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2025 Vol. 47, No. 1

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2025, 47(1): .
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Progress and insights from worldwide deep coalbed methane exploration and development
ZHANG Jiaqi, LIU Zengqin, SHEN Baojian, ZHAO Shihu, CHEN Xinjun, YE Jincheng
2025, 47(1): 1-8. doi: 10.11781/sysydz2025010001
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Since 2021, China has achieved significant breakthroughs in deep coalbed methane (CBM) exploration and development, making it a strategic resource for increasing natural gas reserves and production. To further support the high-quality development of deep CBM in China, it is urgent to study the CBM resource endowments and exploration and development status in worldwide major coal-bearing basins. The exploration and development of CBM in the United States, Australia, and Canada started early, currently mainly focusing on the development of medium- to low-rank shallow CBM, characterized by shallow coal seams and high permeability, with production exceeding 10 000 m3/d using vertical wells. However, due to adjustments in oil and gas strategies, the United States and Canada no longer prioritize CBM exploration. Australia, on the other hand, experiments with combined production of coal measures, propelling it to the top of global CBM production. In China, deep CBM exploration mainly focuses on medium- to high-rank deep CBM. The coal seams are characterized by significant depth variation and low permeability. The Ordos Basin has become the largest deep CBM production base. Multiple horizontal wells in the Daning-Jixian and Daniudi gas fields produce more than 100 000 m3 of gas per day. Deep CBM exploration in the Sichuan Basin has made positive progress, and the Junggar Basin shows potential for deep CBM exploration. Experiences from CBM exploration and development shows that breakthroughs in understanding enrichment patterns, advancements in engineering technologies, integrated management models, and industry- supportive policies are important factors for the rapid development of the CBM industry. Increasing exploration efforts for different types of deep CBM, strengthening theoretical and technological research, accelerating the construction of standard systems, and enhancing industry support policies will help foster high-quality exploration and efficient development of deep CBM in China.
Current status and development trends of deep coalbed methane research in China
JU Wei, TAO Shu, YANG Zhaobiao, CHENG Jiayao, SHANG Haiyan, NING Weike, WU Chunlong
2025, 47(1): 9-16. doi: 10.11781/sysydz2025010009
Abstract(393) HTML (97) PDF-CN(99)
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Deep coalbed methane (CBM) possesses enormous resource potential and is essential for increasing unconventional natural gas reserves and production on a large scale in China. To understand the current status of CBM research and development in China, systematic retrieval and classification of deep CBM-related publications are conducted using the China National Knowledge Infrastructure (CNKI) database and Wanfang Data Knowledge Service Platform. Based on this analysis, the status of deep CBM research in China is reviewed, and its development trends are discussed, providing insights into adaptive exploration and development technologies for deep CBM. The results indicate that the temporal distribution of publications reflects the evolution of China's deep CBM research and industrial development, which can be divided into four stages: the initial exploration stage (1994 to 2005), the slow development stage (2006 to 2015), the steady progress stage (2016 to 2020), and the rapid development stage (since 2021). Geological and engineering "dual sweet spot" prediction is a key research focus for deep CBM research. Conducting geology and engineering integrated research for deep CBM exploration and development, based on the quantitative characterization of geological and engineering parameters and using three-dimensional geological and geomechanical modeling, is a critical pathway to ensuring profitable development. The production state and development degree of natural fractures in coal reservoirs significantly affect fracturing transformation. The connectivity of fracture networks before and after fracturing is an important indicator for determining the performance of deep CBM development. The development of deep CBM technologies and their applicability are the key areas to be explored in the future. Deepening theoretical understanding, quantitatively characterizing geological and engineering conditions, and comprehensively analyzing influencing factors are fundamental and crucial for the further rapid development of deep CBM in China. Deep and ultra-deep CBM in basins such as the Ordos, Junggar, Sichuan, and Tarim basins will be the research focus and the key exploration and development areas.
Geological characteristics of deep coal rock and main geological factors controlling coalbed methane enrichment: a case study of the M area in the eastern Ordos Basin
GUO Xiaojiao, WANG Lei, YAO Xianzhou, LI Xu, ZHANG Linke, WANG Xiaoshuang
2025, 47(1): 17-26. doi: 10.11781/sysydz2025010017
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The 8# thick coal seam is widely distributed with high organic matter thermal maturity at the top of the Upper Carboniferous Benxi Formation in the M area of the Ordos Basin. However, the coal seams in this area are characterized by large burial depth, rapid lateral changes, strong heterogeneity, and unclear basic geological features and enrichment patterns of deep coalbed methane (CBM). The criteria for selecting favorable targets are yet to be established. These severely restrict the efficient exploration of deep CBM. To promote increased reserves and efficient production of deep CBM, and to further develop the enrichment theory of deep CBM in the eastern Ordos Basin, a comprehensive study was conducted based on core observations, experimental tests, scanning electron microscopy, well logging data from 76 wells in the study area, and 3D seismic data. The geological characteristics of deep coal seams and the main controlling factors of CBM enrichment were investigated, preliminary clarifying the exploration potential of this area. The results indicate that: The 8# coal seam at the top of the Upper Carboni-ferous Benxi Formation in the M area of the Ordos Basin is mainly composed of coking coal and lean coal, which are medium to high-ranked coals. The thickness of bright coal and semi-bright coal ranges from 2 to 6 m. Organic components are mainly vitrinite, accounting for 79.8%. Industrial components exhibit medium to high levels of volatile matter and ash, abundant fixed carbon, and low moisture content. The coal rock reservoir has well-developed pores and fractures, primarily composed of micropores and macropores. Gas content ranges between 16-25 m3/t. The enrichment of deep CBM in the eastern margin of the Ordos Basin is mainly controlled by coal reservoir and structural factors. Favorable exploration areas for deep CBM include regions with coal seams thicker than 6 m, areas with developed fractures far from fault zones (fault displacement less than 5 m), and microstructure high points. Based on these criteria, a favorable exploration area of 207 km2 for the 8# coal seam was identified, with 97 km2 classified as Type Ⅰ and 110 km2 as Type Ⅱ.
