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Article

Pore Structure and Its Controlling Factors of Cambrian Highly Over-Mature Marine Shales in the Upper Yangtze Block, SW China

by
Dadong Liu
1,2,3,*,
Mingyang Xu
1,2,
Hui Chen
1,2,
Yi Chen
3,
Xia Feng
3,
Zhenxue Jiang
1,2,3,
Qingqing Fan
1,2,
Li Liu
1,2 and
Wei Du
3
1
State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum, Beijing 102249, China
2
State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Beijing 102206, China
3
Key Laboratory of Unconventional Natural Gas Evaluation and Development in Complex Tectonic Areas, Ministry of Natural Resources, Guiyang 550004, China
*
Author to whom correspondence should be addressed.
J. Mar. Sci. Eng. 2025, 13(5), 1002; https://doi.org/10.3390/jmse13051002
Submission received: 21 April 2025 / Revised: 18 May 2025 / Accepted: 19 May 2025 / Published: 21 May 2025
(This article belongs to the Topic Formation Mechanism and Quantitative Evaluation of Deep to Ultra-Deep High-Quality Reservoirs)
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Abstract

:
Highly over-mature marine shales are distributed worldwide with substantial resource potential, yet their pore structure characteristics and controlling mechanisms remain poorly understood, hindering accurate shale gas resource prediction and efficient development. This study focuses on the Cambrian Niutitang Formation shales in the Upper Yangtze region of South China. To decipher the multiscale pore network architecture and its genetic constraints, we employ scanning electron microscopy (SEM) pore extraction and fluid intrusion methods (CO2 and N2 adsorption, and high-pressure mercury intrusion porosimetry) to systematically characterize pore structures in these reservoirs. The results demonstrate that the shales exhibit high TOC contents (average 4.78%) and high thermal maturity (average Ro 3.64%). Three dominant pore types were identified: organic pores, intragranular pores, and intergranular pores. Organic pores are sparsely developed with diameters predominantly below 50 nm, displaying honeycomb, slit-like, or linear morphologies. Intragranular pores are primarily feldspar dissolution voids, while intergranular pores exhibit triangular or polygonal shapes with larger particle sizes. CO2 adsorption isotherms (Type I) and low-temperature N2 adsorption curves (H3-H4 hysteresis) indicate wedge-shaped and slit-like pores, with pore size distributions concentrated in the 0.5–50 nm range, showing strong heterogeneity. Pore structure shows weak correlations with TOC and quartz content but a strong correlation with feldspar abundance. This pattern arises from hydrocarbon generation exhaustion and graphitization-enhanced organic pore collapse under high compaction stress, which reduces pore preservation capacity. The aulacogen tectonic setting engenders proximal sediment provenance regimes that preferentially preserve labile minerals such as feldspars. This geological configuration establishes optimal diagenetic conditions for the subsequent development of meso- and macro-scale of dissolution pores. Our findings demonstrate that feldspar-rich shales, formed in a proximal depositional system with well-developed inorganic pores, serve as favorable reservoirs for the exploration of highly over-mature marine shale gas.

1. Introduction

The pore structure characteristics of shale reservoirs play a crucial role in shale gas storage and enrichment [1,2,3,4,5]. Features of shale reservoirs include extremely low porosity and permeability, where micrometer- to nanometer-scale pores serve as both critical storage spaces and primary migration pathways for shale gas [1,6,7,8]. Previous studies have demonstrated that shale pore architecture is controlled by multiple factors, including TOC content, mineral composition, and thermal maturity [9]. Organic matter content and thermal evolution directly control the development of organic pores, which are intrinsically linked to hydrocarbon generation processes [10]. Inorganic minerals in shale exhibit dual control mechanisms: (1) governing the development of inorganic pores themselves; (2) influencing both organic and inorganic pore systems through organic–inorganic interactions. Notably, the composition of shale’s inorganic minerals shows significant correlations with provenance characteristics and chemical weathering degrees. Specifically, unstable minerals (e.g., feldspar) typically indicate proximal provenance with relatively weak chemical weathering, whereas stable minerals (e.g., clay minerals such as kaolinite and chlorite) reflect distal provenance and intensive chemical weathering processes [11]. Consequently, the shale pore structure is governed by complex organic–inorganic synergies [7].
It is well accepted that shale pore structure is highly influenced by lithofacies, which commonly refer to the mineral composition, sedimentary structure, texture attributes, and bedding characteristics [12,13]. Recent studies have substantiated that critical shale reservoir attributes, including storage capacity, gas transport efficiency, and hydraulic fracability, demonstrate fundamental dependencies on both total organic carbon (TOC) content and inorganic mineral assemblages. Consequently, shale lithofacies classification criteria should primarily be governed by these geochemical constituents rather than conventional sedimentological parameters such as granulometric distribution, bedding architecture, or depositional fabric patterns. This classification criteria enables comparative analysis of differential impacts of organic versus inorganic components on pore network architecture [14,15].
Extensive studies have been conducted on high-to-over mature marine shale reservoirs (Ro < 3.6%), such as the Mississippian Barnet shale in Texas, USA [13], the Lower Silurian Longmaxi Formation in the Sichuan Basin, SW China [16], and the middle Permian Dohol Formation in the Eastern Belt of Peninsular Malaysia [17], and concluded that the reservoir attributions are highly influenced by tectonic history, depositional environment, and diagenetic processes [7,8,11]. However, research on highly over-mature shales (Ro > 3.6%) remains scarce, despite its critical importance for systematically understanding shale reservoir evolution [18]. The Cambrian Niutitang Formation in the Upper Yangtze region represents a key marine shale gas exploration target in southern China, characterized by high TOC contents, extensive distribution, and extremely high thermal maturity [19,20]. Nevertheless, its pore structure and the controlling factors remain poorly constrained, which hinders efficient exploration and development of shale gas resources in this formation [21,22].
This study investigates the Cambrian Niutitang Formation shales in the Upper Yangtze region of South China, employing TOC and mineralogical analyses to classify lithofacies types, combined with SEM-based pore extraction and quantitative fluid intrusion characterization (including CO2 adsorption, N2 adsorption, and high-pressure mercury intrusion) to systematically analyze pore structure characteristics and identify dominant controlling factors for high-quality reservoir development. The research reveals critical linkages between organic–inorganic diagenetic processes and pore architecture evolution in ultra-high maturity shales, providing crucial insights for guiding sweet spot identification in overmature shale reservoirs and enhancing shale gas exploration efficiency.

