Natural Gas Hydrate Reservoirs Research Articles

Time-dependent deformation of marine gas hydrate-bearing strata conditioned to a wellbore: Experiments and implications

Natural gas hydrate (NGH) is a promising alternative energy resource, whereas marine NGH exploitation suffers from various potential geo-environmental concerns. The existence of a production wellbore not only provides channel for gas extraction, but also causes specific boundary conditions for the occurrence of geo-environmental risks. Almost all kinds of geo-environmental risks during NGH production initiate from time-dependent deformation of the near-wellbore strata. In this paper, the pressuremeter test (PMT) method was firstly introduced to investigate the lateral creep behaviors of the NGH-bearing sediment. The PMT probe was used to apply outwards lateral stress onto the hydrate-bearing sediment to simulate the horizontal stress state of the near-wellbore reservoir during drilling, completion, and/or hydraulic fracturing, during which the pressure inside the wellbore is higher than the reservoirs static pressure. The results indicated that the decelerated creep accounts for more than 70% of the lateral strain before the effective stress reaches the long-term strength. The hardening modulus of the sediment was proven to be increased from the magnitude of ∼102 MPa–∼103 MPa, when the hydrate saturation increases from 2.2% to 50.0%. The PMT creep test results can be used for interpretation of the in-situ horizontal stress and geomechanical parameters such as pro-plastic pressure and ultimate pressure. Based on the fact that PMT test results complies with the previous results from other techniques, a field-applicable PMT technique for NGH reservoir test is suggested to be developed in future study, and a systematic hypothesis and workflow for NGH reservoir modelling is also proposed in this study.

Effect of particle size distribution variability on the permeability of hydrate-bearing sediments: A CFD study

Natural gas hydrates (NGH) are considered as a future clean energy in the era of carbon neutrality. The seepage behaviour of hydrate-bearing sediment (HBS) and its controlling factors are significant for developing effective production strategies. In this study, we aim to elucidate how the heterogeneous spatial distribution of clayey-silty sediment particles, particularly the non-uniform particle size distribution (PSD) affects the permeability of HBS. An algorithm was developed to generate the heterogeneous spatial distribution of sediment particles based on the PSD of hydrate-bearing cores extracted from Japan Nankai Trough (D50 = 122 μm). A series simulation of fluid flow in porous media based on CFD was conducted for the HBS with varying hydrate saturations (SH). The watershed segmentation algorithm was employed for the identification of pore structure, including pore space and pore throat with a detailed analysis on the pore structure evolution with SH. Host sediments with higher uniformity result in initial high permeability but the permeability reduction with increasing SH is more significant compared with that of lower uniformity. Pore throat width reduced to less than 5 μm with SH above 50% compared with its original width of ∼30 μm. Tortuosity exhibits a linear increase with SH, while permeability decreases exponentially with increasing tortuosity. We propose an improved permeability model (KCpro) based on the classical Kozeny-Carman model accounting for the change in specific surface area for non-uniform PSD in HBS with good agreement. This study confirmed the applicability of CFD modelling as a promising tool to study the seepage behaviour of HBS complementary to classical permeability experimental tests. Results of this study provide fundamental understanding on how permeability evolves in HBS with significant PSD variations in natural gas hydrate reservoirs in nature.

Development and application of low-melting-point microencapsulated phase change materials for enhanced thermal stability in cementing natural gas hydrate layers

In the exploration of deep-water oil and gas resources, encountering natural gas hydrate (NGH) layers poses significant challenges, particularly during cementing operations critical for wellbore stabilization. This study proposes a strategy employing cement slurries integrated with micro-encapsulated phase change materials (MPCMs) to address the destabilization of NGH layers, a key obstacle in deep-water cementing. MPCMs containing BaCO3 shell and low-melting binary PCMs in the core were synthesized by the self-assembly method. The structure and thermal properties of MPCMs were thoroughly characterized. MPCMs exhibited a distinct core-shell structure with a hydrophilic and well-sealed shell. Their phase change temperatures were in closely matched the temperatures found in NGH formations, at 3.5 °C and 13.9 °C. A comprehensive evaluation of the fundamental properties of cement slurries containing MPCMs (CSM) was conducted, including thermal stability, setting time, pore structure, and mechanical strength. Additionally, a laboratory device was employed to simulate cementing operations, allowing for intuitive analysis of the impact of hydration heat evolution on NGH stability—a notably underexplored aspect in related literature. The results demonstrated that MPCMs effectively reduced the hydration heat generated by cement slurry within the initial 36 h. Specifically, at a 9% MPCMs dosage, the hydration heat of CSM decreased by 19.0%, resulting in the sustained stability of NGH. In contrast, the control group's cementing process directly led to the complete decomposition of NGH. Even at lower MPCMs concentrations, the decomposed NGH was more likely to recrystallize and return to a stable state due to the slower hydration heat release rate of CSM. This study not only provides evidence of the effectiveness of MPCMs as heat inhibitors in reducing the disruption of hydrate stability during well cementing but also provides theoretical guidance for the design and application of cement slurries for NGH reservoirs. By enhancing the stability of NGH layers, this work supports the safe and efficient exploitation of undersea hydrocarbon resources, contributing to shaping future global energy strategies.

