Natural gas’s constituents are a crucial indicator of the genetic types of natural gas that are present. Given that hydrocarbons, which make up more than 70% of the total gas and dominate the molecular composition of the natural gas in the study area, the natural gas are likely mostly derived from organic sources, according to this theory. Methane is the main hydrocarbon gas in natural gas, and the methane content ranges from 12.57% to 87.90% (Table 1), with an average of 67.3%, the main peak between 70% and 90%. The minor ethane content varies between 1.91% and 25.50%, with an average of 9.64%; the trace propane content varies between 0.41% and 21.56%, with an average of 5.18%; and Well No.13 has the highest concentration, at 87.90%. Well No.5 has the lowest concentration, at 12.57%. Natural gas’s dryness indices (C₁/C_1-5) range from 0.19% on the low end to 0.97% on the high end, with an average of 0.8% (which is typical for wet gas) across faults (Table 1). Nitrogen (N₂), carbon dioxide (CO₂), and hydrogen (H₂) are the most common non-hydrocarbon gases in Shunbei’s natural gas, albeit at low amounts. The CO₂ content ranges from 1.65% to 68.21% (11.77% on average), with the majority of the CO₂ content being less than 10% (Table 1). The N₂ content ranges from 0.37% to 11.34% (2.92% on average) (Table 1), with the majority of the N₂ content being around 2%; and the H₂ content ranges from 0.01% to 1.58% (0.19% on average) (Table 1).

Natural gas in the research area has a standard stable carbon isotope trend, with methane (δ¹³C₁), ethane (δ¹³C₂), and propane (δ¹³C₃) carbon isotope levels increasing with increasing carbon number, starting at a value of −51.7‰ to −44.2‰ (average −47.43‰), −39.3‰ to −28.6‰ (average −34.47‰), −35.6‰ to −25.4‰ (average −31.43‰), respectively. Carbon dioxide (δ¹³C_CO2) has a δ¹³C value that varies from 14 to 2.7‰ (Table 1). The natural gas in the study area has the methane hydrogen isotope (δ²H−CH₄) values rang from −217‰ to −146‰ (average −177‰), the ethane hydrogen isotope (δ²H−C₂H₆) values rang from −205‰ to −99‰ (average −133‰), and the propane carbon isotope (δ²H−C₃H₈) values rang from −157‰ to −81‰ (average −116‰) (Table 1).

Oil and gas’ geochemical properties are mostly determined by their parent material, degree of maturation, and other processes. Natural gas formation theories center mostly on the peculiarities of light hydrocarbons and various isotopes of carbon and hydrogen. ¹²C is typically enriched in the low molecular hydrocarbon as a result of organic matter breaking, whereas ¹³C is significantly enriched in the large molecular hydrocarbon, such that the carbon isotope ratios of natural gas components are ordered from small to large (δ¹³C₁ < δ¹³C₂ < δ¹³C₃ < δ¹³C₄). The difference in carbon isotope content between neighboring components correlates with the age of the parent rock. When the maturity is low, the difference of carbon isotope is obvious. Differences tend to decrease and sometimes reverse as maturity increases (δ¹³C₁ >δ¹³C₂ >δ¹³C₃ >δ¹³C₄) (Schoell 1980; Whiticar et al., 1986; Whiticar 1999; Dai et al., 2016; Xie et al., 2017; Ni et al., 2019). Therefore, the carbon isotope ratio index can be adopted to determine the origin and genetic makeup of various parent natural gases at various times in their development. Carbon isotope characteristics of ethane and propane, as well as the geological history of the study area, suggest that the natural gas in the Shunbei area are likely thermogenic gases (Figure 2). Methane’s hydrogen isotopic composition varies with its sedimentary context, and this variation can be used as a valuable indication of that environment. For methane, the concentration of hydrogen isotopes is highest in marine environments rich in salt, followed by those rich in brackish water and finally those rich in fresh water. The value of methane hydrogen isotope is bounded by −180‰, when the value more than −180‰, indicating marine source rocks; otherwise, indicating continental source rocks (Wang et al., 2015). The average δD−CH₄ values of the naturally occurring gases in Fault 7, 5, 1, and 4 are −208‰, −190‰, and −168.5‰, and −148.5‰, respectively (Table 1). The carbon and hydrogen isotope properties of methane are used to identify the origin of natural gas, and these measurements showed that the gases in the research area were consistent with a sapropelic-kerogen source (Figure 3). To more accurately determine the genetic types of natural gases based on their isotopic makeup, scientists have discovered that carbon isotopes may be utilized to distinguish between gas originating from coal and gas related with oil. Researchers in Shunbei could tell that the gas was predominantly from zone II and that it was an oil-associated gas by analyzing its carbon isotope composition (Figure 4).

