Introduction

Microbial gas is characterized by a high dryness coefficient with C1/C1–5 > 0.95 and is enriched in 12C with δ13C1 <  − 55‰, and it accounts for 8 ~ 15% of the world's gas1,2. Microbial gas includes primary and secondary ones. Primary microbial gas is a product of organic matter in immature stage (Ro ≤ 0.5%) by biochemical degradation of organic matter via acetate fermentation or CO2 reduction3,4. In general, microbial gas is generated through CO2 reduction in marine sediments, in which acetate is largely consumed by sulfate-reducing bacteria. Compared to acetate fermentation, CO2 reduction is the major pathway that forms commercial microbial gas accumulations5,6.

Secondary microbial gas is derived from degradation of oils and ethane and all higher n-alkanes7, and is generally related to tectonic uplift and has methane δ13C values < − 55‰ and the associated CO2 δ13C >  + 2.0‰. These values are shown to relate to oil biodegradation levels and proportions of reduced CO28. Milkov1 systematically summarized the geological and geochemical characteristics of secondary microbial methane: (1) associated with biodegradable crude oil; (2) C1/∑C1–C5 is higher than 95%; (3) δ13C1 <  − 55.0‰ ~  − 35.0‰; (4) δ13CCO2 >  + 2.0‰; (5) reservoir temperature is < 70 °C and occasionally up to ~ 90 °C.

The chemical and stable isotope compositions of natural gas have been used to distinguish between microbial and thermogenic gases in the subsurface2,5,9,10,11. Thermogenic gases typically have methane 13C1 values between − 55‰ and − 25‰ although early mature thermogenic gas can have methane δ13C values as light as − 73‰, and relatively high concentrations of C2+ hydrocarbons2,5. Microbial gas is dominantly composed of methane with δ13C values lighter than − 55‰ or less2,5.

Natural gas has been found from different tectonic units around Junggar basin, but the commercial natural gas distributes mainly in the eastern Luliang area in the east of the basin, and Hutubi, Manas, and Horgos anticlines in the southern margin of the basin. Natural gas in the NW Junggar basin is considered to have been thermally cracked from both types I and III kerogen and their derived oils12. The natural gas in the Mahu Sag was derived from the source rocks of the Lower Permian Fengcheng Formation with present Ro = 0.85 ~ 1.16%13,14. Microbial gas is reported to limit to Shazhang area in the eastern Junggar Basin15, based on relationships of δ13C1 and δ13C2, δ13C1 and C1/(C2+3). That is, microbial gas in the Junggar basin shows limited distribution, which is much less than a proven reserve of about 320 billion m3 in Qaidam basin with similarly abundant type III kerogen16. Interestingly, extremely negative δ13C values (− 70 to − 22‰) from high Mn calcites (average MnO = 5 wt%) have been reported from Lower Triassic Baikouquan Formation sandy conglomerates in the Mahu sag17, leading to a possibility for the oxidized methane to have been microbial18,19. In Zhongguai and Beisantai uplifts, some oils have been biodegraded, and some Fe- or Mn-rich calcite shows δ13C values of about + 22‰20, secondary microbial gases may have occurred. Thus, it is necessary to analyze gases from Mahu sag, Zhongguai and Beisantai uplifts, and other parts of the basin to determine if they are microbial and hopefully to find new microbial gas pools in these areas and provide some clues to identifying microbial gas in the basin.

Geological setting

The Junggar Basin is one of the three major superimposed petroliferous basins in western China, which is rich in oil and gas resources, covering an area of ~ 1,34,000 km2, and is bounded to the northwest by the Zhayier and Halalate Mountains, to the northeast by the Kelameili and Qinggelidi Mountains, and to the south by the Yilinheibiergen and Bogeda Mountains of the Tianshan Range21 (Fig. 1). It is an upper Paleozoic, Mesozoic, and Cenozoic superimposed basin, located at the junction of the Kazakhstan, Siberia and Tarim blocks. The basin has experienced many stages of evolution, such as the extinction and collision orogeny of the paleo Asian Ocean from the Middle Ordovician to the Early Carboniferous, the extension and fault depression from the Late Carboniferous to the early Permian, transformation of the fault depression from the middle to the Late Permian, the unification of the depression during the Mesozoic and the formation of intracontinental foreland during the Cenozoic. According to its geotectonic position, variations in basement rocks, and structural evolution, the basin can be subdivided into six structural units22 (Fig. 1).

