Experimental study on the gas generation processes of lacustrine and marine shales in North China: Source implications for shale gas

Accepted Manuscript Experimental study on the gas generation processes of lacustrine and marine shales in North China: Source implications for shale gas Liujuan Xie, Yongge Sun, Aizhu Jiang, Feiyu Wang, Jianping Chen PII:

S0264-8172(15)00158-0

DOI:

10.1016/j.marpetgeo.2015.05.009

Reference:

JMPG 2237

To appear in:

Marine and Petroleum Geology

Received Date: 18 August 2014 Revised Date:

30 April 2015

Accepted Date: 11 May 2015

Please cite this article as: Xie, L., Sun, Y., Jiang, A., Wang, F., Chen, J., Experimental study on the gas generation processes of lacustrine and marine shales in North China: Source implications for shale gas, Marine and Petroleum Geology (2015), doi: 10.1016/j.marpetgeo.2015.05.009. 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

Experimental study on the gas generation processes of lacustrine and marine shales in North China: Source

Liujuan Xie

a,b,c

,

a*

Yongge Sun ,

d

Aizhu Jiang ,

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implications for shale gas e

Feiyu Wang ,

f

Jianping Chen

Department of Earth Science, Zhejiang University, Hangzhou 310027, China

b

Research Institute of Unconventional Petroleum and Renewable Energy, China University

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a

c

d

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of Petroleum, Qingdao 266580, China

School of Geosciences, China University of Petroleum, Qingdao 266580, China State Key Laboratory of Organic Geochemistry (SKLOG), Guangzhou Institute of

Geochemistry, Chinese Academy of Sciences, Guangzhou 510640, China State Key Laboratory of Petroleum Resource and Prospecting, China University of

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e

Petroleum, Beijing 102249, China

Research Institute of Petroleum Exploration and Development, China National Petroleum

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f

Corporation, Beijing 100083, China

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* Corresponding author. Address: No.38 Zheda Road, Hangzhou, Zhejiang Province, 310027, China. Tel.:+86 571 87951336. E-mail address: [email protected] (Y. Sun).

Abstract

Using a high pressure, semi-closed thermal simulation system, two organic-rich lacustrine and marine immature shales from North China were investigated to probe the dynamic processes and potential for the gas

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ACCEPTED MANUSCRIPT generation throughout the oil-gas window. The results identified at least two processes during gas generation, as revealed by changes of the gas dry coefficient (C1/ΣC1-5%) and carbon isotopic composition of methane (δ13Cmethane).

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The first process is associated with kerogen thermal degradation and occurs during the main phase of oil generation, showing an increasing trend of the dry

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coefficient and δ13Cmethane. The second process begins during the late phase of oil generation, accompanied by increasing yields of wet gas components and 13C

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depleted methane. Due to the lack of aliphatic carbon in kerogen in the highly to over mature stage, as demonstrated by FTIR analyses, the second process is mainly related to the cracking of kerogen-generated bitumen which is retained in the shale.

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The hydrogen content, a key parameter for petroleum generation, is then used to quantitatively evaluate the gas generation potential from kerogen

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thermal degradation and retained-bitumen cracking. Mass balance calculations show that kerogen-generated bitumen that is retained in lacustrine and marine

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shales is estimated to contribute 30% of the total gas yields at the stage of 1.5–2.0% Ro. This result is consistent with the theoretical calculations from Xia et al. (2013) and has important implications for the shale gas sources, and further the shale gas resource assessments before exploration in shale-gas petroleum systems.

Keywords: pyrolysis simulation; kerogen thermal degradation; retained-bitumen

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ACCEPTED MANUSCRIPT cracking; gas generation processes; hydrogen content; shale gas.

1 Introduction

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With the continued growth in production from shale gas reservoirs in the United States, there has been a paradigm shift toward shale gas exploration around the world. Most of the shale gas discovered to date is thermogenetic

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within the main to late phases of oil generation (0.8–2.0% Ro), although biogenic gas and/or mixed gas have also been found (Curtis, 2002; Martini et al., 2003,

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2008; Strąpoć et al., 2010; Zumberge et al., 2012).

Shale gas systems are usually defined as cases of continuous petroleum accumulations, in which the shale is not only the source of but also the reservoir

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for the shale gas (Schmoker, 1995; Hill et al., 2007; Jarvie et al., 2007). The TOC content, kerogen type, thermal maturity, extent of kerogen transformation and in-place gas content are essential for evaluating the shale gas potential (Jarvie

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et al., 2005). However, thermal maturation is a key parameter to assess the

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‘sweet spot’ during exploration. It has been noted that the gas flow rates are greatly improved when the shales reach a level of high thermal maturity, as demonstrated by the high productivity from Barnett Shale with Ro > 1.3% (Jarvie et al., 2007; Rodriguez and Philp, 2010). This phenomenon was brought into question because there is a lower gas potential of kerogen-cracking due to hydrogen exhaustion, which is found in most type I and II shale kerogens beyond the oil window.

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ACCEPTED MANUSCRIPT Previous studies have suggested that this could be attributed to gas contributions both from kerogen thermal degradation and retained-bitumen cracking in the shale. Jarvie et al. (2007) investigated genetic mechanisms of

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shale gas from the Barnett Shale and concluded that the highly mature shale gas systems produced a high gas content from the indigenous generation of gas

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from kerogen, bitumen and oil cracking. Using kerogen pyrolysis data in a closed system and first order kinetic calculations, Hill et al. (2007) predicted that the

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cracking of the retained-bitumen starts by ~1.1% Ro in the Barnett Shale. Xia et al. (2013) further indicated that condensates may act as the major precursor of the secondary gas in shale.

