Quantitative Classification of Shale Lithofacies and Gas Enrichment in Deep-Marine Shale of the Late Ordovician Wufeng Formation and Early Silurian Longyi₁ Submember, Sichuan Basin, China

Abstract

The classification of shale lithofacies, pore structure characteristics, and controlling factors of gas enrichment in deep-marine shale are critical for deep shale gas exploration and development. This study investigates the Late Ordovician Wufeng Formation (448–444 Ma) and Early Silurian Longyi₁ submember (444–440 Ma) in the western Chongqing area, southern Sichuan Basin, China. Using experimental data from deep-marine shale samples, including total organic carbon (TOC) content analysis, X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), low-pressure N₂ and CO₂ adsorption, gas content measurement, and three-quartile statistical analysis, a lithofacies classification scheme for deep-marine shale was established. The differences between various global marine shale formations were compared, and the main controlling factors of gas enrichment and advantageous lithofacies for deep shale were identified. The results show that six main lithofacies were identified: organic-rich siliceous shale (S¹), organic-rich mixed shale (M¹), medium-organic siliceous shale (S²), medium-organic mixed shale (M²), organic-lean siliceous shale (S³), and organic-lean mixed shale (M³). Deep-marine shale gas mainly occurs in micropores, and the development degree of micropores determines the gas content. Micropore development is jointly controlled by the TOC content, felsic mineral content, and clay mineral content. TOC content directly controls the development degree of micropores, whereas the felsic and clay mineral contents control the preservation and destruction of micropores during deep burial. The large-scale productivity of siliceous organisms during the Late Ordovician Wufeng period to the Early Silurian Longmaxi period had an important influence on the formation of S¹. By comparing the pore structure parameters and gas contents of different lithofacies, it is concluded that S¹ should be the first choice for deep-marine shale gas exploration, followed by S².

1. Introduction

With the continuous growth of global energy demand, shale gas has emerged as a significant alternative to conventional hydrocarbon resources and has become an important unconventional natural gas resource worldwide [1,2,3,4]. The advancement of shale gas geological theory, combined with the development of hydraulic fracturing and horizontal drilling technologies, has facilitated the large-scale commercial development of shale oil and gas at shallow to moderate depths (depths of 2000–3500 m) across multiple basins worldwide. Notable examples include the Barnett shale in the Fort Worth Basin of the United States [1], the Haynesville shale and Eagle Ford shale in the Western Gulf of Mexico Basin of the United States [5], the Longmaxi shale in the Sichuan Basin of China [6,7], and the Hot shale in the Jeffara Basin of North Africa [8]. However, to meet the energy demand, exploration of deeper oil and gas resources will inevitably be needed. In recent years, the Wufeng Formation–Longyi₁ submember in the Sichuan Basin has been the most promising strata for deep shale gas exploration and development in China [9,10,11]. According to estimates by PetroChina, the deep shale gas reservoirs (depths of 3500–4500 m) of the Wufeng Formation–Longmaxi Formation contribute 84% of the total resources in the southern Sichuan Basin, demonstrating great potential for shale gas exploration and development [12,13,14]. Due to complex geological conditions, the advantageous shale lithofacies and pore structure characteristics of deep-marine shale gas enrichment are still unclear, and only a few relevant studies have been performed. Therefore, a systematic study of the lithofacies classification scheme, lithofacies characteristics, pore structure parameters, and main factors controlling gas enrichment in deep-marine shale gas reservoirs is of great significance for shale gas exploration and development in similar geological environments worldwide.

Lithofacies analysis is regarded as essential for shale oil or shale gas exploration because it can reveal the special sedimentary environment and pore characteristics of shale reservoirs [15,16,17]. Recently, extensive research has been conducted globally on shale lithofacies classification. The focus of these studies has progressively transitioned from early emphasis on lithology, paleontological features, laminations development, and structural characteristics to the quantitative characterization of mineral content. Similarly, the classification criteria for shale lithofacies types have evolved from subjective, qualitative descriptions to systematic and quantitative classification standards [18,19]. Despite these advancements, because shale gas reservoirs are affected by tectonism, sedimentation, diagenesis, and other factors, leading to significant differences in lithofacies types, no uniform standards or methods have been developed [1,8,15,20]. Scholars have classified shale using various lithofacies classification methods. For example, Loucks and Ruppel [1] recognized three main lithofacies of the Barnett shale based on mineralogy, texture, and biological species. Mustafa et al. [17] classified Qusaiba shale into three different lithofacies based on organic matter abundance and sedimentary structure. However, previous studies on shale lithofacies have mostly focused on shale layers at shallow and moderate depths, and the classification criteria are subjective. Due to the variations in the sedimentary environment and deep burial process of deep-marine shales, there is no suitable shale lithofacies classification scheme for deep-marine shale reservoir evaluation, and the reservoir characteristics of each lithofacies are not clear. Therefore, based on extensive experimental data from deep-marine shale reservoirs, there is a need to further explore lithofacies classification schemes to guide shale gas exploration and development in these environments worldwide.

Comprehensively evaluating the pore characteristics of shale reservoirs can effectively reduce exploration risk [20,21,22]. Numerous studies on the pore characteristics of marine shale, including pore type, morphology, size, volume, specific surface area, and average pore diameter analyses, have been conducted worldwide [23,24,25]. For example, some scholars have divided shale pores into organic pores, inorganic pores, and microfractures [16,26,27]. Some researchers have demonstrated that organic pores are the most significant pore type in marine shale gas reservoirs, and during thermal evolution, overmature marine shale forms numerous organic pores which provide a considerable specific surface area and pore volume [5,14,23,26]. In addition, marine shale is highly heterogeneous, as various lithofacies demonstrate significant differences in pore characteristics [2,28]. Xu et al. [2] concluded that lithofacies type has a prominent influence on the specific surface area of shales. Slatt and O’Brien [26] reported the discovery of organic pores in the Barnett and Woodford shales, which can provide storage space for gas molecules. However, most of these studies focused on the pore characteristics of shales at shallow and moderate depths, and the pore characteristics of different lithofacies in deep-marine shales have not been well documented. Moreover, the main factors controlling the pore structure parameters and gas enrichment of deep-marine shale reservoirs still need to be clarified.

In this paper, Wufeng Formation–Longyi₁ submember deep-marine shale samples were collected from eight typical deep shale gas wells in the western Chongqing area, Sichuan Basin, China. Based on geochemical and mineral composition analysis, low-pressure N₂ and CO₂ adsorption, thin section and field emission scanning electron microscopy (FE-SEM), total gas content measurements, and other experimental procedures were used. We classified the lithofacies of deep shale reservoirs, compared the characteristics of different marine shale formations, and conducted correlation studies between the pore structure parameters and total gas contents of different lithofacies. The major objectives of this work were to (1) establish a deep-marine shale lithofacies classification scheme and classify lithofacies types, (2) compare the similarities and differences between deep-marine shale and global shale formations, (3) evaluate the pore structure and gas content characteristics of the different lithofacies, (4) summarize the main factors controlling gas enrichment, and (5) determine the advantageous lithofacies for deep-marine shale gas exploration. The findings of this study provide a quantitative lithofacies classification scheme for deep-marine shale gas exploration and enhance the understanding of lithofacies characteristics and gas enrichment mechanisms within deep-marine shale in similar geological environments worldwide.

