Investigation of Main Control Factors Governing Gas-Bearing Capacity in Deep Marine Shales: Insights from Quantitative Characterization of Quartz of Multiple Origins

Abstract

Deep shale gas in western Chongqing is a critical successor to conventional resources, but its distinct enrichment mechanisms make sweet-spot identification—particularly of productive layers—significantly challenging. To address this, we developed an integrated approach combining high-fidelity gas-content testing under simulated high-temperature, high-pressure (HTHP) conditions with advanced mineralogical characterization using automated mineralogy (TIMA). Four exploration wells in comparable sedimentary-structural settings were analyzed to establish correlations between reservoir properties and gas content. Results show that the lower Longmaxi Formation in central-western Chongqing exhibits optimal reservoir quality, with high porosity, total organic carbon (TOC), brittleness, and gas content. A substantial free-gas fraction enhances recoverability. The reservoir's quartz-organic matter microfacies provides strong mechanical brittleness, adsorption capacity, and gas supply. High TOC and abundant authigenic microcrystalline quartz are key controls on gas accumulation. These findings clarify the geological drivers of deep shale gas enrichment and provide a direct basis for geology-engineering integration in sweet-spot optimization and development planning.

Keywords

Western Chongqing region deep shale gas gas-bearing capacity main control factors multisource quartz authigenic quartz

Introduction

In recent years, China's shale gas exploration and development has gradually shifted toward deep and ultra-deep enrichment zones, with remarkable breakthroughs achieved in the Sichuan Basin and its surrounding areas (Ma et al., 2022; Zhang et al., 2021). From an exploration perspective, the geological resources of middle-deep shale gas (burial depth: 3500–4500 m) in the Sichuan Basin amount to 9.45 trillion cubic meters, accounting for approximately 50% of the total shale gas resources in the basin. Among these, Chongqing's middle-deep shale gas geological resources reach 3.56 trillion cubic meters, representing 38.8% of the basin's total middle-deep shale gas resources. Notably, 47.9% of Chongqing's middle-deep shale gas (approximately 1.71 trillion cubic meters) is distributed in the western Chongqing region, and subsequent studies have further confirmed the considerable exploration potential of deep shale gas in this area (Dong et al., 2018; Fu et al., 2021).To date, China has well-established geological theories, enrichment mechanisms, and geological evaluation-selection methods for shallow shale gas (burial depth ≤ 3500 m) (Gao et al., 2022; Guo et al., 2017; Liu et al., 2023; Nie et al., 2022). Nevertheless, the geological conditions of deep shale gas reservoirs (burial depth > 3500 m) are significantly more complex, characterized by high-temperature and high-pressure (HTHP) reservoir environments, as well as intricate variations in reservoir physical properties, gas-bearing capacity, and pressure potential (He et al.,2023;Liang et al.,2022; Nie et al.,2023). A comprehensive understanding of these deep reservoir characteristics is therefore essential for advancing deep shale gas exploration and development. In response to the demand for efficient and economical development of deep shale gas, there is an urgent need for targeted research on the “geological-engineering integration sweet spot optimization technology” for deep shale reservoirs. The core of this technology revolves around three key criteria: geological feasibility (superior gas-bearing capacity), engineering operability (favorable fracability), and economic viability (cost-effectiveness) (Bowker, 2007). However, the key indicators for geological-engineering integration sweet spot optimization are strongly influenced by the unique characteristics of deep reservoirs under complex geological conditions, which differ substantially from those of shallow and middle-depth reservoirs (Shi et al., 2022; Zhang et al., 2022). Thus, a refined characterization of the geological features, as well as the identification of main control factors governing the occurrence and enrichment of deep shale gas, are critical to providing scientific support for deep geological-engineering integration sweet spot prediction and guiding the efficient and economical development of shale gas (He et al., 2023; Ma et al., 2022; Nie et al., 2022; Zhao et al., 2021).

