Enrichment conditions and resource potential of coal-rock gas in Ordos Basin, NW China

NIU Xiaobing, FAN Liyong, YAN Xiaoxiong, ZHOU Guoxiao, ZHANG Hui, JING Xueyuan, ZHANG Mengbo

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Petroleum Exploration and Development ›› 2024, Vol. 51 ›› Issue (5) : 1122-1137. DOI: 10.1016/S1876-3804(25)60530-1

Enrichment conditions and resource potential of coal-rock gas in Ordos Basin, NW China

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Abstract

To reveal the enrichment conditions and resource potential of coal-rock gas in the Ordos Basin, this paper presents a systematic research on the sedimentary environment, distribution, physical properties, reservoir characteristics, gas-bearing characteristics and gas accumulation play of deep coals. The results show that thick coals are widely distributed in the Carboniferous-Permian of the Ordos Basin. The main coal seams Carboniferous 5# and Permian 8# in the Carboniferous-Permian have strong hydrocarbon generation capacity and high thermal evolution degree, which provide abundant materials for the formation of coal-rock gas. Deep coal reservoirs have good physical properties, especially porosity and permeability. Coal seams Carboniferous 5# and Permian 8# exhibit the average porosity of 4.1% and 6.4%, and the average permeability of 8.7×10-3 μm2 and 15.7×10-3 μm2, respectively. Cleats and fissures are developed in the coals, and together with the micropores, constitute the main storage space. With the increase of evolution degree, the micropore volume tends to increase. The development degree of cleats and fissures has a great impact on permeability. The coal reservoirs and their industrial compositions exhibit significantly heterogeneous distribution in the vertical direction. The bright coal seam, which is in the middle and upper section, less affected by ash filling compared with the lower section, and contains well-developed pores and fissures, is a high-quality reservoir interval. The deep coals present good gas-bearing characteristics in Ordos Basin, with the gas content of 7.5-20.0 m3/t, and the proportion of free gas (greater than 10%, mostly 11.0%-55.1%) in coal-rock gas significantly higher than that in shallow coals. The enrichment degree of free gas in deep coals is controlled by the number of macropores and microfractures. The coal rock pressure testing shows that the coal-limestone and coal-mudstone combinations for gas accumulation have good sealing capacity, and the mudstone/limestone (roof)-coal-mudstone (floor) combination generally indicates high coal-rock gas values. The coal-rock gas resources in the Ordos Basin were preliminarily estimated by the volume method to be 22.38×1012 m3, and the main coal-rock gas prospects in the Ordos Basin were defined. In the central-east of the Ordos Basin, Wushenqi, Hengshan-Suide, Yan'an, Zichang, and Yichuan are coal-rock gas prospects for the coal seam #8 of the Benxi Formation, and Linxian West, Mizhi, Yichuan-Huangling, Yulin, and Wushenqi-Hengshan are coal-rock gas prospects for the coal seam #5 of the Shanxi Formation, which are expected to become new areas for increased gas reserves and production.

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coal-rock gas / coalbed methane / critical depth / coal characteristics / enrichment conditions / gas accumulation play / resource potential / exploration direction / Ordos Basin

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NIU Xiaobing , FAN Liyong , YAN Xiaoxiong , ZHOU Guoxiao , ZHANG Hui , JING Xueyuan , ZHANG Mengbo. Enrichment conditions and resource potential of coal-rock gas in Ordos Basin, NW China. Petroleum Exploration and Development. 2024, 51(5): 1122-1137 https://doi.org/10.1016/S1876-3804(25)60530-1

Introduction

Coal is a significant source rock for hydrocarbon generation, producing a substantial amount of hydrocarbon gases during coal formation or secondary biological processes [1⇓⇓⇓-5]. Since the 1990s, exploration and development of coalbed natural gas have primarily targeted shallow coal seams both domestically and internationally, and China has achieved large-scale commercial development of mid-shallow coalbed methane in the eastern margin of the Ordos Basin and the Qinshui Basin, China [6⇓⇓⇓⇓⇓-12]. Recent exploration and development of coal strata deeper than 1 500 m have revealed that deep coal seams are rich in natural gas. Notably, the accumulated gas in these deep seams exhibits significant differences from shallow coalbed methane in terms of reservoir gas content, gas occurrence characteristics, gas saturation, preservation conditions, and production characteristics [13⇓⇓⇓⇓⇓-19]. Shallow coalbed methane is characterized by a high proportion of adsorbed gas, typically exceeding 90% [20], and is often under-saturated. Deep coal seams exhibit high gas content, typically ranging from 10 m3/t to 33 m3/t. In deep coal seams, adsorbed gas and free gas are primarily coexisted, with free gas accounting for up to 50%. Adsorbed gas saturation generally exceeds 90%, often reaching a super- saturated state. The enrichment and preservation of natural gas in deep coal seams are largely influenced by the preservation conditions of the lithological combination in the roof and floor, and controlled by structure and geostress during the later stage of hydrocarbon accumulation. Chen et al. [21] analyzed the relationship between gas content and depth in different coal seams of different coal ranks, and defined the coal seam burial depth corresponding to the maximum gas content as the "critical depth". The critical depth for low to medium-rank coal is 1 400-1 700 m, while for medium to high-rank coal, it is 1 500-1 800 m. Below the "critical depth", the negative effect of formation temperature on adsorption predominates, outweighing the positive effect of formation pressure. Qin et al. [22] clarified the characteristics of deep coal reservoirs versus shallow coal reservoirs, noting that deep coalbed methane refers to coalbed methane resources in the geostress state and/or below the "critical depth" for gas content. They illustrated deep coalbed methane from the aspect of coal reservoir state, and emphasized that "deep" is not merely defined by the burial depth of coal reservoir. Guo et al. [23] proposed the concept of "coal-rock gas" by studying the natural gas in the Jurassic Xishanyao Formation coal rocks in the Junggar Basin, and treated coal-rock gas as a new type of natural gas resource that lies between conventional gas and coalbed methane. Zhao et al. [24] conducted a systematic analysis on the geological and development characteristics of coal-rock gas reservoirs, and proposed that coal-rock gas is hydrocarbon gas which is originated from medium to high-rank coal or migrates from other sources, preserved in coal rock reservoirs, and can be produced rapidly and achieve large-scale production after reservoir stimulation. Li et al. [25] thought that coal-rock gas is a type of hydrocarbon gas which is generated within coal rocks or migrated from other gas sources and stored in coal rocks, exists in both free and adsorbed states, with a high free gas content, and can be rapidly and industrially produced through reservoir stimulation. Based on previous research, this paper defined coal-rock gas as hydrocarbon gas located in coal rock reservoirs below the "critical depth", where the negative temperature effect dominates with high content of free gas, requiring reservoir stimulation for rapid gas production and large-scale extraction. The concept of coal-rock gas provides better insights into the differences between coal-rock reservoirs below “critical depth” and shallow coalbed methane from aspects of gas content, occurrence characteristics, and production characteristics.
As a new type of natural gas preserved in coal rocks, coal-rock gas has garnered significant attention in recent years [26]. Notably, multiple well areas in the Ordos Basin have achieved breakthroughs in high-yield industrial gas flows, greatly enhancing confidence in large-scale commercial development of coal-rock gas. Currently, exploration and development of coal-rock gas in China are at initial stages, with relatively few studies on geological characteristics and enrichment conditions. Existing theories derived from shallow coalbed methane accumulation cannot be fully applied to coal-rock gas evaluation, hindering effective exploration and development of coal-rock gas. Based on the sedimentary environment and distribution characteristics of deep coal rocks in the Ordos Basin, this paper investigated their hydrocarbon generation characteristics, reservoir performance, gas content, and accumulation play, elucidated the geological characteristics and enrichment conditions of coal-rock gas in the Ordos Basin, and identified the favorable areas for coal-rock gas enrichment, in order to point out the future direction of coal-rock gas exploration and provide a theoretical foundation for large-scale exploration and development of coal-rock gas in China.

