The southern margin of the Junggar Basin refers to the piedmont thrust belt in North Tianshan, that is the Northern Tianshan Mountain piedmont thrust belt, with an area of 2.1×10⁴ km² and a maximum sedimentary formation thickness up to 15 km. With many structural traps and most active oil and gas shows, and crude oil and natural gas discovered in many anticline structures^{[1,2,3,4,5,6,7,8]}, it is regarded as the area with the highest potential for natural gas exploration in the basin^[9,10,11,12]. However, there have been no major breakthroughs there, despite decades of exploration. Only two medium-sized gas fields are found in the Hutubi and Manas anticlines in the middle of the southern margin. But recently, Well Gaotan-1 drilled in the Gaoquan anticline of Sikeshu sag in the west of southern margin tested a high oil and gas flow of 1 213 m³ oil and 32.17×10⁴ m³ gas a day at the bottom of Cretaceous Qingshuihe Formation. This well is the well with highest oil and gas production so far in Junggar Basin, heralding bright oil and gas exploration prospects of the southern margin area. Geochemical characteristics and source of discovered natural gas in the southern margin were examined before^[1,7,13-19]. It was concluded that the natural gas in this area was basically coal-derived gas from the Jurassic coal-bearing source rocks. Nevertheless, one cannot help asking why natural gases are all derived from the Jurassic source rocks, since in fact five sets of source rocks are developed in the southern margin, namely Permian, Triassic, Jurassic, Cretaceous and Paleogene^[1-2,6]. According to the published literature, previous studies on the geochemical characteristics of natural gas in this area were not detailed enough, and there was no systematic comparison of the geochemical characteristics of natural gas in different structures. The genetic type and source identification are, somewhat, ambiguous, with no awareness of complexity with respect to natural gas genetic types and sources. On the basis of massive geochemical analyses of natural gas samples collected from the southern margin and other areas and latest data in Gaotan well 1, the composition and carbon and hydrogen isotopic characteristics of natural gas samples from different anticline structures are systematically investigated and compared to make clear the genetic types and sources of them, in an attempt to lay foundation for research of the natural gas accumulation in the southern margin and provide references for decision making during natural gas exploration.

The southern margin of the Junggar Basin ranges from the Fukang fault zone in the east to the Sikeshu sag in the west, with a length of 500 km, and north to the Shawan sag, Monan uplift and Fukang sag, south to the Northern Tianshan Mountain, with a width of 40-60 km. Tectonically, the study area belongs to the piedmont thrust belt of the Northern Tianshan Mountain (Fig. 1). On the basis of the formation mechanism and pattern of structures, the study area can be further divided into four secondary structural units^[20], namely the Sikeshu sag, Huomatu anticline zone, Qigu fault-fold zone and Fukang fault zone (Fig. 1). Across the Qigu fault-fold zone and Huomatu anticline zone, three rows of anticline structures are developed from south to north. The 1^st row includes the Tosta, Nananjihai, Honggou, Qingshuihe, Qigu anticlines, etc. The 2^nd row consists of the Horgos, Manas, Tugulu anticlines, etc. The 3^rd row is composed of the Anjihai, Huxi, and Hutubi anticlines, etc. By structural features and differences, the southern margin can be divided into three parts, namely the western, middle and eastern parts. The area on the west of the Dushanzi is classified as the western part; from the Dushanzi to the Urumqi, the middle part; on the east of Urumqi, the eastern part.

There are 7 sets of sedimentary strata, the Permian, Triassic, Jurassic, Cretaceous, Paleogene, Neogene and Quaternary in the southern margin. The maximum sedimentary formation thickness is up to 15 km in the middle part, while it is relatively thin in the western and eastern parts, but usually 8-12 km thick^[1-2,6,21]. The Lower Permian in the southern margin is mainly a set of coarse clastic sediments. The Middle Permian is a set of semi-deep and deep lacustrine facies sediments with a thickness of 600-1 600 m, which is one of the most important source rocks in this area, and oil shale in the Lucaogou Formation is extensively developed in the eastern part. The Upper Permian is mostly composed of fluvial-semi-deep lacustrine deposits. The Middle-Lower Triassic is mainly fluvial-shallow lake coarse clastic deposits, while the Upper Triassic consists of shore-shallow lake and semi-deep lacustrine sediments, interbedded by thin layers of swamp facies carbonaceous mudstone and coal seams, with a total thickness of 300-800 m. The Upper Triassic source rocks are relatively developed in the middle part of the southern margin and the Fukang sag. The Middle-Lower Jurassic, including the Badaowan (J₁b), Sangonghe (J₁s), Xishanyao (J₂x) and Toutunhe (J₂t) formations, is a set of fluvial-swamp and lacustrine-swamp facies coal-bearing sediments. It has thickness generally ranging from 1 000 m to 2 000 m, and is one of the major source rocks in this area. The Upper Jurassic Qigu and Keraza formations are a suite of red coarse clastic deposits. The Lower Cretaceous is a set of shallow lake semi-deep lake facies sediments with a maximum thickness of 1 594 m, in which the dark strata are better developed in the middle part of the southern margin. The Upper Cretaceous is mainly composed of fluvial coarse clastic sediments. The Paleocene-Eocene is fluvial-shallow lake sediments, and the Eocene-Oligocene Anjihaihe Formation is generally made up of shallow lake to deep lake facies sediments, which is seen with extensive development of dark shale in the western part of the southern margin. The Oligocene-Pliocene is mainly dominated by shallow lake facies and fluvial facies sediments. The Quaternary Xiyu Formation is composed of the piedmont pluvial-alluvial fan-fluvial conglomerate and glutenite sediments.

Natural gas has been discovered in many anticline structures in the southern margin^{[1,2,3,4,5,6,7,8]}, but commercial gas fields only include the Hutubi and Mahe gas fields in the middle part (Fig. 1), the Mazhuang gas field is a small gas field in the Santai region of the eastern part. The natural gas discoveries in other structures are mostly small-scale gas reservoirs revealed by wildcat wells or associated gas of oil reservoirs^[1]. In these gas fields or gas-bearing anticlines, the natural gas for anticlines in the middle part is mainly accumulated in the Paleogene (Table 1), except for the Nananjihai and Qigu anticlines, where the natural gas is contained in the Jurassic and the Triassic-Jurassic. In the western part, oil and gas in the Dushanzi anticline are mostly accumulated in the Neogene, while in the Kaindick, Xihu, Gaoquan anticlines, they are contained in reservoirs from the Upper Jurassic Qigu Formation to the bottom of the Lower Cretaceous Qingshuihe Formation. In the eastern part, natural gas in the Mazhuang gas field is primarily reservoired in the Upper Jurassic.

