Channeling control remains the most critical challenge in fluid injection for enhanced oil recovery (EOR). Polymer gels are widely applied in channeling control due to their capability to alter the permeability of flow channels. However, high temperature and high salinity lead to low efficiency of gels, causing injected fluid to flow away through high-permeability channels and thereby hindering petroleum production. To address this, this study developed and applied a new gel, synergistically combining a tailored temperature-/salt-resistant co-polymer with an optimized cross-linker. Laboratory evaluation experiments demonstrated that this gel could resist high temperature (>130 °C) and high salinity (>20 × 104 mg/L), exhibit remarkable stability (gel dehydration rate <20% after 100 days aging), and achieve a plugging rate exceeding 98%. A pilot field case, designed based on laboratory outcomes, was successfully implemented in the Gasikule Block of the Qinghai Oilfield. The field validation indicated that this advanced gel system effectively restored reservoir pressure, thereby establishing critical prerequisites for subsequent EOR operations. This study advances the application of polymer gels in channeling control, demonstrating their superior performance and broad perspective in enhancing channeling control.

An advanced enhanced oil recovery (EOR) method was investigated, employing a surfactant–polymer (SP) system in combination with a viscosity reducer for application in a heavy oil reservoir within the Haiwaihe Block, Liaohe Oilfield, in China. Significant advantages were observed through the combination of LPS-3 (an anionic surfactant) and OAB (a betaine surfactant) in reducing interfacial tension and enhancing emulsion stability, with the optimal results achieved at the ratio of 9:1. The BRH-325 polymer was found to exhibit superior viscosity enhancement, temperature resistance, and long-term stability. Graphene nanowedges were utilized as a viscosity reducer, leading to a viscosity reduction in heavy oil of 97.43%, while stability was maintained over a two-hour period. The efficacy of the combined system was validated through core flooding experiments, resulting in a recovery efficiency improvement of up to 32.7%. It is suggested that the integration of viscosity reduction and SP flooding could serve as a promising approach for improving recovery in mature heavy oil reservoirs, supporting a transition toward environmentally sustainable, non-thermal recovery methods.

CO2-responsive switchable microemulsions have attracted significant attention due to their substantial potential in organic synthesis, drug delivery, and nanomaterial preparation. This study presents a microemulsion system composed of N '-dodecyl-N,N-dimethyl acetamidine, 1-hexanol, brine, and tetradecane. The phase behavior of the microemulsion system was systematically investigated through a salinity scan to access its salinity dependence, while the solubilization ratios were also evaluated. Furthermore, the microstructural characteristics of the microemulsion system were examined using dynamic light scattering, small-angle X-ray scattering, and interfacial tension measurements. A transition from Winsor I to Winsor III, and subsequently to Winsor II, was observed in the alkyl acetamidine surfactant-based microemulsion as salinity increased, with the smallest domain size and most ordered microstructure occurring near the optimal salinity. Notably, the three-phase microemulsion system demonstrated the ability to reversibly switch between emulsification and demulsification upon CO2 or N-2 injection, showcasing its dynamic responsiveness. This study enhances the understanding of CO2-responsive microemulsions and offers potential pathways for sustainable chemical processes.

In the petroleum and petrochemical industries, oil sludge is a common contaminant that causes environmental pollution and resource wastage. Currently, recovering crude oil from oily sludge presents a significant challenge during processing. In this study, an amidinium bicarbonate‐based CO 2 ‐responsive microemulsion was developed to effectively treat sludge and recover crude oil. The microemulsion system demonstrates a strong capability for oil solubilization. After the microemulsion treatment, the residual oil contents in the sludge can be reduced to as low as 2.93% (ME‐1, n‐butanol as cosurfactant) and 1.44% (ME‐2, n‐hexanol as cosurfactant). Complete oil/water phase separation can be achieved by introducing N 2 at 65°C.

Dodecyl dimethyl benzyl ammonium (DDBA) is a novel cation surfactant used to modify clay minerals. DDBA-intercalated montmorillonite is formed by the ion exchange between DDBA cations in the solution and cations in the montmorillonite interlayers. By using molecular dynamics simulations, we investigated the basal spacings, interlayer structures and dynamics of DDBA-montmorillonites. The results showed that the calculated basal spacings agreed well with experimental values and that the layering behaviours of DDBA had been revealed. The ammonium groups of DDBA ions preferred staying close to the centre of Si-O six-member rings. The benzyl group and lauryl group were oriented in parallel in the monolayer state, whereas they were tilted in other states. DDBA ions have very low mobility in the interlayer region, indicating that the negatively charged montmorillonite surfaces can effectively fix this positively charged surfactant. The microscopic structures and dynamics obtained in the present study provide atomic-scale insights into the properties of DDBA-intercalated clay minerals.