Based on 12 analytical tests conducted on 129 core samples, this study integrates, for the first time, an optimized gas-content testing method tailored for deep high-temperature/high-pressure (HTHP) conditions with Tescan Integrated Mineral Analyzer (TIMA)-based quantitative mineral characterization. This approach establishes a complete technical workflow of “quartz origin identification → quantitative characterization → gas content measurement.” Through a comprehensive evaluation of four exploration wells in western Chongqing, we systematically reveal that authigenic microcrystalline quartz enhances gas-bearing capacity by constructing a rigid framework and optimizing organic matter-pore configuration, thereby advancing the research focus from “provenance identification” to the “coupling mechanism between reservoir quality and gas-bearing capacity.” Furthermore, we propose that high TOC content coupled with abundant authigenic microcrystalline quartz serve as dual key parameters for geology-engineering integrated sweet-spot optimization, providing direct guidance for efficient development (Hou et al., 2023).

Geological background of shale gas enrichment in western Chongqing

Structural deformation characteristics

The Western Chongqing Block is situated in the southeastern part of the gentle structural zone of the Central Sichuan Ancient Uplift and the southwestern segment of the Southeast Sichuan Depression-Fold Belt. The northwestern part of the block exhibits a gentle structural setting with poorly developed faults, featuring a flat terrain and well-developed water systems. In contrast, the remaining areas are characterized by steep structural configurations and relatively well-developed faults, though faults in the fold wing regions are poorly developed (Wang et al., 2023) (Figure 1).

Figure 1.

Tectonic background and bore location of the study area.

Stratigraphic development characteristics

The primary gas-bearing shale horizons in the study area are the Lower Ordovician Wufeng Formation and Upper Silurian Longmaxi Formation, with burial depths ranging from 3500 to 4500 m (Nie et al., 2022). Based on lithological, electrical, and paleontological characteristics, the Longmaxi Formation is subdivided into two members: Long2 and Long1. The Long1 member is further divided into two submembers: Long1–1 and Long1–2.Reservoirs of the Wufeng Formation and Longmaxi Formation are laterally continuous and stable, with high-quality shale thickness exceeding 50 m. The dominant lithotypes include carbonaceous shale, grayish-black shale, and silty shale. Shale reservoirs of the Wufeng Formation and Long1 submember are characterized by darker colors, with well-developed graptolite-rich horizontal bedding. Thin-section observations reveal fine grain sizes and low contents of terrigenous clastic particles. Within the Longmaxi Formation, the content of terrigenous clastics increases upward, accompanied by weakened horizontal bedding development and enhanced silty lamina development (Han et al.,2023;Zhao et al., 2021) (Figure 2).

Figure 2.

Lithologic characteristics of Wufeng formation–Longmaxi formation in western Chongqing. (a) Well Z-3, 4104.94 m, Wufeng Formation, Organic shale, Rich in graptolite; (b) Well Z-3, 4107.72 m, Wufeng Formation, Radiolaria siliceous shale; (c) Well Z-3, 4089.77 m, Lower Longmaxi Formation, Organic shale; and (d) Well Z-3, 4097.68 m, Lower Longmaxi Formation, Organic siliceous shale, Horizontal diagenetic joint filled by calcite.

Petrographic characteristics of the reservoir

The microfacies of shale reservoirs in the Wufeng Formation and Longmaxi Formation of the study area are dominated by quartz and clay minerals. Quartz constitutes the primary brittle mineral, while clay minerals are predominantly illite, with minor illite-montmorillonite mixed-layer minerals (Table 1). This reflects a high degree of reservoir diagenetic evolution, having reached the late diagenetic stage without progressing to very low-grade metamorphism (Nie et al., 2022).

Table 1.

Mineral component types and content proportion characteristics of representative shale reservoir.

