Geological storage of CO2 through hydrate formation is a promising approach for carbon sequestration, but its large-scale application remains limited by uncertainties in hydrate distribution and long-term evolution in complex reservoirs. This review systematically examines the occurrence patterns, formation mechanisms, and main controlling factors of gas hydrates in porous media, with a focus on both natural reservoirs and laboratory systems. Hydrate behavior is mainly controlled by sedimentary structure, grain size, and interfacial properties. Coarse-grained and high-permeability sands often promote pore-invading growth, while fine-grained media tend to show particle-displacement behavior. In addition, complex pore structures and fast flow paths increase the diversity of hydrate distribution. We also summarize the effects of key factors, including particle size, temperature, pressure, salinity, wettability, additives, and fluid flow. These factors influence nucleation, growth rate, morphology, and spatial distribution, which together explain the wide range of hydrate patterns observed in natural sediments and laboratory systems. Future work should improve in situ techniques, develop cross-scale models, and strengthen risk assessment to support reliable hydrate-based CO2 sequestration.

CO2 micro bubbles (MBs) represent a promising green approach for enhancing oil recovery in low-permeability reservoirs while advancing the dual carbon goals. The high mass transfer characteristics of MBs constitute their primary advantage, closely related to their hydrodynamics. However, their hydrodynamic behavior under highpressure and high-temperature reservoir conditions remains poorly understood. In this study, we integrate highspeed imaging and NMR to investigate the size evolution and mass transfer of CO2 MBs in oil phase. We found that high pressure can induce shrinkage of smaller CO2 MBs during expansion-paradoxically increasing mean diameter-followed by complete dissolution within 1.3 s. Moreover, their rise velocities exceed those predicted by the Hadamard-Rybczynski theory for single bubble, due to multi-bubble wake interference and flow-field interactions. Mass transfer analysis indicates a shift in dissolution dominance from Laplace- to pressure-driven regimes, reflected in unusual mass transfer coefficient (kL) which decreases then increases with bubble diameter. At 8 MPa, kL values of CO2 MBs reach 4.8-16.2 & times; 10-4 m/s, two orders of magnitude higher than those of ordinary gas. A linear kL- Re relationship was established to predict dissolution behavior. During CO2 core flooding, the superior mass transfer of CO2 MBs induced rapid oil swelling at the front, improving initial oil recovery by 21.1%. These findings offer fundamental insights into the anomalous hydrodynamics of CO2 MBs in oils and pave the way for integrating enhanced oil recovery with long-term carbon sequestration.

The storage and transport of natural gas in solid hydrate form, known as solidified natural gas (SNG), offers a promising alternative to conventional methods such as liquefied natural gas (LNG) and compressed natural gas (CNG). Unlike LNG, which requires cryogenic temperatures and high-pressure systems, SNG can be produced and handled under more moderate conditions. This review examines the current scientific and engineering challenges that continue to limit the industrial adoption of SNG. The underlying mechanisms of hydrate formation are analyzed, focusing on kinetic limitations, the influence of thermodynamic and kinetic additives, and the structural stability of hydrates during transport. The review also assesses the infrastructure requirements for large-scale SNG production, storage, and regasification, highlighting both recent advances and remaining bottlenecks. From an economic perspective, capital and operational costs are compared with those of established technologies, and the feasibility of SNG for different transport distances and capacities is evaluated. Environmental and safety aspects are addressed with particular attention to the impacts of chemical additives, energy use, and potential emissions. Through this critical assessment, this work identifies the key scientific, technical, and environmental factors that must be resolved to enable a transition from laboratory research to commercial-scale deployment of SNG technologies.

