Geochemical Characteristics of Natural Gas in the Upper Permian Reservoir of the Eastern Sichuan Basin, China: Implication of Multiple Sources Mixing

Abstract

For an improved understanding of gas enrichment mechanism in the eastern Sichuan Basin, South China, twelve natural gas samples were obtained from carbonate reservoirs of the Upper Permian strata to analyze the hydrocarbon and non-hydrocarbon gas compositions, stable carbon and hydrogen isotopes ratios of hydrocarbons, and noble gas isotope ratios. The gas samples in the Upper Permian reservoirs principally consist of alkane gas with a dryness ratio ranging from 127.9 to 1 564.4. The carbon isotope ratio of methane (δ¹³C₁) was almost constant at -34.1 to -31.3‰, but the carbon isotope ratio of ethane (δ¹³C₂) varied from -36.6‰ to -25.8‰. The hydrogen isotope ratio of methane (δ²HC₁) also displayed a wide range from -137‰ to -127‰. The large variations in the dryness ratio, δ¹³C₂, and δ²HC₁ with almost constant δ¹³C₁ suggest the mixing of sapropelic and humic origins for hydrocarbon gases in these reservoirs. A high concentration of hydrogen sulfide (H₂S) originated from the thermochemical sulfate reduction (TSR), which was positively correlated with δ¹³C₁ (or δ¹³C₂) in individual gas fields. TSR altered δ¹³C₁ (or δ¹³C₂) and resulted in the abnormal character of isotopic reversal in the individual samples. The δ¹³C₁ (or δ¹³C₂) in most gas samples, independent of H₂S concentration, further displayed reversed carbon isotopes because of the mixture of thermogenic gases with various thermal maturity levels. The measured argon isotope ratio (⁴⁰Ar/³⁶Ar) varied from 310 to 1 225, which suggests that the oldest 320 Ma source rock age corresponds to Permian shales. The analysis of the gas origin and the identification of primary source rock have made a significant contribution to further understanding the resource potential and distribution of natural gas in the Upper Permian, and have great implications for gas exploration in the eastern Sichuan Basin.

Graphical abstract

Keywords

gas origin / stable isotopes / thermochemical sulfate reduction / source rocks / gas accumulation / geochemistry

0 INTRODUCTION

As one of the major petroliferous basins in China (or even globally), the Sichuan Basin yielded natural gas as early as 53 BC to 18 AD (Li, 2011). The reserve assessment of 2019 concluded a recoverable hydrocarbon resource of 136 969 × 10⁸ m³, and the statistical data for 2020 suggested a cumulative hydrocarbon production of 7 134 × 10⁸ m³ (dominated by natural gas production of 7 052.8 × 10⁸ m³) (Dai et al., 2021). Previous research summarized the hydrocarbon enrichment mechanism of the Sichuan Basin as that the organic-rich shale and high-quality reservoir were the basis of gas accumulation, and the good preservation condition was the key to high production (Wu et al., 2023; Li A et al., 2021). Particularly, the multi-layers and multi-types of source rocks, which consist of at least nine organic-rich shale layers from the Ediacaran, Cambrian, Silurian, Permian, Triassic, and Jurassic periods, contributed to the massive hydrocarbon generation (Qiu et al., 2024; Dai et al., 2021; Hao et al., 2008; Ma et al., 2007). Most of these source rocks were high- or over-matured and generated hydrocarbons dominated by relatively few hydrocarbon compounds, including methane, ethane, and propane. The complicated source systems and low geochemical diversity made it a great challenge to reveal the geochemical origins and physicochemical processes associated with the accumulation and preservation of hydrocarbons after multiple tectonic deformations. In particular, the eastern Sichuan Basin was intensively deformed during the Yanshanian and Himalayan orogeny, resulting in a fold-thrust belt (Li C X et al., 2021; Liu S G et al., 2021; Liu R et al., 2019; Li J H et al., 2018; Yan et al., 2003). Furthermore, the natural gas found in the eastern Sichuan Basin contains various contents of non-hydrocarbon gases, including hydrogen sulfide (H₂S) and carbon dioxide (CO₂), which complicates the inorganic-organic interactions during hydrocarbon generation (Hao et al., 2015; Liu et al., 2013; Cai et al., 2010).

