# Marine Shale Gas Occurrence and Its Influencing Factors: A Case Study from the Wufeng-Longmaxi Formation, Northwestern Guizhou, China

Authors: Taotao Cao; Hu Liu; Anyang Pan; Mo Deng; Qinggu Cao; Ye Yu; Yanran Huang; Zhenghui Xiao
Journal: Geofluids
 (2022)

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## Abstract

Organic-rich shales were found in the Ordovician to Silurian Wufeng-Longmaxi Formation in northwestern Guizhou province, China, which has high shale gas content revealed by field measurement. Shale gas occurrence, free gas/sorbed gas ratio, and their influencing factors are crucial for shale gas exploitation strategy. Results indicated that the Wufeng-Longmaxi shales are dominated by type I kerogen, with total organic carbon (TOC) and equivalent vitrinite reflectance (eqvRo) of 0.77%–6.98% and 2.37%–2.53%, respectively. The total porosity and permeability are in the range of 1.23%–8.43% and3×10−4–2.23×10−1 mD, respectively. FE-SEM observation and correlation analysis show shale porosity is dominated by organic matter (OM) pores, followed by interparticle (interP) pores related to brittle minerals. CH4, derived from oil cracking, is the main component of shale gas, but its proportion is lower than that in Fuling and Weiyuan areas, probably due to the weak preservation condition. Desorption gas and lost gas determined by in situ desorption test are 0.42–1.54 cm3/g and 1.9–7.14 cm3/g, respectively, and Langmuir volume (VL) from isothermal adsorption experiment is 1.63–4.78 cm3/g. Shale gas content is positively correlated with micropore volume, mesopore volume and TOC content but negatively correlated with macropore volume and clay mineral content, indicating that methane is preferentially stored in micropores (<2 nm) and mesopores (2–50 nm) related to OMs. By comparing actual total gas content with theoretical gas content, shale gas is considered to exist primarily in sorbed state, and the free gas proportion can increase with increased TOC content, due to that OM pores with larger sizes are also main space for free gas. Combined with the two methods, it can result in accurate calculations of shale gas reserves and free/sorbed gas ratio. Based on this understanding, a model of shale gas occurrence was proposed, which can provide a reference for shale gas exploitation in normal pressure areas.


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## Body

## 1. Introduction

Current energy patterns indicate that shale gas plays more and more important role in energy consumption in the USA, and this trend stimulated the enthusiasm for shale gas exploration and development in China [1–4]. In the last ten years, China has obtained notable achievements in shale gas evaluation and exploration. In 2018, the Sichuan Basin had an industrial output of shale gas of 10.8×109m3 from marine shale gas reservoirs [5]. In this situation, increasing interest is also being attracted to transitional and continental shale gas reservoirs in China, with 2/3 China’s shale gas generated and stored in transitional and continental shales [6, 7]. However, in addition to the Sichuan Basin, other regions that contain thick layers of shale gas reservoirs have no significant breakthrough in shale gas exploration, except for the Wujiaping Formation in western Hunbei province. The marine shale gas in South China is also facing many problems and challenges, because gas content in different regions and different intervals is quite different [8]. To further explore whether it has shale gas potential, investigating shale gas accumulation mechanism and preservation condition is necessary [4, 9] and is also of great importance to shale gas development.Evaluating the shale gas-bearing capacity is the foundation for resource assessment, commercial exploitation, and production forecasting [10, 11]. Unlike conventional natural gas, shale gas has two components: free gas and sorbed gas. Free gas is mainly stored in fractures, mineral pores and organic matter (OM) pores, and sorbed gas exists in nanoscale OM pores and clay mineral pores [12, 13]. Sorbed gas has been studied intensively in the last decade, mainly by experiments and molecular simulations [14, 15], and total organic carbon (TOC) is deemed as a main contributor to sorbed gas content [16], due to that OM is a critical contributor to the development and evolution of pores [17, 18]. Free gas content is the key factor to determine the high yield and final recovery of shale gas wells [19]. Recently, free gas is deemed to be mainly stored within OM-hosted pores rather than mineral-related pores [20]. With increased TOC content, the ratio of free gas is higher, due to that high TOC content can contribute more OM pores>3nm for free gas storage [20]. The total gas in a shale reservoir refers to not only methane but also other hydrocarbon and nonhydrocarbon gases [13]. A sufficient gas content, gas saturation, and thickness are key factors in determining the economic feasibility of shale gas exploration and recovery [21, 22].Shale gas content evaluation can be obtained through several means: the logging interpretation [23], nuclear magnetic resonance (NMR) technique [24], isothermal adsorption method [19], and in-situ gas desorption [25, 26]. Logging interpretation gas content does not take into account vertical or lateral variations of mineral compositions, resulting in larger prediction results than actual gas content [27]. NMR method is used to define sorbed/free gas contents in recent years, which is well consistent with isothermal adsorption experiment [24]. However, these methods are not examined by actual gas content. The isothermal adsorption method is widely used according to the combination with Langmuir volume model. Isothermal adsorption method obtains sorbed gas content by simulating methane adsorption process in shale samples, and free gas content is calculated based on shale porosity and water saturation under the actual formation pressure and temperature [28–30]. This method is an indirect approach to achieving shale gas content due to its simplicity and convenient [26]. However, there is an obvious defect with this method, because this method often overestimates the shale gas content under actual geological conditions. As a constant, in situ gas desorption is a direct mean to acquire the gas content of a shale well, which has been more and more used to evaluate the gas-in-place content and free/sorbed gas ratio for shale reservoir [31, 32]. During the in situ desorption process, shale gas contains three forms of gases: lost gas, desorption gas, and residual gas in terms of desorbed time [33–35]. Residual gas content is very low and generally negligible. Therefore, shale gas estimation refers mainly to lost gas and desorption gas [32]. Measuring in situ desorption requires strict operational procedures. Pressure holding core technology and drilling time can both cause free gas escape during sampling process. Therefore, this method can obtain desorption gas directly, and lost gas is acquired indirectly according to desorption gas content versus desorption time [36].Quantitative analyses of free gas and sorbed gas content in shale reservoirs are of great significance for efficient exploration and development of shale gas. There have been a great number of previous studies that attempted to calculate free and sorbed gas. Gou et al. [19] proposed a new model for calculating sorbed gas and free gas in terms of isothermal adsorption experiment and grey correlation theory. However, the gas content estimated using the methane adsorption isotherm is not accurate [36]. Particularly, the sorbed gas content is significantly controlled by temperature and pressure. Therefore, experimental temperature should be corrected when it is different with actual stratum temperature. Free gas is also influenced by adsorption capacity, because the free gas volume that is calculated by subtracting the sorbed gas volume from the total gas volume. Many scholars have adopted isothermal adsorption experiment jointly combined with in situ desorption measurement to predict shale gas reserves and free/sorbed gas ratio. For in situ gas desorption measurement, it cannot give free gas and sorbed gas content, but it can be evaluated based on desorption data [31]. It is extremely important to confirm time zero and lost gas time, because these variables have significant influences on lost gas content calculation [37]. Therefore, in situ desorption measurements should be implemented right away when the core samples are collected from the wellbore [38]. Meanwhile, the lost gas content obtained through using different methods can vary greatly, and which method used to calculate lost gas is still in dispute [36]. Currently, in situ gas desorption test is still lacking due to the difficult field environment and high cost, and therefore, in situ desorption gas characteristics, occurrence, and significance are not clear [39–41].With the continuous exploration and understanding of shale gas, the deep shale gas in the Sichuan Basin and shale gas reservoir outside Sichuan Basin have attracted extensive attention [42, 43]. In this study, high-pressure methane adsorption and in situ desorption gas tests were conducted on the Wufeng-Longmaxi shales from normal pressure area in northwestern Guizhou, in order to better characterize shale gas desorption process, estimate shale gas content, and get a better understanding of shale gas storage and transport mechanism. We will compare the results of the two methods to get a more precise estimation of shale gas. The methane adsorption capacity and in situ desorption gas content will be discussed with TOC, mineralogical composition, water saturation, and pore structure parameters, to reveal which factor controls shale gas occurrence and content. This study would provide a reference for shale gas exploration and exploitation in normal pressure area around Sichuan Basin.


## 2. Geological Background

The northwestern Guizhou region is situated in the central Guizhou uplift, north of the Yunan-Guizhou depression (Figure1). During the central Guizhou uplift, the Longmaxi stratum was extensively eroded in the central and the south of northwestern Guizhou. During the early Longmaxi Formation, sea water gradually retreated from south to north, and a tidal flat, a shallow water shelf, and a deep water shelf facies were developed in that order (Figure 2). In the north region, organic-rich shales were deposited within lower Longmaxi Formation. During the late Longmaxi Formation, the zone of the central Guizhou uplift was enlarged, the sea water level became shallower, and the terrigenous detritus from the provenance area gradually increased. The Longmaxi Formation shale has a maximum thickness of 80 m located in the Xishui area, whereas there are only several to tens of meters in the Fenggang-Suiyang area. In the Meitan area, the Longmaxi Formation shale is not present. Previous studies have illustrated that the Wufeng-Longmaxi shales are dominated with type II1 kerogen, with averaged TOC of 2.65% and thermal maturities (Ro) of 2.41%–3.08% [44]. The organic-rich shales of the Wufeng-Longmaxi Formation areas are as high as 4% and are regarded as potential shale gas intervals [45].Figure 1
(a) Location map showing the Guizhou province, (b) tectonic framework of the Guizhou province (after [46]) and well site of LY1 well, and (c) distribution of sedimentary facies of the Longmaxi Formation (after [47]).Figure 2
Comparison diagrams of stratigraphic columns of the Wufeng-Longmaxi Formation in northwestern Guizhou province (modified from [45, 48]).


## 3. Sample Information and Measurements

### 3.1. Sample Information

80 samples with the depth of 2058.78–3027.77 m were collected from the LY1 well, which are divided into bioclastic limestone, carbonaceous shale, and argillaceous shale (Figure2). The Longmaxi Formation is divided into lower member and upper member according to changes in sedimentary environments and lithofacies. The lower member is deep-water deposits dominated by black organic-rich shale, and the upper member is shallow-water deposits characterized by argillaceous shale.


### 3.2. Geochemical Analysis

TOC was achieved using a LECO CS 230instrument. Pyrobitumen reflectance (Rb) and maceral composition were measured on kerogen powders using a MPV-SP microphotometer. Powdered samples were conducted on an X-ray diffraction (XRD) analyzer to obtain mineral compositions by a semiquantitative method.


### 3.3. Nitrogen as Adsorption (N2GA) Analysis

Nitrogen gas adsorption analysis was performed on a Micrometrics ASAP-2020 instrument. Sample with 1–2 g was placed into a vacuum and degassed at 110°C for 12 h to remove moisture. Liquid nitrogen (-196.15°C) was used for this experiment. Surface area was calculated with the Brunauer–Emmett–Teller (BET) method, volume and pore size distribution were achieved according to the Barrett–Joyner–Halenda (BJH) and the density–functional–theory (DFT) methods, respectively.


### 3.4. Helium Porosity Test

Cylindrical plugs with length and height of about 2.5 cm and 3.5 cm, respectively, were used to measure porosity by a QK-98 porosimeter. Bulk density and grain density were determined from geometric dimensions of samples and using a helium pycnometer, respectively, and the porosity is calculated as 1-(bulk density/grain density).


### 3.5. SEM Imaging

16 shales were mechanically ground to a level surface by sandpaper and subsequently polished with argon ion beam to provide superflat surface. These treated samples were performed using a ZEISS GEMINI-300 FE-SEM instrument with an accelerating voltage of 10 kV and a working distance of 6–10 mm to observe shale pore morphology, location, size, and distribution. This instrument has a high resolution and is capable of imaging pores down to 5 nm [47, 49].


### 3.6. Water Saturation

A DYP-2 instrument was used to measure water saturation quickly in terms of Chinese National Standard GB/T 29172-2012. The process is to heat sample to a certain temperature to acquire water vapor and then to obtain water volume after condensation. Lastly, according to pore parameters, water saturation was calculated.


### 3.7. High-Pressure Methane Adsorption Experiment

Methane adsorption tests were performed by a Rubotherm IsoSORP-HP Static II gas adsorption instrument, with precision of 10μg. Approximately 5 g of samples with 150 μm sizes were heated at 110°C for 12 h to eliminate adsorbed water. In this study, the temperature was set to 93°C according to the depth of LY1 well. The principle diagram and detailed experimental procedures were referred to [50, 51]. The sorption capacity is expressed as: Vabs=Vex (1−ρg/ρa). Here, Vabs is the absolute sorption capacity, Vex is the excess sorption capacity, ρg and ρa are free methane density and sorbed methane density, respectively. The revised ternary Langmuir equation, Vex=VL×P/PL+P×1−ρg/ρa, was adopted to fit the sorption isotherm curve.


### 3.8. In Situ Desorption Test

38 samples were selected to carry out in situ desorption test. In order to avoid gas escaping, pressure coring was adopted until the core reached the ground and then was immediately put into a sealed desorption canister immersed in a water bath with temperature of 70°C (circulation temperature of drilling fluid) (Figure3). Gas volume was measured by a graduated cylinder in the canister at a normal pressure. However, shale gas is not completely released at this temperature. Therefore, reservoir temperature of 93°C was adopted to accelerate gas released from core samples. Gas volume with less than 5 ml within 2 hours means that the desorption process is over [32]. The desorption process would generally last several days (3–4 days). The lost gas was estimated by the USBM method [36].Figure 3
Interior structure of the instrument showing the process of desorption gas released by water displacement.


## 3.1. Sample Information

80 samples with the depth of 2058.78–3027.77 m were collected from the LY1 well, which are divided into bioclastic limestone, carbonaceous shale, and argillaceous shale (Figure2). The Longmaxi Formation is divided into lower member and upper member according to changes in sedimentary environments and lithofacies. The lower member is deep-water deposits dominated by black organic-rich shale, and the upper member is shallow-water deposits characterized by argillaceous shale.


## 3.2. Geochemical Analysis

TOC was achieved using a LECO CS 230instrument. Pyrobitumen reflectance (Rb) and maceral composition were measured on kerogen powders using a MPV-SP microphotometer. Powdered samples were conducted on an X-ray diffraction (XRD) analyzer to obtain mineral compositions by a semiquantitative method.


## 3.3. Nitrogen as Adsorption (N2GA) Analysis

Nitrogen gas adsorption analysis was performed on a Micrometrics ASAP-2020 instrument. Sample with 1–2 g was placed into a vacuum and degassed at 110°C for 12 h to remove moisture. Liquid nitrogen (-196.15°C) was used for this experiment. Surface area was calculated with the Brunauer–Emmett–Teller (BET) method, volume and pore size distribution were achieved according to the Barrett–Joyner–Halenda (BJH) and the density–functional–theory (DFT) methods, respectively.


## 3.4. Helium Porosity Test

Cylindrical plugs with length and height of about 2.5 cm and 3.5 cm, respectively, were used to measure porosity by a QK-98 porosimeter. Bulk density and grain density were determined from geometric dimensions of samples and using a helium pycnometer, respectively, and the porosity is calculated as 1-(bulk density/grain density).


