Pore characteristics of Damodar valley shale and their effect on gas storage potential

Accepted Manuscript Pore characteristics of Damodar valley shale and their effect on gas storage potential Tuli Bakshi, B.K. Prusty, K. Pathak, S.K. Pal PII:

S0920-4105(17)30883-5

DOI:

10.1016/j.petrol.2017.10.091

Reference:

PETROL 4415

To appear in:

Journal of Petroleum Science and Engineering

Received Date: 10 June 2017 Revised Date:

19 September 2017

Accepted Date: 31 October 2017

Please cite this article as: Bakshi, T., Prusty, B.K., Pathak, K., Pal, S.K., Pore characteristics of Damodar valley shale and their effect on gas storage potential, Journal of Petroleum Science and Engineering (2017), doi: 10.1016/j.petrol.2017.10.091. 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.

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Pore characteristics of Damodar valley shale and their effect on gas storage potential

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Tuli Bakshia, B. K. Prustya*, K. Pathaka, S.K. Pala

2 a

Department of Mining Engineering, Indian Institute of Technology Kharagpur, 721302

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Highlights •

The organic and inorganic composition of shale samples were analyzed.

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•

Micro and mesopore characteristics of shale were discussed.

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•

Methane gas storage capacity in shale was explored.

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•

Effect of shale composition on pore structure and methane adsorption capacity was investigated.

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Abstract

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The current global interest in fine grained sedimentary shale rock is driven by its ability to store gas in the

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pore spaces in them. The current study focuses on the understanding of the gas storage capacity of less

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explored Damodar Valley shales of India, in light of pore characteristics of organic matter and clay

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minerals. In this study, four samples were collected from different parts of Damodar valley basin and their

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geochemical composition, pore structure and adsorption capacity were investigated by XRD studies, rock-

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eval analyses, low-pressure N2-CO2 adsorption analyses and high-pressure methane adsorption

15

experiment. The samples were also studied to know their hydrocarbon potential. The relationship between

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mineralogy, organic matter, and pore-structure was analyzed and finally, their effect on methane sorption

17

capacity was discussed. The shale samples are found to be clay rich. The average clay content of the shale

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samples is 50.69% and average quartz content is 31.65%. Presence of excellent TOC content (4.8% -

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37.36%) with a predominance of type III organic matter and Tmax varying from 440°C - 465°C suggests

20

a very good to excellent hydrocarbon generation potential in all the samples. The correlation between the

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TOC and VL was found to be positive indicating a positive influence of organic matter on methane

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sorption capacity of the studied samples. However, a lack of correlation between total clay and CH4-VL

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indicates that the role of clay minerals on methane sorption behavior of these shales are inconclusive. A

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positive correlation between CO2 micropore volume, CH4-VL and TOC suggest microporous nature of

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organic matter within the shale samples and their positive control on methane sorption potential. The

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negative correlation of clay mineral with CO2 micropore volume suggests a lack of microporosity in the

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clay minerals of the collected shale samples. It was also observed that thermally mature shale samples

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have higher micropore volume and surface area, and are prone to higher methane sorption capacity

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compared to that of less mature shales.

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Keywords Organic matter; Mineralogy; Pore characteristics; Microporosity; Sorption; Shale gas reservoirs.

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34 1. Introduction

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Organic-rich shales have gained extreme importance in recent times because of their emergence as

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hydrocarbon reservoirs (Montgomery et al., 2005; Loucks and Ruppel, 2007; Rowe et al., 2008; Ruppel

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and Loucks, 2008). Apart from being source rocks and seals of conventional reservoirs, shales play the

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most important role of shale gas reservoirs. Shale gas is generated by biogenic and thermogenic process

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from the organic matter trapped in the shale (Hill et al., 2007; Strapoc et al., 2010). Methane gas in shale

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is stored as an adsorbed gas in the micropores1 of organic matter and clay mineral and as free gas in the

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natural fractures and intergranular pores (Curtis, 2002).

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Gas in place (GIP) plays a vital role in the shale-gas resource assessment. GIP is controlled by

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organic/inorganic compositions and porosity and permeability properties of rock (Zhang, 2012).

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Understanding the micropore structure in shale is of utmost importance as significant gas contents are

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present in the adsorbed state in shale micropores (Montgomery et al., 2005; Bustin, 2005a; Pollastro,

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2007; Ross and Bustin, 2007). Organic matter and some clay minerals mainly host micropores whereas

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other kinds of pores are associated with internal arrangements of mineral grains (Reed and Loucks, 2007;

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Sondergeld et al). The understanding of storage behavior of gas in shale is of utmost importance in order

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to evaluate the producibility of a reservoir. But not much light was thrown upon the driving mechanism of

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storage/sorption behavior which is affected by the composition of shale, and pore characteristics. The

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quantity of the sorbed gas depends upon complex pore networks, total organic carbon (TOC) content,

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mineralogy, thermal maturity (Yang and Aplin, 1998; Dewhurst et al., 1999a, b; Ross and Bustin, 2007).

