dat a from this test can be presented as shown in F igure 3-13.

..

Slim Tube Tests. One method of improving oi l recovery involves injection ofgas into the oil reservoir. The gas may be nitrogen, carbon dioxde, Hue gas,

50 Properties 01 Oi ls and Natural Gases Oil and Gas Property Measurements 51


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(5..11:Ueaalea~o-; U)M::

CI I : :JU).c CI I~a:-)~o-a~e aQCI IC J )

el)Clea0 0

'ea'O( ll:5 .~iQ) > J:a. e a '( /) . ea(IiL..o Q l .iE1j e a _ ..,g . e a f(/)eo el)M'':; E Le a j oE o .. > 0 eaa f LL

- e ea~~ o- L t l., e ...o el)0 0

~< elo

~~

N Olci~

: I :o o[O ~ I ~o o

Lt l l < tN

P s p P r e s s u r e

. .>< .> ~ ~ :o & .a. ~.. .: E

I ~~2 ~ 8S~ ~~ ~ g~Q)~o~~~ ~~o 'O-e[~~o ;; ~ ~ ~ ~,...~ ~ sQ lQ ' O~ ' ~ e/F ~rJ~ ~ ~

Co (.1 s:~o :g :g .EI ~ t~.~ *f) C/) ID... ... >-~ tUEO o ;jctS~ el tl t5 el::-.~ ea ea cu ctIOD ...

M ~ ID Q) 'O oEUE Eci~-;;;c .S.2 .2 ~ UUI III I l;o ~~~~C>'~~~oca~~~o~~~o8gCi5CEi~x(/)';cu cu 0 Q) c: ea (1)oo ce e s os ISfiff ~

P i - I n j e c t i o n p r e s s u r eP s - S a t u r a t i o n p r e s s u r eV s - S a t u r a t i o n v o l u meVi - L i Q u i d v o l u me a t i n j e c t i o np r e s s u r eA V - S we l l i n g v o l u me

Figure 3-13. Graphical representation of swelling test data.


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52 Properties of Oils and Natural Gasesor natural gas. It is advantageous to have a miscible displacement. Thismeans that at the gas/oil front only one phase isachieved no matter in whatproportion the oil and the gas are mixed. The injected gas and the reservoiroi lmay be miscible by first contact or miscibility may be achieved as a resultof a multiple contact process. If the gas and oil become miscible, completedisplacement of the reservoir fluid will be accomplished, and the recoverymay be larger than 90 %. It is, therefore, of great practical and economicalinterest to find out if t he gas plus the oil form one phase, i.e., are miscible. Ifso, it becomes important to know what the lowest pressure at the reservoirtemperature is where complete miscibility occurs in the displacement pro-cess. This is c alled the minimum miscibility pressure and it isdetermined ina slim tube test.

The minimum miscibility pressure may be determined from visual obser-vations of the displaced fluido Usually it is determined as the breakoverpoint in the recovery curve from a series of displacement experiments. Anexample of a displacement curve is illustrated in Figure 3-14, showing oilrecovery as a function of pressure at a fixed temperature. The concept ofminimum miscibility pressure is further discussed in Chapter 16.

A schematic diagram of a slim tube apparatus is shown in Figure 3-15.The main part of the equipment is a piece of l(dn. steel tubing, approxi-mately 10 m long and packed with sand. Two containers, one for the injec-tion gas and one for the reservoir oil, are connected to mercury pumps. Us-ing the mercury pumps, the reservoir fluid and the gas may be forced toflow through the steel pipe. A sight glass to observe the produced Huids anda flash separator to determine the amount of fluids produced are provided.

The sand pack i s first saturated with the oil sample to be studied, and theinitial volume of fluid in the coiled tubing is recorded. The pressure of the

Breakover

100

90>-Q ; 80o(JQ)a: : 70;f.601100

P O i n \Figure 3-14. Example of oilrecovery as a functi on ofpressure in a slim tube experi-ment.I o Msc i bl eO I r nrni sci bl e

200 300Test Pressure (bar)

Oil and Gas Property Measurements 53

system is set, and gas is allowed to displace oil through the sand pack. Theamount of produced fluid is monitored as time proceeds.

The sequence is repeated for several pressures, and the recovery, (pro-duced oil)/(initial oil), is recorded for each pressure. The resulting data maybe plotted as shown in Figure 3-16.

GA S

f

o(])1 . - Me r c u r y p u mp2 . - O i l r e s e r v o i r3. - Ga s r e s e r v o i r4 . - S l l m t u b e - s t ee l t u b l n g 1 / 4 a p p r o x. 1 0 m5. - S l g h t g l a s s - v i s u a l f l o w c e l l6 . - B a c k p r e s s ur e v a l v e7 . - 0 1 1 a n d g a s s e p a r a t o r

1,

Figure 3-15. Schematic diagram of slim tube apparatus.

....:.::::::: ::::::::::: ::::::::::: :/ '////MMP

P

Figure 3-16. Pressure as afunction of recovery from aslim tube analysis.

