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Pore structure evolution model of shale reservoir under different fluid pressures: a case study of Wufeng-Longmaxi Formation, SW China

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Open Geosciences
From the journal Open Geosciences Volume 18 Issue 1

Abstract

Multiple studies had been conducted to improve the geological understanding and enrichment patterns of the Wufeng-Longmaxi Formation in the southeastern Sichuan Basin’s complex tectonic belt. However, the influence of different structural conditions on shale gas occurrence and shale reservoirs remained unclear. To address this issue, low-mature shale samples from the Wufeng-Longmaxi Formation in the southeastern Sichuan Basin were selected for thermal simulation experiments, based on the actual burial evolution history of the region. Overmature shale samples with the maximum burial depth were then obtained. Next, based on the maximum burial depth sample, the thermal simulation conditions were adjusted to simulate the evolution of the shale reservoir under different structural preservation conditions. Finally, organic geochemistry, FE-SEM, nuclear magnetic resonance, low-temperature gas adsorption, high-pressure mercury injection, and other experiments were conducted to analyze the characteristics of the shale reservoir and the differences in shale gas occurrence under varying structural preservation conditions. As structural preservation conditions get worse, both the organic and inorganic pore sizes in the shale decrease, and organic pore morphology evolved from round-subround to narrow, elongated shapes. Meanwhile, organic and inorganic pore porosity, organic pore proportion, and fluid pressure within the pores decreased as structural preservation conditions get worse, which suggested that better structural preservation conditions were conducive to maintaining fluid pressure in shale pores, which in turn supported pore preservation. Fluid pressure changes had a greater impact on organic pores. FHH model calculations showed that shale pores formed under poorer structural preservation conditions exhibit more complex pore structures and greater heterogeneity. Finally, a pore structure development model was established based on the characteristics of shale pore structure under different preservation conditions.

Keywords: shale reservoir; fluid pressure; preservation condition; Wufeng-Longmaxi formation; southeast Sichuan basin

1 Introduction

The deep shale of the Wufeng-Longmaxi Formation, buried more than 3,500 m in Sichuan Basin and its surrounding areas, was widely distributed and boasted significant resource potential. This formation represented a crucial alternative area for future gas exploration and production [1], 2]. The proven rate of deep to ultra-deep gas resources in China was only 0.73 %, indicating that shale gas exploration was still in the early stage. At present, the main direction of shale gas exploration was gradually shifting to the deep field [3]. Sinopec had drilled multiple shale gas wells in the Dingshan-Dongxi area, yielding industrial oil and gas flows, which reflected the promising prospect of deep shale gas exploration in the complex structural belt of the southeastern Sichuan Basin [4], 5]. The Wufeng-Longmaxi Formation shale in the southeastern Sichuan Basin reached a maximum burial depth of approximately 5–7 km during geological history, with little variation in thermal maturity. However, differences in subsequent tectonic uplift and erosion had led to variations in the current burial depth of the shale reservoir in different areas [6], 7]. Influenced by the timing and intensity of later tectonic movements, significant differences existed between deep and shallow-to-middle buried shale in reservoir properties, pore structure, gas content, and rock mechanical properties [8]. High-quality deep shale gas reservoirs were characterized by “high pressure, high porosity, and high gas content”. The anti-compaction effect of rigid minerals such as quartz, and fluid in reservoir pores was key to shale pore development and preservation [4], 5], 9].

Structural Preservation Conditions refer to the ability of a target geological unit (e.g., reservoir, organic pores, source rock) to resist physical destruction or chemical alteration under tectonic pressures. Multiple studies indicated that structural preservation conditions were critical for the enrichment of marine shale gas, and the timing and intensity of tectonic movements could significantly impact reservoir development and gas content [8], 10]. Liu et al. (2024) proposed that favorable factors for shale gas enrichment in the complex tectonic area of southeastern Sichuan Basin included being far from faults [11], relatively small tectonic uplift, and an overall gentle structure. In the southeastern Sichuan Basin, abnormal overpressure in shale reservoir was primarily caused by liquid hydrocarbon thermal cracking during deep burial. If subsequent tectonic movements deteriorate preservation conditions, it led to the dissipation of cracking gas, forming a normal-pressure shale gas reservoir. Otherwise, the overpressured shale gas reservoir would be formed [12], 13]. Based on the understanding above, this study focused on how structural preservation conditions influencing shale reservoir development, particularly with respect to the effects of fluid pressure and temperature. Current research suggested that overpressure within shale pores resisted compaction, promoting the development of organic pore with high roundness, large pore size, and uniform shape. However, subsequent tectonic movement disrupted the preservation condition of shale reservoirs, causing pore pressure to be unable to fully resist compaction, thereby reducing the development of pore space [4], 14]. Shi et al. (2023) developed a coupled rigid-plastic mineral pore framework model to explain change in pore characteristics and their formation under overpressure condition [15]. High-temperature and high-pressure condition is considered to accelerate the closure of both organic and inorganic pore and fracture [16]. Under overpressure condition, mechanical compaction is suppressed, allowing for the preservation of significant primary intergranular porosity [17]. Xu et al. (2020) proposed that tectonic uplift led to the collapse and closure of most mesopore to macropore in shale [18], negatively impacting the preservation of reservoir space. But some scholars proposed that the pores under the control of reservoir pressure relief can be maintained [19], 20]. Increased Pore Pressure leads to a higher quartz percentage and a lower clay mineral percentage. However, changes in formation pressure show no significant influence on the thermal maturity evolution of the shale. As fluid pressure increases, the pore shapes within the shale progressively transform from narrow slit-like pores to ink-bottle-shaped pores. The rise in formation pressure causes a slight decrease in micropore volume, a significant increase in mesopore volume, and a two-stage variation pattern in macropore volume. Furthermore, formation pressure results in a notable reduction in pore surface heterogeneity [21], [22], [23].