Evaluation method and application for in-situ stress in No. 8+9 coal seam, southern Shenfu block, northeastern margin of Ordos Basin
WU Jiawei, TANG Wei, ZHU Yanhe, WANG Cunwu, TIAN Yongjing, ZI Jingyu, YANG Jianghao, SHI Xian
2025, 47(1): 27-42. doi: 10.11781/sysydz2025010027
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The direction and magnitude of the present in-situ stress influence the propagation of hydraulic fractures in coal seams, making it a key geological parameter for coalbed methane (CBM) well network deployment and fracturing design. Accurate evaluation of the present in-situ stress direction and magnitude in coal seams is crucial for CBM exploration and development. This study focused on the direction and magnitude of the current in-situ stress in the No. 8+9 coal seam in the southern Shenfu block, northeastern margin of the Ordos Basin. Array acoustic logging, microseismic monitoring, and imaging logging were used to evaluate the direction of the present maximum horizontal principal stress in the coal seam and its roof and floor. Under constraints of the current in-situ stress magnitude from injection/falloff tests, parameters for the composite spring model were determined, and the current in-situ stress magnitude was further calculated. The results showed that the direction of the present maximum horizontal principal stress for the No. 8+9 coal seam and its roof and floor in the eastern part of the study area was nearly in the NNE orientation. In the western part, the directions of the maximum horizontal principal stress may deviate due to stress field disturbances around inactive faults and hydraulic fracturing activities. In 20 wells, calculations of the in-situ stress showed that the vertical principal stress in the No. 8+9 coal seam with a vertical depth of 1 902-2 181 m was 47-54 MPa. The minimum horizontal principal stress was 35-44 MPa, and the maximum was 42-50 MPa. With a lateral pressure coefficient less than 1, it was in the normal faulting stress state. In the eastern part of the study area, the NNE-oriented maximum horizontal principal stress was sequentially evolved from the SN-oriented compression during the Meso-Cenozoic Indosinian stage, the NNW-oriented compression during the Yanshanian stage, and the NNE-oriented compression during the Himalayan stage. Considering the distribution of natural fractures with an average NNW orientation during different tectonic stages, as well as the propagation pattern of NNE-oriented vertical hydraulic fractures under the normal faulting stress state with NNE-oriented maximum principal horizontal stress in the eastern fracture prediction area, it was recommended to deploy horizontal cluster wells within the azimuthal interval perpendicular to the current NNE-oriented maximum horizontal principal stress direction and the average NNW-oriented natural fracture direction. This approach aims to enhance production through large-scale extreme volume fracturing in horizontal wells by integrating the productivity of natural fractures and induced hydraulic fractures. In addition, the in-situ stress direction and natural fracture parameters should be further characterized in detail to guide fracturing design and improve CBM production.
Main controlling factors of production and reasonable fracturing scale optimization of deep coalbed methane wells in Shenfu block, Ordos Basin
SUN Lichun, LIU Jia, LI Na, LI Xinze, WEN Heng
2025, 47(1): 43-53. doi: 10.11781/sysydz2025010043
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The production of deep coalbed methane (CBM) wells in the Shenfu block of Ordos Basin varies greatly, with a lack of understanding of the main controlling factors. To further reveal the production patterns in deep CBM wells, identify key factors affecting well production capacity, and guide the efficient development of deep CBM resources in the Shenfu block, this study analyzed the production dynamic characteristics of typical CBM wells in the area based on basic geological data, production data, and previous research results. Through individual well comparisons and overall trend analysis, the main controlling factors influencing CBM well production in the Shenfu block were identified. The results showed that the gas content and fracturing scale have the greatest impact on production. Pearson's multivariate correlation regression analysis was used to quantitatively evaluate the impact of various factors on production capacity. The factors affecting post-fracturing production capacity of deep CBM wells, ranked by correlation, are as follows: gas content > fracturing sand amount > construction flow rate > fracturing fluid volume > structural depth > thickness. Under certain geological conditions, a reasonable fracturing scale is key to the efficient development of deep CBM wells. An integrated "geological reservoir, fracturing, and economic evaluation" approach was adopted, with economic benefits as the objective. Numerical simulation was conducted to study the coupled optimization of well spacing and fracturing scale. The results determined that the optimal well spacing for the Shenfu block was 300 m, the optimal cluster spacing was 20 m, and the optimal fracture half-length was 120 m. These findings provide technical support for the efficient development of deep CBM resources in the Shenfu block.
