@article{Wichert1972,
author = {Wichert, Edward and Aziz, Khalid},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Wichert, Aziz - 1972 - Calculation of Z's for Sour Gases.pdf:pdf},
journal = {Hydrocarbon Processing},
number = {5},
pages = {119--122},
title = {{Calculation of Z's for Sour Gases}},
volume = {51},
year = {1972}
}
@article{Al-Marhoun2004,
abstract = {This study evaluates the most frequently used pressure–volume–temperature (PVT) empirical correlations to determine reservoir–fluid properties for Middle East crudes. The best available correlations were selected and their predictions compared with a large database of reservoir–fluid studies of samples representing all active areas of the Middle East. The comparison is based on statistical error analysis. This paper gives the best correlations for estimating: bubblepoint pressure, solution gas–oil ratio, oil formation volume factor at bubblepoint pressure, total formation volume factor, undersaturated oil compressibility, and undersaturated, saturated, and dead oil viscosities. Values of reservoir liquid and gas properties are often needed when detailed laboratory PVT data is not available. The published correlations that are not based on Middle East data perform poorly, but, when they are calibrated with this data, the performance improves.},
author = {Al-Marhoun, Muhammad Ali},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Al-Marhoun - 2004 - Evaluation of empirically derived PVT properties for Middle East crude oils.pdf:pdf},
issn = {0920-4105},
journal = {Journal of Petroleum Science and Engineering},
keywords = {Fluid properties,Oil compressibility,Oil viscosity,PVT correlations,PVT data},
number = {2},
pages = {209--221},
title = {{Evaluation of empirically derived PVT properties for Middle East crude oils}},
volume = {42},
year = {2004}
}
@article{Vasquez1980,
abstract = {Introduction The evaluation of physical properties of hydrocarbon mixtures is an important step in the design of various stages of oilfield operations. The fluid properties, which change as pressure and temperature change, must be evaluated for both reservoir engineering and production design operations. For example, the production design operations. For example, the calculation of two-phase flowing pressure gradients occurring in piping systems requires prediction of fluid properties such as dissolved gas, formation volume factor (FVF), oil compressibility, and viscosity at various locations in the pipe, Even though laboratory measurements of these properties may be available as a function of pressure, the measurements usually are made at reservoir temperature only. The behavior of these properties with temperature change usually is predicted empirically. Increasing emphasis is being placed on the necessity of having accurate estimates of fluid physical properties in advance of laboratory PVT physical properties in advance of laboratory PVT analyses of the reservoir fluids. Many times these properties are required at a time when the only properties are required at a time when the only information available consists of oil and gas gravities and reservoir pressure and temperature. The purpose of this study was to utilize a large base of laboratory. measured PVT data to develop improved empirical correlations to replace those commonly in use. Many of the presently used correlations were developed many years ago from limited data and are being used beyond the range for which they were intended. JPT P. 968},
author = {Vasquez, M and Beggs, H D},
doi = {10.2118/6719-PA},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Vasquez, Beggs - 1980 - Correlations for Fluid Physical Property Prediction.pdf:pdf},
issn = {0149-2136},
journal = {Journal of Petroleum Technology},
number = {06},
pages = {968--970},
publisher = {Society of Petroleum Engineers},
title = {{Correlations for Fluid Physical Property Prediction}},
url = {https://doi.org/10.2118/6719-PA},
volume = {32},
year = {1980}
}
@article{Sutton2007,
abstract = {Summary Problems with existing procedures used to estimate gas pressure/volume/temperature (PVT) properties are identified. The situation is reviewed, and methods are proposed to alleviate these problems. Natural gases are derived from two basic sources: associated gas, which is liberated from oil, and gas condensates, where hydrocarbon liquid, if present, is vaporized in the gas phase. The two gases are fundamentally different in that a high-gravity associated gas is typically rich in ethane through pentane, while gas condensates are rich in heptanes-plus. Additionally, either type of gas may contain nonhydrocarbon impurities such as hydrogen sulfide, carbon dioxide, and nitrogen. Failure to distinguish properly between the two types of gases can result in calculation errors in excess of those allowable for technical work. Sutton (1985) investigated high-gravity gas/condensate gases and developed methods for estimating pseudocritical properties that resulted in more-accurate Z factors. The method is suitable for all light