Numerical Evaluation of Natural Gas Flooding Potential in a Deep Sandstone Reservoir Integrated with Phase Behavior

Abstract

Deep sandstone reservoirs typically exhibit complex geological characteristics, including high temperature, high pressure, and high salinity. These reservoirs are predominantly developed using a wide well spacing strategy under natural depletion and water flooding, and no mature tertiary recovery technique has yet been established. Since chemical flooding is essentially inapplicable under such extreme reservoir conditions, natural gas injection offers unique potential due to its multiple displacement mechanisms and low sensitivity to temperature and salinity. This study conducts numerical simulations of natural gas injection in deep sandstone reservoirs coupled with phase behavior to systematically evaluate its enhanced oil recovery (EOR) potential. Phase behavior matching of the reservoir fluid is performed using the PVTi module to determine key component properties, providing an accurate pressure–volume–temperature (PVT) basis for subsequent simulations. Meanwhile, the water drive characteristic curve method is employed to predict the ultimate recovery of the target reservoir under water flooding. Subsequently, based on the fitted equation of state (EOS), a numerical simulation model of the target reservoir is constructed and history-matched against field production data. The calibrated model is then applied to quantify the development potential of both gas injection and water flooding in the target reservoir. The water drive characteristic curve predicts a water flooding recovery of 59.24%. Numerical simulation results show that rich gas flooding achieves a recovery factor of 72.28%, significantly higher than the 65.21% obtained from dry gas flooding. These results provide a theoretical basis for the efficient development of similar reservoirs.