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Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods. [ABSTRACT FROM AUTHOR]

Alkali–surfactant–polymer (ASP) flooding is one of the most effective and promising ways to enhance oil recovery (EOR). The synergistic effect between alkali, surfactant, and polymer can respectively promote emulsification performance, reduce interfacial tension, and improve bulk phase viscosity, thus effectively improving flooding efficiency. However, the displacement mechanism of ASP flooding and the contribution of different components to the oil displacement effect still need further discussion. In this study, five groups of chemical slugs were injected into the fracture model after water flooding to characterize the displacement effect of weak alkali, surfactant, polymer, and their binary/ternary combinations on residual oil. Additionally, the dominant mechanism of the ASP flooding system to improve the recovery was studied. The results showed that EOR can be improved through interfacial reaction, low oil/water interfacial tension (IFT), and increased viscosity. In particular, the synergistic effect of ASP includes sweep and oil washing. As for sweep, the swept volume is expanded by the interfacial reaction between the alkali and the acidic components in Daqing crude oil, and the polymer increases the viscosity of the system. As for oil washing, the surfactant generated by the alkali cooperates with surfactants to reduce the IFT to an ultra-low level, which promotes the formation and migration of oil-in-water emulsions and increases the efficiency of oil washing. Overall, ASP can not only activate discontinuous oil ganglia in the pores within the water flooding range, but also emulsify, decompose, and migrate the continuous residual oil in the expanded range outside the water flooding. The EOR of ASP is 38.0% higher than that of water flooding. Therefore, the ASP system is a new ternary composite flooding technology with low cost, technical feasibility, and broad application prospects. [ABSTRACT FROM AUTHOR]

Copyright of Energy Chemical Industry is the property of Energy Chemical Industry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The paper presents the results of experimental evaluation of oil displacement efficiency by flue gas of a thermal power plant, compared to water, for a carbonate reservoir in the Ural-Volga region. The experiments were performed under two different injection schemes using an original laboratory complex for coreflood studies, with recombined reservoir oil, model of formation water, reservoir core material, and under reservoir thermobaric conditions. It has been confirmed that due to the prevailing nitrogen content and low values of reservoir pressure and temperature, flue gas is ineffective as an independent displacement agent either for injection from the beginning of reservoir development or as a tertiary method after waterflooding. Taking into account the relevance of synergy between increasing oil recovery and sequestration of industrial emissions, evaluation of flue gas injection as part of water-gas mixtures (SWAG) is recommended.

The article presents new results of laboratory studies, along with a summary of previously obtained ones. An analysis of the development of reserves in the experimental area was carried out with recommendations for improving the efficiency of its oil recovery processes in the amount of 10-30% of the pore volume of the experimental area. New conditions for injection with a limited supply of carbon dioxide are considered. The results of oil recovery modeling, using CO2 and water rims, are presented. The increase in oil recovery for reservoirs D1 and D2 was determined, and a forecast was made for the value of additional oil production per ton of carbon dioxide. [ABSTRACT FROM AUTHOR]

Decreasing negative impact of industrial emissions to the atmosphere and prolonging fossil fuel usage period are urgent issues of fuel and energy sector. In view of this problem, injection of flue gases into oil fields to increase oil recovery may be considered as environmentally safe and economically rational way for beneficial use of greenhouse gas emissions. To effectively displace oil with flue gases it is important to consider many factors: influence of composition of the flue gases and oil, miscibility conditions, injection regimes, etc. Flue gases, a product of fuel combustion in air, can be produced as a result of oil self-ignition when air is injected into a reservoir with light oil (thermal gas method). Flue gases from natural gas, fuel oil or coal combustion in power plants or other processes that burn fossil fuels can also be used for injection into the reservoir. This paper presents an analysis of the world laboratory and industrial experience in studying efficiency of oil displacement using flue gases. Conclusions are presented about optimal criteria for implementation of this process and directions for further research.

Sweep efficiency of stagnant and poorly drained reservoir zones is extremely relevant task during gas and chemical flooding of hard-to-recover reserves. The paper presents the results of the field implementation of the in-situ CO2 generation technology to recovery of residual oil reserves and increase the sweep efficiency factor. The article presents the results of theoretical and laboratory studies, as well as field cases of an energy- and resource-saving method for oil recovery increase and improving oil production. The results of the reservoir stimulation confirmed the increase in the total incremental oil production after treatment operation on recovering residual oil reserves on. [ABSTRACT FROM AUTHOR]

