Introduction

Natural gas in nature is classified into two main types based on its formation mechanism: gas of organic origin and gas of inorganic origin. Gas of organic origin is further divided into two subtypes: oil-type gas and coal-type gas. The primary distinguishing feature between gases of organic and inorganic origin is their alkane carbon isotope sequence. It is generally inferred that gas of organic origin exhibits a positive carbon isotope sequence (i.e., δ13C1 < δ13C2 < δ13C3 < δ13C4), while gas of inorganic origin exhibits a negative carbon isotope sequence (i.e., δ13C1 > δ13C2 > δ13C3 > δ13C4)1,2,3,4,5,6,7,8,9,10. In addition, some natural gas samples exhibit a partial inversion of their alkane carbon isotope sequence (e.g., δ13C1 > δ13C2 < δ13C3 < δ13C4, δ13C1 < δ13C2 > δ13C3 < δ13C4, or δ13C1 < δ13C2 < δ13C3 > δ13C4). The causes of this inversion may include: mixing of gases of organic and inorganic origins; mixing of different types of natural gas (oil-type gas and coal-type gas); mixing of gases from different sources or different generations (e.g., primary gas and secondary gas)11,12,13, bacterial oxidation and degradation14; effects of high temperature and/or high pressure (e.g., mixing of gas reservoir gas and water reservoir gas, thermochemical sulfate reduction, or Rayleigh fractionation)15,16,17,18,19,20, and the migration and diffusion effects of natural gas2,21. In shale gas, carbon isotope sequence inversion is typically associated with reservoir overpressure and high gas production, and is often used as an indicator when evaluating areas that may be favorable for shale gas exploration and production19,21,22,23.

Carbon isotope sequences have widespread applications in natural gas geochemistry, including identifying the origin and source of natural gas, studying the maturity of source rocks and secondary changes in natural gas, and reflecting the formation period and sedimentary environment of gas reservoirs, all of which are highly significant1,2,6,14,24,25,26,27,28. It is generally inferred that a negative carbon isotope sequence (complete inversion of carbon isotope signatures) is a typical characteristic of natural gas of inorganic origin3,4,5,6. To date, there have been no publicly reported cases of organic natural gas reservoirs having a negative carbon isotope sequence. Preliminary studies indicate that some gas samples from the Qingyang gas field in the southwestern part of the Ordos Basin exhibit a negative carbon isotope sequence (i.e., δ13C1 < δ13C2 < δ13C3), resembling the characteristics of gas of inorganic origin. However, the Ordos Basin, as a typical cratonic basin, has a relatively stable geological structure with no major deep faults connecting to the subsurface27,28,29,30,31, and no conclusive evidence of inorganic natural gas has been reported. Therefore, the negative carbon isotope sequence of natural gas in the Qingyang gas field may be caused by other factors; however, there is currently no reasonable explanation for this phenomenon.

Here, we take the Qingyang gas field as an example and, based on a discussion of its natural gas origin, conduct a comparative study of the alkane carbon isotope signatures of natural gas of a single origin type in the Ordos Basin. This aims to clarify how the characteristics of alkane carbon isotope composition vary with the degree of thermal maturation. On this basis, we use adsorption/desorption experiments of high-rank coal (Ro > 2.0%) to propose that adsorption may play an important role in creating negative carbon isotope sequences in over-mature coal-type gas. Explaining the negative carbon isotope sequence observed in natural gas of the Qingyang gas field is of great significance for the exploration and development of natural gas in the study area and for the theoretical understanding of natural gas geochemistry.

