A Capillary Pressure Function for Interpretation of Core-Scale Displacement Experiments

A capillary pressure function is proposed for interpreting core-scale flow experiments. This function has been found suitable for a wide range of rock/fluid systems with different pore geometry and wettability characteristics. The petrophysical controls are reflected in the asymptotic values relating to irreducible saturation, and threshold capillary pressure, and in the shape parameters relating to the pore throat size distribution. This function works in both drainage and imbibition modes. When combined with a relative permeability model such as the Corey model, the same residual oil saturation value can be used in both the capillary pressure and the relative permeability functions. Examples are given to illustrate its application in interpreting oil/water multi-speed centrifuge experiments on a range of reservoir cores including high permeability sandstone rocks of intermediate wettability, as well as carbonate reservoir rocks. This paper also assesses the uncertainty of residual oil saturation, oil relative permeability and imbibition capillary pressure obtained from multi-speed centrifuge experiments using a numerical simulator.