natural gases and the heavier gas/condensate gases. It should not be used for high-gravity hydrocarbon gases that do not contain a significant heptanes-plus component. The original Sutton database of gas/condensate PVT properties has been expanded to 2,264 gas compositions with more than 10,000 gas-compressibility-factor measurements. A database of associated-gas compositions containing more than 3,200 compositions has been created to evaluate suitable methods for estimating PVT properties for this category of gas. Pure-component data for methane (CH4), methane-propane, methane-n-butane, methane-n-decane, and methane-propane-n-decane have been compiled to determine the suitability of the derived methods. The Wichert (1970) database of sour-gas-compressibility factors has been supplemented with additional field and pure-component data to investigate suitable adjustments to pseudocritical properties that ensure accurate estimates of compressibility factors. Mathematical representations of compressibility-factor charts commonly used by the engineering community and methods used by the geophysics community are investigated. Generally, these representations/methods are robust and have been found suitable for ranges beyond those recommended originally. Natural-gas viscosity, typically estimated through correlation, has been found to be inadequate for high-gravity gas condensates, requiring revised procedures for accurate calculations. Introduction Since its publication, the Standing and Katz (1942) (SK) gas Z-factor chart has become a standard in the industry. Several very accurate methods have been developed to represent the chart digitally. The engineering community typically uses methods published by Hall and Yarborough (1973, 1974) (HY), Dranchuk et al. (1974) (DPR), and Dranchuk and Abou-Kassem (1975) (DAK). These methods all use some form of an equation of state that has been fitted specifically to selected digital Z-factor-chart data published by Poettmann and Carpenter (1952). The geophysics community typically uses a method developed by Batzle and Wang (1992) (BW). Recently, Londono et al. (2002) (LAB) refitted the chart with an expanded data set, resulting in a modified DAK method. They provided two equations: one fit to an expanded data set from the SK Z-factor chart and another that included pure-component data. A general gas Z-factor chart, such as the one developed by Standing and Katz (1942), is based on the principle of corresponding states (Katz et al. 1959). This principle states that two substances at the same conditions referenced to critical pressure and critical temperature will have similar properties. These conditions are referred to as reduced pressure and reduced temperature. Therefore, if two substances are compared at the same reduced conditions, the substances will have similar properties. In the context of this paper, the property of interest is the gas Z factor. Mathematically, the SK chart relates Z factor to reduced pressure and reduced temperature.},
author = {Sutton, Robert P},
doi = {10.2118/97099-PA},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Sutton - 2007 - Fundamental PVT Calculations for Associated and GasCondensate Natural-Gas Systems.pdf:pdf},
issn = {1094-6470},
journal = {SPE Reservoir Evaluation {\&} Engineering},
number = {03},
pages = {270--284},
publisher = {Society of Petroleum Engineers},
title = {{Fundamental PVT Calculations for Associated and Gas/Condensate Natural-Gas Systems}},
url = {https://doi.org/10.2118/97099-PA},
volume = {10},
year = {2007}
}
@misc{Standing1947,
abstract = {ABSTRACTThe paper presents correlations of bubble-point pressures, formation volumes of bubble-point liquids, and formation volumes of gas plus liquid phases as empirical functions of gas-oil ratio, gas gravity, oil gravity, pressure, and temperature. Although the correlations are on California crude Oils and gases, comparisons are made for the various crudes reported by Katz. In order to facilitate the use of the data, the results of the correlations are presented in the form of calculating charts.The solution of reservoir-performance problems requires that the physical properties of the reservoir fluids be known. These properties may be determined m the laboratory either from bottom-hole samples or from proper recombination of surface trap samples If the results of laboratory tests are not available, however, the physical properties must be estimated from field measurements The purpose of this paper is to give the results of several correlations between the variables normally measured in the field and the physical properties necessary for the solution of reservoir performance problems. Other correlations of this type have been reported by Gosline and Dodson,1a and by Katz3 Sage and Olds4 have recently reported an excellent correlation of formation volumes of condensate systems. The accuracy of the following P-V-T correlations is restricted by two factors. 