1 Introduction

The Jiyang Depression is located in the north part of Shandong Province in China, on the fluvial plain and the delta where the Huanghe River runs into the Bohai Sea. Tectonically, the Jiyang Depression is located in the southeast part of the Bohai Bay Basin. It is a big terrestrial depression and ranks as one of the most prolific petroliferous area (Li et al. 2003). Since the discovery of the Shengli Oilfield in 1960, 50 × 108 t of OOIP and 2,500 × 108 m3 OGIP have been proved, at the same time, 10.7 × 108 tons of oil and 460 × 108 m3 gases have been produced.

Five sets of source rocks were developed in the Jiyang Depression, and they are distributed in the Carboniferous-Permian, the second member of the Kongdian Formation (Ek2), and the fourth, third, and first members of the Eogene Shahejie Formation (Es4, Es3, and Es1). The kerogen in those source rocks is mainly sapropelic type, and some of them are humic type. After a series of tectonic movements, these source rocks vary greatly in depth and evolution histories which influence gas generation and accumulation in many aspects, such as gas components, genesis, etc. (Zhang 1991). Thirteen commercial gas bearing layers have been discovered in the Neogene Minghuazhen and Guantao Formations, the Eogene Shahejie Formation, and the Paleozoic Carboniferous-Permian and Ordovician in the Jiyang Depression (Fig. 1). Gas reservoirs occurred widely at a depth from 192 to 4,750 m. In these reservoirs, gas compositions vary greatly from hydrocarbon gas to abiogenic gas. As for hydrocarbon gas, the paraffin hydrocarbon composition and carbon isotope ratios varied dramatically. There are several different genesis models such as oil-type gas, coal-type gas, biogas, and inorganic mantle source gas, etc. (Gao et al. 2011; Zhou 2004; Luo et al. 2008). Natural gases usually occur as normal gas reservoirs, tight sandstone gas reservoirs, shale gas reservoirs, and coal-bed methane.

Fig. 1
figure 1

Strata histogram and gas bearing layers in the Jiyang Depression

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To make a thorough investigation of the gas genesis in the Jiyang Depression, the authors collected abundant data from exploration wells with commercial gas flow including 472 sets of natural gas composition data, 293 sets of carbon isotope ratio data (both hydrocarbon gas and carbon dioxide), and 69 sets of light hydrocarbon properties data (Fig. 2). According to gas component contents, carbon isotope ratios and light hydrocarbon properties, combined with geological analysis, natural gases in the Jiyang Depression are divided into two categories namely organic gas and abiogenic gas. Organic gas was further divided into coal-type gas, oil-type gas, and biogas according to kerogen type and formation mechanism. The oil-type gases were finally divided into mature oil-type gas (oil-associated gas) and highly mature oil-type gas (including oil-cracking gas and kerogen thermal degradation gas) (Schoell 1980). The geochemical properties of each kind of natural gas were discussed, respectively.

Fig. 2
figure 2

Structural framework and typical gas producing wells in the Jiyang Depression

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2 Abiogenic gas

Abiogenic gas in the Jiyang Depression is mainly CO2, and its distribution is controlled by great deep faults (Tang et al. 2002). This type of gas is mainly found in Pingfangwang, Pingnan, and Huagou gas fields in the western part of the Dongying Sag and the Balipo gas field in the northern part of the Huimin Sag. Vertically, CO2 is mainly distributed in the Shahejie Formation of Eogene (Es for short), Neogene, and Ordovician. The CO2 content of such reservoirs ranges from 55.5 % sto 100 % and averages 82.4 %. Hydrocarbon gases were mixed into CO2 reservoirs in varying degrees. The methane content in those reservoirs ranges from 0 % to 37.2 % with an average of 13.3 %, while the heavy hydrocarbon (C2+) content was low with an average value of 1.4 % (Table 1).

