Microscopic simulations of oil–water two-phase flow in high-porosity and low-permeability carbonate porous media

The pore types in carbonate reservoirs are highly diverse, and a detailed characterization of the flow behavior of oil–water two-phase flow at the pore scale within different pore storage types holds significant importance. In this work, digital core reconstruction based on computed tomography scanning technology has quantitatively characterized the micro-pore structures of these rocks, and typical core samples representing diverse pore storage types have been selected for microscopic visualization simulation studies. Utilizing the volume of fluid method, we conducted visual simulations of oil–water two-phase flow in porous media. Comparisons were made under varying conditions of wettability, displacement pressure, and viscosity ratio regarding breakthrough time, residual oil distribution, and changes in residual oil saturation, revealing the dynamic flow characteristics of oil–water phases within different pore types during water flooding. The results demonstrate that complex pore-throat structures (large pores, small throats) significantly reduce the displacement efficiency during microscopic water flooding. Specifically, moldic pores exhibit high permeability, leading to oil phase retention; biological chamber pores (intraparticle pores) are characterized by the most pronounced high-porosity and low-permeability features, with numerous blind-end voids and poor connectivity, resulting in limited displacement effectiveness, whereas intergranular dissolution pores show good connectivity, achieving more efficient oil recovery. The mobility of the water phase among the three pore types follows the order: intergranular dissolution pores > moldic pores > biological chamber pores. Furthermore, improvements in wettability, increased displacement pressure, and reduced oil–water viscosity ratio serve to optimize the flow process at the microscopic level, thereby enhancing overall oil recovery efficiency.