An experimental study of organic matter, minerals and porosity evolution in shales within high-temperature and high-pressure constraints

Accepted Manuscript High-temperature and high-pressure experimental constraints on the evolution of organic matter, minerals, and porosity in shales Songtao Wu, Zhi Yang, Xiufen Zhai, Jingwei Cui, Lushan Bai, Songqi Pan, Jinggang Cui PII:

S0264-8172(18)30544-0

DOI:

https://doi.org/10.1016/j.marpetgeo.2018.12.014

Reference:

JMPG 3633

To appear in:

Marine and Petroleum Geology

Received Date: 14 June 2018 Revised Date:

28 November 2018

Accepted Date: 6 December 2018

Please cite this article as: Wu, S., Yang, Z., Zhai, X., Cui, J., Bai, L., Pan, S., Cui, J., High-temperature and high-pressure experimental constraints on the evolution of organic matter, minerals, and porosity in shales, Marine and Petroleum Geology (2019), doi: https://doi.org/10.1016/j.marpetgeo.2018.12.014. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

ACCEPTED MANUSCRIPT 1

High-temperature and high-pressure experimental constraints on the evolution of organic

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matter, minerals, and porosity in shales

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Songtao Wu*a,b,c, Zhi Yanga, Xiufen Zhaia,b,c, Jingwei Cui a,b,c, Lushan Baid, Songqi Pana, Jinggang

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Cuia,b,c

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a

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PR China

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National Energy Tight Oil and Gas R&D Center, Beijing 100083, PR China

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Key Laboratory of Oil and Gas Reservoir, CNPC, Beijing 100083, PR China

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d

Liaohe Oilfield, CNPC, Panjin, Liaoning Provinece 124000, PR China

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Research Institute of Petroleum Exploration and Development (RIPED), CNPC, Beijing 100083,

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Abstract

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The development and evolution of porosity in organic-rich shales (ORSs) is critical to the

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commercial exploitation of shale oil and gas resources. In this paper, we present the results of

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high-temperature and high-pressure experiments on typical marine and lacustrine shales to

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investigate porosity changes. The samples were taken from the Proterozoic Xiamaling Formation in

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the North China Platform, the Permian Lucaogou Formation in the Junggar Basin, the Triassic

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Chang 7 member in the Ordos Basin, and the Silurian Longmaxi Formation in the Sichuan Basin,

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all in China. We found that the key factors influencing porosity evolution include the extent of

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compaction, abundance of organic matter, degree of thermal evolution, and organic matter–

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inorganic mineral framework. The effects of thermal evolution on the pore structure of high-mature

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shales are more obvious than those on low-mature shales. Although the porosity evolution is

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positively correlated with maturity, we found evidence for different porosity evolution in ORSs in

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the oil window. High-resolution scanning electron microscopy observations of experimental and

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ACCEPTED MANUSCRIPT actual core samples indicate that liquid hydrocarbon is adsorbed and dissolved in organic matter in

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the oil window, leading to swelling of the organic material. This explains why there are few organic

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matter pores in lacustrine shales in China. The pore structure evolution is similar for marine and

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lacustrine shales, suggesting that kerogen has a stronger influence on the porosity evolution of shale

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than does the depositional environment. The lower limit of vitrinite reflectance values (Ro) at which

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abundant organic pores develop is 1.5%–2.5%, and the degree of pore development in ORSs is

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highest when Ro values are 2.5%–3.0%. These results have important implications for shale oil and

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gas exploration.

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Keywords: Organic matter; porosity evolution; organic–inorganic interaction; unconventional

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petroleum geology; shales

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1 Introduction

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The successful exploration for and development of shale oil and gas resources has expanded the

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traditional “source–caprock” hydrocarbon system to the “source–reservoir–caprock” system and, as

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such, the hydrocarbon storage capacity of shales has become an important research topic. Numerous

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studies have investigated shale reservoir space using scanning electron microscopy (SEM),

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nanometer computed tomography (CT), gas adsorption, high-pressure Hg injection, and other

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methods, which have advanced our understanding of the types, sizes, shapes, space distribution, and

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connectivity of shale pores (Katsube et al., 1993; Javie et al., 2007; Daniel and Marc, 2009; Loucks

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et al., 2009, 2012; Joel et al., 2011; Sondergeld et al., 2011; Chalmers et al., 2012; Zou et al., 2012,

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2017; Cao et al., 2015; Klaver et al., 2015; Wu et al., 2015, 2016; Yang et al., 2016). Moreover,

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these studies have proposed that organic pores are a unique pore type in shale reservoirs. Given this,

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research has focused on the pore systems in organic-rich shales (ORSs). Unlike pore evolution in

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ACCEPTED MANUSCRIPT conventional sandstone reservoirs, which is driven mainly by diagenesis, the pore evolution in

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shales is controlled by both hydrocarbon generation and diagenesis (Jarvie et al., 2007; Cui et al.,

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2013; Hu et al., 2013; Wu et al., 2015). According to the nature of the host, pores in shales are

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divided into organic, clay mineral, and non-clay mineral pores (Loucks et al., 2010; Wu et al., 2015,

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2016; Zou et al., 2017). Organic pores are unique to ORSs and are the major influence on pore

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evolution in these source rocks.

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Experimental and SEM imaging methods are commonly used to investigate pore evolution in shales.

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The main unresolved issue concerns the progressive development of pores with increasing thermal

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evolution. Numerous studies have proposed that the number of organic pores increases with the

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degree of thermal evolution of organic matter in shale (Schieber, 2010; Jarvie et al., 2012), although

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Curtis et al. (2011) showed that the size and proportion of organic pores decreased with increasing

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vitrinite reflectance values (Ro) in the Marcellus shale of North America. Fishman et al. (2012)

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demonstrated that the size and number of organic pores does not increase obviously with increasing

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Ro in the Kimmeridge shale from the UK. Passey et al. (2012) and Mastalerz et al. (2013) proposed

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that organic pores begin to form when Ro = 0.7%, compared with a value of 1.2% proposed by

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Berthonneay et al. (2012), Cui et al. (2013) and Wu et al. (2015). The evolution of shale pores

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remains debated, with two main views having been proposed: (1) porosity first increases and then

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remains constants with thermal evolution (Fishman et al., 2012; Hu et al., 2013; Mastalerz et al.,

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2013; Wu et al., 2015); and (2) porosity first increases and then decreases with thermal evolution

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(Curtis et al., 2011; Cui et al., 2013).

