Mechanistic investigation of using optimum saline water in carbonate reservoirs low asphaltenic crude oil with high resin content: A carbonate-coated microfluidic study

Abstract

Many mature reservoirs around the world have entered the second period of their life and their production rates are going to decline. In addition, after producing from the reservoir at the primary and secondary stages more than 50 percent of hydrocarbons would remain in place. Therefore, it is essential to find a suitable method to increase oil recovery in the tertiary stage. In recent two decades, smart water or low saline water (LSW) flooding has been introduced as a dominant method, especially on wettability alteration from oil-wet to water-wet or neutral wet conditions, which is leading to more oil production. On the contrary, there are an inadequate number of researches on low asphaltenic crude oil with high resin content in water flooding. In this type of crude oil, the role of asphaltene in changing the wettability and reducing the interfacial tension (IFT) is not as great as the other surface active agents of crude oil. Hence, the role of each ion and its synergism with the surface active agents of crude oil may be different from previous studies. The fluid–fluid and rock-fluid interactions between diluted seawater and a low asphaltenic crude oil were investigated by performing different types of experiments, such as pendant drop IFT measurement tests, sessile drop contact angle (CA) measurement experiments, zeta potential analysis, and pH determination. In the next step, the impact of ten different salts on reducing the interfacial tension, and wettability alteration was determined to show the underlying mechanisms of optimum brine based on the same ionic strength (IS). Finally, some microfluidic tests were utilized in a carbonate-coated micromodel to show the confirmation of previous results in porous media visually and determine the fluid–fluid and rock-fluid interactions on the recovery factor (RF). Based on IFT and CA results, the optimum brine was seawater (SW) that could reduce the IFT from 21.13 to 16.21 mN/m and change the CA from 137° to 46° (Δϴ = 91°). Due to the lower asphaltene content in such crude oil, the presence of Na+ with SO42-, and Mg2+ with Cl- plays a significant role in IFT reduction by creating a synergistic effect between these ions with a high fraction of resin. Na2SO4 and MgSO4 reduce the IFT from 21.13 to 6.21 and 8.46 mN/m, respectively due to the existence of the high amount of Mg and SO4 in aqueous solution which has a considerable effect on fluid–fluid interaction. Also, Mg2+ and SO42- can obtain 89° wettability alteration (Δϴ) and provide a water-wet condition (ϴ = 48°) because of the synergistic of the presence of divalent anions and cations through the solution and the presence of high resin content that leads to excellent wettability change. Additionally, Na2SO4 can change the contact angle from 137° to 67° (Δϴ = 70°). Although the greatest impact of single salts on IFT reduction and wettability alteration was obtained by Na2CO3 and NaHCO3 because of saponification and pH elevation; however, the concentration of these salts in SW was negligible. Thus, the main salts for fluid–fluid and rock-fluid interactions in SW/low asphaltenic crude oil/calcite systems were Na2SO4, MgSO4, and MgCl2. Moreover, due to the presence of Na+, Mg2+, and SO42- in SW, the wettability of the pore surface was altered from oil-wet to water-wet during SW flooding in the micromodel. Furthermore, reducing the IFT and changing the wettability lead to decreasing the capillary number and delay in breakthrough (BT) time, which consequently improved the oil recovery from 25.42 % (DIW flooding) to 46.59 %. The findings of this study can help for a better understanding of the effect of low asphaltenic with high resin crude oil and ions on the fluid–fluid and rock-fluid interaction through porous media at static and dynamic conditions in order to increase the final oil recovery.