For an improved understanding of the gas enrichment mechanism in the eastern Sichuan Basin of South China, a series of advanced gas samples were obtained from the Upper Permian carbonate reservoirs to analyze the hydrocarbon and non-hydrocarbon gas compositions, stable carbon and hydrocarbon isotopes of hydrocarbons, and noble gas isotopes. By integrating our recent data with previously published data, the geochemical origins and physicochemical processes of the Upper Permian natural gas in the eastern Sichuan Basin were resolved.

1 GEOLOGICAL BACKGROUNDS

The Sichuan Basin, with a rhombus outline, is tectonically enclosed by fold-thrust belts, comprising the eastern boundary of the Qiyueshan fault, the northern boundary of the Qingling-Dabie fault, and the western boundary of the Longmenshan fault (Figure 1) (Hao et al., 2008). Sediments in the Sichuan Basin are 12 km thick and contain marine strata of Sinian to Middle Triassic and terrestrial deposits of Late Triassic to Cenozoic (Figure 2). Organic-rich marine shales deposited during intense transgressions, e.g., Lower Cambrian, Lower Silurian, and Upper Permian, were suggested to be major source rocks of numerous gas fields targeted in the Upper Permian and Lower Triassic carbonate platforms (Yang et al., 2023). The north-south stretching of the Sichuan Basin during the Late Permian generated the Kaijing-Liangping Ocean Through and the Wushen-Shizhu Depression, which were both characterized by the striking of northwest-southeast (Figure 1a) and prompted the development of carbonate platform during the Changxing period (Figure 2) (Liu S G et al., 2021). Reefs and bioclastic beaches were widely deposited along the margins of the Kaijing-Liangping Ocean Through and the Wushen-Shizhu Depression and were suggested to be high-quality reservoirs even after the mechanical and chemical diagenesis (Chen et al., 2022). Regional anhydrite beds from the Lower to Middle Triassic are the regional cap rocks of marine reservoirs. Organic-rich terrestrial shales with partly distributed coal beds were also deposited during the Late Permian to Triassic conversion during marine to continental deposition (Cai et al., 2003). Collisions along the Qinling-Dabie and Longmenshan fault zones during the Triassic resulted in the exhumation of the southern and northeastern areas of the Sichuan Basin (Liu S G et al., 2021). A flexural loaded foredeep appeared in front of the Longmenshan fault, which was filled with a wedge-shaped aggregation of terrestrial clastic rocks during the Late Triassic (Richardson et al., 2008; Meng et al., 2005). Subsequently, a stepwise northwest progression of deformation generated a well-developed Mesozoic thrust system in the eastern Sichuan Basin from the Middle Jurassic to Late Cretaceous Period(Liu et al., 2021a,2019; He et al., 2018; Dong et al., 2015; Yan et al., 2003). Numerous gas fields have been detected in the anticline structures of the eastern Sichuan Basin.

2 SAMPLES AND METHODS

2.1 Sampling

Twelve gas samples produced from the marine carbonate reservoir of the Upper Permian age were collected from 12 wells of the eastern Sichuan Basin (Table 1). All gas samples were directly collected from the wellhead employing an intake manifold to decrease the wellhead gas pressure prior to flowing into stainless-steel cylinders at 1–3 bar. To avoid air contamination, the sample collection system was flushed for at least 8 to 10 min prior to shutting off the valve connecting the gas cylinder and the wellhead.

2.2 Gas Components

The major gas composition was analyzed utilizing the gas chromatograph (GC) of Agilent 7890A connected with the flame ionization and thermal conductivity detectors. Alkanes were separated using an HP/ALS column. The oven temperature was initially set at 40 ºC for approximately 10 min, and was subsequently elevated to 180 ºC under the heating rate of 4 ºC/min. The carrier gas of the system was helium.

2.3 Carbon, Hydrogen, Helium, and Argon Isotopes

The stable carbon isotope ratios of the gas were examined utilizing a mass spectrometer (MS) of Thermo MAT 253 with an HP 5890II GC. The hydrocarbon gas components were initially segmented using the GC, and further burned into CO₂ before being pumped into the MS. Initially, the GC oven temperature was elevated from 40 to 80 ºC under the heating rate of 8 ºC/min, subsequently to 250 ºC (at 5 ºC/min), and finally maintained for approximately 10 min. The measurement precision was within ±0.5‰ relative to the Vienna pee dee belemnite (VPDB) standard.

