Gas hydrate (GH) dissociation and its interaction with global warming represent a critical yet poorly constrained climate feedback. This study aims to quantify the instrumental and methodological errors in estimating the upper boundary of the gas hydrate stability zone (GHSZ) in the Sea of Okhotsk and to assess how this boundary shifts under various global warming scenarios, thereby evaluating the thermal stability of known GH accumulations in the region. A total of 131286 oceanographic stations (1929-2020) from multiple data centers were compiled and quality-controlled; the upper GHSZ boundary was computed using the Dickens GR and Quinby-Hunt MS phase equilibrium equation for a pure methane-seawater system (100% CH₄, S = 33.5‰) on a 0.35°×0.55° trapezoidal grid, with comprehensive observational errors quantified as three standard deviations within each grid cell, and five warming scenarios (1°C-5°C) applied to full-depth temperature profiles at 22 representative deep-water nodes. The total observational error in upper GHSZ boundary depth is approximately ±25 m, distributed randomly with no dependence on data density or location; each 1°C of warming causes a downward shift of about 40 m, and the boundary of the zone lacking thermobaric conditions for GH formation extends to a maximum isobath of about 170 m under the most extreme scenario considered. Critically, known GH accumulations in the Sea of Okhotsk are not threatened by thermal dissociation even under a conservative 1°C/100 a warming sustained for 300 years or a rapid 3°C warming over 100 years, consistent with global simulations and regional vessel-based observations. These findings provide essential GHSZ boundary constraints for numerical modeling of hydrate-climate interactions, support quantitative assessment of GH sensitivity to environmental changes, and inform hydrate exploration and methane seep monitoring across marginal seas of the western Pacific.

Gas hydrates occurring within the Pleistocene sediments of the Shenhu area, South China Sea, represent a dynamically evolving accumulation inherited from an “ancient” hydrate system. A hydrate-enriched layer with a maximum saturation of 48% is present near the base of the current gas-hydrate stability zone (GHSZ), above which hydrate saturation rapidly declines to nearly zero. This sharp transition cannot be explained by the previously estimated slow and nearly constant aqueous flow rate for the Pleistocene sediments. Geological evidence indicates that a substantial reduction in fluid flow occurred during the Early Pleistocene. To explore this process, the authors develop a coupled fluid-heat flow numerical model to simulate the dynamic evolution of the Shenhu hydrate system under temporally varying water-flow conditions. The model incorporates both the burial of “ancient” hydrates through sedimentation and the formation of “new” hydrates in younger deposits. Simulations with time-dependent flow rates can successfully reproduce the observed hydrate distribution in the Shenhu area. Under present sedimentation and fluid-flow conditions, the burial and dissociation of “ancient” hydrates beneath the GHSZ greatly outpace the formation of “new” hydrates within it, resulting in a continuous decline in the total hydrate inventory over time. These findings offer new insights into the long-term evolution of natural hydrate systems and have important implications for in-situ hydrate resource assessment.

Gas hydrate systems contain large quantities of methane that may originate from biogenic, thermogenic, or mixed sources. Fluid migration pathways, including gas chimneys, faults, inclined permeable strata and diapirs, are critical for transporting thermogenic gases at depth into gas hydrate systems in shallow subsurface. However, the role of these pathways in hydrate accumulation, particularly in systems dominated by biogenic or mixed gases, remains poorly investigated. This study integrates global case analyses of geochemical indicators of gas origin and geophysical signatures revealing spatial relationships between hydrate systems and migration conduits. Numerical modeling of hydrate accumulation history in the Gulf of Mexico Basin and the Qiongdongnan Basin further has been carried out. Results show that regardless of gas origin, in-situ biogenic gas alone is insufficient to form medium- to high-concentration gas hydrate. Fluid migration pathways are necessary for providing allochthonous gas. Generally, this study provides insights into the formation history of gas hydrate system and indicates that fluid migration pathways play a pivotal role in the formation of favorable gas hydrate systems, irrespective of whether the gas source is biogenic, thermogenic, or mixed.

