Enrichment Geological Conditions and Resource Evaluation Methods for the Gas in Thinly Interbedded Coal Measures: A Case Study of the Chengzihe Formation in the Jixi Basin

Abstract

The Cretaceous Chengzihe Formation in the Jixi Basin hosts abundant coal measure gas resources. Analyzing the geological conditions for gas enrichment and evaluating its resource potential are essential for advancing unconventional gas exploration. However, studies on the geological conditions controlling the enrichment of thinly interbedded coal measure reservoirs in the Chengzihe Formation and corresponding assessment methods remain lacking. Based on the analysis of source–reservoir–seal characteristics of the thinly interbedded coal measure gas system in the Jixi Basin, integrated with resource assessment and reservoir formation controls, this study systematically reveals the enrichment patterns and accumulation mechanisms. The results show that the accumulation of thinly interbedded coal measure gas depends on three key geological factors: the gas-generating capacity of high-quality source rocks, the widespread distribution and stacking of thinly interbedded reservoirs, and the sealing capacity of cap rocks. In addition, enrichment is influenced by multiple factors, including tectonic evolution history, magmatic intrusion, sedimentary microfacies, and hydrogeological processes. Among these, the development of sedimentary microfacies (interdistributary bay and peat swamp) plays a decisive role in controlling the spatial distribution and physical properties of the reservoirs, while other factors further shape gas enrichment through synergistic interactions. Finally, using the volumetric method, the estimated gas resources of thinly interbedded coal measure gas in the Chengzihe Formation are 1226.73 × 10⁸ m³, with the upper member showing significant potential of 688.98 × 10⁸ m³.

1. Introduction

In recent years, with the continuous advancement of unconventional natural gas exploration and development, research on coal measure gas has gradually shown the following trends: first, extending from shallow coalbed methane (CBM) to deep CBM to explore the development potential of deep resources; second, expanding from single coal seam to the entire coal measure strata, emphasizing the coexistence and synergistic accumulation of multiple reservoirs within the coal measures [1,2,3]. Coal measure gas generally refers to all types of natural gas contained within coal measure strata, primarily including CBM, shale gas, and tight sandstone gas [4,5,6,7,8,9]. Systematic investigation of the accumulation conditions, reservoir properties, and controlling factors of different types of coal measure gas, along with an in-depth understanding of their integrated accumulation models, is crucial for advancing the efficient exploration of coal measure gas resources.

The coal measure strata in China are widely distributed and exhibit significant stratigraphic thickness, hosting abundant coal measure gas resources with substantial exploration and development potential [10,11,12,13,14,15]. According to preliminary estimates, the potential gas resources of coal measure gas in China range from 136 × 10¹² m³ to 178 × 10¹² m³, of which approximately 82 × 10¹² m³ are located within 2000 m depth [16].

The current evaluation of coal measure gas resources predominantly employs the multi-source superposition method, which assesses individual reservoirs (CBM, sandstone gas, and shale gas) based on their independent attributes and estimates total resource volumes through arithmetic summation. While this method demonstrates computational efficiency under idealized conditions of homogeneous stratigraphic structures and continuous reservoir stability, its theoretical limitations become increasingly pronounced in complex sedimentary systems characterized by coal–mudstone–sandstone lithologic interbeds. A critical limitation lies in the systematic exclusion of thinly interbedded reservoirs that fall below the threshold thickness defined by national standards. This oversight inevitably results in evaluations that fail to fully capture the true potential of coal measure gas resources [17,18]. Compared with the traditional notion that thicker reservoirs yield greater gas production potential, the recognition that thinly interbedded coal measures possess higher gas production potential represents a significant paradigm shift [16]. Given this new understanding, it is imperative to transition from the traditional “mineral classification” approach to an integrated system-based methodology for coal measure gas resources and establish a resource assessment framework tailored to the geological characteristics of thinly interbedded measure gas.

The Jixi Basin is an important area for the exploration and development of coal measure gas resources in China. The Lower Cretaceous Chengzihe Formation is characterized by a multi-thinly interbedded coal measure system, where the coal-bearing sedimentary measure is composed of frequent interbedded thin coal seams, mudstones, and sandstones, exhibiting complex interlayer relationships and thin individual layers. The China Geological Survey (CGS) has implemented two geological survey wells and three parameter wells in the Jixi Basin and made a major breakthrough in coal measure gas exploration. Among them, the HJD1 well has demonstrated a high-yield gas flow, with a peak daily production of 5666 m³, indicating favorable accumulation conditions for multi-thinly interbedded coal measure gas reservoirs in the basin. The estimated coal measure gas resources in the Lower Cretaceous Chengzihe Formation at depths of 400–2000 m is 2048 × 10⁸ m³ [19]. Nevertheless, current research and exploration in the Jixi Basin primarily focus on the assessment of coal measure gas resources in single reservoirs, while there is still a lack of systematic analysis of the resource potential and accumulation mechanisms of thinly interbedded coal measure gas. To address this gap, this study systematically investigates the geological background, resource distribution characteristics, and main controlling factors of thinly interbedded coal measure gas accumulation in the Chengzihe Formation, aiming to clarify the geological conditions and mechanisms controlling its development. Finally, a method for evaluating multi-thinly interbedded coal measure gas was established, and the resource quantity was estimated.

