Methane hydrate is an important form of natural gas occurrence in submarine reservoirs, while its dissociation behavior remains difficult to predict, particularly under complex thermodynamic conditions. The effects of initial reservoir temperatures (274–280.5 K) and pressures (4, 5 and 6 MPa) on methane hydrate dissociation were experimentally investigated under a depressurization rate of 32.7 kPa/min. The thermodynamic and kinetic behavior of hydrate dissociation during depressurization was quantitatively analyzed using real-time experimental date. Two thermodynamic boundaries corresponding to hydrate dissociation onset and completion were identified from the experimental results. A steady dissociation stage accounting for approximately 54 % of the total dissociation process was found between the two boundaries. The steady dissociation rate shows a positive dependence on the steady depressurization rate and a negative dependence on initial stable degree. Furtherly, a simplified model of hydrate dissociation reaction is built up, and thus the total dissociation duration can be directly estimated based on initial thermodynamic and hydrate saturation conditions. This study is significant for understanding the reaction mechanism of hydrate dissociation and predicting production behavior in various methane hydrate reservoirs.

In recent years, CO2 hydrate-based ocean sequestration has been regarded as one of the most promising methods for achieving CO2 emission reduction. The efficiency of CO2 sequestration is significantly influenced by the stability of hydrates. However, current research has not been able to accurately reproduce the stability of CO2 hydrates in real marine environments. Therefore, the stability of hydrates in different forms (exposed to seawater and within sedimentary layers) under non-saturated seawater flow conditions at a depth of 800 m is systematically investigated in this study. Furthermore, the mechanisms and causes of hydrate dissolution under various conditions in the experiment were analyzed using numerical simulations and theoretical formulas. The study results indicate that the dissolution rate of hydrates increases exponentially with the seawater flow rate. Under experimental conditions of 276 K, 8 MPa, and a seawater flow rate of 10 mL/min, 0.545 mol of CO2 hydrate exposed to seawater dissolves almost completely within 3.5 h. In contrast, after 24 h of experimentation, 1.03 mol of hydrates in the sediment layer still retained 89.4 % of the CO2 in the form of hydrate (calculated from the gas production data). The dissolution rate of hydrates in sediment layers is significantly lower (0.027 mol/h), representing only 1.74 % of the rate observed for hydrates exposed to seawater. The reduced dissolution rate in sediment layers is primarily influenced by pore structure (70.7 %) and seawater flow rate (29.3 %). These results provide strong evidence of the sufficient stability of hydrates within sediment layers and offer key data for CO2 sequestration.

CO2 hydrate-based sequestration in marine environments offers a promising strategy for mitigating atmospheric carbon emissions, but its long-term effectiveness is heavily reliant on hydrate stability under marine seafloor conditions. To elucidate the key factors controlling stability, high-resolution X-ray computed tomography (CT) and numerical simulations are integrated to systematically investigate the dissolution behavior of hydrates in different forms (exposed to seawater and buried in sediment layers). The results demonstrate that the dissolution rate of hydrates within sediments is only 20.9 % of that observed for exposed hydrates, highlighting the significant inhibitory effect of the sediment matrix. Seawater flow rate is identified as the primary kinetic factor, with a reduction from 5 mL/min to 1 mL/min resulting in an 87.5 % decrease in the dissolution rate. These findings demonstrate that the sediment matrix significantly impedes hydrate dissolution by extending diffusion pathways and reducing the fluid-hydrate contact area. Therefore, for optimal sequestration stability, priority should be given to sub-seafloor sites characterized by low pore-water flow velocities and sediment structures that inherently suppress mass transfer. This study provides a mechanistic framework for assessing CO2 hydrate storage stability.

