Multi-technique characterization of shale reservoir quality parameters

Journal Pre-proof Multi-Technique Characterization of Shale Reservoir Quality Parameters Vaishali Sharma, Anirbid Sircar PII:

S1875-5100(19)30377-4

DOI:

https://doi.org/10.1016/j.jngse.2019.103125

Reference:

JNGSE 103125

To appear in:

Journal of Natural Gas Science and Engineering

Received Date: 21 June 2019 Revised Date:

12 November 2019

Accepted Date: 21 December 2019

Please cite this article as: Sharma, V., Sircar, A., Multi-Technique Characterization of Shale Reservoir Quality Parameters, Journal of Natural Gas Science & Engineering, https://doi.org/10.1016/ j.jngse.2019.103125. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. 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. © 2019 Published by Elsevier B.V.

Sample Collection

Polishing of Plugs and Pieces

Pieces and Plugs

Slices and Plugs cut into desired size

Powder Form of Pieces

Perform MICP, High Porosity and Permeability, HPP

Perform XRF, LPP and FTIR

NMR

Multi-Technique Characterization of Shale Reservoir Quality Parameters Vaishali Sharmaa, Anirbid Sircarb a b

Former Lecturer and Scholar, Pandit Deendayal Petroleum University Director General, Gujarat Energy Research and Management Institute, Pandit Deendayal Petroleum University

Abstract A multitechnique characterization approach has been used to quantitatively and qualitatively evaluate all the reservoir quality parameters, crucial for the exploitation and development of unconventional shale plays. Characterization methods, in particular FTIR, XRF, NMR, MICP, HPP, LPP and High Pressure Permeameter were used on selected 20 younger and older shale samples of Cambay to determine their true petrophysics, mineralogy, brittleness and fracability potential with respect to depth. Properties mainly porosity, permeability, pore size distribution, mineralogy, brittleness, pore sizes and fracability were determined. It was found that younger cambay has medium size pores with high porosity, low silica and high clay content. On the contrary, older cambay has good pore connectivity, rich in organic and clay content, fair brittleness index and capable of producing hydrocarbons. The performed multidisciplinary analysis is first of its kind research and will go a long way in shale gas research and development in India at pilot scale. The generated data can be helpful in minimizing the research gap and hence the challenges associated with the commercial development of these prolific shales. Keywords: Porosity; Pore Size; Elements distribution; Mineralogy; Permeability

1.

Introduction Natural gas and oil extracted from unconventional shale plays is moving to the centre point of current

discussion on energy, security and environment (Rao, 2011) as they can fulfil the increasing demand of energy in the country. Unconventional shale plays development at commercial level has transformed energy fortunes of many countries especially United States and reshaped them into a self-sustainable energy independent country. According to Bellelli (2013), with the advancement of new technologies and practices, the natural gas production in USA may increase from 23.0 trillion cubic feet (Tcf) in 2011 to 33.1 Tcf in 2040. A 44% incremental growth may be observed due to shale gas production, which is expected to grow from 7.8 Tcf in 2011 to 16.7 Tcf in 2040 (Bellelli, 2013; EIA, 2013). A cheap and clean energy maintaining the socioeconomic balance has always been the need of the hour for every country. In India, hydrocarbon (oil and gas) sector plays a major role in influencing India’s economy and Government’s Revenue. There is a natural gas deficit in the country, and it is expected that natural gas demand will reach 606 MMSCMD by 2021-2022 as against a demand of 473 MMSCMD in 2016-17 (BP Energy Outlook, 2018; IBEF, 2018). It becomes imperative for India to harness all of its energy resources especially Shale gas/oil to overcome current energy deficits and reduce heavy reliance on foreign imports. A resource potential of around 2000 TCF of Shale Gas and 96 TCF of recoverable shale gas reserves has been estimated (Rajendra, 2017) and according to preliminary data analysis, basins like Gondwana, Cambay, Krishna – Godavari, Cauvery, Assam-Arakan, Rajasthan, Vindhyan and Bengal are the most promising shale gas basins (EIA, 2013).

1

Despite having enormous shale oil and gas potential its exploration and exploitation in India is still at the research and development stage. A detailed understanding of promising shale basins of India is necessary for the commercial development of these reserves. Taking production from unconventional shale plays is quite difficult and challenging as compared to conventional plays. Unlike conventional reservoirs, unconventional shale plays have grain size below 2 microns, clay content exceeds 50%, organically rich, deposited in low-energy environment, Total organic content is greater than 2% and permeability is very low i.e. in the orders of nanometres (Richard, 2015). To obtain commercial gas rate at such low permeabilities, advance stimulation techniques like horizontal drilling coupled with hydraulic fracturing and microseismicity are required (Rao, 2011). Adequate information on reservoir and completion quality parameters is required before implementing or suggesting stimulation techniques. Quantitative and qualitative determination of the reservoir quality parameters is the focus of the present work as it greatly affects the economic viability of a shale play. These parameters are the collected predictive characteristic tools which are governed by the porosity, permeability, mineralogy, brittleness index, elements distribution, pore networking and its distribution (Diaz et al., 2013; Green, 2013; Speight, 2013; Glaser et al., 2014) of the shales. In this study, multitechnique characterization approach has been used to quantitatively determine all the discussed parameters, crucial for the development of shale plays at large scale (Fig. 1). This type of study will be first kind of research level investigation for Cambay Shale. It is providing with a road map for complete reservoir characterization of Cambay and may be useful for the oil and

gas professionals to understand true shale oil/gas potential of Cambay Basin, Gujarat.

Fig. 1. Top-down Multitechnique approach used for the exploration of shale rock from petrophysical point of view.

The study area chosen for the laboratory investigations is Cambay Shale of North Cambay Basin of Gujarat from Western India which is the main source rock in this basin having Total Organic Carbon (TOC) content values from 0.61 to 14.3 wt. % (average, 2.6 wt. %). More research data is required to study the mineralogical, petrophysical and pore structures of this shale as limited dataset is available. After reviewing work of various researchers (Chen et al., 2014; Gasaway et al., 2017; Hazra et al., 2016; Li et al., 2015; Yingjie et al., 2015; Kumar et al., 2013; Veselinovic et al., 2016; Daigle et al, 2014; Martinez and Davis, 2000; Loucks et al., 2009; Clarkson et al., 2012; Yuan et al., 2015; Schmitt et al., 2013; Wang et al., 2018; Hintzman et al., 2016; Chen et

2

al., 2014; Gasaway et al., 2017; Soeder, 1988; Goral et al., 2015; Tian et al, 2013; Fauchille et al., 2017; Kong et al., 2018; Liu et al., 2016; Spencer et al., 2015; Rowe et al., 2012; Al-Otoom et al., 2005; Saif et al., 2017; Tovar et al., 2017; Shi et al., 2015), it was found that characterization methods like - Scanning Electron Microscopy (SEM), Low & High Pressure Porosity Methods (LPP and HPP), X-Ray Fluorescence (XRF), Permeability-Porosimeter, Mercury Intrusion Capillary Pressure Test, Fourier Transform Infrared Spectroscopy (FTIR), Nuclear Magnetic Resonance, CT Scanning are the most commonly used methods (Table 1) to determine the shale reservoir quality parameters. Table 2 illustrates a review on the research and development activities pertaining to the data collection using characterization methods on ultra-tight, shale low permeable formations. In this work, characterization techniques mainly LPP, HPP, MICP, NMR, FTIR and XRD are used to determine porosity, permeability, pores structure and dimensions, mineralogy, brittleness index and element distribution in the shale sections of Cambay Basin. 2.

