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Article

Source-Reservoir Characteristics and Pore Evolution Model of the Lower Paleozoic Shales in the Neijiang–Rongchang Area, Sichuan Basin

by
Shizhen Chen
1,2,3,*,
Zhidian Xi
4,*,
Fei Huo
4 and
Bingcheng Jiang
5
1
State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Chengdu University of Technology, Chengdu 610059, China
2
Key Laboratory of Deep-Time Geography and Environment Reconstruction and Applications of Ministry of Natural Resources, Chengdu University of Technology, Chengdu 610059, China
3
Institute of Sedimentary Geology, Chengdu University of Technology, Chengdu 610059, China
4
School of Geoscience and Technology, Southwest Petroleum University, Chengdu 610500, China
5
School of Environment and Civil Engineering, Chengdu University of Technology, Chengdu 610059, China
*
Authors to whom correspondence should be addressed.
Minerals 2025, 15(5), 499; https://doi.org/10.3390/min15050499
Submission received: 28 March 2025 / Revised: 30 April 2025 / Accepted: 5 May 2025 / Published: 8 May 2025
(This article belongs to the Special Issue Element Enrichment and Gas Accumulation in Black Rock Series)
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Abstract

:
The Wufeng–Longmaxi formations in the Sichuan Basin have emerged as China’s principal shale gas exploration target, with drilling results confirming substantial resource potential. Although the Neijiang–Rongchang Block demonstrates promising production, significant performance variations among lithofacies and reservoir types highlight the need for enhanced understanding of reservoir evolution. This study integrates petrological analyses, SEM imaging, XRD characterization, seismic interpretation, and production data from multiple wells targeting the Wufeng–Long 1-1 Sub-member. Key insights reveal the following: (1) reservoir lithology consists predominantly of siliceous shale (68% occurrence), characterized by high quartz content (48% avg), low carbonates (<15%), and low clay (<30%); (2) organic-rich intervals contain Type I kerogen derived from planktonic algae, with thermal maturity indicating post-mature evolution; (3) premium reservoirs develop multi-scale pore networks combining organic-hosted pores, interparticle pores, and micro-fractures. Despite high brittle mineral content, mechanical competence decreases stratigraphically from the Wufeng Formation (78%) to Long 1-17 (63%); (4) depositional redox conditions facilitated exceptional organic preservation. Core analyses reveal low porosity (5.5% avg) and ultra-low permeability (0.27 × 10⁻3 μm2 avg), classifying reservoirs as multiple tight unconventional systems in the study area. The proposed lithofacies-controlled pore evolution model elucidates reservoir heterogeneity mechanisms, providing critical geological criteria for optimized shale gas development.

1. Introduction

Shale gas is a self-contained hydrocarbon system found in organic-rich shales. It serves as a crucial low-carbon energy source in global energy transitions. This unconventional resource mainly exists in adsorbed and free states within shale matrices [1,2]. It has become a key focus in hydrocarbon exploration due to its growing contribution to global energy portfolios [3].
Recent decades have witnessed remarkable progress in marine shale exploration across southern China. The Upper Ordovician Wufeng Formation to the Lower Silurian Longmaxi Formation shales, extensively distributed throughout the Sichuan Basin and adjacent regions, have achieved commercial-scale production through innovative engineering solutions [4,5]. By 2022, cumulative proven reserves surpassed 2 × 1012 m3, with annual output reaching 238 × 108 m3, marking the basin’s transition to an advanced development phase characterized by technological breakthroughs and industrial expansion [6,7].
As China’s principal shale gas target, the Wufeng–Longmaxi Formation exhibits integrated source-reservoir-seal systems with distinctive high-pressure and low porosity-permeability characteristics [8]. Nevertheless, the reservoir’s compositional complexity results in diverse genetic pore types and intricate structural configurations [9,10,11]. Three fundamental geological processes—depositional dynamics, tectonic evolution, and diagenetic alteration—collectively govern reservoir integrity and pore architecture development [12]. Microscale pore networks, serving as direct proxies for storage capacity, demand systematic investigation of their morphological evolution and genetic constraints from nano- to micro-scales [13,14].
Existing research establishes multivariate controls on porosity evolution, including depth-dependent exponential relationships. Critical parameters such as thermal regime, confining pressure, total organic carbon (TOC) content, and organic matter maturity (Ro) exhibit deterministic influences on pore development, particularly regarding organic porosity generation linked to kerogen characteristics [15,16,17,18]. However, significant knowledge gaps persist in lithofacies-specific diagenetic pathways and regional variations in pore systems, leaving diagenetic typology, pore evolution models, and source-reservoir interactions insufficiently constrained [19].
Integrating principles of unconventional hydrocarbon geology with sedimentological and geochemical analytical frameworks, this investigation combines petrographic analysis, scanning electron microscopy (SEM), and dual-gas (N2/CO2) physisorption techniques to characterize the Wufeng Formation–Long 1-1 shales in the Neijiang–Rongchang area. Through multiscale evaluation of diagenetic sequences and pore network evolution, this study aims to establish predictive models for deep shale gas exploration and optimize high-potential reservoir targeting strategies.