Methane breakthrough through hydrate-bearing sediment (HBS) layers plays a critical role in the evolution of marine cold seep systems. However, the evolution of methane breakthrough in water-saturated hydrate layers remains experimentally underexplored, and the underlying mechanisms and theoretical models are still unclear. This study employed 10 cases of hydrate-bearing sandy sediments with saturations ranging from 16.5% to 52.4%, subjected to a 6 MPa methane flow at 6 mL/min to evaluate the hydrate layer's sealing effect. Experimental results show that breakthrough pressures, indicating sealing strength, ranged from 0.7 to 3.2 MPa and positively correlated with sediment water content. Before breakthrough, water efflux dominated with negligible methane release; after breakthrough, methane efflux surged, reaching up to 5.2 times the displacement rate. Throughout the methane seep development process, from gas-water displacement to gas seepage, approximately 0.26∼0.47 moles of hydrate were formed from the residual water in the displacement zone. Based on experimental results and key parameter analysis, a predictive model coupling hydrate formation and gas-water displacement was developed and shows good agreement with the experimental results. This study reveals the dynamic evolution of methane breaking through HBS, offering valuable insights into cold seep development mechanisms.

The necessity to reduce global carbon emissions has become increasingly urgent, and the subsea carbon dioxide (CO2) storage is considered a critical strategy for mitigating climate change. Depleted natural gas hydrate (NGH) reservoirs have favorable temperature and pressure conditions for sequestering CO2 and generating hydrate. However, the blockage of fluid seepage is a major challenge to achieving sustainable storage. This study employs a magnetic resonance imaging (MRI) experimental system to investigate the permeability characteristics of hydrate-bearing reservoirs with different injection rates of liquid CO2 (LCO2) and water. The results demonstrate that high LCO2 flow rates significantly promote the formation, aggregation, and progressive growth of CO2 hydrate particles, leading to a significant decrease in reservoir permeability. Although elevated water injection rates can effectively alleviate hydrate-induced blockage during sequestration, excessive water injection may raise the CO2 leakage fraction to more than 65%, thereby weakening the security of CO2 storage. By quantifying CO2 leakage fractions and stored CO2 amounts, this study identifies favorable water-LCO2 injection-rate combinations within the tested range, corresponding to 0.10–0.15 PV/min and 0.05–0.10 PV/min, respectively. These findings highlight the critical trade-offs among injectivity, storage efficiency, and leakage control, and provide preliminary guidance for developing LCO2-water co-injection strategies for sustainable subsea CO2 sequestration.

To mitigate climate change, hydrate-based CO2 storage in high-pressure and low-temperature geological settings has emerged as a promising negative emission strategy. However, conventional observation methods are inadequate for capturing the real-time dynamics of hydrate formation and spatial distribution in porous media, thereby constraining accurate evaluation of storage capacity and long-term stability. In this study, methane hydrate-bearing porous media were employed to simulate natural gas hydrate reservoir conditions, and magnetic resonance imaging was used for in situ, nondestructive visualization of CO2 seepage and hydrate evolution during storage at 274.15 K and 3.0 MPa. The results showed that newly formed CO2 hydrates can develop into an effective sealing layer that significantly suppresses large-scale water migration beneath it. Nevertheless, the layer was not fully compact; and the presence of micropores allows slow redistribution of the aqueous phase, leading to a cyclic process of dynamic breakthrough, gas release, and regeneration. Moreover, midstage injection of single-phase water was shown to reopen local seepage pathways, not only alleviating blockage but also enlarging the CO2-water contact area, thereby enhancing the ultimate storage performance. Quantitatively, the maximum CO2 storage capacity reached 0.039 mol, and the corresponding storage rate was 0.0099 mol/h under the higher initial hydrate saturation condition. These findings provide mechanistic insight into hydrate-based CO2 sequestration in methane hydrate-bearing reservoirs and offer theoretical support for condition optimization, long-term stability assessment, and the future development of larger-scale monitoring approaches.