## 3.5. SEM Imaging

16 shales were mechanically ground to a level surface by sandpaper and subsequently polished with argon ion beam to provide superflat surface. These treated samples were performed using a ZEISS GEMINI-300 FE-SEM instrument with an accelerating voltage of 10 kV and a working distance of 6–10 mm to observe shale pore morphology, location, size, and distribution. This instrument has a high resolution and is capable of imaging pores down to 5 nm [47, 49].


## 3.6. Water Saturation

A DYP-2 instrument was used to measure water saturation quickly in terms of Chinese National Standard GB/T 29172-2012. The process is to heat sample to a certain temperature to acquire water vapor and then to obtain water volume after condensation. Lastly, according to pore parameters, water saturation was calculated.


## 3.7. High-Pressure Methane Adsorption Experiment

Methane adsorption tests were performed by a Rubotherm IsoSORP-HP Static II gas adsorption instrument, with precision of 10μg. Approximately 5 g of samples with 150 μm sizes were heated at 110°C for 12 h to eliminate adsorbed water. In this study, the temperature was set to 93°C according to the depth of LY1 well. The principle diagram and detailed experimental procedures were referred to [50, 51]. The sorption capacity is expressed as: Vabs=Vex (1−ρg/ρa). Here, Vabs is the absolute sorption capacity, Vex is the excess sorption capacity, ρg and ρa are free methane density and sorbed methane density, respectively. The revised ternary Langmuir equation, Vex=VL×P/PL+P×1−ρg/ρa, was adopted to fit the sorption isotherm curve.


## 3.8. In Situ Desorption Test

38 samples were selected to carry out in situ desorption test. In order to avoid gas escaping, pressure coring was adopted until the core reached the ground and then was immediately put into a sealed desorption canister immersed in a water bath with temperature of 70°C (circulation temperature of drilling fluid) (Figure3). Gas volume was measured by a graduated cylinder in the canister at a normal pressure. However, shale gas is not completely released at this temperature. Therefore, reservoir temperature of 93°C was adopted to accelerate gas released from core samples. Gas volume with less than 5 ml within 2 hours means that the desorption process is over [32]. The desorption process would generally last several days (3–4 days). The lost gas was estimated by the USBM method [36].Figure 3
Interior structure of the instrument showing the process of desorption gas released by water displacement.


## 4. Results

### 4.1. Geochemical Characteristics

#### 4.1.1. Mineralogical Compositions

Mineral compositions of the studied shales are displayed in Figure4, which are primarily consisted of clay minerals, quartz, and carbonates. Quartz has a high content of 21–58%, averaged 33.28%. Carbonate content in the studied shales ranges from 4% to 25%, and in limestones in the Wufeng Formation ranges from 30% to 55%. Clay mineral content varies from 16% to 62%, averaged 42.84%. Feldspar and pyrite have minor contents, with values of 1%–5% and 2%–15%, respectively. Illite, ranging from 35% to 94%, is the main component in the clay minerals. I/S mixed layer and chlorite have mean values of 16.03% and 18.73%, respectively. Brittle minerals, including quartz, carbonate, and pyrite, display an increasing trend with burial depth. Particularly, the Wufeng Formation and the lower member of the Longmaxi Formation have a low content of clay minerals.Figure 4
Vertical variability of TOC, mineral compositions, water saturation, BET surface area, pore volume, He-porosity, and permeability of the Wufeng-Longmaxi shales in LY1 well.


#### 4.1.2. Organic Geochemistry

As shown in Figure4, the TOC content of 80 studied samples varies from 0.57% to 6.98%, averaged 2%. There are great differences in TOC contents within the upper member and the lower member of the Longmaxi Formation. The upper Longmaxi Formation is identified as shallow-water shelf facies and argillaceous shale, and therefore, the shales are generally poor in OM. The lower Longmaxi Formation was formed in deep-water shelf environment and characterized by carbonaceous shale, which give rises to a high content of TOC [52]. Previous studies reported that quartz content correlates differently with TOC in siliceous shales and argillaceous shales [53]. A positive relationship occurs between TOC and quartz contents in the studied shales when TOC>2% (Figure 5), indicating that partial quartz is derived from biological silica [53]. However, no obvious relationship occurs in the samples with TOC<2%, suggesting that limited biological silica contributes to quartz in organic-poor shales.Figure 5
Cross-plot of TOC and quartz contents of the Wufeng-Longmaxi shales in LY1 well compared with other wells from published wells.The eqvRo value is derived from the Rb value in terms ofeqvRo=0.3195+0.6190Rb [54]. The eqvRo values are in the range of 2.37%–2.53%, averaged 2.46%, indicating that the shales are at a high to overmature stage. The Wufeng-Longmaxi shales are dominated by sapropelinite, which accounts for 94%–96% of the total macerals. In addition, minor vitrinite was also detected in the studied samples. Accordingly, the kerogen of the studied shales is considered to be type I kerogen.


### 4.2. Shale Pore Property

#### 4.2.1. Pore Types and Morphologies

Shale pores can be divided into OM pores, interparticle (interP) pores, intraparticle (intraP) pores, and microcracks [55]. FE-SEM observations indicate that OM pores are the dominated pore type in the studied shales (Figures 6(a)–6(h)). IntraP pores related to brittle minerals and microcracks are also developed (Figures 6(f), 6(l), 6(m)–6(o), and 6(p)). Clay mineral pores are poorly developed compared with brittle mineral pores (Figures 6(g) and 6(m)).Figure 6
FE-SEM images displaying pore types in the Wufeng-Longmaxi shales. (a–d) abundant OM pores with varied sizes within solid bitumen that generally fills in mineral pores; (e) subnanometer OM pores developed within depositional OM; (f) solid bitumen exists with pyrite framboids and forms OM/pyrite complexes that contain abundant OM pores; (g) OM occurs with clay minerals and forms OM/clay complexes in which abundant OM pores with smaller sizes are developed; (h–i) OM grains occur with accessory minerals and form OM/mineral complexes, e.g., OM/rutile complexes and OM/apatite complexes; (i–j) few pores within fossil fragments, mainly graptolite fragments; (l) pyrite framboids and index mineral of anoxic deep-water environments contain a certain amount of intercrystalline pores with hundreds of nanometers; (m) flocculated pores are disorderly distributed within clay minerals; (n and o) dissolution pores with poor connectivity caused by organic acids existing within/along carbonate grains; (p) microcrack is within shale matrix and is often filled by solid bitumen.
(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)(n)(o)(p)OM pore development is considered to be a result of hydrocarbon generation with increased maturation levels [55, 56]. Loucks et al. [55] pointed out that OM pores are developed when thermal maturity is higher than 0.6%. In this study, the shales have an eqvRo of 2.37–2.53%, which can promote OM pore development. As shown in Figure 6, OM can be divided into depositional OM, solid bitumen, and graptolite, which have different influences on OM pore development.Solid bitumen, with no specific shape, is the main component in highly mature organic-rich shales and generally fills in interP pores related to brittle minerals [57]. Solid bitumen forms an OM pore network among interP pores in shale (Figures 6(a)–6(c)). Therefore, interP pore shape determines the filled solid bitumen shape, as well as OM pore distribution. The solid bitumen has a size generally smaller than 10 μm and uniform internal structures [58, 59], which can significantly increase shale pore complexity. OM pores develop within solid bitumen are circular and elliptical (Figures 6(a)–6(d)), and they are more developed than other types of OM.As reported by [37], depositional OM shape can change from isolated individual grains to local concentrations of grains. The depositional OM generally has a fixed outline which does not change with hydrocarbon generation processes. This type of OM usually ranges from several microns to several tens of microns. In comparison to solid bitumen, depositional OM also contains numerous pores which are much smaller than solid bitumen (Figure 6(e)). These OM pores are not easily recognized, even under the resolution of FE-SEM instrument. These OM pores have a limited contribution to total porosity.In addition to individual OM grains, solid bitumen and depositional OM can occur with mineral grains and form an OM/inorganic mineral complex, e.g., OM/pyrite complex, OM/clay complex, OM/rutile complex, and OM/apatite complex (Figures6(f)–6(i)). OM pores are well developed within OM/pyrite complexes (Figure 6(f)), probably due to that pyrite crystals can resist compaction and protect OM pores [58]. However, fibrous illite is easily compacted during burial, and hence, OM pores are poorly developed in OM/clay complexes (Figure 6(g)). OM fills the pore spaces and cracks of the rutile and apatite (Figures 6(h) and 6(i)), accompanied with OM pores distributed within OM/rutile and OM/apatite complexes. Because the crystal particles are tight, OM pores are smaller than those within OM/pyrite complexes.Graptolites or fossil fragments can be observed in the Wufeng-Longmaxi shales and are regarded as paleontological features. Fossil fragments and graptolites, with several micrometers, have fixed shapes, and rare pores can be observed in fossil fragments and graptolites (Figures6(j) and 6(k)). Fossil fragments and graptolites refer mainly to a particular group of skeletons and organisms, dominated with collagen [59, 60]. They have low hydrocarbon generation capacities, similar to type II-III kerogens [61]. However, Luo et al. [62] and Tenger et al. [63] observed a small number of pores in some graptolites, probably due to some specific compositions, e.g., cortical bandage in the organisms [58].Inorganic pores are poorly developed in comparison to OM pores. InterP pores between mineral grains are seldom seen, due to strong compaction or cementation. A large proportion of mineral pores are related to pyrites, clay minerals, and carbonates (Figures6(l)–6(o)). Pyrite aggregates can be seen in sizes of several microns and are widely distributed in the studied shales (Figure 6(f)). Intercrystalline pores found within pyrite aggregates (Figure 6(l)) are considered to be the second important pore type [64]. In some cases, intercrystalline pores are filled by solid bitumen and form pore networks with OM pores (Figure 6(f)). Pores associated with clays are widespread among fibrous clay minerals, but most are closed under compaction (Figure 6(m)). This is consistent with Guo and Zhang [65], who found that shale porosity has no significant increase with an increase in clay minerals. Clay mineral pores have good connectivity and can significantly increase shale permeability (Figure 6(m)) [45]. Dissolution pores are generally developed within or along carbonate grains (Figures 6(n) and 6(o)) and have sizes of nanometers to micrometers. Nie et al. [66] systematically summarized dissolution pore types and pointed out that carbonates are the main carriers of dissolution pores. Dissolution pores exhibit a significant role on shale porosity and form an effective connectivity that can provide space for hydrocarbon storage as well as hydrocarbon migration [66]. Microcracks that serve as a migration channel can be observed in the studied shales [55, 67]. Most microcracks are partially cemented by calcite or filled by solid bitumen. Microcracks along the alignment direction of brittle minerals can extend as long as 20 μm, and they can contribute significantly to shale gas migration by improving permeability [68].


#### 4.2.2. Pore Structure Parameters and Water Saturation

Pore structure parameters and porosity of the studied samples are displayed in Figure4. BET surface area and pore volume are in the range of 10.7–35.65 m2/g and 0.014–0.026 cm3/g, averaged 16.96 m2/g and 0.017 cm3/g, respectively. The total porosity and permeability are in the range of 1.23%–8.43% and 0.0003–0.2232 mD, averaged 3.65% and 0.043 mD, respectively. BET surface area and porosity have a significant increasing trend with increasing depth (Figure 4), which is consistent with the variation of TOC content. The permeability varies greatly among the samples and exhibits no significant change with increased porosity. The Wufeng-Longmaxi shales have water saturations of 18.41%–69.33%, averaged 43.87%. Water saturation has an increase trend with increased clay mineral content and a decrease trend with increased TOC content (Figure 4), indicating that water is attracted to hydrophilic clay minerals rather than hydrophobic OMs [69].


### 4.3. In Situ Desorption Gas Characteristics

Total gas refers to the sum of in situ desorption gas and lost gas. The desorption gas is released at fluid circulation temperature and reservoir temperature, and the lost gas is calculated according to the equation of desorption gas data at early time and the square root of time from Figure7(a). The desorption gas content ranges from 0.42 to 1.54 cm3/g. Desorption gas increases rapidly with increased desorption time at the first stage (circulation temperature) and then decreases rapidly with increased desorption time. At the second stage (reservoir temperature), desorption gas has an abrupt increase and then decreases to no significant change (Figure 7(b)). When desorption time is >300 min, it has a limited contribution to desorption gas content. Dang et al. [70] found that the transition of desorption rate was probably caused by variations in the concentration gradient during the desorption process. Yuan et al. [71] found that this phenomenon might be a result of the two-stage gas diffusion process, exhibiting a rapid diffusion from macropores at the early stage and slow a low diffusion from micropores at the late stage. Desorption gas content is low for the upper Longmaxi shales, and desorption gas>1cm3/g generally exists within the Wufeng and lower Longmaxi shales. The lost gas content, in the range of 1.9–7.14 cm3/g, is much higher than desorption gas content. The variations of shale gas content were plotted in Figure 8, and they display an increasing trend with increased burial depth, due to high TOC content and high porosity [32].Figure 7
(a) Total gas curve of in situ desorption versus square root of time, and (b) gas desorption curve with increased desorption time for sample LY1-70. Desorption gas was determined by two steps, at circulation temperature 70°C and reservoir temperature 93°C, and lost gas was obtained by extrapolating 1 h of desorption data to time zero, using a linear fit to the plot of cumulative gas vs. square root of time.
(a)(b)Figure 8
Profiles of desorption gas, lost gas, total gas,VL, and PL of the Wufeng-Longmaxi shales in LY1 well. Desorption gas, lost gas, and total gas were determined by conducting in situ desorption test; VL and PL are Langmuir volume and Langmuir pressure, respectively, determined by performing high-pressure methane adsorption experiments.


