Figure
1.
Geological map and NW-SE profile map of Santanghu Basin. Fm.. Formation.
| Citation: | Daofu Song, Dengfa He, Shurong Wang. Source rock potential and organic geochemistry of carboniferous source rocks in Santanghu Basin, NW China. Journal of Earth Science, 2013, 24(3): 355-370. doi: 10.1007/s12583-013-0339-9
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Carboniferous hydrocarbon exploration in northern Xinjiang has made significant progress in recent years. Several Carboniferous oil/gas reservoirs have been discovered (He et al., 2010; Guo et al., 2009; Lin et al., 2009; Liu et al., 2009; Yan, 2009; Gao, 2008; Zhao et al., 2003; Zhang and Yang, 2000), such as the Wucaiwan gas field, the Kalamaili gas field and the Shixi oil field in Junggar Basin and the Niudong oil field in Santanghu Basin, indicating the good potential for hydrocarbon exploration in Carboniferous systems. The hydrocarbons in these fields originated primarily from Carboniferous source rocks (Cao et al., 2010; He et al., 2010; Guo and Li, 2009; Guo et al., 2009), thus based on Carboniferous source rocks it has been confirmed that a petroleum system exists in northern Xinjiang (Shi et al., 2005). Exploration has shown that Carboniferous reservoir rocks are widely distributed in Xingjiang, comprising primarily volcanic rocks and volcanoclastic rocks with high porosity, and that effective source rock is the key factor controlling hydrocarbon accumulation and distribution in Carboniferous systems (Yang et al., 2010; Zhang and Yang, 2000). Hydrocarbon accumulation occurs around effective source rocks. The Carboniferous exploration in eastern Xinjiang is still in its initial stages; therefore, the distribution of the Carboniferous source rocks is inferred and most of the geochemical indexes are obtained based on several outcropping samples collected from peripheral areas. These geochemical indexes are inadequate to represent the hydrocarbon potential and organic geochemistry characteristics of intrabasinal Carboniferous source rocks (Gao et al., 2009). As a part of the recent exploration in Carboniferous regions, more than sixty wells drilled into Carboniferous strata in eastern Xinjiang; most of these wells were located in Santanghu Basin. Numerous Carboniferous source rocks were confirmed in many wells, making them available for study.
Twenty-five potential Carboniferous source rocks were collected from seven wells in Santanghu Basin. The samples were taken from four formations: Kalagang Formation, Harjiawu Formation, Bashan Formation and Jiangbasitao Formation. The purpose of this article is to evaluate the hydrocarbon generation potential of Carboniferous source rocks in Santanghu Basin (organic richness, potential type of hydrocarbons and thermal maturity). The origin and depositional environment of the organic matter were also analysed based on their organic geochemical characteristics.
Santanghu Basin, eastern Xinjiang, is located between Moqinwula Mountain and Suhaitu Mountain. It is an NW-SE striking band of 500 km long and 40–70 km wide, covering an area of 2.3×104 km2 (Yang et al., 2010; Chen et al., 2009; Gao, 2008; Zhao et al., 2004, Fig. 1). It is an important part of the Paleozoic orogenic belt in northern Xinjiang, belonging to the epicontinental accretional belt in the south margin of the Siberia Plate (Sun et al., 2001; Xiao et al., 1992) and bounding to the north by the Aermantai suture zone and to the south by the Kelamaili tectonic zone. Santanghu Basin is a composite and reconstructive basin developed on the basement of the Paleozoic orogenic belt (Liu et al., 2002). It can be divided into three first-order tectonic units, namely northeastern thrust uplift belt, centre depression belt and southwestern thrust nappe belt (Sun et al., 2001; Hu et al., 1999), and eleven secondary tectonic units, including Malang depression, Tiaohu depression, Hanshuiquan depression, Naomaohu depression, Suluke depression, Kumusu uplift, Suhaitu uplift, Beihu uplift, Tiaoshan uplift, Weibei uplift and Dongshan uplift (Fig. 1).
