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In enhanced oil recovery (EOR), various processes have specific requirements concerning surfactant surface activity. High surface activity is essential during the oil production, whereas low or even negligible surface activity is required during the oil separation process. CO2-responsive surfactants can regulate their surface activity through the addition or removal of CO2 in their aqueous solutions. This property makes them suitable for the formulation of CO2-responsive displacement systems, including CO2-responsive foam, emulsion, and hydrogel systems. These three systems hold significant application value within the realm of enhanced oil recovery. This paper reviews the structure, types, synthesis methods, applications in EOR technology, and the effects of EOR in both field and laboratory settings. This method is both environmentally friendly and efficient for enhancing oil recovery. Furthermore, the application of CO2-responsive surfactants facilitates carbon capture, utilization, and storage, contributing to the achievement of carbon neutrality and the carbon peak. [ABSTRACT FROM AUTHOR]

Sphingan is a crucial exopolysaccharide (EPS) produced by Sphingomonas genus bacteria with wide-ranging applications in fields such as food, medicine, and petroleum. In this study, a novel sphingan, named MT gum, was overproduced from the wild-type strain Sphingomonas sp. MT01 at a yield of 25.6 g/L in a 5 L fermenter for 52 h at 35 °C. The MT gum was mainly composed of D-glucose (65.91%) and L-guluronic acid (30.69%), as confirmed by RP-HPLC, with Mw 7.24 × 105 Da. The MT gum exhibited excellent rheology and pseudoplasticity characteristics while maintaining function in high-temperature and high-salinity environments. The viscosity retention rates of MT gum (0.1%, w/v) were 54.06% (80 °C, 50,000 mg/L salinity) and 34.78% (90 °C, 50,000 mg/L salinity), respectively. The apparent viscosity of MT solutions (0.1%, w/v) was much higher than that of welan solutions under the same conditions. The MT gum also had the property of instant dissolution and completely swelled in 40 min. Meanwhile, the MT gum was resistant to 3–10 mg/L Fe2+ in the reservoir conditions, ensuring its application in offshore oil fields. These findings suggested that the biopolymer MT gum produced by the strain MT01 had significant potential in enhanced oil recovery (EOR) of high-temperature and high-salinity oil reservoirs. [ABSTRACT FROM AUTHOR]

This comprehensive review examines chemical and nano-based methods for asphaltene inhibition in the oil industry, focusing on recent developments and challenges. Asphaltene precipitation and deposition remain significant challenges in oil production, affecting wellbore areas, equipment walls, and surface infrastructure. The review analyzes various chemical inhibition mechanisms and evaluation methods, highlighting the emergence of nanotechnology as a promising solution. Metal oxide nanoparticles, organic nanoparticles, and inorganic nonmetal nanoparticles are discussed as effective inhibitors, with particular attention to their performance in different operational conditions, including CO2 flooding processes. The study reveals that nanoparticles' effectiveness in asphaltene inhibition is attributed to their large specific surface area, strong adsorption capacity, and unique interaction mechanisms with asphaltene molecules. The review also emphasizes the importance of proper inhibitor selection and concentration optimization, as the effectiveness thereof varies with reservoir conditions and crude oil characteristics. Recent developments in functionalized nanoparticles and their applications in enhanced oil recovery are examined, providing insights into future directions for asphaltene management in the petroleum industry. [ABSTRACT FROM AUTHOR]

Developing novel nanocomposites is a successful approach to affecting the nanoparticle, fluid, and rock interactions in porous media. This study introduces new ZnO–TiO2/ZSM-5 nanocomposites (ZTZ), and the improvements compared to the standalone application of ZSM-5 zeolite, are investigated. Several methods, such as XRD, SEM, EDX, and BET, were used to study the morphology of the developed nanocomposites. Zeta potential data showed that ZTZ had better stability conditions compared to ZSM-5. The effect of ZTZ on fluid/rock interactions such as IFT, wettability, and surface charges was measured and analyzed to select the most effective nanocomposites concentration to detach oil from the surface at the reservoir conditions (1800 Psi, 60 °C). In the presence of ZTZ, wettability alteration to the wet state was greater, and IFT was reduced to lower values. Hence, ZTZ altered the capillary force more than standalone nanoparticles. This effect was also observed in oil displacement tests, where at the optimum concentration, accelerated production and a 9% higher recovery by ZTZ were observed compared to the output by ZSM-5 flooding. It was found that the ZTZ presented in this study is an efficient nanocomposite for EOR application in sandstone formations. [ABSTRACT FROM AUTHOR]

Decision-making is among the main concerns in management discussions. This applied research is about a Multiple Criteria Decision Making problem since the decision-making process is drawn upon quantitative and qualitative criteria under uncertain conditions. This study was conducted for an oil reservoir consisting of nine criteria and eight alternatives. To form the network structure and recognize the relationships between the criteria, alternatives, and criteria weights, the Fuzzy Analytic Network Process (FANP) was used. Moreover, the Interval Valued Intuitionistic Fuzzy-TODIM (IVIF-TODIM) technique prioritized the alternatives. A case study was applied to demonstrate and show the suitability of the suggested method. The study's objective is to prioritize enhanced oil recovery (EOR) methods based on the feasibility criteria using the FANP and IVIF-TODIM techniques. This issue is required to implement the research because not all the EOR methods are implemented practically. They should be prioritized and chosen based on the budget, available infrastructures, and other important factors. The important issue is the manager's decision to choose the best method by considering different indicators. This method is a tool for better decision-making. Using these techniques, low salinity water injection was selected as the best and most effective and feasible method. [ABSTRACT FROM AUTHOR]

With increasing energy demands and depleting oil accessibility in reservoirs, the investigation of more effective enhanced oil recovery (EOR) methods for deep and tight reservoirs is imminent. This study investigates a novel hybrid EOR method, a synergistic approach of nonionic surfactant flooding with intermediate CO2-based oil swelling. This study is focused on the efficiency of surfactant flooding and low-pressure oil swelling in oil recovery. We conducted a fluorescence-based microscopic analysis in a microchannel to explore the effect of sodium dodecyl sulfate (SDS) surfactant on CO2 diffusion in Texas crude oil. Based on the change in emission intensity of oil, the results revealed that SDS enhanced CO2 diffusion at low pressure in oil, primarily due to SDS aggregation and reduced interfacial tension at the CO2 gas–oil interface. To validate the feasibility of our proposed EOR method, we adopted a 'reservoir-on-a-chip' approach, incorporating flooding tests in a polymethylmethacrylate (PMMA)-based micromodel. We estimated the cumulative oil recovery by comparing the results of two-stage surfactant flooding with intermediate CO2 swelling at different pressures. This novel hybrid approach test consisted of a three-stage sequence: an initial flooding stage, followed by intermediate CO2 swelling, and a second flooding stage. The results revealed an increase in cumulative oil recovery by nearly 10% upon a 2% (w/v) solution of SDS and water flooding compared to just water flooding. The results showed the visual phenomenon of oil imbibition during the surfactant flooding process. This innovative approach holds immense potential for future EOR processes, characterized by its unique combination of surfactant flooding and CO2 swelling, yielding higher oil recovery. [ABSTRACT FROM AUTHOR]

With the changing picture of global energy supplies and the shift toward the energy transition, it has never been more important to look for alternative sources of energy. Globally there are tens of thousands of abandoned oil fields with considerable reserves left behind. These have the potential to be reactivated to become an energy supply that is cleaner than conventional oil and gas. This can be achieved by the use of in situ combustion and the subsequent exploitation of the inherent increase in temperature and pressure to produce geothermal energy, allied to sequestration of the mixture of produced fluids. In situ combustion (ISC) has conventionally been used as an enhanced oil recovery technique, with a high failure rate that has been recently attributed to poor reservoir selection and project design. We suggest that the failure of many earlier ISC projects is due to insufficient appreciation of how the subsurface geology affects the process. With the use of computer numerical modelling, we aim to ascertain how the geometry and heterogeneity of the reservoir control the success of the process. Here we employ simple three-dimensional sector models to assess a variety of different petrophysical heterogeneities, within a set of different reservoir geometries, on the temperature, velocity, propagation stability and enthalpy rate. These models illustrate that the biggest impact on success of the ISC process for geothermal energy generation, as a function of temperature and enthalpy, is the location of the wells relative to the heterogeneities and the scale of heterogeneities. Metre-scale heterogeneities do not have a significant effect on this. Instead, the biggest contributor to the propagation stability and direction of the fire front is the presence of a large-scale (10 s to 100 s of metres) heterogeneities, such as channels, or the geometry of a tilted fault block; both have a strong control over the direction of the propagation, and therefore are important factors with regards to well placement. [ABSTRACT FROM AUTHOR]

There is a strong global demand for oil and gas resources, and forecasts indicate robust growth in oil demand in the coming years. Meeting this demand necessitates the exploitation of unconventional resources and enhancing the recovery of existing oil and gas fields. Field trials indicate that traditional gas injection in shale wells has low sweeping efficiency. Emerging technologies play an exceedingly significant role in solving the challenges of gas EOR in shale and tight formations. Among these advancements, smart or intelligent well technology has emerged as a promising solution to enhance field development outcomes. This study focuses on improving gas flooding efficiency in the Bakken formation by utilizing smart completions to reduce the gas–oil ratio (GOR) and increase oil recovery. An economic assessment of gas re-injection is conducted, considering both gas storage and enhanced oil recovery, with analysis incorporating capital expenditures, operating costs, and revenue from increased production. Reservoir simulations were employed to determine the most effective gas injection scenarios for maximizing recovery and storage efficiency. Simulation results demonstrate that 20% of perforated laterals account for 80% of the injected gas. To address this challenge, this work proposes using smart completions to segregate lateral sections, thereby optimizing gas injection efficiency, and unlocking additional oil in tight formations. Segregating horizontal laterals for gas re-injection using smart completion technology can achieve gas injection efficiencies of up to 0.25 barrels per Mcf of gas injected, with lower incremental gas production. The optimal injection rate is between 1 MMcfd and 3 MMcfd, with an injection period ranging from one to three years. It was also found that injecting gas into the toe section results in high bottom hole pressure but lower oil recovery due to reduced gas injection efficiency. From an economic perspective, the project yielded favorable outcomes, with a positive net present value (NPV) at a 7% discount rate. Even at lower oil prices (USD 50 per barrel), the Internal Rate of Return (IRR) was calculated to be 170%, indicating strong potential profitability. [ABSTRACT FROM AUTHOR]

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The understanding of the mechanisms behind foam generation and the structure of foam itself form the basis of foam-related experiments for its application in Enhanced Oil Recovery and overcoming gas injection limitations. Novel insights in this paper towards the theory of foam generation can help explain experimental results and lead to improved formulas of the applied substances and concentrations. This study aims to investigate the mechanisms behind foam generation and the structure of foam by specific laboratory experiments and theoretical analyses. The liquid drainage through interconnected Plateau borders was found to be the most critical foam decay mechanism for this particular research. The justification of the foam drainage equation was demonstrated by comparing the numerical solution with the outcome of a few bulk experiments. The discrepancies were described according to the limitations of both the theory and the experimental settings. Foam modelling gives more profound knowledge in more detail of the different stages in foam drainage than experimental data can deliver, which is because of the lack of continuous measurement of foam conductivity for the foam bulk test. Therefore, a comprehension of foam modelling investigation and comparison is required to gain a deeper understanding of foam behaviour.

Abstract Employing safe and inexpensive methods for the synthesis of biocompatible nanoparticles (NPs) can be very challenging. Green synthesis refers to the process of synthesizing nanoparticles without using toxic and dangerous chemicals. One of the applications of nanoparticles is increasing production from oil reservoirs, known as enhanced oil recovery (EOR). The main aim of the current study is the biosynthesis of zinc oxide (ZnO) nanoparticles (NPs) using Enterobacter cloacae (Persian Type Culture Collection (PTCC): 1798) microorganism, extracted from the formation water of one of the southwestern Iranian reservoirs, as a novel approach in EOR applications. Several analytical methods, including Fourier transform infrared (FTIR), field emission scanning electron microscope (FSEM), X-ray diffraction (XRD), dynamic light scattering (DLS), energy dispersive X-ray spectroscopy (EDS), and zeta potential were used to analyze the produced NPs. The FESEM analysis confirmed the amorphous form of the nanoparticles and estimated their size in the range of 32 to 58 nm. In investigating the effect of synthesized nanoparticles on interfacial tension (IFT) and stability tests, three levels of base fluids (distilled water, seawater, and diluted sea water) and five levels of nanoparticle concentrations (0, 100, 500, 1000, and 2000 ppm) were considered. The IFT analysis showed that an increase in nanoparticle concentration causes a decrease in the IFT. Also, ZnO nanoparticles were chosen at concentrations of 500 and 1000 ppm for wettability alteration and the EOR test through injection into porous media. The results for the EOR test demonstrated a maximum oil recovery factor of 56% for nanofluid injection with a concentration of 1000 ppm with diluted seawater as the base fluid. Furthermore, oil recovery factors of 43% and 49% were achieved by injection of distilled water and seawater with a concentration of 1000 ppm, respectively.

Surfactant injection is a well-established method of chemical EOR processes. Surfactant adsorption into clay layers can prevent their proper performance and thus reduce the oil recovery factor. On the other hand, this adsorption property of clay materials can be used to prevent surface and underground water pollution and reduce soil pollution. In this experimental study, the effect of surfactant concentration, electrolyte type (NaCl and MgCl2), and the solution salinity on fluid adsorption into the interlayer space of different clay types (bentonite and kaolinite) was investigated. XRF analysis was conducted on two relevant clay samples, and immersion and Washburn tests were performed on the desired samples with the Sigma 700 setup. Then, according to the clay type, the most optimal conditions were introduced for the surfactant solution used in the two areas of EOR and environmental processes related to reducing soil pollution. In the EOR processes, the optimal condition for the lowest adsorption amount is C (with 1 CMC concentration and salinity of 100,000 ppm for NaCl salt). This fluid works better in kaolinite formations. In the environmental field related to the reduction of soil pollution, if the pollutants we are looking for are R and S (with alkyl benzene sulfonic acid as the dominant agent), bentonite has a better performance than kaolinite in terms of adsorption and subsequently pollution control. If the polluting fluid contains MgCl2 ions in the exact salinity values, the adsorption amount and soil pollution control will be higher for both adsorbent clays than if our fluid has NaCl salinity. The study's findings have a wide range of applications in surfactant flooding designs, surfactant adsorption optimization, and can be generalized to other detergent types.

Abstract Carbon Capture, Utilization, and Storage (CCUS) offers a viable solution to reduce the carbon footprint in the petroleum industry, and foam injection presents a promising method to achieve this while simultaneously increasing oil recovery. In this work, we studied the feasibility of CO2 foam for co-optimizing enhanced oil recovery and CO2 storage in a high-salinity carbonate formation. The simulated hydrodynamic model is a depleted formation containing 30% residual oil, with three mechanisms for CO2 storage: solubility, residual, and mineralization trapping mechanisms. The results showed that after 20 years, oil recovery during foam injection was 2.7 times higher than CO2 injection, and the CO2 stored during foam flooding was 38% higher than CO2 injection. Notably, foam injection also increased CO2 storage capacity by 2.6 times, indicating the potential to store around 2 gigatons of CO2 in the simulated model. This was attributed to the ability of foam to significantly reduce gas mobility and thus form isolated bubbles through its Jamin effect. Residual trapping was the dominant trapping mechanism, contributing to over 70% of the total CO2 trapped, attributed to the reduction in the dissolution of CO2 in brine due to the high salinity of the aqueous medium. CO2 mineralization was also studied, showing the least trapping efficiency and the dissolution trend of all the carbonate minerals. This study illustrates a novel CO2 utilization and storage technique in which CO2 is concurrently sequestered while enhancing oil recovery in a depleted oil reservoir by injecting CO2 as foam. The relevance of this study lies in its potential to provide a dual benefit of reducing greenhouse gas emissions and boosting oil production, offering a sustainable approach for the petroleum industry.

Employing safe and inexpensive methods for the synthesis of biocompatible nanoparticles (NPs) can be very challenging. Green synthesis refers to the process of synthesizing nanoparticles without using toxic and dangerous chemicals. One of the applications of nanoparticles is increasing production from oil reservoirs, known as enhanced oil recovery (EOR). The main aim of the current study is the biosynthesis of zinc oxide (ZnO) nanoparticles (NPs) using Enterobacter cloacae (Persian Type Culture Collection (PTCC): 1798) microorganism, extracted from the formation water of one of the southwestern Iranian reservoirs, as a novel approach in EOR applications. Several analytical methods, including Fourier transform infrared (FTIR), field emission scanning electron microscope (FSEM), X-ray diffraction (XRD), dynamic light scattering (DLS), energy dispersive X-ray spectroscopy (EDS), and zeta potential were used to analyze the produced NPs. The FESEM analysis confirmed the amorphous form of the nanoparticles and estimated their size in the range of 32 to 58 nm. In investigating the effect of synthesized nanoparticles on interfacial tension (IFT) and stability tests, three levels of base fluids (distilled water, seawater, and diluted sea water) and five levels of nanoparticle concentrations (0, 100, 500, 1000, and 2000 ppm) were considered. The IFT analysis showed that an increase in nanoparticle concentration causes a decrease in the IFT. Also, ZnO nanoparticles were chosen at concentrations of 500 and 1000 ppm for wettability alteration and the EOR test through injection into porous media. The results for the EOR test demonstrated a maximum oil recovery factor of 56% for nanofluid injection with a concentration of 1000 ppm with diluted seawater as the base fluid. Furthermore, oil recovery factors of 43% and 49% were achieved by injection of distilled water and seawater with a concentration of 1000 ppm, respectively. [ABSTRACT FROM AUTHOR]

AbstractCarbon nanotubes can enhance the strength of the oil-water interface, and increase the efficiency of emulsification viscosity reduction, thus improving the recovery efficiency of heavy oil reservoirs. In this study, a type of Janus amphiphilic carbon nanotube (JCC18) was synthesized using the Pickering emulsion interfacial stabilization method. The structural characterization of JCC18 using FTIR, ESEM, and XRD confirmed the success of this synthesis. Through zeta potential, dynamic light scattering, and settlement tests, surfactant Tween 80 was identified as the optimal dispersant for JCC18. Emulsification tests demonstrated that the nanofluid emulsified water with crude oil to form an oil-in-water emulsion, and it achieved a maximum viscosity reduction rate of over 99.9% (±0.99%). The viscosity reduction rate of crude oil increased with the water-to-oil volume ratio, nanoparticle concentration, or temperature. However, an increase in the mineralization level decreased the reduction rate of oil viscosity. Compared to the systems without nanoparticles, the nanofluid demonstrated superior performance in reducing crude oil viscosity both before and after aging. Furthermore, the interfacial tension between the nanofluid and crude oil was lowest, reaching 0.153 (±0.002) mN/m. The interfacial tension was more pronounced with the increase in temperature. As the mineralization level increased, the interfacial tension between the nanofluid and crude oil initially decreased and then increased. The core flooding experiments showed that compared to the primary water flooding, the nanofluid, and secondary water flooding enhanced the recovery by 21.92% (±0.22%). These results validated the significant potential of the amphiphilic carbon nanotube fluid in enhancing heavy oil recovery. [ABSTRACT FROM AUTHOR]

Cambrian sandstones comprise a large and saline-only aquifer that can be utilized for CO2 geological storage in the Baltic basin, including Lithuania. The two prospective storage sites with the most potential are located in west Lithuania. Despite the larger area of the Gargždai elevation (233 km2), the Syderiai uplift (62 km2) is characterized by the largest storage volume. The most significant difference between the studied structures is primarily related to the much higher reservoir quality of the Cambrian sandstones at the Syderiai site. The sandstones' average porosity is 16% and their permeability measures 310 mD, while the Gargždai site is characterized by poor reservoir quality (average porosity of 7% and permeability as low as 10 mD in the sandstone). The main controlling parameter for the sandstones is authigenic quartz cementation. The reservoir type is classified as the porous sandstone type for the Syderiai site and as the fractured reservoir type for the Gargždai site. The storage volumes of CO2 of the sites were assessed as 56.7 Mt and 31.3 Mt, respectively. The present study determined that the Syderiai uplift was the prospective site with the most potential for the geological storage trapping of CO2, owing to its high reservoir quality, while the Gargždai elevation is characterized as a potential alternative for CO2 storage combined with EOR technology for oil exploitation, despite its poor reservoir quality. [ABSTRACT FROM AUTHOR]

Nano-emulsions stabilized by nonionic surfactants have the characteristics of ultra-low interfacial tension (IFT) and altered wettability in ultra-low permeability reservoirs. Thus, in this work, a new nanoemulsion is proposed to enhance spontaneous imbibition recovery in ultra-low permeability reservoirs. The nanoemulsion is prepared using n-dodecane, Tween-20, and coconut oil acid diethanolamine n-amyl alcohol. The effects of temperature and salinity on particle size, IFT, and wettability alteration performance of the nanoemulsions were systematically studied. Experimental results show that the particle size of nanoemulsions increases with salinity, and the highest level is up to 100 nm, while an increase in temperature is beneficial to the formation of smaller nanoemulsions. The IFT of the nanoemulsion system can be reduced to an ultra-low level (10–3 mN/m) when the salinity is lower than 50,000 mg/L. As for the wettability alteration property of a nanoemulsion system, an increase in temperature can improve its performance, but variations in salinity seldom have any effects. At 56 °C and 30,000 mg/L salinity, the spontaneous imbibition recovery of 1.00 wt% nanoemulsion can reach 53.8% under the synergistic effect of three mechanisms: extremely small droplet size, excellent wettability alteration performance, and ultra-low IFT. These three mechanisms work together to significantly improve the displacement efficiency of ultra-low-permeability reservoirs. [ABSTRACT FROM AUTHOR]

AbstractThe high viscosity and poor fluidity of heavy oil challenge its extraction, leading to the widespread use of surfactant emulsification to reduce viscosity and enhance recovery. This study evaluated three surfactants—sodium dodecyl sulfate (SDS), sodium oleate (SO), and APG0810—for their suitability and effectiveness in the X reservoir. The solution properties of these surfactants were analyzed and their micro-mechanisms investigated using MD calculations. The effects of surfactant concentration and additives on emulsification and viscosity reduction were elucidated. Ultimately, a system for emulsification and viscosity reduction was selected for physical simulation research. The experimental findings show that SO reduces interfacial tension from 52.4 mN/m to 0.0027 mN/m, transforming lipophilic surfaces into hydrophilic. MD analyses reveal SO’s optimal interfacial properties, with the lowest interfacial energy of −6423.4 kcal/mol, maximum interfacial thickness of 2.56 nm, and minimal diffusion coefficient of 0.4087 Å2/ps at the oil-water interface. These findings align with experimental results, confirming SO’s superior interfacial properties. Combining 0.3% SO with 0.5% n-pentanol results in a 98% viscosity reduction. The emulsion shows excellent stability, with no water separation in the first 30 min and only 8.3% after 2 h. Physical simulation results show that in high(low) permeability core displacement experiments, system flooding and subsequent water flooding can increase recovery rates by 15.39%(36.91%), indicating the system’s potential for enhancing oil recovery in Reservoir X. The findings suggest that the implementation of this system not only boosts the crude oil recovery rate but also carries economic significance in the industry. [ABSTRACT FROM AUTHOR]

Carbon Capture, Utilization, and Storage (CCUS) offers a viable solution to reduce the carbon footprint in the petroleum industry, and foam injection presents a promising method to achieve this while simultaneously increasing oil recovery. In this work, we studied the feasibility of CO2 foam for co-optimizing enhanced oil recovery and CO2 storage in a high-salinity carbonate formation. The simulated hydrodynamic model is a depleted formation containing 30% residual oil, with three mechanisms for CO2 storage: solubility, residual, and mineralization trapping mechanisms. The results showed that after 20 years, oil recovery during foam injection was 2.7 times higher than CO2 injection, and the CO2 stored during foam flooding was 38% higher than CO2 injection. Notably, foam injection also increased CO2 storage capacity by 2.6 times, indicating the potential to store around 2 gigatons of CO2 in the simulated model. This was attributed to the ability of foam to significantly reduce gas mobility and thus form isolated bubbles through its Jamin effect. Residual trapping was the dominant trapping mechanism, contributing to over 70% of the total CO2 trapped, attributed to the reduction in the dissolution of CO2 in brine due to the high salinity of the aqueous medium. CO2 mineralization was also studied, showing the least trapping efficiency and the dissolution trend of all the carbonate minerals. This study illustrates a novel CO2 utilization and storage technique in which CO2 is concurrently sequestered while enhancing oil recovery in a depleted oil reservoir by injecting CO2 as foam. The relevance of this study lies in its potential to provide a dual benefit of reducing greenhouse gas emissions and boosting oil production, offering a sustainable approach for the petroleum industry. [ABSTRACT FROM AUTHOR]

As waterflooding multi-layer reservoirs reach the high-water-cut stage, inter-layer conflicts become increasingly serious, leading to a worsening development effect over time. Production layer regrouping is an effective approach for resolving inter-layer conflicts and improving waterflooding efficiency. At the current stage, there are limitations to most of the methods of production layer regrouping. This article proposes a smart method for optimizing the layer regroup plan based on a genetic algorithm. Comprehensively considering various factors that affect the regroup of layers, such as layer thickness, porosity, permeability, remaining oil saturation, remaining reserves, recovery ratio, water cut, etc., based on the combination principle of "smaller intra-group variance and larger inter-group variance of each influencing factor are expected", a genetic algorithm is used to calculate the fitness value of the initial combination schemes, and the advantageous schemes with higher fitness values are selected as the basis of the next generation. Then, crossover and mutation operations are performed on those advantageous schemes to generate new schemes. Through continuous selection and evolution, until the global optimal solution with the highest fitness value is found, the optimal combination scheme is determined. Comparative analysis with numerical simulation results demonstrates the reliability of this intelligent method, with an increased oil recovery of 4.34% for the sample reservoir. Unlike selecting a preferable plan from a limited number of predefined combination schemes, this method is an automatic optimization to solve the optimal solution of the problem. It improves both efficiency and accuracy as compared to conventional reservoir engineering methods, numerical simulation methods, and most mathematical methods, thus providing effective guidance for EOR strategies of waterflooding reservoirs in the high-water-cut stage. [ABSTRACT FROM AUTHOR]

Surfactant injection is a well-established method of chemical EOR processes. Surfactant adsorption into clay layers can prevent their proper performance and thus reduce the oil recovery factor. On the other hand, this adsorption property of clay materials can be used to prevent surface and underground water pollution and reduce soil pollution. In this experimental study, the effect of surfactant concentration, electrolyte type (NaCl and MgCl2), and the solution salinity on fluid adsorption into the interlayer space of different clay types (bentonite and kaolinite) was investigated. XRF analysis was conducted on two relevant clay samples, and immersion and Washburn tests were performed on the desired samples with the Sigma 700 setup. Then, according to the clay type, the most optimal conditions were introduced for the surfactant solution used in the two areas of EOR and environmental processes related to reducing soil pollution. In the EOR processes, the optimal condition for the lowest adsorption amount is C (with 1 CMC concentration and salinity of 100,000 ppm for NaCl salt). This fluid works better in kaolinite formations. In the environmental field related to the reduction of soil pollution, if the pollutants we are looking for are R and S (with alkyl benzene sulfonic acid as the dominant agent), bentonite has a better performance than kaolinite in terms of adsorption and subsequently pollution control. If the polluting fluid contains MgCl2 ions in the exact salinity values, the adsorption amount and soil pollution control will be higher for both adsorbent clays than if our fluid has NaCl salinity. The study's findings have a wide range of applications in surfactant flooding designs, surfactant adsorption optimization, and can be generalized to other detergent types. [ABSTRACT FROM AUTHOR]

Chemical enhanced oil recovery (cEOR) remains one of the most potent tertiary recovery techniques. However, it is expensive and rarely environmentally friendly. Bio-based amphiphilic polymers have been suggested as an alternative to eradicating the challenges of conventional cEOR because of cost-effectiveness, and sustainability. Unfortunately, few in-depth studies exist in the literature to investigate the prospects of these materials. A new family of amphiphilic polysaccharides was synthesized by hydrophobic modification of cellulose sulphate, and the EOR functionalities were tested. The novel biopolymers exhibited the ability to alter rock wetting properties. In terms of recovery, one of the variants of the synthesized bio amphiphilic polymer (D-I) was able to reduce residual oil saturation to 12% at harsh conditions of 60,000 ppm salinity at 75 °C. Micromodel visual analysis revealed that the performance of the novel materials was due to the combination of mobility control, IFT lowering and emulsification, wettability alteration, and viscoelasticity. With a performance commensurate to that of a commercial hydrophobically modified polymer, it can be said that the novel amphiphilic polysaccharides can stand as a viable cEOR agent for oilfield applications.