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In their original condition, reservoir oils include some natural gas in solution. The pressure at which this natural gas begins to come out of solution and form bubbles is known as the bubblepoint pressure. This page discusses calculations for bubble point and the solution gas/oil ratio (GOR).

Correlations for calculating bubble point

Tables 1 and 2 summarize correlations of bubblepoint.[1][2][3][4][5][6][7][8][9][10][11][12][13][14][15][16][17][18][19][20][21][22][23][24][25][26][27][28][29][30][31][32][33][34][35] Since Standing’s[2] correlation appeared in 1947, more than 30 methods have been proposed. Many of these were developed during the last 15 years. The effective use of the correlations lies in an understanding of their development, along with knowledge of their limitations.

These equations can be expressed functionally as:

Vol1 page 0261 eq 001.png....................(1)

Solution GOR is determined by rearranging any given correlation equation.

Statistical analysis of correlations

Recent studies[36][37][38][39] provide statistical analyses for bubblepoint-pressure correlations and provide recommendations based on their findings; however, none of these references examines the full set of correlations. Al-Shammasi[32] compiled a databank of 1,243 data points from the literature. This was supplemented by 133 samples available from a GeoMark Research database, [40] bringing the total number of data points to 1,376. These data were then used to rank the bubblepoint pressure correlations. Table 3 summarizes the ranges of data found in this compilation and the distribution. Fig. 1 shows the distribution of data used to prepare PVT correlations.

Table 4 summarizes correlation performance. The results are sorted by absolute average relative error, which provided a means to rank the methods.

The data were further grouped to examine the impact of crude oil gravity and GOR on the consistency of the correlations. Methods proposed by Lasater, [4] Al-Shammasi, [32] and Velarde et al.[34] showed reliability over a wide range of conditions. The author has experienced good results from both the Standing[21][29] and Glasø[12] correlations, although they may not have ranked highly with this data set. Fig. 2 depicts these correlations for comparison.

Correlation comparison for varying solution GOR

Fig. 3 graphically summarizes the results of all 32 bubblepoint pressure correlations for varying GOR, a 35°API crude oil, a hydrocarbon gas gravity of 0.65, and a temperature of 150°F. Individual methods are unlabeled because it is the envelope and range of answers that are of interest. Some information concerning correlation trends can be gathered from the outliers.

Impact of impurities on correlations

Owolabi’s[33] method for Alaska Cook Inlet Basin crude oil systems, shown in Fig. 3, illustrates the impact of gas impurities on the bubblepoint pressure correlation. This crude oil system is characterized by GORs in the range 200 to 300 scf/STB and nitrogen contents of 5 to 15%. The limited range of GORs combined with the nitrogen in the surface gas results in a correlation that predicts rather large values of bubblepoint pressure when extrapolated to higher GORs. This illustrates the pitfalls of developing a correlation from a limited set of data and further defines the importance of understanding the range of applicability for any given correlation. The method may be perfectly valid within a limited range of conditions; however, the equations that define the method may not be suitable for extrapolation.

This example also illustrates the importance of adjusting the calculated bubblepoint pressure for the effects of gas impurities. For the most part, bubblepoint-pressure correlations have been established with little or no impurities in the gas. Owolabi recognized the importance of these impurities and their impact on the calculated results. Methods to adjust the calculated bubblepoint pressure for gas impurities have been developed and should be used.

Adjustments to account for crude composition

It is instructive to focus on the large spread in the range of correlations presented in Fig. 3. The correlations form a core envelope of results that coincide with variations expected because of the chemical nature of the crude oil. Correlations with results residing above and below the core envelope were ignored, and the difference between high and low results was determined as shown in Fig. 4.

Correlations using only API gravity to define the crude oil component do not adequately describe the chemical nature of the crude oil. Lasater’s method relies on a relationship relating crude oil gravity and molecular weight. Whitson’s Watson characterization factor equation can be used to examine this relationship. Lasater reported that the oil gravity/molecular weight relationship corresponded to a Watson characterization factor of 11.8; however, on closer examination, the correlation is representative of paraffinic oil with a Watson characterization factor of approximately 12.2, as Fig. 5 shows. Whitson and Brulé[41] recommended that Cragoe’s[42] relationship to determine molecular weight from API gravity be used to determine crude molecular weight.

