stratigraphic and depositional controls on …
TRANSCRIPT
STRATIGRAPHIC AND DEPOSITIONAL CONTROLS ON SOURCE ROCK
HETEROGENEITY AND COMPOSITION OF EXPELLED PETROLEUM IN THE
TRIASSIC SHUBLIK FORMATION OF ARCTIC ALASKA
A DISSERTATION
SUBMITTED TO THE DEPARTMENT OF
GEOLOGICAL SCIENCES
AND THE COMMITTEE ON GRADUATE STUDIES
OF STANFORD UNIVERSITY
IN PARTIAL FULFILLMENT OF THE REQUIREMENTS
FOR THE DEGREE OF
DOCTOR OF PHILOSOPHY
INESSA A. YURCHENKO
AUGUST 2017
http://creativecommons.org/licenses/by-nc/3.0/us/
This dissertation is online at: http://purl.stanford.edu/bx528th8769
© 2017 by Inessa Yurchenko. All Rights Reserved.
Re-distributed by Stanford University under license with the author.
This work is licensed under a Creative Commons Attribution-Noncommercial 3.0 United States License.
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I certify that I have read this dissertation and that, in my opinion, it is fully adequatein scope and quality as a dissertation for the degree of Doctor of Philosophy.
Stephan Graham, Primary Adviser
I certify that I have read this dissertation and that, in my opinion, it is fully adequatein scope and quality as a dissertation for the degree of Doctor of Philosophy.
J. Moldowan
I certify that I have read this dissertation and that, in my opinion, it is fully adequatein scope and quality as a dissertation for the degree of Doctor of Philosophy.
Kenneth Peters
Approved for the Stanford University Committee on Graduate Studies.
Patricia J. Gumport, Vice Provost for Graduate Education
This signature page was generated electronically upon submission of this dissertation in electronic format. An original signed hard copy of the signature page is on file inUniversity Archives.
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ABSTRACT
Petroleum source rocks display significant variability in lithology, and quality,
quantity and thermal maturity of organic matter. However, many regional geochemical
studies focus on a few selected rock samples that may not represent the entire source
rock section, which can affect estimates of resource potential assessment
(conventional and unconventional). For nearly thirty years, the Triassic marine
carbonate Shublik Formation has been suggested and confirmed as a key source rock
for hydrocarbons in the North Slope of Alaska. The formation accounts for roughly
one third of the oil in the supergiant Prudhoe Bay Field, and for nearly all of the oil in
the second largest Kuparuk River Field.
This dissertation examines oil-source rock correlation, source rock
heterogeneity, distribution of organic-rich and -lean intervals, and evidence for
migrated hydrocarbons in a stratigraphic framework with implications for
unconventional shale resources evaluation. While different workers have conducted
lithostratigraphic analysis of the Shublik Formation, and geochemical analyses of
North Slope oils, this work links geochemistry, sedimentology, and petroleum system
analysis, providing detailed shale resource system evaluation, which ultimately
contributes to the growing body of knowledge in such exploration frontiers. This
dissertation consists of the following three chapters.
Chapter 1 investigates source rock heterogeneity, vertical variations of source
rock properties, the distribution of organic-rich and -lean intervals, and evidence for
migrated hydrocarbons in the Shublik core in the Phoenix-1 well, drilled in offshore
Arctic Alaska in 1986. Guided by previously published analyses of the Phoenix-1
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core, this study provides the most detailed core-based analysis of the Shublik
Formation to date.
Chapter 1 has been submitted to Marine and Petroleum Geology (in review)
with co-authors Mike Moldowan, Ken Peters, Les Magoon, and Steve Graham. My
contributions to this chapter include conception and design of the study, samples
collection, laboratory work, interpretation and analysis of the resulted geochemical
data and broader implications, and writing the manuscript. Mike Moldowan, Ken
Peters, Les Magoon, and Steve Graham also contributed to development of the scope
and design of the project, assisted with interpretation of the results and broader
implications, and reviewed the manuscript.
In Chapter 2, we conduct a comprehensive biomarker- and diamondoid-based
oil-source rock correlation study of two genetically-distinct Shublik organofacies and
related oil families in the North Slope of Alaska. Analysis of diamondoids confirms
oil types proposed by previous biomarker studies and establishes diamondoid
signatures of source rock end-members. This allows for correlation of biomarker-poor,
overmature Shublik source rock samples to oils, and extends these interpretations over
large areas of the North Slope.
Chapter 2 has been submitted to Organic Geochemistry (in review) with co-
authors Mike Moldowan, Ken Peters, Les Magoon and Steve Graham. My
contributions to this chapter include design and implementation of the study, samples
collection and laboratory analysis, interpretation of results and broader implications.
Mike Moldowan assisted with samples acquisition, and all co-authors contributed to
interpretation of the findings and reviews of the manuscript.
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Chapter 3 is built upon key results concluded from previous dissertation
chapters, but adds additional geologic and paleoenvironmental insight from core and
well log analysis in a regional stratigraphic context.
This paper is in preparation for submission to AAPG Bulletin with co-authors
Ken Bird and Steve Graham. My contributions to this chapter include conception and
design of the study, compilation of existing published data, and interpretation of
results. Ken Bird assisted with design and scope of the study, and all co-authors
contributed to interpretation of the results, and reviews of the manuscript.
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ACKNOWLEDGEMENTS
This dissertation is a collection of research chapters that represents the
completion of my PhD. It is without a doubt that there are many people who supported
and encouraged me along the way of completing my PhD degree. I would like to take
the opportunity to recognize and thank some of those people.
First and foremost, I would like to thank my advisor, Steve Graham. I am
incredibly grateful for his support and mentorship, academically and personally, for
his patience and help every step of the way. I felt encouraged and supported by Steve
in my scientific pursuits, and I am truly thankful for this. I feel so lucky to be a part of
his research group because in many ways they became my family in the US.
I would also like to thank the members of my research committee. Mike
Moldowan has been an unofficial advisor to me, and a large part of my development
as a scientist. Ken Peters’ energy and enthusiasm for writing papers reinvigorated me
throughout this process. Both Mike and Ken have helped me become an observant,
methodical, and confident geochemist, and I am exceptionally grateful for this. I thank
Tapan Mukerji for his availability, support, and for always providing interesting
interdisciplinary perspectives and suggestions for my research.
My journey to this point started long ago, and there are many people from
across the world that require my acknowledgement and thanks. I am grateful to
ExxonMobil Geoscience Scholarship Program for giving me an amazing opportunity
and sponsoring my MS degree in the US at the University of Nevada, Las Vegas. I
want to thank my MS adviser Andrew Hanson for his research guidance and
encouragement, and for introducing me to the Stanford research community that
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became my scientific family. I thank petroleum geology department of Moscow State
University where I got my BS degree. The multitude of incredible professors made the
fundamental sciences and petroleum geology and geochemistry in particular so
fascinating that I had no choice but to dive in. To them, I owe my thirst for knowledge
and scientific travel.
Special thanks are due to Ed and Karen Duncan, and Great Bear Petroleum for
granting access to the Alcor-1 and Merak-1 Shublik cores, sampling permission, and
funding this research. Their generous offer was a key reason for initiating this research
project at Stanford. I am tremendously grateful for their help in setting up the project,
financial support and overall encouragement along the way.
A lot of work goes on behind the scenes, and I would like to thank all of the
Geological Sciences department office staff including Alyssa Ferree, Yvonne Lopez,
Stephanie James, Julie Hitchcock, Javier Illueca, and Lauren Nelson for their
administrative and financial support. Funding for this research/dissertation was
provided by the indistrustrial affiliates of the Basin and Petroleum System Modeling
group (BPSM). Additional funding came from the McGee and Leverson graduate
research grants provided by the Stanford School of Earth, Energy, and Environmental
Sciences.
A number of scientists, faculty members, and Basin and Petroleum System
Modeling program mentors have influenced my scientific development. I thank Erik
Sperling, Rob Dunbar, Jim Ingle, Bob Garrison, Bruce Kaiser, Harry Row, Noelle
Schoellkopf, and Carolyn Lampe for their time, discussions, and feedback. I am very
grateful for the special time I spent in the North Slope of Alaska and the people I got
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to spend it with. This includes helicopter-supported field opportunity, financial
support and logistical help in the field from Dave Houseknecht, Kate Whidden, Julie
Dumoulin, and Bill Rouse. I also want to say special thanks to Les Magoon and
Allegra Hosford Scheirer, my BPSM mentors, for their support and research guidance
over the past five years. I would like to express my gratitude to Gary Muscio - my
Chevron internship mentor and friend. The many conversations with Gary during the
internship and after, has greatly influenced my development as a scientist, and a basin
modeler in particular. Together we built my largest most-detailed 3D petroleum
system model to date, and co-authored a couple of conference abstracts and talks. I am
thankful for this valuable internship experience, his mentorship, support and
encouragement. Last but not least, my deepest gratitude goes to Ken Bird who has
been a tremendous support and has become my unofficial non-Stanford advisor. I will
be forever thankful for the countless hours of brainstorming sessions and North Slope
geology discussions, from the very initiation of this project through the writing
process at the end. Ken is a co-author on my third chapter, which we continuing to
work on, and hope to turn into publications in the near future.
I am deeply grateful for the support and encouragement of my geology friends.
I feel so lucky to have met each of you and will always be grateful for all the time we
spent together. These folks include all BPSM and SPODDS family: Tess Menotti,
Blair Burgreen, Amrita Sen, Yao Tong, Wisam AlKawai, Mustafa Al Ibrahim, Will
Thompson-Butler, Zack Burton, Best Chaipornkaew, Lauren Schultz, Laura Dafov,
Tanvi Chheda; Larisa Masalimova, Matt Malkowski, Theresa Schwartz, Glenn
Sharman, Nora Nieminski, Jared Gooley, Lauren Schumaker, Danielle Zentner, Nadja
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Drabon, Moy Hernandez, Zach Sickmann, Cody Trigg, Nilay Gungor, Chris Kremer,
Jake Harrington, Earth Jaikla, and Devon Orme. And from the greater Stanford Earth
community: Mary Reagan, Stuart Farris, Aaron Steelquist, Marisa Mayer, Steven
Pearcey, Xiaowei Li, Sam Ritzer, Humberto Arevalo. I especially want to recognize
mental and physical help through the tough last couple of months from Zach, Mary,
Will, Stu, Zack, Matt, Moy, Aaron, Best, and Wisam.
Outside the geology circle, I feel fortunate to have met so many friends
through Stanford Russian-speaking Student Association including Lyuba, Mitya,
Sonia, Volodya, Larisa, Alex, Olya, Lera, Oleg, Igor, Pasha, Vika, and Marina, to
mention a few. Thank you for providing work - life balance, for our semi-regular
volleyball games, hiking, camping in the snow, celebrating Russian and American
holidays and birthdays, and simply getting together. I hope we will find a way to stay
in touch in the future.
Finally, this dissertation has been a difficult but wonderful journey towards
finding my research passion, and a discovery along the way the person I was meant to
be. I am especially thankful to my boyfriend Zach Sickmann and his parents who
supported, encouraged, and cheered for me over the last and most important steps of
my PhD. I express my deepest gratitude to my close family and friends at home in
Russia, and especially my parents, Lubov and Alexander Yurchenko, and my brother
Igor. Thank you for supporting me from afar, and believing in me even when I
couldn't. With a family like you, every goal is within reach, and no dream is too big.
This dissertation is dedicated to my mother Lubov, and to the warm memories of my
grandmother Asya and my best friend Alisa.
