After more than 10 years of exploration and development of shale gas from the Upper Ordovician Wufeng Formation to the Lower Silurian Longmaxi Formation in Sichuan Basin, the industrial production at a shallow depth above 3500 m has been basically realized, and the annual output is nearly 200×10⁸ m^3[1,2]. The favorable shale area of the Wufeng-Longmaxi Formation with a buried depth of 3500-4500 m in the basin is about 1.6×10⁴ km², with geological resources of 9.6×10¹² m³, accounting for 50% of the shale gas resources in southern China^[3]. Deep shale gas has become the key target of natural gas exploration and development in the 14th Five-Year Plan. Difficulties in developing deep shale gas focus on the study of shale reservoir. In recent years, the studies on reservoir space mainly focuses on the development of organic pores^[4,5,6] and their connectivity^[7,8], the influence of mineral components and organic-inorganic diagenetic evolution, "source-reservoir" matching and tectonism on reservoir space^{[9,10,11,12,13,14]}, while studies on organic pores and micro-fractures are relatively independent and do not focus on the configuration between them. During the continuous burial and diagenetic process of organic matter and mineral components, with the increase of temperature and pressure and the coordinated evolution of later adjustment, the proportion of organic pores and micro-fractures also changes, which affects the occurrence, enrichment and exploitation of shale gas. After reaching the over mature stage, shale gas can be migrated a short distance through micro-fractures and re-enriched^[15,16]. The morphological evolution of organic pores occurs due to the change of internal pressure, and the change of inorganic pores is small due to mineral support. The pore-fracture configuration studied in this paper mainly focuses on the relationship between organic pores and micro-fractures. Taking the deep shale reservoir of the Wufeng Formation to the 1^st sub-member of 1^st member in the Longmaxi Formation (referred to as Long 1₁) in western Chongqing block as a case, we systematically analyze the development characteristics of microscopic pores and fractures, carry out the quality evaluation of the microscopic pore-fracture configuration, and discuss the gas-bearing characteristics of different types of pore-fracture configuration. Based on the analysis above, combined with the development characteristics of inorganic pores, the microscopic gas-filled model of shale gas is constructed in order to investigate the enrichment mechanism of shale gas and provide a theoretical basis for selecting "sweet spot intervals".

The study area is located in the southeast of Sichuan Basin. Its plane structure is banded distribution (Fig. 1a), and characterized by "alternating graben and horst" from northeast to southwest^[17,18]. In study area, the black shale of the Wufeng Formation-Long 1₁ sub-member is distributed continuously, with a thickness of 38-72 m and a buried depth of more than 3500 m. It is mainly black, gray black thin-layer shale or silty shale with developed lamina^[19]. The Long1₁ sub-member can be subdivided into four sub-layers: Long1₁¹-Long1₁⁴ (Fig. 1b).

The experimental samples were selected from wells Z201, Z202, Z203, Z205, Z206, Z207 and Z208 drilled in the Wufeng Formation to the Long 1₁ sub-member with high GR values. They are conducive to the analysis of the development characteristics of organic pores and micro- fractures. Seven to eight parallel samples were selected from each well for argon ion polishing scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) experiments. The macro basic parameters have been tested in advance, such as organic matter content, mineral composition, porosity, gas content, etc. The gas content was measured in field. Shale reservoirs with high organic matter content, high porosity and high gas content are mainly distributed at the top of the Wufeng Formation, Long1₁¹ sub-layer and Long 1₁³ sub-layer. In general, from bottom to top, the content of quartz in shale gradually decreases and the content of clay gradually increases (Fig. 1b).

