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Characterization of continental coal-bearing shale and shale gas potential in Taibei sag of the Turpan-Hami Basin, NW China Xiaobo Guo, Zhilong Huang, Xiujian Ding, Jinlong Chen, Xuan Chen, and Rui Wang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b01507 • Publication Date (Web): 30 Jul 2018 Downloaded from http://pubs.acs.org on August 20, 2018
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Energy & Fuels
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Characterization of continental coal-bearing shale and shale gas potential in
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Taibei sag of the Turpan-Hami Basin, NW China
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Xiaobo Guo,a Zhilong Huang,b* Xiujian Ding,c* Jinlong Chen,b Xuan Chen,d Rui Wangd
4 5 6 7 8 9 10 11
a
Shaanxi Key Lab of Petroleum Accumulation Geology, Xi’an Shiyou University, Xi’an 710065,
China b
State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China c School of Geosciences, China University of Petroleum, Qingdao 266580, China d Research Institute of Exploration and Development, Tuha Oilfield Company, CNPC, Hami 839000, China
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ABSTRACT: A series of experimental methods were used to characterize the organic
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geochemistry, mineralogy, and pore structure and to preliminarily evaluate the potential of the
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coal-bearing shale gas of the Xishanyao Formation in Taibei sag of the Turpan-Hami Basin.
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The results reveal that more than 50% of the samples have fair to good organic matter (OM)
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richness with TOC >1.5%, and the shale samples are dominated by type III kerogen with the
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relative content of regular C29 sterane averaging as 0.60, and Pristine/Phytoene (Pr/Ph) values
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averaging 3.10. Vitrinite reflectance (Ro) values are ranging from 0.31% to 0.81%, indicating
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the OM is at an immature to low mature stage. The dominant mineral composition is clay
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minerals. Nanometer-scale inorganic matrix pores and fracture pores are developed in the
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coal-bearing shale, with mean pores diameters ranging from 10.2 nm to 18.1 nm. Compared
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with typical marine and lacustrine gas shale, the Xishanyao coal-bearing shale has a fair to
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good ability to generate low-maturity shale gas, and the clay minerals provide the main
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adsorption surface for adsorbed gas. The shale with clay minerals content lower than 55% and
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quartz content higher than 31%, can have an appropriate gas adsorption ability and brittleness
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simultaneously. An analysis of the development conditions of organic rich shale shows that
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the favorable gas shale is mainly distributed in the margin of the ancient lake basin, which is
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the preferred target area. Overall, high clay content and deep burial are the main adverse
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factors for the recent exploration and development of the Xishanyao coal-bearing shale gas.
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Keywords: Coal-bearing shale gas; Organic geochemistry; Pore structure; Xishanyao
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Formation; Turpan-Hami Basin
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1. INTRODUCTION
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Shale gas as a type of unconventional gas resource has been favored worldwide and was
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first successfully commercially developed in North America, profiting from the successful 1
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application of horizontal drilling and segmented hydraulic fracturing techniques.1-4 Gas shale
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can develop in a marine environment, continental environment and marine-continental
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environment, and marine shale gas is dominant in North America. Recently, shale gas
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exploration and development has made remarkable progress in China, such as the marine
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shale gas in the Wufeng-Longmaxi Formation of the Sichuan Basin and the continental
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lacustrine shale gas in the Yanchang Formation of the Ordos Basin.5-9
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Coal-bearing organic-rich shale is widely developed in China, especially in the northwest
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area. Coal-bearing shale is a lithologic type of coal measure source rock, which also includes
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carbonaceous shale and coal. It has been proven that these coal measure source rocks
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including shale are the main source rocks for the tight gas sandstone reservoirs in different
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Basins, such as the Jurassic coal measure source rocks in the Kuqa depression, the Triassic
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coal measure source rocks in the Sichuan Basin, the Permian coal measure source rocks in the
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Ordos Basin, and the Jurassic coal measure source rocks in the Turpan depression.10-12
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Compared with other types of shale, the coal-bearing shale has two main characteristics. One
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is the development of a swamp environment, and the other is the enrichment of gas-prone
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kerogen.10 Therefore, coal measure shale has a strong gas generating ability, which has the
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potential to form shale gas in China, and some scholars have begun to analyze the geological
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characteristics and resource potential of coal-bearing shale gas.13-15 Resource evaluation
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shows that the nominally recoverable coal-bearing shale gas is as high as 12.9×1012 m3 in
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China.16 However, to our knowledge, no previous studies have been carried out on
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coal-bearing shale for the geological evaluation of shale gas in the Turpan-Hami Basin, which
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is expected to have large quantity of shale gas worth exploring and developing.
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The Turpan-Hami Basin, one of the most important coal measure source rock-bearing
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Basin, has been widely known for the study of coal measure derived hydrocarbon since the
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1990s, especially in the Taibei sag.17-21 In addition, a great deal of oil and gas has been
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discovered in the Taibei sag, and Middle-Lower Jurassic coal measure source rocks were
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considered as the most important source rocks, including the Xishanyao Formation and the
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Badaowan Formation.19,20,22 In recent years, coal-bearing shale gas in the Middle-Lower
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Jurassic has received extensive attention. As pointed out by Zhang and Sun, the Taibei sag in
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the Turpan-Hami Basin has the basic conditions for coal-bearing shale gas generation and
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accumulation potential in the Middle-Lower Jurassic.23,24 The latest shale gas resource
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assessment by Ministry of Land and Resources of PRC shows that shale gas resources are
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approximately 2.064×1011 m3 in the Xishanyao Formation and 4.261×1011 m3 in the
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Badaowan Formation at a probability of 50% calculated by the Monte Carlo resource 2
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evaluation method in the Turpan-Hami Basin.25 Thus, a detailed geological and geochemical
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investigation of coal-bearing shale in the Taibei sag is needed. For the evaluation of the shale
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gas potential, the organic matter (OM) richness, kerogen type, thermal maturity, reservoir
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properties, mineralogy and gas content et al., are the important parameters.26-28 In this study,
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we only discuss the preliminary characteristics of the Xishanyao coal-bearing shale, the shale
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gas potential and the favorable exploration area for shale gas.
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2. GEOLOGICAL SETTING
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The Turpan-Hami Basin is located in the Xinjiang Uygur Autonomous Region and is
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bounded by the Bogda Mountains to the north, Jueluotage Mountains to the south, Haerlike
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Mountain to the east and Kalawucheng Mountain to the west.19,20,22 The basin is composed of
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three first tectonic regions: the Turpan depression, Liaodun uplift and Hami depression from
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west to east.19,22 The Taibei sag is a second-order tectonic unit in the north of Turpan
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depression, with an area of about 1×104 km2, and the sag can be subdivided into three
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sub-sags: the Shengbei sub-sag, Qiudong sub-sag and Xiaocaohu sub-sag,19,22 as shown in
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Figure 1. The Taibei sag was filled with a well-developed Carboniferous through Quaternary
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sedimentary sequence (Figure 2).
