Geochemical characteristics of marine and terrestrial shale gas in China

Accepted Manuscript Geochemical characteristics of marine and terrestrial shale gas in China Jinxing Dai, Caineng Zou, Dazhong Dong, Yunyan Ni, Wei Wu, Deyu Gong, Yuman Wang, Shipeng Huang, Jinliang Huang, Chenchen Fang, Dan Liu PII:

S0264-8172(16)30138-6

DOI:

10.1016/j.marpetgeo.2016.04.027

Reference:

JMPG 2545

To appear in:

Marine and Petroleum Geology

Received Date: 8 October 2015 Revised Date:

26 April 2016

Accepted Date: 26 April 2016

Please cite this article as: Dai, J., Zou, C., Dong, D., Ni, Y., Wu, W., Gong, D., Wang, Y., Huang, S., Huang, J., Fang, C., Liu, D., Geochemical characteristics of marine and terrestrial shale gas in China, Marine and Petroleum Geology (2016), doi: 10.1016/j.marpetgeo.2016.04.027. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

ACCEPTED MANUSCRIPT

Geochemical characteristics of marine and terrestrial shale gas in China

Jinxing Dai, Caineng Zou, Dazhong Dong, Yunyan Ni, Wei Wu, Deyu Gong, Yuman Wang, Shipeng Huang, Jinliang Huang, Chenchen Fang, Dan Liu Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, 100083, China

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(Email: [email protected])

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Abstract: Although the annual production of shale gas in China was 13×108 m3 in 2014, a systematic study on geochemical and isotopic characteristics of these unconventional gases has not been well addressed. In the

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present study, almost all shale gas samples available in China, including marine shale gas from the Wufeng-Longmaxi Formation in the Sichuan Basin (O3w-S1l) and terrestrial shale gas from Chang 7 Member (T3y7) in the Ordos Basin, were collected and analyzed for their geochemical and isotopic compositions. The shale gas from the Wufeng-Longmaxi Shale is dry gas with an average methane content of 98.38% and records

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a highest content of CH4 in the world (99.59%), which is consistent with the very high thermal maturity levels of the gas shales that have equivalent vitrinite reflectance (EqVRo) values between 2.4 to 3.6%. The δ13C1

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values are correspondingly heavy and record a heaviest δ13C1 values (-26.7‰) for the shale gases found in the world as well. The average values of δ13C1, δ13C2 and δ13C3 for the Wufeng-Longmaxi shale gas are -31.3‰,

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-35.6‰, and -47.2‰, respectively, displaying a complete carbon isotopic reversal (i.e., δ13C1 > δ13C2 > δ13C3). δ2HCH4 and δ2HC2H6 has an average value of -148‰ and -173‰, respectively, also yielding a hydrogen isotopic reversal (i.e., δ2HCH4 > δ2HC2H6). The Chang 7 shale has an average TOC content of 13.81% with vitrinite reflectance (VRo) values between 0.7 and 1.2%. The Chang 7 shale gas is wet gas with an average methane content of 84.90% and is rich in heavy gaseous hydrocarbons (C2-C5). The respective values of δ13C1, δ13C2 and δ13C3 are -48.7‰, -36.4‰ and -31.3‰, displaying a positive carbon isotopic distribution pattern (i.e., δ13C1 < δ13C2 < δ13C3). The average δ2HCH4, δ2HC2H6 and δ2HC3H8 values are -256‰, -244‰ and -188‰, respectively, and

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ACCEPTED MANUSCRIPT are characterized by a positive distribution pattern (i.e., δ2HCH4 < δ2HC2H6 < δ2HC3H8). The differences in gas wetness and carbon and hydrogen isotopic distribution patterns between the shale gases from the Wufeng-Longmaxi and Chang 7 shale are attributed to variations in thermal maturity levels. CO2 is present in

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low content in both the Wufeng-Longmaxi and Chang 7 shale gases, mostly less than 1%. δ13C values for the CO2 in the Wufeng-Longmaxi Formation are between 8.9 and -9.2‰, indicating an inorganic origin from the cracking of carbonate mineral in the shales under high temperatures. In contrast, δ13C values of the CO2 in the

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Chang 7 shale gas range from -8.2 to -22.7‰, indicating an organic origin from the thermal degradation of

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organic matter. Helium in both the Wufeng-Longmaxi and Chang 7 shale gases is dominantly of curst origin in terms of their R/Ra ratios that vary from 0.01 to 0.08. Positive carbon isotopic distribution pattern is typical of primitive thermogenic gas. However, it can be converted into complete or partial carbon isotopic reversal patterns due to secondary alteration. The causes that yield carbon isotopic reversal include (1) mixing of gases

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with the same source but different thermal maturity levels; (2) secondary cracking of oil or wet gas; (3) formation water-involved reactions; (4) gas diffusion; and (5) carbon isotope exchange between alkane gases at high temperature. Among them, carbon isotopic exchange between alkane gases at high temperature is a key

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factor. Nine plots have been drawn based on the shale gases from China, USA and Canada. Among them, the

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plot of δ13C2 versus wetness demonstrates a “lying-S” shape with two inflection points on the gas wetness axis. The wetness value of 1.4% represents a critical point from pyrolytic gas (primary cracking gas) to cracking gas (secondary cracking gas) and whereas the wetness value of 6% marks the end of oil generation. On the diagram of wetness versus δ13C, shale gases with wetness values greater than 1.6% are characterized by positive carbon isotopic distribution pattern, whereas a complete or partial carbon isotopic reversals are observed for shale gases with wetness values less than 1.6%. Keywords: shale gas, carbon isotopic reversal, high maturity, marine facies, terrestrial facies, China1. Introduction

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ACCEPTED MANUSCRIPT Shale gas was first discovered in 1821 in the Appalachian Basin in the eastern part of United States (Curtis, 2002), but until 1976, it was only produced in the Devonian and Mississippian of Appalachian Basin in the United States (Selley, 2012). In the past decades, due to the breakthrough and comprehensive development of

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horizontal well drilling and hydraulic fracturing technologies etc., a "revolution of shale gas" was launched in the North America, and has spread worldwide. China was also involved in this "revolution". According to the forecast of US Energy Information Administration (EIA, 2013), the geological reserves of shale gas in China

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are approximately 143.39×1012 m3 with technical recoverable reserves up to 31.57×1012 m3. Ministry of Land

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Resources, China (MLR) also assessed the prospects of China's onshore shale gas resources during the year from 2010 to 2012 and claimed that the geological reserves are 134.42×1012 m3, of which the technical recoverable reserves are 25.1×1012 m3 (Zhang et al, 2012).

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In 2005, China started theoretical research and exploration and development of shale gas. After nearly 10 years of exploration, the preliminary evaluation and screening of favorable area of China's onshore shale gas potential was completed, and the extensive exploration and development of shale gas has been carried out. In

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September 2014, news from the MLR showed that the total investment of shale gas exploration and

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development in China exceeded 20×109 Chinese Yuan, and 400 shale gas wells (including 240 horizontal wells) were drilled. Shale gas has been discovered in multiple shale units in many onshore parts of China (Figure 1). Paleozoic marine shale gas has been found in the Changning-Zhaotong, Fushun-Yongchuan, Weiyuan and Jiaoshiba areas in southern Sichuan Basin, while Mesozoic terrestrial shale gas has been discovered in the Ganquan Xiasiwan area of Ordos Basin. In the Sichuan Basin, the Wufeng-Longmaxi shale gas field in Fuling, which is China's first shale gas field with over one hundred billion cubic meters of gas reserves, has been discovered. By the end of 2014, an annual industrial production capacity of 2.5 billion m3 had been completed,

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ACCEPTED MANUSCRIPT which brought the initial prospect of China’s shale gas exploration and development. A great number of studies have been carried out on the geochemical characteristics of shale gas in the USA and Canada (Jenden et al., 1993a; Martini et al., 2003, 2008; Hill et al., 2007; Burruss and Laughrey, 2010;

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Osborn and Mclntosh, 2010; Rodriguez and Philp, 2010; Strąpoć et al., 2010; Hunt et al., 2012; Zumberge et al., 2012; Hao and Zou, 2013; Tilley and Muehlenbachs, 2013). The shale gas exploration just started in China. To date, only Dai et al. (2014a) performed a preliminary geochemical study on the geochemistry of shale gas from

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the Longmaxi Formation in the Changning-Zhaotong and Weiyuan-Yongchuan areas in Sichuan Basin. Carbon

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isotopic reversal (i.e., carbon isotopic composition decreases with increasing carbon number) has been commonly observed for high maturity shale gas, but there is no consensus concerning this enigmatic phenomenon (Jenden et al., 1993a; Hill et al., 2007; Burruss and Laughrey, 2010; Rodriguez and Philp, 2010; Zumberge et al., 2012; Hao and Zou, 2013; Tilley and Muehlenbachs, 2013; Xia et al., 2013; Gao et al., 2014).

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Based on the geochemical characteristics of shale gases from marine shales in Sichuan Basin and terrestrial

reversal.

