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Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (31 October 2023) | Viewed by 13723

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Dr. Yong Li

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College of Geosciences and Surveying Engineering, China University of Mining and Technology (Beijing), Beijing, China
Interests: coal and coalbed methane; unconventional natural gas/oil resources; sedimentology
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Prof. Dr. Fan Cui

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College of Geosciences and Surveying Engineering, China University of Mining and Technology (Beijing), Beijing 100083, China
Interests: applied geophysics; ground penetrating radar method and technology; 3D seismic inversion of coalfield; basic research on transparent mine technology
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Dr. Chao Xu

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School of Emergency Management and Safety Engineering, China University of Mining and Technology (Beijing), Beijing 100083, China
Interests: coalbed methane geology; rock mechanics; multi-physics coupling; coalbed methane drainage and technology; coal mine methane drainage and technology
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Dr. Liu Yang

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Guest Editor

State Key Laboratory for GeoMechanics and Deep Underground Engineering, China University of Mining and Technology (Beijing), Beijing 100083, China
Interests: imbibition; mutlphase flow in porous media; hydraulic fracturing; rock mechanics
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Special Issue Information

Dear Colleagues,

Global demand for energy, directives to reduce carbon dioxide emissions, and technological advancements in horizontal drilling and hydraulic fracturing have spurred a rapid increase in alternative and unconventional energy production over the past decade. The application of new technologies has enabled natural gas and shale oil to be economically produced from shale and other unconventional formations. Further, various methods have been adopted to improve gas recovery, including but not limited to high-precision characterization of coal and shale reservoirs at multiscales, fast drilling and completion of wells with long laterals as well as large-scale volume fracturing, and new technologies such as multiple well-type development, fluid injection, nano-flooding, and enhancing biogenic methane generation methods.

The aim of this Special Issue is to report on the state of the art in fundamental discipline application to methane production and associated challenges in geoengineering activities. We are particularly interested in the three levels of methane and other hydrocarbon production issues, geological and hydrological controls on the accumulation of hydrocarbon, coupled thermal-hydromechanical–chemical processes influencing methane migration, and new technologies and related field tests applied in hydrocarbon production in coal mines and oil fields. We hope to focus both on progress in new methods and on new technique development. We welcome both original research and review articles

Dr. Yong Li
Prof. Dr. Fan Cui
Dr. Chao Xu
Dr. Liu Yang
Guest Editors

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Keywords

fundamental research in geology, geomechanics, and geofluids
coal mine safety issues and methane extraction advances
real-time detection technology of mine disaster source
recovery mechanisms of oil and gas from heterogeneous reservoirs
enhanced oil/gas production using CO₂, N₂, and other mixed gases
numerical and analytical modeling in predicting production performance
advances in the use of artificial intelligence for the development of geofluid resources

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Published Papers (9 papers)

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Research

18 pages, 6312 KiB

Open AccessArticle

Geochemical Properties and Gas-Bearing Analysis of Lower Cambrian Black Shale in Western Hunan Province

by Kaixun Zhang, Xiaoyin Tang, Xiaoqiang Liu, Zisheng Zhao and Meijun Li

Energies 2024, 17(7), 1743; https://doi.org/10.3390/en17071743 - 4 Apr 2024

Cited by 1 | Viewed by 1196

Abstract

Western Hunan province and its surrounding areas are significant targets for shale gas exploration and development in southern China, where the black shale of the lower Cambrian Niutitang Formation and Wunitang Formation is extensively distributed. Geochemical analysis was conducted on the lower Cambrian black shale from a new exploration well of XAD1 located at the southeast margin of the Yangtze paraplatform, followed by a discussion on gas-bearing properties using molecular dynamics simulation. The geochemical characteristics indicate that the black shale in well XAD1 was primarily deposited in a strongly reducing marine environment, with organic matter predominantly composed of type I kerogen derived from algae. Currently, it has reached a stage of high to over maturity with limited potential for liquid hydrocarbon generation. The recovery of the original hydrocarbon generation potential shows that they are excellent source rocks and have completed the main hydrocarbon generation evolution. Despite the favorable conditions for shale gas formation observed in well XAD1, the low measured gas content within the Niutitang Formation suggests that other geological factors may have contributed to a substantial loss of shale gas. Gas adsorption simulation reveals that the maximum methane adsorption capacity (15.77 m³/t) was achieved by Niutitang shale during the late Silurian period when there was an abundant source of natural gas without any influence from CO₂, H₂O or other molecules. However, due to a lack of natural gas replenishment and subsequent tectonic uplift and subsidence causing variations in temperature and pressure, the methane adsorption capacity gradually decreased (to 6.56 m³/t). Furthermore, water occurrence within the shale reservoir further reduced the methane adsorption capacity (below 2 m³/t), while tectonic activities exacerbated the loss of shale gas potential within this study area. The findings indicate that the dynamic alteration of gas-bearing properties in shale reservoirs due to tectonic movements is a crucial factor influencing the success rate of shale gas exploration in the study area, provided that there are sufficient gas resources and superior reservoir conditions. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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14 pages, 3873 KiB

