This study addresses the challenge of low oil recovery in Y Reservoir, by water flooding with high-water-cut stage (80.1%) and low natural emulsification capability. An interfacial component compensation-synergistic enhancement strategy was proposed to design a benzoic acid-modified nano-SiO2 emulsifier (BHSD). The BHSD was compounded with Tween 20 to form an emulsification system, named TBHSD. The system's dispersion stability, emulsification performance, interfacial properties, and wettability alteration capabilities were systematically evaluated. Pore-scale displacement experiments revealed that the TBHSD system effectively forms high-internal-phase (up to 75-85%) water-in-oil emulsions, significantly reduces interfacial tension (to as low as 0.69 mN/m), enhances interfacial film strength (integrated modulus up to 20.63 mN/m), and alters rock wettability. The core flooding experiments demonstrated that the TBHSD system, followed by subsequent water flooding, achieved an additional oil recovery of 27.8%, primarily by mobilizing crude oil from small pores. The mechanism involves synergistic viscosity enhancement, adaptive mobility control, and improved microscopic displacement efficiency.

This study investigates improving the flowability of heavy crude oil using non-ionic surfactants that modify interfacial properties, thereby enhancing emulsification and dispersion. A mixture of Span 85 (HLB = 1.8) and Tween 20 (HLB = 16.7) was selected to meet the affinity requirements of both oil and water phases. Experiments were conducted on five different densities of heavy crude oil, evaluating viscosity reduction, emulsion droplet size distribution, and interfacial tension. Notably, this work presents the first systematic examination of interactions between various heavy crude oil densities and mixed emulsifiers. Results show that aligning the HLB value of the mixed emulsifier with that of the heavy crude oil enhances electrostatic repulsion between droplets, reducing droplet size and optimizing surfactant arrangement at the interface. The optimal HLB value for viscosity reduction was determined to be 8.0, at which a viscosity reduction rate of over 89% was achieved for high-density heavy crude oil. A quantitative relationship between emulsion droplet size and viscosity reduction rate was also established, leading to improved emulsion stability and significant viscosity reduction. These findings provide a theoretical framework for applying non-ionic mixed surfactants to enhance heavy crude oil flowability, and deliver experimental data to support field applications in petroleum engineering.

This study investigates the emulsification behavior of BZ crude oil under the combined influence of component ratios and heating effects. Emulsification experiments show that the internal phase inversion point of BZ crude oil increases from 55% at 85 °C to 70% under the heating-effect conditions, which can be attributed to strengthened interfacial film formation and enhanced coverage of surface-active components. At 85 °C, the emulsion viscosity reaches a maximum of 52.4 mPa s at a 55% water cut, while the heating effect further increases the emulsion volume by 10.5 mL at a water cut of 70%. Simulated oils with varying asphaltene, resin, and wax compositions reveal that the optimal ratio of 1:5:9 (arw159) yields the highest internal phase inversion point: 80% at 30 °C, 60% at 85 °C, and 75% under the heating-effect conditions. Across all simulated oils, the heating effect consistently enhances viscosity and increases the inversion point. Asphaltene dispersion analysis shows that heating promotes the formation of more abundant and larger asphaltene aggregates. Dynamic interfacial tension measurements further demonstrate a significant reduction in interfacial tension under heating conditions, with asphaltene adsorption exhibiting a clear three-stage kinetic behavior. High-temperature, high-pressure drop-shape analysis confirms that the interfacial complex modulus increases under the heating effect, with arw159 presenting the highest value of 25.52 mN/m. Overall, these findings highlight the synergistic roles of the heating effect and component ratios in enhancing emulsification performance and interfacial properties. By elucidating the key factors and mechanisms governing crude-oil emulsification, this work provides valuable theoretical guidance for emulsifier design and optimization, thereby contributing to the advancement of petroleum engineering practices.

