Natural Gas Hydrate Reservoirs Research Articles

Experimental Study on Mechanical Properties of Artificial Cores Saturated With Ice: An Analogical Simulation to Natural Gas Hydrate Bearing Sediments

ABSTRACTThis work takes the natural gas hydrate (NGH) reservoir in the Shenhu area at the South China Sea as the target. Using the quartz sand, calcite grains, and illite powder as the main mineral composites, and Portland cement as the bonding material, the host skeleton with similar porosity and mechanical properties to the target reservoir were prepared. Ice was used to simulate natural gas hydrates for their high similarity in mechanical properties and distributions within porous host. The ice saturation in the host skeleton is quantitatively controlled by the quality method. As an analogical simulation, artificial samples with different ice saturations were tested by uniaxial compression measurements and the Brazilian tensile tests, aiming to reveal the mechanical behavior of NGH sediments. The results indicated that the plasticity of the artificial sample increases and its damage form transitions from brittleness to ductility as the ice saturation increases. The effects of free water and ice on the strength of saturated samples are quite different. The free water tends to reduce the strength of the sample due to illite hydration and change of internal friction. The bonding effect of ice tends to increase the strength of the sample, while the ice could also reduce the internal friction. When the ice saturation is larger than 30%, the compressive and tensile strengths of the sample increase with ice saturation, which could be regressed as yc = 2.2628S + 0.8322, and yt = 0.411S + 0.0273, respectively. The constitutive model was developed based on the equivalent medium theory and the D‐P criterion, which could describe the experiment data well with deviations less than 10%.

A Nonaxial-Type Swirling Cavitating Nozzle for Exploiting Natural Gas Hydrate

Summary Natural gas hydrates (NGHs) have garnered widespread attention in the new energy sector, owing to their efficient and clean combustion properties. NGHs are ice-like substances formed by methane and water under high-pressure and low-temperature conditions, abundantly deposited in seabeds and frozen soil of highlands on Earth. However, the rock shelves of NGH reservoirs are mostly fragile and sparsely colloidal. Traditional mechanical mining methods can easily cause rock-shelf collapses, leading to mining accidents. Long-term indoor experiments and pilot mining projects have shown that cavitating nozzles can provide a feasible solution to the problem of efficient mining of NGHs. To further improve the efficiency of cavitating nozzle mining for NGHs, we have optimized and designed a nonaxial-type swirling cavitating nozzle (NASCN) based on traditional swirling cavitating nozzles (SCNs). Both numerical simulations and indoor experiments have verified the higher mining performance of this nozzle. In the numerical simulation experiments, we analyzed the cavitation performance, erosion performance, and energy consumption characteristics of different cavitating nozzles using the mixture multiphase flow model and the renormalization group (RNG) k-ε turbulence model. In the indoor experiments, we utilized a jet erosion experimental device for NGHs to analyze the erosion effects of different cavitating nozzles on hydrate samples. The results of these experiments indicate that the NASCN reduces energy consumption by 12% compared with traditional nozzles when there is little difference in cavitation performance and erosion performance. Moreover, under similar energy consumption, the NASCN improves erosion efficiency by 35.2% compared with traditional nozzles. These results demonstrate that the NASCN has good application value in the mining engineering of NGHs.

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.

The role of phase saturation in depressurization and CO2 storage in natural gas hydrate reservoirs: Insights from a pilot-scale study

The natural gas recovery and CO2 storage in natural gas hydrate (NGH) reservoirs is a promising integrated strategy for implementing clean energy production and CCUS. However, the fundamental characteristics (phase saturation) of NGH reservoirs on the feasibility and efficiency of the above-integrated processes remain unclear. In this study, we synthesized methane hydrate-bearing sediments (MHBS) with varying hydrate saturation (SH = 18–66 %) and aqueous saturation (SA = 7–92 %) at marine NGH conditions (T = 283.8 K, P = 11.0 MPa). The effect of phase saturation on depressurization-induced hydrate dissociation, and subsequent CO2 storage and hydrate restoration by CO2/N2 injection was investigated. The water-saturated MHBS with high SA can promote faster MH dissociation during the depressurization stage and prevent secondary hydrate formation, but a slower MH dissociation during the later stage due to slow heat transfer. A relatively high SH (> 63 %) results in sustained low temperatures due to insufficient heat supply slowing down MH dissociation. The CH4/CO2/N2 mixed hydrates (Mix-H) formation and CO2 storage in depleted MHBS after CO2/N2 injection initially increase and then decrease with post-mining SA (peak at SA = 54.5 %). The rate of Mix-H formation decreases as the post-mining SA increases. Higher pre-mining SH and CO2/N2 injection rate facilitates rapid gas phase mixing within the sediments, thereby improving the kinetics and homogeneity of Mix-H formation and hydrate-based CO2 storage efficiency. MHBS with relatively low SH and SA exhibit enhanced safety for the integrated process, offering reduced depressurization-induced sediment subsidence and increased hydrate restoration ratios (∼85 %) by Mix-H formation.

