Introduction

Coalbed methane (CBM) refers to natural gas found in coal seams, with methane as the primary constituent (Fu et al. 2017; Zhao et al. 2020). As an unconventional fossil fuel, the formation and accumulation mechanisms of CBM differ markedly from conventional oil and gas resources (Davies et al. 2005). Extensive research efforts have advanced understanding of CBM enrichment processes. However, identifying highly productive “sweet spots” across regional domains remains an outstanding challenge for CBM exploration.

CBM enrichment is controlled by diverse geological factors, including coal rank (Moore 2012), temperature (Flores 1998), pressure (Jia et al. 2021a, b), moisture content (Jia et al. 2021a, b), maceral composition (Rightmire and Eddy 1984), lithology (Palmer 2010), stratigraphy (Wang et al. 2020), tectonics, hydrogeology (Andrew et al. 1994), and mining activity (Bustin and Clarkson 1998); based on previous research, three primary controls can be identified: geological structure (Andrew et al. 1994), sedimentary environment (Palmer 2010), and hydrogeology (White et al. 2005). CBM accumulation models differ based on coal rank. For low-rank coals, four enrichment models have been proposed: (1) broad gentle folds; (2) basin edge biological effects; (3) hydrodynamic trapping at structural highs; and (4) deep pressured zones (Abraham 2006; Cohen 2009). Medium–high-rank coals exhibit five models: (1) brittle-ductile transition zones; (2) high permeability structures; (3) sloping gas content; (4) rift zones; and (5) gentle folds (Jessen 2008; Zhao et al. 2021). However, most models focus on resource assessment rather than localized sweet spot prediction or integration with production data.

China’s CBM industry remains in its infancy, with commercial development only emerging in recent years (Creedy and Tilley 2003). Although China possesses greater CBM resources than the USA, productivity lags far behind, indicating the need for improved geological understanding (Sun et al. 2017a, b; Mohamed and Mehana 2020). China’s basins exhibit strong heterogeneity (Jiang et al. 2021), low reservoir pressure (Nuccio 2000), and lower permeability (Pashin and McIntyre 2003) compared to analogous North American basins, posing barriers to efficient CBM extraction. Unlocking China’s CBM potential requires tailored strategies that account for these unique characteristics (Li et al. 2008). This research focuses on the southern Qinshui Basin, targeting late stage high-rank coals with low porosity and permeability that impede development (Wang et al. 2009; Fan et al. 2022). We integrate structural models and field data to reveal CBM enrichment patterns and propose a new high-yield model for identifying sweet spots with optimal productivity potential. The model defines favorable structural criteria for CBM accumulation in enriched areas, guiding drilling efforts toward higher resource abundance and permeability. Region-specific understanding of geological controls can inform staged development strategies to gradually achieve broad pressure reductions for scaled CBM production (Pan and Connell 2011; Jiang et al. 2022). Overall, this study provides new insights into overcoming barriers to China’s CBM industry by linking geology to strategic planning. The proposed approach may serve as a blueprint for unlocking unconventional resources in challenging settings worldwide.

The structure of this paper is as follows: section "Geological settings" compares the characteristics of various CBM basins worldwide. In section "Methodology and data", a geological model of the research area is built, and a numerical simulation will be carried out. In section "Results and discussions", the CBM enrichment mechanism is revealed.

Geological settings

Coalbed methane (CBM) accumulates in coal seams predominantly by adsorption. However, CBM distribution is heterogeneous, with the interplay of geological factors producing variations in reservoir scale and gas abundance (Formolo et al. 2008). Different sedimentary basins exhibit distinct characteristics that control CBM occurrence. Comparing well-developed basins to those with untapped potential can elucidate the key geological constraints on productivity. This section contrasts the Qinshui Basin in China against the mature San Juan Basin in the USA. By analyzing differences in basin properties and depositional settings, we aim to reveal the specific barriers hindering efficient CBM development in the Qinshui Basin. These basin comparisons inform construction of a detailed geological model for the Qinshui study area. Integrated with field analyses, the model provides new insights into CBM enrichment patterns and sweet spot prediction. Overall, this comparative approach enables a comprehensive understanding of the geological factors governing China’s CBM resources, serving as an important foundation for future extraction strategies.