2. Geological Setting

The South China plate was located in the northwestern margin of Gondwana during the Ediacaran–Cambrian transition, which consisted of the Yangtze Block in the northwest and the Cathaysia Block in the southeast (Figure 1a) [15]. The study area is situated in the Upper Yangtze Block, where the Cambrian Niutitang Formation predominantly comprises dark gray to black shales, siliceous shales, and silty mudstones, with occasional interbeds of marlstone and siltstone (Figure 1b) [20,23]. This stratigraphic unit exhibits stable regional distribution and significant depositional thickness ranging from 200 to 900 m [24,25]. During the Early Cambrian period, the region developed a shallow-water to deep-water sedimentary framework from northwest to southeast, influenced by global marine transgression events [26,27]. The Niutitang Formation is subdivided into two members: the Lower member displays persistent horizontal laminations with pyrite aggregates and barite mineralization, indicative of deep-water reducing depositional environments [28]. In contrast, the Upper member features reduced pyrite content, dominated by calcareous mudstones and marls with heterogeneous limestone–silty mudstone intercalations [23,29,30]. This vertical lithofacies differentiation reflects progressive shallowing of the depositional system, transitioning from euxinic basinal facies in the Lower member to carbonate ramp environments in the Upper member (Figure 1) [31,32,33].

3. Sampling and Methods

Thirty-two core samples were collected from Wells TX-1, TM-1, and CD-1 (Figure 1a). All samples underwent initial thin-section petrography and X-ray diffraction (XRD) mineralogical composition analysis. Twelve representative specimens were selected for advanced characterization: argon-ion polished scanning electron microscopy (SEM) imaging at 5–20 kV accelerating voltages; multi-scale pore structure quantification through CO2/N2 physisorption (performed at 273 K and 77 K, respectively) and high-pressure mercury intrusion porosimetry (MIP) with pressure up to 60,000 psi. This integrated workflow enabled systematic evaluation of nanopore (<2 nm) to macropore (>50 μm) distributions, ensuring lithofacies-controlled multi-scale pore network analysis critical for understanding fluid storage and migration capacities in these ultra-tight reservoirs.

3.1. TOC, Mineral Components, and Thermal Maturity Analyses

TOC content determination was performed using a LECO CS230 carbon/sulfur analyzer (St. Joseph, MI, USA) at the State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing). Mineralogical composition analysis was conducted via a Bruker D8 DISCOVER X-ray diffractometer (Madison, WI, USA) under controlled laboratory conditions (24 °C, 35% relative humidity), with relative mineral percentages quantified using characteristic peak area integration calibrated against the ICDD PDF-4+ database. Detailed analytical procedures refer to Chalmers and Bustin (2013) [4].
Given the absence of vitrinite in highly mature shales, thermal maturity assessment employed laser Raman spectroscopy with 532 nm excitation wavelength, 10–20 s exposure times, and 500–3000 cm−1 spectral range. Spectral deconvolution using PeakFit v4.12 software applied linear baseline correction and Voigt function fitting to resolve D and G bands. Vitrinite reflectance equivalent (VRe) values were calculated through established correlations between Raman spectral parameters and thermal maturity scales. Full analytical procedures are reported in Kibria et al. (2020) [34].