The natural gas in the southern margin is dominated by hydrocarbon gases (Table 1), and the content is more than 90%, with an average of 96.75%. The other gases include nitrogen, accounting for 0.5% to 8.5%, with an average of 2.21%, followed by carbon dioxide, accounting for 0 to 2%, with an average of 0.18%. In the hydrocarbon gases, the different components vary greatly in content (Fig. 2). In most cases, methane accounts for 50%-99%, with an average of 83.27%. Ethane accounts for 0.2%-26% with the vast majority of 2%-15% and an average of 8.46%. Propane accounts for 0.1%-18% (mostly 0.5%-8.0%), averaging 3.37%. As for butane, it ranges from 0 to 10% (mostly 0.2%-4.0%) with an average of 1.63%. In general, natural gas in this area is dominated by wet gas, with a few cases presenting dry gas.

It is seen that natural gas compositions of different structures in the southern margin have tremendous discrepancies (Table 1 and Fig. 2). The natural gas in the Mazhuang gas field, the Santai region of the eastern part has a high content of methane, typically up to 92%-95%, and is therefore classified as dry gas. The natural gas in the Nananjihai and Qigu anticlines, located in the 1^st row of anticline structures, contains more than 97% methane, with the dryness coefficient greater than 0.99, and is the driest of all natural gas in the southern margin. Also in the middle part, however, methane contents of natural gas in the anticlines in the 2^nd and 3^rd rows, namely the Anjihai, Horgos, Manas, Tugulu and Hutubi anticlines, are lower than that in the 1^st row, generally ranging from 50% to 95%, indicating wet gas. A visible regularity is found in the natural gas composition variation of these structures (Table 1 and Fig. 2), which can be stated as from west to east, methane contents gradually increase and contents of heavy hydrocarbon gas such as ethane and propane correspondingly decrease, resulting in a growing dryness coefficient. The natural gas in the Anjihai anticline has the lowest methane content and belongs to the wettest natural gas in the region, while natural gas in the Hutubi anticline has the highest methane content and is basically dry gas. In terms of the western part of the southern margin, methane contents generally lie between 70% and 90%, with dryness coefficients of 0.73-0.93, indicating dominance of wet gas. Among these anticlines, the natural gas from the oil and gas reservoir of the Qingshuihe Formation of Well Gaotan-1 at the Gaoquan anticline has methane contents of only 75.47%, ethane 13.36%, and propane and heavier hydrocarbon gas 9.84%, and the dryness coefficient of 0.77, indicating wet gas. For the natural gas in the Xihu anticline, methane contents exceed 88%, with 4%-7% of ethane and 0.1%-2.2% of propane. The natural gas produced from 4605-4609 m interval of Well Xi-5 presents a dryness coefficient of 0.90, indicating wet gas, while the gas from 6139 m of Well Xihu-1 has a dryness coefficient of 0.96, indicating dry gas.

The natural gas in the middle and western structures of the southern margin generally has heavy carbon isotope composition (Figs. 3 and 4), and tends to become heavier from west to east. The carbon isotope of methane (δ¹³C₁) ranges from -47‰ to -29‰, with most values from -42‰ to -31‰; the δ¹³C₂ value falls between -30‰ and -21‰, mostly between -28‰ and -22‰; the δ¹³C₃ value is distributed from -27‰ to -19‰, mostly between -25‰ and -20‰. The natural gas in the Santai region of the eastern part has light carbon isotope composition, with δ¹³C₁ value from -51‰ to -43‰, and most cases within the range between -48‰ and -43‰; δ¹³C₂ value from -33‰ to -25‰ and mostly between -33‰ and -28‰, which is apparently different from the natural gas samples from the middle and western parts.

In the middle part of the southern margin, the δ¹³C₁ value of natural gas in the Anjihai, Horgos and Manas anticlines mostly are between -35‰ and -33‰, with only a few less than -35‰; the δ¹³C₂ value is basically within the range from -24.0‰ to -22.5‰; and the δ¹³C₃ value is between -24‰ and -20‰ (Fig. 3b). The carbon isotope composition of the C₁ to C₄ alkane presents a normal positive-sequence distribution, namely δ¹³C₁<δ¹³C₂<δ¹³C₃<δ¹³C₄ (Fig. 4). The methane carbon isotope composition of natural gas from the Anjihai anticline is the lightest, followed by that of the Horgos anticline, and Manas anticline. The carbon isotope composition of natural gas samples from the Tugulu and Hutubi anticlines are basically the same, and considerably heavier than those from the Manas and Horgos anticlines, with δ¹³C₁ from -33‰ to -31‰, δ¹³C₂ value from -23‰ to -22‰; δ¹³C₃ value between -23‰ and -21‰. In some natural gas components above ethane or propane, butane carbon isotopes are reversed (Fig. 4). The natural gas samples from the Qigu anticline have a wide range of carbon isotope composition, with δ¹³C₁ value between -41‰ and -29‰; δ¹³C₂ value between -25‰ and -22‰; δ¹³C₃ value between -27.0‰ and -23.5‰; carbon isotopes of ethane, propane and butane are reversed (Fig. 4).

In the western part, the δ¹³C₁ value of natural gas in the Kaindick anticline is mainly about -35‰; the δ¹³C₂ value, around -26.5‰; the δ¹³C₃ value, about -24‰ (Fig. 3). However, the natural gas from the Jurassic Qigu reservoir at the 3956-3980 m interval of Well Ka-6 is somehow lighter, with the δ¹³C values for ethane and propane of -29.74‰ and -26.35‰, respectively (Fig. 3). For the natural gas contained in the Lower Cretaceous Qingshuihe oil and gas reservoir at the 5768-5775 m interval of Well Gaotan-1 at the Gaoquan anticline, the δ¹³C₁ value is -40.42‰; the δ¹³C values for ethane and propane are -28.94‰ and -26.72‰, respectively. The carbon isotopes of the C₁ to C₄ alkane also present a normal positive-sequence distribution, which is similar to that of the natural gas in the Qigu Formation of Well Ka-6 and yet different from those of other natural gas of the southern margin (Figs. 3 and 4). The carbon isotope composition of natural gas in the Xihu anticline is similar to most natural gases from the Kaindick oil and gas field, and yet the natural gas at 5992 m in Well Xihu-1 presents a relatively heavier carbon isotope composition. The case of the natural gas in the Dushanzi anticline is unique. The δ¹³C₁ value is between -43‰ and -35‰, while the δ¹³C₂ value is basically fixed around -26‰. Nevertheless, relatively large variation is seen in the δ¹³C₃ value, which lies between -26‰ and -19‰. Such features are clearly distinguished from other natural gas in the southern margin (Fig. 3b). In the western part, most of natural gas basically presents the normal positive-sequence distribution of the carbon isotope of components (Fig. 4), and only a small amount of natural gas has a slight reversal of the propane and butane carbon isotopic composition, which may be attributed to the low content of butane, relatively large analysis errors, high maturity or combination of the aforementioned.