This study clarifies the critical role of structural preservation conditions (formation temperature/pressure) in controlling shale reservoir pore structure evolution through systematic thermal simulation experiments. Using mature Wufeng-Longmaxi Formation samples and reconstructing the Silurian shale burial history of the study area, we designed multi-scenario thermal simulations with parameterized tectonic uplift settings (variable T/P conditions) to quantitatively evaluate preservation-condition impacts on petrophysical properties and pore architecture development.

2 Geological setting

2.1 Sedimentary background

During the Late Ordovician Katian to Early Silurian Telychian stage, the Sichuan Basin and surrounding area were situated in a northward-opening continental shelf, bounded by the Central Sichuan Paleo-uplift and the Central Guizhou-Xuefeng Paleo-uplift (Figure 1). Between these paleo-uplifts, a semi-closed, stagnant marine basin developed, with two subsidence centers: one in the Weiyuan-Changning area in the southern Sichuan Basin and another in the Fuling-Jiaoshiba area in the eastern basin. The deposition of the Wufeng-Longmaxi Formation was influenced by two global transgressions. During this period, the sedimentary environment evolved from deep water shelf to semi-deep water shelf, and ultimately to shallow water shelf. This sedimentary sequence reflected a gradual shallowing of the water, with coarser grain sizes and lighter colors [24]. The sequence included thick layers of black to dark gray shale and dark gray silty mudstone. During the early Katian to Aeronian stages of the Wufeng-Longmaxi Formation, organic-rich black shale was deposited in a deep to semi-deep shelf environment [25]. The shale displayed well-developed horizontal layering, abundant graptolites, and frequent pyrite, with a stable planar distribution [26]. The thickness of the Wufeng-Longmaxi Formation shale in the southern and eastern Sichuan Basin ranged from 20 to 40 m, with the burial depth at the bottom of the Wufeng Formation ranging from 1,500 to 5000 m. The lithology consisted primarily of siliceous shale and calcareous siliceous shale, providing the key material foundation for the generation and storage of shale gas. This lithology had been a primary focus of current shale gas exploration research in Sichuan Basin and surrounding areas [27].

Figure 1: Location map of Miaoba outcrop (modified from [23]).
Figure 1:

Location map of Miaoba outcrop (modified from [23]).

2.2 Burial evolutionary history

The geological background of the Wufeng-Longmaxi Formation shale reservoirs in the southeastern Sichuan Basin was similar, with both undergoing a burial-hydrocarbon generation-tectonic uplift geological evolutionary process [6], 28]. Specifically, during the late Caledonian to early Hercynian movement, the study area had experienced a relatively stable shallow burial and uplift stage. During the late Hercynian (early Permian), burial depth increased, and hydrocarbon generation began. Although in the early Triassic, the Wufeng-Longmaxi shale had experienced slight uplift due to the Indosinian movement, the overall trend continued toward sustained burial and deepening, as well as hydrocarbon generation. By the early Yanshan movement, during the early Cretaceous, the maximum burial depth was reached. Both temperature and pressure in the Wufeng-Longmaxi shale increased, leading to continued organic matter thermal evolution and hydrocarbon generation (Figure 2). Since the late Cretaceous, influenced by the Yanshan and Himalayan movement, the Wufeng-Longmaxi shale in southeastern Sichuan Basin began to uplift. The burial depth decreased, interrupting the thermal evolution of organic matter, while the formation temperature and pressure continued to decrease [13], 28].