The development of efficient chemical flooding agents for enhanced oil recovery (EOR) in low-permeability, high-salinity reservoirs remains challenging due to poor mobility control and limited emulsion stability. In this study, a particle-surfactant stabilized emulsion system (TKHSD), composed of gamma-aminopropyltriethoxysilanemodified nano-silica (KHSD) and a nonionic surfactant (Tween 20), is systematically investigated with an emphasis on water-in-oil (W/O) emulsion formation, interfacial film mechanics, and adaptive mobility control mechanisms. Experimental results demonstrate that KHSD particles and Tween 20 synergistically co-adsorb at the oil-water interface to form a hybrid soft-hard interfacial film with pronounced viscoelasticity. This interfacial architecture enables the in-situ generation of highly stable W/O emulsions with a high internal phase inversion point (up to 75%) and uniformly distributed micro-scale droplets (average diameter of 1.41 mu m). Interfacial tension measurements and oscillatory drop rheology reveal that surfactant-dominated interfacial tension reduction and particle-induced mechanical reinforcement jointly govern emulsion stability and rheological response under high-salinity conditions. At the macroscopic scale, the in situ formed W/O emulsions exhibit significantly enhanced apparent viscosity, providing adaptive mobility control by selectively increasing flow resistance in high-permeability channels. At the microscopic scale, reduced interfacial tension and wettability alteration facilitate the mobilization of residual oil trapped in pore throats. Core flooding experiments confirm that these coupled mechanisms lead to substantial improvements in sweep efficiency and displacement efficiency, yielding an incremental oil recovery of 31.63% under harsh reservoir conditions. Similar links between emulsion characteristics and porous-media flow resistance have been modeled, highlighting how droplet concentration changes can map onto measurable pressure-drop evolution. This work elucidates the interfacial and rheological origins of particle-surfactant stabilized W/O emulsions and highlights their role in self-adaptive mobility control, providing fundamental insights and practical guidance for the design of advanced emulsionbased EOR systems.

The low permeability and strong heterogeneity of low-permeability reservoirs result in low recovery rates from water flooding, making it challenging for conventional methods to effectively extract crude oil. Nano-SiO2, with its advantages of small particle size, low cost, and ease of modification, has garnered significant attention in the field of enhanced oil recovery. This study systematically investigates the emulsification performance, interfacial tension, and interfacial viscoelasticity of nano- SiO2 modified with fatty acids, fatty amines, and aromatic

Conventional chemical enhanced oil recovery (EOR) methods encounter significant challenges in heavy oil reservoirs, such as surfactant adsorption, thermal degradation, and unstable emulsions under harsh conditions. These limitations underscore the need for alternative EOR agents with enhanced performance characteristics. In this study, cost-effective silica nanoparticles were employed as a substrate material and functionalized through surface grafting of sodium alpha-olefin sulfonate and Poloxamer (F127) to synthesize the modified nanomaterial SAP. The performance and mechanisms of SAP in EOR were comprehensively investigated. The structure of SAP was characterized using 1H NMR, FTIR, and TGA, while its interfacial activity, stability, emulsification capacity, and oil displacement performance were comprehensively assessed. Additionally, molecular dynamics simulations were performed to explore the microscopic mechanism of viscosity reduction. The results revealed that a 100 ppm of SAP solution reduced the oil-water interfacial tension from 21.6 to 1.25 mN/m. After 72 h of immersion in SAP solutions, the contact angle of oil-wet rock surfaces decreased from 134 degrees to 33.5 degrees, converting the surface from oil-wet to water-wet. The absolute zeta potential consistently exceeded 30 mV within 168h, confirming colloidal stability of the SAP solution. SAP effectively forms low-viscosity oil-in-water (O/W) emulsions with oil, reducing viscosity by 95% at 80% aqueous phase content. Core flooding experiments reveal that the SAP system EOR by 27.3% when combined with subsequent water flooding. Molecular simulations further indicate that SAP interacts with asphaltenes in oil, organizing and localizing their arrangement to form stable O/W emulsion structures. This interaction minimizes direct contact and aggregation of oil droplets, promoting their uniform dispersion in water and significantly reducing overall viscosity. This study offers valuable insights into nanomaterial application for enhancing heavy oil recovery and highlights the potential of SAP as a novel viscosity reducer and emulsifier.

The behavior of SP crude oil defies the typical expectation that crude oil should exhibit lower phase inversion points (PIPs) and interfacial tension (IFT) at higher temperatures. To investigate these unique characteristics, emulsification experiments were conducted on SP oil at different temperatures. The emulsifying properties of various components of SP oil and maltene, with varying asphaltene contents, were further determined. The PIP of SP oil was observed to increase with temperature, ranging from 55 % at 50 degrees C to 85 % at 85 degrees C. Among the components of SP oil, only asphaltenes exhibited a slight resistance to the reduction of the PIP with increasing temperature. For maltene, the addition of asphaltene led to a higher PIP with increasing temperature. When the optimal mass ratio of resin to asphaltene was 5:1, the PIP increased from 65 % at 30 degrees C to 75 % at 60 degrees C. Furthermore, the interfacial properties of SP oil and its components at different temperatures were analyzed. The experimental results demonstrated that the IFT of SP oil increased with temperature. The dynamic IFT exhibited an increasing trend over time while maintaining relative stability. Among the components of SP oil, only asphaltenes exhibited an increase in IFT over time. For maltene, the addition of asphaltene resulted in an increase in IFT with increasing temperature.