1. Exploration and development history of coal-rock gas in the Ordos Basin

Natural gas exploration in the coal seams of the Ordos Basin began in the 1990s, expanding from shallow layers on the eastern edge to deeper layers within the basin. Based on geological understanding, technological advancements, exploration efforts and findings, and gas production change, the exploration and development history of natural gas in the Carboniferous-Permian coal seams of the Ordos Basin can be divided into two phases: shallow coalbed methane exploration and large-scale coal-rock gas exploration and development.

1.1. Shallow coalbed methane exploration phase (1990-2018)

Shallow coalbed methane exploration began in the 1990s, focusing on locating coalbed methane enrichment areas with shallow burial, thick coal seams, high gas content at structural high, under the theoretical guidance of "gas accumulation at structural highs in shallow coal-rich areas". From 1990 to 1996, the North China Petroleum Exploration Bureau of Ministry of Geology and Mineral Resources and the Arco Corporation (USA) conducted small well group production in the Liulin area of Lüliang City, Shanxi Province, with coal seam depths ranging from 343 m to 409 m, Ro values ranging from 1.40% to 1.72%, gas content ranging from 10 m3/t to 20 m3/t, and individual well gas production rates ranging from 1 500 m3/d to 3 000 m3/d [27]. From 1998 to 1999, the Langfang Branch of the PetroChina Research Institute of Petroleum Exploration & Development completed two coalbed methane exploratory wells in the Wubu area of Yulin City. The Wushi 1 well has a burial depth of 1 229.5 m in the Permian Shanxi Formation 5# coal seam and 1 349.8 m in the Carboniferous Benxi Formation 8# coal seam, with a peak instantaneous gas production of 990 m3/d. Between 2000 and 2004, the Langfang Branch conducted the Jishi well group in the Daning-Jixian area of Linfen City. In this well group, Jishi 1 well reaches a depth of 977.8 m in the 5# seam with a gas content of 20.7 m3/t, and 1 050.6 m in the 8# seam with a gas content of 16.1 m3/t, and its gas production rate keeps stable in the range of 1 000-1 500 m3/d, with the maximum instantaneous gas production of 2 847 m3/d. The Jishi 5 well has a burial depth of 904.4 m in the 5# seam (20.9 m3/t gas content) and 965.1 m in the 8# seam (9.5 m3/t gas content), with a peak instantaneous gas production of 6 800 m3/d. From 2004 to 2008, the PetroChina Changqing Oilfield Company intensified coalbed methane exploration. Five exploratory wells and 21 appraisal wells were drilled in Daning-Jixian area of Linfen City and Heyang area of Weinan City, and three evaluation well groups were constructed, namely Wucheng, Xiaohuigong, and Heyang. Wushi 2-3 well reaches a depth of 1 365 m, with a peak instantaneous gas production of 3 003 m3/d; Gong 1-2 well reaches 1 102.25 m with a maximum production of 2 379 m3/d, and Gong 1-3 well reaches 1 107.92 m with a maximum production of 2 757 m3/d. In 2009, the Gong 1 well area submitted proven reserves of 295×108 m3, with cumulative 3P reserves reaching 1 483×108 m3 [28]. From 2009 to 2018, the exploration approach shifted from the "structural high" selection theory to a new framework guided by the "hydrodynamic control of gas-structural adjustment-hydrocarbon accumulation at monocline gentle slope" theory. This deepened the understanding of gas-rich theory of "positive structures and monocline gentle slopes", leading to a change in coal reservoir stimulation strategies. The PetroChina Coalbed Methane Company Limited implemented the Taoping 03 well, a horizontal well in the Daning-Jixian block, utilizing a completion technique of casing cementing, directional perforation, and staged fracturing in the 5# coal seam. This resulted in stable gas production of over 6 000 m3/d, achieving high production of coalbed methane by horizontal well. In 2016, the Ji 4 to Ji 10 well cluster in the Daning-Jixian block reported an additional proven coalbed methane reserve of 222.31×108 m3 [27-28]. Shallow coalbed methane exploration has demonstrated the prospect of coalbed methane exploration and development on the eastern edge of the Ordos Basin, but individual well production still remains low overall, with limited fracturing scale and long gas breakthrough cycles, hindering substantial breakthroughs.

1.2. Large-scale exploration and development phase of coal-rock gas (2019 to present)

From 2019 to 2021, guided by the concept of "micro- overpressure and high saturation adsorption", "geological-engineering" sweet spot evaluation was conducted, achieving breakthroughs in natural gas exploration in coal seams deeper than 2 000 m. PetroChina Coalbed Methane Company Limited drilled the Daji 3-7 Xiang 2 well in the western slope of the Daning-Jixian block, which reaches a depth of 2 217-2 225 m in 8# coal seam and utilizes a composite fracturing fluid of active water and clean liquid, resulting in gas production upon commencement, with stable output of 3 500 m3/d [27]. The Jishen 6-7 Ping 01 well employed the extreme volume fracturing and ignited combustible gas on the same day, achieving a high production rate of 10.1×104 m3/d. The Daning-Jixian block has submitted the proven geological reserves of 1 121.62×108 m3, becoming the first high- abundance monoblock large coalbed natural gas field in China with a depth exceeding 2 000 m and proven geological reserves surpassing 100 billion cubic meters [18,27]. The PetroChina Changqing Oilfield Company produced the 8# coal seam (at a depth of 2 381.5 m) in the Y160 well within the basin. Gas production began after 33 drilling days, with a peak production rate of 1 669 m3/d and a stable production rate of 1 100 to 1 300 m3/d. This marks an extension of natural gas exploration from the eastern edge to the deeper interior of the basin, revealing that the deep coal seams are rich in free gas, with early gas breakthrough during the production test and characteristics of coexisting adsorbed and free gas. In 2022, benefiting from the advancements in volumetric fracturing technology and referring to the unconventional shale oil development concept of "vertical well for reservoir control and horizontal well for production enhancement", the PetroChina Changqing Oilfield Company implemented the wildcat well NL1H targeting the 8# coal seam in the central-eastern basin at a depth of 3 246.09 m. Using pre-acid and guanidine gel with sand fracturing, the well exhibited gas flow upon opening, achieving a test gas output of 5.0×104 m3/d. Meanwhile, the Y160H well (depth of 2 381.5 m), using variable viscosity slickwater (VSW) with sand fracturing, ignited combustible gas on the following day and attained a test gas flow of 4.8×104 m3/d, marking a strategic breakthrough for coal-rock gas in the basin. Since 2023, efforts have been focused on optimizing geological-engineering sweet spots around NL1H and M172H, encompassing development evaluations and pilot test well groups. In 2023, 23 horizontal wells were drilled, averaging a horizontal segment length of 1 265.5 m, with 1 192.0 m of coal seams encountered and a drilling rate of 94.2%. The M172H (vertical depth of 2 415.49 m), J26H (vertical depth of 3 093.71 m), T11 (vertical depth of 2 625.48 m), and HT8H (vertical depth of 3 206.45 m) wells each exceeded 10×104 m3/d in test gas production, with HT8H achieving a record-breaking 18.2×104 m3/d, setting a new daily production record for a single coal-rock gas well in Changqing oilfield.

