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Polymer flooding is an effective development technology to enhance oil recovery, and it has been widely used all over the world. However, after long-term polymer flooding, a large number of oilfields have experienced a sharp decline in reservoir development efficiency. High water cut wells, serious dispersion of residual oil distribution and complex reservoir conditions all bring great challenges to enhance oil recovery. In this study, the method of enhancing oil recovery after polymer flooding was studied by taking the S Oilfield as an example. A surfactant–polymer system suitable for high-permeability heterogeneous oilfields was developed, comprising biogenic surfactants and polymers. Microscopic displacement experiments were conducted using cast thin sections from the S Oilfield, and nuclear magnetic resonance was employed for core displacement experiments. Numerical simulation experiments were also conducted on the S Oilfield. The results show that the enhanced oil recovery mechanism of the surfactant–polymer system is to adjust the flow direction, expand the swept volume, emulsify crude oil and reduce interfacial tension. Surfactant–polymer flooding proves to be effective in improving recovery efficiency, significantly reducing the time of flooding and further enhancing the strong swept area. The nuclear magnetic resonance results indicate a high amplitude of passive utilization of residual oil during the surfactant–polymer flooding stage, highlighting the enormous potential for an increased recovery ratio. Surfactant–polymer flooding emerges as a more suitable technique to enhance oil recovery in the post polymer-flooding stage in high-permeability heterogeneous oilfields. [ABSTRACT FROM AUTHOR]

This work focuses on the development of a novel high-temperature microemulsion for enhanced oil recovery in tight oil reservoirs. Microemulsions are a type of mixture that has properties of both liquids and solids; they have shown significant potential for improving oil recovery through spontaneous imbibition. Herein, a high-temperature-tolerant lower-phase microemulsion using a microemulsion dilution method was developed. The properties and morphological characteristics of the microemulsion were evaluated and proposed a mechanism for enhanced spontaneous imbibition oil recovery using imbibition tests and CT scanning technology. The results of the study showed that the optimum concentration of the microemulsion was 0.2 wt% and that it had good thermal stability, small droplet size, lower interfacial tension, good wettability alteration ability, and minimum adsorption loss. The imbibition and CT experiments demonstrated that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. The study concludes that the solubilization coefficient and self-driving force were defined and calculated to quantitatively analyze the imbibition mechanisms and the results showed that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. [ABSTRACT FROM AUTHOR]

Gas flooding and foam flooding are potential technologies for tertiary oil recovery in fractured-vuggy reservoirs. The development and mechanism research of fractured-vuggy reservoirs is difficult due to the complex structures and the strong heterogeneity of fractured-vuggy reservoirs. Visualization simulation is one of the effective methods to study the flow behavior of fluid in fractured-vuggy reservoirs. In this study, an upscaling method of visualization simulation from one dimension (1D) to three dimensions (3D) was established, and the physical models of fractured-vuggy reservoirs were designed and fabricated. Water flooding, gas flooding, and gel foam flooding were carried out in the models. The experimental results showed that gas flooding has a single flow channel and water flooding has multiple flow channels in fractures and vugs. Gel foam with an excellent capability of mobility control and a high microscopic displacement efficiency swept in all directions at a uniform velocity. The EOR mechanisms of gel foam in fractured-vuggy reservoirs were mainly as follows: reducing interfacial tension, increasing mobility ratio, selectively plugging high permeability channels, and discontinuous flow. In the displacement process of fractured-vuggy reservoirs, water should be injected from the well at the bottom of the reservoir, and gas should be injected from the well located in the vug at the high part of the reservoir. Gel foam with strong stability and high viscosity should be selected and injected in most kinds of injection wells in fractured-vuggy reservoirs. This study provides a complete method of visualization simulation for the study of flow behavior in fractured-vuggy reservoirs and provides theoretical support for the application of gas flooding and gel foam flooding in fractured-vuggy reservoirs. [ABSTRACT FROM AUTHOR]