The hydrogen isotopic values were analyzed utilizing the Thermo MAT 253-Plus MS connected with the TRACE GC Ultra fitted with an HP-PLOTQ chromatographic column. The gas samples were purified and segmented into CO₂ and hydrogen (H₂). Later, H₂ was injected into the MS employing helium as the carrier gas under the flow velocity of 1.5 mL/min. The oven temperature was initially set to 40 ºC (for approximately 10 min), subsequently increased to 80 ºC (at the heating rate of 5 ºC/min), later to 140 °C (following the heating rate of 8 ºC/min), and finally to 260 ºC (under the heating rate of 10 ºC/min). The measurement precision was within ±0.3‰ relative to the Vienna Standard Mean Ocean Water (VSMOW) standard.

The helium and argon isotopes were determined using a VG5400 MS at the Langfang branch of RIPED. All gas samples were separated and purified before being pumped into the VG5400 apparatus. The ³He/⁴He ratios were reported relative to the atmospheric value (RA) of (1.384 ± 0.006) × 10^-6 cm³ STP/cm³ (STP = standard pressure and temperature, i.e., 0.101 MPa, 0 ºC) (Ozima and Podosek, 2001; Clarke et al., 1976).

3 RESULTS

3.1 Composition of Natural Gas

The Upper Permian gas samples obtained from the eastern Sichuan Basin primarily consist of alkane gas, including the 78.22 mol%–98.83 mol% of methane (C₁), < 1 mol% of ethane (C₂), and < 0.2 mol% propane (C₃) (Table 1). The dryness ratio (that is, C₁/(C₂ + C₃)) of the alkane gas ranges from 127.9–1 564.4. Non-hydrocarbon gases are dominated by CO₂ and H₂S, which account for 0.23 mol%–11.83 mol% and 0.26 mol%–9.37 mol%, respectively. Our samples display the gas souring index defined by (Worden et al., 1995) (i.e., GSI = H₂S/(H₂S + C₁ + C₂ + C₃)) varying from 0.26% to 10.63%.

3.2 Stable Isotopic Ratios of Natural Gas

The carbon isotope ratios of methane (δ¹³C₁) and ethane (δ¹³C₂) ranged from -34.1‰ to -31.3‰ and -36.6‰ to -25.8‰, respectively (Table 2). Due to its low concentration, the carbon isotope of propane (δ¹³C₃) was not measured successfully in all samples. Most of the samples exhibited δ¹³C₃ values ranging from -33.5‰ to -22.3‰. Cross plots of δ¹³C₁ with the dryness ratio and δ¹³C₂ indicated that alkanes in our samples belong to the highly matured thermogenic gas (Figure 3) (Milkov et al., 2020; Milkov and Etiope, 2018), which aligned with previous gas analyses of the Sichuan Basin (Li et al., 2020; Lin et al., 2020; Dai et al., 2018; Qin et al., 2016; Hao et al., 2015,2008; Liu et al., 2014,2013; Zhang et al., 2010; Yang et al., 2002). Although natural gas normally exhibits the enrichment of ¹³C with carbon atoms in alkanes (δ¹³C₁ < δ¹³C₂ < δ¹³C₃) due to Rayleigh distillation (Rooney et al., 1995), several of our samples displayed an abnormal isotopic reversal characteristic (i.e., δ¹³C₁ > δ¹³C₂).

The δ²HC₁ (hydrogen isotope ratio of methane) ranged from -137‰ to -127‰ (Table 2). A cross plot of δ¹³C₁ with δ²HC₁ confirms that alkanes in our samples were the result of the late mature thermogenic gas (Figure 4), aligned with the cross plots of δ¹³C₁ with the dryness ratio and δ¹³C₂. Although not all samples were analyzed successfully, the δ²HC₂ (hydrogen isotope of ethane) for most of the samples varied from -154‰ to -120‰ (Table 2).

