Keywords

2.1 What is Shale Gas

The unconventional natural gas usually has been explored by unconventional technologies and is difficult to be explained by the theory of conventional petroleum geology. This type of gas reservoir is generally characterized by low porosity, low permeability and continuous accumulation. Shale gas is one of the most important types of unconventional natural gas and is an important green energy.

The traditional definition of shale gas refers to the natural gas existing in adsorption and free state in low porosity, ultralow permeability, organic-rich dark shale or high-carbon content shale (Zhang et al. 2003, 2004, 2008a, b; Jiang et al. 2010; Xu et al. 2011), it is biogenic, thermogenic or biothermal continuous natural gas accumulation, with geological features such as short migration distance, multiple sealing mechanisms, concealed accumulation and high gas content in reservoir formation (Curtis 2002; Zhang et al. 2003; Xu et al. 2011). Generally, shale gas is natural gas extracted from dark shale rich in organic matters (Zou et al. 2010, 2011).

From the aspect of petrological characteristics, Jiang (2003) believed that shale gas reservoirs did not develop in the traditional organic-rich mudstone/shale (clay mineral content over 50%), but developed in the fine-grained sedimentary rock composed of clay and silty fine-grained sediments. With the rapid development of unconventional oil and gas industry, the concept of fine-grained sedimentary rocks and related research start to get the attention from the scholars (Jia et al. 2014). The scholars redefined that the shale gas is natural gas development in fine-grained sedimentary rocks, and believe that the hydrocarbon source rocks generate a large quantity of natural gas through a series of geological conditions, and discharge the gas under the steady pressure. The gas migrated to permeable strata such as sandstone and carbonate rock and accumulated into structural or lithologic gas reservoirs. The natural gas remained in fine-grained sedimentary rock strata formed shale gas resources (Li et al. 2009a, b). In fact, considering the perspective of oil and gas resources, the concept of fine-grained sedimentary rocks is mentioned by many scholars to distinguish the coarse-grained sedimentary rock as an conventional reservoir rock. Currently, fine-grained sedimentary rocks were referred as unconventional reservoir rock with particle size less than 1/16 mm, including siliceous rock, shale, clay and coal rocks. Of course, this concept has greatly enriched the research field of sedimentary petrology, expanded the scope of reservoir research, and developed traditional sedimentology and reservoir geology (Xu et al. 2015). From this perspective, the concept of fine-grained sedimentary rocks should be more specific to unconventional plays as a whole.

Many scholars also believed that the shale gas developed in the intervals which were mainly silty mudstone, argillaceous siltstone, siltstone, fine sandstone, coarse sandstone and even thin fine conglomerate interbeds (Zhang et al. 2003, 2004, b). Wu et al. (2013b) also pointed out that shale gas not only existed in the interlayer of mudstone, high-carbon mudstone, shale and silty rock in adsorption or free state, but also existed in fractures, pores and other reservoir spaces as free state, or in kerogen, clay particles and pore surface as adsorbed state. Furthermore, a very small amount is stored in dissolved state in kerogen, asphaltene and petroleum, in interbedded siltstone, silty mudstone, argillaceous siltstone or even sandstone formations. Wang et al. (2012a, b) defined shale gas as natural gas occurring in organic-rich shale and its interlayers. From the perspective of self-generation and self-storage of shale gas reservoirs, the natural gas in non-source rock/lithology should actually belong to other types of conventional or unconventional gas reservoirs in the same accumulation system, such as tight sandstone gas.

Generally, more attention should be paid to the organic-rich shale itself, that is, the source rock itself, in order to accurately understand the definition of shale gas. Based on the geological survey and research of shale gas, the author believes that shale gas is the “residual gas” that has not been discharged in time in the source rock. It exists in the form of adsorbed gas, free gas or dissolved gas, and is mainly biogenic gas, thermogenic gas or a mixture of both. Its meaning emphasizes on two aspects: (1) High-quality hydrocarbon source rocks are shale gas accumulation of the main factor. Shale gas originates in the hydrocarbon source rocks; the carrier rock is the organic matter rich rocks that have certain adsorption storage space or silty shale, rather than organic matter-lack rocks like silt (mass) rocks, carbonate rocks. (2) Shale gas is the “residual gas” which has not been timely discharged in the process of hydrocarbon generation from the relatively high-quality source rock. The shale gas reservoir has the integration features of both source and storage. The hydrocarbon generation residual pore is the main storage space for shale gas and determines the adsorption potential of shale gas and adsorbed gas. Thus, shale gas is a special natural gas resource which cannot be exploited by conventional oil and gas exploitation technology under the current economic and technological conditions. In recent years, as vast progress has been made in horizontal well drilling and fracking, “residual gas” in source rocks, known as shale gas, has begun to be exploited on an industrial basis.