Figure 2: Schematic diagram of marine shale gas burial types in southern China (modified from [24]).
Figure 2:

Schematic diagram of marine shale gas burial types in southern China (modified from [24]).

Teng et al. (2024) classified the structural preservation types of marine shale gas in southeastern Sichuan into three categories [28]: (1) overpressure or normal pressure shale gas during the maximum burial stage of the burial-hydrocarbon generation stage; (2) overpressure or normal pressure shale gas during the uplift-modification stage (present day) in deep shele; (c) overpressure or normal pressure shale gas in the mid-shallow shale during the same uplift-modification stage. Shale gas dissipation primarily occurs during the uplift process of the strata and was controlled by the intensity, timing, and nature of structural modifications [2], 9]. Open fractures and surface-to-near-surface erosion were the primary causes of shale gas dissipation. In areas far from major fracture and surface erosion zone, shallower shale reservoirs exhibited poorer self-sealing properties and weaker cap rock integrity. Additionally, the reduction in temperature and pressure led to a decrease in shale gas activity, resulting in lower gas content and a reduced proportion of free gas during the uplift process [2].

3 Materials and methods

3.1 Sample

The thermal evolution of the Longmaxi Formation shale in Chengkou County, Chongqing, was generally considered to be relatively low [27]. Therefore, outcrop samples from the Miaoba profile in this area were selected for thermal simulation experiments (Figure 1). The selected strata were the bottom of the Longmaxi Formation, where a large number of graptolites developed on the surface, characteristic of typical organic-rich shale. The initial sample had a TOC content of 2.89 %, and the vitrinite reflectance, derived from Raman spectroscopy, was 1.16 %. This indicates that the thermal evolution was in the early stage of high maturity.

3.2 Diagenetic simulation experiment

The diagenesis simulation experiment was carried out using the high-temperature, high-pressure diagenesis simulation instrument at Southwest Petroleum University (Figure 3a), with a maximum simulation temperature of 600 °C. After placing the samples, deionized water was added to the reaction vessel, allowing the samples to absorb water and reach fluid saturation (Figure 3b). A threshold pressure for hydrocarbon expulsion was set to achieve a staged expulsion effect, ensuring that the thermal simulation closely mirrors the actual hydrocarbon generation and expulsion process in shale. The furnace was lined with copper, known for its excellent thermal conductivity.

Figure 3: High temperature and high pressure diagenetic simulation system of Southwest Petroleum University.
Figure 3:

High temperature and high pressure diagenetic simulation system of Southwest Petroleum University.

3.3 Experimental schemes

3.3.1 Simulation experiment of burial stage

The Wufeng-Longmaxi shale in the southeastern Sichuan Basin, under different tectonic settings, underwent a similar burial history. Moreover, shale samples from the maximum burial depth had reached the overmature stage, characterized by high porosity, a large proportion of organic pore, and large pore size [9], 29]. Therefore, this study conducted closed-system thermal simulation experiment to obtain four overmature samples with similar maturity levels, representing the reservoir characteristic at the maximum burial depth. This approach also removed the influence of thermal evolution differences before uplift on the pore structure. The experimental instrument utilized a fully closed system with programmed temperature and pressure conditions that were gradually increased (Table 1), simulating the shale reservoir evolution under continuous burial conditions.

Table 1:

Experimental parameters of thermal simulation in shale deep burial stage.

Sample Simulated buried depth(m) Lithostatic pressure (MPa) Heating rate (°C/min) Terminal heating temperature (°C) Holding time

(h)		 Raman reflectivity (%)
Initial / / / / / 1.16
Simulated 4,800 120 3 580 168 2.8

The TOC and mineral composition of both the initial and simulated samples were presented in Table 2. The average reflectance of the simulated samples was 2.84 %, with a TOC of 2.18 %. Approximately 25 % of the organic matter had been cracked. The mineral composition showed a significant increasing in the content of quartz and illite during the simulation, while the content of carbonate minerals and feldspar decreased. This change might be related to strong dissolution processes [30].

Table 2:

Average value of TOC and mineral composition of initial and deep-buried samples.

Sample Raman reflectivity (%) TOC (%) Quartz (%) Feldspar (%) Carbonate (%) Barite (%) Pyrite (%) Clay mineral (%) Illite (%) Chlorite (%) I-M mixed-layer (%)
Initial 1.16 2.89 31 7.2 19.5 7.9 2.4 32 66 21 13
Buried 2.84 2.18 48.3 4.9 13 9.1 3.5 21.2 87 3 10

3.3.2 Simulation experiment of lifting stage

To evaluate the pore preservation mechanism in Longmaxi shale reservoir and investigate the impact of structural preservation changes during tectonic uplift on pore structure, thermal simulation experiments were conducted on four parallel deep burial samples under varying temperature and pressure condition. This experiment simulated the burial history of shale in different tectonic environments of the Silurian period. Four fluid pressure gradient points (70 MPa→0 MPa) were set in the experiment. The samples were heated to the set temperature at a rate of 1 °C/min to simulate the pressure reduction process due to tectonic uplift. Finally, shale samples representing four different burial history conditions were obtained (Table 3). The fluid pressure conditions in this simulation corresponded to pressure coefficients of 1.9, 1.3, 0.7 and 0, representing ultra-high abnormal pressure, high abnormal pressure, normal pressure, and low abnormal pressure respectively.