3.2. Field Emission-Scanning Electron Microscopy (FE-SEM)

Pore morphology characterization in shale reservoirs was conducted using a ZEISS 540 scanning electron microscope (Jena, Germany). To obtain ultra-smooth surfaces for high-resolution imaging, shale samples underwent sequential argon-ion beam polishing: initial surface preparation at 8 kV for 4 h followed by final polishing at 6 kV for 2 h. The SEM system operated in high-vacuum mode with secondary electron imaging configuration, employing a 15 kV accelerating voltage and optimized working distance (typically 4–6 mm) to achieve secondary electron images with a theoretical maximum resolution of 3.5 nm. This protocol enabled nanoscale visualization of organic-hosted pores, intragranular dissolution features, and interparticle pore networks critical for reservoir quality assessment [35,36].

3.3. CO2 and N2 Adsorption

CO2 and N2 adsorption experiments were performed using a Quanta Autosorb iQ automated gas sorption analyzer (Coral Springs, FL, USA) at 77.35 K to determine adsorption–desorption isotherms. CO2 adsorption data were analyzed through density functional theory (DFT) modeling for micropore characterization (<2 nm), while N2 adsorption results were interpreted using Barrett–Joyner–Halenda (BJH) mesopore modeling (2–50 nm) and Brunauer–Emmett–Teller (BET) surface area analysis. This multi-method approach enables comprehensive pore structure quantification across multiple scales, with CO2 adsorption resolving ultra-micropore (<0.7 nm) distributions and N2 adsorption constraining mesopore connectivity and surface roughness parameters critical for gas storage capacity evaluation.

3.4. Mercury Intrusion Porosimetry (MIP)

High-pressure mercury intrusion porosimetry (MIP) was carried out using a Micromeritics AutoPore IV 9500 automated mercury porosimeter (Norcross, GA, USA). Cubic specimens (1 cm edge length) were oven-dried at 120 °C for 24 h to remove free and bound water, followed by vacuum degassing. Pore characterization employed the Young–Dupre equation for specific surface area calculation and the Washburn equation to derive pore radius–pressure correlations. Mercury intrusion curves were analyzed to quantify mercury saturation versus applied pressure (0.5–60,000 psi), enabling the determination of pore throat size distributions (3 nm–360 μm range) and cumulative pore volumes. This methodology provides multiscale porosity data critical for evaluating macropore-dominated flow pathways and storage capacity in tight shale systems.

4. Results

4.1. Shale Lithofacies

Geochemical analysis of 32 Niutitang Formation shale samples from the study area reveals high total organic carbon (TOC) contents, with over 90% of samples exhibiting TOC contents exceeding 2% and an average TOC value of 4.78%. Laser Raman spectroscopy thermal maturity assessments demonstrate advanced hydrocarbon evolution across three key wells: TX-1 well samples show vitrinite reflectance equivalent (Ro) values ranging from 3.63% to 3.78% (average 3.69%), TM-1 well samples range between 3.54% and 3.68% (average 3.61%), and CD-1 well samples exhibit Ro values from 3.46% to 3.65% (average 3.59%). These results collectively confirm that the Niutitang Formation shales have universally entered a highly over-mature stage (Ro > 3.6%), indicating the completion of the primary hydrocarbon generation window and transition to late-stage thermochemical alteration processes [37,38,39].
XRD analysis of the Niutitang Formation shales reveals a distinct mineralogical framework dominated by quartz (average content exceeding 50%), with subordinate clay minerals (17.5% avg., primarily illite/smectite mixed-layer and illite, accompanied by minor chlorite), feldspars (7.74% avg.), carbonates (14.79% avg., including calcite and dolomite), and pyrite (6.67% avg.) (Figure 2). This composition reflects a hybrid siliciclastic-biogenic depositional system influenced by both terrigenous input and marine productivity, where elevated quartz content suggests multiple origins including biogenic silica accumulation and detrital contributions, while carbonate–pyrite associations indicate episodic euxinic conditions during organic-rich shale deposition [11,40,41,42,43].
The lithofacies of the Niutitang Formation shales were classified using a “mineral composition + TOC content” scheme (Figure 3). Given the overall high TOC characteristics of the formation, four organic-richness categories were established based on TOC thresholds: low organic matter (TOC < 1%), moderate organic matter (1% < TOC < 2%), high organic matter (2% < TOC < 4%), and ultra-high organic matter (TOC > 4%). Simultaneously, mineralogical classification defined four lithofacies types using 50% compositional boundaries: siliceous shales (siliceous minerals ≥ 50%), calcareous shales (carbonate minerals ≥ 50%), argillaceous shales (clay minerals ≥ 50%), and mixed shales (all mineral components < 50%) (Figure 3). This dual-parameter classification system integrates geochemical and petrological criteria to systematically characterize reservoir heterogeneity.
The Niutitang Formation shales in the study area were classified into six major lithofacies types based on the aforementioned classification scheme: siliceous shale (S), calcareous shale (C), argillaceous shale (A), siliceous-mixed shale (SM), calcareous-mixed shale (CM), and argillaceous-mixed shale (AM). When integrated with organic matter content, the dominant lithofacies combinations identified include: ultra-high organic matter siliceous shale (U-S), ultra-high organic matter argillaceous-mixed shale (U-AM), ultra-high organic matter calcareous-mixed shale (U-CM), high organic matter argillaceous-mixed shale (H-AM), high organic matter siliceous-mixed shale (H-SM), and moderate organic matter siliceous shale (M-S) (Figure 3).