### 4.4. High-Pressure Methane Supercritical Adsorption Capacity

The methane adsorption isotherms of 15 samples are displayed in Figure9, and the VL and PL values are shown in Table 1. The excess adsorption capacities increase rapidly to a maximum value at the pressure of around 11 MPa and then decline gradually when the pressure>11MPa (Figure 9(a)). The features of the excess adsorption isotherms have already been studied by [51, 72]. The reason for this phenomenon is that the volume of the sorbed gas phase is not negligible, because the free-phase methane density is similar to the sorbed methane density at high pressures [51]. Using the equation Vabs=Vex (1−ρg/ρa), the absolute adsorption capacities were converted from the excess adsorption capacities and plotted into Figure 9(b), which represents the actual adsorption capacities of the studied shales. The absolute adsorption capacities increase significantly with increased pressure when it is less than 11 MPa and then increase lowly at high pressures. As shown in Table 1, VL and PL values vary from 1.63 to 4.78 cm3/g and 3.45 to5.95 MPa, respectively. The VL value and the variation in TOC have similar trends with burial depth and PL value has an inverse trend compared to TOC (Figure 8), suggesting that TOC is a decisive factor of shale adsorption capacity.Figure 9
Methane isotherms of (a) excess adsorption and (b) absolute adsorption for 15 Wufeng-Longmaxi shales at various depths as fitted by the Langmuir model.
(a)(b)Table 1
Shale composition, water saturation, in situ gas desorption, and methane sorption capacity of the Wufeng-Longmaxi shales in LY1 well.
SamplesDepth (m)FormationTOC (%)Clay mineral (%)Water saturation (%)Desorption gas (cm3/g)Lost gas (cm3/g)Total gas (cm3/g)VL (cm3/g)PL (MPa)LY1-12958.78S1l0.774765.690.422.32.72//LY1-32961.08S1l0.5953/0.423.764.181.635.95LY1-52962.96S1l0.584353.070.482.252.73//LY1-72965.11S1l0.715755.080.552.392.94//LY1-92967.21S1l0.815841.970.513.624.13//LY1-112969.28S1l0.685240.10.532.362.89//LY1-132971.22S1l0.654331.680.532.342.871.925.81LY1-152973.35S1l0.674647.990.532.432.96//LY1-172975.53S1l0.756047.760.582.733.31//LY1-192977.51S1l0.696264.940.582.933.51//LY1-212979.19S1l0.825549.050.663.023.68//LY1-232980.72S1l1.015133.30.542.192.73//LY1-252982.62S1l0.844358.580.522.222.742.035.41LY1-272984.48S1l0.635645.820.532.232.76//LY1-292986.34S1l0.644847.670.522.533.05//LY1-302988.03S1l0.685649.630.62.973.57//LY1-322989.98S1l0.765369.330.632.783.41//LY1-342991.84S1l0.715565.090.622.633.25//LY1-362993.86S1l0.8456/0.683.394.072.365.83LY1-382995.52S1l0.984854.690.743.684.42//LY1-402997.19S1l0.956047.460.622.643.26//LY1-422999.55S1l14867.50.663.44.06//LY1-443001.48S1l1.053366.640.773.54.27//LY1-463003.27S1l1.775046.770.721.92.62//LY1-483004.93S1l0.975040.760.652.092.742.54.71LY1-503006.89S1l2.394641.940.962.63.56//LY1-523008.63S1l3.353536.7812.773.77//LY1-543010.47S1l3.653628.581.012.653.66//LY1-563012.26S1l3.413629.9412.623.623.194.23LY1-583013.84S1l3.073027.771.072.93.973.154.52LY1-603015.5S1l3.583535.021.063.214.273.334.33LY1-633017.22S1l3.633630.311.053.214.263.484.26LY1-663019.13S1l4.9138/1.144.15.244.393.96LY1-703021.19S1l4.943323.431.043.234.273.933.77LY1-733022.91S1l4.82320.461.244.455.693.574.22LY1-763024.89S1l6.982818.411.547.148.684.783.45LY1-793026.61O3w5.421630.871.244.115.353.623.46LY1-803027.77O3w4.163221.251.183.254.433.073.98


## 4.1. Geochemical Characteristics

### 4.1.1. Mineralogical Compositions

Mineral compositions of the studied shales are displayed in Figure4, which are primarily consisted of clay minerals, quartz, and carbonates. Quartz has a high content of 21–58%, averaged 33.28%. Carbonate content in the studied shales ranges from 4% to 25%, and in limestones in the Wufeng Formation ranges from 30% to 55%. Clay mineral content varies from 16% to 62%, averaged 42.84%. Feldspar and pyrite have minor contents, with values of 1%–5% and 2%–15%, respectively. Illite, ranging from 35% to 94%, is the main component in the clay minerals. I/S mixed layer and chlorite have mean values of 16.03% and 18.73%, respectively. Brittle minerals, including quartz, carbonate, and pyrite, display an increasing trend with burial depth. Particularly, the Wufeng Formation and the lower member of the Longmaxi Formation have a low content of clay minerals.Figure 4
Vertical variability of TOC, mineral compositions, water saturation, BET surface area, pore volume, He-porosity, and permeability of the Wufeng-Longmaxi shales in LY1 well.


### 4.1.2. Organic Geochemistry

As shown in Figure4, the TOC content of 80 studied samples varies from 0.57% to 6.98%, averaged 2%. There are great differences in TOC contents within the upper member and the lower member of the Longmaxi Formation. The upper Longmaxi Formation is identified as shallow-water shelf facies and argillaceous shale, and therefore, the shales are generally poor in OM. The lower Longmaxi Formation was formed in deep-water shelf environment and characterized by carbonaceous shale, which give rises to a high content of TOC [52]. Previous studies reported that quartz content correlates differently with TOC in siliceous shales and argillaceous shales [53]. A positive relationship occurs between TOC and quartz contents in the studied shales when TOC>2% (Figure 5), indicating that partial quartz is derived from biological silica [53]. However, no obvious relationship occurs in the samples with TOC<2%, suggesting that limited biological silica contributes to quartz in organic-poor shales.Figure 5
Cross-plot of TOC and quartz contents of the Wufeng-Longmaxi shales in LY1 well compared with other wells from published wells.The eqvRo value is derived from the Rb value in terms ofeqvRo=0.3195+0.6190Rb [54]. The eqvRo values are in the range of 2.37%–2.53%, averaged 2.46%, indicating that the shales are at a high to overmature stage. The Wufeng-Longmaxi shales are dominated by sapropelinite, which accounts for 94%–96% of the total macerals. In addition, minor vitrinite was also detected in the studied samples. Accordingly, the kerogen of the studied shales is considered to be type I kerogen.


## 4.1.1. Mineralogical Compositions

Mineral compositions of the studied shales are displayed in Figure4, which are primarily consisted of clay minerals, quartz, and carbonates. Quartz has a high content of 21–58%, averaged 33.28%. Carbonate content in the studied shales ranges from 4% to 25%, and in limestones in the Wufeng Formation ranges from 30% to 55%. Clay mineral content varies from 16% to 62%, averaged 42.84%. Feldspar and pyrite have minor contents, with values of 1%–5% and 2%–15%, respectively. Illite, ranging from 35% to 94%, is the main component in the clay minerals. I/S mixed layer and chlorite have mean values of 16.03% and 18.73%, respectively. Brittle minerals, including quartz, carbonate, and pyrite, display an increasing trend with burial depth. Particularly, the Wufeng Formation and the lower member of the Longmaxi Formation have a low content of clay minerals.Figure 4
Vertical variability of TOC, mineral compositions, water saturation, BET surface area, pore volume, He-porosity, and permeability of the Wufeng-Longmaxi shales in LY1 well.


## 4.1.2. Organic Geochemistry

As shown in Figure4, the TOC content of 80 studied samples varies from 0.57% to 6.98%, averaged 2%. There are great differences in TOC contents within the upper member and the lower member of the Longmaxi Formation. The upper Longmaxi Formation is identified as shallow-water shelf facies and argillaceous shale, and therefore, the shales are generally poor in OM. The lower Longmaxi Formation was formed in deep-water shelf environment and characterized by carbonaceous shale, which give rises to a high content of TOC [52]. Previous studies reported that quartz content correlates differently with TOC in siliceous shales and argillaceous shales [53]. A positive relationship occurs between TOC and quartz contents in the studied shales when TOC>2% (Figure 5), indicating that partial quartz is derived from biological silica [53]. However, no obvious relationship occurs in the samples with TOC<2%, suggesting that limited biological silica contributes to quartz in organic-poor shales.Figure 5
Cross-plot of TOC and quartz contents of the Wufeng-Longmaxi shales in LY1 well compared with other wells from published wells.The eqvRo value is derived from the Rb value in terms ofeqvRo=0.3195+0.6190Rb [54]. The eqvRo values are in the range of 2.37%–2.53%, averaged 2.46%, indicating that the shales are at a high to overmature stage. The Wufeng-Longmaxi shales are dominated by sapropelinite, which accounts for 94%–96% of the total macerals. In addition, minor vitrinite was also detected in the studied samples. Accordingly, the kerogen of the studied shales is considered to be type I kerogen.


## 4.2. Shale Pore Property

### 4.2.1. Pore Types and Morphologies

Shale pores can be divided into OM pores, interparticle (interP) pores, intraparticle (intraP) pores, and microcracks [55]. FE-SEM observations indicate that OM pores are the dominated pore type in the studied shales (Figures 6(a)–6(h)). IntraP pores related to brittle minerals and microcracks are also developed (Figures 6(f), 6(l), 6(m)–6(o), and 6(p)). Clay mineral pores are poorly developed compared with brittle mineral pores (Figures 6(g) and 6(m)).Figure 6
FE-SEM images displaying pore types in the Wufeng-Longmaxi shales. (a–d) abundant OM pores with varied sizes within solid bitumen that generally fills in mineral pores; (e) subnanometer OM pores developed within depositional OM; (f) solid bitumen exists with pyrite framboids and forms OM/pyrite complexes that contain abundant OM pores; (g) OM occurs with clay minerals and forms OM/clay complexes in which abundant OM pores with smaller sizes are developed; (h–i) OM grains occur with accessory minerals and form OM/mineral complexes, e.g., OM/rutile complexes and OM/apatite complexes; (i–j) few pores within fossil fragments, mainly graptolite fragments; (l) pyrite framboids and index mineral of anoxic deep-water environments contain a certain amount of intercrystalline pores with hundreds of nanometers; (m) flocculated pores are disorderly distributed within clay minerals; (n and o) dissolution pores with poor connectivity caused by organic acids existing within/along carbonate grains; (p) microcrack is within shale matrix and is often filled by solid bitumen.
(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)(n)(o)(p)OM pore development is considered to be a result of hydrocarbon generation with increased maturation levels [55, 56]. Loucks et al. [55] pointed out that OM pores are developed when thermal maturity is higher than 0.6%. In this study, the shales have an eqvRo of 2.37–2.53%, which can promote OM pore development. As shown in Figure 6, OM can be divided into depositional OM, solid bitumen, and graptolite, which have different influences on OM pore development.Solid bitumen, with no specific shape, is the main component in highly mature organic-rich shales and generally fills in interP pores related to brittle minerals [57]. Solid bitumen forms an OM pore network among interP pores in shale (Figures 6(a)–6(c)). Therefore, interP pore shape determines the filled solid bitumen shape, as well as OM pore distribution. The solid bitumen has a size generally smaller than 10 μm and uniform internal structures [58, 59], which can significantly increase shale pore complexity. OM pores develop within solid bitumen are circular and elliptical (Figures 6(a)–6(d)), and they are more developed than other types of OM.As reported by [37], depositional OM shape can change from isolated individual grains to local concentrations of grains. The depositional OM generally has a fixed outline which does not change with hydrocarbon generation processes. This type of OM usually ranges from several microns to several tens of microns. In comparison to solid bitumen, depositional OM also contains numerous pores which are much smaller than solid bitumen (Figure 6(e)). These OM pores are not easily recognized, even under the resolution of FE-SEM instrument. These OM pores have a limited contribution to total porosity.In addition to individual OM grains, solid bitumen and depositional OM can occur with mineral grains and form an OM/inorganic mineral complex, e.g., OM/pyrite complex, OM/clay complex, OM/rutile complex, and OM/apatite complex (Figures6(f)–6(i)). OM pores are well developed within OM/pyrite complexes (Figure 6(f)), probably due to that pyrite crystals can resist compaction and protect OM pores [58]. However, fibrous illite is easily compacted during burial, and hence, OM pores are poorly developed in OM/clay complexes (Figure 6(g)). OM fills the pore spaces and cracks of the rutile and apatite (Figures 6(h) and 6(i)), accompanied with OM pores distributed within OM/rutile and OM/apatite complexes. Because the crystal particles are tight, OM pores are smaller than those within OM/pyrite complexes.Graptolites or fossil fragments can be observed in the Wufeng-Longmaxi shales and are regarded as paleontological features. Fossil fragments and graptolites, with several micrometers, have fixed shapes, and rare pores can be observed in fossil fragments and graptolites (Figures6(j) and 6(k)). Fossil fragments and graptolites refer mainly to a particular group of skeletons and organisms, dominated with collagen [59, 60]. They have low hydrocarbon generation capacities, similar to type II-III kerogens [61]. However, Luo et al. [62] and Tenger et al. [63] observed a small number of pores in some graptolites, probably due to some specific compositions, e.g., cortical bandage in the organisms [58].Inorganic pores are poorly developed in comparison to OM pores. InterP pores between mineral grains are seldom seen, due to strong compaction or cementation. A large proportion of mineral pores are related to pyrites, clay minerals, and carbonates (Figures6(l)–6(o)). Pyrite aggregates can be seen in sizes of several microns and are widely distributed in the studied shales (Figure 6(f)). Intercrystalline pores found within pyrite aggregates (Figure 6(l)) are considered to be the second important pore type [64]. In some cases, intercrystalline pores are filled by solid bitumen and form pore networks with OM pores (Figure 6(f)). Pores associated with clays are widespread among fibrous clay minerals, but most are closed under compaction (Figure 6(m)). This is consistent with Guo and Zhang [65], who found that shale porosity has no significant increase with an increase in clay minerals. Clay mineral pores have good connectivity and can significantly increase shale permeability (Figure 6(m)) [45]. Dissolution pores are generally developed within or along carbonate grains (Figures 6(n) and 6(o)) and have sizes of nanometers to micrometers. Nie et al. [66] systematically summarized dissolution pore types and pointed out that carbonates are the main carriers of dissolution pores. Dissolution pores exhibit a significant role on shale porosity and form an effective connectivity that can provide space for hydrocarbon storage as well as hydrocarbon migration [66]. Microcracks that serve as a migration channel can be observed in the studied shales [55, 67]. Most microcracks are partially cemented by calcite or filled by solid bitumen. Microcracks along the alignment direction of brittle minerals can extend as long as 20 μm, and they can contribute significantly to shale gas migration by improving permeability [68].


### 4.2.2. Pore Structure Parameters and Water Saturation

Pore structure parameters and porosity of the studied samples are displayed in Figure4. BET surface area and pore volume are in the range of 10.7–35.65 m2/g and 0.014–0.026 cm3/g, averaged 16.96 m2/g and 0.017 cm3/g, respectively. The total porosity and permeability are in the range of 1.23%–8.43% and 0.0003–0.2232 mD, averaged 3.65% and 0.043 mD, respectively. BET surface area and porosity have a significant increasing trend with increasing depth (Figure 4), which is consistent with the variation of TOC content. The permeability varies greatly among the samples and exhibits no significant change with increased porosity. The Wufeng-Longmaxi shales have water saturations of 18.41%–69.33%, averaged 43.87%. Water saturation has an increase trend with increased clay mineral content and a decrease trend with increased TOC content (Figure 4), indicating that water is attracted to hydrophilic clay minerals rather than hydrophobic OMs [69].


