Geneses, Sources and Accumulation Process of Natural Gases in the Hinterland of the Junggar Basin

The Junggar Basin is rich in natural gas resources, but it has hardly been explored, with the proven rate being less than 9.0%. Although the hinterland of the Junggar Basin has a favorable condition for natural gas accumulation, the complex gas sources cause great trouble in the selection of zones and belts for exploration. Based on the molecular composition and stable carbon and hydrogen isotope data of 95 natural gas samples from 72 wells in this area, combined with the characteristics of structural evolution history, burial history, hydrocarbon generation and expulsion history, and fluid inclusions, this paper clarified the geneses and sources of natural gas, identified the secondary alteration of natural gas, and restored the process of natural gas accumulation. Natural gas in the hinterland was divided into four types: Type I was oil-type gas from the Lower Permian Fengcheng Formation; Type II was coal-type gas derived from the Carboniferous source rock; Type III was the mixture of Type I and II gases, which constituted the major fraction of natural gases in the hinterland; and Type IV that referred to secondary microbial gas formed by the biodegradation of crude oil. During the Late Cretaceous, the Carboniferous and Fengcheng source rocks entered the gas generation peak and a series of natural gas reservoirs were formed. However, affected by the later tectonic movements, some gas reservoirs were damaged or adjusted, and natural gas leakage and biodegradation occurred. This study has shifted the focus of natural gas exploration in the study area from the petroleum system associated with the Middle Permian source rocks to that with the Lower Permian and Carboniferous source rocks, which is of great significance for natural gas exploration in the Junggar Basin. Further, it provides an example to identify the geneses and sources of natural gas under complex conditions based on integrated geological and geochemical assessments.

1 Introduction

The Junggar Basin, a late Paleozoic–Cenozoic superimposed basin, is located in the north of Xinjiang Uyghur Autonomous Region in northwest China (Figure 1A), covering an area of about 130 × 10³ km² (He et al., 2018; Cao et al., 2020; Xia et al., 2021). In 2017, the proven oil reserves and the annual oil production in the basin reached 33.6 × 10⁸ and 12.88 × 10⁶ t (Hu S. Y. et al., 2020; Zhi et al., 2021), respectively, making the Junggar Basin one of the most important oil production bases in China. In contrast, the proven natural gas reserves in the basin are only 209.25 × 109 m³, which comes to less than 9% (Hu S. Y. et al., 2020).

FIGURE 1

FIGURE 1. Geological background in the hinterland of Junggar Basin. (A) Location of the Junggar Basin in China; (B) Characteristics of tectonic units in Junggar Basin; (C) Distribution of natural gas of different origins in the hinterland of Junggar Basin.

At present, gas reservoirs in the Junggar Basin are mainly in the east (e.g., Kelameili and Wucaiwan gas fields), in the southern edge (e.g., Mahe and Hutubi gas fields), and in the northwestern edge (e.g., 561, 581, Ke 84, Jinlong 4 and Zhongjia 2 gas reservoirs) (Wang et al., 2013; Chen et al., 2014, Dai et al., 2016; Sun et al., 2016; Tao et al., 2016; Gong et al., 2018; Chen et al., 2019). The gas-producing reservoirs in the eastern region are mainly volcanic rocks characterized by strong heterogeneity and poor physical properties (Dai et al., 2016; Gong et al., 2019a, Gong et al., 2019b; Gong et al., 2021). The thermal evolution degree of source rocks in the northwestern region is relatively low, resulting in limited distribution range of gas sources kitchen (Chen et al., 2014; Tao et al., 2016). The southern edge has a complex structure, large reservoir burial depth, poor surface conditions, and increased development difficulty (Dai et al., 2016; Chen et al., 2019; Hu S. Y. et al., 2020). Such problems have hindered profitable exploration and development of natural gas in the Junggar Basin. Since 2007, the annual natural gas production in the Junggar Basin has been hovering at 2 × 109 m³–3 × 109 m³.

The total area of the hinterland is about 36 × 10³ km². It is adjacent to the Pengyijingxi Sag in the west and Dishuiquan Sag in the east (Figures 1B,C). Four sets of source rocks developed in the study area, the Middle–Lower Jurassic Formation (J_1–2), Middle Permian Xiawuerhe Formation (P₂w), Lower Permian Fengcheng Formation (P₁f), and Carboniferous Formation (C), promising a favorable hydrocarbon source condition (Figure 2) (Cao et al., 2012; Wang et al., 2013). The gas layers are shallow (generally <4,000 m) and have conducive physical properties (Liu G et al., 2019) for rapidly building the production capacity. Thus, exploration and development of natural gas in the study area can have tremendous economic benefits. Although several gas-producing wells were drilled in this area (Figure 1C) (Cao et al., 2012), no significant reserves have been found yet. In 2019, Well QS2 drilled in the Qianshao Salient (Figure 1C) obtained high-yield industrial oil and gas flow in the Lower Jurassic Sangonghe Formation (J₁s), with a daily gas and oil production of 203.6 × 103 m³ and 39.3 t, respectively. In 2020, 6.5 × 109 m³ of proven geological reserves of natural gas were confirmed, shedding light on great potential for gas exploration in this area.

FIGURE 2

FIGURE 2. Stratigraphic column in the hinterland of Junggar Basin.