Recently, much attention has been directed toward nanofluids' applications for enhanced oil recovery (EOR). Here, amphiphilic molybdenum disulfide (KH550-MoS2) nanosheets are synthesized using a hydrothermal approach. The physicochemical properties and EOR potential of ultralow concentration KH550-MoS2 nanofluids are systematically investigated at Changqing Oilfield (China) reservoir conditions (temperature∼55 °C and salinity∼7.8 × 104 mg/L). Interfacial tension (IFT), wettability alteration and emulsion stability are characterized to evaluate the physicochemical properties of KH550-MoS2 nanofluids. The results show that ultralow concentration KH550-MoS2 nanofluid (50 mg/L) can decrease IFT to 2.6 mN/m, change contact angle (CTA) from 131.2° to 51.7° and significantly enhance emulsion stability. Core flooding experiments are conducted to determine the dynamic adsorption loss law and oil displacement efficiency of KH550-MoS2 nanofluid. Results indicate that the cumulative produced KH550-MoS2 nanosheets ratio to total injected KH550-MoS2 nanosheets (CNR) reaches 91.5% during flooding in a low permeability reservoir. Moreover, ultralow concentration KH550-MoS2 nanofluid can increase oil displacement efficiency by 14% after water driven. This work offers a new amphiphilic nanofluid with high efficiency for EOR. [ABSTRACT FROM AUTHOR]

[Display omitted] • A dilutable single-phase microemulsion oriented toward EOR is formulated using mixed nonionic-cationic surfactants. • The microemulsion features nano-sized droplets and a broad single-phase region. • Phase transition regions and microstructures are directly observed and analyzed. • The interfacial distribution of molecules and mechanisms underlying microstructure transition are explored via MD simulation. Microemulsions demonstrate significant potential for enhancing oil recovery (EOR) owing to their remarkable abilities to reduce interfacial tension, alter wettability, and facilitate solubilization. However, the challenge remains in preparing dilutable single-phase microemulsions with large single-phase regions and tiny droplets. In this study, we developed an EOR-oriented single-phase microemulsion formulated using mixed nonionic-cationic surfactants. The system incorporated a biodegradable double-chain monosaccharide quaternary ammonium surfactant alongside a polyoxyethylene ether surfactant. D -limonene functioned as the oil phase, while propylene glycol butyl ether served as the co-surfactant. Transition regions and microstructures were revealed through conductivity tests and microscopic electron microscopy. Furthermore, the mechanisms of microstructure transition under various phase behaviors were explored by simulating the synergistic effects and interfacial distributions of mixed surfactants through molecular dynamics simulation. [ABSTRACT FROM AUTHOR]

Gemini surfactants have attracted intensive attention owning to their unique physical and chemical properties and have gradually been applied in the field of enhanced oil recovery (EOR). In this work, a combined cationic/anionic-nonionic gemini surfactant system consisting of cetyltrimethyl ammonium bromide (CTAB) and anionic-nonionic gemini surfactants (GAES-9) was proposed for EOR. The surface performance of the combined system was superior to that of either surfactant alone. Critical micelle concentration (CMC) data were used to calculate the molecular interaction parameters according to the regular solution theory. The combined CTAB/GAES-9 surfactant system could greatly affect the interfacial tension (IFT) between water and crude oil, and the strength of this effect depended on the mole fraction and concentration of CTAB/GAES-9. The system could reduce the IFT to an ultra-low level at a total concentration of 200 mg/L, and the system could still maintain ultra-low IFT at a salinity of 10 × 10 4 mg/L. The mechanism underlying the synergistic effect of CTAB/GAES-9 to obtain ultra-low IFT was systematically investigated. It is most probably related to a large number of anions and cations being adsorbed onto the oil-water interface due to electrostatic attraction. Meanwhile, the spatial structure of the elongated, flexible EO chains in the gemini surfactant entangled at the oil-water interface shields some CTAB cations, enabling the adsorption of more cations. To summarize, the combined surfactants exhibit remarkable abilities and could serve as a candidate for EOR in harsh reservoirs. [ABSTRACT FROM AUTHOR]

