Pore-micro fracture structure, porosity and gas- bearing property of deep shale under lithofacies-formation pressure coupling

Yunjun Zhang; Hao Zhang; Li Zhang; Jianlin Li; Yaohui Yan

doi:10.1038/s41598-026-38352-7

. 2026 Feb 4;16:7303. doi: 10.1038/s41598-026-38352-7

Pore-micro fracture structure, porosity and gas- bearing property of deep shale under lithofacies-formation pressure coupling

Yunjun Zhang ¹, Hao Zhang ^1,^✉, Li Zhang ², Jianlin Li ¹, Yaohui Yan ¹

PMCID: PMC12923803 PMID: 41639273

Abstract

Formation pressure-lithofacies type are the most critical factors influencing micro pore structure and porosity in shale reservoir. However, how these two factors jointly affect shale gas accumulation remains unclear. Scanning electron microscopy (SEM), X-ray diffraction (XRD), nuclear magnetic resonance (NMR), on-site desorption and low-temperature N₂ adsorption (LTNA) are integrated to analyze coupling effects of pressure variation and lithofacies on reservoir quality and gas-bearing characteristics of deep-buried shale. Three lithofacies are identified in Longmaxi deep-buried shale: siliceous lithofacies (S), argillaceous lithofacies (CM) and mixed lithofacies (M). Pores with pore size < 4 nm are the main contributors to the specific surface area (SSA), and pores between 4 nm and 30 nm are the main contributors to the pore volume (PV). Pressure variations directly affect the size and number of organic matter pores but have no impact on intraparticle pores. The variability in interparticle pores indicates that the S lithofacies has a stronger resistance to compaction compared to the M lithofacies. Porosity and micro structure of deep-buried shale reservoir are influenced by lithofacies type, burial depth and pressure variation. Organic-rich S shale and organic-poor S shale demonstrate good reservoir properties under over-pressure and well-preserved conditions, with organic-rich S shale having the strongest resistance to compaction. Organic and inorganic pores are largely lost during compaction of organic-rich M shale. CM lithofacies also has a poor material foundation and the weakest resistance to compaction, making it difficult to preserve original porosity and pore structure during compaction. The decrease in formation pressure results in macropores making almost no contribution to pore volume, while the contribution of mesopores is further enhanced. As the formation pressure decreases, the contribution of micropores to pore volume is gradually increased. As shale porosity decreases, porosity associated with macro pores declines first, followed by that associated with mesopores. Free-gas content in the CM and M lithofacies declines rapidly as porosity decreases. Both adsorbed and free gas decrease sharply as porosity is lost.

Keywords: Longmaxi shale, Coupling effect, Formation pressure, Lithofacies type, Porosity variation, Gas content

Subject terms: Energy science and technology, Solid Earth sciences

Introduction

Shale gas reservoirs are typically composed of fine-grained, organic-rich sediments, where nanoscale pores and microfractures serve as the primary spaces for gas storage and migration^1–3. The pore system, comprising both organic and inorganic pores, is a key indicator of shale reservoir quality^2,4–6. Meanwhile, formation pressure has long been recognized as a critical factor controlling shale gas preservation and enrichment^7–10. With the continuous advancement of shale gas exploration, it has been found that even within the same formation, gas content and reservoir quality vary significantly across different regions and structural settings^11–14. Notably, certain lithofacies can maintain high porosity and gas content under low-pressure conditions, suggesting that pressure alone cannot fully explain the heterogeneity of deep shale reservoirs^15–18.

The Longmaxi Formation in the Sichuan Basin represents the most productive shale gas system in China^2,6,19, with proven geological reserves exceeding 1.19 × 10¹² m³. However, commercial production remains concentrated in shallow to medium burial depths (< 3500 m), while the deep-buried shales (> 3500 m) are still in the early stages of exploration^20–22. Compared with shallower reservoirs, deep-buried shales have undergone stronger compaction, more complex diagenetic processes, and multiple tectonic reworking events, leading to pronounced differences in pore preservation and gas occurrence^23–27. Previous studies have demonstrated that overpressure plays a crucial role in mitigating compaction and preserving pore structure^14,28–30. For example, organic-rich siliceous shales tend to maintain higher porosity and gas content under overpressure conditions, whereas clay-rich lithofacies are more susceptible to pore collapse^29,31. These findings indicate that lithofacies characteristics and pressure evolution jointly control the formation and preservation of deep shale reservoirs.

Recent research has shown that deep shales in the Sichuan Basin experienced similar early burial and hydrocarbon generation histories but underwent distinct uplift and pressure evolution processes across different structural zones^32–34. Variations in uplift timing and magnitude have led to differences in gas preservation capacity and pore heterogeneity. Sun et al. (2024)³² emphasized that the timing and intensity of uplift govern the transition of pressure systems and subsequent gas retention. Song et al. (2024)³⁴ reported that during depressurization, adsorbed gas gradually increases while dissolved and free gas decrease. Miao et al. (2025)³⁵ found that under sustained overpressure, organic-rich siliceous shales maintain high porosity and stable pore networks, whereas normal-pressure conditions promote pore compaction and fluid loss. Wei et al. (2023)²⁹ further suggested that biogenic silica and fluid overpressure are key to pore development and preservation, revealing that lithofacies–overpressure coupling is a major factor controlling shale gas enrichment in southeastern Sichuan. Similarly, Wang et al. (2024)³¹ observed that under the same pressure regime, organic-rich siliceous shales exhibit better pore development than organic-poor clay-rich shales, and overpressure effectively reduces compaction-related deformation. Collectively, these studies highlight that the coupling between lithofacies and pressure evolution fundamentally governs pore system development and gas-bearing heterogeneity in deep shale formations.

Although these studies highlight the importance of lithofacies and pressure, most existing work examines their effects separately and lacks quantitative assessment of their coupled influence on pore preservation, pore-size evolution, and gas-bearing capacity in deep-buried shales. In particular, how lithofacies-dependent pore systems respond to compaction and depressurization remains poorly constrained, representing a key scientific gap. To address these unresolved issues, this study investigates deep-buried Longmaxi shales (> 3500 m) from different pressure regimes and aims to quantitatively evaluate the coupling effects of lithofacies and formation pressure on pore structure, pore preservation, and gas-bearing capacity, and clarify the link between pore evolution and gas content, with emphasis on compaction–overpressure interactions. By integrating TOC, mineralogy, pore structure, gas content, and petrophysical data, this study provides a refined understanding of lithofacies–pressure coupling in deep-buried shales and offers a scientific basis for evaluating shale gas potential under various pressure conditions.