Objective During the implementation of chemical flooding, the adsorption and retention of the reservoir on the displacing agent was a major reason for the concentration loss of surfactants entering the reservoir. In order to reduce the loss cost of oil displacement fluid in the formation, the research on the adsorption inhibitor of oil displacement fluid is carried out. Methods A adsorption inhibitor OHCB for oil displacement fluids was synthesized by the nucleophilic addition principle based on the raw materials of dicyanodiamide (DCD) and 1-octadecylamine hydrochloride (OHC) using fusion method at 150 ℃. This surfactant had strong hydrophobic groups, strong polar atoms and cationic groups, and had the ability to occupy the adsorption sites on the clay mineral surface. The structure characterization was carried out by infrared absorption, ultraviolet absorption, elemental analysis, mass spectrometry, etc. The optimum ratio was studied by static adsorption method for using it as an additive, and the adsorption inhibition effects of the optimal ratio on the oil displacement agent AEO7 were verified, as well as the static oil washing efficiency, emulsification and wetting properties of the system were compared with the single AEO7 system. Results The results showed that OHCB had better inhibition effect on the adsorption of oil displacement agent AEO7 on clay mineral surface. The inhibition effect reached more than 27% when the mass ratio of oil displacement agent to adsorption inhibitor was 5∶1. Conclusions The addition of OHCB not only has a good adsorption inhibition effect, but also improves the static oil washing efficiency of AEO7 to 27.3%, reduces γcmc to 27.1 mV/m, reduces cmc to 38 mg/L, and reduces the oil-water interfacial tension to below 0.5 mV/m. It has a synergistic effect on the system performance. Comparing with sacrificial agents requiring pre-adsorption, the method is more convenient. [ABSTRACT FROM AUTHOR]

The characteristics and differences of nano-emulsion and microemulsion are reviewed in detail from the aspects of size, preparation method, thermodynamics and kinetic stability, and the main factors affecting the stability of nanemulsion and the instability mechanism are analyzed in detail. The preparation method, oil displacement and drainage mechanism of nanemulsion are systematically introduced, and its influencing factors are summarized, and the application status of nano-emulsion in the development of unconventional oil and gas reservoirs is reviewed・ The development of new cost and efficient preparation methods and the study of new temp eratu re -resistant and salt-tolerant nano emulsion are the main research directions in the next step. [ABSTRACT FROM AUTHOR]

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods.

In water flooding, residual oil is displaced by injecting water into the reservoir formation. Oil displaced from injection wells is physically swept to adjacent production wells by water. Compared to conventional oil fields, offshore heavy oil fields have low oil recovery using water flooding. If we had a better knowledge of the flow characteristics of the water and oil phases, it would be very useful to improve the oil recovery of the heavy oil reservoir. In developing oil fields, it is important to study the patterns of changes in the flow characteristics of the oil and water phases. This will guide the development of numerical simulation models. This study considered the geological characteristics, fluid properties, and construction technology of an offshore oil field with heavy oil. The relative permeabilities of water and oil were investigated using steady-state and unsteady-state methods. With the unsteady state method, the effect of core permeability, water washout, and oil viscosity on the relative permeability curve and oil displacement efficiency of water flooding has been investigated. Artificial cores were utilized in the experiments. The artificial cores were developed to simulate the structure of unconsolidated sandstone in an offshore oil field. Computed tomography and mercury pressure testing are used to demonstrate the change in the internal structure of the core. Water washout forms the “cleaning” and “erosion” function, which affects core pore structure, increases the radius of the core pore throat, and increases the core permeability. It has the same effect on relative permeability curves and oil displacement efficiency as it does on increased permeability. The total oil recovery decreases with increasing oil viscosity since the ability to control water mobility weakens during the flooding process. Moreover, the coverage volume of the displacing water phase decreases, and the two-phase flow range narrows Water sweeps expand as core permeability increases, resulting in a wider twophase flow as the relative permeability of the water phase increases. In turn, this enhances oil efficiency displacement and total oil recovery. [ABSTRACT FROM AUTHOR]

Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In order to elucidate the oil displacement mechanism of micro-emulsions formed by different betaines at pore throats, this study selected three betaine surfactants with different hydrophobic branched chains for a microscopic visualization oil displacement experiment. The interfacial tension, dilational modulus, interactions of oil droplets, and apparent viscosity of the emulsions were measured. Besides, the microscopic oil displacement mechanism and oil displacement effects of different betaines in homogeneous and heterogeneous models were investigated. The results revealed the beneficial interfacial activity and viscosity enhancement effects of the three betaine solutions. With the increase in the branched degree of betaines, the strength of interfacial films and the viscosity enhancement effect decreases. In the homogeneous model, betaine solutions emulsify crude oil into droplets with strong interfacial films. The in-situ plugging effect improves oil recovery and the sweep efficiency in the pore throats, and the remaining oil is mainly in the form of droplets. As the branched degree increases, the strength of the interfacial films and the oil recovery decline. In the heterogeneous model, the plugging effect enhances the pore structure heterogeneity. The three betaine solutions can increase the sweep efficiency but the displacement solutions only migrate along the dominant pathway within the sweep range. As a result, a large amount of isolated cluster residual oil remains, resulting in similar oil recovery efficiency for betaine flooding to that of water flooding in the heterogeneous model. [ABSTRACT FROM AUTHOR]

