An experimental investigation on relative permeability ratio coefficients and their prediction by using pore properties in carbonate rocks

Relative permeability is one of the dynamic properties in reservoir fluid flow that is essential in characterizing the simultaneous flow of fluids in the reservoir and plays a vital role in reservoir production studies and EOR processes. The relative permeability ratio is used to describe better and employ relative permeability data presented in individual curves. The simultaneous flow of reservoir fluids is well described by the coefficients a and b, which are obtained from the linear part of the ratio curve. These coefficients, considered critical parameters of the relative permeability curve, are complex. Factors and concepts affecting the a and b coeffecients are not well defined. The corresponding values of a and b were obtained from the experimental relative permeability data for carbonate rocks. Factors affecting these coefficients were studied and evaluated in this paper. The results indicate that coefficient b is mainly affected by the pore size heterogeneity and fluid saturation distribution. In contrast, the coefficient a is influenced by residual water saturation and fine pores. Another notable result of this study was using experimental relationships to determine the relative permeability parameters, including coefficients a and b and residual saturation values using mercury injection data.