Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China

Transcription

1 ENERGY EXPLORATION & EXPLOITATION Volume 30 Number pp Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China Ping an Sun 1, Jian Cao 1 *, Xulong Wang 2, Yueqian Zhang 2, Yong Tang 2, Abulimiti 2, Baoli Xiang 2 and Ming Wu 1 1 State Key Laboratory for Mineral Deposits Research, Department of Earth Sciences, Nanjing University, Nanjing, Jiangsu , PR China 2 PetroChina, Xinjiang Oilfield Company, Karamay, Xinjiang , PR China *Author for Corresponding. jcao@nju.edu.cn (Received 6 July 2012; accepted 9 April 2012) Abstract The southwestern Junggar Basin in northwest China is a significant target of basin s hydrocarbon exploration and exploitation at present. It is petroliferous mainly in oil production. However, natural gas should have good prospects because multiple sets of gas-prone source rocks are developed. Thus, in order to expand the field of hydrocarbon exploration (natural gas in particular), origins of the gases were discussed in this paper based on relatively comprehensive analyses of gas geochemistry, which include components, carbon isotopes and light hydrocarbons of gas and biomarkers of associated condensates. The results indicate two typical genetic types of gases. The first type is the coal-type and oil-type gases sourced from Permian lacustrine mudstones in the Shawan sag. It is distributed mainly in the Chepaizi area, whose most distinctive geochemical feature is the δ 13 C 2 value (ranging from to with an average of ) The gas exploration potential is good. By contrast, the second type of gas is the coal-type gas sourced from Jurassic coal-bearing rocks in the southern basin. It is distributed mainly in the western area of the southern basin, with a few in the southern part of the Chepaizi area. δ 13 C 2 value of the gases ranges from to with an average of 24.81, sharply heavier than that of the first type of gas. Gas exploration potential is fairly good, mainly being controlled by source-rock maturity. Keywords: Southwestern Junggar Basin of Northwest China, Natural Gas, Gas Geochemistry, Origin, Gas Source, China

2 708 Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China 1. INTRODUCTION Covering an area of approximately km2, the Junggar Basin is located in the northern part of the Xinjiang Uygur Autonomous Region, northwest China (Jin et al., 2008; Liu et al., 2009a) (Fig. 1). The southwestern part of this basin is petroliferous as several oil and gas fields have been discovered and produced. In particular, the Dushanzi oilfield is especially well known as it is the first oilfield that was discovered in the Junggar Basin Junggar Basin Beijing The southwestern Junggar Basin Figure 1. Sketch map showing tectonic units and oil and gas distribution in the southwestern Junggar Basin.

3 ENERGY EXPLORATION & EXPLOITATION Volume 30 Number exploration history of the basin. Since the discovery in 1950s, it has been a highlight of the basin s hydrocarbon exploration and exploitation. In general, the presently discovered hydrocarbons are mainly oils. These oils have multiple sets of source sequences according to oil-source correlations, mainly including Permian lacustrine mudstones in the Shawan sag (Cui et al., 2005), Jurassic coal-bearing source rocks (coals and mudstones) in the southern basin (Wang et al., 2009) and Cretaceous and Paleogene lacustrine mudstones in the southern Basin (Wei et al., 2007). These source sequences, in theory, can also generate gases in addition to oils (Wei et al., 2010). Thus. the gas exploration should have good prospects. However, only a limited amount of gas has been discovered. This in turn results in the limited works on gas geology and geochemistry, which has been focused mainly on basic reservoir characteristics and conditions (e.g., Li et al., 2004; Cui et al., 2005; Kang et al., 2008). Therefore, in order to provide information on the gas exploration, we conducted a study on the origin of the gases mainly based on their geochemistry in this paper, and the exploration prospect was preliminarily addressed combined with geological setting. 2. GEOLOGICAL SETTING The studied southwestern Junggar Basin can be mainly divided into two areas according to tectonics and current exploration status, i.e., the Chepaizi area and the western area of the southern basin. The Chepaizi area further mainly includes the Chepaizi uplift, Hongche fault belt and Zhongguai uplift, while the western area of the southern basin further comprises the Sikeshu sag, Qigu fault-fold belt and the Huo-Ma- Tu anticline belt (Fig. 1). The study area has a wide distribution of Carboniferous to Tertiary deposits with the partial absence of Permian, Triassic, Jurassic and Cretaceous sequences (especially in the Chepaizi area) (Fig. 2). Gas accumulation is not concentrated, varying sharply between the Chepaizi area and the western area of the southern basin. In the Chepaizi area, gas accumulates temporally in sandstone reservoirs of the Cretaceous Tugulu Group, Jurassic Badanwan Formation, Triassic and Permian and volcanic reservoirs of the Carboniferous (Fig. 2). Spatially, gas accumulates mainly in the Cretaceous, Carboniferous-Jurassic and Carboniferous-Triassic in the southern, middle and northern areas, respectively. This likely indicates different reservoir conditions. In contrast, with respect to the gas accumulation in the western area of the southern basin, it is relatively concentrated, accumulating mainly in the Dushanzi oilfield (dissolved in the oil), Horgos oil-gas field and well NA 1 of the Qigu fault fold belt. It occurs mainly in Tertiary reservoirs, except the Lower Jurassic Badaowan Formation of well NA 1. In addition, it is worth nothing that gas shows have been widely found both in the Chepaizi area and in the western area of the southern basin, reflecting a widespread gas migration and complex gas accumulation. 3. SAMPLES AND METHODS Thirty-seven gas samples and two associated condensates were collected. Components, stable carbon isotopes and light hydrocarbons of gas and biomarkers of associated condensate were analyzed. Chemical compositions of gas were determined using a Hewlett Packard 6890 II gas chromatograph (GC) equipped with a flame ionization detector and a thermal

