The TOC content was performed using ta Leco-CS230 Carbon/Sulfur Analyzer (±5% accuracy) following the Chinese National Standard (GB/T 19,145-2003). Sample preparation involved pulverization to <200 mesh (75–90 μm). This was followed by hydrochloric acid treatment at 60 °C for 4 h to ensure complete removal of inorganic carbon, with periodic agitation to enhance reaction efficiency. Subsequent distilled water rinsing with oven-drying at 60 °C–80 °C. Mineralogical analysis was conducted using a Rigaku Smart Lab-9 XRD system following the Chinese Oil and Gas Industry Standard (SY/T) 5163-2010, with samples ground to <40 μm and pre-dried at 40 °C for 48 h.3.2.2 Field emission-scanning electron microscopy (FE-SEM).

Standardized cylindrical plugs were prepared through precision sectioning, followed by sequential surface processing: mechanical polishing with diamond abrasives and advanced argon ion beam milling to create ultra-smooth observation surfaces. High-resolution microstructural characterization was performed using a ZEISS Sigma 300 FE-SEM system, achieving nanoscale resolution of pore features.

Field measurements utilized brine-saturated containment vessels maintained at reservoir temperature for ≥72 h desorption monitoring. Subsequent laboratory analysis quantified residual gas content, with lost gas estimation through linear regression modeling (Ma et al., 2015). Isothermal adsorption experiments employed ultra-high purity methane (99.99%) under reservoir temperature conditions, measuring high-pressure CH₄ adsorption capacities on desiccated shale samples.

The Langmuir isothermal adsorption model, originally proposed by Langmuir (1918) for gas adsorption equilibrium analysis, has been widely adopted for quantifying adsorbed gas content in shale reservoirs. Subsequent studies (Zhang et al., 2017; Zhao et al., 2017b) refined the parameters of the Langmuir monolayer adsorption equation to better characterize shale methane adsorption isotherms. The fundamental equation is expressed as: V q = V L × P P + P L (6.1) where V q represents the adsorbed gas content (m³/t), P is the formation pressure (MPa), V L denotes the Langmuir volume (m³/t), and P L is the Langmuir pressure (MPa).

Equation 6.1 allows the calculation of adsorbed gas content V q under reservoir temperature and pressure conditions. Formation pressure (P) and temperature (T) vary with depth according to: P = P C × ρ w × g × H × 10 − 6 (6.2) T = T 0 + T G × H (6.3) where, P c is the formation pressure coefficient (dimensionless), ρ w is water density (g/cm³), g is gravitational acceleration (N/kg), H is burial depth (m), T is formation temperature (°C), T₀ is surface temperature (°C), and T G is the geothermal gradient (°C/m).

By incorporating region-specific values of P c and T 0 for the Yaziluo Rift Trough, Equations 6.2,6.3, enable the determination of formation pressure (P) and temperature (T) at varying burial depths for drill core samples.

In addition, shale gas content is governed by multiple factors, necessitating parameter calibration to account for organic carbon content (TOC) and variations in formation temperature across samples (Lewi et al., 2004). Temperature-dependent corrections are applied using the following equations: V l t = 10 − C 3 × T + C 4 (6.4) P l t = 10 C 7 × T + C 8 (6.5) C 4 = log ⁡ V L + C 3 × T i (6.6) C 8 = log ⁡ P L + − C 7 × T i (6.7) where V l t is the temperature-corrected Langmuir volume ( V L , m³/t), P l t is the temperature-corrected Langmuir pressure ( P L , MPa), T_i is the standard temperature (°C) set during isothermal adsorption experiments, T is the formation temperature (°C), and the coefficients C3 and C7 are 0.0027 and 0.005, respectively.

TOC-based correction is integrated into the model: V l c = V l t × TOC TOC lg (6.8) where V l c is the Langmuir volume (m³/t) calibrated for both formation temperature (T) and TOC, and T O C lg represents the TOC (%) derived from well-logging data interpretation.

The refined Langmuir model for adsorbed gas content, incorporating temperature and TOC corrections, is expressed as: V L t = V l c × P P + P l t (6.9) where V L t is the adsorbed gas content (m³/t) and P is the reservoir pressure (MPa).

To account for the 10% reduction in methane adsorption capacity due to moisture content (Zhang et al., 2017), the final equation becomes: V a d s = V l c × P P + P l t × 90 % (6.10) where V a d s denotes the fully calibrated adsorbed gas content (m³/t).