Investigation of creep and transport mechanisms of CO2 fracturing within natural gas hydrates

Natural gas hydrates (NGH) are considered as a potential energy resource in the future because of its dramatic energy reserves. NGH formation owns the characteristic of viscoelasticity, to some extent behaves both like liquid and solid. Ignoring the viscoelastic properties of NGH can lead to inaccurate prediction of related characteristics. In 2020, horizontal-well drilling technology was adopted to improve the stimulation performance of NGH reservoirs in the Shenhu area of China. This indicates that it is possible to apply hydraulic fracturing or CO2 fracturing in the reservoir reconstruction of NGH. CO2 fracturing can generate more fracture networks and connect micro fractures. Additionally, CO2 can be stored geologically and integrated with injection, production, and storage. This study provides a relatively detailed demonstration of the formation and basic mechanical properties of NGH. Then, a comprehensive overview of potential NGH production enhancement methods is conducted. Finally, an evaluation method for dual conductivity considering creep effect is proposed, and the results show that the creep effect of NGH can reduce the conductivity of fractures and matrices. Thus, it is of great importance to investigate the viscoelastic properties of NGH formation, for the long-term prediction of the geo-mechanical response to gas extraction.

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.

Exploration of production capacity-geomechanical evaluation and CO2 reinjection repair strategy in natural gas hydrate production by multilateral horizontal wells

Multilateral horizontal wells (MHW) can enhance gas production by expanding the natural gas hydrate (NGH) decomposition area, but inevitably leading to larger changes in reservoir pressure and rock stresses, causing subsidence or disasters. Therefore, this study established a THMC model that evaluated the production effect and geomechanical response of MHW in Class-I reservoirs with different permeability and proposed a CO2 reinjection repair strategy to achieve subsidence recovery and carbon storage. Results indicate that MHW with vertical branch arrangements performs best in short-term production for low-permeability reservoirs, while the temperature and pressure evolution in high-permeability reservoirs is more drastic than in low-permeability reservoirs, producing many unfavorable factors. Higher capacity also results in larger strata subsidence and stress changes, affecting the reservoir stability and wellbore safety: (i) subsidence occurs mainly in the NGH sediment and the upper zone of the wellbore; (ii) normal stresses around the wellbore increase most significantly in the vertical direction, while shear stresses generally decrease. The repair indicators of subsidence recovery rate, energy recovery rate, and hydrate conversion rate suggest that reinjecting CO2 into depleted NGH reservoirs can improve the mechanical properties of the strata and achieve carbon storage via the hydrate method as well.

An environmental-benign method to enhance hydrate production in clayey silty reservoir via splitting grouting

During the pivotal period of energy transition between carbon neutrality and carbon peaking, it is crucial to develop the natural gas hydrate (NGH) due to the advantages of high energy density and non-pollution. However, the NGH production also faces several significant environmental challenges that need to be addressed such as seawater intrusion, methane leakage, and submarine landslides. Therefore, an environmental-benign method to enhance hydrate production in clayey silty reservoir via splitting grouting was introduced. As a novel method for achieving the two goals of both reservoir skeleton reinforcement and permeability enhancement, is proposed to stimulate NGH reservoir. Herein, the formulation based on foamed ultrafine cement-based grout was established. The results showed that the grout has good fluidity with initial viscosity ∼500 mPa·s and consolidation time in the range of 28–50 min. Meanwhile, the consolidation performance evaluation was studied, and it showed that the consolidation is with porosity in the range of 9.41%–46.59%, permeability in the range of 51.23 mD-789.07 mD, and compressive strength in the range of 3.31 MPa–3.88 MPa. The internal pore channels are uniformly distributed with a large number of stomatal strings, which can be used as a multistage seepage channel for gas and water production from hydrate decomposition. To further examine the stimulating behavior, the effect of hydrate saturation, grouting well diameter, grouting flow rate, and in-situ stress on splitting pressure and grouting volume were analyzed, and it was found that the grout has good ability to split fracturing and grout diffusion under the conditions of axial pressure of 5 MPa, confining pressure of 4 MPa, and hydrate saturation not more than 0.30. In addition, an environmental-benign high-efficient reservoir stimulation method on a laboratory scale was proposed. The findings could provide fundamental insights and recommendations for the implementation of splitting grouting in NGH reservoirs.