4 710 Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China System Formation Lithology Gas interval Representative well Neogene Paleogene Cretaceous Jurassic Triassic Permian Dushanzi (N 2 d) Taxihe (N 1 t) Shawan (N 1 s) Anjihaiche (E 2 3 z) Ziniquanzi (E 1 2 z) Donggou (K 2 d) Tugulu (K 1 tg) Qigu (J 3 q) Toutunhe (J 2 t) Xishanyao (J 2 x) Sangonghe (J 1 s) Badaowan(J 1 b) Baijiantan (T 3 b) Kelamayi (T 2 k) Bakouquan (T 1 b) Shangwuerhe (P 3 w) Xiawuerhe (P 2 w) Fengcheng (P 1 j) Jiamuhe (P 1 j) D1 H10 C80 C45 NA1 C11 C37 G3 Carboniferous C35 Mudstone Silty mudstone Muddy siltstone Siltstone Fine-grained sandstone Medium-grained sandstone Conglomerate Tufaceous conglomerate Volcanic tuff Pyroclastic rock Figure 2. Generalized stratigraphy and main gas reservoirs in the southwestern Junggar Basin. conductivity detector. Individual hydrocarbon gas components (C 1 C 5 ) were separated using a capillary column (PLOT Al 2 O 3 50 m 0.53 mm). GC oven temperature was initially set at 30 C for 10 min, and then ramped to 180 C at 10 C/min. Stable carbon isotope values of gas samples were determined on an Optima isotope ratio mass spectrometer (MS) equipped with a Hewlett Packard 6890 II gas chromatograph. Gas components were separated on a gas chromatograph, converted into CO 2 in a combustion interface, and then injected into the mass spectrometer.

