1 Introduction
China has made significant strides regarding the discovery and exploitation of coalbed methane (CBM) in recent years (
Li et al., 2023;
Xu et al., 2023), with two major CBM demonstration zones being established in the Ordos and Qinshui Basins alongside large-scale development in regions such as southern Sichuan and western Liaoning (
Li et al., 2011;
Zhao and Wei, 2022;
Yan et al., 2023). Globally, research teams have turned their attention to deep and multi-layer coal-derived gas targets to expand coal-derived gas reserves and enhance production. Deep coal-derived gas deposits are currently being developed and yielding encouraging results in the Qinshui Basin and on the eastern fringe of the Ordos Basin (
Shao et al., 2021;
Shen et al., 2021;
Mondal et al., 2024). The Shuangyashan Basin in north-east China contains typical Mesozoic coal-bearing strata, highlighting significant potential for coal-derived gas resources (
Ma and Fan, 2002;
Hou et al., 2010;
Gao and Sun, 2011); however, research on coal-derived gas in this region remains in its early stages, focusing primarily on preliminary studies of coal quality characteristics, regional coal-bearing features, and coal reservoir properties. A notable research gap remains due to a lack of comprehensive studies on the origin, hydrocarbon generation evolution, gas-bearing characteristics, and accumulation mechanisms of coal-derived gas in this region, thus restricting the comprehensive evaluation of oil and gas potential in the Shuangyashan Basin. This research gap must be addressed to promote the exploration and efficient development of coal-derived gas resources in this area.
The hydrocarbon generation evolution and accumulation processes of coal-bearing strata result from the coupled interactions of multiple factors and conditions (
Yu et al., 2018;
Quan et al., 2022;
Yan et al., 2024), influenced by the complexities of geological burial processes, tectonic evolution stages, and specific geological events, the physical properties of source rocks and reservoirs, and regional sealing conditions (
Yan et al., 2015;
Shen et al., 2021;
Cao et al., 2024;
Lin et al., 2024). These elements collaboratively influence the efficiency of hydrocarbon generation and the maturity of organic materials in source rocks to shape the basin’s overall resource potential (
Yu et al., 2020;
Cheng et al., 2024;
Gong et al., 2024). Therefore, conducting a comprehensive analysis of the tectonic evolution characteristics of sedimentary basins and reconstructing their geological accumulation processes will significantly improve our understanding of the enrichment and accumulation characteristics of coal-derived gas. Numerous researchers have combined geochemical testing techniques with basin modeling methods to investigate the formation history of coal reservoirs and the hydrocarbon generation processes in various sedimentary basins, proposing corresponding evolution mechanisms for coal-derived gas accumulation (
Yu et al., 2020;
Cheng et al., 2024;
Yan et al., 2024); however, existing studies primarily focus on the coalbed methane geological conditions and development practices in typical domestic basins, such as the Ordos Basin and the Qinshui Basin. In contrast, research on coalbed methane enrichment zones in foreign regions with similar tectonic backgrounds or significant volcanic-thermal events influencing the system is lacking (
Li et al., 2011;
Zhao and Wei, 2022;
Yan et al., 2023, 2025). The San Juan Basin in the United States is one of the world’s most well-known examples where thermal events, such as deep hydrothermal activity and anomalous high geothermal gradients, have significantly promoted coalbed methane enrichment and high production (
Reiter and Clarkson, 1983;
Clarkson and Reiter, 1987;
Kaiser and Ayers, 1994;
Ayers, 2003). The high-yield gas area in the Cretaceous Fruitland Formation coal seams of this basin is closely associated with the distribution of overlying volcanic rocks, deep hydrothermal activity, and the resulting anomalous high geothermal gradients. Intense thermal evolution significantly increased the coal rank and promoted the generation of large quantities of thermogenic gas (
Clarkson and Reiter, 1987;
Kaiser and Ayers, 1994;
Ayers, 2003). The tectonic–thermal evolution history of the Shuangyashan Basin since the Cenozoic, as well as how much volcanic activity has impacted the evolution of source rocks that generate hydrocarbons in the research area, remains poorly understood. Therefore, using geochemical parameters to reconstruct hydrocarbon production methods and the history of tectonic–thermal evolution of the eastern margin of the Shuangyashan Basin since the Late Mesozoic will allow us to clarify the accumulation processes of coal-bearing strata and evaluate resource potential.
