Effect of gas hydrate formation and decomposition on flow properties of fine-grained quartz sand sediments using X-ray CT based pore network model simulation

Wang, Daigang; Wang, Chenchen; Li, Chengfeng; Liu, Changling; Lu, Hailong; Wu, N.; Hu, Gaowei; Liu, Lele; Meng, Qingguo

doi:10.1016/j.fuel.2018.04.042

Cited by 77 publications

(30 citation statements)

References 45 publications

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“…This gas‐saturated water layer provides enough host and guest molecules for secondary hydrate formation. Moreover, on the hydrate surface, there are complete or semicomplete host cage structures; thus, there are almost no kinetic barriers to reformat hydrate because the nucleation driving force is less than those in areas without hydrate (Han et al, 2018; Wang, Wang, Li et al, 2018). The local low pore pressure caused by the secondary hydrate formation will be the driving force for the dissociated gas‐saturated water upward migration in the liquid phase (Yang et al, 2016).…”

Section: Resultsmentioning

confidence: 99%

Microstructure Evolution of Hydrate‐Bearing Sands During Thermal Dissociation and Ensued Impacts on the Mechanical and Seepage Characteristics

Liu

et al. 2020

JGR Solid Earth

101

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In this study, a microfocus X‐ray computed tomography‐based triaxial testing apparatus was used to observe and quantify the microstructure evolution of hydrate‐bearing sands during thermal dissociation of hydrate. Three triaxial shear tests with X‐ray computed tomography were conducted to study the influence of hydrate dissociation on the mechanical behavior of hydrate‐bearing sands. The results show that hydrate covering the sand particle surface dissociates first and then at the menisci between sand particles. The secondary hydrate formation mainly occurs on the menisci between sand particles and the surfaces of the hydrate shells where hydrates already exist. Hydrate dissociation could cause fabric changes in hydrate‐bearing sands, resulting in a more isotropic orientation distribution of sand particles. The failure behavior of the hydrate‐free sand specimen is similar to that of the specimen after hydrate dissociation, which shows an obvious drum‐shaped failure pattern with X‐shaped shear bands. However, the hydrate‐bearing sand specimen exhibits a shear band with a determined thickness and inclination angle. Hydrate dissociation could cause a significant loss of supporting cementation, resulting in a decline in the stiffness and failure strength. The failure strength of hydrate‐free sand specimen is slightly higher than that of the specimen after hydrate dissociation; this may due to that the homogeneous orientation frequency distribution can enhance the stability of the force chain between sand particles. The secondary hydrate formation causes sediment deformation resulting in a decrease in absolute permeability due to pore blockage.

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Section: Resultsmentioning

confidence: 99%

Microstructure Evolution of Hydrate‐Bearing Sands During Thermal Dissociation and Ensued Impacts on the Mechanical and Seepage Characteristics

Liu

et al. 2020

JGR Solid Earth

101

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“…The permeability of sediments is an important parameter for the experimental and numerical simulation of in situ gas hydrate extraction (Wang et al, ). Permeability, which describes the seepage capacity of fluid in porous media, determines the recovery efficiency of gas and water (Fan et al, ).…”

Section: Introductionmentioning

confidence: 99%

Study on the Effects of Heterogeneous Distribution of Methane Hydrate on Permeability of Porous Media Using Low‐Field NMR Technique

Hou

Zhao

et al. 2020

JGR Solid Earth

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The permeability of sediments is an important parameter that effects flow characteristics of the gas and water in the process of natural gas hydrates development. The distribution of gas hydrate is generally heterogeneous in porous media. It poses a great challenge to the permeability measurement of hydrate‐bearing sediments. To study the effect of heterogeneous distribution of methane hydrate on the permeability of porous media, methane hydrate formation in the sandstone and permeability measurement was carried out using a low‐field nuclear magnetic resonance (NMR) measurement system in situ conditions. The spatial distribution of methane hydrate in the core samples was determined by combining the T2 distribution with magnetic resonance imaging. The results show that the distribution of methane hydrate is heterogeneous in the core samples. The temporal and spatial variation of permeability happens in the process of hydrate dissociation. The heterogeneity of methane hydrate distribution severely affects the analysis of permeability change. Considering the heterogeneity of methane hydrate distribution, a new method was proposed to obtain the quantitative relationship between hydrate saturation and relative permeability based on magnetic resonance imaging and the equivalent seepage capacity method. The results show that the relative permeability models obtained by this method agree better with experimental results. The optimum coefficients of relative permeability models obtained by equivalent seepage capacity method change significantly in contrast with the direct fitting method. The variation of the optimum coefficient is up to 300% in this study. The model coefficients are related to the pore characteristic of hydrate‐free porous media.