There are two main viewpoints on the geneses and sources of the natural gas in the hinterland: one proposed the gases were mainly derived from the J_1–2 coaly source rock (Dai et al., 2009; Li et al., 2009), and the other argued that gases were derived from the P₂w lacustrine source rock (Cao et al., 2012; Sun et al., 2012; Gong et al., 2018). More significant disputes regarding the gas sources of different reservoirs also exist (Song, 1996; Wu et al., 2003; Liao et al., 2004; Li et al., 2011; Sun et al., 2012; Lu et al., 2014). There are several reasons for this diversity of perceptions. 1) Because the organic matter of the source rocks in J_1–2, P₂w, and Carboniferous are all humic types (Cao et al., 2012; Wang et al., 2013; Dai et al., 2016), the geochemical characteristics of the generated natural gas are difficult to distinguish. 2) The superimposition of the multiple sets of source rocks makes natural gas more likely to mix. 3) Because the Cenozoic, the Junggar Basin has tilted southward, resulting in the adjustment or destruction of early formed petroleum reservoirs (Xiang et al., 2015; Liu G et al., 2019). In addition, natural gas may suffer secondary alteration, which further increases the difficulty of gas source identification.

In addition to the three sets of humic source rocks, P₁f sapropelic lacustrine source rock was also developed in the study area (Wang et al., 2013; Cao et al., 2020). In the past, it was mainly considered as a set of oil source rocks (Cao et al., 2020; Xia et al., 2021). Recently, highly mature oil-type gas derived from the P₁f source rock was found in the southwest of the basin (Zhi et al., 2021). However, there is no systematic study on the gas generation potential of P₁f source rocks in the hinterland of the basin.

Given these problems, we systematically analyzed the molecular composition and stable carbon (δ¹³C) and hydrogen (δ²H) isotope ratios of 95 natural gas samples in the hinterland of the Junggar Basin. It clarifies the geneses, sources, and secondary alteration of the natural gas. The natural gas accumulation process is rebuilt with the structural evolution history, burial history, hydrocarbon generation and expulsion history, and fluid inclusion characteristics in the study area. The research results are of great significance for natural gas exploration in the Junggar Basin and provide an example to identify the geneses and sources of natural gas under complex conditions based on integrated geological and geochemical information.

2 Geological Setting

Located at the junction of three paleo-plates (i.e., Siberia, Tarim, and Kazakhstan), the Junggar Basin is composed of the Junggar massif and its surrounding fold belts (He et al., 2018). The basin is approximately rhombic on the plane, with the Qinggelidi Mountains and Kelameili Mountains in the northeast, the Zhayier Mountains, Halaalate Mountains, and Delun Mountains in the northwest, and the Yilingheibiergen Mountains and Bogeda Mountains in the south (Figure 1B). Based on the Permian paleo-structures, the Junggar Basin can be roughly divided into six first-order tectonic units (i.e., Central Depression, Wulungu Depression, Luliang Uplift, West Uplift, East Uplift, and Northern Tianshan thrust belt), and can be further subdivided into 44 secondary tectonic units (Figure 1B) (Gong et al., 2019a; Zhi et al., 2021). The study area is mainly located in the Luliang Uplift and the Central Depression (Figures 1B,C).

After the Hercynian (∼268 Ma) tectonic movement, the Junggar Basin formed large uplifts and depressions dominated by NW- and NWW-striking directions under regional SN compression and collision (Hu et al., 2006; Qi et al., 2010). The study area began to take shape at this time. During the Yanshanian period (∼200 Ma), large-scale uplifting occurred in the study area, and the J_1–2 strata were denuded (Yang et al., 2002). Since then, the basin entered a stable depositional period during which the early-formed structures were better preserved (Li et al., 2002; Hu et al., 2006). During the Himalayan period (∼23 Ma), the basin’s southern part subsided sharply (Liu Q et al., 2019). The structural amplitude in the study area gradually decreased with the high point moving northward. Only a series of low-amplitude bulges were retained (Qi et al., 2010; Cao et al., 2012) (Figure 1C).

The discovered natural gas in the study area is mainly distributed in the Sangequan, Xiayan, Shixi, Mobei, and Mosuowan Salients (Figure 1C). Gas producing zones are mainly in the Jurassic and Cretaceous sandstone reservoirs and Carboniferous volcanic reservoirs (Figure 2; Table 1). Four significant sets of reservoir–seal assemblages were developed in the study area: 1) the reservoir–seal assemblage with the Carboniferous volcanic weathering crust as reservoir and the Lower Permian mudstone as seal, 2) the reservoir–seal assemblage with glutenite in the Middle Permian Xiazijie Formation (P₂x) as a reservoir and the P₂w mudstone as seal, 3) the reservoir–seal assemblage with glutenite of the Lower Triassic Baikouquan Formation (T₁b) and Karamay Formation (T₂k) as reservoirs, and the mudstone of the Upper Triassic Baijiantan Formation (T₃b) as seal, and 4) the reservoir–seal assemblage composed of interbedded sandstone and mudstone in the Jurassic and Cretaceous strata (Figure 2) (Cao et al., 2012; Liu Q et al., 2019).

TABLE 1

TABLE 1. Molecular and stable carbon isotopes of natural gases in the central Junggar Basin.

3 Sample and Methods

3.1 Sampling

Ninety-five natural gas samples were collected from 72 wells in the hinterland of the Junggar Basin, of which 55 samples were newly collected, and the rest were from the previous researches (Li et al., 2009; Cao et al., 2012; Sun et al., 2012). The planar distribution positions and analysis results are shown in Figure 1C and Table 1. In addition, this study also conducted geochemical analysis of 437 source rock samples from 129 wells in the basin and on crude oil samples associated with natural gas.