Ambrose et al. (2011) proposed that adsorbed-phase gas occupies free gas pore space, necessitating volumetric correction (Tian and Yang, 2016; Guo et al., 2023). The maximum pore volume available for free gas equals the total shale pore volume minus the adsorbed-phase pore volume, as expressed by: V f = V p − V a (6.11) where V f is the maximum free-phase pore volume under reservoir conditions (cm³/g), V p denotes the total shale pore volume (cm³/g), and V a represents the adsorbed-phase pore volume (cm³/g).

Accoding to the free gas calculation model proposed by Yang and Guo, 2022, the adsorbed-phase pore volume is calculated as: V a = V s · ρ s t d ρ a d s (6.12) where V s is the standard-state adsorbed methane volume (cm³/g), ρ s t d is the methane density at standard conditions (0.716 × 10⁻³ g/cm³), and ρ a d s is the adsorbed methane density under subsurface conditions (g/cm³).

The standard-state free methane volume is expressed as: V f r e e = V f · ρ N ρ s t d · S g (6.13) where V f r e e is the maximum free gas volume under standard conditions (cm³/g), and ρ N is the methane density under reservoir conditions.

Subsequent studies (Shi et al., 2015; Zhang et al., 2017) have proposed a TOC-based method for determining shale water saturation, where gas saturation (S_g) and water saturation (S_w) are interconvertible through the following expressions: S w = T O C b / T O C n · 100 % , S g = 1 − S w × 100 % (6.14) where S_w represents water saturation (%), S_g denotes gas saturation (%), TOC_b is the total organic carbon content of non-reservoir intervals at equivalent burial depth, TOC is the measured TOC value of the shale reservoir, and n is the gas saturation index, typically ranging from 2 to 3 in shale reservoirs.

By substituting Equation 6.11 into Equation 6.12 and combining the result with Equation 6.13 and Equation 6.14, the free gas volume under shale formation conditions can be derived as: V f r e e = V p − V s · ρ s t d ρ a d s · ρ N I S T ρ s t d · S g (6.15) where V f r e e denotes the standard-state free gas content (m³/t).

This shale association includes Calcareous Siliceous Shale Lithofacies (S-1) and Mixed Siliceous Shale Lithofacies (S-2), whose organic carbon content (TOC) ranges from 1.46% to 5.70%, with an average content of 3.63% (Table 1). The S-1 lithofacies is characterized by grayish-black siliceous mudstone with calcite vein fillings (Figure 5A). Mineralogically, quartz dominates (49.2% avg.), followed by clay minerals (20.5% avg.), while calcite, dolomite, plagioclase, and pyrite collectively account for less than 10% (Figure 4). Petrographic analysis reveals an argillaceous-siliceous matrix with heterogeneous ferruginous-organic distribution. Calcite laminae exhibiting first-order white interference colors alternate with organic-rich layers (Figure 5B). The S-2 lithofacies predominantly consists of black siliceous mudstone with abundant pyrite (Figure 5C). Mineralogically, quartz constitutes the dominant component (62.4% avg.), followed by clay minerals (18.2% avg), and calcite (9.9% avg.) (Figure 4). Compared to S-1 lithofacies, it exhibits 13.2% quartz increase and 2.3% clay reduction. Petrographic analysis reveals that the matrix contains clay-quartz-pyrite assemblages with anhedral to subhedral quartz grains (0.005–0.06 mm) and lamellar pyrite structures (Figure 5D).

This shale association contains Calcareous/Siliceous Mixed Shale Lithofacies (M-1) and Argillaceous/Siliceous Mixed Shale Lithofacies (M-2), whose TOC content ranges from 0.86% to 3.51% with a median of 1.80% (Table 1). The M-1 lithofacies features black calcareous mudstone with sporadic pyrite (Figure 5E). Mineral composition includes quartz (42.5% avg.), calcite (32.7% avg.), and clay minerals (17.3% avg.) (Figure 4). Petrographic observations reveal the matrix primarily contains angular quartz and minor feldspar fragments (0.02–0.06 mm). Subordinate calcite occurs as fine granular particles (0.02–0.05 mm) intermixed with clay minerals. Accessory pyrite manifests as black granular particles, while organic matter appears as black amorphous clots within the argillaceous matrix (Figure 5F). The M-2 lithofacies displays grayish-black calcareous mudstone with silty laminae (Figure 5G). Mineral composition is dominated by quartz (44.1% avg.) and clay minerals (30.9% avg.), followed by calcite (15.2% avg.) (Figure 4). Compared to the M-1 lithofacies, it demonstrates significantly higher clay mineral content. Petrographic analysis reveals a matrix predominantly composed of microcrystalline/cryptocrystalline clay mineral aggregates with yellowish-brown coloration. Detrital components consist mainly of monocrystalline quartz grains (0.03mm–0.1 mm), micritic calcite, and pyrite aggregates with organic clots (Figure 5H).

