Sage Journals: Discover world-class research

Abstract

The Erlian Basin may be one of the most promising areas for low-rank coalbed methane (CBM) in China. The Cretaceous coal-bearing strata in the Bayanhua sag contain abundant low-rank CBM resources with suitable depths and large coal thicknesses (1.00–78.85 m, avg.22.53 m). However, the research on CBM geology and exploration potential is still lacking, which severely hinders its exploration and development. This paper presents an integrated study of CBM geology in terms of gas reservoir properties, gas-bearing characteristics and controlling factors. The results of the analysis show that lignite and subbituminous coals are the main coal types present in the study area, with medium porosity (7.3–27.8%, avg.20.77%) and low permeability (0.05–21.8 mD, avg.5.54 mD) being dominant. The pores are dominantly transition pores with inkpot shapes, which is beneficial to the adsorption of CBM. The gas content of the coal seams is 1.66–4.45 m³/t and most coal reservoirs are oversaturated. The CBM is primarily of secondary microbial origin, mostly carbon dioxide reduction. The accumulation of CBM is mainly influenced by the structure type, roof lithology and hydrogeology in the study area. According to the integrated analysis of the vertical changes in the physical properties and gas-bearing characteristics, the dominant horizon tends to be the No. 6-7 coal seam, followed by the No. 6-4 coal seam. Based upon the CBM geology and the factors controlling enrichment, the prospecting potential in the Bayanhua sag was appraised, and two favorable areas are proposed for CBM exploitation.

Keywords

Erlian basin low rank CBM accumulation characteristics exploration potential Bayanhua sag

Introduction

Industrial exploitation of high to medium-rank coalbed methane (CBM) has been realized in China. However, the annual production of CBM is far below the set targets (Chen BY et al., 2019; Liu et al., 2014; Tao S et al., 2014 Zhao et al., 2017). Recently, low-rank CBM has been successfully developed in the Powder River Basin, Uinta Basin, Alberta Basin and Surat Basin (Ayers, 2002; Hamilton et al., 2014; Tang et al., 2018), indicating that new blocks with high resource potential may exist to be discovered and researched in China (Lau et al., 2017; Sun et al., 2008; Yun et al., 2012). The Erlian Basin is considered a new block for CBM exploitation in China. The CBM resources of the Erlian Basin account for 8.5% of the nation (approximately 1.25 trillion cubic meters) according to the fourth round of oil and gas resource evaluation (Liu et al., 2005; Sun et al., 2017). Nevertheless, due to a lack of systematic study of gas geological characteristics and controls, the degree of CBM research and exploration is still in its infancy.

It is necessary to evaluate the CBM exploitation potential through synthetic research on CBM geology and its enrichment controlling factors. The factors affecting CBM accumulation include the sedimentary environment, structural characteristics, coal seam distribution, coal rank, reservoir properties, gas bearing properties, roof and floor lithology, hydrodynamics, etc. (Kaiser et al., 1994; Li H et al., 2018 Li ZT et al., 2018 Wang et al., 2020; Yao et al., 2014). Among them, reservoir physical properties have proven to be critical to CBM adsorption, diffusion, seepage and production (Levine, 1992; Xin et al., 2020; Xu et al., 2014). Moreover, the gas content tends to directly affect the economy of CBM exploitation. Reservoirs of low-rank coal have a lower gas content than medium to high-rank coal. However, the characteristics of a large thickness, moderate burial depth, and high permeability mostly compensate for these shortcomings (Esen et al., 2020; Scott, 2002). Additionally, the dynamic process of hydrocarbon generation history determines the CBM generation types, leading to a diversity of CBM origins (Chen et al., 2016; Wang et al., 2020). Hence, understanding CBM geology requires a comprehensive analysis of reservoir properties, gas-bearings characteristics and their controls.

Previous research in the Erlian Basin has primarily focused on the structural and sedimentary geological characteristics of coal-bearing strata (Bonnetti et al., 2014; Ding et al., 2015) and on the CBM genetic types, biogas generation influencing factors, nanopore structure characteristics and feasibility studies of biogas recovery in the Jiergalangtu sag (Chen H et al., 2019; Sun B et al., 2018; Sun F et al., 2017; Sun QP et al., 2018; Tao JJ et al., 2019; Zhao et al., 2021). The Bayanhua sag is the key sag with low-rank CBM exploration potential in the Erlian Basin. However, only a few studies related to CBM, mainly focusing on the key geologic factors affecting coal reservoirs, have been performed, and the classification of coal seams may be relatively simple (Yao et al., 2020). To date, no commercial CBM production wells have been developed in the Bayanhua sag, although several companies are conducting exploration in this area. Recently, six CBM production wells have been completed, which contain a cluster well of three, and a quantity of gas-bearing layers have been discovered in this area. Hydraulic fracturing work has just been carried out, and the wells are ready for drainage and gas production. Even so, the geological characteristics and exploration potential of CBM still need to be further systematically studied.

In this paper, CBM geology, coal reservoir properties and gas-bearing characteristics are analyzed in detail based on synthetic research of collected and experimental data. Geological controls on CBM accumulation in the Bayanhua sag are comprehensively studied in the Bayanhua sag. In view of the CBM geology and controlling factors, the CBM exploitation potential is evaluated to provide the basis for further industrial development of CBM in the Bayanhua sag.

Geological setting

Tectonic setting

The Erlian Basin is a Mesozoic continental rifted basin situated in Inner Mongolia, northeastern China, and covers a surface area of approximately 117,685 km² (Charles et al., 2013; Lin et al., 2001). Additionally, the Erlian Basin is one of the main areas containing lignite and subbituminous coal in China, with abundant coal resources (<2,000 m) that mostly formed in the Cretaceous. The coal reserves are 142.5 Gt, and the predicted coal resources are approximately 85.7 Gt (Li et al., 2016). The Erlian Basin consists of five depressions and one uplift and is further subdivided into 21 ranges and 56 sags, with graben-shaped and residual lacustrine subbasins (Ding et al., 2015; Dou and Chang, 2003).

The Bayanhua sag is a half-graben-shaped syncline structure with a dip of 10–15° and an orientation of NE-NNE, and it is located at the northeastern end of the Wunite Depression. Small-scale folds also formed in the area, all trending in the NE direction. In addition, the faults in the area mostly trend in the NE-SW direction and developed during the large-scale rifting period (Figure 1(b)).

Figure 1.

(a) location map of the study area in the erlian basin modified from Dou and Chang (2003); (b) Map of the Bayanhua sag structural outline and structural contour map of the base of the No. 6-7 coal seam modified from Yao et al. (2020); (c) Stratigraphic column of Cretaceous coal-bearing strata in the Bayanhua sag.

Coal-bearing strata in the Bayanhua sag

The majority of Erlian subbasins were subjected to erosion in the Triassic and entered the rifting period from the early Middle Jurassic to the Late Cretaceous, during which they experienced a sedimentary process characterized by rapid filling with terrigenous clasts and lacustrine expansion. This process deposited the Lower Cretaceous Aershan Formation (K₁a), the Tengger Formation (K₁t), the Neogene (N₂) and the Quaternary strata (Q). The Tengger Formation (K₁t) is the predominant coal measure in the Bayanhua sag.

