Investigation of CO2 displacement oil with modified diffusion model in high water cut oil reservoir

Many oilfields have entered a high-water content stage after years of water-driven extraction, leading to common multiphase coexistence scenarios. However, current studies mainly focus on two-phase flow, and the influence of CO₂-oil–water three-phase flow diffusion is insufficiently addressed. In this study, a two-dimensional pore three-phase flow-diffusion model was developed to simulate a more realistic exfoliation process. The effects of temperature, pressure, and injection velocity on the recovery rate were comparatively analyzed. The simulation results show that the modified model improves the recovery rate by 4.9% and the prediction accuracy by 20.8%, which is more consistent with the experimental results. Temperature significantly affects crude oil viscosity and transforms CO₂ from the liquid to the supercritical state, enhancing mobility and recovery. Increased pressure raises CO₂ solubility in oil and reduces clustered residual oil formation. Higher injection velocities create a greater driving effect, increasing breakthrough exits and improving recovery, though they may also result in less effective CO₂ distribution horizontally or vertically, thus reducing recovery. The study, which investigates the influence of CO₂-oil–water three-phase flow diffusion, is characterized by its methodological rigor. It not only considers the impact of the aqueous phase on CO₂ oil displacement but also corrects the model error when diffusion is not considered, thereby enhancing the reliability of our findings and providing a reference for mass transfer studies in multi-liquid-phase systems at the pore scale.