For organic thermogenic natural gas, its composition and carbon and hydrogen isotopic compositions are closely related to the sedimentary environment, organic matter type and thermal evolution degree of the gas-generating organic matter. Therefore, carbon and hydrogen isotopes are often used to determine the genetic type and source of natural gas^{[25,26,27,28,29,30,31,32,33,34,35,36,37,38,39,40,41,42]}. In the southern margin, the C₁/(C₂+C₃) ratio of natural gas ranges from 2 to 500, with most values lying between 4 and 40. The δ¹³C₁ value of methane is seen from -51‰ to -28‰, mostly distributed within the range between -42‰ and -31‰, indicating organic thermogenic natural gas (Fig. 5a).

3.1.1. Identification based on natural gas composition and carbon isotope

Of the natural gas samples collected from the southern margin, those from the Kaindick, Xihu and Dushanzi anticlines in the Sikeshu sag have the lowest C₁/(C₂+C₃) value and the lightest methane carbon isotope composition, which is similar to the natural gas from the Middle and Lower Jurassic coal-bearing source rocks in the Taibei sag, Turpan Basin^[22,23] (or with slightly heavier methane carbon isotope composition). Most of the gas samples are thermogenic gas derived from Type-III kerogen, a few are thermogenic gas from Type-II kerogen. The natural gas from Well Gaotan-1 at the Gaoquan anticline has lighter methane carbon isotopic composition and very low C₁/(C₂+C₃) ratio, different from most natural gas samples from the western part (Fig. 5).

In addition, Dai et al.^[24] reveal that the δ¹³C₁ value of gas seeps in the surface mud volcano of the Dushanzi anticline and Maoyanshan structure is seen between -47‰ and -40‰, and the δ¹³C₂ value between -28‰ and -26‰. The carbon isotope composition of alkanes is characterized by δ¹³C₁< δ¹³C₂<δ¹³C₃, which demonstrates typical pattern of thermogenic coal-derived gas. However, the C₁/(C₂+C₃) ratios of these gas seeps are 10-20 (Fig. 5a), not only apparently different from the natural gas of exploration wells in Dushanzi and Kaindick anticlines, but also different from the natural gas of the Taibei sag in the Turpan Basin. They are found more similar to oil-associated gas from the Permian Fengcheng Formation in the northern part of the northwest margin^[1,7], and seem to be more like natural gas or mixed gas from Type-II organic matter, or coal-derived gas with lower maturity. Besides, one of these mud volcano gas seeps presents a C₁/(C₂+C₃) ratio high up to 255, with a methane δ¹³C₁ value down to -49.1‰, indicating that it seems to be the mixture of thermogenic gas and biogenic gas.

The natural gas from the Anjihai anticline in the middle part is similar to that from the western part. From the Anjihai to Horgos, Manas, Tugulu and the Hutubi anticlines, the C₁/(C₂+C₃) ratio of natural gas gradually increases, and the methane isotopic value correspondingly decreases. The samples fall almost all within the region of gas generated by Type-III kerogen due to thermal evolution, and constitute a thermal evolution sequence with the natural gas from the Taibei sag of the Turpan Basin, indicating that these natural gases should be mainly derived from humic organic matter. But for the natural gases from the Nananjihai and Qigu anticlines located in the 1^st row of anticline structures in the middle part, although their methane carbon isotope δ¹³C₁ values are similar to those of the 2^nd and 3^rd rows (from the Anjihai anticline to the Hutubi anticline), their C₁/(C₂+C₃) ratios amount to 80-500, considerably higher than those of natural gas from other anticlines in the middle part. They fall in the region of high-maturity thermogenic gas of Type-II kerogen, and are at the same evolution sequence with oil-associated gas^[1,7] derived from the Permian Fengcheng lacustrine source rock in the northwest margin, which seems to indicate that these natural gas samples are generated by organic matter different from natural gas samples from other structures in the middle part and should be mainly derived from highly mature Type-II organic matter. The natural gas from the Santai region in the eastern part has methane isotope composition identical to that of natural gas in the northwest margin, but C₁/(C₂+C₃) ratio of 20-100, much higher than that of the oil-associated gas from the northwest margin. They are primarily located in the region of gas generated by Type-I and Type-II kerogens, indicating they are generated by sapropelic and sapropelic-humic organic matters. Some natural gas samples are in the mixed gas region, indicating that biogenic gas may contribute to the natural gas^[1,13].

3.1.2. Identification based on carbon and hydrogen isotopic compositions of natural gas

The cross plot of methane carbon and hydrogen isotopic values is also frequently used to determine the genetic type of natural gas^{[26,28-30,32,34,36-39]}. The δD value of methane generated from organic matter in terrestrial fresh-water sediments is typically lower than -190‰, while that of methane generated from organic matter in marine and saline sediments is in most cases higher than -190‰^{[26,28-30,32,34,38]}. However, with the increase of thermal evolution, the hydrogen isotope composition of methane also became considerably heavier^{[28,29,43-45]}. The δ¹³C₁ value of natural gas in the Hutubi gas field of the middle part lies between -32‰ and -30‰, which is accompanied by the methane hydrogen isotopic value δD within the range from -200‰ to -197‰, which clearly indicates organic thermogenic natural gas (Fig. 5b). Compared with the gas from the Taibei sag in the Turpan Basin, gases from the Hutubi gas field is seen with higher carbon and hydrogen isotopic compositions, which are lighter, with respect to those of natural gas in the Kuqa depression of the Tarim Basin. The natural gas in the Taibei sag is mainly derived from humic organic matter in the Middle-Lower Jurassic coal-bearing source rocks, and belongs to coal-derived gas. Moreover, since the Jurassic source rocks are in general at the low mature to mature stage^[22,46,47], the maturity of natural gas is also low, dominated by wet gas^[22,23]. The natural gas in the Kuqa depression is also mainly derived from the Middle-Lower Jurassic coal-bearing source rocks, and is also coal-derived gas^[43,44]. Nevertheless, the Middle-Lower Jurassic coal-bearing strata in the Kuqa has reached the mature to overmature stage^[48], and thus the generated gas is seen with higher maturity, basically presenting itself as dry gas. Obviously, the natural gases from the Taibei sag, Hutubi gas field and Kuqa depression constitute a maturity sequence of coal-derived gas.