1 The varied and complex multi-component hydrocarbon systems which are dealt with are defined by only three simple parameters gas gravity, oil gravity, and gas-oil ratio, and, 2. These parameters themselves depend upon the process by which the oil and gas are separated The method used by Sage and Reamer2 in the RIO Bravo Field studies of specifying hexanes and heavier material as $\backslash$"oil$\backslash$" and all pentanes and lighter material as $\backslash$"gas$\backslash$" would overcome these difficulties. However, this approach does not lend Itself to field usage. A further aid to preparing correlations would be to make use of a standard procedure in separating the oil and gas when gas-oil ratios are determined. However, as the P-V-T data are prepared for individual field conditions, it is normally not possible to use such a method. The gas-oil ratios, gas gravities, oil gravities, and formation volumes presented in this paper are laboratory values. They are the result of a 2-stage flash separation at 100 deg F-the first stage normally being within the pressure range of 250 psi to 450 psi and second stage at atmospheric pressure. This procedure is considered to approximate the average California field practices.Bubble-Point Pressure CorrelationsOne of the important functions of P-V-T data is to indicate whether the reservoir oil is under saturated or saturated, or whether free gas is being produced from the sand. This required a knowledge of the gas solubility-bubble-point-pressure relationship of the oil and gases associated in the reservoir. In considering the manner in which the several variables affect the bubble-point pressure of a mixture of an oil and a gas, it seems reasonable to postulate a correlation of the form (mathematical equation available in full paper)In developing the specific equation relating the bubble-point pressure to the variables on the right side of equation (1), the general relationship between the variables was used to suggest graphical methods of determining specific relationships.},
address = {New York, New York},
author = {Standing, M B},
booktitle = {Drilling and Production Practice},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Standing - 1947 - A Pressure-Volume-Temperature Correlation For Mixtures Of California Oils And Gases.pdf:pdf},
pages = {275--287},
publisher = {American Petroleum Institute},
title = {{A Pressure-Volume-Temperature Correlation For Mixtures Of California Oils And Gases}},
year = {1947}
}
@article{Spivey2007,
abstract = {Summary The coefficient of isothermal compressibility (oil compressibility) is defined as the fractional change of oil volume per unit change in pressure. Though the oil compressibility so defined frequently appears in the partial-differential equations describing fluid flow in porous media, it is rarely used in this form in practical engineering calculations. Instead, oil compressibility is usually assumed to be constant, allowing the defining equation to be integrated over some pressure range of interest. Thus, the oil compressibility in the resulting equations should be regarded as a weighted average value over the pressure range of integration. The three distinct applications for oil compressibility in reservoir engineering are (1) instantaneous or tangent values from the defining equation, (2) extension of fluid properties from values at the bubblepoint pressure to higher pressures of interest, and (3) material-balance calculations that require values starting at initial reservoir pressure. Each of these three applications requires a different approach to calculating oil compressibility from laboratory data and in developing correlations. The differences among the values required in these three applications can be as great as 25{\%}. Most published correlations do not indicate the particular application to which the proposed correlation applies. A correlation equation for oil compressibility has been developed using more than 3,500 lines of data from 369 laboratory studies. This correlation equation gives the average compressibility between the bubblepoint pressure and some higher pressure of interest. Equations to calculate appropriate values of compressibility for the other two applications are presented. Introduction The equation defining the coefficient of isothermal compressibility at pressures above the bubblepoint pressure is rather simple: (Equation 1) However, in application the situation becomes somewhat complex. Usually the equation is integrated by separating variables: (Equation 2) Moving oil compressibility outside the integral sign requires the assumption that it is constant. Because it is not constant, the use of this equation requires a value of oil compressibility that is a pressure-weighted average across the pressure range used in the calculations. There are three applications for oil compressibility in reservoir engineering: The defining equation, for which the oil compressibility should be calculated as a single value at the pressure of interest, often used in pressure-transient analysis. The extension of fluid properties from correlations starting