Table 3:

Experimental parameters of thermal simulation experiment in uplift stage under different tectonic backgrounds.

Sample ID Simulation stage Simulated buried depth (m) Lithostatic pressure (MPa) Setting temperature (°C) Holding time (h) Raman reflectivity (%) Experimental system
1 ① 5,000 125 580 130 2.91 Closed system
② 3,400 85 24
③ 415 60
2 ① 5,000 125 580 120 2.9 Semi-open system
② 3,400 85 72
3 ① 5,000 125 580 78 2.82 Semi-open system
② 3,400 85 415 70
4 ① 5,000 125 580 6 2.73 Open system
② 72
③ 3,400 85 415 72

① The strata underwent uplift under favorable preservation condition. The reservoir was well-sealed, with a 70 MPa fluid pressure, corresponded to pressure coefficient of 2.1, indicating ultra-high abnormal pressure. ② The strata was uplifted in a structurally broad and gentle region, far from fault zones. The preservation conditions were favorable, with only minimal gas escape from the shale reservoir after shale gas generation. The pressure at which hydrocarbon expulsion occurs in the reaction vessel was controlled at 45 MPa [2], corresponded to pressure coefficient of 1.3, indicating abnormal high pressure. ③ The strata had undergone uplift, but the reservoir was close to a fault zones, which led to part of shale gas escape. However, the shale reservoir still maintained a reasonable level of sealing. The fluid pressure was 24 MPa, corresponded to pressure coefficient of 0.7, indicating normal pressure condition. ④ The strata were uplifted and significantly affected by tectonic activity. The preservation conditions for shale gas were completely destroyed, with the reservoir being connected to the atmosphere, resulting in the total loss of shale gas.

The variations in temperature, lithostatic pressure, and fluid pressure during the simulation were shown in Figure 4. For Sample 1, the pressure inside the reaction vessel increased to 76 MPa by the end of the first stage. After adjusting the lithostatic pressure and temperature during the second and third stage, the pressure inside the reaction vessel decreased and stabilized at 70 MPa. For Sample 2, the pressure inside the reaction vessel increased to 69 MPa by the end of the first stage. After adjusting the lithostatic pressure in the second stage, the pressure inside the reaction vessel decreased and stabilized at 45 MPa, with the expulsion pressure also set at 45 MPa. For Sample 3, the pressure inside the reaction vessel increased to 55 MPa by the end of the first stage. The lithostatic pressure was lowered, and the vent valve was opened to slowly released gas, reducing the pressure inside the reaction vessel to 24 MPa. For Sample 4, the pressure inside the reaction vessel was 73.8 MPa by the end of the second stage. After opening the gas outlet and allowing the system to vent, the pressure inside the reaction vessel rapidly decreased.

Figure 4: The change of temperature, static rock pressure and fluid pressure with time during the simulation.
Figure 4:

The change of temperature, static rock pressure and fluid pressure with time during the simulation.

3.4 Supporting experiment and process

TOC, RO analysis, rock pyrolysis, mineral composition, NMR, gas adsorption and other experiment analyses were performed on natural and simulated samples from gold tube simulation experiment. RO analysis was performed by measuring the Raman spectral peak spacing of the samples and applying a conversion formula to calculate the equivalent vitrinite reflectance [31]. Nitrogen adsorption experiment was conducted using the Autosorb-IQ3 fully automated surface area and pore size distribution analyzer (Contech, USA). The samples were degassed under vacuum at 110 °C for 12 h before the nitrogen adsorption experiments. The Density Functional Theory (DFT) model was used to calculate the specific surface area, pore volume, and pore size distribution of micropores to macropores. Mercury intrusion experiment was conducted using the AutoPore IV 9520 automatic mercury porosimeter (Contech, USA) at China University of Geosciences. Argon ion polishing and FE-SEM observation were performed at Southwest Petroleum University. Each sample was cut into 1 cm × 1 cm × 1 cm cubes, which were then polished using an argon ion polishing system to achieve a flat and smooth surface. After polishing, the samples were observed using a Zeiss Gemini SEM 500 field emission scanning electron microscope, with a resolution of up to 0.8 nm, magnification from 20 to 2,000,000 times, and an acceleration voltage range of 0.02–30 kV. T2 NMR spectroscopy was conducted using the NMRC12-010V low-temperature nanopore analyzer (Newma, Suzhou). Samples were saturated with distilled water for 48 h before measurement and the main frequency was set to 12 MHz. Detailed operating procedures and experimental theory were illustrated in Wang (2022) [32].

