The influences of NaCl concentrations from 1-5 mol% on the growth kinetics of CO2 hydrates and the structural characteristics of the formed solid products were investigated through molecular dynamics simulations. Lower temperatures and higher NaCl concentrations exhibited increasing inhibition effects on hydrate growth. Small numbers of Cl- anions constituted distorted edge-sharing host cages while minority Na+ cations tended to behave as hopping guests shuttling among host cages. NaCl crystallites were observed, suggesting both the carbon storage capability in the hydrate even from highly salty solutions and the presence of solid NaCl inclusions within polycrystalline hydrate entities, necessitating practical considerations in potential industrial processes such as oceanic carbon storage and desalination.

CO2-enhanced gas recovery (CO2-EGR) offers a dual benefit of boosting natural gas production while enabling carbon sequestration. However, the pore-scale displacement dynamics of CO2-CH4 interactions remain poorly understood due to limitations in conventional observation methods. This study develops an integrated low-field nuclear magnetic resonance (NMR) workflow that combines T2 spectra, stratified T2 spectra, 1D profiling, and NMR imaging to quantitatively monitor and visualize, in real time, the CO2-driven displacement of CH4 in sandstone cores. This integrated method enabled multi-scale visualization of the CO2-EGR process. T2 spectra analysis revealed that CH4 was primarily stored in mesopores, with signal amplitude and peak area reflecting CH4 content and recovery. Stratified T2 spectra offered spatially resolved insights, confirming piston-like migration fronts across core layers. 1D profiling captured axial CH4 distribution and displacement front progression, identifying CO2 breakthrough timing. NMR imaging provided intuitive visualization of displacement morphology, revealing piston-like fronts and CH4 redistribution. This integrated low-field NMR approach proves to be a powerful, non-destructive tool for real-time, multi-scale characterization of gas–gas displacement processes. Results show that CH4 recovery is significantly affected by both permeability and injection rate: high-permeability cores with higher injection rates achieved greater recovery, while low-permeability cores showed limited performance. These findings validate NMR as an effective, non-destructive tool for real-time monitoring and contribute to a better understanding of CO2-EGR mechanisms in heterogeneous reservoirs.

Direct injection of liquid CO2 into the ocean for hydrate-mediated sequestration offers advantages in feasibility and capacity, yet faces challenges in rapid hydrate formation and long-term stability in positive buoyancy zones where CO2 density is lower than seawater. Herein, a pilot-scale (ca. 4.5 m) fully visualized vertical riser reactor was used to conduct a series of experiments on dynamic injection of liquid CO2 into simulated seawater (3.5 wt% NaCl solution) at 4.5 MPa and 3 degrees C, investigated the effects of different initial injection velocities on hydrate formation within two flow regimes: varicose breakup and full atomization. Meanwhile, the efficacy of a simple physical trapping device in stabilizing floating multiphase CO2 (droplets and hydrate composite particles) was demonstrated. Results revealed that both regimes enable rapid accumulation of composite particle clusters at the device interface via two distinct solidification mechanisms. High-We atomization reduced droplet sizes to approximately 1/6 of those in low-velocity breakup, facilitating immediate hydrate-cluster formation. Notably, transient contact between ascending CO2 droplets and pioneer hydrate films triggered rapid lateral hydrate shell growth across interfaces. Statistical analysis demonstrated that droplets with a median diameter of 6.3 f 0.3 mm achieved full encapsulation only within 2.7 f 0.4 s, with propagation initiating at contact point and extending to antipodal position. Finally, a two-step injection strategy derived from optimized flow velocities is proposed to enhance CO2 hydrate sequestration efficiency. These findings are expected to progressively establish a novel methodology for marine carbon storage, further contributing to the advancement of global carbon neutrality goals.