Sample number	Layer	Mineral mass fraction (wt.%)
Sample number	Layer	Quartz	Carbonate minerals	Feldspar	Illite	Chlorite	Illite + montmorillonite	Pyrite
0036	S₁l Upper	36.1	3.1	6.6	34.6	11.0	4.5	4.1
0041	S₁l Upper	37.9	3.5	7.4	28.1	20.3	0	2.8
0049	S₁l Middle	39.8	15.9	7.9	22.3	7.0	0	7.1
0056	S₁l Middle	47.0	14.3	7.9	15.3	4.2	8.4	2.9
0067	S₁l Lower	56.1	4.3	10.0	18.2	8.5	0	2.9
0072	S₁l Lower	51.3	12.2	10.1	17.1	6.7	0	2.6
0079	S₁l Bottom	66.9	6.1	3.2	14.4	4.1	0	5.3
0081		54.6	22.9	3.1	15.3	2.1	0	2.0
0083		70.1	11.3	3.7	10.1	1.6	0	3.2
0086	O₃w	83.5	3.3	2.4	6.7	2.2	0	1.9
0089		62.0	9.2	5.2	18.2	3.9	0.7	0.8
0091		39.2	12.1	6.0	26.9	15.8	0	0
Average		53.7	9.9	6.1	18.9	7.3	1.1	3.0

Conventional core analysis indicates that the porosity of shale reservoirs in the Wufeng and Longmaxi Formations ranges from 0.97% to 5.67%. The maximum porosity (5.67%) is observed in the bottom of the Longmaxi Formation, with vertical high-porosity zones distributed from the middle-upper interval of the Wufeng Formation to the lower-to-bottom intervals of the Longmaxi Formation.

In this study, 3D CT scan reconstruction data were employed for comparative analysis of reservoir pore system characteristics. 3D CT scan structures of different intervals in the Wufeng and Longmaxi Formations from the Z-3 borehole are presented in Figure 3. Samples from the middle-upper interval of the Longmaxi Formation (Figure 3a–b) exhibit pore space zoning and limited microfracture development, with overall poor pore development. For samples from the middle-lower interval of the Longmaxi Formation (Figure 3(c) and –(d)), pore space development is significantly reduced, and interconnected pore connectivity is impaired. This interval also displays pore space zoning attributed to vertical variations in rock composition, accompanied by a marked increase in the spatial heterogeneity of microscopic reservoir spaces.

Figure 3.

Three-dimensional structure of CT scan in different layers of Wufeng formation–Longmaxi formation.

Pore clusters are most well-developed in the bottom intervals of both the Wufeng and Longmaxi Formations. Samples from the Wufeng Formation bottom interval exhibit microfractures and deformation, induced by microscale structural effects. In contrast, the pore system of samples from the Longmaxi Formation bottom interval is relatively well-developed, with a scattered yet dense pore distribution (Figure 3(e) and (f)).

Sampling and analytical methods

Sample collection

The samples utilized in this study were collected from four exploration wells in the Western Chongqing Block, with sampling depths ranging from 3300 to 4200 m. A total of 129 core samples were obtained, covering the key gas-bearing intervals of the Wufeng and Longmaxi Formations.

Analytical tests and equipment

Twelve analytical tests were conducted to characterize the reservoir and gas properties, including on-site gas content measurement, scanning electron microscopy (SEM) observation, gas composition analysis, methane isotope determination, thin-section identification, nano-CT scanning, as well as analyses of porosity, permeability, mineral composition, total organic carbon (TOC) content, and organic matter maturity. Except for the TIMA mineral quantitative analysis, all tests were performed at the Analytical and Experimental Center of the Exploration and Development Research Institute, PetroChina Southwest Oil & Gas Field Company. TIMA mineral quantitative analysis was carried out at the Science Park Laboratory of Nanjing University, enabling precise quantitative characterization of quartz particle sizes from multiple sources (Luo et al., 2024; Wang et al., 2024).

Method optimization and quality control

To accurately simulate the reservoir environment of the study area with burial depths >3500 m, temperatures >90°C, and pressures >70 MPa, key modifications were implemented on the analysis canister of the field gas-content testing apparatus: (a) an infrared heating module was integrated to enable programmed heating above 90°C, replicating in-situ formation temperature; and (b) the sample chamber was filled with quartz sand to simulate formation confining pressure and reduce the dead volume between crushed sample particles. These improvements aim to make the desorption process more closely approximate the gas-release kinetics under true geological conditions. Tests were conducted in accordance with the Chongqing Local Standard Measurement and Technical Specification for Shale Gas Content (issued in December 2019) to ensure data reliability.

