Depressurization Production Research Articles

How shallow CO2 hydrate cap affects depressurization production in deeper natural gas hydrate reservoirs: An example at Site W17, South China Sea

The logging results from the Shenhu Sea show that the P-T conditions of NGH deposits are below the CO2 hydrate phase equilibrium curve. The burial depth difference between the CO2 hydrate stable zone and NGH deposits is usually above 100 m, which differs from the laboratory scale. Thus, whether CO2 hydrate caps can provide pore sealing and reinforcement of natural gas hydrate (NGH) overburden at the engineering scale is unknown. Based on this, we aimed to perfect research on the CO2 hydrate cap, including its formation process, effects on NGH exploitation, geomechanical response, and comprehensive benefit evaluation, by establishing a THMC model based on Site W17. Results indicate that (i) CO2 can form hydrates in the overburden layer with a conversion rate of about 28%, preventing the upward escape of residual liquid CO2 due to density difference. (ii) CO2 injection and CO2 hydrate cap formation can increase the decomposition driving force during depressurization to enhance production, but it fails to inhibit water invasion from the upper part of the NGH deposit due to the excessive depth difference. (iii) The CO2 hydrate cap causes strata uplift, thereby mitigating strata subsidence during depressurization production, especially for the cases of horizontal wells, where the subsidence is reduced by about 103.4%. (iv) Injecting too much CO2 may not benefit gas production, where part of the free gas will convert into NGH due to pressure rise. The optimal injection rate in this study is 40,000 m3/d. (v) Indicators like CO2 hydrate conversion rate, gas-water ratio, and maximum strata displacement show that horizontal well systems with CO2 hydrate caps are more beneficial than vertical well systems, and multi-branched well systems are more beneficial than single-direction well systems. These key findings may differ from the laboratory scale, which can provide a reference for applying CO2 hydrate caps in actual NGH exploitation.

CH4 hydrate dissociation and CH4 leakage characteristics: Insights from laboratory investigation based on stratified environment reconstruction of natural gas hydrate reservoir

Submarine natural gas hydrates (NGHs) are one of the largest methane reservoirs on Earth, offering huge potential as an alternative energy source and serving as a crucial global carbon sink. However, the substantial risk of methane leakage during NGH development seriously threatens marine and global ecological and environmental safety, presenting a major challenge for commercial NGH exploitation. Focusing on the unknown leakage mechanisms, this study employed a new simulation device to construct a stratified environment and to investigate the characteristics of hydrate dissociation and methane leakage during depressurization production, under conditions of varied fracturing in overlying sediment. A movable module was used to dynamically isolate and connect the hydrate reservoir with the overlying layer. The results showed that the intrusion of overlying water decelerated the reservoir depressurization rate, leading to a mass of hydrate reformation. The invasion locations and flow paths of the overlying water were influenced by the fracture scale of the overlying sediment. Benefiting from the additional sensible heat and reservoir space occupation of the overlying water in the later production stages, the methane recovery ratio in the fracture-containing systems were not significantly affected. However, the leakage methane increased as fracture channels enlarged, reaching up to 9.90 % of the total methane content in the hydrate reservoir. The leakage mechanism primarily involved local overpressure, buoyancy effects, and diffusion. The research, for the first time, experimentally revealed the response relationship between methane leakage and hydrate dissociation, providing foundational data and theoretical support for the safe and efficient NGH development.

Multiphase behavior and fluid flow of oil–CO2–water in shale oil reservoirs: Implication for CO2-water-alternating-gas huff-n-puff

Based on the CO2-WAG (water-alternating-gas) flooding for conventional reservoirs, CO2-WAG huff-n-puff in shale reservoirs is proposed. To clarify the phase behavior and fluid flow of oil–CO2–water in the CO2-WAG huff-n-puff process, a series of experimental studies are conducted under different injection sequences of CO2 and water. The results show that the saturation pressure of the oil–CO2–water systems is lower than that of the oil–CO2 systems since a portion of the CO2 is dissolved in water. In addition, CO2 injection followed by water can significantly reduce the dissolution of CO2 in the water. CO2 and water preferentially flow into the macropores and bedding fractures of the oil-saturated cores at the injection stage, and the oil in mesopores and micropores reflows into macropores and bedding fractures at the soaking stage. At the depressurization production stage, the oil in mesopores and micropores is gradually extracted. Compared to water injection followed by CO2, injecting CO2 first can avoid the barrier effect caused by the subsequent injection of water and promotes oil flow into mesopores and micropores in the matrix. At the end of production, the oil recovered from water injection followed by CO2 mainly originates from macropores, while that from CO2 injection followed by water primarily comes from mesopores.