Volcanic activity frequently occurred during Carboniferous in Santanghu Basin. A large set of volcanic rocks formed (Yang et al., 2010; Gao, 2008) and abundant volcanoclastic and normal clastic rocks were deposited during volcanic eruption intervals. The Carboniferous strata of the studied area can be divided into five formations (from bottom to top, Fig. 2): Donggulubasitao Formation (C1d), Jiangbasitao Formation (C1j), Bashan Formation (C2b), Harjiawu Formation (C2h) and Kalagang Formation (C2k). Kalagang Formation is mainly composed of basicintermediate volcanic lava, including basalt and andesite with transitional rock types between them (Lin et al., 2009). Most of the volcanic rocks are the product of fissure eruption and distribute along faults belonging to the volcanic effusive facies near the crater (Yan et al., 2010; Suo and Li, 2009). A small number of volcanic breccia and agglomerates of volcanic explosive facies are found in only a few of the wells (Lin et al., 2009). In addition to these volcanic rocks, darkly coloured tuffaceous mudstones and carbargilite are deposited in volcanic rock intervals. Harjiawu Formation and its underlying Carboniferous systems are mainly composed of basic-acidic volcanic rocks formed by central vent eruptions (Lin et al., 1997). Basaltic, andesitic and dacitic-rhyolitic lavas, volcanic breccia and eruptive tuff all develop in the study area. Characterised by chaotic domal seismic reflection, they are the products of crater-forming explosion facies (Yan et al., 2010). Volcanoclastic rocks and normal sediments are also widely distributed in these formations. Abundant facies fossils in normal sediments indicate a neritic or marine-continental alternating environment for Carboniferous of Santanghu Basin (Liang and Gou, 2009; Yan, 2009; Lin et al., 1997).
The Carboniferous strata was once considered as the basement of Santanghu Basin (Liu et al., 2002; Hu et al., 1999), so little attention was paid to it until the hydrocarbon exploration in Carboniferous volcanic rocks of Santanghu Basin made considerable progress (Liu et al., 2009). With effective source rocks and several oil/gas reservoirs being continuously found in Carboniferous strata (Yan, 2009), the Carboniferous petroleum system in Santanghu Basin began to attract more and more attention (Yang et al., 2010). Practice and knowledge of exploration showed that the darkly coloured, fine-grained, organic-rich Carboniferous source rocks could be widely deposited during volcanic eruption intervals, mainly including mudstones, tuffaceous mudstones and carbargiltes formed in a neritic environment or a marine-terrigenous condition (Liu et al., 2009; Gao, 2008), and most of them were preserved in Jiangbasitao Formation (C1j), Bashan Formation (C2b), Harjiawu Formation (C2h) and Kalagang Formation (C2k) (Fig. 3).
Sedimentary rocks that are, or may become, or have been able to generate petroleum are source rocks (Tissot and Welte, 1984). The potential Carboniferous source rocks in Santanghu Basin include darkly coloured mudstones, tuffaceous mudstones and carbargilites. A total of 25 samples collected from 7 wells were analyzed mainly by RockEval pyrolysis and biomarker analysis. It is difficult to distinguish the three different types of potential source rocks (darkly coloured mudstones, tuffaceous mudstones and carbargilites) based on log data and hand specimens, so the samples were identified under a microscope using thin sections of rock (Fig. 3).
All the experimental data were obtained in the labs of PetroChina Exploration and Development Research Institute, Beijing. The experimental conditions were as follows.
Total organic carbon (TOC) and Rock-Eval pyrolysis were performed on 100 mg of crushed rock sample. The samples were heated to 600 ℃ in a helium atmosphere using a Rock-Eval II instrument equipped with a TOC module. For this analysis free hydrocarbons (S1), pyrolysate hydrocarbons (S2) temperature of maximum generation (Tmax), HI and production index (PI) were obtained.
The samples were soxhlet-extracted for 72 h with CHCl3. The extracts were separated using column chromatography over activated silica gel with an Iatroscan MK5 apparatus and eluted sequentially to provide four fractions (saturated hydrocarbons, aromatic hydrocarbons, asphaltic hydrocarbons and non-hydrocarbons). To obtain the gross composition of each extract, a quantitative measurement was carried out by means of a flame ionisation detector.
