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CO2 injection is considered as one of the proven EOR methods and is being widely used nowadays in many EOR projects all over the globe. The process of in situ displacement of oil with CO2 gas is implemented in both miscible and immiscible modes of operation. In some oil reservoirs, CO2 miscibility will not be attained due to fluid composition characteristics as well as in situ pressure and temperature conditions. Laboratory determination of gas–oil relative permeability curves is usually performed with air, nitrogen, or helium gases, and the results are then implemented for both natural depletion processes (especially in reservoirs with “solution gas” or “gas cap” drive mechanisms) and gas injection processes. For the gas injection processes, it is therefore necessary to find out how selection of the gas phase would affect the relative permeability curves when the intention of developing the curves is to use them for immiscible CO2 displacement. In this study, a reservoir simulator was first used to quantitatively analyze the effect of variation in relative permeability data (due to the use of different gas phases) on production performance of a reservoir. Then, computational analysis was performed on changes in relative permeability curves upon using different gas phases with the aid of pore-scale modeling using statistical methods. To predict gas–oil relative permeability curves, a Shan–Chen-type multi-component multiphase Lattice Boltzmann pore-scale model for two-phase flow in a 2D porous medium was developed. Fully periodic and “full-way” bounce-back boundary conditions were applied in the model to get infinite domain of fluid with nonslip solid nodes. Incorporation of an external body force was performed by Guo scheme, and the influence of pore structure and capillary number on relative permeability curves was also studied for CO2–oil as well as N2–oil fluid pairs. The modeled relative permeability curves were then compared with experimental results for both these fluid pairs.

Pore-scale numerical modeling of relative permeability curves for CO2–oil fluid system with an application in immiscible CO2 flooding