2. Geological Setting

The Sichuan Basin, located in the northwest of Yangtze Platform, is a large-scale ancient superimposed sedimentary basin developed on the basement of Presinian metamorphic and magmatic rocks in south China [29] (Figure 1A). The western Chongqing area is located in a low and steep tectonic belt in the southern Sichuan Basin, south of the Central Sichuan gentle tectonic belt and west of the Eastern Sichuan high and steep tectonic belt (Figure 1B,C) [30]. The study area has experienced multiple episodes of tectonic movements, including the Caledonian movement, Hercynian movement, Indosinian movement, Yanshan movement, and Himalayan movement, resulting in the formation of a northeast–southwest structural feature and leading to the development of a complex faulted anticline [29,30].

The sedimentary period of the Wufeng Formation (O₃w) to the Longyi₁ submember (bottom of the Silurian Longmaxi Formation) in the western Chongqing area was dominated by an anoxic shallow to deep-water shelf depositional environment, depositing a set of organic-rich black shale [31] (Figure 2A). The sedimentation environment during this period was affected by a combination of global climatic changes, sea-level fluctuations, and regional tectonic activities [32]. During the early Wufeng Formation, sedimentation was influenced by the Qianzhong ancient land and the Leshan-Longnüsi paleouplift, which occurred during a regressive phase with shallow sedimentary water, resulting in the deposition of low TOC content silty clay shale. By the late Wufeng stage, global cooling and a drop in sea level led to the deposition of the Guanyinqiao section shell limestone, with a thickness of less than 0.5 m in the study area. In the early stage of the Longyi₁ submember, global warming, ice sheet melting, and a major marine transgression deepened the water column, resulting in the deposition of black siliceous shale at the bottom of the Longmaxi Formation. In the late Longyi₁ submember stage, sea levels fell, water depths shallowed, anoxic conditions weakened, and terrigenous input increased, resulting in the deposition of silty shale with lower organic content.

The Wufeng Formation–Longyi₁ submember in this area is characterized by its significant thickness (55–81 m) and considerable burial depth (3500–4500 m), making it one of the most important areas for deep-marine shale gas exploration and development in China [6,20]. Based on lithological characteristics, electrical properties, and logging curves, the Longyi₁ submember can be further subdivided into four sublayers: Longyi₁¹, Longyi₁², Longyi₁³, and Longyi₁⁴ (hereafter referred to as Sublayer 1, Sublayer 2, Sublayer 3, and Sublayer 4) [6,12]. Among these, the interval from the top of Wufeng Formation to Sublayer 3 is dominated by black carbonaceous siliceous shale, with high total organic carbon (TOC) content and abundant graptolites, indicating deposition under anoxic conditions with high primary productivity. This is the main shale-gas-producing layer in the study area, with a thickness of 14–28 m (Figure 2B).

Figure 1. (A) Location of Sichuan Basin in the Upper Yangtze Block; (B) Location of the southern Sichuan Basin; (C) Geological map of the western Chongqing area and locations of research wells. (Base maps for (A,B) were modified from [16,29]; the latitude and longitude data in (A) were obtained from [29], while those in (B,C) were sourced from the Standard Map Service Network [33]).

Figure 1. (A) Location of Sichuan Basin in the Upper Yangtze Block; (B) Location of the southern Sichuan Basin; (C) Geological map of the western Chongqing area and locations of research wells. (Base maps for (A,B) were modified from [16,29]; the latitude and longitude data in (A) were obtained from [29], while those in (B,C) were sourced from the Standard Map Service Network [33]).

Figure 2. (A) Stratigraphic column of the well H202; (B) Stratigraphic column of the Wufeng Formation–Longyi₁ submember, showing the vertical distribution of TOC content in well H202 (numbers 1-4 correspond to sublayers 1 through 4).

Figure 2. (A) Stratigraphic column of the well H202; (B) Stratigraphic column of the Wufeng Formation–Longyi₁ submember, showing the vertical distribution of TOC content in well H202 (numbers 1-4 correspond to sublayers 1 through 4).

3. Samples and Methods

3.1. Shale Samples

In this study, deep-marine shale drilling core samples were collected from the Upper Ordovician Wufeng Formation and the Lower Silurian Longyi₁ submember in eight typical deep shale gas wells in the western Chongqing area, namely, well He201, well H202, well H203, well H204, well H205, well H206, well H207 and well R203, totaling 80 shale samples from different sublayers. There are 8 samples from the Wufeng Formation, 11 samples from Sublayer 1, 14 samples from Sublayer 2, 13 samples from Sublayer 3, and 34 samples from Sublayer 4. The burial depths of the samples range from 3600 m to 4400 m; thus, all of the samples are deep shale reservoir samples. The drilling locations are shown in Figure 1C.

3.2. Experimental Methods

The experiments involved in this study included TOC analysis, whole-rock X-ray diffraction (XRD), FE-SEM, low-pressure N₂ and CO₂ adsorption, and total gas content measurements.

The TOC content analysis was conducted using a LECO CS-230 carbon and sulfur analyzer at the Geological Laboratory Research Institute of Hebei Scoilmic company (Cangzhou, China). To ensure the accuracy of TOC measurements, the samples were pretreated to remove inorganic carbon, which is particularly important for carbonate-rich shale. Prior to testing, the samples were crushed to a particle size of 60–80 mesh and pretreated with hydrochloric acid (HCl) to eliminate inorganic carbon, mainly carbonate components [18]. After acid treatment, the samples were rinsed with distilled water to remove any residual acid, dried, and then combusted with oxygen in the carbon–sulfur analyzer. The amount of CO₂ produced during the combustion process was detected to quantitatively calculate the TOC content in the shale sample. This pretreatment step ensures that the measured CO₂ is derived exclusively from organic carbon, thereby providing an accurate determination of TOC content even in carbonate-rich shale formations.

The XRD analysis was conducted using a Bruker AXS D8 Discover X-ray diffractometer at the Geological Laboratory Research Institute of Hebei Scoilmic company (Cangzhou, China). The shale samples were ground to 200 mesh using an agate mortar and then placed in an oven for 24 h. After drying, XRD experiments were conducted to determine the type of mineral based on the characteristic peaks in the diffraction pattern, compared with the standard pattern or database. Quantitative phase analysis was performed using the K-value method (reference intensity ratio method), where the relative mineral contents were determined by calculating the integrated areas of characteristic diffraction peaks and applying appropriate K-factors for each mineral content. Experimental conditions: Cu target, tube voltage 40 kV, tube current 100 mA, step size 0.02°, rotation speed 4°/min [20].

The FE-SEM observations were conducted using a Zeiss Merlin Compact field emission scanning electron microscope at the Geological Laboratory Research Institute of Hebei Scoilmic company (Cangzhou, China). The samples were prepared as rectangular blocks measuring 30 mm × 30 mm × 15 mm. First, they were subjected to mechanical polishing, followed by argon ion polishing. Subsequently, carbon powder was sprayed onto the samples to enhance conductivity, enabling quantitative observations of nanoscale pore sizes and morphologies within the shale samples under the electron microscope [34,35,36]. The working voltage was 15 kV, and the observation distance was 9–11 mm.

The low-pressure N₂ and CO₂ adsorption tests were conducted using a Micromeritics ASAP 2460 automatic gas adsorption analyzer at the Kezheng Testing company (Suzhou, China). Before the experiment, 3–5 g of the sample was weighed and it was crushed into powder with a particle size of 60–80 mesh. The shale powder sample was dried for 12 h at 110 °C in the degassing chamber to eliminate free water and impurity gas in the samples. Then, the degassed samples were exposed to N₂ at 77 K and CO₂ at 273.15 K, respectively, to obtain adsorption–desorption isotherms for both gases. CO₂ is suitable for characterizing micropores (<1.5 nm), while N₂ is appropriate for analyzing a limited range of micropores, mesopores, and some macropores (1.5–100 nm). Next, we used the Brunauer—Emmett—Teller (BET) model to calculate the specific surface area data and used the Barrett–Joyner–Halenda (BJH) model to calculate the total pore volume and average pore diameter [37,38,39]. The pore diameter distribution was calculated with the density functional theory (DFT) model [38,39,40], and the micropore specific surface area and micropore volume were estimated by the Dubinin–Radushkevich (DR) model [38].