Geological backgrounds

Sichuan Basin in SW China has a basin area of 260,000 km² (Fig. 1a). In the Late Ordovician-Early Silurian, most areas of this basin were dominated by shallow to deep-water shelf³⁶. A large area of continuous marine shale was deposited during this period, which is the gas production layer (Fig. 1b). Considering the sedimentary cycle, Longmaxi Formation can be divided into 1st Member and 2nd Member (Fig. 1c). The 1st Member is a gradational reverse cycle of continuous regression³⁷, which is subdivided into 1st Submember and 2nd Submember from bottom to top according to sedimentary cycle and lithologic characteristics¹³. The 1st Submember is the shale gas production interval of commercial exploitation in the South China²⁵. According to the demands of on-site exploitation³⁸, it is divided into four units from bottom to top based on petrological difference and logging signal (Fig. 1c).

The pressure evolution of the Longmaxi Shale is strongly governed by multi-stage tectonic events^6,12. During the late Caledonian to early Hercynian, the basin remained in a shallow-burial and weak-uplift state with a relatively stable pressure regime. From the late Hercynian to early Permian, rapid subsidence drove the shale into deep burial, leading to increasing temperature–pressure conditions and progressive overpressure accumulation. By the early Yanshanian to Early Cretaceous, the strata reached maximum burial depth, forming a high-pressure system. Since the Late Cretaceous, uplift and erosion associated with the late Yanshanian and Himalayan movements caused widespread cooling and depressurization^2,6. Variations in uplift magnitude and timing across different structural belts produced distinct pressure compartments within the basin (Fig. 1b). The superposition of early overpressure buildup and later depressurization resulted in complex pressure evolution pathways and significant differences in shale-gas preservation³². Exploitation practice has shown that the pressure coefficient differences in different areas are directly reflected in the significant differences in gas production^8,39.

Materials, experiments and theories

Approximately 99 core samples, predominantly shale from different stratigraphy and lithofacies, were collected from four representative wells (Well A, B, C, and D) distributed from the basin interior to the basin margin of the Sichuan Basin. Specifically, 25, 30, 31, and 13 samples were obtained from Wells A, B, C, and D, respectively. These wells were selected to capture the regional variability in burial depth and formation pressure of the Longmaxi Formation. Well A and Well D are located in the deep central part of the basin, with burial depths exceeding 5000 m and pressure coefficients of ~ 1.9 and ~ 2.0, respectively. Well B, in the transitional zone, has a burial depth of ~ 4000 m and a pressure coefficient of 1.08, while Well C, near the basin margin, is more shallowly buried with a pressure coefficient of 0.98. This selection ensures regional representativeness across different structural and pressure regimes and provides accessible, continuous core data suitable for comparative analysis of shale pore structure and gas-bearing characteristics.

All samples were collected for TOC measurement and X-ray Diffraction (XRD) and they were completed in the Chengdu University of Technology. TOC values were determined through a LECO CS230 Series Carbon and Sulfur Analyzer. The XRD of bulk and clay mineral were determined using a German Bruker D8 Advance X-ray diffractometer. Mercury intrusion porosimetry (MIP) was performed using a Quantachrome Poremaster. Samples (~ 20 mm × 20 mm, 10–20 g) were oven-dried at 110 °C under vacuum for at least 24 h. The mercury injection pressure ranged from 0 to 215 MPa. To minimize potential artifacts caused by high intrusion pressures, sample integrity was carefully checked before and after testing, and pressure was increased gradually to reduce sudden fracturing. In addition, pore size distributions from MIP were cross-validated with low-temperature adsorption (LTNA/LTCA) results to identify and exclude anomalous readings, ensuring reliable data interpretation. The remaining samples were divided into two parts for Scanning electron microscope (SEM), low temperature carbon dioxide adsorption (LTCA) and low temperature nitrogen adsorption (LTNA). For LTCA and LTNA analyses, the samples were crushed to 60–80 mesh, oven-dried at 110 °C for 12 h, and degassed under vacuum at 110 °C for an additional 12 h. Measurements were conducted using an Autosorb-IQ3 surface and pore size analyzer (Cantor Company, USA). The Brunauer–Emmett–Teller model was applied to determine the specific surface area (SSA) due to its suitability for mesoporous and microporous materials, while the Density Functional Theory model was used to obtain pore size distributions, as it effectively characterizes the heterogeneous and slit-shaped pores typical of shale samples. Pores were classified into micropores (< 2 nm), mesopores (2–50 nm), and macropores (> 50 nm) following Loucks et al. (2012)^40,41. LTCA primarily resolves micropores (< 2 nm), LTNA targets mesopores (2–50 nm), and high-pressure MIP characterizes macropores (> 50 nm). Eight core-plug samples of different shale lithofacies were implemented with nuclear magnetic resonance (NMR) experiment in both dry and saturated fluid states (including n-dodecane and brine water) using a NMRC12-010 V low-field NMR device manufactured by the Suzhou Numag Corporation. The porosity data is sourced from the South Sichuan Basin, Southeastern Sichuan Basin, and northern Guizhou Province.

There are three major test methods for gas content measurement in shale: logging interpretation, isothermal adsorption, and desorption^10,42. The on-site desorption method has the advantages of convenience, simplicity, and rapid measurement. The shale gas content obtained by this method consists of three components: lost gas, desorbed gas, and residual gas⁴³. In this study, the on-site desorption experiment was conducted using a desorption apparatus composed of a thermostatic control unit, desorption canisters, and a gas-measuring system⁴⁴. The methane released from the core in the desorption canister was guided through a connecting hose into an inverted water-sealed glass cylinder. Driven by buoyancy, the gas displaced the water and accumulated at the top of the cylinder, where the released gas volume was measured to obtain the desorbed gas content. During the field desorption process, the desorbed gas volume refers to the total gas released from the core placed in a sealed canister and allowed to desorb naturally until the daily desorption rate falls below 10 cm³, which marks the end of the experiment. Residual gas volume is the amount of gas that remains in the core after canister desorption has ceased, determined by the standard ball-milling method in the laboratory. Lost gas volume is the gas released from the moment the bit penetrates the formation until the core is retrieved at the wellhead and placed into the desorption canister. Because lost gas cannot be measured directly, it is estimated using mathematical models fitted to the desorption data. The total gas content is calculated as the sum of these three components, following the standard procedure specified in GB/T 19,559–2021. This integrated approach ensures the accuracy and representativeness of the measured shale gas content. By contrast, residual gas volume is the amount of gas that remains in the core after canister desorption has ceased. In laboratory practice, ball milling is the standard method for measuring residual gas. Lost gas is the volume released from the moment the bit penetrates the formation until the core is retrieved at the wellhead and placed into the desorption canister. Because lost gas cannot be measured directly, it is estimated using appropriate mathematical modeling fitted to the desorption data.