Injecting impure CO2 for enhanced gas recovery (CO2-EGR) offers a dual benefit by improving natural gas extraction while enabling CO2 sequestration. However, the interactions between CO2, N2, and CH4 under reservoir conditions require further investigation. This study employs Grand Canonical Monte Carlo (GCMC) and Molecular Dynamics (MD) simulations to quantify the adsorption and diffusion behaviors of CO2, N2, and CH4 in quartz nanopores over a pressure range of 1–24 MPa under varying water saturations and gas compositions. The results indicate that: (1) CO2 exhibits the broadest energy distribution and the strongest adsorption stability, occupying about 20 %–30 % more adsorption sites than CH4 or N2 and showing the least sensitivity to water saturation, with only a 30 % reduction at 50 % saturation, compared to 60 % for CH4, giving CO2 a clear competitive advantage. (2) The adsorption and desorption behaviors are strongly pressure dependent, as increasing pressure reduces the adsorption layer area and shifts gas distribution from adsorption dominated to free phase. Competitive adsorption analysis reveals that while CO2 dominates displacement at low pressures, mixtures that contain N2 achieve higher CH4 desorption efficiency above 13 MPa by mitigating diffusion resistance. (3) A higher N2 fraction improves CH4 diffusion coefficients, thereby facilitating gas mobility and ensuring superior recovery performance under high-pressure conditions. This study advances the fundamental knowledge of microscale gas behavior in tight sandstones and supports the feasibility of impure CO2 injection as a practical strategy for sustainable gas production.

Natural gas hydrate holds significant importance for the sustainable energy development in the future with high efficiency and enormous reserves. However, hydrate exploitation involves complex physical phenomena such as phase transition, mass transfer, deformation, gas expansion, and particle migration compared with conventional oil and gas reservoirs, resulting in spatiotemporal variations in key flow parameters including permeability, water retention curve, and gas-water relative permeability curve. Figuring out the evolution mechanisms of these key flow parameters is crucial for accurate prediction, strategies determination and adjustment of production in hydrate-bearing sediments. Although substantial research has been carried out, comprehensive review summarizing key flow parameters evolution remains scarce. Therefore, this work systematically summarizes the current research respectively from three aspects involving hydrate pore habit that primarily affects key flow parameters evolution, experimental and numerical methods for obtaining key flow parameters, and the representative models. Potential directions for future investigation are further proposed followed by challenges in this research area. This work provides a solid foundation towards the efficient and safe exploitation of natural gas hydrate.

Due to its widespread geological distribution and substantial storage capacity, CO2 storage in saline aquifers is internationally recognized as one of the most effective methods for mitigating the greenhouse effect. The characteristics of the two-phase flow in porous media significantly affect the capacity and safety of CO2 storage. In this study, two structures at different locations of the Berea core were obtained and subsequently etched into two different micromodels to investigate the two-phase flow characteristics between CO2 and water. Using a microscopic visualization method, many experimental results have been obtained under different displacement patterns, including qualitative results of the displacement process, interface changes, and phase distributions and quantitative results of differential pressure, CO2 relative permeability, fractal dimension, and CO2 saturation. The results indicated that the maximum CO2 saturation, relative permeability, and fractal dimension were achieved when the displacement pattern was viscous fingering with CO2 predominantly existing in the micromodel as the main displacing channel. On the contrary, when the displacement pattern was capillary fingering, CO2 clusters showed the characteristics of large numbers and small areas, which led to the minimum CO2 saturation, relative permeability, and fractal dimension. Due to the simultaneous dominance of viscous and capillary forces, the flow characteristics under crossover fell between viscous fingering and capillary fingering, rendering them more complex. The phase states of CO2 and water exerted a profound influence on the differential pressure and displacement processes, primarily driven by the viscosity ratio at varying temperatures and pressures. The influence of the micromodel structure on the displacement process was mainly reflected in the local two-phase flow dynamics, resulting in numerical variations without significantly altering the general trend of change.