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TABLE OF CONTENTS
CHAPTER 1. Source rock heterogeneity and migrated hydrocarbons in the
Triassic Shublik Formation and their implication for unconventional resource
evaluation in Arctic Alaska .......................................................................................... 1
ABSTRACT ................................................................................................................... 2
INTRODUCTION .......................................................................................................... 3
GEOLOGICAL BACKGROUND ................................................................................. 4
Shublik Formation lithostratigraphy ....................................................................... 5
Shublik source rock geochemistry .......................................................................... 6
MATERIALS AND METHODS ................................................................................... 7
Dataset ..................................................................................................................... 7
Source rock geochemistry ....................................................................................... 8
Elemental analyses .................................................................................................. 9
RESULTS AND INTERPRETATION ........................................................................ 10
Organic matter type, petroleum potential, and level of thermal maturity from
Rock-Eval pyrolysis ............................................................................................. 10
Evidence of evaporation from n-alkanes distribution ........................................... 13
Analysis of biomarkers .......................................................................................... 14
Thermal maturity .............................................................................................. 14
Variations in organic facies ............................................................................. 16
Estimation of oil cracking and evaporation from quantitative diamondoid analysis
............................................................................................................................... 18
Petroleum generation kinetics ............................................................................... 20
TOC - major and trace elements covariation and XRF chemostratigraphy .......... 21
DISCUSSION ............................................................................................................... 23
Interpretive pitfalls ................................................................................................ 23
Evidence for several charges of petroleum ........................................................... 24
Stratigraphic extent of source rock and non-source intervals ............................... 25
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Implications for understanding Arctic Alaska resource potential ......................... 27
Implications for other unconventional shale resource systems ............................. 28
CONCLUSIONS .......................................................................................................... 29
ACKNOWLEDGMENTS ............................................................................................ 31
REFERENCES ............................................................................................................. 32
TABLES ....................................................................................................................... 39
FIGURES ..................................................................................................................... 46
CHAPTER 2. The role of calcareous and shaly source rocks in the composition of
petroleum expelled from the Triassic Shublik Formation, Alaska North Slope .. 62
ABSTRACT ................................................................................................................. 63
INTRODUCTION ........................................................................................................ 64
MATERIALS AND METHODS ................................................................................. 66
Samples ................................................................................................................. 66
Methods ................................................................................................................. 67
Source rock screening ...................................................................................... 67
Analysis of biomarkers ..................................................................................... 68
Analysis of diamondoids ................................................................................... 68
RESULTS ..................................................................................................................... 69
Source rock screening ........................................................................................... 69
Analysis of biomarkers .......................................................................................... 70
Quantitative diamondoid analysis (QDA) ............................................................. 71
Quantitative extended diamondoid analysis (QEDA) ........................................... 73
Compound specific isotope analysis of diamondoids (CSIA-D) .......................... 73
DISCUSSION ............................................................................................................... 75
Organic matter input .............................................................................................. 75
Oil-source rock correlation .................................................................................... 76
Prediction of source rock character from oil composition ........................................... 78
Redox and salinity ............................................................................................ 78
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Lithology ........................................................................................................... 79
CONCLUSIONS .......................................................................................................... 80
ACKNOWLEDGMENTS ............................................................................................ 81
REFERENCES ............................................................................................................. 82
TABLES ....................................................................................................................... 86
FIGURES ..................................................................................................................... 92
CHAPTER 3. Depositional environment and chemostratigraphy of organic facies
of the Triassic Shublik Formation, Alaska North Slope ....................................... 106
ABSTRACT ............................................................................................................... 107
INTRODUCTION ...................................................................................................... 108
METHODOLOGY ..................................................................................................... 109
PREVIOUS WORK ................................................................................................... 111
Regional geologic setting .................................................................................... 111
Lithostratigraphy ................................................................................................. 112
Paleoenvironment ................................................................................................ 113
Sequence stratigraphy ......................................................................................... 114
Paleoecology ....................................................................................................... 116
Paleoenvironmental controls on distribution of Triassic bivalves ................. 116
RESULTS AND DISCUSSION ................................................................................. 118
Phoenix-1 source-rock distribution model .......................................................... 118
Regional maturity and thickness variations ........................................................ 121
Merak-1 source-rock distribution model ............................................................. 121
Prudhoe Bay source-rock distribution model ...................................................... 122
Modern analog ..................................................................................................... 123
SUMMARY ............................................................................................................... 127
REFERENCES ........................................................................................................... 129
FIGURES ................................................................................................................... 133
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LIST OF APPENDICES
APPENDIX A: SUPPLEMENTARY MATERIAL FOR CHAPTER 1
APPENDIX A-1: Compiled dataset of total organic carbon and Rock-Eval pyrolysis
results for Phoenix-1 core analyzed in this study ....................................................... 158
APPENDIX A-2: Biomarker analysis results ............................................................. 160
APPENDIX A-3: XRF analysis results for Phoenix-1 Shublik core ......................... 163
APPENDIX B: SUPPLEMENTARY MATERIAL FOR CHAPTER 2
APPENDIX B-1: Biomarker analysis results ............................................................. 170
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LIST OF TABLES
CHAPTER 1
Table 1. Total organic carbon and Rock-Eval pyrolysis data ............................. 39
Table 2. Interpretation of Rock-Eval pyrolysis results for eleven key core
samples ................................................................................................. 40
Table 3. Measured geochemical parameters include extract yield and key
biomarker ratios .................................................................................... 41
Table 4. Extent of cracking, key diamondoids concentration and observations
resulted from quantitative diamondoid analysis of Phoenix-1 core
extracts .................................................................................................. 42
Table 5. Petroleum generation kinetic parameters for samples from the Shublik
Formation in the Phoenix-1 well .......................................................... 43
Table 6. ICP-MS elemental analysis results ....................................................... 44
Table 7. Key source rock properties of defined Shublik source rock intervals .. 45
CHAPTER 2
Table 1. Summary of oil and rock samples analyzed in this study .................... 86
Table 2. Carbonate content, total organic carbon (TOC), and Rock-Eval
pyrolysis results for source rock samples ............................................. 87
Table 3. Whole rock and clay x-ray diffraction mineralogy results ................... 88
Table 4. Key biomarker characteristics of oils and rock extracts from the North
Slope of Alaska ..................................................................................... 89
Table 5. Quantitative diamondoid analysis results and extent of oil cracking for
analyzed oil and rock samples ............................................................. 90
Table 6. Quantitative extended diamondoid analysis results ............................. 91
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LIST OF FIGURES
CHAPTER 1
Figure 1. Map of part of Arctic Alaska showing the study area and location of the
sampled data ......................................................................................... 46
Figure 2. Generalized chronostratigraphic column of Arctic Alaska ................. 47
Figure 3. Stratigraphic column of Phoenix-1 Shublik core and methodology .... 48
Figure 4. Lithostratigraphy and representative core photos of collected core
samples ................................................................................................. 49
Figure 5. Total organic carbon and Rock-Eval pyrolysis results ......................... 50
Figure 6. Gas chromatography - flame ionization detection results .................... 51
Figure 7. Correlation between extract yields and Rock-Eval peak S1 (A). Terpane
thermal maturity parameters correspond to the immature to early oil
window maturity range (B) .................................................................. 52
Figure 8. Biomarker analysis results. A - Comparison of terpane and diasterane
mass chromatograms. B - Representative lithology-related biomarker
parameters ............................................................................................. 53
Figure 9. Ternary diagrams of steranes and diasteranes ...................................... 54
Figure 10. The Shublik petroleum generation kinetics measured for two proposed
Shublik organofacies end-members ..................................................... 55
Figure 11. Quantitative diamondoid analysis results ............................................. 56
Figure 12. Total organic carbon versus measured values for elements analyzed by
ICP-MS (A) and HH-XRF (B) ............................................................. 57
Figure 13. A - Schematic cross section from Brooks Range to the Beaufort Sea
through several oil and gas fields. B - Schematic presentation of
primary and secondary migration within and from the Shublik
Formation ............................................................................................. 58
Figure 14. Subdivision of the Shublik Formation into two non-source and four
source intervals based on distinctive geochemical and lithologic
features and their well-log signatures ................................................... 59
Figure 15. Ternary diagram showing variations in mineralogical composition of
the Shublik Formation in the Phoenix-1 core ....................................... 60
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Figure 16. Total organic carbon, carbonate content, hydrocarbon generative
potential, and production index comparison in the Shublik, Niobrara,
and Eagle Ford Formations .................................................................. 61
CHAPTER 2
Figure 1. Generalized chronostratigraphic column of Arctic Alaska .................. 92
Figure 2. Map of part of Arctic Alaska showing the study area, sampled and
referenced data. ..................................................................................... 93
Figure 3. Comparison of terpane mass chromatograms (m/z 191) for all crude oil
and source rock extract samples ........................................................... 94
Figure 4. Chemometric analysis of source- and age-related biomarker ratios .... 95
Figure 5. Quantitative diamondoid analysis results ............................................. 96
Figure 6. Quantitative extended diamondoid analysis (QEDA) results ............... 97
Figure 7. Compound specific isotope analysis of diamondoids (CSIA-D) ......... 98
Figure 8. Ternary diagram of C27, C28, and C29 monoaromatic steroids .............. 99
Figure 9. Ternary diagrams of C27, C28, and C29 steranes and diasteranes ........ 100
Figure 10. Diasteranes/(Dia + regular) C27 steranes versus Ts/(Ts + Tm) plot ... 101
Figure 11. Distribution of tricyclic terpanes and hopanes for oil-source rock
correlation. .......................................................................................... 102
Figure 12. Homohopane distributions for six North Slope oils vary between
calcareous and shaly oil families ........................................................ 103
Figure 13. Variations in homohopane and gammacerane indices indicate redox
and salinity stratification during source-rock deposition ................... 104
Figure 14. Representative lithology-related biomarker parameters support
subdivision into calcareous and shaly oil families ............................. 105
CHAPTER 3
Figure 1. Map of part of Arctic Alaska showing study area, sampled and
referenced data. ................................................................................... 133
Figure 2. Generalized chronostratigraphic column of norther Alaska ............... 134
Figure 3. Schematic cross section from Brooks Range to the Beaufort Sea
through several oil and gas fields ....................................................... 135
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Figure 4. Middle Triassic palaeogeographic map showing approximate location
of the Phoenix-1 and Merak-1 cores .................................................. 136
Figure 5. A - Schematic reconstruction showing oceanic upwelling setting on an
open shelf during deposition of the Triassic Shublik Formation. B -
Lateral distribution of upwelling related facies of the Shublik
Formation and its distal equivalents ................................................... 137
Figure 6. Summary of disputed life habits of halobiids ..................................... 138
Figure 7. Subdivision of the Shublik Formation into two non-source and four
source intervals based on TOC and Rock-Eval pyrolysis results ....... 139
Figure 8. Variation of TOC and Rock-Eval pyrolysis peak S2 in different
lithofacies ........................................................................................... 140
Figure 9. Comparison of variations in mineralogical and elemental composition
of the Shublik Formation in the Phoenix-1 core ................................ 141
Figure 10. Representative core photos of defined source rock intervals in the
Phoenix-1 core .................................................................................... 142
Figure 11. Hierarchical cluster analysis dendrogram resulted from chemometric
analysis of XRF data from Phoenix-1 core ........................................ 143
Figure 12. Variation of selected major and trace elements by chemofacies in the
Phoenix-1 well .................................................................................... 144
Figure 13. Regional structural map of the top of the Shublik Formation ............ 145
Figure 14. Regional isopach map based on well control illustrates total thickness
distribution of the Shublik Formation ................................................ 146
Figure 15. TOC and selected major and trace elements variations in the Merak-1
core ..................................................................................................... 147
Figure 16. Comparison of variations in mineralogical and elemental composition
of the Shublik Formation in the Merak-1 core. .................................. 148
Figure 17. Representative core photographs of Merak-1 core intervals with
elevated TOC values ........................................................................... 149
Figure 18. Hierarchical cluster analysis dendrogram resulted from chemometric
analysis of XRF data from both Phoenix-1 and Merak-1 core ........... 150
Figure 19. Variation of selected major and trace elements by chemofacies in the
combined dataset of Merak-1 and Phoenix-1 measurements ............. 151
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Figure 20. A - TOC variation in PBU U-13 well. B, C, D - Core photographs of
wavy-laminated, fossiliferous claystone and siltstone facies and
Halobia sp. impressions ..................................................................... 152
Figure 21. Stratigraphic cross-section across the Prudhoe Bay unit area based on
conventional core descriptions and sequence stratigraphic framework
............................................................................................................ 153
Figure 22. A - Locations of the California, Peru, Canary and Benguela coastal
upwelling systems. B - Schematic model of environmental conditions
leading to the bivalve-dominated carbonate production of the northern
Mauritanian shelf ............................................................................... 154
Figure 23. Bivalve facies distribution on the northern Mauritanian shelf ........... 155
Figure 24. Schematic diagram of the organic-rich Shublik facies abundant in
monospecific accumulations of Triassic flat clams typical of anoxic to
dysoxic environments ......................................................................... 156
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CHAPTER 1
SOURCE ROCK HETEROGENEITY AND MIGRATED HYDROCARBONS IN
THE TRIASSIC SHUBLIK FORMATION AND THEIR IMPLICATION FOR
UNCONVENTIONAL RESOURCE EVALUATION IN ARCTIC ALASKA
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SOURCE ROCK HETEROGENEITY AND MIGRATED HYDROCARBONS IN
THE TRIASSIC SHUBLIK FORMATION AND THEIR IMPLICATION FOR
UNCONVENTIONAL RESOURCE EVALUATION IN ARCTIC ALASKA
Inessa A. Yurchenko1, J. Michael Moldowan2, Kenneth E. Peters1, 3, Leslie B.
