Dynamic prediction of whole CO2 flooding development process in low permeability reservoirs - WANG Yanwei, LIN Lifei, WANG Hengli (Youqicang pingjia yu kaifa, 2025)
CO2 flooding can effectively enhance oil recovery of low permeability reservoirs. However, due to the common presence of strong heterogeneity in such reservoirs, accurately predicting the development dynamics of CO2 flooding is difficult. To address this issue, a time-node-based dynamic prediction model for the entire CO2 flooding process in low permeability reservoirs was developed, based on the comprehensive consideration of factors such as throat size and distribution, viscosity reduction due to CO2 dissolution, and changes in interfacial tension, combined with CO2 flooding seepage mechanics theory. This model achieved innovative whole-process dynamic prediction by accounting for reservoir micro-heterogeneity. The results showed that the throat radius significantly influences flow resistance during the early stage of CO2 displacement. Meanwhile, the continuous iterative coupling of diffusion, dissolution, viscosity reduction, and drag reduction during the CO2 displacement process led to differences in the displacement front positions in throats of different radii at the same time. The difference was reflected in development dynamics: larger pore-throat radius and better reservoir properties led to earlier gas breakthrough and higher gas-oil ratio at the same time. According to the CO2 volume fraction distribution between injection and production wells, the displacement process could be divided into three zones: pure CO2 zone, mass transfer diffusion zone, and pure oil zone. When the front of the mass transfer diffusion zone in large throats reached the production well, gas breakthrough occurred, and oil production gradually increased; thereafter, the oil recovery increased rapidly. When the front of the pure CO2 zone reached the production well, the gas-oil ratio increased rapidly, oil production decreased sharply, and the growth rate of the recovery curve slowed down and eventually stabilized. Compared with the experimental results, the predicted recovery errors of the model were 5.7% and 4.5%, respectively, with good agreement in gas-oil ratio and oil recovery curves. This method was used to predict the development dynamics of the H3 experimental area, providing critical guidance for analyzing CO2 flooding performance and timely adjustment of the development strategy for gas channeling wells.