San Juan basin

The San Juan Basin is defined by a series of major geological structures (Mullen 1989). It covers an area of about 19,425  m2 and is approximately circular in shape, with a North–South length of about 161 km and an East–West width of about 145 km (Young et al. 1991). The San Juan Basin is an asymmetric syncline with a North Central, NW–SE axis. The northern margin strata dip steeply and tend to be flat to the central and southern strata (Kaiser and Ayers 1994; Sun et al. 2023a). The main coal seam is Fruitland Formation, which is a delta plain sedimentary facies in a sea–land interaction sedimentary environment (Pétron et al. 2020). The basin is divided into zones 1A, 1B, 1C, 2, and 3 (Fig. 1).

Fig. 1
figure 1

San Juan Basin block division

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Zone 1A is a high-abundance-rich area of the basin. The CBM-rich area is located in the northeast of the basin, covering an area of about 3100 km2 (Joshi et al. 2022). The gas content of Zone 2 and Zone 3 is lower, less than 4.25 m3/t. In terms of the permeability of coal seam, the permeability of coal seam in zone 1A is also relatively high, most of which are more than 15 × 10–3 μm2, and the highest can reach 60 × 10–3 μm2. The permeability of the coal seam in zone 1B and 1C ranges from 10 × 10–3 to 35 × 10–3 μm2, and the permeability of the coal seam in zone 2 and 3 is low. The production of CBM in zone 1A is also extensive, with high single-well production, and the production of most Wells ranges from 28,000 to 168,000 m3/d. The single-well production of CBM in zone 1B and 1C ranges from 1400 to 14,000 m3/d. Zone 3 is the lowest, with most wells not producing more than 1000m3/d. According to statistics, the total annual production of CBM in Zone 1A accounts for 50% of the annual production of CBM in the USA and more than 80% of the basin (Table 1). In Table 1, C1 means hydrocarbon with only one carbon (CH4), and C5 means hydrocarbon with five carbons (C5H12).

Table 1 Comparison of parameters in the Juan Basin
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Qinshui basin

The Qinshui Basin is a typical high-coal coal bed gas basin in China and the world, which is located in the southeast of the Shanxi plateau, with a long axis along the North–North East, and the elliptical form of the middle, a large craton basin composed of Paleozoic and Triassic (Su et al. 2005; Sun et al. 2017a, b). Figure 2 shows the location of Qinshui Basin and our study area in this work. The left figure shows the location of Qinshui Basin, and the right figure shows the location of the study area, which locates south of Qinshui Basin.

Fig. 2
figure 2

The location of Qinshui Basin and Study Area. The left figure shows the location of Qinshui Basin, and the right figure shows the location of the study area, which locates south of Qinshui Basin

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Coal-bearing formation is mainly the Taiyuan Group and the lower Permian Shanxi Group. The amount of coal bed methane in the Qinshui basin is 3.96 billion m3, which accounts for 10.70% of the total resources of China, and is a critical pilot in the development of CBM exploration in China (Sun et al. 2023b). The production of CBM in the basin accounts for 93% of the national CBM production, and CBM in the south of the basin accounts for more than 70% of the whole basin (Sun et al. 2018).

The thickness distribution of the 3# coal seam in the Shanxi Formation is thin in the middle and thick at both ends, and the thickness in the south is more significant than that in the north. Vitrinite reflectance Ro is concentrated above 2.5%; the highest is 4.5%. The metamorphic degree of coal is low in the north and high in the south, low around and high in the middle, which may be closely related to the activity of Yanshan magmatic rocks in the south of the basin. The metamorphic degree of the Taiyuan Formation coal seam is also very high, and the Ro distribution characteristics of vitrinite reflectance are similar to Shanxi Formation. The Ro of the Taiyuan Formation in the basin is generally above 2.7%, and the highest Ro is 4.5%.