4.2. SEM-Based Semi-Quantitative Pore Structure Characterization

FE-SEM observations reveal three primary pore types in the Niutitang Formation shales: organic pores, intragranular pores, and intergranular pores (Figure 4). Organic pores, predominantly occurring within organic matter, constitute the main pore type in the study area. These nanometer-scale pores (<50 nm) exhibit honeycomb-like, slit-like, or irregular morphologies (Figure 4a–c). Compared with the Wufeng–Longmaxi shales, the Niutitang shales demonstrate inferior organic pore development [44,45]. Intragranular pores include two subtypes: dissolution pores formed by mineral corrosion (Figure 4d,e) and lattice-defect pores from crystal structure imperfections (Figure 4f). Intragranular pores in the Niutitang shales primarily comprising feldspar and carbonate dissolution pores, with some isolated larger pores displaying polygonal shapes. Dissolution pore formation is influenced by hydrocarbon generation processes, where organic acids produced during maturation dissolve calcite and feldspar minerals, creating variably sized dissolution voids. Intergranular pores are formed between detrital components (quartz, feldspar, carbonates, pyrite, and clay), exhibiting polygonal geometries with straight edges and predominantly nanometer-scale diameters, though some reach micrometer dimensions (Figure 4g–i). These pores are particularly susceptible to mechanical compaction and cementation effects. Additionally, grain-edge pores or fractures along mineral boundaries are occasionally observed.
SEM image processing and analysis using ImageJ software (v 1.0) enables semi-quantitative characterization of microscopic pore structures in shale reservoirs [46]. Prior to pore extraction, raw images undergo essential preprocessing to enhance feature recognition. The workflow involves the following: (1) conversion of original images into grayscale format to eliminate color interference; (2) application of the “Threshold” plugin for semi-automatic segmentation of pores (low-intensity regions) versus matrix (high-intensity regions) based on grayscale histograms; (3) quantitative calculation of pore parameters including count, area, and porosity percentage using built-in analytical tools. This standardized protocol ensures systematic identification and measurement of nano- to micro-scale pore networks while maintaining geometric fidelity of pore morphologies.
Analytical results demonstrate distinct organic porosity characteristics across the six lithofacies types: ultra-high organic matter siliceous shales (U-S) exhibit 7.81% areal porosity with pore sizes predominantly distributed in the 10–30 nm and 30–50 nm ranges, each accounting for over 30% of total pores. Ultra-high organic matter argillaceous-mixed shales (U-AM) show 3.82% areal porosity dominated by pores < 50 nm (exceeding 30% proportion). Ultra-high organic matter calcareous-mixed shales (U-CM) display lower areal porosity (2.63%) with pores primarily concentrated in the 30–50 nm range (>40% proportion). High organic matter argillaceous-mixed shales (H-AM) achieve 8.53% areal porosity, featuring bimodal pore size distribution between 10 and 30 nm and 30–50 nm. High organic matter siliceous-mixed shales (H-SM) present 2.64% areal porosity dominated by sub-30 nm pores, while moderate organic matter siliceous shales (M-S) exhibit 1.81% areal porosity with majority pores (over 30%) in the 10–50 nm range (Figure 5).

4.3. Quantitative Pore Structure Characterization

4.3.1. CO2 Adsorption

The CO2 adsorption method, employing the Density Functional Theory (DFT) model, was utilized to characterize micropore (<2 nm) distributions in the Niutitang Formation shales [47]. All samples exhibit Type I adsorption isotherms, indicative of microporous structures with substantial internal surface areas. Measured CO2 adsorption capacities range from 0.5 to 2.0 mL/g (STP), reaching maximum adsorption at a relative pressure of 0.3 MPa.
As shown in Figure 6, pore volume distributions across lithofacies display tri-modal peaks at 0.35–0.4 nm, 0.5–0.7 nm, and 0.7–0.9 nm. Notably, CO2 adsorption capacities vary significantly among lithofacies, with higher TOC shales not necessarily exhibiting greater adsorption values. This observation suggests that micropore development in the Niutitang shales is not primarily controlled by organic matter content but rather influenced by other mineralogical factors.