Magoon1, and Stephan A. Graham1
1Department of Geological Sciences, Stanford University, Stanford CA 94305, USA
2Biomarker Technologies, Inc., Rohnert Park CA 94928, USA
3Schlumberger Information Solutions, Mill Valley CA 94941, USA
ABSTRACT
This organic geochemical study of the Triassic Shublik Formation investigates
source rock heterogeneity and vertical variability in organic-richness distribution in
the Tenneco Phoenix-1 well (OCS-Y-0338), drilled in offshore Arctic Alaska in 1986.
Recovered continuous core is nearly 90 m thick core through the entire Shublik
Formation. Guided by previously published analyses of the Phoenix-1 core by
Robison et al. (1996), this study provides the most detailed core-based analysis of the
Shublik Formation to date. Analysis of biomarkers and diamondoids combined with
Rock-Eval pyrolysis results yields evidence of mature migrated hydrocarbons that
may have affected previous interpretations of organic matter type and maturity of this
core. Despite the variable lithology, four identified source rock intervals contain oil-
prone type I kerogens and are immature to marginally mature. Biomarker analysis
indicates the presence of two organic facies deposited under anoxic clay-poor and
suboxic clay-rich environments that likely generated genetically distinct oils.
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INTRODUCTION
It is widely recognized that petroleum source rocks can have significant spatial
variability in lithology, and the quality, quantity and thermal maturity of the organic
matter, which impact resource potential and the composition of expelled petroleum.
However, most oil-source rock correlation studies focus on only a few selected rock
samples that may not be representative of the entire source-rock interval. In practice,
most conventional cores target reservoir rocks, and most source rock analyses use
cuttings and/or outcrop samples, thus creating interpretive pitfalls. Recent success in
shale-oil and shale-gas exploration and production shifts the research focus from
reservoir to source rock and elevates the importance of recognizing geochemical and
lithologic heterogeneity. Moreover, this sparked scientific interest to identify new
unconventional hydrocarbon facies within the source rock and to better understand the
distributions of their reservoir and source rock properties for a more accurate resource
assessment (Jarvie, 2012; Schneider et al., 2013). Source rock cores are now an
essential part of the unconventional shale resource exploration procedure providing
many opportunities for advanced shale research.
Despite much work, the nomenclature for unconventional shale resource
systems remains poorly defined and sometimes misleading. Shale, mudstone, and
source rock are terms often used interchangeably despite fundamentally different
lithologic and geochemical characteristics. A shale resource system is an organic-rich
mudstone that serves as both source and reservoir rock for generated oil and gas
(Jarvie, 2012). It can also charge and seal petroleum in juxtaposed organic-lean facies.
Thus, all of the elements and processes in a conventional petroleum system (Magoon
4
and Dow, 1994) also apply to shale resource systems. The pod of active source rock
remains a key component of both conventional and unconventional systems.
The primary objective of this research is to understand how lithologic
heterogeneity relates to the distribution of source rock properties and to quantify its
impact on resource potential. To fulfill this objective, a thorough core-based
investigation was conducted on the Triassic Shublik Formation source rock in Arctic
Alaska.
GEOLOGICAL BACKGROUND
Arctic Alaska is one of the world’s most petroliferous regions, containing a
great share of U.S. energy resources (Bird and Houseknecht, 2011). Nearly all
petroleum-producing fields are located in the central North Slope between the
National Petroleum Reserve in Alaska (NPRA) to the west and the Arctic National
Wildlife Refuge (ANWR) to the east (Fig. 1). Most of the petroleum production is
from the northern part of the central North Slope, whereas the area to the south
remains a risky exploration frontier. The origin of North Slope petroleum has been
debated and discussed in numerous publications since the discovery of the supergiant
Prudhoe Bay Field in 1967. It is widely recognized that crude oil accumulations in the
North Slope commonly represent mixtures of oil derived from several source rocks
(Seifert et al., 1980; Wicks et al., 1991; Masterson, 2001; Peters et al., 2008). Four key
petroleum source rocks in the North Slope include: the Triassic Shublik Formation;
Jurassic Lower Kingak Shale; Cretaceous pebble shale unit and the Cretaceous Hue
Shale (Magoon and Bird, 1985; Bird, 1994; Houseknecht and Bird, 2004; Peters et al.,
2006) (Fig. 2). Other source units proposed in the North Slope include, but are not
5
limited to: the Carboniferous to Permian Lisburne Group; the Cretaceous Seabee and
Torok formations; and the Tertiary Canning Formation (Claypool and Magoon, 1985,
Lillis et al., 1999; Lillis, 2003; Magoon et al., 1999; Peters et al., 2007).
The Middle to Upper Triassic Shublik Formation is a key source rock in the
North Slope of Alaska and the greater Prudhoe Bay Field area. This accounts for
nearly all of the oil in the Kuparuk River Oil Field and about a third of the oil in the
Prudhoe Bay Oil Field (Peters et al., 2008) (Fig. 1). Although it has been recognized
that organic-rich Shublik rocks show variable lithology, the majority of the research
historically focused on organic geochemical assessments of Shublik oil types, rather
than the source rock itself.
Shublik Formation lithostratigraphy
The Shublik Formation is a laterally continuous (over 400 km) and vertically
variable (20 to 150 m) (Bird, 1994) unit that has been widely described in both
outcrop and in the subsurface. Since it was first described by Leffingwell (1919),
mapped by Keller et al. (1961), and measured by Detterman (1970), the Shublik
Formation has been divided into different facies, units, and zones (Dingus, 1984;
Parrish, 1987; Kupecz, 1995; Hulm, 1999; Parrish et al., 2001; Kelly et al., 2007;
Hutton, 2014). As described by Parrish et al. (2001), the Shublik Formation contains a
characteristic set of lithologies that include glauconitic, phosphatic, organic-rich, and
cherty facies. Perhaps the most widely-used subclassification of the Shublik Formation
is the zonation scheme employed within the Prudhoe Bay unit (Kupecz, 1995), which
subdivides the Shublik Formation into four zones (from A, shallowest to D, deepest).
These zones show different gamma-ray log signatures, which reflect the lithologic
6
contrast between phosphatic sandstone (zone D), interlaminated black shale and
limestone (zone C), phosphorite and phosphatic carbonate (zone B), and
interlaminated shales and carbonate grainstone (zone A). Hulm (1999) extended this
interpretation regionally outside of the Prudhoe Bay unit and into the NPRA area, and
provided a detailed conventional core description for 10 wells, that allowed the
subdivision of the Shublik Formation into 12 depositional facies. Hulm’s facies
classification and some core descriptions were adopted and used in this study (Figs. 3
and 4).
Shublik source rock geochemistry
Although lithological heterogeneity and thickness variability of the Shublik
Formation is widely recognized, most of the literature refers to it as one source rock
unit. Several studies consider the Middle to Upper Triassic Shublik Formation to be
the major source rock for oil in the North Slope (Seifert et al., 1980; Magoon and Bird,
1985; Bird, 1994; Masterson, 2001; Peters et al., 2008). Magoon and Bird (1985)
reported that average richness for Shublik Formation is 1.7 wt%, and that it contains
type II/III (hydrogen index, HI = 200 - 300 mg hydrocarbons/g TOC) organic matter
in the west and type I (HI > 600 mg hydrocarbons/g TOC) in the Prudhoe Bay area.
Bird (1994) showed that total organic carbon (TOC) in the Shublik Formation ranges
from 0.49 to 6.73 wt%, with an average value of 2.3 wt%. Peters et al. (2007) noted
that most of the present-day Shublik Formation is mature to overmature, which
complicates estimation of the original TOC and source-rock generative potential.
Robison et al. (1996) published the most detailed core-based analysis of the Shublik
Formation in the Phoenix-1 well (Fig. 1). Their study utilized more than 60 samples in
7
about 90 meters of completely cored Shublik section and suggested the presence of
multiple organofacies with different hydrogen indices and TOC values. Current work
utilizes and re-analyzes Rock-Eval analysis results from Robison et al. (1996) that
provide improved understanding of Shublik geochemical heterogeneity in Phoenix-1
core.
Masterson (2001) conducted a comprehensive geochemical evaluation of the
Shublik Formation. He compared biomarker signatures of core extracts from the
Prudhoe Bay Field to extracts in the Phoenix-1 well in a regional context of proximal
shaly facies versus distal calcareous facies. Masterson (2001) concluded that core
extract from the proximal shaly Shublik facies at Prudhoe Bay Field are
geochemically distinct from the distal calcareous Shublik facies as well as overlying
GRZ and Kingak (Fig. 2).
MATERIALS AND METHODS
Dataset
In order to better understand how lithological heterogeneity relates to source
rock properties in the Shublik Formation, a detailed core-based analysis of the
Phoenix-1 core was conducted. The Tenneco Phoenix-1 well (OCS-Y-0338), drilled
offshore on a structural feature northwest of the Prudhoe Bay Field in 1986, recovered
continuous core through the entire Shublik Formation. The published analyses of this
core (Robison et al., 1996) and its later release to the U.S. Geological Survey Core
Research Center in Denver, Colorado, allows the most detailed core-based analysis of
the Shublik Formation to date. As part of the current work, this core was viewed at the
USGS Core Research Center, and scanned at 0.3-m intervals, using a hand-held x-ray
8
fluorescence (XRF) device. Eleven samples from six different lithologies (originally
detailed and described by Hulm, 1999) were collected for total organic carbon (TOC),
Rock-Eval pyrolysis, carbonate content, elemental analysis (ICP-MS), and analysis of
biomarkers and diamondoids (Fig. 3). Representative core photos of collected samples
are displayed in Fig. 4 and a complete set of core photos can be found in D’Agostino
and Houseknecht (2002). Based on the results of the initial source rock screening and
analysis of biomarkers, two organic-rich samples (PH07 and PH09) were selected for
petroleum generation kinetic analysis. In addition, Rock-Eval pyrolysis results for the
11 analyzed samples are discussed with re-analyzed results of published data from the
Phoenix-1 core by Robison et al. (1996) and Masterson (2001). This appraisal
improved the quality of interpretation by linking geochemical and lithological data.
Source rock geochemistry
In order to assess organic matter quantity, quality, and thermal maturity, all
collected samples were analyzed using standard Rock-Eval pyrolysis - TOC source
rock screening procedure (Peters and Cassa, 1994). Analyses (GeoMark Research,
Ltd.) employed Rock-Eval II and LECO C230 instruments. In addition, carbonate
content measurements were based on sample weight differences before and after acid
treatment.
Petroleum generation kinetics of two selected source-rock samples (GeoMark
Research, Ltd.) used kinetic modeling based on a discrete activation energy
distribution using three different pyrolysis heating rates as discussed in Peters et al.
(2015).
9
All samples were analyzed for biomarkers and diamondoids at Biomarker
Technologies, Inc. Analysis of biomarkers involved organic matter extraction, gas
chromatography (GC), gas chromatography – mass spectrometry (GCMS) and gas
chromatography – mass spectrometry – mass spectrometry (GC-MS-MS) using
laboratory procedures described in Peters et al. (2005). Knowledge of presence,
absence and relative abundance of different biomarkers was used to assess the level of
thermal maturity, environment of deposition, and the quality of organic matter (Peters
et al., 2005). Analysis of diamondoids included quantitative diamondoid analysis
(QDA) described in Moldowan et al. (2015). Diamondoids are highly stable, highly
resistant cage-like compounds commonly found in oil (McKervey, 1980). They are
more thermally resistant than biomarkers and most other hydrocarbons in oil. The
correlation between diamondoid (methyldiamantanes) and biomarker (stigmastane)
concentrations in source rock extracts was used to estimate the level of thermal
maturity and the extent of secondary cracking (Dahl et al., 1999).
Elemental analyses
Major and trace element data were measured to link organic geochemistry and
core description data, and to provide quantitative prediction of organofacies
variability. The elemental concentrations for 11 collected samples were quantified
using traditional inductively-coupled plasma (ICP) analysis (Bureau Veritas Group,
North America) using the MA200 package. In addition, the entire core was scanned
using a hand-held XRF Bruker Tracer IV-SD at 0.3-m intervals. Yurchenko et al.