Table 1 Geochemical characteristics of CO2 in the Jiyang Depression
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There are usually three genetic types of natural CO2, namely magma degassing, decomposition of carbon rich crustal rock, and decomposition of organic matter. Studies have confirmed that δ13CCO2 can be used to identify its genesis. It is generally believed that δ13CCO2 > −8 ‰ indicates inorganic genesis, and δ13CCO2 < −10 ‰ indicates organic genesis (Zhang 1991; Dai 1993). In the Jiyang Depression, gas reservoirs with high CO2 content (>60 %) usually have heavy carbon isotope ratios ranging from −9.8 ‰ to −3.4 ‰ (PDB). The δ13CCO2 of most samples was higher than −7 ‰, and this can be classified as inorganic genesis. The CO2 content in hydrocarbon gas reservoirs was usually lower than 10 % with δ13CCO2 less than −8 ‰, and it can be deduced that the CO2 came from decarboxylation of organic matter (Fig. 3).

Fig. 3
figure 3

Identifying inorganic and organic CO2 with δ13CCO2—CO2 relationships (Dai 1993)

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Previous studies have shown that helium of different genesis has different isotopic compositions, and the 3He/4He values of atmosphere, earth mantle, and crust are, respectively, 1.4 × 10−6, 1.1 × 10−5, and 2 × 10−8 (Sun et al. 1996). As shown in Table 2, the 3He/4He value of CO2 reservoirs in the Pingfangwang, Huagou, and Yangxin gas fields in the Jiyang Depression was high (3.55–4.49 × 10−6), and R/Ra was 2.5–3.2, indicating a mixed He origin of mantle genesis and crust genesis (Wang et al. 2013). The isotopic analysis of rare gases and CO2 indicated that the highly concentrated CO2 gas reservoir in the Jiyang Depression originated from magma–mantle degassing (Hunt et al. 2012).

Table 2 Characteristics of rare gas isotope in CO2 gas reservoirs in the Jiyang Depression
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3 Organic gases

Organic hydrocarbon gases are produced from sedimentary organic matter due to a series of biological-geochemical reactions. Organic matter of different types and in different thermal evolution stages will produce hydrocarbon gases with different component compositions and isotopic compositions. C1/C1−5 and δ13C1 of hydrocarbon gases in the Jiyang Depression changed regularly with depth, and could be divided into three categories according to the reservoir depth (Fig. 4):

Fig. 4
figure 4

Variation of δ13C1 and C1/C1−5 of hydrocarbon gases with depth in the Jiyang Depression

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  1. (1)

    Buried less than 1,500 m: the C1/C1−5 value is usually high and ranges from 0.8 % to 1.0, 90 % of the natural gases are dry gas (C1/C1−5 > 0.95) with a methane content more than 95 %, while the values of δ13C1 can be separated into two groups: the values of group one are between −40 ‰ and −50 ‰, and the values of group two are less than −55 ‰.

  2. (2)

    Buried between 1,500 and 3,500 m: the heavy hydrocarbon content is usually high, and C1/C1−5 ranges from 0.4 to 0.9. Most gases are associated with oil, and their δ13C1 ranges from −45 ‰ to −52 ‰.

  3. (3)

    Buried between 3,500 and 5,500 m: the value of C1/C1−5 ranges from 0.6 to 1.0. Compared with the natural gas buried between 1,500 and 3,500 m, the value of C1/C1−5 is higher, and the δ13C1 is also heavier with a value of −30 ‰ to −50 ‰.

The carbon isotope composition can be used to determine the natural gas genesis as concluded below. Under conditions of similar maturity, hydrocarbon gases generated from sapropelic-type kerogen usually had heavier δ13C1 than gases generated from humic kerogen; under the condition of similar kerogen type, the natural gases of high thermal evolution degree tend to have heavy δ13C1. Due to multiple reasons such as various kerogen types, different thermal evolution degrees, and secondary changes, the distribution characteristics of δ13C1 show that δ13C1 values of natural gases at middle depth are much lower, but those at shallow and deep depths are higher (Fig. 4).