The enrichment and accumulation of natural gas hydrates depend on sufficient gas supply and effective migration pathways. The upward migration of deep thermogenic gases through fault systems is critical for seepage-type hydrate formation. This study aims to elucidate the developmental characteristics of Cenozoic fault systems in the eastern offshore area of Dongsha Island and their influence on natural gas hydrate formation. Utilizing high-resolution 3D seismic data, this study conducted a detailed structural interpretation and seismic attribute analysis to systematically investigate the spatial distribution, developmental stages, and dynamic mechanisms of the Cenozoic fault systems in this region. In addition, this study explored the role of these fault systems in facilitating the migration of deep thermogenic gases to the shallow strata. The study area is dominated by extensional and transtensional normal faults characterized by inherited development and relatively small fault displacements. The Cenozoic strata exhibit a tectonic framework of block-faulted uplift and subsidence with alternating highs and lows. Faults on either side of the central uplift dip in opposite directions and commonly exhibit parallel, step-like patterns. Differences in fault system attitudes were observed between the southern and northern parts of the study area. In the south, fault strikes remained consistent from deep to shallow levels, predominantly trending NE and NEE. In the north, fault strikes varied significantly with depth, transitioning from predominantly NEE in deeper strata to EW and NWW in shallower strata. The study identifies two distinct phases of Cenozoic fault activity: (1) 66-10 Ma, a regional extensional tectonic regime controlled fault development, resulting in the formation of NEE-trending normal faults; (2) 10-2.6 Ma, the Dongsha Movement influenced fault activity, during which EW- and NW-W-trending transtensional faults with dextral strike-slip characteristics developed in the Miocene strata of the northern region. The Cenozoic fault system played a significant positive role in facilitating the migration of deep thermogenic gas to shallow levels, thereby enabling the formation of natural gas hydrates.

Natural gas hydrate (NGH) has attracted increasing attention as a promising unconventional energy resource owing to its high volumetric storage capacity, yet its development is accompanied by significant greenhouse gas risks. Therefore, accurate reservoir characterization is vital for marine resource exploration and sustainable development. Full waveform inversion (FWI) offers high-resolution imaging, yet suffers from heavy computation, sensitivity to initial models and non-uniqueness. Recent deep learning (DL) methods improve efficiency and accuracy, nevertheless, still struggle with clear boundary extraction and multi-level semantic representation. The authors propose a novel deep architecture (SC-UNeXt) designed to learn a mapping from seismic records to velocity models, which integrates a U-Net backbone, ConvNeXt residual blocks, spatial-channel squeeze-and-excitation attention and pixel shuffle up-sampling. Furthermore, a hybrid loss integrating mean squared error, multi-scale structural similarity, and perceptual discrepancy simultaneously optimizes pixel-wise accuracy, structural fidelity, and semantic consistency. Comprehensive tests on both synthetic NGH data and the 3D SEG/EAGE marine overthrust model with NGH demonstrate that SC-UNeXt outperforms FWI and advanced DL methods in boundary delineation, structural preservation, noise robustness, and computational efficiency. These results highlight SC-UNeXt as a reliable tool for high-resolution seismic characterization of NGH reservoirs, thereby supporting sustainable exploration and risk assessment of marine hydrate resources.

Gas hydrates are increasingly recognized as a significant unconventional energy resource and a key factor in marine geohazards and the global carbon cycle. However, accurately identifying and quantifying hydrate-bearing formations remains challenging due to complex geophysical signatures and heterogeneous distribution. This study evaluates twelve supervised machine learning (ML) algorithms for two key tasks: Classification of hydrate-bearing layers and regression-based estimation of hydrate saturation, using well log and pore-water geochemical data from Site NGHP-01-19B. Two physically independent labeling frameworks are employed: One based on Archie’s law using resistivity (1350 samples, 29% hydrate-bearing), and another based on a three-phase velocity model (890 samples, 25% hydrate-bearing). A diverse set of models, including tree-based ensembles (Decision Tree, Random Forest, GBDT, XGBoost, LightGBM, CatBoost, Bagging, AdaBoost), kernel methods (SVM, SVR), instance-based learning (KNN), neural networks (MLP), and Gaussian Process models (GPR, GPC), are systematically compared using cross-validation and grid search. Ensemble methods consistently performed best in classification, with AdaBoost and GBDT, achieving test accuracies above 0.94 (Archie) and 0.98 (velocity-based). For regression, GPR delivered the most accurate hydrate saturation estimates (R² > 0.99), while GBDT and Random Forest provided a strong balance of accuracy and computational efficiency. Notably, depth below seafloor (TDEP), though not a direct geophysical input, significantly enhanced model performance by acting as a proxy for stratigraphic and thermodynamic conditions. Group-based validation confirmed that random-sample splitting overestimates performance due to depth-wise autocorrelation, highlighting the importance of geologically informed model assessment. Overall, the consistent performance of ML models across both labeling schemes and input feature sets underscores their robustness and transferability, supporting their use as a reliable toolset for offshore gas hydrate reservoir characterization.