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The heterogeneity of shale includes the variability in mineral and structural composition from one

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formation to the next (even within the same formation). Several works on the Mississippian Barnett Shale

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have shown the presence of dominant intraparticle nanopores, ranging from 5–750 nm in organic matter

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with a median of approximately 100 nm (Loucks et al., 2009; Milliken et al., 2012). A significant amount

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of GIP is associated with organic pores as they host both sorbed and free gas (Ambrose et al., 2010, 2011;

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Wang and Reed, 2009). So it can be said that the porous organic material (kerogen) plays an important

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role in gas storage. Hence it is of utmost importance to understand the methane adsorption behavior of

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shales in the context of organic-inorganic material and pore surface chemistry (Psarras et al., 2017).

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Strapoc et al., (2010) have shown a positive correlation between total organic carbon (TOC) and

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total gas content from the canister desorption of fresh cores of Devonian–Mississippian New Albany

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Shale, and concluded that organic matter content contributes to the total GIP. A positive influence of TOC

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on CH4 sorption capacity in shales has been observed in previous studies (Lu et al., 1995; Ross and 1

Following the International Union of Pure and Applied Chemistry (IUPAC) pore classification (Rouquerol et al., 1994), micropores are <2 nm diameter, mesopores are between 2 and 50 nm, and macropores are >50 nm.

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Bustin, 2007; Cui et al., 2009). Methane sorption also linearly increased with TOC and micropore volume

67

(<2 nm), indicating that micropores associated with the organic fraction have a prime control on CH4

68

sorption (Ross and Bustin, 2009). Microporosity leads to large internal surface areas and higher

69

adsorption energies (Chalmers and Bustin, 2007a, b; Ross and Bustin, 2009). So for a better

70

understanding of shale as a reservoir, it is imperative to characterize shale pore structure which controls

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both storage and mobility of gas.

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It has been reported by Sondergeld et al. (2010) that organic porosity increases with increasing

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thermal maturity. With increasing, thermal maturity hydrogen indices (HI) of organic matter decreases as

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conversion of kerogen to hydrocarbons takes place (Behar and Vandenbroucke, 1987; Behar et al., 1992;

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Peters et al., 2005). These findings suggest that a proper understanding is necessary to understand the

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effect of thermal maturity type on organic pores and gas storage potential.

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As per EIA reports of 2015 India has a total shale gas resource of 584 tcf with 96 tcf of

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recoverable resource. After the discovery of RNSG-1, the first shale gas well of India Barren Measure

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Shale with reported gas shows, along with D-A and D-B well of Cambay black shale with modest shale

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gas and oil production, it can be concluded that there exists a significant potential for shale gas resource

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development. Shale gas scenario in India is in a very nascent stage with very few reports in the public

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domain. Although few researchers have reviewed potential gas shale formations and characterized their

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source rock potential and methane sorption capacity, the relationship of the organic-inorganic matter with

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pore characteristics and methane sorption capacity is not clearly understood (Misra et al., 2012; Padhy et

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al., 2013, Verma et al., 2014). Characterization of organic-inorganic pores ultimately leads to the

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sorption, entrapment, and flow of gas.

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The Permian Barakar coal formations of the Damodar Valley basins in India have played a vital

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role in providing energy security to India (Vishal et al., 2015). Following the discovery of shale gas well

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RNSG-1, Damodar Valley basins have been receiving a lot of attention of Indian researchers lately. The

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goal of this research study is to characterize shale on the basis of organic-inorganic constituents and their

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contribution to micropore structure and sorption behavior of shales. In this study shale samples from

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Lower Permian Barakar Formation of the Damodar Valley basin were taken for several analyses. XRD,

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Rock-eval pyrolysis was done to know the mineral matter and source rock characteristics. Low-pressure

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CO2-N2 isotherm study was done in order to understand the nature of pore volume, specific surface area.

95

High-pressure methane isotherm was performed to estimate the gas storage potential. Through critical

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data analyses, we have tried to unravel the relationships between mineralogical composition, organic

97

matter, and sorption behavior of Indian gas shales.

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2. Samples and Experimental Methods

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Four shale samples of Permian age were collected from Damodar Valley coalfields. The sample locations

103

are shown in Figure 1. All the samples were collected as core samples. The sample name, corresponding

104

coalfield, formation, and depth are shown in Table 1. The samples were organized based on the location

105

of the samples occurring from east to west. Starting MOON in the east and NKP in the west.