The carbon capture, utilization and storage (CCUS) technique is widely applied in order to solve energy shortages and global warming, in which CO2 storage plays an important part. Herein, the CO2 storage in reservoir pores with a dead-end is investigated using a molecular dynamics simulation. The results indicate that, when a CO2 molecule flows through a reservoir pore towards its dead-end, it is readily captured inside said dead-end. When the pressure difference of the CO2 injection increases, the transport speed of the CO2 becomes faster, and the storage efficiency increases. The rate constants for the absorption of the carbon dioxide at 5 MPa, 10 MPa, and 15 MPa are 0.47 m/s, 2.1 m/s, and 3.1 m/s. With the same main channel, a narrower dead-end with less oil molecules would cause a smaller spatial potential resistance, which would lead to a faster CO2 replacement and storage process. The 3 nm main channel with a 1.5 nm dead-end model had the highest absorption rate of 5.3 m/s out of the three sets of models with different dead-ends. When the dead-end's width was constant, the rate constants for the absorption of carbon dioxide in the 6 nm main channel with a 1.5 nm dead-end model was 1.8 m/s, which was higher than that of the 3 nm–1.5 nm model. This study investigates the mechanism of CO2 storage in reservoir pores with a dead-end at the molecular level and provides a scientific basis for the practical application of CO2 storage. [ABSTRACT FROM AUTHOR]

The occurrence state of oil, gas, and water plays a crucial role in exploring shale reservoirs. In this study, molecular dynamics simulations were used to investigate the occurrence states of these fluids in shale nanopores. The results showed that when the alkane is light oil, in narrow pores with a width less than 3 nm, oil molecules exist only in an adsorbed state, whereas both adsorbed and free states exist in larger pores. Due to the stronger interaction of water with the rock surface, the adsorption of oil molecules near the rock is severely prohibited. Oil/water/gas occurrence characteristics in the water-containing pore study indicate that CO2 gas can drive free oil molecules out of the pore, break water bridges, and change the occurrence state of water. During displacement, the gas type affects the oil/gas occurrence state. CO2 has strong adsorption capacity, forming a 1.45 g/cm3 adsorption layer on the rock surface, higher than oil's density peak of 1.29 g/cm3. Octane solubility in injected gases is CO2 (88.1%) > CH4 (76.8%) > N2 (75.4%), with N2 and CH4 having weak competitive adsorption on the rock. The investigation of different shale reservoir conditions suggests that at high temperature or low pressure, oil/gas molecules are more easily displaced, while at low temperature or high pressure, they are tightly adsorbed to the reservoir rock. These findings contribute to the understanding of fundamental mechanisms governing fluid behavior in shale reservoirs, which could help to develop proper hydrocarbon recovery methods from different oil reservoirs. [ABSTRACT FROM AUTHOR]

After polymer flooding, substantial oil and residual polymers remain in reservoirs, leading to plugging and reduced recovery. MEOR (Microbial Enhanced Oil Recovery) aims to release trapped oil by utilizing microorganisms and their byproducts. The microorganisms can use residual HPAM (hydrolyzed polyacrylamide) as an energy source for polymer degradation, addressing reservoir plugging issues and improving oil recovery. However, microorganisms are sensitive to environmental conditions. This paper presents a detailed update of MEOR, including microbial products, mechanisms, and merits and demerits. The effect of the displacement fluid and conditions on microorganisms is thoroughly demonstrated to elucidate their influencing mechanism. Among these factors, HPAM and crosslinkers, which have significant biological toxicity, affect microorganisms and the efficiency of MEOR. Limited research exists on the effect of chemicals on microorganisms' properties, metabolism, and oil displacement mechanisms. The development of microbial consortium, their metabolic interaction, and oil displacement microprocesses are also discussed. In addition, prior studies lack insights into microorganisms' interaction and mechanisms using chemicals. Finally, field trials exist to examine the microbial consortium's efficiency and introduce new technologies. This review mainly explores the influencing factors on microorganisms, and confirms the credibility of MEOR after polymer flooding, providing a scientific basis for improving the theory of MEOR. [ABSTRACT FROM AUTHOR]

