As a new type of clean energy, shale gas has the characteristics of large reserves and wide distribution and is highly valued by countries around the world^[1,2]. In 2018, the US shale gas production reached 6 669×10⁸ m³, accounting for 63.4% of the total natural gas production^[3], which changed the global natural gas supply pattern. In recent years, China has made important understandings and breakthroughs in the southern marine shale formations^[4,5,6,7]. Exploration and development of shale gas for the Lower Cambrian Niutitang Formation and Lower Silurian Longmaxi Formation was carried out in the Sichuan Basin and its surroundings, and in Changning, Weiyuan, Zhaotong, Fuling, and Wei (Yuan) Rong (counties), shale gas fields were discovered with proven geological reserves exceeding 100 billion cubic meters. In 2019, China's deepest shale gas exploration Well Zu 206 (6,038 m deep) was completed. In addition, Well Lu 203 (137.9×10⁴ m³ per day) became the first well in China with a test daily output exceeding 1 million cubic meters. Well Anye 1 achieved a breakthrough in oil and gas exploration in four different layers. Well Qianziye 1, Well Dongtang 1, Well Liucheng 1, Well Guiliudi 1, Well Eyangye 1, and Well Eyiye 1 have demonstrated better shale gas accumulation conditions and resource prospects in southern China^[8-9] (Fig. 1).

The marine shale gas in South China is facing many problems and challenges while making breakthroughs. For example, the gas content of shales in different regions and different intervals is quite different, and the heterogeneity of shale organic matter content, mineral composition, and other evolutionary conditions are very different, which leads to a huge difference in shale gas generation conditions, reservoir conditions, and preservation conditions. In different shale gas reservoirs, there are differences in the development degree and distribution characteristics of the shale itself, the top and bottom floors, indirect cap rocks, and different structural styles have different controlling effects on shale gas accumulation^[10,11,12]. At present, the geological elements of marine shale gas enrichment in southern China are still unclear. The relationship between shale gas supply, gas storage, gas preservation, structural style, and spatial-temporal matching of reservoir formation is unclear, and research on the mechanism of shale gas reservoir formation is urgently needed.

This article takes the Sichuan Basin and its surroundings, a set of Paleozoic shale formations, as research objects and conducts qualitative and quantitative characterization and evaluation of key geological elements of shale gas enrichment to determine the key control factors for differential enrichment of shale gas and to clarify the spatial-temporal matching relationship and accumulation effects of key accumulation factors in gas supply, gas storage, preservation, and structure, etc. The establishment of shale gas accumulation models at different structural locations provides theoretical guidance and technical support for marine shale gas exploration and development in southern China.

The abundance of organic matter in shale is one of the important factors affecting the gas bearing property of shale^[13,14,15]. There is a good positive correlation between the total gas content and total organic matter content in the Paleozoic Marine shale, South China, which indicates that the organic matter plays a significant role in controlling the shale gas content (Fig. 2). Taking the lower Silurian Longmaxi Formation as an example, when the organic matter abundance increased by 1.0%, the total gas content increased by about 1.2 m³/t. When the shale total organic carbon (TOC) content is higher than 2.0%, the gas content can reach a level of higher than 2.0 m³/t. When the shale TOC value is higher than 3.0%, the gas content is generally higher than 4.0 m³/t. Due to the earlier formation of gas reservoirs, high thermal maturity, and poor preservation conditions, gas content is generally not high in Niutitang Formation shale^[16], Lower Cambrian, but total gas content and organic carbon content are positively correlated overall. The controlling effect of organic matter abundance on gas content in the Longmaxi Formation is stronger than that in the Niutitang Formation (Fig. 2). High organic matter abundance is the basic premise of shale gas enrichment.

As the marine shale in South China is generally at the high or over mature stage, it is difficult to select shale samples with low maturity. Thermal simulation experiments with hydrocarbon generation and expulsion processes were carried out on the low-mature marine shale of the Mesoproterozoic Xiamaling Formation in north China under actual formation temperature and pressure conditions to study the hydrocarbon generation evolution process of marine shale in South China. By simulating the hydrocarbon generation process, the influence of thermal maturity on differential enrichment of shale gas was studied.