(2016) described the instrument settings for trace elements analysis. The current
method provides rapid and non-destructive measurements of major elements heavier
10
than sodium, along with trace elements from barium to uranium. Quantification of
elemental concentrations was performed using matrix-specific calibration described by
Rowe et al. (2012). Note that the reference material set was developed for typical
mudrock analysis and all references have phosphorus concentrations less than 20 wt%,
whereas the Shublik Formation is a very phosphate-rich unit and its phosphorus
content often exceeds 20 wt%. Thus, phosphorus content (wt%) measured using ICP
was utilized to define the phosphorus calibration for proper conversion of net count
rates to concentration.
RESULTS AND INTERPRETATION
Organic matter type, petroleum potential, and level of thermal maturity from
Rock-Eval pyrolysis
In order to assess organic matter type (quality), petroleum potential (quantity),
and level of thermal maturity of the Shublik Formation in Phoenix-1 well, a total of 72
core samples were analyzed using Rock-Eval pyrolysis - TOC (Table 1; Appendix A-
1). The selected sample set includes 11 samples from six different lithologies collected
for this study, as well as previously published data by Masterson (2001) and Robison
et al. (1996). The determination of lithology for pre-existing geochemical data was
based on reported depth of each sample and sedimentological core description by
Hulm (1999).
For source rock quality and thermal maturity, we used generally accepted
criteria described by Peters and Cassa (1994). In addition, we modified their
petroleum potential parameters and classified samples with TOC >2 wt% and S2 >10
mg HC/g rock as having good petroleum potential, whereas those with TOC<1 wt%
11
S2< 5 mg HC/g rock have poor petroleum potential. Samples with PI and Tmax values
less than 0.1 and 435 °C were interpreted as immature. Conversely, samples with PI
and Tmax greater than 0.4 and 470°C were considered postmature.
The Shublik samples in Phoenix-1 core show variable quantity (S2 - TOC
plot), quality (HI – OI plot) and thermal maturity (PI - TOC plot) of organic matter
(Fig. 5A), with TOC ranging from 0.5 to 10.1 wt% (poor to good), S2 ranging from 0.8
to 75.2 mg HC/g rock (poor to good), HI varying from 29 to 965 mg HC/g TOC (inert
type IV to highly oil-prone type I) , PI from 0.03 to 0.4 (immature to late maturity),
and Tmax from 420 to 459 °C (immature to late maturity). Interpretation of Rock-Eval
pyrolysis results depends on multiple factors (e.g., relative abundance of OM,
lithology, level of thermal maturity, sampling, contamination, and measured
procedures), and should be applied with caution for proper petroleum generative
potential assessment (Espitalié et al., 1977; Peters, 1986).
Thus, the modified Van Krevelen diagram (HI – OI plot) (Fig. 5A) suggests
different organic matter types from oil-prone type I to gas-prone type III and inert OM
based on HI values. Conversely, HI derived from the regression line in S2 versus TOC
cross-plot measures HI = 757 mg HC/g TOC is indicative of highly oil-prone type I
kerogen. The reduced S2 pyrolysis yields and resulting reduction of the hydrogen
indices has been recognized as kerogen dilution by mineral matrix effect (Dahl et al,
2004; Peters, 1986; Katz, 1983; Espitalié et al., 1980).
The Shublik interval in the Phoenix-1 well is marginally mature based on the
average values of Tmax (438 °C) and PI (0.1) values. A PI vs. TOC cross-plot
suggests immature to early phase of hydrocarbon generation (PI <0.15) for source
12
rock samples with indigenous bitumen, which indicates the presence of migrated
hydrocarbons (PI >0.15). In addition, the oil saturation index (OSI = (S1 x 100)/TOC)
values greater than 100 mg HC/g TOC also suggest that producible oil is present
(Jarvie and Baker, 1984).
We plot TOC and Rock-Eval pyrolysis results versus lithofacies (Fig. 5B) and
depth (Fig. 5C) in order to evaluate lithologic and stratigraphic effects on source rock
properties. Most samples collected from parallel-laminated claystone (PC), wavy-
laminated, fossiliferous claystone and siltstone (WC), and bioclastic, argillaceous
packstone and grainstone (BP) facies, display good petroleum potential and the
indigenous nature of the bitumen. However, samples from the bioclastic wackestone
(BW) facies with poor to good organic richness show evidence for both in situ and
migrated petroleum (Fig. 4B). Samples collected from graded grainstone and
packstone (GG); bioturbated, calcareous sandstone (CS); bioturbated, glauconitic
sandstone and grainstone (GS); and nodular phosphorite (NP) facies show poor to fair
petroleum potential, as well as evidence of migrated petroleum. Further, the oil
saturation index (OSI = (S1 x 100)/TOC) values greater than 100 mg HC/g TOC also
suggest producible oil (Jarvie and Baker, 1984).
In addition, geochemical logs (Fig. 5C) were used to divide the Shublik
Formation in the Phoenix-1 well into four stratigraphic intervals. Two of these
intervals show higher generation potential and good source rock characteristics, while
the other two show poor source rock quality but elevated quantities of migrated
hydrocarbons.
13
Table 2 summarizes the source rock screening results for 11 samples from six
different lithofacies submitted for biomarker and diamondoid analyses. Four samples
(PH01, PH07, PH08, and PH09) from two lithofacies (PC and WC) show good
petroleum potential (TOC = 3.1 – 5.4 wt%, S2 = 17 – 41 mg HC/g rock), HI > 550 (mg
HC/ g TOC), and immature indigenous bitumen (PI = 0.04 – 0.07). However, three
samples (PH03, PH11, and PH13) from two other lithologies (BP and CS) show low
organic richness (TOC = 0.6 – 1.3 wt%), and high production (PI = 0.15 – 0.3) and oil
saturation indices (94 – 177 mg HC/g TOC), indicative of migrated petroleum.
Bioturbated, calcareous sandstone (CS) lithofacies description for sample PH13, as
well as visible oil stains (Fig. 3) observed in the core section where PH03 was
collected, support migrated oil interpretation. Four samples (PH02, PH05, PH06 and
PH12) from three other lithologies (GG, BP and BW) show fair to good petroleum
potential (TOC = 1.1 – 1.8 wt%, S2 = 3 – 9 mg HC/g rock), HI = 296 – 479 (mg HC/ g
TOC). However, elevated PI values (0.09 – 0.12) conflicting with immature
indigenous bitumen maturity parameters (PI = 0.04 – 0.07) suggest presence of higher
maturity migrated fluids.
Evidence of evaporation from n-alkanes distribution
All rock extracts were analyzed by gas chromatography with flame ionization
detection (GC-FID). Based on the GC-FID traces (Fig. 6), samples PH02, PH03,
PH05, PH11, and PH12 have lost nearly all compounds in the boiling range of n-C11
to n-C12, due to evaporative loss during storage. Those extracts show significant
concentrations of hydrocarbons eluting after the C15 n-alkane that were not altered
significantly by evaporation. Sample PH13 lost most of the hydrocarbons up to about
14
n-C16, demonstrating even greater evaporative loss during storage. This should be
expected considering the sandy lithology of the sample. Samples PH01, PH06, PH07,
PH08, and PH09 show significant n-C11 peaks indicating that the loss by evaporation
at n-C11 was not severe. These samples have high TOC values and low permeability
lithologies (claystone and wackestone), and retained light hydrocarbons better than the
higher permeability, low TOC samples (packstone, grainstone, and sandstone).
In addition, three persistent peaks around n-C13 occur in all of the samples,
except PH13. This is the signature of synthetic drilling mud of unknown origin, which
should not contribute diamondoids or biomarkers.
Analysis of biomarkers
Thermal maturity
Extract yields of 0.6 to 5 mg HC/g rock, Rock-Eval peak S1 values of 0.39 to
2.33 mg HC/g rock (Fig. 7A), and production indices (PI) of 0.04 to 0.3 show the
presence of free hydrocarbons in the sampled rocks. Based on Rock-Eval pyrolysis
results four samples (PH01, PH07, PH08, and PH09) show immature indigenous
bitumen characteristics, and remaining samples show evidence for higher maturity
migrated hydrocarbons. The following discussion addresses the question of whether
bitumen extracted from proposed source rocks contains migrated oils.
A wide maturity range is indicated by various biomarker thermal maturity
parameters (Table 3), suggesting a mature biomarker overprint from the migrated
hydrocarbons. The ratio of H32 22S/(R+S) homohopanes is highly specific for
immature to early oil generation and reaches end point at about 0.57 – 0.62. Thus,
measured values of 0.59 to 0.61 indicate that the main phase of oil generation has been
15
reached or surpassed (Seifert and Moldowan, 1986; Peters et al., 2005). As reported,
lithology and hypersalinity may affect the rate of 17α-homohopane isomerization (Ten
Haven et al., 1986; Moldowan et al., 1992).
The sterane maturity parameters C29 ααα 20S/(20S+20R) and C29
αββ/(αββ+ααα) (Seifert and Moldowan, 1986; Peters et al., 2005) are highly specific
for immature to mature range. The sterane ratio C29 ααα 20S/(20S+20R) reaches end
point at about 0.52 – 0.55, around equivalent vitrinite reflectance of Ro = 0.8%. The
C29 αββ/(αββ+ααα) ratio has values around 0.25 at the onset of the oil window and
reaches end point at 0.67 to 0.71, around equivalent maturity of Ro = 0.9%. Both
20S/(20S+20R) and αββ/(αββ+ααα) measurements were done by GCMS/MS of C29
steranes to avoid interference by co-eluting peaks and show values of 0.48 to 0.6 and
0.23 to 0.6, respectively (Table 3). Thus, the entire oil window appears to be present in
just 90 m of the Phoneix-1 Shublik section. As reported, both 20S/(20S+20R) and
αββ/(αββ+ααα) isomerizations can be affected by weathering, biodegradation, and
organofacies differences (Moldowan et al., 1992; Peters et al., 2005), however in this
case it is likely linked to the presence of migrated mature oil.
The ratio of Ts/(Ts+Tm) trisnorhopanes is applicable over a wide range from
immature to postmature and is highly dependent on source (Seifert and Moldowan,
1986; Peters et al., 2005). The Ts/(Ts + Tm) undergoes full conversion at the end of
the oil window (Ro = 1.35%). For analyzed samples, these ratios range between 0.34
and 0.44 (Fig. 7B; Table 3), which corresponds to the early oil window maturity
range, and is consistent with the immature indigenous bitumen interpretation derived
from Rock-Eval pyrolysis. The thermal maturity effect on C29 Ts /(C29 Ts + C29
16
hopane) is comparable with, but slightly less than, the effect on Ts/(Ts + Tm). Values
of C29 Ts / (C29 Ts + C29 hopane) are in the range of 0.14 – 0.34, which correspond to
the immature to early oil window maturity range. Both of these ratios are reported to
be sensitive to clay-catalized reactions and oxicity of the depositional environment
(Peters et al., 2005). Most of the samples plot near the maturity trend line; the two
outliers PH02 and PH07 may represent different organic facies (Fig. 7B).
The monoaromaric steroid side chain scission (carbon-carbon cracking)
maturity parameter MA(I)/MA(I+II) (Mackenzie et al., 1981; Seifert and Moldowan,
1986), with MA(I) as C21-C22 monoaromatic steroids and MA(II) as the sum of C27-
C26 (S + R-isomers) monoaromatic steroids (Peters et al., 2005), ranges from 0.06 to
0.25, also indicating early maturity. Some interference from source input is possible
for this ratio (Peters et al., 2005).
Variations in organic facies
Although conflicting maturities among the bitumen extracts can result from
contamination by migrated oil (see discussion), a large number of biomarker
parameters (Appendix A-2) were analyzed to infer variability in the type of organic
matter, environment of deposition, lithology, and organofacies in the corresponding
source rocks. Analyses of biomarkers revealed that C24/C23 tricyclic terpanes ratio,
C29/(C29 + C30 hopanes), diahopane index (C30 18α-diahopane /(C30 18α-diahopane +
C30 hopane)), and C27 - C28 - C29 steranes and diasteranes were the most useful
parameters for differentiating Shublik rock extracts into two genetically-distinct
organic facies, labeled organofacies C and S in Figs. 8 and 9. Combinations of these
parameters are commonly used to differentiate between marine carbonate versus shale
17
source rocks. However, considering evidence for possible migrated hydrocarbons from
a deeper Shublik charge, as well as reported lithofacies and measured carbonate
content (Table 2) for analyzed rock extracts, the term “carbonate” should be used with
caution.