The Tengger Formation is composed of six coal groups in the Bayanhua sag, which are 4Sun F et al., 2017; Sun QP et al., 2018; divided into 23 coal seams. There are five principal coal seams, including the No. 6-7, No. 6-4, No. 6-1, No. 5-2, and No. 5-1 coal seams, in ascending order (Figure 1(c)). The main coal seams have a cumulative thickness of 1.00-78.85 m (avg.22.53 m) with an occurrence area of 565 km² (Figure 2), which is representative of the large, thick coal seams in the Erlian Basin. The coals have an average burial depth of 300–1,200 m, and the burial depth ranges from 600 to 1,200 m in the northeastern region, which is beneficial to the formation and preservation of CBM and is also a suitable exploration depth range for CBM in this region (Ruppert et al., 2010).

Figure 2.

Contour map of the total thickness of coal seams.

At the beginning of the Early Cretaceous, due to the differential movement of the basement in the Erlian Basin, the Bayanhua sag began to extend and rift along the NE direction. In the middle of the Early Cretaceous, it continued to subside and experience deposition, forming a series of braided river deltas, fan deltas and shore-shallow lacustrine deposits, i.e., the Tengger Formation. Peat swamps widely developed in delta plains and lacustrine bogs, forming the main coal seams, namely, the No. 5 and No. 6 coal groups. During the deposition of the upper member of the Tengger Formation, sediments overlapped the margin of the sag, and the lacustrine regime expanded, which was disadvantageous to peat swamp growth. During this period, the No. 2, No. 3 and No. 4 coal groups were deposited discontinuously. Additionally, gray siltstone, pelitic siltstone, and large thick mudstone were deposited, which was conducive to CBM sealing. After the Late Cretaceous, the crust began to uplift, the lake silted up, the climate gradually became drier, the fluvial and alluvial fan facies developed widely, and coal accumulation ceased (Figure 3).

Figure 3.

Cretaceous burial history diagram of CBM in well B-C1 in the Bayanhua sag.

Coal seams are mostly present in the middle of the Tengger Formation in the Bayanhua sag. The thickness of the No. 6-7 coal seam is 1.50–12.46 m (avg. 5.09 m) and shows three coal accumulation centers in the sag (Figure 4(a)). The thickness of the No. 6-4 coal seam is 1.52–44.37 m (avg. 16.98 m), which is greater than that of other coal seams (Figure 4(b)). The No. 5-2 coal seam (1.51–18.07 m, avg. 5.74 m) and No. 5-1 coal seam (1.55–13.50 m, avg. 3.62 m) are thicker than the No. 6-1 coal seam (1.51–21.78 m, avg. 4.25 m), but they have similar distributions, i.e., a saddle pattern (Figure 4(c)–(e)).

Figure 4.

Thickness of each main coal seam in the Bayanhua sag: The No. 6-7 coal seam (a), No. 6-4 coal seam (b), No. 6-1 coal seam (c), No. 5-2 coal seam (d), and No. 5-1 coal seam (e).

Samples and experiments

Data and sample sources

In this paper, CBM geological setting data were collected from 200 coal exploration holes and CBM exploration wells. These coal exploration holes and CBM wells were carried out by the Coalfield Geology Bureau of Inner Mongolia. The CBM geological characteristics in the Bayanhua sag were analyzed with these data.

The coal samples used in these experiments, such as maceral composition, proximate analysis, vitrinite reflectance, mercury intrusion, and low-temperature nitrogen were taken from 6 large fresh samples collected from open-pit mines and 20 core samples freshly recovered from CBM exploration wells. Additionally, the gas samples used in experiments of gas content, gas composition, carbon and hydrogen isotopic compositions came from in situ desorption gas. All samples were numbered, classified, carefully sealed and packaged and delivered to the laboratory immediately.

Experiments

Vitrinite reflectance (% R_o) and maceral measurements were carried out on the same section of the coal samples with a Leitz MPV-3 photometer microscope, according to China National Standards GB/T 6948-2008 and GB/T 8899-2013, respectively. Proximate analysis and elemental analysis were performed based on Chinese standards GB/T 212-2008 and GB/T 31391-2015.

Low-field nuclear magnetic resonance (NMR) tests were implemented by a RecCore-5000 instrument to obtain pore structure, porosity and other reservoir data (Table 1) in light of Chinese standard SY/T 6490-2014. A low-temperature nitrogen adsorption trial was then conducted to acquire pore morphology data following Chinese standard GB/T21650.2-2008 with an ASAP 2460 instrument. The microtopography of pores was observed using an FESEM JSM-7500F scanning electron microscope based on the Chinese standard GB/T 12334-2001. The porosity and permeability of coal reservoirs were measured at a confining pressure of 400 psi (average formation pressure) with an HKY-300 automatic porosity and permeability tester based on the Chinese standard GB/T 29172-2012.

Table 1.

Petrological permeability, porosity and pore volume proportion of coal seams.

Coal seam	Burial depth (m)	Porosity (%)	Permeability (×10⁻³ μm²)	Proportion of pore volume in each aperture segment (%)
Coal seam	Burial depth (m)	Porosity (%)	Permeability (×10⁻³ μm²)	<10 nm	10–100 nm	100–1,000 nm	>1,000 nm
5-1	896.43	21.7	1.82	0.46	57.58	34.04	7.91
5-2	921.27	17.4	0.48	6.37	57.19	28.01	8.43
5-3	928.58	22.00	2.64	–	–	–	–
5-4	952.00	17.90	1.34	–	–	–	–
5-5	956.00	21.10	0.76	–	–	–	–
6-1	1,002.00	16.7	7.33	1.20	43.63	43.86	11.30
6-2	1,006.70	25.10	0.60	–	–	–	–
6-3	1,018.10	23.20	15.60	–	–	–	–
6-4	1,034	24.3	21.8	2.38	61.56	24.30	11.76
6-5	1,047.00	7.30	0.05	–	–	–	–
6-6	1,065.00	21.30	9.93	–	–	–	–
6-7	1,101	27.8	8.73	3.24	60.08	29.73	6.95
6-8	1,107.00	24.30	0.98	–	–	–	–

Gas content data were measured through desorption experiments of field cores based on the Chinese standard NB/T 10018-2015. After the gas content was measured, some gas samples were gathered to detect gas components and carbon and hydrogen isotopes to analyze the gas origin. A 7820A gas chromatograph and MAT-253 isotope mass spectrometers were used to analyze gas conditions based on the Chinese standards GB/T 13610-2014 and SY/T 5238–2008, respectively. The adsorption isotherm experiment was conducted by the Chinese standard GB/T 19560-2008 using the adsorption isotherm YRD-2 apparatus.

Results and discussion

Physical properties of CBM reservoirs

Coal maceral composition and quality

The macrolithotypes of coals in the Bayanhua sag are mostly xylitic coal and minor amounts of detritic coal with black and asphaltic lusters and light brown streaks. The experimental results indicate that the maceral composition is dominated by organic matter, ranging from 58.4% to 99.6% (avg. 82.32%) (Table 2). The huminite content accounts for the highest proportion (91.14%–99.86%, avg.98.56%), followed by inertinite (0.14–8.10%, avg. 1.05%) and liptinite (0–2.5%, avg. 0.39%). The coal seams feature low sulfur contents (0.32–1.84%, avg. 0.76%), which indicates a nonmarine sedimentary environment (Tang et al., 2015). Vertically, there is no obvious change in the maceral composition of the main coal seams. However, comparing the No. 5-1 coal and No.5-2 coal with the No. 6-1 coal, No. 6-4 coal and No. 6-7 coal, the huminite content and sulfur content of the former are slightly lower than those of the latter, and this difference is mainly related to the sedimentary environment and coal accumulation (Tang et al., 2015). Combined with the maceral composition, it could be concluded that the coal-forming plants are mainly woody, and the coal seams formed in moist and deeply covered swamps (Diessel, 1982).