Numerical simulation on natural gas hydrate depressurization production considering sediment compression effects

Sediment compression during submarine hydrate depressurization production causes changes in physical and mechanical characteristics, which in turn affects production results. In this paper, based on geological conditions of SHSC-4 well in Shenhu area, a theoretical model considering sediment compression effects is established by COMSOL, and the effects on the evolution of reservoir physical and mechanical characteristics within 60 days during depressurization production is simulated. The results show that model dimension effects can be ignored when the size l ≥ 100 m within 60 days. The effects of sediment compression on the physical characteristics of the reservoir are mainly realized by affecting the evolution of porosity, and the porosity reduction leads to permeability reduction. The larger the sediment compression coefficient, the higher the pore pressure in the reservoir. Sediment compression hinders the propagation of low pore pressure and heat transfer in the reservoir, which is unfavorable for hydrate decomposition favorable to hydrate reformation. A larger or smaller sediment compression coefficient selected in the simulation can lead to under- or over-estimate of reservoir gas production, so choosing an appropriate sediment compression coefficient when considering sediment compression is necessary for rational assessment of reservoir production behavior. In the production test site, when the production pressure is higher than 3 MPa, the pore pressure gradient is the key factor to promote gas production from the reservoir. When the production pressure is lower than 3 MPa, the sediment compression is the key factor to impede gas production from the reservoir.

A Review on Submarine Geological Risks and Secondary Disaster Issues during Natural Gas Hydrate Depressurization Production

The safe and efficient production of marine natural gas hydrates faces the challenges of seabed geological risk issues. Geological risk issues can be categorized from weak to strong threats in four aspects: sand production, wellbore instability, seafloor subsidence, and submarine landslides, with the potential risk of natural gas leakage, and the geological risk problems that can cause secondary disasters dominated by gas eruptions and seawater intrusion. If the gas in a reservoir is not discharged in a smooth and timely manner during production, it can build up inside the formation to form super pore pressure leading to a sudden gas eruption when the overburden is damaged. There is a high risk of overburden destabilization around production wells, and reservoirs are prone to forming a connection with the seafloor resulting in seawater intrusion under osmotic pressure. This paper summarizes the application of field observation, experimental research, and numerical simulation methods in evaluating the stability problem of the seafloor surface. The theoretical model of multi-field coupling can be used to describe and evaluate the seafloor geologic risk issues during depressurization production, and the controlling equations accurately describing the characteristics of the reservoir are the key theoretical basis for evaluating the stability of the seafloor geomechanics. It is necessary to seek a balance between submarine formation stability and reservoir production efficiency in order to assess the optimal production and predict the region of plastic damage in the reservoir. Prediction and assessment allow measures to be taken at fixed points to improve reservoir mechanical stability with the numerical simulation method. Hydrate reservoirs need to be filled with gravel to enhance mechanical strength and permeability, and overburden need to be grouted to reinforce stability.

Development and application of wellbore flow assurance monitoring system for combustible ice production in deepwater

The commercial development of combustible ice, as the most promising strategy energy, requires not only efficient gas production technology but also a safe flow assurance system. For the depressurization development of combustible ice in the sea area, the issues of wellbore fluid carrying sand, hydrate re-formation in the wellbore, and instability of wellbore flow, are the key problems leading to flow obstacles in the wellbore and affecting the normal production. Therefore, some measures must be taken to effectively monitor and analyze the flow situation in the wellbore during the development of combustible ice in the sea. In this paper, a Wellbore Flow Assurance Monitoring System (WFAMS) is developed to display the fluid flow conditions in the wellbore in real-time during the gas hydrate production, including temperature, pressure, flow rate, the carrying sand amount, etc. Furthermore, the system is capable of online monitoring for potential plug risks, including sand plugs and hydrate blockages caused by gas hydrate formation, as well as assessing flow stability. Additionally, it can provide valuable information, such as production adjustment data and the required injection dosage of thermodynamic inhibitors to prevent hydrate formation. In the 2020 South China Sea production test, this system was used for depressurization production and successfully predicted wellbore flow conditions. This enabled field engineers to monitor flow risks and adjust production plans in a timely manner, ensuring smooth test progress.