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Previous studies have conducted preliminary research on the factors controlling pore evolution in

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shales. Kennedy et al. (2002, 2011) used the EGME (Ethylene glycol monoethyl ether) chemical

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adsorption method to determine the specific surface area of minerals in low-mature shale, and

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ACCEPTED MANUSCRIPT showed that the organic matter content is strongly positively correlated to the specific surface area

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of clay-sized minerals, and that the specific surface area decreases with thermal maturity. Katsube

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et al. (1993) proposed that initial porosity is controlled by the size and number of deposited

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particles, clay mineral composition, and sedimentary depositional environment. Subsequently, the

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pore size is reduced due to sedimentary compaction and cementation, and the porosity is increased

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due to hydrocarbon generation, acid discharge, and dissolution of organic material. Loucks et al.

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(2012) proposed that the porosity loss caused by compaction reaches 83%–88% and that when the

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burial depth exceeds 2.5 km and the shale porosity is <10%, new pores will be formed due to

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hydrocarbon generation and late dissolution. Modica et al. (2012) considered that the evolution of

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shale pores is controlled mainly by the thermal evolution of kerogen, and has little relationship with

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the evolution of matrix mineral pores. Cui et al. (2013) and Mastalerz et al. (2013) proposed that the

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evolution of shale pores is controlled by the interactions among hydrocarbon generation,

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mechanical compaction, and chemical compaction. Most studies have shown that for mature

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samples, the specific surface area increases with higher total organic carbon (TOC) contents,

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whereas for low-mature samples, the relationship between specific surface area and TOC contents is

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not clear (Curtis et al., 2011; Javie et al., 2012). In summary, hydrocarbon generation and

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diagenesis are probable the key factors controlling the evolution of shale pores.

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Notably, most previously published studies have been undertaken on a single shale sample (Cui et

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al., 2013; Hu et al., 2013; Wu et al., 2015), and the potentially contrasting pore evolution of marine

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and lacustrine shales deposited in different environments has yet to be investigated. As such, we

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undertook a comprehensive investigation of the evolution of organic matter–inorganic minerals–

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pores in various marine and lacustrine ORSs. Our studied samples include those from the

ACCEPTED MANUSCRIPT Proterozoic Xiamaling Formation in the North China Platform (NC-Ptx), the Permian Lucaogou

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Formation in the Junggar Basin (JB-P2l), the Triassic Chang 7 member in the Ordos Basin

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(OB-T3y7), and the Silurian Longmaxi Formation in the Sichuan Basin (SB-S1l), all in China. We

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carried out high-temperature and high-pressure experiments on the samples and CT measurements

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and SEM imaging. By comparing the experimentally modified and original geological samples

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using image analysis, gas adsorption, X-ray diffraction (XRD), and rock pyrolysis techniques, we

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were able to quantitatively characterize the pore evolution, determine the key factors controlling the

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pore evolution, and contribute to the identification and evaluation of favorable shale reservoirs.

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2 Experimental methods and samples

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2.1 Samples

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The samples subjected to high-temperature and high-pressure experiments include the marine

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NC-Ptx and lacustrine JB-P2l and OB-T3y7 low-mature ORSs (Ro < 0.7%, TOC > 2.2%, and type II

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kerogen; Table 1). Besides these samples, we also investigated actual geological samples with

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different Ro from the marine SB-S1l and lacustrine JB-P2l and OB-T3y7 ORSs (34 samples in total;

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Table 2) for comparation. Figure 1 shows the sample locations.

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2.2 Experimental methods and conditions

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2.2.1 High-temperature and high-pressure experiments

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The experimental system developed by the China National Petroleum Corpration (CNPC ) Key

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Laboratory of Oil and Gas Reservoirs located in Beijing of China is used to investigate the

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evolution of shale pores under a range of geological conditions under controlled pressure and

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temperature (Fig. 2). Initial high-temperature experiments on various types of shale samples

ACCEPTED MANUSCRIPT revealed that the degree of thermal evolution is positively correlated with the experimental

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temperature and, at a given temperature, the measured Ro is the same in all samples with a standard

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error of <0.5% (Fig. 2). Therefore, in our experiments the set temperature points were 350, 450,

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and 550°C, with corresponding Ro of 1.0%–1.5% (mature–high-mature), 2.0%–2.5% (over-mature),

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and 2.5%–3.0% (over high-mature). The experimental pressures were set based on the burial depths

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of the samples. For the marine NC-Ptx and lacustrine JB-P2l and OB-T3y7 ORSs, the lithostatic

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pressures are 70, 80, and 90 MPa, respectively.

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The experimental procedures were as follows. (1) Sample preparation, three-dimensional nanometer

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CT scanning, and two-dimensional high-resolution field-emission SEM (FE-SEM) imaging to

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constrain the two- and three-dimensional pore throat system in the initial state. (2) Samples were

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placed in the high-temperature reaction furnace, heated to 350°C, and cooled to a constant

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temperature over 8 h. The nanometer CT scanning and FE-SEM imaging were then repeated. (3)

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Step (2) was repeated at temperatures of 450°C and 550°C.

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Prior to the experiments, 600 g of primary sample was ground to a particle size of 0.15 mm (100

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mesh). From this, 450 g of powdered sample and the intact nanometer CT sample were place in the

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high-temperature reaction furnace. Approximately 150 g of powdered sample was successively

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removed after each heating step. The powder samples, including the 150 g not subjected to the

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high-temperature and high-pressure experiments, were subjected to rock pyrolysis, gas adsorption,

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and XRD analysis. Finally, three-dimensional analysis software was used to process the four sets of

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nanometer CT data.

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2.2.2 Two- and three-dimensional imaging of pore structure

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A Helio Nano-Lab 650 FE-SEM was used to image the two-dimensional shale pore structure.