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Coal measure source rocks mainly developed in the Middle-Lower Jurassic Shuixigou
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Group. From the bottom to the top, the Shuixigou Group is composed of three Formations:
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the Badaowan Formation (J1b), the Sangonghe Formation (J1s) and the Xishanyao Formation
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(J2x) (Figure 2), and the Xishanyao Formation can be divided into four sections vertically
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from the bottom (J2x1, J2x2, J2x3, J2x4). Shao pointed out that the Middle-Lower Jurassic
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Shuixigou Group coal-bearing sedimentary strata formed in fluvial, delta, and lake
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sedimentary systems, which had successively experienced swamping (Badaowan)-lake
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flooding (Sangonghe)-swamping (J2x1-2)-lake flooding (J2x3-4) processes.29,30 During the
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sedimentation period of the Xishanyao Formation, the Taibei sag was covered by shallow
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water, and lacustrine-swamp, near-shore and delta depositional systems were widely
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distributed. J2x1 is mostly composed of gray sandstone with some shale and carbon shale, J2x2
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is dominated by coal, carbon shale and shale, and together with J2x1, it is one of the important
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strata of the coal measure source rocks; J2x3 and J2x4 are mainly composed of interbedded
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sandstone and shale.22,30 Coal measure shale in Xishanyao Formation is widespread in the
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whole Taibei sag with the largest thickness being 600m.31 Coal-bearing shales are mostly
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present in J2x1-2, which is a favorable section for the development of potential shale gas,24,25
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and it is also the target section studied in this paper.
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Figure 1. Map showing the location of research area and sampling wells (Modified from Yuan22)
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Figure 2. Stata section of Taibei sag in Turpan-Hami Basin (Modified from Yuan22) 4
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Energy & Fuels
3. SAMPLES AND EXPERMENTAL METHODS
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In this study, 40 gray and gray-black shale experimental samples were collected from the
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Xishanyao Formation in the Taibei sag, whose well locations are shown in Figure 1. For these
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experimental samples, we have carried out many experimental analyses, which can be
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attributed to four types: organic geochemistry, quantitative analysis of mineral composition by
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X-ray diffraction, pores image analysis by field emission scanning electron microscopy
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(FE-SEM) and CT scanning and low-pressure N2 adsorption/desorption analysis. The
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experimental analyses were conducted at the State Key Laboratory of Petroleum Resources
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and Prospecting, China University of Petroleum (Beijing).
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3.1. Geochemical analysis
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A total of 34 selected gray and gray-black coal-bearing shale samples were pulverized to
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200 mesh in preparation for the integrated suite of organic geochemistry experimental
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analyses, including total organic carbon (TOC), Rock-Eval pyrolysis, vitrinite reflectance (Ro),
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extraction of chloroform asphalt “A”, and gas chromatography–mass spectrometry (GC–MS)
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analyses of the saturated fractions. The results are listed in Table 1, Table 2 and Table 3.
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TOC was determined using a Leco CS-230 HC carbon analyzer at the State Key
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Laboratory of Petroleum Resources and Prospecting. For the powder sample, the inorganic
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carbon was removed by diluted hydrochloric acid (10% HCl solution); then, the sample was
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burned in a high-temperature furnace up to 1000°C to convert the organic carbon to carbon
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dioxide for measurement. Rock-Eval pyrolysis analysis was performed on an ROCK-EVAL.II
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oil and gas evaluation workstation, which provided the parameters of S1 (mg HC/g rock), S2
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(mg HC/g rock) and Tmax (°C) during heating at a programmed rate. S1, known as the residual
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hydrocarbons, represents the hydrocarbons released by heating the source rock powder to
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300°C. S2 is called the pyrolysis hydrocarbons, representing the newly generated
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hydrocarbons of kerogen when the powder of the source rock is heated to 650°C from 300°C.
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Tmax is the peak temperature of S2, representing the temperature at the maximum generation
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rate of pyrolytic hydrocarbons.
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An MPV-SP microscope photometer instrument was used to perform vitrinite reflectance
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value determination by kerogen slice in the kerosene environment, which follows the SY/T
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5124-2012 method. In order to assess OM more accurately, the kerogen element composition
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was determined by the instrument of ELEMENTAL CUBE. The residual powder of all the 34
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shale samples were used for soluble OM (bitumen “A”) extraction based on the Soxhlet
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extraction principle using chloroform/methanol (87:13) for 72 h, and the extracts were further 5
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separated by the column chromatography method to obtain the saturated hydrocarbon
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fractions. The saturated fractions were analyzed by GC-MS to obtain biomarker parameters
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using an HP6890GC/5973MSD instrument. The corresponding methods are available in Ding
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et al. (2015).32
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3.2. Mineral composition analysis
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A Bruker D8-Discover Advance X-ray diffractometer was used for mineralogy study of
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the coal-bearing shale in the Xishanyao Formation. The test experiment including the bulk
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mineral content and clay mineral fraction analysis for the 34 shale samples crushed into
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approximately 200 μm powder were performed at a temperature of 24°C and a humidity of
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35%. The data were measured in the 2θ angular range of 2-60°at scan rates of 2°/min with
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Cu-Kα radiation (45 kV, 35 mA). First, the bulk mineral composition, such as clay, quartz,
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and calcite, was determined. Second, the individual mineral composition of clay was
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separated and examined from the rock powder. Finally, a quantitative assessment was
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performed to determine the relative amount of various mineral compositions and clay mineral
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fractions.
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3.3. Pore structure analysis
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To directly observe the pore morphology of the coal-bearing shale, high-performance
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FE-SEM and CT scanning analyses were performed on an FEI Quanta 200F scanning electron
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microscope and an Xradia MicroXCT-200 micron CT scanner for image analysis, respectively.
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Low-pressure (77K) N2 adsorption analysis is commonly used to characterize the specific
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surface area (SSA), pore volume and pore size distribution (PSD), especially for mesopores
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with diameter ranging from 2nm to 50nm. Six samples underwent low-pressure N2
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adsorption/desorption analysis using a Quantachrome Quadrasorb SI instrument in this study.
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Before the experiment, the samples were ground to 60-80 mesh and dried at 300°C for 3 h in
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a vacuum oven to remove air and bound and capillary water. N2 adsorption-desorption
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isotherms were then obtained at -196.15°C with a relative pressure (P/Po) range of
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0.004-0.995 and a pore diameter ranging from 1.4 nm to 200 nm. The SSA and PSD can be
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calculated based on the adsorption data with an elective multipoint Brunauer-Emmett-Teller
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(BET) model and the Barrett-Joyner-Halenda (BJH) model, respectively. The mean pore size
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was calculated by N2 adsorption data at P/P0 0.993.
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4. RESULTS
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4.1 Organic geochemical characteristics
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4.1.1 OM richness
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A good hydrocarbon generation capability is the primary influencing factor for a shale
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source rock to be considered a shale gas accumulation. Total organic carbon (TOC),
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hydrocarbon genetic potential (S1+S2) and chloroform asphalt “A” are the most common
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proxies for evaluating the OM richness of source rocks. Table 1 provides the TOC results of
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all 34 samples of the coal-bearing shale in the Xishanyao Formation, which exhibits TOC
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ranging from 0.45% to 5.84%, averaging 2.10%. The S1+S2 values obtained from the
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Rock-Eval analysis increase from 0.13 to 15.36 mg HC/g rock, averaging 3.10 mg HC/g rock
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(Table 1; Figure 3A). Chloroform asphalt "A" ranges from 0.013% to 0.345%, with an
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average of 0.099%. In addition, S1+S2 and chloroform asphalt “A” display a good positive
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correlation with TOC (Figure 3B). Chen et al. (1997) put forward the evaluation standard of
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OM richness of coal-bearing shale based on the studies of coal measure source rocks mainly
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in the Turpan-Hami Basin.33 According to the standard, approximately 56% of samples have a
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fair to good OM richness with TOC > 1.5% and S1+S2 > 2 mg HC/g rock, and approximately
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79% of samples have a fair to good OM richness with chloroform asphalt “A” > 0.03%
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(Figure 3A and B). Pyrolytic hydrocarbon S1 has a strong volatilization property, and it may
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have a larger loss in the experimental process, resulting in a lower evaluation result of S 1+S2
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than chloroform asphalt “A”.
