Low-salinity waterflooding has been identified as a cost-effective and environmentally friendly means to enhance oil recovery in carbonate reservoirs by decreasing hydrophobicity. Published work shows that a low concentration of 1-pentanol can further decrease the hydrophobicity, although the mechanism(s) remain unclear. In this work, we aimed to decipher the controlling factor(s), which prevail the process of wettability alteration, by adding alcohols in injected water. To achieve this aim, we examined the effect of alcohol carbon chain length and number of −OH functional groups on the contact angle of oil–brine–carbonate using ethanol, isopropanol, 1-pentanol, and glycerol in high- and low-salinity brines. Moreover, to interpret the contact angle results on the basis of a thermodynamic isotherm, we measured the ζ potential of brine–calcite and brine–oil with and without alcohols at ambient conditions. Contact angle results confirm that intermediate carbon chain alcohol (1-pentanol) shifts the wettability of the oil–brine–carbonate system to less oil-wet or more water-wet, implying greater hydrophilicity compared to other short carbon chain alcohols. Also, the number of −OH functional groups in an alcohol has a negligible effect on the contact angle and, thus, wettability alteration. However, the ζ potential at oil–brine and brine–calcite fails to explain the effect of alcohols on the wettability of the oil–brine–carbonate system, implying that the Derjaguin, Landau, Verwey, and Overbeek (DLVO) theory may not account for the effect of alcohol on the wettability alteration. We argue that increasing the length of the carbon chain likely increases −OH at oil–brine interfaces, which likely breaks the in situ bridges between oil and calcite surfaces, thus increasing hydrophilicity. Our finding shows that waterflooding efficiency may be boosted by adding 1-pentanol with a low concentration in high-salinity carbonate reservoirs, where conventional chemical-assisted enhanced oil recovery (e.g., polymer flooding and surfactant flooding) may not be viable.

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Low-salinity water flooding appears to be a promising means to improve oil recovery in carbonate reservoirs because of a wettability alteration process. Contact angle measurement is a direct approach to reveal the wettability alteration in an oil–brine–carbonate system. However, questions have been raised about using contact angle measurement to justify the wettability alteration. This is because the contact angle may be significantly affected by surface roughness variation in the presence of low-salinity water because of calcite dissolution during the contact angle measurement. To clarify the cause and effect of wettability alteration during low-salinity water flooding, we measured the contact angle on two calcite substrates with similar surface roughness (7 and 4 nm) in the presence of high-salinity water (1 mol NaCl + 0.01 mol CaCl2) and low-salinity water (100 times diluted high-salinity water). Moreover, we measured the surface roughness of the substrates before and after the contact angle measurements using atomic force microscopy (AFM). Furthermore, we performed a geochemical study to quantify the amount of calcite dissolution in the presence of low- and high-salinity brines and compared it with surface roughness measurements. Our contact angle and AFM results reveal that surface roughness increase due to calcite dissolution in low-salinity water plays a negligible role in the contact angle, rather confirming that oil–brine–rock interactions govern the system wettability. Furthermore, our geochemical study shows that low-salinity water only dissolves 1.16 × 10–4 mol/mol of calcites in low-salinity water during the contact angle measurement. We, therefore, eradicate the possibility that surface roughness variation due to calcite dissolution in low-salinity water would affect contact angle results. Consequently, we argue that contact angle measurement remains a valid approach to directly examine the wettability alteration process in low-salinity water flooding.

Low salinity water flooding appears to be an important means to improved oil recovery in sandstone reservoirs. Wettability alteration has been identified as the main effect behind low salinity water flooding due to the interaction of oil− brine−rock interfaces, where clay minerals play a significant role. While how edge-charged clays (kaolinite-bearing sandstone) contribute to wettability alteration during low salinity water flooding has been well-studied, the role of basal charged clays (smectite, illite, and chlorite) in wettability alteration remains unclear. We previously confirmed that basal charged clays trigger pH increases (2 to 3) due to ion exchange with added impetus of mineral dissolution by means of geochemical modeling (Chen et al. Fuel 2018, 112−117). In this work, we hypothesized that the pH increase triggers negative zeta potential of both oil−brine and brine−clays, thus increasing double layer expansion, as well as hydrophilicity. To test our hypothesis, we measured adhesion force between functional groups (−CH 3 and −COOH) and muscovite using atomic force microscope (AFM) at pH of 7 and 11 with NaCl at a concentration of 10 000 mg/L NaCl. To gain a better isotherm thermodynamic understanding, we measured zeta potential of brine−muscovite and oil−brine and computed total disjoining pressure under constant potential condition using flat to flat and sphere to flat thermodynamic models. Zeta potential measurements show that increasing pH shifted the zeta potential of oil−brine and brine−muscovite to more negative values thus increasing the electrical double layer force. Our AFM measurements show that increasing pH from 7 to 11 indeed decreased 80% of the adhesion force for both functional groups. Total disjoining pressure calculation predicts the same trend as the AFM adhesion measurements. However, the sphere to flat thermodynamic model predicts a correct degree of decrease in adhesion force compared to AFM, implying that the sphere to flat model should be applied to interpret AFM results. Together, our results confirm that basal-charged clays can significantly contribute to low salinity effect due to electrical double layer expansion, thus expanding the application envelope of low salinity flooding in sandstone reservoirs bearing basal-charged clays.

While the effect of polar-oil component on oil-brine-carbonate system wettability has been extensively investigated, there has been little quantitative analysis of the effect of non-polar components on system wettability, in particular as a function of pH. In this context, we measured the contact angle of non-polar oil on calcite surface in the presence of 10,000 ppm NaCl at pH values of 6.5, 9.5 and 11. We also measured the adhesion of non-polar oil group (–CH3) and calcite using atomic force microscopy (AFM) under the same conditions of contact angle measurements. Furthermore, to gain a deeper understanding, we performed zeta potential measurements of the non-polar oil-brine and brine-calcite interfaces, and calculated the total disjoining pressure. Our results show that the contact angle decreases from 125° to 78° with an increase in pH from 6.5 to 11. AFM measurements show that the adhesion force decreases with increasing pH. Zeta potential results indicate that an increase in pH would change the zeta potential of the non-polar oil-brine and calcite-brine interfaces towards more negative values, resulting in an increase of electrical double layer forces. The total disjoining pressure and results of AFM adhesion tests predict the same trend, showing that adhesion forces decrease with increasing pH. Our results show that the pH increase during low-salinity waterflooding in carbonate reservoirs would lift off non-polar components, thereby lowering residual oil saturation. This physiochemical process can even occur in reservoirs with low concentration of polar components in crude oils.