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Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas

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A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Chemical Processes and Systems".

Deadline for manuscript submissions: 30 November 2024 | Viewed by 5298

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Dr. Junjian Zhang

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College of Earth Sciences & Engineering, Shandong University of Science and Technology, Qingdao 266590, China
Interests: unconventional resource; methane adsorption; molecular structure
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Dr. Fangkai Quan

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School of Safety Science and Engineering, Anhui University of Science and Technology, Huainan 232001, China
Interests: methane desorption; reservoir simulation; methane extraction

Dr. Xuanxuan Chu

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School of Ocean Engineering, Harbin Institute of Technology, Weihai 264209, China
Interests: unsaturated soil mechnics; offshore geotechnical engineering

Special Issue Information

Dear Colleagues,

The drainage of coal-measure gas, represented by deep coalbed methane, has made significant progress. The daily production of deep coalbed methane in the Ordos Basin of China has exceeded 100000 m³/d, indicating that its development has excellent prospects. The purpose of this Special Issue is to summarize the current theory of deep coalbed methane accumulation and enrichment and clarify the respective laws. Meanwhile, due to the accuracy of the instruments currently used as well as the high temperature and pressure conditions, the physical parameters of deep coal seams cannot be directly obtained. Therefore, this Special Issue aims to summarize and clarify methods for predicting and evaluating the physical and gas properties of deep coal reservoirs and seams. In addition, advanced theories of deep coalbed methane development technology require summation.

Dr. Junjian Zhang
Dr. Fangkai Quan
Dr. Xuanxuan Chu
Guest Editors

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Keywords

deep coal seam
coal reservoirs
physical properties
development technology
predictive evaluation

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Published Papers (10 papers)

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Research

15 pages, 8119 KiB

Open AccessArticle

Fracture Properties of Nitrogen–Slick Water Composite Fracturing in Coal Reservoir

by Menglong Wang, Lin Tian, Jinghao Wu, Yunxing Cao, Li Wang, Bin Shi, Mingyue Sun, Shimin Liu and Yunbing Hu

Processes 2024, 12(9), 1949; https://doi.org/10.3390/pr12091949 - 11 Sep 2024

Abstract

Nitrogen–slick water composite fracturing is a novel, recently developed fracturing technology. Due to its impact on increasing permeability, this technology outperforms hydraulic fracturing. This study adopted the horizontal well XJ-1L, Xinjing coal mine, Qinshui Basin, China, as a study area to statistically analyze the fracture properties, stress drop, and b-value distribution characteristics of 1217 effective micro-seismic events generated during nitrogen–water composite fracturing. The results show that: (1) gradually reducing the proportion of gas in fracturing fluid reduced the proportion of tensile fractures at a ratio of between 15.6% and 0.8%, whereas the proportion of strike-slip fractures gradually increased by between 1.6% and 15.2%; (2) the stress drop and b-values in the nitrogen fracturing (NF) stage, representative of stress disturbance, exceeded those in the hydraulic fracturing (HF) stage, consistent with greater numbers of tensile fractures formed in the NF stage; (3) the greater number of tensile fractures and their increasing permeability could be explained based on the influences of gas compressibility and pore pressure on coal fractures. This study provides a theoretical and practical basis for optimizing the exploitation of low-permeability coal reservoirs. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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16 pages, 5406 KiB

Open AccessArticle

Re-Calibrating the Mercury-Intrusion-Porosimetry-Measured Pore Size Distribution of Coals: A Novel Method for Calculating the Matrix Compression Coefficient

by Bin Ren, Sijian Zheng, Lihua Ping, Meng Wang, Xuguang Dai, Yanzhi Liu, Shen Xu and Xiuping Wu