SEM experimental samples were taken from the end of the plunger sample in NMR experiment. For microscopic observation and photo shooting, 4 rectangular areas were selected, and 9 photos were taken in each area, that is, at least 36 photos were collected from each sample. To more objectively reflect pore information in the samples, they were spliced into rectangular photos 10 μm long and 8 μm wide. Parameters such as plane porosity of pores, pore size, fracture width and plane porosity of fractures were statistically analyzed by Image J (an image processing software) to provide data support for the study of microscopic pore-fracture configuration types. Considering the complex pore system of shale reservoir and obvious wettability difference, water with media of different wettability (potassium chloride solution with 20 000×10^-6 in mass fraction) and oil (n-dodecane) were used to saturate the plunger samples for NMR T₂ (transverse relaxation time) spectrum test, and then the proportion of organic pores, inorganic pores and micro-fractures were analyzed. The saturation pressure was set to 25 MPa, the echo interval was set to 0.06 ms, the number of echoes was set to 12 000, the cumulative sampling times was set to 128, and the waiting time was set to 3000 ms.

A large amount of natural gas is accumulated in the complex pore-fracture system of shale reservoirs which is formed by multi-stage thermal maturation and diagenesis^[20]. However, no consensus has been reached on the classification of shale reservoir pores due to diverse genesis. In this study, shale reservoir space is divided into organic pores, inorganic pores, and micro-fractures according to existing schemes of pore system classification in China and abroad^[21,22,23] and SEM results, to analyze the characteristics of pores and micro-fractures.

2.1.1. Organic pores

Organic pores can be further classified according to their development position and morphology into organic pores in migrating organic matter, spongy organic pores in original organic matter, and isolated organic pores in solid kerogen^[12]. Migrating organic matter is formed by the migration of liquid hydrocarbon products generated during the gas generation stage of kerogen degradation, and fills in the residual intergranular pores and intragranular pores in the form of "extensively distributed round pores" (Fig. 2a)^[13], and accounts for the largest proportion in the study area. Overpressure is formed by the cracking of the migrating organic matter during the thermal maturation, which generates massive natural gas and leads to the formation of hydrocarbon-generating pressurized fractures at the edges of the minerals. In this context, natural gas in the organic matter may migrate into nearby fractures for preservation, resulting in reduced amounts of organic pores in some parts near the fractures (Fig. 2b). Meanwhile, organic pores may be deformed due to structural influence or compaction (Fig. 2c). Original organic matter refers to the original kerogen that stays in place during hydrocarbon generation and evolution, and it is relatively large, mostly in shapes of circles, ellipses, or long strips (Fig. 2d). It is believed in previous research that organic pores in original organic matter are large in number and small in size, but rarely occur as bubble-like pores^[24]. However, connected macro-pores have been observed in the study area (Fig. 2d), which is attributed to the low hydrocarbon expulsion efficiency due to the large distribution area of original organic matter.

2.1.2. Inorganic pores

The shale of the Wufeng Formation-Long 1₁ sub-member in the study area is deeply buried and thus subjected to strong compaction that results in massive dissolution accompanied by intergranular pores. Minerals including clay, feldspar, dolomite and calcite are vulnerable to transformation or dissolution during the diagenesis, forming various intergranular dissolution pores (Fig. 2e) and intragranular dissolution pores (Fig. 2f). In addition, there are a large number of intercrystalline pores developed in pyrite (Fig. 2g), with local organic fillings. Flake-shaped clay particles aggregated and dehydrated, forming irregular pores among the layers of clay mineral aggregates, which are mainly in the forms of parallel lines, clusters, or "paper houses" (Fig. 2h). Some grains are broken and embedded in adjacent organic matter due to influences of structural deformation or compaction, resulting in a large number of intergranular pores (Fig. 2h). In general, intergranular pores are mostly irregular with large sizes, while intragranular pores are mostly isolated with round shape and small size.