The methane δ¹³C₁ value of natural gas from the Jurassic gas reservoir of the Mazhuang gas field, the Santai region of the eastern part is generally between -51‰ and -44‰, and the hydrogen isotopic value δD is between -250‰ and -180‰^[13], which indicates that the gas is organic thermogenic gas (Fig. 5b). However, this natural gas, with greatly lower carbon and hydrogen isotopic values, is apparently different from the coal-derived gas of the Hutubi gas field. On contrary, it stays at the same sequence with the oil-associated gas of the Tazhong and Tabei uplifts in the Tarim Basin. Accordingly, the natural gas of the Mazhuang gas field should be classified as the oil-associated gas.

Besides, according to Dai et al.^[24], the δD values of mud volcano gas seeps in the Dushanzi anticline of the western part lie between -247‰ and -231‰. In particular, the gas seeps of the Aerqin mud volcano are seen with the δD values down to the range from -268‰ to -267‰, which are similar to the case of natural gas in the Mazhuang gas field of the eastern part and the Taibei sag. The values are lower than those of natural gas of the Hutubi gas field, and far lower than that of natural gas from organic matters in the Jurassic coal-bearing strata of the Kuqa depression. It is indicated that the natural gas in the mud volcanoes is generated by organic matters deposited in a fresh-brackish water environments and with lower maturity.

3.1.3. Identification based on carbon isotopic compositions of natural gas components

Dai^[30] proposed the genetic type identification chart based on carbon isotopes of methane, ethane and propane (Fig. 6), and classified the gas with the δ¹³C₂ value higher than -25‰ as coal-derived gas, the value between -25‰ and -28‰ as mixed gas, and the value lower than -28‰ as oil-associated gas. In addition, the distribution pattern of carbon isotopes of natural gas components can also be used to identify organic thermogenic natural gas. For normal organic thermogenic natural gas, the carbon isotopic value often presents a positive sequence, in which the value gradually increases from C₁ to C₄, that is, δ¹³C₁<δ¹³C₂<δ¹³C₃<δ¹³C₄. For natural gas subjected to biodegradation, the carbon isotopic value of components may be reversed^[31,49].

From the carbon isotope distribution pattern of natural gas components (Fig. 4), most natural gases in the southern margin present a positive sequence pattern, i.e. δ¹³C₁<δ¹³C₂< δ¹³C₃<δ¹³C₄, which implies that these natural gases are all organic origins. However, some natural gases are found with lower carbon isotopic values for propane and butane, e.g. the natural gas in the Kaindick and Dushanzi anticlines; some gases even present a reversal distribution since ethane, e.g. the natural gas in the Qigu and Tugulu anticlines, which implies complex genetic origins and accumulation processes. From the correlation between the carbon isotope compositions of different natural gas components (Fig. 3), the carbon isotope composition of natural gas in the southern margin is obviously much heavier than that in the Karamay-Urxia region of the northwest margin, so the two are not a sequence, nor is it the same sequence with the natural gas in the Central depression of the Junggar Basin (Fig. 3a). From the carbon isotope compositions of ethane and propane, the two still present a good linear relationship (Fig. 3b), only the carbon isotope compositions of ethane and propane in the northwest margin are much lighter than those in the southern margin, indicating that the types of organic matter generating natural gas in the southern margin are inferior to those generating natural gas in the northwestern margin. The crude oil and natural gas in the Karamay-Urxia region are mainly derived from the Lower Permian Fengcheng lacustrine source rock, and the natural gas is mostly associated gas of crude oil, belonging to typical oil-associated gas^[1,7]. From this comparison, it can be seen that the vast majority of natural gas samples from the middle and western parts of the southern margin are obviously coal-derived gas and mixed gas, rather than oil-associated gas. Only the natural gas in the Santai region of the eastern part is mainly oil-associated gas (Figs. 3 and 6). The natural gas samples from Well Ka-6 in the Kaindick oilfield and from the Cretaceous Qingshuihe reservoir in Well Gaotan-1 at the Gaoquan anticline are between mixed gas and typical oil-associated gas (Figs. 3 and 6), and appear to be largely oil-associated gas. But they have some difference from the typical oil-associated gas in the northwest margin, and should be classified as mixed gas.

It should be noted that the mixed gas here refers not only to the mixture of the typical oil-associated gas from Type I and II₁ kerogen and the coal-derived gas generated by the typical Type III kerogen, but also the natural gas generated by the Type-II kerogen (sapropelic-humic kerogen and humic-sapropelic kerogen) in the Jurassic coal-bearing strata. In fact, organic matter in the Jurassic coal measures in the southern margin has generated a large amount of crude oil during the geological history. The crude oil in the Jurassic and Cretaceous reservoirs which are the main body of the Kaindick oilfield, is derived from the Jurassic coal-bearing source rocks, and other structures such as the Xihu anticline also have similar crude oil^[1,4]. In the Gaoquan anticline, the high yield of crude oil recently obtained from the Cretaceous Qingshuihe oil and gas reservoir is also derived from the Jurassic coal-bearing source rock. Furthermore, about 50% of the crude oil in the Jurassic reservoir of the Qigu oilfield is also derived from the Jurassic source rocks^[1,4]. The presence of the massive crude oil is sufficient to prove that in addition to the predominantly gas-generating Type-III organic matter, the Jurassic coal measures also contain considerable Type-II organic matter capable of generating both oil and gas. Compared with the Permian, Triassic and Cretaceous lacustrine organic matters and the crude oils they produce in the Junggar Basin, the organic matter in the Jurassic coal measures and the corresponding crude oil have relatively heavier carbon isotope compositions (the δ¹³C value of the crude oil generated by the former and latter were -32‰ to -29‰ and -28‰ to -26‰ respectively). Correspondingly, the natural gas associated with the Jurassic crude oil could also have higher carbon isotopic value, and thus have not the carbon isotope composition characteristics of typical oil-associated gas, nor the carbon isotope composition characteristics of coal-derived gas generated by typical Type-III organic matter in coal measures, but exhibit the characteristics of mixed gas. Of course, if the natural gas derived from the coal measures source rock is defined as coal-derived gas, or the δ¹³C₂ value of the coal-derived gas is defined as greater than -28‰^[24], then most of the mixed gas samples in the southern margin should be classified as coal-derived gas. However, such classification is not scientific and does not correspond to the classical classification of organic matters. For example, the crude oil in the Central depression of the Junggar Basin and its associated natural gas are derived from the Permian lacustrine organic matter (Type II kerogen)^[1,7], but most of the natural gas samples have an ethane carbon isotopic value from -28‰ to -26‰ (Fig. 3), but these gas samples can’t be regarded as coal-derived gas thus. In fact, in many previous criteria of natural gas genetic type identification, the natural gas with δ¹³C₂ value greater than -25‰ is defined as coal-derived gas, which mainly refers to the gas derived from highly mature to overmature coal-bearing organic matter^[31]. The natural gas derived from low-medium mature coal-bearing organic matter often has the ethane carbon isotopic value lower than -25‰, e.g. the natural gas in the Taibei sag of the Turpan Basin^{[22, 23, 29,32]}.

