Eighteen shale gas samples from the southeastern Sichuan Basin were collected using steel cylinder gas containers with a maximum gas pressure capacity of 15 MPa and a maximum volume of 1,000 mL. To avoid atmospheric contamination, the containers were flushed with wellhead gas at least 10 times before gas collection. The studied shale gas samples were collected from the sweet shale gas layer (Wufeng‒Longmaxi Formation) based on a continuous pressure coefficient series moving from the intra-basin and basin-margin transition belt toward the basin exterior; specifically, they were collected from Pingqiao (PQ), Dongsheng (DS), Jinfo (JF), Wulong (WL), and Pengshui (PS). The pressure coefficients for the Long-1 shale gas from these regions were 1.35 (PQ), 1.20–1.35 (DS), 1.12–1.20 (JF), 1.08 (WL), and 0.98 (PS), respectively.

The chemical compositions of non-hydrocarbon gases (CO₂, H₂, H₂S, N₂, and He) and hydrocarbon gases were examined. Non-hydrocarbon molecular compositions were analyzed using a gas composition mass spectrometer (MAT-271). Hydrocarbon gas compositions were analyzed using a gas chromatograph (GC, Agilent 6890N) equipped with an FID detector. To differentiate each of the individual hydrocarbon gas components (e.g., CH₄, C₂H₆, and C₃H₈), an aluminum oxide capillary column with a length of 50 m and a diameter of 0.53 mm was used. The oven temperature setting for GC analysis was set at 30°C for 10 min, followed by an increase to a target temperature of 180°C at a heating rate of 10°C/min, and then maintained at the target temperature for 20–30 min.

An Agilent 6890N GC equipped with an isotope ratio mass spectrometer (IRMS, Delta plus XP) was used to determine the δ¹³C signatures of individual hydrocarbon gas components. The operating temperature for δ¹³C analysis was set at 30°C for 3 min, followed by an increase to a target temperature of 250°C at a heating rate of 10°C/min, and then maintained at the target temperature for 50 min. To calculate the δ¹³C values of hydrocarbon gases, three pulses of standard pure CO₂ gas were injected into the GC‒IRMS instrument. The overall analytical precision was ±3‰.

A MAT-253 IRMS coupled with an HP6890 GC instrument was used to analyze shale gas H isotopes. CH₄ and C₂H₆ components were chromatographically distinguished using a fused silica capillary column (HP-PLOT Q, 30 m × 0.32 mm × 20 μm). The operating GC temperature for H isotope analysis was set at 40°C for 5 min, followed by an increase to 80°C at a heating rate of 5°C/min, a further increase to 140°C at a heating rate of 10°C/min, and a final increase to a target temperature of 260°C at a heating rate of 30°C/min (Xing et al., 2021). The pyrolysis-oven temperature was set at 1,450°C, and a standard H₂ sample was used as the reference gas. The accuracy of the H isotope analysis was approximately ±3‰. Hydrogen isotope data are reported in δ notation (δD, ‰) relative to Vienna Standard Mean Ocean Water (VSMOW = 0.0‰). An internal standard was measured to calibrate the δD data for the studied shale gas samples (Cao et al., 2020).

Abundances and isotopic compositions of noble gases (He, Ne, and Ar) were measured using a noble gas isotope mass spectrometer (Noblesse SFT). The shale gas sample container was first connected to the purification vacuum system. After the system reached vacuum, the gas sample was introduced into a gas pipette with a volume of 8.5 cm³. According to the pressure and temperature variations in the gas pipette before and after the gas sample introduction, the absolute amount of gas sample introduced was calculated. Then, 1.5 cm³ of the gas sample was further introduced to the online noble gas isotope mass spectrometer for noble gas purification. Details of the analytical procedure for noble gas abundance and isotope composition determination can be found in Cao et al. (2018).

Shale gas yields from the basin-margin transition belt and extra-basin complex fold belt vary markedly. Considering that drilling wells in different structural zones are currently in different stages of production, daily shale gas production values for the first 500 production days were compared herein (Table 1; Figure 2). Compared with the highly pressured Jiaoshiba shale gas production region (e.g., 20.3 × 10⁴ m³/day for well JY1), daily shale gas production values in the study area were much lower. Shale gas production in the PQ area was the highest, ranging from 4.19 × 10⁴ to 6.55 × 10⁴ m³/day (average: 5.55 × 10⁴ m³/day). The average daily shale gas production values for the DS and JF areas were 3.32 × 10⁴ and 3.40 × 10⁴ m³/day, respectively. Shale gas production in the extra-basin complex fold belt was much lower, with average values of 2.15 × 10⁴ m³/day for the WL area and 0.77 × 10⁴ m³/day for the PS area. In general, daily shale gas production exhibited a decreasing trend with a decreasing pressure coefficient across the study area.

