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Summary Low-salinity waterflooding in limestone formations has been less explored and hence less understood in enhanced-oil-recovery (EOR) literature. The mechanisms leading to improved recovery have been mostly attributed to wettability alteration, with less attention given to fluid/fluid-interaction mechanisms. In this work, we present a thorough investigation of the formation of water-in-oil microdispersions generated when low-salinity brine encounters crude oil and the suppressed snap-off effect caused by the presence of sulfate content in seawater-equivalent-salinity brines as recovery mechanisms in limestone rocks. We believe this is a mechanism that leads to the improved oil recovery experienced with low-salinity waterflooding and seawaterflooding in carbonate formations. This novel interpretation was studied by integrating petrographic and spectroscopic observations, dynamic interfacial-tension (IFT) measurements, thermogravimetrical analyses, and coreflooding techniques. Our data show that low-salinity brine caused a greater change in the crude-oil composition compared with seawater brine and formation-water brine. Formation-water brine created nearly no changes to the crude-oil composition, indicating its limited effect on the crude oil. These compositional changes in crude oil, caused by the low-salinity brine, were attributed to the formation of water-in-oil microdispersions within the crude-oil phase. Fourier-transform infrared (FTIR) spectroscopy data also showed that at brine-concentration levels greater than 8,200 ppm, this phenomenon was not experienced. Oil-production data for nonaged limestone cores showed an improved recovery of approximately 5 and 3% for seawater and low-salinity brines, respectively. Although the wettability-alteration effect was minimized by the use of nonaged cores, improved oil recovery was still evident. This was interpreted to represent the formation of water-in-oil microdispersions when low-salinity water (LSW) of 8,200-ppm salinity and less was used. The formation of the microdispersions is believed to increase the sweep efficiency of the waterflood by swelling and therefore blocking the pore throats, causing low-salinity-brine sweeping of the unswept pore spaces. Improved recovery by seawater brine was attributed to the changes in dynamic IFT measurement experienced using seawater brine as the continuous phase, compared with the use of LSW and formation-water-salinity (FWS) brine. This change caused a higher surface dilatational elasticity, which leads to a suppression of the snap-off effect in coreflooding experiments and hence causes improved oil recovery. Our studies conclude that the formation of microdispersions leads to improved oil recovery in low-salinity waterflooding of limestone rocks. Furthermore, the use of seawater as a displacing fluid succeeds in improving recovery because of its high surface elasticity suppressing the snap-off effect in the pore throat. We also present an easy and reliable mixing procedure representative of porous media, which could be used for screening brine and crude-oil samples for field application. Fluid/fluid interaction as well as high surface elasticity should be investigated as the causes of wettability alteration and improved recovery experienced by the use of LSW and seawater-salinity (SWS) brines interacting with limestone formations, respectively.

The impact of ionic association with the carbonate surface and its influence toward carbonate wettability remains unclear and is an important topic of interest in the current literature. In this work, a triple layer model (TLM) approach was used to capture the electrokinetic interactions at both calcite–brine and oil–brine interfaces. The developed TLM was assembled against measured ζ-potential values from the literature, successfully capturing the trends and closely matching the ζ-potential magnitudes. The developed TLM was compared to a diffused layer model (DLM) presented in previous works, with the DLM showing a better match to the ζ-potential values for seawater brine solutions. The ζ-potential values predicted from both surface complexation models (SCMs) were used to calculate the total interaction energy (or potential) based on the Derjaguin, Landau, Verwey, and Overbeek (DLVO) theory. It was observed that low Mg 2+ and high SO 4 2– concentrations in modified composition brine (MCB) made the calcite–brine interface more negative. However, at the oil–brine interface, low Mg 2+ made the oil–brine interface more negative but high SO 4 2– concentrations slightly shifted the oil–brine ζ-potential toward negative. At the crude oil–brine–rock (COBR) interfaces, low Mg 2+ and high SO 4 2– concentrations in the MCB were observed to generate a greater repulsive interaction energy, which could trigger carbonate wettability alteration toward water wetness. The absolute sum of the ζ-potential at both interfaces was observed to be correlated to the total interaction potential at a 0.25 nm separating distance. Thus, an increase in the absolute sum of the ζ-potentials would generate a greater repulsive interaction potential and trigger wettability alteration. Therefore, these SCMs can be applied to design modified composition brine capable of triggering a repulsive interaction energy to alter carbonate wettability toward water wetness.

Low-salinity waterflooding (LSWF) has proven to improve oil recovery in carbonate formations through rock wettability alteration, although the underlying mechanism remains elusive. Multivalent ionic exchange and calcite dissolution have usually been investigated using geochemical analysis in secondary coreflooding. In this work, coreflooding, in tertiary mode, coupled with a surface reactivity analysis approach was employed to investigate the interplay of wettability alteration mechanisms such as mineral dissolution, electrostatic bond attraction, and the effect of pH at in situ conditions. Improved oil recovery (IOR) in tertiary mode observed by coreflooding in Indiana limestone rocks showed an ionic strength dependence, that is, reducing brine ionic strength resulted in an increase in oil recovery. Coreflooding results showed that the seawater and low-salinity brines deprived of Mg2+ ions resulted in the lowest IOR in tertiary mode, indicating the significance of Mg2+ on IOR in limestone rocks. Similar results were observed through the contact angle measurement showing the limestone rock wettability state dependence on ionic strength and the effect of Mg2+ ions. Surface reactivity analysis showed an increase in solution pH, Ca2+ and Mg2+ ions concentration in the effluent solution from the coreflooding in tertiary mode using low salinity brines (about 40 and 20% increase in the effluent composition for Ca2+ and Mg2+, respectively). These changes in solution composition were used to calculate the in situ oil–brine and rock–brine zeta potential using a validated surface complexation model, showing the changes of zeta potential as brine is injected into limestone rocks. The results show that using seawater-like brine in tertiary mode resulted in no mineral dissolution or ionic exchange. However, improved oil recovery (IOR) using such seawater-like brine was due to wettability alteration caused by reduced electrostatic bond attraction associated with Mg2+ ions [from 2.6 × 10–13 (mol/m2)2 for formation water salinity to 1.5 × 10–13 (mol/m2)2 for seawater salinity]. Using low-salinity brines in tertiary mode improved oil recovery by mineral dissolution, resulting in oil desorption and an increase in solution pH. The increase in solution pH also resulted in reduced electrostatic bond attraction which lead to rock wettability alteration using low-salinity brines.