Pore-Scale Mechanisms of Waterflooding in Saline Reservoirs: Coupling Salt Dissolution, Interfacial Dynamics, and Multiphase Flow by Lattice Boltzmann Simulation

Summary

Oil reservoirs rich in soluble salt minerals, such as intersalt shale oil, subsalt shale oil, and carbonate reservoirs, undergo significant physicochemical interactions during water injection, which significantly influence oil recovery. Conventional simulation approaches fail to capture the coupled effects of salt dissolution on multiphase flow, particularly the concentration-dependent variations in viscosity and interfacial tension (IFT). In this study, we developed a new lattice Boltzmann method (LBM) framework that incorporates correction functions coupling brine concentration with both viscosity and IFT, and validated the model using in-situ computed tomography (CT) imaging experiments on artificial salt/reservoir composite cores. Unlike conventional approaches, our method incorporates correction functions that couple brine concentration with both viscosity and IFT, enabling a more realistic simulation of the synergistic effects of salt dissolution in multiphase flow systems. Our simulation results show strong agreement with experimental data, revealing not only how injection pressure and brine concentration alter flow pathways and displacement efficiency in both homogeneous cores and salt/reservoir composite cores but also clarifying the influence of the presence of a salt layer on the waterflooding oil-recovery process. This work provides a robust predictive tool for optimizing waterflooding strategies in saline reservoirs, thereby enhancing oil recovery while mitigating operational challenges caused by salt dissolution.