A CO2-Modified Surfactant for Chemical Flooding

Abstract

Summary Carbon dioxide (CO2) modification of a nonionic surfactant alkyl polyglycoside (C-APG) was conducted based on a commercial APG product under mild synthesis conditions, including a low temperature (50°C) and a low pressure (2.5 bar). Using this method, CO2 was incorporated into APG molecules through the formation of carbonyl structures. The effectiveness and performance of C-APG as a novel surfactant for enhanced oil recovery (EOR) application in carbonate reservoirs were investigated and compared with its precursor—the unmodified APG. The key factors in the chemical structure of C-APG were characterized by Fourier transform infrared spectroscopy (FTIR) to confirm successful CO2 modification. The properties, including compatibility, surface tension, wettability alteration, interfacial tension (IFT), phase behavior, and static and dynamic adsorption of both APG and C-APG, were evaluated by various techniques and methods. Crude oil displacement efficiency of the surfactants was investigated via spontaneous imbibition, visualized micromodel, and coreflooding tests, respectively. Both surfactants were compatible with a high-salinity water (HSW), they exhibited a similar critical micelle concentration (CMC) of 8.5 mg/L and 13.5 mg/L for APG and C-APG, respectively, and had the same contact angle of around 135°. Interestingly, C-APG was found more effective in reducing IFT between oil and water phases. The IFT of oil in the C-APG solution was 0.058 ±0.001 mN/m, one order of magnitude lower than the value of 0.47 ±0.02 mN/m obtained from the solution of original APG, suggesting a better performance of C-APG in chemical flooding for oil displacement. A Winsor Type I microemulsion was formed by APG within the salinity range, while a transition of Type I to Type II microemulsion was observed for C-APG. The static adsorption of APG and C-APG at 2 g/L in carbonate were 0.93 mg/g rock and 1.08 mg/g rock, and the adsorption decreased to 0.11 mg/g rock and 0.13 mg/g rock under dynamic conditions for APG and C-APG, respectively. The spontaneous imbibition test demonstrated a higher oil imbibition recovery of 18.0% from C-APG solution compared to the result of 10.2% obtained from APG solution. A micromodel test showed that more crude oil was displaced by injection of APG or C-APG solution after waterflooding, while C-APG injection exhibited a stronger emulsification. The oil displacement by coreflood test showed that C-APG injection led to a lower differential pressure and a higher cumulative oil production (48%) compared to APG chemical flooding with a cumulative oil production of 41%. The produced fluids containing displaced crude oil from C-APG flooding, and subsequent waterflooding demonstrated very strong emulsification compared to the fluids produced after APG injection. This study demonstrates the significant potential of C-APG in two aspects—CO2 reduction and chemical EOR for the upstream petroleum industry.