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Geophysical detection techniques are important methods in marine gas hydrate exploration and monitoring, because the small-scale distribution of hydrates has a large impact on the wave velocity. The acoustic response characteristics of hydrate micro-distributions have strong significance for monitoring the hydrate dissociation process. In this paper, experiments simulating the hydrate dissociation process were carried out in a self-developed experimental device combining X-ray computed tomography (X-CT) scanning and ultrasonic detection, which allowed the acoustic wave characteristics and X-CT scanning results to be simultaneously obtained during the hydrate dissociation process. This study found that the hydrate dissociation stage is divided into three stages. The hydrate begins to dissociate at spots where it comes into touch with sand particles early in the dissociation process. The main factor affecting the acoustic wave velocity of hydrates in this stage is changes in the microscopic distribution of hydrate. In the middle stage, a large amount of hydrate decomposes, and the main factor affecting the acoustic wave velocity of hydrate in this stage is the change in hydrate content. In the later stage of hydrate dissociation, the hydrate distribution pattern consists mainly of the pore-filling type, and the hydrate micro-distribution at this stage is the main factor affecting the acoustic wave velocity. This study will be of great significance for understanding the microscopic control mechanism of hydrate reservoir geophysical exploration. [ABSTRACT FROM AUTHOR]

The acoustic characteristics of hydrates are important parameters in geophysical hydrate exploration and hydrate resource estimation. The microscale distribution of hydrate has an important influence on the acoustic response of a hydrate-bearing reservoir. Although microscale hydrate distributions can be determined using means such as X-ray computed tomography (X-CT), it is difficult to obtain acoustic parameters for the same sample. In this study, we developed an experimental system that integrated pore-scale visualization and an ultrasonic testing system for methane-hydrate-bearing sediments. Simultaneous X-CT observation and acoustic detection could be achieved in the same hydrate sample, which provided a new method for synchronously monitoring microscale distributions during acoustic testing of natural gas hydrate samples. Hydrate formation experiments were carried out in sandy sediments, during which the acoustic characteristics of hydrate-bearing sediments were detected, while X-ray computed tomography was performed simultaneously. This study found that hydrates formed mainly at the gas–water interface in the early stage, mainly in the pore fluid in the middle stage, and came into contact with sediments in the later stage. The development of this experimental device solved the difficult problem of determining the quantitative relationship between the microscale hydrate distribution and the acoustic properties of the reservoir. [ABSTRACT FROM AUTHOR]

Proper models for predicting strength parameters of reservoirs are vital to the numerical simulation and risk analysis during gas hydrate exploration. However, unlike homogeneous hydrate reservoirs, strength parameters of interlayered sediments depend on hydrate distribution modes, which remains unclear. Herein, a series of triaxial shearing tests on sediments with hydrate layered distribution are conducted to investigate variations of strength parameters and effects of sublayers. The results indicate that failure strength of whole sediments mainly depends on the high hydrate-saturated sublayer, while the cohesion is more relevant to the low hydrate-saturated layer. Besides, prediction models are proposed to estimate the failure strength through data-fitting, strength-average, and hydrate-average methods. By comparing the accuracy and applicability of these three methods, the hydrate-average method is the best way to estimate failure strength for current use. This study can provide a feasibility reference for strength estimation and risk control during natural gas hydrate development. • Strength parameters of interlayered sediments depend on all sublayers. • High hydrate-saturated sublayers cause increasing deviator stress at small strains. • Hydrate-average method is an effective way to predict strength of layered sediments. [ABSTRACT FROM AUTHOR]

The permeability anisotropy (ie, horizontal, kr, to vertical, kz, permeability ratio) of gas hydrate reservoirs may be a significant factor that affects hydrate dissociation and gas production. Here, site SH2, a candidate for field testing comprising a clayey silt gas hydrate reservoir in the Shenhu area in the South China Sea, was chosen to investigate the effect of permeability anisotropy on gas production behavior through numerical simulations. The spatial distribution of physical fields (ie, pressure, temperature, and saturation) and the evolution of gas and water recovery are comparatively analyzed. The simulation results show that permeability anisotropy has a significant impact on gas extraction, especially when the horizontal permeability is higher than the vertical one. The sensitivity analyses indicate that permeability anisotropy in both medium‐permeability (10‐100 mD) and low‐permeability (1‐10 mD) sediments are conducive to hydrate dissociation and that a higher horizontal permeability is more favorable for gas production. Comparatively, permeability anisotropy in low‐permeability sediments is not beneficial for improving production efficiency. In addition, our work also suggests that heterogeneous hydrate saturation in a reservoir‐scale model should be employed in future predictions because the gas production potential will be overestimated in a homogeneous reservoir under the same conditions. These findings contribute to a clear understanding of the influence of reservoir properties on gas hydrate dissociation processes and provide a reference for future field trials and commercial production. [ABSTRACT FROM AUTHOR]