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After sample collection, they were crushed to different sizes for different analysis. To understand

107

the presence of mineral phases, X-Ray diffraction study was done on the powdered samples. To know the

108

hydrocarbon potential of shale samples, Rock-eval pyrolysis was done on a powdered sample of 72 mesh

109

(-212 µm). The low-pressure N2-CO2 adsorption study was done to understand the pore characteristics of

110

the shale samples. For the low-pressure adsorption study, the samples were crushed to size <250 µm. The

111

crushed samples were heated for 8 hours at 110°C to remove gas, free water, and hydrocarbons. The main

112

concern during heating the shale sample is preserving the organic materials and the clay bound water.

113

High-pressure CH4 adsorption was done to have an idea of the methane storage capacity of the shale

114

samples, and the analysis was performed on powdered and oven dried (at 110°C for 24 hours) samples.

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The detailed description of all the analytical procedure is explained below.

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Table 1. Location of the Permian shale samples with depth and formation Sample Name Coalfield Formation Depth(m) MOON Jharia 421 PB 180 Barakar WB West Bokaro 80 NKP North Karanpura 523

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2.1. X-ray diffraction (XRD) study

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All of the collected samples were crushed to powder and screened through -212 microns sized mesh

123

before carrying out the analyses. X-ray diffraction analysis of the crushed samples was done in IIT

124

Kharagpur, using Bruker D8 Advance instrument with Cu target and lynxeye detector. The X-ray powder

125

diffraction (XRPD) patterns were recorded for 2θ values in the range of 7-80° using Copper Kα radiation.

126

The clay and non-clay minerals peaks were distinguished, using basal spacings (d) and 2-theta for Cu K-

127

alpha radiation, The quantitative analysis was carried out by Rietveld analyses using the software Topas.

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2.2. Rock-Eval pyrolysis

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The powdered shale samples (-212 µm) were weighed crucibles depending upon the organic matter

130

content (~ 50–70 mg). A Rock-Eval 6 instrument was used for the Rock-Eval pyrolysis and TOC analysis

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of the samples. Particulars on Rock-Eval have been discussed by several workers (Espitalie et al., 1987;

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Lafargue et al., 1998; Peters and Cassa, 1994). Different parameters like TOC content, S1, S2, S3

133

pyrolysis yields and temperature of maximum S2 pyrolysis yield (Tmax) were measured. Hydrogen (HI),

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oxygen (OI), the genetic potential (GP) and production (PI) indices were calculated (Table 3). Estimated

135

vitrinite reflectance (EVRo) was calculated from Tmax using the equation below after Jarvie et al. (2001):

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– 7.16

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Fig. 1. Geological map of the Damodar Valley Coalfield(Gupta 1999) showing sample locations

(1)

2.3 High-pressure methane adsorption analysis

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High-pressure CH4 adsorption experiments were carried out using an adsorption isotherm (AI) setup

139

based on the volumetric method. Adsorption experiments were conducted at a constant temperature

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(40°C) on the four shale samples. Although such condition is not necessarily indicative of subsurface

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reservoir temperature for all the shale samples, it was kept constant so that a meaningful comparison can

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be made. The samples were crushed to fine powders size ranging from 150 to 425 micron and were used

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for sorption experiment as per the ASTM (American Standard for Testing Materials) standard D2013.

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Shales have low adsorption capacity with a tendency of decreasing methane adsorption capacity with

145

increased moisture content. Hence, the adsorption experiments for shales were carried out on as-received

146

samples. Similar protocols were followed by Rani in her work (Rani et al., 2015). The set-up (shown in

147

Fig. 2) consists of a fixed volume stainless steel sample cell (SC) and reference cell (RC) separated by a

148

two-way ball valve (valve 1). The RC is connected to a high precision pressure transducer (Make – Druck

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& Leicester, UK; Maximum pressure – 25 MPa, Sensitivity – 2.5%; 0.05% of full scale). A filter is fixed

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in between the sample cell and reference cell to prevent entry of powdered shale sample into the reference

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cell. The setup follows the volumetric method of gas expansion technique (Boyle’s law) to evaluate the

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volume of gas adsorbed on shale. The reference cell contains a known volume of gas while the sample

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cell contains the 50-80 g of crushed shale sample. The entire set-up is placed in a constant temperature

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water bath with an accuracy of ±0.1°C to control the temperature fluctuation. The adsorption isotherm

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experiment is done in two stages. Void volume is determined in the first stage using a non-adsorbing gas

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(helium) and in the second stage, actual adsorption steps are carried out using the desired adsorbate gas

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such as methane. To determine the void volume, the prepared sample is filled in the SC and the SC is closed by

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tightening the nuts. The RC is charged with helium keeping the valve 1 (between the RC and SC) closed.