The measured helium ratios (³He/⁴He) normalized to the air value (R_A = (1.384 ± 0.006) × 10^-6) (Ozima and Podosek, 2001; Clarke et al., 1976) ranged from 0.025 to 0.063 (Table 2). Most samples exhibited a significant contribution of crustal-derived He, which has a typical ³He/⁴He value of approximately 0.01–0.02 (Ballentine and Burnard, 2002). The measured ⁴⁰Ar/³⁶Ar ratios varied from 310 to 1 225 (Table 2), exceeding the atmospheric ratio of 298.56 (Mark et al., 2011).

4 DISCUSSION

4.1 Origin of Hydrocarbon Gas

4.1.1 Mixing of sapropelic and humic origins

The depositional setting of the eastern Sichuan Basin gradually transferred from marine to terrestrial ecosystems during the Late Permian to the Triassic, contributing to the potential mixing of hydrocarbons generated by sapropelic and humic organic matter in the marine and terrigenous shales, respectively. Nevertheless, the carbon and hydrogen isotopes of hydrocarbon gases can be applied to distinguish their origins (Milkov, 2021; Milkov et al., 2020; Prinzhofer et al., 2000; Prinzhofer and Huc, 1995).

Based on the statistics, the carbon isotope of thermogenic methane (δ¹³C₁) generally exceeds -50‰ and increases with elevated thermal maturity levels, resulting in a positive correlation between δ¹³C₁ and the dryness ratio (Milkov, 2021; Milkov and Etiope, 2018; Whiticar, 1994; Faber et al., 1988; Bernard et al., 1978). Even at a similar dryness ratio, methane generated from Type III kerogen (i.e., humic origin) has a relatively higher δ¹³C₁ value than that from Type II kerogen (Figure 5a). As shown in Figure 5a, our samples and previously reported data were plotted in the zone between typical areas of gases originating from the Type II and III kerogens, suggesting a mixing of sapropelic and humic origins for hydrocarbon gases in the Upper Permian reservoirs.

The carbon isotope of ethane (δ¹³C₂) also increases with increasing thermal maturity, but commonly exhibits relatively higher values in humic-origin gas than in sapropelic-origin gas (Milkov, 2021; Jenden et al., 1988; Rooney et al., 1995). Several researchers have also summarized that humic-origin gas commonly has δ¹³C₂ > -28‰, but sapropelic-origin gas has δ¹³C₂ < -28‰ (Dai et al., 2014). Both our samples and previous data demonstrated a large variation in δ¹³C₂ (-40‰ to -20‰), which implies both humic and sapropelic origins (Figure 5b).

4.1.2 Mixing of various thermal maturities

In addition to organic matter types and thermal maturity levels, δ¹³C₁ and δ¹³C₂ are controlled by post-genetic alteration processes, including thermochemical sulfate reduction (TSR) (Torghabeh et al., 2021; Cai et al., 2019; Hao et al., 2015), migration fractionation (Tilley et al., 2011), mixing of gases of various origins (thermal maturity levels), and various source layers (Prinzhofer and Huc, 1995).

As shown in Table 1, various H₂S contents were detected in the Upper Permian reservoir, consistent with previously reported data (Li et al., 2016; Liu et al., 2013; Cai et al., 2010; Hao et al., 2008). Potential mechanisms that account for H₂S in hydrocarbons include the thermal decomposition of sulfur compounds in organic matter (TDS), bacterial sulfate reduction (BSR), and TSR (Loegering et al., 2022; Torghabeh et al., 2021). The low abundance of organic sulfur compounds in organic matter commonly limits the TDS-associated H₂S concentration to no more than 5%; BSR generally appears in recent sediments with a maximum temperature of approximately 80 ºC and accounts for H₂S < 5%; and high H₂S concentrations (> 5%) are widely assumed to be related to TSR that occurs at temperatures > 110 ºC (Torghabeh et al., 2021;Cai et al., 2019,2010; Li et al., 2016; Liu et al., 2013; Hao et al., 2008; Worden et al., 1996). Regionally, the H₂S concentration in the Upper Permian reservoirs increases from south to north (Table 1; Figure 1a), which is consistent with the conclusion that the H₂S concentration was positively correlated with the thickness of anhydrite-bearing evaporitic rocks that supplied sulfur during the TSR and primarily appeared in the Triassic strata of northern Sichuan Basin (Zhu, 2005).