4.3.2. N2 Adsorption

Low-temperature N2 adsorption experiments are primarily employed for mesopore (2–50 nm) characterization [48]. Shale samples exhibit distinct hysteresis loops in their N2 adsorption–desorption isotherms at elevated relative pressures (P/P0 > 0.40), where the magnitude and morphology of these hysteresis loops directly reflect the structural complexity and geometric features of reservoir pore networks.
N2 adsorption–desorption isotherm analysis reveals systematic variations across lithofacies while maintaining a general reverse “S” shape profile (Figure 7). At low relative pressures (P/P0 < 0.1), adsorption primarily occurs in micropores (<2 nm). The inflection point at P/P0 ≈ 0.4 indicates transition to multilayer adsorption, followed by abrupt adsorption capacity increases at P/P0 > 0.9 due to capillary condensation. Following IUPAC classification, the Niutitang shales exhibit predominantly H3-type hysteresis loops (80–85% of samples), with minor H4-type occurrences (15–20%), suggesting dominant wedge-shaped and slit-like pore geometries. Among ultra-high organic lithofacies, siliceous shales (U-S) exhibit 25–40% higher adsorption values compared to argillaceous-mixed (U-AM) and calcareous-mixed (U-CM) counterparts. Within high organic matter lithofacies, argillaceous-mixed shales (H-AM) show 50–65% greater adsorption capacities than siliceous-mixed shales (H-SM), reflecting mineralogical controls on mesopore accessibility beyond organic matter content (Figure 7).

4.3.3. High Pressure MIP

Mercury intrusion–extrusion curves reveal macroporosity and pore-throat connectivity characteristics in the Niutitang Formation shales [49]. Comparative analysis of high-pressure mercury intrusion (MIP) curves across lithofacies demonstrates distinct mercury saturation variations under equivalent pressures. Within ultra-high organic matter lithofacies, siliceous shales (U-S) exhibit greater mercury intrusion volumes compared to other ultra-high organic lithofacies types (U-AM, U-CM). Similarly, among high organic matter lithofacies, argillaceous-mixed shales (H-AM) display higher mercury intrusion capacities than siliceous-mixed shales (H-SM). These differential intrusion patterns reflect lithofacies-controlled variations in accessible macropore networks and throat size distributions (Figure 8).

5. Discussion

5.1. Effect of TOC on Pore Structure

Extensive studies of organic-rich shales have established organic matter content as a primary control on pore volume and specific surface area, with high-TOC shales demonstrating superior porosity parameters [50,51]. This is primarily attributed to the fact that kerogen generates a significant volume of pores during both the oil generation stage and the subsequent thermal cracking of crude oil into gas. These honeycomb-like, well-connected pores provide abundant surface area and free spaces for gas storage. Consequently, Total Organic Carbon (TOC) has long been recognized as one of the most critical factors influencing shale pore structure development [1,6].
However, the Niutitang Formation shales in this study exhibit weak correlations between TOC content and micro-/mesopore volumes (R2 < 0.25) or specific surface area (R2 < 0.3), with no significant TOC–macropore relationship observed (Figure 9a). This divergence likely stems from the Niutitang shales’ advanced thermal maturity (maximum burial depth ~6000 m, Raman-derived Ro values 3.4–3.8%, avg. 3.65%), indicating late-stage overmaturation where hydrocarbon generation capacity diminishes and graphitization initiates [52,53]. At Ro > 3.6%, organic matter undergoes structural reorganization: (1) reduced hydrocarbon generation limits pore-filling bitumen preservation; (2) graphitic carbon stacking increases matrix rigidity while decreasing pore compressibility; (3) prolonged tectonic activity (multiphase burial-uplift cycles) enhances hydrocarbon migration losses. Concurrently, high TOC content enhances shale plasticity, rendering organic pores more susceptible to compaction-induced collapse (about 45–60% porosity reduction under >50 MPa vertical stress). Unlike the Wufeng–Longmaxi system, the Cambrian Niutitang shales’ extreme diagenetic overprinting and prolonged pressure–temperature history fundamentally alter original pore networks, resulting in the flattening and collapse of pore systems (Figure 10) [54,55,56].
This work challenges conventional TOC-centric shale gas models, emphasizing the critical role of thermal-diagenetic thresholds in governing reservoir viability within over-mature shale systems. The Niutitang case study provides a predictive framework for analogous pre-Silurian shale plays globally, where extreme maturation and tectonic recycling dominate pore evolution pathways. The protracted burial history and polyphase tectonothermal events characteristic of Cambrian-aged shales have imposed compounding effects on their pressure regimes. This geological evolution induces progressive diagenetic overprints, particularly destabilizing mechanically vulnerable organic-hosted pores through tectonic deformation and collapse, ultimately degrading bulk reservoir competence.

