Pore-Scale Modeling of Gas–Oil Two-Phase Flow Based on the Phase-Field Method—A Case Study of Glutenite Reservoirs in China

Abstract

This work employs the phase field method combined with a realistic microscopic heterogeneous pore structure model to conduct numerical simulations of CO2–oil two-phase flow. This study investigates the diffusion behavior of CO2 during the displacement process and analyzes the impact of various parameters such as the flow rate, the contact angle, and interfacial tension on the displacement effect. The results indicate that, over time, saturated oil is gradually replaced by CO2, which primarily flows along channels with larger throat widths and lower resistance. The preferential flow paths of CO2 correspond to high flow rates and high pore pressures occupied by CO2. As the injection rate increases, the CO2 filtration rate increases, CO2 movement becomes more pronounced, and CO2 saturation rises. Beyond the optimal flow rate, however, the displacement effect worsens. The wettability of the porous medium predominantly determines the CO2 migration path during the displacement process. As the contact angle increases, CO2 wettability towards the rock improves, significantly enhancing the displacement effect. Under different interfacial tension conditions, the recovery rate increases with the amount of CO2 entering the porous medium, but no clear correlation is observed between interfacial tension and the recovery rate. Therefore, it is challenging to further improve the recovery rate by altering interfacial tension. The viscosity ratio affects wettability and thereby influences the displacement effect. Lower viscosity ratios result in reduced wettability effects, making CO2 diffusion more difficult. This study provides theoretical guidance and technical support for CO2-EOR (Enhanced Oil Recovery) in highly heterogeneous reservoirs on a field scale.