Storage and permeation space development characteristics and water production capacity evaluation of deep coal reservoirs in Linxing-Shenfu area of Ordos Basin
WANG Jinwei, XU Hao, LIU Yinan, ZHANG Bing, XU Yanyong, LIU Ding, ZONG Peng, WANG Yajuan, SONG Xuejing
2025, 47(1): 54-63. doi: 10.11781/sysydz2025010054
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The Linxing-Shenfu area in the Ordos Basin is one of the key areas for deep coalbed methane (CBM) development in China. However, significant variations in water production among CBM wells in different regions have hindered the efficient development of deep CBM. This study conducted multi-scale characterizations of coal samples from the 8#+9# coal seams in the Linxing-Shenfu area using high-pressure mercury intrusion porosimetry, low-temperature CO2 adsorption, low-temperature N2 adsorption, and CT scanning experiments. These methods revealed the development characteristics of the storage and permeability space in the study area. Water saturation simulation experiments were conducted to estimate the water storage capacity of coal samples, and numerical simulations were used to predict the water production capacity of deep reservoirs, providing a clear understanding of the water production capacity of deep coal reservoirs in the study area. Combined with actual water production data from CBM wells, the sources of coal seam water were further evaluated. The results show that deep coal reservoirs in the Linxing-Shenfu area exhibit well-developed micropores, macropores, and fractures, with relatively underdeveloped mesopores. As coal rank increases, the total pore volume first decreases and then increases. The original water content of deep coal samples declines sharply, while the water storage capacity first decreases and then increases, with bright coal showing a greater advantage in water storage capacity. The predicted daily water production ranges for low-vitrinite-reflectance (Ro) coal reservoirs in the study area are 12.81 to 26.01 m3, for medium-Ro coal reservoirs 1.82 to 7.22 m3, and for high-Ro coal reservoirs 1.90 to 8.22 m3. Actual water production exceeding these ranges indicates the influence from external water input, while production below these ranges indicates self-sourced water from the coal seams. Deep coal reservoirs have poor original water content and limited water storage capacity, especially in high-Ro coal reservoirs. Even when these reservoirs are fully saturated, water production remains low. Sustained high water output must involve substantial external water input.
Geological characteristics and main enrichment controlling factors of coalbed methane in Nanchuan area, southeastern Sichuan Basin
HE Xipeng, WANG Kaiming, LUO Wei, GAO Yuqiao, LIU Nana, GUO Tao, ZHOU Yatong, WU Didi
2025, 47(1): 64-76. doi: 10.11781/sysydz2025010064
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A significant strategic breakthrough has been achieved in the exploration of deep coalbed methane (CBM) in the Upper Permian Longtan Formation in the Nanchuan area, southeastern Sichuan Basin, showing promising exploration potential for CBM in this area. To identify the main geological factors controlling its enrichment, this study used data from drilling, cores, well logging, and experimental analyses to investigate the geological characteristics and main controlling factors for CBM enrichment, focusing on coal seam distribution, coal quality, physical properties, gas content, and fracturability characteristics of the Longtan Formation. The results show that: (1) The main coal seams of the Longtan Formation exhibit stable distribution (thickness of 2.8 to 5.7 m), good coal body structure (mainly primary structural coal), high vitrinite content (average content of 79.7%), high degree of thermal evolution (average Ro of 1.9%), and low ash yield rate (average of 14.3 %). These characteristics provide the basic conditions for the formation of CBM reservoirs. (2) The coal reservoir has a pore-fracture structure, with micropores accounting for 78% of the total pore volume and contributing 99.6% of the total specific surface area, which is favorable for CBM adsorption and post-fracturing seepage. (3) The total gas content of the coal seam is 14.0 to 46.7 m3/t, with free gas accounting for 39% to 44%. It is characterized by "high gas content, abundant free gas, and oversaturation", and its gas content increases with burial depth. (4) The in-situ stress in the study area is moderate (35 to 60 MPa), with a small two-way horizontal stress difference coefficient (< 0.1) and good roof and floor plates, forming effective stress shielding favorable for fracturing transformation. (5) The main controlling factors for CBM methane enrichment in the Nanchuan area include the sedimentary environment, which determines coal-bearing formations; the degree of coal evolution, which determines the intensity of hydrocarbon generation; and the preservation conditions, which govern CBM enrichment.
Compressibility characteristics and modification effect of coal reservoirs in Longtan Formation, Nanchuan area, southeast Chongqing
LIU Jinxian, GUO Tao, ZHOU Yatong, LI Dongyang, JIN Xiaobo
2025, 47(1): 77-88. doi: 10.11781/sysydz2025010077
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Fracturing modification is an important method for enhancing the permeability and conductivity in coalbed methane (CBM) wells. To better guide the development and production of CBM wells in Longtan Formation of Nanchuan area, southeast Chongqing, the study comprehensively applied various experimental methods including well logging data, industrial analysis, scanning electron microscopy, polished section observation, and whole-rock analysis. Based on the characteristics of coal rock porosity, roof and floor plate distribution, and gas content, it analyzed the compressibility characteristics of coal reservoirs and their impact on reservoir modification. The study shows that: (1) The coal rocks exhibit characteristics of medium to high evolution degree, medium to high vitrinite content, and medium to low ash content. The primary storage spaces in coal rocks are micropores and fractures, which facilitates gas adsorption. The coal seams are stably distributed, with the floor plate consisting of aluminous mudstone and the roof plate composed of mudstone, which locally transitions to argillaceous limestone and limestone. The assemblage patterns of the coal reservoir and its roof and floor plates, as well as the variations of mineral composition in roof plate, indicate a transitional sedimentary environment between land and sea. (2) Significant differences in mechanical parameters and in-situ stress of coal seams and roof and floor plates were observed, preliminarily indicating good compressibility. Triaxial stress experiments revealed that under high pressures, mechanical parameters of coal seams could exceed those of roof plate, thereby increasing the risk of fracturing. (3) Controlled by the variations of sedimentary conditions in coal measures, the lithological assemblage of the coal seams with the roof plate, and the mineral composition of the roof plate directly affect wellbore stability during horizontal drilling. Mudstone roof plates with high clay mineral content are brittle, prone to fracturing, and susceptible to swelling upon water contact, which are the major causes for spalling risks and impact horizontal well drilling rate. (4) Irregular natural fractures can lead to fracture propagation and fracture height control failure, while regular fractures that align with the direction of maximum principal stress facilitate artificial fracture propagation and contribute to effective reservoir modification.