2.2 Geological Characteristics of Shale Gas

Based on the definition of shale gas, shale gas reservoirs should have the three most basic and important geological characteristics as following:

  1. (1)

    The primary condition and key factor for the shale gas reservoir are that there must be sufficient in situ gas content and sufficient organic matter in mudstone/shale to produce a large amount of biogenic gas and thermogenic gas, which requires that mudstone/shale must be hydrocarbon source rock. Thus, shale gas normally occurs in the source rock.

  2. (2)

    Integration of source and storage. Shale gas reservoirs have the typical characteristics of in situ accumulation, and the natural gas that cannot be discharged in time remains in the source rock to form gas source accumulation. Moreover, in the long process of hydrocarbon generation, the generation of natural gas is not only to meet the adsorption by particles surface like organic matter and clay minerals in rock, but also need to fully occupy its matrix pore and various types of reservoir space of reserves. When the adsorption gas and dissolved gas reaches saturation, the surplus of natural gas in free state starts to migrate and accumulates the water-soluble gas reservoirs under suitable conditions (Nie et al. 2009a; Wang et al. 2010). Thus, although the shale gas storage carrier rock is a low porosity and ultralow permeability reservoir, it has a wide range of gas saturation.

  3. (3)

    The development and distribution of shale gas reservoirs are not controlled by structure; there is no obvious or fixed limit trap. It was only controlled by the area of source rock and capping rock. Compared with conventional oil and gas reservoirs, shale gas accumulation belongs to the occurrence and enrichment of natural gas without secondary migration or with very short distance secondary migration and does not depend on conventional traps (Zhang et al. 2011).

Generally, shale gas reservoir is a continuous natural gas reservoir formed by continuous gas supply, continuous accumulation, and it is formed from hydrocarbon source rock as same as gas source rock, reservoir and cap rock (Li et al. 2014). The geological parameters such as lithology, thickness, area, geochemical parameters, physical parameters and mineral composition have direct control of the content of shale gas and determine the accumulation (Wang et al. 2015a; Mou et al. 2016). In fact, the gas content of shale gas indicates the shale gas enrichment, is a direct indicator of the residual gas in organic-rich shale, and is also an important parameter in the calculation of shale gas resources in China (Wang et al. 2013b; Wang et al. 2015a). Thus, in the regional geological survey of shale gas, the analysis of influencing factors of shale gas accumulation is actually the analysis of influencing factors of shale gas content.

2.3 Influencing Factors of Shale Gas Enrichment

The commercial development of shale gas in North America depends on the abundance and proper thermal evolution of organic matter, the content of brittle minerals, preservation conditions, shale thickness, surface topography and hydrology (Martini et al. 1998; Daniel et al. 2007; Gault and Scotts 2007; Martineau 2007; Ross et al. 2008; Li et al. 2014). Key parameters used by foreign oil companies in shale gas favorable area screening (Martini et al. 1998; Daniel et al. 2007; Gault and Scotts 2007; Martineau 2007; Ross et al. 2008) can be divided into two categories, including geological conditions and engineering conditions. The first one controls the generation and enrichment of shale gas, including gas-bearing shale area and thickness, abundance of organic matter, type and maturity, brittle mineral content and hydrocarbon display, etc. The latter one controls the cost of shale gas development, including burial depth, surface topography and road transportation.

In China, scholars (Xu et al. 2011; Chen et al. 2011a, b) believe that there are three key factors controlling the enrichment of shale gas: shale thickness, organic matter content and shale reservoir space (pores and fractures). Wang et al. (2013a, b, c) systematically studied the gas-generating material basis of coal-bearing shale gas in Carboniferous Ceshui Formation in central Hunan from the aspects including black organic-rich shale thickness, organic carbon content, organic matter type and thermal evolution degree. He believes that these three factors are the main key factors affecting shale gas accumulation.

