Micro visualization has become an important means of solving colloid and interface scientific problems in enhanced oil recovery. It can establish a relationship between a series of performance evaluations of an oil-water interface under macroscopic dimensions and the actual application effect in confined space, and more truly and reliably reflect the starting and migration behavior of crude oil or emulsion in rock pores. In this article, zwitterionic surfactant alkyl sulfobetaine (ASB) and anionic extended surfactant alkyl polyoxypropylene sulfate (A145) were employed as flooding surfactants. The macroscopic properties of the surfactant solutions, such as the oil-water interfacial tension (IFT), the interfacial dilational rheology and the viscosity of crude oil emulsions, have been measured. At the same time, we link these parameters with the oil displacement effect in several visual glass models and confirm the main factors affecting the migration ability of emulsions in micro-scale pores. The experimental results show that ASB reduces the IFT through mixed adsorption with crude oil fractions. The flat arrangement of the large hydrophilic group of ASB molecules enhances the interactions between the surfactant molecules on the oil-water interface. Compared with sulfate, betaine has higher interfacial membrane strength and emulsion viscosity. A145 has a strong ability to reduce the IFT against crude oil because of the larger size effect of the PO chains at the oil side of the interface. However, the membrane strength of A145 is moderate and the emulsion does not show a viscosity-increasing effect. During the displacement process, the deformation ability of the front emulsions or oil banks is the main controlling factor of the displacement efficiency, which is determined by the membrane strength and emulsion viscosity. The strong interfacial membrane strength and the high emulsion viscosity are not conducive to the migration of droplets in pore throats and may result in low displacement efficiency.

In enhanced oil recovery (EOR), various processes have specific requirements concerning surfactant surface activity. High surface activity is essential during the oil production, whereas low or even negligible surface activity is required during the oil separation process. CO₂-responsive surfactants can regulate their surface activity through the addition or removal of CO₂ in their aqueous solutions. This property makes them suitable for the formulation of CO₂-responsive displacement systems, including CO₂-responsive foam, emulsion, and hydrogel systems. These three systems hold significant application value within the realm of enhanced oil recovery. This paper reviews the structure, types, synthesis methods, applications in EOR technology, and the effects of EOR in both field and laboratory settings. This method is both environmentally friendly and efficient for enhancing oil recovery. Furthermore, the application of CO₂-responsive surfactants facilitates carbon capture, utilization, and storage, contributing to the achievement of carbon neutrality and the carbon peak.

Three amphiphilic peptides with varied molecular hydrophobicity, charge number and charge location have been designed as regulators to modulate the crystal growth of zeolitic imidazolate framework-8 (ZIF-8). All three peptides can interact with ZIF-8 to inhibit {100} facet growth and produce truncated cubic crystals. The peptide’s molecular hydrophobicity plays a dominant role in defining the final morphology and size of the ZIF-8 crystals. The peptides with less charge and higher hydrophobicity can promote nuclei formation and crystal growth to give smaller ZIF-8 crystals. However, the charge located in the center of the molecular hydrophobic region has little effect on the crystal nucleation and growth due to the shielding of its charge by molecular aggregation. The study provides insights into the effect of molecular charge and hydrophobicity on ZIF-8 crystal growth and is helpful for guiding the molecular design for regulating the synthesis of metal-organic framework materials.

Surfactant aggregates have long been considered as a tool to improve drug delivery and have been widely used in medical products. The pH-responsive aggregation behavior in anionic gemini surfactant 1,3-bis(N-dodecyl-N-propanesulfonate sodium)-propane (C₁₂C₃C₁₂(SO₃)₂) and its mixture with a cationic monomeric surfactant cetyltrimethylammonium bromide (CTAB) have been investigated. The spherical-to-wormlike micelle transition was successfully realized in C₁₂C₃C₁₂(SO₃)₂ through decreasing the pH, while the rheological properties were perfectly enhanced for the formation of wormlike micelles. Especially at 140 mM and pH 6.7, the mixture showed high viscoelasticity, and the maximum of the zero-shear viscosity reached 1530 Pa·s. Acting as a sulfobetaine zwitterionic gemini surfactant, the electrostatic attraction, the hydrogen bond and the short spacer of C₁₂C₃C₁₂(SO₃)₂ molecules were all responsible for the significant micellar growth. Upon adding CTAB, the similar transition could also be realized at a low pH, and the further transformation to branched micelles occurred by adjusting the total concentration. Although the mixtures did not approach the viscosity maximum appearing in the C₁₂C₃C₁₂(SO₃)₂ solution, CTAB addition is more favorable for viscosity enhancement in the wormlike-micelle region. The weakened charges of the headgroups in a catanionic mixed system minimizes the micellar spontaneous curvature and enhances the intermolecular hydrogen-bonding interaction between C₁₂C₃C₁₂(SO₃)₂, facilitating the formation of a viscous solution, which would greatly induce entanglement and even the fusion of wormlike micelles, thus resulting in branched microstructures and a decline of viscosity.

