Recently, carbon capture, utilization, and storage (CCUS) with enhanced oil recovery (EOR) have gained a significant traction in an attempt to reduce greenhouse gas emissions. Information on pore-scale CO2 fluid behavior is vital for efficient geo-sequestration and EOR. This study scrutinizes the behavior of supercritical CO2 (sc-CO2) under different reservoir temperature and pressure conditions through computational fluid dynamics (CFD) analysis, applying it to light and heavy crude oil reservoirs. The effects of reservoir pressure (20 MPa and 40 MPa), reservoir temperature (323 K and 353 K), injection velocities (0.005 m/s, 0.001 m/s, and 0.0005 m/s), and in situ oil properties (835.3 kg/m3 and 984 kg/m3) have been considered as control variables. This study couples the Helmholtz free energy equation (equation of state) to consider the changes in physical properties of sc-CO2 owing to variations in reservoir pressure and temperature conditions. It has been found that the sc-CO2 sequestration is more efficient in the case of light oil than heavy oil reservoirs. Notably, an increase in temperature and pressure does not affect the trend of sc-CO2 breakthrough or oil recovery in the case of a reservoir bearing light oil. For heavy oil reservoirs with high pressures, sc-CO2 sequestration or oil recovery was higher due to the significant increase in density and viscosity of sc-CO2. Quantitative analysis showed that the stabilizing factor (ε) appreciably varies for light oil at low velocities while higher sensitivity was displayed for heavy oil at high velocities. In a subsequent study, a tortuous microscopic pore scale model was used to study and investigate the phenomena of water-alternating gas (WAG) and surfactant-alternating gas (SAG) with sc-CO2. The study scrutinizes the dynamics of the pore-level phenomenon in the multiphase WAG and SAG flows at the pore level in detail. It was found that higher oil recovery does not necessarily indicate higher sc-CO2 sequestration and that temperature harms the displacement mechanism due to unfavourable mobility ratios. Comparing WAG and SAG for the first injection cycle, SAG showed a more diffused interface between displaced and displacing fluid. The additional oil recovery produced in patches was a result of pressure oscillations near the blind pores. Moreover, high vorticity promotes greater intermixing between the displacing and displaced fluid by increasing the rate of interface length. In SAG cases, faster sc-CO2 breakthroughs were observed due to reduced shear stress along the fluid interfaces, which resulted in higher sequestration values in a given time frame. The CO2 sequestration volume in SAG cases was found to be approximately 40% more than in WAG experiments. The study confirms that lower values of oil–water interfacial tension aids in faster and more efficient sequestration of sc-CO2 along with additional oil gain from a given reservoir.