Nonionic–anionic surfactants are expected to be applied in chemical flooding due to their important properties such as ultralow IFT values, good salt tolerance, and no chromatographic separation in porous media. In this study, a new type of nonionic–anionic–hydrophobic group structure surfactant N, N-dihydroxyethylalkylamide carboxylate (EAMC) was synthesized. The synergistic effects between petroleum sulfonate (KPS) and EAMC in reducing interfacial tension (IFT) and emulsification properties were studied. The influences of salt, alkali and Ca²⁺ on the IFTs of surfactant solutions were also investigated. One-dimensional core flooding experiments were used to characterize the enhanced oil recovery capability of the KPS and EAMC mixed system. The experimental results show that both EAMC and KPS have high interfacial activity and can reduce IFTs to about 0.01 mN/m order of magnitude against decane at optimized concentrations. The area occupied by the hydrophilic group of EAMC on the interface is smaller than that of its own hydrophobic group. The interfacial film formed by EAMC alone is relatively loose. The IFTs of KPS containing different structure petroleum sulfonates is affected by the difference in the adsorption rate of petroleum sulfonates on the interface, which shows that both the dynamic and equilibrium interfacial tensions can have the lowest values. However, the IFTs of the EAMC solutions against crude oil can be reduced to ultralow values because the mixed tight adsorption film is formed by EAMC and crude oil fraction molecules with synergistic effect. On the other hand, the KPS molecule has a hydrophobic part with large size and no synergism with crude oil fractions can be observed in the solutions containing only KPS. The combination of EAMC and KPS shows synergistic effect, namely ultralow IFT values, good emulsification properties, high alkali tolerance, and good salt and Ca²⁺ tolerance during a wide percentage range of EAMC. The best formula of EAMC and KPS system can be applied for EOR after polymer flooding. The studies in this paper are helpful for the design and application of a chemical flooding formula with nonionic–anionic–hydrophobic group structure surfactants.

Betaine is a new surfactant with good application prospects in high-temperature and high-salinity reservoirs. The interfacial properties of two kinds of betaine mixtures with a good synergistic effect were evaluated in this paper. On this basis, the effects of temperature-resistant, salt-resistant polymers with different contents of 2-acrylamide-2-methylpropanesulfonic acid (AMPS) on dynamic interfacial tensions (IFTs) against n-alkanes and crude oil were studied. The experimental results show that the IFTs between betaine ASB and n-alkanes can be reduced to ultra-low values by compounding with anionic surfactant petroleum sulfonate (PS) and extended anionic surfactant alkoxyethylene carboxylate (AEC), respectively. ASB@AEC is very oil-soluble with n_min value ≥14, and ASB@PS is relatively water-soluble with n_min value of 10. The water solubility of both ASB@PS and ASB@AEC is enhanced by the addition of water-soluble polymers. The HLB of the ASB@AEC solution becomes better against crude oil after the addition of polymers, and the IFT decreases to an ultra-low value as a result. On the contrary, the antagonistic effect in reducing the IFT can be observed for ASB@PS in the same case. In a word, polymers affect the IFTs of surfactant solutions by regulating the HLB.

The compound surfactant system has considerable development prospects for improving oil recovery. A synergistic effect can be achieved through the orderly arrangement of the two surfactants on the interface, which can make up for the performance defects of a single surfactant. In this paper, the effects of the number of propylene oxides (PO) in composite surfactants on interfacial tension and emulsion stability were systematically studied. The results showed that the solubility of composite surfactants was significantly improved under high-salinity conditions by adding anionic–nonionic surfactants to a single anionic surfactant. The interfacial tension of composite surfactants shows a V-shaped change of first decreasing and then increasing with the increase in PO groups. As the number of PO groups increases, the emulsion first increases and then decreases. Among the series of composite surfactants, LBAS/C₁₂PO₁₀S has the lowest interfacial tension, reaching the order of 10⁻³ mN/m, and the emulsion formed by it exhibits superior stability. This indicates that the synergistic effect of the two surfactants can be improved by adjusting the number of PO groups. Furthermore, the LBAS/C₁₂PO₁₀S composite system can be mixed with crude oil to form Winsor III microemulsion, which has great potential for application in enhanced oil recovery via chemical flooding.

This study aims to investigate the interfacial tension, emulsion stability, and the impact on oil displacement effectiveness of mixed systems containing nonionic surfactants and amphoteric surfactants at different ratios. To achieve this, three different emulsion stability formulations were prepared by mixing betaine and nonionic surfactants in ratios of 1:1, 3:2, and 3:1 respectively. By adjusting the proportions of betaine and nonionic surfactants, variations in interfacial tension and emulsion formation among the three mixed systems were studied to analyze the mechanism of interaction between betaine and nonionic surfactants and evaluate their effects on crude oil displacement and enhanced oil recovery in reservoirs. Subsequently, microscopic and macroscopic oil displacement experiments were conducted on the three mixed systems, along with experiments on emulsion flow resistance. The aim was to verify the oil displacement effectiveness of different mixed systems and further understand their potential applications in reservoirs. By comprehensively analyzing the experimental results, optimal ratios and conditions for the mixed systems were determined. The experimental results indicate that the emulsification system formed by mixing betaine and nonionic surfactants at a ratio of 3:1 achieves molecular synergies through electrostatic interactions and mixed adsorption with betaine, resulting in a compact arrangement of interface membranes and demonstrating a synergistic effect in reducing interfacial tension to an ultra-low value of 10 -4 mN/m. Additionally, as the proportion of betaine surfactant increases, the viscosity of the aqueous phase liquid film increases, the rate of thinning of the liquid film slows down, the rate of water release slows down, and the stability of the emulsion increases. Microscopic oil displacement experiments verified that the three mixed systems increase oil washing efficiency through low interfacial tension and emulsification stripping action, thereby increasing the oil displacement mechanism's coefficient. Emulsion flow resistance experiments demonstrated that as the proportion of betaine surfactant increases, the system exhibits better plugging ability. However, macroscopic oil displacement experiments revealed differences in compatibility between different emulsion stability solutions and rocks with different permeabilities. The mixed system of betaine and nonionic surfactants at a ratio of 3:1 exhibits the best emulsification plugging ability in rocks with a permeability of 109mD, while the 1:1 mixed system performs best in rocks with a permeability of 12mD. This holds significant theoretical and practical significance for reservoir development and enhanced production.

With the continuous decline in easily recoverable reserves of conventional oil and gas, the focus of oil and gas exploration and development has gradually shifted toward complex reservoirs, such as low-permeability, tight, high-temperature and high-pressure (HTHP), and strongly heterogeneous reservoirs. Such reservoirs are characterized by complex pore–throat structures, poor seepage capacity, extreme temperature and pressure conditions, and strong heterogeneity. Traditional acidizing technologies face multiple challenges, including short effective penetration distances, system instability at high temperatures, uneven stimulation, and a tendency to induce secondary formation damage, making it difficult to meet the requirements for highly efficient reservoir stimulation. This paper systematically analyzes the petrophysical properties and acidizing challenges of four typical types of complex reservoirs. It reviews the reaction mechanisms, research and development progress, and reservoir adaptability principles of six acid systems, and elaborates on the application value of molecular simulation technology in acid–rock reaction analysis, formulation optimization, and injection regulation. The review indicates that, under extreme operating conditions, existing technologies still suffer from inadequate system stability, limited deep mass transfer, and environmental concerns. Future research should deepen the understanding of multi-scale acid–rock reaction mechanisms, develop composite acid systems tolerant to extreme conditions, and drive the development of acidizing technologies toward refinement and intelligentization.