Natural gas hydrate (NGH) extreme thermodynamic sensitivity poses challenges for pressure-preserved coring operations in reservoir evaluation and commercial development. Current preservation strategies employing “pressure-only” approaches fail to address temperature-induced instability, leading to sample degradation and compromised geological characterization. This study investigates temperature-pressure synergistic preservation mechanisms using fully coupled thermal-hydraulic-mechanical-chemical (THMC) numerical simulation of hydrate cores from the Shenhu area, South China Sea. Numerical modeling incorporating hydrate dissociation kinetics, multiphase fluid dynamics, and heat/mass transfer processes reveals that temperature variations trigger cascading destabilization mechanisms. Results demonstrate that temperature field evolution follows exponential growth patterns, generating steep radial gradients up to 35 K/cm that induce pressure surges from 0.11 MPa to 0.82 MPa, establishing positive feedback loops destabilizing hydrate structures. Hydrate dissociation kinetics conform to Kim-Bishnoi laws, exhibiting “S-shaped decay” patterns with 2 times rate acceleration under elevated temperatures, reducing dissociation completion times from 1200 s to 600 s. The investigation identifies “threshold effects” in relative permeability evolution, where growth exceeding three orders of magnitude occurs when hydrate saturation drops below 0.15-0.2, transforming core hydraulic properties. Multiphase fluid migration transitions from diffusive regimes (0-0.4×10⁻³ m/s) to explosive patterns (1×10⁻³-1.25×10⁻³ m/s), exhibiting “burst-decay” kinetics that compromise sample integrity through rapid methane release and pore structure reconstruction. The study establishes quantitative criteria for developing temperature-pressure synergistic preservation technologies, with numerical results indicating potential sample quality loss reduction of 60%-80%.

During drilling in marine gas hydrate reservoirs, drilling-fluid invasion can induce hydrate dissociation, wellbore instability, and reservoir damage, thereby compromising drilling safety and reservoir protection. To address the low-temperature agglomeration and limited self-unplugging capability of conventional temporary plugging agents, a water-soluble thermoresponsive temporary plugging agent (TRP) was synthesized via free-radical copolymerization. Its structural characteristics, phase-transition behavior, plugging performance, reversible unplugging capacity, and underlying mechanism were systematically investigated through laboratory experiments and low-field nuclear magnetic resonance (NMR) imaging. The results show that TRP exhibits a lower critical solution temperature (LCST) of approximately 15°C, matching the thermal conditions of marine hydrate reservoirs. Above the LCST, TRP rapidly aggregates to form a dense plugging layer, effectively suppressing drilling-fluid invasion; below the LCST, it redissolves and restores formation permeability, with a maximum permeability recovery of 96.8%. Sand-disk filtration tests further demonstrate that TRP provides more effective fluid-loss control than ultrafine CaCO₃ and nano-emulsion under the tested conditions. Low-field NMR imaging directly visualizes the invasion-plugging-unplugging process. Mechanism analysis indicates that plugging originates from hydrophobic association of polymer chains above the LCST, which enhances filter cake compactness and increases the rock-surface contact angle from 41.5° to 77.4°. This reversible thermoresponsive strategy provides a practical basis for intelligent reservoir protection during deep-sea hydrate drilling.

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.

