Despite the potential of hydraulic fracturing to enhance development efficiency in low-permeability hydrate reservoirs, its effectiveness is hindered by the infiltration of fracturing fluid into the reservoir. This infiltration can lead to water blockages at the matrix-fracture interface, compromising reservoir permeability and optimal gas production. To address this, breakers, clay stabilizers, and cleanup additives were added into water-based fracturing fluids to mitigate water blockage. Our research was centered on the fluid invasion into hydrate-bearing sediments, particularly the impact and mechanism of these additives in reducing water blockage, and their contribution to boosting production. The results showed that nonionic surfactants, acting as cleanup additives, significantly reduced interfacial tension, altered reservoir wettability, and decreased the invasion distance of the fracturing fluid. This effectively limited the degree of permeability damage caused by water blockage. The inclusion of cleanup additives enhanced pore water flowback efficiency, which markedly reduced the water saturation of the invaded region. However, it was noted that both insufficient and excessive amounts of these surfactants and additives could lead to adsorption or blockages near the fracture surface, thus rendering them ineffective in deeper sediments. Permeability and gas production tests revealed that the simultaneous use of a cleanup additive and clay stabilizer resulted in more effective water blockage removal. Remarkably, with the combined addition of a gel breaker, 5 %wt cleanup additives and KCl, the damage degree near the fracture surface was reduced to only 10 %. Simultaneously, the gas production rate in the uninvaded zone increased by 74.3 % compared to the fracturing fluid without additives. These results suggest that including cleanup additives in the fracturing fluid system can mitigate water blockage damage and boost methane gas recovery, which is vital for the successful application of hydraulic fracturing technology in marine natural gas hydrate reservoirs.

The commercial exploitation of natural gas hydrates is currently facing several challenges,including low production rates,limited recovery areas,and brief periods of continuous production.To address these issues,we propose a novel dual-enhanced stimulation(DES) method for marine hydrate reservoirs.This method involves injecting a special slurry that solidifies into porous,high-permeability,and highstrength slurry veins.These veins not only enhance permeability,allowing for faster gas and water flow,but also improve reservoir stability.This study experimentally investigated the split grouting of clayey-silty sediments with dual-enhanced slurry to assess the feasibility of DES and to explo re the slurry diffusion mechanism and micro-pore structure of the veins.The results showed that split grouting with dual-enhanced slurry exhibited frequent fracture initiation with quick pressure spikes and sharp declines,suggesting shorter fractures in clayey-silty sediments.As vertical stress increased,the primary diffusion direction of the dual-enhanced slurry shifted from horizontal to vertical,aligning with fracture propagation patterns observed during fracturing.Unlike hydraulic fracturing in hard rocks,split grouting in clayey-silty sediments encountered more difficult conditions.These veins formed through a recurring cycle of splitting into fractures and filling with slurry,occurring more frequently in weaker sediments with slower injection rates and higher vertical stress.Increased vertical stress hindered slurry vein diffu sion,easily resulting in compaction grouting near the grouting pipe.Additionally,three-dimensional laser scanning of the veins showed that those formed through split grouting were continuous and stable,with their thickness decreasing as diffusion distance increased.The morphology of these veins was shaped by factors such as grouting rate,formation stress,and elastic modulus,with higher rates and elastic moduli facilitating the formation of complex vein networks.Mercury intrusion porosimetry demonstrated that the DES method resulted in veins with consistent effective porosity between 65% and70% and median pore sizes of 11-15 μm across different locations.These veins formed a well-connected porous network of smaller pores,significantly enhancing both permeability and sand control.The research findings validate the effectiveness of the DES method for marine hydrate reservoirs,providing a strategy for the safe and efficient exploitation of NGH resources.