The plot of GSI, the proxy for TSR extent, against δ¹³C₁ (or δ¹³C₂), indicates that δ¹³C₁ (or δ¹³C₂) in the Upper Permian reservoirs can be positively correlated with elevated GSI (> 5%), for example, samples from the Puguang field (Figures 7a, 7b). This positive correlation suggests that the TSR altered δ¹³C₁ (or δ¹³C₂) in individual gas fields (e.g., Puguang field) of the northern Sichuan Basin. The TSR favors the removal of ¹²C, contributing to the enrichment of ¹³C in residual hydrocarbon gases (Cai et al., 2019; Hao et al., 2008; Rooney et al., 1995). Due to the difference in reactivity, heavy hydrocarbon gases (C₂₊) are preferentially involved in TSR, which can account for the increase in δ¹³C₂ but no change in δ¹³C₁ with elevated GSI (Mankiewicz et al., 2009); thus, the difference between δ¹³C₁ and δ¹³C₂ (i.e., δ¹³C₁-δ¹³C₂) theoretically decreased with TSR progress (Figure 7c).

TSR was suggested as a potential mechanism for inducing reversed carbon isotope ratios between methane and ethane (i.e., δ¹³C₁ > δ¹³C₂), despite hydrocarbon gases originating from the same source layer and similar thermal maturity levels, theoretically showing the elevation of the carbon isotope ratio with carbon atom numbers in the gas molecule (δ¹³C₁ < δ¹³C₂) (i.e., the normal carbon isotope ratios) (Feng et al., 2021; Milkov et al., 2020; Liu et al., 2013; Tilley and Muehlenbachs, 2013; Hao et al., 2008). Hao et al. (2008) proposed that methane, as the only organic reactant, is involved in the TSR after the exhaustion of most of the heavy hydrocarbon gases (C₂₊). Nevertheless, no direct correlation between the reversed carbon isotope ratios and the methane-involved TSR was identified in our data. Although methane was involved in TSR progress, δ¹³C₁-δ¹³C₂ may not be increased to > 0 (i.e., reversed carbon isotope ratios) (Figure 7c). As shown in Figures 7a and 7b, δ¹³C₁ (or δ¹³C₂) of the Upper Permian gas samples were independent of low GSI values (< 5%) (e.g., samples from the Longgang field), suggesting that TSR-independent samples also showed the reserved carbon isotopes. Prinzhofer and Huc (1995) pointed out that the fractional leakage of a gas reservoir can cause the preferential loss of lighter carbon isotopes (i.e., ¹²C) and lighter molecular weight (i.e., methane), resulting in the enrichment of C₂₊ and heavier carbon isotopes (i.e., ¹³C) in the residual gas. This partial diffusion model preferentially increases δ¹³C₁, which conflicts with the narrow change in δ¹³C₁ in the gas samples of the Upper Permian reservoir (Figure 5b). Jenden et al. (1993) suggested that a mixture of thermogenic gases with different thermal maturity levels can complicate the molecular and isotopic signatures of hydrocarbon gases. Because the highly matured gas contains significantly less C₂₊ than the low-maturity gas, the mixing of a minor amount of highly matured gas with the less matured gas can primarily elevate δ¹³C₁ without a significant change in δ¹³C₂. In contrast, adding a minor amount of low-maturity gas within the high-maturity gas can distinctly decrease δ¹³C₂. Abundant gas samples in the Upper Permian reservoir indicate a wide variation in δ¹³C₂ with almost constant δ¹³C₁, which aligns with the bivariate mixture model of Jenden et al. (1993) (Figure 8).

