The distribution of CO₂ is critical to the efficiency and stability of carbon storage; however, the roles of wettability and capillary number in controlling CO₂ distribution remain inadequately understood. In this study, visual waterflooding experiments and numerical simulations were performed using five homogeneous micromodels with distinct wettability characteristics to examine how wettability and capillary number influence CO₂ distribution during short-term waterflooding. The results demonstrate that both wettability and capillary number govern CO₂ distribution patterns and saturation. These patterns include continuous distribution, cluster-like distribution, and isolated bubbles. Both experimental and simulation data reveal that the total residual CO₂ saturation follows a non-monotonic trend with increasing contact angle, while it increases as the capillary number decreases. As the capillary number varies, the displacement behavior transitions gradually from a stable displacement regime to a capillary fingering regime, resulting in variations in residual CO₂ saturation. With changing wettability, cooperative pore filling leads to fluid bypassing, thereby modifying the saturation of continuously distributed CO₂. In contrast, variations in the saturation of cluster-like and isolated bubble CO₂ are attributed to snapoff mechanisms initiated by preceding film flow. This study elucidates how wettability and capillary number govern the residual trapping and distribution of CO₂ at the pore scale.

Tight and shale reservoirs are forming important components of the global hydrocarbon landscape, which impede the free thermal movement of fluid molecules, with numerous nanoscale pores. The confined hydrocarbons in the nanopores cannot be industrially produced from conventional exploration and development methods, with deviated fluid phase behavior under nano-confinement effects. Most commonly important fluid phase behavior in nanopores has been simulated and compared with the bulk cases previously, including phase coexistence, critical properties, and density distribution of confined fluids. This paper focuses on the deviated fluid phase behavior under nano-confinement effects by Monte Carlo modeling. The Monte Carlo simulation is still limited to modeling the macroscopic pore-related behavior like capillarity and complex fluid and solid materials. Moreover, the Monte Carlo simulation is usually scale-restricted and the pore-size range where the nano-confinement effect fails to work needs to be quantitatively determined. Overall, for the tight and shale fluid phase behavior, a functional Monte Carlo model, coupled with the long-range correction and configuration bias techniques, is suggested to include both the multi-component fluids and skeleton.