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In the first step, helium is filled in the RC to a pressure of approximately 1 MPa and the pressure readings

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are noted at an interval of 30 min until equilibrium pressure is achieved. Once the pressure in the RC

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equilibrates, the valve 1 is opened. The pressure of the RC and SC is allowed to stabilize and the stable

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pressure is recorded. For the second step, the valve 1 is closed and the RC is again charged with helium to

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a higher pressure (approximately 1 MPa higher than the previous value).This procedure is repeated for 3

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times. For each step, the void volume is calculated using the real gas law. The average value of the void

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volume obtained in three steps is considered as the void volume of the setup and subsequently used for

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methane adsorption calculation purpose.

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After completion of the helium steps, keeping the valve 1 closed, helium gas is vented out from

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the RC. The RC is repeatedly flushed with methane at low pressure and vented to the atmosphere.

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Flushing and venting of methane are at least 3 times to ensure that all the helium from RC is driven out.

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Then methane is charged into the RC to a pressure of approximately 1 MPa and the steps followed with

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helium are repeated with methane. Increasing pressure is charged to the RC in successive steps. At each

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pressure step, the volume of methane adsorbed is calculated using real gas law taking into account the

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compressibility factor of methane. The compressibility factor for pure methane was calculated from the

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Peng-Robinson equation of state (Friend, 1992). For helium, compressibility factor was calculated from

176

the equation of National Bureau of Standards Technical Note 631 for helium (McCarty, 1972). The

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following Langmuir adsorption isotherm model is used for plotting and estimation of Langmuir

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coefficients (Langmuir, 1918):

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=

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(2)

is adsorbed volume, VL is Langmuir volume, PL is Langmuir pressure and P is Equilibrium

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where,

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pressure. A plot of P/V versus P is used to determine the Langmuir parameters (VL and PL) and then

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using these parameters, the Langmuir isotherm is plotted.

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Fig. 2. Schematic diagram of adsorption isotherm setup.

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2.4 Low-Pressure N2- CO2 isotherm

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(PSD), and total surface area using isotherms is selected as a widely used technique for pore

188

characterization (Holmes et al., 2017). Low-pressure N2 isotherms at-196°C are very useful to understand

189

the pore characteristics of any porous material in the mesopore (pore dia, 2~50 nm) to macropore range

190

(dia > 50nm) and low-pressure CO2 isotherms effectively describes the micropore characteristics of

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porous materials as the gas can effectively enter into the nanometer scale pore spaces (Dubinin,1975,

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1989; Lamberson and Bustin, 1993; Larsen et al., 1995;Clarkson and Bustin, 1996, 1999; Levy et al.,

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1997; Bustin and Clarkson, 1998; Prinz and Littke, 2005; Chalmers and Bustin,2007a,b). Hence a

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combination of this two analytical procedures is likely to give a complete picture of pore systems of

195

studied samples.

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Samples were crushed to <250 mm for low-pressure CO2-N2 sorption analysis (N2 surface area

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measurement) using Micromeritics® instrument (TriStar 3000) (Rani et al., 2015; Pan et al., 2015; Labani

198

et al., 2013). At first, the degassing of shale samples were done in 150°C for 12 hours in a vacuum oven

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before being fed to N2 adsorption analysis. At -196°C nitrogen isotherms were measured under a relative

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pressure range of 0.001–0.9 which ultimately provides the information on total pore volume, pore size

201

distribution, specific surface area. The surface areas (m2/g) were calculated using the Brunauer–Emmett–

202

Teller (BET) method with the relative pressure range being 0.049-0.300 (P/P0, where P is the gas vapour

203

pressure in the system and P0 is the vapour pressure of the gas at the temperature of interest), following

204

the equation (Brunauer et al., 1938):

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1/W

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Where W is the weight of the sorbed gas at relative pressure P/P0, Wm is the weight of the monolayer

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adsorbent (N2), C is the BET constant which relates to the sorption energy between adsorbent and

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adsorbate.

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The low-pressure gas adsorption (LPGA) method for estimation of pore volume, pore size distribution

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The total pore volume was calculated as the molar volume of adsorbed nitrogen at the relative pressure of

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0.99. The N2 data of the crushed sample were interpreted using multi-point Brunauer–Emmett–Teller

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(BET) and Langmuir analysis for surface area and DFT analysis for pore size distributions. CO2 sorption was done over a pressure range of 0.00003- 0.03 at 0°C. The micropore capacity

214

was calculated by using Dubinin–Radushkevich (D–R) equation (Gregg and Sing, 1982). CO2 data was

215

interpreted using BET model and D-R model.

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log V = log V0 - S log2(P/P0)

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V is the volume of sorbed gas at equilibrium pressure (cm3g-1, s.t.p.), V0 is the total micropore volume

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(cm3g-1, s.t.p.). S is a constant, P is pressure, P0 is saturation vapor pressure. The total volume of the

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adsorbed CO2 completely filling the micropores, helps in estimating the micropore volume (Rouquerol et

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al., 1994). Dubinin and Stoeckli (1980), has discussed that microporous structures in carbonaceous

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materials can be described by the theory of volume filling.