Using ammonia terminated polydimethylsiloxane - methoxy polyethylene glycol acrylate - and vinyl acetate as raw materials - sufficient CO2 friendly groups are introduced to increase the solubility of the thickener in CO2. A CO2 thickener with easy solubility - environmental protection - low cost and good thick¬ening effect is developed - achieving CO2 viscosity increase under solvent-free conditions. The synthesis process conditions of supercritical CO2 tackifier were optimized using response surface methodology. The results showed that the optimal synthesis conditions were as follows: the addition of ammonia terminated polydimethylsiloxane was 50 g - the addition of methoxy polyethylene glycol acrylate was 27 g - the addition of vinyl acetate was 41 g-the reaction temperature was 75 °C - and the reaction time was 8 h. At a tempera¬ture of 35 °C and a pressure of 8 MPa-the CO2 liquid viscosity of the 2 supercritical CO2 tackifier in¬creased by 50.46 -53. 17 times-which is close to the predicted value of 52.085 times by the model. [ABSTRACT FROM AUTHOR]

Biosurfactants are amphiphilic compounds synthesized from plants and microorganisms and are known for their high biodegradability, low toxicity, and eco-friendliness. They have diverse applications in industrial and environmental fields, including oil recovery, bioremediation, and cleaning up hydrocarbons from polluted areas. Surfactin is a potent lipopeptide biosurfactant produced by Bacillus subtilis bacteria. In this study, we produced surfactin by B. subtilis using cassava wastewater as the fermentation medium. This production was monitored by high performance liquid chromatography (HPLC). Approximately 600 mg L−1 of surfactant was produced. The oil displacement test was then performed to evaluate the effectiveness of crude and purified surfactin compared to a synthetic surfactant and a biosurfactant. Three types of surfactants were tested: the synthetic surfactant sodium lauryl sulfate (SDS), the commercial biosurfactant rhamnolipid (Rh), and surfactin in its crude form and purified one – after acid precipitation. The analysis results indicated that surfactin, in both its crude and purified forms, was more effective at dispersing oil than the other surfactants tested, even at lower concentrations. This suggests that biosurfactants have great potential as a more sustainable and effective alternative to petroleum-derived synthetic surfactants. Surfactin can be applied without the need for downstream processes. [ABSTRACT FROM AUTHOR]

Janus nanoparticles (JNPs) possess great potential in recovering the residual oil from reservoirs, however, the fundamental interaction mechanisms among nanoparticles, the oil, and reservoir wall characteristics remain to be elucidated. In this work, models of oil trapping grooves with different geometric features are subjected to molecular dynamics simulations for investigating the influences of roughness parameters on oil displacement dynamics by JNPs. Four key surface geometry parameters and different degrees of surface hydrophobicity are considered. Our results indicate that JNPs hold an outstanding performance in displacing residual oil on weakly to moderately hydrophobic surfaces. Overall, smaller entry and exit angles, the larger aspect ratio of the oil trapping grooves, and a bigger tip length of the rough ridges lead to superior oil recovery. Among the key geometric parameters, the aspect ratio of the oil trapping grooves plays the dominant role. These insights about the interaction of surface properties and JNPs and the resulting trapped oil displacement could serve as a theoretical reference for the application of JNPs for targeted reservoir conditions. [ABSTRACT FROM AUTHOR]

The problem of optimizing water and gas injection to displace heavier oil components used in fuel production is solved. Several initial oil compositions in the reservoir and various mixtures of injected substances are considered. Numerical optimization is automated in such a way that for a fixed amount of injected pore volumes, the composition of the injected mixture is automatically changed and the most favorable composition is selected, which increases the oil-recovery factor. It is shown that for various initial oil compositions, the displacement efficiency, depending on the amount of injected pore volumes of more valuable components, qualitatively coincides. In this regard, optimization of the injection of a mixture consisting of four components is studied for one of the initial compositions. The processes occurring during injection of the optimal composition are calculated on a finer grid. [ABSTRACT FROM AUTHOR]

This paper presents a numerical and experimental study of the effect of viscous and capillary forces on the characteristics of a multiphase flow in a pore doublet model, which is one of the most well-known elementary models of a pore space. Numerical simulation is carried out using OpenFOAM. The process of oil displacement by various agents in a pore doublet model is subjected to a multiparametric analysis with varying pore surface wettability, pressure difference, surface tension, and the ratio of the pore doublet channel size. It is shown that the numerical simulation results are in good agreement with experimental data for the pore doublet model in the case of a hydrophobic surface at various capillary numbers. The physical model of the pore doublet is implemented in a microfluidic chip manufactured using soft lithography. The proposed approach based on computational and experimental microfluidics makes it possible to carry out a numerical study of two-phase filtration in porous medium models corresponding to laboratory studies and to scale the results by characteristic sizes of the core. [ABSTRACT FROM AUTHOR]