Vol1 page 0266 eq 001.png....................(2)

First published in 1929, this equation is generally used with condensates and is applicable over the range of 20 to 80°API. It should not be used outside this range. A Watson characterization factor of 11.8 is defined by Cragoe’s relationship over the API gravity range 30 to 40. Whitson’s work with North Sea crudes that have a characterization factor of 11.9 supports this recommendation. A more general recommendation is to use Whitson’s equation to determine the molecular weight from the Watson characterization factor and oil specific gravity. This adds the dimension of crude oil chemical nature to the estimate of fluid properties using correlations.

Lasater developed a correlation between a bubblepoint pressure factor, pbγg/T, and the mole fraction of gas dissolved in the oil, which is depicted in Fig. 6. The equation fit to the data has been modified to provide better performance of the correlation at high GOR conditions. Lasater’s method is summarized in its entirety in Tables 1 and 2.

Whitson and Brulé offered a modification to Glasø’s correlation to account for changes in characterization factor. Glasø’s correlation was developed from North Sea crude oils with a Watson characterization factor of 11.9. The proposed modification is

Vol1 page 0266 eq 002.png....................(3)

Fig. 7 depicts the effect of changing the Watson characterization factor on bubblepoint pressure for the Lasater and Glasø correlations. The range in bubblepoint pressure solutions is comparable to the range exhibited in Fig. 4. Clearly, the addition of Watson characterization factor to correlation of bubblepoint pressure offers increased flexibility in the use of a correlation on a worldwide basis. Whitson and Brulé present graphs detailing the relationship between bubblepoint pressure and characterization that show bubblepoint pressure declining with an increase in characterization factor. Their analysis procedure also allows for changing API gravity and GOR. By allowing these two quantities to vary, their evaluation shows the converse of Fig. 7.

Cautions in use of correlations

A correlation is an equation or method fit to specific data groups to provide the relationship between dependent and independent variables. Properly defined, the variables cover a wide range of conditions, enabling the correlation to properly represent the physical processes being modeled. Formulation of the equations is important because they are routinely extrapolated outside the range used for their development. Some correlations have been developed with multiple equations for various ranges of crude oil gravity. Normally, 30°API is selected as a point at which the equations change. Discontinuities in relationships can arise as a result of using multiple equations. Other methods show nonphysical trends. Care must be exercised in the use of these methods for "general use" calculations over a wide range of conditions.

Correlations proposed by Vazquez and Beggs,[5][6] Al-Najjar et al.,[15] Kartoatmodjo and Schmidt,[19][20][21] De Ghetto et al., [27][28] and Elsharkawy and Alikhan[30] use multiple equations to cover the range of API gravities. These methods often exhibit discontinuities across the boundaries. The method of Dokla and Osman[16] shows virtually no sensitivity to crude oil gravity. Bubblepoint pressure should increase with rising temperature. Methods proposed by Dokla and Osman, Almehaideb,[29] Elsharkawy, and Dindoruk and Christman[35] show a decrease. Bubblepoint pressure should decrease with increasing gas gravity. Methods proposed by Asgarpour et al.[14] (for the Cardium/Viking and D2/Leduc formations) and Elsharkawy are insensitive to gas gravity or show increasing bubblepoint pressure with increasing gas gravity. Omar and Todd’s[24][25] correlation shows a parabolic trend that is inaccurate for high gas gravities. This method should be avoided for crude oil systems with gas-specific gravities greater than 1.10. Figs. 8 through 10 show these results graphically.

Additionally, several other correlations have been found to exhibit undesirable tendencies. At atmospheric pressure where solution GOR is zero, Petrosky and Farshad[17][18] determines a value of 50 to 100 scf/STB. Dindoruk and Christman provided separate equations for GOR and bubblepoint pressure because of their complexity. Both equations provide nearly identical results for low GOR systems. For higher GOR systems (e.g., greater than 2,000 scf/STB), their GOR equation provides more realistic results; therefore, when using the Dindoruk and Christman method, their equation for solution GOR is recommended. For calculating bubblepoint pressure, this equation must be solved with numerical methods because of its formulation. Correlations proposed by Owolabi[10] and Hasan et al.[26] are undefined at pressures less than 55 psia, while Al-Marhoun’s[11] method, published in 1985, has an upper pressure limit of 5,348 psia because of the formulation of the equations.

