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The technological landscape for industrial processes handling asphaltene is evolving at a rapid pace due to the increase in the extraction of heavy crude oil. The main underlying challenges in this regard are the flow assurance, the recovery of the spent solvent, and the sophisticated extractor setup required to develop the process to an industrial scale. The number of studies focused on the handling of the asphaltene at the atomic and molecular scales is growing enormously in order to identify new sustainable solvents for the effective extraction of asphaltene from heavy crude oil or oil-bearing sands. This Perspective focuses on the importance of density functional theory and molecular dynamics simulations to explore the broader range of asphaltene inhibitors, e.g., nanoparticles, ionic liquids, and deep eutectic solvents, to prevent asphaltene precipitation. We provide a concise overview of the major accomplishments, analyze the aspects that require attention, and highlight the path-breaking studies having a significant impact on the process of chemical enhanced oil recovery from heavy crude oil reservoirs primarily based on atomistic and molecular simulations. [ABSTRACT FROM AUTHOR]

Most of the oil reserves have remained unrecovered during primary and secondary recovery scenarios which raise the need for novel and more useful recovery methods to produce the unrecovered oil and increase the recovery factor as an Enhanced oil recovery method. As the most common oil recovery method, the performance of the water injection can be further enhanced by adding polymers to water by the mobility control mechanism. Nanoparticle and nanohybrid flooding are one of those novel methods which can recover oil using wettability alteration and IFT reduction mechanisms. In this study, we synthesized polyacrylamide-based nanohybrids such as graphene oxide (GO)/PAM and carbon nanotube (CNT)/PAM combine the advantages of both nanoparticle and polymer flooding using a novel and simple method. The effect of different mechanisms involved such as wettability alteration, IFT reduction, and mobility control were studied separately in form of contact angle, IFT, and viscosity measurements and in combination with each other in the form of coreflooding tests were studied. The stability of the synthesized nanohybrids against temperature and salinity was investigated using TGA and bulk tests. The effectiveness of these novel nanohybrids was never investigated to this extent. Our investigation showed that GO/PAM nanohybrids had better performance in IFT reduction and mobility control and CNT/PAM in wettability alteration. During coreflooding tests, the GO/PAM showed the highest light and heavy oil recoveries with recovering 63.8% and 28.57%, respectively, in comparison to CNT/PAM with recovery factors of 60.95% and 25.71%. Both of the nanohybrids showed great performance in oil recovery due to wettability alteration and IFT reduction but the GO/PAM showed the best performance because of its higher viscosity which made the mobility control of the injected fluid much better. [ABSTRACT FROM AUTHOR]

The process of injecting carbon dioxide (CO2) into oil reservoirs involves intricate interactions between the reservoir's hydrocarbons and CO2, resulting in changes to various physiochemical properties such as interfacial tension (IFT) between complex acidic hydrocarbons and CO2. The IFT plays a crucial role in enhanced oil recovery by altering capillary force. Hydrocarbon mixtures usually contain a percentage of acidic organic compounds that pose a crucial effect on IFT measurement. In this study, benzoic acid was chosen as a representative of acidic compounds to study the effect of acid number (0.0–0.8 g/L) on the IFT between CO2 and different combinations of diesel fuel (representing aliphatic hydrocarbons) and gasoline (representing aromatic hydrocarbons). The volume ratios of the mixtures were varied at 0:100, 25:75, 50:50, 75:25 and 100:0%. Results revealed that increasing the acid number in gasoline from 0.2 to 0.8 g/L led to a significant change of more than 10 dyne/cm in the IFT between aromatic hydrocarbons and CO2. On the other hand, IFT alteration for aliphatic hydrocarbons was observed to be up to 5 dyne/cm. A new correlation for estimating IFT between CO2 and different hydrocarbons was also proposed with an average relative error of less than 9%. [ABSTRACT FROM AUTHOR]

Optimal core length for enhanced oil recovery (EOR) core flood experiments lacks consensus. Shorter cores are commonly used, but assessing sweep efficiency in mobility control EOR methods, crucial for longer inter-well distances, remains a question. The adequacy of shorter cores in evaluating sweep efficiency in these EOR processes needs attention. Despite the recognized importance of core flood for enhanced oil recovery (EOR) applications, there is no consensus in the literature on the optimal core length to be used in displacement experiments. Therefore, it is important to address the key question "whether the shorter length cores are sufficient for proper sweep efficiency evaluation in mobility control-based EOR processes?". The objective of this study is to investigate the effect of core length on the core-scale sweep efficiency and ultimate recovery for the displacement experiments carried out at different viscosity ratios between injected fluid and residing oil. Two identical core flooding experiments were conducted using cores that have similar porous media properties ensured through chromatography scan (CT) but have different lengths of 3 and 7 inches. Two different viscosity ratio conditions (10, 0.1) were imposed sequentially in each of the core flooding experiments by injecting water at 2 ft/day as a primary slug and then 2,000 ppm HPAM polymer solutions at 0.25 ft/day as the secondary slug. The results suggest that the use of shorter-length cores for displacement experiments under unfavourable viscosity ratio conditions would overestimate the early sweep effect by over 10%. In contrast, polymer flood conducted under favourable viscosity ratio conditions resulted in a higher-pressure gradient of 95 psi and showed only a marginal ∼ 2% difference in the incremental recovery factor between shorter and longer cores from ∼ 0.4 PV to 1.9 PV injections. [ABSTRACT FROM AUTHOR]

Carbon dioxide (CO2) flooding is a widely adopted enhanced oil recovery (EOR) technique known for its ability to displace crude oil effectively by altering its properties. However, in high-temperature Malaysian reservoirs, achieving the minimum miscibility pressure (MMP) for successful miscible flooding can be challenging. This study investigates the potential of using fatty acid methyl esters (FAMEs) derived from biomass sources to lower the MMP in CO2-crude oil systems, thereby enhancing CO2-EOR performance. FAME, renewable and sustainable, presents an innovative alternative to conventional petroleum-based chemicals in EOR. The study involved two types of biomass-derived FAME, sourced from Rubber Seed Oil and Palm Kernel Oil, and two types of crude oil, Tapis and Dulang, tested using the slim tube method at 90 °C and pressures up to 4500 psi. Our findings indicate the presence of Methyl Oleate in Rubber Seed Oil and Methyl Laurate in Palm Kernel Oil, both likely derivatives formed during biodiesel production through transesterification. The MMP for Tapis crude oil was 3620 psi, and for Dulang crude oil, it was 3860 psi, exceeding both the reservoir and fracture pressures of the formation. This can lead to inefficient CO2 injection, reservoir fracturing, and increased costs. However, the addition of 5% vol. FAME to Tapis crude oil demonstrated promise, with Methyl Laurate reducing the MMP by 17.12% and Methyl Oleate by 3.34%. Increasing the concentration of Methyl Laurate to 10% vol. resulted in a substantial 21% MMP reduction. Notably, the presence of waxes and asphaltenes further lowered the MMP compared to pure Tapis crude oil, with Methyl Laurate achieving a 6.42% reduction compared to 17% for Methyl Oleate. In conclusion, this study explores the use of biomass-derived FAME to improve CO2 flooding performance by lowering MMP. The findings suggest that FAME, particularly Methyl Laurate, offers a sustainable solution to address MMP challenges in CO2-based EOR operations, contributing to the advancement of the oil industry in the region. [ABSTRACT FROM AUTHOR]