Characteristics, controlling factors of development and exploration areas of deep coal-rock reservoirs in rift basins: a case study of the second member of Cretaceous Nantun Formation in Huhehu Sag, Hailar Basin
GAO Geng, XIE Yingyi, HOU Beibei, MA Wenjuan, XU Hui, WANG Yujie, HUO Yingdong, ZHANG Jingyuan, LIU Shichao, ZHAO Wei, LIANG Yuan
2025, 47(1): 89-103. doi: 10.11781/sysydz2025010089
Abstract(237) HTML (102) PDF-CN(45)
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In recent years, major breakthroughs have been made in deep coal-rock gas exploration, revealing the promising exploration prospects of such resources. This has become a new hotspot in unconventional oil and gas exploration and development, following tight oil and gas and shale oil and gas. The second member of Cretaceous Nantun Formation (N2) in the Huhehu Sag of Hailar Basin is characterized by deep coal-rock layers in a thick stack with high resource potential for deep coal-rock gas. This region is an important area for exploration succession. Clarifying the characteristics, main controlling factors, and development patterns of deep coal-rock reservoirs is essential for the exploration and development of deep coal-rock gas in the coal-bearing rift basins of northeastern China. Based on drilling and seismic data from the Huhehu Sag, the characteristics and main controlling factors of the high-quality coal rock reservoirs in N2 are studied through core and thin section observations and experimental analysis. The coal-rock reservoirs in N2 of the Huhehu Sag have the characteristics of low ash content, ultra-low moisture content, and medium to high volatile matter. The main reservoir space is mainly composed of organic pores, fractures, and inorganic mineral pores, with porosity mainly distributed between 4.5% to 7.6%, with an average of 6.0%. The average permeability is 0.45×10-3 μm2, and the pore structure is mainly microporous, with a high proportion of macropores, making it easier for free gas storage. Swampy shore-shallow lakes are widely distributed, controlling the large-scale development of coal rocks, providing material sources and storage space for deep coal-rock gas reservoir formation. High-quality coal-rock reservoirs are mainly developed in the depression zones and steep slope zones, where swampy shore and shallow lakes are widely distributed. The coal-rocks formed in these areas are mainly bright to semi-bright primary structural coal, forming cleats, organic pores, and micro-fractures. Organic pores are connected to micro-fractures, resulting in high pore connectivity, better physical properties, superior gas content, and richer "free gas". The southern depression zones and steep slope zones are more likely to form multiple favorable source and reservoir configurations, with superior reservoir formation conditions. The predicted resource volume exceeds one trillion cubic meters, making it a favorable breakthrough area for deep coal-rock gas exploration in the Huhehu Sag. It is expected to become the first trillion-cubic-meter deep coal-rock gas field in the Hailar Basin.
Combined multi-scale characterization of pores in ultra-thick coal seams of Jurassic Xishanyao Formation, Tiaohu-Malang sags, Santanghu Basin
CHEN Yue, LEI Qiqi, MA Dongmin, WANG Xin, WANG Xinggang, HUANG Diefang, RONG Gaoxiang
2025, 47(1): 104-116. doi: 10.11781/sysydz2025010104
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The ultra-thick coal seams in the middle and lower parts of the Jurassic Xishanyao Formation in the Santanghu Basin are widely distributed. However, research on the pore characteristics of these ultra-thick coal seams is limited. To accurately characterize the porosity features of these coal reservoirs in the Tiaohu-Malang sags of the Santanghu Basin, the study examined the 9-1 and 9-2 coal samples of the Xishanyao Formation. Techniques such as high-pressure mercury intrusion porosimetry, low-temperature liquid nitrogen adsorption, nuclear magnetic resonance (NMR), CT scanning, scanning electron microscopy (SEM), and the pore-crack analysis system (PCAS) were used to investigate pore development characteristics. The results show significant differences in surface morphology between the two coal seam samples. The surface of the 9-1 coal sample contains a large number of mineral crystal particles, with well-developed pores, breccia pores, friction holes, and micro-fractures, displaying a distinct pore-fracture topological structure. The 9-2 coal sample exhibits prominent primary fibrous structures, with smaller and more dispersed fractures. The fractal characteristics of the pore structures also differ significantly between the two coal seams, with the 9-1 coal sample showing stronger heterogeneity. Its liquid nitrogen adsorption curves correspond to type Ⅱ with a H4 hysteresis loop. For the 9-2 coal sample, the fractal dimensions of micropores and small pores are 2.53 and 2.63, respectively, indicating higher complexity and better permeability connectivity. Multifractal characteristics analysis shows that pores of small diameters exhibit a more concentrated distribution and a narrower range, with stronger heterogeneity. The pore distribution of 9-1 coal sample is more concentrated, with a relatively more uniform pore size distribution intervals. Using a combined full-scale characterization method, it is revealed that 9-2 coal sample has a higher total pore volume than 9-1. Macropores have the largest volume proportion, accounting for 47.97% and 44.48%, respectively, followed by mesopores and small pores, and the proportion of micropores is the smallest. Micropores contribute the most to the pore specific surface areas for both seams, which are 62.67% and 58.43%, respectively. For the 9-1 coal sample, the pore volume contribution positively correlates with pore size, while the specific surface area contribution negatively correlates with pore size.
