Mechanistic evaluation of surfactant assisted smart water flooding with sulfate and phosphate anions

Enhanced Oil Recovery (EOR) poses a significant challenge for carbonate rock reservoirs in the oil and gas industry. To address this, researchers have introduced methods such as smart water and surfactant-assisted injections. The complex and heterogeneous nature of these rock formations requires a comprehensive understanding of the processes during injection. In recent years, researchers have used phosphate and sulfate anions for smart water injections. While sulfate anion injections have received considerable attention, a significant gap remains in understanding the impact of phosphate anions. This gap calls for further exploration and study to uncover the potential effects of phosphate anion injections. A comprehensive understanding of their EOR mechanisms has yet to be efficiently achieved. This study aimed to examine the impact of sulfate ([Formula: see text]), mono- ([Formula: see text]) and dihydrogen ([Formula: see text]) phosphate anions on altering wettability in oil-wet carbonate rock and reducing water/oil interfacial tension. The simultaneous use of these anions with a cationic surfactant, Cetyl Trimethyl Ammonium Bromide (CTAB) was also investigated. These mechanisms were explored through experimental tests, including contact angle measurements, fourier-transform infrared spectroscopy-attenuated total reflectance (FTIR-ATR) imaging, zeta potential measurements, and spontaneous imbibition. Contact angle measurements showed that [Formula: see text] and [Formula: see text] anions perform better than [Formula: see text] in restoring water-wetness to carbonate rocks. FTIR-ATR analysis confirmed that carbonate rock exhibits higher water-wettability in solutions enriched with [Formula: see text]. Zeta potential assessments showed a shift in the charge of oil-wet carbonate rock: from -54.9 mV to -32.4 mV with [Formula: see text], -16.4 mV with [Formula: see text], and -24.8 mV with [Formula: see text]. Moreover, the spontaneous imbibition test enabled us to calculate oil recovery. The computed oil recovery values for low-salinity water enriched with [Formula: see text], [Formula: see text], and [Formula: see text] were 48%, 44%, and 36%, respectively. Finally, these recovery values significantly increased to 78%, 74%, and 66% for [Formula: see text], [Formula: see text], and [Formula: see text] solutions after exposure of the core plug sample to CTAB. Therefore, the presence of [Formula: see text] ion, in conjunction with CTAB, yielded the most favorable results across all conducted tests.