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# Calculating PVT properties

This is an example of calculating PVT properties. The specific correlations that should be used for a specific crude oil or reservoir may vary, as discussed in the referenced pages focusing on specific properties.

Determine the PVT properties for a United States midcontinental crude oil and natural gas system with properties listed in Table 1. Table 2 lists the correlations to be used. Measured data are provided for comparison with the calculated results. For correlations that rely on other correlations, these data illustrate the effects of error propagation in the calculations.

## Gravity and molecular weight

Determine the crude oil specific gravity,

....................(1)

and molecular weight,

....................(2)

## Bubblepoint pressure

Use the Lasater[1] correlation to estimate bubblepoint pressure. Calculate the gas mole fraction in the oil,

....................(3)

and the Lasater bubblepoint pressure factor,

....................(4)

with Lasater’s relationship between bubblepoint pressure factor and bubblepoint pressure,

....................(5)

For comparison, Standing[2][3] = 2,316 psia, Glasø[4] = 2,725 psia, Al-Shammasi[5] = 2,421 psia, and Velardi[6] = 2,411 psia.

Modify the calculated bubblepoint pressure to account for the effects of nitrogen in the surface gas with Jacobson’s equation.

....................(6)

Therefore, the bubblepoint pressure should be increased by 9.8% to 2,251 psia. The measured bubblepoint pressure was reported to be 2,479 psia.

## Bubblepoint oil formation volume factor

Calculate the bubblepoint oil formation volume factor (FVF) using the correlation from Al-Shammasi.[5]

....................(7)

For comparison (in bbl/STB), Standing[2][3] = 1.410, Glasø[4] = 1.386, Al-Marhoun[7] = 1.364, Farshad[8] = 1.364, and Kartoatmodjo[9][10][11] = 1.358. The measured bubblepoint oil FVF is 1.398 bbl/STB.

## Isothermal compressibility

Calculate the isothermal compressibility of oil using the Farshad[8] correlation.

....................(8)

....................(9)

The measured isothermal compressibility is 11.06 × 10-6psi-1.

## Undersaturated oil formation volume factor

With the results from Lasater’s[1] method for bubblepoint pressure, use Al-Shammasi’s[5] method for bubblepoint oil FVF, and Farshad’s[8] equation for isothermal compressibility, the undersaturated oil FVF is given by

....................(10)

which compares to a measured value of 1.367 bbl/STB. Because this calculation uses the results from multiple correlations, individual correlation error compounds and propagates through to the final result. The calculated value is 1.367 bbl/STB with the actual bubblepoint value of 1.398 bbl/STB; therefore, the accuracy of the bubblepoint FVF is primarily affected by the accuracy of the undersaturated FVF.

## Oil density

Calculate the oil density.

....................(11)

Calculate the dead oil viscosity using the correlation from Glasø.[4]

....................(12)

For comparison, Fitzgerald[12][13][14] = 1.808 cp, and Bergman[15][16] = 2.851 cp. The measured dead oil viscosity is 1.67 cp.

## Bubblepoint oil viscosity

Calculate the bubblepoint oil viscosity using the method developed by Chew and Connally.[17][18]

....................(13)

....................(14)

....................(15)

For comparison, Beggs and Robinson[19] = 0.515 cp. The measured viscosity at bubblepoint is 0.401 cp.

## Undersaturated oil viscosity

Calculate the undersaturated oil viscosity by applying the Vazquez and Beggs[20][21] correlation.

....................(16)

For comparison, Beal[22] = 0.730 cp and Kouzel[23] = 0.778 cp. The measured value is 0.475 cp. This example illustrates the steps necessary to calculate oil viscosity requiring correlations for dead oil viscosity, bubblepoint viscosity, undersaturated viscosity, and bubblepoint pressure/solution GOR. Errors in individual correlations can compound and propagate through to the resulting answer. For instance, if the measured bubblepoint viscosity is used in Eq. 16, the result is 0.52 cp—much closer to the measured value. Therefore, care should be exercised in the selection of accurate correlations for individual properties.

## Gas/oil interfacial tension

Estimate the gas/oil surface tension using the method developed by Abdul-Majeed.[24] Calculate the dead oil surface tension.

....................(17)

Determine the live oil adjustment factor.

Convert Rs to SI units (dividing 769 Scf/STB by 5.614, the result is 136.98 m3/m3)

..........................(18)

Calculate the live gas/oil surface tension.

....................(19)

For comparison, Baker and Swerdloff[25][26] = 4.73 dynes/cm.