To identify the genesis of natural gases, the three categories of natural gases (shallow gas <1,500 m, middle gas 1,500–3,500 m, and deep gas >3,500 m) were put into the genesis identification template built by Dai (1993). As shown in Fig. 5, the genesis of shallow gas is complicated with biogas and oil-associated gas dominating, while there is still a small portion of shallow gas having a δ13C1 value of −40 ‰ to −55 ‰ with high C1/C1−5 and C1/C2+3 values higher than 500, which indicate secondary changes. The genesis of middle gas is comparatively simple and dominated by oil-associated gas. As for deep gas, there are several genesis options such as highly mature oil-cracking gas, associated gas with condensate oil, coal-type gas, and the mixture of two or more of them (Fig. 5).

Fig. 5
figure 5

Genesis identification template for hydrocarbon gas in the Jiyang Depression (Dai 1993)

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Carbon isotope ratios of methane, ethane, and propane can also be used to identify the genesis of natural gases (Lin et al. 2011). As shown in Fig. 6, shallow buried hydrocarbon gases in the Jiyang Depression were located in the area of oil-associated gas, but the ethane and propane carbon isotope ratios of some samples were abnormally heavy, which might be caused by secondary changes such as biodegradation. The middle buried hydrocarbon gases are mainly oil-associated gas mixed with a small amount of coal-type gas. The deep natural gases were coal-type gas, oil-type gas, as well as a mixture of the both.

Fig. 6
figure 6

Characteristics of δ13C1, δ13C2, and δ13C3 in the Jiyang Depression (Dai 1993)

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In general, hydrocarbon gases in the Jiyang Depression include biogas, oil-associated gas, highly mature oil-type gas, coal-type gas, and their geochemical characteristics are separately discussed below.

3.1 Biogas

Biogas is defined as hydrocarbon gas or nonhydrocarbon gas that is produced due to biochemical reactions of fermentative bacteria and methanogens in the process of degradation of organic matter in source rocks or crude oil (Gao et al. 2010). Naturally existed biogas was formed due to two kinds of processes: one is methyl-type fermentation (CH3COOH → CH4 + CO2) and the other is carbonate reduction (CO2 + 4H2 → CH4 + 2H2O). Limited by the survival temperature of methanogens (0−75 °C) (Li et al. 2008), biogas was mainly developed in shallow-middle buried horizons. The present geothermal gradient in the Jiyang Depression is about 3 °C/100 m, and the surface temperature was about 17 °C, so biogas in the Jiyang Depression tends to occur above 2,000 m. Biogas reservoirs have already been discovered and they are scattered in the Huagou and Yangxin gas fields.

The composition of biogas is fairly simple and is mainly methane. Heavy hydrocarbon (C2+) contents are extremely low (usually less than 0.5 %), the value of C1/C1−5 is higher than 0.995, and there are also low levels of nonhydrocarbon components (mainly N2, CO2). δ13C1 ranged from −55 ‰ to −60.9 ‰ (Table 3) (Hu et al. 2010). Since very little ethane and propane exist in biogas, it is difficult to measure their corresponding carbon isotope ratios.

Table 3 Geochemical properties of biogas in the Jiyang Depression
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Biogas is mainly developed in the first member of the Eogene Shahejie Formation (Es1 for short) in the Yangxin and Huagou gas fields. Source rocks in Es1 were buried in less than 2,000 m, and were at an immature stage with an R o value of 0.3 %–0.6 %, the formation temperature was about 55–75 °C, which provided favorable conditions for survival of methanogens. Anaerobes and methanogens have already been detected in the formation water in this area, and this confirmed that natural gas occurring in this interval is biogas.

3.2 Mature oil-type gas (oil-associated gas)

Mature oil-type gas is generated by sapropelic-type source rocks in mature stage (R o = 0.6 %−1.3 %). Since sapropelic-type source rocks tended to generate more oil than gas during its mature stage, this kind of gas usually occurred as dissolved gas in oil reservoirs. Sometimes gas would exsolve from oil due to changes in temperature and pressure, and a gas cap would be formed.