at the bubblepoint pressure to pressures above the bubblepoint pressure. This application is also used in black-oil reservoir simulation. The use of oil compressibility in black-oil material-balance equations in which the starting point is the initial reservoir pressure. Values of oil compressibility should be calculated from laboratory data with these applications in mind. Most published correlations for oil compressibility do not indicate the particular situation to which the correlation applies, although values calculated for these three applications can differ significantly. For example, Fig. 1 gives values of oil compressibility calculated with the constant-composition-expansion data from a widely available black-oil laboratory report (Reservoir Fluid Study 1988). Two things are readily apparent. First, coefficients of isothermal compressibility are not constant as pressure changes. Second, the three applications require values that differ by up to 25{\%}.},
author = {Spivey, John Paul and Valko, Peter P and McCain, William D},
doi = {10.2118/96415-PA},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Spivey, Valko, McCain - 2007 - Applications of the Coefficient of Isothermal Compressibility to Various Reservoir Situations With New Co.pdf:pdf},
issn = {1094-6470},
journal = {SPE Reservoir Evaluation {\&} Engineering},
number = {01},
pages = {43--49},
publisher = {Society of Petroleum Engineers},
title = {{Applications of the Coefficient of Isothermal Compressibility to Various Reservoir Situations With New Correlations for Each Situation}},
url = {https://doi.org/10.2118/96415-PA},
volume = {10},
year = {2007}
}
@article{Spivey2004,
abstract = {New correlations for density of methane-free sodium chloride brine and solubility of methane in sodium chloride brines, valid over wide ranges of pressure, temperature, and salinity, are presented. Both correlations agree with the best available measurements within experimental error over most of the range of validity. These new correlations are combined with published correlations for methane partial molar volume to provide accurate and internally consistent estimates of brine density, specific volume, formation volume factor, and coefficient of isothermal compressibility at pressures above or below the bubble point pressure. The brine density correlation is valid for temperatures from 0 to 275°C (32 to 527° F), pressures from 0.1 to 200 MPa (14.5 to 29,000 psi), and sodium chloride content from 0 to 6 moles/kg H 2O (0 to 26{\%} by weight). The methane solubility correlation is valid for temperatures from 20 to 360°C (68 to 680° F), pressures from 0.9 to 200 MPa (130 to 29,000 psia), and sodium chloride content from 0 to 6 moles/kg H 2O (0 to 26{\%} by weight). A modification of an existing correlation for brine viscosity is also presented, extending its range of applicability to temperatures between 20 and 300°C (68 to 572° F), pressures between 0.1 and 200 MPa, and salinity between 0 and 5.4 moles NaCl/kg H 2O (0 to 25{\%} NaCl by weight).},
author = {Spivey, John P. and McCain, William D. and North, Rob},
doi = {10.2118/04-07-05},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Spivey, McCain, North - 2004 - Estimating density, formation volume factor, compressibility, methane solubility, and viscosity for oilfi.pdf:pdf},
issn = {00219487},
journal = {Journal of Canadian Petroleum Technology},
number = {7},
pages = {52--61},
title = {{Estimating density, formation volume factor, compressibility, methane solubility, and viscosity for oilfield brines at temperatures from 0 to 275 C, pressures to 200 MPa, and salinities to 5.7 mole/kg}},
url = {https://doi.org/10.2118/04-07-05},
volume = {43},
year = {2004}
}
@article{PetroskyJr.1998,
abstract = {This paper (SPE 51395) was revised for publication from paper SPE 26644, first presented at the 1993 SPE Annual Technical Conference and Exhibition, Houston, 3-6 October. Original manuscript received for review 25 October 1993. Revised manuscript received 1 October 1997. Paper peer approved 28 January 1998.SummaryNew empirical pressure-volume-temperature (PVT) correlations for estimating bubblepoint pressure, solution gas-oil ratio (GOR), bubblepoint oil formation volume factor (FVF), and undersaturated isothermal oil compressibility have been developed as a function of commonly available field data.Results show that these PVT properties can be predicted with average absolute errors ranging from 0.64{\%} for bubblepoint oil FVF to 6.66{\%} for undersaturated isothermal oil compressibility.P. 416},
author = {{Petrosky Jr.}, G E and Farshad, F},
doi = {10.2118/51395-PA},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Petrosky Jr., Farshad - 1998 - Pressure-Volume-Temperature Correlations for Gulf of Mexico Crude Oils.pdf:pdf},
issn = {1094-6470},
journal = {SPE Reservoir Evaluation {\&} Engineering},
number = {05},
pages = {416--420},
publisher = {Society of Petroleum Engineers},
title = {{Pressure-Volume-Temperature Correlations for Gulf of Mexico Crude Oils}},
