The results of total organic carbon and mineral compositions of 14 samples are listed in Table 1. The total organic carbon of studied 14 samples varies from 1.39% to 7.22%, with a mean value of 4.48%. All shale samples mainly consist of quartz, feldspar, clay minerals, calcite, dolomite, and a lower content of pyrite. All samples are clay-rich, and the content of clay minerals varies from 19.8% to 54.5%, with a mean value of 35.9%. The content of quartz varies from 21.1% to 64.4%, with a mean value of 38.7%. The positive correlation between TOC and the content of quartz can be observed (Figure 3A), which may indicate that the quartz is mainly of biogenic origin (Guo, 2014; Liang et al., 2016).

The results of desorption experiments show that the gas volume ranges from 2.14 m³/t to 6.01 m³/t, with a mean value of 4.12 m³/t (Table 2). All samples show the gas volume exceeds 1 m³/t, which indicates it reaches the industrial standard. The positive correlation between TOC and gas volume (Figure 3B) indicates that the organic matter provides the main pore volume for the preservation of shale gas. The molecular composition of desorption gases is dominantly hydrocarbon gases, in which methane and ethane meanly account for 99.70% (99.64‰–99.74%) and 0.30% (0.26‰–0.36%), respectively, and no carbon dioxide, hydrogen sulfide, and nitrogen are detected. The lower wetness of shale gas from Wufeng–Longmaxi shale is very common in Sichuan Basin and its adjacent areas, such as Changning, Jiaoshiba, and Weiyuan areas (Dai et al., 2014; Feng et al., 2016).

The carbon isotopic results (Table 2) show that the methane carbon isotopic values (δ¹³C-CH₄) of desorption gases range from −37.41‰ to 31.21‰, with a mean value of −33.70‰. The ethane carbon isotopic values (δ¹³C-C₂H₆) range from −37.90‰ to −35.47‰, with a mean value of −36.27‰. The carbon isotopic values of desorption gases show an obvious reversal distribution (Figure 4A, δ¹³C-CH₄ > δ¹³C-C₂H₆), which is similar to other areas, such as Changning, Weiyuan, Jiaoshiba, and Dingshan in the Sichuan Basin (Dai et al., 2014; Dai et al., 2016; Feng et al., 2016; Yang et al., 2017; Zhong et al., 2019). Figure 4B shows that shale gas samples of Well XK-3 fall in the post-rollover zone with the wetness lower than 1.2%, suggesting an extremely high maturity (Dai et al., 2014). In addition, the δ²H-CH₄ (‰) values range from −157.07‰ to −159.99‰, with a mean value of −154.37‰, which is similar to Weiyuan (with a mean value of 141.50‰), Jiaoshiba (with a mean value of 148.95‰), and Changning (with a mean value of 148.00‰) areas.

For discussing the origin of desorption gas, we also built the geological model of Well XK-3 by using PetroMod software with the constrain of measured maturity data (Ro%) from publications (Zhao et al., 2015; Guo et al., 2016). The results of burial and thermal histories of Wufeng–Longmaxi shale from Well XK-3 are shown in Figure 5 (Zhao et al., 2015; Guo et al., 2016). It can be seen that Wufeng–Longmaxi shale of Well XK-3 experienced four stages of deep burial and uplift. The shale in Well XK-3 experienced a long-term erosion caused by Guangxi movement in the Late Silurian and the burial depth of Wufeng–Longmaxi shale is shallow (<1,500 m), when the temperature of Wufeng–Longmaxi shale is about 70°C and the maturity (Ro%) of the shale is about 0.40%, showing an immature stage. During the Permian period, there was short-term quick erosion due to the Dongwu movement (approximately 259 Ma). At that period, the burial depth of Wufeng–Longmaxi shale was also lower than 1,500 m, the temperature was approximately 90°C, and the maturity (Ro%) was about 0.50%, which was still in the immature stage. After the Dongwu movement, the Wufeng–Longmaxi shale of Well XK-3 entered into a long-term continuous deep burial stage and a short-term erosion related to the Indosinian movement occurred during the Late Triassic period. Meanwhile, the temperature and maturity (Ro%) of Wufeng–Longmaxi shale increased with the burial depth. Since the middle Triassic (approximately 235 Ma), the Wufeng–Longmaxi shale has been in the main oil stage (Ro = 0.70–1.00%); the burial depth was more than 2,700 m, and the temperature was about 120°C. Subsequently, the shale entered into the wet gas stage at the Late Jurassic (Ro > 1.30%, approximately 150 Ma) and dry gas stage at the early stage of Late Cretaceous (Ro > 2.00%, approximately 100 Ma), successively. The burial depth of Wufeng–Longmaxi reached the maximum depth (approximately 5,500 m) at the Late Cretaceous. At the same time, the temperature of the Wufeng–Longmaxi shale in Well XK-3 reached 190°C, and the maturity of the shale reached the current level (around 2.21%). Then, the shale of Well XK-3 uplifted and was eroded because of the Himalayan movement. Currently, the burial depth of Wufeng–Longmaxi shale in this area is about 650 m, and the temperature is about 37°C.