Four products were obtained from sodium dodecylbenzene sulfonate (SDBS) and formaldehyde (40% solution) using a simple reaction. The products were characterized by TGA, IR, UV and MS to confirm the major chemicals in each sample. The new products could reduce the interfacial tension between oil and water in the experimental temperature range further compared to SDBS. The emulsion ability was also enhanced by SDBS-1 to SDBS-4. The oil-displacement efficiencies of SDBS-1 to SDBS-4 were obviously higher than that of SDBS, and the oil-displacement efficiency of SDBS-2 was the best, with an efficiency of 25%. The experimental results all indicate that these products have an excellent ability to reduce oil–water interfacial tension and that they can be used in the oil and petrochemical industry for oil production and have certain practical uses. [ABSTRACT FROM AUTHOR]

In this paper, we investigated a two-phase model of incompressible fluid filtration. We apply the irregular grid method and the variable direction scheme. This approach gives the effect of solution accuracy near discontinuities (wells) due to the use of an irregular grid. The model is built taking into account the influence of capillary pressure and gravitational forces. The results confirm that the amount of oil that came out of the layer in a certain time is equal to the volume of water injected, except for the amount of water in the outlet stream in the same time. The proposed solutions of the new approach are intended to improve the methods and schemes of numerical investigation of this model. A balanced monotonic finitedifference scheme was developed and an efficient algorithm for its implementation was proposed. From a practical point of view, numerical modeling allows early prediction of performance. Thus, the applied aspect of the use of the obtained scientific result is the possibility of improving the process by taking into account the distribution of water saturation in the layer. [ABSTRACT FROM AUTHOR]

Unconventional reservoirs have characteristics of complex pore geometry, high heterogeneity and low permeability. The wetting behavior between the fluid and solid is the dominant factor that controlling the static and dynamic fluid displacements, which is of great crucial for evaluating the fracturing fluid performance, enhancing the oil recovery during the fracturing fluid imbibition, and optimizing the fracturing fluid formulation. In this paper, we propose a new in-situ wettability characterization method based on the Gauss-Bonnet theorem and 3D micro-computed tomography experiments. In addition, we systematically analyze the effect of complex wetting condition on fracturing fluid performance during the imbibition process of fracturing fluids by applying digital rock technology and lattice-Boltzmann method simulations. It is elucidated that the wettability characterization method by the topological principles is more accurate than in-situ microscopic contact angles, of which accuracy is higher than 95%. It is also capable of characterizing the wettability that is influenced by different wetting characteristics. Simultaneously, the tight oil recovery in the homogeneous water-wet reservoir is 33.8% higher than that of mixed-wet reservoirs, which leads to a better performance of fracturing fluid. The initial condition of reservoir is commonly mixed-wet. Therefore, the formulation of fracturing fluid needs to be optimized to reduce the rock wettability and enhance tight oil recovery. [ABSTRACT FROM AUTHOR]

Objective Aiming at the problems of poor shear resistance of polymer and the influence of deep formation viscosity retention in conventional chemical flooding system, wormlike micelle oil displacement technology was studied. Methods Using betaine surfactant monomer (PSM), N, N-dimethylpropylene diamine and other raw materials, by two-step reaction of amidation and quaternization, the wormlike micellar surfactant for oil displacement with viscoelasticity and interfacial activity was synthesized under the conditon of reduced pressure spin drying. The molecular structure, theological properties, microstructure, shear resistance, salt resistance, interfacial tension and oil displacement characteristics of wormlike micelle were investigated. Results The structure obtained by NMR was consistent with the target product. Wormlike micelle has good viscosity increasing (mass fraction O. 30% —O. 50%, apparent viscosity 10 — 50 mPa • s, 7. 34 s-1), salt resistance (<100 000 mg/L) and the ability to reduce oil-water interfacial tension (10-2 mN/m). The core displacement experiment results showed that the wormlike micelle has stronger oil displacement ability than conventional polymer, and the FOR was increased by 11. 7%. Field well group test increased oil by 2 700 m3. Conclusions Wormlike micelle oil displacement technology can be used as an efficient oil displacement agent in offshore high water-cut reservoirs to effectively increase oil rate and reduce water production. Keywords: wormlike micelle; oil displacement; viscoelasticity; surfactant; interfacial tension [ABSTRACT FROM AUTHOR]