5 ENERGY EXPLORATION & EXPLOITATION Volume 30 Number Individual hydrocarbon gas components (C 1 C 4 ) were separated using a fused silica capillary column (PLOT Q 30 m 0.32 mm). The GC oven was ramped from 35 C to 80 C at 8 C/min, then to 260 C at 5 C/min, and the oven maintained at the final temperature for 10 min. All gas samples were analyzed in triplicates, and the stable carbon isotopic values are reported in the δ notation in per mil ( ) relative to the VPDB standards. Accuracy is estimated to be ±0.5 with respect to VPDB standard. Light hydrocarbons of gas were analyzed on a Hewlett Packard 6890 II gas chromatograph with a Hewlett Packard PONA capillary column with dimensions of 50 m 0.25 mm 25 µm. The carrier gas was helium, and the inlet temperature was 120. The components were collected with cold trap for 5 min, and the eluting hydrocarbons were then detected using flame ionization detector (FID) at a temperature of 320. The initial oven temperature was held at 25 for 15 min and then programmed to 70 at 1.5 / min, then rose from 70 to 160 at 3 / min, and finally from 160 to 270 at 5 / min. The final temperature was held for 20 min. GC MS of saturated hydrocarbons of associated condensates was carried out on a Hewlett Packard 6890 II GC coupled to a Quattro II mass selective detector fitted with a HP-1 fused silica column (30 m 0.25 mm 25 µm). For analyzing saturated fractions, the GC oven was initially set at 50 C for 2 min, programmed to 100 C at 2 C/min and then to 310 C at 3 C/min, with a final hold time of 15 min. 4. RESULTS AND DISCUSSION 4.1. Chemical compositions of natural gas The chemical compositions of natural gas are important geochemical index in natural gas research (Chen et al., 2000; Wang et al., 2007; Kovalevych et al., 2008; Sun et al., 2009; Zhu et al., 2011). Hydrocarbon gases are the main components of the natural gas in the Chepaizi area, ranging from 92.70% to 98.63% (Table 1). Furthermore, the compositions of the hydrocarbon gases are dominated by methane, whose content varies between 77.81% and 95.53%. Contents of heavy hydrocarbons from ethane to pentane decrease along with increasing carbon numbers. The gas dryness, defined as C 1 /Σ(C 1 C 5 ), ranges from 0.81 to 0.98 (Table 1). This indicates large variations of gas maturity. By contrast, the gas composition is quite different in the western area of the southern basin. For example, some gases are dominated by nitrogen, such as in wells An 5 ( m) and HQ 1 (861 m). The nitrogen content in the gases ranges from 64.69% to 66.70%, likely reflecting that the gases are mixed with the nitrogen from air or deep strata (Chen and Zhu, 2003). In contrast, the possibility of nitrogen releasing in highly to over mature stage of source rock can be ruled out as the source sequences are generally mature (Wang, 2001). Most of the other gases in the area are dominated by hydrocarbon gases; this is similar to the Chepaizi gases. The compositions of the hydrocarbon gases are also dominated by methane, and the gas dryness ranges from 0.63 to 0.93 (Table 1). In particular, the hydrocarbon gases of sample NA 1 contain only methane with minor ethane and no propane, butane and pentane. The gas dryness is so high at This likely indicates some biological activities (Pallasser, 2000) Stable carbon isotopes of natural gas Carbon isotope compositions of natural gas can be used to indicate the origin, type and maturity of the gas (Stahl, 1974; Galimov, 2006; Dai et al., 2007; Liu et al., 2009b). Specifically, the δ 13 C 1 value has certain ranges in different evolutionary stages and

6 712 Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China Table 1. Chemical compositions and carbon isotopes of natural gases in the southwestern Junggar Basin. Chemical composition (%) δ 13 C ( ), VPDB Area Well Formation Depth (m) CH 4 C 2 H 6 C 3 H 8 C 4 H 8 C 5 H 10 CO 2 N 2 Dryness CH 4 C 2 H 6 C 3 H 8 C 4 H 8 C91 C CF1 C / / CF3 C CF6 C / G3 P G3 P G5 P G9 P XG1 P Chepaizi area XG2 P / C45 J 1 b C82 J 1 b / XG1 J 1 b G20 J 1 s SM1 J 1 s C80 K 1 tg C83 K 1 tg HG3 K 1 tg SM1 K 1 tg / / Western area NA1 J 1 b / of NA1 J 1b / / the southern K002 J 3 q basin K6 J 3 q H001 K 2 d K003 E 1 2 z

7 ENERGY EXPLORATION & EXPLOITATION Volume 30 Number /: not detected X5 E 1-2 z K001 E 1-2 z H001 E 1-2 z / H002 E 1-2 z / H10 E 1-2 z H10 E 1-2 z H10 E 1-2 z An5 E 2-3 a An5 E 2-3 a HQ2 N 1 s HQ2 N 1 s / D1 N 2 t