Whiticar’s diagrams (Whiticar, 1999) could be used to determine the origin of natural gases based on the chemical and isotopic compositions of natural gases. As Figure 6A shows, shale gases from Well XK-3, Dingshan, Changning, Weiyuan, and Jiaoshiba are of thermogenic origin, which is different from the gases from Barnett and Fayetteville shales. The δ¹³C-CH₄ vs. CH₄/(C₂H₆+C₃H₈) diagram (Figure 6B) shows that shale gases from Barnett and Fayetteville shales fall into the type II zone. On the contrary, shale gases from Well XK-3, Dingshan, Changning, and Jiaoshiba areas almost fall into the zone shifting from the typical type II kerogen gases, except for the Weiyuan area. This phenomenon may be caused by the extremely high content of methane and heavier carbon isotopic value at a relatively higher thermal maturity stage (Ro > 2.00%) (Liu et al., 2016; Yang et al., 2017). The δ¹³C-C₂H₆ values could be used to classify two types of natural gases. Dai (2011) proposed that natural gases with δ¹³C-C₂H₆ < −28.5‰ are oil-associated gases, while the gases with δ¹³C-C₂H₆ > −29‰ are coal-derived gases. Although there are some different viewpoints regarding this threshold (Milkov et al., 2020), a range of −27.0‰ to −29.0‰ for δ¹³C-C₂H₆ value is acceptable for distinguishing oil-derived gases. As shown in Table 2, the δ¹³C-C₂H₆ values of the gas samples are between −37.90‰ and −35.47‰, suggesting that the desorption gases of Wufeng–Longmaxi shale from Well XK-3 are oil-associated gases, which is similar to other areas in the Sichuan Basin (Figure 4).

The carbon isotopic reversal is commonly observed in Wufeng–Longmaxi shale gas in the Sichuan Basin (Figure 4A). Previous studies interpreted and summarized the following causes of this phenomenon: 1) mixing gases with different thermal maturity (Hao and Zou, 2013; Xia et al., 2013; Liu Q. et al., 2018; Zhao et al., 2019); 2) redox reactions with transition metals and water (Burruss and Laughrey, 2010; Feng et al., 2016); 3) depressurization during uplifting (Milkov et al., 2020); and 4) thermochemical sulfate reduction (Hao et al., 2008; Liu et al., 2019).