The total gas content includes three parts, namely lost gas, desorption gas, and residual gas. The lost gas was calculated using an improved USBM model, while the desorbed gas was measured using an on-site desorption gas analyzer. The residual gas was measured using a residual gas analyzer after crushing and heating the residual samples [41].

In this study, the pore size classification is based on the International Union of Pure and Applied Chemistry (IUPAC) shale pore size classification standard, which identifies pores with sizes less than 2 nm as micropores, pores with sizes from 2 to 50 nm as mesopores, and pores with sizes greater than 50 nm as macropores [42].

4. Results

4.1. Characteristics of Deep-Marine Shale Gas Reservoirs

4.1.1. Geochemical Characteristics

The geochemical experimental data indicate that the organic matter type and maturity of the Upper Ordovician Wufeng Formation and lower Silurian Longyi₁ submember in the western Chongqing area exhibit little variation overall, while the TOC content varies more markedly among the different sublayers (

Table 1. Geochemical characteristics of different sublayers in the western Chongqing area, Sichuan Basin.

Well	Depth (m)	Strata	Macerals Composition Percentage (%)				TI	Organic Matter Type	Rb (%) (a)	Ero (%) (b)
			Sapropelinite	Exinite	Vitrinite	Inertinite
H204	3581.4	Sublayer 4	96	0	4	0	93	Type I	3.24	2.40
H204	3599.92	Sublayer 4	98	0	2	0	96.5	Type I	3.28	2.43
H204	3610.4	O3w	95	0	5	0	91.3	Type I	3.25	2.41
H207	4232.1	Sublayer 4	98	0	2	0	96.5	Type I	3.34	2.46
H207	4242.6	Sublayer 4	95	0	5	0	91.3	Type I	3.36	2.48
H207	4252.4	Sublayer 3	94	0	6	0	89.5	Type I	3.35	2.47
H207	4262.4	O3w	96	0	4	0	93	Type I	3.38	2.49
H202	4072.32	Sublayer 4	/	/	/	/	/	/	2.8	2.13
H202	4075.01	Sublayer 3	99	0	1	0	98.3	Type I	/	/
R203	4330.9	Sublayer 2	/	/	/	/	/	/	2.88	2.18
R203	4335.77	Sublayer 1	99	0	0	1	98	Type I	/	/

Note: ^(a) Rb is the solid bitumen reflectance. ^(b) The calculation method for the equivalent vitrinite reflectance (Ero = 0.618 × Rb + 0.4) is from [43].

).

Kerogen microscopic identification analysis reveal that the microscopic components of the organic matter are dominated by amorphous sapropelinite, with contents ranging from 94% to 99% and an average of 96.7% (Table 1). In addition to sapropelinite, the samples contain small amounts of vitrinite, with contents ranging from 0% to 6% and an average of 3.2% (Table 1). The kerogen type index (TI) ranges from 89.5 to 98.3, with an average of 94.2, indicating Type I kerogen (Table 1), and the parent material source was mainly algae. Although the burial depth of the Wufeng Formation–Longyi₁ submember in the western Chongqing area is characterized by deep burial in the north and shallow burial in the south, the bitumen-equivalent vitrinite reflectance ERo of organic matter maturity shows slight variation [43], with ERo values ranging from 2.13% to 2.49%, with an average of 2.38% (Table 1), indicating that all samples have reached the overmature stage. This suggests that, during the deep burial process of the shale reservoirs in the study area, the crude oil initially generated from kerogen has undergone thermal cracking, transitioning into the dry gas stage and resulting in significant gas generation [44]. The TOC distribution exhibits significant variations among sublayers (Figure 3A), primarily controlled by sedimentary environment differences [45]. Enhanced productivity of siliceous organisms during the late Wufeng to early Longyi₁ submember global warming period, combined with excellent preservation conditions in deep-water environments [32], resulted in high TOC content at the Wufeng Formation top and Sublayer 1 (Figure 2B). In the late Longyi₁ submember deposition stage, water depth reduction and transition to a shallow-water shelf environment led to TOC content decrease.

Some scholars have set the lower limit of the TOC content in the Longmaxi Formation shale in the Sichuan Basin at 1.0% [46], and the lower limit for the TOC of effective shale established by North American petroleum geologists is 2.0% [15]. In the deep shale samples from the Wufeng Formation–Longyi₁ submember in the western Chongqing area, the TOC content ranging from 0.30% to 6.23%, averaging 2.87%. Notably, the TOC content at the top of the Wufeng Formation and in Sublayer 1 and Sublayer 2 is significantly higher than this lower limit in all samples, indicating good exploration potential.

However, due to the significant differences in the geochemical characteristics of shale in different regions and layers, scholars have proposed numerous classification and evaluation schemes for the TOC content in shale gas reservoirs [46,47,48]. These methods mainly rely on empirical division, which is highly subjective and has limited regional applicability. Currently, there is still a lack of applicable TOC content classification and evaluation schemes for the deep-marine shale in the western Chongqing area. Therefore, based on the TOC distribution characteristics of deep-marine shale samples in the western Chongqing area, IBM SPSS Statistics software (Version 24) was used to conduct a three-quartile statistical analysis [49]. Based on the results of the first quartile of Q₁ = 2.04% and the second quartile of Q₂ = 3.1%, and combined with previous studies on the TOC content characteristics of the Wufeng Formation–Longmaxi Formation shale in the Sichuan Basin, a classification evaluation scheme for the TOC content in the western Chongqing area was established. That is, a TOC content < 2% indicates organic-lean shale, a TOC content between 2% and 3% indicates medium-organic shale, and a TOC content > 3% indicates organic-rich shale, with corresponding proportions of 31.3%, 29.6%, and 39.1%, respectively, among all samples investigated here (Figure 3B).

4.1.2. Characteristics of the Mineral Compositions

XRD data show that deep-marine shale minerals are mainly composed of felsic minerals such as quartz, K-feldspar, and plagioclase; carbonate minerals such as calcite and dolomite; clay minerals such as illite, kaolinite, chlorite, and mixed-layer illite/smectite (I/S); and other minerals such as rutile and pyrite (Figure 4C). Owing to the low content of rutile and K-feldspar, only a few samples contain 1% to 3% of these minerals. Therefore, in this study, rutile was ignored, K-feldspar and plagioclase were merged into feldspar, and the main mineral content was normalized to calculate the relative percentage content of each main mineral.

The mineral composition exhibits pronounced vertical variations across different sublayers. In the Wufeng Formation, quartz content is relatively low at the bottom but shows an upward-increasing trend. The highest quartz abundance occurs in Sublayer 1 of the Longyi₁ submember, above which quartz gradually decreases while feldspar content slightly increases. This distribution pattern is due to the global warming from the late Wufeng to early Longyi₁ submember periods, which enhanced the productivity of siliceous organisms. In addition, the deep-water shelf depositional environment and reduced terrestrial inputs jointly promoted the large-scale preservation of biogenic silica [50]. Initially, biogenic silica was preserved in sediments as opal-A. During deep burial diagenesis, increasing temperature and pressure triggered the opal-A → opal-CT → microcrystalline quartz transformation, ultimately forming dense, high-hardness aggregates of microcrystalline quartz [51]. Given the deep burial and overmature thermal conditions (ERo > 2.0%) of the study area, silica predominantly exists as microcrystalline quartz. Notably, feldspar content remains low throughout the sequence (<10%), which results from both depositional and diagenetic factors [52]. The shallow- to deep-water shelf environment received limited terrigenous input, restricting initial feldspar supply. Furthermore, advanced thermal maturity promoted extensive feldspar alteration, with conversion to clay minerals (primarily illite) and authigenic quartz [50].