Marine hydrate-based CO2 sequestration is a promising technology by CO2 injection into the hydrate stability zone of oceanic reservoir. Yet the role of injection method in the hydrate formation remains unclear due to lack of experimental evidence. In this work, three CO2 injection strategies-pulse injection (PT), continuous injection (CT) and a combination of both methods (PCT)-were experimentally investigated and compared. Experiments utilizing ultrapure water and South China Sea sediment were performed at 3.5-4 MPa and 4-4.5 degrees C. The results show that the pressure fluctuations of approximately 0.5 MPa were observed at the bottom of the hydratebearing reservoir. The fluctuations were primarily caused by the blocking effect of the formed hydrate during the CO2 injection process, which initially occurred after the second injection and persisted thereafter. In addition, for the PT, the increase in injection times enlarged the sequestration capacity caused by the increase of the sequestration pressure and hydrate saturation. The CT can improve the hydrate saturation of the reservoir more effectively than PT, but the enhancement of stability is not obviously improved. The molar amount of CO2 sequestered in per unit pore volume of reservoir was defined as the sequestration coefficient to show the CO2 sequestration capacity of reservoir. The maximum CO2 sequestration capacity achieved was 216.04 kg/m3 of reservoir. The PCT yielded an 86.50 % higher sequestration coefficient than the eight-time pulse method. The PCT had best sequestration stability and largest sequestration coefficient, which is the optimal strategy of CO2 injection for sequestration in oceanic reservoir.

Leakage following carbon dioxide (CO2) sequestration has been a significant worldwide concern. Previous studies have demonstrated that the formation of hydrate cap is able to prevent CO2 leakage. However, fracture channels are extensively developed and commonly present within porous media but hardly considered. This study employed magnetic resonance imaging (MRI) visualization technique to investigate the whole dynamic process of CO2 leakage in porous media with channels of four inner diameters (0, 200, 450 and 1000 mu m) at 277.15 K, 3 MPa condition. The presence of fracture channels significantly facilitates gas-water flow, decreasing the efficiency of water-CO2 displacement by 0.62% to 4.91%, and reduced the breakthrough pressure of pore water flowed through the hydrate-bearing zone. The hydrate cap can form in porous media even with 1000 mu m fracture caused by the CO2 hydrate formation, and it can withstand the overpressure caused by CO2 accumulation of at least 7.0 MPa. In addition, a method for determining the sealing interface and CO2 sequestration volume based on pressure changes of sequestrate CO2 was proposed, with an error of 0.1%similar to 0.92%. Hydrate cap would be broken through caused by pressure decrease, and the breakthrough pressure decreased exponentially with increasing channel size. These findings provide significant experimental evidence and theoretical understanding on CO2 leakage evolution after sequestration, especially in porous media with fracture channel.

Enhancing understanding of the coupled behavior of natural gas hydrate dissociation and gas production during joint exploitation is crucial for optimizing production, improving efficiency, and achieving hydrate commercialization. However, existing studies lack key conclusions regarding experimental and model predictions of hydrate dissociation and gas production behavior within muddy cores during joint exploitation. Therefore, natural gas hydrate reservoirs with different gas volume ratios (19X similar to 30X) are remolded using marine soil. Experimental results indicate that increasing the gas volume ratio enhances total gas production (dissociation amount) by 75.88 % (11.88 %), primarily driven by the increased volume of underlying gas (higher hydrate saturation). The dissociated pressure of the core inlet is correlated with the gas volume (Y = 2.81 + 0.21X, R-2 = 0.9715), while the dissociated pressure of the core outlet is uniformly 3.3 MPa. Additionally, enhanced gas seepage improves thermal and mass transfer efficiency, reducing hydrate dissociation time (gas production) by 27.47 % (9.46 %). A stable seepage stage persists across all gas volume ratios, facilitated by enhanced pressure gradient stability at higher gas volume ratio. The duration of stable seepage (average flux) increases by up to 109.87 % (17.01 %). Furthermore, the dissociation front propagates along the pressure gradient direction, with phase change completing before substantial gas production. Coupling the experimental conditions, the real-time outlet pressure, inlet pressure, and hydrate dissociation amount under different conditions are predicted (R-2 >= 0.9949). The research results can provide an important theoretical basis for dynamic optimization and modeling predictions of hydrate dissociation and gas production behavior during joint exploitation.