This study’s main objectives are to (i) assess the possibility and severity of hydrocarbon formation in the source rocks along the Shuangyashan Basin’s eastern edge via organic geochemical analysis; (ii) combine geochemical information with structural and stratigraphic details gleaned from drilling results and use PetroMod 1D software to build models that depict the burial history, thermal evolution, and hydrocarbon generation processes of the coal-bearing strata in the research area; and (iii) ascertain the evolutionary mechanisms underlying the accumulation of coal-derived gas in the research area and identify the critical circumstances that promote coal-derived gas enrichment and accumulation. This study offers significant insights and is an essential resource for the accurate assessment, investigation, and development of coal-derived gas resources in the Shuangyashan Basin.
2 Geological settings
The Shuangyashan Basin is located in the central part of the Jiamusi Block, with a predominantly east–west orientation and a monocline structure that dips southward. To the north and south, it is connected to the Sanjiang Basin and borders the Shuanghua Basin, respectively, with the entire basin surrounded by the Huanan Uplift (Fig. 1(a)). The internal structure of the basin is highly complex and is influenced by thrust faults, with numerous folds and faults developed from east to west. The coal-bearing strata have undergone several structural movements since their formation, experiencing various geological burial and deformation processes (Fig. 1(b)). The current structural state results from the superposition of several tectonic movements, which can be divided into the embryonic stage (Early to Middle Yanshan period), the development stage (Late Yanshan period to the first stage of the Himalayan period), and the final stage (second stage of the Himalayan period to the present) of tectonic evolution (
Guo and Wang, 2008;
Zhang et al., 2009, 2020;
Lan et al., 2023).
Based on stratigraphic data revealed by drilling and profiles within the basin, in descending chronological order, the strata consist of the Cretaceous, Neogene, and Quaternary, (Fig. 1(c)). Dispersed throughout the study area, coal-bearing strata from the Cretaceous Chengzihe (CZH) and Muling (ML) Formations are the study’s target layers, primarily consisting of sandstone, coal seams, and thin layers of mudstone, with a thickness of 512.89 m, and sandstone, andesite, thin layers of mudstone and shale, and coal seams, with a thickness of 584.85 m, respectively.
3 Samples and methodology
3.1 Sample preparation
This study selected eight drill cuttings samples (including coal seams 8, 12, 13, etc.) from the SD-01 coal-derived gas parameter well on the eastern margin of the Shuangyashan Basin (Fig. 1(c)) to effectively evaluate the hydrocarbon generation intensity and potential of source rocks in the study area. All samples were collected from the Cretaceous Chengzihe Formation via borehole cores, with sampling depths ranging from 1100 m to 1450 m (Table 1), and were unaffected by weathering or erosion, with their lithology identified as coal.
3.2 Experimental method
The analysis of coal samples involved determining vitrinite reflectance, total organic carbon (TOC) concentration, proximate analysis of coal, and methane isothermal adsorption experiments, all of which was carried out at the Jiangsu Geological and Mineral Design and Research Institute’s laboratory. Vitrinite reflectance was measured using an Axio Imager Mlm microspectrophotometer (ZEISS, Germany) with a 100× magnification lens, following the Chinese standard
SY/T 5124–2012, where 50 measurement points were examined for each sample to reduce mistakes.
TOC content determination was conducted using the total organic carbon measurement method for sedimentary rocks. To eliminate inorganic carbon, coal samples were pulverized into particles smaller than 0.074 mm (after passing through a 200-mesh filter) and then steeped in boiling hydrochloric acid. The analyses were carried out using a CS-230 carbon–sulfur analyzer (LECO, St. Jose, CA, USA) with an accuracy range of ± 0.001–0.5%, in accordance with the Chinese standard
GB/T19145-2022.
Proximate analysis of coal was conducted by grinding coal samples into particles smaller than 0.2 mm (passing through a 60-mesh sieve) and using a 5E-MAG6700 fully automated proximate analyzer (Changsha Kaiyuan Instruments Co., Ltd., China). The Chinese standard
GB/T 212–2008 was followed in the analyses of the fixed carbon content, ash, moisture, and volatile matter.
The identification and analysis of coal macerals involved preparing thin sections of coal samples and examining them under transmitted light and reflected fluorescence conditions. The Chinese standard SY/T5125-2014 was followed in the analyses of the fixed carbon content, ash, moisture, and volatile matter.
High-pressure methane isothermal adsorption experiments on coal were performed by crushing coal samples into particles ranging from 0.180 mm to 0.425 mm in diameter (40 to 60 mesh). The adsorption capacity of the coal samples for methane and other gases was analyzed using an H-Sorb 2600 analyzer (Guoyi Quantum) in accordance with the Chinese standard GB/T 19560-2008.