It is worth noting that the natural gas samples from the 1^st-row of structures such as the Nananjihai and Qigu anticlines, are in the same series of coal-derived gas with the natural gas in other structures of the southern margin (Fig. 3a), or within the range of coal-derived gas (Fig. 3b and Fig. 6) according to the carbon isotope composition. However, from perspectives of natural gas composition and methane carbon isotope composition (Fig. 3a), they are significantly different from other natural gas samples from the southern margin, and should be classified as high-maturity oil-associated gas from Type-II kerogen or mixed gas. The natural gas in the two structures have very low contents of heavy hydrocarbons above C₂, and the carbon isotopes of heavy hydrocarbons have even been reversed (Fig. 4), which indicates that its maturity is already very high, and it is greatly different from the gas associated with the crude oil in the northwest margin. According to the component content and methane carbon isotopic value (Fig. 5a), the natural gas in the Nananjihai anticline belongs to oil-associated gas, and meanwhile the natural gas in the Qigu anticline is between oil-associated gas and coal-derived gas. In fact, the natural gas in the Qigu anticline is much more complicated. The methane carbon isotopic value of the natural gas in the shallow Jurassic reservoir is relatively low, and the carbon isotopic values of ethane, propane and butane are also lower than those of the Hutubi gas field. The carbon isotopic values of methane and ethane of the natural gas in the deep Triassic reservoir are basically the same as those of the Hutubi gas, but the values of propane and butane are obviously lower than those of natural gas in the Hutubi gas field (Fig. 4). The crude oil in the Qigu anticline Jurassic reservoir is a mixture of the Permian crude oil and the Jurassic crude oil^[1,4], and the natural gas may also be a mixture of gas from different sources. The great gap between carbon isotope compositions of natural gas is likely to be attributed to varied mixing proportions of the Permian oil-associated gas and the Jurassic coal-derived gas. The natural gas in the Jurassic reservoir is characterized by a mixed gas due to the relatively high proportion of the oil-associated gas from the Permian, while the natural gas in the Permian-Triassic reservoir is characterized by coal-derived gas due to the relatively low proportion of oil-associated gas.

Furthermore, the carbon isotope composition of the natural gas in the Dushanzi anticline is also very complicated (Fig. 3). For some natural gases, the methane and ethane carbon isotopic values are similar to that of the natural gas in the Taibei sag of the Turpan Basin, which belongs to the same sequence with the natural gas in the structures of the middle part. Also, some natural gases share ethane carbon isotopic values similar to those of other natural gas, yet with much higher methane carbon isotopic values (Fig. 3a). A common feature of these natural gases is that the propane carbon isotopic value is particularly high (Fig. 3b). The gas samples from the Dushanzi and the Maoyanshan mud volcano gas seeps also have particularly high propane carbon isotopic values^[24]. In addition, the natural gas of Well Du-58 has lighter methane and ethane carbon isotopic values, and seems to be oil-associated gas (Fig. 3a), but the propane carbon isotopic value is also particularly high. What causes the anomaly heavy propane carbon isotopic value needs to be investigated further. It is speculated that microbial degradation is the cause.

3.1.4. Genetic types of natural gas

In general, based on the natural gas composition, carbon and hydrogen isotope composition and comparison with natural gases in other basins, the natural gases in the southern margin can be divided into three types: coal-derived gas, mixed gas and oil-associated gas, among which, the coal-derived gas and mixed gas take dominance, while oil-associated gas is less in quantity. Specifically, the natural gases in the Kaindick, Xihu and Dushanzi anticlines in the western part are dominated by coal-derived gas and mixed gas, while natural gas in the Qingshuihe oil and gas reservoir of Well Gaotan-1 is largely mixed gas. The natural gases in the Anjihai, Horgos, Manas, Tugulu and Hutubi anticlines are mainly coal-derived gas. The natural gas in the Nananjihai anticline is oil-associated gas; the Qigu anticline, mixed gas; and the Mazhuang gas field in the Santai of the eastern part, oil-associated gas.

The relative content of natural gas hydrocarbon components and the carbon and hydrogen isotopic values are also used to identify the maturity of natural gas. As the maturity increases, the methane content increases gradually and the heavy hydrocarbon content such as ethane and propane correspondingly decreases, and the carbon and hydrogen isotopic composition gradually becomes heavier, among which the methane is more affected by the thermal evolution of the source rock than the heavy hydrocarbon gases such as ethane and propane. Therefore, many researchers have proposed empirical formulas between the vitrinite reflectance and the hydrocarbon isotope composition^{[26,28,34-35,50-52]}. The dryness or wetness coefficients of natural gas are also used commonly to measure maturity of natural gas^[43,53,54].

3.2.1. Maturity determination based on dryness

The hydrocarbon composition of natural gas varies greatly in the southern margin (Fig. 2), with methane contents of 50%-99%, ethane contents ranging from 0.2% to 26.0%, and propane contents of 0.2%-17.0%. The dryness coefficient is of 0.6-1.0, indicating that maturity also varies significantly. It can be seen from Table 1 that the dryness coefficients of natural gas in the Kaindick, Dushanzi and Xihu anticlines are 0.73, 0.82 and 0.93, respectively, all suggesting wet gas. However, according to Dai et al.^[24], the dryness coefficient of mud volcano gas seeps in the western part is basically within 0.89-1.0, among which the gas seeps from the Aerqin, Maoyanshan and Dushanzi mud volcanoes are 0.92-1.0, mostly dry gas, and only the gas seeps from mud volcanoes around the Sikeshu coal mine are between 0.89 and 0.92 in dryness coefficient, still significantly higher than those of natural gas in the exploration wells of the western part. Obviously, if not because of post-biodegradation, these mud volcano gases are much higher in maturity.