The process of extracting natural gas from gas hydrate‐bearing sediments (GHBS) may yield significant sand influx due to the metastable nature of GHBS. Selecting appropriate sand control media is vital to addressing the challenges caused by excessive sand production. This study proposes a protocol called holding coarse expelling fine particles (HCEFP) for sand control design. The protocol aims to provide a new optimization method for screen mesh size selection for clayey silt hydrate reservoirs. Detailed optimizing procedures of proper candidate screen mesh sizes in hydrate exploitation well in clayey silt hydrate reservoirs are depicted based on the HCEFP. Then, the site W18, which is located in the Shenhu area of the northern South China Sea, is taken as an example to illustrate the optimization procedure for screen mesh size selection. The results reveal that complete solid retention via a standalone screen is rarely beneficial as high clay contents can adversely affect wellbore productivity due to excessive plugging. Screen aperture size selection for clayey silt hydrate wells should strike a balance between retaining coarser particles and avoiding screen blockage by the relatively fine particles. Furthermore, longitudinal heterogeneity of the PSDs also increases the difficulties associated with sand control design. Multistage sand control optimization is necessary in hydrate production wells. For Site W18, we recommend that the entire production interval can be divided into two subintervals for multistage sand control operations. [ABSTRACT FROM AUTHOR]

Abstract Different micro-distribution patterns in gas hydrates may produce different acoustic effects on the deposition medium. The influence of hydrate distributions on the reservoir and the acoustic response of the hydrate during the dissociation process are very important. In this paper, ultrasonic velocity and hydrate saturation were measured by ultrasonic measurement and time domain reflection (TDR) techniques, respectively. The relationship between the wave velocities and saturation of the hydrate along with X-ray computed tomography (X-CT) scanning results were used to analyze hydrate distribution patterns and their acoustic response characteristics. The results show that the rate of decrease in hydrate saturation in the dissociation stage remains basically unchanged, and the hydrate dissociation rate remains constant. During the process of hydrate dissociation, the hydrate first disrupts the stable sedimentary skeleton structure, and then breaks down at the contacts with sediment particles. Then, the hydrate gradually decomposes into the pore space away from the particle contacts and the hydrate is mainly present in suspended mode. Finally, hydrate decomposes entirely and free bubbles are in contact with the hydrate. In the early stage of hydrate dissociation, compressional and shear wave velocities decreased rapidly by 453 m/s and 307 m/s, respectively. In the later stage of hydrate dissociation, compressional and shear wave velocities decreased by 271 m/s and 119 m/s, respectively, with smaller decreases in wave velocities than in the early hydrate dissociation stage. The results show that the measured changes in P-wave velocity are consistent with results obtained from a site in the Shenhu area. The micro-distribution modes during the hydrate dissociation process were inferred. At the initial stage of dissociation, the hydrate decomposed at the contacts with sediment particles, whereas the hydrate was mainly suspended in the pores in the later stage. Highlights • The ultrasonic detection and X-CT technology were used to measure elastic wave velocities and hydrate distribution. • The relationship between the velocity and the hydrate saturation in sands and sediments from South China Sea was established. • The micro-distribution of hydrate in sands and sediments from South China Sea was discussed during hydrate dissociation. • The acoustic characteristics were combined to infer microscopic distribution patterns in the South China Sea sediments. [ABSTRACT FROM AUTHOR]

