Study of Surfactant–Polymer Flooding in High-Temperature and High-Salinity Carbonate Rocks

Secondary waterflood processes have low oil recovery in carbonate reservoirs as a result of their oil-wetness and heterogeneity. Surfactants in combination with polymer solutions can improve the oil recovery significantly from these reservoirs through ultralow interfacial tension (IFT), mobility control, and wettability alteration. However, application of surfactant–polymer (SP) flooding in high-salinity and high-temperature carbonate reservoirs is constrained by the thermal stability of polymers at elevated temperatures, compatibility of surfactants with a high concentration of divalent cations present in formation brines, and geochemical interactions with carbonate minerals. This research is focused on understanding surfactant and polymer interactions with formation brines containing high concentrations of divalent cations and thermal stability and transport of polymers in carbonate rocks at a high temperature (80 °C). Surfactant phase behavior experiments (with and without polymer) were performed to identify promising surfactant candidates, which show ultralow IFT with crude oil and aqueous stability (with and without polymer) at a high temperature in high-salinity and high-hardness brines. Several iterations of experiments were performed to understand the effect of the surfactant hydrophobe length on the phase behavior, oil recovery, and surfactant retention in coreflood experiments. Results showed that a carboxylate surfactant with a minimum of 30 ethylene oxide groups and a large hydrophobe is necessary to make the chemical formulation tolerant to high concentrations of divalent ions. Surfactant blends can be chosen strategically based on the hydrophilic–lipophilic balance of each of the surfactants. Specialty synthetic polymers with good thermal stability and salinity tolerance (total dissolved solids of >90 000 ppm) were investigated for their transport in single-phase corefloods. Results showed successful transport of polymer, without in situ degradation, and improvement in mobility control. SP corefloods were conducted using selected formulations in Indiana limestone cores. Coreflood experiments showed a significant increase in oil recovery over waterflood (77–92% residual oil in place) after the injection of the chemical formulation and surfactant retention in the range of 0.2–0.32 mg/g of rock. Successful polymer transport was observed in each of the SP corefloods at this high temperature.