The adsorption behaviors of methane(CH4), 4 ), hydrogen(H2), 2 ), and their mixtures are crucial for estimating the underground hydrogen storage(UHS) capacity in depleted shale gas reservoirs. In this study, we developed four formulated kerogen models, each representing different maturation levels of type II kerogen molecules via utilizing molecular dynamics (MD) methodologies. We investigated the adsorption characteristics of pure H2 2 and mixed gases(H2 2 and CH4) 4 ) on these kerogen models with varying gas components(0.5:0.5 to 0.9:0.1) and moisture content(0-3.0 wt percentage) through grand canonical Monte Carlo(GCMC) simulations. Our findings reveal that pure H2 2 lacks a pressure point for adsorption equilibrium below 100 MPa at ambient temperature(298K). The competitive adsorption dynamics between H2 2 and CH4 4 on kerogen models demonstrate that CH4 4 exhibits stronger selectivity at lower pressures. Yet, this selectivity diminishes compared to H2 2 as system pressure increases, indicating turning points in pressure buildup with kerogen maturity. Additionally, the presence of pre- loading H2O 2 O molecules reduces the adsorption capacity of mixed gases, particularly affecting CH4 4 more than H2. 2 . This study offers profound insights into the effect of kerogen maturity and moisture content on the interaction between H2/CH4 2 /CH 4 and kerogen at a microscopic scale.

Nowadays, high-phase-inversion in situ emulsification technology has shown great potential in enhancing oil recovery from high-water-cut thin-oil reservoirs. However, emulsification characteristics, interfacial properties, and the mechanism of high phase inversion have not been systematically described. In this study, an emulsification experiment was conducted to investigate the effects of shear time, shear rate, and temperature on the phase inversion of thin oil. Furthermore, the influence of resin and wax on the dispersion of asphaltene was studied through microscopic morphology analysis. Interfacial tension measurement and interfacial viscoelasticity analysis were carried out to determine the interaction characteristics of asphaltene, resin, and wax at the interface. The results showed that, at 50 °C, the phase-inversion point of thin oil reached as high as 75%, and even at 60 °C, it remained at 70%. The shear time and shear rate did not affect the phase-inversion point of thin oil, while an increase in temperature led to a decrease in the phase-inversion point. Moreover, compared to the 20% phase-inversion point of base oil, the phase-inversion point increased with different proportions of asphaltene, resin, and wax. Particularly, at the ratio of asphaltene/resin/wax = 1:5:9, the phase-inversion point reached as high as 80%, indicating the optimal state. In this proportion, asphaltene aggregates exhibited the smallest and most uniform size, best dispersion, lower interfacial tension, and higher interfacial modulus. These findings provide reference and guidance for further enhancing oil recovery in medium-to-high-water-cut thin-oil reservoirs.

Currently, the method for confirming the phase inversion point of an emulsion only exists at a macro level, and it is almost impossible to determine the phase inversion point from a micro level. In order to further enrich the methods for determining the phase inversion point, this study attempts to investigate the phase inversion point from a microscopic perspective. Based on the actual water content method, the macroscopic volume of the emulsion was converted into the total number of emulsion droplets in a micrograph. Secondly, the viscosity method and the actual water cut method were used to determine the phase inversion point. Finally, a new method was used to determine the phase inversion point of the emulsion, and compared with the viscosity method and the actual water cut method. Results showed that first, after a series of simplifications, the RN value (the product of the average radius and number of droplets) was employed to represent the actual macroscopic water content, and the RN micro-scale method was formed to determine the phase inversion point of the emulsion. Second, the phase inversion point determined by the new method was consistent with the results calculated by the viscosity method and the actual water cut method, both of which were 60