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2. Geological Setting

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shales in Ordos Basin, this study performed a detailed discussion on the cause of partial carbon isotopic

From the Precambrian to the Neogene, abundant organic-rich shale formations were developed in the Chinese mainland. These organic-rich shales were formed mainly in three major depositional environments, including marine, transitional facies-limnetic facies coal measures and lacustrine environments. Compared to the North America shales, the geological conditions of organic-rich shales in China are complex, which are characterized by great burial depth, complex evolutionary history and ground conditions. The Sichuan Basin has an area of approximately 18.1×104 km2, and is one of the most stable large

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ACCEPTED MANUSCRIPT sedimentary basins in China (Figure 1). It is the first basin in China that produces commercial conventional natural gas, and also a major gas producing area in China currently. The basin mainly developed six sets of black shales including three sets of marine strata (Figure 2). From bottom to top, they are the Proterozoic Lower

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Sinian Doushantuo Formation, the Paleozoic Lower Cambrian Qiongzhusi Formation, and the Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation. Among them, the Wufeng-Longmaxi Shale (O3w-S1l) is featured by large thickness, high organic enrichment, high maturity, strong gas generation

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capability and good rock brittleness, which are conducive to the formation and enrichment of shale gas. The

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first shale gas field in China– Jiaoshiba gas field, has been found in this basin with a shale gas production of more than 12×108 m3 in 2014.

The organic-rich Wufeng-Longmaxi Shale (TOC>2%) is mainly developed in the bottom part of the Wufeng -Longmaxi Formation. Except in the palaeo-high in the Leshan-Longnvsi area, it is widely distributed

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throughout the Sichuan Basin with a maximum thickness of approximately 120 m in the depositional center (Figure 3). The distribution area of the Wufeng-Longmaxi Formation is more than 10×104 km2, and the part of it that is buried less than 4000 m covers an area of approximately 5×104 km2. The TOC values for the Longmaxi

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Shale range from 0.35 to 18.4% with an average of 2.52%. Shales with TOC values greater than 2% account for

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45% of the total shale unit. The primitive organic matter is dominated by amorphous macerals and belongs to type I and/or IIa kerogens. The shales display very high thermal maturity levels with equivalent vitrinite reflectance (EqVRo, %) values typically in the range from 1.8 to 3.6%, indicating they are largely thermally over-mature and in dry gas generation stage. The Wufeng-Longmaxi Shale has relatively good porosity and permeability (Zou et al, 2010; Huang et al, 2012; Wang et al, 2012; Zou, 2013). The porosity ranges from 1.15 to 10.8% with an average of 3.0%, and the permeability varies from 0.00025×10-3 to 1.737×10-3 µm2 with an average of 0.421 × 10-3 µm2. Regionally, the mineral composition of Wufeng-Longmaxi Shale did not change

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ACCEPTED MANUSCRIPT significantly, and the brittle mineral content is in the range of 47.6–74.1% with an average of 56.3% (Figure 4). The Ordos Basin is located in northern China and covers an area of approximately 37×104 km2 (Figure 1). It ranks the second largest sedimentary basin in size but is producing the largest amount of natural gas in China.

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On the Archean and Proterozoic crystalline basement rocks were deposited a series of sedimentary rocks ranging in age from the Middle-Upper Proterozoic through the Cenozoic. Among these sedimentary rocks are three sets of black shales formed under various depositional environments, including the Ordovician marine

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Pingliang Shale, the Carboniferous-Permian coal-bearing shales deposited in transitional marine and terrestrial

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environments and the terrestrial Triassic Yanchang Shale. The seventh member of Yanchang Formation (T3ych7) contains excellent shale layers that were formed in deep lake environment and are often generally referred to as the Chang 7 Shale (Figure 5). To date, 64 wells have been drilled for unconventional oil and gas in the Chang 7 Shale in the Ordos Basin, and the preliminarily proved gas-bearing area in the Xiasiwan Block (Figure 6) is

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approximately 130 km2, with proved shale gas reserves of around 290×108 m3 and an annual shale gas production of about 1.18 × 108 m3.

The Chang 7 Shale is featured by great thickness (Figure 6), high TOC contents and relatively high

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brittleness, all of which are conducive to the shale gas formation and enrichment. The Chang 7 Shale has

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extremely high TOC values, most of which are in the range from 6 to 14% and can be up to 40%. The organic-rich shale has an average TOC of 13.81%. Vertically, the upper part of the Chang 7 Shale has relatively low TOC values less than 3%, whereas the shale in the bottom part has high TOC values typically greater than 10%. The Chang 7 Shale was formed in a reducing depositional environment with deep water, moderate salinity, and weak water stratification (Wang, 2014). The Chang 7 Shale, with equivalent vitrinite reflectance values (EqVRo, %) mostly in the range from 0.7 to 1.2% (Figure 7), is mainly in the peak oil to early gas generation stages. The Chang 7 shale has relatively low porosity and permeability. The porosity ranges from 0.5 to 3.5%,

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ACCEPTED MANUSCRIPT and about 70% samples have permeability less than 0.01×10-3 µm2. The pore diameter typically ranges from 6 to 9 nm with an average of 7.2 nm (Gao et al., 2014). Brittle minerals are dominated by quartz and feldspar

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(Figure 4), and the total clay content is relatively high and varies from 37.4 to 72.8% with an average of 42.1%.

3. Samples and methods

Eleven shale gas samples from the Triassic Yanchang Formation in the Ordos Basin and 45 shale gas

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samples from the Wufeng-Longmaxi Formation in the Sichuan Basin were collected for analyses of molecular composition, and isotopes of carbon, hydrogen and helium (Table 1, Table 2). For comparison purposes, some

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gas samples from conventional reservoirs were collected and analyzed, including one gas sample from the Triassic Xujiahe Formation and one from the Jurassic in the Sichuan Basin, four gas samples from the Jurassic, Permian, Triassic and Ordovician in the Ordos Basin, one gas sample from the Paleogene in the Qiongdongnan

(Table 2, Table 3).

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Basin, one from the Ordovician in the Bohai Bay Basin and one from the Carboniferous in the Junggar Basin

The molecular composition of gas samples was determined using an Agilent 7890 gas chromatograph

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equipped with a flame ionization detector and a thermal conductivity detector at the Research Institute of

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Petroleum Exploration and Development of PetroChina (RIPED). GC oven temperature was initially set at 70 ºC for 5 min, and then ramped to 180 ºC at 15 ºC/min, and finally maintained at 180 ºC for 15 min. All the gas compositions were corrected for oxygen and nitrogen. Stable carbon isotope values were determined on a Thermo Delta V mass spectrometer interfaced with a Thermo Trace GC Ultra gas chromatograph (GC) also at RIPED. Individual hydrocarbon gas components (C1-C4) and CO2 were separated on a gas chromatograph using a fused silica capillary column (PLOT Q 27.5 m×0.32 mm×10µm) followed by conversion into CO2 in a combustion interface, and then injected into the mass

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ACCEPTED MANUSCRIPT spectrometer. The GC oven was ramped from 33 ºC to 80 ºC at 8 ºC/min, then to 250 ºC at 5 ºC/min, and maintained at the final temperature for 10 min. Gas samples were analyzed in triplicate, and the stable carbon isotope values are reported in the δ-notation in per mil (‰) relative to the Vienna Peedee Belemnite standard

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(VPDB). Precision for δ13C analysis is ± 0.5‰ for individual hydrocarbon gas compounds. Stable hydrogen isotopes were measured on a GC/TC/IRMS mass spectrometer at RIPED, which consists of Trace GC Ultra gas chromatograph (GC) interfaced with a micropyrolysis furnace (1450 ºC) in line with a Finnigan MAT253

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isotope ratio mass spectrometer. Gas components were separated on a HP-PLOT Q column (30m × 0.32mm ×

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20µm) with a helium carrier gas flow of 1.5 ml/min. After high-temperature thermal conversion, gases were cracked into H2, and then the H2 was injected into the mass spectrometer. Split injection was used for methane with a ratio value of 1:7, and a constant temperature of 40 ºC was used. For ethane and propane, they were injected into the mass spectrometer using a non-split injection mode, and the temperature was initially set at 40

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ºC for 4 min, and then increased to 80 ºC at 10 ºC/min, then to 140 ºC at 5 ºC/min, and finally to 260 ºC at 30 ºC /min. The temperature of the pyrolysis oven was 1450 ºC. The gas compounds were transformed into C and H2. The H2 went into mass spectrometer to be determined. The stable hydrogen isotope values (δ2H) are reported in

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the δ-notation in per mil (‰) relative to standard mean ocean water (VSMOW) with an analysis precision of

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±3 ‰. The working standard in our laboratory for hydrogen isotope analysis is a coal-derived hydrocarbon gas that was collected from the Ordos Basin and has been calibrated by ten laboratories through more than 800 measurements with both on-line and off-line methods (Dai et al., 2012b). Two-point calibrations were performed with international measurements standards for carbon isotope ratios (NBS19 and L0SVEC CO2) and hydrogen isotope ratios (VSMOW and SLAP). The consensus δ13C values and uncertainties were derived from the Maximum Likelihood Estimation (MLE) based on off-line measurements; the consensus δ2H values and uncertainties were derived from MLE of both off-line and on-line measurements, taking the bias of on-line

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ACCEPTED MANUSCRIPT measurements into account (Dai et al., 2012b). The calibrated consensus values reported in ‰ relative to VSMOW and VPDB are: δ13C of -34.18±0.10‰ for methane, -24.66±0.11‰ for ethane, -22.21±0.11‰ for propane, -21.62±0.12‰ for i-butane, -21.74±0.13‰ for n-butane, and -5.00±0.12‰ for CO2; δ2H of

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-185.1±1.2‰ for methane, -156.3±1.8‰ for ethane, and -143.6±3.3‰ for propane (Dai et al., 2012b). All of these values are traceable to the international carbon isotope standard of VPDB and hydrogen isotope standard of VSMOW.

