Use of in situ saturation data in estimation of two-phase flow functions in porous media

Accurate estimates of multiphase flow functions (relative permeability and capillary pressure) are necessary for reliable prediction of oil recovery from a reservoir and nonaqueous phase (NAPL) contaminants from aquifers. Current methods of estimating two-phase relative permeabilities from unsteady state displacement experiments are based on Buckley-Leverett model. This model assumes that the medium is homogeneous, flow is one-dimensional and capillary effects are negligible. These assumptions are not valid for many reservoir rock samples. In this work, we have used a parameter estimation procedure to predict simultaneously relative permeabilities and capillary pressure functions from production, pressure drop as well as in situ saturation data of unsteady state displacements. Heterogeneities in porosity, permeability, residual oil saturation and initial saturation are accounted for in our model. Experimental data, estimated flow functions, and associated uncertainties are presented for two reservoir rock samples. The in situ saturation profiles are better matched by our technique over the JBN method because the heterogeneities of the sample are incorporated into our estimation procedure. Use of in situ saturation profile reduces the uncertainties in the estimations.