Geological setting

The Ordos Basin is the second-largest sedimentary basin in China and is rich in oil, gas, and coal resources. It is a large, continental oil- and gas-bearing basin with a complex multi-cycle superimposition pattern, characterized by stable subsidence in the Paleozoic, sag migration in the Mesozoic, and surrounding tectonic movement and faulting in the Cenozoic29,30,32,33,34. The Ordos Basin is divided into six primary structural units: Jinxi Fold Zone (eastern part), Yishan Slope (central part), Yimeng Uplift (northern part), Weibei Uplift (southern part), and Tianhuan Depression and Western Margin Thrust Belt (western part) (Fig. 1). The overall structural form of the basin is high in the east and low in the west, high in the north and low in the south, with a gently sloping central area, surrounded by uplifts and well-developed faults. The tectonic evolution of the basin can be divided into five stages: Mid‒Late Proterozoic rift valley, Early Paleozoic shallow marine platform, Late Paleozoic coastal plain, Mesozoic inland basin, and Cenozoic peripheral fault depression27,28,34,35. The Ordos Basin contains three sets of sedimentary rock sequences: Lower Paleozoic marine carbonates and gypsum, Upper Paleozoic marine‒terrestrial transitional clastic rocks and coal, and Mesozoic lacustrine and riverine clastic rocks; this results in a tri-layer geological structural imprint on the hydrocarbon generation of the basin. The basin contains two sets of gas-bearing assemblages, with the upper assemblage comprising Upper Paleozoic Carboniferous–Permian tight sandstone gas reservoirs, and the lower assemblage comprising Ordovician carbonate-rock gas reservoirs. Following over 40 years of exploration, eight major gas fields with proven reserves exceeding 100 billion m3 have been discovered; these are Sulige, Wushenqi, Daniudi, Yulin, Zizhou–Mizhi, Shenmu, and Jingbian. The cumulative proven natural gas reserves amount to 6.89 × 1012 m327,28,31 (Fig. 1).

Fig. 1
figure 1

Distribution of coal-type gas in the Ordos Basin and vitrinite reflectance (Ro) isopleth map of source rocks.

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Two sets of natural gas source rocks are developed within the Ordos Basin: one set consists of Upper Paleozoic Carboniferous–Permian coal source rocks, and the other of Lower Paleozoic dark mudstone, shale, and mud-dominated carbonate rocks deposited in marine environments. Among these, the Carboniferous–Permian coal source rocks are the dominant hydrocarbon source rocks in the basin27,28,36. The Upper Paleozoic coal source rocks consist of coal and dark mudstone, developed within the Benxi Formation (C2b) of the Carboniferous and Taiyuan (P1t) and Shanxi formations (P1s) of the Permian. These source rocks are relatively stable in distribution within the basin, with coal seam thicknesses ranging from approximately 10 to 25 m; seams in the central part of the basin are thinner (2–10 m), with a gradual thickening towards the west and east, where local thicknesses exceed 40 m. In most areas of the basin, the source rocks have entered the high maturity stage, with vitrinite reflectance (Ro) values predominantly ranging from 0.6 to 3.0%. The general trend is one of relatively low Ro values in the northern and eastern parts of the basin, and higher values in the southern and western parts. Locally, there are anomalously over-mature regions, with Ro values reaching 4.0%27,28,31.

In 2018, the Qingyang gas field was discovered within the Ordos Basin, in the Longdong area of the southwestern part of the Yishan Slope (Fig. 1). Similar to gas fields in the northern part of the basin, such as the Sulige gas field, the Qingyang gas field exhibits tight-reservoir characteristics, such as low porosity, low permeability, low gas abundance, and low pressure. Additionally, the reservoir in the Qingyang gas field is buried at a relatively great depth (averaging over 4200 m), with the main gas-bearing layer located in member 1 of the Lower Permian Shanxi Formation (P1s1). The thermal maturity of the source rocks is relatively high, with an average Ro of approximately 3.0%37.

Samples and experimental method

A total of 27 natural gas samples were collected for this study, primarily from wells in the Qing 1–11 series, Qing 1–12 series, Qing 1–13 series, and Qing Tan 1. The gas-producing strata all occur within member 1 of the Lower Permian Shanxi Formation (referred to hereafter as Shan 1 member, P1s1). The gas samples were collected using dual-port steel cylinders. During sampling, both ends of the cylinder valves were opened and the cylinder was flushed with the target natural gas for at least 1 min before collecting a sample. The cylinder pressure was generally kept at > 2 MPa to ensure that the collected samples were not contaminated by air. After collection, the samples were sent to the laboratory, where their gas composition and alkane carbon and hydrogen isotope compositions were analyzed.