3.2 Analytical Processes

3.2.1 Geochemical Analysis of Natural Gas

The geochemical analysis of the natural gas was conducted at the Experimental and Testing Institute of PetroChina Xinjiang Oilfield Company and Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences. A Hewlett Packard 6890 II gas chromatograph (GC) was used for the analysis of the natural gas components. The hydrocarbon gas component was separated with capillary columns (Plot Al₂O₃ 50 m × 0.53 mm). The furnace temperature of the GC was first set to be 30°C and held for 10 min. Then the temperature was ramped up to 180°C at a rate of 10°C/min. Stable carbon isotope analysis of alkane gas (C₁–C₄) was conducted with a Finnigan Mat Delta S mass spectrometer interfaced with an HP 6890II gas chromatograph. The alkane gas components (C₁–C₃) and CO₂ were separated by using a chromatographic column (Plot Q 30 m × 0.32 mm). The column heating process was as follows: the heating rate was 8°C/min at temperatures of 35–80°C; the temperature was then increased to 260°C at a heating rate of 5°C/min. The final temperature was held for 10 min. Each sample was analyzed three times with an accuracy of ±0.3‰ (VPDB).

The hydrogen isotopic compositions of natural gas were determined on a MAT253 isotopic mass spectrometer (Thermo Fisher Scientific) equipped with a Trace GC Ultra™ using the gas chromatography pyrolysis interface and the water removing device. Helium was used as the carrier gas and a 30 m × 0.32 mm × 20 µm HP–PLOT Q column was used with flow rate of 1.4 ml/min. The inlet temperature was set at 180°C. A split injection mode (split ratio 1:7) was used for the methane hydrogen isotope measurement and a splitless injection mode for the ethane and propane hydrogen isotopes. The initial temperature was 40°C and held for 5 min, then heated from 40 to 80°C at 5°C/min, from 80 to 140°C at 10°C/min and from 140 to 260°C at 30°C/min, respectively. The temperature of the pyrolysis oven was 1,450°C, and gaseous hydrocarbon components were transformed into C and H₂. The H₂ went into mass spectrometer to be measured. The δ²H was calculated relative to VSMOW. The reproducibility and precision of hydrogen isotope value are less than ±3‰.

3.2.2 Geochemical Analysis of Oil

The GC analysis of oils was performed in an Agilent 7890A gas chromatograph fitted with a 60 m × 0.25 mm × 0.25 µm capillary column with nitrogen (99.999%) as the carrier gas. The GC oven temperature was initially held at 40°C for 10 min, then ramped from 40 to 70°C at 4°C/min and to 300°C at 8°C/min, and finally held at 300°C for 40 min.

The GC–MS analysis was performed in an Agilent 7890–5975C with the same column type as used in the GC analysis, but with helium (99.999%) as the carrier gas. During the GC–MS analysis, the GC oven temperature was initially held at 50°C for 1 min, then ramped to 120°C at 20°C/min, from 120 to 250°C at 4°C/min, and from 250 to 310°C at 3°C/min. Finally, it was held at 310°C for 30 min.

3.2.3 Basin Modelling

The burial and thermal histories of the source rocks in the study area were reconstructed using PetroMod software. The current heat flow and thermal conductivity values of the source rocks were adopted from previous studies (Wang et al., 2000a, Wang et al., 2000b; Qiu et al., 2000; Qiu et al., 2001; Qin, 2002). The vitrinite reflectance (Ro) values were calculated with the Easy%Ro model proposed by Sweeney and Burnham (1990). This model was proved to be applicable for a Ro range of 0.3%–4.6%.

3.2.4 Total Organic Carbon and Rock–Eval Analysis

The analyses were carried out at the China University of Petroleum (Beijing). The 146 rock samples were crushed to powder for total organic carbon (TOC) analysis (Table 1). The powdered samples were split into 200-mg sub-samples and treated with HCl at 60°C to remove the carbonates, then washed with distilled water to remove the HCl. The washed sub-samples were dried overnight at 50°C, and their carbon contents were determined using a LECO CS–230 analyzer.

For rock–eval pyrolysis, 100 g of each crushed rock sample was placed in the vessel of an OGE-II instrument. These samples were heated from 300 to 600°C in a helium atmosphere at a heating rate of 50°C/min, and their Rock–Eval parameters (S₁, S₂, and T_max) were measured. Here S₁ is the amount of free hydrocarbon that can be volatilized from the rock sample (mg HC/g rock), and S₂ is the amount of hydrocarbon produced by the cracking of organic matter (mg HC/g rock). T_max (^oC) is the temperature at which the S₂ yield is maximized, which roughly estimates the thermal maturity of the sediment (Peters, 1986).

4 Results

4.1 Molecular Compositions of the Natural Gas

The alkane content of the natural gas was relatively concentrated, ranging from 72.87% to 99.01% (95.30% on average) (Table 1), the majority of which was within 90%–100% (Table 1). The methane content varied significantly from 36.89% to 95.89% (87.16% on average), with its primary span being 80%–100%. Except for samples SD10 and LN6 (K₁q), whose methane content was only 36.89% and 44.99%, respectively, most samples had methane content higher than 70% (Table 1). The contents of heavy hydrocarbon (C_2–4) gas components in natural gas were 0.12%–42.66% (averaging 8.14%), and the dominant frequency was distributed between 0% and 20%. The samples with C_2–4 gas contents were mainly distributed in the Shidong and Lunan Salients and sporadically distributed in the Mosuowan and Shixi Salients (Table 1). Natural gas’s drying coefficient (C₁/∑C_1–4) was 0.51–1.00 (0.91 on average) with a primary interval of 0.85–0.95. Dry gas (C₁/∑C_1–4 > 0.95) and wet gas (C₁/∑C_1–4 < 0.95) constituted 15.4% and 84.6% of the total data, respectively (Table 1).