Figure 1
figure 1

Diagram showing division of structural units in Junggar Basin and well locations for gas samples (created with CoreDRAW × 7, http://www.coreldraw.com/en/).

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In the Junggar Basin, there are several sets of source rocks, including the Carboniferous, Lower Permian Jiamuhe Formation and Jurassic high-quality type III, gas-prone source rocks; and the Lower Permian Fengcheng Formation, Middle Permian Lower Wuerhe Formation high-quality oil-prone source rocks23,24(Fig. 2). Most of the hydrocarbon accumulation in the basin were derived from the above three suites of the source rocks in terms of the source rock distribution and hydrocarbon generation history25. Three major hydrocarbon-bearing systems were formed with Carboniferous and Permian oil and gas source rocks dominating in the eastern basin, Permian oil source rocks in the central and western parts, and Jurassic gas source rocks in the south. The Carboniferous source rocks are mainly tuff mudstones, with an average TOC content of 1.2%, an average hydrocarbon generation potential (PG = S1 + S2) of 0.75 mg/g. The source rock is high maturity (vitrinite reflectance Ro > 0.9%) type III kerogen and thus was favorable for natural gas generation26. The industrial-scale source rocks are mainly located in the Dishuiquan sag on the Luliang area.

Figure 2
figure 2

The stratigraphic sequence of the Junggar Basin. The stratigraphy is based on refs.12,15,30.

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Lower Permian to Middle Permian Fengcheng Formation (P1f), Lower Wuerhe Formation (P2w), the Pingdiquan Formation (P2p) and the Lucaogou Formation (P2l) mudstones were deposited in a deep anoxic lacustrine environment and are the most important source rocks in the basin27. The P1f source rocks are mostly mature to highly mature (Ro = 0.85 ~ 1.16%) lacustrine mudstones with an average TOC of 1.38% and an average S1 + S2 of 5.6 mg /g, and a Type I ~ II kerogen28. Burial history rebuilding shows that the source rocks have experienced Ro of ≤ 2% in the depression center, indicating that the source rocks are in the stage of oil to wet gas generation. This P1f may have contributed billion-tonne oil reserves in the Mahu area29.

The Middle Permian source rocks show a significantly wider distribution than the P1f and are widely distributed in the central depression of the basin and in the eastern uplift sedimentary depressions. In the northwest margin and central part of the basin, the P2w source rocks are mainly type III kerogen, have a TOC range from 1.4% to 1.73%, S1 + S2 of 2.68 mg/g, and Ro values of 0.64% ~ 1.56%23,24, indicating that the organic matter is within the mature to high mature stage. The P2l source rocks are distributed along the south margin dominated by oil shale and black-grey mudstone, with an average TOC of 7.60%, and S1 + S2 of 34.95 mg/g. The organic matter is mainly low to mature Type II and Type I kerogen, with Ro values ranging from 0.50% to 0.91%25.

Hydrocarbon production peaks and charge have been considered to occur during T3–J2, K1, K2–E and N–Q, which correspond to the tectonic development periods T3, J3, K and N–Q28.

Materials and methods

24 gas samples produced from Carboniferous to Cretaceous were collected (Table 1), including 6 samples from the Mahu sag, 7 samples from the Wu-Xia fault, 6 samples from the Zhongguai uplift in the western Shawan sag, 2 samples from the Luliang area and 3 samples from the Beisantai uplift (Fig. 1). The Mahu sag, Wu-Xia fault and the Zhongguai uplift are in the northwest of the Junggar basin, the Luliang area is in the central and the Beisantai uplift is in the east of the basin. All gas samples were collected from the wellhead in the commercial petroleum production field, after flushing the bottles for 15–20 min to remove air contamination. Double-ended, high-grade stainless steel bottles equipped with shut-off valves were used to collect gas samples.