Carbon capture and storage is a key strategy for mitigating global warming, with ocean sequestration offering a unique advantage: its theoretical capacity is approximately 20 times that of terrestrial geological formations. However, direct evidence has been lacking for the core question determining the feasibility of ocean sequestration—whether CO2 hydrates can remain stable in the marine environment over the long term. In this study, we propose an innovative approach by using methane hydrate, which has naturally remained stable in seafloor sediments for millennia, as a benchmark. Through multi scale experiments and simulations, we investigate the stability of CO2 hydrates under various marine conditions. Remarkably, in quiescent sediment layers (representing stable storage environments), the dissolution rate of CO2 hydrate is only 1.75 times that of methane hydrate, providing strong evidence for the feasibility of hydrate-based CO2 ocean sequestration. In contrast, under unconventional storage conditions (strong hydrodynamic disturbance within sediment layers or direct exposure to seawater), the stability of CO2 hydrate is substantially reduced, with dissolution rates 4.27 and 15 times those of methane hydrate, respectively. These results provide the first quantitative evidence that, when protected by a low permeability sediment layer under diffusion-dominated conditions, CO2 hydrate exhibits dissolution behaviour compatible with millennial-scale persistence, suggesting its potential for long-term stability comparable to that of methane hydrate. Our findings strongly validate the feasibility of hydrate-based CO2 sequestration in marine sediments and establish a scientific basis for site selection.

CO2 hydrate cap plays a crucial role in the long-term carbon storage in sub-marine reservoirs, and its formation is influenced by various factors, such as storage pressure and flow conditions. However, systematic investigations of the dynamic formation and stability of hydrate caps under multiphase flow process, particularly regarding the coupled effects of storage pressure and flow regimes, are still lacking. Therefore, this study explores the formation dynamics and stability behaviors of CO2 hydrate sealing cap under varying pressures and flow rates during CO2 single-phase and CO2-H2O two-phase flow. The experimental findings indicated that the hydrate cap was uniformly distributed under CO2 single-phase flow, while a more dispersed distribution occurred in CO2-H2O two-phase flow, particularly at lower gas fractional flow (20 similar to 40 %). Moreover, the formation time of the hydrate cap decreased with increasing storage pressure and CO2 fractional flow. Notably, storage pressure had a more significant effect on rapid hydrate cap formation. Decreasing the pressure from 5 MPa to 3 MPa resulted in a formation time that was approximately 4 times longer. Furthermore, the hydrate cap formed under CO2 single-phase flow shows greater stability than that formed under CO2-H2O two-phase flow. These insights offer vital guidance for developing the efficient CO2 storage strategies in submarine environments.

With the ever-increasing global energy demand, natural gas hydrates, as an important reserve of methane gas, have attracted growing attention. The key mechanism controlling hydrate exploitation is its dissociation by depressurization, yet previous studies were unable to solve the accurate coupling of thermodynamic and kinetic models. In this study, nine experimental cases were conducted in porous media by depressurization with the fastest rate being 256 times of the slowest, and the real-time thermodynamic and kinetic evolutions of methane hydrate dissociation under different depressurization rates were experimentally obtained. Based on these results, an empirical relationship is employed to describe the relationship between temperature and pressure of methane hydrates in dissociation, and then a skewed-normal kinetic model with four parameters is proposed to calculate dissociation kinetics, with coefficients of determination (R2) exceeding 0.99 for all cases. In addition, it is found that there should be a correlation term to correctly evaluate the interphase heat transfer between hydrates and reservoirs, which considers pressure changes, hydrate instantaneous dissociation rate and hydrate temperature. Combining traditional heat and mass transfer theories, the energy balance models can hence be established to calculate the entire process of methane hydrate dissociation by depressurization, with R2 values exceeding 0.94 in all cases. This study provides a reliable approach for calculating entire dissociation kinetic and temperature response evolutions of methane hydrate under different depressurization rates, offering important basis for accurate exploitation predictions of large-scale hydrate reservoirs.

