SmartWater flooding (SWF) has been proven as an effective and successful recovery method for carbonates, in which the injected water alters the carbonate rock wettability to produce incremental oil. Core-scale displacement experiments have demonstrated significant incremental recoveries of SmartWater in both secondary and tertiary modes. Single-well chemical tracer tests have demonstrated this potential in the field at a scale larger than those examined in the laboratory. Still, the underlying mechanisms responsible for SmartWater wettability alteration of carbonates are not well understood. The objective of this work is to understand the effects of individual mono and divalent ions on brine-oil interactions and their role in the observed alteration of carbonate wettability.In previous studies, we have investigated liquid-rock interactions and their role in wettability alteration. At fixed salinities, mono and divalent ions were found to have different effects on the calcite surface potential. Here, we investigate SmartWater effects on liquid-liquid interactions. We perform interfacial tension (IFT) measurements between oil and brines of fixed salinities but varying ionic compositions, and we collect IFT data at different temperature conditions. The different SmartWater recipes, at fixed salinities, have exhibited different IFT values indicating the varying effects of ions on fluid-fluid interactions. SmartWater recipes composed exclusively of magnesium cations exhibited a remarkably low level of IFT values. In contrast, SmartWater recipes with sodium or calcium cations exhibited comparable IFT stabilization levels, while SmartWater recipes that are solely composed of sulfate anions have resulted in higher IFT values. The low IFT values obtained with Mg 2ϩ ions can be attributed to weaker bond dissociation energies and quicker ion accessibility in MgCl 2 when compared to the other salts.In the next stage, these results will be integrated with Zeta potential and contact angle data acquired at similar brine salinities and composition. This systematic integration will allow for a better understanding of individual ion effects, which would eventually help to further optimize the SmartWater recipe for higher oil recovery.

SmartWater injection is a proven technology and a successful recovery method in carbonates at tertiary and secondary modes that showed significant incremental oil recovery compared to seawater injection. The objective of this paper is to bring new insights on wettability alteration mechanisms caused by SmartWater by investigating the effects of single ions (monovalent and divalent) at fixed salinity on rock/fluids and fluid/fluid interactions. Contact Angle (CA) measurements of oil, carbonate rock and different SmartWater recipes at fixed salinity were conducted at different temperatures and pressures in an attempt to evaluate the impact of individual components on the wettability of oil/brine/rock systems. Contact angle data are compiled and compared to rock surface potential properties obtained by earlier Interfacial Tension (IFT) measurements. This integration will help to identify the role and influence of individual mono and divalent ions on the wettability alteration mechanisms. The data analysis confirms the sensitivity of contact angle against different temperatures and reveals the effect of individual key ions on crude oil/water/rock interface. At fixed salinity, different SmartWater recipes give different contact angle values, indicating that the interplay of determining ions is critical to fluid/rock interactions as individual ions play different roles depending on their valence, which will affect the wettability, and ultimately the oil recovery. SmartWater recipes that are composed of Mg2+ ions solely have exhibited a lower level of contact angle values compared to other SmartWater key ionic components. Na+ and Ca2+ have shown a comparable contact angle level, while SO42- ions, generally, have resulted in low contact angle values only at elevated temperatures. The ultimate goal of this study is to enhance our understanding of carbonate wettability alteration by integrating the role of oil/brine/rock interactions and the effect of individual mono and divalent ions. These efforts will ultimately lead to additional oil recovery through optimizing injected SmartWater recipes.

During waterflooding processes, injected water disconnects oil droplets as it flows through pores/throats in the reservoir. These disconnections are a consequence of capillary effects hindering the mobilization of oil through pores/throats of the reservoir. Thus, mobilizing the remaining oil in place by any enhanced oil recovery (EOR) process becomes very challenging. Chemical flooding has been identified as an effective EOR method, which is usually implemented in tertiary mode, where field development has reached a mature level. At this stage, the efficiency of waterflooding, in terms of mobilizing remaining oil, declines due to capillary trapping. Chemical EOR (CEOR) methods such as polymer-surfactant flooding are used to reduce this trapping and mobilize the remaining oil. Although most EOR processes have been implemented in tertiary mode, earlier implementation is more desirable, because capillary trapping is less prominent. This study investigates the impact of post-waterflood implementation time of surfactant-polymer flooding on ultimate recovery and net present value (NPV), given this capillary trapping. A series of numerical experiments was conducted to test this effect while accounting for operating expenses associated with both flooding options. Capillary pressure curves for the waterflood case and the chemical flood case were added to incorporate capillary trapping effects. Then the chemical-flood implementation time was varied to evaluate its impact on the ultimate oil recovery. These experiments were performed on two stylized reservoir models PUNQ-S3 and SPE10M reservoir models. Given our assumptions, the ultimate recovery did not significantly change with varying the CEOR implementation time. There is, however, an optimum implementation time for CEOR at which NPV is maximized. The optimum implementation time becomes sooner as the geologic model is more heterogeneous.

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