8 714 Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China commonly increases proportionally along with maturity (Stahl, 1974; Dai, 1992; Galimov, 2006). According to Stahl (1974) and Dai (1992), the relation between δ 13 C 1 and R o has been established for coal-type and oil-type gases, respectively. Based on the standard that is widely used in China (Dai, 1992), we divided the stage of maturity of the gases (Fig. 3a). As shown in Fig. 3a, the δ 13 C 1 values range from to 31.36, implying that most of the gases are mature. (a) A B C D E F Immature Lowly mature Mature Highly mature 13 C2 ( ) Coal-type gas δ 28 Mixed Oil-type gas Lowly mature 45 Mature Highly mature Over mature δ 13 C 1 ( ) (b) 10 4 I II 2 C 1 /C I 2 I 3 III 1 III II 1 δ 13 C 1 ( ) V 2 IV V 1 A B C D E F Figure 3. Distribution of δ 13 C 1 δ 13 C 2 (a) and cross plot of δ 13 C 1 vs. C 1 /C 2 3 (b) of natural gases in the southwestern Junggar Basin. A. the Chepaizi area (C-T reservoir); B. the Chepaizi area (J reservoir); C. the Chepaizi area (K reservoir); D. the western part of the southern basin (J reservoir); E. the western part of the southern basin (K 2 -E reservoir); F. the western part of the southern basin (N reservoir). Zones of I-V 2 reflect different origins of natural gas (Dai, 1992). I, biogenic gas; II, oil-type gas; III 1, mixed oil-type and coal-type gases; III 1, mixed coal-type and condensate gases; IV, coal-type gas; V 1, abiogenic gas; V 2, mixed abiogenic gas and coal-type gas.

9 ENERGY EXPLORATION & EXPLOITATION Volume 30 Number Compared to δ 13 C 1 value, the δ 13 C 2 value is commonly believed to be less influenced by maturity, whereas it is a significant index for identifying the origin of natural gas (Wang, 1994; Dai, 1999; Dai et al., 2007). According to numerous analytical results in China, Dai (1999) proposed that the gases with δ 13 C 2 > 27.5 are coal-type in origin, while Wang (1994) suggested that the Jurassic Sinian natural gases with δ 13 C 2 > 29 in the Sichuan Basin are coal-type in origin. However, it should be noted that the δ 13 C 2 value can also be influenced by maturity. For example, at highly over mature stage, natural gas sourced from sapropelic organic matters has the carbon isotopes more than 28. As the gases in this study are mostly mature based on the above discussion on gas chemical compositions and δ 13 C 1 values and previous source-rock studies (Wang, 2001), here we define that the gases with δ 13 C 2 > 27.5 are typically coal-type in origin, δ 13 C 2 < 29 are typically oil-type in origin and those with δ 13 C 2 values between 27.5 and 29 are mixed in origin (Fig. 3a). As shown in Fig. 3a, δ 13 C 2 values of gases vary between and 21.74, indicating that most of the gases are coal-type in origin. In addition, correlation of δ 13 C 1 and C 1 /C 2 3 can be used to discriminate gas origins (Dai, 1992; Kotarba and Nagao, 2008). As shown in Fig. 3b, it is also illustrated that the coal-type gases are dominant in the southwestern Junggar Basin, either for the Chepaizi area and for the western area of the southern basin Compositions of light hydrocarbons Compositions of light hydrocarbons of gas can be used to indicate the gas origin, type, maturity and gas source correlation (Thompson, 1983). Table 2 presents the representative parameters of light hydrocarbons. Heptane and isoheptane indexes are important indices for gas maturity (Thompson, 1983; Chen et al., 1987). Cross plot of heptane index vs. isoheptane index (Fig. 4a) indicates that the natural gases in the southwest Junggar Basin are mainly mature, consistent with the above understanding obtained from compositions and stable carbon isotopes of natural gas. The relative compositions of C 7 -series compounds in light hydrocarbons, including heptanes (nc 7 ), dimethylcyclopentane (DMCP) and methylcyclohexane (MCH), have been commonly proposed to discriminate coal-type and oil-type gases (Hu et al., 2010). In general, methylcyclohexane is believed to derive from humic organic matter, such as lignin, fiber and saccharide from higher plants, and has relatively high thermal stability. In contrast, dimethylcyclopentanes predominantly originates from steroid and terpenoid compounds of aquatic organisms, and n-heptane is mainly derived from bacteria, algae and higher plants (Hu et al., 2010). In the Chepaizi area, the relative content of methylcyclohexane ranges from 35.3% to 57.3% with an average of 44.9%, suggesting that the gases are mainly coal-type besides a few of oil-type in origin (Fig. 4b). In contrast, the light hydrocarbon compositions of gas in the western area of the southern basin provide a strong indication of terrigenous sources because the relative content of methylcyclohexane ranges from 47.4% to 54.1% with an average of 50.9%. Relative abundance of some light hydrocarbon compounds with similar boiling points can be used as fingerprints to discern genetic types of gas and has been effectively applied in the Junggar Basin. The light hydrocarbon fingerprints of Carboniferous and Permian gases in the Chepaizi area are complex in general (Fig. 5a), likely implying complex secondary alteration. In contrast, the