ACCEPTED MANUSCRIPT Samples were coated with carbon after mechanical and argon ion polishing. The imaging voltage

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was 1–2 kV. For three-dimensional nanometer CT scanning, we used an UltraXRM-L200 (Xradia)

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stereoscopic microscope. This instrument operates at 8 keV and uses the X-ray optical lens

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microscopic imaging technique, which results in ultrahigh-resolution, non-destructive stereoscopic

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imaging. It can be used for non-destructive imaging of the microscopic pore throat system of shales.

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The nanometer CT scanning was undertaken at a test temperature of 20°C and used an exposure

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time of 120 s for a single image. The number of images collected was 1601, and the total scanning

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time was ~54 h per sample.

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2.2.3 Quantitative analysis

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The quantitative pore evaluation was undertaken primarily with an ASAP2020 specific surface area

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analyzer on the basis of nitrogen adsorption experimental results. These experiments were

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performed according to the determination of the specific surface area of solids by gas adsorption

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using the Brunauer-Emmett-Teller (BET) method (Wei et al., 2004). The quantitative analysis of

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pore structure was conducted on the basis of the pore volume obtained from the desorption curve

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determined by Barret–Joyner–Halenda (BJH) theory. Three-dimensional analysis software was used

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to process the nanometer CT pore data and determine the porosity, pore surface area, and pore

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volume. TOC content, rock pyrolysis, and XRD mineral analysis were carried out in the CNPC Key

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Laboratory of Geochemistry and CNPC Key Laboratory of Oil and Gas Reservoirs which are

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located in Beijing, China. Determination of TOC contents and rock pyrolysis and XRD analysis

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followed the methods of Wu et al. (2001), Xu et al. (2003) and Zeng et al. (2010).

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3 Results and discussion

ACCEPTED MANUSCRIPT 3.1 Three-dimensional nanometer CT results

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The nanometer CT results show that the three types of shales have a similar pore evolution, as

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follows: (1) with increasing maturity, the pore development gradually increased at different rates

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among the samples; and (2) the pore throat size and development showed a pronounced increase

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from the original samples to 350°C and then to 450°C, with a small increase from 450°C to 550°C

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(Fig. 3; Table 1).

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There is a difference in the increasing pore development in the three types of samples. The increase

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in the JB-P2l samples is the most obvious. In these samples, the pore area calculated on the basis of

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the three-dimensional model increased from 2620 to 20,932 µm2, pore volume increased from 204

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to 2150 µm3, and calculated porosity increased from 0.62% to 6.58% (Table 1; Fig. 3B1–B8). The

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OB-T3y7 pore system increased the least, with a four-fold volume increase (Table 1; Fig. 3A1–A8).

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The pore volume of SB-Ptx had a five-fold increase (Table 1; Fig. 3C1–C8). In general, with

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increasing pore evolution the overall connectivity of the pore throat system gradually increased (Fig.

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3A5–A8, B5–B8, and C5–C8).

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3.2 Liquid nitrogen adsorption results

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The quantitative evaluation of shale pore structure was conducted by liquid nitrogen adsorption

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techniques, with an effective testing range of 2–100 nm (Wu et al., 2016). With increasing

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temperature, both the BET specific surface area and pore volume of the three types of shale

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increased (Table 1). For JB-P2l, the BET specific surface area increased from 7.17 m2/g (350°C) to

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12.77 m2/g (450°C) and to 11.93 m2/g (550°C) from the original sample value (2.93 m2/g). The

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specific pore volume gradually increased from 0.0432 cm3/g (350°C) to 0.0849 cm3/g (450°C) and

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to 0.0867 cm3/g (550°C) from the original sample value (0.018 cm3/g) (Table 1; Fig. 4). Samples

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OB-T3y7 and NC-Ptx showed similar trends. In general, the increase in JB-P2l shale pores is clearly

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ACCEPTED MANUSCRIPT larger than those of the other two shale samples (Fig. 4), which is consistent with the nanometer CT

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results.

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The pore volume changes show that the key temperature range for shale pore evolution is 350–

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450°C, with corresponding Ro = 1.5%–2.5% (i.e., the pyrolysis gas generation stage). At this range,

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the pore size in the three types of shale generally increased by 1.5 to 2.5 times. This indicates that

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the main population of pores formed at this temperature, and that kerogen and chloroform bitumen

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pyrolysis are critical in the development of nanopores.

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3.3 Evolution of organic matter and inorganic minerals

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The pore evolution in ORSs is affected by mineral composition, organic material, diagenetic fluids,

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temperature, pressure, and other factors, reflecting the combined interaction of organic material and

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inorganic minerals. In this study, the organic and mineral composition of the three types of ORSs

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changed obviously during the experiments. In the NC-Ptx marine shale, increasing temperature

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reduced the TOC content to 0.18% from 6.8%, the (S1+S2) (According to Peters (1986), S1 is a

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measurement of the free hydrocarbons present in the sample before analysis, whereas S2 is the

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volume of hydrocarbons that formed during thermal pyrolysis of the sample) value to 0.09 mg/g

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from 32.85 mg/g, and the sulfur content to 0.05% from 0.24%, showing that organic material was

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strongly pyrolyzed. XRD mineral analysis results indicate that the clay content increased to 68.6%

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from 46.2%, the relative illite content increased to 91% from 51%, the mixed-layer illite–smectite

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ratio decreased to <10% from 30%, and the content of quartz and feldspar increased (Table 1),

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indicating that inorganic minerals were transformed.

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3.3.1 Organic pores

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Organic pores are formed during the thermal evolution of shales. The most direct expression of

ACCEPTED MANUSCRIPT increasing thermal evolution is that hydrocarbon components are pyrolyzed, aromatized, and

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adsorbed. In addition, amorphization occurs on macerals, producing hydrocarbon fluids. All these

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processes change the volume of organic material, thus forming organic pores, which are the main

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reservoir space and migration pathways of liquid hydrocarbons and natural gases (Chen and Xiao,

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2014; Kuila et al., 2014; Li et al., 2015; Wu et al., 2015). It is widely considered that with

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increasing thermal evolution, organic pores gradually develop and increase in abundance (Mastalerz

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et al., 2013; Cui et al., 2013; Kuila et al., 2014; Wu et al., 2015). In our experiments, the formation

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of organic pores did not increase gradually, but instead showed a multi-stage evolution (Fig. 5). The

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pores first increased, then decreased, and then increased again, before finally becoming relatively

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stable. Such a trend occurred in all three types of shale (Fig. 5A1–D4). In the following, we take

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NC-Ptx shale as an example for describing these trends (Fig. 5C1–C4). The maturity of the original

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NC-Ptx sample is only 0.48%, which is in the non-mature stage and, as such, organic pores are not

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developed. When the temperature reached 250°C (Ro = 0.7%), oil and gas were produced due to

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pyrolysis, leading to the formation of organic pores (Fig. 5C2). When the temperature reached

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300°C (Ro = 1.0%), both the organic pore volume and diameter showed a decreasing trend (Fig.