The selected Xiamaling samples were comparable with the Wufeng-Longmaxi marine shale in the Sichuan Basin in terms of organic matter type and mineral composition (Table 1). The observed thermal evolution process can be used as a reference for hydrocarbon generation evolution of the Wufeng-Longmaxi shale.

The experimental results showed that the changes of liquid and gaseous hydrocarbons produced by unit organic carbon content have the following characteristics (Fig. 3). (1) Mature stage (R_o<1.6%): kerogen mainly produced liquid hydrocarbons, and the peak of hydrocarbon generation was 1.0% - 1.3%, with a maximum oil discharging productive rate of over 90 kg/t. At this stage, the gas supply of kerogen was not large, and the output of gaseous hydrocarbon was mostly less than 60 kg/t. (2) High to over-mature stage (R_o>1.6%): The variation of different curves varies greatly. The total oil production rate and residual oil production rate decreased, gaseous hydrocarbon began to increase rapidly, and liquid hydrocarbon began to produce crack gas. When R_o was higher than 2.5%, the volume of kerogen pyrolysis gas decreased continuously, and the cumulative contribution of kerogen pyrolysis to the total gas content also gradually decreased. The residual hydrocarbon continued to generate a large amount of gas and continued until R_o reached 4.0%. When R_o was higher than 2.9%, the mass yield of gaseous hydrocarbon decreased, but the volume yield remained unchanged, indicating that the heavy hydrocarbon gas was cracked into light hydrocarbon gas such as methane.

Hydrocarbon generation products in shale reservoirs mainly go through the following evolution stages: biogas - immature oil and transition zone gas - mature crude oil and associated gas - kerogen pyrolysis gas - crude oil pyrolysis gas - heavy gaseous hydrocarbon pyrolysis gas - methane pyrolysis gas. A marine shale gas model was established according to hydrocarbon generation products in different evolutionary stages (Fig. 4). There were several key time points with the change of the gas parent material. When R_o value was less than 1.6%, it was the kerogen that provided gas supply, and the kerogen cracking gas was the main gas source. After R_o reached over 1.6%, the kerogen gas gradually reduced, and the cracking of liquid hydrocarbons and bitumen remaining in shale became the main supply of the gas source, which continued until R_o was equal to 4.0%, widening the effective maturity threshold (lower limit of maturity) of shale gas generation. The pyrolysis of kerogen, liquid hydrocarbon, and asphalt ensure the high efficiency of gas generation in highly over- mature marine shale.

The pore types of shale are diverse, and the matrixes such as organic matter, brittle minerals, and clay minerals all have pore development, among which the organic pores are mainly developed in the organic-rich siliceous shale and organic-rich mixed shale facies^[17,18]. Due to the high maturity of marine organic-rich shale in South China (the dry gas stage), most of the sapropelic components are decomposed by thermal decomposition. The main components of organic matter are the transport asphalt and the residual kerogen, and the occurrence morphology and pore development characteristics of the two are quite different. The migration asphalt has no specific morphology. It is filled between mineral particles and cracks, and it is mostly in contact with secondary cements, such as in strawberry-like pyrite crystal clusters, secondary mineral particle gaps, and clay mineral plates. The pores of the transported asphalt are relatively developed, in the form of ellipses, circles, gneiss or irregular polygons. The pore diameter is usually 5 to 200 nm, and it shows strong heterogeneity (Fig. 5a-c). The shape of residual kerogen is relatively fixed. Some are affected by compaction, and the cross sections are mostly ellipsoidal or semi-ellipsoidal. Some kerogen retains its original pore shape. This type of organic matter is larger in size but with less pore development (Fig. 5d). The organic matter (kerogen and asphalt) pores of the Longmaxi Formation shale are continuously and densely distributed in a honeycomb shape. In the process of organic pore formation, it has the advantage of in situ adsorption of methane and storage of free methane and has a positive effect on both free gas and adsorption gas storage.