Objective The performances of fluorinated surfactants by introducing fluorinated segments into sutfactants were studied. Methods Maleic anhydride, dodecyl primary amine, hexamethylene diisocyanate (HDI), perfluorobutyl ethanol and sodium bisulfite were used to synthesize wetting and emulsifying fluorinated surfactants( EFS). The structure of EFS was characterized by FTIR and ' HNMR. The wettability, emulsifying and oil displacement properties of EFS were investigated. Results The EFS can effectively improve the wettability and change the oil-wet glass surface into neutral surface, showing wetting reversal properties. Besides, the emulsification and solubilization performance indicated that 0.2% EFS has good emulsifying properties for crude oil. Moreover, the EFS presented good oil displacement performance, and more than half of crude oil in capillary can be driven out when the concentration of EFS was 0. 2% within 24 hours. Meanwhile, the larger angle between capillary and bottle bottom, the easier the crude oil is driven out. [ABSTRACT FROM AUTHOR]

The sustainable production of sophorolipids (SLs) has promoted the use of alternative agricultural byproducts and residues as nutrient sources. Corn, sunflower, soybean, and rapeseed oilseed cakes have been studied as newer hydrophobic feedstocks for SL production through solid-state fermentation using the wild-type strain of Starmerella bombicola. Maximum sophorolipid production at 0.5-L bioreactors was found to be reached by corn cake (0.743 ± 0.038 gSL g−1Fat i). HPLC analysis revealed that the composition of the hydrophobic substrate influences the profile and distribution of SL congeners. Emulsification and oil displacement tests were performed for the crude extracts showing that emulsification stability is influenced by SLs crude extract concentration. The best-performing oilseed cakes were scaled-up in a 22-L bioreactor demonstrating that the increase in scale by 44 times-maintained SLs production. The temperature influence was discussed, and the reproducibility of the method was confirmed. Outcomes highlighted a linear relation between initial fat concentration and SLs crude extract production. [Display omitted] • Oilseed cakes show potential as viable alternatives to pure oils in SLs production. • Corn and rapeseed oilseed cakes achieved the highest SLs production. • Hydrophobic substrate composition significantly influences SLs congener profile. • SLs produced via SSF exhibit good emulsifying and oil displacement capacities. • Initial fat concentration and SLs production showed a linear relationship. [ABSTRACT FROM AUTHOR]

• A series of thickening copolymers is synthesized via inverse emulsion polymerization, offering ease of handling and promising application prospect. • The copolymer exhibits superior surface and interfacial activity, thickening, thixotropy, temperature and shear resistance, and viscoelasticity. • Application tests indicate that the copolymer's effectiveness in gel-breaking, sand suspension, wettability and oil displacement, making it suitable for integrated fracturing and oil flooding in low permeability reservoirs. Polymer is an essential type of fracturing fluid. Nevertheless, issues such as slow dissolution, high initial viscosity, and challenges in storage, transportation and operation limit its application. To address these issues, a thickened copolymer P(AA-AMPS) was synthesized by inverse emulsion polymerization using acrylic acid (AA) and 2-acrylamide-2-methylpropanesulfonic acid (AMPS) as the monomers. Three P(AA-AMPS) copolymers were obtained by changing the weight ratio of AA and AMPS monomers. When the weight ratio of AA to AMPS monomers was 8.2:1.8, the P(AA-AMPS) copolymer solution exhibited the best interfacial activity, reducing the oil–water interfacial tension to 3.95 mN m−1. The initial viscosity of the copolymer was only 66 mPa s, but its solution could reach a high viscosity of up to 817 mPa s. P(AA-AMPS) copolymers demonstrated good resistance for temperature and shear. For instance, the viscosity of copolymer solution still remained 300 mPa s with a shear rate of 170 s−1 at 90 °C. Furthermore, P(AA-AMPS) copolymers had excellent gel-breaking capacity, sand suspension stability, wettability and oil displacement ability. Therefore, the integration of fracturing and oil flooding can be realized for the development of low permeability reservoirs by selecting appropriate copolymers. P(AA-AMPS) copolymers would play an important role due to their significant viscosity differences and easy operation on storage, transportation and application. [ABSTRACT FROM AUTHOR]

By introducing the natural gas generation system into the foam flooding system, they react with each other, release heat, and generate a large amount of gas.The gas interacts with the foaming agent to generate a large number of fine foams, “blocking big but not small”,inducing non-producing reservoirs, promoting the oil layer is fluidly connected to improve oil and gas recovery and solve the problem of poor displacement effect caused by rapid water cut rise.The preferred self-generating formula is: 2.5% sodium nitrite+2.5% ammonium chloride+3.0% citric acid+1% pH regulator.The preferred foam system is: 0.5% cocamidopropyl betaine+0.1% partially hydrolyzed polyacrylamide, stirring for 1 min at 5 000 r/min, the foam foaming volume is 430 mL,the liquid elution half-life is 120 s, and the defoaming half-life is 500 s.The self-generating foam flooding system can automatically generate bubbles to supplement the formation energy, without the need for special foaming equipment, and it is easy to use on site.200 mL of foam liquid can generate about 830 mL of foam within 15 s, the liquid elution half-life is 122 s, and the defoaming half-life is 494 s, which can fully meet the field requirements, especially suitable for oil displacement in formations with high water content, heterogeneity and low formation pressure. [ABSTRACT FROM AUTHOR]

