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Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H3: Fossil".

Deadline for manuscript submissions: closed (28 February 2023) | Viewed by 13029

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Special Issue Editors

Dr. Zhenyuan Yin

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Guest Editor

Institute for Ocean Engineering, Tsinghua Shenzhen International Graduate School, Tsinghua University, Shenzhen 518055, China
Interests: natural gas hydrate; CO₂ hydrate; thermodynamics; kinetics; numerical modeling; reservoir simulation
Special Issues, Collections and Topics in MDPI journals

Prof. Dr. Shuxia Li

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Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, China
Interests: natural gas hydrate; reservoir simulation; numerical modeling; fluid flow in porous media; hydrate dissociation; NGH production strategy; pore-scale simulation

Special Issue Information

Dear Colleagues,

Gas hydrates are ice-like compounds comprising gas molecules (i.e., CH₄, CO₂) and water. Natural gas hydrates (NGHs) are stable under low-temperature and high-pressure conditions, thus constraining their occurrence in sediments in marine and permafrost environments with a large resource volume (>3000 trillion cubic meters). A shift in their stability condition triggers an endothermic hydrate dissociation with an accompanying release of gas and water, impacting (among other factors) sediment pore pressure, temperature, multiphase fluid flow and associated deformations in geological sediments. Therefore, the behaviour of hydrate-bearing sediments (HBS) is controlled by strongly coupled thermo-hydro-chemo-mechanical (THCM) interactions. The analysis of available data from past research in this field and laboratory experiments as well as the optimization of future field production studies requires a formal and robust numerical framework that is capable of capturing the complex and dynamic behaviour of gas hydrates in porous media. Significant progress has been achieved in recent years with regard to numerically describing the gas hydrate phase change and the fluid flow behaviour in porous media considering all the related coupled physical effects.

In this Special Issue, we are inviting the contribution of innovative studies (including both review and research papers) that numerically describe gas hydrate dynamic behaviour in porous media at various temporal and spatial scales (i.e., core scale, laboratory reactor scale, reservoir field scale, etc.). Prospective topics include but are not limited to (a) the fluid production and energy recovery process of natural gas hydrates (i.e., depressurization, thermal stimulation, inhibitor injection and other novel methods including wellbore design, etc.); (b) hydrate-based CO₂ storage in geological settings (e.g. deep marine locations, CO₂–CH₄ exchange method, etc.); (c) the short-term and long-term transport of CH₄ in geological environments and the associated formation of the NGH reservoir; (d) pore-scale simulation (Lattice Boltzmann method, pore network model, CFD simulations, etc.) that elucidates the fundamental heat and mass transfer behaviour and thermophysical properties of hydrate-bearing sediments with phase change; and (e) reservoir-scale simulation that aims to optimize the production strategies of different types of NGH reservoirs.

Dr. Zhenyuan Yin
Prof. Dr. Shuxia Li
Guest Editors

Manuscript Submission Information

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Keywords

CH4 hydrate
CO2 hydrate
Formation and dissociation
Kinetic behavior
Phase change
Controlling mechanism
Dissociation front
Heat and mass transfer
Reservoir simulation
Porous media
Geological settings
Production strategy
Sand production
Deformation analysis
Wellbore design
THCM

Published Papers (8 papers)

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Research

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19 pages, 8546 KiB

Open AccessArticle

Multi-Lateral Well Productivity Evaluation Based on Three-Dimensional Heterogeneous Model in Nankai Trough, Japan