Driven by China's carbon peaking and carbon neutralization goals as well as the strategic development of deep-offshore energy resources,energy island clusters in the South China Sea are evolving from single energy-supply nodes into integrated engineering platforms that combine multi-energy coupling,energy conversion,operational support,emergency response,and long-distance replenishment.However,the existing support model dominated by nearshore home ports is constrained by long offshore distances,complex sea conditions,extended replenishment chains,and insufficient multi-stakeholder coordination,making it difficult to support large-scale and continuous operation of deep-offshore energy island clusters.This study reviews operational support models for energy islands and offshore energy hubs in China and abroad,analyzes the capability basis and limitations of ports,island-reef nodes,and frontier facilities in the South China Sea,and proposes a three-tier coordinated support system consisting of core home ports,relay hubs,and frontier support nodes.Based on support distance,water depth,task attributes,and response requirements,the proposed system divides the support space into a nearshore support layer,an offshore relay layer,and a deep-offshore frontier layer,corresponding respectively to integrated coordination,relay transfer,and near-field response functions.Scenario-based calculations indicate that the proposed system can reduce the response time for urgent spare-parts replenishment from approximately 51.5 h to 17.5 h,a decrease of about 66%,and reduce the arrival time for medical rescue from approximately 3.28 h to 1.43 h,a decrease of about 56.4%.Institutionally,this study recommends establishing the South China Sea Deep Blue Economic Comprehensive Pilot Zone as a coordination platform,while advancing standard sea-unit certification,three-dimensional layered sea-use rights,enclave-economy cooperation,and sea-air emergency coordination mechanisms.The results indicate that the three-tier coordinated support system can improve the operational efficiency,emergency response capability,and system resilience of energy island clusters in the South China Sea,providing a reference for the construction of deep-offshore energy engineering support systems in China.

Understanding the evolution of sandstone mechanical behavior under high pressure and high temperature (HPHT) is crucial for the efficient development of ultra-deep tight reservoirs. In this study, triaxial compression tests on ultra-deep core samples and true triaxial hydraulic fracturing experiments on 200 mm × 200 mm × 200 mm sandstone cubes were conducted under HPHT conditions. The brittle–ductile transition behavior and fracture initiation and propagation characteristics of rocks in ultra-deep reservoirs were investigated, and four classical break-down models were employed to evaluate break-down pressures under different stress state and temperature conditions. The results show that, at elevated confining pressures and temperatures, ultra-deep rocks undergo a transition from brittle failure dominated by shear cracks to ductile deformation involving numerous microcracks; pre-peak plastic strain increases markedly, and a pronounced post-peak stress plateau appears in the stress–strain curves, indicating a significant enhancement of overall ductility. Under HPHT conditions, breakdown pressure increases and fracture propagation resistance becomes stronger, and hydraulic fractures tend to exhibit an intermittent “initiation–arrest–reinitiation” propagation pattern, which is unfavorable for the development of a complex fracture network. Comparison of model predictions with experimental and field data further demonstrates that, for reservoirs deeper than 5000 m, thermally induced stresses should be incorporated into break-down pressure prediction. Among the four models considered, the T-H-W model exhibits superior physical plausibility and predictive reliability for ultra-deep tight reservoirs. These findings provide important experimental and theoretical support for optimizing hydraulic fracturing design and enhancing stimulation effectiveness in ultra-deep tight formations.