3.5 Fractal dimension calculation based on nitrogen adsorption data

The fractal theory, first introduced by French mathematician Mandelbrot, was used to reflect the efficiency with which complex shapes occupy space, serving as a measure of their irregularity [33]. This theory had been applied to reservoir research in geology and was often used to quantitatively characterize the fractal characteristics and complexity of shale pores at different scales [32], [33], [34]. When characterizing the fractal features of shale pores using low-temperature nitrogen adsorption, the modified FHH (Frenkel-Halsey-Hill) theory by Pfeifer (1989) effectively captured the complexity and heterogeneity of the shale reservoir [35]. The FHH model calculated the fractal dimension using two methods: one based on van der Waals forces and the other based on capillary condensation mechanisms [36]. The fractal dimension calculation based on the capillary condensation mechanism was more suitable for studying the heterogeneity of porous media. The formula for this calculation was as follows:

l n V = C + D − 3 ln   ln p 0 p

In the formula, V represents the volume of adsorbed gas at an absolute pressure P (ml/g), P0 is the saturated vapor pressure (MPa), D is the fractal dimension, and C is a constant. To determine D, a scatter plot was created with ln (lnP0/P) on the x-axis and lnV on the y-axis. The slope of the fitted line was used to calculate the fractal dimension. The fractal dimension of the shale reservoir, calculated using the FHH model, typically ranges from 2 to 3. A higher value indicates greater pore system complexity and irregularity. The double logarithmic curve often exhibits an obvious turning point, and based on this, the fractal dimensions of different adsorption stages can be calculated. This stage is typically selected at a relative pressure P/P0 = 0.45–0.5 (i.e., when the adsorption isotherm exhibits a hysteresis loop and capillary condensation occurs) for segmentation [37], 38]. In this study, the fractal dimension D is divided into two regions: D1(P/P0 < 0.5) and D2 (0.5 < P/P0 < 1). D1 represents the fractal dimension of smaller pore structures, while D2 represents the fractal dimension of larger pore structures.

4 Results and discusstion

4.1 Pore type and morphology

Simulated samples had similar thermal maturity (≈2.8 %), but differences in fluid pressure resulted in significant variations in pore structure between the samples (Figure 5). Under ultra-high abnormal pressure, organic pores in shale were well-developed, and most exhibited honeycomb, round, or oval bubble-like pore morphologies. Irregular and angular organic pores were rarely observed. The pore sizes were similar, with large diameters, and the connectivity between organic pores was high. Inorganic pores were abundant, primarily consisting of intergranular dissolution pores and clay mineral intercrystalline pores (Figure 5a). Under high abnormal pressure, organic pores in shale reservoir exhibited more complex shapes and a significant increase in pore size variability. The pores were primarily sub-rounded, with fewer bubble-like pores. Organic pore diameter and volume were smaller, and the pores were relatively independent, exhibiting lower connectivity (Figure 5b and c). As fluid pressure decreased, both organic and inorganic pore sizes reduced significantly, and organic pore shapes evolved from bubble-like or sub-rounded to elongated or linear. Under normal pressure, organic pores were nearly absent (Figure 5a–d), and inorganic intergranular pores gradually diminished or disappeared, with only a few intergranular dissolved pores remaining (Figure 5e and f). Teng et al. (2021) suggested that factors such as organic carbon content [39], organic matter type (kerogen or pyrobitumen), maturation level, and mineral content collectively influenced the development of organic matter pores in the Longmaxi Formation shale. This study, however, demonstrates that tectonic preservation conditions were a critical factor influencing the morphology, size, and connectivity of organic pores. It is suggested that organic carbon content, organic matter type (kerogen or pyrobitumen), maturation level, and mineral content affected the development of organic pores in the Longmaxi Formation shale comprehensively [40]. However, this study demonstrated that tectonic preservation conditions were a critical factor influencing the morphology, size, and connectivity of organic pores.

Figure 5: The characteristics of shale pore type and morphology change with fluid pressure change during simulation.
Figure 5:

The characteristics of shale pore type and morphology change with fluid pressure change during simulation.