Table 1 Chemical composition and carbon and hydrogen isotope data of natural gas from the Junggar Basin.
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The chemical composition of the gas samples has been analyzed by a combination of mass spectrometry and gas chromatography. The analysis of C1 to C5 hydrocarbons was carried out using an Agilent 6890 N gas chromatograph equipped with a flame ionization detector. The individual gas components of hydrocarbons were separated through a capillary column (PLOT Al2O3 50 m × 0.53 mm). The GC oven temperature was initially set at 30 °C for 10 min, and then gradually increased by 10 °C/min until it reached 180 °C. After reaching this temperature, it was maintained at this level for 20–30 min. Using a Finnigan MAT-271 mass spectrometer, non-hydrocarbon gases were determined. Using the calibration curve obtained from standard gases, the concentration of each component was determined. The data of the non-hydrocarbon components obtained from the mass spectrometer and the data of the hydrocarbon gas component (C1 to C5) obtained from the gas chromatograph were normalized to obtain the final results of the complete component data.

The stable carbon isotope ratios were measured using a Trace 1310 gas chromatograph coupled with a Thermo Finnigan Delta V Advantage mass spectrometer. The GC conditions for the carbon isotope were as follows: A HP-PLOT-Q column measuring 30m × 0.53mm × 40μm was used. The carrier gas, Helium (99.999%), flowed at a rate of 3.0 ml/min. The GC oven temperature was increased from 50 °C to 200 °C at a rate of 15 °C/min and maintained at 200 °C for 20 min. We used a split injection mode with a split ratio of 6 and an injector temperature of 200 °C. The temperature of the oxidation furnace was set at 975 °C. Carbon stable isotope ratios are expressed in δ notation in permil (‰) relative to the Vienna Pee Dee Belemnite (V-PDB) standard.

Hydrogen isotopic compositions were measured using a Thermo Delta V Advantage instrument interfaced with a Trace 1310 gas chromatograph. The GC was equipped with a 50 m × 0.53 mm HP-Al2O3/KCl column coated with a 10 μm film. The helium carrier gas flowed at a rate of 3.0 ml/min. The GC oven was held constant at 45 °C for 3 min and then heated to 200 °C at a rate of 15 °C/min and held at 200 °C for 20 min. The sample was injected using split mode with a split ratio of 6 and an injector temperature of 200 °C. The cracking furnace temperature was set to 1460 °C, and the H3+ factor was tested at least once a day with a value of less than 10 ppm/nA. The analyses are reported relative to the standard mean ocean water (V-SMOW) standard.

Results

Chemical composition of the gas

All the gases analyzed are dominated by hydrocarbon gas with contents from 81.07% to 98.96% and non-hydrocarbon gas including N2 and CO2 with contents from 0.23% to 11.50% and 0.08 to 4.04%, respectively (Table 1). The gases from the Mahu sag have dryness coefficients (C1/∑C1 − C5) from 0.86 to 0.98, N2 and CO2 contents from 0.70% to 9.09% and 0.09 to 1.06%, respectively. The gases from the Wu-Xia fault have dryness coefficients from 0.72 to 0.94, N2 and CO2 contents from 0.23% to 11.50% and 0.16 to 4.04%, respectively. The gases from the Zhongguai uplift have dryness coefficients from 0.93 to 1, N2 and CO2 contents from 0.24% to 5.03% and 0 to 0.27%, respectively. The dryness of gas in the Luliang area and Beisantai uplift is higher, from 0.96 to 1 and 0.98 to 0.99 respectively. Among different regions of the study area, the dryness coefficients decrease from the Beisantai uplift (average 0.98) to the Luliang area (average 0.98), the Zhongguai uplift (average 0.97), the Mahu sag (average 0.91), and the Wu-Xia fault (average 0.84).