Hydrate-based carbon dioxide (CO₂) sequestration (HBCS) within marine sediments has emerged as a highly promising strategy for long-term carbon storage and climate mitigation. Nevertheless, the efficiency of this process is hindered by the inhibition of clay hydration on CO₂ hydrate formation in marine sediments. This study develops a hydrophobic modification strategy to facilitate hydrate formation by regulating the interfacial water structure at the mineral-water interface. The in-situ formation of CO₂ hydrate and the evolution of water structure were investigated using low-field nuclear magnetic resonance (LF-NMR) techniques and molecular dynamics (MD) simulations. Experimental results demonstrate that the hydrophobic modification of MMT significantly enhances hydrate growth kinetics, achieving a water-to-hydrate conversion rate of ∼41% within 30 min, which is markedly higher than that of raw MMT (∼18%). Transverse relaxation time (T₂) analysis reveals that the hydrophobic modification effectively eliminates the constraints on water molecules imposed by MMT hydration, increases the proportion of free water while reducing the bound water that is reluctant to participate in hydrate conversion. MD simulations further elucidate that the hydrophobic modification creates a “repulsive interfacial environment” through ionic substitution and the hydrophobic effect, which alleviates the confinement of water molecules on the MMT surface and favors hydrate formation. This work highlights that the regulation of interfacial water structure via hydrophobic modification is a critical mechanism for optimizing CO₂ storage in fine-grained marine sediments.

The co-occurrence of marine gas hydrates, shallow gas, and deep oil and gas has been widely recognized, offering favorable conditions for integrated resource development. This study aims to explore the coupled production dynamics of shallow gas hydrates and underlying free gas to support the industrialization of marine natural gas hydrate resources. A productivity prediction model for the combined extraction of hydrate and underlying gas is developed, integrating multi-physics coupling mechanisms. Using logging data from two test wells in the Qiongdongnan Basin, a short-term physical model is constructed to simulate and predict production performance. Results show that: (1) The average wellhead gas production rate increases significantly with a linear relationship to the production pressure differential; (2) pressure propagation differs notably between hydrate and free gas layers, with a distinct low-temperature zone forming near the wellbore in the hydrate-bearing layer; (3) free gas migration results in a high-saturation gas zone near the hydrate-gas interface, and elevated pressure differentials can trigger secondary hydrate formation; and (4) during short-term testing, hydrate decomposition is limited, with most gas production sourced from the underlying gas layer. By adjusting production pressure or controlling wellbore temperature, hydrate decomposition and reformation can be balanced to optimize recovery efficiency. This study highlights a novel multi-gas co-production approach and provides a theoretical basis for sustainable deepwater hydrate development.

To address the challenges of mechanical failure mechanisms and strength prediction for non-diagenetic hydrate reservoirs, triaxial mechanical tests were performed on non-diagenetic hydrate-bearing argillaceous silt sediments under in-situ static conditions. This study delineated the variation patterns of mechanical properties, including failure strength, volumetric strain, elastic modulus, cohesion, internal friction angle, and stress paths. It further elucidated the mechanical influence mechanism of heterogeneous fracture-filling non-diagenetic hydratebearing sediments (THFHBS-Hetero) on the sediment matrix. The results demonstrated that under 2 MPa effective confining pressure and 40 % hydrate saturation, the failure strength of single-layer THFHBS-Hetero was 31 % higher than that of homogeneous pore-filling non-diagenetic hydrate-bearing sediments (THFHBS-Homo). The reliability of the laboratory-fabricated samples was validated by comparing them with literature data and remolded cores from the Qiongdongnan Area. Drawing on the experimental results, this study innovatively proposes the particle-scale mechanisms and particle movement patterns governing the shear failure of porefilling and fracture-filling non-diagenetic hydrate-bearing sediments (ND-HBS), accounting for the effects of hydrate saturation, effective confining pressure, and the number of hydrate-filled fracture layers. It was determined that the shear failure of the sediments is governed by the detachment, sliding, and rotation of "hydratesediment" cemented aggregates. This research provides a theoretical basis for understanding the variation of mechanical parameters during subsequent well construction and the exploitation of non-diagenetic hydrates.