Foam flooding is an extremely effective method of enhanced oil recovery used to address uneven utilization in strongly heterogeneous reservoirs. However, conventional foam is not stable and is unevenly distributed in oil reservoirs during conventional foam flooding. Hydrolyzed polyacrylamide-strengthened nitrogen foam (HSNF) was therefore proposed to overcome the defects of conventional foam flooding. In this investigation, a comprehensive method was utilized to understand the mechanisms of HSNF with regard to its stability and distribution in reservoirs. In situ experimental characterization and molecular dynamics simulations were designed to examine the characteristics of HSNF. Foam stability was analyzed as a function of the viscosity of the liquid phase, adsorption, and pressure for HSNF and conventional foam. Parallel core flooding experiments were conducted to compare the oil recovery efficiencies of HSNF and conventional foam. Molecular dynamics simulations were utilized to examine the nanostructure of HSNF in brine. Foam stability tests demonstrated that foam stability was enhanced by increasing the viscosity and pressure of the liquid phase and reducing the adsorption capacity of the surfactant. HSNF increased the foam half-life by a factor of 1.67-27.1. The parallel core flooding experiments showed that HSNF effectively initiated flow in low-permeability cores to increase the mobilization of oil even when the permeability ratio was 14.86. However, conventional foam only achieved similar performance at a permeability ratio of less than 10.64. The molecular dynamics simulations revealed that the addition of hydrolyzed polyacrylamide improved the uniform distribution of the oil displacement agent in porous media, inhibited the diffusion of nitrogen in the foam system, and enhanced the interactions between the water phase and crude oil. This suggests that HSNF is a promising oil recovery agent for use in low-porosity, low-permeability, and strongly heterogeneous sandstone reservoirs.

Pyrolysis is regarded as the primary reaction for heavy crude oil upgrading during ISC process, and gas compositions produced by this reaction is also gaining attention. It is critical to establish the kinetic model to predict all products. The kinetic of heavy oil upgrading was studied and all experiments were carried out in an autoclave at 350-450 degrees C, 0.5 MPa, and 1-10 h. An improved kinetic including SARA fractions, coke, and gas compositions was proposed be more detailed description of the reaction process. Smaller SSE and bigger coefficients of determination (>0.99) of parity plots suggested the accuracy of calculated parameters of the improved kinetic model. The sensitivity analysis results demonstrate that the obtained kinetic parameters represent the optimal values. Gas prediction, a neglected aspect in previous studies, was also addressed, further enhancing the model's utility.

In -situ emulsification has recently shown promise for increasing oil production in water flooding reser-voirs owing to its easy procedure and polymer and surfactant properties. The phase inversion point (PIP) plays a vital role in emulsification technology. However, the existing free energy models have lim-ited accuracy in the calculation of the PIP, and the models' areas of applicability are not specified. The free energy model was improved in this study by classifying crude oil to enhance the prediction accuracy and expand the free energy model's range of calculation. The applicable range of the model was defined by analyzing and comparing the distribution characteristics of interfacial tension (IFT) and PIP. Firstly, the effects of temperature, shear rate, shear time, salinity, and pH on the PIP were discussed. The experimen-tal results showed that, among these external factors, only the temperature could change the PIP. Generally, the PIP decreased with increasing temperature. Second, different parameters a and b were obtained using the differential aggregation characteristics of oil and water. Then, to further analyze and demonstrate the new model's accuracy, the experimental data of three new oil samples (crude oil D, G, and J) were collected and compared with the results of other models. The results showed that the new model could successfully fit the data; its average absolute error was 4.47%, while that of the previous models was about 40%. The other models were particularly unsuitable for calculating the PIP of heavy oil, but the new model's inaccuracy was only 1.48%. Finally, the IFT and PIP data were analyzed and compared. The results showed that, for conventional crude oil, the IFT and PIP decreased with the temper-ature increase. The applicable conditions of the model were also clarified. The model is suitable for crude oil whose IFT decreases with temperature increase. The results of this study can be used in the petroleum industry and other industries dealing with mixed immiscible fluid transport. (c) 2022 Elsevier B.V. All rights reserved.

In this study, based on X reservoir conditions from Dagang Oilfield, China (temperature: 104 degrees C, salinity: 26376 mg/L), from the perspective of reducing interfacial tension and emulsification performance, IAPES (isododecyl alcohol polyoxyethylene ether sulfonate) with high temperature and high salt resistance was selected and its performance was evaluated. Finally, physical simulation experiments were conducted to form an in situ viscosity-increasing emulsion to enhance oil displacement efficiency. The experimental results show that when the concentration of IAPES is 0.3 wt%, the ability to reduce the interfacial tension of oil and water is significant and it has good antiaging stability. In addition, the lower the shear rate, the higher the water content, and the worse the emulsion stability. Finally, physical simulation experiments show that IAPES can increase the recovery rate by at least 28% in a larger permeability range. Under the experimental research conditions, the injection process parameters-injection speed (0.4 mL min(-1)) and injection volume (0.3PV) were optimized.

