This study critically evaluates Russia’s carbon capture, utilization, and storage (CCUS) policy within the framework of low-carbon hydrogen development, with a particular focus on the feasibility of “blue” hydrogen. Using a multivocal literature review of 44 high-quality academic and gray sources, the analysis compares Russia’s emerging CCUS framework with established international policy models. The results show that blue hydrogen production in Russia is technically feasible and cost-competitive at the production stage, with estimated costs of approximately USD 2.8–3.5 per kg H 2 when CCUS is applied, compared to USD 0.5–1.7 per kg H 2 for unabated hydrogen. Lifecycle emissions of blue hydrogen range from 7.6 to 9.3 kg CO 2 -eq/kg H 2 , representing a 30–45% reduction relative to grey hydrogen but remaining significantly higher than renewable-based green hydrogen (0.6–2.5 kg CO 2 -eq/kg H 2 ). Russia possesses substantial geological CO 2 storage potential, estimated at over 7.3 Gt, with individual projects capable of injecting up to 1 Mt CO 2 annually; however, only about 22.6% of this capacity is suitable for CO 2 -enhanced oil recovery. Despite these technical advantages, large-scale CCUS deployment is constrained by high capital intensity, leakage risks, geopolitical barriers, and a “soft” regulatory regime lacking enforceable carbon pricing or targeted fiscal incentives. In contrast to countries such as the United States, Norway, and Canada, where tax credits, carbon pricing, and dedicated storage regulation underpin commercial CCUS projects, Russia’s current policy framework remains insufficient to ensure investment viability. The study concludes that without the rapid introduction of robust carbon pricing, legally defined CO 2 storage regimes, and performance-based financial incentives, CCUS in Russia will remain confined to pilot projects, limiting the environmental credibility and export competitiveness of Russian blue hydrogen. • Russian blue hydrogen is technically and cost competitive • Blue hydrogen reduces emissions but lags green • Vast CO 2 storage, limited practical capacity • Policy gaps block CCUS scale-up in Russia • Stronger policies needed for blue hydrogen success

Dynamic adsorption kinetics of the functionalized ionic liquids and their impact on enhanced oil recovery in harsh carbonate reservoirs

Enhanced oil recovery via metal oxide nanoparticles: A review of recent advancements, core mechanisms, and future outlook

Microemulsions versus nanoemulsions: A comparative overview of features, formulation, and pharmaceutical applications.

Genomic insights into the biotechnological potential of Bacillus subtilis DW-2 for enhanced recovery of heavy oil.

The imbibition process, which is characterized by the displacement of non-wetting phase by wetting phase in porous media, plays a crucial role in enhancing oil recovery of unconventional reservoirs. However, due to the complex nature of reservoir characteristics and fluid properties, existing research on this phenomenon presents contradictory conclusions and interpretations. This paper aims to fill this knowledge gap by providing a comprehensive review of the fundamental concepts, primary mechanical factors, and critical influences in oil-water imbibition. Primary mechanisms, including capillary, viscous, gravitational, hydrostatic, inertial, capillary back, dead end, and osmotic forces, are analyzed in terms of their key roles under varying boundary conditions and scales. To further clarify the conflicting research findings, we systematically analyze the factors influencing water imbibition, encompassing rock and fluid properties, rock-fluid interactions, and reservoir conditions. Based on this analysis, an integrated framework is established to describe the underlying coupled mechanisms. Furthermore, this review details the imbibition mechanisms and fluid distribution characteristics across the entire development cycle of unconventional oil reservoirs, from injection and shut-in to flowback and production. It subsequently offers practical recommendations for optimizing development strategies. Finally, we identify persistent knowledge gaps and propose critical directions for future research. By synthesizing these insights, this work provides valuable insights for advancing the understanding of oil-water imbibition and improving recovery processes in unconventional oil reservoirs.

Synthesis of smart temperature responsive silicon quantum dots to stabilize Pickering emulsion for enhancing oil recovery

Facile synthesis of Janus particles via ethanol-water-ammonia interfacial exchange for enhanced oil recovery

Interaction of supercritical CO2 with organic matter: Kerogen crystal stacking structure evolution during supercritical CO2 immersion for enhanced oil recovery and geological storage

Interfacial interactions between oil and porous calcium carbonate in brine: Insights for enhanced oil recovery and spill remediation.