In this study, a nano‐focus X‐ray computed tomography (X‐CT) is used to observe the formation of methane hydrate in sands on pore scale and to quantify hydrate saturation, pore structure parameters, and permeability of hydrate‐bearing sands. A new analytical technique is developed to improve the identification of water‐hydrate boundary. Three hydrate accumulation habits (i.e., floating, contacting, and cementing) in pore spaces are observed. When there is no methane bubble, hydrate distribution evolves from floating to contacting and then to cementing as hydrate saturation increases. In contrast, only contacting and cementing distribution patterns appear in the pores with methane bubbles. Based on the surface extraction and defect detection from 3‐D images, both the gas/water/hydrate distributions and the pore structure characteristics are investigated. The results show that the porosity, the maximal pore volume, and maximal diameter decrease as hydrates accumulate in the pores. However, the maximal pore surface, the total pore number, and the large pores (>100 voxels) number increase gradually until the hydrate saturation reaches 35%, when they turn to decrease rapidly. The pore structure parameters show detailed changes of hydrate and water on pore scale. The incompressible Navier‐Stokes equations are used to calculate absolute permeability of hydrate‐bearing sands based on X‐ray computed tomography digital images. It indicates that the microdistribution of the hydrate has a significant effect on the permeability calculation. The fluid streamlines obtained through simulation are used to track the water transport paths. Key Points: The growth of hydrate in pores with methane bubbles is different from that in pores full of waterPore structure characteristics are affected by the saturation and the distribution patterns of gas hydrateA method of calculating permeability of hydrate‐bearing sands based on X‐ray CT images is developed [ABSTRACT FROM AUTHOR]

Gas hydrate has been recognized as a potential energy resource in South China Sea (SCS). Understanding the acoustic response of gas hydrate formation in the SCS sediments is essential for regional gas hydrate investigation and quantification. The sediments were obtained from gravity core sampling at E 115°12.52363′ N 19°48.40299′. Gas hydrate was formed within a “gas + water-saturated SCS sediments” system. Combination of a new bender element technique and coated time domain reflectometry (TDR) was carried out to study the acoustic response of hydrate occurrence in SCS sediments. The results show the acoustic signal becomes weak when hydrate saturation (S h ) is lower than 14%. The acoustic velocities (Vp, Vs) of the sediments increase with S h during hydrate formation, and Vs increases relatively faster when S h is higher than 14%. These results indicate that tiny hydrate particles may firstly float in the pore fluid, which causes a significant acoustic attenuation, but has little influence on shear modulus. As time lapses and S h approaches 14%, numerous particles coalesce together and contact with sediment particles. As a result, Vs has a sharp increase when hydrate saturation exceeds 14%. Several velocity models were validated with the experimental data, which suggests a combination of the BGTL (Biot–Gassmann Theory modified by Lee) model and the Weighted Equation is suitable to estimate S h in SCS. [ABSTRACT FROM AUTHOR]

The elastic wave velocities of hydrate-bearing sediments (HBS) are considerably affected by the content of free gas and hydrate. Although several existing models relate the free gas and hydrate saturation to acoustic velocities, the accuracy of these models is still uncertain because of the difficulty in determining the gas content. In this study, we acquired the gas volume fraction and acoustic velocity data of the hydrate-bearing sands through a X-ray computed micro-tomography (CT) and an ultrasonic apparatus, respectively. The acoustic velocities increase slowly at low hydrate saturation (S h < 33%), whereas they increase rapidly when hydrate saturation exceeds 33%. Using the measured data, we verified three commonly used velocity models, namely, the Biot-Gassmann theory by Lee (BGTL), effective media theory (EMT), and simplified three-phase equation (STPE). The results obtained using the BGTL are consistent with the experimental results when hydrate saturation exceeds 45%, while the EMT-B model is more suitable for predicting P-wave velocity (V p) when the hydrate saturation varies from 15% to 55%. The value of V p calculated by the STPE model, without considering the effects of gas on velocity, is higher than the experimental value. We further applied a new method combining the Wood and Domenico equations to calculate the bulk modulus of HBS containing methane gas, which can improve the precision and applicability of the STPE model. Compared with the EMT and BGTL models, the modified STPE model is more suitable for predicting V p of unconsolidated reservoirs with high porosity and permeability. These results provide a new method for further experimental research and a theoretical reference for accurately estimating hydrate saturation through logging data during natural gas exploration and development. • A CT-ultrasonic detection apparatus was used to measure the micro distribution and velocity of hydrate bearing sediments simultaneously. • The accuracy of different velocity models and equations was verified. • A new bulk modulus calculation method is applied to improve the accuracy and adaptability of the velocity model. [ABSTRACT FROM AUTHOR]