Study Area: Cambay Basin The Cambay basin forms a significant petroleum province with established hydrocarbon source potential.

The estimates of the most likely retained in-place accumulations are the order of 2700 MMT of oil and oil equivalent of gas. The phenomenon of geology, stratigraphy and hydrocarbon prospects of this basin has been worked out by several workers. Tectonically, from North to South, the Cambay basin is divided into five tectonic blocks namely Sanchor-Patan, Mehsana-Ahmedabad, Tarapur-Cambay, Jambusar-Broach and Narmada Tapti (Fig. 2). All the tectonic blocks are having thick sequences of Cambay Shale of Lower Eocene age lying on the top of Olpad formation of Palaeocene age (Fig. 2). Stratigraphically, cambay shale is further divided into following two parts Older Cambay Shale Formation (Paleocene-early part of Lower Eocene) OCS This has conformable to gradational relationship with underlying Olpad formation (Fig. 2). It consists of grey to dark grey thin bedded shales, occasionally calcareous and carbonaceous. The thickness varies between 500-1900 m. It is inferred that the deposition took place in paludal to lagoonal environment. The VRo values are in the range of 0.75 % to 0.852 % and the unit has got well defined TOC. These shales could form potential shale gas areas as they are thick, rich in organic content and placed at deeper levels. Younger Cambay Shale Formation (Lower Eocene) YCS It overlies unconformable the Older Cambay Shale Unit and underlies the Kalol formation (Fig. 2). It consists of grey to black massive siderite and pyritic shales along with occasional thin coal bands. Thickness varies between 520 m and 1500 m in Ahmedabad-Mehsana Tectonic block. The Cambay shales are deposited in a reducing euxinic environment, in general. The TOC values range between 0.5 % and 4.0 % and the kerogen type is Type II and Type III.

In the present study, samples were collected from older and younger cambay shale of north tectonic block of cambay basin to understand their true petrophysics, mineralogy, brittleness index and fracability potential. A multi-technique experimental technique has been devised and proposed, which can be unanimously applied for exploring other blocks of cambay and other shales of India. The findings may be helpful in comparing the results of other blocks and a fairway map may be constructed to understand the true shale oil/gas potential of

3

Cambay basin. Similar type of experimentation can be performed for other geographical regions and shales to understand their petrographic characteristics.

Fig. 2. a Location map of Cambay Basin and b. Stratigraphy of Cambay Basin (modified after EIA, 2011.)

3.

Samples and experimental methods

A total of 20 older and younger Cambay shale samples (in the form of pieces and cuttings, Table 1b) belonging to North Cambay Basin were analysed to determine shale reservoir quality parameters in the selected depthinterval. Table 1a gives the details of the selected depth intervals used for this study. A multitechnique integrated characterization approach was applied on the collected shale samples to determine the porosity, permeability, element distribution, mineralogy and brittleness index of the samples. This approach includes quantitative assessment of shales by using characterization methods like Fourier Transform Infrared Spectroscopy (FTIR), X-Ray Fluorescence (XRF), Low Pressure Porosity (LPP), High Pressure Porosity (HPP), Nuclear Magnetic Resonance (NMR), Mercury Intrusion Capillary Pressure (MICP) and High-Pressure Porosity Permeameter. Table 1 Sample Collection Intervals and Characterization Methods Applied a. Sample Collection Intervals and Form Depth Sample Collection Form Interval Younger Cambay Shale (YCS) 1200-1400 m Raw Cutting and Pieces Older Cambay Shale (OCS) 3600-3610 Large Core b. Characterization Method Applied on the Samples Collected from YCS and OCS SN Depth Interval Samples Form Characterization Method Applied 1 1200 - 1400 m ; 3600 - 3610 Powdered and Ashed Fourier Transform Infrared Spectroscopy, m FTIR 2 1200 – 1400 m Powdered Form (63 X-Ray Fluorescence, XRF microns mesh size) 3 1320 – 1330 m; 3600 - 3610 Powdered Form Low Pressure Porosity, LPP m 4 1320 - 1330 m; 3600 - 3610 m Polished Pieces High Pressure Porosity, HPP Shale Sections

4

5

1320 - 1360 m; 3600 - 3610 m

6

1320 - 1330 m; 3600 - 3610 m

7

3600-3610 m

3 Polished Pieces and 1 Horizontal and Vertical Plug 2 polished Pieces, 1 Horizontal Plug 1 Vertical Plug

5

Nuclear Magnetic Resonance, NMR

Mercury Intrusion Capillary Pressure, MICP High Pressure Porosity Permeameter

Table 2 Research and Development Review on Multi-Technique Characterization SN

Characterization Methods

Property Identified

Formation / Basin

Porosity (%)

1.

FTIR, XRD

Different Functional Groups and Mineral Matter

Permian Shales, Raniganj Basin, India

-

Permea bility (mD) -

Mapping of Chemical and Mineralogical Properties

New Albany Shale Devonian and Haynesville Shale, USA

1-9 vol. %

-

Shale Heterogeneity – Clay, carbonates and quartz minerals

Late Devonian / Early Mississippian New Albany Shale, Illinois Basin, USA

1- 4 %

2 - 12

Property Identified

Formation / Basin

Minerals and Functional Group Identified at Depth Intervals 55.80 to 728.70 m

Major Oxide and Elements Content

Barren Measure Formation, India

SiO2 (57.2662.64 %)

Property Identified

Formation / Basin

Aromatics and Saturates

Uppar Assam North East Oil Shale, India Bohai Basin, Eastern China Bohai Basin, Eastern China

Aromatics Saturates: 14.9-28 %w/w 72-85% w/w Avg Porosity: 1.48-4.78% DFT Average pore width 7.70-82.04 nm

Surface area 0.07436.007 m2/g

Bohai Basin, Eastern China

Porosity 0.60-4.39%

Total Pore Area - 0.074-36.007 m2/g; Total intrusion Volume 0.0023-0.0198 cm3/g

Li et al., 2015

Uppar Assam North East Oil Shale Uppar Assam North East Oil Shale

Kaolinite

Illite

Pyrite

Hydrotalcite

Clay

Kumar et al., 2013

O-H Band

Aromati c C-H

Aliphati c

Carboxylic acids

Aromatic Olefinic C-C Double bond

SN 2

SN 3 4

Characterization Methods X-Ray Fluorescence (XRF)

Characterization Methods Nuclear Magnetic Resonance (NMR) NMR

Pore Size and Porosity

6

LTNA – Low Temperature Nitrogen Adsorption

DFT Avg Pore Width, BET adsorption average pore width, Single point adsorption total pore volume, BET surface area