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Helium isotopic measurements were made on a VG5400 mass spectrometer at the Research Institute of

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Petroleum Exploration & Development-Langfang (RIPED-Langfang), PetroChina, China. A defined amount of sample gas is transferred into a preparation line which separates and purifies the noble gases from other gases and is connected to the VG5400 apparatus. The 3He/4He ratios are reported relative to the atmospheric ratio (Ra) using Lanzhou air helium as an absolute standard (Ra=1.4×10-6). Reproducibility

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and accuracy for 3He/4He ratios are estimated to be ±3%.

4. Geochemical characteristics of marine and terrestrial shale gas

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This study collected 56 gas samples from 53 wells of marine shale gas in the Wufeng-Longmaxi

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Formation and marine shale gas in the Late Triassic Xujiahe Formation in southern Sichuan Basin, and terrestrial shale gas in the Chang 7 Member in southeastern Ordos Basin (Figures 1, 3, 6). A series of analyses have been carried out for molecular composition, carbon, hydrogen and helium isotopes of the gases (Tables 1, 2) and a comparative study has been performed on the alkane gas, carbon dioxide, carbon and hydrogen isotopes for marine and terrestrial shale gases. 4.1 Hydrocarbon gas

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ACCEPTED MANUSCRIPT Methane is the dominant constitute of the shale gas from marine Wufeng-Longmaxi Formation (O3w-S1l) and varies in concentration from 95.52 to 99.59% with an average of 98.38% (Table 1). The content of ethane varies from 0.23% (Well Lai101) to 0.74% (Well Jiao12-2); the content of propane ranges from below detection

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to 0.05% and no butane is identified. Alkane gas contents in shale gas from the Wufeng-Longmaxi Formation are similar to those in the conventional gas in the gas fields of Carboniferous Huanglong Formation in eastern Sichuan Basin which is sourced from Longmaxi Formation (Hu and Xie, 1979; Dai et al., 2010), and are also

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comparable to those in the shale gas from Fayetteville, Barnett, Utica , Marcellus and Canadian Horn River

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shales (Jenden et al., 1993a; Hill et al., 2007; Burruss and Laughrey, 2010; Rodriguez and Philp, 2010; Zumberge et al., 2012; Tilley and Muehlenbachs, 2013). Note that the shale gas from the Wufeng-Longmaxi Formation has the highest average methane concentration for shale gas around the world and the methane content is up to 99.59% for the Well Yang201-H2, which is the highest value ever reported for shale gas.

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In the Ordos Basin, shale gas from the terrestrial sapropelic Chang 7 Shale (Table 2) has methane content ranging from 76.09% (Well Xin59, 1076-1084m) to 91.68% (Well Liuping177) with an average of 84.90%; the content of ethane ranges from 1.15% (Well Fuye1) to 10.85% (Well Liuping179, 1460m) with an average of

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6.83%; the propane content varies from 0.08% (Well Fuye1) to 6.59% (Well Liuping179, 1460m) with an

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average of 3.32%; the sum of n-butane and i-butane ranges from 0.03% (Well Fuye1) to 3.27% (Well Xin59, 1076-1084m) with an average of 1.32%. Therefore, the Chang 7 shale gas has high content of C2+ alkane gases and belongs to wet gas. This is similar to the wet gas with high content of alkane gases from the mature Barnett shale.

Table 2 shows the alkane content of shale gas from the Xu5 Member (T3x5) for the Well Xinye2 in the Xinchang tight gas field of the Sichuan Basin. The Xujiahe Formation can be subdivided into 6 members, among which the Xu1 (T3x1), Xu3 (T3x3), and Xu5 (T3x5) members are largely made up of dark grey to grey mudstones

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ACCEPTED MANUSCRIPT and shales and interbedded coal seams that were deposited in swamp environments and contain mainly humic organic matter. The Xu2 (T3x2), Xu4 (T3x4) and Xu6 (T3x6) members are reservoir rocks of many tight gas fields (including the Xinchang gas field) in the Sichuan Basin (Dai et al., 2014b). The thermal maturity level of organic

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matter in the Xu5 Member is similar to that of the Chang7 shale, with a vitrinite reflectance value (Ro %) of about 1.2%.

As shown in Table 2, the content of C2+ (C2-5) shale gas from the sapropelic Lower Triassic Chang 7 (T1y7)

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Member in the Ordos Basin is higher than that in the Upper Triassic Xu5 Member (T3x5) of Sichuan Basin. This

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is partly attributed to the relatively lower thermal maturity level of the Chang 7 Shale as compared to that of T3x5. Furthermore, the difference in organic matter type between the two shales might also contribute to the chemical composition of natural gas because sapropelic source rocks tend to produce more C2+ hydrocarbon gases than humic source rocks even at comparable thermal maturity levels (Table 3). As shown in Tables 1 and 2, shale gas

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from the marine Wufeng-Longmaxi Formation has high content of methane with an average of 98%, and the content of heavy hydrocarbon gas is very low. However, the terrestrial Chang7 and Xu5 shale gas has low content of methane (85.61% on average) but high content of heavy hydrocarbon gases. This is mainly due to the

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4.2 CO2

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maturity of source rocks.

CO2 is present in very low quantities for the Wufeng-Longmaxi shale gas, ranging from below 1% for most gas samples to 1.74% for one gas sample in the Well Dong202-H1 (Table 1). The CO2 content is also low in the Chang 7 and Xu 5 shale gas, but high content of CO2 is also encountered in some wells, such as Well Yanye22 (up to 11.26 %) and Well Fuye 1 (7.55 %) (Table 2). As shown in Figure 8, the content of CO2 in either marine or terrestrial shale gas increases with the decrease of ethane. This phenomenon is also observed for the marine shale gas from the Barnett, Antrim, and Fayetteville shales in USA (Martini et al., 2003; Zumberge et al., 2012).

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ACCEPTED MANUSCRIPT 4.3 Stable carbon and hydrogen isotopes 4.3.1 Carbon isotopes The Wufeng-Longmaxi shale gas has δ13C1 values from -26.7‰ (Zhao 104) to -37.3‰ (Wei 201) with an

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average of -31.3‰, δ13C2 values from -31.6‰ (YSL 1-1H) to -42.8‰ (Wei 202) with an average of -35.6‰, and δ13C3 values from -33.1‰ (Zhao 104) to -49.5‰ (PY1) with an average of -38.9‰ (Table 1). In the

Changning-Zhaotong area, except Well Ning H2-3, all shale gas samples have δ13C1 values from -26.7 to -28.9‰,

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which is the heaviest δ13C1 range among the known shale gases in the world. For example, the heaviest δ13C1

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value is -35.4‰ for the Fayetteville shale gas in the Arkoma Basin (Ro=2.5–3.0%) (Edwards J. 3-36-H), -35.7‰ for the Barnett shale gas in the Fort Worth Basin (Ro=1.3–2.1%) (WS Minerals Well 4H) (Rodriguez and Philp, 2010; Zumberge et al., 2012), -30.9‰ for the Queenston shale gas in the Northern Appalachian Basin (Harris Unit 4079) (Jenden et al., 1993a) where the Ordovician Utica shale gas has δ13C1 value of -26.97‰ (Burruss and

Muehlenbachs, 2013).

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Laughrey, 2010), and -27.6‰ for the Devonian Horn River shale gas in the WCSB (HR1) (Tilley and

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Shale gas with heavier δ13C1 values in the Fayetteville, Barnett, Queenston, Utica and Horn River shales is usually distributed in over-mature regions. The Longmaxi Shale in the Changning-Zhaotong area has even

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higher thermal maturity levels than those shales in USA and Canada. For example, the shale in Well Zhao 104 has an EqVRo value of 3.4%, which corresponds to the heaviest δ13C1 value of -26.7‰. Therefore, high maturity level is an important cause for the presence of isotopically heavy methane in shale gas. In addition, the carbon isotopic composition of methane is also closely dependent on the carbon isotope of its parent kerogen. As illustrated in Figure 9, the kerogen δ13C values in the Changning-Zhaotong area are heavier than those in the Weiyuan area. In particular, the kerogen δ13C value is as heavy as -25.8% for the Well Ning 211 at 2214.65m in the Changning-Zhaotong area. Therefore, the much heavier δ13C1 values for the shale gas in the

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ACCEPTED MANUSCRIPT Changning-Zhaotong area can be attributed to both the higher thermal maturity level and the heavier kerogen δ13C value. Chang 7 shale gas has δ13C1 values from -40.8‰ (Yongye 1) to -53.4‰ (Yanye 11) with an average of

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-48.7‰; δ13C2 values from -30.8‰ (Fuye 1) to -39.5‰ (Yanyeping 1) with an average of -36.4‰; δ13C3 values from -19.6‰ (Fuye 1) to -34.3‰ (Yanyeping 1) with an average of -31.3‰; and δ13C4 value from -23.2‰

(Liuping 179, 1453-1479m) to -34.7‰ (Liuping177, 1070-1487m) with an average of -31.6‰ (Table 2). The

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respective δ13C value for C1, C2, C3, and C4 in the Xu5 shale gas sample is -36.2‰, -25.1‰, -22.9‰-22.4‰, all

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of which are heavier than the average carbon isotopic composition of counterpart compounds in Chang7 shale gas (Figure 10a). Because the thermal maturity levels of the two shales are only slightly different (Table 2), the difference in stable carbon isotopic compositions for their shale gas is most likely caused by the fact that kerogen is humic in Xu5 but sapropelic in Chang7. The carbon isotope varies from -26.9‰~-25.4‰ for the