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3 Results

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controls on the pore size distribution. A wide range of mineral compositions was observed from the

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analysis and the mineral percentages for all the samples are given in Table 2. Samples are composed of

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quartzo-feldspathic content and various clay minerals (smectite+illite+kaolinite+chlorite) and carbonate

232

(dolomite and siderite). The shale samples are found to be richer in clay content. The clay content varies

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between 32.02% to 65.30% with an average of 50.69%. The quartz content ranges between 25.45% to

234

36.88% with an average of 31.65%.Since muscovite and illite are difficult to distinguish with Rietveld

235

analyses, all dioctahedral Al-rich 2:1 clay minerals (illite, muscovite, smectite) are quantified together as

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the illite smectite group mineral (Clarkson, 2013; Reitveld HM, 1967; S´rodon´ et al. 2001; Kuila, 2011).

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XRD analysis was done in order to identify and quantify different mineral phases and ultimately their

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3.1 Mineralogy

Table 2. XRD analysis showing distribution of minerals in shale Feldspar Kaolinite Muscovite+Illite Chlorite Dolomite

Sample

Quartz

MOON

25.45

2.53

3.52

28.50

PB

37.41

-

16.13

40.22

WB

36.88

8.28

NKP

26.88

-

Siderite

29.12

10.88

1.27

0.97

3.20

41.31

4.60

2.94

2.79

11.34

44.70

9.26

2.32

7.50

238 239 240

3.2 Rock-Eval Pyrolysis

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results are shown in Table 3. The TOC and rock pyrolysis data are used to ascertain the source rock

242

characteristics for the shale samples and their thermal maturity.

Rock-eval pyrolysis was carried out to estimate the hydrocarbon potential of the samples and the

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The organic richness of the samples is indicated by excellent TOC content ranging from 4.8 wt.

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% - 30.91 wt. % (Peters and Cassa, 1994). The HI values of the Permian shale samples vary between 142

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and 297 mg HC/g TOC indicating a predominance of type III organic matter. According to Hunt, source

246

rocks with a GP <2, from 2 to 5, from 5 to 10 and >10 are considered to have poor, fair, good, and very

247

good generation potential, respectively (Hunt, 1996). Hence a very good genetic potential (GP = S1+S2

248

HC/g rock) is suggested by all the shale samples as GP values are varying from 19.7-44.8 HC/g rock.

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Coupled with very good GP values, ‘excellent’ TOC content indicates that the samples have good

250

potential for hydrocarbon generation. Very low values of OI as observed in table 3 could be ascribed to

251

the existence of stable oxygen moieties which were not cracked at a higher temperature. This is a feature

252

of Gondwana shale as described by Varma in his work (Varma et al., 2014)

253

Tmax values (Table 3) indicate that the shale samples are in the thermally mature zone (Tmax varying from

254

440°C - 465°C). At this zone of oil window, kerogen is thermally mature and is capable of generating

255

hydrocarbons upon thermal cracking (Gentzis, 2013). The range of EVRo varies between 0.76–1.21 %

256

(Table 3). Hackley in his studies has shown that Pennsylvanian coals and carbonaceous shale (containing

257

type III organic matter) has EVRo values ranging from 0.50–0.80% and they are capable of generating

258

thermogenic gas (Hackley et al, 2009). Thus the EVRo values suggest that the studied samples are in the

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zone of oil window.

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HI vs Tmax and HI vs TOC were plotted as shown in Fig. 3 and 4 respectively. The figures

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indicate that the shale samples are mainly gas prone in nature with predominantly type III kerogen falling

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in the mature to post mature phase of thermal maturity (following Espitalie et al., 1985; Peter and Cassa,

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1994). With increasing thermal maturity a decrease in the HI values has been observed amongst the

264

samples (Fig. 3). This is because expulsion of hydrocarbon takes place with decreasing H/C ratio and

265

increasing thermal maturity (Jimenez et al, 1999).

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Table. 3: Rock eval pyrolysis data for Damodar Valley shale GP (S1+S2) Tmax(ºC) EVRo(%) TOC (%) HI (mg HC/g rock HC/g TOC) MOON 44.89 465 1.21 30.91 142 PB 22.06 440 0.76 12.18 173 WB 28.46 451 0.95 19.01 139 NKP 19.70 442 0.79 6.39 297 HI: Hydrogen Index, mg HC/g TOC, Ro: Vitrinite reflectance (%), TOC: Total organic Carbon, wt. denoting the maximum rate of HC generation, PI: Production Index, OI: Oxygen Index, mg CO2/g TOC.

