Significance and evolution characteristics of the isobutane/n-butane ratio of natural gas

Abstract

In previous studies, two conflicting conclusions existed, which were: (a) the isobutane/n-butane ratio of natural gas increases with the increasing maturity (R_o) of source rocks and (b) decreases with the increasing R_o. In this paper, the correlations between the isobutane/n-butane ratios, dryness of natural gases, and the R_o values of source rocks of 77 gas samples from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, Carboniferous–Permian in Sulige and Yulin gas field, Ordos Basin, China, and 80 shale gas samples from Mississippian Barnett Shale in the Fort Worth Basin, the United States are analyzed to reveal the evolution of the isobutane/n-butane ratios, then mathematical models of the isobutane/n-butane ratios and R_o are attempted to be established. Results show that the isobutane/n-butane ratio initially increases and then decreases with increasing R_o, both coal-derived gas and oil-type gas. Diverse types of kerogens may be responsible for the different corresponding R_o values when the isobutane/n-butane ratios of gases reach their maximum values. The initial increase in the isobutane/n-butane ratios with increasing R_o is the reason that isobutane is mainly generated at a higher rate by carbonium ion reaction of α-olefins with protons during kerogen primary cracking at lower maturity, whereas free radical reactions to form n-butane relatively quickly during oil cracking at higher maturity and isobutane cracked at a higher rate during the wet gas cracking stage may result in the terminal decreases in the isobutane/n-butane ratios. Besides, mathematical models of the isobutane/n-butane ratios of different types of natural gas and maturity are established. Therefore, the maturity of gas source rock can be obtained quickly based on the models using the isobutane/n-butane ratio combined with other component information (such as dryness, wetness, etc.), which is of great significance to the characterization of natural gas maturity and gas source rock correlation.

Keywords

Natural gas geochemical characteristics isobutane/n-butane ratio maturity indicator gas source rock

Introduction

Natural gas is mainly composed of methane, ethane, propane, butane, light hydrocarbon, nitrogen, carbon dioxide, and rare gas. Chemical and isotopic compositions are the most important parameters for characterizing the geochemical properties of natural gases. In particular, methane and ethane components and their isotopes are widely used in genetic type analysis, maturity estimation, gas source rock correlation, migration tracer, and secondary transformation identification of natural gas (Dai, 2018; Dai et al., 2012; Galimov, 2006; Jenden et al., 1988; Kotarba and Lewen, 2013; Prinzhofer and Huc, 1995; Schoell, 1983; Sechman et al., 2017). Due to the influence of isotopic fractionation caused by pyrolysis, methane and higher hydrocarbons should become increasingly enriched in the ¹³C isotope with increasing thermal stress, i.e. with increasing maturity of their source rocks (Berner and Faber, 1996, 1988; Dai, 1992; Faber et al., 1988; Liu and Xu, 1999; Schoell, 1983; Stahl, 1977). Thus, the identification of natural gas maturity is mainly based on the mathematical formulas of source rock maturity and methane isotope (δ¹³C₁) obtained by thermal simulation experiments or empirical formulas so far. For a long time, different scholars have been concerned about whether the parameters that reflect the maturity of gas source rock can be sought from the composition of natural gas, such as dryness or wetness (Dai et al., 2016), Bernard parameter (Bernard et al., 1978), heptane (C₇) fraction concentration (Philippi, 1975; Thompson, 1983), the isobutane/n-butane (iC₄/nC₄) and i-pentane/n-pentane ratio (Qin et al., 2019; Wang et al., 2017), etc. Generally, for thermogenic natural gas, the methane content will gradually increase with increasing thermal stress, i.e. with increasing maturity of their source rock (Berner and Faber, 1988; Dai et al., 2016; Tissot and Welte, 1984). The Bernard parameter (C₁/(C₂₊₃)), also having the same tendency, increases with increasing maturity (Bernard et al., 1978). Similarly, the wetness ( $W = \sum C_{2 - 5} / \sum C_{1 - 5}$ ) of coal-derived gas has a good negative correlation with the maturity of gas source rocks (Dai et al., 2016). In addition, different scholars have found that the relative contents (volume fraction) of methane, ethane, and propane in thermogenic gases are positively correlated with the maturity of source rocks (Berner and Faber, 1988; Chen and Jin, 2005; Jin et al., 2004). Compared with other alkanes, two isomers, iC₄ and nC₄, exist in butane. The isomer ratios and stable carbon isotopic characteristics have certain applications in the study of biodegradation, natural gas genesis, maturity characterization, and migration tracer of natural gas (Boreham and Edwards, 2008; He et al., 2015; Katz et al., 2002; Miao et al., 2011; Qin et al., 2019; Wang et al., 2017; Wood and Sanei, 2016; Xie et al., 2017). However, to date, previous researches have two diametrically opposite views on the relationship between iC₄/nC₄ ratio and the maturity of gas source rocks: (a) the ratio increases with increasing maturity (Qin et al., 2019) and (b) decreases with increasing maturity (Gao et al., 1998; Héroux et al., 1979; Wang et al., 2017; Xie et al., 2017). In this paper, the correlations between iC₄/nC₄ ratios, dryness of natural gases and maturities of source rocks of 77 gas samples from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, Carboniferous–Permian (C–P) in Sulige and Yulin gas field, Ordos Basin, China, and 80 gas samples from Mississippian Barnett Shale in the Fort Worth Basin, the United States, are analyzed to reveal the evolution of iC₄/nC₄ ratio, then mathematical models of iC₄/nC₄ ratios and maturities of gas source rocks are attempted to be established. If the quantitative relationship between iC₄/nC₄ ratio and the maturity of source rocks can be determined, the maturity of gas source rocks can be obtained rapidly in the gas field, especially in the new gas exploration areas, which is of great significance to the characterization of natural gas maturity, gas source correlation, and natural gas resource evaluation.

Geological and geochemical backgrounds of the samples

In order to exclude the influence of the organic type of natural gas source rocks, the natural gas compositions and stable carbon isotopes data of gases produced from different types of kerogens were collected, respectively, from previous studies (He et al., 2015; Li et al., 2007a; Tao et al., 2009; Qin et al., 2018a, 2018b, 2019; Dai et al., 2014b, 2005b; Yu et al., 2013; Zumberge et al., 2012), including 77 gas samples in Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, C–P in Sulige and Yulin gas field, Ordos Basin, China, and 80 shale gas samples from Mississippian Barnett Shale in the Fort Worth Basin, the United States, respectively (Table 1 and Supplemental Material). The geological and geochemical backgrounds of the samples are as follows (Table 2).

Table 1.

Chemical and isotopic compositions of the gases used in this study.

Basin	Location	Number of samples	CH₄	C₂H₆	C₃H₈	iC₄/nC₄	C_2–5	C₁/C₁₊	δ¹³C₁(‰)	δ¹³C₂(‰)	δ¹³C₃(‰)	R_o(%)
Kuqa Depression, Tarim Basin	Cretaceous,	13	72.90–97.20(89.08)	1.23–12.10(5.19)	0.09–3.95(1.14)	0.05–1.06(0.85)	1.39–17.71(6.83)	0.82–0.99(0.93)	–35.8 to –28.2(–32.3)	–26.3 to –18.9(–22.4)	–19.3 to –25.9(–21.7)	0.79–2.74(1.53)
Ordos Basin	Tertiary	26	86.47–93.96(89.90)	3.31–8.00(6.17)	0.42–2.81(1.61)	0.90–1.73(1.26)	3.87–11.61(8.66)	0.88–0.96(0.91)	–42.7 to –37.2(–39.9)	–28.3 to –24.2(–26.7)	–25.9 to –22.1(–24.1)	0.86–1.23(1.02)
Central Sichuan Basin	Carboniferous–Permian	38	79.77–96.37(92.15)	1.66–8.18(4.21)	0.16–2.56(0.85)	0.73–1.44(1.06)	2.28–11.85(5.38)	0.88–0.98(0.94)	–36.5 to –29.8(–32.5)	–26.3 to –22.1(–24.2)	–25.6 to –21.1(–23.5)	0.71–2.11(1.42)
Fort Worth Basin	Triassic	80	78.58–97.19(92.40)	0.81–12.17(4.44)	0–5.05(1.05)	0.31–1.79(1.03)	0.83–20.83(6.15)	0.79–0.99(0.94)	–45.2 to –37.9(–41.1)	–41.7 to –29.1(–34.9)	–35.4 to –20.6(–27.7)	0.52–1.62(1.02)

The values in brackets are averages. The R_o values of gas source rocks from the Mesozoic Cretaceous in Kuqa Depression, Tarim Basin, Paleozoic Permian in Sulige and Yulin gas field, Ordos Basin, and Barnett shale gases in Fort Worth Basin are calculated by the Formulas 1 and 2. The R_o values of gas source rocks from Triassic Xujiahe Formation in central Sichuan Basin are from Qin et al. (2019).

Source: reproduced with permission from Qin et al. (2019).

R_o: vitrinite reflectance.

Table 2.

The characteristics of geological and geochemical backgrounds of the samples.