Correlations are often incorporated into computer programs in which they can easily be used for conditions outside the range intended for the method. Some methods are well behaved and provide reasonable results when extrapolated. Other methods should only be used within the bounds defined by the data used in the development of the correlation.

Nonhydrocarbon gas effects

Nonhydrocarbon gases typically found in crude oil systems are nitrogen, carbon dioxide, and hydrogen sulfide. The bubblepoint pressure correlations (with the exception of Owolabi, [10] Al-Marhoun, [11][13] and Dokla and Osman[16]) were developed with crude oil systems that did not contain significant amounts of impurities in the gas phase. Work by Jacobson, [43] Glasø, [7] and Owolabi point out the need for procedures to modify the calculated bubblepoint pressure for these impurities. Nitrogen does not readily dissolve in crude oil, resulting in an increase in bubblepoint pressure. On the other hand, carbon dioxide and hydrogen sulfide are more soluble in crude oil than natural gas, which has the effect of lowering bubblepoint pressure. Jacobson evaluated 110 crude oil PVT samples containing up to 14% nitrogen and found that a correction factor need only be based on the nitrogen content of the gas and the temperature of the mixture. An equation to account for the effects of nitrogen on bubblepoint pressure was developed.

Vol1 page 0271 eq 001.png....................(4)

Glasø examined the effects of nitrogen, carbon dioxide, and hydrogen sulfide on bubblepoint pressure and developed corrections for each impurity. The correction for nitrogen content is a function of nitrogen content in the gas, temperature, and crude oil gravity.

Vol1 page 0271 eq 002.png....................(5)

The correction for carbon dioxide is a function of carbon dioxide content and temperature,

Vol1 page 0272 eq 001.png....................(6)

while the correction for hydrogen sulfide was found to be a function of hydrogen sulfide content in the surface gas and crude oil gravity.

Vol1 page 0273 eq 001.png....................(7)

Figs. 1 through 3 depict these corrections. Owolabi found that Jacobson’s method was superior for correcting the calculated bubblepoint pressure for the nitrogen content in Cook Inlet crude oil systems. Jacobson’s method was derived from measured data containing less than 14% nitrogen, while Glasø’s data covered systems with nearly 20% nitrogen. Glasø’s correction factors for carbon dioxide and hydrogen sulfide used measured data containing impurities of 20 and 40%, respectively.

Nomenclature

Mo = oil molecular weight, m, lbm/lbm mol
T = temperature, T, °F
pb = bubblepoint pressure, m/Lt2, psia
γoc = "corrected" oil specific gravity
γom = measured oil specific gravity
Vol1 page 0304 inline 001.png = bubblepoint pressure of oil with CO2 present in surface gas, m/Lt2, psia
Vol1 page 0304 inline 002.png = bubblepoint pressure of oil with H2S present in surface gas, m/Lt2, psia
Vol1 page 0304 inline 003.png = bubblepoint pressure of oil with N2 present in surface gas, m/Lt2, psia
pbh = bubblepoint pressure of oil without nonhydrocarbons, m/Lt2, psia
γAPI = oil API gravity
Kw = Watson characterization factor, °R1/3