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194 195 196 197
Figure 3. Plots of S1+S2 (A) and bitumen “A” (B) versus TOC
4.1.2 OM type
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OM type or kerogen type is an important parameter for evaluating the gas/oil-prone
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capability of shale. Rock-Eval pyrolysis and the elemental composition of kerogen are usually
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used to classify OM types.34 As shown in Figure 4A, the hydrogen index (HI, S2 HC/g TOC) 7
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for the samples range from 15.3 to 395.4 mg HC/g TOC, and the shale mainly contains type
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III kerogen and individual samples contain type II kerogen. In the H/C-O/C kerogen type
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classification diagram, the kerogens have low H/C atomic ratios (< 1.0) for most shale
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samples, ranging from 0.52 to 1.63, with an average of 0.84, indicating that the Xishanyao
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shale is dominated by type III kerogen with a strong gas-prone capability (Figure 4B).
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Figure 4. Plots of hydrogen index (HI) versus Tmax (A) and H/C versus O/C of kerogen (B) outlining the kerogen type of shale samples
The kerogen type is consistent with the OM source, and the biomarkers from the GC-MS
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analysis are very useful in assessing the OM source and type.35 The relative abundance of
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regular sterane (C27, C28 and C29) can be used to denote the OM source of shale. C29 regular
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sterane domination reflects OM sourcing from advanced plants mainly, corresponding with
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gas-prone kerogen mostly.36 In contrast, C27 regular sterane domination with a lower content
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of C29 regular sterane reflects OM sourcing from lower organisms mainly, corresponding with
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oil-prone kerogen.36 There are some variations in the distribution of regular C27, C28 and C29
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steranes among the shale samples from the Xishanyao Formation. The relative content of
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regular C27, C28 and C29 steranes of the shale source rock extracts range from 0.06 to 0.43
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(averaging 0.17), 0.15 to 0.35 (averaging 0.23) and 0.31 to 0.74 (averaging 0.60) respectively
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(Table 2), indicating that the OM in the kerogen is mainly derived from advanced plants for
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most of the shale samples. In addition, this is congruent with the swamp and oxidation
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environment reflected by higher values of Pristine/Phytoene (Pr/Ph), ranging from 0.49 to
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7.79 and averaging 3.10 (Table 2). Although there are few samples containing more C27
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regular sterane than C29 regular sterane expressing oil-prone features, the results are consistent
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with the results above for most samples.
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4.1.3 OM thermal maturity
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Vitrinite reflectance (Ro) is a common parameter to evaluate the OM thermal maturity. 8
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Measured Ro values range from 0.31% to 0.81%, with an average of 0.49%, which indicates
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that the coal-bearing shale is immature to low maturity stage (Table 1, Figure 5). The Tmax of
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the Rock-Eval results can also be used to evaluate OM thermal maturity. Tmax data has a
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narrow range between 433°C and 457°C, with Tmax lower than 445°C for most samples,
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reflecting thermal maturity from immature to low maturity stage (except for one sample with
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an abnormally high value of 479°C).34 Biomarker parameters can be used to feature the OM
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thermal maturity at a low maturity stage, such as the isomerization parameters of C29 regular
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sterane. C2920S/20(S+R) ranges from 0.37 to 0.55, averaging 0.47; and C29ββ/(αα+ββ) ranges
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from 0.22 to 0.47, averaging 0.34 for Xishanyao shale (Table 2, Figure 6). The two
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parameters both illustrate the OM thermal maturity at an immature-low maturity stage.
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240 241 242
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Figure 5. Frequency distribution histogram of Ro (%) for Xishanyao shale samples
Figure 6. Plot showing the relationship between C29 ββ/(ββ+αα) and C29 ααα20S/(20S+20R)
4.2 Mineral composition characteristics
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The mineral composition of the coal-bearing shale of Xishanyao was determined by
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XRD, and the results are given in Table 3. The mineral composition of coal-bearing shale in
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Xishanyao Formation consists of clay, quartz, plagioclase and calcite, and the dominate
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mineral in most samples is clay, with content ranging from 17% to 78%, averaging 50.3% of
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the bulk mineral composition. The second highest composition is quartz, ranging from 19% to 9
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46%, with an average of 35.5%. Although some samples contain plagioclase and calcite up to
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21% and 19%, respectively, some samples have little to no plagioclase and/or calcite. The
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clay minerals are composed of illite, kaolinite, chlorite and illite/smectite mixed layers,
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among which the content of the mixed layers is the highest, with an average of 45%, kaolinite
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and illite are second, with an average content of 22%, and the content of chlorite is the lowest,
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with an average of 11% (Table 3, Figure 7).
258 259 260 261
Figure 7. Ternary diagram of the clay mineral composition of Xishanyao shale samples
4.3 Characterization of pores
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Loucks divided the pore types of bearing gas shale into three groups: inorganic matrix
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pores, OM pores and fracture pores.37 From the SEM images, there are some inorganic matrix
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pores that developed between the clastic particles and in the clay minerals (Figure 8A, B and
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C). The content of quartz and feldspar framework minerals is relatively low in Xishanyao
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Formation shale. A small amount of mineral particles can be seen in the SEM images.
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Intergranular pores can be developed between framework minerals, most of which are
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residual pores after compaction of primary pores (Figure 8A and B). Interparticle pores often
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have a large pore radius and can be used as a space for the existence of free gas. Clay
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minerals are the most common in the SEM images of shale samples and most of framework
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mineral particles are covered with clay, which mainly consist of illite/smectite mixed layers,
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illite and kaolinite (Table 3, Figure 7). The pores are developed between randomly distributed
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clay mineral particles, and the pores are flaky, triangular and irregular cylindrical (Figure 8C).
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The pore morphology is influenced by the clay minerals morphology, such as the illite can be
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lamellar, and the irregular triangular pores are often formed by the random accumulation of
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lamellar particles. In the samples, smectite appears in the form of mixed layer of
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illite/smectite, which makes the original form of smectite is difficult to distinguish. Smectite,
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with its unique structure, can form not only intergranular pores, but also interlayer fractures 10
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between the layers, which are very important to increase the specific surface area of shale.
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Inorganic matrix pores diameters range from a dozen nanometers to several hundred
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nanometers or even several microns in Xishanyao coal-bearing shale (Figure 8A, B and C).
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However, OM pores are not observed in the samples, which was considered to be an
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important pore-type in marine shale gas reservoirs, such as the Barnett shale in the Fort Worth
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Basin and the Marcellus shale in the Appalachian Basin of the United States and the
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Longmaxi shale in the Sichuan Basin of China.38-40 Figure 8D, E and F show the CT images
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of coal-bearing shale in the Taibei sag. As shown in Fig.8, micro-fractures are present in the
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shale with a parallel platy shape, which is beneficial to the transfusion and storage of shale
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gas. The distribution of the pores within the inorganic matrix is scattered with poor
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connectivity in the CT scanning images (Figure 8E). In addition, high-density minerals, such
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as quartz and feldspar, are uniformly distributed in the shale (Figure 8F), which play an
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important role in the formation of micro-fractures.