2. Geological Setting

The Jixi Basin is situated in the southeastern portion of northeastern China, along the southeastern margin of the Jiamusi Block (Figure 1A), adjacent to the Sanjiang Basin. The basin spans 55–70 km in width from east to west and 100 km in length from south to north, covering a total area of 3780 km² [20]. The NNE-trending Hengshan uplift in the central part of the basin and the EW-trending Pingyang–Mashan thrust fault zone (Pingma fault) divide the basin into two tectonic belts. The northern tectonic belt is oriented in an EW direction, while the southern tectonic belt is oriented in a NE-NNE direction, resulting in a structural framework of two depressions and one uplift as a whole (Figure 1B) [21]. The Jixi Basin underwent multistage tectonic overprinting and modification during the Yanshanian–Himalayan orogenic cycles. During the mid-Yanshanian stage, N–S-oriented compressional stress induced significant deformation within the lower part of the late Mesozoic succession, resulting in a dual-depression structural framework with the central Hengshan Uplift flanked by northern and southern depocenters [22]. By the late Yanshanian, NWW–SEE-directed regional compression reactivated pre-existing fault systems and triggered syn-tectonic volcanism, which further fragmented and overprinted the earlier fold-thrust architecture. In the early Cretaceous, deposition of the Didao Formation was primarily controlled by the Dunmi Fault zone [23]. This was followed by the accumulation of the marine–continental transitional Dongrong Formation during a transgressive phase. Subsequent regional regression facilitated the development of coal-bearing successions characterized by peat-accumulation facies associations.

The main coal-bearing strata in the basin include the Lower Cretaceous Chengzihe Formation, Muling Formation, and Didao Formation. Among them, although the Muling and Didao Formations contain certain coal-bearing strata, the development of thinly interbedded coal measure strata is relatively limited [24]. In contrast, the Chengzihe Formation has a large thickness and frequent development of thinly interbedded coal measures, making it the primary target interval of this study. The Chengzihe Formation has a thickness ranging from 600 m to 1400 m and is deposited during the rift period of the basin. It is composed of a suite of sandstone and mudstone sediments formed by the interbedding of fluvial, deltaic, and lacustrine facies. The lower part of the Chengzihe Formation was influenced by the Early Cretaceous marine transgression, resulting in the development of multiple layers of marine mudstone interbeds locally [25].

The lithology of the Chengzihe Formation is predominantly composed of gray to grayish-white siltstone and fine-grained sandstone, locally interbedded with medium-to coarse-grained sandstone, mudstone, thin tuff layers, and coal seams. Based on lithological and sedimentary characteristics, the Chengzihe Formation can be further subdivided into upper, middle, and lower members. The lower member is composed of alternating black mudstone, siltstone, and grayish-white medium-to fine-grained sandstone in the marine-terrestrial transitional facies, with locally developed coal seams. In contrast, the middle and upper members are dominated by continental coal-bearing sediments, comprising grayish-white conglomerate, medium-to coarse-grained sandstone, gray fine-grained sandstone, grayish-black siltstone, mudstone, carbonaceous mudstone, and coal seams. The coal seams, carbonaceous mudstones, and tight sandstones of the Chengzihe Formation are interbedded in a source-reservoir configuration, forming an effective source-reservoir coupling system, providing a critical material foundation for the generation and accumulation of coal measure gas.

Figure 1. (A) Simplified tectonic map of Northeast Asia, showing the location of the Jixi Basin (modified from [26]); (B) Tectonic outline of the Jixi Basin.

Figure 1. (A) Simplified tectonic map of Northeast Asia, showing the location of the Jixi Basin (modified from [26]); (B) Tectonic outline of the Jixi Basin.

3. Methodology

3.1. Resource Evaluation Method

This study employs the volumetric method to holistically assess coal measure gas resources in thin interbeds (Equation (1)). In traditional coal measure gas evaluation systems, CBM and shale gas predominantly stored in adsorbed states are typically evaluated using the volumetric method. In contrast, coal measure sandstone gas, dominated by free-state gas, is conventionally quantified via the volumetric method. Building on the trinity collaborative occurrence mechanism (coal–sandstone–mudstone interbedded structure) inherent to thinly interbedded coal measures, this study advances beyond traditional phase-separated evaluation approaches by innovatively integrating both adsorbed and free-state gases into a unified volumetric framework for resource estimation. The proposed methodology systematically quantifies key parameters including gas-bearing area, net thickness, air-dry basis gas content and apparent density to accurately characterize the spatial distribution of coal measure gas resources. The evaluation process rigorously incorporates relevant industry standards, including those for shale gas, coalbed methane, and tight sandstone gas [27,28,29].

$$G=0.01AhDCad$$

(1)

where $G$ represents the volume of natural gas resources, 10⁸ m³; $A$ represents the gas-bearing area, km²; $h$ represents the average effective thickness, m; $Cad$ represents the air-dry gas content, m³/t; $D$ represents the air-dry apparent density, t/m³.