url = {https://doi.org/10.2118/51395-PA},
volume = {1},
year = {1998}
}
@article{Meehan1980b,
author = {Meehan, D N},
journal = {Petroleum Engineer},
pages = {125--126},
title = {{A correlation for water compressibility}},
volume = {56},
year = {1980}
}
@article{Meehan1980a,
author = {Meehan, D N},
journal = {Petroleum Engineer},
pages = {117--118},
title = {{Estimating water viscosity at reservoir conditions}},
volume = {35},
year = {1980}
}
@book{McCainJr.2011,
author = {{McCain, Jr.}, William D and Spivey, John P and Lenn, Christopher P},
isbn = {978-1-59370-187-1},
pages = {219},
publisher = {PennWell Corporation},
title = {{Petroleum Reservoir Fluid Property Correlations}},
year = {2011}
}
@article{McCainJr.1991,
abstract = {Summary. This paper presents correlations to determine reservoir-fluid properties from field data. The best available correlations were selected by comparison with a data base of hundreds of reservoir-fluid studies of samples representing all areas of the free world involved in active petroleum exploitation from 1980 to 1986. Also, correlations of formation-water properties are given. IntroductionValues of reservoir liquid and gas properties are often needed when laboratory PVT data are not available. This paper shows how to use normally available field data to estimate fluid properties. While at Texas A and M U., I had access to a data base of hundreds of reservoir-fluid studies provided by Core Laboratories Inc. The geographical and geological origins of the reservoir samples had been carefully removed from the data but the samples were known to represent all areas of the free world in which petroleum exploitation was active during the first 6 years of the 1980's. All reservoir-fluid property correlations available in the petroleum engineering literature were compared with this data base. This paper gives the best correlations. Identification of Reservoir-Fluid Type Surprisingly accurate "rules of thumb" are available to identify reservoir-fluid type from field data. When the initial producing GOR is less than 3,300 scf/STB, the fluid is a liquid at reservoir conditions. Possible exceptions occur if the stock-tank liquid is colorless or has a gravity higher than about 50 degrees API. Reservoir liquids are either black oils or volatile oils; the general material-balance equations work only for black oils. The behavior of volatile oils does not fit the assumptions inherent in the derivation of the material-balance equations. Black oils are identified as having initial producing GOR's below 2,000 scf/STB and deeply colored stock-tank oil with gravities below 45 degrees API. Reservoir gases are classified as retrograde gases (often called condensate gases or gas condensate), wet gases, and dry gases. Retrograde gases have initial producing GOR's {\textgreater}3,300 scf/STB. The few exceptions of oils that have ratios higher than this are identified as having deeply colored stock-tank liquids with gravities less than 40 degrees API. Retrograde behavior occurs for gases with initial producing GOR's of 150,000 scf/STB or higher;however, as a practical matter, gases with initial producing GOR's {\textgreater} 50,000 scf/STB can be treated as wet gases. The term wet gas is used for a gas that does not release condensate in the reservoir but does form hydrocarbon liquid at the surface. The term dry gas is used for a gas that does not form any hydrocarbon liquid at the surface. In this context, the terms "wet" and "dry" do not refer to water or water vapor, which is always present to some extent. Properties of Reservoir Liquids The physical properties discussed next apply only to black oils. Engineering a volatile-oil reservoir requires a special laboratory study not discussed here. Solution GOR at Bubblepoint, Rsb. The initial producing GOR provides a good estimate of solution GOR for use at pressures equal to and above. bubblepoint pressure. Ms wig not be true if free gas from a gas cap or another formation is produced with the oil. Field data often exhibit a great deal of scatter; however, a trend of constant GOR usually can be discerned before reservoir pressure drops below the bubblepoint. Often the reported values of producing GOR do not include stocktank vent gas. In this case, the use of initial producing GOR for solution GOR results in values that are low by 10{\%} or more. The stock-tank GOR can be estimated with log RST =A1+A2 log o +As log gSP+A4 log PSP +a5 log Tsp,............................................ (1) where A1=0.3818, A2=-5.506, A3=2.902, A4=1.327, and A5=-0.7355. Eq. 1 should not be used if the separator temperature is {\textgreater}140 degrees F. Addition of the estimate of stock-tank GOR from Eq. 1 to the separator GOR results in an estimate of solution GOR accurate to within 3 {\%}. Bubblepoint Pressure, Pb. The bubblepoint pressure of the oil at reservoir conditions can be estimated with Pb = 18.2(Cpb - 1.4),...................................... (2) where Cpb =(Rs/ g)0.83 x 10(0.00091T-0.0125 API)..............