Accumulation conditions and target area evaluation of coalbed methane in eastern uplift of Junggar Basin
YU Qixiang, TIAN Mi, LUO Yu, YANG Fan, CHEN Yan'e, WANG Feng, GAO Yuqiao, GUO Tao
2025, 47(1): 117-129. doi: 10.11781/sysydz2025010117
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The eastern uplift of the Junggar Basin has great coalbed methane (CBM) exploration potential. CBM selection and evaluation will provide scientific guidance and direction for CBM exploration in the region. Utilizing well logging data, core analysis test results, and seismic data, well-seismic calibration and seismic profile interpretation were carried out. Connecting-well profiles and thickness distribution maps for coal seams in the Jurassic Xishanyao and Badaowan formations were compiled. The study analyzed main accumulation factors, including gas source, basic characteristics of coal rocks, reservoir physical properties, gas content, and preservation conditions. The results show that: ① Coal seams of the Xishanyao Formation are distributed continuously in the Wucaiwan-Wutongwozi sags to the north of the Shaqi Uplift, while to the south of the Shaqi Uplift, the seams are mainly distributed in the Jimusaer-Jinan sags. Coal seams of the Badaowan Formation are strongly segmented and mainly distributed in parts of the sags. ② This region contains self-sourced biogenic gas from coal seams, low-maturity thermogenic gas, and high-maturity deep-seated exogenous gas. ③ The organic components in coal rocks are mainly inertinite, followed by vitrinite with small amounts of exinite. The vitrinite reflectance (Ro) in coal rocks is low (0.39%-0.47%), indicating low-rank coal. CBM mainly consists of N2, CO2, and CH4, with N2 being the dominant component. The combustible gas (CH4) content is low relative to the total gas content in coal rocks. ④ CBM enrichment and accumulation models include piedmont fault depression, deep depression, and open slope gas escape models. ⑤ Evaluation parameters and classification standards were established. The Wucaiwan, Wutongwozi, Jimusaer, and Jinan sags are favorable areas for CBM exploration. The Shazhang fault-fold belt and the Shiqiantan Sag are moderately favorable areas. The Shishugou and Gucheng sags are unfavorable areas.
Combined characterization of pore structurein deep medium-rank coal using mercury intrusion and liquid nitrogen adsorption methods and its pore fractal characteristics
LI Qi, WU Yong, QIAO Lei
2025, 47(1): 130-142. doi: 10.11781/sysydz2025010130
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To study the pore structure and fractal characteristics of deep medium-rank coal, combined characterization using mercury intrusion and liquid nitrogen adsorption methods was conducted on coal samples from the main coal seams in typical deep mining areas, including Shenyang Hongyang Third Mine, Kailuan Linxi Mine, Huainan Xinji Second Mine, and Pingdingshan Pingmei Sixth Mine. Parameters such as pore size, pore volume, and specific surface area were obtained, and the pore fractal characteristics were studied based on the Menger sponge model and the FHH model. The results showed that: (1) Among the pore structure parameters tested with mercury intrusion method, the average pore size ranged from 31.10 to 34.70 nm, pore volume from 0.048 3 to 0.059 4 mL/g, and specific surface area from 5.590 9 to 7.652 8 m2/g. The pore development in the main coal seams of typical deep mining areas was relatively similar. The pore volume distribution was dominated by macropores, with micropores and transition pores contributing roughly equally, and mesopores having a relatively small distribution. This indicated that macropores had better connectivity and mesopores were more closed. Micropores accounted for more than 70% of the total specific surface area, while the proportions of mesopores and macropores were minimal, indicating that micropores had the strongest adsorption capacity, which was negatively affected gas management in deep coal seams. The fractal dimensions based on the Menger sponge model ranged from 2.6 to 3.0, indicating irregular pore shapes, complex pore structures, and generally rough pore surfaces. (2) The effective pore size tested using liquid nitrogen adsorption method ranged from 3 to 177 nm with significant differences in total pore volume and specific surface area among the mining areas. Pore volume distribution was dominated by transition pores and mesopores, with a lower distribution of micropores and no macropores. This indicated that liquid nitrogen adsorption was effective for characterizing mesopores and transition pores but struggled to characterize macropore structures. Moreover, the connectivity of micropores was relatively poor. The specific surface area was mainly composed of transition pores, micropores, and mesopores, with no macropores. Among them, transition pores were mostly dominant and had relatively strong adsorption capacity. The fractal dimensions based on the FHH model ranged from 2.0 to 2.7, indicating a relatively simple and regular structure. (3) The differences in pore structures of deep medium-rank coal were discussed. The pore structure parameters (specific surface area and pore volume) determined by mercury intrusion and liquid nitrogen adsorption methods showed a non-linear concave curve variation with increasing burial depth. The fractal dimensions derived from the Menger sponge model and the FHH model showed a convex curve trend with increasing burial depth.