Under tectonic movement in an environment of high temperature and relatively low pressure, the fractures of the coal seam well develop, and the reservoir has good physical properties and medium permeability. The coal seam pores mainly show characteristics of micropores, with a small number of mesopores and macropores.

The effective porosity is between 1.15 and 7.69%, generally < 5%, and the permeability is 0.1–6.7 × 10–3 μm2. Generally not more than 2 × 10–3 μm2 has obvious directionality along the direction of the primary fracture and has the most considerable permeability.

The southern Qinshui Basin is superior to other areas, among which the Pan-zhuang-Fanzhuang-Guxian area is a high-abundance area of high-grade CBM (Table 2). The high-abundance area of Panzhuang-Fanzhuang-Guxian is located at the southern end of the Qinshui syncline. The strata strike is NNE-NEE, which tends to the northwest, accompanied by wide and gentle folds. Faults are not developed in this area, and the strata are continuous, complete, and gentle.

Table 2 Parameter comparison table of each block in Qinshui Basin
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The thickness of the coal seam ranges from 4.25 to 7.25 m, with an average of 5.79 m. The structure of the coal seam is simple, the roof of the coal seam is mainly mudstone, silty mudstone, and a small part of siltstone, and the floor is mainly carbonaceous mudstone, mudstone, and siltstone. The burial depth of coal seam is generally 400–750 m. 15# coal seam is located at the top of Taiyuan formation, the thickness of the coal seam is mostly 1.20–5.70 m, the average is 2.56 m, the continuity of the coal seam is good, the roof is mainly carbonaceous mudstone and mudstone, the floor is mainly mudstone, carbonaceous mudstone, silty mudstone and siltstone, the coal seam burial depth is about 100 m deeper than 3# coal seam.

The thermal evolution degree of the coal seam in rich areas is higher, Ro is more than 3%, and the permeability of the generally coal seam is higher, generally ranging from 0.5 to 18.3 × 10–3 μm2, which is conducive to exploiting coalbed methane. Gas content in the Panzhuang-Fanzhuang-Guxian area is also the largest among these blocks. The gas content of 3# coal is 11.54–35.70 m3/t, an average of 22.15 m3/t, and the gas saturation is 69.65–95.11%. The gas of 15# coal is 10.52–36.87 m3/t, an average of 22.23 m3/t, and the gas saturation is 70.04–86.28%. In terms of resource abundance, the abundance of Panzhuang-Fanzhuang-Gu County is more than 1.5 × 108 m3/km2, which is higher than other blocks. At present, the actual data generated by coalbed methane exploration show that the single-well production of some coalbed methane Wells in the Panzhuang-Fanzhuang-Guxian area exceeds 10,000 m3/d, and the majority of coalbed methane production is 2000–7000 m3/d.

The coal seam in China generally experiences a complex tectonic movement process after deposition, and the coal seam is characterized by strong heterogeneity, low permeability, and strong permeability sensitivity with pressure. Compared with the San Juan Basin, which have succeeded in CBM development in the USA, the main problem of CBM development in China is low permeability.

Methodology and data

Geological model building

This section establishes a geological model of the South Qinshui Basin based on the actual production data (Fig. 3). The red means the higher area, and the blue means the lower area. The southern Qinshui Basin is a vast and gentle slope zone, with relatively developed folds and faults, and relatively high-coal seam gas content in general, with an average of 10–25 m3/t. Fanzhuang, Panzhuang, and Zhengzhuang located in the southern Qinshui Basin have initially realized large-scale development. Through many examples, it is proved that under the condition of similar gas content, the gas production of different parts of the structure is quite different, which shows that the production of coalbed methane (CBM) is relatively more prominent in the higher part of the structure.