In addition, we collected 188 geochemical data points from publicly available literature on natural gas from 12 other gas fields/regions, including the Sulige gas field11,38, Sulige South gas field39, Yulin gas field38,40, Daniudi gas field38,41, Dingbei gas field41, Zizhou gas field38, Wushenqi gas field40, Gaoqiao area39, Dongsheng gas field38, Linxing area, Shiguhao, and Shili Jahan42. All of these natural gas occurrences are sourced from ancient Paleozoic Carboniferous‒Permian strata, essentially covering all natural gas in Paleozoic strata of the Ordos Basin; these data were used for comparative research.

Gas geochemical analysis

Gas composition was analyzed using an Agilent 6890N gas chromatograph (GC), with a Plot Al2O3 column (50 m × 0.53 mm × 0.25 μm). The initial temperature was maintained at 30 °C for 10 min, followed by a temperature increase to 180 °C at a rate of 10 °C/min, then this temperature was held for 20 min.

Carbon isotope analysis was conducted using an Agilent 6890 GC coupled with a MAT 253 stable isotope mass spectrometer (IRMS). Helium was used as the carrier gas, then converted to CO2 at the combustion interface with a column flow rate of 3 mL/min at split ratio of 10:1, before being introduced into the IRMS. The chromatographic column used was a fused silica capillary column (Plot 30 m × 0.32 mm × 0.25 μm). The initial temperature of the chromatograph was set to 40 °C, followed by an increase to 80 °C at a rate of 8 °C/min, and a further increase to 260 °C at a rate of 5 °C/min, where it was then held for 10 min. Carbon isotope data were obtained relative to the international carbon reference standard (VPDB), with an analytical precision of ± 0.3‰.

Hydrogen isotope analysis was conducted using an Ultra Trace GC-MAT 253 IRMS. The chromatographic column used was a fused silica capillary column (HP-AI2O3, 50 m × 0.53 mm × 0.25 μm). Helium was again used as the carrier gas. The column flow rate was 3 mL/min, the GC inlet temperature was maintained at 280 °C, and the split ratio was 5:1. The initial temperature of the chromatograph was set to 40 °C and held for 4 min, followed by a temperature increase to 250 °C at a rate of 8 °C/min, where it was then held for 10 min. Hydrogen isotope data were obtained relative to the international hydrogen reference standard (V-SMOW), with an analytical precision of ± 3‰.

Mixed gas adsorption/desorption experiment

To investigate the characteristics of gas adsorption/desorption on high-rank coal, we designed a dedicated gas adsorption/desorption apparatus. The standard gas mixture used consisted of methane (5.01%), ethane (0.25%), and helium (94.74%) as the adsorbed gases. The adsorbent selected was high-rank coal from Carboniferous‒Permian strata of the Ordos Basin (Ro > 2.0%, particle size 60‒80 mesh).

Sample pretreatment was conducted by placing the 60‒80 mesh high-rank coal samples into a drying oven and drying at 150 °C for 24 h to remove moisture and other impurities adsorbed on the samples. The samples were then placed into the sample chamber, which was evacuated to a vacuum, then filled with helium gas. Once stable, the helium supply was switched to the adsorbed gas mixture. The adsorbed gas entered from one end of the sample chamber, gradually filling the chamber, and exited from the other end. The outlet was connected to a six-way valve, allowing the effluent gas to be carried by the carrier gas into a GC for compositional analysis. At regular intervals, gas samples were collected from the effluent and their carbon isotope compositions were then analyzed. The carbon isotope analysis method was the same as that described above. For detailed experimental procedures and operating protocols, please refer to Liu et al.43,44.

Results and discussion

Geochemical characteristics of natural gas

The analyzed natural gas samples predominantly comprised hydrocarbons: the methane content ranged from 85.02 to 93.73%, with an average of 90.97%; ethane content ranged from 0.79 to 1.22%, with an average of 1.01%; and propane content ranged from 0.063 to 0.218%, with an average of 0.130%. Non-hydrocarbon gases included CO2, with a content ranging from 0.907 to 4.23% (average of 3.81%), and N2, with a content ranging from 2.13 to 10.08% (average of 4.04%) (Table 1). The gas dryness factor ranged from 0.984 to 0.991, indicative of dry gas. Distinctive features of the Qingyang natural gas samples were the gas composition being predominantly methane, and a high gas dryness factor (C1/C1–5) close to 1.0. Dry gas is typically derived from biogenic gas or highly over-mature source rocks6,7,9,24,45.