CO2 geological storage via hydrate formation in clay-rich marine sediments offers a high-density, environmentally benign solution for carbon capture. However, predictions of hydrate permeability, formation kinetics, and storage capacity under varying clay content remain poorly quantified, limiting engineering design of storage systems and long-term stability assessment. Therefore, 18 CO2 hydrate cores with varying clay content (0.05-0.30) are remolded. The permeability characteristics are systematically investigated across different clay contents. Furthermore, predictive modeling is conducted to elucidate hydrate formation behavior with different clay contents. Results show that increasing clay content induces exponential permeability decay (maximum decrease of 5.18 mD) and elevates the permeability damage coefficient by 26%, attributed to pore volume occupation. Considering induction time and nucleation mechanisms, the CO2 hydrate formation kinetics conform to the N(t) = N0(1-e-((t-to)/tau)<^>d). The characteristic parameter tau demonstrates a positive linear correlation with clay content. In contrast, the parameter d exhibits a negative linear relationship with clay content. When the clay content is 0.15, the hydrate formation is maximum (0.102 mol), and the water conversion efficiency is increased by 36%. Proposed equivalent hydrate saturation, derived from water/hydrate density relationships, correlates negatively with permeability and positively with breakthrough pressure via Pearson analysis. Clay content exerts a stronger influence than equivalent saturation. Crucially, employing a hydrate cap enables CO2 storage via overpressure, enhancing storage capacity by an average of 4.89 times (maximum 6.41 times) relative to pure hydrate storage. These findings provide fundamental theoretical insights for optimizing CO2 hydrate storage strategies in clay-rich marine sediments.

Gas-water migration in mixed-wet porous media is the primary determinant of CO2 trapping efficiency in geological storage applications. Heterogeneous wetting surfaces give rise to scale-dependent, non-snap-off trapping mechanisms that are currently not fully elucidated. Here, the phase-field method is utilized to numerically explore non-snap-off residual trapping and interface overlapping during brine displacement in mixed-wettability porous media. Key findings: wettability distribution governs trapping patterns and scale. For the grain-scale wettability pattern with larger grains being more hydrophilic and smaller grains more hydrophobic, the bypass flow trapping area (2.352 mm2) is 3.14 times that under the sub-grain wettability pattern with four quadrants of distinct wettability. The pore-corner trapping area under the sub-grain wettability pattern (1.645 mm2) is 1.47 times that under the grain-scale wettability pattern. Interface overlapping drives wall-adhered trapping, controlled jointly by wettability and capillary number. Under the sub-grain pattern, decreasing Lg(Ca) from-4 to-5 reduces adhered zones from 53 to 4 and total area from 0.1725 mm2 to 0.01166 mm2. At the single surface, wettability governs bubble migration via contact line and curvature, while the injection rate influences the regulatory weight of wettability on bubble migration. Specifically, stronger surface hydrophilicity corresponds to higher bubble migration velocity. Key contact angle characteristics for distinguishing the outcomes of overlapping events are identified, interprets bubble migration to strong hydrophobic regions via energy minimization, and clarifies injection rate-wettability coupling, providing new insights into CO2 sequestration pore-scale dynamics in heterogeneously wetting porous media.

Fiber-optic Fabry-Perot (F-P) sensors are commonly demodulated using spectral interferometric techniques to measure the optical path difference (OPD). However, spurious jumps in the sensor output, widely called "mode jumping," are frequently observed in OPD-based measurements. This paper proposes a new method based on 1DCNN to solve such jumps, which is combined with the LabVIEW program for the real-time demodulation of the pressure value, with an R2 of 0.9999998 in the pressure range of 0-24 MPa. The experiments also verified that the algorithm achieves a demodulation resolution of 0.0012 MPa (0.005 % F.S.) and a repeatability error of 0.16 % F.S. The experiments demonstrate that 1D-CNN can effectively avoid mode jumping. To explore why the model can avoid jumps, the interpretability of the model is analyzed from the perspective of feature contribution. The algorithm learns a direct, end-to-end, unambiguous mapping from the global features of the entire spectrum to the pressure through adaptive feature weighting, thereby circumventing the OPD calculation that causes the mode jumping. It has been proven that the neural network has great potential to improve demodulation accuracy, resolution, repeatability, and solve the problem of mode jumping.