An acid-alternating-base (AAB) system was evaluated based on ability to generate CO 2 in a reservoir for blockage removal and oil recovery improvement. CO 2 generation processes were measured in both the containers and the porous media for comparison. Optimal CO 2 production and generating efficiency were obtained by adjusting the acid molar concentration ratio and system mass concentration. The AAB system had a good displacement efficiency in both homogeneous and heterogeneous porous media. Enhanced oil recovery (EOR) mechanisms of the acid-alternating-base (AAB) technology were then investigated. The basic solution of the AAB system can lower interfacial tension (IFT) between crude oil and displacing fluid; the CO 2 generated in formation can swell oil and reduce oil viscosity; the heat released by the acid-base reaction can dissolve organics and increase oil recovery, and the pressure fluctuation caused by CO 2 generation process and inorganic dissolution can also contribute to the improvement of oil recovery. This technology has been successfully applied in the offshore Bohai Bay Field approximately 200 km east of Beijing. [ABSTRACT FROM AUTHOR]

Alkali plays an important role in alkali/surfactant/polymer (ASP) technology. The mechanisms of alkali were reviewed in this paper and the advantages were significant. In this study, three main steps were conducted. Firstly, ethanolamine was selected from four organic alkalies (ethanolamine, diethanolamine, triethanolamine and triethylamine) by interfacial tension (IFT) tests. Then the selected organic alkali, ethanolamine, was compared with inorganic alkali (sodium carbonate) by IFT performance. The results showed that ethanolamine had low IFT like inorganic alkali and it has lower IFT than sodium carbonate when concentration was higher than 0.8%. Secondly, alkali consumption experiment was conducted to compare organic alkali and inorganic alkali. The results indicated that ethanolamine had lower consumption than inorganic alkali, which maintained the efficiency of ASP flooding. Finally, the concentrations of silicon and aluminum in solution were measured to evaluate the reservoir damage caused by alkali. The results found that ethanolamine system had the lower concentrations of silicon and aluminum than inorganic alkali, which means it caused less reservoir damage. Thus, ethanolamine may be a potential alkali which can replace inorganic alkali in ASP technology. [ABSTRACT FROM AUTHOR]

[Display omitted] • Morphology of modified MoS 2 nanosheets adsorbed at W/O interface is obtained by MD. • The stress exerted on a nanosheet is analyzed. • The non-uniform forces acting on a nanosheet result in an intersection angle. • Notable IFT decline is followed by fluctuation with increased nanosheet concentration. • Competition between interface coverage and intersection angle causes IFT fluctuation. Plate-shaped nanoparticles exhibit huge potential for a broad range of cutting-edge applications in interfacial-based science and technology, such as enhanced oil recovery in hydrocarbon reservoirs, owing to their remarkable features in superior affinity toward interfaces. Understanding the adsorption behavior of nanosheets (NSs) self-assembled at the water/oil interface (W/O interface) is crucial to elucidate the variation of interfacial tension (IFT) and establish special design criteria for efficient industrial use of NSs. Here we present a molecular dynamics study to reveal the morphology of carbon-chain modified molybdenum disulfide (MoS 2) nanosheets. The stress exerted on a nanosheet is analyzed. The simulation results demonstrate a significant decrease in interfacial tension after adding NSs to the water/oil system, followed by a noticeable fluctuation with increased NS concentration. Surprisingly, the carbon-chain modified MoS 2 nanosheets do not show a greater ability in altering IFT compared to unmodified ones. The IFT fluctuation is found strongly linked to the competition between the effects of interface coverage rate of adsorbed nanosheets and the intersection angle arising from non-uniform forces acting on a nanosheet. [ABSTRACT FROM AUTHOR]

