This study presents a novel Enhanced Oil Recovery (EOR) method using Smart Black Nanocards (SLNs) to mitigate the environmental impact of conventional thermal recovery, especially under global warming. Unlike prior studies focusing on wettability alteration via adsorption, this research innovatively models ‘oil film detachment’ in a reservoir simulator to achieve wettability alteration. Using the CMG-STARS (2020) simulator, this study highlights SLNs’ superior performance over traditional chemical EOR and spherical nanoparticles by reducing residual oil saturation and shifting wettability toward water-wet conditions. The structural disjoining pressure (SDP) of SLNs reaches 20.99 × 10³ Pa, 16.5 times higher than spherical particles with an 18.5 nm diameter. Supported by the Percus–Yevick (PY) theory, the numerical model achieves high accuracy in production history matching, with oil recovery and water cut fitting within precision error ranges of 0.02 and 0.05, respectively. This research advances chemical EOR technologies and offers an environmentally sustainable, efficient recovery strategy for low-permeability and heavy oil reservoirs, serving as a promising alternative to thermal methods.

Summary: Single-energy X-ray computed tomography (CT) enables repeated in-situ imaging of multiphase flow in centimeter-scale cores, but oil/water/gas three-phase saturation estimation remains underdetermined because each voxel provides only one gray-value response. With this study, we develop a three-phase saturation estimation workflow for water-alternating-gas (WAG) displacement in a layered heterogeneous core by combining macroscopic material-balance constraints with dynamic iteration. The method first identifies the gas phase using the CT-response contrast between gas and liquid phases, and removes the gas contribution from the measured CT signal. Cumulative oil production is then used to constrain the whole-core hydrocarbon-equivalent remaining volume, while a dynamic oil/water threshold is determined within the liquid-voxel set, and the liquid-phase CT baseline is iteratively updated. Compared with the two-phase reduction, fixed-threshold (fixed-Tow), and static liquid-baseline workflows, the dynamic iterative method maintained low material-balance closure deviation while retaining relatively low CT forward-reconstruction residuals. Across the one-at-a-time parameter tests, the largest change in whole-core material-balance closure mean absolute error (MAE) was 0.0415, and the complete processed sequence required approximately 167 seconds, only 2.4% longer than the fixed-Tow workflow. Three-phase spatial distributions at representative displacement stages further show that the method can more continuously characterize preferential sweep, water invasion, and gas-channel development. The workflow was demonstrated in a layered artificial core with permeabilities of approximately 2.0–10.0 md; its applicability to substantially lower-permeability systems, stronger compositional mass transfer, or poorly separated oil/water CT responses remains to be independently evaluated. The proposed workflow provides a practical approach for quantitative three-phase saturation characterization under conventional single-energy CT conditions.

Wettability alteration is a key mechanism in chemical enhanced oil recovery (C-EOR) because it controls capillary pressure, fluid distribution, residual-oil mobilization, and multiphase flow pathways in porous media. In most chemical-flooding designs, adsorption on reservoir rocks is treated as an unfavorable loss because it reduces the effective concentration of injected agents. However, increasing evidence shows that when adsorption occurs at appropriate interfacial locations and remains stable during flow, it can modify surface energy, adjust oil–water–rock contacts, and change how fluids occupy and transport through pore networks. This review explores adsorption-induced wettability alteration as an interfacial process that links chemical retention with displacement response. It begins with the initial wetting state of reservoir rocks, which is controlled by mineral surface chemistry, adsorbed polar crude-oil components, organic matter, brine ions, and water-film stability. It then compares how different chemical agents alter oil–water–rock interfaces through distinct adsorption modes and evaluates characterization and modeling methods according to whether they quantify adsorption, locate interfacial reconstruction, and connect wettability alteration with dynamic flow behavior. Two EOR pathways are emphasized: microscopic oil mobilization, where adsorption-induced changes in interfacial energy, capillary pressure, and oil–rock adhesion promote oil-film detachment, capillary desaturation, and residual-oil mobilization; and sweep improvement, where adsorption layers, hydration layers, particle deposition, structural disjoining pressure, or disproportionate permeability reduction modify local flow resistance and redistribute injected fluids. Finally, the review distinguishes functional adsorption from excessive adsorption according to adsorption location, persistence under flow, measurable interfacial or flow-regulation benefits, and low-damage performance.