Processes 2024, 12(9), 1928; https://doi.org/10.3390/pr12091928 - 8 Sep 2024

Abstract

Accurate measurement of the pore size distribution (PSD) in coals is crucial for guiding subsequent coalbed methane (CBM) engineering practice. Currently, mercury intrusion porosimetry (MIP) measurement has been widely used as a PSD testing method due to its effectiveness and convenience. Nevertheless, it is worth noting that the elevated pressure during the MIP experiments can lead to matrix compressibility, potentially causing inaccurate estimations of PSD in coals. Therefore, correction methods are used to modify the PSD in the high-pressure segment to improve the accuracy of MIP data. This study proposed a novel method with higher accuracy and convenience for calculating the matrix compressibility coefficient compared to the traditional calculation methods. Firstly, the matrix compressibility coefficients of six coal samples were calculated by using low-temperature nitrogen adsorption (LTNA) data. Subsequently, by utilizing the mathematical correlation between K_c (the compressibility coefficient of the coal matrix) and R_o,max (the maximum vitrinite reflectance) from prior research, a novel statistical method was designed to determine the matrix compressibility coefficient of the samples. Finally, the statistical matrix compressibility coefficient determination method was used to examine the fractal characteristics of the actual PSD. The results indicate that when the pressure exceeds 24 MPa, the volume obtained from mercury intrusion exceeds the pore volume measurement. The K_c calculated using the traditional correction method is in the range of 0.876–1.184 × 10⁻¹⁰ m²/N, while the K_c values of our proposed statistical correction method range from 0.898 × 10⁻¹⁰ to 1.233 × 10⁻¹⁰ m²/N, with a comparison error rate of ~0.11–5.25%. The MIP data greater than 24 MPa were effectively corrected using the statistical correction method, thus reducing the mercury intrusion volume error by 91.75–96.40%. Additionally, the corrected pore fractal dimension (D₂) values fall within the range of 2.792 to 2.975, which are closer to the actual values than the pore fractal dimension range of 3.186 to 3.339. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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14 pages, 4268 KiB

Open AccessArticle

The Analysis of Differential Saturation in Shale Oil Accompanied by an Enhanced Classification of Fluid Distribution within the Pore

by Teng Li, Xiaohang Li and Xiulan Zhu

Processes 2024, 12(9), 1870; https://doi.org/10.3390/pr12091870 - 1 Sep 2024

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Abstract

Shale oil saturated by high temperature (20 MPa) and high pressure (60 °C) conditions can not only realize the efficient saturation of shale, but also invert the shale oil return and drainage characteristics under the stratum temperature and pressure due to the heterogeneity of shale formations. In this study, the Chang 7 Member shale samples were collected, and the high-temperature and high-pressure containment device was utilized to saturate the shale oil efficiently under 20 MPa and 60 °C, and the differences of liquid hydrocarbon saturation and the degree of liquid hydrocarbon saturation for different types of pores and fractures in the shale were quantitatively characterized with a low-field nuclear magnetic resonance (NMR) technology. The results show that under the condition of formation temperature (60 °C) and pressure (20 MPa), shale oil saturation can be reached after 14 d of saturation in the shale samples. The shale oil saturation process can be roughly divided into three stages according to the various saturation rates: the rapid saturation stage, the slow saturation stage, and the second rapid saturation stage, and the degree of saturation of shale oil is characterized by a V-shape. The shale oil was distributed into four types of pore-fracture systems: adsorption pores, micropores, seepage fractures, and layer fractures. Additionally, the fluid dominantly distributes in the micropores and seepage fractures, the shale oil saturation degree of the micropores features a continuous increase, while that for the seepage fractures presents a V-shape, which finally determines the shale oil saturation characteristics of the shale. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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21 pages, 5840 KiB

Open AccessArticle

Effects of Compositions and Fractal Pores on CO₂ Adsorption in Lacustrine Shale

by Guangjun Feng, Meng Wang, Yanming Zhu, Yu Song, Sijian Zheng, Xuguang Dai and Xuheng Wang