Basin	Location	Reservoirs name	Source	Carbon isotope of kerogen	Kerogen type	R_o of source rocks	Accumulation period
Kuqa Depression, Tarim Basin	Cretaceous, Tertiary	Kela-2, Yinan-2, Dabei, Dina-2	Jurassic	–25.2‰ to –22.6‰,(–23.8‰)	III	>0.6%	Pleistocene–present
Ordos Basin	Carboniferous–Permian	Sulige, Yulin	Carboniferous–Permian	–26.3‰ to –21.5‰(–24.2‰)	III	1.2%–2.2%	Late Jurassic–Early Cretaceous
Central Sichuan Basin	Triassic	Guang’an, Hechuan, Anyue, Longgang, etc.	Triassic	–26.3‰ to –23.5‰(–24.3‰)	III	0.8%–1.8%	Late Jurassic–Late Paleogene
Fort Worth Basin	Mississippian	Barnett Shale	Mississippian Barnett Shale	–31.0‰ to –28.1‰(–29.8‰)	II₁	0.5%–2.3%	Pennsylvanian–Triassic

The values in brackets are averages.

R_o: vitrinite reflectance.

The Kuqa Depression, located in the southern piedmont of the southern Tianshan orogenic belt in the Tarim Basin, is composed of five tectonic belts and three sags, namely the Northern Monoclinal belt, Southern Slope, and Kelasu, Yiqikelike, Qiulitage structural belt, and Wushi, Baicheng, and Yangxia sags (Hu et al., 2014; Xu et al., 2011). In the past few decades, several tight gas fields, including Kela-2, Yinan-2, and Dabei gas fields in the Kelasu tectonic zone, the Dina-2 gas field in the Qiulitage tectonic belt have been discovered in Cretaceous and Tertiary reservoirs (Zou et al., 2006). Hydrocarbon gas is the dominant component of natural gas with a relatively high dryness ranging from 0.77 to 1.00 in Kuqa depression (Liu et al., 2007a). Most discovered gas reservoirs have mainly experienced large-scale gas charging since the Pleistocene (∼3 Ma) (Guo et al., 2016; Li et al., 2014, 2015; Liang et al., 2003; Lu et al., 2012; Sun et al., 2018; Wei et al., 2019; Zhang et al., 2011; Zhao et al., 2005; Zhu et al., 2019), and are generally believed to be mainly originated from Jurassic coal-bearing source rocks (Liang et al., 2003; Wei et al., 2019; Zhang et al., 2011; Zhu et al., 2012; Zou et al., 2006). The Jurassic source rocks, composed of 400 m–1100 m of coal-bearing clastic rocks deposited in swamp-lacustrine settings, are widely distributed throughout the Kuqa Depression (Chen et al., 2012; Liu et al., 2007b). Most of the organic matter was derived from terrestrial higher plants, and the carbon isotope of kerogen was between –25.2‰ and –22.6‰, and the average value was –23.8‰ (Liang et al., 2003; Shi, 2000; Zhu et al., 2012). The thermal maturity (R_o) of source rocks is generally greater than 0.60%, and have a higher R_o value in the center and lower value in the edge of depression (Liang et al., 2003; Tang et al., 2014). Some samples data in this paper are mainly selected from typical tight gas reservoirs in Kuqa Depression, including Kela-2, Yinan-2, and Dabei and the Dina-2 gas field. These gas reservoirs are mainly derived from Jurassic coal-bearing source rocks during the similar charge timings (since ∼3 Ma), but the maturity of natural gas is different (Guo et al., 2016; Li et al., 2014; Lu et al., 2012; Sun et al., 2018; Wei et al., 2019; Yu et al., 2017; Zhang et al., 2011; Zhao et al., 2005). The current Kela-2 and Dabei are dry gas reservoir/field, whereas the Dina-2 and Yinan-2 are wet gas reservoirs. Obviously, the thermal maturity of source rocks controls the distribution of natural gas, thus the relatively lower maturity of source rocks in Yangxia sag, resulting in the wet gas in Yinan-2 and Dina-2 gas reservoir (Liang et al., 2003). This gas distribution difference also suggests that there is no significant large-scale lateral migration in these tight gas reservoirs.

The Ordos Basin is a large sedimentary basin located near the western margin of the North China craton in central China (Shuai et al., 2003). Several large tight gas reservoirs have been discovered in the Upper Paleozoic, such as the Sulige, Wushenqi, Yulin, Daniudi, and Mizi gas fields (Dai et al., 2005a; Li et al., 2018; Ma, 2005). The Upper Paleozoic natural gases in the two large gas fields are coal-derived gas and characterized by major dry gases and minor wet gases (Dai et al., 2005a; Li et al., 2012a, 2012b). The gases are generally thought to be generated from Upper C–P coal measures with the main gas reservoir being in the Lower Permian Shanxi Formation (Dai et al., 2005a, 2014; Feng et al., 2016; Hu et al., 2010a, 2010b; Li et al., 2012a, 2012b; Liu, et al., 2007b; Shuai et al., 2013; Zhao et al., 2014). The C–P coal-measure source rock, present in this area, is mainly a transitional marine-terrestrial stratum, including coal, mudstone, and limestone (Fu et al., 2005; Li et al., 2012b). The high-quality gas source rocks of C–P, which extensively develop in this area, have a high content of organic carbon, medium hydrocarbon potential, and type III kerogens, and the carbon isotope of kerogen was between –26.3‰ and –21.5‰ with the average value of –24.2‰ (Dai et al., 2001, 2003; Li et al., 2012a; Zhong and Chen, 2002). The vitrinite reflectance values for the C–P strata in the gas field areas range from 1.2% to 2.2% (Dai et al., 2003; Zhao et al., 1996). Some samples data in this paper are mainly selected from typical tight gas reservoirs in the Sulige and Yulin gas fields. The natural gas in the Sulige and Yulin gas field may be charged by a continuous process, and experiences one main gas accumulation period, mainly occurring at the Late Jurassic and Early Cretaceous, belonging to the near-source gas charging and cumulative gas accumulation (Hu et al., 2010a; Li et al., 2012a, 2012b; Mi et al., 2004; Zhang et al., 2014).

The Xujiahe Formation, consisting of six members, is mainly composed of a set of coal deposits originated from fluvial, lacustrine, and swamp facies and commonly developed in the central Sichuan Basin (Dai et al., 2009, 2012; Yang et al., 2009; Zhao et al., 2010). The first, third, and fifth members (T₃x₁, T₃x₃, and T₃x₅) of this formation are dominated by gas prone dark mudstones and coals. The source rocks are intercalated with the sandstone-dominated second, fourth, and sixth members of the Xujiahe Formation (T₃x₂, T₃x₄, and T₃x₆), thus leading to three separate self-contained petroleum systems in the region (Dai et al., 2009). Several large-scale gas fields have been discovered in the Xujiahe Formation in the Central Sichuan Basin, such as the Xujiahe reservoir in the Anyue gas field, Guang’an gas field, Hechuan gas field, and a series of small and medium gas fields (Qin et al., 2018c). The natural gases are characterized by wet gas with a dryness generally lower than 0.95, and believed to be derived from the black mudstone and coal-bearing mudstone source rocks of the formation’s T₃x₁, T₃x₃, and T₃x₅ (Dai et al., 2009, 2012; Wang et al., 2013). The coal-bearing source rock mainly have type III kerogens, and the carbon isotope of kerogen was between –26.3‰ and –23.5‰ with the average value of –24.3‰ (Dai et al., 2009, 2012; Zhang, 2013). The maturities of the source rocks, characterized by vitrinite reflectance (R_o), range from 0.8% to 1.8% (Dai et al., 2012). Some samples data in this paper are mainly selected from typical tight gas reservoirs (Guang’an, Hechuan, Anyue, Longgang, etc.) in the Xujiahe Formation in the Central Sichuan Basin. The hydrocarbon filling and accumulation of these reservoirs was a successive process which lasted from Late Jurassic to Late Paleogene (Tao et al., 2009, 2014; Zhang et al., 2015), and tight gas accumulation is in situ, and natural gas has not experienced large-scale migration (Qin et al., 2018c, 2019; Tao et al., 2009).

In recent years, the Barnett Shale of the Fort Worth Basin has been a major target for exploration and development of unconventional shale gas in the USA (Curtis, 2002). The shale serves as both the reservoir and source rock (Hill et al., 2007a; Montgomery et al., 2005), with no significant modification by migrated hydrocarbons (Wood and Sanei, 2016). General geological reviews, petrographic analyses, and organic geochemical evaluations of the Barnett Shale play have recently been published (Bowker, 2007; Hickey and Henk, 2007; Hill et al., 2007a, 2007b; Jarvie et al., 2007; Loucks and Ruppel, 2007; Montgomery et al., 2005; Pollastro, 2007; Pollastro et al., 2007). This organic-rich succession of black shales, which averages 4.5 wt.% total organic carbon (TOC), is thermally mature (R_o = 0.5%–2.3%) for hydrocarbon generation over most of the Fort Worth Basin area. The source rock mostly contains type II₁ kerogen of marine algal source and deposited in a deep foreland marine basin under upwelling conditions, and the carbon isotope of kerogen was between –31.0‰ and –28.1‰ with the average value of –29.8‰. The origin of the gas is thermogenic, probably derived from both kerogen cracking and secondary cracking of previously generated non-migrated hydrocarbons (Rodriguez and Philp, 2010; Wood and Sanei, 2016). The peak maturity of the Barnett Shale in the Fort Worth Basin is reached perhaps in the latest Pennsylvanian and maintained through the Permian and into the Triassic, and the unconventional shale gases are continuous accumulations within the Barnett Shale (Ewing, 2006; Hill et al., 2007a; Pollastro et al., 2007).