by Xin Xin, Ying Shan, Tianfu Xu, Si Li, Huixing Zhu and Yilong Yuan

Energies 2023, 16(5), 2406; https://doi.org/10.3390/en16052406 - 2 Mar 2023

Cited by 1 | Viewed by 1269

Abstract

Widely employed in hydrate exploitation, the single well method is utilized to broaden the scope of hydrate decomposition. Optimizing the well structure and production strategy is necessary to enhance gas recovery efficiency. Complex wells represented by the multilateral wells have great application potential in hydrate mining. This study focused on the impact of multilateral well production methods on productivity, taking the Nankai Trough in Japan as the study area. The spatial distribution of physical parameters such as porosity, permeability, and hydrate saturation in the Nankai Trough has significant heterogeneity. For model accuracy, the Sklearn machine learning and Kriging interpolation methods were used to construct a three-dimensional heterogeneous geological model to describe the structure and physical property parameters in the study area of the hydrate reservoir. The numerical simulation model was solved using the TOUGH + Hydrate program and fitted with the measured data of the trial production project to verify its reliability. Finally, we set the multilateral wells for hydrate high saturation area to predict the gas and water production of hydrate reservoir with different exploitation schemes. The main conclusions are as follows: ① The Sklearn machine learning and Kriging interpolation methods can be used to construct a three-dimensional heterogeneous geological model for limited site data, and the fitting effect of the heterogeneous numerical simulation model is better than that of the homogeneous numerical simulation model. ② The multilateral well method can effectively increase the gas production rate from the hydrate reservoir compared with the traditional single well method by approximately 8000 m³/day on average (approximately 51.8%). ③ In the high saturation area, the number of branches of the multilateral well were set to 2, 3, and 4, and the gas production rate was increased by approximately 51.8%, 52.5%, and 53.5%. Considering economic consumption, the number of branching wells should be set at 2–3 in the same layer. Full article

(This article belongs to the Special Issue Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media)

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35 pages, 31835 KiB

Open AccessArticle

Quantitative Simulation of Gas Hydrate Formation and Accumulation with 3D Petroleum System Modeling in the Shenhu Area, Northern South China Sea

by Pibo Su, Jinqiang Liang, Haijun Qiu, Jianhua Xu, Fujian Ma, Tingwei Li, Xiaoxue Wang, Jinfeng Zhang, Zhifeng Wan, Feifei Wang, Yaoyao Lv and Wei Zhang

Energies 2023, 16(1), 99; https://doi.org/10.3390/en16010099 - 22 Dec 2022

Cited by 1 | Viewed by 1282

Abstract

Gas hydrates have been considered as a new energy that could replace conventional fossil resources in the future because of their high energy density, environmental friendliness, and enormous reserves. To further analyze the potential distribution of gas hydrate stability zones (GHSZ) and the formation of a gas hydrate system in the Shenhu area of the South China Sea (SCS), a 3D petroleum simulation model (PSM) was built from 3D seismic interpretations and all available geological data. Based on the thermal calibration of the 3D model, the evolution of the GHSZ, hydrocarbon generation and migration, and the formation and accumulation of gas hydrates were simulated for the first time in the area. Thermal simulation shows that the methane source of gas hydrate originated from shallow biogenic gas and deep thermogenic gas. Most areas are dominated by shallow biogenic gas, while, only about 3% of the deep thermogenic gas derived from Enping Formation source rock and contributed to the gas hydrate formation within a few areas in the southeast. The thermogenic gas migrated vertically into the GHSZ through connecting faults, mud diapir, and/or gas chimney to form gas hydrate. The source rocks of the Wenchang Formation, a deep thermogenic gas source, began to enter the main hydrocarbon generation window at 28.4 Ma. The Enping source rock began to generate oil from 25 Ma on and gas from 16 Ma on. Since 5.3 Ma, most areas of the source rocks have generated a gas window, and only the shallower parts in the east still in the oil window, which had lasted until now. The shallow biogenic gas source rocks from the Hanjiang, Yuehai, and Wanshan formations generated gas in different periods, respectively. The Qionghai Formation began to generate hydrocarbon from 0.3 Ma and until now. Other results show that the GHSZ developed mainly during the Quaternary and Neogene (Wanshan Formation) and the GHSZ is thicker in the southern area and thinner in the northern part with a positive correlation with water depth. Starting at 11.6 Ma, the GHSZ developed in the Hanjiang Formation in the south of the Shenhu area and gradually expanded to the north to cover most of the study area at 5.3 Ma during the Yuehai Formation. From 1.8 Ma on, the GHSZ covered the entire study area. At the same time, the GHSZ in the Hanjiang Formation disappeared because of the change in temperature and pressure. At present, the GHSZ in the Yuehai Formation has disappeared, while the Quaternary and Wanshan are the two main formations for GHSZ development. The formation and distribution of gas hydrates are fundamentally controlled by the space-time coupling between the hydrocarbon generation and expulsion time and distribution of the GHSZ. The simulation results of gas hydrate accumulation and distribution were verified by drilling results and the matching rate is 84%. This is the first time that 3D simulation was successfully conducted with PSM technology in the Shenhu area and it provides important guidance for gas hydrate study in other areas of the SCS. Full article