Carbon dioxide capture, EOR-utilization and storage (CCUS-EOR) are the most practical and feasible large-scale carbon reduction technologies, and also the key technologies to greatly improve the recovery of low-permeability oil fields. This paper sorts out the main course of CCUS-EOR technological development abroad and its industrialization progress. The progress of CCUS-EOR technological research and field tests in China are summarized, the development status, problems and challenges of the entire industry chain of CO2 capture, transportation, oil displacement, and storage are analyzed. The results show a huge potential of the large-scale application of CCUS-EOR in China in terms of carbon emission reduction and oil production increase. At present, CCUS-EOR in China is in a critical stage of development, from field pilot tests to industrialization. Aiming at the feature of continental sedimentary oil and gas reservoirs in China, and giving full play to the advantages of the abundant reserves for CO2 flooding, huge underground storage space, surface infrastructure, and wide distribution of wellbore injection channels, by cooperating with carbon emission enterprises, critical technological research and demonstration project construction should be accelerated, including the capture of low-concentration CO2 at low-cost and on large-scale, supercritical CO2 long-distance transportation, greatly enhancing oil recovery and storage rate, and CO2 large-scale and safe storage. CCUS-EOR theoretical and technical standard system should be constructed for the whole industrial chain to support and promote the industrial scale application, leading the rapid and profitable development of CCUS-EOR emerging industrial chain with innovation.

The occurrence state of oil, gas, and water plays a crucial role in exploring shale reservoirs. In this study, molecular dynamics simulations were used to investigate the occurrence states of these fluids in shale nanopores. The results showed that when the alkane is light oil, in narrow pores with a width less than 3 nm, oil molecules exist only in an adsorbed state, whereas both adsorbed and free states exist in larger pores. Due to the stronger interaction of water with the rock surface, the adsorption of oil molecules near the rock is severely prohibited. Oil/water/gas occurrence characteristics in the water-containing pore study indicate that CO2 gas can drive free oil molecules out of the pore, break water bridges, and change the occurrence state of water. During displacement, the gas type affects the oil/gas occurrence state. CO2 has strong adsorption capacity, forming a 1.45 g/cm3 adsorption layer on the rock surface, higher than oil’s density peak of 1.29 g/cm3. Octane solubility in injected gases is CO2 (88.1%) > CH4 (76.8%) > N2 (75.4%), with N2 and CH4 having weak competitive adsorption on the rock. The investigation of different shale reservoir conditions suggests that at high temperature or low pressure, oil/gas molecules are more easily displaced, while at low temperature or high pressure, they are tightly adsorbed to the reservoir rock. These findings contribute to the understanding of fundamental mechanisms governing fluid behavior in shale reservoirs, which could help to develop proper hydrocarbon recovery methods from different oil reservoirs.

The carbon capture, utilization and storage (CCUS) technique is widely applied in order to solve energy shortages and global warming, in which CO2 storage plays an important part. Herein, the CO2 storage in reservoir pores with a dead-end is investigated using a molecular dynamics simulation. The results indicate that, when a CO2 molecule flows through a reservoir pore towards its dead-end, it is readily captured inside said dead-end. When the pressure difference of the CO2 injection increases, the transport speed of the CO2 becomes faster, and the storage efficiency increases. The rate constants for the absorption of the carbon dioxide at 5 MPa, 10 MPa, and 15 MPa are 0.47 m/s, 2.1 m/s, and 3.1 m/s. With the same main channel, a narrower dead-end with less oil molecules would cause a smaller spatial potential resistance, which would lead to a faster CO2 replacement and storage process. The 3 nm main channel with a 1.5 nm dead-end model had the highest absorption rate of 5.3 m/s out of the three sets of models with different dead-ends. When the dead-end’s width was constant, the rate constants for the absorption of carbon dioxide in the 6 nm main channel with a 1.5 nm dead-end model was 1.8 m/s, which was higher than that of the 3 nm–1.5 nm model. This study investigates the mechanism of CO2 storage in reservoir pores with a dead-end at the molecular level and provides a scientific basis for the practical application of CO2 storage.