Borehole Stability of Natural Gas Hydrate Reservoirs

Abstract The decomposition of natural gas hydrate (NGH) due to long-term drilling may decrease the strength of reservoirs and increase the borehole failure risk. Meanwhile, the creep properties of NGH reservoirs also may give rise to engineering problems including borehole shrinkage and jamming of drilling tools in the late stage of drilling, which seriously impairs the drilling safety. A thermal-fluid-solid multi-field coupling model considering the decomposition kinetics of NGH and creep properties of reservoirs was established to explore the influence mechanism of NGH decomposition and creep properties of hydrate-bearing sediments on mechanical behaviors of boreholes. In addition, influences of drilling parameters and geomechanical properties of reservoirs on borehole stability in the drilling process of NGH reservoirs were analyzed. Research results show that creep properties of NGH deposits causes homogenization of stress distribution in different directions of NGH reservoirs around boreholes, transition of plastic zones around boreholes to a round shape, and possibly overall borehole collapse. As the horizontal geostress becomes more inhomogeneous, the borehole instability risk increases; the higher the initial pore pressure of formation is, the lower the effective geostress and the lower the borehole instability risk. The research results can provide theoretical support for safe drilling of NGH reservoirs in South China Sea and promote the early commercial exploitation of NGH resources in China.

Study on the Influence of Structural Parameters of Microwave Heating Device on the Heating Effect of Natural Gas Hydrate Reservoir

Abstract The investigation into microwave heating technology for enhancing gas production from hydrate reservoir has attracted wide attention. However, the initial microwave heating device structure still has limitations of low average temperature and uneven temperature distribution in the reservoir during microwave heating. This study has established the microwave heating simulation model, which is validated by the reservoir microwave heating experiment results. Based on the simulation results of microwave heating model, the optimized structure parameters of microwave heating device are obtained: the slots distribution method is cross-distribution, the slot shape is rectangle, the slot angle is 75°, and the slot length is 30 mm. Following microwave heating with the optimized structure for 10 hours, the average temperature within the 1-meter radius of the reservoir rises from 2 °C to 9.52 °C, the maximum temperature in the reservoir is 58.21 °C, and the temperature standard deviation is 9.15 °C. The results mentioned above indicate that the optimized structure can well increase the temperature in the gas hydrate reservoir and the temperature distribution is uniform. This study will further promote the application of microwave heating technology in the actual exploitation of natural gas hydrate.

Experimental study on acidizing of natural gas hydrate reservoirs

Abstract Natural gas hydrates (NGH) are a promising resource. Due to the weak cementation of hydrate reservoirs, the reservoirs are prone to sand production or destabilization during hydrate dissociation. Samples of hydrate sediments were manually prepared, consolidated using a cementing agent, and then subjected to flow experiments using an acid solution. Comparative experiments were also conducted with unconsolidated samples. The consolidation samples could maintain the skeleton morphology after acidizing, and no sand production was observed; the unconsolidated samples had severe skeleton deformation after acidizing and serious sand production. The permeability of the consolidation samples after acidizing was 2.95mD, and porosity increased by 8.56%; the permeability of the unconsolidated samples after acidizing was 1.26mD, and the porosity decreased by 7.45%. CT scan images and mercury intrusion curves show good pore development after acidizing the consolidation samples, while the unconsolidated samples have poor pore development and sand plugging after acidizing. This result is because the cementing agent can consolidate the sand and gravel so that it will not be dislodged and transported during the acidizing process, thus maintaining reservoir stability. This study demonstrates the feasibility of acid modification technology in hydrate reservoirs, which is informative for the safe development of gas hydrates.

Synthesis and performance evaluation of polymer-ceramic composite microcapsules as reservoir protectant for natural gas hydrate drilling.