Due to increasingly stringent global environmental regulations, the petroleum industry must find practical, affordable, and environmentally compliant biopolymers. This study is focused on developing such a biopolymer from orange peels, which exhibits viscous properties and stability in high-salinity and high-temperature (HSHT) reservoirs. The extraction process involved drying, crushing, and grinding orange peels into particulate sizes. These preprocessed peels were then heated in a mixture of water and hydrochloric acid (HCl) before vacuum extracting the yield solution—biopolymer. Parameters that could influence the yield viscosity of the biopolymer, like extraction solvent salinity, HCl concentration, orange peel concentration, peel part—whole or albedo, peel size, and heating, were studied. The highest yield viscosity obtained was 75 cp at a shear rate of 5 s−1 and temperature of 25 °C; this decreased to 20 cp at 90 °C at the same shear rate. The viscosity was 47 cp at 65 s−1 at 25 °C, which decreased to 10 cp at the same shear rate, demonstrating a shear thinning behavior. These results were obtained for powdered whole orange peels with 8% concentration, water salinity of 37,000 ppm, and 5 ml/L of HCl. An environmentally friendly and sustainable enhanced oil recovery (EOR) biopolymer has been successfully extracted from citrus wastes with a viscosity suitable for EOR applications in HSHT reservoirs. [ABSTRACT FROM AUTHOR]

With the global energy consumption on the rise and the gradual decline in conventional oil production, unconventional reservoirs have received considerable attention in the last decade. However, due to the unique physical properties and a large number of micro/nanopores in unconventional reservoirs, fluid flow in these reservoirs is considerably different from conventional ones. Therefore, it is highly important to conduct research on elucidating these fluid flow mechanisms. Furthermore, to avoid problems associated with the rapid production decline and low recovery efficiency in such reservoirs, an enhanced oil recovery technology that can efficiently and economically develop unconventional reservoirs is urgently required. This paper systematically summarizes the current research on flow mechanisms, including capillary imbibition, molecular-scale fluid flow and productivity prediction in unconventional reservoirs, and introduces the enhanced oil recovery and application status of hydraulic fracturing assisted oil displacement technology, along with a brief analysis of their advantages and disadvantages. This study is intended to serve a reference for the efficient development of unconventional reservoirs. [ABSTRACT FROM AUTHOR]

The formation of hydrogen sulfide (H2S) in petroleum reservoirs by anaerobic microbial activity (through sulfate-reducing microorganisms, SRMs) is called biogenic souring of reservoirs and poses a risk in the petroleum industry as the compound is extremely toxic, flammable, and corrosive, causing devastating damage to reservoirs and associated surface facilities. In this paper, we present a workflow and the tools to assess biogenic souring from a pragmatic engineering perspective. The retention of H2S in the reservoir due to the reactions with iron-bearing rock minerals (e.g., siderite) is shown in a theoretical approach here and supported with literature data. Cases are provided for two fields under secondary (waterflooding) and tertiary flooding with microbial enhanced oil recovery (MEOR). The use of the Monte Carlo method as a numerical modeling tool to incorporate uncertainties in the measured physical/chemical/biochemical data is demonstrated as well. A list of studies conducted with different chemicals alone or in combination with various biocides to mitigate biogenic souring provides an overview of potential inhibitors as well as possible applications. Furthermore, the results of static and dynamic inhibition tests using molybdate are presented in more detail due to its promising mitigation ability. Finally, a three-step workflow for the risk assessment of biogenic souring and its possible mitigation is presented and discussed. [ABSTRACT FROM AUTHOR]

Heavy oil accounts for a considerable proportion of the world's petroleum resources, and its exploitation helps to mitigate reliance on conventional oil resources and diversify energy supply. However, due to the high viscosity and high adhesion characteristics of heavy oil, conventional methods such as thermal recovery, emulsification, and dilution have significant limitations and cannot meet the growing demands for heavy oil production. In this study, 3-propyltrimethoxysilane (MPS) was used to modify and graft amphiphilic surfactants (AS) onto nanosilica to prepare a salt-resistant (total mineralization > 8000 mg/L, Ca2+ + Mg2+ > 1000 mg/L) and temperature-resistant (250 °C) nanosilicon viscosity reducer (NSD). This article compares amphiphilic surfactants (AS) as conventional viscosity-reducing agents with NSD. FTIR and TEM measurements indicated successful bonding of 3-propyltrimethoxysilane to the surface of silica. Experimental results show that at a concentration of 0.2 wt% and a mineralization of 8829 mg/L, the viscosity reduction rates of thick oil (LD-1) before and after aging were 85.29% and 81.36%, respectively, from an initial viscosity of 38,700 mPa·s. Contact angle experiments demonstrated that 0.2 wt% concentration of NSD could change the surface of reservoir rock from oil-wet to water-wet. Interfacial tension experiments showed that the interfacial tension between 0.2 wt% NSD and heavy oil was 0.076 mN/m. Additionally, when the liquid-to-solid ratio was 10:1, the dynamic and static adsorption amounts of 0.2 wt% NSD were 1.328 mg/g-sand and 0.745 mg/g-sand, respectively. Furthermore, one-dimensional displacement experiments verified the oil recovery performance of NSD at different concentrations (0.1 wt%, 0.15 wt%, 0.2 wt%, 0.25 wt%) at 250 °C and compared the oil recovery efficiency of 0.2 wt% NSD with different types of demulsifiers. Experimental results indicate that the recovery rate increased with the increase in NSD concentration, and 0.2 wt% NSD could improve the recovery rate of heavy oil by 22.8% at 250 °C. The study of nano-demulsification oil recovery systems can effectively improve the development efficiency of heavy oil. [ABSTRACT FROM AUTHOR]

The combined heat and mass transfer, the so-called thermosolutal convective problem, has become an attractive field of research in many diversified areas. In this paper, for the first time, oscillatory flow analysis has been carried out for triple diffusive viscoelastic fluid flow in a porous medium. A comprehensive model is developed for the modified Darcy–Brinkman–Oldroyd-B fluid, porous medium, Boussinesq approximation, heat and mass transfer across a finite temperature and concentration difference in the chemical potential of two salts. Triple diffusive viscoelastic fluid flows through porous media have grown significantly as this situation occurs in more than a few applications such as improved oil recovery filtration, liquid complex molding, solidification of liquid crystals, cooling of metallic plate in a bath, exotic lubricants and colloidal solutions, polymer processing, chemical and bioengineering industries, among others. The governing coupled nonlinear partial differential equations with boundary constraints represent the modeled flow problem. In addition, these equations are converted into non-dimensional form by employing suitable non-dimensionalizing quantities. The impacts of the pertinent parameters and related dimensionless numbers on the dimensionless velocity, temperature, concentrations, shear stress, heat and mass transfer are examined for both suction and injection cases. It has been found that when the injection level on the heated plate is increased, the shear rate increases for each channel plate. Furthermore, we recognized that the viscoelastic parameters exhibit an opposite kind of behavior on the velocity, temperature, and concentrations fields. [ABSTRACT FROM AUTHOR]

In the enhanced oil recovery (EOR) process, interfacial tension (IFT) has become a crucial factor because of its impact on the recovery of residual oil. The use of surfactants and biosurfactants can reduce IFT and enhance oil recovery by decreasing it. Asphaltene in crude oil has the structural ability to act as a surface-active material. In microbial-enhanced oil recovery (MEOR), biosurfactant production, even in small amounts, is a significant mechanism that reduces IFT. This study aimed to investigate fluid/fluid interaction by combining low biosurfactant values and low-salinity water using NaCl, MgCl2, and CaCl2 salts at concentrations of 0, 1000, and 5000 ppm, along with Geobacillus stearothermophilus. By evaluating the IFT, this study investigated different percentages of 0, 1, and 5 wt.% of varying asphaltene with aqueous bulk containing low-salinity water and its combination with bacteria. The results indicated G. Stearothermophilus led to the formation of biosurfactants, resulting in a reduction in IFT for both acidic and basic asphaltene. Moreover, the interaction between asphaltene and G. Stearothermophilus with higher asphaltene percentages showed a decrease in IFT under both acidic and basic conditions. Additionally, the study found that the interaction between acidic asphaltene and G. stearothermophilus, in the presence of CaCl2, NaCl, and MgCl2 salts, resulted in a higher formation of biosurfactants and intrinsic surfactants at the interface of the two phases, in contrast to the interaction involving basic asphaltene. These findings emphasize the dependence of the interactions between asphaltene and G. Stearothermophilus, salt, and bacteria on the specific type and concentration of asphaltene. [ABSTRACT FROM AUTHOR]