Table 2.

Results of maceral composition test and proximate analysis.

Well number	Coal seam	Burial depth (m)	Total organic content (%)	Macrolithotype	Maceral composition (%)			Proximate analysis (%)			St,d (%)	R_o, max (%)
Well number	Coal seam	Burial depth (m)	Total organic content (%)	Macrolithotype	Huminite	Inertinite	Liptinite	Mad	Aad	Vad	St,d (%)	R_o, max (%)
B2-7	5-1	498.55	82.60	xylitic	97.34	0.73	1.94	7.96	23.63	33.63	0.34	0.311
	5-2	506.40	81.80	xylitic	97.56	1.83	0.61	11.56	10.07	20.07	0.36	0.415
	6-1	561.70	78.80	xylitic	98.98	0.63	0.38	8.34	8.06	18.06	0.82	0.410
	6-4	582.50	70.10	detritic	99.43	0.57	0.00	6.27	16.34	26.34	0.53	0.427
	6-7	632.05	69.00	detritic	99.86	0.14	0.00	5.64	21.89	31.89	1.05	0.425
B6-13	5-1	577.65	83.50	xylitic	99.76	0.24	0.00	2.85	3.33	22.33	0.45	0.371
	5-2	588.15	84.40	xylitic	98.82	1.18	0.00	3.31	18.88	28.88	0.91	0.411
	6-1	637.80	68.90	xylitic	99.13	0.87	0.00	5.95	19.49	29.49	0.55	0.424
	6-4	679.85	83.10	xylitic	99.04	0.72	0.24	3.06	13.89	23.89	0.54	0.421
	6-7	721.60	78.00	detritic	99.74	0.26	0.00	3.63	17.08	27.08	0.76	0.429
B8-5	5-1	544.25	78.30	xylitic	99.11	0.64	0.26	5.32	10.03	20.03	0.42	0.424
	5-2	547.50	79.50	xylitic	98.99	0.88	0.13	5.15	6.9	16.9	0.35	0.432
	6-1	632.10	84.40	detritic	99.29	0.71	0.00	2.82	22.6	32.6	0.46	0.434
	6-4	652.30	82.40	xylitic	99.76	0.24	0.00	7.72	22.55	32.55	0.82	0.431
	6-7	725.50	81.30	xylitic	99.51	0.25	0.25	3.32	17.55	27.55	0.96	0.425
B-C1	5-1	906.85	99.60	detritic	98.11	1.89	0.00	13.24	6.66	34.17	0.32	0.451
	5-2	922.71	84.90	xylitic	98.59	1.41	0.00	7.86	3.47	38.4	0.61	0.462
	6-1	1,001.78	89.25	xylitic	91.14	8.10	0.76	12.83	14.41	25.95	0.9	0.513
	6-4	1,038.27	77.88	xylitic	99.07	0.23	0.70	7.42	13.4	31.08	1.1	0.462
	6-7	1,107.81	99.47	xylitic	97.23	2.37	0.40	7.92	5.83	33.29	0.51	0.513

Mad, moisture (air-dried basis); Aad, ash (air-dried basis); Vad, volatile (air-dried basis); St,d, total sulfur(dry, ash free).

The proximate analysis tests show that the moisture, ash content and volatile matter content are 2.82–13.24% (avg. 7.00%), 1.78–23.63% (avg. 12.55%), and 16.9–38.66% (avg. 28.99%), respectively (Table 2). The coal quality of the main coal seams has no evident vertical changes. However, comparing the No. 5-1 coal and No.5-2 coal with the No. 6-1 coal, No. 6-4 coal and No. 6-7 coal, the ash and volatile contents of the former are lower than those of the latter, while the moisture content is higher than that of the latter (Table 2). Based on the Chinese standard GB/T15224.1-2004, the coals in the study area exhibit low-medium ash and moisture levels and medium-high volatile contents, which can be conducive to CBM accumulation (Fu et al., 2016).

Coal rank usually has a positive correlation with gas content. Coals from the Bayanhua sag are mainly lignite and subbituminous according to ASTM D388-2015. The maximum reflectance of vitrinite (R_{o, max}) is 0.311–0.592% (avg. 0.449%). The reflectance is largely proportional to the burial depth, indicating that coals are dominated by plutonic metamorphism (Figure 5(a)). Based on the contour map of vitrinite reflectance (R_o), R_o increases from southwest to northeast, with the highest R_o in the northeastern area (Figure 6).

Figure 5.

Scatter plots showing the correlations between depth and R_{o, max} (a), permeability (b), gas content (c) and CBM δ¹³C(CH₄) (d) modified from Yao et al. (2020).

Figure 6.

Vitrinite reflectance contours of the tengger formation No. 6-7 coal seam in the Bayanhua sag.

Reservoir porosity and permeability

The seepage of the CBM reservoir is generally evaluated by the permeability parameter (Li et al., 2014). The laboratory outcomes demonstrate that the permeability and porosity of coal reservoirs are 0.05–21.8 mD (avg.5.54 mD) and 7.3–27.8% (avg.20.77%), respectively (Table 1). As a result, the reservoir can be classified as low permeability and medium porosity, and it is higher than high and middle-rank coal (Fu et al., 2006). The relationship between permeability and burial depth is notably poor (Figure 5(b)). Furthermore, the porosity and permeability changes in the main coal seams are vertically inconsistent. The sequence of coal seams in terms of porosity from high to low are No. 6-7 coal, No. 6-4 coal, No. 5-1 coal, No. 5-2 coal, and No. 6-1 coal. The sequences of coal seams in terms of permeability from high to low are No. 6-4 coal, No. 6-7 coal, No. 6-1 coal, No. 5-1 coal, and No. 5-2 coal. Overall, the porosity and permeability of the No. 6 coal group are better than those of the No.5 coal group, which may be caused by the formation of more microfissures during the process of pressolution.

Pore structure

Pores of coal reservoirs can be systematically classified as micropores (<10 nm), transition pores (10–100 nm), mesopores (100–1,000 nm) and macropores (>1,000 nm), which mainly determine the adsorption, diffusion and seepage of natural gas in coal reservoirs (Liu et al., 2009; Xu et al., 2012).

Low-field NMR is a nondestructive inspection method for coal reservoirs. The pore structure with a full aperture can be effectively studied based on the characteristics of the NMR T2 spectrum (Yao et al., 2010). The results indicate that transition pores dominate the porosity, followed by mesopores, micropores and macropores, which account for only a small proportion. Changes in the pore volume ratio of the main coal seams in the vertical direction are not obvious. However, the proportions of micropores and transition pores in the No. 6-4 coal, No. 6-7 coal and No. 5-2 coal are slightly higher than those in the No. 6-1 coal and No. 5-1 coal (Figure 7). The data show a poor-medium degree of pore connectivity (Liu et al., 2009). In addition, plant tissue pores, residual plant tissue pores, and intergranular pores mainly present in the huminite and intergranular pores present in the inertinite contribute to the transition pores and mesopores (Figure 8).

Figure 7.

Proportion of pore volume of the main coal seams in the Bayanhua sag.

Figure 8.

The main types of pores developed in coal reservoirs of the Bayanhua sag (SEM). (a): Pores in the textinite, 1–10 µm; (b): Por es in the textinite, 2–20 µm; (c): Pores in the fusinite, 0.5–3 µm; (d): Pores in the fusinite, 1–4 µm.

