Geochemical characteristics of the Triassic Chang 7 lacustrine source rocks, Ordos Basin, China: Implications for paleoenvironment, petroleum potential and tight oil occurrence

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Geochemical characteristics of the Triassic Chang 7 lacustrine source rocks, Ordos Basin, China: Implications for paleoenvironment, petroleum potential and tight oil occurrence ⁎

Zhengjian Xua,b, Luofu Liua,b, , Benjieming Liuc, Tieguan Wanga,b, Zhihuan Zhanga,b, Kangjun Wud, Chenyang Fenge, Wenchao Doua,b, Yang Wanga,b, Yun Shuf a

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing), Beijing 102249, China College of Geosciences, China University of Petroleum (Beijing), Beijing 102249, China McDougall School of Petroleum Engineering, The University of Tulsa, Tulsa, OK 74104, USA d School of Petroleum Engineering, Chongqing University of Science and Technology, Chongqing 401331, China e Faculty of Science, University of Alberta, Edmonton T6G2E1, Canada f Sichuan Salt Geological Drilling Brigade, Zigong 643000, China b c

A R T I C LE I N FO

A B S T R A C T

Keywords: Lacustrine source rock Geochemical characteristics Paleoenvironment Petroleum potential Hydrocarbon generation kinetic Tight oil occurrence

The fact that high-quality lacustrine source rocks (generally shale and mudstone) control the formation and distribution of conventional and unconventional oil and gas reservoirs in lacustrine basins has been well-accepted in petroleum exploration and exploitation. Taking the Chang 7 lacustrine source rocks in the Ordos Basin as an example, several points having been reached are as follows. (1) The Chang 7 source rocks possess an excellent source rock potential, and the shales hold a better potential than the mudstones. (2) The paleoenvironments of the Chang 7 source rocks were sub-reducing to sub-oxidizing conditions and fresh- and brackish-water depositional environments with a maximum water depth of 150 m. The organic matter origins of the source rocks are mainly plankton, algae, bacteria and other aquatic microorganisms. (3) The beginning time of the oil generation of the Chang 7 source rocks is at 165 Ma, and the peak oil generation occurred during 115–95 Ma. The cumulative amounts of oil generation are up to 4711 × 103 t/km2 and the ratios of peak generation amounts to cumulative generation amounts are > 50%. The beginning timing and peak generation timing of the shales are earlier than those of the mudstones, respectively, and the cumulative oil generation amount of the shales is higher than that of the mudstones, indicating a better oil generation potential of the shales. (4) Due to the more remained oil possessed in the shales, the hydrocarbon expulsion threshold of the Chang 7 shales (2560 m) is deeper than that of the Chang 7 mudstones (2080 m). (5) The occurrences of the Chang 8–6 tight oils are predominantly controlled by the outer boundary of the Chang 7 source rocks distribution, while the transition areas between thickness, TOC, and RO high value centers are the accumulation and enrichment zones. The Chang 7 shales controlled the occurrence of the Chang 8 tight oil reservoirs and the Chang 7 mudstones controlled the occurrence of the Chang 7 and Chang 6 tight oil reservoirs.

1. Introduction Fine-grained siliciclastic rocks (including mudstones and shales) are the most abundant deposits of earth’s sedimentary record (Aplin and Macquaker, 2011), which are transformed by the clay- and silt-size particles that mostly comprise grains smaller than 62.5 μm through mechanical and chemical compaction (Aplin and Macquaker, 2011). These deposits may variously act as a source, seal and even reservoir (unconventional) layers for conventional and unconventional hydrocarbon resources (Law and Curtis, 2002; Zhang et al., 2006; Aplin and ⁎

Macquaker, 2011; McCarthy et al., 2011; Arthur and Cole, 2014; Li and Lin, 2015). Investigations of these rocks have become increasingly important in conventional and unconventional hydrocarbon exploration and exploitation. Generally, fine-grained siliciclastic rocks are considered to be high-quality source rocks, and it is well-accepted that the high-quality source rocks control the occurrence of conventional and unconventional oil and gas reservoirs (Zhang et al., 2006; McCarthy et al., 2011; Arthur and Cole, 2014). It has been proved that the Early Mississippian Bakken Formation (Williston Basin, USA) (Bend et al., 2015), the Mississippian Barnett Shale (Forth Worth Basin, USA)

Corresponding author at: State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing), Beijing 102249, China. E-mail address: [email protected] (L. Liu).

https://doi.org/10.1016/j.jseaes.2018.03.005 Received 27 August 2017; Received in revised form 6 March 2018; Accepted 9 March 2018 1367-9120/ © 2018 Elsevier Ltd. All rights reserved.

Please cite this article as: Xu, Z., Journal of Asian Earth Sciences (2018), https://doi.org/10.1016/j.jseaes.2018.03.005

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Fig. 1. Location of the Ordos Basin in China (a). Tectonic units in the Ordos Basin (b). Geographic and geological information of the study area (c). Geological cross section in the Ordos Basin (d) (Modified from Li and Lu, 2002; Yang et al., 2005), location of the section is shown in Fig. 1b.

Hanson et al., 2007; Ji et al., 2007; Duan et al., 2008; Yu et al., 2010; Han et al., 2014; Ji et al., 2014). Generally, the term “mudstone” implies fine-grained rocks without lamination, while the term “shale”, from a sedimentary geology perspective, should be used only for finegrained rocks with laminations (Macquaker and Adams, 2003; Aplin and Macquaker, 2011; Hart et al., 2013). The laminations are thinnest recognized stratigraphic units uniform in composition and texture, referring to laterally continuous partings that have similar grain size, composition and fabric that range in thickness from less than 1 mm to 1 cm thick (Macquaker and Adams, 2003; Aplin and Macquaker, 2011; Hart et al., 2013). Thus, shales are also called laminated mudstones. Utilizing major, trace, rare earth and platinum-group element

(Montgomery et al., 2005), the Eagle Ford Shale (South Texas, USA) (Tunstall, 2015), the Permian Lucaogou Formation (Junggar Basin, China) (Cao et al., 2016), the Paleogene Lower Ganchaigou Formation (Qaidam Basin, China) (Hanson et al., 2001) and the Cretaceous Qingshankou Formation (Songliao Basin, China) (Huang et al., 2017) possess huge amounts of oil and gas reserves (conventional and unconventional) formed and dominated by widely-distributed, organicrich source rocks. The Mesozoic petroleum systems are very important petroleumbearing plays in the Ordos Basin of Central China. The Triassic Chang 7 source rocks, typically shales and mudstones, are regarded as highquality source rocks in the Ordos Basin (Zhai, 1997; Zhang et al., 2006; 2

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Fig. 2. Comprehensive stratigraphic column of the Triassic Yanchang Formation in the Ordos Basin (modified after Xu et al., 2017).

Although Hanson et al (2007) and Duan et al (2008) proposed that the Chang 7 source rocks have a good to excellent source rock potential, they did not recognize the origin of organic matters and organic petrography in the Chang 7 source rocks. Han et al (2014) has only analyzed the hydrocarbon generation kinetics of Yanchang shales and

geochemistry, Zhang et al (2008), Qiu et al (2015) and Zhao et al. (2018) proposed that the paleoenviroments of the Chang 7 source rocks were sub-reducing to reducing conditions. However, they did not discuss the salinity and depth of the paleo-Ordos Lake during the Chang 7 deposition and the evidences from biomarkers are insufficient. 3

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the upper of the shales (Chang 73–Chang 71) (Fig. 2). The mineral compositions of shales in the Chang 7 are characterized by more clay minerals (52.1%) and less quartz contents (12.5%) than those of the mudstones (43.4% and 21.5%, respectively) (Liu and Sun (2015); Wu et al., 2015).

proposed the phase kinetics description of Yanchang shale oil and shale gas, without any discussions on the Chang 7 mudstones. Besides, previous works didn’t differentiate the mudstones and shales in the Chang 7. The differences may exist, including organic matter origins, depositional conditions of redox states, salinities and water-depths of lake during the source rocks deposition. And these differences may result in different primary productivities and source rock potentials. Besides, these differences may influence the quantitative implications of heterogeneity for petroleum generation, expulsion, retention and migration. In this paper, we analyze the characteristics of source rocks by classifying shales and mudstones, respectively. Several principal objectives are focused on: (1) analyzing the organic petrology and thermal-maturity of the Chang 7 shales and mudstones, (2) recognizing the paleoenvironments and organic matter origins of Chang 7 shales and mudstones; (3) analyzing the bulk organic geochemical characters of Chang 7 shales and mudstones; (4) ascertaining spatial distribution of the Chang 7 shales and mudstones; (5) analyzing the generation and expulsion characteristics of Chang 7 shales and mudstones; and (6) discussing the influences on the Chang 8–6 (from Chang 8 to Chang 6) tight oil occurrence.

2.3. Characters of tight oil reservoir beds Tight oil reservoirs of the Yanchang Formation are mainly distributed in the central area of the Mesozoic petroleum system, which are commonly found in the depression and slope areas, being successive at a large scale (Fig. 1). Stratigraphically, tight sandstones of the lower–middle Yanchang Formation (especially from Chang 8 to Chang 6) are the main targets, which are adjacent to lacustrine source rocks or para-genetically interbedded with the source rocks (Fig. 2) (Zou et al., 2013). Fine sandstones and siltstones are the predominant reservoir beds for the Chang 8–Chang 6 tight oil reservoirs (Fig. 2). The porosity of the reservoir beds of the Chang 8 tight oil mainly ranges from 2.00% to 16.00%, with a mean value of 8.30%. The permeability of the reservoir beds is mainly 0.01–5.00 mD, with an average value of 0.51 mD (Zhang et al., 2013). The porosity of the reservoir beds of the Chang 7 tight oil mainly ranges from 4.00% to 12.00%, with a mean value of 7.60%. The permeability of the reservoir beds is mainly 0.05–0.30 mD, with an average value of 0.15 mD (Xu et al., 2017). The porosity of the reservoir beds of the Chang 6 tight oil mainly ranges from 6.0% to 12.0%, with a mean value of 9.03%. The permeability of the reservoir beds is mainly 0.01–2.03 mD, with an average value of 1.16 mD (Bai et al., 2013). According to the definition of tight reservoir beds in China (porosity of sandstone < 12% and permeability of sandstone < 2.00 mD) (Zou et al., 2013, Zou et al. (2015)), the reservoir beds of the Chang 8-Chang 6 can be classified as tight reservoir beds, and are the important exploration and exploitation target for tight oil reservoirs in the Ordos Basin.

2. Geological settings 2.1. Structure and tectonics The Ordos Basin, with an area of 37 × 104 km2, was formed on the western part of the North-China Platform, which is a large asymmetric syncline with a broad gently dipping eastern limb and narrow steeply dipping western limb. The Mesozoic-Cenozoic Ordos Basin developed on the Paleozoic North China craton with a Paleo-proterozoic crystalline basement (Yang et al., 2005). The evolution of the Ordos Basin during the Paleozoic–Mesozoic is divided into three stages: (1) a Cambrian to Early Ordovician cratonic basin with divergent margins; (2) a Middle Ordovician to Middle Triassic cratonic basin with convergent margins; and (3) a Late Triassic to Early Cretaceous intraplate remnant cratonic basin (Yang et al., 2005). Tectonically, the basin can be subdivided into six substructures: the Yimeng Uplift, the Western Edge Fold-Thrust Belt, the Tianhuan Depression, the Yishan Slope, the Weibei Uplift and the Jinxi Flexural-Fold Belt (Fig. 1).

3. Samples and methods In this study, samples were collected from core samples in the Chang 7 Member. The lithology of the samples are predominant shale and mudstone. 10 shale samples and 27 mudstone samples are operated for organic petrography analyses. 17 shale samples and 38 mudstone samples are operated for thermal maturity-vitrinite reflectance (RO) analyses. 38 shale samples and 74 mudstone samples are operated for TOC and Rock-Eval pyrolysis analyses. 20 shale samples and 42 mudstone samples are operated for chloroform bitumen “A” analyses. 10 shale samples and 13 mudstone samples are operated for gas chromatography-mass spectrometry analyses. And two shale samples and two mudstone samples are operated for hydrocarbon generation kinetic analyses. The samples for organic petrography and vitrinite reflectance are thin-sections, while the samples for other analyses are made in powder.

