A Mixed-Wet Hysteretic Relative Permeability and Capillary Pressure Model for Reservoir Simulations

Abstract

Summary A crucial component of all multiphase flow models is the relationship 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 through 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 from 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 two-phase flow in mixed-wet rocks are discussed. Relative permeabilities are predicted by 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 then was incorporated in the U. 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 also were validated against a sandpack experiment.