Hydraulic fracturing is a potentially promising technology for stimulating gas production and improving energy efficiency in low -permeability hydrate reservoirs. However, marine hydrate reservoirs, with weak cementation, unconsolidated nature, low mechanical strength, and the potential for decreased strength and fines migration resulting from hydrate decomposition, pose significant challenges for effective fracture propping and maintaining high conductivity. To assess hydraulic fracturing feasibility in marine hydrate reservoirs, we conducted experiments to investigate the impact of closure pressure, hydrate saturation, and hydrate decomposition mode on fracture conductivity, with a particular focus on understanding the propping mechanism and identifying potential sources of conductivity damage in artificial fractures. The results demonstrated that the conductivity of propped fractures within hydrate -bearing clayey silt sediments linearly decreased with increasing closure pressure, primarily due to proppant compaction and embedding. The conductivity disparity under different hydrate saturation levels decreasesd and became similar at 16 MPa closure pressure. The decomposition mode of hydrates had a significant impact on fracture conductivity damage, with higher degree of damage observed with increasing depressurization range (up to 90.3% at a 3.0 MPa range), whereas slow decomposition induced by heating only resulted in minor decreases in fracture conductivity (damage degree: 6.6%), primarily attributed to the migration of fine particles during gas -water production. Proppant embedding and fines migration were the main causes of fracture conductivity damage in hydrate reservoirs. Proppant embedding damage occurred at higher closure pressures or slow hydrate decomposition, while fines migration damage occurred with rapid hydrate decomposition. In proppant-filled propped fractures, fines migration posed a greater risk to fracture conductivity than proppant embedding, as the migration of fine particles can block the pore spaces within the proppant-filled fractures, leading to a significant reduction in conductivity. Therefore, it was recommended to induce hydrate decomposition by slowly reducing pressure during production to minimize fines migration damage to fracture conductivity. These research findings hold significant importance in the application of hydraulic fracturing during field tests conducted on hydrate reservoirs, as they assist in optimizing the propping mode of fractures and ensuring the effectiveness and prolonged success of fracturing stimulation.

Storing CO2 in underwater sand sediments as hydrates offers vast capacity and minimal leakage risk. But direct CO2 injection can clog the surrounding area, reducing the flow. One solution is injecting CO2-N2 mixtures. This study investigated the movement and transformation of this gas mixture, with a focus on the formation rates and main factors of hydrate-based CO2 storage. Results revealed two distinct gas seepage-phase transition processes. In freshwater conditions, there was an initial temperature spike followed by localized hydrate formation, which then spread outward. In memory water, multiple hydrate formations occurred simultaneously. Freshwater conditions led to more blockages due to the concentration of hydrates, while the memory conditions maintained better flow due to more evenly distributed hydrates. Gas composition analysis showed that as CO2-rich hydrates formed, the CO2 level in the flowing gas dropped, which could stop further hydrate formation. This finding indicates that mixed gas injections could prevent excessive hydrate formations and maintain flow. The saturation of hydrates varied between 10 % and 50 %, with differences attributed to the unpredictable nature of initial hydrate formation. Overall, this research will guide efforts to optimize CO2 storage as hydrates and re-evaluate the viability and safety of this storage method using CO2-N2 mixtures.

Clayey-silty hydrate reservoirs in the South China Sea (SCS) are characterized by low permeability, poor strength, and weak cementation. In order to improve the injection effect of reservoir stimulation by highviscosity grout, this paper proposes a pulsed pneumatic pre-fracturing grouting technology to enhance the injectability of grout and improve overall conductivity of hydrate-bearing sediments. In the pulsed pneumatic fracturing experiment, increasing the frequency f results in higher average pneumatic pressure sigma(avg) and maximum pneumatic pressure sigma(max), maintaining elevated pneumatic pressure levels that reduce local soil strength and improve fracturing effectiveness. In addition, the fracture extension range is positively correlated with the pressure and frequency. In a pulsed pneumatic pre-fracturing grouting experiment, this technology outperformed the conventional fracturing grouting. At frequencies of 2.5 Hz, 5 Hz, and 10 Hz, the total extension distance of the grout consolidation body increases by 3.28, 4.43, and 4.71, respectively. Meanwhile, the total weight of the grout consolidation body increased by factors of 1.94, 2.45, and 3.57. Additionally, under high-frequency fracture initiation condition (10 Hz), the average thickness of the grout consolidation body doubled compared to that under low-frequency condition (2.5 Hz). In conclusion, the pulsed pneumatic pre-fracturing grouting technology significantly improved the injectability of high-viscosity grout and the effectiveness of grouting stimulation in sandy and clayey-silty hydrate-bearing sediments.