The Chengzihe Formation coal’s hydrocarbon generation potential and organic matter maturity were assessed using Origin (2021) software, previously created categorization templates, and analytical techniques based on the experimental data. The burial and hydrocarbon generation history of the coal-bearing layers on the eastern margin of the Shuangyashan Basin were simulated using Schlumberger’s PetroMod 1D (2012.2) program in conjunction with geochemical data and stratigraphic information obtained from drilling records.
3.3 1D basin modeling method
3.3.1 Model selection and parameterization
The petroleum system of a basin primarily comprises three key elements, namely source rock maturation, hydrocarbon generation, and hydrocarbon expulsion (
Gottardi et al., 2019). The hydrocarbon generation evolution of a basin can be analyzed and simulated based on geological factors such as stratigraphic deposition processes, tectonic evolution history, geochemical characteristics of source rocks, and depositional environments. Stratigraphy, thickness, absolute ages of deposition and erosion events, lithology, total organic carbon (TOC) content, hydrogen index (HI) values, kinetic equations, and other pertinent characteristics are among the geological data inputs used in PetroMod 1D basin modeling and analysis (
Büker et al., 1995;
Gottardi et al., 2019;
Yu et al., 2020;
Wang et al., 2024) (Table 2, Figs. 2 and 3). This study built on previous research findings and employed PetroMod 1D to perform one-dimensional sedimentary burial history modeling for Well SD-01 (coordinates: 44476387.49, 5147562.3) in the study area, reconstructing the hydrocarbon generation evolution of the Chengzihe and Muling Formations.
3.3.2 Erosional events
The accurate identification and representation of stratigraphic uplift and erosion events are essential for constructing precise geological models. Stratigraphic erosion is a direct consequence of tectonic uplift, and its thickness restoration forms the basis for sedimentary burial history analysis. Erosion thickness can be estimated through two primary methods, namely regional stratigraphic thickness comparison and indirect inference techniques, such as vitrinite reflectance analysis or reservoir porosity correction (
Armagnac et al., 1989;
Kim et al., 2018;
Hamsi Júnior et al., 2024). The study area underwent three significant uplift and erosion events following the deposition of the Chengzihe Formation, according to previous studies and descriptions of the tectonic and sedimentary evolution of the Sanjiang Basin. The first event occurred during the Late Yanshanian tectonic uplift, leading to the absence of Lower Cretaceous strata in most parts of the study area and the formation of a parallel unconformity between the Lower Cretaceous and the overlying Paleogene strata, and is estimated to have taken place between approximately 90 Ma and 65 Ma, with erosion thicknesses ranging from 1000 m to 1600 m (
Han, 2021). The second event, occurring between approximately 36 Ma and 20 Ma, was influenced by the second phase of the Himalayan movement, causing crustal uplift in the study area and erosion of Paleogene strata, with erosion thicknesses ranging from 600 m to 2000 m (
Yu et al., 2010;
Xu et al., 2013;
Dong et al., 2023). The third event took place in the late Neogene and is estimated to have occurred between approximately 15 Ma and 10 Ma with erosion thicknesses ranging from 150 m to 1000 m (
Zhang, 2019); driven by the late Himalayan tectonic movement, this phase involved extensive folding, faulting, and regional uplift, leading to erosion and the formation of the basin’s present-day depositional characteristics.
3.3.3 Petroleum system enhancement (PSE)
The configuration of the petroleum system elements (PSEs) is hypothesized based on stratigraphic lithology and contact relationships, with the coal seams of the Muling and Chengzihe Formations serving as potential source rocks in the study area (Table 1). The reservoirs in the study area are largely classified into sandstone reservoirs and coal reservoirs from the Muling and Chengzihe Formations. The sandstones in these formations exhibit good porosity and permeability, along with natural fracture systems, which provide favorable connectivity for hydrocarbon accumulation and redistribution within the reservoirs, whereas coal reservoirs possess the unique characteristics of being both self-sourcing and self-storing and exhibit high microporosity and a large specific surface area, enabling the efficient adsorption and storage of coalbed methane resources. Furthermore, coal seams are highly compact, and the surrounding rocks generally exhibit excellent sealing properties, effectively preventing the dissipation of coalbed methane and facilitating its long-term preservation within the coal seams.
The cap rocks in the study area primarily consist of interbedded sandstones, mudstones, and andesite of the Dongshan Formation, which exhibit excellent compactness and extremely low permeability, providing dual sealing protection through the andesite and mudstone. Individually, the sandstone acts as an isolating layer and a localized storage medium. Together, the sandstone, mudstone, and overlying andesite form a composite sealing system that effectively limits the dissipation of coalbed methane, thus creating highly favorable conditions for its long-term preservation and enrichment.