5.2. Effect of Clay Minerals on Pore Structure

During shale reservoir diagenesis, temperature and pressure variations drive mineralogical transformations among clay minerals, notably the conversion of smectite to illite, which generates pore-fracture networks and enhances specific surface area [57,58]. The layered and flocculent structures of clay minerals further amplify surface area contributions. Additionally, clay minerals catalyze hydrocarbon generation from organic matter, indirectly increasing organic pore abundance, thereby establishing a positive correlation between clay content and organic porosity development [59,60]. XRD analysis of the Niutitang Formation shales identifies illite and illite/smectite mixed-layer clays as dominant components (72–85% of clay fraction), with subordinate chlorite (15–28%). This mineral assemblage reflects advanced diagenetic alteration, where smectite illitization (I/S ordering > 80%) promotes micro-fracture formation while layered clay architectures enhance adsorption capacity, collectively governing pore network complexity in these thermally overmature systems.
The Niutitang Formation shales exhibit weak negative correlations between clay mineral content and pore volume/specific surface area across micro-, meso-, and macroporosity domains (Figure 9b). Fishman et al. (2012) [61] attribute such relationships to clay-dominated lithologies lacking rigid grain frameworks, where enhanced ductility promotes pore collapse under compaction, while migrated bitumen occludes inter-/intragranular pores, particularly in micro- and mesopore networks. Although abundant clay interlayer pores exist within the shale matrix (Figure 10), their preservation relies on rigid mineral supports (quartz, feldspar, pyrite), yet these pores contribute minimally to total pore volume due to limited connectivity and nanometer-scale dimensions [62,63,64]. Post-depositional tectonic uplift, generating extensive fractures and folds, accelerated hydrocarbon leakage and thermal decline, decelerating clay-porosity transformation kinetics [65,66]. This process reduces the specific surface area of the shale matrix during clay mineral diagenesis, further explaining the observed clay-specific surface area inverse correlation. The combined effects of compaction-induced pore occlusion, rigid mineral-dominated pore preservation, and stress-driven surface area reduction collectively govern the subdued role of clay minerals in porosity development within these ultra-tight reservoirs [67,68].

5.3. Effect of Brittle Minerals on Pore Structure

Pore systems associated with brittle minerals constitute critical reservoir spaces in shale gas systems, primarily occurring between or within rigid brittle particles [69,70]. In the Niutitang Formation shales, quartz content averages 51.95%, yet exhibits negligible correlations with micropore (R2 = 0.0905), mesopore (R2 = 0.0895), and macropore (R2 = 0.0723) volumes, indicating minimal quartz control on pore porosity development. Specific surface area analysis further reveals insignificant quartz influence, with correlation coefficients of 0.1876 (micropores) and 0.065 (mesopores) (Figure 9c). This behavior reflects the dual roles of quartz: (1) as rigid framework suppressors limiting macropore development via pressure dissolution and overgrowth cementation; (2) as chemically inert components providing minimal surface reactivity for physisorption [71,72]. The observed relationships highlight that while quartz enhances mechanical brittleness, its dominance in these ultra-mature shales does not translate to improved storage capacity, necessitating revised exploration strategies that prioritize ductile–organic composites over conventional brittle mineral targets.
Previous studies indicate that authigenic quartz enhances pore development, while detrital quartz exerts minimal influence [73]. The Niutitang Formation shales, deposited in a marine environment, predominantly contain authigenic microcrystalline quartz [54]. This siliceous phase forms a rigid framework that mitigates pore collapse and preserves primary porosity [74]. Moderate quartz content (40–60%) optimizes porosity preservation; however, its high weathering resistance compared to feldspar and carbonate minerals limits dissolution-related porosity generation. Consequently, excessive quartz content (>65%) inhibits macropore development by suppressing chemical leaching processes and promoting cementation-dominated diagenesis. This dual behavior reflects the critical balance between quartz’s mechanical stabilization benefits and its chemical inertness in controlling pore architecture within marine shale systems [74].
The Niutitang Formation shales exhibit an average feldspar content of 7.744%, with distinct correlations to pore structure parameters. The relatively high feldspar content in the Niutitang Formation shales is genetically linked to their tectonic setting and/or chemical weathering processes. During the Early Cambrian period, the Upper Yangtze region was in an aulacogen tectonic setting [33], which provided proximal sediment sourcing conditions conducive to the preservation of labile minerals such as feldspars [11]. Meanwhile, the low-to-moderate chemical weathering degree of this formation (with CIA values of 56–74 and an average of 64) also favors the preservation of feldspars [75,76,77]. Feldspar demonstrates a weak correlation with micropore volume (R2 = 0.1142), but a moderate correlation with mesopore volume (R2 = 0.4345) and a strong correlation with macropore volume (R2 = 0.6007), indicating its significant influence on meso- and macropore development (Figure 9d). Higher feldspar content corresponds to better-developed macropores, primarily attributed to intergranular pores between feldspar and other minerals, as well as intragranular dissolution pores within feldspar grains (Figure 10) [78]. Specific surface area analysis reveals a moderate correlation between feldspar content and mesopore surface area (R2 = 0.4538), and a weak correlation with micropore surface area (R2 = 0.2756) (Figure 9d). These trends highlight feldspar’s dominant role in enhancing mesopore network complexity through dissolution-related porosity generation, while its contribution to macroporosity is largely structural rather than surface area-dependent [79]. The preferential development of feldspar-associated mesopores underscores the mineral’s diagenetic importance in governing fluid migration pathways within these thermally overmature shales.
The Niutitang Formation shales contain an average carbonate mineral content of 13.81%, exhibiting negligible correlations with micro- (R2 = 0.0921), meso- (R2 = 0.0397), and macropore (R2 = 0.0059) volumes (Figure 9e). The weak negative correlation with micropore volume suggests limited nano-scale pores and fractures within carbonate-rich matrices or cementation phases, while carbonate minerals demonstrate minimal influence on meso- and macropore development [80]. Specific surface area analysis further reveals insignificant carbonate contributions, with correlation coefficients of 0.0134 (micropores) and 0.1783 (mesopores) (Figure 9e). This behavior reflects carbonate diagenetic characteristics: (1) calcite/dolomite cementation preferentially occludes primary pores during burial; (2) carbonate dissolution-reprecipitation cycles under high thermal stress (Ro > 3.6%) homogenize pore networks; (3) mechanical rigidity contrasts between carbonates and clay–organic composites inhibit fracture propagation. The muted porosity-carbonate relationships highlight the subordinate role of carbonate minerals in shaping reservoir architecture within these thermally overmature shales, contrasting sharply with their porosity-enhancing effects in lower-maturity systems [81,82].