In contrast to the conventional USBM direct method typically conducted at ambient or lower temperatures (<90°C), the HTHP-simulated test employed in this study enhances the desorption temperature, thereby more effectively liberating free-state gas stored in micro- to nano-scale pores and fractures of the reservoir. This modification allows for a more accurate representation of the dominant free-gas occurrence characteristic of deep, over-mature shale gas systems.

Taking Well Z-2 as an example, for core samples from the same interval, the conventional USBM method yielded lost gas contents ranging from 0.05 to 2.43 m³/t (average 1.00 m³/t) and total gas contents of 0.67–5.12 m³/t. In contrast, the modified HTHP method produced lost gas contents of 0.23–3.57 m³/t (average 1.50 m³/t) and total gas contents of 0.86–6.26 m³/t. The results from the improved method show better agreement with the actual production data of this well, thereby confirming the reliability of the modified approach.

Data analysis framework

A comprehensive data analysis workflow was established as follows.

Basic geological conditions for shale gas enrichment in western Chongqing were determined through experiments on newly drilled core samples, including reservoir material composition, physical properties, pore structure, and mechanical characteristics. Residual gas testing based on the ideal gas state equation and lost gas recovery via the curve polynomial method were integrated with on-site gas content measurements to accurately quantify gas-bearing capacity. Microscopic identification combined with the TIMA mineral analysis system was employed to quantitatively characterize quartz from multiple sources, revealing the gas enrichment mechanism of high-brittle shale reservoirs. Key control factors governing the gas-bearing capacity of deep shale in the Western Chongqing Block were identified through systematic integration of all test data.

Gas-bearing characteristics of deep marine shale in western Chongqing

A quantitative evaluation of gas-bearing capacity was conducted on 129 core samples from four exploration wells (Wells Z-2, Z-3, Z-5, and Z-6) in the Western Chongqing Block. Key parameters analyzed included total gas content, desorbed gas content, vertical distribution of gas-bearing capacity, and the proportion of lost gas and residual gas (Shen et al., 2023).

Well-specific gas-bearing characteristics

Well Z-2: Total gas content ranges from 0.86 to 6.26 m³/t (average: 3.56 m³/t). Lost gas dominates (24–65% of total gas), followed by desorbed gas (17–51%) and trace residual gas (0.19–0.44 m³/t). Vertically, superior gas-bearing capacity is observed in the middle-lower intervals (3872–3896.17 m) compared to the upper section (Figure 4).

Figure 4.

Gas content evaluation of Well Z-2, Z-3, Z-5, and Z-6 in West Chongqing.

Well Z-3: Total gas content is 1.23–6.74 m³/t (average: 3.47 m³/t). Lost gas accounts for 29–78% of total gas, with desorbed gas (10–24%) and residual gas (0.3–0.72 m³/t) as minor components. Middle-lower intervals (4076–4107 m) exhibit better gas-bearing performance (Figure 4).

Well Z-5: The highest gas-bearing capacity among the four wells, with total gas content of 1.25–12.75 m³/t (average: 5.51 m³/t). Lost gas constitutes 81–92% of total gas, while desorbed gas (6–16%) and residual gas are negligible (Figure 4). Optimal gas-bearing intervals are the middle-lower sections (3326–3351 m), with the Longmaxi Formation bottom reaching 9.83–12.75 m³/t; the well's test production is 92,600 m³/d.

Well Z-6: Total gas content is 0.6–9.83 m³/t (average: 4.73 m³/t), higher than Well Z-3 and significantly exceeding that in southeastern/northeastern Chongqing. Lost gas contributes 67–89% of total gas, followed by desorbed gas (10–29%) and trace residual gas (0.02–0.14 m³/t). Vertically, favorable gas-bearing intervals are the middle (4238–4250 m) and lower (4260–4270 m) sections (Figure 4).