3.3.4 Source rock characteristics and kinetics
Source rocks’ HI value and TOC content are useful markers for assessing their capacity to produce hydrocarbons. The findings of TOC experimental analysis of eight coal core samples from the Chengzihe Formation in Well SD-01 (Table 1) indicate that the Chengzihe coal seams have an average TOC content of 81.73%. Furthermore, previous evaluations of the organic matter abundance in the coaly source rocks of the Shuangyashan Basin have shown that the S1 + S2 of the Chengzihe Formation coal ranges from 165.14 mg/g to 244.32 mg/g (average 198.41 mg/g), with an average hydrogen index (HI) of 254.11 mg/g and a range of 213.2 mg/g to 327.7 mg/g. The Muling Formation coal has an average organic matter concentration (TOC) of 71.92%, with a range of 66.92% to 76.91%. Its S1 + S2 and hydrogen index (HI) range from 151.16 mg/g to 178.2 mg/g (average 164.67 mg/g) and from 221.15 mg/g to 228.15 mg/g (average 224.65 mg/g), respectively (
Hou et al., 2010). This study integrates lithological assemblage characteristics, stratigraphic thickness data, TOC content, and HI values of source rocks, applies the kinetic methods for Type II and Type III kerogens proposed by
Burnham and Sweeney (1989) to constrain source rock parameters, and utilizes PetroMod software to conduct one-dimensional basin modeling analysis.
3.3.5 Heat flow calculation
Heat flow has the greatest influence on the hydrocarbon creation and development of coaly source rocks, as the generation of coal-derived hydrocarbons results from the combined effects of heat and time. Based on the extensive literature, the study area was located in the Circum-Pacific tectonic domain during the Early Cretaceous, with a geothermal gradient of 4.26°C/(100 m)–7.0°C/(100 m) (
Lu et al., 2024). During the late Early Cretaceous, from the sedimentation of the Chengzihe Formation to the Dongshan Formation, the basin entered a subsidence phase, causing a reduction in the geothermal gradient and a transition to a low-temperature stable state. In the Paleogene, the study area was influenced by the Himalayan orogeny and magmatic activities, resulting in anomalous geothermal conditions and geothermal gradients ranging from 3.2°C/(100 m) to 3.7°C/(100 m) (corresponding to heat flow values of approximately 80–92.5 mW/m
2) (
Jiang et al., 2009). According to borehole temperature profiles, the current geothermal gradient in the study area is 3.18°C/(100 m), with a corresponding heat flow value of approximately 79 mW/m
2.
The basin modeling analysis was adjusted to include various heat flow values from earlier research to develop the ideal basin model. The heat flow values were refined using the measured Ro values, ultimately achieving the best-fit result (Fig. 2(b)).
3.3.6 PWD and SWIT simulation
Paleowater depth is determined by the depositional environment of the study area; as such, incorporating variations in paleowater depth, obtained from previous studies (
Yang et al., 2012) (Fig. 3), allows the simulation results of the burial history to more accurately reflect the actual burial process. PetroMod (2012.2) software was used to automatically determine the surface water temperature (SWIT) of the deposits in the research area, which is situated in the Northern Hemisphere’s East Asia region between 46° and 47° N latitude (Fig. 2(a)).
4 Results
4.1 Source rock characteristics
The organic petrological features of the investigated coaly source rocks are shown in Table 1 and Figs. 4 and 5. One important measure of a coal reservoir’s ability to produce hydrocarbons is the maturity of its coal organic matter, which directly impacts the accumulation, migration, and trapping processes of coalbed methane and its hydrocarbon formation and evolution. Therefore, the ability to determine when coalbed methane generation and accumulation occur depends on knowing how mature the coal organic matter is. According to the maturity (Ro) analysis of coal organic matter from the Chengzihe Formation, the Ro values of coal samples from Well SD-01 range from 0.95% to 1.04% (average 0.996%), indicating that the Chengzihe coal seams have reached the mature stage. Additionally, the poor relationship between Ro and burial depth suggests that magmatic intrusions throughout the Late Cretaceous likely had an impact on the maturity of the source rocks in the study area, rather than burial depth alone (Table 1, Fig. 3(a)). The test results reveal significant variability in the organic matter abundance of the Chengzihe Formation coal samples, with the TOC content ranging from 72.61 wt% to 91.88 wt%. Overall, coal samples have an average TOC value of 84.07 weight percent, indicating that they are excellent source rocks with the ability to generate hydrocarbons.