2.1.3. Micro-fractures

Micro-fractures not only provide reservoir space but also effectively increase permeability. In addition to hydrocarbon-generating pressurized fractures (Fig. 2b), there are also dissolution fractures, structural fractures, compaction fractures, organic matter edge fractures and diagenetic contraction fractures in the Wufeng Formation-Long1₁ sub-member shale. Dissolution fractures are secondary micro-fractures formed after formation fluids dissolve unstable minerals. They often develop on the edges of unstable minerals and are mostly in curved shape or irregular pits (Fig. 2i). Some organic pores are destroyed by tectonics, which squeeze and break minerals at local places, releasing natural gas inside (Fig. 2h). This type of micro-fractures is mostly in the form of jagged lines, extending long and usually running through the entire field of view. Compaction is also one of the reasons for the formation of micro-fractures since brittle minerals are vulnerable to breakage due to overlying pressure. This type of micro-fractures is of relatively limited development, mainly on the edge or inside of certain minerals (Fig. 2j), which can facilitate natural gas migration. Meanwhile, long micro-fractures are also observed on the contact edge of organic matter and minerals (Fig. 2h). It is previously believed that this type of organic matter should be original organic matter or solid asphalt, which has poor hydrocarbon generation capacity during thermal maturation and can’t develop organic pores^[25]. However, organic pores are observed in the migrating organic matter strips adjacent to, but not connected with diagenetic contraction fractures in clay minerals (Fig. 2k), while they are rare in the migrating organic matter connected with micro-fractures (Fig. 2l). These phenomena could be related to the migration of natural gas along micro-fractures to other "low potential areas" during thermal maturation. Therefore, it can be inferred that large micro-fractures between organic matter and rigid minerals may connect with other inorganic pores, so high pressure in the organic pores can not formed because shale gas migrating out. In this condition, organic pores became smaller, deformed, and even completely closed. As the main source of migrating organic matter, the original organic matter expelled hydrocarbon during the oil generation stage, but bubble-like organic pores cannot be formed in later cracking and gas generation stage. While hydrocarbon expulsion in large-area original organic matter is constrained, bubble-like, interconnected organic pores can be formed inside the organic matter during the cracking and gas generation process. Therefore, micro-fractures have a greater impact on the shape and distribution of organic pores.

2.2.1. Classification of microscopic pore-fracture configurations

As shown in Table 1, organic pores in wells Z201, Z203, Z206, and Z208 account for more than 48% of the total pores, while the average proportion of micro-fractures in these wells is lower than 20%. In contrast, wells Z202, Z205 and Z207 have larger proportion of inorganic pores and micro-fractures. Wells Z201, Z203 and Z208 have fewer micro-fractures and more round organic pores, while wells Z202, Z205 and Z207 have more micro-fractures and less or no irregular organic pores. It indicates that micro-fractures affect the morphology, size, and development scale of organic pores in shale reservoir.

Tectonics might be a macroscopic factor that causes the great inter-well difference in proportions of different pore types^[16]. Microscopic factors have not been identified. Under normal circumstances, a higher pressure coefficient generally corresponds to higher pore pressure, which can offset the overlying pressure and facilitate the preservation of organic pores in round-hole and honeycomb shapes. In contrast, a lower pressure coefficient generally corresponds to lower pore pressure, and organic pores may shrink, deform and even completely close^[26]. Therefore, the morphology of organic pores is dynamically changed with changes in geological conditions, and this modification may be accompanied by short-distance shale gas migration^[15]. Shale gas gets enriched when a new equilibrium state reaches. After shale gas migrates out of organic pores, the pressure in the organic pores decreases, which affects the pore shape and size. If we regard organic matter as an independent unit of shale gas microscopically enriched and balanced and ignore the influence of possible micro-fractures, the relationship among overlying formation pressure (p_f), mineral pressure (p_w), and pore internal pressure (p_o) determines the shapes and sizes of organic pores. When p_f is equal to the sum of p_w and p_o, organic pores are regularly round; when p_f is less than the sum of p_w and p_o, organic pores present complex features with smaller pores in larger pores; when p_f is greater than the sum of p_w and p_o, organic pores are deformed and smaller. If a large number of micro-fractures are connected to the organic pores, shale gas in the organic pores will migrate through the micro-fractures to other spaces, thereby reducing the internal pressure of the pores and leading to the destruction of the original balance. In this context, organic pores are deformed to various degrees. The interrelationship between organic pores and micro-fractures can reflect the superiority of pore structure to a certain extent.