Primary intergranular pores are the residual pores after mechanical compaction and chemical diagenesis, and they are mainly composed of brittle minerals such as quartz, calcite, and pyrite (Fig. 5e-h). They mainly store free shale gas. Most of the compacted residual pores in the Longmaxi Formation are slit-shaped, wedge-shaped, or cylindrical, with pore diameters ranging from nanometers to microns. Clay mineral pores are formed by the undirected accumulation of lamellar clay minerals (like the structure of a house of cards). Or the regeneration pores formed by the combination of clay minerals and rigid mineral frameworks are mainly developed in clay minerals such as illite smectite mixed layer, illite and chlorite. Clay mineral pores are mostly interstitial pores of mineral crystals, mostly in the shape of slits or wedges, with a large number and a wide range of pore diameters (30 to 600 nm). The plates are not stacked or composited with particles, and they are in the shape of slots or triangles. Clay mineral pores often have adsorbed or free water, which is not conducive to methane storage. Brittle mineral pores mainly store free gas.

Shale gas usually occurs in mesopores, macropores, and fractures in a free state^[19,20,21], so the amount of free gas is mainly related to the pore volume. The pore volumes of the organic-rich siliceous shale in the main producing layer at the bottom of Longmaxi Formation shales are mainly provided by mesopores, and the pore volumes of micropores, mesopores, and macropores account for 9.97%, 55.91%, and 34.12%, respectively (Fig. 6a). The adsorption gas is adsorbed on the surface of micropores and mesopores of organic matter and clay minerals, so the adsorption gas amount is mainly related to the specific surface area^[22,23]. The pore specific surface area of organic-rich siliceous shale in the main producing layer at the bottom of the Longmaxi Formation was mainly provided by micropores and mesopores. The specific surface area of micropores, mesopores, and macropores accounted for 48.86%, 50.19%, and 0.91%, respectively (Fig. 6b). Compared with the organic-poor shales, the organic-rich shales have higher pore volume and specific surface area, showing superior free gas and adsorption gas storage capacity.

For the organic-matter-rich shale samples with similar organic matter content and different maturity obtained from the thermal simulation experiment above, the evolution of shale micropores (pore diameter less than 2 nm), mesopores (pore diameter ranges from 2 to 50 nm) and macropores (pore diameter ranges from 50 to 100 nm) was studied by the CO₂ adsorption method and the N₂ adsorption method. With the increase of thermal evolution degree, the pore volume of mesopores changed greatly, and the specific surface area of micropores changed greatly, while the pore volume and specific surface area of macropores changed little (Fig. 7). When the R_o value was greater than 1.0%, the specific surface area of micropores and mesopores increased with the increase of R_o. When the R_o value was 2.23% - 3.33%, the specific surface area of micropores increased significantly, which was more conducive to shale gas adsorption (Fig. 7a). When the R_o value was less than 1.6%, the pore volume increased with the increase of R_o. When the R_o value was 1.6% - 2.2%, the pore volume tended to decrease, which may be due to the large amount of hydrocarbon generation at this stage, and the hydrocarbon takes up the pore space, resulting in the pore volume decreasing. When the R_o value was greater than 2.2%, the volume of mesopores and micropores increased continuously, mainly due to the secondary cracking of liquid hydrocarbons into gaseous hydrocarbons, which releases part of the pore space (Fig. 7b).

For the over-mature shale, when the R_o value was greater than 3.33%, the pore development degree and pore connectivity were poor, the specific surface area tended to decline in the over-mature stage, and the adsorption amount of shale gas kept decreasing, which was not conducive to the enrichment of shale gas. For the highly mature shale, with the increase of the degree of thermal evolution, the organic pores continued to develop, and the pore volume and specific surface area of the micropores and mesopores all increased significantly, which provided a good storage space and was conducive to the enrichment of shale gas.