10 716 Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China Table 2. Representative geochemical parameters of light hydrocarbons of natural gases in the southwestern Junggar Basin. Area Well Formation Depth (m) C91 C CF1 C CF3 C CF6 C XG1 P XG2 P Chepaizi area XG1 J 1 b C82 J 1 b G20 J 1 s SM1 J 1 s C83 K 1 tg HG3 K 1 tg SM1 K 1 tg Western area of the K001 E 1 2 z southern An5 E 2 3 a basin An5 E 2 3 a , heptane index (%); 2, isoheptane index; 3, nc7%; 4, MCH%; 5, ΣDMCP% 6. 1,3-Trans-dimethylcyclopentane /1,2-Trans-dimethylcyclopentane; 7. cyclohexane /methyl cyclopentene; 8. methyl cyclohexane / Σdimethylcyclopentane; 9. n-heptane /( ethyl cyclopentane+ methyl cyclohexane); 10. n-hexane / cyclohexane; methyl cyclopentene /3- methyl cyclopentene; methyl hexane /2,3- dimethyl pentane

11 ENERGY EXPLORATION & EXPLOITATION Volume 30 Number (a) 4 (b) MCH / % Isoheptane index The chepaizi area (C-T) The chepaizi area (J) The chepaizi area (K) The western area of the southern basin Low mature Mature High mature Heptane index (%) ΣDMCP / % nc 7 / % Figure 4. Cross plot of heptane index vs. isoheptane index (a) and ternary plot of C 7 light hydrocarbons (b) of natural gases in the southwestern Junggar Basin. The boundary lines between gases with different maturities in Fig. (a) are after Chen et al (1987). (a) 4 3 (b) C91(C) CF6(C) CF1(C) XG1(P) 4 XG1 (J 1 b) C82 (J 1 b) CF3(C) XG2(P) 3 G20 (J 1 s) SM1 (J 1 s) Ratio 2 Ratio (c) a b C83 (K 1 tg) HG3 (K 1 tg) SM1 (K 1 tg) c d Parameter e f g (d) a b c d Parameter e K001 (E 1 2 z) An5 (E 2 3 a) An5 (E 2 3 a) f g Ratio 2 Ratio a b c d Parameter e f g 0 a b c d Parameter e f g Figure 5. Light hydrocarbon fingerprints of natural gases in the southwestern Junggar Basin. a. 1,3-Trans-dimethylcyclopentane/1,2-Trans-dimethylcyclopentane; b. cyclohexane/methyl cyclopentene; c. methyl cyclohexane/σdimethylcyclopentane; d. n-heptane/(ethyl cyclopentane+ methyl cyclohexane); e. n-hexane/cyclohexane; f. 2-methyl cyclopentene/3- methyl cyclopentene; g. 3-methyl hexane/2,3-dimethyl pentane. A. the Chepaizi area (C-T reservoir); B. the Chepaizi area (J reservoir); C. the Chepaizi area (K reservoir); D. the western area of the southern basin.

12 718 Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China fingerprints of Jurassic and Cretaceous gases in the area are similar (Fig. 5b, 5c), but are quite different from those in the western area of the southern basin (Fig. 5d). Thus, the gases may have different origins, which will be discussed in detail later Biomarkers of associated condensates Two condensates that are associated with gas were analyzed in biomarker compositions for further characterizing the gas origin. Representative biomarker parameters and chromatograms of the condensates are listed in Table 3 and Fig. 6, respectively. For the Table 3. Representative biomarker parameters of gas associated condensates in the southwestern Junggar Basin. Well Formation Depth (m) HG3 K 1 tg / / XC2 N 1 s /: not detected. 1.Pr/Ph; 2, 3, 4, tricyclic terpane C 20 %, C 21 %, C 23 %; 5, C 24 tetracyclic terpane/c 30 hopane; 6, gammacerane/c 30 hopane; 7, Ts/Tm; 8, 9, 10, sterane C 27 %, C 28 %, C 29 %; 11, C 29 sterane 20S/(20S+20R); 12. C 29 sterane ββ/(ββ + αα). Figure 6. Representative biomarker chromatograms of gas associated condensates in the southwestern Junggar Basin. Well HG 3, m, K 1 tg (a); Well XC 2, m, N 1 s (b).

