geological controls on the eocene shale gas resources plays in
TRANSCRIPT
GEOLOGICAL CONTROLS ON THE EOCENE SHALE GAS
RESOURCES PLAYS IN NORTH AND WEST INDIA:
STRATIGRAPHY, PALAEOENVIRONMENT AND
TECTONIC SETTING
THESIS SUBMITTED TO THE UNIVERSITY OF JAMMU
FOR THE AWARD OF THE DEGREE OF
DOCTOR OF PHILOSOPHY
IN
GEOLOGY
(FACULTY OF SCIENCE)
BY
MATEEN HAFIZ
POSTGRADUATE DEPARTMENT OF GEOLOGY
UNIVERSITY OF JAMMU
JAMMU-180006
2015
Post Graduate Department of Geology
University of Jammu
Jammu – 180006
CERTIFICATE
This is to certify that:
i) This thesis entitled “Geological Controls on the Eocene Shale Gas
Resources Plays in North and West India: Stratigraphy,
Palaeoenvironment and Tectonic Setting” embodies the work of Mr.
Mateen Hafiz.
ii) The candidate has worked under my supervision for the period required under
the statutes of the University of Jammu.
iii) The candidate has put in the required attendance in the Department during this
period.
iv) The conduct of the candidate remained satisfactory during this period.
v) The candidate has fulfilled the statutory conditions as laid down in statutes
(Section 18).
Prof. G. M. Bhat Supervisor
Countersigned
Prof. R. K. Ganjoo Head of the Department
Dedicated to my
Parents
Table of Contents
ACKNOWLEDGEMENTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .(i)
LIST OF FIGURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (iii)
LIST OF TABLES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .(vii)
CHAPTER 1: INTRODUCTION
1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 Purpose and Scope of the Study. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3
1.3 Outline of the Thesis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
CHAPTER 2: GEOLOGY OF THE BASINS
2.1 Cambay Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6
2.1.1 Stratigraphy and Tectonic Evolution of the Basin. . . . . . . . . . . . . . . . . . . . . 10
2.1.2 Conventional Petroleum System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20
2.2 Himalayan Foreland Basin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
2.2.1 Stratigraphy and Evolution of the Basin. . . . . . . . . . . . . . . . . . . . . . . . . . . . .22
2.2.2 Conventional Petroleum System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
2.3 Sampling Details. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
CHAPTER 3: SOURCE ROCK GEOCHEMISTRY AND HYDROCARBON
POTENTIAL
3.1 Visual Kerogen Analysis (VKA) and Vitrinite Reflectance (Ro)
3.3.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.1.2 Methodology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
3.1.3 Results and Discussions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
3.1.3.1 Cambay Shale Samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
3.1.3.2 Subathu Fm Shale Samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
3.1.4 Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
3.2 Rock Eval Pyrolysis
3.2.1 Introduction and Methodology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .60
3.2.2 Results. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .62
3.2.2.1 Cambay Shale Samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .62
3.2.2.2 Subathu Fm Shale Samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .72
3.2.3 Discussion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .75
3.3 Gas Chromatography
3.3.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .80
3.3.2 Sample Preparation and Methodology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
3.3.2.1 Sample Preparation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81
3.3.2.2 Gas Chromatography – Flame Ionization Detection (GC – FID). . . .82
3.3.3 Results and Discussions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .82
3.3.3.1 Biodegradation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .86
3.4 Bulk Chemical Composition and Isotopic Geochemical Analysis of Gas Seeps
3.4.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
3.4.2 Methodology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
3.4.2.1 Sampling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
3.4.2.2 Analytical Procedure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
3.4.3 Results and Discussions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .89
CHAPTER 4: PETROPHYSICS
4.1 X-Ray Diffraction Analysis
4.1.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
4.1.2 Principle of Diffraction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
4.1.3 Methodology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
4.1.3.1 Sample Preparation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96
4.1.4 Bulk XRD Analytical Results. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
4.1.4.1 Cambay Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
4.1.4.2 Subathu Formation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .101
4.1.5 QEMSCAN vs. XRD Mineralogy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104
4.1.6 Clay Minerals and Diagenesis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104
4.1.7 Provenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .105
4.1.7.1 Cambay Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .105
4.1.7.2 Subathu Formation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .106
4.1.8 Reservoir Quality. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .107
4.1.9 Pressure Conditions and Associated Fractures. . . . . . . . . . . . . . . . . . . . . . . 112
4.1.10 Gas-in-Place (GIP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .114
4.2 Scanning Electron Microscopic (SEM) Studies
4.2.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117
4.2.2 Methodology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117
4.2.3 Results and Discussions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .118
4.2.3.1 Interparticle Pores. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .120
4.2.3.2 Intraparticle Pores. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .120
4.2.3.3 Organic Matter Hosted pores (Organopores). . . . . . . . . . . . . . . . . . .125
4.3 QEMSCAN® (Quantitative Evaluation of Minerals by Scanning Electron
Microscopy)
4.3.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
4.3.2 Methodology and Rationale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .132
4.3.2.1 Sample Preparation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133
4.3.2.2 Analysis Technique. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133
4.3.3 Results and Discussions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .134
4.3.3.1 Cambay Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .135
4.3.3.2 Subathu Fm Shales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .136
4.3.4 Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136
CHAPTER 5: PALAEOCLIMATE AND PALAEOENVIRONMENTAL
RECONSTRUCTION
5.1 Indian Plate Tectonics and Climatic Evolution. . . . . . . . . . . . . . . . . . . . . . . . . . .147
5.2 Late Palaeocene – Early Eocene Climate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148
5.3 Clay minerals as Palaeoclimate Proxies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .149
5.4 Cambay and Subathu Shales: Palaeoclimatic and Palaeoenvironmental Scenarios
5.4.1 Cambay Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .150
5.4.2 Subathu Fm Shales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .151
5.4.3 Palaeoenvironmental Reconstruction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .152
5.5 Discussions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
CHAPTER 6: SUMMARY AND CONCLUSIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . 158
REFERNCES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .166
APPENDICES
Appendix A – Analysed Samples Lists and Codes. . . . . . . . . . . . . . . . . . . . . . . . . . . . 203
Appendix B – Gas Chromatography Samples and Extract Details. . . . . . . . . . . . . . . . 210
Appendix C – Complete Gas Chromatographic Data. . . . . . . . . . . . . . . . . . . . . . . . . . 211
Appendix D – Gas Chromatograms of the Analysed Cambay Shale and Subathu Fm
shale samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .212
Appendix E – Complete XRD data (with Kaolinite Illite (KI) Ratios) of the Analysed
Cambay Shale and Subathu Fm Shale Samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215
Appendix F – XRD Graphs of the Analysed Cambay and Subathu Fm Shale Samples. . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .219
Appendix G: XRD pattern of samples throughout the BBHA borehole. The patterns are
not to scale in the vertical. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 256
Appendix H – XRD Analytical Details (with FWHM) of Borehole BBHA Subathu Fm
Shale Samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .258
Appendix I – Brittleness Index (BI) of Subathu Fm and Cambay Shale Samples. . . . 287
i
Acknowledgements
First & foremost, I praise to Almighty Allah for his blessings, grace &
guidance.
The drive for the Shale Gas project in India was built upon collaboration basis
with the Energy and Geoscience Institute (EGI), University of Utah (USA).
This project was the idea of Prof. G. M. Bhat, Dr. R. Levey & Dr. B. Thusu
and I am highly grateful to them for considering me worthy enough to be the
part of this project and encouraging me to study in the world of shale. I hope
I am not too vain to consider myself the sole author of this work. This thesis
would not have been developed without the support of several professors,
staff members, researchers & laboratory technicians.
I would like to begin by thanking my research supervisor, Prof. G. M. Bhat
(University of Jammu). Over the past five years, he has helped me to flourish
both academically and personally. The work quality achieved here was
impossible without his guidance, kindness and support. His critical insights
aided me to comprehend & to develop this research topic. I am highly grateful
to Dr. Thusu (MPRG, UCL) for his constant support & encouragement
throughout the course of this study. I would like to thank Dr. Jonathan Craig
(eni, Milan) for his valuable advice & suggestions. His professional knowledge
& rich industrial & academic experience encouraged me to study in the world
of shale. I am also thankful to Prof. Juergen Thurow (University College
London- UCL) for inculcating geological skills in me.
I owe a debt of gratitude to Dr. Raymond Levey (EGI) for his generosity, help,
support & also for providing me the opportunity to work with the leading
shale geoscientists in EGI research laboratories in University of Utah, Salt
Lake City, Utah, USA during summers of 2012 & 2013. I am also thankful to
entire EGI family for their kind help & support. I am greatly indebted to Dr.
Sudeep Kanungo, Prof. Rasoul Sorkhabi, Dr. John Mclennan, Mr. Steve
Osborne, Dr. Lauren Birgenheier, Mr. Ian Walton, Dr. Tom Anderson, Prof.
Milind Deo & Dr. Shu Jiang for sharing their experiences & infinite
knowledge with me during our fruitful discussions. I am also grateful to Dr.
Julia Kotulova, Mr. Nick Dahdah, Mr. Clay Jones, Mr. Christopher Kesler,
Mr. Peter Pahnke, Mr. Britt Osborne, Mr. Jeffrey Quick, Mr. David
Christensen for their support in the laboratories & contribution to the data
interpretation & clarification. The analytical results & their interpretations
would not have been possible without their help. I extend my sincere
gratitude to Ms. Elinda McKenna, Mr. Varun Gowda, Mr. Manas Pathak,
Ms. Peggy Nish, Ms. Nancy Taylor, Ms. Candice Kidd & Ms. Natalia Wilkins
for extending all possible help during my stay in EGI.
ii
I am highly thankful to Dr. Ameed Ghori (Geological Survey, West Australia),
Dr. R. N. Pandey (Gujarat State Petroleum Corporation (GSPC), Gandhinagar
Gujarat), Dr. Ravi Misra (Oil & Natural Gas Corporation (ONGC),
Dehradun), Dr. Devleena Mani, Dr. A. M. Dayal & Dr. D. J. Patil (National
Geophysical Research Institute (NGRI), Hyderabad) for their help &
cooperation. I gratefully acknowledge the research funding, & analytical
support by EGI. I also acknowledge eni, NGRI, & SAIF Lab, PU (Chandigarh)
for their analytical support & GSPC for providing the Cambay Shale samples.
I express my sincere gratitude to Prof. R. K. Ganjoo, Head of the Department
of Geology, University of Jammu for providing me the necessary facilities
required during the completion of this work. Special thanks go to the faculty
of the department, Prof. C. S. Sudan, Prof. M. A. Malik, Prof. P. K.
Srivastava, Prof. S. K. Pandita, Prof. A. S. Jasrotia, Dr. Varun Parmar, Dr.
S. Kundal, Dr. Rajwant, Dr. Yudhbir Singh for their cooperation & support. I
am also grateful to the staff of the department especially Dr. A. K. Sahni, Dr.
B. A. Lone, Mr. Sudesh Sharma, Ms. Radha, Mr. Zaheer Abbas, Mr. Sham
Sunder, Mr. Ashok Sharma, Mr. Janak Raj, Mr. Harvinder, Mr. Mukesh, Mr.
Madan, Mr. Yogesh & Mr. Latief for their help & cooperation.
Many thanks go to Dr. Naveen Hakhoo for his support during my research
work. I am also thankful to my colleagues, especially, Mr. Surjeet Shan, Mrs.
Ishya Shan, Mr. Deepak Kumar, Ms. Rajni Magotra, Mr. Rahul Magotra,
Mr. Shiv Pandey, Ms. Shveta Puri, Ms. Neha Raina, Ms. Meera Sharma, Ms.
Monika Jamwal, Ms. Neha Arora, Mr. Naveed Chowdhary, Mr. Waquar
Ahmed, Mr. Sumeet Khullar, Dr. Sajjad Khan & Mr. Sheraz Malik amongst
other.
I express my heartfelt gratitude to my dear friends Jameel Firdosi, Mr.
Usman Hashmi, Mr. Yasir Niaz, Mr. Majid Wani, Mr. Muneeb Wahidi, Mr.
Murtaza, Mr. Syed Tehsin & Mr. Kashif for support & always being around.
Lastly & most importantly, I would like to extend my profound gratitude to
my beloved family members for their constant inspiration, continued
support, encouragement & patience during all these years. My parents, Mr.
Mohammad Hafiz & Mrs. Rafiga Begum, who raised me to everything I am
today, my lovely sisters, Sidra & Urwa, for their constant support &
happiness they have brought to me during my life. I owe everything to them.
If any errors or inadequacies that may remain in this work, the
responsibility is entirely my own.
Mateen Hafiz Date:
iii
LIST OF FIGURES
Figure 2.1: Structural map of West India. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 2.2: A) Geologic/Structural map of the Cambay Basin. The blue line is the
transect from north to south, shown in B. B) The regional north – south geological cross
section showing the sampling locations. Modified after Raju & Srinavasan, 1993;
Chowdhary, 2004; Biswas et al., 1994. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8
Figure 2.3: Palaeofacies map of West India during the Deccan Trap eruption (c. 65 Ma). .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Figure 2.4: Palaeofacies map of West India during the deposition of Olpad Fm (Early
Palaeocene) and Cambay Shale (Early Eocene) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Figure 2.5: Tarapur – Narmada Cross Section showing the depth of Moho Discontinuity.
Modified after Raju and Srinavasan, 1993; Chowdhary, 2004; Biswas et al., 1994; Tewari
et al., 2009. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Figure 2.6: Heat Flow distribution map of the Cambay Basin. . . . . . . . . . . . . . . . . . . . . 13
Figure 2.7: Free Air Gravity map of the Cambay Basin. . . . . . . . . . . . . . . . . . . . . . . . . .14
Figure 2.8: The generalised stratigraphic column of the Cambay Basin. . . . . . . . . . . . . 15
Figure 2.9: The thickness map of the Cambay Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Figure 2.10: The depth map of the Cambay Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Figure 2.11: The conventional petroleum system events charts of the South and North
Cambay Basin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21
Figure 2.12: Regional geological map of the foothills of the NW Himalaya showing the
distribution of slivers of the Subathu Fm (Hakhoo et al., 2014) . . . . . . . . . . . . . . . . . . . .23
Figure 2.13: Gravity modelling profile of Punjab Plains and Sub-Himalayan Foreland
Basin (After Singh et al., 2005) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
iv
Figure 2.14: Local geology of the Riasi and Kalakot areas and the key outcrop localities
of the Subathu Fm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Figure 2.15: The subsidence history of the HFB (showing the rate of subsidence,
sedimentation and critical timing of the hydrocarbon generation) . . . . . . . . . . . . . . . . . . 27
Figure 2.16: The conventional petroleum system events charts of the Himalayan Foreland
Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Figure 2.17: Lithologs from A) Mangrol Lignite Mine, Surat (Cambay Basin). B-C)
Schematic logs of whole Subathu Fm from two boreholes and Manma Section. . . . . . . .30
Figure 3.1: The source rock quality measurement plot of the Cambay Shale. The TOC
values are plotted against the Hydrocarbon Generation Potential (HCGP) of the Cambay
Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .67
Figure 3.2: The kerogen maturity plot of the Cambay Shale to reconstruct the expulsion
of oil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . .68
Figure 3.3: TOC map of the Cambay Shale with the TOC values of the samples. . . . . . 69
Figure 3.4: Pseudo-van Krevelen plot of the Cambay Shale samples where Hydrogen
Index (HI) values are plotted against Oxygen Index (OI) values. . . . . . . . . . . . . . . . . . .70
Figure 3.5: Kerogen type and maturity plot of the Cambay Shale samples through HI and
Tmax values. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .71
Figure 3.6: Tmax vs. Depth plot for the source maturity of the Cambay Shale samples. . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .71
Figure 3.7: Graph showing TOC distribution of the Subathu Fm shale samples. . . . . . .72
Figure 3.8: The source rock quality measurement plot of the Subathu Fm shales. . . . . . 73
Figure 3.9: Kerogen type and maturity plot of the Subathu Fm shale samples. . . . . . . . .74
Figure 3.10: Pseudo-van Krevelen plot of the Subathu Fm shale samples. . . . . . . . . . . .74
Figure 3.11: Source rock kerogen type map of the Cambay Shale . . . . . . . . . . . . . . . . . 76
Figure 3.12: The Vitrinite Reflectance (Ro) map of the Cambay Shale. . . . . . . . . . . . . .77
v
Figure 3.13: Production Index vs. Maturity plot of the Cambay Shale. . . . . . . . . . . . . . .78
Figure 3.14: Scheme showing the conversion of phytol to pristane and phytane
(after Didyk et al., 1978) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . 83
Figure 3.15: Plot showing the Pr/n-C17 to Py/n-C18 ratios of the Cambay Shale samples. .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
Figure 3.16: A). General geology around gas seep site; B) collection of gas samples; C)
The combustibility of gas being checked. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
Figure 3.17: Schoell’s diagram plotting carbon isotopic composition of methane is
plotted against the total percentage of methane. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .90
Figure 3.18: Schoell’s Plot plotting carbon isotopic composition of methane against the
hydrogen isotopic composition of methane. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
Figure 3.19: Whiticar’s Plot plotting carbon isotopic composition of methane against the
hydrogen isotopic composition of methane. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
Figure 4.1: Pie plot showing the average mineral composition of the Cambay Shale
samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
Figure 4.2: Average mineral composition of the Cambay Shale along with standard
deviation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
Figure 4.3: Average mineral composition of the Subathu Fm along with the standard
deviation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .102
Figure 4.4: Depth vs Clay and Silica total for the BBHA. Note the increase in silica total
up-section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
Figure 4.5: Cross plot showing the relationship of total silica with TOC content. . . . . 109
Figure 4.6: Ternary plot showing the relative proportion of of clays, silica, carbonate and
other minerals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .110
Figure 4.7: Ternary diagram plotting the XRD results of the Cambay Shale and Subathu
Fm shales against the four major US shale plays. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .111
vi
Figure 4.8: GPESGS software screenshot showing the GIP and storage mechanisms in
the Cambay Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .116
Figure 4.9: GPESGS software screenshot showing the GIP and storage mechanisms in
the Subathu Fm shales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
Figure 5.1: Major Early Palaeogene hyperthermal events recorded in the bulk carbon
isotope composition. (After Dickens, 2009; DeConto et al., 2012) . . . . . . . . . . . . . . . . 148
Figure 5.2: Palaeofacies and tectonic map of North India during Ypressian times
(modified after Golonka, 2009; Scotese, 2013) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
Figure 5.3: The model depicting the environmental scenario during the deposition of
Cambay Shale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154
Figure 5.4: The model depicting the environmental scenario during the deposition of
basal Subathu Fm. . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155
vii
LIST OF TABLES
Table 3.1: Vitrinite Reflectance Analysis of Cambay Shale and Subathu Fm Shale
samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Table 3.2: Visual Kerogen Analysis (VKA) of Cambay Shale and Subathu Fm Shale
samples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Table 3.3: Rock Eval pyrolysis data of the Cambay Shale samples . . . . . . . . . . . . . . . . .63
Table 3.4: Rock Eval Pyrolysis of the Subathu Fm shales. . . . . . . . . . . . . . . . . . . . . . . . 64
Table 3.5: Pristane Phytane (Pr/Ph) ratios of the Cambay Shale samples. . . . . . . . . . . . .85
Table 4.1: Percentages of spaces occupied by the minerals identified in the samples. . 134
viii
PUBLICATIONS
Mani, D., Patil, D. J., Dayal, A. M., Kavitha, S., Hafiz, M., Hakhoo, N. and Bhat, G. M.,
2014. Gas Potential of Proterozoic and Phanerozoic Shales from the NW Himalaya,
India: Inferences from Pyrolysis. International Journal of Coal Geology, Vol. 128-
129, pp. 81-95.
Bhat, G. M., Craig, J., Hafiz, M., Hakhoo, N., Thurow, J. W., Thusu B. and Cozzi, A.,
2012. Geology and Hydrocarbon Potential of Neoproterozoic – Cambrian Basins in
Asia: an introduction. In: Bhat, G. M., Craig, J., Thurow, J. W., Thusu, B. and
Cozzi, A. (Eds) 2012. Geology and Hydrocarbon Potential of the Neoproterozoic-
Cambrian Basins in Asia. Geological Society London, Special Publication, Vol.
366, pp. 1-17.
ix
“And with Him are the keys of all that is hidden, none knows
them but He. And He knows whatever there is in (or on) the earth
and in the sea; not a leaf falls, but He knows it. There is not a
grain in the darkness of the earth, nor anything fresh or dry, but
is written in a Clear Record.” (Al-Quran, 59:6)
x
CHAPTER 1
INTRODUCTION
1
INTRODUCTION
1.1 Introduction
The word “Shale” has Teutonic origin, meaning “laminated clayey rock” (Tourtelot,
1960). It is an abundant and wide spread sedimentary mudrock constituting 60% of the
sediments distributed globally. It is composed of clay minerals, silica, carbonates, some
heavy minerals and significant percentage of organic matter. The organically rich shale
has the potential to generate hydrocarbons or may yield hydrocarbons by pyrolysis. Since
shale has low permeability and in certain cases is impermeable, it also acts as seal in
conventional hydrocarbon systems. This mudrock was initially misinterpreted as
interbedded matrix and taken for granted because of the fine grained nature of the
sediments and lack of the textural and structural attributes visible to the naked eye or
hand lens (Potter et al., 1980 and O’Brien and Slatt, 1990). Later these organic rich shales
were found to be the source of hydrocarbons with the potential to generate resources due
to the thermal alteration of the organic matter in the subsurface (Tourtelot, 1979). The
progressive development of the analytical techniques have provided an insight regarding
the lithofacies characteristics of these source rocks which help in better understanding of
the depositional environment that influenced its deposition, source and percentage of
organic carbon content and petrophysical attributes etc. (Loucks and Ruppel, 2007;
Hickey and Henk, 2007; Loucks et al., 2012; Passey et al., 2012 and Milliken et al.,
2013). These technological advancements have led to the identification of sweet spots and
subsequently helped in designing and drilling the horizontal wells for accessing and
stimulating (by hydraulic fracturing) the ultra-tight reservoirs for economic gas fairways
(Schmoker, 2002; Jarvie et al., 2007; Boyer et al., 2006; Gale et al., 2007; Hill et al.,
2007; Pollastro et al., 2007; Pollastro, 2007; Romero and Philp, 2012; Macquaker et al.,
2014).
A major decline in new discoveries of the conventional hydrocarbons has globally
spurred interest in shale gas exploration. With energy security of the world at stake, shale
gas can ease the demand pressure on conventional energy resources, at least temporarily
and act as a bridge-fuel to cleaner energy. Driven by the new understanding of the great
abundance of shale gas and other unconventional hydrocarbon resources, a “paradigm
shift” from conventional resources potential began more than a decade ago in North
America and is now gaining importance in Europe, Asia and Australia and is going to be
2
as major ‘game changer’ which will have significant implications for the global energy
supply and demand balance.
Unconventional natural gas rich in methane is trapped in geologically complex
reservoirs (shales, coalbeds and tight gas sands); whilst shale gas is self sourcing reservoir
where the resources are stored within the framework constituents of the rocks (intra-
particle porosity), between the constituent grains (inter-particle porosity), in fractures or
are adsorbed onto the organic matter and in its pores (organo-porosity). To have adequate
flow paths, the shale needs to be fractured by using intensively stimulated horizontal
wells and efficaciously placed and well executed hydrofracking is critical for the
economic production.
Shale Gas exploration in India is in its infancy, especially when compared to the
United States; which has been successfully exploiting the shale gas for the last one
decade. Although numerous basins with proven shale resource potential are present in
India, the shale gas play fairways are yet to be identified in the prospective basins and the
basic data for prospectivity assessment is lacking.
The Cambay Basin has been extensively explored since 1956 and plethora of data
has been generated to understand the geological architecture and petroleum systems
present within the basin. The Cambay Shale of Late Palaeocene to Early Eocene age is
considered as the main source of hydrocarbons and has been investigated by various
researchers in the past to estimate its source potential (e.g., Orlov and Sovirn, 1965;
Yalcin et al., 1987; Chandra et al., 1994; Arora and Mehrotra, 1993; Banerjee and Rao,
1993; Biswas et al., 1994; Garg and Philp; 1994; Mangotra et al., 1995; Banerjee et al.,
2000 & 2002; Sivan et al., 2006; Misra, 2009; Mishra and Patel, 2011; Devi et al., 2012;
Dayal et al., 2013; references therein and other works.). The Subathu Formation (Fm)
shales of the Himalayan Foreland Basin (HFB) have long been known as potential source
rocks for hydrocarbons but have remained relatively underexplored vis-a-vis conventional
and unconventional hydrocarbon prospects. ONGC has conducted a few geochemical
analyses on the Subathu Fm shales so as to ascertain their source potential during their
exploratory drilling in the Himalayan Foothills (Mittal et al., 2006), but the data
generated is unavailable in public domain. There is also scarcity of the published
literature regarding the source rock characterisation of the Subathu Fm shales and only
few researchers have published the data in public domain (e.g., Mittal et al., 2006;
3
Siddaiah, 2011b; Verma et al., 2012 and Mani et al., 2014). Although the organic
richness of the Cambay Shale and Subathu Fm shales have been estimated by few earlier
workers, the reservoir quality and other basic geochemical data important for shale gas
evaluation are virtually unknown.
In the current research work, Eocene shale units of the Cambay Basin and HFB
from Jammu region were selected for in-depth examination and understanding of their
shale gas/oil potential. The reason of selecting these two shale units from the two basins
was to compare and contrast the critical geological, geochemical and clay mineralogical
attributes of the Subathu Fm shales with the proven conventional source rock of the
Cambay Basin. Although these shale formations were deposited in different tectonic
regimes, the review of the published data suggests that the climatic and environmental
conditions were similar during their deposition in Early Palaeogene times. This study
aims to bring attention to the geologic, geochemical and petrophysical commonalities
between these two shales and develop geologic models depicting their origin, distribution,
depositional setting and hydrocarbon source and reservoir potential.
1.2 Purpose and Scope of Study
This study is focused to assess and evaluate the geological, organic and whole rock
geochemical; and clay mineralogical attributes of the Cambay Shale and Subathu Fm
shales to determine their shale gas potential using modern analytical techniques. The
main research objectives of the study are:
Evaluate the organic source potential of the Eocene shale formations in the
two selected basins
Determine the organic facies types within the studied shale units
Establish the unconventional reservoir potential of the target shale
formations
Document the different pore types in matrix and organic constituents and
networks within the selected shales
Develop geologic models depicting palaeoclimatic and palaeoenvironmental
conditions during their deposition
The thesis entitled “Geological Controls on the Eocene Shale Gas Resources Plays in
North and West India: Stratigraphy, Palaeoenvironment and Tectonic Setting”, embarks
4
upon the Cambay Basin and HFB hosting potential shale horizons of Eocene age. The
Cambay Shale and Subathu Fm shales from Jammu region were studied for their source
and reservoir characteristics and to establish their unconventional hydrocarbon resources
potential. Their source and reservoir qualities were measured by various analytical
procedures. This study is likely to assist in determining the source and reservoir
properties of the shales sourcing conventional hydrocarbons in the commercially
productive Cambay Basin. It also provides insights in characterizing the unconventional
hydrocarbon resource potential of the shales from the Subathu Fm in prospective HFB.
Depositional history of these shales was worked out and the analytical results obtained on
these shales were used to understand their palaeoclimatic and palaeoenvironmental
conditions.
1.3 Outline of the Thesis
The thesis is developed on six chapters. The first chapter starts with an introduction
to the topic and outlines the thesis structure and defines the objectives of the work.
Chapter–2 describes geology of the basins which details their stratigraphy, structural
architecture and tectonic evolution. The conventional petroleum systems of the two basins
are also discussed in this chapter. Chapter–3 covers the source rock geochemistry of the
shales analysed for Visual Kerogen Analysis (VKA) and Vitrinite Reflectance (Ro); TOC
and Rock Eval Pyrolysis; and Gas Chromatography (GC). These methods were used to
understand the type of organic matter and estimate the hydrocarbon generation potential
of the target shales. The analytical results of the gas seeps samples collected from the
HFB are also discussed in this chapter. Chapter–4 embodies the reservoir qualities of the
investigated shales. Quantitative Evaluation of Minerals by SCANning Electron
Microscopy (QEMSCAN®), X-Ray Diffraction (XRD) and Scanning Electron
Microscopic (SEM) studies were carried out to determine the mineralogical composition,
fabric and pore-types and morphology of the studied shales. Chapter–5 describes the
palaeoclimatic and palaeoenvironmental depositional scenarios of the two basins during
the deposition of these shales. Chapter–6 sums up the outcome of the investigations
carried on the selected shales. At the end of the chapter 6, comprehensive list of
references cited in the thesis is given.
5
CHAPTER 2
GEOLOGY OF THE
BASINS
6
GEOLOGY OF THE BASINS
2.1 Cambay Basin
Cambay Basin is located in the state of Gujarat along the western margin of the
northwestern part of the Indian Craton. It is an elongated, intra-cratonic rift basin (graben)
of Late Cretaceous to Palaeogene age, covering an area of 53, 500 sq. km which also
includes the 2500 sq. km area in the shallow water of Gulf of Cambay (DGH India,
2012). The Deccan Trap basalt forms the technical basement on which 7–11 km thick pile
of sediments has been deposited. It is bounded by Saurashtra Peninsula in the west (Fig.
2.1), which is completely covered by Deccan Trap basalts, with some Cretaceous rocks
cropping out on the northeastern flanks. The basin extends further north into shallower
Barmer Basin and towards northwest into Kutch Basin and is separated from these two
basins by Radhanpur–Barmer Arch. The geological map of the area and regional north
south cross section is shown in Figure 2.2. The northeastern flank of the basin is
delineated by Aravalli–Delhi fold belts of Precambrian age whereas the Deccan Trap
inliers and Precambrian Champaner Series border its limit in the east. Deccan Craton of
Rajpipla–Navasari–Bombay restricts it towards southeast. The basin continues southward
into the Gulf of Cambay and further extends into the Bombay Offshore Basin. It is
bordered by the en echelon faults on its eastern and western margins (Raju, 1968) and
several north–south trending normal faults and east–west trending transverse faults have
compartmentalised the basin into five tectonic blocks, named as (from north to south)
Patan–Sanchor, Mehsana–Ahmedabad, Tarapur, Broach and Narmada blocks (Raju,
1968; Chowdhary, 2004).
Cambay Basin is the plume related failed/abandoned arm (aulacogen) of a four
armed (quadruple) junction which is related to the opening of the Arabian Sea (Burke and
Dewey, 1973; Chowdhary, 2004). It is one of the three western marginal/pericontinental
(Kutch, Cambay and Narmada) basins which came into existence during the northward
flight of the Indian Subcontinent between the Early Jurassic and Palaeogene periods, after
the breakup from the main Gondwanaland (Biswas, 1982 and 1999; Tewari et al., 1995;
Zutshi and Panwar, 1997; Rangarajan, 2008). The rifting opened up the basins when the
plate experienced the counter-clockwise rotation by 50 degrees (Klootwijk, 1979). During
the Palaeozoic and Mesozoic eras, the western and northwestern parts of the Indian Plate
functioned as platform on which the alternating shallow marine, brackish and deltaic
7
Figure 2.1: Structural map of West India.
8
Figure 2.2: A) Geologic/Structural map of the Cambay Basin. The blue line is the transect from north to south, shown in B. B) The regional north
– south geological cross section showing the sampling locations. Modified after Raju & Srinavasan, 1993; Chowdhary, 2004; Biswas et al., 1994.
A
B
9
sediments (Upper Carboniferous Umaria beds, Upper Jurassic Dhangadra beds,
Cretaceous Wadhwan Sandstone and Bagh beds) were deposited. The tensional faults
started developing during the beginning of Early Jurassic Period and probably submerged
the parts of the platform (Raju, 1968). During the northward movement, the western part
of the Indian Plate traversed over the Reunion hotspot causing the upliftment of the crust
by thermal expansion which led to crustal thining and subsidence, usually seen in the rift
basins (Falvey, 1974; Campbell and Griffiths, 1990). This was accompanied by large
scale extrusive volcanism, called Deccan Trap Volcanism, leading to outpouring of the
tholeiitic basalt causing the subsidence and rifting events in Cambay during the early
Figure 2.3: Palaeofacies map of West India during the Deccan Trap eruption (c. 65 Ma).
10
phase of basin development (Fig. 2.3). Deccan basaltic trap erupted for less than 1 million
year, mostly in the 24R reverse magnetic chron, in the short time between 65 and 69
million years (Courtillot et al., 1988; Keller, 2000). The rifting started from north to south
from Kutch along the NE–SW to ENE–WSW Delhi–Aravalli trend during the Early
Jurassic Period with the extensional faulting causing the transgression of the Tethys Sea
into the Kutch Rift. The rifting migrated towards the south and during the Early
Cretaceous Period, Cambay Rift initiated along the NNW – SSE Dharwar trend as the
half graben. It continued southward and started opening in Narmada along the ENE–
WSW Satpura trend during Late Cretaceous and Early Palaeogene (Raju, 1968; Raju et
al., 1971; Biswas, 1982 and 1999). During this time, trap derived conglomerate in the
form of alluvial fans and lacustrine claystones were deposited in the fault controlled
discrete half graben. Later, the entire basin experienced the large scale marine
transgression and deposited thick carbonaceous Cambay Shale (Fig. 2.4).
The crustal stretching, which is related to mantle upwarping and basin subsidence,
brought the Mohorovicic (Moho) discontinuity upward and is present at the depth of 31-
33 Km near Jambusar and Mehmadabad (Dixit et al., 2010). It further shallows towards
the south and is shallowest near Daman (Mumbai offshore) area (Fig. 2.5) (Kaila, 1988).
This corresponds to the high geothermal gradient in the South Cambay Basin with the
highest gradient of 67oC/km towards the eastern margin of the Narmada Block (Sonam et
al., 2013). The average geothermal gradient value of about 39oC/km is observed in the
south and 30oC/km in the northern part of the basin (Thiagarajan et al., 2001). These
values confirm high surface heat flow in this region (77–92 mW/m2) with an average
value of c. 83 mW/m2 (Fig. 2.6). The values are abnormally high when compared to
normal heat flow values in stable continental shield area (approx. around 58 mW/m2).
The basin also shows high gravity field and residual anomaly is about +37 mgal near
Cambay which decreases towards north (Fig. 2.7). The Curie temperature (approx.
580oC) in the basin lies approximately at 22 km depth. These tectonic and geothermic
conditions in the basin provided additional favourable setting which conforms to the
source rock maturation and hydrocarbon generation.
2.1.1 Stratigraphy and Tectonic Evolution of the Basin
The sedimentation in the Cambay Basin occurred on the Late Cretaceous Deccan
Trap basalt floor which forms the technical basement (Fig. 2.8). It mainly comprises of
11
tholeiitic amygdaloidal basalt in association of andesite, trachyte and picrite. The Deccan
Trap Basalt is unconformably overlain by Early Palaeocene ‘trap wash’ or ‘trapwacke’ of
Olpad Fm (or Vagadkhol Fm) deposited in fluvial to marginal marine environmental
settings.
Figure 2.4: Palaeofacies map of West India during the deposition of Olpad Fm
(Early Palaeocene) and Cambay Shale (Early Eocene).
12
It is mostly composed of trap derived thick succession comprising of
conglomerates, claystones, sandstones, silts and clays. The formation attains maximum
thickness in the Broach Block. A thick shale unit called Cambay Shale of Late
Palaeocene (Thanetian Stage) to Early Eocene (Ypressian Stage) age overlie the Olpad
Fm which is divided into Older and Younger Cambay Shale on the basis of log (neck)
marker, separated by short time erosional unconformity. This formation consists of dark
grey to black organic rich shale with some siltstone streaks. The Older Cambay Shale
(OCS) was deposited in open marine under highly anoxic environment, whereas the
Younger Cambay Shale (YCS) shows the characteristics indicating deposition in shallow
marginal marine, brackish quite water conditions. In the northern part of the basin, OCS
shows the intertonguing relationship with Kadi Fm which comprises of three arenaceous
members, viz. Mandhali, Mehsana, and Chhatral, deposited within deltaic settings. The
Cambay Shale grades into coal-bearing succession towards the marginal parts of the basin
and the coal and lignite occurrences in Vastan, Mangrol and Tadkeshwar areas in the
southern part of the basin in the Narmada Block are regarded as onland continuity of the
Cambay Shale. The thickness of Cambay Shale ranges from 500 m on the flanks and
increases towards the depocenters where it reaches up to 1500 m thickness (Fig. 2.9). The
depth map (Fig. 2.10) of the Cambay Shale shows that the formation deepens towards the
south of the basin and is very deep in the Broach depression. The overlying Middle
Eocene Kalol Fm in the northern part of the basin is characterized by intercalations of
sandstone and siltstone, dark brown shale, and paralic coal and the formation was largely
deposited in regressive systems tract. In the southern part of the basin, arenaceous
Figure 2.5: Tarapur – Narmada Cross Section showing the depth of Moho Discontinuity.
Modified after Raju and Srinavasan, 1993; Chowdhary, 2004; Biswas et al., 1994; Tewari
et al., 2009.
13
Figure 2.6: Heat Flow distribution map of the Cambay Basin.
14
Figure 2.7: Free Air Gravity map of the Cambay Basin.
15
Figure 2.8: The generalised stratigraphic column of the Cambay Basin.
16
Figure 2.9: The thickness map of the Cambay Shale.
17
Figure 2.10: The depth map of the Cambay Shale.
18
dominant rocks with thick shale intervals of Ankleshvar Fm and Hazira Shale are
deposited directly over the YCS. The carbonaceous and silty shale units of Vaso Fm are
overlying the YCS in the Tarapur Block. These beds are conformably overlain by Late
Eocene to Oligocene Tarapur Shale Fm, consisting of 200-300m thick, greenish brown to
dark brown shales with infrequent sideritic bands. In the southern part of the basin, sandy
succession with some shale units of Dadhar Fm are deposited which is partly coeval with
the upper part of the Tarapur Shale. Tarapur Shale is unconformably overlain by Early
Miocene Kathana Fm which is composed of carbonaceous, siderite rich shales,
arenaceous units and variegated claystone. Tarkeshwar Fm comprises of variegated
claystones overlying the Numulititic unit towards the eastern margin of the basin. The
Kathana Fm is overlain by Early Miocene Babaguru Fm which is mainly composed of
arenaceous rocks, deposited in fluvial to shallow marine oxidising environment. This is
overlain by brown claystone and occasional arenaceous units of Middle Miocene Kand
Fm which in turn is overlain by calcareous and micaceous sandstones of Jhagadia Fm.
The Broach Fm of Late Miocene to Pliocene age is overlying the Jhagadia Fm, but was
not deposited in the southern part of the basin in Narmada Block. The formation consists
of reddish brown claystones deposited in shallow marine oxidising environment. The
brown clay and coarse sands of Pliestocene Jambusar Fm are finally overlain by the
recent alluvium brought in by numerous fluvial systems. The stratigraphic charts of all
five tectonic basins have been prepared (data taken from Banerjee and Rao, 1993; Raju
and Srinavasan, 1993; Mangotra et al., 1995; Samanta et al., 1997; Pandey and Dave,
1998; Bhandari and Raju, 2000; Banerjee et al., 2002; Chowdhary, 2004; Sivan et al.,
2006; NELP-VII, 2007; Gupta and Shanmukhappa, 2007; Shukla et al., 2007; Misra,
2009) which show lithologies, thickness, depositional environments, etc. (Strat column in
the back leaf).
