*3.1. Molecular Composition*

With an average content of 98.2%, CH4 dominates the Longmaxi shale gases. The average contents of C2H6 and C2H6 are 0.51% and 0.02%, respectively. Non-hydrocarbon gases are mainly composed of N2 and CO2, with a small amount of He and Ar. H2S has not been detected. The content of methane in Weiyuan (WY) shale gas (av. 97.9%) is slightly lower than that in Changning (CN) shale gas (av. 98.6%), while the contents of CO2 (av. 0.47%) and N2 (av. 0.98%) in the WY area are higher than those in CN area (av. 0.45% and av. 0.70%, respectively).

#### *3.2. Carbon Isotope Composition*

As shown in the carbon isotope correlation diagrams in Figures 4 and 5, there were distinct differences in the carbon isotopic distribution characteristics between the WY and CN shale gases. The δ13C1 values of WY Longmaxi shale gas ranged from −34.1% to −37.3%, the δ13C2 values ranged from −37.6% ~ −43.4%, and the δ13C3 values ranged from −33.6% ~ −43.5%. The δ13C1 (−26.8% to −31.3%) and δ13C2 (−32.3% to −34.9%) values of the CN Longmaxi shale gas were heavier by about 8% and 6%, respectively, than those in the WY area (Figure 4). The δ13C3 values ranged from −34.8% to −37.2% in the CN area.

Reversed distribution patterns of carbon isotopic compositions for CH4 to C3H8 were found in the Longmaxi shale gas in both the WY and CN areas. Full reversal distribution patterns of the carbon isotopic composition according to the carbon number were found in most Longmaxi Formation shale gases in these areas—that is, δ13C1 > δ13C2 > δ13C3. However, shale gases from three wells (W202, W201, and W201-H1) in the WY area showed a partial reversal distribution pattern of carbon isotopic composition according to the carbon number—that is, δ13C2 > δ13C1 and δ13C3 < δ13C2 (Figure 5).

**Figure 4.** Carbon isotopic composition of shale gas from the Longmaxi Formation in the Weiyuan and Changning areas, Sichuan Basin, China.

**Figure 5.** Variation in δ13C2-δ13C1 as a function of δ13C3-δ13C2 for gases from the Weiyuan (WY) and Changning (CN) areas, showing the isotope distribution patterns among methane, ethane, and propane.

#### *3.3. Noble Gases*

The Longmaxi formation shale gases in the Sichuan Basin showed regional differences in the abundance and isotopic compositions of noble gases [15]. The abundance and isotopic ratios of He and Ar in the WY shale gas are slightly higher than those in the CN shale gas (Figure 6). The concentrations of 4He and 40Ar ranged from 304.5 to 1286.3 ppm and 473.7 to 734.7 ppm, respectively, in the WY shale gas. The 3He/4He ratio was mainly around 0.02Ra, and the 40Ar/36Ar ratios ranged from 1276.2 to 6640.3 in the WY shale gas, while the concentration of 4He and 40Ar in the CN area varied in a small range from 386.1 to 445.9 ppm and 32.0 to 176.4 ppm, respectively. The 3He/4He ratios were around 0.01Ra, and the 40Ar/36Ar ratios were clustered around 1700 in the CN area. The ratios of 20Ne/22Ne and 21Ne/22Ne of the Longmaxi shale gases showed similar values to those of atmospheric Ne.

**Figure 6.** Plots of (**a**) 3He/4He vs. 40Ar/36Ar and (**b**) 20Ne/22Ne vs. 40Ar/36Ar of Longmaxi shale gases in the Weiyuan (WY) and Changning (CN) areas, China.