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4.4 Low-pressure N2 adsorption
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4.4.1 Pore size distribution
Figure 8. SEM images of pores (A, B and C) and CT images of pores and micro-fracture (D, E and F) in coal-bearing shale (A-B) interparticle pore; (C) pores in clay mineral; (D) fracture pores; (E-F) the space destitution of pores, fracture pores and minerals (the pores and cracks coloured in the same color are connected).
301
The Low-pressure N2 adsorption-desorption branches have been used to analyze PSD by
302
the data interpretation model. The adsorption branch is most widely used for PSD calculation
303
through the BJH model because the results are hardly affected by the tensile strength effect 11
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304
and can more accurately reveal the PSD.41-43 The PSD of coal-bearing shale calculated from
305
the N2 adsorption branch are shown as the plot of dV(d) versus Diameter plots in Figure 9.
306
According to Figure 9, all samples have no obvious peak curves, indicating that the
307
distribution of the pore diameter is continuous and no pore diameter interval is dominant, with
308
mean diameters ranging from 14.8 nm to 19.5 nm. There is a slight exception for sample T1,
309
with a peak pore proportion at the diameter of approximately 2 nm. However, the curves of
310
samples T4 and T5 have tailing phenomena, which indicate the existence of some macropores
311
at a larger diameter level in those samples. From the pores images (Figure 8), it can be seen
312
that there are some larger pores in shale, and the pore size distribution of these pores needs to
313
be further characterized by high pressure mercury injection technology.
314
315 316 317 318
Figure 9. Pore volume distributions relative to pore diameter derived from the N2 adsorption branch
4.4.2 N2 adsorption-desorption isotherm
319
In this study, we investigate the shale pore shapes using the hysteresis loops formed by
320
N2 adsorption-desorption branches, as shown in Figure 10. According to the International
321
Union of Pure and Applied Chemistry (IUPAC) isotherm and hysteresis loop classifications,
322
the pore shapes consist of four types, namely, type H1, H2, H3 and H4 representing different
323
pore structure characteristics.44 A close examination of the adsorption curve shows that
324
samples in the low relative pressure (P/Po < 0.05) section exhibit adsorption, demonstrating
325
the presence of micropores in the shale. The six samples all formed hysteresis loops,
326
indicating that the pores are mainly open pores, as the SEM images showing. According to the
327
hysteresis loops shape of sample T1, T2, T4 and T6, the adsorption curve is steep at the
328
saturated vapor pressure accessory and the desorption curve is steep at the middle pressure,
329
and the hysteresis loops are similar to the type H3 hysteresis loop recommended by IUPAC
330
(Figure 10), indicating complex pore structure more related to plate-like matrix, such as clay
331
minerals. The N2 adsorption content increases with the increase of relative pressure (P/Po) of
332
the four samples and sample T6, and there is no tendency of adsorption saturation at the 12
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maximum P/Po of 0.99 (Figure 10), indicating that there are still macropores that have not
334
been filled and analyzed. The hysteresis loop of sample T6 has some of the characteristics of
335
hysteresis loop type H3 and H4 (Figure 10 B). Sample T3 are similar to the type H4 hysteresis
336
loop, and the adsorption and desorption curves are approximately horizontal and parallel to
337
each other at low P/P0 stage, indicating mainly nanometer pores in T3 samples (Figure 10 A).
338
339 340 341 342
Figure 10. Low-pressure N2 adsorption and desorption isotherms of core-bearing shale samples
4.4.3 Pore volume and specific surface area
343
Pore volume (PV) and specific surface area (SSA) of shale control the capability of gas
344
storage and transfusion. The PV and SSA results of the coal-bearing shale samples calculated
345
by the Brunauer-Emmett-Teller (BET) model and BJH model using N2 adsorption data are
346
shown in Table 4. The BET SSA of the six samples varies from 0.96 m2/g to 12.18 m2/g, with
347
an average of 5.64 m2/g. The BJH SSA ranges between 1.56 m2/g and 12.71 m2/g, averaging
348
6.71 m2/g, which is larger than the BET SSA. Different calculation models have different
349
results, indicating that both results do not reflect the true SSA, but the results can reflect the
350
relative amounts for the same model. The BJH pore volume cumulative adsorption pore
351
volume varies from 0.010 cm3/g to 0.036 cm3/g, with an average of 0.018 cm3/g. The mean
352
diameter of the shale samples varies between 10.2 nm and 18.1 nm, averaging 12.9 nm.
353
5. DISCUSSION
354
5.1 Qualification for shale gas generation
355
In order to evaluate the potential of the coal-bearing shale gas of the Xishanyao
356
Formation in the Taibei sag, we chose some typical gas shale reservoirs in the United States
357
and China to make a comparative analysis. Table 4 lists the key parameters for the evaluation
358
of the shale gas potential of the Barnett shale, Ohio shale, Antrim shale, New Albany shale,
359
Lewis shale, Wufeng-Longmaxi shale, Yanchang shale (Chang7) (Table 5) and Xishanyao 13
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shale. The contrast parameters include shale burial depth, TOC, Ro, kerogen type and gas
361
content. Compared with the other gas shales, the Xishanyao coal-bearing shale is
362
characterized by low thermal maturity, type III kerogen and deep burial (Table 5, Figure 11).
363
For OM maturity, the Xishanyao shale has similar low Ro values to those of the Antrim shale
364
(Figure 11A), which is a famous immature to low mature gas-bearing shale. In the geological
365
evaluation of conventional natural gas, the Xishanyao formation coal measures have been
366
proven as source rocks providing natural gas for sandstone reservoirs in the Xishanyao
367
formation and overlying strata.19-22 Scholars argued that most of the discovered natural gas
368
related to the Xishanyao coal measure source rocks include coal-bearing shale, with the
369
thermal maturity Ro at 0.4~0.8%, and the natural gas was considered to be low-maturity gas.
370
22,45,46
371
generation by type III kerogen is lower than that for oil generation, and the source rock can
372
form large-scale industrial gas reservoirs at a low thermal evolution stage.22,45,46 In contrast
373
with successful shale gas area, the coal-bearing shale of Xishanyao Formation and Lewis
374
shale of San Juan Basin have similar kerogen types, mainly III kerogen type, and the OM
375
richness of Xishanyao shale is higher than that of Lewis shale (Table 4, Figure 11B). In the
376
geological evaluation for the potential of natural gas, the evaluation criterion of shale as a
377
source rock for unconventional shale gas can be lower than that of conventional natural gas.
378
For conventional natural gas accumulation, shale can not only generate natural gas but also
379
discharge sectional natural gas effectively after satisfying autogenetic residues. However,
380
shale gas as self-generation and self-reservoirs is rudimental gas remaining in the source rock,
381
without an additional discharge process. In other words, a shale gas reservoir can only be
382
formed if the shale can generate a quantity of natural gas meeting its own requirements for
383
free gas and adsorbed gas. In addition, the gas samples of Xishanyao Formation coal-bearing
384
shale were obtained by field analysis. The carbon isotopic of CH4 is -45.6‰, -43.60‰ and
385
-43.70‰. According to the low mature gas identification index proposed by Yuan, the
386
methane carbon isotopic composition ranges from -54‰ to 39‰.22 It can be seen that the
387
shale gas of Xishanyao Formation shale belongs to low mature gas. Therefore, the low
388
thermal maturity Xishanyao shale also has the capacity to form shale gas accumulations.