2. Deep coal rocks

2.1. Developmental environment of coal seams

During the Late Carboniferous, the North China Block was located south of 30°N, characterized by a warm and humid climate with developed vegetation. Regional sea level changes affected the gently sloping terrain, leading to the formation of extensive transitional coal seam in the Ordos Basin. Ten coal seams developed vertically, with the 5# and 8# seams being the primary coal layers (Fig. 1). The 5# coal seam was formed primarily in peat swamp environments of deltaic plain interfluves and delta front interdistributary bays, exhibiting low sulfur content. In contrast, the 8# coal seam was formed in nearshore plain and tidal flat environments influenced by seawater, resulting in high sulfur content (Fig. 2). Due to the influence of clastic material supply from provenances and significant marine regression, not only the industrial analysis of the coal, but also the maceral and inorganic element distribution characteristics of coal rocks confirm that the coal-forming environment in the basin became less influenced by terrestrial clastic input moving from the northern and southern provenances toward the central catchment zone. This resulted in increased water reduction and promoting gelification processes [29-30].
Fig. 1. Structural units (a) and composite stratigraphic column (b) of the Ordos Basin.

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Fig. 2. Well-tie section of coal-bearing formation in the 2nd Member of Shanxi Formation (Shan 2 Member) (a) and the Benxi Formation (b) in the Ordos Basin (see the section location in Fig. 1).

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2.2. Distribution of coal seams

During the Late Paleozoic, woody plants were developed, and the accumulation rate of plant remains was generally consistent with the rising rate of water level in swamps. Under equilibrium compensation conditions, the peat layer was continuously thickened, leading to the extensive overlapping development of multiple peat swamp facies, which contributed to the formation of thick coal seams in the basin. The main coal seam, the 5# seam, has a thickness ranging from 2 to 8 m, with an average of 3.0 m. The thick coal layers are distributed in a band-like manner, primarily located to north of the Sulige-Jingbian- Wubu line, in the Daning-Jixian-Heyang area of southeastern basin, and to the west of the Qingyang-Huachi line in the southwestern basin (Fig. 3a). The 8# coal seam is well-developed throughout the basin with good continuity. The 8# coal seam is thicker than the 5# seam, ranging from 6 to 16 m, with an average thickness of 7.8 m. The coal accumulation centers are primarily located to north of the Wushenqi-Hengshan-Wubu line and in the Daning area of southeastern basin, where seam thickness exceeds 8 m and decreases toward the west and the south, exhibiting a northeast-southwest band-like distribution of overlapping with each other (Fig. 3b). Seismic geological interpretation profiles indicate that the 8# coal seam in the Ordos Basin exhibits continuous high amplitude with good continuity, while the 5# seam shows intermittent moderate to high amplitude with relatively good continuity (Fig. 4). Overall, the basin features simple internal structures and gentle stratigraphy, with complex structures on both flanks. The coal seams display a distribution pattern that is thick and shallow in the east and thin and deep in the west (Figs. 3 and 4).
Fig. 3. Depth and thickness distribution of the 5# coal seam (a) and 8# coal seam (b) in the Ordos Basin.

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Fig. 4. Seismic geological interpretation profile of the Ordos Basin (see the section location in Fig. 1).

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3. Conditions for coal-rock gas enrichment

3.1. High thermal evolution and hydrocarbon potential

The coal source rocks are fundamental for the formation of coal-rock gas. In the Ordos Basin, the 5# and 8# coal seams exhibit relatively high total organic carbon content (TOC), chloroform bitumen "A" content, and total hydrocarbon content. Specifically, the 5# seam has TOC ranging from 49.3% to 89.2% (on average 73.6%), chloroform bitumen "A" content from 0.203 3% to 2.449 1% (average 0.8012%), and total hydrocarbon content ranging from 519.9×10-6 to 6 699.9×10-6 (on average 2 539.8×10-6). The 8# seam shows TOC between 55.4% and 80.3% (on average 70.8%), chloroform bitumen "A" content from 0.406 2% to 0.966 0% (on average 0.770 6%), and total hydrocarbon content ranging from 240.0×10-6 to 4 556.5×10-6 (onaverage 2 896.2×10-6). The 5# and 8# coal seams in the Ordos Basin exhibit overall good hydrocarbon generation potential, with generative capacity ranging from 4 to 220 mg/g and hydrogen index from 10 mg/g to 260 mg/g. According to the evaluation criteria for the hydrocarbon generation potential of coal in medium to high evolution stage by Dong et al. [31], a generative capacity of 6-10 mg/g and a hydrogen index of 12-18 mg/g indicate good source rocks, while values greater than 10 mg/g and 18 mg/g denote excellent source rocks. Approximately 75% of coal samples from the Paleozoic coal are classified as good to excellent source rocks. The rank of coal influences its hydrocarbon generation capability. Typically, lignite generates less methane, while anthracite has a strong methane generation potential, reaching up to 590 m3/t [24]. In the Ordos Basin, the Ro values of the 5# and 8# coal seams primarily range from 1.2% to 2.4%, indicating medium to high metamorphic bituminous coal to anthracite, with robust gas generation capacity.

3.2. The development of coal fractures and pores enhances the storage capacity of coal rock gas

The development, distribution characteristics, and storage performance of coal reservoirs determine the ratio of adsorbed gas to free gas, ultimately influencing the enrichment of coal-rock gas. A reservoir characteristic analysis was conducted on 26 coal samples from the study area. The porosity of the 5# coal seam ranges from 2.5% to 5.5%, with an average of 4.1%. The 8# coal seam exhibits higher porosity, ranging from 4.8% to 9.0%, averaging 6.4% (Fig. 5a). The permeability of the 5# coal seam is (2.4-21.1)×103 μm2, with an average of 8.7×103 μm2, while the No. 8 coal seam permeability is (2.3-98.5)×103 μm2, averaging 15.7×103 μm2 (Fig. 5b). The development of cleats and fractures is significant, typically ranging from 3 to 33 cleats per 5 cm, averaging 7 to 8 cleats per 5 cm. The development degree of cleats and fractures greatly influences permeability, and more developed fractures lead to higher permeability.
Fig. 5. Distribution of porosity (a) and permeability (b) in deep coal reservoirs of the Ordos Basin.

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Previous studies [32] indicate that coal reservoirs possess a dual medium of pore-fracture storage space, where adorption pores (micropores and mesopores) primarily influence gas adsorption and diffusion, while flow pores (macropores and fractures) serve as the main pathways for gas flow [33]. According to the classification method stipulated by the International Union of Pure and Applied Chemistry (IUPAC) [34], pores are categorized by diameter into micropores (<2 nm), mesopores (2-50 nm), and macropores (>50 nm). Micro-CT scanning allows for quantitative characterization of the spatial distribution and connectivity of certain macropores and microfractures within coal reservoirs [35-36]. Due to factors such as the height and diameter of cylindrical coal samples (5.0 cm height×2.5 cm diameter) and the exposure time during experiments, the maximum resolution of micro-CT scanning is approximately 10 μm. The effective pore size measurement range by high-pressure mercury intrusion analysis after Washburn equation is 3 nm to 10 μm. The upper limit of the mercury intrusion test results is close to the resolution of the micro-CT scanning presented in this study [37]. This study defined a lower limit of 10 μm (10 000 nm) for fracture characterization. Using CO2 adsorption, low-temperature N2 adsorption, high-pressure mercury intrusion, and micro-CT scanning, we employed a four-class classification of micropores (<2 nm), mesopores (2-50 nm), macropores (50-10 000 nm), and fractures (>10 000 nm) to characterize the structural characteristics of reservoir space throughout all pore diameters in deep coal rocks. Results indicate that the pores in both 5# and 8# coal primarily consist of micropores and fractures, with pore and fracture volumes exhibiting an "U"-shaped distribution, highlighting the coexistence of micropores and fractures (Fig. 6). In the Q35 well (sample Q35-8-2-7), for example, the pore and fracture volume of 8# coal is 0.098 cm3/g, with the largest contribution from micropores (0.067 cm3/g), accounting for 68.6% of the total volume, followed by fractures (0.025 cm3/g), accounting for 25.3%. Mesopores and macropores show smallest volumes, comprising 2.9% and 3.2%, respectively. In Well WT1H (sample WT1H-5-1-14), the pore and fracture volume of 5# coal is 0.049 cm3/g, with comparable contributions from fractures (0.020 cm3/g, 41.1%) and micropores (0.020 cm3/g, 41.0%). Mesopores and macropores are minimal, representing 9.0% and 8.9%, respectively.
Fig. 6. Distribution of different types of reservoir space in deep coal rocks of the Ordos Basin.