Fig. 3
figure 3

3D Geological model. The red means the higher area, and the blue means the lower area

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Field analysis

This study investigates the characteristics and geological controls on high-productivity coalbed methane (CBM) accumulation zones. The first objective is to delineate relatively high-yield well areas within the study area based on two key production indicators: (1) high individual well production rates; and (2) large cumulative production volumes. Wells exhibiting favorable values of these metrics can be classified as occurring in high CBM yield sweet spots. By mapping the distribution of high-yield wells, discrete productive fairways emerge that define zones of elevated CBM content and deliverability. Detailed analysis of the geology and reservoir properties within these CBM sweet spots provides insights into the parameters governing productivity.

Integrating well production statistics with geological data enables the development of a specialized enrichment model tailored to the study area. This model defines the specific structural, stratigraphic, and diagenetic conditions favorable for forming concentrated CBM accumulations. The approach taken here provides a blueprint for leveraging production records to guide exploration efforts toward the most prospective areas in frontier CBM basins.

For instance, the production of the F-12-9 well is lower than 600 m3/d, and the cumulative output is small, less than 80,000 m3, defined as a low-yield well area. Gu7-13 is considered a high-production area with a high single-well production rate of approximately 4500 m3/d and a high cumulative production rate of over two million m3. The principle of determining the high-production well area of undeveloped exploration well follows two indexes: one is the relatively high-production of single-well trial production, and the other is the relatively sizeable cumulative trial production of trial production. As for the ZS-62 well, during the trial production period, the single-well production was low, mostly at 900 m3/d, and the cumulative production was small, less than 100,000 m3, defined as a low-producing well area. As for ZT-27 well, during the trial production period, the single-well production is high; the highest is more than 3000 m3/d, usually more than 2000 m3/d; the cumulative production is high, more than 600,000 m3, defined as a high-yield well area.

Results and discussion

As an unconventional resource, coalbed methane (CBM) accumulates predominantly by adsorption within coal seams. Consequently, CBM enrichment levels closely relate to coal reservoir properties. Two parameters are particularly critical—resource abundance and permeability. Coal rank, maceral composition, and burial history govern gas sorption capacity, defining total CBM resources. Permeability exerts first-order control on producibility, determining how much gas can be extracted. Therefore, favorable CBM sweet spots require both high gas content and adequate deliverability.

Analysis of coal seam thickness maps overlaid with highly productive coalbed methane (CBM) well locations reveals that high-yield wells occur across a range of seam thicknesses (Fig. 4). No strong correlation is observed between coal thickness and CBM productivity. This indicates seam thickness exerts minimal control on sweet spot distribution in the study area. The poor thickness-productivity relationship likely arises because coal seams maintain sufficient thickness overall to provide adequate gas resources. With abundant gas content, other geological factors become more influential in governing deliverability and enrichment. This highlights the need for a multifaceted approach to sweet spot identification that integrates various controls on accumulation and flow. While coal thickness contributes to total CBM volumes, other attributes like permeability, gas saturation, and fracture intensity appear more significant for differentiating highly productive sweet spots. The findings demonstrate the importance of analyzing multiple geological parameters rather than relying solely on net coal thickness for CBM prospectivity assessments.

Fig. 4
figure 4

Relationship between high-yield area and thickness of coal seam. The red stars represent the high-production well, and the red circle represents the high-production area. A thick seam does not necessarily mean high production

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The elevation depth of the 3# coal seam in the research area is superimposed with the high-yield well area (the area defined by the red circle) (Fig. 4). It can be seen that the high-yield well area is distributed in the high structural part and the monocline area. The buried depth is superimposed with the high-yield well area (the area defined by the red circle) (Fig. 5). We can see that the high-yield well area is primarily distributed in the relatively shallow buried area. Therefore, the high part of the local structure and the shallow buried area of a monoclinic zone is closely related to the high-yield well area.