Pore-scale water–gas distribution and gas permeability of natural gas hydrate reservoirs in the South China Sea

Challenges in water drainage within natural gas hydrate reservoirs in the Shenhu area of the South China Sea, characterized by high clay content and strong hydrophilicity, significantly hinder natural gas recovery. Examining the effects of gas pressure and liquid/gas saturation on gas permeability reveals essential insights for increasing gas production potential. We report gas displacement experiments on clayey-silt sediment samples, alongside X-ray computed tomography imaging, that reveal critical findings: a notable increase in flow rate and permeability as displacement pressure nears compaction pressure, highlighting the role of pressure management in enhancing recovery; water displacement from varying pore sizes under different pressures, highlighting the influence of pore size on fluid dynamics, and structural changes, including microfracture formation and a significant fracture that enlarges total pore space by about 15%, which collectively suggest methods to improve gas flow and recovery. Moreover, our analysis identifies average throat length, fractal dimension, and succolarity as principal controls on gas permeability, indicating the substantial impact of microstructural properties on extraction efficiency. These outcomes offer valuable strategies for optimizing natural gas hydrate reservoir development in the South China Sea, emphasizing the need for meticulous pressure and saturation control and in applying a deep understanding of microstructural dynamics.

Research on productivity of stimulated natural gas hydrate reservoir

Natural gas hydrate (NGH) is a prospective clean energy. Conventional development method of the NGH reservoir by pressure drop in vertical well faces the problems of limited stimulated reservoir volume, low production efficiency, and low conductivity. At present, pressure drop production in various well types and stimulation treatments such as hydraulic fracturing in fracable NGH reservoirs have become the focus. The effects of pressure drop production in vertical well, horizontal well, radial wells, and hydraulic fracturing in vertical and horizontal wells in NGH reservoirs were simulated with HydrateResSim. We simulated the productivity of NGH reservoir for 1000 days with several types of development mode. The productivity is highest in horizontal well staged fracturing (5 stages), followed by pressure drop production in horizontal well, fractured vertical well (single fracture), and radial well (16 holes). The worst effect is obtained through production by pressure drop in single vertical well. The optimal effects were obtained with the fracture spacing of 58 m, the fracture half-length of 100 m and the conductivity of 30 μm2 cm. The horizontal well multi-cluster fracturing significantly enlarges the stimulated area and provides channels for gas migration and enhances productivity.

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.

Development of a dual-functional inhibitor for natural gas hydrates and construction of drilling fluid system

Throughout the 21st century, natural gas hydrates have emerged as a pivotal and promising clean energy resource with immense potential for commercial development. However, during shallow-water gas hydrate drilling in deep-sea areas, heat and mass transfer between the drilling fluid and the natural gas hydrate reservoir result in hydrate dissociation. As a result, the reservoir strength is weakened, wellbore instability occurs, and there is a high risk of well collapse. Additionally, the formation of secondary hydrates can cause blockages in drilling tools or pipelines, compromising drilling safety. In this study, acrylamide and dimethyl diallyl ammonium chloride were used as raw materials to successfully develop a dual-effect hydrate inhibitor named ADP. The results showed that a 1% ADP concentration increased the inhibition efficiency of hydrate dissociation by approximately 21.13%. Furthermore, core immersion and linear expansion experiments using a 1% ADP solution showed that after 24 h, the core maintained its structural integrity without experiencing collapse, and the linear expansion rate decreased to 1.5%. Building upon the HEM system, this research employed the developed dual-effect hydrate inhibitor as the core component and further optimized density, rheology, filtration loss, hydration expansion inhibition, and hydrate inhibition properties to construct a high-performance water-based drilling fluid system for strong hydrate inhibition. Performance evaluation of the HTX system demonstrated excellent rheological filtration, lubrication, plugging, hydration expansion inhibition, and hydrate inhibition properties. Additionally, predictive models for drilling fluid rheological parameters under different temperature conditions were established. The research outcomes presented in this paper hold significant practical value in addressing the wellbore stability issues encountered during the drilling process of gas hydrate reservoirs in deep-sea areas.