2.2. Lithostratigraphy As a consequence of regional collisional tectonism and related intraplate deformation in the Middle–Late Triassic (Indosinian Movement), the southern Ordos Basin evolved into a foreland basin, and was dominated by lacustrine environments in its center during most of the Late Triassic. Orogenic highlands, such as the Yin Mountains in the north and the Qinling Orogen in the south, were the main sediment source areas around the basin (He et al., 2016), gradually forming some fluvial-lacustrine-deltaic sediments, including sandstones, siltstones, mudstones, shales and tuff interlayers, named the Yanchang Formation. The Yanchang Formation can be divided into ten members from top to bottom, namely the Chang 1 to Chang 10 members (Guo et al., 2014; Tang et al., 2014), which records a complete cycle of lake development (Li et al. 2009): initial formation and development stage (Chang 10–Chang 8), peaking stage (Chang 7–Chang 4 + 5) and declining stage (Chang 3–Chang 1) (Fig. 2). The Chang 9, Chang 7 and Chang 4 + 5 are composed predominantly of dark shale and mudstone, and the other intervals of the Yanchang Formation, especially the Chang 8 and Chang 6, are composed of delta plain, delta front and fluvial sandstones and silt sandstone predominantly interbedded with greyish-green mudstones (Zou et al., 2013) (Fig. 2). The Chang 7 can be further divided into three oil reservoirs, the Chang 73 oil reservoir (Chang 73 for short), the Chang 72 oil reservoir (Chang 72 for short) and the Chang 71 oil reservoir (Chang 71 for short). The shales are predominantly located at the bottom of the Chang 73, and the mudstones are mainly located in

3.1. Organic petrography and vitrinite reflectance measurements Polished blocks of about 0.3 cm grains were mounted in densification mixture of hardener. Petrographic analysis was conducted under LEICA CTR 6000 Orthoplan microscope with ×50 oil immersion objectives utilizing immersion oil with a refractive index (ne) of 1.518 at 23 °C. Measurements of mean random RO were obtained using an oil immersion lens and a Leica MPV Compact II reflected-light microscope fitted with a micro-photometer (Zeng et al., 2013). Calibration for the reflectance measurement was done using a sapphire glass standard of 0.589% reflectance value, while DISKUS software was used for capturing (Ayinla et al., 2017). 4

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Table 1 Samples for the analysis of hydrocarbon generation kinetics in the Ordos Basin. Well

Lithology

Depth (m)

TOC (%)

S1 (mg/g)

S2 (mg/g)

HI (mg/g)

RO (%)

Kerogen type

G252 L42 Z87 L32

Shale Shale Mudstone Mudstone

2557.51 2715.45 1986.93 2808.56

10.37 13.92 1.82 6.46

3.78 2.19 1.17 5.38

50.18 64.34 1.84 19.13

483.9 462.2 101.1 296.1

0.73 0.65 0.68 0.65

II1 II1 II2 II2

In order to evaluate the organic geochemical characteristics of source rocks, relevant organic geochemical analyses should be carried out, including determination of TOC content, Rock-Eval pyrolysis, bitumen extraction, and chemical composition of the extracts. Samples were crushed to fine powder (< 150 μm). Firstly, the TOC content was measured after carbonate removal using a LECO CS-400 analyzer. RockEval pyrolysis was performed using a Rock-Eval II instrument (Espitalie et al., 1977; Peters, 1986). The parameters include free and volatile hydrocarbons (S1), which are thermally released from a sample lower than 300 °C; the remaining hydrocarbon generative potential (S2), which arises during progressive heating from 300 °C to 600 °C (Espitalie et al., 1977; Tissot and Welte, 1984), with the temperature of maximum pyrolysis yield being defined as Tmax. HI is the ratio of (S2 × 100)/TOC and petroleum yield (PY) is the ratio of S1/(S1 + S2). Next, the pulverized samples were Soxhlet-extracted using chloroform/methanol (97:3) for 72 h to obtain extractable organic matter (EOM) (Yang et al., 1997). Asphaltenes were precipitated in excess cold pentane and separated by centrifugation. Saturated, aromatic hydrocarbon fractions and NSO compounds were separated by silica gel-alumina chromatography and quantitatively analyzed by a flame ionization detector (Radke et al., 1980; Sabel et al., 2005).

temperature problem related to the fast heating rate, slow heating rates were employed to calculate and model the evolution curves using the KINETICS05 and KMOD programs (Behar et al., 1992; Tegelaar and Noble, 1994; Han et al., 2014). Bulk kinetic parameters (activation energy (Ea) and frequency factor (A)) for hydrocarbon conversion information to kerogen are calculated on the basis of the mathematical routine. Assuming parallel first-order reactions with a single frequency factor and activation energies, different heating rates are used to achieve optimal values. And optimization results best fit calculated curves and measured curves. Simplified kinetic models are commonly applied with a distribution of activation energies (Ea) and single average frequency factor (A), which are not sufficient to correctly predict organic matter transformation in heterogeneous kerogen under geological conditions. Dieckmann (2005) proposed that an average single frequency factor suppresses the initial formation of petroleum at geological heating rates because high activation energies are needed to maintain the kinetic equation at low generation temperatures. Correct activation energies derive from individual frequency factors which keep the activation energies low at low levels of organic matter transformation and result in a more reliable description of the low energy bonds in the heterogeneous organic matter types (Dieckmann, 2005). In this study, four samples with low thermal-maturities were chosen for analysis (Table 1).

3.3. Gas chromatography-mass spectrometry (GC-MS)

3.5. Hydrocarbon expulsion analyses

Saturated hydrocarbons were further analyzed using gas chromatography-mass spectrometry (GC-MS) to examine biomarker geochemistry, which was conducted using an Aglient 5973I instrument interfaced to an HP6890 chromatograph fitted with the same type of column used during GC analysis and using Helium as a carrier gas. The temperature of the oven was programmed to increase from 80 °C to 290 °C at 4 °C/min, followed by an isothermal period of 15 min. Compounds were identified by combined GC-MS using an Agilent GC6890 Plus/ MS5973 network system quadrupole instrument in electron ionization mode (electron energy 70 eV, ion source temperature 230 °C, scanning from 20 to 750 Da at 3 scans/s). The compounds were determined on the basis of their retention time and comparison with literature data (Kitson et al., 1996; Philp, 1985; Peters et al., 2005; Amijaya et al., 2006). The elemental composition (C, H, N and O) of organic matter was measured using a vario-EL analyzer (Hu et al., 2016).

The conceptual model of hydrocarbon generation and expulsion proposed by Pang et al. (2005a,b) was used to establish our hydrocarbon generation and expulsion model. The [(S1 + S2)/TOC] ×100 ratio is used as hydrocarbon generation potential index, which can be employed to estimate the hydrocarbon generation potential. When the index decreases, hydrocarbon expulsion is known to occur (Pang et al., 2005a, b; Hu et al., 2016); the corresponding geological condition is defined as the hydrocarbon expulsion threshold (Zhou and Pang, 2002; Pang et al., 2005a, b; Hu et al., 2016). When no hydrocarbons have been expelled, the index is known as the original hydrocarbon generation potential, which represents the hydrocarbon generation potential of both the source rocks and retained hydrocarbons. After hydrocarbon expulsion has occurred, the hydrocarbon generation potential decreases; this is termed the remaining hydrocarbon generation potential, and it represents the residual hydrocarbon generation potential rather than the original hydrocarbon generation potential.

3.2. Bulk organic geochemical analyses

3.4. Hydrocarbon generation kinetics 3.6. Spatial distribution analyses of shales and mudstones Using an open pyrolysis system at five different heating rates (10, 20, 30, 40 and 50 °C/min), Rock-Eval was employed to characterize the kinetic parameters of organic matter. Then, with a source rock analyzer, hydrocarbon conversion could be characterized. The varying heating rates ensured the mathematical model and the parameter calculation based on equation iteration. The temperature was programmed from 200 to 600 °C. Four ground material aliquots (ranging from 10 to 200 mg according to the above-mentioned heating rates and organic matter richness) of each sample were weighed into small vessels and subsequent pyrolysis. Bulk generated products were carried to the FID by helium gas flow at the constant rate of 50 mL/min. The peak generation temperature shifted via ranging heating rates. To avoid the

Shale and mudstone are commonly identified by high gamma-ray (GR) values (Beers, 1945; Burton et al., 2014). Where analyses have been made, the anomalous GR values have been attributed to uranium, associated with the organic matter (Swanson, 1960). GR data from well logging are used to estimate the volume of argillaceous components (Vsh). For typical wells, the Vsh of the sandstone, shale and mudstone was calculated and a correlation was developed between sandstone, shale and mudstone. Then the lower limit Vsh of shale and mudstone can be ascertained. Based on this lower limit Vsh, the vertical distribution of shale and mudstone in the single well can be established. Compared to the mudstones, the Chang 7 shales are characterized by 5

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0.14%, while those for the mudstones range from 0.59% to 1.09%, with an average of 0.86% and standard deviation of 0.13%. 4.2. Bulk organic geochemical parameters The Chang 7 source rocks were analyzed for the determination of TOC, S1, S2, Tmax, HI and PY (See Tables 4 and 5). The values of Tmax for the shale samples range from 441 °C to 451 °C, with a mean of 447 °C and a standard deviation of 2.4 °C, while those for the mudstones are 437–460 °C, with a mean of 448 °C and a standard deviation of 4.7 °C. The results of the TOC analysis for the shale samples range from 4.66% to 31.11%, with an average of 11.87% and a standard deviation of 6.96%, while those for the mudstone samples are 0.26%–14.58%, with an average of 5.05% and a standard deviation of 3.45%. The values of HI for the shale samples are 157–484 mg HC/g TOC, with an average of 294 mg HC/g TOC, and those for the mudstone samples are 55–377 mg HC/g TOC, with a mean of 193 mg HC/g TOC. The values of hydrocarbon generation potential (S1 + S2) for the shale samples are 10.42–122.52 mg HC/g rock, with a mean of 39.64 mg HC/g rock and a standard deviation of 27.54 mg HC/g rock, while those for the mudstones are 0.37–47.72 mg HC/g rock, with a mean of 13.44 mg HC/g rock and a standard deviation of 10.86 mg HC/g rock. The results of petroleum yield (S1/(S1 + S2)) for the shale samples are 0.03–0.19, with an average of 0.09 and a standard deviation of 0.03, while those for the mudstones are 0.04–0.39, with a mean of 0.20 and a standard deviation of 0.09. The extraction results of the Chang 7 source rocks are shown in Table 5. The values of chloroform bitumen “A” (i.e., the organic matters dissolved in the chloroform, containing the saturated hydrocarbon, aromatic hydrocarbon, asphaltene and resin.) for the shale samples range from 0.24 wt% to 1.56 wt%, with a mean of 0.66 wt% and a standard deviation of 0.41 wt%, while those for the mudstones are 0.02–0.86 wt%, with an average of 0.44 wt% and a standard deviation of 0.29 wt%.