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5C3). When the temperature reached 350°C (Ro = 1.5%), the volume of organic pores increased (Fig.

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5C4), and as the temperature was further increased to 450–550°C the size of the organic pores first

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increased and then remained constant (Fig. 5).

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We propose that the decrease in organic pores when Ro = 1.0% is related to the swelling of organic

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material during hydrocarbon generation. From the immature to low-mature stage, organic material

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begins to be pyrolyzed and generate hydrocarbons, and the volume of solid kerogen decreases,

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forming long and narrow pores between organic material and the mineral matrix. Subsequently, in

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the oil generation window, hydrocarbon generation intensifies, but the main product is liquid

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ACCEPTED MANUSCRIPT hydrocarbons. The liquid hydrocarbons are adsorbed on the surface of organic material, resulting in

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swelling, and the volume of organic material increases, leading to a decrease in the size of the long

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and narrow pores between organic material and the mineral matrix.

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Although some studies have previously proposed this process (e.g., Zou et al., 2017), it has not been

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widely accepted. Our research provides the first direct evidence for the swelling of organic material.

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We observed the generation of liquid hydrocarbons and their dissolution and adsorption onto the

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surface of organic material during hydrocarbon generation. For the JB-P2l and OB-T3y7 shales, with

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increasing temperature we observed that liquid hydrocarbons formed inside the organic material and

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migrated outwards, and the volume of organic material increased (Figs 5A3, 5B3, and 6A–F),

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whereas in the NC-PtX shale we observed the formation of oil droplets (Fig. 6G–I).

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The actual geological samples also provide evidence that the pore size is reduced by the swelling of

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organic material. SEM observations of the JB-P2l shale revealed differences in grayscale values

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inside organic material (Fig. 7A), reflecting variable carbon contents (Fig. 7B). We also extracted

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the hydrocarbons in these samples with dichloromethane and ultrasonication, and conducted SEM

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analysis on the samples. After hydrocarbon extraction, new pores appeared inside the organic

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material and surrounding minerals (Fig. 7C–F), which indicated that adsorption and dissolution of

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liquid hydrocarbons on the surface of the organic material had occurred in the oil generation

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window (Fig. 7D, F). This also explains why organic pores are not developed and why the shale

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shows poor reservoir properties in the oil window (Chalmer et al., 2012; Passey et al., 2012; Wu et

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al., 2015, 2016; Zou et al., 2017).

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TOC contents are also a key factor influencing the development of organic pores. Higher TOC

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contents result in greater hydrocarbon generation and pore formation. For the three ORSs, the final

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porosities after the experiments were different, owing to variable TOC contents. The TOC content

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of JB-P2l shale is the highest, followed by that of NC-Ptx shale, and that of OB-T3y7 shale, which

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explains the highest porosity of the JB-P2l shale and lowest porosity of the OB-T3y7 shale (Table 1;

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Fig. 3).

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3.3.2 Rearrangement and transformation of clay minerals

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Clay minerals are closely related to organic material (Kennedy et al., 2002, 2014; Cai et al., 2007;

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Kennedy and Wagner, 2011; Lohr and Kennedy, 2014). During thermal evolution, clay minerals are

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rearranged and readily transformed, with the transformation from smectite to illite being the most

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important (Theng, 1979; Yariv and Cross, 2002; Wang et al., 2006; Li and Cai, 2014). This process

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is directly related to hydrocarbon generation. Previous studies have shown that the catalytic activity

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of natural clay is minor, but is strengthened by treatment with weak organic or inorganic acid

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(Wang et al., 2006). During thermal evolution, organic material can produce a large amount of

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organic acid, thus accelerating the transformation from smectite to illite (Abid and Hesse, 2007) and

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increasing the amount of mixed-layer illite–smectite (Wang et al., 2006; Li and Cai, 2014;

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Berthonneau et al., 2016). Our experiments showed similar results to these observations, as with

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increasing thermal evolution, illitization occurred in the three types of ORS. The total clay content

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in the OB-T3y7 shale increased to 51.6% from 46.1%, and the relative content of illite increased to

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15% from 5%. The total clay content in the NC-Ptx shale increased to 68.6% from 46.2%, and the

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relative content of illite also increased to 91% from 51%. The clay content in the JB-P2l shale

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decreased somewhat from 15.3% to 13.5%, but the relative content of illite increased from 15% to

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100% (Table 1). Zhao (1990) showed that the smectite-to-illite transformation can increase the pore

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space by 1%–5%.

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SEM results show that with increasing thermal evolution, intragranular pores in clay minerals

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ACCEPTED MANUSCRIPT gradually developed, particularly those in mixed-layer illite–smectite and chlorite. Image analysis

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of the NC-Ptx shale samples shows that with increasing temperature, intragranular pore sizes in

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mixed-layer illite–smectite increased gradually, original pores became connected by newly

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developed micro-fractures, and the range of pore development expanded, improving the overall

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connectivity (Fig. 5F1–F4). Intragranular pores in chlorite exhibited similar features (Fig. 5G1–G4).

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At a temperature of 350°C, the intragranular pore sizes of the mixed-layer illite–smectite and

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chlorite increase, but at temperatures of >350°C, the change is minor. This indicates that the

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diagenetic evolution of clay minerals occurs mainly from the low-mature stage to the second half of

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the oil generation stage. As such, reservoir space is mainly formed during this stage (Zhao et al.,

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1990). After entering the gas generation stage, clay minerals tend to become stable, mineral

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transformations are reduced, and their contribution to the enhancement of reservoir space is limited.