Shale gas compositions from 18 wells within the Wufeng‒Longmaxi Formation in the southeastern Sichuan Basin are shown in Table 1. All samples were dominated by CH₄, with minor amounts of C₂H₆ and non-hydrocarbon gases (e.g., N₂, CO₂, and He). The CH₄ content ranged from 95.99% to 98.8%, with an average of 97.2%; the C₂H₆ content ranged from 0.28% to 0.99%, with an average of 0.48%; and the C₃H₈ content in all shale gas samples was very low, with an average of 0.01%. Non-hydrocarbon gases in the studied shale gas samples mainly consisted of N₂ (0.76%–3.11%, average: 1.39%) and CO₂ (0.01%–0.321%, average: 0.16%). The non-hydrocarbon gases He and Ar occurred in trace amounts in the shale gas samples and were detected using more precise noble gas mass spectrometry (the results are presented in Section 4.4).

The δ¹³C signatures of alkane gases varied among shale gas samples collected from different areas. The δ¹³C₁ values ranged from −36.5‰ to −29.6‰, with average values of −34.3‰, −33.8‰, −33.1‰, −30.7‰, and −30.8‰ for the PQ, DS, JF, WL, and PS areas, respectively. The δ¹³C₂ values ranged from −38.2‰ to −33.4‰, with average values of −37.1‰, −37.4‰, −36.2‰, −30.7‰, and −33.4‰ for the PQ, DS, JF, WL, and PS areas, respectively. The δ¹³C signatures of alkane gases exhibited an increasing trend with a decreasing pressure coefficient. In contrast to the δ¹³C data, the δD signatures of alkane gases showed no evident pattern of change with a decreasing pressure coefficient, with δDC₁ ranging from −162.2‰ to −165.4‰ and δDC₂ ranging from −166.1‰ to −135.1‰.

He, Ne, and Ar concentrations and isotopic data from the 18 studied Longmaxi shale gas samples are presented in Table 2. The He concentration ranged from 383.6 to 976.9 ppm, with an average of 550.3 ppm. The He concentration varied among shale gas samples collected from different areas, showing an increasing trend with a decreasing pressure coefficient moving from the intra-basin toward the basin exterior. The average He contents of shale gas from the PQ, DS, JF, WL, and PS areas were 551.0, 446.2, 444.8, 530.5, and 954.3 ppm, respectively. Ne and Ar concentrations had ranges of 0.01–0.278 and 26–96 ppm, respectively.

³He/⁴He ratios ranged from 0.0045 to 0.013 Ra, where Ra is the atmospheric ratio of (1.384 ± 0.013) × 10^–6 (Ozima and Podosek, 2017; Mishima et al., 2018). ²⁰Ne/²²Ne ratios (9.3–11.7, average: 10.6) were higher than the atmospheric value (9.80; Sarda et al., 1988) and lower than the mantle value (12.2; Ballentine et al., 2005). ⁴He/²⁰Ne ratios ranged from 2,425.8 to 75,716.2, much higher than the atmospheric value of 0.288 (Kipfer et al., 2002). Most ²¹Ne/²²Ne ratios (0.028–0.039, average: 0.033) were higher than the atmospheric value (0.02959; Gyore et al., 2019), indicating a mixed source of two end-members: crustal (0.03–0.70; Ozima and Podosek, 2017) and atmospheric Ne. The ⁴⁰Ar/³⁶Ar ratios of the studied shale gas samples varied from 730.1 to 1,648.2, with an average of 1,286.7; these ratios are much higher than those of air, indicating no apparent noble gas contamination from the atmosphere during shale gas sampling and analysis.