Fig. 3. Frequency histogram of Vsh of the Chang 7 shale-mudstone and non shale-mudstone, Ordos Basin.

high values of GR (> 170 API), Δt (the value of acoustic interval transit time in the well logs) (> 280 μs/m), CNL (compensated neutron logging) (> 27%), and DEN (rock density) (< 2.53 g/cm3) in the well logging (Deng et al., 2013). Then the Chang 7 shales and mudstones can be classified. Then the spatial distribution and thickness of the Chang 7 shales and mudstones can be ascertained, respectively. According to Fig. 3, the amount of shale-mudstone samples, the Vsh of which is greater than 70%, accounts for 89.6%. Meanwhile, with the Vsh is smaller than 70%, the amount of non shale-mudstone samples accounts for 94.9%. The lower limit Vsh of the Chang 7 shales and mudstones is 70%. 4. Results 4.1. Organic petrography and vitrinite reflectance

4.3. Biomarker compounds

Liptinite, vitrinite/huminite and inertrinite are the three basic maceral groups in coal and sedimentary rocks. They display distinguishing characteristics under microscope in terms of color, relief of polished surface, morphology (shape and structure) reflectance and fluorescence (Bertrand, 1989; Teichmuller, 1989; Abdullah, 2003; Sykorova et al., 2005; Hakimi and Abdullah, 2014). In the study area, vitrinite mainly consists of vitrinites with various shapes (Fig. 4a–c). The vitrinites are with no fluorescence under the fluorescent light and are gray under the oil-immersed reflected light (Fig. 4a–c). The inertrinites predominantly consist of fusinites with gray-white color under the oil-immersed reflected light (Fig. 4d). The liptinites mainly contain sporinites, resinites, cutinites, alginites and liptodetrinites with yellow fluorescence under the fluorescent light (Fig. 4e–i). The sporinites are mainly vermicular, and the resinites are mainly ellipitical and lump. The cutinites are mainly strip, and the alginites are mainly cellular and circular. The mineral bituminous groundmass is mainly dispersive with yellow fluorescence color (Fig. 4l). Table 2 has shown the relative contents of the macerals of organic matters. The vitrinite contents of the shales range from 0.9% to 15.0%, with a mean of 5.08%, while those of the mudstones are 0.2%–42.0%, with a mean of 5.63%. The inertrinite contents of the shales are 0.2%–1.9%, with a mean of 0.7%, and those of the mudstones are 0.1%–3.1%, with a mean of 1.1%. The liptinite contents of the shales range from 1.0% to 46.3%, with a mean of 20.28%, and those of the mudstones are 0.7%–18.5%, with an average of 6.67%. The total organic matters (including vitrinite, inertrinite and liptinite) of the shales are 6.4%–47.7%, with a mean of 25.78%, and those of the mudstones range from 2.1% to 59.7%, with an average of 13.24%. The results of vitrinite reflectance (RO %) for the Chang 7 source rocks are show in Table 3. The values for the shale samples are 0.65%–1.15%, with a mean of 0.87% and a standard deviation of

In this study, biomarkers such as normal alkanes (n-alkanes), isoprenoids, terpanes, and steranes are used for determination of paleoenvironment and organic matter source of the Chang 7 source rocks. The GC-MS chromatographic patterns and distributions of n-alkanes, acyclic isoprenoids, tricyclic terpanes, hopanes and steranes were analyzed using total ion chromatograms (TICs), m/z 191 and 217 (Fig. 5) of saturated hydrocarbons. 4.3.1. Acyclic alkanes All n-alkanes, consisting of major intermediate to long chain (C22–C45) n-alkanes and minor short chain (C10–C21) ones, are characterized by similar unimodal distributions (Fig. 5). Odd n-alkanes predominate over even n-alkanes (Fig. 5) with significant relative abundance of n-C15 and n-C17 in the shale samples and n-C17 in the mudstone samples. The values of carbon preference index (CPI; Bray and Evans, 1961) for the shale samples range from 1.02 to 1.09, with a mean of 1.05, while those for the mudstones are 1.02–1.09, with a mean of 1.06 (Table 6). Acyclic isoprenoids pristane (Pr) and phytane (Ph) both occur in relatively high amounts in the shale and mudstone samples (Fig. 5). The values of Pr/Ph ratios range from 0.73 to 1.51 in the shale samples, varying values of Pr/n-C17 (0.15–0.25) and Ph/n-C18 ratios (0.15–0.33) (Table 6). The values of Pr/Ph ratios are 0.54–1.56 in the mudstone samples, with various values of Pr/n-C17 (0.20–0.46) and Ph/n-C18 ratios (0.14–0.58) (Table 6). 4.3.2. Polycyclic terpanes The contents of sesquiterpenoids (eg. drimanes) are relatively high in the shale and mudstone samples (Table 6). The 8β(H)-drimane/ 6

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Fig. 4. Photomicrographs of identified macerals in the Chang 7 source rocks under fluorescent light and oil-immersed reflected light. ((a) Vitrinite, Well Z58, 2424.30 m, shale, oilimmersed reflected light. (b) Vitrinite, Well L57, 2347.00 m, shale, oil-immersed reflected light. (c) Vitrinite, Well Z85, 2209.25 m, mudstone, oil-immersed reflected light. (d) Detrital fusinite, Well X17, 2052.80 m, mudstone, oil-immersed reflected light. (e) Sporinites, Well Z58, 2422.80 m, shale, fluorescent light. (f) Sporinites, layer-like distribution, Well Z74, 2298.60 m, shale, fluorescent light. (g) Alginite, circular, Well M14, 2121.00 m, mudstone, fluorescent light. (h) Cutinite, Well Z74, 2298.60 m, shale, fluorescent light. (i) Alginite, cellular distribution, Well Z37, 2337.00 m, mudstone, fluorescent light. (j) Resinite, Well M13, 2292.70 m, mudstone, oil-immersed reflected light. (k) Alginite and vitrinite, Well L57, 2347.00 m, shale, oil-immersed reflected light. (l) Mineral bituminous groundmass, Well L57, 2352.95 m, mudstone, fluorescent light. V-vtrinite, F-fusinite, Sp-sporinite, Re-resinite, Cutcutinite, Alg-alginite, Mb-mineral bituminous groundmass (= mineral liptinite).) (well location shown in Fig. 1).

trisnorhopane (Tm) in the shale and mudstone samples, resulting in high Ts/Tm ratios. The Ts/Tm ratios of the shale samples range from 1.30 to 5.08, with a mean of 3.34, while those of the mudstone samples are 0.21–13.81, with a mean of 4.89. Gammacerane has been detected in low contents in the shale and mudstone samples. The gammacerane indexes (GI: the ratio of gammacerane to C30-hopane) of the shale and mudstone samples are 0.05–0.22, with a mean of 0.12. The distribution of homohopanes is characterized by a predominance of C31 homohopane, with values of C3122S/(22S + 22R) ratios of 0.36–0.56.

8α(H)-drimane ratios of the shale samples ranges from 0.53 to 1.80, with a mean of 1.21, while those of the mudstone samples are 0.47–1.37, with an average of 0.85 (Table 6). The homodrimane/drimane ratios of the shale samples are 1.02–1.35, with a mean of 1.14, while those of the mudstone samples are 0.93–2.97, with an average of 1.71 (Table 6). Triterpenoids, characterized by major C19–C21 and minor C22–C26 tricyclic terpanes, are present in relatively stable quantities. In addition, C24 tetracyclic terpane was detected in low contents. According to Table 6 and Fig. 5, both the m/z 191 of the shale and mudstone samples mainly show predominance of the C30-hopane. For the shale samples, the contents of C29-norhopane are mainly higher than those of C30-diahopane, resulting in low C30-diahopane/C29-norhopane ratios (avg. = 0.83). However, for the mudstone samples, the contents of C30-diahopane are mainly higher than those of C29-norhopane, with high C30-diahopane/C29-norhopane ratios (avg. = 2.20). 18α(H)-trisnornehopane (Ts) mainly predominates over 17α(H)-

4.3.3. Steroids Steranes, dominated by regular steranes, diasteranes and preganes, are present in low abundances relative to hopanes. The contents of pregame are higher than those of homopregane in the Chang 7 source rocks, resulting in an average pregnane/homopregane ratio of 1.67 for the shale samples and an average of 2.13 for the mudstone samples 7

Journal of Asian Earth Sciences xxx (xxxx) xxx–xxx

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Table 2 Relative content of the macerals of organic matters of the Chang 7 source rock samples, Ordos Basin. Well

G252 G252 L79 C80 L79 Z58 Z58 L57 Z74 L42 B244 N57 Z87 H190 L32 Q19 Z357 L32 X44 X59 M13 M13 M14 M14 L38 L38 L38 Z124 L57 H38 H38 Z85 H89 X17 X17 Z37 Z37

Depth (m)

2557.51 2564.66 2283.00 2453.43 2285.90 2424.30 2422.80 2347.00 2298.60 2715.45 2137.46 1464.13 1986.93 2240.62 2792.60 1327.94 2384.54 2808.56 2034.40 2130.74 2490.70 2492.70 2121.00 2122.20 2326.50 2328.80 2331.00 2313.00 2352.95 2091.62 2317.00 2209.25 2688.70 2052.80 2068.00 2337.00 2240.00

Lithology

Vitrinite (%)

Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone

2.8 15.0 1.4 11.7 5.4 1.1 2.1 5.2 5.2 0.9 3.2 1.5 0.6 2.3 3.0 0.9 1.0 1.6 42.0 1.8 2.7 1.3 7.6 7.3 26.2 5.7 21.8 1.2 1.8 0.6 1.7 3.7 5.0 3.6 0.2 1.3 2.5

Inertrinite (%)

0.4 – – 1.9 – 0.3 0.7 0.2 – 0.7 – 0.7 1.2 3.0 2.0 1.4 – 1.5 0.5 2.6 0.8 0.4 1.5 1.2 0.3 1.1 0.2 0.3 0.7 0.1 – 3.1 1.2 0.4 – 0.3 0.8

∑OM (%)

Liptinite (%) Sp

Cu

Alg

Re

Lip

Total

2.0 1.3 23.6 – – 6.7 20.6 1.0 7.6 – – 2.1 – 5.4 – – – – 4.7 0.5 0.2 – 2.6 3.1 5.3 4.5 4.4 2.7 0.8 – – 0.8 1.7 1.8 0.6 2.6 1.7

– – – – – – 0.7 – 1.2 – – – – – – – – – – – – – 0.1 – 0.8 1.2 – – – – – 0.6 2.5 – – 0.9 –

21.0 4.0 3.2 – – 0.9 0.6 – – 33.3 – – – – – – – – – – – – 0.6 0.7 0.5 0.8 1.7 1.3 – – – – – – – 5.2 –

– 11.5 13.5 – – 0.2 1.8 1.7 1.5 4.5 – – – – – – – 1.3 3.1 1.0 – 0.2 1.7 1.2 2.3 1.4 1.8 – 0.5 – – – 0.8 0.1 – 4.3 1.5

10.5 4.0 7.4 2.5 1.0 5.8 3.5 3.5 3.6 – 0.7 4.0 1.0 2.6 2.8 2.5 1.5 6.2 9.4 3.8 3.9 4.2 6.5 6.7 3.1 4.7 2.6 3.8 1.3 1.4 1.5 3.4 1.6 2.2 6.2 5.5 3.4

33.5 20.8 47.7 2.5 1.0 13.6 27.2 6.2 13.9 37.8 0.7 6.1 1.0 8.0 2.8 2.5 1.5 7.5 17.2 5.3 4.1 4.4 11.5 11.7 12.0 12.6 10.5 7.8 2.6 1.4 1.5 4.8 6.6 4.1 6.8 18.5 6.6

36.7 35.8 47.7 16.1 6.4 15.0 30.0 11.6 19.1 39.4 3.9 8.3 2.8 13.3 7.8 4.8 2.5 10.6 59.7 9.7 7.6 6.1 20.6 20.2 38.5 19.4 32.5 9.3 5.1 2.1 3.2 11.6 12.8 8.1 7.0 20.1 9.9

Minerals (%) M1

M2

52.8 52.6 26.5 75.0 56.6 53.3 52.7 58.2 69.8 35.4 70.4 79.2 61.2 63.5 63.8 74.4 78.5 70.6 8.6 63.6 68.6 74.5 67.7 65.2 33.3 51.1 42.1 70.3 28.9 86.5 80.3 68.1 76.8 65.3 62.5 40.8 43.3

3.5 7.7 11.4 6.4 33.0 4.8 2.1 6.9 3.5 5.9 16.2 4.2 30.2 8.2 9.0 4.8 14.4 6.3 9.0 15.0 13.7 10.6 2.5 5.4 11.4 10.2 12.3 13.3 36.8 7.1 12.7 8.4 8.3 17.2 22.9 8.7 6.5

∑M (%)

Bitumen (%)

56.3 60.3 37.9 81.4 89.6 58.1 54.8 65.1 73.3 41.3 86.6 83.4 91.4 71.7 72.8 79.2 92.9 76.9 17.6 78.6 82.3 85.1 70.2 70.6 44.7 61.3 54.4 83.6 65.7 93.6 93.0 76.5 85.1 82.5 85.4 49.5 49.8

7.0 3.9 13.0 2.5 4.0 26.9 15.2 23.3 7.6 19.3 9.5 8.3 5.8 15.0 19.4 16.0 4.6 12.5 22.7 11.7 10.1 8.8 9.2 9.2 16.8 19.3 13.1 7.1 29.2 4.3 3.8 11.9 2.1 9.4 7.6 30.4 40.3

Sp = Sporinite; Cut = Cutinite; Alg = Alginite; Re = Resinite; Lip = liptodetrinite; ∑OM = Total organic matter; M1 = Minerals with fluorescence; M2 = Minerals with no fluorescence; ∑M = Total minerals; – = no data.