Abstract The Shenhu area, located in the Pearl River Mouth Basin, South China Sea (SCS), is currently one of the most promising exploration areas for gas hydrates. In this study, the lithological characteristics, as well as the molecular and isotopic composition of hydrocarbon gases are systematically reported for the first time for core sediments obtained from two new drilling sites (referred to as W01B and W02B) in the southeast Shenhu area. Both gas hydrate-bearing and gas hydrate-free samples are characterized by fine-grained sediments (dominantly coarse silt and to a lesser extent, fine and medium silt) and similar median grain-sizes (5.94Φ to 6.49Φ), sorting (2.32 to 2.59), kurtosis (0.82 to 0.97), skewness (−0.12 to 0.03) and mineral compositions. Abundant authigenic pyrites (including euhedral and framboidal pyrites) also occur in these sediments. All these characteristics collectively indicate that the core sediments from the southeast Shenhu area formed in a relatively stable, low-energy and anoxic sedimentary environment. Nevertheless, the hydrate-bearing layers in this study are characterized by lower sand contents and more foraminifera than gas hydrate-free layers. The molecular and isotopic composition of hydrocarbon gases hosted by secondary minerals in the studied sediments indicates that they are of thermogenic origin. Combined with previously published data, we suggest that the abundant foraminifera within the sediments of the Shenhu area play a significant role in controlling the formation of gas hydrates by increasing the porosities of sediments, and that the thermogenic gas is an important source for the hydrocarbon gases of hydrates in the SCS. Highlights • The gas hydrate-bearing and barren samples show similar grain size distribution. • These sediments formed in a stable, low-energy and anoxic sedimentary environment. • Foraminifera within the sediments are favorable for the formation of gas hydrates. [ABSTRACT FROM AUTHOR]

Experiments are performed to study the closed-loop effect of gas hydrate formation and decomposition on the flow properties of a fine-grained quartz sand specimen. The high resolution X-ray CT images of the test specimen at different experimental stages are acquired. In order to elucidate the changes in pore structure of the test specimen, topologically representative pore networks are established. The evolution of the flow properties during gas hydrate formation and decomposition is further evaluated. The results show that, gas hydrates occupancy in pore space exhibit different modes; they grow mainly as the grain-cementing mode except some intermediate stages, where pore-filling or load-bearing hydrates are observed. It is also found that the formation and decomposition of gas hydrates can cause the pore structure and flow properties changed. Increase of gas hydrate saturation results in a sharp decline in water relative permeability, larger irreducible water saturation and smaller gas-water percolation zone, while gas relative permeability does not exhibit obvious changing law. The decomposition of gas hydrates will exert a greater influence on the flow properties described above than gas hydrate formation does. The increase in frequency percentage of 10–20 μm pores within the fine-grained test specimen after experiments might be caused by gas hydrate decomposition induced damage of pore structure. [ABSTRACT FROM AUTHOR]

According to the preliminary geological data of gas hydrate bearing-sediments (GHBS) at site GMGS3-W19 in the third Chinese expedition to drill gas hydrates in 2015, a production model using three different recovery pressures was established to assess the production feasibility from both production potential and geomechanical response. The simulation results show that for this special Class 1 deposit, it is a little hard for gas production rate to reach the commercial extraction rate because the degree of hydrate dissociation is limited due to the low reservoir permeability and the permeable burdens. However, the free gas accumulating in the lower part of the GHBS can significantly increase gas-to-water ratio. It also generates many secondary hydrates in the GHBS at the same time. Decreasing the well pressure can be beneficial to gas recovery, but the recovery increase is not obvious. In term of geomechanical response of the reservoir during the gas recovery, the permeable burdens are conducive to reduction of the sediment deformation, though they don't facilitate the gas recovery rate. In addition, significant stress concentration is observed in the upper and lower edges of GHBS around the borehole during depressurization because of high pressure gradient, and the greater the well pressure drop, the more obvious the phenomenon. Yield failures and sand production easily take place in the edges. Therefore, in order to achieve the purpose of safe, efficient and long-term gas production, a balance between the production pressure and reservoir stability should be reached at the hydrate site. The production pressure difference and sand production must be carefully controlled and the high stress concentration zones need strengthening or sand control treatment during gas production. Besides, the sensitivity analyses show that the hydrate saturation heterogeneity can affect the production potential and geomechanical response to some extent, especially the water extraction rate and the effective stress distribution and evolution. Increasing GHBS and its underlying free gas formation permeabilities can enhance the gas production potential, but it probably introduces geomechanical risks to gas recovery operations. [ABSTRACT FROM AUTHOR]