Paraquat, one of the most widely utilized herbicides globally, causes a significant environmental challenge due to its poor degradation rate and tendency to adsorb into clay interlayers. Several remediation methods have been proposed but their effectiveness remains suboptimal. The primary reason for this is the lack of microscopic understanding of paraquat-montmorillonite interactions. In this work molecular dynamics simulations were applied to study the interlayer structures and mobility of paraquat intercalated montmorillonite. Two stable hydration states were identified from the calculated immersion energy curve, which corresponded to a water content of 185 mgwater/gclay and 278 mgwater/gclay (the most stable). Paraquats remained in direct contact with the clay surface in both the anhydrous and hydrated states. At the water content of 185 mgwater/gclay, paraquats formed pi-pi stacking while at 278 mgwater/gclay, they were separated by a layer of water. Paraquat showed very small self-diffusion coefficients in the interlayer space of montmorillonite, indicating rather limited motions. The results in this work provide a basis for a better understanding of the interaction of paraquat with clay minerals.

CO2-responsive 2-responsive surfactants are a promising technology with potential applications in various fields. Therefore, the design of their formulations must be carefully considered to ensure their effectiveness in each specific application. Herein, we employed molecular dynamics simulations to investigate an oil/water (O/W) interface stabilized by a surfactant mixture containing a CO2-responsive 2-responsive cationic primary surfactant and another co- surfactant. It has been discovered that formulating the CO2-responsive 2-responsive cationic surfactant with a typical anionic surfactant (sodium dodecyl sulfate, SDS) can lead to a distinct CO2-responsive 2-responsive mechanism of the surfactant mixture. To compare, the CO2-responsive 2-responsive mechanism remains unchanged if the CO2-responsive 2-responsive cationic surfactant is formulated with a typical cationic surfactant (dodecyl trimethylammonium bromide, DTAB). A nonionic co-surfactant can enhance the interface activity of the surfactant mixture but the synergistic effect is not strong enough to lead to a different CO2-responsive 2-responsive mechanism. The distinct phase behavior between two surfactant mixtures suggests that the CO2-responsive 2-responsive mechanism is dominated by the type of surfactants formulated with the CO2-switchable 2-switchable surfactant.

The Gasi reservoir in the Qinghai oilfield is a typical high-temperature and high-salinity reservoir, with an average temperature and average salinity of 70.0 °C and 152,144 mg/L, respectively. For over 30 years since 1990, water flooding has been the primary method for enhancing oil recovery. Recently, the Gasi reservoir has turned into a mature oilfield. It possesses a high water cut of 76% and a high total recovery rate of 47%. However, the main developing enhanced oil recovery (EOR) technology for the development of the Gasi reservoir in the next stage is yet to be determined. Surfactant–polymer (SP) flooding, which can reduce the oil–water interfacial tension and increase the viscosity of the water phase, has been widely applied to low-temperature and low-salinity reservoirs across China in the past few decades, but it has rarely been applied to high-temperature and high-salinity reservoirs such as the Gasi reservoir. In this study, the feasibility of SP flooding for high-temperature and high-salinity reservoirs was established. Thanks to the novel surfactant and polymer products, an SP flooding formula with surfactants ZC-2/B2 and polymer BRH-325 was proposed for Gasi. The formula showed a low interfacial tension of 10−2 mN/m and a high viscosity of 18 MPa·s in simulated reservoir conditions. The oil displacement experiment demonstrated that this formula can enhance the oil recovery rate by 26.95% upon water flooding at 64.64%. This study provides a feasible EOR candidate technology for high-temperature and high-salinity reservoirs, as exemplified by the Qinghai Gasi reservoir.