The macroscopic coal type in the study area is predominantly bright coal, whose main constituents under a microscope are vitrinite, inertinite, and liptinite, the latter being the least prevalent. The average mass fractions of vitrinite, inertinite, and liptinite are 77.93%, 7.33%, and 2.73%, with ranges of 65.6% to 86.2%, 1.8% to 13.6%, and 1.0% to 6.2%, respectively. The organic matter type of the Chengzihe Formation coal is classified as humic based on photomicrographs, suggesting good gas generation potential (Fig. 3(b)). Furthermore, the coal samples’ air-dried moisture content (Mad), ash content on a dry basis (Ad), and volatile matter (Vdaf) have averages of 0.26%, 15.93%, and 34.10%, ranging from 0.11% to 0.52%, 8.12% to 27.39%, and 28.3% to 37.36%, respectively, indicating that the coal seams of the Chengzihe Formation are mainly composed of low- to medium-ash coal.
4.2 Basin modeling results
The original results of the basin modeling analysis of Well SD-01 for coal samples from the Chengzihe Formation indicate that the average vitrinite reflectance (%Ro) is 0.996%, with a range of 0.95% to 1.04%. This study simulated %Ro of the Chengzihe Formation coal seams using the “Easy%Ro” numerical model and the Type III kinetic equation by Burnham and Sweeney (1989), revealing that the %Ro of the Chengzihe Formation coal seams ranges from 0.95% to 0.98%, closely matching the measured values of the samples (Fig. 4(c)). Additionally, the current geothermal gradient was used to compute the formation temperatures at various burial depths in the research area. Together, the calculated results and the model simulation data demonstrate strong consistency (Fig. 4(d)).
Although basin modeling for Well SD-01 was conducted using the kinetic equations for both Type II and Type III kerogen, only the basin model for Type III kerogen was presented as the output result. The Type II and Type III kerogen basin models differ only slightly in terms of maturity and transformation ratio (the ratio of kerogen converted into hydrocarbons); however, since the source rocks in the study area are coal seams predominantly composed of higher plant remains, the Type III kerogen evolution model more accurately represents the hydrocarbon generation process in the study area.
According to the results of the PetroMod 1D basin simulation, the kerogen transformation ratio of the Chengzihe Formation coal seams in the study area is approximately 44% under Type III kerogen properties, with a total hydrocarbon generation of 1.55 Mtons for the corresponding strata (Figs. 4(a) and 4(b)). In contrast, the Muling Formation has a transformation ratio of only 8.2%, generating a mere total of 0.03 Mtons of hydrocarbons (Figs. 4(a) and 4(b)). Although the coal properties and kinetic equations for both formations are identical, the Chengzihe Formation coal seams exhibit greater thickness, deeper burial depth, and more favorable preservation conditions, thus forming this study’s primary focus.
4.3 Gas content characteristics of coal samples
The adsorption of methane in coal reservoirs is governed by solid–gas interactions between the coal matrix surface and methane molecules, classified as physical adsorption processes (
Majewska et al., 2010;
Cao et al., 2024). Existing studies also indicate that, in a relatively closed system, the coal matrix surface undergoes simultaneous adsorption and desorption processes, which, when equal, cause the number of molecules on the solid surface to remain constant, a state referred to as adsorption equilibrium. The temperature and pressure of the gas affect how much is absorbed at adsorption equilibrium. The following is an expression for this equilibrium process:
where Q, T, and P represent the amount of adsorbed gas (cm3/g), the gas temperature (°C), and the free gas phase’s equilibrium pressure (MPa), respectively.
Methane isothermal adsorption experiments were conducted on coal samples from drilling cores to further investigate the gas content characteristics of the Chengzihe Formation coal seams in the study area and to better understand the transformation processes between adsorption, desorption, and free gas states after coalbed methane generation (
Langmuir, 1918).
The adsorption characteristics of the coal seam samples from the Chengzihe Formation are largely comparable based on the isothermal adsorption results for different coal seam samples, notwithstanding minor variations (Table 3 and Fig. 5). Among the samples, SD-01-6 and SD-01-9 exhibit the highest and lowest adsorption gas quantities, at 11.62 m3/t and 8.59 m3/t, respectively. Overall, the adsorption capacity tends to increase with rising pressure, while the coal seams’ adsorption capacity first rises at the same pressure, falling thereafter as the burial depth increases.
5 Discussion
5.1 Tectonic–burial–thermal evolution coupling process
The stratigraphic burial history of a sedimentary basin is closely tied to its tectonic background, as tectonic activities not only significantly impact sedimentation and uplift but also directly determine the thermal evolution history of the basin. The tectonic evolution of the eastern margin of the Shuangyashan Basin reflects the complex coupling of multiple tectonic movements, stratigraphic burial, and thermal evolution processes. According to one-dimensional basin modeling results, the study area underwent two major tectonic events, namely the Yanshan and Himalayan movements (Fig. 6). The influence of these two tectonic events caused the subsidence and uplift processes of the basin to undergo significant changes, which in turn affected the burial depth, heat flow, and temperature variations in the coal seams.