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The development degree of pore and fracture is closely related to the thermal evolution degree. As the Ro value increases, the volume and specific surface area of micropores in coal increase, indicating enhanced micropore development with rising coal ranks. Conversely, the volume of fractures tends to decrease, likely due to increased compaction associated with greater burial depth (Fig. 7a, 7b). As ash content increases, the volume of micropores and fractures decreases, along with the specific surface area of micropores in coal, indicating a negative impact of ash content on the development of pores and fractures in coal reservoirs (Fig. 7c, 7d). Due to the strong heterogeneity of coal seams, there are significant differences in ash content among coal formed in different depositional environments. During the early stages of deposition, clay minerals tend to fill the original plant cell cavities, modifying primary pores. Moreover, high-ash coal typically forms in more oxidative depositional settings, characterized by higher inertinite content and lower vitrinite content. This maceral affects the formation of pores and the development of cleats and fractures during later coalification processes.
Fig. 7. Correlation of reservoir space with thermal evolution degree (a, b) and ash content (c, d) of deep coal in the Ordos Basin.

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The pore development characteristics and industrial composition of the Benxi Formation 8# coal exhibit notable vertical heterogeneity [38]. The semi-bright coal in the lower section overall has relatively low porosity and higher ash content, while the bright and semi-bright coal in the middle and upper sections show higher porosity, with increased fixed carbon content and reduced ash content. Samples with higher ash content and lower fixed carbon content have lower porosity (Fig. 8), exhibiting a clear negative correlation of porosity with ash content and a positive correlation with fixed carbon content. This relationship suggests that the pore development characteristics of the 8# coal are influenced by terrigenous mineral input, where higher ash content can lead to pore and fracture infilling, resulting in reduced porosity. The distribution characteristics of pore volumes throughout all pore diameters indicate that the lower section of the 8# coal is less developed in terms of pores, with both micropores and macropores being less developed than those in the middle and upper sections. Combined with the industrial composition analysis results, it is indicated that the bright coal in the upper and middle sections of 8# coal seam exhibits lower ash content and better-developed pores and fractures, making it a favorable reservoir, while the lower semi-bright coal is not favorable for the preservation of coal-rock gas for the pores are infilled due to the effect of terrigenous mineral infilling.
Fig. 8. Comprehensive columnar chart of the characteristics of the 8# coal seam of the Benxi Formation in Well M172.

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3.3. High gas content and proportion of free gas in coal

The total gas content in the coal was measured using on-site core analysis methods, and the maximum adsorbed gas content was calculated using parameters from methane isothermal adsorption experiments (Langmuir volume and pressure) and reservoir pressure, with the difference between these two contents representing free gas content. In addition, the proportions of adsorbed gas and free gas were calculated. The results reveal that the total gas content of the 5# coal seam in the Ordos Basin ranges from 7.5 m3/t to 20.0 m3/t, with an average of 13.0 m3/t. The adsorbed gas content ranges from 5.7 m3/t to 13.6 m3/t (Fig. 9a), with an average of 8.5 m3/t. The free gas content ranges from 1.7 m3/t to 8.0 m3/t (Fig. 9b), with an average of 4.5 m3/t. The 8# coal seam exhibits a higher total gas content, ranging from 15.1 m3/t to 32.7 m3/t, with an average of 24.6 m3/t. The adsorbed gas content ranges from 12.3 m3/t to 27.2 m3/t (Fig. 9a), with an average of 19.2 m3/t, while the free gas content ranges from 1.7 m3/t to 10.1 m3/t (Fig. 9b), with an average of 5.4 m3/t. The proportion of free gas in the coal-rock gas of the Ordos Basin is between 11.0% and 55.1%, which significantly differs from shallow coalbed methane, whose adsorbed gas typically exceeds 90% and free gas represents less than 10%.
Fig. 9. Distribution of gas content in deep coal reservoirs of the Ordos Basin.

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The amount of adsorbed gas shows a significant positive correlation with the micropore specific surface area, indicating that adsorbed gas volume increases with increasing micropore specific surface area. Micropores provide numerous adsorption sites for gas storage in coal. Additionally, a clear positive correlation exists between the adsorbed gas quantity and the micropore volume, primarily because the volume of coal and fractures in coal is predominantly contributed by micropores. Micropores, with their large specific surface area, control the adsorbed gas quantity, indicating that they primarily govern the ability to adsorb methane in deep coal reservoirs. The free gas quantity shows a positive correlation with macropore and fracture volumes, suggesting that as these volumes increase, the free gas quantity also rises (Fig. 10). Macropores and fractures provide storage space, facilitating the enrichment of coal-rock gas. Research indicates that as the burial depth of coal increases to a certain level, the positive effect of formation pressure on gas adsorption becomes less significant than the negative effect of temperature (i.e., desorption effect), resulting in the gradual saturation of adsorbed gas (with an adsorption saturation of 100%) and the transition to the native free gas accumulation stage for the formation of deep supersaturated coal-rock gas reservoirs [39]. In contrast to shallow coal seams, which are significantly affected by tectonic activities, deep coal formations exhibit greater structural stability and favorable preservation conditions, providing advantageous storage space for free gas. Consequently, in deep coal reservoirs, larger macropore-microfracture volume correlate with greater capacities for free gas storage, indicating the controlling effect of macropores and microfractures on the free gas storage capacity of deep coal reservoirs.
Fig. 10. Correlation of reservoir space characteristics with adsorbed gas content (a, b) and free gas content (c, d) of deep coal in the Ordos Basin.

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3.4. In-situ accumulation within the source rock, with favorable roof sealing conditions

Coal-rock gas exhibits the accumulation characteristics of "source-reservoir integration, continuous hydrocarbon generation, and box-type sealing". Due to the strong gas production capacity of coal, the generated but not expelled methane is effectively trapped within the coal pores, resulting in five key occurrence characteristics of "high pressure, high temperature, high gas content, high saturation, and high free gas", which contrast sharply with those of shallow and medium coalbed methane (Fig. 11).
Fig. 11. Comparison between coal-rock gas and coalbed methane accumulation models of the 8# coal seam in the Ordos Basin.