13 ENERGY EXPLORATION & EXPLOITATION Volume 30 Number condensate from well HG 3, Pr/Ph value is The abundance of tricyclic terpane C 20, C 21 and C 23 follows the order of C 20 > C 21 > C 23. The ratio of C 24 tetracyclic terpane/c 30 hopane is The content of sterane C 27, C 28 and C 29 follows the order of C 27 < C 28 < C 29. C 29 sterane 20S/(20S + 20R) and C 29 sterane ββ/(ββ + αα) are 0.42 and 0.41, respectively. In contrast, for the condensate from well XC 2, Pr/Ph value is The abundance of tricyclic terpane C 20, C 21 and C 23 follows the order of C 20 > C 21 < C 23. The ratios of C 24 tetracyclic terpane/c 30 hopane, gammacerane/c 30 hopane and Ts/Tm are 0.06, 0.22 and 0.52, respectively. The content of sterane C 27, C 28 and C 29 follows the order of C 27 > C 28 < C 29. C 29 sterane 20S/(20S + 20R) and C 29 sterane ββ/(ββ + αα) are 0.37 and 0.45, respectively. In general, the condensate from well HG 3 is lack of heavy hydrocarbon components and, thus, it is relatively difficult to determine the gas source (Fig. 6a). In contrast, the gas associated condensate from well XC 2 is mainly sourced from Jurassic coal-bearing sequences according to oil-source correlation standards, e.g., extremely low relative abundance of tricyclic and tetracyclic terpanes to pentacyclic terpanes (Wang, 2001) (Fig. 6b) Origins and exploration prospect of natural gas Based on the above gas and associated condensate geochemistry, natural gas in the southwestern Junggar Basin can be mainly divided into two genetic types (Table 4). Their exploration prospects were further discussed preliminarily in combination with geological setting Type I: coal-type and oil-type gases sourced from Permian lacustrine mudstones in the Shawan sag This type of gas is distributed mainly in the Chepaizi area, with δ 13 C 2 values ranging from to with an average of Thus, the origin may include coal-type gas, oil-type gas and mixture of them. As shown in the diagram of δ 13 C vs. 1/n (Fig. 7a), the curve of carbon isotope type is convex, being characteristic of mixture between coal-type and oil-type gases (Chung et al., 1988; Zou et al., 2007). In addition, partially reversed order can also be observed, which can be attributed to the mixing of gases sourced from sapropelic and humic organic matters (Dai et al., 2004). Combined with geological setting of source rock development (Wang et al., 2001), it can be deduced that the gases are sourced mainly from Permian source rocks in the Shawan sag, including Lower Permian Fengcheng and Middle Permian Xiawuerhe formations (Fig. 2). They are highly developed in the sag and mature with high organic matter abundance. However, the kerogen type of them is different. The Fengcheng Formation source rocks are characterized by type I-II kerogen, while the Xiawuerhe Formation source rocks are characterized by type II-III kerogen (Cui et al., 2005). Thus, the two units both have good gas generation potential and exploration potential Type II: coal-type gas sourced from Jurassic coal-bearing sequences in the southern basin This type of gas is distributed mainly in the western area of the southern basin and some of the southern part of the Chepaizi area (see lines (1) and (2) in Fig. 7a). The

14 720 Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China Table 4. Representative geochemical parameters of two genetic types of natural gases in the southwestern Junggar Basin. Chemical Biomarker of composition Light associated Genetic type Origin Occurrence (gas dryness) Carbon isotope hydrocarbon condensate I Coal-type and oil-type gases, δ 13 C 2 sourced from Permian The Chepaizi area = 30.29~ Fig. 5a, 5b, 5c / lacustrine mudstones in the Shawan sag II Coal-type gas, The western area Extremely low sourced from of the southern relative abundance Jurassic basin and some of of tricyclic and δ 13 C 2 > 27.5 Fig. 5d coal-bearing the southern part tetracyclic terpanes sequences in the of the Chepaizi to pentacyclic southern basin area terpanes /: no data