Zhang et al. (2008b) believe that shale gas, as a special type of natural gas accumulation, has lower reservoir-forming threshold (Pang et al. 2004) and consequently leads to a larger distribution area of shale gas. Qiu et al. (2014) believe that shale properties like thickness, burial depth, mass fraction of organic carbon, maturity of organic matter, gas content and preservation conditions are key factors for shale gas accumulation after the in-depth study of Lower Cambrian Marine shale in the Middle Yangtze Region. The previous research (Curtis 2002) shows that shale gas accumulation requires the following geological conditions: The sedimentary strata are mainly mudstone/shale, with the thickness of single layer larger than 10 m, high mud content (the thickness of pure mudstone in mudstone/shale stratum is more than 10%), low organic matter abundance (TOC ≥ 0.3%), low maturity threshold (Ro ≥ 0.4%) and low porosity (less than 12%). For commercial exploration, the shale gas is required to have a small burial depth (no more than 3 km), development of fractures, high adsorbed gas content (no less than 20%), etc. Mudstone/shale that is still in the stage of gas generation has better favorable shale gas accumulation.

Scholars focus on different shale gas development blocks or different shale formations and have proposed different ideas on key factors affecting shale gas accumulation and enrichment. These factors are mainly thickness of mudstone/shale, organic carbon content, organic matter types, thermal maturity, the brittle mineral content, porosity and permeability of reservoirs, the fracture development, paleo structure, preservation conditions and hydrocarbon content and so on. These are the main factors of gas content and all influencing the shale gas content. Together with environmental factors such as depth, temperature and pressure, they determine whether a block has commercial exploration and development value (Zhang et al. 2011a, b, c; Li et al. 2013a, b). The gas content of shale is the key to evaluate these factors and directly reflects the characteristics of shale gas reservoirs.

Shale gas content refers to the total amount of natural gas existing in rock per ton under the standard temperature and pressure (101.325 kPa, 25 ℃), including free gas, adsorbed gas, dissolved gas and so on. At present, the main focus is on adsorbed gas and free gas (Li et al. 2011; Nie et al. 2013); its amount directly determines the economic recoverable value of shale gas reservoirs (Han et al. 2013a, b). Nie et al. (2012) found that shale gas is mainly adsorbed gas, and shale gas content indicates the enrichment degree of shale gas, which is a direct indicator to evaluate the residual gas in shale and an important parameter to calculate the amount of shale gas resources in China (Wang et al. 2013b). Yang et al. (2012) believes that shale gas evaluation is a resource factor, which determines the regional shale gas resource potential and reserves, and is a key indicator for shale gas resource evaluation and favorable block selection. Therefore, the analysis of influencing factors of shale gas enrichment in regional geological survey is actually the analysis of influencing factors of shale gas content.

2.3.1 Organic Carbon Content

Shirley (2001) proposed that the organic carbon content of shale is one of the main factors affecting the adsorbed gas volume of shale, while the abundance, type and evolution degree of organic matter are the main factors affecting the gas generation. Organic matter content determines the hydrocarbon generation capacity, pore space size and adsorption capacity of shale and plays a decisive role in the gas content of organic-rich shale (Li et al. 2011). Generally speaking, the higher the abundance of organic matter and gas generation in source rocks, the higher the enrichment of gas reservoirs (Xu et al. 2011). The successful experience of shale gas exploration and development in North America shows that organic matter content is an important indicator to measure the gas bearing of shale (Curtis 2002; Bowker 2007). Through the study of shale gas in North America, it is found that there is a linear relationship between the content of organic carbon in shale and the gas production rate of shale (Fig. 2.1). The content of organic carbon is an important variable determining the gas production capacity of shale. Due to the adsorption characteristics of organic carbon, its content directly controls the adsorbed gas content of shale. Accordingly, shale adsorbed gas increases (Jarvie et al. 2005). Ross et al. (2007) studied Gordondale formation of Jurassic System in Eastern Canada and found that calcareous or siliceous shale with higher organic carbon content had higher storage capacity for adsorbed shale gas. On the contrary, as organic carbon content decreases, adsorbed gas content also decreases, reflecting the close relationship between shale adsorption capacity and organic carbon content (Bowker 2007).