#### **4. Causes of Gas Geochemical Variation**

Hydrocarbon gases are ubiquitous products of organic maturation at all stages of burial. During the burial history, complex geological events may occur that could influence their maturity and lead to secondary alteration processes (migration, preservation, and water–rock interactions) that may result in changes in gas geochemical characteristics. The carbon isotope compositions of shale gas are closely related to the thermal alteration of organic matter. The different thermal histories of source rocks could bring about various patterns of carbon isotope composition [42–44]. Apart from the effect of temperature, the loss of natural gas during tectonic processes also affects the distribution of the molecular and isotope compositions of shale gas [45–50]. Water–organic matter redox reactions are another factor which could reform the gas geochemical characteristics of shale gases [51–54]. Lastly, the heterogeneity of Longmaxi Formation shale can lead to different concentrations of some molecules/elements in shale gases.

#### *4.1. Mixing of Secondary Cracking Gas*

Most shale gases are generated by the thermal degradation of sedimentary organic matter. The origin of this sedimentary organic matter is tightly linked to organic matter diagenetic and thermal alteration [42–44]. Although differences in the thermal maturity and/or organic type (marine and terrestrial shale gas) could bring about various δ13C values and carbon isotopic distribution patterns [24], this seems not to be the reason for the differences in gas geochemistry between Weiyuan (WY) and Changning (CN) shale gas, as they have the same conditions in terms of these two factors [21,22,24]. Tissot and Welte [55] found that, in the early thermal evolution stage, gaseous hydrocarbons are formed concurrently with oil from kerogen in source rocks, whereas in the late thermal evolution stage gaseous hydrocarbons are generated by the thermal cracking of both residual kerogen and oil. The produced natural gas becomes progressively drier and isotopically more positive with the improvement in the thermal evolution degree [43,56]. The source rocks of the Longmaxi formation in the WY and CN areas are all in the high to over-maturity stage [24–26]. However, according to the tectonic activity history, Longmaxi shale in the WY and CN areas has experienced different processes of temperature change. Therefore, the differences in the molecular and carbon isotopic compositions of shale gas from the

Longmaxi Formation between the WY and CN areas could be caused by the di fferent proportions of secondary cracking gas generated by residual kerogen and liquid hydrocarbons.

The di fferent e ffects of tectonic movement in the WY and CN areas could have led to the di fferent burial and thermal histories of Longmaxi shale. During the Triassic to Early Cretaceous era, the WY area underwent strong subsistence and then experienced extensive uplifting and erosion after the Late Cretaceous era. These events resulted in large fluctuations in temperature in the shales [57]. As shown in Figure 7, from the Middle Triassic (70 ◦C, started to generate oil) to the Late Cretaceous era (210 ◦C, maximum gas generation), a complete evolution of the hydrocarbon generation stages occurred in the WY Silurian Longmaxi shale, including oil generation, oil cracking to gas, and residual kerogen cracking to gas [57,58]. High temperature ranges from 172 ◦C to 205 ◦C were revealed by the homogenous temperature of the fluid inclusions taken from N202 in the CN area [59,60], providing evidence that the CN Silurian Longmaxi shale also went through the complete evolution of the hydrocarbon generation stages. The complex tectonic activities in the Weiyuan and Changning areas will cause source rocks to undergo di fferent evolutionary processes, leading to di fferences in the shale gas geochemical characteristics. However, this needs to be proven by accurate source rock burial history and other information in each region.

**Figure 7.** Plots of the burial history and thermal evolution of the Silurian Longmaxi shales in the Weiyuan area (Well W117). The thermal gradient evolution history was established by the reflectance inversion method: 32 ◦C/km (>96 Ma), 30 ◦C/km (96–65 Ma), 27 ◦C/km (<65 Ma). The thermal evolution histories of Lower Silurian shale were reconstructed by combining the thermal gradient model and their burial histories [57,58].