7

9

MICP – Mercury Intrusion Capillary Pressure X-Ray Diffraction

Total Pore Area, Porosity, Total intrusion Volume Minerals

10

IR Spectral Analysis

Inorganic Materials; Functional Groups

Al2O3 (26.19 %-25.88 %) Parameters Obtained

Depth Range

Quartz (wt %)

Identified Minerals

Organic Matter

Clay (wt %)

References

55-1095 m

Abundant in Barren i.e. 14.33 wt % (average)

Yes

14-38 %

Kaolinite Clay Mineral Raniganj: 17-50 % Barakar: 20-31 % Barren: 12 -32% 1-45% (Illite Dominant)

Hazra et al., 2016

Selected on the basis of Vitrinite Reflecta nce 70-1700 m

Carbonates, Aliphatic C-H Stretch, Kaolinite, Quartz, OH Group, Aromatic hydrogen, Aromatic carbon All Clays, Quartz, Feldspar, Carbonates, Albite, Dolomite, Calcite, Ankerite, Pyrite, Sanidine, All Feldspars Kerogen, Illite, Dolomite, Quartz, Chlorite, Pyrite, Clay, Carbonates

Yes

> 40 % (Parallel to the bedding) (Illite – Dominant Clay Mineral)

Gasaway et al., 2017

Fe2O3 (9.23 % to 4.55 %)

25-33 %

K2O (2.92 % to 2.66 %)

CaO (0.54 % to 0.25 %)

-

Chen et al., 2014

References MgO (0.97 % to 0.98 %)

TiO2 (1.47 % to 1.45 %)

Hazra et al., 2016

References

Pore Volume 0.00117 0.03485 cm3/g

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Kumar et al., 2013 Li et al., 2015 BET Average Pore Width 3.87-63.13 nm

Li et al., 2015

Quartz

Kumar et al., 2013

4.

Results

4.1. Multi Mineral Analysis by Fourier Transform Infrared Spectroscopy (FTIR) Approximately 13 samples (belonging to younger and older cambay shale) at depth interval of 1200-1400 m and 3600-3610 m were obtained in the form of cuttings and pieces and transformed into fine powder for running FTIR analysis. The samples were first put into an oxygen-rich Plasma Asher and then left for overnight drying in the oven. FTIR spectrometer needs to be purged for the removal of undesired gases, optics protection and for improving the thermal stability of the instrument. A background spectrum will be collected prior to the spectrum collection for samples by FTIR. This background spectrum detects the spectrometer’s response without the sample in place. A weight of 0.3 g KBr was used for running the background and spectrum was obtained in the absorbance range 4000 cm-1 to 500 cm-1 (Fig. 3). It is recommended to collect a new background every four hours to obtain good results and spectrums for the samples. After this 0.0005 g of ashed powdered shale sample was stranded with 0.3 g of KBr and placed in between the acetone washed die under vacuum conditions. The pressure was continuously levelled up in the range 9.6 - 10.5 kpsi by pressing hand crank. After waiting for 3 minutes, the system was depressurized, vacuum was released, and spectra was collected by hitting “Collect Sample”. The same procedure was followed to collect spectra for other shale samples in the absorbance mode at 4000 cm-1 to 500 cm-1 wavenumbers. The spectra were processed and mineralogical composition of the samples in wt % was identified. The pressed sample discs were removed upon completion of the analysis.

Fig. 3. Background Spectra Collected in the Wavenumbers range 4000 cm-1 – 500 cm-1

For each shale sample, FTIR spectra i.e. absorbance vs wavenumber was obtained and interpreted to identify different groups and mineral composition present in the samples. Out of 13 samples, only three representative spectra (Fig. 4, Fig. 5, Fig.6) are discussed, and the presence of different groups, water and minerals is shown. In the spectra, kaolinite mineral is represented by the Red Line AA’ at wavenumbers 3700 cm-1 and 3610 cm-1

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respectively (Hazra et al., 2016). Peak observed at 3400 cm-1 is indicating the presence of clay mineral and is represented as Blue line B. Spectra obtained at wavenumber 2920 cm-1 and 2850 cm-1 is marked by Green Line i.e. C and C’ respectively and is an indicator of Aliphatic C-H bond stretching. Presence of carbonated is shown by Purple Line i.e. D at wavenumber 1430 cm-1 (Hazra et al., 2016; Chen et al., 2014; Gasaway et al., 2017). EE’ (Orange Line) peaks obtained in the wavenumber range 1200-800 cm-1 is an indicative of presence of water (Gasaway et al., 2017). In the spectra obtained at depth 1250m (Fig. 4), presence of kaolinite, clay carbonates and water is shown. Fig. 5 is the spectra obtained for sample at depth 1326.3 m, and good peaks of Kaolinite, Carbonates, Clay, Aliphatic CH stretching, and Water were observed. Weak peaks of clay and carbonate minerals were observed for sample collected from older cambay (Fig. 6) and may be a favorable zone for implementing advance stimulation techniques such as hydraulic fracturing. The minerals/groups identified in the samples is shown in Table 3 and Table 4.

Fig. 4. FTIR spectra obtained for shale sample collected at top depth 1250 m in the Wavenumbers range 4000 cm-1 – 500 cm-1. Presence of Kaolinite, Clay, Carbonates and Water are indicated by wavenumbers corresponding to spectra AA’, B, D and EE’ respectively. Aliphatic CH stretching is indicated by CC’ line

Fig. 5. FTIR spectra obtained for shale sample collected at top depth 1326.3 m. Good Peaks are observed for Kaolinite, Carbonates, Clay, Aliphatic CH stretching and Water and are indicated by wavenumbers corresponding to spectra AA’, D, B, CC’ and EE’ respectively.

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Fig. 6. FTIR spectra obtained for shale sample collected from older cambay shale at deeper depth 3605.4 m. Weak peaks are observed for clay and carbonate minerals. Other peaks for kaolinite, aliphatic CH and Water content shows sharp peak and represented by lines AA’, CC’ and EE’.

Additionally, a quantitative assessment of identified mineral has also been done and reported in wt% (as shown in Table 4). A ternary diagram (shown in Fig. 7) has been prepared to identify the dominant mineral. It was found that the younger cambay has high clay content as compared to older cambay. Illite is the dominant clay mineral contributing to 62 % to 65 % to the overall clay content of the dataset which include Kaolinite, Smectite, Chlorite and Illite (Sharma and Sircar, 2019). (Fig. 7). The percentage of each clay mineral in the samples is: i) Illite: 21-45 %, ii) Kaolinite: 11-27%. iii) Smectite: 11-19% and iv) Chlorite 0-5%. Quartz which is an indicator of silica is present in the range 1-23 % which is the second dominant mineral present in the entire mineralogy data set. The presence of carbonate and apatite mineral is very low. Feldspar is the range of 1-14 % which is fair percentage. Other minerals like pyrite, siderite etc. holds fair percentage in the data set.