Results

Lithofacies classification and geological characteristics

Lithofacies classification and mineral composition

Using clay minerals, carbonates, and the sum of quartz and feldspar as the three end-members, shale lithofacies were classified based on mineral content thresholds of 50% and 25%^45,46. For each sample, the proportions of feldspar, carbonate, clay, and quartz were plotted on the ternary diagram (Fig. 2) to illustrate the lithofacies distribution and facilitate interpretation. The results suggest that the 1st to 2nd Unit is composed of siliceous shale (S) (Fig. 2). The lower part of the 3rd Unit is also composed of mixed shale (M), but the upper part of the 3rd Unit is composed of siliceous lithofacies (S). The lower part of the 4th Unit is also composed of mixed shale (M), but the upper part of the 4th Unit is composed of argillaceous shale (CM). The 2nd Submember of Longmaxi Formation is composed of argillaceous shale (CM). The hydrocarbon-rich shale in North America is mainly composed of carbonate shale (C) and siliceous shale (S)⁴⁷.

Fig. 2 — Shale lithofacies classification of the Longmaxi 1st Submember shale.

Bulk organic geochemistry

Measurements from core samples of four shale gas wells indicate that the total organic carbon (TOC) content of the 1st Submember gradually decreases vertically. The overall distribution of TOC in 1st Submember is 1.55%-7.32%, with an average of 2.46%. The 1st Unit S lithofacies exhibits the highest TOC, ranging from 2.80% to 7.32%, with well averages exceeding 5% (Fig. 3). The 2nd Unit S lithofacies has TOC values between 3.81% and 5.10%, with well averages above 4% (Fig. 3). For the 3rd Unit M lithofacies, TOC ranges from 2.26% to 4.97%, with well averages between 4.50% and 5.50%. The 4th Unit CM lithofacies shows the lowest TOC, ranging from 0.28% to 1.92%, with well averages around 2.00%. Overall, organic matter abundance is highest in the 1st Unit S lithofacies, followed by the 3rd Unit M lithofacies, then the 2nd Unit S lithofacies, and lowest in the 4th Unit CM lithofacies (Fig. 3).

Fig. 3 — Comprehensive column of the Longmaxi 1st Submember shale (based on Well C).

Gas-bearing characteristics

The on-site shale gas content comprises three components: desorbed, lost, and residual gas. While desorbed and residual gas volumes can be directly measured, lost gas cannot be determined in situ and is typically estimated using empirical formulas. In China, the most commonly applied approaches for gas loss estimation are the USBM linear method and the polynomial curve method, both originally developed for coalbed methane⁴⁸. Among these, the polynomial curve method has been demonstrated to provide a more objective estimate of lost gas volume in high- to ultra-high-pressure formation^49–51. Since the commercially developed shale gas in the Sichuan Basin is generally characterized by over-pressure^32,51, the polynomial method is used to estimate the lost gas volume^34,52. For comparative purposes, the lost gas volumes are regressed using the polynomial method for subsequent statistical analyses. To facilitate comparative analysis, this study employs the polynomial method to regress lost gas volume. Although uncertainties exist when extrapolating to ultra-high-pressure regimes (pressure coefficient > 2.0), as observed in the Wufeng–Longmaxi Formation where pressures exceeded 2.4 during the mid-Cretaceous before tectonic uplift and depressurization, this method remains necessary for estimating lost gas in overpressure shales³⁵.

Under overpressure conditions, the 1st Unit S lithofacies exhibits the highest gas content, ranging from 7.8 to 18.8 m³/t. The 3rd Unit M lithofacies shows slightly lower gas content, ranging from 5.2 to 13.5 m³/t, while the 4th Unit CM lithofacies consistently presents the lowest gas content across all pressure conditions. As the pressure coefficient decreases, the gas content of all lithofacies significantly decreases. The S lithofacies shows the smallest decrease, while the CM lithofacies exhibits the largest decrease (Fig. 4). With decreasing pressure, the gas content in the shale gradually transforms into a clear upward decreasing trend (Fig. 4).

Fig. 4 — Total gas content (measured by on-site desorption method) of different lithofacies in different pressure coefficient, Longmaxi 1st Submember shale.

Porosity is a key indicator of shale reservoir quality, reflecting the overall storage capacity for both adsorbed and free gas. Higher porosity provides more adsorption surface and space for free gas^53,54. Figure 5 shows a weak positive correlation between porosity and both total gas content and free gas content, indicating that larger pores favor the accumulation of free gas. However, as porosity increases, the adsorbed gas content does not change significantly. This may be related to the degree of fracture development in the reservoir, which strongly influences the storage of adsorbed gas. Fractures can facilitate the release and migration of adsorbed gas, but they can also lead to gas loss, thereby weakening the correlation between porosity and adsorbed gas content^55,56. In addition, micropores and mesopores within organic matter and clay minerals are well developed and provide high specific surface area, making them more favorable for adsorbed gas storage. Therefore, the overall porosity, which largely reflects the abundance of larger pores, is not a primary controlling factor for adsorbed gas content in these shale reservoirs.

Fig. 5 — The relationship for porosity vs. total gas content, adsorbed gas content and free gas content for the Longmaxi 1st Submember shale.