4.2 Pore type ratio and pore size evolution

As fluid pressure decreased, the simulation instrument gradually transitioned from a closed system to an open system, and the porosity of both organic and inorganic pores showed a significant decline (Figure 6a–c). Specifically, organic pore volume decreased from 3.71 % to 0.5 %, representing an 86.5 % reduction (Figure 6a, 6c), while inorganic pore volume decreased from 2.96 % to 1.87 %, representing a 36.8 % reduction (Figure 6b and c). This indicated that the porosity of organic pores decreased rapidly, while the decline rate of inorganic pore porosity was slower. Total porosity also decreased significantly, from 6.82 % to 2.37 %, representing a 65.2 % reduction (Figure 6c). Furthermore, the proportion of organic pores in the shale reservoir gradually decreased, shifting from predominantly organic pores (55.6 %) to predominantly inorganic pores (78.9 %) (Figure 6d). As fluid pressure within the shale reservoir decreased, its anticompaction ability weakened, resulting in a significant reduction in pore size. The decrease in fluid pressure had a greater effect on organic pores. This could be attributed to favorable preservation conditions, where abnormal pore pressure within the pores was sufficient to effectively resist formation pressure, thus slowing compaction damage and helping to maintain shale storage space. The latter might be due to the plasticity of organic matter, which was more prone to deformation and compression under overlying pressure and compaction. In contrast, inorganic pores were more dependent on the support of rigid minerals. Although they lost the support of fluid overpressure, the mineral framework could still partially resist compaction, allowing inorganic pores to remain partially preserved. This was consistent with the conclusion that inorganic intergranular pores in the open system disappear, while intragranular pores remain preserved under the scanning electron microscope.

Figure 6: Variation characteristics of organic pore-fissure (a) and inorganic pore-fissure (b) NMR T2 spectrum distribution, porosity (c) and ratio (d) of organic/inorganic pore, of shale sample as fluid pressure changes.
Figure 6:

Variation characteristics of organic pore-fissure (a) and inorganic pore-fissure (b) NMR T2 spectrum distribution, porosity (c) and ratio (d) of organic/inorganic pore, of shale sample as fluid pressure changes.

The pore size of Wufeng-Longmaxi shale in different tectonic regions of the southeastern Sichuan Basin was primarily between 10 and 25 nm (Figure 7a). As fluid pressure decreased, the full-aperture curve of the shale shifted left, indicating a reduction in both pore size and volume (Figure 7a). This trend was consistent with the gradual decrease in total pore volume (Figure 7b). Additionally, the T2 spectra for both organic and inorganic pores shifted from a bimodal to a unimodal distribution, with the peak moving to the left, further indicating an overall reduction in pore size (Figure 6a and b). As fluid pressure decreased (pressure coefficient reduced from 2.1 to 0), total pore volume decreased by 68.5 %, from 0.0232 cm3/g in the ultra-high abnormal pressure samples to 0.0073 cm3/g in the low abnormal pressure samples (Figure 6b). As fluid pressure decreased, the shale pore volume for pores with diameters greater than 10 nm decreased rapidly. However, when fluid pressure dropped below 24 MPa, the pore volume in shale with pore sizes between 0 and 10 nm actually increased to some extent. The pore volume of all pore sizes decreased in the open system (Figure 7c and d), which indicated that as fluid pressure decreased, larger pores in shale were gradually compressed into smaller pores under formation pressure. The proportion of small pore sizes gradually increased (Figure 7c and d). As fluid pressure reached a sufficiently low value, intergranular pores disappeared rapidly.

Figure 7: Variation characteristics of pore size distribution (a), total pore volume (b), pore volume proportion (c) and distribution (d) of different pore size, of shale sample as fluid pressure changes.
Figure 7:

Variation characteristics of pore size distribution (a), total pore volume (b), pore volume proportion (c) and distribution (d) of different pore size, of shale sample as fluid pressure changes.

4.3 Pore complexity

The micro-nanometer pores in the shale reservoir exhibited various forms, complex structures, and strong heterogeneity. The low-temperature nitrogen adsorption-desorption isotherms exhibit subtle morphological variations but collectively conform to a characteristic inverted S-shape, with the hysteresis loops primarily categorized as H2(b) and H3 types according to the classification standards for adsorption isotherms and hysteresis loops established by the International Union of Pure and Applied Chemistry (IUPAC) (Figure 8). Fractal theory was an important method for the microscopic quantitative study of pore heterogeneity. In this study, low-temperature nitrogen adsorption data and the FHH model were used to calculate the shale sample fractal dimension, as shown in Table 4.

Figure 8: Low temperature nitrogen adsorption-desorption loops in shale with different fluid pressures.
Figure 8:

Low temperature nitrogen adsorption-desorption loops in shale with different fluid pressures.

Table 4:

Fractal dimension parameters of shale with different fluid pressures based on FHH model.