Table 3 Vitrinite reflectance (RO %) data of the Chang 7 source rock samples, Ordos Basin. Well

Depth (m)

Lithology

Measuring points

Standard deviation (%)

Ro (%)

Well

Depth (m)

Lithology

Measuring points

Standard deviation (%)

Ro (%)

A84 B246 B246 C96 G252 G252 G252 H62 L51 L57 L57 L42 L79 M14 Z37 Z46 Z50 B244 C91 D49 G8 G8 G8 G8

2258.46 2223.00 2240.30 2618.70 2557.51 2564.66 2572.13 2655.50 2267.50 2349.50 2352.95 2715.45 2285.69 2124.40 2238.20 1851.70 1943.00 2137.46 2059.60 1535.12 2619.50 2618.80 2621.10 2695.00

Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone

30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30

0.10 0.13 0.11 0.08 0.11 0.13 0.12 0.07 0.09 0.10 0.07 0.10 0.10 0.08 0.09 0.09 0.09 0.06 0.10 0.09 0.07 0.10 0.11 0.07

0.79 0.82 0.85 0.87 0.73 0.78 0.80 1.15 0.96 1.02 1.05 0.65 0.89 0.83 1.09 0.75 0.68 0.59 0.92 0.85 0.86 0.87 0.95 0.96

G8 H190 H60 L32 L32 L79 L55 L57 L57 N57 Q19 T166 X44 X44 X59 Z19 Z33 Z357 Z37 Z39 Z43 Z44 Z53 Z87

2680.00 2240.62 2787.50 2808.56 2792.60 2212.54 2352.00 2346.00 2333.45 1464.13 1327.94 1982.20 2034.40 2033.80 2130.74 2015.60 2213.60 2384.54 2242.90 2287.50 2215.60 2566.10 2096.30 1986.93

Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone

30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30

0.10 0.08 0.06 0.10 0.08 0.10 0.11 0.08 0.08 0.08 0.10 0.09 0.09 0.08 0.10 0.09 0.09 0.10 0.10 0.08 0.10 0.09 0.10 0.11

0.97 0.77 1.08 0.78 0.76 0.82 0.82 0.84 0.88 0.70 0.63 1.02 0.66 1.09 0.79 0.87 0.98 0.79 1.03 0.90 0.99 1.00 0.91 0.68

8

Journal of Asian Earth Sciences xxx (xxxx) xxx–xxx

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Table 4 Rock-Eval pyrolysis data of the Chang 7 source rock samples, Ordos Basin. Well

Depth (m)

Lithology

TOC (Wt. %)

S1 (mg/g)

S2 (mg/g)

Tmax (°C)

HI (mg/g)

S1 + S2 (mg/g)

G196 G196 L42 A84 A84 A84 C96 C96 C96 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 G252 L42 L79 L79 L79 L79 L79 L79 L79 G196 G196 G196 L79 A77 A77 A84 A84 B135 B135 B244 B244 B244 B244 B488 B488 G196 G196 G196 G196 G196 G196 G196 G196 G196 G190 G190 G190 G190 G191 G191 G191 G191 G191 G191 H97 H41 H51 H51

2662.50 2683.50 2716.85 2257.56 2256.65 2258.46 2618.70 2619.04 2617.00 2555.08 2555.80 2559.12 2558.77 2569.15 2567.87 2572.13 2557.51 2566.10 2561.34 2570.45 2556.62 2569.95 2560.41 2562.06 2564.66 2563.80 2562.70 2715.45 2213.88 2212.54 2285.69 2285.90 2284.82 2283.62 2283.00 2656.50 2677.50 2680.50 2213.17 2386.78 2387.38 2252.13 2254.55 2024.13 2024.63 2135.02 2136.65 2137.46 2138.14 1891.81 1893.75 2597.00 2617.50 2620.50 2634.00 2639.00 2641.50 2653.50 2671.50 2674.50 2240.62 2242.32 2243.15 2243.40 2142.03 2142.88 2144.08 2145.56 2148.25 2149.71 2587.73 2593.84 2895.21 2895.88

Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone

14.50 13.73 4.88 6.49 6.98 7.41 4.71 5.58 7.60 5.54 6.60 6.92 8.55 8.88 9.75 10.51 10.37 10.90 11.47 12.90 13.16 13.97 14.01 17.07 22.08 29.81 31.11 13.92 4.66 5.07 7.63 7.96 15.83 24.39 28.11 9.20 8.59 10.07 3.34 0.75 2.44 4.04 3.67 11.89 12.92 4.05 6.10 5.04 8.44 8.21 6.26 1.26 2.15 2.98 2.51 4.35 4.89 6.84 7.88 8.04 4.83 5.94 3.28 2.07 1.21 0.73 0.64 2.24 2.36 3.96 5.33 10.89 4.18 5.67

3.24 1.70 1.86 1.32 1.30 1.79 2.48 1.89 3.11 2.57 2.64 1.84 3.01 2.68 2.98 3.69 3.78 3.39 3.59 4.06 3.72 3.76 4.36 4.38 4.92 5.75 7.41 2.19 1.39 1.24 1.39 1.79 3.38 4.38 5.64 3.80 1.24 1.30 2.46 0.20 0.68 1.18 1.23 1.57 2.30 0.74 2.15 1.95 1.62 2.03 1.81 0.14 1.40 2.56 1.83 3.10 3.06 3.79 1.24 1.18 2.53 2.63 2.03 1.43 0.33 0.17 0.28 0.98 1.08 1.97 5.14 3.24 2.64 2.81

27.88 28.42 11.92 18.21 18.98 24.80 10.49 10.27 20.55 21.06 19.23 17.52 32.45 36.81 37.10 34.10 50.18 38.13 34.98 38.95 43.80 44.79 55.93 50.12 86.64 110.11 115.11 64.34 9.03 9.99 11.99 16.95 43.94 61.38 77.74 16.25 19.45 21.83 20.68 0.80 2.96 10.95 8.81 34.96 39.90 6.13 8.77 9.79 13.23 19.44 12.10 0.69 3.13 4.82 3.72 5.88 6.98 9.82 12.14 15.47 15.16 16.23 8.62 5.65 1.01 0.67 0.65 5.95 4.06 6.28 10.18 25.86 7.32 11.35

446 448 448 448 451 450 445 449 442 446 441 448 447 450 449 450 450 448 447 447 448 448 451 449 449 448 451 446 442 446 448 449 448 446 444 447 449 449 443 447 442 450 448 448 441 452 449 449 449 446 447 448 449 446 440 446 443 443 446 448 448 448 447 451 447 447 447 448 450 447 451 448 439 443

192 207 244 281 272 335 223 184 270 380 291 253 380 415 381 324 484 350 305 302 333 321 399 294 392 369 370 462 194 197 157 213 278 252 277 177 184 217 253 107 121 271 240 294 309 151 144 151 157 237 193 55 146 162 148 135 143 144 154 192 314 273 263 273 83 92 102 266 172 159 191 237 175 200

31.12 30.12 13.78 19.53 20.28 26.59 12.97 12.16 23.66 23.63 21.87 19.36 35.46 39.49 40.08 37.79 53.96 41.52 38.57 43.01 47.52 48.55 60.29 54.50 91.56 115.86 122.52 66.53 10.42 11.23 13.38 18.74 47.32 65.76 83.38 20.05 20.69 23.13 23.14 1.00 3.64 12.13 10.04 36.53 42.20 6.87 10.92 11.74 14.85 21.47 13.91 0.83 4.53 7.38 5.55 8.98 10.04 13.61 13.38 16.65 17.69 18.86 10.65 7.08 1.34 0.84 0.93 6.93 5.14 8.25 15.32 29.10 9.96 14.16

9

PY

0.10 0.06 0.13 0.07 0.06 0.07 0.19 0.16 0.13 0.11 0.12 0.10 0.08 0.07 0.07 0.10 0.07 0.08 0.09 0.09 0.08 0.08 0.07 0.08 0.05 0.05 0.06 0.03 0.13 0.11 0.10 0.10 0.07 0.07 0.07 0.19 0.06 0.06 0.11 0.20 0.19 0.10 0.12 0.04 0.05 0.11 0.20 0.17 0.11 0.09 0.13 0.17 0.31 0.35 0.33 0.35 0.30 0.28 0.09 0.07 0.14 0.14 0.19 0.20 0.25 0.20 0.30 0.14 0.21 0.24 0.34 0.11 0.27 0.20 (continued on next page)

Journal of Asian Earth Sciences xxx (xxxx) xxx–xxx

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Table 4 (continued) Well

Depth (m)

Lithology

TOC (Wt. %)

S1 (mg/g)

S2 (mg/g)

Tmax (°C)

HI (mg/g)

S1 + S2 (mg/g)

PY

L132 L132 L132 L132 L132 L132 L132 L221 L221 L221 L221 L221 L32 L32 L32 L32 L32 L32 L32 L32 L32 L32 L42 T2 X44 X44 X98 X59 X59 X59 X61 Y424 Z357 Z357 Z64 Z64 Z87 Z87 Z87

2201.96 2203.30 2204.52 2245.11 2246.41 2247.52 2249.30 2681.70 2682.31 2683.71 2684.24 2687.38 2789.54 2790.77 2791.55 2792.60 2808.56 2809.85 2812.52 2824.77 2826.05 2827.54 2721.10 1690.64 2036.29 2037.00 2120.36 2123.68 2129.74 2130.74 1862.40 2097.80 2384.54 2414.95 1648.26 1649.26 1985.49 1986.24 1986.93

Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone

11.30 7.38 5.30 14.58 11.44 6.97 2.80 4.75 2.31 5.75 5.58 4.40 6.65 11.39 6.01 14.41 6.46 3.82 3.05 2.44 2.81 5.78 1.17 3.49 4.05 5.22 14.18 6.36 4.14 4.76 2.99 0.26 1.06 5.57 2.01 1.56 1.74 1.91 1.82

5.11 4.55 4.06 3.33 2.09 1.94 0.97 1.56 1.13 2.13 2.14 2.59 4.20 5.23 4.67 6.65 5.38 3.20 2.39 2.24 2.71 5.25 0.25 1.22 1.65 1.17 3.21 1.17 2.16 2.34 0.49 0.13 0.33 0.72 0.32 0.44 0.53 0.75 1.17

29.11 13.66 9.57 33.72 25.37 16.90 5.28 5.24 2.30 6.63 10.00 8.34 18.08 31.45 14.81 41.07 19.13 7.48 6.45 4.00 5.32 16.28 1.03 4.76 15.10 15.81 33.65 23.99 12.00 14.30 2.49 0.24 1.07 17.01 3.70 1.16 1.18 1.61 1.84

447 446 450 445 444 446 449 459 460 456 453 449 447 448 437 448 449 442 449 446 443 446 450 453 446 446 445 453 449 454 454 457 448 451 450 459 460 455 459

258 185 181 231 222 242 189 110 100 115 179 190 272 276 246 285 296 196 211 164 189 282 88 136 373 303 237 377 290 260 83 92 101 305 184 74 68 84 101

34.22 18.21 13.63 37.05 27.46 18.84 6.25 6.80 3.43 8.76 12.14 10.93 22.28 36.68 19.48 47.72 24.51 10.68 8.84 6.24 8.03 21.53 1.28 5.98 16.75 16.98 36.86 25.16 14.16 16.64 2.98 0.37 1.40 17.73 4.02 1.60 1.71 2.36 3.01

0.15 0.25 0.30 0.09 0.08 0.10 0.16 0.23 0.33 0.24 0.18 0.24 0.19 0.14 0.24 0.14 0.22 0.30 0.27 0.36 0.34 0.24 0.20 0.20 0.10 0.07 0.09 0.05 0.15 0.14 0.16 0.35 0.24 0.04 0.08 0.28 0.31 0.32 0.39

TOC = total organic carbon (Wt.%); S1 = free hydrocarbons (mg HC/g rock); S2 = pyrolytic hydrocarbon yield (mg HC/g rock); Tmax = temperature with maximum hydrocarbon generation; HI = hydrogen index; S1 + S2 = production index (mg HC/g rock); PY = production yield (S1/(S1 + S2)).