Pore-micro fracture under different formation pressure

Organic matter (OM) pores

Pores developed in OM are considered an important part of the shale gas pore system^57,58. OM pores are often isolated in two-dimensional space (Fig. 6a) but show good connectivity in 3-dimensional space³⁸. The two-dimensional shape is mostly irregular, blister-like, elliptical, beehive-like (Fig. 6b), etc. The OM pore distribution observed in these SEM photos range from 120 nm to 550 nm, mainly macropores (Fig. 6a, b and c). The pore morphology is mostly round, oval, and honeycomb. OM pores are most easily observed in S lithofacies of 1st Unit. With decreasing pressure coefficients and increasing compaction, pore morphology gradually transforms from large, nearly circular pores (hundreds of nanometers to micrometers) to smaller, flattened, or irregularly shaped pores (Fig. 6a–c). Eventually, under strong compaction, only nanoscale (< 50 nm) OM pores remain, typically exhibiting poor circularity (Fig. 6a). This suggests that overpressure conditions are favorable for the preservation of OM pores. In contrast, the number and size of inorganic pores show no significant variation with changes in pressure coefficient (Fig. 6d–f). Under overpressure, OM pores in M lithofacies are comparable in number and size to those in the S lithofacies. However, as pressure decreases, OM pores in the M lithofacies sharply decline in both abundance and size, and are nearly absent when the pressure coefficient drops to 0.98 (Fig. 6g–i). OM pores are not observed in CM lithofacies, likely due to its lower OM content and weaker compaction resistance (Fig. 6j–l).

Intraparticle pores

Intraparticle pores in deep shale were formed during digenetic alteration with feldspar and calcite particles (Fig. 6e). Thus, these pores are commonly observed within almost every feldspar and calcite particle (Fig. 6f). From the perspective of pore size distribution, the intraparticle pores fall into mesopore and macropore range, but the connectivity performance of these pores is generally weak. Under different pressure coefficients, rigid minerals themselves maintain the size and shape of intraparticle pores well (Fig. 6e and f).

Interparticle pores

During the depositional process, the accumulation of sediment will form many micro sedimentary structures⁵⁹. The incomplete cementation between these structures preserves a large number of interparticle pores between sedimentary particles (Fig. 6e). The interparticle pores of deep-buried shale mainly exist between different mineral particles, such as feldspar, illite, pyrite, and quartz. The size of interparticle pores is directly controlled by particle size and compaction strength (Fig. 6h). The larger the particle size, the larger the interparticle pores. The greater the buried depth, the fewer the interparticle pores. In addition, many interparticle pores develop within pyrite framboids. Interparticle pores most accurately reflect intensity of compaction. The decrease in pressure coefficient had no effect on the number and size of interparticle pores in the S lithofacies (Fig. 6d–f), indicating its highest compaction resistance. In the CM lithofacies, interparticle pores nearly disappear due to intense compaction (Fig. 6j–l).

Micro-fractures

Micro fracture width varies markedly with formation pressure, with the effect especially pronounced in fractures associated with organic matter. Under pressure coefficient of 1.9, microfractures can be wider than 1 μm. As pressure declines, the widths of micro-fractures and the sizes of pores within OM gradually decrease (Fig. 6g–i).

Porosity variation under different burial depth and formation pressure

Shale reservoirs in the southern Sichuan Basin occur at varying burial depths, from shallow to deep and ultra-deep layers^13,32. These depth variations lead to significant differences in lithostatic compaction and pore-space preservation^29,31,60. To understand how burial depth influences shale reservoirs, this study compares porosity, pore volume (PV), and SSA, focusing on the development of both organic matter (OM) and inorganic pores across different depths.

Within different TOC intervals, porosity generally decreases with increasing burial depth from 3500 to 4500 m (Fig. 7). For deeply buried shale reservoirs (> 3500 m), porosity values mostly range between 1% and 6%. Around 3500 m, the decline in porosity becomes moderate, and some samples retain relatively high porosity within the 3500–4000 m interval (Fig. 7). With increasing burial depth, the formation pressure coefficient also rises. Based on depth and pressure, the deep shale intervals are divided into three ranges: <3000 m, 3000–3500 m, and > 3500 m, and the relationships between porosity and formation pressure coefficient were statistically analyzed. When burial depth is < 3000 m, porosity increases with both depth and formation pressure coefficient (Fig. 7). However, for depths > 3000 m, where the pressure coefficient generally exceeds 1.4, porosity becomes concentrated within 2–6%, mostly between 2 and 5%, showing no clear increasing trend with pressure coefficient. Further analysis indicates that both compaction intensity and formation pressure increase with burial depth. The interaction between overpressure and compaction exhibits a mutually offsetting effect, and beyond ~ 3000 m, the balance between compaction and overpressure results in limited protective effects of overpressure and a relatively narrow porosity distribution (Fig. 8).

Fig. 8 — Variation of porosity and permeability with temperature and formation pressure of shale reservoir.

(modified from⁴⁵).

In addition to the offsetting effect of overpressure, the wide dispersion of porosity data within the same TOC interval suggests that lithofacies and mineralogical variations also influence pore preservation. Within a given TOC interval, S shale exhibits the highest TOC, followed by M shale, and the lowest is in CM shale. Comparisons among samples at similar depths but with different TOC levels show that high-TOC shales generally have higher porosity than low-TOC shales, indicating that interlayer TOC variability affects pore development, likely due to compaction resistance provided by migrated organic matter. Furthermore, multivariate linear regression analysis indicates that decreasing contents of rigid minerals (e.g., quartz and feldspar) and increasing clay content enhance compaction effects, reduce the distribution of migrated organic matter, and thus decrease porosity. This phenomenon highlights a “pore-preserving effect” of rigid minerals against compaction.

The formation of OM pores in shale is related to the hydrocarbon generation process of OM. OM pores observed under scanning electron microscopy were originally gas bubbles during geological history⁶¹. During bitumen maturation, these gas bubbles cease to grow and transform into organic pores of varying sizes. The generation of bitumen in shale creates numerous micro- and nano-scale pore reservoirs. When the pressure within these nano-reservoirs falls below the bubble point, the dissolved gas in the oil phase does not immediately exsolve, resulting in supersaturation, where the actual dissolved gas exceeds the amount predicted by thermodynamic equilibrium. Supersaturation is a prerequisite for bubble nucleation. Neglecting the effects of impurities and the porous matrix, crude oil saturated with natural gas can be treated as a single homogeneous system. When components in this system cluster to form a stable second phase due to pressure or temperature fluctuations, homogeneous nucleation occurs. During the initial stage of bubble nucleation, the free energy (ΔG) increases⁶¹. As shown in the following equation, when ΔG reaches the critical minimum free energy (ΔG*), bubble formation initiates within the hydrocarbon liquid. The corresponding critical bubble radius is r*, at which point the bubble size stabilizes. If ΔG exceeds ΔG*, bubbles grow and may coalesce; otherwise, nascent bubbles rapidly dissolve. Upon further increases in Δp, if ΔG surpasses the surface tension critical point, bubble rupture occurs, forming stable OM pores.