Sample ID 0.01 < P/P0 < 0.5 0.5 < P/P0 < 1 Nitrogen adsorption capacity (cm3/g)
Fitting equation D1 R2 Fitting equation D2 R2
Sample 1 Y = −0.4724x+1.0118 2.5276 0.9991 Y = −0.2813x+1.2933 2.7187 0.996 0.0232
Sample 2 Y = −0.4037x+1.0695 2.5963 0.9965 Y = −0.2831x+1.2507 2.7169 0.9959 0.0149
Sample 3 Y = −0.3555x+1.1512 2.6445 0.9995 Y = −0.254x+1.3169 2.746 0.9939 0.0135
Sample 4 Y = −0.3272x+1.1787 2.6728 0.99 Y = −0.2391x+1.371 2.7609 0.9934 0.0073

The fractal dimension results showed that the pore volume component (lnV) and relative pressure (ln (ln (P0/P))) exhibited two slopes in the intervals of 0.01–0.5 and 0.5–1, indicating that the pores in shale samples display a dual fractal characteristic (Figure 9). D1 represented the fractal dimension in the low-pressure region (P/P0 < 0.45), primarily reflecting monolayer-multilayer adsorption and filling occurring within micropores (<2 nm) and partial mesopores (2∼50 nm). It could be used to indicate the irregularity, roughness, and complexity of the pore surface [36], 41]. D2 represented the fractal dimension in the high-pressure region (P/P0 > 0.45), reflecting the capacity of macropores (>50 nm). As pressure increased, capillary condensation of gas occurred in shale pores, typically indicating the complexity of the pore space and structural irregularity [42].

Figure 9: Fractal characteristics of nitrogen adsorption in shale with different fluid pressures.
Figure 9:

Fractal characteristics of nitrogen adsorption in shale with different fluid pressures.

The fractal dimension results calculated from low-temperature nitrogen adsorption data showed that (Table 4) shale samples with different maturities’ nitrogen adsorption capacity range from 0.0073 cm3/g to 0.0232 cm3/g, with an average of 0.0147 cm3/g, while D1 values ranging from 2.53 to 2.67, with an average of 2.57. D2 ranged from 2.72 to 2.76, with an average of 2.73. Both D1 and D2 were relatively high, indicating that the shale samples possessed complex pore structures, with both small and large pores exhibiting high surface roughness and significant heterogeneity. The correlation coefficients for the D1 and D2 fractal dimension calculation formulas were both greater than 0.99 (Figure 9), confirming that the pore structures of all shale samples exhibited significant fractal characteristics. The average D1 value calculated by the FHH model was lower than D2, suggesting that under different preservation conditions, the surface roughness of the simulated samples was less pronounced than the complexity of their internal pore structures.

D1 and D2 were negatively correlated with final fluid pressure (Figure 10), indicating that as fluid pressure decreased, both surface roughness and internal structural complexity of the pores increased. This suggested that the supporting effect of fluid pressure on pore weakening significantly enhanced the complexity and heterogeneity of the pores under compaction. The correlation between D2 and fluid pressure was stronger, indicating that changes in fluid pressure had a more significant impact on the internal complexity of the pores. Additionally, by comparing the fractal dimension D1 and D2 of shale under different fluid pressures, we found that the complexity of small pores was greater than that of large pores under all fluid pressures. This was related to the higher development of organic pores in the simulated samples. The bubble-like and needle-like pores produced by the thermal evolution of secondary organic matter increased the development of pores smaller than 5 nm in shale, enhancing the complexity and heterogeneity of the pores.

Figure 10: Relation between final fluid pressure and fractal dimension.
Figure 10:

Relation between final fluid pressure and fractal dimension.

4.4 Pore development models of shale reservoirs

The Wufeng-Longmaxi shale in the Sichuan Basin underwent a tectonic evolution process involving earlier burial and later rapid uplift, and was generally overpressured before the Yanshan movement. The Yanshan and Himalayan movements caused the tectonic uplift of the Wufeng-Longmaxi shale in southeastern Sichuan Basin. During the uplift, the shale experienced deformation and erosion of overlying strata, the termination of hydrocarbon generation, changes in rock mechanical properties, and fault formation. Significant pressure differences in gas reservoirs across various structural regions led to the differential evolution of reservoir characteristics [9], 14]. To clarify the relationship between shale pore development characteristics and tectonic preservation conditions, a pore development model under different tectonic preservation conditions was established based on the actual tectonic background (Figure 11a).