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.

Abstract Shallow methane leakage is a topic of great concern for governments and the public worldwide. Upward methane leakage can induce hydrate formation, enabling high-density carbon sequestration but also causing significant changes in fluid saturation and reservoir properties. However, existing studies lack key conclusions about the dynamic prediction of saturation during upward methane migration. Therefore, the formation characteristics and saturation prediction of methane hydrates in muddy cores at different flow rates were studied. The results show that lower gas flow rates are more conducive to hydrate formation, which is attributed to sufficient gas–liquid contact and enhanced mass transfer. The maximum increase in hydrate saturation is 47.43%, and the maximum decrease in permeability (increase in damage coefficient) is 65.99% (27.48%). Methane hydrate formation leads to a decrease in permeability and induces an increase in the inlet pressure nonpressurization gradient, with a maximum pressure difference of 5.85 MPa. At the same time, the permeability and hydrate saturation comply with K = K0((1 – Sh)/(1 + 2Sh))2.5, and the measured values are all within the 95% prediction band. On the basis of the coupled relationship between hydrate saturation and inlet pressure during the flow process, a new hydrate saturation prediction method is proposed (R2 > 0.98). Orthogonal experiment results show that the gas flow rate has the greatest influence on the hydrate saturation, while the outlet pressure has the least influence. This study provides a constructive solution for predicting the hydrate saturation during the upward leakage process of methane.

CO2 enhanced oil recovery technology, as a critical component in the field of carbon capture, utilization, and storage, enables simultaneous geological sequestration and efficient utilization of CO2. Current numerical simulations of CO2 miscible displacement predominantly concentrate on investigating the seepage processes while lacking a comprehensive quantitative analysis of the residual oil distribution. Addressing this research gap, this study employs digital core technology to reconstruct the actual three-dimensional rock pore structures and establishes a mathematical model coupling fluid flow with interphase mass transfer. The process of CO2 miscible displacement is simulated to elucidate its seepage mechanisms in the complex pore structures, classify the occurrence morphologies of the residual oil, and conduct quantitative analysis. Further investigations examine the impacts of CO2 injection velocity, fluid viscosity ratio, and rock wettability on the displacement dynamics and the reduction of the residual oil. Simulation results reveal that the displacement process can be divided into three stages. During the early stage, a rapid CO2 breakthrough into the crude oil is observed. During the intermediate stage, CO2 plumes are formed, establishing the dominant flow pathways that sweep into the surrounding pores from the main flow zone; meanwhile, the displacement efficiency decreases. During the late stage, the morphological types of residual oil within the pore region tend toward stability. After the displacement, the residual oil can be divided into seven categories according to the different occurrence forms, with the descending remaining quantities as follows: lump-shaped (32.1%), blind-end-shaped (21.8%), sheet-shaped (19.7%), strip-shaped (15.5%), columnar-shaped (8.2%), annular-shaped (2.3%), and corner-shaped (0.4%) residual oils. Among these morphologies, the lump-shaped, blind-end-shaped, sheet-shaped, and strip-shaped residual oils account for nearly 90%, making them the primary mobilizable types. Increasing the injection velocity accelerates the displacement process, with the reduction in lump-shaped, sheet-shaped, and strip-shaped residual oils being the most substantial, accounting for 34.7%, 29.0%, and 16.5% of the total reduction, respectively. On the other hand, reducing the viscosity ratio enhances the piston-like displacement efficiency, significantly decreasing the sheet-shaped and strip-shaped residual oils adhering to the pore walls and the difficult-to-mobilize corner-shaped residual oil, with relative reduction rates of 67.8%, 54.2%, and 73.7%, respectively. When the rock wettability transitions from the oil-wet to the nonoil-wet conditions, the CO2 seepage resistance decreases, and the displacement efficiency for the sheet-shaped and strip-shaped residual oils adhering to the pore surfaces is significantly improved, with reductions accounting for 43.2% and 28.8% of the total reduction, respectively, while the blind-end-shaped residual oil is also notably mobilized, contributing 11.5% to the total reduction. This study achieves the classification and quantitative characterization of the occurrence morphologies for different types of residual oil during CO2 miscible displacement in the three-dimensional complex pore structures and quantitatively reveals the mobilization potential of each type of residual oil, thereby providing a theoretical basis and quantitative support for optimizing targeted injection strategies and enhancing oil recovery.