The tectonic development of the Cambay Basin can be described in two major
stages, viz. the Late Jurassic–Early Cretaceous platform phase and complex Late
Cretaceous–Palaeogene stage of rifting/post rifting activities (Raju and Srinivasan, 1993;
Kundu et al., 1993; Sarraf et al., 2000; Chowdhary, 2004). The latter stage was further
evolved in multiple phases, namely:
First rift Phase during Late Cretaceous
Formative Phase of Palaeocene age
Early–Middle Eocene Second Rift Phase
19
Late Eocene–Oligocene Inversion Phase
Miocene–Holocene Post Rift Phase
1. Platform Phase
Late Jurassic–Early Cretaceous sedimentary succession forms the pre-rift
evolutionary stage of the basin. These sediments were deposited in alternating shallow
marine, brackish and deltaic environmental settings, suggesting that the northwestern part
of the Indian Plate was a gentle shelf bounded platform which submerged in the Tethyan
realm from time to time.
2. First Rift Phase
The first episode of rifting occurred during Late Cretaceous when the 1000–3200 m
thick Deccan Trap volcanics extruded leading to the subsidence and development of
graben/half graben along NNW-SSE trending marginal faults.
3. Formative Phase
The formative phase initiated during Palaeocene with the development of intra-
basinal horst and rift structures and the basalt derived clastic conglomerate and claystones
of Olpad Fm were deposited within the basin. The NNW-SSE trending basement faults
were reactivated which produced strong relief on the basaltic floor.
4. Second Rift Phase
This phase of rifting started during Early–Middle Eocene along the pre-existing
NNW-SSE aligned marginal faults which caused subsidence and subsequent marine
transgression flooding the entire Cambay graben. This led to the deposition of 500-1500
m thick pyritic and organic rich Cambay Shale Fm over the Olpad Fm. The transgression
didn’t reach the northern extremities of the basin and therefore led to the deposition of
arenaceous Tharad Fm in Patan Block and coarse clastic units in the Kadi Fm under
deltaic environmental conditions.
5. Inversion Phase
During Late Eocene–Oligocene stage of the basin development, argillaceous and
arenaceous successions were deposited during transgressive and regressive phases with
differential depositional suites in the northern and southern parts of the basin. The dark
brown shale alternating with paralic coal, siltstone and sandstones of Kalol Fm were
20
deposited in the north and greyish brown shale with the intervals of sandstone beds were
deposited and representing Ankleshvar and Dadhar formations in the southern part of the
basin.
The basin experienced southward tilt during the Early Oligocene ensuing brief
marine incursion and resulted in the deposition of Tarapur Shale Fm. The sea receded
during Late Oligocene representing the period of non-deposition and erosion
(unconformity) on the top of the Tarapur Shale throughout the basin.
6. Post Rift Phase
Miocene to Holocene post rift phase of the basin was unstable and sedimentation
occurred in different environmental settings starting from marine transgression and
continental sediments brought in by transverse rivers flowing into the basin.
2.1.2 Conventional Petroleum System
Two major petroleum systems have been identified in the Cambay Basin. 1.
Cambay - Hazad petroleum system in South Cambay Basin and 2. Cambay-Kalol/Kadi
petroleum system in North Cambay Basin (Fig. 2.11).
Cambay-Hazad is the main petroleum system of the South Cambay Basin, where
Cambay Shale is the major source rock. In addition to this, Olpad Fm and Kanwa Shale
are also identified as potential source rocks. The Ankleshwer Fm comprising of deltaic
sandstones (Hazad and Ardol) deposited during the regressive phase are the main
reservoir rocks of South Cambay Basin. Reservoir rocks of Ardol, Babaguru and Olpad
account for the remaining part of hydrocarbons generated in South Cambay Basin.
Transgressive shales within the Hazad Member and Kanwa Shale are main cap rocks for
the Hazad Member reservoirs in the southern part of the basin. Babaguru reservoirs are
capped by transgressive shales of the Tarkeshwar Fm. The hydrocarbon generation within
the Cambay Shale started as early as 43 Ma. The peak oil generation reached towards the
end of the Middle Eocene. At that time, temperatures were high enough for gas
generation in conjunction with the peak oil generation. The hydrocarbon generation
reached the critical moment at 10 Ma BP (million annum before present) (Yalcin et al.,
1987; Sarraf et al., 2000).
Another major petroleum system is the Cambay - Kalol/Kadi in the North Cambay
Basin, where Cambay Shale forms the major source rock and Kalol Fm and Kadi Fm act
21
Figure 2.11: The conventional petroleum system events charts of the South and North
Cambay Basin.
22
as main reservoirs. The Tarapur Shale forms the regional seal in this northern Cambay
petroleum system. The hydrocarbon generation, accumulation and migration initiated
during Late Miocene and reached the critical moment at 10 Ma BP (Yalcin et al., 1987;
Sarraf et al., 2000).
2.2 Himalayan Foreland Basin
2.2.1 Stratigraphy and Evolution of the Basin
The great Himalaya was formed due to the collision between the Indian Plate and
the Asian Plate with the subsequent closure of the Tethyan Ocean initiating at around 50
Ma (Searle et al., 1987; Searle and Treloar, 1993; Rowley, 1996; Najman et al., 2001;
Zhu et al., 2005; Green et al., 2008; Henderson et al., 2010 and 2011; White and Lister,
2012; Meng et al., 2012; Chatterjee et al., 2013; Bouilhol et al., 2013). The convergence
of the two plates led to the southward migration of the thrust sheets. This caused the
down-buckling of the lithosphere due to the weight of the stacking thrust sheets in the
fold thrust belt leading to the formation of Himalayan Foreland Basin (HFB). The
depression created on the Indian Plate south of the Main Boundary Thrust (MBT)
received more than 10 km of sediments eroded mainly from the orogen.
An ideal peripheral foreland basin consists of three discrete depocentres which
include i) wedge-top depozone which is characterized by the coarse alluvial and mixed
depositional sediments, ii) foredeep depocentre with shallow marine to turbidite deposits,
and iii) back-bulge depozone on the craton-ward side, formed of fine grained sediments
and carbonate platforms in the shallow marine depositional system (DeCelles and Giles,
1996). The peripheral HFB like an ideal foreland basin (Sinclair, 1997; Naylor and
Sinclair, 2008) evolves progressively from flysch, through marginal and fully marine
environment and finally show transition into distal continental filled stage.
The HFB is located in Sub-Himalaya which is bounded by the Himalayan Frontal
Thrust (HFT) in the south and flanked by the Main Boundary Thrust (MBT) in the north.
The HFB sediments in the study area in Jammu region consist of the Late Palaeocene -
Middle Eocene Subathu Fm, Late Middle Eocene - Early Miocene Murree Fm and
Neogene Siwalik Gp. The Subathu Fm forms the base of the basin fill and constitutes the
only (last) marine fossiliferous sediments in the Sub-Himalaya. It is juxtaposed (Fig.
2.12) with the Neoproterozoic Sirban Limestone Fm (exposed as Riasi, Lopri and Kalakot
23
– Mahogala Inliers) and represents the oldest lithounit in the area and forms the technical
basement for the Cenozoic successions. Traditionally, the contact between the Subathu
Fm and Sirban Limestone Fm has been considered as a major unconformity (e. g., Raha
and Shastry, 1973; Raha, 1974 and 1984; Chadha, 1992; Thappa et al., 1993) (spanning
for c. 540 Ma) which is marked by different varieties of breccia, quartz-arenite, iron-
stone, shale and pisolitic bauxite (Singh and Andotra, 2000; Singh et al., 2005; Siddaiah,
2011, Siddaiah and Shukla, 2012; Hakhoo et al., 2011). However, recent study has
revealed the back thrusted contact between the two lithounits (Hakhoo, 2014). The HFB
constitutes the shallow marine and distal continental facies (Subathu Fm) to fully
continental facies (Murree Fm and Siwalik Gp). The Subathu Fm occurs as discontinuous
fragments along the flanks of the Sirban Limestones Inliers and its thickness varies. The
estimation of the exact thickness of this formation is complicated due to the tectonic
complexity in the region. The outcrops of the Subathu Fm around Kalakot area are c. 50-
80 m in thickness. The high quality seismic profiling data is lacking which would have
been significant in understanding the subsurface behavior and the exact thickness of these
Figure 2.12: Regional geological map of the foothills of the NW Himalaya showing the
distribution of slivers of the Subathu Fm (Hakhoo et al., 2014).
24
rocks. The seismic surveys, gravity modelling and depth section refraction profiling
undertaken in HFB and Punjab plains indicate that the Subathu Fm forms a ‘wedge’
which pinches out and becomes completely absent towards the south and south-west (Fig.
2.13). Numerous wells have been drilled in the median and outer belts of the HFB, but
Subathu Fm rocks have not been encountered in any of the drilled wells (Mittal et al.,
2006). The depth section and gravity modelling profiles show that the Subathu Fm is of
considerable thickness towards the inner belt of the HFB.
Subathu Fm is composed of the transgressive and regressive facies beginning with
the subsidence and formation of the basin, leading to the marine transgression. This is
followed by the upliftment and shallowing of the basin and ultimately leading to the
regression and complete withdrawal of the sea (Raiverman and Raman, 1971; Chaudhri,
1976; Singh, 1978; Mathur, 1978). Subathu Fm has got wide lateral extension in excess
of 500 km, where it crops out as discontinuous slivers all along the northwestern sector of
the Himalaya. It extends from Pakistan (Salt Range and Northwest area), through Jammu
(Punch, Kalakot and Riasi) and upto Himachal Pradesh (Dharamsala, Mandi, Bilaspur,
Subathu, Nahan, Kangra and other areas) and Uttrakhand regions (Garhwal area). The
current study is restricted to the Subathu Fm sediments cropping out in Jammu region
along the Riasi and Kalakot – Mahogala inliers (Fig. 2.14). Multiple outcrops of Subathu
Fm occur in Chapparwari, Pahnasa, Arnas, Kanthan, Salal, Bakkal, Kalimitti,
Sukhwalgali, Jangalgali and Muttal areas along the Riasi Inlier and in Jigni, Manma,
Tattapani, Beragua, Kalakot, Metka and Mahogala areas along the Kalakot–Mahogala
Inlier.
Figure 2.13: Gravity modelling profile of Punjab Plains and Sub-Himalayan Foreland
Basin (After Singh et al., 2005).
25
The Subathu Fm represents the platform succession and is comprised of three main
facies (Sahni et al., 1983; Najman and Garzanti, 2000) which include:
Basal swampy to marginal marine facies, in which carbonaceous black shale
and limestones were deposited.
An intra-shelf lagoonal facies consisting of intercalating green shale and
limestone.
Delta plain and tidal flat facies consisting of red, bioturbated fine-grained
sandstones, siltstones, and mudstones.
Rao et al. (1974) have also reported the presence of bioherm facies in the Subathu
Fm of Jammu and Kashmir. The Subathu Fm comprises of black carbonaceous shale at
the base overlain by black coal seam with the intermittent anastomosing stringers of ash
seen at only one outcrop (at Manma Section). This is followed by grey shale with a thin
sandstone unit which is overlain by limestone which contains a variety of foraminifera.
This succession is overlain by the rhythmic sequences of grey shale and limestone
conglomerate, indicating the storm activity (Singh and Srivastava, 2011). The overlying
succession consists of shelly limestone which is dominated by oyster shell fragments.
Above the oyster bed lies the oxic pink needle shale which marks the upper boundary of
the Subathu Fm. This is unconformably overlain by the continental facies of the Murree
Figure 2.14: Local geology of the Riasi and Kalakot areas and the key outcrop localities
of the Subathu Fm.
26
Fm (equivalent to Dharamsala Gp or Dagshai – Kasuali formations) which in turn is
overlain by the Late Miocene to Pliestocene Siwalik Gp followed by Recent Alluvium.
The sandy turbidites have also been reported from the Muttal Section, where these beds
are around 2 m thick and are overlain my nummulitic bed. On the basis of the
foraminifera, Subathu Fm has been dated as the Late Palaeocene to Mid Eocene. The age
of the coal beds at the base of the Subathu Fm is assigned as Late Palaeocene based on
the presence of an assemblage of Daviesina garumnensis, D. tenuis, D. langhami and
Lockhartia conditi (Mathur and Juyal, 2000). The presence of benthic forams Assillina
spira abrardii (Shallow Benthic Zone – SBZ-14) and A. exponens – A. papillata –
Nummulites discorbinus assemblages has established Early and Late Lutetian age (upper
limit at c. 44 Ma) to the nummulitic limestones of the Subathu Fm (Mathur, 1978; Bhatia
and Bhargava, 2005 and 2006). The basal part of the Dagshai Fm (=Murree Fm) has been
assigned the depositional age of c. 31 ± 1.6 Ma based on the fission-track dating of the
detrital zircon from the white sandstone of the Dagshai Fm (Najman et al., 2004),
suggesting a major unconformity of > 10 Ma between the Subathu Fm and Dagshai Fm.
However, Bera et al. (2008) has reassessed the duration of this unconformity and
interpreted it to be ≤3 Ma on the basis of the reworked fossils in calciturbidite, which
suggest the upper limit of the Subathu Fm younger than c. 44 Ma.
The tectonics had played major role in the hydrocarbon generation, accumulation
and trap formation in the HFB. The subsidence history of the HFB is concomitant with
the initiation of, and peak activity along the major regional thrusts in the region. The
subsidence rates increased rapidly post 40 Ma in tune with the initiation of the activity
along the Main Central Thrust (MCT), which attained peak activity around 16-14 Ma
(Fig. 2.15). During this time the Subathu Fm sediments attained maturation window and
initial generation of the hydrocarbons occurred (Verma et al., 2012). The peak oil was
reached c. 10 Ma concomitant with the peak activity along the MBT and the gas window
was attained around 9-6 Ma (Verma et al., 2012). Interestingly, all the structures present
in the median and the outer belts of the HFB (explored by the ONGC) have formed with
respect to the activity along the HFT around 1 Ma BP and bear minimal chance for being
charged by the hydrocarbons generated c. 10 Ma BP from the Subathu Fm. Thus, the
traps formed concomitant with the activity along the MBT in the inner belt of the HFB
hold significant potential for the accumulation of oil and gas, thereby the inner belt of the
HFB warrants further exploration.
27
2.2.2 Conventional Petroleum System
The HFB constitutes the main Subathu-Murree/Siwalik conventional petroleum
system. Petroleum system events chart of the HFB was developed which depicts the
timing of petroleum system elements and processes (Fig. 2.16). Subathu Fm shales form
the principle source rocks apart from the algal laminated dolostones and interbedded
shales in the Sirban Limestone Fm (Hakhoo, 2014). Main reservoirs include the Murree
Fm and the Siwalik Group sandstones. The Sirban Limestone Fm limestones/dolostones
also possess the essential reservoir characteristics. Seal/cap rocks include the interbedded
chert, argillite and shale in the Sirban Limestone Fm, Subathu Fm shale, the Murree Fm
and the Siwalik Gp claystones/mudstones. Trap formation and hydrocarbon generation,
migration and accumulation was concomitant with the activity along the major thrusts in
the region (viz. MCT and MBT), i.e. between 16-14 Ma, 10 Ma and 9-6 Ma in the inner
belt of the HFB, where the preservation potential is good. The gas window was acquired
around 9-6 Ma BP (Verma et al., 2012). The time span between 14-10 Ma depicts the
critical moment during which generation, migration and accumulation of hydrocarbons
took place in the HFB.
Figure 2.15: The subsidence history of the HFB (showing the rate of subsidence,
sedimentation and critical timing of the hydrocarbon generation).
28
2.3 Sampling Details
The Eocene Cambay Shale samples were collected from 4 wells [JU-1
(22°56'27.16'' N, 72°25'53.13'' E), JU-2 (23°09'23'' N, 72°19'2'' E), JU-3 (22°18'16.4'' N,
72°40'55.5'' E) and JU-4 (21°35'9.5'' N, 72°50'34.9'' E)] from four different tectonic
blocks and mudstones from the open cast Mangrol Lignite Mine (JU-5: 21°27'21.10'' N,
73°07'55.92'' E), Surat (Gujarat State). The litholog of the Mangrol section is shown in
Figure 2.17. The Eocene Subathu Fm shales, coaly shales, coals and grey shale samples
were collected from the boreholes, underground mines and fresh outcrops near Kalakot
(33°12.979'N, 74°25.011'E), Mahogala (33°12.459' N, 74°30.127' E), Beragua
(33°13.681' N, 74°24.077' E), Manma (33°14.543' N, 74°22.699' E), Tattapani
(33°14.583' N, 74°24.780' E), Chakkar (33°10.661' N, 74°35.628' E), Chapparwari
(33°11.550' N, 74°35.903' E), Salal (33°9'46.15'' N, 74°49'3.13'' E), Kanthan
((33°10'32.78'' N, 74°50'59.34'' E), Bakkal (33°08'28.20'' N, 74°54'16.59'' E), Ransoo
(33°08'08.03'' N, 74°37'25.91'' E), Kalimitti (33°05'25.21'' N, 74°57'51.69'' E) and Muttal
(32°59'31.49'' N, 75°02'12.56'' E) areas near Jammu. The lithologs of the Manma Section,
Figure 2.16: The conventional petroleum system events charts of the Himalayan Foreland
Basin.
29
Beragua (BBHA) and Mahogala (MBH3) boreholes is shown in the Figure 2.17. Different
analyses of cores, cuttings and fresh samples from outcrops, boreholes, open-cast and
underground mines and wells were carried out in the laboratories at NGRI, Hyderabad;
SAIF Lab, Chandigarh and Energy and Geosciences Institute (EGI), University of Utah
(USA). The source potential of these samples was determined by performing the
sophisticated geochemical analytical techniques, viz. Total Organic Carbon (TOC)
estimation and programmed pyrolysis technique (Rock Eval Pyrolysis) developed by the
Institut Français du Pétrole (Espitalie et al., 1977). Gas Chromatographic (GC) analysis
was also done to find out the depositional environment, maturation and biodegradation of
the shale samples. Organic Petrography, Visual Kerogen Analysis (VKA) and Vitrinite
Reflectance (Ro) tests were carried out to study the nature and proportions of the organic
matter constituents in the samples and to determine the level of organic maturation
(LOM). Bulk mineralogical and clay mineral analyses of the samples were performed to
evaluate their reservoir potential. Rapid reconnaissance methodological analyses, viz.
XRD and QEMSCAN® were done for estimating the shale mineralogy and texture. SEM
studies were carried out to understand the fabric and pore type and networks of these
shales. The data generated by all these analyses were used for the palaeoclimatic and
palaeoenvironmental reconstruction and a depositional model is proposed for the selected
shale formations.
30
Figure 2.17: Lithologs from A) Mangrol Lignite Mine, Surat
(Cambay Basin). B-C) Schematic logs of whole Subathu Fm
from two boreholes and Manma Section.
A
B
C
D
31
CHAPTER 3
SOURCE ROCK
GEOCHEMISTRY AND
HYDROCARBON
POTENTIAL
32
SOURCE ROCK GEOCHEMISTRY AND HYDROCARBON POTENTIAL
3.1 Visual Kerogen Analysis (VKA) and Vitrinite Reflectance (Ro)
3.1.1 Introduction
Organic petrography or Visual Kerogen Analysis (VKA) is performed to study the
nature and proportions of the organic matter constituents in a rock and also helps in
understanding the maturity of these organic components. Maceral (derived from Latin
word ‘macerare’ which means ‘to soften’ (Stopes, 1935) is a word typically used for the
organic matter identified in coals and possesses distinctive physico-optical properties.
The visual observation of kerogen/maceral and its detailed study of physico-optical
characteristics helps in identifying the source of organic constituents. Organic matter
present in sediments is broadly divided into three main maceral groups, viz. hydrogen-
rich liptinite, oxygen-rich vitrinite and carbon-rich inertinite (Teichmuller, 1989; Taylor
et al., 1998 and ICCP, 1998 and 2001).
Liptinite (exinite) is derived from the algal bodies (alginite), spores (sporinite),
hydrogen-rich plant matter, and bacterial substances and also from degraded organic
material. In oil immersion, it shows lowest reflectance under reflected light. The high
content of hydrogen compounds in this maceral group suggests that the liptinites are oil
prone kerogen (mainly Type I and Type II) and produces hydrocarbon after attaining the
suitable thermal maturity (Tissot and Welte, 1984; Taylor et al., 1998; Wilkins and
George, 2002). Inertinite maceral group comprises of organic matter derived from the
higher plants which have been oxidized, burned, altered and degraded prior to the
deposition. This group contains high carbon content and low hydrogen and its reflectance
is higher than the macerals of liptinite and vitrinite groups (ICCP, 2001). It represents a
part of kerogen Type IV and is usually considered as dead carbon with no hydrocarbon
generation potential and may also include the other three types of kerogens when
subjected to higher degree of thermal maturation, making them ‘inert’ or ‘dead’ (no
remaining hydrocarbon generation potential). Vitrinite, another maceral with shiny
texture, is formed through thermal modification of lignin and cellulose (woody tissue) of
terrestrial higher plants cell wall, after the successive processes of humification and bio-
and geochemical gelification (Teichmuller, 1989). It is ubiquitous in post Silurian
sedimentary rocks. The vitrinite macerals are mostly grey in colour and show medium
reflectance, between that of darker liptinites and lighter inertinites (ICCP, 1998). It occurs
as lenses, cells, pores and fissure fillings and represents the key component of the kerogen
Type III (gas prone), with high oxygen and low hydrogen content.
33
Vitrinite macerals have been widely used to ascertain the maturation of organic
matter. Being abundant in coals, it has been extensively used to determine their thermal
alteration by coal petrologists. During mid 1960s the technique was adopted by petroleum
industry to evaluate the thermal maturity of kerogen and is considered as one of the most
important parameters used to assess the gas shale and shale oil potential. After the burial
under the sediments, vitrinite undergoes reflectance changes due to complex
aromatization reactions with increasing time and temperature. Therefore, it helps in
understanding the palaeotemperature of the source rocks (Littke et al., 2012). Vitrinite
reflectance (% Ro) is measured by using the oil immersion objective lens and the
percentage of the light reflected off the maceral is calculated and the value is compared
with the standard of known reflectance.
The organic matter maturation leads to the generation of hydrocarbon, starting with
heavy and liquid hydrocarbons, lighter oil, wet gas condensates and ultimately dry gas
with the increase in the most important parameters of maturation, i.e., temperature and
time (Lopatin, 1971; Waples, 1980 and 1994). The maturation value calculated through
vitrinite reflectance depends upon the type of maceral and varies from one type to
another. The lower vitrinite reflectance value of kerogen (Ro < 0.5% to 0.6%) indicates
diagenesis and immature source rock and the values between Ro 0.5% and 1.0% indicates
oil generation window. The reflectance values between Ro 1.1% to 1.5 % indicate wet
gas window with more inclination towards generation of oil at the lower side of the
reflectance range. The values above 1.5 % (Ro > 1.5%) generally suggest dry gas window
(Hood et al., 1975; Tissot and Welte, 1984; Murchison, 1985; Teichmuller, 1987;
Marshall, 1990; Peters and Cassa, 1994 and McCarthy et al., 2011). There are no sharp
boundaries of hydrocarbon generation zones but it depends on the various assemblages of
organic matter subjected to thermal maturation. Vitrinite reflectance values can
sometimes be misleading, therefore should be supported by other measurements. The
alginite, sporinite and other liptinite macerals fluorescence colour can also be used to
ascertain the thermal maturity of organic matter.
3.1.2 Methodology
The visual kerogen analysis (VKA) and vitrinite reflectance (Ro) measurements
were performed at EGI Laboratory in Bratislava (Slovakia). The Ro measurements were
made on the polished surfaces of whole rocks and cuttings samples. A microscope Leitz
MPV-Compact with photometer was used for organic petrographic/visual kerogen (VKA)
analyses – vitrinite reflectance measurements and maceral analysis. Random reflectance
34
(% Ro, % Rr) was determined for vitrinite particles and also in suitable conditions for
other types of organic particles (liptinites, fusinites, solid bitumen, etc.). Mean (random)
vitrinite reflectance readings (% Ro, % Rr) were taken from randomly oriented
phytoclasts (i.e., no rotation of the microscope stage) in non-polarized light, using an oil
medium.
Measurements were made under the following conditions: immersion oil with a
refractive index of n = 1.518; glass standard 1.24 % Ro, objective 50x. The number of
individual reflection measurement was dependent on the abundance of vitrinite in a
sample. From the appropriate population of vitrinite average value and standard deviation
(STDEV) were calculated.
The same polished sections were used for the organic petrography study of
macerals. Samples were studied using an Olympus BX-51IR microscope system with an
Ultra - high vacuum mercury lamp produced wide-band radiation, from which the UV
radiation with a wavelength of 365 nm was extracted using a U-MWU2 mirror unit with a
DM 400 dichroic mirror, BP330-385 nm excitation filter and a barrier filter to block out
the over 420 nm electromagnetic radiation. Documentation was made using a G1-2000C
CCD color camera.
Table 3.1: Vitrinite Reflectance Analysis of Cambay Shale and Subathu Fm Shale samples
3.1.3 Results and Discussions
Sample % Ro (Rr) No. Of
Measurements STDEV
Stratigraphic
Age Mean Min. Max.
CAM3 0.58 0.48 0.7 53 0.047 Eocene
CAM8 0.59 0.51 0.7 49 0.045 Eocene
CAM13 0.7 0.59 0.87 49 0.073 Eocene
CAM19 0.54 0.44 0.65 36 0.05 Eocene
CAM21 0.46 0.35 0.64 53 0.24 Eocene
SUB2 1.65 1.29 2.01 48 0.24 Eocene
SUB5 1.24 1.16 1.39 42 0.069 Eocene
SUB6 1.16 1.04 1.36 64 0.069 Eocene
SUB9 1.6 1.26 2.04 53 0.19 Eocene
SUB17 n/a Eocene
35
Visual Kerogen Analysis and Vitrinite reflectance analysis were performed for 10
rock and cuttings samples; five Cambay Shale samples and five samples of basal Subathu
Fm shales. The results are presented and summarised in Tables 3.1 and 3.2 and each
sample is individually discussed below.
3.1.3.1 Cambay Shale Samples
1. Sample: CAM3
Stratigraphic age: Eocene
Sample type: Cuttings (black mudstones; dark siltstones; unidentified black rock chips
with spherical pores filled with an opal and calcite)
Table 3.2: Visual Kerogen Analysis (VKA) of Cambay Shale and Subathu Fm Shale samples
Sample
ID
Vitrinit
e %
Inertinite
%
Liptinite % Solid
Bitumen
%
Floures.
OM %
Oil
Prone
%
Gas
Prone
%
Pollen/
Spore
Floures.
Color
Alginite
Floures.
Color Alginite
%
Amorphous
Organic
Matter %
Other
%
CAM3 80 -
90 0 – 5 10 – 20 0 0 90
CAM8 10-
90* 10-90 2* 15* 0-100
0-
100
0-
100 Yellow Yellow
CAM1
3 75-90 1 5-6 5-20 0 5 4 100
CAM1
9 40-45 2 10-15 30 0 40 45 35 Yellow
Green
-
Yellow
CAM2
1 45-55 2-7 35-40 15-25 40 50 40 Yellow
Green
-
Yellow
SUB2 60 40 0 0 100
SUB5 60 40 0 0 100
SUB6 65 10-15 20 100
SUB9 60 40 0 Oil 100
SUB17 n/a
* Depending on rock type
36
Comments:
Vitrinite, liptodetrinite (detrital macerals of cutinite, sporinite) and very rare
inertinite (inertodetrinite, sclerotinite) were identified in the shale and siltstone samples
(Plate 3.1a, b, c). Solid bitumen fills were observed in the inter-granular spaces in
siltstone. Resinite (mainly lipid resinites, formed from fats and waxes) shows brown-
orange fluorescence under blue light excitation (Plate 3.1d, e). Nearly all observed
liptinites are represented by macerals derived from terrestrial plants. The typical ratio of
individual maceral groups is: 80 – 90 % vitrinite group, 10 – 20 % liptinite group and 0 –
5 % inertinite group. Such a maceral assemblage is characteristic of a coal forming
environment and/or lower delta plain environment (e.g., lignite-bearing environments
represented by marine coastal swamps, mangrove and freshwater swamps). The
unidentified rock chips have also been seen in this cutting sample, which is black and
porous and the spherical pores are filled with an opal and calcite (Plate 3.1f).
Vitrinite reflectance analysis:
Based on 53 measurements, the average Ro of vitrinite is 0.58 % (st. dev. = 0.047);
(Plate 3.1g). Reflectance values suggest early maturation stage of organic matter. The
fluorescence of resinite indicates threshold maturity of the samples typical of oil window.
Mean reflectance of other macerals:
Recycled vitrinite Ro = 0.72 % (n = 58; st. dev. = 0.081)
Liptinite Ro = 0.44 % (n = 14; st. dev. = 0.034)
Funginite Ro = 0.66 % (n = 11; st. dev. = 0.04)
Solid bitumen Ro = 0.28 % (n = 2; st. dev = 0.02)
2. Sample: CAM8
Stratigraphic age: Eocene
Sample type: Cuttings (black mudstones; dark siltstones)
Comments:
The sample consists of finely laminated shales and siltstones. Alginite, sporinite and
bituminite are the dominant constituents of the shale sample. Macerals derived from a
terrestrial source are represented by vitrinite, inertinite (fusinite, sclerotinite) and
funginite and is dominant in siltstone. More than 95 % of vitrinite particles observed in
37
Plate 3.1: Counter-clockwise from a, b, c) Photomicrographs of macerals in reflected white light (oil immersion): Vitrinite and liptinite
particles; d & e) Photomicrographs of macerals and rock in UV light (dry lenses): Resinite
38
Plate 3.1: f) Unidentified black rock chips (basalt?) with spherical pores filled with an
opal and calcite. g) Frequency distributions of vitrinite and other macerals reflectance
values.
39
siltstone are autochthonous and only small portion represents allochthonous vitrinites.
Such a maceral assemblage indicates an input of sediments enhanced by immature/fresh
organic matter from proximal terrestrial source and dysoxic bottom water conditions.
Quite high content of algae Botryococcus braunii (maceral telalginite) (Plate 3.2a–f)
indicates deposition in limnic/brackish water settings. The alginite exhibits yellow color
under UV irradiation, which indicates low maturity of organic matter.
Vitrinite reflectance analysis:
Based on 49 measurements, the average Ro of vitrinite is 0.59 % (st. dev. = 0.045);
(Plate 3.2h). Reflectance values suggest that the organic matter is in early mature stage.
The fluorescence of alginite indicates threshold maturity typical for oil window.
Mean reflectance of other macerals:
Liptinite Ro = 0.43 % (n = 14; st. dev. = 0. 055)
3. Sample: CAM13
Stratigraphic age: Eocene
Sample type: Cuttings; particular rock pieces are: black and grey claystones, shales and
yellow-grey siltstones
Comments:
The quantity of organic matter depends on the type of rock fragment analyzed. It
was observed that calcareous grey shales contain only small amount of organoclasts. The
absolute majority of particles are small-sized recycled (allochthonous) vitrinites. It is
estimated that in this type of rocks, the organic matter content accounts for 0.5 – 1 % by
volume. In dark non- calcareous siltstones and shales the organoclasts are larger and more
abundant. In some rock pieces the organic matter content accounts for 9 % by volume.
Terrestrially-derived type of organic matter (mainly vitrinite and liptinite; Plate. 3.3a–d)
dominates over the marine-derived liptinite (algae) in an approximate ratio 8:1. Vitrinite
is both autochthonous as well as allochthonous and relatively high content of both types
of these macerals indicate the proximal source of terrestrially-derived organic matter
deposited in brackish environment. The presence of angular quartz grains observed in the
samples also suggests relatively close terrestrial source of the sediments.
40
Plate 3.2: a-c) Photomicrographs of alginite (Botryococcus braunii) in ultra-violet light (dry lenses).
41
h) Frequency distributions of Vitrinite and Liptinite reflectance values
Plate 3.2: d-f) Photomicrographs of alginite (Botryococcus braunii) in ultra-violet light (dry
lenses). g) Photomicrographs of vitrinite in reflected white light (oil immersion).
42
Vitrinite reflectance analysis:
Based on 49 measurements, the average Ro of vitrinite is 0.7 % (minimum Ro 0.59,
maximum value 0.87 %); (Plate 3.3e). These reflectance values suggest that the organic
matter is mid mature and within the oil generation zone.
Mean reflectance of other macerals:
Recycled vitrinite Ro = 0.8 % (n = 58; st. dev. = 0.116)
Liptinite Ro = 0.57 % (n = 4; st. dev. = 0.206)
Sclerotinite Ro = 0.75 % (n = 5; st. dev. = 0.041)
4. Sample: CAM19
Stratigraphic age: Eocene
Sample type: Black mudstone with secondary gypsum crystal coating
Comments:
Macerals derived from terrestrial and aquatic sources are present in equal amounts
(Plate 3.4a–g). Liptinitic macerals slightly predominate over vitrinites and inertinites.
Recycled vitrinites (allochthonous) are less abundant and inertinite is present in negligible
quantity. Sporinite maceral shows yellow fluorescence under UV light. Corpocolinite,
which is the filling of the cell lumens, exhibits weak light brown fluorescence.
Exsudatinite, a secondary maceral generated from liptinite and vitrinite, exhibits bright
yellow fluorescence. The presence of such maceral assemblages suggests the brackish
type of depositional environment. Pyrite mineral is also abundant in this sample,
indicating reducing (anoxia) environment.
Vitrinite reflectance analysis:
Based on 36 measurements, the average Ro of vitrinite is 0.54 % (st. dev. = 0.065)
(Plate 3.4h). These reflectance values and the fluorescence of liptinite indicate that the
organic matter has not entered the oil window stage suggesting immaturity.
Mean reflectance of other macerals:
Recycled vitrinite Ro = 0.65 % (n = 7; st. dev. = 0.073)
Liptinite Ro = 0.37 % (n = 14; st. dev. = 0. 06)
43
Plate 3.3: Photomicrographs of macerals in reflected white light (oil immersion): a, b)
Tiny vitrinite, liptinite and funginite particles; c, d) Liptinite with pyrite; e) Frequency
distributions of vitrinite and other macerals reflectance values. fg - funginite, v - vitrinite,
lp - liptinite, py – pyrite.
44
Plate 3.4: a) Brown corpocolinite bodies in dark liptinite in reflected white light (oil immersion); b) The same macerals in UV light (dry
lenses). Note the bright yellow fluorescence of exsudatinite. c) Vitrinite with tiny yellow resinites in UV light; d) Liptinites & vitrinites
(reflected white light, oil immersion). c – Corpocolinite; r – resinite.
45
Plate 3.4: e, f, g) Liptinites in UV light (dry lenses); h) Frequency distributions of vitrinite and other macerals reflectance values.
46
5. Sample: CAM21
Stratigraphic age: Eocene
Sample type: Black mudstone with small brown fish scales and surface of the rock is
coated with secondary gypsum crystals
Comments:
Fine laminated rock contains macerals derived from terrestrial and aquatic source.
Macerals of vitrinite group slightly predominate over macerals of liptinite group.
Inertinites (mainly sclerotinite and funginite) are present only in small quantity. Vitrinites
are autochthonous, only small part of vitrinite particles are oxidized or allochthonous.
Liptinite is represented by liptodetrinite, sporinite and alginite (e.g. Botryococcus braunii,
Plate 3.5a-e). The presence of such maceral assemblage indicates brackish type of
environment during the sedimentation. Under blue light the alginite shows green-yellow
fluorescence and the sporinite shows yellow fluorescence. This indicates immature
organic matter.
Vitrinite reflectance analysis:
The average Ro of vitrinite is 0.46 % (st. dev. = 0.05); (Plate 3.5f). Reflectance
values suggest immature organic matter. The fluorescence of alginite and sporinite
indicates immature organic matter and has not yet entered in the oil window zone.
Mean reflectance of other macerals:
Liptinite Ro = 0.34 % (n = 8; st. dev. = 0.051)
Allochthonous (recycled) vitrinite: Ro = 0.52 % (n = 8; st. dev. = 0.04)
3.1.3.2 Subathu Fm Shale Samples
1. Sample: SUB2
Stratigraphic age: Eocene
Sample type: Very fine laminated black shale
Identified macerals:
The Non-fluorescent particles of organic matter cover approximately 7 % of the
total surface area of the polished rock. Macerals of vitrinite and inertinite groups are
predominant (Plate 3.6a, b, c). Liptinite macerals can only be identified by their typical
47
Plate 3.5: Photomicrographs of macerals: a, b) Alginite and vitrinite in reflected white light
(oil immersion); a – alginite, v – vitrinite; c, d, e) Alginite and sporinite in UV light (dry
lenses). Note the bright yellow fluorescence of liptinitic macerals. f) Frequency distributions
of macerals reflectance values.
48
Plate 3.6: Photomicrographs of macerals in reflected white light (oil immersion): a) Tiny
inertodetrinite, vitrinite and fusinite particles; b) Semifusinite; c) Semifusinite; (note a finely
laminated texture of black shale); d) High-mature sporinite; e) Vitrinite reflectances bar
charts.
49
shape (Plate 3.6d). The abundance of the terrestrial organic matter (vitrinite) suggests the
deposition of the sediments in shallow, brackish water environment.
The non-fluorescent vitrinite occurs as needle-shaped particles as well as irregular
fragments. All macerals exhibit the anisotropy of the reflectance. Sporinite and vitrinite
exhibit significant bireflectance. The bireflectance of fusinite is very weak.
Vitrinite reflectance analysis:
The vitrinite reflectance values range between 1.29 % and 2.01 %, mean Rr = 1.65
% (Plate 3.6e). The reflectance indicates that the organic matter is within the gas
generation zone.
Mean reflectance of other macerals:
Inertodetrinite and semi-fusinite reflectances range from 1.89 to 4.81 %
Sporinite reflectances are in the interval of 1.28 – 1.87 % Rr.
Fusinite Rr = 3.91 % (n=45; st. dev. = 1)
2. Sample: SUB5
Stratigraphic age: Eocene
Sample type: Coaly Shale
Identified macerals:
The analyzed coaly shale sample has vitrinite, semi-vitrinite and inertinite (fusinite,
semi-fusinite and sclerotinite) (Plate 3.7a-d). The presence of the abundant inertinite
maceral like fusinite and semi-fusinite indicate the thermal maturation of the plant
organic matter. Organic matter covers more than 70 % of the total surface area of the
polished coal. Vitrinite is grey and porous. Semi-vitrinite is the transition maceral
between vitrinite and semi-fusinite. Observed semi-vitrinites are grey with a weak yellow
tint and cellular structure. Cell walls of semi-vitrinite are less abundant and usually
thicker than those of semi-fusinite. Semi-vitrinite particles exhibit significant decrease in
porosity in comparison with the observed vitrinites. The organopores of nanometer-scale
are also seen in the macerals. Semi-fusinite is yellow with weak grey tint. Fusinites are
bright gold yellow with well-preserved cell walls. Macerals including funginite,
sclerotinite and inertinite are greyish yellow. Pyrite is rare in this sample. This maceral
assemblage suggests the swampy depositional environment.