Planar and overall gas-bearing characteristics

The reservoir properties and gas-bearing capacity of the Longmaxi Formation exhibit systematic variations both vertically and laterally: (1) Vertically, the optimal reservoir is concentrated in the lower section of the Long-1 member, characterized by “four-high” attributes: high porosity, high TOC, high brittleness, and high gas content. Reservoir quality deteriorates upward. (2) Laterally, gas-bearing capacity follows a “central superior, northern and southern inferior” pattern, which aligns with structurally stable areas such as the Xishan Anticline. This indicates that favorable preservation conditions are key to the lateral heterogeneity. (3) Main controlling factors: Vertical variations are primarily governed by sedimentary microfacies (i.e., the enrichment of silica and organic matter), whereas lateral differences are jointly controlled by the intensity of post-depositional tectonic modification. （4） Overall, the total gas content of deep marine shale in western Chongqing ranges from 0.6 to 12.75 m³/t, with lost gas accounting for 24–92% of the total. This confirms that shale gas in the study area is dominated by free gas, which is conducive to exploitation (Fu et al., 2021).

Main controlling factors of deep marine shale gas-bearing capacity in western Chongqing

Shale gas-bearing capacity is governed by internal and external factors. Given the consistent tectonic-sedimentary background of the four selected wells, this study focuses on internal factors—that is, the control of reservoir properties on gas-bearing capacity—including TOC, Ro, porosity, quartz content, and clay mineral content (Guo et al., 2017; Shi et al., 2022; Chen et al., 2023; Wu et al., 2022).

Total organic carbon (TOC) content

Correlation analysis of gas-bearing capacity and TOC in Wells Z-3 and Z-6 reveals that lost gas, desorbed gas, and total gas content are significantly positively correlated with TOC, residual gas, and TOC show an extremely significant and strong negative correlation. This pattern is consistent with the occurrence characteristics of shale gas -gas in shale with high TOC is more easily desorbed, and the amount of gas remaining in the rock is relatively less (Figure 5). This trend is consistent with the relationship between gas production and TOC (Figure 6), confirming TOC as a key factor regulating shale gas-bearing capacity.

Figure 5.

Correlation analysis of shale gas content and organic carbon content in western Chongqing. (a) WellZ-3: n = 47, lost gas: R = 0.83/P = 0.000, desorbed gas: R = 0.89/P = 0.000, total gas content: R = 0.84/P = 0.000, and residual gas: R = −0.17/P = 0.235. (b) WellZ-6: n = 46, lost gas: R = 0.99/P = 0.000, desorbed gas: R = 0.99/P = 0.000, total gas content: R = 0.99/P = 0.000, and residual gas: R = −0.98/P = 0.235.

Figure 6.

Relationship between gas production contribution and TOC of each section of Well Z-3 in West Chongqing.

Vitrinite reflectance (RO, organic matter maturity)

Ro in Well Z-3 exhibits a narrow range (2.76–3.11%), corresponding to the high over-mature stage, with a weak positive correlation with gas-bearing capacity (Figure 7). Integrated with discussions on the correlation between shale gas-bearing capacity and Ro in other regions (Jarvie et al.2007; Li et al., 2022), it is concluded that organic matter maturity is not a key controlling factor for shale gas enrichment in western Chongqing.

Figure 7.

Correlation analysis of shale gas content and organic matter maturity in western Chongqing. WellZ-3: n = 10, lost gas: R = 0.35/P = 0.328, desorbed gas: R = 0.41/P = 0.234, total gas content: R = 0.37/P = 0.289, and residual gas: R = −0.63/P = 0.048.

Porosity

The relationship between gas-bearing capacity and porosity is complex, with contrasting trends in the two wells: total gas content and lost gas are positively correlated with porosity in Well Z-3 (consistent with the positive correlation between porosity and gas production rate; Figure 8), while a weak negative correlation is observed in Well Z-6 (Figure 9). Porosity varies widely in Well Z-3 (0.97–6.01%) but slightly in Well Z-6 (2.42–2.81%). Regional studies indicate that higher porosity favors free gas accumulation; however, comprehensive analysis of porosity's control on gas-bearing capacity must integrate pore types, sedimentary facies, and preservation conditions (Li et al., 2022; Zhao et al., 2019; Zhang et al., 2021).

Figure 8.