Two-phase fluid displacement in porous media represents a critical physical process in the field of underground energy and environmental engineering, especially in CO2 enhance water recovery process. However, the impact of pore structure heterogeneity and brine salinity on the microscopic displacement mechanisms and storage efficiency remains unclear, with a lack of quantitative characterization, thus limiting the optimization of storage efficiency. In this study, high-pressure and high-temperature microfluidic experiments were conducted. By designing porous media chips and integrating microscopic imaging with quantitative image analysis, the effects of varying pore structures and brine salinity on the microscopic flow characteristics and displacement mechanisms of CO2-brine two-phase flow were systematically investigated. The results demonstrate that pore structure heterogeneity impedes effective CO2 sequestration. In homogeneous structures, CO2 exhibits an approximately piston-like displacement pattern, achieving the highest displacement efficiency (81.98%). In contrast, in heterogeneous and rock structures pronounced capillary fingering and fluid bypassing occur, leading to reduced efficiencies between 63.86% and 73.38%. As the pore structure transitions from homogeneous to rock model, the CO2 sequestration capacity decreases significantly by 62.59%. When the injection rate increases from 0.002 mL·min-1 to 0.01 mL·min-1, the displacement efficiency increases by around 10% for the three structures studied. Increasing brine salinity enhances interfacial tension and aqueous phase viscosity, thereby reducing the capillary number and promoting fingering and bypassing phenomena. Consequently, the displacement efficiency decreases from 72.43% to 63.86%. This study provides a quantitative characterization of CO2 microscopic displacement efficiency and sequestration capacity at the pore scale, revealing the critical controlling roles of pore-structure heterogeneity and brine salinity in multiphase flow fields. These findings offer mechanistic insights essential for the design and optimization of CO2 sequestration strategies.

Geological sequestration of carbon dioxide (CO2) is a vital approach to achieving carbon reduction targets. Among the various methods of storage, those in subsea natural gas hydrate (NGH) reservoirs have attracted increasing attention due to their potential for long-term stability. However, inappropriate selection of injection paths often restricts the effective storage extent, hindering large-scale and efficient CO2 sequestration. In this study, an innovative two-direction seepage scheme was proposed and experimentally validated to investigate the effects of different water-gas injection rates and initial NGH saturation (Sh0) on reservoir permeability evolution and sequestration efficiency. The results indicate that two-direction delivery induces asymmetric seepage and dynamic breakthrough behavior of H2O and CO2, causing alternating flow directions. Furthermore, the alignment of water-gas flow rates and Sh0 is imperative for the effective regulation of the sequestration process. A reduction in the CO2 injection rate from 1.0 mL/min to 0.5 mL/min results in a 64.4% increase in average storage capacity, significantly enhancing the sequestration performance. An increase in Sh0 from 10% to 25% results in a significant reduction in hydrate blocking time, while the impact on storage capacity demonstrates a non-linear trend. The present study demonstrates that two-direction seepage can alleviate the limitation of restricted storage extent caused by one-direction. This finding offers a novel technical pathway to improve the safety and effectiveness of large-scale CO2 sequestration.