50
Plate 3.7: a-d) Macerals shown include vitrinite, semivitrinite, fusinite, semifusinite and sclerotinite. Reflected white light, oil immersion.
51
Plate 3.7: e) Maceral reflectances graph. SEM images showing macerals which
include vitrinite, semivitrinite, fusinite, semifusinite and sclerotinite; and Pyrite.
52
Vitrinite reflectance analysis:
The vitrinite reflectance values of measured sample range between 1.16 and 1.39 %
Rr, mean Rr = 1.24 % (Plate 3.7e). Maceral composition and vitrinite reflectance indicate
medium bituminous coal. The reflectance indicates that the organic matter is mature -
within the gas generation zone.
Mean reflectance of other macerals:
Semi-vitrinite Rr =1.52 % (n=24; st. dev. = 0.07)
Semi-fusinite Rr =1.69 % (n = 9; st. dev. = 0.018)
Fusinite Rr = 3.52 % (n = 9; st. dev. = 0.15)
Corpocolinite Rr = 1.45 % (n = 6, st. dev. = 0.044)
Inertinite Rr = 2.37 % (n = 9; st. dev. = 0.012)
3. Sample: SUB6
Stratigraphic age: Eocene
Sample type: Dark claystone
Identified macerals:
Organic matter covers approximately 10-12 % of the total surface area of polished
claystone. Non-fluorescing vitrinite is the dominant maceral (Plate 3.8a-c). More than 60
% of observed vitrinites are autochthonous and the rest consists of recycled vitrinites
(irregular and broken fragments, frequently with higher reflectance). Vitrinites are usually
highly porous and these pores (organic-matter interparticle pores or organopores) may
have been formed due to the thermal maturation of organic matter. Inertinites and semi-
fusinites are present in small amounts. The non-fluorescent solid bitumen fills the
intergranular space between mineral grains. It was observed as speckles dispersed in the
matrix. Pyrite is less common. Some grains of newly formed quartz were also observed.
The abundance of autochthonous and allochthonous vitrinite suggest the high terrestrial
influx and such maceral assemblage is indicates brackish or lower delta plain
environment of sedimentation.
53
Plate 3.8: a ,b, c) Vitrinite and solid bitumen in reflected white light
(oil immersion), d) Vitrinite and other macerals reflectance values.
54
Vitrinite reflectance analysis:
The vitrinite reflectance values of measured sample range between 1.04 and 1.26 %
Rr, mean Rr = 1.16 % (Plate 3.8d). These reflectance values indicate that the organic
matter is mature - within the wet-gas generation zone.
Mean reflectance of other macerals:
Recycled vitrinite Rr = 1.63 % (n = 12; st. dev. = 0.38)
Semi-fusinite Rr = 1.84 % (n = 5; st. dev. = 0.35)
4. Sample: SUB9
Stratigraphic age: Eocene
Sample type: Laminated black shale
Identified macerals:
Abundant small particles of organic matter below 20 μm are typical for the analysed
black shale (Plate 3.9a), with only a small part of macerals being larger than 50 μm.
Macerals of inertinite group (inertodetrinite and fusinite) are dominant over vitrinites.
Inertinite and fusinite are light grey, white and yellow. These macerals exhibit higher
reflectance than vitrinite (Plate 3.9b). All macerals exhibit low bireflectance. . The
presence of such maceral types suggests terrestrial influx and paludal depositional
environment.
Vitrinites are porous, thus exhibiting the organoporosity and display abnormal
differences of grey color tones as well as reflectivity between the individual particles.
Some vitrinites have dark grey rim (Plate 3.9c), which indicate the presence of vitrinite
that has adsorbed liquid hydrocarbon. Oil presence in the shale is suggested by oil
droplets, which were visible during microscopic examination of the sample under UV
light (Plate 3.9e). It is assumed that different impregnation intensity of particular vitrinite
particles with oil is the cause of the abnormal differences in vitrinite color intensity and
the suppression of vitrinite reflectance.
The source of oil is unknown. The organic matter in the shale is over mature so it
cannot be the source of the observed hydrocarbons. We could assume that i) the sample
has been stained during handling or storing; or ii) the oil has migrated into the rock from
the place of its original occurrence in the geological past.
55
Vitrinite reflectance analysis:
The vitrinite reflectance values range between 1.26 and 2.04%, mean Rr = 1.6 %
(Plate 3.9f). The reflectance indicates that the organic matter is within the gas generation
zone. But it can be assumed that the value of mean reflectance is affected by anomalously
suppressed Rr and it could be lower than the real value. Suppressed vitrinite reflectance
produces slightly lower reflectance and makes it difficult to accurately determine the
maturity.
Mean reflectance of other macerals:
Inertodetrinite and fusinite Rr = 3.91 % (n = 45; st. dev. = 1)
5. Sample: SUB17
Stratigraphic age: Eocene
Sample type: Grey crumbly siltstone with a calcite vein
Identified macerals:
The rock sample is crumbly, loose and tectonically disrupted which resulted in the
low quality of polished rock surface. Therefore only limited observations and analysis
were made on this sample. Most of the maceral present are mainly derived from terrestrial
sources (autochthonous and allochthonous vitrinite, liptinite and inertinite), and solid
bitumen is present in the rock. One type of organic particles has higher reflectance (0.9 –
1.53 %). This reflectance could correspond to vitrinite (allochthonous or/and
autochthonous) and inertinite. The second type of organic matter has low reflectance
(0.23 – 0.35 %). This could correspond to solid bitumen (but the possibility of the
presence of autochthonous vitrinite and liptinite with low Ro in the case of low thermal
alteration can’t be excluded).
As mentioned above, the poor quality of polished rock surface does not allow the
observation of particular macerals in details; therefore the degree of maturation of the
sample was not estimated more precisely.
3.1.4 Summary
Generally, all five Cambay Shale samples show the dominance of kerogen type III,
with the high vitrinite percentage which ranges from 40 – 90 %. The second most
abundant maceral types observed in the samples belong to liptinite group with the
56
c
Plate 3.9: Photomicrographs of macerals in reflected white light
(oil immersion): a) Tiny inertodetrinite and fusinite particles; b)
Fusinite; c) Vitrinite with a dark rim (perhydrous vitrinite)
57
Plate 3.9: d) Vitrinite, inertinite and fusinite (Note anomalously
big contrast between the reflectivity of particular macerals; e)
Green-shining oil droplets in fusinite (UV light, dry lenses); f)
Vitrinite reflectances bar charts.
58
percentage ranging from 10 – 90 % (depending on the rock type). Some of these liptinite
macerals are derived from terrestrial plants and some samples (CAM13, CAM19 and
CAM21) also show the presence of marine-derived liptinite macerals like alginite,
sporinite and amorphous algal and bacterial organic matter (AOM). The dominance of
vitrinite, alginite and other liptinite macerals indicates the organic facies Type BC and C
(using the nomenclature of Jones, 1987) deposited in dysoxic bottom water condition
during transgressive sedimentation. Moreover, the high TOC and moderate HI values of
the Cambay Shale samples (See the Rock Eval Sub-chapter) are consistent with organic
facies BC and C.
The inertinite type (Kerogen Type IV – “Dead Carbon”) of macerals (mainly
sclerotinite and funginite) are also seen in some of the samples (0 – 7 %) and are strongly
affected by oxidation during the biochemical stage of coalification.
The high percentage of gas prone organic matter (kerogen Type III) coupled with
inertinite macerals suggests that they were deposited in close proximity of the source in
lower deltaic plain environment. The high content of Botryococcus braunii (maceral
telalginite) and oil prone marine influenced (kerogen type II) macerals in JU4 and JU5
samples indicate limnic/brackish type of environment during sedimentation.
The Subathu Fm shale samples are highly represented by vitrinite macerals, with
percentage around 60 – 65 %. Inert coaly material is another dominant maceral (10 – 40
%) in these shales. The dominance of plant derived gas prone organic matter (Vitrinite
kerogen) and semifusinite and fusinite inertinite macerals, which are indicative of organic
facies C, suggest that these samples were deposited in close proximity to the source (e.g.
swamp forest) in paludal environement. The abundant organopores of nanometer scale are
observed in the vitrinite and inertinite macerals.
It has been studied that the rocks deposited on the shelves and slopes of continental
margins during the Mesozoic and Palaeogene times show the dominance of organic facies
type BC and C (Jones, 1987). The Cambay Shale and the Subathu Fm samples also show
the abundance of organic matter which has the characteristics similar to these two organic
facies i.e. Type BC and C.
Vitrinite reflectance (% Ro) and the fluorescence colour of some of the liptinite
macerals were used to ascertain the thermal maturity of the organic content in the
Cambay Shale samples. The three samples from the shallower depth of three different
59
wells show vitrinite reflectance values ranging between 0.58% and 0.7%. With respect to
the mixed kerogen (Types III + II), the reflectance range corresponds to the main zone of
oil generation (0.5% - 1.0%). The fluorescence of resinite and alginite in these samples
suggest maturity typical for oil window stage. The samples from the Mangrol open-cast
lignite mine representing the basin margin, show Ro values very less suggesting
immature organic matter in early diagenesis.
The basal Subathu Fm Shale samples exhibit the high reflectance values ranging
from 1.16% to 1.65% suggesting high level of organic maturation. This reflectance range
indicates wet gas to dry gas generation zone.
60
2 Rock Eval Pyrolysis
3.2.1 Introduction and Methodology
Organic geochemistry is essential for the shale characterisation and shale gas
evaluation. Rock Eval (RE) Pyrolysis forms the fundamental organic geochemical
technique to evaluate the petroleum potential of the organic matter rich sedimentary
rocks. This method rapidly acquires the information regarding the type, amount and the
level of maturation (LOM) of the organic matter (Espitalié et al., 1977; Peters, 1986). The
pyrolysis simulates the natural hydrocarbon generation process in the laboratory at a
higher temperature and in an inert atmosphere, expelling hydrocarbon molecules in a
short time span, which would otherwise take longer time at lower temperature under the
natural earth processes (Waples, 1980 and 1994; Nuñez-Betelu and Baceta, 1994;
Lafargue et al., 1998; Behar et al., 2001).
The programmed RE pyrolysis of the fine powdered rock sample is performed in an
inert (helium) atmosphere. The pyrolysis starts with the steady increase in the temperature
of the oven up to 300°C and is held constant for 3 minutes. This causes the volatilisation
of the free gaseous and liquid hydrocarbons, detected by the Flame Ionization Detector
(FID) as S1 signal. The temperature is then increased at 25°C/minute to 600°C, causing
the thermal degradation of the organic matter and the liberation of heavy and light
hydrocarbons, detected as S2 peak by FID. The temperature at which the maximum
amount of S2 hydrocarbons is released is referred to as Tmax. Its value depends on the
nature of the organic matter and indicates the thermal organic maturity. However, Tmax
values are unreliable for the organically lean rock samples and are also influenced by the
type of the minerals, free heavy hydrocarbons and contaminations. Additionally, the
thermal crackdown of the carbon bearing molecules of the kerogen releases the CO2 that
gets trapped between 340°C to 390°C and is detected as S3 peak by Terminal Carbon
Detector (TCD) during the cooling of the oven. The temperature of the pyrolysis oven is
cooled down to 580°C and the remaining kerogen is oxidised by treating with oxygen for
3 minutes. CO2 and CO generated during this time are detected by infrared (IR) detector
as S4 peak. The S4 peak is used to calculate the Total Organic Carbon (TOC) content of
the rock by oxidation of the residual organic carbon under air in a second oven, after
pyrolysis. It provides the precise percentage of the organic carbon content by subtracting
the contribution of the carbon generated due to the decomposition of minerals during the
pyrolysis and combustion processes (Lafargue et al., 1998; Behar et al., 2001).
The important parameters ascertained during the pyrolysis are given below:
61
TOC (Total Organic Carbon) content indicates the organic richness of the source
rock and is given in weight percentage of carbon. It is composed of two fractions, S1 and
S2 and is calculated as TOC = [k × (S1 + S2)]/10 + S4/10, where k = 83, which represents
an average carbon content of hydrocarbons by atomic weight (Fujine, 2014). S1 is
measured in milligrams of hydrocarbon per gram of rock (mg HC/g rock) and indicates
the free, light and thermally extractable hydrocarbons (gas or oil) in the rock sample. S1
value is used to calculate the TOC but the results can be erroneous if the sample is
contaminated. S2 (mg HC/g rock) is the amount of the hydrocarbons generated through
the thermal conversion of the kerogen and higher molecular hydrocarbons that do not
vaporize during the S1 peak. It indicates the genetic potential of the rock and the
temperature at which the maximum generation of the hydrocarbons occur (peak of the S2
signal), suggesting the thermal maturity of the rock and is represented as Tmax (in °C). If
the rock sample is organically lean, the Tmax value can be erroneous. The clay rich
samples with low organic matter content, where S2 value is as high as 2.00 mg HC/g rock
may have Tmax values of uncertain reliability (Espitalie et al., 1985). S3 values are
expressed in milligram of CO2 generated during the pyrolysis of one gram of rock up to
the temperature of 390°C. The abnormally higher values can be due to weathering or
mineral matrix interaction. S1+S2 value is the measure of the total genetic potential of the
rock sample. Hydrogen Index (HI) is the ratio of hydrogen to carbon [HI =
(S2/TOC×100)] and represents the quantity of pyrolyzable hydrocarbon content in the
sample. The organic matter from algae, planktons and other marine organisms are
hydrogen rich (Type I and II kerogen). Its value ranges from ~100 to 600 mg HC/g TOC
and is highest for Type I kerogen and lowest for Type IV. With the increase in sample
maturity, HI value decreases. Oxygen Index (OI) indicates the oxygen content of the
sample and corresponds to the ratio of oxygen to carbon [OI = (S3/TOC×100)]. Its values
range from near 0 to c. 150 mg CO2/g TOC. Organic matter derived from land plants
(Type III kerogen) generally has higher OI values. The higher values of OI also indicate
low TOC content or the CO2 contribution due to the pyrolysis of mineral matrix. The
weathered and contaminated sample may also show higher OI values. S2/S3 is the ratio of
the amount of hydrocarbons generated from a rock sample to the amount of organic CO2
liberated during the pyrolysis of the rock upto the temperature of 390°C. It is a quality
index and suggests the type of kerogen when the TOC data is absent. S2/S3 ratios are
considerably lower for the oxygen-rich, terrestrially derived kerogen type III than for
Type I and II kerogens. Production Index (PI) is defined as the ratio of the amount of
hydrocarbon which has been produced to the total genetic potential of the rock sample.
[PI = S1/ (S1 + S2) × 100]. S1/TOC parameter helps to identify source or reservoir rocks.
62
It is the ratio of free hydrocarbon to total organic carbon content (S1/TOC×100) and is
used to reconstruct the expulsion of oil when plotted against the depth (Hunt, 1996).
Selected cuttings, core and fresh outcrop samples of the Cambay Shale and Subathu
Fm shale samples were geochemically analysed to determine the total organic carbon
content, the variations of organic facies, thermal maturity and their depositional
environments. The pyrolysis experiment was carried out in the Weatherford Laboratories,
Houston, USA and Geochemical Laboratory, National Geophysical Research Institute
(NGRI), Hyderabad, India. Some of the samples were separately analysed using ‘Leco
Analyser’ to determine their carbon content so as to cross-check the results with the TOC
data calculated by Rock Eval method. Leco analyser works on the principle of the thermal
degradation during combustion of the sample from 105°C to 1050°C with the increase in
temperature at c. 105°C per minute. About 20 to 200 mg of pulverised sample is treated
with the concentrated hydrochloric acid (HCl) to dissolve any inorganic carbon present
within the sample. The sample is then dried and combusted in the furnace in which the
organic carbon is converted to CO2 which is quantified by infrared detector. For RE
Pyrolysis, the finely powdered Cambay Shale and Subathu Fm shale and coaly shale
samples were weighed in pre-oxidized crucibles depending upon the organic matter
content (~50-70 mg of the shale; and 8-15 mg of coaly shale) before running them in the
Rock Eval 6 machine, designed by Institut Français du Pétrole (IFP), France. The
instrument was calibrated in standard mode using the IFP standard (Tmax = 416°C; S2=
12.43) and the shale samples were run under analysis mode using the bulk rock method
and basic cycle of RE 6.
3.2.2 Results
3.2.2.1 Cambay Shale Samples
The RE data collected from the programmed pyrolysis of the shales are given in
Table 3.3, which includes TOC, S1, S2, S3, S1+S2, Tmax, HI, OI, S2/S3, PI and S1/TOC
× 100. The Eocene Cambay Shale samples collected from the 4 wells (JU-1, JU-2, JU-3
and JU-4) from four different tectonic blocks and also from open cast Mangrol Lignite
Mine (JU-5) show high organic carbon content. The TOC values are ranging from 0.37
wt. % to 10.68 wt. % with an average value of 2.43 wt. % (Fig. 3.1), indicating fair to
excellent
63
Table 3.3: Rock Eval pyrolysis data of the Cambay Shale samples. The measured and calculated Ro values are also given.
Well
Name Sample ID Depth (m) TOC S1 S2 S3 S1+S2
Tmax
(°C) Ro HI OI S2/S3 S1/TOC*100 S1/(S1+S2)
JU-1 CAM1 1305 1310 2.8 0.07 1.66 1.04 1.73 437 0.7 59 37 1.6 2.56 0.04
JU-1 CAM2 1325 1330 2.02 0.1 1.24 0.86 1.34 438 0.72 61 43 1.44 5.07 0.08
JU-1 CAM3 1350 1355 2.93 0.13 2.04 1.76 2.17 440 0.58 70 60 1.16 4.54 0.06
JU-1 CAM4 1365 1370 2.14 0.1 1.36 1.21 1.46 439 0.74 64 57 1.12 4.85 0.07
JU-2 CAM5 1495 1500 2.34 0.25 1 2.86 1.25 426 0.51 43 122 0.35 10.5 0.2
JU-2 CAM6 1700 1705 4.59 0.74 10.11 1.88 10.85 433 0.63 220 41 5.38 16.18 0.07
JU-2 CAM7 1795 1800 1.513 0.11 2.31 0.81 2.42 436 0.69 153 54 2.85 7.29 0.05
JU-2 CAM8 1800 1805 1.83 0.33 2.61 1.24 2.94 436 0.59 143 68 2.1 18.06 0.11
JU-3 CAM9 2180 2185 2.2 0.58 3.18 1.16 3.76 439 0.74 145 53 2.74 26.46 0.15
JU-3 CAM10 2250 2253 1.34 0.39 1.69 0.89 2.08 440 0.76 126 66 1.9 29.06 0.19
JU-3 CAM11 2280 2285 1.71 0.53 2.81 1.47 3.34 439 0.74 164 86 1.91 31.13 0.16
JU-3 CAM12 2310 2315 1.21 0.53 1.88 2.72 2.41 435 0.67 155 225 0.69 43.71 0.22
JU-4 CAM13 1665 1670 1.19 0.09 0.68 1.07 0.77 436 0.7 57 90 0.64 7.65 0.12
JU-4 CAM14 1710 1715 1.26 0.09 0.87 1.08 0.96 438 0.72 69 86 0.81 6.9 0.09
JU-4 CAM15 1945 1950 2.29 0.27 3.49 0.78 3.76 441 0.78 153 34 4.47 11.7 0.07
JU-4 CAM16 1975 1980 0.75 0.04 0.36 1.28 0.4 440 0.76 48 171 0.28 5.26 0.1
JU-5 CAM19
4.76 0.2 4.05 1.89 4.25 409 0.54 85 40 2.14 4.17 0.05
JU-5 CAM21
2.34 0.29 2.91 0.73 3.2 418 0.46 124 31 3.99 12.53 0.09
JU-5 CAM26
10.68 0.46 6.18 4.76 6.64 387
58 45 1.3 4.31 0.07
JU-5 CAM22
0.88 0.06 0.33 0.73 0.39 408
37 83 0.45 6.79 0.15
JU-5 CAM27
0.37 0.07 0.16 0.29 0.23 398
44 79 0.55 19.05 0.3
64
Table 3.4: Rock Eval Pyrolysis of the Subathu Fm shales. The measured and calculated Ro values are also given.
Sample ID Location TOC S1 S2 S3 S1+S2 Tmax (°C) Ro HI OI S2/S3 S1/TOC*100 S1/(S1+S2)
SUB1 BRG 42.4 1.81 28.62 0.2 30.43 489 1.64 67 0 143.1 4.2 0.06
SUB2 BRG 4.08 0.08 0.32 0.45 0.4 525 1.65 8 11 0.7 1.9 0.2
SUB3 BRG 3.6 0.11 0.54 0.78 0.65 526 2.3 15 21 0.7 3.03 0.17
SUB4 TTP 6.6 0.11 0.69 1.44 0.8 530 2.38 10 22 0.5 1.7 0.14
SUB5 TTP 18.15 0.41 3.57 0.29 3.97 530 1.24 20 2 12.3 2.2 0.1
SUB6 KLK 3.5 0.2 0.77 1.44 0.97 512 1.16 22 41 0.5 5.74 0.21
SUB7 MHG-M 11.6 0.48 4.25 0.12 4.72 500 1.84 37 1 35.4 4.16 0.1
SUB8 MHG-M 10.4 0.29 2.14 0.28 2.42 517 2.14 21 3 7.6 2.75 0.12
SUB9 MHG-M 7.8 0.36 1.84 0.69 2.19 515 1.6 23 9 2.7 4.53 0.16
SUB10 MHG-M 19.5 0.45 9.19 0.21 9.63 492 1.69 47 1 43.8 2.3 0.05
SUB11 MHG-M 4.7 0.14 1.15 1.37 1.29 503 1.89 24 29 0.8 3.06 0.11
SUB12 CKR 3.2 0.08 0.48 0.05 0.56 501 1.85 15 2 9.6 2.49 0.15
SUB13 CKR 1.27 0.07 0.16 0.1 0.23 502 1.87 13 8 1.6 5.52 0.3
SUB14 CKR 3.85 0.15 0.83 0.18 0.98 495 1.75 22 5 4.6 3.99 0.16
SUB15 CKR 4.8 0.17 0.93 0.04 1.1 486 1.58 19 1 23.3 3.54 0.16
SUB16 CKR 0.75 0.05 0.01 0.2 0.05 423 0.45 1 27 0 6.56 0.83
SUB17 CKR 0.86 0.05 0.03 0.26 0.08 340
3 30 0.1 5.77 0.62
SUB18 SLL 23.23 0.19 1.35 1.68 1.54 540 2.56 6 7 0.8 0.84 0.13
SUB33 MBH1 0.35 0.08 0.21 0.04 0.29 474 1.37 60 11 5.25 22.85 0.27
SUB34 MBH1 0.25 0.08 0.1 0.05 0.18 470 1.3 40 20 2 36.36 0.43
SUB35 MBH1 0.04 0.04 0.03 0.04 0.07 368
75 100 0.75 100 0.57
SUB50 MBH1 0.02 0.04 0.09 0.05 0.13 364
450 250 1.8 200 0.32
SUB49 MBH1 0.4 0.02 0.15 0.04 0.17 496 1.76 38 10 0.13 5 0.11
SUB36 MBH1 0.12 0.1 0.07 0.04 0.17 362
58 33 1.75 83.3 0.58
SUB7 MHG-M 7.25 0.15 4.29 0.02 4.44 515 2.11 59 0 214.5 2.06 0.03
SUB31 MHG-M 2.83 0.02 0.81 0.01 0.83 525 2.29 29
81 0.7 0.03
SUB8 MHG-M 6.12 0.05 2.26 0.01 2.31 530 2.38 37
226 0.81 0.02
SUB55 MNM 15.82 0.45 29.88 0.34 30.33 504 1.91 189 2 87.88 2.84 0.01
SUB48 KHAR 12.84 0.29 7.33 0.08 7.62 536 2.48 57 1 91.6 2.25 0.04
SUB62 BRG 19.14 0.45 16.03 0.02 16.48 501 1.85 84
801.5 2.35 0.03
SUB57 BRG 7.76 0.27 5.32 0.01 5.59 500 1.84 69
532 3.47 0.05
65
SUB6 KLK 2.4 0.11 0.86 0.94 0.97 522 2.23 36 39 0.91 4.58 0.11
SUB44 KLK 1.62 0.02 0.36 0.28 0.38 524 2.27 22 17 1.28 1.23 0.06
SUB61 KLK 9.89 0.69 3.46 0.1 4.15 549 2.72 35 1 34.6 6.97 0.17
SUB72 TTP 0.42 0 0.01 0.02 0.01 563 2.97 2 5 0.5 0 0.25
SUB46 TTP 12.24 0.04 2.99 0.04 3.03 552 2.77 24
74.75 0.32 0.01
SUB5 TTP 12.81 0.03 3.39 0.02 3.42 547 2.68 26
169.5 0.23 0.01
SUB56 TTP 26.65 0.18 15.55 0.18 15.73 520 2.2 58 1 86.38 0.67 0.01
SUB65 TTP 3.65 0.02 0.37 1.13 0.39 580 3.28 10 31 0.32 0.54 0.05
SUB4 TTP 4.83 0.02 0.69 0.77 0.71 570 3.1 14 16 0.89 0.41 0.03
SUB75 TTP 3.11 0.01 0.15 1.98 0.16 492 1.69 5 64 0.07 0.32 0.07
SUB76 CHP-M 1.38 0.01 0.34 0.36 0.35 519 2.18 25 26 0.94 0.72 0.03
SUB58 CHP-M 4.66 0.13 2.32 0.06 2.45 509 2 50 1 38.66 2.78 0.05
SUB53 CHP-M 7.82 0.07 2.24 1.77 2.31 559 3.08 29 23 1.26 0.89 0.03
SUB74 CHP-M 0.26 0.01 0.01 0.48 0.02 540
4 185 0.02 3.84 0.57
SUB66 SLL 9.65 0.03 4.47 0.54 4.5 513 2.07 46 6 8.2 0.31 0.01
SUB68 SLL 17.73 0.21 3.19 2.13 3.4 597 3.58 18 12 1.49 1.18 0.06
SUB73 SLL 0.75 0.03 0.04 0.1 0.07 576 3.2 5 13 0.4 4 0.42
SUB63 SLL 0.32 0.2 0.14 0.05 0.34 325
44 16 2.8 62.5 0.6
SUB54 SKW 11.9 0.09 4.2 5.77 4.29 508 1.98 35 48 0.72 0.75 0.02
SUB60 SKW 17.01 0.1 3.53 7.38 3.63 579 3.26 21 43 0.47 0.58 0.03
SUB67 SKW 16.23 0.38 17.15 0.02 17.53 493 1.71 106
857.5 2.34 0.02
SUB51 SNG 0.02 0.01 0.02 0 0.03 350
0
50 0.27
SUB69 KNT 11.1 0.02 0.46 3.28 0.48 607 3.76 4 30 0.14 0.18 0.04
SUB70 BKL 0.13 0 0 0.04 0 512
0 31 0 0 0
SUB71 RNS 0.79 0.01 0.13 0.8 0.14 523 2.25 16 101 0.16 1.26 0.07
SUB52 KLM 21.87 0.11 5.51 0.53 5.62 557 2.86 25 2 10.4 0.5 0.02
SUB59 MTL 1.47 0.04 0.6 0.29 0.64 493 1.71 41 20 2.06 2.72 0.06
SUB64 CKR 2.68 0.05 0.86 0.01 0.91 511 2.03 32
86 1.86 0.05
66
Borehole Sample ID Depth (m) TOC S1 S2 S3 S1+S2 Tmax (oC) HI OI S2/S3
BBHA A16 5 0.4 0 0.01 0.16 0.01 342 2.5 40 0.062
BBHA A15 6 0.33 0 0.03 0.08 0.03 338 9.09 24 0.37
BBHA A11 14
0.03 0.02 0.03 0.05 334
0.66
BBHA A10 14
0.09 0.07 0.02 0.16 504
3.5
BBHA A9 15
0.01 0.01 0.01 0.02 337
1
BBHA A8 16
0.02 0.01 0.04 0.03 363
0.25
BBHA A7 16
0.02 0.02 0.05 0.04 342
0.4
BBHA A6 16
0.01 0 0.03 0.01 336
0
BBHA A5 17
0.01 0.02 0.08 0.03 338
0.25
BBHA IF9 21
0.01 0 0.4 0.01 333
0
BBHA IF8 22 0.9 0.05 0.05 0.32 0.1 498 5.55 36 0.16
BBHA IF7 24
0.02 0 0.27 0.02 339
0
BBHA IF6 25
0.11 0.08 0.33 0.19 512
0.3
BBHA IF5 30 1.99 0.2 0.34 0.26 0.54 506 17.08 13 1.3
BBHA IF4 31
0.02 0.01 0.39 0.03 342
0.03
BBHA IF3 33 0.9 0.08 0.12 0.3 0.2 517 13.33 33 0.4
BBHA IF2 42
0.02 0.03 0.26 0.05 344
0.12
BBHA IF1 43 0.57 0.02 0.02 0.23 0.04 380 3.5 40 0.09
BBHA A3 46
0.05 0.06 0.16 0.11 371
0.4
BBHA A2 47 0.8 0.02 0.02 0.21 0.04 343 2.5 26 0.1
67
source potential as per the parameters described by Peters (1986) and Peters and Cassa
(1994). The minimum value of TOC was observed in the sample from the Mangrol
Lignite Mine, collected at the depth of c. 150 m from the surface. The S1 values range
from 0.04 – 0.74 mg HC/g rock. The S2 shows an elevated values ranging from 0.16 –
10.11 mg HC/g rock. The total hydrocarbon genetic potential (S1+S2) of the Cambay
Shale samples ranges from fair to good potential, with an average of 2.68 mg HC/g rock.
The hydrocarbon genetic potential of the samples from the shallower depths in four
different wells is poor. The HI ranges from 37 – 220 mg HC/gTOC, with an average
value of 98.95 mgHC/g TOC, suggesting gas generation potential with some samples
(having HI from 150 – 300 mg HC/g TOC) showing both gas and oil generation potential.
The Oxygen Index (OI) shows an average value of 74.71 mg CO2/gTOC. Some of the
samples show abnormally higher OI values, indicating either the oxygen release from
inorganic carbonate or sample weathering. S2/S3 ratios show an average value of 1.80,
Figure 3.1: The source rock quality measurement plot of the Cambay Shale. The TOC values
are plotted against the Hydrocarbon Generation Potential (HCGP) of the Cambay Shale.
68
suggesting the gas prone nature of most of the samples while some samples with S2/S3
ratio more than 3 indicates both gas and oil prone nature (e.g. Peters, 1986). The Tmax
values range from 387°C – 441°C revealing an immature to mature level. Most of the
samples collected from the considerable depths of the wells show higher Tmax values
which suggest early peaking oil generation stage; while the samples from the lignite mine
show very low Tmax values. The measured vitrinite reflectance (Ro) values of five
Cambay Shale samples (Table 3.1) were obtained from the polished surfaces of the whole
rocks and the cuttings. The calculated vitrinite reflectance of the samples was obtained by
using the Tmax data according to the equation; Calculated %Ro = 0.018 × Tmax − 7.16
proposed by Jarvie et al. (2001). The average value of 0.60% of the calculated and
measured vitrinite reflectance suggests that the Cambay Shale samples are in early oil
generation window. These samples show an average 0.11 value of Production Index (PI)
or transformation ratio, indicating the beginning of a considerable amount of oil
generation (Peter, 1986; Hunt, 1996). The maturity of samples increases with depth and
the Tmax versus Depth plot indicates the oil generation window of the analysed samples.
Figure 3.2: The kerogen maturity plot of the Cambay Shale to reconstruct the expulsion
of oil.
69
S1/TOC ratio is used to reconstruct the expulsion of oil from the source rock. In general,
the S1/TOC × 100 ratio between 10 and 20 have been suggested for oil generation
(Smith, 1994; Hunt, 1996). In an ideal condition, S1/TOC ratio increases as the maturity
increases. After expulsion it remains constant and then gradually decreases with
increasing depth and thermal maturity. A plot of S1/TOC × 100 vs. depth (Fig. 3.2) for
the Cambay Shale samples show that the majority of samples are well above the oil
expulsion window of 10 to 20. The samples from the JU-1 well suggests immaturity and
all samples from JU-3 well are mature and outside the threshold of oil generation.
Figure 3.3: TOC map of the Cambay Shale with the TOC values of the samples.
70
The TOC values of the Cambay Shale are indicative of fair to excellent source rock
potential. The distribution of organic matter within the Cambay Basin shown in the TOC
map (Fig.3.3) suggests that the percentage of organic carbon content of the Cambay Shale
increases towards the basinal depressions. The northern part of the basin is organically
richer where the avg. TOC goes above 4 wt. % in Patan – Tharad depression. The
respective HI vs. OI plot on the pseudo van Krevelen diagram (Fig. 3.4) indicates the
predominance of Type III (gas prone) organic matter, whereas the samples from the JU-2
well from the Mehsana–Ahmedabad Block show mixed Type II and III (oil – gas prone)
kerogen. The kerogen type and maturity plot of HI vs. Tmax (Fig. 3.5) suggests the
kerogen Type III and II pertaining to oil generation window. Tmax vs. Depth plot for the
source rock maturity (Fig. 3.6) suggests that most of the samples from the shallower
depth (< 2500m) are in the oil maturation window.
Figure 3.4: Pseudo-van Krevelen plot of the Cambay Shale samples where Hydrogen Index
(HI) values are plotted against Oxygen Index (OI) values.
71
Figure 3.5: Kerogen type and maturity plot of the Cambay Shale samples through
HI and Tmax values.
Figure 3.6: Tmax vs. Depth plot for the source maturity of the Cambay Shale samples.
72
3.2.2.2 Subathu Fm Shale Samples
The Eocene Subathu Fm shales, coaly shales, and coals samples collected from the
boreholes, underground mines and fresh outcrops near Kalakot, Mahogala, Beragua,
Manma, Tattapani, Chakkar, Chapparwari, Salal, Kanthan, Bakkal, Ransoo, Kalimitti,
and Muttal areas show high TOC content with an average value of 7.5 wt. % (Table 3.4).
The TOC distribution diagram (Fig. 3.7) shows high organic richness of the Subathu Fm
shales. The TOC is higher in the shales present in the basal part of the Subathu Fm and
the organic richness diminishes from base to the top in the overlying beds. The RE results
of the samples collected from the two boreholes drilled by Directorate of Geology and
Mining (DGM) at Mahogala (MBH1) and Beragua (BBHA) suggest that the grey shales
from the top of the Subathu Fm are organically very lean and show very low S1, S2 and
HI values. The highly organic rich basal Subathu Fm Shales possess good to excellent
source rock quality (Fig. 3.8). The S1 values range from 0.01 – 1.81 mgHC/g rock and S2
peaks show a wide set of values ranging from 0.03 – 29.88 mgHC/g rock. These shales
have poor to excellent hydrocarbon genetic potential with the values ranging from 0.01 –
30.43 mgHC/g rock. The poor genetic potential is shown by the younger grey and
calcareous shale samples whereas the basal Subathu Fm Shale and coaly shale samples
from Kalakot, Tattapani and Mahogala show good genetic potential. In most of the
Figure 3.7: Graph showing TOC distribution of the Subathu Fm shale samples.
73
Figure 3.8: The source rock quality measurement plot of the Subathu Fm shales.
samples, the HI values is less than 100 mgHC/g TOC, showing an average value of 32.20
mgHC/g TOC which indicate the gas generation potential and only one sample from
Manma section (sample #SUB 55) shows the minor potential for both liquid and gaseous
hydrocarbons generation. The OI values range from 0 – 101 mgCO2/g TOC, except for
the few samples with very low TOC content are showing abnormally high OI values. The
Tmax of the samples ranges from 340°C – 607°C, where the younger grey and calcareous
shale samples are thermally immature and the basal Subathu Fm Shales and coaly shales
with high TOC and Tmax values and low HI values suggesting over maturity phase for
the hydrocarbons (Fig. 3.9). The calculated vitrinite reflectance of the samples ranges
from 1.3 – 3.76 %, except for one sample which shows 0.45 Ro %. These Ro values
indicate over maturity and dry gas generation stage of the samples. S1/TOC × 100 ratio of
most of the Subathu Fm Shale samples is below 10 due to high thermal maturity, which
indicates that these shales could generate gas (Hunt, 1996).
The Subathu Fm shales show fair to excellent source rock quality (Fig. 3.8) and
most of the basal Subathu Fm Shale samples are organically very rich. The pseudo van
Krevelen diagram indicates that the organic matter is dominated by Type III kerogen (Fig.
3.10).
74
HI
Figure 3.9: Kerogen type and maturity plot of the Subathu Fm shale samples.
Figure 3.10: Pseudo-van Krevelen plot of the Subathu Fm shale samples.
75
versus Tmax plot for the determination of kerogen type and maturity indicates that most of
the Subathu Fm Shale samples are over mature and plot in the dry gas window (Fig. 3.9).
3.2.3 Discussion
The Eocene Cambay Shale is a laterally extensive, organic rich source rock in the
Cambay Basin, with fair to excellent source rock quality, suggesting an excellent
hydrocarbon generation potential. It is observed that the TOC wt. percent of the Cambay
Shale increases towards the basinal depressions (Fig. 3.3) and is maximum in the Pattan –
Tharad depression in the northern part of the basin. This increase in the organic richness is
attributed to the sedimentary facies changes as a result of marine transgression. However, the
sedimentation and depositional trends within the basin were largely controlled by the NW-SE
trending rift faults, leading to the thickness variation in the Cambay Shale. The TOC
percentage decreases towards the basin margins where the Cambay Shale turns shallow and
shows the drastic reduction in the thickness pattern by pinching towards the margin and
henceforth becomes absent. This decrease is due to the change of lithofacies with fluctuating
depositional environment ranging from marshy (brackish) to deltaic condition. According to
the Rock Eval Pyrolysis data, the Cambay Shale is dominated by Type III kerogen,
containing gas prone land derived organic matter. The Ahmedabad – Mehsana depression
shows the significant percentage of the Type II kerogen, dominated by foraminifera,
dinoflagellates and other phytoplanktons and deposited in the reducing environment
conducive for the source rock accumulation (Strat Chart III in the back leaf). The high
variability in the HI values of the analysed samples can be attributed to the variation in
organic facies along the analysed sections. HI versus Tmax plot for the determination of
kerogen type and maturity seems to be more accurate as compared to the HI versus OI,
because OI values of the samples containing carbonate minerals can be influenced by
inorganic carbon. The high OI value can also be attributed to weathering of the samples. HI
versus Tmax plot again suggests the dominance of Type III kerogen with few samples
showing the presence of both Type III and II kerogen (Fig. 3.11).