Hydraulic fracturing has been proven useful for improving the gas production efficiency of low-permeability hydrate reservoirs. However, no specific fracturing fluid system exists for marine hydrate reservoirs. Applying conventional water-based fracturing fluids in low-temperature (<293.2 K) marine hydrate reservoirs can lead to difficulties in gel-breaking and hydrate instability caused by external additives. In this study, we developed two water-based fracturing fluid systems that exhibited good gel-breaking performance at low temperatures (278.2–288.2 K), one comprising ammonium persulfate (APS), ferrous sulfate (FeSO4), and citric acid (CA), the other APS and triethanolamine (TEA). In addition, we investigated the influence of crosslinking and gel-breaking reactions of the fracturing fluids on the methane hydrate phase equilibrium. The breaking time of the APS-FeSO4-CA system at 278.2K, 283.2K, and 288.2K was 30 min, 75 min, and 120 min respectively. On the other hand, the APS-TEA system accomplished the same task in 3 h, 6 h, and 10 h respectively. Furthermore, methane hydrate phase-equilibrium data showed that the fracturing fluid's three states, base fluid (BF), fracturing fluid gel (FFG), and gel-breaking liquid (GBL), all exerted an inhibitory effect on the phase equilibrium, with the hydrate suppression temperature (ΔT) ranging from 0.4 to 1.0 K. The differences in their inhibitory effect were primarily related to the micromorphology of the hydroxypropyl guar gum (HPG) molecules and the number of active hydroxyl (-OH) groups in the solution. Cryo-scanning electron microscopy (SEM) measurements revealed that the micromorphology of HPG in BF, FFG, and GBL transformed from regular ribbon-like structures to 3-D network structures and then to hole-containing, short ribbon-like structures. FFG formed a regular 3-D network structure after adding crosslinking agents to the BF. The ΔT values reversed from FFG < BF to FFG > BF when the HPG concentration increased from 0.3 wt% to 0.5 wt%, possibly due to the difference in the HPG molecules' water adsorption capacity before and after crosslinking. The broken HPG molecules with OH− groups in the solution were transformed into residues after gel-breaking, decreasing the GBL's inhibitory effect. Therefore, our results indicated that micromorphology variations could cause differences in the HPG molecules' water adsorption capacity, ultimately leading to ΔT differences. Based on our findings, the gel-breaking fracturing fluid systems we developed demonstrated potential for optimizing hydraulic fracturing in marine hydrate reservoirs.

This study investigates the fracture conductivity characteristic of propped fractures in marine hydrate-bearing clayey silt sediments, focusing on the Shenhu area of the South China Sea. Closure pressure is identified as the primary influencing factor, causing a significant loss of fracture conductivity—6.9 times more than that induced by hydrate decomposition. Proppant embedment and rearrangement of the proppant pack body emerge as the major contributors to conductivity loss. The positive correlation between fracture width displacement and closure pressure reveals that proppant rearrangement plays a more substantial role than hydrate-sediment deformation and proppant embedment. The decrease in elastic modulus during hydrate decomposition slightly increases proppant embedment, especially at around 35% hydrate saturation. In comparison to other unconventional reservoirs, proppant embedment exhibits a more pronounced impact in hydrate reservoirs, resulting in significant embedment amounts for different proppant particle sizes. Interestingly, conductivity does not increase with larger proppant sizes, with the 40/70 mesh fracture conductivity surpassing that of the 30/50 mesh. Furthermore, increased proppant concentration leads to reduced embedment due to proppant packing rearrangement. Different mechanisms contribute to conductivity reduction in varied proppant loading concentrations, with single-layer concentrations experiencing rapid conductivity decline due to proppant embedment, while multilayer concentrations face major reductions from proppant compaction. Finally, seawater flow introduces a negative impact on fracture conductivity, causing a 20.68% loss. This is attributed to seawater softening fracture surfaces, expanding clay in sediments, and inducing further proppant embedment. Overall, the study underscores the critical role of closure pressure and proppant characteristics in governing fracture conductivity in hydrate-bearing clayey silt sediments. The findings contribute valuable insights for optimizing natural gas hydrate exploitation, especially in offshore environments.