Permeability is a crucial factor in the gas production of natural gas hydrates, significantly influenced by the saturation and distribution of hydrates. In this study, a high-pressure visual microchip system is developed that enables in situ observation of hydrate formation/dissociation while simultaneously measuring permeability. The experimental results demonstrate that hydrate morphology is strongly influenced by the initial gas-water distribution, leading to distinct permeability responses. Four contact patterns are identified: when gas bubbles are dispersed in the water phase, hydrates form around the bubbles; when small water droplets are dispersed in the gas phase, only limited hydrate forms on one side of each droplet; when extensive gas-water contact occurs, hydrates grow abundantly within the gas phase; when only water is present, no hydrate forms. Furthermore, a variation coefficient (CV Sh ) is defined to characterize the spatial heterogeneity of hydrate saturation. During hydrate dissociation, permeability exhibits a two-stage behavior, with a gradual increase at the early stage followed by a rapid recovery at the later stage. This behavior is closely associated with the evolution of CV Sh , where increasing CV Sh indicates enhanced hydrate heterogeneity and suppresses the extent of permeability increase.

CO2 injection monitoring using electrical resistivity is a key tool for leakage detection of long-term geological storage. It is of importance to reveal the electrical response of reservoir rocks for developing accurate monitoring techniques. In this work, the electrical characteristics of CO2 displacement of water and oil in a Berea sandstone were analyzed using an electrical impedance spectroscopy. Flooding test results show that the final saturation of CO2 and oil recovery increase with temperature and pressure. CO2 injection obtained an oil recovery of 48.98% at 10 MPa and 40 degrees C, 53.07% at 10 MPa and 25 degrees C, and 44.18% at 5 MPa and 25 degrees C. Cole's equivalent circuit model was used to describe how the AC electric signal in the low frequency band was conducted inside the core, and the system impedance was significantly correlated with the fluid saturation and scanning frequency. Diffusive relaxation effects and interfacial polarization reactions occurring in the low-frequency region led to characteristic circular arcs in the Nyquist diagram. In addition, as the saturation of the conductive brine within the pore space gradually decreases, the decrease in the connectivity of the internal conductive circuit leads to an increase in impedance, which is consistent with the trend of resistance and capacitance when fitting the Cole's equivalent circuit model. This study provides experimental evidence for the application of resistivity monitoring technology in aiding CCUS, contributing to improving the reliability of reservoir leakage risk assessment.

Pore scale displacement behaviors of reservoir oil is of importance for understanding the displacement mechanism and developing efficient oil recovery techniques. In this work, a low field nuclear magnetic resonance (NMR) core analyzer was used to perform CO2 displacement experiments. Through the spin-spin relaxation time (T2) spectrum and magnetic resonance imaging (MRI), CO2 displacement behaviors at core and pore-scale were investigated. The results show the final oil recovery of miscible displacement is about 10 % higher than that of immiscible displacement. However, it becomes less pressure sensitive when the minimum miscible pressure (MMP) is exceeded. Pore structure analysis showed that macropores contributed to the main oil production (79.7 % in immiscible state, 89.0 % in miscible state), while mesopore recovery responded significantly to pressure change, and its recovery under miscible state was 52.4 % higher than that of immiscible state. It was confirmed that the injection rate was negatively correlated with the recovery rate, and the recovery rate reached 90.2 % at 0.03 mL/min, which was 4.1 % higher than that at 0.1 mL/min, indicating that the injection rate was not the main controlling factor under the miscible state. The MRI in situ observation shows that miscible displacement forms a "piston leading edge", effectively reducing the residual oil saturation in macropores, while the T1-T2 spectrum confirms that CO2 realizes the cross-scale exploitation of the oil phase in mesopores by diffusion. These findings are of great significance for optimizing the development scheme and enhancing recovery in heterogeneous low permeability sandstone reservoirs.