Fig. 7. Ternary Diagram of Minerals present in the shale samples. The dominant mineral is Clay from which Illite is the dominant clay mineral contributing to the highest percentage to the overall clay content of the dataset.

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Table 3 Spectra Interpretation for shale samples Depth (m) 1250 1285 1312 1326 1327.6 1378 3605.4

Spectra Interpretation Kaolinite, Clay, Carbonates and Water Kaolinite, Carbonates, Aliphatic CH Stretching Water, Weak Peaks of Clay Minerals Kaolinite, Carbonates, Clay, Aliphatic CH Stretching and Water Kaolinite, Carbonates, Clay, Aliphatic CH Stretching, Water Weak peaks for clay and carbonate minerals, Sharp peaks of kaolinite, Aliphatic CH and Water Kaolinite, Aliphatic CH Stretching, Water, Low peaks of Carbonate and Clay Weak Clay and Carbonate Peaks, Sharp peaks Kaolinite, Aliphatic CH and Water Content

Table: 4 Minerals identified in the shale samples Depth (m) 1250 1265 1275 1285 1295 1300 1312 1326 1327.6 1334 1377.5 1378 3605.4

Quartz wt % 7 6 4 12 6 11 6 3 6 10 13 8 23

Feldspar wt % 4 2 10 14 2 1 5 11 7 10 5 2 3

Carbonate wt % 7 4 7 1 3 1 8 7 2 5 9 1 7

Clay wt % 74 79 73 58 72 75 73 66 75 54 62 81 61

Illite wt % 39 39 33 25 33 34 36 38 42 30 22 42 21

Kaolinite wt% 18 19 20 17 20 24 19 14 17 11 19 20 27

An Illite / Smectite (I/S) ratio is also calculated to understand diagenesis and clay conversion. Samples show less I/S ratio i.e. 1.2-2.7 % (Fig. 8) and high content of Illite which indicates late diagenesis and possibility of alteration of Smectite and chlorite into Illite. This may be the possible reason for Illite to be the most dominant clay mineral in the given data set.

Fig. 8. Illite / Smectite ratio with respect to depth for the samples collected from younger and older cambay shale

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4.2. Elemental Distribution in Shale using X-Ray Fluorescence (XRF) X-Ray Fluorescence analysis is used for the quantitative determination of elemental composition of materials in powder, solid and liquid forms. Approximately, 20 shale cuttings were collected at every 5 m of interval in the depth range of 1200 – 1400 m and analysed for the fluorescence measurement in Spectro Xepos Spectrometer which is having precision of analysis better than 5% for major elements and better than 10% for trace elements. As a part of sample preparation, samples were first washed, dried off, crushed and screened up to 63 µm mesh size to obtain a finished powder, which was later placed into the sample cups and then placed into the spectrometer for obtaining elemental distribution of the samples. The analysis revealed the presence of major and trace elements in all the samples. Table 5 and Table 6 shows the concentration of different oxides of major and trace elements identified in the entire dataset through XRF analysis. The identified oxides are mainly Al2O3, SiO2, P2O5, K2O, CaO, TiO2, Fe2O3, ZnO, BaO and MnO. SiO2 was observed to be the most abundant oxide with its content varying between 29.4 % and 48.9 %. Al2O3 was observed to be the next most abundant oxide with its content ranging within the limits of 13.4 – 28.1 %. Fe2O3 was noted to be the third most abundant oxide in the samples. The sample also contains variable amounts of trace elements like Mn, Zr, Mo, Ba, Cr, Ti and U. The concentrations of trace elements Zr, Cr and Ba are in the range of 220 – 435 ppm, 39 – 412 ppm and 427 – 155200 ppm respectively which is very high in all the studied samples and indicates presence of marine depositional environment. Table 5 Major Oxide Distribution within the Cambay Shale Samples identified through XRF Analysis Element Al2O3 SiO2 P 2O 5 K 2O CaO TiO2 Fe2O3 ZnO K2O / Al2O3 Unit % % % % % % % % % Reference 10.39 83.26 0.02 2.37 0.87 0.19 3.96 0.04 Sample Sample Id CB XX40 26.17 46.95 0.25 1.28 0.50 2.94 19.64 0.01 0.05 CB XX50 20.94 39.98 0.21 1.53 0.56 3.56 18.88 0.02 0.07 CB XX65 20.09 41.60 0.18 1.48 0.43 3.59 14.23 0.02 0.07 CB XX75 21.46 42.13 0.82 1.85 1.98 3.11 20.81 0.02 0.09 CB XX85 21.10 40.33 0.17 1.88 2.73 3.33 18.30 0.02 0.09 CB XX95 22.57 42.16 0.16 2.03 0.37 2.96 12.99 0.02 0.09 CB XX00 23.59 42.30 0.23 1.95 0.52 3.08 18.67 0.02 0.08 CB XX12 23.05 42.25 0.21 2.01 0.57 3.00 17.78 0.02 0.09 CB XX19 23.67 37.37 0.22 1.77 1.18 2.10 22.00 0.01 0.07 CB XX20 13.48 29.44 0.33 2.80 1.98 1.17 20.69 0.01 0.21 CB XX28 15.55 34.51 0.20 4.18 0.75 1.54 17.76 0.02 0.27 CB XX31 19.09 40.43 0.29 3.82 0.69 2.14 15.16 0.02 0.20 CB XX34 17.20 35.07 0.16 4.37 0.60 1.86 13.23 0.02 0.25 CB XX75 28.13 49.81 0.16 1.69 0.29 2.02 12.22 0.01 0.06 CB XX76 20.64 41.41 0.16 1.69 0.27 2.62 12.20 0.02 0.08 CB XX76 18.09 35.69 0.20 1.98 0.57 2.46 17.81 0.02 0.11 CB XX77 21.38 41.92 0.18 1.60 0.33 2.68 19.22 0.02 0.07 CB XX77 18.00 36.18 0.14 1.75 0.31 2.06 13.47 0.02 0.10 CB XX78 18.43 37.20 0.23 1.77 0.37 2.10 13.31 0.02 0.10 CB XX79 26.72 48.91 0.14 1.66 0.30 1.80 14.99 0.01 0.06

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Al2O3/ TiO2 %

8.90 5.89 5.59 6.91 6.33 7.62 7.65 7.69 11.26 11.48 10.10 8.91 9.23 13.93 7.88 7.35 7.97 8.74 8.79 14.83

Table 6 Trace Elements within the Cambay Shale Samples identified through XRF Analysis Trace Elements (ppm) 25 29 40 56 Atomic No. MnO CuO ZrO2 Bao Element CB XX40 1930 119.9 399.5 2769 CB XX50 1735 182.4 433.6 427 CB XX65 1094 191 404.9 3268 CB XX75 3083 187.8 349.4 704.6 CB XX85 2158 174.1 391.8 770.5 CB XX95 938.3 212.4 357.2 1968 CB XX00 2365 215 348.1 1626 CB XX12 1274 223.4 435.6 1253 CB XX19 2783 104.4 286.6 35800 CB XX20 3214 88.7 274.7 155200 CB XX28 1698 200.7 220.3 127000 CB XX31 1310 187.3 399.9 92810 CB XX34 1006 184.5 331.8 118400 CB XX75 1083 166 345.1 23650 CB XX76 1380 204.9 400.5 4449 CB XX76 2039 189.2 396.4 11960 CB XX77 2179 222.8 332.6 5414 CB XX77 1638 157.3 340.8 9643 CB XX78 1580 166.8 342 8684 CB XX79 1831 121.1 328.1 20770 4.3. Petrophysical