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A well-sealed roof and floor combination provides ideal preservation conditions for coal-rock gas enrichment. The ability of natural gas generated within the coal to be effectively stored in the coal reservoir to form self-generated and self-stored coal-rock gas is significantly influenced by the sealing capacity of the coal seam's roof and floor. Effective surrounding rock can effectively prevent the dissipation of coal-rock gas [27]. Mudstone is tight with low permeability, so it can effectively prevent the escape of natural gas. Thick layers of mudstone and tight limestone serve as excellent sealing layers, while sandstone roof is detrimental to coal-rock gas accumulation. The 8# coal seam is thick and continuous, with limestone and mudstone roof and mudstone floor, indicating favorable sealing conditions. Seismic profiles show continuous reflections from the coal seam, with distinct lithological changes between the roof and the floor, particularly characterized by limestone reflections. The quality of sealing conditions varies with the play characteristics. Mudstone at the floor provides ideal sealing, while sandstone, despite its good reservoir quality and permeability, weakens the storage capacity, making it unfavorable for the preservation of Benxi Formation coal-rock gas. Under the condition of mudstone/limestone (roof)-coal seam-mudstone (floor) play, overall coal rock gas measurements are high, indicating favorable accumulation conditions.
Based on the lithological variations of the coal seam's roof, the 5# coal seam is categorized into two accumulation plays: coal-mudstone and coal-sandstone, and the 8# coal seam is divided into three accumulation plays: coal- limestone, coal-mudstone, and coal-sandstone (Fig. 12). The peak gas contents of coal-limestone and coal-mudstone typically range from 65% to 95%, indicating good gas-bearing property. Pressure testing analysis of the coal rock shows that the coal-limestone and coal-mudstone plays have favorable sealing properties. The stress differences between the coal rock and the roof and floor barriers range from 6.7 MPa to 12.0 MPa, meeting the stress isolation conditions for large-scale stimulation.
Fig. 12. Comparison of accumulation combination profiles for the 5# (a) and 8# (b) coal seams (see the section location in Fig. 1). GR—natural gamma; Δt—acoustic time difference.

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4. Coal-rock gas resource potential and exploration directions

4.1. Coal-rock gas resource potential

4.1.1. Calculation methods for coal-rock gas resources

Currently, the primary methods for calculating coal-rock gas resources include the volumetric method, analogy method, and numerical simulation method [40-41]. There are no standardized calculation guidelines for coal-rock gas resources. Referring to the calculation methods for coalbed methane resources, this study adopted the volumetric method to calculate coal-rock gas resources, with comprehensive consideration of the characteristics, exploration degree and geological understanding of coal- rock gas reservoirs [42].
Q=0.01Ahρq
where Q—coal-rock gas resource volume, 108 m3; A—gas-bearing area, km2; h—effective thickness of coal seam, m; ρ—average coal density, t/m3; q—measured average gas content of coal, m3/t.

4.1.2. Determination of evaluation parameters

The evaluation of coal rock gas resources is divided into two zones: the 5# and the 8# coal seam. Considering factors such as coal thickness, thermal evolution degree, accumulation play type, burial depth, and gas content, the 8# coal seam is classified into 11 evaluation zones (Table 1), while the 5# coal seam is divided into 16 evaluation zones (Table 2). Coal-rock gas is contained within the coal reservoir, below the "critical depth," which is controlled by the coal rank. The critical depth for medium to high-rank coals is 1 500 m to 1 800 m [21]. The Ro values of the 5# and 8# coal seams in the Ordos Basin range from 1.2% to 2.4%, indicating a medium to high-rank bituminous to anthracite coal. Therefore, the starting depth for resource evaluation in the Ordos Basin is set at 1 500 m. The coal seam thickness is primarily assessed using the contour area weighting method, while the gas content parameter is the average of all measured gas contents within the evaluation zones, and the coal density is the average of all measured apparent densities within the evaluation zones, as detailed in Table 1 and Table 2.
Table 1. Evaluation data for coal-rock gas resources of the 8# coal seam in the Ordos Basin
No. Zone name Area/
km2		 Average coal thickness/m Density/
(t·m-3)		 Average gas
content/(m3·t-1)		 Ro/% Buried
depth/m		 Resources/
108 m3
1 Otog Banner 8 999 4.2 1.4 15.0 1.2-2.0 3 500-4 000 7 937
2 North of Uxin Banner 7 349 6.4 1.4 17.0 1.2-2.0 2 500-3 500 11 194
3 Ordos-Shenmu 19 050 9.0 1.4 15.0 0.6-1.2 1 500-3 000 36 005
4 Otog Front Banner 4 190 3.3 1.4 15.0 1.2-1.6 3 500-4 000 2 904
5 Dingbian-Wuqi 21 420 3.0 1.4 18.0 1.6-2.0 3 500-4 000 16 194
6 Uxin Banner 15 277 7.0 1.4 24.0 1.6-2.4 2 500-3 500 35 932
7 Hengshan-Suide 8 682 8.5 1.4 25.0 1.6-2.4 1 500-3 000 25 829
8 West of Wuqi 4 831 3.0 1.4 18.0 1.8-2.2 3 500-4 000 3 652
9 Zichang 10 400 3.0 1.4 23.0 1.8-2.8 2 000-3 500 10 046
10 Yan'an 9 457 5.0 1.4 25.0 2.6-3.0 1 500-3 000 16 550
11 Yichuan 8 346 3.0 1.4 24.0 2.2-3.0 1 500-3 500 8 413
Total 118 001 174 654
Table 2. Evaluation data for coal-rock gas resources of the 5# coal seam in the Ordos Basin
No. Zone name Area/
km2		 Average coal
thickness/m		 Density/
(t·m-3)		 Average gas
content/(m3·t-1)		 Ro/% Buried
depth/m		 Resources/
108 m3
1 Otog Banner 1 015 3.30 1.4 18.0 1.6-2.0 3 500-4 000 844
2 North of Uxin Banner 3 791 4.10 1.4 18.0 1.2-2.0 2 500-3 500 3 917
3 Ordos 4 395 5.20 1.4 11.0 0.6-1.2 1 500-3 000 3 520
4 North of Shenmu 3 721 5.00 1.4 11.0 0.6-1.2 1 500-2 500 2 865
5 South of Shenmu 2 925 5.10 1.4 11.0 0.8-1.2 1 500-2 000 2 297
6 Yulin 4 322 6.00 1.4 20.0 1.2-2.0 2 000-3 000 7 261
7 Uxin Banner-Hengshan 5 259 4.00 1.4 20.0 1.4-2.0 2 500-3 500 5 890
8 West of Uxin Banner 587 4.00 1.4 18.0 1.4-2.0 3 000-3 500 592
9 East of Otog Front Banner 1 536 3.00 1.4 18.0 1.6-2.0 3 500-4 000 1 161
10 West of Otog Front Banner 649 3.00 1.4 18.0 1.4-2.0 3 500-4 000 491
11 West of Nalinhe 466 2.50 1.4 20.0 1.6-2.0 3 000-3 500 326
12 Mizhi 2 331 2.80 1.4 23.0 1.6-3.0 2 000-3 000 2 102
13 West of Linxian 1 458 4.50 1.4 22.0 1.2-2.8 1 500-2 500 2 021
14 Dingbian 650 2.50 1.4 20.0 1.6-2.0 3 500-4 000 455
15 West of Jingbian 1 265 2.50 1.4 20.0 1.6-2.4 3 500-4 000 886
16 Yichuan-Huangling 9 843 4.80 1.4 22.0 1.6~3.0 1 500-3 000 14 552
Total 44 213 49 179

4.1.3. Geological resources and distribution of coal-rock gas

Using the volumetric method, the total overlapping area of deep coal reservoirs in the basin (burial depth greater than 1 500 m) is estimated to be 165 000 km2, with a total coal-rock gas resource volume of 22.38×1012 m3. Among this, the resource volume of the 8# coal seam is 17.47×1012 m3, while that of the 5# coal seam is 4.92×1012 m3. The 8# coal seam resources are primarily distributed in five evaluation zones: Ordos-Shenmu, Wushenqi, Hengshan-Suide, Yan'an, and Dingbian-Wuqi, accounting for 75% of the total resources. The 5# coal seam resources are mainly found in five zones: Yichuan-Huangling, Yulin, Wushenqi-Hengshan, Wushenqi North, and Ordos, constituting 71% of its total coal-rock gas resources.

