Аңдатпа
Abstract Storage and the long-term immobilization of CO2 in saline aquifers and depleted fields occur due to several mechanisms, such as capillary trapping. The efficiency of this process is controlled by the competition between governing capillary, viscous, and gravity forces. Pore-scale factors such as wettability, pore geometry, and heterogeneity control these forces. Experimental observation of the effect of these parameters on capillary trapping at the pore scale is challenging. Micromodels help analyze CO2 trapping under different capillary/viscous force conditions. With this technique, it is possible to quantitatively and qualitatively track CO2 distribution patterns at different capillary numbers. This study investigates CO2 displacement and residual trapping using a set of custom-designed 2D glass micromodels representing both homogeneous and heterogeneous pore networks. The experiments were performed by varying typical reservoir wettability states from strongly water-wet to weakly water-wet conditions, injection rates, and heterogeneity. A high-resolution imaging technique was used to evaluate how each parameter affects CO2 trapping behaviour. CO2 was injected under controlled conditions followed by brine imbibition to mimic the trapping at aquifer or reservoir. Image analysis was used to quantify trapped saturation, ganglion distribution, fluid interface, and displacement patterns. The results demonstrate that wettability strongly controls residual trapping. Water-wet micromodels yielded trapped CO2 saturations averaging 20.3%, whereas intermediate-wet conditions reduced trapping to 15.0%. Increasing capillary number caused a transition from capillary-controlled to viscous-dominated flow, reducing the residual gas significantly. Moreover, heterogeneous micromodels exhibited higher trapped saturations compared to homogeneous cases, consistent with pore-size variability enhancing snap-off and ganglion fragmentation. Microporosity contributed an additional 3-6% to final trapped saturation. These findings provide direct pore-scale evidence of how wettability, heterogeneity, and pore geometry govern CO2 entrapment. The results improve the physical basis for upscaling pore-scale trapping behavior to reservoir simulations and help identify geological settings that offer higher long-term CO2 storage security.