In general, deep-marine shale mineral compositions within each sublayer of the Wufeng Formation–Longyi₁ submember vary only slightly in the study area, but there are differences between each sublayer. As shown in Figure 4A, quartz content displays a distinct stratigraphic distribution, reaching its maximum concentration in Sublayer 1 and decreasing both upward and downward. The clay minerals are dominated by illite, followed by chlorite, with minor amounts of kaolinite and I/S (Figure 4B). This mineralogical composition indicates deposition in a stable environment with limited terrigenous input, followed by advanced diagenesis under thermal conditions, as shown by the illite predominance and lack of smectite-rich phases [52].

4.2. Classification Scheme and Lithofacies Types

4.2.1. Lithofacies Classification Scheme

Previous studies demonstrate the TOC content in marine shale is a key parameter affecting the hydrocarbon generation capacity of shale gas reservoirs [26,44], while mineral composition significantly influences fracability [20]. In this study, the lithofacies classification criteria are primarily based on TOC content and mineral composition, as these parameters are the most critical factors controlling gas generation capacity and reservoir fracability in deep-marine shale. Although stratification structure can reflect sedimentary environments [29], it was not included in the classification scheme due to its subjectivity in qualitative observation. Based on the geochemical and mineral composition characteristics of shale samples, we adopted a composite lithofacies classification method that incorporates the TOC content and mineral composition to classify the deep-marine shale lithofacies of the Wufeng Formation–Longyi₁ submember in the western Chongqing area.

The TOC content was classified according to the Classification and Evaluation Scheme for TOC Content in the western Chongqing area. Due to the small size of the study area, the straight-line distance between the farthest two wells (well R203 and well H206) is less than 70 km. The sedimentary facies of the Wufeng Formation–Longyi₁ submember in the research area are all deep-water shelf facies, and the mineral composition differences are not significant. Therefore, considering the practicality and operability of the mineral composition classification scheme, four types of lithofacies were classified based on the ternary diagram. The specific classification scheme is as follows:

First, three types of shale were classified using the Classification and Evaluation Scheme for TOC Content in the western Chongqing area, namely, a TOC content > 3% corresponded to organic-rich shale, a TOC content between 2% and 3% corresponded to medium-organic shale, and a TOC content < 2% corresponded to organic-lean shale. Second, felsic minerals (quartz and feldspar), carbonate minerals (calcite and dolomite), and clay minerals were used as the three terminal elements for graphical analysis. Based on 50% as the classification standard, four types of shale lithofacies were classified: siliceous shale lithofacies, calcareous shale lithofacies, clay shale lithofacies, and mixed shale lithofacies. Therefore, the composite lithofacies classification method that incorporates the TOC content and mineral composition distinguishes a total of 12 lithofacies (Figure 5).

4.2.2. Lithofacies Types

The results of the TOC content classification show that organic-rich shale, medium-organic shale, and organic-lean shale are present in the western Chongqing area, with differences between each sublayer. The Wufeng Formation mainly features organic-lean shale, followed by medium-organic shale, while organic-rich shale is less common. All samples from Sublayer 1 are organic-rich shale. The vast majority of samples from Sublayer 2 are organic-rich shale, with rare medium-organic shale and no organic-lean shale development. Sublayer 3 mainly consists of organic-rich shale, followed by medium-organic shale, with less organic-lean shale. Sublayer 4 mainly consists of medium-organic shale, followed by organic-lean shale, with no organic-rich shale development (Figure 6).

The results of the composite lithofacies classification method that incorporates TOC content and mineral composition (Figure 5) indicate that a total of 10 shale lithofacies developed in the Wufeng Formation–Longyi₁ submember in the research area, namely, organic-rich siliceous shale (S¹), organic-rich calcareous shale (C¹), organic-rich mixed shale (M¹), medium-organic siliceous shale (S²), medium-organic calcareous shale (C²), medium-organic mixed shale (M²), organic-lean siliceous shale (S³), organic-lean calcareous shale (C³), organic-lean clay shale (CM³), and organic-lean mixed shale (M³). Among them, most samples of organic-rich shale are S¹, followed by M¹, and only one sample of Sublayer 2 is C¹; most samples of medium-organic shale are S², followed by M², and only one sample of Sublayer 3 is C²; most samples of organic-lean shale are S³, followed by M³. Only a small number of samples from the Wufeng Formation and Sublayer 4 are from C³ and CM³. Overall, the study area mainly features the following six types of shale lithofacies: organic-rich siliceous shale (S¹), organic-rich mixed shale (M¹), medium-organic siliceous shale (S²), medium-organic mixed shale (M²), organic-lean siliceous shale (S³), and organic-lean mixed shale (M³).

The TOC and mineral composition characteristics of the main lithofacies are shown in

Table 2. Statistics of the TOC content and mineral composition of the main lithofacies in the western Chongqing area, Sichuan Basin.

Lithofacies	Main Developmental Sublayers	TOC (%)	Mineral Composition Percentage (%)
			Felsic Minerals	Carbonate Minerals	Clay Minerals
S1	O3w, Sublayer 1, Sublayer 2	${\displaystyle \frac{3.01–5.88}{4.18}}$	${\displaystyle \frac{51–85}{66}}$	${\displaystyle \frac{5–37}{13.5}}$	${\displaystyle \frac{8–34.9}{16.86}}$
M1	Sublayer 1, Sublayer 2	${\displaystyle \frac{3.05–6.23}{4.17}}$	${\displaystyle \frac{42–49}{45.4}}$	${\displaystyle \frac{13–39}{23.8}}$	${\displaystyle \frac{13–39}{27}}$
S2	O3w, Sublayer 3, Sublayer 4	${\displaystyle \frac{2.0–2.52}{2.21}}$	${\displaystyle \frac{50.2–67}{57.63}}$	${\displaystyle \frac{2.7–15}{9.25}}$	${\displaystyle \frac{18–38.4}{29.72}}$
M2	O3w, Sublayer 2, Sublayer 4	${\displaystyle \frac{2.0–2.88}{2.48}}$	${\displaystyle \frac{37–50}{43.39}}$	${\displaystyle \frac{6.9–46}{18.35}}$	${\displaystyle \frac{6–45.7}{34.78}}$
S3	O3w, Sublayer 3, Sublayer 4	${\displaystyle \frac{1.02–1.9}{1.53}}$	${\displaystyle \frac{51.8–67}{55.67}}$	${\displaystyle \frac{5–19.9}{13.07}}$	${\displaystyle \frac{12–37.6}{28.65}}$
M3	O3w, Sublayer 4	${\displaystyle \frac{0.5–1.86}{1.59}}$	${\displaystyle \frac{23–50}{42.58}}$	${\displaystyle \frac{4.6–46}{17.07}}$	${\displaystyle \frac{29–44}{37.76}}$

Note: The data format of the TOC content and mineral composition column is ${\displaystyle \frac{\mathrm{M}\mathrm{i}\mathrm{n}–\mathrm{M}\mathrm{a}\mathrm{x}}{\mathrm{A}\mathrm{v}\mathrm{e}\mathrm{r}\mathrm{a}\mathrm{g}\mathrm{e}}}$.

