The Mahu Sag in the Junggar Basin holds significant potential for oil and gas exploitation and development. However, the strong reservoir heterogeneity therein leads to a rapid decline in oil and gas production. Presently, the pre-CO₂ fracturing, gas flooding, sequestration (PCFS) synergistic technology is commonly employed for enhanced oil recovery from glutenite reservoirs. This study aims to investigate the impact of CO₂-water-rock interactions on pore structures during pre-flushing CO₂ fracturing, as well as CO₂ migration patterns in the process of gas flooding. Using a glutenite core taken from the Mahu Sag, we perform CO₂ soaking experiments, high-precision micro-computed tomography (micro-CT), and volume of fluid (VOF) method-based numerical simulations of two-phase flow in 3D digital cores. The results indicate that CO₂-water-rock interactions facilitate the dissolution-derived expansion of the pore structure, and the originally isolated channels converge into sheets, increasing the sweep range of CO₂ clusters. Meanwhile, this process induces secondary mineral precipitation and expansion, which can block or restructure pathways for fluid flow and, accordingly, change the flow paths and velocity of fluids in the pore structure. These, thereby, hinder the formation of the preferential flow pathways. Nevertheless, compared to the negative impact of secondary mineral precipitation and expansion, the pore space expansion under CO₂ soaking-induced dissolution is greater in positive effect. Specifically, the permeability is improved, so does the seepage capacity of pore structures. CO₂ clusters in different flow channels exhibit different morphologies (like convex or concave) at the displacement front. In the representative elementary volume (REV) models before and after CO₂ soaking, the dimensionless parameters (i.e., capillary number C_a, contact angle θ, and viscosity ratio M) exert varying degrees of influence on the displacement efficiency. Specifically, in the REV model after CO₂ soaking, exhibiting a relatively higher degree of porosity evolution, the displacement efficiency is more sensitive to changes in the dimensionless parameters. This indicates that the PCFS synergistic technology is more effective in the exploitation of reservoirs with higher-degree porosity development.

Spontaneous imbibition is an essential mechanism for recovering oil from low-permeability fractured water-driven reservoirs. To accurately capture the migration interface of oil-water two-phase flow under these conditions, this study employs phase field theory coupled with Cahn-Hilliard and Navier-Stokes equations. We conduct a numerical pore-scale investigation on countercurrent imbibition in low-permeability fractured porous media. The results show that pore-scale spontaneous imbibition can be divided into four stages. In the first stage, oil-water film is formed when oil contacts with water, and this contact line moves under the action of capillary force. In the second stage, the oil film at the end of the oil cluster ruptures to form isolated oil droplets. In the third stage, these oil droplets are surrounded by water and gradually transported outward. In the final stage, oil droplets accumulate in the fractures and are collectively expelled from the matrix. In the process of oil droplet migration, the phenomenon of sticking occurs under the influence of water extrusion and the internal structure of the matrix, which leads to the formation of residual oil. The increased complexity of open boundary and fracture development strengthens the imbibition effect by elevating the degree of spontaneous imbibition pore utilization, thus improving the oil utilization efficiency. The above findings can provide a numerical modeling reference for the study of spontaneous imbibition in fractured porous media, and at the same time, has some guiding significance for the development of low-permeability reservoirs.