Low-maturity gas theory points out that the average activation energy for gas
389
With the increase of buried depth, shale maturity increases, which is beneficial to the
390
shale gas generation. But the shale burial depth is a key factor limiting the development of
391
shale gas owing to the hydraulic fracturing technology not meeting the standard requirement.
392
The burial depth of the Xishanyao coal-bearing shale samples is about 2500-5000m in Taibei
393
sag (Figure 11C). The study of resource evaluation shows that the shale burial depth is 14
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between 2500-3750m in the target area (favorable shale depth) of Xishanyao coal-bearing
395
shale gas (Figure 11C), which is greater than that of most gas-bearing shale.25 At present,
396
China has already achieved the standard requirement for marine shale gas reservoir hydraulic
397
fracturing shallower than 3500 m.47 The drilling and fracturing equipment and technology for
398
marine shale gas deeper than 3500m have also made some progress, but have not yet made a
399
comprehensive breakthrough.47 For the sake of continental coal-bearing shale gas
400
development in the Taibei sag, drilling technology and reservoir reconstruction technology
401
should be further innovated and promoted.
402
403 404 405 406 407 408 409
Figure 11. Main parameters comparison between Xishanyao shale and other major gas-bearing shale in China and America 6, 47-52 (A) Comparison of burial depth for different shales; (B) Comparison of TOC for different shales; (C) Comparison of Ro for different shales.
5.2 Qualification for shale gas reservoirs
410
Shale is an unconventional gas reservoir with low porosity and permeability, in which
411
natural gas production must be performed by hydraulic fracturing, and the brittleness of the
412
shale is the key factor that affects the development of shale gas.47,53,54 According to the
413
experience of successful shale gas fields, the brittle mineral content such as siliceous and
414
carbonate minerals is the commonly used parameter to evaluate shale brittleness. The mineral
415
compositions of the Barnett shale in the Fort Worth Basin, the Yanchang shale (Chang7) in the
416
Ordos Basin, and the Longmaxi shale in the Sichuan Basin1, 6, 40 and the Xishanyao shale in
417
the Taibei sag are shown in the ternary diagram (Figure 12, Table 3). From the diagram, we
418
can conclude that the Xishanyao shale has a significantly different mineral composition from
419
the marine shale and has a certain degree of similarity with Chang7 lacustrine shale with a 15
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high content of clay. In addition, the distribution range of the minerals with different
421
properties is more concentrated for Xishanyao shale than Barnett shale, indicating that the
422
heterogeneity of coal-bearing shale is not very strong. The clay mineral content directly
423
affects shale brittleness and gas adsorption ability. Generally, the lower the content of clay as
424
a plastic mineral and the higher the content of brittle minerals, the stronger the brittleness of
425
the shale reservoir and the more favorable the reservoir is to hydraulic stimulation. For now,
426
the clay minerals in shale have a dual influence on shale gas accumulations.
427
428 429 430 431
The surface area of clay minerals and OM is the main carrier for natural gas adsorption,
432
in many successful shale gas fields.38,39,55 However, the Chang7 shale gas is also mainly
433
dominated by adsorbed gas, which is mainly dependent on clay minerals to provide
434
adsorption surface area due to the limited development of organic pores in the Ordos Basin.56
435
Facing these unfavorable conditions, effective development of the Yanchang Formation shale
436
gas has been performed by adopting CO2 energy increasing fracturing, supercritical CO2
437
fracturing, etc..57 The specific surface area of clay minerals is different, which affects the
438
adsorption ability of shale gas. Under the same temperature and pressure conditions,
439
montmorillonite has the strongest adsorption capacity of the gas, followed by the
440
illite/smectite mixed layers, then kaolinite, chlorite and illite.58 The Xishanyao coal-bearing
441
shale in the Taibei sag is similar to the Chang7 shale with the development of rare OM pores,
442
and the clay minerals may play an important role in providing adsorption surface area.
Figure 12. Ternary diagram of the bulk mineral composition for different shales.1, 6, 40
443
Xishanyao shale contains the highest content of illite/smectite mixed layers, followed by
444
illite, kaolinite, and finally chlorite (Table 3, Figure 7). Previous research has shown that
445
coal-bearing shale gas mainly occurs in free gas and adsorbed gas, accounting for more than 16
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45% each in the Turpan-Hami Basin.59 In shale gas exploration, the shale gas-bearing
447
capability affected by the clay mineral content and the reservoir fracturing property affected
448
by the quartz mineral content should both be considered for low-maturity continental shale
449
gas. Therefore, we need to find an optimal combination point of the clay mineral content or
450
quartz content and the gas-bearing property of the shale, which may not be at the point of the
451
highest gas value or the lowest brittle mineral content value. The important factor is that it can
452
reach the reservoir fracturing standard and gas-bearing standard of economical exploitation
453
and development. For the Xishanyao coal-bearing shale in the Taibei sag, the content of clay
454
minerals was negatively correlated with quartz content, and the content of clay minerals
455
decreased with the increase of quartz content (Figure 13). The negative correlation of
456
Xishanyao shale is slightly worse than that of Wufeng-Longmaxi shale, but is better than that
457
of Chang7 shale (Figure 13). Referring to the highest content of clay minerals in Chang7
458
shale and the lowest content of quartz in Wufeng-Longmaxi shale, the content of clay
459
minerals at the combination point is about 55% and quartz content is about 31%, which can
460
be used as the boundary of mineral composition for the favorable shale reservoir evaluation in
461
Xishanyao gas-bearing shale (Figure 13).
462
463 464 465 466 467
The BET SSA of Xishanyao coal-bearing shale in the Taibei sag (0.96-12.18 m2/g, with a
468
mean of 5.64 m2/g) is larger than that of the Chang 7 continental shale in the Ordos Basin
469
(0.25-4.4 m2/g, with a mean of 2.62 m2/g),6 which is less than that of the Silurian marine shale
470
of the Sichuan Basin (8.21-27.92 m2/g, with a mean of 17.29 m2/g),60 and that of the North
471
American shales (2.3-17.1 m2/g, with a mean of 10 m2/g).61,62 The pore volume of the
472
Xishanyao coal-bearing shale (4-36 μl/g, with an average of 18 μl/g) is larger than that of the
473
Chang 7 shale in the Ordos Basin (0.23-9.02 μl/g, with an average of 4.90 μl/g),6 and that of
Figure 13. Correlation between clay and quartz for different shales in China (Chang7: Jiang; Wufeng-Longmaxi: Hu).6,40
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474
the North American shales (2.99-50.26 μl/g, with an average of 5.32 μl/g),61,62 but
475
significantly lower than that of the Silurian marine shale of the Sichuan Basin (12.8-42 μl/g,
476
with an average of 30 μl/g).60 The above comparative analysis shows that the Xishanyao
477
coal-bearing shale has higher content of shale gas storage space and surface area than that of
478
Chang 7 continental shale in the Ordos Basin, but is lower than that of marine shales
479
generally.
480
The gas-bearing property is the most immediate index to evaluate the shale gas potential.