Fig. 2.1
figure 1

Relationship between TOC and gas content of North American shale gas (after Chen et al. 2011a, b; Wang et al. 2010)

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Domestic scholars also found that organic matter content is the key factor affecting shale gas content. Organic matter content is a key parameter restricting shale gas content and resource potential (Wang et al. 2013b), which determines the amount of hydrocarbon generation and affecting the intensity of hydrocarbon generation (Bai et al. 2011). Organic matter abundance and thermal maturity are the basic conditions for shale gas accumulation (Li et al. 2014). Organic carbon content is also an important indicator to measure the gas bearing of shale (Han et al. 2013b). Studies show that, same as shale in North America, there is a clear linear relationship between organic carbon content and gas production rate of shale in most basins in China (Zhang et al. 2011a, b, c). In the process of actual exploration and research, it is found that the total organic matter content is often positively correlated with the gas content of shale, and the higher the organic matter content in shale, the greater the gas content (Fig. 2.2) (Guo et al. 2013; Wang et al. 2013b; Tu et al. 2014). Organic matter in shale can adsorb shale gas generated by the source rock on its surface, leading to a linear relationship between the shale gas adsorption capacity of organic matter and the total organic carbon content in shale (Bai et al. 2011). Han et al. (2013a) found that the adsorbed gas content of Longmaxi Formation shale in Southeastern Chongqing increased with the increase of organic carbon content and proposed that this was related to the microscopic pore in the organic matter. Xue et al. (2013) measured the organic carbon content and field gas production of Longmaxi Formation shale in Zhaotong block, Sichuan Basin. And the results show that with the increase of organic carbon content, the specific surface area of shale increased, the adsorption capacity enhanced, the saturated adsorption quantity increased, and leading to an increase in gas content. In addition, Nie et al. (2012) analyzed and calculated the gas content of Upper Ordovician-Lower Silurian black shale in the Sichuan Basin and its surrounding areas. The results obtained by tests and calculations are highly consistent. The calculation method is mainly based on the linearity of organic matter content and shale porosity. Shale reservoir porosity is mainly from the organic matter hydrocarbon generation pores, this is under the control of the organic matter content. Thus, it can be further shown that the development of black shale rich in organic matter can be used as the important indexes for evaluation of shale gas. In shale gas exploration, vertical and horizontal permeability increases after hydraulic fracturing, and high organic carbon content also increases in situ permeability. These factors would greatly increase the EUR (Zhang et al. 2011a, b, c).

Fig. 2.2
figure 2

Relationship between TOC and gas content of black rocks in Longmaxi Formation of Southern Sichuan Basin and its periphery (A. YY1 well, after Han et al. 2013a, b; B. JY1 well, after Guo et al. 2013)

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In general, organic carbon content is the main factor controlling the adsorbed gas content of shale. On one hand, higher organic carbon content leads to higher gas generation potential and higher gas content per unit volume of shale. On the other hand, higher organic carbon content leads to more hydrocarbon generation pores of organic matter, and the more specific surface available for natural gas adsorption, and accordingly the increases of adsorbed shale gas content (Xu et al. 2011). As adsorbed gas is the main type of shale gas, organic matter content influences the shale gas content the most. Studies have shown that once the organic-rich mudstone/shale must have sufficient organic matter, generally TOC > 2%, the shale gas accumulated as shale gas play (Mou et al. 2016).

2.3.2 Types and Maturity of Organic Matter

Organic matter type is also one of the important indicators to evaluate the gas generation quality of organic-rich shale, which plays a decisive role in the gas generation potential and nature of shale (Wang et al. 2013a, b, c). Because the chemical composition and structural characteristics of different kerogens are significantly different, the gas production rate varies greatly. Under the experimental conditions, the gas generation of organic matter at different heating rates is basically the same, but the Ro values corresponding to the main gas generation period (70–80% of the total gas generation) are different for different kerogen types. Ro of type I kerogen is 1.2–2.3%, type II kerogen is 1.1–2.6%, type III kerogen is 0.7–2.0%, and marine petroleum cracking into gas is 1.5–3.5% (Zhao et al. 1996).