## 4.2.1. Pore Types and Morphologies

Shale pores can be divided into OM pores, interparticle (interP) pores, intraparticle (intraP) pores, and microcracks [55]. FE-SEM observations indicate that OM pores are the dominated pore type in the studied shales (Figures 6(a)–6(h)). IntraP pores related to brittle minerals and microcracks are also developed (Figures 6(f), 6(l), 6(m)–6(o), and 6(p)). Clay mineral pores are poorly developed compared with brittle mineral pores (Figures 6(g) and 6(m)).Figure 6
FE-SEM images displaying pore types in the Wufeng-Longmaxi shales. (a–d) abundant OM pores with varied sizes within solid bitumen that generally fills in mineral pores; (e) subnanometer OM pores developed within depositional OM; (f) solid bitumen exists with pyrite framboids and forms OM/pyrite complexes that contain abundant OM pores; (g) OM occurs with clay minerals and forms OM/clay complexes in which abundant OM pores with smaller sizes are developed; (h–i) OM grains occur with accessory minerals and form OM/mineral complexes, e.g., OM/rutile complexes and OM/apatite complexes; (i–j) few pores within fossil fragments, mainly graptolite fragments; (l) pyrite framboids and index mineral of anoxic deep-water environments contain a certain amount of intercrystalline pores with hundreds of nanometers; (m) flocculated pores are disorderly distributed within clay minerals; (n and o) dissolution pores with poor connectivity caused by organic acids existing within/along carbonate grains; (p) microcrack is within shale matrix and is often filled by solid bitumen.
(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)(m)(n)(o)(p)OM pore development is considered to be a result of hydrocarbon generation with increased maturation levels [55, 56]. Loucks et al. [55] pointed out that OM pores are developed when thermal maturity is higher than 0.6%. In this study, the shales have an eqvRo of 2.37–2.53%, which can promote OM pore development. As shown in Figure 6, OM can be divided into depositional OM, solid bitumen, and graptolite, which have different influences on OM pore development.Solid bitumen, with no specific shape, is the main component in highly mature organic-rich shales and generally fills in interP pores related to brittle minerals [57]. Solid bitumen forms an OM pore network among interP pores in shale (Figures 6(a)–6(c)). Therefore, interP pore shape determines the filled solid bitumen shape, as well as OM pore distribution. The solid bitumen has a size generally smaller than 10 μm and uniform internal structures [58, 59], which can significantly increase shale pore complexity. OM pores develop within solid bitumen are circular and elliptical (Figures 6(a)–6(d)), and they are more developed than other types of OM.As reported by [37], depositional OM shape can change from isolated individual grains to local concentrations of grains. The depositional OM generally has a fixed outline which does not change with hydrocarbon generation processes. This type of OM usually ranges from several microns to several tens of microns. In comparison to solid bitumen, depositional OM also contains numerous pores which are much smaller than solid bitumen (Figure 6(e)). These OM pores are not easily recognized, even under the resolution of FE-SEM instrument. These OM pores have a limited contribution to total porosity.In addition to individual OM grains, solid bitumen and depositional OM can occur with mineral grains and form an OM/inorganic mineral complex, e.g., OM/pyrite complex, OM/clay complex, OM/rutile complex, and OM/apatite complex (Figures6(f)–6(i)). OM pores are well developed within OM/pyrite complexes (Figure 6(f)), probably due to that pyrite crystals can resist compaction and protect OM pores [58]. However, fibrous illite is easily compacted during burial, and hence, OM pores are poorly developed in OM/clay complexes (Figure 6(g)). OM fills the pore spaces and cracks of the rutile and apatite (Figures 6(h) and 6(i)), accompanied with OM pores distributed within OM/rutile and OM/apatite complexes. Because the crystal particles are tight, OM pores are smaller than those within OM/pyrite complexes.Graptolites or fossil fragments can be observed in the Wufeng-Longmaxi shales and are regarded as paleontological features. Fossil fragments and graptolites, with several micrometers, have fixed shapes, and rare pores can be observed in fossil fragments and graptolites (Figures6(j) and 6(k)). Fossil fragments and graptolites refer mainly to a particular group of skeletons and organisms, dominated with collagen [59, 60]. They have low hydrocarbon generation capacities, similar to type II-III kerogens [61]. However, Luo et al. [62] and Tenger et al. [63] observed a small number of pores in some graptolites, probably due to some specific compositions, e.g., cortical bandage in the organisms [58].Inorganic pores are poorly developed in comparison to OM pores. InterP pores between mineral grains are seldom seen, due to strong compaction or cementation. A large proportion of mineral pores are related to pyrites, clay minerals, and carbonates (Figures6(l)–6(o)). Pyrite aggregates can be seen in sizes of several microns and are widely distributed in the studied shales (Figure 6(f)). Intercrystalline pores found within pyrite aggregates (Figure 6(l)) are considered to be the second important pore type [64]. In some cases, intercrystalline pores are filled by solid bitumen and form pore networks with OM pores (Figure 6(f)). Pores associated with clays are widespread among fibrous clay minerals, but most are closed under compaction (Figure 6(m)). This is consistent with Guo and Zhang [65], who found that shale porosity has no significant increase with an increase in clay minerals. Clay mineral pores have good connectivity and can significantly increase shale permeability (Figure 6(m)) [45]. Dissolution pores are generally developed within or along carbonate grains (Figures 6(n) and 6(o)) and have sizes of nanometers to micrometers. Nie et al. [66] systematically summarized dissolution pore types and pointed out that carbonates are the main carriers of dissolution pores. Dissolution pores exhibit a significant role on shale porosity and form an effective connectivity that can provide space for hydrocarbon storage as well as hydrocarbon migration [66]. Microcracks that serve as a migration channel can be observed in the studied shales [55, 67]. Most microcracks are partially cemented by calcite or filled by solid bitumen. Microcracks along the alignment direction of brittle minerals can extend as long as 20 μm, and they can contribute significantly to shale gas migration by improving permeability [68].


## 4.2.2. Pore Structure Parameters and Water Saturation

Pore structure parameters and porosity of the studied samples are displayed in Figure4. BET surface area and pore volume are in the range of 10.7–35.65 m2/g and 0.014–0.026 cm3/g, averaged 16.96 m2/g and 0.017 cm3/g, respectively. The total porosity and permeability are in the range of 1.23%–8.43% and 0.0003–0.2232 mD, averaged 3.65% and 0.043 mD, respectively. BET surface area and porosity have a significant increasing trend with increasing depth (Figure 4), which is consistent with the variation of TOC content. The permeability varies greatly among the samples and exhibits no significant change with increased porosity. The Wufeng-Longmaxi shales have water saturations of 18.41%–69.33%, averaged 43.87%. Water saturation has an increase trend with increased clay mineral content and a decrease trend with increased TOC content (Figure 4), indicating that water is attracted to hydrophilic clay minerals rather than hydrophobic OMs [69].


## 4.3. In Situ Desorption Gas Characteristics

Total gas refers to the sum of in situ desorption gas and lost gas. The desorption gas is released at fluid circulation temperature and reservoir temperature, and the lost gas is calculated according to the equation of desorption gas data at early time and the square root of time from Figure7(a). The desorption gas content ranges from 0.42 to 1.54 cm3/g. Desorption gas increases rapidly with increased desorption time at the first stage (circulation temperature) and then decreases rapidly with increased desorption time. At the second stage (reservoir temperature), desorption gas has an abrupt increase and then decreases to no significant change (Figure 7(b)). When desorption time is >300 min, it has a limited contribution to desorption gas content. Dang et al. [70] found that the transition of desorption rate was probably caused by variations in the concentration gradient during the desorption process. Yuan et al. [71] found that this phenomenon might be a result of the two-stage gas diffusion process, exhibiting a rapid diffusion from macropores at the early stage and slow a low diffusion from micropores at the late stage. Desorption gas content is low for the upper Longmaxi shales, and desorption gas>1cm3/g generally exists within the Wufeng and lower Longmaxi shales. The lost gas content, in the range of 1.9–7.14 cm3/g, is much higher than desorption gas content. The variations of shale gas content were plotted in Figure 8, and they display an increasing trend with increased burial depth, due to high TOC content and high porosity [32].Figure 7
(a) Total gas curve of in situ desorption versus square root of time, and (b) gas desorption curve with increased desorption time for sample LY1-70. Desorption gas was determined by two steps, at circulation temperature 70°C and reservoir temperature 93°C, and lost gas was obtained by extrapolating 1 h of desorption data to time zero, using a linear fit to the plot of cumulative gas vs. square root of time.
(a)(b)Figure 8
Profiles of desorption gas, lost gas, total gas,VL, and PL of the Wufeng-Longmaxi shales in LY1 well. Desorption gas, lost gas, and total gas were determined by conducting in situ desorption test; VL and PL are Langmuir volume and Langmuir pressure, respectively, determined by performing high-pressure methane adsorption experiments.


## 4.4. High-Pressure Methane Supercritical Adsorption Capacity

The methane adsorption isotherms of 15 samples are displayed in Figure9, and the VL and PL values are shown in Table 1. The excess adsorption capacities increase rapidly to a maximum value at the pressure of around 11 MPa and then decline gradually when the pressure>11MPa (Figure 9(a)). The features of the excess adsorption isotherms have already been studied by [51, 72]. The reason for this phenomenon is that the volume of the sorbed gas phase is not negligible, because the free-phase methane density is similar to the sorbed methane density at high pressures [51]. Using the equation Vabs=Vex (1−ρg/ρa), the absolute adsorption capacities were converted from the excess adsorption capacities and plotted into Figure 9(b), which represents the actual adsorption capacities of the studied shales. The absolute adsorption capacities increase significantly with increased pressure when it is less than 11 MPa and then increase lowly at high pressures. As shown in Table 1, VL and PL values vary from 1.63 to 4.78 cm3/g and 3.45 to5.95 MPa, respectively. The VL value and the variation in TOC have similar trends with burial depth and PL value has an inverse trend compared to TOC (Figure 8), suggesting that TOC is a decisive factor of shale adsorption capacity.Figure 9
Methane isotherms of (a) excess adsorption and (b) absolute adsorption for 15 Wufeng-Longmaxi shales at various depths as fitted by the Langmuir model.
(a)(b)Table 1
Shale composition, water saturation, in situ gas desorption, and methane sorption capacity of the Wufeng-Longmaxi shales in LY1 well.
SamplesDepth (m)FormationTOC (%)Clay mineral (%)Water saturation (%)Desorption gas (cm3/g)Lost gas (cm3/g)Total gas (cm3/g)VL (cm3/g)PL (MPa)LY1-12958.78S1l0.774765.690.422.32.72//LY1-32961.08S1l0.5953/0.423.764.181.635.95LY1-52962.96S1l0.584353.070.482.252.73//LY1-72965.11S1l0.715755.080.552.392.94//LY1-92967.21S1l0.815841.970.513.624.13//LY1-112969.28S1l0.685240.10.532.362.89//LY1-132971.22S1l0.654331.680.532.342.871.925.81LY1-152973.35S1l0.674647.990.532.432.96//LY1-172975.53S1l0.756047.760.582.733.31//LY1-192977.51S1l0.696264.940.582.933.51//LY1-212979.19S1l0.825549.050.663.023.68//LY1-232980.72S1l1.015133.30.542.192.73//LY1-252982.62S1l0.844358.580.522.222.742.035.41LY1-272984.48S1l0.635645.820.532.232.76//LY1-292986.34S1l0.644847.670.522.533.05//LY1-302988.03S1l0.685649.630.62.973.57//LY1-322989.98S1l0.765369.330.632.783.41//LY1-342991.84S1l0.715565.090.622.633.25//LY1-362993.86S1l0.8456/0.683.394.072.365.83LY1-382995.52S1l0.984854.690.743.684.42//LY1-402997.19S1l0.956047.460.622.643.26//LY1-422999.55S1l14867.50.663.44.06//LY1-443001.48S1l1.053366.640.773.54.27//LY1-463003.27S1l1.775046.770.721.92.62//LY1-483004.93S1l0.975040.760.652.092.742.54.71LY1-503006.89S1l2.394641.940.962.63.56//LY1-523008.63S1l3.353536.7812.773.77//LY1-543010.47S1l3.653628.581.012.653.66//LY1-563012.26S1l3.413629.9412.623.623.194.23LY1-583013.84S1l3.073027.771.072.93.973.154.52LY1-603015.5S1l3.583535.021.063.214.273.334.33LY1-633017.22S1l3.633630.311.053.214.263.484.26LY1-663019.13S1l4.9138/1.144.15.244.393.96LY1-703021.19S1l4.943323.431.043.234.273.933.77LY1-733022.91S1l4.82320.461.244.455.693.574.22LY1-763024.89S1l6.982818.411.547.148.684.783.45LY1-793026.61O3w5.421630.871.244.115.353.623.46LY1-803027.77O3w4.163221.251.183.254.433.073.98


## 5. Discussion

### 5.1. Shale Gas Composition and Genesis

As shown in Table2 and Figure 10, desorption gas consists of hydrocarbon gas and nonhydrocarbon gas. Nonhydrocarbon gas is dominated by N2, which varies in concentration from 5.27% to 11.14%, higher than that with averaged value of 0.68% in Weiyuan, Fuling, Changning, and Zhaotong areas [73]. This case suggests that the preservation condition is weaker than the inner Sichuan Basin. CO2, H2, and O2 are minor, with concentrations of 0.07%–1.15%, 0.01%–1.25%, and 0.01%–0.03%, respectively, similar to shale gas fields in the inner Sichuan Basin. CO2 exhibits an increasing trend with increased depth and TOC, suggesting that OM abundance and thermal evolution fuel the CO2 generation, which is probably due to CO2 liberation from kerogen [74]. A weakly negative relationship between O2 and N2 illustrates that the leaning of OM tends to an anaerobic condition, which promotes the conversion of OM to hydrocarbons under reduced conditions at greater depths [22]. Hydrocarbon gas in the studied shales is primarily CH4, followed by minor C2H6 and C3H8. CH4 content varies from 86.99% to 93.08%, averaged 90.18%, significantly lower than that, averaged 97.78%, in Weiyuan and Fuling areas [73].Table 2
Desorption gas compositions andδ13C value of shale gas of the Wufeng-Longmaxi Formation in LY1 well.
SamplesDepth (m)FormationCH4 (%)C2H (%)C3H8 (%)O2 (%)N2 (%)H2 (%)CO2 (%)δ13C1 (‰)LY1-32961.08S1l90.550.450.011.257.620.020.11-28.7LY1-112969.28S1l89.960.570.080.198.940.020.24-27.6LY1-272984.48S1l89.920.340.130.219.310.020.07-29.8LY1-422999.55S1l92.060.270.030.437.10.020.11-30LY1-443001.48S1l88.410.590.010.0510.070.030.84-29.5LY1-463003.27S1l88.80.810.010.119.10.021.15-28.5LY1-483004.93S1l90.10.350.030.139.280.030.08-30.5LY1-503006.89S1l90.390.870.010.218.090.020.41-26.2LY1-523008.63S1l91.190.340.080.137.730.020.51-25.4LY1-543010.47S1l88.50.940.010.139.860.020.54-25.9LY1-563012.26S1l89.390.880.070.129.160.030.35-25.9LY1-583013.84S1l90.350.830.010.118.80.020.6-26.3LY1-603015.5S1l89.910.880.080.428.360.010.34-29.6LY1-633017.22S1l88.380.410.090.3410.320.010.45-29.2LY1-663019.13S1l90.360.470.110.188.10.020.76-24.3LY1-703021.19S1l86.990.980.080.1411.140.020.65-27.5LY1-733022.91S1l90.010.780.060.318.270.010.56-28.4LY1-763024.89S1l92.840.460.070.015.890.020.71-28.6LY1-793026.61O3w92.330.720.060.16.140.020.63-28.5LY1-803027.77O3w93.080.890.090.615.270.030.43-28.8Figure 10
Gas compositions of in situ desorption gas from the Wufeng-Longmaxi shales in LY1 well.Dai et al. [75] pointed out that the heavy carbon isotope (δ13C1) value of the natural gas in Sichuan Basin ranges from -28.26‰ to -30.98‰, which indicates that the CH4 is from a biogenic source. The thermal maturation evolution process begins with biogenic gas, then to pyrolysis gas, and finally to carbon-carbon bond cracking gas. Whiticar [76] compiled the identification chart of natural gas genesis in terms of δ13C1 versus C1/C2+3 to identify the origin of natural gas. As seen in Figure 11(a), shale gas in this study is thermogenic but approximate to beyond evolution trend of type III kerogen. However, the OM is dominated by the type I kerogen. Therefore, this phenomenon implies that a slightly higher in δ13C1 value is likely related to a high evolution of OM. Overall, shale gas in northwestern Guizhou is cracking gas derived from oil. The isotopic compositions of CH4 and C2H6 in present pyrolytic chart were applied to the quantitative identification of the isotopic compositions from kerogen cracking or oil cracking. It illustrates that shale gas from oil cracking gas was 60–80% in Fuling shale gas fields (Figure 11(b)) [76]. Li et al. [73] pointed out that δ13C1 value of Weiyuan, Changning, Zhaotong, and Fuling areas ranges from -36.9‰ to -36.0‰, -27.7‰ to –27.2‰, -29.6‰ to –26.3‰, and -31.5‰ to –30.8‰, which are closely related to their maturities. OM compositions and thermal maturities of the studied shales are similar to those in Fuling area and Changning areas, and therefore, shale gas must be derived from oil cracking.Figure 11
(a) Identification and distinction diagram of natural gas genesis fromδ13C1 versus C1/C2+3 values (after [76]) and (b) quantitative identification of natural gas isotopic compositions of oil and kerogen (after [77]).
(a)(b)