Burnham et al. (1988). Samples with low heating rates generated at relatively low temperatures. Subsequently, the samples with higher heating rates began to generate at higher temperatures. The mudstones from Well Z87 are characterized by relatively high CHGR (up to 30%) at low temperature (< 400 °C), and the dominant temperatures (400–475 °C) account for 52% of the cumulative hydrocarbon generation. The peak generation rate is relatively low (about 1.8 × 10−3 mg/g s) (Fig. 7a and b). However, for the Chang 7 shales of Well L42, they are characterized by low CHGR (being 10%) at low temperature (< 400 °C), and the dominant temperatures (400–475 °C) account for 87% of the cumulative hydrocarbon generation. The peak generation rate is high (up to 8.0 × 10−3 mg/g s) (Fig. 7g–h). The dominant CHGRs and peak generation rates of the Well L32 mudstones and Well G252 shales are between those of the Well Z87 mudstones and Well L42 shales, and the dominant CHGRs and peak generation rates of the Well G252 shales are higher than those of the Well L32 mudstones (Fig. 7).

(Table 6; Fig. 5). Among the regular steranes, C27 sterane is generally greater than C29 and C28 steranes, whereas C29 sterane is subequal to or slightly greater than C28 sterane in quantities, with values of C27/C29 steranes ratios of 1.20–2.82. The C27, C28 and C29 regular steranes of the Chang 7 source rocks mainly show V- or L-shaped patterns on the m/z 217 mass chromatograms (Fig. 5). The C2920S/(20S + 20R) ratios of the Chang 7 source rocks range from 0.35 to 0.44, with an average of 0.40. 4.4. Hydrocarbon generation kinetics The kinetic parameters have been calculated, which utilize different levels of organic matter transformation ranging from CHGR (cumulative hydrocarbon generation ratio) 1% to CHGR 95%. Such an approach should result in individual pairs of Ea and A with a relationship of oneto-one correspondence (Table 7), which describe petroleum forming reactions at any level during source rock transformation. The experimental and measured data of Ea, CHGR, and HI are displayed in Tables 7, 8 and Fig. 6. The temperatures vs. hydrocarbon generation at different CHGR levels were measured by simulating bulk petroleum formation at five different heating rates (10, 20, 30, 40 and 50 °C/min). The hydrocarbon formation curves are shown in Fig. 7. In each diagram, it can be seen that the hydrocarbon generation curves shift to lower temperatures with decreasing rate of heating, which is a major prerequisite for the application of kinetic concepts. Each transformation level was then treated individually by applying the Tmax-shift concept discussed by

4.5. Thickness and distribution of source rocks Based on the lower limit Vsh (Vsh > 70%) and the characters of shales in the well logs (Deng et al., 2013), the thickness of the Chang 7 shales and mudstones can be obtained, respectively (Fig. 8). The Chang 7 shales are predominantly developed with a maximum cumulative thickness being up to 36.5 m (Fig. 9). The maximum cumulative thickness of the Chang 7 mudstones is up to 60 m, with a mean of 25 m (Fig. 9). Stratigraphically, the Chang 7 shales predominantly locate at the bottom of Chang 73. The depositional center of the Chang 7 shales 10

Journal of Asian Earth Sciences xxx (xxxx) xxx–xxx

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Table 5 Chloroform bitumen “A”and TOC data of the Chang 7 source rock samples, Ordos Basin. Well

Depth (m)

Lithology

TOC (wt. %)

Cl-B “A” (wt. %)

Well

Depth (m)

Lithology

TOC (wt. %)

Cl-B “A” (wt. %)

A84 A84 B246 B246 B246 B246 B246 G252 G252 G252 M14 M14 Z46 Z46 Z46 Z46 Z50 G196 G196 L42 L79 B244 D49 D49 D49 D49 D49 G196 G196 H190 H60

2256.65 2258.46 2223.00 2227.20 2229.80 2231.80 2240.30 2557.51 2562.06 2570.45 2120.80 2124.40 1848.80 1849.80 1850.30 1851.70 1943.00 2659.50 2677.50 2715.45 2213.17 2137.46 1533.20 1534.11 1535.12 1535.73 1537.12 2597.00 2641.50 2240.62 2751.20

Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone

5.18 6.21 26.69 8.14 11.60 7.94 7.34 10.37 13.69 10.59 4.44 10.98 5.81 5.19 4.30 5.65 24.68 13.85 8.59 13.92 3.34 5.04 3.24 3.37 3.07 3.12 4.54 1.74 4.57 4.32 1.18

0.52 0.62 1.44 0.50 0.56 0.41 0.56 0.89 1.23 1.10 0.45 0.59 0.25 0.24 0.24 0.25 1.56 1.08 0.47 0.83 0.51 0.42 0.62 0.69 0.67 0.63 0.69 0.09 0.86 0.81 0.10

H60 H60 H60 H60 H60 H62 H62 H63 H63 H63 H63 H65 L38 L38 L51 L68 L68 L68 L221 N57 W8 W25 W25 W25 X44 X59 Z357 Z58 Z58 Z58 Z87

2753.30 2754.00 2783.20 2784.40 2787.50 2541.48 2591.59 2386.00 2387.80 2390.00 2392.00 2250.50 2311.00 2326.50 2267.30 1970.05 1970.90 1998.40 2684.24 1464.13 579.08 2030.50 2032.40 2036.50 2034.40 2130.74 2384.54 2422.80 2426.80 2429.40 1986.93

Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone

1.10 1.22 0.80 0.74 0.85 1.18 2.68 3.32 2.95 4.83 4.01 3.27 3.99 4.34 13.22 1.08 5.29 7.80 5.62 1.46 2.56 8.14 7.51 4.66 25.49 4.76 0.93 1.44 6.37 10.43 1.82

0.08 0.07 0.02 0.02 0.02 0.06 0.35 0.47 0.52 0.74 0.78 0.72 0.66 0.48 0.66 0.23 0.70 0.41 0.30 0.25 0.32 0.56 0.61 0.85 2.23 0.84 0.08 0.06 0.69 0.80 0.18

TOC = total organic carbon (wt. %); Cl-B “A” = chloroform bitumen “A” (wt. %).

with the previous research made by Zhang et al. (2006), Hanson et al. (2007), and Han et al. (2014).

located in the south of Jiyuan and the east of Heshui, while the center of the Chang 7 mudstones located in the south of Jiyuan, the south of Huachi, the west of Fuxian and the east of Zhengning (Fig. 9).

5.1.2. Petroleum potential According to the TOC and Rock-Eval data related to the Chang 7 source rocks have been summarized in Tables 4, 5 and Fig. 11, the quantity of organic matter in the Chang 7 shales is larger than that in the Chang 7 mudstones. Based on the evolution criteria of source rocks proposed by Peters and Cassa (1994) and Tissot and Welte (1984), the Chang 7 shales are consistent with very good to excellent source rock potential, while the Chang 7 mudstones correspond to fair to excellent source rock potential. The results are consistent with the more lipitinite contents and total organic matters in the shales (Table 2). In summary, the Chang 7 source rocks mainly hold the very good to excellent source rock potential.

5. Discussion 5.1. Bulk organic geochemical characters 5.1.1. Thermal maturity Thermal maturity of organic matter in sediments is determined by creation process of hydrocarbons through undergoing a series of physical or/and chemical changes by different agents such as heat, pressure, subsidence and time after deposition (Zeng et al., 2011). Combining organic petrography results, vitrinite reflectance (RO, %), Tmax (°C), the ratio of chloroform bitumen “A” to TOC and certain biomarker parameters, source rock thermal-maturity can be inferred reliably (Tissot and Welte, 1984; Bordenave et al., 1993; Peters et al., 2005). According to Table 3, the Chang 7 source rocks have entered the mature stage, with a Ro range of 0.59–1.15% (avg. = 0.87%). The general distribution of the RO values and chloroform bitumen “A”/TOC ratios as shown in Fig. 10 indicate that the mature shales and mudstones correspond to the “oil window”. This interpretation is supported by the Tmax data which are 441–451 °C for the Chang 7 shales with a mean of 447 °C and ranging from 437 °C to 460 °C, the Chang 7 mudstones have a mean of 448 °C (Table 4; Fig. 12). The mean value of the Carbon Preference Index (CPI) of the Chang 7 shales is 1.05 for average and that of the Chang 7 mudstones is 1.06 for average (Table 6). All the data, from the RO, Tmax, CPI and the ratio of chloroform bitumen “A” to TOC, have indicated that the organic matters of the Chang 7 source rocks have entered the mature stage of hydrocarbon generation (Table 3; Fig. 10; Fig. 12). The Chang 7 source rocks have entered the “oil window” at the depth of 1800 m and reached the hydrocarbon generation peak at the depth of 2450 m (Fig. 10), which is consistent

5.1.3. Organic matter type Since the property, composition and quantity of hydrocarbon generation are controlled by organic matter type (Tissot and Welte, 1984), it is significant to determine the type of kerogen in potential source rocks. Type I and II1 kerogens, commonly derived from lacustrine and marine organic matters and their corresponding source rocks, are capable to generate liquid hydrocarbons. Primary biogenic organic matters usually forming Type II2 and III kerogens are mainly composed of woody materials and they are more susceptible to generate gas (Peters and Cassa, 1994). In this study, the kerogen classification diagrams were constructed utilizing HI versus Tmax based on earlier works given by Mukhopadhyay et al. (1995) and Hakimi et al. (2011). The pyrolysis data (HI vs. Tmax) (Fig. 12) suggested that the Chang 7 shales are predominantly plotted in the mature zone of mixed Type I–II1 kerogens, and the Chang 7 mudstones are mainly plotted in the mature zone of mixed Type II1–II2 kerogens. The results are consistent with the organic petrographic 11

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Fig. 5. Total ion chromatogram (TIC), terpane, and sterane mass chromatograms of the Chang 7 source rocks in the Ordos Basin.