Based on Rock-Eval pyrolysis results, only four samples (PH01, PH07, PH08,
and PH09) from two lithofacies (parallel-laminated claystone and wavy-laminated
claystone) demonstrate good petroleum potential and indigenous bitumen (red
diamonds on Fig. 8B). Three of these four samples (PH01, PH08, and PH09) plot in
the same group, showing low diasteranes/steranes, C24/C23 tricyclic terpanes,
diahopane index, and high C29/C30 hopane values indicative of a carbonate source.
Conversely, sample PH07 is interpreted as a shaly source. However, measured
carbonate content for PH01, PH08, and PH09 samples is 24, 30, and 38 wt%, which is
less than the 50% implied for a typical “carbonate” source. Furthermore, “shaly”
sample PH07 is in the same range with a carbonate content of 25 wt%.
Steranes and hopanes have different biological precursors and reflect different
input of eukaryotic (mainly algae and higher plants) versus prokaryotic (bacteria)
organisms, respectively. However, presences of both diasteranes (rearranged steranes)
and diahopanes may be related to precursors that have undergone oxidation and
rearrangement by clay-mediated acidic catalysis (Peters et al., 2005). Thus, low
diasteranes/steranes and diahopane index ratios for PH01, PH08, and PH09 samples
most likely indicate anoxic clay-poor environment during diagenesis, whereas higher
values for these ratios in PH07 sample suggest deposition under clay-rich oxic or
18
suboxic conditions. Samples PH07 and PH09 were selected as end-members for
kinetic analysis (Fig. 10).
All samples contain relatively abundant tricyclic terpanes, ranging from C19 to
C30. Tricyclic terpanes are structurally similar to hopanes (Trendel et al., 1982),
although they originate from different biological precursors (Peters et al., 2005).
Several sources have been proposed for the origin of tricyclics, including bacterial or
algal (Tasmanites or other algae) lipids (e.g., Ourisson et al., 1982; Revill et al., 1994;
Aquino Neto et al., 1983; Azevedo et al., 1992), although high concentrations of
tricyclic terpanes commonly correlate with high-paleolatitude Tasmanites-rich rocks,
suggesting their origin is from these unicellular green algae (Aquino Neto et al., 1992).
Widespread occurrence of Tasmanites is reported in northern Alaska, in Middle–
Upper Triassic deposits of Svalbard, the Barents Shelf, and Taimyr, Siberia (Vigran et
al., 2008). This supports a Tasmanites origin for tricyclic terpanes in the Shublik
source rock.
Estimation of oil cracking and evaporation from quantitative diamondoid
analysis (QDA)
Moldowan et al. (2015) indicated that the ratio of (1- + 2-
methyladamantanes)/(3- + 4-methyldiamantanes) shows little effect of oil cracking
and is relatively constant for each source (Fig. 11A). The four samples with good
petroleum potential and immature indigenous bitumen based on Rock-Eval screening
results (red diamonds on Fig. 11) approximately follow the established trend line,
suggesting no greater loss of 1- + 2-methyladamantanes relative to 3- + 4-
methyldiamantanes, whereas the remaining samples (black squares on Fig. 11) appear
19
to have lost 1- + 2-methyladamantanes relative to 3- + 4-methyldiamantanes. Fig. 11B
shows a linear correlation between n-C11/n-C15 ratios of n-alkanes versus 1- + 2-
methyladamantanes. This confirms evaporative loss during storage by preferential
evaporation of the more volatile compounds from the rock. This observation makes
sense, considering that the core was drilled and placed in core storage in 1987.
On the other hand, the (1- + 2-methyladamantanes)/(3- + 4-
methyldiamantanes) ratio for four samples, PH01, PH07, PH08 and PH09, is fairly
constant, indicating that they have not experienced significant evaporative losses.
Therefore, the 3- + 4-methyldiamantanes concentrations can be used to estimate the
extent of oil cracking for each of them (Fig. 11C). The extract from sample PH08
shows a 3- + 4-methyldiamantanes concentration at 7.4 ppm, which suggests little, if
any alteration by thermal cracking has occurred. We can use the 7.4 ppm value as a
“diamondoid baseline”, which is the diamondoid concentration generated from the
kerogen of a given source rock in the bitumen or produced oil. Wang et al. (2014)
estimated 10.6 ppm as the diamondoid baseline for a suite of Shublik oil samples,
which is similar to the 7.4 ppm value. Two oil samples that showed very strong
biomarker indications of limestone source rock were estimated by Wang et al. to have
a diamondoid baseline of 5.3 ppm. The diamondoid concentration for sample PH08
lies between the values from Wang et al. (2014).
Assuming a diamondoid baseline of 7.4 ppm for the Phoenix-1 core samples
allowed an estimate of the extent of cracking using the formula of Dahl et al (1999),
resulting in cracking percentages for PH01, PH07 and PH09 of 72.9, 66.3 and 80.0 %,
respectively (Table 4). These high cracking values are impossible for organic matter
20
that has only reached maturity up to oil window (as indicated by Rock-Eval and some
biomarker parameters). They suggest that a charge of postmature hydrocarbons, wet
gas window or probably higher maturity, infiltrated much of the Phoenix-1 well core.
Due to the high maturity of this charge it should not entrain high concentrations of
biomarkers, although some less mature oil that has biomarkers could be included in
those migrated fluids.
Petroleum generation kinetics
Petroleum generation kinetics for two selected end-member samples (PH07
and PH09) were measured by GeoMark Research, Ltd. using kinetic modeling based
on a discrete activation energy distribution and three different pyrolysis heating rates,
as discussed in Peters et al. (2015). The organofacies S (clay-rich oxic/ suboxic
conditions) PH07 sample of wavy-laminated claystone lithology has 25 wt%
carbonate, 1.3 wt% total sulfur, TOC = 4.8 wt% and HI = 613 mg HC/ g TOC, Tmax
= 431 °C, and classifies as Type I, whereas the organofacies C (anoxic clay-poor
conditions) PH09 sample of parallel-laminated claystone lithology has 38 wt%
carbonate, 0.6 wt% total sulfur, TOC = 5.4 wt%, HI = 759 mg HC/ g TOC, Tmax =
436 °C, and also classifies as Type I.
In order to illustrate the differences in timing of hydrocarbon generation
between the organofacies, a constant heating rate of 3 °C per million years was used to
calculate kerogen transformation as a function of temperature using the optimized
discrete activation energy distributions and corresponding frequency factors (Fig. 10,
Table 5). Organofacies S of the Shublik Formation begins to generate hydrocarbons
earlier than organofacies C, reaching 10%, 50% and 90% transformation at
21
temperatures of approximately 90, 100 and 113.5 °C, as opposed to 97, 107 and 118
°C for organofacies C (Fig. 10). This is counter-intuitive because kerogen in many
calcareous source rocks is sulfur-rich (Peters et al., 2005) and transforms to
hydrocarbons at lower temperatures than shaly source rocks due to sulfur-carbon
bonds, which break more rapidly than carbon-carbon bonds under thermal stress.
Samples PH07 and PH09 have carbonate and sulfur contents of 25 and 1.3 wt%, and
38 and 0.6 wt%, respectively.
Thus, both samples show high TOC, Type I organic matter, and have
production index values of ≤ 0.05. This indicates that none of them have generated
significant concentrations of liquid hydrocarbons. The small differences in Tmax (431
°C for faster organofacies S versus 436 °C for slower organofacies C), therefore, could
possibly be attributed to kinetic properties. QDA results suggest that a charge of
postmature hydrocarbons, wet gas window or probably higher maturity infiltrated both
samples. Due to the high maturity of this charge (66.3% and 80% of cracking) it
should not entrain high concentrations of biomarkers, and/or affect bulk kinetic
analysis determined from kerogen conversion. The Shublik petroleum generation
kinetics curve from Masterson (2001) (sample 97R00331; 2421.941 m depth) shows a
close match to organofacies S curve (Fig. 10, Table 5)
TOC - major and trace elements covariation and XRF chemostratigraphy
Organic-richness in shale is mainly a function of production, accumulation and
preservation of organic matter closely linked to sediment input, mixing (dilution), and
removal (or destruction) and the environmental conditions in which source rocks were
deposited (Tissot and Welte, 1984; Trabucho‐Alexandre, 2015). Some major and trace
22
elements and their covariation with TOC proved to be useful in recognizing what
combination of controlling factors yields organic-rich sediments.
Fig. 12A summarizes crossplots of TOC versus calcium (Ca), aluminum (Al),
phosphorus (P), molybdenum (Mo), vanadium (V) and nickel (Ni) commonly used as
carbonate content, detrital flux, paleoredox, and paleoproductivity proxies
(Tribovillard et al., 2006). One distinct observation is the linear relationship between
TOC and Ni (Fig. 12A). This is expected, considering that nickel and vanadium are
the two most abundant metals in petroleum, and their concentrations and ratios are
commonly used in distinguishing oil types worldwide. They both can be derived from
chlorophyll precursors and preserved as porphyrin organometallic complexes under
reducing conditions (abiotic processes; Lewan and Maynard, 1982). However, V and
Ni show variations in oxidation state and solubility as a function of the redox status of
the depositional environment (Tribovillard et al., 2006). Vanadium is a redox-proxy
with minimal detrital influence soluble under oxidizing conditions and less soluble
under reducing conditions, resulting in authigenic enrichments in oxygen-depleted
sediments. Biotic processes comprise the uptake of nickel that serve as micronutrient
for plankton, and gets delivered to the sediment mainly in association with organic
matter, making it a good proxy for organic carbon sinking flux (productivity;
Tribovillard et al., 2006). After organic matter decays in reducing sediment, Ni may be
preserved with porphyrin complexes.
The direct correlation of TOC and Ni and the lack of correlation with other
proxies (Fig. 12 A and B) suggests that variation in primary organic productivity is the
main factor controlling organic-richness distribution in the Shublik Formation. Similar
23
correlation of TOC with copper (Cu) (Table 6 and Appendix A-3), which also behaves
as a micronutrient, supports this interpretation.
Fig. 12B displays XRF chemostratigraphic logs, where Ni-TOC linear relation
(TOC = 0.07 + 0.05 x Ni) was used to highlight (in red) organic-rich intervals (TOC
>2 wt%, Ni > 38.6 ppm) and analyze the behavior of other elemental proxies (Ca, Al,
P, Mo, S) in those intervals. However, redox sensitive elements, such as Mo, S, V, fail
to express linear covariation with TOC. They clearly define three stratigraphic
intervals enriched in these elements, as well as Ni, Al and TOC, implying the
deposition of high TOC, relatively clay-rich, and carbonate-poor facies under anoxic
conditions. In addition, two intervals show strikingly high P content related to the
deposition of phosphorites, confirmed by lithologic descriptions of the core. One of
these high P intervals coincides with the deposition of organic-rich facies.
DISCUSSION
Interpretive pitfalls
Bitumen extracts from Shublik samples in the Phoenix-1 core show evidence
of migrated oil. Expulsion from the fine-grained source rock, as well as migration
through coarser-grained carrier beds continues throughout petroleum generation, and
different compounds (with different molecular weight and adsorptivity) form at
different times during this process. Thus, mixing of indigenous source-rock bitumen
and migrated oil may result in conflicting thermal maturities and organofacies
assignments. Therefore, for correlations between samples, we used a multi-proxy
approach to improve the reliability of final interpretations.
24
Petroleum is a complex mixture of fluid and gases generated and expelled from
source rock sections. Commercial oil accumulations may contain contributions from
more than one source rock section. This study is limited to 11 selected samples from
90 m – thick Shublik source rock sections. Understanding how representative these
samples are of the composite section, and the difference in timing of generation by
different organofacies are important factors in evaluating the petroleum generative
potential of the different source rock intervals and the entire Shublik section, as well
as predicting the composition of generated hydrocarbons and possible migration
pathways.
Evidence for several charges of petroleum
The Shublik Formation in the Phoenix-1 well is immature to early mature
based on immature indigenous bitumen interpretation from Rock-Eval pyrolysis, and
supported by tisnorhopane and monoaromaric steroid biomarker maturity ratios.
However, Rock-Eval pyrolysis results also show evidence of higher maturity migrated
oil with elevated PI values that lack representation of the indigenous hydrocarbons.
Conflicting maturities based on sterane and homohopane biomarker ratios suggest the
presence of high maturity migrated oil. QDA also shows evidence for migrated higher
maturity oil (Fig. 11A). Despite conflicting maturity parameters caused by mixed
indigenous bitumen and higher maturity migrated oil, both components in the extracts
are believed to originate from the Shublik source rock based on the analysis of
biomarkers.