2.2.2. Types of microscopic pore-fracture configuration

Since shale reservoirs are tight in structure and poor in permeability, abnormally high pressure is easily formed after the thermal maturation of organic matter and hydrocarbon expulsion^[27]. Moreover, pore-fracture configuration directly affects the enrichment of shale gas in the reservoir. If there are a large number of micro-fractures in shale reservoirs, natural gas will migrate from the “high-pressure area” with massive organic pores to the “low-pressure area” with micro-fractures or micro-fractures connecting to inorganic pores. This results in “microscopic pressure release” from organic matter, and consequently organic pores in various shapes and open micro-fractures to various degrees. From the microscopic perspective of hydrocarbon generation and expulsion, a systematic analysis of the configuration between organic pores and micro-fractures can help better understand natural gas enrichment in shale reservoirs.

Four types of microscopic pore-fracture configurations are classified according to the development degree of organic pores, the types of micro-fractures, and their contact relationship: pore-hydrocarbon-generating pressurized fracture contact, pore-inorganic diagenetic fracture separation, structural micro-fracture contact, and organic matter edge fracture contact (Table 2). Specifically, the pore-inorganic diagenetic fracture separation type can be further divided into three sub-types according to the types of inorganic diagenetic fractures: pore- clay fracture separation, pore-mineral dissolution fracture separation, and pore-compaction fracture separation (Table 2 and Fig. 3). Pore-hydrocarbon-generating pressurized fracture contact type is featured by developed organic pores with the pore diameter of 20-200 nm and the highest surface porosity of 18% (Fig. 3a). Pore-inorganic diagenetic fracture separation type is characterized by poor contact between the micro-fracture and organic matter, so organic pores in some local areas adjacent to micro-fractures are depressurized and become smaller (Fig. 3b-3d). Structural micro-fracture contact and organic matter edge fracture contact types are affected by tectonism or diagenesis, which generate massive, elongated micro-fractures in the particle or at the edge of organic matter, thereby enhancing the permeability of the shale reservoir and causing organic pore deformation, shrink and destruction due to pressure loss (Fig. 3e, 3f). In these two types, the surface porosity of organic pores is relatively low, while that of the micro-fractures is relatively high.

There are many types of pore-fracture configuration in shale reservoirs. However, quantitative evaluation on pore-fracture configuration is influenced by experiment operators and samples in SEM analysis^[28]. In this study, efforts are made to quantitatively evaluate the types of pore-fracture configuration by determining the proportions of organic pores and micro-fractures based on the difference between oil-saturated and water-saturated T₂ spectra.

There are obvious differences in the morphological characteristics of NMR T₂ spectra of different types of pore-fracture configuration, especially in the oil-saturated T₂ spectra (Fig. 4). Moreover, oil-saturated and water-saturated T₂ spectra are different in all types of pore- fracture configuration, mainly due to the difference in the development degree of organic pores, inorganic pores, and micro-fractures^[29,30]. It was proposed in previous researches that the relaxation time of micro-fractures should be longer^[31]. Usually, the peak with relaxation time greater than 100 ms corresponds to micro-fractures, while that with less than 100 ms corresponds to pores. Moreover, organic pores tend to be oil-wet, while inorganic pores tend to be water-wet^[32,33]. Micro-fractures related to organic matter are different from those related to minerals in T₂ spectra. Accordingly, it is feasible to differentiate organic pores, organic matter-related micro-fractures, and mineral-related micro-fractures by comparing oil-saturated and water-saturated T₂ spectra.