Although it has been demonstrated that both kerogen thermal degradation

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and retained-bitumen cracking play important roles in shale gas accumulation, the best method to experimentally evaluate their contributions to shale gas

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systems upon thermal evolution has not yet been determined. In this study, a semi-closed thermal simulation system that was developed in our lab is used to

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delineate the processes involved in gas generation during whole rock pyrolysis with constant temperature and mechanical pressure. The main advantage of this new system is that it can model the expulsion process accompanying hydrocarbon generation (Xie et al., 2013). It avoids the secondary cracking of the generated oil to a maximum extent and therefore represents the cracking of retained-bitumen after expulsion within the whole rock. This corresponds to the

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ACCEPTED MANUSCRIPT actual hydrocarbon generation and expulsion processes within a geological profile. In addition, quantitative calculations of the gas contribution from the retained-bitumen cracking become possible by integrating the experimental data

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and hydrogen mass balance. The purpose of this study is to investigate the processes involved in gas generation throughout the oil-gas window and to

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identify the geochemical evidence of retained-bitumen cracking in typical Chinese lacustrine and marine shales, and finally, to try to quantitatively

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calculate the gas contributions from kerogen thermal degradation and retained-bitumen cracking for shale gas exploration implications.

2 Samples and experiments

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2.1 Sample background

Two shales were collected from lacustrine and marine depositional environments. The lacustrine shale is from the first member of the Nenjiang

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Formation of the Upper Cretaceous strata (K2n1), Songliao basin, NE China, and

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is named ‘DU shale’. The Nenjiang Formation is one of the three major sets of petroleum source rocks in the Songliao Basin, which is one of the largest continental petroliferous basins in the world, and is an important candidate for shale gas exploration and development in China (e.g., Bechtel et al., 2012; Jia et al., 2013; Liu et al., 2014). Thermal simulated experiments with typical organic-rich and low mature shale are useful for regional shale gas resource evaluation, as well as the determination of a ‘sweet spot’, and can be used as a

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ACCEPTED MANUSCRIPT reference for shale gas exploration in other lacustrine petroliferous basins. The marine shale is from the Xiamaling Formation of the Middle Proterozoic strata at Xiahuayuan town, Hebei Province, North China, and is named ‘XHY

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shale’. The shale from the Xiamaling Formation is the only marine shale with low maturity found in China and was usually used for hydrocarbon-generated

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simulations during past three decades among Chinese petroleum geochemists (e.g., Liu et al., 1990; Fang et al., 2002; Wang et al., 2008). This shale could

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provide a unique reference for current Cambrian shale gas evaluation in Southern China if the gas generation processes can be clearly determined upon thermal evolution.

2.2 Pyrolysis with a semi-closed thermal simulation system

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The semi-closed thermal simulation system consists mainly of a booster, heater, cylinder reactor, and collecting devices (oil/water collecting tube and gas

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volume measurer). Six experimental points were set at 300, 350, 400, 450, 500, and 550 °C. The shales were powdered to 80 meshes and inserted in a cylinder

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mold with 0.5-cm thick quartz filled at the bottom. After air evacuation, the system was heated from room temperature to a set-point, and then held isothermally for 72 hours under 80 MPa. The generated gas and liquids flow out of the cylinder mold through the quartz layer and are collected by the collecting devices. An oil/water collecting tube was placed in a cold trap system (saline water, -15 °C) to reduce the volatilization loss of light hydrocarbons. Gas was

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ACCEPTED MANUSCRIPT collected by a water drainage system. After the experiments, retained-bitumen was extracted from the heated shales using mixed solvent (dichloromethane: methanol =97: 3, v: v) in a Soxhlet apparatus, while the expelled oil was

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collected from the quartz layer and the oil/water collecting tube. The total amount of retained-bitumen and expelled oil are defined as the total generated-bitumen.

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Because the heating process is not strictly programmed, the equivalent vitrinite reflectance at each temperature was obtained by parallel coal pyrolysis

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experiments with the same conditions (Lu, 1990), rather than by an EASY%Ro calculation that overestimates the equivalent vitrinite reflectance. 2.3 Analyses of the pyrolysis products

The gas composition, stable carbon isotopic composition of methane,

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expelled oil / retained-bitumen composition, and functional groups in kerogens were measured. The heated shale samples were powdered to conduct

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Rock-Eval pyrolysis.

Gas: The gas composition (C1-5) was analyzed with an HP 6890 gas

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chromatograph with an FID detector. The GC was equipped with a Poraplot Q capillary column (30 m× 0.25 mm× 0.25 µm) with helium as the carrier gas. The oven temperature was maintaned at 70 °C for 6 min, then increased to 130 °C at 15 °C/min, to 180 °C at 25 °C/min, and finally held at 180 °C for 4 min. The stable carbon isotopic composition of methane was measured on a Delta plusXL gas chromatograph-isotope ratio mass spectrometer. The GC was

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ACCEPTED MANUSCRIPT equipped with a Poraplot Q capillary column (30 m× 0.32 mm× 0.25 µm) with helium as the carrier gas. The oven temperature was maintained at 50 °C for 3 min, then increased to 190 °C at 15 °C/min and held at 190 °C for 15 min. The

usual delta notation relative to the VPDB.

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isotope values were calibrated against the reference gas and are reported in the

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Liquids: The expelled oil was divided into two portions. One portion was used for whole oil gas chromatography analyses, and the other was used for

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compound-grouped class analyses. Asphaltene was removed from the expelled oil and retained-bitumen by precipitation with petroleum ether, followed by filtration. The maltene was then separated into saturates, aromatics and resins by column chromatography.

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The expelled whole oil was analyzed by a HP 6890 gas chromatograph. The GC was equipped with a CP7749 capillary column (50 m× 0.32 mm× 0.4 µm)

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with nitrogen as the carrier gas. The oven temperature was maintained at 35 °C for 10 min, then increased to 300 °C at 3 °C/min, and finally held at 300 °C for 15

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min.

