The low-salinity effect (LSE) in carbonate rock has been less explored in comparison to sandstone rock. Laboratory experiments have shown that brine composition and (somewhat reduced) salinity can have a positive impact on oil recovery in carbonates. However, the mechanism leading to improved oil recovery in carbonate rock is not well understood. Several studies showed that a positive low-salinity flooding (LSF) effect might be associated with dissolution of rock; however, because of equilibration, dissolution may not contribute at reservoir scale, which would make LSF for carbonate rock less attractive for field applications. This raises now the question whether calcite dissolution is the primary mechanism of the LSF effect. In this paper, we aim to first demonstrate the positive response of carbonate rock to low salinity and then to gain insight into the underlying mechanism(s) specific to carbonate rock. We followed a similar methodology as in sandstone rock [Kinetics of low-salinity-flooding effect Mahani H. Berg S. Ilic D. Bartels W.-B. Joekar-Niasar V. Mahani H. Berg S. Ilic D. Bartels W.-B. Joekar-Niasar V. SPE J.201520820, DOI: 10.1021/ef5023847] using a model system comprised of carbonate surfaces obtained from crushed carbonate rocks. Wettability alteration upon exposure to low-salinity brine was examined by continuous monitoring of the contact angle. Furthermore, the effective surface charge at oil–water and water–rock interfaces was quantified via ζ-potential measurements. Mineral dissolution was addressed both experimentally and with geochemical modeling using PHREEQC. Two carbonate rocks with different mineralogy were investigated: limestone and Silurian dolomite. Four types of brines were used: high-salinity formation water (FW), seawater (SW), 25× diluted seawater (25dSW), and 25× diluted seawater equilibrated with calcite (25dSWEQ). It was observed that, by switching from FW to SW, 25dSW, and 25dSWEQ, the limestone surface became less oil-wet. The results with SW and 25dSWEQ suggest that the LSE occurs even in the absence of mineral dissolution, because no dissolution is expected in SW and none in 25dSWEQ. The wettability alteration to a less oil-wetting state by low salinity is consistent with the ζ-potential data of limestone, indicating that, at lower salinities, the charges at the limestone–brine interface become more negative, indicative of a weaker electrostatic adhesion between the oil–brine and rock–brine interfaces, thus recession of the three-phase contact line. In comparison to limestone, a smaller contact angle reduction was observed with dolomite. This is again consistent with the ζ-potential of dolomite, generally showing more positive charges at higher salinities and less decrease at lower salinities. This implies that oil detachment from the dolomite surface requires a larger reduction of adhesion forces at the contact line than limestone. Our study concludes that surface charge change is likely to be the primary mechanism, which means that there is a positive LSE in carb...

Summary Laboratory studies have shown that wettability of carbonate rock can be altered to a less-oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (Mahani et al. 2015b) suggests that surface-charge alteration is likely to be the driving mechanism of the low-salinity effect in carbonates. Various studies have already established the sensitivity of carbonate-surface charge to brine salinity, pH value, and potential-determining ions in brines. However, in the majority of the studies, single-salt brines or model-carbonate rocks have been used and it is fairly unclear how natural rock reacts to reservoir-relevant brine as well as successive brine dilution; whether different types of carbonate-reservoir rocks exhibit different electrokinetic properties; and how the surface-charge behavior obtained at different brine salinities and pH values can be explained. This paper presents a comparative study aimed at gaining more insight into the electrokinetics of different types of carbonate rock. This is achieved by ζ-potential measurements on Iceland spar calcite and three reservoir-related rocks—Middle Eastern limestone, Stevns Klint chalk, and Silurian dolomite outcrop—over a wide range of salinity, brine composition, and pH values. With a view to arriving at a more-tractable approach, a surface-complexation model (SCM) implemented in PHREEQC software (Parkhurst and Appelo 2013) is developed to relate our understanding of the surface reactions to measured ζ-potentials. It was found that regardless of the rock type, the trends of ζ-potentials with salinity and pH are quite similar. For all cases, the surface charge was found to be positive in high-salinity formation water (FW), which should favor oil-wetting. The ζ-potential successively decreased toward negative values when the brine salinity was lowered to seawater (SW) level and diluted SW. At all salinities, the ζ-potential showed a strong dependence on pH, with positive slope that remained so even with excessive dilution. The sensitivity of the ζ-potential to pH change was often higher at lower salinities. The existing SCMs cannot predict the observed increase of ζ-potential with pH; therefore, a new model is proposed to capture this feature. According to modeling results, formation of surface species, particularly >CaSO4− and to a lower extent >CO3Ca+ and >CO3Mg+, strongly influence the total surface charge. Increasing the pH turns the negatively charged moiety >CaSO4− into both negatively charged >CaCO3− and neutral > CaOH entities. (Note that throughout this paper, the symbol > indicates surface complexes.) This substitution reduces the negative charge of the surface. The surface concentration of >CO3Ca+ and >CO3Mg+ moieties changes little with change of pH. Nevertheless, besides similarities in ζ-potential trends, there exist notable differences in terms of magnitude and the isoelectric point (IEP), even between carbonates that are mainly composed of calcite. Among all the samples, chalk particles exhibited the most negative surface charges, followed by limestone. In contrast to this, dolomite particles showed the most positive ζ-potential, followed by calcite crystal. Overall, chalk particles exhibited the highest surface reactivity to pH and salinity change, whereas dolomite particles showed the lowest.

It has been proposed that increased oil recovery in carbonates by modification of ionic composition or altering salinity occurs mainly at a temperature exceeding 70–80 °C. The argument was that elevated temperatures enhance adsorption of the potential determining ions which then modifies wettability to a less-oil-wetting state. According to this rationale, it becomes questionable if diluted brines or brines without these ions can be still applicable. Therefore, the aim of this paper is to investigate if the wettability alteration truly depends on temperature and if so how the trend with temperature can be explained. We followed a combined experimental and theoretical modeling approach. The effect of brine composition and temperature on carbonate wettability was probed by monitoring contact angle change of sessile oil droplets upon switching from high salinity to lower salinity brines. IFT measurements as a function of salinity and temperature along with extensive ζ-potential measurements as a function of salinity, pH, temperature, and rock type were conducted. Interaction potentials between oil and carbonate surfaces were estimated based on DLVO theory, and its consistency with oil-droplet data was checked to draw conclusions on plausible mechanisms. Three carbonate rocks (two limestones and one dolomite) were used along with two reservoir crude oils, high salinity formation water (FW), seawater (SW), and 25 times diluted seawater (25dSW) as low salinity (LS) brine. It was observed that (i) wettability alteration to a less-oil-wetting state can occur at ambient temperature for specific rock types and brines, and (ii) there is no univocal increase in response to SW and LS brine at elevated temperature. The largest improvement in wettability was observed for dolomite, while, among the limestones, only one rock type showed noticeable wettability improvement at elevated temperature with SW. The difference in behavior between limestones and dolomite indicates that the response to brine composition change depends on rock type and mineralogy of the sample. These observations are consistent with the ζ-potential trends with salinity at a given temperature. Dolomite generally shows more positive ζ-potential than limestones. However, even the two limestones react differently to lowering salinity and exhibit different magnitude of ζ-potential. Moreover, it is observed that, at a specific salinity, an increase in temperature leads to reduction of ζ-potential magnitude on both rock/brine and oil/brine interfaces toward zero potential. This can affect positively or negatively the degree of wettability alteration (to a less-oil-wetting state) at elevated temperature depending on the sign of oil/brine and rock/brine ζ-potential in SW/LS. The observed trends are reflected in the DLVO calculations which show consistency with contact angle trends with temperature and salinity. According to the DLVO calculation, the lack of response to SW/LS in some of the systems above can be explained by stronger electrostatic attractive forces und...

Literature review shows that improved oil recovery (IOR) by lowsalinity waterflooding could be attributed to several mechanisms, such as sweep-efficiency improvement, interfacial-tension (IFT) reduction, multicomponent ionic exchange, and electrical-doublelayer (EDL) expansion. Although these mechanisms might contribute to IOR by low-salinity water, they may not be the primary mechanism. Therefore, the main objective of this study is to investigate if the mechanism of EDL expansion could be the principal reason for IOR during low-salinity waterflooding.Low-salinity water results in a thicker EDL when compared to high-salinity water, so we tried to eliminate the effect of low-salinity brines on double-layer expansion to show to what extent IOR is related to EDL expansion caused by low-salinity water. The double-layer expansion is dependent on the electric surface charge, which is a function of the pH of brine; therefore, the pH levels of low-salinity brines were decreased in this study to provide low-salinity brines that can produce a thinner EDL, similar to high-salinity brines. f-potential measurements were performed on both rock/brine and oil/brine interfaces to demonstrate the effect of brine pH and salinity on EDL. Contact angle and coreflood experiments were conducted to test different brine salinities at different pH values, which could assess the effect of water salinity and pH on rock wettability and oil recovery, and hence involvement of EDL expansion in the IOR process.f-potential results in this study showed that decreasing the pH of low-salinity brines makes the electrical charges at both oil/ brine and brine/rock interfaces slightly negative, which reduces the double-layer expansion caused by low-salinity brine. As a result, the rock becomes more oil-wet, which was confirmed by contact-angle measurements. Moreover, coreflood experiments indicated that injecting low-salinity brine at lower pH values recovered smaller amounts of oil when compared to the original pH because of the elimination of the low-salinity-water effect on the thickness of the double layer. In conclusion, this study demonstrates that expansion of the double layer is a dominant mechanism of oil-recovery improvement by low-salinity waterflooding.

The ionic strength of injection water can have a major impact on oil recovery resulting from the use of low-salinity brines. Understanding how the water and oil chemistry affects the final recovery from a physicochemical point of view is necessary in order to optimize low-salinity waterflooding. It is clear from the literature that wettability is a key factor in achieving the low-salinity effect. Optimum ionic strength and conditions for low-salinity flooding with respect to wettability are still uncertain.In this paper, we studied fluid/rock interactions at different salinity levels and elevated temperature conditions in terms of wettability and surface charge. Wettability is determined by a high-temperature/high-pressure (HT/HP) contact-angle method and zeta-potential technique. Outcrop rocks and stock-tank crudeoil samples were used in all experiments. Synthetic formation brine water, aquifer water, and seawater were evaluated under highpressure conditions. Zeta potential of sandstone rocks and selected clay minerals was measured as a function of ionic strength.Wettability of oil/brine/sandstone systems depends on salinity, temperature, and rock mineralogy. Using aquifer water in Berea sandstone improved the wettability toward a water-wet condition. The same aquifer water behaved in a different way when a different sandstone surface was tested. In Scioto sandstone, aquifer water changed the wettability to a neutral state. Low-salinity water expanded the double-layer thickness and eventually increased the zeta-potential magnitude. As a result of this expansion, it provides a greater opportunity to alter the wettability and enhance oil recovery. This study indicates that clay content in sandstone rocks can significantly alter the wettability either toward water-wet or intermediate. On the basis of the results obtained from this study, it is clear that low-salinity waterflooding can improve oil recovery in the field.