Processes 2024, 12(9), 1842; https://doi.org/10.3390/pr12091842 - 29 Aug 2024

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Abstract

Lacustrine shale reservoirs hold promise for CO₂ geological sequestration and enhanced shale gas/oil recovery, while the CO₂ adsorption capacity and its controlling factors are still unclear in lacustrine shales. Using a volumetric-based adsorption apparatus, CO₂ adsorption experiments were performed at 50 °C on the Ch7 lacustrine shale samples from the Yanchang Formation in Ordos Basin, China. Basic petro-physical experiments, low-temperature N₂ adsorption, and field emission scanning electron microscopy were used to characterize shale properties and fractal pores in the lacustrine shales. Further, the effects of shale compositions and fractal pores on CO₂ adsorption capacities were serially investigated. The results show that Ch7 lacustrine shales are characterized by being rich in their TOC (total organic carbon) content, high in their clay content, but low in their quartz content, which is distinguished from the mineral compositions in marine shales. The pore size distributions are multi-modal with a main peak and two secondary peaks. Meanwhile, two-regime pore fractal characteristics were identified in the Ch7 lacustrine shales, and the fractal dimensions of the pore surface and spatial structure were calculated based on the FHH (Frenkel–Halsey–Hill) model with D₁ and D₂ ranging from 2.586–2.690 and 2.756–2.855, respectively. CO₂ adsorption isotherms present an initial phase of rapid adsorption followed by a slow saturation and were fitted using the Langmuir model with Langmuir volumes in the range of 2.16–6.89 cm³/g for Ch7 lacustrine shales. TOC is crucial for enhancing the CO₂ adsorption capacity, whereas the effect of clays on CO₂ adsorption is complex because of the reverse effects of clay-related pores and other pores filled by clays. Micropores (<2 nm) dominate the CO₂ adsorption capacity because they offer a larger unit-specific surface area and possess a higher adsorption potential compared to meso- (2–50 nm) and macro- (>50 nm) pores. Moreover, the D₁ is positively related to the CO₂ adsorption capacity as a larger D₁ coincides with more heterogeneous fractal pore surfaces and more available locations for CO₂ adsorption. This work provides useful knowledge and important data for estimating the CO₂ geological storage potential in lacustrine shale reservoirs. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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13 pages, 3205 KiB

Open AccessArticle

Method for Predicting Bound Water Saturation in Tight Sandstone Reservoirs Using Morphology and Fractal Models

by Di Zhang, Tian Tian, Yong Shi, Yaomiao He, Junjian Zhang and Zhenyuan Qin

Processes 2024, 12(9), 1811; https://doi.org/10.3390/pr12091811 - 26 Aug 2024

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Abstract

The nuclear magnetic resonance T₂ spectrum was used to identify the T_2 cut-off value, which is the key to determining the irreducible water saturation of a reservoir. In this paper, the saturation and centrifugal T₂ spectra of sandstone and coal samples were used to explore the correlation between each parameter and the T_2 cut-off value, using a single fractal dimension, a multifractal dimension and a spectral morphology discrimination method. The conclusions are as follows: (1) The T₂ spectra of nine sandstone samples in this paper can be divided into four types. Type A is represented by sample 2, wherein the T₂ spectrum shows a bimodal state and the area of the right T₂ spectrum (2.5~100 ms) is larger than that of the left T₂ spectrum (T₂ < 2.5 ms), indicating that the sample has good pore connectivity and belongs to the macroporous development sample. The B-type T₂ spectrum is unimodal, and the pore connectivity is poor, indicating that it is a large-pore development sample. The T₂ spectrum of the C-type sample is unimodal, and the pore connectivity is very poor, indicating that it is a mesoporous development sample. The T₂ spectrum of the D-type sample shows a single peak state, and the main T₂ is distributed within 0.1~2.5 ms. The pore connectivity is very poor, which indicates that it belongs to the small pore development type sample. (2) The single fractal model shows that, compared with other single fractal parameters, D₂ increases with the increase in the T_2 cut-off value, but the correlation is weak. Therefore, it is not feasible to predict the T_2 cut-off value using the single fractal dimension parameter. (3) The multifractal model shows that D₋₁₀–D₁₀ increases linearly with the increase in D₋₁₀–D₀, but there is no obvious linear correlation between D₀–D₁₀ and D₋₁₀–D₁₀, indicating that the low pore volume area in this kind of sample controls the overall heterogeneity of pore distribution. (4) The related parameters affecting the T_2 cut-off value include D₋₁₀–D₁₀, D₋₁₀/D₁₀, D₋₁₀–D₀, T_M and D₂. Therefore, based on the above five parameters, a T_2 cut-off value prediction model is constructed. The T_2 cut-off value calculated by the model is highly consistent with the experimental value, which proves the reliability of the model. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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12 pages, 4613 KiB

Open AccessArticle

The Strike-Slip Fault System and Its Influence on Hydrocarbon Accumulation in the Gudong Area of the Zhanhua Depression, Bohai Bay Basin

by Hongke Zhou, Qunhu Wu, Zhiwei Wang, Fei Teng, Genhou Guo, Zunxiang Zhang, Yanjia Wu and Yanjun Cheng

