Organic matter pores (organic pores for short) refer to the nano-scale pore throat system in the organic matter of fine-grained sedimentary rock, and they make up a large proportion of the total pores in fine-grained sedimentary rock. Some studies on shale gas exploration^[1,2,3,4] have confirmed that organic pore is a major pore type in marine shale gas reservoirs in North America and southern China, and a key element for shale gas enrichment. As the shale gas exploration in southern China expands from the middle-shallow layers of the Ordovician Wufeng Formation-Silurian Longmaxi Formation to new areas like the deep layers of the Ordovician Wufeng Formation-Silurian Longmaxi Formation, Cambrian, Carboniferous-Devonian and continental-marine transitional facies^{[3, 5]}, it is found that the organic-rich shales in different areas or horizons vary greatly in gas-bearing capacity. A root cause behind this is the differences in the development degree of shale reservoirs and organic pores^[5,6]. It is recognized that the development of organic pore is not a simple function of the abundance, type and maturity of organic matter, but also affected by several factors such as inorganic minerals and pore pressure^[7,8], in other words, organic pores have gone through complex formation and evolution process and show strong heterogeneity. Therefore, it is necessary to figure out how these factors interact in the processes of diagenesis, hydrocarbon generation and expulsion, and later structural reformation, and how they affect the development of organic pores, so that the essence of the formation and preservation of organic pores can be clarified to provide more scientific basis for shale gas reservoir evaluation and sweet spot prediction.

In this study, organic-rich shale samples from some exploratory wells of marine shale gas in the Sichuan Basin and its periphery were analyzed for macerals, pores, diagenesis and pore connectivity by field emission scanning electron microscopy (FESEM) + energy dispersive spectroscopy (EDS), laser microscopic confocal Raman spectroscopy (Raman), and fluid injection + CT/FESEM imaging. Combined with the studies on hydrocarbon generation and expulsion mechanisms and pore-forming mechanism of organic matter-based activated carbon, the relationship between the development of organic pores and the organic matter type, hydrocarbon generation process, diagenesis and pore pressure was examined to reveal the microscopic mechanism by which organic pores are formed, preserved and connected in the geological evolution process of source rocks to create effective storage space.

The organic-rich shale in the Ordovician Wufeng Formation (O₃w)-Silurian Longmaxi Formation (S₁l), mainly in the Upper Ordovician Wufeng Formation to the first member of Lower Silurian Longmaxi Formation (Long 1 Member, or S₁l₁), can be divided into nine layers (①-⑨), with TOC>2.0% and thickness of 80-120 m (Fig. 1). Layers ①-⑤ are high-quality shale intervals dominated by siliceous shale, with TOC>3.0% and thickness of 20-40 m.

They are distributed along the Weiyuan (Well WY1)- Changning (Well N201) and Dingshan (Well DY2)-Wulong (Well LY1)-Fuling (Well JY1) areas, where such shale gas fields as Fuling, Weirong, and Weiyuan-Changning have been discovered, and exploration breakthroughs have been made in the Dingshan-Dongxi structure (Well DY2) and the Wulong syncline (Well LY1)^{[5, 9]}.

The Lower Cambrian organic-rich shale is found in the Middle-Upper Yangtze region, mainly distributed around the Central Sichuan Paleo-uplift^[10]. Specifically, the Cambrian Qiongzhusi Formation (Є₁q) shale is distributed along the Mianyang-Changning area (typically Well JinY1), which is mainly argillaceous shale, with TOC of 0.4%-3.4% and a 14 m industrial gas shale interval^[3]. The Cambrian Niutitang Formation (Є₁n) shale is distributed in the southern Guizhou-western Hubei and eastern Chongqing area (typically Wells HY1 and EY1), which is mainly siliceous and carbonaceous shale, with TOC of 2.2%-9.5%. In Well HY1, the shale with TOC >4% is 90 m thick.

The samples in this study were collected from exploratory wells of marine shale gas, including WY1, JY1, YZ1, JinY1, HY1, and EY1. They were analyzed for macerals, pore structure, minerals and pore connectivity, etc., with details shown in references [6, 11].

Macerals and hydrocarbon-generating organisms were identified by FESEM + EDS, and maturity was analyzed by Raman. Organic pore structure was investigated by focused ion beam scanning electron microscopy (FIB- SEM) and other imaging techniques. Physical properties were measured by pulse permeability and mercury intrusion-adsorption methods jointly. Pore connectivity was analyzed by sodium chloroaurate injection method and high-pressure alloy injection method together with CT/FESEM imaging technology. Diagenetic parameters (e.g. mineral composition, crystal structure and illite crystallinity) were determined through X-ray diffraction and FESEM+EDS micro-area analysis.