(This article belongs to the Special Issue Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media)

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17 pages, 3708 KiB

Open AccessArticle

Numerical Simulation of Gas Production and Reservoir Stability during CO₂ Exchange in Natural Gas Hydrate Reservoir

by Qingping Li, Shuxia Li, Shuyue Ding, Zhenyuan Yin, Lu Liu and Shuaijun Li

Energies 2022, 15(23), 8968; https://doi.org/10.3390/en15238968 - 27 Nov 2022

Cited by 5 | Viewed by 1679

Abstract

The prediction of gas productivity and reservoir stability of natural gas hydrate (NGH) reservoirs plays a vital role in the exploitation of NGH. In this study, we developed a THMC (thermal-hydrodynamic-mechanical-chemical) numerical model for the simulation of gas production behavior and the reservoir response. The model can describe the phase change, multiphase flow in porous media, heat transfer, and deformation behavior during the exploitation of NGH reservoirs. Two different production scenarios were employed for the simulation: depressurization and depressurization coupled with CO₂ exchange. The simulation results suggested that the injection of CO₂ promotes the dissociation of NGH between the injection well and the production well compared with depressurization only. The cumulative production of gas and water increased by 27.88% and 2.90%, respectively, based on 2000 days of production simulation. In addition, the subsidence of the NGH reservoir was lower in the CO₂ exchange case compared with the single depressurization case for the same amount of cumulative gas production. The simulation results suggested that CO₂ exchange in NGH reservoirs alleviates the issue of reservoir subsidence during production and maintains good reservoir stability. The results of this study can be used to provide guidance on field production from marine NGH reservoirs. Full article

(This article belongs to the Special Issue Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media)

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18 pages, 4246 KiB

Open AccessArticle

An Experimental and Numerical Study of Abrupt Changes in Coal Permeability with Gas Flowing through Fracture-Pore Structure

by Lin Li, Shufan Zhang, Zhiqiang Li, Xiangjun Chen, Lin Wang and Shuailong Feng

Energies 2022, 15(21), 7842; https://doi.org/10.3390/en15217842 - 22 Oct 2022

Cited by 1 | Viewed by 1160

Abstract

Coal permeability is related to the fracture-pore structure of coal and is a key factor in determining gas drainage efficiency. The characteristics of the methane flow in coal fractures are different from those in coal matrix pores. However, due to the difficulty of observing fast methane flow in coal fractures, the effect of gas flow in coal fractures on coal permeability has seldom been considered and investigated. In this study, a cylindrical coal sample is used for the measurement of coal permeability under different gas pressures, and an abrupt change in coal permeability evolution was observed. Then, a tandem fracture-pore permeability model was adopted to analyze these new methane flow phenomena. In this permeability model, the deformation of coal fractures was directly analyzed and modeled without the reversed derivation. With the consideration of elastic modulus of coal fractures, the deformation of coal fractures is controlled by the effective strain of coal fractures, the adsorption-induced strain and effective strain of coal matrix. The research results show that (1) coal fractures quickly and significantly influence coal permeability by resisting coal deformation; (2) a complete evolution of coal permeability consists of the fast permeability change caused by methane flow in coal fractures and the slow permeability change caused by methane flow in coal matrix; (3) the low efficiency of gas mass exchange between coal fractures and coal matrix leads to a two-stage evolution for gas desorption flow and coal permeability. Full article