The morphology of micropores and transition pores can be well detected by the N₂ adsorption method (Liu et al., 2009). The structure of transition pores and micropores is dominated by inkpot, open cylindrical or flat shapes, yielding low-medium connectivity according to N₂ adsorption (Figure 9). The N₂ adsorption volume of the No. 6 coal group is larger than that of the No. 5 coal group as a whole, indicating that the No. 6 coal group has a strong adsorption capacity. This structure has both negative and positive influences on CBM exploitation. Pores with inkpot shapes can be conducive to CBM adsorption, although they may increase the difficulty of CBM desorption and diffusion. Pores with open cylindrical or flat shapes can be beneficial to CBM adsorption, desorption and diffusion.

Figure 9.

N₂ gas adsorption/desorption curves of coal seams from the Bayanhua sag.

Microfractures

Fractures in coal reservoirs have an important impact on CBM adsorption, diffusion and migration (Yuan et al., 2022). In this study, the development of microfractures in the coal reservoirs was observed by photon microscopy and scanning electron microscopy (SEM). The results indicate that microfractures are mainly developed in huminite, such as corpohuminite, gelinite and attrinite, and are mostly distributed in a parallel and interleaved manner. Most microfractures are not filled by secondary minerals and have widths of 1–30 μm (Figure 10). Huminite is the primary form of organic matter of in the coals in the study area, and the macrolithotype of coal is dominated by xylitic coal. Xylitic coal tends to develop abundant natural fractures, which tend to improve the permeability of CBM reservoirs (Lyu et al., 2020; Yuan et al., 2022). Therefore, hydraulic fracturing technology should be applied to connect different sizes of pore-fracture systems to improve CBM productivity.

Figure 10.

Microfractures developed in the coal reservoirs of the Bayanhua sag (photon microscopy and SEM). (a): Microfractures in corpohuminite; (b): Microfractures in gelinite; (c): Microfractures in gelinite; (d): Microfractures in attrinite.

Through comprehensive analysis of the vertical changes in the physical properties of the main coal seams, it is found that the reservoir porosity and permeability and pore structure of the No. 6-7 coal, No. 6-4 coal and No. 6-1 coal are better than those of the No. 5-1 coal and No. 5-2 coal. The dominant horizon tends to be the No. 6-7 coal and No. 6-4 coal seams.

Coal seam gas-bearing properties

Origin of coalbed methane

Many researchers have proposed a number of identification indicators for the origin of biogas, among which the major characteristics of biogas involve two aspects: (1) methane is the main component of biogas, and it has a quite high drying coefficient; (2) the carbon isotopic value of methane is comparatively light (Ju et al., 2014; Tao MX et al., 2014). The CBM composition in the Bayanhua sag varies little, and methane is the dominant component (Table 3), ranging from 70.87% to 97.18% (avg. 81.54%), followed by a small amount of ethane, ranging from 0.23% to 0.42% (avg. 0.34%). Additionally, the drying coefficient is much higher than 198. These features suggest that the CBM in the study area is a typical dry gas. The nonhydrocarbon gases are mainly N₂, CO₂ and CO, accounting for 1.76–27.84%, 0.32–1.05% and 0–0.15%, respectively. Additionally, the coal seam burial depth is relatively shallow, and N₂ primarily comes from the atmosphere and enters the coal seam through groundwater. Consequently, the high content of methane, the low content of heavy hydrocarbons and CO₂ in the CBM, and the low degree of coalification (0.371%-0.592% R_o) indicate that the CBM in the Bayanhua sag is mainly of secondary biological origin.

Table 3.

Gas content test and methane isothermal adsorption results.

Coal seam	Burial depth (m)	Gas content (m³/t) (ad)	Gas composition(%)					V_L (m³/t)	P_L (MPa)	Reservoir (MPa)	Gas saturation (%)
Coal seam	Burial depth (m)	Gas content (m³/t) (ad)	CH₄	C₂₊	N₂	CO₂	CO	V_L (m³/t)	P_L (MPa)	Reservoir (MPa)	Gas saturation (%)
5-1	902.27	2.37	97.18	0.23	1.76	0.79	0.05	4.68	8.31	10.11	92.22
5-2	921.27	3.43	81.78	0.36	16.75	1.05	0.06	7.88	6.28	10.32	70.00
5-3	928.58	3.34	76.64	0.35	22.04	0.82	0.15	4.24	7.24	10.4	133.60
5-4	952.00	3.66	75.55	0.3	23.81	0.32	0.03	4.98	7.02	10.66	122.00
5-5	955.50	2.28	93.59	0.42	5.02	0.92	0.04	2.78	4.88	10.7	119.37
5-5	959.84	3.47	70.87	0.33	27.84	0.88	0.08	4.71	6.9	10.75	120.91
6-1	1,001.00	3.31	80.47	0.39	18.08	1.03	0.03	5.28	7.09	11.21	102.48
6-2	1,008.00	3.53	83.02	0.4	15.57	0.96	0.04	7.32	6.76	11.29	77.07
6-3	1,013.00	3.02	77.89	0.35	20.91	0.84	0.01	6.9	13.87	11.35	97.42
	1,018.95	3.72	78.61	0.36	20.23	0.8	0	8.11	11.89	11.41	93.70
	1,023.00	4.25	77.85	0.35	21.08	0.7	0.02	6.14	8.49	11.46	120.40
	1,027.68	3.97	78.48	0.36	20.26	0.89	0.02	6.47	7.33	11.51	100.51
6-4	1,035.00	3.08	80.37	0.37	18.48	0.88	0.02	3.85	6.02	11.59	121.74
6-5	1,049.00	3.16	71.5	0.36	27.2	0.93	0.01	6.38	6.49	11.75	76.89
6-6	1,071.00	3.14	81.32	0.38	17.51	0.77	0.02	5.22	7.29	12	96.62
6-7	1,095.00	2.25	88.41	0.27	9.95	0.57	0.04	5.28	8.66	12.26	72.82
6-7	1,101.80	3.47	91.39	0.28	7.45	0.84	0.04	6.79	7.74	12.34	83.21
6-8	1,108.00	3.99	82.94	0.32	16.33	0.39	0.01	2.78	8.78	12.41	244.79

The carbon isotopic value of methane in the Bayanhua sag ranges from −62.3‰ to −54.1‰ according to the CBM isotopic test results. The test data are plotted on the Whiticar template, and the data indicate that the CBM originated mainly from microbes and certain mixed gases (Whiticar, 1999), and carbon dioxide reduction was the major process of methane generation (Figure 11). As the burial depth increases, a small amount of thermogenic gas was generated and mixed with the biogenic gas and was preserved during coal metamorphism. Further research has revealed that the δ¹³C(CH₄) value of the CBM is positively correlated with burial depth (Figure 5(d)). The linear fitting analysis reveals that an important conversion is present at a burial depth of approximately 1,200 m, roughly corresponding to a δ¹³C(CH₄) value of −55‰ (Figure 5(d)). A small amount of mixed gas appears at depths deeper than 1,200 m, which is consistent with the origin suggested by the Whiticar template.

Figure 11.

Genetic characteristics of CBM from the B-C1 well using δD(CH₄) versus δ¹³C(CH₄) modified from Whiticar (1999).

Gas-bearing characteristics

The gas content of the coal seams is 1.66–4.45 m³/t (avg. 3.34 m³/t) (ad), and shows a poor relationship with the burial depth (Figure 5(c)). This means that gas content is likely to be affected by other factors, such as hydrodynamics, roof lithology, and coal quality.