Development of a novel suction cylinder exploitation device for marine natural gas hydrate and the feasibility studies

Natural gas hydrate (NGH), a novel clean energy with enormous potential, has drawn the attention of many countries for research and development. In recent years, exploitation theories and technical capabilities have advanced quickly. However, commercial production, in terms of current exploitation equipment and tried tests, is still challenging to implement. In this paper, a novel suction cylinder exploitation device (SCED) was proposed based on marine NGH depressurization exploitation technology and suction anchor to replace conventional wellbore. The SCED is a prefabricated steel construction that enters the NGH reservoir by suction and gravity and has the potential to be recycled after exploitation. Through indoor experiments, the SCED penetration mechanisms and characteristics were investigated to confirm whether it can smoothly penetrate the NGH reservoir. Simultaneously, the gas production situation of the SCED was explored by CMG software. Results show that: (i) the super sizeable length-to-diameter ratio SCED model can complete the penetration from the experimental results. Although the “soil plug” height increases with the increase of the length-diameter ratio, it can be solved by taking appropriate methods for specific engineering; (ii) Due to the larger diameter and higher strength of the SCED, it can achieve greater pressure reduction and exploitation range, making the efficiency of gas production roughly 5.7–11.77 times greater than that of a conventional wellbore. In summary, it is anticipated that the SCED will open up new opportunities for the early commercial exploitation of marine NGH due to its advanced advantages of high equipment strength, big exploitation diameter, and easy construction.

Sustained production of gas hydrate through hybrid depressurization scheme with enhanced energy efficiency and mitigated ice blockage

Several trial productions have been conducted on marine natural gas hydrate reservoirs, demonstrating its enormous potential as an alternative energy source. Nonetheless, sustained and efficient production still remains challenging, with crucial issues on low gas production efficiency and blockages. The large amount of hydrate decomposition and resulting heat absorption can lead to prolonged subzero conditions close to the well; this can readily induce ice formation and blockage. This study aims to investigate the issue of ice blockages caused by insufficient energy supply during the recovery process. A systematic analysis of the energy consumption and ice blockage quantification at each stage of the traditional multi-stage direct depressurization and constant speed depressurization methods is conducted. A hybrid optimized scheme is proposed, which enhances energy utilization efficiency by appropriately utilizing reservoir sensible heat during the initial stage of production. Additionally, a multi-stage constant speed depressurization method is introduced in the later stages to mitigate production fluctuations and reduce blockage duration. Results showed a 69.5 % increase in energy efficiency and an average 67.1 % decline in gas blockage duration with comparable gas productivity. The proposed method could be a viable solution to mitigate challenges of icing blockages and fluctuating production during trial tests of marine hydrate reservoirs, achieving improved energy efficiency and sustainable production.

Numerical simulation on gas production from hydrate-bearing sediments by depressurization considering time-varying reservoir compressibility

Depressurization is a promising Natural Gas Hydrate (NGH) recovery method. However, the pressure drop can cause significant pore compression, particularly in clayey-silty reservoirs. Additionally, the decomposition of NGH will further weaken the reservoir strength, leading to the time-varying characteristics of reservoir compressibility. This study analyzed depressurization-based gas production under different NGH reservoir models and accounted for time-varying reservoir compressibility. The results showed that the increased reservoir compressibility caused by hydrate decomposition significantly affected the pressure propagation and permeability evolution, further diminishing gas production. The cumulative gas production from sandy reservoirs with lower reservoir compressibility could reach 60 times that from clayey-silty reservoirs with higher reservoir compressibility. The optimal bottom-hole pressure (BHP) gradually increased with the reservoir compressibility. For the reservoir with the higher compressibility, the cumulative gas production at a BHP of 3 MPa was 58% lower than at 9 MPa. Therefore, considering time-varying reservoir compressibility during hydrate decomposition is essential for accurately forecasting the gas production capacity of depressurization. Furthermore, BHP should be cautiously determined in reservoirs with higher reservoir compressibility.