3.2. Parameter Acquisition

3.2.1. Gas-Bearing Area

The gas-bearing area is a core parameter for calculating coal measure gas resources, and the accuracy of its spatial distribution has a decisive impact on resource scale estimation. To improve the calculation accuracy of the gas-bearing area, this study employs a comprehensive approach integrating multi-source data fusion and geological constraint methods. Based on the gas content contour map of thinly interbedded coal measures, Surfer software (version 21, Golden Software, LLC, Golden, CO, USA) was utilized to vectorize the contours, and the Kriging interpolation algorithm was applied to generate a continuous gas content field. The effective gas content boundary was delineated using color-coded intervals. By integrating thinly interbed thickness distribution, basin structural framework, and exploration targets, the gas-bearing extent was optimized through sedimentary facies-controlled exclusion of non-reservoir zones (shore-shallow lake facies and alluvial facies) and structurally complex zones, thereby ensuring the spatial characterization accuracy of gas-bearing area in thin interbeds.

3.2.2. Gas Content

The calculation of gas content in thinly interbedded coal measure gas reservoirs should be based on differentiated models constructed according to the gas occurrence mechanisms of different lithological reservoirs (

Table 1. Summary of Gas Content Data for the Jixi Basin.

Lithology	Gas Content Data Wells	Prediction Method
Coal	JMC1, JMC2, HJD1, HJD2, LS02-1V, LS02-2D, DD-05, ZK-29, ZK-30, ZK-50, PG17-1, ZK12-73, ZK12-82, ZK12-87, ZK12-93	Multi-linear Regression Method
Mudstone	HJD2, JMC1	Formula method
Sandstone	HJD2, JMC1, JMC2	Formula method

). The CBM content is estimated using a multiple linear regression model implemented in SPSS software (version 26, IBM Corp, Armonk, NY, USA), with an absolute correlation coefficient requirement of ∣R∣ > 0.85 to ensure the reliability of the model (

Table 2. Multivariate linear regression model and correlation of CBM wells in Jixi Basin.

Well Number	Logging Parameters	Multiple Linear Regression Model	R
JMC1	GR, SP, CAL, RLLS, R	$\begin{array}{l}{Q}_{coal}=-0.202GR-0.046CAL-0.064R-\\ 0.142SP+0.007RLLS+48.878\end{array}$	0.87
JMC2	DEN, AC, CNL, RLLS, QT, RLLD	$\begin{array}{l}{Q}_{coal}=-3.011DEN+0.008AC+0.352CNL+\\ 0.052 RLLS+0.061QT-0.053RLLD-4.232\end{array}$	0.94
HJD1	ρb, AC1, AC2, RLLD, SP	$\begin{array}{l}{Q}_{coal}=-6.025{\rho }_b+0.008A{C}_1-0.038A{C}_2+\\ 0.021 RLLD+0.044SP-117.841\end{array}$	0.86
HJD2	ρb, AC, RLLS, RLLD, SP, CAL	$\begin{array}{l}{Q}_{coal}=3.776{\rho }_b+0.241AC-0.986RLLS+\\ 0.872 RLLD+0.469SP-1.694CAL-24.205\end{array}$	0.89
LS02-1V	GR, DEN, CNL	$\begin{array}{l}{Q}_{coal}=-0.461GR+73.752DEN-2.751CNL+\\ 16.533\end{array}$	0.95
LS02-2D	GR	$Q_{coal}=0.033GR+3.603$	0.895
PG17-1	CAL, GR	$Q_{coal}=0.016CAL+0.005GR-19.676$	0.864
ZK12-82	GR, SP, R	$Q_{coal}=0.002GR+0.094SP+0.002R-279.834$	0.863
ZK12-87	R, CAL	$Q_{coal}=-0.006R+0.009CAL-3.156$	0.853
ZK12-93	GR, SP, CAL, R	$\begin{array}{l}{Q}_{coal}=0.001GR+0.082SP+0.001CAL+\\ 6.744E-5R-250.814\end{array}$	0.859

). Taking the well JMC1 as an example, a multiple linear regression analysis was conducted based on the available logging parameters, including Gamma Ray Log (GR), Caliper Log (CAL), Resistivity Log (R), Spontaneous Potential Log (SP), and Shallow Laterolog Resistivity Log (RLLS), to identify the optimal model. The resulting predictive model is provided in Table 2.

The calculation of shale gas content requires a comprehensive assessment of both the adsorbed gas component and the free gas component. To estimate the adsorbed gas content, Total Organic Carbon (TOC) must first be predicted using well log data. Pearson’s correlation analysis was performed in SPSS between measured TOC values and well log parameters for each individual well, using ∣R∣ > 0.85 as the threshold for variable selection. Based on the selected logging parameters, multiple linear regression models were developed to predict TOC for specific wells (

Table 3. Multiple linear regression model and correlation of TOC in mudstone of Jixi Basin.

