Impact of relative permeability hysteresis on geological CO2 storage

Relative permeabilities are the key descriptors in classical formulations of multiphase flow in porous media. Experimental evidence and an analysis of pore‐scale physics demonstrate conclusively that relative permeabilities are not single functions of fluid saturations and that they display strong hysteresis effects. In this paper, we evaluate the relevance of relative permeability hysteresis when modeling geological CO 2 sequestration processes. Here we concentrate on CO 2 injection in saline aquifers. In this setting the CO 2 is the nonwetting phase, and capillary trapping of the CO 2 is an essential mechanism after the injection phase during the lateral and upward migration of the CO 2 plume. We demonstrate the importance of accounting for CO 2 trapping in the relative permeability model for predicting the distribution and mobility of CO 2 in the formation. We conclude that modeling of relative permeability hysteresis is required to assess accurately the amount of CO 2 that is immobilized by capillary trapping and therefore is not available to leak. We also demonstrate how the mechanism of capillary trapping can be exploited (e.g., by controlling the injection rate or alternating water and CO 2 injection) to improve the overall effectiveness of the injection project.