2. Geological Setting

The study area occupies the southwestern Sichuan Basin, encompassing three structural blocks: Dazu (Chongqing), Rongchang, and Neijiang. Tectonically positioned at the transitional interface between the Chuanzhong Paleo-uplift and the southern periphery of the Qianzhong Paleo-uplift (Figure 1a), this region records critical stratigraphic transitions.
The Late Caledonian orogeny during the Ordovician–Silurian transition initiated a major paleogeographic transformation, with the regional setting evolving from carbonate platform to shelf basin environments (Figure 1a) [11,20]. Within the Neijiang–Rongchang Block, the Longmaxi Formation exhibits moderate burial depths (3500–4500 m at Wufeng Formation base), notably shallower than adjacent areas. Regional structure displays gentle northwestward dips, with Silurian strata progressively thinning northwestward due to erosional truncation, while southeastward uplift forms the Luoguanshan Anticline [14,17,21].
Stratigraphically, the Longmaxi Formation maintains conformable contacts with both overlying (Shiniulan Formation) and underlying (Wufeng Formation) units. It comprises two principal members: the upper Long 2 and lower Long 1, with the latter subdivided into Long 1-1 Sub-member and Long 1-2 Sub-member (Figure 1b). The Long 1-1 Sub-member emerges as the primary hydrocarbon-bearing interval, containing eight distinct lithostratigraphic units (ascending sequence): the Wufeng Formation overlain by Long 1-11 sub-layers through Long 1-17 sub-layers (Figure 1c). This refined subdivision integrates lithological characteristics and well-log correlations [22,23].

3. Materials and Methods

Core samples were collected from over 20 wells (including L208, W210, and Z201) in the Neijiang–Rongchang region, from which more than 50 shale samples were obtained for experimental analysis. These samples underwent comprehensive analyses including field emission scanning electron microscopy (FE-SEM), thin-section petrography, total organic carbon (TOC) quantification, X-ray diffraction (XRD), low-temperature N2/CO2 adsorption–desorption tests, kerogen microcomponent identification, vitrinite reflectance measurement, and rock pyrolysis.

3.1. Argon Ion Polishing-Scanning Electron Microscopy

Specimen preparation and FE-SEM imaging were conducted at the State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation in Chengdu University of Technology. Sample surfaces were polished using a Gatan Ilion + II argon ion mill, followed by microstructural characterization using a Philips XL30 FE-SEM (20 °C ambient temperature), Eindhoven, The Netherlands.

3.2. X-Ray Diffraction Analysis

Bulk mineralogical composition was determined for 9 core samples from Well R232 using a Rigaku D/Max IIIC X-ray diffractometer. Powdered samples (200-mesh) were analyzed following the Chinese national standard SY/T 5163-2018 protocols [24].

3.3. Total Organic Carbon Quantification (TOC)

TOC analysis of multiple samples (Wells R232, W219, R239, Z201, W210, L208, etc.) was performed at PetroChina Southwest Oil & Gas field Company’s Analytical Center. Measurements utilized a KLT-005 carbon/sulfur analyzer under controlled conditions (14–16 °C, 42% RH), adhering to GB/T 19145-2022 standards [25].

3.4. Kerogen Microcomponent and Vitrinite Reflectance Analysis

These two experiments were conducted at the Analytical Experiment Centre of the Research Institute of Exploration and Development, Southwest Oil & Gas field, PetroChina. Twelve samples (Wells R232, W219, R239) were examined using a ZEISS Axio Imager.M2m fluorescence microscope (SY/T 5125-1996) [26]. Vitrinite reflectance measurements employed a Leica MSP400 microspectrophotometer under standard conditions (23 °C, 50% RH) in accordance with SY/T 5124-2012 [27]. In order to reveal the equivalent relationship between solid bitumen and vitrinite reflectance, optical characterization and reflectance measurement of organic matter were conducted on the shale in the study area. The results show that the equivalent relationship between the reflectance of solid bitumen and that of vitrinite is that for shale at a high over-mature stage, the value of solid bitumen reflectance is basically consistent with that of vitrinite reflectance, and a good linear correlation is displayed.

3.5. High-Pressure Mercury Porosimetry Experiment

This experiment was conducted at the Analytical and Experimental Center of the Exploration and Development Research Institute, PetroChina Southwest Oil & Gasfield Company, Chengdu, China. Core samples from multiple research wells were selected for high-pressure mercury porosimetry analysis. The measurements were performed using a Micromeritics AutoPore IV 9500 Series Porosimeter, Norcross, GA, USA. The samples were prepared as cylindrical specimens with a diameter of 2.5 cm and a length of 2 cm. Specimens underwent a standardized preparation process: initial drying at 60 °C for 48 h, followed by cooling to 23 °C in a desiccator under humidity-controlled conditions (<10% RH). Mercury intrusion analysis was subsequently conducted on the dried and degassed specimens under controlled pressure conditions ranging from 0.14 MPa to 420 MPa.

3.6. Gas Physisorption Analysis

The experiment was conducted at the National Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Chengdu University of Technology, China. Pore structure characterization of 9 samples in Well R232 was completed using a Quantachrome NOVA2000e analyzer, Quantachrome Instruments, Boynton, FL, USA. Low-pressure N2 (77 K) and CO2 (273 K) adsorption isotherms were acquired to assess mesopore and micropore distributions.

3.7. Carbon Isotopic Analysis

Carbon isotope analysis was performed in the laboratory of the School of Archaeology and Museums of Peking University. The specific analysis process is as follows: the sample powder (200 mg) is mixed with a phosphoric acid solution (100% purity, temperature 75 °C), reacted in the Kiel IV device for 16 h, and the released CO2 enters the IsoPrime (Elementar, UK). 100 mass spectrometer for final carbon isotope detection. The test was calibrated using a standard specimen (IAEA CO-8) [28].