Well Number	Multiple Linear Regression Model	R
J2	$TOC=0.016LLD+2.327$	0.992
J6	$\begin{array}{l}TOC=-0.054GR-30.958DEN+0.368RLLD-0.344RLLS-\\ 4.161CAL-0.177AC+140.180\end{array}$	0.86
JC1	$\begin{array}{l}TOC=0.006GR+0.303SP-0.021DT-0.086LLS+5.043\hfill \end{array}$	0.986
JD2	$\begin{array}{l}TOC=-0.02GR+0.455SP+0.145RD-0.333RS+0.028AC\\ -35.91\end{array}$	0.87
JD6	$\begin{array}{l}TOC=-0.031GR-0.064SP-0.134CAL-0.048LLD+\\ 0.038LLS+23.768\end{array}$	0.852
JD7	$TOC=-3.643DEN+10.003$	0.907
JD8	$TOC=0.016LLD+0.002GR-0.002GR+2.327$	0.892
JMC1	$TOC=0.015LLD+0.005DEN-0.005DEN+2.387$	0.86
JMC2	$\begin{array}{l}TOC=0.016LLD-1.214\hfill \end{array}$	0.992
HJD2	$TOC=0.01GR+0.65DEN-1.68$	0.91

). Subsequently, a regression model was established to estimate adsorbed gas content from TOC, based on their linear relationship (Equation (2)).

$$Q_{ads}=k\cdot TOC+b$$

(2)

where k and b represent the regression coefficients; TOC represents the total organic carbon content, %.

Due to the scarcity of measured shale gas content data in the study area, only datasets from two wells (JMC1 and HJD2) were available. Based on their adsorbed gas measurements and TOC content, a TOC adsorbed gas regression model was established to quantify gas storage potential (

Table 4. Multivariate linear regression model for adsorbed gas in JMC1 and HJD2 wells.

Well Number	Multiple Linear Regression Model	R
JMC1, HJD2	$Qads=0.4853TOC-0.0878$	0.875

).

The calculation of free gas is based on the gas saturation conversion method (Equation (8)), the specific calculation steps are as follows:

First, the mud content of the formation is calculated using the natural gamma curve, and the formula is as follows (Equations (3) and (4)):

$$V_{sh}={\displaystyle \frac{2^{GCUR\times SH}-1}{2^{GCUR }-1}}$$

(3)

$$\mathrm{SH}={\displaystyle \frac{GR-G{R}_{min}}{G{R}_{max}-G{R}_{min}}}$$

(4)

where $GCUR$ represents the formation constant; $G{R}_{min}$ represents the logging value of pure sandstone, API; $G{R}_{max}$ represents the logging value of pure mudstone, API.

Second, the formula for calculating porosity using acoustic time difference curve is as follows (Equation (5)):

$${\varphi }_t={\displaystyle \frac{\Delta t-\Delta t_{ma}}{\Delta t_f-\Delta t_{ma}}}-V_{sh}{\displaystyle \frac{\Delta t_{sh}-\Delta t_{ma}}{\Delta t_f-\Delta t_{ma}}}$$

(5)

where ${\varphi }_t$ represents acoustic porosity; $\Delta t_{ma}$ represents matrix acoustic transit time, μs/m; $\Delta t_f$ represents fluid acoustic transit time, μs/m; $V_{sh}$ represents shale volume fraction; $\Delta t$ represents acoustic transit time log reading, μs/m; $\Delta t_{sh}$ represents shale acoustic transit time, μs/m.

Third, the original water saturation was calculated using Archie’s equation, expressed as (Equation (6)):

$$S_w=\sqrt[n]{{\displaystyle \frac{a\cdot R_w}{{\varphi }^m\cdot R_t}}}\left(S_g=1-S_w\right)$$

(6)

where $R_w$ represents the formation water resistivity, Ω m; $R_t$ represents the true formation resistivity, Ω m.

Then, the calculation formula for the volume coefficient of natural gas is as follows (Equation (7)):

$$B_g={\displaystyle \frac{V_2}{V_1}}={\displaystyle \frac{P_1\times T_2}{P_2\times T_1}}$$

(7)

where $P_1$ represents pressure under surface conditions, MPa; $T_1$ represents the thermodynamic temperature under surface conditions, K; $P_2$ represents pressure at the mid-depth of the subsurface reservoir, MPa; $T_2$ represents thermodynamic temperature at the mid-depth of the subsurface reservoir, K.

The final formula for calculating the free gas content of mudstone is as follows (Equation (8)):

$$Q_{free}={\displaystyle \frac{{\varphi }_t\cdot S_g}{B_g\cdot DEN}}$$

(8)

where ${\varphi }_t$ represents porosity, %; $S_g$ represents gas saturation, %; $B_g$ represents the gas volume factor; DEN represents the density of mudstone, t/m³.

Since sandstone also primarily contains free gas, the free gas content was calculated using (Equations (3)–(8)), as was performed for mudstone.