In the equation, ΔG represents free energy (J), r denotes the bubble nucleus radius (m), Δp is the pressure difference inside and outside the bubble (MPa), and σ_bp is the surface tension of the bubble (N/m). Based on this bubble formation mechanism, the evolution of organic pores under different burial depths can be inferred⁶¹.

For burial depths < 2000 m, Δp between the bubble interior and exterior is relatively high. The free energy in the original large gas bubbles exceeds the surface tension threshold, causing the bubbles to fragment into smaller pores. These newly formed small pores connect with expanded needle-like pores, ultimately forming a complex pore network. At burial depths between 2000 m and 4000 m, the free energy within the organic pores is stabilized, insufficient to overcome the surface tension limit for fragmentation. However, it exceeds the critical free energy required for bubble nucleation, allowing the formation of larger and interconnected pore structures. When burial depth exceeds 4000 m, both pore size and scale decrease markedly. Statistical analysis of core samples indicates that at depths > 4500 m (Fig. 7), the reduction in pore size and scale becomes minimal.

Taking the S lithofacies as an example, under temperature and pressure loading (Fig. 8), porosity at different depths decreased by 54–71% (mean 59%), while permeability decreased by 85–97% (mean 91%). When pressure and temperature were reduced to 10 MPa and 60 °C, porosity recovered by 48–74%, and permeability recovered by 17–36%³⁹.

Pore structure variation under different formation pressure

LTCA and LTNA curves under different formation pressure

The LTNA curves reveal notable differences in pore structure and adsorption capacity among the shale units (Fig. 9). The adsorption curve of the 1st Unit of S lithofacies is very steep at the saturated vapor pressure (Fig. 9a). The desorption curve is steep at the median pressure (Fig. 9b), indicating that the pores mainly comprise nanopores. SEM observations show irregular, primarily cylindrical pores with open ends (Fig. 9c). In contrast, the 2nd Unit S lithofacies exhibits gentler adsorption and desorption curves (Fig. 9d and e), reflecting lower adsorption capacity and fewer pores, which are mainly conical with four open ends or flat with two open ends; a few cylindrical OM pores with both ends open are also present. The 3rd Unit M lithofacies displays steep adsorption and desorption curves (Fig. 9g and h), indicating a large number of pores. Pores include cylindrical OM pores with both ends open, as well as flat and conical inorganic pores with openings at both ends (Fig. 9i). The 4th Unit CM lithofacies shows gentle adsorption and desorption curves (Fig. 9j and k), corresponding to a small number of pores and undeveloped OM porosity (Fig. 9l).

Variations in formation pressure have minimal influence on the LTNA curves of the S lithofacies (Fig. 9a–f), indicating limited effects on microstructure. By contrast, under identical pressure conditions, the CM lithofacies exhibits a more pronounced hysteresis loop, suggesting distinct pore characteristics. As formation pressure declines, the S lithofacies largely maintains pore integrity, whereas pores in the M lithofacies evolve from rounded to plate-like, parallel forms (Fig. 9g–i). LTNA results further indicate that declining pressure severely alters pore geometry in the CM lithofacies (Fig. 9j–l).

Results from LTCA-LTNA show that 1st Unit S lithofacies has the highest volumes of micropores and mesopores associated with OM, reflecting the best overall microstructure (Fig. 10a–c). The M lithofacies shows slightly smaller and fewer micropores compared to the S lithofacies (Fig. 10d–f), while the CM lithofacies displays the lowest micropore abundance and size (Fig. 10g–i). In terms of macropores, the S lithofacies also possesses the largest volume, indicative of well-developed macropores and/or microfractures and overall superior microstructure (Fig. 11a–c). The mesopore and macropore volumes decrease progressively in the M and CM lithofacies (Fig. 11d–f). Quantitatively, micropore volume in the 1st Unit S lithofacies reaches 0.002 cm³/g, and mesopore volume reaches 0.016 cm³/g, whereas the 4th Unit CM lithofacies exhibits the lowest values (Fig. 11). The 3rd Unit M lithofacies displays intermediate properties, slightly lower than those of the 1st Unit S lithofacies. With decreasing formation pressure, micropore and mesopore volumes in the M and CM lithofacies decline markedly, indicating a deterioration of pore structure (Fig. 11g–i).

Fig. 10 — LTCA cumulative adsorption curve of different lithofacies in the Longmaxi 1st Submember shale. (a) S lithofacies, 1st Unit, Well A, 3350 m, pressure coefficient: 1.9. (b) S lithofacies, 1st Unit, Well B, 4270 m, pressure coefficient: 1.08. (c) S lithofacies, 1st Unit, Well C, 3837 m, pressure coefficient: 0.98. (d) M lithofacies, 3rd Unit, Well A, 3330 m, pressure coefficient: 1.9. (e) M lithofacies, 3rd Unit, Well B, 4250 m, pressure coefficient: 1.08. (f) M lithofacies, 3rd Unit, Well C, 3816 m, pressure coefficient: 0.98. (g) CM lithofacies, 4th Unit, Well A, 3320 m, pressure coefficient: 1.9. (h) CM lithofacies, 4th Unit, Well B, 4240 m, pressure coefficient: 1.08. (i) CM lithofacies, 4th Unit, Well C, 3806 m, pressure coefficient: 0.98.

Fig. 11 — LTNA cumulative adsorption curve of different lithofacies in the Longmaxi 1st Submember shale. (a) S lithofacies, 1st Unit, Well A, 3350 m, pressure coefficient: 1.9. (b) S lithofacies, 1st Unit, Well B, 4270 m, pressure coefficient: 1.08. (c) S lithofacies, 1st Unit, Well C, 3837 m, pressure coefficient: 0.98. (d) M lithofacies, 3rd Unit, Well A, 3330 m, pressure coefficient: 1.9. (e) M lithofacies, 3rd Unit, Well B, 4250 m, pressure coefficient: 1.08. (f) M lithofacies, 3rd Unit, Well C, 3816 m, pressure coefficient: 0.98. (g) CM lithofacies, 4th Unit, Well A, 3320 m, pressure coefficient: 1.9. (h) CM lithofacies, 4th Unit, Well B, 4240 m, pressure coefficient: 1.08. (i) CM lithofacies, 4th Unit, Well C, 3806 m, pressure coefficient: 0.98.