76
The Cambay Shale is in oil generation window, as evidenced by the RE and measured
and calculated Ro data. The samples from the Mangrol Lignite Mine in the Narmada Block
are immature but show good hydrocarbon generation potential. The low thermal maturity can
be attributed to the shallowness of these shale samples towards the basin margin. The
samples from the four wells are from the structural highs; therefore these are still in
Figure 3.11: Source rock kerogen type map of the Cambay Shale.
77
the oil generation window. The Cambay Shale present at greater depth in the basinal
depressions shows higher thermal maturity and indicates wet gas/condensate to dry gas
generation stage (Banerjee et al., 2000) (Fig. 3.12). The thermal maturation map of the
Cambay Basin based on the Ro values indicates that the maturity of the Cambay Shale
increase towards the depressions and the Ro value reaches up to 2 % (dry gas generation
window) in the Broach Depression towards the southern part of the basin. The high
Figure 3.12: The Vitrinite Reflectance (Ro) map of the Cambay Shale.
78
maturation of the Cambay Shale is driven by high thermal gradient and high heat flow in the
region (Majumdar and Nasipuri, 2008) (Fig. 2.5). The crustal stretching during the basin
extension led to the mantle upwarping which corresponds to the high heat flow in the basin.
This provided the additional favourable geological setting for the source rock maturation and
hydrocarbon generation. The Production Index (PI) versus Tmax plot (Fig. 3.13) suggests
that some of the samples are in oil generation window. The samples from JU-1 and JU-2
wells show low S1 values and therefore show low transformation ratios within these samples.
The high organic richness and moderate HI values of the Cambay Shale reflect characteristics
of organic facies type BC and C determined by Jones (1987). This suggests the deposition of
this formation in marginal marine to deltaic dysoxic to anoxic bottom water condition. The
S1/TOC × 100 values of the Cambay Shale increase with depth and thermal maturity
assuming no facies change and majority of samples are well outside the threshold zone of oil
expulsion.
The Subathu Fm shales are characterised as organic rich source rocks with good
hydrocarbon generation potential. The organic matter in these shales is dominated by gas
prone Type III kerogen with the preponderance of vitrinite and inertinite matching with the
Figure 3.13: Production Index vs. Maturity plot of the Cambay Shale
79
organic facies type C. Since these shales contain the terrestrially derived organic matter
which is hydrogen poor, the HI values in these shales are low indicating gas generation
potential. The thermal maturity assessed from Tmax and measured and calculated vitrinite
reflectance shows the post mature stage of organic matter. These values reveal that the basal
Subathu Fm shales are in the dry gas generation window. The younger grey and calcareous
shales show an immature stage of the organic matter. Also, these samples are organically
lean, the Tmax value can be anomalous due to very low S2 peak. The higher maturation of
these shales can be attributed to the skin frictional heat generated due the tectonic
deformation along the thrusted contact. The higher geothermal gradient observed in the
drilled wells (or bore holes) show the range of 1.86°C – 1.98°C/100m. This can be another
possible reason for the thermal maturation of the source rocks of Subathu Fm which is or was
under the sediment overburden of c. 3 kms (Mittal et al., 2006). The thermal maturity of the
shales from Mahogala and Beragua areas is also low as compared to the Subathu Fm shales
from other places of Jammu region (Fig-Map). The HI vs. Tmax plot also depicts the dry gas
generation stage of the Type III kerogen. The facies studies of the basal Subathu Fm
suggests that these rocks were deposited in close proximity to the source (e.g. swamp forest)
in paralic/paludal, strandline marginal marine conditions on the platform margin of the
northward moving Indian Plate (See the VKA_Ro Chapter). The rest of the sequence was
deposited in an intra-shelf lagoonal to fully continental depositional conditions.
80
3.3 Gas Chromatography
3.3.1 Introduction
Biomarkers are molecular fossils derived from formerly organisms which were
buried alongwith the sediments. The structure of these molecules show no or minor
alteration during diagenesis, but their carbon skeleton is preserved and can be traced back
to their precursor compounds in modern-day or extinct organisms (Tissot and Welte,
1984; Killops and Killops, 1993). They are chemically complex organic compounds
present in both oils and source rocks extracts and are composed of carbon, hydrogen with
other elements like oxygen, sulphur and nitrogen. The biomarker studies have been
extensively used in organic geochemistry to ascertain the valuable information regarding
the age and thermal maturity of the source rock. These can provide the essential
information regarding the description, correlation, and recognition of the nature and
habitat of the ancient organisms which can facilitate in the reconstruction of the
depositional environment of the ancient sediments and crude oils. It helps in determining
the source of organic matter in oils and their source rocks and is also good indicator of the
degree of biodegradation. Hundreds of biological markers have been found in crude oils
and sediments and most of them are derived from steroids, cyclic and acyclic terpenoids
(Tissot and Welte, 1984).
In the current study, petroleum geochemical analysis was carried out by Gas
Chromatography – Flame Ionization Detection (GC – FID) method on the Cambay Shale
and Subathu Fm shales for the detailed investigation of the acyclic isoprenoid alkanes.
This analysis was performed to get the basic organic geochemical parameters concerning
the source and maturity of organic matter in the selected source rock samples and their
depositional environment.
3.3.2 Sample Preparation and Methodology
Gas Chromatography – Flame Ionization Detection (GC – FID) technique is used
for the qualitative and quantitative analysis of hydrocarbon molecules which are
separated in the column of gas chromatograph. The analysis was performed at Gas
Chromatography Laboratory in Energy and Geoscience Institute (EGI), University of
Utah, Salt Lake City, USA.
81
3.3.2.1 Sample Preparation
GC – FID analysis was performed on the eight shale samples (five Cambay and
three Subathu Fm samples) (Appendix B), which were extracted using a Soxhlet
Apparatus. The sediments were loaded into coarse porous alundum thimbles and
extracted with dichloromethane (DCM) organic solvent for 18 hours. The condensers
were connected in series to a Brinkman water circulator that was set to -5°C. After
extraction, the solvent was recovered under vacuum with an automated Buchi rotary
evaporator apparatus, utilizing Brinkman water circulator for cold condenser. Residual
solvent was removed under a stream of nitrogen. The procedure which was followed for
Soxhlet extraction is given below:
1) Crush the source rock sample into small pieces using a porcelain mortar and pestle.
2) Put the rock chips into the rock grinder until fine powder is obtained (be sure to
clean the grinder between samples with sand).
3) Remove the rock powder from the grinder and place in an alundum extraction
thimble (be sure the thimble is clean and is stored in dessicator). This transfer is
easily performed using a clean piece of paper which can be rolled to fit the
diameter of thimble.
4) Record the weight of the rock powder (Appendix B).
5) Fill a 500 ml round bottom flask with approximately 300 ml DCM.
6) Place thimble with rock powder in Soxhlet apparatus (use long forceps) and place
the base of the Soxhlet into the round bottom flask.
7) Attach entire assembly to the base of a condenser (located in the fumehood).
8) Set chiller to -5°C (1/2 hour prior to starting the extraction).
9) Turn on heating mantle (set at 3.5) and allow extracting for 24 hours.
10) After extraction rotovap the extracts (the excess of extract is evaporated using
rotary evaporator) and transfer to tarred vials.
82
3.3.2.2 Gas Chromatography – Flame Ionization Detection (GC – FID)
The sediment extracts were analysed using an Agilent 6890 gas chromatograph
equipped with a Flame Ionization Detector (a carbon specific detector). The samples
were diluted in DCM. Split injection (30:1) was employed at 300°C injection port
temperature (detector temperature = 350°C) onto a non-polar RestekTM
column (30m x
®-1). The GC column temperature was programmed from 35°C
(2 minutes isothermal) to 310°C at 4°C/minute using helium as the carrier gas. Auto
samplers (Agilent 7673 series) were used to increase efficiency and achieve reproducible
results. Data were collected and processed with Agilent ChemStation software. The
produced chromatogram shows the time along the X-axis and the Y-axis represents the
signal intensity.
3.3.3 Results and Discussions
Gas chromatograms obtained after the GC – FID analysis for the saturate fractions
of the Cambay and Subathu Fm samples are shown in the Appendices C and D. The main
compounds from GC – FID data that are of interest are pristane and phytane.
Pristane and phytane are the most common acyclic saturated isoprenoid isoalkanes.
The most common source of these isoprenoids is the phytol the side chain of chlorophyll-
a, which occurs in photosynthetic organisms. (Treibs, 1934; Peters and Moldowan,
1993). They are also derived from bacteriochlorophyll a and b of purple sulphur bacteria
(Brooks et al., 1969; Powell and McKirdy, 1973), tocopherols and chromans (Goossens et
al., 1984; ten Haven et al., 1987; Li et al., 1995). Risatti et al. (1984) have found
archaebacteria as another source of phytane. The pristane (i-C19) and phytane (i-C20) are
extensively used as the tentative guide for the redox condition of depositional
environment. Under the anoxic environmental condition, phytol is hydrogenated into
dihydrophytol and then subsequently into phytane (Fig. 3.14). The oxidation of phytane
converts phytol into phytenic acid under oxic depositional conditions which is further
transformed by carboxylation and reduction into pristane on thermal diagenesis
(Eglington and Calvin, 1967; Cox et al., 1972; Maxwell et al., 1972 and 1973; Didyk et
al., 1978). Pristane and phytane are found predominantly in anoxic environment and their
ratio tends to increase with the increased influence of terrestrial organic matter.
Pristane/phytane (Pr/Ph) ratio is high in oxic environments such as peat swamps and low
in strongly reducing environments such as marine or brackish water (Powell and
83
McKirdy, 1973). Since phytane is unstable at higher temperature, the Pr/Ph ratio will
increase with the increasing thermal maturation. Their high ratio also reflects the
relationship between the contributing organic matter and chemistry of the environment
(Mello and Maxwell, 1990). The Pr/Ph ratio less than unity are an indication of anoxic
depositional environment in carbonate, lacustrine or brackish setting particularly when
associated with high sulphur content. The ratio > 1 indicate alternating oxic, and anoxic
conditions, whereas the ratio above 3 indicate the deposition of organic matter in oxic
environment with the large amount of terrestrial inputs (Powell and McKirdy, 1973;
Didyk et al., 1978; Hughes et al., 1995). The Pr/Ph ratio is dependent on both source and
maturity of organic matter, therefore great caution should be taken before using this
parameter for assessing the palaeodepositional environment of the source rocks.
Pristane/n-heptadecane (n-C17) vs. Phytane/n-octadecane (n-C18) ratios provides the
valuable information regarding the source material type, depositional environment,
maturity and biodegradation (Connon and Cassou, 1980; Peters et al., 1999; Arfaoui and
Figure 3.14: Scheme showing the conversion of phytol to pristane and phytane (after Didyk
et al., 1978)
84
Montacer, 2007). Since the isoprenoids are thermally unstable, their values decrease with
the increasing maturity. Therefore, the low ratio of pristane/n-C17 and phytane/n-C18 also
indicate high thermal maturity. Lijmbach (1975) suggested that the high Pr/ n-C17 (>1)
ratio indicate the terrigenous higher plants as the source of organic matter deposited in
swampy environmental condition. The care need to be taken before using this parameter
as the ratio is also affected by the bacterial biodegradation of n-alkanes before
isoprenoids.
The results for the analysed Cambay Shale and Subathu Fm samples used for
maturity and depositional environment indications are given in the Appendix C and the
representative chromatograms of the aliphatic and acyclic isoprenoid hydrocarbons are
shown in Appendix D.
The Subathu Fm shale samples show the erroneous results. The chromatograms of
these samples do not correlate with the standard chromatogram of the non-biodegraded
oil sample. This suggests that the samples are contaminated with some chemicals and
plastics and are highly biodegradable. Therefore, the Pr/Ph ratios of these samples were
not ascertained.
Pristane and phytane occur in high concentration in all the Cambay sample extracts
(Fig. 3.15 and Table 3.5). The Pr/Ph ratio of the samples (CAM 3, CAM 7 and CAM 13)
from three different wells shows very high values. This indicates that the samples were
deposited in the non-marine oxic depositional environment. The high ratio can be
attributed to the abundance of terrestrially derived Type III kerogen in these samples
which generally tend to increase the Pr/Py ratio. Another possible reason can be the
higher thermal and geochemical alteration of the organic facies at the greater depth and
increases the Pr/Ph ratio. Since phytane is unstable at higher temperature, the increasing
thermal maturity has the tendency to significantly modify the Pr/Ph ratio of mostly Type
III kerogen close the oil window maturation level.
The Mangrol Lignite Mine samples (CAM 19 and CAM 21) show the ratio <1,
indicating that these samples were deposited in strongly reducing environment in brackish
water condition and also suggests immaturity. These samples show the presence of
liptinite and other marine derived macerals in abundance (see Table 3.2). Under this
environmental condition, the salinity of the water increases which develops the
environment conducive for the growth of archaebacteria which contain a major source of
85
Sample ID Pr/Ph Pr/n-C17 Ph/n-C18
CAM3 Area 6.23 3.92 0.77
CAM7 Area 7.35 0.82 0.17
CAM13 Area 7.05 1.76 0.37
CAM19 Area 0.58 9.93 13.45
CAM21 Area 0.44 8.61 18.69
CAM3 Height 6.94 3.56 0.54
CAM7 Height 7.08 0.72 0.12
CAM13 Height 6.85 1.58 0.27
CAM19 Height 0.63 9.09 9.07
CAM21 Height 0.46 7.6 13.8
phytane (Mello and Maxwell,
1990). Therefore the increase in
salinity might have increased the
concentration of phytane
precursors in the restricted
depositional environment of the
sediments along the basin
margin.
The ratio of pristane and
phytane relative to the adjacent n-
alkanes were plotted in a
logarithmic plot initially proposed by Lijmbach (1975) and developed by others given by
others (Fig. 3.15). The Pr/n-C17 to Py/n-C18 ratios are variably ranging from 0.82-9.93 and
0.37-18.61 respectively. The Pr/n-C17 ratio suggests the terrestrial source (Type III
kerogen) of organic matter deposited in the shales. The plot suggests that the samples
from the wells are thermally mature and indicates the higher oxygen content in bottom
Figure 3.15: Plot showing the Pr/n-C17 to Py/n-C18 ratios of the Cambay Shale
samples.
Table 3.5: Pristane Phytane (Pr/Ph) ratios of the
Cambay Shale samples
86
waters during their deposition. The other samples from the Lignite Mine indicate the
deposition in reducing environment. These samples show higher relative concentration of
the pristane and phytane isoprenoids to the adjacent n-alkanes, suggesting biological
degradation (Connan et al., 1980).
3.3.3.1 Biodegradation
Biodegradation is the effect on the petroleum and source rocks due to bacterial
activity where the lighter molecular weight hydrocarbons are eaten up by the bacteria.
The n-alkanes are unstable and are highly susceptible to the biodegradation than the more
resistant isoprenoids. Due to the degradation of normal hydrocarbons (n-C17 and n-C18),
the more resistant isoprenoids are conserved leading to the relative increase in Pr/n-C17 to
Py/n-C18 ratios.
The samples from Mangrol Lignite Mine show the evidence of biodegradation and
this can been seen on the GC-FID chromatograms (Appendix D). The higher ratios of
Pr/n-C17 to Py/n-C18 of these samples correspond to very high degree of biodegradation.
The samples from the wells show very little bacterial effect. The preferential degradation
of the normal hydrocarbons (n-alkanes) over isoprenoids of the Mangrol Lignite Mine
samples is illustrated in chromatograms.
87
3.4 Bulk Chemical Composition and Isotopic Geochemical Analysis of Gas Seeps
3.4.1 Introduction
Numerous gas seeps have been reported in the northwestern Himalayan Foreland
Basin and Fold-Thrust Belt. The streams of gas seeps in the Chenab River bed have also
been seen on the northern side of the Riasi Inlier near Kanthan village, where the Chenab
River veers its course and forms a drainage anomaly along the back-thrusted contact
between the Subathu Fm and the Sirban Limestone Fm (Fig. 3.16). Atleast 20 individual
seeps were seen in the river where the gas streams were found rising from a discrete holes
within the muddy river-bed. The gas may be emanating from the nearby source and
reaching the surface through fault conduits and fractured networks in the underlying
bedrock. The gas seep samples were collected from the river bed and analysed for bulk
chemical composition and carbon isotopic studies.
The carbon isotopic study of the hydrocarbon gases have been widely used to
understand the origin of the gas seeps and potential sources (Stahl, 1974 and 1977; Tissot
Figure 3.16: A). General geology around gas seep site; B) collection of gas samples; C) The
combustibility of gas being checked.
88
and Welte, 1978; Schoell, 1980 and 1983; Mettavelli et al., 1983; Whiticar et al., 1986;
Whiticar, 1999). Natural hydrocarbon gas is produced by two distinct processes; either
biogenic or thermogenic degradation of organic matter. Biogenic (also called microbial)
gas is formed in shallow, swampy areas and in immature sediments and is generated at
temperatures less than 75°C. This gas is composed of isotope depleted methane (δ13
C
generally less than –60‰) and is characterised by low concentration of ethane and higher
hydrocarbons. Thermogenic gas is produced by thermal cracking of sedimentary organic
matter into hydrocarbon liquids and gas at higher temperatures and increasing burial. This
type of gas is mostly composed of isotopically heavier methane and are characterised by
higher hydrocarbons. The thermogenic hydrocarbon gas seeps are the direct indicators of
the possibility of the presence of hydrocarbons at depth and their isotopic signatures can
help in understanding their source and maturity.
3.4.2 Methodology
3.4.2.1 Sampling
The gas seep samples were collected from the Chenab River bed by filling the
sample bottles with water. The water filled bottles were then inverted in the water column
above the gas bubble streams, allowing the collected gas to displace the water. Once the
sampling bottles were full with gas, they were capped underwater and taken to the labs
for composition and isotopic analyses. The combustibility of the gas collected was
checked on site (Fig. 3.16). The samples were analysed at eni GEBA laboratory in Milan
and also in the NGRI laboratory in Hyderabad, India.
3.4.2.2 Analytical Procedure
The gas seep samples were analysed for CH4, CO2 and N2, using a Varian CP-3380
gas chromatograph (GC) equipped with a Porapak ‘Q’ column and flame ionization
detector (FID). The column oven was programmed at 60°C for 3 minutes and the
temperature was increased to 120°C at the rate of 20°C per minute and kept for 18
minutes with a total time of 24 minutes. Nitrogen was used as carrier gas and the flow
rate of 30 ml/minute was maintained. The fuel gases were hydrogen and zero air with a
flow of 300 ml/minute. The temperature of the injector and detector was kept at 120°C
and 200°C respectively. Star Workstation software was used for data acquisition and the
89
gas chromatographic calibration was performed by using an external standard with its
peak area as a basis for conversion to concentration with corrections for moisture applied.
Stable carbon isotopes (δ13
C) of methane and carbon dioxide were carried out using
Gas Chromatography–Combustion-Isotope Ratio Mass Spectrometry (GC–C-IRMS). An
Agilent 6890 GC attached to a Finnigan- Delta PlusXP IRMS via a GC combustion III
interface was used for the carbon isotope analysis. One ml of the sampled gas was
injected into the Agilent 6890 GC, equipped with “Pora Plot Q” capillary column. The
instrument uses helium as carrier gas at a fixed oven temperature of 28°C. The GC–C-
IRMS results were calibrated using Natural Gas Standard (NGS-1) mixture and reported
to the Vienna PeeDee Belemnite (VPDB). The stable carbon isotopic results are
expressed in delta (δ) notation, which depict the deviation of the 13
C/12
C ratio in parts per
thousand (per mil or ‰) relative to the VPDB standard.
3.4.3 Results and Discussion
The results of the gas samples analysis indicate that the gas is comprised of air and
other gases, which include methane (16.2 %), nitrogen (83.2%) and Carbon dioxide
(0.6%). The bulk composition shows that the gas is significantly contaminated by
atmospheric air during the sampling. The data given above were rescaled to 100% after
removal of atmospheric oxygen and related nitrogen. The nitrogen composition is
correlatable and very close to atmospheric nitrogen.
The stable carbon isotope (δ13
C) of methane of one sample (KA1) shows the value
of –62.40‰ and in other samples, the values range from –50.26 to –51.46‰. The δ D
(hydrogen stable isotope) methane value is around –182.0‰ and that of δ13
C CO2 ranges
between –29.7 to –24.9‰.
Two types of gases are distinguished in the analysed samples after the isotopic
studies; biogenic gas, which is characterised by δ13
C value of methane less than –60‰.
The other type is mixed gas where δ13
C value of methane ranges between –60 to –50‰.
The classical Schoell’s plots (Schoell, 1983) (Fig. 3.17) have been used to distinguish
between the biogenic and thermogenic sourced gases. The carbon isotopic composition of
methane is plotted against the total percentage of methane and the results show that KA1
sample contains methane of clear, unquestionable biogenic origin. The other two samples
show shallow mixed source of origin. Another Schoell’s plot (Fig. 3.18) where carbon
90
isotopic composition of methane is plotted against the hydrogen isotopic composition of
methane and this plot also show clear evidence of biogenic origin of KA1 sample and
mixed nature of other two gas samples.
The diagram put forth by Whiticar (1999) (Fig. 3.19) has been used to understand
the nature and source of methane. The carbon and hydrogen isotopic signatures have been
plotted together to find out the source of gas. The results show that the bacterial carbonate
reduction appears to be the most likely mechanism of formation of methane of biogenic
origin. The other two samples suggest mixed type (both biogenic and thermogenic) of
gas.
Figure 3.17: Schoell’s diagram plotting carbon isotopic composition of methane is plotted
against the total percentage of methane.
91
The biogenic gas is dry and produced from the shallow source. The gas is
characterized by low (light) δ13
C methane values, low carbon dioxide and high nitrogen
values. This gas is most likely originated from the bacterial carbonate reduction process
in the underlying shallow source rocks. The relatively higher δ13
C methane values
indicate the occurrence of mixed gas which is the mixture of dry thermogenic and
biogenic gases. The organic matter rich Subathu Fm Shales which are present at the
shallower depth are considered to be the primary source of these gases. The gas seepage
from the shales in all probabilities has been made possible due to the natural fracturing of
the shales, thus interconnecting the pores. The fracturing of the shales is concomitant with
the prevalence of faults and thrusts in the region which may have produced passages for
gas seeps to reach the surface.
Figure 3.18: Schoell’s Plot plotting carbon isotopic composition of methane against the
hydrogen isotopic composition of methane.
92
Figure 3.19: Whiticar’s Plot plotting carbon isotopic composition of methane against the
hydrogen isotopic composition of methane.
93
CHAPTER 4
PETROPHYSICS
94
PETROPHYSICS
This chapter attempts to do petrophysical characterisation of the Cambay Shale and
Subathu Fm shales though XRD, SEM and QEMSCAN analyses. These analyses are
performed to evaluate the reservoir characteristics of the target shales.
4.1 X-ray Diffraction Analysis
4.1.1 Introduction
After the discovery of X-rays in 1895, scientists have been able to examine
crystalline structure at the atomic level. The reason of using X-rays for obtaining
information about the internal lattice of crystalline substances is that the X-rays
wavelength and the structural spacings of crystals both have similar dimensions of about
10-8
cm (10-8
cm = 1 Angstrom, Å). X-rays can be used to determine the size and shape of
the unit cell of any compound.
The X-ray Diffraction (XRD) is the most common technique which has been
extensively used for the identification and quantification of any crystalline substances and
to determine the mineralogy of rocks, especially finer grained clay sediments. This
method helps in investigating qualitatively and quantitatively the composition of the rock
minerals and also provides the structural and chemical details of the very fine natured
minerals, for example clay minerals which are less than 2 μm in diameter. XRD technique
provides the data very quickly and the small amount of sample is required to perform the
analysis. With the advent of Terra XRD portable machine, the identification and
quantification of the minerals can be performed in the field.
4.1.2 Principle of Diffraction
When an X-ray beam, which is produced due to the bombardment of a metal target
(usually Cu) with a beam of electrons emitted from a hot filament (usually tungsten),
penetrates a crystal, a diffracted beam is produced due to the constructive interference of
the mutually reinforcing rays. The contact between the incident X-ray beam and the
crystals in the sample produce intense reflected X-rays by constructive interference when
conditions satisfy Bragg’s Law.
W.H. Bragg (father) and William Lawrence Bragg (son) at the beginning of 20th
Century developed a simple relation for scattering angles, expressed by the equation nλ =
95
2d Sinθ, called the Bragg’s Law. This law describes the general relationship between the
wavelength of the incident X-rays (λ), the angle of both incident and reflected beam with
the given atomic plane (θ) and the spacing between the crystal lattice planes of atoms (d).
4.1.3 Methodology
Whole-rock and clay X-ray Diffraction (XRD) analyses were performed on each
sample in the XRD laboratory at the Energy and Geoscience Institute at the University of
Utah (USA), using a Bruker D8 Advance X-ray diffactometer and the Terra XRD
portable machine by InXitu. Some of the samples were also analysed at Sophisticated
Analytical Instrumentation Facility (SAIF) at Panjab University Chandigarh (India),
where the PANalytical X’pert Powder was used for the powder diffraction. Phase
quantification using the Rietveld method was performed using TOPAS software,
developed by Bruker AXS. The Rietveld method fits the peak intensities calculated from
a model of the crystalline structure to the observed X-ray powder pattern by a least
squares refinement. This is done by varying the parameters of the crystal structures and of
the peak profiles to minimize the difference between the observed and calculated powder
patterns. Because the whole powder pattern is taken into consideration, problems of peak
overlap are minimized and accurate quantitative analyses can be obtained.
The sample preparation is simple for the analysis performed by using Terra InXitu
XRD portable machine and PANalytical X’pert Pro machine. The fine powdered sample
(c. 15 mg) ground to 100 mesh size is loaded in the sample holding device in the InXitu
machine, where the vibration of the chamber keeps the sample moving so as to get
different orientations of the crystal structure to the instrument optics. In Terra InXitu
machine, Cu-K-α radiation (λ = 1.5406 Å) is used with 30 kV voltage of the XRD tube
and is equipped with charge coupled device (CCD) camera. The samples were analysed in
the XRD range from 5 to 55o2θ. In PANalytical X’pert Pro machine, Cu-K-α at 45 kV
and 40 mA filtered with Johansson monochromator radiation is used. The samples in this
machine were examined in the XRD range from 5 to 65 o2θ.
The following operating parameters were used when analyzing the powdered
samples in Bruker D8 Advance X-ray diffactometer: Cu-K-α radiation at 40 kV and 40
mA, 0.02o
2θ step size, and 0.4 and 0.6 seconds per step, for clay and bulk samples
respectively. Clay samples were examined from 2 to 45o
2θ, and the bulk samples from 4
to 65o2θ. The instrument is equipped with a lynx eye detector which collects data over 2.6
96
mm, rather than at a point, greatly increasing X-ray counts collected and decreasing
acquisition time; a rotating sample stage which increases the mineral grain orientations
encountered by the incident electron beam; and an automated sample exchanger capable
of holding up to 90 samples.
At a minimum, three analyses were conducted on each sample, two or more of the
clay-sized fraction and a bulk sample.
4.2.3.1 Sample Preparation
The clay sized fraction is prepared as follows:
Samples are first ground in an electric mortar and pestle.
The resulting powder is mixed with deionized water and further ground in a
micronizing mill until fine enough to pass through a 325 mesh screen (particle
size < 44 micrometers).
The less than 2 micrometer size fraction is then separated using Stokes Law by
placing the resulting slurry in a beaker (with a small amount dispersant) and
vigorously stirring. After allowing it to settle for 37 minutes an aliquot (~100 ml)
is pipetted out of the top ½ inch or so.
The particles are removed from the water column by centrifuging for 15 min at
1500 rpm.
The bulk of the clean water is decanted, and the sample is thoroughly mixed using
an ultra-sonic homogenizer.
The slurry is then applied to a glass slide using a pipette.
Once the sample has dried an ‘air dried’ XRD pattern is obtained.
The sample is then allowed to interact with ethylene glycol vapors for at least 12
hours at 65oC to induce swelling of susceptible clays, after which an additional
‘glycolated’ XRD pattern is obtained.
Additional heat treatments and scans that involve heating for 1 hour at 375 and/or
550oC may be required to confirm the presence of some clay species.
The fraction used for the bulk analysis is prepared as follows:
97
Samples are first ground in an electric mortar and pestle.
The resulting powder is mixed with deionized water and further ground in a
micronizing mill until fine enough to pass through a 325 mesh screen (particle
size < 44 micrometers).
The sample is then rolled approximately 50 times to randomly orient the mineral
grains before being scanned.
The powder is placed in a sample holder which has concentric ridges in the
bottom to help decrease the effects of preferred orientation.
The surface is smoothed with a razor blade to eliminate surface roughness
The air-dried, glycolated and heated scans of the clay-sized fraction are compared
with each other to identify the clay minerals present in the sample, using methods
described by Moore and Reynolds (1997). The mineralogy of the clay fraction is then
used in the Rietveld refinement of the bulk sample to quantify the abundances of all
crystalline phases that are present.
27 samples of Cambay Shale from four different wells and Mangrol Lignite Mine of
the Cambay Basin were analysed using the XRD method to measure the mineralogical
composition of shale samples. 63 Subathu Fm samples from two boreholes, underground
mines and fresh outcrops were also analysed for bulk mineralogy (Appendix A). Most of
the samples analysed were the basal Subathu shales, while the borehole core samples
constituted the samples from the complete Subathu Fm. The summary of all XRD data is
listed in Appendix E and the raw data can be viewed in Appendix F. The XRD patterns of
the 17 analysed samples from borehole BBHA are combined into one plot to show the
mineralogical changes throughout the section (Appendix G).
4.1.4 Bulk XRD Analytical Results
4.1.4.1 Cambay Shale
Clays form the major constituents of the Cambay Shale samples. Based on the data
generated through XRD, while highly variable among samples the most abundant
minerals of Cambay Shale are kaolinite, illite and quartz with average content of over 33
wt. %, 15 wt. % and 11 wt. %, respectively (Fig. 4.1 and 4.2). Chlorite group minerals,
98
feldspars, and pyrite are next in abundance. Other minerals which include
Figure 4.1: Pie plot showing the average mineral composition of the Cambay Shale samples.
Figure 4.2: Average mineral composition of the Cambay Shale along with standard
deviation
99
montmorillonite, gypsum, calcite and siderite minerals are present in minor amounts. The
minerals identified are described in detail below:
Clay Minerals
Clay minerals, the part of the phyllosilicates, are formed of small hydrous layer
silicates. These are one of the main components of the shale and mudstones and have
been used worldwide for targeting the hydrocarbons. Clay minerals are widely used to
understand the source rock quality of organic rich shales and mudstones (Grim, 1947;
Brooks, 1952), where these minerals act as the catalysts to help the thermal breakdown of
organic matter into liquid and gaseous hydrocarbons (Johns, 1979; Goldstein, 1983).
Kaolinite mineral as described by Murray (1991 and 1999) is theoretically formed
of 39.8% alumina, 46.3% silica and 13.9% water and represents simplest 1:1 type two-
layer crystal (silica tetrahedral layer joined to alumina octahedral sheet in each repeating
layer) arrangement. This mineral belongs to the kaolin group which also include dickite,
nacrite and the hydrated analogous, halloysite. It is the most abundant mineral and is
present in all the samples of the Cambay Shale. The values range from 6 to 60 wt. % and
produces the basal reflection sharp peaks at 12.35o
2θ (001) and 24.85o
2θ (002). The
samples from JU-2 well show high kaolinite content, where the value goes above 60 wt.
% in CAM 6, whereas its percentage is less in the samples from JU-3 well and Mangrol
Lignite Mine (JU-5). JU-3 samples are from the depth of more than 2000 m, therefore
some of the bookish kaolinite might have transformed into blocky dickite due to burial
diagenesis (Ehrenberg et al., 1993, Bjorlykke, 1998, Beaufort et al., 1998; Ruiz Cruz and
Reyes, 1998) or local heating due to the tectonics or magmatic intrusions (Parnell et al.,
2000). Kaolinite and dickite have essentially the same XRD patterns with extremely
subtle differences and it is very difficult to identify the correct peak to distinguish the two
minerals and calculate their relative percentages. On that account, these peaks are
mineralogically classified and written as kaolinite. Dickite is stable polytype at the greater
depth of burial (Zotov et al., 1998; Lanson et al., 2002) and does not form exclusively
due to the thermal alteration of kaolinite. The dissolution of K-feldspar and other alumina
rich silicates due to the thermal alteration can also lead to the formation of coarse and
blocky dickite (Lanson et al., 2002).
Illite is a fibrous, mica type mineral and is quite different from kaolin group
minerals. It is potassium rich and represents the 2:1 structural arrangement where the
aluminium octahedral sheet is sandwiched between two silica tetrahedron sheets. The
mineral is non-expandable due to the strong ionic bonding given by potassium cations.
100
The Cambay Shale samples show the good percentage of illite mineral, ranging from 4 to
30 wt. % with an average value of 15 wt. %. The maximum value is that of a sample
CAM8, from JU-2 well. Illite forms the peaks at 8.7o
2θ (001), 17.52o
2θ, 20.03o
2θ and
26.58o
2θ. It is formed by the thermal transformation of feldspar, micas and smectite
(Birkeland, 1984; Nesbitt and Young, 1989). The diffusion of K from K-feldspar can also
lead to the transformation of kaolinite into illite at depth greater than 4 km (120 – 130oC)
(Bjorlykke, 1998). The illitization of kaolinite generally occurs after the illitization of the
smectite mineral present in the shale (Ruiz Cruz and Andreo, 1996). Smectite alter into
mixed-layer illite/smectite (I/S) due to thermal diagenesis and the reaction continues to
form illite (Perry and Hower, 1972; Hower et al., 1976).
Chamosite is another abundant clay mineral in the Cambay Shale samples. It is the
hydrous ferrous silicate and belongs to the chlorite group. It is the non-expansive mineral
and shows the 2:1 structural arrangement. The average weight percentage of chamosite in
the Cambay Shale samples is 7 wt. % and peaks occur at 6.26o 2θ (001) and 35.1
o 2θ. Few
samples also show the presence of some chlorite.
Montmorillonite, the dioctahedral smectite, shows the 2:1 structural arrangement
where the two tetrahedral sheets are sandwiching a central octahedral sheet. Smectite
group minerals are mostly expansive and have the property to swell in presence of water.
This clay mineral is less abundant in the Cambay Shale samples and show the average
percentage of 5 wt. % and peaks occur at 5.6o 2θ. It is almost absent in the JU-3 and JU-4
wells. The samples from Mangrol Lignite Mine (JU-5) show the abundance of
montmorillonite and the value in one of the sample goes upto 20 wt. %.
Other Minerals
Quartz (SiO2) is the second most abundant mineral in the continental crust, after
feldspar. It is the third most abundant mineral in the Cambay Shale samples, where the
values range from 3 to 34 wt. %. It produces the sharp peaks at 20.85o
2θ (100) and at
26.65o 2θ along with illite. The high percentage of quartz is seen in the samples from JU-3
well.
Muscovite is the phyllosilicate mineral of mica group with perfect basal cleavage.
This mineral is present only in CAM1 sample (JU-1) with the percentage of 17.5 wt. %.
The JU-5 samples shows good percentage of muscovite and the value goes upto 22.4 wt.
% in CAM21. Minor amounts of feldspar (avg. 5 wt. %) were also detected in the
samples with orthoclase and albite in all samples in good quantities. Carbonate minerals
101
are present in lesser quantities in the sample. Some JU-5 samples with abundant bivalve
fossils show considerable amount of calcite. Gypsum (CaSO4.2H2O) and anhydrite
(CaSO4) minerals are also found in all the samples in lesser quantities, except for the
samples from JU-1 and JU-2 wells. These two related minerals are formed due to the
evaporation of sea water in restricted environment. The gypsum content ranges from zero
to as high as 57.7 wt. % in the CAM19 sample (JU-5). Pyrite (FeS2) and siderite (FeCO3)
are also present in considerable amount in almost all the samples of Cambay Shale. Pyrite
in shale is usually formed in reducing environment and its formation depends on the
availability of sulphate, reactive iron and organic matter. It is pyrite is formed due to the
sulphur reduction in anaerobic condition, where sulphur readily reacts with iron which is
abundant in clay muds. This reaction forms hydrotroilite and troilite, which are slowly
transformed into pyrite. Siderite is also formed in strongly reducing environment but in
low sulphate water. Siderite is formed due to the combined effects of iron reduction and
bacterial methanogenesis of organic matter. The presence of pyrite and siderite in
considerable amounts in the Cambay Shale increase the bulk-density of the formation and
also causes the decrease in resistivity.
4.1.4.2 Subathu Formation
The XRD bulk mineralogical results of the Subathu Fm shales are shown in the
Appendix E and the average composition is shown in the Figure 4.3. The data suggest
that these samples are dominated by kaolinite a mineral which is present in all samples in
high quantities. Its value ranges from 1.39 to as high as 83.77 wt. %. The basal Subathu
Fm shales are dominated by clay minerals, mostly kaolinite and its concentration is
highest in the samples collected from Mahogala Mine. The percentage of clays decreases
up-section (Fig. 4.4) and the younger shales show lesser clay and more silica. The X-ray
diffraction patterns of all the analysed samples from borehole BBHA are combined in one
plot to show the mineralogical changes throughout the succession (Appendix G). The
basal Subathu Fm shales have more than 30 wt. % kaolinitic clay, except for the sample at
the sample A2 of BBHA borehole at the interval 47.2 m. The middle lagoonal green and
the top red tidal flat facies of the Subathu Fm show less kaolinite content, as seen in the
samples from shallower depths of the borehole BBHA and Manma section. The
sediments of the Subathu Fm have been subjected to the high thermal alteration, mostly
the basal part of it, which is in close proximity of the thrust that significantly has raised
the temperature of the basal rocks.
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Figure 4.3: Average mineral composition of the Subathu Fm along with standard deviation
Figure 4.4: Depth vs Clay and Silica total for the BBHA. Note the increase in silica total
up-section.
103
Kaolinite in these samples might have been transformed into dickite but the identification
of this polytype is difficult due to the similarity in the XRD patterns of kaolinite and
dickite. Kaolinite produces a (001) peak at 12.4o
2θ and a (002) peak at 25.1o
2θ.
Halloysite mineral was identified in some of the samples from borehole BBHA with its
peaking at 23.9o 2θ.
The other clay minerals identified in the Subathu Fm samples are illite and
chamosite. Chlorite is seen in few samples but in lesser quantity. Illite is present in all the
samples with its peaks at 8.50o 2θ, 20.03
o 2θ and 26.65
o 2θ. Its percentage ranges from 0.5
to 39.8 wt. %, with an average value of 12.45 wt. %. Chamosite is also found in most of
the samples but in lesser amounts and the value ranges from 0 to 12.68 wt. %.
Quartz is present in all the samples in considerable amounts, except for few samples
from Chapparwari and Manma sections where it is either negligible or completely absent.