Mechanical Modeling and Analysis of Stability Deterioration of Production Well During Marine Hydrate Depressurization Production

Mechanical Modeling and Analysis of Stability Deterioration of Production Well During Marine Hydrate Depressurization Production

Analysis of Factors Influencing the Stability of Submarine Hydrate-Bearing Slopes during Depressurization Production

Natural gas hydrate reservoirs, with shallow burial, poor cementation, and low strength, are prone to submarine landslides triggered by hydrate decomposition during extraction. Prior studies have inadequately considered factors such as the dynamic decomposition of hydrates during depressurization, and its impacts on the reservoir’s geomechanical properties. In this paper, a coupled thermal–hydraulic–mechanical–chemical mathematical model of hydrate decomposition is proposed, and the dynamic geomechanical response and the effect of hydrate decomposition on seafloor settlement and slope destabilization during the process of depressurization mining are analyzed by combining the strength discount method with the example of a hydrate-bearing seafloor slope in the Shenhu area. Furthermore, the study employs an orthogonal experimental design along with range and variance analysis to gauge the impact of critical factors (degree of hydrate decomposition, seawater depth, hydrate reservoir burial depth, hydrate reservoir thickness, and slope angle) on slope stability. The findings suggest that hydrate decomposition is non-uniform and is influenced by stratigraphic temperature gradients and gravity. In the region where hydrate decomposition occurs, the decrease of pore pressure leads to the increase of effective stress. Additionally, the decomposition of hydrates decreases the shear modulus of sediments, leading to deformation and reduced permeability in the affected area. Over a three-year period of depressurization mining, the significantly reduced safety factor increases the risk of landslides. Various factors play a role in the control of submarine slope stability, with slope inclination being the primary factor, followed by the degree of hydrate decomposition, reservoir thickness, burial depth, and seawater depth. Among these factors, hydrate burial depth and seawater depth have a positive correlation with submarine slope stability, while increases in other factors generally decrease stability. These research findings have important implications for the safe exploitation of slopes that contain hydrates.

Numerical Simulation of Production Behavior with Different Complex Structure Well Types in Class 1-Type Hydrate Reservoir

Enhancing the production capacity of natural gas hydrates (NGHs) is critical for its commercial development. Complex structure wells may efficiently increase drainage areas while enhancing exploitation efficiency. Based on the field data of China’s first offshore NGH test production, the numerical method was used to analyze the production performance of different complex structure well types by continuous depressurization production for 360 days under the preconditions of fixed effective completion length of 300 m and a pressure difference of 6 MPa. Results indicated that the complex structure well types deployed at the three-phase layer demonstrated superior production performance within 240 days of production; the DLW2 and HW2 well types stood out, with an average gas production rate Qg reaching 43,333 m3/d and a specific production index J of 24.1. After 360 days of production, benefiting from multi-layer combined production, the Cluster vertical well deployed at the multi-layer had the best production performance, with an average Qg of 34,444 m3/d and a J-index of 19.1. The research results provided insights into the complex structure well-type selection strategy for NGH depressurization in this sea area.

Enhancement of Gas Production from Class 1-Type Hydrate Reservoirs with High-Pressure Rotating Water Jets in Horizontal Well Depressurization Production

Enhancement of Gas Production from Class 1-Type Hydrate Reservoirs with High-Pressure Rotating Water Jets in Horizontal Well Depressurization Production

Influence of depressurization mode on natural gas hydrate production characteristics: One-dimensional experimental study

The latest research suggests that using depressurization methods and their enhancements could be the most effective way to produce natural gas hydrates efficiently in marine areas. Therefore, it's crucial to investigate the gas production behavior and the changes in temperature and pressure within natural gas hydrate reservoirs under different depressurization methods. In this paper, the self-developed one-dimensional natural gas hydrate production simulation test system was utilized to conduct one-dimensional depressurization production tests during two depressurization modes of significant depressurization and slow depressurization. The findings indicated that the minimum temperature increment-depressurization rate curves in significant depressurization tests exhibited irregular patterns, primarily due to the frequency and intensity of hydrate reformation, while the smaller the depressurization rate, the larger the minimum temperature increment and the smaller the maximum dissociation rate under slow depressurization. In addition, when maintaining a fixed hydrate saturation level, the peak gas production rate showed a decline with decreasing depressurization rate. However, the exact correlation between the peak gas production rate and the depressurization rate remained uncertain due to the unpredictable nature of the “armoring” effect.