The purpose of the surfactants used is to greatly reduce the interfacial tension between the crude oil and brine, thereby decreasing the capillary number. The resulting oil-in-water emulsions are often grouped according to the Winsor theory. Oil recovery aims to produce Winsor type-III emulsions because they have the lowest interfacial tension values and the most favorable flow properties. The sensitivity of oil–water–surfactant systems to environmental influences (e.g., mixing speed and equilibration time) increases close to the favorable environmental range (temperature, brine total salt concentration, pressure, etc.) of the Winsor III type, the middle microemulsion phase, which is favorable for crude oil recovery. The tests aimed to investigate the quality and quantity of emulsions prepared with surfactants used in enhanced oil recovery (EOR) using an automatic device to characterize and select surfactants for industrial petroleum applications. An essential method for surfactant selection is to study the emulsifying effect and phase behavior. Phase behavior tests and emulsifying effect tests were performed on surfactants and surfactant packages as a function of mixing parameters. The mixing speed and mixing time can influence the results of the phase behavior and emulsifying effect tests, although during the investigations, other parameters were unchanged. [ABSTRACT FROM AUTHOR]

This paper addresses the problem of hydrogen generation from hydrocarbon gases using Steam Methane Reforming (SMR) with byproduct CO2 injected into and stored in a partially depleted oil reservoir. It focuses on the reservoir aspects of the problem using numerical simulation of the processes. To this aim, a numerical model of a real oil reservoir was constructed and calibrated based on its 30-year production history. An algorithm was developed to quantify the CO2 amount from the SMR process as well as from the produced fluids, and optionally, from external sources. Multiple simulation forecasts were performed for oil and gas production from the reservoir, hydrogen generation, and concomitant injection of the byproduct CO2 back to the same reservoir. EOR from miscible oil displacement was found to occur in the reservoir. Various scenarios of the forecasts confirmed the effectiveness of the adopted strategy for the same source of hydrocarbons and CO2 sink. Detailed simulation results are discussed, and both the advantages and drawbacks of the proposed approach for blue hydrogen generation are concluded. In particular, the question of reservoir fluid balance was emphasized, and its consequences were presented. The presented technology, using CO2 from hydrogen production and other sources to increase oil production, also has a significant impact on the protection of the natural environment via the elimination of CO2 emission to the atmosphere with concomitant production of H2. [ABSTRACT FROM AUTHOR]

The evaluation of water-alternating-gas (WAG) efficiency and profitability is complicated by a large number of reservoir, operating, and economic parameters and constraints. This study aims at understanding the influence of the oil composition on different WAG injections. By employing compositional reservoir modeling and the Monte Carlo method to characterize the diversity of oils occurring in nature, we simulate the microscopic displacement efficiency of CO2 flooding when it is applied to both light- and heavy-oil reservoirs. We find that the economic performance of WAG in both miscible and immiscible scenarios is mainly characterized by the dimensionless injection rate and the oil density at surface conditions. Neither the bubble point pressure nor the minimum miscibility pressure can be used for the quantification of the optimal WAG parameters. We present our estimates of the best strategies for the miscible and immiscible injections and verify some of our previous results for randomly sampled oils. In particular, we demonstrate that CO2 flooding is better to apply at higher-dimensionless injection rates. We show that the injection of CO2 organized at a light-oil reservoir results in a higher profitability of WAG, although this comes at the cost of lower carbon storage efficiency. [ABSTRACT FROM AUTHOR]

The development of oil and gas resources in low-permeability reservoirs is being paid more and more attention. Moreover, oil and gas resources in low-permeability reservoirs are affluent, and the water cut of the medium permeability layer is so high that the injection capacity has decreased significantly. Therefore, it is of great importance to address the issues of injectability and enhance oil recovery in low-permeability reservoirs. Given the existing conditions of low permeability and high water cut in Daqing Oilfield, the synthesis of an in situ emulsified associative polymer (ISEPAM) is the focus of the research. The polymer was prepared by micellar polymerization, ensuring a molecular weight of 5 × 106 Dalton. A series of experiments were conducted to investigate its dissolution filtration property, viscosifying, emulsification, anti-adsorption, conductivity, and oil displacement capacity. The experimental results show that ISEPAM has more significant properties than the polymeric surfactant (HB) used in Daqing Oilfield. The ISEPAM solution has significant filterability (filter factor is 1.1), viscosifying (38.66 mPa·s), emulsification (the water evolution rate of ISEPAM was only 4.4% for 60 min at 90% water cut), and good anti-adsorption property (after five adsorptions, still has a viscosity retention rate of 65%) in a specific concentration (1000 mg/L) and the field water in Daqing Oilfield (salinity is 4996.3 mg/L). The reason for this is due to the presence of dynamic reversible networks in the ISEPAM solution, and there are no cationic functional groups on the polymer chain. The conductivity of ISEPAM was tested using a homogeneous square core with 48.1 mD permeability, and the results show that the viscosity retention rate of the effluent can reach 90% and excellent injection property can be achieved. In the oil displacement test, ISEPAM presents excellent sweep efficiency and enhanced oil recovery by about 25% under 50 mD permeability. Under low permeability conditions, the ISEPAM exhibits better injectability and excellent oil displacement capacity. The related findings can provide an important idea and reference for the design and development of EOR polymers in the reservoirs with low permeability or high water cut. [ABSTRACT FROM AUTHOR]

Shale gas is an extremely important unconventional oil and gas resource, and its efficient development can effectively alleviate the current tense energy situation. However, shale gas reservoirs often have extremely poor permeability, and reservoir transformation has become a key technology for achieving their efficient development. However, the commonly used hydraulic fracturing technology is difficult to achieve its target production capacity, and other engineering technologies related to reservoir transformation urgently need to be proposed and attempted. The synergistic operation of oxidation dissolution and acid fracturing may provide new ideas for the effective transformation of shale reservoirs. To this end, a comparative analysis was conducted on the synergistic effects of oxidation dissolution and acid fracturing operations in improving shale gas production capacity. The research results indicate that the dissolution effect of oxidants is more effective than acid solution in the transformation process of shale reservoirs. The use of acid only widens the crack width from the initial 4.4 mm to the final 5.1 mm. However, the use of oxidants will result in the final width of hydraulic fractures reaching 8.3 mm. Meanwhile, the effects of acid concentration and oxidant concentration on hydraulic fracture conductivity and shale gas production capacity were investigated. The results indicate that increasing the acid concentration below the low concentration range can significantly enhance the fracture conductivity, thereby promoting the production capacity of shale gas. However, within a higher concentration range, its effect on shale gas production is significantly limited. It is recommended to set the acid concentration design value at 0.5 wt% during the acidizing and fracturing reservoir transformation process of the shale gas reservoir in Changning block. In addition, an increase in the concentration of oxidants can widen the width of fractures and increase permeability, thereby promoting the migration and extraction of shale gas. To avoid the increase in development costs caused by high oxidant concentration in the working fluid, it is recommended to design the oxidant concentration at 3 wt%. [ABSTRACT FROM AUTHOR]