. S¹ occurs mainly at the top of the Wufeng Formation and Sublayer 1, with a small amount of development in Sublayer 2. It is characterized by both high contents of felsic mineral (more than 50%) and TOC (higher than 3%) (Table 2), and the core is black and dark gray shale with developed laminations and abundant and well-preserved graptolites (Figure 7A). Under the microscope, S¹ is mainly composed of mud and felsic grains, and individual spicules can be seen. The clastic particles are suspended in the mud and show a directional arrangement (Figure 7B), which indicates a relatively weak hydrodynamic environment; M¹ is found mainly in Sublayer 1 and Sublayer 2. In terms of mineral composition, the average silica, carbonate, and clay mineral contents are all less than 50% (Table 2), and the core is composed of dark gray and black shale with well-developed laminations, pyrite patches, and incompletely preserved graptolites (Figure 7C). Under the microscope, M¹ is mainly composed of mud, fewer carbonate particles and felsic grains, and fewer fossils than S¹ can be observed. Massive and faint laminations are the dominant sedimentary structures in this lithofacies (Figure 7D); S² occurs mainly in the Wufeng Formation and Sublayer 3, with a small amount of development in Sublayer 4. It is typical for its high felsic mineral content (more than 50%) and medium TOC content (ranging from 2% to 2.52%) (Table 2). This rock is dark gray shale with developed laminations. There are few pyrite particles at the lamination boundaries, and the graptolite species are few and not well preserved (Figure 7E). Under the microscope, S² has similar characteristics to S¹ but with larger grain sizes (Figure 7F). M² is found mainly in the Wufeng Formation and Sublayer 2, with a small amount of development in Sublayer 4. In terms of the mineral and TOC contents, the average silica, carbonate, and clay mineral contents were all less than 50%, with a moderate TOC content (ranging from 2% to 2.88%) (Table 2). This rock is black gray shale with a massive structure and unclear laminations intercalated with silty muddy strips. Scattered pyrite particles are visible on the surface, with few graptolites (Figure 7G). Under the microscope, M² has larger grain sizes than M¹, also showing massive and faint lamination structures (Figure 7H). S³ occurs mainly at the bottom of the Wufeng Formation and from Sublayer 3 to Sublayer 4. It is typical for its high content of felsic minerals (more than 50%) and low TOC content (less than 2%) (Table 2). This rock is gray shale with unclear laminations, occasionally showing pyrite phenocrysts, silty strips, and sandy nodules (Figure 7I). Under the microscope, silty homogeneous particles and radiolarians can be observed (Figure 7J). M³ is found mainly in the Wufeng Formation and Sublayer 4. It is characterized by mixed mineral contents (all below 50%) and low TOC contents (less than 2%) (Table 2). Core observations show that M³ is mainly characterized by a massive structure with a gray color (Figure 7K). Under the microscope, the main body of M³ is mud, and the clastic grains have a faint directional arrangement and are significantly larger than those observed in other layers (Figure 7L), indicating a strong hydrodynamic depositional environment.

The overall relationship between TOC content and clay content demonstrates a negative and reversible trend (Table 2), implying that an increase in clay mineral content dilutes organic matter, thereby hindering its enrichment [29]. In the M³, the higher clay mineral content, combined with stronger hydrodynamic conditions, results in the dilution and oxidative degradation of organic matter, ultimately leading to lower TOC content.

4.3. Reservoir Spatial Characteristics

The microscopic characteristics of the shale pores within the Wufeng Formation–Longyi₁ submember in the western Chongqing area were analyzed via FE-SEM and argon ion beam polished SEM (Figure 8). Following the shale pore classification scheme proposed by researchers [16,23,26], three main types of pores were identified in deep-marine shale reservoirs: organic pores, inorganic pores, and microfractures. Based on polished SEM images, the surface porosity of both inorganic and organic pores in different shale lithofacies was quantified using ImageJ software (Version 1.54f) (Figure 9A,B). The pores were mainly observed at the nanoscale, with notable variations in surface porosity among the various shale lithofacies (Figure 9C).

4.3.1. Organic Pores

Organic pores are of great significance in marine shale gas reservoirs because they are the main reservoir space for shale gas storage and the key factor for shale gas enrichment and stable production [26,27,53].

The shale lithofacies and microscopic organic matter types in the study area control the development of organic pores. S¹ has the most developed organic pores (Figure 9C), which mainly developed inside the migrated organic matter associated with clay minerals and strawberry-shaped pyrite. The organic pores are mainly circular and nearly circular (Figure 8A), with pore diameters ranging from 10 nm to 800 nm, mainly nanoscale pores, and the pores were predominantly produced during the process of maturation and gas generation of the organic components in shale. However, the organic pores inside the strip-shaped organic matter in S¹ are almost nonexistent (Figure 8B,G). The massive organic matter in S² developed a small number of organic pores with a nearly circular pore morphology (Figure 8E). The migrated organic matter in S² grew interactively with clay minerals and are thus mainly distributed in the intergranular pores between rigid mineral particles, with slit-like and floccular pore morphologies, and shrinkage fractures developed at the edges or inside of the organic matter (Figure 8D). The organic-lean shale (including S³ and M³) has less organic matter, irregular organic matter is sporadically distributed in the clay mineral interlaminar pores and the intergranular pores of strawberry-shaped pyrite, and organic pores are not developed (Figure 8H,I).

4.3.2. Inorganic Pores

The inorganic pores of deep-marine shale reservoirs in the study area are mainly divided into intergranular and intragranular pores. Intergranular pores are more common in siliceous shales and are commonly found between rigid mineral particles such as quartz, feldspar, and pyrite (Figure 8D). Clay mineral interlaminar pores are the main inorganic pore type in deep-marine shale reservoirs in the western Chongqing area. Due to the impact of compaction during diagenesis, clay mineral interlaminar pores have directional distribution characteristics (Figure 8C,I). Because these pores were formed between clay mineral interlayers, mixed shale lithofacies exhibit a higher development of clay mineral interlaminar pores compared to siliceous shale lithofacies with similar TOC content, resulting in a higher inorganic surface porosity (Figure 9C). The FE-SEM observations show that the clay mineral interlaminar pores in M³ are the most developed, followed by those in M², which are mainly developed between the interlamellar layers of clay mineral aggregates such as illite and chlorite in the form of elongated or slit-like pores with widths ranging from 50 nm–1 μm (Figure 8C,F,H,I). The intragranular pores are mainly dissolution pores, which are mainly isolated and distributed in quartz, dolomite, calcite, or feldspar, with nearly circular and elliptical shapes. The pore size ranges from 100–500 nm (Figure 8D), which may be caused by organic matter acid discharge and the dissolution of mineral particles during hydrocarbon generation [32].

4.3.3. Microfractures

Microfractures are conducive to shale gas accumulation and migration and are important reservoir storage spaces and migration channels for shale gas [54]. Nanoscale to microscale microfractures are developed in deep-marine shale in the western Chongqing area and can be divided into structural fractures and shrinkage fractures. The structural fractures are wavy and microtoothed shapes, with lengths of 1–40 μm and openings of 50–500 nm (Figure 8B,D,I). Shrinkage fractures developed inside organic matter or at the contact edge between organic matter and mineral particles and were formed by the volume contraction of organic matter during hydrocarbon generation and expulsion (Figure 8D).

Overall, S¹, S², and M³ all exhibit relatively high surface porosity (Figure 9C). Among them, S¹ and S² are dominated by organic pores, with the development of organic shrinkage fractures, while inorganic pores are relatively scarce and consist primarily of intergranular pores. In contrast, M³ contains a large number of inorganic pores, mainly clay mineral interlaminar pores, while organic pores are almost undeveloped.