4. Results

4.1. Mineral Composition and Lithofacies Classification

4.1.1. Mineral Composition

The Wufeng Formation–Long 1-1 Sub-member shales exhibit a heterogeneous mineral assemblage dominated by quartz (21.6–82.3%), clay minerals (7.9–58.6%), and carbonate minerals (<15%), with subordinate plagioclase and pyrite (Figure 2). Spatial heterogeneity in quartz distribution reveals contrasting origins: biogenic silica (e.g., sponge spicules, graptolites) predominates in southern regions, while terrigenous quartz characterizes northern areas, and paleo-uplift characterizes erosional zones. Clay mineral assemblages are illite-dominated (>60% of clay fraction), with minor chlorite and kaolinite. Notably, Weiyuan shales display elevated carbonate content (up to 25% as cement) due to terrigenous input from the Qianzhong and Central Sichuan uplifts, contrasting with Rongchang and Luzhou regions. Under the influence of the global sea invasion during the Early Silurian period, the shale of the Long1-1 Sub-member was mainly deposited in the deep-water continental shelf environment, with a relatively high content of pyrite. A large number of strawberry-shaped pyrite could be seen [29,30,31,32].

4.1.2. Petrographic Division

Integrated field section surveys, core analyses, and petrographic characterization classify the Wufeng Formation-Long1-1 Sub-member shales into four distinct lithofacies based on mineralogical composition: (1) siliceous shale, (2) clay-rich shale, (3) mixed shale, and (4) calcareous shale (Figure 2). Each lithofacies displays unique sedimentary environments and vertical stacking patterns.
(1)
Siliceous Shale Facies: Deposited in organic-rich siliceous muddy shelf environments at the Wufeng Formation–Long1-1 Sub-member base, this facies unconformably overlies Linxiang Formation limestone. Comprising >75% siliceous minerals (Figure 2), it features cryptocrystalline to micritic textures with abundant biogenic components, including sponge spicules and radiolarians, confirming biogenic silica origins.
(2)
Clay-Rich Shale Facies: Developed in clay-bearing siliceous muddy shelf environments within the middle-lower Long1-1 Sub-member, this lithofacies contains >50% siliceous and >25% clay minerals (Figure 2). A large amount of pyrite can be observed to develop in bedding planes within the rock core, or it can be distributed in bedding planes in a well-formed granular form. Such rock facies are the most widespread in the study area.
(3)
Mixed Shale Facies: Deposited in calcareous-siliceous-clay-rich composite muddy shelf settings (middle-upper Long1-1 Sub-member), this facies exhibits equal siliceous (25–50%) and clay mineral (25–50%) contents (Figure 2). Core samples reveal distinctive silt-rich laminae, indicative of hydrodynamic enhancement.
(4)
Calcareous Shale Facies: Accumulated in deep-water silty muddy shelf environments (upper Long1-1 Sub-member), this carbonate-rich facies (>25% carbonate minerals) displays reduced siliceous content (Figure 2). Sedimentary architecture features horizontal and banded texture, with laminated varieties showing alternating light-colored calcareous/siliceous-clay laminae and dark clay-dominated layers.

4.2. Hydrocarbon Source Rock Characteristics

4.2.1. Organic Matter Abundance

The hydrocarbon generation potential of source rocks is governed by organic matter abundance, which exhibits a quantifiable relationship with pore evolution in shale reservoirs [11,19,33]. Total organic carbon (TOC) contents in the study area range from 0.4% to 5.5% (mean 2.45%), meeting the threshold for effective shale gas reservoirs (TOC > 2%) [34]. Stratigraphically, TOC values decrease systematically from the Wufeng Formation base to the Long1-1 Sub-member top (Figure 3). High-TOC intervals (TOC > 2%) are concentrated in four lower sub-layers, with thicknesses varying between 23 m and 63 m. These intervals correspond to black siliceous shales deposited in deep-water shelf environments of the lower Longmaxi Formation. During the deposition of the Wufeng–Long1-1 Sub-member, high-quality shale predominantly occurs in the central and southern domains of the study area, exhibiting total organic carbon contents exceeding 2.3%. Specifically, shales from the Wufeng Formation demonstrate elevated TOC values (>2.6%), while organic-rich shales within the Longmaxi Formation maintain TOC concentrations above 2.3% (Figure 1 and Figure 3). The lateral extent of these high-TOC shales shows a positive correlation with the stratigraphic thickness of the Wufeng Formation–Long1-1 Sub-member.

4.2.2. Organic Matter Type

The hydrocarbon generation potential of source rocks is fundamentally controlled by organic matter type. Distinct depositional environments produce different organic matter compositions, with maceral variations being modulated by sedimentary conditions and diagenetic processes to varying extents, and mud-forced turbulence dampening facilitates rapid burial and enhanced preservation of terrestrial organic matter in deep-sea environments [5,35,36]. In the Wufeng Formation–Long1-1 Sub-member of the study area, comparative analysis employing kerogen type index (TI) and δ13C isotopic composition (Table 1) demonstrates limited variability in both organic matter types and thermal maturity. Kerogen macerals exhibit a pronounced dominance of sapropelinite (>70%), accompanied by subordinate quantities of bituminite, vitrinite, and inertinite. The δ13C kerogen values range from −31.62‰ to −28.45‰, consistent with predominantly Type I kerogen and minor Type II-1 components. This sapropelinite predominance reflects the unique depositional environment of the Wufeng Formation—a deep abyssal plain characterized by persistent anoxic conditions. Such environmental constraints promoted a marine ecosystem dominated by planktonic organisms and lower aquatic biota (particularly algae), resulting in uniform organic input. The oxygen-depleted conditions enhanced preservation of lipid-rich organic matter derived from these primitive organisms, creating optimal conditions for hydrocarbon generation [37,38].

