Bubble Point Pressure Correlations

Overview

The bubble point pressure ($P_b$) is the pressure at which the first bubble of gas evolves from an oil at reservoir temperature. This thermodynamic property is fundamental to reservoir characterization:

• Phase behavior prediction — distinguishes undersaturated from saturated flow conditions
• Material balance calculations — determines oil compressibility above versus below $P_b$
• Production forecasting — gas evolution affects mobility ratios and recovery
• Facilities design — separator sizing requires saturation pressure knowledge

When laboratory PVT data are unavailable, engineers rely on empirical correlations derived from regression analysis of measured datasets.

Physical Significance

At the bubble point:

• Reservoir oil transitions from a single-phase liquid to a two-phase gas-liquid system
• Solution gas begins evolving from the oil phase
• Oil compressibility changes discontinuously
• Formation volume factor reaches its maximum value ($B_{ob}$)

The bubble point pressure depends on:

Correlation Equations

All correlations covered here solve the inverse problem: given measured $R_s$, $\gamma_g$, $\gamma_{API}$, and $T$, calculate $P_b$.

Standing (1947)

The earliest widely-used correlation, developed from 105 California crude oil samples:

$$P_b = 18.2 \left[ \left( \frac{R_s}{\gamma_g} \right)^{0.83} \frac{10^{0.00091 \, T}}{10^{0.0125 \, \gamma_{API}}} - 1.4 \right]$$

Where:

• $P_b$ = bubble point pressure, psia
• $R_s$ = solution gas-oil ratio, scf/STB
• $\gamma_g$ = gas specific gravity (air = 1.0)
• $\gamma_{API}$ = oil API gravity, °API
• $T$ = temperature, °F

Applicability Range:

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Vasquez and Beggs (1980)

Developed from over 5,000 data points with API gravity-dependent coefficients:

$$P_b = \left[ \frac{R_s}{C_1 \, \gamma_g \, \exp \left( \frac{C_3 \, \gamma_{API}}{T + 459.67} \right)} \right]^{1/C_2}$$

Coefficients:

Where:

• $T$ = temperature, °F (converted to °R with +459.67)

Applicability Range:

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Glasø (1980)

Developed from 45 North Sea crude oil samples using a correlation factor $P_b^*$:

$$P_b^* = \left( \frac{R_s}{\gamma_g} \right)^{0.816} T^{0.172} \, \gamma_{API}^{-0.989}$$$$P_b = 10^{\, 1.7669 + 1.7447 \log P_b^* - 0.30218 (\log P_b^*)^2}$$

Applicability Range:

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Al-Marhoun (1988)

Developed from 160 Middle East crude oil samples:

$$P_b = 5.38088 \times 10^{-3} \, R_s^{0.715082} \, \gamma_g^{-1.87784} \, \gamma_o^{3.1437} \, (T + 460)^{1.32657}$$

Where:

• $\gamma_o$ = oil specific gravity = $\frac{141.5}{131.5 + \gamma_{API}}$
• $T$ = temperature, °F (converted to °R with +460)

Applicability Range:

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Petrosky and Farshad (1993)

Developed from Gulf of Mexico crude oil samples:

$$X = 7.916 \times 10^{-4} \, \gamma_{API}^{1.5410} - 4.561 \times 10^{-5} \, T^{1.3911}$$$$P_b = \frac{112.727 \, R_s^{0.577421}}{\gamma_g^{0.8439} \, 10^X} - 1391.051$$

Applicability Range:

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Dokla and Osman (1992)

Developed from UAE crude oil samples:

$$P_b = 8363.86 \, R_s^{0.724047} \, \gamma_g^{-1.01049} \, \gamma_o^{0.107991} \, (T + 460)^{-0.952584}$$

Where:

• $\gamma_o$ = oil specific gravity = $\frac{141.5}{131.5 + \gamma_{API}}$

Applicability Range:

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Dindoruk and Christman (2004)

Developed from Gulf of Mexico deepwater crude oils using complex regression:

$$A = \frac{a_1 \, T^{a_2} + a_3 \, \gamma_{API}^{a_4}}{\left( a_5 + \frac{2 \, R_s^{a_6}}{\gamma_g^{a_7}} \right)^2}$$$$P_b = a_8 \left[ \frac{R_s^{a_9}}{\gamma_g^{a_{10}}} \cdot 10^A + a_{11} \right]$$

Coefficients:

Applicability Range:

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Correlation Selection Guidelines

By Region

By Fluid Properties

Statistical Performance

Based on the Brazilian Campos Basin study comparing 20 correlations:

Note: Statistical performance varies significantly by dataset. Regional correlations typically outperform global correlations when applied to their development region.

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Related Documentation

• Solution Gas-Oil Ratio (Rs) — input parameter for Pb correlations
• Oil Formation Volume Factor (Bo) — property at bubble point
• Oil Viscosity Correlations — μo above and below bubble point
• PVT Properties Overview — correlation selection strategy

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References

1. Standing, M.B. (1947). "A Pressure-Volume-Temperature Correlation for Mixtures of California Oils and Gases." Drilling and Production Practice, API, pp. 275-287.

2. Vazquez, M. and Beggs, H.D. (1980). "Correlations for Fluid Physical Property Prediction." Journal of Petroleum Technology, 32(6), pp. 968-970.

3. Glasø, Ø. (1980). "Generalized Pressure-Volume-Temperature Correlations." Journal of Petroleum Technology, 32(5), pp. 785-795.

4. Al-Marhoun, M.A. (1988). "PVT Correlations for Middle East Crude Oils." Journal of Petroleum Technology, 40(5), pp. 650-666.

5. Petrosky, G.E. and Farshad, F.F. (1993). "Pressure-Volume-Temperature Correlations for Gulf of Mexico Crude Oils." SPE Reservoir Engineering, 8(4), pp. 416-420.

6. Dokla, M.E. and Osman, M.E. (1992). "Correlation of PVT Properties for UAE Crudes." SPE Formation Evaluation, 7(1), pp. 41-46.

7. Dindoruk, B. and Christman, P.G. (2004). "PVT Properties and Viscosity Correlations for Gulf of Mexico Oils." SPE Reservoir Evaluation & Engineering, 7(6), pp. 427-437.

8. Santos, R.G., Silva, J.A., Mehl, A., and Experiment, P.E. (2019). "Comparison of PVT Correlations with PVT Laboratory Data from the Brazilian Campos Basin." Brazilian Journal of Petroleum and Gas, 13(3), pp. 129-157.