4.4. Low-Pressure N₂ and CO₂ Adsorption Experiments

4.4.1. Low-Pressure N₂ and CO₂ Adsorption Isotherms

Shale gas is mainly enriched in micropores and smaller mesopores [35,38], and the low-pressure N₂ and CO₂ adsorption technique can be used to quantitatively analyze pores with diameters less than 100 nm. Specifically, N₂ adsorption is particularly effective for characterizing a limited range of micropores (1.5–2 nm), mesopores (2–50 nm), and some macropores (50–100 nm) [35,36], whereas CO₂ adsorption is widely utilized for analyzing micropores (<1.5 nm) in shale samples [38,55,56].

The N₂ adsorption–desorption isotherms of the main lithofacies of the Wufeng Formation–Longyi₁ submember in the western Chongqing area have similar shapes. The curve pattern is a three-segmented feature with a reversed S-shaped characteristic (Figure 10A). According to the classification scheme of the IUPAC [42], the N₂ adsorption isothermal curve hysteresis loops of deep-marine shale samples show H₃ or H₂ characteristics. The adsorption–desorption isotherms begin to separate at a relative pressure (p/p₀) of approximately 0.45–0.48, forming a clear hysteresis loop. At a relative pressure (p/p₀) of approximately 0.50, the desorption curve shows a clear inflection point where the adsorption amount decreases significantly (Figure 10A). This behavior indicates that the pore structures are primarily composed of cylindrical pores, slit pores, wedge-shaped pores, and ink-bottle-shaped pores [40,57]. Meanwhile, the CO₂ adsorption isotherms of deep-marine shale samples conform to a typical Type I adsorption isotherm, indicating the presence of micropores in these samples (Figure 10B) [38].

The shale lithofacies influences the N₂ adsorption curve morphology (Figure 10A). S¹ exhibits a high adsorption capacity, with a clear H₃ hysteresis loop and a large hysteresis loop area, indicating that the pores in S¹ consist mainly of open-ended cylindrical pores and parallel slit-shaped pores. In contrast, S³ and M³ have a low adsorption capacity, with the hysteresis loop transitioning from H₃ to H₂ and a small hysteresis loop area, indicating that the pores of the samples mainly consist of ink-bottle-shaped pores, wedge-shaped pores, and parallel slit-shaped capillary pores. This suggests that the organic-lean shale samples contain more clay mineral interlaminar pores, which is in line with the results of the SEM observations.

The low-pressure N₂ and CO₂ adsorption isotherms reveal that the nanometer pores in the deep-marine shale reservoirs of the Wufeng Formation–Longyi₁ submember in the western Chongqing area are distributed from micropores to macropores. The pore morphologies are dominated by an intricate combination of slit pores, wedge-shaped pores, ink-bottle-shaped pores, cylindrical pores, and parallel slit-shaped pores, reflecting the heterogeneity of these reservoirs [38,40,57].

4.4.2. Pore Diameter Distribution

The pore diameter distributions of the different shale lithofacies can be calculated with a DFT model (Figure 10C,D). The nanopores in deep-marine shale reservoirs of the Wufeng Formation–Longyi₁ submember in the western Chongqing area are classified as micropores, mesopores, and macropores, but there are some variations in distribution among different lithofacies. The micropores of the six main lithofacies are mainly contributed by pores with a size range of 0.4–0.9 nm, which has a bimodal feature (Figure 10D). Notably, organic-rich shale (including S¹ and M¹) displays higher peak heights and larger peak areas, suggesting more developed micropores. The pore size distribution derived from N₂ adsorption reveals multipeak characteristics in the shale samples (Figure 10C). Siliceous shale (including S¹ and S²) exhibits the most developed micropores in the 1.5–2 nm range, followed by mesopores in the 3–20 nm range. Among these, S¹ has the highest peak height in the pore diameter distribution, indicating a more concentrated distribution and development of micropores and mesopores. In contrast, organic-lean shales primarily developed mesopores in the 7–50 nm range, with lower peak heights and a smaller area under the pore diameter distribution curve, suggesting a significantly smaller total pore volume compared to S¹.

5. Discussion

5.1. Comparison of Global Marine Shales

The Wufeng–Longmaxi shale in the western Chongqing area shows both similarities and differences in geological characteristics and pore types when compared with global marine shale formations (Table 3).

Specifically, the current burial depth of the Wufeng–Longmaxi shale greatly exceeds that of the Barnett shale (US) [26,58], the Poker Chip shale (Canada) [56,59,60], and North African Hot shales [8] and is only similar to the Eagle Ford shale located south of the Edwards and Sligo Shelf Margins [61]. Notably, its maturity substantially exceeds that of these formations due to complex tectonic influences and burial depth. The Wufeng–Longmaxi shale entered the uplift stripping stage in the Late Cretaceous [62], reaching a peak in the Miocene, and its ancient depth was much deeper than present, causing a great maturity–depth mismatch [20]. This makes the Wufeng–Longmaxi shale exhibit the highest maturity among these shales, now in the overmature dry gas stage.

In terms of shale lithofacies and pore types, the lithofacies of the Longmaxi shale is similar to that of the Barnett shale, with both classified as S¹ (high carbon and felsic content). However, there are notable differences in their pore types: the Longmaxi shale has a deeper burial depth and higher compaction and thermal maturity, resulting in lower development of intergranular pores compared to the Barnett shale, while organic matter pores are more well-developed. Additionally, the carbonate mineral content in the Longmaxi Formation is higher than that in the Barnett shale, and the tectonic activity in the western Chongqing area has been more intense, resulting in a greater number of carbonate mineral dissolution pores and microfractures observable in the Longmaxi shale.

Table 3. Comparison of geological characteristics and pore types between Global Marine Shale Formations and the Wufeng–Longmaxi Formation in Western Chongqing, Sichuan Basin, China.

Country	Shale Name	Depth	Ro	TOC	Carbonate Mineral	Clay Mineral	Felsic Mineral	Lithofacies (a)	Main Pore Types (b)	Data Sources
		(m)	(%)	(%)	(%)	(%)	(%)
America	Barnett shale	799–2484	1–1.4	5.3	0.4	37.4	55.3	S1	Intergranular pores, organic pores, clay mineral interlaminar pores	[5,26,58,61,63]
	Eagle Ford shale	232–3962	0.67–1.76	1.8	81	5	11	C3	Intergranular pores, dissolution pores
Canada	Poker Chip shale	1081	0.5–1.2	2.2	1.8	75.7	21.8	CM2	Clay mineral interlaminar pores	[56,59,60]
North Africa	Hot shale	1245–2140	0.35–0.9	5.72	24	41	16	M1	Clay mineral interlaminar pores, microfractures	[8]
China	Longmaxi shale	3612–4125	2.13–2.48	3	15.9	27.2	56.9	S1	Organic pores, intergranular pores, dissolution pores, microfractures	Experimental data
	Wufeng shale	3616–4128	2.41–2.49	1.66	24.9	30.8	44.3	M3	Clay mineral interlaminar pores, intergranular pores

Note: ^(a) Lithofacies were identified according to the lithofacies classification scheme proposed in this study. ^(b) Main pore types are described in the reference literature or recognized based on SEM images found in the literature.

Table 3. Comparison of geological characteristics and pore types between Global Marine Shale Formations and the Wufeng–Longmaxi Formation in Western Chongqing, Sichuan Basin, China.