MIP curves under different formation pressure

The mercury intrusion curves of the shale samples show high threshold pressures, broad plateaus, and low mercury withdrawal efficiencies (Fig. 12a–c). All threshold pressures exceed 13.7 MPa, corresponding to pore-throat diameters of approximately 100 nm, indicating that the majority of pore throats are smaller than 100 nm (Fig. 12d–f). Mercury injection increases nonlinearly with pressure and displays a pronounced plateau; that is, over a wide pressure range the amount of intruded mercury grows only slowly. In several samples, mercury withdrawal efficiencies are below 50%. Taken together, these patterns indicate that the shale pore system is dominated by large pores connected by narrow throats and by ink-bottle geometries, or by dendritic and conduit-like networks with small pore throats (Fig. 12g–h).

Fig. 12 — Capillary pressure curves of MIP in different lithofacies, Longmaxi 1st Submember shale. (a) S lithofacies, 1st Unit, Well A, 3350 m, pressure coefficient: 1.9. (b) S lithofacies, 1st Unit, Well B, 4270 m, pressure coefficient: 1.08. (c) S lithofacies, 1st Unit, Well C, 3837 m, pressure coefficient: 0.98. (d) M lithofacies, 3rd Unit, Well A, 3330 m, pressure coefficient: 1.9. (e) M lithofacies, 3rd Unit, Well B, 4250 m, pressure coefficient: 1.08. (f) M lithofacies, 3rd Unit, Well C, 3816 m, pressure coefficient: 0.98. (g) CM lithofacies, 4th Unit, Well A, 3320 m, pressure coefficient: 1.9. (h) CM lithofacies, 4th Unit, Well B, 4240 m, pressure coefficient: 1.08. (i) CM lithofacies, 4th Unit, Well C, 3806 m, pressure coefficient: 0.98.

Discussion

Coupling effects of lithofacies-formation pressure on micro pore

Coupling effects on pore proportion

In deeply buried, generally over-mature shale, reservoir space development is controlled not only by intrinsic factors such as organic content, thermal maturity, and mineral composition, but also by the interplay between structural pressure and hydrocarbon generation–diagenesis evolution^26,31,33. During the Cretaceous Yanshan Movement, the shale reservoir reached the maximum burial depth (Fig. 13), maintaining an over-pressure condition before this event^15,32,57. It should be noted that the reconstructed burial history and paleo-pressure estimatesare subject to uncertainties due to assumptions in compaction, lithology, and thermal history, which may affect the exact magnitude and timing of overpressure evolution. In the southern Sichuan Basin, the current formation pressure coefficient in the Weiyuan and Yongchuan regions generally ranges from 1.6 to 2.1 (Fig. 1b).

Fig. 13 — Burial history, thermal history and formation pressure evolution modeling of the Longmaxi 1st Submember shale.

(modified from³³).

Compared to the southeastern Sichuan Basin, shale gas preservation in the southern Sichuan Basin is generally better, with significant variations in formation pressure controlling differential reservoir evolution (Fig. 14). Under conditions of minimal depressurization, both organic-rich and organic-poor S lithofacies exhibit relatively good reservoir properties, with the organic-rich S lithofacies showing the strongest resistance to compaction (Fig. 14). For instance, the 1st Unit S lithofacies has an average TOC of up to 5% and a maximum gas content of 18.8 m³/t. It is characterized by abundant elliptical or honeycomb-shaped organic matter pores, and OM-related micropore and mesopore volumes reach up to 0.002 cm³/g and 0.016 cm³/g, respectively, reflecting the most favorable microstructure among all lithofacies. In contrast, the organic-poor S lithofacies exhibits extremely low natural gas adsorption capacity, generally below 3 m³/t, highlighting its poor reservoir quality. The organic-rich M lithofacies, despite higher organic content supporting gas adsorption and accumulation, suffers substantial loss of both organic and inorganic pores during compaction, resulting in inferior reservoir performance compared to S lithofacies. The CM lithofacies has a weak material framework and the lowest compaction resistance (Fig. 14), leading to poor porosity preservation; however, its low porosity and effective sealing capacity allow it to function as a competent cap rock for shale gas pools. Overall, increasing burial depth intensifies compaction and exacerbates pore structure degradation. While favorable factors, such as high brittle mineral content and overpressure, can partially counteract compaction, excessive burial depth remains the dominant control on pore preservation, pore connectivity, and ultimately shale gas storage.

Fig. 14 — Diagram of the differential compaction patterns of shale reservoirs under over-pressure condition and lithofacies control.

OM pores are commonly lipophilic, while inorganic pores are typically hydrophilic⁶². Based on this principle, NMR experiments were conducted under brine- and oil (n-dodecane)-saturated conditions (Fig. 15a and b) to separately characterize the relaxation signals of inorganic and OM-related pore spaces (Fig. 15c and d). Three distinct peaks appear in the T₂ spectra of lipophilic pores, representing three categories of OM pores: dominant small pores with short T₂ values, larger pores with longer T₂ values, and organic matter–related fractures characterized by T₂ > 100 ms (Fig. 15e and f). Three distinct peaks appear in the T₂ spectra of lipophilic pores, corresponding to three pore types: short-T₂ components mainly represent nanoscale OM pores; medium-T₂ components correspond to meso–macropores within OM matrices; and long-T₂ components (> 100 ms) indicate organic fractures. The identification of the > 100 ms cutoff is supported by the extended relaxation tail observed in overpressured samples and by the presence of connected organic fractures in SEM images, suggesting that these long-T₂ signals mainly reflect fracture systems rather than isolated large pores. The relative intensity of this component varies among lithofacies, with a more pronounced signal observed under overpressure conditions, reflecting enhanced fracture development and connectivity (Fig. 15g and h).