The contents of non-hydrocarbon gases varied from 0.46% to 19.38% (averaging 3.45%) (Table 1). 78.9% of the samples have non-hydrocarbon gas contents less than 5% (Table 1). Except for SD10, whose nitrogen content reached 19.20%, most samples had a nitrogen content of 0%–5% (3.00% on average) (Table 1). Carbon dioxide content was mainly between 0 and 1% (0.47% on average) (Table 1).

4.2 Stable Carbon Isotopic Composition of Natural Gas

Stable carbon isotopic compositions of methane (δ¹³C-CH₄) varied broadly (from –54.8‰ to –31.8‰, –37.7‰ on average) with a primary interval of –45.0‰ to –30‰ (Table 1). Among them, the relatively ¹³C-depleted samples (δ¹³C-CH₄ < –45‰) were mainly distributed in the Luliang oil and gas field, while the relatively ¹³C-enriched samples were mainly in the Lunan, Shidong, and Monan Salients (Figure 1C; Table 1). Stable carbon isotopic compositions of ethane (δ¹³C-C₂H₆) ranged from –32.4‰ to –24.2‰ (–27.1‰ on average) with the dominant interval between –28‰ and –24.0‰. Among them, 78.9% of the samples have δ¹³C-C₂H₆ ratios more than –28.0‰, and the samples with δ¹³C-C₂H₆ < –28.0‰ are mainly distributed in the Mobei and Mosuowan Salients (Figure 1C; Table 1). Stable carbon isotopic compositions of propane (δ¹³C-C₃H₈) varied from –30.1‰ to –14.8‰ (–25.6‰ on average), and their dominant frequency was between –28.0‰ and –24.0‰. Four samples (i.e., L9, SN30, L113, and L151) have the most ¹³C-enriched δ¹³C-C₃H₈ ratios (–14.8‰, –16.4‰, –17.8‰ and –17.9‰, respectively), presenting an apparent difference from the other samples (Figure 1C; Table 1).

Generally, the natural gas samples in the study area showed a distribution pattern of δ¹³C-CH₄ < δ¹³C-C₂H₆ < δ¹³C-C₃H₈ (Figure 3; Table 1). The reversals between δ¹³C-C₂H₆ and δ¹³C-C₃H₈ ratios were only observed in L102, P8, and M21 (Figure 3; Table 1). Some samples have reversed carbon isotopic composition of propane and butane. Except for SN30, which had the maximum the Δδ¹³C-(C₄H₁₀ – C₃H₈) ratio (9.6‰), most of other samples have ratios less than 1.0‰ (Figure 3; Table 1).

FIGURE 3

FIGURE 3. The δ¹³C distribution pattern of natural gas in the hinterland of Junggar Basin.

5 Discussion

5.1 Geneses of the Natural Gas

The δ¹³C ratios are the most common and practical tools to distinguish the genetic types of natural gas (Liu G. et al., 2019). Based on the δ¹³C data of thousands of natural gas samples from major petroliferous basins around the world, (Dai et al., 1992, Dai et al., 2014) proposed a δ¹³C-CH₄–δ¹³C-C₂H₆–δ¹³C-C₃H₈ genetic identification chart for natural gas. The natural gas in the study area can be divided into four types in the chart. Type I gas generally has relatively ¹³C-depleted δ¹³C ratios, with average δ¹³C-CH₄, δ¹³C-C₂H₆ and δ¹³C-C₃H₈ values being –42.6‰, –29.5‰ and –27.5‰, respectively, falling within the domain of oil-type gas (Figure 4; Table 1). Type II and Type III gases generally had relatively ¹³C-enriched δ¹³C ratios, both falling in the domain of coal-type gas (Figure 4; Table 1). Although Type II and Type III gas had similar δ¹³C ratios, they could still be distinguished from their δ¹³C-CH₄ ratios. The δ¹³C-CH₄ ratios of Type II gas were between –34.1‰ and –31.8‰, while those of Type III were between –39.0‰ and –34.0‰ (Figure 4; Table 1). The average value of the former was 3.4‰ more than that of the latter. Because the C₁/∑C_1–4 ratios of these two types of natural gases were similar (mainly 0.90–0.95) (Table 1), their δ¹³C-CH₄ difference was primarily affected by their distinct geneses, rather than the difference in maturities. The distribution position of Type IV gas in Figure 4 was different from the other types of natural gases. Type IV gas had the most ¹³C-depleted δ¹³C-CH₄ value, and most of them were within the range of low mature oil-type gas (Figure 4). However, its C₁/∑C_1–4 ratios were very high (0.97 on average, Table 1), significantly different from thermogenic gas, reflecting possible secondary alteration.

FIGURE 4

FIGURE 4. Using the δ¹³C-CH₄–δ¹³C-C₂H₆–δ¹³C-C₃H₈ diagram to identify the genesis of natural gas in the hinterland of Junggar Basin (diagram modified after Dai et al., 1992, Dai et al., 2014).