A comprehensive study of fines migration in internally unstable natural gas hydrate reservoirs

Evaluating unconsolidated reservoirs' internal stability concerning fine migration is essential for the commercial development of natural gas hydrate resources. In this pursuit, we use our newly developed visualized sand production cell and validated CFD-DEM model to study the fines migration dynamics in unconsolidated reservoirs. Our approach leveraged the novel Analysis Software for the Internal Stability of Granular Soils (ASISGS), equipped with three distinct criteria. Experimental observations revealed reservoirs with smaller fine particles experience intensified sand production, characterized by extended production durations and a heightened presence of fine particles in the produced sand. The fine particles move faster than the coarse ones. The ‘coarse matrix with floating fines’ is a premise for fines migration. The flow channel severely clogged by fine particles may reopen, leading to erosive bursts. Kezdi law and the Kenney and Lau criterion in ASISGS software successfully assessed reservoirs' internal stability, consistent with our experimental results. However, the Sherard criterion sometimes overestimated the reservoir's internal stability. Rather than a binary distinction, our research posits a continuum between internally stable and unstable reservoirs. From a CFD-DEM perspective, we discerned two predominant failure modes leading to sand production: erosion of fines and destabilization of the primary sand arch subsequently triggering a sand skeleton reorganization. The smaller the fine particle size, the slower the coordination number increase, the lower the coordination number the platform reach, and the more significant the fine particle migration. With the hydrodynamic drag force exerted by the fluid, fine particles move faster and farther than coarse particles. The formation process of the sand arch includes initial, migration, and equilibrium stages. Overall, this study offers valuable insights into fines migration and its impact on sand production, providing a foundation for effective sand management in natural gas hydrate reservoirs.

Methane replacement into hydrate reservoirs with carbon dioxide: Main limiting factors and influence of the gaseous phase composition, over hydrates, on the process

Replacement processes are probably the most attractive methodologies for methane recovery from natural gas hydrate reservoirs. The injection of replacing guest species enhances the recovery of methane and, at the same time, strengthens the hosting sediments and allows to permanently store carbon dioxide is solid structures. Unfortunately, the process is still far from the industrial maturity and its field application is limited. This study deals with a critical discussion about the main influencing factors of replacement; in detail: heat and mass transfer limitations; extension of the thermodynamic region available for replacement; maximum ideal efficiency achievable and role of composition of the gas phase present in the replacement region. This latter aspect is then experimentally investigated and its effect on the quantities of, respectively, methane recovered and carbon dioxide stored, together with the whole amount of hydrate structures (preserved or re-formed) is quantified in detail. Within the selected range of CO2/CH4 compositions for the replacing phase (CO2 content higher than 65 vol%), the percentage of methane recovered gradually diminished: it passed from 84.14%, related to the initial gas composition equal to 67.55–32.41 vol%, to 21.54%, corresponding to 91.83–8.17 vol% CO2/CH4. The maximum quantity of CO2 stored into hydrates via replacement (thus not through formation of new hydrate structures) was reached at 67.55–32.41 vol% CO2/CH4 and was equal to 70.40%, proving that the presence of methane in the replacing gaseous phase plays a key role during replacement processes.

Study on microwave heating energy supplement technology for gas hydrate reservoir

This study proposes a microwave heating energy supplement technology for gas hydrate reservoir. The microwave radiation simulation model of the leaky coaxial antenna is established by HFSS. Based on the simulation results of microwave antenna structure parameters on the radiation performance, the optimized shape, angle, length, width and fillet of the slot are rectangle, 80°, 38 mm, 12 mm and 2 mm, respectively. To compare the heating performance of microwave antenna before and after optimization, a microwave heating simulation model for hydrate reservoir is developed, which is validated by experimental results. The comparison results illustrate that, after microwave heating 10 h with the optimized antenna structure, the average temperature within a 1-m radius of natural gas hydrate reservoir increases to 10.613 °C, which is about 5.5 °C higher than that before the optimization. The aforementioned results suggest that the optimized microwave antenna structure significantly increases the temperature of the hydrate reservoir, providing the necessary energy to drive hydrate decomposition. The proposed microwave energy supplementation technique holds promise for advancing the efficient development of natural gas hydrates, the further investigation of effect of which on gas production within hydrate reservoirs is needed for future application.

