Pore-scale study of three-phase displacement in porous media

Abstract

Carbon capture, utilization, and storage have been an effective way to deal with global climate issues. Injecting CO2 into depleted oil reservoirs can reach the dual goal of carbon storage and enhanced oil recovery. To optimize the gas injection strategy, it is necessary to understand the underlying mechanisms of three-phase fluid flow of oil, water, and gas. In this study, a lattice Boltzmann color gradient model is used to investigate the pore-scale three-phase displacement process in porous media. Gas is injected into the porous domain initially occupied by water and oil. Typical microscopic behaviors, including coalescence and split-up, pinch-off, double and multiple displacement, as well as parallel flow, are identified and discussed. Effects of water content (ϕ), capillary number (Ca), wettability and viscosity ratio (M) on the flow pattern, and oil recovery rate are explored. The oil ganglia inhibit the development of gas fingers, causing stronger viscous fingering characteristics with increasing ϕ. The fingering pattern is located in the crossover zone for the Ca from 5 × 10−5 to 5 × 10−4. As ϕ increases, the oil recovery rate reduces. The oil ganglia tend to occupy small pores as oil wettability enhanced, making it more difficult to be drained out. The reduction of oil viscosity is beneficial to improve connectivity, thereby effectively enhancing the oil recovery. Finally, the CO2 storage rate is also evaluated. It is found that the storage rate is very sensitive to the initial oil–water distributions. In general, the storage rate increases as ϕ decreases, Ca increases, and oil wettability enhances.