Isotopic composition of the gases

The gas samples of the Junggar basin show a wide variation of the stable carbon and hydrogen isotopic compositions. The δ13C values of methane, ethane, propane, and butane in the Mahu sag range between − 46.8‰ and − 41.1‰, between − 32.5‰ and − 30.7‰, between − 31.9‰ and − 28.6‰, and between − 28.7‰ and − 27.7‰, respectively. The carbon dioxide from the Mahu sag shows δ13C values ranging from − 20.3‰ to − 23.7‰ (Table 1), with an average of − 21.6‰. The gases have methane δ2H values from − 169.7‰ to − 151.2‰, with an average of − 160.4‰. The δ13C values of methane, ethane, propane, and butane in the Zhongguai uplift range between − 56.0‰ and − 39.6‰, between − 31.9‰ and − 25.8‰, between − 30.7‰ and − 24.4‰, and between − 29.7‰ and − 26.8‰, respectively. The δ13C values of methane, ethane, propane, and butane in the Wu-Xia fault range between − 54.4‰ and − 41.4‰, between − 40.9‰ and − 25.1‰, between − 37.7‰ and − 22.0‰, and between − 36.8‰ and − 24.3‰, respectively. As for the Luliang area, the δ13C values of methane, ethane, propane, and butane range between − 54.8‰ and − 50.1‰, between − 28.0‰ and − 24.5‰ respectively. Gas samples from the Beisantan uplift have δ13C values of methane, and ethane range between − 50.7‰ and − 49.8‰, between − 31.4‰ and − 28.4‰ respectively. The δ13C value of methane in the Junggar Basin is the lightest in the Luliang area (average − 52.5‰), followed by the Wu-Xia fault (average − 51.0‰), Beisantai uplift (average − 50.6‰), Zhongguai uplift (average − 45.3‰), and heaviest in the Mahu sag (average − 43.3‰).

Discussion

Evidence of microbial gas

The carbon isotope composition of natural gas can be used to indicate the origin, type, and maturity of the gas. δ13C1 value in combination with the ratio “C1/(C2 + C3)” of gas compositions is widely used to identify the origin of the gases (especially of methane) and the possible processes of gas generation5,31. The Junggar Basin gases are plotted mainly within the area of “thermogenic gases” with four samples within the microbial gas area (Fig. 3). The gases from Triassic reservoirs of the Mahu sag have C1/(C2 + C3) ratios from 9.06 to 66.74, and δ13C1 values from − 46.8‰ to − 41.1‰, most of which are indistinguishable from other “thermogenic gases” with only the highest C1/(C2 + C3) ratio outside the range. A thermogenic origin for the gases is supported by the plot of the C2/C3 ratio vs the differences in δ13C2 − δ13C3 (Fig. 4), which shows ethane and propane of the gases were derived mainly from the primary cracking of kerogen with part from oil cracking at Ro < 1.1%. However, it cannot be ruled out for some of the “thermogenic gases” to have mixed with microbial methane as indicated by methane δ13C1 and δ2H1 plot which shows the samples plot on the area representing an overlap between microbial gases and thermogenic gases32 (Fig. 5). The “natural gas plot”, a plot of the inverse carbon number (1/n) of the C1–C4 components (the x-axis) against isotope ratio values of each component (the y-axis), showed that primary, unaltered gas, derived from a single source plot along a straight line33. Thus, the “natural gas plot” can be distinguished a single-source thermogenic gas from a mixed source. When we plot the data analyzed in this and previous data30 from the Junggar Basin on the diagram, some of the gases have ethane, propane, and butane plotting along straight lines in the Mahu sag, Wu-Xia fault and Luliang area (Fig. 6). However, the methane was plotted below the lines showing significantly lighter δ13C values. This result suggests that the methane was not co-generated with C2–C4 fraction and may have mixed with 13C-poor methane with δ13C from − 54.8‰ to − 41.4‰, which is most likely to be microbial although an origin of early mature thermogenic gas cannot be ruled out5.

Figure 3
figure 3

Plot of C1/(C2 + C3) versus δ13C1 on the genetic diagram of /(from ref.2). CR: CO2 reduction; F: fermentation; SM: secondary microbial; EMT: early mature thermogenic gas; OA: oil associated thermogenic gas; LMT: late mature thermogenic gas. Data are from this study, refs.12,17,26,30.