(This article belongs to the Special Issue Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media)

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25 pages, 10537 KiB

Open AccessArticle

Numerical Simulation of Coastal Sub-Permafrost Gas Hydrate Formation in the Mackenzie Delta, Canadian Arctic

by Zhen Li, Erik Spangenberg, Judith M. Schicks and Thomas Kempka

Energies 2022, 15(14), 4986; https://doi.org/10.3390/en15144986 - 7 Jul 2022

Cited by 4 | Viewed by 1634

Abstract

The Mackenzie Delta (MD) is a permafrost-bearing region along the coasts of the Canadian Arctic which exhibits high sub-permafrost gas hydrate (GH) reserves. The GH occurring at the Mallik site in the MD is dominated by thermogenic methane (CH₄), which migrated from deep conventional hydrocarbon reservoirs, very likely through the present fault systems. Therefore, it is assumed that fluid flow transports dissolved CH₄ upward and out of the deeper overpressurized reservoirs via the existing polygonal fault system and then forms the GH accumulations in the Kugmallit–Mackenzie Bay Sequences. We investigate the feasibility of this mechanism with a thermo–hydraulic–chemical numerical model, representing a cross section of the Mallik site. We present the first simulations that consider permafrost formation and thawing, as well as the formation of GH accumulations sourced from the upward migrating CH₄-rich formation fluid. The simulation results show that temperature distribution, as well as the thickness and base of the ice-bearing permafrost are consistent with corresponding field observations. The primary driver for the spatial GH distribution is the permeability of the host sediments. Thus, the hypothesis on GH formation by dissolved CH₄ originating from deeper geological reservoirs is successfully validated. Furthermore, our results demonstrate that the permafrost has been substantially heated to 0.8–1.3 °C, triggered by the global temperature increase of about 0.44 °C and further enhanced by the Arctic Amplification effect at the Mallik site from the early 1970s to the mid-2000s. Full article

(This article belongs to the Special Issue Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media)

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18 pages, 3724 KiB

Open AccessArticle

Application of Machine Learning in Predicting Formation Condition of Multi-Gas Hydrate

by Zimeng Yu and Hailong Tian

Energies 2022, 15(13), 4719; https://doi.org/10.3390/en15134719 - 28 Jun 2022

Cited by 8 | Viewed by 1827

Abstract

Thermodynamic models are usually employed to predict formation condition of hydrates. However, these thermodynamic models usually require a large amount of calculations to approach phase equilibrium. Additionally, parameters included in the thermodynamic model need to be calibrated based on the experimental data, which leads to high uncertainties in the predicted results. With the rapid development of artificial intelligence (AI), machine learning as one of sub-discipline has been developed and been widely applied in various research area. In this work, machine learning was innovatively employed to predict the formation condition of natural gas hydrates to overcome the high computation cost and low accuracy. Three data-driven models, Random Forest (RF), Naive Bayes (NB), Support Vector Regression (SVR) were tentatively used to determine the formation condition of hydrate formed by pure and mixed gases. Experimental data reported in previous work were taken to train and test the machine learning models. As a representative thermodynamic model the Chen–Guo (C-G) model was used to analyze the computational efficiency and accuracy of machine learning models. The comparison of results predicted by C-G model and machine learning models with the experimental data indicated that the RF model performed better than the NB and SVR models on both computation speed and accuracy. According to the experimental data, the average AADP calculated by the C-G model is 7.62 times that calculated by the RF model. Meanwhile, the average time costed by the C-G model is 75.65 times that by the RF model. Compared with the other two machine learning models, the RF model is expected to be used in predicting the formation condition of natural gas hydrate under field conditions. Full article

(This article belongs to the Special Issue Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media)