The permeability of methane hydrate-bearing sediments (MHBS) is a key parameter for evaluating reservoir exploitation potential and formulating efficient production strategies. In actual field development, MHBS exists in a complex environment characterized by stress-seepage coupling. Research on the permeability model of methane hydrate-bearing sediments under multi-factor coupling conditions remains scarce, limiting the assessment of methane hydrate (MH) reservoir hydrocarbon production potential and efficient development. This study used quartz sand and deep-sea clay from the South China Sea as matrix materials to generate MH, simulating MHBS. Systematic triaxial seepage experiments were conducted to assess the influence of multiple factors, including triaxial shear process, effective confining pressure, and hydrate saturation, on the permeability characteristics of MHBS. The results demonstrate the following: (1) During triaxial compression, permeability exhibits a nonlinear variation—first decreasing and then stabilizing or rebounding—with increasing shear strain, reflecting stress-induced pore structure evolution; (2) the permeability of MHBS decreases nonlinearly with increasing effective confining pressure, showing higher sensitivity in the low-pressure range. Effective confining pressure reduces sample permeability by compressing seepage channels, and this effect is more significant at the initial stages of stress growth; (3) hydrate saturation is negatively correlated with permeability, with the cementing effect of hydrates being the primary cause for the decrease in permeability of MHBS, also reducing the impact of effective confining pressure; (4) effective confining pressure, hydrate saturation, and shear strain have a coupled effect, jointly influencing the permeability of MHBS, but their relative weights vary and require specific consideration; (5) based on experimental data, a permeability prediction model considering the coupling effects of shear strain, effective confining pressure, and hydrate saturation was established. This model demonstrates excellent predictive accuracy and can be applied to forecast the hydrocarbon yield potential of MHBS under varying geological and engineering conditions, providing quantitative basis for reservoir evaluation and gas production prediction. This study bridges the gap between laboratory permeability characterization and field production capacity forecasting, offering critical theoretical and technical support for the sustainable development of marine gas hydrate resources.

Marine clay reservoirs are considered ideal substrates for hydrate-based CO₂ capture and storage owing to their large specific surface area, high porosity and favorable adsorption capacity. Understanding the evolution mechanism of quasi-liquid layers (QLLs) and hydrate formation at clay interfaces under nanoconfinement is crucial for evaluating the spatial potential of storage matrices and enhancing CO₂ sequestration efficiency. In this study, molecular dynamics (MD) simulations were conducted at 250 K and 300 bar with a time step of 2 fs to investigate the effects of salinity and electrostatic fields on CO₂ hydrate formation and QLL thickness within montmorillonite (MMT) slit pores. Simulation results indicate that CO₂ hydrate nucleation and growth predominantly occur away from MMT interfaces, with elevated salinity significantly delaying nucleation onset. Dynamic salt exclusion during hydrate formation inhibits interfacial hydrate growth toward clay surfaces. Elevated salinity increases QLL thickness from 1.2 nm to 1.6 nm near isomorphic substitution surfaces and from 1.1 nm to 1.4 nm near non-substituted MMT surfaces. Notably, under seawater salinity conditions, QLL thickening demonstrates dynamic coupling with salt exclusion effects. Electrostatic fields substantially influence nucleation stochasticity and spatial distribution through electric double-layer restructuring and ion migration. QLL thickness near isomorphic substitution surfaces shows limited sensitivity to electrostatic fields, stabilizing at about 1.15 nm. Conversely, QLLs adjacent to non-substituted surfaces exhibit significant field dependence due to surface ion redistribution, with thickness increasing to 1.55 nm at an applied field of 0.3 V/nm before reaching a plateau. These molecular-scale insights into salinity and electrostatic effects on hydrate formation and interfacial QLL evolution provide critical references for optimizing clay-based carbon storage matrices and advancing CO₂ sequestration technologies.