The oil-water distribution is essential for evaluating the oil displacement effect and development potential during flooding in high temperature and high salt reservoir. Low-field nuclear magnetic relaxometry(NMR) T1-T2 maps is one of the methods for analyzing oil- water distribution. In order to analysis oil-water distribution at different displacement stage, two-dimension NMR T1-T2 map, and oil-water two-phase displacement experiments were employed on sandstone samples and oil collected in Gasi Reservoir, Qinghai Oilfield. Combining NMR and core displacement results data analysis, the reason for whether oil is produced and the entire flow process of oil and water in the displacement experiments were explained, distribution characteristics of oil and water in the NMR T1-T2 map were analyzed, and evaluate the crude oil production characteristics during the flooding. The results indicated that the pore structure of the sandstone samples is single and show weak heterogeneity according to the NMR T2 spectrum, and the distribution of sandstone pore size is the main factor determining whether there is oil in the sandstone core in the displacement experiment. NMR T1-T2 map is an effective way to identify different components (oil and water) of sandstone samples and the oil-water distribution, and Hydrogen signal distribution regions of oil and water changed after the oil and the brine of 152144 mg/L injected into the sandstone core successively, and the recovery rate increased by approximately 71.3

Chemical flooding methods are used to recover the remaining oil after water flooding, and surfactant-polymer (SP) flooding is an important chemical flooding technology. It is of great significance to design and screen high-performance oil displacement agents in order to overcome the increasingly challenging high temperature (>70 ℃) and high salinity (>10,000 mg/L) reservoirs. Based on the characteristics of high temperature (70 ℃) and high salinity (151,000 mg/L) in the Qinghai Gasi reservoir, the performance of the SP flooding system was studied. This study considered interfacial tension, emulsification, viscosity, compatibility, and oil displacement efficiency. The selected formula demonstrated high resistance to both salinity (151,000 mg/L) and temperature (70 ℃), characterized by a low oil-water interfacial tension (10-2 mN/m) and high viscosity (18.13 mPa.s). After water flooding achieved an oil recovery rate of 64.64%, the subsequent replacement rate of crude oil increased by 26.95%, confirming that SP flooding can be used as a technology for enhancing oil recovery in high-temperature, high-salinity reservoirs represented by Qinghai Gasi reservoirs.

CO2-responsive surfactants are a promising technology with potential applications in various fields. Therefore, the design of their formulations must be carefully considered to ensure their effectiveness in each specific application. Herein, we employed molecular dynamics simulations to investigate an oil/water (O/W) interface stabilized by a surfactant mixture containing a CO2-responsive cationic primary surfactant and another co-surfactant. It has been discovered that formulating the CO2-responsive cationic surfactant with a typical anionic surfactant (sodium dodecyl sulfate, SDS) can lead to a distinct CO2-responsive mechanism of the surfactant mixture. To compare, the CO2-responsive mechanism remains unchanged if the CO2-responsive cationic surfactant is formulated with a typical cationic surfactant (dodecyl trimethylammonium bromide, DTAB). A nonionic co-surfactant can enhance the interface activity of the surfactant mixture but the synergistic effect is not strong enough to lead to a different CO2-responsive mechanism. The distinct phase behavior between two surfactant mixtures suggests that the CO2-responsive mechanism is dominated by the type of surfactants formulated with the CO2-switchable surfactant.

The flow of two immiscible liquids in porous media can lead to fluid mixing, resulting in emulsions-where one phase is dispersed as droplets in the other. In reservoir rocks, natural surfactants and polar molecules, like asphaltenes, can promote oil-water emulsion formation. During chemically enhanced oil recovery processes (CEOR) such as surfactant, alkali, or surfactant-alkali flooding, in-situ emulsification is often seen as key to enhancing frontal stability and facilitating the piston-like displacement of oil by water. However, this work reports a minimal effect of in-situ emulsification on oil production during surfactant-polymer (SP) flooding. Experimental studies show this by injecting prepared emulsions into a multi pressure-tap core holder and examining emulsion formation in one reservoir core before moving it into a second core for oil displacement. This helps us understand the specific role of emulsions in oil mobilization. Factors like surfactant concentration, interfacial tension, and the timing of introducing the surfactant-polymer solution do influence the intensity of insitu emulsification. Yet, the incremental oil recoveries show no significant differences. Through similar experiments, it is observed that ultra-low interfacial tension (IFT) in our surfactant-polymer system is the primary mechanism for oil mobilization. The slight increase in pressures suggests that in-situ emulsification has a limited role in increasing flow resistance during the ultra-low IFT SP flood process, potentially not improving the swept volume. This research can guide the development of systematic approaches to analyze the effects of in-situ emulsification on oil mobilization and evaluate chemical flooding processes.