2.1.1. Formation and preservation of organic pores

Kerogen is a high-molecular polymer composed of condensed cyclic aromatic nuclei linked by heteroatomic bonds or aliphatic chains. In the burial, diagenesis and thermal evolution process of source rock, the core of kerogen evolution is the rearrangement of aromatic nuclei - the turbostratic structure is orderly transformed to graphite crystal structure by virtue of condensation reaction, and multiple aromatic nuclei may condensate to form a larger polymer. In the rearrangement process, the steric hindrance of aliphatic chains and heteroatomic bonds caused by intermolecular interactions reduces the heat of polymerization and inhibits the condensation of aromatic nuclei. Through decarboxylation, dealkylation and other hydrocarbon generation processes, aliphatic chains and heteroatomic bonds can be removed to eliminate the condensation hindrance^[12]. (1) The break of aliphatic chain bridges and heterocyclic functional groups releases fragments of different sizes (bitumen with different relative molecular mass, volatile matter, etc.), and the void generated is the space formed by pores. (2) When falling off but not leaving the parent, the fragments continue to produce steric hindrance, inhibiting the condensation reaction, so the original storage space can be maintained in the disorderly arrangement. When fragments are discharged, the condensation reaction intensifies, leading to reduction of pores due to the rearrangement and condensation of surrounding aromatic nuclei. (3) The formation and evolution of pores run through the entire hydrocarbon generation process, it begins in the hydrocarbon generation and expulsion period of source rock and terminates after the source rock reaches the maximum burial depth and starts to uplift, when organic matter is no longer aromatized and pores decrease or disappear. Clearly, the nature of the formation and preservation of organic pores in the geological evolution process is the generation and in-situ retention of hydrocarbons. The pore pressure caused by retained hydrocarbons is the essence of the suppression of organic matter hydrocarbon generation and thermal maturation under overpressure conditions.

2.1.2. Pores in different types of organic matter

The components of aromatic, aliphatic and heterocyclic functional groups in different proportions decide the types of organic matter, which include the sapropelic organic matter rich in hydrogen-rich aliphatic structure (Type I-II) and the humic organic matter rich in hydrogen-lean aromatic structure (Type III). In the process of hydrocarbon generation, the hydrogen-rich components (especially the lipid components) in the organic matter release a large amount of bitumen or petroleum fragments, making pores develop in the kerogen and also making bitumen crack to produce solid bitumen with abundant pores. The hydrogen-lean organic matter, especially humic organic matter, has a low oil-generating potential, and mainly generates pores locally in the process of gas generation by its hydrogen-rich part, with no solid bitumen rich in pores. As shown in Figs. 2 and 3a-3d, the sapropelic organic matter rich in hydrogen-rich aliphatic structure, such as planktonic algae and acritarch, have widespread pores. Moreover, the components and structures are different for different organic matter or at different parts of the same organic matter, so the development degree and distribution of pores are uneven, which leads to a strong heterogeneity of pore development in organic matter. Studies on the composition and structure, and hydrocarbon generation capacity of graptolites with different thermal maturities and the pore development characteristics of high-mature graptolites (Table 1, Fig. 3e-3g) show that graptolites are carbon-rich and hydrogen-lean humic organic matter composed of aromatic rings, and have hydrocarbon generation capacity equivalent to Type III kerogen or vitrinite, without organic pores. Foreign researchers^{[1, 13]} found through study of North American shale gas reservoirs that Type I and II kerogens are richer in hydrogen and lipid components than Type Ⅲ kerogen, and algae is richer in hydrogen and lipid components than vitrinite, so Type I and II kerogens and algae contain more organic pores. In contrast, some hydrogen-lean macerals do not experience the process of hydrocarbon generation from pyrolysis and thus have no pores generated. Evidently, the type of organic matter is the basic condition for the formation of a large number of organic pores. The differences in composition, structure and hydrocarbon generation process of organic matter are the internal factors controlling the development degree and heterogeneity of organic pore. It is clear that organic pores mainly occur in sapropelic kerogen and solid bitumen, while humic organic matter has limited pores developed.

2.1.3. Differential formation of pores in kerogen and bitumen

As shown in Figs. 2 and 3, the pores in kerogen are highly heterogeneous and uneven in distribution, with irregular angular shapes and relatively uniform size, while the pores in bitumen are relatively uniform in distribution, appear in sponge or honeycomb form, and are composite circular or elliptical pores. This is mainly caused by the different hydrocarbon generation components and differential hydrocarbon generation evolution of the two.

