The formation of three phases with CO2/oil mixtures at temperatures below about 120°F is well established. Several West Texas crude oils form three phases at CO2 concentrations higher than about 55% and pressures ranging between 900 and 1300 psia. These phases include an oleic phase (L1), a gaseous phase (V), and a CO2-rich liquid phase (L2). Although some authors have published equation-of-state (EOS) calculations of this type of behavior and used parameter tuning to match their experimental data, they did not give a methodology for characterizing these fluids. This paper presents a reservoir fluid characterization scheme for three-phase CO2/oil mixtures. An analytical procedure has been developed to generate mole fraction and density distributions for the heavy oil fraction. These distributions are then used for calculating EOS properties of heavy fraction components and for lumping into pseudocomponents. A new correlation for CO2-hydrocarbon binary interaction coefficients was required to make accurate predictions of three-phase (L1-L2-V) regions as well as the liquid-liquid (L1L2) region at higher pressures. Results for four West Texas crude oils are presented to validate the fluid characterization scheme. The first two cases, at 83°F and 94°F, exhibit large three-phase regions and the pressure-composition behavior has been predicted with good accuracy. The other two cases, at 105°F and 110°F, exhibit small three-phase regions and very good agreement has been obtained between the experimental and predicted pressure-composition diagrams and between compositional simulations and slimtube displacement experiments. Furthermore, this fluid characterization scheme has been implemented on a workstation using an expert system shell and is fast and easy to use.

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