The Emeishan large igneous province (ELIP) covers an area of about 2.5 × 10<sup>5</sup> km<sup>2</sup> in southwest China. The heat flow in the inner and intermediate zones is abnormally high compared with that in the outer zone, where a decrease in the average heat flow from 76 to 51 mW/m<sup>2</sup> has been observed [59]. This provides a di fferentiated heat source for overlying and underlying strata in di fferent areas. The appearance of pyrobitumen in the Sinian–Cambrian reservoirs is clear evidence of an abrupt hydrothermal fluid event, which might correspond to the Emei mantle plume in the late Permian era [60,61]. WY and CN are in the Emeishan large igneous province region (Figure 3). The thermal evolution of source rocks in the WY and CN areas was strongly a ffected by the ELIP [62–64]. From Figure 3, we can see that the CN area is in the intermediate zone of ELIP, while the WY area is in the outer zone. We can conclude that the CN area received relatively more heat energy than the WY area during the Emeishan mantle plume activity.

The shale gases from the Longmaxi formation in the WY and CN areas are thermogenic gases, which are formed at higher temperatures by the thermal decomposition of higher molecular weight organic matter (kerogen or oil) [27]. It is known that 12C forms slightly weaker chemical bonds in the process of thermal decomposition than 13C, resulting in a "kinetic isotope fractionation" in which the reaction product (gas in this case) is enriched in 12C (isotopically "lighter") and the rest of the source material (kerogen or oil) becomes similarly enriched in 13C (isotopically "heavier") in a process known as the Rayleigh fractionation e ffect [27]. As the maturity degree increases, the δ<sup>13</sup> C1 ratio decreases until it reaches the lightest point, after which it increases [9]. Closed-system kerogen pyrolysis experiments and the study of geologic systems have determined that the secondary cracking of heavier hydrocarbons is a crucial pathway for gas generation [47,65–68]. Primary gases generated from kerogen and secondary gases cracked by oil and/or gaseous hydrocarbons are the main components of thermogenic shale gases. Shale gas (e.g., CH4, C2H6, and C3H8) generated at di fferent temperatures will have di fferent isotopic compositions due to the Rayleigh fractionation e ffect. This may be one of the primary causes of the di fferences in the carbon isotopic composition of Longmaxi shale gases between the WY and CN areas, which experienced di fferent temperature changes throughout their thermal evolution.

#### *4.2. The Loss of Shale Gas*

Shale gas aggregates continuously in gas reservoirs and is characterized by relatively short hydrocarbon migration distances [69]. Tectonic movement and preservation conditions are the main drivers of the accumulation and migration of shale gas [33,36]. The Sichuan Basin experienced complex tectonic movements during the evolution from the Craton basin (Palaeozoic) to the foreland basin (Triassic) [33,36]. Silurian Longmaxi shale was a ffected by the Yanshan, Indo-China, Dongwu, and Yunnan movements after deposition (Figure 2), which generated a large number of faults and unconformity surfaces and resulted in various pathways of hydrocarbon migration and gas loss [33,70,71]. Repeated uplift and erosion and numerous faults destroyed the preservation conditions of Longmaxi shale gas in the WY and CN areas [36,70] and consequently caused shale gas loss. The formation of the Leshan–Longnvsi paleo uplift involved several periods of tectonic movements, from the Tongwan movement to Yanshanian movement [35]; its tectonic evolution has had a greater influence on the formation and distribution of the WY shale gas reservoirs than that of the CN shale gas reservoirs [72–74].

During shale gas loss in the geological history, di ffusive leakage from reservoirs and source rocks could induce carbon isotope fractionation ranges from 1% to 30% [75], and this loss of fractionation is universal in sedimentary basins [75,76]. Further, the smaller the volume of gas in the accumulation, the more likely any type of secondary fractionation will be significant [77]. Cao et al. [15] and Zhang et al. [16] discovered changes in noble gas abundance and isotopic composition and molecular and carbon isotope variation in the Longmaxi Formation shale gas in the WY and CN areas over the course of 3.5 years. Shale gas production is a kind of artificial di ffusion process; the methane carbon isotope composition become slightly heavier, with its content decreasing in WY shale gases, while there are no changes in CN shale gases [16]. The di fferences between the gas geochemical characteristics in these two areas is due to the lower gas pressure (which means smaller volume) of the Longmaxi reservoir in the WY area [15,16,75–77].