This study presents a tailored nitrogen foam flooding system developed for the Mu146 block’s medium-high permeability reservoir conditions. Through systematic optimization, we establish an optimal formulation comprising 0.40% FP2398 foaming agent and 0.13% WP2366 stabilizer. The formulated foam demonstrates superior performance characteristics with a generated volume of 850 mL and extended stability duration of 1390 s, exhibiting exceptional structural integrity under oil-bearing conditions. Core flooding experiments conducted on berea cores reveal a 33.20% incremental oil recovery factor following waterflooding that achieves 53.60% primary recovery. The non-steady-state nitrogen foam huff-and-puff (NSSNFHF) field test at Well Mu146-61 shows significant reservoir response, with post-treatment analyses indicating an average chloride ion concentration increase of 540.20 mg/L and total salinity elevation of 1194.20 mg/L across five monitoring wells. These chemical signatures confirm effective volumetric sweep enhancement through the NSSNFHF field test, demonstrating a flooding-like mechanism that mobilizes bypassed oil in previously unswept zones. The field test encompassing Well Mu146-61 and four offset producers yield substantial production improvements, including a 74.55% increase in fluid production rates and a sustained oil yield of 1.80 tons per day. The validity period of the NSSNFHF field test is more than 12 months. The technology demonstrates dual functionality in conformance control and enhanced recovery, effectively improving both oil productivity and ultimate recovery factors.

Tight oil reservoirs are widely recognized as a critical successor in global unconventional energy development and are generally characterized by distinct geological features, including fine pore throats, pronounced heterogeneity, and a high concentration of clay minerals (e.g., montmorillonite and mixed-layer illite/smectite). Severe hydration, swelling, and fines migration are readily induced during water injection or conventional water-based fluid operations, thereby resulting in irreversible impairment of reservoir permeability. Despite the excellent injectivity and capacity for viscosity reduction associated with CO₂ flooding, sweep efficiency is severely compromised by viscous fingering and gas channeling, which are induced by the inherent low viscosity of the gas. While CO₂ foam technology is widely acknowledged as a pivotal solution for addressing mobility control challenges, its implementation is hindered by a primary technical bottleneck: the incompatibility between traditional water-based foam systems and strongly water-sensitive reservoirs. A dual challenge comprising water injectivity constraints and gas channeling is presented by strongly water-sensitive tight oil reservoirs. To address these impediments, three emerging low-damage CO₂ foam systems are critically evaluated in this review. First, the synergistic mechanisms of novel quaternary ammonium salts and polymers in inhibiting clay hydration and enhancing foam stability within modified water-based systems are elucidated. Next, the physical isolation strategy of substituting the water phase with a non-aqueous phase (oil/organic solvent) in organic emulsion systems is analyzed, highlighting advantages in wettability alteration and the mitigation of water blocking. Finally, the prospect of waterless operations using CO₂-soluble foam systems—wherein supercritical CO₂ is utilized as a surfactant carrier to generate foam or viscosify fluids via in situ formation water—is discussed. It is revealed by comparative analysis that: (1) Modified water-based systems are identified as the most economically viable option for reservoirs with moderate water sensitivity, wherein cationic stabilizers are utilized to inhibit hydration; (2) Superior wettability alteration and the elimination of aqueous phase damage are provided by organic emulsion systems, rendering them ideal for ultra-sensitive, high-value reservoirs, despite higher solvent costs; (3) CO₂-soluble systems are recognized as the future direction for “waterless” flooding, specifically tailored for ultra-tight formations (<0.1 mD) where injectivity is critical. Current challenges, such as surfactant solubility, high-temperature stability, and cost control, are identified through a comparative analysis of these three systems with respect to structure-activity relationships, rheological properties, damage control capabilities, and economic feasibility. What is more, an outlook is provided on the molecular design of future environmentally sustainable, cost-effective CO₂-philic materials and smart injection strategies. Consequently, theoretical foundations and technical support are established for the efficient exploitation of strongly water-sensitive tight oil reservoirs. By bridging the gap between reservoir damage control and mobility enhancement, this study identifies viable strategies for enhanced oil recovery. Crucially, it supports carbon neutrality and sustainable energy targets via CCUS integration.