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3.3.3 Transformation of non-clay minerals

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The main non-clay minerals are quartz, feldspar, calcite, and dolomite, and pyrite and hematite

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occur in some samples (Tables 1 and 2). With increasing temperature and thermal evolution,

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hydrocarbon generation leads to the corrosion of unstable minerals such as feldspar and calcite, thus

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producing new pores. Feldspar corrosion was observed in the OB-T3y7 and NC-Ptx shales, and

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dissolved carbonate pores developed in the JB-P2l shale (Fig. 5E1–E4). After being dissolved by

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organic acids, feldspar releases K ions and forms quartz, and the K ion and mixed-layer illite–

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smectite can further evolve into illite, which explains the increase in quartz content in the OB-T3y7

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and NC-Ptx shales (Table 1). At higher temperatures, the increase in pore size and connectivity due

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to non-clay minerals is small as compared with the thermal evolution of organic material and

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transformation of clay minerals.

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ACCEPTED MANUSCRIPT Another important role of non-clay minerals in the evolution of shale pores is to bear the overlying

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formation pressure. Compaction is the most important factor influencing the evolution of shale

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pores, which can reduce the pore volume by 83%–88% (Loucks et al., 2012). The content of

303

non-clay minerals in JB-P2l shale reaches 84.7%, which is higher than in the OB-T3y7 and NC-Ptx

304

shales (i.e., 54%; Table 1). As such, the compaction resistance of JB-P2l is strong, and this provides

305

a good framework for the development and preservation of pores.

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3.3.4 Evolution of shale pores

308

The lacustrine OB-T3y7 and JB-P2l, and marine NC-Ptx shales all contain type II kerogen. The pore

309

evolutions of the three samples show the same features, comprising four stages as follows (Fig. 8).

310

Stage 1: The pore system is reduced rapidly, the corresponding Ro value is <0.5%, and the samples

311

are in the immature stage. Although we did not obtain experimental data for this stage, numerous

312

previous studies (Katsube et al., 2003; Loucks et al., 2012; Mastalerz et al., 2013; Cui et al., 2014;

313

Lu et al., 2014) have shown that pore evolution during this stage is affected mainly by mechanical

314

compaction. With increasing burial depth, the overburden pressure results in the original porosity

315

being reduced rapidly.

316

Stage 2: The pore system shows variable development and the corresponding temperature is 250°C

317

to 300°C. From the low-mature stage to the first half of the oil generation stage, compaction

318

continues to result in reduced porosity. Organic material begins to pyrolyze, forming new organic

319

pores, but the liquid hydrocarbons produced are adsorbed and dissolved in the kerogen framework,

320

leading to the swelling of organic material. Therefore, the number of inorganic pores continues to

321

be reduced, whereas that of organic pores shows a trend of first increasing and then decreasing.

322

Stage 3: The pore system develops rapidly and the corresponding temperature is 350°C to 450°C.

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ACCEPTED MANUSCRIPT After the organic material enters the over-mature stage, hydrocarbon generation greatly increases,

324

liquid hydrocarbons are produced by pyrolysis on a large scale, the swelling of organic material

325

ceases, and a large number of organic pores develop. Correspondingly, a large amount of organic

326

acid is produced due to hydrocarbon generation, changing the fluid environment, and K-feldspar,

327

calcite, and other unstable minerals are corroded, forming secondary pores. The release of K ions,

328

combined with relatively high temperatures and pressures, further promotes the transformation of

329

clay minerals, such as smectite and mixed-layer illite–smectite. Therefore, during this stage the total

330

clay content and proportion of intragranular pores increase, the compressive rock strength increases,

331

and the influence of compaction on the pore system is reduced. In general, the size, distribution, and

332

connectivity of the pore system are greatly improved, and the porosity is generally increased by a

333

factor of 2 to 4 during this stage.

334

Stage 4: The pore system remains stable, the corresponding temperature is 550°C, and the samples

335

enter the high- to over-mature stage. The peak period of hydrocarbon generation has ceased, and

336

only a little residual organic material undergoes pyrolysis reactions to form a small amount of new

337

organic pores. In this stage, the rock is in late diagenesis, and the compression resistance and

338

stability of the rock are both greatly improved. Therefore, the influence of compaction on the pore

339

structure is not significant and the relatively stable fluid environment reduces the development of

340

inorganic pores inside minerals. As such, the overall pore system is in a relatively stable state.

341

Our research has shown that the key factors influencing the final porosity of the three types of shale

342

are the initial porosity, compaction, TOC content, pyrolysis, and pore-forming ability. The former

343

two factors are closely related to the mineral framework, and the latter two factors reflect the

344

contribution of organic material to the reservoir space, which is key in controlling the reservoir

345

properties of shale. As compared with the OB-T3y7 and NC-Ptx shales, the content of non-clay

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ACCEPTED MANUSCRIPT minerals in the JB-P2l shale is high, and the compaction resistance of minerals such as quartz,

347

feldspar, and calcite is strong, leading to this shale having the ability to preserve the pore structure

348

and high original porosity. In addition, the TOC content of JB-P2l is higher than those of the other

349

two shales, also leading to its high final porosity. The OB-T3y7 and NC-Ptx shales have a similar

350

mineral framework, but the NC-Ptx shale was collected from a field outcrop, and so its initial

351

porosity is slightly higher than that of the OB-T3y7 shale. In addition, the TOC content of the

352

NC-Ptx shale is high, and so its final porosity is higher than that of the OB-T3y7 shale. The Ro value

353

is 1.5%–2.5% when organic pores in ORSs begin to develop on a large scale. From this stage to the

354

high-mature stage, the pore system development in shale is relatively advanced, making this a

355

favorable range for shale oil and gas exploration.

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3.4 Controlling factors of pore evolution

358

The organic matter and inorganic mineral framework in shale controls the development of pores,

359

which influences the development of pore structure. Our results show that thermal evolution has a

360

key influence on the organic material and inorganic mineral framework, and thus on pore structure.