481
Total gas content of the coal-bearing shale ranges from 0.92 m3/t to 1.53 m3/t by field
482
desorption analyses in the Taibei sag,59 which is most close to that of Lew shale
483
(0.37-1.27m3/t). The TOC values of the tested samples are 1.58% and 2.14%. For the
484
successfully developed shale gas fields, the adsorbed gas content is usually proportional to the
485
TOC, such as Longmaxi shale gas in the southern Sichuan Basin of China.27,63 Therefore, the
486
total gas content is likely to be greater for coal-bearing organic rich shale with TOC values
487
greater than 2.14%, which can be compared with the successfully developed shale gas fields
488
(Table 4). Therefore, under certain economic and technical conditions, the coal-bearing shale
489
of the Xishanyao Formation with high OM richness can be targeted for shale gas exploitation.
490
5.3 Potential shale gas distribution
491
For the geological factors of coal-bearing shale gas enrichment in Taibei sag, we think
492
that the richness of OM and the degree of hydrogen enrichment are the most important
493
influencing factors. First, there is no obvious difference in the thermal maturity of
494
coal-bearing shales. Second, OM richness is the material basis that affects shale gas
495
generation ability, and it is also an important factor affecting the content of adsorbed gas in
496
shale. Third, in the process of hydrocarbon generation, carbon elements are often sufficient to
497
reach the final stage of hydrocarbon generation, and the hydrogen element is depleted.
498
Therefore, the degree of hydrogen enrichment of shale OM is another key factor affecting
499
shale gas enrichment, especially for coal-bearing shale. For source rock development,
500
previous studies show that the primary OM productivity and the redox conditions are the most
501
important factors for OM accumulation.64-66 Generally, a high productivity of original OM
502
and a partial reduction depositional environment are the necessary conditions for the
503
formation of high-quality source rocks in marine and lacustrine environments. In this paper,
504
the distribution of coal-bearing organic rich shale is discussed from the aspects of the redox
505
environment and the biological source composition of OM in coal-bearing shale.
506
It has been long recognized that the Pristane/Phytane (Pr/Ph) ratio can be used as an
507
indicator of redox conditions during or immediately after the deposition of OM.67,68 At the 18
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low-maturity stage, the Pr/Ph ratio values of the source rock is less than 1.0, which suggests
509
an anoxic condition with lower organism OM input, while values greater than 3.0 usually
510
indicate oxidizing conditions with terrigenous OM input.67,69 Pr/Ph is also affected by the
511
thermal evolution. The study of the experimental data shows that there is no obvious linear
512
correlation between the Pr/Ph ratio and the maturity parameters, such as Ro and C29 ααα20S/
513
(20S+20R) (Figure 14). Therefore, Pr/Ph ratio mainly reflects redox conditions and is less
514
affected by OM maturity in the study area. As shown in Table 1, the Pr/Ph ratio values of
515
coal-bearing shale samples range from 0.5 to 7.8, with an average of 3.1 in the Taibei sag,
516
suggesting that most of the coal-bearing shale formed under redox conditions during or
517
immediately after the deposition of the OM. The positive correlation between Pr/Ph and TOC
518
indicates OM accumulation in oxidizing-prone environments for the Xishanyao coal-bearing
519
shale (Figure 15A), which is different from tropical marine and lacustrine facies shale. A
520
positive correlation between the HI and the Pr/Ph ratio also indicates that an oxidizing-prone
521
environment favors the formation and accumulation of hydrogen-rich components (Figure
522
15B).
523
524 Fig 14. Correlations between Pr/Ph and Ro (A) and C29 ααα 20S/ (20S+20R) (B).
525 526 527
For the hydrogen-rich components and OM origin, the relative abundance of regular
528
steranes can be used as an indicator of the biological sources. It was found that both TOC and
529
HI were positively correlated with the relative content of regular C 29 sterane and negatively
530
correlated with the relative content of regular C27 sterane (Figure 16), which indicates that the
531
formation of coal-bearing shale with high TOC and high HI is closely related to the
532
environment in which terrestrial higher plants are mainly input with few lower organisms. In
533
other words, high TOC and HI shale often corresponds to higher Pr/Ph ratio values and C29
534
sterane content (Figure 15, 16). This environment corresponds to the deposition of coal seams
535
mainly in the swamps on the edge of the ancient lake basin. What is the geological reason for 19
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536
this phenomenon?
537
538 539 540
Figure 15. Variation of TOC (A) and HI (B) as a function of Pr/Ph of coal-bearing shale, in Taibei sag.
541
542 543 544 545 546
Figure 16. Correlations between TOC and αααRC29/R(C27-C29) (A) and ααα RC27/R(C27-C29) (B), HI and αααRC29/R(C27-C29) (C) and ααα RC27/R(C27-C29) (D).
In the Xishanyao coal measure strata, the shales and coal seams are often interbedded
547
with symbiotic development, and the development environment and OM components of the
548
shale are inherited from the coal seam to some level. Therefore, the relative development
549
environment of higher plants is more conducive to the accumulation of OM for coal-bearing
550
shale. In this environment, during and/or immediately after the deposition of the OM
551
sediments, the conditions became highly oxidizing, and the vitrinite and suberinite were 20
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decomposed in the oxidizing environment to form hydrogen-rich components.31 Wang and
553
Zhao has pointed out that most of the oil and gas resources found in the Taibei Sag are related
554
to coal measure source rocks, and the hydrocarbon is mainly distributed along the inner side
555
of the ancient lake Basin shoreline, which is also a favorable position for the development of
556
coal measure source rocks including coal-bearing shale.70 Therefore, coal-bearing shale gas
557
exploration is mainly aimed at the sedimentary facies zone on the margin and is not in the
558
center of the ancient lake basin. According to the evaluation of hydrocarbon source rocks for
559
shale gas considering the gas content, the OM richness of effective coal-bearing shale in
560
Taibei sag is limited to 1.5% (TOC). The thickness of effective coal-bearing shale is mainly
561
distributed in the range of 60-120m, with two thickness centers located in the Qiudong
562
sub-sag and Xiaocaohu sub-sag, respectively.
563
5.4 Other risk factors analysis
564
Although the above analysis shows that continental coal-bearing shale gas is a good
565
prospect for exploration and development, there are still risks in China. Compared with
566
marine shale, continental shale has many differences, such as rapid sedimentary phase change,
567
different enrichment process of OM and clay mineral dominated. For example, through the
568
analysis of experimental data, there is no definite relationship between the OM richness and
569
the content of quartz and clay minerals in coal-bearing shale. The shale with high OM
570
richness (TOC > 1.5%), the quartz content is both high and low, and the relationship between
571
the clay minerals and OM richness is similar to that of quartz (Figure 17), which increase the
572
uncertainty of exploration and development of continental coal-bearing shale gas.
573
574 575 576
Figure 17. Correlations between TOC and quartz (A) and clay (B).
577
With the development of shale gas, the important role of preservation conditions in shale
578
gas enrichment has been gradually recognized. For example, tectonic action is an important 21
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579
geological factor affecting shale gas enrichment for marine shale gas in Sichuan Basin.71,72
580
For Taibei sag, there are thick mudstone cap rocks in the Xishanyao Formation and Qiketai
581
Formation adjacent to the gas-bearing shale, which should be of positive significance to the
582
preservation of shale gas. However, faults in the Taibei sag are also relatively developed. In
583
conventional oil and gas geological evaluation, these faults can be used as hydrocarbon
584
migration channels if they communicate with source rocks and reservoirs. However, shale gas
585
prospects in faulted areas will have an increased exploration and development risk, which
586
should be thoroughly considered. Fortunately, coal-bearing shale gas is often interbedded with
587
coalbed methane and tight sandstone gas, which are other kinds of unconventional natural gas
588
resources in coal-bearing strata. Some scholars have suggested that cooperative exploration
589
and development of the above three types of unconventional natural gas reservoirs is an
590
important measure to reduce the economic risk of coal-bearing shale gas.