15 ENERGY EXPLORATION & EXPLOITATION Volume 30 Number (a) /n 1/4 1/2 The chepaizi area C-T J K (b) (4) Well NA 1 1/n 1/4 1/2 The western area of the southern basin J K 2 -E N (1) Well C (2) Well C C ( ) δ 30 Coal-type gas Coal-type gas (3) Well K 6 13 C ( ) δ Oil-type gas 40 Oil-type gas C 4 C 3 C 2 C 1 C 4 C 3 C 2 C 1 Figure 7. δ 13 C vs. 1/n diagram of natural gases in the Chepaizi area (a) and the western area of the southern basin (b). δ 13 C 2 values are relatively heavier than those of the type-i gas, ranging from to with an average of Therefore, the source area of these gases is different from that of the type-i gas, which is the Shawan sag. This implied that the source area should be the southern basin, where humic organic matters are developed mostly in the Jurassic coal-bearing sequences. Thus, this type of gas is mainly sourced from Jurassic source rocks in combination with geological setting (Dai et al., 2009). The carbon isotopes of ethane, propane and butane of gases in the Sikeshu sag, especially the gas collected from well K 6 (see line (3) in Fig. 7b) are lighter than gases in the Horgos and Anjihai oil-gas fields. This likely indicates a mixture with small amounts of low mature oil-type gas sourced from Cretaceous/Paleogene lacustrine mudstones (Wei et al., 2007). In addition, some secondary alteration on gas may be implied. For example, the nitrogen-rich gases have been discovered in the Horgos oil-gas field (well HQ 2) and Anjihai oil field (well An 5) as discussed previously. Another type of secondary

16 722 Geochemistry and origins of natural gases in the southwestern Junggar basin, northwest China influence may be bacterial oxidation (see line (4) in Fig. 7b), which results in a 13 C- enrichment of the higher molecular-weight hydrocarbon gases (C 2+, especially propane) and a depletion of the methane (Zou et al., 2007). The source rocks of the type-ii gas, i.e., the Jurassic coal-bearing sequences including coals and mudstones, all have high organic matter abundance and are dominated by type III kerogen. The maturity of the rocks is relatively low in the Sikeshu sag and much higher in the eastern areas of the southern basin (Dai et al., 2009; Wei et al., 2010). Thus, the exploration prospect of gas in the Sikeshu sag would be limited in comparison with the eastern area. In addition, there are likely some oil-type gases sourced from Cretaceous/Paleogene source rocks as discussed above. They have relatively low gas generation potential due to low maturation (Wang, 2001), although they also have high organic matter abundance with type I- II kerogen (Wei et al., 2007). 5. CONCLUSIONS Geochemistry of natural gases in the southwestern Junggar Basin was comprehensively analyzed and reported for the first time. Based on the results, their origins and exploration prospects were discussed. (1) Hydrocarbon gases are the main components of the gases, and the gas dryness ranges from 0.63 to The gases are mainly mature with the δ 13 C 1 value ranging from to The origin of the gases is complex, evidenced by the δ 13 C 2 value varying between and Thus, the origin includes coal-type, oil-type and the mixture of them. The light hydrocarbon parameters also indicate the multiple origins of gases. (2) Two genetic types of gases are mainly discriminated. One is the coal-type and oiltype gases sourced from Permian lacustrine mudstones in the Shawan sag. The δ 13 C 2 value ranges from to with an average of 27.03, implying coal-type gas, oil-type gas and a mixture of them. The other is the coaltype gas sourced from the Jurassic coal-bearing sequences in the southern basin. The δ 13 C 2 value is relatively heavier, ranging from to with an average of (3) Gas exploration potential in the Chepaizi area is good. In contrast, gas exploration potential in the Sikeshu sag is relatively limited mainly due to unfavorable maturity condition, while the potential is better eastward. ACKNOWLEDGEMENTS We would like to thank editor and anonymous reviewers for constructive reviews. We thank Dr. Jiande Liao of PetroChina Xinjiang Oilfield Company for his kind and hard work in the experimental. This work was jointly funded by the Major State Basic Research Development Program (973 project, Grant No. 2012CB214803) and the National Natural Science Foundation of China Grant No REFERENCES Chen J.F., Xu Y.C. and Huang D.F., Geochemical characteristics and origin of natural gas in Tarim Basin, China. AAPG Bulletin 84(5),

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