### 5.2. Shale Composition Controls Shale Gas Capacity

Shale gas, referring to sorbed gas and free gas, is primarily stored within nanometer pores related to shale compositions [78]. Different compositions and physical properties can give rise to different shale gas contents and free/sorbed ratios [21].


#### 5.2.1. TOC Controls Shale Gas Content

As illustrated above, pore spaces in the studied shales are mainly contributed by OMs, and therefore, TOC content exhibits a vital role on shale porosity. As shown in Figure12, TOC content is positively correlated with micropore volume and mesopore volume, as well as specific surface area, with correlation coefficients of 0.86, 0.82, and 0.82, respectively. However, TOC content has a negative correlation with macropore volume (Figure 12(a)), suggesting that OM pores are not a major contributor to macropore volume. Overall, shale porosity has a significantly increasing trend with increasing TOC content (Figure 12(b)). This indicates that total porosity is mostly made up of OM nanometer-scale pores rather than the macropores related to minerals, which is also supported by FE-SEM observations (Figure 6). It is well known that sorbed gas exists mainly in micropores and mesopores, and free gas occurs in meso- to macropores and fractures. Hence, abundant micro to mesopores in the studied shales provided numerous spaces for sorbed gas and free gas. However, macropores and fractures are not fully filled by free gas. To further reveal how TOC affects shale gas content, the correlations of TOC content with shale gas content were plotted in Figures 12(d) and 12(e). TOC content has a positive correlation with VL, desorption gas, lost gas, and total gas, with correlation coefficients of 0.9, 0.92, 0.47, and 0.63, respectively. Therefore, we can conclude that TOC is the decisive factor of shale gas content, similar to the Wufeng-Longmaxi shales in Jiaoshiba, Dingshan and Nanchuan areas, and Niutitang shales in Weiyuan-Changniang areas [79–81]. High content of TOC can not only generate a large amount of natural gas but also provide a significant amount of nanometer-scale pores for sorbed gas and free gas. The total gas content determined by in situ desorption measurement is higher than VL value at reservoir conditions, indicating that sorbed gas is saturated at reservoir conditions and there is still partial free gas in the shale reservoir. TOC content displays different degrees of positive influences on desorption gas, lost gas, and total gas. Desorption gas is significantly controlled by TOC content, suggesting that desorption gas is mainly sorbed gas stored within OM micropores and mesopores. However, lost gas content displays only a moderate correlation with TOC content, which illustrates that lost gas is controlled not only by OM mesopores but also mineral pores and fractures. Therefore, we could conclude that desorption gas is primarily derived from sorbed gas but lost gas is made up of not only free gas but also sorbed gas. VL value also shows a better correlation with desorption gas content than that with lost gas (Figure 12(f)), which further proves that desorption gas content is mainly determined by TOC and adsorption gas capacity, and lost gas is derived from two sources as sorbed gas and free gas.Figure 12
Cross-plots of TOC with (a) pore volume, (b) porosity, (c) specific surface area, (d)VL, (e) measured shale gas content, and (f) cross-plot of VL with measured shale gas content.
(a)(b)(c)(d)(e)(f)


#### 5.2.2. Mineral Composition Controls Shale Gas Content

Minerals can also provide a certain amount of pores in various shapes and sizes ranging from several nanometers to tens of micrometers [82]. However, the influence of mineral variations on shale gas content is not very clear, due to these shales having been subjected to various geological processes, e.g., burial, compaction, cementation, secondary compaction, and water occupation. Previous studies have indicated that shale composition has significant influences on shale physical properties and further determines shale gas storage and transport mechanisms [21]. In this study, there are negative correlations between clay mineral content and volumes of micropores and mesopores, but a positive correlation occurs between clay mineral content and macropore volume (Figure 13(a)). This implies that clay minerals provide primarily macropores rather than micropores and mesopores. As known, total porosity of the Wufeng-Longmaxi shales is primarily from OM pores, and therefore, total porosity displays a decrease trend with increased clay mineral content (Figure 13(b)). As shown in Figures 13(c) and 13(d), water saturation decreases with an increase of micro to mesopore volume but increases with increased macropore volume and clay mineral content. As illustrated, water molecules are generally sorbed on the surface of hydrophilic clay minerals [21, 69]. Therefore, the studied shales with high clay mineral contents generally have high water saturations. With increased TOC content, water saturation is generally low due to that pore space is primarily determined by hydrophobic OM pores. Hence, the studied shales with higher TOC contents generally have higher natural gas saturations and lower water saturations, which are favorable for shale gas accumulation and storage. Figures 13(e) and 13(f) also prove that the increased clay mineral content would result in a low content of shale gas, exhibited by negative correlations of clay mineral content with desorption gas, lost gas, total gas, and VL. This is well consistent with the shales of Wufeng-Longmaxi and Niutitang Formations in the southeastern Sichuan Basin [18]. Particularly, desorption gas content and VL value are more easily influenced by clay mineral content, due to that sorbed gas are more likely to store within hydrophobic OM pores rather than hydrophilic clay mineral pores. Overall, the negative influence of clay minerals on shale gas content is due to that high content of immovable water as well as strong compaction.Figure 13
Cross-plots of clay mineral content with pore structures, water saturation, shale gas content, andVL.
(a)(b)(c)(d)(e)(f)Revealed by FE-SEM images, brittle minerals can contain various types of pores with diameters that fall within the meso to macropore range. No significant relationships are displayed among carbonate content and volumes of micropore, mesopore, and macropore (Figure14(a)). However, there is a weak relationship between carbonate content and total porosity (Figure 14(b)), suggesting that partial pores with diameters larger than 200 nm are found within carbonates or along carbonate grains. Therefore, desorption gas and VL display no correlation with carbonate content (Figures 14(c) and 14(d)). There is also no correlation between carbonate content and lost or total gas, probably due to that macropore volume is not saturated by natural gas. From this point of view, carbonate content has no significant role on shale gas accumulation.Figure 14
Cross-plots of carbonate content with (a) pore volume, (b) porosity, (c) shale gas content, and (d)VL.
(a)(b)(c)(d)Pyrite framboids are regarded as an index for anoxic depositional environments [68]. Many scholars have noticed that pyrite framboids may have influence on hydrocarbon generation, accumulation, and preservation. Pyrite framboids usually coexist with OM and contain a great deal of intercrystalline pores and OM pores. With increased burial depth and diagenesis, liquid hydrocarbon eventually migrates into the intercrystalline pores associated with pyrite framboids and finally evolves into solid bitumen. Therefore, intercrystalline pores and OM pores within pyrite-OM complexes are favorable conditions for shale gas accumulation. As seen in Figure 15(a), pyrite content has a weak relationship with micropore volume and no correlations with mesopore and macropore volumes. This indicates that any correlation between pyrite content and micropore volume is likely due to its positive correlation with TOC content. Pyrite/OM complexes develop a certain amount of OM micropores and mesopores that enhance shale gas adsorption capacity. It can be expected that pyrite content exhibits positive correlations with total porosity, desorption gas, and VL (Figures 15(b)–15(d)). However, pyrite content does not correlate with lost gas and total gas (Figure 15(c)). This suggests that intercrystalline pores related to pyrite framboids have no significant influence on free gas content. This further indicates that the mineral pores, particularly macropores, in the studied shales are not saturated by free gas.Figure 15
Cross-plots of pyrite content with (a) pore volume, (b) porosity, (c) shale gas content, and (d)VL.
(a)(b)(c)(d)


#### 5.2.3. Physical Properties Control Shale Gas Content

The ability for shale to store and transport natural gas depends on the composition of the shale, more specifically, the pore structures. Shale porosity consists of OM pores, clay mineral pores, dissolution pores, interP pores, and fractures. Different types of pores can retain different forms of shale gas. Previous studies indicated that sorbed gas generally occurs within OM pores, clay mineral surfaces, and pores related to mineral/OM complexes, and free gas can exist in all of the types of interconnected pores. Unlike sorbed gas, free gas is more easily to be escaped from shale gas reservoirs during burial. Therefore, the physical properties have significant influences on shale gas storage capacity.As shown in Figure16(a), the volumes of micropore and mesopore have obvious correlations with VL, with correlation coefficients of 0.95 and 0.73, respectively. This suggests that sorbed gas is mainly stored within micro to mesoscale pores, particularly within micropores. However, macropores with diameters less than 200 nm are not favorable for sorbed gas storage. Micropores and mesopores also exhibit negative correlations to PL value (Figure 16(b)), suggesting that molecular methane is more easily sorbed in micropores and mesopores. Hence, the studied shales dominated with OM nanometer-scale pores are more likely to accumulate shale gas than macropores related to minerals.Figure 16
Cross-plots of pore volume with (a)VL and (b) PL for the studied shales.
(a)(b)Pores with different sizes have different roles on shale gas occurrence and content. As seen in Figures17(a) and 17(b), desorption gas content is directly controlled by micropore and mesopore volumes. More specifically, micropore and mesopore volumes have better correlations with desorption gas content than those with lost gas content, suggesting that desorption gas is primarily released from micropores then mesopores. Interestingly, free gas is also primarily released from micro- to mesopores, because the lost gas content also has positive correlations with volumes of micropores and mesopores. However, there are no correlations between macropore volume and desorption gas, lost gas, and total gas contents (Figure 17(c)). This may be an indication that the macropores are not saturated by free gas. Overall, shale gas content, whether desorption gas, lost gas, or total gas, has a significantly increasing trend with increased total porosity (Figure 17(d)). This case illustrates that shale porosity is mainly made up of OM micro to mesopores, and shale gas occurs mainly as sorbed gas in these nanometer-scale pores.Figure 17
Cross-plots of measured shale gas content with (a) micropore volume, (b) mesopore volume, (c) macropore volume, and (d) porosity.
(a)(b)(c)(d)As illustrated above, shale gas in the studied shales is mainly accumulated as sorbed gas in nanometer-scale pores, and free gas is not saturated within OM pores and mineral-related pores. OM micropores and mesopores are priority to storage sorbed gas, followed by free gas. TOC content is the decisive factor of shale gas content. Inorganic macropores are not favorable spaces for natural gas storage, and mineral compositions have limited contributions to sorbed even free gas content. It can be concluded that shale gas is preferentially stored in hydrophobic OM pores, secondly in neutral brittle mineral pores, and hydrophilic clay mineral pores are not a viable factor for shale gas storage.