Research and insights for application of CO2-ECBM technology in deep high-rank coal seams: a case study of Jinzhong block, Qinshui Basin
ZHENG Yongwang, CUI Yinan, LI Xin, XIAO Cui, GUO Tao, ZHANG Dengfeng
2025, 47(1): 143-152. doi: 10.11781/sysydz2025010143
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Deep high-rank coal seams have significant resource potential, but exhibit characteristics of "strong adsorption and weak desorption", making it challenging to effectively utilize with conventional development methods. Compared with other enhanced recovery technologies such as chemical flooding and thermal flooding, CO2-ECBM (CO2 geological sequestration-Enhanced Coal Bed Methane Recovery) technology offers dual benefits of energy conservation and emission reduction, and increased recovery rates of coalbed methane. In order to clarify the characteristics of CO2 adsorption and desorption, demonstrate the feasibility of CO2-ECBM technology in enhancing the recovery of deep high-rank coalbed methane, and help release the productivity of deep high-rank coalbed methane, this study focused on the Jinzhong block, Qinshui Basin, and conducted experimental research on the CO2 adsorption and desorption characteristics of deep high-rank coal seams. The research results showed that the adsorption capacity of CH4 in coal seams increased gradually with rising equilibrium pressures. In contrast, the adsorption capacity of CO2 in coal seams initially increased, then sharply dropped near the critical pressure, followed by a significant rise, which was influenced by the pore and fracture development characteristics of the coal seams and the properties of CO2. The adsorption capacity of CO2 in deep high-rank coal seams was about 2 to 5 times that of CH4, and the adsorption capacity of supercritical CO2 in coal seams was stronger. The sensitive desorption pressure of CO2 was 3/4 of that of CH4. Once adsorbed in coal seams, CO2 showed an obvious adsorption/desorption lag, with a large proportion of CO2 remaining in coal seams in the form of adsorbed storage and residual storage, which provided favorable conditions for large-scale CO2 storage and CH4 replacement. Through the analysis of experimental results, it was clear that developing CO2-ECBM in deep high-rank coal seams was feasible and could significantly enhance coalbed methane recovery. In field application, the pressure level of gas reservoir could be increased through methods such as advanced gas injection and increasing injection pressure, thereby enhancing competitive adsorption efficiency. Additionally, the low sensitive desorption pressure indicated a high backflow rate after CO2 injection, suggesting that CO2 recycling should be considered.
Hydraulic fracture propagation characteristics of directional perforation fracturing in horizontal wells for deep coalbed methane
HUANG Shuxin, LI Song, CHEN Bo
2025, 47(1): 153-162. doi: 10.11781/sysydz2025010153
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Deep coalbed methane resources exhibit favorable geological characteristics and significant exploration and development potential, offering a substantial foundation for China's strategy to enhance natural gas storage and production. Directional perforation fracturing of horizontal wells is widely used as an important permeability enhancement technology for deep coalbed methane exploration. However, the mechanisms of hydraulic fracture initiation and propagation under the influence of geological and engineering factors remain unclear. To explore directional perforation fracturing characteristics in deep coal seams, a three-dimensional discrete lattice simulation algorithm was used to establish a numerical model. The paper studied the effects of geological and perforation parameters on fracturing difficulty, fracture morphology, and stimulated reservoir area (SRA). The results showed that, with the increase in elastic modulus, coal seam fracture pressure rose, and SRA and its variation coefficient increased gradually, which is conducive to long and narrow fracture formation. An increase in horizontal stress differences weakened the interaction between hydraulic fractures, reducing SRA while increasing its variation coefficient and fracture aperture. In addition, increasing perforation depth and diameter significantly reduced the fracture pressure in deep coal seams. Higher perforation depths greatly increased SRA, whereas larger perforation diameters decreased SRA, and its variation coefficient increased gradually. Perforation density had no significant impact on fracture pressure, but was positively correlated with SRA. The study suggests that for fracturing of structurally intact coal seams, increasing perforation depth and density while reducing perforation diameter can achieve better results.
Analysis of pressure-maintaining coring process in deep coal seams and gas content determination methods
WU Jian, ZHANG Songhang, JIA Tengfei, CHAO Weiwei, PENG Wenchun, LI Shilong
2025, 47(1): 163-172. doi: 10.11781/sysydz2025010163
Abstract(195) HTML (81) PDF-CN(43)
Abstract:
Gas content is an important parameter for calculating coalbed methane (CBM) reserves and guiding their exploration and development. For deep coal seams, the prolonged coring duration and inaccuracies in lost gas volume calculations result in reduced accuracy in gas content measurement using conventional wireline coring methods. To accurately determine the actual gas content in deep coal seams and gas occurrence state, pressure-maintaining coring technology, which retains in-situ pressure and gas content in samples, is considered the most effective method. However, due to the unique characteristics of unconventional reservoirs, such as adsorption gas, there are currently no standardized coring processes or gas content determination methods. To address this issue, this paper analyzed the environmental conditions and gas loss characteristics during each stage of pressure-maintaining coring. Considering the presence of both adsorbed gas and free gas in deep coal seams, the study proposes a method for determining both components based on pressure-maintaining coring. The analysis shows that gas content calculations in pressure-maintaining coring have the characteristics of "four stages, two losses, and two collections". The reasonable design of pressure points during pressure-reducing and gas-collecting stages of pressure-maintaining coring can effectively distinguish adsorption gas from free gas. In addition, by analyzing the differences and connections between the two methods, the gas content measured using pressure-maintaining coring can be used to correct gas loss caused by using wireline coring at the same well platform. Based on this, a method for calculating gas content in deep coal seams based on wireline coring was established. The successful application of pressure-maintaining coring technology is significant for deep coal seam exploration. The study recommends appropriately increasing the number of pressure-maintaining coring test wells in deep coal seam exploration areas to precisely determine the actual gas content in reservoirs.