The origin of Longmaxi shale gas has been widely discussed in previous studies (Hao et al., 2013; Dai et al., 2014; Wu et al., 2017; Cao et al., 2018; Liu et al., 2021). Methane is the dominant component in the high-/over-pressured Longmaxi shale gas produced (Dai et al., 2014; Liu et al., 2021). Normally pressured shale gas samples in the studied southeastern margin of the Sichuan Basin show similar characteristics, with high CH₄ abundance and high gas dryness ratios [C₁/(C₂ + C₃)] (94.3–339.7, avg. 216.8). The δDC₁ values of normally pressured shale gas have a similar distribution range to those of Wufeng‒Longmaxi shale gas from Weiyuan and Changning, as reported by Dai et al. (2014). Plots of δ¹³C₁ versus [C₁/(C₂ + C₃)] (Figure 3A) and δ¹³C₁ versus δDC₁ (Figure 3B) both suggest that the Longmaxi shale gas is of late-mature thermogenic origin. A kinetic isotope effect resulting from differences in the energy required to cleave ¹²C\¹²C and ¹²C\¹³C bonds in shale gas precursors has been reported (Tang et al., 2000). Such a kinetic isotope effect results in a more positive δ¹³C composition in hydrocarbons at higher maturity (Xia et al., 2013).

The δ¹³C₁ and δ¹³C₂ values of our normally pressured shale gas samples are plotted in Figure 3C, together with those of Barnett (Milkov et al., 2020), Fayetteville (Milkov et al., 2020), and Wufeng‒Longmaxi (Dai et al., 2014) shale gas samples studied previously, in which the dashed line represents the relationship δ¹³C₁ = δ¹³C₂. Above the dashed line, a normal δ¹³C trend exists, characterized by δ¹³C₁ < δ¹³C₂. The turning point in this normal trend area has been suggested to represent the start of secondary hydrocarbon cracking and mixing of gas (primary and secondary cracking), which would likely cause a δ¹³C reversal among alkane gases (Tilley and Muehlenbachs, 2013; Xia et al., 2013). Shale gas with a normal δ¹³C trend is mostly related to the low‒middle stage of maturity. As maturity increases, a reversal in the trend (δ¹³C₁ > δ¹³C₂) can be observed. A further turning point in this reversed trend area has been suggested to represent a post-reversal stage at an extremely high or over-mature stage of evolution (Dai et al., 2014). This was confirmed by Xia et al. (2013) when applying a δ¹³C correlated with the maturity model and by Wu et al. (2017) when studying even higher-maturity Lower Cambrian Niutitang shale gas.

For our normally pressured shale gas, δ¹³C and δD data suggest that the shale gas originated from late-mature thermogenic generation, equivalent to shale gas in other production areas of the inner Sichuan Basin. The [C₁/(C₂ + C₃)] data exhibit a negative relationship with δ¹³C₁ and δ¹³C₂ (Figure 4). Shale gas from the basin-margin transition belt (areas PQ, DS, and JF) is characterized by higher [C₁/(C₂ + C₃)] and lighter δ¹³C compared with shale gas samples from the extra-basin complex fold belt (areas WL and PS). The slope trend of decreasing [C₁/(C₂ + C₃)] with heavier δ¹³C matches the decreasing trend of the pressure coefficient for the selected shale gas samples. Meanwhile, daily shale gas yields for the selected production wells exhibit a negative correlation with δ¹³C and a positive correlation with [C₁/(C₂ + C₃)] (Figure 5), indicating that shale gas production wells in the basin-margin transition belt and extra-basin complex fold belt have completely different shale gas yields and gas geochemistry characteristics. The PS, DS, and JF areas have better gas production than WL and PS. The reason for this phenomenon may be that shale gas expulsion efficiency and gas source supply are different in different structural belts.