  1. If the structural preservation conditions in the shale reservoir were favorable during the uplift period, with strong reservoir sealing and no effects from fractures or faults, an ultra-high abnormal pressure shale reservoir could form. Under these conditions, fluid overpressure significantly affected pore preservation. Shale porosity was extremely high, with both organic and inorganic pores developed, predominantly organic. The organic pore morphology was characterized by large-diameter bubble-like pores and honeycomb-like or network-like structures, exhibiting high connectivity. Inorganic pores were primarily intergranular, with point or line contacts frequently observed between particles (Figure 11b).

  2. If the shale reservoir was located far from faults during the uplift period, and the tectonic structure was broad and gentle, the reservoir preservation conditions were favorable, and a high-pressure reservoir formed. Under these conditions, porosity in the shale reservoir was relatively high, with organic and inorganic pores developing to a similar extent. Organic pores were predominantly spherical, with smaller diameters and relatively isolated spaces, while intergranular pores were less developed (Figure 11c).

  3. If the shale reservoir was located near faults or surrounding fractures during the uplift period and shale gas was partially dissipated, the shale reservoir may still be relatively closed, forming a normal formation pressure reservoir. Under these conditions, fluid pressure in the shale pores was relatively low and cannot resist compaction. Therefore, the reservoir space was dominated by inorganic pores. Under the influence of compaction, organic pores were significantly deformed; they become elliptical or irregular, reducing pore size, and the development of intergranular pores was further diminished, with particles primarily in line contact (Figure 11d).

  4. If the shale reservoir undergone intense tectonic activity during the uplift process, the preservation conditions for shale gas were completely destroyed, forming an abnormal low-pressure reservoir. Under these conditions, the storage capacity of shale reservoir was poor; shale pores were primarily inorganic, while organic pores were poorly developed and are small, needle-like, or wedge-shaped. The inter-particle contacts were primarily linear or mosaic, and inter-particle pores were largely undeveloped, with inorganic pores mainly consisting of intra-particle dissolved pores (Figure 11e).

Figure 11: Pore structure evolution model of shale reservoirs under different tectonic preservation conditions ((a) is modified from Hu [1]).
Figure 11:

Pore structure evolution model of shale reservoirs under different tectonic preservation conditions ((a) is modified from Hu [1]).

5 Conclusions

  1. As the preservation conditions of shale deteriorated, both organic and inorganic pore sizes decreased significantly. Organic pore morphology evolved from circular or near-circular shapes to elongated or strip-like shapes. In an open system, organic pores were barely developed, while interparticle inorganic pores gradually diminished or disappeared.

  2. The pore volume, total porosity, and proportion of organic pores all decreased as preservation conditions deteriorated and fluid pressure decreased. It was suggested that favorable preservation conditions, supported by higher fluid pressure, could resist and slow down compaction, thereby aiding in pore retention. The reduction in fluid pressure had a more significant impact on organic pores, likely because organic matter, being a plastic medium, was more prone to deformation under overlying pressure and compaction.

  3. The FHH calculation results showed that as fluid pressure decreased, both the roughness of the pore surface and the complexity of its internal structure increased. This was related to the weakening effect of fluid pressure on pore retention. The fractal dimension (D2) showed a stronger negative correlation with fluid pressure, indicating that changes in fluid pressure had a more significant effect on the internal complexity of the pores.

  4. Four preservation scenarios are emerged, demonstrating how tectonic stress regimes and fluid pressure histories directly control pore architecture from well-connected networks in preserved zones to collapsed structures in disturbed areas, with organic pore morphology serving as a sensitive indicator of preservation conditions. The established model quantitatively links structural setting to pore characteristics, providing predictive capability for shale gas exploration targeting.

Corresponding author: Yifan Gu, School of Geosciences and Technology, Southwest Petroleum University, Chengdu, Sichuan 610500, China, E-mail:

  1. Funding information: This work was supported by National Natural Science Foundation of China (Grant No. 42272171) and National Natural Science Foundation of China (Grant No. 42302166).

  2. Author contributions: Yue Sun contributed to the conception of the manuscript, edited and revised it. Yuqiang Jiang contributed importantly to the analysis and review. Chan Jiang helped perform data curation and analysis. Yixiao Yang and Yifan Gu contributed to the data collection and processing. Yixiao Yang and Chan Jiang helped revised the manuscript. All authors have read and agreed to the published version of the manuscript.

  3. Conflict of interest: The authors declare no conflict of interest.

  4. Data availability statement: The data supporting the findings of this study are available within the article.

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Received: 2025-02-18
Accepted: 2025-10-26
Published Online: 2026-04-24

© 2026 the author(s), published by De Gruyter, Berlin/Boston

This work is licensed under the Creative Commons Attribution 4.0 International License.

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https://doi.org/10.1515/geo-2025-0921
Keywords for this article
shale reservoir; fluid pressure; preservation condition; Wufeng-Longmaxi formation; southeast Sichuan basin
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BY 4.0

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