## 1 Introduction
The high cost of adding surfactants alone also means that this method is difficult to scale up [19; 20; 21; 22]. In addition to surfactants, it has been mentioned in past studies that other chemicals can be used to reduce interfacial tension or change rock wettability to a more favorable state [23; 24; 25; 26; 27; 28; 29; 30; 31; 32; 33; 34; 35; 36; 37; 38; 39; 40; 41; 42; 43]. Among the various enhanced oil recovery techniques, the injection of low-salinity water has garnered significant interest from the research community in recent years, primarily due to its operational simplicity and reduced implementation costs. Currently, international researchers have performed specialized core analysis experiments on samples derived from carbonate reservoirs. These studies have demonstrated that the efficacy of low-salinity water injection is highly dependent on the specific properties of the rock and the chemical composition of the water injected [23]. By manipulating the ionic composition of the injected water, it is possible to enhance recovery rates by modifying relative permeability and altering the wettability of oil-wet and mixed-wet carbonate rocks towards increased hydrophilicity [24; 25; 26; 27; 28]. In addition, zeta potential assessments have revealed that the impact of low-salinity water injection in carbonate reservoirs is more pronounced at elevated temperatures [20]. Lower acid values in oil, elevated initial water saturation, and the presence of calcium, magnesium, and sulfate ions in the injected water can also enhance the efficacy of advanced water injection techniques [29; 30; 31]. In the present research, we have developed a novel enhanced recovery technique for carbonate reservoirs, integrating water injection with surfactants to optimize oil and gas extraction. For this study, rock and oil samples were collected from a fractured reservoir located in the Sichuan Basin. The Sichuan Basin, encompassing approximately 260,000 square kilometers or 46 percent of Sichuan Province's total area, is geographically delineated by the Tibetan Plateau and the Hengduan Mountains to the west, and the Qinba Mountains to the north, adjacent to the Hanzhong Basin. The primary lithological composition of the basin predominantly includes purplish-red sandstones and shales. Low-salinity solutions were formulated by adjusting the ionic composition and diluting the formation water. Through experimental evaluations of various diluted low-salinity solutions, the optimal salinity level that resulted in the minimum contact angle was identified. Additionally, to enhance the efficacy of water injection, two types of surfactants, cationic and nonionic, were incorporated into the solution with the determined optimal salinity. The stability of the water containing the designed surfactant mixture was assessed through multiple experiments. These assessments confirmed that an optimal proportion of cationic to non-ionic surfactant concentrations effectively minimized the interfacial tension. The specific methods and results of the above experiments are described in detail below. The efficacy of the formulated solutions was rigorously assessed through core flooding and seepage experiments, and the outcomes were benchmarked against those achieved with alternative surfactant formulations and low-salinity solutions. The findings substantiated that the specifically tailored surfactant ratios in the designed solution significantly enhance hydrocarbon recovery in carbonate fractured reservoirs, demonstrating a pronounced superiority over other comparable methods.