Enhancement of carbon dioxide (CO2) storage capacity in subsurface formations aids in offsetting the projected increase in carbon emissions. Consequently, various injection techniques should be explored to optimize the storage process. This study delves into CO2-foam utilization in a saline carbonate aquifer for underground carbon storage (UCS) purposes. In order to depict the subsurface flow dynamics, a carbonate saline aquifer model, which incorporates heterogeneous properties, a natural fracture network, and geochemical reactions, was developed. Various subsurface flow dynamics were considered by generating multiple natural fracture network realizations. Afterward, the developed model was utilized to numerically simulate the UCS process for two hundred years, capturing the CO2 inventory as well as fluid–fluid and fluid–rock interactions throughout the storage process. Introducing the foam enabled the injected CO2 to penetrate deeper around the injection zone; hence, higher trapped CO2 can be expected at the bottom of the aquifer. Despite the heterogeneity and natural fractures, CO2 foam helped in enhancing the dissolved CO2 distribution in the swept volume of the aquifer. The natural fracture network realizations demonstrated that the CO2 foam can potentially limit the influence of natural fractures during the UCS process. Furthermore, the subsurface geochemical reactions tend to be altered due to the drop in the fluid–fluid and fluid–rock interactions. Overall, the findings suggest that CO2 foam impacts surpass the heterogeneity and natural fracture network effects during the UCS. While the performed evaluation highlighted the CO2 foam role within a carbonate saline aquifer, the workflow and outcomes of the study can be extended to various subsurface environments wherein a compatible CO2 foam design can lead to CO2 storage capacity enhancement.
Mulhim et al. (Tue,) studied this question.