Natural gas hydrate is a promising unconventional natural gas source due to its high energy density and huge global reserves. During exploitation, the drilling fluid may invade the hydrate formation and induce hydrate decomposition, causing reservoir damage. Herein, a novel reservoir protectant made by bio-degradable temporary plugging material (BDTPM) was developed in the form of polymer-ceramic composite microcapsules. As an additive to the drilling fluid, the BDTPM can minimize drilling fluid intrusion by plugging the reservoir during drilling and afterwards maximize permeability recovery by degrading the material. The particle size distribution was in the range of 1-130μm. The optimal mass ratio between modified ceramic particles, ethyl cellulose and epoxy resin was found to be 4:2:1. The plugging rate was 100% when ethyl cellulose and epoxy resin were mixed to coat the ceramic particles to form BDTPM, and the plugging performance was the best. At a temperature close to the typical hydrate reservoir environment (5°C), 0.02 wt% low-temperature complex enzyme can degrade BDTPM, and the permeability recovery rate is 64.66%. The efficient reservoir protectant developed in this work could play an important role in the successful drilling of natural gas hydrate reservoirs.

Natural gas hydrate dissolution kinetics in sandy sediments: Implications for massive water production in field tests

The tremendous natural gas hydrate (NGH) reserve in globe makes it a promising future energy. The field test production indicates that massive water production may occur in the depressurization of sandy NGH reservoirs. The dissolution of NGH may play a significant role in this process. Therefore, quantifying the NGH dissolution kinetics and clarifying the relations between NGH dissolution and water production is crucial. In this work, a modified excess water method was developed to prepare quasi-homogenous water-saturated methane hydrate (MH) bearing sediments (HBS). The MH dissolution kinetics were investigated by flowing methane-free water through the HBS. The MH dissolution process could be divided into the rapid stage and the decayed stage. Preferential flow channels may form by the inhomogeneous MH dissolution. Water flux has a significant impact on the MH dissolution kinetics via affecting the mass transfer and the hydrate-water exposure in flow channels. When increasing the water fluxes from 2.0 mL·cm−2·min−1 to 6.1 mL·cm−2·min−1, the MH dissolution rate initially ramped up from 15.4 cm·d−1 to 36.0 cm·d−1 (mass transfer dominates), and then decreased to 28.7 cm·d−1 (flow channels dominate). MH saturation has an influence on dissolution kinetics. The MH dissolution rate increased from 27.1 cm·d−1 to 44.2 cm·d−1 when the MH saturations increased from 11.8 % to 60.1 %. Experimental results indicate that the preferential flow channels by inhomogeneous NGH dissolution could contribute to the massive water production in the depressurization of NGH reservoir. Large pressure gradient in NGH production may accelerate the NGH dissolution and the following massive water production. Homogeneous high-saturation HBS could more facilitate the hydrate-water exposure for dissolution, which could retard the onset of massive water production. This work may ignite some new thoughts on the water control and production optimization strategies in sandy NGH exploitation.

Significance of well placement and degree of hydrate reserve recovery for synergistic CH4 recovery and CO2 storage in marine heterogeneous hydrate-bearing sediments

The synergistic CH4 recovery and CO2 storage in marine natural gas hydrate reservoirs presents an emerging strategic solution for energy and environment challenges, yet the efficiency requires innovative engineering designs to enhance. In this study, a water-saturated CH4 hydrate-bearing sediment (HBS, V = 22 L, T = 284 K, and P = 11.2 MPa) was synthesized to investigate the pilot-scale combined processes of CH4 recovery by depressurization followed by CO2 storage through CO2/N2 injection. The synthesized HBS exhibited vertical heterogeneity with higher hydrate saturation observed in the upper sediment and a decreasing saturation trend in the lower sediment. The effect of well placement designs on CH4 recovery and hydrate restoration by mixed CH4/CO2/N2 hydrate (Mix-H) formation was investigated, considering two scenarios: upper well for recovery while lower well for injection (URLI), and lower well for recovery while upper well for injection (LRUI). Additionally, the impact of the degree of hydrate reserve recovery (100% and 80% hydrate dissociated) on subsequent Mix-H formation was also studied. Results indicate that the URLI setting achieves a higher CH4 recovery ratio and rate during depressurization compared to the LRUI setting which encounters low-T shielding. The T variation between upper and lower sediment highlights the influence of heterogeneity on fluid behaviors. Halting the CH4 recovery after 80% hydrate dissociation results in a halved recovery time and water production. During later CO2/N2 injection and Mix-H formation process, the LRUI setting achieves a 13–54% higher Mix-H saturation and a 33–56% higher CO2 hydrate encapsulation than the URLI setting. Moreover, 80% dissociation proves more favorable for Mix-H formation achieving nearly twice higher final amount than 100% hydrate dissociation. However, it results in a lower CO2 encapsulation. This study provides insights into the trade-off between CH4 recovery and CO2 storage efficiency, emphasizing the need for optimized well placement and controlled hydrate extraction.