Fig. 5
figure 5

Map of the relationship between high-yield well area and the top surface of 3# coal seam. The red stars represent the high-production well, and the red circle represent the high-production area. A thick seam does not necessarily mean high production

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Gas content and coal seam thickness are essential parameters for calculating of CBM resource abundance. The thickness of the 3# coal seam in the southern research area is 4–7 m, an average of 6 m. Overall, it shows a trend of thick in the east and thin in the west, but the thickness of the coal seam does not change much, so it has no apparent relationship with coalbed methane production. The gas content is mainly in the range of 4–25 m3/t, which has a specific range of variation. The high gas content coal seam is conducive to forming a high yield.

For coalbed methane development, the coal seam’s permeability is a crucial factor, and the coal seam in situ stress significantly influences the reservoir’s permeability. When the in situ stress is high, it is not easy-to-open the seam cracks and cutting, and it is difficult to form a pathway, resulting in development difficulty. The coal seam in the southern research area has the characteristics of typical high-rank coal. The pores of the coal reservoir are mainly micropores, with a few medium and large pores, and the effective porosity is between 1.15 and 7.69%, generally < 5%. Permeability ranges from 0.1 to 6.7 × 10–3 μm2, generally no more than 2 × 10–3 μm2, and gradually decreases from shallow to deep . The local shallow buried area is mainly because the ground stress is relatively small, which is often the area with high permeability and easy-to-form high yield. The high part of the local structure is the area of regional tectonic stress concentration, with tensile stress in the core and microscopic fracture development, which is often the area of regional high permeability development and easy-to-form high yield.

Figure 6 shows the high-yield pattern of relative structural high position in rich areas. The coal bed gas is relatively enriched in the syncline of the slope belt of the coal-bearing basin due to the moderate depth of the coal seam. The relative structural height of the secondary fold in the inner syncline is a relatively high permeability zone due to the development of microfractures released by uplift stress and weak compaction of the overlying strata. Tectonic uplift reduces reservoir pressure, which is equivalent to the self-drainage process in the reservoir, and the high adsorption saturation zone of coalbed methane is easy to form in the area with suitable preservation conditions.

Fig. 6
figure 6

High-yield pattern of relative structural high position in the rich area. The blue plots represent the water, and the yellow plots represent gas. The red lines represent micro fractures. The relative structural height of the secondary fold in the inner syncline is a relatively high permeability zone due to the development of microfractures released by uplift stress and weak compaction of the overlying strata

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Figure 7 shows the relationship between gas production and ground stress horizontal principal stress difference. According to the production data of CBM well testing and fracturing in Qinshui Basin, the permeability, and maximum horizontal principal stress. and minimum horizontal principal stress of CBM well testing can be obtained. It is found that the principal stress difference of ground stress level is significantly correlated with permeability and single-well daily gas production in Qinshui Basin. The principal stress difference of ground stress level is positively correlated with permeability. The high-yield wells of CBM are usually distributed in the area with significant differences in ground stress level principal stress, that is, the high structure part.

Fig. 7
figure 7

The relationship between gas production and ground stress horizontal principal stress difference. The blue plots show the real production data of CBM wells. The black dotted line shows the gas production trends with the increasing ground stress horizontal principal stress difference. With the increasing stress difference, gas production also increases

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Conclusions

In this work, the coalbed methane (CBM) enrichment mechanism in the southern Qinshui Basin is revealed from the view of in situ stress. The following conclusions are drawn:

  1. 1.

    When compared to the highly productive San Juan Basin in the USA, low permeability poses the primary impediment to effective CBM development in China. Unlocking substantial CBM potential will rely on tailored strategies to locate and target sweet spots of relatively less impeded permeability.

  2. 2.

    In situ stress conditions exert a primary control on the development of microfracture systems, which in turn govern reservoir permeability. By constraining stress magnitudes and orientations across a basin through geo-mechanical modeling, the associated fracture development can be predicted to map permeability sweet spots.

  3. 3.

    Zones characterized by shallow burial depths and low tectonic stress regimes emerge as favorable exploration targets, owing to enhanced permeability development.