By analyzing the geological and geochemical background of the selected samples, the hydrocarbon filling and accumulation of the tight gas reservoirs are successive process, and tight gas accumulations are almost in situ, and natural gas has not experienced large-scale horizontal and vertical migration. Meanwhile, the selected Barnett shale gases in the Fort Worth Basin, the United States, are typical “self-generation and self-accumulation” gas reservoirs. Shale gases represent gases at their site of generation (Price and Schoell, 1995) and therefore provide representative in situ samples to investigate the complex physicochemical processes in the kerogen-hydrocarbon-water-matrix systems at varying temperature and pressure. In addition, the selected natural gas samples are all thermogenic gas (analyzed in next section), so the effect of biodegradation on iC₄/nC₄ ratio can be avoided. All the source rocks for the analyzed coal-type gases mostly contain type III kerogen and have similar carbon isotopes (Table 2). In this case, the isotopic and component fractionation of natural gas, the effect of carbon isotope difference in the same type kerogen, and the influence of accumulation processes may have little influence, which lays a foundation for studying the iC₄/nC₄ ratio evolution characteristics of different types of natural gas.

Geochemical characteristics and genesis of natural gas

Chemical and isotopic compositions of natural gas

Methane is the dominant component of the natural gases analyzed for the four study areas with concentrations ranging from 72.90% to 91.20%, with an average of 91.65% (Table 1, Figure 1). The contents of heavy hydrocarbon gas (C_2–5) range from 0.83% to 20.83% with an average of 6.44%. The dryness (C₁/∑C_1–5) is widely distributed, between 0.79 and 0.99, showing the coexistence of wet and dry gas. The methane content of gases from Cretaceous in Kuqa Depression, Tarim Basin, ranges widely (72.90%–97.20%), and the dryness ranges from 0.82 to 0.99, with an average value of 0.93 (Figure 1, Table 1). The methane contents of gases from Triassic Xujiahe Formation in central Sichuan Basin have a relatively narrow distribution, ranging from 86.47% to 93.96% with an average value of 89.90%, and the dryness ranges from 0.88 to 0.96, with an average value of 0.91. The gases from Sulige and Yulin gas field, Ordos Basin, has a high methane content, ranging from 79.77% to 96.37% with an average value of 92.15%, and the dryness ranges from 0.88 to 0.98 with an average value of 0.94. The shale gases from Mississippian Barnett Shale in Fort Worth Basin have the highest methane content, ranging from 78.58% to 97.19% with an average value of 92.40%, and the dryness ranges from 0.79 to 0.99 with an average value of 0.94.

Figure 1.

Chemical and isotopic compositions of the gases from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, Carboniferous–Permian in Sulige and Yulin gas field, Ordos Basin, China, and Barnett shale gases in Fort Worth Basin, the United States.

Methane stable carbon isotope ratios (δ¹³C₁) for the gases from the four study areas (Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, C–P in Sulige and Yulin gas field, Ordos Basin, China, and Mississippian Barnett Shale in the Fort Worth Basin, the United States) is –35.8‰ to –28.2‰, –42.7‰ to –37.2‰, –36.5‰ to –29.8‰, and –45.2‰ to –37.9‰, with the average value of –32.3‰, –39.9‰, –32.5‰, and –41.1‰, respectively. As a whole, stable carbon isotopic values of methane and ethane (δ¹³C₂) of natural gases produced from Kuqa Depression, Tarim Basin, and Sulige and Yulin gas field, Ordos Basin are heaviest, whereas the values from Mississippian Barnett shale gases are lightest, and stable carbon isotopic values of natural gases produced from Triassic Xujiahe Formation in central Sichuan Basin are between the three other study areas (Figure 1, Table 1).

Genetic types of natural gas

The chemical composition and stable carbon isotopic ratios of thermogenic natural gas are closely related to the sedimentary environment, kerogen type, and thermal evolution degree of the source rock, so they are widely used to determine the genetic type of natural gas and maturity of gas source rocks (Berner and Faber, 1996, 1988; Dai et al., 2016; Faber et al., 1988; Schoell, 1983; Stahl, 1977). Maturity has a significant effect on the δ¹³C₁ relative to the δ¹³C₂, whereas the δ¹³C₂ may be predominantly controlled by their source rather than maturity (Dai et al., 2005b; Galimov, 2006). Therefore, the δ¹³C₁ is usually used as a proxy to ascertain the maturity of gas source rocks, whereas the δ¹³C₂ is the common and effective indicators to distinguish coal-derived from oil-type gas (Dai, 2018; Dai et al., 2005b; Galimov, 2006). Numerous empirical studies of gas geochemistry in sedimentary basins have suggested a cutoff point in the δ¹³C₂ for differentiating the origin of thermogenic gases in these basins (Dai, 2018; Dai et al., 1992; Galimov, 2006; Gang et al., 1997). Generally, the δ¹³C₂ less than –29.0‰ is oil-type gas generated from sapropelic kerogen (Galimov, 2006), while the value greater than –28.0‰ is coal-derived gas generated from humic kerogen (Dai, 2018; Dai et al., 1992; Gang et al., 1997). The gases from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, and C–P in Sulige and Yulin gas field, Ordos Basin are mainly coal-derived gases, while the gases produced from Mississippian Barnett Shale in the Fort Worth Basin are mainly oil-type gas based on the values of δ¹³C₂ (Figure 1). However, a few gas samples produced from Triassic Xujiahe Formation in central Sichuan Basin are oil-type gases, and some shale gas samples produced from Fort Worth Basin are coal-derived gases. Dai et al. (1992) proposed a δ¹³C₁–δ¹³C₂–δ¹³C₃ plot for discriminating coal-derived and oil-type gases. The consistent conclusion can be recognized on the Dai et al. (2014c) plot (Figure 2).

Figure 2.

Plot of δ¹³C₁–δ¹³C₂–δ¹³C₃ diagram for the gases from the four study areas analyzed, indicating genetic types of the gases.

The δ¹³C₁ versus C₁/C₂₊₃ diagram can also identify gas types (Whiticar, 1999). The gases produced from the four study areas are all organic and thermogenic based on their Bernard parameters (C₁/C₂₊₃ = 4.56–116.92) and the δ¹³C₁ ratios (–45.2‰ to –28.2‰) (Figure 3). The gases from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, and C–P in Sulige and Yulin gas field, Ordos Basin mainly distribute along the tendency of type III kerogen, suggesting that the gases are mainly humic sourced (Figure 3). Nevertheless, the gases produced from Mississippian Barnett Shale in the Fort Worth Basin are mainly sapropelic gases mixed with a few humic ones. The δ¹³C₁ and C₁/C₂₊₃ values of gases from Triassic Xujiahe Formation in central Sichuan Basin distribute between types II and III kerogen tendency, indicating the gases are sourced from mixed sapropelic and humic gases. In addition, the maturities of their source rocks are systematically lower than that of three other areas (Figure 3). Oil-type gas will enrich ¹²C, while coal-derived gas will enrich ¹³C at the same maturity on account of stable carbon isotope inheritance effect of source rocks (Dai et al., 1992; Galimov, 2006). Stahl and Carey (1975) and Dai (1992) established the relationship between the δ¹³C₁ of oil-type, coal-derived gas and R_o of source rock based on the chemical and isotopic compositions of natural gas from numerous basins as follows

δ^{13} C_{1} = 14 . {8lgR}_{o} - 41 .0 (oil type gas)

(1)

δ^{13} C_{1} = 14 . {12lgR}_{o} - 34.391 (coal derived gas)

(2)

Figure 3.

Plot of δ¹³C₁–C₁/C₂₊₃ diagram for the gases from the four study areas analyzed, suggesting genetic types of the gases.

Based on the above calculation formulas, the R_o of source rocks from the four study areas (Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, C–P in Sulige and Yulin gas field, Ordos Basin, China, and Mississippian Barnett Shale in the Fort Worth Basin) is 0.79%–2.47%, 0.86%–1.23%, 0.71%–2.11%, and 0.52%–1.62%, with the average value of 1.53%, 1.02%, 0.52%, and 1.02%, respectively (Table 1, Figure 4), which corresponds to the predicting maturity levels for the gas samples analyzed, based on calculation model proposed by Berner and Faber (1996) (Figure 5).

Figure 4.

The R_o of gas source rocks from the four study areas.