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“…The NRP model by Singh et al () assumed negligible capillary pressure, which can be an appropriate assumption for production from a sandy gas hydrate‐bearing field with operating pressures higher than capillary pressures, but capillary pressure is relevant at laboratory scale (Buleiko et al, ; Chen & Espinoza, ; Liu & Flemings, ; Pesaran & Shariati, ; Uchida et al, ), especially when the pore sizes are smaller than ~1 μm (Chen & Espinoza, ; Kang et al, , ; Liu & Flemings, ; Uchida et al, ) and in that case the accuracy of prediction from NRP is impacted as shown later. Capillary pressure also plays an important role in percolation properties of multiphase flow in hydrate‐bearing medium, where capillary pressure versus water saturation curve can be used to assess properties such as the degree of sorting and pore size distribution; a medium with uniform pore size distribution leads to a well‐sorted medium that is depicted by an elongated horizontal segment of the capillary pressure curve (Wang et al, ). It has been found that the presence of capillarity results in higher water permeability than when there is no capillarity for both grain‐coating and pore‐filling hydrates (Kang et al, ), but the mechanisms that reduce permeability in presence of hydrates (channel blocking and pore size reduction) are also alleviated a little (Kang et al, ) in the presence of capillarity.…”

Section: Modelmentioning

confidence: 99%

A Mechanistic Model for Relative Permeability of Gas and Water Flow in Hydrate‐Bearing Porous Media With Capillarity

Singh

Mahabadi

Myshakin

et al. 2019

Water Resources Research

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Lack of mechanistic models to describe petrophysical properties of mobile phases in gas hydrate‐bearing sediments is one of the key challenges in accurately predicting gas production. The major drawback of empirical models that are used to fit a relative permeability curve for mobile phases in gas hydrate‐bearing sediments is that they are based on experimental data, which are limited, and not able to account for hydrate morphology in pore space. This study proposes a relative permeability model that is mechanistic in nature and developed to account capillarity by building on the original nonempirical relative permeability model that assumes negligible capillary pressure. The proposed model implicitly accounts for capillarity with the help of four empirical parameters (two for each mobile phase) that incorporate each mobile phase pressure. It is shown that the proposed model provides an improved match to relative permeability data (derived from pore‐scale simulation of gas hydrate‐bearing sediments) than nonempirical relative permeability by accounting for the effect of capillary pressure. Additionally, unlike fully empirical models that can predict relative permeabilities reliably only at gas hydrate saturations for which experimental data are available, the proposed model only requires fitting the empirical parameters once with experimental data at any single gas hydrate saturation and then it can then be used to predict relative permeability at any gas hydrate saturation. The mechanistic nature of the proposed model allows studying relative permeability of hydrate‐bearing sediments as a function of hydrate morphology and wettability (fluid phase distribution) besides other physical parameters of the model (e.g., porosity, gas, and water residual saturation). Based on the sensitivity analysis of different hydrate morphologies on gas/water relative permeability, it is found that gas relative permeability is sensitive to hydrate morphologies, while water relative permeability shows little dependency on hydrate localization in pore space.

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Effect of gas hydrate formation and decomposition on flow properties of fine-grained quartz sand sediments using X-ray CT based pore network model simulation

Cited by 77 publications

References 45 publications

Microstructure Evolution of Hydrate‐Bearing Sands During Thermal Dissociation and Ensued Impacts on the Mechanical and Seepage Characteristics

Microstructure Evolution of Hydrate‐Bearing Sands During Thermal Dissociation and Ensued Impacts on the Mechanical and Seepage Characteristics

Study on the Effects of Heterogeneous Distribution of Methane Hydrate on Permeability of Porous Media Using Low‐Field NMR Technique

A Mechanistic Model for Relative Permeability of Gas and Water Flow in Hydrate‐Bearing Porous Media With Capillarity

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