Table 1 Gas compound and carbon/hydrogen isotope signatures of natural gas from the Qingyang gas field in the Ordos Basin.
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The methane carbon isotope signature (δ13C1) of the Qingyang gas field samples ranged from − 29.5 to − 26.5‰, with an average of − 27.7‰; the ethane carbon isotope signature (δ13C2) ranged from − 32.9 to − 26.9‰, with an average of − 29.4‰; and the propane carbon isotope signature (δ13C3) ranged from − 31.6 to − 27.6‰, with an average of − 29.8‰. Some samples did not yield reliable carbon isotope data for propane owing to its low concentration. The carbon isotope signature of CO2 (δ13CCO2) ranged from − 11.9 to − 4.8‰, with an average of − 7.5‰ (Table 1). The hydrogen isotope signature of methane (δDc1) ranged from − 180 to − 170‰, with an average of − 174‰; the hydrogen isotope signature of ethane (δDc2) ranged from − 161 to − 113‰, with an average of − 137‰; and the hydrogen isotope signature of propane (δDc3) ranged from − 120 to − 21‰, with an average of − 72‰ (values for reference only). No hydrogen isotope data for butane were obtained.

Source and origin of natural gas in the Qingyang gas field

The genetic sources of natural gas are complex and diverse. A source is usually distinguished by integrating the gas composition, carbon isotope composition, hydrogen isotope composition, and geological background6,14,46. The carbon/hydrogen isotope sequence of natural gas can be used to identify its genetic type1,5,6,7,9. Broadly speaking, natural gas can be classified into gas of organic origin and gas of inorganic origin, with the carbon isotope composition sequence used as the primary indicator to distinguish between these two types. Gas of organic origin generally follows a positive sequence, wherein the carbon isotope signature gradually becomes heavier as the carbon number of the gas component increases (i.e., δ13C1 < δ13C2 < δ13C3 < δ13C4). In contrast, gas of inorganic origin generally follows a negative sequence, wherein the carbon isotope signature gradually becomes lighter as the carbon number increases (i.e., δ13C1 > δ13C2 > δ13C3 > δ13C4), so that methane has the heaviest carbon isotope composition, followed by ethane, then propane; this being the opposite of natural gas of organic origin5,6,11,16. The hydrogen isotope composition generally exhibits the above similar characteristics6.

The alkane carbon isotope sequence of natural gas in the Qingyang gas field is generally characterized by a negative sequence, with some samples recording partial inversion of the sequence (Fig. 2). According to traditional thinking, this Qingyang natural gas can be classified as inorganic in origin. However, careful analysis reveals that although the carbon isotope sequence of Qingyang natural gas generally follows a negative sequence, there is substantial geological and geochemical evidence that is inconsistent with an inorganic origin for the gas. From a geological perspective, the Ordos Basin, as a typical large, multi-cycle cratonic basin27,28,29,30,31, is the most tectonically stable oil- and gas-bearing basin in China. It does not contain deep major faults that connect different geological layers, and the geological conditions necessary for the generation of mantle-derived gas (i.e., gas of inorganic origin) are not present. Currently, there is no conclusive evidence to suggest the existence of inorganic natural gas anywhere in the Ordos Basin. From a geochemical perspective, gas of inorganic origin typically possesses a relatively heavy methane carbon isotope signature, generally ranging from − 1 to − 21‰47, and methane is generally not the major gaseous component. However, in the Qingyang gas field, the average methane content is 90.97% and the average carbon isotope composition of methane (δ13C1) is − 27.7‰; this is evidently inconsistent with gas of inorganic origin.

Fig. 2
figure 2

Carbon isotope sequence of alkanes in coal-type gas in the Ordos Basin.