Polymer flooding technology has caused different degrees of polymer-plugging problems in oil and water wells while increasing the recovery rate. The reduction of oil production in the oil recovery wells and the increase of injection pressure in the injection wells seriously affect the development effect of polymer flooding reservoirs. Therefore, efficient polymer plug removers are needed to remove polymer-plugging and restore formation permeability. In this work, a modified sulfamic acid (SPL) that remains stable at room temperature and gradually releases as the temperature rises was synthesized. Then, a new type of polymer plug remover (TCPR) was prepared by SPL, sodium chlorite, [ethylenebis [nitrilobis (methylene)]] tetrakisphosphonic acid, sodium salt (EDTMPS) and water. The corrosion rates of TCPR for N80 coupons at 60 degrees C and 90 degrees C are 1.5625 g/(m2 & sdot;h) and 1.8934 g/(m2 & sdot;h) respectively. The viscosity reduction rate of the polymer solution reached 96.2 % in 4 h at 60 degrees C, and 97.3 % in 3 h at 90 degrees C. The true triaxial physical simulation experiment demonstrated that TCPR can effectively remove residual polymers from core fractures, increasing fracture permeability by 95.2%. The results of the degradation mechanism study show that the TCPR firstly oxidizes and breaks the long-chain polymer macromolecules into small-molecule polymers, and then further oxidizes them into CO2 and H2O. Field test results show that the TCPR can effectively remove polymer-plugging in oil and water wells, reduce injection pressure in water injection wells, and increase oil well production. After the test well was put into production for 6 months, the cumulative oil increase was 1128 t.

Reliable heat extraction from enhanced geothermal systems (EGS) requires accurate characterisation of complex hydraulic fracture networks in low-permeability granite. Existing approaches struggle to reconstruct three-dimensional fracture geometries non-destructively, to enforce thermodynamic consistency, and to transfer laboratory observations to reservoir scale. To address these gaps, we develop an entropy-regularised control-volume physics-informed neural network (cvPINN) framework constrained by acoustic emission (AE) and distributed acoustic sensing (DAS) measurements, and we couple it to a novel multi-fidelity transfer-learning module that upscales laboratory-derived fracture patterns to km-scale discrete fracture networks (cvPINN-TL-DFN). A time-dependent Open Stimulation Fracture (OSF) damage variable governs permeability enhancement and stiffness degradation within a fully coupled thermo-hydro-mechanical (THM) formulation, with thermodynamic admissibility enforced by a hinge-loss penalty on the local entropy production. AE events provide micro-crack locations and timing, while DAS captures dynamic strain and flow-induced vibrations along the borehole; the two modalities are fused as physics-informed observational anchors. The framework is calibrated on a single-stage hydraulic stimulation of a 300 mm granite block under true triaxial stress, achieving a reconstruction error below 2

To investigate the deformation characteristics of nondiagenetic hydrate under depressurization, this study conducted triaxial tests systematically controlling hydrate saturation (Sh), sediment matrix, depressurization procedure, and effective axial stress (sigma 1 '). Gas production and axial deformation were monitored in real time, revealing the settlement deformation characteristics of nondiagenetic hydrate-bearing sediments under multifactor control. The results show: (1) The hydrate decomposition process is characterized by three stages: "undecomposed, rapidly decomposed, continuously decomposed". (2) Increased Sh significantly enhanced total gas production and axial deformation. Conversely, coarser sediment matrix particles significantly reduced axial deformation while exerting negligible influence on total gas yield. (3) Larger depressurization magnitudes intensified settlement deformation. However, drastic temperature drops could trigger secondary hydrate formation and redissociation, reducing dissociation efficiency. (4) Lower sigma 1 ' reduced the amount of deformation. As dissociation is primarily governed by thermodynamic phase equilibrium, variations in stress have a limited impact on total gas production. These results elucidate the critical influence of reservoir matrix properties and depressurization strategies on gas production and deformation in nondiagenetic hydrate reservoirs, providing a theoretical basis for their safe exploitation.