(ɸ

and

k)

Characterization

of

90 Th 11.6 15.6 12 13.3 13.4 12.1 15.8 13.9 6.2 0.4 2.4 9.1 7.7 8 13.4 12 14.2 11.1 11.7 6 Cambay

92 U 1.2 2.8 1 4.5 2.2 1.9 4.7 6 0.4 1.1 1.2 5.4 5.2 0.5 1.3 0.4 1.1 0.7 1 0.4 Shale

4.3.1. Low Pressure and High-Pressure Porosity (ɸ) LPP and HPP Analysis of three shale samples collected at depth intervals 1320 – 1330 m (YCS) and 3600 3610 m (OCS) was carried out using Micrometrics Accu Pyc-II LPP and Micrometric Accu Pyc HPP apparatus. It was observed through low pressure porosity (LPP) investigations that the sample has porosity in the range 1118 % and at high pressure, the value ranges from 11-15 % as identified through Sharma and Sircar, 2019. The results are tabulated and shown in Table 7. Table 7. Low Pressure Porosity and High-Pressure Porosity Data at different depth and Temp. Depth. M 1327.6 1326.3 3605.4

Temp. (deg. C) 25.0 25.0 25.6

LPP Porosity (%) 17.1 18.10 11.2

HPP Porosity (%) 16.7 15.1 11.5

Bulk Density (g/cc) 2.08 2.23 2.37

4.3.2. High Pressure Gas and Liquid Porosity and Permeability (ɸ and k) A horizontal plug extracted from the core collected from older (deeper) cambay shale at depth 3600-3610 m was run in the Automated Permeameter/ Porosimeter AP608 to investigate the porosity and permeability of the sample under the realistic reservoir pressure conditions. The plug with dimensions- length 5.35 cm, diameter 2.51 cm and weight 63.4 g was loaded in the core holder of the instrument to determine the liquid and gas permeability & porosity with respect to time at confining pressure ranges from 500 to 3000 psi. Table 8a & 8b shows the observed values of porosity and permeability of the tested sample. Low porosity values were observed in the sample i.e. in the range of 3 to 9 % with respect to change in time and confining pressures. The

12

permeability is also very low i.e. 0.007 mD (liquid permeability) and 0.014 mD (air permeability) which indicates that it is a low permeable shale formation. Table 8a Porosity Experimental Data P conf (psi) 576 730 1007.8 1480.1 1971.2 2243.1 2483.9 2981.6

Time Horizontal Plug

Sample

0:07 0:16 0:25 0:35 0:47 0:59 1:11 1:20

Table 8b Liquid & Air Permeability Experimental Data P conf Sample Time (psi) 576 Horizontal Plug 0:07

Porosity (%) 8.987 8.127 8.838 7.598 6.678 6.185 5.196 3.939

Porosity (%) 8.987

K air (mD) 0.014

K klink (mD) 0.007

Slip factor 49.739

4.3.3. Nuclear Magnetic Resonance (NMR) Based Porosity Three shale pieces and 1 horizontal and vertical plug collected at depth interval of 1320 - 1360 m (YCS) and 3600 - 3610 m (OCS) were analysed using NMR Analyzer. Prior to the analysis, samples were weighed, polished and then tested in Hg i.e. Mercury set up for measuring bulk volume of each samples. Fields like diameter, length, bulk volume and dry piece mass (wt.) were entered in the set up to obtain NMR based porosity and pore radii of each sample. The NMR porosity values are shown in Table 9, which were obtained at TAU (Ʈ) = 57 µs, T2 relaxation time of 200ms and Signal to Noise Ratio (SNR) of 100. Table 9 NMR Based Porosity Results Sample Depth (m) 3605.4 (Horizontal) 3605.4 (Vertical) 1326.3 (Piece) 1327.6 (Piece) 1328.0 (Piece)

T2_peak,ms 0.28 0.35 0.25 0.22 0.20

T2_geom,ms 0.27 0.32 0.23 0.22 0.20

Porosity Units 3.36 4.7 6.33 2.31 3.49

Pore Body Radii (µm)# 0.04 0.05 0.04 0.03 0.02

# Pore body radii is calculated by assuming surface relaxivity of 0.05 µm / ms and pores as spherical pores.

4.3.4. Mercury Intrusion Capillary Pressure (MICP) Porosity Micrometric Auto Pore-IV Mercury Porosimeter with one high pressure and two low pressure analysis port was used to test the shale samples collected at depth intervals 1320 - 1360 m and 3600 - 3610 m. This high pressure (60, 000 psi) set up can determine broad range of values for pore- size distribution / pore diameters i.e. from 0.003 to 360 µm. The set up consists of a penetrometer which entails a sample cup and is attached to a precision-bore glass capillary stem. The shale samples were placed in the sample cup and mercury was injected, filling the sample cup and the glass capillary stem. The pressure is continuously increased in the penetrometer, thereby intruding mercury into the pores of the samples beginning with the pores of largest diameter and ending

13

with the pores of smallest diameter. It is to be noted that continuous increase in pressure or high-pressure results in more intrusion into the smallest diameter pores. Material compressibility, pore throat radius, permeability, pore size are the parameters obtained from this measurement and are reported in Table 10. Table 10 Experimentally determined values from Mercury Porosimeter Sample Depth 3605.4 m 1327.6 m 1328 m

Hg Porosity % 10.3451 14.1188 12.8903

Bulk Density gm/cc 2.358 2.0837 2.3472

Grain Density gm/cc 2.6301 2.4262 2.6946

Stem Volume % 79 72 78

Maximum Pore Radius Nm 4.498725 3.373132 3.373149

Hysteresis ml*100 2.74 4.20 3.53

Table 11 Comparative analysis of porosity and pore radius values of all the samples collected from Older and Younger Cambay Shale Shale Sections Property

Older Cambay At Depth 3605.4

Total Intrusion Volume, mL/g Total Pore Area, m2 / g Median Pore Radius (Volume), nm Median Pore Radius (Area), nm Average Pore Radius (2V/A), nm Bulk Density at 4.48 psia, g/mL Apparent (skeletal) Density, g/mL Porosity, % Stem Volume Used, %

0.0439 22.752 3.9 3.6 3.9 2.3580 2.6301 10.3451 79

5.