(3) to an accuracy of 15{\%}. The specific gravity of the separator gas can be used for g; however, Rs should include stock-tank vent gas. The equations are valid to 325 degrees F. A more accurate estimate of bubblepoint pressure can be obtained if reservoir pressure is measured regularly. Plot reservoir pressure and producing GOR vs. cumulative production. For a volumetric solution-gas-drive reservoir, pressure will decline rapidly initially, then flatten when reservoir pressure drops below the oil bubblepoint pressure (the pressure at which the line changes slope). The producing GOR will begin to increase shortly after bubblepoint pressure is reached. Solution GOR, Rs. Eqs. 2 and 3 can be used to estimate solution GOR for pressures below the bubblepoint. Enter any pressure below bubblepoint in place Of Pb in Eq. 2 and calculate the corresponding value of solution GOR with Eq. 3. The results should be within 15{\%} of measured values. If a field-derived bubblepoint pressure has been obtained from pressure measurements as described above. the accuracy of the estimates of solution GOR can be improved. Start by creating a table of pressures and solution GOR'S. Subtract the field-derived bubblepoint pressure from the bubblepoint pressure calculated with Eqs. 2 and 3 to obtain a "delta pressure." Subtract this "delta pressure" from all pressures in the Rs vs. p table. This procedure works very well for pressures near the bubblepoint. It is less accurate at low pressures. Oil FVF, Bo. The oil FVF for use at pressures equal to or below bubblepoint can be estimated with Bob =0.9759+12(10 -5)C Bob 1.2,......................... (4) where C Bob=Rs( g/ o)0.5+1.25T..............................(5) The equations can be used for any pressure equal to or below the bubblepoint by inserting the corresponding value of solution GOR estimated as discussed above. The resulting FVF value will be within 5{\%} of laboratory-measured values if accurate values of solution GOR are used. If solution GOR's are obtained with Eqs. 2 and 3. the accuracy of the resulting FVF values will be some unknown combination of the 15{\%} accuracy of Eqs. 2 and 3 and the 5{\%} accuracy of Eqs. 4 and 5. Do not use at temperatures above 352 degrees F. SPERE P. 266{\^{}}},
author = {{McCain Jr.}, W D},
doi = {10.2118/18571-PA},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/McCain Jr. - 1991 - Reservoir-Fluid Property Correlations-State of the Art (includes associated papers 23583 and 23594 ).pdf:pdf},
issn = {0885-9248},
journal = {SPE Reservoir Engineering},
number = {02},
pages = {266--272},
publisher = {Society of Petroleum Engineers},
title = {{Reservoir-Fluid Property Correlations-State of the Art (includes associated papers 23583 and 23594 )}},
url = {https://doi.org/10.2118/18571-PA},
volume = {6},
year = {1991}
}
@article{Glaso1980,
abstract = {Empirical equations for estimating saturation pressure, oil formation volume factor (FVF) at saturation pressure, and two-phase FVF were derived as a function of reservoir temperature, total surface-gas gravity, producing GOR, and stock-tank oil gravity. These equations should be producing GOR, and stock-tank oil gravity. These equations should be valid for all types of oil/gas mixtures after correcting for nonhydrocarbons in surface gases and paraffinicity of oil. Introduction Pressure-volume-temperature (PVT) correlations are Pressure-volume-temperature (PVT) correlations are important tools in reservoir technology. These measurements form the basis for estimating the amount of oil in the reservoir, production capacity, and variations in produced gas/oil ratios during the reservoir's production life. PVT relations also are a requirement for calculating the recovery efficiency of a reservoir. Especially during the prospection phase, when only produced fluid properties are available from flowing tests, one can resort to empirically derived PVT relations. It is, of course, of great importance PVT relations. It is, of course, of great importance that such estimations be as accurate as possible. From PVT correlations published until now, Standing's work is perhaps the most widely used. His correlations were developed for California oils and make no corrections for oil type or nonhydrocarbon content. Other PVT relations developed for oils from other parts of the world, based on Standing's work, yield "best-fit lines" ordinarily parallel-shifted. Their differences can be understood from two factors not included in Standing's original correlations: (1) crude oils from other regions have different paraffinicity - i.e., they contain varying amounts of paraffinic oil components (saturated hydrocarbons in open chains), and (2) the surface gases from some reservoirs contain relatively large amounts of nonhydrocarbons (CO2, N2, and H2S). By considering the variation in these parameters, this paper develops generalized PVT correlations: (1) (2) (3) These equations were derived from laboratory data, exclusively sampling North Sea oils. However, they should be valid for all types of gas/oil mixtures after correcting for nonhydrocarbons (CO2, N2, and H2S) in the surface gases and paraffinicity of the oil as defined by the Kuop factor. Procedure Procedure PVT Measurements PVT Measurements Six reservoirs fluid samples were made from two North Sea separator liquid and gas samples. These reservoir samples were labeled A1, B1, and C1 and A2, B2, and C2. Fig. 1 shows the experimental procedure used in the PVT analysis. procedure used in the PVT analysis. JPT P. 785},