In the Early to Late Cretaceous period, the Shuangyashan Basin underwent its first subsidence phase, during which the subsidence depth gradually increased, with coal seams buried to depths ranging from 2750 m to 3700 m and temperatures rising to 106°C (
Li et al., 2002;
Chen et al., 2005). The geothermal gradient decreased and the formation temperature began to stabilize during this phase. The basin experienced large-scale uplift and magmatic thermal events with the onset of tectonic uplift during the Late Yanshan period, resulting in a sharp increase in geothermal heat flow and a rapid rise in formation temperature, reaching the Early Paleocene peak (
Meng et al., 2014;
Guo, 2016;
Meng et al., 2022). The thermal evolution during this stage reflects a close interaction between tectonic movement and heat flow, with magmatic thermal events and tectonic uplift not only significantly raising formation temperatures but also promoting the thermal cracking and hydrocarbon generation of coal seam organic matter.
The Himalayan movement triggered the second tectonic uplift phase in the Shuangyashan Basin, during which the burial depth of the strata gradually decreased and the coal seam temperature dropped to around 47°C, its current temperature. The trend of heat flow changes shows that the basin’s heat flow decreased during the Himalayan period from 124 mW/m2 in the early stage to 74 mW/m2, with significant fluctuations in heat flow values during the Late Early Cretaceous and Early Paleocene periods. The evolution of tectonic movements and thermal events in the basin highlights the influence of the basin’s thermal evolution history on the maturity of coal seams and hydrocarbon generation. The coupling process of tectonic–burial–thermal evolution demonstrates a dynamic relationship between coal seam temperature and stratigraphic sedimentary evolution in the Shuangyashan Basin.
5.2 Organic matter maturity evolution and hydrocarbon generation response
The maturation evolution of coal seam organic matter is a key factor in the generation and accumulation of coal-derived gas, directly influencing the generation, enrichment, and migration of coal seam gas. We aim to precisely reveal the maturation evolution of coal seam organic matter and its relationship with hydrocarbon generation reactions by analyzing the organic matter maturity of coal seam samples from Well SD-01 and combining this with burial thermal evolution models.
This study used the EASY%Ro model to simulate the maturation of coal seams, revealing that the coal seams in the Chengzihe and Muling Formations reached the “hydrocarbon generation threshold” during the Late Early Cretaceous, at which point organic matter transitioned from the generation stage of light oil to that of gaseous hydrocarbons. Based on the thermal evolution history of the coal seams, after entering the Paleocene, tectonic movements during the Yanshan and Himalayan periods significantly influenced the coal seams, leading to a rapid increase in geothermal temperature and a significant rise in organic matter maturity, notably reaching maximum maturity during the Late Eocene (Ro = 0.99%). The organic matter in the coal seams underwent a transformation from liquid hydrocarbons to gaseous hydrocarbons during this process, with liquid hydrocarbons (mainly heavy oil) converting into gaseous hydrocarbons, accompanied by the generation of large amounts of methane gas (Fig. 7).
According to the coal-derived gas generation model, the hydrocarbon generation process of coal seams is divided into three main stages as follows: the organic matter in the coal seams produces small amounts of methane in the biogenic gas generation stage due to the action of microorganisms. Heavy oil begins to dominate the hydrocarbon generation process during the liquid hydrocarbon generation stage. As thermal evolution progresses, the coal seams enter the gaseous hydrocarbon generation stage, where methane generation significantly increases, and the adsorbed gas stored in the coal seams is gradually released (Fig. 7).
The maturity of coal seams is positively correlated with their hydrocarbon generation potential, meaning that, as maturity increases, the coal seam’s gas generation capability typically improves. However, under the influence of tectonic uplift, the coal seams gradually undergo erosion and exposure, causing the hydrocarbon generation process to cease and the generated gas to dissipate to the surface or adjacent reservoirs. This process indicates that the hydrocarbon generation history of coal seams is closely related to their thermal evolution and significantly influenced by tectonic activity and crustal uplift. The dynamic processes of coalbed methane generation, occurrence, and migration are quantitatively analyzed by investigating both the combinations of coal-bearing strata, coal seams, and the characteristics of the overlying and underlying strata and the “three histories” evolutionary features in the study area. The geological control mechanisms of its accumulation and the complete process of gas generation, occurrence, enrichment, and dissipation in the main coal seams of the study area are also examined. Figure 7(b) shows the “three histories” configuration relationship diagram for the eastern margin of the Shuangyashan Basin divided into three stages.