Pore-hydrocarbon-generating pressurized fracture contact is featured by developed bubble-like organic pores, limited-developed micro-fractures, bimodal oil- saturated T₂ spectrum, dominant pore responses of 0.01- 10.00 ms, and weak responses of micro-fractures larger than 100 ms (Fig. 4a). Pore-inorganic diagenetic fracture separation is featured by developed micro-fractures, local influence on organic pores, smaller peak areas in oil-saturated T₂ spectra than those in water-saturated ones, and strong responses of micro-fractures (Fig. 4b-4d). Structural micro-fracture contact is characterized by deformed and smaller organic pores, increasing intergranular pores, unimodal peaks in both oil-saturated and water-saturated T₂ spectra with main relaxation time of 0.01-1.00 ms, weak pore heterogeneity, and continuous T₂ spectrum peaks (Fig. 4e). Organic matter edge fracture contact is featured by influence on organic pores development, unimodal peaks in both oil-saturated and water-saturated T₂ spectra, and the micro-fractures with relaxation time longer than 100 ms characterized by oil saturation (Fig. 4f). Therefore, it can be concluded that differences in types of organic pores and micro-fractures result in different T₂ spectral peaks in different types of pore-fracture configuration.

In general, more developed organic pores contribute to better shale reservoir quality and larger shale reservoir space^[34]. Hydrocarbon-generating pressurized fractures can increase reservoir space, which is conducive to natural gas enrichment though their development degree is low. Organic matter edge fractures and structural micro-fractures can cause the deformation or extinction of organic pores. Therefore, the ratio of the porosity of oil-wet micro-fractures (ϕ_of) to that of oil-wet pores (ϕ_op) can reflect the configuration relationship between organic pores and micro-fractures, and the larger the value, the more unfavorable for natural gas migration. Similarly, the ratio of the porosity of water-wet micro-fractures (ϕ_wf) to that of water-wetted pores (ϕ_wp) can reflect the configuration relationship between inorganic pores and micro-fractures, and the larger the value, the more favorable for natural gas migration. On this basis, the evaluation parameter Q of pore-fracture configuration is defined (Eq. 1). A larger value indicates poorer pore-fracture configuration. The Q value is less than 40%, the pore-fracture configuration is better; the Q value is 40% to 60%, the configuration is medium; the Q value is greater than 60%, the configuration is poor. Ratios of ϕ_of to ϕ_op and ϕ_wf to ϕ_wp can be calculated by oil-saturated and water-saturated T₂ spectra (Eqs. 2 and 3).

All Q values are smaller than 40% for pore-hydrocarbon-generating pressurized fracture contact, pore-clay fracture separation, and pore-mineral dissolution fracture separation, indicating good pore-fracture configuration. The Q value for pore-compaction fracture separation is 40% to 60%, indicating moderate pore-fracture configuration. The Q values are greater than 60% for structural micro-fracture contact and organic matter edge fracture contact, indicating poor pore-fracture configuration (Table 3).

The study area is located in a highly steep structural belt with complicated geological conditions. The sampling wells are distributed in Mituochang and Pulvchang synclines, with various distances from faults and thus different influences of tectonic activities on the pore-fracture configuration. Well Z203 far away from faults and Well Z205 close to faults^[35] were selected to compare the vertical distribution characteristics of the pore-fracture configuration in shale reservoirs (Fig. 5).

Well Z203 is far from faults and is thus less affected by tectonics. The development of pores and micro-fractures is mainly affected by material composition, diagenesis, thermal maturation, and formation pressure coefficient^{[12, 14, 26]}. With constant thermal maturity and diagenesis, pore development is mainly affected by TOC and mineral composition. The interval from the top of the Wufeng Formation to Long1₁¹ sub-layer is featured by high organic matter and quartz contents, low clay mineral content, strong hydrocarbon generation capacity, and well-developed organic pores due to offset of overlying pressure by the presence of quartz and internal pore pressure. The pore-fracture configuration in the interval is mainly in pore-hydrocarbon-generating pressurized fracture contact. The Long1₁² sub-layer is characterized by relatively low TOC, high feldspar content, and low internal pore pressure. In this interval, the overlying pressure is mainly resisted by minerals, and many grains are broken. The pore-fracture configuration in this interval is mainly in pore-dissolution fracture separation and pore-compacted fracture separation. The interval from the top of the Long1₁³ sub-layer to the bottom of Long1₁⁴ sub-layer is featured by relatively high TOC, relatively high hydrocarbon generation capacity, so the pore-fracture configuration is locally in pore-hydrocarbon-generating pressurized fracture contact. The upper part of Long1₁⁴ sub-layer has rapidly decreasing TOC and increasing clay mineral content, accompanied by massive diagenetic contraction fractures at the contact between organic matter and clay minerals. The pore-fracture configuration in this interval is in organic matter edge fracture contact (Fig. 5a).