Microbubble (MB) flooding provides a potent means of suppressing gas channeling and enhancing mobility control in CO2-Enhanced Oil Recovery (CO2-EOR). Unlike conventional continuous gas injection, dispersed microbubbles can leverage the Jamin effect to improve sweep efficiency. This study investigates the transport mechanisms and oil-displacement behavior of CO2 microbubble in fractured, low-permeability reservoirs using high-fidelity Euler-Lagrange pore-scale simulations. We examined the impact of bubble diameter (10-90 mu m) and carrier fluid viscosity on displacement efficiency within complex pore networks (Types I, II, and III). The simulation results indicate that optimized MB injection significantly delays gas breakthrough from 0.87 pore volumes (PV) in conventional CO2 flooding to 3.86 PV, increasing final displacement efficiency to 94-95% when using 10-30 mu m bubbles. Mechanistic analysis reveals that uniform MB dispersion dynamically redirects flow from high-permeability channels into previously bypassed zones via capillary blocking. Furthermore, the high effective viscosity of the microbubble dispersion (similar to 243.5 cP) stabilizes the displacement front, suppressing viscous fingering and minimizing vortex formation in tortuous pore geometries. Parametric optimization suggests a coupled size-viscosity window-specifically 20-30 mu m bubbles at effective viscosities of similar to 220-250 cP-provides an optimal balance between throat penetration and mobility control. These findings offer theoretical support for the field-scale deployment of MB-assisted CO2-EOR, demonstrating how tailored bubble rheology can mitigate operational risks and maximize recovery in heterogeneous strata.

Solar-driven interfacial evaporation holds promise for decentralized freshwater supply, but practical deployment is hindered by the high cost, complex fabrication, and insufficient durability of existing evaporators. Herein, we report a simple and scalable strategy to transform fly ash into high-performance composite films. The composite film not only possesses excellent mechanical properties and outstanding salt resistance, but also exhibits remarkable water activation capability, making it highly suitable for use in solar-driven interfacial evaporation technology. Leveraging the thixotropic property of natural sepiolite clay, fly ash particles can be stably dispersed within the nanofiber network, thereby achieving a broad-spectrum light absorption efficiency of over 80%. The incorporation of polyvinyl alcohol modulates the hydrophilic network structure, yielding films with remarkable mechanical robustness. The FASP composite withstands arbitrary bending, folding, and even boiling water without structural damage, while exhibiting a tensile strength of 18.2MPa. Critically, the polymer network regulates intermolecular hydrogen bonding among internal water molecules. This water state regulation reduces the evaporation enthalpy to 1634.9Jg-1, fundamentally enhancing evaporation efficiency. Under 1 sun illumination, the optimized FASP-50 achieves a high evaporation rate of 2.09kgm-2 h-1 and its energy conversion efficiency reaches 91.7%. This figure notably exceeds the theoretical limit of two-dimensional evaporators. Due to the extremely low material cost, the cost-effectiveness of this product is as high as 1.14kgh-1 $-1. This work provides a mechanically durable, salt-resistant, and cost-effective platform for solar desalination. The strategy also opens a new technological pathway for high-value resource utilization of fly ash.

To achieve the"carbon peaking and carbon neutrality"goals,carbon capture,utilization,and storage(CCUS)technology plays a key role,among which CO2 geological storage is an effective means of carbon reduction,mainly utilizing the deep saline aquifer as an important storage site.The injection capacity and storage safety become the two core indicators for evaluating CO2 storage efficiency during this process.The Jiyang Depression was taken as the target storage area,and the changes in formation pressures and temperatures,CO2 migration and distribution characteristics,and CO2 storage capacity after CO2 injection were evaluated.A CO2 geological storage model for the deep saline aquifer was established,and nine sets of CO2 injection schemes were designed to investigate the effects of different injection rates,injection pressures,and injection temperatures on CO2 migration and distribution characteristics,as well as storage capacity.The results indicate that the injection rate and injection pressure have a significant impact on the injection amount and CO2 migration and distribution characteristics during CO2 geological storage,and the impact of the injection pressure is greater,while the impact of the injection temperature is not significant.Increasing the injection rate and injection pressure will increase the total CO2 injection amount,which is beneficial for improving the storage capacity and increasing the migration distance of the free-phase CO2 and dissolved-phase CO2.When 1.4 times the initial formation pressure is applied for CO2 injection,the maximum CO2 storage capacity can be achieved.The injection temperature has a significant impact on the formation temperature.Increasing the injection temperature will raise the formation temperature near the injection well.The total CO2 storage capacity first increases and then decreases with the increase in injection temperature,reaching the maximum when the injection temperature is 52 ℃.