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.

Analysis on a five-spot well for enhancing energy recovery from silty natural gas hydrate deposits in the South China Sea

The five-spot well is a promising technique for enhancing the inherent low gas production rate from silty natural gas hydrate (NGH) reservoirs with low permeability in the South China Sea (SCS). However, the production characteristics and the responses to key geological and engineering factors are still unclear and warrants investigation. Herein, we first establish a three-dimensional reservoir model based on the SH2 NGH deposits at SCS with the implementation of a five-spot well. We systematically examine the gas production enhancement effect and the unexpected well-to-well interaction induced by long-term depressurization. A sensitivity analysis on the effects of bottomhole pressure (Pbtm), permeability (k) and hydrate saturation (SH) is conducted to elucidate the key factors controlling the gas production enhancement. Our results reveal that the five-spot well significantly improves the gas productivity with cumulative gas production increased to 4.12 times that of a single well over 10 years. The well interference on gas production is not significant in the early stage but becomes more significant as depressurization sustains. Due to the relatively slow pressure propagation at the inner well, contribution to gas production from the inner well decreases over time while the outer wells increase. Based on the sensitivity analysis, gas production increases with decreasing Pbtm, increasing k, and decreasing SH with Pbtm and k as the key controlling factors. The findings provide valuable design basis for the adoption of a multi-well system in enhancing gas production for targeted NGH reservoirs in the next field production trial at SCS.

Spatial evolution of CO2 storage in depleted natural gas hydrate reservoirs and its synergistic efficiency analysis

Carbon neutrality is now a common strategic target worldwide, with geological storage seen as the mainstream scheme to address CO2 emissions and the greenhouse effect. Depleted natural gas hydrate reservoirs (DNHR), with their high-pressure, low-temperature environment, could capture CO2 in the form of hydrates, being an innovative way for carbon storage. A lab-scale reactor was used in this work to simulate CO2 injection into the reservoir after gas hydrate exploitation. As expected, it was found that the low-temperature environment of the depleted reservoir at the end of gas production provided a high driving force and accelerated the rate of CO2 hydrate formation. Consequently, the maximum gas storage capacity was increased by 66% by optimizing the injection timing and reducing the gas injection flow rate to enable enough hydrate formation. Besides, the formation of CO2 hydrate in the DNHR could also help stabilize the reservoir to achieve a more efficient CH4 production and CO2 storage. This study provides a novel strategy for gas hydrate exploitation as well as subsequent geological storage of CO2 in depleted natural gas hydrate reservoirs by making full use of their favorable conditions.

A well-testing model for partially perforated wells in natural gas hydrate reservoirs

A well-testing model for partially perforated wells in natural gas hydrate reservoirs

Energy Recovery from Natural Gas Hydrate and Shallow Gas Reservoirs: Exploring the Impact of Interlayer Gas Cross-Flow Behaviors

Energy Recovery from Natural Gas Hydrate and Shallow Gas Reservoirs: Exploring the Impact of Interlayer Gas Cross-Flow Behaviors

Study on the hydrate growth characteristics and rheology of silica-containing sand water-in-oil emulsion system