591
CONCLUSIONS
592
(1) The Xishanyao Formation coal-bearing shale has a relatively high OM richness from
593
TOC, S1+S2 and asphalt “A” experimental data, the OM is dominantly type III kerogen, with
594
thermal maturity at immature-low maturity stage based on the Ro and biomarker parameters.
595
Gas-prone kerogens can form low-maturity gas at the low-maturity stage, which is an
596
important material basis for shale gas reservoirs formation.
597
(2) The mineral composition of coal-bearing shale in the Xishanyao Formation is
598
dominated by clay minerals followed by quartz, calcite, and plagioclase, and clay as a plastic
599
mineral has a high content, which average 50.3% of the bulk mineral composition. The clay
600
minerals consisted of illite/smectite mixed layers, illite, kaolinite and chlorite, ordered by
601
decreasing content.
602
(3) Based on SEM and CT scanning, microfractures and micropores are developed in the
603
Xishanyao shale, and the micropores have poor connectivity compared with the
604
microfractures. The micropores provide the main space for shale gas storage with mean
605
diameters ranging from 10.2 nm to 18.1 nm and BET SSA averaging 5.64 m 2/g and BJH SSA
606
averaging 6.71 m2/g; the hysteresis loops are dominated by type H3, which indicates that the
607
pore structure is complex and pores are mainly open pores.
608
(4) The Xishanyao Formation shale has good low-maturity gas generation conditions
609
compared with other shale, and the deeper burial depth and high clay content are considered
610
to be the main unfavorable factors. However, the distribution of favorable shale in coal
611
measures is different from that of lacustrine shale, which is mainly distributed in the margin 22
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612
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of the ancient lake basin and is symbiotic with coal seams.
613 614
AUTHOR INFORMATION
615
Corresponding Authors:
616 617 618
*Corresponding author: Zhilong Huang. Present address: No.18, FuXue Road, Changping, Beijing, China, 102249. E-mail:
[email protected]. *Corresponding author: Xiujian Ding. Present address: No. 66, Changjiang West Road,
619
Huangdao District, Qingdao, China, 266580. Email:
[email protected].
620
Author Contributions
621
The manuscript was written by the contributions of all the writers. All the authors agreed
622
to the final revision.
623
Notes
624
The authors declare no competing financial interest.
625 626 627
ACKONWLEDGMENTS We thank PetroChina Tuha Oilfield Company for providing samples. This paper was
628
supported by the Natural Science Foundation of Shaanxi Province (2017JQ4004, 2017JQ4013),
629
the National Natural Science Foundation of China (41702127), the Special Foundation of the
630
Shaanxi Provincial Education Department (17JK0596), and the National Science and
631
Technology Major Project of China (2017ZX05039001).
632 633
REFERENCE
634 635 636 637 638 639 640 641 642 643 644 645 646 647 648 649 650
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Table 1. Total organic carbon content (TOC), Rock-Eval pyrolysis, element composition of kerogen, bitumen “A” and vitrinite reflectivity (Ro) data for the Xishaoyao shale samples Well ID
Depth (m)
TOC (%)
S1 (mg HC/g)
S2 (mg HC/g)
Tmax (℃)
HI (mg HC/g TOC)
H/C
O/C
"A" (%)
Ro (%)
DB2 DS1 DS1
3657.1 3684.1 3687
1.97 1.63 5.68
0.12 0.58
2.47 7.01
438 438
152.0 123.4
0.52 0.77 0.71
0.06 0.05 0.07
0.02 0.11 0.35
0.79 0.43 0.61
DS1 DS1
3871.4 3876.9
4.22 1.25
0.56 0.06
14.80 0.91
439 441
350.6 73.0
0.88 0.73
0.05 0.07
0.22 0.09
0.60 0.44
G17 G18
2932.6 3684.4
1.47 3.21
0.07 0.42
0.90 6.04
444 450
61.4 188.5
0.69 1.00
0.07 0.11
0.09 0.23
0.57 0.59
H3 Hq3
2560.5 3229.6
2.92 2.78
0.25 0.07
8.07 1.19
441 451
276.7 42.8
1.22 0.93
0.16 0.14
0.28 0.07
0.42 0.64
Ht21 N1
3548.6 3415.8
1.10 2.25
0.01 0.15
0.59 1.98
448 441
53.5 88.0
0.54 0.78
0.06 0.10
0.03 0.10
0.50 0.64
N11 N2
3841.9 3224.3
2.84 1.32
0.07 0.02
11.23 0.45
439 442
395.4 34.1
1.19 0.63
0.12 0.08
0.13 0.05
0.45 0.31
N2 Ns1
3224.8 3371.5
1.58 0.64
0.11 0.04
3.23 0.31
438 449
204.9 48.3
0.77 0.71
0.08 0.12
0.05 0.02
0.32 0.32
Ns1 Ns1
3573 3780.5
0.75 4.44
0.03 0.19
0.34 7.73
448 441
45.3 174.0
1.63 0.76
0.39 0.07
0.02 0.14
0.31 0.37
Ns1 B21
3783.3 3059.5
1.19 1.75
0.05 0.18
0.66 2.18
440 441
55.5 124.4
0.69 0.83
0.08 0.08
0.06 0.14
0.38 0.34
B23 B23
3286.4 3288.5
1.82 1.03
0.12 0.09
1.00 1.15
444 433
55.1 112.2
0.75 0.83
0.11 0.10
0.09 0.09
0.38 0.81
B13 B13
2930.9 2931.7
5.84 0.72
0.60 0.03
9.44 0.59
439 440
161.7 82.5
0.82 1.35
0.11 0.26
0.14 0.01
0.49 0.59
B13 B3
2936.3 3176.5
1.85 4.81
0.10 0.15
0.59 6.65
479 441
31.8 138.1
1.05 0.92
0.22 0.16
0.03 0.18
0.53 0.47
L4 L4
3954.2 3955.1
2.02 0.78
0.05 0.01
1.10 0.12
437 438
54.5 15.5
0.71 0.59
0.10 0.08
0.06 0.03
0.43 0.44
L4 L4
3959.6 3959.8
1.86 3.25
0.05 0.21