Horizontal well technology serves as the core means for the development of oil and gas reservoirs, and the optimization of the well trajectory is of great significance for improving the development efficiency and oil and gas production. However, current research on the multi-objective optimization of the horizontal wells rarely involves the decision-making of the Pareto front solutions, and fails to consider the impact of the parameter disturbances in the actual construction on the stability of the implementation scheme. To address the above issues, a multi-objective optimization model is established based on a 3D seven-segment horizontal well structure, considering the well trajectory length, drill string torque, and well trajectory complexity. A comprehensive solution and decision-making framework is proposed, which integrates the MOPSO algorithm for solving, the entropy weight-TOPSIS method for decision-making, and the central difference method for parameter sensitivity analysis. The results indicate that 31 groups of the well trajectory alternatives are obtained through the MOPSO algorithm. The entropy weight-TOPSIS method recommends Scheme 22 (with the score of 0.67) as the optimal scheme for the well trajectory design that balances the economic benefits, risk control, and long-term production efficiency by constructing the weight logic system and quantifying the competitiveness of each scheme. The parameter sensitivity analysis based on the central difference method identifies the highly sensitive parameters within the optimization system. The results show that the objective functions are more sensitive to the inclination than to the azimuth, and the perturbations in the inclination can break the multi-objective balance and amplify the systemic risks. Therefore, the real-time monitoring of the inclination should be strengthened during the actual construction. While the impact of the azimuth disturbances on the current optimization system is limited, and they can be dynamically adjusted within a certain range during the construction to compensate for the uncertainties in the geological conditions.

Deep saline aquifers in offshore regions are key storage sites for large-scale CO₂ geological sequestration. However, multiple low-permeability cap rocks and localized high-permeability channels significantly impact CO₂ migration pathways and storage safety. This study addresses the limited understanding of the coupled effects of high-permeability channels on CO₂ migration and multi-storage mechanisms in multi-layer cap rock conditions. A two-dimensional numerical model based on geological characteristics in a South China Sea region was established, and CO₂ migration was systematically studied using CMG-GEM under two different vertical high-permeability channel widths (10 m and 50 m). The results show that channel width has a coupled influence on CO₂ migration mechanisms: a 50 m wide channel accelerates pressure propagation and promotes horizontal CO₂ migration, while a 10 m wide channel exhibits a stronger flow focusing effect, enhancing vertical gas migration. The channel width significantly controls the accumulation and lateral diffusion of CO₂ beneath different cap rocks, affecting the proportions of structural, dissolution, and residual storage. Salt precipitation occurs similarly across both scenarios but is more pronounced with wider channels, with the maximum reduction in porosity being approximately 0.076% for the 10 m channel and 0.11% for the 50 m channel, leading to a permeability decrease of about 0.23% and 0.33%, respectively. The impact on overall reservoir flow capacity is minimal. This study provides the first quantitative assessment of the coupled effects of high-permeability channel width on CO₂ sequestration, offering valuable insights for impact assessment and long-term safety analysis in offshore saline aquifer CO₂ storage.

