Pore-scale flow simulator for studying carbon dioxide capillary trapping under varying wettability scenarios

The pore space in sedimentary rocks could suffice to store all the C$O_2$ removed from the air, making geological sequestration a safe and permanent carbon storage technology in our global effort to reduce the atmospheric concentration of greenhouse gases (GHG). It involves the injection of C$O_2$ in either (dissolved) gas, liquid, or supercritical phase, into the pore space of subsurface rock formations. Once injected, C$O_2$ can become trapped due to structural mechanisms, like a low permeability caprock preventing the fluid from floating up, or capillary forces holding C$O_2$ droplets or bubbles within the constricted space of the pore channels. The most stable, albeit slower storage mechanism involves chemical processes like the mineralization of C$O_2$ when reacting with the rock surface to form solid carbonate minerals.

A better understanding of how the pore structure and material properties of the rock matrix influence the extent to which pressurized fluids can be injected and permeate the pore network is needed to accelerate innovation towards enhancing long-term storage in underground geological formations. In our work, we apply pore-scale flow simulations to the study of C$O_2$ storage in porous media modeled as a network of connected capillaries with spatially varying radii, providing an accurate representation of the pore space geometry extracted from high-resolution X-ray microtomography of suitable rocks. Experimental measurement of porosity and permeability of several sedimentary rocks with a range of morphologies, as well as high-speed optical imaging of flow through Si/Si$O_2#-based microfluidic channels using fluorescent microbeads, served validate single phase simulation results.

Multiphase flow simulations track the displacement in time of the fluid interface within each capillary, providing insight into the physics behind residual storage by analyzing the infiltration and retention of C$O_2$ inside the capillary network of a porous sandstone rock sample under varying fluid and rock parameters. A new simulation methodology is introduced to overcome the computational cost of these dynamic simulations on the high-resolution capillary network representation of the rock by carrying out the analysis on the aggregate result of multiple two-phase flow simulations on several statistically equivalent capillary network models of the rock sample, which retain topological properties of the original at a significantly lower computational cost. Our simulations showed that the conditions for maximum C$O_2$ 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. As the fluid interface contact angle is a manifestation of the wettability of the rock and may be modulated with additives in the injected fluid, this may offer a path to increasing the volume of stored C$O_2$ within the pore space of the rocks.