The gas in the Anjihai anticline in the middle part has the highest content of heavy hydrocarbons, and the average dryness coefficient of only 0.71, the lowest among all natural gases in the southern margin. From the Anjihai anticline towards the east to the Hutubi anticline, the natural gas dryness coefficient gradually increases. The Hutubi anticline natural gas reaches 0.95 in dryness coefficient, representing critical dry gas. Clearly, the natural gas in the middle part of the southern margin is mainly wet gas, so the gas-generation organic matter is basically in the mature to high-mature stage. But the natural gases from the Nananjihai and Qigu anticlines in the 1^st row of structure belt have a dryness coefficient of 1.0 and 0.99, respectively, representing dry gas; Aerqin anticline and Maoyanshan structure in the western part are also located in the 1^st row of the structural belt, and the gases from them are also dry gas. Obviously, natural gas of the 1^st row of structure is generally higher in maturity than natural gases of the 2^nd and 3^rd rows. The natural gas in the Mazhuang gas field in the eastern part has a dryness coefficient of 0.97, is classified as dry gas, and it seems that its maturity is also high. But the natural gas may be biogas formed by bacterial degradation of crude oil, or has gas from bacterial degradation mixed in. Therefore, although its composition is mainly methane, its maturity cannot be determined with respect to the dryness coefficient.

3.2.2. Maturity determination based on carbon isotopic compositions of natural gas components

The influence of the type and maturity of gas-generation organic matter on the methane and ethane carbon isotope of natural gas in the southern margin is also tremendous. With increasing maturity, the carbon isotopic composition of methane and ethane of different types of natural gas is gradually becoming heavier (Fig. 3). According to the genetic types of natural gas in the southern margin decided in the above section and the empirical formula for maturity of coal-derived and oil-associated gas proposed by Dai et al.^[51], calculated maturities of most natural gases or maturity of gas-generation organic matter in this area are within 0.8%-1.7%, gradually growing from west to east. The Anjihai anticline natural gas is with 0.8%-1.0%; the Horgos anticline natural gas, 0.8%- 1.2%; the Manas anticline natural gas, 0.9%-1.4%; the Tugulu anticline natural gas, 1.4%-2.0%; the Hutubi gas field, 1.5%-1.9%. The maturity of natural gas in the Nananjihai anticline, 2.0%-2.3%, corresponds to the natural gas source of the Type-II kerogen in the highly mature to overmature stage (Fig. 5a). The natural gas in the Jurassic reservoir of the Qigu anticline is only 0.33%-0.88%, if calculated in reference to the coal-derived gas, which is obviously inconsistent with its composition. If it is calculated using the oil-associated gas formula, the maturity will be of 1.17%- 2.77%, presenting a large variation range. Consequently, such gas is highly likely to be mixed by oil-associated gas and coal-derived gas. For the natural gas in the Permian-Triassic reservoir, maturity would amount to 4.7%-6.6%, if it is treated as oil-associated gas, and such maturity is obviously impossible. On the other hand, in the case of coal-derived gas, the calculation results are of 1.6%-2.3%, which successfully corresponds to its composition as well as the distribution of natural gas from Type-II and Type III kerogen with high-over-maturity (Fig. 5a).

For most natural gases of the Kaindick, Xihu and Dushanzi anticlines in the west part, only those with heavier carbon isotopic values are seen with maturity of 0.7%-1.0%, if calculated as coal-derived gas. This is basically consistent with the maturity of the coexisting crude oil in these anticlines^[1,3,4,7]. As for the natural gas samples with lower carbon isotopic values, such as those from the Qingshuihe Formation of Wells Ka-6 and Gaotan-1, the calculated maturity is only 0.38% using the coal-derived gas formula, which is inconsistent with the maturity of the Jurassic coal measures source rock and associated crude oil in the area. If calculated using the oil-associated gas formula, the maturity is 1.0%-1.3%, which is similar to that of the Jurassic source rocks and associated crude oil (still slightly higher). In addition, if calculated with the coal-derived gas formula, the maturity of natural gas with lower methane carbon isotopic values in the Dushanzi anticline and mud volcano gas seeps is basically less than 0.4%, which is clearly too low. If calculated with the oil-associated gas formula, most of them are at 0.9%-1.4%, obviously more reasonable than values from the coal-derived gas-based calculation, but still to some extent inconsistent to their nearly dry-gas composition. Furthermore, some natural gas samples, e.g. the shallow gas of Well Du-230 and some mud volcano gas seeps, are still too low in maturity (0.35%-0.55%), even calculated with oil-associated formula, which is also inconsistent with the fact that the gas composition is close to dry gas. Given this, it can be concluded that the natural gases in the western part are relatively complicated in genetic types. It is difficult to estimate their maturity with either the coal-derived gas formula or oil-associated gas formula, which indicates they are complex in source and accumulation process.

The maturity of the natural gas samples from the Mazhuang gas field in the eastern part are only 0.28%-0.79%, even calculated with the oil-associated gas formula. The maturity calculated would be below 0.2%, if the coal-derived gas formula is used. This obviously deflects from their dry-gas composition, and hence, the gas probably has biogas mixed in or is mainly secondary biogas from biodegradation of crude oil.

There are five sets of source rocks, the Permian, Triassic, Jurassic, Cretaceous and Paleogene-Eocene in the southern margin^[1,2,6]. The lacustrine source rocks of the Middle Permian Lucaogou Formation are mainly distributed from the eastern to the middle parts, with high abundance and favorable organic matter types, and high potential for hydrocarbon generation. The Upper Triassic Huangshanjie lacustrine and Haojiagou swamp source rocks are also widely distributed in the southern margin, but with organic matter abundance lower than that of the Permian Lucaogou source rock, mainly Type-II and Type-III organic matters, and higher hydrocarbon generation potential. The Middle and Lower Jurassic coal-bearing strata, extensively distributed in the southern margin, contain three types of source rocks, namely dark mudstone, carbonaceous mudstone and coal. The source rock, thick and rich in Type-II and Type III organic matter, with some Type II₁ organic matter, is the most important set of source rocks in the southern margin. The lacustrine source rock of the Lower Cretaceous Qingshuihe Formation is most developed in the middle part, with fairly high abundance of and mainly Type-I and Type II organic matter and higher hydrocarbon generation potential. The lacustrine source rock of the Paleogene-Eocene Anjihaihe Formation, mainly distributed in the middle and western parts, has a big range of organic carbon content, mainly Type-II organic matter and higher hydrocarbon generation potential. Among the above five sets of source rocks, the Permian, Triassic and Jurassic source rocks are all buried deep, and thus in the mature to overmature stage. They have reached the maturity level for generating massive hydrocarbons during the geological history. In contrast, the Lower Cretaceous and Paleogene-Eocene source rocks are mainly in the low-mature to mature oil generation stage, and have not yet reached the thermal level of massive natural gas generation^[1,2,6]. Therefore, the effective natural gas source rocks in the southern margin are mainly the Middle-Lower Jurassic coal measures, the Upper Triassic lacustrine-swamp and the Permian lacustrine source rocks.