4.2.3. Organic Matter Maturity

The thermal maturity of shale organic matter serves as a critical indicator of its thermal evolution history, hydrocarbon generation stage, and impact on organic pore development [19]. While diagenetic processes generally reduce shale porosity with increasing thermal maturity [39], vitrinite reflectance (Ro) measurements remain the primary maturity quantification method. Higher Ro values correlate with advanced thermal evolution and enhanced hydrocarbon generation potential [20]. In the Wufeng Formation–Long1-1 Sub-member of the southern Sichuan Basin, Ro values range from 1.62% to 4.86%, with most measurements exceeding 2% [40]. These values confirm that the shale reservoirs have predominantly reached the over-mature stage, though localized southern areas display marginally higher thermal maturity while remaining within the dry gas window (Figure 4).

4.3. Reservoir Characteristics

4.3.1. Reservoir Space Types

The Wufeng–Long1-1 Sub-member shales contain four principal reservoir spaces: (1) organic pores, (2) intercrystalline pores, (3) intragranular pores, and (4) microfractures [11,41]. Organic pores constitute the dominant storage spaces, exhibiting decisive control over shale gas generation and enrichment through their development patterns [6,20,42,43]. These pores predominantly display irregular spongy, elliptical, or honeycomb morphologies (diameter <1 μm) within organic matter, with a minor population of larger (several micrometers) irregular polygonal or slit-shaped pores occurring at inorganic mineral edges (Figure 5a–c).
Intercrystalline pores demonstrate extensive development, particularly those associated with pyrite framboids formed during the Wufeng–Longmaxi transgression under deep-water anoxic conditions. These pyrite-hosted pores feature relatively large apertures suitable for hydrocarbon storage. Additional intercrystalline pores occur between quartz, calcite, and dolomite crystals, as well as along chlorite and illite mineral edges, exhibiting 1–6 μm apertures with irregular or grid-like morphologies controlled by crystal geometry (Figure 5d,e).
Intragranular pores primarily form within unstable minerals (e.g., calcite, dolomite) through secondary dissolution processes. Microscopic observations reveal abundant bubble-like or elongated pores in detrital feldspar, calcite, and dolomite grains, their morphologies reflecting diverse diagenetic histories (Figure 5f,i).
Microfractures occur as three genetic types: (1) organic matter shrinkage fractures, (2) tectonic fractures, and (3) bedding-parallel fractures. While most fractures are calcite-filled (with minor quartz and feldspar infilling), their development significantly enhances both porosity and permeability, facilitating gas migration and storage (Figure 5g,h).

4.3.2. Pore Structure

The multiple data sets of three wells in the Wufeng Formation–Long1-1 Sub-member within the study area were tested by low-temperature nitrogen adsorption and carbon dioxide adsorption methods. The nitrogen adsorption–desorption isotherms indicated that the isotherm shapes were more inclined to be reverse “S” type, which demonstrated the porosity of the Wufeng Formation–Long1-1 Sub-member shale [43]. Moreover, the increase in the adsorption loop area and the gradual convergence of some adsorption and desorption curves suggested that the shale in this section was mainly composed of mesopores. According to the classification of isothermal adsorption curves by previous researchers, it can be concluded that these shales were mainly composed of slit-like, plate-like, and lamellar pores. The N2 adsorption/desorption isotherms also confirmed this (Figure 6) [44]. The pore size distribution curve obtained from the BJH model based on the low-temperature nitrogen adsorption data clearly showed that the peak values of the samples in the study area mainly occurred in the 3–5 nm range, but were mainly distributed in the 5–50 nm range (Figure 7). The conclusion obtained was consistent with that from the adsorption test, indicating that the pores of the shale were mainly mesopores. Moreover, the number of pores in the lower section of the reservoir (Wufeng Formation–Long1-1 Sub-member) within the study area was higher than that in the upper section (Long1-15 sub-layers–Long1-17 sub-layers). The pore volume of the study section within the area, calculated by the BET model, ranged from 0.003019 m3/t to 0.03444 m3/t, and the specific surface area ranged from 1.568 m2/g to 31.187 m2/g. The pore volume of the lower section of the reservoir in the southern Sichuan area was significantly higher than that of the upper section, and the specific surface area showed the same trend as the pore volume (Figure 8).
The multi-data set analysis from three wells in the Wufeng Formation–Long1-1 Sub-member within the study area was conducted through integrated low-temperature nitrogen adsorption and carbon dioxide adsorption methods. Nitrogen adsorption–desorption isotherms revealed that the isothermal curves predominantly exhibited a reverse “S” configuration, confirming the well-developed porosity characteristics of the Wufeng Formation–Long1-1 Sub-member shales [43]. Progressive expansion of adsorption hysteresis loops coupled with convergence trends between adsorption/desorption branches demonstrated mesopore dominance in the shale pore system (Figure 6) [44]. Classification of isothermal adsorption curves according to established petrophysical schemas identified slit-shaped, platy, and lamellar pore morphologies as principal constituents. BJH model-derived pore size distribution curves from nitrogen adsorption data exhibited bimodal characteristics, with primary peak intensities at 3–5 nm and dominant pore size populations spanning 5–50 nm (Figure 7), corroborating the mesoporous nature revealed by adsorption analyses. Comparative analysis revealed higher pore density in lower reservoir intervals (Wufeng Formation-Long1-14 sub-layer) compared to upper sequences (Long1-15 to Long1-17 sub-layers). BET model quantification determined pore volumes ranging from 0.003019–0.03444 m3/t and specific surface areas of 1.568–31.187 m2/g within the studied intervals. Notably, the southern Sichuan Basin reservoirs displayed greater pore volumes in lower members versus upper sections, with specific surface area variations exhibiting proportional relationships to pore volume distributions (Figure 8).