Its maximum value reaches up to 74.4 wt. % with an average of 26.74 wt. %. The quartz
content of the Subathu Fm Shales increases up-section (Fig. 4.4) and the higher
percentages are seen in the samples from the Kalakot sections. Muscovite is highly
variable and its maximum percentage is 37.4 wt. %. It is completely absent in the samples
from Mahogala section. Plagioclase feldspar is not present in the Subathu Fm shales;
however, minor amount of albite was identified in some samples. Orthoclase is also
present in lesser quantities, which is negligible to most of the samples and maximum
value is 6 wt. %. Anatase was found in samples from BBHA borehole with value ranging
from 1.5 to 13.1 wt. %.
Carbonate minerals are not found in abundance in the Subathu Fm Shales. Calcite is
highly variable and only traces of it were seen in most of the samples, except for some
samples from BBHA and Mahogala borehole (MBH1), where it is found in considerable
quantities. Pyrite is also present in considerable amount and its maximum value is 9.3 wt.
%. Siderite is present in some of the samples. Magnetite mineral shows the presence in
minor amounts in some of the samples from BBHA borehole and aluminium oxide
bayerite and extremely rare mineral zunyite were also identified in them.
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4.1.5 QEMSCAN® vs. XRD Mineralogy
The results obtained by XRD and QEMSCAN® analysis of the samples were
compared to find out the similarities and differences between the results. The data
generated by both the methods are largely in agreement. There are the higher chances of
discrepancy in the calculated percentages of minerals due to the variability associated
with the selection of the samples. For XRD analysis, the powdered whole rock sample is
randomly selected, regardless of any grain size difference or colour change. However,
small rock piece is selected for the QEMSCAN® analysis to infer the mineralogical and
textural variabilities within the sample. Therefore the techniques may show the similarity
in the data but there are grim chances of having the same results.
The samples analysed for the QEMSCAN® were also studied by XRD method and
the results show similar trend. The minerals percentages calculated by QEMSCAN®
match well with the XRD results of the Subathu Fm samples. However, the QEMSCAN®
data of the Cambay Shale samples disagree with the XRD data from the mineralogical
point of view. The difference in the data can either be due to the selection of the rock
sample or the library being used for the identification of the mineral.
4.1.6 Clay Minerals and Diagenesis
The thermal evolution or diagenesis of shale can be inferred on the basis of organic
thermal maturity and crystallinity or Kübler Index (KI) of illite mineral present in its
rocks. The immature shale rock is mostly dominated by neoformed and inherited clay
minerals. But with the increase in the burial depth, these neoformed and inherited clays
are transformed due to thermal diagenesis. The burial diagenesis, tectonic deformation
and regional metamorphism can lead to the high thermal maturation of rocks in a basin.
The studied Cambay Shale samples are dominated by kaolinite and illite clay minerals,
with the considerable percentage of smectite clays in the samples from Mangrol Lignite
Mine (JU-5). The presence of highly crystalline illite (see SEM Plates) and kaolinite in
the samples from the considerable depth indicate that these samples are thermally mature.
This is also confirmed by the thermal maturity of organic matter present in these samples
which suggest that these rocks are in oil generation window. The occurrence of less
crystalline smectite clay, mostly montmorillonite in the JU-5 samples indicates immature
stage.
105
In order to determine the intensity of the diagenetic processes that acted upon the
Subathu Fm shale samples after their deposition, Kübler Index (KI) of illite “crystallinity”
(IC) was assessed by measuring the full width at half maximum (FWHM) intensity of the
first illite basal (001) reflection at 10 Å peak (Kübler, 1964 and 1968). It is used as a
measure of maturation with burial and its value decreases with improving crystallinity,
therefore indicating increase in metamorphic grade (Wang et al., 1996; Jaboyedoff et al.,
2001; Abad, 2007). FWHM values of only Subathu Fm Shale samples from BBHA were
calculated and their values range from 0.66 to 0.10oΔ2θ, with an average value of
0.27oΔ2θ (Appendix H). This suggests that these samples are supermature and fall in the
high anchizone and epizone level of the maturation. The higher maturation level of these
samples may be attributed to deep burial and also due to the close proximity of the thrust
which might have significantly raised the temperature of the Subathu Fm shales.
4.1.7 Provenance
The term provenance has been derived from the French word “provenir”, which
means “to supply” or “provide for” (Potter et al., 2005). Some authors (e.g., Weltje and
Eynatten, 2004) have written that the word originated from the Latin word “provenire”,
meaning to come forth or to originate. The provenance study is used to determine the
immediate source of the mineral constituents of the sedimentary rocks, relief, climatic
conditions and tectonic setting of the source area. Clay mineral studies have been widely
used to determine the initial source of the sediments and to reconstruct and interpret its
history from the erosion of the parent rock to its deposition as the detritus in the basin.
4.1.7.1 Cambay Shale
Cambay Shale samples are dominated by the clay minerals which have been used to
reconstruct their provenance. The abundance of kaolinite and illite minerals indicate that
the source of sediments was mainly Deccan Trap Basalt and the volcanic and
metamorphic rocks of the Aravalli – Delhi orogenic belt in the northeast. Dave and
Pandey (1998) suggested the basic (Deccan Trap basalt) igneous rocks as the source of
sediments for the Older Cambay Shale, whereas acidic provenance of igneous and
metamorphic rocks for the Younger Cambay Shale. Towards the northern part in the
Pattan – Sanchor Block, the Deccan Trap Basalt was either absent or present in patches;
therefore, the main source of the sediments was the acidic and basic rocks of the Aravalli
– Delhi orogenic belt. The northern part of the Cambay Basin received the detrital inputs
106
from the west and southwest flowing proto–Banas, proto–Sabarmati and proto–Mahi
rivers, besides the drainages which flowed along the basin axis from north to south (Raju
and Srinivasan, 1993; Chowdhary, 2004). These rivers originated in the Aravalli
highlands in the north and northeast and deposited sediments in the major part of the
North Cambay Basin. The southern part of the basin received the sediments from the
proto–Narmada, a major river system flowing from the east.
4.1.7.2 Subathu Formation
The mineralogy of the Subathu Fm shale is interpreted to reflect the inheritance of
clay minerals from the weathered basic igneous rocks. Kaolinite is the most dominant
clay mineral in these shales and is found in abundance in all the samples. Much of the
kaolinite in the Subathu Fm shales is classified as dickite, which is transformed due to the
thermal maturation. However, the transformation of kaolinite to dickite is poorly
understood and it is very difficult to distinguish between the two due to their similar
diffraction patterns. Therefore, kaolinite is written instead of dickite while presenting this
data. Kaolinite in shales is mostly detrital, which is derived mostly from feldspar and
mica (Bloch and Hutcheon, 1992; Hugget, 1992) and also from the volcanic ash (De
Caritat et al., 1994 and 1997). There are less chances of authigenic precipitation of the
kaolinite in shales due to their low permeability for the flow of meteoric water
(Bjorlykke, 1998). The higher kaolinite content in the Subathu Fm shales can be
explained by the local volcanic source with high feldspar content which weather and
preferentially alter in to kaolinite (Chamley, 1989; Galán, 2006). Bulk of the clay
minerals has been transported from the source area in the north, where the volcanic arc
and ultramafic rocks are considered as the possible source of the Subathu Fm shales. The
southerly source of sediments is another possibility, where the Deccan Trap Basalt is the
likely source of the sediments. However, Najman and Garzanti (2000) found low Cr # in
the detrital spinels of the Subathu Fm Shales, which suggests their source from basaltic
rocks (mostly mid-ocean ridge basalt–type) and ophiolites and ruled out the possibility of
Deccan Traps (which has high Cr # spinels) as the source. The high kaolinite content is
attributed to intense weathering during monsoonal humid climate within subtropics. The
basal Subathu Fm sediments were deposited during the initial stage of collision and the
development of the Himalayan fold thrust belt was in progress which later separated the
suture zone from the foreland basin.
107
Illite mineral is found sporadically throughout the Subathu Fm. It shows the
abundance in some of the samples from Mahogala and Chapparwari sections. The KI of
the Subathu Fm shale samples suggests the development of illite clay from feldspar and
mica due to burial diagenesis (Birkeland, 1984; Nesbitt and Young, 1989). The presence
of illite in the samples with higher KI values can be detrital in origin, formed due to the
physical weathering of the crystalline (basic igneous and low grade metamorphic) rocks.
Chamosite clay is also found intermittently in the Subathu Fm samples and is low in
percentage. It suggests the weathering of the basic igneous rocks of the hinterland and
deposition in marine environment shallower than c. 60m in the tropical warm condition
(Porrenga, 1967).
Quartz mineral, which is present in significant quantity in almost all the Subathu
Fm Shale samples, is mostly extrabasinal detrital brought in by the rivers from the
potential source of low grade metamorphic rocks.
Muscovite in the Subathu Fm samples is mostly detrital in origin transported by the
fluvial systems from the nearby source into the basin. Muscovite can also be formed due
to the recrystallization of illite during the late diagenetic to low metamorphic processes
(Totten and Blatt, 1993; Schieber, 1996). However, it is very difficult to determine the
origin (whether detrital or thermal alteration) of muscovite mineral from the XRD
analysis.
In summary, the mineralogical assemblage of the Subathu Fm rocks suggests their
derivation from the mixed source terrane in the north in the proto-Himalaya suture zone
during the collision and development of the Himalayan fold-thrust belt and foreland
basin. The sediments were mostly derived from the basic igneous and low grade
metamorphic rocks of Trans-Himalaya, Higher Himalayan crystalline zone and ultramafic
rocks of Indus Suture Zone.
4.1.8 Reservoir Quality
Mineral constituents of the shale affect its reservoir quality and well completion.
The composition of shale controls its porosity, permeability, brittleness and ductility and
consequently defines the Young’s Modulus and Poisson’s Ratio. The high percentage of
clay minerals increases the ductility of the shale and usually destroys its porosity and
permeability. The shales with high silica content show high Young’s Modulus and low
Poisson’s Ratio values, making them more brittle (Aoudia et al., 2010; Ding et al., 2012;
108
Sone and Zoback, 2013). Mineralogy and mineral fabric (arrangement of grains) also
affect the pores and associated pore networks. Shale reservoirs have low porosity and
permeability and require natural or induced fractures to produce economic fairways for
hydrocarbons. The fracability or fracturing potential of a reservoir depends on its
brittleness which is largely controlled by the mineralogy, geomechanical properties and
also the amorphous material (e.g. organic matter) especially in shale reservoirs (Kowalska
et al., 2013). Silica rich and carbonate rich shales are more susceptible to fracking than
clay-rich shales (Sondergeld et al., 2010). If the clay content in the shale is less than 40%,
the rock is considered as brittle (Wang and Carr, 2013). The major shale gas plays like
Barnett and Marcellus in North America have less than 50% of total clay and are rich in
silica (mostly biogenic) and carbonate minerals (Passey et al., 2010; Bruner and Smosna,
2011; Hart et al., 2013).
Various methods have been proposed to quantify brittleness of the shale (Otis,
2013). However, the method after Jarvie et al. (2007) has been used for this study, where
the proportion of quartz relative to clay and carbonate determines the brittleness index
(BI). This is defined by the equation given as:
Brittleness Index (BI) = Quartz / (Quartz + Carbonate + Clay Content)
The Brittleness Index indentified for individual samples on the basis of the equation
given above, is shown in the Appendix I. The Cambay Shale samples show very low BI
with an average value of 0.15. The basal Subathu Shale samples also show low BI values
lower than 0.4 as compared to the samples from the top section. The younger lithofacies
show the Brittleness Indices higher than 0.5.
TOC data also forms the important parameter along with mineralogical composition
and percentage to ascertain the reservoir quality and only these two parameters cause the
critical heterogeneity in unconventional shale reservoirs (Boyce and Carr, 2010).
Therefore, a crossplot was drawn to show the relationship between total silica content
with TOC content (Fig. 4.5). The figure shows Cambay Shale samples with high TOC
content but their silica weight percentage is less than 40. Most of the Subathu Shale
samples show high TOC and also high silica content.
The mineralogical data generated is also plotted on the ternary diagram (Fig. 4.6) to
visualise the realative proportion of clays, silica, carbonate and other minerals. In the
ternary plot, all the minerals are arranged into three groups, viz. clay total (kaolinite,
109
illite, chlorite and other clay minerals), silica total (quartz, feldspars and mica) and
carbonate and other (calcite, dolomite, pyrite, siderite and other minerals). The zone in
the plot with 40-60% of clay content is marked as brittle – ductile transition zone.
According to the ternary diagram, half of the analysed Cambay Shale samples are clay
dominated and rest of the samples fall in brittle – ductile transition zone. On the basis of
mineralogical classification put forth by Gamero-Diaz et al. (2012), most of the samples
are identified as silica-rich argillaceous mudstone. Subathu Fm shale samples show wide
range of mineral compositions and majority of the samples fall in brittle – ductile
transition zone. The basal Subathu Fm shales are mostly clay dominated (mostly
kaolinite) whereas the younger rocks are clay rich siliceous mudstones. Figure 4.6 shows
that most of the samples do not plot in the brittle region with higher clay content
imposing difficulties for hydrofracking stimulation and economic production. However,
the younger samples and Kalakote section samples of Subathu Fm show the dominance of
prospective minerals with fracking potential.
The XRD results of the Cambay Shale and Subathu Fm shales are plotted against
the four major US shale plays (data taken from Passey, 2010 and Gale, 2014) on ternary
Figure 4.5: Cross plot showing the relationship of total silica with TOC content.
110
plot (Fig. 4.7). A clear division can be seen between the Cambay Shale and prospective
US shale plays. However, some of the data with lesser clay content are partly analogous
to Haynesville and Barnett shales. Also, the mineralogical studies performed by Oilex
(Oilex, 2010 and 2014) on the Eocene unconventional Cambay Shale reservoir in the
Cambay Field (near Khambat town) in Tarapur Sub-Basin indicates low clay content and
high carbonate and silica content and show good correlation with the Eagle Ford,
Haynesville and Montney shales. The Subathu Fm Shale shows the mineralogical
resemblance with Barnett Shale.
The shale gas exploration in Cambay Basin has recently been started and few
exploratory wells have been drilled so far. The hydrofracking of the Cambay Shale
reservoir by Joshi Technologies International in Dholka Field showed promising results
(Sharma et al., 2010; Sharma and Kulkarni, 2010). The short horizontal well penetrated in
the hybrid siltstone and shale horizon in the Cambay Field produced significant amount
of gas and liquid hydrocarbons (Oilex, 2010 and 2014).
Figure 4.6: Ternary plot showing the relative proportion of of clays, silica, carbonate and
other minerals.
111
Shale, which is intrinsically heterogeneous and anisotropic, shows the mineralogical
variations which occurs not only at large scale but also at micro-scale. Silt and sand
streaks are usually present within the shale which can function as flow paths and transmit
fluids to the fractures far better than shale in the stimulated reservoir (Gale et al., 2014).
The natural fracture networks and associated silt/sand laminations present in the shale
reservoirs can be target for the economic production. The orientation of fractures is
important for stimulation and enhanced producibility and should remain open so as to
allow the proppant to settle. Both Cambay and Subathu Fm Shales are naturally fractured
and faulted. Numerous natural fractures and silt laminations in the Younger Cambay
Shale in Mehsana-Ahmedabad Block near Sanand and Wadu fields have been observed
(Dutt et al., 1993). Several thrusts and duplexes with the characteristic thrust bound
horses have been described in the Subathu Fm shales (Hakhoo, 2014) which can be
important conduits for gas to flow from pores to the wellbore.
Figure 4.7: Ternary diagram plotting the XRD results of the Cambay Shale and Subathu Fm
shales against the four major US shale plays.
112
4.1.9 Pressure Conditions and Associated Fractures
The pressure conditions in a shale gas reservoir depend on number of factors. Clay
mineral dehydration is one of the numerous causes of abnormally high pore-fluid
pressures (overpressures) in the shale reservoirs (Tingay et al., 2009). The dehydration of
kaolinite and smectite clays due to disequilibrium compaction (Osborne and Swarbrick,
1997) can cause the expulsion of significant percentage of structured water after thermal
breakdown of clay minerals lattices as it transform into another minerals. 20% of
kaolinite in a shale reservoir can produce water equivalent to c. 4% of the rock volume
which could contribute to the development of overpressure (Bjorlykke, 1996). The
thermal cracking of organic matter and generation of hydrocarbon can also lead to the
formation of high-magnitude overpressures due to the release of as much as 50% of
hydrocarbon (Tingay et al., 2012). The adsorption capacity of organic matter and clays
increases as the pressure builds up in organic rich shale and decreases due to the increase
in temperature (Hao et al., 2013). Therefore, the hydrocarbons will be detached from the
organic matter and clay surfaces due to the increase in temperature at greater depth and
remain as free gas/oil in the non-occluded void space (pores and fractures).
The abnormally high fluid pore pressure can lead to the development of natural
non-tectonic fractures or joints within the shale reservoirs. The thermal maturation of
organic matter and clay dehydration raise the overpressure which exceeds lithospheric
pressure causing the natural hydraulic fracturing (Lash and Engelder, 2005; Lash and
Blood, 2007; Engelder et al., 2009; Day-Stirrat et al., 2010; Jiu et al., 2013).
The Cambay Shale is moderately overpressured and is around 5000 psi (pounds per
square inch) or 34 MPa (megapascal) (Oilex, 2010 and 2014), where Older Cambay Shale
exhibits higher pore-pressure as compared to Younger Cambay Shale (Chennakrishnan,
2008). The overpressures are interpreted to be due to hydrocarbon generation during
thermal evolution and clay dehydration. The pressures in the Eocene Subathu Fm Shales
are also abnormally high (Law et al., 1998; Mittal, et al., 2006) and the pore pressure
gradient in these rocks is c. 13.5 MPa/km (Law et al., 1998). The abnormally high
pressure has been attributed to a combination of tectonic compression, clay dehydration
and hydrocarbon generation. The average pore-pressure gradient in the Paleogene
sediments in the HFB is c. 13.5 MPa/km (Law et al., 1998). The abnormal overpressure
indicates that the gas present in the Cambay Shale and Subathu Fm shales will be free gas
113
Plate 4.1: Natural Fractures within the Cambay (A, B, C) and Subathu Fm (D, E) shales. (A)
Natural fracture possibly developed due to abnormal pressure. (B) Interparticle and
intraparticle natural fractures. This image also shows interparticle porosity between organic
matter and clay particles. (C) Hydraulic fractures within the clay particle. (D) This
microphotograph shows the fracture filled with bitumen. (E) Dendritic fractures possibly
formed due to clay mineral dehydration after clay diagenesis.
114
stored in liquid-free pore spaces (intra-particle, inter-particle and organo-pores) and
natural fractures.
Abundant natural hydraulic fractures are formed within the Cambay Shale and
Subathu Fm Shales indicating episodic overpressure generation due to the above
mentioned reasons during the burial history (Plate 4.1). These are mostly irregular and
non-directional. These micro-cracks may get filled with bitumen or remain partially open.
These natural hydraulic fractures in combination with tectonic fractures improve the
porosity and enhance the permeability of the shale reservoirs. The fractures can be
targeted during the well stimulation to generate long and wide fairways for economic
production.
4.1.10 Gas-in-Place (GIP)
The mineralogical and source rock properties (clay content, TOC content and
maturity) of a shale alongwith its basic in-situ information (including formation thickness,
porosity, pressure, temperature) can be used to estimate the gas-in-place (GIP) of shale
gas system. The software, designated as GPESGSTM
(Gas-in-Place-Estimator-for-Shale-
Gas-System) and developed by Energy and Geoscience Institute (EGI), University of
Utah, USA, was used for GIP prediction model. Given the shale properties and reservoir
conditions, this software assesses the contribution for different gas storage mechanisms to
GIP. The gas is stored in shale gas reservoir by three primary mechanisms, viz.
compression, where the gas is stored as free gas in the pores and fractures; adsorption on
organic matter or inorganic mineral assemblages; and by solution in hydrocarbon liquids
and partly in water.
The GPESGSTM
was used to estimate in terms of the volume of gas-in-place and
storage mechanisms in Cambay and Subathu Fm Shales. The input data include the basic
rock properties (density, porosity and saturation), reservoir conditions (pressure and
temperatures), organic properties and maturity (TOC, Tmax and HI) and inorganic clay
mineralogy. The average values of all these parameters were considered for estimation of
methane gas capacity of Cambay Shale and Subathu Fm shales. The Cambay Shale shows
average effective porosity c. 5 – 6% (Basu and Dutta, 2010) and the average bulk density
is around 2.5 g/cm3. Figure 4.8 shows the results of the Cambay Shale after inputting the
required parameters. The result shows the methane capacity of 170 scf/ton (standard
cubic feet per ton) total gas-in-place. Free gas is the dominant contribution (140 scf/ton)
115
of total GIP. Due to high pressures, most of the gas is present in the free spaces of pores
and natural fractures. Very less amount of gas is found to be absorbed on the organic
matter.
The gravity modelling profile of Sub Himalayan Foreland Basin suggests that the
Subathu Fm Shales are thicker and better preserved towards the inner belt of the HFB and
are present at the depth of approx. 6500 km (Singh et al., 2005). The geothermal gradient
in the HFB is low, ranging from 18oC/km to 21
oC/km (Verma et al., 2012; Mittal et al.,
2006). Taking a hydrostatic pressure gradient of 13.5 MPa/km and a thermal gradient of
21oC/km into account, the Subathu Fm Shales at the given depth are extremely
overpressured with the whopping value of 87 MPa (12,600 psi). The shale properties and
reservoir conditions parameters of the Subathu Fm Shales are put into the module and
result generated is shown in the Figure 4.9. It shows the GIP of 400 scf/ton in the Subathu
Fm shales and more than half of it is present as fee gas.
The high amount of gas content present in both Cambay and Subathu Fm shales
suggests excellent potential source of shale gas plays that could be hydraulically
stimulated and exploited by using the hydrofracking technology. The fracturing treatment
design depends on the mineralogical nature of the rock besides other important factors
like porosity, density, natural fractures etc. Since both Cambay and Subathu Fm shales
are clay rich, therefore cross-linked gel treatment would be favourable as compared to
slickwater treatment (Lancaster et al., 1992). The methanol can also been used as base
fluid for fracturing the rocks with high clay content (Gandossi, 2013).
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Figure 4.8: GPESGS software screenshot showing the GIP and storage mechanisms in the
Cambay Shale.
Figure 4.9: GPESGS software screenshot showing the GIP and storage mechanisms in the
Subathu Fm shales.
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4.2 Scanning Electron Microscopic (SEM) Studies
4.2.1 Introduction
Shales are considered as the ultratight reservoirs where the hydrocarbons resources
are stored in heterogeneous and complex geological systems. These resources are trapped
in the micro-pores (µm) systems to nanometer (nm) scale (Ross and Bustin, 2009) and are
difficult to produce due to the ultra-low permeability in the shales (Curtis, 2002). The
understanding of the nature and distribution of pore types and networks can help in
estimating and optimising these resources (Curtis et al., 2011). Shale characteristics
research has attained novel dimensions with technological breakthrough and development
of shale resources exploration, prime example being documentation and understanding of
pore systems for gas, liquid storage and their flow within the shales. Innovations and
advancement in the scanning electron microscope (SEM) imaging and bulk analysis are
providing insights regarding the qualitative and quantitative assessment of porosity and
microstructures (Chalmers et al., 2009; Curtis et al., 2011 and 2014; Huang et al., 2013).
This technique helps in understanding the hydrocarbon storage mechanism and
permeability fairways from shale matrix into the artificially stimulated hydraulic fracture
systems (Loucks et al., 2009; Ambrose et al., 2010).
4.2.2 Methodology
In SEM instrument, the high energy electron beams from an electron gun under
high acceleration voltage are focussed on the sample. The electrons after hitting the
samples generate various signals which include Secondary Electrons (SE), Backscattered
Electrons (BSE), characteristic secondary X-rays etc. SE is used to generate the
morphology and topographic SEM images, whereas BSE shows relative density and
contrast in composition. Since, the samples used in this study are polished, therefore BSE
signals are mostly used for imaging the samples.
The Cambay Shale samples were prepared using ion milling technique. The Argon
ion milling of the samples was carried out to obtain smooth and enhance the quality of the
sample surface and diminish the surface topographical irregularities which commonly
form during conventional milling methods (Sondergeld et al., 2012; Garcia et al., 2014;
Cerchiara et al., 2014). The Fischione Instrument Model 1060 SEM Mill installed at E. A.
Fischione Instruments Inc. in Pennsylvania (USA) was used for ion milling at low
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incident angle for three hours. The samples were mounted to 25 mm diameter stub using
the carbon tape. In this instrument, the argon ion beam is used to gently sputter away the
uneven surface of the sample and make extremely polished surface for SEM studies. The
argon ion beam at 5kV is rastered at an incident angle of 5° on the sample placed on the
360° rotational stage. The rocking or rotation of the sample produces the smooth surface
with minimal topographic variations and polishing damage to the sample.
The argon ion milled samples were imaged on FEI Quanta 600 Field-Emission Gun
Scanning Electron Microscope (FEG-SEM) installed at Utah Nanofab Lab., College of
Engineering, University of Utah (USA). The samples were examined without conductive
coating in low vacuum mode. The electron detectors used for the study were an Everhart-
Thornley secondary electron detector (ETD), a large-field detector and a solid-state
backscattered electron detector (BSED). Both BSE and SE images were acquired to
ascertain the pore types and their distribution and also lithological identification within
the sample.
SEM Backscattered Electron (BSE) imaging was also done by using the
QEMSCAN® instrument to study the nature of pores and their distribution within the
Cambay and Subathu Fm shale samples (for methodology and samples details see
QEMSCAN chapter 4.3).
4.2.3 Results and Discussions
Shale rocks possess complex pore structures which are of varying sizes ranging
from micrometer to nanometer scales in diameter. It has been suggested that the organic
matter pores which are formed during the maturation of hydrocarbons are the dominant
pore type system and network (Jarvie et al., 2007; Ambrose et al., 2010; Curtis et al.,
2011; Klaver et al., 2012; Loucks et al., 2012; Dahl et al., 2012; Slatt and O’Brien, 2013;
Tian et al., 2013). However, other types of pores associated with the mineral grains are
also present in shales which can also contribute to the storage and migration pathways for
hydrocarbons (Loucks et al., 2012).
The general sample preparation and polishing techniques can pluck the mineral
grains of differential hardness, leaving depressions on the surface of the samples.
However, these holes are different from the ones which are formed naturally and are easy
to differentiate. The artifacts are usually circular or ellipsoidal in shape with shallow
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depth. The naturally formed pores are irregular in morphology and extend deeper into the
rock matrix and can easily be recognised (Slatt and O’Brien, 2011). Ion milling procedure
for preparation of samples is performed to avoid the plucking of mineral grains and
formation of artifacts. However, the samples should be treated with special care because
this method of sample preparation also produces some sort of artifacts. The milling
process can also clog the natural pores by redeposition of the milled material. The most
common type of artifact formed due to the ion milling is the flaring structures called
curtaining developed due to differential abrasion by ion beam (Loucks et al., 2012). The
curtaining with minor relief can be seen in the studied samples and these curtains usually
taper opposite to the direction of ion-beam currents (Plate 4.2A). The ion milled material
may get redeposited which can cover up the pores and cause serious problem during their
identification (Plate 4.2B). Most of the studied samples are clay minerals rich and these
clay particles in some of the samples formed the desiccation or shrinkage cracks on
drying (Plate 4.2C, D).
The classification put forth by Loucks et al. (2012) is used for naming the pores in
this study. The classification is based on the type, nature as wells as the width of pores.
The pores with diameter of less than 1 nm are termed as picopores. Nanopores are less
than 1 µm (1000 nm) and greater than or equal to 1 nm. Micropores range from 1 µm to
62.5 µm in size. Mesopores range from 62.5 µm to 4 mm in size and macropores are
larger than 4 mm. Most of the pores in the studied shale samples are generally less than 1
µm (nanopores), while some organic matter hosted pores are tens of micrometers in
diameter (micropores) and mesopores have also been observed.
The SEM images of the Cambay and Subathu Fm shale samples taken parallel to
the bedding plane, show abundance of dispersed organic matter and are mainly comprised
of clays minerals, siderite, pyrite, chlorite etc. The pores commonly discernible in the
analysed Cambay Shale samples include intraparticle and interparticle porosity associated
with mineral matrix. However, the organic matter hosted pores (or organopores) are the
abundant types of pores within these shales. The dominant type of porosity within the
Subathu Fm shales is organoporosity with very less mineral porosity.
The following types of the pores are present in the Cambay and Subathu Fm shale
samples.
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4.2.3.1 Interparticle Pores
These are the pores present between different particles within a shale rock. These
pores are abundant in young sediments which are not subjected to the higher degree of
diagenetic alterations. However, many older types of shale also possess depositional
interparticle pores and survived during burial diagenesis (Slatt and O’Brien, 2011).
Multiple sources of interparticle pores are present in shales and these include porous clay
flocculates, faecal pellets, organic matter, mineral grains (e.g. quartz, feldspars, and pyrite
framboids) and skeletal materials. The interparticle pores are produced by multiple
processes and have not been documented well in shales, therefore require detailed study
to understand their origin.
The Cambay Shale samples show abundance of interparticle porosity and are
present in different shapes (Plate 4.3). The interparticle pores (Plate 4.3A) are present at
interfaces between rigid grains and clay particles. These pores are also developed
between clay particles and along the edges of organic matter (Plates 4.4A and 4.5A). The
pores are mostly elongated, however rounded, sub-rounded and angular pores are also
present. The long dimensions of the pores are mostly less than 4 µm.
Subathu Fm Shales also possess interparticle pores but are present less frequently
(Plate 4.7 and Plate 4.8B). Most of these interparticle pores are present adjacent to large
organic matter particles.
4.2.3.2 Intraparticle Pores
Intraparticle pores are present within particles which are of primary origin or
produced after diagenetic alteration (Loucks et al., 2012). These pores are mostly
intragranular formed within mineral grains or fossils skeletons, shells and faecal pellets.
Intercrystalline intragranular pores within pyrite framboids also contribute to the
intraparticle porosity of these shales.
In the studied Cambay Shale samples, both intragranular and intercrystalline -
intragranular pores are present (Plates 4.3, 4.5 and 4.8). The rigid clay grains show
intraparticle pores which are rounded to elongated in shape (Plate 4.3A and B). The size
of these pores is less than 1 µm. Sheet-like intraparticle pores are also found within
chlorite grains (Plate 4.5A and B). These pores are elongated and their width ranges from
0.1 to 1 µm.
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Plate 4.2: Common types of artifacts. (A) Curtaining developed due to differential abrasion by ion beam. (B) Milling material
deposited on the kerogen. (C & D) Possible shrinkage cracks by desiccation.
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Plate 4.3: The FEG-SEM images of Cambay Shale sample showing interparticle and intraparticle pores. (A) Grain rim interparticle pores
along rigid clay-size grain. Sub-rounded interparticle pores along clay particles and intraparticle pores on the rigid clay-size grain are also
present. (B) Enlargement of blue-framed area in (A). Rounded and linear intraparticle pores of nanometer size. det = detector; ETD =
Everhart-Thornley Detector; HV = High Voltage; mag = magnification; spot = spot size; HFW = Horizontal Frame Width; WD = Working
Distance.
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Plate 4.4: The FEG-SEM images of Cambay Shale sample showing different types of pores. (A) Interparticle pores between organic matter and
clay particles. Linear natural fractures and organopores are also present. (B) Enlargement of blue-framed area (organic matter) in (A). The
Image shows numerous round-shaped organopores of nanometer size. Detector = mixed signal using BSE + SE combination. det = detector;
ETD = Everhart-Thornley Detector; HV = High Voltage; mag = magnification; spot = spot size; WD = Working Distance.
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Plate 4.5: The FEG-SEM images showing different types of pores within Cambay Shale. (A) The sample contains sheet-like intraparticle pores
within chlorite grain. Interparticle and organopores are also present. (B) Enlargement of blue-framed area in (A). The image shows long and
elongated intraparticle pores. Detector = mixed signal using BSE + SE combination; HV = High Voltage; mag = magnification; spot = spot size;
HFW = Horizontal Frame Width; WD = Working Distance.
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Intercrystalline-intraparticle pores within pyrite framboids are present in abundance
in Cambay Shale samples (Plate 4.9). Many of these pores between pyrite crystallites are
filled with organic matter or clay particles (Plate 4.9A and B). Pyrite in these shales is
either disseminated, elongated (Plate 4.9A) or in framboidal forms (Plate 4.9B) and
numerous pores are visible between euhedral to subhedral crystallites.
The intraparticle pores are also visible within broken fossil gastropods shells. These
fossils are partially pyritised (Plate 4.9A, B and C) and patchy in most of cases.
Pyritisation has occurred mostly on rims of the fossils fragments and central portion
contains pores of micrometer and nanometer scale. The process commence immediately
after the dissolution of calcareous shells.
Intraparticle pores are not found in the Subathu Fm Shale samples. However, these
shale samples are rich in organopores.
4.2.3.3 Organic Matter Hosted pores (Organopores)
These are intraparticle pores hosted within organic matter and are considered as the
most dominant type of pore system within shales. These pores are developed during
burial and thermal maturation of organic matter. The organopores begin to develop after
attaining the oil generation window (Loucks et al., 2012; Schieber, 2013) and the
generation of these pores is strongly controlled by the thermal maturity of organic matter
(Milliken et al., 2013). The organopore generation potential depends on the type of
kerogen (Schieber, 2010; Milliken et al., 2013). Since type II kerogen is less complex as
compared to type III and the former type breakdown easily into hydrocarbon. Therefore
type II kerogen appears to be more prone to the formation of organopores than type III
kerogen.
Organic matter hosted pores or organopores are present in abundance within both
Cambay and Subathu Fm shales (Plates 4.4, 4.6, 4.7 and 4.8). Most of these pores are
irregular, bubble-type, elongated, elliptical and rounded in shape. The size of these
organopores ranges from nanopore to mesopore scale. Some pores have long dimensions
more than 80 µm (Plate 4.7 and Plate 4.8A) and some pores are < 1 µm in diameter (Plate
4.4A and Plate 4.6B). The large size organopores are observed as isolated structures in
two dimensions but they display interconnectivity in three dimensions and provide
permeability fairways for hydrocarbon flow and discharge. The three dimensional
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evaluation of pores systems and networks can be illustrated and studied by using FIB-
SEM analysis (Chalmers et al., 2009; Ambrose et al., 2010; Curtis et al., 2011; Zhang et
al., 2011; Sondergeld et al., 2012).
The nature, amount and distribution of pores are important components for
understanding the hydrocarbon storage, flow and discharge. Interparticle pores exhibit
effective interconnected pore networks as compared to intraparticle mineral pores
(Loucks et al., 2012). Organopores also exhibit effective pore systems and can contribute
to the hydrocarbon storage and flow pathway.
The intragranular organopores and intercrystalline intraparticle pores within pyrite
framboids and concretions are the primary contributors to the hydrocarbon storage, flow
and discharge in the Cambay Shale. In Subathu Fm Shales, the mesometer and
micrometer interconnected organopores are the main facilitators of effective gas storage
and also provide gas flow permeability fairways.
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Plate 4.6: The FEG-SEM images (A, B & C) show organic matter hosted pores (organopores) of different shapes. det = detector; ETD =
Everhart-Thornley Detector; BSED = Backscattered Electron Detector; HV = High Voltage; mag = magnification; spot = spot size; HFW =
Horizontal Frame Width; WD = Working Distance.
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Plate 4.7: The SEM image of Subathu Fm shale sample showing large size organopores. One pore is of mesometer scale.
Interparticle pores are also present. The signal used is Quadrant Backscattered detector (QBSD). Mag = magnification; WD =
Working Distance.
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Plate 4.8: The backscattered electron image of Subathu Fm shale sample showing organopores and interparticle porosity. (A) The pores are of
micrometric and mesometric scale. (B) The image shows organopores and interparticle pores. QBSD = Quadrant Backscattered detector; Mag =
Magnification; WD = Working Distance; EHT = Electron High Tension (accelerating voltage); Fil I = Current.
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Plate 4.9: Interparticle and intraparticle pores within Cambay Shale samples. (A) Elongated
pyrite concretion showing intercrystalline intraparticle pores. (B) Intercrystalline intraparticle
pores within pyrite framboids. (C, D & E) These images show partially pyritised fossils and
organic matter with interparticle and intraparticle porosity. (F) Oragnic matter with
organopores.
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4.3 QEMSCAN® (Quantitative Evaluation of Minerals by Scanning Electron
Microscopy)
4.3.1 Introduction
QEMSCAN® (Quantitative Evaluation of Minerals by SCANning Electron
Microscopy) technology is a high end, automated mineralogical tool being used for
quantitative chemical analysis and generates detailed high-resolution mineral images
(Gottlieb et al., 2000). QEMSCAN® has become one of the essential laboratory tools in
geology and other allied areas of research (Pirrie et al., 2004; Lui et al., 2005; Sliwinski
et al., 2010a, 2010b; Rollinson et al., 2011; Ayling et al., 2012; Allen et al., 2012). It
combines the scanning electron microscopy (SEM) with four high speed energy
dispersive X-ray spectrometers (SEM-EDS) for the rapid characterization of minerals by
collecting thousands of energy dispersive spectra per hour on the polished thin sections or
epoxy plugs. Traditional X-Ray Diffraction (XRD) method is usually used for qualitative
analysis of the samples but it gives rough quantitative estimates of the mineral contents
present in the samples. QEMSCAN® is the best tool available at the moment being used
to precisely quantify the minerals within samples which otherwise is difficult to obtain by
the traditional methods. QEMSCAN® is useful for quantification of the abundances,
compositions and morphologies of the minerals particles and the mineral associations,
especially in the fine grained rocks like shales and mudrocks.
QEMSCAN® consists of the scanning electron microscope with four energy
dispersive X-ray detectors which use Backscattered Electron (BSE) and Energy
Dispersive X-ray (EDX) for the identification of mineral species within a micro-domain
under the electron beam. When an electron beam is made incident on the surface of the
predetermined pixel spacing intervals (usually between 0.2 µm and 25 µm), the BSE and
X-ray energy spectra emitting from a given point are rapidly acquired and used to identify
the elements and the minerals present. Each mineral has its own distinctive energy
dispersive X-ray spectrum which is compared with the database of the known spectra
existing within the mineral identification library called Species Identification Protocol
(SIP). Some minerals with similar X-ray spectra (e.g. hematite and magnetite) can be
differentiated by using the backscattered Electron (BSE) images and the mineral species
with similar X-ray spectra and BSE image (e.g. chalcopyrite and cubanite) can be
distinguished on the basis of elemental ratios (Gottlieb et al., 2000). The image at a given
point within the mineral particle is built up pixel-by-pixel and each pixel is assigned a
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number which is identified by SIP and appropriate mineral name and default colour code
is given to each mineral. The beam then shifts to the next point and the process is
repeated and a complete mineral map is prepared in this way. The mineral identification
and data analysis is performed in a software programme called iDiscover, where the
results can be thoroughly examined and manipulated. This programme is used for the
microfabric analysis and calculation of the space (in area percentage) occupied by the
different minerals.