In addition, QDA showed evidence for highly cracked gas (at least 80%
cracked). Both analysis of GC-FID traces of whole rock extracts, as well as QDA,
25
showed loss of the light hydrocarbons due to evaporation during storage (Fig. 11C)
that could have lowered the estimates of percent of cracking. The effect of evaporative
loss on biomarkers concentrations is unclear, and could be minimal.
Figure 13 shows the present-day location of the Phoenix-1 well on the Barrow
Arch and schematically illustrates migration pathways from deeper, more mature
Shublik kitchens (south, and possibly, north) up dip within the source interval and into
juxtaposed non-source facies within the Shublik. This indicates migration away from
the source rock into conventional carrier beds and reservoirs. Expulsion from the
deeper Shublik source rock and up dip migration continues throughout petroleum
generation and different compounds (with dissimilar molecular weight and
adsorptivity) form at different times during this process.
Stratigraphic extent of source rock and non-source intervals
Analysis of TOC and Rock-Eval pyrolysis results (Fig. 5B) allowed
subdivision of the Shublik Formation in the Phoenix-1 well into four stratigraphic
intervals. Two of these intervals display good source rock characteristics, whereas the
other two have poor source quality and show evidence of migrated hydrocarbons.
Detailed chemostratigraphy of the Shublik core (Fig. 12B) helped to better define the
stratigraphic extent of these intervals and allowed subdivision of the upper source rock
interval into three chemostratigraphically and lithologically distinct intervals. Figure
14 summarizes subdivision of the Shublik Formation into two non-source and four
source intervals and displays some distinctive geochemical and lithologic features and
their well-log signatures. The widely-used Shublik zonation (from A to D) scheme of
26
Kupecz (1995) is also shown to demonstrate the possibility of subsurface mapping of
defined intervals.
Table 7 summarizes key source rock properties of defined Shublik source
intervals (SR-1 through SR-4). Because the core is immature, measured TOC and HI
are close to the original values. Note similar average TOC (4.7 to 6.5 wt%) and
average HI (596 – 763 mg HC/ g TOC) values characteristic of Type I kerogen for all
four intervals. However, only the SR-3 interval is defined by organofacies S based on
the biomarker analysis. The SR-3 interval has a distinct facies association of dominant
wavy-laminated claystone and siltstone, interbedded with relatively minor bioclastic
wackestone facies (Hulm, 1999), restricted stratigraphically to the lower part of
Shublik zone C. Hulm (1999) reported that the claystone is characterized by the
abundant white laminae consisting of thin-shelled pectinid bivalves identified as
Halobia (lower Shublik Formation) and Monotis (upper Shublik Formation) by
Dingus (1984). Fossils are so abundant that every parting is entirely covered with
bivalve shell impressions. The bivalves are usually disarticulated and parallel to
bedding. Differential compaction between the shells and matrix resulted in the wavy
laminations. The extreme abundance of these opportunistic bivalves characterizes
areas dominated by dysaerobic depositional conditions (Kupecz, 1995). The
wackestone facies is composed of whole bivalve shells with shell fragments in a
quartzose silt and lime mud matrix and rare brown calcareous, phosphatic nodules
(Hulm, 1999). The fine-grained matrix, presence of whole disarticulated bivalves, and
laminations is interpreted to be deposited below the wave base under relatively low
energy conditions (Jones and Desrochers, 1992; Hulm, 1999). Both facies were
27
deposited on the outer shelf to the lower inner shelf below the storm wave base (Hulm,
1999).
The SR-1 and SR-4 intervals show similar elemental composition (except P) to
SR-3, but different lithofacies associations (Figs. 12 and 14). Interval SR-2 has
strikingly different elemental composition and is characterized by type C kinetics;
whereas, SR-1 shows similar to type S kinetics (measured by Masterson, 2001; Table
7). No kinetics measurements were made in the SR-4 interval. Despite the difference
in lithology and kinetics, all three inetrvals (SR-1, SR-2, and SR-4) are defined by
biomarker organofacies C.
Implications for understanding Arctic Alaska resource potential
Conventional estimates of the volume of petroleum originating from source
rock require information on the distribution, thickness, lithology, original organic
richness (TOCo), original organic matter type (HIo), and petroleum generation kinetics,
as well as present-day thermal maturity (Hantschel and Kauerauf, 2009; Peters et al.,
2006). The Shublik Formation is one of the most important source rocks in Arctic
Alaska, an important remaining petroleum exploration frontier. Although variable
lithology and organic-richness in the Shublik Formation is widely recognized, all of
the published estimates of resource potential refer to it as one source rock unit. These
including a recent comprehensive study by Peters et al. (2006) comparing different
methods of expulsion factors and petroleum charge calculations, as well as 3D
petroleum system modeling of Northern Alaska by Schenk et al. (2012).
This paper expands current understanding of source rock heterogeneity,
thickness, lithology, original organic richness, and organic matter type (HIo), along
28
with petroleum generation kinetics of source intervals that can be used to improve
assessments of the conventional resource potential of the Shublik Formation. In
addition, these data, together with information about thickness of juxtaposed non-
source units, provide evidence for migrated petroleum, as well as evaporative loss
over time of hydrocarbons during storage. This provides a first look at expulsion and
retention of petroleum in source units, and storage capacity of non-source/reservoir
units in the context of an unconventional shale resource system.
Implications for other unconventional shale resource systems
Despite much work, the nomenclature for unconventional shale resource
systems is poorly defined and sometimes misleading. Shale, mudstone, and source
rock terms are often used interchangeably, despite fundamentally-different lithologic
and geochemical contexts. These “shale” resource systems vary considerably from
tight organic-rich calcareous mudstone to siltstone to shale (argillaceous mudstone)
with interbedded conventional reservoir lithofacies (Fig. 15). The term “hybrid” shale
resource system is often applied to systems with juxtaposed organic-rich and -lean
intervals (Jarvie, 2012). Differences in lithofacies and rock permeability play key roles
in oil producibility from these systems. However, the close association of source and
juxtaposed non-source intervals is difficult to define and often the actual source rock
interval(s) is poorly defined. This may affect evaluation of source rock properties
(quantity, quality and thermal maturity) distribution and understanding of migration
pathways within the source interval and into juxtaposed non-source facies, as well as
migration away from the resource system into the carrier beds and conventional
reservoirs. TOC versus mineralogical composition varies in organic-rich (TOC > 2
29
wt%) and organic-lean (TOC < 2 wt%) Shublik samples in Phoenix-1 core. Fig. 15
displays variations in mineralogical composition of 29 Shublik samples (black circles),
and compares their average (grey circle) to average compositions for the major
unconventional shale resource plays (grey diamonds). This highlights the importance
of recognizing heterogeneity and the ambiguity of interpretations caused by using
average of the entire source rock section.
Figure 16 compares total organic carbon, carbonate content, hydrocarbon
generative potential, and production indices in the Triassic Shublik Formation to two
world-class “hybrid” shale-oil systems – the Cretaceous Niobrara Formation
(Colorado) and the Cretaceous Eagle Ford Formation (West Texas). All three
formations show strikingly similar TOC versus carbonate content distribution patterns.
Despite the variable organic richness and lithology, S2 versus TOC cross-plots for all
formations show clearly defined regression lines. These samples also show reduced S2
pyrolysis yields due to kerogen dilution by the mineral matrix (as discussed earlier).
This results in lower calculated hydrogen indices and possibly misleading organic
matter type interpretations from standard OI vs. HI plots. Thus, HI derived from the
regression line of S2 vs. TOC should be used for correct organic matter type
evaluation. In addition, PI - TOC plots for all three formations show a wide range of
values from immature to peak oil window. This indicates the presence of migrated oil
that complicates thermal maturity evaluation of in situ organic matter.
CONCLUSIONS
The Triassic Shublik Formation in the Phoenix-1 core was subdivided into four
source-rock and two non-source intervals. The presence of mature migrated
30
hydrocarbons from a deeper Shublik source is confirmed by Rock-Eval pyrolysis, as
well as analyses of biomarkers and diamondoids. This documents the excellent
potential of the Shublik Formation as an unconventional resource system and provides
the first look at expulsion and retention of source units and storage capacity of non-
source/reservoir units in this context. Our results show that the presence of previously
unrecognized migrated fluids may have resulted in misleading interpretations of
organic matter type and maturity in the past.
Despite the geochemical overprint of non-indigenous hydrocarbons, detailed
geochemical characterization of immature Shublik core samples from the Phoenix-1
well reveals similar organic matter input and a clear difference in depositional
environments between the analyzed samples. The organic matter of the Shublik
Formation is dominated by Type I kerogen based on Rock-Eval pyrolysis. The algal
contribution of organic matter is supported by biomarker analysis, particularly high
tricyclic terpanes concentrations linked to reported widespread occurrence of
unicellular algae Tasmanites in northern Alaska. Within this Shublik succession, the
depositional environment changes from anoxic clay-poor to suboxic clay-rich
conditions. This apparently leads to the generation of genetically distinct oils. Kinetic
analyses of organofacies end-members suggest different timing of onset and peak of
hydrocarbon generation that may have significantly affected generation and expulsion
history of mature Shublik source kitchens, and resultant petroleum migration and
filling history of the North Slope oil fields.
31
ACKNOWLEDGMENTS
Support for this study was provided by the Stanford Basin and Petroleum
System Modeling (BPSM) Industrial Affiliates Program and Great Bear Petroleum.
Special thanks are due to USGS Core Research Center in Denver, Colorado for
granting access to the Phoenix-1 Shublik core and allowing core sampling. We thank
Bruce Kaiser, Harry Rowe, and Bruker Corporation for their discussions and
assistance with XRF instrumentation access; Agilent Technologies for providing
MassHunter workstation software; Erik Sperling for sponsoring ICP-MS analysis.
This work benefitted from discussions with Ken Bird and Allegra Hosford Scheirer.
We also thank the staff of the Biomarker Technologies, Inc. for their lab assistance
and Will Thompson-Butler for XRF measurements assistance.
32
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Trendel, J.M., Restle, A., Connan, J., and Albrecht, P., 1982, Identification of a novel
series of tetracyclic terpene hydrocarbons (C24-C27) in sediments and
petroleums: Journal of the Chemical Society, Chemical Communications, v. 5,
p. 304–306, doi: 10.1039/c39820000304.
Tribovillard, N., Algeo, T.J., Lyons, T., and Riboulleau, A., 2006, Trace metals as
paleoredox and paleoproductivity proxies: An update: Chemical Geology, v.
232, p. 12–32, doi: 10.1016/j.chemgeo.2006.02.012.
Vigran, J.O., Mørk, A., Forsberg, A.W., Weiss, H.M., and Weitschat, W., 2008,
Tasmanites algae - Contributors to the Middle Triassic hydrocarbon source
rocks of Svalbard and the Barents Shelf: Polar Research, v. 27, p. 360–371,
doi: 10.1111/j.1751-8369.2008.00084.x.
Wang, Y., Peters, K.E., Moldowan, J.M., Bird, K.J., and Magoon, L.B., 2014,
Cracking, mixing, and geochemical correlation of crude oils, North Slope,
Alaska: AAPG Bulletin, v. 98, p. 1235–1267, doi: 10.1306/01081412197.
Wicks, J. L., Buckingham, M. L., and Dupree, J. H., 1991, Endicott field– U.S.A.,
North Slope basin, Alaska, in N. H. Foster and E. A. Beaumont, eds.,
38
Structural traps V: AAPG Treatise of Petroleum Geology, Atlas of Oil and Gas
Fields, p. 1–25.
Yurchenko, I., Graham, S.A., Scheirer, A.H., and Al Ibrahim, M., 2016,
Understanding Depositional Environments of the Shublik Formation of Arctic
Alaska Using XRF Chemostratigraphy, in Proceedings of the 4th
Unconventional Resources Technology Conference, doi: 10.15530/urtec-2016-
2448374.
39
Table 1. Total organic carbon and Rock-Eval pyrolysis bulk geochemical data.