Open AccessArticle

Research on the Shale Porosity–TOC Maturity Relationship Based on an Improved Pore Space Characterization Method

by Jianbin Zhao, Shizhen Ke, Weibiao Xie, Zhehao Zhang, Bo Wei, Jinbin Wan, Daojie Cheng, Zhenlin Li and Chaoqiang Fang

Energies 2024, 17(5), 997; https://doi.org/10.3390/en17050997 - 20 Feb 2024

Cited by 1 | Viewed by 1125

Abstract

Shale pore structure characterization is key to shale reservoir evaluation, sweet spot selection, and economic exploitation. It remains a challenge to accurately characterize shale micro-nano pores. Common experimental characterization methods for shale pore systems are listed, and advantages and weaknesses of each method are analyzed. An improved pore structure characterization method for shale is proposed by combining Helium and NMR. The new method does not affect shale samples and has a higher accuracy. The affecting factors for shale pore evolution for shale are also discussed, showing that organic matter content and maturity are key factors in total porosity development. Furthermore, a shale porosity–TOC maturity relationship chart is developed based on the experimental data of shale samples selected from six shale reservoirs. The application of this chart in Well X in the Gulong field of Songliao Basin proves its utility in evaluating shale reservoirs. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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18 pages, 5625 KiB

Open AccessArticle

Permeability Evolution of Bituminous Coal and Its Dynamic Control, a Case Study from the Southeastern Ordos Basin, China

by Yongkai Qiu, Dingjun Chang, Fengrui Sun, Abulaitijiang Abuduerxiti and Yidong Cai

Energies 2023, 16(24), 8046; https://doi.org/10.3390/en16248046 - 13 Dec 2023

Viewed by 725

Abstract

Coalbed methane (CBM) reservoirs’ permeability is the result of dynamic variations influenced by tectonics, hydrology and the CBM production process. Taking samples from the southeastern Ordos Basin, China, the permeability evolution of bituminous coal and its control were analyzed in three steps: (1) the coal fracture permeability evolution was acquired via X-ray CT scanning and permeability evolution experiments; (2) the permeability variation was determined while considering the coupling characteristics effective stress, gas slippage, and matrix shrinkage effect and its influencing factors; and (3) a dynamic permeability model was built while considering those effects. For samples in which neither fractures nor bedding developed, the permeability decreased first and then increased as the gas pressure increased. For samples with fractures that developed parallel to the axial direction, with a gradual increase in gas pressure, the permeability also increased. As the gas pressure decreased, the matrix shrinkage effect became positive, resulting in a permeability increase. The gas slippage effect was positive in the low-pressure stage, which also resulted in a permeability increase. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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14 pages, 2839 KiB

Open AccessArticle

Experimental Study on the Influence of Wettability Alteration on Gas–Water Two-Phase Flow and Coalbed Methane Production

by Aoxiang Zhang, Longyong Shu and Zhonggang Huo

Energies 2023, 16(15), 5756; https://doi.org/10.3390/en16155756 - 2 Aug 2023

Cited by 1 | Viewed by 1448

Abstract

The surface wettability is important in the change in the relative permeability of gas and water. Due to the heterogeneous property of coal, it has a mixed wetting state, which makes it difficult to predict the change in permeability. To investigate the influence of different wettabilities on two-phase flow, a total of three different rank coal samples were collected and were treated with different chemicals. The alteration of the coal’s wettability, characteristics of gas–water flow, and relative permeability of the coal after the chemical treatments were analyzed. The research conclusions suggest that (1) the coal samples treated with SiO₂ and H₂O₂ increased the hydrophilicity of the coal surface, while the coal samples treated with DTAB increased the hydrophobicity of the coal surface. Compared to SiO₂, both H₂O₂ and DTAB can form a uniform wetting surface. (2) The wettability alteration mechanism among the three different chemical reagents is different. (3) All the chemicals can change the gas–water interface. The water migrates more easily through the cleats after H₂O₂ treatment, while it is more difficult for the water to migrate through cleats after the DTAB treatment. (4) There are two types of flow states of gas and water on different wetting surfaces. A slug flow is formed on a hydrophilic surface, while an annular flow is formed on a hydrophobic surface. (5) The crossover point and the residual water saturation of the relative permeability curves were influenced by the surface wettability. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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19 pages, 7560 KiB

