Effect of viscosity and interfacial tension of surfactant–polymer flooding on oil recovery in high-temperature and high-salinity reservoirs

Abstract

This study aims to analyze the influence of viscosity and interfacial tension (IFT) on oil displacement efficiency in heterogeneous reservoirs. Measurement of changes in polymer viscosity and IFT indicates that viscosity is influenced by brine salinity and shearing of pore media and that IFT is influenced by salinity and the interaction between the polymer and surfactant. High concentrations (2,500 and 3,000 mg/L) of polymer GLP-85 are utilized to reduce the effect of salinity and maintain high viscosity (24 mPa s) in formation water. After shearing of pore media, polymer viscosity is still high (17 mPa·s). The same polymer viscosity (17 mPa·s) is utilized to displace oil, whose viscosity is 68 mPa·s, at high temperature and high pressure. The IFTs between surfactant DWS of 0.2 % in the reservoir water of different salinities and crude oil droplet are all below 10−2 mN/m, with only a slight difference. Surfactant DWS exhibits good salt tolerance. In the surfactant–polymer (SP) system, the polymer solution prolongs the time to reach ultra-low IFT. However, the surfactant only has a slight effect on the viscosity of the SP system. SP slugs are injected after water flooding in the heterogeneous core flooding experiments. Recovery is improved by 4.93–21.02 % of the original oil in place. Furthermore, the core flooding experiments show that the pole of lowering the mobility ratio is more significant than decreasing the IFT of the displacing agent; both of them must be optimized by considering the injectivity of the polymer molecular, emulsification of oil, and the economic cost. This study provides technical support in selecting and optimizing SP systems for chemical flooding.