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Utilizing the hydrogen isotope characteristics of thermogenic natural gas, Wang et al.48 proposed the use of the methane carbon/hydrogen isotope ratio or methane hydrogen isotope/ethane carbon isotope composition to identify the source rock types of natural gas in China. The diagrams shown in Fig. 3 combine carbon and hydrogen isotope data and have been widely applied to identify natural gas of complex origin. When these data were plotted for typical Upper Paleozoic coal-type gas in the Ordos Basin, we found that natural gas samples from the Qingyang, Sulige, and Daniudi gas fields, among others, plotted within the coal-type gas region on the methane carbon/hydrogen isotope discrimination diagram (Fig. 3a). However, on the ethane carbon isotope/methane hydrogen isotope discrimination diagram, natural gas samples from the Sulige, Daniudi, and Dingbei gas fields plotted within the coal-type gas region, but natural gas from the Qingyang gas field deviated from the coal-type gas region and approached the oil-type gas region (Fig. 3b). Further analysis revealed that the methane hydrogen isotope signature of natural gas from the Qingyang gas field exhibits little variation, but the ethane carbon isotope signature becomes gradually lighter with increasing Ro, thereby deviating from the coal-type gas region. This indicates that these discrimination diagrams work well for identifying the source rock types of the majority of natural gas samples, but appear less applicable to over-mature natural gas.

Fig. 3
figure 3

Carbon and hydrogen isotope compositions of (a) methane and (b) ethane in coal-type gas from the Ordos Basin.

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The δ13C1 vs. C1/C2+3 diagram proposed by Whiticar49 is widely used to identify the genesis of natural gas. According to this diagram, natural gas from the Qingyang gas field plots relatively close to natural gas samples from typical Upper Paleozoic coal-type gas fields in the Ordos Basin, such as Sulige, Yulin, Zizhou, Wushenqi, and Dongsheng; these all plot close to the Type III kerogen field (Fig. 4). This indicates that natural gas from the Qingyang gas field shares a similar genesis to that of other coal-type gases in the basin, i.e., it is a typical coal-type gas, derived from Upper Paleozoic Carboniferous‒Permian strata. Further analysis reveals that natural gas from the Qingyang gas field plots closest to that from the southern Sulige region and Gaoqiao area, exhibiting a relatively heavy methane carbon isotope signature and high C1/C2+3 ratio (Fig. 4). In contrast, natural gas samples from the Sulige, Yulin, Zizhou, Wushenqi, and Dongsheng gas fields generally exhibit lighter methane carbon isotope signatures and lower C1/C2+3 ratios. This primarily indicates that the degree of thermal evolution of source rocks in gas fields such as Sulige and Yulin is lower than that in the Qingyang gas field, southern Sulige region, and Gaoqiao area. According to the empirical formula for coal-type gas, δ13C1‒Ro, proposed by Chen et al.50, the calculated source rock Ro for natural gas in the Qingyang gas field is 2.47%, indicating that it is in the over-mature stage. This value is similar to the maturity level of Carboniferous‒Permian coal in the Qingyang region, suggesting that natural gas in the Qingyang gas field is over-mature coal-type gas, primarily sourced from Carboniferous‒Permian coal seams.

Fig. 4
figure 4

Relationship between C1/C2+3 and carbon isotope composition of methane (δ13C1) from coal-type gas in the Ordos Basin.

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Although natural gas in the Qingyang gas field appears to be over-mature coal-type gas sourced from Carboniferous‒Permian strata, its geochemical characteristics exhibit two anomalies: (1) the carbon isotope composition of ethane exhibits characteristics typical of oil-type gas; (2) the carbon isotope sequence of alkanes in the majority of samples is reversed (δ13C1 > δ13C2 > δ13C3), a pattern similar to that found in inorganic gas.

Characteristics of the alkane carbon isotope composition of coal-type gas at different maturity levels in the Ordos Basin

Previous studies have established empirical formulae for oil- and coal-type gases based on the correlation between the carbon isotope composition of methane (δ13C1) and thermal maturity of source rocks (Ro)9,50,51,52,53. It is generally inferred that the carbon isotope composition of methane becomes heavier with increasing thermal maturity, and at the same level of thermal maturity, the carbon isotope composition of methane in coal-type gas is heavier than that in oil-type gas. The δ13C1‒Ro empirical formula proposed in previous studies has played an important role in natural gas exploration. According to this formula, the Ro of a source rock can be calculated based on the δ13C1 signature, allowing for an accurate determination of the source rocks from which a natural gas sample originates during gas source comparison. Although the formulae proposed by different scholars vary and their ranges of applicability differ, the common point is that with increasing thermal maturity, the δ13C1 signature in natural gas gradually becomes heavier6. To date, no natural gas reservoir has been discovered where the δ13C1 signature becomes lighter with increasing Ro, unless secondary processes have occurred.