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kerogen in Xu5 (Yang et al., 2009) and from -30.0‰~-28.5‰ for the kerogen in Chang7 (Yang and Zhang, 2005). This is because, the carbon isotope of alkane gas is controlled by various factors such as the thermal evolution of source rocks, the types of organic matter and gas generation mechanism. Therefore, at a similar

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thermal maturity, humic source rocks might generate methane and its homologues with heavier carbon isotopes

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than those sapropelic source rocks (Table 3) (Stahl and Carey, 1975; Dai and Qi, 1989). With similar maturity, δ13C1 value of shale gas sourced from marine sapropelic source rocks will be around 14‰ lower than those from terrestrial humic source rocks (Zheng and Chen, 2000). Shale gases from the marine Wufeng-Longmaxi Formation and terrestrial Chang7 and Xu5 members have different isotopic distribution pattern among the C1-C4 alkanes (Figure 10). Dai et al. (2004) proposed three types of stable carbon isotopic distribution pattern. The first one is a positive or “normal” carbon isotopic distribution pattern where the δ13C value increases with increasing carbon number (i.e., δ13C1 < δ13C2 < δ13C3 <

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ACCEPTED MANUSCRIPT δ13C4), which is usually typical of thermogenic gas from primary cracking of kerogen; the second is a completely or totally reversed stable carbon isotopic distribution pattern with δ13C1 > δ13C2 > δ13C3 > δ13C4; the third pattern is characterized by a partial carbon isotopic reversal where there are no general rules between the

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carbon isotopic composition and carbon number (i.e., δ13C1 > δ13C2 < δ13C3 < δ13C4 or δ13C1 < δ13C2 > δ13C3 > δ13C4). Both the Chang7 and Xu5 shale gases are largely characterized by a positive carbon isotopic distribution pattern with occasional partial carbon isotopic reversal, indicating their organic origin (Figure 10a and Table 2).

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In contrast, all the shale gas samples from the Wufeng-Longmaxi Formation display a completely reversed

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carbon isotopic distribution (Figure 10b, Table 1). Shale gas from the Barnett and Fayetteville shale which also has high thermal maturity has all the three kinds of carbon isotopic distribution pattern (Rodriguez and Philp, 2010; Zumberge et al., 2012), this is because the thermal maturity of the Barnett and Fayetteville shale is also high but still lower than that of the Wufeng-Longmaxi shale, so all the three types of carbon isotopic

4.3.2 Hydrogen isotopes

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distribution patterns are observed.

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Shale gas from the Wufeng-Longmaxi Formation has δ2HCH4 values from -136‰ (Wei 201) to -163‰ (Jiaobisha 12-1) with an average of -148‰ and δ2HC2H6 values from -128‰ (Yang 101) to -224‰ (Jiaoye 1).

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Shale gas from the Chang 7 shale has δ2HCH4 values from -237‰ (Fuye 1) to -277‰ (Yanye 5, Yanyeping 1) with an average of -256‰, δ2HC2H6 values from -182‰ (Fuye 1) to -286‰ (Yanye 5) with an average of -244‰ and δ2HC3H8 values from -170‰ (Yongye 1) to -203‰ (Liuping 179, 1460m) with an average of -188‰. The Xu 5 shale gas has δ2HCH4 value of -178‰ and δ2HC2H6 value of -147‰ (Table 2). The shale gas from the marine Wufeng-Longmaxi Shale has heavier δ2HCH4 values than that from the terrestrial Chang 7 and Xu 5 shales, and most of the shale gas from the Wufeng-Longmaxi Shale has δ2HC2H6 values heavier than that from the terrestrial Chang 7 and Xu 5 shales. Both δ2HCH4 and δ2HC2H6 values for the terrestrial sapropelic Chang7 shale gas are

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ACCEPTED MANUSCRIPT lighter than those for the terrestrial humic Xu 5 shale gas. Similar to carbon isotopes, the hydrogen isotopic distribution pattern can be also divided into three types. The first one is a positive hydrogen isotopic distribution pattern where δ2H value increases with increasing

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carbon number (δ2HCH4 < δ2HC2H6 < δ2HC3H8 < δ2HC4H10); the second is a completely reversed hydrogen isotopic distribution (δ2HCH4 > δ2HC2H6 > δ2HC3H8 > δ2HC4H10); the third displays a pattern of partial hydrogen isotopic reversal. As shown in Figure 11 and Table 1, except four samples from the Gaoshun-Yongchuan area that

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display a positive hydrogen isotopic distribution, all other gas samples from the Wufeng-Longmaxi Shale in

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southern Sichuan Basin are characterized by hydrogen isotopic reversal. For the Chang 7 and Xu 5 shale gases, a predominant positive hydrogen isotopic distribution pattern is observed with only three samples displaying partial hydrogen isotopic reversal (δ2HCH4 < δ2HC2H6 > δ2HC3H8) (Figure 11, Table 2).

4.4 Plot of the alkane gas composition, carbon and hydrogen isotopes

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Figure 12 shows the relationship between δ13C1 and δ13C2 values for shale gases from the Wufeng-Longmaxi Formation (Table 1) and Chang 7 Member (Table 2) in China, Barnett and Fayetteville

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shales (Rodriguez and Philp, 2010; Zumberge et al., 2012), New Albany and Antrim shales (Martini et al., 2003, 2008; Strąpoć et al., 2010), Marcellus shale, Queenston shale and Organic-rich shales (Undifferentiated Upper

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Devonian Shale in Appalachian Basin) (Jenden et al., 1993a; Osborn and Mclntosh, 2010), Utica shale (Burruss and Langhrey, 2010), Doig, Montney and Horn River shales in West Canada Basin (Tilley and Muehlenbachs, 2013). The AB line means equal δ13C1 and δ13C2 values; the area above the AB line represents shale gas that is in thermally mature stage and characterized by δ13C1 < δ13C2; the area under it, however, represents shale gas that is in thermally overmature stage and characterized by δ13C1 > δ13C2. It is evident that the Wufeng-Longmaxi shales in China has the most advanced thermal maturity levels among these gas shales, and correspondingly the shale gas stored in them also has the heaviest δ13C1 values. Hao and Zou (2013) has made such a plot based on

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ACCEPTED MANUSCRIPT the Barnett and Fayetteville shale gases. By combing together all shale gases from both China and North America, Figure 12 in this study shows a clear relationship between δ13C1 and δ13C2 values that is shaped like a letter “N” from low maturity, through maturity, into over maturity levels.

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As Figure 13 shows, a trend shape like the Greek letter “п” is observed on the diagram of δ13C1 versus gas wetness when all available shale gas data are plotted together discovered in the Wufeng-Longmaxi (Table 1) and Chang7 shales (Table 2) in China, Barnett and Fayetteville shales (Rodriguez and Philp, 2010; Zumberge et

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al., 2012), New Albany and Antrim shales (Martini et al., 2003, 2008; Strąpoć et al., 2010), Marcellus,

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Queenston shales, and the Upper Devonian organic-rich shales in northern Appalachian Basin (Jenden et al., 1993a; Osborn and Mclntosh, 2010), Utica shales (Burruss and Langhrey, 2010) in USA, and Horn River and Doig shales in Canada (Tilley and Muehlenbachs, 2013).

Figure 14 shows the relationship between δ13C2 and gas wetness for the shale gases from the

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Wufeng-Longmaxi (Table 1) and Chang 7 shales (Table 2) in China, Barnett, Fayetteville, New Albany, Marcellus, Queenston, northern Appalachian Basin and Utica shales in USA, and Horn River shale in West Canada Basin (Jenden et al., 1993a; Burruss and Langhrey, 2010; Osborn and Mclntosh, 2010; Rodriguez and

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Philp, 2010; Zumberge et al., 2012; Tilley and Muehlenbachs, 2013). The decreasing trend of gas wetness

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reflects the thermal evolution of a source rock shale from low maturity, through maturity, into high to over maturity levels. In particular, the shale gas from the Wufeng-Longmaxi Formation in China fills up the blank area of high to over maturity, thus revealing a whole thermal evolution process on the diagram of δ13C2 versus gas wetness along with other shale gas data. It is evident that with increasing gas wetness, there is a “lying-S” trend on the diagram of δ13C2 versus gas wetness. The left turning point of the “lying-S” shape corresponds to a gas wetness value of approximately 1.4%, and it is about 6% for the right turning point. These two gas wetness values are of great geochemical significance because the value of 6% usually marks an ending of oil generation

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ACCEPTED MANUSCRIPT and the value of 1.4% largely corresponds to a beginning of wet gas cracking. Figure 15 shows the relationship between δ13C1 and δ2HCH4 values for the shale gases from the Wufeng-Longmaxi Formation (Table 1) and Chang 7 Member (Table 2) in China, Barnett, Fayetteville, Antrim,

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New Albany, Organic-rich, Marcellus, Queenston and Utica shales in USA (Jenden et al., 1993a; Martini et al., 2003, 2008; Burruss and Langhrey, 2010; Osborn and Mclntosh, 2010; Rodriguez and Philp, 2010; Strąpoć et al., 2010; Zumberge et al., 2012). It is clear to see that there is largely positive relationship between the δ13C1

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Wufeng-Longmaxi Formation having the heaviest δ13C1 values.