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Figure 4
figure 4

Plot of δ13C2 -δ13C3 versus C2/C3 on (from ref.34) with data from this study and refs.12,17,26,30.

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Figure 5
figure 5

Plot Mahu sag gases on the diagram of δ13C1 versus δ2H1 to identify the genetic type (ref.2). CR: CO2 reduction; F: fermentation; SM: secondary microbial. Some data are from ref.26.

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Figure 6
figure 6

Diagrams of 1/Cn versus δ13C for gas in Junggar basin. Some data of the Luliang area are from ref.30.

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The C2–C4 isotope data are extrapolated to the y-axis to predict the δ13C of the thermogenic methane endmember. The difference between the predicted δ13C of thermogenic methane and measured δ13C is due to microbial inputs. According to Chung's gas plot model, we can judge whether microbial or early mature gas mixed with thermogenic gas by calculating the difference between the carbon isotope value of methane in pure thermogenic gas (δ13C1, t) and that of natural methane measured (δ13C1, m)35. The specific calculation methods are as follows where K is the slope of the C2 − C3 straight line on the natural gas plot:

$${\text{K}} = \left( {\delta^{{{13}}} {\text{C}}_{{3}} - \delta^{{{13}}} {\text{C}}_{{2}} } \right)/\left( {0.{33} - 0.{5}0} \right)$$
(1)
$$\delta ^{{13}} {\text{C}}_{{1,{\text{ t}}}} = {\text{K}}/2 + \delta ^{{13}} {\text{C}}_{2}$$
(2)
$$\Delta \delta ^{{13}} {\text{C}}_{{{\text{C1}},{\text{ t}} - {\text{C1}},{\text{m}}}} = \delta ^{{13}} {\text{C}}_{{1,{\text{ t}}}} - \delta ^{{13}} {\text{C}}_{{1,{\text{ m}}}}$$
(3)

Besides, we find that the natural gas of Junggar Basin has a positive relationship between Δδ13CC1, t−C1, m and Δδ13C2−1 (Fig. 7 and Supplementary Table S1), indicating that the contribution of more 13C-depleted methane to thermogenic gases leads to increase in both the differences. This line of evidence reflects the mixing of gases with 13C-depleted methane.

Figure 7
figure 7

Positive relationship between Δδ13CC1, t‒C1, m and Δδ13C2-1 of natural gas in Junggar Basin with data from this study and refs.12,17,26,30.

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However, recent investigations show that not all the natural gases from a single source are plot along a straight line on Chung’s plot, and some thermogenic gases may show dogleg distribution in C1 to C4 due to inhomogeneous organic matter components of source rock kerogen2,35,36,37,38,39. Thus, other lines of evidence should be present to indicate that at least part of the “thermogenic gases” in Fig. 3 may have mixed with primary or secondary microbial gases.

