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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

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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

ACS Paragon Plus Environment

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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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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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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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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).

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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

289

connectivity in the CT scanning images (Figure 8E). In addition, high-density minerals, such

290

as quartz and feldspar, are uniformly distributed in the shale (Figure 8F), which play an

291

important role in the formation of micro-fractures.

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293 294 295 296 297 298 299

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).

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The Low-pressure N2 adsorption-desorption branches have been used to analyze PSD by

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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


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

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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Energy & Fuels

333

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


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

360

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


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

420

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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446

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

17


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

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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Energy & Fuels

508

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


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

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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Energy & Fuels

552

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


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

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

Energy & Fuels

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


Page 29 of 30 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

866 867

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Table 2. Saturated hydrocarbon gas chromatography-mass spectrometry parameters data for the Xishaoyao shale samples Well ID

Depth (m)

Pr/Ph

C27 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


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


Characterization of continental coal-bearing shale ... - ACS Publications

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