No abstract

Low-salinity water injection is an emerging enhanced oil recovery technique and an area of active research. According to many researchers, the role of brine salinity has been attributed to its ability to change the reservoir rock wettability. The influence of different parameters such as total dissolved solids, concentration of individual ions, oil composition, lithology, acid and base number, etc., has been tested previously using different combinations of crude oil and reservoir core samples. However, because of the complex nature of crude oil–brine–rock system, there is no clear idea of the mechanism of wettability alteration and the influence of above parameters on this process. In this work, we have investigated the governing factors affecting the wettability of mineral surface using pure alkane liquids and model oils (containing organic acid and base). The wettability studies were performed through contact angle measurements over a wide range of concentration (1 mM to 1M) of monovalent and divalent salts (NaCl, CaCl2, and Na2SO4) to identify the effect of salt types and concentrations of different ions present in the injection water. The use of model systems provided a better understanding of the wettability alteration mechanism, in comparison to the earlier studies performed using crude oil and actual reservoir rock sample. The results of this study showed that the wettability alteration with brine salinity is significantly different for pure alkanes and model oils containing polar component, and it is dependent on the type of cations (monovalent versus divalent) present in the system. Scanning electron microscopy and electron dispersive spectroscopy studies showed that the polar oil components such as petroleum acids and bases get adsorbed on mineral (quartz) surface in the presence of cations and are primarily dependent on the cationic concentrations in water, affecting the performance of a low-salinity water flooding process.

With a constant upsurge in energy demand, production from depleted and harsh reservoirs through enhanced oil recovery techniques (EOR) has significantly increased. Among many EOR techniques, chemical EOR (cEOR) is one of the most widely used methods of oil extraction. Surfactants used in cEOR are instrumental in reducing interfacial tension (IFT) and altering the wettability of rock, which leads to additional oil recovery. This review draws attention to detail on surfactants from fundamentals to field scale. Properties of surfactants like phase behaviors, critical micelle concentration (CMC), hydrophilic–lipophilic balance and deviation, zeta potential, and their importance are discussed in depth. The presence of a saline environment, polymer, cosurfactant, and other factors affecting the performance of surfactant during the cEOR process are also elaborated. Key findings on surfactant adsorption on reservoir rock with other influencing aspects have also been reported in this study. Types of surfactants, from basic to the likes of polymeric, viscoelastic, Gemini, natural, and their effects on oil recoveries have been analyzed and compared. Special emphasis on emerging aids for surfactant flooding such as applications of nanotechnology, use amphoteric Janus particles, and synergies of surfactant–low salinity water flooding, along with their mechanisms and recent advances have been thoroughly duscussed. Lastly, the review delineates discerning criteria for the selection of surfactants, reviews recent field applications, and outlines the challenges that the industry faces while implementing surfactant cEOR. It has been found that exhaustive studies have been conducted on sandstones with success. However, extreme temperature and saline conditions in the case of carbonate reservoirs limit the applicability of surfactants, and the pursuit to accomplish its efficacy continues.

No abstract

Synergism between different enhanced oil recovery (EOR) methods has always been a subject of paramount interest for oil industry as it led to the development of many successful EOR methods in the past. Low salinity water flooding is a recent development in the field of EOR, and polymer flooding is a conventional EOR technique that has been practiced for many decades. In this study, we have investigated the synergistic effects of low salinity water flooding and polymer flooding focusing on the effect of low salinity on polymer rheology, polymer solution injectivity, retention of polymer in the reservoir rock, and oil recovery efficiency of low salinity polymer flooding. The study is comprised of a multidimensional experimental approach including measurements of bulk rheology of polymer solutions prepared with brines of varying salinities, single phase displacement experiments for injectivity analyses, UV–visible and electron dispersive spectroscopy along with scanning electron microscopy for studying retention of polymer on the reservoir rock surface, and finally laboratory flooding experiments to demonstrate the oil recovery efficiency of low salinity polymer flooding synergy. The results obtained from this study show that low salinity water tremendously improves the polymer rheology that could greatly favor the oil recovery efficiency of the overall process. Low salinity water is also found to be a very impressive agent for improving displacement efficacy and the injectivity of a polymer solution. Finally, the results of enhanced oil recovery flooding experiments demonstrated that low salinity polymer flooding could significantly increase the oil recovery efficiency in comparison to either low salinity or conventional polymer flooding alone.