Understanding the transportability of silica-sand-containing hydrate slurries is crucial for production safety of non-consolidated natural gas hydrate reservoirs, especially when solid-state fluidization technology is utilized. Despite some research on silica sand and marine sediments’ influence on hydrate formation kinetics, rheological studies are scarce for systems with silica sands. The formation process of cyclopentane hydrates under the coexistence of hydrophilic silica particles and surfactants were observed. The effects of the concentration and particle size of silica sands as well as the water cut and surfactant concentration of emulsion on the rheological properties of hydrate slurries were investigated using a rheometer. The results indicated: (1) Hydrophilic sand aggregates were entrapped in water droplets, indirectly affecting the oil–water contact area due to the increase in water droplet volume, which was conducive to the combination of alkanes and water molecules to form a hydrate shell; silica particles provided nucleation sites at the oil–water interface to promote the adsorption and aggregation of cyclopentane molecules. (2) The synergistic effect of silica sand and surfactants significantly shortened the induction time of hydrates and increased the viscosity of the slurry. As the concentration of silica sand (1 wt%, 5 wt%, 10 wt%) increased, the induction time of hydrate formation decreased by 44.8 min. Within the concentration range below 5 wt%, the viscosity of the slurry increased as the concentration increased, with an amplitude of 13830.7 mPa·s. The induction time of hydrate formation decreased with increasing silica sand particle size (2 μm, 6.5 μm, 12 μm), but the size of silica sand particles had no significant effect on the viscosity of the slurry. (3) Hydrate slurries in all systems exhibited shear-thinning behavior. There was no obvious relationship between the yield stress of slurry under different silica sand concentrations. However, the yield stress of the slurry was inversely proportional to the size of silica sand particles. The yield stress decreased by 141.13 Pa when the size of silica sand particles increased from 2 μm to 12 μm. Overall, this study highlighted the influence of silica sand presence on flow safety assurance in solid-state fluidization technology.

Experimental study on direct shear properties and shear surface morphologies of hydrate-bearing sediments

The safe production of methane gas requires a comprehensive understanding of the geomechanical behavior for hydrate-bearing sediments (HBS). Currently, there is a lack of detailed exploration of the shear surface failure characteristics of specimens. To address this, direct shear tests were performed to observe shear surfaces at the microscopic level. This study mainly focuses on the mechanical parameters of HBS and the morphological characteristics of shear surfaces, aiming to elucidate the deformation modes and failure mechanisms. Results reveal that shear load-displacement curves illustrate three stages: elastic deformation, strain softening, and stability stage. The shear strength increases from 12.65 KPa to 153.86 KPa with hydrate saturation rising from 12% to 72%, while decreases versus shear rate. Shear surfaces exhibit concave, convex, and S-shape patterns with remarkable differences in crack number and orientation. The shear load-displacement curves and shear surface morphology are closely correlated with shear rates, especially shear strength and shear surface roughness. Furthermore, the shear surface roughness varies between 2.02 mm and 3.61 mm with hydrate saturation increasing from 12% to 72%, which are also influenced by the shear rate. Empirical formulas were established based on test data to predict the shear strength and surface roughness. The failure mechanism of the specimens mainly depended on the movement modes of the sediment particles, hydrate strength, and hydrate-sediment cementation strength. Findings of this study provide a theoretical reference for evaluating geo-mechanical stability and predicting the destabilization of natural gas hydrate reservoirs.

Evaluation of Thermal and Mechanical Properties of Foamed Phosphogypsum-Based Cementitious Materials for Well Cementing in Hydrate Reservoirs

As detrimental byproduct waste generated during the production of fertilizers, phosphogypsum can be harmlessly treated by producing phosphogypsum-based cementitious materials (PGCs) for offshore well cementing in hydrate reservoirs. To be specific, the excellent mechanical properties of PGCs significantly promote wellbore stability. And the preeminent temperature control performance of PGCs helps to control undesirable gas channeling, increasing the formation stability of natural gas hydrate (NGH) reservoirs. Notably, to further enhance temperature control performance, foaming agents are added to PGCs to increase porosity, which however reduces the compressive strength and increases the risk of wellbore instability. Therefore, the synergetic effect between temperature control performance and mechanical properties should be quantitatively evaluated to enhance the overall performance of foamed PGCs for well cementing in NGH reservoirs. But so far, most existing studies of foamed PGCs are limited to experimental work and ignore the synergetic effect. Motivated by this, we combine experimental work with theoretical work to investigate the correlations between the porosity, temperature control performance, and mechanical properties of foamed PGCs. Specifically, the thermal conductivity and compressive strength of foamed PGCs are accurately determined through experimental measurements, then theoretical models are proposed to make up for the non-repeatability of experiments. The results show that, when the porosity increases from 6% to 70%, the 7 d and 28 d compressive strengths of foamed PGCs respectively decrease from 21.3 MPa to 0.9 MPa and from 23.5 MPa to 1.0 MPa, and the thermal conductivity decreases from 0.33 W·m−1·K−1 to 0.12 W·m−1·K−1. Additionally, an overall performance index evaluation system is established, advancing the application of foamed PGCs for well cementing in NGH reservoirs and promoting the recycling of phosphogypsum.

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.