As mentioned above, according to geochemical characteristics and genetic types, the natural gas in the southern margin can be divided into three types: coal-derived gas, mixed gas and oil-associated gas. The coal-derived gas and mixed gas are dominant, while the oil-associated gas is minor.

4.2.1. Natural gas in the middle part

The content of heavy hydrocarbons in the natural gas composition of the Anjihai, Horgos, Manas, Tugulu and Hutubi structures in the middle part is observed with great variations, and the dryness coefficient gradually increases from 0.65 to 0.95 from west to east, correspondingly changing from wet gas into dry gas. The maturity variation basically corresponds to the change of maturity of the Jurassic source rocks^[1,2,6]. On the other hand, these natural gases have high carbon isotopic values (heavy isotope compositions). Except for the Anjihai anticline natural gas, the δ¹³C₂ value of natural gas in these anticlines is mostly higher than -25‰, and the δ¹³C₃ value is basically over -23‰, which indicates typical highly mature coal-derived gas.

Among the three possible source rocks in the middle part, the Permian and Triassic are mainly lacustrine source rocks, and the generated crude oil and natural gas have lighter carbon isotopic composition^[1,3-6]. The oil-associated gas from the Permian lacustrine source rock in the northwest margin has lighter carbon isotope composition^[1,7], which is completely different from the natural gas in the middle part of southern margin. The Jurassic is a set of coal-bearing source rock, and the crude oil it generates has heavier carbon isotopic composition. The natural gas generated by it should also have heavier carbon isotope composition, which corresponds to the carbon isotopic composition of the natural gas. In fact, the carbon isotope composition of the natural gas with low maturity in the Anjihai anticline is similar to that from the Jurassic coal-bearing strata in the Taibei sag, Turpan Basin; whereas the highly mature natural gas from the Hutubi gas field has carbon isotope composition similar to the gas from the Jurassic coal measures in the Kuqa depression.

Therefore, the coal-derived gas of these anticlines in the middle part should be mainly derived from the source rocks of the Middle and Lower Jurassic coal measures, and the upper coal-bearing source rocks in the Upper Triassic may also contribute a small amount. The natural gas and the crude oil share no common source rocks^[3,4,5]. The natural gas in the 1^st row of anticlines in the middle part is mainly dry gas, with maturity higher than natural gases in the 2^nd and 3^rd rows of anticlines, and more complicated carbon isotope composition. The natural gas in the Nananjihai anticline is oil-associated gas, and its possible sources are the highly mature and overmature Permian or Triassic lacustrine source rocks. The natural gas in the Qigu anticline is more complicated. In this anticline, the natural gas in the Jurassic reservoir is mainly mixed gas, which should be a mixture of the coal-derived gas from the Jurassic coal-bearing strata and the oil-associated gas from the Permian/Triassic lacustrine source rocks at different proportions. The natural gas of the Permian-Triassic reservoir is mainly highly mature coal-derived gas, primarily derived from the Jurassic coal-bearing source rocks, which may have oil-associated gas from the Permian/Triassic lacustrine source rocks mixed in.

4.2.2. Natural gas in the western part

The natural gases in the Kaindick oilfield and the Xihu anticline in the western part have relatively high contents of heavy hydrocarbons, with medium maturity, and have heavy carbon isotope composition which is significantly different from that of the Permian oil-associated gas in the northwest margin and instead, similar to that of natural gas in the Taipei sag of the Turpan Basin, being mixed gas and coal-derived gas. The source rock that has been confirmed in the western part is the Jurassic coal measures source rock, which is currently at the peak oil generation stage. The Paleogene Anjihaihe lacustrine source rock with low maturity is not the main source rock for the gas. Furthermore, the distribution and hydrocarbon generation potential of the Permian and Triassic lacustrine source rocks are still unclear. At present, the crude oil samples from in the Qigu-Qingshuihe formations in the Kaindick and Xihu anticlines are all derived from the Middle and Lower Jurassic coal-bearing source rocks^[1,4,7], and the natural gas is mainly gas associated with the crude oil. Therefore, the natural gas in these structures should be mainly derived from the mature source rock in the Jurassic coal measures. The natural gas samples in the Dushanzi anticline, including the mud volcano gas seeps, have special carbon isotope composition. The δ¹³C₂ value is about -26‰ and the δ¹³C₃ value varies widely between -26‰ and -19‰, indicating these natural gases have complex genetic types, origins and accumulation process. From the ethane and propane carbon isotopic values, it is inferred these natural gases should be mainly derived from the Jurassic coal-bearing source rock, but may be subjected to bacterial degradation.

4.2.3. Natural gas of Well Gaotan-1

One thing that may arouse extra attention is the fact that some natural gas samples from the anticline structures in the western part have lighter carbon isotopic values too. For example, the natural gas from 5 768-5 775 m interval of Well Gaotan-1 in the Gaoquan anticline that recently tested high yield of oil and gas flow and the natural gas from 3 956-3 980 m interval of the Lower Cretaceous Qingshuihe Formation of Well Ka-6 in the Kaindick anticline, have lighter carbon isotopic values. Similar natural gas is also found in the Neogene formation of Well Du-58 in the Dushanzi anticline. Natural gas from Well Gaotan-1 has a dryness coefficient of only 0.76, but lighter carbon isotopic values of methane, ethane and propane (Fig. 3), particularly, those of ethane and propane, not only lighter than the highly mature natural gas in the Hutubi gas field (with the dryness coefficient of 0.90-0.95), but also much lighter than those of mature natural gas in the Anjihai anticline (wet gas with a dryness coefficient of only 0.71), lighter than the natural gas in the Kaindick and Xihu anticlines with similar dryness coefficients, and even lighter than low-mature natural gas (largely associated gas of crude oil) from the Middle and Lower Jurassic coal measures in the Taibei sag of the Turpan Basin^[22,23]. The natural gas in Well Gaotan-1 is nearly the lightest in carbon isotopic value in the southern margin. However, this natural gas is heavier in carbon isotopic value than the typical oil-associated gas derived from the Permian Fengcheng lacustrine source rock in the northwest margin (Fig. 3b).