The saturate fraction from the expelled oil and retained-bitumen were

analyzed by an HP 5973 mass spectrometer coupled with a Hewlett-Packard 6890 gas chromatograph. The GC was equipped with a DB-1MS capillary column (60 m× 0.32 mm× 0.25 µm). The temperature was maintained at 70 °C for 2 min, then increased to 210 °C at 3 °C/min, to 300 °C at 2 °C/min, and finally

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ACCEPTED MANUSCRIPT held at 300 °C for 30 min. Helium was used as the carrier gas with a flow rate of 1.0 ml/min. The transfer line temperature was 280 °C, and the ion source temperature was 200 °C. The ion source was operated in electron impact (EI)

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mode at 70 eV.

Kerogens: The kerogens were isolated from the heated shales and purified

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with mixed solvent extraction (methanol: acetone: benzene =1: 2.5: 2.5) for one week. The functional groups of the kerogens were determined by a NICOLET

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NEXUS 670 FTIR Spectrometer with a DTGS detector. In an environment of infrared light, kerogen and potassium bromide pellets were mixed together and then grounded and tableted into wafer with diameters of 13 mm. The signals accumulated from 10 scans were collected, with the resolution of a single

3 Results

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spectrum amounting to 4 cm -1.

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3.1 Bulk geochemical characteristics of the lacustrine and marine shales

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As shown in Table 1, both the DU and XHY shales are characterized by high TOC contents and have a TOC of 3.29% and 6.27%, respectively. Equivalent vitrinite reflectance measurements show an indicative of thermally immature to early mature stage (0.35% Ro for the DU shale and 0.60% Ro for the XHY shale). Combined with the Rock-Eval data and organic maceral compositions, the DU shale can be classified as type IIA and the XHY shale can be classified as type IIB (Fig. 1).

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ACCEPTED MANUSCRIPT 3.2 Oil / bitumen yields Both the DU and XHY shales demonstrate peak oil at an equivalent vitrinite reflectance of 1.0% to 1.1% (the stage of 400 °C) during pyrolysis, as revealed

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by their maximum yields of bitumen (Table 2, Fig. 2). Corresponding to this process, the HI of the DU and XHY shales decreases rapidly from 531 to 150 mg

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HC/g TOC and 356 to 94 mg HC/g TOC, respectively. The hydrocarbon generation potential (S1+S2) of the DU and XHY shales decreases from 18.18 to

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2.35 mg HC/g and 22.87 to 5.25 mg HC/g, respectively (Table 3). The maximum yield of the total generated-bitumen of DU shale is 402.74 mg/g.TOC, whereas the maximum yields is 169.42 mg/g.TOC for the XHY shale. The difference in the oil yields between the DU and XHY shales could be a reflection of TOC and

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kerogen types. The DU shale is more enriched in hydrogen compared to that of the XHY shale, as revealed by the Hydrogen Index (Table 1), resulting in higher

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oil yields.

A quick decrease of the retained-bitumen in shales strongly indicates the

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occurrence of hydrocarbon expulsion from 400 °C to 450 °C. The content of polar fractions (resins and asphaltenes) in the extracted retained-bitumen from the DU and XHY heated shales is higher than that in the expelled oil (Fig. 3). The resin and asphaltene enrichment in the retained-bitumen can be attributed to hydrocarbon expulsion fractionation due to the molecular weight differences among compounds and partly to the strong adsorption capacity of kerogen

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ACCEPTED MANUSCRIPT and/or the mineral matrix (Tissot and Welte, 1984; Stainforth and Reinders, 1990). Using the relative contents of the compound-grouped fractions, the expelled oils of the DU and XHY shales in the main expulsion stage (450 °C) of

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the thermal simulation experiments can be ascribed as ‘paraffinic’ and ‘aromatic-intermediate’ types, respectively (Fig. 4; Tissot and Welte, 1984).

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3.3 Gas yields

As shown in Fig. 5, the gas yields of the DU and XHY shales monotonically

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increase with increasing temperature and two gas-producing stages can be identified. The increasing rate of stage I is higher than that of stage II. Take the XHY shale for example: stage I shows a quick increase of gas yields from 12.79 to 109.86 ml/g.TOC, corresponding to a rapid decrease of HI from 356 to 94 mg

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HC/g.TOC; by contrast, stage II demonstrates a relatively low increasing rate of gas yields from 172.31 to 265.07 ml/g.TOC, accompanied by a slight decrease

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of HI from 18 to 3 mg HC/g.TOC. The DU shale generated a higher gas yield than the XHY shale, e.g., 646.00 ml/g.TOC for the DU shale and 265.07

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ml/g.TOC for the XHY shale at 550 °C. This could be due to the higher hydrogen content of the DU shale compared to the XHY shale, resulting in higher gas yields. However, it is noted that the difference between the gas yield of the DU and XHY shales is reduced when presented in the format of ml/g.rock (Table 4).

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ACCEPTED MANUSCRIPT 4 Discussion 4.1 Organic sources of the DU and XHY shales The molecular geochemistry of the DU shale demonstrates typical

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characteristics of lacustrine source rocks from Tertiary terrestrial petroliferous basins in China. As shown in Fig. 6a, low molecular weight n-alkanes with n-C16

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as the most abundant peak are the main components, and the ratio of (n-C21+n-C22)/ (n-C28+n-C29) is up to 2.17. This indicates a major input from

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planktonic algae to sedimentary organic matter (Philippi, 1974; Moldowan et al., 1985; Cranwell et al., 1987). Figure 6a shows the relatively high abundance of 4-methylsteranes, which is probably indicative of dinoflagellates in the Songliao Basin (Hou et al., 2000). This is consistent with the organic petrology

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observations showing that alginite and its degraded products (sapropelinite) are the major components (Table 1). The high molecular weight n-alkanes

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demonstrate a marked odd-even carbon number predominance, with a carbon preference index (CPI) value of 2.31 in the n-C22 to n-C31 range, suggesting a

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low maturity of shale experienced and the organic source from high terrestrial plants (Moldowan et al., 1985). The low pristane/phytane ratio (Pr/Ph=0.37) of the DU shale indicates that an anoxic depositional environment prevailed during sedimentation (Didyk et al., 1978), resulting in the good preservation of organic matter. This is further supported by the presence of β-carotane in the extracted organic matter (Fig. 6a; Peters et al., 2005).