Gas chromatography (GC) of the saturate fractions was performed using an HP-7890 gas chromatograph equipped with a fused silica column (HP-1, 30 m×0.25 mm i.d.). The oven temperature program was 80 ℃ (5 min) to 310 ℃ (held 25 min) at 5 ℃ /min. He was used as the carrier gas. Aromatic hydrocarbons were analysed on a Varian 7890 gas chromatograph fitted with an HP-5MS fused silica column (30 m×0.22 mm i.d.). The oven temperature program was 80 (5 min) to 310 ℃ (held 20 min) at 6 ℃ /min. He was used as the carrier gas. GC-mass spectrometry (GC-MS) analysis of saturate fractions was conducted using a thermo trace GC ultra gas chromatograph fitted with an HP5-MS fused silica column (60 m× 0.25 mm i.d.×0.25 μm film thickness) coupled to a trace DSQ mass selective detector. The samples were analysed in single ion monitoring (SIM) mode with ionisation energy 70 eV, filament current 220 μA, source temperature 250 ℃ and multiplier voltage 2 000 V. The temperature of the GC oven was programmed to rise from 100 (5 min) to 220 ℃ at 4 ℃ /min, then to 320 ℃ (held 65 min) at 2 ℃ /min. He was the carrier gas. The saturated hydrocarbon biomarker parameters were calculated from integrated peak areas on the ion chromatograms.
For the stable carbon isotopic analysis, the samples and their extracts were combusted using an Isopach-13 isotope sample maker. The resulting CO2 was collected and purified using a liquid N2 trap and analysed using a Finnigan MAT-252 isotope ratio mass spectrometer. The working conditions of the Isopach-13 were as follows: oxygen oven temperature 800 ℃, reduction oven temperature 400 ℃, O2 as combustion gas, He as carrier gas and combustion time 5 min.
Vitrinite reflectance measurements were determined under reflected light with a Leitz microphotometric system calibrated with a Leitz Saphir standard (reflectance, R, 0.522%). The photometer was provided with a pinhole aperture to read a spot with a diameter of 5 μm on the sample surface at 546 nm, using a 50×0.85 objective in oil immersion.
Individual results of total organic carbon content, chloroform extracts and pyrolysis analyses of all the Carboniferous samples collected from Santanghu Basin are provided in Table 1. The TOC is expressed as the relative dry weight percentage of organic carbon in the sediments (Batten, 1996a, b ). The Rock-Eval S1 value refers to the amount of free hydrocarbons presenting in the sample, while S2 represents the TOC that can be transformed to hydrocarbons during pyrolysis. (S1+S2) is known as the potential yield and is a measure of the transformation potential of the total organic matter within the rocks (Demaison and Huizinga, 1994; Tissot and Welte, 1984).
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The TOC contents of the Carboniferous carbargilites vary between 12.0% and 18.7%; the chloroform extract amounts range from 0.443% to 1.693%; and the (S1+S2) values range from 12.36 to 123.66 mg/g. The organic richness of the carbargilites is much higher than that of the mudstones. The mudstones have 1.8% to 5.57% TOC, 0.038% to 0.471% chloroform extract and 1.01 to 55.69 mg/g (S1+S2). Tuffaceous mudstones show a wide variation in their TOC contents, chloroform extract amounts and (S1+S2) values. The TOC contents of tuffaceous mudstones vary between 2.25% and 25.7%; the chloroform extract amounts range from 0.007% to 2.244%; and the (S1+S2) values vary from 0.26 to 167.18 mg/g. The organic richness of tuffaceous mudstones is lower than that of carbargilites and higher than that of mudstones (Fig. 4a), showing that rapid volcanic ash deposition is favourable for organic matter preservation; however, an excessive abundance of volcanic ash will also result in a reduction of the total organic content. According to Chen et al. (2007), the content of chloroform extract and S1 and S2 values in source rocks are influenced greatly by the maturity of the organic matter. Here, high maturity (Table 1) is the dominant factor resulting in the low content of chloroform extract and S1 and S2 values for the Carboniferous source rocks in wells H1 and M32.
It is generally accepted that for a rock to be a source of hydrocarbons, it must contain sufficient organic matter to provide significant generation and expulsion for many years. Previous work has established an amount of 0.5 wt.% TOC for shales and 0.3 wt.% TOC for carbonates (Batten, 1996b). The minimum TOC content of a source rock should be within the range of 1 wt.%–2 wt.% (Peters and Cassa, 1994). Based on the TOC content, all the Carboniferous samples collected from Santanghu Basin have the potential to act as good to very good petroleum source rocks (Peters and Moldwan, 1993; Leckie et al., 1988). This is confirmed by the source rock quality as measured by the petroleum potential, S2. With the exception of the samples in wells H1 and M32 (in which high maturity resulted in low S2 values), most of the other Carboniferous samples exceed S2=10 mg Hc/g rock, and several have S2 > 5 mg Hc/g, indicating good to very good hydrocarbon generative potential (Bordenave, 1993; Peters, 1986). Moreover, the source rocks in Harjiawu Formation have higher organic abundance than in other formations (Fig. 4b).