Mature oil-type gas is the most important kind of natural gas in the Jiyang Depression. Most shallow gases and middle gases as well as part of deep gases are of this kind, and the reserves of this kind of gas resource account for 3/4 of all the proved gas reserves in place. Mature oil-type gas usually occurred in the third member and the fourth member of the Eogene Shahejie Formation (Es3, Es4), and sometimes in buried hills in the Paleozoic Carboniferous or Ordovician (e.g., Zhuangxi Oilfield). This kind of gas always occurred associated with oil reservoirs and gas was produced together with oil.

The methane content of mature oil-type gas varied greatly and ranged from 25.6 % to 99.6 %. The methane content of most oil-associated gas (81 %) was about 60 %–90 %, the heavy hydrocarbon content ranged from 0 % to 70.9 %, and C1/C1−5 ranged from 0.6 to 0.99. δ13C1 of mature oil-type gas in the Jiyang Depression ranged from −38 ‰ to −55 ‰, δ13C2 ranged from −26.3 ‰ to −34.9 ‰, δ13C3 ranged from −25.6 ‰ to −32.1 ‰, δ13C4 ranged from −25.6 ‰ to −32.1 ‰, and they were arranged in the order of δ13C1 < δ13C2 < δ13C3 < δ13C4 (Table 4).

Table 4 Geochemical characteristics of typical mature oil-type gases in the Jiyang Depression
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δ13C1 and δ13C2 of mature oil-type gas in the Jiyang Depression correlated well with depth, so it is possible to calculate the maturity using gas carbon isotope ratios. Comparison between gas samples and source rock samples was carried out, and the relationship between δ13C1 and R o was established:

$$ \updelta^{{\text{13}}} \text{C}_{\text{1}} \text{ = 6}\text{.942}\ln R_{\text{o}} - \text{45}\text{.254} \, \left( {R_{\text{o}} \text{ = 0}\text{.4} - \text{1}\text{.3}} \right), $$
(1)

where δ13C1 is the methane carbon isotope ratios of mature oil-type gas, ‰; R o is vitrinite reflectance, %.

3.3 Highly mature oil-type gas

Highly mature oil-type gas was generated by sapropel-type source rock in highly mature stage (R o > 1.3 %) (Zhao et al. 2013). There are two options for the genesis of highly mature oil-type gas, one is kerogen thermal degradation gas which means that sapropel-type kerogen degrades into natural gas at high temperature; and the other is oil-cracking gas which means that oil cracks into natural gas at high temperature (Lu et al. 2006).

Compared with mature oil-type gas, kerogen thermal degradation gas usually has a higher value of C1/C1−5, and heavier δ13C1 and δ13C2. Methane comprises 70.78 %–88.6 % of kerogen thermal degradation gas and heavy hydrocarbons about 5 %–29 %, usually in the range of 10 %–15 %. The value of C1/C1−5 ranged from 0.7 to 0.9 and was a little higher than that of mature oil-type gas. δ13C1 ranged from −43.9 ‰ to −33.9 ‰, δ13C2 ranged from −27.6 ‰ to −28.7 ‰, δ13C3 ranged from −23.3 ‰ to −25.9 ‰, and δ13C4 ranged from −25.0 ‰ to −26.6 ‰. There was an apparent reversal of δ13C3 and δ13C4 (Table 5). There are multiple reasons for the isotope reversal such as mixture of gases from different kerogen types, mixture of gases from the same kerogen type but of different maturities, inorganic originated hydrocarbon gas, and biodegradation gas (Burruss and Laughrey 2010). Analysis of the reservoir forming processes indicated that the discovered highly mature oil-type gases originated from the same source rocks, i.e., the fourth member of the Eogene Shahejie Formation (Es4), which was deeply buried with little chance of undergoing biodegradation. Therefore, it can be inferred that the reversal in δ13C3 and δ13C4 was caused by the mixing of gases of different maturities.

Table 5 Geochemical properties and genesis of typical highly mature oil-type gas in the Jiyang Depression
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Table 6 Geochemical properties of typical coal-type gas in the Jiyang Depression
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Only oil-cracking gas was discovered in the Minfeng area (Chen et al. 2014), where the fourth member of the Shahejie Formation (Es4) was deeply buried, and the temperature might exceed 210 °C in its maximum depth. According to the experiment carried out by Luo et al. (2008), crude oil would crack into gases when the temperature exceeded 160 °C. Compared with kerogen thermal degradation gas with the similar maturity, δ13C1 and δ13C2 of oil-cracking gas were fairly light and, respectively, ranged from −48.4 ‰ to −50.4 ‰ and from −33 ‰ to −34 ‰ (Song et al. 2009; Tian et al. 2009).