Study on microscopic pore structures and mechanical properties
ZHAO Shihu, LI Yong, LIU Yali, WANG Yanbin, LIU Zengqin, CHEN Gang, CHEN Xinjun
2025, 47(1): 173-183. doi: 10.11781/sysydz2025010173
Abstract(189) HTML (104) PDF-CN(32)
Abstract:
The pore structures and mechanical properties of coal are key parameters for geological evaluation of coalbed methane, reflecting its reservoir capacity and compressibility. The study investigated four coal samples from the Qinshui and Datong basins in Shanxi Province, including Jurassic coal from Datong (Ro=0.91%), No. 2 coal from the Shanxi Formation in Gujiao (Ro=1.34%), No. 8 coal of the Taiyuan Formation in Gujiao (Ro=1.70%), and No. 2 coal of the Shanxi Formation in Yicheng (Ro=1.77%). Using atomic force microscopy (AFM), a combined characterization technique was established for microscopic pore structure and mechanical properties based on image segmentation and Derjaguin-Muller-Toporov (DMT) mechanical model. This method clarified the microscopic pore structure and mechanical properties of coal samples and revealed the influence of material composition, pore structure, and thermal evolution level on their microscopic mechanical properties. The results showed that the surface porosity of coal samples mainly ranged from 2.72% to 4.60%, with an average of 3.58%. The total pore surface area and total pore volume were (3.413-5.638)×10-2 μm2/μm2 and (0.5-3.9)×10-4 μm3/μm2, respectively. The pore sizes were mainly distributed between 10-100 nm, and the Young's modulus ranged from 2.24 to 3.10 GPa, with an average of 2.77 GPa. The mechanical properties of coal were influenced by the material composition, pore structure, and thermal evolution level. As moisture decreased and volatile and mineral content increased, the Young's modulus showed an increasing trend. With an increase in surface roughness, mean pore size, porosity surface, specific surface area, and total pore volume, the Young's modulus decreased. As thermal evolution progressed, the Young's modulus decreased. AFM enables simultaneous analysis of microscopic pore structure and mechanical properties of coal, providing new methods and insights for studying reservoir capacity and mechanical behavior of coal reservoirs. It holds significant implications for the evaluation of reservoir capacity and compressibility in unconventional reservoirs.
Study on sedimentary organic facies of coal-measure source rocks in Shuixigou Group, Taibei Sag, Tuha Basin
LIANG Hao, FAN Tanguang, WANG Zhiyong, TAO Shu, WEN Yijie, ZHENG Haitian, ZHANG Zijian
2025, 47(1): 184-194. doi: 10.11781/sysydz2025010184
Abstract(169) HTML (83) PDF-CN(17)
Abstract:
The Taibei Sag in the Tuha Basin contains abundant oil and gas resources. The coal-measure source rocks in the Jurassic Shuixigou Group are the main hydrocarbon source layers in the area, with significant hydrocarbon generation potential. However, organic facies types of the coal-measure source rocks in the Shuixigou Group and their relationships with sedimentary environments remain unclear, hindering oil and gas exploration across the sag and the entire basin. To enable a detailed classification and evaluation of coal-measure source rocks in the Shuixigou Group of the Tuha Basin, geochemical analyses were conducted, including maceral composition, total organic carbon (TOC) content, and hydrocarbon generation potential (S1+S2). Based on the result, the study established classification criteria for sedimentary organic facies of coal-measure source rocks in the study area, identified organic facies types, and clarified hydrocarbon generation potential and their relationships with sedimentary facies. The results indicate that the sedimentary organic facies of the coal-measure source rocks in the Shuixigou Group of the Taibei Sag can be categorized into five types: organic facies of lacustrine with strong water coverage and high vitrinites, organic facies of lacustrine with water coverage and medium to high vitrinites, organic facies of delta plain with water coverage and medium to high vitrinites, organic facies of delta plain with weak water coverage and medium vitrinites, and organic facies of front delta with weak water coverage and low vitrinites. The organic facies of lacustrine with strong water coverage and high vitrinites have a large organic abundance and exhibit the highest hydrocarbon potential, with TOC contents ranging from 5.05 % to 18.31 % and S1+S2 values from 6.35 to 20.93 mg/g, and vitrinites exceeding 80%. Following this, the organic facies of lacustrine with water coverage and medium to high vitrinites and the organic facies of delta plain with water coverage and medium to high vitrinites exhibit TOC contents of 3.83%-17.68% and 2.30%-7.41%, with average S1+S2 values of 6.35 mg/g and 4.48 mg/g, and vitrinites ranging between 50%-80%, respectively. The organic facies of front delta with weak water coverage and low vitrinites show the poorest hydrocarbon generation potential, with an average TOC content of only 1.3% and an average S1+S2 of 4.1 mg/g. The findings provide a critical basis for predicting the distribution of coal-measure high-quality source rocks in the Shuixigou Group in the Taibei Sag and for accurately assessing their oil and gas resource potential.