Stability of the wellbore wall during marine hydrate depressurization production based on a modified Drucker-Prager model

Different from oil and gas production, hydrate reservoirs are shallow and unconsolidated, whose mechanical properties deteriorate with hydrate decomposition, so there is a risk of wellbore wall failure during depressurization production. However, the existing researches of wellbore stability focuses on the drilling process, and the stress model used does not taking the effect of casing into account. Therefore, this paper aims to propose an analytical approach suitable for the analysis of wellbore wall stability during production. We proposed a stability analysis criterion based on a modified Drucker-Prager model, derived an effective stress model considering casing-reservoir interaction, established a multi-field coupling model reflecting the dynamic effect of hydrate decomposition, and developed a solver. An experimental system was designed to verify the models. A case study found that the stability is worst near the casing in the direction of maximum horizontal in-situ stress, relatively better in the direction of minimum horizontal in-situ stress, and progressively increase away from the casing. The stability decreases with the decrease of hydrate saturation, and the lower the saturation, the faster the stability decreases. The inhomogeneous of in-situ stress has great influence on the stability, and if it is too high, the wellbore wall will be damaged.

Multi-field coupling analysis of mechanical responses in methane hydrate exploitation with a practical numerical approach combining T + H with DEM

The methane hydrate (MH) is widely distributed in deep-sea sedimentary layers, considered as the most promising clean energy to replace conventional oil and gas in the 21st century. Large-scale exploitation of MH may lead to a series of geotechnical engineering problems. To numerically estimate the seabed stability during MH exploitation which should involve multi-field coupling simulation of complex mechanical behaviors of methane hydrate bearing sediment (MHBS), a new practical hybrid numerical method is proposed, which combines the TOUGH + HYDRATE (T + H) code, targeting multiphase flow analysis of hydrate-bearing geologic systems, with the improved Distinct Element Method (DEM). Porosity, temperature, pressure, salinity fields are exchanged between DEM and T + H to realize the thermal-hydro-mechanical-chemical (THMC) coupling and to reproduce the progressive discontinuous failure process. The results of verification show obvious uniformity between numerical and analytical results for one-dimensional (1D) consolidation and 1D heat conduction tests on soils. The paper tries to analyze evolutions of THMC fields, gas production, hydrate bond breakage and other mechanical behaviors of actual depressurization production by using this method, focusing on geotechnical risks of exploitation. In addition, study observes significant changes within certain range from the wellbore for gas production and mechanical responses in the early stage.

Class-III Hydrate Reservoir Depressurization Production Enhancement by Volume Fracturing and Cyclic N2 Stimulation Combination.

The depressurization effect is limited to class III hydrate reservoir recovery. To improve the depressurization effect, a new method of volume-fracturing and cyclic N2 stimulation combination (VFCS) was proposed. The production performance of this method was investigated by using numerical models based on reservoir parameters of the SH7 hydrate site in the South China Sea. The results show that (1) VFCS can greatly enhance the production performance with the average CH4 production rate being approximately 2.85 times higher than that of pure depressurization. This method combines the effects of volume fracturing and cyclic N2 stimulation by improving the seepage environment and further reducing the CH4 partial pressure in the gas phase. (2) High reservoir permeability, medium hydrate saturation, large volume-fracturing scale, low bottom-hole pressure, and high N2 injection amount can increase CH4 production by VFCS. (3) Although VFCS has the largest CH4 production volume and the highest hydrate dissociation degree among the studied production strategies, the reservoir temperature drop is significant by VFCS and future studies can be focused on the external heat supply to the reservoir to further improve the production.