Processes 2024, 12(8), 1750; https://doi.org/10.3390/pr12081750 - 20 Aug 2024

Viewed by 362

Abstract

The Gudong area contains abundant petroleum resources. Previous studies have mainly focused on the extension structure in this area, with its strike-slip characteristics remaining poorly understood. In this study, the geometry of the strike-slip faults in the Gudong area was investigated using high-resolution 3D seismic reflection and drilling data, as were their associated releasing and restraining structures. Based on the profile’s flower structure and the plane’s horsetail splay pattern, the Gudong fault in the study area can be characterized as a dextral strike-slip. Three types of strike-slip fault-associated structures can be identified in the study area: (a) a restraining bend occurring in the right-stepping area of the S-shaped Gudong strike-slip fault, (b) a restraining bend identified in the left-stepping, overlapping zone of the Gudong and Kendong faults, and (c) a releasing bend seen in the extensional horsetail splay structure at the southern end of the Gudong fault. The restraining stress induced the formation of a fault-related open anticline, which led to a significant increase in fault sealing efficiency, thereby preserving an estimated 75.479231 million tons of oil and 15.28317145 billion cubic meters of gas. Conversely, releasing transtensional stress has compromised the effectiveness of the traps, preventing hydrocarbon retention. Consequently, oil and gas have migrated upward along the horsetail faults to the top of Cenozoic formations and have then dispersed. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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15 pages, 12040 KiB

Open AccessArticle

Geological Conditions of Shale Gas Accumulation in Coal Measures

by Fengchu Liao, Keying Wang, Jian Zhan, Zhiwei Liu, Jiang Du, Shuhua Gong, Ningbo Cai, Jianglun Bai and Junjian Zhang

Processes 2024, 12(8), 1734; https://doi.org/10.3390/pr12081734 - 18 Aug 2024

Viewed by 290

Abstract

The shale of different potential layers is studied by using rock pyrolysis analysis, total organic carbon determination (TOC), kerogen microscopic component identification, mineral X-ray diffraction, scanning electron microscopy, and low-temperature nitrogen adsorption experiments. The results are as follows: (1) Shishui Formation of the Lower Carboniferous and Longtan Formation of the Upper Permian are the two most important shale gas reservoirs in the Chenlei Depression. The sedimentary environment of the target shale is a marine land interaction facies coastal bay lagoon swamp sedimentary system. Two sedimentary facies of tidal flat facies, subtidal zone, and lagoon swamp facies are developed. (2) The organic matter types of shale are Type III and II₂, with TOC content greater than 1%. The maturity of shale samples is relatively higher (R_o,max is above 2%), which means they have entered the stage of large-scale gas generation. The overall brittle mineral content of the target shale sample is relatively higher (above 40%), which is conducive to artificial fracturing and fracture formation in the later stage, while an appropriate amount of clay minerals (generally stable at 40%) is conducive to gas adsorption. (3) The overall pore structure of the water measurement group and Longtan group is good, with a higher specific surface area and total pore volume (average specific surface area is 12.21 and 8.36 m²/g, respectively), which is conducive to the occurrence of shale gas and has good adsorption and storage potential. The gas content of the water measurement group and the Longtan Formation varies from 0.42 to 5 cm³/g, with an average of 2.1 cm³/g. It indicates that the water measurement group and the Longtan Formation shale gas in the study area have good resource potential. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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22 pages, 9597 KiB

Open AccessArticle

Dynamic Change Characteristics and Main Controlling Factors of Pore Gas and Water in Tight Reservoir of Yan’an Gas Field in Ordos Basin

by Yongping Wan, Zhenchuan Wang, Meng Wang, Xiaoyan Mu, Jie Huang, Mengxia Huo, Ye Wang, Kouqi Liu and Shuangbiao Han