Therefore, this characteristic relationship can be used to verify changes in the geochemical indicators of natural gas as thermal maturity increases. The Upper Paleozoic Carboniferous‒Permian coal source rocks in the Ordos Basin are an extremely important set of source rocks within the basin27,28,31. The gas in many medium to large gas fields in the basin originates from this set of source rocks, and this has become a consensus. Overall, the Carboniferous‒Permian coal source rocks in the northeastern part of the basin are buried at a relatively shallow level and have low thermal maturity, reaching the mature stage. Towards the southwest, the burial depth gradually increases, as does the thermal maturity, eventually reaching the highly mature or over-mature stage (Fig. 1).

On the basis of data from other gas fields in the Ordos Basin (e.g., Sulige, Yulin, Daniudi, Dingbei, and Wushenqi), there is a strong positive correlation between the δ13C1 signature and gas dryness coefficient (C1/C1‒5) (Fig. 5a), indicating that the gas dryness coefficient is also a good indicator of thermal maturity. Therefore, both the δ13C1 signature and gas dryness coefficient can be used as indicators to verify variation in the carbon isotope compositions of ethane and propane with respect to thermal maturity.

Fig. 5
figure 5

Relationship between gas dryness coefficient (C1/C1‒5) and carbon isotope composition of (a) methane (δ13C1) and (b) ethane (δ13C2) from coal-type gas in the Ordos Basin.

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From the relationship between the gas dryness coefficient and carbon isotope composition of ethane (δ13C2) in typical Upper Paleozoic coal-type gas in the Ordos Basin, it can be seen that as the gas dryness coefficient increases, the δ13C2 signature first becomes slightly heavier; then, when C1/C11–5 ≥ 0.98, the δ13C2 signature becomes markedly lighter (Fig. 5b). This indicates that at a certain level of thermal maturation, the δ13C2 signature slowly becomes heavier as thermal maturity increases. However, when the source rock maturity reaches a critical threshold, the δ13C2 signature will suddenly become much lighter.

In addition, in typical Upper Paleozoic coal-type gas from the Ordos Basin, as the δ13C1 signature increases, the δ13C2 signature increases slightly at first; however, when the δ13C1 signature reaches ≥ − 30‰, the δ13C2 signature rapidly becomes lighter (Fig. 6a). Again, this indicates that at a certain level of thermal maturation, the δ13C2 signature slowly becomes heavier as thermal maturity increases, but when the source rock maturity reaches a critical threshold, the δ13C2 signature will abruptly become lighter. Simultaneously, as the δ13C1 signature gradually becomes heavier, the propane carbon isotope composition (δ13C3) gradually becomes lighter (Fig. 6b). These combined data suggest that as thermal maturity increases, the δ13C2 signature will abruptly become much lighter at a certain threshold (Fig. 6a), while the δ13C3 signature will gradually become lighter (Fig. 6b).

Fig. 6
figure 6

Variation of alkane carbon isotope composition in coal-type gas from different regions of the Ordos Basin with changing thermal evolution.

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By studying the relationship between the δ13C2 and δ13C3 signatures of typical Upper Paleozoic coal-type gas in the Ordos Basin, we observed that natural gas samples from the Sulige, Yulin, Daniudi, Dingbei, and Wushenqi gas fields all plot within the coal-type gas region (Fig. 6c). However, natural gas samples from the over-mature Qingyang gas field and Gaoqiao area mostly plot within the oil-type gas region (Fig. 6c). This suggests that when the source rock maturity has not reached the over-mature stage, δ13C2 and δ13C3 signatures can be used to identify the type of source material of the resultant natural gas. However, when the source rock maturity becomes too high, the δ13C2 and δ13C3 signatures in coal-type gas gradually become lighter with increasing Ro, leading to the failure of the δ13C2 = − 28‰ and δ13C3 = − 25‰ criterion for distinguishing oil- and coal-type gases.