In summary, based on the comprehensive analyses of thermal-maturity, petroleum potential and organic matter type, the Chang 7 source rocks have an excellent source rock potential, indicating that it is favorable for generating oils, and the shales have a better potential than

characteristics that the shales hold more liptinites than the mudstones (Table 2). In summary, the kerogen types of the Chang 7 source rocks mainly belong to Type I–II2, indicating a good hydrocarbon generation potential. 12

13

Shale Shale Shale Shale Shale Shale Shale Shale Shale Shale Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone Mudstone

G196 G196 A84 A84 G252 G252 G252 G252 L79 L42 L79 L221 B244 G196 N57 G196 H190 L32 Z357 L32 X59 Z87 X44

2659.50 2677.50 2256.65 2258.46 2557.51 2562.06 2564.66 2570.45 2283.00 2715.45 2213.17 2684.24 2137.46 2597.00 1464.13 2641.50 2240.62 2792.60 2384.54 2808.56 2130.74 1986.93 2034.40

Depth (m)

C15 C15 C17 C17 C15 C15 C15 C15 C15 C17 C15 C17 C17 C19 C19 C17 C21 C17 C21 C17 C17 C17 C17

Maximumpeaks

1.05 1.03 1.04 1.02 1.07 1.09 1.07 1.06 1.03 1.02 1.05 1.04 1.05 1.06 1.08 1.09 1.02 1.03 1.09 1.08 1.06 1.08 1.07

CPI

0.73 1.20 1.51 1.46 1.11 1.13 1.14 1.11 1.15 0.98 0.76 0.67 1.15 1.08 0.76 0.54 0.97 0.93 1.00 0.99 1.56 0.97 1.36

Pr/Ph

TIC (n-alkanes and isoprenoids)

0.20 0.25 0.25 0.25 0.20 0.18 0.18 0.25 0.15 0.22 0.36 0.26 0.22 0.38 0.36 0.30 0.46 0.30 0.41 0.27 0.22 0.32 0.20

Pr/n-C17

0.33 0.24 0.17 0.18 0.20 0.18 0.17 0.24 0.15 0.25 0.54 0.43 0.21 0.35 0.45 0.58 0.44 0.34 0.41 0.28 0.14 0.34 0.17

Ph/n-C18

1.31 1.65 0.53 0.56 1.36 1.33 1.19 1.12 1.80 1.21 0.85 0.67 0.73 1.04 0.77 1.00 0.47 0.84 0.86 0.66 0.49 1.30 1.37

A

1.02 1.06 1.35 1.20 1.06 1.13 1.18 1.17 1.07 1.17 1.34 0.93 1.16 2.74 2.54 1.50 1.72 1.07 2.70 1.20 1.38 0.98 2.97

B

m/z 123 (Sesqui-terpenoids)

4.55 1.30 5.08 4.91 2.53 2.79 3.52 3.66 2.65 2.36 4.72 – 0.21 0.63 4.16 13.81 7.63 4.86 2.55 6.74 7.69 – 0.66

Ts/Tm

1.14 0.57 1.92 1.98 0.31 0.30 0.46 0.50 0.54 0.56 1.52 7.47 3.04 0.42 0.93 3.16 2.07 0.76 0.86 1.85 3.41 2.91 0.22

C

m/z 191 (Hopanes)

0.14 0.14 0.15 0.14 0.05 0.05 0.06 0.07 0.11 0.09 0.14 – 0.15 0.12 0.10 – 0.17 0.07 0.22 0.12 0.20 – 0.07

GI

1.84 1.72 1.56 1.56 1.59 1.67 1.69 1.63 1.67 1.81 1.79 2.32 2.37 2.24 2.04 2.20 2.19 1.76 1.98 2.12 2.19 2.78 1.76

E

0.43 0.54 0.51 0.50 0.55 0.55 0.54 0.54 0.49 0.53 0.51 – 0.43 0.56 0.54 0.36 0.52 0.50 0.53 0.48 0.46 – 0.56

F

39.38 41.77 51.63 50.96 42.46 43.46 46.96 46.97 41.09 49.29 44.66 47.10 44.65 46.97 48.41 44.61 63.35 49.00 61.06 57.42 59.71 46.69 39.78

C27

27.88 23.79 19.97 20.29 23.50 23.00 24.31 23.02 28.27 23.98 25.61 23.82 25.00 19.86 26.76 23.33 14.15 19.46 15.63 17.25 16.73 26.67 27.04

C28

Regular steranes (%)

m/z 217 (Steranes)

32.74 34.44 28.40 28.75 34.04 33.54 28.73 30.01 30.64 26.72 29.74 29.08 30.35 33.17 24.83 32.06 22.50 31.54 23.30 25.33 23.56 26.65 33.17

C29 1.20 1.21 1.82 1.77 1.25 1.30 1.63 1.57 1.34 1.84 1.50 1.62 1.47 1.42 1.95 1.39 2.82 1.55 2.62 2.27 2.53 1.75 1.20

C27/C29

0.39 0.42 0.40 0.41 0.39 0.39 0.40 0.39 0.42 0.43 0.39 0.35 0.38 0.42 0.43 0.40 0.41 0.38 0.44 0.38 0.42 0.42 0.36

G

A: 8β(H)-drimane/8α(H)-drimane. B: Homodrimane/Drimane. C: C30-diahopane/C29-norhopane. GI: Gammacerane/C30-hopane. E: Pregnane/Homopregane. F: C3122S/(22S + 22R) G: C2920S/(20S + 20R). CPI: Carbon preference index Pr: Pristane. Ph: Phytane. Ts: C27 18α(H)-trisnornehopane. Tm: C27 17α(H)-trisnorhopane.

Lithology

Well

Table 6 Biomarker ratios based on TIC, m/z 123, 191 and 217 mass chromatograms for the Chang 7 source rock samples, Ordos Basin.

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Table 7 Distribution of activiation energies (Ea) and frequency factors (A) calculated from different CHGRs. CHGR

1% 10% 20% 30% 40% 50% 60% 70% 80% 90% 95%

Z87

L32

G252

L42

Ea (kJ/mol)

A (1/s)

Ea (kJ/mol)

A (1/s)

Ea (kJ/mol)

A (1/s)

Ea (kJ/mol)

A (1/s)

111.63 195.67 285.34 290.81 295.46 307.02 329.05 375.96 547.03 790.73 –

5.23 × 108 9.46 × 1012 9.83 × 1018 1.28 × 1019 2.29 × 1019 6.52 × 1019 9.46 × 1020 9.48 × 1023 1.22 × 1037 1.19 × 1036 –

118.65 164.05 242.65 248.81 251.18 252.89 255.70 258.61 262.20 314.37 463.86

5.62 × 108 1.98 × 1011 1.88 × 1016 2.74 × 1016 3.63 × 1016 6.47 × 1016 5.49 × 1016 1.67 × 1017 2.90 × 1017 1.78 × 1020 4.58 × 1029

157.47 215.27 217.14 219.59 221.11 222.53 224.52 233.95 247.00 266.27 299.57

2.12 × 1011 6.42 × 1013 7.20 × 1013 1.35 × 1014 2.15 × 1014 2.99 × 1014 4.03 × 1014 1.79 × 1015 2.44 × 1016 4.28 × 1017 4.05 × 1018

229.06 232.10 233.62 236.65 239.25 241.91 247.06 252.94 266.08 290.03 322.17

5.83 × 1014 1.11 × 1015 1.21 × 1015 3.72 × 1015 5.56 × 1015 8.73 × 1015 2.32 × 1016 6.87 × 1016 7.13 × 1017 2.60 × 1018 1.06 × 1022

CHGR = Cumulative hydrocarbon generation ratio (%); – = no data. Table 8 Range of activiation energies (Ea) and dominant distribution of Ea and its corresponding to ratio of generated amounts to cumulative generation amounts and HI, Chang 7 source rocks, Ordos Basin. Well

Layer

G252 L42 L32 Z87

Chang Chang Chang Chang

Lithology

7 7 7 7

Shale Shale Mudstone Mudstone

Ea (kJ/mol)

Dominant distribution of Ea

Range

Average

Range (kJ/mol)

Ratio (%)

HI (mg HC/g TOC)

157.47–299.57 229.06–322.17 118.65–463.68 111.63–790.73

218.00 235.00 237.00 292.00

210.00–235.00 230.00–255.00 240.00–285.00 275.00–350.00

67.80 70.26 68.09 50.28

328.11 324.52 201.55 50.79

Ea: Activation energies (kJ/mol); Ratio: Ratio of generated amounts to cumulative generation amount (%).

Fig. 6. The histograms of Ea vs. HI and Ea vs. hydrocarbon generation ratio and curves of Ea vs. cumulative CHGR of the Chang 7 source rocks, Ordos Basin.

the mudstones.

proposed by Didyk et al. (1978), has been widely utilized in many studies to infer oxicity or anoxicity of depositional environments and source of organic matter. High Pr/Ph ratios (> 2) are usually associated with oxic depositional environments, however, low Pr/Ph ratios (< 0.5) indicate anoxic depositional conditions and usually hypersaline environments. The Pr/Ph ratios being 0.5–1.0 indicate reducing

5.2. Paleoenvironments and organic matter source 5.2.1. Redox conditions of paleoenvironment Pr/Ph ratio, an indicator of redox potential of source sediments 14

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Fig. 7. Cumulative hydrocarbon generation vs. temperature curves (left) and hydrocarbon generation rate vs. temperature curves (right) for Chang 7 source rocks illustrating the shift of the respective transformation levels to higher temperature with increasing rate or heating (10, 20, 30, 40, and 50 °C/min).

rocks. Pr/nC17 ratios being lower than 0.5 indicate the open depositional environments, while Pr/nC17 ratios being higher than 1.0 reflect the swamp environment. And the Pr/nC17 ratios being 0.5–1.0 indicate the transitional environments (Didyk et al., 1978). Although affected by biodegradation and maturity (ten Haven et al., 1987), some authors debated that the Pr/n-C17 vs. Ph/n-C18 alkanes ratios of deposited organic matter are also associated with environmental conditions (Amijaya et al., 2006; Sarki Yandoka et al., 2015; Zakir Hossain et al., 2009). The pristane and phytane will be larger than nC17 and nC18, respectively, when the samples have experienced some degree of

depositional conditions, and the values of Pr/Ph ratios being 1.0–2.0 indicate sub-reducing to sub-oxidizing conditions (Peters and Moldowan, 1991; Zhang et al., 2008). Although influenced by organic matter types (see Section 5.2.3), the Pr/Ph ratios (0.54–1.56) for the Chang 7 source rocks are preliminarily indicative of reducing to suboxidizing environments. This is consistent with similar redox environments inferred from the trace elements (Mo, V, Ni, Cu, U, Th, Sr, Ba etc.) and rare earth elements (La, Ce, Pr, Nd, Sm, Eu, Gd etc.) (Zhang et al., 2008). In addition, the cross plots of Pr/Ph vs. regular steranes C27/C29 ratios also show that environmental conditions were sub-reducing to sub-oxidizing during the deposition of the Chang 7 source 15

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Fig. 8. Calculated thickness of the Chang 7 shales and mudstones by well logging data, Ordos Basin.

predominance of a low salinity level in the Ordos Lake during the Chang 7 deposition is confirmed by low gammacerane contents and GI values from the Chang 7 source rocks (Table 6; Fig. 5). The GI ratios of the Chang 7 shales range from 0.05 to 0.15, with a mean of 0.10, while the GI ratios of the Chang 7 mudstones are 0.07–0.22, with a mean of 0.14, indicating that the paleoenvironment of the Chang 7 source rocks were fresh- to brackish-water depositional environments (Table 6). However, relatively high gammacerane abundances are also seen in freshwater lacustrine sediments, and Sinninghe Damsté et al. (1995) thus proposed that gammacerane index is in fact an indicator for water column stratification. A low level of salinity in water column may be unfavorable to maintain long-standing stratification during the Chang 7 deposition. In most modern tropic lakes, the water stratification induced by temperature rather than salinity is prone to experiencing semi-annual and/or annual overturn (Katz, 1990; Walker, 2011). Therefore, the episodic holomixis maybe result in sub-oxidizing conditions in the Ordos Lake to support bottom-dwelling activities during the late Chang 7 deposition. The maximum depth of water column in the paleo-Ordos Lake is unclear, but it can reach up to dozens of meters based on the extent of deposited shales. It is argued that the water depth for deposition of shales (micro-laminated sediments) is greater than storm wave base

biodegradation (Peters and Moldowan, 1991). The lower carbons of nalkanes of the Chang 7 source rocks are preserved completely and the Pr/nC17 ratios and Ph/nC18 ratios are smaller than 1.0, indicating that the shales and mudstones have not experienced strong biodegradation (Fig. 13a). Thus, according to the plots of Pr/nC17 vs. Ph/nC18 and Pr/ Ph vs. C27/C29, the paleoenvironments of the Chang 7 source rocks relate to sub-reducing to sub-oxidizing conditions (Fig. 13). Besides, Zhang et al. (2009) and Zhao and Zhang (2001) proposed that C30-diahopane is generated easily by arranging through catalysis of acid clay in oxidation to sub-oxidation environment. The ratios of C30diahopane/C29-norhopane indicate that the reducing degree of the paleoenvironments of the shales was stronger than that of the mudstones during the Chang 7 deposition (Table 6).