Kerogen is a dispersive organic matter insoluble in organic solvents. During the pore formation in hydrocarbon generation process, kerogen is always in a solid state, and the different structures and components at different parts, together with the different intensities of decomposition or poly-condensation reaction, lead to the heterogeneity of pore development in the same organic matter particle (Figs. 2a, 2b and 3). The hydrogen-rich components mainly decompose in the solid-liquid phase reaction system to generate liquid hydrocarbons in the oil generation period, while aliphatic and heterocyclic functional groups gradually fall off and escape in the form of hydrocarbons and volatiles to produce pores. In the wet gas generation stage (R_o≥1.3%), the condensation reaction starts to strengthen, accompanied by decomposition in the solid-liquid-gas phase reaction system to generate hydrocarbon gas and pores. When the source rock reaches the maximum burial depth (larger than 5000 m), the dry gas generation stage (R_o≥2.0%) starts. In the solid-gas reaction system, the aromatic nuclei condense to form more nanoparticles and rearrange to produce polygon "intergranular" pores with relatively uniform size and mostly angular shape (Fig. 4). The pores can be effectively preserved due to the steric hindrance effect of retained hydrocarbons and the disorder arrangement of nanoparticles. In the condition of high thermal maturity, hydrocarbons are discharged, while kerogen, aromatized and polycondensed strongly, is more orderly and compact in structure. With pores decreased, the kerogen tends to become graphite crystals. Therefore, the development degree of pores in kerogen depends on the comprehensive effect of the nature of organic matter, the efficiency of hydrocarbon expulsion and the degree of condensation.

Solid bitumen is derived from bitumen rich in heteroatomic bonds and soluble in organic solvents. It is mainly composed of colloids and asphaltene dissolved in liquid hydrocarbon. During the continuous burial of source rock, the retained oil begins to crack when the ground temperature exceeds the critical temperature (150 °C) for the existence of liquid hydrocarbons. In this process, liquid hydrocarbons convert into gaseous hydrocarbons through the rupture of C-C bonds. The gas generation process simultaneously occurs on the surface and inside of crude oil, indicating a "boiling" process. When the generation rate is greater than the escape rate of natural gas, a part of the retained gas (bubbles) would form vesicles in the matrix, mostly in circle or ellipse shape. As shown in Fig. 2c-2d, due to the relatively uniform composition and structure of liquid hydrocarbons, the generated pore at this time are relatively uniform in density and morphology, and multiple adjacent small pores in the densely populated area may combine to form circular or elliptical larger pores, resulting in the pattern of "small pores in large pores and connection between pores". Experiments on the pore formation mechanism of petroleum coke by pyrolysis have confirmed that pyrolysis occurs simultaneously inside and outside the spatial framework structure of petroleum coke^[14]. In the initial stage of pyrolysis, the “open pore” effect by the release of volatiles and pyrolysis of solid organic matter increases the specific area of the part participating in the chemical reaction, therefore the pyrolysis rate of petroleum coke is increased to promote the generation of more abundant pores. In the dry gas generation stage (R_o≥2.0%), the hydrocarbons in the liquid hydrocarbons are exhausted, and the colloid and asphaltene components further decompose-condense-consolidate or "precipitate" to form a solid product-solid bitumen of porous structure. Fig. 5 shows the surface morphology of bitumen filling in conventional oil and gas reservoir. Such bitumen has no pores. Essentially, solid bitumen is produced by high-temperature cracking of crude oil under open conditions; in the process, in-situ escape rate of gas is higher than the generation rate of gas, resulting in condensation and densification of the bitumen. It can be seen that the decomposition and condensation reaction in the hydrocarbon generation process have different effects on the formation and evolution of organic pores. When decomposition predominates, the higher the temperature, the more hydrogen-rich the component, the more intense the reaction, the greater the decomposition rate, the more bubbles, and the more developed the pores will be. When polycondensation predominates, the more intense the reaction, the more intense the densification will be. As a result, the pore volume decreases and becomes smaller, and eventually disappears.

2.2.1. Influencing mechanism of maturity on the development of organic pore

According to the formation and preservation mechanism of organic pores described above, it can be inferred that thermal maturation is the basic thermodynamic condition for the development of organic pores. With the rise of maturity (R_o), organic matter starts to generate hydrocarbons, and pores in organic matter increase in number and volume. In the early hydrocarbon generation stage, the swelling of the kerogen due to generated liquid hydrocarbons makes the generated pores difficult to identify. In the dry gas generation stage, the porosity increases significantly, mainly due to the formation of organic pores. Researchers have measured the specific area of internal pore structure of kerogen during the hydrocarbon generation process. They found that with the increase of thermal maturity, the internal specific area of organic matter increased from less than 10 m²/g at 1000 m to about 35 m²/g at 4000 m^[12], indicating that more pores are generated in the kerogen. Through study on the development characteristics of organic pores in shale with different maturities in the naturally evolved field sections of the Permian and Appalachian Basins in North America^{[1, 15]} and simulation experiments of hydrocarbon generation and pore formation in organic-rich shale^[16], researchers have confirmed that thermal maturity controls the formation and evolution of organic pores, and the organic pores increase with the rise of maturity and are most developed in the high-maturity stage of organic matter. However, the causal relationship does not always exist in the entire thermal evolution process. In shale gas exploration practices^{[15, 17]}, it is found through statistical analysis between maturity and porosity or gas-bearing capacity that organic-rich shale with R_o>3.5% generally has no pores and low gas content. It is believed that the low porosity caused by extremely high maturity is one of the causes for the failure of exploration, and R_o=3.5% is proposed as the upper limit of maturity for shale gas exploration.