The effects of the branched structures of SDBS molecules on oil recovery are investigated by molecular dynamics method. The relative density of oil molecules shows that SDBS molecule with benzene ring located near the center of alkyl chain has the best effect on oil displacement. Dynamic trajectories show that the water and SDBS molecules gradually occupy the calcite surface and replace the oil droplets. In this process, more water molecules gather nearby the polar groups of SDBS, indicating that the polar group has a significant effect on the water infiltration and the formation of water channels. Contact angle between SDBS molecule and calcite surface indicates that compared to straight chains, the branched structure tends to spread on the calcite interface. Moreover, adsorption energies of the simulation systems further prove that as the aromatic ring is closer to the middle of the alkyl chain, the oil displacement effect is better. [ABSTRACT FROM AUTHOR]

Multiphase flows in porous media are widespread in nature and various technologies. One of the most common examples of this kind of task is the task of recovering oil from the rock. This article describes a mathematical model of the flow of a two-phase (immiscible) liquid based on a new approach of network hydrodynamics for a highly branched microchannel medium (simulating a porous space in the rock). The coupling of the flow and pressure fields in the network is performed using a well-proven SIMPLE algorithm in CFD problems; this approach allows us to use effective approaches to modeling 3D tasks. Phase transfer over the network is carried out by an explicit method with an adaptive time step. The article presents the results of verification of the model, with analytical calculations and in comparison with the results of experimental studies. As an experiment, the displacement of oil from a microchip (Dolomite: 3200284) simulating a porous medium was simulated. The good qualitative and quantitative compliance with the results calculated and the results of the experiment show the correct functioning of the model. [ABSTRACT FROM AUTHOR]

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This study explored potential applications of a mixtures of nanoparticles and wormlike micelles as a chemica flooding agent in a specific Bohai Bay Oilfield. Sample preparations were carried out, based on two different zwitterionic surfactants cetylamidopropyl hydroxypropyl sulfobetaine and tetradecyl propyl sulfobetaine. A wormlike micelle which can significantly improve the viscosity in simulatated injected water was prepared, and a nanoparticle wormlike micelle was formed by directly introducing nano silica solid. The results of transmission electron microscope showed that the formation of long cetylamidopropyl hydroxypropyl sulfobetaine/tetradecyl propyl sulfobetaine composite wormlike micelles endowed the water phase with high viscosity. By adjusting the amount of surfactant in the range of 0.2 ∼ 0.5 wt%, the water phase viscosity can be controlled between 10 50 mPa·s. This work provided insights either in developing a new high-efficiency oil displacement agent, or offering a new idea for the rheological study on wormlike micelle agents.

• Crude oil droplet displacement by interfacially active nanoparticles was examined. • Coupling effect between the nanoparticles and low-salinity brines were investigated. • Nanoparticles in monovalent brine synergistically promoted oil droplet dewetting dynamics due to combined structural forces. • The structural forces constructed are salt-induced hydration and nanoparticle-induced structural forces. • Divalent brine severely hindered oil droplet dewetting with cation bridging domination. From the microscopic scale to the petroleum-reservoir scale, the interfacial phenomena of a crude oil–water-rock system crucially control immiscible flow in a porous reservoir. One of the key mechanisms is crude oil droplet displacement dynamics, which can be optimized by manipulating the oil–water interfacial tension and the three-phase contact angle by means of chemical injection. Oil film displacement was enhanced by adding interfacially active nanoparticles, namely poly(N -isopropylacrylamide) or pNIPAM (43–48 nm hydrodynamic diameter and 0.0005–0.0050 wt% concentration range), accelerating the oil droplet receding rate (up to 5.66°/s) and greater degree of oil film dewetting (37.0° contact angle). Such behavior was attributed to nanoparticle-induced structural disjoining pressure between the oil–water and water–solid interfaces. The coupling effect of pNIPAM nanoparticles with low-salinity brines was studied, revealing discrepancy in different valency brines. Coupling with divalent CaCl 2 led to much slower oil droplet receding dynamics (2.58°/s, and 58.7° contact angle) since oil-substrate bridging is formulated and promoted by the divalent cation. However, a positive synergy was observed with a monovalent NaCl blend. The crude oil dewetting dynamics were enhanced (9.55°/s) owing to the combined salt-induced hydration and nanoparticle-induced structural forces. The contact angle reduced to 21.5° before eventually detaching from the substrate after a relatively short period (156 s). These findings highlight the coupling effects of nanoparticles and low-salinity brine to enhance dewetting of heavy crude oil. Adding nanoparticles to an 'optimal' brine could be an option for faster and greater fluid displacement, which is not limited to oil production applications but several others, such as detergency and other forms of geological storage. [ABSTRACT FROM AUTHOR]