Finally, for a thinly interbedded system composed of coal seams (c), mudstone layers (m), and sandstone layers (s), the average gas content ($C_{avg}$) is calculated using the thickness-weighted method (Equation (9)).

$$C_{avg}={\displaystyle \frac{{{\displaystyle \sum }}_i\left(H_{c,i}\cdot C_{c,i}\right)+{{\displaystyle \sum }}_i\left(H_{m,i}\cdot G_{m,i}\right)+{{\displaystyle \sum }}_i\left(H_{s,i}\cdot G_{s,i}\right)}{{{\displaystyle \sum }}_i{H}_{c,i}+{{\displaystyle \sum }}_i{H}_{m,i}+{{\displaystyle \sum }}_i{H}_{s,i}}}$$

(9)

where $C_{avg}$ represents the thickness-weighted gas content of the thinly interbedded system, m³/t; $H_{c,i}$ represents the thickness of the i-th coal seam layer, m; $C_{c,i}$ represents the gas content of the i-th coal seam layer, m³/t; $H_{m,i}$ represents the thickness of the i-th mudstone layer; $C_{m,i}$ represents the gas content of the i-th mudstone layer, m³/t; $H_{s,i}$ represents the thickness of the i-th sandstone layer, m; and $C_{s,i}$ represents the gas content of the i-th sandstone layer, m³/t.

3.2.3. Density

The lithological combination of thinly interbedded gas reservoirs is complex and diverse, typically characterized by alternating layers of coal seams, shale, sandstone, and other lithologies, with their density distribution exhibiting significant heterogeneity. Due to the substantial differences in physical properties among different lithologies, traditional single-lithology density calculation methods struggle to accurately characterize the overall density characteristics of reservoirs, thereby compromising the accuracy of resource estimation. To enhance the precision of density calculation in thinly interbedded reservoirs, this study extracts density parameters for each lithology based on density logging (DEN) data and determines the thickness of each lithology by integrating logging interpretation and core description data. The weighted average density calculation method is employed to systematically quantify the overall density of the reservoir, thereby comprehensively reflecting the heterogeneous characteristics of the reservoir and the influence of its multi-layer structure on reservoir performance.

The fundamental formula is as follows (Equation (10)):

$${\overline{D}}_r={\displaystyle \frac{{{\displaystyle \sum }}_{i=1}^n{D}_i{h}_i}{{{\displaystyle \sum }}_{i=1}^n{h}_i}}$$

(10)

where ${\overline{D}}_r$ represents the weighted density of the thinly interbedded reservoir, t/m³; $D_i$ represents the density of the i-th layer of rock (coal/mud/sand), t/m³; and $h_i$ represents the thickness of the i-th layer of rock (coal/mud/sand), m.

To reflect the representative density characteristics of thinly interbedded reservoirs while maintaining practical feasibility, this study selected several typical wells with complete and reliable logging and core data to calculate the average density values (

Table 5. Average density parameters of thinly interbedded coal measure gas reservoirs in typical wells of the Jixi Basin (Note: K1ch¹–K1ch³ represent the lower, middle, and upper members of the Lower Cretaceous Chengzihe Formation, respectively, arranged from bottom to top).

Well Number	Layer ID	Member	Thickness (m)	Average Density (g/cm3)
HDJ1	Z1	K1ch3	15.61	2.21
	Z2	K1ch2	18.32	2.26
	Z3	K1ch2	12.13	2.48
	Z4	K1ch2	13.51	2.32
	Z5	K1ch2	17.65	2.42
	Z6	K1ch1	12.68	2.51
	Z7	K1ch1	14.37	2.34
HJD2	Z1	K1ch3	14.59	2.36
	Z2	K1ch3	26.21	2.32
	Z3	K1ch3	17.32	2.45
	Z4	K1ch2	11.91	2.41
	Z5	K1ch1	13.63	2.39
	Z6	K1ch1	10.74	2.35
	Z7	K1ch1	15.45	2.38
	Z8	K1ch1	21.82	2.14
JMC1	Z1	K1ch3	16.13	2.26
	Z2	K1ch2	23.51	2.48
	Z3	K1ch2	12.46	2.32
	Z4	K1ch2	11.17	2.42
	Z5	K1ch2	13.81	2.36
	Z6	K1ch2	14.64	2.33

).

3.2.4. Thickness

In the evaluation of coal measure gas resources, reservoir thickness is one of the critical parameters determining the scale and enrichment characteristics of gas reservoirs. This study develops a three-level progressive quantitative evaluation system to improve the accuracy of identifying reservoir thickness in thin interbedded layers. The first level involves screening coal seam target layers with thicknesses between 0.3 m and 0.5 m based on drilling lithology data and density–natural gamma logging curves (DEN, GR). The boundaries are defined by the top and bottom depths of single reservoirs that meet the thickness threshold, providing an initial delineation of the spatial distribution of thinly interbedded layers. The second level requires that the cumulative thickness of thin interbeds be ≥10 m. The continuity of the reservoirs is verified through comprehensive analysis of lithology data and thickness distribution, while excluding interference from heterogeneous interlayers. The third level applies constraints using the total gas curve (Total Gas) and gas-bearing criteria. The peak-to-base ratio of gas measurements must be ≥5 (dimensionless), or individual layers must independently meet the minimum threshold through gas content testing, well log interpretation, and gas logging parameters.