The degree of thermal evolution of organic matter can affect the hydrocarbon generation potential of shale (Han et al. 2013b), and the degree of thermal evolution (or maturity) is a key indicator to determine the hydrocarbon generation from organic matter (Li et al. 2013a, b). Wu et al. (2013a, b) found that the maturity of organic matter has a certain negative correlation with micropore volume and mesopore volume and has no correlation with macropore volume when Ro < 2.0%. However, it has a certain positive correlation with macropore volume when Ro > 2.0%. Both Ro > 2.0% and high maturity organic carbon content were positively correlated with macropore volume, which may be related to the increase of macropore volume caused by the development of nanoscale microcracks in high-maturity organic matter. It can be concluded that the maturity of organic matter affects the reservoir space type of shale and consequently affects the gas content of shale. The higher the thermal maturity of gas-bearing shale is, the more gas exists in shale, indicating that the higher the thermal maturity is, the more gas generated. As the maturity increases, the formation pressure caused by hydrocarbon gas generation can also improve the adsorption capacity of shale gas. Therefore, thermal maturity is an important geochemical parameter to evaluate the potential of high shale gas production (Bai et al. 2011).

In conclusion, different types of organic matter have different hydrocarbon generation capacities under different thermal evolution degrees. Therefore, organic matter types not only affect the hydrocarbon generation capacity of shale, but also affect the gas content of shale (Zou et al. 2010).

2.3.3 Thickness of Gas-Bearing Shale

It is well known that widely distributed mudstone/shale is an important basis for shale gas generation (Yang et al. 2009). A certain thickness of shale is the fundamental condition for shale gas enrichment. Shale thickness is also an important influence factor for the shale gas resources abundance, which directly affects the size of shale gas resources (Li 2009; Liang et al. 2011; Lu et al. 2012). Bai et al. (2011) proposed that the commercial accumulation of shale gas requires sufficient thickness and certain burial depth of shale. The deposition thickness is the prerequisite to ensure sufficient organic matter and reservoir space. Therefore, the thickness of organic shale is positively related to the enrichment degree of shale gas; organic shale is the carrier for the generation and occurrence of shale gas and an important condition for ensuring sufficient storage and permeability space (Tu et al. 2014).

In addition, the shale thickness and roof and floor conditions have controlled the storage condition (Li et al. 2014). Mudstone/shale itself has sealing capability and can be used as shale cap rock of gas reservoir. Especially for larger thickness of mudstone/shale, when thickness is greater than the maximum distance of hydrocarbon expulsion during the climax period of hydrocarbon generation, the gas will effectively trapped in mudstone/shale (Bai et al. 2011; Hu et al. 2014). Therefore, if the mudstone/shale itself has a certain thickness, it can self-seal and obtain a certain amount of shale gas (but not enough for commercial exploitation) (Hu et al. 2014). In order to form a large-scale shale gas reservoir, the thickness of shale must be greater than the effective hydrocarbon expulsion thickness, normally more than 30 m. In addition, under the same deep burial conditions, from the test analysis data, the Lower Paleozoic marine mudstone in Sichuan Basin has very low permeability and is self-sealing (Hu et al. 2014), which may also be one of the factors for it to become a high-quality shale gas reservoir.

It can be seen that the effective thickness of deposition is the prerequisite to ensure sufficient organic matter and reservoir space. The thicker the shale is, the stronger the sealing ability of shale has, which is benefit to gas preservation and shale gas accumulation (Yang et al. 2009). For example, continental lacustrine basin, Marine basin and slope area are all regions where mudstone/shale developed widely, with large thickness and wide distribution area, and are also the preferred and favorable prospect areas for shale gas exploration (Xu et al. 2011).

2.3.4 Mineral Composition

As the matrix permeability of shale gas reservoir is generally nano-Darcy level and the lithology is dense, fracturing is needed to generate fracture network to improve the seepage capacity of shale gas. Therefore, shale gas reservoir itself should have a certain brittleness, which is easy to produce fractures under the fracking (Wang et al. 2013b). Brittle mineral content controls the reformability of shale (Li et al. 2014). Therefore, mineral composition and content of shale often affect the exploitation and fracturing effect of shale gas reservoirs (Li et al. 2013a, b).