The S1, S2 and HI values exhibit a broad variation in Carboniferous source rocks from Santanghu Basin. The S1 values range from 0.06 to 10.77 mg/g; the S2 values range from 0.19 to 166.1 mg/g; and HI values vary between 6 and 923 mg/g TOC. The S1 and S2 values are determined by kerogen types and many other factors, including maturity and oxidation. The S1, S2 and HI values in the samples from wells H1 and M32 occur in much lower concentrations than in other samples, mainly due to their relatively high maturity.
The pyrolytic parameters of samples from wells H1 and M32 have lost their geological information due to their high maturity (Tmax > 500 ℃); thus, the kerogen types of their organic matter are established through optical palynological methods. The samples from wells H1 and M32 contain abundant amorphous organic matter (83%–89%) with minor amounts of vitrinite, inertinite and sporinite. They have an organic matter type index (TI, Shang et al., 1990) varying between 27 and 34, indicating kerogen Type II. For other samples with Tmax lower than 500 ℃, the cross plotting of the pyrolytic and other parameters is used to indicate the kerogen type and the maturation stages, including the so-called modified Van Krevelen diagram or HI versus Tmax. In the plots of S2 versus TOC (Langford and Blanc-Valleron, 1990) and HI versus T max (Fig. 5), most Kalagang Formation samples plot in type I kerogen fields (oil prone); the Bashan Formation samples plot in Type II kerogen fields (oil prone) and the samples from Harjiawu Formation plot in types I, II or III kerogen fields. All the samples are mature based on Fig. 5b.
The δ13C value of kerogen in the source rocks depends on the types of organisms preserved and the depositional environment (Chung et al., 1992; Schoell, 1984). In general, organic matter originating from aquatic organisms is characterised by light δ13C values, corresponding to Type I or Type II kerogen, and the terrestrial organic matter has a heavy δ13C value, consistent with Type III kerogen.
The kerogen of the samples from wells H1 and M32 have δ13C values from -20.6‰ to -22.2‰ (mean -21.68‰, Table 1). The δ13C values of kerogen in other samples are lighter, varying from -23.1‰– -28.5‰ (average -26.05‰). The δ13C values of chloroform extract are 2‰–5‰ lighter than kerogen in the same samples, ranging from -25.7‰– -31.7‰. In general, all the samples are characterized by relatively light δ13C values of kerogen, except for the samples from wells H1 and M32 (Table 1), supporting a dominance of aquatic organisms input and kerogen Type I and Type II. According to Su (1999), the δ13C value of kerogen in source rocks is also affected by its high maturity. The relatively heavy δ13C values for the samples from wells H1 and M32 are likely related to their high maturity.
Several data types and parameters were used to evaluate the organic maturity, including vitrinite reflectance (Ro), Rock-Eval pyrolysis Tmax and biomarker parameters (Peters et al., 2005; Hunt, 1996; Bordenave et al., 1993; Peters and Moldowan, 1993; Peters, 1986; Waples, 1985; Tissot and Welte, 1984).
The top and bottom of the oil and gas generation vary with the type of organic matter, ranging from 0.5%–1.0% and 1.4%–3.5% Ro, respectively (Espitalié, 1985). Thermogenic oil is thought to be generated at vitrinite reflectance values above 0.6% Ro for kerogen types I and II (Bordenave, 1993). The lowest value of vitrinite reflectance associated with the known generation of conventional oil is approximately 0.5% or 0.6%. The peak of oil generation with vitrinite reflectance values lies between 0.8% and 1% Ro. Generally, vitrinite reflectance values increase with depth due to corresponding increases in temperature and the age of the rock. Most analysed samples show vitrinite reflectance < 1.0%, except for those from wells H1 and M32 (Table 1), which generally cluster around 0.70%–0.85% Ro, corresponding to an mid-mature stage. The minimum reading of the studied samples is 0.53% Ro at 1 720 m depth. The vitrinite reflectance of the samples from wells H1 and M32 is much higher than the other samples, varying from 1.25% to 1.63% Ro and corresponding to high maturity (Hunt, 1996; Tissot and Welte, 1984). The distribution of vitrinite reflectance data suggests that all the Carboniferous samples are sufficiently mature to generate oil.