This study investigates the catalytic effects of Nickel-ligated catalysts derived from tall oil (NiTO) and sunflower oil (NiSFO) on the oxidation of heavy oil. Thermogravimetric (TG) analysis were employed to assess the thermal behavior and kinetics of heavy oil degradation. The Friedman isoconversional method provided the activation energies (Ea), which were then used to derive thermodynamic parameters including changes in enthalpy (ΔH), entropy (ΔS), and Gibbs free energy (ΔG). The TG analysis revealed that both NiTO and NiSFO influence the degradation kinetics of heavy oil. Moreover, NiTO exhibited a consistent catalytic effect across a wide range of conversions, lowering the onset temperature of degradation and promoting faster degradation rates, which suggests a rapid breakdown at lower temperatures. Conversely, NiSFO demonstrated a substantial decrease in activation energy at mid-range conversions, indicating a highly efficient catalysis during these stages. In addition, thermodynamic analysis indicated that both catalysts alter the energetic profile of the reaction. Notably, NiSFO reduced ΔG significantly at lower conversions, enhancing the spontaneity of the reaction, while NiTO was associated with lower ΔG values across most conversions, implying a more favorable reaction throughout the process. The findings suggest that the choice of catalyst can be tailored based on the desired conversion range and reaction spontaneity in industrial heavy oil processing. These insights could be crucial for optimizing thermal treatments in heavy oil upgrading, offering potential improvements in the efficiency of in-situ combustion and enhanced oil recovery technologies. [ABSTRACT FROM AUTHOR]

After volumetric fracturing, the conventional recovery methods for tight oil reservoirs rely on natural energy depletion. However, the production rate rapidly declines due to their intricate characteristics, such as threshold pressure gradient (TPG), stress sensitivity, and multi-scale porous media. This study plotted permeability loss charts based on stress sensitivity experiments. A pressure distribution equation incorporating TPG and flow in different regions was developed, and production prediction methods for tight oil reservoirs were established. The results revealed the effects of TPG and multi-region flow on pressure distribution, demonstrating the need to control bottom hole pressure (BHP) in tight oil reservoirs. Accordingly, methods to improve tight oil reservoir development were proposed by controlling BHP. Reducing BHP, increasing the imbibition displacement, and improving oil-phase mobility proved conducive to enhanced oil recovery. The development model featuring BHP control for 1000 days with initially rapid and subsequently slower BHP declines demonstrated the highest recovery rate, surpassing depletion development by 7.404%. This research helps us to optimize tight oil reservoir development plans while offering significant practical guidance for developing similar oil reservoirs, which is of the reference value for the industry. [ABSTRACT FROM AUTHOR]

Molecular diffusion is critical for enhanced oil recovery (EOR) in shale oil reservoirs with complex fracture networks. Understanding the influence of fractures on diffusive mass transfer is crucial for predicting oil recovery and remaining oil distribution. Diffusive mass transfer between fractures and matrix is critical in comprehensively and effectively simulating molecular diffusion. Resolution of matrix cells significantly affects diffusion accuracy at the fracture–matrix interface. Low resolution results in multiple fractures in the same matrix cell, leading to decreased precision in calculating mass transfer by conventional methods. To address this, a novel multiphase and multicomponent model is proposed. The new model integrating the consideration of fracture spacing modifies molecular diffusion transmissibility between fracture and matrix in an embedded discrete fracture model. The discretization employs the two-point flux approximation in the finite-volume method. Validation compares the coarser mesh to the finest grid as a reliable reference. Results show the proposed model accurately captures diffusive mass transfer in a coarser mesh. Modified models study molecular diffusion's effects on EOR in shale oil reservoirs with complex fracture networks by CO2 huff and puff. Results indicate that increasing injection rates cannot improve oil recovery under extremely low porosity and permeability. Molecular diffusion facilitates CO2 penetration into the formation. This expands the swept CO2 volume and increases both volume expansion and formation energy. In addition, the light and heavy components of the crude oil are diffused into the fractures and eventually produced, which reduces gas production in the case of diffusion. [ABSTRACT FROM AUTHOR]

Understanding the detachment dynamics of droplets adhered to reservoir walls holds significant importance for the residual oil displacement process in high water-cut oilfields. Existing studies demonstrated that increasing mainstream shear by adjusting displacement flow and weakening wall adhesion by increasing contact angle can enhance droplet detachment. However, the complex physical and chemical oil–wall interactions, a crucial reservoir feature, cannot be solely relied on the macroscopic representation through contact angle. A deviation in understanding the process of crude oil droplet detachment would be resulted due to the change of wall adhesion. Considering the intricate physical and chemical interactions between oil and walls, in this paper, we employed the extended Derjaguin–Landau–Verwey–Overbeek (EDLVO) theory to establish an oil–wall interaction forces system, and coupling computational fluid dynamics method to further explore the detachment dynamics of sessile oil droplets in a microchannel under varying EDLVO forces. The findings showed that (1) by increasing the Capillary number, the droplets gradually occur in four typical dynamic states: static, sliding, detachment, and pinch-off. (2) Static droplets are more prone to experience sliding behavior when influenced by EDLVO forces. (3) For droplets undergoing detachment and pinch-off, EDLVO forces inhibit entrainment behavior. These results contribute to an enhanced comprehension of droplet detachment dynamics in reservoirs, offering fresh insights for enhanced oil recovery strategies. [ABSTRACT FROM AUTHOR]

Nowadays, there has been a recognition of the remarkable potential of nanofluids and microorganisms as eco-friendly agents for enhanced oil recovery. on the other hand, one of the unique strategies for boosting hydrocarbon recovery is altering the wettability of the rock surface of oil and gas reservoirs. Herein, a nanohybrid that combines graphene oxide (GO) and silica (SiO2) was synthesized using a low-temperature, facile, and eco-friendly approach (sol-gel). GO-SiO2 nanocomposite was characterized with the aid of XRD, SEM, and FTIR analyses. Afterward, Nanofluids with different concentrations (0.005, 0.01, 0.015, and 0.02 wt%) of GO-SiO2 nanocomposite at various ratios (1:1, 1:2, and 2:1) were prepared using a surfactant-free and pH-neutral approach with a salinity of 30,000 ppm. The results of the Zeta potential measurement reveal that the manufactured nanofluids have great stability and the ratio of 1:1 was the most effective ratio for improving the reservoir wettability change from oil-wet to water-wet. At a higher temperature of 80 °C compared to the ambient condition of 25 °C, a more significant change in wettability was observed (23° to 161°). At the optimal concentration of nanofluid (0.015 wt%), the contact angle increased from 23° (on a non-treated surface) to 161°. These findings suggest that GO-SiO2 has great potential as an affordable, flexible, and environmentally friendly natural nanofluid, particularly under harsh conditions for the EOR process. [ABSTRACT FROM AUTHOR]

This study intends to assess the heat transmission of a steady two-dimensional MHD Casson nanofluid flow across a non-linearly stretching sheet concerning viscous dissipation, heat generation, thermal radiation, and chemical radiate parameters. Mathematically, the flow is outlined as PDE systems, converted to ODE systems by a well-posed transformation, which are afterwards solved numerically in Matlab employing the fourth-order precision program (Bvp4c). The comparison indicates adequate agreement, demonstrating the correctness of the numerical strategy. It is observed that in the existence of a chemical reaction, the temperature is elevated, while the concentration profile is markedly reduced, in contrast to a scenario where no chemical reaction is taking place. In consideration of viscosity, heat radiation, thermophoresis impact, and suction or injection parameter, the Nusselt number reveals a growing tendency. In contrast, it exhibits opposing behavior with regard to the other addressed factors. The findings of this study have applications in the engineering, biomedical and industrial sectors, including food processing, polymer making, glass and fiber production, material processing, and enhanced oil recovery. [ABSTRACT FROM AUTHOR]

New approaches to low salinity water (LSW) injection methods, such as LSW/surfactant, LSW/polymer, and LSW/nanofluid flooding, have been studied for oil reservoirs. Numerous researchers discussed the mechanisms related to enhanced oil recovery (EOR) efficiency and highlighted the significant impact of the wettability alteration and interfacial tension (IFT) reduction. This work studied the effect of exposure time on the wettability alteration and IFT in the LSW/nanoparticle (LSWN) flooding. Contact angle tests investigated rock wettability over a series of different times. A pendant drop tensiometer was used to measure the IFT. By coreflood apparatus, waterflood tests were also conducted, considering the effect of soaking time. Laboratory results showed that the involved mechanisms are time-dependent. More water-wet conditions and higher oil recovery were obtained under longer soaking time. In addition, the positive effect of LSWN was observed in tertiary flooding tests. The results also indicate that the effect of water-soluble oil compounds should be considered in measuring wettability and IFT. [ABSTRACT FROM AUTHOR]