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ACCEPTED MANUSCRIPT Previous studies suggested that benthic macro red algae are the primary biologic source of organic matter in the XHY shale, whereas planktonic algae and acritarch play a minor role (Bian et al., 2005; Zhang et al, 2007). A full suite

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of n-C12– n-C28 alkanes, maximizing at C17, are detected in the extracted organic matter of the XHY shale, with an n-C21-/ n-C22+ ratio of 7.34 and abundant

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methylated alkanes and n-alkyl cyclohexane distributions (Fig. 6b). Interestingly, the isoprenoids (e.g., pristane, phytane), steranes and hopanes are

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undetectable. In general, the molecular geochemical characteristics of the XHY shale are similar to those from other Proterozoic strata around the world (Summons et al., 1988; Logan et al., 1997).

4.2 Processes involved in gas generation during pyrolysis

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As previously stated, two gas-producing stages (I and II) can be identified according to the gas yields curve. As shown in Fig. 5, stage I occurs before the

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main oil expulsion occurred and was followed by stage II during the highly to over mature stage. These two stages can be well-matched with oil generation,

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expulsion and cracking processes. For example, at the highly to over mature stage as 450, 500 and 550 °C, the retained-bitumen and total generated-bitumen yields of the DU shale show a decreasing trend due to expulsion and cracking (Fig. 2a; Tissot and Welte, 1984), although the volatile loss of light hydrocarbons during the experiments may influence the total generated-bitumen. A slight increase of the total generated-bitumen yields for the XHY shale at 550 °C is

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ACCEPTED MANUSCRIPT unexpected (Fig. 2b) and is most likely an artifact (e.g., quartz particle input during expulsion). These two gas-producing stages strongly suggest that there are probably

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different genetic mechanisms involved in gas generation during pyrolysis. As shown in Fig. 5, whatever the gas yield of DU or XHY shale is present, the

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turning-point between the two stages occurs at an equivalent vitrinite reflectance of 1.1–1.5% (400–450 °C), corresponding to the peak oil to main oil expulsion

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stages. Interestingly, the hydrocarbon generation potentials from the Rock-Eval pyrolysis data of the heated DU and XHY shales clearly demonstrate that the TOC, S1+S2 and HI values decrease quickly from 300 °C to 450 °C (Table 3). For example, the hydrocarbon generation potentials (S1+S2) of the heated DU and

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XHY shales at the stage of 300 °C to 450 °C decrease from 18.18 to 0.97 mg/g and 22.87 to 1.17 mg/g, respectively. Moreover, the FTIR analyses of two shale

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kerogens reveal that the relative contents of the lipid groups (–CH3, –CH2) in the kerogens also decrease rapidly upon thermal evolution and are almost

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undetected at 450 °C, leaving aromatic groups as the main peaks at higher thermal stress levels (Fig. 7). This means that the hydrocarbon potential of the kerogens is almost exhausted when the temperature is up to 450 °C, indicating that gas source transformation at the highly to over mature stage given a continuing increase of gas yields occurred along the maturity sequence. It is well known that gas generation in shale at the highly to over mature

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ACCEPTED MANUSCRIPT stage is not only from kerogen thermal degradation but also from retained-bitumen cracking. A large body of studies have confirmed that with the increasing extent of kerogen degradation, the methane yield increases more

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quickly than ethane and propane, and then, the gas dry coefficient (C1/ΣC1-5%) monotonically increases until it reaches an equilibrium value (e.g., Schoell, 1983;

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Behar et al., 1992; Zhang et al., 2009). However, oil and/or bitumen cracking produces a much larger amount of ethane and propane through the cleavage of

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carbon chains than does the demethylation of highly mature kerogen in the early stage (Hill et al., 2003). At higher temperatures, the wet gas (C2-5) will further crack into methane and lead to the formation of pyrobitumen (Hill et al., 2003; Tian et al., 2006). Thereafter, mixed contributions from kerogen degradation and

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bitumen cracking in shale could lead to a relatively flat curve of the gas dry coefficient and even a declining trend once the highly to over mature stage is

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reached. As shown in Table 4 and Fig. 8, except for the early 300–350 °C stage, the gas dry coefficient of the DU shale always increases with increasing

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temperature, but in a relatively flat trend around 450 °C. The gas dry coefficient of the XHY shale shows a significant decline around 450 °C, followed by a slow rebound during the highly to over mature stage. Changes of the gas dry coefficient upon thermal evolution strongly indicate gas contributions from retained-bitumen cracking in shale at stage II. The differential behavior of the gas dry coefficient between the DU and XHY shales is mainly ascribed to the

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ACCEPTED MANUSCRIPT organic source characteristics of shales, thereafter the generated hydrocarbon properties. As shown in Fig. 4, the DU shale produces ‘paraffinic’ type oil, whereas

the

XHY

shale

produces

‘aromatic-intermediate’

type

oil.

