Impact of reservoir organic acid and brine salinity on CO2-rock interfacial tension and wettability in carbonate rocks: Insights for geological CO2 storage - Ramyar Suramairy; Azad Anugerah Ali Rasol; M.N.A.M. Norddin; Maha R. Hamoudi; Amanj W. Khalid; Dana A. Hasan (Results in Engineering)
CO2 storage in geological structures is a significant strategy to reduce CO2 concentration in the atmosphere. Depleted gas and oil reservoirs are ideal vicinities for trapping CO2. Nevertheless, the success of a CO2 sequestration project is committed to efficient long-term confinement of CO2, which is governed by various factors, mainly the wettability and interfacial tension in the reservoir. In depleted reservoirs, rock wettability may shift toward more hydrophobic due to the hydrocarbon residues, brine salinity, and subsurface pressure increasing the potential of CO2 leakage. This study investigated the effect of naphthenic acid (present in crude oil), actual reservoir brine salinity, and pressure on wettability and fluid-rock interfacial tension in carbonate rocks using the modified Neumann’s equation of state. The tests were conducted at 75 °C and pressures ranging from 725 to 2900 psia. The results reveal that naphthenic acid markedly increased the advancing and receding contact angles by 28 % and 25 %, respectively, at high salinity conditions. Notably, a tenfold dilution in salinity reduced contact angles by 13 % (advancing) and 14 % (receding), yet this proved insufficient to reestablish wettability below the structural CO₂ entrapment threshold. Concurrently, CO2-rock interfacial tension exhibited a pronounced diminution from 13.4 mN/m to 7.97 mN/m with naphthenic acid at 1450 psia, and further to 3.1 mN/m at 2900 psia. Furthermore, increasing pressure was found to lower CO₂-rock interfacial tension, ascending advancing and receding contact angles from 99.86°/88.24° at 725 psia to 121.72°/110.5° at 2900 psia. These findings yield valuable insights for CO2 storage studies in carbonate reservoirs.