There is an obvious correlation between rock mineral composition and organic matter content in black shale of Silurian Longmaxi Formation in Southern Sichuan and its periphery (Wang et al. 2015a), which further affects the gas content of shale. There is a slightly negative correlation between clay content and organic carbon content. Therefore, Nie et al. (2011) believes that with the increase of clay content, the adsorbed gas content of shale shows a slightly downward trend. In addition, there are micropores in clay minerals, illite, illite/montmorillonite and chlorite with certain specific surface areas, which can be used as adsorption media for organic matter and one of the main adsorption media for adsorbing gas (Xue et al. 2013). It can be seen that the type and content of clay minerals not only affect the organic matter content, but also affect the adsorption and adsorption gas volume of shale. In addition, the change of rock mineral composition affects the rock mechanical properties and pore structure of shale. Compared with quartz and carbonate, clay minerals have more micropores and larger surface area and have stronger adsorption capacity for shale gas. As seen from the three-dimensional relationship diagram of quartz, organic matter content and adsorbed gas content, the organic matter content of rock increases with the increase of quartz content, and the adsorbed gas content of shale also increases with the increase of quartz content (Fig. 2.3, according to enterprise internal report). The content of clay minerals and quartz is positively correlated with adsorbed gas, while quartz content is negatively correlated with clay mineral content. When studying the relationship between mineral composition and shale gas content, it is necessary to find a favorable range between clay minerals, quartz and carbonate content.

Fig. 2.3
figure 3

Three-dimensional diagram of quartz, TOC and absorbed gas content in black rocks (according to the internal data)

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2.3.5 Reservoir Characteristics

The volume and aperture of micropores and fractures in shale are the main storage space of free gas in shale. The distribution and volume of the pores and fractures can significantly affect the occurrence form of shale gas and control the content of free gas in shale. Organic pores and intergranular pores of clay minerals are the two pore types with most wide development in shale, which are of great significance for gas adsorption and storage. Microfractures are not only the storage space of free gas, but also the main channel of gas seepage (Yang et al. 2013). Chalmers et al. (2012) believe that porosity is positively correlated with the total shale gas content; thus, the total shale gas content increases with the increase of shale porosity. Ross et al. (2009) found that when the porosity increased from 0.5 to 4.2%, the content of free gas increased from 5 to 50%.

Shale is a low porosity and ultralow permeability reservoir, and its permeability is generally less than 0.01 × 10−3 μm2. However, with the development of microfracture system, the permeability of rock is increased significantly, and the relative accumulation of free shale gas is larger. Barnett shale gas in North America is related to the development of microfracture system, and its free gas content accounts for about 55–75%. This is mainly because the natural microfractures in Barnett shale developed. Although most of them are cemented by calcite, the fractures in the rock can be effectively increased after fracturing, thus increasing the permeability of the rock.

2.3.6 Burial Depth and Formation Pressure

Lin et al. (2012) tested isothermal adsorption of 21 core samples with different TOC content of the Longmaxi shale in the southeast of Chongqing region. The results revealed the relationship among shale buried depth, gas content and the TOC under the condition of the organic matter maturity. With the same depth, the higher the shale content of TOC value is, the higher adsorbed gas content is. If TOC value is constant, the shale adsorbed gas content increases gradually with the increase of burial depth and formation pressure, and the increase rate decreases when it reaches about 1200 m. And the adsorbed gas content gradually stabilizes and tends to a constant value. In order to achieve the same gas content, the shallower the burial depth is, the higher TOC content is required, that is, the shale burial depth and adsorbed gas content have a mutual compensation relationship.

Formation pressure is also a factor affecting shale gas production. The amount of gas absorbed in shale is also affected by formation pressure. Studies show that there is a positive correlation between formation pressure and adsorbed gas capacity, and the higher formation pressure is, the greater the adsorption capacity is and the higher the adsorbed gas content is (Wang et al. 2010; Bai et al. 2011). Free gas content also increases with the increase of pressure, and the two basically show a linear relationship (Wang et al. 2010). Hu et al. (2014) believes the shale gas accumulation is endogenous. As hydrocarbon generation increases shale pore pressure and leads abnormal high pressure in the hydrocarbon source rocks, by action of abnormal pressure and hydrocarbon concentration difference, hydrocarbon always migrates outside, if the sealing ability for shale gas is poor, shale gas discharge greatly and pressure reduced quickly too, and form low pressure shale formation. Otherwise, a good sealing ability will lead a higher formation pressure and shale gas will be maintained. Therefore, formation pressure coefficient is a good indicator of shale gas preservation conditions. Pressure coefficient is a comprehensive discriminant index of preservation conditions, and there is a positive correlation between pressure coefficient and shale gas production (Hu et al. 2014). When the local pressure rises to a certain degree, the microfractures is also a good storage space for shale gas (Bai et al. 2011). The total gas content of organic-rich shale increases with the increase of pressure. Adsorbed gas increases rapidly under low pressure. When the pressure reaches a certain level, the increased rate slows down significantly, while free gas still increases significantly and becomes the main body of shale gas (Li et al. 2011). If shale reservoir pressure is abnormally high, it means that a large amount of oil and gas has been generated in shale, and there may be no large-scale migration or loss in geological history. High shale reservoir pressure also means high shale gas content and initial production (Wang et al. 2013b).