5.2 Sources of Natural Gas

5.2.1 Type I Gas

Four sets of source rocks were developed in the study area (i.e., J_1–2, P₂w, P₁f, and Carboniferous source rocks) (Cao et al., 2012; Wang et al., 2013). The J_1–2, P₂w, and Carboniferous source rocks are humic, characterized by kerogen types II₂–III with their carbon isotopic composition of kerogen (δ¹³C_kerogen) mainly varying from –26.0‰ to –20.0‰ (Figure 5). These source rocks primarily generate coal-type gases (Dai et al., 1992; Liu G. et al., 2019). The P1f source rock was deposited under a saline lacustrine environment, with algae and lower aquatic organisms as the primary organic input (Cao et al., 2020; Xia et al., 2021; Zhi et al., 2021). It is a set of oil-prone source rock characterized by kerogen type II₁ with their δ¹³C_kerogen mainly varying from –28.0‰ and –24.0‰ (Figure 5). The Mahu super-giant oil field’s petroleum in the Junggar Basin was mainly generated from the P₁f source rock (Wang et al., 2013; Cao et al., 2020). Besides oil, the P₁f source rock can also generate a considerable amount of oil-type gas. As discussed in Section 5.1, Type I gas was an oil-type gas with relatively ¹³C-depleted δ¹³C ratios (Figure 4; Table 1), which was generated from the P₁f source rock, the only sapropelic source rock in the study area.

FIGURE 5

FIGURE 5. Histogram of δ¹³C_kerogen values of primary (A) J_1-2, (B) P₂w, (C) P₁f, and (D) C source rocks in the hinterland of Junggar Basin.

This conclusion was supported by evidence from the δ²H ratios of natural gas. Identical to δ¹³C ratios, the δ²H ratios of alkane gases also have parent material inheritance (Schoell, 1980, Schoell, 1984; Ni et al., 2011). Under the same or similar thermal evolution conditions, the δ²H ratios of the natural gas generated by marine or saline lacustrine source rocks are usually more enriched in ²H (Liu et al., 2008a; Wang et al., 2015; Liu Q. et al., 2019). Therefore, the δ²H ratios of alkane gas can be used to judge the geneses and sources of natural gas (Schoell, 1980; Wang et al., 2015). Gases from Well PD1 have δ²H-CH₄ and δ¹³C-CH₄ ratios of –164‰ and –38.5‰, respectively, and was located within the distribution area of oil-type gas generated from the saline sapropelic source rock (Wang et al., 2015; Figure 6; Table 2). Two gas samples derived from the P₁f source rock in the Mahu Sag (Dai et al., 1992) were also located in this area (Figure 6; Table 2).

FIGURE 6

FIGURE 6. The δ¹³C-CH₄ vs. δ²H-CH₄ plot of natural gas in the Junggar Basin (diagram modified after Wang et al., 2015).

TABLE 2

TABLE 2. Stable hydrogen isotopes of natural gases in the Junggar Basin.

5.2.2 Type II Gas

As mentioned in Section 5.1, the Type II gas is a highly mature coal-type gas generated from the humic source rock. Unfortunately, however, three sets of humic source rocks (i.e., J_1–2, P₂w, and Carboniferous) developed in the study area (Figure 5), which brought added complications in identifying the gas source.

In northwestern China, the J_1–2 source rock is a set of high-quality coaly source rock, and a large number of giant gas fields related to the J_1–2 source rock were discovered (Dai et al., 2009, 2014). Some researchers once pointed out that the study area’s natural gas was mainly generated from the J_1–2 source rock (Dai et al., 2009; Li et al., 2009). In this study, the limiting thermal evolution conditions of the four sets of source rocks were simulated (Figure 7A) based on a pseudo well in the deepest part of the Pengyijingxi Sag (for well location see Figure 1C). When the Lower Jurassic Badaowan (J₁b) source rock reached the maximum burial depth, it was still in the immature–low mature stage (Ro = 0.5%–0.7%) (Figure 7A). In other words, this set of source rock in the study area has never entered the main oil generation window, let alone the main gas generation window. Therefore, the contribution of J_1–2 source rock was excluded.

FIGURE 7

FIGURE 7. Burial history and geothermal evolution history of (A) virtual well and (B) Well SX16 in the Pengyijingxi Sag.

Type II gas from Wells MS1, SD2, and LD1 were produced from the Carboniferous reservoirs (Table 1). The P₂x was interbedded between the Carboniferous and P₂w with a thickness of approximately 200 m in Well MS1. Besides, the gas-producing zone was approximately 400 m lower from the top Carboniferous in Well MS1. Moreover, Permian strata were absent in the area where Well SD2 and Well LD1 were drilled. Therefore, it is inferred from geological conditions that the Type II gas was derived from the Carboniferous source rock rather than from the P₂w source rock. Previous studies have shown that the natural gas of the Kelameili gas field in the eastern Junggar Basin was generated from the Carboniferous source rock (Sun et al., 2016; Gong et al., 2019a, Gong et al., 2019b, Gong et al., 2021). It shared similar δ¹³C ratios with the Type II gas (Figure 4), further supporting our conclusion.

5.2.3 Type III Gas

Generally, the δ¹³C_kerogen values of P₂w source rocks were more enriched in ¹³C than Carboniferous source rocks, although the former has a broader distribution range (Figure 5). The δ¹³C_kerogen ratios revealed that the P₂w source rock has more terrigenous organic input and poorer kerogen type (Hunt et al., 1996). When the maturities of natural gas were similar (the C₁/∑C_1–4 ratios were similar) (Table 1), the δ¹³C-CH₄ values of natural gas generated from the P₂w source rocks should theoretically be more enriched in ¹³C than those generated from the Carboniferous source rocks (Liu et al., 2008b; Gai et al., 2018). However, the actual condition was just the opposite (Figure 4). We also noticed that a small number of P₂w source rock samples had relatively ¹³C-depleted δ¹³C_kerogen values (–28‰ to –25‰) (Figure 5). Thus, the contribution to Type III gas by P₂w source rock could not be totally excluded, entirely based on δ¹³C_kerogen values (Figure 5).