Meng et al. (2022) studied the CH₄ and C₂H₆ δ¹³C changes in the Triassic Yanchang Formation from the Ordos Basin using pressure coring to avoid the problem of lost gas. During shale gas desorption, both δ¹³C₁ and δ¹³C₂ values became heavier, and gas dryness coefficients (C₁/C_1‒5) decreased with increasing desorption rates. Smaller molecules (e.g., CH₄) desorb more rapidly than longer-chain hydrocarbon gases. For normally pressured shale gas, variations in gas geochemistry characteristics provide evidence for the gas accumulation and expulsion processes during geological time. The WL and PS areas within the extra-basin complex fold belt experienced earlier uplift compared with the PQ, DS, and JF areas within the basin-margin transition belt (Figure 6, modified after Teng et al., 2020). Although shale layers in the WL and PS areas have similar top and bottom cap-rock conditions to those in the inner basin area (e.g., Fulin shale gas field), their relatively poor self-sealing capacity and low displacement pressure mean that an episodic hydrocarbon expulsion process is more likely to occur. More oil and gas escape from these shale layers during the peak hydrocarbon generation period, reducing the potential source supply for later shale gas generation during higher maturity stages. During expulsion, hydrocarbons with a lighter δ¹³C escape first, leaving the residual hydrocarbons richer in ¹³C. As the pressure coefficient decreases, the hydrocarbon expulsion efficiency increases and residual gas abundance is reduced. Therefore, the PS shale gas samples are characterized by the heaviest δ¹³C values, lowest gas dryness coefficients, and lowest daily gas yields among all studied shale gas samples.

The H atom is much smaller than the C atom; hence, H isotope fractionation occurs more readily during shale gas expulsion or desorption. Notably, unlike δ¹³C, the δD values of CH₄ and C₂H₆ show little variation with changes in pressure coefficient across all studied shale gas samples. A previous study suggested that δD values in alkane gases desorbed from pressure coring remained stable with increasing gas desorption rates (Meng et al., 2022).

In subsurface fluid systems, noble gases can have atmospheric, mantle, or radiogenic origins, with distinct isotopic signatures associated with each component (Ballentine et al., 2005). According to its origin, there are three types of He: atmospheric, mantle-derived, and crust-derived. Helium has two isotopes: primordial ³He and ⁴He sourced from the radioactive decay of ²³⁸U, ²³⁵U, and ²³²Th over geological time (Graham, 2002). The origin of He is usually determined using the ratio of the isotopic abundances of ³He and ⁴He, i.e., R = ³He/⁴He. Atmospheric He is ubiquitous in the air, showing no industrial significance, owing to its low concentration. The R value for atmospheric helium is 1.4 × 10⁶, normally referred to as Ra. Mantle-derived He refers to He of deep magmatic origin, including the original ³He captured in the early stage of the formation of the Earth, and ⁴He produced by radioactive decay, with a high R ratio of approximately 8 Ra. Crust-derived He is mainly sourced from α radioactive decay of U and Th in ancient sedimentary rocks, metamorphic rocks, migmatites, and granites. This crust-derived He, with a low R ratio of approximately 0.02 Ra, is an important source of He input in natural gas reservoirs (Oxburgh et al., 1986; Ballentine and Lollar, 2002; Kennedy and van Soest, 2005; Wang et al., 2020). As shown in a plot of R/Ra vs ⁴He/²⁰Ne (Figure 7A), the ³He/⁴He ratios (R/Ra) of our normally pressured shale gas samples range from 0.0045 to 0.013 Ra, all plotted within the crust end-member region. A plot of CH₄/³He vs R/Ra (Figure 7B) also indicates that the studied shale gas samples lie in the crustal field, suggesting that the Longmaxi shale gas received a substantial contribution of crust-derived He; this is consistent with the Weiyuan and Changning shale gas samples studied by Cao et al. (2020).

Argon has three isotopes, namely, ⁴⁰Ar, ³⁸Ar, and ³⁶Ar, with ⁴⁰Ar mainly sourced from the radioactive decay of K, and ³⁸Ar and ³⁶Ar of primordial origin (Ballentine and Burnard, 2002). The ⁴⁰Ar/³⁶Ar ratios of our shale gas samples are relatively high (Figure 8; ranging from 1,194.3 to 4,604.5), indicating a radiogenic origin consistent with that suggested by the He isotope data. The ⁴⁰Ar/³⁶Ar ratios of our shale gas samples exhibit similar values to those of Jiaoshiba shale gas but are higher than those of Changning shale gas samples from the southern Sichuan Basin (Wang et al., 2022).