At Depth 1327.6m 0.0678 35.285 3.8 2.7 3.8 2.0837 2.4262 14.1188 72

Younger Cambay At Depth 1328 m 0.0549 28.228 3.6 2.8 3.9 2.3472 2.6946 12.8903 78

Discussions Advance stimulation technique such as hydraulic fracturing is most commonly used to exploit

unconventional shale resources at commercial scale. To design an exploitation plan, an adequate information on shale reservoir quality parameters and hydraulic parameters is always required and needed. Shale gas exploration and exploitation in India is at the research and development stage. However, tremendous efforts are going on to understand complex nature of this shale and suggesting best exploitation plans. The present work is an effort to determine the key reservoir properties of Cambay including porosity, permeability, brittleness and fracability potential, and understand it from reservoir point of view so that better stimulation strategies can be implemented for its exploitation. Following are the key inferences from the obtained results: 5.1 Mineral based shale brittleness index Brittleness index is an important property from fracking point of view. For a shale to be favorable for fracking BI values greater than 40% are more acceptable, however low values are still considerable if clay conditioning and proper fracking fluid is used (Rojas et al., 2016). We have calculated the brittleness index using correlation proposed by Rojas et al. (2016) for the collected shale samples from older/younger cambay. It was found that shales of younger cambay having less brittleness index (Fig. 9) and proper treatment schedule with clay conditioning may be required before intitiating fracturing in the selected depth intervals. The reason

14

may be presence of high clay content (mainly Illite which might have formed due to the alteration of Smectite and Chlorite into Illite). On the contrary older cambay shale is highly brittle and more favorable for fracking. This region has low clay content and high quartz (Table 4) as confirmed by the FTIR test. Interestingly, there are some zones in younger cambay where high BI values are found and may be brittle. This needs to be confirmed by understanding element composition and geomechanics of the selected depth intervals.

Fig. 9. The frequency of occurrence of Brittleness Index with respect to depth is shown in this figure.

5.2 Fracking Potential SiO2 and Al2O3, both the oxides are important to understand brittleness and fracturing potential of shale and are the main contributors to the samples’ elemental composition, having their content varying between 29.4 48.9% and 13.4 – 28.1% respectively for the younger shale. This makes SiO2 the most abundant mineral oxide present in the entire dataset. Fe2O3 has been identified as the third most abundant oxide with its content ranging in the limits of 12-22 %. Similar kind of results have been observed by Hazra et al., 2016 for Permian shales. High silica values tend to make shale more brittle while high Al2O3 values makes it more ductile. SiO2 / Al2O3 ratio is a measure of relative brittleness i.e. higher the ratio, higher the brittleness and higher the fracability potential. This ratio can therefore be entitled as an important oxide ratio to identify fracable zones of interest in the formation. SiO2 / Al2O3 ratio has been determined with respect to change in depth from top to bottom and is shown in Table 5. In the studied samples, it was observed that deeper depth sections may be more favorable fracable zones as SiO2 / Al2O3 ratio is higher in the greater depths of the formation (Table 5). This has also been confirmed by FTIR measurement (Fig. 9) which shows moderate to high brittleness index values. These zone with good brittleness index may be favorable for shale exploitation / stimulation (Sharma and Sircar, 2019). 5.3 Petrophysical (Porosity and Permeability) distribution in shales LPP, HPP, and Permeameter set ups were used to determine porosity and permeability of the samples having high and low clay content belonging to younger and older cambay. It was found that samples at shallow depth (from younger cambay) have high LPP and HPP porosity as compared to the deeper older cambay sample. This may be due to the presence of some strata with high clay content. These strata may be composed of

15

siltstones which are sandwiched in between the shales. Older cambay is having less LPP and HPP porosity which was confirmed again by performing an experiment to determine porosity and permeability under realistic reservoir pressure conditions. Ultra-low permeability i.e. 0.007 mD (liquid permeability) and 0.014 mD (air permeability) and low porosity values i.e. in the range of 3 to 9 % (Table 8a and Table 8b) were observed with respect to change in time and confining pressures. This shows the true characteristics of a shale reservoir. 5.4 Pore sizes and Fluid distribution NMR is a characterization technique used to study the pore sizes and porosity of the shale samples. This measurement technique has been used by various researchers (Curtis et al., 2011; Miknis et al., 1979; Netzel et al., 1982; Lewis et al., 2013; Sulucarnain et al., 2012; Miknis et al.,1984; Odusina and Sigal, 2011; Minh et al., 2006; Fleury et al., 2016; Chen et al., 2012; Washburn et al., 2013) on shales of different countries (like USA, China and Middle East) to understand presence of clay bound water, free fluids movement and Capillary bound water. The measured amplitude of NMR signal is proportional to the amount of hydrogen nuclei (Lewis et al., 2013). NMR T2 distributions are used to differentiate bound porosity (Clay bound and Capillary Bound) and free porosity. Relaxation time (T2) for clay bound water is very short i.e. 3 ms (Lewis et al., 2013; Odusina and Sigal, 2011; Curtis et al., 2010 ), however for sandstones and carbonates (Capillary bound and free fluids) relaxation time is 33 ms and 100 ms respectively (Lewis et al., 2013; Odusina and Segal, 2011).

Fig. 10a. NMR T2 relaxation vs Incremental porosity (%) a. for sample depth 3605.4 m (Older Cambay Shale, horizontal plug), b. for sample depth 3605.4 m (vertical plug), c. for sample depth 1326.3 m (Younger Cambay Shale),d. for sample depth 1328 m (Younger Cambay Shale)

16

In the present work, as received one horizontal and vertical plug of older cambay shale and 3 pieces from Younger cambay shale have been tested for NMR based porosity characterization. Table 9 shows the experimentally obtained data for younger and older cambay shale. Fig. 10a to Fig.10d shows the NMR distributions obtained for Younger and Older Cambay Shale. In all the samples, sharp peaks are observed in between 0.20 ms to 0.35 ms relaxation times. Generally, clay bound waters shows shorter relaxation time i.e. 3 ms (Lewis et al., 2013; Odusina and Segal, 2011; Curtis et al., 2010). Very small peaks are observed for sandstones which indicates low levels of free fluids in the samples. The peak magnitude in all the sample is almost similar. NMR porosity for each sample has been tabulated in the Table 9. Using the correlation discussed by Curtis et al., 2010, pore radii of the samples was calculated by assuming spherical pores and a surface relaxivity of 0.05 µm / ms under fast diffusion limit. It has been observed from Table 9 that calculated pore body radii are in the range of 0.02 to 0.05 µm (20 nm to 50nm). This shows that all the pore sizes are medium-sized pores. In the Fig. 10a to Fig. 10d the red line indicates the clay bound water cut offs and the green line corresponds to the capillary bound water cut offs which is 3 ms and 33 ms respectively. High peaks are observed for clay bound water. The presence of high clay content has also been observed by Mineralogy Analysis. 5.5. Pore size under capillary pressure Mercury is a non-wetting fluid and tend to bridge across the openings of the small pores. For a mercury to enter into the tiny or small pores, sufficient pressure should be applied for force entry (Curtis et al., 2010). According to Washburn equation, mercury Porosimetry is computed as Eq. 1 (Elgmati et al., 2011), P