As a key parameter determining fluid flow dynamics, it is significant to determine the dynamic permeability evolution during the hydrate phase transition in consideration of media deformation for the safe and efficient development of hydrate-bearing sediments. In this work, a novel methodology of constructing unstructured hydrate-bearing networks with complex morphologies and anisotropy, respectively, in grain-coating and pore-filling hydrate pore habits coupling media deformation was proposed for the first time. After the validation, dynamic permeability evolution regularity considering media deformation was predicted and analyzed. Furthermore, the impact of parameters related to media deformation on the effective pore structure and dynamic permeability evolution was studied in detail. Results indicate that the effective permeability turns smaller, while the decline rate decreases with increasing hydrate saturation due to the difference in the number and compression degree of hydrate-occupied and unoccupied pore elements induced by media deformation. Moreover, the media deformation effect on the effective pore structure intensifies with an increase in the effective stress, a decrease in the elastic modulus, and a reduction in Poisson's ratio, resulting in a larger decrease in the effective pore-throat radii and reduction in dynamic permeability at the same hydrate saturation. In addition, the number of hydrate-occupied pore bodies and throats grows smaller at the same increment in hydrate saturation as media deformation becomes more pronounced, leading to a slower decline rate and a smaller difference in dynamic permeability with different media deformation parameters.

The accelerating accumulation of anthropogenic CO2 emissions is a major driver of global climate change, emphasizing the urgent need for effective mitigation strategies. CO2-enhanced gas recovery (CO2-EGR) offers dual benefits of improving hydrocarbon recovery while enabling long-term geological storage. However, uncertainties in pore-scale transport mechanisms and rock-fluid interactions hinder reliable implementation. In this study, in-situ CT imaging combined with digital rock reconstruction was employed to investigate CO2-CH4 displacement in carbonate rocks. CT observations showed that prolonged exposure to CO2-saturated brine induced dissolution-dominated reactions with localized precipitation, which increased porosity but also elevated tortuosity and heterogeneity, as reflected in broadened pore size distributions and higher fractal dimensions. Numerical simulations based on a multicomponent convection-diffusion model revealed that mass transfer is governed by a diffusion-dominated mixing front and a convection-dominated trailing region. The mixing front, accounting for similar to 5.5 %-22.8 % of the total mixing zone, provides a clear boundary between diffusion- and convection-driven regimes, with pore connectivity exerting strong control on their persistence. Parametric analyses demonstrated that injection velocity is the primary factor reducing breakthrough and completion times, while pore pressure has a secondary influence via its impact on fluid properties. Temperature and injection composition exert relatively smaller effects at the pore scale, though their significance may increase under reservoir conditions. Rock-fluid reactions further prolonged displacement and enhanced the relative contribution of diffusion. These integrated insights advance the mechanistic understanding of coupled transport processes and offer practical guidance for predictive modeling and optimization of CO2-EGR strategies.

In the context of global carbon neutrality, supercritical CO2 (scCO2) mineralization offers a promising CCUS solution. However, pore-scale evolution mechanisms under CO2-water-rock dynamic coupling remain poorly understood, limiting engineering applications. This study elucidates these mechanisms in silicate reservoirs by utilizing an accelerated conceptual analogue combined with in-situ sub-resolution nano-CT tracking. The results demonstrate that the injection of scCO2 instigates water redistribution within the pore space and water migration to the low-porosity seepage zones. Furthermore, the mineralization products exhibit a conspicuously differentiated morphology. Locally, the pore structure exhibits significant spatial variability, centered on the nonuniform evolution pattern of the high-and low-porosity seepage zones, which have different evolution patterns. The coupling and connectivity zones are more susceptible to cementation. This evolutionary mechanism directly leads to an increase in the heterogeneity of the pore network and blockage of secondary seepage channels. However, the introduction of a macroscopic fracture fundamentally sh]ifts the advection-diffusionreaction coupling regime. Because fractures inherently harbor high residual water, they trigger a diffusion-driven partitioning mechanism: dissolved cations from the tight matrix diffuse into and precipitate within the fracture voids, effectively mitigating matrix blockage. Based on these spatiotemporal insights, an optimized three-stage scCO2injection strategy is proposed to maximize long-term stable carbon sink capacity while preserving reservoir injectivity.