Techno-economic co-optimization of CO2 enhanced oil recovery and geological carbon storage considering CO2 trapping mechanisms

The CO2 channeling issue has long plagued many oilfields implementing CO2 flooding. Foam flooding serves as an important method for controlling gas channeling, and developing an efficient foam-stabilizing system for CO2 is thus of great significance. In this study, silica nanoparticles (NPs) with a diameter of 20 nm were surface-modified to produce NP3-P4 by grafting a hydrophilic group, (γ-glycidoxypropyl)trimethoxysilane, at a density of 3.0 μmol/m2 and a hydrophobic long-chain alkyl group, propyltrimethoxysilane, at a density of 0.4 μmol/m2. The resulting NP3-P4 exhibited a contact angle of 60.2° and retained excellent stability for more than 30 days in 0.25 API brine at 80 °C. When combined with AOS31, the hybrid system produced CO2 foam with a half-life extended to 24 h under harsh conditions (0.25 API brine, 80 °C, and 8 MPa), demonstrating outstanding foam stabilization. In sand-packed tube flow experiments, the composite of AOS31 and NP3-P4 achieved a resistance factor exceeding 70, indicating strong plugging performance. Furthermore, measurements of surface tension and surface dilational modulus revealed that NP3-P4 imparted high expansion elasticity to the interfacial film. Observations via confocal laser scanning microscopy (CLSM) and cryogenic scanning electron microscopy (Cryo-SEM) confirmed a pronounced synergy between NP3-P4 and AOS31. Specifically, in a CO2-saturated environment, the adsorption of betaine surfactants from AOS31 promoted the migration of NP3-P4 to the gas-liquid interface, inducing synergistic interactions and forming a thicker mixed interfacial film in the composite system. This study not only provides deep insights into the underlying stabilization mechanism but also holds considerable potential for broad foam-based applications, particularly demonstrating significant value in carbon dioxide sequestration and enhanced oil recovery (EOR).

Enhanced oil recovery (EOR) methods are essential for maximizing oil extraction from mature reservoirs. Given the ongoing reliance on crude oil, it is essential to advance enhanced oil recovery techniques to boost reservoir production and extend their lifespan. Among the chemical EOR methods, chemical flooding is a well-established technique that can theoretically be utilized across various reservoir conditions. In this paper three novel bis (ethanethioyl) oxalamide derivatives synthesized via an eco-friendly green chemistry route using ethanol solvent at ambient temperature as chemical flooding agents. Their molecular efficacy was rationalized by quantum chemical (DFT) calculations and FTIR spectroscopy, which linked optimal interfacial activity to specific structural features. They were tested as an agent in reducing the interfacial tension (IFT) between the injected water and crude oil and also, in altering the wettability of reservoir rock. The results indicated the efficiency of the new compound (bis N) in reducing the IFT from 27 to 5 mN/m also altering the rock's affinity for water than oil. Finally, this agent was used in chemical flooding experiments on real core plugs under reservoir conditions in terms of (temperature, pressure, and crude oil). From flooding experiments, these calculations indicate positive economics for enhanced oil recovery through this new compound where it can withstand severe reservoir conditions and achieve a recovery factor of 22.82%Sor, 29.75%Sor and 34.12%Sor in the case of 1g/l, 1.5g/l and 2g/l concentrations respectively, from the remaining oil.

Microemulsions have been increasingly applied in oil reservoirs for enhanced oil recovery because they can significantly reduce water-oil interfacial tension and increase the capillary number. However, during subsurface flow, microemulsions undergo phase transitions among Winsor I, II, and III as the salinity, water-oil ratio, and surfactant concentration change. The effectiveness of microemulsions in enhancing oil recovery is strongly dependent on their phase type. Therefore, accurately characterizing the phase-transition behavior is crucial for reservoir development design. The Hand method, which is widely used in numerical simulations, faces challenges, such as low computational efficiency and limited applicability, when dealing with phase equilibrium calculations involving microemulsions and excess phases. To overcome these limitations, this study proposes a simplified two-dimensional Cartesian coordinate method for calculating the microemulsion phase equilibrium. This method reduces complexity by mapping pseudocomponent compositions and the nodal lines of pseudoternary phase diagrams at different salinities onto a planar coordinate system. Compared with the Hand and HLD-NAC methods, the proposed approach improves the computational efficiency while maintaining accuracy. Moreover, validation against experimental data demonstrates that the method effectively captures the salinity-, composition-, and surfactant-dependent phase behaviors of microemulsions. This work provides theoretical support and a practical computational tool for the phase identification and numerical simulation of microemulsions in enhanced oil recovery applications.