Figure 5.

Predicting maturity levels for the gas samples analyzed. Numbers on the lines of sapropelic and terrestrial indicate the maturity of the respective source rock. Initial isotope value of types II and III kerogen are taken the average value as –29.8‰ and –24.2‰, respectively.

Generally, the oil generation stage, “wet gas” and condensate stage, and metagenesis to form methane stage may mainly occur at the R_o value from 0.5% to 1.3%, 1.3% to 2.0%, and greater 2.0%, respectively (Tissot and Welte, 1984). The gas source rocks thermal maturity of the Cretaceous and Tertiary in Kuqa Depression, Tarim Basin and C–P in Sulige and Yulin gas field, Ordos Basin have a relatively wide distribution, ranging from oil generation to metagenesis to form methane stage, whereas the thermal evolution of the gas source rocks from Triassic Xujiahe Formation in central Sichuan Basin, C–P in Sulige and Yulin gas field, Ordos Basin, and Mississippian Barnett Shale in the Fort Worth Basin distribute mainly in the oil generation and condensate stages (Figures 4 and 5). Prinzhofer and Huc (1995) suggest that the primary cracking of kerogen is characterized by progressive increases in C₁/C₂ ratios and relatively constant C₂/C₃ ratios, whereas secondary cracking of hydrocarbons is characterized by significant increases in C₂/C₃ ratios and almost constant C₁/C₂ ratios (inset in Figure 6). As shown in Figure 6, the humic sourced (type III kerogen) gases from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin and C–P in Sulige and Yulin gas field, Ordos Basin are mainly a mixture of primary kerogen cracking and liquid hydrocarbons secondary cracking gases. In addition, the gas samples from Triassic Xujiahe Formation in central Sichuan Basin and Mississippian Barnett Shale in the Fort Worth Basin distribute between the evolution lines types II and III kerogens (Figure 6). The reason may be some gas samples from two areas are mixture of oil-type and coal-derived gases (Figures 2 and 3). However, some difference exist in the gases from the two studies areas. The gases from Triassic Xujiahe Formation in central Sichuan Basin are mainly primary kerogen cracking gases, whereas gases from Mississippian Barnett Shale in the Fort Worth Basin are a mixture of primary kerogen cracking and hydrocarbons secondary cracking gas (Figure 6).

Figure 6.

Molecular proportions C₂/C₃ versus C₁/C₂, in natural logarithmic scales, for gases from the four study areas.

The iC₄/nC₄ ratio characteristics of natural gas

The relationship between iC₄/nC₄ ratio and dryness of natural gas

Generally, for thermogenic natural gas, the dryness values will gradually increase with increasing maturity of their source rocks (Boreham and Edwards, 2008; Dai et al., 2016; Whiticar, 1999). As shown in Figure 7, the iC₄/nC₄ ratios initially increase relatively slowly with dryness, pass through a maximum around dryness = 0.94, and then decrease relatively quickly as dryness further increases both oil-type and coal-derived gas. At the same time, this phenomenon also implies that the iC₄/nC₄ ratios initially increase and then decrease with increasing maturity of their source rocks, except for the difference that the iC₄/nC₄ ratios decrease faster after reaching the maximum value compared with initial increasing stage, which may be caused by the different thermal evolution stages of source rocks experienced (discussed below).

Figure 7.

The relationship between iC₄/nC₄ ratios and dryness of coal-derived gases (a) and oil-type gases (b) from the four study areas.

The relationship between iC₄/nC₄ ratio and maturity of gas source rock

There is a good relationship between the iC₄/nC₄ ratios of gases and the maturity values of source rocks, both coal-derived and oil-type gases, by the fitting of the ratios and calculated R_o values. As shown in Figure 8, the iC₄/nC₄ ratios initially increase with increasing R_o, and then decrease as R_o further increases both oil-type and coal-derived gas. However, the corresponding R_o values are different when the iC₄/nC₄ ratios of two different types of gases reach their maximum values, which may be related to different types of kerogens (discussed below). As for coal-derived gas, the iC₄/nC₄ ratio passes through a maximum around R_o = 1.2%, and the mathematical relationship with R_o is as follows

{iC}_{4} / {nC}_{4} = 1 . {765R}_{o} - 0. 578 (0. 5 % < R_{o} < 1.2 %)

(3)

{iC}_{4} / {nC}_{4} = - 0. {824R}_{o} + 2.364 (R_{o} > 1.2 %)

(4)

Figure 8.

The relationship between iC₄/nC₄ ratios of coal-derived gases (a) and oil-type gases (b) and R_o of source rocks from the four study areas.

As for oil-type gas, the iC₄/nC₄ ratio passes through a maximum around R_o = 1.0%, and the mathematical relationship with R_o is as follows

{iC}_{4} / {nC}_{4} = 2 . {589R}_{o} - 0. 913 (0. 5 % < R_{o} < 1 .0 %)

(5)

{iC}_{4} / {nC}_{4} = - 2 . {148R}_{o} + 3.574 (R_{o} > 1 .0 %)

(6)

In addition, the relationship between the iC₄/nC₄ ratios and R_o is more convergent at the iC₄/nC₄ ratios initially increasing stage. The data points become rather scattered as R_o increases, which may be a reflection of the fact that iC₄ and nC₄ at high-maturity degree have different precursors (kerogen, the NSO (nitrogen, sulfur, oxygen) compounds, C₁₅₊ saturates, C₁₅₊ aromatics, the C_6∼14 fraction, etc) (Hao and Zou, 2013; Hill et al., 2003).

Discussion

Mechanism of iC₄/nC₄ ratio changing with the maturity of gas source rocks

The iC₄/nC₄ ratios initially increase with increasing dryness, pass through a maximum around dryness = 0.94, and then decrease as dryness further increases both oil-type and coal-derived gas. That is to say, the iC₄/nC₄ ratio gradually increases with increasing R_o when the gas source rocks at relatively lower maturity, and only begins to decrease when the gas pool is close to a dry gas reservoir. Such a high dryness seems to mean that the iC₄/nC₄ ratios of natural gases begin to decrease only when the gas source rocks reach the metagenesis to form methane stage (R_o > 2.0%), which seems to be inconsistent with the maximum iC₄/nC₄ ratio around R_o = 1.0% or 1.2% (Figure 8). In fact, for thermally formed natural gas, the dry gas reservoir does not necessarily indicate the gas source rock has reached the metagenesis to form methane stage. Dai et al. (2016) discovered that the wetness of natural gas decreases with the maturity of source rock based on 49 coal-derived gas samples from the Ordos, Sichuan, Bohai Bay, Qiongdongnan, Junggar, and Turpan-Hami Basins in China with integral molecular series. The relationship between wetness and maturity of coal-generated gas in China can be concluded as follows

R_{o} = - 0. 419ln W + 1.908

(7)

When the dryness is 94% (that is, the wetness is 6%), the calculated R_o of gas source rock is 1.18% based on the relationship between wetness and maturity of coal-derived gas (equation (7)), indicating the gas source rocks just reach the late oil generation stage or the early “wet gas” and condensate stages. This is consistent with the R_o ≈ 1.2% when iC₄/nC₄ ratios of coal-derived gas reach the maximum in this paper. Therefore, what can be illustrated is that during the “wet gas” and condensate stage of gas source rocks, the iC₄/nC₄ ratios of natural gases begin to decrease with the increasing R_o.

The corresponding R_o value is different when the iC₄/nC₄ ratios of two different types of gases reach their maximum values, which may be on account of different types of kerogens. Primary cracking of kerogen and secondary cracking of oil are dynamic processes (Hao and Zou, 2013; Hill et al., 2003). The hydrocarbon generation model of source rock emphasizes that kerogen form liquid oil and gas by thermal degradation at lower maturity, and then liquid hydrocarbon cracking generates the gas at higher maturity (Tissot and Welte, 1984). Previous studies have summarized the changes of liquid hydrocarbons generated by different kerogen types with increasing maturity by hydrous pyrolysis simulation and comparing the maturity parameters and composition characteristics of different kerogen types (Law, 1999; Mao et al., 2012; Qi et al., 2017). As for types II and III kerogen, the liquid hydrocarbons begin to form wet gases by thermal cracking when the R_o is about 1.0% and 1.2%, respectively (Law, 1999; Mao et al., 2012; Qi et al., 2017; Tissot and Welte, 1984). The iC₄/nC₄ ratios of gases, mainly produced by type II kerogens from Mississippian Barnett Shale in the Fort Worth Basin, change from increase to decrease gradually when the R_o is about 1.0% (that is, the timing of the liquid hydrocarbon begins to form wet gas for type II kerogen) (Figure 8). In addition, the iC₄/nC₄ ratios of gases, mainly produced by type III kerogens from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin, Triassic Xujiahe Formation in central Sichuan Basin, and C–P in Sulige and Yulin gas field, Ordos Basin, reach exactly the inflection point when the R_o is about 1.2% (that is, the timing of the liquid hydrocarbon begins to form wet gas for type III kerogen). Therefore, diverse types of kerogen may be responsible for the different corresponding R_o values when the iC₄/nC₄ ratios of gases reach their maximum values. Moreover, it also indicates that the iC₄/nC₄ ratios initially increase during the stage of primary cracking of kerogen, and then decrease during the stage of secondary cracking of liquid hydrocarbons.