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OI (mg CO2/g TOC) 0.71 0.903 1.104 8.763 %, Tmax: Temperature

Fig 3. HI vs Tmax plot

Fig 4. HI vs TOC plot showing gas source potential

3.3 Low-pressure N2 adsorption analysis

Low-pressure N2 isotherm at-196°C is very useful to understand the pore characteristics of any porous

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material in the mesopore to macropore range (> 2nm diameter) (Bustin et al., 2008). Low-pressure N2

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isotherm of the studied shale samples is type II in nature (Fig. 5) following the classification of Brunauer

278

et al. (1940). Micropore filling at low pressure and multilayer adsorption at high pressure is indicated by

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Type II adsorption isotherms that signifies mesoporosity according to the Brunauer, Deming, Deming and

280

Teller classification (Ross, 2004, 2009). Fig. 5 depicts that the Parbatpur shale (PB) sample exhibits the

281

highest N2 adsorption and MOON exhibits the least. At low relative pressure (P/P0 = 0~0.8), an increment

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in the gas adsorption volume is observed with monolayer adsorption. As the relative pressure increases,

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monolayer adsorption starts shifting towards multilayer adsorption from the relative pressure of 0.8.

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BET surface areas and pore volumes, obtained from the N2 adsorption analysis are given in Fig 6.

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Amongst the samples, Parbatpur exhibits the highest surface area (13.6 m2/g) and pore volume (0.023

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m2/g) and MOON shows the least surface area (3.59 m2/g) and pore volume (0.011 m2/g).

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Fig 5. N2 adsorption isotherms for all samples

Fig 6. N2 BET (A) surface area and (B) pore volumes of shale samples

3.4 Low-pressure CO2 adsorption analysis

Low-pressure N2 isotherm only measures the pore characteristics of any porous material in the mesopore

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to macropore range (> 2nm diameter) (Bustin et al., 2008). So pore characteristics based on only N2

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adsorption study would have been incomplete. Since CO2 can effectively penetrate into the pores less than

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2 nm radii, CO2 adsorption analysis was done to understand the micropore characteristics of shale (Ross

300

et al., 2007). The isotherms found from the analysis were presented in Fig. 7 are Type I, indicating

301

microporosity. Among all the shale samples, NKP displays the least amount of adsorption, suggesting

302

little microporosity, and the MOON sample exhibits the highest adsorption indicating a higher amount of

303

microporosity, compared to other samples. NKP (19 m2/g) has the smallest micropore surface area, and

304

MOON (86.1 m2/g) has the highest (Fig 8A). There is also a substantial variation in micropore volume as

305

determined from CO2 adsorption analysis (Fig. 8B). The NKP (4.23 cc/g) shows the smallest micropore

306

volume, and MOON (18.8 cc/g) shows the highest among all the shale samples.

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308 309 310

Fig 7. CO2 adsorption isotherms for all samples

Fig 8. CO2 BET (A) surface area and (B) pore volumes of shale samples

3.5 High-pressure CH4 sorption isotherm

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311 312 313 314 315

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The methane adsorption isotherms of shale samples are shown in Figure 9 and experimental adsorption data are presented in Table 4 below. The methane adsorption isotherm experiments were carried at 40°C

317

temperature on four shale samples (MOON, PB, WB, NKP). The adsorption data was plotted using

318

Langmuir equation and the Langmuir parameters (VL and PL) are given in Table 4. MOON sample

319

(8ml/g) shows the highest and NKP (3.01 ml/g) shows the smallest adsorption capacity amongst shales.

320

From the figure, it can be seen that the methane isotherms for all the samples are following Type I curve.

321

In a Type I isotherm, the sorbed volume increases linearly with pressure initially. However, after a certain

322

pressure, the rate of increase slows and the plot flattens, reaching equilibrium.

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324 325 326 327

Table 4: Langmuir parameters for methane adsorption isotherm data

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MOON PB WB NKP

Maximum Experimental Pressure, bar

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Shale Sample

328

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175 103 130 103

Langmuir Volume Constant,VL, ml/g 8.60 4.00 5.00 3.03

Langmuir Pressure Constant,PL, bar 23.7 5.4 18.0 0.8

TOC (%)

30.91 12.18 19.08 6.38

329

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Fig 9. Methane adsorption plots of A: MOON, B: PB, C: WB, D: NKP

3.5.1 Repeatability of experimental data

332

In order to check the repeatability of the adsorption data, experiment for two of the shale samples (i.e.

333

MOON and PB shale) were repeated (Fig. 10). Similar experimental conditions (T = 40 oC and up to a

334

pressure of 150 bar for MOON and 100 bar for PB) was maintained. The adsorption data of both the

335

experiments are shown in Figure 10. In the plot, the blue rhombic symbol represents data from the first

336

experiment and the red square symbol represents those of repeat experiment. Good repeatability of

337

experimental data for both the shale samples was observed. The deviation between two experimental data

338

was calculated to be 4.28% for MOON and 4.57% for PB.