361

The thermal evolution of the OB-T3y7 and JB-P2l shales is relatively low, and these rocks are within

362

the range of the oil generation window (Table 2; Fig. 9). The difference in the overall development

363

of pores in these samples, particularly the development of organic pores, is not large, and the BJH

364

pore volume is not obviously correlated with TOC contents, S1 values, or contents of clay minerals,

365

quartz, and feldspar (Fig. 9A–I). The thermal evolution of the SB-S1l marine shale is high, and it is

366

in the over-mature stage (Table 2; Fig. 9C). As such, the organic matter and inorganic mineral

367

framework has a large influence on pore structure, and the BJH pore volume is positively correlated

368

with the clay mineral and quartz content (Fig. 9D–H). A large amount of biogenic silica is present

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ACCEPTED MANUSCRIPT in the SB-S1l marine shale (Wang et al., 2014; Zhao et al., 2016), which formed a large amount of

370

biogenic-quartzs that is typically associated with organic pores. This explains why the porosity of

371

SB-S1l is closely related to quartz content. Such features have also been documented for the Barnett

372

shales (Schieber et al., 2000; Bower, 2003; Papazis, 2005). Quantitative Evaluation of Minerals by

373

SCANning electron microscopy (QEMSCAN) shows the influence of mineral associations and

374

arrangement patterns on organic pores. Experiments on the SB-S1l marine shale showed that the

375

quartz content of organic origin can be further increased to 60% from 40%, and that of clay

376

minerals can be reduced to 5% from 30% (Fig. 10F). In this shale with an organic silica framework,

377

calcite cementation is developed locally and a large number of organic pores have formed (Fig.

378

10G). This increases the clay mineral content, siliceous quartz and clay minerals form the mineral

379

framework, and organic material is distributed primarily in bands, although the development of

380

organic pores is reduced (Fig. 10H). With further increases in the clay mineral content, rocks

381

experience stronger compaction, organic material is developed primarily in the clay mineral

382

framework, and the number and size of organic pores are further reduced (Fig. 10I). Therefore,

383

organic matter–inorganic mineral framework interactions directly control pore formation and

384

development in high-mature shale.

385

We experimentally investigated the differences in pore evolution between marine and lacustrine

386

shales. Although the experiments do not perfectly mimic actual geological conditions (i.e., in terms

387

of temperature differences of >300°C and the short experimental periods), the high-temperature and

388

high-pressure experiments can reproduce the thermal evolution of shales and provide important

389

constraints on pore evolution and optimal conditions for the formation of favorable shale reservoirs.

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390 391

4 Conclusions

ACCEPTED MANUSCRIPT Pores in ORSs are the combined result of the behavior of organic material and inorganic minerals at

393

high temperatures and pressures. Hydrocarbon generation and diagenesis are key factors in pore

394

evolution. In detail, the main geological factors include the TOC content, degree of thermal

395

evolution, and organic matter–inorganic mineral framework interactions. The TOC contents and

396

mineral frameworks control the distribution of organic material in shale, and the thermal evolution

397

strongly influences the pore structure in high- to over-mature shale. The pore throat evolution of

398

shale is positively correlated with maturity. With increasing maturity, the number of nanopores in

399

ORSs increases, and the porosity increases continuously. The development of organic pores occurs

400

over four stages, involving an increase, then a decrease, and then an increase until becoming stable.

401

In the oil generation window, liquid hydrocarbons are adsorbed and dissolved in kerogens, leading

402

to the swelling of organic material, which is why the number of organic pores is reduced and the

403

relative decrease in porosity is up to 10%. For type II kerogen, the pore structure evolution of

404

marine and lacustrine shales shows the same features, and the factors that control the final porosity

405

are the initial porosity, compaction, TOC content, pyrolysis, and pore-forming ability. Ro values are

406

1.5%–2.5% when a large number of organic pores begin to develop in ORSs, and the pore system

407

development reaches a maximum when Ro = 2.5%–3.0%, which is a favorable range for shale oil

408

and gas exploration.

409

Acknowledgement

410

We thank members of our research community for the data and ideas they contributed, including

411

Prof. Rukai Zhu, Xuanjun Yuan, Prof. Shizhen Tao, Dr. Lianhua Hou, Dr. Zhiguo Mao, and Ms.

412

Ling Su. We also thank China National Petroleum Corporation’s permission to public this paper.

413

Last but not least, we thank the MPG Editor and reviewers for their time and attention.

414

This study was supported by the National Key Basic Research Program-973 Project (Grant No.

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ACCEPTED MANUSCRIPT 2014CB239000), the National Science and Technology Major Project of China (Grant No.

416

2017ZX05001), the CNPC Science and Technology Project (Grant No. 2016b-03), and the Key

417

Laboratory of Oil and Gas Reservoirs, CNPC.

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ACCEPTED MANUSCRIPT 418

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Table 1 Geochemistry, mineralogy, and pore structure data for the ORSs subjected to high-temperature and high-pressure experiments.

Marine shale

North China

Ro (%)

S (%)

Kerogen type

S1 (mg/g TOC)

S2 (mg/g TOC)

Tmax (℃)

Quartz

Original

2.23

0.67

0.14

Ⅱ

5.11

10.73

426

20.5

350

0.32

0.16

Ⅱ

0.18

0.08

505

450

0.13

0.05

Ⅱ

0.04

0.03

550

0.04

0.01

Ⅱ

0.03

Original

9.29

0.10

Ⅱ

1.4

350

1.62

0.11

Ⅱ

450

0.518

0.06

Ⅱ

550

0.103

0.03

Ⅱ

Original

6.8

350

1.8

450

0.45

550

0.18

P2l

Ptx

0.48

0.24 0.20

Nitrogen adsorption

Nano-CT analysis

Illite

I/S mixed layer

BET surface area (m2/g)

BJH Desorption pore volume (cm3/g)

Pore area (µm2)

Pore volume (µm3)

Porosity (%)

1.6

46.1

5

50

3.61

0.018 0

692

118

0.56

19.6

2.5

46.1

8

20

7.20

0.030 8

1 474

414

0.95

546

19.4

2.4

48.0

13

5

7.95

0.031 5

3 963

432

1.98

0.01

559

15.1

1.0

51.6

15

<5

8.60

0.035 0

4 029

446

2.06

62.46

448

16.1

32.6

15.3

15

85

2.93

0.0186

2620

204

0.62

M AN U

0.68

Feldspar

Clay mineral

SC

TOC (%)

T3y7

Lacustrine shale

Junggar

Modeling temperature (℃)