In addition, the δ13C1‒Ro empirical formula proposed in previous research has played an important role in natural gas exploration. Other empirical formulae have also been proposed (e.g., δ13C2‒Ro and δ13C3‒Ro), which imply that δ13C2 and δ13C3 signatures gradually become heavier with increasing thermal maturity9,53. However, the over-mature natural gas samples analyzed herein, such as those from the Qingyang gas field and Gaoqiao area, indicate that the δ13C2‒Ro and δ13C3‒Ro empirical formulae proposed previously are not applicable to over-mature natural gas.

In summary, the geochemical characteristics of natural gas in the Qingyang gas field are anomalous in three aspects: (1) The δ13C2 and δ13C3 signatures in coal-type gas gradually become lighter with increasing Ro, leading to the failure of the indicators (δ13C2 = −28‰ and δ13C3 = −25‰) used to distinguish oil-type gas from coal-type gas. (2) The δ13C2‒Ro and δ13C3‒Ro empirical formulae proposed in previous research are not applicable to over-mature natural gas. (3) With increasing Ro, the δ13C2 signature gradually becomes lighter, invalidating the δ13C2‒δ2H1 chart used by previous researchers to determine the source material type, because samples deviate from the coal-type gas range.

Insights from mixed gas adsorption/desorption experiments on negative carbon isotope sequences

From the above analysis, we conclude that the anomalous geochemical characteristics of natural gas in the Qingyang gas field are primarily characterized by the relatively light carbon isotope compositions of ethane (C2H6) and propane (C3H8). In this section, we focus on the causes of these anomalous carbon isotope compositions, addressing the issue from two aspects. Firstly, natural gas in the Qingyang gas field originates from over-mature Carboniferous‒Permian coal source rocks. During the evolution of coal, the pore volume and specific surface area initially decrease and then increase. After reaching the medium coal stage, the pore volume and specific surface area of coal gradually increase with increasing thermal maturation54,55,56,57. In particular, there is a marked increase in micropores and transition pores, which substantially enhances the adsorption capacity of the coal. At this stage, the natural gas is predominantly dry gas (C1/C1–5 > 0.95), with a very low content of heavier hydrocarbon gases (C2+). Therefore, we infer that the observed anomalous carbon isotope phenomenon is related to the adsorption of gas by coal. During the over-mature stage, the content of C2+ gases is extremely low, and coal adsorbs these gases more strongly than it does methane. As a result, ethane and other C2+ gases with lighter carbon isotope compositions will desorb preferentially. In contrast, owing to its higher concentration, the isotopic composition of methane is less affected by adsorption.

In this study, we also conducted gas adsorption/desorption experiments using Carboniferous‒Permian high-rank coal from the Ordos Basin. These experimental results showed that when gas passes through a coal sample, part of the gas is adsorbed by the coal, while the excess gas is gradually expelled, resulting in detection of gas at the outlet of the experimental apparatus. During the adsorption experiment, methane was detected first, followed by ethane after a period of time, indicating that the coal sample adsorbed less methane than ethane. The time required for methane to reach adsorption equilibrium was also shorter than that for ethane. During the gas desorption phase, there was an initial surge in the amounts of methane and ethane detected, which then rapidly decreased. Relatively speaking, the methane content decreased faster than the ethane content (Fig. 7a).

Fig. 7
figure 7

Characteristics of gas composition and the carbon isotope compositions of methane and ethane during the adsorption/desorption process of high-rank coal (Ro > 2.0) in the Ordos Basin.