The wettability of matrix components (organic matter and mineral) of marine organic shale in South China is significantly different, resulting in the complex wettability of shale, which is generally characterized by mixed wettability. Minerals have a water contact angle of less than 90° and are hydrophilic. Quartz has the largest water contact angle among minerals and the weakest hydrophilicity. Kaolinite has the smallest contact angle with water among minerals and is the most hydrophilic. Previous studies have shown that the oil wetting angle of organic matter is less than 90°, which is a lipophilic component^[24,25,26]. In the organic-rich shale of the Longmaxi Formation, with the increase of organic matter content, the wettability of shale gradually changes from weak lipophilicity to lipophilic, and the oil wetting angle kept decreasing. The development of organic pores and organic-clay intergranular pores enhances the overall lipophilicity of the shale, and minerals such as quartz and clay develop inorganic pores, resulting in enhanced shale hydrophilicity.

Oil-wet organic pores can adsorb shale gas more easily. Fully oil-wet organic pores can obtain the maximum shale gas adsorption. The large organic pores in shale are more conducive to the occurrence of free gas. In water-wetted inorganic pores, the adsorption of pores on water is significantly higher than the adsorption of shale gas. There is only free gas in the pores. At the same time, pore water occupies pore space and free gas storage space. The higher the water saturation of shale, the weaker the ability of hydrophilic pores to adsorb shale gas, the smaller the space for free gas, and the worse the overall gas-bearing property.

The physical properties of the roof and floor are very important for shale gas preservation. Roofs and floors of shale gas with good sealing conditions can effectively slow down shale gas diffusion and dissipation^[27,28], resulting in effective shale gas preservation. The roof and floor with good isolation performance in the Jiaoshiba shale gas field in the Southeastern Sichuan Basin is a good example^[28]. For shale sections with poor roof and floor conditions, natural gas is easy to be dissi-pated outwards, which is extremely disadvantageous to shale gas enrichment and accumulation. For example, the floor of the lower Cambrian Niutitang shale in the Southeastern Sichuan Basin is an ancient crust of the Sinian Dengying Formation, with relatively developed palaeo-karsts and fractures, which lead to shale gas escape along the unconformity surface and result in low gas content^[29]. The characteristics of roofs and floors have a direct impact on shale gas content and shale gas enrichment and accumulation^[30,31]. The statistical results of shale roof and floor thickness of the Longmaxi Formation in South China show that the larger the thickness of roof and floor, the better the gas content of shale (Fig. 8).

As an indirect or regional cap, the tight rocks such as mud shale and gypsum-salt rocks above the roof can maintain the structural stability and pressure system of the lower underlying layer, which has an important impact on the preservation of shale gas^{[30, 32-34]}. The gypsum-salt rock of the Jialingjiang Formation is an important regional cap for Longmaxi shales. The pressure coefficient of the Fushun-Yongchuan area with relatively complete gypsum-salt layer preservation was 2.2, which had high yield gas flow. The pressure coefficient in the Changning area where part of the gypsum-salt layer was preserved was 2.0 and also had high-yielding flows, while the gas reservoir in the Dingshan area where the gypsum-salt layer missed had normal pressure, and basically no gas existed. Therefore, regional cap development is also an important factor affecting shale gas differential enrichment.

Tectonic movement plays an important role in controlling the accumulation and destruction of shale gas reservoirs, especially the time, amplitude, and scale of the last tectonic movement, which have a great influence on the differential enrichment of shale gas. Marine shale in South China is generally at the high or over-mature stage. Gas from liquid hydrocarbon and bitumen cracking is the main source^[16]. The negative influence on shale gas enrichment and accumulation for the last early tectonic uplift is mainly manifested in two aspects: (1) an early stop to hydrocarbon generation, especially for the termination time of cracking to gas, which is relatively early, resulting in lower efficiency of gas generation and shale gas resource supplement; (2) the uplift of the formation results in a certain degree of damage to the preservation conditions, resulting in the loss of shale gas. The earlier the uplift, the longer the loss time and the lower the gas content (Fig. 9).