Primary microbial gases may have occurred in the Mahu sag. CO2/(C1–5 + CO2) ratio from the Mahu sag T1b gases shows decrease with δ13C119. The line of evidence has been considered as the oxidation of methane to CO2 in closed systems prior to C2-5 charge19. This is because methane is the least reactive among saturated hydrocarbons40, and thus C2+ alkanes are expected to be oxidized preferentially over methane and leave methane intact. On the other hand, as the result of kinetic fractionation, 12C-rich methane is preferentially oxidized to 12C-rich CO2, and when more methane is oxidized, both residual methane and newly generated CO2 are expected to be heavier. This newly generated CO2 may have precipitated as early calcite cement with δ13C values from − 31‰ to − 70‰18,19. The oxidation of methane in closed systems are indicated by the positive relationship between MnO content in calcite and the δ13C1 value of the associated methane19. Thus, it can be concluded that the pre-oxidized methane must have δ13C1 heavier than that of the most 13C-depleted Mn-bearing calcite (− 70‰) but lighter than that of the present residual methane (− 48‰). Although thermochemical oxidation of methane have been shown to have fractionation of 16–19‰ based on extrapolation of experimental results at 400–500 °C to 90–135 °C17 and a case-study on thermochemical sulfate reduction by methane41, microbial oxidation of methane shows a wide fractionation factor between 4 and 30 based upon aerobic culture experiments and model calculation using field data5,42. Thus, it is hard to determine the δ13C1 value of pre-oxidized methane. The present δ13CCO2 values can be used to differentiate primary from secondary microbial gas, and range from − 29.4‰ to − 20.1‰ in the Mahu sag (Fig. 8). The CO2 may be the mixtures among previously existing inorganic CO2, methane-derived CO2 gas and later charged thermogenetic CO2 along with alkanes. Considering that the calcites have more negative δ13C values than the associated CO2 and a carbon isotope fractionation of < 5‰ during precipitated CaCO3 from the original gaseous CO243. The methane-derived CO2 should have δ13C values lighter than the measurement values, which are much lighter than those of secondary microbial gas (> + 2‰). The three aspects of evidence, including, δ13C1 values of the pre-oxidized methane from − 70‰ to − 48‰, oxidization of only methane in the Mahu sag17 and significantly lighter CO2 δ13C values than the threshold of >  + 2‰ for secondary microbial gas, suggest that the early charged gas must be primary microbial gas. This is supported by the absence of biodegradation of the oils in the association with the gases17, one C1/(C2 + C3) ratio higher than the maximum value of the expected thermogenic gases and a trend showing mixing with primary microbial gases (Fig. 9).

Figure 8
figure 8

Genetic diagram of δ13C CO2 versus δ13C1 (from ref.2). CR: CO2 reduction; F: fermentation; SM: secondary microbial; EMT: early mature thermogenic gas; OA: oil associated thermogenic gas; LMT: late mature thermogenic gas. Some data are from ref.26.

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Figure 9
figure 9

Genetic diagram of C1 /(C2 + C3) versus δ13CCO2 (from ref.1). Some data are from ref.26.

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By contrast, secondary microbial gases are considered to be generated through the following reactions44,45:

$${\text{C}}_{{{16}}} {\text{H}}_{{{34}}} + {\text{16H}}_{{2}} {\text{O}} \to {\text{8CH}}_{{3}} {\text{COO}}^{ - } + {\text{8H}}^{ + } + {\text{17H}}_{{2}}$$
$${\text{CH}}_{{3}} {\text{COO}}^{ - } + {\text{H}}^{ + } + {\text{2H}}_{{2}} {\text{O}} \to {\text{2CO}}_{{2}} + {\text{4H}}_{{2}}$$
$${\text{CO}}_{{2}} + {\text{4H}}_{{2}} \to {\text{CH}}_{{4}} + {\text{2H}}_{{2}} {\text{O}}$$
$${\text{Net reaction}}:{\text{ 4C}}_{{{16}}} {\text{H}}_{{{34}}} + {3}0{\text{H}}_{{2}} {\text{O}} \to {\text{49CH}}_{{4}} + {\text{15 CO}}_{{2}}$$

Secondary microbial gases have been shown in the association with 13C enriched CO2 and HCO3− up to + 32.7‰ and + 26‰, respectively, in San Juan basin45,46,47,48. Pallasser47 and Milkov1 found that most of the secondary microbial gases have C1/C1-5 > 98%, Δδ13C2-1 > 10‰ and δ13CCO2 >  + 2‰.

Secondary microbial gas may have occurred in the Luliang area, Wu-Xia fault, Beisantai and Zhongguai uplifts. Oil biodegradation is indicated by strong depletion in n-alkanes, the occurrence of unresolved complex mixture (UCM), and a series of C25-norhopanes from the crude oil in the Permian sandstones from wells K76 in Zhongguai uplift, B47, T49 and DQ-3 in Beisantai uplift and the surrounding (Fig. 10)20,49,50,51. Similar to secondary microbial gases in Australian basins47, propane was selectively degraded resulting in a positive shift in its δ13C value for some gases from Zhongguai uplift and Luliang and Wu-Xia areas as shown in Chung’s plot with propane plot above the straight lines (Fig. 6b–d). Anoxic degradation of the oils and propane is expected to produce extremely 13C-depleted methane in association with 13C enriched CO2 as the result of carbon isotope fractionation49,52,53, thus ferroan calcites from the Permian Wutonggou Formation sandstones from well B-69 in the Beisantai uplift have δ13C values of + 22.10‰ to + 22.16‰20.