4.2. Exploration targets and favorable area evaluation of coal-rock gas

Analysis of the coal reservoir characteristics, gas content, and accumulation factors indicates that significant coal thickness (larger than 2 m), suitable coal rank (coking, meagre, lean, and anthracite), favorable accumulation play (coal-mudstone and coal-limestone), and appropriate burial depth (1 500 m to 4 000 m) are key controls on coal-rock gas enrichment. Based on parameters such as coal thickness, coal rank, burial depth, and accumulation play, evaluation standards for favorable areas in the 5# and 8# coal seams were established (Table 3 and Table 4). The evaluation results (Fig. 13) indicate that there is one Class I favorable area for 5# coal rock gas located in the Linxian West, covering an area of 1 458 km2. There are two Class II favorable areas primarily in the Mizhi and Yichuan-Huangling regions, with a total area of 12 174 km2. Additionally, there are two Class III favorable areas mainly in the Yulin and Wushenqi-Hengshan regions, totaling 9 581 km2. There are three Class I favorable areas for 8# coal rock gas located in Wushenqi, Hengshan-Suide, and Yan'an, covering a total area of 33 416 km2. Additionally, two Class II favorable areas are situated in Zichang and Yichuan, with a total area of 18 746 km2. These regions are promising for the formation of new natural gas reserves and potential production increases.
Table 3. Evaluation criteria for favorable areas of the 5# coal seam in the Ordos Basin
Comprehensive evaluation Ro/% Gas accumulation play Thickness/m Burial depth/m
I >1.2 Coal-mudstone >4 1 500-3 500
II >1.2 Coal-mudstone 2-4 1 500-3 500
III >1.2 Coal-sandstone & coal-mudstone >4 1 500-3 500
IV >1.2 Coal-sandstone & coal-mudstone 2-4 1 500-3 500
V >1.2 Coal-sandstone & coal-mudstone 2-4 3 500-4 000
VI >1.2 Coal-sandstone >4 1 500-3 500
VII >1.2 Coal-sandstone 2-4 3 500-4 000
VIII <1.2 Coal-sandstone & coal-mudstone >4 1 500-3 500
IX <1.2 Coal-sandstone >4 1 500-3 500
Table 4. Evaluation criteria for favorable areas of the 8# coal seam in the Ordos Basin
Comprehensive evaluation Ro/% Gas accumulation play Thickness/m Burial depth/m
I >1.2 Coal-mudstone & coal-limestone/coal-limestone >4 1 500-3 500
II >1.2 Coal-mudstone & coal-limestone/coal-limestone 2-4 1 500-3 500
III >1.2 Coal-mudstone & coal-limestone/coal-limestone 2-4 3 500-4 000
IV >1.2 Coal-sandstone & coal-mudstone >4 1 500-3 500
V >1.2 Coal-sandstone & coal-mudstone >4 3 500-4 000
VI >1.2 Coal-sandstone & coal-mudstone 2-4 3 500-4 000
VII <1.2 Coal-sandstone & coal-mudstone >4 1 500-3 500
Fig. 13. Distribution map of favorable areas for coal-rock gas in the 5# (a) and 8# (b) coal seams in the Ordos Basin.

Full size|PPT slide

5. Conclusions

The Ordos Basin exhibits extensive thick coal seams in the Carboniferous to Permian, with the Shanxi Formation 5# and Benxi Formation 8# seams being the primary coal layers. In deep coal reservoirs, the developed cleats and fractures, along with micropores, constitute the main reservoir space. Additionally, as the degree of evolution increases, the volume of micropores tends to expand.
Due to the negative effects of temperature, the adsorbed gas in deep coal reaches saturation state, entering the stage of in-situ free gas accumulation. This results in a high free gas content in coal-rock gas, with free gas accounting for over 10%. The enrichment of free gas is primarily controlled by the development of macropores and microfractures.
Deep coal reservoirs in the Ordos Basin possess high organic matter abundance and strong gas generation capacity, indicating a high-maturity thermal evolution stage that provides a solid material basis for the formation of coal-rock gas. Overall, the reservoir performance is favorable, particularly characterized by well-developed pores and fractures, abundant macropores, low ash content, high gas content, and a significant proportion of free gas in the upper bright coal section. Moreover, the in-situ accumulation within the coal and the effective roof sealing provide favorable preservation conditions for coal-rock gas.
A preliminary assessment of coal-rock gas resource potential in the Ordos Basin using the volumetric method shows the estimated total amount of coal-rock gas resources in the basin is at 22.38×1012 m3. The favorable exploration areas for the 8# coal seam of the Benxi Formation are identified in the central and eastern regions, including Wushenqi, Hengshan-Suide, Yan'an, Zichang, and Yichuan. Additionally, the favorable exploration areas for the 5# coal seam of the Shanxi Formation are located in Linxian West, Mizhi, Yichuan-Huangling, Yulin, and Wushenqi-Hengshan. These regions hold potential for new natural gas reserves and production growth. Coal-rock gas will be an important replacement field of natural gas exploration in the Ordos Basin.

Acknowledgments

We are grateful for the valuable suggestions provided by Professor Wen Zhigang's team from Yangtze University during the analysis of conditions for coal-rock gas enrichment.