However, evidence from the fluid inclusions further precluded the significant contribution from the P₂w source rock. SX16 was a high yield well drilled in 2011 in the study area (Figure 1C). The producing layer was the Carboniferous volcanic rocks, and the daily gas production was 86.27 × 103 m³. Abundant oil and gas inclusions and associated contemporaneous brine inclusions were detected in the calcite-filled fractures in the producing interval (Figure 8). Through microscopic observation, one period of oil charging and one period of gas charging were identified. The oil inclusions mainly emitted blue or blue-green fluorescence (Figures 8A,B). Most natural gas inclusions are circular/oval-shaped and appear black under transmitted light with no fluorescence (Figures 8C,D). The homogenization temperature of the brine inclusions associated with natural gas inclusions ranged from 92.7 to 106.6°C. Combined with the thermal evolution history of Well SX16, the natural gas filling period was mainly the Late Cretaceous (Figure 7B). At that time, the deepest P₂w source rock in the Pengyijingxi Sag was still in the main oil generation window (Ro = 1.0%–1.3%) and had not entered the gas generation stage (Figure 7A). On the contrary, the P₁f and Carboniferous source rocks had entered a high mature–overmature stage in the deep part of the sag (Figure 7A). They could have generated a large amount of natural gas, which accumulated in suitable traps. Therefore, type III gas was most likely a mixture of natural gases generated from the P₁f and Carboniferous source rocks.

FIGURE 8

FIGURE 8. Micrographs of fluid inclusions in the Carboniferous reservoir of Well SX16 ((A,C,D) under plane polarized light; (B) under fluorescence).

In addition, the TOC, S₁ + S₂, and hydrogen index (HI) of P₂w source rock were 0.1%–1.2% (0.5% on average), 0.08–3.16 mg HC/g rock (0.82 mg HC/g rock on average), and 7–103 mg HC/g TOC (53 mg HC/g TOC on average), respectively, indicating poor source rock–non-source rock (Figure 9). The P₂w source rock had a hydrocarbon generation capacity far inferior to P₁f and Carboniferous source rocks (Figure 9). Thus, it did not have the potential to form a large-scale natural gas field (reservoir).

FIGURE 9

FIGURE 9. The TOC vs. S₁ + S₂ plot of C, P₁f, and P₂w source rocks in the Junggar Basin.

Based on the hypotheses, it was believed that Type III gas was a mixture of natural gas generated from the Carboniferous and P₁f source rocks. The mixing gas (Type III) had δ¹³C-CH₄ values between Type I and Type II gases (Figure 4; Table 1). The δ¹³C ratios of C_2–4 of Type III gas were relatively ¹³C-enriched, similar to those of Type II natural gas (Figure 4; Table 1). Under similar maturity, the oil-type gas usually had a lower content of C_2–4 than the coal-type gas (Dai et al., 1992; Whiticar, 1994; Liu Q et al., 2019), causing the δ¹³C ratios of C_2–4 gas in type III to be closer to those in type II, rather than in Type I gas.

The evidence from hydrogen isotopes further confirmed our conclusion. The δ²H-CH₄ values of three samples from Peng5 gas field were –186‰, –185‰ and –186‰, respectively (Figure 6; Table 2), which was significantly different from those of gases generated from the fresh (humic) source rocks such as Carboniferous or P₂w (Wang et al., 2013). The three samples were located in the transitional area between the coal-type gas (from fresh humic source rock) and oil-type gas (from saline sapropelic source rock) (Figure 6). Considering the number and planar distribution of the samples, the Type III natural gas constituted the main part of the natural gas in the hinterland.

However, recent researches indicated that Well JT 1 in the Shawan Sag has encountered high-quality P₂w source rocks with their TOC, HI and δ¹³C_kerogen being 4.15%, 671 mg HC/g TOC and –28.6‰, respectively (Zhi et al., 2021; Gong et al., 2022). Thus, the locally developed high-quality P₂w source rocks cannot be excluded in the hinter land of Junggar Basin. Since the P₂w source rock has entered condensate-generating period in the Pengyijingxi Sag nowadays (Figure 3A), it may also made some contribution to the Type III gas.

5.2.4 Type IV Gas

Compared with the δ¹³C ratio of C_2–4 gas, methane is generally more sensitive to the change of maturity (Stahl and Carey, 1975; Dai et al., 1992; Berner and Faber 1996). Thus, the Δδ¹³C-(CH₄ – C₂H₆) ratio is often used to reflect the maturity of natural gas (Prinzhofer and Huc, 1995; Dai et al., 2014; Wu et al., 2019). For primary thermogenic gas, the increase of Δδ¹³C-(CH₄ – C₂H₆) reflected the increase of maturity. However, with the increase of Δδ¹³C-(CH₄ – C₂H₆), the ln(C₁/C₂) of Type IV gas showed a decreasing trend, which was not in line with the characteristics of primary thermogenic gas (Figure 10A).

FIGURE 10

FIGURE 10. Cross plots of (A) Δδ¹³C-(CH₄ – C₂H₆) vs. ln(C₁/C₂) (the chart is modified after Prinzhofer and Huc, 1995), and (B) depth vs. Δδ¹³C-(CH₄ – C₂H₆) of natural gas in the hinterland of Junggar Basin.