Numerical Investigation on Mesoscale Evolution of Hydraulic Fractures in Hydrate-Bearing Sediments

Hydraulic fracturing is widely recognized as a potential stimulation technology for the development of challenging natural gas hydrate. However, the fracturing behavior of non-diagenetic hydrate reservoirs has peculiar characteristics that are different from those of conventional oil and gas reservoirs. Herein, a fully coupled fluid-mechanical model for simulating hydraulic fracturing in hydrate-bearing sediments (HBS) was established based on the discrete element method, and the influence of hydrate saturation, in situ stress, and injection rate on the meso-fracture evolution was investigated. The results indicate that with the increase in hydrate saturation, the fracture morphology transitions from bi-wing to multi-branch, thereby enhancing fracture complexity. Both tensile and shear failure modes exist, and the tensile failure between the weakly cemented sediment particles is dominant. The tensile strength of HBS is an exponential function of hydrate saturation, with the breakdown pressure being governed by hydrate saturation and in situ stress, with the form being consistent with the classical Kirsch equation. Additionally, lower in situ stress and higher injection rates are conducive to the generation of microcracks, whereas an excessive injection rate reduces the fracture length. These findings contribute to understanding the meso-evolution mechanism of hydraulic fractures and guide the design of on-site hydraulic fracturing plans of natural gas hydrate reservoirs.

Numerical investigation of production characteristics and interlayer interference during co-production of natural gas hydrate and shallow gas reservoir

The coexistent system of natural gas hydrate and shallow gas (NGH-SG) enhances stability compared to single resource reservoirs, rendering it a promising target for co-production and commercial exploitation. In this study, we established a reservoir model of the NGH-SG system based on actual geological conditions. Subsequently, a long-term production simulation was performed to contrast the production behaviors of three exploitation methods: co-production of NGH-SG (CP), single production of hydrate-bearing layer (SP-HBL), and single production of shallow gas layer (SP-SGL). The study revealed that the presence of free gas in SGL can significantly increase the overall gas production capacity, with SGL contributing over 85% of the total gas production during the entire co-production period. On the 5000th day, the cumulative gas production of CP exceeded that of SP-SGL by 1.07 times and surpassed SP-HBL by 9.60 times. Furthermore, the study extensively investigated the impact of interlayer permeability on production behaviors. Lower interlayer permeability was found to be more conducive to releasing the natural gas production capacity from the reservoir. Notably, the phenomenon of interlayer interference should be carefully considered during CP. The influence degree of interlayer interference during CP becomes increasingly pronounced with increasing interlayer permeability. Fundamental contributors to interlayer interference encompass heat transfer, pressure diffusion, and interlayer cross-flow. As interlayer permeability rises, mass transfer between the layers intensifies, thus promoting pressure diffusion. Interlayer pressure difference and permeability are critical factors that affect interlayer cross-flow. For NGH-SG reservoirs with higher interlayer permeability, the advantages of CP are more obvious during the early production period. The implementation of the findings of this study may improve production efficiency and contribute to the development of effective management strategies for offshore NGH-SG reservoirs.

Influence of key geological factors on fluid production behaviors in marine natural gas hydrate reservoirs: A case study

Accurate geological model of hydrate reservoir is the prerequisite of obtaining the credible prediction results. Not only stress sensitivity and anisotropy of permeability but also non-uniformity in hydrate saturation and permeability distribution are key geological factors influencing fluid production behaviors. However, they have been overlooked to some extent in previous numerical simulations. To highlight the significance of these factors, this study develops a robust production model at site AT1 based on geological data and laboratory tests. Then we systematically investigate the effects of the aforementioned factors on production performance. The simulation results exhibit that all the factors have notable impacts on fluid production behaviors, especially the non-uniform hydrate saturation and permeability distributions. Ignoring the permeability stress sensitivity and adopting the homogeneous simplification of hydrate saturation may overestimate gas and water production. Besides, various characterization methods of reservoir permeability can give rise to the significantly different production behaviors for heterogeneous hydrate reservoirs. The stronger the reservoir permeability anisotropy, the better the production performance. In order to achieve the reliable predictions, the geological model built should properly incorporate these factors during numerical modeling. These findings provide valuable guidance for constructing robust models and optimizing production strategies for natural gas hydrate reservoirs.