Figure 10
figure 10

Biomarker chromatograms of, (a) a produced oil in the Zhongguai uplift (from ref.14), and (b) and (c) oils extracted from sandstone reservoir in the Beisantai uplift with data from ref.54, showing abundant C25-norhopanes from biodegraded oils.

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Primary microbial gas generation and accumulation in the Mahu sag

The source and charge history of the microbial gas are puzzled. Microbial methane is generally accepted to generate from type III kerogen at vitrinite reflectance Ro < 0.5%. The microbial gas may have charged earlier than thermogenic gas and oil. This proposal is supported by the following two aspects: (1) microbial gas is generated at low temperatures favorable for microorganisms to grow; (2) a calcite with δ13C of − 30.6‰ was precipitated at the temperature of 59 °C19. That means that the microbial gas was charged at < 59 °C when the reservoirs were buried to < 1300m prior to the late Triassic prior to its oxidation to extremely 12C-rich calcite based on burial and thermal history rebuilding55. Thus, the primary microbial gases in the Mahu sag are most likely from the P2w coal-bearing source rock. The source rock was deposited under sulfate-poor freshwater to brackish lacustrine environment with mudstone and shale Sr/Ba ratios from 0.36 to 0.5756, and are thus favorable for methanogenesis in the Lower Wuerhe Formation to generate primary microbial gas57,58,59, followed by its up-migration and accumulation in the overlying Lower Triassic reservoirs. The methanogenesis may have occurred prior to the late Triassic when the Lower Wuerhe Formation has organic matter maturity < 0.5% and the underlying Lower Permian Fengcheng Formation, the main source rock for the petroleum in the Mahu sag12 experienced temperatures < 70 °C and thus no significant oil and gas has been generated55.

Secondary microbial gas generation in the Zhongguai and Beisantai Uplifts

From the Late Triassic to Early Jurassic, the P1j and P1f source rocks in the Shawan sag reached thermal maturation stage60, from which oil and the associated gas generated were then migrated to structural highs and accumulated in the Zhongguai uplift. Oil and the associated gas in Triassic and Middle and Lower Jurassic reservoirs in the Beisantai uplift were generated from the Permian Pingdiquan Formation (P2p) in the Fukang sag during the Middle and Late Jurassic periods20. The oils in both Zhongguai and Beisantai uplifts were sterilized at temperatures higher than around 80–90 °C during deep burial, killing the organisms needed for oil biodegradation to occur61. Subsequently, the reservoirs were uplifted significantly to depths with temperatures < 80 °C during the Late Jurassic, followed by the influx of freshwater with bacteria, resulting in biodegradation of oils (Fig. 11) and thus the present oils produced and extracted from sandstones show large unrecognized complex compounds (UCM) and abundant 25-norhopanes (Fig. 10). Biodegradation of oils and propane generated 13C-rich CO2 and Fe- and Mn-rich calcites and 12C-depleted methane-dominated secondary microbial gases in the areas.

Figure 11
figure 11

Schematic diagram of the oil and gas accumulation processes in the Zhongguai uplift. The ___location of the cross-section is shown in Fig. 1.

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Conclusions

The microbial gas can be concluded to occur from the Carboniferous to the Jurassic in Mahu sag, Zhongguai and Beisantai uplifts. The primary microbial gas in Mahu sag may have generated from the P2w, type III organic matter with vitrinite reflectance Ro < 0.5% prior to Late Triassic, and were partially oxidized to calcite with extremely negative carbon isotopic composition and partially mixed with later charged thermogenic gas. Secondary microbial gases from the Zhongguai and Beisantai uplifts were formed from biodegradation of oils and gases from the P1j and P1f source rocks which generated abundant 25-norhopanes and 13C-rich CO2 precipitating as calcite. The study provides a new case showing how to identify microbial gas in a basin and has implication for microbial gas exploration in the Junggar basin.