The coalfield in the mining area experienced the early Yanshan movement from the Early to Middle Late Cretaceous (initial hydrocarbon generation phase), with stable crustal subsidence leading to the formation of a stable coal-bearing stratigraphy, where coal seams and dark mudstones formed the foundation for coalbed methane. In the later stages of deposition, the coal seams reached their maximum burial depth and the “hydrocarbon generation threshold”, initiating the coalification and hydrocarbon generation processes. From the Middle Late Cretaceous to the Early Eocene (comprehensive coalification and hydrocarbon generation—reservoir formation stage), the coalfield in the mining area was influenced by both Yanshan and Himalayan tectonic movements. Intense magmatic activity led to the formation of a high paleo-geothermal field during the tectonic uplift phase, after which the crust underwent further subsidence and organic matter in the coal seams was reheated under the combined effects of burial thermal evolution and magmatic radiation, generating hydrocarbons, resulting in a large amount of gas accumulating in the upper and lower strata of the coal seams. The eastern margin of the Shuangyashan Basin has been influenced by Himalayan tectonic uplift since the Early Eocene (coalbed methane dissipation—stabilization stage), wherein the burial depth of the coal seams became shallower, the paleo-geothermal gradient approached normal, hydrocarbon generation ceased, and methane and other adsorbed gases in the coal seams desorbed, diffusing into the overlying strata or the atmosphere; the coalbed methane characteristics in the study area then gradually reached their current levels (Fig. 7).
5.3 Features of the coal seam that hold gas
Coalbed methane primarily consists of adsorbed gas and free gas, with the former being the dominant component, and its adsorption capacity is typically characterized by the Langmuir isotherm adsorption curve. The Langmuir volume and pressure for coal seam samples from the Chengzihe Formation were determined using the adsorption quantity calculation formula, and the findings show that the samples’ average VL and PL are 12.82 m3/t and 2.23 MPa, with ranges of 10.92–14.61 m3/t and 1.96 MPa and 2.60 MPa, respectively. While PL often displays a progressive increase with increasing burial depth, VL shows a trend of initially growing and then dropping (Table 4). The gas saturation of the coal seam samples was then determined using the on-site desorbed gas content data of Chengzihe Formation coal seam samples and the calculated VL and PL values (Table 4). The basic formula for calculating gas saturation is as follows:
where, Sg, V, and Pr represent the gas saturation of the coal seam, the measured gas content from on-site desorption (m3/t), and the measured reservoir pressure (MPa), respectively.
The calculation results (Table 4) indicate that the gas saturation of the Chengzihe Formation coal seams in Well SD-01 ranges from 47.59% to 122.61% (average 72.67%) and increases with burial depth, exceeding 80% when the burial depth exceeds 1,240 m. This suggests that the strata in Well SD-01 have favorable preservation conditions and that the coalbed methane is well-preserved.
While variables such as the coal seam’s degree of thermal evolution, burial depth, coal quality attributes, and organic matter content affect the gas content of coalbed methane in underground coal seams, the diagram showing the relationship between the gas saturation of Chengzihe Formation coal seam samples and the controlling factors (Fig. 8) indicates that gas content is primarily controlled by burial depth and thermal evolution degree, with a significant positive correlation (R2 > 0.75). In contrast, the gas content shows no significant correlation with coal quality parameters, such as volatile yield, ash yield, moisture, and TOC content (R2 < 0.30). It is inferred that as the thermal evolution degree increases, the pore structure of coal becomes more developed, enhancing its gas adsorption capacity, and gas generation within highly evolved coal seams increases, resulting in a positive correlation with gas content. The possibility of gas escape is decreased by the gradual improvement of gas generation and storage characteristics under deep burial settings, causing coal seam gas saturation to rise with increasing depth.
5.4 Tectonic thermal evolution’s dynamic mechanism
The Late Mesozoic and Cenozoic tectonic processes are principally responsible for the hydrocarbon formation and buildup in the Mesozoic coal-bearing strata of the Shuangyashan Basin (
Xu et al., 2013;
Han, 2021;
Dong et al., 2023). Previous studies also suggest that the tectonic evolution during the Late Mesozoic significantly influenced the formation, preservation, and thermal evolution of coal seams while also providing the essential prerequisites and foundations for the formation, enrichment, migration, distribution, and accumulation of coal-derived gas in the Shuangyashan Basin.