2.2.2. Maturity threshold for the disappearance of organic pores

As shown in Fig. 6, the Raman study of O₃w-S₁l shale graptolite shows that when the R_o value reaches 3.8%, the Raman spectrum D peak (representing the defect peak degree and disorder of the C lattice) changes inversely in shift and decreases in intensity, while the G peak (the C-C bond stretching vibration in the aromatic structure) is unchanged in shift and increases in intensity, indicating that the lattice defects (e.g. vacancies, and functional groups, etc.) have reduced, and the disordered layered structure of the aromatic nucleus has transformed to the orderly graphite crystal structure. Previous studies^[18] have confirmed that when the R_o value is greater than 4.0%, the anisotropy of vitrinite and solid bitumen also significantly enhances, and there is no longer a linear relationship between the maximum and minimum reflectance, indicating a fundamental change in the structure of organic matter. Statistical analysis of data from multiple shale gas exploratory wells in the Sichuan Basin also shows^[19,20] that the shale layers in O₃w-S₁l with R_o>3.5% are generally characterized by low-ultra-low resistivity responses, graphite peaks in the Raman spectrum, and poor physical properties, which are interpreted as the result of over-maturation and carbonization of organic matter. Evidently, after the R_o value reaches 4.0%, the aromatic nuclei arrange in a highly orderly manner, making solid bitumen and kerogen further crystallized and densified. This suggests a critical limit for the fundamental change in the structure of organic matter and the disappearance of organic pore during the hydrocarbon generation evolution, which corresponds to a R_o threshold of 4.0%. This understanding sheds light on the mechanism why there is an upper threshold of R_o of 3.5% for shale gas exploration, and why it is a threshold in line with geological reality.

Combined with the geological evolution process of O₃w-S₁l and the study on shale gas geochemistry, it is found that the undeveloped pores and low gas content of the marine shale intervals with R_o>3.5% in southern China are primarily "inherent deficiency". The hydrocarbon generation system was in an open state before uplift, with high hydrocarbon expulsion efficiency and intense condensation reaction, thus the organic pores had begun to be tightened. When R_o was 4.0%, the organic pores tended to disappear basically. For the shale intervals with R_o<3.5%, the hydrocarbon generation system had good sealing before uplift and the level of gas content is mainly dependent on the differences in the strength of structural reformation in the later stage of uplift. With similar background of burial process and maximum burial depth (continuous burial to about 6000 m) of the O₃w-S₁l shale in the Sichuan Basin and its periphery, the O₃w-S₁l shale inside the basin has better sealing conditions conducive to the preservation of organic pores, which is reflected by lower R_o and lighter δ¹³C₁ of shale gas there. The shale reservoir in Well WY1 has R_o of 2.72% and δ¹³C₁ of natural gas of -35.9‰; while the shale reservoirs in the Fuling-Wulong-Dingshan area have R_o and δ¹³C₁ higher than those in the basin. The shale reservoir in Well JY1 has R_o of 3.44% and δ¹³C₁ of -30.5‰. The shale reservoir in Well LY1 has R_o of 3.39% and δ¹³C₁ of -31.1‰, similar to those in Well JY1. Hence, it is inferred that the intensity of structural reformation is the primary reason for the differential enrichment of shale gas in this area.

As shown in Table 2, the Niutitang Formation shale in Wells HY1 and EY1 differ widely in the maturity and pore volume. The Niutitang Formation shale in Well EY1 has R_o of 4.84% on average, which is higher than the threshold of organic pore disappearance, indicating the Niutitang Formation shale in this area had high hydrocarbon expulsion efficiency and strong condensation reaction before uplifting and reformation, leading to compact structure and poor gas-bearing capacity of the organic matter. In Well JinY1 in southwestern Sichuan Basin (Table 2), the shale layers at the bottom and top of the Qiongzhusi Formation differ more drastically in R_o, organic pore development degree, and gas-bearing capacity. The shale layer at the bottom has typically “congenital deficiency”, as the Qiongzhusi Formation is in unconformable contact with the underlying stratum, the process of hydrocarbon generation and expulsion has always been in open state, little hydrocarbons are retained in-situ, and organic matter has suffered strong aromatization and hence has high R_o value and few organic pores developed. In contrast, the shale layer in the upper part has argillaceous shale or silty shale with good sealing capacity as direct roof and floor, so this hydrocarbon generation system is well sealed, which is conducive to the in-situ retention of hydrocarbons and the formation and preservation of organic pores; moreover, the structural reformation in the later stage is weak, so this shale layer becomes the gas-rich zone today.