4. Results and Discussion

4.1. Geological Conditions for the Development of Thinly Interbedded Coal Measure Gas Reservoirs

4.1.1. Geological Conditions of Thinly Interbedded Coal Measures

The sedimentary facies belt controls the scale and physical properties of coal-measure reservoirs through the lithology, lithofacies, and spatial combination of coal measures. The scale and distribution of high-quality reservoirs directly influence the enrichment and accumulation of coal measure gas [30]. The Chengzihe Formation is predominantly developed within a fluvial-delta-lacustrine sedimentary system (Figure 2). Its coal-bearing strata are characterized by frequent lithological changes, thin single-layer thickness, multiple layers, and large cumulative thickness, forming an integrated source-reservoir-caprock structure for coal measure gas reservoirs [31].

Among them, the thinly interbedded coal measures are predominantly developed in the delta front interdistributary bay microfacies, with localized development in the delta plain peat swamp microfacies. The interdistributary bay microfacies are developed between the distributary channels of the delta front. The sediments are predominantly composed of mudstone and silty mudstone, exhibiting typical low-energy sedimentary characteristics, and forming frequent interbeds of fine-grained sandstone, mudstone, and thin coal seams [32]. The peat swamp microfacies predominantly develops in the low-lying interdistributary areas of the delta plain. Influenced by continuous basin subsidence and intermittent siltation processes, the sediments are predominantly composed of mudstone, carbonaceous mudstone, and thin coal seams, with localized development of thin interbeds. The scale, physical properties, and spatial distribution of the coal measure reservoirs are jointly constrained by the sedimentary environment and interlayer structure, ultimately influencing the enrichment and accumulation patterns of coal measure gas. The interdistributary bay microfacies play a key role in the formation and distribution of thinly interbedded coal measure gas reservoirs and are the key to analyzing the enrichment law of coal measure gas. The low-permeability reservoir in this microfacies environment is controlled by the structural background, which makes it easier to form favorable enrichment conditions in the structural low-lying area and promote gas accumulation. Within the Chengzihe Formation, coal seams, mudstones, and sandstones are vertically stacked and interbedded, forming a multi-layered, composite source–reservoir system. The close spatial coupling and vertical offset between source rocks and reservoirs facilitate the efficient generation and accumulation of coal measure gas.

4.1.2. Symbiotic Combination Mode of Thinly Interbedded Coal Measure Gas

The enrichment characteristics of thinly interbedded coal measure gas in the Chengzihe Formation are controlled by the source-reservoir coupling relationship, exhibiting typical features of tightly coupled and vertically interbedded source and reservoir rocks. Based on the lithological combination characteristics of coal measure reservoirs in the study area and the analysis of typical borehole gas logging data, coal seams generally serve as the primary gas source rocks in the symbiotic model of thinly interbedded coal measure gas. Gas logging anomalies are predominantly concentrated within coal seams and their adjacent surrounding rocks. Based on the above characteristics, the enrichment patterns of thinly interbedded coal measure gas can be categorized into three typical types (

Table 6. Lithologic associations of thin interbeds and symbiotic association modes of coal measure gas in the Chengzihe Formation, Jixi Basin.

Lithologic Association
	S1	S2	M1	M2	T1	T2
Lithological Column Example
Well number	JMC2	HJD2	HJD1	JMC1	HJD2	HJD1
Coal Measure Gas Symbiosis Mode	CBM + tight gas		CBM+ shale gas		CBM + shale gas + tight gas
Mode	A		B		C
Sedimentary Microfacies	Interdistributary Bay + Peat Swamp

): the CBM + tight gas symbiosis mode with a single-source and dual-reservoir configuration (Mode A), the CBM + shale gas symbiosis mode with a dual-source and dual-reservoir configuration (Mode B), and the CBM + shale gas + tight gas symbiosis mode with a dual-source and multi-reservoir configuration (Mode C) [33].

Mode A primarily includes lithologic combinations of sandstone interbedded with thin layers of sandstone, mudstone, and coal (S1) and sandstone interbedded with single or multiple thin coal seams (S2). Gas-bearing displays are observed in coal seams and adjacent tight sandstones. In mode A, coal seams serve dual functions as both gas source rocks and reservoirs, with their internal micropores and fracture systems acting as the primary storage spaces for gas. The adjacent tight sandstones are hydraulically and spatially connected to the coal seams, where gas migration may occur through a combination of fracture systems, matrix diffusion, and stress-driven desorption mechanisms, thereby forming stable gas-bearing assemblages with improved reservoir capacity and seepage performance [34].

Mode B is predominantly developed in the symbiotic association of coal seams and adjacent organic-rich mudstones. The corresponding lithological types include mudstone interbedded with single or multiple thin coal layers (M1) and mudstone interbedded with multiple layers of sandstone, mudstone, and coal (M2). In mode B, coal seams and shale jointly serve as source rocks. CBM is primarily stored in the micropores and fracture systems of coal seams, while shale gas is dominantly enriched via adsorption within the nanopores of organic-rich mudstones. In mode B, shale not only provides a gas source but also functions as a reservoir. The strong sealing capacity of shale effectively inhibits gas escape, facilitating the long-term retention and enrichment of coal measure gas.