Sample
ID
Depth
(m)
TOC
(wt%)
S1
(mg HC/g
rock)
S2
(mg HC/g
rock)
S3
(mg CO2/g
rock)
Tmax
(°C)
HI
(mg HC/
g TOC)
OI
(mg CO2/g
TOC)
S2/S3
(mg HC/mg
CO2)
S1/TOC
(mg HC/
g TOC)
PI
(S1/(S1+S2))
PH01 2459.7 4.3 2.2 27 0.5 432 634 12 54 51 0.07
PH02 2445.4 1.1 0.6 5 0.3 434 432 31 14 57 0.12
PH03 2431.9 0.6 0.4 2 0.3 434 384 58 7 68 0.15
PH05 2456.3 1.8 1.2 9 0.5 431 479 28 17 66 0.12
PH06 2452.2 1.8 0.8 8 0.4 431 430 25 17 44 0.09
PH07 2442.5 4.8 1.5 29 0.5 431 613 11 55 32 0.05
PH08 2413.9 3.1 1.0 17 0.4 431 564 14 40 32 0.05
PH09 2428.2 5.4 1.8 41 0.5 436 759 8 91 33 0.04
PH11 2383.2 1.3 1.2 5 0.4 433 404 32 13 94 0.19
PH12 2410.8 1.1 0.4 3 0.4 431 296 34 9 37 0.11
PH13 2396.1 1.3 2.3 6 0.4 432 419 31 13 177 0.30
40
Table 2. Interpretation of Rock-Eval pyrolysis results for eleven key core samples.
Petroleum
potential* Sample ID Lithofacies TOC (wt%) OM Type* Maturity* Oil saturation Carbonate (wt%) Depth (m)
good PH09 PC 5.4 Type I Immature low OSI 38 2428.2
good PH01 PC 4.3 Type I Immature low OSI 24 2459.7
good PH07 WC 4.8 Type I Immature low OSI 25 2442.5
good PH08 WC 3.1 Type II Immature low OSI 30 2413.9
fair to good PH06 BW 1.8 Type II Immature low OSI 60 2452.2
fair to good PH05 GG 1.8 Type II Early low OSI 48 2456.3
fair PH12 GG 1.1 Type II Early low OSI 50 2410.8
fair PH02 BP 1.1 Type II Early low OSI 62 2445.4
fair PH11 BP 1.3 Type II Early high OSI 37 2383.2
poor PH03 BP 0.6 Type II Early visible oil stain (Fig.4) 93 2431.9
fair PH13 CS 1.3 Type II Peak high OSI 22 2396.1
* Petroleum potential interpretation is based on TOC and S2 values, OM Type is based on HI values, whereas maturity is
interpreted from PI alone. Lithofacies key is on Fig. 4.
41
Table 3. Measured geochemical parameters include extract yield and key biomarker ratios.
Parameter PH01 PH02 PH03 PH05 PH06 PH07 PH08 PH09 PH11 PH12 PH13
Extract yield (mg HC/g rock) 3.0 1.2 1.4 2.4 1.2 2.6 1.5 2.0 2.4 0.6 5.0
C29 ααα 20S/(20S+20R) 0.52 0.60 0.59 0.48 0.56 0.59 0.55 0.59 0.54 0.48 0.51
C29 αββ/(αββ+ααα) 0.34 0.59 0.60 0.32 0.38 0.60 0.34 0.59 0.53 0.23 0.52
Ts/(Ts+Tm) 0.44 0.36 0.37 0.37 0.38 0.36 0.41 0.38 0.34 0.41 0.34
C29 Ts / (C29 Ts + C29 Hopane) 0.25 0.28 0.21 0.19 0.22 0.34 0.24 0.24 0.14 0.23 0.14
H32 S/(R+S) Homohopanes 0.60 0.61 0.61 0.60 0.61 0.61 0.60 0.61 0.60 0.59 0.60
MA(I)/MA(I+II) 0.06 0.09 0.13 0.18 0.14 0.07 0.09 0.21 0.25 0.16 0.22
C22/C21 tricyclic terpane 0.31 0.46 0.61 0.56 0.46 0.39 0.31 0.51 0.86 0.37 0.95
C24/C23 tricyclic terpane 0.36 1.00 0.84 0.43 0.45 1.24 0.61 0.68 0.50 0.40 0.54
C29 / (C29 + C30 Hopanes) 0.28 0.26 0.34 0.37 0.33 0.22 0.30 0.36 0.43 0.39 0.42
Diahopane Index 0.03 0.05 0.04 0.05 0.03 0.05 0.03 0.03 0.05 0.05 0.04
C27 diasteranes/(regular+diasteranes) 0.44 0.56 0.42 0.43 0.49 0.59 0.39 0.33 0.42 0.35 0.41
42
Table 4. Extent of cracking, key diamondoids concentration and observations resulted
from quantitative diamondoid analysis (QDA) of Phoenix-1 core extracts.
Sample
ID
3- + 4-methyl
diamantanes
Cc (ppm)
C29 ααα 20R
Stigmastane
(ppm)
1- + 2-methyl
adamantanes
(ppm)
Baseline
Co
(ppm)
Extent of cracking
(%)
(1 – (Co/Cc)) x 100
PH08 7.4 301.3 100.0 7.4 0.0
PH01 27.1 359.1 126.6 7.4 72.9
PH07 21.8 62.7 117.2 7.4 66.3
PH09 36.7 17.4 196.3 7.4 80.0
PH02 13.5 63.1 10.3 7.4 45.4
PH03 10.7 43.2 14.9 7.4 31.3
PH05 11.0 84.3 14.8 7.4 33.4
PH06 23.8 96.6 68.7 7.4 69.2
PH11 21.3 30.8 12.5 7.4 65.5
PH12 16.3 145.6 15.6 7.4 54.9
PH13 3.7 43.0 0.0 7.4 N/A
43
Table 5. Petroleum generation kinetic parameters for samples from the Shublik
Formation in the Phoenix-1 well.
Sample Depth
(m)
Data source Frequency
factor (sec-1)
Activation
Energy
(kcal/mole)
% of
Reaction
PH07 2442.5 This work 1.56 x 1013 51 77.64
52 2.61
53 17.99
55 1.76
PH09 2428.2 This work 3.08 x 1013 52 84.26
54 15.21
55 0.53
97R00331 2421.9 Masterson
(2001)
1.34 x 1013 51 85.59
52 0.13
53 12.55
55 1.13
63 0.6
44
Table 6. ICP-MS elemental analysis results.
Sample
ID
Ca
(%)
P
(%)
Al
(%)
Fe
(%)
S
(%)
Mo
(ppm)
V
(ppm)
Ni
(ppm)
V/(V+Ni)
PH01 8.3 0.3 4.6 1.8 0.6 26 289 97 0.75
PH02 20.4 0.2 2.2 0.8 0.3 4 35 21 0.63
PH03 34.3 0.4 0.3 0.1 0.1 1 15 8 0.66
PH05 18.9 3.7 1.8 0.7 0.3 11 102 41 0.72
PH06 22.9 0.1 1.6 0.7 0.4 28 151 48 0.76
PH07 7.8 0.1 6.5 3.3 1.3 30 197 114 0.63
PH08 9.5 0.7 5.3 2.4 1.1 5 113 71 0.61
PH09 13.4 0.5 3.8 1.1 0.6 8 164 80 0.67
PH11 10.6 0.0 3.8 1.5 0.5 1 173 33 0.84
PH12 17.5 0.9 2.0 3.0 1.0 28 52 27 0.66
PH13 8.3 0.1 1.3 0.6 0.3 3 54 22 0.71
45
Table 7. Key source rock properties of defined Shublik source rock intervals.
Interval
Name
TOC ave
(wt%)
HI ave
(mg HC/ g TOC)
OM Type
Biomarker
organofacies
Kinetics
SR -1 6.5 763 Type I C S*
SR-2 5.7 672 Type I C C
SR-3 4.7 596 Type I S S
SR-4 6.2 599 Type I C N/A
* Petroleum generation kinetic measurements by Masterson (2001).
46
Figure 1. Map of part of Arctic Alaska showing the study area, location of the
sampled data (Phoenix-1 well) and cross section (Fig. 13). Main producing oil field
units (light grey) are located in the northern part of the central North Slope (area
between NPRA and ANWR) along the structural axis of the Barrow Arch (grey
dashed line).
47
Figure 2. Generalized chronostratigraphic column of Arctic Alaska after Houseknecht
et al. (2012). Key petroleum source rocks are Shublik Formation (grey), Kingak Shale,
pebble shale unit, and Hue Shale, including the GRZ (gamma ray zone).
48
Figure 3. Stratigraphic column of Phoenix-1 Shublik core based on conventional core
description by Hulm (1999), lithology and location of collected samples in depth, and
analytical methodology. Representative core photos and lithofacies key are displayed
in Fig. 4. Schematic composition of disseminated organic matter is based on Tissot
and Welte (1984). GR – gamma ray, QDA – quantitative diamondoid analysis.
49
Figure 4. Lithostratigraphy (adopted from Hulm, 1999) and representative core photos
of collected core samples. White four-digit labels on core photos indicate core depths
in feet, while depths labels on stratigraphic column are in meters.
50
Figure 5. Total organic carbon and Rock-Eval pyrolysis results. A – Bulk analysis of
organic matter quantity (S2 vs. TOC plot), quality (HI vs. OI plot) and thermal
maturity (PI vs.TOC plot). B – Variability of source rock properties by lithology.
Lithofacies key is on Fig. 4. C - Geochemical logs in depth. The selected sample set
includes 11 samples collected for this study, as well as 61 core samples previously
published by Masterson (2001) and Robison et al. (1996).
51
Figure 6. Gas chromatography - flame ionization detection (GC-FID) results. Note the
difference in distributions of n-alkanes for all the samples, and evaporative loss of
some compounds during storage (see text). In addition, three persistent peaks around
n-C13 are interpreted as the signature of synthetic, drilling mud of unknown origin,
which should not contribute diamondoids or biomarkers.
52
Figure 7. Correlation between extract yields and Rock-Eval peak S1 (free
hydrocarbons) in the sampled rocks (A). Terpane thermal maturity parameters
correspond to the immature to early oil window maturity range (B). The two outliers
PH02 and PH07 may represent different organic facies.
53
Figure 8. Biomarker analysis results. A - Comparison of terpane and diasterane mass
chromatograms (m/z 191 and m/z 372 → 217) for organofacies C and S rock extract
end-members. B - Representative lithology-related biomarker parameters. The
majority of the samples plot in the same group, showing low C27 diasteranes/(regular +
diasteranes), C24/C23 tricyclic terpanes, diahopane index, and high C29/C30 hopane
values indicative of a carbonate source. Conversely, samples PH07 and PH02 are
interpreted as a shaly source.
54
Figure 9. Ternary diagrams of steranes and diasteranes support subdivision of the
Shublik core samples into two genetically distinct organofacies C and S (grey shaded
areas).
55
Figure 10. Comparison of temperature of transformation (kerogen to petroleum) based
on 3°C/my heating rate and measured kinetics for two proposed Shublik organofacies
end-members. The Shublik petroleum generation kinetics curve from Masterson
(2001) (sample 97R00331; 2421.941 m depth) shows a close match to organofacies S
curve.
56
Figure 11. A - Ratio of adamantanes and diamantanes shows little effect of oil
cracking and is relatively constant for samples with TOC > 2wt%. B - Adamantanes
and diamantanes are volatile hydrocarbons. Their ratios show a linear correlation
between n-C11/n-C15 ratios of n-alkanes, confirming evaporative loss during storage by
preferential evaporation of the more volatile compounds from the rock. C - The
correlation between diamondoid and biomarker concentrations in source rock extracts
was used to estimate the level of thermal maturity and the extent of secondary
cracking.
57
Figure 12. Total organic carbon (TOC) versus measured values for elements analyzed
by ICP-MS (A) and HH-XRF (B). Intervals with elevated TOC, Ni, Mo, S, and Al
contents are highlighted in grey.
58
Figure 13. A - Schematic cross section from Brooks Range to the Beaufort Sea
through several oil and gas fields. Modified from Houseknecht et al. (2012), Bird and
Bader (1987). Location of cross section is shown in Figure 1. B - Schematic
presentation of primary and secondary migration within and from the Shublik
Formation. Present-day location of the Phoenix-1 well on the Barrow Arch allows
migration from both north and south. Note horizontal exaggeration along the flanks of
the Barrow Arch (actual dip 1-2 degrees) for illustration purposes.
59
Figure 14. Subdivision of the Shublik Formation into two non-source and four source
intervals based on distinctive geochemical and lithologic features and their well-log
signatures. For key source rock properties of defined Shublik source intervals refer to
Table 7.
60
Figure 15. Ternary diagram showing variations in mineralogical composition of the
Shublik Formation in the Phoenix-1 core. Original data were adapted from USGS
Core Research Center well catalog (library number E921) and normalized to one.
Average compositions for major unconventional hydrocarbon plays in North America
are from Allix et al. (2011). Note that most of the samples contain more than clays,
carbonate, and quartz/feldspar components.