The artificial maturity of kerogen or oil in closed-system pyrolysis revealed the general tendency of molecular composition change (Prinzhofer and Huc, 1995). In the closed-system experiments, the C₁/C₂ ratio increased significantly during the primary cracking of kerogen but remained almost stable during the secondary cracking of oil. Conversely, the C₂/C₃ ratio remained stable during the primary cracking of kerogen but increased drastically during the secondary cracking of oil. As shown in Figure 9, the C₂/C₃ ratio varied more rapidly than the C₁/C₂ ratio in the Upper Permian gas samples, implying the dominance of secondary cracking. However, the Upper Permian samples deviated from the correlation between the C₁/C₂ and C₂/C₃ ratios in the Sichuan Basin, which was quantified by the oil cracking experiments of Hao et al. (2008). Notably, the system openness of the Upper Permian reservoir may be higher than that in the artificial pyrolysis experiment. Adding various amounts of the less matured gas primarily cracked from kerogen, within the highly mature gases cracked from the oil can induce a parallel shift in the correlation of Hao et al. (2008) to account for the measured C₁/C₂ and C₂/C₃ ratios of most gas samples in the Upper Permian reservoirs. Some samples involved in the TSR reaction showed increasing values of ln(C₁/C₂) and a relatively wider range of values with the TSR process.

4.2 Identification of Primary Source Rock

Noble gas isotopes have been suggested as powerful tools for source-rock identification (Zhang et al., 2005; Liu and Xu, 1993). ³⁶Ar in the crust is principally derived from the atmosphere and introduced through dissolution in groundwater; ⁴⁰Ar (in atoms/g) is primarily generated from the decay of ⁴⁰K following the equation.

{}_{}{}^{\mathrm{40}}\mathrm{A}\mathrm{r}=X_{\mathrm{K}}\left[K\right]\times {\mathrm{10}}^{-\mathrm{6}}\left(\frac{N_{\mathrm{A}}}{A_{\mathrm{K}}}\right)\left(\frac{{\lambda }_{\mathrm{e}}}{{\lambda }_{\mathrm{k}}}\right)\left({\mathrm{e}}^{\lambda t}-\mathrm{1}\right)(1)

where, X_K = 1.167 × 10^-4 (the fractional natural abundance of ⁴⁰K), [K] is the K concentration (in ppm), N_A = 6.023 × 10²³ (Avogadro’s number), A_K = 39.964 g (molar mass of K), λ_e = 0.581 × 10^-10 yr^-1, λ_Κ = (5.463 ± 0.054) × 10^-10 yr^-1, and t = age (yr) (Ballentine and Burnard, 2002). The atmospheric ⁴⁰Ar/³⁶Ar ratio is almost constant at 298.56 (Mark et al., 2011). Assuming a closed system involving source and reservoir rocks, the ⁴⁰Ar/³⁶Ar ratio of the hydrocarbon gas is controlled by the K concentration and age of the source rock. Based on the statistical analysis of Liu and Xu (1993), the ⁴⁰Ar/³⁶Ar ratio of hydrocarbon gas sourced from shale is positively correlated with the source rock age (T) in most Chinese basins (including the Sichuan Basin)

T\left(\mathrm{M}\mathrm{y}\mathrm{r}\right)=\mathrm{544.5}\mathrm{l}\mathrm{o}\mathrm{g}\left(\frac{{}_{}{}^{\mathrm{40}}\mathrm{A}\mathrm{r}}{{}_{}{}^{\mathrm{36}}\mathrm{A}\mathrm{r}}\right)-\mathrm{1}\mathrm{362.3}(2)

The measured ⁴⁰Ar/³⁶Ar ratios of hydrocarbon gas in the Upper Permian reservoir ranged from 310 to 1 225 (Table 2), which suggests a source rock age of 320–0 Ma, referring to the oldest source rock of the Permian age (Figure 2). Previous studies also suggested that gas in the Upper Permian reservoir of the Sichuan Basin mainly came from the Permian source rocks (Borjigen et al., 2014; Tang et al., 2011; Zhu et al., 2006). The Permian source rocks consist of shale interbedded with carbonates in the Lower Permian, and marine shale interbedded with terrestrial shale or coal (Figure 2). In particular, shales of the Dalong and Wujiaping formations (Upper Permian) with deposition centers around Dazhou City and Chongqing City (Figure 1) were suggested to have generated 3 290 × 10⁸ t of oil and 420 × 10¹² m³ of gas; nevertheless, the gas reserves originating from the cracking of oil and kerogen reached 4.45 × 10¹² m³ and 4.45 × 10¹² m³, respectively (Yi et al., 2024; Chen et al., 2018).