The thermal maturity of organic matter in the analysed samples is also evaluated based on the Tmax of the S2 peak. The maturation range of Tmax varies for different types of organic matter (Bordenave, 1993; Peters, 1986; Tissot and Welte, 1984). The range of Tmax is narrow for Type I kerogen, wider for Type II and much wider for Type III kerogen due to the increasing structural complexity of the organic matter (Tissot et al., 1987). The maturation window for oil/condensate generation from types I and II organic matter ranges from 430 to 470 ℃ (Tissot et al., 1987; Peters, 1986); from Type III terrigenous organic matter ranges from 465 to 470 ℃ (Bordenave, 1993). The pyrolysis Tmax values are listed on Table 1 and correlate well with the measured Ro. The samples with < 1.0% Ro have Tmax values between 434 and 453 ℃, confirming early to middle maturity for most of the analysed samples. The pyrolysis Tmax values for the samples from wells H1 and M32 are > 500 ℃, suggesting that these samples are probably close to their maximum generative capacity (Tissot and Welte, 1984).
In gas chromatography-mass spectrometry (GC-MS), the 22S/(22S+22R) homohopane ratio is widely used as an indicator of maturity. The 22S/(22R+22S) ratio value of C31 17α(H)- homohopane and C32 17α(H)-bishomohopane for the three samples from a depth of < 2 000 m range from 0.27 to 0.46 and from 0.34 to 0.37, well below their equilibrium values (approximately 0.6, Peters and Moldowan, 1993; Seifert and Moldowan, 1986) and consistent with an early maturity. Other samples from the > 2 000 m depth have C31—22S/(22R+22S) values from 0.54 to 0.59 and C32—22S/(22R+22S) values from 0.55 to 0.61, which are near or at their equilibrium values (Hao et al., 2012) and correspond to a mid-oil window maturity.
Based on the maturity analysis, we can infer that the Carbonifeous source rocks from Santanghu Basin at 1 500 to 2 000 m depth are still in the early mature stage. When the burial depth > 2 000 m, the source rocks enter the peak of oil generation, corresponding to middle maturity. Because of their deep burial, most of the Carboniferous source rocks correspond to the mature or high mature stage.
The nonaromatic fractions of the source rocks from the study area are dominated by n-alkane. Representative gas chromatograms of Carboniferous samples from Santanghu Basin are presented in Fig. 6. In general, the n-alkanes range from C9 to C33. All the samples show a dominance of short-chain n-alkanes with a unimodal distribution centred around nC15–nC23 (maximum at nC15, nC17, nC19, nC21 or nC23, Table 2). For most of the samples, both ∑C21-/∑C22+ and (C21+C22)/(C28+C29) values are > 1.0. The low-molecular n-alkane predominance and most samples with a maximum at nC17, nC19 or nC21 indicate a dominance of algal/bacterial source. Odd/even predominance (OEP, Scalan and Smith, 1970) for C15–C21 range is around 1.0, showing no/slight odd/even predominance, while the long chain n-alkanes exhibit a striking odd predominance with carbon preference index (CPI, Bray and Evens, 1961) values greater than 1.0. According to Peters et al. (2005) and Pancost and Boot (2004), the strong odd/even predominance for long chain n-alkanes is attributable to terrestrial plant input.
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The Pr/Ph ratio has been used as an indicator of the depositional environment (Zeng and Cheng, 1998; Didyk et al., 1978) and to reflect the relationship between contributing organisms and the chemistry of the environment. It is generally accepted that low values (< 1.0) indicate anoxic conditions (Zhang and Zhang, 2009; Chen et al., 2007; Liu et al., 2006) commonly associated with a stratified water column or hypersaline environments, whereas high values (Pr/Ph > 3.0) are related to terrestrial organic matter inputs under less restricted conditions. The Pr/Ph ratio of Carboni-ferous source rocks from Santanghu Basin exhibit a wide variation, ranging from 1.19 to 2.73 and suggesting a suboxic condition of deposition, likely in a neritic or marine-continental alternating environment consistent with the study results presented by Gao (2008). Pristane and phytane are much less abundant than the adjacent n-alkanes, indicating that the samples have not biodegraded (Abeed et al., 2011; Springer et al., 2010; Meng et al., 2004, Fig. 6). Accordingly, the Pr/nC17 and Ph/nC18 ratios for most samples are less than 1.0.