Based on comparison of light hydrocarbon compounds in oil-cracking gas and kerogen thermal degradation gas, Hu et al. (2005) put forward that MCC6/nC7 and (2-MC6 + 3-MC6)/nC6 of oil-cracking gas were higher than those of kerogen thermal degradation gases (MCC6 means methylcyclohexane, 2-MC6 means 2-methylhexane, 3-MC6 means 3-methylhexane, nC7 means n-heptane, nC6 means n-hexane). Based on simulation experiments, Wang (2005) discovered that there were differences in MCC6/CC6, MCC6/nC7, and (2-MC6 + 3-MC6)/nC6 between these two kinds of highly mature oil-type gases (CC6 means cyclohexane). The content of thermally stable compounds in kerogen thermal degradation gas was higher than that in oil-cracking gas. In the Jiyang Depression, MCC6/nC7 of oil-cracking gas was higher than 1.0, (2-MC6 + 3-MC6)/nC6 of oil-cracking gas was higher than 0.4, which were higher than those of kerogen thermal degradation gas and mature oil-type gas, while MCC6/nC7 of oil-cracking gas was less than 0.8 which was lower than that of kerogen thermal degradation gas and mature oil-type gas (Fig. 7).

Fig. 7
figure 7

Light hydrocarbon property differences between oil cracking gas and kerogen thermal degradation gas

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3.4 Coal-type gas

Coal-type gas is defined as natural gas generated by coal or humic kerogen due to biochemical and chemical action. Coal-type gas discovered in the Jiyang Depression was mainly developed in the Paleozoic Ordovician and Carboniferous—Permian in the Gubei buried hill belt, the fourth member of the Shahejie Formation in the Bonan deep sag, and the Shahejie Formation in the Qudi Oilfield in the Huimin Sag. Coal-type gas in the Gubei buried hill and Qudi Oilfield was generated by coal and humic kerogen in the Shanxi Formation and Taiyuan Formation in Carboniferous—Permian, while that in the Bonan Sag (Well Yi115 and Yi121) was generated by humic kerogen in the upper part of Es4.

The methane content of coal-type gas ranged from 75 % to 92 %, and the heavy hydrocarbon content varied greatly from 0.51 % to 19.5 %. C1/C1−5 ranged from 0.8 to 0.99 and the value of most samples exceeded 0.9. C1/C1−5 of coal-type gas is usually higher than that of oil-type gas with a similar maturity. δ13C1 of coal-type gas in the Jiyang Depression ranged from −32.6 ‰ to −41.0 ‰, δ13C2 ranged from −22.0 ‰ to −27.6 ‰ (Table 6). There was a slight reversal in δ13C3 and δ13C4 and this might be caused by mixing with oil-type gas. It is pointed out that δ13C2 of coal-type gas in China is usually higher than −28 ‰ (Song et al. 2012; Dai et al. 2012; Wang et al. 2010), and in the Jiyang Depression, the carbon isotope ratios of coal-type gas are located in the “I” area of the “V” shaped δ13C1-δ13C2-δ13C3 template (Fig. 6).

C7 light hydrocarbon information can also be used to distinguish coal-type gas from oil-type gas. The C7 system is composed of three kinds of compounds: normal heptane (nC7), methylcyclohexane (MCC6), and multi-structured dimethylcyclopentane (∑DMCC5). MCC6 mainly came from higher plants and was a major component of C7 system in coal-type gas, and ∑DMCC5 mainly came from aquatic organisms and was a major component of C7 system in oil-type gas (Song and Zhang 2004).