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Corresponding to this observation, the retained-bitumen in the XHY shale is enriched in the polar fractions (NSO compounds) compared to those in the DU

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shale, especially in terms of the asphaltene fraction (Fig. 3). This is a main factor for controlling the gas dry coefficient curve because it depends on the relative

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contributions from both kerogen-generated gas and retained-bitumen cracking gas. It is well known that the energy of bond cleavage reactions for NSO compounds is lower than that of chain hydrocarbons. The NSO compounds start to significantly crack at an equivalent vitrinite reflectance of ~1.3% Ro and chain

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hydrocarbons (e.g., n-alkanes) of >1.5% Ro (Hill et al., 2003). The relative enrichment of the polar fractions (NSO compounds) in the retained-bitumen of

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the XHY shale could make a significant contribution to the gas compositions at 400–450 ºC. This results in a definite decline of the gas dry coefficient curve

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during pyrolysis of the XHY shale. In contrast, the retained-bitumen cracking gas in the DU shale at the same thermal tress probably makes a relatively low contribution due to its paraffinic characteristics. The most interesting is that the turning-point of the gas dry coefficient curves for the DU and XHY shales occurs at 400–450 °C, which is consistent with the turning-point

of

the

two

gas-producing

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stages,

suggesting

that

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ACCEPTED MANUSCRIPT retained-bitumen cracking starts to play an important role in gas accumulation during and/or after the main oil expulsion. A sudden decline of the gas dry coefficient at 550 °C for the DU shale may be induced by its high oil generation during

isothermal

pyrolysis,

directly

resulting

in

oil-cracking

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potential

accompanying oil expulsion due to highly thermal stress, and with abnormally

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high gas yields at 550 °C (Fig. 8a).

The stable carbon isotopic profile of methane along the maturity sequence

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from the DU shale provides another evidence for the retained-bitumen cracking contribution at the highly to over mature stage. The methane carbon isotope first becomes enriched in

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C and then in

13

C with increasing thermal maturity or

decreasing wetness, which has been documented in many pyrolysis

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experiments or in shale gas plays (Smith et al., 1985; Hill et al., 2003). One explanation for this phenomenon could be the diverse precursors for gas

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generation with different isotopic compositions (Tang et al., 2000; Xia et al., 2013). Usually, the stable carbon isotopic composition of produced methane

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would be progressively heavier through the oil window to late gas stage with increasing kerogen degradation (Rooney et al., 1995). Carbon isotopes of the liquid hydrocarbons generated from kerogen have been considered to be lighter than their precursors, leading to

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C-enriched methane that is produced by

oil/bitumen cracking compared to that of methane generated from kerogen degradation at the similar thermal stress levels (Tang et al., 2000; Guo et al.,

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ACCEPTED MANUSCRIPT 2009; Xia et al., 2013). Thus, the methane carbon isotope of the DU shale shows a trend of enrichment in

C at 400–450 °C (Fig. 8a) due to the mixed

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contribution from retained-bitumen and kerogen. Jarvie and Behar (2010)

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suggested that the retained-bitumen consisted mainly of resins and asphaltenes, which could be important precursors of shale gas at the highly to over mature

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stage. This is exactly the same phenomenon that was observed in this study. As shown in Fig. 3, there are abundant polar fractions in the retained-bitumen of the

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DU and XHY heated shales, and the polar fraction content increases from 300 °C to 450 °C, followed by a decrease from 450 °C to 550 °C. The relative abundance of resins decreases from 300 °C to 450 °C, whereas asphaltenes increase in the same range. This could be due to the lower activation energy of

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the degradation of resins than that of asphaltenes (Karacan and Kok, 1997); thus, resins would crack to asphaltenes and secondary oil/gas (Phillips et al.,

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1985; Ranjbar and Pusch, 1991). From 450 °C to 550 °C, the relative abundance of asphaltenes shows a significant decrease. This is consistent with previous

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work showed that asphaltenes could convert to coke, light oils, gases and resins (Fig. 3; Karacan and Kok, 1997). Therefore, the gas generation from the shale experiments can be related to

at least two processes. The first process is associated with kerogen thermal degradation and occurs at the main phase of oil generation. The second process starts at the late phase of oil generation and is mainly associated with the

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ACCEPTED MANUSCRIPT secondary cracking of kerogen-generated bitumen, which is characterized by dominant C2–5 wet gas and

13

C depleted methane, resulting in the approximate

reversal of the dry coefficient and δ13Cmethane.

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4.3 Quantitative calculations of gas from kerogen thermal degradation and retained-bitumen cracking

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Although an increasing number of studies suggest the importance of retained-bitumen cracking contributions to gas accumulation in shale gas

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systems, it is still unclear how much accumulated gas originates from the retained-bitumen cracking. Moreover, gas generation processes from kerogen thermal degradation or oil/retained-bitumen cracking usually overlap in geological time and reservoir space, making it difficult to calculate their

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contributions. Here, we develop a new method to quantitatively evaluate their contributions by integrating of experimental data and mass balance of hydrogen

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content.

4.3.1 Theoretical consideration and method within hydrogen mass balance

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Petroleum is mainly composed of carbon- and hydrogen-containing

compounds, and the hydrogen content in sediments is a main factor that determines the oil and gas generation potential upon thermal evolution. In terms of the chemical reactions (decomposition and condensation) that occur during thermal maturation, hydrocarbon generation is the progressive consumption of hydrogen in shale. To any given maturity point, the consumed hydrogen can be

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ACCEPTED MANUSCRIPT allocated into expelled oil, retained-bitumen in shale and generated gas (i.e., hydrocarbon gas and non-hydrocarbon gas). Due to very low yields of H2 and H2S, the yield of total hydrocarbon gas can be calculated within the framework of

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hydrogen mass balance if the loss of hydrogen in non-hydrocarbon gas components is neglected. The following equations can be derived:

H heated shale =

(H C ) × TOCoriginal shale 12

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H original shale =

(H C ) × TOC heated shale 12

Vtotal gas =

(H

original shale

− H heated shale − H total bitumen ) × Vm × 1000 n

(2) (3)

(4)

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where:

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H total bitumen = M total bitumen × 0.125

(1)

Horiginal shale and Hheated shale (mol/g) are the hydrogen content in the original and heated shales at any given maturity point, respectively;

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point;

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H/C is the hydrogen to carbon atom ratio of kerogen at any given maturity

Htotal bitumen (mol/g) is the hydrogen content of the total generated-bitumen

(expelled oil and retained-bitumen in shale) at any given maturity point; Mtotal bitumen is the yield of the total generated-bitumen at any given maturity

point. A 12.5%wt of total generated-bitumen is adopted based on the average content of hydrogen in crude oils (Tissot and Welte, 1984); n is the mole number of hydrogen in 1 mole of hydrocarbon gas;