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and δ2HCH4 values for the shale gases from both China and USA, with the Chinese shale gases from the

Figure 16 shows the relationship between δ2HCH4 and gas wetness values for shale gases from the Wufeng-Longmaxi Formation (Table 1), Chang 7 and Xu 5 members (Table 2) in China and various shales in USA. Similar to the relationship between δ13C1 and gas wetness values (Figure 13), the δ2HCH4 and gas wetness

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values are also closely related to one another and yield a “lying-п” trend shape on the diagram of δ2HCH4 and gas wetness (Figure 16). The upper branch of the lying “п” is mainly comprised of the marine shale gases with high δ2HCH4 values, whereas its lower branch is dominated by the shale gases with low δ2HCH4 values, including

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the terrestrial Chang 7 shale gases and the marine Antrim shale gases. This is because marine shales deposited

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in saline waters tend to produce methane with heavy hydrogen isotopes, whereas terrestrial shales deposited in fresh waters will produce methane with light hydrogen isotopes (Wang, 1996). As far as the shale gas from the marine Antrim shale gas is concerned, low δ2HCH4 values are likely related to both their biogenic origin and the influx of glacial meltwaters during methanogenic process (Martini et al, 2008).

4.5 Helium isotope of shale gas Shale gas from the Wufeng-Longmaxi Formation in the Sichuan Basin has 3He/4He values from 1.5×10-8 (Zhao 104, YSL1-1H) to 6.0×10-8 (Jiaoye 1-2) and R/Ra ratios from 0.01 (Zhao 104, YSL1-1H) to 0.04 (Jiaoye

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ACCEPTED MANUSCRIPT 1-2 Jiaoye 7-2 Jiaoye 9-2 Jiaoye 11-2) (Table 1). For the shale gas from Chang 7 Member in the Ordos Basin (Table 2), the 3He/4He values range from 7.6×10-8 (Yanye 13) to 10.9×10-8 (Xin 59) and R/Ra ratios vary from 0.05 (Yanye 13) to 0.08 (Yanyeping 1 Xin 59). Therefore, shale gas from Chang 7 Member has higher 3He/4He

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and R/Ra values than that from the Wufeng-Longmaxi Formation. Dai et al. (2014a) found shale gas from the Longmaxi Formation has 3He/4He values from 2.3×10-8 to 4.3×10-8. Previous research on the helium isotopes for the conventional gas in the Sichuan Basin found that their 3He/4He values range from 0.40×10-8 to 8.46×10-8

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with an average of 1.89×10-8, corresponding to an average R/Ra of 0.01 (Dai et al., 2000). Based on 78 natural

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gas samples, Ni et al. (2014) also found that their R/Ra values range from 0.002 in eastern Sichuan Basin to 0.050 in western Sichuan Basin. For the Ordos Basin, the natural gas samples show 3He/4He values from 1.91×10-8 to 7.7×10-8 with an average of 3.74×10-8 and R/Ra ratios from 0.01 to 0.06 (Dai et al., 2000). There are different criteria for the identification of crustal helium, such as R/Ra < 0.05 (Mamyrin and Tolstikhin, 1984;

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Andrews, 1985) and R/Ra of 0.01–0.1 (Wang, 1989). Jenden et al. (1993b) pointed out that R/Ra > 0.1 typically implies the existence of mantle-derived helium, whereas R/Ra<0.1 usually indicates a crustal origin of helium

is of crustal origin.

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4.6 CO2 and δ13CCO2

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(Xu, 1997). According to these criteria, helium in the shale gas from the Wufeng-Longmaxi and Chang 7 shales

δ13CCO2 values for the shale gas from the Wufeng-Longmaxi Formation vary from 8.9‰ (Jiaoye 6-2, Jiaoye 9-2) to -9.2‰ (Ning 211) with an average of +2.2‰ (Table 1). The δ13CCO2 values for the shale gas from the Chang 7 Shale range from -8.2‰

Fuye 1) to -22.7‰

Yanye 11) (Table 2) with an average of -18.3‰, much

lighter than those for the shale gas from the Wufeng- Longmaxi Shale. A series of researches have been performed on the origin of CO2. Gould et al. (1981) proposed that δ13C values for magmatic CO2 vary significantly, but typically around -7±2 ‰. The δ13C values for CO2 from upper

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ACCEPTED MANUSCRIPT mantle or lower crust in the granitic inclusions range from -3.8 to -7.9 ‰ (Zheng et al., 1987). The δ13C values for CO2 extracted from the inclusions in the Pacific Mid-Ocean Ridge basalts are in the range from -4.5 to -6.0‰ (Moore et al., 1977). Shangguan and Gao (1990) pointed out that δ13C values for metamorphic CO2 are

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similar to those for sedimentary carbonates ranging from +1 to -3‰, and the average δ13C values for mantle-derived CO2 are between -5 and -8.5‰. Dai et al. (1996, 2000) compiled a great number of CO2 data in China and other countries and pointed out that δ13C values for organic CO2 are typically lighter than -10 ‰ and

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mostly range from -10 to -30‰, whereas they are typically heavier than -8 ‰ for inorganic CO2 with a range

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from -8 to 3‰. As illustrated in Figure 17, CO2 in the Chang 7 shale gas mainly plots in the zone of organic origin, indicating it is formed together with hydrocarbon generation. However, CO2 in the Wufeng-Longmaxi shale gas is mainly of inorganic origin with respect to their carbon isotopes. Furthermore, the R/Ra ratios for associated helium range from 0.01 to 0.04, indicating that CO2 in the Wufeng-Longmaxi shale gas is not of

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mantle origin. Thus they are quite possibly a product of the breakdown of carbonate minerals in the Wufeng-Longmaxi shale at elevated temperatures through the following reactions that could be accelerated by formation water.

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CaCO3→CaO+CO2

CaMg(CO3)2→CaO+MgO+2CO2

(1)

(2)

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Such inorganic CO2 was also reported in the Yingqiong Basin in China, with δ13CCO2 values between -2.8 and 3.4‰ and helium R/Ra ratios in the range from 0.01 to 0.003 (Schoell et al., 1996; Dai et al., 2003; Huang et al., 2015). As shown in Figure17, shale gas in USA has low content of CO2, which is similar to that in the Wufeng-Longmaxi Formation and Chang 7 Member, and they also have similar δ13CCO2 values.

4.7 Cause of the carbon isotopic reversal and the partial carbon isotopic reversal As discussed above, carbon isotopic distribution pattern of alkane gases has three types: positive carbon

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ACCEPTED MANUSCRIPT isotopic distribution pattern which is a characteristic of primitive thermogenic gas (δ13C1 < δ13C2 < δ13C3 < δ13C4), complete or full carbon isotopic reversal (δ13C1 > δ13C2 > δ13C3 >δ13C4) and partial carbon isotopic reversal (δ13C1 > δ13C2 or δ13C2 > δ13C3 or δ13C3 > δ13C4). Complete carbon isotopic reversal is often typical of inorganic

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gas (Galimov, 1973, 2006; Dai, 1992; Dai et al., 2004, 2008). For example, the natural gas in the fluid inclusions hosted in Russian Khibiny massif has δ13C1 of -3.2‰, δ13C2 of -9.1‰, and δ13C3 of -23.7‰ (Zorikin et al., 1984); the natural gas seep from ophiolites in Çirali (Chimera), Turkey has δ13C1 of -11.9‰, δ13C2 of -22.9‰, and δ13C3

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of -23.7‰ (Hosgӧrmez, 2007); the natural gas from the Lost City in the North Atlantic Mid-Ocean Ridge has

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δ13C1 of -9.9‰, δ13C2 of -13.3‰, δ13C3 of -14.2‰, and δ13C4 of -14.3‰ (Proskurowski et al., 2008); the natural gas from the Australian Murchison meteorites has δ13C1 of 9.2‰, δ13C2 of 3.7‰, and δ13C3 of 1.2‰ (Yuen et al., 1984). Although complete carbon isotopic reversal is a feature of primitive gas of inorganic origin, a number of over-mature shale gases also display such a feature of complete carbon isotopic reversal (Figure 18) (Jenden et

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al., 1993a; Burruss and Laughrey, 2010; Zumberge et al., 2012; Tilley and Muehlenbachs, 2013; Dai et al., 2014a). The complete carbon isotopic reversal for shale gas of organic origin might result from various secondary alterations to the primitive gases which originally have positive carbon isotopic distribution pattern.

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The following text will discuss some possible factors that may cause the change from positive carbon

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isotopic distribution to complete carbon isotopic reversal or partial carbon isotopic reversal for shale gases. 4.7.1 Mixing of alkane gases from the same source but at different thermal maturation stage. Jenden et al. (1993a) found increased δ13C1 values but decreased gas wetness with advancing thermal maturity levels in the Appalachian Basin. This is because the residual 12C-enriched ethane of early stage is reserved in many high maturity gases (including Marcellus and Queenston shale gas). A model of carbon isotopic reversal of ethane can be established using the mixing calculation of low maturity wet gas and high maturity dry gas as an end member. The multi-charge of gas from the Wufeng-Longmaxi Formation in the multi-cycle superimposed Sichuan Basin

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ACCEPTED MANUSCRIPT resulted in the δ13C1 > δ13C2 (Guo and Zhang, 2013). 4.7.2 Secondary cracking (Rodriguez and Philp, 2010; Tilley et al., 2011; Hao and Zou, 2013; Xia et al., 2013). At high thermal maturity levels, gas in shale reservoirs is a mixing product of the cracking of kerogen, retained

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oil and wet gas. The cracking of oil or condensates will produce ethane with low carbon isotope. The content of ethane is very low at this moment, any mixing with ethane with low carbon isotope will cause the isotopic

reversal. Hao and Zou. (2013) also found the concurrent carbon isotopic reversal between ethane and propane

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and reversed iC4/nC4 ratios, indicating that the inflection point is a marker of gas cracking.