Through hydromechanical coupling, fluid migration in porous media can induce structural deformation. Consequently, monitoring such deformation serves as a key diagnostic tool for identifying fluid migration processes. In this study, a high-resolution technique integrating Nuclear Magnetic Resonance (NMR) and Distributed Optical Fiber Sensing (DOFS) was first developed to enable synchronous monitoring of the water-gas displacement process and the associated structural responses. The migration front was visually observed to evolve from preferential channeling to dispersion before eventually stabilizing, and this evolution was in good agreement with the strain response, revealing a linear relationship between water volume and strain. Strain-rate analysis identified high-response zones, thereby delineating the effective coupling range of structural disturbance and establishing an effective disturbance threshold of approximately 0.4 mu epsilon/s. Furthermore, irreducible water was found to significantly affect the structural response. At an irreducible saturation of 18.1%, the overall strain amplitude decreased by nearly an order of magnitude. These findings reveal the flow-solid coupling mechanisms during the water-gas displacement process and offer a novel approach to monitoring fluid flow in geological engineering applications.

Hydrate-based carbon capture offers a new route for CO2 immobilisation. However, its process stability is significantly affected by restricted mass transfer within porous media, hydrate formation, and flow-path blockage. Existing visualisation studies have primarily focused on regular microchannels, isolated droplets, or idealised pore networks. In heterogeneous porous media, the coupling between CO2 hydrate growth characteristics, occurrence patterns, and hydraulic response remains poorly understood. This study directly visualised CO2 hydrate formation within a heterogeneous microfluidic pore network derived from sediment. Through time-lapse image analysis, hydrate growth kinetics and the evolution of the equivalent relative permeability of the porous medium were characterised. The results indicate that single-crystal growth exhibits a slow-then-rapid pattern, suggesting the presence of mass transfer limitations related to local water supply. In contrast, polycrystalline growth follows a rapid–slow–rapid sequence when bridging occurs, corresponding to an initial nucleation burst, transport-limited growth, and a re-accelerated growth phase upon contact with the wall water film. In a representative local region, the hydrate saturation increased by 50.61%, 20.18% and 29.21% during these three stages, respectively. As the hydrate crystals grew, the pore structure changed markedly: the equivalent relative permeability decreased by up to 77.13%. Even within the connected stage, before any bridging-induced disconnection, the permeability fell substantially while the flow-path tortuosity increased by only about 2.70%. This indicates that the loss of flow capacity was governed mainly by the constriction and blockage of critical pore throats. These results, obtained in a hydrophilic, sediment-derived pore network, reveal how local water distribution and hydrate-shell formation govern CO2 immobilisation and flow-path blockage at the pore scale, providing mechanistic insights relevant to the stability of hydrate-based carbon capture.

Hydrate-based CO2 storage in subsea sediments shows considerable potential. Understanding hydrate formation kinetics is crucial for safe and effective CO2 storage. Although experimental studies have demonstrated the critical role of different gas-liquid contact modes in hydrate growth, existing kinetic models for hydrate formation largely neglect this effect. In this study, two typical gas-liquid contact modes, i.e., spherical-cap liquid droplets and cylindrical gas columns, were conceptualized based on fluid phase continuity. A refined kinetic model for hydrate formation was developed by considering their effects on the specific reactive surface area, and an effective permeability model was constructed to describe the dominant morphological transition of hydrates from grain coating to pore filling. Subsequently, numerical simulations were performed for three sets of CO2 hydrate formation experiments at a constant termination pressure with varying injection rates, and the numerical predictions of pressure, temperature, and hydrate formation amount agreed well with the experimental data. Furthermore, simulation results revealed that hydrates preferentially formed near the wellbore and the reactor wall, and higher injection rates shortened the induction time, increasing the fraction of CO2 stored as hydrates from 48.91% to 58.19% through a pressure-buffering effect. Sensitivity analyses demonstrated that a smaller contact angle (i.e., stronger hydrophilicity), a smaller curvature radius of the liquid droplet, and a lower threshold aqueous saturation promoted hydrate formation by enlarging the specific reactive surface area. The proposed models provide a refined modeling framework for predicting hydrate formation rates and assessing the potential of hydrate-based subsea CO2 storage.