Correlation analysis of shale gas content and porosity in western Chongqing. (a) WellZ-3: n = 46, lost gas: R = 0.52/P = 0.000, desorbed gas: R = 0.68/P = 0.000, total gas content: R = 0.58/P = 0.000 and residual gas: R = −0.09/P = 0.568. (b) WellZ-6: n = 26, lost gas: R = −0.59/P = 0.001, desorbed gas: R = −0.68/P = 0.000, total gas content: R = −0.61/P = 0.000, and residual gas: R = −0.68/P = 0.000.

Figure 9.

Relationship between gas production contribution and porosity of each section of Well Zu203 in West Chongqing.

Quartz content

Quartz content shows a similar correlation with gas-bearing capacity to TOC: lost gas, desorbed gas, and total gas content are significantly positively correlated with quartz content, while residual gas content is nearly unchanged (Figure 10). Additionally, quartz content is strongly positively correlated with TOC in both wells, indicating that siliceous shale with high quartz content constitutes a favorable lithofacies for shale gas enrichment（Figure 11） (Cao et al., 2023; Feng et al., 2024).

Figure 10.

Correlation analysis of shale gas content and quartz content in western Chongqing. (a) WellZ-3: n = 46, lost gas: R = 0.58/P = 0.000, desorbed gas: R = 0.70/P = 0.000, total gas content: R = 0.63/P = 0.000 and residual gas: R = −0.12/P = 0.490. (b) WellZ-6: n = 9, lost gas: R = 0.41/P = 0.268, desorbed gas: R = 0.43/P = 0.242, total gas content: R = 0.43/P = 0.249, and residual gas: R = 0.42/P = 0.255.

Figure 11.

Correlation analysis of shale organic carbon content and quartz content in western Chongqing. (a) WellZ-3: n = 46, R = 0.78, P = 0.000. (b) WellZ-6: n = 9, R = 0.48, P = 0.192.

Clay mineral content

Lost gas and total gas content are negatively correlated with clay mineral content in the two wells (Figure 12). Theoretically, clay minerals have strong adsorption capacity due to their large specific surface area; however, shale gas in the study area is dominated by free gas. This negative correlation suggests that clay minerals exert a restrictive effect on free gas content via their adsorption capacity (Wu et al., 2022).

Figure 12.

Correlation analysis of shale gas content and clay mineral content in western Chongqing. (a) WellZ-3: n = 46, lost gas: R = −0.61/P = 0.000, desorbed gas: R = −0.73/P = 0.000, total gas content: R = 0.63/P = 0.000 and residual gas: R = 0.12/P = 0.420. (b) WellZ-6: n = 9, lost gas: R = −0.82/P = 0.004, desorbed gas: R = −0.85/P = 0.002, total gas content: R = −0.84/P = 0.003, and residual gas: R = −0.83/P = 0.003.

Synthesis with fracturing test production data

The highest test production intervals in both wells correspond to optimal reservoir properties: Well Z-3 (Long1–1 interval): TOC = 4.5%, porosity = 5.4%, total gas content = 6.5 m³/t, quartz content = 72.4%, with a maximum test production of 213,000 m³/d; Well Z-6 (Long1–1 interval): TOC = 4.8%, porosity = 5.1%, total gas content = 6.4 m³/t, quartz content = 67.5%, with a test production of 125,000 m³/d. Collectively, these results confirm that high TOC content and high quartz content are the key controlling factors for high gas-bearing capacity in deep shale reservoirs.

Quantitative characterization of quartz from multiple origins and its relationship with gas-bearing capacity in deep marine shale

Building on the preceding analysis identifying high TOC and high quartz content as key controls on deep shale gas-bearing capacity, this chapter further explores the regulatory mechanism of quartz from different origins using quartz genesis identification and TIMA quantitative characterization.

Identification of quartz origins

Quartz genesis in the study area was determined via a combination of elemental geochemistry and microscopic observations (microscopy, cathodoluminescence, scanning electron microscopy (SEM)).