### 5.3. Existence State of Shale Gas

Shale gas existence state is a significant factor in natural gas productivity. Previous studies have shown that in situ desorption gas in coalbed reservoirs is primarily sorbed gas and in shale reservoirs can contain both sorbed gas and free gas [41, 83]. In coalbed methane reservoirs, it has been documented methane adsorption capacity is higher than total gas content, due to that methane is stored mainly in sorbed state and cannot be released completely from coal reservoir [83]. For a shale gas reservoir, total gas is higher than methane adsorption capacity [41], because total gas determined by in situ desorption tests is a mixed of both free gas and sorbed gas. Free gas is generally higher and is more easily to be released from shale gas reservoir. The in situ desorption isotherm in Figure 7(b) is similar to the methane adsorption isotherm in Figure 9(b), indicating that desorption gas is primarily made up of sorbed gas. The total gas is higher than VL, suggesting that free gas is a main contributor to total gas.In this study, we adopted the methane adsorption capacity at 93°C and 30 MPa as the sorbed gas content at reservoir conditions, which ranged between 1.36 and 4.29 cm3/g. The sorbed gas content positively correlates with desorption gas, lost gas, and total gas (Figure 18(a)). Particularly, methane adsorption content exhibits a better relationship with desorption gas than that with lost gas, suggesting that most desorption gas and partial lost gas are contributed by sorbed gas. We compared sorbed gas content with total gas content and found that sorbed gas can account for 55.32%–81.73%, averaged 63.09% of total gas in theory (Figure 18(b)). With the increase of TOC, free gas proportion has a significant increase due to the increase in OM porosity especially pores>3nm and a decrease in water saturation [20]. However, the actual proportion of sorbed gas in total gas should be less than 63.09%. First, the methane adsorption capacity determined by isothermal methane adsorption presents the maximum of sorbed gas content. Second, partial sorbed gas, in the form of residual gas, is retained in the studied shales, which further reduce the proportion of sorbed gas in total gas. Third, methane adsorption tests were conducted on dried samples, and the influence of the connate water was not considered. Overall, in situ desorption gas comprised mainly of sorbed gas, followed partial free gas. Free gas ratio in the studied shales is significantly higher than that in Cambrian Shuijingtuo shales in which free gas ratio is less than 20% [41] but is lower than the Wufeng-Longmaxi shales in the Sichuan Basin, e.g., Fuling and Changning-Weiyuan shale gas fields [84]. For Fuling and Weiyuan shale gas fields, the free gas accounts for 47.98%–72.81% and 26.70%–82.35%, averaged 55.46% and 57.76%, respectively, in the total gas content. The high ratio of free gas in Fuling and Weiyuan areas is due to high pressure coefficient in the inner Sichuan Basin [19].Figure 18
(a) Cross-plots of methane adsorption content tested at 30 MPa with measured shale gas content (desorption gas, lost gas, and total gas) and (b) comparison of sorbed gas with total gas for the studied shales in LY1 well.
(a)(b)In order to further evaluate shale gas content, we also calculated theoretical shale gas content and compared it with measured total gas content. The sorbed gas has been tested by methane adsorption experiment conducted at 93°C. In terms of the Gibbs adsorption theory, theoretical total gas, sorbed gas, and free gas under specific temperature and pressure can be acquired by the following calculations, respectively [85].
(1)SHtotal=SHex,sorbed+Ф1−Swρapparent.ρbH,T,y/ρbSTP(2)SHabsolute=SHex.ρadHρadH−ρbH,T,y(3)SHfree=SHtotal−SHabsoluteSw is the water saturation, Ф is the porosity, ρapparent is the shale apparent density, ρbSTP is the methane density at 0°C and 0.1 MPa, SHtotal, SHabsolute, and SHfree represent theoretical total gas, absolute adsorption gas, and free gas at depth of H, respectively. H, Tg, and To are the given parameters, Sw, Ф, and ρapparent are fundamental parameters obtained from experiments, ρadH is the adsorption parameter that can be obtained by the SDR model [86], and ρbH,T,y can be calculated with the PVT equation. It is important to state that moisture can reduce sorbed gas content, and therefore, the geological extrapolation according to dry adsorption data should be only used as a maximum scenario. Furthermore, total porosity should be corrected according to burial depth and confining stress, with the equation of y=−0.337lnx+4.835 with R2=0.998 [13]. In this equation, y represents the bulk porosity and x represents the confining stress. The experimental data, the parameters, and the calculated results are displayed in Table 3.Table 3
Sorbed gas, free gas, and theoretical gas content determined by published equations under actual geological conditions.
SamplesDepth (m)Water saturation (%)Porosity at 30 MPa (%)Vex (cm3/g)Apparent density (g/cm3)Sorbed gas (cm3/g)Free gas (cm3/g)Theoretical gas (cm3/g)Measured gas(cm3/g)Free gas proportion(%)LY1-32961.0859.382.230.342.711.36-0.281.084.18/LY1-132971.2231.682.430.492.701.610.241.852.8712.76LY1-252982.6258.581.620.512.691.72-0.661.062.74/LY1-362993.8658.891.940.672.711.98-0.511.474.07/LY1-483004.9340.762.260.872.672.16-0.191.972.74/LY1-563012.2629.943.501.562.592.790.853.643.6223.42LY1-583013.8427.773.701.382.582.730.933.663.9725.40LY1-603015.5035.023.741.432.552.900.633.534.2717.78LY1-633017.2230.314.111.702.563.051.124.174.2626.78LY1-663019.1325.395.332.212.523.881.805.685.2431.75LY1-703021.1923.435.592.192.533.492.425.914.2740.97LY1-733022.9120.465.372.002.503.132.635.765.6945.68LY1-763024.8918.416.752.822.404.293.587.878.6845.49LY1-793026.6130.875.312.282.563.252.195.445.3540.25LY1-803027.7721.254.021.852.502.711.934.644.4341.55As seen in Table3 and Figure 19, when TOC and porosity are low, the theoretical gas content is inconsistent with measured gas content. Particularly, free gas content is negative, likely due to the fact that bulk porosity is not accurate or the overcalculation of sorbed gas under dried conditions in shales with TOC<1%. Therefore, theoretical shale gas content has no relationship with measured shale gas content for the shales with low TOC content. However, for the shales with higher TOC content and porosity, the measured gas content is very consistent with theoretical gas content, with a correlation coefficient of 0.78. This result indicates that actual shale gas content could be predicted using theoretical methods only for organic-rich shales, which has vital importance for shale gas resource assessment and exploration in the absence of desorption gas in field.Figure 19
(a) Vertical variability of sorbed gas, free gas, and theoretical gas content obtained from mathematical model and measured gas content determined by in situ desorption test and (b) cross-plots of theoretical gas content with measured gas content.
(a)(b)


### 5.4. A Schematic of the Types of Shale Gas Reservoirs

As illustrated above, free gas is usually lower than sorbed gas under natural burial conditions, indicating that natural gas is first stored in the sorbed state and then in the free gas state. As illustrated by [32], pores with diameters of 1–4 nm store primarily sorbed gas in the Lujiaping Formation shale. Yu et al. [20] pointed out pores smaller than 3 nm store primarily sorbed gas and pores larger than 3 nm store primarily free gas. These smaller pores can sorb a single layer of methane molecules, with strong interactions between pore walls and the methane molecular. Therefore, sorbed gas has a hard time escaping from the shale reservoir. However, natural gas migrates from shale reservoirs, so it must displace water in the pores/fractures. Only when reservoir pressure decreases to a critical pressure can sorbed gas migrate from OM pores. As illustrated by [82], the Wufeng-Longmaxi shales are primarily dominated by pores with diameters<4 nm, and therefore, these shales have a strong methane adsorption capacity and a high capillary pressure. This gives rise to high sealing capacity and good preservation condition for shale gas in such a complex tectonic region. With increased depth, both TOC and porosity increase, which significantly increases pore space for free gas under high stratum pressure. In this case, the proportion and content of free gas increase (Figure 19(a)), and it can be explained by the microscopic mechanism of gas preservation in the Wufeng-Longmaxi shales.Natural gas in a shale gas reservoir experiences sorbed, desorbed, diffused, and accumulated processes. The four stages, as sorbed stage, pore filling stage, fracture filling stage, and gas accumulation stage, of shale gas storage were divided. The generated natural gas firstly satisfies physical adsorption and dissolution, followed by the existence in free gas, which is similar to the shale gas desorption process [87]. Therefore, a microscopic model of shale gas existence was proposed based on FE-SEM images, shown in Figure 20. Small dots with different colors (yellow, red, and blue) indicate three gas molecules (sorbed gas, free gas, and water molecular), and the density of small dots indicates the main occurrence sites of gas/water molecules. As shown in Figure 20, shale gas occurs in different states in different types of pores. With increased thermal maturation, natural gas first satisfies the adsorption demands of OM particles and the surfaces of mineral grains. During this period, sorbed gas dominates the process. Simultaneously, limited natural gas would be dissolved in water, kerogen, asphalt, and residual oil. With large quantities of natural gas produced, the sorbed gas is saturated and excess gas in the free gas state would migrate into OM pores, interP pores, and microfractures. However, clay mineral pores are almost occupied by water moleculars as water saturation reaches 18.41%–69.33% with averaged value 43.87%. Overall, OM pores within solid bitumen, depositional OM, and mineral/OM complexes, are preferentially storage for sorbed gas, followed by free gas. With the increase of TOC, free gas content is significantly increased, due to that more OM pores with sizes>3−4 nm are developed. Clay minerals have a limited contribution to sorbed gas and free gas. Though fractures are filled by calcite and solid bitumen or closed under actual geological condition, they could still provide a certain space for free gas. Therefore, shale gas potential is controlled primarily by OM pore development level and then by fractures.Figure 20
Microscopic occurrence model of shale gas in the accumulation process. (a–c) OM pores and surfaces are primary space for sorbed gas and most free gas; (d and e) clay mineral pores are most filled by water molecules and have limited contribution to sorbed gas and free gas; (f) sorbed gas, free gas, and molecular water exist within clay minerals; (g) dissolution pores can provide space for free gas; (h) OM/pyrite complex contains OM pores and interP pores that contribute firstly to sorbed gas and followed free gas; (i) microcracks contribute primarily to free gas and limited sorbed gas.
(a)(b)(c)(d)(e)(f)(g)(h)(i)


## 5.1. Shale Gas Composition and Genesis

As shown in Table2 and Figure 10, desorption gas consists of hydrocarbon gas and nonhydrocarbon gas. Nonhydrocarbon gas is dominated by N2, which varies in concentration from 5.27% to 11.14%, higher than that with averaged value of 0.68% in Weiyuan, Fuling, Changning, and Zhaotong areas [73]. This case suggests that the preservation condition is weaker than the inner Sichuan Basin. CO2, H2, and O2 are minor, with concentrations of 0.07%–1.15%, 0.01%–1.25%, and 0.01%–0.03%, respectively, similar to shale gas fields in the inner Sichuan Basin. CO2 exhibits an increasing trend with increased depth and TOC, suggesting that OM abundance and thermal evolution fuel the CO2 generation, which is probably due to CO2 liberation from kerogen [74]. A weakly negative relationship between O2 and N2 illustrates that the leaning of OM tends to an anaerobic condition, which promotes the conversion of OM to hydrocarbons under reduced conditions at greater depths [22]. Hydrocarbon gas in the studied shales is primarily CH4, followed by minor C2H6 and C3H8. CH4 content varies from 86.99% to 93.08%, averaged 90.18%, significantly lower than that, averaged 97.78%, in Weiyuan and Fuling areas [73].Table 2
Desorption gas compositions andδ13C value of shale gas of the Wufeng-Longmaxi Formation in LY1 well.
SamplesDepth (m)FormationCH4 (%)C2H (%)C3H8 (%)O2 (%)N2 (%)H2 (%)CO2 (%)δ13C1 (‰)LY1-32961.08S1l90.550.450.011.257.620.020.11-28.7LY1-112969.28S1l89.960.570.080.198.940.020.24-27.6LY1-272984.48S1l89.920.340.130.219.310.020.07-29.8LY1-422999.55S1l92.060.270.030.437.10.020.11-30LY1-443001.48S1l88.410.590.010.0510.070.030.84-29.5LY1-463003.27S1l88.80.810.010.119.10.021.15-28.5LY1-483004.93S1l90.10.350.030.139.280.030.08-30.5LY1-503006.89S1l90.390.870.010.218.090.020.41-26.2LY1-523008.63S1l91.190.340.080.137.730.020.51-25.4LY1-543010.47S1l88.50.940.010.139.860.020.54-25.9LY1-563012.26S1l89.390.880.070.129.160.030.35-25.9LY1-583013.84S1l90.350.830.010.118.80.020.6-26.3LY1-603015.5S1l89.910.880.080.428.360.010.34-29.6LY1-633017.22S1l88.380.410.090.3410.320.010.45-29.2LY1-663019.13S1l90.360.470.110.188.10.020.76-24.3LY1-703021.19S1l86.990.980.080.1411.140.020.65-27.5LY1-733022.91S1l90.010.780.060.318.270.010.56-28.4LY1-763024.89S1l92.840.460.070.015.890.020.71-28.6LY1-793026.61O3w92.330.720.060.16.140.020.63-28.5LY1-803027.77O3w93.080.890.090.615.270.030.43-28.8Figure 10
Gas compositions of in situ desorption gas from the Wufeng-Longmaxi shales in LY1 well.Dai et al. [75] pointed out that the heavy carbon isotope (δ13C1) value of the natural gas in Sichuan Basin ranges from -28.26‰ to -30.98‰, which indicates that the CH4 is from a biogenic source. The thermal maturation evolution process begins with biogenic gas, then to pyrolysis gas, and finally to carbon-carbon bond cracking gas. Whiticar [76] compiled the identification chart of natural gas genesis in terms of δ13C1 versus C1/C2+3 to identify the origin of natural gas. As seen in Figure 11(a), shale gas in this study is thermogenic but approximate to beyond evolution trend of type III kerogen. However, the OM is dominated by the type I kerogen. Therefore, this phenomenon implies that a slightly higher in δ13C1 value is likely related to a high evolution of OM. Overall, shale gas in northwestern Guizhou is cracking gas derived from oil. The isotopic compositions of CH4 and C2H6 in present pyrolytic chart were applied to the quantitative identification of the isotopic compositions from kerogen cracking or oil cracking. It illustrates that shale gas from oil cracking gas was 60–80% in Fuling shale gas fields (Figure 11(b)) [76]. Li et al. [73] pointed out that δ13C1 value of Weiyuan, Changning, Zhaotong, and Fuling areas ranges from -36.9‰ to -36.0‰, -27.7‰ to –27.2‰, -29.6‰ to –26.3‰, and -31.5‰ to –30.8‰, which are closely related to their maturities. OM compositions and thermal maturities of the studied shales are similar to those in Fuling area and Changning areas, and therefore, shale gas must be derived from oil cracking.Figure 11
(a) Identification and distinction diagram of natural gas genesis fromδ13C1 versus C1/C2+3 values (after [76]) and (b) quantitative identification of natural gas isotopic compositions of oil and kerogen (after [77]).
(a)(b)


## 5.2. Shale Composition Controls Shale Gas Capacity

Shale gas, referring to sorbed gas and free gas, is primarily stored within nanometer pores related to shale compositions [78]. Different compositions and physical properties can give rise to different shale gas contents and free/sorbed ratios [21].