The respective terpanes (m/z 191) and steranes (m/z 191) distributions of Carboniferous source rocks from Santanghu Basin are shown in Figs. 7 and 8. The biomarker data obtained from m/z 191 and 217 mass chromatographs are provided in Table 2. The distribution of terpanes (m/z 191) and regular steranes (m/z 217) is similar in most of the samples.
As shown in Fig. 7, tricyclic and tetracyclic terpanes occur in much lower concentrations than pentracyclic terpanes. Pentacyclic triterpanes (Fig. 7) are characterised by the presence of a series of hopanes from C27 to C35 and other triterpanes (primarily gammacerane, based on retention time and mass spectral data; Seifert and Moldowan, 1978). C30 17α(H)-hopanes are the highest peaks in the m/z 191 chromatograms of all the samples. The terpanes widely found in petroleum and source rock extracts may have originated in microbial cell membranes (Ourisson et al., 1982). This also can be proved by the abundant bituminite which is the principal maceral composition and represents the product of algal decomposed by bacterial.
The use of the 14α(H)17α(H)20(R) C27–C29 regular steranes to evaluate the origin of the organic matter is based on the observation that C27 steranes originate primarily from marine zooplankton, C28 steranes from yeast, fungi, phytoplankton and algae (Volkman, 2003) and C29 steranes from higher plants (Volkman, 1986) and brown and green algae (Zhang and Wang, 2008; Volkman, 2003). The regular steranes for all the samples from the study area are dominated by sitostanes (31.8% to 57.0% of the total of regular steranes, avg. 44%). The content of cholestanes ranges from 22.7% to 40.4% of the total of regular steranes, with a mean of 31.4%. The relative abundance of ergostanes in comparison with the total of regular steranes is low for most of the samples and varies from 12.6% to 34.0%, with an average of 23.4%. Accordingly, all the samples have a C29 > C27 > C28 normalised relative abundance of regular steranes (V pattern, Fig. 8), supporting a mixture of algal/bacterial material and terrigenous higher land plant source (Moldowan et al., 1985).
Carboniferous source rocks in Santanghu Basin were analysed using Rock-Eval pyrolysis/TOC and organic geochemistry. The results indicate that most of the samples in the study area are organic-rich source rocks with very good source rock potential for oil generation, which is supported by their high TOC values, extractable organic matter and hydrocarbon yield. The organic matter of Carboniferous source rocks is predominantly Type I and Type II kerogen with a minor contribution of Type III kerogen, as demonstrated by its pyrolysis parameters and carbon isotope values. Vitrinite reflectance data reveal that the samples in wells H1 and M32 have reached the stage of gas generation, while all the other samples are at the early to middle mature stage. This conclusion is also confirmed by Rock-Eval pyrolysis Tmax and by biomarker maturity parameters.
The origin and depositional environment of the organic matter in Carboniferous source rocks from Santanghu Basin were also analysed through biomarker analysis. All the samples were deposited in a suboxic depositional condition as confirmed by their Pr/Ph ratio, most likely in a neritic or marinecontinental alternating environment. The biomarker analysis and light δ13C value support a dominance of algal/bacterial organic matter inputs, with a minor contribution of land plant material.
ACKNOWLEDGMENTS: Thanks are due to the China National Petroleum Corporation (CNPC) for supporting our sample analysis at its experimental centres. We are particularly grateful to Guangjun Xu and Yuxi Li for their assistance during the laboratory analysis of the samples. This study was financially supported by the China Postdoctoral Science Foundation funded project.| Abeed, Q., Alkhafaji, A., Littke, R., 2011. Source Rock Potential of the Upper Jurassic-Lower Cretaceous Succession in the Southern Mesopotamian Basin, Southern Iraq. Journal of Petroleum Geology, 34(2): 117–134 doi: 10.1111/j.1747-5457.2011.00497.x |
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Daofu Song, Dengfa He, Shurong Wang. Source rock potential and organic geochemistry of carboniferous source rocks in Santanghu Basin, NW China. Journal of Earth Science, 2013, 24(3): 355-370. doi: 10.1007/s12583-013-0339-9
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