The amplitude of tectonic uplift also greatly affects shale gas accumulation and enrichment. The greater the uplift amplitude, the greater the thickness of formation denudation, the more serious the destruction of preservation conditions, and the lower the shale gas content (Fig. 9). The target formation section is usually outcropped in areas with severe overburden denudation and generally has a low gas content. For example, the uplifting amplitude in the Qianjiang area is more than 5 km, and the gas content is only 0.9 m³/t.

Shale usually develops horizontal lamelliform bedding, resulting in the permeability of the shale parallel to the bedding being 2-8 times as the permeability perpendicular to the bedding^[28]. In the spontaneous percolation experiment, the slope of the self-absorption parallel to the bedding direction was greater than that of the vertical bedding direction, indicating that the pore connectivity parallel to the bedding direction was much larger than the vertical bedding direction (Fig. 10) and that natural gas in the shale mainly migrates along the bedding plane. The migration of natural gas in shale also follows the principle of conservation of energy. It moves from high fluid potential to low fluid potential and accumulates at low fluid potential^[35,36,37]. In general, the fluid potential of the lower part of the structure is higher than that of the higher part of the structure, so natural gas migrates from the lower part to the higher part. There are no high-potential areas and low-potential areas when the formation is horizontal, so there is no obvious seepage of shale gas in the horizontal formation, and shale gas migrates along the bedding plane from the lower part to the higher part of the structure when the formation is inclined.

In order to quantify the controlling effect of formation burial depth on gas enrichment, a numerical simulation study of gas migration was conducted using the Longmaxi Formation shale in the Weiyuan area as a research object. In the geological environment, the gas content distribution can be described using Fick's second law when the vertical gas loss is relatively small:

The natural gas seepage migration amount can be calculated by the classic Darcy's law:

For different structural styles, the differential enrichment of shale gas can be divided into two cases (Fig. 11):

In the first case, the vertical loss of natural gas in different structural parts is roughly the same, but the positive structure has additional gas migration from the negative structure along the bedding plane when the positive structural parts (Point C in Fig. 11a) and negative structural parts (Point A in Fig. 11a) are not adjacent but at the same depth. Thus, the gas content of the positive structural part is always higher than that of the negative structural part (Fig. 11b). For example, the average buried depth of Well N203 in the Changning area and Well W202 in the Weiyuan area is about 2500 m, and the properties of the overburden are similar. Well W202 always has the low structural parts’ gas supply, and the average gas content is 3.1 m³/t. The lateral loss increases greatly because Well N203 has open faults in the direction of the consequent layer, and the average gas content is 1.9 m³/t^[6].

In the second case, the positive structural parts (Point C in Fig. 11a) and negative structural parts (Point A in Fig. 11a) are adjacent but at the different depth. There are four continuous evolution patterns (Fig. 11c): (1) There is not much difference in gas bearing properties between positive and negative structures when the formation uplifting amplitude is small. (2) The gas bearing properties of the positive structure is much better than that of the negative structure when the formation is uplifted and the burial depth from the surface is greater than 2,000 m. This is the case for the Longmaxi Formation shale gas in Jiaoshiba area. (3) The positive structure reached the critical depth of shale fracture, and the shale gas was relatively concentrated in the lower part of the structure when the formation uplift intensity continued to increase and was greater than about 4 700 m. This is the case for the Longmaxi Formation shale gas in Weiyuan area. The average gas content of Well W202 in the deeper part is 3.1 m³/t, while the average gas content of Well W201 in the shallow part is 2.8 m³/t. (4) If it continues to rise, both the positive structure and the negative structure have poor gas bearing properties. This is the case for shale gas from the Longmaxi Formation in Southeast Chongqing. The shale emerges from the surface, and the gas reservoir has been destroyed completely. Wells near the surface, such as Well Yuye1 and Well Qian1, have poor gas bearing properties.

The dip angle of the formation directly controls the normal stress on the bedding plane. The greater the dip angle of the stratum, the smaller the pressure on the direction of the vertical bedding plane of the stratum and the greater the amount of consequent landslide recharge that can be accepted by the positive structure. The maximum seepage rate at a formation inclination of 30° is about 6 times as much as that of a formation of 5° (Fig. 12a). Therefore, on the premise that the vertical loss of the positive structure is unchanged, the larger the inclination angle, the richer the gas content in the high part of the positive structure.

