Surfactant and polymer enhanced oil recovery application in a high temperature and high salinity carbonate reservoir

As discoveries of new, conventional oil reservoirs diminishes, advanced techniques (such as chemical EOR) must be utilized to meet future oil demand. Surfactants can be used in chemical floods to reduce the interfacial tension (IFT) between oil and water phases, allowing for some of the residual oil to be mobilized and recovered. Polymers are typically used to increase the viscosity of the solution, enhancing the mobility control, thereby providing a better sweep of the reservoir. However, surfactant-polymer (SP) flooding can be challenging when applied to high temperature, high salinity carbonate reservoirs. The extreme conditions of the reservoir can cause many surfactants and polymers to degrade. Carbonate reservoirs also tend to have higher concentrations of divalent cations and positive surface charges, which contribute to both chemical degradation and surfactant adsorption. This study investigated several SP formulations at 100oC using the reservoir injection brine with divalent ions. The formulations were mixtures of carboxylate, internal olefin sulfonates, and lauryl betaine surfactants. Indiana limestone cores and sand grains were used to mimic the minerology of the reservoir. After generating ultra-low IFT formulations and testing their phase behavior with surrogate reservoir oil, three corefloods were completed to test their oil recovery potential. The first two corefloods were performed using Indiana limestone cores and resulted in 72% and 71% recovery, respectively, of the original oil in place. Experiment 3 was performed with a sandpack made from Indiana limestone sand grains to provide a more homogeneous pore size structure than the core. This flood had a recovery of nearly 99% of the original oil in place. It was found that adding lauryl betaine, a zwitterionic surfactant, helped decrease IFT substantially and resulted in very high oil recovery in the sandpack. Oil was also added in the SP slug in small quantities to help avoid precipitation and phase separation early in the injection process. While the pH was found to be nearly neutral during the floods, surfactant retention was found to be 0.325 mg/g-rock and 0.303 mg/g-rock in corefloods 2 and 3, respectively. These are moderate adsorption amounts when considering the probable positive surface charge of the carbonate rock and divalent cation concentration