Numeric determination of relative permeability of heterogeneous porous media with capillary discontinuities

Performance assessment of CO2 storage sites requires realistic modelling of the impact of heterogeneous aquifer properties on brine-CO2 flow. Heterogeneity gives rise to non-uniform saturation distributions that are affected by the balance of capillary, gravitational, and viscous forces. Since equivalent relative permeability and capillary pressure depend on saturation, their shape also varies with flow rate and gravitational phase segregation. This must be considered during performance assessment. Here we present a new workflow for the computation of equivalent relative permeability from force -balance controlled saturation distributions in heterogeneous rocks, computed with a novel continuum-scale flow solver with special provisions for material interfaces. Instead of simulating core flooding, the solver is used to recirculate phases across periodic boundaries until their distribution is in equilibrium with the applied forces. Our workflow is demonstrated on a segmented X-ray scan of a core sample of a laminated sandstone from a potential CO2 storage site in the Surat Basin, Australia, and an outcrop analogue model from Argentina. This application highlights how heterogeneity manifests in multi-phase flow functions, confirming rate dependence after eliminating capillary end effects.

Automated summary

Performance assessment of CO2 storage sites requires realistic modeling of the impact of heterogeneous aquifer properties on brine-CO2 flow. A new workflow for the computation of equivalent relative permeability is presented using a novel continuum-scale flow solver. The workflow is demonstrated on samples from a potential CO2 storage site in Australia and an outcrop analogue model from Argentina.