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.
Nuetor et al. (Mon,) studied this question.