Well Z205 is close to faults and thus greatly affected by tectonic activities. Developed micro-fractures reduce the internal pore pressure and thus decrease the pore size. The interval from the Wufeng Formation to the Long1₁² sub-layer belongs to type of structural micro-fracture contact, while the pore-fracture configuration of the interval from Long1₁³ sub-layer to Long1₁⁴ sub-layer is similar to Well Z203 (Fig. 5b).

It is found by comparison of vertical distribution of pore-fracture configurations in Z203 and Z205 that high- quality pore-fracture configurations with less structural influences are almost distributed in the top of the Wufeng Formation to Long1₁¹ sub-layer, followed by the interval from the top of Long1₁³ sub-layer and the bottom of Long1₁⁴ sub-layer. In addition, high-quality pore-fracture configurations with large structural influences are mainly in the interval from the top of Long1₁³ sub-layer and the bottom of Long1₁⁴ sub-layer. Therefore, three-dimensional shale gas development should focus on the reservoir in the interval from the top of Long1₁³ sub-layer and the bottom of Long1₁⁴ sub-layer.

In addition to the impact of engineering construction, the gas content of shale reservoir and the occurrence state of shale gas directly affect the production effect, which is the key to high and stable production of shale gas^[36]. In addition to TOC, mineral composition, temperature and pressure conditions, gas content and occurrence state are also closely related to pore structures^[37]. Generally, shale reservoirs with superior pore structures have high porosity, gas content and free gas content^[1]. Exploration and development practice has proved that the high-efficiency shale gas production layer in the study area is concentrated in the Long₁¹ sub-layer. Therefore, this paper focuses on the impact of pore-fracture configuration on gas bearing property of this sub-layer.

The proportion of pores varies greatly among different types of pore-fracture configuration (Fig. 6). Wells Z202, Z205 and Z207, etc. have large Q values, poor pore-fracture configuration and developed micro-fractures, which are easy to cause the reduction, deformation or extinction of organic pores, resulting in short-distance migration of shale gas, and consequently reduced reservoir porosity and increased permeability (Fig. 6a, 6b). Wells Z201, Z203 and Z208, etc. have small Q values, good pore-fracture configuration quality, and more developed organic pores. But the micro-fractures have limited extension, small width, and good plugging property. It is easy to form abnormal high pressure, which is conducive to pore preservation, increasing reservoir porosity and reducing permeability (Fig. 6a, 6b).

In this study, field desorption test was carried out at 60°C, and the desorbed gas volume before heating was obtained; then the temperature was increased to 90 °C and the desorbed gas volume after heating was obtained. Before the desorption test, part of shale gas quickly escaped from the core is called the lost gas (Fig. 6c). After field test, the core was brought into lab where it was crushed and tested for content of residual gas. The total gas content is the sum of lost gas, desorbed gas and residual gas contents. The gas-bearing property of shale reservoir is affected by porosity and pore structures^[37]. Porosity mainly affects the gas content, and pore structures mainly affect the desorbing rate or occurrence state. The increase of Q of shale reservoir represents the increase of microfracture development degree, the shrink or even extinction of organic pores, resulting in the development of inorganic pores, the decrease of total porosity and the decrease of total gas content (Fig. 6d). Because the adsorption capacity of organic pores is stronger than inorganic pores and microfractures, the more developed the microfractures and inorganic pores, the easier for the shale gas to escape. Shale gas desorbing from organic pores with small size needs further heating, so that the desorbed gas volume before heating is negatively correlated with Q, and the desorbed gas volume after heating is positively correlated with Q (Fig. 6e, 6f).