Diagenesis studies in light of minerals and illite crystallinity in the study area show that the O₃w-S₁l shale has experienced mechanical compaction, pyrite cementation, and biological opal recrystallization in the early diagenetic period, the transformation from montmorillonite to illite, secondary growth of quartz, hydrocarbon generation of kerogen in the middle diagenetic period, and the metasomatism of ankerite, cracking of liquid hydrocarbon in late diagenetic periods. This shale suite is in the late diagenetic period now, with an illite crystallinity of 0.27-0.37 and R_o of 2.5%-3.2%. Different types of diagenetic processes and the mineral components generated by them have different effects on the development of organic matter pores.

2.3.1. Influence of compaction on the preservation of organic pores

The decrease of organic pores is mainly affected by the condensation and compaction of organic matter. As mentioned above, organic matter is densified by condensation reaction during the thermal maturation, which is intrinsically responsible for the reduction of organic pores and the main factor causing the disappearance of organic pores in shale with R_o>3.5%. Compaction is the most prominent reason for the reduction of pores in the initial stage of shale deposition and plays a destructive role in the preservation of organic pores. Compaction runs through the entire evolution process of burial diagenesis to uplifting epigenetic diagenesis and is an external factor affecting pore preservation. It is mainly manifested in the compaction and reduction of number, porosity and pore volume of organic pores without the support of rigid mineral framework and pore fluid pressure due to press of overlying strata or structural extrusion. Especially, the high enrichment of clay minerals or organic matter enhances the plasticity of the rock, in this case the organic pores are more likely to be compacted and collapse. As shown in Table 2 and Fig. 7, TOC is in positive correlation with porosity of Niutitang Formation shale in Well HY1 for the shale interval with TOC<6%, while TOC is in negative correlation with porosity for shale interval with TOC>6%. The organic pores in the shale samples are mainly micropores and secondarily mesopores in directional arrangement, showing imprints of compaction. The Lower Cambrian shale in southern China and the Marcellus and Woodford shales in the United States all show the same law, only the TOC values of the peak porosity differ somewhat. For example, the TOC value is 3.0% for shales in Wells Xuanye A, Tianma A and Tianxing A^[21], and 3.6%^[15] and 5.6%^[22] for Woodford and Marcellus shales respectively. Obviously, high TOC value affects the mechanical properties of shale and increases plasticity of shale. Especially for argillaceous shale, with no support of rigid minerals and fluid pressure, this kind of shale has lower resistance to compaction, and is more likely to reduce in porosity and pore size when subjected to compaction.

2.3.2. Pore formation from recrystallization in early stage and pore preservation by compaction resistance in late stage of bio-silicon

In the diagenetic process of shale, early siliceous cementation-recrystallization and quartz minerals have a dual effect on the formation and evolution of organic pores, that is, the intergranular pores produced by the early cementation-recrystallization of biologically-sourced siliceous minerals and the late resistance to compaction of quartz framework generated by the early cementation-recrystallization. The former provides effective storage space for early bitumen retention. The latter provides important support and preservation for primary pores of organic matter (the protoplasmic structure of bioclastics, inherited pores formed in the organic matter deposition and in the early diagenesis) and secondary pores (pores generated in the process of hydrocarbon generation). As shown in Fig. 8, based on the mineral morphology and composition analysis of FESEM-EDS, the radiolarian cavity is composed of dispersed quartz crystallites, in mainly point contact and secondly floating contact, indicating that these quartz micro-crystallites mainly developed in the early stage of diagenesis and originate from the recrystallization of biological opal. On one hand, intergranular pores of 1-5 μm are widespread between microcrystals and filled with a large amount of bitumen, and abundant nano-pores are generated after the secondary pyrolysis of the bitumen. On the other hand, quartz is a typical rigid mineral, the microcrystalline quartz framework can improve the mechanical support and increase the resistance to compaction of the shale, and thus makes it possible for the organic pores to be preserved under deep burial conditions. These diagenetic processes mainly occur in the ①-⑤ layers of O₃w-S₁l, in which siliceous organisms (e.g. radiolarians and spongy spicules) deposit in a laminar pattern (Fig. 8a), affecting the development and distribution of organic pores, reservoir physical properties, and rock mechanical properties significantly. In the marine shale gas system in southern China, organic pore is one primary type of storage space. Generally, there is a positive correlation between the content of organic matter and siliceous minerals and porosity and gas-bearing capacity, indicating that the higher the content of organic matter and siliceous minerals, the more developed the organic pores, and the higher the gas content will be. This characteristic is most prominent in the O₃w-S₁l shale suite, which is attributed to the fact that the siliceous mineral framework plays a pivotal role in the preservation of organic pores under pressure.