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29 pages, 11566 KiB

Open AccessArticle

Numerical Simulation of Hydrate Decomposition during the Drilling Process of the Hydrate Reservoir in the Northern South China Sea

by Lei Zhang, Yu Zhang, Chang Chen, Xiao-Sen Li and Zhao-Yang Chen

Energies 2022, 15(9), 3273; https://doi.org/10.3390/en15093273 - 29 Apr 2022

Cited by 3 | Viewed by 1337

Abstract

The process of drilling in natural gas hydrate reservoirs in sea areas involves problems such as hydrate decomposition and wellbore instability. To study the response behaviors of a reservoir during the drilling process, a two-dimensional numerical model of drilling fluid invading a hydrate reservoir in a cylindrical coordinate system was established to simulate the processes of heat and mass transfer, gas–liquid two-phase flow, and hydrate formation and decomposition in the hydrate reservoir during the drilling process. Based on the hydrate reservoir at station W17, Shenhu area of the South China Sea, the physical property response of the hydrate reservoir under different drilling fluid temperatures and salinity values was studied. The simulation results showed that during the drilling process, the temperature and pressure of the reservoir respond rapidly in a large area, further promoting the hydrate decomposition in the reservoir around the wellbore and leading to secondary hydrate formation. Moreover, a high hydrate saturation zone appears near the decomposed hydrate area in the layer without free gas, which corresponds to the low water saturation and high salinity zone. The hydrate decomposition area in the layer with free gas is larger than that without free gas. The increase in the drilling fluid temperature significantly enhances the hydrate decomposition in both layers of the reservoir. The hydrate decomposition near the wellbore under the high drilling fluid temperature will cause a sharp increase in the pressure in the reservoir, leading to the flow of pore fluid into the wellbore. The increase in drilling fluid salinity has little effect on the range of the hydrate decomposition in the reservoir but significantly increases the salinity of the pore water in the layer with free gas. As the drilling fluid temperature increases, the possibility of the gas invasion from the reservoir into the wellbore will be greatly increased at the early stage. Full article

(This article belongs to the Special Issue Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media)

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Review

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65 pages, 18537 KiB

Open AccessReview

Permeability Models of Hydrate-Bearing Sediments: A Comprehensive Review with Focus on Normalized Permeability

by Jianchun Xu, Ziwei Bu, Hangyu Li, Xiaopu Wang and Shuyang Liu

Energies 2022, 15(13), 4524; https://doi.org/10.3390/en15134524 - 21 Jun 2022

Cited by 6 | Viewed by 1874

Abstract

Natural gas hydrates (NGHs) are regarded as a new energy resource with great potential and wide application prospects due to their tremendous reserves and low CO₂ emission. Permeability, which governs the fluid flow and transport through hydrate-bearing sediments (HBSs), directly affects the fluid production from hydrate deposits. Therefore, permeability models play a significant role in the prediction and optimization of gas production from NGH reservoirs via numerical simulators. To quantitatively analyze and predict the long-term gas production performance of hydrate deposits under distinct hydrate phase behavior and saturation, it is essential to well-establish the permeability model, which can accurately capture the characteristics of permeability change during production. Recently, a wide variety of permeability models for single-phase fluid flowing sediment have been established. They typically consider the influences of hydrate saturation, hydrate pore habits, sediment pore structure, and other related factors on the hydraulic properties of hydrate sediments. However, the choice of permeability prediction models leads to substantially different predictions of gas production in numerical modeling. In this work, the most available and widely used permeability models proposed by researchers worldwide were firstly reviewed in detail. We divide them into four categories, namely the classical permeability models, reservoir simulator used models, modified permeability models, and novel permeability models, based on their theoretical basis and derivation method. In addition, the advantages and limitations of each model were discussed with suggestions provided. Finally, the challenges existing in the current research were discussed and the potential future investigation directions were proposed. This review can provide insightful guidance for understanding the modeling of fluid flow in HBSs and can be useful for developing more advanced models for accurately predicting the permeability change during hydrate resources exploitation. Full article

(This article belongs to the Special Issue Advances in Coupled Numerical Simulation of Gas Hydrate Behaviour in Porous Media)

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