[Display omitted] • Amphiphilic molybdenum disulfide nanosheets can self-adsorb onto the oil-water interface to form a dense interface adsorption film. • The oil-water interface adsorption film exhibits excellent elastic properties and higher strength. • The oil-water interface adsorption film can intelligently control displacement front in porous media for enhanced oil recovery. Immiscible liquid-liquid interfaces have widespread applications in drug delivery, oil-water separation, oil recovery, emulsion and foam stability, etc. Here, a dense viscoelastic interface film is constructed via the self-adsorption of amphiphilic molybdenum disulfide nanosheets at the oil-water interface, which has significant implications for enhanced oil recovery. The microscopic dispersion characteristics of amphiphilic nanosheets in water phase are characterized using Cryo-EM, and the adsorption regularities of amphiphilic nanosheets in horizontal and vertical directions of oil-water interface are also revealed. Besides the mechanical response and rheological properties of interface adsorption film are systematically studied. Experimental results demonstrate that the amphiphilic nanosheet can self-curl to form a single amphiphilic nanosheet with a size of 30 nm in the water phase as the amphiphilic nanosheets concentration is lower than 50 mg/L. When the amphiphilic nanosheets concentration reaches 100 mg/L, obvious water-phase aggregation behaviors happen. The amphiphilic nanosheets can reduce the oil-water interfacial tension from 18.47 mN/m to 0.27 mN/m by forming multilayer adsorption at the oil-water interface. The adsorption ratio of amphiphilic nanosheets from bulk phase to oil-water interface can reach 97.50 %. In addition, the oil-water interface adsorption film exhibits excellent elastic properties and higher strength because the amphiphilic nanosheets can form a planar network structure at the oil-water interface which can be also directly observed in microfluidic pores. The storage modulus and interface shear viscosity of interface adsorption film are 1.65 Pa and 1.38 mN·s/m, respectively. In theory, the required desorption energy of a single amphiphilic nanosheet from oil-water interface to bulk phase is deduced to be 587 K B T. This work is expected to provide amphiphilic molybdenum disulfide nanosheet as an effective candidate for enhanced oil recovery. [ABSTRACT FROM AUTHOR]