As shown in Fig. 8, coal-type gas differed significantly from oil-type gas. MCC6/∑C7 of the coal-type gas exceeded 50 %, while ∑DMCC5/∑C7 was less than 40 %; as for oil-type gas, nC7/∑C7 exceeded 30 %, MCC6/∑C7 ranged from 20 to 40 %.

Fig. 8
figure 8

Triangular template of C7 light hydrocarbon in different kinds of natural gases in the Jiyang Depression

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4 Secondary changes of natural gas

Most shallow gas in the Jiyang Depression was originally dissolved gas that escaped from oil when temperature and pressure changed due to migration of oil along faults or sand bodies. This kind of natural gas was located in the “d” area (oil-associated gas) of “δ13CCH4−C1/(C2 + C3) template” in Fig. 5, and in “II” area of “V” shaped “δ13C1−δ13C2−δ13C3 template” in Fig. 6, and was typical mature oil-type gas.

There is a kind of shallow gas whose hydrocarbon carbon isotope ratios are similar to mature oil-type gas, but its heavy hydrocarbon content is extremely low, the methane content is very high (>95 %), C1/C1−5 is higher than 0.95, and is located above the “d” area of the “δ13CCH4−C1/(C2 + C3) template” (Table 7; Fig. 5). Such characteristics are caused by composition changes during long distance migration of natural gas. Gas migration experiments in porous sandstone core samples indicated that, with increasing migration distance, the methane content tended to increase while the heavy hydrocarbon content (C2+) decreased correspondingly. Furthermore, the carbon isotopes of hydrocarbon differentiated slightly and this means that carbon isotopes became lighter with an increase of migration distance (variation range usually less than −2 ‰). Therefore, it is believed that this kind of natural gas with a high content of methane was dissolved gas that escaped from oil after long-distance migration.

Table 7 Geochemical properties and genesis of shallow gas (part) in the Jiyang Depression
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There is another kind of shallow gas whose methane carbon isotope ratios are heavier than those of mature oil-type gas, and δ13C2 and δ13C3 are extremely heavy. δ13C3 of normal mature oil-type gas ranged from −26 ‰ to −34 ‰, while δ13C3 of this kind of natural gas might as heavy as −8.5 ‰. δ13C3 of most natural gas ranged from −8 ‰ to −22 ‰, and carbon isotope ratios of light hydrocarbons arranged in the order of δ13C1 < δ13C2 < δ13C3 > δ13C4. δ13C1 of some samples was about 2 ‰–7 ‰ heavier than that of mature oil-type gas. Take the Gudong Oilfield as an example, δ13C1 of mature oil-type gas (Well Gud3-517) was about −49.9 ‰, δ13C2 was about −31.4 ‰, but δ13C1 and δ13C2 of the sample from the same horizon and similar depth (Gud2-2) were, respectively, −41.9 ‰ and −31.1 ‰, that is to say δ13C1 was about 8 ‰ heavier than that in Well Gud3-517.

Analysis indicated that the main reason that caused abnormal carbon isotope ratios was biodegradation. James and Burns (1984) analyzed the carbon isotope ratios of light hydrocarbons of biodegradation natural gases in Australia and Canada, and discovered that δ13C3 was abnormally heavy. They deduced that since propane is soluble in water, it is readily biodegradable. Secondary biodegradation shallow gas in the Jiyang Depression exhibited the similar characteristics.

Stahl (1980) carried out bacterial degradation experiments, and pointed out that long-chained paraffin hydrocarbon is more easily degradable than short-chained ones, and normal paraffin hydrocarbon is more easily degradable than isomeric ones. As shown in Fig. 8, nC7/∑C7 of biodegradation shallow gas was less than 20 %, and was obviously less than that of mature oil-type gas.

