2.1.1. Mineral Composition

The rock mechanics, adsorption capacity, and well productivity of shale gas reservoirs are directly determined by the relative content of di fferent minerals due to the property di fferences among the minerals. Taking 18 samples from X1 well, eight samples from X2 well, and 60 samples from X3 well, we tested the mineral compositions using an X'Pert Pro type X-ray scattering di ffractometer produced by PANalytical B.V. (Almelo, The Netherlands) and following the Chinese Oil and Gas Industry Standard SY/T 5163 1995 and SY/T 5983 94. The laboratory temperature is 24 ◦C and the humidity is 30%. The test results are shown in Figure 3. As shown, the main mineral compositions of the Longmaxi Formation are quartz (11–70%, average 31.06%) and clay minerals (7–64%, average 33.87%). Comparing the results with those in the Mississippian Barnett Shale of the Fort Worth Basin in North America [15,16], the content of brittle minerals (such as quartz, feldspar, and calcite) in the Longmaxi Formation is relatively lower, while the content of clay minerals is higher (Figure 4).

**Figure 3.** Relative content of minerals of samples from the Longmaxi Formation in the south Sichuan Basin.

**Figure 4.** Comparison of mineral content between shale samples from the Longmaxi Formation and the Barnett Shale [15,16].

With less clay mineral and more brittle minerals, natural or induced fractures more easily develop under external forces. On the contrary, the higher clay mineral content has a negative e ffect on volume stimulation, since most of the energy is absorbed by shale formations. Under such circumstances, plane fractures are more likely to be generated, rather than tree-like or reticular structural fractures. Generally, the brittle minerals need to be higher than 40% and the clay minerals need to be less than 30% for a potential shale gas reservoir to be commercially developed [16,17].

The content of different minerals also exhibits different trends in terms of formation depth, as shown in Figure 5. For the formation depth increasing from 2120 m to 2250 m, the content of calcite decreases from 12% to 5%, and the content of brittle minerals increases from 28% to 60%. The content of clay minerals increases from 44% to 48% for the formation depth, increasing from 2120 m to 2205 m, while it decreases rapidly from 48% to 8% for formation depth increasing from 2205 m to 2250 m.

**Figure 5.** The relationship between mineral mass content and depth.

The TOC content is determined by a CS230 carbon/sulfur analyzer (LECO, St. Joseph, USA) with samples crushed into powder less than 100-mesh. The powder is pyrolyzed up to 600 ◦C and the inorganic carbon is removed by hydrochloric acid. The relationship between quartz and TOC content can help to explain the origin of quartz, i.e., detrital or biogenic.

There is no linear relationship between detrital quartz and TOC content, while a positive correlation can be found for biogenic quartz and TOC. As shown in Figure 6, the correlation coefficients between quartz and TOC content in X1, X2, and X3 wells are larger than 0.53, indicating that the quartz in the targeted formation is biogenic.

**Figure 6.** The relationship between quartz and TOC contents in Longmaxi Formation.

#### 2.1.2. Organic Geochemical Characteristics of Shale

The organic matter richness, thermal maturity, and kerogen types are three key parameters for the accurate assessment of hydrocarbon-forming conditions. The organic matter richness not only a ffects the hydrocarbon generating strength, but also the development of organic pores and the adsorbed gas content. The lower limit value of the TOC content for economic exploitation of shale gas reservoirs is approximately at 2.5–3 wt % [18]. However, with the development of technology, this value could become even lower.

Measuring 122 samples of TOC content, we find that the TOC content ranges from 0.43% to 8.39%, with an average value of 2.20% in Longmaxi Formation of Sichuan Basin. The samples with a TOC content less than 2.00% account for 57.38%, while 42.62% of samples have a TOC content larger than 2.00%. This reflects the fact that TOC is abundant in Longmaxi Formation, which is advantageous for shale gas generation and storage. However, comparing with shale gas reservoirs in North America, the TOC content in Sichuan Basin is smaller. The TOC content of Antrim shale and New Albany shale is between 1% and 25%, while it is between 0.45% and 4.5% in the Barnett Shale and Lewis Shale [19].

Analyzing the TOC content data of three wells in the Longmaxi Formation longitudinally, we find a positive relationship between TOC content and depth, as shown in Figure 7. The TOC content at the bottom of the formation is much larger than that at the top. The TOC content increases with depth at 2.3–10.0% per 100 m in the targeted formation.

The kerogen types can be classified into sapropelic type (type I), mixed -type (type II), and humic type (type III) [20]. All three types of kerogen can generate natural gas. For type I and II1 kerogen, oil is generated first and then cracked into gas. The type III kerogen is not advantageous for oil generation and gas is formed directly from organic matter [17]. The abundance of organic matter is the material basis for hydrocarbon generation, while the type of organic matter determines the hydrocarbon generating potential and hydrocarbon characteristics.