20

ACCEPTED MANUSCRIPT Vm is the standard molar volume of gas (22.4 L/mol). To calculate the gas yields from kerogen degradation independently, two assumptions are required. The first is the starting point and extent of the

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retained-bitumen cracking in shale. In a semi-closed thermal simulation system, an experimental set-point of 400 °C (peak oil) is arbitrarily considered to be the

SC

starting point of retained-bitumen cracking and contributes approximately 10% of the hydrocarbon gas to the total gas yields. The second assumption is that there

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is no oil generation from kerogen at 450 °C or higher temperature set-points due to undetectable lipid groups in heated shale kerogens, and the difference of the hydrogen content in kerogens between the adjacent experimental set-points is converted to hydrocarbon gas. With these assumptions, the hydrocarbon gas

Eqs. (5) and (6):

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generated from kerogens at temperatures of 450 °C or above can be written as

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∆Vkerogen = (∆H n ) × Vm × 1000

(6)

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Vkerogen (T ) = Vkerogen (T − 50°C ) + ∆Vkerogen

(5)

In the above equations, when the temperature was 450 °C, the difference of

hydrogen consumption (∆H) in kerogen between adjacent temperatures was given by Eq. (7):

∆H = H heated shale (450°C ) − H heated shale (400°C )

(7)

At temperatures of 500 °C and 550 °C, the difference of hydrogen consumption in kerogens between adjacent temperatures (given in Eq. (8)) need 21

ACCEPTED MANUSCRIPT to be compared to the hydrogen consumption of CH4 generation, which depends on the carbon depletion (given in Eq. (9)). If the former hydrogen consumption is

the former exceeded the latter, then Eq. (9) is adopted.

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less than the latter hydrogen consumption, then Eq. (8) is adopted, whereas if

∆H = H heated shale (T ) − H heated shale (T -50°C )

the

yields

heated shale (T )

of

the

− TOC heated shale (T − 50°C ) ) ×4 12

hydrocarbon

gas

sourced

(9)

from

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Thereafter,

(TOC

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∆H =

(8)

retained-bitumen upon thermal evolution can be obtained by the subtraction of kerogen-degraded gas from the total hydrocarbon gas.

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4.3.2 Gas contributions from kerogen degradation and retained-bitumen cracking in typical Chinese lacustrine shale and marine shale Table 5 lists the theoretically calculated yields of the hydrocarbon gas of the

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DU and XHY shales from kerogen degradation and retained-bitumen cracking

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upon thermal evolution, respectively. As shown in Fig. 9a, for the lacustrine DU shale, there is little hydrocarbon

gas contribution from the retained-bitumen cracking at a temperature of 400 °C (Ro=1.0–1.1%). However, the retained-bitumen cracking starts to play an important role in gas yields after a temperature of 450 °C (Ro=1.3–1.5%), and can contribute approximately 30.47% of the total hydrocarbon gas at a temperature of 500 °C (Ro=1.7–1.9%). This is consistent with previously

22

ACCEPTED MANUSCRIPT published calculations by Xia et al. (2013). They suggested that the condensate retained in the source rock contributes up to 30% of the total hydrocarbon gas at high maturity. With a simple mathematical conversion, the retained-bitumen in

to shale gas during the stage of 1.5–2.0%Ro.

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the organic rich shale (e.g., TOC%=3–5%) can contribute 2–3 m3 HC gas/t.rock

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For the marine XHY shale, the retained-bitumen begins to crack in the range of 400–450 °C (Ro=1.0–1.1% to 1.3–1.5%) and makes little contribution of

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hydrocarbon gas (Fig. 9b). Considerable hydrocarbon gas sourced from retained-bitumen cracking is expected at temperatures exceeding 450 °C. Approximately 20.05% of the total hydrocarbon gas generated is derived from retained-bitumen cracking at 500 °C (Ro=1.7–1.9%), and this contribution

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reaches 28.93% when the pyrolysis temperature reaches 550 °C (Ro=2.1–2.3%). The hydrocarbon gas generated from the retained-bitumen cracking in

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organic-rich marine shale could be up to 1–2 m3 HC gas/t. rock. The biologic source of the XHY shale is benthic macro red algae that have low oil generation

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potential. Therefore, the XHY shale generates less hydrocarbon gas than that of the DU shale.

4.4 Implications for shale gas exploration The retained-bitumen cracking in highly mature source rocks has long been recognized as an important source of gas (Liu et al., 2007; Zhao et al., 2007), but its exploration prospect had not received attention until the successful

23

ACCEPTED MANUSCRIPT commercial discovery of shale plays in North America (Hill et al., 2007; Rodriguez and Philp, 2010). Generally, the amount of kerogen-generated bitumen retained in shale strongly depends on the expulsion efficiency, which is

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influenced by the type and richness of the organic matter, adsorptive capacity of the mineral matrix and kerogen, and openness of the shale-gas system. Jarvie

strong

adsorptive

capacity

resulted

in

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et al. (2007) suggested that the low permeability of the Barnett Shale and its the

retention

of

abundant

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kerogen-generated bitumen and concluded that retained-bitumen cracking made important contributions to the shale gas. Here, a mathematical method within the hydrogen dynamics in sedimentary organic matter upon thermal evolution is developed with data input from a newly designed semi-closed thermal simulation

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system, allowing for a possibility to quantitatively calculate the shale gas contributions from kerogen thermal degradation and retained-bitumen cracking.