2.3.3. Influence of pyrite on the preservation of organic pores

The widely distributed pyrite cements in O₃w-S₁l also have a dual effect similar to siliceous minerals, which is reflected by intergranular pores of framboidal pyrite and solid bitumen with rich pores, and pyrite filling in animal cavities, etc. According to the statistics of Meng^[23], the ①-④ layers of O₃w-S₁l have most developed pyrite, with pyrite content of 4.0%-6.5%; the ⑤-⑨ layers have a pyrite content of 2.0%-4.0%, indicating that abundant pyrite was formed during the diagenesis of O₃w-S₁l. As shown in Fig. 9, the graptolite cavity is hollow and contains a large amount of pyrite. Due to the support of pyrite, the graptolite cavity has remained open to semi-open. Solid bitumen rich in pores fills the graptolite cavity (Fig. 9a). The rupture of the graptolite cavity causes the exposure of pyrite on the surface of the graptolite (Fig. 9b), which can be connected with other pores and crack to become one of the primary components of pore fracture network system of organic matter.

2.3.4. Influence of burial depth and brittle-ductile transition on the preservation of organic pores

Exploration practices show that the current burial depth of organic-rich shale layers can also affect the preservation of organic pores through brittle-ductile transition. Under high-temperature and high-pressure conditions in deep formations, especially at depth larger than 4470 (±230) m, shale gradually enters the ductile zone from the brittle-ductile transition zone^[24], enhances in plasticity, and reduces in compaction resistance, resulting in severe decrease of organic pores. For example, the burial depth of O₃w-S₁l in all four exploratory wells YZ1, RY1, DY2 and Dong YS1 is more than 4000 m, staying at the lower limit of the brittle-ductile transition zone. The exploration via YZ1 and RY1 reveals that the O₃w-S₁l shale suite has normal pressure, low gas content, and porosity of less than 3% (Fig. 1). In Well RY1, the shale has a porosity of 1.63%-3.14% or only 2.38% on average. In Well YZ1, the shale, more than 4500 m deep, is more plastic and over-mature (with R_o of 3.54%), indicating that the gas might have escaped at the maximum burial depth or before it was uplifted, and there was no pore fluid pressure inhibiting thermal maturation of organic matter. Therefore, under the dual effects of high thermal maturity and compaction of overlying strata, organic pores decrease (Fig. 3d), and the pore volume is only 0.009-0.013 cm³/g, much lower than 0.025-0.029 cm³/g of the same interval in Well DY2. Evidently, the high porosity and high gas content of this suite of shale with overpressure in Wells DY2 and Dong YS1 form stark contrast with the low porosity and low gas content of this suite of shale in Wells YZ1 and RY1^[5]. It follows that the coupling effect of overpressure and rigid mineral framework is more conducive to the preservation of organic pores in deep layers. Therefore, pore fluid pressure dependent on preservation conditions and rock mechanical properties under different burial depths have important controlling effects on the dynamic evolution of pores in deep-ultra-deep formations, of which sufficient retained hydrocarbons and pore pressure are particularly critical.

2.4.1. Amount of retained hydrocarbons

As mentioned above, hydrogen-rich organic matter can generate more hydrocarbons. Especially, lipid-rich organisms like planktonic algae and radiolarians can generate rich bitumen in the immature-low-mature stages. These lipid-rich organisms have relatively large molecular mass, high contents of colloid and asphaltene, and strong polarity. They can emplace the inorganic pores/ fractures and primary organic pores formed in the early diagenesis stage through adsorption and precipitation etc.^[25] (Figs. 2, 8 and 9), thus hindering the densification of pores/fractures by compaction and cementation, and producing more natural gas, solid bitumen and associated pores through high-temperature cracking in the middle and late stages of diagenesis.

The authors carried out simulation experiments of shale gas generation with selected low-mature marine source rock samples according to the burial history and thermal history of O₃w-S₁l in the Fuling shale gas field. The results show that when the hydrocarbon expulsion efficiency reaches 70%, residual kerogen and retained oil (30%) still have good gas generation potential in the high-mature to overmature stage and have a cumulative maximum gas generation capacity of 8 m³/t; and the gas generated is dominantly cracking gas from retained oil (accounting for 70%)^[8]. The geochemical characteristics of carbon isotope composition of Fuling shale gas and its mixed fractionation model calculation results also suggest that the shale gas is a mixture of kerogen and crude oil cracking gases^{[4, 8]}, with the latter taking 80%. Based on the statistics of solid bitumen content in the source rock samples^[26], the oil retention efficiency of the O₃w-S₁l shale in the Jiaoshiba structural area was estimated by inversion. It is found that the ③-⑤ layers have an oil expulsion efficiency of 12%-36% or 23% on average. That is, the average retention rate of crude oil in situ is 77%, which is consistent with the abovementioned experimental and geochemical research results. It follows that the O₃w-S₁l shale was in a closed state during the burial and hydrocarbon generation in the Jiaoshiba structural area, with low hydrocarbon expulsion efficiency and large retained hydrocarbons, which provides rich materials for shale gas generation and the development of organic pores and creates conditions for inhibiting aromatization of organic matter and preserving organic pores. Researchers^[12] pointed out that kerogen had no more potential to generate hydrocarbon gas due to the exhaustion of hydrogen-rich components in the high-mature stage, and the large amount of methane might be generated by the cracking of retained liquid oil. Therefore, the significant increase of organic pores in the organic matter in high mature-overmature stage is mainly due to the contribution of solid bitumen. The amount of retained oil containing colloid and asphaltene determines the development potential of organic pores to some extent.