Country	Shale Name	Depth	Ro	TOC	Carbonate Mineral	Clay Mineral	Felsic Mineral	Lithofacies (a)	Main Pore Types (b)	Data Sources
		(m)	(%)	(%)	(%)	(%)	(%)
America	Barnett shale	799–2484	1–1.4	5.3	0.4	37.4	55.3	S1	Intergranular pores, organic pores, clay mineral interlaminar pores	[5,26,58,61,63]
	Eagle Ford shale	232–3962	0.67–1.76	1.8	81	5	11	C3	Intergranular pores, dissolution pores
Canada	Poker Chip shale	1081	0.5–1.2	2.2	1.8	75.7	21.8	CM2	Clay mineral interlaminar pores	[56,59,60]
North Africa	Hot shale	1245–2140	0.35–0.9	5.72	24	41	16	M1	Clay mineral interlaminar pores, microfractures	[8]
China	Longmaxi shale	3612–4125	2.13–2.48	3	15.9	27.2	56.9	S1	Organic pores, intergranular pores, dissolution pores, microfractures	Experimental data
	Wufeng shale	3616–4128	2.41–2.49	1.66	24.9	30.8	44.3	M3	Clay mineral interlaminar pores, intergranular pores

Note: ^(a) Lithofacies were identified according to the lithofacies classification scheme proposed in this study. ^(b) Main pore types are described in the reference literature or recognized based on SEM images found in the literature.

The mineral composition of the Wufeng Formation is similar to North Africa’s Hot shale, with both classified as M-type (mixed shale) lithofacies and dominated by clay mineral interlaminar pores. However, the TOC content of the Wufeng Formation is significantly lower than that of the Hot shale, and it has a higher content of felsic minerals, greater burial depth, and a higher degree of compaction. Consequently, a small number of intergranular pores can be observed in the Wufeng Formation, primarily surrounding the felsic minerals. In contrast, the Eagle Ford (US) and Poker Chip (Canada) shales demonstrate significant differences in lithofacies and pore types compared to the Wufeng–Longmaxi shale. The Eagle Ford shale is characterized by a lower TOC content and a very high carbonate mineral content, classifying it as C³, with pore types predominantly consisting of intergranular pores and carbonate mineral dissolution pores. Conversely, the Poker Chip shale has a moderate TOC content and a higher clay mineral content, classifying it as CM², with pore types primarily composed of clay mineral interlaminar pores.

Compared with various global marine shale formations, the deep-marine shale in the study area exhibits greater burial depths, higher thermal maturity, and more intense tectonic activity. As a result, the pore types of deep-marine shale are more diverse than those of other shales, with more developed organic pores and more microfractures. Additionally, the strong compaction during deep burial resulted in smaller intergranular pores, mainly developed around felsic minerals.

5.2. Evaluation of Fractal Dimensions and Pore Structure Parameters

5.2.1. Fractal Dimensions

This study is based on experimental data of low-pressure N₂ adsorption and uses the Frenkel–Halsey–Hill (FHH) model to calculate the pore surface fractal dimension (D₁) and structural fractal dimension (D₂) of deep-marine shale samples in the study area [2,64,65]. Specifically, D₁ represents the fractal dimension under relative pressure (p/p₀) conditions below 0.45, reflecting the influence of van der Waals forces and characterizing the surface roughness of the samples; D₂ represents the fractal dimension under relative pressure (p/p₀) conditions above 0.45, reflecting capillary condensation effects and characterizing the complexity and irregularity of the pore structure. The values of D₁ and D₂ are shown in

Table 4. Reservoir characteristics, fractal dimensions, and pore structure parameters of the main lithofacies in the western Chongqing area, Sichuan Basin.

Sample ID	Depth	TOC	Carbonate Mineral	Clay Mineral	Felsic Mineral	Surface Area	Total Pore Volume	Average Pore Diameter	Micropore Surface Area	Micropore Volume	Total Gas Content	D1	D2	Lithofacies
	(m)	(%)	(%)	(%)	(%)	(m²/g)	(m3/g)	(nm)	(m²/g)	(m3/g)	(m3/t)
H204-07	3607.34	4.3	15	13	66	24.717	0.0217	5.34	21.944	0.00423	2.74	2.6782	2.8243	S1
H207-06	4255.96	4.7	12	18	60	22.42	0.019	5.713	20.922	0.00404	1.62	2.6495	2.8573	S1
H202-8	4075.01	3.8	6.6	12.7	72.5	21.786	0.0203	6.458	22.808	0.00442	4.69	2.6853	2.8791	S1
H207-04	4258.64	3.2	17.3	33.7	49	19.431	0.0182	5.988	18.500	0.00409	1.35	2.6681	2.8584	M1
H204-11	3600.73	2.6	13	22	60	20.499	0.0185	6.118	16.584	0.00359	3.02	2.636	2.858	S2
R203-5	4343.19	3	5.8	13.7	79	13.947	0.0124	7.92	19.456	0.00393	4.2	2.7322	2.8728	S2
H204-15	3594.73	2.6	7.7	41.2	47	20.477	0.0183	6.015	14.935	0.00327	2.01	2.633	2.8466	M2
H202-3	4085.6	0.7	19.9	26	53.2	8.578	0.0131	10.242	9.129	0.00227	0.61	2.6678	2.7732	S3
H207-25	4224.39	1.9	12.5	36.6	45.3	17.067	0.0142	5.007	11.614	0.00254	0.3	2.6218	2.8822	M3
H204-01	3617.71	0.9	24.2	34.1	36.9	22.425	0.0195	4.95	13.936	0.00307	2.16	2.5982	2.883	M3

.

The D₁ and D₂ of the main lithofacies of deep-marine shale in the study area are generally high. Specifically, D₁ ranges from 2.5982 to 2.7322, with an average value of 2.6584, while D₂ ranges from 2.7732 to 2.8830, with an average value of 2.8493. Notably, all samples exhibit D₂ values greater than D₁, indicating that the internal pore structure of deep-marine shale is more complex [64,65]. There are differences in fractal dimensions among different lithofacies. The D₁ values of M² and M³ are relatively low. It is speculated that this is because organic pores are underdeveloped, and during the deep burial process, the compaction effect makes the clay mineral particles arrange more closely, the pores become more regular, the homogeneity is stronger, and thus the fractal dimension is smaller. The D₂ value of S³ is relatively low. This is because, due to the lack of organic pores and clay mineral interlaminar pores, the pore types are relatively simple, mainly intergranular pores, with strong homogeneity, resulting in a smaller fractal dimension [2,40].

5.2.2. Pore Structure Parameters

In this study, five key pore structure parameters, namely, the specific surface area, total pore volume, average pore diameter, micropore specific surface area, and micropore volume, are used to quantitatively analyze and discuss the pore structure characteristics of deep-marine shale in the study area. The detailed parameter data are given in Table 4.

The correlations between the different pore structure parameters and the TOC contents of different lithofacies are shown in Figure 11A–D. The specific surface area and pore volume are positively correlated with the TOC content, with Pearson’s r values of 0.591 and 0.517, respectively (Figure 11A,B); moreover, the micropore specific surface area and micropore volume are strongly correlated with the TOC content, showing a significant positive correlation, with Pearson’s r values of 0.906 and 0.871, respectively (Figure 11C,D). This indicates that deep-marine shale pores in the research area are mainly developed in organic matter and that the organic pores contribute greatly to the micropore specific surface area and micropore volume. Therefore, the organic micropores developed in organic matter can provide potential adsorption sites for shale gas and provide storage space for the enrichment of adsorbed gas [57,66].

The correlation analysis between the mineral content and pore structure parameters revealed that the micropore specific surface area and micropore volume are positively correlated with the felsic mineral content, with Pearson’s r values of 0.695 and 0.628, respectively (Figure 11E,F), and it is speculated that the enrichment of felsic minerals improves the compressive strength of deep-marine shales, which is conducive to the preservation of micropores during deep burial [40]. The micropore specific surface area and micropore volume are negatively correlated with the clay mineral content, with Pearson’s r values of −0.689 and −0.619, respectively (Figure 11G,H). This is presumed to be due to the strong compaction during deep burial, where compaction closed and very small clay mineral particles filled part of the pore space, inhibiting the development of micropores [45]. From the comparison of the pore structure parameters of the different lithofacies, the micropore specific surface area and micropore volume of S¹ have obvious advantages, followed by those of S² and M¹, and they are the lowest for the organic-lean shales (including S³ and M³), indicating that S¹ has the greatest adsorption capacity, which is more conducive to the enrichment of shale gas (Figure 12).