Sensitivity Analysis of Multi‐phase Seepage Parameters Affecting the Clayey Silt Hydrate Reservoir Productivity in the Shenhu Area, South China Sea

AbstractNatural gas hydrate (NGH) is an important future resource for the 21st century and a strategic resource with potential for commercial development in the third energy transition. It is of great significance to accurately predict the productivity of hydrate‐bearing sediments (HBS). The multi‐phase seepage parameters of HBS include permeability, porosity, which is closely related to permeability, and hydrate saturation, which has a direct impact on hydrate content. Existing research has shown that these multi‐phase seepage parameters have a great impact on HBS productivity. Permeability directly affects the transmission of pressure‐drop and discharge of methane gas, porosity and initial hydrate saturation affect the amount of hydrate decomposition and transmission process of pressure‐drop, and also indirectly affect temperature variation of the reservoir. Considering the spatial heterogeneity of multi‐phase seepage parameters, a depressurization production model with layered heterogeneity is established based on the clayey silt hydrate reservoir at W11 station in the Shenhu Sea area of the South China Sea. Tough + Hydrate software was used to calculate the production model; the process of gas production and seepage parameter evolution under different multi‐phase seepage conditions were obtained. A sensitivity analysis of the parameters affecting the reservoir productivity was conducted so that: (a) a HBS model with layered heterogeneity can better describe the transmission process of pressure and thermal compensation mechanism of hydrate reservoir; (b) considering the multi‐phase seepage parameter heterogeneity, the influence degrees of the parameters on HBS productivity were permeability, porosity and initial hydrate saturation, in order from large to small, and the influence of permeability was significantly greater than that of other parameters; (c) the production potential of the clayey silt reservoir should not only be determined by hydrate content or seepage capacity, but also by the comprehensive effect of the two; and (d) time scales need to be considered when studying the effects of changes in multi‐phase seepage parameters on HBS productivity.

Molecular simulation of the dynamic distribution of complex oil components in shale nanopores during CO2-EOR

Due to the high clay content of shale reservoirs, developing shale oil by water flooding is difficult. CO2 is easier to inject into formations than water, significantly increasing shale oil production by reducing the viscosity of shale oil and increasing the gas-oil ratio. Moreover, CO2 flooding can also effectively reduce emissions. However, CO2 flooding changes the formation fluid's phase behavior and composition. This causes the fluid to redistribute in the nanopore. Based on the field data, it can be seen that the changes of formation fluid components are obvious in the three stages of CO2 injection, the initial state of production and depressurization production. Therefore, this paper uses the molecular dynamics method to study the changes in adsorption layer thickness, adsorption ratio of components, interaction energy, and self-diffusion coefficient of fluids in organic and inorganic pores under these three stages. The results show that the adsorption layer thickness gradually increases during CO2 flooding. After CO2 injection, the fluid components in kerogen are significantly desorbed. The desorption of the components in the small pore size of illite, feldspar, and calcite is insignificant; the desorption of the components in the large pore size is significant, and the desorption of the components in quartz is insignificant. The interaction energy between fluid and pores decreases first and then increases during CO2 flooding, and the types of interaction energy between pores and fluids differ. The results show that CO2 injection can increase shale oil production. New ways to enhance oil recovery are needed to increase shale oil production in the later stage of depressurization production.

Unraveling the complex pressure propagation of two-time depressurization production in Shenhu hydrate reservoir: Insights for long-term exploitation

Depressurization serves as the primary method for exploiting marine hydrate reservoirs, and understanding the long-term pressure propagation efficiency and identifying the potential limiting factors are crucial for enhancing and optimizing this approach. In this study, we employed numerical modeling to simulate two-time depressurization exploitation in the Shenhu hydrate reservoir, aiming to predict the long-term gas production and pressure propagation efficiency under various depressurization schemes. Our simulation results indicate: 1) The pressure propagates rapidly near the wellhead and gradually decelerates with distance due to the impeding influence of the reservoir's low intrinsic permeability and groundwater seepage in the covering strata. 2) Pressure propagation in single-well systems exhibits substantial variation among sublayers, resulting in limited areas of hydrate dissociation. Long-term gas production depends on the hydrate dissociation. Consequently, the total 5-year gas production for single-vertical-well and single-horizontal-well systems are only 3.59 × 106 m3 and 5.04 × 106 m3, respectively. 3) Multi-horizontal-well systems can significantly extend pressure propagation, but the maximum increase in gas production is only 47.0%. This is due to the reservoir's low permeability (2.3 mD), which severely hampers hydrate dissociation pressure, limiting it to 8 MPa. Therefore, optimizing depressurization requires reservoir modifications to enhance reservoir permeability.