4.3.3. Reservoir Analysis

Integrated analysis of porosity, brittle mineral content, and permeability reveals distinct reservoir quality patterns. In the Neijiang–Rongchang region, siliceous and clay-rich shales exhibit maximum porosity (average ~5.5%), outperforming mixed and calcareous lithofacies. Regional comparisons show that the Weiyuan and Rongchang areas (5.5%) surpass Dazu (4.5%) in porosity development. Stratigraphically, lower intervals (Wufeng Formation–Long1-14) maintain higher porosity (5.5%) versus upper units (Long1-15–17; 4.7%). TOC content demonstrates a segmented correlation with porosity and carbonate mineral abundance, where elevated carbonate content (>60%) inversely impacts porosity preservation, particularly in calcareous upper intervals (Figure 9a).
Brittle mineral assemblages (quartz + feldspar + calcite + dolomite) exceed 70% regionally, dominated by felsic constituents (>80%). Spatial heterogeneity shows that the Rongchang–Luzhou–Dazu areas contain higher brittle mineral concentrations than the southern zones. Vertical profiles document decreasing brittleness from the Wufeng Formation (>90%) to the Long1-17 sub-layer (<40%), though localized enrichment occurs near the Weiyuan erosion boundary (Figure 9b). Permeability-porosity relationships exhibit weak coupling (R2 < 0.3), with lower reservoirs (average < 0.3 × 10−3 μm2) outperforming upper units (<0.1 × 10−3 μm2). The Rongchang Block demonstrates marginally enhanced permeability correlating with porosity, while overall reservoir characteristics reflect tight storage (porosity <6%, permeability <<0.3 × 10−3 μm2) and limited pore connectivity (Table 2).

5. Discussion

5.1. Mineral Composition and Lithofacies

Mineral composition and lithofacies architecture fundamentally control reservoir space abundance and high-quality reservoir distribution. Shale mineralogy governs fracture development, pore architecture, and fracture-filling mineralogy [45]. The lower Wufeng Formation–Long1-1 Sub-member features quartz-rich intervals (>40% total quartz content), with biogenic quartz accounting for >50% of silica, confirming predominant biogenic origins [46]. These siliceous shale facies, developed in organic-rich siliceous mud shelf environments, exhibit synergistic pore-fracture networks comprising microfractures, pyrite intercrystalline pores, and organic-hosted pores (Figure 5a–i).
Brittle minerals (e.g., quartz, feldspar) demonstrate enhanced fracture generation potential compared to ductile clay minerals. Elevated quartz content increases rock brittleness, promoting extensive fracture networks [47]. Strong linear correlations between brittle mineral abundance and TOC (quartz: R2 = 0.68; feldspar: R2 = 0.52) reveal organic-inorganic synergies (Figure 9b). Vertically, lithofacies transition from siliceous shale (base) → clay-rich shale → mixed shale → calcareous shale (top), paralleling upward-decreasing silica and TOC contents.
Clay minerals exhibit distinct reservoir impacts: (1) illite shows weak negative correlations with effective porosity (R2 = 0.32) and permeability (R2 = 0.28), moderate negative correlation with gas saturation (R2 = 0.45), and weak positive correlation with water saturation (R2 = 0.33). (2) Chlorite displays stronger negative correlations with gas saturation (R2 = 0.62) and water saturation (R2 = 0.58), indicating dual inhibition of pore development and gas accumulation (Figure 9c) [48,49,50,51].
Laminated siliceous shales facilitate interlayer fracturing, where biogenic silica and organic matter jointly foster abundant organic pores. In contrast, increasing clay/calcareous mineral content shifts pore dominance to clay intergranular and calcite dissolution pores. High TOC concentrations in organic-rich siliceous mud shelf facies confirm optimal reservoir development in silica-enriched intervals.

5.2. Organic Matter Characteristics

Organic matter constitutes the fundamental precursor for organic pore formation, with its abundance directly controlling pore density [52]. Shale organic pore development is governed by three key factors: organic matter type, thermal maturity, and hydrocarbon generation potential [53,54]. In the Wufeng Formation–Long1-1 Sub-member, total organic carbon (TOC) content exhibits a significant positive correlation with porosity (R2 = 0.72), demonstrating that organic matter functions dual roles as (1) precursor material for organic pores, and (2) catalytic agents for hydrocarbon generation, which enhances pore space through gas expansion and diagenetic reorganization (Figure 8) [55].
CT scanning and FIB-SEM 3D reconstructions reveal multiscale organic pore networks within the shale matrix. Quantitative analysis shows pore volume displays a moderate positive correlation with TOC (R2 = 0.44), while specific surface area exhibits a stronger correlation (R2 = 0.63), indicating micropore (<2 nm) and mesopore (2–50 nm) development preferentially enhances surface area at higher TOC levels. Surface area magnitude is primarily controlled by kerogen type, thermal maturity, and clay mineral content.
Depositional environments exert distinct controls: (1) underwater highs feature larger pore diameters (>10 nm), with TOC primarily correlating with macroporosity (>50 nm) due to carbonate cementation and reduced compaction. (2) Underwater depressions preserve smaller pore sizes (~10 nm), where increasing TOC enhances both pore volume and surface area. Elevated pressure in depressions better retains primary micropores, which contribute 58% of total surface area and facilitate organic pore generation (Figure 10) [18,41,56].
Different tectonic movements and ancient landform patterns control different sedimentary environments, resulting in differences in pore connectivity and structure. The observed pore architectures demonstrate preferential alignment parallel to bedding planes, reflecting depositional control on organic matter distribution. High-TOC (>3%) intervals in organic-rich siliceous mud shelf facies exhibit optimal pore connectivity, confirming TOC abundance as the dominant control on reservoir quality.