## Water/oil interfacial tension

Estimate the water/oil surface tension using Firoozabadi and Ramey.[27] Calculate the pseudocritical temperature of the dead oil.

....................(20)

Calculate the pseudocritical temperature of the gas.

....................(21)

Calculate the pseudocritical temperature of the live gas/oil mixture.

....................(22)

Convert oil density units from lbm/ft3 to g/cm3.

....................(23)

Calculate the surface tension between the oil and water phases.

....................(24)

## Nomenclature

 Bg = gas FVF, ft3/scf Bo = oil FVF, bbl/STB Bob = oil formation volume at bubblepoint pressure, bbl/STB co = oil isothermal compressibility, Lt2/m, psi-1 cob = oil isothermal compressibility at bubblepoint, Lt2/m, psi-1 Kw = Watson characterization factor, °R1/3 Mg = gas molecular weight, m, lbm/lbm mol Mgo = gas/oil mixture molecular weight, m, lbm/lbm mol Mo = oil molecular weight, m, lbm/lbm mol Mog = oil-gas mixture molecular weight, m, lbm/lbm mol p = pressure, m/Lt2, psia pb = bubblepoint pressure, m/Lt2, psia = bubblepoint pressure of oil with N2 present in surface gas, m/Lt2, psia pbh = bubblepoint pressure of oil without nonhydrocarbons, m/Lt2, psia pf = bubblepoint pressure factor, psia/°R pr = pressure ratio (fraction of bubblepoint pressure) Rs = solution GOR, scf/STB T = temperature, T, °F Tabs = temperature, T, °R Tb = mean average boiling point temperature, T, °R Tcg = gas pseudocritical temperature, T, °R Tcm = mixture pseudocritical temperature, T, °R Tco = oil pseudocritical temperature, T, °R Tr = reduced temperature, T Tsc = temperature at standard conditions, T, °F V = volume, L3 Vo = volume of crude oil, L3 Wg = weight of dissolved gas, m Wo = weight of crude oil, m xg = gas "component" mole fraction in oil xo = oil "component" mole fraction in oil yg = gas "component" mole fraction in gas = mole fraction N2 in surface gas yo = oil "component" mole fraction in gas Z = gas compressibility factor γAPI = oil API gravity γg = gas specific gravity, air=1 γgc = gas specific gravity adjusted for separator conditions, air=1 γghc = gas specific gravity of hydrocarbon components in a gas mixture, air=1 γgs = separator gas specific gravity, air=1 γo = oil specific gravity μo = oil viscosity, m/Lt, cp μob = bubblepoint oil viscosity, m/Lt, cp μod = dead oil viscosity, m/Lt, cp ρg = gas density, m/L3, lbm/ft3 ρo = oil density, m/L3, lbm/ft3 ρob = bubblepoint oil density, m/L3, lbm/ft3 ρw = water density, m/L3, g/cm3 σhw = hydrocarbon/water surface tension, m/t2, dynes/cm σgo = gas/oil surface tension, m/t2, dynes/cm σod = dead oil surface tension, m/t2, dynes/cm