Enhancing shale gas recovery by carbon dioxide injection: A method of carbon capture, utilization and storage (CCUS)

CO2 injection in shale gas reservoir can not only increase the production of shale gas, but also realize carbon dioxide capture, utilization and storage. At present, most experimental studies of CO2 injection in shale are carried out by conventional core experiments. However, it is difficult to analyze the process of CO2 replacing shale gas and adsorption in shale pores on microscopic scale. In this study, nuclear magnetic resonance (NMR) technology is used to analyze the migration and conversion of CH4 in process of CO2 injection and depressurization production. Based on above experiments, microscopic mechanism of competitive adsorption of CH4 and CO2 during CO2 injection is clarified, and the stimulation mechanism of CO2 injection to improve shale gas recovery is further proposed. The results show that CH4 preferentially exists in form of adsorption state in shale. When CH4 adsorption amount reaches a certain degree, CH4 gas in form of free state gradually appears. During depressurization stage, further depressurization failed to promote the desorption of adsorbed gas when pressure reduced to 3 MPa. Therefore, adsorbed CH4 gas still exists after depressurization production. Shale has stronger adsorption capacity for CO2 than CH4. CO2 can replace CH4 adsorbed on the pore surface, and promote the desorption of adsorbed CH4 gas to free state. CO2 has the best displacement effect on adsorbed CH4 in pores with diameter of 15.04–21.62 nm, but it fails to replace CH4 in pores with diameter less than 1.08 nm. The competitive adsorption of CO2 and CH4 can effectively promote the further desorption of residual adsorbed CH4 gas after depressurization, and significantly improve the cumulative shale gas production.

Study of CO2 injection to enhance gas hydrate production in multilateral wells

Multilateral wells offer promising opportunities for the commercial development of natural gas hydrates. The reservoir strength and stiffness weaken as hydrates decompose during the depressurization production process, potentially leading to formation subsidence, seabed inclination, and other associated geomechanical risks. Thus, understanding the geomechanical issues surrounding the wellbore is crucial for attaining safe and efficient hydrate development. This paper develops a three-dimensional numerical model to simulate the production capacity of hydrate reservoirs through CO2 injection in multilateral wells. The study compares the pressure and temperature response of the reservoir, the characteristics of gas and water production, the variation in hydrate and methane saturation, the productivity, and the geological subsidence patterns during the extraction process. Results indicate that hydrates generated through CO2 injection inhibit methane hydrate decomposition, with delayed injections resulting in higher cumulative yields. CO2 injection can restore reservoir pressure and mitigate formation subsidence. The combined depressurization method, which involves CO2 injection in multilateral wells, can increase hydrate production while preserving formation stability, offering a potential approach for commercial hydrate exploitation. This approach is anticipated to advance the industrialization of gas hydrate extraction and propose a new possibility for CO2 utilization to curb climate change.

Production Behavior of Hydrate-Bearing Sediments with Mixed Fracture- and Pore-Filling Hydrates

Most hydrate-bearing sediments worldwide exhibit mixed pore- and fracture-filling hydrates. Due to the high exploitation value, pore-filling hydrate production is the focus of current hydrate production research, and there is a lack of systematic research on the decomposition of fracture-filling hydrates and their effects on the evolution of temperature and pressure in hydrate-bearing sediments. If only the decomposition characteristics of pore-filling hydrates are studied while the fracture-filling hydrates decomposition and its effects on the hydrate-bearing sediments production process are ignored, the obtained research results would be inconsistent with the actual situation. Therefore, in this study, the effects of fracture-filling hydrates with different dipping angles on the hydrate production process were studied, and the necessity of considering the phenomenon of mixed pore- and fracture-filling hydrates in hydrate-bearing sediments was illustrated. On this basis, the simulation of a typical site (GMGS2-16) with mixed pore- and fracture-filling hydrates was constructed, and the production process was researched and optimized. The results indicated that: (a) fracture-filling hydrates formed in shallow fine-grained sediments and gradually approached the area of pore-filling hydrates, before a stable mixed zone was formed; (b) the occurrence of fracture-filling hydrates was conducive to the hydrate-bearing sediment depressurization production, and the promoting effect of the fracture-filling hydrate with smaller dipping angles was stronger; and (c) depressurization combined with heat injection could effectively compensate for the local low temperature and secondary hydrate caused by the mass decomposition of fracture-filled hydrates.