The Chengzihe and Muling Formations’ most significant coal seam source rock systems were formed during the study area’s steady subsidence phase, brought on by extensional faulting that affected the Shuangyashan Basin during the late Early Cretaceous deposition stage (Fig. 9(a3)). The stable basin environment during this period provided favorable preservation conditions for coal seam source rocks, laying the geological foundation for Mesozoic coalbed methane fields. Under the influence of the Yanshanian orogeny and the subduction-collision between the Pacific Plate and the Jiamusi Block during this deposition stage, the study area accumulated thick fluvial–deltaic sediments of the Early Cretaceous, as a result of which the coal-bearing strata’s burial depth and temperature quickly increased (Fig. 9(a2)). The source rocks surpassed the “hydrocarbon generation threshold” with low coalbed methane generation, primarily in an adsorbed state (Fig. 9(a1)).
The subduction of the Pacific Plate intensified during the Late Cretaceous deposition stage, resulting in a significant upwelling of mantle-derived material, frequent magmatic activity, and large-scale tectonic destruction of the Jiamusi Block (Fig. 9(b2)). The formation of andesitic intrusions during this stage serves as the most direct geological marker in the eastern margin of the Shuangyashan Basin (Fig. 9(b3)). Magmatic intrusion caused geothermal anomalies in the study area, as large amounts of heat from deep thermal materials directly heated the Chengzihe Formation coal-bearing source rocks, resulting in coal seams quickly maturing, thus providing a wealth of coalbed methane resources as organic matter entered the peak gas generation stage. Potential gas reservoirs were developed under the composite sealing system formed by sandstone, mudstone, and andesite (Fig. 9(b1)). Additionally, methane isothermal adsorption measurements show that the Langmuir pressure constant is less than 2.5 MPa and that the Chengzihe Formation coal seams currently have a methane adsorption capacity of over 10 m3/t. These findings suggest that the study area has abundant coalbed methane reserves and the coal seams exhibit low desorption pressure, offering excellent resource extraction potential and promising prospects for exploitation.
6 Conclusions
Geochemical experiments and methane isothermal adsorption tests were conducted on the coal source rocks from the eastern margin of the Shuangyashan Basin to investigate the origin, hydrocarbon generation evolution, and accumulation mechanisms of coal-derived gas in this region. The main findings are summarized as follows.
1) The Cretaceous Chengzihe Formation coal exhibits a high TOC content (72.61 wt% to 91.88 wt%), primarily composed of Type III kerogen. The coal samples have maturity levels (Ro) ranging from 0.95% to 1.04%, indicating that the organic matter has entered the mature stage. Organic petrology research demonstrates that the Chengzihe Formation coal possesses excellent hydrocarbon generation potential.
2) Burial and thermal models indicate that the study are underwent two tectonic evolution events, with two main subsidence phases occurring from the Early Cretaceous to the early Late Cretaceous (145–89 Ma) and from the Paleogene to the end of the Eocene (64.5–35.8 Ma). The study area experienced a rapid increase in heat flow during the late Yanshanian period due to large-scale uplift accompanied by magmatic thermal events, reaching a second peak of 91.5 mW/m2. Since the Eocene, the heat flow has gradually decreased due to rapid uplift and cooling events, now reading at approximately 74 mW/m2.
3) Around 122 million years ago, in the mid-Cretaceous, the source rocks began to generate biogenic gas, and approximately 111 million years ago, the organic matter found in coal seams had crossed the “hydrocarbon generation threshold”. By the mid-Late Cretaceous (around 89.8 Ma), the coal seams had reached a moderate maturity stage. Subsequently, under the influence of high heat flow values, the coal seams attained maximum maturity in the late Eocene, with the coal seam source rocks entering the relative dry gas generation stage.
4) With Langmuir pressure constants less than 2.5 MPa, the Chengzihe Formation coal seams currently have a methane adsorption capability of over 10 m3/t. The degree of thermal development and burial depth have the greatest impact on the gas content in coal seams. The findings of methane isothermal adsorption studies clearly show that there is a great deal of potential for resource extraction and excellent exploitation opportunities in the studied area.
5) Both the coal’s degree of thermal development and the process of hydrocarbon formation were significantly influenced by regional tectonic activity. The rapid subsidence during the Early Cretaceous allowed the coal to surpass the “hydrocarbon generation threshold” and reach a moderate maturity stage. Magmatic activity in the Late Cretaceous caused the maturity of coal organic matter to rapidly increase, approaching the “gas generation threshold.” The Pacific Plate’s long-term westward subduction has the greatest impact on the tectonic development of the Shuangyashan Basin.
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