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Hydrate reformation, caused by the Joule-Thomson effect (JTE) during depressurization, poses a major obstacle to efficient gas production. This study examines the impact of the JTE on hydrate reformation near the wellbore during depressurization, focusing on the influences of gas-to-water ratio, depressurization range, and permeability. The results indicate that JTE significantly contributes to a gradual temperature decrease, leading to hydrate reformation. Reformed hydrates, potentially saturating up to 80%, initially appear near the wellbore then move away due to intense depressurization that eroded their inner surface, creating a moving lowpermeability barrier that obstructs fluid flow and reduces gas-water production rates. Formations with higher permeability and gas saturation experience intensified JTE, leading to faster temperature drops, shorter hydrate reformation times, and quicker expansion of secondary hydrate bands. The study also evaluates the effectiveness of wellbore heating to mitigate hydrate reformation. Wellbore heating is found to be more effective in lowpermeability formations, but only within a 0.5 m radius near the wellbore in high-permeability formations. This research suggests narrower depressurization ranges to prevent hydrate reformation and indicates the limited impact of wellbore heating on enhancing gas production. The findings have significant implications for preventing hydrate reformation near the wellbore and improving hydrate production efficiency.

Hydrate-based CO2 capture and separation is considered to be an effective technology in reducing the greenhouse effect. To effectively capture CO2 from flue gas, it is crucial to understand the mechanisms underlying the dissolution-hydration reactions of CO(2 )and N-2. However, the selective adsorption of CO2 and N-2 during the formation of the CO2 + N-2 hydrate complicates the kinetics and alters the gas phase composition and driving force. Unfortunately, limited research has been conducted on the kinetics of the CO2 + N-2 dissolution-hydration reactions. To address this gap, this study conducted experiments on hydrate formation from a CO2 + N-2 gas mixture in a stirred gas-water system. The main objective was to investigate the kinetic characteristics of CO2 + N-2 hydrate formation in water-rich environments, with a primary focus on the selective adsorption of CO2 and N2 during hydrate formation. Analysis of the gas phase composition revealed a gradual decrease in the CO2 content and a corresponding increase in the N-2 content as the experiment progressed, indicating the enrichment of CO2 in the hydrate phase. Gas consumption changes indicated a two-step kinetics process for hydrate formation from CO2 + N(2 )gas mixtures: (1) rapid complexation of CO2 with water during the initial stage to form basic hydrates with empty cavities, and (2) slow adsorption of N-2 into the empty cavities (linked cavities) during the later stage. This two-step kinetic process resulted in significant CO2 gas consumption in the initial stage and slower N-2 gas consumption throughout the entire hydrate formation process. Notably, lower pressure and higher stirring speed promoted greater CO2 adsorption into hydrate structures, which benefitted the capture of CO2 capture. These findings offer valuable insights for selecting favorable conditions for the application of hydrate-based CO(2 )capture and CO2/N-2 separation.

Hydraulic fracturing is a potentially promising stimulation technology employed for enhancing gas productivity and energy efficiency of low-permeability hydrate reservoirs. At present, most studies in the field of hydrate reservoir fracturing have mainly focused on the fracturing feasibility and recovery efficiency without considering the effects of fracturing fluids on hydrate reservoirs. However, fracturing fluid will inevitably invade hydrate reservoirs driven by high fracturing pressure, which may cause hydrate phase transitions and consequently affects fracturing. In this study, the dynamic process of fracturing fluid invasion into hydrate reservoir was simulated using the TOUGH+HYDRATE software, primarily focusing on the differences between the fracturing fluid invasion into the gas hydrate-bearing layer (GHBL), three-phase layer (TPL), and free gas layer (FGL). The results showed that a secondary hydrate column was formed within 2–10 m around the fracture by the fracturing fluid/free water and free gas during fracturing fluid invasion into the TPL and FGL, which was mainly driven by the large driving force exerted by high fracturing pressure. But the exothermic reaction of hydrate formation can provide negative feedback to the formation and expansion of the secondary hydrate column, leading to a state of phase equilibrium in the secondary hydrate formation region and the outward expansion of the secondary hydrate column in a “three-phase equilibrium” mode. It should be noted that secondary hydrate formation did not occur during fracturing fluid invasion into GHBL because of the absence of free gas, and fracturing fluid invasion into GHBL only affected reservoir temperature and pressure, which was similar to the fracturing fluid invasion into unconventional oil and gas layers. These results will provide important guidance for the potential application of hydraulic fracturing in the field tests of hydrate reservoirs and its scheme formulation.