Li et al. (2011) proposed that pressure is directly related to burial depth. For shale gas play, in stable structure areas, the higher the burial depth is, the higher the formation pressure is. This also coincides with the proposition of Shirley (2001), Pu et al. (2010) and Li et al. (2011). They proposed that organic carbon content and formation pressure are the most important factors affecting shale adsorption capacity.

2.3.7 Storage Conditions

Compared with conventional reservoir gas, shale gas accumulation belongs to the natural gas without secondary migration or with very short distance secondary migration. It accumulated independently without the help of trap and preservation conditions in the conventional sense (Zhang et al. 2011a, b, c). Shale gas plays are typical in situ accumulation. In the long process of hydrocarbon generation, the natural gas generated firstly meets the adsorption needs of organic matter and clay mineral particles on the surface of rock, and also meets the needs of matrix pores and various reservoir spaces. When the adsorbed gas and dissolved gas reached saturation, the enriched natural gas migrated and dispersed in free or dissolved phases, forming conventional gas reservoirs when conditions are suitable (Nie et al. 2009b; Wang et al. 2010).

Most sedimentary basins in China have experienced superimposed reconstruction of multiphase tectonics in geological history. For a large number of complex structural faults, the structural framework of the original sedimentary basin and the integrity of the original sedimentary strata of organic-rich mudstone/shale, it is very difficult to understand the preservation conditions of shale gas (Nie et al. 2011; Guo et al. 2012). So, the preservation conditions, as an important research content in geological theory, cannot be ignored in China's shale gas exploration and development. Compared with the North American stable tectonic background of sedimentary basin, the shale gas preservation condition is especially content and unique proposition in China’s shale gas geology theory study (Zeng et al. 2011; Li et al. 2013a, b). The key to shale gas exploration in China is to find favorable areas with relatively stable structure, continuous distribution of organic-rich shale and good preservation conditions based on the restoration of prototype basins (Zou et al. 2011). Factors influencing and characterizing the preservation conditions of shale gas include tectonic movement, development degree of faults and microfractures, development characteristics of roof and bottom strata, magmatic thermal events, hydrogeological conditions, current shale pressure, etc. Preservation conditions of shale gas should be considered comprehensively (Li et al. 2009a, b; Nie et al. 2012). However, shale gas reservoir has the characteristics of “self-generation, self-storage and self-capping”, and due to its adsorption properties, it consequently has relatively low requirements for preservation conditions (Chen et al. 2011a, b; Wang et al. 2012a, b). Guo and Liu (2013) analyzed the shale gas reservoir with its characteristics of gas adsorption, physical property, continuous gas accumulation and so on, and combining with the actual shale gas breakthrough of JY1, they believe that shale gas reservoir has relatively weak influences on preservation conditions compared to conventional gas reservoir from the aspects of oil and gas migration channel including porosity, unconformity, fault and so on. Compared with carbonate and sandstone, mudstone/shale usually has characteristics of stronger plasticity and lower permeability; thus, the shale has certain ability to resist tectonic deformation. But when tectonic movement is too strong initiating uplift, denudation, fold, fracture, surface water infiltration or pressure system damage, the sealing and preservation conditions of mudstone/shale become poor (Hu et al. 2014). Therefore, the study of shale gas preservation conditions became one of the important contents for shale gas exploration and development in China. And the research should be based on a recognition using the basin evolution, structure characterization, cap and floor rock development, burial depth and pressure conditions to determine the shale gas preservation condition (Li et al. 2013a, b).