6. Conclusions

This study systematically characterizes the pore structure of highly over-mature marine shales from the Cambrian Niutitang Formation through integrated methodologies including SEM-based pore extraction and fluid intrusion techniques (CO2 and N2 adsorption, mercury intrusion). Our results show that, unlike moderately over-mature marine shales (Ro < 3.6%), pore architecture in highly over-mature shales (Ro > 3.6%) shows weak correlations with TOC and quartz content but strong feldspar dependency. SEM observation shows that the organic pores within the Niutitang Formation exhibit elliptical, wedge-shaped, or slit-like morphologies, with pore diameter mostly <50 nm. This pattern arises from hydrocarbon generation exhaustion and graphitization-enhanced organic pore collapse under high compaction stress, which reduces pore preservation capacity. The aulacogen tectonic setting favors the preservation of labile minerals such as feldspars. The diagenesis of feldspar provides ample space for the development of mesopores and macropores. These findings redefine evaluation criteria for highly over-mature shale reservoirs, emphasizing mineral-controlled pore evolution over traditional TOC-dominated models in ultra-high maturity systems.

Author Contributions

Conceptualization, D.L.; methodology, L.L. and Q.F.; software, L.L. and H.C.; validation, D.L.; formal analysis, M.X.; investigation, Z.J.; resources, Y.C., X.F. and W.D.; data curation, H.C.; writing—original draft preparation, D.L.; writing—review and editing, D.L.; visualization, M.X. and H.C.; supervision, Z.J.; project administration, D.L.; funding acquisition, D.L. All authors have read and agreed to the published version of the manuscript.

Funding

This work is funded by the National Natural Science Foundation of China (No. 42472185), Geological Survey Foundation of Guizhou Province, China (52000024P0048BH10174M), Sinopec Petroleum Exploration and Production Research Institute (No. 33550000-24-ZC0699-0112), and PetroChina Southwest Oil & Gas Field Company (No. 2024D104-01-07).

Data Availability Statement

Data will be made available on request.

Acknowledgments

The authors have reviewed and edited the output and take full responsibility for the content of this publication. We express our great gratitude to Daniel Tentori and an anonymous referee, for their critical insight and constructive comments, which have greatly improved this manuscript.

Conflicts of Interest

The authors declare no conflicts of interest.