References

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  2. 2.0 2.1 Standing, M.B. 1947. A Pressure-Volume-Temperature Correlation for Mixtures of California Oils and Gases. API Drilling and Production Practice (1947): 275-287.
  3. Elam, F.M. 1957. Prediction of Bubble Point Pressures and Formation Volume Factors from Field Data. MS thesis, University of Texas at Austin, Austin, Texas.
  4. 4.0 4.1 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
  5. 5.0 5.1 Vazquez, M.E. 1976. Correlations for Fluid Physical Property Prediction. MS thesis, University of Tulsa, Tulsa, Oklahoma.
  6. 6.0 6.1 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
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  15. 15.0 15.1 Al-Najjar, H.S., Al-Soof, N.B.A., and Al-Khalisy, K.M. 1988. Correlations For Bubble-Point Pressures, Gas Oil Ratios And Formation Volume Factors For Iraqi Crude Oils. Journal of Petroleum Research (June 1988): 13.
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  17. 17.0 17.1 Petrosky, G.E. Jr. 1990. PVT Correlations for Gulf of Mexico Crude Oils. MS thesis. 1990. . MS thesis, University of Southwestern Louisiana, Lafayette, Louisiana.
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  19. 19.0 19.1 Kartoatmodjo, R.S.T. 1990. New Correlations for Estimating Hydrocarbon Liquid Properties. MS thesis, University of Tulsa, Tulsa, Oklahoma.
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  21. 21.0 21.1 21.2 Kartoatmodjo, T. and Z., S. 1994. Large Data Bank Improves Crude Physical Property Correlations. Oil Gas J. 92 (27): 51–55.
  22. 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
  23. Macary, S.M. and El-Batanoney, M.H. 1992. Derivation of PVT Correlations for the Gulf of Suez Crude Oils. Proc., 11th EGPC Petroleum Exploration and Production Conference, Cairo, Egypt, Vol. 1, 374.
  24. 24.0 24.1 Omar, M.I. and Todd, A.C. 1993. Development of New Modified Black Oil Correlations for Malaysian Crudes. Presented at the SPE Asia Pacific Oil and Gas Conference, Singapore, 8-10 February. SPE-25338-MS. http://dx.doi.org/10.2118/25338-MS
  25. 25.0 25.1 Omar, M.I., Daud, M.E., and Raja, D.M.A. 1993. New Correlation For Determining Bubble Point Oil FVF (Formation Volume Factor). Presented at the 1993 Asian Council Petroleum Conference, Bangkok, Thailand, 2–6 November.
  26. 26.0 26.1 Hasan, M., Lestari, and Inawati. 1993. PVT Correlations for Indonesian Crude Oils. Proc., 22nd Annual Convention of the Indonesian Petroleum Association, Indonesia, Vol. 1, IPA93-2.1-070.
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  28. 28.0 28.1 De Ghetto, G., Paone, F., and Villa, M. 1995. Pressure-Volume-Temperature Correlations for Heavy and Extra Heavy Oils. Presented at the SPE International Heavy Oil Symposium, Calgary, 19-21 June. SPE-30316-MS. http://dx.doi.org/10.2118/30316-MS
  29. 29.0 29.1 29.2 Almehaideb, R.A. 1997. Improved PVT Correlations for UAE Crude Oils. Presented at the Middle East Oil Show and Conference, Bahrain, 15-18 March. SPE-37691-MS. http://dx.doi.org/10.2118/37691-MS
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  31. Khairy, M., El-Tayeb, S., and Hamdallah, M. 1998. PVT Correlations Developed for Egyptian Crudes. Oil Gas J. 96 (18): 114.
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  35. 35.0 35.1 Dindoruk, B. and Christman, P.G. 2001. PVT Properties and Viscosity Correlations for Gulf of Mexico Oils. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-3 October. SPE-71633-MS. http://dx.doi.org/10.2118/71633-MS
  36. Elsharkawy, A.M., Elgibaly, A.A., and Alikhan, A.A. 1995. Assessment of the PVT correlations for predicting the properties of Kuwaiti crude oils. J. Pet. Sci. Eng. 13 (3–4): 219-232. http://dx.doi.org/10.1016/0920-4105(95)00012-7
  37. Mahmood, M.A. and Al-Marhoun, M.A. 1996. Evaluation of empirically derived PVT properties for Pakistani crude oils. J. Pet. Sci. Eng. 16 (4): 275-290. http://dx.doi.org/10.1016/S0920-4105(96)00042-3
  38. Robertson, C.J. 1983. Comparison of Revised PVT Properties with Published Correlations. Internal Report, Marathon Oil Company, Houston, Texas (April 1983).
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  40. GeoMark Research. 2003. RFDbase (Reservoir Fluid Database), http://www.RFDbase.com.
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See also

Oil fluid properties

Crude oil characterization

PEH:Oil System Correlations