### 5.2.1. TOC Controls Shale Gas Content

As illustrated above, pore spaces in the studied shales are mainly contributed by OMs, and therefore, TOC content exhibits a vital role on shale porosity. As shown in Figure12, TOC content is positively correlated with micropore volume and mesopore volume, as well as specific surface area, with correlation coefficients of 0.86, 0.82, and 0.82, respectively. However, TOC content has a negative correlation with macropore volume (Figure 12(a)), suggesting that OM pores are not a major contributor to macropore volume. Overall, shale porosity has a significantly increasing trend with increasing TOC content (Figure 12(b)). This indicates that total porosity is mostly made up of OM nanometer-scale pores rather than the macropores related to minerals, which is also supported by FE-SEM observations (Figure 6). It is well known that sorbed gas exists mainly in micropores and mesopores, and free gas occurs in meso- to macropores and fractures. Hence, abundant micro to mesopores in the studied shales provided numerous spaces for sorbed gas and free gas. However, macropores and fractures are not fully filled by free gas. To further reveal how TOC affects shale gas content, the correlations of TOC content with shale gas content were plotted in Figures 12(d) and 12(e). TOC content has a positive correlation with VL, desorption gas, lost gas, and total gas, with correlation coefficients of 0.9, 0.92, 0.47, and 0.63, respectively. Therefore, we can conclude that TOC is the decisive factor of shale gas content, similar to the Wufeng-Longmaxi shales in Jiaoshiba, Dingshan and Nanchuan areas, and Niutitang shales in Weiyuan-Changniang areas [79–81]. High content of TOC can not only generate a large amount of natural gas but also provide a significant amount of nanometer-scale pores for sorbed gas and free gas. The total gas content determined by in situ desorption measurement is higher than VL value at reservoir conditions, indicating that sorbed gas is saturated at reservoir conditions and there is still partial free gas in the shale reservoir. TOC content displays different degrees of positive influences on desorption gas, lost gas, and total gas. Desorption gas is significantly controlled by TOC content, suggesting that desorption gas is mainly sorbed gas stored within OM micropores and mesopores. However, lost gas content displays only a moderate correlation with TOC content, which illustrates that lost gas is controlled not only by OM mesopores but also mineral pores and fractures. Therefore, we could conclude that desorption gas is primarily derived from sorbed gas but lost gas is made up of not only free gas but also sorbed gas. VL value also shows a better correlation with desorption gas content than that with lost gas (Figure 12(f)), which further proves that desorption gas content is mainly determined by TOC and adsorption gas capacity, and lost gas is derived from two sources as sorbed gas and free gas.Figure 12
Cross-plots of TOC with (a) pore volume, (b) porosity, (c) specific surface area, (d)VL, (e) measured shale gas content, and (f) cross-plot of VL with measured shale gas content.
(a)(b)(c)(d)(e)(f)


### 5.2.2. Mineral Composition Controls Shale Gas Content

Minerals can also provide a certain amount of pores in various shapes and sizes ranging from several nanometers to tens of micrometers [82]. However, the influence of mineral variations on shale gas content is not very clear, due to these shales having been subjected to various geological processes, e.g., burial, compaction, cementation, secondary compaction, and water occupation. Previous studies have indicated that shale composition has significant influences on shale physical properties and further determines shale gas storage and transport mechanisms [21]. In this study, there are negative correlations between clay mineral content and volumes of micropores and mesopores, but a positive correlation occurs between clay mineral content and macropore volume (Figure 13(a)). This implies that clay minerals provide primarily macropores rather than micropores and mesopores. As known, total porosity of the Wufeng-Longmaxi shales is primarily from OM pores, and therefore, total porosity displays a decrease trend with increased clay mineral content (Figure 13(b)). As shown in Figures 13(c) and 13(d), water saturation decreases with an increase of micro to mesopore volume but increases with increased macropore volume and clay mineral content. As illustrated, water molecules are generally sorbed on the surface of hydrophilic clay minerals [21, 69]. Therefore, the studied shales with high clay mineral contents generally have high water saturations. With increased TOC content, water saturation is generally low due to that pore space is primarily determined by hydrophobic OM pores. Hence, the studied shales with higher TOC contents generally have higher natural gas saturations and lower water saturations, which are favorable for shale gas accumulation and storage. Figures 13(e) and 13(f) also prove that the increased clay mineral content would result in a low content of shale gas, exhibited by negative correlations of clay mineral content with desorption gas, lost gas, total gas, and VL. This is well consistent with the shales of Wufeng-Longmaxi and Niutitang Formations in the southeastern Sichuan Basin [18]. Particularly, desorption gas content and VL value are more easily influenced by clay mineral content, due to that sorbed gas are more likely to store within hydrophobic OM pores rather than hydrophilic clay mineral pores. Overall, the negative influence of clay minerals on shale gas content is due to that high content of immovable water as well as strong compaction.Figure 13
Cross-plots of clay mineral content with pore structures, water saturation, shale gas content, andVL.
(a)(b)(c)(d)(e)(f)Revealed by FE-SEM images, brittle minerals can contain various types of pores with diameters that fall within the meso to macropore range. No significant relationships are displayed among carbonate content and volumes of micropore, mesopore, and macropore (Figure14(a)). However, there is a weak relationship between carbonate content and total porosity (Figure 14(b)), suggesting that partial pores with diameters larger than 200 nm are found within carbonates or along carbonate grains. Therefore, desorption gas and VL display no correlation with carbonate content (Figures 14(c) and 14(d)). There is also no correlation between carbonate content and lost or total gas, probably due to that macropore volume is not saturated by natural gas. From this point of view, carbonate content has no significant role on shale gas accumulation.Figure 14
Cross-plots of carbonate content with (a) pore volume, (b) porosity, (c) shale gas content, and (d)VL.
(a)(b)(c)(d)Pyrite framboids are regarded as an index for anoxic depositional environments [68]. Many scholars have noticed that pyrite framboids may have influence on hydrocarbon generation, accumulation, and preservation. Pyrite framboids usually coexist with OM and contain a great deal of intercrystalline pores and OM pores. With increased burial depth and diagenesis, liquid hydrocarbon eventually migrates into the intercrystalline pores associated with pyrite framboids and finally evolves into solid bitumen. Therefore, intercrystalline pores and OM pores within pyrite-OM complexes are favorable conditions for shale gas accumulation. As seen in Figure 15(a), pyrite content has a weak relationship with micropore volume and no correlations with mesopore and macropore volumes. This indicates that any correlation between pyrite content and micropore volume is likely due to its positive correlation with TOC content. Pyrite/OM complexes develop a certain amount of OM micropores and mesopores that enhance shale gas adsorption capacity. It can be expected that pyrite content exhibits positive correlations with total porosity, desorption gas, and VL (Figures 15(b)–15(d)). However, pyrite content does not correlate with lost gas and total gas (Figure 15(c)). This suggests that intercrystalline pores related to pyrite framboids have no significant influence on free gas content. This further indicates that the mineral pores, particularly macropores, in the studied shales are not saturated by free gas.Figure 15
Cross-plots of pyrite content with (a) pore volume, (b) porosity, (c) shale gas content, and (d)VL.
(a)(b)(c)(d)


### 5.2.3. Physical Properties Control Shale Gas Content

The ability for shale to store and transport natural gas depends on the composition of the shale, more specifically, the pore structures. Shale porosity consists of OM pores, clay mineral pores, dissolution pores, interP pores, and fractures. Different types of pores can retain different forms of shale gas. Previous studies indicated that sorbed gas generally occurs within OM pores, clay mineral surfaces, and pores related to mineral/OM complexes, and free gas can exist in all of the types of interconnected pores. Unlike sorbed gas, free gas is more easily to be escaped from shale gas reservoirs during burial. Therefore, the physical properties have significant influences on shale gas storage capacity.As shown in Figure16(a), the volumes of micropore and mesopore have obvious correlations with VL, with correlation coefficients of 0.95 and 0.73, respectively. This suggests that sorbed gas is mainly stored within micro to mesoscale pores, particularly within micropores. However, macropores with diameters less than 200 nm are not favorable for sorbed gas storage. Micropores and mesopores also exhibit negative correlations to PL value (Figure 16(b)), suggesting that molecular methane is more easily sorbed in micropores and mesopores. Hence, the studied shales dominated with OM nanometer-scale pores are more likely to accumulate shale gas than macropores related to minerals.Figure 16
Cross-plots of pore volume with (a)VL and (b) PL for the studied shales.
(a)(b)Pores with different sizes have different roles on shale gas occurrence and content. As seen in Figures17(a) and 17(b), desorption gas content is directly controlled by micropore and mesopore volumes. More specifically, micropore and mesopore volumes have better correlations with desorption gas content than those with lost gas content, suggesting that desorption gas is primarily released from micropores then mesopores. Interestingly, free gas is also primarily released from micro- to mesopores, because the lost gas content also has positive correlations with volumes of micropores and mesopores. However, there are no correlations between macropore volume and desorption gas, lost gas, and total gas contents (Figure 17(c)). This may be an indication that the macropores are not saturated by free gas. Overall, shale gas content, whether desorption gas, lost gas, or total gas, has a significantly increasing trend with increased total porosity (Figure 17(d)). This case illustrates that shale porosity is mainly made up of OM micro to mesopores, and shale gas occurs mainly as sorbed gas in these nanometer-scale pores.Figure 17
Cross-plots of measured shale gas content with (a) micropore volume, (b) mesopore volume, (c) macropore volume, and (d) porosity.
(a)(b)(c)(d)As illustrated above, shale gas in the studied shales is mainly accumulated as sorbed gas in nanometer-scale pores, and free gas is not saturated within OM pores and mineral-related pores. OM micropores and mesopores are priority to storage sorbed gas, followed by free gas. TOC content is the decisive factor of shale gas content. Inorganic macropores are not favorable spaces for natural gas storage, and mineral compositions have limited contributions to sorbed even free gas content. It can be concluded that shale gas is preferentially stored in hydrophobic OM pores, secondly in neutral brittle mineral pores, and hydrophilic clay mineral pores are not a viable factor for shale gas storage.


## 5.2.1. TOC Controls Shale Gas Content

As illustrated above, pore spaces in the studied shales are mainly contributed by OMs, and therefore, TOC content exhibits a vital role on shale porosity. As shown in Figure12, TOC content is positively correlated with micropore volume and mesopore volume, as well as specific surface area, with correlation coefficients of 0.86, 0.82, and 0.82, respectively. However, TOC content has a negative correlation with macropore volume (Figure 12(a)), suggesting that OM pores are not a major contributor to macropore volume. Overall, shale porosity has a significantly increasing trend with increasing TOC content (Figure 12(b)). This indicates that total porosity is mostly made up of OM nanometer-scale pores rather than the macropores related to minerals, which is also supported by FE-SEM observations (Figure 6). It is well known that sorbed gas exists mainly in micropores and mesopores, and free gas occurs in meso- to macropores and fractures. Hence, abundant micro to mesopores in the studied shales provided numerous spaces for sorbed gas and free gas. However, macropores and fractures are not fully filled by free gas. To further reveal how TOC affects shale gas content, the correlations of TOC content with shale gas content were plotted in Figures 12(d) and 12(e). TOC content has a positive correlation with VL, desorption gas, lost gas, and total gas, with correlation coefficients of 0.9, 0.92, 0.47, and 0.63, respectively. Therefore, we can conclude that TOC is the decisive factor of shale gas content, similar to the Wufeng-Longmaxi shales in Jiaoshiba, Dingshan and Nanchuan areas, and Niutitang shales in Weiyuan-Changniang areas [79–81]. High content of TOC can not only generate a large amount of natural gas but also provide a significant amount of nanometer-scale pores for sorbed gas and free gas. The total gas content determined by in situ desorption measurement is higher than VL value at reservoir conditions, indicating that sorbed gas is saturated at reservoir conditions and there is still partial free gas in the shale reservoir. TOC content displays different degrees of positive influences on desorption gas, lost gas, and total gas. Desorption gas is significantly controlled by TOC content, suggesting that desorption gas is mainly sorbed gas stored within OM micropores and mesopores. However, lost gas content displays only a moderate correlation with TOC content, which illustrates that lost gas is controlled not only by OM mesopores but also mineral pores and fractures. Therefore, we could conclude that desorption gas is primarily derived from sorbed gas but lost gas is made up of not only free gas but also sorbed gas. VL value also shows a better correlation with desorption gas content than that with lost gas (Figure 12(f)), which further proves that desorption gas content is mainly determined by TOC and adsorption gas capacity, and lost gas is derived from two sources as sorbed gas and free gas.Figure 12
Cross-plots of TOC with (a) pore volume, (b) porosity, (c) specific surface area, (d)VL, (e) measured shale gas content, and (f) cross-plot of VL with measured shale gas content.
(a)(b)(c)(d)(e)(f)


## 5.2.2. Mineral Composition Controls Shale Gas Content

Minerals can also provide a certain amount of pores in various shapes and sizes ranging from several nanometers to tens of micrometers [82]. However, the influence of mineral variations on shale gas content is not very clear, due to these shales having been subjected to various geological processes, e.g., burial, compaction, cementation, secondary compaction, and water occupation. Previous studies have indicated that shale composition has significant influences on shale physical properties and further determines shale gas storage and transport mechanisms [21]. In this study, there are negative correlations between clay mineral content and volumes of micropores and mesopores, but a positive correlation occurs between clay mineral content and macropore volume (Figure 13(a)). This implies that clay minerals provide primarily macropores rather than micropores and mesopores. As known, total porosity of the Wufeng-Longmaxi shales is primarily from OM pores, and therefore, total porosity displays a decrease trend with increased clay mineral content (Figure 13(b)). As shown in Figures 13(c) and 13(d), water saturation decreases with an increase of micro to mesopore volume but increases with increased macropore volume and clay mineral content. As illustrated, water molecules are generally sorbed on the surface of hydrophilic clay minerals [21, 69]. Therefore, the studied shales with high clay mineral contents generally have high water saturations. With increased TOC content, water saturation is generally low due to that pore space is primarily determined by hydrophobic OM pores. Hence, the studied shales with higher TOC contents generally have higher natural gas saturations and lower water saturations, which are favorable for shale gas accumulation and storage. Figures 13(e) and 13(f) also prove that the increased clay mineral content would result in a low content of shale gas, exhibited by negative correlations of clay mineral content with desorption gas, lost gas, total gas, and VL. This is well consistent with the shales of Wufeng-Longmaxi and Niutitang Formations in the southeastern Sichuan Basin [18]. Particularly, desorption gas content and VL value are more easily influenced by clay mineral content, due to that sorbed gas are more likely to store within hydrophobic OM pores rather than hydrophilic clay mineral pores. Overall, the negative influence of clay minerals on shale gas content is due to that high content of immovable water as well as strong compaction.Figure 13
Cross-plots of clay mineral content with pore structures, water saturation, shale gas content, andVL.
(a)(b)(c)(d)(e)(f)Revealed by FE-SEM images, brittle minerals can contain various types of pores with diameters that fall within the meso to macropore range. No significant relationships are displayed among carbonate content and volumes of micropore, mesopore, and macropore (Figure14(a)). However, there is a weak relationship between carbonate content and total porosity (Figure 14(b)), suggesting that partial pores with diameters larger than 200 nm are found within carbonates or along carbonate grains. Therefore, desorption gas and VL display no correlation with carbonate content (Figures 14(c) and 14(d)). There is also no correlation between carbonate content and lost or total gas, probably due to that macropore volume is not saturated by natural gas. From this point of view, carbonate content has no significant role on shale gas accumulation.Figure 14
Cross-plots of carbonate content with (a) pore volume, (b) porosity, (c) shale gas content, and (d)VL.
(a)(b)(c)(d)Pyrite framboids are regarded as an index for anoxic depositional environments [68]. Many scholars have noticed that pyrite framboids may have influence on hydrocarbon generation, accumulation, and preservation. Pyrite framboids usually coexist with OM and contain a great deal of intercrystalline pores and OM pores. With increased burial depth and diagenesis, liquid hydrocarbon eventually migrates into the intercrystalline pores associated with pyrite framboids and finally evolves into solid bitumen. Therefore, intercrystalline pores and OM pores within pyrite-OM complexes are favorable conditions for shale gas accumulation. As seen in Figure 15(a), pyrite content has a weak relationship with micropore volume and no correlations with mesopore and macropore volumes. This indicates that any correlation between pyrite content and micropore volume is likely due to its positive correlation with TOC content. Pyrite/OM complexes develop a certain amount of OM micropores and mesopores that enhance shale gas adsorption capacity. It can be expected that pyrite content exhibits positive correlations with total porosity, desorption gas, and VL (Figures 15(b)–15(d)). However, pyrite content does not correlate with lost gas and total gas (Figure 15(c)). This suggests that intercrystalline pores related to pyrite framboids have no significant influence on free gas content. This further indicates that the mineral pores, particularly macropores, in the studied shales are not saturated by free gas.Figure 15
Cross-plots of pyrite content with (a) pore volume, (b) porosity, (c) shale gas content, and (d)VL.
(a)(b)(c)(d)