2.3.8 Comprehensive Analysis of Influencing Factors

Organic matter, as hydrocarbon generating material, controls the existence of shale gas reservoirs. In the process of hydrocarbon generation of organic matter, not only natural gas is generated, but also the organic pore is generated as the main storage space, which controls the adsorption potential and gas volume of shale gas. There is a certain correlation between mineral composition and organic matter content, which not only affects the physical properties of shale, but also affects the gas content of shale. Shale storage space and physical properties are mainly affected by organic carbon content, mineral composition and thermal maturity of organic matter and tectonic movement. It can be concluded that shale reservoir characteristics directly affect the gas content. The organic pores and intergranular pores are the main storage spaces. These pores are formed by the extensive transformation of clay minerals and hydrocarbon generation of organic matter when the organic-rich shale enters the middle-diagenetic stage A (Wang et al. 2015b). Therefore, the effective shale reservoir is controlled by organic matter content and comprehensive evolution of organic and inorganic diagenesis. Chen et al. (2013) proposed that the influence of clay minerals on pore formation is far less than TOC and brittle mineral content. And TOC content is the most critical and significant factor influencing pore formation in mudstone/shale. Wu et al. (2015) analyzed the pores in shale samples of Longmaxi Formation and Xujiahe Formation in Southeast Chongqing. The mathematical statistics of the test results showed that pore type was not the main controlling factor of gas content, while TOC was the most essential factor of shale gas reservoirs. It is suggested that the shale gas content is the result of the comprehensive influence of many factors, but the most direct and fundamental factor is the organic matter characteristics, and the content of organic matter is the most important factor.

However, the characteristics of organic matter (like organic carbon content, organic matter type) and the thickness of organic-rich shale are controlled by sedimentary environment or sedimentary facies. The characteristics of mineral composition are also controlled by sedimentary environment. The correlation between mineral composition and organic carbon content is caused by the joint influence of sedimentary environment on them. Therefore, sedimentary environment is the fundamental factor determining the shale gas enrichment. It does not only control the thickness, distribution area, organic matter content and other characteristics of mudstone/shale, but also seriously affect the sedimentary rock types and rock mineral composition. And the differences in rock types and mineral composition determine the characteristics of reservoir physical property development, thus affecting the accumulation of shale gas (Wang et al. 2013a, b, c). Shale gas in Jiaoshiba area has been made a breakthrough, and it is believed that the development of organic-rich shale provides a rich material basis for the generation and storage of shale gas (Guo et al. 2014).

If organic matter has good sealing ability in the process of hydrocarbon generation and expulsion, good shale gas play can be formed, which is characterized by high-pressure or abnormal high-pressure distribution area. In stable tectonic zone, formation pressure is related to burial depth. Therefore, under certain tectonic background, the main geological factors affecting formation pressure are organic carbon content, thermal maturity of organic matter and burial depth. The shale gas play formed under certain tectonic setting and sedimentation. The fine-grained sediments rich in organic matter developed in anoxic, reduction environment; after the diagenetic evolution of water–rock reaction and organic matter, hydrocarbon expulsion, without strongly fracturing damage (kept good seal), the shale gas play formed (Fig. 2.4). Shale gas must be “residual gas” staying in rich organic matter in mudstone/shale. The size of the shale gas play is controlled by the thickness and distribution of fine-grained sedimentary rocks rich in organic matter. And it is showed by the characteristics of the very short migration distance and self-generation and self-storage. And the fine-grained sedimentary rocks are controlled by the sedimentary facies. Therefore, sedimentary facies (lithofacies paleogeography) influence the development of shale gas reservoirs.

Fig. 2.4
figure 4

Related schematic diagram of the factors affecting the shale gas enrichment

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Therefore, to conduct comprehensive shale gas evaluation and favorable area selection, it is necessary to analyze the sedimentary facies, diagenesis and diagenetic evolution with detailed tectonic background understanding, to determine the key factors affecting the enrichment of shale gas reservoirs and to select appropriate parameter criteria. Lithofacies paleogeography, as a comprehensive reflection of facies and paleosedimentary environment, is the main controlling factor and basic element affecting the development of organic-rich shale and should be the basis and key of shale gas geological survey. This study, from analysis of the main geological parameters of shale gas, based on the actual data, choose to sedimentary facies (lithofacies paleogeography) map as basic layout, considered organic carbon content contour map, the rich organic shale thickness contour map and vitrinite reflectance contour map as main control consideration. And take the mineral components (clay minerals, brittle minerals) and the buried depth map of the study area as further restriction, and use the gas content data to correct the conclusion. See Chap. 4 for detailed steps and methods.