5.3. Diagenetic Sequence

Diagenetic processes exert multistage controls on the evolution of organic and inorganic pores in shale reservoirs [18,39,57,58,59,60]. Integrating previous studies with geological characteristics of the study area, four principal diagenetic processes were identified through macro-micro analysis, combining core observations, thin-section petrography, and field-emission scanning electron microscopy (FESEM): compaction, dissolution, cementation, and clay mineral transformation. These processes exhibit dynamic interactions that collectively govern reservoir pore evolution (Figure 11) [61].
Based on paleotemperature, vitrinite reflectance (Ro), mineral assemblages, and pore architecture of the Wufeng Formation–Long1-1 Sub-member, the diagenetic sequence is reconstructed as follows:
(1)
Synsedimentary Stage: During slow subsidence of synclinal basins, loosely packed biogenic quartz (50–60%), pyrite (8–12%), and terrigenous clasts (10–15%) formed a rigid framework with abundant primary pores (porosity: 15–22%). High initial porosity resulted from minimal compaction and shallow burial (<1200 m) [62].
(2)
Early Diagenesis (Ro < 0.62%): Increasing burial depth (1200–2500 m) and geothermal gradients induced semi-consolidation. Clay mineral contacts transitioned from point-to-line configurations, reducing primary porosity to 8–12%. Early calcite cementation (5–8 vol%) and pyrite authigenesis (3–5 vol%) occurred concurrently with smectite-to-kaolinite transformation [63].
(3)
Middle Diagenesis (Ro = 0.62–1.86%): Thermochemical sulfate reduction at 80–120 °C generated acidic fluids, dissolving 20–30% of carbonate minerals and creating secondary pores (dissolution pores: 4–6%; organic pores: 3–5%). Quartz overgrowths (2–4 μm thickness) and illitization of smectite (60–70% conversion) dominated, while ferroan dolomite (5–7 vol%) and sparry calcite (3–5 vol%) precipitated in suture-contact fabrics [64].
(4)
Late Diagenesis (Ro > 1.86%): At burial depths >3500 m and temperatures >150 °C, hydrocarbon generation ceased, reducing organic pores by 40–50%. Chloritization was completed (>90% smectite conversion), while calcite (10–12 vol%) and pyrite (5–7 vol%) infilled fractures as lenticular or bed-parallel cements. Porosity stabilized at 2–4% due to fracture compensation [65].
This diagenetic sequence evolutionary framework provides a predictive model for reservoir quality assessment in the southern Sichuan Basin (Figure 11).
Minerals 15 00499 g011
Figure 11. Diagenetic evolution sequence of major minerals in shales of the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block [53,66].
Figure 11. Diagenetic evolution sequence of major minerals in shales of the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block [53,66].
Minerals 15 00499 g011

5.4. Pore Evolution Model

The Wufeng Formation–Long1-1 Sub-member shales in southern Sichuan Basin are classified into four distinct lithofacies types based on mineral composition variations [37,41,56]. This lithofacies differentiation fundamentally controls diagenetic evolution pathways through mineralogical heterogeneity, subsequently influencing pore system development [47,66]. Through integrated analysis of lithofacies characteristics and experimental data, this study establishes a thermal simulation-based pore evolution model for different shale lithofacies in the study area (Figure 12).
In siliceous shales, biogenic quartz constitutes the primary silica source. During synorogenic stages, abundant siliceous organisms, including sponge spicules and radiolarians, developed under high productivity conditions. Early diagenesis witnessed gradual authigenic quartz precipitation alongside mechanical compaction of carbonate minerals (calcite and dolomite), significantly reducing primary intergranular porosity. By middle-late diagenetic stages, dispersed organic matter facilitated extensive secondary pore development, predominantly organic-hosted pores with subordinate intragranular pores in carbonate and quartz grains (Figure 13) [43,56].
Clay-rich shales exhibit distinct evolutionary patterns, with siliceous components derived from both biogenic and terrigenous sources. Early diagenetic compaction transformed particle contacts to linear configurations while clay mineral filling substantially diminished primary porosity. Subsequent diagenetic stages featured clay mineral transformation coupled with organic matter migration, generating pore systems dominated by organic pores and clay intergranular pores (Figure 13). Notably, these shales maintain 18–23% higher microporosity than siliceous lithofacies during equivalent diagenetic phases.
Mixed lithofacies shales demonstrate transitional characteristics, showing increased terrigenous detritus (quartz and feldspar) with reduced biogenic silica. Their early diagenetic porosity (primarily meso-macropores) benefits from limited authigenic quartz precipitation. Subsequent clay mineral transformation and pressure solution during middle-late diagenesis enhanced secondary porosity through organic pores and solution-derived pores (Figure 13) [67,68,69].
Calcareous shales present unique evolution trajectories dominated by carbonate minerals (calcite/dolomite) with minimal siliceous components. Early orogenic cementation creates abundant intergranular and dissolution pores. Middle-late diagenetic dissolution intensification and clay mineral alteration produce complex pore networks characterized by dissolution voids, clay intercrystalline pores, and minor organic pores (Figure 13) [60,67,70]. These carbonates maintain 22–28% higher macroporosity compared to other lithofacies during advanced diagenesis. Based on the analysis of pore structure, it can be concluded that the pores in siliceous shale and clay-rich shale are mainly composed of medium-sized pores and organic matter micropores. The pore volume is also higher than that of the upper part of calcareous shale and mixed shale, while calcareous shale and mixed shale are mainly composed of inorganic medium-sized pores.
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Figure 13. Organic-inorganic pore evolution model of shale in different lithofacies of the Wufeng Formation–Long1-1 Sub-member in the Neijiang–Rongchang Block [71].
Figure 13. Organic-inorganic pore evolution model of shale in different lithofacies of the Wufeng Formation–Long1-1 Sub-member in the Neijiang–Rongchang Block [71].
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6. Conclusions