Natural gas genetic kinds can be determined using carbon isotopes contained in gas components as trustworthy indicators. In order to gauge the precision of the method, the reciprocal value of the carbon number associated with methane and pentanes is used (Chung et al., 1988; Dai et al., 2016). In the case when δ¹³Cn is proportional to 1/n, it can be inferred that the carbon isotopic composition of the ancestor is also homologous. However, if this is not the case, it suggests that the genetic source has a complex carbon isotope makeup (Prinzhofer et al., 1995; Zhang et al., 2005; Zou et al., 2007). In the Shunbei, there is a positive trend in the carbon isotopic compositions of alkanes, suggesting that these gases are produced by the cracking of organic materials. This is denoted by the notation δ¹³C₁< δ¹³C₂ < δ¹³C_3. According to the information presented in Table 1, δ¹³C₁ and δ¹³C₂ values of natural gases display quite wide ranges of variation, with values ranging from −51.7‰ to −44.2‰ (average −47‰) and −39.3‰ to −28.6‰ (average −34‰), respectively. Natural gases are oil-associated gas and its parent material type is I kerogen in Shunbei, which can be further divided three subcategories. Type I₁, Type I₂ and Type I₃ (Figure 5A). Type I₁ shows a positive trend, δ¹³C₁ values range from −47.5‰ to −44.2‰ (average −45.85‰), δ¹³C₂ values range from −28.6‰ to −29.9‰ (average −29.3‰) (Table 1; Figure 5B), the representative wells are No. 26 and No. 13, and C₁/ƩC_1–5 values range from 0.97 to 0.95, respectively, indicating dry gas and oil-associated gas of high maturity. Type I₂ shows a positive trend, δ¹³C₁ values of the Type I₂ range from −51.7‰ to −44.7‰ (average −47.2‰), δ¹³C₂ values of the Type I₂ range from −34.8‰ to −32.1‰ (average −33.7‰) (Table 1; Figure 5C). C₁/ƩC_1–5 values of Type I₂ range from 0.81 to 0.97 (average 0.87), the Type I₂ gas is wet gas. The δ¹³C₁ values of the Type I₃ range from −49.2‰ to −46.4‰ (average −48.51‰), δ¹³C₂ values of the Type I₃ range from −39.3‰ to −37.7‰ (average −38.6‰) (Table 1; Figure 5D). C₁/ƩC_1–5 values of Type I₃ range from 0.19 to 0.72 (average 0.56), the Type I₃ gas is wet gas. Type I₂ and Type I₃ gases are distinguished from Type I1 gases by having δ¹³C₃ values typically lower than −28.0‰. In addition, Type I₁ gas exhibits heavier δ¹³C₃ values than Type I₂ and Type I₃ gas, indicating a greater degree of thermal maturity.

Although CO₂ is widely distributed in nature, its concentration is generally low. If located near to oil fields, large reserves of CO₂ have the potential to be used to enhance oil recovery. Natural gas typically contains a number of components, carbon dioxide being one of the most frequent that is not a hydrocarbon. Most natural gases contain a certain CO₂ content. The CO₂ content is an effective indicator for geologists to understand geochemical processes in natural gases. The starting point for evaluating the regularity of CO₂ enrichment is the source of the gas. Many studies have been conducted to determine where CO₂ first appeared in the atmosphere (Gould et al., 1981; Shang et al., 1990; Tassi et al., 2012; Dai et al., 2016; Mikov et al., 2018). Dai et al. (1996) divided carbon dioxide gas reservoirs into four categories according to the content of CO₂ in gas reservoirs, and believed that the content of CO₂ in gas reservoirs is more than 60%, CO₂ is of inorganic origin, and the content of CO₂ is 15%–60% Mainly of inorganic origin. There is little difference about CO₂ content in Shunbei area. Most of wells have been acidified fracturing in Shunbei, CO₂ content will be increase during the process of acidizing fracturing. The CO₂ produced by the dissolution of acid in the formation water of carbonate rocks is generally low in formation rate and gas production intensity, because the acid in the formation water is generally low in content and concentration. However, the high concentration and quantity of strong acid injected during artificial acid fracturing can quickly react with the carbonate formation to produce a large amount of CO₂ in a short period of time, resulting in high CO₂ content in gas samples collected during this period (Zhang et al., 2010). Therefore, the CO₂ content were related to acidified fracturing in Shunbei. Carbon dioxide origin can be determined by measuring its δ¹³C isotope signature, which has been shown to be greater than −8% for inorganic carbon dioxide and less than −10% for organic carbon dioxide (Dai et al., 1996). Figure 6 shows that the majority of the CO₂ in natural gases in the Shunbei region comes from inorganic sources and exists in a coexisting zone.

