Regional Application of Relative Permeability Derived from CO2 Injection into Brine-Saturated Cores

The prediction of storage capacity, plume migration, and injection behavior is crucial for the successful implementation of Carbon Capture and Storage (CCS). Numerical simulators rely on a wide range of geological data, fluid dynamics inputs, and well-related datasets to evaluate CO2 storage performance. Among these inputs, saturation functions—comprising relative permeability and capillary pressure—play a pivotal role. Notably, displacement mechanisms differ significantly between the near-wellbore region and the deeper reservoir, primarily due to simultaneous mass transfer between phases, particularly when dry CO2 is injected into water-unsaturated zones.

In this study, we utilize experimental results from published data to investigate how relative permeability and capillary pressure vary across different reservoir regions. By performing history matching of experimental data, we aim to determine whether it is necessary to distinguish between these saturation functions when simulating various parts of the reservoir. The findings demonstrate that realistic relative permeability data, derived through history matching, can effectively represent diverse regions of the reservoir—provided that mass transfer effects are incorporated into near-wellbore simulations. This insight offers valuable guidance for implementing saturation functions from different experimental datasets into reservoir numerical models.