Carbonate reservoirs hold vast oil reserves, but their complex properties make traditional enhanced oil recovery (EOR) methods challenging. This study explores the application of low-salinity water flooding (LSWF) as a novel EOR method for India's largest offshore carbonate oil field. Conventional EOR techniques were deemed unsuitable due to reservoir heterogeneity, pressure decline, high temperature, and the offshore location. Favorable factors for LSWF included successful seawater flooding history, medium-weight crude oil, and existing infrastructure. Following core flooding experiments demonstrating a 6–16% increase in oil recovery, a multi-pronged evaluation process was implemented. Single-well chemical tracer tests (SWCTT) and reservoir simulations confirmed the potential of LSWF. A specific target area was chosen based on reservoir characteristics, production data, and available facilities. Simulations predicted a 1.5% incremental oil recovery using diluted seawater (25% salinity) at 30% pore volume injection. After a positive techno-economic analysis, the first offshore LSWF project in India was completed within 3 years. Initial monitoring results are encouraging. This study highlights the successful journey of LSWF from concept to field deployment in a challenging carbonate reservoir, showcasing its potential for revitalizing such fields. Furthermore, this work provides valuable data relevant to Indian offshore environments, where factors like salinity, mineralogy, and crude oil composition pose unique challenges compared to other LSWF applications. These detailed data fill a critical gap in the existing literature. [ABSTRACT FROM AUTHOR]

Enhancing oil recovery through surfactants has proven to be a successful strategy in recent times. However, traditional surfactants have their limitations, particularly in terms of stability under high temperatures and salinity levels. This study delved into a groundbreaking macromolecular polymeric surfactant, S‐AV, which holds the unique ability to transform rock surface characteristics, effectively stripping away residual oil while maintaining resilience against elevated temperatures and salinity. S‐AV was synthesized through a free‐radical copolymerization process, incorporating benzyl, perfluoroalkyl, alkyl‐, benzyl‐, ethylene glycol, and amide‐alkyl‐sulfonate groups, ultimately yielding a comb‐like molecular structure. S‐AV demonstrated exceptional prowess, swiftly reducing the underwater oil contact angle to 53.4° in just 48 h. This synthesized surfactant also retained its phase stability up to salinity levels of 36,000 ppm, with temperature having no disruptive impact on its phase stability performance. Furthermore, S‐AV showcased remarkable viscosity reduction in conditions of high temperature and salinity. The core flooding experiments underscored the potential of S‐AV, as its injection led to a significant oil recovery rate of up to 83%. These findings position S‐AV as a promising candidate for practical enhanced oil recovery applications. [ABSTRACT FROM AUTHOR]

In this study, a novel high‐temperature and high‐pressure foam evaluator with variable diameters inner cell and cylinder flip function was designed on our own, which can solve the problems such as difficulties in foam generation and inaccurate determination of various foam parameters by the same type of instruments, through which the foaming performance of more than 10 betaine surfactants was evaluated. The results show that: (1) the higher the pressure, the higher the foaming rate of the foaming agent and the more stable the foam, but the foam stability of the foamers at low and high pressures, and low and high temperatures do not correspond exactly, and the foaming agent used needs to be screened under simulated reservoir conditions. (2) The comprehensive foaming performance of different types of foamers with different molecular structures found that hydroxy sulfobetaine with longer carbon chains has a relatively better foaming performance. Therefore, for the reservoir conditions of temperature 130°C, pressure 30 MPa, and salinity 22 × 104 mg/L, hydroxy sulfobetaine, which does not contain an amide group in the molecule, can be considered preferentially as a foaming agent. The results can guide the selection of foaming agents for high‐temperature and high‐salinity reservoirs. [ABSTRACT FROM AUTHOR]

To understand the effect of the spontaneous imbibition (SI) and waterflooding on oil recovery in the tight sandstone reservoirs, we selected three pairs of tight sandstone samples from the Ordos Basin in China to conduct the SI-plus-waterflooding and waterflooding-only experiments, and monitor the oil distribution and flow characteristics by using the low-field nuclear magnetic resonance (NMR) technology. One interesting observation was that oil extracted in the SI process mainly comes from macropores and micropores, which doesn't agree with the previous results wherein oil was produced from micropores, and oil was produced from the mesopores during the waterflooding after the SI process. The oil recovery factor of tight sandstone samples in the process of the SI-plus-waterflooding was more than 50%, and even more than 85%, which was greater than that in the waterflooding-only process. Moreover, we found that our tight sandstone samples behaved lower residual oil saturation, and wider oil-water two-phase co-flow region during the SI-plus-waterflooding process than that did during the waterflooding-only process. These differences in behavior appear to be linked to the fluid dynamic characteristics and capillary pressure acting on the flow fluid during the two processes. In summary, the SI-plus-waterflooding overcame the limitations related to waterflooding-only and further improved oil recovery factor in the tight sandstones. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery (EOR) by surfactant flooding has been attractive. Among the surfactants developed alcohol polyoxypropylene (PO)‐polyoxyethylene (EO) ether sulfates (APES), also named extended surfactants, have been proved efficient. However, the arrangement of the PO and EO chains as well as the hydrocarbon structure in the molecules may significantly affect their performances. In this paper three APES, C18−16PO25EO10SO4Na (I), C18−16(PO/EO)25+10SO4Na (II), and C16GA(PO/EO)25+10SO4Na (III) were prepared and investigated, in which APES (I) and APES (II) were designed to have same PO and EO numbers but block and randomly copolymerized respectively with linear C18−16 fatty alcohols as starting agent, whereas the APES (III) was derived from double chain C16 Guerbet alcohol (C16GA) with PO and EO randomly copolymerized. The results show that the block copolymerized APES (I) gives much better brine solubility and counterion tolerance than the randomly copolymerized APES (II) and (III). Although all APES synthesized are highly surface‐active and can reduce Daqing crude oil/simulated brine interfacial tension (IFT) to ultralow by mixing with more hydrophobic surfactants in presence or absence of alkali, the APES (III) gives the lowest IFT due to with double hydrocarbon chains. In addition, it is found that for APES (I) gelation occurs in neutralization process and the corresponding nonionic intermediate is highly viscous, whereas the randomly copolymerized two intermediates are liquid‐like with low viscosity, which may be feasible to apply SO3/air falling film sulfation. This study provided useful information for arrangement of embedded nonionic moiety and hydrocarbon structure in designing extended surfactants for EOR. [ABSTRACT FROM AUTHOR]

After decades of water-driven development, the conglomerate reservoir in Karamay, Xinjiang, is plagued by issues such as highly dispersed residual oil and a low oil recovery rate. To create various binary composite systems, polymeric partially hydrolyzed polyacrylamide (HPAM), low tension surfactant PS-30, and strong emulsifying surfactant OP-10 were chosen. The long sand pipe model was used to investigate the application limits and recovery enhancement limits of the composite drive system in conglomerate reservoirs with varying permeability, replacement methods, and injection volumes. The experimental results show that the binary composite flooding can effectively replace residual oil, expand the wave volume, and significantly improve the recovery rate of a conglomerate reservoir. The recovery rate of compound drive is 66. 31%, which is 21. 85 percentage points greater than that of water flooding when the polymer concentration is 1 000 mg / L and the relative molecular mass is 7 × 106 at a permeability of 3 × 10-2 μm² . The recovery rate is improved more by the strong emulsification composite system than by the low tension composite system. The higher the injection volume of the composite system, the greater the recovery improvement, but the magnitude of the recovery improvement is not linear. After the injection volume of the composite system reaches 3. 5 PV, the recovery improvement value of the composite system gradually stabilizes, and the highest recovery improvement magnitude of the composite flooding system reaches 40. 38 percentage points after the injection of 10 PV. [ABSTRACT FROM AUTHOR]

One of the main challenges in screening of enhanced oil recovery (EOR) techniques is the class imbalance problem, where the number of different EOR techniques is not equal. This problem hinders the generalization of the data-driven methods used to predict suitable EOR techniques for candidate reservoirs. The main purpose of this paper is to propose a novel approach to overcome the above challenge by taking advantage of the Power-Law Committee Machine (PLCM) technique optimized by Particle Swam Optimization (PSO) to combine the output of five cutting-edge machine learning methods with different types of learning algorithms. The PLCM method has not been used in previous studies for EOR screening. The machine learning models include the Artificial Neural Network (ANN), CatBoost, Random Forest (RF), K-Nearest Neighbors (KNN), and Support Vector Machine (SVM). The CatBoost is used for the first time in this work for screening of EOR methods. The role of the PSO is to find the optimal values for the coefficients and exponents of the power-law model. In this study, a bigger dataset than those in previous studies, including 2563 successful worldwide EOR experiences, was gathered. A bigger dataset improves the generalization of the data-driven methods and prevents overfitting. The hyperparameters of the individual machine-learning models were tuned using the fivefold cross-validation technique. The results showed that all the individual methods could predict the suitable EOR method for unseen cases with an average score of 0.868. Among the machine learning models, the KNN and SVM had the highest scores with a value of 0.894 and 0.892, respectively. Nonetheless, after combining the output of the models using the PLCM method, the score of the predictions improved to 0.963, which was a substantial increase. Finally, a feature importance analysis was conducted to find out the most influential parameters on the output. The novelty of this work is having shown the ability of the PLCM technique to construct an accurate model to overcome the class-imbalance issue in EOR screening by utilizing different types of data-driven models. According to feature importance analysis, oil gravity and formation porosity were recognized as the most influential parameters on EOR screening. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery (EOR) by in situ formation of oil-in-water emulsion in heavy oil cold production technology has received growing interest from the petroleum industry. We present an experimental study of emulsification of model oils prepared by heavy oil and its functional group compositions dissolved into toluene brought into contact with a surfactant solution. The effects of functional group composition, emulsifier concentration, temperature, pH and stirring speed on the emulsification rate of heavy oil was investigated. A second-order kinetic model characterizing the temporal variation of conductivity during the emulsification has been established. The results show that acidic and amphoteric fractions exhibit higher interfacial activity, larger emulsification rate constant and faster emulsification rate. With the increase of emulsifier concentration, the emulsification rate constant increase to the maximum value at a concentration of 0.05 mol/L before decreasing. Temperature increase benefits the emulsification rate and the activation energy of the emulsification process is 40.28 kJ/mol. Higher pH and stirring speed indicate faster emulsification rate. The heterogeneity of emulsions limits the accuracy of dynamic characterization of the emulsification process and the determination method of emulsification rate has always been controversial. The conductivity method we proposed can effectively evaluates the emulsification kinetics. This paper provides theoretical guidance for an in-depth understanding of the mechanism and application of cold recovery technology for heavy oil. [ABSTRACT FROM AUTHOR]

Self–emulsification can be accomplished by enhanced oil recovery (EOR), the realization of the exploration of natural emulsifiers, which is a crucial task to understand the mechanism of crude oil self–emulsification, albeit it is, of course, accompanied by difficulties, during the development of shale crude oil. In this study, we separated the active components of crude oil, and with the help of modern characterization and laboratory tests, coupled with nuclear magnetic resonance of core flooding method, we fully explored the independent and synergistic effects of crude oil active components, and deepened the understanding of the mechanism of crude oil self–emulsification. Among the active components of crude oil, asphaltene and resin have vital effects on its self–emulsification, which is shown in the amphiphilic structure of asphaltene and the effect of resin solvent. Asphaltene can reduce oil–water interfacial tension to 19 mN/m, and the resin significantly increase the viscosity of emulsion. Meanwhile, resin and asphaltene stabilize the viscoelasticity of oil–water interface films and affect the phase transition of emulsions in different water oil ratio environment. As a result, the active components of crude oil are closely related to formation and stabilization of the emulsion, which together endue the inherent conditions of its self–emulsification. Core flooding test confirmed that some emulsions in nanoscale size are produced in shale porous media, and the average emulsion diameter size is 181 nm. This study explored the effects of natural emulsifiers on the self–emulsification of crude oil, thereby promising new potential opportunities for EOR of shale oil. Static experiment and core flooding test indicated that asphaltene and resin reduce the oil–water interfacial energy, and aromatic and saturated hydrocarbons stabilize the viscoelasticity of the oil–water interface to synergestically produce nanoscale emlusions in shale porous media. [ABSTRACT FROM AUTHOR]

Scleroglucan (SG) is resistant to harsh reservoir conditions such as high temperature, high shear stresses, and the presence of chemical substances. However, it is susceptible to biological degradation because bacteria use SG as a source of energy and carbon. All degradation effects lead to viscosity loss of the SG solutions, affecting their performance as an enhanced oil recovery (EOR) polymer. Recent studies have shown that nanoparticles (NPs) can mitigate these degradative effects. For this reason, the EOR performance of two new nanohybrids (NH-A and NH-B) based on carboxymethyl-scleroglucan and amino-functionalized silica nanoparticles was studied. The susceptibility of these products to chemical, mechanical, and thermal degradation was evaluated following standard procedures (API RP 63), and the microbial degradation was assessed under reservoir-relevant conditions (1311 ppm and 100 °C) using a bottle test system. The results showed that the chemical reactions for the nanohybrids obtained modified the SG triple helix configuration, impacting its viscosifying power. However, the nanohybrid solutions retained their viscosity during thermal, mechanical, and chemical degradation experiments due to the formation of a tridimensional network between the nanoparticles (NPs) and the SG. Also, NH-A and NH-B solutions exhibited bacterial control because of steric hindrances caused by nanoparticle modifications to SG. This prevents extracellular glucanases from recognizing the site of catalysis, limiting free glucose availability and generating cell death due to substrate depletion. This study provides insights into the performance of these nanohybrids and promotes their application in reservoirs with harsh conditions. [ABSTRACT FROM AUTHOR]

In this study, the effect of salinity on the enhanced oil recovery process in the presence of commercial silica nanoparticles and a new synthesized polymeric ZnO/SiO2/Xhantan nanocomposites (NCs) at reservoir conditions were investigated. First, the crystal structure and morphology of the NCs were investigated using x-ray diffraction, Scanning electron microscopy, Fourier transform infrared spectroscopy, Brunauer–Emmett–Teller, and energy-dispersive x-ray. Then, the effect of silica nanoparticles and NCs on the change of wettability and interfacial tension at different salinities and reservoir conditions was studied. For 2 SW (seawater) and 10 SW (two times diluted seawater), silica and NCs decreased contact angle from (79 °, 75 °) to (78 °, 74 °) and (70 °, 62 °), respectively. Zeta potential results are −31.37 and −28.00 for 10 SW and 2 SW concentrations, which show the perfectly stable and relatively stable regions, respectively. Moreover, interfacial tension was decreased more in the presence of 10 SW in comparison to 2 SW, and the oil recovery at 2 SW and 10 SW concentrations were 51.71% and 70.25%, respectively, at 0.05 wt% NCs concentration which main reasons are improving wettability, interfacial tension, and stability. [ABSTRACT FROM AUTHOR]

Polyacrylamide, silica, and other nanoparticles have all been realized in the field of enhanced oil recovery. Researchers often explore the mechanisms of spreading behavior and simulated displacement to develop more efficient types of nanoparticles. In this study, copper quantum dots were introduced into a acrylamide copolymerization system to obtain composite nanospheres and its structure, topographic, and application performance were characterized. The results show that the composite nanospheres have a particle size of around 25 nm, are uniformly loaded with copper particles, and have good temperature resistance. The spreading ability on the quartz flake surfaces and displacement effect in microchannels of composite nanospheres, acrylamide copolymer nanospheres, and copper quantum dots were compared by nanofluid spreading experiments and microchannel chip oil displacement experiments. The results indicate that the composite nanospheres can effectively reduce the water contact angle, promote the spreading of aqueous phase, and accelerate the oil droplet removal process; the accelerating effect is stronger than other samples. Its oil displacement effect is also the strongest, and it is minimized by the influence of channel size, temperature, and dispersing medium, with better stratigraphic adaptability. This work supports the practical application of copper quantum dot/polyacrylamide composite nanospheres in the oilfield. [ABSTRACT FROM AUTHOR]

Polymer flooding has achieved considerable success in medium–high permeability reservoirs. However, when it comes to low-permeability reservoirs, polymer flooding suffers from poor injectivity due to the large molecular size of the commonly used high-molecular-weight (high-MW) partially hydrolyzed polyacrylamides (HPAM). Herein, an amphiphilic polymer (LMWAP) with a low MW (3.9 × 106 g/mol) was synthesized by introducing an amphiphilic monomer (Allyl-OP-10) and a chain transfer agent into the polymerization reaction. Despite the low MW, LMWAP exhibited better thickening capability in brine than its counterparts HPAM-1800 (MW = 1.8 × 107 g/mol) and HPAM-800 (MW = 8 × 106 g/mol) due to the intermolecular hydrophobic association. LMWAP also exhibited more significant shear-thinning behavior and stronger elasticity than the two counterparts. Furthermore, LMWAP possesses favorable oil–water interfacial activity due to its amphiphilicity. The oil–water interfacial tension (IFT) could be reduced to 0.88 mN/m and oil-in-water (O/W) emulsions could be formed under the effect of LMWAP. In addition, the reversible hydrophobic association endows the molecular chains of LMWAP with dynamic association–disassociation transition ability. Therefore, despite the similar hydrodynamic sizes in brine, LMWAP exhibited favorable injectivity under low-permeability conditions, while the counterpart HPAM-1800 led to fatal plugging. Furthermore, LMWAP could enhance oil recovery up to 21.5%, while the counterpart HPAM-800 could only enhance oil recovery by up to 11.5%, which could be attributed to the favorable interfacial activity of LMWAP. [ABSTRACT FROM AUTHOR]

Surfactant huff-n-puff (HnP) has been shown to be an effective protocol to improve oil recovery in tight and ultratight reservoirs. The success of surfactant HnP for enhanced oil recovery (EOR) process depends on the efficiency of the designed chemical formula, as the formation of an in situ microemulsion by surfactant injection is considered to be the most desirable condition for achieving an ultra-low interfacial tension during the HnP process. In this work, we conducted experimental studies on the mechanism of in situ microemulsion EOR in the Mahu tight oil reservoir. Salinity scan experiments were carried out to compare different surfactants with crude oil from the Mahu reservoir, starting with the assessment of surfactant micellar solutions for their ability to form microemulsions with Mahu crude oil and examining the interfacial characteristics. Subsequently, detailed micromodels representing millimeter-scale fractures, micron-scale pores, and nano-scale channels were utilized to study the imbibition and flowback of various surfactant micellar solutions. Observations of the in situ microemulsion system revealed the mechanisms behind the enhanced oil recovery, which was the emulsification's near-miscibility effect leading to microemulsion formation and its performance under low-interfacial-tension conditions. During the injection process, notable improvements in the micro-scale pore throat heterogeneity were observed, which improved the pore fluid mobility. The flowback phase improved the channeling between the different media, promoting a uniform movement of the oil–water interface and aiding in the recovery of a significant amount of the oil phase permeability. [ABSTRACT FROM AUTHOR]

Surfactant-assisted spontaneous imbibition is an important mechanism in enhanced oil recovery by capillary pressure in low permeability and tight oil reservoirs. Though many experiments have been conducted to study the mechanism of enhanced oil recovery by surfactant-assisted spontaneous imbibition, the effects of surfactant type, concentration, and temperature have not been well studied. Using tight sandstone outcrop core samples with similar permeability and porosity, this paper experimentally studies surfactant-assisted spontaneous imbibition using three different surfactant types, i.e., sodium dodecylbenzene sulfonate (SDBS), cocamidopropyl betaine (CAB), and C12–14 fatty alcohol glycoside (APG). In addition to the type of surfactant, the effect of the surfactant concentration and the temperature is also investigated. The study results show that the ultimate oil recovery of spontaneous imbibition with formation water and denoised water is about 10%. Surfactant can significantly improve the oil recovery of spontaneous imbibition by reducing the interfacial tension between oil and water, emulsifying crude oil and improving oil mobility. APG showed better performance compared to SDBS and CAB, with a maximum oil recovery factor of 36.19% achieved with formation water containing 0.05% APG surfactant. Lower concentrations (0.05% APG) in the formation water resulted in a higher oil recovery factor compared to 0.1% APG. Increasing temperature also improves oil recovery by reducing oil viscosity. This empirical study contributes to a better understanding of the mechanism of surfactant-assisted spontaneous imbibition and enhanced oil recovery in tight oil reservoirs. [ABSTRACT FROM AUTHOR]

A novel hyperbranched polymer with polyacrylamide side chains (HAPAM) was synthesized by aqueous solution polymerization using acrylic acid, acrylamide, 2-acrylamido-2-methyl-1-propanesulfonic acid, hydrophobic monomer of dimethyl octadecyl ammonium chloride, and the homemade skeleton monomer of modified-M2.0 as raw materials and (NH4)2S2O8-NaHSO3 as initiator. The molecular structure, functional groups, and surface morphology of HAPAM were characterized by Fourier transform infrared spectroscopy, nuclear magnetic resonance hydrogen spectroscopy, and scanning electron microscopy. It was found that the performance of HAPAM solution was higher than that of ordinary polyacrylamide solution in terms of thickening ability, shearing resistance, thermal endurance, salt-resistance, resistance-coefficient and residual-resistance-coefficient, ability to reduce interfacial tension between polymer solution and crude oil, and oil-displacement-efficiency. In particular, the enhanced oil recovery of the HAPAM solution was 13.03%, and the improvement of shearing resistance and immunity to chromatographic separation were simultaneously achieved by the HAPAM solution. These results indicate that the successful synthesis of the novel HAPAM opens a promising strategy for developing new high-performance oil-displacing polymers. [ABSTRACT FROM AUTHOR]

The viscosity ratio of polymer and oil is a crucial factor for polymer flooding, which can affect the water–oil mobility ratio and oil recovery. However, for high-temperature and high-salinity reservoirs, the reasonable viscosity ratio limit of polymer flooding under the condition of medium–high permeability and low oil viscosity is not clear. Thus, the heterogeneous sand-pack flooding experiments were carried out to analyze the influence of polymer–oil viscosity ratio on the enhanced oil recovery (EOR) performance of anti-hydrolyzed polymer to establish a reasonable viscosity ratio limit. Then the three-dimensional heterogeneous model flooding experiments were performed to clarify the mechanism. The results showed that when the permeability ratio was the same, as the viscosity ratio increased from 0.15 to 2.0, the incremental oil recovery increased from 3.2% to 27.2%. When the viscosity ratio was the same, the incremental oil recovery decreased with the increase in the permeability ratio. The reasonable viscosity ratio ranges from 1.0 to 1.5. For three-dimensional heterogeneous model flooding experiments, as the polymer–oil viscosity ratio increased from 0.45 to 1.0, the swept area of high and low permeability area was expanded and the oil saturation near the injection well in the mainstream channel was greatly reduced. Moreover, when the polymer–oil viscosity ratio was 1, the difference in the width of the mainstream channels between high and low permeability layers in the saturation field decreased, and the degree of utilization in low permeability layers increased significantly. As the polymer–oil viscosity ratio increased from 0.45 to 1.0, the incremental oil recovery increased from 16.2% to 24%. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition is one of the important means to enhance oil recovery in low permeability reservoirs, and it has good field application effects. Through the interfacial tension (IFT), contact angle (CA), and adsorption experiments, the effects of SDBS surfactant on IFT and reservoir wettability were studied, and the adsorption rule of SDBS at the mineral surface was obtained. On this basis, the imbibition recovery and mechanism of cores with different permeability are studied. The study showed that in low permeability reservoir, gravity and capillary force are the main controlling factors of imbibition. In the early stage, gravity determines the recovery, because the imbibition rate is 2.75 times that dominated by capillary force. The capillary force can continue to produce oil in small pores, and the imbibition time is twice that of gravity, which determines the recovery in the late imbibition stage. Therefore, the synergistic effect of gravity and capillary force can optimize the imbibition recovery, in low permeability reservoirs. When the concentration of SDBS solution is CMC (0.1%), due to the mineral interface adsorbs, the capillary force decreases by 10.76%, and the adhesion work increases by 3.42 times, resulting in a decrease in the imbibition recovery. The imbibition driving force is different for different reservoir properties, which can be adjusted by adding a surfactant to change IFT and CA. [ABSTRACT FROM AUTHOR]

This review comprehensively summarizes potential applications of SiO2–polymer composites especially in oil industries: enhanced oil recovery (EOR), loss circulation (LC), and relative permeability modification (RPM). The significance of these materials has been widely recognized as high-performance functional materials as they combine the flexural properties of the polymer and enhanced thermo-mechanical characteristics of SiO2 nanoparticles (NPs). The composite exhibits increased impact resistance and tensile strength without decreasing the flexibility of the polymer. The addition of SiO2 into the polymer matrices can further extend the possibility of creating hierarchically structured materials, and therefore, SiO2–polymer composites have attracted great interest in various industries. Compared to other materials, suspended NPs/polymer composites offer various advantages, such as high thermal stability, long-term stability, salinity tolerance, and viscosity increment which are very crucial criteria for increased oil production. [ABSTRACT FROM AUTHOR]

Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant sodium alkyl glucosyl hydroxypropyl sulfonate (APGSHS) and zwitterionic surfactant octadecyl betaine (BS-18) is proposed. The performance of APGSHS/BS-18 mixed surfactant system was evaluated in terms of interfacial tension, emulsification capability, emulsion size and distribution, wettability alteration, temperature-resistance and salt-resistance. The emulsification speed was used to evaluate the emulsification ability of surfactant systems, and the results show that mixed surfactant systems can completely emulsify the crude oil into emulsions droplets even under low energy conditions. Meanwhile, the system exhibits good temperature and salt resistance. Finally, the best oil recovery of 25.45% is achieved for low permeability core by the mixed surfactant system with a total concentration of 0.3 wt% while the molar ratio of APGSHS:BS-18 is 4:6. The current study indicates that the anionic/zwitterionic mixed surfactant system can improve the oil flooding efficiency and is potential candidate for application in low permeability reservoirs. [ABSTRACT FROM AUTHOR]

CO2 emulsions used for EOR have received a lot of interest because of its good performance on CO2 mobility reduction. However, most of them have been focusing on the high quality CO2 emulsion (high CO2 fraction), while CO2 emulsion with high water cut has been rarely researched. In this paper, we carried out a comprehensive experimental study of using high water cut CO2/H2O emulsion for enhancing oil recovery. Firstly, a nonionic surfactant, alkyl glycosides (APG), was selected to stabilize CO2/ H2O emulsion, and the corresponding morphology and stability were evaluated with a transparent PVT cell. Subsequently, plugging capacity and apparent viscosity of CO2/H2O emulsion were measured systematically by a sand pack displacement apparatus connected with a 1.95-m long capillary tube. Furthermore, a high water cut (40 vol%) CO2/H2O emulsion was selected for flooding experiments in a long sand pack and a core sample, and the oil recovery, the rate of oil recovery, and the pressure gradients were analyzed. The results indicated that APG had a good performance on emulsifying and stabilizing CO2 emulsion. An inversion from H2O/CO2 emulsion to CO2/H2O emulsion with the increase in water cut was confirmed. CO2/H2O emulsions with lower water cuts presented higher apparent viscosity, while the optimal plugging capacity of CO2/H2O emulsion occurred at a certain water cut. Eventually, the displacement using CO2/H2O emulsion provided 18.98% and 13.36% additional oil recovery than that using pure CO2 in long sand pack and core tests, respectively. This work may provide guidelines for EOR using CO2 emulsions with high water cut. [ABSTRACT FROM AUTHOR]

This paper aims to investigate the tragacanth gum potential as a natural polymer combined with natural clay mineral (montmorillonite, kaolinite, and illite) nanoparticles (NPs) to form NPepolymer suspension for enhanced oil recovery (EOR) in carbonate reservoirs. Thermal gravimetric analysis (TGA) tests were conducted initially in order to evaluate the properties of tragacanth gum. Subsequently, scanning electron microscopy (SEM) and energy-dispersive X-ray (EDX) tests were used to detect the structure of clay particles. In various scenarios, the effects of natural NPs and polymer on the wettability alteration, interfacial tension (IFT) reduction, viscosity improvement, and oil recovery were investigated through contact angle system, ring method, AntonPaar viscometer, and core flooding tests, respectively. The entire experiment was conducted at 25, 50, and 75 °C, respectively. According to the experimental results, the clay minerals alone did not have a significant effect on viscosity, but the addition of minerals to the polymer solution leads to the viscosity enhancement remarkably, resulting mobility ratio improvement. Among clay NPs, the combination of natural polymer and kaolinite results in increased viscosity at all temperatures. Considerable wettability alteration was also observed in the case of natural polymer and illite NPs. Illite in combination with natural polymer showed an ability in reducing IFT. Finally, the results of displacement experiments revealed that the combination of natural polymer and kaolinite could be the best option for EOR due to its substantial ability to improve the recovery factor. [ABSTRACT FROM AUTHOR]

Objective Aiming at the poor development effect of water injection in the medium-low permeability reservoir of Weizhou 12-1 oilfield the under-injection caused by high injection pressure easily due to the injection gel conditioning, and the foam volume and half-life of foam repellent are greatly affected by the high temperature and high salt environment etc, we propose to use the synthesized SMG microspheres, which are controllable in size stable in nature, and have excellent injection ability and temperature and salt resistance as the deep driving agent, so as to satisfy the further increase of the production in the field. Methods The hydration swelling performance injection performance plugging performance and recovery enhancement effect of SMG deep profile control system were analyzed by scanning electron microscope, laser particle size meter and physical simulation experiments. Results SMG has good swelling and plugging performance with an initial particle size of 0.71 µm, expansion slows down after seven days, and a final particle size swelling multiple of 5.32 µm, the final particle size expansion ratio was about 7 times. When the core permeability was in the range of 69.8×10-308.0×10-3 µm², the plugging rate was above 90% in all cases. The resistance coefficient and plugging rate of SMG showed a small fluctuation and then gradually decreased with the increase of core permeability. The highest recovery increase in the experimental group was 15.49%. Conclusions The injection of SMG can achieve deep retention, effectively seal the large pore throat of high permeability improve the reservoir inhomogeneity. It can change the flow direction and pressure distribution of the drive fluid increase the wave area to improve the oil recovery and the earlier the timing of SMG injection the stronger the ability of pressurization and flooding the better the recovery enhancement effect. [ABSTRACT FROM AUTHOR]