Enhanced oil recovery (EOR) plays a pivotal role in maximizing hydrocarbon extraction following primary and secondary recovery stages. While conventional methods remain applicable, chemical enhanced oil recovery has emerged as a cost-effective alternative [1-5]. Generally, with declining discoveries of new reservoirs, optimizing recovery from existing fields has become imperative [6]. Low-permeability reservoirs present particular challenges, where water flooding typically recovers only ~20% of original oil in place due to narrow pore throats, heterogeneity, and complex flow dynamics [7,8]. Recently, nanocomposites have shown particular promise in chemical enhanced oil recovery by modifying key reservoir parameters [9-11]. These advanced materials function through multiple mechanisms: wettability alteration (WA) from oil-wet to water-wet conditions, prevention of asphaltene precipitation, interfacial tension reduction, and mobility ratio optimization [12-16]. It is worth noting, nanotechnology has revolutionized enhanced oil recovery through nanoparticles, nanofluids, and nanocomposites that modify fluid-rock interactions [17,18]. The unique behavior of nanofluids arises from electrostatic repulsion and Brownian motion, creating layered structures that generate wedge films at solid-oil-water interfaces [19-21]. Salem et al. (2023) [22] explored polymer flooding enhanced by nanoparticles, finding that optimal concentrations of both polymer and nanoparticles improved oil recovery by 18% of the original oil in place. A subsequent study by Salem et al. (2024) [23] examined Enhanced oil recovery using nanocomposite flooding, testing three formulations: hydrolyzed polyacrylamide-silica, hydrolyzed polyacrylamide-alumina, and hydrolyzed polyacrylamide. The experiments revealed recovery rates of 8.6%, 17.4%, 15.3%, and 13.6% of the original oil in place for hydrolyzed polyacrylamide, hydrolyzed polyacrylamide-silica, hydrolyzed polyacrylamide-alumina, and hydrolyzed polyacrylamide-zirconia, respectively. Surfactant nanofluids, which blend nanoparticles with surfactants, enhance microscopic displacement efficiency by lowering interfacial tension and modifying wettability [24]. Nano-surfactants demonstrate significant potential for enhanced oil recovery by effectively reducing interfacial tension at rock/oil/brine interfaces, thereby inducing more substantial WA [25]. These advanced formulations exhibit synergistic interactions with both oil and aqueous phases, facilitating improved hydrocarbon mobilization. Particularly in carbonate reservoirs - which are characterized by natural fracturing and inherent hydrophobicity leading to suboptimal recovery [26]. Recent research confirms surfactant flooding as a robust Enhanced oil recovery technique, operating through multiple mechanisms including interfacial tension reduction, phase emulsification, wettability modification, and asphaltene precipitation inhibition [27]. However, practical implementation faces challenges such as surfactant hydrolysis, chemical degradation, precipitation phenomena, and substantial adsorption onto reservoir rock surfaces, which collectively diminish efficiency and elevate operational costs [28]. In general, recent investigations reveal that coupling low-salinity water, defined as aqueous solutions containing <2000 mg/L dissolved saltes [29], with complementary agents can substantially improve oil recovery [30-34]. The appeal of low salinity water stems from its economic viability, tunable chemical composition, and environmental sustainability [35], with demonstrated capacity to transform rock wettability from oil-wet to water-wet states [36,37]. Sekerbayeva et al. (2022) [38] developed an optimized low-salinity water-surfactant system, demonstrating that maximum WA occurred at 10-times seawater dilution, with alkyl benzene sulfonic acid exhibiting superior surfactant stability. Their results revealed that the composite low-salinity water-surfactant formulation induced more significant WA compared to low-salinity water alone, achieving a 70% oil recovery factor - a substantial improvement over the 61% and 52% recovery obtained with standalone low-salinity water and formation water injection, respectively. Complementary research by Al-Shatty et al. (2022) [39] showed that octanoic acid-functionalized alumina nanoparticles combined with cetyltrimethylammonium bromide surfactant enhanced oil recovery by 5% relative to cetyltrimethylammonium bromide alone, which was attributed to the enhanced interfacial activity of nanoparticle-surfactant complexes at oil-water interfaces. Further supporting these findings, Pereira et al. (2020) [40] reported 30% incremental oil recovery in tertiary mode using iron oxide nanoparticles with cetyltrimethylammonium bromide, where mechanistic studies indicated that nanoparticles promoted oil mobilization through asphaltene adsorption and WA while the surfactant primarily reduced interfacial tension [41]. Recent studies demonstrate that silica nanoparticles, when used with surfactants and low-salinity water, enhance oil recovery. Compared to non-silica nanoparticles, adding 0.1 wt% silica nanoparticles to a mixture of 50% low-salinity water and surfactants boosted oil recovery by 15% [42]. In carbonate reservoirs, silica nanoparticles with low-salinity water and surfactants improved recovery by 8–11% over low-salinity water alone [43], while also increasing the original oil in place by 5% due to reduced water production [42]. The optimal silica concentration in surfactant solutions was found to be 0.05 wt%, and injecting a combination of low-salinity water, cetyltrimethylammonium bromide, and silica nanoparticles over 2 pore volumes recovered 76% of original oil-in-place [44]. Silica nanoparticle-surfactant blends outperform standalone surfactants or brine by more effectively reducing interfacial tension and altering rock wettability [45], making them highly effective for enhance oil recovery. Trabelsi et al. (2011) [46] confirmed a strong synergy between in situ and added surfactants, achieving an ultralow interfacial tension of ~4×10-4 mN/m at 0.05% sodium dodecyl benzene sulfonate concentration and pH 11. Silica nanoparticle-surfactant systems show great promise across various reservoir conditions, with surface-modified silica nanoparticles maintaining stability for at least six months even under high salinity and temperature [47]. Adding anionic surfactants like sodium dodecyl sulfate further enhances nanofluid stability and recovery efficiency in saline environments [48]. Additionally, silica nanoparticles with low-salinity water shift wettability toward water-wet conditions and lower interfacial tension in carbonate formations [49]. Hybrid nanostructures, such as silica-iron oxide composites, can drastically reduce interfacial tension—from 17.39 mN/m to 2.55 mN/m—when combined with surfactants [50]. These findings highlight the strong potential of silica-based nanomaterials in advancing enhanced oil recovery technologies. Generally, SiO2 nanoparticles are the most widely utilized nanomaterials due to their affordability, simple surface modification, and excellent environmental compatibility. Properly modifying these nanoparticles serves as a crucial approach for enhanced oil recovery [51]. In the field of EOR with nanofluids, numerous studies have been conducted on various nanoparticles and surfactants. In this regard, while previous studies have explored physical mixtures of SiO2/Al2O3 or their composites, our approach is fundamentally different. A key limitation of prior nanofluid studies is long-term instability and the risk of asphaltene precipitation, which can clog low-permeability formations. Our formulation, stabilized by the non-ionic surfactants (Triton X-100, Brij 35) in low-salinity water, is explicitly designed for superior thermodynamic stability under reservoir conditions. Furthermore, we provide direct experimental evidence that our system actively asphaltenes stability instead of precipitating them, thereby mitigating a major risk associated with nanofluid injection and making it uniquely suitable for low-permeability reservoirs. However, our innovation is the design and mechanical validation of a synergistic and multifunctional "smart nanofluid" system for the first time. The novel contributions are fourfold: first, our system presents a novel synergistic nano-architecture, not just a nanocomposite, where SiO2-modified HDTMS serves as a highly hydrophobic agent to disrupt the oil phase, while petroleum-degrading Al2O3 acts as a hydrophilic catalytic agent, with this specific synergy in a low-salinity surfactant solution being a first-time proposal for EOR. In this regard, special surfactants such as Triton X-100 and Brij 35 have been used in the synthetic solution, which makes this innovation more visible. Second, our work advances a multi-mechanistic approach beyond just interfacial tension reduction, as our nanofluid is engineered to simultaneously activate ultra-low IFT, profound wettability alteration, asphaltene stabilization, and structural disjoining pressure. Third, our formulation explicitly addresses key limitations like thermodynamic instability and asphaltene deposition by providing a stable system that actively stabilizes asphaltenes, mitigating risks for low-permeability reservoirs. Finally, the system is "smartly" designed for low-permeability environments, utilizing collaborative pore-throat unclogging and viscous oil mobilization. In summary, our novel contribution lies in the rational design, experimental demonstration, and mechanistic elucidation of this multi-component system where each component has a designated role, working in concert to achieve a superior EOR outcome through multiple, simultaneous pathways. Our findings reveal that the synergistic interaction between nanoparticles and surfactant significantly enhances oil displacement efficiency.