Mode C represents a complex symbiotic system of CBM, shale gas, and tight gas, characterized by intricate lithological assemblages typically manifested as the interbedding of coal seams, shale, and tight sandstone (T1, T2). In mode C, coal seams remain the primary source rocks, while shale plays a dual role as both an auxiliary gas source and a caprock. Tight sandstone constitutes the main reservoir, which is connected to the coal seams through fracture systems, providing pathways for gas occurrence and migration. The reservoir-forming mechanism of this mode is more complex, influenced by multiple factors such as tectonic stress, fracture distribution, and diagenesis, resulting in highly heterogeneous gas enrichment characteristics.

4.2. Gas Enrichment Characteristics and Control Factors of Thinly Interbedded Coal Measure

4.2.1. Gas Content and Thickness of Thin Interbeds

Based on the multi-source data fusion of well-logging parameters and mud-logging records [35,36], the spatial distribution pattern of thinly interbed thickness in the Chengzihe Formation was quantitatively characterized, and the vertical heterogeneity of gas-bearing properties was systematically analyzed. By integrating sedimentary facies-controlled boundary constraints (excluding shore-shallow lake facies and alluvial facies) with thickness-weighted calibration of thin interbeds, this study quantitatively elucidates for the first time the genetic coupling mechanism between thin interbed thickness and gas content under constrained geological conditions.

The thickness of the thinly interbedded measure in the upper member ranges from 5 m to 65 m (Figure 3), with an average thickness of 30.26 m, while the gas content ranges from 0.5 m³/t to 4.8 m³/t (Figure 4), with an average gas content of 2.32 m³/t. The high gas-content zones are primarily concentrated in localized areas of the Muling–Hezuo depression. The distribution characteristics indicate that tectonic subsidence processes in the depression enhance thick sedimentary deposition and promote gas accumulation under effective sealing conditions.

The thickness of the thinly interbedded measure in the middle member ranges from 5 m to 80 m (Figure 5), with an average thickness of 26.52 m, while the gas content ranges from 0.2 m³/t to 4.3 m³/t (Figure 6), with an average value of 2.1 m³/t. The high gas-content zones are concentrated in localized areas of the Muling–Hezuo Depression and the Didao Depression, decreasing towards the margins. This distribution pattern indicates that the gas content of the thinly interbedded measure in the middle member is locally controlled by sedimentary facies distribution. The sandy sedimentary facies belts in the central part of the basin are more developed, enhancing reservoir connectivity and gas migration capacity. Conversely, the gas enrichment capacity in the marginal zones is relatively weak due to changes in sediment grain size and the attenuation of pore-permeability properties. The thickness of the thinly interbedded measure in the lower member ranges from 5 m to 90 m (Figure 7), with an average thickness of 23.15 m, while the gas content ranges from 0.5 m³/t to 4.55 m³/t (Figure 8), with an average value of 1.86 m³/t. The high gas-content zones are still primarily located in localized areas of the Muling–Hezuo Depression, further indicating that sedimentary infilling in the deep depression plays a significant controlling role in the enrichment of coal measure gas.

4.2.2. Controlling Factors

The enrichment of thinly interbedded coal measure gas in the Chengzihe Formation is influenced by multiple factors, including tectonic evolution, sedimentation, hydrogeological processes, and magmatic activities. These factors collectively shape the storage characteristics of thinly interbedded coal measure gas by regulating the sealing capacity, permeability, and gas migration pathways of the reservoirs. Among above factors, the regional tectonic framework plays a dominant role in controlling the accumulation and distribution of coal measure gas.

The Jixi Basin inherits a structural framework characterized by two depressions flanking a central uplift. The northern and southern depressions serve as the primary accumulation zones for coal measure gas, with gas content ranging from 2.1 to 4.0 m³/t, owing to the strong sealing capacity of the synclinal structures (Figure 6 and Figure 8). In contrast, the central Hengshan Uplift has undergone significant denudation, leading to gas escape and poor preservation conditions, with gas content reduced from 0.5 to 1.2 m³/t [21]. The strata at the core of the syncline are complete, and the caprock is well-developed, providing effective conditions for gas accumulation. The gas content in the core of the syncline of the Chengzihe Formation coal seams in the Muling mining area is significantly higher than that in the axis of the anticline, further confirming the dominant role of synclinal structures in the gas accumulation process [37]. In addition, multi-stage fault activities not only enhance the permeability of the reservoirs but also create closed spaces in high-stress areas, influencing the enrichment and distribution of gas [21].

The depositional environment plays a pivotal role in the formation and sealing mechanisms of reservoirs. The coal reservoirs of the Chengzihe Formation are predominantly developed within a fluvial–delta–lacustrine depositional system, where the depositional thickness and lithological assemblages directly influence the storage and migration characteristics of coal measure gas. The thick coal seam areas in the syncline core typically exhibit high gas content, whereas the permeability is enhanced in areas with developed sandstone interbeds, facilitating gas migration and dissipation [38,39]. In addition, the extensive distribution of mudstone enhances the sealing capacity of the reservoir cap rock, thereby further improving the preservation conditions of coal measure gas.