To improve the dispersion stability of the nanofluid, SDS/Tween 60 surfactant solution was employed as the dispersant for the Janus SiO 2 nanofluid. The compounded system showed good dispersion stability and oil displacement effect at high temperature (90 ℃) and high salinity (35000 ppm). The amphiphilic Janus SiO 2 nanoparticle was synthesized by Pickering emulsion method. Next, by introducing SDS/Tween60 surfactant system as a dispersant agent, the Janus SiO 2 nanofluid could disperse well for more than 12 h at 90 ℃ with a salinity of 35000 ppm. The surfactant-enhanced Janus SiO 2 nanofluids showed good dispersion stability in different characterization methods, including visual observation, Turbiscan stability index (TSI) and particle size. Based on the adsorption experiments, the optimal mass concentration ratio between surfactant and Janus nanoparticles was fixed at 2:1. The possible dispersion and stability mechanism of Janus SiO 2 nanoparticles was explained from the perspective of the synergistic effect, between surfactants and nanoparticles and between surfactants and surfactants. Then, interfacial tension reduction ability, emulsion stability and wettability alternation capability of surfactant-enhanced Janus SiO 2 nanofluid with various concentrations, were studied at 90 ℃ with a salinity of 35000 ppm. The surfactant-enhanced Janus SiO 2 nanofluid, with a nanoparticle concentration of 0.01 wt%, showed the best EOR performance. The current study provides a new prospective in preparing Janus SiO 2 nanofluids applied for enhanced oil recovery in high temperature and high salinity reservoirs. [Display omitted] • The anionic/non-ionic surfactant system, SDS/Tween 60 (S/T), was employed as a dispersing agent for Janus SiO 2 nanofluids. • The surfactant-enhanced Janus SiO 2 nanofluids can maintain good dispersion stability at 90 ℃ with a salinity of 35000 ppm. • Addition of the S/T surfactants helps to enhance the interfacial properties of the Janus SiO 2 nanofluids. • The surfactant-enhanced Janus SiO 2 nanoparticles with the concentration of 0.01 wt% can increase the oil recovery by 15.3%. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition has been proved to be a promising enhanced oil recovery method for tight reservoirs, but the mechanisms of spontaneous imbibition oil recovery (SIOR) are still unclear. Here, we use the self-prepared novel lower-phase nano-emulsion (LWPNE) to reveal the mechanisms. In LWPNE solution, nano-scale oil drops (NODPs) in 6 nm diameter are formed and dispersed with co-presence of micelle solubilizing N-hexane. The effects of LWPNE on both interfacial tension (IFT) and contact angle were studied at 0–10,000 mg/L salinity condition, and spontaneous imbibition efficiency was determined from imbibition experiments in Amott cells at 60 °C. Electron Microscope and Transmission Electron Microscope were used to analyze the emulsification and solubilization mechanisms of LWPNE. Experimental results show that the original 135° (oil-wet) contact angle can be reduced to 32.7° (water-wet); the IFT is decreased to 0.0038 mN/m, and electrolyte has no contribution to either IFT reduction or wettability alteration. The average oil recovery from spontaneous imbibition testing using 0.3 wt% LWPNE is 44.1%, which is 20.5% higher than that from systems at similar conditions but using brine only. The LWPNE can solubilize oil by increasing NODPs' sizes to average 36 nm in diameter, which is the dominant mechanism to improve SIOR for LWPNE. The solubility of LWPNE is evaluated by the diameter growth rate of NODPs, and once it reaches 350%, a self-driving force drives oil drops to move forward. Moreover, the transformation mechanisms of spontaneous imbibition modes from imbibition to drainage are revealed by using the imbibition discriminant parameter (N B m − 1 ). • The nano-scale oil drops (NODPs) with a size of 6 nm in diameter are formed and evenly dispersed with co-presence of micelle solubilizing N-hexane. • The emulsification and solubilization effects of NODPs are discovered to be the dominant mechanisms for spontaneous imbibition oil recovery (SIOR). • A self-driving force (pressure difference at the curved interface) is proposed to drive oil drops moving forward during the solubilization processes. [ABSTRACT FROM AUTHOR]

• A pH-responsive emulsifier composed of SDS and EAB was proposed. • The interaction strength between SDS and EAB could be adjusted by regulation of pH. • The emulsions stabilized by SDS and EAB could demulsify once 0.1M HCl was added. In order to improve the recovery of crude oil and realize rapid demulsification of produced fluid, a pH-responsive zwitterionic/anionic surfactant system was proposed. The pH-responsive zwitterionic/anionic surfactant system consists of zwitterionic surfactant EAB (erucic amide carboxylic betaine) and anionic surfactant SDS (sodium dodecyl sulfate). By adjusting the pH value, the protonation degree of EAB could be controlled. Accordingly, the interaction between surfactants in the mixed system could be strengthened or weakened in neutral environment (pH = 6–8) or acidic conditions (pH = 2–4), respectively. In consequence, transformation between the emulsification and demulsification states for the emulsions stabilized by zwitterionic/anionic surfactant system could be effectively controlled by variation of the pH values. Meanwhile, the interfacial tension, average droplet size, microstructure and stability analysis of the mixed system emulsifying at various pH values were studied. For the emulsion stabilized by the pH-responsive zwitterionic/anionic surfactant system, the droplets size was evenly distributed and the average particle size was the lowest when the molar ratio of EAB to SDS was 4:6, whilst the average particle size increased significantly once the pH value was reduced down to 2 or 3. Above all, this study provides a new approach for the development of chemical flooding agents for enhancing oil recovery. [ABSTRACT FROM AUTHOR]