The coupling of formation dip and burial depth further controls the relative enrichment of shale gas in the positive structure. Regardless of whether it is a positive or negative structural part, the difference in the gas content change rate is first increased then decreased and first positive then negative. The greater the dip angle of the formation, the larger the range of the difference between the positive and negative structure gas content and the smaller the magnitude of formation uplift when the amplitude difference is maximum (Fig. 12b).

The key to shale gas enrichment is the optimum matching of hydrocarbon generation; reservoir development; and roof, floor, and cap formation. Marine shale in South China has basically experienced the processes of deep burial, hydrocarbon generation, and late tectonic uplift in geological history, so the shorter the end period of the optimal matching period is, the more favorable it is for shale gas enrichment. The following uses Well Jiaoye 1 in Jiaoshiba area and Well Yucan 6 in southeast Chongqing as an example to study the differences in reservoir formation matching.

The shale of the Longmaxi Formation in Well Jiaoye 1 was in the sedimentation and compaction stage before the end of the Permian period. Since the burial depth was always shallow and the organic matter was in the immature stage, the porosity of the shale with inorganic pores as the main storage space decreased to 9.1% with the increase of burial depth. When the R_o value reaches 0.5%-0.7%, it enters the initial hydrocarbon generation stage. At the beginning of the early Triassic period, the Longmaxi Formation was in the stage of tectonic subsidence, diagenesis continued to strengthen, and the porosity provided by inorganic pores continued to decrease. At this time, a large amount of organic matter began to generate hydrocarbons, which made the organic pores form, and the porosity provided by organic pores gradually increased to 1.9%. By the end of the middle Triassic period, the R_o value reached 0.7%-1.3%, and the Longmaxi Formation entered the peak of liquid hydrocarbon generation. In the late Jurassic period, the Longmaxi Formation was buried rapidly, with the R_o value reaching 1.3%-2.0%. The organic matter entered the high maturity stage, generating a large amount of wet gas and oil cracking gas. In the early cretaceous period, the R_o value exceeded 2.0%, the organic matter entered the over-mature stage, and the liquid hydrocarbon cracked into dry gas. As a result of the large amount of hydrocarbon gas, organic pores began to form in large quantities. Under the action of hydrocarbon-forming supercharging, the formation pressure also increased significantly, resulting in the extrusion and expansion of secondary pores in shale. At this time, the porosity of organic pores was about 4.0%. After the late cretaceous period, the Jiaoshiba area was in the tectonic uplift stage, and the shale of the Longmaxi Formation in Well Jiaoye 1 was uplifted from a burial depth of about 6500 m to the current level of 2420 m, and the gas reservoir underwent adjustment and transformation. During the late tectonic uplift, the generation of organic hydrocarbons and the development of organic pores was basically stopped, and tectonic activity causes faults and fractures development and related fluid activity.

Shale of Well Jiaoye 1 has high organic matter content, and it has experienced early kerogen gas generation and late crude oil cracking, which supplement the gas source. At present, the total porosity of the reservoir is about 7.0%, of which organic pores are more developed and the porosity is about 3.5%. The floor of the Longmaxi Formation is nodular limestone of the Linxiang Formation, and the top is silty mudstone. The roof and floor are compact in lithology and good in condition. The strata began to lift at the end of the Cretaceous period, and so far they have lifted about 4 000 m. This area has the characteristics of late lifting time and moderate lifting range. The regional Triassic cap rock developed well, with short destruction time and low damage degree. Therefore, the Longmaxi Formation shale gas reservoir in Jiaosha 1 well has high source-reservoir-preservation matching efficiency. The shale gas accumulation duration is long, and the enrichment is high (Fig. 13).

