ArticleScientific reports2025
Mechanistic evaluation of surfactant assisted smart water flooding with sulfate and phosphate anions.
Article in Scientific reports, 2025. The graph could read no effect estimate from its abstract, so it casts no vote on the map. Cited by 1 paper.
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Abstract
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.
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