=

-

2σ

Cos

ϴ

/

r

Eq.1 Where, P is the pressure that must be applied to the mercury to enter in to the small and tiny pores of radius r, σ is the mercury surface tension and ϴ is the contact angle. High pressure is required to force mercury to enter the very tiniest or small pores provided that, surface tension and contact angle is constant. Lower the pore radius, higher will be the force or pressure required for mercury intrusion and penetration. The volume of mercury forced to enter the pores at specific pressure is equal to the total volume of pores of certain size (Paul, 1993). Pore size, permeability, Porosity, bulk density, compressibility etc. are the properties of the rock that can determined by using MICP characterization techniques, also known as Mercury Porosimetry. Numerous attempts has been made by Curtis et al., 2010; Elgmati et al., 2011; Clarkson et al., 2012; Schmitt et al., 2013; Li et al., 2015; Al Hinai et al., 2014; Josh et al., 2012; Mastalerz et al., 2013; Curtis et al., 2011; Comisky et al., 2011; Dawson et al., 2010; Zhang et al., 2017 on Western Australia, USA and China Shale to understand the pore size and its distribution using mercury porosimetry. The present work uses three shale samples of Cambay Shale (Younger (YCS-1 & YCS -2) and Older (OCS)) and conducted successful MICP experimentation on all of them. The test summary is presented in Table 10 which shows the experimentally determined values for porosity, bulk density, pore radius (maximum) and compressibility. Table 11 details out the comparative analysis of all data obtained for the sample.

17

5.5.1. Intrusion & Extrusion Cycles and Pore Size of Samples Collected at Depth 3605.4 m (Older Cambay, OCS) For a mercury to penetrate into the pores, the pressure must be sufficiently high and radius of curvature (i.e. pressure surface created by mercury as it bridges the pore opening) should be equal to the radius of the pore. Fig. 11a shows the cumulative intrusion of mercury (mL/g) into the largest and smallest pores at Hg surface tension 485 dyne/cm and contact angle 130 degrees. It can be seen that, there is no Hg intrusion when the pore diameter is greater than 1 µm and pressure upto 100 psia which means that, mercury has bridged across the pore but unable to penetrate at such low-pressure value. So, more energy / more pressure is required to force mercury to enter the tiniest and smallest pores. There is a continuous growth observed in Hg intrusion curve as the pressure is increased from 100 psia to 15000 psia which means that there is a good volume of pores available with opening size range from 1 µm to 0.01 µm (Fig. 11b). Fig. 11c shows the change in incremental Hg intrusion with respect to pore size radius in nano meters. Peaks are observed at very high pressure ranging from 15000 psi to 60, 000 psi for which pore throat radius is observed in the range 4.5 nm to 1.5 nm. Odusina et al., 2010 performed NMR investigations on Barnett shale samples and observed the pore throat radius range from 8 to 2 nm at very high pressures ranging from 14000 psi to 50, 000 psi. The median pore throat radius was observed as 3.6 nm (i.e. 0.007 µm). Most of the mercury intruded in the pressure range in between 15000 psia to 60,000 psia at which pore throat radius of 4.5 nm to 1.5 nm (i.e. 0.009 to 0.003 µm) was observed. The total occupied pore area is 22.75 (m2/g) with average pore radius as 3.9 nm and porosity as 10.34 % and is tabulated in Table 10 and 11.

Cumulative Intrusion (mL/g)

Cummulative Intrusion (mL/g)

0.05 0.045 0.04 0.035 0.03 0.025 0.02 0.015 0.01 0.005 0 1000

100

10

1

0.1

0.01

0.001

Pore Diameter (Micrometers)

Fig. 11a. Cumulative Intrusion Plot vs Pore Diameter (micrometers). The graph illustrates the change in pore diameter and available volume of pore for Hg cumulative intrusion at depth 3605.4 m (OCS)

18

Fig. 11b. The cumulative intrusion with respect to incremental change in pressure has been plotted for intrusion and extrusion cycles of Hg injection at depth 3605.4 m (OCS)

Fig.11c. At depth 3605.4 m (OCS), incremental intrusion with respect to pore size radius for Hg intrusion and extrusion cycle has been plotted and presented in this graph

5.5.2 Intrusion & Extrusion Cycles and Pore Size of Samples Collected at Depth 1327.6 m and 1328 m (Younger Cambay Shale, YCS-1 and YCS-2) Fig. 12a and Fig. 13a shows the cumulative intrusion of mercury (mL/g) into the largest and smallest pores at Hg surface tension 485 dyne/cm and contact angle 130 degrees for both the samples of younger cambay shale collected at depth 1327.6 m (YCS-1) and 1328 m (YCS-2). It can be seen for YCS-1 from Fig. 12a and Fig. 12c, there is an incremental Hg intrusion in the pore diameter range 10 µm to 0.1 µm as pressure reaches up to 10,000 psia. There is large volume of pores available beyond 10,000 psia with pore openings in the size range 0.016 µm to 0.003 µm. Once the pressure reaches the upper limit, i.e. 60, 000 psi, extrusion cycle will begin and reduced to atmospheric pressure (Fig. 12b). The median pore radius was observed for this sample is 2.7 nm. Maximum mercury intruded in the pressure range in between 10,000 psia to 60,000 psia at which pore throat

19

radius of. 0.016 to 0.003 µm was observed. The total occupied pore area is 35.28 (m2/g) with average pore radius as 3.8 nm and porosity 14 % as tabulated in Table 10 and 11. However, in the YCS-2 (Fig. 13a and Fig. 13c), continuous cumulative intrusion occurs up to 0.01 µm pore diameter and pressure up to 10,000 psia. Sharp increase in the peak observed in the pore size ranges from 0.01 µm to 0.003 µm beyond 10,000 psia. Once the pressure reaches the upper limit, i.e. 60, 000 psi, extrusion cycle will began and reduced to atmospheric pressure (Fig. 13b). The intrusion and extrusion cycle is very similar to the cycles observed for YCS-1. The median pore radius reported for this sample is 2.8 nm. Maximum mercury intruded in the pressure range beyond 10, 000 psi at which pore throat radius of. 0.01 to 0.003 µm was observed. The total occupied pore area is 28.22 (m2/g) with average pore radius as 3.9 nm and porosity 12 % as tabulated in Table 10 and 11. According to IUPAC classification, the pores have been classified into 3 types: micro-pores with radius less than 2nm, medium pores with radius from 2 nm to 50 nm, macro-pores with radius over 50 nm. In the Shale section of Cambay Basin, it has been observed that the pore radius of all three samples are lying in the range 3 nm to 2 nm which indicates that all the samples are medium pores sized (tiny pores). According to IUPAC classification, the pores have been classified into 3 types: micro-pores with radius less than 2nm, medium pores with radius from 2 nm to 50 nm, macro-pores with radius over 50 nm. In the Shale section of Cambay Basin, it has been observed that the pore radius of all three samples are lying in the range 3 nm to 2 nm which indicates that all the samples are medium pores sized (tiny pores)

Fig. 12a. Cumulative Intrusion Plot vs Pore Diameter (micrometers) at depth 1327.6 m (The graph illustrates the change in pore diameter and available volume of pore for Hg cumulative intrusion . Fig. 13a. Cumulative Intrusion Plot vs Pore Diameter (micro meters). The graph illustrates the change in pore diameter and available volume of pore for Hg cumulative intrusion at depth 1328 m.