5 0 1 0 0 R e c o v e r y

54 Properties oj Oils and Natural Gases Oil and Gas Property Measurements 55


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The pressure at which 90-100% of the ini tial fluid in the sand pack isrecovered is defined as the minimum miscibility pressure of the system.

Several modifications of this apparatus can be made. Online density de-termination of the fluids using a high-pressure densitometer, and viscositymeasurements using a capil lary tube viscosimeter, are examples of suchmodifications.

GAS CONDENSATE EQUIPMENTAt reservoir conditions, gas condensates usually exist in one single gaseous

phase. Therefore, gas condensates must be studied using types of PVT cellsdifferent from those used for black oils.

There are two main types of gas condensate PVT cells: the long win-dowed cell (or three windowed cell), and the Sloane type of cell. Figures3-17 to 3-20 show the different fea tures of the cells.

The windows in the cells are located so that visual observation of thewhole or the bottom part of the hydrocarbon sample can take place.

The dew point is defined as the pressure at which an infinitesimally smallamount of Iiquid is in equilibrium with a gas phase. At constant tempera-ture, this can be observed as the pressure at which a small amount of l iquidappears in the system. For gas condensates, normally the upper dew point is

Figure 3-17. A Ruska three-windowed gas condensate/volatile oil cell in its ther-mostatic enclosure.

1 ~ .:.~J

Figure 3-19. A cutaway diagramof a Sloane type gas condensatecell.Hola a nd valve torintroduction 01 gasoline

Spiral lor stirringgas. The l iquid isstirred by a s piral 5coil wound aroundthe axisLighting window 8

Liquid voluma 9measuremantchamber

Figure 3-18. Sloane type PVTcell in itsthermostatic enclosure.

1 Ori lice lor int roduc-/ tion 01 mercury

through the uppercap, lor operation01 the pisto n

2 P iston w ith joistpacking

Hole and valve lor4 i nt rod uc ti on a nd

sampling 01 gas

6 Sapphire v iewingwindow~ 7 Viewing w indow

1O Magnetic agitator


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56 Propertes of Oils and Natural Gases

Figure 3-20. Pump and valve arrangement for ~Ioane type cel .

of interest, i.e., the liquid is formed ( drops out ) by pressure reduction.The separator samples, gas and liquid, are prepared as for black oil analy-

siso The PVT cell is charged, first with the gas, by allowing the gas to ex-pand into the cell and d isplace the mercury. The volume of mercury dis-placed can be measured, and thus the volume of gas in the cell is known.

Constant Mass ExpansionIn order to achieve a represen ta tive reservoir fluid, separator liquid is

added to the cell in the gas/oil ratio measured during the sampling. Oncethis is done, the system in the PVT cell is a t reservoir temperature, corn-pressed to above the recorded reservoir pressure. At this pressure, the cell isleft (usually overn ight) fo r equilibration. The system ischecked to see if it isall in single phase, and the total system volume i s then recorded. A constantmass expans ion can st art. Figure 3-21 shows a schematic diagram of thisprocess.

The pressure isreduced in a stepwise manner. The system is observed visu-a lly, and the volume recorded at each pressure level by reading the mercurypump.

The dew point pressure can be somewhat diff icul t to observe, and there-fore the stepwise pressure reduction is continued below the dew point.

Oil and Gas Property Measurements 57Below the dew point, the liquid volume is determined at each pressure.

These readings result in the liquid dropout curve. Data from the constantmass study can be plotted as shown in Figure 3-22. It should be noted thatthe dew point is obtained by extrapolating the liquid dropout curve.

The amount of liquid formed is usually relatively small, and thereforespecial attention mus t be paid to the liquid volume determinations. Theavailable cell designs oHer diHeren t methods by which the liquid volumescan be measured. Best resul ts are ob ta ined in cells where charge volumes areup to 400 cm'' at the dew point. Significant liquid volumes will then beformed, allowing relat ively accurate liqu id vo lume measurements. Theamount of liquid is best determined in a cell where the window configura-tion allows light to shine through the system.

For the previous reasons, a Sloane type cell is recommended. It can beused to s tudy very lean gas condensate systems.

However, a Sloane type cell is not recomrnended for studies of volatile ornear cri tica l fluids.

I N C I P I EN T F OR M A T I O N, OF usuiu IyI .... I .... . . . . 1, ,,,'.... .... ....l .... . . . .Ga s Ga s .. Ga s I l. Ga sv t , 't 2 '.... . . . . >1 .... 1 .... ', .. . f . . . . . . . . M .... I v t s.. .... .... > . . . . .... . . . . 1 .........p,' P s a t P 2 > P s a t P 3 = P s a t P 4 < P s a t P S


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Constant Volume DepletionIn order to simulate production behavior of the reservoir condensate

fluid, a constant volume depletion experiment isperformed. A schematic di-agram of the process i s shown in Figure 3-23.

The system is brought to just below its dew point . The dew-point volumeof the system

Properties of Oils and Natural Gases

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