2.24 5.21
438 436
120.3 160.1
0.82 0.93
0.09 0.10
0.11 0.19
0.68 0.62
Tc2 Tc2
5001.8 5004.5
1.15 1.06
0.09 0.11
0.59 0.40
449 457
51.3 37.7
0.88 0.56
0.11 0.05
0.04 0.06
0.42 0.41
B15 B3
2793.5 3014
0.93 0.45
0.03 0.05
0.39 0.22
437 457
41.8 49.0
0.73 0.69
0.13 0.10
0.03 0.03
0.66 0.36
B7
2921.5
0.77
0.07
0.60
433
78.0
1.05
0.20
0.05
0.37
863 864 865 28
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Energy & Fuels
Table 2. Saturated hydrocarbon gas chromatography-mass spectrometry parameters data for the Xishaoyao shale samples Well ID
Depth (m)
Pr/Ph
C27 steranes (%)
C28 steranes (%)
C29 steranes (%)
C29 ααα20S/(20S+20R)
C29 ββ/(ββ+αα)
DB2
3657.10
0.49
0.35
0.19
0.45
0.44
0.40
DS1
3684.10
4.66
0.07
0.21
0.73
0.44
0.27
DS1
3687.00
2.69
0.14
0.26
0.61
0.52
0.44
DS1
3871.40
4.66
0.10
0.22
0.68
0.37
0.39
DS1
3876.90
2.02
0.20
0.26
0.54
0.46
0.44
G17
2932.60
1.91
0.09
0.23
0.68
0.46
0.28
G18
3684.40
1.95
0.21
0.29
0.50
0.43
0.47
H3
2560.50
3.40
0.15
0.23
0.63
0.47
0.38
Hq3
3229.60
3.81
0.11
0.18
0.71
0.47
0.30
Ht21
3548.60
1.30
0.26
0.24
0.50
0.52
0.40
N1
3415.80
3.37
0.12
0.20
0.68
0.44
0.23
N11
3841.88
4.42
0.11
0.20
0.69
0.50
0.30
N2
3224.30
1.32
0.13
0.24
0.63
0.41
0.29
N2
3224.80
3.88
0.30
0.21
0.49
0.43
0.28
Ns1
3371.50
1.13
0.43
0.26
0.31
0.48
0.44
Ns1
3573.00
2.16
0.32
0.24
0.45
0.48
0.31
Ns1
3780.50
7.79
0.06
0.26
0.68
0.47
0.26
Ns1
3783.30
3.35
0.37
0.15
0.47
0.49
0.33
B21
3059.50
2.09
0.13
0.21
0.66
0.52
0.45
B23
3286.40
3.14
0.10
0.24
0.66
0.44
0.28
B23
3288.50
2.79
0.13
0.23
0.63
0.46
0.30
B13
2930.90
5.05
0.08
0.18
0.74
0.46
0.22
B13
2931.70
0.95
0.25
0.35
0.39
0.55
0.32
B13
2936.30
1.40
0.16
0.18
0.67
0.46
0.24
B3
3176.50
3.33
0.12
0.24
0.64
0.47
0.39
L4
3954.20
7.33
0.10
0.29
0.61
0.47
0.27
L4
3955.10
1.59
0.24
0.33
0.43
0.46
0.32
L4
3959.60
3.89
0.10
0.19
0.71
0.49
0.28
L4
3959.80
3.00
0.14
0.23
0.63
0.50
0.28
Tc2
5001.80
4.83
0.12
0.22
0.66
0.48
0.38
Tc2
5004.50
4.48
0.07
0.23
0.70
0.45
0.35
B15
2793.50
1.83
0.12
0.21
0.66
0.40
0.38
B3
3014.00
2.21
0.17
0.27
0.56
0.48
0.41
B7
2921.50
3.21
0.15
0.27
0.58
0.44
0.39
868 869
Table 3. Mineral compositions of Xishaoyao shale samples Mineral content of the bulk mineral composition (%)
Well ID
Depth (m)
Cla
Qtz
Fel
DB2 DS1 DS1 DS1 DS1 G17 G18 H3
3657.1 3684.1 3687.0 3871.4 3876.9 2932.6 3684.4 2560.5
51 43 44 49 47 44 48 45
40 38 35 41 37 34 33 39
9 19 21 7 12 13 16 16
Cal -
Sid 3 4 9 3 -
Ana -
29
ACS Paragon Plus Environment
Clay minerals (%) Kln
Chl
Ill
I/S
16 20 17 25 34 16 17
13 19 12 10 11 3 12
16 30 27 32 20 31 42 34
55 31 44 33 46 42 55 37
Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
870
871 872 873 874
Table 3. (Continued) Well ID
Depth (m)
Mineral content of the bulk mineral composition (%) Cal Sid Ana Cla Qtz Fel
Hq3 Ht21 N1 N11 N2 N2 Ns1 Ns1 Ns1 Ns1 B23 B23 B13 B13 B13 B3 L4 L4 L4 L4 Tc2 Tc2
3229.6 3548.6 3415.8 3841.9 3224.3 3224.8 3371.5 3573 3780.5 3783.3 3286.4 3288.5 2930.9 2931.7 2936.3 3176.5 3954.2 3955.1 3959.6 3959.8 5001.8 5004.5
60 51 42 67 45 52 48 49 52 52 47 46 63 48 55 58 61 71 69 50 78 50
35 40 43 29 42 39 36 36 46 41 34 40 26 39 39 31 39 29 30 45 19 40
2 2 1 2 2 2 3 10
-
5 7 15 4 11 7 16 15 1 3 19 12 7 9 5 9 -
2 -
3 -
2 1 3 2 1 2 1 2 -
Clay minerals (%) Kln
Chl
Ill
I/S
7 16 16 16 25 21 32 12 49 29 17 26 34 26 20 24 52 47 34 40 5 19
10 12 15 10 17 15 14 11 12 12 17 7 23 22 16 20 5 9
14 16 35 26 18 23 25 23 15 24 15 30 5 6 8 10 4 2 16 16 26 27
69 56 34 48 40 41 29 54 36 35 56 27 61 68 72 59 21 29 34 24 64 45
Cla: Clay minerals; Qtz: Quartz; Fel: Feldspar; Cal: Calcite; Sid: Siderite; Ana: Analcite; Kln: Kaolinite; Chl: Chlorite; Ill: Illite; I/S: Illite/Smectite mixed layers Table 4. Pore volume and specific surface area calculates by N2 adsorption branch for c shale samples Sample NO.
875 876
Page 30 of 30
Depth (m)
BET-SSA (m2/g)
BJH-SSA (m2/g)
BJH pore volume (μl/g)
Mean diameter (nm)
T1
Well ID Ns1
3697.8
3.54
4.24
10
11.0
T2
Ns1
3781.9
4.17
5.03
11
10.2
T3
Ns1
3782.6
0.96
1.56
4
14.0
T4
Q2
2258.5
12.18
12.71
36
11.8
T5
N5
3889.1
5.67
6.23
26
18.1
T6
Ht21
3547.2
7.32
10.47
24
12.3
Table 5. Key parameters of Xishanyao shale and other major gas shale in China and America 6, 47-52 ID name
Shale name
Basin
Depositional setting
Burial depth (m)
TOC (%)
Ro (%)
Kerogen type
Gas content (m3/t)
1 2 3 4 5 6 7 8
Barnett Ohio Antrim New Albany Lewis Wufeng-Longmaxi Yanchang Xishanyao
Fort Worth Appalachian Michigan Illinois San Juan Sichuan Ordos Turpan-Hami
Marine Marine Marine Marine Marine Marine Continental Continental
1981~2591 610~1524 183~730 183~1494 914-1829 900~4500 500~2000 2500~5000
3.0-13.0 0-4.7 0.3-24.0 1.0-25.0 0.45-3.0 1.5-6.0 1.8-6.3 0.45-5.84
1.0-1.3 0.4-1.3 0.4-0.6 0.4-1.0 1.6-1.88 1.5-3.5 0.6-1.25 0.3-0.8
II I-II I II III I-II I-II III
8.49-9.91 1.70-2.83 1.13-3.50 1.13-2.64 0.37-1.27 1.30-6.30 2.43-6.45 0.90-1.50
877
30
ACS Paragon Plus Environment