The thermal evaluation extent of organic matter can be characterized by thermal maturity, reflected by the vitrinite reflectance *R*o, which is the basis of assessing the hydrocarbon generating potential of source rocks (Table 1). The organic matter maturity range of 1.1% < *R*o < 3.5% is advantageous for the generation of shale gas [3,21]. Single well production in more mature shale formations is larger than in less mature ones, because more gas is generated by kerogen or the thermal cracking of crude oil in more mature areas. The average thermal maturity of the targeted Barnett Shale is *R*o = 1.7%, with the maximum value larger than 2.0% [22]. Oil and gas are generated from the kerogen with initial *R*o < 1.1% in the Barnett Shale, but gas is produced within the formation in the Newark East and surrounding areas at higher thermal maturity, i.e., *R*o > 1.1% [23]. The e ffect of organic matter maturity *R*o on shale gas reservoirs is very complicated and needs further study.

**Table 1.** Characterization of thermal evaluation of organic matter [24].


The *R*o of the Longmaxi Shale Formation in the Sichuan Basin ranges from 2.4 wt % to 4.0 wt %, mainly in the stage of high maturity and overmaturity.

**Figure 7.** The frequency distribution histogram of TOC content as well as its relationship with depth in the Longmaxi Formation.

#### *2.2. Porosity and Permeability Characterization*

Porosity and permeability are the two most important parameters to characterize gas storage and seepage capacities in shale gas reservoirs. Compared to conventional reservoirs, shale gas reservoirs are ultra-tight formations with extremely low porosity and permeability. Corresponding formation physical properties of main shale gas reservoirs in North America are attributed in Table 2 [3,15,18,19,25,26].


**Table 2.** Statistical physical properties of the main shale gas reservoirs in North America [3,15,18,19,25,26].

As the earliest country to commercially develop shale gas resources, the USA has formulated a standard system to evaluate the physical properties of shale formations. The Gas Research Institute (GRI) of America proposed a test method for shale cores to determine both the total porosity and the gas-bearing porosity of the shale matrix. Generally, the porosity range of shale formations is between 2% and 15%. From the statistical data in Table 2, we can see that the total porosity of shale formation in North America is between 2% and 14%, and the average value is between 4.22% and 6.51%. Following the procedure of GRI, the statistical results of measured gas-filled porosity is between 1% and 7.5%, and water-filled porosity is between 1% and 8% in the Longmaxi Formation. The permeability of measured samples in the Longmaxi Formation is less than 0.1 mD, and the average pore-throat radius is smaller than 0.002 μm.

#### *2.3. Pore Structure Division*

Pore structures in shale formations can roughly be divided into two types: matrix pores and fractures (Table 3). Matrix pores are the main storage space of shale gas, directly determining the reserve of a shale gas reservoirs. The development of fractures as well as the connectivity of pores determines the gas-transporting and -producing capabilities [27].

Loucks et al. [28] studied the pore structures of Barnett Shale and concluded that micropores (*d* ≥ 0.75 μm) and nanopores (*d* < 0.75 μm) are the two main pore types. Meanwhile, nanopores were divided into organic pores, intergranular pores, intragranular pores, and mixed pores. Slatt and O'Brien [29] analyzed pore types in the Barnett and Woodford Shale and the main pore types were intergranular pores of clay minerals, micropores in organic matter, pores in fecal spherulites, pores in bioclastic, and intergranular micropores. According to pore sizes, Loucks et al. [30] divided mudrock pores into: picopores (*r* < 1 nm), nanopores (1 nm < *r* < 1 μm), micropores (1 μm < *r* < 62.5 μm), mesopores (62.5 μm < *r* < 4 mm), and macropores (4 mm < *r* < 256 mm).


**Table 3.** Classification of storage space in shale formation.

Based on previous studies [16,28–31], we came up with a new classification method of gas storage space in shale formations in this paper by comprehensively utilizing core observation, thin-section analysis, SEM analysis, and emission scanning electron microscopy after argon ion polishing technologies. The main storage and seepage space in shale formations can be classified into fractures and matrix pores (Table 3). According to the origin mode, matrix pores are further divided into inorganic pores and organic pores, among which inorganic pores include intergranular pores and intragranular pores. Fractures can be classified into tectonic extensional fractures, tectonic shear fractures, interlayer bedding fractures, rock convergen<sup>t</sup> fractures, and abnormal pressure fractures (Table 3).

**Figure 8.** Different types of pores or fractures in the Longmaxi Shale Formation. (**a**) Tectonic extensional fractures. (**b**) Tectonic shear fractures. (**c**) Interlayer bedding fractures. (**d**) Rock convergen<sup>t</sup> fractures. (**e**) Abnormal pressure fracture. (**f**) Intergranular pores. (**g**) Clay interslice pores. (**h**) Intercrystalline pores of pyrite. (**i**) Marginal pores. (**j**) Dissolved pores of pyrite. (**k**) Cleavage crack of clay minerals. (**l**) Biogenetic pores.

#### *2.4. Pore Size Distribution and Influential Factors*

Gas storage and seepage mechanisms vary significantly due to the difference of pore sizes. Clear knowledge of pore size distribution (PSD) in shale formations is essential for shale gas exploitation and development. MICP, gas adsorption, and NMR are three commonly used methods to determine PSD. In this section, the principles and results of different methods will be introduced and analyzed, based on the measurements of samples from the Longmaxi Formation in Sichuan Basin, China.

#### 2.4.1. Test Methods and Principles