In order to discuss the cause of carbon isotopic reversal in this area, we recovered the generation history of hydrocarbons of Wufeng–Longmaxi shale of Well XK-3 with consideration of oil secondary cracking based on Pepper’s hydrocarbon generation kinetics (Pepper and Corvi, 1995), and the results are shown in Figure 7. During the relatively lower maturity stage (Ro < 1.00%), a considerable amount of gases was mainly from kerogen cracking, and no or little retained oil cracking before oil cracking (Figure 7). δ¹³C increased with the carbon number, and the carbon isotopic distribution was normal (Figures 4A, 7; δ¹³C-CH₄ < δ¹³C-C₂H₆); thus, the carbon isotopic reversal was not observed due to the same origin of gases. With the increase in thermal maturity and burial depth, the open system was gradually converted into a closed system. When thermal maturity (Ro%) reached over 1.00% (165 Ma, T = 160°C), the retained oil started cracking (Figures 5A, 7). The retained oil was mainly cracked and converted into wet gases and generated lighter δ¹³C-C₂H₆ values (Liu Q. et al., 2018). As a result, δ¹³C-C₂H₆ becomes lighter due to the mixing of gases from kerogen cracking and retained oil cracking (Dai et al., 2017; Liu Q. et al., 2018). Although δ¹³C-CH₄ also becomes lighter, the extent of change for δ¹³C-CH₄ is not as obvious as δ¹³C-C₂H₆ (Figure 4A)_. The main reason causing isotopic reversal is that the retained oil mainly cracked into wet gases with a little methane, and methane was mainly from kerogen cracking (Xia et al., 2013). During this stage, δ¹³C-C₂H₆ becomes more negative with the increase in thermal maturity, and reversal carbon isotopic distribution (δ¹³C-CH₄ > δ¹³C-C₂H₆) occurs with increasing contribution of wet gases from retained oil cracking (Figure 4). Therefore, we proposed that mixing gases from kerogen and retained oil cracking might be the main reason for the carbon isotopic reversal in this area.

In this study, we also collected carbon isotopic data of Wufeng–Longmaxi shale gas from Changning, Weiyuan, Dingshan, and Jiaoshiba areas. Although the values of δ¹³C-CH₄ and δ¹³C-C₂H₆ for shale gas are distributed in the reversal zone, we still found that there existed differences in the carbon isotopic values of shale gases in different areas, Sichuan Basin (Figure 8). The mean values of δ¹³C-CH₄ are −36.21‰ in Weiyuan (Dai et al., 2014), −33.70‰ in Well XK-3, −30.73‰ in Dingshan (Zhong et al., 2019), −30.59‰ in Jiaoshiba (Dai et al., 2016; Yang et al., 2017), and −28.34‰ in Changning (Feng et al., 2016), respectively. The mean values of δ¹³C-C₂H₆ are −39.31‰ in Weiyuan (Dai et al., 2014), −36.27‰ in Well XK-3, −34.09‰ in Dingshan (Zhong et al., 2019), −35.09‰ in Jiaoshiba (Dai et al., 2016; Yang et al., 2017), and −33.44‰ in Changning (Feng et al., 2016), respectively. As shown in Figure 8, the carbon isotopic values of Well XK-3 and Weiyuan are lighter than those of the other areas, and gases from Changning show the heaviest carbon isotopic values for both methane and ethane. We regard that this difference may be controlled by thermal maturity. The current maturities of Wufeng–Longmaxi shale from Weiyuan, Xishui, Dingshan, Jiaoshiba, and Changning are 2.00%–2.20% (Feng et al., 2016), 1.80%–2.20% (Zhao A. et al., 2017), 2.14%–2.24% (Wei et al., 2017), 2.50%–2.80% (Feng et al., 2018), and 2.50%–3.00% (Chen et al., 2017), respectively. It is obvious that there exists a positive correlation between δ¹³C-CH₄ or δ¹³C-C₂H₆ and thermal maturity (Figure 8).

The generation history of Wufeng–Longmaxi shale of Well XK-3 shows the retained oil stopped cracking into gases when thermal maturity reached 2.00% (Figures 5A, 7, approximately 100 Ma, T = 185°C). The current thermal maturity of Wufeng–Longmaxi shale is over 2.00%, which indicates that Wufeng–Longmaxi shale had experienced the stage of retained oil cracking into wet gases. It is worth noting that gaseous hydrocarbons are still generated and increased when thermal maturity is greater than 2.00% (Figure 7). This increasing part of generated gases might be from kerogen cracking because the cracking of retained oil is stopped. Meanwhile, heavier gaseous hydrocarbons are further cracked and converted to lighter gaseous hydrocarbons, and this process is also controlled by thermal maturity (Hao and Zou, 2013; Liu Q. et al., 2018). The current maturity (Ro%) values of Wufeng–Longmaxi shale in Changning and Jiaoshiba areas are higher than those in Xishui, Weiyuan, and Dingshan areas. It may indicate that Wufeng–Longmaxi shale in Changning areas experienced a longer period of heavier gases cracking into lighter gases. Thus, the carbon isotopic values of shale gases in Changning and Jiaoshiba are heavier than those of other areas.