This shale association comprises Mixed Calcareous Shale Lithofacies (C-2) and Argillaceous-Bearing Calcareous Shale Lithofacies (C-3), whose TOC content ranges from 0.56% to 1.63%, with an average value of 0.99% (Table 1). The C-2 lithofacies primarily consists of grayish argillaceous limestone (Figure 5I). Mineral composition is dominated by calcite (average 38.0%) and dolomite (average 25.7%), followed by quartz (15.5%) and clay minerals (18.9%) (Figure 4). The micritic calcite matrix (<0.01 mm) contains subhedral-euhedral dolomite (0.02–0.05 mm) and organic clots (0.05–0.2 mm) (Figure 5J). The C-3 lithofacies is characterized by grayish-black calcareous mudstone, locally intercalated with siltstone (Figure 5K). Mineral composition remains carbonate-dominated, with calcite (average 27.7%) and dolomite (average 23.7%), followed by clay minerals (average 31.4%), and quartz (average 13.8%) (Figure 4). Compared to the C-2 lithofacies, it exhibits a 70% relative increase in clay mineral content. Petrographic observations demonstrate a microcrystalline clay mineral matrix containing cryptocrystalline quartz, dolomite grains (0.03–0.08 mm), and pyrite aggregates (5–20 μm) (Figure 5L).

Basin facies shale exhibit the most developed organic pore, occupying quartz-inorganic mineral interstices and clay aggregates (Figures 6A–D). In contrast, lower slope facies shale demonstrate reduced organic pores, where organic matter pores frequently coexist with clay minerals as composite structures. Pore diameters range from several nanometers to hundreds of nanometers, displaying circular, elliptical, or irregular morphologies (Figures 6E–H). The upper slope facies shales generally exhibit poorly developed organic pore. Organic matter predominantly occurs as elongated or irregularly shaped particles interspersed among inorganic minerals, with limited intraparticle pore. Brittle minerals such as carbonates act as rigid frameworks, providing mechanical support and preservation for organic pores. Additionally, composite structures of organic matter and clay minerals are observed, with pore diameters reaching up to hundreds of nanometers (Figures 6I–L).

Inorganic pores in the basin facies shale are predominantly composed of intragranular dissolution pores supported by rigid minerals (Figures 7A–D). The lower slope facies shale exhibit more developed inorganic pores, primarily including clay mineral interlayer pores, intergranular pores, intragranular pores, and partial pyrite intercrystalline pores. Their diameters vary significantly, ranging from tens of nanometers to several micrometers, with the largest extending into micron-scale fracture pores. Intergranular pores are mainly distributed along the edges of quartz and calcite grains, exhibiting triangular or irregular polygonal shapes. Intragranular pores, typically sub-circular, elliptical, or irregular polygonal in form, occur within quartz and carbonate minerals (Figures 7E–H). In the shale of upper slope facies, inorganic pores are dominated by dissolution-derived pores intersecting with clay/pyrite pores, forming interconnected networks (Figures 7I–L). Additionally, discordant contacts between inorganic minerals and clay mineral edges, influenced by matrix-mineral interfacial relationships, create slit-shaped pores or fractures with widths ranging from tens to hundreds of nanometers.

Microfractures in basin and lower slope facies shales are primarily distributed along mineral edges and within mineral grains. Most microfractures exhibit favorable extensibility, with lengths reaching tens of micrometers and widths ranging from tens to hundreds of nanometers. Edge microfractures, predominantly diagenetic shrinkage fractures, form at the boundaries of clay and inorganic minerals. Intragranular fractures, caused by stress release during tectonic activity, penetrate mineral grains, extending for several to tens of micrometers, thereby enhancing pore connectivity (Figures 8A–H). Microfractures in upper slope facies shales are more extensively developed, primarily generated by overpressure from hydrocarbon generation and tectonic stresses. These microfractures display parallel alignment or mutual intersection. Microfractures widths can exceed 1 μm, and lengths may span tens to hundreds of micrometers (Figures 8I–L).