## 5.2.3. Physical Properties Control Shale Gas Content

The ability for shale to store and transport natural gas depends on the composition of the shale, more specifically, the pore structures. Shale porosity consists of OM pores, clay mineral pores, dissolution pores, interP pores, and fractures. Different types of pores can retain different forms of shale gas. Previous studies indicated that sorbed gas generally occurs within OM pores, clay mineral surfaces, and pores related to mineral/OM complexes, and free gas can exist in all of the types of interconnected pores. Unlike sorbed gas, free gas is more easily to be escaped from shale gas reservoirs during burial. Therefore, the physical properties have significant influences on shale gas storage capacity.As shown in Figure16(a), the volumes of micropore and mesopore have obvious correlations with VL, with correlation coefficients of 0.95 and 0.73, respectively. This suggests that sorbed gas is mainly stored within micro to mesoscale pores, particularly within micropores. However, macropores with diameters less than 200 nm are not favorable for sorbed gas storage. Micropores and mesopores also exhibit negative correlations to PL value (Figure 16(b)), suggesting that molecular methane is more easily sorbed in micropores and mesopores. Hence, the studied shales dominated with OM nanometer-scale pores are more likely to accumulate shale gas than macropores related to minerals.Figure 16
Cross-plots of pore volume with (a)VL and (b) PL for the studied shales.
(a)(b)Pores with different sizes have different roles on shale gas occurrence and content. As seen in Figures17(a) and 17(b), desorption gas content is directly controlled by micropore and mesopore volumes. More specifically, micropore and mesopore volumes have better correlations with desorption gas content than those with lost gas content, suggesting that desorption gas is primarily released from micropores then mesopores. Interestingly, free gas is also primarily released from micro- to mesopores, because the lost gas content also has positive correlations with volumes of micropores and mesopores. However, there are no correlations between macropore volume and desorption gas, lost gas, and total gas contents (Figure 17(c)). This may be an indication that the macropores are not saturated by free gas. Overall, shale gas content, whether desorption gas, lost gas, or total gas, has a significantly increasing trend with increased total porosity (Figure 17(d)). This case illustrates that shale porosity is mainly made up of OM micro to mesopores, and shale gas occurs mainly as sorbed gas in these nanometer-scale pores.Figure 17
Cross-plots of measured shale gas content with (a) micropore volume, (b) mesopore volume, (c) macropore volume, and (d) porosity.
(a)(b)(c)(d)As illustrated above, shale gas in the studied shales is mainly accumulated as sorbed gas in nanometer-scale pores, and free gas is not saturated within OM pores and mineral-related pores. OM micropores and mesopores are priority to storage sorbed gas, followed by free gas. TOC content is the decisive factor of shale gas content. Inorganic macropores are not favorable spaces for natural gas storage, and mineral compositions have limited contributions to sorbed even free gas content. It can be concluded that shale gas is preferentially stored in hydrophobic OM pores, secondly in neutral brittle mineral pores, and hydrophilic clay mineral pores are not a viable factor for shale gas storage.


## 5.3. Existence State of Shale Gas

Shale gas existence state is a significant factor in natural gas productivity. Previous studies have shown that in situ desorption gas in coalbed reservoirs is primarily sorbed gas and in shale reservoirs can contain both sorbed gas and free gas [41, 83]. In coalbed methane reservoirs, it has been documented methane adsorption capacity is higher than total gas content, due to that methane is stored mainly in sorbed state and cannot be released completely from coal reservoir [83]. For a shale gas reservoir, total gas is higher than methane adsorption capacity [41], because total gas determined by in situ desorption tests is a mixed of both free gas and sorbed gas. Free gas is generally higher and is more easily to be released from shale gas reservoir. The in situ desorption isotherm in Figure 7(b) is similar to the methane adsorption isotherm in Figure 9(b), indicating that desorption gas is primarily made up of sorbed gas. The total gas is higher than VL, suggesting that free gas is a main contributor to total gas.In this study, we adopted the methane adsorption capacity at 93°C and 30 MPa as the sorbed gas content at reservoir conditions, which ranged between 1.36 and 4.29 cm3/g. The sorbed gas content positively correlates with desorption gas, lost gas, and total gas (Figure 18(a)). Particularly, methane adsorption content exhibits a better relationship with desorption gas than that with lost gas, suggesting that most desorption gas and partial lost gas are contributed by sorbed gas. We compared sorbed gas content with total gas content and found that sorbed gas can account for 55.32%–81.73%, averaged 63.09% of total gas in theory (Figure 18(b)). With the increase of TOC, free gas proportion has a significant increase due to the increase in OM porosity especially pores>3nm and a decrease in water saturation [20]. However, the actual proportion of sorbed gas in total gas should be less than 63.09%. First, the methane adsorption capacity determined by isothermal methane adsorption presents the maximum of sorbed gas content. Second, partial sorbed gas, in the form of residual gas, is retained in the studied shales, which further reduce the proportion of sorbed gas in total gas. Third, methane adsorption tests were conducted on dried samples, and the influence of the connate water was not considered. Overall, in situ desorption gas comprised mainly of sorbed gas, followed partial free gas. Free gas ratio in the studied shales is significantly higher than that in Cambrian Shuijingtuo shales in which free gas ratio is less than 20% [41] but is lower than the Wufeng-Longmaxi shales in the Sichuan Basin, e.g., Fuling and Changning-Weiyuan shale gas fields [84]. For Fuling and Weiyuan shale gas fields, the free gas accounts for 47.98%–72.81% and 26.70%–82.35%, averaged 55.46% and 57.76%, respectively, in the total gas content. The high ratio of free gas in Fuling and Weiyuan areas is due to high pressure coefficient in the inner Sichuan Basin [19].Figure 18
(a) Cross-plots of methane adsorption content tested at 30 MPa with measured shale gas content (desorption gas, lost gas, and total gas) and (b) comparison of sorbed gas with total gas for the studied shales in LY1 well.
(a)(b)In order to further evaluate shale gas content, we also calculated theoretical shale gas content and compared it with measured total gas content. The sorbed gas has been tested by methane adsorption experiment conducted at 93°C. In terms of the Gibbs adsorption theory, theoretical total gas, sorbed gas, and free gas under specific temperature and pressure can be acquired by the following calculations, respectively [85].
(1)SHtotal=SHex,sorbed+Ф1−Swρapparent.ρbH,T,y/ρbSTP(2)SHabsolute=SHex.ρadHρadH−ρbH,T,y(3)SHfree=SHtotal−SHabsoluteSw is the water saturation, Ф is the porosity, ρapparent is the shale apparent density, ρbSTP is the methane density at 0°C and 0.1 MPa, SHtotal, SHabsolute, and SHfree represent theoretical total gas, absolute adsorption gas, and free gas at depth of H, respectively. H, Tg, and To are the given parameters, Sw, Ф, and ρapparent are fundamental parameters obtained from experiments, ρadH is the adsorption parameter that can be obtained by the SDR model [86], and ρbH,T,y can be calculated with the PVT equation. It is important to state that moisture can reduce sorbed gas content, and therefore, the geological extrapolation according to dry adsorption data should be only used as a maximum scenario. Furthermore, total porosity should be corrected according to burial depth and confining stress, with the equation of y=−0.337lnx+4.835 with R2=0.998 [13]. In this equation, y represents the bulk porosity and x represents the confining stress. The experimental data, the parameters, and the calculated results are displayed in Table 3.Table 3
Sorbed gas, free gas, and theoretical gas content determined by published equations under actual geological conditions.
SamplesDepth (m)Water saturation (%)Porosity at 30 MPa (%)Vex (cm3/g)Apparent density (g/cm3)Sorbed gas (cm3/g)Free gas (cm3/g)Theoretical gas (cm3/g)Measured gas(cm3/g)Free gas proportion(%)LY1-32961.0859.382.230.342.711.36-0.281.084.18/LY1-132971.2231.682.430.492.701.610.241.852.8712.76LY1-252982.6258.581.620.512.691.72-0.661.062.74/LY1-362993.8658.891.940.672.711.98-0.511.474.07/LY1-483004.9340.762.260.872.672.16-0.191.972.74/LY1-563012.2629.943.501.562.592.790.853.643.6223.42LY1-583013.8427.773.701.382.582.730.933.663.9725.40LY1-603015.5035.023.741.432.552.900.633.534.2717.78LY1-633017.2230.314.111.702.563.051.124.174.2626.78LY1-663019.1325.395.332.212.523.881.805.685.2431.75LY1-703021.1923.435.592.192.533.492.425.914.2740.97LY1-733022.9120.465.372.002.503.132.635.765.6945.68LY1-763024.8918.416.752.822.404.293.587.878.6845.49LY1-793026.6130.875.312.282.563.252.195.445.3540.25LY1-803027.7721.254.021.852.502.711.934.644.4341.55As seen in Table3 and Figure 19, when TOC and porosity are low, the theoretical gas content is inconsistent with measured gas content. Particularly, free gas content is negative, likely due to the fact that bulk porosity is not accurate or the overcalculation of sorbed gas under dried conditions in shales with TOC<1%. Therefore, theoretical shale gas content has no relationship with measured shale gas content for the shales with low TOC content. However, for the shales with higher TOC content and porosity, the measured gas content is very consistent with theoretical gas content, with a correlation coefficient of 0.78. This result indicates that actual shale gas content could be predicted using theoretical methods only for organic-rich shales, which has vital importance for shale gas resource assessment and exploration in the absence of desorption gas in field.Figure 19
(a) Vertical variability of sorbed gas, free gas, and theoretical gas content obtained from mathematical model and measured gas content determined by in situ desorption test and (b) cross-plots of theoretical gas content with measured gas content.
(a)(b)


## 5.4. A Schematic of the Types of Shale Gas Reservoirs

As illustrated above, free gas is usually lower than sorbed gas under natural burial conditions, indicating that natural gas is first stored in the sorbed state and then in the free gas state. As illustrated by [32], pores with diameters of 1–4 nm store primarily sorbed gas in the Lujiaping Formation shale. Yu et al. [20] pointed out pores smaller than 3 nm store primarily sorbed gas and pores larger than 3 nm store primarily free gas. These smaller pores can sorb a single layer of methane molecules, with strong interactions between pore walls and the methane molecular. Therefore, sorbed gas has a hard time escaping from the shale reservoir. However, natural gas migrates from shale reservoirs, so it must displace water in the pores/fractures. Only when reservoir pressure decreases to a critical pressure can sorbed gas migrate from OM pores. As illustrated by [82], the Wufeng-Longmaxi shales are primarily dominated by pores with diameters<4 nm, and therefore, these shales have a strong methane adsorption capacity and a high capillary pressure. This gives rise to high sealing capacity and good preservation condition for shale gas in such a complex tectonic region. With increased depth, both TOC and porosity increase, which significantly increases pore space for free gas under high stratum pressure. In this case, the proportion and content of free gas increase (Figure 19(a)), and it can be explained by the microscopic mechanism of gas preservation in the Wufeng-Longmaxi shales.Natural gas in a shale gas reservoir experiences sorbed, desorbed, diffused, and accumulated processes. The four stages, as sorbed stage, pore filling stage, fracture filling stage, and gas accumulation stage, of shale gas storage were divided. The generated natural gas firstly satisfies physical adsorption and dissolution, followed by the existence in free gas, which is similar to the shale gas desorption process [87]. Therefore, a microscopic model of shale gas existence was proposed based on FE-SEM images, shown in Figure 20. Small dots with different colors (yellow, red, and blue) indicate three gas molecules (sorbed gas, free gas, and water molecular), and the density of small dots indicates the main occurrence sites of gas/water molecules. As shown in Figure 20, shale gas occurs in different states in different types of pores. With increased thermal maturation, natural gas first satisfies the adsorption demands of OM particles and the surfaces of mineral grains. During this period, sorbed gas dominates the process. Simultaneously, limited natural gas would be dissolved in water, kerogen, asphalt, and residual oil. With large quantities of natural gas produced, the sorbed gas is saturated and excess gas in the free gas state would migrate into OM pores, interP pores, and microfractures. However, clay mineral pores are almost occupied by water moleculars as water saturation reaches 18.41%–69.33% with averaged value 43.87%. Overall, OM pores within solid bitumen, depositional OM, and mineral/OM complexes, are preferentially storage for sorbed gas, followed by free gas. With the increase of TOC, free gas content is significantly increased, due to that more OM pores with sizes>3−4 nm are developed. Clay minerals have a limited contribution to sorbed gas and free gas. Though fractures are filled by calcite and solid bitumen or closed under actual geological condition, they could still provide a certain space for free gas. Therefore, shale gas potential is controlled primarily by OM pore development level and then by fractures.Figure 20
Microscopic occurrence model of shale gas in the accumulation process. (a–c) OM pores and surfaces are primary space for sorbed gas and most free gas; (d and e) clay mineral pores are most filled by water molecules and have limited contribution to sorbed gas and free gas; (f) sorbed gas, free gas, and molecular water exist within clay minerals; (g) dissolution pores can provide space for free gas; (h) OM/pyrite complex contains OM pores and interP pores that contribute firstly to sorbed gas and followed free gas; (i) microcracks contribute primarily to free gas and limited sorbed gas.
(a)(b)(c)(d)(e)(f)(g)(h)(i)


## 6. Conclusions

The evaluation of shale gas content serves an important role in shale gas exploration and development. In this study, we investigated shale gas content of the Wufeng-Longmaxi Formation in normal pressure area of northwestern Guizhou by two ways: practical measurement and theoretical calculations. Theoretical calculations determined by adsorption measurements from isothermal experiments and total porosity were compared with practical measurements by in situ desorption test. The controlling factors of shale gas content were also discussed. And the following conclusions were obtained.(1)
The dominated pore type in the Wufeng-Longmaxi Formation shales is mainly OM pores in solid bitumen and depositional OM, which contribute greatly to shale porosity and surface area. Rigid grains, primarily quartz, carbonate, and pyrite can resist tectonic stress and protect OM pores(2)
Desorption gas, lost gas, and total gas determined by in situ desorption methods are in the range of 0.42–1.54, 1.9–7.14, and 2.72–8.68 cm3/g, respectively. Langmuir volumes obtained from high-pressure adsorption tests vary from 1.63 to 4.78 cm3/g. TOC content is the decisive factor of in situ desorption gas content and methane adsorption capacity, indicating shale gas is primarily stored in OM-hosted micropores and mesopores. Clay mineral content has negative correlations with shale gas content, due to that clay minerals are easily compacted and occupied by water molecules(3)
Methane adsorption capacity at reservoir conditions (93°C and 30 MPa) is considered to be sorbed gas content, which accounts for 63.09% of total gas content and is higher than that in the Wufeng-Longmaxi Formation in abnormal high-pressure areas, e.g., Fuling and Changning-Weiyuan gas fields. With increased TOC content, free gas proportion has a significant increase due to the increase in OM porosity and a decrease in water saturation(4)
By comparing theoretical gas content with actual measured gas content, theoretical gas content is well consistent with measured gas content only whenTOC>3%. This helps to predict shale gas geological reserves for organic-rich shales in the absence of shale gas content. Shale gas occurrence mechanism model was proposed in terms of FE-SEM images and free gas/sorbed ratio, which provides a reference for shale gas exploitation in normal pressure areas



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