4.3.2 Methodology and Rationale
QEMSCAN® analysis was performed on eight shale samples (four from Cambay
and four from Subathu Fm Shales) to determine their mineralogical distribution, texture
and depositional facies. It was completed in QEMSCAN® Laboratory at the Energy and
Geoscience Institute (EGI), University of Utah, Salt Lake City, USA. The analysis was
done on QEMSCAN® model 4300, built on Zeiss EVO 50 by Intellection, with a tungsten
filament and four light element Brüker Xflash energy dispersive X-ray detectors. The
instrument uses iMeasure v.5.2 software for the data acquisition and iDiscover v.5.2 for
the spectral interpretation and data processing. The measurements were taken in field
scan mode and scans were performed at 20 µm spacing.
QEMSCAN® system works in different operational modes depending on the grain
size and distribution of the mineral particles. These are:
1) Bulk mineral analysis (BMA) is applied for the analysis of cores, rocks or
particulate samples, in which the bulk mineral particles including background (epoxy or
organic matter present in samples) are scanned by using the pre-determined spacing and
the quantitative data is generated. Bulk mineral analysis requires less time for the
completion of the analysis as compared to other operational modes.
2) Particle mineral analysis (PMA) method is used for the detailed and systematic
mineralogical characterisation of the particles present in the sample. Specific Mineral
Particle Analysis includes trace mineral search (TMS) and specific mineral search (SMS)
which are similar to PMA mode. These are used for measurement of the mineral particles
with the specific backscattered electron coefficient above a predetermined value (Gottlieb
et al., 2000; Pirrie et al., 2004).
4.3.2.1 Sample Preparation
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Selected samples were prepared for QEMSCAN® analysis by making 1 cm graphite
impregnated epoxy plugs. The samples were cut into small bits and were set in a plug
mould with epoxy (8 gm) mixed with 1 gm of hardener. Then the moulds were cured
under a vacuum at 2 bar/30 psi pressure for 10 hours. The plugs were then lapped and
polished using Struers Grinder and Polisher. After grinding and polishing, the surfaces of
the plugs were coated with a thin layer of carbon to ensure electrical conductivity
preventing charging of the samples during measurements. The carbon coating was
performed by using Struers Carbon Coater and the procedural steps were methodically
followed, which are given below:
1. Plug in vacuum pump.
2. Turn on coating unit (on/off button at the back of the unit).
3. Prepare two carbon rods (one sharpened to reduced diameter, one sanded flat at
end) and insert them into the lid, lining them up so that they are centred where
touching.
4. Put holder into the chamber and samples into the holder.
5. Insert clean brass plug into the holder.
6. Close the lid and hold it down during next step.
7. Press start to turn on the pump.
8. Wait for target pressure to be reached (5 minutes), then another 2 minutes and
then hit start.
9. Hit ‘Up’ button to outgas. Wait half a minute.
10. Hit ‘Down’ button to evaporate (burn carbon rod), averting the eyes.
11. Press ‘Stop’ to return to atmospheric pressure.
12. Check the brass plug to confirm adequate carbon coat.
13. Remove samples.
14. Clean up the holder, including the brass plug. The brass plug can be cleaned with
detergent and water or by using polishing compound.
15. Turn off the coating unit.
4.3.2.2 Analysis Technique
Following the carbon coating, eight epoxy plugs (30 mm in diameter) were put in
the QEMSCAN® sample holder and were loaded in the machine for the analysis. Before
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the analysis, the machine was calibrated to check its proper functioning. The instrument
was run by using an accelerating voltage of 20 KeV and specimen current of
approximately 5 nA.
After analysis, the data were processed using iDiscover v 5.2 software with the Oil
and Gas (O & G v 3.3 DH SIP) Species Identification Protocol (SIP) produced by FEI
company. Oil and Gas SIP is a library with the collection of energy spectra that are
specifically helpful for sedimentary rocks studies for the oil and gas industry.
4.3.3 Results and Discussions
The spaces (in area percentages) occupied by the minerals present in the samples
are given in Table 4.1. The mineralogy maps generated for representative samples from
the Cambay Shale and Subathu Fm shales are show in the plates (Plate 4.10-4.17). The
minor constituents of the analysed samples with the percentage less than 0.5% were not
accounted for the overall percentage calculations. The mineral constituents having
percentage above 0.5% were then normalised to 100%. The spaces on mineral maps
where mineral grains are absent (pore space) or filled with epoxy (in particulate samples)
or organic matter are shown in white colour and termed as ‘background’. These
background points can be seen on the mineral map but their values were subtracted from
the bulk mineralogy and were not included in the data plots.
Table 4.1: Percentages of spaces occupied by the minerals identified in the samples
Mineral
Name CAM2 CAM8 CAM16 CAM19 SUB3 SUB5 SUB11 SUB22
Alkali Feldspar 1.54 - - - - - - -
Ankerite - - 3.93 - - - - -
Biotite 2.87 - 0.59 - - - - -
Calcite - - 2.22 - - - - -
Chlorite 27.02 65.23 25.26 1.71 - - - -
Fe-Oxides - - 7.38 - - - - -
Glauconite 4.40 - 1.92 - - - - -
Gypsum - - 1.36 - - - -
Illite 36.80 2.21 5.02 0.89 - 4.50 2.69 -
Kaolinite 0.98 1.16 - 2.14 92.62 49.01 74.11 98.72
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Muscovite - - - - - 1.31 5.66 -
Other 1.11 1.00 5.07 3.36 - - - -
Other
Silicates 6.13 11.61 4.65 31.50 0.63 4.03 17.53 1.28
Particle Rims 3.50 1.78 6.78 6.36 - 1.15 - -
Plagioclase 0.68 - - 3.26 1.91 15.30 - -
Pyrite 3.39 - 2.37 24.64 - - - -
Quartz 4.69 1.71 11.19 2.09 3.57 20.00 - -
Siderite - 0.59 19.07 - - - - -
Smectite 6.88 14.65 4.54 22.68 1.26 4.39 - -
The QEMSCAN® results are compared with the results generated through XRD
analytical technique and both are broadly comparable (See 4.1.5 in XRD chapter). The
observed variability in mineral percentages calculated through these two different
techniques is due to lack of precision in sample selection. For example, the samples from
Cambay Basin are cuttings; therefore there are higher chances of finding mineralogical
variability within the sample selected from an interval.
4.3.3.1 Cambay Shale
The Cambay Shale samples, from four different blocks of the basin, show wide
mineralogical variability. Chlorite mineral is found in all the four samples, with the
minimum occupied spaces of 1.71% in CAM19 sample and the maximum of 65.23% in
CAM8 sample. Smectite is also present is all the samples occupying variable spaces from
4-23%. Illite is present in varying amounts with maximum percentage in CAM2 sample
(36.80%) but is negligible in CAM19 sample. ‘Other Silicates’ which include other
feldspar group minerals occupy spaces ranging from 5-31%, with the maximum
percentage in CAM19 sample. Pyrite mineral, in disseminated form and as framboids, is
also seen in all the samples (except for CAM8) with the maximum percentage in CAM19
sample. Siderite is identified in only two samples, with 19.07% in CAM16. Quartz grains
are also present with significant percentage in all the samples (Table 4.1). Particle rims
also show the presence in all the samples within the range of 1.7% to about 6.7%. All four
Cambay shale samples show the amount of some minerals here termed as ‘Others’. These
unclassified points of the scan either represent the boundary phases between mineral
grains where composite signals are generated by EDX spectra or they constitute the group
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of elements or mineral species that are not present in the SIP library and thus remain
unidentified. The percentages of this group “Other” ranges from 1% to 5% in the
samples. Kaolinite is present in three samples with the maximum percentage of 2.14% in
CAM19. Plagioclase feldspar is shown up only in two samples in minor quantities.
Glauconite is seen in CAM2 with 4.40% and CAM16 with 1.92%. Gypsum is also found
in minor amount in CAM19 sample.
4.3.3.2 Subathu Fm Shales
All the four Subathu Fm Shale Samples are dominated by kaolinite mineral. SUB22
sample show 98.72% space occupied by kaolinite and the rest (1.28%) is occupied by
other silicates. Other Silicate mineral group is present is varying amounts, ranging from
0.63% in SUB3 to 17.53% in SUB11 sample. Quartz mineral occupies 20% space in
SUB5 and 3.57% in SUB3. Plagioclase feldspar is identified in only two samples (SUB3
and SUB5) and occupies 15.30% space in SUB5 sample. Smectite is occupies 1.26%
space in SUB3 and 4.39% in SUB5 samples. Illite and muscovite are seen in minor
quantities in SUB5 and SUB11 samples.
4.3.4 Summary
The QEMSCAN analysis provided significant information about the quantity and
distribution of the mineral constituents in the studied shale samples. This analysis shows
the abundance of clay minerals in the both shale formations. The Cambay Shale samples
show the predominance of illite and chlorite minerals. The abundance of these two
mineral constituents indicates deposition of shales in marine and slightly alkaline
environmental condition. The glauconite mineral has been used as depth indicator
(Porrenga, 1967; Imenez-Millan et al., 1998) and the presence of this mineral indicates
calm marine, deep water (> 125 m) depositional settings. Presence of glauconite within
the analysed samples suggests cold bottom water conditions, generally less than 15oC.
Presence of pyrite in the samples suggests redox potential supplied by reducing (anoxia)
environment. The samples from the Mangrol Lignite Mine show high percentage and
sporadic distribution of pyrite indicating anoxic bottom water condition and the presence
of gypsum suggests restricted marine environment. The presence of angular quartz grains
indicates detrital input from the nearby terrestrial source. The Cambay Shale samples also
show the large percentages of white coloured background within the samples which
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suggests good and sporadically distributed organic carbon content and abundant
interparticle porosity.
The Subathu Fm shale samples show the dominance of kaolinite mineral which is
present in high percentage and suggests nearby volcanic source of sediments. This is also
confirmed by the presence of thin ash beds observed within the Subathu Fm during the
field investigations. The quartz and other silicate minerals indicate detrital influx for the
continental source. The large percentage of the background space represents abundance of
organic matter present in the samples.
The Cambay Shale and Subathu Fm shale samples show the abundance of mostly
clay minerals which indicate that these rocks are less brittle and therefore cross-linked gel
treatment or methanol (Lancaster et al., 1992; Gandossi, 2013) would be useful for
fracking these rocks.
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A
C
B
D
Plate 4.10: QEMSCAN data for the sample CAM 2. (A) QEMSCAN image with
minerals colour coded. (B) Table expressing minerals abundance in area percent. (C) 30
mm diameter epoxy plug. (D) Close up view.
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Plate 4.11: QEMSCAN data for the sample CAM 8. (A) QEMSCAN image with
minerals colour coded. (B) Table expressing minerals abundance in area percent. (C) 30
mm diameter epoxy plug.
A
C B
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C
B
A
Plate 4.12: QEMSCAN data for the sample CAM 16. (A) QEMSCAN image with
minerals colour coded. (B) Table expressing minerals abundance in area percent. (C) 30
mm diameter epoxy plug.
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Plate 4.13: QEMSCAN data for the sample CAM 19. (A) QEMSCAN image with minerals
colour coded. (B) Table expressing minerals abundance in area percent. (C) 30 mm
diameter epoxy plug.
C B
A
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Plate 4.14: QEMSCAN data for the sample SUB 3. (A) QEMSCAN image with minerals colour coded. (B) Table expressing
minerals abundance in area percent. (C) 30 mm diameter epoxy plug.
C
B
A
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Plate 4.15: QEMSCAN data for the sample SUB 5. (A) QEMSCAN image with minerals colour coded. (B) Table expressing
minerals abundance in area percent. (C) 30 mm diameter epoxy plug.
A B
C
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Plate 4.16: QEMSCAN data for the sample SUB 22. (A) QEMSCAN image with minerals colour coded. (B) Table expressing
minerals abundance in area percent. (C) 30 mm diameter epoxy plug.
A
C
B
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C
A
B
Plate 4.17: QEMSCAN data for the sample SUB 11. (A) QEMSCAN image with
minerals colour coded. (B) Table expressing minerals abundance in area percent. (C) 30
mm diameter epoxy plug.
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CHAPTER 5
PALAEOCLIMATE AND
PALAEOENVIRONMENTAL
RECONSTRUCTION
147
PALAEOCLIMATE AND PALAEOENVIRONMENTAL RECONSTRUCTION
The analytical results of the bulk and clay mineral geochemistry and organic
geochemistry reported in this study permit the reconstruction of palaeoclimates and
palaeoenvironments of the studied Eocene sequences. The tectonic and climatic activities
greatly influence the depositional environments and preserve the proxy records of these
conditions in the sediments. The organic facies studies in association with the
understanding of mineral assemblages provide snapshots of the climatic and
environmental conditions that prevailed during the deposition of these shales.
In order to discuss the palaeoclimatic and palaeoenvironmental interpretations of
the studied sequences, it is pertinent to review the tectonics and climatic history which
prevailed during the unique climatic event that characterises the Early Eocene history.
5.1 Indian Plate Tectonics and Climatic Evolution
The northward flight of the Indian Plate and its collision with the Asian Plate
followed by the rise of the Himalaya and Tibetan Plateau are of fundamental importance
to understand the global tectonics, atmospheric circulation pattern, monsoonal
intensification, atmospheric and ocean water chemistry and global climate (Ramstein et
al., 1997; Zhisheng et al., 2001; Guo et al., 2002; Dupont-Nivet et al., 2007; Searle,
2013).
Massive carbonates and mixed carbonates-clastic rocks were deposited on the
Tethys Ocean floor before the India-Asia collision (Achharyya, 2007; Green et al., 2008).
Initial convergence caused the subduction of the Tethys Ocean ‘carbonate-rich’ crust
beneath the stable Asian Plate (Caldeira, 1992), leading to the metamorphic
decarbonation of the slab and degassing of the CO2 in to the atmosphere and also resulted
in the enormous release of methane stored as gas hydrates (Kerrick & Caldeira, 1994;
Kent and Muttoni, 2008). The release of CO2 continued till the Tethys Plate was
completely consumed at the onset of the continent–continent collision at 50 Ma and 24oN
latitude (Meng et al., 2012). This coincided with the zenith of extreme Early Eocene
global warming (Turner et al., 2014). The increase in the global temperature augmented
the metabolic processes in marine sediments (Zeebe, 2013) leading to the extensive
deposition of clay rich and organic rich shales in Southern Asia (Robert and Kennet,
1992; Speijer and Wagner, 2002).
148
5.2 Late Palaeocene – Early Eocene Climate
Understanding past climates provides a valuable perspective of current climatic
variations and future trends of climate changes that we foresee. The present
anthropogenic global warming trends parallel the climate of Palaeocene–Eocene times,
which caused the enormous release of carbon dioxide into the atmosphere-ocean system
leading to the dramatic increase in mean annual temperatures of between 5–8oC
(McInerney and Wing, 2011; Foreman et al., 2012).
The global climate during the Early Cenozoic was dominated by extreme warm
conditions which reached its acme at c. 50 Ma during the Early Eocene Climatic
Optimum (EECO) (Hodell et al., 2007; Kent and Muttoni, 2008). The EECO event was
preceded by several transient hyperthermal events, viz., PETM, also called ETM-1 (c.
55.9-55.7 Ma); Eocene Thermal Maximum 2 (ETM-2), also known as H-1 or Elmo Event
(c. 53.7 Ma); ETM-3 (c. 52.4 Ma ) and other small events (Cramer et al., 2003; Lourens
et al., 2005; Nicolo et al., 2007; Abdul Aziz et al., 2008; Sluijs et al., 2008; DeConto et
al., 2012; Ma et al., 2014) (Fig. 5.1). The perturbation during these thermal events was
due to the massive and rapid input of thousands of petagrams of isotopically depleted
carbon into the marine and terrestrial environments. This led to the prominent negative
carbon isotopic excursion (CIE) of the global exogenic carbon pool, which was found c. –
Figure 5.1: Major Early Palaeogene hyperthermal events recorded in the bulk carbon isotope
composition. (After Dickens, 2009; DeConto et al., 2012)
149
3.5‰ in the marine sediments (Kennett and Scott, 1991; Pak and Miller, 1992; Bains et
al., 1999; Thomas et al., 2002; Zachos et al., 2003) and –5‰ to –6‰ in the terrestrial
sediments (Koch et al., 1992 and 2003; Thomas and Shackleton, 1996; Bowen et al.,
2004; Bowen and Zachos, 2010). The causes of the Early Cenozoic hyper-thermals have
been vigorously debated. Various researchers have suggested different mechanisms
(ranging from bolide impacts to Milankovitch cyclicity) and sources (injection of magma
to metamorphic degassing) of CIE in the ocean – atmosphere systems (e.g. Cramer and
Kent, 2005; Kurtz et al., 2003; Svenson et al, 2004; Kerrick and Caldeira, 1994; Galeotti
et al., 2010; Eldrett et al., 2014 amongst others). Regardless of the source, the carbon
which was released altered the atmospheric and ocean water chemistry. The atmospheric
partial pressure of CO2 (pCO2) soured high during this time interval and reached the
estimated value of > 1,200 ppmv during the EECO (Royer et al., 2004; Lowenstein and
Demicco, 2006; McInerney and Wing, 2011; Foreman et al., 2012). This enormous
release of carbon altered the ocean carbon chemistry and increased the acidification by
lowering the pH. These changes led to the transient shoaling of lysocline and carbonate
compensation depth (CCD) upto 2000 m (Zachos et al., 2005) which caused around 30 to
50 % extinction of the deep-sea benthic foraminifera (Kennett and Scott, 1991; Thomas
and Shackleton, 1996; Alegret and Ortiz, 2006), evolutionary diversification of
planktonic foraminifera and dinoflagellate cyst blooms (Crouch et al., 2001). This led to
the deposition of organic and clay rich sediments along the Neo-Tethys peripheral
margins.
5.3 Clay Minerals as Palaeoclimate Proxies
The formation of clay minerals in the sedimentary rocks is controlled by tectonics,
climate, eustatic sea-level changes and provenance (Chamley, 1989; Bolle and Adatte,
2001; Ruffell et al., 2002). Studying clay mineral assemblages provides significant
insights into the processes that led to their formation, especially palaeotectonics and
palaeoclimate.
Kaolinite mineral generally forms due to the chemical weathering of parent rocks in
warm and humid climates in the tropical environment where the perennial precipitation is
high and soil temperature is > 15oC (Robert and Chamley, 1991; Hallam et al., 1991).
Kaolinite also forms due to the extensive leaching in the warm and highly precipitated
area where deep weathering is caused by sea-level fall (Robert and Kennett, 1992).
Kaolinite in marine sediments is also contributed by reworking of the older sediments
during the marine transgressions (Chamley, 1989) and due to the hydrothermal alteration
150
(Robertson and Eggleton, 1991). Illite, chlorite and feldspar are generally formed due to
physical erosion of the high relief areas, where the active mechanical erosion limits the
soil formation. These minerals usually develop in relatively cold, dry and arid
environments and are abundant at high latitudes (Chamley, 1989; Thiry, 2000). Illite also
forms due to diagenetic alteration of micas and feldspar in warm and humid conditions
(Birkeland, 1984). Chlorite mineral is environmentally sensitive and is unstable under
warm, humid and highly acidic environment. Therefore it persists only in arid and dry
climatic conditions. It also forms due to diagenetic alteration of kaolinite or smectite
(Pearson, 1990). Chamosite, an iron rich mineral of chlorite group, has been used as depth
indicator in the marine environments (Porrenga, 1967). It usually develops in the warm,
tropical nearshore marine environments where depth is shallower than 60 m, but may also
form up to the depth of 150 m. Warm bottom water conditions, with temperature > 20oC,
are essential for its formation. Smectite clays (most commonly montmorillonite and
bedellite) are commonly formed due to the chemical weathering of soil with high pH
within tropical to subtropical conditions (Borchardt, 1989, Robert and Kennett, 1992;
Sheldon and Tabor, 2009). Monsoon climate with seasonal precipitation provide ideal
conditions for smectite formation.
5.4 Cambay and Subathu Shales: Palaeoclimatic and Palaeoenvironmental
Scenarios
Based on the aforementioned literature review above, the data generated in the
present study contrives to ascertain the climatic conditions prevailing during the
deposition of the Cambay Shale and Subathu Fm shales. The XRD, QEMSCAN and
organic geochemical analyses provide significant insight into the palaeoclimatic and
palaeoenvironmental depositional scenarios of the two basins during the deposition of
these shales.
5.4.1 Cambay Shale
The clay mineral assemblages of Cambay Shale mostly comprise of kaolinite, illite,
chlorite and smectite. Kaolinite dominates in all the analysed samples suggesting warm
and humid depositional environment. Illite content is considerable suggesting relatively
cold, dry or desert climate with low temperatures and less rainfall (Millot, 1970;
Chamley, 1998). The presence of clay mineral assemblages reflecting two contrasting
humid and arid conditions in the same samples is conflicting and ambiguous. Therefore,
kaolinite–illite (K/I) ratio has been used as the humidity index and to interpret the
climatic and sea-level changes (Chamley, 1989; Curtis, 1990; Thiry, 2000). The K/I ratio
151
in the Cambay Shale samples is mostly high, suggesting warm and humid conditions.
However, few samples from JU3 well (from deeper depth) show low K/I ratio indicating
the semi-arid condition. The samples from the Mangrol Lignite Mine show significant
percentages of montmorillonite. Schultz (1963) is of the opinion that in situ
montmorillonite is a good indicator mineral of seasonal climate variations. The presence
of montmorillonite in the Mangrol samples is suggestive of the tropical to subtropical
environment and the persistence of alternating wet and dry climate during the deposition
of these Younger Cambay Shale (YCS). The substantial percentages of chamosite present
in almost all analysed samples suggest that these shales were deposited in shallow, warm
water in nearshore environment. The results of the QEMSCAN analysis show the
presence of glauconite mineral in samples from JU1 and JU4 wells in addition to its
reported presence from the northern part of the basin (Raju, 1968). The presence
glauconite suggests the deposition of the sediments in offshore deeper water with
temperature lower than 15oC (Porrenga, 1967; Imenez-Millan et al., 1998). The presence
of chamosite in considerable quantity in all the Cambay Shale samples is related to their
deposition in shallower (< 60m depth) marine environment in tropical warm bottom water
conditions with the temperature > 25°C (Porrenga, 1967) and generally in slightly
alkaline to acidic, Fe rich reducing environment. Gypsum and anhydrite minerals are also
identified in low percentage in some of the samples suggesting occasional arid conditions
during their depositions.
The kaolinite distribution in the studied Cambay Shale samples deposited in
shallow deltaic environment indicates its formation during low as well as high sea-level
oscillating conditions. During the sea-level fall, the increased rate of precipitation under
the humid climatic conditions led to the erosion, transport and accumulation of kaolinite
in the basin. During the high sea-level kaolinite formation resulted due to the
remobilisation of formerly deposited kaolinite in the older sediments and soil.
5.4.2 Subathu Fm Shale
The clay mineral assemblages of the Subathu Fm Shales from seven different
sections is mainly composed of kaolinite and illite, with some samples showing the
presence of mica (muscovite) and chamosite (see the mineralogy table). The kaolinite-
illite (K/I) ratio is very high in the shale samples from the basal part of the Subathu Fm
suggesting extremely warm and humid climate. The K/I ratio decreases up-section,
showing an increase in the percentage of illite. The samples from Manma section and the
core samples of the younger strata from the shallower depth of Mahogala borehole show
152
low K/I ratio, where illite content in these samples exceeds the kaolinite content. This
suggests dry and arid climate during the deposition of these shales. The presence of
chamosite suggests that the samples were deposited in shallow, warm and acidic
nearshore marine environment.
The kaolinite mineral distribution pattern varies over the entire Subathu Fm shale
sequences. The basal Subathu Fm Shale sequence shows very high percentage of
kaolinite and its value diminishes up-section. The gradual decrease in kaolinite
percentage is compensated with the corresponding increase in quartz content in the
middle and top facies. This indicates that the basal part of the Subathu Fm black facies
sequence was deposited in the extremely warm and humid environment in paralic,
marginal marine conditions on the platform margin of the northward moving Indian Plate.
The high quartz content in the younger facies of the Subathu Fm indicates the sea-level
fall and erosion of terrigenous silica rich nearshore sediments in the source area. The
climate gradually changed from humid to arid conditions as is indicated by the increase in
the percentage of terrigenous input of quartz in the middle and top facies of the sequence.
5.4.3 Palaeoenvironmental Considerations
The organic geochemical and visual kerogen contents are suggestive of the
dominance of terrestrial organic matter with the minor input of telalginite (Botryococcus)
to the Cambay Shale and the Subathu Fm shales (e.g. Prasad and Sarkar, 2000). The
elevated terrestrial runoff resulted in water column stratification and also in low salinities
and eutrophic conditions (Pagani et al., 2006; Sluijs et al., 2006 and 2008; Harding et al.,
2011). The dinocysts and palm-dominated floral assemblages in the Cambay Shale (Sahni
et al., 2006; Rao et al., 2013) indicate the prevalence of tropical to sub-tropical climate
during their deposition. The rich assemblages of Palmae family along with the minor
contribution of dinocysts assemblages and foraminiferal lining (Singh, 2007) in the
Subathu Fm shale samples also suggest tropical to sub-tropical climatic condition.
Deposition of Cambay Shale and Subathu Fm shales in anoxic, deep-water facies is
strongly supported by the presence of pyrite and siderite minerals in the analysed
samples. The Cambay Shale samples from JU3 well show the abundance of siderite
suggesting low sulphate waters and strongly reducing conditions in the methanogenic
zone (Berner, 1981). Authigenic pyrite is common in both the studied shale formations
and occurs both in framboidal and disseminated forms. The samples from the Mangrol
Lignite Mine show the abundance of framboidal pyrites, which are smaller and less
variable in size suggesting anoxic bottom water conditions (Wilkin et al., 1996;
153
Roychoudhury et al., 2003). These framboids form during the bacterial sulphate reduction
(Berner, 1981 and 1984) in the stratified anoxic water column and sink to the sea bottom.
The large size nodular pyrite is present in the Subathu Fm Shales which may be
diagenetic in origin.
5.5 Discussions
The evidences from bulk organic geochemistry, whole rock geochemistry and clay
mineralogy are suggestive of hot and humid climate for the Cambay Shale and the basal
Subathu Fm during the Early Cenozoic hyperthermal events. These events led to warming
of ocean water by about 4° to 5°C at the tropics (Zachos et al., 2003; Jones et al., 2013).
This increase in temperature affected the oceanic bottom chemistry, carbonate
precipitation and circulation patterns. The increase in seasonal precipitation enhanced the
river runoff leading to the augmentation of productivity by rise in availability of nutrients
(Speijer and Wagner, 2002). This productivity caused the depletion of oxygen which
caused the stratification and local dysoxic conditions forming organically rich black
shales and coals along the North and West Indian Plate margins with excellent
conventional and unconventional hydrocarbon source potential (Fig. 5.2).
Figure 5.2: Palaeofacies and tectonic map of North India during Ypressian times
(modified after Golonka, 2009; Scotese, 2013).
154
The basal Subathu carbonaceous shale and coal horizons were deposited during the
transgression, causing drowning and subsidence of the cratonic passive margin and the
development of bioherm ramp carbonates (Bera et al., 2008). These organic rich horizons
were deposited under anoxic environment in close proximity to the terrestrial organic
matter source in paralic marginal marine conditions towards the craton (Fig. 5.2). The
clastic sediment influx came from the volcanic and low grade metamorphic sources in the
north. The sediments were also brought by marginal colluvial action towards the
forebulge.
The black carbonaceous Cambay Shale deposited during the large scale marine
transgression shows the presence of terrestrial and marine organic matter. These rocks
deposited in marginal marine to inner neritic bathymetry as evidenced by the occurrence
of mangrove palynotaxa (Strat columns in back leaf) (Grover et al., 2010). The coal and
lignite sequences seen in the Mangrol basin margins were deposited in deltaic and anoxic
environment (Fig. 5.3). The rivers flowing towards west and south-west brought the
sediments sourced from the Deccan Trap Basalt, the volcanic and metamorphic rocks of
the Aravalli-Delhi orogenic belt.
Figure 5.3: The model depicting the environmental scenario during the deposition of
Cambay Shale
155
The high percentage of organic matter in both the Cambay and the basal Subathu
Fm shales is related to the enhanced organic carbon content in the oxygen deficient
bottom waters. The organic rich, black Cambay Shale was deposited during the PETM
(Samanta et al., 2013) while the samples from the Lignite Mine in the southern part of the
basin suggest the deposition of Cambay Shale during the ETM2 (Clementz et al., 2011).
This formation was deposited near the equator in hot and humid tropical climate in the
acidic and low salinity oceanic water. The abundance of kaolinite mineral in the basal
Subathu Fm suggests the perennial monsoon type rainfall which favoured the extensive
leaching of the source rock. The clay mineral assemblages and presence of palynomorphs
of Palmae family (Singh, 2007) suggest the prevalence of tropical to subtropical climate
(Fig. 5.4). This climatic condition is in synchroneity with the extremely hot and humid
global climate that persisted during the Early Eocene Climatic Optimum (EECO). The
gradual decline in the kaolinite content and the corresponding increase in the silica
content from base to the top depict the change from the humid to arid climate.
The Himalayan and Tibetan uplift and the intensification of seasonal monsoon
systems induced erosion weathering of tectonically uplifted rocks in the collision zones
(Raymo and Ruddiman, 1992; France-Lanord and Derry, 1997) and that of Indian
Figure 5.4: The model depicting the environmental scenario during the deposition of basal
Subathu Fm.
156
continental crust, which resulted in the drawdown of atmospheric pCO2 concentration
since the Middle Eocene (Kent and Muttoni, 2008). The intense terrestrial weathering of
the Deccan Trap basalts in the Indian subcontinent also acted as important carbon sink
(Kent and Muttoni, 2008). The deposition of organic matter rich sediments along the
Tethyan continental margins during the Early Eocene times also played a significant role
in carbon sequestration (Speijer and Wagner, 2002; Schulte et al., 2011) during the Early
Palaeogene hyperthermal events.
In conclusion, the clay mineralogy and organic geochemical studies suggests that
the Cambay and basal Subathu shale sequences were deposited in hot and humid tropical
to subtropical climatic conditions during the tectonic convergence of Indian Plate. These
sequences were deposited in marginal marine acidic and low salinity water during the
Early Palaeogene hyperthermal events which culminated in EECO.
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CHAPTER 6
SUMMARY AND
CONCLUSIONS
158
6. SUMMARY AND CONCLUSIONS
Eocene shales of the Cambay Basin, Gujarat and HFB from Jammu region were
examined for in-depth understanding of their shale gas/oil potential. The reason of
selecting these two shale units from the two basins was to compare and contrast the
critical geological, geochemical and petrophysical attributes of the Subathu Fm shales
with the proven conventional source rocks of the Cambay Basin. Although these shale
formations were deposited in different tectonic regimes, their climatic and environmental
scenarios were similar during their deposition in Early Palaeogene. The ultimate aim of
the current research is to develop geologic models depicting origin, distribution,
depositional setting and shale gas source and reservoir potential of the target shales.
The Cambay Shale of Late Palaeocene to Early Eocene was deposited during the
second rift phase in the basin which led to the subsidence and marine transgression hence
the formation of carbonaceous shale with a few interbedded siltstone streaks. The
Subathu Fm was deposited during the Late Palaeocene to Middle Eocene in the HFB. It is
comprised of basal carbonaceous shale and coal deposited in swampy to marginal marine
facies. The middle intra-shelf lagoonal facies consists of intercalating green shale and
limestone, while the top delta plain and tidal flat facies consists of red, bioturbated fine-
grained sandstones, siltstones and mudstones.
Although the source potential of the Cambay Shale and Subathu Fm shales has been
proved, the reservoir quality and other basic geochemical data important for shale gas
evaluation are virtually unknown. The current research thesis embodies the analytical
results of the Eocene samples collected from Cambay Basin and HFB hosting shale
horizons. The Cambay Shale and Subathu Fm shales were studied to assess their source
and reservoir properties and to establish their unconventional hydrocarbon resources
potential.
The source potential of the selected shale formations was determined by performing
the sophisticated geochemical analyses which include Visual Kerogen Analysis (VKA)
and vitrinite reflectance, TOC and Rock Eval Pyrolysis; and Gas Chromatographic (GC)
studies. The Cambay Shale shows the dominance of vitrinite, and also alginite and other
liptinite macerals indicating the organic facies Type BC and C deposited in dysoxic
bottom water conditions during transgression. Moreover, the high TOC and moderate HI
values of the Cambay Shale are consistent with organic facies Type BC and C. The
159
presence of terrestrially derived gas prone organic matter (kerogen Type III) coupled with
inertinite macerals suggest that they were deposited in close proximity of the source in
lower deltaic plain environment. The high content of Botryococcus braunii (maceral
telalginite) in addition to the oil prone marine influenced (kerogen Type II) and vitrinite
(Type III) macerals in JU4 and JU5 samples indicate limnic/brackish type of environment
during sedimentation. Vitrinite reflectance and the fluorescence colour of some of the
liptinite macerals in the Cambay Shale samples indicate main zone of oil generation. The
Mangrol Lignite Mine samples from the basin margin in the Narmada Block show low Ro
values suggesting immature organic matter in early diagenetic stage.
The basal Subathu Fm shale samples are exclusively dominated by higher plant
derived gas prone vitrinite organic matter and also inertinite macerals indicating organic
facies C deposited in close proximity to the source (e.g. swamp forest) in paludal
environment. These samples are thermally overmature and exhibit the high reflectance
values ranging from 1.16% to 1.65% suggesting wet gas to dry gas generation zone.
The Rock Eval Pyrolysis results of the Cambay Shale samples show fair to
excellent source potential, with an average TOC value of 2.43 wt. %. The data also
indicate that these shales are dominated by type III kerogen. The significant percentage of
type II kerogen is present in Ahmedabad-Mehsana Depression. The Tmax and calculated
Ro values again suggest that this formation is thermally mature and in oil generation
window. The organic richness of the Cambay Shale is more towards the northern part of
the basin and thermal maturity increases with the increasing depth and the shale units are
more mature in the Broach Depression. The high maturation is driven by high thermal
gradient and high heat flow in the region caused due to the mantle upwarping and
shallowing of the Moho Discontinuity that provided the additional favourable geological
setting for the source rock maturation and hydrocarbon generation. The samples from the
Mangrol Lignite Mine in the Narmada Block are immature but show good hydrocarbon
generation potential. The high organic richness and moderate HI values of the Cambay
Shale reflect characteristics of organic facies type BC and C, deposited in marginal
marine to deltaic dysoxic to anoxic bottom water conditions.
The basal Subathu Fm shales and coaly shale samples show very high TOC content
(with an average value of 7.5 wt. %), suggesting good hydrocarbon generation potential.
These rocks are dominated by Type III gas prone kerogen with the preponderance of
160
vitrinite and inertinite matching with the organic facies type C. The organic matter in
these shales is dominated by gas prone Type III terrestrially derived organic matter which
is hydrogen poor, the HI values are low indicating gas generation potential. The thermal
maturity assessed from Tmax and measured and calculated vitrinite reflectance shows the
post mature stage of organic matter. The higher maturation of the basal Subathu Fm
shales is attributed to the skin frictional heat generated due the tectonic deformation along
the thrusted contact. The higher maturation can also be attributed to the high geothermal
gradient observed in the drilled wells (Mittal et al., 2006). The younger grey and red
facies sediments are organically lean and show an immature stage of the organic matter.
The facies studies of the basal Subathu Fm suggests that these rocks were deposited in
close proximity to the source (e.g. swamp forest) in paralic/paludal, strandline marginal
marine conditions on the platform margin of the northward moving Indian Plate.
The Gas Chromatography-Flame Ionization Detection (GC-FID) analysis of the
Cambay Shale and Subathu Fm shales was performed to investigate the acyclic
isoprenoids which help in understanding the source, maturity and biodegradation of
organic matter in the selected source rock samples and their depositional environment.
The Cambay Shale samples show very high Pr/Ph ratio values indicating non-marine oxic
depositional environment. The high ratio can be attributed to the abundance of
terrestrially derived Type III kerogen and higher thermal and geochemical alteration of
the organic facies at the greater depth. The samples from the Mangrol Lignite Mine show
low Pr/Ph ratio suggesting strongly reduced marine/brackish environment. These samples
also show very high degree of biodegradation.
The Subathu Fm shale samples show the erroneous results, most probably due to
the contamination with some chemicals and plastics and the samples are highly
biodegraded. Therefore, the Pr/Ph ratios of these samples were not ascertained.
Numerous gas seeps have been observed towards the north of the Riasi Inlier where
the Chenab River veers its course (forming a drainage anomaly) along the back-thrusted
contact between the Subathu Fm and the Sirban Limestone Fm. The gas samples were
collected from the Chenab River bed near Kanthan and analysed for bulk chemical and
isotopic composition (CH4, CO2, N2) in order to characterise its origin. The analytical
results suggest that the gas is enriched in methane of mixed thermogenic and biogenic
origin. The composition of nitrogen suggests the atmospheric contamination of the
161
samples during the gas sampling. The Subathu Fm shales are considered to be the likely
source of the gas.
Petrophysical analyses through XRD, SEM and QEMSCAN were done to evaluate
their reservoir potential. The XRD generated data show that clays form the major
constituents of the Cambay Shale and Subathu Fm shales. The most abundant minerals of
Cambay Shale are kaolinite, illite and quartz with an average content in excess of 33 wt.
%, 15 wt. % and 11 wt. % respectively. Chlorite group minerals, feldspars and pyrite are
next in abundance. Other minerals which include montmorillonite, gypsum, calcite and
siderite are present in minor amounts. The abundance of kaolinite and illite minerals
indicate that the source of sediments was mainly Deccan Trap Basalt in the east and
volcanic and metamorphic rocks of the Aravalli-Delhi orogenic belt in the northeast.
The basal Subathu Fm rocks are dominated by the clay minerals, mostly kaolinite
and its concentration is highest in the samples from Mahogala Mine. The percentage of
clays decreases up-section and the younger shales show lesser clay and more silica
content. Bulk of the clay minerals has been transported from the source area in the north,
where the volcanic arc and ultramafic rocks are considered as the possible source of
sediments. The southerly derivation of sediments is another possibility, where the Deccan
Trap basalt is the likely source of these sediments.
The reservoir potential of shales depends on its brittleness which is largely
controlled by the mineralogy. The proportion of quartz relative to clay and carbonate in
the shale samples has been used to determine the brittleness index (BI) (Jarvie et al.,
2007). The Cambay Shale samples are clay rich and show very low BI with an average
value of 0.15. However, the shales from Tarapur Sub-basin indicate low clay content and
high carbonate and silica content (Oilex, 2010 and 2014). The basal Subathu Fm shale
samples are also clay dominated and therefore show low BI values (<0.4) as compared to
the samples from the overlying younger rocks. The younger shales show the BI values
higher than 0.5, suggesting good fracability potential.