Middle-phase microemulsion flooding provides stable oil-displacing fluids which are highly desirable for enhanced oil recovery (EOR). Although nanocellulose-surfactant systems have been widely explored for emulsion-based EOR, their use for stabilizing middle-phase microemulsions has been rarely reported. In this work, a novel middle-phase microemulsion flooding system was formulated by combining phosphorylated cellulose nanocrystals (P-CNCs) with a binary surfactant mix including anionic sodium dodecylbenzenesulfonate (SDBS) and amphoteric dodecyl/myristyl dimethyl hydroxypropyl sulfobetaine (HSB1214). The formulation was evaluated using n-decane as a model oil, NaCl as a model brine, and sandstone cores for core flooding tests. The negatively charged P-CNC adsorbs strongly onto the mixed surfactant micelles via electrostatic interactions and hydrogen bonding, creating a robust interfacial layer. The resulting dispersion remains single-phase and stable in 4.0 wt % NaCl for over 75 days, reflecting the intrinsic macroscopic storage stability of microemulsions. Phase behavior observation, solubilization parameters (SPo, SPw), and dynamic/static interfacial tension (IFT) measurements collectively confirmed the optimal Winsor III middle-phase microemulsion formulation: 0.05 wt % P-CNC, 0.5 wt % SDBS/HSB1214, and 4.0 wt % NaCl. This formulation achieved a dynamic oil-water IFT of 2.4 × 10-4 mN/m, with static equilibrium IFT on the order of 10-3 mN/m. In microscopic EOR and core flooding test (core permeability 217.68 × 10-3 μm2, porosity 24.45%), the optimized P-CNC-surfactant system effectively removed residual oil films and achieved an overall oil recovery of 88.85% (a 25.13% increment over conventional water flooding). Notably, the incorporation of P-CNC suppresses the SDBS adsorption loss rate from 81.60% to 47.06%, corresponding to a 42.34% reduction in surfactant loss, while the P-CNC retention in sandstone cores is only 17.61 μg/g, indicative of excellent pore-scale transport compatibility. Overall, the P-CNC-surfactant flooding system offers a stable, high-performance chemical EOR agent capable of ultralow IFT and robust operation under NaCl model brine conditions.

To address the critical challenge where the excessively high Minimum Miscibility Pressure (MMP) restricts the effectiveness of CO2 flooding, this study proposes a novel strategy utilizing SiO2-ethanol nanofluids (SiO2-C2H6O NFs) as additives to reduce the MMP. By systematically optimizing particle size, concentration, and dispersant types, a 5 nm/5 wt% SiO2 nanofluid with polyvinylpyrrolidone (PVP) as the dispersant was successfully prepared, demonstrating excellent long-term dispersion stability. Phase equilibrium experiments indicate that after adding 20 vol% of the optimized nanofluid into crude oil model components (n-alkanes and cycloalkanes), the solubility of CO2 in the oil phase is significantly enhanced. The maximum average equilibrium pressure reduction (PAVG) reached 2.24 MPa, effectively lowering the MMP of the system. Furthermore, a modified PR-vdW1 equation of state considering nano-confinement effects was developed and validated to systematically reveal the phase equilibrium behavior of CO2-alkane systems within nanopores. This research not only enriches the fundamental thermodynamic data for CO2-hydrocarbon systems but also provides a novel and efficient technical pathway for improving CO2 flooding efficiency and achieving synergistic carbon emission reduction.

Using surfactants to manipulate the interfacial tension (IFT) of oil-water systems represent a critical strategy for enhanced oil recovery (EOR). However, predicting the physical properties of surfactants based on their molecular structure remains a challenging task, as conventional machine learning methods struggle to capture the coupled interactions between molecular structures and environmental parameters, while existing graph neural networks predominantly focus on single-molecule representations and overlook the characteristics of the system environment. Accordingly, a Gated Message-passing Graph Neural Network with an Attention Mechanism (Gated-MPNN-AT) is proposed to integrate molecular graph structures and environmental features, aiming to achieve accurate prediction of interfacial tension in surfactant-oil-water systems. The model dynamically controls the message passing process through a dual gated mechanism, adopts a Cross-Attention mechanism to achieve the in-depth interaction between molecular topological features and environmental parameters, and designs a hybrid robust loss function to handle the IFT data with cross-order-of-magnitude distribution. The research results show that the prediction accuracy of the model is better than that of traditional machine learning methods (such as Random Forest (RF) and eXtreme Gradient Boosting (XGBoost)) and some graph neural network methods (such as Graph Convolutional Network (GCN), and Graph Attention Network (GAT)). Ablation experiments have confirmed that the gated mechanism increases the coefficient of determination (R 2) by 4.8%, and the Cross-Attention fusion strategy reduces the mean absolute error (MAE) by 21.3%. Meanwhile, the model has good generalization ability and strong anti-interference ability against abnormal IFT data.

