A crucial component of all multiphase flow models is the relationships among relative permeabilities, fluid saturations, and capillary pressures. Relative permeability and capillary pressure parametric models can be very useful for predicting fluid behavior in porous media. However, relative permeabilities and capillary pressures used in oil reservoir simulators are commonly determined via interpolation between laboratory measurements. A problem with this approach is that the relations are valid only for the specific saturation path measured. Therefore, simulations of oil production using different saturation paths than those measured are likely to be in error and can limit the investigation of alternative production scenarios. In this paper, saturation-history-dependent relative permeability and capillary pressure functions for mixed-wet rocks are discussed. Relative permeabilities are predicted via integrating a pore-distribution model between limits that reflect how oil and water are distributed in mixed-wet porous media. The proposed model was tested against mixed-wet capillary pressure data. The model was then incorporated in the University of Texas Chemical Compositional simulator called UTCHEM to compare waterflood simulations in water- and mixed-wet reservoirs. The simulation results agree qualitatively with laboratory core and field observations. The model and its implementation were also validated against sandpack experiment.

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