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4.7.3 Special redox reaction of the formation water (Burruss and Laughrey, 2010; Tang et al., 2010; Zumberge et al., 2012; Gao et al., 2013). The methane isotopic composition appears to be dominated by the mixing with late stage methane that is enriched in 13C but depleted in 2H (Burruss and Laughrey, 2010). During the late stage in the deeply buried parts of a basin that underwent metamorphism, late stage methane generation

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could occur in carbonaceous metasediments or residual kerogen (including pyrobitumen) from oil cracking (Burruss and Laughrey, 2010). Comparison experiments show that hydrous pyrolysis of organic matter will yield more C2+ compounds and carbon isotopic rollover but anhydrous pyrolysis does not have such phenomenon,

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indicating that water plays a significant role in the process of gas generation and isotopic rollover (Gao et al.,

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2013). Burruss and Laughrey (2010) divided the isotope rollover of deep basin gas (including some shale gas) in the Appalachian Basin into two types: isotope rollover during highly mature stage which is caused by mixing with isotopically light ethane; isotope rollover during over-mature stage which is likely related to the mixing of late stage methane enriched in 13C. 4.7.4 Diffusion. Diffusion decreases exponentially with increasing molecular weight. Molecular diffusion, especially the hydrocarbon diffusion, is influenced by molecular weight and size. Gas diffusion is the flow of single molecule in a material such as tight sandstone. Due to different diffusion coefficients of methane, ethane

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ACCEPTED MANUSCRIPT and propane, the diffusion speed will be methane > ethane > propane. At the same time, it also causes a decreased δ13C2 value along the diffusion direction, thus forming isotopic fractionation (Li, 2004). CH4, C2H6 and C3H8 are respectively composed of pairs of 12CH4 and 13CH4, 12C12CH6 and 12C13C H6 and 13C13CH6, C12C12CH8 and 12C12C13C H8 and 12C13C13C H8 and 13C13C13CH8. The molecular weight of CH4, C2H6 and C3H8

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is different. During the diffusion process, molecule with light carbon isotopic composition will diffuse first, i.e., CH4, 12C12CH6 and 12C12C12CH8 diffuse first. In terms of the molecular weight order of 12CH4 < 12C12CH6 <

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C12C12CH8 and the exponentially decreased diffusion ability with increasing molecular weight, the enrichment

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of δ13C in the remaining gas would be most notable for methane, less notable for ethane and least notable for propane, which results in the formation of carbon isotopic reversal pattern among the C1-C3 alkanes. Based on Ne and Ar isotopes, Hunt et al. (2012) proposed that the isotopic rollover for the hydrocarbon gases in the Appalachian Basin is likely related the substantial gas loss including gas diffusion.

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4.7.5 Carbon exchange at high temperature. As shown in Figure 18, all the over-mature Wufeng-Longmaxi Formation shale gases with wetness less than 0.8% display carbon isotopic reversal. The Chang 7 shale gases, which are at the mature stage and have gas wetness values between 6.45 and 20.71% (Table 2), display both

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positive carbon isotopic distribution pattern and partial carbon isotopic reversal with δ13C3 > δ13C4. When their

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gas wetness values are between 6.45 and 20.71%, the shale gases from the USA and Canada are all characterized by positive carbon isotopic distribution pattern. More technically, when gas wetness is about 1.6% or higher, all shale gases from China (Except Chang 7), USA and Canada are characterized by positive carbon isotopic distribution pattern. Only when the gas wetness value is smaller than 1.6%, there would be frequent carbon isotopic reversal, either complete or partial. Therefore, a gas wetness value of 1.6% can be considered as a critical point that marks the transition from positive carbon isotopic distribution pattern for primary gas to complete or partial carbon isotopic reversal for secondary gas. Above this point (>1.6%), shale gas will be

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ACCEPTED MANUSCRIPT characterized by positive carbon isotopic distribution pattern; below this point (<1.6%), which means highly mature to over-mature stages, shale gas will display complete or partial carbon isotopic reversals. Therefore, high thermal maturity level is a main factor that determines whether or not carbon isotopic reversal would occur.

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Vinogradov and Galimov (1970) pointed out that carbon isotopic exchange among alkane gases is dependent on temperatures. At temperatures over 150 ºC, it is common for δ13C1 > δ13C2; however, at temperature is over 200 ºC, the positive carbon isotopic distribution pattern will convert into complete carbon isotopic reversal pattern,

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i.e., δ13C1 > δ13C2 > δ13C3. For the Barnett shale gases (Figure 18), there is a gradational change in gas wetness

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ranging from 0.80 to 22.06 %, which illustrates that the Barnett Shale displays a wide span of thermal maturity levels from mature through over mature. While positive carbon isotopic distribution pattern predominates among the Barnett shale gases, partial carbon isotopic reversal is only sporadically observed for several samples with gas wetness between 0.8 and 1.6% but there is no complete carbon isotopic reversal at all. These observations

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imply that the Barnett shale gas with wetness between 0.8 and 1.6% is young, not allowing enough time for them to reach a complete carbon isotopic reversal via carbon isotope exchange between alkane gases. For the Wufeng-Longmaxi and Fayetteville shale gases, their gas wetness is typically smaller than 0.80% and 1.6%,

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respectively, and there is no gas with wetness greater than 1.6%. This indicates that these highly mature to over

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mature gases are old and have enough time for complete carbon isotopic exchange equilibrium which will convert a positive carbon isotopic distribution pattern into a pattern of complete or partial carbon isotopic reversal.

The Wufeng-Longmaxi Formation in the Sichuan Basin was ever deeply buried before it was uplifted to the present burial depth. The fluid inclusions hosted in the Silurian gas shales of Well Jiaoye 1 in the eastern Sichuan Basin have homogenization temperatures ranging from 215.4 to 223.1 ºC, corresponding to an ancient burial depth in the range between 7600 and 10000 m (Guo and Zhang, 2013); the fluid inclusions in the Silurian

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ACCEPTED MANUSCRIPT gas shales in the southern Sichuan Basin has homogeneous temperatures in the range from 140 to 189 ºC, recording an ancient burial depth of approximately 6500 m. Therefore, the gas shales in the lower part of the Wufeng-Longmaxi Formation have experienced high temperatures greater than 150 ºC, high enough for trigging

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carbon isotope exchange among alkane gases that can result in a complete or partial carbon isotopic reversal.

5. Conclusions

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(1) Shale gas from the marine Wufeng-Longmaxi Formation is dominated by CH4 with an average of 98.38% and records the highest CH4 content (99.59%) for the shale gases in the world. The gas wetness ranges from

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0.24 to 0.78% and is consistent with thermal maturity levels of the Wufeng-Longmaxi Shale whose equivalent vitrinite reflectance values (EqVRo, %) are mostly between 2.4 and 3.6%. Shale gas from the terrestrial Chang 7 Shale has an average methane content of 84.90% and is enriched in heavy gaseous hydrocarbons, belonging to wet gas. The gas wetness ranges between 6.45 and 20.71% and is consistent

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with the low vitrinite reflectance values for the Chang 7 Shale that has vitrinite reflectance values (VRo, %) in the range between 0.7 and 1.2%. The reason that the Wufeng-Longmaxi shale gas is dry but Chang 7

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shale gas is wet is primarily because of their difference in thermal maturity levels.

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(2) The Wufeng-Longmaxi shale gas has δ13C1 values from -26.7 to -37.3‰ with an average of -31.3‰ and records a highest δ13C1 value (-26.7‰) for shale gases found in the world. Such high δ13C1 values can be attributed to both high thermal maturity and parent kerogen with high δ13C value. The average δ13C values for ethane and propane are -35.6‰ and -47.2‰, respectively, leading to a dominantly complete carbon isotopic reversal, i.e., δ13C1 > δ13C2 > δ13C3. In contrast, the Chang 7 shale gas has an average δ13C value of -48.7‰ for methane, -36.4‰ for ethane, and -31.3‰ for propane, displaying a positive carbon isotopic distribution pattern, i.e., δ13C1 < δ13C2 < δ13C3. The differences in both average δ13C values and carbon

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ACCEPTED MANUSCRIPT isotopic distribution pattern between the two different shale gas are probably caused by their difference in thermal maturity. (3) The average hydrogen isotope value is -148‰ and -173‰ for methane and ethane, respectively for the shale

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gas from the Wufeng-Longmaxi Formation and also displays a hydrogen isotopic reversal, i.e., δ2HCH4 > δ2HC2H6. For the Chang 7 shale gas, the average value of δ2HCH4, δ2HC2H6 and δ2HC3H8 is -256‰, -244‰, and -188‰, respectively, displaying a normal hydrogen isotopic distribution pattern (i.e., δ2HCH4 < δ2HC2H6 <

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δ2HC3H8). Therefore, the two types of shale gases are different in both the average δ2H values and the

(water salinity) and thermal maturity.

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hydrogen isotopic distribution pattern, which is probably due to the differences in depositional environments

(4) CO2 content in the shale gases from the Wufeng-Longmaxi Formation and Chang 7 Member is both low,

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mostly less than 1%. δ13CCO2 values for the shale gas in the Wufeng-Longmaxi Formation are between 8.9 and 9.2‰, indicating an inorganic origin from the cracking of carbonate minerals in shales at high temperature. δ13CCO2 values for the shale gas in the Chang 7 Member, however, is low and ranges between

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-8.2‰ and -22.7‰, indicating an organic origin from organic matter thermal degradation. R/Ra values for

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the two types of shale gases are both low and range between 0.01 and 0.08, indicating an dominantly crustal origin.