The abundance of clay minerals is one of the numerous causes of abnormally high
pore-fluid pressures (over pressures) in the shale reservoirs (Tingay et al., 2009). The
Cambay Shale is moderately over pressured and is around 5000 psi or 34 MPa (Oilex,
2010 and 2014). The over pressures are interpreted to be due to hydrocarbon generation
162
during thermal evolution and clay dehydration. The pressures in the Eocene Subathu Fm
shales are also abnormally high (Law et al., 1998; Mittal, et al., 2006) which are
attributed to a combination of tectonic compression, clay dehydration and hydrocarbon
generation.
The GPESGSTM
was used to estimate volume of gas-in-place and storage
mechanisms in the target shales. The Cambay Shale shows methane capacity of 170
scf/ton (standard cubic feet per ton) total gas-in-place. Free gas form dominant
component (140 scf/ton) of total GIP. Due to high pressures, most of the gas is present in
the free spaces of pores and natural fractures. Very less amount of gas is found to be
adsorbed on the organic matter. The Subathu Fm shales show the GIP of 400 scf/ton and
more than half of it is present as free gas.
The high amount of gas content present in both Cambay Shale and Subathu Fm
shales suggest excellent source potential of shale gas plays that could be hydraulically
stimulated and exploited by using the hydrofracking technology. The fracturing treatment
design depends on the mineralogical nature of the rock besides other important factors.
Since both Cambay Shale and Subathu Fm shales are clay rich, therefore cross-linked gel
treatment or methanol can also be used as base fluid for fracking (Lancaster et al., 1992;
Gandossi, 2013).
SEM imaging and bulk analysis were performed for the qualitative and quantitative
assessment of porosity and microstructures in the Cambay Shale and Subathu Fm shales
and the results show the abundance of interparticle, intraparticle mineral pores and
organopores. The intragranular organopores and intercrystalline intraparticle pores within
pyrite framboids and concretions are the primary contributors to the hydrocarbon storage,
flow and discharge in the Cambay Shale. In the Subathu Fm shales, the mesometer and
micrometer sized interconnected organopores are the main facilitators of effective gas
storage and also provide gas flow fairway.
The QEMSCAN analysis provided significant information regarding the quantity
and distribution of the mineral constituents in the studied shale samples. This analysis
shows the abundance of clay minerals in the studied formations. The Cambay Shale
samples show the patchy distribution of chlorite, smectite and illite minerals. Pyrite is
present in the samples in disseminated form as well as framboids and it suggests redox
163
potential supplied by reducing (anoxia) environment. The presence of glauconite in some
of the samples indicates calm marine, deep (>125 m) and cold bottom (<15oC) water
conditions (Porrenga, 1967; Imenez-Millan et al., 1998). The analysis also shows good
and sporadic distribution of organic matter and interparticle porosities. The Subathu Fm
shale samples show the dominance of kaolinite mineral suggesting nearby volcanic
source of sediments. The other minerals which are substantially present in these samples
include quartz, plagioclase, illite, and smectite.
The clay mineralogy and organic geochemical studies are of significant importance
in understanding and interpreting the palaeoclimatic, palaeotectonic and
palaeoenvironmental conditions prevailing during sedimentation in a basin. The analytical
results suggest that the Cambay Shale was deposited near the equator in hot and humid
tropical climate during the PETM and ETM2 (Clementz et al., 2011; Samanta et al.,
2013) in the acidic and low salinity oceanic water. The kaolinite distribution in the
Cambay Shale samples reflects deposition in shallow deltaic environment during low and
high sea-level conditions. During the sea-level fall, the increased rate of precipitation
under the humid climatic conditions led to erosion, transport and accumulation of
kaolinite into the basin. The occurrence of kaolinite in the sediments during the high sea-
level is due to the remobilisation of formerly deposited kaolinite in the older sediments.
The coal and lignite sequences seen in the Mangrol basin margins were deposited in
deltaic and anoxic environment
The Clay mineralogy and organic geochemical analytical results of the Subathu Fm
shales indicate that the basal part of the Subathu Fm black shales were deposited in the
extremely warm and humid environment during EECO in paralic, marginal marine acidic
conditions. The high humid climate is attributed to the metamorphic decarbonation of
pelagic Tethyan oceanic crust that subducted during the tectonic convergence of Indian
Plate. The high quartz content in the younger facies of the Subathu Fm indicate the sea-
level fall, resulting in intense erosion of terrigenous silica rich sediments in the source
area. The climate gradually changed from humid to arid conditions as indicated by the
increase in the percentage of terrigenous input of quartz in the middle and top shale units.
The two selected shale formations from two different sedimentary basins varying in
size and tectonic setting were deposited in similar climatic and depositional environment
in tropical and sub-tropical conditions during the Early Palaeogene hyperthermal events.
164
Detailed geochemical analyses indicate a predominance of terrestrial (Type III) kerogen
in both shale units, with maturity ranging from oil, to wet- and the dry gas window. The
thermal maturity of Cambay Shale is high in the basinal depression towards the southern
part. The organic content and thermal maturity in Subathu Fm shales diminishes up-
section in the younger shale units.
The mineralogical studies of both the target shales show dominance of clay
minerals deposited in warm and humid tropical to subtropical climates. The mineralogy
of the Cambay Shale varies throughout the basin and is silica and carbonate rich in
Tarapur Sub-basin. The Subathu Fm shales show high clay content in the basal shales and
enrichment of silica in the younger shale units with good fracability potential. The high
clay content in both the cases suggests that the cross-linked gel treatment or methanol
would be favourable for fracturing treatment design. Shale characterisation studies on
selected samples revealed excellent micro- and nanoporosity related to a mix of
intercrystalline, intraparticle, organic matter and microfractures. These shales also show
high gas content present in the free pore spaces and also in adsorbed form on the organic
matter.
The geological, geochemical, and petrophysical analyses conducted on the Cambay
Shale and the Subathu Fm shale samples reveal the Cambay Shale with favourable source
rock parameters, fracability potential and well infrastructure, making it the most potent
target for unconventional shale exploration. The Subathu Fm shales in the HFB, with all
essential source and reservoir parameters necessary for shale gas exploration has
remained underexplored, and therefore can be considered a frontier target for shale gas
exploration.
165
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202
APPENDICES
203
Appendix A – Analysed Samples Lists and Codes
Eocene Cambay Shale samples list and codes
Sample ID Loca Coordinates Codes XRD Ro RE GC QEMSCAN/
SEM
A 1305-1310 JU1 N 22°56'27.16'', E 72°25'53.13'' CAM1 *
*
A 1325-1330 JU1 Do CAM2 *
*
*
A 1350-1355 JU1 Do CAM3 * * * *
A 1365-1370 JU1 Do CAM4 *
*
B 1495-1500 JU2 N 22°09'23'', E 72°19'2'' CAM5 *
*
B 1700-1705 JU2 Do CAM6 *
*
B 1795-1800 JU2 Do CAM7 *
* *
B 1800-1805 JU2 Do CAM8 * * *
*
C 2180-2185 JU3 N 22°18'16.4'', E 72°40'55.5'' CAM9 *
*
C 2250-2253 JU3 Do CAM10 *
*
C 2280-2285 JU3 Do CAM11 *
*
C 2310-2315 JU3 Do CAM12 *
*
D 1665-1670 JU4 N 21°35'9.5'', E 72°50'34.9'' CAM13 * * * *
D 1710-1715 JU4 Do CAM14 *
*
D 1945-1950 JU4 Do CAM15 *
*
D 1975-1980 JU4 Do CAM16 *
*
*
19512S1a JU5 N 21°27.000', E 73°07.923' CAM17 *
19512S1d JU5 Do CAM18 *
19512S1e JU5 Do CAM21 * * * *
19512S1i JU5 Do CAM22 *
*
19512S1j JU5 Do CAM20 *
19512S1k JU5 Do CAM19 * * * * *
19512S1l JU5 Do CAM23 *
204
19512S1m JU5 Do CAM26 *
*
19512S1n JU5 Do CAM24 *
19512S1o JU5 Do CAM25 *
19512S1p JU5 Do CAM27 *
*
205
Eocene Subathu Fm samples list and codes
Sample ID Section Coordinates Code XRD Ro RE GC QEMSCAN/
SEM
8512S1b Beragua (BRG) 33°13.681' N, 74°24.077' E SUB1 *
*
8512S1c Beragua (BRG) 33°13.681' N, 74°24.077' E SUB2 * * *
8512S1d Beragua (BRG) 33°13.681' N, 74°24.077' E SUB3 *
* * *
28312S3b Tatapani (TTP) 33°14.583' N, 74°24.780' E SUB4 *
*
28312S6c Tatapani (TTP) 33°14.583' N, 74°24.780' E SUB5 * * *
*
29312S4a KalaKot (KLK) 33°12.979' N, 74°25.011' E SUB6 * * *
30312S4a Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB7 *
*
30312S4c Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB8 *
*
9512S1b Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB9 * * *
9512S1f Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB10 *
*
9512S1i Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB11 *
* * *
8512S3a Chakkar (CKR) 33°10.661' N, 74°35.628' E SUB12 *
*
8512S3c Chakkar (CKR) 33°10.661' N, 74°35.628' E SUB13 *
*
8512S3d Chakkar (CKR) 33°10.661' N, 74°35.628' E SUB14 *
*
8512S3f Chakkar (CKR) 33°10.661' N, 74°35.628' E SUB15 *
*
12SEP11S1c Chakkar (CKR) 33°10.661' N, 74°35.628' E SUB16 *
*
12SEP11S1d Chakkar (CKR) 33°10.661' N, 74°35.628' E SUB17 * * *
9512S2a Salal (SLL) 33°9'46.15'' N, 74°49'3.13'' E SUB18
*
12SEP11S1e Chakkar (CKR) 33°10.661' N, 74°35.628' E SUB19 *
12SEP11SR5 Sangar Road (SNG) 33°09.589' N, 74°36.720' E SUB20 *
8SEP11S7a Chhaparwari (CHP) 33°11'37.95'' N, 74°35'52.34'' E SUB21 *
8SEP11S7b Chhaparwari (CHP) 33°11'37.95'' N, 74°35'52.34'' E SUB22 *
* *
8SEP11S11al Chhaparwari (CHP) 33°11.550' N, 74°35.903' E SUB 23 *
8SEP11S11au Chhaparwari (CHP) 33°11.550' N, 74°35.903' E SUB24 *
206
8SEP11S11d Chhaparwari (CHP) 33°11.550' N, 74°35.903' E SUB25 *
9512S1a Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB26 *
9512S1d Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB27 *
9512S1e Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB28 *
9512S1g Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB29 *
9512S1h Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB30 *
30312S4b Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB31 *
30312S4d Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB32 *
C1 94 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB33 *
C2 135-160 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB34 *
C5 202 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB35 *
C8 335-340 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB36 *
26312S6b Manma (MNM) 33°14.543' N, 74°22.699' E SUB37 *
27312S2e1 Manma (MNM) 33°14.538' N, 74°22.863' E SUB38 *
27312S2e3 Manma (MNM) 33°14.538' N, 74°22.863' E SUB39 *
27312S2d Manma (MNM) 33°14.538' N, 74°22.863' E SUB40 *
27312S4 Manma (MNM) 33°14.530' N, 74°22.749' E SUB41 *
27312S5 Manma (MNM) 33°14.530' N, 74°22.749' E SUB42 *
29312S4b KalaKot (KLK) 33°12.979' N, 74°25.011' E SUB43 *
29312S4c KalaKot (KLK) 33°12.979' N, 74°25.011' E SUB44 *
8512S1a Chakkar (CKR) 33°13.681' N, 74°24.077' E SUB45 *
28312S6b Tatapani (TTP) 33°14.551' N, 74°24.612' E SUB46 *
28312S6e Tatapani (TTP) 33°14.551' N, 74°24.612' E SUB47 *
28312S13 Tatapani (TTP) 33°14.339' N, 74°23.663' E SUB48 *
C8335-340 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB36
*
C7305 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB49
*
207
C6207-212 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB50
*
C5202 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB35
*
C2135-160 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB34
*
C1-94 Mahogala (MBH1) 33°12.364' N, 74°30.271' E SUB33
*
30312S4A Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB7
*
30312S4C Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB8
*
30312S4B Mahogala (MHG-M) 33°12.459' N, 74°30.127' E SUB31
*
29312S2A Manma (MNM) 33°13'40.82'' N, 74°24'4.56'' E SUB55
*
28312S13 Khargla (KHAR) 33°14.339' N, 74°23.663' E SUB48
*
29312S2D Beragua (BRG) 33°13'40.82'' N, 74°24'4.56'' E SUB57
*
29312S2C Beragua (BRG) 33°13'40.82''N, 74°24'4.56''E SUB62
*
29312S4C Kalakot (KLK) 33°12.979' N, 74°25.011' E SUB44
*
29312S4A Kalakot (KLK) 33°12.979' N, 74°25.011' E SUB6
*
7A/7 Jan 2 Kalakot (KLK) 33°13'00.71'' N, 74°24'58.35'' E SUB61
*
28312S6D Tatapani (TTP) 33°14.551' N, 74°24.612' E SUB56
*
28312S6B Tatapani (TTP) 33°14.551' N, 74°24.612' E SUB46
*
28312S6C Tatapani (TTP) 33°14.551' N, 74°24.612' E SUB5
*
28312S6A Tatapani (TTP) 33°14.551' N, 74°24.612' E SUB72
*
28312S3C Tatapani (TTP) 33°14.583' N, 74°24.780' E SUB75
*
28312S3B Tatapani (TTP) 33°14.583' N, 74°24.780' E SUB4
*
28312S3A Tatapani (TTP) 33°14'35.01'' N, 74°24'46.66'' E SUB65
*
11SEP11S6CM Chapparwari (CHP-M) 33°10'55.58'' N, 74°35'40.07'' E SUB53
*
11SEP11S4 Chapparwari (CHP-M) 33°10'39.32'' N, 74°35'41.03'' E SUB58
*
11SEP11S2CM Chapparwari (CHP-M) 33°10'37.57'' N, 74°35'37.57'' E SUB74
*
11SEP11S4LW Chapparwari (CHP-M) 33°10'39.32'' N, 74°35'41.03'' E SUB76
*
24G Salal (SLL) 33°11'38.03'' N, 74°35'47.00'' E SUB66
*
20FG Salal (SLL) 33°09'49.51'' N, 74°49'1.08'' E SUB63
*
208
20FA Salal (SLL) 33°09'46.84'' N, 74°49'3.05'' E SUB68
*
20FC Salal (SLL) 33°09'46.84'' N, 74°49'3.05'' E SUB73
*
17DE Sukhwalgali (SKW) 33°03'11.07'' N, 74°58'37.80'' E SUB54
*
17DF Sukhwalgali (SKW) 33°02'57.49'' N, 74°58'49.02'' E SUB60
*
17DI Sukhwalgali (SKW) 33°02'54.25'' N, 74°58'49.55'' E SUB67
*
31312S17A Sangar Road (SNG) 33°09'31.73'' N, 74°36'49.68'' E SUB51
*
5E Kanthan (KNT) 33°10'32.78'' N, 74°50'59.34'' E SUB69
*
221111S10C Bakkal (BKL) 33°08'28.20'' N, 74°54'16.59'' E SUB70
*
1412S13B Ransoo (RNS) 33°08'08.03'' N, 74°37'25.91'' E SUB71
*
15OH1 Kalimitti (KLM) 33°05'25.21'' N, 74°57'51.69'' E SUB52
*
31B Muttal (MTL) 32°59'31.49'' N, 75°02'12.56'' E SUB59
*
12SEP11S1b Chakkar (CKR) 33°10'40.11'' N, 74°35'37.57'' E SUB64
*
Borehole Sample ID Depth (m) Coordinates XRD RE
BBHA A16 5 33°13.681' N, 74°24.077' E * *
BBHA A15 6 33°13.681' N, 74°24.077' E * *
BBHA A11 14 33°13.681' N, 74°24.077' E * *
BBHA A10 14 33°13.681' N, 74°24.077' E * *
BBHA A9 15 33°13.681' N, 74°24.077' E * *
BBHA A8 16 33°13.681' N, 74°24.077' E * *
BBHA A7 16 33°13.681' N, 74°24.077' E * *
BBHA A6 16 33°13.681' N, 74°24.077' E * *
BBHA A5 17 33°13.681' N, 74°24.077' E * *
BBHA IF9 21 33°13.681' N, 74°24.077' E * *
BBHA IF8 22 33°13.681' N, 74°24.077' E * *
BBHA IF7 24 33°13.681' N, 74°24.077' E * *
BBHA IF6 25 33°13.681' N, 74°24.077' E * *
209
BBHA IF5 30 33°13.681' N, 74°24.077' E * *
BBHA IF4 31 33°13.681' N, 74°24.077' E * *
BBHA IF3 33 33°13.681' N, 74°24.077' E * *
BBHA IF2 42 33°13.681' N, 74°24.077' E * *
BBHA IF1 43 33°13.681' N, 74°24.077' E * *
BBHA A3 46 33°13.681' N, 74°24.077' E * *
BBHA A2 47 33°13.681' N, 74°24.077' E * *
210
Appendix B – Gas Chromatography Samples and Extract Details
Sample
ID
Powdered
Sample
Weight
Big Vial
Weight
Small
Autosample
Vial Weight
Small Autosample
Vial + Extract
Weight
Extract
Weight
Big Vial +
Extract
Weight
Extract
Weight
Total
Extract
CAM 3 17.1331 8.2012 2.4368 2.438 0.0012 8.2146 0.0134 0.0146
CAM 7 19.8931 8.1341 2.4642 2.4645 0.0003 8.1413 0.0072 0.0075
CAM 13 10.9741 8.1193 2.475 2.4759 0.0009 8.1259 0.0066 0.0075
CAM 19 11.7346 8.1301 2.4508 2.4522 0.0014 8.1259 0.047 0.0484
CAM 21 21.4244 8.0958 2.4597 2.461 0.0013 8.109 0.0132 0.0145
SUB 3 60.3019 8.1286 2.4674 2.4682 0.0008 8.154 0.0254 0.0262
SUB 11 33.0992 8.1296 2.4531 2.4637 0.0006 8.1347 0.0051 0.0057
SUB 22 41. 9540 8.1346 2.4194 2.4195 0.0001 8.1357 0.0011 0.0012
211
n- C10 n- C11 n- C12 i- C13 i- C14 n- C13 i- C15 n- C14 i- C16 n- C15 n- C16 i- C18 n- C17 pr n- C18 ph n- C19 n- C20 n- C21 n- C22 n- C23 n- C24 n- C25 n- C26 n- C27 n- C28 n- C29 n- C30
CAM3 Area 6.66 15.62 16.57 5.46 5.93 17.77 11.47 23.90 19.66 27.13 23.25 38.41 30.46 119.45 25.02 19.19 25.03 32.02 28.48 27.17 25.22 16.70 13.91 10.47 14.95 12.81 36.85 22.55
CAM7 Area 22.97 49.93 61.81 14.23 22.05 67.10 15.08 82.96 30.79 76.47 86.22 57.17 116.91 95.76 78.52 13.02 70.39 86.59 86.02 92.71 91.08 67.71 68.97 56.45 66.71 45.77 42.87 27.53
CAM13 Area 14.39 36.71 52.65 16.76 32.95 63.64 41.09 75.38 50.20 75.61 66.94 241.73 90.12 158.81 60.80 22.53 54.96 69.23 59.83 65.86 53.92 44.79 43.46 40.01 45.26 40.24 49.65 37.72
CAM17 Area 0.02 0.11 5.28 0.30 0.76 0.90 1.53 1.66 2.57 0.70 1.16 5.89 1.22 12.15 1.55 20.79 1.26 1.14 2.06 6.95 1.65 5.32 2.44 1.20 5.88 3.52 13.79 5.83
CAM18 Area 0.05 0.25 0.73 0.68 1.08 1.63 5.86 3.67 6.38 3.74 4.82 7.59 5.70 49.06 5.90 110.29 9.30 6.86 10.90 29.62 39.38 38.22 19.96 8.20 17.95 9.40 31.20 13.60
CAM3 Height 2.14 4.58 5.03 1.62 1.80 5.79 3.20 7.49 5.96 8.05 7.59 10.29 8.30 29.58 7.90 4.26 7.65 9.42 8.72 8.17 7.39 4.83 4.27 3.24 4.61 3.58 9.58 5.77
CAM7 Height 8.13 17.09 21.11 4.52 7.47 22.72 4.78 27.52 9.45 24.48 28.15 15.12 29.31 21.16 25.01 2.99 23.01 27.10 27.42 28.07 28.28 21.36 21.24 17.54 19.84 13.50 12.72 8.31
CAM13 Height 5.20 11.85 17.28 5.58 8.89 21.45 8.65 24.21 15.68 24.11 21.97 68.11 22.49 35.60 19.13 5.20 17.97 19.91 18.96 19.32 17.21 14.18 13.41 12.03 13.77 11.87 14.97 10.57
CAM17 Height 0.03 0.06 1.66 0.12 0.22 0.29 0.49 0.44 0.80 0.27 0.37 1.48 0.40 3.67 0.64 5.81 0.44 0.43 0.61 1.44 0.62 1.38 0.84 0.44 1.68 1.22 3.82 1.73
CAM18 Height 0.04 0.12 0.24 0.23 0.31 0.54 1.40 1.07 2.14 1.42 1.75 2.26 1.92 14.59 2.32 31.97 2.78 2.41 3.47 8.78 12.36 11.09 5.88 2.65 5.14 2.97 9.03 4.36
CAM3 RT 13.11 17.07 20.89 21.46 23.62 24.52 27.23 27.95 30.05 31.19 34.25 35.77 37.16 37.44 39.93 40.27 42.56 45.07 47.47 49.77 51.97 54.09 56.12 58.08 59.96 61.79 63.54 65.24
CAM7 RT 13.11 17.07 20.89 21.46 23.62 24.52 27.22 27.95 30.04 31.19 34.26 35.77 37.17 37.44 39.93 40.26 42.57 45.08 47.48 49.78 51.98 54.10 56.13 58.08 59.97 61.79 63.54 65.24
CAM13 RT 13.11 17.07 20.89 21.46 23.63 24.52 27.23 27.95 30.05 31.19 34.26 35.78 37.17 37.44 39.93 40.27 42.58 45.08 47.48 49.78 51.98 54.10 56.13 58.08 59.97 61.80 63.55 65.25
CAM17 RT 13.12 17.08 20.91 21.47 23.63 24.53 27.21 27.95 30.05 31.19 34.26 35.78 37.17 37.44 39.91 40.29 42.59 45.09 47.48 49.80 51.98 54.09 56.12 58.08 59.97 61.81 63.55 65.24
CAM18 RT 13.14 17.09 20.91 21.47 23.64 24.53 27.21 27.96 30.05 31.19 34.26 35.79 37.17 37.44 39.93 40.29 42.57 45.08 47.48 49.78 51.99 54.10 56.13 58.09 59.97 61.80 63.56 65.26
Appendix C – Complete Gas Chromatographic Data
212
Appendix D – Gas Chromatograms of the Analysed Cambay Shale and Subathu Fm
shale samples
213
214
215
Appendix E – Complete XRD data (with Kaolinite Illite (KI) Ratios) of the Analysed Cambay Shale and Subathu Fm Shale Samples.
Table. XRD results of the Cambay Shale samples
Code Illi Kaol KI Chlo Cham Mont Orth Qtz Musc Oligo Micr Alb Dol Side Cal Pyr Anh Gyp
CAM1 4.8 31.1 6.5
11.7 4.7 4.4 8.2 17.5
6.2
4.5 6.9
CAM2 26.9 45.6 1.7
12.3
11.8
3.4
CAM3 18.0 38.1 2.1
13.9 0.3 7.4 11.2
2.9
4.2 1.3 2.7
CAM4 18.6 52.3 2.8 1.0 10.2 4.7 2.9 7.8
0.4
2.2
CAM5 24.6 44.7 1.8
3.0 2.8 4.8 7.7
0.9 2.3 2.1 7.2
CAM6 16.7 60.3 3.6
6.8 0.2 2.8 3.3
0.9 1.3 4.9 0.5 2.3
CAM7 25.9 50.2 1.9
8.2
2.7 2.7
0.9 0.8 0.8 1.2 3.4 3.2
CAM8 30.1 42.7 1.4
8.6
6.2 5.0
1.1 0.1
2.7 3.6
CAM9 21.3 29.5 1.4
7.6 0.2 2.2 23.5
8.0 0.8
3.1 3.8
CAM10 24.0 19.5 0.8
8.4
5.5 26.4
6.9 1.4 1.7 1.7 4.4
CAM11 24.1 22.4 0.9
10.0 0.2 5.0 21.1
4.4 0.7 2.7 3.3 6.2
CAM12 13.1 31.7 2.4
5.6 1.9 3.9 14.7
2.2
15.7
2.2 3.6 5.4
CAM13 24.9 45.4 1.8
5.1 1.1 2.0 1.9
2.6
9.7
2.3 2.0 3.1
CAM14 13.9 48.7 3.5 3.1 5.9
3.9 2.9 5.4 2.6
0.7
1.0
2.1 5.4 4.2
CAM15 21.7 25.2 1.2 8.0 6.6
0.7 19.9 3.8 1.1
1.4
1.2
3.3 2.1 5.0
CAM16 11.6 21.4 1.8 7.4 6.7
3.5 14.9 21.3
0.1
1.0
3.3 2.8 5.9
CAM17 3.4 27.1 7.9
3.2 7.6 3.6 34.0 16.6
1.3 0.5
1.6 1.1
CAM18 7.5 32.1 4.3
7.1
3.3 21.9 7.9
0.4 0.6
11.0 8.2
CAM21 7.2 33.4 4.7
3.4 12.3 1.0 4.0 22.4
0.1
1.2 0.5 9.8
4.7
CAM22 10.2 31.5 3.1
6.7 21.0 3.5 3.4 8.8 15.7
1.0
3.5 0.6 7.5
2.3
CAM20 8.5 18.4 2.2
14.0
7.2 9.0 3.8
1.8
4.7 11.3 10.4
10.9
CAM19 7.8 5.7 0.7
10.6
0.1 6.4 3.6
0.2 0.6
7.2 57.7
CAM23 21.5 24.3 1.1
5.7 15.8
5.8 1.7
1.1
1.4
16.2
6.5
216
CAM26 8.3 41.9 5.0
8.7 10.4 8.7 3.7
3.6
1.3 5.2 1.0
7.1
CAM24 6.2 29.9 4.8
2.5 17.0 3.7 8.0 14.3
4.6
3.3
8.6
1.8
CAM25 7.3 29.6 4.0
6.4 20.2 1.4 3.4 8.3
2.3
1.6
10.8
8.7
CAM27 16.4 33.6 2.1
6.0 13.9 1.8 4.1 12.6
1.7
1.1 0.9 3.8
4.2
Table. XRD results of Subathu Fm shale samples
Section Code Illit. Kaol. KI Ratio Chlo. Cham. Mont. Ortho. Qtz. Musc. Alb. Side. Calc. Pyr. Gyp.
BRG SUB1 1.4 26.4 18.9 0.9
0.7 57.5 12.1 0.8
0.2
BRG SUB2 14.6 76.7 5.3
0.9
2.5 0.2 3.3 0.4
0.2 1.2
BRG SUB3 5.5 70.8 12.9
1.6
3.8 0.8 15.3 1.1
0.4 0.6
TTP SUB4 16.5 47.4 2.9
3.7
2.6 9.6 18.1
0.4 0.9 0.8
TTP SUB5 5.5 47.6 8.6
1.6
1.1 27.9 15.0
1.4
TTP SUB46 6.5 49.2 7.6
1.7
0.9 26.1 14.6
0.2 0.7
TTP SUB47 18.9 54.5 2.9
0.7
1.6 3.2 19.2
0.7 1.2
TTP SUB48 5.6 37.3 6.7
0.5
1.3 35.3 18.7
1.3
KLK SUB6 3.7 30.6 8.3
1.8
0.1 40.1 22.6
1.0
KLK SUB43 6.4 9.0 1.4
9.7
8.1 60.8 3.6
2.3
KLK SUB44 13.0 38.2 2.9
3.7
1.6 6.1 29.9
2.4
3.4 1.7
MHG SUB7 12.1 82.8 6.9
0.9
2.6 0.3
0.6
0.4 0.3
MHG SUB8 15.5 76.0 4.9
2.1
4.0 0.2
0.7
0.1 1.2
MHG SUB26 24.1 68.7 2.9
0.5
1.4 4.5
0.0
0.4 0.4
MHG SUB9 6.7 80.7 12.0
3.2
6.6
2.5
0.3 0.0
MHG SUB27 11.7 81.9 7.0
1.9
1.4 0.1
1.5
0.6 0.9
MHG SUB28 3.7 83.7 22.5
2.1
5.2 0.2
3.1
0.8 1.1
MHG SUB10 15.1 80.1 5.3
1.1
2.0 0.3
0.4
0.1 0.8
MHG SUB29 11.7 81.2 6.9
1.5
3.9 0.0
0.4
0.5 0.8
217
MHG SUB30 14.6 74.6 5.1
2.1
5.8 0.4
0.8
0.7 1.0
MHG SUB11 32.6 62.9 1.9
1.7
1.7 0.1
0.5 0.6
MHG SUB31 29.0 64.1 2.2
1.6
3.5 0.1
0.2
0.8 0.7
MHG SUB32 21.0 73.1 3.5
1.1
3.0 0.9
0.5
0.0 0.3
MBH SUB33 29.9 5.9 0.2
3.1
0.5 21.0
0.0
38.8 0.6
MBH SUB34 33.0 2.9 0.1
6.2
3.9 41.7
0.8
10.0 1.5
MBH SUB35 27.8 11.0 0.4 5.1 9.3
1.6 41.0
3.2 1.0
MBH SUB36 39.8 27.9 0.7 6.6 3.0
2.0 18.1
0.8 1.8
CHK SUB45 1.9 21.3 11.1 0.4
0.8 74.4 1.0 0.2
CHK SUB12 8.9 39.3 4.4 2.8 3.6
1.9 6.7 26.3 3.1 1.5 1.8 4.2
CHK SUB13 10.5 27.6 2.6
0.6
58.1
1.0 0.6 1.6
CHK SUB14 5.0 43.3 8.7
2.6
1.0 8.2 29.1 4.0 1.9 0.9 4.1
CHK SUB15 26.6 48.7 1.8
3.1
3.1 7.2 3.6 3.0 1.9 0.7 1.9
CHK SUB16 1.8 26.6 14.8
1.8 55.6 10.5 0.5 0.8 0.8 1.5
CHK SUB17 1.6 14.3 8.9
0.5
1.5 63.8 13.3 0.8 0.7 1.0 2.4
CHK SUB19 0.9 22.9 24.9
1.0
1.6 55.9 13.3 0.4 0.8 0.7 2.4
CHK SUB20 30.7 6.5 0.2
1.6
1.5 29.7 27.2
2.8
CHP SUB21 20.1 69.6 3.5
8.2
1.7 0.4
CHP SUB22 16.9 70.1 4.1
12.6
0.2 0.1
CHP SUB23 2.4 8.8 3.7
10.4
2.4 60.3 10.8
4.9
CHP SUB24 15.2 32.0 2.1
6.0
1.1 18.3 26.8
0.7
CHP SUB25 1.6 13.8 8.5
1.1
1.1 73.5 8.0
0.9
MNM SUB37 22.5 3.3 0.1
10.4
1.0 41.9 16.6
0.0
0.0 4.3
MNM SUB38 20.0 17.6 0.9
0.7 4.1 0.8 13.6 37.5
3.9 1.8
MNM SUB39 13.7 2.6 0.2
12.1
2.2 38.0 16.7
9.3 5.4
MNM SUB41 36.0 3.4 0.1
11.1
2.2 32.7 11.1
0.4 1.5 1.7
MNM SUB42 13.6 1.4 0.1
11.2
1.4 58.5 9.7
0.4 1.7 2.1
218
Table. XRD results of the Subathu Fm shale core samples from borehole BBHA
Code Depth
(m) Illi. Kaol.
KI
Ratio Halloy. Qtz. Anat. Calc. Dol. Side. Pyr. Pyrr. Magn. Zuny. Diasp. Bayrt.
A2 47 10.3 8.3 0.8 2.9 23.2 1.5 50
1.4 1.9 tr
A3 46 17.9 40.9 2.3
16.2 11.6 5
2.4
6
IF1 43 7.4 46.2 6.2
11.3 4.9 25.5
1.4
3.3
IF2 42 4.7 51.2 10.9
20.4 9.7 7.6
1.8
4.5
IF3 33 4.8 32.1 6.7 8.3 30.5 6.6
7.7
3 3.4 3.4 tr
IF4 31 7.1 45.5 6.4
21.36 13.1 4.5
2.3
6.2
IF5 30 5.2 32.9 6.3
42.3 6.9 1.3
5.5 3.1
2.8
IF6 25 1.4 27.5 19.6 5.1 43.1 5.7 tr
3.4 4.6
5.2
3.3
IF7 24 14.7 27.9 1.9
40 8.9 1.2
1.8
5.6
IF8 22 1.5 12.3 8.2
27.7 1.9 22.2 33.2
1.3
IF9 21 6.9 16.5 2.4 9.7 46.2 6.7
2
3.3 6
2.9
A6 16 1.9 42.9 22.6 7.3 35 3.7
tr 3.9
5.5
A9 15 3.8 34 8.9
46.7 10
tr
4.6
A10 14 6.2 38.2 6.2
36.5 11.5
2.7
4.7
A11 14 tr 21.2 9.6 44.9 6.3
1.4
4.9 6.1 1.2 4.1
A15 6 1.1 19.3 17.5 4.7 45.8 2
22.4
tr
tr
4.8
A16 5 1.1 15.7 14.3
59.9 2 15.8 3.1
tr
2.1
Illi. – Illite, Kaol – Kaolinite, Halloy – Halloysite, Qtz – Quartz, Anat – Anatase, Calc – Calcite, Dol – Dolomite, Side – Siderite,
Pyr – Pyrite, Pyrr – Pyrrhotite, Magn – Magnetite, Zuny – Zunyite, Diasp – Diaspore, Bayrt – Bayerite, Musc – Muscovite, Alb – Albite
Gyp – Gypsum, Anh – Anhydrite, Micr – Microcline, Oligo – Oligoclase, Cham – Chamosite, Mont – Montmorillonite, Chlo – Chlorite,
Ortho – Orthoclase. KI – Kaolinite-Illite Ratio.
219
Appendix F – XRD Graphs of the Analysed Cambay and Subathu Fm Shale Samples
C= Chamosite; K= Kaolinite; Q= Quartz; I= Illite; P=Pyrite; S= Siderite; F=Feldspar; G=
Gypsum; M=Muscovite; Ch= Chlorite.
CAM 2
220
CAM 4
221
222
223
224
225
226
227
228
229
230
231
232
233
234
235
236
237
238
239
240
241
242
243
244
245
246
247
248
249
250
251
252
253
254
255
256
Appendix – G
257
Appendix G: XRD pattern of samples throughout the BBHA borehole. The patterns are not
to scale in the vertical. Note quartz increases up-section. K=Kaolinite, I=Illite, Q=Quartz
258
Appendix H – XRD Analytical Details (with FWHM) of Borehole BBHA Subathu Fm
Shale Samples
Sample 1
Measurement Conditions: (Bookmark 1)
Sample Code A2
File name C:\X'Pert Data\JAN2014\A2.xrdml
Comment Configuration=Flat Sample Stage, Owner=jagtar, Creation
date=6/11/2007 3:57:00 PM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=PW3071/xx Bracket
Diffractometer system=XPERT-PRO
Measurement program=PU, Owner=jagtar, Creation
date=4/15/2008 1:52:59 PM
Measurement Date / Time 1/10/2014 9:14:38 AM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.8709
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
FWHM: Full Width Half Maximum.
259
Pos. [°2Th.] FWHM
[°2Th.]
d-spacing
[Å]
Rel. Int. [%] Area
[cts*°2Th.]
5.2581 0.4015 16.80725 1.31 37.29
8.7754 0.2007 10.07693 1.10 15.72
11.1832 0.4015 7.91214 0.86 24.55
12.3993 0.4015 7.13874 3.48 98.99
17.7932 0.3346 4.98498 1.12 26.47
19.6895 0.2342 4.50896 2.44 40.47
20.8126 0.0836 4.26811 4.12 24.42
23.0527 0.1171 3.85819 6.19 51.39
23.9753 0.0836 3.71176 3.92 23.25
24.9259 0.2007 3.57233 2.56 36.39
25.3168 0.1673 3.51805 2.28 27.01
26.5168 0.1004 3.36150 33.28 236.79
29.4105 0.1506 3.03702 100.00 1067.16
31.4760 0.1506 2.84228 1.79 19.07
32.4144 0.1004 2.76211 2.00 14.23
34.6705 0.4015 2.58737 1.49 42.54
35.4696 0.0836 2.53088 3.75 22.26
35.9940 0.1506 2.49521 6.29 67.17
38.8399 0.1004 2.31868 2.38 16.93
39.4165 0.1004 2.28608 11.32 80.51
42.7365 0.1171 2.11586 1.73 14.33
43.1729 0.1673 2.09548 7.83 92.89
43.6214 0.1171 2.07497 2.37 19.69
45.2762 0.8029 2.00291 0.30 17.18
47.1598 0.1338 1.92721 1.58 14.97
47.5541 0.1338 1.91215 5.67 53.83
48.5588 0.0836 1.87491 7.67 45.49
50.1154 0.2007 1.82026 0.88 12.52
51.4382 0.1004 1.77652 1.03 7.30
56.6742 0.2007 1.62419 1.06 15.15
57.4287 0.1506 1.60464 2.88 30.76
60.7413 0.1171 1.52482 2.33 19.37
63.1922 0.3346 1.47146 0.64 15.17
64.6517 0.1836 1.44053 1.38 24.32
Sample 2
Measurement Conditions: (Bookmark 1)
Sample Code A11
File name C:\X'Pert Data\JAN2014\A11.xrdml
Comment Configuration=Flat Sample Stage, Owner=jagtar, Creation
date=6/11/2007 3:57:00 PM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=PW3071/xx Bracket
260
Diffractometer system=XPERT-PRO
Measurement program=PU, Owner=jagtar, Creation
date=4/15/2008 1:52:59 PM
Measurement Date / Time 1/9/2014 6:12:03 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.8709
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM
[°2Th.]
d-spacing
[Å]
Rel. Int. [%] Area
[cts*°2Th.]