Impact of new coalbed methane wells on old well productivity and its controlling factors: a case study of Shizhuangnan block in Qinshui Basin
HAN Xueting, MENG Shangzhi, LIU Guangjing, REN Zhenyu, TAO Shu, MEN Xinyang, WEI Ziyang
2025, 47(1): 195-203. doi: 10.11781/sysydz2025010195
Abstract(113) HTML (64) PDF-CN(20)
Abstract:
To address the issue of uneven productivity release in the Shizhuangnan block of the Qinshui Basin, the initial well pattern is optimized through horizontal well infill to enhance reservoir utilization. However, frequent occurrences of drilling mud and fracturing fluid migration to neighboring wells have resulted in varying degrees of effect to old well productivity. Based on the coalbed methane development in the Shizhuangnan block, the study analyzed the main causes for well-to-well interference and its impact on productivity. From the geological and engineering perspectives, countermeasures and suggestions on well deployment were proposed. The results revealed that staged fracturing of new horizontal wells is the primary cause impairing old well productivity. The proportion of wells affected by drilling is relatively low, with poor productivity recovery efficiency. The impact from fracturing is predominantly concentrated near the wellbore (minimum well spacing < 120 m). The minimum well spacing for fracturing-affecting wells generally ranges from 120 to 300 m, with impact observed at burial depth between 550 to 900 m. The abnormal production in affected wells is characterized by the height increase in liquid water column. Some old wells, with a minimum well spacing of less than 150 m or developed tectonic coal, experience black water production and pump shutdowns. Wells with these issues exhibit lower recovery efficiency. While the production can be significantly restored by manual real-time unclogging, failure in unclogging results in a substantial decrease in gas production. Old wells affected by new well fracturing are distributed in the perforation direction of the horizontal section of new wells. Geologically, the distribution is mainly controlled by the anisotropy of horizontal principal stress. There are two propagation mechanisms depending on well spacing: hydraulic fracture communication and fracturing fluid front propagation. The horizontal stress difference in the coal reservoir of the Shizhuangnan block ranges from 5.5 to 13.5 MPa, with the average horizontal stress difference in the fracturing-affected wells greater than 10 MPa. Under high horizontal stress differences, the strong orientation of hydraulic fractures disturbs the fluid field of the old wells. To mitigate the impact, the deployment of new wells should maintain a minimum well spacing of over 300 m to the old wells and avoid faults. In areas with high stress differences, temporary plugging and diverting fracturing, reducing spacing between clusters, and enhancing stress interference between fractures can be employed to mitigate the fracturing impact on old well productivity.
Brittleness evaluation of main coal seams in Permian Taiyuan-Shanxi formations, Baode block, Ordos Basin: based on a convolutional neural network method
ZHANG Qingfeng, LI Ziling, ZHANG Jikun, HAO Shuai, SUN Xiaoguang, SHANG Yanjie, ZUO Yun
2025, 47(1): 204-212. doi: 10.11781/sysydz2025010204
Abstract(105) HTML (51) PDF-CN(20)
Abstract:
The coal seams of the Permian Taiyuan-Shanxi formations in the Baode block of the northeastern margin of the Ordos Basin have abundant coalbed methane resources. However, the productivity varies greatly among wells, mainly attributed to the strong heterogeneity caused by regional differences in reservoir brittleness. Rock mechanical parameter method is commonly used to evaluate reservoir brittleness. Studying rock mechanical parameters and brittleness can provide an important basis for fracturing modification. However, current methods mostly rely on empirical formulas, leading to limited evaluation accuracy. In this study, a convolutional neural network (CNN) was utilized to construct a conversion model between experimentally obtained elastic modulus, Poisson's ratio, and multi-logging curves. Based on this method, rock mechanical profiles were further established, enabling quantitative evaluation of brittleness. The results indicated that CNN-based predictions of rock mechanical parameters had good applicability for coal-bearing layers. The brittleness indices the main coal seams, 4+5# and 8+9#, in the Baode block were generally low. The brittleness index of the 4+5# seam was slightly higher than that of the 8+9# seam. Both seams exhibited similar spatial distributions, with low brittleness values in the central and southeastern parts of the study area. Differences in mineral composition affected rock brittleness. Higher quartz content was linearly correlated with greater elastic modulus and brittleness index.
Geological characteristics and development effect evaluation of coalbed methane reservoirs in Panguan syncline, Guizhou Province
HU Haiyang, YANG Fuqin, CHEN Jie, LOU Yi, WAN Yuting
2025, 47(1): 213-222. doi: 10.11781/sysydz2025010213
Abstract(110) HTML (57) PDF-CN(26)
Abstract:
The Upper Permian Longtan Formation in Guizhou Province contains multiple coal seams with abundant coalbed methane (CBM) resources, providing a solid base for CBM development. However, the low permeability of the coal seams hinders gas and water production, necessitating the development of key technologies for CBM development under conditions of low permeability and multiple coal seams in Guizhou. Based on the geological characteristics of coal reservoirs in the Panguan syncline and CBM well engineering data, the study analyzed geological, fracturing, and drainage and production parameters, and summarized development technologies for low-permeability and multi-seam CBM reservoirs. Engineering practices in Panguan syncline show that: (1) For commingled development of coal seams 12# and 18# in the syncline, factors such as permeability, reservoir temperature, fracture pressure, liquid and sand addition per meter of coal seam, pressure drop rate, and production enhancement rate significantly influence gas production of CBM wells. (2) Increasing the liquid and sand addition per meter of coal seam can significantly increase the reservoir permeability after fracturing. The permeability of well YP-1 after fracturing reached 64.158×10-3 μm2, 1 304 times higher than before. (3) Controlling pressure drop rate and production enhancement rate to appropriate levels can improve the fracturing fluid flowback rate and expand the pressure drop funnel radius of CBM wells. The cumulative fracturing fluid flowback rate of well YP-1 reached 82.53% after 210 days of drainage and production, with the water production radius reaching 91% of the fracturing influence radius. This helps to expand effective desorption radius and improve the effectiveness of gas production. For the Panguan syncline with low permeability and multiple coal seams, the study suggests adopting the technical approach of "selected layer perforation, segmented fracturing, and commingled drainage and production" to improve the geological and engineering potential of CBM development.

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