Abstract: The emulsification and entrainment of crude oil into displacing water is one of the mechanisms of alkaline flooding for conventional oil. If this mechanism is applied in heavy oil reservoirs, the flow of viscous oils and subsequently the oil recovery can be greatly improved. The formation brine of heavy oil reservoirs usually has a high salinity and high content of multiple cations that make the in situ emulsification of heavy oil a challenge. In this work, a heavy oil of 14° API is used to study the mechanism of emulsification of heavy oils in brine under slight interfacial disturbance. Emulsification tests and interfacial measurements are carried out to screen alkalis and surfactant additives for emulsifying the oil in the diluted formation brine. The results show that if only alkali or only surfactant is added into the brine, emulsification of the oil in brine cannot be triggered. When alkali (Na2CO3) and very dilute surfactant are used together, the oil can be easily emulsified. The synergy of alkali and surfactant in emulsifying the heavy oil in brine is investigated by measuring the dynamic interfacial tension (IFT) and zeta-potential of emulsions. It is found that the interaction of added surfactant and in situ surfactant from the reaction of alkali and organic acids in oil can significantly reduce the dynamic interfacial tension between oil and water and increase the surface charge density of emulsions. The synergistic enhancement between alkali and surfactant is the key mechanism of emulsifying heavy oils in brine under slight interfacial disturbance. [Copyright &y& Elsevier]

Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 °C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C 16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C 12 surfactants), which was mainly depending on better IFT reduction ability of C 16 surfactants than C 12 surfactants. Appropriate IFT reduction, such as 10−1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10−2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs. • The spontaneous imbibition efficiencies of different surfactant solutions based on molecular structures were investigated systematically. • The reasons for the imbibition efficiency differences of different solutions were investigated in detail. • The optimum surfactant types and IFTs suitable for imbibition were obtained. [ABSTRACT FROM AUTHOR]

Alkyl polyglucoside, an eco-friendly, stable and low-cost available biobased surfactant, was chemically modified to develop ultra-low interfacial tension (IFT) surfactants for crude oil recovery from low permeability reservoirs. The modified anionic surfactant alkyl polyglucoside sodium hydroxypropyl sulfonate (APGSHS) was structurally characterized by FT-IR, 1H NMR and TGA methods. Following that, the cationic surfactant cetyl trimethyl ammonium bromide (CTAB) was combined with APGSHS to formulate the ultra-low oil/water IFT catanionic surfactants, which exhibits higher water-solubility than DTAB/APGSHS mixtures at various concentrations and combined ratios. Furthermore, the surface properties, thermodynamic parameters of the sole and combined surfactants show that the combined APGSHS/CTAB catanionic surfactants have lower surface tension (22.90 mN/m) at cmc , smaller area occupied per molecule and stronger micellization capacity, which indicates that the surfactant molecules are tightly absorbed onto the two-phase interface for catanionic surfactants. The mechanism underlying the strong electrostatic attraction between the ion head groups in APGSHS and CTAB could be proven by the high absolute value of interaction parameters (12.23) in binary systems. Besides, the salinity resistance effect tests indicate that the ultra-low IFT formula exhibits excellent performance in both monovalent and divalent ions conditions. Notably, the APGSHS/CTAB surfactants with total concentration of 3000 mg/L and molar ratio of 6:4 can effectively enhance oil recovery and decrease the injected pressure for low permeability reservoirs. Hence, the newly formulated green catanionic surfactants exhibit remarkable abilities for maintaining the ultra-low IFTs and can be used for EOR in low permeability and high salinity reservoirs. Unlabelled Image • A biobased surfactant alkyl polyglucoside is chemically modified for crude oil recovery from low permeability reservoirs. • Ultra-low interfacial tension (IFT) catanionic surfactants were formulated. • The ultra-low IFT formula exhibits excellent tolerance capacities against both monovalent and divalent ions. [ABSTRACT FROM AUTHOR]