The hydrogeological processes governing the preservation and enrichment dynamics of coal measure gas involve hydraulic confinement and migration mechanisms. In the Muleng–Hezuo area, thick mudstone and diatomite aquitard layers are developed, exhibiting extremely low permeability. These layers effectively block groundwater, thereby facilitating the enrichment of coal measure gas. The thinly interbedded coal measure gas in the Muleng–Hezuo area exhibits a relatively high average gas content [40] (Figure 6 and Figure 8), with values ranging from 2.0 to 3.2 m³/t across different well blocks. By contrast, in the northern depression, where significant formation uplift and denudation have occurred, groundwater migrates along fractures, resulting in the dissipation of coal measure gas and reducing its enrichment potential [41]. In the above area, the gas content is markedly lower, ranging from 0.2 to 1.0 m³/t. Furthermore, the hydraulic sealing effect of the syncline core effectively prevents the upward escape of gas, thereby further enhancing the accumulation conditions. The sealing performance of the deep aquifer, combined with the hydraulic barrier effect of the syncline core structure, plays a significant role in regulating the distribution and preservation of coal measure gas [42,43].

The thermal metamorphism induced by magmatic activity accelerated the thermal evolution of coal seams, while simultaneously enhancing or weakening the sealing properties of the reservoir and cap layers (Figure 9). Under the influence of multi-phase large-scale magmatic activities in the Heitai area of the northern basin, the thermal metamorphism of coal seams has been significantly enhanced, accompanied by a notable reduction in volatile matter content. Coal seams adjacent to magmatic intrusions have progressively evolved into anthracite or natural coke, thereby substantially diminishing their hydrocarbon generation capacity. Consequently, the gas content of coal measure gas within thinly interbedded coal measures exhibits an overall low value (Figure 4, Figure 6 and Figure 8), predominantly ranging from 0.2 m³/t to 1 m³/t. In contrast, areas distal to the magma body experienced moderate thermal evolution, resulting in localized gas enrichment [44,45,46]. Furthermore, magmatic thermal activity has been shown to enhance the densification of the cap layer and improve its sealing capacity, while simultaneously reducing the permeability of the coal seam. This process further influences the state of gas fugacity [47,48,49].

4.3. Resource Evaluation Results

Based on the above parameters, the gas resources of the thinly interbedded coal system in the Chengzihe Formation can be calculated. Based on the parameters listed in

Table 7. Statistics of Coal Measure Gas Resources in the Thinly Interbedded Chengzihe Formation.

Formation	Member	Gas-Bearing Area (km2)	Average Thickness (m)	Gas Content (m3/t)	Density (t/m3)	Resource Volume (108 m3)
Chengzihe Formation	Upper Member	618.52	29.26	1.62	2.35	688.98
	Middle Member	423.36	25.47	1.43	2.33	359.27
	Lower Member	301.75	22.12	1.21	2.21	178.48

, the total gas resource volume is calculated to be approximately 1226.73 × 10⁸ m³.

From the perspective of stratified members, the resource volume of the upper member is 688.98 × 10⁸ m³, accounting for the highest proportion; the middle and lower members are 359.27 × 10⁸ m³ and 178.48 m³, respectively. The upper member significantly contributes to the resources due to its larger gas-bearing area and higher effective thickness, while the middle and lower members have lower resource volumes but still exhibit good exploration potential in local areas.

5. Conclusions

This study integrates drilling data, geological exploration data and related geological characteristics, systematically analyzes the enrichment mode and accumulation mechanism of thinly interbedded coal measures gas and puts forward a method suitable for quantitative evaluation of thinly interbedded coal measures gas resources. The main conclusions are as follows.

The accumulation process of thinly interbedded coal measure gas in the Chengzihe Formation of the Jixi Basin relies on the efficient gas supply capacity of high-quality source rocks, the widely distributed thinly interbedded reservoir system, and the stable and efficient sealing of cap rocks. Various geological factors work together to lay the foundation for the accumulation of thinly interbedded coal measure gas, revealing the complexity of resource distribution and the differences between layers.

The enrichment characteristics of thinly interbedded coal measure gas are influenced by various geological factors, including sedimentary facies, tectonic evolution, hydrogeology, and magmatism. Among them, the sedimentary environment of interdistributary bay microfacies and peat swamp microfacies determines the spatial distribution and physical property differences in the reservoir, serving as the primary factor controlling the enrichment of coal measure gas. Tectonic activities play a crucial role in regulating gas migration pathways and accumulation areas. Magmatic activity and hydrogeological processes further enhance the accumulation of coal measure gas by improving the thermal evolution degree of source rocks and optimizing sealing conditions. According to the volume method, the total amount of coal measure gas resources in the thinly interbed of Chengzihe Formation is 1226.73 × 10⁸ m³, of which the upper, middle, and lower members have the gas resources of 688.98 × 10⁸ m³, 359.27 × 10⁸ m³, and 178.48 × 10⁸ m³, respectively. Overall, this study presents a methodological advancement in resource evaluation for thinly interbedded coal measure gas, addressing key limitations of conventional techniques when applied to heterogeneous, multi-layered systems. However, the current method has several limitations. Future studies should focus on integrating high-resolution 3D seismic data, stochastic geological modeling, and production history matching to improve prediction accuracy. Furthermore, validating this methodology in other coal-bearing basins will be essential for assessing its general applicability and enhancing its scientific and practical value.