Gas production from hydrates induced by depressurization is a complex thermal-hydrodynamic-mechanical–chemical (THMC) coupled process. In this paper, we present a THMC coupled model to simulate the fluid flow in hydrate-bearing sediments (HBS) and the geomechanical behavior of HBS. The model is made of two subsystems, which are the fluid part of non-isothermal multi-phase flow with hydrate kinetic and solid part of geomechanical deformation. It accounts for two-way coupling effects between these two subsystems, i.e. the effect of pore pressure and hydrate dissociation on the solid mechanical behavior and the effect of stress on the hydraulic behavior. A new numerical method based on the hybrid control volume finite element method (CVFEM)-finite element method (FEM) is developed to solve the mathematical models. The local conservative CVFEM is used for the fluid part, and the standard FEM for the solid part. In the framework of hybrid CVFEM-FEM, the local conservation is reserved and the primary variables for the two subsystem are co-located. A multi-point flux approximation (MPFA) is adopted without orthogonal meshes so that it is very flexible to build complex geometrical models. The accuracy and reliability of the newly developed simulator QIMGHyd-THMC are tested by comparing with two experimental examples and a large-scale benchmark problem of other popular simulators. • A fluid-solid coupled mathematical framework is proposed for gas hydrate production. • A hybrid control volume finite element method and finite element method is presented. • Numerical method preserves local conservation for solving of fluid subsystem. • Co-located variable for simulation of fluid and solid is achieved. • Method and software are validated by experiments and comparing with other simulators. [ABSTRACT FROM AUTHOR]

Buried depth, as an inherent occurrence feature of hydrate reservoir, plays a significant role in fluid production during hydrate dissociation. In this study, we experimentally investigate the production performance of hydrate reservoirs at various buried depths beneath the seafloor. The hydrate-bearing system is synthesized in quartz sand with grain size varying between 100 and 500 μm in a 0.98 L reactor. Similar hydrate saturation is obtained at different prevailing pressures between 5.6 and 8.8 MPa. Depressurization experiments are designed to investigate the effect of buried depths on fluid production behavior. The results show that gas and water production increase with elevated buried depths at the same production pressure. However, based on the gas to water ratio, a deep-buried reservoir has a higher production potential at the initial stage. In contrast, a shallow-buried reservoir is an ideal candidate for fluid production in the later stage. Depressurization to the equilibrium P - T condition could lead to potential hydrate dissociation, but the rate is less intensive with less than 46.0 vol% hydrates dissociated in a prolonged time. The experimental results also reveal that both the design of depressurization and the reservoir depths have a combined effect on the overall fluid production performance. • A series of hydrate-bearing sediments with different buried depths were synthesized. • An accurate calculation method quantifying multi-phase saturation was developed. • Stability of hydrate reservoir and fluid production performance were analyzed. • Different production pressures but with the same degree of pressure driving force were employed. [ABSTRACT FROM AUTHOR]

Evaluating deformation characteristics and predicting strength parameters of hydrate-bearing sediments (HBS) are indispensable for natural gas hydrate exploration and development. A series of triaxial shearing tests were conducted in this paper to analyze the mechanical behaviors and failure mechanisms of hydrate-bearing sediments. The failure strength is discussed comprehensively based on the Mohr-Coulomb criterion, the Drucker-Prager criterion, and the Lade-Duncan criterion. Failure mechanisms of the specimens during shearing are discussed at the micro-level. The results indicate that specimens with relatively high hydrate saturation exhibit strain-softening brittle failure mode, whereas those with relatively low hydrate saturation exhibit obvious strain-hardening ductile failure mode. The cohesion of HBS is enhanced from 0.42 MPa to 1.0 2 MPa, and the friction angle increases from 26.4° to 34.2° with hydrate saturation rising. Additionally, the modified criteria based on the Drucker-Prager criterion can predict the strength with the highest accuracy. The results provide a theoretical and experimental reference for developing the natural gas hydrate reservoirs efficiently. • Mechanical properties of hydrate-bearing sediments based on triaxial shearing tests. • Failure strength is discussed comprehensively based on the Mohr-Coulomb criterion, the Drucker-Prager criterion, and the Lade-Duncan criterion. • Failure mechanisms of the specimens during shearing are discussed at the micro-level. • The cohesion is enhanced from 0.42 MPa to 1.0 2 MPa, and the friction angle increases from 26.4° to 34.2°. [ABSTRACT FROM AUTHOR]