Synergistic effect of low saline ion tuned Sea Water with ionic liquids for enhanced oil recovery from carbonate reservoirs

Theoretical and experimental investigation of the impact of oil functional groups on the performance of smart water in clay-rich sandstones

This research investigated the effect of ion concentration on the performance of low salinity water under different conditions. First, the effect of injection water composition on interparticle forces in quartz-kaolinite, kaolinite-kaolinite, and quartz-oil complexes was tested and modeled. The study used two oil samples, one with a high total acid number (TAN) and the other with a low TAN. The results illustrated that reducing the concentration of divalent ions to 10 mM resulted in the electric double layer (EDL) around the clay and quartz particles and the high TAN oil droplets, expanding and intensifying the repulsive forces. Next, the study investigated the effect of injection water composition and formation oil type on wettability and oil/water interfacial tension (IFT). The results were consistent with the modeling of interparticle forces. Reducing the divalent cation concentration to 10 mM led to IFT reduction and wettability alteration in high TAN oil, but low TAN oil reacted less to this change, with the contact angle and IFT remaining almost constant. Sandpack flooding experiments demonstrated that reducing the concentration of divalent cations incremented the recovery factor (RF) in the presence of high TAN oil. However, the RF increment was minimal for the low TAN oil sample. Finally, different low salinity water scenarios were injected into sandpacks containing migrating fines. By comparing the results of high TAN oil and low TAN oil samples, the study observed that fine migration was more effective than wettability alteration and IFT reduction mechanisms for increasing the RF of sandstone reservoirs.

Stability of the emulsion during the injection of anionic and cationic surfactants in the presence of various salts

Smart water injection is one of the engineering techniques to enhance oil recovery (EOR) from carbonate and sandstone reservoirs that have been widely used in recent decades. Wettability alteration and IFT are among the essential and influential mechanisms that can be mentioned to achieve EOR. One of the critical issues in the field of EOR is the effect of reservoir ions on the formation and stability of the emulsion. Investigating the role and performance of these ions during EOR processes is of significant importance. These processes are based on smart water injection and natural production. In this research, stability was investigated and formed during the injection of different concentrations of anionic and cationic surfactants, respectively alpha olefin sulfonate (AOS) and cetrimonium bromide (CTAB), into a water-oil emulsion with a volume ratio of 30-70. Considering the droplet diameter distribution and the flow speed of separation by centrifugation, the optimal concentration level has been investigated in both surfactants. Based on the results, the highest stability and emulsion formation occurred in the presence of AOS surfactant. Then different concentrations of CaCl₂, MgCl₂, and NaCl salts were added in optimal concentrations of both surfactants. The formation and stability of the emulsion was checked by examining the distribution of the droplet diameter and the separation flow rate. AOS anionic surfactant had the most stability in the presence of MgCl₂ salt, and better performance in stability of the emulsion was obtained. The maximum number of droplet diameters in the optimal concentration for AOS and CTAB surfactant systems is 1010 and 880, respectively, and for binary systems of AOS surfactant and MgCl₂, CaCl₂ and NaCl salts, it is 2200, 1120 and 1110, respectively. Furthermore, for the CTAB binary system in the presence of MgCl₂, CaCl₂, and NaCl salts, it is 1200, 1110, and 1100, respectively. The stability of the emulsion of salts in the presence of both AOS and CTAB surfactants was MgCl2 > CaCl₂ > NaCl.

Experimental investigation of wettability alteration, IFT reduction, and injection schemes during surfactant/smart water flooding for EOR application

In recent years, the application of smart water and surfactant in order to improve oil recovery has attracted special attention in carbonate reservoirs. In this research, the effects of various salts in smart water and two surfactants of Cetyl Trimethyl Ammonium Bromide (CTAB) and Sodium Dodecyl Sulfate (SDS) on the wettability alteration of carbonate rock and IFT were studied. Besides, along with micromodel flooding, core flooding tests were conducted to assess the amount of oil recovery at reservoir conditions as an injection scheme was used. In this regard, the results illustrated that the presence of CTAB or SDS in seawater (SW) can act better in contact angle reduction compared to smart water. Also, a four times increase in the concentration of SO₄^2- and removing Na⁺ from SW reduced the contact angle to 68° and 71°, respectively, being the best possible options to alter the carbonate surface wettability to more water-wet states. Moreover, in the second-order process in which the rock section was first placed in SW, and then was put in the smart solution (with or without surfactant), CTAB had a great effect on the wettability alteration. In the case of IFT reduction, although SW4Mg²⁺, compared to other ions, better decreased the IFT to 17.83 mN/m, SW + SDS and SW + CTAB further declined the IFT to 0.67 and 0.33 mN/m, respectively. Concerning different ions, divalent cations (Mg²⁺ and Ca²⁺) show better results in improving oil recovery factor. However, the combination of SW and surfactants has a more positive effect on boosting oil recovery, as compared to smart water flooding. It should be mentioned that the first-order injection is better than the second-order one since SW is flooded at first, and then, after the breakthrough, smart water is injected into the micromodel. In addition, the core flooding tests showed that SW + CTAB and SW + SDS in tertiary injection increased the oil recovery to about 59 and 57%, respectively, indicating that the presence of CTAB could be more effective than that of SDS.

Experimental Investigation of the Synergistic Effect of Two Nonionic Surfactants on Interfacial Properties and Their Application in Enhanced Oil Recovery

In chemically enhanced oil recovery (EOR), surfactants are conventionally used to lower the interfacial tension (IFT) at the water-oil interface, alter the rock wettability, and help in the emulsification of trapped oil after primary and secondary modes of recovery. A mixture of surfactants is usually more effective than a single surfactant with enhanced surface or interfacial properties. The primary objective of this study is to examine the synergistic effects of two nonionic surfactants (Tergitol 15-S-12 and PEG 600) on surface properties, such as surface tension, IFT, and wettability alteration, in the context of EOR. The optimum composition of the surfactant mixture was obtained by surface tension measurement, and it has been found that the Tergitol 15-S-12 and PEG 600 mixture shows better synergistic effect with a minimum surface tension value of 30.3 mN/m at 225 ppm concentration of Tergitol 15-S-12 and 1 wt % of PEG 600. The surfactant mixture with optimum composition shows an ultra-low IFT of 0.672 mN/m at optimum salinity. The wettability alteration study was conducted in a goniometer by observing the change of the contact angle of an oil-wet sandstone rock in the presence of the formulated chemical slugs at different concentrations, and the results show a shift in the wettability of rock from the oil-wet to the water-wet region. The wettability alteration behavior of oil-wet rock is established using X-ray diffraction analysis of sandstone rock and zeta potential measurements of the chemical slugs. The efficacy of the optimized chemical slug for EOR was checked by a core flooding experiment, and an additional recovery of 17.73% of the original oil in place was observed.