The C_2–5 fraction precursors include C₁₅₊ saturates, C₁₅₊ aromatics (including alkyl aromatics), the C_6–14 fraction and perhaps the NSO compounds based on the accumulation of C_2–5 during C₁₅₊ cracking and C_6–14 cracking (Hill et al., 2003). As far as the formation process of nC₄ and iC₄ is concerned, nC₄ were formed through free radical reactions, whereas the branched iC₄ arose from the free radical cracking of branched fragments of kerogen and bitumens, and/or carbonium ion reaction of α-olefins with protons which were enhanced in acidic conditions (Almon and Johns, 1977; Eisma and Jurg, 1969; Kissin, 1987, Pan et al., 2006). That is, iC₄/nC₄ ratio is controlled by the kerogen nature (relative content of straight chain fragments to branched fragments) and the result of competition between free radical reaction of n-alkenes to form nC₄ and the carbonium ion reaction of n-alkenes with protons to form iC₄ (Hao and Zou, 2013; Pan et al., 2006). Therefore, as for the same type of natural gas (coal-derived gas or oil-type gas), iC₄/nC₄ ratio is mainly controlled by the latter. Free radical reactions to form n-alkenes is dominated during the thermal cracking of crude oil (Hao and Zou, 2013), which means that the initial increase in iC₄/nC₄ ratio with increasing R_o is related to kerogen cracking. In addition, the increases in iC₄/nC₄ ratio may result from two factors: (1) iC₄ is generated at a higher rate than nC₄ or (2) iC₄ is cracked at a lower rate than nC₄ (Hao and Zou, 2013; Hill et al., 2003; Pan et al., 2006). According to their molecular structures and chemical properties, the carbon and hydrogen content of the isomers are the same; however, iC₄ has a more active tertiary carbon, whereas nC₄ has only primary and secondary carbon with relatively weak chemical properties, so the nC₄ is less stable than iC₄ (He et al., 2015; Hill et al., 2003). In addition, the carbon–carbon bond breaking is dominated when the nC₄ and the iC₄ molecule are subjected to thermal cracking. The energy required for the breaking of carbon–carbon bond in the former (383 kJ/mol) is larger than the latter (355 kJ/mol) (Hao et al., 2013), indicating iC₄ is more prone to pyrolysis than nC₄. Therefore, the initial increase in iC₄/nC₄ ratios with increasing R_o is the reason that iC₄ is generated at a higher rate during kerogen cracking. Similarly, the terminal decreases in iC₄/nC₄ ratios also may result from two factors: (1) nC₄ is generated at a higher rate or (2) iC₄ is cracked at a higher rate. Free radical reactions to form nC₄, dominated during the thermal cracking of crude oil (Hao and Zou, 2013), may cause a higher nC₄ generation rate. Moreover, iC₄ is cracked at a higher rate during the wet gas cracking because iC₄ is more prone to pyrolysis than nC₄. Therefore, the superposition effect of these two aspects may result in the terminal faster decreases in iC₄/nC₄ ratios with further increasing dryness (Figure 7).

In a word, the evolution of the iC₄/nC₄ ratios in gases has two stages, that is, iC₄/nC₄ ratio initially increases and then decreases with increasing R_o both coal-type gas and oil-type gas. The initial increase iC₄/nC₄ ratios with increasing R_o is the reason that iC₄ is generated at a higher rate by carbonium ion reaction of α-olefins with protons during primary cracking of kerogen at lower maturity, whereas free radical reactions to form nC₄ during the thermal cracking of crude oil at higher maturity, and iC₄ is cracked at a higher rate during the wet gas cracking stage may results in the terminal decreases in iC₄/nC₄ ratio.

The causes of controversial views about the evolution of the iC₄/nC₄ ratios

In previous studies, two conflicting conclusions existed, which were: (a) the iC₄/nC₄ ratio in natural gas increases with increasing maturity (Qin et al., 2019) and (b) decreases with increasing maturity (Gao et al., 1998; He et al., 2015; Héroux et al., 1979;Wang et al., 2017; Xie et al., 2017). In this paper, the correlations between iC₄/nC₄ ratios and corresponding maturity data of gas source rocks in these studies are reanalyzed (Figure 9). Qin et al. (2019) selected coal-derived gases from Xujiahe Formation in central Sichuan Basin to reveal the relationship between the iC₄/nC₄ ratios and the maturity values of source rocks. The gases were generated from the source rocks at the thermal evolution stages of oil generation and “wet gas” stage (R_o = 0.86%–1.23%), so it is concluded that the iC₄/nC₄ ratio is positively correlated with increasing R_o (the solid line in Figure 9(a)). However, it is not difficult to find that the iC₄/nC₄ ratios have a decreasing tendency around R_o = 1.2%. If there were some gas samples produced by source rocks at higher maturity, the decreasing tendency of the iC₄/nC₄ ratios may be revealed (the dotted line in Figure 9(a)). On the contrary, He et al. (2015) selected coal-derived gases from Cretaceous and Tertiary in Kuqa Depression, Tarim Basin to analyze the relationship between the iC₄/nC₄ ratios and R_o of gas source rocks. The gases were generated from the source rock at the thermal evolution stages of “wet gas” and metagenesis to form methane stage (R_o = 1.33%–2.50%) (Figure 9(b)), so it is concluded that the iC₄/nC₄ ratio is negatively correlated with increasing R_o. In addition, Gao et al. (1998) attempted to reveal the evolution characteristics of gaseous products of mature humic coal (R_o is about 0.9%) by hydrous pyrolysis. The calculated R_o using the simulation temperatures by Easy%R_o model (Burnham and Sweeney, 1989) in the simulation experiment is 1.07%, 1.28%, 1.36%, and 1.66%, respectively. The results show that the iC₄/nC₄ ratios of gases generated by coal decrease with increasing R_o (the solid line in Figure 9(c)). Selected mature humic coal samples and a few simulation temperature points may be responsible for the lopsided conclusion. If low-maturity samples are selected and different simulation temperature points are added, the whole evolution of the iC₄/nC₄ ratios—“increase initially and then decrease”—may be revealed (the dotted line in Figure 9(c)). Therefore, the gases at narrow evolution stages of the iC₄/nC₄ ratios selected by previous scholars may be responsible for the controversial views.

Figure 9.

The relationship between iC₄/nC₄ ratios of gases and R_o of source rocks. The iC₄/nC₄ ratio increases with the R_o (a) and (b), and decreases with the R_o (c).

Chemical composition analysis of natural gas is usually the primary procedure of natural gas analysis, and is also a basic and important analysis project that can be implemented in the oil and gas field (Dai et al., 2016). The study of the iC₄/nC₄ ratios may be a potentially significant and effective approach to deepen natural gas research. The maturity of gas source rock can be obtained quickly based on the model using the iC₄/nC₄ ratios combined with other component information (such as dryness, wetness, etc.), which is of great significance to the characterization of natural gas maturity and gas source rock correlation. Of course, several aspects should be cautious when the method is applied in a gas reservoir/field. Previous studies have shown that the iC₄/nC₄ ratio in natural gas is also influenced by several factors such as the type of source rock, obvious migration fractionation, biodegradation or oxidation in addition to maturity of source rock (Boreham and Edwards, 2008; He et al., 2015; Katz et al., 2002; Miao et al., 2011; Pan et al., 2006; Qin et al., 2019; Wang et al., 2017; Wood and Sanei, 2016). Therefore, it may get more deviation and even wrong results using this method to estimate the maturity of natural gas when the gas reservoir suffers from one or more of the above secondary processes. So, before estimating natural gas maturity, it is very important to analyze the geological and geochemical background of the study area to avoid the influence of secondary processes. In addition, it should be pointed out that the maturity of the natural gas in this paper is mainly calculated by the empirical model, which is established based on the relationship between the δ¹³C₁ of oil-type, coal-derived gas and R_o of source rock and the geological characteristics of the gas fields (Dai, 1992; Stahl and Carey, 1975). The empirical models, including other established models (Liu and Xu, 1999; Schoell, 1983; Shen et al., 1991), have already been widely applied in natural gas maturity estimation, and they are still the common research methods on natural gas research at present. However, there is no denying that these models have inherent limitations (Prinzhofer et al., 2001; Shuai et al., 2003): (1) only applicable to local basins and (2) not considering the influences of various secondary processes. Therefore, it should be pointed out that the mathematical model for estimating natural gas maturity using the iC₄/nC₄ ratio in this study is also only applicable to local basins, i.e. not applicable to all gas reservoirs in any basin. If the analyzed gas reservoirs meet the following two conditions: (1) no obvious secondary process and (2) a relatively clear relationship between δ¹³C₁ and R_o of source rocks, then, the relationship between iC₄/nC₄ ratio and the R_o can be established relatively accurately to estimate natural gas maturity. In any case, this study provides a method for estimating maturity using natural gas components, which may be a potentially significant and effective approach to deepen natural gas research. Clearly, more work is called for in elucidating the relationship of iC₄/nC₄ ratios and maturity of gas source rocks to provide a quick and effective method to estimate the maturity of natural gas.