5.3. Evaluation of Gas Content

The gas content is a key indicator of the production capacity and economic exploitation value of shale reservoirs, and the enrichment of shale gas is affected by a variety of factors, such as temperature and pressure conditions, TOC content, mineral composition, and pore structure characteristics [45,66]. Therefore, correlation analyses of the TOC content, mineral content, and various pore structure parameters of deep-marine shale in the study area with the total gas content were performed (Figure 13).

The results show that the specific surface area, total pore volume, and average pore diameter are not significantly correlated with the total gas content, with Pearson’s r values all less than 0.4 (Figure 13A–C); however, the TOC content is positively correlated with the total gas content, with a Pearson’s r value of 0.424 (Figure 13D). In addition, the micropore specific surface area and micropore volume are strongly positively correlated with the total gas content, with Pearson’s r values of 0.708 and 0.701, respectively (Figure 13E,F), indicating that the development degree of the micropores in the study area is the main factor controlling the gas content of deep-marine shale and that the shale gas is mainly adsorbed in the organic micropores [3]. On the other hand, the felsic mineral content is positively correlated with the total gas content and TOC content, with Pearson’s r values of 0.749 and 0.592, respectively (Figure 13G,H), indicating that the felsic minerals of the Wufeng Formation–Longyi₁ submember in the western Chongqing area are mainly derived from biogenic silica [50,51,52]. Previous researchers have shown that siliceous organisms (such as radiolarians and sponge spicules) aggregate to form high-silica and organic-rich aggregates, which increases their deposition rate in sediment water and effectively reduces the oxidation rate of organic matter in water, providing favorable conditions for the enrichment and accumulation of organic matter in shales [67]. Therefore, it is speculated that the massive reproduction and accumulation of siliceous organisms during the Late Ordovician Wufeng period to the early Silurian Longmaxi period were important factors influencing the formation of S¹ in the study area [50]. The clay mineral content and the total gas content showed a negative correlation, with a Pearson’s r value of −0.671 (Figure 13I). Samples with higher clay mineral contents generally have lower total gas contents, which may be related to the inhibition of micropore development by clay minerals [51].

According to the comparison of the gas content characteristics of the different lithofacies, the gas content of the organic-rich shale and medium-organic shale is generally greater than that of the organic-lean shale, and the gas content of the siliceous shale lithofacies is slightly greater than that of the mixed shale lithofacies.

5.4. Main Controlling Factors of Gas Enrichment and Advantageous Shale Lithofacies

Based on the correlation analysis of the TOC content, mineral content, pore structure parameters, and gas content, the results of pairwise correlation analysis between each parameter are displayed in a heatmap (Figure 14, values are Pearson’s r). The results show that deep-marine shale gas in the study area is mainly stored in micropores, and the degree of micropore development determines the gas content [40,45]. The development of micropores in deep-marine shale reservoirs is jointly controlled by the TOC content, felsic mineral content, and clay mineral content. Micropores mainly developed in organic matter, and organic pores contribute a large amount of the micropore specific surface area and micropore volume [67]. Therefore, for the overmature deep-marine shale in the study area, the TOC content directly controlled the degree of micropore development, while the felsic and clay mineral contents controlled the preservation and destruction of micropores during the deep burial process. Therefore, deep-marine shale with a high TOC content, high felsic mineral content, and low clay mineral content has the greatest exploration potential.

The discrimination of advantageous shale lithofacies is key for evaluating the economic value and resource potential of deep-marine shale [45,68,69]. Based on the evaluation of pore structure parameters and gas content, as well as the main factors controlling gas enrichment, the main lithofacies of the Wufeng Formation–Longyi₁ submember in the western Chongqing area were analyzed and compared. The results show that the source of S¹ was mainly biogenic silica, with a high TOC content and felsic mineral content. Moreover, organic micropores are well-developed in the organic matter, with a high micropore specific surface area and micropore volume, as well as a high total gas content; thus, S¹ could be considered an excellent advantageous lithofacies in the study area. The TOC content of S² is relatively low, but the content of felsic minerals is high. Organic pores are relatively developed in S², and the specific surface area, micropore volume, and total gas content are relatively high, so S² is assumed to be a moderately advantageous lithofacies in the research area. Organic-lean shales (including S³ and M³) have low TOC contents, underdeveloped organic pores, and relatively low micropore specific surface areas, micropore volumes, and total gas contents, indicating poor development potential. Overall, based on the analysis above, S¹ is regarded as the optimal choice for shale gas exploration in deep-marine shale formations with similar geological environments worldwide, followed by S². In contrast, the development potential of organic-lean shale is relatively limited.

6. Conclusions

The deep-marine shale of the Wufeng Formation–Longyi₁ submember in western Chongqing was selected as the research object, aiming to establish a suitable lithofacies classification scheme for deep-marine shale. Based on a comprehensive analysis of lithofacies types and correlation studies of key parameters, advantageous shale lithofacies were identified. The following conclusions have been drawn:

(1)

A suitable lithofacies classification scheme for deep-marine shale was established using the three-quartile statistical analysis method and mineralogical ternary diagrams. Based on this scheme, six main lithofacies have been identified in deep-marine shale, namely, organic-rich siliceous shale (S¹), organic-rich mixed shale (M¹), medium-organic siliceous shale (S²), medium-organic mixed shale (M²), organic-lean siliceous shale (S³), and organic-lean mixed shale (M³).

(2)

Through comparisons with various global marine shale formations, it was found that deep-marine shales exhibit greater burial depths, higher thermal maturity, and more intense tectonic activity. The increase in burial depth and compaction, coupled with intense tectonic activity, has resulted in a greater diversity of pore types in deep-marine shales, characterized by well-developed organic pores and microfractures, while intergranular pores are relatively small.

(3)

The development degree of the micropores is the main factor controlling the gas content of deep-marine shale, and the shale gas is mainly adsorbed in the organic micropores. The development of micropores in deep-marine shale reservoirs is jointly controlled by the TOC content, felsic mineral content, and clay mineral content. The degree of micropore development is directly controlled by the TOC content, whereas the felsic and clay mineral contents controlled the preservation and destruction of micropores in the process of deep burial.

(4)

Based on the investigation of the felsic mineral content, total gas content, and TOC content, it is concluded that the large-scale reproduction and accumulation of siliceous organisms during the Late Ordovician Wufeng period to the early Silurian Longmaxi period had an important influence on the formation of S¹.

(5)

By comparing the pore structure parameters and gas contents of the different lithofacies, it is concluded that S¹ has a high TOC content and felsic mineral content, well-developed organic pores, a large micropore specific surface area, a large micropore volume, and a high total gas content, making it an excellent advantageous lithofacies for deep-marine shale gas exploration. In contrast, the TOC content of S² is relatively low, but the felsic mineral content is high. Organic pores are relatively developed, with a relatively large specific surface area and micropore volume and high total gas content, so S² is assumed to be a moderately advantageous lithofacies. The TOC content, micropore specific surface area, micropore volume, and total gas content of the organic-lean shale (including S³ and M³) are relatively low, resulting in poor development potential. Therefore, in deep-marine shale with similar geological environments worldwide, S¹ is considered the best choice for shale gas exploration, followed by S².