Yousef Kazemzadeh

The relative permeability and capillary pressure data are critically important in estimating reservoir parameters in reservoir behavior simulation and predicting its future performance. They are critically used in comprehensive studies and the preparation of development plans. Routinely in the industry, the relative permeability curves are either determined and corrected by the analytical methods (e.g., the JBN method) or history matching. In these methods, the capillary pressure effects are generally ignored. However, the fluid flow across the heterogeneous carbonate reservoir rocks is mainly controlled by the capillary effect due to their pore size distribution and the complex mixed wettability behavior. Consequently, considering both capillary and viscous impact and the other governing mechanisms in the extraction of fluid flow functions should be regarded as necessary, especially in heterogeneous media. The effect of the capillary pressure curve on the determination and correction methods of relative permeability has been rarely addressed in the literature. Moreover, in the complex behavior of the heterogeneous mixed-wet carbonate rocks, the impact of the wettability preference on the flow functions has not been frequently reported for the reservoir fluids and the modified fluids, such as in the case of IOR/EOR methods (e.g., low salinity, engineered water, and micellar methods). For this purpose, in this study, a series of capillary pressure and relative permeability tests have been performed on different carbonate plug samples. Then, the relative permeability curves of the plug samples were measured and corrected in two cases: Pc = 0 and Pc≠0 (concerning the centrifuge data), to investigate the relative permeability of both phases. The results indicated that the injection fluid and initial wettability of the rock are critically important parameters in considering the capillary pressure as a factor in the calculation and correcting of the relative permeability