The gas content of the No. 6-7 coal seam is 0–3.58 m³/t (avg. 2.12 m³/t), with the maximum in the middle of the Bayanhua sag (Figure 12(a)). Moreover, the gas contents of the No. 6-4, No. 6-1, No. 5-2, and No. 5-1 coal seams are 0∼3.29 m³/t (avg. 1.59 m³/t), 0–3.27 m³/t (avg. 1.54 m³/t), 0–3.23 m³/t (avg. 1.35 m³/t), and 0–3.09 m³/t (avg. 1.13 m³/t), respectively (Figure 12(b)–(e)). The distribution of the gas content is mainly similar and generally increases near the syncline axis, especially in the northeastern and central areas, which is primarily caused by hydrodynamic, structural and preservation conditions.

Figure 12.

Gas content distributions in the main coal seams in the Bayanhua sag: The gas content of the No. 6-7 coal seam (a), No. 6-4 coal seam (b), No. 6-1 coal seam (c), No. 5-2 coal seam (d), and No. 5-1 coal seam (e).

Vertically, coal No. 6-7 and coal No. 6-4 have the highest gas contents in most regions of the Bayanhua sag, followed by coal No. 6-1, No. 5-2, and No. 5-1, which is mainly due to the factors of reservoir properties and preservation conditions. Coal seams No. 5-1 and No. 5-2 formed when the shore-shallow lacustrine regime transitioned to fan delta and braided river delta systems, and the supply of continental debris was sufficient. As a result, relatively poor-quality coal seams formed in the low-steady peat swamps, which is one of the prime reasons leading to the differences in gas content. The preservation conditions of the coal seams are detailed in CBM accumulation and its controlling factors.

The gas content of low-rank coals cannot well reflect the degree of CBM enrichment. Gas saturation, as a major factor affecting CBM production (Moore, 2012), could reflect the CBM distribution vertically in the same or different areas. Based on statistics, when per-well production exceeds 1,000 m³/d (Li et al., 2010), adsorption saturation of the coal seams is mostly more than 60%; as a result, high gas saturation is an important factor for the high yield of CBM wells. The analysis data show that the gas saturation of the Bayanhua sag ranges from 70% to 244.79% (avg.108.1%), especially for the No. 5-3, No. 5-4, No. 5-5, No. 6-3 and No. 6-4 coal seams (Table 3), which indicates that the CBM wells in the Bayanhua sag have the potential for high production during the exploitation process.

CBM accumulation and its controlling factors

Structural types

Tectonics directly affect the formation and evolution of coal-bearing strata, as well as CBM generation, migration, enrichment and preservation. In the process of tectonic evolution, structural deformation and stress field changes also affect CBM migration and occurrence, restricting CBM accumulation (Bai et al., 2014; Hamilton et al., 2012). The Bayanhua syncline is the primary structure in the research area. The syncline axis regions tend to deposit comparatively thick coal-bearing strata, accumulate tectonic stress and maintain relatively stagnant hydrodynamic conditions, which are generally beneficial to CBM accumulation (Li et al., 2005; Yao et al., 2009, 2013; Zhu et al., 2004). In addition, the gas content distributed in the axis regions is much higher, especially in the middle of the Bayanhua syncline (Figure 12). The small-scale synclines and anticlines in the central regions may also have a positive influence on the gas content.

In addition, faults are also an important structural factor that affects CBM accumulation. On the basis of the influence on gas content, faults can be classified as open faults and closed faults. Open faults can be regarded as gas migration and diffusion channels (Chen XJ et al., 2019; Losh et al., 2002), while closed faults can be considered barriers to gathering and trapping migratory gas (Bense and Person, 2006; Jolley et al., 2007). The faults in the Bayanhua sag are all normal faults, which are generally considered gas escape channels (Kedzior et al., 2013; Liu et al., 2009). However, most of the normal faults developed in the Bayanhua sag are closed on account of the dense lithologies present on both sides of the faults. However, the normal faults adjacent to the sag boundary in the southeast are open faults. As a result, it is better to avoid faults during the initial CBM exploration stage.

Roof lithology

Previous studies have shown that roof lithology directly affects CBM preservation and accumulation. Dense, fine-grained and thick roofs possess better sealing capabilities than high-porosity, coarse-grained roofs (Buttinelli et al.,2011; Drobniak et al.,2004; Jin et al.,2015; Ouyang et al.,2017). Three sealing models are divided by different roof lithologies. Models A and B are conducive to CBM preservation. In contrast, model C is adverse to CBM accumulation (Figure 13).

Figure 13.

The sealing models of roof lithology of coal seams in Bayanhua sag.

Different sedimentary environments deposit different types of roof lithologies. The studied coals were primarily deposited in peat swamps associated with braided rivers, fan delta plains and lacustrine areas, which mainly resulted in roofs composed of siltstone, mudstone, pelitic siltstone, and fine sandstone. The roofs of the No. 6-7, No. 6-4, No. 5-2 and No. 5-1 coal are mainly composed of fine-grained mudstone in most of the study area (model A). The roof lithologies of the No. 6-7, No. 6-4, No. 6-1 and No.5-1 coal are made up of siltstone and pelitic siltstone in the northeastern part of the study area (model B). The fine sandstone on the margin of the Bayanhua sag is partly developed in the roof of the No. 6-1 and No. 5-2 coal (model C) (Figure 14). The gas contents of coal seams No. 6-7 and No. 6-4 are higher than those of coal seams No. 6-1, No. 5-2 and No. 5-1.

Figure 14.

Roof lithology distribution of the main coal seams in the Bayanhua sag: The roof lithology distribution of the No. 6-7 coal seam(a), No. 6-4 coal seam(b), No. 6-1 coal seam(c), No. 5-2 coal seam(d), and No. 5-1 coal seam(e).

Hydrogeological condition

Hydrogeology tends to affect CBM generation, migration and accumulation, especially for the enrichment of low-rank CBM (Ayers, 2002; Flores et al., 2008; Yao et al., 2014). For low-rank CBM, weak runoff hydrodynamics could not only be conducive to CBM preservation but also favorable for biogas generation (Beaton et al., 2006; Chen H et al., 2019; Fu et al., 2016). The sandstone pore-confined aquifers interbedded with the main coal seams directly influence CBM enrichment. The unit water inflow rate and permeability coefficient are 0.0091–0.017 L/(s·m) and 0.0098∼0.016 m/d, respectively, indicating weak aqueous aquifers (Table 4). Aquicludes interbedded with coal-bearing strata are thick and continuous between the layers. Therefore, groundwater can only be recharged laterally, CBM is sealed in the weak runoff-stagnant zone.

Table 4.

Hydrogeological parameters of coal measure strata in the Bayanhua Sag.

Aquifer	Hydrochemical type	Salinity (mg/L)	Unit water inflow (L/(s·m))	Permeability coefficient (m/d)
No. 5 coal group	Na-Cl Na-HCO3	791∼1,823	0.0091∼0.017	0.0098∼0.012
No. 6 coal group	Ca·Mg-HCO3Na-HCO3Na-Cl	836∼1,849	0.001∼0.015	0.0011∼0.016

The aquifers of coal strata are in direct contact with the exposed formations on the eastern and western margins of the study area and can be replenished by meteoric precipitation and lateral runoff. From the edge of the study area to the syncline axis regions, the hydrochemical type changes from Ca•Mg-HCO₃ to Na-HCO₃ and Na-Cl, with salinities of 791∼1,849 mg/L, indicating that most of the axis regions are in a weak runoff and stagnant state. The active groundwater in the shallow strata mostly flows to the axis regions in the downward-dipping direction, forming hydraulic sealing of CBM. Additionally, groundwater can transport methane bacteria that can degrade coal seams and generate secondary biogenic gas, which accumulates in coal reservoirs.