6.2617 0.4015 14.11548 0.96 16.38
8.7624 0.2007 10.09189 2.06 17.57
11.1225 0.3346 7.95521 2.74 39.04
12.2655 0.1004 7.21633 12.28 52.42
17.7498 0.2007 4.99708 3.43 29.25
18.7491 0.0669 4.73293 6.29 17.90
19.7234 0.2342 4.50129 5.59 55.64
20.7896 0.1004 4.27278 22.52 96.12
22.6972 0.1004 3.91780 2.88 12.31
261
23.9406 0.0836 3.71706 25.26 89.86
24.8074 0.1338 3.58912 8.44 48.06
25.2038 0.1673 3.53356 9.57 68.12
26.5505 0.1171 3.35732 100.00 497.99
31.2377 0.4015 2.86342 0.93 15.82
32.9539 0.1506 2.71811 1.77 11.35
34.9136 0.2007 2.56990 3.47 29.63
36.4568 0.1338 2.46459 4.88 27.79
37.0552 0.2007 2.42615 1.58 13.49
39.3672 0.0669 2.28883 5.08 14.46
40.2271 0.1004 2.24187 2.21 9.45
42.3587 0.0669 2.13385 6.23 17.72
44.9499 0.1004 2.01669 1.93 8.24
50.0717 0.0836 1.82175 7.83 27.86
53.4282 0.6691 1.71495 0.53 15.14
54.9762 0.5353 1.67027 1.29 29.46
59.8829 0.0816 1.54333 5.07 23.80
61.5225 0.4080 1.50607 0.93 21.86
Sample 3
Measurement Conditions: (Bookmark 1)
Sample Code A6
File name C:\X'Pert Data\JAN2014\A6.xrdml
Comment Configuration=Flat Sample Stage, Owner=jagtar, Creation
date=6/11/2007 3:57:00 PM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=PW3071/xx Bracket
Diffractometer system=XPERT-PRO
Measurement program=PU, Owner=jagtar, Creation
date=4/15/2008 1:52:59 PM
Measurement Date / Time 1/9/2014 6:23:22 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
262
Divergence Slit Size [°] 0.8709
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM
[°2Th.]
d-spacing
[Å]
Rel. Int. [%] Area
[cts*°2Th.]
6.2188 0.2007 14.21279 1.92 13.52
8.7692 0.1004 10.08403 3.67 12.96
11.1136 0.2676 7.96154 4.18 39.30
12.2527 0.2342 7.22382 15.79 129.92
12.4456 0.1171 7.11228 16.46 67.75
17.8149 0.2676 4.97896 3.75 35.29
18.7179 0.0669 4.74075 7.10 16.70
19.6710 0.2342 4.51315 5.85 48.14
20.7603 0.1171 4.27875 23.52 96.78
22.7551 0.2007 3.90797 2.83 19.95
23.9267 0.0836 3.71920 26.54 78.01
25.2206 0.1004 3.53124 13.33 47.01
26.5417 0.1171 3.35841 100.00 411.46
31.2362 0.4015 2.86355 1.34 18.94
34.8523 0.2007 2.57428 3.33 23.46
36.4640 0.0836 2.46412 9.10 26.75
39.3692 0.1338 2.28872 4.89 22.99
40.2258 0.1338 2.24194 2.23 10.51
41.1072 0.1004 2.19588 2.51 8.86
42.3653 0.1338 2.13353 3.32 15.61
44.9437 0.0836 2.01695 4.79 14.09
45.7172 0.0836 1.98461 6.33 18.60
47.9707 0.4015 1.89651 1.24 17.45
50.0568 0.0816 1.82075 16.28 63.11
54.9506 0.6528 1.66960 2.01 62.34
59.8788 0.0816 1.54343 6.21 24.08
263
63.9259 0.3264 1.45512 1.57 24.33
Sample 4
Measurement Conditions: (Bookmark 1)
Sample Code A15
File name C:\X'Pert Data\JAN2014\A15.xrdml
Comment Configuration=Flat Sample Stage, Owner=jagtar, Creation
date=6/11/2007 3:57:00 PM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=PW3071/xx Bracket
Diffractometer system=XPERT-PRO
Measurement program=PU, Owner=jagtar, Creation
date=4/15/2008 1:52:59 PM
Measurement Date / Time 1/10/2014 9:25:17 AM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.8709
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
264
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM
[°2Th.]
d-spacing
[Å]
Rel. Int. [%] Area
[cts*°2Th.]
6.0116 0.2676 14.70223 1.00 21.97
8.7311 0.2007 10.12799 0.81 13.32
12.4490 0.1673 7.11034 2.36 32.24
17.6607 0.1673 5.02210 1.99 27.18
18.3608 0.5353 4.83215 1.03 45.24
18.7239 0.0836 4.73925 6.04 41.33
19.6605 0.2007 4.51553 3.10 50.96
20.7659 0.1004 4.27760 22.90 188.00
22.7030 0.4015 3.91681 0.49 15.96
23.9266 0.0836 3.71922 26.17 179.07
25.1466 0.4684 3.54147 2.71 103.80
26.5367 0.1171 3.35903 100.00 957.89
27.6152 0.1004 3.23025 9.07 74.51
29.3391 0.1171 3.04424 0.83 7.99
30.6496 0.1506 2.91701 28.05 345.50
32.8021 0.0836 2.73034 1.83 12.53
33.1708 0.2007 2.70083 1.45 23.84
34.8836 0.1338 2.57205 2.48 27.13
35.4196 0.0836 2.53434 2.38 16.30
36.4391 0.0836 2.46574 7.53 51.53
37.1017 0.1506 2.42322 3.21 39.52
38.0587 0.1004 2.36445 1.46 11.97
39.3590 0.0836 2.28929 5.99 40.97
40.1845 0.0669 2.24415 3.46 18.91
40.8106 0.1171 2.21115 2.76 26.47
42.3513 0.0669 2.13421 4.70 25.73
44.6159 0.1004 2.03100 2.19 17.95
44.9186 0.1004 2.01802 4.01 32.96
45.6924 0.0669 1.98563 3.92 21.47
47.4771 0.1506 1.91507 0.38 4.63
49.1137 0.1338 1.85502 1.04 11.40
50.0406 0.0816 1.82130 11.90 107.33
50.6314 0.1836 1.80142 2.65 53.84
53.6010 0.1632 1.70841 2.34 42.20
54.7750 0.1020 1.67454 3.18 35.91
55.2273 0.1224 1.66189 1.80 24.39
59.8655 0.1020 1.54374 7.98 89.96
60.3879 0.1224 1.53163 1.20 16.27
60.7316 0.1632 1.52378 1.56 28.08
61.6742 0.4080 1.50273 0.90 40.82
63.9370 0.1020 1.45490 1.32 14.88
Sample 5
265
Measurement Conditions: (Bookmark 1)
Sample Code IF3
File name C:\X'Pert Data\JAN2014\IF3.xrdml
Comment Configuration=Flat Sample Stage, Owner=jagtar, Creation
date=6/11/2007 3:57:00 PM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=PW3071/xx Bracket
Diffractometer system=XPERT-PRO
Measurement program=PU, Owner=jagtar, Creation
date=4/15/2008 1:52:59 PM
Measurement Date / Time 1/9/2014 5:50:47 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.8709
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM
[°2Th.]
d-spacing
[Å]
Rel. Int. [%] Area
[cts*°2Th.]
8.6912 0.5353 10.17440 2.14 37.34
11.0542 0.1338 8.00421 6.75 29.45
12.2343 0.1171 7.23467 29.89 114.12
266
17.6529 0.2676 5.02430 4.35 37.96
18.6988 0.0836 4.74555 5.52 15.06
19.6620 0.1673 4.51520 6.48 35.35
20.7531 0.1004 4.28020 19.24 62.95
22.2994 0.1673 3.98679 5.04 27.48
23.9162 0.1004 3.72080 23.86 78.08
24.7263 0.2007 3.60070 25.13 164.46
25.1898 0.1004 3.53550 11.36 37.16
26.5266 0.1171 3.36028 100.00 381.79
28.7444 0.1004 3.10586 4.42 14.47
31.9461 0.1506 2.80152 14.90 73.16
34.7862 0.3346 2.57902 4.44 48.38
36.4091 0.0836 2.46770 5.16 14.07
36.9357 0.2007 2.43373 1.67 10.92
37.6623 0.1673 2.38843 3.74 20.39
38.3745 0.2007 2.34572 4.45 29.14
39.3570 0.1338 2.28940 4.36 19.04
40.1497 0.2676 2.24601 2.17 18.90
42.3404 0.0669 2.13473 7.26 15.84
45.5534 0.4015 1.99136 2.22 29.10
46.1366 0.1673 1.96754 2.65 14.48
49.2919 0.1171 1.84873 1.68 6.43
50.0231 0.0836 1.82340 6.25 17.05
50.7984 0.2007 1.79738 2.10 13.75
52.8738 0.1840 1.73162 2.84 17.03
53.6154 0.1338 1.70940 1.62 7.06
54.8196 0.2007 1.67467 2.97 19.45
59.8540 0.0836 1.54529 5.28 14.40
61.5116 0.4896 1.50631 1.38 29.81
Sample 6
Measurement Conditions: (Bookmark 1)
Sample Code IF6
File name C:\X'Pert Data\JAN2014\IF6.xrdml
Comment Configuration=Flat Sample Stage, Owner=jagtar, Creation
date=6/11/2007 3:57:00 PM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=PW3071/xx Bracket
Diffractometer system=XPERT-PRO
Measurement program=PU, Owner=jagtar, Creation
date=4/15/2008 1:52:59 PM
Measurement Date / Time 1/10/2014 9:36:04 AM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
267
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.8709
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM
[°2Th.]
d-spacing
[Å]
Rel. Int. [%] Area
[cts*°2Th.]
8.8379 0.1004 10.00579 3.71 22.86
11.1423 0.1673 7.94108 4.18 43.00
12.3251 0.1338 7.18155 19.32 158.92
17.7645 0.1004 4.99299 2.60 16.07
18.7844 0.0836 4.72412 4.16 21.37
19.8080 0.2007 4.48226 2.84 35.06
20.8210 0.1004 4.26641 15.68 96.70
22.4050 0.0836 3.96823 3.45 17.74
23.9742 0.0836 3.71194 25.53 131.25
24.8402 0.1338 3.58446 16.39 134.84
25.2665 0.1506 3.52494 6.50 60.15
26.5817 0.1338 3.35344 100.00 822.52
27.4146 0.1004 3.25343 1.65 10.16
28.4874 0.1338 3.13329 2.28 18.72
29.4160 0.1171 3.03647 2.71 19.51
31.7794 0.1338 2.81584 3.58 29.47
32.9965 0.0836 2.71470 4.30 22.13
34.9572 0.1338 2.56680 2.99 24.58
35.9910 0.3011 2.49541 1.87 34.56
36.4915 0.0669 2.46232 4.87 20.03
37.0358 0.0836 2.42738 3.46 17.80
37.7435 0.2007 2.38347 2.61 32.20
268
38.4532 0.4684 2.34110 2.13 61.37
39.4121 0.0669 2.28633 4.85 19.93
40.2371 0.1004 2.24133 2.23 13.76
40.6929 0.0836 2.21727 2.93 15.07
41.1214 0.1171 2.19516 1.54 11.11
42.4065 0.0669 2.13156 3.66 15.04
44.9868 0.0836 2.01511 2.35 12.09
45.7479 0.1004 1.98335 3.18 19.60
47.3658 0.0836 1.91931 2.12 10.92
49.1552 0.1338 1.85355 0.84 6.93
50.0949 0.0669 1.82096 6.06 24.91
53.6569 0.1004 1.70818 1.85 11.42
54.8279 0.0816 1.67305 4.39 29.74
56.2390 0.1020 1.63437 4.32 36.63
59.9198 0.0816 1.54247 6.14 41.64
61.7157 0.3264 1.50182 0.81 21.89
62.2683 0.2448 1.48981 1.07 21.79
64.2964 0.4896 1.44763 0.85 34.45
Sample 7
Measurement Conditions: (Bookmark 1)
Sample Code IF9
File name C:\X'Pert Data\JAN2014\IF9.xrdml
Comment Configuration=Flat Sample Stage, Owner=jagtar, Creation
date=6/11/2007 3:57:00 PM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=PW3071/xx Bracket
Diffractometer system=XPERT-PRO
Measurement program=PU, Owner=jagtar, Creation
date=4/15/2008 1:52:59 PM
Measurement Date / Time 1/9/2014 6:01:24 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.8709
Specimen Length [mm] 10.00
269
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM
[°2Th.]
d-spacing
[Å]
Rel. Int. [%] Area
[cts*°2Th.]
8.7101 0.2007 10.15235 2.32 17.33
11.0857 0.3346 7.98151 3.17 39.40
12.1950 0.1171 7.25787 13.29 57.90
12.4058 0.1004 7.13500 12.03 44.90
17.6724 0.3346 5.01877 4.26 53.08
18.6954 0.0836 4.74642 8.58 26.69
19.6824 0.2007 4.51057 4.43 33.05
20.7369 0.1004 4.28352 31.64 118.12
22.5432 0.6691 3.94422 1.90 47.39
23.8821 0.1004 3.72604 25.28 94.39
24.7638 0.1506 3.59533 10.91 61.10
25.1487 0.1506 3.54118 12.11 67.82
26.4965 0.1338 3.36404 100.00 497.83
27.7333 0.1506 3.21675 1.93 10.82
29.6808 0.2007 3.00998 1.42 10.59
31.1628 0.5353 2.87013 1.32 26.30
32.7618 0.0836 2.73361 3.23 10.04
34.8525 0.2007 2.57427 3.03 22.62
36.3955 0.0836 2.46859 12.20 37.96
39.3196 0.0836 2.29149 5.40 16.80
40.1509 0.1338 2.24594 3.67 18.26
40.8690 0.4015 2.20813 1.09 16.30
42.2991 0.0669 2.13672 5.71 14.22
44.8827 0.0836 2.01955 4.98 15.48
45.6414 0.0836 1.98773 5.80 18.04
49.9955 0.0669 1.82435 10.27 25.57
53.5463 0.1004 1.71145 3.59 13.40
270
54.7379 0.1004 1.67698 4.03 15.05
56.1891 0.2007 1.63706 2.38 17.81
59.8233 0.1004 1.54601 7.08 26.44
63.9509 0.2448 1.45461 1.23 15.12
Sample 8
Measurement Conditions: (Bookmark 1)
Sample Code A3
File name C:\X'Pert Data\JAN2014\A3.xrdml
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/28/2014 11:44:08 AM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
271
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
8.8594 0.2676 9.98160 15.87 26.33 12.4187 0.0836 7.12762 83.19 43.14
17.8351 0.1673 4.97338 16.47 17.08
19.9469 0.2007 4.45135 20.94 26.06 20.9276 0.1338 4.24491 21.54 17.87
24.9817 0.1506 3.56447 85.02 79.36
25.3722 0.1338 3.51049 49.48 41.05 26.6993 0.1004 3.33894 100.00 62.23
29.5095 0.1004 3.02705 30.37 18.90
33.1166 0.1338 2.70513 12.44 10.32
34.8159 0.2676 2.57689 18.26 30.30 36.0244 0.2007 2.49317 9.65 12.01
37.1288 0.1673 2.42151 12.05 12.50
37.8114 0.2676 2.37935 10.76 17.86 39.5899 0.1673 2.27647 7.58 7.87
40.8954 0.2676 2.20676 6.42 10.66
42.5069 0.1673 2.12676 7.77 8.06
45.5304 0.4015 1.99231 10.05 25.01 47.5594 0.2007 1.91195 6.38 7.94
48.6512 0.2007 1.87156 6.07 7.55
53.9691 0.1673 1.69903 6.69 6.94 55.3322 0.5353 1.66036 8.31 27.58
56.3226 0.1004 1.63350 12.07 7.51
60.1144 0.4015 1.53921 5.54 13.80 61.6528 0.9792 1.50320 4.66 38.27
Sample 9
Measurement Conditions: (Bookmark 1)
Sample Code A9
File name C:\X'Pert Data\JAN2014\A9.xrdml
Sample Identification A9
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/27/2014 4:09:13 PM
Operator Panjab University
272
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
8.9347 0.1506 9.89766 2.56 10.56
12.4566 0.2007 7.10607 13.64 75.07 17.8531 0.2007 4.96840 2.30 12.67
19.8707 0.2342 4.46826 5.15 33.04
20.9204 0.1004 4.24635 21.16 58.22 24.9493 0.1171 3.56902 11.88 38.15
25.3826 0.1673 3.50908 12.19 55.91
26.6978 0.1171 3.33912 100.00 321.00
31.3032 0.4015 2.85757 1.04 11.48 33.1229 0.1004 2.70463 1.72 4.73
34.8857 0.4015 2.57190 3.34 36.80
36.6064 0.0669 2.45485 5.87 10.77 37.8577 0.1004 2.37654 2.86 7.88
39.5233 0.0669 2.28015 8.41 15.42
40.3486 0.0669 2.23540 3.62 6.64 40.8461 0.2007 2.20931 1.24 6.81
273
42.5173 0.1004 2.12626 4.59 12.63
45.8483 0.1004 1.97924 4.27 11.74 48.0720 0.2342 1.89275 1.39 8.91
50.1969 0.0816 1.81599 13.36 40.41
55.0420 0.6528 1.66705 2.20 53.20
60.0185 0.1020 1.54017 6.23 23.54 61.7110 0.6528 1.50192 1.43 34.53
FWHM: Full Width Half Maximum.
Sample 10
Measurement Conditions: (Bookmark 1)
Sample Code A10
File name C:\X'Pert Data\JAN2014\A10.xrdml
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/28/2014 11:55:23 AM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
274
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
12.3878 0.1673 7.14537 18.41 58.40 17.8475 0.2676 4.96995 2.89 14.68
19.8743 0.2676 4.46744 7.52 38.16
20.9187 0.1004 4.24670 22.65 43.11 24.9669 0.1338 3.56655 16.58 42.08
25.3557 0.1171 3.51273 19.35 42.99
26.6888 0.1004 3.34022 100.00 190.37 31.5773 0.8029 2.83339 1.04 15.90
33.0863 0.0669 2.70754 6.54 8.29
35.0257 0.1338 2.56194 5.90 14.97
36.5837 0.0836 2.45633 6.65 10.55 37.1315 0.1338 2.42134 4.88 12.38
37.8607 0.2007 2.37636 3.77 14.35
39.5069 0.1338 2.28106 4.27 10.84 40.3338 0.1004 2.23618 4.21 8.02
40.8317 0.1338 2.21005 3.05 7.73
42.5015 0.1004 2.12701 6.53 12.43 45.9258 0.8029 1.97608 2.09 31.86
50.1872 0.0836 1.81783 9.85 15.62
54.9756 0.2007 1.67029 2.86 10.89
56.3883 0.3346 1.63175 2.15 13.68 60.0039 0.0816 1.54051 7.79 16.29
61.7337 0.6528 1.50143 1.92 32.10
Sample 11
Measurement Conditions: (Bookmark 1)
Sample Code A16
File name C:\X'Pert Data\JAN2014\A16.xrdml
Sample Identification A16
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
275
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/27/2014 4:19:39 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
6.2433 0.3346 14.15695 0.77 18.97
8.9011 0.2007 9.93498 0.71 10.52 12.5386 0.2676 7.05978 1.64 32.37
15.0198 0.1338 5.89864 0.43 4.27
17.8723 0.2676 4.96311 1.03 20.38 18.6907 0.4015 4.74759 0.62 18.41
19.7778 0.1171 4.48901 1.46 12.62
20.9174 0.1004 4.24697 21.45 158.58
23.1539 0.1171 3.84155 1.67 14.40 25.2709 0.2676 3.52433 1.48 29.08
26.6890 0.1338 3.34020 100.00 985.70
276
29.5094 0.1506 3.02706 17.54 194.47
30.7980 0.1171 2.90329 4.58 39.47 31.5605 0.1673 2.83486 0.74 9.06
33.1174 0.2007 2.70507 0.52 7.65
35.0343 0.2007 2.56133 1.46 21.56
36.0736 0.1004 2.48989 2.10 15.51 36.5845 0.0836 2.45627 6.73 41.45
37.1919 0.2007 2.41754 0.59 8.65
39.5158 0.1004 2.28057 7.90 58.42 40.3318 0.0669 2.23629 2.88 14.18
41.0449 0.2676 2.19907 0.37 7.38
42.4966 0.0836 2.12725 4.58 28.21 43.2805 0.0836 2.09052 2.62 16.14
45.8323 0.0836 1.97989 2.79 17.17
47.2367 0.1004 1.92425 1.03 7.60
47.6333 0.1338 1.90915 1.73 17.06 48.6479 0.1673 1.87168 2.83 34.87
50.1812 0.1020 1.81653 10.14 102.98
54.9198 0.1020 1.67047 2.89 29.30 55.3751 0.1224 1.65780 1.21 14.72
57.5334 0.1020 1.60064 1.45 14.75
60.0050 0.1020 1.54048 6.86 69.63 60.8869 0.4080 1.52026 0.44 18.04
61.8255 0.2448 1.49942 0.84 20.52
64.0831 0.1224 1.45193 1.07 12.99
Sample 12
Measurement Conditions: (Bookmark 1)
Sample Code IF1
File name C:\X'Pert Data\JAN2014\IF1.xrdml
Sample Identification IF1
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/27/2014 3:06:29 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
277
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
8.8869 0.5353 9.95077 5.59 27.07
12.4175 0.1338 7.12830 30.51 36.93
17.9899 0.5353 4.93093 3.25 15.75
19.8446 0.2676 4.47406 14.93 36.15 20.9071 0.0836 4.24904 13.67 10.34
23.1789 0.1004 3.83747 10.35 9.40
24.9621 0.2007 3.56723 28.04 50.91 25.3685 0.1673 3.51099 20.20 30.57
26.6994 0.1171 3.33893 64.85 68.69
29.5386 0.1840 3.02414 100.00 166.44 32.1452 0.2007 2.78462 3.84 6.97
33.1121 0.1171 2.70549 7.79 8.25
35.0176 0.1673 2.56251 13.38 20.24
36.1686 0.2342 2.48356 11.20 23.73 36.5772 0.1673 2.45675 9.42 14.25
37.1680 0.2007 2.41905 6.82 12.39
37.8244 0.2676 2.37856 4.98 12.06 39.5498 0.1673 2.27868 16.47 24.91
42.5130 0.2007 2.12647 4.01 7.29
43.2733 0.2007 2.09085 10.98 19.93
45.6297 0.4015 1.98821 5.35 19.43 47.7983 0.2007 1.90295 9.52 17.28
48.7034 0.1338 1.86968 11.98 14.50
50.1952 0.2676 1.81756 5.09 12.31
278
55.2982 0.6691 1.66130 3.45 20.86
56.5239 0.4015 1.62816 2.96 10.74 57.6169 0.2007 1.59984 4.13 7.50
59.7126 0.5353 1.54861 2.48 12.00
61.0829 0.2342 1.51711 2.79 5.92
61.7241 0.9792 1.50164 3.85 46.07
Sample 13
Measurement Conditions: (Bookmark 1)
Sample Code IF2
File name C:\X'Pert Data\JAN2014\IF2.xrdml
Sample Identification IF2
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/27/2014 3:16:56 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
279
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
8.9083 0.2007 9.92688 9.08 21.62
12.4139 0.0836 7.13036 44.06 43.72 17.8180 0.2342 4.97811 5.82 16.16
19.9534 0.1338 4.44992 13.69 21.73
20.9325 0.1004 4.24393 16.58 19.74
23.1815 0.1004 3.83704 4.74 5.64 24.9897 0.1673 3.56335 36.12 71.67
25.3897 0.1171 3.50811 24.02 33.36
26.7004 0.1004 3.33881 100.00 119.06 29.5635 0.1171 3.02165 28.21 39.19
32.1034 0.2676 2.78815 3.12 9.89
33.1306 0.1004 2.70402 5.16 6.14 35.0037 0.5353 2.56350 10.05 63.80
36.1107 0.2342 2.48741 3.20 8.90
37.7906 0.2676 2.38061 2.41 7.66
38.4948 0.3346 2.33867 3.05 12.11 39.6068 0.1673 2.27554 7.40 14.68
42.4595 0.4015 2.12902 2.49 11.88
45.7290 0.8029 1.98412 3.47 33.05 47.4783 0.4015 1.91502 3.54 16.85
48.7300 0.2676 1.86872 2.78 8.81
50.2285 0.2007 1.81643 4.48 10.67
54.9978 0.2007 1.66966 4.39 10.46 56.3986 0.2007 1.63148 3.57 8.50
60.0047 0.1004 1.54176 5.91 7.03
61.7452 0.6528 1.50117 2.98 31.18
Sample 14
Measurement Conditions: (Bookmark 1)
Sample Code IF4
File name C:\X'Pert Data\JAN2014\IF4.xrdml
Sample Identification IF4
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
280
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/27/2014 3:27:23 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
8.9631 0.2007 9.86637 11.20 19.68
12.4446 0.1338 7.11285 59.81 70.07 17.8248 0.4684 4.97621 6.57 26.95
19.8988 0.2676 4.46200 15.31 35.88
20.9445 0.1004 4.24153 15.69 13.78 24.9937 0.1338 3.56279 54.98 64.41
25.3924 0.1673 3.50774 32.78 47.99
26.7293 0.1004 3.33526 100.00 87.86
29.5762 0.1171 3.02038 18.40 18.86 33.1356 0.1004 2.70362 9.33 8.19
34.6802 0.2007 2.58667 10.17 17.87
35.0765 0.2007 2.55834 13.32 23.41
281
36.1104 0.2007 2.48743 8.80 15.46
36.5943 0.2007 2.45564 7.90 13.88 37.1874 0.2007 2.41783 9.83 17.26
37.8223 0.2676 2.37869 10.25 24.00
38.5230 0.2676 2.33702 5.83 13.65
39.5734 0.2676 2.27738 5.56 13.03 42.6246 0.1673 2.12116 4.26 6.24
45.7041 0.6691 1.98515 5.77 33.78
47.6535 0.5353 1.90839 3.60 16.85 50.2430 0.1171 1.81594 6.56 6.72
55.3511 0.4015 1.65984 4.08 14.33
56.3585 0.1004 1.63254 7.44 6.53 59.8977 0.8029 1.54426 3.24 22.80
61.7602 0.4896 1.50085 5.51 31.94
Sample 15
Measurement Conditions: (Bookmark 1)
Sample Code IF5
File name C:\X'Pert Data\JAN2014\IF5.xrdml
Sample Identification IF5
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/27/2014 3:37:49 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
282
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
8.8915 0.4015 9.94563 1.25 15.14 12.3706 0.1338 7.15524 13.39 54.05
17.7747 0.2676 4.99014 1.96 15.81
19.8673 0.1673 4.46901 4.79 24.17 20.4898 0.1673 4.33462 1.78 8.99
20.8667 0.1004 4.25717 19.64 59.48
24.8871 0.1506 3.57780 16.02 72.74 25.3405 0.1338 3.51481 9.35 37.73
26.6528 0.1338 3.34466 100.00 403.72
27.9072 0.2007 3.19710 2.32 14.05
28.5575 0.1171 3.12576 2.65 9.35 29.5323 0.1338 3.02477 2.64 10.67
31.8754 0.1506 2.80757 6.36 28.91
33.0717 0.0836 2.70870 4.71 11.89 35.0578 0.1338 2.55966 5.31 21.43
36.0045 0.2676 2.49451 2.39 19.31
36.5537 0.0836 2.45828 7.92 19.99 37.0717 0.1506 2.42511 4.16 18.89
37.7830 0.1673 2.38107 3.55 17.90
38.3897 0.3346 2.34483 3.08 31.09
39.4650 0.0836 2.28339 7.12 17.97 40.3002 0.0669 2.23797 4.27 8.61
40.7971 0.1004 2.21185 3.95 11.96
42.4524 0.0836 2.12936 5.01 12.63 45.7889 0.1004 1.98167 4.09 12.37
47.4451 0.1004 1.91629 2.25 6.81
48.0309 0.1673 1.89427 1.26 6.37
50.1402 0.1224 1.81791 9.74 48.61 50.9747 0.2040 1.79009 1.28 10.62
52.6542 0.6528 1.73688 1.22 32.54
54.8805 0.1224 1.67157 3.80 18.97 55.3677 0.2448 1.65801 3.00 29.98
56.2873 0.1020 1.63308 4.70 19.53
59.9819 0.1224 1.54102 6.84 34.16 61.7439 0.4080 1.50120 1.00 16.71
64.1665 0.4080 1.45024 0.90 14.93
283
Sample 16
Measurement Conditions: (Bookmark 1)
Sample Code IF7
File name C:\X'Pert Data\JAN2014\IF7.xrdml
Sample Identification IF7
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/27/2014 3:48:16 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
284
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
8.9364 0.6691 9.89579 3.78 43.96 12.5949 0.1004 7.02830 23.57 41.08
17.8135 0.2007 4.97935 3.45 12.02
19.7597 0.2007 4.49310 7.50 26.14 20.9216 0.1004 4.24611 24.19 42.15
24.9683 0.2342 3.56635 13.17 53.53
25.3160 0.1506 3.51816 20.83 54.44 26.6930 0.1338 3.33972 100.00 232.36
28.5977 0.1338 3.12146 1.40 3.26
29.5511 0.2007 3.02289 2.37 8.27
33.1127 0.1004 2.70544 3.70 6.44 35.1224 0.2342 2.55510 4.97 20.22
36.5953 0.0669 2.45558 8.83 10.26
37.1253 0.1004 2.42173 3.57 6.22 39.5271 0.0836 2.27994 6.03 8.76
40.3366 0.1673 2.23603 3.11 9.03
42.5225 0.1004 2.12601 5.16 9.00
45.8774 0.2007 1.97805 3.35 11.67 50.1936 0.0836 1.81761 8.72 12.67
54.9970 0.2007 1.66969 3.30 11.51
56.3174 0.1004 1.63363 4.31 7.51 60.0115 0.0836 1.54160 8.68 12.61
61.7479 0.2448 1.50112 3.21 18.46
Sample 17
Measurement Conditions: (Bookmark 1)
Sample Code IF8
File name C:\X'Pert Data\JAN2014\IF8.xrdml
Sample Identification IF8
Comment Configuration=Reflection Spinner Stage, Owner=jagtar,
Creation date=12/6/2007 10:50:59 AM
Goniometer=PW3050/60 (Theta/Theta); Minimum step
size 2Theta:0.001; Minimum step size Omega:0.001
Sample stage=Spinner PW3064
Diffractometer system=XPERT-PRO
Measurement program=Spinner, Owner=jagtar, Creation
date=1/9/2008 11:57:34 AM
Measurement Date / Time 1/27/2014 3:58:43 PM
Operator Panjab University
Raw Data Origin XRD measurement (*.XRDML)
Scan Axis Gonio
Start Position [°2Th.] 5.0084
End Position [°2Th.] 64.9844
Step Size [°2Th.] 0.0170
Scan Step Time [s] 20.0253
Scan Type Continuous
285
PSD Mode Scanning
PSD Length [°2Th.] 2.12
Offset [°2Th.] 0.0000
Divergence Slit Type Fixed
Divergence Slit Size [°] 0.4354
Specimen Length [mm] 10.00
Measurement Temperature [°C] 25.00
Anode Material Cu
K-Alpha1 [Å] 1.54060
K-Alpha2 [Å] 1.54443
K-Beta [Å] 1.39225
K-A2 / K-A1 Ratio 0.50000
Generator Settings 40 mA, 45 kV
Diffractometer Type 0000000011023505
Diffractometer Number 0
Goniometer Radius [mm] 240.00
Dist. Focus-Diverg. Slit [mm] 100.00
Incident Beam Monochromator No
Spinning No
Main Graphics, Analyze View: (Bookmark 2)
Peak List: (Bookmark 3)
Pos. [°2Th.] FWHM [°2Th.] d-spacing [Å] Rel. Int. [%] Area [cts*°2Th.]
12.4453 0.1004 7.11246 5.85 17.40
17.8354 0.2007 4.97329 1.67 9.95 19.9273 0.1338 4.45568 3.56 14.09
20.9308 0.1004 4.24427 19.35 57.54
23.1856 0.1171 3.83637 5.78 20.06 24.0174 0.1673 3.70536 2.40 11.89
24.9518 0.1004 3.56867 4.86 14.45
25.4027 0.1004 3.50635 3.71 11.04
26.7114 0.1338 3.33745 100.00 396.39 28.5925 0.1338 3.12202 1.14 4.53
29.5276 0.1673 3.02524 39.39 195.18
30.7991 0.1673 2.90318 43.78 216.91 33.1211 0.0836 2.70477 3.16 7.84
35.1088 0.2676 2.55606 3.08 24.43
36.0948 0.1004 2.48847 6.06 18.03
36.6113 0.0669 2.45454 5.83 11.56 37.2782 0.2676 2.41215 3.58 28.42
37.8650 0.2007 2.37610 1.13 6.70
39.5430 0.0836 2.27906 17.37 43.02 40.3621 0.1338 2.23468 2.39 9.48
40.9674 0.1004 2.20305 8.90 26.46
42.5196 0.0669 2.12615 3.67 7.27 43.3141 0.1673 2.08898 4.56 22.61
44.7801 0.1171 2.02394 4.87 16.89
45.8663 0.0612 1.97686 3.15 7.71
47.6566 0.1004 1.90827 5.32 15.82 48.6474 0.0836 1.87170 5.26 13.03
50.2090 0.0816 1.81559 14.87 48.59
286
50.7109 0.1632 1.79879 5.07 33.15
50.9292 0.3264 1.79159 4.35 56.87 54.9421 0.1020 1.66984 4.12 16.84
55.4197 0.1020 1.65658 2.21 9.02
56.3422 0.1224 1.63162 2.61 12.77
57.6311 0.3264 1.59816 1.84 24.08 58.6900 0.2448 1.57182 0.75 7.30
60.0266 0.1020 1.53998 6.77 27.66
60.8311 0.2448 1.52152 1.62 15.86 61.7499 0.4896 1.50107 1.07 20.98
63.2622 0.4080 1.46878 1.31 21.48
(This is the simple example template containing only headers for each report item and the
bookmarks. The invisible bookmarks are indicated by text between brackets.
Modify it according to your own needs and standards)
287
Appendix I – Brittleness Index (BI) of Subathu Fm and Cambay Shale samples
Brittleness Index (BI) of Subathu Fm shale samples
Code Quartz Carbonate Clay
Total Q+C+Cl
Q/Q+C+Cl
or BI
SUB1 57.49 0.17 28.77 86.43 0.7
SUB2 0.17 0.20 92.22 92.58 0.002
SUB3 0.83 0.42 77.90 79.14 0.01
SUB4 9.59 0.38 67.63 77.60 0.1
SUB5 27.88 0.00 54.72 82.60 0.3
SUB46 26.13 0.23 57.40 83.76 0.3
SUB47 3.21 0.74 74.15 78.09 0.04
SUB48 35.34 0.00 43.44 78.79 0.5
SUB6 40.15 0.00 36.09 76.24 0.5
SUB43 60.85 0.00 25.17 86.01 0.7
SUB44 6.14 0.00 54.80 60.93 0.1
SUB7 0.27 0.38 95.86 96.52 0.003
SUB8 0.24 0.10 93.71 94.05 0.003
SUB26 4.49 0.38 93.25 98.13 0.05
SUB9 0.00 0.34 90.62 90.96 0.0
SUB27 0.13 0.55 95.53 96.20 0.001
SUB28 0.24 0.78 89.60 90.62 0.003
SUB10 0.33 0.11 96.31 96.75 0.003
SUB29 0.01 0.49 94.50 94.99
SUB30 0.42 0.75 91.30 92.46 0.005
SUB11 0.10 0.49 97.19 97.78 0.001
SUB31 0.13 0.79 94.69 95.61 0.001
SUB32 0.93 0.00 95.17 96.10 0.01
SUB33 21.04 38.83 38.93 98.80 0.2
SUB34 41.71 9.99 42.15 93.84 0.4
SUB35 40.99 3.16 53.23 97.38 0.4
SUB36 18.14 0.81 77.24 96.19 0.2
SUB45 74.41 0.00 23.64 98.05 0.8
SUB12 6.71 1.83 54.50 63.04 0.1
SUB13 58.13 0.59 38.70 97.42 0.6
SUB14 8.17 0.88 50.92 59.96 0.1
SUB15 7.23 0.74 78.43 86.41 0.1
SUB16 55.60 0.85 28.38 84.83 0.7
SUB17 63.78 1.04 16.44 81.26 0.8
SUB19 55.85 0.71 24.92 81.48 0.7
SUB20 29.70 0.00 38.89 68.59 0.4
SUB21 0.43 0.00 97.92 98.34 0.004
SUB22 0.10 0.00 99.70 99.80 0.001
288
SUB23 60.34 0.00 21.60 81.94 0.7
SUB24 18.26 0.00 53.19 71.45 0.3
SUB25 73.52 0.00 16.54 90.06 0.8
SUB37 41.87 0.00 36.22 78.09 0.5
SUB38 13.64 0.00 42.36 56.00 0.2
SUB39 38.02 0.00 28.44 66.45 0.6
SUB41 32.73 0.41 50.42 83.57 0.4
SUB42 58.49 0.37 26.21 85.07 0.7
A2 23.20 50.00 21.50 94.70 0.2
A3 16.20 5.00 58.80 80.00 0.2
IF1 11.30 25.50 53.60 90.40 0.1
IF2 20.40 7.60 55.90 83.90 0.2
IF3 30.50
45.20 75.70 0.4
IF4 21.36 4.50 52.60 78.46 0.3
IF5 42.30 1.30 38.10 81.70 0.5
IF6 43.10
34.00 77.10 0.6
IF7 40.00 1.20 42.60 83.80 0.5
IF8 27.70 55.40 13.80 96.90 0.3
IF9 46.20
33.10 79.30 0.6
A6 35.00
52.10 87.10 0.4
A9 46.70
37.80 84.50 0.6
A10 36.50
44.40 80.90 0.5
A11 44.90
30.80 75.70 0.6
A15 45.80 22.40 25.10 93.30 0.5
A16 59.90 18.90 16.80 95.60 0.6
Brittleness Index (BI) of Cambay Shale samples
Code Quartz Calcite Clay
Total Q+C+Cl
Q/Q+C+Cl
or BI
CAM1 8.2 0.0 52.2 60.5 0.1
CAM2 11.8 0.0 84.8 96.6 0.1
CAM3 11.2 1.3 70.3 82.8 0.1
CAM4 7.8 0.0 86.8 94.6 0.1
CAM5 7.7 3.0 75.0 85.8 0.1
CAM6 3.3 1.8 84.0 89.2 0.0
CAM7 2.7 1.6 84.3 88.6 0.0
CAM8 5.0 0.1 81.4 86.4 0.1
CAM9 23.5 0.8 58.6 82.9 0.3
CAM10 26.4 1.4 51.9 79.7 0.3
CAM11 21.1 0.7 56.7 78.5 0.3
CAM12 14.7 0.0 52.3 67.0 0.2
CAM13 1.9 0.0 76.5 78.4 0.0
289
CAM14 2.9 0.0 71.7 74.6 0.0
CAM15 19.9 0.0 61.5 81.4 0.2
CAM16 14.9 0.0 47.1 62.1 0.2
CAM17 34.0 0.5 41.3 75.8 0.4
CAM18 21.9 0.6 46.8 69.3 0.3
CAM21 4.0 0.5 56.2 60.7 0.1
CAM22 3.4 0.6 69.4 73.4 0.0
CAM20 9.0 11.3 40.9 61.2 0.1
CAM19 6.4 0.6 24.1 31.1 0.2
CAM23 5.8 0.0 67.4 73.1 0.1
CAM26 3.7 5.2 69.4 78.3 0.0
CAM24 8.0 0.0 55.6 63.6 0.1
CAM25 3.4 0.0 63.5 66.9 0.1
CAM27 4.1 0.9 69.9 74.9 0.1