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The results from lacustrine shale and marine shale from China are consistent with previously theoretical calculations by Xia et al. (2013), and retained-bitumen

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cracking can contribute up to 30% of the total hydrocarbon gas at high maturity. Therefore, using this calculation together with the TOC measurements, organic type decisions, thicknesses and areas of shale deposits, and maturity experienced in a given petroliferous basin, the shale gas contributions of both kerogen and retained-bitumen can be estimated. The results are clearly of value in maturity map-making and shale gas resource assessments before

24

ACCEPTED MANUSCRIPT exploration. The mixing of primary gas generated from kerogen thermal degradation and secondary gas generated from retained-bitumen cracking probably provides a

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reasonable explanation for what is termed as ‘isotope reversal’ during shale gas exploration (Rodriguez and Philp, 2010; Tilley et al., 2011; Xia et al., 2013), as

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revealed by a trend of more negative δ13Cmethane values with respect to maturity in the range of 1.5–2.0% Ro in this experiment. Further specialized experiments

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could be designed and the results would be expected to delineate the ‘isotope reversal’.

5. Summary

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(1) The DU and XHY shales are organic-rich, oil-prone shales that expelled ‘paraffinic’ and ‘aromatic-intermediate’ types oil, respectively, during the oil window.

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(2) The gas generation processes involved during thermal evolution and the

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potential of the DU and XHY shales were evaluated by the newly designed semi-closed thermal simulation system. Apart from the kerogen thermal degradation, the cracking of kerogen-generated bitumen retained in shale could be an important contributor of gas beyond the late phase of the oil window, which was characterized by a significant amount of

12

C-enriched methane and the

increasing yields of wet gas components. (3) Mass balance calculations using the hydrogen content in sedimentary

25

ACCEPTED MANUSCRIPT organic matter demonstrate that the bitumen retained in the DU and XHY shales can contribute 30% of the total shale gas at the stage of 1.5–2.0%Ro. The results provided experimental evidence that kerogen-generated bitumen is a source of

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shale gas and is critical to shale gas resource assessments before exploration.

Acknowledgements

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We would like to express our thanks to Prof. Jialan Lu of SKLOG for his technical assistance during the semi-closed pyrolysis experiments. We also

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thank the anonymous reviewers for the constructive comments and suggestions, which significantly improved this manuscript. This work was jointly supported by the grants from National Science Foundation of China (Grant No. 41172112,

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41372131), the ‘151 Talent Program of Zhejiang Province’ and The State Project of Oil & Gas Exploration (2011ZX05008-002-15) to Yongge Sun.

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ACCEPTED MANUSCRIPT Table 1 Bulk characteristics of original DU and XHY shales.

naa na na na

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6.27 0.98 23.37 376 25 434 24.35 0.04

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XHY shale 0.60

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Sample DU shale Vitrinite reflectance (%) 0.35 Maceral composition Sapropelinite (%) 90 Vitrinite (%) 5 Exinite (%) 3 Inertinite (%) 2 TOC and Rock-Eval TOC (%) 3.29 0.51 S1 (mg HC/g) S2 (mg HC/g) 17.87 HI (mg HC/gTOC) 543 OI (mg HC/gTOC) 18 Tmax (°C) 435 S1+S2 (mgCO2/gTOC) 18.38 b PI 0.03 a na=not analyzed. b PI=production index (S1/(S1+S2)).

1

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Total bitumen

Expelled oil

mg/g.TOC 117.02 317.63 402.74 358.36 306.08 284.80 37.38 67.47 147.51 144.08 145.78 169.42

mg/g.T OC 5.77 65.35 350.46 351.98 304.86 283.89 1.73 21.66 111.68 139.20 144.38 169.26

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mg/g.rock 0.19 2.15 11.53 11.58 10.03 9.34 0.11 1.36 7.00 8.73 9.05 10.61

Retained-bitu men mg/g.rock 3.66 8.30 1.72 0.21 0.04 0.03 2.23 2.87 2.25 0.30 0.09 0.01

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% 0.6 0.7-0.8 1.0-1.1 1.3-1.5 1.7-1.9 2.1-2.3 0.6 0.7-0.8 1.0-1.1 1.3-1.5 1.7-1.9 2.1-2.3

Expelled oil

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XHY Shale

°C 300 350 400 450 500 550 300 350 400 450 500 550

Total bitumen mg/g.rock 3.85 10.45 13.25 11.79 10.07 9.37 2.34 4.23 9.25 9.03 9.14 10.62

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DU shale

Ro

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Sample

T

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Table 2 Liquid hydrocarbon yields of DU and XHY shales under different pyrolysis temperatures.

2

Retained-bitu men mg/g.TOC 111.25 252.28 52.28 6.38 1.22 0.91 35.65 45.81 35.83 4.88 1.40 0.16

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S1+S2 mgHC/g 18.18 12.14 2.35 0.97 0.69 1.12 22.87 19.03 5.25 1.17 0.64 0.43

PIa

0.03 0.06 0.13 0.40 0.62 0.61 0.02 0.05 0.09 0.25 0.47 0.65

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S2 mgHC/g 17.72 11.47 2.05 0.58 0.26 0.44 22.31 18.13 4.76 0.88 0.34 0.15

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S1 mgHC/g 0.46 0.67 0.30 0.39 0.43 0.68 0.56 0.90 0.49 0.29 0.30 0.28

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T TOC Tmax Sample °C % °C 300 3.19 438 350 2.63 441 DU 400 1.52 443 shale 450 1.40 444 500 1.29 572 550 1.20 392 300 6.24 433 350 5.85 438 XHY 400 5.06 463 450 4.70 568 shale 500 4.51 600 550 4.41 319 a PI=production index (S1/(S1+S2)).

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Table 3 Rock-Eval pyrolysis results of heated shales under different pyrolysis temperatures.

3

HI mgHC/gTOC 531 416 150 40 25 30 356 312 94 18 8 3

OI mgCO 2/gTOC 10 12 15 14 15 9 7 5 7 6 5 5

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C2 % 52.31 46.28 30.30 24.25 20.40 25.87 12.15 24.60 27.09 26.78 23.36 22.42

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C1 % 22.62 20.03 35.31 39.84 46.75 40.12 13.05 29.10 34.32 29.04 38.06 48.21

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Gas ml/g.TOC 48.88 124.32 275.08 340.93 394.12 646.00 12.79 39.61 109.86 172.31 212.01 265.07

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XHY Shale

Gas ml/g.rock 1.61 4.09 9.05 11.22 12.97 21.25 0.80 2.48 6.89 10.80 13.29 16.62

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DU shale

T °C 300 350 400 450 500 550 300 350 400 450 500 550

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Sample

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Table 4 Gas yields of DU and XHY shales under different pyrolysis temperatures and their hydrocarbon gas compositions.