During crude oil production and transportation, water-in-oil emulsions are often formed. To reduce the adverse effects of emulsification on the production and transportation of heavy oil, the factors affecting the emulsion stability of heavy oil have been systematically studied using the simple, reliable and widely used bottle test. The effect factors included shear rate, shear time, temperature, and salinity. At the same time, to reveal the mechanism of these factors affecting emulsion stability, 500 ppm asphaltene was added to crude oil and all of the above experiments were repeated. In the experiment, oil and water were stirred, in which the total volume of oil and water was 30 ml and the water-oil ratio was 50

Fracturing flowback fluid (FFF) including various kinds of organic pollutants that do harms to people and new treatments are urgently needed. Advanced oxidation processes (AOPs) are suitable methods in consideration with molecular weight, removal cost and efficiency. Here, we summarize the recent studies about AOP treatments towards organic pollutants and discuss the application prospects in treatment of FFF. Immobilization and loading methods of catalysts, evaluation method of degradation of FFF, and continuous treatment process flow are discussed in this review. In conclusion, further studies are urgently needed in aspects of catalyst loading methods, macromolecule organic evaluation methods, industrial process, and pathways of macromolecule organics’ decomposition.

Crude oil emulsions generated during the life period of crude oil from production and separation comprise a fascinating interdisciplinary topic that is being actively studied in both chemical science and engineering. However, a comprehensive understanding of the emulsification mechanism based on a sound chemicophysical foundation for the natural emulsifiers of crude oil remains challenging and is not well established. In this study, we developed a framework that combines crude oil separation, molecular structure characterization and infer-ence, self-assembly of natural emulsifiers at the oil-water interface, and phase behavior of natural emulsifier emulsions to decipher the self-emulsification of crude oil. Our results revealed that crude oil components have independent and synergistic effects on the formation and stabilization of crude oil emulsions. Asphaltene has the highest molecular weight and the strongest interfacial activity compared to other components, significantly contributing to the formation of crude oil emulsions. As the second highest molecular weight crude oil component, resin is the solvent for asphaltene. Aromatic and saturated hydrocarbons adsorbed at the oil-water interface form an interfacial viscoelastic film that mainly stabilizes the crude oil emulsion. The viscosity of crude oil emulsions is mostly affected by asphaltene and resin, while their phase inversion point is primarily deter-mined by aromatic and saturated hydrocarbons. These results provide a universal insight into the internal emulsification mechanism of crude oil. We expect that these findings will also provide theoretical support for taking advantage of crude oil emulsions for the purpose of efficient oil recovery.

Water flooding can create a transient heating effect that causes oil and water to self-emulsify. This study sought to understand how this effect impacts crude oil's emulsifying properties by conducting oil-water emulsification experiments and investigating the effects of initial temperature, heating rate, and effective time. Additionally, asphaltene dispersion, adsorption behavior, and viscoelasticity of crude oil and its interfacial components were analyzed to unravel the mechanism behind the heating effect on crude oil's emulsifying capacity. The heating effect was observed to suppress interaction force dissipation between asphaltene molecules effectively from low to high temperatures. This increased both the interfacial film thickness and steric hindrance, improving crude oil's emulsifying ability. However, at high temperatures, the interfacial film became unstable, which led to the normalization of crude oil's emulsifying ability after the effective time. These findings provide insight into the emulsifying mechanisms of water-drive reservoirs and the in-situ emulsifying theory of underground crude oil.

Most waterflooding oilfields have entered the high water cut stage, but significant amounts of crude oil remain in the formation. Therefore, understanding the emulsifying characteristics of crude oil with high water content is crucial. This study investigates the effects of shear time, shear rate, temperature, water content, and re-emulsification at high water content on the emulsifying properties of crude oil. Results indicate that shear time, temperature, and water content play a role in enhancing the emulsifying capacity of crude oil. Additionally, the initial water content of the emulsion affects the solubilization ability of crude oil; lower initial water content leads to stronger solubilization ability, while higher total water content leads to weaker solubilization capacity. Under an optical microscope, the morphology of the emulsion was observed, revealing that an increase in water content resulted in an increase in particle size and quantity of emulsion droplets, leading to more uniform droplets. However, at high water content, the particle size of emulsion decreased, the number of droplets decreased, and the droplets became uneven. Furthermore, the particle size of re-emulsified emulsion was smaller than that of the emulsion with the same moisture content, indicating that re-emulsification can lead to instability. The interfacial characteristics of the emulsion were also analyzed, showing that an increase in water content caused an increase in interfacial tension and expansion modulus of emulsion compared to crude oil. Finally, the study elucidates the influence mechanism of high-water content on the emulsifying performance of crude oil, which includes the destruction of molecular forces on and between interfaces, weakening the steric hindrance effect. Unstable film and non-uniform droplets can promote coalescence and fragmentation of droplets, limiting the emulsifying performance of crude oil. The results of this study provide a better understanding of the formation and fracture process of emulsion under high water cut conditions, offering a theoretical basis for further enhanced oil recovery.