Processes 2024, 12(7), 1504; https://doi.org/10.3390/pr12071504 - 17 Jul 2024

Viewed by 486

Abstract

Tight sandstone gas has become an important field of natural gas development in China. The tight sandstone gas resources of Yan’an gas field in Ordos Basin have made great progress. However, due to the complex gas–water relationship, its exploration and development have been seriously restricted. The occurrence state of water molecules in tight reservoirs, the dynamic change characteristics of gas–water two-phase seepage and its main controlling factors are still unclear. In this paper, the water-occurrence state, gas–water two-phase fluid distribution and dynamic change characteristics of different types of tight reservoir rock samples in Yan’an gas field were studied by means of water vapor isothermal adsorption experiment and nuclear magnetic resonance methane flooding experiment, and the main controlling factors were discussed. The results show that water molecules in different types of tight reservoirs mainly occur in clay minerals and their main participation is in the formation of fractured and parallel plate pores. The adsorption characteristics of water molecules conform to the Dent model; that is, the adsorption is divided into single-layer adsorption, multi-layer adsorption and capillary condensation. In mudstone, limestone and fine sandstone, water mainly occurs in small-sized pores with a diameter of 0.001 μm–0.1 μm. The dynamic change characteristics of gas and water are not obvious and no longer change under 7 MPa displacement pressure, and the gas saturation is low. The gas–water dynamic change characteristics of conglomerate and medium-coarse sandstone are obvious and no longer change under 9 MPa displacement pressure. The gas saturation is high, and the water molecules mainly exist in large-sized pores with a diameter of 0.1 μm–10 μm. The development of organic matter in tight reservoir mudstone is not conducive to the occurrence of water molecules. Clay minerals are the main reason for the high water saturation of different types of tight reservoir rocks. Tight rock reservoirs with large pore size and low clay mineral content are more conducive to natural gas migration and occurrence, which is conducive to tight sandstone gas accumulation. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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17 pages, 11594 KiB

Open AccessArticle

Geochemical Characteristics and Hydrocarbon Generation Potential of Coal-Measure Source Rocks in Julu Sag

by Yang Wang, Hanyu Zhang, Liu Yang, Yanming Zhu and Zhixiang Chang

Processes 2024, 12(7), 1399; https://doi.org/10.3390/pr12071399 - 4 Jul 2024

Viewed by 511

Abstract

To uncover the reservoir characteristics and enrichment law of coal-measure gas in Julu sag, Hebei Province, and achieve co-exploration and co-mining, it is necessary to conduct a comprehensive analysis. In this study, we investigated the characteristics of coal-measure gas accumulation in the Taiyuan Formation and Shanxi Formation in the Julu area. This was achieved by collecting data on coal-measure source rocks and organic geochemistry, which were then combined with regional geological conditions. This study indicates that the coal seams and shales of Shanxi Formation and Taiyuan Formation in the study area serve as the primary source rocks. The predominant macerals found in coal rock are vitrinite. Furthermore, the organic matter type present in shale is primarily categorized as type II₂, with the organic matter maturity falling within the immature–mature stage. Based on the simulation results of tectonic-burial history, thermal evolution history, and hydrocarbon generation history in the study area, it is evident that the coal-measure source rocks experienced their first peak of hydrocarbon generation during the Mesozoic era as a result of deep metamorphism. Subsequently, the area experienced uplift and erosion, leading to the release of coal-bearing natural gas. Since the Paleogene period, the coal-bearing source rocks have undergone sedimentary burial and entered the secondary hydrocarbon generation stage, resulting in significant production of oil and gas. Based on the analysis of gas content, buried depth, source rock thickness, and sealing conditions in the study area, it is evident that the potential of coal-measure gas resources in the study area is primarily comprised of shale gas with supplementary coalbed methane. It can be inferred that the deeper areas within the study area hold greater exploration prospects. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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12 pages, 3587 KiB

Open AccessArticle

Research on Mechanism of Surfactant Improving Wettability of Coking Coal Based on Molecular Dynamics

by Ren Liu, Shilin Li, Yuping Ling, Yuanpei Zhao and Wei Liu

Processes 2024, 12(6), 1271; https://doi.org/10.3390/pr12061271 - 20 Jun 2024

Viewed by 530

Abstract

Coal dust is a major safety hazard in the process of coal mining and is of great importance to ensure production safety and maintain the health of operators. In order to understand the microscopic mechanism during coal seam water injection and reveal the mechanism of surfactants in improving the wettability of coal dust, coking coal was selected as the research object. Three surfactants, SDBS, AEO-9, and CAB-35, were chosen for molecular dynamics simulation research on the wetting and adsorption properties of water/coal/surfactants. The results show that surfactant molecules can cover the hydrophobic groups on the surface of coking coal, forming a hydrophilic adsorption layer, changing the coal surface from hydrophobic to hydrophilic, and enhancing the wettability. After adding surfactants, the thickness of the adsorption layer in the z-axis direction increases, expanding the contact area between coking coal and water molecules, thereby improving the wettability. When surfactants tightly cover the surface of coking coal, their binding strength increases, forming a more stable hydrophilic layer and further improving the wettability. At the same time, surfactants promote the diffusion of water molecules and enhance the interaction between hydrophobic alkyl chains and water molecules, further enhancing the wetting effect. Full article

(This article belongs to the Special Issue Theoretical Progress in the Exploration and Development of Deep Coal-Measure Gas)

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