The wetting behavior of rock/CO₂/brine systems highly impacts the fluid distribution at the pore-scale and multiphase flow at the macroscale and is considered a key parameter controlling the CO₂ residual trapping in geological storage. The effect of wettability on residual trapping is, however, still uncertain as the current literature suggests high discrepancies among the published datasets. Moreover, the dataset for residual trapping observations for non water-wet carbonate rocks is relatively scarce; none of the published studies investigated this aspect in CO₂-wet limestones. Thus, a series of core-flooding experiments was conducted at reservoir conditions for three limestone samples having different wettability states, water-wet, intermediate wet, and CO₂-wet. Wettability alteration of sister rocks was achieved using stearic acid to mimic the wettability alteration in saline aquifers due to the interaction with natural organic compounds. Notably, increasing the hydrophobicity of limestone tends to decrease CO₂ residual trapping efficiency $\sim$ 19% and 37% when the initial water-wetting state shifts to intermediate-wet and CO₂-wet, respectively. This is attributed to the fluid distribution at the pore scale, in particular the wetting layers, and its effect on the CO₂/brine displacement. In case of CO₂-wet rocks, macroscopic CO₂-wetting layers act as flow paths, which reduces the residual CO₂ saturation from 29% (water-wet) to 8%. These findings advocate water-wet rocks as better candidates for CO₂ residual trapping and provide insights into residual trapping-rock wettability correlation pertinent to CO₂ geo-storage.

The utilization of supercritical CO₂ in oil and gas reservoir engineering, particularly for enhanced oil recovery, has garnered considerable attention due to its potential to boost hydrocarbon production while reducing CO₂ emissions. This study investigates the improvements achievable in CO₂-enhanced oil recovery and subsequent carbon storage capacity within heterogeneous carbonate reservoirs through supercritical CO₂ miscible injection after seawater flooding. Utilizing a dual-core flooding setup with carbonate core samples exhibiting significant permeability contrast, experiments were conducted under reservoir conditions using live oil, seawater, and supercritical CO₂ miscible injection. To enhance CO₂-enhanced oil recovery and storage within low-permeability zones, a thermal foam gel system was introduced into a highly permeable core after initial supercritical CO₂ miscible injection, effectively sealing off high-permeability zones and improving displacement and storage capacity. Results demonstrate that reservoir heterogeneity notably influences supercritical CO₂-enhanced oil recovery efficiency and sequestration in low permeable regions, with bypass flow in high- permeable regions hindering displacement efficiency and CO₂ storage capacity. However, plugging high-permeability zones using a thermal foam gel system after the initial supercritical CO₂ miscible injection, about 15% extra oil recovery of the pore volume from low-permeability zones was recovered during the second supercritical CO₂ miscible injection, and the equivalent pore space provides a site for storing CO₂ also. Additionally, dynamic characteristic parameters such as injectivity, permeability loss, and endpoint relative permeability related to supercritical CO₂ storage are discussed in this study. The study’s outcomes contribute to advancing the understanding of CO₂-enhanced oil recovery and sequestration, facilitating the development of more effective and sustainable reservoir management practices.