Effects of dissolved binary ionic compounds and different densities of brine on interfacial tension (IFT), wettability alteration, and contact angle in smart water and carbonated smart water injection processes in carbonate oil reservoirs

Interfacial tension and wettability are among factors affecting forces in an oil reservoir. Both of these factors are influenced by chemical mechanisms. For example, the interactions between ions, the rock surface and fatty acids can alter the wettability. Moreover, the competitive effects of salting-out and salting-in on increasing and decreasing the salinity of injected water can lead the water-oil interfacial tension (IFT) to another direction where adding carbon dioxide to the injected water can create factors that change the properties of the oil droplet and consequently change the interfacial tension value. The dissolution of carbon dioxide in smart water (low salinity water) results in a chemical reaction and reduces the density as well, and its diffusion into the oil droplet adjacent to the smart water increases the volume of the droplet and affects its viscosity and other properties. The acid formed by the dissolution of CO2 in the injected water may dissolve some minerals in carbonate rock surface and change the surface properties. The goal in enhanced oil recovery (EOR) process through water injection is to minimize interfacial tension, and moderate rock wettability to exhibit hydrophilic characteristics. Ions in injection water in a certain density cause the interfacial tension to reach relative minimum, and alter oil-wet characteristics of carbonate rocks towards more water wet characteristics. The effect of CO2 dissolution in injection water, forming carbonated water containing dissolved ions, on these two parameters is obvious and improves them. In this communication, K2SO4, KI, MgSO4, Na2SO4, CaCl2, MgCl2, KCl, and NaCl salts, as binary ionic compounds, were used for producing smart water with concentrations of 1000 + 1000, 2000 + 2000, 5000 + 5000, and 10,000 + 10,000 ppm. Then, the effects of dissolution of these salts on interfacial tension and contact angle between water, oil, and carbonate rock were studied. In addition, CO2 was added to the ionic solution with optimal compositions and densities in terms of minimum interfacial tension under the pressures of 6894.7, 10,342.1, and 13,789.5 kPa, and its effects on the latter two parameters were investigated. After that, the effects of ions dissolved in seawater (10 times diluted seawater) on water-oil interfacial tension, wettability of carbonate rock and contact angle under the pressure of 101.4 kPa in the absence of CO2, and under the pressures of 6894.7, 10,342.1, and 13,789.5 kPa in the presence of CO2 were studied. All tests were conducted at constant temperature of the reservoir (75 degrees C). The minimum interfacial tension was obtained for MgCl2 + K2SO4 composition (6.73 mN/m), which was lower than the interfacial tension between the initial amount of fresh water and oil (24.145 mN/m) by 72%. This reduction reached 83% after carbonating the solution under 2000 ppm and 75 degrees C conditions. The minimum contact angle in the aged segment for KCl + MgCl2 composition with concentration of 2000 + 2000 ppm was recorded as 39.80, which decreased by 49.62% and reached 20.05 degrees by adding CO2 under 13,789.5 kPa condition. The interfacial tension between seawater (initial density) and crude oil, under 101.4 kPa and 75 degrees C conditions, was obtained as 27.464 mN/m. The interfacial tension values under 6894.7, 10,342.1, and 13,789.5 kPa conditions were obtained as 25315 mN/m, 25.146 mN/m, and 21.464 mN/m, respectively. These results reveal a decreasing trend after each dilution stage. In addition to trend, reduction of the initial contact angle in the aged segment in the solution after each dilution step indicates better performance of ionized seawater relative to normal seawater. (C) 2017 Published by Elsevier B.V.