(1) Integrated analysis of field outcrops, core samples, and petrographic microscopy reveals four principal lithofacies in the Wufeng Formation–Long1-1 Sub-member shales of the Neijiang–Rongchang area: siliceous, clayey, mixed, and calcareous shales. The siliceous lithofacies (>75% biogenic silica content) represents the dominant shale gas reservoir, primarily deposited in organic-rich siliceous mud environments at the formation’s basal section. The stratigraphic subdivision based on well-logging signatures and lithological features identifies eight distinct sublayers within the study interval: the Wufeng Formation, followed by sublayers Long1-11 through Long1-17 in ascending order.
(2) Organic geochemical characterization demonstrates that the shales contain Type I sapropelic organic matter with subordinate Type II-1 humic-sapropelic components. Total organic carbon (TOC) values range from 0.4% to 6.5% (mean: 2.45%), while vitrinite reflectance (Ro) measurements between 1.62% and 4.86% confirm post-mature thermal evolution. Reservoir spaces comprise organic-hosted pores, intercrystalline voids, intragranular dissolution features, and microfractures, with irregular sponge-like organic pores dominating the pore architecture. Significant pore heterogeneity is observed across sublayers, reflecting differential diagenetic controls.
(3) The shales currently reside in late diagenetic stages, with four interdependent diagenetic processes identified through macro-micro analysis: (1) mechanical compaction, (2) chemical dissolution, (3) mineral cementation, and (4) clay mineral transformation. These processes exhibit stage-specific dominance during the syngenetic to late diagenetic evolution sequence. Pore system development demonstrates dual control from diagenetic modification and hydrocarbon generation dynamics, manifesting as progressive reduction in inorganic/intergranular pores coupled with increasing organic/intragranular porosity. The evolutionary sequence is categorized into four distinct phases: syngenetic pore formation, early diagenetic adjustment, middle diagenetic transformation, and late diagenetic stabilization.
(4) Based on the research on the lithofacies, reservoir characteristics, and pore evolution patterns in the study area, it is concluded that the development focus of shale gas in this area should be placed on the siliceous shale with high TOC and porosity in the lower part of the Wufeng Formation–Longmaxi Formation. In combination with the diagenesis characteristics, pore evolution patterns, and reservoir distribution characteristics of the siliceous shale, favorable exploration areas should be delineated.

Author Contributions

Conceptualization and writing—original draft, writing—review, S.C.; resources and data curation, F.H.; software and visualization, Z.X. and B.J. All authors have read and agreed to the published version of the manuscript.

Funding

This research was financially supported by the SINOPEC Petroleum Exploration and Production Research Institute (NO. 33550007-22-zc0613-0039) and Sichuan Science and Technology Program (NO. 2025YFHZ0021).

Data Availability Statement

The data that support the findings of this study are available from the corresponding author upon reasonable request.

Acknowledgments

Thanks are also extended to the anonymous reviewers for their constructive comments.

Conflicts of Interest

The authors declare no conflicts of interest.