The wide range of inferred source rock ages primarily accounts for the mixing of hydrocarbon gases generated from younger shales, for example, from the Triassic. Nevertheless, Zhang et al. (2005) suggested that the K concentration in special source rocks, such as coal and carbonate rocks, is an order of magnitude lower than that in shale, which may cause an underestimation of the source rock age from Eq. (2). The assumption of an ideal closed source-reservoir system may be too harsh; the mixing of atmosphere-saturated groundwater and the subsequent water-gas interaction (Liu et al., 2021b) may also decrease the ⁴⁰Ar/³⁶Ar ratio to approach the atmospheric ratio (298.56) (Mark et al., 2011) and underestimate the source rock age.

4.3 Hydrocarbon Accumulation Model

As shown in Figure 10, the Upper Permian reservoir mainly experienced two episodes of hydrocarbon evolution processes: (1) charging of oil and gas from five sets of the Permian source rocks (Figure 2), including deep marine mudstone of the Dalong and the Wujiaping formations dominated by Type II kerogen with the average equivalent reflectance of 1.75% and 2.32% (Wu et al., 2019), lagoon-facies mudstone of the Maokou and the Qixia formations (Zhu et al., 2006) which mainly contained Type II kerogen with the average equivalent reflectance greater than 2%, and humic mudstone with interbedded coal seams in the transitional facies of the Longtan Formation which consisted mainly of Type III organic compounds with an average equivalent reflectance of 2.13% (Chen et al., 2018; Zhu et al., 2006); and (2) hydrocarbon thermal alteration, e.g., oil-cracking gas and TSR. The mixing of various origins for hydrocarbon gas and thermal alteration processes varied spatially, and then complicated the molecular and isotopic compositions in the eastern Sichuan Basin. The sulfur-rich brine sourced from the Triassic evaporites was mainly distributed around the Kaijing-Liangping Ocean Through, which promoted the TSR reaction in that region and resulted in high GSI values. These TSR processes mainly consumed ethane and thus didn’t successfully cause the reversed carbon isotope ratios. Gas originated from multiple sources (e.g., a mixing of Sapropelic and humic origins or a mixing of various maturity levels) which led to the reversed carbon isotope rations and a relatively wider δ¹³C₁ range in the reservoirs around the Wushen-Shizhu Depression; whereas induvial reservoirs that were not affected by mixing still show. In the transition zone between the Wushen-Shizhu Depression and the Kaijing-Liangping Ocean Through, the chemical processes were more complicated, which involved the superposition of mixing and TSR processes and resulted in greater carbon isotopic reversal (e.g., Well B001-1).

5 CONCLUSIONS

In this study, the origin of natural gases in the Upper Permian reservoir has been comprehensively analyzed, which is significant to further understand the resource potential and distribution of natural gas in the Upper Permian. Meanwhile, the source rocks’ ages have been measured by the noble gas isotopes model, which suggests that the younger source rock from the Triassic might contribute to gases in the Upper Permian reservoir and reveals the gas enrichment mechanism in the eastern Sichuan Basin of South China.

The gas in the Upper Permian reservoir was altered by two important chemical processes: the mixing of various source rocks and hydrocarbon thermal alteration. Non-hydrocarbon gas dominated by CO₂ and H₂S spatially increased the concentration northward. A high concentration of H₂S was primarily generated by TSR. For gases with GSI values (> 5%), TSR altered δ¹³C₁ (or δ¹³C₂). However, because of the mixing of thermogenic gases with various levels of thermal maturity, the majority of the δ¹³C₁ (or δ¹³C₂) values, independent of low GSI values (<5%), demonstrated reversed carbon isotopes.

The measured helium isotope ratio (i.e., ³He/⁴He) ranged from 0.025–0.063 (R_A = (1.384 ± 0.006) × 10^-6), indicating the dominance of crustal fluids without mantle fluid disturbance. The measured argon isotope ratio (i.e., ⁴⁰Ar/³⁶Ar) varies from 310 to 1 225, which suggests that the source rock age is up to 320 Ma, corresponding to Permian shales.

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Funding

the National Natural Science Foundation of China(42072184)

the National Natural Science Foundation of China(41702157)

the Science and Technology Cooperation Project of the CNPC-SWPU Innovation Alliance

RIGHTS & PERMISSIONS

China University of Geosciences (Wuhan) and Springer-Verlag GmbH Germany, Part of Springer Nature