Integrated analysis of groundwater flux and CBM enrichment implies that the hydrological units of the study area are separated into two zones: runoff zones and weak runoff-stagnant zones. Influenced by the flux of groundwater, CBM accumulates from the shallow to the deep areas of the syncline. Consequently, the gas content is lower in the runoff zone and higher in the weak runoff-stagnant zone (Figure 15).

Figure 15.

Comprehensive profile of hydrodynamic gas controls in the Bayanhua sag (see Figure 1 for the location).

According to the integrated analysis of the vertical changes in the physical and gas-bearing characteristics of the main coal seams and the controlling factors, the dominant horizon tends to be the No. 6-7 coal seam, followed by the No. 6-4 coal seam.

CBM exploration potential and favorable area appraisal

Influenced by the elements of structure, hydrodynamics, coal mining activities and preservation conditions, it is difficult to accumulate CBM where coal seams are shallower than 300 m. Based on a comprehensive analysis of CBM reservoir properties, gas-bearing characteristics, structural complexity, hydrodynamics and preservation conditions, this paper divided the study area into three zones horizontally A, B, and C, and each of them was evaluated (Figure 16 and Table 5).

Figure 16.

Schematic diagram of zone division in the Bayanhua sag.

Table 5.

CBM geological characteristics in each zone of the Bayanhua sag.

Evaluation parameters	A	B	C
Main coal seam thickness (m)	0–95.59	1.36–131.75	1.23–57.38
Burial depth (m)	20.65–325.32	140.48–974.57	90.95–1,300
Roof mudstone thickness (m)	1.4–11.45	0.6–89.03	0.7–101.4
Gas content (m³/t)	0–2.2	0.5–3.18	0.6–3.53
Structural complexity	Simple	Medium	Simple
Hydrodynamics	Recharge and runoff zone	Weak runoff and stagnant zone	Stagnant zone
Resource abundance (×10⁸ m³/km²)	0.43	1.66	1.91

Zone A is mostly located along the southwestern, southeastern and northwestern edges of the study area, with a main coal seam burial depth of 20.65–425.32 m. Affected by coal mining activities and weathered zones, the CBM preservation conditions in this zone are generally poor. The main coal seams are 0–95.59 m thick, and the faults barely develop, resulting in a relatively simple structure. In addition, the coal seams are generally located in the replenishment and runoff zone, leading to low gas content of 0–2.2 m³/t. Therefore, the abundance of CBM resources is only 0.43 × 10⁸ m³/km², which is unfavorable for CBM exploration. Furthermore, all open-pit mines in the study area are located in this zone. As a consequence, Zone A might not be conducive to CBM exploitation.

Zone B is distributed in the middle of the Bayanhua sag. The main coal seams have burial depths of 140.48–974.57 m. In contrast with other zones, this zone has the thickest accumulated thickness of coal seams (1.36–131.75 m). The coal-bearing strata are mostly distributed in the weak runoff-stagnant zone, and the thickness of mudstone in the roof is 0.6–89.03 m. Therefore, the gas content (0.5–3.18 m³/t) of the coal seams is comparatively higher. The abundance of CBM resources is approximately 1.66×10⁸ m³/km² and has good exploitation potential from the perspective of resources. According to the structural development, zone B is subdivided into two subzones B1 and B2.

Subzone B1, where the faults are barely developed, is conducive to CBM exploration and development. Subzone B2, where 11 normal faults are distributed, exhibits a complex structure. Although the gas content and resource abundance in this subzone are relatively high, CBM development may be technically difficult in the initial stage; as a result, it could be regarded as a candidate area.

Zone C is located in the northeastern Bayanhua sag and is mainly in the syncline axis region. The burial depth is 90.95–1,300 m and mostly deeper than 600 m. Although the cumulative thickness of the coal seams is 1.23–57.38 m, most of them are distributed in the stagnant zone with respect to hydrodynamic conditions. Coupled with the thick mudstone in the roof (0.7–101.4 m), the coal seams chiefly possess the highest gas contents (0.6–3.53 m³/t). Only small-scale normal faults are developed on the western side of this zone, creating relatively simple tectonic conditions. Therefore, the CBM resource abundance is 1.91×10⁸ m³/km², which is beneficial to CBM exploration. According to the burial depth, zone C is partitioned into two subzones. Subzone C2 is located at the edge of the sag, with burial depth shallower than 300 m, which is not conducive to CBM development. Subzone C1 is located in the syncline axis region. All CBM wells have good gas indications during drilling, and are advantageous to CBM exploration on the basis of the comprehensive analysis of coal seam thickness, burial depth, hydrodynamics, roof lithology and gas-bearing conditions.

Conclusions

The Bayanhua sag features large, thick coal seams in most regions, with an accumulated thickness of the main coal seams of 1.00–78.85 m (avg.22.53 m). The low-rank coal is mainly lignite and subbituminous coal, with R_o values ranging from 0.311% to 0.592%, and is primarily affected by plutonic metamorphism. Coals in the Bayanhua sag tend to be characterized by a relatively high content of organic components (avg. 82.32%) and low levels of ash and moisture, high volatile contents and moderate burial depths, which are beneficial to CBM accumulation and preservation.

The coal reservoirs in the Bayanhua sag are characterized by mainly medium porosity (7.3–27.8%, avg. 20.77%) and low permeability (0.05–21.8 mD, avg.5.54 mD). Pore morphology is represented by transition pores with inkpot, open cylindrical or flat shapes, leading to low-medium connectivity. To improve the permeability of coal reservoirs and penetrate through pores and fracture systems of different sizes, hydraulic fracturing should be used to enhance CBM production.

The gas content of the Bayanhua sag is affected by various factors such as hydrodynamics, roof lithology, and structure. The gas content of coals is 1.66–4.45 m³/t (avg. 3.34 m³/t). Gas saturation ranges from 70% to 244.79% (avg.108.1%). Horizontally, the gas content generally increases toward the syncline axis regions, with the highest in the central and northeastern regions. Vertically, the No. 6-7 and No. 6-4 coal seams have higher gas contents than the No. 6-1, No. 5-2, and No. 5-1 coal seams. The CBM in the Bayanhua sag is mainly of secondary biological origin.

The Bayanhua syncline is the main structure, and most of the faults are closed. The roof lithology mainly consists of mudstone and sandy mudstone, which are dense, fine grained and thick. The syncline axis region, with relatively thick coal-bearing strata, accumulated tectonic stress and weak runoff-stagnant hydrodynamic conditions, is favorable to CBM enrichment and preservation. According to the integrated analysis of the vertical changes in the physical properties and gas-bearing characteristics, the dominant horizon tends to be the No. 6-7 coal seam, followed by the No. 6-4 coal seam.

Based on the coal seam distribution, gas-bearing characteristics, structure, roof lithology, and hydrodynamic conditions of the Bayanhua sag, the main coal seams in zone B and zone C exhibit thick and moderate burial depths, weak runoff-stagnant hydrodynamic conditions, and comparatively better gas-bearing conditions. The abundances of CBM resources in these zones are 1.66 × 10⁸ m³/km² and 1.91 × 10⁸ m³/km², respectively. Based on these conditions, subzone B1 and subzone C1 possess opportune geological conditions for CBM exploration, while the structure of subzone B2 is fairly complex and can be considered a candidate area for CBM exploitation.

Highlights

The Lower Cretaceous Tengger Formation coal and the geological characteristics of large, thick and low-rank CBM in the representative graben-shaped sag (Bayanhua sag) are analyzed in detail.

Gas-bearing analysis makes clear that almost half of coal reservoirs are supersaturated, and microbial carbon dioxide reduction is the dominant methane genetic type in situ.