We believe that Type IV gas was mainly a secondary microbial gas. Natural gas generated via bacterial alteration of organic matter is called primary microbial gas, whose δ¹³C-CH₄ values are generally lower than –55‰ to –60‰ (James and Burns, 1984). The δ¹³C-CH₄ of Type IV natural gas was more enriched in ¹³C than this threshold (Table 1). Secondary microbial gas refers to the natural gas formed by the biodegradation (anaerobic biodegradation in most cases) of crude oil (Head et al., 2003; Etiope et al., 2009; Milkov, 2010; Milkov, 2011). Generally, secondary microbial gas has the following characteristics: 1) δ¹³C-CO₂ > +2‰; 2) Natural gas is associated with biodegraded crude oil; 3) δ¹³C-CH₄ = –55‰ to –35‰; 4) High methane content; 5) Low reservoir temperature (<70–90°C); 6) The reservoirs are mostly sandstone formations with high porosity and permeability; and 7) The reservoirs are usually characterized by normal pressures with poor sealing conditions (Bernard et al., 1992; Milkov, 2010; Milkov, 2011).

The crude oil associated with Type IV gas is generally subjected to biodegradation (Figure 11). The 25-norhopanes are formed by the loss of methyl group at C–10 position of hopanes via the alteration of microorganisms (Seifert and Moldowan, 1979). Their appearance has been widely used as a sign of severe biodegradation to crude oil (Moldowan et al., 1984; Tian et al., 2012). In the study area, abundant C₂₈ and C₂₉ 25-norhopane were detected in the m/z 177 mass chromatogram of crude oil associated with the Type IV gas, indicating that the crude oil had suffered severe biodegradation (Figure 11). In addition, when crude oil was subjected to biodegradation, the compounds with strong resistance to biodegradation formed bulges (i.e., unresolved complex mixtures, UCM) in gas chromatography of saturated hydrocarbons or FID diagram (Killops and Al-Juboori, 1990; Gouch et al., 1992; Hu S. Z. et al., 2020). Noticeable UCM bulges were observed in the FID diagram in the current samples, which also reflected the biodegradation of crude oil (Figure 11).

FIGURE 11

FIGURE 11. Biomarker characteristics of crude oil associated with Type IV gas in Well L103. (A) TIC; (B) m/z 177; (C) m/z 191.

The δ¹³C-CH₄ and C₁/∑C_1-4 ratios of Type IV gas were –54.8‰ to –43.2‰ (–48.7‰) and 0.93–1.0 (0.97 on average), respectively, which are well in accordance with those of the typical secondary microbial gas (Table 1). The gas-producing zones of Type IV gas had favorable physical properties, with their porosity and permeability being 20.7%–31.0% (24.9% on average) and 313 × 10⁻³ μm²–4,760 × 10⁻³ μm² (1,180.6 × 10⁻³ μm² on average), respectively. All gas-producing zones had normal pressures, with the formation pressure coefficients (obtained by the DST test) being 0.77–1.04 (0.92 on average). The burial depths of the producing zones were 960–2,041.5 m. Assuming the current surface temperature was 20°C and the geothermal gradient was 22.3°C/km (Qiu, 2002; Wang et al., 2013), the current formation temperatures were 41.4–65.5°C (Figure 10B; Table 1). Although δ¹³C-CO₂ data were not obtained in this study, considering other characteristics, the Type IV gas was identified as a secondary microbial gas in this study。

It should be noted that laboratory simulation and field examples showed that the main component of the pure secondary microbial gas was methane, and the content of C_2–4 gas was extremely low (Pallasser, 2000; Milkov and Dzou, 2007; Jones et al., 2008). However, a certain amount of C_2–4 gas components were found in Type IV natural gas (Table 1), indicating the gases were also mixed with a small amount of thermogenic gas.

5.3 Secondary Alteration of Natural Gas

5.3.1 Biodegradation

Bacteria may alter C_1–4 gaseous hydrocarbons in gas reservoirs (Davis, 1967; Whiticar, 1994; Clayton et al., 1997; Pallasser, 2000). In most cases, the alteration on C_2–4 gas components tends to be more prominent (James and Burns, 1984). The selective degradation of a specific gas component by bacteria will reduce its relative content. At the same time, as ¹²C is less stable than ¹³C, it is often degraded first, resulting in a more ¹³C-enriched δ¹³C ratio of natural gas (Dai et al., 1992; Galimov, 2006). The carbon isotopic reversal of ethane and propane were observed in natural gas in Wells L102 and M11, with Δδ¹³C-(C₂H₆ – C₃H₈) values being 2.0 and 0.08‰, respectively (Figure 12A). Meanwhile, the C₂/C₃ ratios of the two samples were relatively low, at 2.25 and 1.76, respectively (Figure 12A). The above characteristics inferred that the ethane was selectively degraded by bacteria.

FIGURE 12

FIGURE 12. Cross plots of (A) Δδ¹³C-(C₂H₆ – C₃H₈) vs. C₂/C₃ and (B) Δδ¹³C-(C₄H₁₀ – C₃H₈) vs. C₄/C₃ of natural gas in the hinterland of Junggar Basin.

Similarly, some samples had significant carbon isotopic reversal between propane and butane [Δδ¹³C-(C₄H₁₀ – C₃H₈) < 1‰], accompanied by a decrease in C₄/C₃ ratio (Figure 12B). The propane in this part of the natural gas was selectively degraded by bacteria. This process also resulted in the abnormal decrease of Δδ¹³C-(C₂H₆ – C₃H₈) (<–5‰) and the increase of C₂/C₃ in these natural gas (Figure 13A; Table 1). We noted differences in the degraded gas components in different samples, which may be caused by different types of bacterial strains involved in the degradation processes (Connan et al., 1996; Wilkes et al., 2000; Gong et al., 2017). Moreover, some natural gas samples also displayed δ¹³C-C₃H₈ and δ¹³C-C₄H₁₀ inversion, but the amplitude was relatively small (<1‰), and the C₄/C₃ ratio had not increased significantly (Figure 12B). The carbon isotopic reversal of these samples was more likely caused by the mixing of natural gas with different maturity or different geneses (Dai et al., 2004; Liu et al., 2016).