Open AccessArticle

Geochemical and Microstructural Characteristics of Clay Minerals and Their Effects on the Pore Structure of Coal-Measure Shale: A Case Study in Qinshui Basin, China

by Kunjie Li, Shaoqi Kong, Yanxia Liang, Muhammad Ali, Yongfa Zhang and Yuqiong Zhao

Energies 2023, 16(9), 3804; https://doi.org/10.3390/en16093804 - 28 Apr 2023

Viewed by 1395

Abstract

As the essential component of shale, clay minerals have a vital influence on the pore structure and the gas content of reservoirs. To investigate the compositional characteristics of coal-measure shale and its effects on pore structure, a total of thirteen Taiyuan formation shale samples were collected from the Qinshui Basin and were analyzed using a combination of X-ray diffraction analysis, X-ray fluorescence spectrometry, Fourier transform infrared spectroscopy (FE-SEM), polarized optical microscopy, and field emission scanning electron microscopy. The results show that the principal minerals of the samples are quartz, kaolinite, and illite. Most of the kaolinite was an original terrigenous detrital material with low crystallinity and a low degree of ordering, whereas the illite was mainly composed of 1M_d resulting from diagenesis. Clay minerals developed slits, irregularly-shaped or multisized pores during diagenesis, which can be classed into interlayered pores, intergranular pores, and microfractures. Eight micro-morphological forms of clay minerals were summarized based on FE-SEM observations, such as compacted, parallel, bent, tilted, mutually supporting structures, etc., which are mainly formed by the mechanical compaction of clay minerals with different sizes, shapes, and contact relationships. The diversity and complexity of the micro-morphological forms of clay minerals contribute to the strong heterogeneity, low porosity and high permeability anisotropy of shale. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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14 pages, 3024 KiB

Open AccessArticle

Experimental Study on Coal Seam Gas Desorption Characteristics Caused by Moisture under Stepwise Depressurization

by Xinjian Li, Xiangjun Chen, Lin Wang, Haoyang Shi and Tongyong Yu

Energies 2023, 16(8), 3566; https://doi.org/10.3390/en16083566 - 20 Apr 2023

Viewed by 1212

Abstract

Expansion energy is the main factor of coal and gas outbursts, and the gas desorption around the outburst hole is developed in variable pressure conditions. While studying the impact of moisture on gas desorption characteristics, atmospheric pressure desorption is usually used, but its characteristics under variable pressure conditions have not been thoroughly investigated. In this study, typical outburst coal samples with different water contents from the Jincheng mining area of China were selected as research objects, and the effects of water on gas displacement, desorption, desorption rate, and gas desorption index (K₁) of drilling cuttings under step-by-step depressurization were analyzed by means of stepwise depressurization and atmospheric desorption experiments. The research conclusions suggest that (1) the amount of gas replacement, which augments rapidly during the inception, increases with the growth of water content under the experimental conditions, and then the rate decreases; (2) the gas desorption falls gradually at different depressurization stages when the humidity is constant, while the total desorption and the drop amplitude taper with the increasing water content; (3) the additional water enhances the desorption rate significantly only at the initial stage, but scarcely has an impact later on; and (4) the value of the drilling cuttings’ gas desorption index (K₁) shows a downward trend with the developing humidity in each stage of stepwise depressurization desorption. We take humidity as a variable to simulate the desorption process of coal gas around the hole when coal and gas outbursts occur in the laboratory and study the influence of water on the desorption characteristics under desorption conditions of stepwise depressurization. This provides a reference for the purpose of studying the mechanism of coal and gas outbursts from the perspective of energy. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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15 pages, 2319 KiB

Open AccessArticle

Influence of Supercritical CO₂ Fluid on CH₄ and CO₂ Diffusion in Vitrinite-Rich Coals and Inertinite-Rich Coals