Fig. 15 — NMR T₂ spectra of different lithofacies under different pressure for the Longmaxi 1st Submember shale. (a) Organic-rich S lithofacies, 1st Unit, Well A, pressure coefficient 1.9. (b) Organic-rich S lithofacies, 1st Unit, Well D, pressure coefficient 1.9. (c) Organic-rich S lithofacies, 1st Unit, Well B, pressure coefficient 1.08. (d) Organic-rich S lithofacies, 1st Unit, Well C, pressure coefficient 0.98. (e) Organic-rich M lithofacies, 3rd Unit, Well A, pressure coefficient 1.9. (f) Organic-rich M lithofacies, 3rd Unit, Well D, pressure coefficient 1.9. (g) Organic-rich M lithofacies, 3rd Unit, Well B, pressure coefficient 1.08. (h) Organic-rich M lithofacies, 3rd Unit, Well C, pressure coefficient 0.98.

The main peak at 0.5 ms under brine-saturated condition represents the hydrophilic pores, while the secondary peak represents the fractures with small PV and large sizes (Fig. 15). As formation pressure decreases, the NMR curves corresponding to OM pores, inorganic pores, and OM-related microfractures all significantly decrease (Fig. 15). In particular, when the pressure coefficient of the organic-rich M lithofacies decreases from 2.0 to 0.98, the T₂ peak amplitude drops by more than 53.2%, indicating severe pore compaction. In contrast, the reduction in the NMR response for the organic-rich S lithofacies is much smaller, demonstrating its stronger resistance to compaction during depressurization. Moreover, after the pressure coefficient decreases, the NMR curves for saturated water and oil in the M lithofacies split into multiple segments (Fig. 15g and h), corresponding to different pore distributions. This indicates that the depressurization process increases the heterogeneity of pore distribution within the organic-rich M lithofacies.

Coupling effects on pore size distribution

In this study, LTCA, LTNA, and MIP data were integrated to construct full-scale pore size distribution curves. The results indicate that macropores, mesopores, and micropores all contribute to the total PV of the S lithofacies (Fig. 16a), with mesopores between 2 and 100 nm and macropores larger than 8000 nm contributing the most (Fig. 16b). As formation pressure decreases, the contribution of macropores to PV declines, whereas the relative contribution of mesopores and micropores increases significantly (Fig. 16c). For the M lithofacies, PV is mainly derived from micropores and mesopores, with macropores contributing minimally (Fig. 16d); mesopores of 2–50 nm are the dominant contributors (Fig. 16e). Upon reduction of formation pressure, macropores contribute almost nothing to PV, while the role of mesopores is further enhanced (Fig. 16f). Similarly, for the CM lithofacies, PV primarily originates from micropores and mesopores, with macropores being negligible (Fig. 16g). As pressure decreases, the contribution of micropores to PV gradually increases (Fig. 16h–i).

Fig. 16 — Pore size distribution under different pressure coefficient for the Longmaxi 1st Submember shale. (a) S lithofacies, 1st Unit, Well A, 3350 m, pressure coefficient: 1.9. (b) S lithofacies, 1st Unit, Well B, 4270 m, pressure coefficient: 1.08. (c) S lithofacies, 1st Unit, Well C, 3837 m, pressure coefficient: 0.98. (d) M lithofacies, 3rd Unit, Well A, 3330 m, pressure coefficient: 1.9. (e) M lithofacies, 3rd Unit, Well B, 4250 m, pressure coefficient: 1.08. (f) M lithofacies, 3rd Unit, Well C, 3816 m, pressure coefficient: 0.98. (g) CM lithofacies, 4th Unit, Well A, 3320 m, pressure coefficient: 1.9. (h) CM lithofacies, 4th Unit, Well B, 4240 m, pressure coefficient: 1.08. (i) CM lithofacies, 4th Unit, Well C, 3806 m, pressure coefficient: 0.98.

Comparison across different shale lithofacies shows that, with decreasing pressure coefficient, the reservoir pore structure becomes increasingly complex and heterogeneous. The macropore volume exhibits partly significant reductions and partly minimal changes, leading to a slight overall decrease in their proportion. Although the absolute volumes of mesopores and micropores may slightly decrease, their relative proportions increase, resulting in a more pronounced multi-scale pore distribution. Fractal dimensions calculated from N₂ adsorption data using the FHH model reveal that^63,64, as the relative contributions of mesopores and micropores increase, pore surface heterogeneity is enhanced, and the fractal dimensions rise markedly—particularly D₁, which characterizes micropore complexity. For example, in the S lithofacies, D₁ increases from 2.62 at a pressure coefficient of 1.9 to 2.71 at 0.98, and D₂ rises from 2.82 to 2.87; in the CM lithofacies, D₁ increases from 2.68 to 2.75, and D₂ from 2.80 to 2.86. These observations indicate that, as pressure decreases, the proportion of macropores declines while mesopores and micropores occupy a larger relative fraction, leading to enhanced pore heterogeneity, particularly in terms of surface roughness and structural complexity.

Coupling effects of lithofacies-formation pressure on gas content

The role of OM in shale gas storage can be divided into two main aspects: providing storage space and generating hydrocarbons^43,53. As an adsorbent, OM offers abundant adsorption sites for methane, while its internal micropores serve as storage space for both adsorbed and free gas. These micropores originate from two mechanisms: (1) the inherently loose, porous structure of OM aggregates, which becomes more developed with increasing OM content, and (2) the formation of secondary pores during thermal maturation, when hydrocarbon generation causes OM volume reduction. In this study, OM abundance shows a strong positive correlation with total, adsorbed, and free gas contents (Fig. 17), indicating that OM plays a dominant role in gas storage. The correlation coefficient for free gas is higher than that for adsorbed gas, implying that OM-rich lithofacies retain more free gas space even under compaction. In contrast, organic-poor lithofacies, lacking sufficient OM to generate or preserve pores, exhibit limited capacity to store or adsorb gas.

Fig. 17 — Cross-plot of total gas content, adsorbed gas content, free gas content vs. mineral composition under over-pressure condition.

Mineral composition also exerts a major control on pore structure and gas occurrence. Higher quartz content enhances the rock’s resistance to compaction, aiding the preservation of primary and intergranular pores, which serve as free gas storage spaces. Soluble minerals such as feldspar, dolomite, and calcite contribute to secondary dissolution pores. Quartz content shows a positive correlation with both total and free gas contents (Fig. 16), suggesting that quartz-rich lithofacies favor gas enrichment. High quartz content also facilitates OM enrichment and the formation of OM-related pores. Consequently, the organic-rich S lithofacies, characterized by both high OM and quartz contents, exhibits the highest gas content and best pore preservation even when the pressure coefficient decreases.