5.2.2. Salinity, stratification, and depth of the Ordos Lake Gammacerane, a C30 triterpane first identified in bitumen of the Green River shale, is usually considered an indicator of hypersaline marine and non-marine depositional environments (Hills et al., 1966). Gammacerane index (GI: the ratio of gammacerane to C30-hopane) increases with increasing salinity of depositional conditions (Moldowan et al., 1985; Brassell et al., 1986). Based on comparison with the data of other lacustrine sediments (Mello Sinninghe et al. (1988)), the 16

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Fig. 9. Spatial distribution (cumulative thickness) of the Chang 7 shales (a) and mudstones (b) in the Ordos Basin.

Fig. 10. The cross plots of (a) RO vs. depth and (b) chloroform bitumen “A”/TOC vs. depth showing the source rock thermal maturity for the analyzed Chang 7 source rocks, Ordos Basin.

wind fetch as proposed by Olsen (1990), the maximum depth of the paleo-Ordos Lake during the deposition of the shales is roughly estimated as 150 m. This is consistent with the tectonic subsidence rates of the Ordos Basin (Yang et al., 2005) and survival domains of specific ostracods preserved in the Chang 7 source rocks.

(Duncan and Hamilton, 1988). Depth of wave base is a function of the distance over which the lake is exposed to wind (fetch) and the speed and duration of the wind itself (Olsen, 1990). The shale deposits in the Ordos Basin span an approximate distance of > 180 km along its long axis (Fig. 9). According to the correlations of the depth of wave base vs. 17

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Fig. 11. The cross plots of petroleum generation potential vs. TOC (a) and TOC vs. chloroform bitumen “A” (b) showing the source rock potential for the analyzed Chang 7 source rocks, Ordos Basin.

microorganism (Table 6; Fig. 5). Besides, low abundance of gammacerane in the source rock extracts imply the minor organic input from bacterivores (e.g., ciliates) living at or below the chemocline in stratified lakes (Moldowan et al., 1986; Sinninghe Damsté et al., 1995). According to Fig. 5, the low abundance of gammacerane in the Chang 7 source rocks indicates that the organic matter source originated from aquatic microorganism. Steranes originate from sterols in higher plants and algae (Volkman, 1986; Peters et al., 2005; Farhaduzzaman et al., 2012). C27 and C28 steranes are generally derived from (specific) phytoplankton and/or algae, while C29 sterane is representative of organic matter input from terrestrial higher plants (Huang and Meinschein, 1979; Moldowan et al., 1986; Volkman, 2003). According to ternary diagram based on the relative percentages of C27, C28 and C29 steranes (Fig. 14) and their distribution patterns on m/z 217 mass chromatograms (Fig. 5), the organic matters of the Chang 7 source rocks predominately originate from plankton, bacteria and algae, which plots of Pr/n-C17 vs. Ph/n-C18 and HI vs. Tmax indicate terrestrial Type I–II2 kerogen for the source rocks (Figs. 12 and 13a). Besides, the interpretation of organic matter source based on the clustered plots of C27/C29 regular sterane vs. Pr/Ph ratio shows a dominance of phytoplankton and algae for the source rock samples (Fig. 13b). In addition, the activiation energy (Ea) data hint of the origin of the

5.2.3. Organic matter source Organic matter characterization was done based on molecular geochemistry and organic petrography. Analytical results of biomarker can provide more reliable interpretation of the organic either terrestrial, marine or mixed source (Peters et al., 2005; Hakimi et al., 2011; Hakimi and Abdullah, 2014; El Diasty and Moldowan, 2013). In this study, observation from TIC distribution of the saturated hydrocarbons (Fig. 5) shows basically aquatic organisms origin for the organic matter (Peters et al., 2005). Generally, the maximum peaks of n-alkanes derived from the terrestrial higher plants are at n-C27, n-C29, and n-C31, while the maximum peaks of n-alkanes derived from phytoplankton and/or algae are at n-C15 and n-C17 (Fu et al., 2009). Even over odd distribution in n-alkanes is usually considered to be a common feature for organic matter deposited in saline environments (Tissot et al., 1977), which are generally considered to originate from bacterial lipids (Grimalt and Albaiges, 1987) or be produced by a mechanism in which carbonate catalyzes β-breakage of even numbered n-fatty acids (Shimoyama and Johns, 1972). Both the Chang 7 shales and mudstones show significant unimodal n-alkane distributions from n-C15 to n-C35 without odd/even predominance (Fig. 5). The maximum peak of n-alkanes in the shale samples is mainly n-C15, while that in the mudstone samples is mainly n-C17, indicating that the organic matters in the Chang 7 source rocks mainly originated from algae and aquatic 18

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5.3. Hydrocarbon generation and expulsion 5.3.1. Hydrocarbon generation analyses In this study, the subsidence and rifting process of the Ordos Basin was simulated via forward and inverse modelling. Numerous measured vitrinite reflectance values are used to examine the simulation results under an extensional basin model. When the “simulated” RO values have fitted the “measured” RO values reasonably, the geologic model provided the process of thermal evolution. Based on the thermal evolution simulation (RO) of four wells (Fig. 15), the hydrocarbon generation process of the Chang 7 source rocks was established by the obtained kinetic parameters. Both the timing, amount of hydrocarbon generation and the composition of hydrocarbon are subject to thermal history. The present-day heat flow is calculated from thermal conductivities of the rocks and the subsurface geothermal gradients which are determined by measured temperatures. Influenced by the continuous subsidence and thermal events in the Early Cretaceous (140–110 Ma) (Zhao et al., 1996), the Chang 7 source rocks matured rapidly and fluid movements were effectively enhanced. The vitrinite reflectance data are well-correlated between the simulation results and the measured RO data from the Well L32, G252, L42 and Z87 (Fig. 15). Four simulation wells (Fig. 16) were established to analyze the burial and thermal evolution in the study area. According to these evolutions (Fig. 16), the different stages and duration timing of different wells can be ascertained in Table 9, suggesting that the Chang 7 Member should be in a mature stage currently. Based on the degrees of evolution of different sections, the thermal evolution of Chang 7 Member can be divided into two stages: the early mature stage, from 170 Ma to 127 Ma; the mature stage, namely the main oil generation stage, from 127 Ma to the present. According to Fig. 17, the timing and amounts of hydrocarbon generation of the Chang 7 source rocks can be ascertained, as shown in Table 10. The results indicate that the beginning of hydrocarbon generation of the Chang 7 source rocks is at 165 Ma, and the duration timing of peak generation of the source rocks is 115–95 Ma. The cumulative amounts of oil generation are up to 4711 × 103 t/km2 and the ratios of peak generation amounts to cumulative generation amounts are > 50% (Table. 10), which are consistent with the ratios of generated amounts/ cumulative generation amounts in the range of dominant Ea distribution (Table. 8). The shales (avg. = 4438×103 t/km2) have higher amounts than the mudstones (avg. = 1285×103 t/km2), due to the higher organic matter abundance and better organic matter origins of the shales. Besides, the Chang 7 shales entered the oil generation stage earlier than the Chang 7 mudstones due to lower activation energies of the shales. In summary, the Chang 7 source rocks have an excellent oil generation potential, which can be the predominant excellent source rocks of the Mesozoic in the study area, and the petroleum potential per unit volume (e.g. 1 m3) of shales is better than that of the mudstones.

Fig. 12. Cross plot of the hydrogen index (HI, mg HC/g TOC) versus pyrolysis Tmax (°C) showing the kerogen type of the analyzed Chang 7 source rocks, Ordos Basin.

organic matter within distinct organic facies as the width of the Ea distribution is more or less directly related to kerogen heterogeneity and hence depositional environments (Tissot et al., 1987; Ziges et al., 2015). The lower Ea values represent the more liptinites and less vitrinites of the kerogen (Dieckmann, 2005; Jiang et al., 2005). Compared to the lacustrine Green River shales (Dieckmann, 2005), the analyzed samples are characterized by a broad distribution of activation energies rather than a single activation energy, reflecting heterogeneous compositions, which are typical for terrestrial organic matters (Schenk et al., 1997; Petersen and Rosenberg (1998)). The Ea distributions (Fig. 6) indicate that the compositions of the organic matters in the mudstone samples are more heterogeneous than those in the shale samples. Furthermore, more lipinites in the shale samples (Table 2) indicate that the organic matter origins of the shales consist of more algae and other aquatic microorganisms than those of the mudstones, and the organic matters of the mudstones may mix with some higher plants.

Fig. 13. Cross plots of Pr/nC17 vs. Ph/nC18 (a) and Pr/Ph vs. C27/C29 (b) showing the organic matter source and paleoenvironment for the Chang 7 source rocks, Ordos Basin.

19

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hydrocarbons decreased gradually (Fig. 18). Once the hydrocarbon generation threshold and expulsion threshold had been reached, the hydrocarbon generation ratio and expulsion ratio increased rapidly in the early period and then more slowly at a later stage (Fig. 18). As a result of the differences of burial depths and organic matter origins between the shales and mudstones, the differences of the hydrocarbon expulsion threshold exist. The hydrocarbon expulsion threshold of the Chang 7 mudstones is 2080 m (Fig. 18a), while the threshold of the Chang 7 shales is 2560 m (Fig. 18b), indicating that hydrocarbon expulsion has occurred in the source rocks and great amounts of hydrocarbons (Max. = 4170 × 103 t/km2; Avg. = 1140 × 103 t/km2) (Xu et al., 2017) have been provided sufficient oils with the reservoir beds. The hydrocarbon expulsion efficiency (the ratio (%) of the total amount of hydrocarbon expulsion to that of hydrocarbon generation in the source rocks) of the Chang 7 source rocks varies from 25% to 90% with a mean of 65% (Zhang et al., 2006). In addition, the threshold of the shales is deeper than the mudstones. In other words, the shales need more generated oil remained in the source rocks to reach the expulsion threshold. The results correspond to the points proposed by Li et al. (2015) and Yang et al. (2016) that the amounts of oil remained in the source rocks increase with the increasing quantities of organic matters and clay minerals of the source rocks.

Fig. 14. Ternary plot of C27, C28 and C29 steranes indicating organic matter source input for the Chang 7 source rocks, Ordos Basin.

5.4. Control of source rocks on tight oil occurrence

However, taking the differences of the thickness and area of the shales and mudstones into consideration, the total amounts of the oil generation of the shales and mudstones may be equal.

The term “tight oil” first appeared in the 1940s when it was used to describe oil-bearing tight sandstones (Ledingham, 1947). In this study, tight oil refers to “oil produced from tight sandstones that are adjacent to or interbedded with source rocks, utilizing horizontal drilling and multistage hydraulic fracturing technology”, which can also be called tight sandstone oil. Due to the sedimentation patterns, diagenesis and polycyclic tectonic evolution, the reservoir heterogeneity of the lacustrine basin is extremely strong. Hydrocarbon migration was typically short range through permeable sand bodies and micro-fractures, without large regional unconformities or vertical faults (Bai et al., 2013; Zhang et al., 2016). As a result, primary migration is predominant during the tight oil accumulation, and there is also shortdistance secondary migration (Zou et al., 2013). Therefore, tight oil accumulated proximally to source rocks. The main driving force for hydrocarbon migration from source rocks to reservoir beds is overpressure developed in the source rocks (shales and mudstones), which are mainly caused by disequilibrium compaction and hydrocarbon generation pressurization (Bowers, 2002; Ruth

5.3.2. Hydrocarbon expulsion analyses To evaluate the quality of the source rocks, analyzing the hydrocarbon generation potential of the source rocks is insufficient. The quantity of the hydrocarbon expulsion of the source rocks is the controlling factor to affect the reserves possessed in the petroleum plays. Thus, it is important for the source rock evaluation to ascertain whether the hydrocarbon expulsion has occurred in the source rocks and what amounts of the hydrocarbon expulsion are. According to Fig. 18, the Chang 7 source rocks have reached the hydrocarbon generation threshold and the hydrocarbon expulsion threshold. Both the hydrocarbon generation threshold (depth) and hydrocarbon expulsion threshold (depth) of the Chang 7 shales are larger than those of the Chang 7 mudstones. All the generated hydrocarbons remained in the source rocks prior to reaching the expulsion threshold, and once this threshold was attained, the capacity of the source rocks to retain

Fig. 15. Simulated RO modelling matches with the measured RO data in Well G252, L32, L42, and Z87 Ordos Basin (T3c7 = the Chang 7 Member).

