## 1 Introduction  
Petroleum in carbonate reservoirs constitutes 60% of the global oil reserves and has significant potential for enhanced oil recovery (EOR) [1]. However, owing to the heterogeneity and oil-wet characteristics of carbonate formations, the effectiveness of conventional water-proofing, a secondary recovery method, is limited, resulting in lower oil recovery [2, 3, 4]. With the advancement of nanotechnology, its application in the oil and gas industry has expanded. In particular, the use of nanofluids in the field of EOR is increasing, offering the promise of improved oil recovery through various mechanisms, such as wettability alteration, structural disjoining pressure, and interfacial tension (IFT) reduction. The primary mechanisms of nanoscale particles involve rock-fluid interactions and fluid-fluid interactions. In rock-fluid interactions, nanoscale particles are adsorbed onto the rock surface, displacing oil droplets and altering the wettability of the rock to render it more hydrophilic, thereby inducing oil recovery. However, pore deformation or plugging may occur during adsorption, leading to decreased permeability. As the degree of adsorption increases, oil recovery can be simultaneously enhanced by increasing hydrophilicity and reducing fluid mobility owing to decreased permeability. Therefore, a comprehensive anal ysis is essential to understand the effects of adsorption on both wettability and permeability and their implications for oil recovery. [PERSON] and [PERSON] [5] analyzed the EOR effect of silica nanoparticles (SNPs) on carbonate rock samples. In their observations, the oil recovery rate varied with the nanoparticle concentration. [PERSON] et al. [6] investigated the impact of SiO\({}_{2}\)-based nanofluids on the wettability of carbonate rocks. They determined the minimum reaction time required for a sample to transition from hydrophobic to hydrophilic. [PERSON] et al. [7] used hydrophilic silica nanofluids to determine the effects of nanofluid salinity and particle concentration on oil recovery and stability. They found that wettability alteration and reduced interfacial tension maximized oil recovery at a salinity level of 20,000 ppm and a nanoparticle concentration of 0.05 wt.%. Notably, typical salinity levels in carbonate reservoirs are approximately 90,000 ppm, indicating a high brine environment. This may affect the dispersion stability of nanoparticles, potentially leading to reduced efficiency in nanoparticle injection methods and hindering reservoir productivity. [PERSON] et al. [8] and [PERSON] and [PERSON] [9] polymerized silica nanoparticles with silane and confirmed their high dispersion stability. [PERSON] et al. [10] also demonstrated stable dispersion over a week in environments with temperatures up to 90 \({}^{\circ}\)C and salinity levels of 12 wt.% by binding cationic polymers to silica nanoparticles. [PERSON] et al. [11] manufactured stable nanofluids using a silane coupling agent called GPTMS ((3-glycidoxypropyl)trimethoxysilane) and silica nanoparticles at 20 wt.% salinity and 90 \({}^{\circ}\)C. They also confirmed that the nanofluid had a positive effect on the wettability of carbonate rock samples. The synthesis of nanoparticles using chemical methods and subsequent polymerization can enhance their dispersion stability, even in high-temperature and high-salinity environments [12; 13; 14]. These nanoparticles can be injected into carbonate reservoirs to aid oil recovery. When nanoparticles undergo functionalization, the characteristics of the resulting material and their interaction with the reservoir environment can be influenced, affecting both fluid-fluid and fluid-rock interactions. To optimize nanofluid flow using injection methods, it is crucial to characterize the produced nanofluid. Specifically, it is essential to analyze the impact of nanofluid reactivity (adsorption capacity) on wettability alteration, which is one of the main mechanisms. This can significantly affect the oil recovery rate by altering the wettability. [PERSON] et al.