Fig. 12b. The cumulative intrusion with respect to incremental change in pressure has been plotted ) at depth 1327.6 m for intrusion and extrusion cycles of Hg injection

20

Fig. 13b. The cumulative intrusion with respect to incremental change in pressure has been plotted at depth 1328 m. for intrusion and extrusion cycles of Hg injection

Fig. 12c. Incremental intrusion with respect to pore size radius for Hg intrusion and extrusion cycle has been plotted ) at depth 1327.6 m and presented in this graph

Fig. 13c. At depth 1328 m, Incremental intrusion with respect to pore size radius for Hg intrusion and extrusion cycle has been plotted and presented in this graph

21

The permeability of samples is calculated as per the Kozeny model and plotted with respect to the Hg based porosity. It is assumed that the pores are straight (cylindrical capillaries) in nature and tortuosity coefficient is 1. For the samples, the calculated permeability value is low and is lying in the range 5.4 x 10-3 mD to 5.9 x 10-3 mD. This has been shown and represented in Fig. 14.

6.

Comparative Assessment with US Shales A property wise comparison of Cambay (India) shale with various prominent shales of USA is illustrated in

Table 12. Cambay has very high clay content which may be due to the presence of siltstones in between the shales unlike US shales which are less clay rich having ultra-low permeability and high silica content. Only Eagle ford and Haynesville shale shows low clay and silica content. Table 12 Comparative Assessment of Cambay and USA shales Experimental & Some Literature Data Data obtained from Literature (EIA, 2013) Fig. 14. Permeability estimated from Kozeny-Models, assuming Tortuosity coefficient equal to 1 and pores are assumed to be straight, Cambay Shale Bakken Eagle Ford Marcellus Wolfcamp cylindrical capillaries. A plot of porosity and permeability has been created and the permeability of all the samples are lying in theHaynesville range of 5.4 Shale Shale Shale Shale Shale Shale x 10-3 mD to 5.9 x 10-3 mD, which is quite low. Cambay Permian TX-LA-MS Basin Williston South Texas Appalachian Midland Salt 500-1900 (Older Organically cambay) Rich 10-120 120-300 75-150 300-575 225-300 520-1500 Thickness (ft) (younger cambay) TOC % 0.6-14.3 5-20 2-8 4-7 2-9 3-4 (Avg) Thermal 0.75-0.85 Maturity, Ro, 0.5-1.0 0.7-1.8 1.3-2.4 0.7-0.9 1.7-2.8 % Porosity % 11 3-12 4-15 7-9 5-18 7-14 Permeability 0.007mD 10-20000 100-1500 nD 100-200 nD 50-300 nD 50-400 nD (nD) nD Clay Content 50-80 34-44 10-20 10-35 22-36 25-35 % Quartz 3-23 34-51 10-30 10-60 14-35 Content %

22

7.

Conclusions

We have performed a multitechnique reservoir characterization on the younger and older shale of Cambay, which has an immense potential of shale oil/gas and is capable of generating 90 TCF of hydrocarbons. All the data pertaining to shale petrophysical and mineralogical properties was experimentally determined and interpreted to understand reservoir quality of this shale. Properties mainly porosities, permeability, pore size distribution, mineralogy, brittleness, pore sizes and fracability were determined. It was found that younger cambay has medium size pores with high porosity, low silica and high clay content. On the other hand, older cambay has good pore connectivity, rich in organic and clay content, fair brittleness index and capable of producing hydrocarbons. They are more favorable from fracking point of view as the brittleness index and silica content is good. This must be confirmed and checked with geomechanical logs / lab data to make a valid conclusion. So, a detailed study of geomechanical parameters is also required to confirm their fracability potential. Accordingly, advanced stimulation techniques (in particular, hydraulic fracturing) for their commercial exploitation may be suggested. The performed multidisciplinary analysis is first of its kind research and will go a long way in shale gas research and development in India at pilot scale. The generated data can be helpful in minimizing the existing research and development gap in these shales and many challenges associated with their development can be overcome. Conflicts of Interest There are no conflicts of interest to declare. Acknowledgments The authors extend their sincere thanks to Prof. Chandra Rai and Prof. Subhash Shah, The University of Oklahoma, USA, for giving an opportunity to work in IC3 centre of MPGE, OU to complete all the necessary experimentation and data generation. We are also thankful to Institute of Seismological Research for allowing us to work in their laboratory for additional data generation. List of Abbreviations & Variables Al2O3

Aluminium Oxide

BaO

Barium Oxide

CaO

Calcium Oxide

CB

Cambay Basin

CuO

Copper (II) Oxide

EIA

Energy Information Administration

Fe2O3

Iron (III) Oxide

FTIR

Fourier Transform Infrared Spectroscopy

HPP

High Pressure Porosity

IC3

Integrated Core Characterization Centre

IR

Infrared

ISR

Institute of Seismological Research

IUPAC

International Union of Pure and Applied Chemistry

K2O

Potassium Oxide

23

LPP

Low Pressure Porosity

LTNA

Low Temperature Nitrogen Adsorption

MICP

Mercury Intrusion Capillary Pressure

MnO

Manganese (II) Oxide

NMR

Nuclear Magnetic Resonance

OCS

Older Cambay Shale

P2O5

Phosphorous Pentoxide

SiO2

Silicon Dioxide

Th

Thorium

TiO2

Titanium Dioxide

TOC

Total Organic Carbon

U

Uranium

VRo

Vitrinite Reflectance

XRD

X-Ray Diffraction

XRF

X-Ray Fluorescence

YCS

Younger Cambay Shale

ZnO

Zinc Oxide

ZrO2

Zirconium Dioxide

mD

milli Darcy

nm

nanometer

Tcf

Trillion cubic feet

IBEF

India Brand Equity Foundation

BP

British Petroleum

CT

Computed Tomography

KBr

Potassium Bromide

CH

Carbon-Hydrogen Bond

ɸ

Porosity

k

Permeability

Pconf

Confining Pressure

Kklink

Klinkenberg Permeability

T2

Relaxation time

BI

Brittleness index

ms

milli seconds

σ

mercury surface tension

ϴ

contact angle

r

Pore radii

P

pressure

Hg

Mercury

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Highlights •

A multitechnique characterization approach has been used to understand true petrophysics, brittleness and fracability of cambay shale.

•

Porosity, permeability, mineralogy, brittleness index, elements distribution and pore size are determined through the laboratory experimentation.

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Shales are found to be clay rich, having medium pore size with ultralow permeability.

Author Contributions Vaishali Sharma: Methodology, Analysis, Interpretation, Writing, Reviewing Anirbid Sircar: Reviewing, Supervision, Interpretation, Visualization, Comments

Declaration of interests ☒ The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. ☐The authors declare the following financial interests/personal relationships which may be considered as potential competing interests: