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Intracranial epidermoid cysts are rare, benign tumors. Nevertheless, the microsurgical removal of these cysts is challenging. This is due to their capacity to adhere to the neurovascular tissue, as well as the associated difficulties in microsurgically peeling off their capsular wall hidden in dead angles. To better understand the rate of recurrence after surgical intervention, we have performed preoperative and postoperative volumetric analysis of epidermoid cysts, allowing the estimation of their growth rate after resection. Imaging data from 22 patients diagnosed and surgically treated for an intracranial epidermoid cyst between 2000 and 2022 were retrospectively collected from 2 European neurosurgical centers with microsurgical expertise. Volumetric analysis was performed on magnetic resonance imaging data. Average cyst volume at diagnosis, before any surgery, measured in 12 patients was 28,877.6 ± 10,250.4 mm3 (standard error of the mean [SEM]). Estimated growth rate of incompletely resected epidermoids after surgery was 1,630.05 mm3 ± 729.95 (SEM). Assuming linear growth dynamics and normalizing to postoperative residual volume, the average postoperative growth rate corresponded to 61.5% ± 34.3% (SEM) of the postoperative residual volume per year. We observed signs of recurrence during a radiologic follow-up period of 6.0 ± 2.8 years (standard deviation) in more than 50% of our patients. Due to their slow-growing nature, epidermoid cysts can often reach a complex multicompartmental size before resection, even in young patients, thus requiring complex approaches with challenging capsular resection, which implies a high risk of nerve and vascular injury per se. Tumor recurrence may be predicted on the basis of postoperative volumetry. [ABSTRACT FROM AUTHOR]

Direct ethanol fuel cells (DEFCs) provide a portable and environmentally friendly power source with high energy density. However, the slow kinetic of the ethanol oxidation reaction (EOR) has hindered the commercialization of DEFCs. Palladium (Pd)-based nanomaterials are the best promising catalysts for EOR due to the high catalytic activities and relatively abundant reserves. In this paper, we developed a simple and green way for the preparation of palladium hydride (PdH 0.43) and Au/PdH 0.43 heterostructures. Ethylene glycol (EG) provided the source of H atoms for the formation of PdH 0.43 in synthesis process. The as-synthesized PdH 0.43 and Au/PdH 0.43 nanocrystals were extremely stable under ambient conditions and annealing at 300 °C under Ar. Compared with PdH 0.43 and commercial Pd/C, Au/PdH 0.43 presented a higher mass activity of 2659 mA mg−1, a lower oxidation peak potential, and a higher catalytic stability for oxidizing ethanol. Remarkably, the improved catalytic performance might arise from the synergistically modulation of electronic structure, the enhanced resistance to poisoning products and the acceleration of electron transfer by the formation of palladium hydrides and abundant heterostructures of Au/PdH 0.43. This work provides a promising reference for the development of metal-hydride nanomaterials and heterostructures as efficient catalysts. • The PdH 0.43 and Au/PdH 0.43 were prepared with ethylene glycol as the H source. • The PdH 0.43 and Au/PdH 0.43 were extremely stable in the air over six months. • Au/PdH 0.43 can maintain the stability of structure even annealing at 300 °C in Ar. • Au/PdH 0.43 exhibited a higher performance toward EOR than PdH 0.43 and Pd/C. • The improved activities might arise from the doping of H and heterostructures. [ABSTRACT FROM AUTHOR]

Adding nanoparticles (NPs) into surfactant solutions represents a promising strategy for enhancing oil displacement in porous media, with significant implications for various engineering and environmental applications, including soil remediation and enhanced oil recovery from underground reservoirs. Recent investigations have focused on the integration of silica and alumina NPs into anionic surfactant solutions to mitigate interfacial tension (IFT) and reduce the contact angle between the surfactant and oil phases. However, the utilization of these injection scenarios in fractured porous media has received limited attention. In this experimental study, we employed a 3D printer to design and fabricate three distinct porous media types: single permeability (S), fractured (F), and dual permeability (D). Subsequently, we prepared the sodium dodecyl sulfate (SDS) solution by adding SDS powder into a brine solution containing 2% NaCl. Nanofluids were then produced through the dispersion of SiO 2 and Al 2 O 3 NPs in the SDS solution using a sonicator. The prepared solutions were subsequently injected into each porous medium, while the recovery process was recorded using a camera. Recovery rates for each scenario were calculated utilizing a developed Python image processing code. Furthermore, analysis of the images enabled us to demonstrate the behavior and growth of the displacing phase's fingers within the oil phase. Findings from this study showed that SDS injection into the S medium resulted in an approximate 60% oil recovery. Adding silica and alumina NPs into the SDS solution led to enhanced total recovery rates of up to 70% and 78%, respectively. The recovery results obtained from tests conducted within the F medium exhibited a pronounced decrease, with the SDS solution sweeping a mere 25% of the medium, while the silica and alumina nanofluids recovered 43% and 47%, of the oil respectively. Notably, the silica nanofluid displayed superior performance to the alumina nanofluid during the breakthrough stage in the F medium. In the D medium, the injection of SDS, silica, and alumina nanofluids achieved total recovery rates of 49%, 53%, and 56%, respectively. These outcomes highlight the diminished effectiveness of nanofluids within the dual permeable medium. [Display omitted] • Different porous media (single permeability, dual permeability and fractured structure) were fabricated utilizing 3D printing technology. dual permeability (D). • A base solution was prepared by combining NaCl and sodium dodecyl sulfate (SDS), followed by the addition of SiO 2 and Al 2 O 3 nanopowders. [ABSTRACT FROM AUTHOR]

One of the most efficient ways to extract hydrocarbons is to use nanoparticles for wettability alteration, to address dwindling reservoirs and growing energy demand. Another crucial factor is inhibiting asphaltene precipitation, which can cause damage to production components and alter the rock's wettability and permeability. This study investigates the impact of synthesized Fe 3 O 4 , SiO 2 , and Fe 3 O 4 /SiO 2 nanomaterials on wettability alteration and asphaltene removal in an oil/water system at two temperatures (25 °C and 80 °C). The nanocomposites with various ratios were manufactured with the aid of the sol-gel method and characterized using FTIR, XRD, and dynamic light scattering analysis. The stability of different concentrations of nanofluids was assessed via sedimentation tests and zeta potential measurements. According to the results, there was a reduction in both surface energy and oil area fraction from 89.46 to 8.13 mN/m and from about 1–0.075, respectively. Maximum wettability alteration (from 155° to 32°) was achieved at the optimum condition (0.075 wt% of C1000 at 80 °C). The C1000 nanocomposite played a significant role as an inhibitor in shifting the onset point to higher concentrations of n-heptane compared to Fe 3 O 4 and SiO 2 nanoparticles. Furthermore, nanomaterials have a better association with the Langmuir model, and the asphaltene particles are adsorbed homogeneously and in the form of one layer of adsorbents. The results of this study can assist the petroleum sector in better controlling asphaltene precipitation and enhancing oil recovery by C1000 nanoparticles, leading to a higher recovery rate and a more cost-effective production approach. [Display omitted] • The strongly oil-wet surface becomes water-wet in presence of various ratio of nanoparticles. • The asphaltene particles are adsorbed homogeneously and in the form of one layer on the adsorbents. • Optimization of different nanocomposites and nanofluid concentrations. • The static and dynamic contact angles of the rock surface were measured. [ABSTRACT FROM AUTHOR]

CARMEN 3 and CARMEN 4 are two missions developed by the CNES to measure flux particle levels in the radiation belts. These two missions consist in embedding the CNES-developed ICARE-NG instrument on both the JASON-3 satellite (LEO: 1336 km, 66°) and the E7C satellite (GEO with EOR posting) for respectively CARMEN 3 and CARMEN 4. During the CARMEN 4 EOR phase (21.06.2019 to 30.10.2019), E7C run through the same L ∗ range ( L ∗ = 3 - 7) as JASON-3 during the same period. As these two satellites are equiped with the same ICARE-NG instrument but are not at the same altitude, it is relevant to compare the electron flux temporal evolution measured on both satellites. Common electron energies measured by ICARE-NG during CARMEN 3 and CARMEN 4 are 1.6 MeV and 1.8 MeV. Studying temporal electron flux evolution for both missions, we notice for both a remarkable exponential decay of the flux level subsequently to a rapid filling of the outer radiation belt due to an important solar activity (geomagnetic storm). This exponential decay is characterised with a timescale τ which depends on the mission, the energy, the L ∗ value, and the concerned exponential decay. These timescales are compared to several previously published estimates. Then, noticing that electron flux temporal evolution have the same dynamics for both missions, we find a projection function from one to the other using classical statistics methods (linear regression, with least squares method). We find that the correlation between CARMEN 3 and CARMEN 4 data depends on the value of Roederer's L ∗ parameter. The r 2 correlation coefficient is higher than 0.6 for L ∗ = 3.5 - 4.8 and smaller otherwise. We notice a global same trend of electron flux temporal evolution from both missions. However, the correlation is limited by irregularities in the electron flux measured by CARMEN 3. The causes of these irregularities are discussed and explained. [ABSTRACT FROM AUTHOR]

• A new coke plugging model has been developed that is applicable in the permeability range of 3 D to 7 D. • An evaluation model for methods to mitigate water invasion has been proposed. • The "Air + LTO" coking method combines the benefits of both nitrogen and gel injection. Heavy oil is one of the globally important unconventional oil and gas resources, and its development faces the challenge of water invasion. The numerical model of a heavy oil reservoir with edge water is established and validated by field data and physical experiments. An evaluation model for selecting water invasion mitigation measures for different targets is established. The mechanisms of mitigating water invasion in the vertical-horizontal well steam drive (VHSD) heavy oil reservoir by cold-water injection, gel injection, nitrogen injection, and "Air + LTO" coking are investigated. The advantages of the "Air + LTO" coking technology in mitigating water invasion are elucidated. The importance of LTO reaction for water invasion mitigation is emphasized. The results show: (1) the edge water flows into the reservoir along the drainage interface of the steam chamber first and forms large water invasion channels in the heated crude oil region in the middle part of the reservoir; (2) the cold-water injection reduces the oil recovery factor by 3 %, the nitrogen injection increases it by 16.3 %, the gel injection improves it by 11.5 % and the "Air + LTO" coking technology enhances it by 24.1 %; (3) after air injection, the coke deposition effectively plugs the water invasion channels in the middle of the reservoir. This research provides a new perspective for mitigating water invasion and improving the oil recovery factor in heavy oil reservoirs with edge water, demonstrating the potential value and feasibility of the "Air + LTO" coking technology. [ABSTRACT FROM AUTHOR]

• The impacts of citrate ester surfactants on the decreasing MMP, extraction and swelling behaviors between CO 2 and oil were investigated. • The MMP can be decreased from 17.4 MPa to 13.7 MPa at the presence of 1% citrate ester A in CO 2. • Citrate ester A can enhance the extraction and swelling effects of CO 2 to oil. • 1% citrate ester A in CO 2 can enhance the shale oil recovery about 10%. • The oil recovery can be enhanced by the decreasing MMP, improvements of extraction, swelling and solution-gas-drive effects. The impacts of citrate ester surfactants on the MMP, extraction and swelling behaviors between CO 2 and oil were investigated to enhance shale oil recovery. Firstly, the dissolution behaviors of citrate ester in CO 2 and the influence of citrate ester on the MMP between CO 2 and oil were investigated by the phase-transition-point measurement. Then, the effects of citrate ester on the extraction and swelling behaviors between CO 2 and oil were explored by a newly-designed method. At last, the effect of surfactant on the shale oil recovery during CO 2 huff-n-puff process was discussed. The results show that compared with citrate ester B, citrate ester A has a lower cloud-point pressure and higher effect to decrease the MMP of oil and CO 2. The extraction ratio and swelling ratio both increase with the increase of CO 2 pressure and the increase of oil content in the oil and CO 2 systems. Citrate ester A can enhance the extraction and swelling effects of CO 2 to oil and the promoting effect increases with the increasing surfactant concentration. The presence of 1% citrate ester A in CO 2 can enhance the oil recovery about 10% caused by the decreasing MMP, improvements of extraction, swelling and solution-gas-drive effects. [ABSTRACT FROM AUTHOR]

• Novel strategies for enhancing CO 2 storage capacity in low permeability reservoirs. • Results provide ground to understand the mechanism of oil-based CO 2 foam EOR. • Oil-based CO 2 foam shows excellent performance in both flooding and HnP methods. Excessive CO 2 emissions contribute to global climate change thus mandating effective methods for CO 2 utilization and sequestering. In this study, one-dimensional flow simulation experiments on CO 2 flooding, CO 2 Huff-n-Puff, oil-based CO 2 foam flooding, and oil-based CO 2 foam Huff-n-Puff are conducted using low-permeability sandstone cores modeled after the Q131 block in Liaohe Oilfield, characterized by porosity ranging from 15% to 20% and permeability between 25 mD to 35 mD. Low permeability reservoirs are rich in oil resources and may effectively sequester CO 2. Parameters pertaining to oil and gas production and carbon storage are collected. Nuclear magnetic resonance (NMR) is employed to determine the spatial variation of oil saturation in the cores. The experimental results show 8.03% and 41.21% increase in oil recovery factor by foam flooding and foam Huff-n-Puff relative to CO 2 as the recovery agent. Moreover, NMR analysis confirms lower residual oil saturation in core samples using foam, suggesting better displacement agent. Oil-based CO 2 foam recovery contributed to effective carbon sequestration, with carbon storage increasing by 34.24% and 315% relative to CO 2 flooding and CO 2 Huff-n-Puff, respectively. CO 2 storage mechanisms for oil-based CO 2 foam recovery method are detailed. [ABSTRACT FROM AUTHOR]

• CO 2 -responsive gel with good shear resistance and viscoelasticity was designed. • The plugging characteristics and EOR performance of the gel system were evaluated. • The dynamic filtration damage the gel system to the matrix was identified. • The microscopic oil displacement characteristics in different stages were clarified. • The synergistic EOR mechanism of CO 2 -responsive gel and CO 2 was revealed. During the CO 2 flooding process in fractured low-permeability oil reservoirs, the injected CO 2 is prone to channeling along fractures due to severe reservoir heterogeneity, resulting in poor development effect. The CO 2 -responsive gel system shows dual advantages in achieving CO 2 capture and plugging gas channeling to enhance oil recovery. This paper constructed a system with good CO 2 sensitivity based on long-chain alkyl amide propyl dimethyl tertiary amine first. Subsequently, the properties of the system before and after the response were evaluated through rheological test, and its microstructure was characterized by Cryo-TEM. The system exhibited good CO 2 responsiveness, transitioning from low-viscosity solution system to high-viscosity CO 2 -responsive gel system upon contact with CO 2 , with its viscosity increasing by nearly five orders of magnitude. The CO 2 -responsive gel demonstrated excellent shear resistance, viscoelasticity and shear self-repairing ability. The change of microstructure further verified the mechanism of molecules self-assembly in the system under the action of CO 2. Then, a series of core physical simulation experiments were carried out to comprehensively evaluate the effects of different factors on the injection capacity, plugging characteristics, dynamic filtration damage performance and EOR effect of CO 2 -responsive gel. The gel maintained injectability while achieving an exceptional deep plugging effect, and the plugging rate reached 98.77%. It showed good characteristics of low filtration and permeability damage in low permeability reservoirs, effectively ensuring the fracture plugging effect. After the fracture was plugged by gel, the sweep range of CO 2 to the matrix significantly expanded, and the gas flooding recovery increased by 18.19–21.7%. Finally, the matrix-fracture dual-media chip model was used to conduct microfluidic experiment, the oil displacement characteristics in different displacement stages were visually clarified, and the synergistic plugging and oil displacement mechanism between the CO 2 -responsive gel and CO 2 was summarized. The research results can provide important insights for the green and efficient application of CO 2 -responsive gel in fractured low-permeability reservoirs. [ABSTRACT FROM AUTHOR]

• Reduced aqueous mobility with gas injection observed numerically and experimentally. • Mineral dissolution with CO 2 injection showed minor impact on tracer migration. • Conventionally generated static geologic models were insufficient for tracer modeling. • Nonaqueous-soluble tracers showed bypassing of production wells. • Tracer modeling was moderately sensitive to petroleum model component count. A series of six aqueous-soluble and four nonaqueous-soluble tracer experiments and corresponding numerical simulations were executed for the Farnsworth Field in Ochiltree County, Texas, USA, a field which is undergoing tertiary enhanced oil recovery with water-alternating-gas (WAG) production. The combination of field experiments and numerical simulations was designed to identify flow pathways between injectors and producers and potential short circuiting of injected fluids. Field recoveries of aqueous-soluble tracers were dependent on the WAG stages of the tracer injection well, with shorter arrival times for strictly waterflooding and delayed arrival times for alternating injection stages. Aqueous-soluble tracer (i.e., 1,3,6-naphthalene trisulfonate, 1,5-naphthalene disulfonate, 1,6-naphthalene disulfonate, 2-naphthalene sulfonate, 2,6-naphthalene disulfonate, and 2,7-naphthalene disulfonate) arrivals for WAG injectors indicated water bypass was occurring during gas injection stages. Nonaqueous-soluble tracer (i.e., perfluoro-1,2-dimethylcyclohexane, perfluoroethylcyclohexane, perfluoromethylcyclohexane, and perfluoromethylcyclopentane) experiments revealed faster migration velocities than for the aqueous-soluble tracers and flow heterogeneities that resulted in the tracers bypassing nearer production wells. Base-case numerical simulations of the tracer experiments used a geologic model of the Morrow B sandstone production interval with parameters calibrated from history matching simulations, with the Morrow B sandstone sub-divided into hydrologic flow units (HFUs). Alternative simulation scenarios investigated HFU-dependent three-phase relative permeability models and dynamic intrinsic permeability enhancement with exposure to aqueous-dissolved CO 2. Compositional petroleum models with four components were shown to be sufficient for tracer modeling compared against a nine-component model, with a factor of four difference in simulation execution time. HFU-dependent relative permeability models and dynamic intrinsic permeability modifications influenced arrival times and production concentrations of both aqueous- and nonaqueous-soluble tracers but did not yield unique flow pathways compared to those observed in the base-case scenario. [ABSTRACT FROM AUTHOR]

[Display omitted] • The WAG injection process while considering the CO 2 dissolution and viscosity reduction effect was investigated. • When W : G and Ca increased, the fingering phenomenon was suppressed and stable displacement was more likely to occur. • The viscosity reduction effect of CO 2 dissolution has the greatest impact on viscous fingering. As a CO 2 capture, utilization, and storage (CCUS) technology, water-alternating-CO 2 (WAG) injection has demonstrated excellent results in enhancing oil recovery. Current research on WAG injection primarily focused on factors such as increasing injection pressure and optimizing the water–gas slug ratio (W : G) to enhance the driving force, reduce instability due to the significant viscosity difference between oil and CO 2 , thereby inhibiting fingering phenomenon and improving oil recovery. However, in immiscible flooding, CO 2 dissolution reduces the viscosity of the oil, changing the instability of the interfaces and affecting oil recovery. We employed computational fluid dynamics to study the effect of CO 2 dissolution and viscosity reduction on fingering patterns and its effect on enhanced oil recovery (EOR) under capillary numbers Ca = 0.12 × 10−2–1.14 × 10−2 and W : G = 1:3–3:3. The results indicated that: (1) the dissolution of CO 2 reduced oil viscosity, inhibiting the fingering phenomenon, promoting stable displacement and enhancing oil recovery. (2) The viscosity reduction effect of CO 2 dissolution was more effective in viscous fingering. (3) Analysis of the EOR capacity after injecting a unit volume of displacement fluid confirmed that the optimal W : G remains 1:3. These findings highlight the importance of considering CO 2 dissolution and its viscosity reduction effect to optimize WAG injection strategies for enhanced oil recovery. [ABSTRACT FROM AUTHOR]

Carbon dioxide foam injection stands as a promising method for enhanced oil recovery (EOR) and carbon sequestration. However, accurately predicting its efficiency amidst varying operational conditions and reservoir parameters remains a significant challenge for conventional modeling techniques. This study explores the application of machine learning (ML) methodologies to develop a robust model for matching experimental values in CO 2 foam flooding scenarios. Leveraging a comprehensive dataset encompassing diverse surfactants and rock types, with varied porosity and permeability, our model demonstrates accurate predictions across a wide spectrum of conditions. By focusing on key parameters such as foam apparent viscosity, interfacial tension (IFT), injected foam volume, initial oil saturation, porosity, and permeability, we unveil the pivotal role of these factors in determining CO 2 foam EOR performance. Through rigorous analysis, we identify the relative importance of each input parameter, with injected foam volume, apparent viscosity, and IFT emerging as dominant factors. The most accurate model was deep neural network (DNN) (R2 value of 0.99). Higher foam viscosity and lower IFT were found to significantly enhance oil recovery rates, though their effects plateau beyond certain thresholds (apparent viscosities above 1200 cP and IFT values below 0.2 mN/m). The findings underscore the potential of ML-driven approaches in enhancing CO 2 foam EOR predictions, offering insights crucial for optimizing foam flooding performance across diverse reservoir settings. [Display omitted] • Development of ML models for predicting oil recovery during CO 2 foam EOR. • Six ML algorithms trained involving six input parameters including foam fluid properties. • Artificial neural networks outperformed the other employed algorithms. • Feature importance analysis revealed apparent viscosity and IFT as critical parameters. • Higher foam viscosity and lower IFT values resulted in increased predicted oil recovery potentially over 35%. [ABSTRACT FROM AUTHOR]

• The addition of polymer can regulate the rheological behavior of C/W foam. • The inhibition of foam shear thinning is beneficial for EOR. • The foam displacement behavior is verified by two-phase flow simulation. Polymer-enhanced foam can reduce viscous fingering by controlling CO 2 mobility, thus improving the sweep efficiency and CO 2 sequestration. High internal phase CO 2 foam with a foam quality of 0.9 can further improve viscosity and flow ratio due to its tightly packed structure. In this study, cocamidopropyl betaine (CAPB) and four polymers were used to produce high internal phase CO 2 foams. The rheological behavior of the foam was measured via a steady-state flow experiment using a straight tube. Polymer-enhanced foams exhibited high viscosities, but they all exhibited shear-thinning non-Newtonian behavior and conformed to the power-law model. The changes in the rheological properties were mainly due to the different adsorption behaviors of the polymers. Core flooding experiments showed that high-viscosity foam significantly improved oil recovery compared to water. Among them, polyvinyl alcohol (PVA)- and poly (2-acrylamide-2-methyl-1-propanesulfonic acid) (PAMPS)-enhanced foams exhibited a significant increase in ultimate oil recovery, reaching 85.21% and 80.69%, respectively. By combining the displacement pressure difference and two-phase flow simulation in porous media, the synergistic effects of the viscosity coefficient and power-law index on enhanced oil recovery (EOR) were verified. The viscosity of the foam determines its ability to plug high-permeability zones, which is the premise of the EOR. With an increase in the shear resistance of the foam, the foam fluid can further spread in the low-permeability zones, enhancing the sweep efficiency and residual oil recovery. [ABSTRACT FROM AUTHOR]

Some surfactants may not be effective in harsh reservoir environments because of their tendency to precipitate in high salinity and high temperature conditions. However, Zwitterionic surfactants are considered more tolerant to salinity and temperature. This study investigates the ability of zwitterionic surfactants to improve oil recovery in tight core samples obtained from the Middle Bakken (MB) Formation in North Dakota. The Laboratory tests to determine the efficacy of three betaine zwitterionic surfactants were carried out at a temperature of 90 °C and a high salinity formation brine of 29 wt% to simulate oil recovery under Bakken reservoir conditions. Before the imbibition experiment, the samples underwent petrophysical investigation, and the mineral compositions were determined using the XRD method. The three surfactant samples ME1, CD 2, and CG 3 applied in the study consistently changed the wetting condition of Bakken cores from contact angle of 143.2° to a range of 32°-42°, indicating changing from oil-wet to water-wet. The result obtained shows that the interfacial tension (IFT) between brine and crude oil was reduced from 34.5 mN/m to 8.9 × 10−1 mN/m, 1.19 mN/m, and 2.49 mN/m, respectively, at a critical micelle concentration (CMC) of 0.05 %. The surfactants demonstrated a significantly higher ability to recover oil from the core samples compared to the use of brine only. The imbibition experiments revealed an extra oil recovery of 16.4 % at CMC. Thus, the imbibition of surfactant formulations offers significant potential for enhancing oil recovery in the Bakken Formation. [Display omitted] • The recovery capacity of betaine zwitterionic surfactants in Bakken brine/crude oil systems was explored. • Zwitterionic surfactants were tested at 90 °C and 29 wt% salinity to mimic Bakken reservoir conditions. • The impact of salinity and temperature on interfacial tension (IFT) was studied. • An improved effect of wettability alteration of Bakken cores from oil-wet to water-wet wettability was observed. • Surfactant imbibition recovered more than 12.6 % additional oil from the Bakken core samples. [ABSTRACT FROM AUTHOR]

• The effect of different microwave frequencies on improving the quality of heavy oil was investigated. • According to the spectral sulfuration coefficient, a significant decrease in sulfur content was observed at the frequency of 2 GHz. • According to GC–MS, a strong dependence of naphthalene content on MR frequency was seen. • The average diameter and average height of the aromatic sheet stack reduced with decreasing frequency. Asphaltene and resin are polar compounds that have a high potential to absorb microwaves. Irradiation frequency is one of the important factors in increasing the efficiency of this process in improving the quality of heavy oil, which has not yet been investigated in detail. Therefore, this research was designed with the aim of analyzing the effect of different microwave frequencies on improving the quality of heavy oil at frequencies of 1.6, 2 and 2.5 GHz in a period of 5 min. The results of group composition (SARA) showed that, as the frequency of microwaves diminish the amount of asphaltene decreases drastically, which could be a reason for the transformation of long-chain hydrocarbons into short-chains hydrocarbons and their stabilization in lighter content. Based on the micellar theory of the physical structure of crude oil, the highest effectiveness in creating stabile colloid was obtained for the frequency of 2 GHz. In addition, in the GC–MS study of saturated compounds, isoalkanes dominated over n-alkanes, which is probably due to the separation of aliphatic substituents from asphaltene chains. The chromatograph content of aromatic compounds showed a strong dependence of naphthalene content on microwave radiation (MR) frequency. Moreover, the abating trend of sulfur coefficients in asphaltene was observed with decreasing frequency in FTIR spectroscopy, which was consistent with EDX data. X-ray diffraction analysis (XRD) revealed the structural changes of asphaltene stacks. Whereby, the average aromatic stack height (L c) with MR for MF–1.6 and MF–2 reduced from 11.54 Å to 10.59 Å and 10.43 Å, respectively, compared to EHO. Furthermore, the distance of the aromatic layer (d m) was augmented by decreasing the microwave frequency. [ABSTRACT FROM AUTHOR]

[Display omitted] • CO 2 responsive Janus SiO 2 nanofluid system was designed. • Crude oil emulsion breaks down after 5 min by CO 2 bubbling. • The response mechanism was proposed on the interfacial adsorption, rheological behavior and chemical properties. • Interfacial synergy behavior of JNPs, surfactants and asphaltenes was investigated. • Formation in-situ emulsification W/O Pickering emulsion control and flooding. Aiming to address the issues of limited suitability of conventional chemical oil displacement materials for formation conditions and the serious emulsification of oil and water in the produced liquid, the innovative nano oil-displacing system with CO 2 -responsive behavior has been developed. This system integrates oil displacement and emulsion breaking. The efficacy of the CO 2 -response system in creating stable emulsions with a high capacity to decrease interfacial tension has been demonstrated. The interfacial responsive behavior of all active components, including Janus nanoparticles, sodium oleate, gums, and asphaltenes, in the emulsion system was analyzed in terms of interfacial rheology and adsorption. Additionally, the prepared system demonstrated a rapid response to CO 2 , effectively breaking the emulsion within 5 min. Furthermore, the oil recovery enhancing mechanism of the CO 2 -response system was investigated using a microscopic visualization model. The system was proved to be efficient in initiating the residual oil within pore channels. Considering the combined effectiveness of the CO 2 -response system in terms of efficient oil displacement and rapid response, it offers valuable insights for advancing the chemical flooding technology of in enhanced oil recovery. [ABSTRACT FROM AUTHOR]

• We study formate species, a product of CO 2 electrochemical reduction, as an alternative carbon carrier for sequestration and EOR • Formate solution injection yielded greater levels of oil recovery and net carbon storage • Carbon-bearing species resided in the dense aqueous phase without having to rely on petrophysical trapping mechanisms • In establishing carbon tax credit policies and regulations, policymakers should include alternative carbon carriers. As carbon capture, utilization, and storage (CCUS), carbon-dioxide enhanced oil recovery (CO 2 EOR) has inherent shortcomings, such as inefficient oil recovery and carbon storage, and low storage security with mobile CO 2. This paper presents a techno-economic-environmental analysis of using formate species, a product of CO 2 electrochemical reduction, as an alternative carbon carrier for sequestration and EOR in a carbonate oil reservoir in the Gulf of Mexico Basin. CO 2 injection, water-alternating-CO 2 injection, and aqueous formate solution injection were compared using a compositional reservoir simulation model and an economic calculator. Formate solution injection yielded greater levels of oil recovery and net carbon storage, where the carbon-bearing species resided in the dense aqueous phase without having to rely on petrophysical trapping mechanisms (structural and capillary). The enhanced oil production, net carbon storage, and storage security can be promoted by providing formate-based CCUS with more incentives (e.g., greater tax credit) in comparison to CO 2 -based CCUS for EOR and the manufacture of chemicals and products. In establishing carbon storage incentive policies and regulations, policymakers should include alternative carbon carriers. [ABSTRACT FROM AUTHOR]

Within the broader strategy of deep decarbonization, hydrogen stands out as an emerging energy vector poised to influence various sectors. Recognizing that its role is in development and not yet fully realized, our research focuses on the transitional use of depleted oil reservoirs for hydrogen storage and enhanced oil recovery (EOR). While these reservoirs are not geologically superior for hydrogen storage, their established containment capabilities and existing infrastructure offer dual benefits and economic incentives through the valorization of residual oil. To circumvent the limitations of conventional hydrogen injection, such as poor sweep efficiency and premature breakthrough, we propose the use of high-viscosity hydrogen foam. Our experimental data reveals that such foam can significantly enhance oil recovery by 17.95% and increase storage efficiency to 36.2%. These improvements underscore the foam's ability to control hydrogen mobility and optimize sweep efficiency within heterogeneous geological formations. These findings suggest that high-viscosity hydrogen foam could significantly improve the effectiveness of depleted reservoirs for both energy storage and the recovery of residual oil. Looking forward, it is crucial to investigate the long-term integrity of subsurface hydrogen storage, the transition from laboratory to field-scale applications, and the environmental consequences to ensure that this approach is sustainable. Our study serves as an incremental step in recognizing the integral role hydrogen could play in achieving a decarbonized energy future. [Display omitted] • Hydrogen foam achieved 17.95% incremental oil recovery versus 6.39% for sole hydrogen. • Foam enhanced hydrogen storage efficiency to 36.2% from 8.4%. • Visualization showed hydrogen foam significantly enhanced oil recovery. [ABSTRACT FROM AUTHOR]

• The synergy of zwitterionic and nonionic-anionic surfactants can greatly enhance in-situ emulsification performance. • The combination of NPEC and OAPB significantly reduces interfacial tension and enhances emulsion stability. • The synergistic effects of NPEC and OAPB arise from electrostatic attraction and form a dense interfacial film. • In-situ emulsification flooding has the potential to enhance both oil displacement efficiency and sweep efficiency. In-situ emulsification flooding has the potential to enhance oil recovery in waterflooded heavy oil reservoirs. The objective of this study was to investigate the synergistic effects of a nonylphenol polyoxyethylene ether carboxylate (NPEC) nonionic-anionic surfactant and an oleic amide propyl betaine (OAPB) zwitterionic surfactant on interfacial tension and emulsifying capacity. The synergistic effects of NPEC/OAPB arise from electrostatic attraction between NPEC and OAPB, which facilitates the formation of a dense adsorption film at the oil–water interface to increase the intensity and strength of the interfacial film. Consequently, the interfacial tensions between the emulsification systems and heavy oil rapidly decrease to ultralow levels, which promotes rapid heavy oil dispersion into stable oil-in-water (O/W) emulsions with minimal disturbance. Sandpack flooding tests showed that the injection of a 0.3 wt% NPEC/OAPB synergistic system resulted in an additional oil recovery of 14.8%. Micromodel flooding tests demonstrated that residual heavy oil could be easily emulsified into stable O/W emulsions by an in-situ emulsification system to increase oil displacement efficiency. The formation of stable emulsion droplets via the Jamin effect effectively blocks pore throats to improve sweep efficiency. [ABSTRACT FROM AUTHOR]

[Display omitted] • The applications of nanomaterials in EOR are summarized from 0D, 1D, and 2D. • The main EOR mechanisms of nanomaterials are concisely presented. • The influence factors of EOR are elaborated from nanomaterials and the environment. • The challenges and development of nanomaterials used in the EOR are discussed. In recent years, nanomaterials have shown great potential in the enhanced oil recovery (EOR) process due to their superior properties. In this work, the application of nanomaterials in EOR is reviewed and classified into various categories based on their dimensionality, ranging from zero-dimensional, one-dimensional to two-dimensional nanostructures. The EOR mechanisms related to nanofluids are thoroughly discussed. Key factors contributing to the effectiveness of nanomaterials in EOR include the enhancement of structural separation pressure, the reduction of interfacial tension, and the modification of wettability properties. In addition, the review analyzes the effects of different factors on the stability of nanomaterials and their effectiveness in EOR. Researches show that the stability and performance of nanofluids used in EOR are significantly influenced by the size and concentration of nanomaterials. Generally, smaller particle sizes and higher concentrations result in more effective oil recovery. Furthermore, the review summarizes the challenges and opportunities of the EOR process with nanomaterials, pointing out that the cost is the first issue to be solved in applying nanomaterials to EOR. Although expanding nanofluids from laboratory to oilfield applications faces many challenges, nanomaterials can still be a significant candidate for future EOR techniques. [ABSTRACT FROM AUTHOR]

In this paper, I delve into the physics of foams within the context of Enhanced Oil Recovery (EOR). Foams present a promising prospect for use in EOR, applicable to both conventional and non-conventional oil wells. A primary challenge faced by oil industry technologists is ensuring foam stability in porous media under harsh conditions of temperature, pressure, and salinity. To surmount these challenges, a profound understanding of the physicochemical mechanisms governing foam formation and stability at a microscopic level is required. In this article, I explore some fundamental aspects of foam physics that should be considered when developing foam systems for EOR. I conclude the paper by briefly discussing the use of machine learning in the design of foam-assisted EOR, and by highlighting the potential of smart foams in the oil industry. [Display omitted] [ABSTRACT FROM AUTHOR]

• Surface modification of nanoparticles is key for the successful implementation of foam for subsurface applications. • Previous research has focused on enhanced oil recovery, with limited exploration of novel nanoparticles for CO2 sequestration. • Hydrophilic nanoparticles increase foam drainage, while partially hydrophobic nanoparticles prevent foam rupture. • Surface grafting of nanoparticles introduces additional mechanisms for bubble interaction and preventing coalescence. Foams are used as an enhanced oil recovery (EOR) method to reduce the mobility of injected gaseous phases. However, foam stability is often compromised under harsh reservoir conditions, leading to drainage of the aqueous phase and gas diffusion. Incorporating nanoparticles, particularly SiO 2 , has been found to enhance foam stability due to their surface chemistry and natural abundance. To create stable nanofluids at high temperatures and low concentrations, nanoparticles need to have their surfaces altered, allowing particles and molecules to interact and keep the nanoparticle-stabilized foam in the reservoir for extended periods. This review paper highlights the use of novel nanoparticles for stabilizing foams for EOR and CO 2 sequestration. It also discusses the modification of nanoparticles to improve foam stability in porous media, focusing on the impact of surface groups and hydrophobicity. Additionally, it covers how to alter nanoparticle surfaces by adding different functional groups or long-chain molecules to stabilize nanofluids in various conditions. The review also delves into how charge interactions and the hydrophilic or partially hydrophobic nature of nanoparticles affect foam stability. Overall, incorporating novel nanoparticles with surfactants has the potential to optimize oil recovery and CO 2 sequestration by improving foam stability. This perspective article explores the potential of using newly modified nanoparticles to stabilize foams and provides a comprehensive review of recent advancements in utilizing modified nanoparticles for foam stabilization, with a focus on surface-modified novel nanoparticles and their influence on stabilizing foams. [ABSTRACT FROM AUTHOR]

[Display omitted] • The impact of diethyl ether on the interfacial tension (IFT) of crude oil-brine was examined under varying salinity and temperature conditions. • An experimental database comprising 7,017 sets of crude oil/brine/DEE IFT data was acquired. • Six advanced machine-learning models were developed to accurately estimate the IFT of Crude oil–Brine-DEE. • Statistical analysis was conducted, demonstrating outstanding predictions for a wide range of input variables. Solvent injection, a well-established method for enhanced oil recovery (EOR), has demonstrated significant improvements in oil recovery when compared with conventional water flooding techniques. The interfacial tension (IFT) is pivotal in determining the displacement efficiency and overall performance of innovative techniques like dimethyl ether-enhanced waterflooding (DEW), which has gained substantial attention in recent years. In this study, following laboratory measurements of IFT, six advanced machine learning (ML) techniques were employed: Generalized Linear Model (GLM), Generalized Additive Model (GAM), Random Forest (RF), Support Vector Machine (SVM), Extreme Gradient Boosting (XGBoost), and Boosted Regression Tree (BRT) to model the IFT in both oil-brine and oil-brine-diethyl ether (DEE) systems. The analysis is based on an extensive dataset comprising 7,017 data points for oil-brine and 6,949 data points for oil-brine-DEE systems obtained from experimental studies. The findings indicate that the developed RF model excels in predicting IFT, boasting a remarkable coefficient of determination (R2 = 0.99) along with the lowest root mean squared error (RMSE = 0.2), mean squared error (MSE = 0.04), and mean absolute error (MAE = 0.13). The study underscores the significance of optimizing salinity levels to achieve the most substantial reduction in IFT. This reduction is attributed to the enhanced migration of polar components, such as asphaltene molecules, to the interface of the oil-brine system. Moreover, the research highlights a synergistic decrease in IFT when both DEE and soluble ions are present, resulting in the lowest IFT at around 2 mN/m in 40,000 ppm salinity (S 2) at 70 °C (T 3). This indicates that the adsorption of DEE at the water–oil interface forms a layer capable of adsorbing ions, thereby enhancing the layer's thickness. As a result, the oil–solvent-ion layer becomes thicker compared to the oil-ion layer, leading to the maximum decrease in IFT. Additionally, with increasing temperature up to 70 °C, the IFT of both systems demonstrated a downward trend, as evidenced by all experiments. The outcomes of this study have the potential to enhance our comprehension of the underlying mechanisms involved in water-soluble solvent EOR techniques. [ABSTRACT FROM AUTHOR]

• Effect of produced water components on polymer microsphere swelling properties was investigated. • The injectivity and in-depth migration characteristics of polymer microsphere was studied. • The EOR mechanisms of microsphere solution prepared with produced water was revealed. Due to the strong heterogeneity, the infaust mobility ratio of offshore heavy oil reservoirs and the high cost of produced water treatment, a "green" in-depth profile control technology was proposed, which integrated produced water reinjection and microsphere in-depth profile control and displacement technology. Experimental results show that RGO-PMSs maintained to be spherical and expanded 5.2–6 time after aging 15 days in brine. While the size of RGO-PMSs aggregation increased 15–25 times, which induced the enhancement of plugging efficiency when permeability was higher than 3000 mD. During RGO-PMSs migration in porous media, it could adjust profile by adsorbing on rock surface or forming plugging in the forms of single capture, bridging, and accumulation. Due to the elastic deformation ability of RGO-PMSs, the particles could enter in-depth reservoirs to form plugging and modulate profile. Moreover, RGO-PMSs system injection and subsequent water flooding could enhance the oil recovery in high permeability layer and low permeability layer of 31.3% and 73.5%, respectively in parallels core displacement experiments. It is believed that the proposed produced water injection combined with RGO-PMSs could be a potential "green" candidate for enhancing oil recovery in offshore heavy oil reservoirs. [ABSTRACT FROM AUTHOR]

In this work, an anatase Ti 0.7 W 0.3 O 2 -supported Pt 3 Ru nanoparticles (NPs) were fabricated by combining the advantages of the non-carbon Ti 0.7 W 0.3 O 2 nanosupport and the synergistic effect of the bimetallic Pt 3 Ru nanoalloy that was investigated as electrocatalyst toward alcohol electrochemical oxidation. The bimetallic Pt 3 Ru nanoparticles with ~3 nm in diameter were relatively well-dispersed on the surface of the anatase Ti 0.7 W 0.3 O 2 nanosupport via a surfactant-free microwave-assisted polyol route that, which was attributable to the good dispersibility of ethylene glycol and the rapid, uniformity of the microwave heating. For methanol and ethanol electrochemical oxidation, the as-obtained Pt 3 Ru (NPs)/Ti 0.7 W 0.3 O 2 electrocatalyst exhibited the low onset potential (~0.10 V vs. NHE for MOR and ~0.35 V vs. NHE for EOR) and high mass activity (~350.84 mA mg Pt −1 for MOR and ~274.59 mA mg Pt −1 for EOR) compared to the commercial Pt (NPs)/C (E-TEK) electrocatalyst. Additionally, the CO-stripping and CA results indicated the remarkably enhanced CO-tolerance of the Pt 3 Ru (NPs)/Ti 0.7 W 0.3 O 2 catalyst. After the 5000-cycle accelerated durability test (ADT) in acidic ethanol media, the bimetallic Pt 3 Ru (NPs)/Ti 0.7 W 0.3 O 2 catalyst only showed the mass activity loss of 19.11% of its initial mass activity, compared with the severe deterioration of 44.04% of the commercial Pt (NPs)/C (E-TEK) catalyst. The outstanding results could be interpreted due to the bifunctional mechanism of the Pt 3 Ru nanoalloys combining with the synergistic effect between the bimetallic nanoalloy and the mesoporous Ti 0.7 W 0.3 O 2 nanosupport as well as the superior anti-corrosion of the TiO 2 -based nanosupport under acidic and oxidative environments. [Display omitted] • The Pt 3 Ru/Ti 0.7 W 0.3 O 2 catalyst was fabricated using microwave-assisted polyol route. • The Pt 3 Ru/Ti 0.7 W 0.3 O 2 catalyst showed the great performance for both MOR and EOR. • The Pt 3 Ru/Ti 0.7 W 0.3 O 2 catalyst displayed the superior CO-tolerance and stability. [ABSTRACT FROM AUTHOR]

A novel exopolysaccharide, named WL gum, was obtained from the fermentation broth of Sphingomonas sp. WG. The effects of temperature and salinity on the rheological properties of WL gum solution and fermentation broth (WL-Fer) were systematically investigated and compared with another exopolysaccharide, welan gum (WG). The results showed that the network structures formed in WL solution were more compact than those of WG. WL solution and WL-Fer were not sensitive to high temperatures (80–120 °C) and only weakly affected by the cations (Na+, K+, and Ca2+). Moreover, Fe2+ and high temperature (100 °C) even enhanced the viscosity of WL-Fer. The results of flooding experiments demonstrated that the enhanced displacement efficiency of WL gum (14.55%) was similar to that of partially hydrolyzed polyacrylamide (HPAM, 13.36%) at 65 °C. And the enhanced displacement efficiency of WL-Fer was as high as 23.31%. It can be concluded that WL gum is a kind of potential and environmentally benign polymer that could be used in EOR, and the fermentation broth could be used directly after dilution. Unlabelled Image • WL gum (WL) is a novel sphingan produced by Sphingomonas sp. WG. • The solution of WL and fermentation broth (WL-Fer) form gel-like structures. • The viscosity of WL-Fer increase with high temperature not exceeding 100 °C. • Salts cannot destroy the network states of WL and WL-Fer, even for Ca2+ and Fe2+. • The enhanced oil recovery of WL and WL-Fer can be above 14%. [ABSTRACT FROM AUTHOR]

Surfactant huff-n-puff can enhance fossil hydrogen energy recovery from low permeability reservoirs. However, due to the high cost and adsorption of surfactant, its commercial application is limited. Liquid nanofluid (LNF) has been widely used in hydraulic fracturing since it can significantly reduce the adsorption. In this study, a series of experiments were conducted to investigate the potential of LNF huff-n-puff. First, the spontaneous and dynamic imbibition with NMR was conducted to study the imbibition oil recovery for the LNF. The results showed that the spontaneous imbibition recovery of LNF is 1.43 folder than brine. Besides, the LNF enters the small pores first in spontaneous imbibition. In the process of dynamic imbibition, the LNF enters the larger pore with smaller resistance first, then enters the small pore around the flow path. After dynamic imbibition, the imbibition recovery in small pores increased 54%. Moreover, pressure transmission tests (PTT) were conducted to evaluate the increasing rate of reservoir pressure. This work provides a new view of how surfactant or LNF functions in the process of huff-n-puff. • The movement of nanofluid was studied. • A new method to test increasing rate of pressure. • A new view to evaluate surfactant in huff-n-puff. [ABSTRACT FROM AUTHOR]

Due to the heterogeneity of the pore structure, there is still much residual fossil hydrogen energy in the pore space. In this study, the distribution of residual fossil hydrogen energy after imbibition with liquid nanofluid (LNF) has been studied through the. Firstly, relevant properties of the LNF were tested, including particle size, wettability alteration, and interfacial tension (IFT). Then, one micromodel under both oil-wet and water-wet conditions was used to elucidate the difference of residual oil after imbibition. Moreover, the difference of imbibition processes with oil-wet and water-wet models was further studied. Finally, the influence of dimensions and coordination numbers of pores was investigated. Besides, the impact of fluid type on imbibition efficiency was also compared through microfluidic experiments. Results show that the residual oil saturation is significantly higher in the oil-wet micromodel than in the water-wet micromodel, even the wettability alteration additive was used. There are four kinds of locations for residual oil after imbibition in water-wet micromodel, while only three kinds of locations for residual oil in oil-wet micromodel. The imbibition rate and residual oil saturation in small pores are higher than the larger ones. Due to the unbalanced force at pore throats, a micromodel with a high coordination number has lower residual oil saturation. Besides, the lower residual oil saturation is obtained by adding the LNF. This paper provides a micro-visual method to understand the imbibition process under different wettability and pore structures in fossil hydrogen reservoirs. • The difference of residual fossil hydrogen energy after imbibition under different wettability was compared. • The imbibition orders in different pore scale and wettability were discussed. • The influence of dimensions and coordination numbers of pores were investigated. • The impact of fluid type on imbibition efficiency was compared. [ABSTRACT FROM AUTHOR]

Heterogeneity is well known to reduce sweep efficiency during oil development processes. Self-adaptive micro gel (SMG) as a agent for in-depth profile control is significantly limited to strict matching between complicated pore structure and particle size. A new matching factor considering size and distribution of particle and pore is presented to study the relationship of SMG and cores. The resistance coefficient and plugging rate indicate that it will get the greatest plugging effect when matching factor ranges from 1 to 1.3. Long cores with multiple pressure points and Dual-tube parallel flooding experiments shows that SMG can significantly reduce the water cut and obtain the best oil recovery efficiency when the high permeability layer within the matching factor range. According to the number and relative size to pore throats of SMG, microfluidic experiments show that plugging can be divided into direct plugging, bridging plugging, superimposed plugging and hydrodynamic plugging. Unlabelled Image • The matching factor considers the particle size and its distribution range. • The permeability of heterogeneous core is selected by matching coefficient. • Double inject end avoid the effects of SMG plugging at the injection side. • The micro - model is used to reveal the macro – mechanism. [ABSTRACT FROM AUTHOR]

• The temperature-resistant polymeric surfactant FA was synthesized as a foam stabilizer. • Constructed temperature-resistant CO 2 foam system EFS and optimized its formula. • Elucidated the foam stabilization mechanism of EFS foam from lamella adsorption. • Clarified the CO 2 -EOR effect of the EFS foam system. • Quantitatively split the contribution rate of three storage mechanisms to CO 2 storage. Foam flooding can effectively suppress CO 2 channeling, improving oil recovery and CO 2 storage efficiency. However, elevated reservoir temperatures can considerably impair the effectiveness of CO 2 foam. Moreover, our comprehension of the storage capacity and mechanisms involved in CO 2 foam flooding remains limited. This study introduces a temperature-resistant foam system, denoted as EFS, and conducts assessments of its enhanced oil recovery (EOR) efficiency and CO 2 storage ability. To begin, the polymeric surfactant (FA) was synthesized by micellar polymerization, and its temperature resistance performance was evaluated by the TGA curve, aging viscosity, and hydrodynamic size test. Following, the room- and high-temperature foaming performance of FA, foaming agent EBB, and the compound system (EBB + FA, named EF, and EBB + FA + nano-SiO 2 , named EFS) were compared, and the optimal foam system formula was optimized. Next, the plugging performance of EFS foam under three gas–liquid ratios and two injection rates was evaluated by core injectivity experiments. Lastly, CO 2 flooding (5 MPa, 15 MPa, and 30 MPa) and CO 2 foam flooding (15 MPa) were carried out to clarify the CO 2 channeling law, EOR, and CO 2 storage effect of CO 2 foam flooding. Meanwhile, the contribution rates of different mechanisms to CO 2 storage were qualitatively split. The TR-IR and 1H spectra confirm the successful synthesis of FA, whose molecular degradation temperature surpasses 230 °C and has good solution thermal stability. Upon meticulous evaluation of foam volume and half-life, the pinnacle formulation for the EFS foam system emerged as comprising 0.2 wt% EBB, 0.3 wt% FA, and 0.05 wt% nano-SiO 2. Notably, the introduction of nano-SiO 2 exerted a profound influence on enhancing foaming performance, particularly at elevated temperatures. In terms of plugging efficacy, the EFS foam exhibited impressive performance. Optimal results were obtained using a gas–liquid ratio of 3:1 and an injection rate of 0.4 mL/min. Supercritical CO 2 flooding can slightly delay CO 2 channeling, but the effect is significantly lower than near-miscible CO 2 flooding. CO 2 foam flooding can further increase EOR by 13.74 % based on CO 2 flooding. Meanwhile, CO 2 foam flooding can increase the storage rate by 3.53 % based on reducing CO 2 consumption by 15.23 %. Residual storage, comprising a substantial majority at over 65 %, stands as the predominant method for CO 2 storage, with oil dissolution storage following behind, which increases significantly with the remaining oil. [ABSTRACT FROM AUTHOR]

• An in situ bitumen decomposition kinetic model is developed. • The significance of bitumen decomposition to oil recovery is discussed. • A green and economical recovery tech without steam additives injection from surface. • The tech has higher oil production, lower steam consumption and carbon emission. In the late stages of Steam Assisted Gravity Drainage (SAGD) development, the increase in steam chamber volume and greater heat losses result in elevated thermal losses, and increased CO 2 emissions, leading to reduced economic efficiency. To address this issue, this paper proposes a pioneering approach, termed the in situ solvent generation enhanced SAGD technique (ISSG-SAGD). Through a comprehensive review of Athabasca bitumen aquathermolysis, thermal cracking, and their phase behavior with solvents, a general reaction kinetic model and fluid model are established. Subsequently, the feasibility and recovery mechanism of ISSG-SAGD are elucidated by employing numerical simulation that compares SAGD with ISSG-SAGD. Results show that, in comparison to SAGD, ISSG-SAGD reduces steam consumption by 13.77 %, lowers carbon intensity by 18.12 % and increases oil production by 5.48 %. These advantages arise from the synergistic integration of recovery mechanisms characteristic of Expanding Solvent SAGD (ES-SAGD) and Steam and Gas Push (SAGP). Notably, non-condensable gas accumulation above the steam chamber diminishes heat loss while replenishing reservoir energy. Simultaneously, light hydrocarbons are strategically positioned at the drainage interface, leading to a reduction in residual oil saturation and an increment in drainage rates. Consequently, ISSG-SAGD emerges as an environmentally sustainable and economically viable trajectory for heavy oil development. [ABSTRACT FROM AUTHOR]

• Three double-chain imidazolium ionic liquids surfactants were synthesized via the one-step Debus-Radziszewski reaction and characterized for their chemical structure by FT-IR, 1H NMR, TGA and LC-MS. • The physicochemical properties of double-chain imidazolium ionic liquids surfactants are better than that of single-chain imidazolium surfactants. • [C14mimC14][OAc] had lowest surface tension and critical micelle concentration, which were 29.07 mN/m and 1.64 × 10-2 mmol/L, respectively. • Double-chain imidazolium ionic liquids surfactants have good interfacial activity and wettability. Three double-chain imidazolium ionic liquid surfactants (ILS) with varying alkyl lengths, namely [C10mimC10][OAc], [C12mimC12][OAc], and [C14mimC14][OAc], were synthesized via the one-step Debus-Radziszewskireaction. The chemical structures of these three ILS were confirmed through FT-IR, 1H NMR and ESI-MS analyses. Their surface/interface activity, wetting ability, thermal stability, and aggregation properties were investigated. The results indicated that the presence of double-chain hydrophobic groups in ILS exerted a significant influence on their surface/interface activity. Surface activity and micellization properties were assessed using surface tension measurements, revealing that the micellization process of double-chain ILS was more favorable compared to single-chain ILS. Among the three ILS examined, [C14mimC14][OAc] exhibited the lowest surface tension and critical micelle concentration (CMC) values, measuring 29.07 mN/m and 1.64 × 10-2 mmol/L, respectively. Solutions containing approximately 50 ppm of these ILS could reduce interfacial tension to below 1 mN/m. Additionally, the contact angle decreased to less than 90° within 90 s. The formation of aggregates in aqueous solutions was found to be influenced by the number of CH 2 units present in the different ILS molecules. [ABSTRACT FROM AUTHOR]

The primary bottleneck in heavy oil production lies in the significant energy consumption and CO 2 emissions associated with steam injection for recovery. To address this challenge, we propose the ISSG-SAGD (in-situ solvent generation enhanced steam assisted gravity drainage) technique. The recovery mechanisms and operational strategies are investigated using a numerical simulation with an Athabasca bitumen reservoir model, affirming the considerable environmental and economic potential of ISSG-SAGD. The results demonstrate that ISSG-SAGD integrates the recovery mechanisms of both SAGP (steam and gas push) and ES-SAGD (expanding solvent SAGD). Moreover, employing cyclic steam injection, maintaining low operating pressure, and initiating ISSG-SAGD at an early stage enable a 33.79 % reduction in steam consumption, a 39 % decrease in average carbon intensity, a 5.40 % increase in oil production, and a 61.28 % rise in net present value compared to conventional SAGD. This study proves that the ISSG-SAGD approach offers a sustainable and efficient alternative for future heavy oil recovery endeavors, addresses the challenges of high energy consumption and carbon emissions, and paves the way towards a green and economically viable future for the heavy oil development. • ISSG-SAGD is a low carbon and high-efficiency heavy oil recovery technique • Utilizing solar power to supply gravity drainage and in-situ cracking • ISSG-SAGD combines SAGP and ES-SAGD mechanisms, increased oil production • ISSG-SAGD lowers carbon emissions and demonstrates higher economic efficiency to SAGD [ABSTRACT FROM AUTHOR]