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...

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A percolation model of foam mobilization in porous media is developed. This model indicates that there is a minimum pressure gradient or, equivalently, a minimum gas velocity required to initiate mobilization of foam. As a result, for most foam enhanced oil recovery processes, where the surface tension is not low, deep foam penetration depends on propagation of foam formed at a high pressure gradient near the well. Low surface tension makes mobilization of CO, foams feasible, however, at pressure gradients found throughout much of the formation in a typical field application. The theory further predicts, and data confirm, that the minimum velocity for foam mobilization during steady flow of liquid and gas decreases as injected liquid volume fraction increases. The theory suggests a better strategy for foam generation: alternate injection of small slugs of liquid and gas.

(Received ?; revised ?; accepted ?. -To be entered by editorial office)During improved oil recovery, gas may be introduced into a porous reservoir filled with surfactant solution in order to form foam. A model for the evolution of the resulting foam front known as 'pressure-driven growth' is analysed. An asymptotic solution of this model for long times is derived that shows that foam can propagate indefinitely into the reservoir without gravity override. Moreover 'pressure-driven growth' is shown to correspond to a special case of the more general 'viscous froth' model. In particular, it is a singular limit of the viscous froth, corresponding to the elimination of a surface tension term, permitting sharp corners and kinks in the predicted shape of the front. Sharp corners tend to develop from concave regions of the front. The principal solution of interest has a convex front, however, so that although this solution itself has no sharp corners (except for some kinks that develop spuriously owing to errors in a numerical scheme), it is found nevertheless to exhibit milder singularities in front curvature, as the long-time asymptotic analytical solution makes clear. Numerical schemes for the evolving front shape which perform robustly (avoiding the development of spurious kinks) are also developed. Generalisations of this solution to geologically heterogeneous reservoirs should exhibit concavities and/or sharp corner singularities as an inherent part of their evolution: propagation of fronts containing such 'inherent' singularities can be readily incorporated into these numerical schemes.

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