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 CO₂ sequestration processes. Here we concentrate on CO₂ injection in saline aquifers. In this setting the CO₂ is the nonwetting phase, and capillary trapping of the CO₂ is an essential mechanism after the injection phase during the lateral and upward migration of the CO₂ plume. We demonstrate the importance of accounting for CO₂ trapping in the relative permeability model for predicting the distribution and mobility of CO₂ in the formation. We conclude that modeling of relative permeability hysteresis is required to assess accurately the amount of CO₂ 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 CO₂ injection) to improve the overall effectiveness of the injection project.