Isothermal methane adsorption experiments were conducted under formation temperature conditions corresponding to different samples, yielding adsorption capacities under varying pressure conditions. The Langmuir model (Equation 6.1) was subsequently applied to obtain the methane saturated adsorption gas content (V_L) under formation conditions. The shale association of upper slope facies displayed the lowest methane saturation adsorption capacity (V_L), ranging from 0.60 m³/t to 1.49 m³/t with an average of 1.07 m³/t. The lower slope facies shale association showed intermediate values, with Langmuir adsorption content (V_L) values ranging from 1.01 m³/t to 3.67 m³/t and averaging 2.19 m³/t. In contrast, the shale association of basin facies exhibited the highest methane adsorption capacity, demonstrating V_L values between 2.23 m³/t and 3.63 m³/t, with a mean value of 2.90 m³/t (Table 1).

The gas content of basin facies shale association ranges from 0.04 m³/t to 0.14 m³/t, representing the lowest values among the three sedimentary facies analyzed. In contrast, shale association of upper slope facies exhibit significantly higher gas concentrations, with measured values spanning 0.51 m³/t to 2.58 m³/t and a mean value of 1.16 m³/t. Comparatively, lower slope facies shale association demonstrate the most substantial gas storage capacity, displaying a gas content range of 0.34 m³/t to 2.62 m³/t and achieving the highest average value of 1.40 m³/t (Table 1).

The adsorbed gas content ( V a d s ) and the standard-state free gas content ( V f r e e ) for 14 shale samples were quantitatively evaluated, with detailed results presented in Table 2. Basin facies shale association exhibit the highest theoretical gas content (2.90 m³/t avg.), with adsorbed gas dominating at 1.98 m³/t (68.28%) and free gas contributing 0.92 m³/t (31.72%), but near-zero measured values. The lower slope facies shale association show moderate theoretical gas content (1.81 m³/t avg.) with the highest measured gas content. It remains predominantly adsorbed gas-rich, containing 1.67 m³/t adsorbed gas (66.80%) and 0.83 m³/t free gas (33.20%). Shale association of upper slope facies shale exhibits the lowest theoretical values (1.70 m³/t avg.) while showing intermediate measured contents. Obviously, there is a clear discrepancy between the theoretical gas content and the actual measured values. The lower slope facies shale association, characterized by moderate hydrocarbon generation capacity and reservoir properties, paradoxically exhibits the highest measured gas content. In contrast, the basin facies shale association, despite demonstrating optimal hydrocarbon-generating potential and superior reservoir performance, shows not only significantly lower measured gas content than the lower slope facies but also falls below that of the upper slope facies.

The basin facies shale association predominantly consists of continuous thick-bedded siliceous mudstone (S-1 and S-2) characterized by the complete absence of argillaceous limestone interbeds. Despite demonstrating superior source-reservoir quality parameters compared to other shale associations, it paradoxically exhibits the lowest gas content. A systematic analysis of high-quality shale interval in Well A (1919m–1940 m; Figure 9) reveals distinctive shale gas accumulation patterns, providing critical insights into the gas-bearing mechanisms of high-quality shale reservoirs but low-gas-content. The extremely low carbonate mineral content in these shale formations is a key contributor to their reduced triaxial stress strength. Under multi-phase tectonics stresses, progressive fracturing initiates at microscopic scales when external stresses surpass rock strength under confining pressure conditions (Gale et al., 2022; Li et al., 2025; Wang et al., 2025). This fracturing process systematically upscales to macroscopic dimensions, generating extensive high-angle fractures and causing structural disintegration of shale units (Figure 9). In addition, the absence of argillaceous limestone interlayers critically compromises the formation of effective upper seals. Consequently, the combined structural and seal failures create interconnected gas migration pathways, ultimately leading to gas escape.

The lower slope facies shale association comprises calcareous mudstones dominated by M-1 and M-2 lithofacies, which is interbedded with argillaceous limestone layers primarily composed of C-2 lithofacies. Well B is selected as a representative lower slope facies example, with detailed analysis focused on the interval (1,537m–1555 m) where peak gas logging responses were recorded (Figure 10).

The interval below 1548 m exhibits distinct fracture development characteristics, dominated by bedding-parallel fractures, horizontal fractures, and low-angle intrastratal fractures (Figure 10). This interval demonstrates significant gas-bearing potential, with gas logging values exceeding 30% and a vertical gas anomaly spanning approximately 5 m (Figure 10). The maximum on-site measured gas content of 1.63 m³/t confirms this unit as a high gas-bearing layer. With increasing depth shallowing upward, the lithology gradually transitions to argillaceous limestone, accompanied by a progressive increase in carbonate mineral content and a concurrent decrease in clay minerals. This mineralogical evolution creates a pronounced brittleness contrast between lithologies (He et al., 2024; Wang et al., 2025). Higher clay content and lower carbonate content can enhance ductility, showing significant negative correlation with triaxial stress strength (Sone and Zoback, 2013; Rybacki et al., 2015; Herrmann et al., 2018). Evidently, the clay minerals of shale predominantly act as ductile components, displaying a significant negative correlation with triaxial stress strength, thereby impeding stress resistance enhancement (Rybacki et al., 2015; Herrmann et al., 2018). In contrast, carbonate mineral content exhibits a strong positive correlation with shale triaxial stress strength, while siliceous mineral content shows no statistically significant relationship (Sone and Zoback, 2013; Herrmann et al., 2018; Zou, et al., 2023). This disparity arises from the superior mechanical strength of carbonate minerals significantly enhances bulk shale stress resistance (Gao et al., 2017; He et al., 2024).

