Abstract
A deep understanding of the pore-scale fluid flow mechanism during the CO2 flooding process is essential to enhanced oil recovery (EOR) and subsurface CO2 sequestration. Two-phase flow simulations were performed to simulate the CO2 flooding process based on the phase-field method in this study. Two-dimensional models with random positions and sizes of grains of circular shape were constructed to reproduce the topology of porous media with heterogeneous pore size distributions in the reservoir rock. A multiple-parameter analysis was performed to investigate the effects of capillary number, viscosity ratio, wettability, density, gravity, interfacial tension, and absolute permeability on the two-phase fluid flow characteristics. The results indicated that when the capillary number and viscosity ratio were large enough, i.e., log Ca = −3.62 and log M = −1.00, the fingering phenomenon was not obvious, which could be regarded as a stable displacement process. CO2 saturation increased with the increase in the PV value of the injected CO2. Once the injected CO2 broke through at the outlet, the oil recovery efficiency approached stability. Two types of broken behaviors of the fluids were observed during the wettability alternation, i.e., snap-off and viscous breakup. Snap-off occurred when capillary forces dominated the fluid flow process, while viscous breakup occurred with a low viscosity ratio. With a low capillary number, the flooding process of the injected CO2 was mainly controlled by the capillary force and gravity. With the decrease in the interfacial tension between the fluids and the increase in the permeability of the porous media, the recovery of the displaced phase could be enhanced effectively. In the mixed-wet model, with the increase in the percentage of the nonoil-wetted grains, the intersecting point of the relative permeability curve moved to the right and led to a higher oil recovery.