4

C3 % 9.78 14.95 17.33 18.68 15.37 17.49 14.96 21.23 22.39 24.18 19.90 16.18

C4 % 11.95 14.30 13.16 13.02 12.21 12.31 42.19 19.17 13.22 15.86 14.26 10.51

C5+ % 3.34 4.44 3.90 4.22 5.28 4.20 17.65 5.90 2.99 4.14 4.42 2.68

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XHY shale

Vtotal gas

Vkerogen

V bitumen

Vtotal gas

%mol/g

mol

m /t.rock

m /t.rock

m /t.rock

m /t.TOC

naa 0.123 0.105 0.054 0.049 0.49 0.39 0.31 0.24 0.17

naa 0.166 0.147 0.126 0.117 0.051 0.111 0.108 0.110 0.127

naa 6.40 6.35 6.18 6.29 6.96 6.47 6.79 6.47 5.94

0.1b 4.39 5.70 8.50 8.83 2.07 3.54 6.07 8.68 11.51

0.1 3.95 4.58 5.91 6.08 2.07 3.18 5.82 6.94 8.18

0 0.44 1.12 2.59 2.75 0 0.36 0.25 1.74 3.33

3.04 133.43 173.25 258.36 268.39 33.01 56.46 96.81 138.44 183.57

3

3

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1.53 0.97 0.90 0.50 0.49 1.01 0.94 0.80 0.64 0.47

n

Htotal bitumen %mol/g

na=not analyzed. Suppose that the DU shale generates 0.1 m3/t.rock hydrocarbon gas at 350 °C.

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b

350 400 450 500 550 350 400 450 500 550

Hheated shale

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a

°C

H/C

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DU shale

T

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Sample

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Table 5 Hydrocarbon gas yields from the kerogen thermal degradation and retained-bitumen cracking, calculated by hydrogen mass balance.

5

3

3

Vkerogen

V bitumen

3

m /t.TOC m3/t.TOC 3.04 120.06 139.21 179.64 184.80 33.01 50.72 92.82 110.69 130.46

0.00 13.37 34.04 78.72 83.59 0.00 5.74 3.99 27.75 53.11

ACCEPTED MANUSCRIPT Figure Captions Fig.1. Hydrogen index (HI) vs. Tmax diagram representing the organic matter type for the original DU and XHY shales. Fig.2. Liquid hydrocarbon yields dynamics along the pyrolysis temperatures,

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correlated with the HI profiles. (a) DU shale; (b) XHY shale. Fig.3. Changes on the compound-group fractions of the retained-bitumen along the pyrolysis temperatures. (a) DU shale; (b) XHY shale.

Fig.4. The ternary diagram showing the classification of the expelled oil at the

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main expulsion stage (450 °C) for the DU and XHY shales (after Tissot and Welte, 1984).

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Fig.5. Total gas yields dynamics along the pyrolysis temperatures, correlated with the HI profiles. (a) DU shale; (b) XHY shale. The gas generation process can be divided into two stages according to the slope of the gas yield curve. Fig.6. Total ion chromatograms (TIC) of saturate fractions from the original DU shale (a) and XHY shale (b). Peak number represents the carbon number of

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the n-alkanes.

Fig.7. FTIR spectra of kerogens at various pyrolysis temperatures. (a) DU shale; (b) XHY shale.

Fig.8. Gas dry coefficient (C1/ΣC1-5%) dynamics along the pyrolysis

(b).

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temperatures, correlated with δ13Cmethane for DU shale (a) and HI for XHY shale

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Fig.9. Hydrocarbon gas yields profile from the kerogen thermal degradation and retained-bitumen cracking, based on the hydrogen mass balance calculations. (a) DU shale; (b) XHY shale.

1

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Fig.1. Hydrogen index (HI) vs. Tmax diagram representing the organic matter type for the original DU and XHY shales.

2

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Fig.2. Liquid hydrocarbon yields dynamics along the pyrolysis temperatures, correlated with the HI profiles. (a) DU shale; (b) XHY shale.

3

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Fig.3. Changes on the compound-group fractions of the retained-bitumen along the pyrolysis temperatures. (a) DU shale; (b) XHY shale.

4

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Fig.4. The ternary diagram showing the classification of the expelled oil at the main expulsion stage (450 °C) for the DU and XHY shales (after Tissot and Welte, 1984).

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Fig.5. Total gas yields dynamics along the pyrolysis temperatures, correlated with the HI profiles. (a) DU shale; (b) XHY shale. The gas generation process can be divided into two stages according to the slope of the gas yield curve.

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Fig.6. Total ion chromatograms (TIC) of saturate fractions from the original DU shale (a) and XHY shale (b). Peak number represents the carbon number of the n-alkanes.

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Fig.7. FTIR spectra of kerogens at various pyrolysis temperatures. (a) DU shale; (b) XHY shale.

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Fig.8. Gas dry coefficient (C1/ΣC1-5%) dynamics along the pyrolysis temperatures, correlated with δ13Cmethane for DU shale (a) and HI for XHY shale (b).

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Fig.9. Hydrocarbon gas yields profile from the kerogen thermal degradation and retained-bitumen cracking, based on the hydrogen mass balance calculations. (a) DU shale; (b) XHY shale.

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(1) A new semi-closed system was used to investigate the gas generation processes.

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(2) Kerogen-degraded and retained-bitumen cracking gas in shale can be differentiated.

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(3) Retained-bitumen cracking can contribute 30% of shale gas at the stage of

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1.5–2.0%Ro.