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Fig. 16. Temperature modelling and burial history in Well G252 (a), Well L32 (b), Well Z87 (c), and Well L42 (d), Ordos Basin (T3c7 = the Chang 7 Member).

Chang 7 are mainly 8–20 MPa with the pressure coefficients of 1.5–1.8, while the pressures of the Chang 6 and Chang 8 mainly range from 4 MPa to 8 MPa with the pressure coefficients of 1.2–1.4 (Fig. 19; Guo, 2013; Yao et al., 2013; Xu et al., 2017), indicating that large pressure differences exist between the Chang 7 and Chang 6/Chang 8. These pressure differences can be the driving force for crude oil from the Chang 7 to itself, upward to the Chang 6, and downward to the Chang 8, with the expulsion efficiency up to 72% (Zhang et al., 2006). Due to the results above and the migration distance of the tight oils, the occurrence of the Chang 8–6 (Chang 8 to Chang 6) tight oil reservoirs may correlate with the distribution of the Chang 7 mature source rocks (shales and mudstones). To investigate whether/how the Chang 8–6 tight oil enrichment is controlled by the Chang 7 source rocks, we have discussed the spatial distribution relationships between the Chang 8–6 tight oil reservoirs and shales/mudstones, respectively. Due to higher pressure differences in the shales (Fig. 19), the shales can be the driving source and overpressure seal for the Chang 8 tight oil reservoirs, which may strongly affect the Chang 8 tight oil occurrence in the Ordos Basin. According to the overlapping figures between the Chang 8 tight oil reservoirs and the Chang 7 shales (Fig. 20a–c), the Chang 8 tight oil reservoirs are predominantly distributed in transition areas between the high value centers of the shale thickness, TOC and RO. However, the shales have little influence on the occurrence of the Chang 7–6 tight oil reservoirs, especially the tight oil reservoirs in the northeastern study area (Fig. 20d–i). Due to the upward decreasing-gradient of pressure differences developed between the Chang 7 and Chang 6 (Fig. 19), the Chang 7–6 tight oil occurrences are mainly affected by the Chang 7 mudstones through the study area. These tight oil reservoirs are also predominantly distributed in transition areas between the high value centers of the mudstone thickness, TOC and RO (Fig. 21d–i). These results can be interpreted as follows. These centers may be the hydrocarbon generation centers, which have relative high fluid potential energy caused by hydrocarbon generation. And the transition areas

Table 9 The stages of thermal-maturity from the burial and thermal evolution of different wells, Ordos Basin (well location shown in Fig. 1). Well

Well Well Well Well

Layer

G252 L32 Z87 L42

Chang Chang Chang Chang

7 7 7 7

Early mature stage

Mature stage

RO (%)

Duration timing (Ma)

RO (%)

Duration timing (Ma)

0.5–0.7 0.5–0.7 0.5–0.7 0.5–0.7

170–112 150–127 145–124 172–114

0.7–1.2 0.7–1.2 0.7–1.2 0.7–1.2

112 127 124 114

to to to to

Present Present Present Present

Fig. 17. Evolutions of oil generation of the Chang 7 source rocks, Ordos Basin.

et al., 2004; Guo, 2013; Shi et al., 2013). Overpressure is mainly developed in the Chang 7 Member in the southwestern Ordos Basin, especially with high values in the Chang 73 (Fig. 19; Guo, 2013; Yao et al., 2013; Xu et al., 2017). The residual formation pressures of the 21

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Table 10 Timing and amounts of hydrocarbon generation of the Chang 7 source rocks, Ordos Basin (well location shown in Fig. 1). Well

G252 L42 L32 Z87

Layer

Chang Chang Chang Chang

Lithology

7 7 7 7

Shale Shale Mudstone Mudstone

Beginning of generation (Ma)

165 160 150 145

Cumulative generation amount (×104 t/km2)

Peak generation Duration timing (Ma)

Ratio of generated amounts to cumulative generation amount (%)

115–98 114–96 115–96 114–95

68.60 68.75 67.89 50.14

471.1 416.5 163.5 93.5

Fig. 18. Hydrocarbon generation and expulsion of the Chang 7 mudstones (a) and shales (b), Ordos Basin.

Fig. 19. Sectional distribution of residual formation pressure of Yanchang Formation in the Ordos Basin (Modified after Guo (2013) and Yao et al. (2013)).

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Fig. 20. Distribution relationships between shales characteristics and tight oil reservoirs in the Chang 8–6, Ordos Basin ((a) Distribution relationship between shales thickness and the Chang 8 tight oil reservoirs. (b) Distribution relationship between shales TOC and the Chang 8 tight oil reservoirs. (c) Distribution relationship between shales RO and the Chang 8 tight oil reservoirs. (d) Distribution relationship between shales thickness and the Chang 7 tight oil reservoirs. (e) Distribution relationship between shales TOC and the Chang 7 tight oil reservoirs. (f) Distribution relationship between shales RO and the Chang 7 tight oil reservoirs. (g) Distribution relationship between shales thickness and the Chang 6 tight oil reservoirs. (h) Distribution relationship between shales TOC and the Chang 6 tight oil reservoirs. (i) Distribution relationship between shales RO and the Chang 6 tight oil reservoirs.).

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Fig. 21. Distribution relationships between mudstones characteristics and tight oil reservoirs in the Chang 8–6, Ordos Basin ((a) Distribution relationship between mudstones thickness and the Chang 8 tight oil reservoirs. (b) Distribution relationship between mudstones TOC and the Chang 8 tight oil reservoirs. (c) Distribution relationship between mudstones RO and the Chang 8 tight oil reservoirs. (d) Distribution relationship between mudstones thickness and the Chang 7 tight oil reservoirs. (e) Distribution relationship between mudstones TOC and the Chang 7 tight oil reservoirs. (f) Distribution relationship between mudstones RO and the Chang 7 tight oil reservoirs. (g) Distribution relationship between mudstones thickness and the Chang 6 tight oil reservoirs. (h) Distribution relationship between mudstones TOC and the Chang 6 tight oil reservoirs. (i) Distribution relationship between mudstones RO and the Chang 6 tight oil reservoirs.).

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RO high value centers are the accumulation and enrichment zones. The Chang 7 shales controlled the occurrence of the Chang 8 tight oil reservoirs and the Chang 7 mudstones controlled the occurrence of the Chang 7 and Chang 6 tight oil reservoirs.

have the relatively low potential energy. According to the potential energy principle, fluids migrate from high potential areas to low potential areas (England et al., 1987; Hubbert, 1953). Fluids migrate along a path where the fluid potential decreases. As a result, areas with low fluid potential energy are favorable orientation-zones for primary migration or short-distance secondary migration. Besides, the tight oil reservoirs are mainly distributed in the area of RO over than 0.7%, because mature source rocks can provide sufficient crude oil with the tight reservoir beds and the tight oil reservoirs accumulated proximally to source rocks. These results are consistent with the previous research made by Guo et al. (2006), Zhang et al., (2006); Zheng et al. (2011), Bai et al. (2013), and Ma et al. (2015). Utilizing the oil-source correlations, the researchers proposed that the oils in the Chang 8 are predominantly derived from the Chang 7 shales and Chang 9 source rocks, while the oils in the Chang 7 and Chang 6 mainly come from the Chang 7 mudstones. In summary, the occurrences of the Chang 8–6 tight oils are predominantly controlled by the outer boundary of the Chang 7 source rocks distribution, while the transition areas between thickness, TOC, and RO high value centers are the accumulation and enrichment zones. The Chang 7 shales controlled the occurrence of the Chang 8 tight oil reservoirs and the Chang 7 mudstones controlled the occurrence of the Chang 7 and Chang 6 tight oil reservoirs.

Acknowledgements This study was jointly supported by the National Natural Science Foundation of China [grant number 41372143] and the Research Fund for the Doctoral Program of Higher Education of China [grant number 20130007110002]. We thank the Research Institute of Changqing Oilfield, CNPC for providing basic data and the permission to publish the results. References Abdullah, W.H., 2003. Coaly source rocks of NW Borneo: role of suberinite and bituminite in generation and expulsion. Bull. Geol. Soc. Malaysia 47, 119–129. Amijaya, H., Schwarzbauer, J., Littke, R., 2006. Organic geochemistry of the Lower Suban coal seam, South Sumatra Basin, Indonesia: palaeoecological and thermal metamorphism implications. Org. Geochem. 37, 261–279. Aplin, A.C., Macquaker, J.H.S., 2011. Mudstone diversity: origin and implications for source, seal, and reservoir properties in petroleum systems. AAPG Bull. 95, 2031–2059. Arthur, M.A., Cole, D.R., 2014. Unconventional hydrocarbon resources: prospects and problems. Elements 10, 257–264. Ayinla, H.A., Wan, H.A., Makeen, Y.M., Abubabar, M., Jauro, A., Mohammed, B., Abidin, N.S.Z., 2017. Petrographic and geochemical characterization of the Upper Cretaceous coal and mudstones of Gombe Formation, Gongola sub-basin, northern Benue trough Nigeria: implication for organic matter preservation, paleodepositional environment and tectonic settings. Int. J. Coal Geol. 180, 67–82. Bai, Y.B., Luo, J.L., Liu, X.J., Jin, W.Q., Wang, X.J., 2013. Geochemical characteristics of crude oil and oil-source correlation in Yanchang Formation (Upper Triassic) in Wubao Area, Ordos Basin. Acta Sedimentol. Sin. 31, 374–383. Beers, R.F., 1945. Radioactivity and organic content of some Paleozoic shales. AAPG Bull. 29, 1–22. Behar, F., Kressmann, K., Rudkiewicz, J.L., Vandenbroucke, M., 1992. Experimental simulation in a confined system and kinetic modelling of kerogen and oil cracking. Org. Geochem. 19, 173–189. 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6. Conclusions Based on the systematic analysis of geological characteristics associated with the Chang 7 lacustrine shales and mudstones, the following conclusions can be drawn: (1) Based on the comprehensive analyses of bulk organic geochemical characteristics, the Chang 7 source rocks have entered the mature stage of hydrocarbon generation and a good to excellent source rock potential. The kerogen type of the source rocks are Type I–II2. The results indicate that the Chang 7 source rocks have an excellent hydrocarbon generation potential, and the shales hold a better potential than the mudstones. (2) According to the analyses of the biomarkers, the paleoenvironments of the Chang 7 source rocks were sub-reducing to sub-oxidizing conditions and fresh- and brackish-water depositional environments. The maximum depth of the paleo-Ordos Lake during the deposition of the Chang 7 shales is roughly estimated as 150 m. The organic matter origins of the source rocks are mainly plankton, algae, bacteria and other aquatic microorganisms. (3) Based on the hydrocarbon generation kinetic analyses, the beginning time of the oil generation of the Chang 7 source rocks is at 165 Ma, and the peak oil generation occurred during 115–95 Ma. The cumulative amounts of oil generation are up to 4711 × 103 t/ km2 and the ratios of peak generation amounts to cumulative generation amounts are > 60%. Due to the differences of the burial depth and macerals of organic matters, the beginning time and peak generation time of the shales are earlier than those of the mudstones, respectively. The Chang 7 shales possess a cumulative oil generation of 4438 × 103 t/km2 (avg.), while the Chang 7 mudstones have a cumulative oil generation of 1285 × 103 t/km2 (avg.). The Chang 7 source rocks possess an excellent oil generation potential, which can be the predominant excellent source rocks of the Mesozoic in the Ordos Basin. (4) As a result of the differences of burial depths and macerals of the organic matter between the shales and mudstones, the shales need more generated oil remained in the source rocks to reach the expulsion threshold than the mudstones. The hydrocarbon expulsion threshold of the Chang 7 mudstones is 2080 m, while the threshold of the Chang 7 shales is 2560 m. (5) The occurrences of the Chang 8–6 tight oils are predominantly controlled by the outer boundary of the Chang 7 source rocks distribution, while the transition areas between thickness, TOC, and 25

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