Apparently, such natural gas in the western part should not be completely derived from the Middle and Lower Jurassic coal measures, but be a mixture of the natural gas from the Jurassic coal-bearing source rocks and that from the Permian lacustrine source rocks. With the help of the carbon isotope binary mixing model of natural gas, the relative contributions of the Jurassic and Permian can be calculated. The natural gas in the Kaindick oilfield, the Xihu and Anjihai anticlines is derived from the Jurassic coal measures, and its hydrocarbon composition (dryness coefficient) is basically identical to that of Well Gaotan-1 (Table 1), which indicates that their maturity are also close to each other. Hence it can be used as the end member of the typical coal-derived gas from the Jurassic source rocks. However, the natural gas in the Mahe and the Hutubi gas fields in the middle part mainly consist of methane, and the dryness coefficient is significantly higher than that of Well Gaotan-1 (Table 1), which indicates that its maturity is higher than that of Well Gaotan-1. Given this, it cannot be used as the end member of coal-derived gas. On the other hand, the natural gas in the northern part of the northwest margin is mainly derived from the Permian Fengcheng lacustrine source rocks, and its hydrocarbon composition^[1,7] is similar to that of Well Gaotan-1, and therefore it can be used as the end member of the oil-associated gas of the Permian source.

The natural gas derived from the Jurassic coal-bearing source rocks in the Kaindick, Xihu and Anjihai anticlines has an average dryness coefficient of 0.80, and an average value of methane and ethane carbon isotope of -37.63‰ and -26.27‰, respectively. The natural gas from the Permian Fengcheng source rocks in the northwest margin has an average dryness coefficient of 0.88, and an average value of methane and ethane carbon isotope of -43.24‰ and -31.35‰, respectively. The natural gas from the Qingshuihe Formation in Well Gaotan-1 has a dryness coefficient of 0.77, methane and ethane carbon isotope δ¹³C values of -40.42‰ and -28.94‰, respectively. These natural gases have similar dryness coefficients and moreover similar maturity. Therefore, on the basis of the binary mixing model combined with the methane carbon isotopic δ¹³C value, the contribution of the Jurassic coal-bearing source rocks to the natural gas in Well Gaotan-1 is 50.27%, and the contribution of the Permian lacustrine source rocks is 49.73%. On the other hand, the calculation using the carbon isotopic value of ethane suggests that the contribution of the Jurassic source rocks is 47.44%, and the contribution of the Permian lacustrine source rocks is 52.56%. Consequently, it is safe to say that the shares of the Jurassic-sourced gas and Permian-sourced gas in Well Gaotan-1 are about 50% for each.

4.2.4. Natural gas in the eastern part

For the natural gas in the Mazhuang gas field in the eastern part of the southern margin, Hui et al.^[13] considered it as coal-derived gas from the Jurassic coal-bearing source rocks. However, the natural gas is basically dry gas, and has low carbon isotopic values, which is greatly different from the highly mature coal-derived gas in the Hutubi gas field, and thus should be oil-associated gas. Yet, the calculated maturity, regardless of using either the oil-associated formula or coal-derived formula proposed by Dai et al.^[51], are both very low, indicating immature and low-mature natural gas, which is obviously inconsistent with its dry gas composition. Xu et al.^[34] defined the natural gas generated by the source rock at the low mature stage (R_o=0.5%-0.6%) as the bio-thermocatalytic transitional natural gas. Dai^[31] named this type of natural gas as the sub-biogas. This type of natural gas has the following characteristics: it is dominated by methane in composition, low in content of heavy hydrocarbon components of ethane and heavier components, dry, between -55‰ and -50‰ in δ¹³C₁ value, and often associated with minor low- mature crude oil^[31,34]. The natural gas in the Mazhuang gas field, Santai region is also dry gas, and yet its methane carbon isotopic value δ¹³C₁ is often between -50‰ and -44‰, about 5‰ higher than that of bio-thermocatalytic transitional gas named by Xu et al.^[34]. Therefore, such natural gas should not be generated by sources rocks at low-mature stage. In fact, this kind of natural gas has also been found in the Luliang uplift in the Central depression and Fengcheng region in the northwest margin, typically associated with biodegraded heavy oil or above the heavy oil reservoir. In the Santai region, such natural gas is often at burial depth of less than 2 200 m, and is in most cases associated with biodegraded heavy oil or above the heavy oil reservoir^[1]. Therefore, the authors consider that the dry gas in Mazhuang gas field is secondary biogas generated during the biodegradation of crude oil. The crude oil in the Santai region is derived from the Middle Permian Lucaogou lacustrine source rock^[1]. Therefore, the natural gas in the Mazhuang gas field is indirectly derived from the Permian lacustrine source rock.

The natural gas samples from the southern margin of the Junggar Basin vary widely in hydrocarbon composition. Most of them are wet gas, and only a few dry gas. The natural gas samples from the western Sikeshu sag have a dryness coefficient of 0.73-0.93, indicating most of them are wet gas; natural gas samples in the 2^nd and 3^rd rows of anticline structures have a dryness coefficient of 0.63-0.95 that gradually increases from the west to the east, also indicating wet gas, while the natural gas in the 1^st row is dry gas; natural gas in the Mazhuang gas field in the eastern part is dry gas.

The natural gas samples from the southern margin generally have heavier carbon isotopic composition and light hydrogen isotopic composition. Most of them have positive sequence distribution of carbon isotopic composition of natural gas components, but some have reversal of carbon isotopic value distribution. They are all organic thermogenic gas, derived from organic matters deposited in fresh-brackish-water environment. They can be divided into three types, namely the coal-derived, mixed and oil-associated gases. The coal-derived gas and mixed gas take dominance. Natural gas samples from the Kaindick, Xihu and Dushanzi anticlines in the western part are mostly coal-derived and mixed gases; samples from the Anjihai, Horgos, Manas, Tugulu and Hutubi anticlines in the middle part are dominated by coal-derived gas; the natural gas in the Nananjihai anticline is oil-associated gas, and the natural gas from the Qigu anticline include mixed and coal-derived gases. The natural gas in the Santai region in the eastern part is oil-associated gas.

The Jurassic coal-bearing source rocks are the uppermost supplier of the natural gas in the southern margin, while in local areas, the Permian and Upper Triassic source rocks are also important sources for natural gas. The natural gas in the 2^nd- and 3^rd- row structures is mainly derived from the Jurassic coal-bearing source rocks, and meanwhile that of the 1^st-row structure is derived from the Permian lacustrine and Jurassic coal-bearing source rocks, which may also have contributions from the Upper Triassic source rocks. The natural gas in the western part is mainly derived from the Jurassic coal-bearing source rocks and the Permian lacustrine source rocks. For natural gas in the Santai region in the eastern part, it is generated by the Permian lacustrine source rocks.

The natural gas in the Lower Cretaceous Qingshuihe reservoir of Well Gaotan-1 at the Gaoquan anticline, Sikeshu sag, in the western part is a mixture of the coal-derived gas and oil-associated gas. Shares of gas from the Jurassic coal measures and the Permian lacustrine source rocks are 50% for each, which reveals that the Permian gas source rock should exist, besides the Jurassic coal-bearing source rocks for both oil and gas in the western part of the southern margin.