Leythaeuser et al. (1979) studied biodegradation of oil using light hydrocarbon data, and summarized typical characteristics: the content of normal paraffin hydrocarbon was low, while the contents of isomeric ones (such as 3,3-DMC5; 2,3,3-TMC4; 2,2-DMC5; 2,4-DMC5 and 2,2-DMC4) were high (DMC5 means dimethylpentane, TMC4 means triptane, DMC4 means dimethylbutane). Based on analysis of light hydrocarbons in shallow gas in the Jiyang Depression, Zhang (1991) pointed out that the relationship between 2,4-DMC5/nC6 and the heptane index can be used to distinguish biodegradation oil-type gas from other oil-type gases. As shown in Fig. 9, the value of 2,4-DMC5/nC6 for biodegradation gas was usually higher than 0.5, and the heptane index was usually less than 5; in contrast, the heptane index usually ranged from 20 to 50, and 2,4-DMC5/nC6 for other oil-type gases was less than 0.1.

Fig. 9
figure 9

2,4-DMC5/nC6–heptane index template of natural gases in the Jiyang Depression (Zhang 1991)

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5 Identification factors

Based on discussion above, the identification factors for different kinds of natural gases are summarized in Table 8, and with the help of gas compositions, carbon isotope ratios of paraffin hydrocarbon and CO2, and light hydrocarbon index, it is feasible to identify the genesis of natural gases in the Jiyang Depression.

Table 8 Identification factors of hydrocarbon gases with different genesis in the Jiyang Depression
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Take mature oil-type gas as reference, biogas has a high methane content, and δ13C1 was less than −55 ‰; highly mature oil-type gases are divided into kerogen thermal degradation gas and oil-cracking gas. They both have a high value of C1/C1−5 and heavy methane carbon isotope ratios, and they can be distinguished by the (2-MC6 + 3-MC6)/nC6–MCC6/nC7 template. Ethane carbon isotope ratios of coal-type gas in the Jiyang Depression are usually higher than −28 ‰ and the compositions of C7 can be used to effectively distinguish coal-type gas from oil-type gas.

Heavy hydrocarbons usually reduce in the process of gas migration. The C1/C2+3 value of methane rich secondary gas might exceed 280, and its carbon isotope compositions and light hydrocarbon compositions are similar to those of mature oil-type gas. Secondary biodegradation gas is featured by heavy carbon isotope ratios of δ13C1 or δ13C3, and light hydrocarbon isotope ratios arrange in the order of δ13C1 < δ13C2 < δ13C3 > δ13C4. Influenced by biodegradation, the normal paraffin hydrocarbon content is low. The triangular template of C7 and 2,4-DMC5/nC6—heptane index template can be used to distinguish the secondary biodegradation gas from other natural gases.

6 Conclusions

  1. 1)

    Based on analysis of gases compositions, carbon isotope ratios, light hydrocarbon properties, combined with geological analysis, natural gases in the Jiyang Depression were classified into two categories namely hydrocarbon gas and abiogenic gas. The abiogenic gas was mainly magmatogenic or mantle derived CO2. Hydrocarbon gases were further divided into coal-type gas, oil-type gas, and biogas according to the kerogen types and formation mechanisms. The oil-type gases were divided into mature oil-type gas (oil-associated gas), highly mature oil-type gas. Highly mature oil-type gases were subdivided into oil-cracking gas and kerogen thermal degradation gas.

  2. 2)

    Analysis results showed that shallow gases (buried less than 1,500 m) are mainly mature oil-type gases, secondary gas is rich in methane after chromatographic separation during migration and secondary mature oil-type gas after biodegradation is featured by rich in 13C in methane and ethane. Meanwhile, biogas is another kind of shallow gas. The genesis of middle gases buried in the depth of 1,500–3,500 m was simple and was dominated by mature oil-type gases. Deep gases buried in the depth of 3,500–5,500 m were usually kerogen thermal degradation gas, oil-cracking gas, and coal-type gas.

  3. 3)

    Due to chromatographic effects, the methane content increases and heavy hydrocarbons decrease during the progress of migration. Secondary biodegradation gas was featured by heavy carbon isotope ratios of δ13C1 or δ13C3, and light hydrocarbon isotope ratios arranged in the order of δ13C1 < δ13C2 < δ13C3 > δ13C4. Influenced by biodegradation, the normal paraffin hydrocarbon content was low. Triangular template of C7 and 2,4-DMC5/nC6—heptane index template can be used to distinguish secondary biodegradation gas from other natural gases.