Heavy oil extraction is a challenging and energy-intensive process. Herein, Ti3AlC2 was etched to obtain nanosheet layer Ti3C2Tx MXene, which was then carboxylated and poly(ethylene glycol) (PEG)-grafted to obtain Ti3C2Tx-COOH-g-PEG to increase viscosity for stabilizing SDBS emulsions. Morphological analysis confirmed the formation of a nanosheet layer structure, and structural analysis confirmed PEG grafting (21.50%). Crossover emulsification experiments demonstrated that Ti3C2Tx-COOH-g-PEG at 0.3 mg/mL exhibited excellent resistance to mineralization, high temperatures, and elevated pH levels. Ti3C2Tx-COOH-g-PEG improved the surfactant solubility under high mineralization conditions and reduced solution corrosiveness. Emulsion displacement tests proved the effectiveness of Ti3C2Tx-COOH-g-PEG in enhancing the heavy oil recovery by 25.07%. Therefore, Ti3C2Tx-COOH-g-PEG is an ideal emulsion stabilizer, offering substantial improvements in emulsification for enhancing oil recovery.

This comprehensive study delves into an application of surfactant flooding as a robust enhanced oil recovery (EOR) technique, incorporating both core-scale experiments and reservoir-scale numerical simulations. The research's focal point is to evaluate a novel surfactant's performance in extending oil recovery efficiency within an oil reservoir. The study commences with thorough laboratory experiments at the core scale, illuminating the interplay of fluids within porous media. Transitioning seamlessly to reservoir-scale numerical modeling, the research replicates real-world reservoir conditions. Various well configurations are scrutinized to optimize surfactant flooding strategies for EOR purposes. A key aspect of this analysis is the in-depth examination of the sensitivity of numerical simulations to changes in relative permeability curves during surfactant injection, enabling a robust assessment of the performance of surfactant injection in a broad spectrum of uncertainties. Comparative experiments elucidated the significant influence of a surfactant molecular structure, with aliphatic variants showcasing superior oil displacement efficiency. Moreover, combining surfactant and polymer proved pivotal, enhancing reservoir sweep efficiency and significantly boosting oil recovery. This work establishes a comprehensive framework for evaluating chemical flooding, including surfactant and polymer, as a potent EOR method by bridging the gap between core-scale experiments and reservoir-scale simulations.

This study aims to investigate the impacts of a surfactant structure, surfactant concentration, and salt content on switchable emulsification processes through molecular dynamics (MD) simulations. Specifically, we focus on assessing the properties and behaviors of water/tetradecane systems containing CO2-switchable acetamidine surfactant N’-dodecyl-N, N-dimethylacetamidine (C12DMAA) and C18 naphthalene sulfonate (C18PS), both of which are relevant to enhanced oil recovery processes. Utilizing MD simulations, we comprehensively explore the influence of the molecular composition of switchable surfactants, salinity, and surfactant concentration on the reversible processes of emulsification and demulsification in a complex oil/water/C18PS/C12DMAA system. This system can be activated through the injection of CO2 or N2 gas. Various analyses, including molecule mobility, hydration behavior, void volume analysis, a solvent accessible surface area (SASA), a diffusion coefficient, and relative concentration profiles, are employed to gain insights into the emulsification and demulsification processes. Our study reveals that lower surfactant concentrations result in the formation of partial emulsions, while the presence of salt disrupts surfactant hydration and weakens emulsification properties. Additionally, we observe that the impact of hydrogen bonding interactions is less pronounced at lower surfactant concentrations. Furthermore, the MD simulations provided insights into the interplay of a surfactant monomer number and alkyl phenyl introduction with a solvent-accessible surface area (SASA) and a void volume. Understanding these factors is crucial for designing and optimizing emulsion systems, particularly in oil recovery processes. The findings advance our understanding of CO2/N2-switchable surfactants, offering insights into their potential for sustainable development in the petroleum industry. This research contributes to the optimization of switchable surfactants, providing a foundation for improved emulsification processes in enhanced oil recovery applications.

Amidine-based switchable surfactants, whose surface activity is enabled by protonation, are a desirable candidate for the development of enhanced oil recovery methods. However, studies on the influence of salt components on the protonation of amidine-based surfactants are still very limited. In this study, it has been found that inorganic salts can induce the protonation of amidine-based surfactants, using N’-dodecyl-N and N-dimethyl acetamidine (C12-DMAA) as an example. The feasibility predictions of protonation of C12-DMAA in pure water and brines were attained by quantum chemical simulation. The occurrence of partial protonation is determined by Nuclear Magnetic Resonance (NMR). In the dispersion test, variation in conductivity and pH indicated that the water molecule plays the role of proton donor in the protonation process, and the protonation level is unaffected by the presence of cationic species. Overall, this research enhances the understanding of the switchable ability, as well as the efficient utilization of amidine-based surfactants in salt-containing systems.

