One potential method of geologically sequestering carbon dioxide (CO2) is to inject the gas into brine-filled, subsurface formations. Within these low-permeability rocks, fractures exist that can act as natural fluid conduits. Understanding how a less viscous fluid moves when injected into an initially saturated rock fracture is important for the prediction of CO2 transport within fractured rocks. Our study examined experimentally and numerically the motion of immiscible fluids as they were transported through models of a fracture in Berea sandstone. The natural fracture geometry was initially scanned using micro-computerized tomography (CT) at a fine volume-pixel (voxel) resolution by Karpyn et al. [1]. This CT scanned fracture was converted into a numerical mesh for two-phase flow calculations using the finite-volume solver FLUENT® and the volume-of-fluid method. Additionally, a translucent experimental model was constructed using stereolithography. The numerical model was shown to agree well with experiments for the case of a constant rate injection of air into the initially water-saturated fracture. The invading air moved intermittently, quickly invading large-aperture regions of the fracture. Relative permeability curves were developed to describe the fluid motion. These permeability curves can be used in reservoir-scale discrete fracture models for predictions of fluid motion within fractured geological formations. The numerical model was then changed to better mimic the subsurface conditions at which CO2 will move into brine saturated fractures. The different fluid properties of the modeled subsurface fluids were shown to increase the amount of volume the less-viscous invading gas would occupy while traversing the fracture.

This content is only available via PDF.
You do not currently have access to this content.