fluid_properties · black oil
Bubble Point Pressure (Pb)
Pb = 18.2 × [(Rsi/γg)^0.83 × 10^(0.00091T−0.0125API) − 1.4] [Standing]
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Inputs
scf/STB
°F
—
°API
—
Description
Estimates bubble point pressure (Pb) — the pressure at which gas first comes out of solution from oil at reservoir temperature — from an empirical PVT correlation. Pb determines whether a reservoir is undersaturated (P > Pb, single-phase oil) or saturated (P ≤ Pb, two-phase), which controls which IPR model applies and whether compressibility-drive or solution-gas-drive dominates.
Variables
| Symbol | Unit | Description |
|---|---|---|
| Pb | psi | Bubble Point Pressure |
| Rsi | scf/STB | Solution GOR at the bubble point — the total dissolved gas in the oil at initial reservoir pressure. Measured from a PVT cell separator test or estimated from surface GOR at high pressure. |
| T | °F | Reservoir temperature, from a bottomhole temperature measurement or geothermal gradient estimate. |
| γg | — | Gas specific gravity relative to air, from a separator gas analysis. |
| °API | °API | Oil API gravity from a stock-tank sample or PVT report. |
| Method | — | 1 = Standing (1947); 2 = Vasquez-Beggs (1980, Pb form). Select the correlation most appropriate for your crude oil type and basin. |
Assumptions
- Rsi is the equilibrium solution GOR at the true bubble point, not the producing GOR at a later depleted pressure
- No significant CO2, H2S, or N2 in the reservoir gas — non-hydrocarbon components shift Pb away from the correlation prediction
- Reservoir temperature is constant (isothermal — no steam injection or thermal effects)
Limitations
- Correlation accuracy degrades for crude oils outside the original calibration range (Standing: API 16–58°, GOR 20–1,425 scf/STB; Vasquez-Beggs: more general but still empirical)
- For volatile-oil or condensate systems, measured PVT laboratory Pb is strongly preferred over any correlation estimate
- A correlated Pb should always be compared to field evidence (e.g., GOR trend, separator behavior) before being used as a design input for IPR modeling or artificial lift selection
Use Cases
- → IPR model selection: Determine whether the reservoir is above or below Pb to select between the linear productivity index (above Pb) and Vogel's IPR (below Pb) for well deliverability calculations.
- → Undersaturated material balance scope: Confirm P > Pb before applying the undersaturated oil material balance — the single-phase compressibility-drive form is valid only above the bubble point.
- → Depletion planning: Identify the pressure at which solution gas will begin breaking out of solution, enabling advance planning for gas handling facilities and compression requirements.
Related Calculations
Region Notes
Permian Basin
Wolfcamp/Bone Spring oils typically show Pb in the range of 1,500–3,500 psi at 180–240°F reservoir temperature, with initial reservoir pressures of 3,000–6,000 psi — many Permian wells start undersaturated and deplete below Pb over time.
Eagle Ford
Gas-condensate windows have Pb (dew point) rather than bubble point behavior. For volatile oil windows (API 40–48°, GOR 1,500–3,000 scf/STB), both correlations are near their reliability limits — measured PVT is strongly preferred.
Gulf of Mexico
GOM deepwater Miocene oil reservoirs often have Pb of 4,000–7,000 psi due to high dissolved GOR from long column height — well above initial reservoir pressure in some cases (undersaturated by hundreds to thousands of psi).
North Sea
Brent Group: typical Pb 2,000–4,000 psi at 200–260°F. Glaso (1980) was specifically calibrated to North Sea crude systems and may outperform Standing or Vasquez-Beggs here.
References
Primary source
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