At the lithological transition boundary (1,547.8 m), sporadic high-angle fractures (<0.1 m in length) interconnect with bedding-parallel fractures, forming a complex fracture network within 2–3 m vertical range. This structural heterogeneity enhances gas migration efficiency by through improved fracture connectivity (Zhao et al., 2017a; Zhu, et al., 2019; Chen, et al., 2022). Micron-scale fractures (5–20 μm) and dissolution pores in inorganic minerals synergize with nanopore networks, expanding effective flow areas and enhancing localized storage capacity (Qiao et al., 2020; Wu et al., 2023). Notably, 20–30 cm thick gas-bearing intervals persist in transition-adjacent argillaceous limestone, demonstrating persistent hydrocarbon accumulation potential under such petrophysical conditions.

With further upward shallowing of depth, the carbonate mineral content progressively increases while clay mineral content diminishes, leading to enhanced triaxial stress strength within the shale that exceeds external stress intensity (Sone and Zoback, 2013; Rybacki et al., 2015; Yang et al., 2025b). This results in a highly compacted lithology with minimal fracture development, effectively ceasing deformation and maintaining structural stability (Zhu et al., 2025; Yang et al., 2025b). These mechanical properties establish a direct caprock that effectively seals the underlying gas-bearing layers. In addition, the sealing system is further enhanced by the underlying Devonian Wuzhishan Formation. This formation predominantly consists of micritic-siliceous limestones with regional thicknesses of 80–120 m and permeability below 0.01 mD (Mei et al., 2007; Huang et al., 2013; Mei et al., 2013), functioning as an effective basal seal that significantly inhibits vertical migration.

The upper slope facies shale association is predominantly composed of calcareous mudstone dominated by the C-3 lithofacies, interbedded with argillaceous limestone layers primarily consisting of the C-2 lithofacies. Compared to the lower slope facies, this shale association contains a higher frequency and greater cumulative thickness of interbeds. Taking the well C in the upper slope facies as a representative example, the 1,679m–1688 m interval with elevated gas logging values was selected to systematically analyze the shale gas accumulation patterns (Figure 11).

The upper slope facies shale association exhibits vertically continuous calcareous mudstone units compartmentalized by interbedded argillaceous limestone layers, resulting in enhanced lithological heterogeneity. Within this configuration, the basal calcareous mudstone functions as the primary gas source, where organic matter preferentially fills microfractures in banded distribution patterns (Figures 6I,K). Intermediate argillaceous limestone interlayers demonstrate effective connectivity of dissolution pores and microfractures near lithofacies transition zones (Figures 8I–L), forming favorable reservoir intervals. Conversely, distal interlayer segments develop competent caprocks that effectively seal underlying reservoirs. The overlying calcareous mudstone above these interlayers lacks direct caprock confinement, resulting in negligible gas logging anomalies and significantly reduced measured gas content (Figure 11).

Notable differences exist in “source-reservoir-seal” configurations between upper and lower slope facies association. The calcareous mudstone of upper slope facies (predominantly comprising C-3 lithofacies) demonstrates constrained hydrocarbon potential due to its reduced thickness (typically <5 m), lower TOC content (averaging 0.99 wt%), and limited adsorption capacity (averaging V_L = 1.07 m³/t). These constraints produce narrow gas-bearing interval with gas logging anomalies spanning approximately 2 m (Figure 11), substantially less pronounced than lower slope facies counterparts. Furthermore, thickened argillaceous limestone interlayers (3m–5 m vs. 1m–2 m in lower slope facies) enhance sealing capacity through increased caprock thickness, as evidenced by formation pressure coefficients reaching 1.18 (over pressured conditions) in Well C. The over pressured system promotes efficient gas accumulation along lithofacies transition zones, resulting in pronounced gas logging anomalies characterized by rapid amplitude increases during drilling penetration.