Global dependence on fossil fuels has led to escalating atmospheric carbon dioxide emissions. The consecutive greenhouse effect poses a serious threat to the human habitat, rendering carbon dioxide abatement a key focus in contemporary research. Hydrate-based CO₂ sequestration offers a promising pathway for carbon capture and storage, though its efficiency is strongly influenced by pressure, salinity, and sediment properties. In this study, the kinetic characteristics and occurrence states of CO₂ hydrates in porous media were systematically investigated under varying pressures (3.0-3.6 MPa), NaCl concentrations (0-3.5%), and sediment types (quartz sand vs kaolinite). Results reveal a non-linear pressure dependence—gas storage capacity increases by 16.3% as pressure rises from 3.0 MPa to 3.3 MPa, but diminishes to 9.4% with further increase to 3.6 MPa. NaCl exhibits dual inhibitory effects: Thermodynamically shifting the phase equilibrium leftward in the P-T domain and kinetically suppressing growth, with 3.5% NaCl systems exhibiting persistently slow hydrate formation. Sediment type also plays a critical role, as kaolinite’s low-permeability clay structure substantially impedes hydrate formation compared to quartz sand while altering hydrate distribution patterns. Understanding the interplay between pressure-driven efficiency gains and inhibitor-mediated stability control across diverse geological environments is essential for optimizing hydrate-based CO₂ storage strategies.

Carbon dioxide (CO₂) replacement is a promising technique for extracting natural gas hydrate (NGH, a promising clean energy source), capable of promoting energy development while mitigating the greenhouse effect. However, the improvement of NGH extraction efficiency in field engineering is hindered by the difficulty of CO₂ injection and diffusion. To overcome these difficulties, this study proposes combining CO₂ replacement with the solid fluidization method for the exploitation of NGH. The effects of solid fluidization mining goaf on methane (CH₄) recovery and CO₂ sequestration were experimentally investigated. The results indicate that the presence of a goaf in a sandy hydrate reservoir improves the CH₄ recovery ratio and CO₂ storage capacity due to its ability to provide a higher replacement driving force. However, the CO₂ sequestration ratio in the goaf-containing reservoir is lower than that in the intact hydrate reservoir due to the influence of free water content. Besides increasing the replacement driving force, the goaf in the clayey hydrate reservoir can also enhance the diffusion of the replacement medium. The enhancement of CH₄ recovery and CO₂ storage amount per unit sediment volume is 5.3% and 22.8%, respectively. Moreover, the CO₂ sequestration ratio in the goaf-containing hydrate reservoir is higher than that in the intact hydrate reservoir. These results provide theoretical support for the extraction of NGH via the CO₂ replacement method.

Sequestration of CO₂ as hydrates in seafloor sediments is an effective method for reducing CO₂ emissions. However, the efficiency of CO₂ hydrate sequestration can be influenced by the geological structure of seafloor reservoirs. To address this, the authors numerically investigate the effects of four reservoir structures (horizontal, inclined, anticline, and syncline) and dip angle on CO₂ hydrate formation mass and sequestration security. The results show that different geological structures alter the temperature distribution within the reservoir, thereby modifying the stability zone of CO₂ hydrates. At a dip angle of 30°, the hydrate formation mass (F_hyd) in the inclined, anticline, and syncline structures changes by -19.12%, +6.60%, and -7.19%, respectively, relative to the horizontal structure (baseline: 342×10⁶ kg). The distance from the top of the CO₂ hydrate cap to the seafloor mudline (D_H), a key security indicator, varies significantly: Compared to 25 m in the horizontal structure, D_H changes by +160%, -20%, and +20% for the inclined, anticline, and syncline structures, respectively. As the dip angle increases, F_hyd in the anticline structure increases while D_H decreases. In contrast, F_hyd decreases and D_H increases in both the inclined and syncline structures. The temperature variation across structures is a key factor influencing F_hyd, while permeability is a major factor affecting the safety of CO₂ sequestration. Therefore, if F_hyd is the sequestration objective, the anticline structure is the optimal reservoir. If D_H is the objective, the inclined structure is the best reservoir. These findings provide critical insights for site selection in marine CO₂ hydrate sequestration projects.

Geological risks are the main obstacles encountered during drilling in marine natural gas hydrate reservoirs. This review aims to provide a primary insight into the geological risks in the process of drilling in marine hydrate reservoirs. Different geological risks and their characteristics will be analyzed, together with a discussion of possible influencing factors. Geological risks occurring in the marine natural gas drilling process have a close association with uncontrollable drilling fluid invasion and hydrate dissociation. Finally, the mechanisms of drilling risks and control strategies for safe drilling are highlighted. Results can give a reference to drilling risk prediction and control for drilling in marine natural gas hydrate reservoirs efficiently.