Clay minerals, by contrast, play a dual but less favorable role. Their interlayer pores increase adsorption capacity, particularly in montmorillonite, whose methane adsorption capacity is 2–4 times that of other clays. However, illite—the dominant clay mineral in the Longmaxi Shale—has the weakest adsorption capacity. Clay minerals show a negative correlation with total and free gas contents and only a weak correlation with adsorbed gas (Fig. 17), indicating that while they provide adsorption sites, they contribute little to overall storage capacity. This weak relationship likely arises from competitive adsorption between OM and clays. OM exhibits a stronger affinity for methane, dominating gas adsorption in TOC-rich samples. Furthermore, compaction and diagenetic transformation reduce the surface area and accessibility of clay interlayers, further diminishing their adsorption efficiency. During illitization, volume shrinkage may generate microfractures that locally store free gas, but such effects are limited. Owing to their plasticity, clay minerals are readily compacted and deformed, leading to pore collapse and poor OM-pore preservation, explaining the observed negative correlation with free gas. Overall, among the examined lithofacies, the organic-rich S lithofacies provides the most favorable conditions for shale gas accumulation.

With increasing burial depth, temperature and pressure both rises. Elevated temperature enhances the deformability of OM and clays⁶⁵, greatly reducing their resistance to compaction. However, rigid minerals largely preserve the bulk rock volume³⁹. Consequently, porosity in the CM and M lithofacies decreases markedly under higher temperature and pressure, regardless of OM abundance. Since porosity correlates positively with free gas content⁴⁵, compaction-induced porosity loss inevitably reduces gas content. As shown in Fig. 18, free gas declines rapidly with decreasing macropore and mesopore volumes, even though some adsorbed gas converts to free gas during depressurization. The M lithofacies retains a slightly better microstructure than the CM lithofacies, likely due to its higher proportion of rigid grains that mitigate pore collapse and gas loss.

Fig. 18 — Cross-plot of porosity of micro pore vs. free gas volume and absorbed gas volume under over-pressure condition.

Conclutions

Three shale lithofacies—siliceous (S), mixed (M), and clay-rich (CM)—are developed in the deep-buried Longmaxi Formation. OM abundance decreases from the 1st to the 4th Unit, while the 2nd Submember is clay-rich and TOC-poor, making it unfavorable for shale gas development. This study systematically links lithofacies characterization to shale reservoir quality, providing a refined framework for predicting favorable intervals in deep-buried shales.
OM pores are mainly concentrated in the OM-rich S and M lithofacies, while OM-poor CM lithofacies lacks large-scale OM pores under overpressure. Micropores (< 4 nm) dominate SSA, and pores of 4–30 nm contribute most to PV. The 1st Unit S lithofacies exhibits the highest TOC, porosity, brittleness, and total gas content, showing the strongest resistance to compaction. The innovative aspect lies in quantitatively demonstrating lithofacies-dependent pore preservation under varying pressure conditions, highlighting the S lithofacies as the most favorable reservoir.
Porosity and microstructure are jointly controlled by lithofacies, burial depth, and formation pressure. In shales buried > 3000 m, overpressure mitigates compaction, preserving porosity in S lithofacies (2–5%), whereas M and CM lithofacies lose substantial pore volume. This work quantifies the interplay between compaction and overpressure in deep-buried shales, revealing a balance that regulates pore maintenance and destruction, which is rarely addressed in prior studies.
With decreasing formation pressure, S lithofacies experiences minor pore changes, whereas M and CM lithofacies show significant micropore and mesopore reduction, shifting pore-size distribution toward micropores. Free gas is controlled by macropores and microfractures, while adsorbed gas resides in micropores. Temperature-induced plastic deformation further reduces large and medium pores in M and CM lithofacies. The innovation lies in linking lithofacies-dependent pore evolution to gas distribution under deep-burial and depressurization conditions, providing direct guidance for exploration and development of deep, over-pressured shale reservoirs.

Author contributions

Y.Z: Writing-Original Draft, Writing –Review & Editing, Data Curation, Formal Analysis, and Validation; H.Z. and L.Z: Formal Analysis, Validation, and Reviewing; J.L., Y.Y., and L.Z.: Data Curation, Validation, and Reviewing.

Funding

This study was financially supported by National Natural Science Foundation of China (No. 42302166).

Data availability

The datasets used and analysed during the current study are available from the corresponding author on reasonable request.

Declarations

Competing interests

The authors declare no competing interests.

Footnotes

Publisher’s note

Springer Nature remains neutral with regard to jurisdictional claims in published maps and institutional affiliations.

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Associated Data

This section collects any data citations, data availability statements, or supplementary materials included in this article.

Data Availability Statement

The datasets used and analysed during the current study are available from the corresponding author on reasonable request.

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PERMALINK

Pore-micro fracture structure, porosity and gas- bearing property of deep shale under lithofacies-formation pressure coupling

Yunjun Zhang

Hao Zhang

Li Zhang

Jianlin Li

Yaohui Yan

Abstract

Introduction

Geological backgrounds

Fig. 1.

Materials, experiments and theories

Results

Lithofacies classification and geological characteristics

Lithofacies classification and mineral composition

Fig. 2.

Bulk organic geochemistry

Fig. 3.

Gas-bearing characteristics

Fig. 4.

Fig. 5.

Pore-micro fracture under different formation pressure

Organic matter (OM) pores

Fig. 6.

Intraparticle pores

Interparticle pores

Micro-fractures

Porosity variation under different burial depth and formation pressure

Fig. 7.

Fig. 8.

Pore structure variation under different formation pressure

LTCA and LTNA curves under different formation pressure

Fig. 9.

Fig. 10.

Fig. 11.

MIP curves under different formation pressure

Fig. 12.

Discussion

Coupling effects of lithofacies-formation pressure on micro pore

Coupling effects on pore proportion

Fig. 13.

Fig. 14.

Fig. 15.

Coupling effects on pore size distribution

Fig. 16.

Coupling effects of lithofacies-formation pressure on gas content

Fig. 17.

Fig. 18.

Conclutions

Author contributions

Funding

Data availability

Declarations

Competing interests

Footnotes

References

Associated Data

Data Availability Statement

ACTIONS

PERMALINK

RESOURCES

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