author = {Glaso, Oistein},
doi = {10.2118/8016-PA},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Glaso - 1980 - Generalized Pressure-Volume-Temperature Correlations.pdf:pdf},
issn = {0149-2136},
journal = {Journal of Petroleum Technology},
number = {05},
pages = {785--795},
publisher = {Society of Petroleum Engineers},
title = {{Generalized Pressure-Volume-Temperature Correlations}},
url = {https://doi.org/10.2118/8016-PA},
volume = {32},
year = {1980}
}
@article{Beggs1975,
abstract = {Viscosity values of crude oils and crude oils containing dissolved natural gas are required in various petroleum engineering calculations. In evaluation of fluid flow in a reservoir, the viscosity of the liquid is required at various values of reservoir pressure and at reservoir temperature. This information can be obtained from a standard laboratory PVT analysis that is run at reservoir temperature. There are cases, however, when the viscosity is needed at other temperatures. The most common situation requiring viscosities at various pressures and temperatures occurs in the calculation of two-phase, gas-liquid flowing pressure traverses. These pressure traverses are required in tubing-string design, gas-lift design, and pipeline design. Calculation of these pressure traverses involves dividing the flow string into a number of length increments and calculating the pressure gradient at average conditions of pressure and temperature in the increment. Calculation of pressure and temperature in the increment. Calculation of pressure gradients requires knowledge of oil viscosity. In pressure gradients requires knowledge of oil viscosity. In many cases, the only information available on the fluid properties are the separator gas gravity and stock-tank oil properties are the separator gas gravity and stock-tank oil gravity; therefore, correlations requiring a knowledge of crude oil composition are not applicable. The most popular methods presently used for predicting oil viscosity are those of Beal for dead oil and Chew and Connally for live or saturated oil. Beal correlated dead oil viscosity as a function of API gravity and temperature. Chew and Connally presented a correlation for the effect of dissolved gas on the oil viscosity. The dead oil viscosity and the amount of dissolved gas at the temperature and pressure of interest must be known. pressure of interest must be known. When these correlations were applied to data collected for a study of dissolved gas and formation volume factor, considerable errors and scatter were observed. These data, therefore, were used to develop new empirical correlations for dead or gas-free crude oil as a function of API gravity and temperature, and for live oil viscosity as a function of dissolved gas and dead oil viscosity. A description of the data used, which were obtained from Core Laboratories, Inc., is given in Table 1. The correlation for dead oil viscosity was developed by plotting log 10 (T) vs log 10 log 10 (mu OD + 1) on cartesian plotting log 10 (T) vs log 10 log 10 (mu OD + 1) on cartesian coordinates. The plots revealed a series of straight lines of constant slope. It was found that each line represented oils of a particular API gravity. The equation developed is = ,........................(1) where X = y = Z = The correction of the dead oil viscosity for dissolved gas was developed by taking advantage of the fact that a linear relationship exists between log 10 mu OD and log 10 mu for a particular value of dissolved gas, Rs. Live oil viscosity may be calculated from = ...........................(2) TABLE 1 - DESCRIPTION OF DATA USED Variable Range Solution GOR, scf/STB 20 to 2,070 Oil gravity, API 16 to 58 Pressure, psig 0 to 5,250 Pressure, psig 0 to 5,250 Temperature, F 70 to 295 Number of oil systems - 600 Number of dead oil observations - 460 Number of live oil observations 2,073 P. 1140},
author = {Beggs, H D and Robinson, J R},
doi = {10.2118/5434-PA},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Beggs, Robinson - 1975 - Estimating the Viscosity of Crude Oil Systems(2).pdf:pdf},
issn = {0149-2136},
journal = {Journal of Petroleum Technology},
number = {09},
pages = {1140--1141},
publisher = {Society of Petroleum Engineers},
title = {{Estimating the Viscosity of Crude Oil Systems}},
url = {https://doi.org/10.2118/5434-PA},
volume = {27},
year = {1975}
}
@article{Al-Marhoun1988,