Conclusions

The iC₄/nC₄ ratios initially increase with increasing R_o of gas source rocks, and then decrease as R_o further increases both oil-type and coal-derived gas. Diverse types of kerogen may be responsible for the different corresponding R_o values when the iC₄/nC₄ ratios of gases reach their maximum values.

The initial increase in iC₄/nC₄ ratios with increasing R_o is the reason that iC₄ is mainly generated at a higher rate by carbonium ion reaction of α-olefins with protons during kerogen cracking, whereas free radical reactions to form nC₄ relatively quickly during the thermal cracking of crude oil at higher maturity and iC₄ is cracked at a higher rate during the wet gas cracking stage may result in the terminal decreases in is iC₄/nC₄ ratios.

The mathematical models of iC₄/nC₄ ratios of different types of natural gas and maturity are established. The maturity of gas source rock can be obtained quickly based on the model using the iC₄/nC₄ ratio combined with other component information (such as dryness, wetness, etc.), which is of great significance to the characterization of natural gas maturity and gas source rock correlation.

Supplemental Material

EEA880648 Supplemental Material - Supplemental material for Significance and evolution characteristics of the isobutane/n-butane ratio of natural gas

Supplemental material, EEA880648 Supplemental Material for Significance and evolution characteristics of the isobutane/n-butane ratio of natural gas by Nian Liu, Nansheng Qiu, Zhenming Li, Chuan Cai, Xinjie Shan, Ting Gao and Yuanjie Wang in Energy Exploration & Exploitation

Footnotes

Acknowledgements

We are grateful to collaboration and enthusiastic support from Jianzhang Tian and Jin Ming in the Huabei Research Institute of Petroleum Exploration and Exploitation and Zhili Zhu, Xinjian Zhu, and Shengbao Shi at the China University of Petroleum, Beijing.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research, authorship, and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research, authorship, and/or publication of this article: The authors gratefully acknowledge the supports from the National Major Science and Technology Projects of China (2017ZX05008-006–002-005) and the PetroChina Key Project (HBYT-YJY-2018-JS-177).

Supplemental Material

Supplemental material is available for this article online.

References

Almon

Johns

(1977) Petroleum-forming reactions. The mechanism and rate of clay catalyzed fatty acid decarboxylation. In: Campos

Goni

(eds) Advances in Organic Geochemistry 1975. Madrid, Spain: Enadimsa, pp. 157–172.

Bernard

Brooks

Sackett

(1978) Light hydrocarbons in recent Texas continental shelf and slope sediments. Journal of Geophysical Research 83(C8): 4053–4061.

Berner

Faber

(1988) Maturity related mixing model for methane, ethane and propane, based on carbon isotopes. Organic Geochemistry 13(1): 67–72.

Berner

Faber

(1996) Empirical carbon isotope/maturity relationships for gases from algal kerogens and terrigenous organic matter, based on dry, open-system pyrolysis. Organic Geochemistry 24(10–11): 947–955.

Boreham

Edwards

(2008) Abundance and carbon isotopic composition of neo-pentane in Australian natural gases. Organic Geochemistry 39(5): 550–566.

Bowker

(2007) Barnett Shale gas production, Fort Worth Basin: Issues and discussion. AAPG Bulletin 91(4): 523–533.

Burnham

Sweeney

(1989) A chemical kinetic model of vitrinite maturation and reflectance. Geochimica et Cosmochimica Acta 53(10): 2649–2657.

Chen

Jin

(2005) A novel approach for quantitative study on two-source-mixed natural gas reservoirs. Acta Sedimentologica Sinica 23(3): 554–558.

Chen

Zhu

Zhang

, et al. (2012) Control factors and diversities of phase state of oil and gas pools in the Kuqa petroleum system. Acta Geologica Sinica–English Edition 86(2): 484–496.

10.

Curtis

(2002) Fractured shale-gas systems. AAPG Bulletin 86(11): 1921–1938.

11.

Dai

(1992) Identification and distinction of various alkane gases. Science in China (Series B) 35(10): 1246–1257.

12.

Dai

(2018) Coal-derived gas theory and its discrimination. Chinese Science Bulletin 63(14): 1291–1305.

13.

Dai

Chen

Zhong

(2003) Large Gas Fields in China and Their Gas Sources. Beijing, China: Science Press, pp. 93–136.

14.

Dai

Gong

, et al. (2014a) Genetic types of the alkane gases in giant gas fields with proven reserves over 1000 × 10⁸ m³ in China. Energy Exploration & Exploitation 32(1): 1–18.

15.

Dai

Luo

, et al. (2005a) Stable carbon isotope compositions and source rock geochemistry of the giant gas accumulations in the Ordos Basin, China. Organic Geochemistry 36(12): 1617–1635.

16.

Dai JX, Ni YY, Hu GY, et al. (2014b) Stable carbon and hydrogen isotopes of gases from the large tight gas fields in China. Science China Earth Sciences 57(1): 88–103.

17.

Dai

Zou

(2012) Stable carbon and hydrogen isotopes of natural gases sourced from the Xujiahe Formation in the Sichuan Basin, China. Organic Geochemistry 43(2): 103–111.

18.

Dai

Huang

, et al. (2014c) Significant function of coal-derived gas study for natural gas industry development in China. Natural Gas Geoscience 25(1): 1–22.

19.

Dai

Zhang

, et al. (2016) Relationships between wetness and maturity of coal-derived gas in China. Petroleum Exploration and Development 43(5): 675–678.

20.

Dai

Zou

, et al. (2009) Stable carbon isotopes of alkane gases from the Xujiahe coal measures and implication for gas-source correlation in the Sichuan Basin, SW China. Organic Geochemistry 40(5): 638–646.

21.

Dai

Pei

(1992) China Natural Gas Geology, Vol. 1. Beijing, China: Petroleum Industry Press, pp. 5–146.

22.

Dai

Wang

(2001) Geochemical Features of Hydrocarbon from Coal-Measure, Formation and Resource Evaluation of Coal-Formed Gas Reservoir in China. Beijing, China: Petroleum Industry Press, pp. 1–159.

23.

Dai

Qin

Tao

, et al. (2005b) Developing trends of natural gas industry and the significant progress on natural gas geological theories in China. Natural Gas Geoscience 16(2): 127–142.

24.

Eisma

Jurg

(1969) Fundamental aspects of the generation of petroleum. In: Eglinton

Murphy

MTJ

(eds) Organic Geochemistry, Methods and Results. Berlin, Germany: Springer-Verlag, pp. 675–698.

25.

Ewing

(2006) Mississippian Barnett Shale, Fort Worth Basin, North-Central Texas: Gas-shale play with multi-trillion cubic foot potential: Discussion. AAPG Bulletin 90(6): 963–966.

26.

Faber

Gerling

Dumke

(1988) Gaseous hydrocarbons of unknown origin found while drilling. Organic Geochemistry 13(4/5/6): 875–879.

27.

Feng

Liu

Huang

, et al. (2016) Geochemical characteristics and genesis of natural gas in the Yan’an gas field, Ordos Basin, China. Organic Geochemistry 102: 67–76.

28.

Wang

Wei

, et al. (2005) Origin and characteristics of quartz-sandstone reservoir of the Yulin gas field, Ordos Basin. Petroleum Exploration and Development 32(1): 30–32.

29.

Galimov

(2006) Isotope organic geochemistry. Organic Geochemistry 37(10): 1200–1262.

30.

Gang

Gao

Hao

, et al. (1997) Carbon isotope of ethane applied in the analyses of genetic types of natural gas. Experimental Petroleum Geology 19(2): 164–167.

31.

Gao

Gang

Hao

, et al. (1998) The evolution characteristics of gaseous products of humic coal and it’s geological significance. Acta Sedimentologica Sinica 16(2): 30–41.

32.

Guo

Liu

Jia

, et al. (2016) Fluid evolution in the Dabei Gas Field of the Kuqa Depression, Tarim Basin, NW China: Implications for fault-related fluid flow. Marine and Petroleum Geology 78: 1–16.

33.

Hao

Zou

(2013) Cause of shale gas geochemical anomalies and mechanisms for gas enrichment and depletion in high-maturity shales. Marine and Petroleum Geology 44: 1–12.

34.

Hao

Zhang

, et al. (2013) Molecular simulationon pyrolysis mechanism of butane. Acta Petrolei Sinica 29(5): 824–829.

35.

Chen

Liu

, et al. (2015) Significance and geochemical characteristics of butane in coal gas: An example from the Kuqa Depression, Tarim Basin. Bulletin of Mineralogy, Petrology and Geochemistry 34(5): 987–992.

36.

Héroux

Chagnon

Bertrand

(1979) Compilation and correlation of major thermal maturation indicators. AAPG Bulletin 63: 2128–2144.