by Wei Li, Weili Lin, Hongfu Liu, Xiaoxia Song and Zhenji Wei

Energies 2023, 16(3), 1432; https://doi.org/10.3390/en16031432 - 1 Feb 2023

Cited by 1 | Viewed by 1710

Abstract

Coal maceral composition has a great effect on gas adsorption and diffusion. The interaction between maceral composition and supercritical CO₂ (SCCO₂) fluid will affect gas diffusion behavior in coals. Thus, the diffusivity derived from adsorption kinetics of CH₄ and CO₂ in vitrinite- and inertinite-rich coals with low-violate bituminous rank collected from the Hancheng mine of the Weibei coalfield pre- and post-SCCO₂ fluid exposure (SFE) were tested at the conditions of 45 °C and 0.9 MPa. In combination with pore distribution and functional group content, the possible mechanism of the alterations in gas diffusion characteristics in coals with various maceral compositions was addressed. The results show that for vitrinite-rich coals, SFE increases the macropore apparent diffusion coefficient of CH₄, while this treatment decreases the micropore apparent diffusion coefficient of CH₄. However, the reverse trend is found for CO₂ diffusion–adsorption rate. For inertinite-rich coals post-SFE, CH₄ diffusion–adsorption rate increases, while an increase and a decrease in diffusivity CO₂ occur for macropore and micropore, respectively. Generally, SFE shows a stronger impact on CO₂ adsorption rate than CH₄ in coals. The results suggest that the diffusion of CH₄ and CO₂ in coals with different maceral compositions show selectivity to SCCO₂ fluid. The possible reason can be attributed to the changes in pore structure and surface functional group content. SFE causes an increase in macro/mesopore volume of all samples. However, SFE induces a reduction in oxygen-containing species content and micropore volume of inertinite-rich coals, while the opposite trend occurs in vitrinite-rich coals. Thus, the changes in pore volume and surface functional group account for the difference in gas diffusivity of coals with different maceral compositions. With regard to the micropore diffusion–adsorption behavior of CH₄ and CO₂, the impact of oxygen-containing species is superior to pore volume. The oxygen-containing species favor CO₂ diffusion–adsorption but go against CH₄ transport. This effect accounts for the reduction in the micropore diffusion–adsorption rate of CH₄ and the increase in micropore diffusivity of CO₂ in vitrinite-rich coals, respectively. However, the aforementioned effect is the opposite for inertinite-rich coals. Overall, the changes in gas diffusion in coals with different maceral composition during the CO₂-ECBM process requires further attention. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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20 pages, 4643 KiB

Open AccessArticle

Analytical Model for the Pressure Performance Analysis of Multi-Fractured Horizontal Wells in Volcanic Reservoirs

by Junqiang Wang, Xiaolong Qiang, Zhengcheng Ren, Hongbo Wang, Yongbo Wang and Shuoliang Wang

Energies 2023, 16(2), 879; https://doi.org/10.3390/en16020879 - 12 Jan 2023

Cited by 2 | Viewed by 1407

Abstract

Multi-fractured horizontal well (MFHW) technology is a key technology for developing unconventional reservoirs, which can generate a complex fracture network called a stimulated reservoir volume (SRV). Currently, there are many relative analytical models to describe the fluid seepage law, which are not suitable for volcanic reservoirs as of yet. The reasons are as follows: (1) due to the development of natural fractures, multi-scaled flow (matrix, natural fractures, SRV) should be considered to characterize MFHW flow in volcanic reservoirs; (2) non-Darcy flow and stress sensitivity should be considered simultaneously for seepage in volcanic reservoirs. Thus, this paper presents a novel MFHW analysis model of volcanic reservoirs that uses a multi-scale dual-porosity medium model and complex flow mechanisms. Laplace transformation, the Duhamel principle, the perturbation method and Stehfest numerical inversion are employed to solve the model to obtain dynamic pressure response curves. The results show that the pressure response curve can be divided into eight stages. Sensitivity analysis shows that the parameters of hydraulic fractures mainly affect the early flow stage. The parameters of the SRV region mainly affect the middle flow stage. The parameters of unreconstructed regions, non-Darcy flow and stress sensitivity mainly affect the late flow stage. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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16 pages, 2872 KiB

Open AccessArticle

Time-Series Well Performance Prediction Based on Convolutional and Long Short-Term Memory Neural Network Model

by Junqiang Wang, Xiaolong Qiang, Zhengcheng Ren, Hongbo Wang, Yongbo Wang and Shuoliang Wang

Energies 2023, 16(1), 499; https://doi.org/10.3390/en16010499 - 2 Jan 2023

Cited by 2 | Viewed by 2590

Abstract

In the past, reservoir engineers used numerical simulation or reservoir engineering methods to predict oil production, and the accuracy of prediction depended more on the engineers’ own experience. With the development of data science, a new trend has arisen to use deep learning to predict oil production from the perspective of data. In this study, a hybrid forecasting model (CNN-LSTM) based on a convolutional neural network (CNN) and a Long Short-Term Memory (LSTM) neural network is proposed and used to predict the production of fractured horizontal wells in volcanic reservoirs. The model solves the limitation of traditional methods that rely on personal experience. First, the production constraints and production data are used to form a feature space, and the abstract semantics of the feature time series are extracted through convolutional neural network, then the LSTM neural network is used to predict the time series. The certain hyperparameters of the whole model are optimized by Particle Swarm Optimization algorithm (PSO). In order to estimate the model, some production dynamics from the Xinjiang oilfield of China are used for comparative analysis. The experimental results show that the CNN-LSTM model is superior to traditional neural networks and conventional decline curves. Full article

(This article belongs to the Special Issue Advances in Methane Production from Coal, Shale and Other Tight Rocks 2023)

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