Consistent extrapolation of black and volatile oil fluid properties above original saturation pressure for tight and conventional reservoirs

Black-oil fluid properties are determined by lab measurements or can be calculated through flash calculations of the reservoir fluid. Allowing for a variable bubble-point pressure in black-or volatile-oil models requires a table of fluid properties be extended above the original bubble-point. Reservoir simulation accuracy, however, may be affected by discontinuities in the input data and poor predictions of extrapolated fluid properties. Common practice is to add surface gas to the original oil in the lab and increase the pressure to reach a new bubble-point. Another approach is to use linear extrapolation of oil and gas K-values with pressure on a log-log plot, where K-values are equal to 1.0 at a pseudo-critical or convergence pressure. The latter approach results in discontinuities in the phase behavior. We calculate continuous black-oil fluid properties above the original bubble-point by adding a fraction of the equilibrium gas at one bubble-point pressure to achieve a larger bubble-point pressure. This procedure continues until a critical point is reached at the top of the pseudocomponent pressure-composition diagram. Unlike other methods commonly used or recently proposed, the approach provides a smooth and continuous pressure-composition curve to the critical point. The model further allows for reinjection of produced gas, methane, or CO₂ to increase oil recovery for both volatile and black oils. We show how to tune the models to the MMP by matching the appropriate critical point pressure. Further, the approach allows the use of black-oil or volatile-oil properties for tight rocks where capillary pressure alters the saturation pressures by decreasing the bubble-point pressure or increasing the dew-point pressure. Bubble-point pressure in the new model is a function of both capillary pressure (effective pore radius) and gas content. The phase behavior is also described on ternary diagrams for up to four components (water, oil, gas, and CO₂ or CH₄) and three phases (aqueous, oleic, gaseous) to allow for miscible and immiscible injection (or soaking) of various gases. The new phase behavior could be easily incorporated in a compositionally-extended black-or volatile-oil simulator. The approach could also be extended to model gas condensate reservoirs with or without gas injection and capillary pressure.