For a complete picture of the natural gas cycle and its origin, it is also important to distinguish between oil-associated gas and coal-type gas, as well as kerogen cracking gas and oil cracking gas (Tissot et al., 1984; Lan et al., 2009; Cheng et al., 2013). If the natural gas is oil cracking gas, then the oil and gas that the source rock produces during the peak phase of oil generation are in the large cracking gas stage when they are trapped to form paleo-reservoirs. Since the oil reservoir created in the early stage of the source rock would have been destroyed, the availability of natural gas would be drastically impacted if it were determined to be kerogen cracking gas (Stahl et al., 1975; Berner et al., 1996; Huang J. et al., 2016). Zhao et al. (2001) proved that there are two kinds of cracking gas in the Tarim Basin, namely, the natural gas in the eastern Tabei Uplift is mainly kerogen cracking gas, and the natural gas in the Hetianhe gas field is mainly crude oil cracking gas; Zhang et al. (2011) proposed that the natural gas in the east Lungu area was mainly crude oil cracking gas.

The natural logarithmic relationship of methane, ethane, and propane ratios shows a positive trend for this ln (C₁/C₂) and ln (C₂/C₃) (Figure 7) (Li et al., 2017). The results show that the values of ln(C₁/C₂) of natural gas in Shunbei area range from 0.20 to 3.81, and the values of ln(C₂/C₃) vary from 0.26 to 1.78, which mainly fall on the evolution curve of kerogen cracking gas, most of which are below 1.5%. Some natural gas is located between the curves of kerogen cracking gas and oil cracking gas, which indicates the contribution of natural gas mixed with oil cracking gas. However, the ln(C₁/C₂) values of natural gas in Shunnan, Gulong and Gucheng areas are mostly greater than 4, and the ln(C₂/C₃) values vary greatly, ranging from 0.5 to 3.04, which falls on the evolution curve of crude oil cracking gas. The maturity of natural gas is mostly between 1.5% and 2.5% (Ma et al., 2021).

From Shunbei to Shuntuo to Shunnan area, the content of methyl adamantane in crude oil shows an increasing trend, which indicates that the cracking degree of crude oil has increased, which provides geochemical evidence that the natural gas is crude oil cracking gas in Shuntuo and Shunnan areas (Ma et al., 2021). The oil cracking degree of Well Shuntuo 1 and Well Shunnan 1 are 96%, 98%, respectively (Ma et al., 2021). The coke bitumen developed in the Ordovician Yingshan Formation reservoir in Shunnan, Gulong and Gucheng area provides petrological evidence for the formation of natural gas as crude oil cracking gas in this area. The high vitrinite reflectance of pyrobitumen indicates a high degree of cracking of the paleo-oil reservoir (Cao et al., 2019; Zhou et al., 2019).

Since the thermal maturity of natural gas cannot be directly obtained, it is necessary to use its carbon isotope to judge. Methane carbon isotopes in natural gas are closely related to maturity. Important theoretical support for tracing the gas’s origins and establishing a gas-source correlation comes from a set of empirical carbon isotope-maturity relationships given for evaluating the maturity of gases and estimated Ro value (Dai, 1989; Huang et al., 1996). There are some discrepancies between the calculated conclusions of the δ¹³C-maturity models in the Shunbei, however, because of the region’s varied geological settings and/or accumulation history. Because of this, Huang (1979) advocated using the δ¹³C-maturity model, with the equation δ¹³C₁= 21.88logRo−45.6 (Huang et al., 1996). The δ¹³C₁-Ro model was used to calculate the Ro values (Table 1). The carbon isotope of methane and Ro values are displayed in Table 1 in accordance with the dryness coefficient, demonstrating that the maturity of natural gases in the Shunbei area steadily increases from west to east. The southern part of Fault 5 has a higher maturity level than the center and northern parts. The northern portion of Fault 1 is more mature than the southern portion. Natural gas maturity can be determined using a variety of markers, the most popular and reliable of which is the light hydrocarbon component. The light hydrocarbon component’s n- and iso-heptane may efficiently discriminate between various maturity stages (Thompson, 1979). Figure 8 shows that the natural gas in Shunbei area is in the mature to high mature stage.

