Surfactants play a crucial role in tertiary oil recovery by reducing the interfacial tension between immiscible phases, altering surface wettability, and improving foam film stability. Oil reservoirs have high temperatures and high pressures, making it difficult and hazardous to conduct lab experiments. In this context, molecular dynamics (MD) simulation is a valuable tool for complementing experiments. It can effectively study the microscopic behaviors (such as diffusion, adsorption, and aggregation) of the surfactant molecules in the pore fluids and predict the thermodynamics and kinetics of these systems with a high degree of accuracy. MD simulation also overcomes the limitations of traditional experiments, which often lack the necessary temporal–spatial resolution. Comparing simulated results with experimental data can provide a comprehensive explanation from a microscopic standpoint. This article reviews the state-of-the-art MD simulations of surfactant adsorption and resulting interfacial properties at gas/oil–water interfaces. Initially, the article discusses interfacial properties and methods for evaluating surfactant-formed monolayers, considering variations in interfacial concentration, molecular structure of the surfactants, and synergistic effect of surfactant mixtures. Then, it covers methods for characterizing microstructure at various interfaces and the evolution process of the monolayers’ packing state as a function of interfacial concentration and the surfactants’ molecular structure. Next, it examines the interactions between surfactants and the aqueous phase, focusing on headgroup solvation and counterion condensation. Finally, it analyzes the influence of hydrophobic phase molecular composition on interactions between surfactants and the hydrophobic phase. This review deepened our understanding of the micro-level mechanisms of oil displacement by surfactants and is beneficial for screening and designing surfactants for oil field applications.

CO₂ fracturing is a promising technology for oil field development in tight, continental deposits, with potential advantages of enhanced oil recovery (EOR), CO₂ sequestration, and water conservation. Compared with CO₂-EOR techniques, such as CO₂ huff and puff and CO₂ flooding, CO₂ can interact with reservoir rock and fluid under higher pressure conditions during fracturing, resulting in CO₂ stimulation and sequestration effects that differ from those that occur during conventional CO₂-EOR. In this paper, the CO₂ interactions between CO₂ and reservoirs in continental tight oil reservoirs under fracturing conditions are systematically studied through laboratory experiments. The results show that under high pressure, CO₂ effectively changes the pore structure through the extraction of hydrocarbons, dissolution of the rock matrix, and migration of minerals. CO₂ dissolution of the rock matrix can significantly increase the number and complexity of fractures. Furthermore, CO₂ has a higher solubility in formation fluid under high-pressure conditions. Given the higher pressures, CO₂ forms a miscible phase with crude oil, diffuses more deeply into the formation, and reacts fully with the reservoir minerals and fluid during CO₂ fracturing. Accordingly, CO₂ can improve the permeability of the reservoir and flowability of crude oil significantly. Hence, CO₂ fracturing can enhance oil recovery and CO₂ sequestration more effectively. Core displacement experiments indicate that oil recovery of CO₂ soaking process after CO₂ fracturing is 36%, which is 12% and 9% higher than those of CO₂ huff and puff and CO₂ flooding with 5 pore volume, respectively. Field tests show that average oil production after CO₂ fracturing is 1.42 times higher than that after CO₂ flooding, which further validates the advantage of CO₂ fracturing and demonstrates its huge application potential.