Elemental geochemical identification

Major and trace element geochemical/isotopic characteristics (e.g., excess silica (Si_excess), Si/Al ratio, K₂O/Na₂O ratio) were used to distinguish biogenic quartz. Si_excess was calculated as follows:

S i_{e x c e s s} = S i_{s a m p l e} - (S i / A l_{b a c k g r o u n d} \times A l_{s a m p l e})

(1)

where

{Si}_{excess}

is the sample's SiO₂ content,

{Si}_{sample}

is its Al content, and 3.11 is the typical background Si/Al ratio. A K₂O/Na₂O ratio ≫ 1 indicates a biological origin for siliceous materials. Elemental tests on representative samples from the Wufeng Formation and Longmaxi Formation (bottom, lower, middle-upper intervals; Table 2) showed: Si_excess occurred in the Wufeng Formation and Longmaxi Formation bottom; partial samples from the Wufeng Formation and Longmaxi Formation middle-upper intervals exhibited Si deficiency;K₂O/Na₂O ratios were generally > 1, confirming partial control by biogenic silica.

Table 2.

Geochemical characteristics and discrimination of silicon in shale reservoirs of Wufeng formation–Longmaxi formation.

Formation	Samples	SiO₂ (%)	Al₂O₃ (%)	Si/Al	Si_excess (%)	K₂O/Na₂O
O_3w	Guanyin Bridge Section	59.48	10.32	5.11	10.95	6.83
S₁l bottom		76.52	5.07	13.39	27.61	3.64
S₁l lower		76.28	7.59	8.91	23.34	6.36
S₁l Middle-upper		56.95	14.07	3.59	3.57	2.92

Microscopic identification

Microscopic characteristics of quartz from different origins are presented in Figure 13.

Figure 13.

Microscopic characteristics of quartz in the shale of the Wufeng formation and Longmaxi formation. (a,b) Authigenic quartz with a particle size of 1 micron; (c,d) Terrigenous detrital quartz particles; and (e,f) Field emission electron microscopy images of authigenic quartz by argon ion polishing.

Authigenic quartz (derived from mineral transformation): Fine-grained (< 10 μm; Figure 13(g)-(h)), weakly to nonluminescent under cathodoluminescence, distributed between clay minerals and organic matter, and well-developed in the Longmaxi Formation bottom-lower interval. Terrigenous detrital quartz: Coarse-grained (tens to hundreds of micrometers), with clay minerals/organic matter around edges (Figure 13(c)–(f)).

Biogenic siliceous fossils: Dominated by radiolarian remains, concentrated in the Wufeng Formation and Longmaxi Formation bottom (consistent with geochemical results) (Figure 14), and absent in the Longmaxi Formation middle-upper interval —corresponding to lower TOC and gas content in the latter.

Figure 14.

Microscopic characteristics of siliceous fossils in the bottom of the Wufeng formation–Longmaxi formation in Well Z203.

TIMA quantitative characterization of quartz

TIMA was used to systematically characterize quartz particle size and distribution (Figure 15) after microscopic observation. Key results: Wufeng Formation–Longmaxi Formation bottom: Similar quartz particle size distributions, with 88–89% of grains < 5 μm (no tailing), consistent with recrystallized biogenic silica or authigenic quartz (Milliken et al., 2013). Longmaxi Formation lower interval: Mixed-origin quartz (dominated by terrigenous detritus per geochemistry), with a right-skewed particle size distribution; ∼50% of grains > 5 μm (significant tailing), indicating distinct microscopic properties from the Wufeng Formation–Longmaxi Formation bottom. Longmaxi Formation upper interval: < 1% of quartz grains < 5 μm, with negligible authigenic quartz and dominance of terrigenous detrital quartz.

Figure 15.

Fine characterization of quartz particle size in representative layers of shale reservoirs in the Wufeng formation–Longmaxi formation.