The adsorption interaction of heavy components at a mineral surface can reduce the flowability of shale oil and decrease the recovery of shale oil. In this work, the heavy component resin was separated from crude oil, and the adsorption and aggregation interactions at shale Illite surfaces were systematically studied from experimental and theoretical insights. Thermodynamic results indicated the Redlich-Peterson model (R2 = 0.990) with the maximum adsorption amount of qm = 6.19 mg/g, reflecting a composite of monolayer resin adsorption and Illite surface heterogeneity. Kinetic results indicated the pseudo-second-order model with the maximum adsorption rate of 31.48 h-1, reflecting a chemical domination of resin interaction at the Illite surface. With 170-times increasement for diffusion rate (kdif) but only 30-times increasement for aggregation rate (kagg), the 'fast diffusion-slow aggregation' processes were also analyzed for low and high resin concentration stages on the Illite surface. For a theoretical calculation, density functional theory elucidated the 'lying-down' configuration of molecular resin with interaction energy of -1.68 eV. A molecular dynamic simulation obtained the binding energy results of Ebin = -113.31 ∼ -1571.71 kcal/mol for 1-20 resin molecules. As a result, the interaction forces were deduced by combining the experimental and theoretical results, including hydrogen bonding (resin H-Illite O), cation-π interactions (resin aromatic structure-Illite K+), electrostatic adsorption (resin S-Illite K+), and coordination interaction (resin S-Illite Al, Si). The additional π-π interactions were produced between resin molecules for high resin concentration interaction. This work can clarify the microscopic interactions of heavy components at the surface of shale reservoir, which can effectively reveal the occurrence pattern of shale oil and improve oil recovery.

An inevitable decrease in oil production from reservoirs all over the world necessitates the application of microbial enhancement of oil recovery (MEOR) technologies. The high total salinity of formation water is a factor strongly suppressing the growth of most industry-applicable strains of hydrocarbon-oxidizing bacteria. The halotolerant strain Ectopseudomonas guguanensis G3 isolated from an oil reservoir (Republic of Kazakhstan) has demonstrated high efficiency of oil degradation and presumable biosurfactant production. The ability of the strain to utilize crude oil, n-alkanes, toluene, and xylene and its resistance to NaCl concentrations up to 6% were shown, as well as a high decrease in the interfacial tension of the culture liquid. Genomic analysis of the strain confirmed its ability to oxidize aromatic oil compounds and a wide range of n-alkanes (with a chain length up to C30) and revealed its potential capabilities to produce alginate, consume nitrate and urea as nitrogen sources, and synthesize betaine as an osmoprotectant. These findings demonstrate the high potential of E. guguanensis strain G3 to be used in oil reservoirs with high-salinity formation water in the biotechnology of oil displacement through oil degradation and in situ microbial metabolite production.

CO2 miscible flooding is an effective enhanced oil recovery (EOR) technique. However, its application is constrained by unclear microscopic displacement mechanisms and the risk of asphaltene deposition. Furthermore, conventional macroscopic experiments and microscopic simulation often fail to adequately address the conditions of medium-deep reservoirs. This study employs an integrated approach combining high-pressure, high-temperature microfluidic experiments with molecular simulations. The microfluidic experimental system enables direct visualization of CO2-crude oil interface dynamics and asphaltene deposition, while quantifying oil recovery. Concurrently, simplified molecular models were constructed based on representative hydrocarbon components of authentic shale oil (i.e., light to heavy alkanes C7H16-C18H38, verified by GC-MS analysis) to analyze alkane adsorption, diffusion on different mineral wall surfaces, and the underlying mechanisms of asphaltene deposition. The results demonstrate that miscible conditions significantly enhance displacement efficiency, with miscible flooding achieving oil recoveries of 84% at 50 °C and 91% at 80 °C, which are significantly higher than those of immiscible flooding (59% and 65%, respectively). However, an increased temperature increases the risk of asphaltene precipitation. Molecular simulations confirm that CO2 exhibits higher solubility in light alkanes (e.g., C7H16) and that high temperature weakens the adsorption of alkane molecules onto quartz surfaces. This study provides critical insights for optimizing CO2 miscible flooding in shale oil reservoirs, proposing a near-miscible strategy at 80 °C that balances high recovery (82%) with economic viability.