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During the gas adsorption process, the methane that first flowed out had a very light carbon isotope signature (– 48‰), this being approximately 8‰ lighter than that of the original methane. Methane that flowed out later had a carbon isotope signature that was approximately 3.5‰ heavier than that of the original methane. As the adsorption experiment progressed, the δ13C1 signature gradually became lighter and eventually reached equilibrium. The variation in the δ13C2 signature during the gas adsorption process was slightly different. Initially, the ethane that flowed out had a carbon isotope composition that was approximately 11‰ heavier than that of the original ethane. As the adsorption experiment progressed, the δ13C2 signature gradually became lighter and eventually reached equilibrium (Fig. 7b). These experimental data indicate that during gas adsorption, the coal sample first preferentially adsorbs methane and ethane with lighter isotopic signatures, which contradicts common understanding. From our analysis, we infer that the slightly faster migration and diffusion rates of molecules containing lighter isotopes leads to their slight enrichment in the early stage of the gas flow, allowing them to preferentially occupy adsorption sites in the coal medium. The patterns for methane and ethane are similar, but a lower concentration equates to a more pronounced isotopic fractionation.

During gas desorption, the δ13C1 and δ13C2 signatures in the outflowing gas gradually became lighter, with that of ethane ultimately becoming lighter by approximately 5‒6‰, and that of methane becoming lighter by approximately 6‒7‰. This indicates that gases with lighter carbon isotope signatures desorb preferentially, ultimately resulting in a gas with a lighter carbon isotope composition. The patterns for methane and ethane are similar. However, in an actual production scenario, the δ13C1 signature is less affected by adsorption owing to its higher concentration. This also indicates that during the over-mature stage, the content of heavier hydrocarbon gases, such as ethane, is very low, and they primarily exist in the adsorbed state. During natural gas extraction, it is difficult to desorb heavier hydrocarbon gases such as ethane and propane. The small amount of ethane and propane that does desorb has a relatively light carbon isotope composition. In contrast, because there is a higher initial concentration of methane, there is a markedly lower proportion of adsorbed methane compared with that of heavier hydrocarbon gases such as ethane. Therefore, during extraction, the δ13C1 signature does not change markedly. This leads to the carbon isotope composition of extracted methane being representative of its in-situ state, while the carbon isotope compositions of ethane and propane are much lighter than those of their in-situ state, resulting in the observed phenomenon of anomalously light carbon isotope signatures associated with ethane and propane in the analyzed samples.

In Upper Paleozoic coal-derived gas in the Ordos Basin, this phenomenon primarily occurs in over-mature natural gas, where the contents of ethane and propane are low, and their carbon isotope compositions also exhibit a distinct shift to lighter values (Fig. 8). This phenomenon is jointly caused by changes in the physical properties of coal and the drying of gas components.

Fig. 8
figure 8

Relative contents of (a) ethane and (b) propane in coal-type gas and their carbon isotope signatures in different regions of the Ordos Basin.

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Conclusion

  1. 1.

    Natural gas from the Qingyang gas field is derived from over-mature coal-type gas from Carboniferous‒Permian coal. However, its geochemical characteristics are anomalous: the δ13C2 signature shows characteristics typical of oil-type gas; moreover, there is a negative carbon isotope sequence (δ13C1 > δ13C2 > δ13C3) in the majority of samples, similar to that observed in inorganic gas.

  2. 2.

    The anomalous geochemical characteristics of natural gas in the Qingyang gas field are primarily related to the adsorption of different gases by coal. During the over-mature stage, the content of heavier hydrocarbon gases is very low, and the coal has a stronger adsorption capacity for heavier hydrocarbon gases than it does for methane. Ethane and propane with lighter carbon isotope signatures desorb preferentially, resulting in a lighter observed carbon isotope composition. Owing to its higher concentration, the isotopic composition of methane is less influenced by adsorption.

  3. 3.

    The anomalous geochemical characteristics of over-mature coal-type gas result in the failure of the ‘negative carbon isotope sequence’ diagnostic criterion for inorganic gas. This also causes the criterion using thresholds of δ13C2 = ‒ 28‰ and δ13C3 = ‒ 25‰ to distinguish oil-type gas from coal-type gas to become ineffective. Furthermore, empirical formulae proposed in previous research (e.g., δ13C2‒Ro and δ13C3‒Ro) are not applicable to over-mature natural gas. These discoveries have revised and improved the criteria for identifying the origin of natural gas.

  4. 4.

    The carbon isotope signature of methane (δ13C1) and gas dryness coefficient (C1/C1–5) are reliable indicators of source rock maturity.