Therefore, we can conclude that the Longmaxi shale in the WY area has been more a ffected by the intense tectonic activities, resulting in more shale gas loss over geological history. According to the di ffusive fractionation theory [75,77], there should be a heavier δ<sup>13</sup> C1 ratio in WY shale gases, but just the opposite is true [16,21,22,27]. Some other secondary reactions may have occurred in the Longmaxi shale gas reservoirs, either in WY or CN, leading to the present carbon isotope composition characteristics.

## *4.3. Water–Rock Interaction*

The δ<sup>13</sup> C1 ratios of shale gases in the CN area range from −26.8% to −31.3%, which is heavier than that of the thermogenic methane from type I and II kerogen (−50% to −30%, [78,79]). Its carbon isotope composition and distribution pattern are similar to those of abiogenic gas (<sup>&</sup>gt;−30%, [80]). Abiogenic hydrocarbons could be generated by Fischer–Tropsch-type reactions in granitic rocks, whose δ<sup>13</sup> C1 ratios range from −32% to −20% and δ<sup>13</sup> C1 > δ<sup>13</sup> C2+ [81,82]. Tang et al. [83] recognized a new mechanism of shale gas generation: a Fischer–Tropsch-type synthesis of hydrocarbon from CO2 and H2, resulting from the water reforming of residual organic matter in shale.

$$\text{CH}\_{\text{x}}\text{ (organic matter)} + 2\text{H}\_{2}\text{O} \rightarrow \text{CO}\_{2} + \text{(2} + \text{x/2)}\text{H}\_{2}.\tag{1}$$

$$\rm{x}\rm{CO}\_{2} + \rm{mH}\_{2} \rightarrow \rm{xCH}\_{4} + \rm{yC}\_{2}\rm{H}\_{6} + \dots \rightarrow \rm{zH}\_{2}\rm{O}.\tag{2}$$

The Longmaxi shale in the CN area contains a large amount of formation water, providing the base materials for this methane generation mechanism, which may account for 50% or as much as 80% of the gas in shale, especially in particularly high-producing wells [83]. This also could increase the porosity and permeability of the shales [83]. Therefore, high δ<sup>13</sup> C1 ratios, the full reversal distribution pattern of the carbon isotopic composition, and high gas pressure may be related to this new mechanism of shale gas generation. However, much more detailed work, including on the temperature and catalyst of the reaction and the matrix pore features, should be undertaken to properly understand this Fischer–Tropsch-type reaction.

#### *4.4. Heterogeneity of Longmaxi Shale*

Longmaxi shale has obvious lateral and vertical heterogeneity in its mineral composition, Total Organic Carbon (TOC), porosity, and trace elements [84–89]. Figure 6 shows the di fferences in 4He and 40Ar content between the WY and CN shale gases. The 4He production in the crust is dominated by the α-decay of the 235,238U and 232Th decay chains, and is therefore directly proportional to the concentration of these radioelements in the crust, while the decay of 40K dominates the 40Ar production in the crust, which is thus directly proportional to the K concentrations. The contents of U, Th, and K are varied in Silurian Longmaxi shale [88,89], which may be one reason for the di fferences in noble gas isotope abundance (4He and 40Ar).

In addition, the 40Ar/36Ar ratio of W201-H1 is extremely high (6640.3), and close to that (7000) of conventional natural gas from the Sinian Dengying Formation reservoirs [15,90]. The two sets of gas reservoirs are in the same area (WY), and this combined with the intense tectonic activities in this area makes it very likely that some deeper conventional natural gas has leaked into the W201-H1 well from the fractures. Due to the low permeability and connectivity of shale rock, these deeper gases remained contained and did not spread to other shale gas wells.