The CBM prospecting potential in the Bayanhua sag was appraised, and two favorable zones are predicted for CBM development.

Footnotes

Acknowledgements

This work was subsidized by the National Science and Technology Major Project of China (2016ZX05041-003),Geological Exploration Fund Project of Inner Mongolia (20-1-NY02),Key Technology Research Project of Inner Mongolia,and the Major Science and Technology Project of China National Petroleum Corporation (2021DJ2303). The authors appreciate the anonymous reviews for their elaborative reviews and detailed comments.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research,authorship,and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research,authorship,and/or publication of this article: This work was supported by the the Major Science and Technology Project of China National Petroleum Corporation,the National Science and Technology Major Project of China,Key Technology Research Project of Inner Mongolia,Geological Exploration Fund Project of Inner Mongolia,(grant number 2021DJ2303,2016ZX05041-003,20-1-NY02).

ORCID iDs

Dazhen Tang

Hao Xu

Shu Tao

References

Ayers

JWB

(2002) Coalbed gas systems, resources, and production and a review of contrasting cases from the San Juan and Powder River Basins. AAPG Bulletin 86: 1853–1890.

Bai

Yan

, et al. (2014) Structural features controls of coalbed methane (CBM) accumulation in the Weibei CBM field, Southeastern Ordos Basin. Advanced Materials Research 962: 79–82.

Beaton

Langenberg

Panǎ

(2006) Coalbed methane resources and reservoir characteristics from the Alberta Plains, Canada. International Journal of Coal Geology 65: 93–113.

Bense

Person

(2006) Faults as conduit-barrier systems to fluid flow in siliciclastic sedimentary aquifers. Water Resources Research 42: 1–18.

Bonnetti

Malartre

Huault

, et al. (2014) Sedimentology, stratigraphy and palynological occurrences of the late Cretaceous Erlian Formation, Erlian Basin, Inner Mongolia, People’s Republic of China. Cretaceous Research 48: 177–192.

Buttinelli

Procesi

Cantucci

, et al. (2011) The geo-database of caprock quality and deep saline aquifers distribution for geological storage of CO2 in Italy. Energy 36: 2968–2983.

Charles

Augier

Gumiaux

, et al. (2013) Timing, duration and role of magmatism in wide rift systems: Insights from the Jiaodong Peninsula (China, East Asia). Gondwana Research 24: 412–428.

Chen

Stuart

, et al. (2019) Evolution of coal-bed methane in Southeast Qinshui Basin, China: Insights from stable and noble gas isotopes. Chemical Geology 529: 119–298.

Chen

, et al. (2016) Simulation experiment on enhancing coalbed methane production by microbes. Coal Geology & Exploration 44(4): 64–68.

10.

Chen

Qin

Deng

, et al. (2019) Factors influencing biogenic gas production of low-rank coal beds in the Jiergalangtu Sag, Erlian Basin. Natural Gas Industry 6: 1–6.

11.

Chen

Yuan

, et al. (2019) Effect and mechanism of geological structures on coal seam gas occurrence in Changping minefield. Energy Science & Engineering 8: 104–115.

12.

Diessel

(1982) An appraisal of coal facies based on maceral characteristics. Australian Coal Geology 4: 474–483.

13.

Ding

Liu

Zha

, et al. (2015) Characteristics and origin of lacustrine source rocks in the lower Cretaceous, Erlian Basin, northern China. Marine and Petroleum Geology 66: 939–955.

14.

Dou

Chang

(2003) Fault linkage patterns and their control on the formation of the petroleum systems of the Erlian Basin, Eastern China. Marine and Petroleum Geology 20: 1213–1224.

15.

Drobniak

Mastalerz

Rupp

, et al. (2004) Evaluation of coalbed gas potential of the Seelyville coal member, Indiana, USA. International Journal of Coal Geology 57: 265–282.

16.

Esen

Özer

Soylu

, et al. (2020) Geological controls on gas content distribution of coal seams in the Kınık coalfield, Soma Basin, Turkey. International Journal of Coal Geology 231: 1036–1052.

17.

Flores

Rice

Stricker

, et al. (2008) Methanogenic pathways of coal-bed gas in the Powder River Basin, United States: The geologic factor. International Journal of Coal Geology 76: 52–75.

18.

Huo

Chen

, et al. (2006) The study on the reservoir characteristics of low rank coal seam in China. China Coalbed Methane 3(2): 42–46.

19.

Tang

, et al. (2016) Geological characteristics and CBM exploration potential evaluation: A case study in the middle of the southern Junggar Basin, NW China. Journal of Natural Gas Science and Engineering 30: 557–570.

20.

Hamilton

Esterle

Golding

(2012) Geological interpretation of gas content trends, Walloon Subgroup, eastern Surat Basin, Queensland, Australia. International Journal of Coal Geology 101: 21–35.

21.

Hamilton

Golding

Baublys

, et al. (2014) Stable isotopic and molecular composition of desorbed coal seam gases from the Walloon Subgroup, eastern Surat Basin, Australia. International Journal of Coal Geology 122: 21–36.

22.

Jin

Cheng

Wang

, et al. (2015) The effect of sedimentary redbeds on coalbed methane occurrence in the Xutuan and Zhaoji coal mines, Huaibei Coalfield, China. International Journal of Coal Geology 137: 111–123.

23.

Jolley

Bar

Walsh

, et al. (2007) Structurally complex reservoirs: An introduction. Geological Society London Special Publication 292(1): 1–24.

24.

Yan

, et al. (2014) Origin types of CBM and their geochemical research progress. Journal of China Coal Society 39(5): 806–815.

25.

Kaiser

Hamilton

Scott

, et al. (1994) Geological and hydrological controls on the producibility of coalbed methane. Journal of the Geological Society of London 151: 417–420.

26.

Kedzior

Kotarba

Pekała

(2013) Geology, spatial distribution of methane content and origin of coalbed gases in Upper Carboniferous (Upper Mississippian and Pennsylvanian) strata in the south-eastern part of the Upper Silesian Coal Basin, Poland. International Journal of Coal Geology 105: 24–35.

27.

Lau

Huang

(2017) Challenges and opportunities of coalbed methane development in China. Energy & Fuels 31: 588–602.

28.

Levine

(1992) Influences of coal composition on coal seam reservoir quality—a review. In: Coalbed Methane Symposium, pp.19–21.

29.

Wang

, et al. (2005) Theory of syncline-controlled coalbed methane. Natural Gas Industry 25: 26–28.

30.

Yao

(2016) CBM Resource distribution features in Inner Mongolia. Coal Geology of China 28: 43–48.

31.

Lau

Huang

(2018) China’s coalbed methane development: A review of the challenges and opportunities in subsurface and surface engineering. Journal of Petroleum Science and Engineering 166: 621–635.

32.

Tian

Chen

, et al. (2010) Research and application of appraisal variables for the prioritizing of coalbed methane areas featured by different coal ranks. Natural Gas Industry 30: 45–47. 63.

33.

Tang

, et al. (2014) Experimental research on coal permeability: The roles of effective stress and gas slippage. Journal of Natural Gas Science and Engineering 21: 481–488.

34.

Liu

Ranjith

, et al. (2018) Geological controls on variable gas concentrations: A case study of the northern Gujiao Block, northwestern Qinshui Basin, China. Marine and Petroleum Geology 92: 582–596.

35.

Lin

Eriksson

Sitian

, et al. (2001) Sequence architecture, depositional systems, and controls on development of lacustrine basin fills in part of the Erlian basin, northeast China. American Association of Petroleum Geologists 85(11): 2017–2043.