Hydraulic fracturing is a promising stimulation technology for enhancing the gas productivity and energy efficiency of low-permeability hydrate reservoirs. Presently, most studies focus on the fracturing feasibility of hydrate-bearing sediments and recovery efficiency after fracturing. Although the fracturing fluid inevitably invades the hydrate reservoirs during fracturing, the effects of invaded fracturing fluid on sediment permeability and hydrate dissociation have not been investigated yet. In this study, the invasion of water-based fracturing fluid into hydrate-bearing sediments was experimentally studied to clarify the dynamic characteristics of the fracturing fluid invasion, including its effects on sediment permeability and hydrate dissociation. The results revealed that the fracturing fluid loss rate was initially high but abruptly became extremely small, potentially because of the filter cake deposition on the fracture surface and the secondary hydrate formation in the invaded zone. However, the invaded fracturing fluid increased the dissociated gas flow resistance and inhibited the hydrate dissociation and gas production that yielded a two-stage gas production process, including slow hydrate dissociation in the invaded zone followed by relatively fast hydrate dissociation in the uninvaded zone. Furthermore, the degree of permeability damage in the invaded zone gradually decreased with the increasing invasion distance that was caused by the variations in the microscopic filtrate-sediment reactions. Interestingly, the water saturation measured by NMR gradually decreased from about 90% to 60% (initial water saturation) along the invasion distance. This phenomenon indicates that water sensitivity and water lock acted as the primary sources of permeability damage to the clayey-silty sediments after fracturing fluid invasion, suggesting that inhibiting clay swelling and increasing the flowback rate of the invaded fluid were essential for reducing permeability damage. Noted that using the fracturing fluid with breaker and KCl exhibited the lowest degree (25%) and shortest distance (<15 cm) of sediment permeability damage. The present results are vital for applying hydraulic fracturing in the field tests of hydrate reservoirs to optimize the fracturing fluid and improve the fracturing stimulation effect.

Mixed hydrates have been found in some ocean and permafrost deposits, and the dissociation of mixed hydrates by depressurization alone has been reported to be difficult and inefficient. However, most studies in the field of mixed hydrate decomposition have mainly focused on dissociation behaviors at the crystal lattice and guest molecular levels, but there has been little discussion about recovery efficiency. The dissociation of CH4-C3H8 or CH4-C2H6-C3H8 mixed hydrates in sandy sediments using depressurization followed by the gas sweep method was investigated to determine the underlying mechanism of difficulty in decomposition and to enhance hydrocarbon recovery. It was found that CH4 and C2H6 were preferentially released over C3H8 from mixed hydrates in the depressurization stage. Particularly, the dissociation of mixed hydrates tended to stop despite substantial hydrates remaining above the water freezing point, which was similar to the self-preservation effect of CH4 hydrates below the ice point. Interestingly, when gas sweep was performed, mixed hydrates continued to decompose, and more C3H8 was recovered at the beginning of the gas sweep. Compositional analysis of the dissociated gas confirmed that the gradual formation of C3H8-rich hydrate shell led to the cessation of hydrate decomposition, which hinders the diffusing hydrocarbons in the internal hydrate to be released. Furthermore, continuous gas sweep resulted in continuous and rapid decomposition of mixed hydrates, but when it was stopped, the decomposition of mixed hydrates gradually slowed down and tended to stop, and the C3H8-rich hydrate shell was re-formed. This suggested that the formation and decomposition of the C3H8-rich hydrate shell may control the decomposition rate of mixed hydrates. These results are of significance for guiding successful and efficient hydrocarbon recovery from mixed hydrates.

本文基于我国第一轮海域天然气水合物试采地质模型,利用Tough+Hydrate对近井储层改造后的水合物藏进行降压开采模拟研究.探究了多孔骨架渗流通道对气/水输送、压降传播、水合物分解等的影响机制,评估了近井储层改造在不同开采层位和整个开采过程中对产能提高的贡献大小.模拟结果表明:多孔骨架渗流通道内气/水流速高,可以起到导流、防砂的作用;近井储层改造可促进压降传播,加快水合物分解,但骨架通道的增产作用随开采时间增加逐渐减弱;近井储层改造在不同开采层位起到的增产效果不同,三相层中的增产效果最明显,但由于模拟改造范围较小、形成的多孔骨架渗流通道渗透性较低,增产效果不明显,多孔骨架渗流通道高度为50 cm时,2年产气量仅提高11.7％.