Pore-scale direct simulation of CO2, water, and oil three-phase relative permeabilities considering mineral wettability and dissolution

CO2 enhanced oil recovery (CO2-EOR) is an important technology due to its dual advantages of increasing oil production and mitigating CO2 emission. However, complex multiphase seepage mechanisms that are critical to the successful application of CO2-EOR are still uncertain. Three-phase relative permeabilities of CO2, water, and oil in the oil reservoir are an important parameter to characterize multiphase flow. To quantitatively investigate these relative permeabilities, pore-scale direct simulations were performed using the Lattice Boltzmann Method (LBM). Given the complexity and diversity of factors affecting relative permeability, fluid distribution characteristics, and three-phase relative permeability isoperms were investigated in water-wet, oil-wet, and mixed-wet porous media, and their variation caused by calcite dissolution was further studied. Furthermore, two widely accepted models (i.e., Stone II and the Baker models) were compared with the simulation results, and their applicability was discussed. Results demonstrate that in both water-wet and oil-wet porous media, the isoperms of CO2, water, and oil relative permeability exhibit distinct variations. Additionally, in the mixed-wet sample, the presence of a high quartz content results in three-phase relative permeabilities resembling that of the single-wet sample with a water-oil contact angle of 60°. Furthermore, it is observed that the dissolution of calcite enhances the relative permeability of non-wetting fluids, but its effect on wetting fluids remains insignificant. The comparison of the predictive results from two empirical models with those obtained from LBM simulations demonstrates their superior accuracy in predicting three-phase relative permeability values in water-wet porous media while exhibiting limited applicability in oil-wet porous media.