Gas enrichment mechanism of high-brittleness high-quality deep shale reservoirs

Integrated analysis of the vertical distribution of gas content, TOC, and authigenic microcrystalline quartz reveals that the shale intervals at the bottom of the Wufeng—Longmaxi formations exhibit high gas content, high TOC, and well-developed authigenic microcrystalline quartz (Figure 16), representing high-brittleness, high-gas-quality reservoirs. Microscopic analysis further indicates that the microfacies association in these intervals is dominated by microcrystalline quartz and organic matter. This association provides the reservoir with excellent mechanical brittleness, storage capacity, and abundant gas supply through the following mechanisms:(1) Silica-rich biogenic sources and early diagenetic fluid recrystallization led to the formation of abundant authigenic microcrystalline quartz around organic matter. (2) These quartz grains constitute a rigid supporting framework that effectively resists deep compaction, thereby preserving organic-matter pores and intergranular pores—the latter serving as the primary storage space for free gas, which explains the high proportion of free gas in the bottom intervals of the Wufeng—Longmaxi formations. (3) The close association between quartz and organic matter creates a composite pore network with high specific surface area, simultaneously enhancing the storage of both adsorbed gas (associated with organic matter) and free gas (associated with rigid pores). (4) The high-brittleness mineral-rich shale reservoirs generally exhibit well-developed horizontal bedding, which contributes to good self-sealing capacity of the reservoir (Sun et al., 2023; Zhao et al., 2019).

Figure 16.

Comprehensive histogram of optimization and evaluation of shale reservoir in well Z-3 from the perspective of quartz.

Conclusions

The Western Chongqing Block features a relatively gentle structure with poorly developed faults, providing favorable preservation conditions for shale gas. Thick black organic-rich shale in the Wufeng Formation and Longmaxi Formation bottom serves as a high-quality material basis for gas enrichment. While western Chongqing has emerged as a key replacement for shallow shale gas in China with significant advancements in deep marine shale gas exploration, exploration challenges—such as inconsistent production performance despite similar static reservoir parameters and variable initial production—highlight the complexity of deep shale gas accumulation.

To address this, comprehensive evaluations were conducted on four exploration wells with consistent tectonic-sedimentary backgrounds. Key relationships between reservoir performance indicators and gas-bearing capacity were analyzed, and core controlling factors for deep shale gas enrichment were identified, providing scientific support for sweet spot optimization. The main conclusions are as follows:

(1). Spatial distribution of gas-bearing capacity: Planarly, central western Chongqing exhibits the best gas-bearing potential; vertically, the Long1–1 member of the Longmaxi Formation is the optimal reservoir, characterized by high porosity, high TOC, high brittleness, and high gas-bearing capacity. Deep shale gas in the study area is dominated by free gas, facilitating exploitation.

(2). Key controlling factors for gas enrichment: Correlation analysis of static reservoir parameters and fracturing test data confirms that high TOC and high quartz content are the core controlling factors for high gas-bearing capacity in deep shale. The Wufeng Formation and Longmaxi Formation bottom are enriched in authigenic microcrystalline quartz, which constructs a rigid rock framework interspersed with abundant organic matter. This microfacies association—dominated by microcrystalline quartz and organic matter—collectively forms high-quality reservoirs with excellent mechanical brittleness, adsorption-storage capacity, and abundant gas sources.

(3). Implications for sweet spot optimization: High TOC content ensures “superior gas-bearing capacity” (geological criterion), while high authigenic microcrystalline quartz content enhances reservoir fracability (engineering criterion). These two parameters align with the core criteria for geological-engineering integration sweet spot optimization in deep marine shale. Their clarification provides a scientific foundation and technical support for sweet spot identification (both intervals and zones) under deep geological conditions, promoting the efficient and economical development of deep shale gas.

Footnotes

Acknowledgments

This work was supported by the Science and Technology Research Program of Chongqing Municipal Education Commission (Grant No. KJZD-K202103201) and the Natural Science Foundation of Chongqing (Grant No. cstc2021jcyj-msxmX0959). The authors would like to express their sincere gratitude to Zhian Lei (Chongqing Shale Gas Exploration and Development Co., Ltd) and Zhiping Zhang (Chongqing Institute of Geology and Mineral Resources) for their valuable contributions to sample analyses and field assistance.

ORCID iDs

Weiwei Jiao

Difei Zhao

Funding

The authors disclosed receipt of the following financial support for the research, authorship, and/or publication of this article: This work was supported by the Natural Science Foundation of Chongqing, the Science and Technology Research Program of Chongqing Municipal Education Commission (Grant Numbers cstc2021jcyj-msxmX0959 and KJZD-K202103201).

Declaration of conflicting interests

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

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