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Figure 1. Regional geological setting of the study area. (a) Structural framework of the Sichuan Basin and the study area. (b) Generalized stratigraphic framework of the Sichuan Basin. (c) Composite lithostratigraphic architecture of the Wufeng–Longmaxi succession in the Southern Sichuan Basin sector.
Figure 1. Regional geological setting of the study area. (a) Structural framework of the Sichuan Basin and the study area. (b) Generalized stratigraphic framework of the Sichuan Basin. (c) Composite lithostratigraphic architecture of the Wufeng–Longmaxi succession in the Southern Sichuan Basin sector.
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Figure 2. Mineral composition bar charts of wells and shale sample ternary diagrams for the Wufeng Formation-Long 1-1 Sub-member in the Neijiang–Rongchang Block.
Figure 2. Mineral composition bar charts of wells and shale sample ternary diagrams for the Wufeng Formation-Long 1-1 Sub-member in the Neijiang–Rongchang Block.
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Figure 3. Bar chart of the average TOC content in shales from different well locations in the Wufeng Formation–Long1-1 Sub-member and the composite stratigraphic column of TOC content in Well R232, Neijiang–Rongchang Block.
Figure 3. Bar chart of the average TOC content in shales from different well locations in the Wufeng Formation–Long1-1 Sub-member and the composite stratigraphic column of TOC content in Well R232, Neijiang–Rongchang Block.
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Figure 4. Contour map of vitrinite reflectance (Ro) in shales of the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Figure 4. Contour map of vitrinite reflectance (Ro) in shales of the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
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Figure 5. Characteristics of reservoir spaces in shales of the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block. (a) Well R232, 3531.5 m, S1l11, honeycomb-like organic pores; (b) Well W204H, 3359.4 m, S1l17, elongated organic pores formed by clay mineral intercrystalline pores filled with organic matter; (c) Well L208, 3800.85 m, S1l16, honeycomb-like organic pores; (d) Well R232, 3506.76 m, S1l15, intercrystalline pores associated with framboidal pyrite aggregates; (e) Well R233-H, 3898.85 m, S1l12, intercrystalline pores along chlorite mineral edges; (f) Well W205, 3695.34 m, S1l14, intragranular dissolution pores developed within calcite cleavage planes; (g) Well L205, 3859.34 m, S1l11, calcite-filled cross-cutting fractures; (h) Well W219, 3706.9 m, S1l17, high-angle fractures infilled with calcite; and (i) Well R232, 3529.29 m, S1l13, intragranular dissolution pores in detrital grains.
Figure 5. Characteristics of reservoir spaces in shales of the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block. (a) Well R232, 3531.5 m, S1l11, honeycomb-like organic pores; (b) Well W204H, 3359.4 m, S1l17, elongated organic pores formed by clay mineral intercrystalline pores filled with organic matter; (c) Well L208, 3800.85 m, S1l16, honeycomb-like organic pores; (d) Well R232, 3506.76 m, S1l15, intercrystalline pores associated with framboidal pyrite aggregates; (e) Well R233-H, 3898.85 m, S1l12, intercrystalline pores along chlorite mineral edges; (f) Well W205, 3695.34 m, S1l14, intragranular dissolution pores developed within calcite cleavage planes; (g) Well L205, 3859.34 m, S1l11, calcite-filled cross-cutting fractures; (h) Well W219, 3706.9 m, S1l17, high-angle fractures infilled with calcite; and (i) Well R232, 3529.29 m, S1l13, intragranular dissolution pores in detrital grains.
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Figure 6. Adsorption/desorption isotherms of the Wufeng Formation–Long1-1 Sub-member in the Neijiang–Rongchang Block.
Figure 6. Adsorption/desorption isotherms of the Wufeng Formation–Long1-1 Sub-member in the Neijiang–Rongchang Block.
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Figure 7. Pore size distribution curve of shales in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Figure 7. Pore size distribution curve of shales in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
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Figure 8. Pore volume distribution characteristics from different well locations and specific surface area vs. pore volume relationship of shales in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Figure 8. Pore volume distribution characteristics from different well locations and specific surface area vs. pore volume relationship of shales in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
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Figure 9. Relationship between TOC and mineral contents in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block. (a) Correlation Plot of TOC Content and Carbonate Mineral Content; (b) Correlation Plot of TOC Content and Siliceous Mineral Content; (c) Correlation Plot of TOC Content and Clay Mineral Content.
Figure 9. Relationship between TOC and mineral contents in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block. (a) Correlation Plot of TOC Content and Carbonate Mineral Content; (b) Correlation Plot of TOC Content and Siliceous Mineral Content; (c) Correlation Plot of TOC Content and Clay Mineral Content.
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Figure 10. Characteristics of organic pore connectivity in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Figure 10. Characteristics of organic pore connectivity in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Minerals 15 00499 g010
Minerals 15 00499 g012
Figure 12. Pore evolution model based on thermal simulation experiments of shale samples.
Figure 12. Pore evolution model based on thermal simulation experiments of shale samples.
Minerals 15 00499 g012
Table 1. Kerogen type classification of shale in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Table 1. Kerogen type classification of shale in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Sample NumberStrataTIδ13C (‰)Kerogen Type
1S1l1670.80−31.26Ⅰ
2S1l1573.66−28.45Ⅱ-1
3S1l1380.20−30.25Ⅰ
4S1l1383.56−31.56Ⅰ
5S1l1278.45−28.81Ⅱ-1
6S1l1175.67−29.46Ⅰ
7O3w79.85−31.62Ⅰ
Table 2. Porosity and permeability statistics of shales in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Table 2. Porosity and permeability statistics of shales in the Wufeng Formation–Long1-1 Sub-member, Neijiang–Rongchang Block.
Sample NumberStrataTotal Porosity (%)Effective Porosity (%)Permeability (×10−3 μm2)
1S1l176.724.980.0857
2S1l166.383.570.0918
3S1l167.213.980.1216
4S1l1510.117.860.1573
5S1l146.895.250.1385
6S1l136.484.660.3752
7S1l1211.8510.290.6760
8S1l1111.308.950.6428
9O3w9.876.850.1587
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Chen, S.; Xi, Z.; Huo, F.; Jiang, B. Source-Reservoir Characteristics and Pore Evolution Model of the Lower Paleozoic Shales in the Neijiang–Rongchang Area, Sichuan Basin. Minerals 2025, 15, 499. https://doi.org/10.3390/min15050499

AMA Style

Chen S, Xi Z, Huo F, Jiang B. Source-Reservoir Characteristics and Pore Evolution Model of the Lower Paleozoic Shales in the Neijiang–Rongchang Area, Sichuan Basin. Minerals. 2025; 15(5):499. https://doi.org/10.3390/min15050499

Chicago/Turabian Style

Chen, Shizhen, Zhidian Xi, Fei Huo, and Bingcheng Jiang. 2025. "Source-Reservoir Characteristics and Pore Evolution Model of the Lower Paleozoic Shales in the Neijiang–Rongchang Area, Sichuan Basin" Minerals 15, no. 5: 499. https://doi.org/10.3390/min15050499

APA Style

Chen, S., Xi, Z., Huo, F., & Jiang, B. (2025). Source-Reservoir Characteristics and Pore Evolution Model of the Lower Paleozoic Shales in the Neijiang–Rongchang Area, Sichuan Basin. Minerals, 15(5), 499. https://doi.org/10.3390/min15050499

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