37.

Hickey

Henk

(2007) Lithofacies summary of the Mississippian Barnett Shale, Mitchell 2 T.P. Sims well, Wise County, Texas. AAPG Bulletin 91(4): 437–443.

38.

Hill

Jarvie

Zumberge

, et al. (2007a) Oil and gas geochemistry and petroleum systems of the Fort Worth Basin. AAPG Bulletin 91(4): 445–473.

39.

Hill

Tang

Kaplan

(2003) Insights into oil cracking based on laboratory experiments. Organic Geochemistry 34: 1651–1672.

40.

Hill

Zhang

Katz

, et al. (2007b) Modeling of gas generation from the Barnett Shale, Fort Worth Basin, Texas. AAPG Bulletin 91(4): 501–521.

41.

, et al. (2010b) Composition and carbon isotopic distribution characteristics of light hydrocarbon in coal-derived gas and natural gas exploration. Acta Petrolei Sinica 31(1): 42–48.

42.

Shan

, et al. (2010a) The origin of natural gas and the hydrocarbon charging history of the Yulin gas field in the Ordos Basin, China. International Journal of Coal Geology 81(4): 381–391.

43.

Tian

(2014) The origin of abnormally high benzene in light hydrocarbons associated with the gas from the Kuqa depression in the Tarim Basin, China. Organic Geochemistry 74: 98–105.

44.

Jarvie

Hill

Ruble

, et al. (2007) Unconventional shale-gas systems: The Mississippian Barnett Shale of north–central Texas as one model for thermogenic shale-gas assessment. AAPG Bulletin 91(4): 475–499.

45.

Jenden

Kaplan

Poreda

, et al. (1988) Origin of nitrogen-rich natural gases in the California Great Valley: Evidence from helium, carbon and nitrogen isotope ratios. Geochimica et Cosmochimica Acta 52: 851–861.

46.

Jin

Chen

Liu

(2004) Research in gas accumulations with mixed sources. Journal of the University of Petroleum, China 28(6): 11–16.

47.

Katz

Narimanov

Huseinzadeh

(2002) Significance of microbial processes in gases of the South Caspian basin. Marine and Petroleum Geology 19(6): 783–796.

48.

Kissin

(1987) Catagenesis and composition of petroleum: Origin of n-alkanes and isoalkanes in petroleum crudes. Geochimica et Cosmochimica Acta 51(9): 2445–2457.

49.

Kotarba

Lewan

(2013) Sources of natural gases in Middle Cambrian reservoirs in Polish and Lithuanian Baltic Basin as determined by stable isotopes and hydrous pyrolysis of Lower Palaeozoic source rocks. Chemical Geology 345: 62–76.

50.

Law

(1999) Evaluating source rocks. In: Beaumont

Foster

(eds) Exploring for Oil and Gas Traps. Tulsa, OK: AAPG, pp. 1–41.

51.

Wang

, et al. (2007) Genetic type and source of gas in the Guang’an gas field, central Sichuan. Geology in China 34(5): 829–836.

52.

Jiang

, et al. (2014) Palaeo-fluid evidence for the two-stage hydrocarbon charges in Dibei gas reservoir of Kuqa Depression. Natural Gas Geoscience 25(7): 1033–1041.

53.

Jiang

, et al. (2015) Enriched mechanism of natural gas of Lower Jurassic in Dibei Area, Kuqa Depression. Earth Science 40(9): 1538–1548.

54.

, et al. (2018) Characteristics and genetic types of the Lower Paleozoic natural gas, Ordos Basin. Marine and Petroleum Geology 89: 106–119.

55.

Feng

, et al. (2012a) Geochemistry of natural gas accumulation in Sulige large gas field in Ordos Basin. Acta Petrologica Sinica 28(3): 836–846.

56.

Wang

, et al. (2012b) Charging migration and accumulation characteristics of natural gas in Sulige low permeability sandstone large gas field. Geological Science and Technology Information 31(3): 55–62.

57.

Liang

Zhang

Chen

, et al. (2003) Organic geochemistry of oil and gas in the Kuqa depression, Tarim Basin, NW China. Organic Geochemistry 34(7): 873–888.

58.

Liu

, et al. (2007a) Geochemistry of natural gas and crude computation of gas-generated contribution for various source rocks in Sulige gas field. Natural Gas Geoscience 18(5): 697–702.

59.

Liu

Qin

, et al. (2007b) Analysis on geochemistry and origin types of the natural gas in Kuqa Depression. Science in China (Series D) 37: 149–156.

60.

Liu

(1999) A two-stage model of carbon isotopic fractionation in coal-gas. Geochimica 28(4): 359–365.

61.

Loucks

Ruppel

(2007) Mississippian Barnett Shale: Lithofacies and depositional setting of a deep-water shale-gas succession in the Fort Worth Basin, Texas. AAPG Bulletin 91(4): 579–601.

62.

Liu

Zhuo

, et al. (2012) Palaeo-fluid evidence for the multi-stage hydrocarbon charges in Kela-2 gas field, Kuqa foreland basin, Tarim Basin. Petroleum Exploration and Development 39(5): 537–544.

63.

(2005) Natural gas exploration and development situation in Ordos Basin, NW China. Petroleum Exploration and Development 32(4): 12–14.

64.

Mao

Zhang

, et al. (2012) Study on the hydrocarbon generation characteristics of different coaly source rocks by gold-tube pyrolysis experiment. Natural Gas Geoscience 23(6): 1127–1134.

65.

Xiao

Liu

, et al. (2004) Palaeo–water and gas boundary in the late Paleozoic gas reservoir of Ordos Basin reconstructed using the information of fluid inclusion. Chinese Science Bulletin 9(2): 396–400.

66.

Miao

Chen

Guo

, et al. (2011) Geochemistical characteristics of butane gas in Tarim Basin. Journal of China University of Mining and Technology 40(4): 592–597.

67.

Montgomery

Jarvie

Bowker

, et al. (2005) Mississippian Barnett Shale, Fort Worth Basin, north-central Texas: Gas-shale play with multi–trillion cubic foot potential. AAPG Bulletin 89(2): 155–175.

68.

Pan

Liu

, et al. (2006) Chemical and carbon isotopic fractionations of gaseous hydrocarbons during abiogenic oxidation. Earth and Planetary Science Letters 246(1–2): 70–89.

69.

Philippi

(1975) The deep subsurface temperature controlled origin of the gaseous and gasoline-range hydrocarbons of petroleum. Geochimica et Cosmochimica Acta 39(10): 1353–1373.

70.

Pollastro

(2007) Total petroleum system assessment of undiscovered resources in the giant Barnett Shale continuous (unconventional) gas accumulation, Fort Worth Basin, Texas. AAPG Bulletin 91(4): 551–578.

71.

Pollastro

Jarvie

Hill

, et al. (2007) Geologic framework of the Mississippian Barnett Shale, Barnett-Paleozoic total petroleum system, Bend arch-Fort Worth Basin, Texas. AAPG Bulletin 91(4): 405–436.

72.

Price

Schoell

(1995) Constraints on the origins of hydrocarbon gas from compositions of gases at their site of origin. Nature 378(6555): 368–371.

73.

Prinzhofer

Huc

(1995) Genetic and post-genetic molecular and isotopic fractionations in natural gases. Chemical Geology 126(3–4): 281–290.

74.

Prinzhofer

Mello

Takaki

(2001) Geochemical characterization of natural gas: A physical multivariable approach and its applications in maturity and migration estimates: Reply. AAPG Bulletin 85(12): 2114–2117.

75.

, et al. (2017) Comparative research on the yields and chemical of light hydrocarbons derived from pyrolysis of organic matters with different types. Natural Gas Geoscience 28(6): 975–986.

76.

Qin

Huang

Sun

, et al. (2019) Relationships of the iC₄/nC₄ and iC₅/nC₅ ratios with maturity of coal-derived gases of Xujiahe Formation in central Sichuan Basin, NW China. Petroleum Exploration and Development 46(3): 1–8.

77.

Qin

, et al. (2018b) Formation mechanism of tight coal-derived-gas reservoirs with medium-low abundance in Xujiahe Formation, central Sichuan Basin, China. Marine and Petroleum Geology 89: 144–154.

78.

Qin

Yuan

, et al. (2018c) Geochemical tracing of tight gas migration in Xujiahe Formation in central Sichuan Basin. Journal of China Coal Society 43(11): 3178–3186.

79.

Qin

Zhang

Zhao

, et al. (2018a) Geochemical evidence for in situ accumulation of tight gas in the xujiahe formation coal measures in the central Sichuan Basin, China. International Journal of Coal Geology 196: 173–184.

80.

Rodriguez

Philp

(2010) Geochemical characterization of gases from the Mississippian Barnett shale, Fort Worth basin, Texas. AAPG Bulletin 94(11): 1641–1656.

81.

Schoell

(1983) Genetic characterization of natural gases. AAPG Bulletin 67(12): 2225–2238.

82.

Sechman

Kotarba

Dzieniewicz

, et al. (2017) Evidence of methane and carbon dioxide migration to the near surface zone in the area of the abandoned coal mines in Wałbrzych District (lower Silesian Coal Basin, SW Poland) based on periodical changes of molecular and isotopic compositions. International Journal of Coal Geology 183: 138–160.

83.

Shen

Wang

, et al. (1991) Studies on Geochemical Characteristics of Gas-Source Rock and Natural Gas and Mechanism of Genesis of Gas. Lanzhou, China: Gansu Science and Technology Press, pp. 120–121.

84.

Shi

(2000) Coal-Formed Hydrocarbon Geological and Geochemical Characteristics in Kuqa Depression, Tarim Basin. Beijing, China: PetroChina Research Institute of Petroleum Exploration and Development, pp. 23–24.

85.

Shuai

Zhang

, et al. (2013) Charging time of tight gas in the Upper Paleozoic of the Ordos Basin, central China. Organic Geochemistry 64: 38–46.

86.

Shuai

Zou

Peng

(2003) Kinetic model for the stable carbon isotope of methane: The state of the art. Advance in Earth Sciences 18(3): 405–411.

87.

Stahl

(1977) Carbon and nitrogen isotopes in hydrocarbon research and exploration. Chemical Geology 20: 121–149.

88.

Stahl WJ and Carey BD (1975) Source-rock identification by isotope analyses of natural gases from fields in the Val Verde and Delaware basins, West Texas. Chemical Geology 16: 257–267.

89.

Sun

Wei

, et al. (2018) Restore the hydrocarbon charge history by using fluid history analysis techniques in Dabei Gas Field, Kuqa Depression, Tarim Basin. Natural Gas Geoscience 29(9): 1289–1300.

90.

Tang

Yang

(2014) Thermal and maturation history of Jurassic source rocks in the Kuqa foreland depression of Tarim Basin, NW China. Journal of Asian Earth Sciences 89: 1–9.

91.

Tao

Zou

, et al. (2014) Geochemical comparison between gas in fluid inclusions and gas produced from the Upper Triassic Xujiahe Formation, Sichuan Basin, SW China. Organic Geochemistry 74: 59–65.

92.

Tao

Zou

Tao

, et al. (2009) Study on fluid inclusion and gas accumulation mechanism of Xujiahe Formation of Upper Triassic in the Central Sichuan Basin. Bulletin of Mineralogy Petrology and Geochemistry 28(1): 2–11.

93.

Thompson

KFM

(1983) Classification and thermal history of petroleum based on light hydrocarbons. Geochimica et Cosmochimica Acta 47(2): 303–316.

94.

Tissot

Welte

(1984) Petroleum Formation and Occurrence, 2nd ed. Berlin, Germany: Springer-Verlag, pp. 69–130.

95.

Wang

Shen

, et al. (2017) The geochemical characteristics of butane and its application. Natural Gas Geoscience 28(4): 529–538.

96.

Wang

Huang

Gong

, et al. (2013) Geochemical characteristics of natural gases in the Upper Triassic Xujiahe Formation in the southern Sichuan Basin, SW China. International Journal of Coal Geology 120: 15–23.

97.

Wei

Sun

, et al. (2019) Geochemical characteristics of deep-seated natural gas accumulation of the Keshen large gas field in the Kuqa Depression, Tarim Basin. Natural Gas Geoscience 30(6): 897–907.

98.

Whiticar

(1999) Carbon and hydrogen isotope systematics of bacterial formation and oxidation of methane. Chemical Geology 161(1–3): 291–314.

99.

Wood

Sanei

(2016) Secondary migration and leakage of methane from a major tight-gas system. Nature Communications 7: 1–9.

100.

Xie

Shen

Wang

, et al. (2017) Geochemical characteristics of butane of natural gas in West Sichuan Depression, China. Journal of Chengdu University of Technology 44(4): 435–441.

101.

, et al. (2011) Tectonic units division and natural gas exploration in the Kuqa Depression, Tarim Basin. Natural Gas Industry 31(3): 31–36.

102.

Yang

Wang

Huang

, et al. (2009) Features of source rocks in the Xujiahe Formation at the transitional zone of central southern Sichuan Basin. Natural Gas Industry 29(6): 27–30.

103.

Huang

Gong

, et al. (2013) Partial reversal cause of carbon and hydrogen isotope compositions of natural gas: A case study in Sulige gas field, Ordos Basin. Acta Petrolei Sinica 34(S1): 92–101.

104.

Liu

Zhao

, et al. (2017) Petrological record of hydrocarbon accumulation in the Kela-2 gas field, Kuqa Depression, Tarim Basin. Journal of Natural Gas Science and Engineering 41: 63–81.

105.

Zhang

Zhu

, et al. (2011) Geochemical evidence for coal-derived hydrocarbons and their charge history in the Dabei Gas Field, Kuqa Thrust Belt, Tarim Basin, NW China. Marine and Petroleum Geology 28(7): 1364–1375.

106.

Zhang

(2013) The Formation Conditions of Gas Reservoiring in the Xujiahe Formation in Central Sichuan Basin. Sichuan, China: Chengdu University of Technology, pp. 18–19.

107.

Zhang

Horst

Liu

, et al. (2014) Perspective on the K/Ar and Ar/Ar geochronology of authigenic illites: A case study from the Sulige gas field, Ordos Basin. Acta Petrolei Sinica 35(3): 407–416.

108.

Zhang

Tao

Liu

, et al. (2015) Authigenic illite age and hydrocarbon accumulation time in Xujiahe Formation sand stone reservoirs (Upper Triassic), Sichuan Basin. Acta Ptrolei Sinica 36(11): 1367–1379.

109.

Zhao

Zhang

, et al. (2014) Genesis of tight sand gas in the Ordos Basin, China. Organic Geochemistry 74: 76–84.

110.

Zhao

Wang

Zhang

, et al. (2005) Accumulation and features of natural gas in the Kuqa foreland basin. Acta Geologica Sinica 79(3): 414–422.

111.

Zhao

Behr

Ahrendt

, et al. (1996) Thermal and tectonic history of the Ordos Basin, China: Evidence from apatite fission track analysis, vitrinite reflectance, and K-Ar dating. AAPG Bulletin 80(7): 1110–1133.

112.

Zhao

Wang

Yuan

, et al. (2010) Petroleum systems of Chinese nonmarine basins. Basin Research 22(1): 4–16.

113.

Zhong

Chen

(2002) Controlling Factors of Gas Oil Ratio Distribution in Coal Measures and the Relationship with Giant Gas Fields. Beijing, China: Petroleum Industry Press, pp. 15–155.

114.

Zhu GY, Chi LX, Zhang ZY, et al. (2019) Composition and origin of molecular compounds in the condensate oils of the Dabei gas field, Tarim Basin, NW China. Petroleum Exploration and Development 46(3): 482–495.

115.

Zhu

Yang

Zhang

, et al. (2012) The geological feature and origin of Dina 2 large gas field in Kuqa Depression, Tarim Basin. Acta Petrologica Sinica 28(8): 2479–2492.

116.

Zou

Zhao

Wang

, et al. (2006) Characteristics and origin of natural gases in the Kuqa Depression of Tarim Basin, NW China. Organic Geochemistry 37(3): 280–290.

117.

Zumberge

Ferworn

Brown

(2012) Isotopic reversal (‘rollover’) in shale gases produced from the Mississippian Barnett and Fayetteville formations. Marine and Petroleum Geology 31: 43–52.

Supplementary Material

Please find the following supplemental material available below.

For Open Access articles published under a Creative Commons License, all supplemental material carries the same license as the article it is associated with.

For non-Open Access articles published, all supplemental material carries a non-exclusive license, and permission requests for re-use of supplemental material or any part of supplemental material shall be sent directly to the copyright owner as specified in the copyright notice associated with the article.

0.00 MB

0.70 MB

Significance and evolution characteristics of the isobutane/n-butane ratio of natural gas

Abstract

Keywords

Introduction

Geological and geochemical backgrounds of the samples

Geochemical characteristics and genesis of natural gas

Chemical and isotopic compositions of natural gas

Genetic types of natural gas

The iC4/nC4 ratio characteristics of natural gas

The relationship between iC4/nC4 ratio and dryness of natural gas

The relationship between iC4/nC4 ratio and maturity of gas source rock

Discussion

Mechanism of iC4/nC4 ratio changing with the maturity of gas source rocks

The causes of controversial views about the evolution of the iC4/nC4 ratios

Conclusions

Supplemental Material

EEA880648 Supplemental Material - Supplemental material for Significance and evolution characteristics of the isobutane/n-butane ratio of natural gas

Footnotes

Acknowledgements

Declaration of conflicting interests

Funding

Supplemental Material

References

Supplementary Material

The iC₄/nC₄ ratio characteristics of natural gas

The relationship between iC₄/nC₄ ratio and dryness of natural gas

The relationship between iC₄/nC₄ ratio and maturity of gas source rock

Mechanism of iC₄/nC₄ ratio changing with the maturity of gas source rocks

The causes of controversial views about the evolution of the iC₄/nC₄ ratios