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

Bahareh Nojabaei, Russell T. Johns

Research output: Chapter in Book/Report/Conference proceedingConference contribution

9 Scopus citations


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.

Original languageEnglish (US)
Title of host publicationSociety of Petroleum Engineers - SPE Reservoir Simulation Symposium 2015
PublisherSociety of Petroleum Engineers
Number of pages18
ISBN (Electronic)9781510800618
StatePublished - 2015
EventSPE Reservoir Simulation Symposium 2015 - Houston, United States
Duration: Feb 23 2015Feb 25 2015

Publication series

NameSociety of Petroleum Engineers - SPE Reservoir Simulation Symposium 2015


OtherSPE Reservoir Simulation Symposium 2015
Country/TerritoryUnited States

All Science Journal Classification (ASJC) codes

  • Modeling and Simulation
  • Geochemistry and Petrology


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