Before the end of the Permian period, the shale of the Longmaxi Formation in Well Yucan 6 was in the stage of sedimentation and compaction, and the burial depth was always shallow. However, hydrothermal activities were frequent in southeastern Chongqing during the sedimentary period, and the degree of shale thermal evolution was greatly accelerated. At the end of the Silurian period, the organic matter reached the hydrocarbon generation threshold, and the organic pores began to form. In the Carboniferous period, the tectonic activity in the southeast of Chongqing was stable, the strata were in the shallow burial stage for a long time, and the diagenesis was stable. The decrease of inorganic pores’ porosity caused by compaction is not obvious. The R_o value of organic matter has increased rapidly to 1.0%, and the porosity provided by organic matter gradually increases when the Longmaxi Formation enters the peak period of liquid hydrocarbon generation. In the early Triassic period, the porosity of organic matter was about 2.3%, and the total porosity was about 11.5%. The Longmaxi Formation was also buried rapidly, with the R_o value reaching 2.0%. It entered the over-mature stage, and the liquid hydrocarbon cracked into dry gas. From the Late Jurassic to Early Cretaceous period, the southeastern Chongqing region entered the tectonic uplift stage. The shale was greatly raised from a buried depth of 8 500 m to the present buried depth of 610 m. The preservation conditions of gas reservoirs were severely damaged. During the late tectonic uplifting process, organic hydrocarbon generation and the development of organic pores also basically stopped, and tectonic activity also caused faults, fractures, and related fluid activities.

The content of organic matter in Well Yucan 6 is relatively low, the TOC value is 0.16% - 4.79%, and the number of samples with the TOC value higher than 2.0% only accounts for 13.16% of the total number of samples. The hydrocarbon generation time is early, the crude oil cracking gas time is short, and the effective porosity is low (the highest is 1.32% and the lowest is less than 0.1%). From the middle Jurassic to the early cretaceous period, the source rock was closed in terms of physical properties, the strata uplifted early and with a large uplifting range, the cap rock was damaged, the source-reservoir-preservation matching effectiveness was low, the shale gas enrichment period ended early, and the gas content was only 0.07 m³/t (Fig. 14).

High organic matter abundance and suitable thermal evolution are favorable for shale gas production. The controlling effect of shale organic matter on gas bearing in the Longmaxi Formation is stronger than that in the Niutitang Formation. The matching of the two processes of kerogen pyrolysis gas and liquid hydrocarbon pyrolysis gas provides a guarantee for marine shale gas production capacity and broadens the lower limit of gas production.

The shale matrix composition and the degree of thermal evolution also control the development of shale pores. In the process of organic pore formation, it has the advantage of in situ adsorption of methane, and a large organic pore can store a large amount of free gas. When the R_o value is 2.23% - 3.33%, the shale reservoir capacity is the strongest, and shale gas is easier to be enriched in oil-wetted matrix pores.

Good roof and floor conditions and the development of tight caprocks are conducive to shale gas enrichment. The thicker the roof and floor, the higher the shale gas content. The regional caprock can maintain structural morphological stability and pressure system of the underlying formation and has an important impact on the preservation of shale gas. The late tectonic uplift time and the small uplift rate are favorable for shale gas enrichment.

The controlling effect of formation burial depth on shale gas enrichment under different structural styles is relatively complicated. For positive and negative structures that are not adjacent at the same depth, the gas-bearing potential of positive structures is always greater than that of negative structures. For the adjacent positive and negative structures with different depths, gas is preferentially enriched in the high part of the positive structure, and when the local layer is uplifted above the shear fracture depth of shale, gas is relatively enriched in the lower part of the negative structure.

The abundance and thermal evolution of organic matter determine the effective gas content of shale. The development of a large number of organic pores, the early formation of organic pores supported by bio-silicon, and the development of micro-fractures all determine the better storage capacity. The closer the main gas generation period is to this time, the more favorable it is for shale gas enrichment. The effectiveness of the matching of the source, reservoir, and preservation factors controls the shale gas accumulation and the degree of accumulation.

K_H—shale bedding permeability at depth H, μm²;

L—migration distance, m;

P—pore pressure, Pa;

q—migration amount, m³/s;

Q—gas content, m³/t;

S—migration cross-sectional area, m²;

t—migration time, s;

μ—gas viscosity, Pa·s.