Quantitative characterization of microscopic pore structures in carbonate rocks and numerical simulation of oil–water two-phase flow considering key multiphase flow parameters

Abstract Characterizing microscopic pore structures and analyzing oil–water two-phase flow behavior are critical for optimizing development strategies in carbonate reservoirs. This study constructed the digital core model using computed tomography (CT) scanning and three-dimensional (3D) digital reconstruction technology, achieving precise characterization of pore structure features. Three connectivity models were established: pore-type (S1), fracture-pore-type (S2), and fracture-type (S3), with further investigation into the effects of wetting angle ( θ ), capillary number (lgCa), and viscosity ratio ( M ) on oil–water flow simulation. Results indicated that the 3D pore structure model exhibited a surface porosity range of 4.48% to 11.21% and a fractal dimension of 2.21, reflected irregular pore geometry and high spatial complexity. The stress distribution demonstrated significant stress concentration phenomenon, where stress values at pore corners and terminations were approximately 1–2 orders of magnitude higher than those in the rock matrix. Flow velocity increased sharply at pore throat constrictions, with the most prominent velocities observed in preferential flow channels. Fractures in S2 and S3 acted as high-permeability preferential pathways, both exhibiting superior connectivity compared to S1. The oil recovery efficiency for S1-S3 showed an inverse correlation with θ and M but a positive correlation with lgCa. Residual oil of S1 primarily existed as porous and corner-shaped forms, while S2 and S3 predominantly exhibited blind-end types. Pore structure was identified as the main factor causing differences in oil recovery efficiency. The contributions of the three factors to recovery efficiency, ranked from highest to lowest, followed the order: M > θ > lgCa.