## References

1. Lasater, J.A. 1958. Bubble Point Pressure Correlations. J Pet Technol 10 (5): 65–67. SPE-957-G. http://dx.doi.org/10.2118/957-G.
2. Standing, M.B. 1981. Volumetric and Phase Behavior of Oil Field Hydrocarbon Systems, ninth edition. Richardson, Texas: Society of Petroleum Engineers of AIME
3. Standing, M.B. 1947. A Pressure-Volume-Temperature Correlation for Mixtures of California Oils and Gases. API Drilling and Production Practice (1947): 275-287.
4. Glasø, Ø. 1980. Generalized Pressure-Volume-Temperature Correlations. J Pet Technol 32 (5): 785-795. SPE-8016-PA. http://dx.doi.org/10.2118/8016-PA
5. Al-Shammasi, A.A. 2001. A Review of Bubblepoint Pressure and Oil Formation Volume Factor Correlations. SPE Res Eval & Eng 4 (2): 146-160. SPE-71302-PA. http://dx.doi.org/10.2118/71302-PA
6. Velarde, J., Blasingame, T.A., and McCain Jr., W.D. 1997. Correlation of Black Oil Properties At Pressures Below Bubble Point Pressure - A New Approach. Presented at the Annual Technical Meeting of CIM, Calgary, Alberta, 8–11 June. PETSOC-97-93. http://dx.doi.org/10.2118/97-93
7. Al-Marhoun, M.A. 1992. New Correlations For Formation Volume Factors Of Oil And Gas Mixtures. J Can Pet Technol 31 (3): 22. PETSOC-92-03-02. http://dx.doi.org/10.2118/92-03-02
8. Frashad, F., LeBlanc, J.L., Garber, J.D. et al. 1996. Empirical PVT Correlations For Colombian Crude Oils. Presented at the SPE Latin American and Caribbean Petroleum Engineering Conference, Port of Spain, Trinidad and Tobago, 23–26 April. SPE-36105-MS. http://dx.doi.org/10.2118/36105-MS
9. Kartoatmodjo, R.S.T. 1990. New Correlations for Estimating Hydrocarbon Liquid Properties. MS thesis, University of Tulsa, Tulsa, Oklahoma.
10. Kartoatmodjo, T.R.S. and Schmidt, Z. 1991. New Correlations for Crude Oil Physical Properties, Society of Petroleum Engineers, unsolicited paper 23556-MS.
11. Kartoatmodjo, T. and Z., S. 1994. Large Data Bank Improves Crude Physical Property Correlations. Oil Gas J. 92 (27): 51–55.
12. Fitzgerald, D.J. 1994. A Predictive Method for Estimating the Viscosity of Undefined Hydrocarbon Liquid Mixtures. MS thesis, Pennsylvania State University, State College, Pennsylvania.
13. Daubert, T.E. and Danner, R.P. 1997. API Technical Data Book—Petroleum Refining, 6th edition, Chap. 11. Washington, DC: American Petroleum Institute (API).
14. Sutton, R.P. and Farshad, F. 1990. Evaluation of Empirically Derived PVT Properties for Gulf of Mexico Crude Oils. SPE Res Eng 5 (1): 79-86. SPE-13172-PA. http://dx.doi.org/10.2118/13172-PA
15. Whitson, C.H. and Brulé, M.R. 2000. Phase Behavior, No. 20, Chap. 3. Richardson, Texas: Henry L. Doherty Monograph Series, Society of Petroleum Engineers.
16. Bergman, D.F. 2004. Don’t Forget Viscosity. Presented at the Petroleum Technology Transfer Council 2nd Annual Reservoir Engineering Symposium, Lafayette, Louisiana, 28 July.
17. Chew, J. and Connally, C.A. Jr. 1959. A Viscosity Correlation for Gas-Saturated Crude Oils. In Transactions of the American Institute of Mining, Metallurgical, and Petroleum Engineers, Vol. 216, 23. Dallas, Texas: Society of Petroleum Engineers of AIME.
18. Aziz, K. and Govier, G.W. 1972. Pressure Drop in Wells Producing Oil and Gas. J Can Pet Technol 11 (3): 38. PETSOC-72-03-04. http://dx.doi.org/10.2118/72-03-04
19. Beggs, H.D. and Robinson, J.R. 1975. Estimating the Viscosity of Crude Oil Systems. J Pet Technol 27 (9): 1140-1141. SPE-5434-PA. http://dx.doi.org/10.2118/5434-PA
20. Vazquez, M.E. 1976. Correlations for Fluid Physical Property Prediction. MS thesis, University of Tulsa, Tulsa, Oklahoma.
21. Vazquez, M. and Beggs, H.D. 1980. Correlations for Fluid Physical Property Prediction. J Pet Technol 32 (6): 968-970. SPE-6719-PA. http://dx.doi.org/10.2118/6719-PA
22. Beal, C. 1970. The Viscosity of Air, Water, Natural Gas, Crude Oil and Its Associated Gases at Oil Field Temperatures and Pressures, No. 3, 114–127. Richardson, Texas: Reprint Series (Oil and Gas Property Evaluation and Reserve Estimates), SPE.
23. Kouzel, B. 1965. How Pressure Affects Liquid Viscosity. Hydrocarb. Process. (March 1965): 120.
24. Abdul-Majeed, G.H. and Abu Al-Soof, N.B. 2000. Estimation of gas–oil surface tension. J. Pet. Sci. Eng. 27 (3–4): 197-200. http://dx.doi.org/10.1016/S0920-4105(00)00058-9
25. Baker, O. and Swerdloff, W. 1955. Calculation of Surface Tension 3—Calculating parachor Values. Oil Gas J. (5 December 1955): 141.
26. Baker, O. and Swerdloff, W. 1956. Calculation of Surface Tension 6—Finding Surface Tension of Hydrocarbon Liquids. Oil Gas J. (2 January 1956): 125.
27. Firoozabadi, A. and Ramey Jr., H.J. 1988. Surface Tension of Water-Hydrocarbon Systems at Reservoir Conditions. J Can Pet Technol 27 (May–June): 41–48.