As a promising chemical-enhanced oil recovery method (CEOR), switchable acetamidine surfactant flooding is investigated in sandstone oil reservoirs. To describe the distributions of the injected water during the surfactant flooding, long-time and multifrequency NMR scanning was employed in combination with core displacement experiments. We found that the water saturation increased and swept volume was improved with the injection rates increasing from 0.01 to 0.5 mL/min in all pores. During water flooding, the water injection rate and distribution had a positive correlation. The water saturation increased as the surfactant concentration increased, and the water saturation and the swept volume of surfactant flooding were larger than those of the water flooding. Furthermore, the water saturation increase in migration pore (MP) was much larger than that in other pores during the switchable acetamidine surfactant flooding. As a result, the water saturation increased and the oil recovery enhanced. Our research results provided novel perspectives on switchable acetamidine surfactant flooding for enhanced oil recovery (EOR).

CO2/N2 switchable surfactants have recently attracted significant attention in enhanced oil recovery. Their environmental and economic benefits are the main driving forces for their application in the oil and gas industry. This study evaluated mixtures of sodium dodecyl sulfate (SDS), C18 naphthalene sulfonate (C18PS), and CO2-switchable acetamidine surfactant N′-dodecyl-N, N-dimethylacetamidine (C12DMAA) in water/dodecane systems by using molecular dynamics (MD) simulation. The effects of the molecular structure of anionic surfactant and surfactant concentration on switchable emulsification and demulsification in an oil/water/SDS or C18PS/C12DMAA system triggered by CO2/N2 injection were investigated. The molecule mobility, hydration behavior, density field analysis, diffusion coefficient, radial distribution functions (RDFs), and the density profiles of various systems were thoroughly examined. Based on MD simulation outputs, increasing surfactant concentration can intensify a demulsification process and create a clear phase separation between water and tetradecane. On the other hand, during an emulsification process, adding more surfactant monomers improved a hydration layer around oil droplets and increased hydrogen bonds; however, the contribution of hydrogen bonds between water and N′-dodecyl-N, N-dimethylacetamidinium (C12DMAAH+) compared to SDS and C18PS is limited. MD simulations proved the switchability of SDS/C12DMAA and C18PS/C12DMAA for emulsification and demulsification processes. The results of the current study will be beneficial for developing and optimizing the switchable surfactant structures for further use in the oil and gas industry through surfactant injection.

A comprehensive understanding of interfacial behavior in water/oil/surfactant systems is critical to evaluating the performance of emulsions in various industries, specifically in the oil and gas industry. To gain fundamental knowledge regarding this interfacial behavior, atomistic methods, e.g., molecular dynamics (MD) simulation, can be employed; however, MD simulation cannot handle phenomena that require more than a million atoms. The coarse-grained mesoscale methods were introduced to resolve this issue. One of the most effective mesoscale coarse-grained approaches for simulating colloidal systems is dissipative particle dynamics (DPD), which bridges the gap between macroscopic time and length scales and molecular-scale simulation. This work reviews the fundamentals of DPD simulation and its progress on colloids and interface systems, especially surfactant/water/oil mixtures. The effects of temperature, salt content, a water/oil ratio, a shear rate, and a type of surfactant on the interfacial behavior in water/oil/surfactant systems using DPD simulation are evaluated. In addition, the obtained results are also investigated through the lens of the chemistry of surfactants and emulsions. The outcome of this comprehensive review demonstrates the importance of DPD simulation in various processes with a focus on the colloidal and interfacial behavior of surfactants at water-oil interfaces.

The adsorption behaviours of three typical surfactants at n-dodecane-water and n-dodecane + asphaltene-water interfaces were systematically studied by atomic molecular dynamics (MD) simulation. The theoretical simulation results show that surfactants and asphaltene molecules have different synergistic effects in reducing interfacial tension. For surfactants SDBS and OP-10, the increase of interfacial concentration leads to the dissociation of asphaltene molecular aggregation structure and the further reduction of interfacial tension. However, DTAB showed the opposite effect. The increase of surfactant interfacial concentration leads to the increase of asphaltene aggregation. With the increase of surfactant interfacial concentration, the interaction between surfactant and asphaltene is not conducive to further reduce the interfacial tension.