(5) There are three types of carbon isotopic distribution pattern: positive carbon isotopic distribution pattern; complete carbon isotopic reversal; and partial carbon isotopic reversal. Positive carbon isotopic distribution pattern is characteristic of primitive thermogenic gas. However, positive carbon isotopic distribution pattern can be converted into complete carbon isotopic reversal and partial carbon isotopic reversal patterns through

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ACCEPTED MANUSCRIPT secondary alteration. The carbon isotopic reversal (either complete or partial) observed for shale gas is due to the mixing of gases with the same source but different maturity levels, secondary cracking, formation water-involved reactions, diffusion, and isotope exchange between alkane gases at high temperature. Among

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them, isotope exchange between alkane gases at high temperature is the main controlling factor.

(6) Based on the shale gas data from China, USA and Canada, plots of δ13C2 vs. wetness and wetness vs. carbon

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isotopic distribution pattern have been investigated. The plot of δ13C2 vs. wetness shows a “lying-S” shape,

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and there are two inflection points at the wetness axis, wherein 1.4% is the critical point marking a transition from pyrolytic gas (primary cracking gas) to cracking gas (secondary cracking gas), and 6% marks the termination of oil generation window. In the plot of wetness vs. carbon isotopic distribution pattern, when wetness is 6% or higher, shale gas is generally characterized by positive carbon isotopic distribution pattern;

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when wetness is lower than 6%, there is a great deal of shale gas samples displaying complete carbon isotopic reversal or partial carbon isotopic reversal; only when wetness is between 0.8% and 1.6%, there is a

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Acknowledgements

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positive carbon isotopic distribution pattern for some Barnett shale gas samples.

We thank Profs. Shimeng Liao, Yongsheng Ma, Tonglou Guo and Degao Hu for long-standing helpful and open discussion on an earlier version of this study. We also thank PetroChina Southwest Oilfield Company, Sinopec South Exploration Company and Sinopec Jianghan Oilfield Company for help on the sample collection.

26

ACCEPTED MANUSCRIPT Figure Caption: Figure 1. Shale gas exploration and development situation in China Figure 2. The stratigraphic column of Lower Paleozoic in the Sichuan Basin

RI PT

Figure 3. The thickness contour line of organic-rich shale in the lower part of Wufeng-Longmaxi Formation in the Sichuan Basin

Figure 4. Comparison between the mineral composition of shales from China and USA

SC

Figure 5. The stratigraphic column of the 7th member of Yanchang Formation (Chang 7 Member) in the Ordos

M AN U

Basin

Figure 6. The thickness distribution of organic-rich shale of Chang 7 Member in the Ordos Basin Figure 7. Maturity contour line (Ro %) of Chang7 shale in the Ordos Basin Figure 8. Plot of CO2 versus C2H6 for the shale gas from China and USA

Figure 9. δ13C values of the kerogen from Longmaxi Formation in the Changning-Zhaotong and Weiyuan areas

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Figure 10. The carbon isotopic distribution pattern of shale gas from Chang 7 and Xu 5 members (a) and Wufeng-Longmaxi Formation (b)

Figure 11. Hydrogen isotopic distribution pattern of the C1-C3 alkanes for the shale gases from the Wufeng-Longmaxi and Chang 7 and Xu 5 formations

“N” shape

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Figure 12. Plot of the δ13C1 vs. δ13C2 for the shale gases from China, USA and Canada which shows a trend of

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Figure 13. Plot of δ13C1 vs. wetness for the shale gases from China, USA and Canada which displays a “п” shape trend.

Figure 14. Plot of δ13C2 vs. wetness for the shale gases from China, USA and Canada showing a trend of “lying-S” shape.

Figure 15. Plot of δ13C1 vs. δ2HCH4 for the shale gases from China and USA Figure 16. Plot of δ2HCH4-wetness for the shale gases from China and USA Figure 17. Genetic types of CO2 from the Wufeng-Longmaxi and Chang 7 shale gases in term of the diagram of Dai et al (1996). Figure 18. Plot of wetness vs. carbon isotopic distribution pattern for the shale gases from China, USA and

27

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ACCEPTED MANUSCRIPT

EqV Depth

Main Component (%)

δ13C (‰, VPDB)

Wetness

Ro Well % m

CH4

C2H6

C3H8

CO2

N2

98.32

0.46

0.01

0.36

0.81

He(10-6)

%

CH4

C2H6

0.48

-36.9

-37.9

1520-1 2.1

Wei201 1520-1 Wei201*

2.1

99.09

0.48

0.42

0.48

523 95.52

0.01

98.56 *

8

Wei201-H2

2840.0

2595

95.52

2.4

99.27

0.37

2745

99.12

ChangningNing201-H1 2745 *

0.34

0.32

0.68

0.01

0.02

99.04

0.57

1.07

0.02

0.37

1.05

AC C

98.27 161

Zhaotong

2.95

1.06

3137-3 Wei203*

Ning201-H1

1.07

2823.4

Weiyuan

Wei202

0.32

TE D

Wei201-H1

2840

0.50

0.54

0.01

2.95

0.01

0.34

228±8

EP

Wei201-H1

0.04

0.40

C3H8

0.08

0.70

-37.3

-35.1

-35.4

CO2

δ2H (‰, VSMOW)

3

He/4He (10-8)

CH4

δ13C2-δ13 R/Ra C1

C2H6

-14 3.594±0.653

0.03

-1.0

0

M AN U

523

SC

Area

RI PT

Table 1 Molecular composition, stable carbon, hydrogen and helium isotopes of shale gases from the marine Wufeng-Longmaxi shale in the Sichuan Basin