This shows that the high-quality pore-fracture configuration makes the reservoir have good sealing property, and is easy to induce abnormal high pressure, which is conducive to the preservation of organic pores, resulting in high total porosity and total gas content. Poor quality of pore-fracture configuration means that the reservoir has a high development degree of microfracture, increased permeability, short-distance migration of shale gas, affecting the development of organic pores and the preservation of shale gas, and reducing the total porosity and total gas content.

Pore-fracture configuration affects pore structure at the microscopic level, controls microscopic gas accumulation, and then affects shale gas enrichment at the macroscopic level. In the long process of shale gas enrichment, pore structure is constantly evolving or changing, and the occurrence state of shale gas is also transformed to reach a new "equilibrium state". An in-depth understanding of the differences of microscopic gas enrichment of different pore-fracture configurations is helpful to guide exploration and development of shale gas.

With the increase of thermal evolution, original organic matter gradually decreases, migrated organic matter gradually increases, some intergranular pores are filled, and cracked organic pores increase, finally forming a large amount of shale gas stored in the microscopic pore-fracture system^[13]. The shale reservoirs with similar thermal evolution degree and burial depth in the study area have significant differences in pore-fracture configuration, indicating that there are differences in the relative equilibrium state among "pore, fracture and gas". During the dynamic migration of shale gas, "liquid hydrocarbon occupation" often takes place, and a large amount of shale gas and bubble-like organic pores are generated after continuous thermal evolution, so the migration of shale gas to inorganic pores is inevitable^[38]. If minerals around organic matter are well sealed and there are no connected channels, the possibility of shale gas stored in inorganic pores is small. If microfractures are connected to organic matter, shale gas will migrate to inorganic pores. Therefore, the development characteristics of inorganic pores need to be considered to analyze the microscopic gas-filled mechanism based on the pore-fracture configuration. From the perspective of organic hydrocarbon generation and microfractures providing migrating channels and reservoir space, three microscopic gas-filled models are summarized, including assemblage of organic pores and fractures, assemblage of organic pores, inorganic pores and fractures, and assemblage of inorganic pores and fractures.

Organic pore-fracture assemblage means that with the thermal evolution process, a large number of pores appear in organic matter, the pressure in the pores increases, natural gas is discharged out of the pores, and hydrocarbon generation pressurized fractures are induced at the margin of minerals. Due to high overlying pressure, good mineral plugging ability, small hydrocarbon generation pressurized fractures, the organic pores are "round and large ", shale gas accumulates nearby in the bubble-like organic pores and hydrocarbon generation pressurized fractures with large size, and they are in a relatively "saturated" equilibrium state as a whole (Fig. 7a). The corresponding pore-fracture configuration is pore-hydrocarbon generation pressurized fracture contact (Fig. 3a). Due to the strong sealing ability of the reservoir, no large-scale pressure relief and with high pore pressure, shale gas can continuously desorb after fracturing, so the stability of formation energy can maintain.

In the assemblage of organic pores, inorganic pores and fractures, a large number of microfractures are induced by continuous increase of overlying pressure, crushed rigid minerals, transformation and contraction of clay minerals and dissolution on the edge of soluble minerals. These microfractures indirectly contact to organic matter (Fig. 3b, 3c) or locally contact directly (Fig. 3d), providing channels for shale gas migration and "pressure relief" from the organic pores close to the microfractures. Organic pores are "smaller and deformed", corresponding to the pore-fracture configuration of pore-inorganic diagenetic fracture separation. Shale gas accumulates in organic pores, inorganic pores and micro-fractures connected with fractures, and the whole system is in a relatively "balanced" state (Fig. 7b). Local pressure relief leads to the shrink and deformation of organic pores, it is more difficult to produce shale gas in organic pores.

The geological conditions of shale reservoir with inorganic pore-fracture assemblage are complex, and a large number of structural micro-fractures (Fig. 3e) or organic matter contraction fractures (Fig. 3f) are developed. The micro-fractures are connected with organic pores, so that the organic pores die out due to pressure release. And the corresponding pore-fracture configuration is structural micro-fracture contact and organic matter edge fracture contact (Fig. 3e, 3f). Shale gas is stored in microfractures and inorganic pores connected with them, and the system is in an "under saturated" state (Fig. 7c). As microfractures increase the reservoir permeability, shale gas migrates in a short distance, which may lead to the transfer of "the gas-enrichment area". After fracturing, the initial production is often high, but declines rapidly. The micro gas-filled model based on the microscopic pore-fracture configuration can directly reflect the pore-fracture pattern and spatial distribution of shale gas reservoir, which is of guiding significance for the exploitation of shale gas.