TE D

Ordos

Formation

0.49

2.45

520

16.1

34

13.7

80

20

7.17

0.0432

6633

708

2.16

0.29

0.12

566

16.3

33.1

13.4

95

5

12.77

0.0849

17313

2019

6.18

0.03

0.06

570

15.6

33.2

13.5

100

<5

11.93

0.0867

20932

2150

6.58

EP

Basin

Ⅱ

3.12

29.73

434

32.5

4.9

46.2

51

30

5.34

0.0287

2710

210

0.65

Ⅱ

0.3

1.06

446

26.8

2.3

62

55

23

7.05

0.0307

5860

612

2.05

AC C

Type

Mineral content (%)

RI PT

Geochemical data

0.10

Ⅱ

0.05

0.05

559

25.6

2.7

69.7

76

10

7.68

0.0422

9265

1061

3.15

0.05

Ⅱ

0.03

0.06

573

25.4

8.7

68.6

91

<10

7.72

0.0458

11975

1263

4.06

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Table 2 Geochemistry, mineralogy, and pore structure data for the original ORSs. Total Brittle mineral content (%)

Forma Sample ID

conten

BET

t of

Surfae

TO tion

S1(mg/g Ro

S2(mg/g

Quart

Albit

Calcit

Dolomit

Pyrit

Hematit

clay

C

S

)

)

z

e

e

e

BJH

Relative content of Clay mineral (%)

RI PT

Geochemical data

e

e

I/S

Desorptio n pore area I

K

C

C/S

minera

(%)

(m2/g)

volume (cm3/g)

0.67

4.04

1.21

12.65

17.2

15.1

0

6.1

L147-02

T3y7

0.73

14.4

4.3

35.62

14.8

8.1

0

0

L147-03

T3y7

0.83

13.4

6.45

19.81

13.9

4.5

0

0

L147-04

T3y7

0.95

8.5

1.01

5.4

17.1

7.7

0

0

L147-05

T3y7

0.76

2.91

2.05

7.25

12.6

13

0

0

L147-06

T3y7

0.9

15.6

5.8

40.6

14.8

8.1

L147-07

T3y7

0.95

5.6

1.0

5.4

13.9

4.5

L147-08

T3y7

0.83

13.4

6.5

19.8

17.1

7.7

L147-09

T3y7

0.76

2.9

2.1

7.3

12.6

13.0

L147-10

T3y7

0.71

2.06

0.58

5.99

18.5

L147-11

T3y7

0.92

15.6

5.81

40.6

L147-12

T3y7

0.74

6.23

1.86

18.42

XP01

P2L

1.14

4.4

1.9

17.6

58.2

0

22.12

25.02

3.49

7.566

0

1.322

0.006551

M AN U

T3y7

0

3.4

10.5

0

36.2

0

18.46

11.22

3.26

3.258

0

1.811

0.007133

9

0

37.4

0

24.31

5.984

2.99

4.114

0

5.6278

0.017206

1

0

48.3

0

36.71

4.347

2.41

4.83

0

6.411

0.01934

0

0

46.9

0

35.17

4.69

1.41

5.628

0

5.3438

0.021989

TE D

L147-01

SC

l (%)

