fluid_properties · black oil
Oil Compressibility (Undersaturated)
co = (−1433 + 5·Rs + 17.2·T − 1180·γg + 12.61·API) / (10⁵·P) [undersaturated, Vasquez-Beggs 1980]
click formula to derive ↑
Inputs
scf/STB
°F
—
°API
psi
Description
Computes the isothermal compressibility of an undersaturated oil (above the bubble point) using the Vasquez-Beggs (1980) correlation. Oil compressibility governs the pressure decline per barrel produced in an undersaturated reservoir and is a required input to single-phase material balance and to the total-compressibility term in well-test analysis.
Variables
| Symbol | Unit | Description |
|---|---|---|
| co | μpsi⁻¹ | Oil Compressibility |
| Rsb | scf/STB | Solution gas-oil ratio at the bubble point (Rsb), from black_oil_pvt or a PVT report. Above the bubble point Rs is constant at Rsb, so this fixes the dissolved-gas content of the undersaturated oil. |
| T | °F | Reservoir temperature at which compressibility is evaluated. |
| γg | — | Gas specific gravity (air = 1.0), from a separator gas analysis. Typically 0.65–0.75 for associated gas. |
| °API | °API | Oil API gravity — the standard measure of oil density. |
| P | psi | Reservoir pressure (must be above the bubble point — this is the undersaturated compressibility). co is inversely proportional to pressure. |
Assumptions
- Reservoir pressure is above the bubble point — this is the undersaturated (single-phase liquid) compressibility only; below Pb, total compressibility is dominated by gas coming out of solution and this correlation does not apply
- The supplied Rs is the solution GOR at the bubble point (Rsb), which is constant above Pb
- Black oil of conventional composition — consistent with the worldwide dataset Vasquez-Beggs was fit to
Limitations
- Applies only above the bubble point. Below Pb the effective oil compressibility is far larger and dominated by liberated gas — use a saturated/total-compressibility treatment (e.g. via Bo, Bg, and Rs derivatives) instead
- Fitted-range annotations (fittedRange) are not authored on this calculator's inputs: the specific Vasquez-Beggs data ranges were not independently verified this session, so no fitted-range warning is shown yet — this is a disclosed gap, not an assertion that any input is universally valid
- As an empirical correlation it can err by 10–20% versus measured PVT for fluids far from its calibration set; use lab-measured co when available for material-balance-critical work
Use Cases
- → Undersaturated material balance: Provide co for the single-phase (undersaturated) material-balance expansion term used in material_balance_undersaturated to relate pressure decline to oil produced.
- → Total compressibility for well testing: Combine co with water and formation compressibilities (weighted by saturation) to build the total compressibility ct used in pressure-transient/skin analysis.
- → Reservoir energy screening: Gauge how much pressure support undersaturated fluid expansion provides before the bubble point is reached, informing whether pressure maintenance is needed early.
Related Calculations
Region Notes
Permian Basin
Undersaturated Wolfcamp/Bone Spring oils (35–45°API, Rsb 500–1,200 scf/STB) typically show co ≈ 8–20 μpsi⁻¹ at initial reservoir pressure, rising as pressure depletes toward the bubble point.
Gulf of Mexico
Deepwater Miocene undersaturated oils (25–40°API) commonly give co ≈ 6–15 μpsi⁻¹. Higher-GOR, lighter oils sit at the top of that range; validate against PVT for volatile systems near the correlation's edge.
Global
As a rule of thumb undersaturated co falls in 5–30 μpsi⁻¹, increasing with API, GOR, and temperature and decreasing with pressure. Values outside that band usually indicate an input error or a near-bubble-point/volatile fluid.
References
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