CO₂ flooding has become a strategic tool for enhanced oil recovery and reservoir management in mature fields. This technique, however, is rarely utilized in asphaltenic crude oil systems, due to the likely occurrence of high asphaltene precipitation. The effect of asphaltene concentrations and CO₂ injection pressures has mostly been the focus of studies in determining asphaltene precipitation rates. However, asphaltene precipitation is not the only direct factor to be considered in predicting the extent of damage in an asphaltenic crude oil system. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection pressure at which asphaltene-induced formation damage can be avoided during both miscible and immiscible CO₂ flooding in an asphaltenic crude system. Simulation results indicate that asphaltene-induced permeability reduction exceeded 35% in most affected zones, with a corresponding drop in injectivity of 28%. Cumulative oil recovery improved by 19% compared to base cases without CO₂ injection, achieving peak recovery after approximately 4200 days of simulation time. As CO₂ was injected below the Minimum Miscibility Pressure (MMP) of 2079.2 psi, a significantly lower asphaltene precipitation was observed near the injector. This could be attributed to the stripping of lighter hydrocarbon components (C2–C7+) occurring in the transition zone at the gas–oil interface. Injecting CO₂ at pressures above the MMP resulted in precipitation occurring throughout the entire reservoir at 3200 psia and 1000 bbl/day injection rates. An increase in the injection rate at pressures above the MMP increased the rate of precipitation. However, a further increase in the injection rate from 1000 bbl/day to 4200 bbl/day resulted in a decrease in asphaltene deposition. The pressure drop in the water phase caused by pore throat increase demonstrated that water injection was effective in removing asphaltene deposits and restoring permeability. This work provides critical insights into optimizing CO₂ injection strategies to enhance oil recovery while minimizing asphaltene-induced formation damage in heavy oil reservoirs.

Surfactant flooding is a promising enhanced oil recovery (EOR) method for mobilizing residual oil after primary recovery and conventional waterflooding. Its performance is highly sensitive to reservoir chemistry, particularly in associated gas reservoirs where CO₂, H₂S, and CH₄ may alter aqueous-phase behavior, surfactant stability, adsorption, and chemical transport. This study evaluates salinity-controlled surfactant flooding performance in a synthetic three-dimensional associated gas–oil reservoir using a simulation-guided diagnostic workflow. The model examines surfactant transport, adsorption, oil rate response, and block-level oil saturation across ultralow-, low-, and moderate-to-high-salinity ranges. Performance was evaluated using field oil production rate (FOPR), cumulative field oil production (FOPT), block oil saturation (BOSAT), block total surfactant concentration (BTCNFSUR), and block total adsorbed surfactant (BTADSUR). Because the simulation does not independently vary gas composition, the results should be interpreted as salinity effects under an associated gas reservoir setting rather than as isolated gas composition effects. The strongest sustained production response occurred in the ultralow- to low-salinity cases, especially 400 ppm and 1000 ppm, where surfactant propagation was more stable and late-time FOPR recovery was stronger. The 15,000 ppm case was the best performer only within the moderate-salinity group and should not be interpreted as the global optimum across all salinity cases. Above 25,000 ppm, FOPR declined to approximately 50–60 Sm³/day, while BOSAT remained high in poorly swept layers, indicating channelized flow, localized chemical contact, and greater retention risk. The results show that salinity compatibility is a dominant control on surfactant flood efficiency and that salinity screening is necessary before applying surfactant flooding in gas-rich reservoirs.