It is common knowledge that the Cambrian, Lower-Middle Ordovician, and Upper Ordovician were the most productive times for production of the marine source rocks that make up the Tarim Basin (Zhang et al., 2000b). While both the Xishanbulake-Xidashan and Yuertusi Formations contributed to the formation of Cambrian source rocks, the Yuertusi Formation was far more instrumental. Well XH1 uncovered the Cambrian Yuertusi Formation, which has a total thickness of about 40 m and a total organic carbon (TOC) concentration of 1.0%–9.43% (7 samples averaged out to 5.5%) (Yun et al., 2014; Jin et al., 2017). Type I-II organic compounds make up the bulk of all organic materials (Xiao et al., 2000). There is now a stage of extreme maturity in the Cambrian source rocks (Zhan, 2016).

The Heituao and Saergan Formations have the highest concentration of middle and lower Ordovician source rocks (Chen et al., 2014). The presence of kerogen type II in algae and acritarchs causes a wide range of total organic carbon (TOC) values in Middle-Lower Ordovician source rocks (average 1.77%; 7 samples) (Zhao et al., 2012; Zhao et al., 2014). There is a total organic carbon concentration of 0.47–0.56% in the Upper Ordovician source rocks of the North Uplift of the Tarim Basin, and a TOC concentration of 0.5% or higher in rocks with a thickness of 6–28 m. Natural gas in the Shunbei area was determined to be oil-associated gas based on its geochemical features and those of the source rocks. The Ordovician age is largely responsible for the generation of the gas found in oil reservoirs. The evidence is broken down and addressed in detail below.

①The δ¹³C properties of the natural gas in the Shunbei exploratory wells show that the oil-associated gas originates from the Ordovician source rocks. Gaseous alkanes from the Middle-Upper Ordovician and Cambrian have been dated using their carbon isotope distribution curves, which have been published by Wang et al. (2014). It is discovered that the wet gases show steep C₁-C₃ alkane carbon isotope distribution curves with negative δ¹³C₁ values (<− 42.5‰), which are assumed to have originated from Middle-Upper Ordovician source rocks. In contrast, Cambrian natural gas had δ¹³C values that were considerably high (>−42.5‰), along with flat distribution curves for carbon isotopes C₁–C₃. Therefore, using the carbon isotopes of gaseous alkanes permits one to determine the origin of gases and establish relationships between gases. The wet gas from the Shunbei correlates well with gases from the Middle-Upper Ordovician, with δ¹³C values that range from 44‰ to 52‰ (or <− 42.5‰) and a steep distribution curve of C₁-C₃ alkanes carbon isotopes (Table 1; Figure 9).

②In accordance with the inheritance of isotopes, dispersion of isotopes, and variation of isotopes during the formation and evolution of hydrocarbons, the carbon isotopes can be utilized to correlate oil sources. The majority of Cambrian source rock samples exhibit stable carbon isotopes heavier than −30‰, with the greatest values seen in Well H4 at −25.8‰. The isotopic curve distribution of Cambrian and Ordovician crude oils is shown in Figure 10 and Table 2. Obviously, Cambrian crude oils are consistent with Cambrian source rocks. On the other hand, the isotopes of Ordovician crude oil are obviously lighter and are distributed in −32‰ ∼ −36‰ (Song et al., 2016), so it is obviously impossible for them to be derived from Cambrian source rocks.

The crude oil in Shunbei area mainly comes from the Lower Cambrian Yuertusi Formation source rocks (Yun et al., 2014), the Ordovician reservoir is mainly controlled by the multi-stage structural rupture of the strike-slip fault zone and the dissolution along the fault (Jiang et al., 2005). The characteristics of hydrocarbon reservoirs revealed in shallow and deep parts of the same fault zone are consistent. For example, deep well SHB1-10H and shallow well SHB1-3 of Shunbei No. 1 fault zone have basically the same crude oil density and gas dryness coefficient of the two Wells, which proves that the oil and gas generated by in-situ source rock is mainly formed by vertical transport along the fault in Shunbei area. The movable oil and gas are mainly accumulated since the late Hercynian period, and the fault zone plays an obvious role in controlling reservoir and accumulation. This area is located in the sedimentary area of gentle slope source rocks in the early Cambrian period. In the later period, the pass-source strike-slip fault was developed and the reservoir was dominated by “fault-karst”. Therefore, because strike slip faults influence in-reservoir geochemical processes and vertical petroleum migration, strike slip faults play an important role in the ultra-deep fault-karst petroleum systems present in the Shunbei area (Figure 11) (Qi, 2021).