2.4.2. Influence of hydrocarbon fluid pressure on the preservation of organic pores

The retained hydrocarbons inhibit diagenetic compaction and thermal maturation, and play a role in preserving organic pores by changing pore pressure, including causing abnormally high pressure and capillary pressure.

With the continuous thermal cracking of kerogen and retained oil, a large amount of gaseous hydrocarbons is generated, making pore fluid pressure increase constantly. Under good sealing conditions, the organic pore system that retains a large amount of high-pressure gaseous hydrocarbons is in an overpressure state, and can counterbalance the effects of overburden pressure and tectonic stress, so overpressure plays a constructive role in maintaining organic pores under deep burial conditions. In the overpressure systems of the Fuling and Weirong shale gas fields, the O₃w-S₁1 gas-rich layers have very abundant organic pores mostly in various sizes, round or elliptical shapes, and ink bottle structure (Figs. 2c, 2d and 8a). This is because overpressure enhances the resistance of shale to compaction. Especially under the coupling effect of rigid mineral lattices such as quartz and pyrite, even in the deep-ultra-deep formations, zones with rich organic pores can still exist. The deep reservoirs in O₃w-S₁1 of Well DYS1 with high porosity and high gas content dominated by organic pores are the best examples^[5]. The statistical analysis of the relationships between porosity, pressure coefficient and gas content of typical shale gas fields also confirms that abnormally high pressure of pore fluid is conducive to the preservation of organic pores which provide better storage condition for massive accumulation of shale gas^{[7, 27]}.

The development of organic pores under normal pressure is more complicated than that under overpressure, and is related to the degree of in-situ preservation of hydrocarbon-generating products and capillary pressure. The capillary pressure is inversely proportional to the pore throat radius. Usually, the organic nano-pore system dominated by micropores and mesopores has higher capillary pressure. For example, when the pore throat radius is 4.0 nm, the capillary pressure can reach 35 MPa; assuming that the hydrostatic pressure is 25 MPa (at the burial depth of 2500 m), the displacement pressure would be 60 MPa under normal pressure, which is conducive to shale gas retention and pore preservation. The O₃w-S₁l shale gas reservoirs in Pengshui and Wulong areas are normal in pressure, and have quite developed organic pores and no signs of compaction^[9]. This is attributed to the retention of some of gaseous hydrocarbons in the organic pores through adsorption and capillary pressure sealing etc. Before pressure breakthrough and escape, the retained gas is sufficient to slow down the damage of the overburden pressure or the post-structural compression to the organic pores. In addition, the shale suite is currently in the brittle zone of the middle-shallow depth (2000-2800 m)^[24], the compaction resistance of rigid minerals (e.g. quartz) is also favorable to the preservation of organic pores.

The distribution of organic matter in shale has an important influence on the development and connectivity of organic pores. According to the comparison of geochemical and organic petrological features, layers in O₃w-S₁1 differ significantly in the abundance, composition and distribution characteristics of organic matter in the vertical direction. The ①-⑤ layers with TOC>3% and SiO₂ mass fraction larger than 40% are carbon-rich and high-silicon shale layers. They are rich in radiolarians, acritarch, graptolites and concomitants with primary pores, planktonic algae with secondary pores, and solid bitumen, and have different types of minerals such as siliceous, calcareous and clayey minerals in continuous and dense laminae (Figs. 8-11), so the organic pores and grain boundary fractures (mineral grain boundary fractures, organic matter shrinkage fractures, etc.) are connected with each other to form a complex organic-inorganic pore-fracture connected network system and bedding fractures with better connectivity, forming three-dimensionally connected effective reservoirs and lateral dominant paths along the bedding fractures (Fig. 12a-12b) to provide primary storage space and flow pathways for enrichment and high production of shale gas. In contrast, the shale in other layers is massive; even with higher organic carbon content (less than 3%), the number of acritarch, graptolite and siliceous organisms is smaller, and the organic matter is mostly dispersed and isolated. Hence, only when the mineral grain boundary fractures are developed, can the pore-fracture connected network system be formed, and can the layer become an effective reservoir (Fig. 12c).