Compared with conventional natural gas reservoirs, the enrichment and preservation of noble gas and the controlling factors of the formation of He-rich natural gas reservoirs show some similarities and also differences. Regions with high hydrocarbon generation intensity that are conducive to the formation of large oil and gas reservoirs may not be conducive to the formation of He-rich natural gas reservoirs. However, tectonic uplift and denudation areas with relatively low hydrocarbon generation intensity may be favorable for forming He-rich natural gas. The same applies to shale gas reservoirs, in which self-generation and self-storage occur. Excessive hydrocarbon generation intensity greatly dilutes the concentration of He. Therefore, for self-generated and self-stored He-rich shale gas reservoirs, despite the high content of U and Th in shale, it is difficult to achieve commercial development of He, owing to the dilution effect of hydrocarbon gases (Wang et al., 2020). The He concentration of Wufeng‒Longmaxi shale gas is relatively low in the high-yield Jiaoshiba and Changning areas, with average concentrations of 205 and 376 ppm, respectively. However, in extra-basin areas that are structurally complex, the He concentration can reach 941 ppm (Wang et al., 2022).

The spatial distributions of He and Ar concentrations have been suggested to be closely related to the accumulation and dissipation of shale gas (Wang et al., 2022). Owing to mixing and dilution, the concentration of He decreases with an increase in the shale gas content. Compared with shale gas development areas in a structurally stable basin, such as Changning and Jiaoshiba, the preservation conditions of shale gas in structurally complex areas outside the basin, such as Pengshui in southeastern Chongqing, are relatively poor. At the over-mature evolution stage, owing to the continuous decay of U and Th releasing ⁴He, higher He contents are found in structurally complex areas outside the basin compared with inner basin areas with high shale gas production.

As shown in Figure 9, the He and Ar concentrations of shale gas samples from the basin-margin transition belt (PQ, DS, and JF areas) are lower than those of the extra-basin complex fold belt (WL and PS areas). The He and Ar concentrations of PS shale gas samples in this study are consistent with previous data (He: 716–941 ppm, Ar: 42–56 ppm; Wang et al., 2022). The contents of ⁴He and ⁴⁰Ar show a weak positive correlation (Figure 10A), indicating a radiogenic contribution for both noble gases.

The He content exhibits a negative correlation with daily shale gas yield for the studied shale gas wells (Figure 10B). High-gas yield wells located in structural regions with higher in situ stress and higher pressure coefficients have low concentrations of He and Ar. As an unconventional gas, shale gas has the characteristics of self-generation and self-storage. A large amount of gas can be generated during the hydrocarbon gas generation stage. However, the abundance of noble gas (He and Ar) source elements, such as U, Th, and K, is very low in geological bodies, with an extremely long half-life and a very low rate of He or Ar generation (1 m³ km−3 year−¹). Furthermore, there is no peak of concentrated noble gas generation during the generation and storage processes. After the termination of the hydrocarbon generation process, the concentrations of He and Ar will inevitably be diluted with increasing CH₄ concentrations (Li et al., 2022).

The correlations between He and δ¹³C are shown in Figure 11. The ⁴He content exhibits positive correlations with both δ¹³C₁ and δ¹³C₂, with WL and PS shale gas samples having the highest ⁴He contents and heaviest δ¹³C signatures. The PQ and DS shale gas samples have the lowest ⁴He contents and the lightest δ¹³C signatures, with JF shale gas samples having intermediate values.

The above coupled noble gas and stable isotope analyses reveal that the concentrations of He and Ar and δ¹³C signatures of alkane gases are closely related to the accumulation and expulsion of shale gas. Generally, with an increasing pressure coefficient, shale gas preservation conditions become better, and high shale gas yields are attained, which will dilute the concentration of noble gases. Furthermore, better preservation conditions equate to less shale gas escaping during the gas generation period, causing δ¹³C values to remain closer to their initial values. In contrast, shale gas preserved under poor conditions loses lighter hydrocarbons and isotopes, causing decreasing pressure coefficients and residual gases rich in heavy components. For shale gas reservoirs characterized by a wide range of pressure coefficients, such as the normally pressured Marcellus (pressure coefficient between 0.9 and 1.4; Chalmers et al., 2012) and highly pressured Haynesville (pressure coefficient between 1.61 and 2.07; Hammes et al., 2011) shale gas fields in North America, shale gas production exhibits a similar positive correlation with an increasing pressure coefficient to that found herein. Therefore, gas geochemical data may also provide effective indicators for shale gas production evaluation in these regions. Compared with tectonically stable regions, which exhibit fewer differences in gas geochemical characteristics, the noble gas and stable isotope distribution trends presented herein for tectonically active regions will be more effective in evaluating shale gas accumulation and expulsion in shale gas reservoirs worldwide.