abstract = {Summary. Empirical equations for estimating bubblepoint pressure, oil FVF at bubblepoint pressure, and total FVF for Middle East crude oils were derived as a function of reservoir temperature, total surface gas relative density, solution GOR, and stock-tank oil relative density. These empirical equations should he valid for all types of oil and gas mixtures with properties falling within the range of the data used in this study. properties falling within the range of the data used in this study. Introduction PVT correlations are important tools in reservoir-performance PVT correlations are important tools in reservoir-performance calculations. The major use of PVT data is in carrying out material-balance calculations. In 1947, Standing published correlations for determining the bubblepoint pressure and FVF from known values of temperature, solution GOR, gas relative density, and oil API gravity. A total of 105 experimentally determined data points on 22 different crude oil and gas mixtures from California were used in deriving the correlations. Standing reported an average relative error of 4.8{\%} for the bubblepoint pressure correlation and an average relative error of 1.17{\%} for the FVF correlation. In 1980, Glaso presented correlations for calculating bubblepoint pressure, oil FVF, and total FVF from known values of temperature, solution GOR, gas relative density, and oil API gravity. A total of 45 oil samples, mostly from the North Sea region, were used in obtaining the correlations. Glaso reported average relative errors of 1.28{\%}, -0.43{\%}, and -4.56{\%} for the bubble point pressure, the bubblepoint oil FVF, and the total FVF correlations, pressure, the bubblepoint oil FVF, and the total FVF correlations, respectively. Reviews of other empirical PVT correlations were presented by Sutton and Farshad in 1984. Standing used a graphic method and Glass used both a graphic method and linear regression analysis in the development of their PVT correlations. The graphic estimation and curve-fitting, PVT correlations. The graphic estimation and curve-fitting, however, do not lead to the best estimate. Therefore, this study developed the correlations using only linear and nonlinear multiple regression analyses to obtain the highest accuracy. This paper deals with PVT correlations exclusively for samples of Middle East crude oils. However, they should he valid for all types of gas/oil mixtures with properties falling within the range of data used in this study. Moreover, this study evaluates the accuracy of Standing's and Glass PVT correlations, which are shown in Table 1. Error analyses were done for this study and also for Standing's and Glass correlations to compare their degree of accuracy. Finally, nomographs for bubblepoint pressure, bubblepoint oil FVF, and two-phase total FVF were constructed on the basis of the developed empirical correlations. PVT Data PVT Data The PVT analyses of 69 bottomhole fluid samples from 69 Middle East oil reservoirs were made available for this study. The experimentally obtained data points were 160 each for the bubblepoint pressure, Pb, and bubblepoint oil FVF, Bob, correlations, and pressure, Pb, and bubblepoint oil FVF, Bob, correlations, and 1,556 for the total FVF, Bt, correlation. The ranges of the data used are shown in Table 2. PVT Correlations PVT Correlations The correlations for bubblepoint pressure, bubblepoint oil FVF, and two-phase total FVF were developed by use of the linear and nonlinear multiple regression analyses shown in the Appendix. Bubblepoint Pressure. The following general relation of bubblepoint pressure of an oil and gas mixture with its fluid and reservoir properties was assumed: (1) Table 3 shows the 160 experimentally determined bubblepoint pressures obtained from PVT analyses of 69 different Middle East pressures obtained from PVT analyses of 69 different Middle East oil/gas mixtures. The nonlinear multiple regression analysis was used to develop the following relation: (2) where Pb = bubblepoint pressure, Rs = solution GOR, gammag = dissolved gas relative density (air = 1), gammag = stock-tank oil relative density (water = 1), and T = absolute temperature. Bubblepoint Oil FVF. Oil FVF at bubblepoint pressure can he derived as a function of solution GOR, average gas relative density, oil relative density, and temperature as fellows: (3) The following empirical equation was developed by use of the nonlinear multiple regression analysis and a trial-and error method based on the 160 experimentally obtained data points shown in Table 3: (4) where B is an intermediate oil FVF value. The bubblepoint oil FVF correlation (Eq. 4) was further refined by applying the linear regression analysis on the same data. P. 650},
author = {Al-Marhoun, Muhammad Ali},
doi = {10.2118/13718-PA},
file = {:C$\backslash$:/Users/ftn60/AppData/Local/Mendeley Ltd./Mendeley Desktop/Downloaded/Al-Marhoun - 1988 - PVT Correlations for Middle East Crude Oils.pdf:pdf},
issn = {0149-2136},
journal = {Journal of Petroleum Technology},
number = {05},
pages = {650--666},
publisher = {Society of Petroleum Engineers},
title = {{PVT Correlations for Middle East Crude Oils}},
url = {https://doi.org/10.2118/13718-PA},
volume = {40},
year = {1988}
}