Pore connectivity is a key parameter to characterize effective shale reservoir. In order to find out the connectivity between pores in a single organic matter particle, between organic pores in different particles, and between such pores and inorganic pores/fractures, the authors used high-pressure alloy injection and CT/FIB-SEM imaging methods to analyze the connectivity of pores of different scales in the O₃w-S₁l organic-rich shale samples with different textures by percolation theory numerical algorithm^[28,29].

As shown in Table 3 and Fig. 13, the connectivity of micron-scale pores in a single particle of organic matter in shale samples from the bottom of O₃w-S₁l in Well JY1 was analyzed by using FIB-SEM nanoscale imaging and according to the percolation theory. It can be seen that when the porosity is 1.42%, flow pathways are preferentially formed in the X and Y directions. When the porosity is 5.19%, the pores are connected in all three directions, following the rule that at the threshold porosity smaller than 1.42 %, the pores inside single organic matter particle are likely to connect with each other effectively.

As shown in Table 3 and Fig. 14, the connectivity of millimeter-scale pores in organic-rich shale samples with laminar and massive structures was analyzed by using high-pressure alloy injection, CT imaging, and percolation theoretical numerical algorithm. The results show that the sample with a porosity of 4.26% has no flow pathways formed; the sample with a porosity of 6.31% has 1 and 3 flow pathways formed respectively in the X and Z directions. It follows that at the percolation threshold of 6.31%, flow pathways are preferentially formed in the X and Z directions. This is because the organic matter is distributed in layers, and brittle minerals (e.g. quartz and carbonate) are interbedded with organic matter (Fig. 11) and have grain boundary fractures developed, these pores and seams can connect with each other to form flow pathways extending horizontally and vertically. The sample with a porosity of 7.46% has flow pathways in three directions, forming a three-dimensional connection. This indicates that organic pores in organic-rich laminated shale can form effective connection at relatively low percolation threshold (about 6%) together with bedding fractures, grain boundary fractures, etc., thereby forming dominant flow pathways. Among the massive shale samples, the sample with a porosity of 5.54% has no flow pathways in the three directions; the sample with a porosity of 9.26% has flow pathways formed in the X, Y, and Z directions, indicating that the percolation threshold is 9.26%; the sample with a porosity of 10.2% has no increase in flow pathways in the three directions than the sample with a porosity of 9.26%, and no dominant direction of flow pathways turning up, indicating that the increase in porosity has limited improvement in connectivity, and the connectivity of organic-inorganic pores and fractures is generally poor.

The above research results show that the pores inside organic matter particle can effectively connect with each other, but the critical percolation porosity and connectivity between organic pores in different organic matter particles and between organic pores and inorganic pores/fractures differ greatly, depending on the shale texture type, organic matter distribution and pore difference. In the laminar shale with organic matter distributed in lamina, and brittle minerals such as quartz and carbonate interbedded with organic matter, organic pores and other pores/fractures can effectively connect at a relatively low porosity (6%±). In massive shale with mainly organic pores in matrix, dispersed and isolated organic matter, and few inorganic pores/fractures, the organic pores and inorganic pores/fractures can only connect effectively at a higher porosity (larger than 9%). The accumulation of different types of organic matter and brittle minerals massively and laminar distribution of organic matter and brittle minerals are the prerequisites for the development and connection of organic pores, grain boundary fractures and bedding fractures in shale.

The formation of organic pores is attributed to the formation and in-situ retention of hydrocarbons under the synergistic effect of organic matter type, maturity and decomposition in the hydrocarbon-generating process of organic-rich shale. Sapropelic kerogen and bitumen are the main contributors to organic pores. The organic pores increase with the increase of R_o and are mostly developed in the high-mature stage, but tend to die out when R_o is 3.5%. The threshold R_o for shale gas reservoirs is 4.0%. Shale layers with R_o>3.5% have a high risk of "congenital deficiency" in shale gas exploration.

The preservation of organic pores is dependent on the joint effect of steric hindrance, rigid minerals, pore pressure and brittle-ductile transition. The steric hindrance of in-situ retention of hydrocarbons is limited to the hydrocarbon generation process, which is the intrinsic cause of organic pore preservation by inhibiting the aromatization of organic matter. The support of rigid mineral framework, retained hydrocarbon and pore pressure runs through the whole process of burial-uplift diagenesis, and is primarily responsible for pressure resistance and pore preservation. Under the joint effect of overpressure and rigid minerals, organic-rich shale can develop organic pores even at the depth of brittle ductility transition zone.

The effective connection between various types of organic pores is the basic condition for organic pores to become the primary storage space of shale gas. The effective connection between pores inside one organic matter particle and between organic pores and inorganic pores/fractures depends on the abundance and distribution of organic matter and the development degree of pores/fractures. The enrichment of hydrogen-rich organic matter and interbedded laminar distribution of organic matter and brittle minerals are the prerequisites for the development and connection of organic pores, grain boundary fractures and bedding fractures in shale to become effective reservoir.