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340 341 342 343 344 345

Fig 10. Repeatability of methane isotherm for (a) MOON and (b) PB shale

4. Discussion 4.1 Pore size distribution of Damodar Valley shale samples

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The pore size versus differential pore volume graph was plotted in Fig.11 combining N2 and CO2 pore

348

size distribution. N2 pore size distribution is found bi-modal for all the shale samples (peaks at around 1.1

349

nm and at >3nm, Fig. 11) except MOON, which shows unimodal pore size distribution (PSD) with a peak

350

around 3.6 nm. We note that the dV/dlogr = ln 10 x r dV/dr, which indicates that the derivative (y-axis

351

value) is distinctly expanded for larger pore sizes (Clarkson, 2013). The CO2 pore volume distribution

352

plots indicate a bimodal pore size distribution in the micropore range with the peaks around 0.2 and 0.4

353

nm (Fig. 11). When N2 and CO2 pore size distribution curve were combined together, it can be seen that

354

the last peak from CO2 PSD is matching well with the first peak of the N2 PSD. The continuity and a

355

smooth transition of the CO2 and N2 pore volume distributions are well observed for all the studied shale

356

samples. The plot of combined CO2 and N2 pore volume distributions suggests the dominance of

357

mesopore and micropore in case of all shale samples than that of macropore.

358 359

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346 347

Fig 11. Pore volume distribution using N2-CO2 dV/dlogr plots for A: MOON, B:PB, C:WB, D: NKP samples

360 361 362 363

4.2 Effect of organic and inorganic composition on methane sorption capacity

364

between the TOC and VL of the shales are shown in Fig. 12A. It is observed that VL increases with

365

increasing TOC. This positive correlation between TOC and VL (R2 = 0.96) suggests that organic matter

366

has a strong influence in controlling methane sorption of the studied samples. Similar observations were

367

found by several other workers. (Butland and Moore, 2008; Crosdale et al., 1998; Lamberson and Bustin,

368

1993; Laxminarayana and Crosdale, 1999; Moore, 2012; Aljamaan et al., 2017). Varma in his work has

369

shown that shales from Raniganj, West Bokaro, and Ib valley basins of India show similar results, where

370

TOC and VL positively correlate with each other indicating the positive role of organic matter in methane

371

sorption (Varma et al., 2012).

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The methane Langmuir volumes were compared to the TOC of the studied sample. The correlation

372

The effect of clay minerals on methane sorption behavior was studied. As seen from Fig 12B the

373

total clay and methane VL of the shale samples show no correlation (R2 = 0.39). Hence a conclusion can

374

be made that clay minerals play no role in sorption of methane in this case of the studied shale samples. A

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similar observation was reported by Varma in case of Damodar Valley shales where a decrease in VL was

376

observed with increase in the mineral matter (Varma et al., 2014; 2015) indicating the fact that mineral

377

matters play no role in methane adsorption capacity of shale.

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378 379 380 381 382

4.3 Effect of pore characteristics on methane sorption capacity

383

The methane Langmuir volumes were correlated with the N2-CO2 pore volume and surface area of the

384

studied sample and the data is presented in Table. 5. The correlation between the N2-CO2pore volume –

385

and Langmuir volume (VL) of the shales are shown in Figs. 13 and 14. Low-pressure D–R CO2 isotherms

386

of shales yield micropore volumes which positively correlate with VL (13A) and TOC (Fig. 13B) (R2 =

387

0.95, 0.87 respectively). Organic-lean shale samples have low micropore volumes and have lower VL than

388

organic-rich shale samples. The positive correlation between CO2 micropore volume, VL and TOC

389

suggest that organic matter within the shale samples are the primary hosts of micro-pores, which in turn

390

adsorb the methane gas molecules. Similar results were established by several workers (Ross et al., 2009;

391

Manger et al., 1991; Lu et al., 1995; Ross and Bustin, 2008, 2009; Strapoc et al., 2010; Wang et al., 2013;

392

Tan et al., 2014).

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Fig. 12. The relation between (A) Langmuir volume (VL; cc/g rock) and TOC (wt %) (B) Langmuir volume (VL; cc/g rock) and clay mineral (wt %).

The negative correlation of clay mineral with CO2 micropore volume (R2 = 0.89, 13C) suggests

394

that clay minerals are devoid of micropores in case of the collected shale samples. Furthermore, N2 pore

395

volume was plotted against VL and TOC (Fig. 14A and B respectively) and a negative trend was observed

396

in case of all the shale samples (R2 = 0.79 and 0.30 for 14 A and B). As N2 BET study is capable of

397

detecting nanopores over 2 nm diameter (Bustin, 2008), it can be said that the mesopores might be absent

398

in organic matter and play no role in methane sorption. Previous works on Gondwana shale from India

399

shows that clay minerals contribute to the meso and macropore rather than micropores of shale (Bakshi et

400

al., 2017).