Implementing carbon sequestration in permafrost regions using hydrate technology offers a promising strategy for long-term carbon storage. Ice phases in permafrost play a critical role in regulating hydrate decomposition kinetics and sequestration stability. This study, for the first time, proposes and validates a stability-enhancement strategy that exploits these ice phases, progressing from pore-scale analysis to ice lens-covered reservoirs representative of natural permafrost heterogeneity. Using low-field NMR and visualization experiments, we examine hydrate phase-transition responses under heating (−5 to 5 °C), depressurization (0.9 MPa to atmospheric pressure), and varying ice cap thicknesses (0–2.5 cm). Results show that regenerated pore ice formed during heating inhibits hydrate decomposition, an effect amplified by ice lens structures. Ice-induced gas diffusion suppression and heat transfer between ice and hydrates prolongs sequestration duration by up to 231.9 min and increases retained sequestration capacity by 31.8%±1.15%. Moreover, the instability threshold of hydrate sequestration is critically controlled by asynchronous deformation between ice and hydrate phases in conjunction with pore structure characteristics. This study elucidates the pore-scale structural evolution during instability in ice-hydrate reservoirs, providing new insights into stability regulation mechanisms for hydrate-based carbon sequestration in permafrost regions and establishing a theoretical basis for optimizing sequestration engineering designs.

The increasing global energy demand and the accelerated integration of renewable energy have intensified the need for efficient and flexible building cooling technologies with low carbon impact. Ice cold storage systems (ICSS) offer a promising solution for demand-side energy management; however, their practical application is still constrained by limited heat transfer efficiency, insufficient cold energy conversion efficiency and restricted operational flexibility. In this study, a pilot-scale ICSS incorporating an internal cycle gas disturbance strategy was developed and investigated. Results indicate that the internal cycle gas disturbance significantly improves system performance by enhancing heat transfer coefficients and accelerating the rate of cold energy storage and release. Under optimal conditions (−3°C, 30 m3/h), the coefficient of performance (COP) of the chiller and the overall system increased by 9.27% and 7.42%, respectively, while favorable cold storage and discharge efficiency was achieved. Simulations further demonstrated that the proposed system outperforms conventional air-conditioning systems, reducing annual operational costs by a factor of 2.16 to 3.91, with payback periods of less than 2.77 years achieved across all representative regions under the optimal cold supply mode. Overall, the developed ICSS provides an energy-efficient and economically viable approach for cold energy storage. The results obtained under pilot-scale conditions demonstrate its engineering applicability and provide valuable insights into the scale-up and practical implementation of ice cold storage systems for building cooling applications.

Solid fluidized method is a novel and promising technique for submarine methane hydrate exploitation, which involves the formation and decomposition of methane hydrate in submarine muds. However, the effects of complex flow conditions on solid fluidized exploitation are still unclear. This study employed real South China Sea sediments to simulate submarine muds and considered different flow conditions, including pressures (7.19, 7.79, and 8.14 MPa), rates (250, 300, and 400 mL/min), and water contents (50, 70, and 90 wt%). Based on the nonlinear logarithmic collaborative change stage of pressure and temperature during formation or decomposition process, non-equilibrium decomposition curve (NEDC) and minimum formation limitation (MFL) of methane hydrate in submarine muds under different flow conditions are quantitatively obtained. Experimental results indicate that the NEDC of methane hydrate in flowing submarine mud is only affected by fluidized water contents, rather than pressure and rate, which is mainly due to the heat and mass transfer obstruction of water phase surrounding hydrate crystals in decomposition process. In addition, it is found that the presence of MFL means the soil-in-water particles, around which the internal pressure of water can be decreased, are the attached media of hydrate formation in muds and are mainly affected by pressure, rather than fluidized rate and water contents. This study reveals the basic thermodynamic characteristics of methane hydrates in flowing muds, which are significant for the process control of submarine solid fluidized exploitation.