In order to illustrate the influence of different microscopic gas-filled models on shale gas production, Well Z202 with a large Q value and Well Z203 with a small Q value were selected for comparative analysis. The total fractured volume of the two wells after fracturing operation is similar, indicating that the fracturing effect is equivalent. But the production curves are different due to the differences of microscopic gas-filled models.

The pore-fracture configuration in Well Z202 is of poor quality and belongs to inorganic pore-fracture mode. This well has low development degree of organic pores, low adsorption of organic matter to shale gas, without the shale gas in organic pores, the production curve shows high initial production (19.46×10⁴ m³/d) and rapid decline in the later stage (Fig. 8a). Well Z203 has good pore-fracture configuration and good self-plugging performance, which is in an organic pore-fracture mode. The organic pores in this well are developed and large, shale gas in the organic pores can be desorbed continuously, the supporting formation energy is stable, and the initial test production is low (8.71×10⁴ m³/d), but the stable production time is long (Fig. 8b). Therefore, exploration and development should be strengthened on the gentle syncline for the shale reservoir with a small Q value (organic pore-fracture configuration), and exploration should be strengthened on the "structural high" for the shale reservoir with a large Q value (inorganic pore-fracture configuration).

The space of shale reservoir in the Wufeng Formation- Long 1₁ sub-member in the western Chongqing area is composed of organic pores, inorganic pores and micro- fractures. Organic pores are mainly honeycomb shaped ones in migrating organic matter, and inorganic pores are mainly intragranular pores. There are obvious differences in the development types of microfractures in different wells.

Four types of microscopic pore-fracture configurations are classified according to the development of organic pores and micro-fractures, which are pore-hydrocarbon- generating pressurized fracture contact, pore-inorganic diagenetic fracture separation, structural micro-fracture contact, and organic matter edge fracture contact. Pore- hydrocarbon-generating pressurized fracture contact and pore-inorganic diagenetic fracture separation are dominated by organic matter pores, with microfractures providing a large amount of reservoir space. Structural micro-fracture contact and organic matter edge fracture contact are mainly inorganic pores, and the organic pores become smaller, deformed or even disappear.

According to the difference in NMR T₂ spectra of saturated media with different wettability, a quantitative evaluation parameter (Q) for pore-fracture configuration quality of shale reservoir is established. The Q value of pore-hydrocarbon-generating pressurized fracture contact, pore-clay fracture separation and pore-mineral dissolution fracture separation is less than 40%, indicating good quality; the Q value of pore-compaction fracture separation is 40% to 60%, representing medium quality; the Q value of structural micro-fracture contact and organic matter edge fracture contact is greater than 60%, indicating poor quality. Based on the pore-fracture configuration type, three microscopic gas-filled models are established: organic pore-fracture assemblage, organic pore-inorganic pore-fracture assemblage, and inorganic pore-fracture assemblage, corresponding to pore-fracture configuration quality of good, medium and poor, respectively.

p_f—overlying formation pressure, MPa;

p_o—pore pressure, MPa;

p_w—mineral pressure, MPa;

Q—quality parameter of pore-fracture configuration, %;

T_2max—maximum relaxation time of NMR response, ms;

T_2min—minimum relaxation time of NMR response, ms;

T_2o—NMR response relaxation time of saturated oil, ms;

T_2w—NMR response relaxation time of saturated water, ms;

ϕ_of—porosity of oil wetted micro-fractures, %;

ϕ_op—porosity of oil wetted pores, %;

ϕ_wf—porosity of water wetted micro-fractures, %;

ϕ_wp—porosity of water wetted pores, %.