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Fig. 13. Relationship between of CO2 micropore volume and (A) Langmuir volume and (B) TOC (C) Clay mineral

Fig. 14. Relationship between N2 pore volume and (A) Langmuir volume and (B) TOC

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404 405 406 407 408 409

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Sample Moon PB WB NKP

410 411 412

Table 5: Pore characteristics and methane sorption capacity of shale samples BJH EXT BJH Adsorption CO2 micropore CO2 Micropore Surface Surface Pore vol (cc/g) surface area vol (cc/g) area (m2/g) area (m2/g) (m2/g) 8.00 3.29 0.012 86.11 18.85 30.31 12.03 0.011 35.01 7.66 19.11 9.40 0.017 32.42 7.09 29.39 12.65 0.021 19.35 4.23

VL cc/g 8.60 4.00 5.00 3.03

4.4 Effect of Source rock characteristics on methane sorption capacity and pore characteristics

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Source rock characteristics of shale depend upon quality, quantity and thermal maturity of the organic

414

matter. An effort has been made to understand the effect of source rock parameters on sorption behavior.

415

VL is plotted against Tmax, HI and TOC (Fig. 15A and B, Fig. 16A and B, Fig. 12A). It is observed that

416

methane VL increases with thermal maturity (Fig. 14A, R2 = 0.92). This could be due to the structural

417

transformations of the organic fraction. At higher thermal maturity, diagenesis takes place with the

418

generation of more microporosity (Fig. 15A, R2 = 0.81) leading to larger sorbed gas capacities (Levy et

419

al., 1997; Bustin and Clarkson, 1998; Laxminarayana and Crosdale, 1999). Also, it is interesting to note

420

that, type of organic matter plays no role in CO2 micropore volume in shale samples (Fig. 16B, R2 =

421

0.35). A negative correlation was obtained between VL and HI of the shale samples (Fig. 14B, R2 = 0.45).

422

The result of VL vs HI plot indicates that differences in molecular structure of organic matters have a role

423

on CH4 adsorption in organic-rich rocks. Zhang suggested that aromatic rich kerogens (type III &IV) may

424

have a stronger affinity for methane than kerogens containing more aliphatic organic matter (type I and

425

II). Although he claimed that the mechanism for this affinity is not well understood and this is an area and

426

needs further investigation (Zhang, 2012).

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427 428 429

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Fig. 15. Relation of VL with (a) Thermal maturity (b) type of organic matter (HI)

430 431 432 433 434

Fig. 16. Relation of CO2 micropore volume with (A) Thermal maturity (B) type of organic matter (HI)

6. Conclusion

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High-pressure methane sorption analysis was performed on four shale samples from Damodar Valley

436

basin considered as probable shale gas target reservoir for shale gas exploration in India. Similarly, pore

437

structure analyses have been applied to these same four samples of Damodar valley basin of India. The

438

source rock characteristics and mineralogical compositions have driven us to investigate the control of

439

these parameters on microporosity and sorption capacity. The conclusions of the study are summarized

440

below:

441

I.

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435

A very good to excellent hydrocarbon generation potential is indicated by the studied shale

442

samples with the presence of excellent TOC content, type III kerogen, and also the thermally

443

mature nature of the shales. An excellent genetic potential is shown by all samples.

The methane adsorption isotherms for the studied shale samples are following typical Langmuir

445 446

SC

II.

(Type I) curve. III.

Although shales are found to be richer in clay minerals (kaolinite, illite, and chlorite) than quartz,

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444

447

they play no role in methane sorption. The abundance of clays shows no correlation with methane

448

sorption potential.

449

IV.

TOC, VL and CO2 micropore volume correlate positively with one another suggesting the microporous nature of organic matter and their control on gas sorption. The strong positive linear

451

relation of TOC with VL indicates that abundance of organic matter has a positive influence in

452

governing methane sorption of all shales. A negative correlation of CO2 micropore volume, clay

453

minerals

454

V.

455

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450

It is observed that in case of MOON, PB, WB, NKP shales CH4VL increases with increasing thermal maturity.

456 Acknowledgements

458

The authors are extremely grateful to ECIL, NECL, and TISCO for providing samples for this work. The

459

authors also wish to acknowledge important contributions by Dr. Devleena Mani of NGRI for her help in

460

experimentation of Rock-Eval pyrolysis and Dr. Sujan Saha of CIMFR for his help in the experimentation

461

of N2-CO2 BET surface area of the shale samples.

463 464 465 466 467 468 469

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Highlights Organic and inorganic composition of shale samples were analysed.

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Micro and mesopore characteristics of shale were discussed.

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Methane gas storage capacity in shale was explored.

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Effect of shale composition on pore structure and methane adsorption capacity was investigated.

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