-13

-38.2

-0.2

-0.9 6 -14

-38.7

-3.6 4 -13

-37.9

-1.5

3.684±0.697

0.03

-2.5

0.03

-3.6

0.02

-5.9

8 -14 -35.1

-38.7 4 -14

-36.9

-42.8

-43.5

-2.2

-164

2.726±0.564

4 -14 0.58

-35.7

-40.4

-1.2

-4.7 7 -14

0.30

187±6

0.51

-27.0

-34.3

2.307±0.402

0.02

-7.3

8 0.00

0.54

-27.8

-34.1

-6.3

ACCEPTED MANUSCRIPT

2313-2 Ning211

-14 3.2

98.53

0.32

0.03

0.91

0.17

353±12

0.35

-28.4

-33.8

-36.2

-9.2

NingH2-3

NingH2-4

Zhao104

99.07

2586

99.28

2503

98.62

2568

2117.5

99.15

3.3

99.25

0.42

0.47

0.42

0.44

0.52

0.10

0.01

0.01

0.01

0.01

0.00

0.40

0.00

0.53

0.23

0.59

0.48

0.37

0.00

0.43

0.40

0.07

0.15

0.45

253±8

2002-2 YSL1-1H

3.2

99.45

0.47

0.01

0.01

0.03

258±9

2408-2 2.9

98.52

0.67

0.05

0.32

416

JY1-3

2320

98.80

2799

98.67

0.70

0.72

0.02

0.03

JY6-2

JY7-2

2850

98.95

2585

98.84

0.17

AC C

Jiaoshiba

0.13

0.63

0.67

0.02

0.03

0.43

0.34

362±14

335±13

EP

JY1-2

0.02

0.14

0.53

0.48

TE D

028 JY1

-28.7

-28.9

-33.8

1.867±0.453

0.03

-5.4

-31.3

0.41

0.72

0.73

-28.4

-26.7

-27.4

-15

-35.4

-34.2

-31.6

-5.1

-161

-5.7

-161

-2.9

-169

-5.4

-14 9 -15

-35.5 1 -14

-33.8

-31.7

-156 1

-34.0

SC

NingH2-2

2790

M AN U

NingH2-1

-173 8

RI PT

341

8 -14 -33.1

3.8

-163

1.958±0.445

0.01

-5.0

-159

1.556±0.427

0.01

-4.2

-224

4.851±0.944

0.03

-5.4

-199

6.012±0.992

0.04

-6.0

9 -14 -33.2 7 -14

-30.1

-35.5

-1.4 9 -14

-29.9

-35.9

5.9 7 -15

0.75

-31.8

-35.3

6.1

-206

-3.5

2 -14

0.39

359±14

0.65

-31.1

-35.8

8.9

-191

2.870±1.109

0.02

-4.7

-158

5.544±1.035

0.04

-5.3

9 -14 0.32

418±16

0.70

-30.3

-35.6

8.2 3 -14

JY8-2

2622

3.1

98.75

0.70

0.02

0.21

0.32

0.72

-30.5

-35.6

7.8

-164 1

-5.1

ACCEPTED MANUSCRIPT

-14 JY9-2

2588

98.56

0.69

0.02

0.20

0.52

419±16

0.72

-30.7

-35.4

8.9

-199

5.297±1.086

0.04

-4.7

JY12-1

JY12-3

JY12-4

JY13-1

JY13-3

JY20-2

2665

2778

2778

2778

2665

2665

98.87

97.67

98.87

98.76

98.35

98.57

98.38

JY29-2

0.74

0.65

0.68

0.67

0.66

0.60

0.66

0.02

0.04

0.02

0.02

0.02

0.02

0.02

0.02

0.26

0.36

0.23

0.42

0.09

0.42

1.16

0.47

0.00

0.39

0.71

0.02

369±14

0.43

0.03

0.00

0.72

0.44

0.25

0.00

0.72

0.78

0.57

0.64

0.51

-31.0

-30.4

-29.8

0.68

0.71

0.69

0.68

0.62

-30.3

-30.8

-30.5

-14

-35.9

-35.9

-4.9

-14 -195

5.649±1.225

0.04

-5.5

9 -15

-35.5

5.7

-212

-5.7

-190

-5.2

-219

-4.5

-166

-4.6

-164

-4.4

-163

-4.3

-165

-3.9

-165

-4.4

0 -14

-35.5

3.2 8 -16

-35.3

-35.1

-186 8

8.0

SC

98.69

0.69

0.02

M AN U

JY13-2

2778

98.63

0.70

TE D

JY12-2

2520

98.66

EP

JY11-2

2644

AC C

JY10-2

RI PT

6

0.8 3 -14 -38.4

1.7 9 -15

-30.7

-35.1

-38.7 0 -15

-30.2

-35.9

-39.3 0 -14

0.68

-29.5

-34.7

-37.9 9 -14

0.89

0.74

-29.7

-35.9

-39.1 9 -15

-29.6

-35.4

-6.6

-5.8 3 -14

JY42-1

98.54

0.68

0.02

0.38

0.38

0.71

-31.0

-36.1

-166 7

-5.1

ACCEPTED MANUSCRIPT

-14 JY42-2

98.89

0.69

0.02

0.00

0.39

0.71

-31.4

-35.8

-39.1

-167

-4.4

-165

-4.6

-167

-4.1

-136

-3.9

-135

-0.2

-128

-0.5

JY4-2

2800

97.89

2800

98.06

Hai201-H

95.32

0.62

0.57

0.60

0.02

0.01

0.02

0.00

1.07

0.00

0.65

1.36

0.00

0.59

4.05

0.65

97.16

0.41

0.03

1.74

0.67

0.45

1 Fushun-Yon Yang101

2.8

97.60

0.27

0.01

1.60

0.53

0.28

gchuan Yang201-H 4568

99.59

0.33

0.01

0.06

0.01

0.34

2466

97.64

98.77

0.23

0.71

0.00

0.01

Pengshui 98.46

0.55

0.01

0.35

0.93

AC C

PY3

1.48

0.61

0.15

0.24

1000±39

EP

PY1

4700

TE D

2 Lai101

0.05

-32.2

-32.0

986±38

0.72

-35.5

-34.4

-33.8

-14

-36.2

7 -15

-36.3

0 -15

-35.9

M AN U

Dong202-H

-31.6

SC

JY4-1

RI PT

8

2 -15

-35.7

-3.6 1 -15

-34.8

-36.0

-1.5 0 -15 -39.4

5.4

-140

3.263±0.636

0.02

-2.2

-151

2.606±0.470

0.02

0.1

-195

4.430±1.050

0.03

3.9

-209

4.620±0.873

0.03

3.6

1 -15

-33.2

-33.1 1 -15

-31.0

-34.9

-49.5

3.2 6 -15

0.57

-30.1

-33.7

-45.4 5

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Table 2 Molecular composition, stable carbon, hydrogen and helium isotopes of shale gases from the terrestrial Chang 7 shale in the Ordos Basin and shale gases from the terrestrial Xujiahe shale in Xinchang area in the Sichuan Basin

1225

δ13C (‰, VPDB)

Main Component

Strata m

Yanye13

Ro

type

T1y7

%

CH4

C2H6

C3H8

C4H10

CO2

N2

1.10

88.95

6.95

2.78

0.64

0.23

0.27

1380

T1y7

1.10

81.81

9.94

5.72

1.89

0.02

0.32

Yanye11

1490

T1y7

1.11

89.06

5.56

2.29

0.98

0.03

0.84

SaproYanyeH1

1310

1.10

T1y7

Yanye22 Liuping179

T1y

pelic

1460

T1y7

84.86

8.12

82.12

4.25

77.94

10.85

AC C

Yanye5

7

δ2H (‰, VSMOW)

3.27

0.81

0.10

(10-6)

203±12

3

He/4He R/R

He

EP

Well

Gas

TE D

Depth

CH4

C2H6

C3H8

C4H10

CO2

CH4

C2H6

C3H8

-51.0

-38.3

-33.3

-32.4

-20.1

-265

-260

-186

10-8

δ13C2-δ13C1

7.649±1. 0.05

12.7

428

-51.0

-37.9

-33.2

-33.5

-19.6

-277

-286

-201

-53.4

-39.1

-34.1

-33.8

-22.7

-261

-244

-187

13.1 8.121±1.

368±23

0.06

14.3

517 this study 10.817±1 0.32

256±26

-52.3

-39.5

-34.3

-33.2

-277

-277

-195

0.08

12.8

.859

0.95

0.46

11.26

0.85

6.59

2.89

0.20

0.49

-49.4

-31.9

-29.6

-31.8

-46.3

-36.7

-32.3

-32.3

-19.3

-245

-225

-174

-255

-266

-203

17.5 9.340±1.

1.12

Reference

a

78±5

0.07 772

9.6

ACCEPTED MANUSCRIPT

Liuping177

1540

9.507±1.

T1y7

1.10

91.68

5.55

1.77

0.41

0.49

1.00

449±28

-49.8

-37.1

-32.6

-33.3

-17.7

-256

-248

-182

0.07

12.7

0.08

12.2

1090

T1y7

0.92

82.33

8.66

5.30

2.60

0.38

0.49

256±16

T1y7

Fuye1

7

Yongye1

T1y 1070-

Liuping177

0.95

T1y7

88.93

5.32

1.94

0.71

0.32

2.15

-49.1

-30.8

-19.6

-40.8

-36.9

-32.3

-48.7

-35.8

T1y7

84.79

6.91

3.13

1.21

1.29

1.75

1479 1076Xin59

T1y7

0.92

76.09

8.69

6.05

3.27

0.87

3.14

1.20

94.1

3.48

0.85

0.02

0.63

0.89

1084 T3x5

Humic

-32.0

-257

-31.1

-35.9

-30.8

10.852±1 -278

.922

-8.2

-237

-182

-20.2

-257

-238

17.0 -170

3.9

-242.

-34.6

-23.2

-199

-221

12.9

-208

11.6

8 Wang et -247

al., 2015

-46.6

-36.1

-31.4

-27.5

-36.4

-25.1

-22.9

-22.4

10.5 -178

-147

11.3

EP

TE D

3087

-47.5

AC C

Xinye2

-31.3

M AN U

1453-

-32.1

-47.8

1487 Liuping179

-36.9

SC

Xin59

RI PT

599

Table 3 The δ13C values of methane and its homologues of coal-derived and oil-derived gases from source rocks with similar or the same maturity levels Basin

Well

Gas

Ro

type

%

δ13C (VPDB, ‰)

Main component (%)

Strata CH4

C2H6

C3H8

iC4H10

nC4H10

iC5H12

nC5H12

CH4

C2H6

C3H8

C4H10

this study

ACCEPTED MANUSCRIPT

1.04

57.94

Ordos

Se 1

Permian

Ordos

Yang 8

Triassic

Qiongdongnan

Ya 13-1-2

Sichuan

10.05

10.82

2.02

3.49

4.27

4.30

-46.4

-36.0

-32.3

-31.2

coal-derived

1.04

94.32

oil-derived

1.08~1.10

67.38

2.49

0.84

0.12

0.15

0.03

0.03

-32.0

-25.6

-24.2

-23.1

10.07

8.38

1.34

1.81

-47.4

-37.2

-33.1

-31.7

Paleogene

coal-derived

1.09~1.10

87.00

4.00

2.00

-35.6

-25.1

-24.23

-24.1

Jiao 2

Jurassic

oil-derived

1.05

84.34

9.10

3.11

0.29

0.93

-46.3

-32.8

-30.0

-29.8

Bohaibay

Su 401

Ordovician

coal-derived

1.05

86.76

5.94

2.38

0.55

0.74

-36.5

-25.6

-23.7

Ordos

Niu 1

Ordovician

oil-derived

1.90

96.09

1.81

0.28

0.03

-36.7

-29.3

-27.3

Junggar

Caican 1

Carboniferous

coal-derived

1.90

77.85

1.12

0.14

-29.9

-22.8

0.80

RI PT

oil-derived

SC

Jurassic

0.02

EP

TE D

M AN U

Hua 11-32

AC C

Ordos

1.81

1.24

0.37

0.43

0.64

0.02

CE ED

PT

SC

M AN U

RI

AC C

EP

TE D SC

M AN U

R

CE ED

PT

SC

M AN U

RI

TE D

M AN U

S

CE ED

PT

SC

M AN U

RI

CC EP TE D

SC

M AN U

RI P

CC EP TE D

SC

M AN U

RI P

PT ED

S

M AN U

EP TE D

SC

M AN U

TE

D

M AN U

TE D

M AN U

TE D

M AN U

S

ED

M AN U

TE D

M AN U

TE D

M AN U

TE D

M AN U

EP TE D

SC

M AN U

TE D

M AN U

S

ACCEPTED MANUSCRIPT

Research Highlights 1. Gas from the marine facies Wufeng-Longmaxi shale in Sichuan is dominated by 98.38% CH4. 2. Marine facies shale gas is characterized by δ13C1＞δ13C2＞δ13C3 and δ2HCH4＞δ2HC2H6.

AC C

EP

TE D

M AN U

SC

RI PT

3. The cause for carbon isotopic reversal is high temperature effect.