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Figure 1. (a) Paleogeography of the Yangtze Block in the South China plate during the Early Cambrian showing the location of the studied wells; (b) comprehensive lithological column of the Cambrian Niutitang Formation.
Figure 1. (a) Paleogeography of the Yangtze Block in the South China plate during the Early Cambrian showing the location of the studied wells; (b) comprehensive lithological column of the Cambrian Niutitang Formation.
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Figure 2. (a–c) Whole-rock mineralogical and (d) clay mineral compositions of the Niutitang Formation shales. I/S = mixed illite–smectite. (a) Well TX-1; (b) well TM-1; (c) well CD-1; (d) well TX-1.
Figure 2. (a–c) Whole-rock mineralogical and (d) clay mineral compositions of the Niutitang Formation shales. I/S = mixed illite–smectite. (a) Well TX-1; (b) well TM-1; (c) well CD-1; (d) well TX-1.
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Figure 3. Lithofacies classification diagram for the Niutitang Formation shales.
Figure 3. Lithofacies classification diagram for the Niutitang Formation shales.
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Figure 4. FE-SEM images showing characteristics of (a–c) organic pores; (d–f) intragranular pores; and (g–i) intergranular pores.
Figure 4. FE-SEM images showing characteristics of (a–c) organic pores; (d–f) intragranular pores; and (g–i) intergranular pores.
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Figure 5. SEM image-based pore extraction of different lithofacies of shales from the Niutitang Formation. The red areas are extracted pores or micro-fractures. (a) The U-S lithofacies, with TOC content of 6.25%, exhibit areal porosity of 7.81% and pore diameter mainly at 10–30 nm and 30–50 nm; (b) the U-AM lithofacies, with TOC content of 8.01%, show areal porosity of 3.82% and pore diameter mainly below 50 nm; (c) the U-CM lithofacies, with TOC content of 5.32%, exhibit areal porosity of 2.63% and pore diameter mainly at 30–50 nm; (d) the H-AM lithofacies, with TOC content of 3.22%, represent areal porosity of 8.53% and pore diameter mainly at 10–30 and 30–50 nm; (e) the H-SM lithofacies, with TOC content of 2.84%, exhibit areal porosity of 2.64% and pore diameter mainly below 30 nm; (f) the M-S lithofacies, with TOC content of 1.65%, show areal porosity of 1.81% and pore diameter mainly below 50 nm.
Figure 5. SEM image-based pore extraction of different lithofacies of shales from the Niutitang Formation. The red areas are extracted pores or micro-fractures. (a) The U-S lithofacies, with TOC content of 6.25%, exhibit areal porosity of 7.81% and pore diameter mainly at 10–30 nm and 30–50 nm; (b) the U-AM lithofacies, with TOC content of 8.01%, show areal porosity of 3.82% and pore diameter mainly below 50 nm; (c) the U-CM lithofacies, with TOC content of 5.32%, exhibit areal porosity of 2.63% and pore diameter mainly at 30–50 nm; (d) the H-AM lithofacies, with TOC content of 3.22%, represent areal porosity of 8.53% and pore diameter mainly at 10–30 and 30–50 nm; (e) the H-SM lithofacies, with TOC content of 2.84%, exhibit areal porosity of 2.64% and pore diameter mainly below 30 nm; (f) the M-S lithofacies, with TOC content of 1.65%, show areal porosity of 1.81% and pore diameter mainly below 50 nm.
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Figure 6. CO2 adsorption isotherms and pore size distributions of different lithofacies of shales from the Niutitang Formation.
Figure 6. CO2 adsorption isotherms and pore size distributions of different lithofacies of shales from the Niutitang Formation.
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Figure 7. N2 adsorption isotherms and pore size distributions of different lithofacies of shales from the Niutitang Formation.
Figure 7. N2 adsorption isotherms and pore size distributions of different lithofacies of shales from the Niutitang Formation.
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Figure 8. Mercury intrusion–extrusion curves and pore size distributions of different lithofacies of shales from the Niutitang Formation.
Figure 8. Mercury intrusion–extrusion curves and pore size distributions of different lithofacies of shales from the Niutitang Formation.
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Figure 9. Correlation coefficients (R2) histogram of pore volume and pore-specific surface area with (a) TOC; (b) clay minerals; (c) quartz; (d) feldspar; (e) carbonate minerals.
Figure 9. Correlation coefficients (R2) histogram of pore volume and pore-specific surface area with (a) TOC; (b) clay minerals; (c) quartz; (d) feldspar; (e) carbonate minerals.
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Figure 10. Schematic model of pore development in highly over-mature marine shales.
Figure 10. Schematic model of pore development in highly over-mature marine shales.
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Liu, D.; Xu, M.; Chen, H.; Chen, Y.; Feng, X.; Jiang, Z.; Fan, Q.; Liu, L.; Du, W. Pore Structure and Its Controlling Factors of Cambrian Highly Over-Mature Marine Shales in the Upper Yangtze Block, SW China. J. Mar. Sci. Eng. 2025, 13, 1002. https://doi.org/10.3390/jmse13051002

AMA Style

Liu D, Xu M, Chen H, Chen Y, Feng X, Jiang Z, Fan Q, Liu L, Du W. Pore Structure and Its Controlling Factors of Cambrian Highly Over-Mature Marine Shales in the Upper Yangtze Block, SW China. Journal of Marine Science and Engineering. 2025; 13(5):1002. https://doi.org/10.3390/jmse13051002

Chicago/Turabian Style

Liu, Dadong, Mingyang Xu, Hui Chen, Yi Chen, Xia Feng, Zhenxue Jiang, Qingqing Fan, Li Liu, and Wei Du. 2025. "Pore Structure and Its Controlling Factors of Cambrian Highly Over-Mature Marine Shales in the Upper Yangtze Block, SW China" Journal of Marine Science and Engineering 13, no. 5: 1002. https://doi.org/10.3390/jmse13051002

APA Style

Liu, D., Xu, M., Chen, H., Chen, Y., Feng, X., Jiang, Z., Fan, Q., Liu, L., & Du, W. (2025). Pore Structure and Its Controlling Factors of Cambrian Highly Over-Mature Marine Shales in the Upper Yangtze Block, SW China. Journal of Marine Science and Engineering, 13(5), 1002. https://doi.org/10.3390/jmse13051002

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