capillary trapping under varying wettability scenarios

Geological sequestration involves the injection of CO₂ in either (dissolved) gas, liquid, or supercritical phase, into the pore space of subsurface rock formations. The pore space in sedimentary rocks could suffice to store all the CO₂ removed from the air, making geological sequestration a promising carbon storage technology.  Once there, CO₂ can become trapped due to a series of physical and/or chemical mechanisms, some relating directly to the pore scale, such as capillary trapping inside the rock’s microscopic pore channels.  In this work, we apply pore-scale flow simulations to the study of CO₂ storage in geological formations modeled as a network of connected capillaries with spatially varying radii.  Multiphase flow simulations were employed to study the physics behind residual storage by analyzing the infiltration and retention of CO₂ inside the capillary network of a porous sandstone rock sample under varying fluid and rock parameters. We found that the conditions for maximum CO₂ storage through capillary trapping in a water filled reservoir greatly depends on the fluid interface contact angle and on the applied pressure gradient, followed by the absolute temperature of the reservoir, as it affects the viscosity of the fluids. The fluid interface contact angle is a manifestation of the wettability of the rock and may be modulated with additives in the injected fluid. Our simulation showed that beyond a pressure threshold, a contact angle approaching 90 degrees maximizes the storage of super-critical CO₂ as the effect of capillary pressure is minimized, leaving viscosity as the dominant forces limiting the displacement of the resident fluid from the pores.