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.
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.
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 (Fhyd) 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 (DH), a key security indicator, varies significantly: Compared to 25 m in the horizontal structure, DH changes by +160%, –20%, and +20% for the inclined, anticline, and syncline structures, respectively. As the dip angle increases, Fhyd in the anticline structure increases while DH decreases. In contrast, Fhyd decreases and DH increases in both the inclined and syncline structures. The temperature variation across structures is a key factor influencing Fhyd, while permeability is a major factor affecting the safety of CO2 sequestration. Therefore, if Fhyd is the sequestration objective, the anticline structure is the optimal reservoir. If DH is the objective, the inclined structure is the best reservoir. These findings provide critical insights for site selection in marine CO2 hydrate sequestration projects.
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.