0.0

10.5

0.0

36.2

0.0

18.46

11.22

3.25

3.258

0.0

1.811

0.007133

0.0

0.0

9.0

0.0

37.4

0.0

24.31

5.984

2.99

4.114

0.0

5.6278

0.017026

0.0

0.0

1.0

0.0

48.3

0.0

36.71

4.347

2.41

4.83

0.0

6.411

0.01934

0.0

0.0

0.0

0.0

46.9

0.0

35.17

4.69

1.41

5.628

0.0

5.3438

0.021989

15.4

0

7.7

0

14.8

43.6

0

23.108

14.824

0

5.668

0

0.6529

0.003359

18.2

12.8

0

4.4

0

22.8

41.8

0

30.096

7.942

2.09

1.672

0

0.6982

0.003801

23.5

14.4

0

0

9.5

0

52.6

0

28.404

18.41

2.63

3.156

0

0.582

0.00216

48.9

18.9

4.7

5.1

0.0

0.0

22.4

0.0

5.598

22.081

1.555

1.866

0.0

2.3632

0.006424

AC C

EP

0.0

0.71

7.0

1.6

32.6

38.3

40.1

0.0

0.0

2.3

0.0

8.8

XP03

P2L

1.16

3.8

1.0

4.2

23.2

39.9

19.3

0.0

6.7

0.0

10.9

XP04

P2L

1.06

7.9

2.5

46.5

34.6

25.3

10.4

0.0

0.0

0.0

10.8

XP05

P2L

1.16

2.9

6.2

10.8

26.1

37.8

0.0

15.1

10.9

0.0

10.1

XP06

P2L

0.72

3.5

6.2

17.9

17.7

42.1

0.0

33.6

0.0

0.0

XP07

P2L

0.7

11.8

3.0

67.1

23.5

35.6

7.5

22.1

0.0

0.0

XP08

P2L

0.74

3.0

4.2

10.6

27.7

32.5

3.8

25.4

XP09

P2L

0.73

3.6

0.8

15.7

24.1

12.1

0.0

58.6

XP10

P2L

0.76

3.2

3.9

18.8

19.9

22.4

0.0

50.9

XP11

P2L

0.79

1.5

1.1

7.4

42.0

26.6

0.0

SW-01

S1L

2.34

2.5

0.1

0.2

32.9

8.5

SW-02

S1L

2.33

3.7

0.1

0.2

50.9

1.6

SW-03

S1L

2.34

3.4

0.0

0.2

27.5

SW-04

S1L

2.35

1.5

0.0

0.1

21.0

SW-05

S1L

2.39

2.2

0.0

0.1

SW-06

S1L

2.43

0.8

0.0

0.1

SW-07

S1L

2.76

1.0

0.0

0.1

0.0

7.416

RI PT

P2L

7.416

1.854

1.854

0.0

1.983

0.007975

0.0

19.56

31.296

3.912

5.868

0.0

4.3041

0.02385

0.0

6.96

11.832

1.624

2.784

0.0

2.6217

0.011858

0.0

15.62

22.176

5.04

7.56

0.0

0.9112

0.005018

SC

XP02

EP

ACCEPTED MANUSCRIPT

0.0

5.51

32.509

3.857

13.224

0.0

1.9112

0.007624

11.3

0.0

5.34

31.506

4.272

12.282

0.0

3.7058

0.008967

M AN U

6.6

0.0

10.6

0.0

8.55

37.525

0.475

0.95

0.0

5.2364

0.024568

0.0

0.0

5.2

0.0

8.92

38.857

2.548

13.377

0.0

4.4834

0.014541

0.0

0.0

6.8

0.0

10.2

28.56

0.816

1.224

0.0

3.0919

0.021512

18.5

0.0

0.0

12.9

0.0

4.494

13.696

1.712

1.498

0.0

3.5589

0.01786

11.8

13.0

2.7

0.0

31.1

8.512

0.0

3.36

0.448

0.672

9.408

19.4483

0.028826

7.3

7.5

1.8

0.0

30.9

3.344

0.0

0.968

0.968

0.88

2.64

19.9871

0.033723

TE D

0.0

10.8

4.8

4.1

0.0

48.9

1.962

0.0

0.654

0.654

0.545

7.085

23.1782

0.035396

2.5

34.9

4.9

0.0

4.7

23.2

7.128

0.0

0.54

0.0

0.0

3.132

9.9159

0.020331

AC C

3.9

27.5

3.3

11.7

4.0

3.1

0.0

50.4

2.727

0.0

0.505

0.0

0.101

6.767

20.0646

0.030414

32.3

4.5

6.3

0.0

1.8

0.0

55.1

5.412

0.0

0.264

0.132

0.132

0.726

13.624

0.028518

34.2

4.5

5.2

0.0

2.7

0.0

53.4

0.0

0.452

0.113

0.0

0.0

15.8459

0.034017

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S1L

2.39

3.1

0.0

0.1

20.4

0.0

0.0

0.0

8.5

0.0

47.5

10.07

0.0

0.53

0.0

0.0

0.0

8.1269

0.022916

SW-09

S1L

2.32

0.3

0.0

0.0

36.3

0.0

0.0

0.0

0.0

0.0

63.7

5.096

0.0

0.052

0.052

0.0

0.0

14.6035

0.040325

SW-10

S1L

2.38

1.3

0.0

0.1

26.6

0.0

20.2

5.5

6.9

0.0

40.8

6.664

0.0

0.068

0.068

0.0

0.0

14.679

0.034951

SW-11

S1L

2.35

3.1

0.1

0.2

58.8

2.9

6.7

5.3

4.9

0.0

21.4

1.806

0.0

0.516

0.258

0.258

14.8215

0.024742

AC C

EP

TE D

M AN U

SC

RI PT

SW-08

10.06 2

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Figure 1 Locations of the studied basins and samples used in this study. The samples are

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organic-rich shales (ORSs) from the Proterozoic Xiamaling Formation in the North China Platform (NC-Ptx), the Permian Lucaogou Formation in the Junggar Basin (JB-P2l), the Triassic

EP

Chang 7 member in the Ordos Basin (OB-T3y7), and the Silurian Longmaxi Formation in the

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Sichuan Basin (SB-S1l).

EP

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Figure 2 Relationship between experimental temperature and measured vitrinite reflectance (Ro).

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Figure 3 Two-dimensional nano-CT images (A1–A4, B1–B4, and C1–C4) and three-dimensional pore system models (A5–A8, B5–B8, and C5-C8) of samples at different temperatures. Series A are OB-T3y7; series B are JB-P2l; series C are NC-Ptx.

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Figure 4 Liquid nitrogen adsorption results for the three types of shale at different temperatures. A is the BET surface area and B is the BJH pore volume. The figure shows a positive relationship between temperature and these two factors; however, the increases in surface area and pore volume for JN-P2l are larger than those of OB-T3y7 and NC-Ptx.

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Figure 5 SEM images showing the porosity evolution in different components at different temperatures. Series A and D are organic matter in OB-T3y7; series B is organic matter in JN-P2l; series C is organic matter in NC-Ptx. Series E, F, and G are feldspar, mixed-layer illite–smectite, and chlorite in NC-Ptx, respectively. OP-Organic pore, PY-Pyrite, AB-Albite, K-F-K-feldspar, I/S-Illite-smectite mixed layer, CH-Chlorite.

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Figure 6 SEM images of hydrocarbon generation during the thermal evolution of the different types of shale. A, B, and C are of JN-P2l; D, E, and F are of OB-T3y7; G, H, and I are of NC-Ptx. The hydrocarbon occurrences include

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veinlet and droplet shapes. OM-Organic matter, OP-Organic pore, HC-Hydrocarbon

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Figure 7 SEM images of organic matter before and after hydrocarbon extraction. This sample is XP04 in Table 2. A is an SEM image of the original organic matter; B is the EDS result from point P1 to P2, which shows obvious differences in carbon contents that indicate hydrocarbon dissolution and adsorption in the kerogen; C and D are images before dichloromethane extraction; E and F are images after dichloromethane extraction and 30 min of ultrasonication. The new pores are observed in F. OM-Organic matter, OP-Organic pore, DO-Dolomite.

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Figure 8 Schematic chart of the porosity evolution in the three ORSs. The organic matter and mineral reactions are similar for the three ORSs, although there are differences in the percentage porosity growth and mineral evolution. S1 is a measurement of the free hydrocarbons present in the sample before analysis (Peters, 1986).

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Figure 9 Bivariate plots of BJH pore volume versus organic–inorganic components in the three ORSs. S1 is a

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measurement of the free hydrocarbons present in the sample before analysis (Peters, 1986).

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Figure 10 QEMSCAN results and organic pores in the Silurian Longmaxi marine shales. A is SW-02, B is SW-07, and C is SW-08. D, E, and F are the contents of important minerals. The mineral contents were calculated based

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on the QEMSCAN analysis. G, H, and I are organic pores in SW-02, SW-07, and SW-08, respectively.

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Establish pore evolution model and investigate key factors on organic-inorganic interaction. Describe the differences of porosity evolution between lacustrine and marine shales in China. Provide evidence of best maturity ranges for shale oil and gas sweet-spotting.