Overview
The bubble point pressure (Pb) is the pressure at which the first bubble of gas forms in an oil system as pressure is reduced at constant temperature. It is a critical parameter for reservoir characterization, PVT analysis, and production planning. Above Pb, oil is undersaturated (single-phase liquid); below Pb, gas liberates from solution, creating two-phase flow.
Theory
Standing's correlation (1947), developed from 105 experimentally determined bubble points on California crude oil systems, relates Pb to four readily measurable parameters: solution GOR (Rs), gas gravity (γg), oil API gravity, and reservoir temperature (T).
Formula
Standing Correlation (1947)
Pb = 18.2 * ((Rs / γg)^0.83 * 10^a - 1.4)
where:
a = 0.00091 * T - 0.0125 * API
| Symbol | Description | Units |
|---|---|---|
| Pb | Bubble point pressure | psia |
| Rs | Solution gas-oil ratio | scf/STB |
| γg | Gas specific gravity (air = 1) | dimensionless |
| T | Temperature | °F |
| API | Oil API gravity | °API |
Inverse — Estimating Rs from Pb
Rs = γg * ((Pb / 18.2 + 1.4) / 10^a)^(1/0.83)
Other Correlations (for comparison)
Vasquez-Beggs (1980):
Rs = C1 * γgs * P^C2 * exp(C3 * API / (T + 460))
where C1, C2, C3 depend on API > or < 30.
Glaso (1980):
log(Pb) = 1.7669 + 1.7447*log(Pb*) - 0.30218*(log(Pb*))^2
Pb* = (Rs/γg)^0.816 * T^0.172 / API^0.989
Worked Example
Given: Rs = 600 scf/STB, γg = 0.80, T = 220°F, API = 32°
Step 1: Calculate exponent a:
a = 0.00091 * 220 - 0.0125 * 32
= 0.2002 - 0.400
= -0.1998
Step 2: Calculate Pb:
Pb = 18.2 * ((600/0.80)^0.83 * 10^(-0.1998) - 1.4)
= 18.2 * (750^0.83 * 0.631 - 1.4)
= 18.2 * (298.5 * 0.631 - 1.4)
= 18.2 * (188.4 - 1.4)
= 18.2 * 187.0
= 3,403 psia
Valid Ranges
| Parameter | Range (Standing, 1947) |
|---|---|
| Pb | 130 – 7,000 psia |
| T | 100 – 258°F |
| Rs | 20 – 1,425 scf/STB |
| API | 16.5 – 63.8° |
| γg | 0.59 – 0.95 |
When to Use and When Not To
Use when:
- Quick screening / initial estimate
- California-type or light-medium crudes
- Lab PVT data is unavailable
Avoid when:
- Heavy oils (API < 15) — use Petrosky-Farshad or lab data
- High CO2 or H2S content (>5 mol%) — corrections needed
- Volatile oils or near-critical fluids — use EOS
References
- Standing, M.B. (1947). "A Pressure-Volume-Temperature Correlation for Mixtures of California Oils and Gases." Drilling and Production Practice, API.
- Vasquez, M. & Beggs, H.D. (1980). "Correlations for Fluid Physical Property Prediction." JPT, 32(6), 968–970.
- Glaso, O. (1980). "Generalized Pressure-Volume-Temperature Correlations." JPT, 32(5), 785–795.
- PetroWiki — Bubble point pressure: https://petrowiki.spe.org/Oil_fluid_properties