FIGURE 13

FIGURE 13. Accumulation model of natural gas in (A) early Jurassic, (B) Cretaceous, and (C) nowadays in the hinterland of Junggar Basin.

5.3.2 Gas Leakage

Gas leakage often occurs in the reservoir when the sealing condition is poor. In this case, the gases in the leakage phase will be rich in methane, and its δ¹³C ratios tend to be depleted in ¹³C (Prinzhofer and Huc, 1995). In contrast, the residual gas in the reservoir tends to show lower C₁/C₂ ratio and higher δ¹³C-CH₄ values [decreasing δ¹³C-(CH₄ – C₂H₆) values] (Prinzhofer and Huc, 1995). As shown in Figure 10A, considerable part of natural gas in the study area deviated from the evolution trend of primary thermogenic gas and showed the characteristics of residual phase gas after leakage. Thus, the leakage process reflected a poor preservation condition of gas reservoirs in the study area, and intense modifications occurred after the formation of these reservoirs. Wells LN6 and SD10 are two typical examples. The extremely low C₁/C₂ values in natural gases (Table 1) indicated that the two gas reservoirs had been completely destroyed after reconstruction. Furthermore, the oil test data showed that LN6 and SD10 only produced more than 100 m³ of natural gas per day, which also confirmed our analysis.

5.4 Gas Accumulation Process

From the Late Permian to the Early Triassic, the Carboniferous and P₁f source rocks in the Penyijingxi Sag became mature successively (Figure 6B). During the Jurassic, the P₁f source rock had entered the stage of generating condensate/wet gas, while the Carboniferous source rock began generating dry gas (Figure 7A). The early natural gas reservoirs were formed at that time. It is speculated that gases derived from the Carboniferous source rock account for most (Figure 13A). During the same time, the P₂w source rock was still in the early stage of the oil generation window (Figure 7A), which corresponded to the early crude oil filling reflected by fluid inclusions (Figure 7B).

During the Late Cretaceous, the P₁f source rock also entered the gas generating peak. The generated oil-type gas and the coal-type gas from the Carboniferous source rock constituted the main body of natural gas in the hinterland of the Junggar Basin (Figure 13B). The process corresponded to the second stage of natural gas filling reflected by fluid inclusions (Figure 7B). At that time, the P₂w source rock entered the late stage of the oil generation window and was still dominated by oil generation (Figure 7A).

During the Himalayan period, the Junggar Basin totally tilted southward, resulting in different degrees of adjustment or destruction of early formed petroleum reservoirs (Figure 13C). This process resulted in a widespread leakage in gas reservoirs in the hinterland (Figure 10A and Figure 13C). Meanwhile, some oil reservoirs suffered severe biodegradation (Figure 13C), with the residual crude oil generally rich in 25-norhopane (Figure 11). During the biodegradation process, a large amount of secondary microbial gas (Type IV gas) was formed, and the latter accumulated in suitable traps (Figure 13C).

6 Conclusion

Four types of natural gas have been identified in the hinterland of the Junggar Basin. The Type I gas was derived from the P₁f saline lacustrine source rock in the Pengyijingxi Sag. It had relatively ¹³C-depleted δ¹³C ratios with an average C₁/ƩC_1–4 value of 0.92. The δ²H ratios of Type I gas were enriched in ²H. Type II gas was coal-type gas derived from the Carboniferous source rock. It had relatively ¹³C-enriched δ¹³C ratios with C₁/ƩC_1–4 values mainly varying from 0.90 to 0.95. The Type III natural gas was a mixture of Type I and Type II gases, which constituted the main part of the natural gas in the study area. The Type IV gas was a secondary microbial gas generally occurring in the shallow reservoirs (960–2,041.5 m), with the δ¹³C-CH₄ values and C₁/ƩC_1–4 ratios being –54.8‰ to –43.2‰ and 0.96, respectively. Abundant 25-norhopane and UCM bulges were found in its associated crude oil. One period of oil charging and one period of gas charging were identified in the study area. The homogenization temperature range of the latter was 92.7–106.6°C, corresponding to the gas generation peak of P₁f and Carboniferous source rocks (Late Cretaceous). Affected by the late tectonic movements, some gas reservoirs were damaged and adjusted, and natural gas leakage and biodegradation widely occurred.

The research results shifted the focus of natural gas exploration in the study area from the petroleum systems associated with the P₂w source rocks to those associated with the P₁f and Carboniferous source rocks. This is of great significance for natural gas exploration in the Junggar Basin. When the geochemical characteristics alone cannot accurately determine the gas genesis, the geological characteristics of the gas reservoir can often be used as an effective auxiliary tool.

Data Availability Statement

The original contributions presented in the study are included in the article/supplementary material, further inquiries can be directed to the corresponding author.

Author Contributions

DZ: Conceptualization, Resources, Project administration; XW: Writing Original Draft, Formal analysis; ZQ: Writing Original Draft, Formal analysis, Methodology.

Funding

This work is funded by Chinese National Natural Science Foundation (No. 41802177).

Conflict of Interest

Authors DZ, XW, and ZQ were employed by the company Xinjiang Oilfield Company. Author DZ was employed by the company Turpan-Hami Oilfield Company.

Publisher’s Note

All claims expressed in this article are solely those of the authors and do not necessarily represent those of their affiliated organizations, or those of the publisher, the editors and the reviewers. Any product that may be evaluated in this article, or claim that may be made by its manufacturer, is not guaranteed or endorsed by the publisher.

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