36.

Liu

Yao

Tang

, et al. (2009) Coal reservoir characteristics and coalbed methane resource assessment in Huainan and Huaibei coalfields, Southern North China. International Journal of Coal Geology 79: 97–112.

37.

Liu

Sang

Wang

, et al. (2014) Block scale investigation on gas content of coalbed methane reservoirs in southern Qinshui basin with statistical model and visual map. Journal of Petroleum Science and Engineering 114: 1–14.

38.

Liu

Wang

, et al. (2005) Exploring fore-ground of low rank coal basins in eastern inner Mongolia of China. Natural Gas Geoscience 6(6): 771–775.

39.

Losh

Walter

Meulbroek

, et al. (2002) Reservoir fluids and their migration into the South Eugene Island Block 330 reservoirs, offshore Louisiana. AAPG Bulletin 86: 1463–1488.

40.

Lyu

Wang

Chen

, et al. (2020) Natural fractures in soft coal seams and their effect on hydraulic fracture propagation: A field study. Journal of Petroleum Science and Engineering 192: 107255.

41.

Moore

(2012) Coalbed methane: A review. International Journal of Coal Geology 101: 36–81.

42.

Ouyang

Sun

Wang

, et al. (2017) CBM Sealing system and its relationship with CBM enrichment. Natural Gas Industry B 4: 39–47.

43.

Ruppert

Hower

Ryder

, et al. (2010) Geologic controls on thermal maturity patterns in Pennsylvanian coal-bearing rocks in the Appalachian basin. International Journal of Coal Geology 81: 169–181.

44.

Scott

(2002) Hydrogeologic factors affecting gas content distribution in coal beds. International Journal of Coal Geology 50: 363–387.

45.

Sun

Shao

Zhao

, et al. (2008) Evaluation of coalbed gas exploration target in Erlian Basin. Coal Geology & Exploration 36(1): 22–26.

46.

Sun

Cheng

, et al. (2018) The feasibility of biological gas recovery in low-rank coal:A case study of Jiergalangtu depression in Erlian Basin. Acta Petrolei Sinica 39: 1272–1278. 1291.

47.

Sun

, et al. (2017) Low-rank coalbed methane exploration in Jiergalangtu sag, Erlian Basin. Acta Petrolei Sinica 38(5): 485–492.

48.

Sun

Wang

Tian

, et al. (2018) Accumulation patterns of low-rank coalbed methane gas in the Jiergalangtu Sag of the Erlian Basin. Natural Gas Industry 38(4): 59–66.

49.

Tang

, et al. (2018) Coalbed methane accumulation conditions and enrichment models of Walloon Coal measure in the Surat Basin, Australia. Natural Gas Industry B 5: 235–244.

50.

Tang

Cheng

, et al. (2015) Occurrence and sedimentary control of sulfur in coals of China. Journal of China Coal Society 40(9): 1977–1988.

51.

Tao

Shen

Wang

, et al. (2019) Genetic types and exploration prospect of coalbed methane in Jiergalangtu depression, Erlian Basin. Geological Journal of China Univerdities 25(2): 295–301.

52.

Tao

Wang

, et al. (2014) Comprehensive study on genetic pathways and parent materials of secondary biogenic gas in coalbeds. Chinese Science Bulletin 59(11): 970–978.

53.

Tao

Tang

, et al. (2014) Factors controlling high-yield coalbed methane vertical wells in the Fanzhuang Block, Southern Qinshui Basin. International Journal of Coal Geology 134–135: 38–45.

54.

Tao

Pan

Tang

, et al. (2019b) Current status and geological conditions for the applicability of CBM drilling technologies in China: A review. International Journal of Coal Geology 202: 95–108.

55.

Wang

, et al. (2020) CBM Geological characteristics and exploration potential in the Sunan Syncline block, southern north China basin. Journal of Petroleum Science and Engineering 186: 1067–1093.

56.

Whiticar

(1999) Carbon and hydrogen isotope systematics of bacterial formation and oxidation of methane. Chemical Geology 161: 291–314.

57.

Xin

Tang

(2020) An improved method to determine accurate porosity of low-rank coals by nuclear magnetic resonance. Fuel Processing Technology 205: 1064–1077.

58.

Tang

Liu

, et al. (2012) Study on coalbed methane accumulation characteristics and favorable areas in the Binchang area, southwestern Ordos Basin, China. International Journal of Coal Geology 95: 1–11.

59.

Tang

, et al. (2014) A dynamic prediction model for gas-water effective permeability based on coalbed methane production data. International Journal of Coal Geology 121: 44–52.

60.

Yao

Wang

, et al. (2020) Key geological factors and evaluation methods for huge low-rank coalbed methane reservoirs: Taking Bayanhua depression in Erlian basin as an example. Coal Geology & Exploration 48: 85–95.

61.

Yao

Liu

Tang

, et al. (2009) Preliminary evaluation of the coalbed methane production potential and its geological controls in the Weibei Coalfield, Southeastern Ordos Basin, China. International Journal of Coal Geology 78: 1–15.

62.

Yao

Liu

Tang

, et al. (2010) Petrophysical characterization of coals by low-field nuclear magnetic resonance (NMR). Fuel 89: 1371–1380.

63.

Yao

Liu

Qiu

(2013) Variable gas content, saturation, and accumulation characteristics of Weibei coalbed methane pilot-production field in the southeastern Ordos Basin, China. AAPG Bulletin 97: 1371–1393.

64.

Yao

Liu

Yan

(2014) Geological and hydrogeological controls on the accumulation of coalbed methane in the Weibei field, southeastern Ordos Basin. International Journal of Coal Geology 121: 148–159.

65.

Yuan

Lyu

Wang

, et al. (2022) Macrolithotype controls on natural fracture characteristics of ultra-thick lignite in Erlian Basin, China: Implication for favorable coalbed methane reservoirs. Journal of Petroleum Science and Engineering 208: 109598.

66.

Yun

Zeng

, et al. (2012) Analysis of critical restricting factors and proposals for coabed methane development in China. Advanced Materials Research 361–363: 848. 52.

67.

Zhao

Shen

Qin

, et al. (2021) Coal petrology effect on nanopore structure of lignite: Case study of No. 5 coal seam, Shengli coalfield, Erlian Basin, China. Natural Resources Research 30: 681–695.

68.

Zhao

Jiang

Zhang

, et al. (2017) Main controlling factors of productivity and development strategy of CBM wells in Block 3 on the eastern margin of Ordos Basin. Acta Petrolei Sinica 38(11): 1310–1319.

69.

Zhu

Song

Cui

(2004) The study of syncline controlling coalbed methane in Wangying-Liujia district in Fuxin coal field. Natural Gas Geoscience 15: 673–675.

Coalbed methane geology and exploration potential in large,thick,low-rank seams in the Bayanhua Sag of the Erlian Basin,northern China

Abstract

Keywords

Introduction

Geological setting

Tectonic setting

Coal-bearing strata in the Bayanhua sag

Samples and experiments

Data and sample sources

Experiments

Results and discussion

Physical properties of CBM reservoirs

Coal maceral composition and quality

Reservoir porosity and permeability

Pore structure

Microfractures

Coal seam gas-bearing properties

Origin of coalbed methane

Gas-bearing characteristics

CBM accumulation and its controlling factors

Structural types

Roof lithology

Hydrogeological condition

CBM exploration potential and favorable area appraisal

Conclusions

Highlights

Footnotes

Acknowledgements

Declaration of conflicting interests

Funding

ORCID iDs

References