References

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China's deep coalbed methane (CBM) resources, with the burial depths exceeding 1 500 m, are abundant and coexist with adsorbed and free gases. The occurrence state, accumulation characteristics, and development laws of deep CBM differ significantly from those of mid-shallow CBM, and the unclear evolution patterns have restricted its efficient exploration and development. Taking the No.8 deep coal seam in Daning-Jixian block on the eastern margin of Ordos Basin for example, this study finely characterizes the accumulation characteristics of deep CBM and simulates the burial evolution history, thermal evolution history, and hydrocarbon generation history of deep coal seams, thus improving the deep CBM enrichment and accumulation laws and patterns; moreover, the targeted exploration and development strategies are proposed. The results show that the No.8 deep coal seam is widespread in Daning-Jixian block, with high organic matter thermal maturity and Type III kerogen. This indicates significant hydrocarbon generation potential, with the total hydrocarbon intensity of (20.2-34.7) ×10<sup>8</sup>m<sup>3</sup>/km<sup>2</sup>. The deep coal reservoir develops cleats, fractures, texture pores, cell pores, gas pores, intergranular pores, and dissolution pores, providing favorable conditions for the accumulation of deep free-state CBM. The structural-lithologic-hydrodynamic coupling closure is favorable for the preservation of deep CBM. The evolution stages of hydrocarbon accumulation in deep coal seams in the study area include the initial hydrocarbon generation stage (Stage I, 306-251 Ma), the first thermal hydrocarbon generation stage (Stage II, 251-203 Ma), the decreasing stage of organic matter thermal evolution (Stage III, 203-145 Ma), the hydrocarbon generation peak stage (Stage IV, 145-130 Ma), and the final formation stage of the oil/gas accumulation pattern (Stage V, 130 Ma to present). The deep CBM under free and adsorbed states coexist in the study area. On this basis, the paper proposes the hydrocarbon enrichment and accumulation pattern of "wide covering hydrocarbon generation, box-type closure, microstructure adjustment, self-generation and self-storage, and blanket-type accumulation", and establishes three types of deep CBM accumulation models:microfold and physical property coupling control (Type I), microfault monocline and hydrodynamic force coupling control (Type II), and physical property and hydrodynamic force coupling control (Type III) on reservoir accumulation. These understandings can effectively guide the selection of favorable areas for deep CBM exploration in Daning-Jixian block, establish an evaluation index system for favorable areas in deep coal reservoirs, propose differentiated development plans for exploration areas with different accumulation models, and help achieve the truly efficient and low-cost development of deep CBM in the study area. The research findings have important reference significance for carrying out deep CBM exploration and development in other blocks in China.
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Deep coalbed methane (CBM) resources are abundant in Daning-Jixian block in the eastern margin of Ordos Basin, and the development practice in recent years has broken through the traditional understanding that it is difficult to develop and utilize deep CBM resources. At present, there are still a series of geological problems unsolved in the exploration and development of deep CBM, and especially the control factors of gas-bearing properties and the prediction of free gas content seriously restrict the resource evaluation and efficient development of deep CBM. Comprehensively using the geological data of CBM development and experimental testing methods, the paper compares and analyzes the differences in gas content between mid-deep coal seams (with buried depth from 1 000 m to 1 500 m) and deep coal seams (with buried depth greater than 1 500 m) in Daning-Jixian block, thus discovering the internal and external controlling factors of gas content in deep coal seams, and establishing the prediction models and vertical distribution patterns of gas content in different phases. The results show that the gas oversaturated coal reservoirs are generally detected in deep layer, of which the free gas proportion is from 17% to 43% and tends to increase with reservoir pressure. The free gas content is negatively correlated with water saturation. Before adsorption and saturation, coal reservoir pressure can promote the adsorption of methane by coal seams, while temperature and moisture can inhibit the adsorption of methane. Compared with low-rank coal, high-rank coal has stronger methane adsorption capacity, which is mainly attributed to the material composition of coal, pore structure, physical and chemical reactions between methane molecules and coal surface. Due to many limitations, the adsorbed gas content in coal seams presents a changing trend from "rapid rise to slow growth to slow decline" with the increase of buried depth, while the free gas content presents a trend from "stable rise to slow growth to being constant". Therefore, the change of total gas content in coal reservoirs with buried depth is divided into four evolution stages:rapid rise, slow rise, remaining stable and slow decline.
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Deep coalbed methane (CBM) with a buried depth of greater than 2 000 m is an important field of CBM exploration and development. Different from the middle-shallow CBM that mainly consists of adsorbed gas, the occurrence state of deep CBM is characterized by the coexistence of free gas and adsorbed gas. At present, the desorption law of deep CBM, the opportunity for conversion between free gas and desorbed gas and the reasons for the difference in development effect are still unclear. This paper is a case study of Daning-Jixian block in the eastern margin of Ordos Basin. Since the distribution law of its key geological parameters is consistent with the tectonic trend, the block can be divided into four development areas based on the microstructural morphology, including negative microtectonic area, gentle tectonic area, positive microtectonic area and tectonic uplift area, of which the geological characteristics have been determined. The key factors that impact the development effect of deep CBM can be summarized as "five essential conditions" and "one degree". Moreover, an analysis is performed on the coupling control mechanism of these key factors in deep CBM development. The "five essential conditions" include the preservation condition, resource condition, desorption condition, seepage condition, and reservoir stimulation condition, which are the geological foundation; the "one degree" refers to the degree of fracturing reformation, which needs to be differentially adjusted according to the "five essential conditions" in the hydrocarbon development process. Based on the "five essential conditions" (25 geological parameters), the paper systematically summarizes the evaluation results, comprehensive production characteristics, and typical production curves of coalbed methane development in 4 development areas, and further proposes corresponding engineering countermeasures. Based on the desorption condition that has been neglected in the evaluation of CBM, the main controlling factors affecting the isothermal adsorption characteristics of deep CBM were identified through isothermal adsorption experiments. The adsorption capacity of deep coal rock is weakened with the increase of temperature, ash content, and moisture content, and increased with the increasing level of the thermal evolution of organic matter. Meanwhile, Langmuir pressure keeps increasing with the increase of moisture content; when the ash content in coal rock varies greatly, the adsorption capacity of coal rock is not significantly correlated with the thermal evolution level of coal rock, and the ash content becomes the main controlling factor for desorption; from the gentle tectonic area to positive microtectonic area, the isothermal adsorption curve of coal rock is varied from steep to gentle, the Langmuir volume is decreased by 10.7%, and the Langmuir pressure is increased by 36.8%. In combination with the experimental results from basic theoretical methods, the paper further determines the desorption laws of deep CBM in different tectonic development areas, and compares and analyzes the differences in desorption characteristics. The production process of deep CBM can be divided into four stages:(1) low efficiency desorption stage + free gas dominant stage (Stage Ⅰ), (2) slow desorption stage (Stage Ⅱ), (3) high efficiency desorption stage (Stage Ⅲ), and (4) sensitive desorption stage (Stage Ⅳ). The starting pressure for the desorption of deep CBM in Daning-Jixian block is 9.05 MPa to 9.30 MPa, the desorption turning pressure is about 6.00 MPa, and the desorption sensitive pressure is 2.30 MPa to 2.70 MPa. In the production of deep CBM wells, the transition from dominant free gas production to dominant adsorbed gas production is a process that mainly depends on the duration of the slow desorption stage, the size of key desorption pressure points (desorption starting pressure and turning pressure), pressure drop, and the characteristics of desorption curve. Finally, based on geological laws and relevant understandings, the reasons for the difference in the development effect of CBM wells in the gentle tectonic area and positive microtectonic area have been analyzed in detail, which aims to provide scientific guidance for the fine geological evaluation and units division, prediction of development laws, optimization of gas production equipment, and formulation of drainage and production system in promoting the efficient development of deep CBM.
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Deep coalbed methane (CBM) is a new area in unconventional natural gas exploration of China.Thus, the paper analyzed geological conditions and basic principles of deep CBM reservoirs and discussed the specificity of deep CBM-accumulation effects in three respects including the state transition of deep geo-stress, the negative effect of geothermal field on deep coal adsorptivity, and specific physical properties of coals under temperature and pressure conditions of deep strata. The results show that the critical depth for deep geo-stress state transition is related to the maximum horizontal principal stress, which affects the permeability of deep coal reservoirs in various degrees. The negative effect of deep geothermal field on coal adsorptivity is greater than the positive effect of formation pressure, resulting also in a critical depth for deep CBM content, and the deep CBM content can not be simply predicted using the shallow CBM content gradient. Confining pressure is a major factor that affects mechanical properties of deep coal reservoirs, and the effect of temperature and fluid pressure on mechanical properties is rather complex, it profoundly affects the porosity, permeability and absorptivity of coal reservoirs. As a result of differences in the seepage capability of various surrounding rocks, the fluid pressure system of deep coal seams is significantly controlled by the sedimentary framework of coal-bearing strata, which may lead to different gas-bearing systems for coal and non-coal reservoirs even in the same set of coal-bearing strata. On this basis, an idea named as the four-step hierarchical coupling analysis on deep CBM-accumulation effects was proposed and it provided a basis for the establishment of an optimum method to seek deep favorable CBM zones.
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Deep coalbed methane(CBM) resources is an important basis for the scale development of the CBM industry in China,but some basic geological problems such as the meaning,definition and the particularities on the "deep" are still not clear.Preliminary investigation shows that the particularity of deep coal reservoir is resulted from higher strata temperature and pressure,which bring about higher compressibility,lower permeability and lower elasticity of deep coals.At the scientific level,the "deep" in CBM fields means not only a depth,more important is a state,which is dependent on threefold formation states the including stress,temperature and(organic) reservoir.At the operational level,the definition of the critical depth between deep and shallow CBM needs to takes into account three geological factors such as the stress state conversion,coal adsorption(gas content) and mechanical properties of coals.Recent research progress provides new insights for solving the basic geological problems.The importance of the free gas to the gas content of deep low-rank coal reservoir is explained,the relationship between the desorption and output stage sensitivity of deep CBM is discussed,the profound impact of variable pore compression coefficient on deep low-rank coal reservoir permeability is analyzed,and the seek-optimizing method of favorable deep-CBM zone based on the accumulation effects is set up.It is suggested that still the geological problems of the four aspects need to solve for deep CBM exploration and development.The first is the deepening evaluation and recognition of deep CBM resource potential,the second is the coupling effect of the basic deep geological characteristics to deep coal reservoir,the third is the geological control of the principles of efficient deep CBM development technology under deep strata stress field,temperature field and chemical field,and the fourth is the geological evaluation of the symbiotic characteristics,co-exploring method and co-mining effectiveness of deep CBM,tight sandstone gas and shale gas in coal measure.
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GUO Xujie, ZHI Dongming, MAO Xinjun, et al. Discovery and significance of coal measure gas in Junggar Basin. China Petroleum Exploration, 2021, 26(6): 38-49.
https://doi.org/10.3969/j.issn.1672-7703.2021.06.003
本文引用 [1] 摘要
Based on the analysis of reservoir in coal measure strata, geochemical characteristics of natural gas, as well as the test results ofCBM wells, a new type of natural gas – coal measure gas of the Jurassic Badaowan Formation and Xishanyao Formation is proposed in this study,which is different from both coalbed methane and conventional gas, and characterized by coexistence of conventional and unconventional reservoirs, symbiosis of free gas and adsorbed gas, complementary accumulation and orderly distribution of self-generated and other-source gas. Aiming at this new exploration field, Well Caitan 1H has been deployed in Cai 31 faulted anticline structure in Baijiahai Bulge with the target layer of coal seam of the Jurassic Xishanyao Formation and great discovery of coal measure gas been achieved with the highest gas production of 5.7×104 m3/d and stable gas production of 2×104 m3/d during the well test, which enables a new breakthrough in geology understanding of natural gas, opens up a new field of natural gas exploration, guides a new direction of natural gas exploration, and has a major and far-reaching significance on gas exploration in coal bearing basins.
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ZHAO Zhe, XU Wanglin, ZHAO Zhenyu, et al. Geological characteristics and exploration breakthroughs of coal rock gas in Carboniferous Benxi Formation, Ordos Basin, NW China. Petroleum Exploration and Development, 2024, 51(2): 234-247.
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LI Guoxin, ZHANG Shuichang, HE Haiqing, et al. Coal- rock gas: Concept, connotation and classification criteria. Petroleum Exploration and Development, 2024, 51(4): 783-795.
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<p>This paper studied the key elements of CBM pool that affected by coal generating and storing capacity, permeability of coal seals and preservation of coalbed methane in Daning Jixian area. Results showed that the CBM pool of this area was sealed off by tectonic and artesian hydrodynamic force. Deposition environment, coalbed permeability, current terrestrial stress and hydrodynamic environment affected the coalbed methane enrichment and high production. It was proved by exploration that high production area was in marsh facies, broad structural and low terrestrial stress area, which was one of CBM exploration optimum in midrank coal in China.<br></p>
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DENG Ze, WANG Hongyan, JIANG Zhenxue, et al. Influence of deep coal pore and fracture structure on occurrence of coalbed methane: A case study of Daning-Jixian Block in the eastern margin of Ordos Basin. Coal Science and Technology: 1-18 [2024-06-05]. http://kns.cnki.net/ kcms/detail/11.2402.TD.20240311.1045.005.html
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ZHAO Weibo, LIU Honglin, WANG Huaichang, et al. Discussion on pore characteristics and forming mechanism of coal in the deep area, Ordos Basin: Case study of No.8 coal seam in Well M172 of Yulin area. Natural Gas Geoscience, 2024, 35(2): 202-216.
https://doi.org/10.11764/j.issn.1672-1926.2023.10.012
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To search for the distribution of deep coalbed methane resources， it is urgent to identify the macerals and pore distribution characteristics of deep coal reservoirs. Therefore， taking the No.8 coal seam in Well M172 as an example， the paper conducted coal macerals， nuclear magnetic resonance porosity， and electron microscopy imaging in the Yulin area. The paper analyzed the parameters such as pore fracture types， pore connectivity， porosity， and pore structure distribution of coal rocks in the Yulin area， and explored the main controlling factors that affect coal seam reservoir performance， such as pore structure and macerals， as well as the mechanism of gas pore formation. The research results indicate that： （1）There are three peaks in the nuclear magnetic relaxation time T2 of saturated water coal samples， with peaks located at 0.2 ms， 8 ms， and 300 ms， corresponding to adsorption pores， transition pores， and free pores， respectively， with adsorption pores being the main ones. （2）The total porosity and effective porosity of coal samples increase with the increase of vitrinite content； pores in coal rocks are related to the production of liquid hydrocarbons， and the matrix vitrinite develops a group of pores generated by the cracking of liquid hydrocarbons. （3）There are two types of occurrence states in deep coal seams： free gas and adsorbed gas. The coal seam has a higher gas content， and the gas saturation is generally supersaturated. The main controlling factors for coalbed methane accumulation are more complex， with multiple types of reservoir formation developed， such as fault shielding， hydrodynamic traps， structural lithology， and micro structures. The types of reservoir formation are more abundant than those in the middle and shallow layers. The study and genetic analysis of the pore structure characteristics of deep coal and rock in this article have certain geological significance for clarifying the formation laws of deep coalbed methane reservoirs.
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KANG Yongshang, YAN Xia, HUANGFU Yuhui, et al. Concept and main characteristics of deep oversaturated coalbed methane reservoir. Acta Petrolei Sinica, 2023, 44(11): 1781-1790.
https://doi.org/10.7623/syxb202311003
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Based on the analysis of deep oversaturated coalbed methane (CBM) reservoirs, the following understandings are obtained. (1) As the buried depth of coal seam increases to a certain depth, the positive effect of coal rank and formation pressure on adsorption is less than the negative effect of temperature on adsorption, as result of which the adsorption gas is gradually saturated (adsorption saturation of 100%) and enters in the stage of in-situ free gas occurrence, thus forming deep oversaturated CBM reservoirs. The formation pressure and temperature keep increasing with the buried depth, and this objective law provides natural conditions for the formation of oversaturated CBM reservoirs in deep strata of the basin. (2) The critical depth of oversaturated CBM reservoirs varies in different basins, and the critical depth difference of oversaturated CBM reservoirs is determined by the basin geothermal gradient and pressure gradient. Abnormal high pressure and temperature (such as the high temperature caused by volcanic thermal events) can reduce the critical depth of oversaturated CBM reservoirs. (3) Deep oversaturated CBM reservoirs have the advantages of short gas breakthrough time, full utilization of formation energy and low cumulative water production in the exploitation, which is expected to become an important field of CBM exploration and development in the future, possessing broad exploration prospects in China's large-scale basins with deep coal seam burial conditions. The understandings of deep oversaturated CBM reservoirs come from the analysis of static data and production dynamic data on-site, reflecting the epistemological view that the knowledge originates from practice and in turn serves practice. This has great significance for guiding deep CBM exploration and development.
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LI Yong, TANG Dazhen, XU Hao, et al. Calculation of abroad coalbed methane recoverable resources. Coal Geology & Exploration, 2014, 42(2): 23-27.
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ZHANG Xinmin, HAN Baoshan, LI Jianwu, et al. Prediction methods of recoverable coalbed methane resources. Natural Gas Industry, 2005, 25(1): 8-12.
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LIU Chenglin, ZHU Jie, CHE Changbo, et al. Methodologies and results of the latest assessment of coalbed methane resources in China. Natural Gas Industry, 2009, 29(11): 130-132.
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Funding

China National Petroleum Corporation Science and Technology Project(2023ZZ18)
CNPC Changqing Oilfield Company Project(2022D-JB01)
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