61
Figure 16. Total organic carbon, carbonate content, hydrocarbon generative potential
(Rock-Eval S2 peak), and production index (PI) comparison in the Shublik, Niobrara,
and Eagle Ford Formations. Carbonate content of the Shublik Formation was
measured in Merak-1 core (Yurchenko et al., 2016). Geochemical data for Niobrara
Formation are from USGS Core Research Center well catalog (library number B129).
Carbonate versus total organic content data for the Eagle Ford Formation are from
Jarvie (2012). TOC and Rock-Eval pyrolysis results for the Eagle Ford Formation are
from Fairbanks (2012).
62
CHAPTER 2
THE ROLE OF CALCAREOUS AND SHALY SOURCE ROCKS IN THE
COMPOSITION OF PETROLEUM EXPELLED FROM THE TRIASSIC SHUBLIK
FORMATION, ALASKA NORTH SLOPE
63
THE ROLE OF CALCAREOUS AND SHALY SOURCE ROCKS IN THE
COMPOSITION OF PETROLEUM EXPELLED FROM THE TRIASSIC SHUBLIK
FORMATION, ALASKA NORTH SLOPE
Inessa A. Yurchenko1, J. Michael Moldowan2, Kenneth E. Peters1, 3, Leslie B.
Magoon1, and Stephan A. Graham1
1Department of Geological Sciences, Stanford University, Stanford CA 94305, USA
2Biomarker Technologies, Inc., Rohnert Park CA 94928, USA
3Schlumberger Information Solutions, Mill Valley CA 94941, USA
ABSTRACT
For nearly thirty years, the Triassic marine carbonate Shublik Formation has
been suggested and confirmed as a key source rock for hydrocarbons in the North
Slope of Alaska. The formation accounts for roughly one third of the oil in the
supergiant Prudhoe Bay Field, and for nearly all of the oil in the second largest
Kuparuk River Field. Recent studies of oil types in the vicinity of the Northstar Field
suggested presence of “shaly” organofacies of the Shublik Formation based on the
likely Triassic age and marine shale biomarker signatures of some analyzed oil
samples. Current work fills the gap between biomarker analysis of predicted
“calcareous” and “shaly” oil types and source rock geochemistry. Biomarker-based
oil-source rock correlation confirms the presence of two genetically-distinct
organofacies and related oil families. Both groups were deposited under a similar
redox condition (anoxic to suboxic) with dominantly marine algal input but in either 1)
a clay-rich or 2) a clay-poor depositional setting. Chemometric evaluation of
64
multivariate biomarker data reveals mixtures with variable degrees of mixing between
end members. Analysis of diamondoids confirms mixed oil types and establishes
diamondoid signatures of source rock end-members. This allows for correlation of
biomarker-poor, overmature Shublik source rock samples to oils, and extends these
interpretations over large areas of the North Slope.
INTRODUCTION
It is widely recognized that petroleum is a complex mixture of hydrocarbons
and non-hydrocarbons generated and expelled from fine-grained-organic-rich source
rock. Many petroleum accumulations in the North Slope of Alaska consist of
contributions from more than one source rock, or different organic facies of the same
source rock (Seifert et al., 1980; Wicks et al., 1991; Masterson, 2001; Peters et al.,
2008; Wang et al., 2014). Four main petroleum source rocks in the North Slope
include (1) the Triassic Shublik Formation; (2) Jurassic Lower Kingak Shale; (3)
Cretaceous pebble shale unit; and, (4) the Cretaceous Hue Shale (Magoon and Bird,
1985; Bird, 1994; Houseknecht and Bird, 2004; Peters et al., 2006) (Fig. 1). It is
widely accepted that the Middle to Upper Triassic Shublik Formation is one of the
major origins of source rocks for oil, accounting for nearly all of the oil in the
Kuparuk River unit along with a large volume of petroleum in the Prudhoe Bay unit
(Fig. 2), (Seifert et al., 1980; Magoon and Bird, 1985; Bird, 1994; Masterson, 2001;
Peters et al., 2008). In addition, crude oil composition is influenced by secondary
effects, such as thermal maturity of the source rock at the time of oil generation, and
biodegradation and cracking of the oil during migration and accumulation. Thus, de-
65
convolution of oil mixtures and oil-source rock correlation on the North Slope has
been a challenge for many years.
Recent studies of Alaska North Slope oil types by Peters et al. (2007) and
Wang et al. (2014) used decision-tree chemometrics of selected source- and age-
related biomarker ratios to classify over forty Shublik crude oil samples into two
genetically-distinct families, which were linked to calcareous and shaly organofacies
of the Shublik source rock (Figs. 2 and 4). Peters et al. (2007) proposed a “shaly”
organofacies based on likely Triassic age and distal-marine shale biomarker signatures
of some analyzed oil samples. Wang et al. (2014) extended this interpretation by
emphasizing the difference between samples collected from wells located north and
south of the Barrow Arch, a regional structural high that first formed during rift-
related uplift in the Jurassic and Early Cretaceous. Later it served as a focal point for
petroleum migration and accumulation of the largest north Alaskan oil fields (Bird and
Houseknecht, 2011). Wang et al. (2014) suggested the source for the “shaly” oil
family to be a clay-rich equivalent of the calcareous Shublik Formation that occurs to
the north of the Barrow Arch (Fig. 2).
In addition, Peters et al. (2008) classified oil samples from the Prudhoe Bay
field area into a separate family, indicating approximately equal contributions from
Shublik Formation and Hue-GRZ source rocks (37% each), and less from the Kingak
Shale (26%). That oil family was not addressed in this study. Masterson (2001)
compared some biomarker characteristics of five Shublik source rock extracts from the
Phoenix-1 well to nine extracts from cores in two Prudhoe Bay wells. He used the
term “calcareous facies” for the distal, organic-rich facies of the Shublik Formation in
66
the Phoenix-1 well, whereas the more shoreward, proximal facies at Prudhoe Bay
Field was described as the “shaly facies.”
Despite much work, most published research was conducted on Shublik oils
rather than source rock, and there remains a gap between biomarker analysis of
various North Slope oil families and geochemical and geological assessment of the
Shublik organofacies. Moreover, Peters et al. (2006) noted that much of the present-
day Shublik Formation is mature to postmature, complicating the analysis of
biomarkers and oil-source rock correlation. In this study, the terms ‘calcareous’ and
‘shaly’ are used inherently to describe two genetically-distinct oil families. This initial
distinction was based on the biomarker analysis of over forty (40) oil samples from all
over the North Slope and source rock character was inferred from oil composition
(Peters et al., 2007; Wang et al., 2014).
This current work builds upon previous geochemical interpretations of the two
Shublik oil families, but adds additional insight from source rock analysis of
biomarkers and oil-source rock correlation, and recently-acquired diamondoid data to
better distinguish end-member and mixed-oil types. Utilization of biomarker and
diamondoid analyses provided the ability to overcome problems in correlating
biomarker-poor overmature source rocks and oils, which helped to extend
interpretations over large areas of the North Slope.
MATERIALS AND METHODS
Samples
Twenty oil samples and rock extracts were selected for this study. Samples,
well names, and performed analyses are listed in Table 1. Sample locations are
67
displayed in Fig. 2. Rock extracts 207 and 208, and oil samples NS13, SP1a, SP1b,
N1, KC-4, F5a, M1, MB13b, D1 re-analyzed in this study, were previously
investigated by Seifert et al. (1980) and Wang et al. (2014), respectively. Previously-
published sample names were utilized for consistency. Sample CO1 is oil tested from
the Shublik interval in the Colville St-1 well of the Kuparuk River unit. Rock samples
PH01, PH07, PH08, and PH09 collected from the most-studied Shublik core in the
Phoenix-1 well were discussed in Chapter 1. Sample PH04 is oil extracted from the
Ivishak rock samples in the Phoenix-1 well. Rock samples AL02, AL03, and 13AL31
were collected from the Shublik core in the Alcor-1 well and drilled about 20 km
south of the Prudhoe Bay Unit by Great Bear Petroleum in 2012. These data present
first insight into geochemical characteristics of the Shublik source rock in a frontier
area south of the producing fields. Thedataset targets a large area of the North Slope
(about 140 km east to west and 80 km north to south). It includes previous and newly-
acquired geochemical data, provides improved understanding of distinguished Shublik
end-member and mixed-oil types, and allows their correlation to Shublik organofacies.
Methods
Source rock screening
All collected rock samples were analyzed for carbonate and total organic
carbon content (TOC), and Rock-Eval pyrolysis to assess organic matter quantity,
quality, and thermal maturity (Peters and Cassa, 1994). Analyses (GeoMark Research,
Ltd.) employed Rock-Eval II and LECO C230 instruments. In addition, two samples
(AL02 and AL03) were subjected to whole rock and clay x-ray diffraction (XRD)
analysis (K-T GeoServices, Inc.) in order to provide mineralogy of the samples.
68
Analysis of Biomarkers
Analysis was performed at Biomarker Technologies, Inc., and included organic
matter extraction, gas chromatography (GC), gas chromatography – mass
spectrometry (GCMS), and gas chromatography – mass spectrometry – mass
spectrometry (GCMS/MS) using laboratory procedures described in Peters et al.
(2005) and Wang et al. (2014). Measured biomarker concentrations and calculated
ratios were used to assess thermal maturity, organic matter input, and environment of
deposition, as well as for oil-source rock correlation. In addition, statistical analysis of
multivariate biomarker ratios was completed using a commercial chemometrics
program (Pirouette Version 4.5, Infometrix) for genetic classification and oil-source
rock correlation. Exploratory data analysis included hierarchical cluster analysis
(HCA) and principal component analysis (PCA). A detailed description of applied
HCA and PCA methods is described in Peters et al. (2007).
Analysis of Diamondoids
Analyses (Biomarker Technologies, Inc.) included quantitative diamondoid
analysis (QDA) and quantitative extended diamondoid analysis (QEDA), as described
in Moldowan et al. (2015). Diamondoids are highly stable cage-like compounds that
are more thermally resistant than biomarkers and most other hydrocarbons in oil
(McKervey, 1980). The correlation between diamondoid (3- + 4- methyldiamantanes)
and biomarker (stigmastane) concentrations in analyzed samples was used to estimate
the level of thermal maturity and the extent of secondary cracking (Dahl et al., 1999).
The distribution of extended diamondoids (larger than three-caged triamantane) is
related to the source and was used to distinguish Shublik end-member and mixed-oil
69
types, and for oil-source rock correlation (Moldowan et al., 2015). In addition,
compound-specific isotope analysis of diamondoids (CSIA-D), an independent
correlation tool, complimentary QEDA, was applied for oil-source rock correlation
(Moldowan et al., 2015).
RESULTS
Source rock screening
Carbonate content, TOC, Rock-Eval data and calculated parameters such as
hydrogen index (HI), oxygen index (OI), and production index (PI = S1/(S1+S2)) are
listed in Table 2. The TOC content of the samples ranges from 0.2 to 5.4 wt%. The HI
values range from 47 to 759 mg HC/ g TOC. The drastic differences in TOC and HI
values are mainly due to a thermal maturity, which range from immature (Tmax < 435
°C) in the Phoenix-1 core to postmature (Tmax > 470 °C) in the Alcor-1 core.,
However, carbonate content variation from 24 to 89 wt% signifies presence of
different lithofacies. Thus, four immature samples from the Phoenix-1well (PH01,
PH07, PH08, and PH09), two mature samples from the western part of the Prudhoe
Bay Field (207 and 208), and three postmature samples from the Alcor-1 well (AL02,
AL03, 13AL31) compose a more than 100 km-long maturity profile from north to
south across the Barrow Arch.
In addition, two postmature samples from the Alcor-1 well were analyzed
using bulk rock and clay XRD. The resultant mineralogy is summarized in Table 3,
and discussed in the QEDA results section.
70
Analysis of biomarkers
The initial distinction of Shublik oil families was based on biomarker analysis
of oil samples throughout the North Slope and source rock character was inferred from
oil composition (Fig. 2; Peters et al., 2007; Wang et al., 2014). Six previously studied
oil samples (NS13, SP1a, N1, KC4, F5a, and M1) were included in order to establish
‘calcareous’ and ‘shaly’ end-member characteristics to be compared with source rock
extracts. Samples compared with these end-members include CO1 oil sample, PH04
oil extract from Ivishak Sandstone, and five Shublik rock extracts (13AL31, PH01,
PH07, PH08 and PH09). In addition, saturate and aromatic fractions of Samples 207
and 208, rock extracts from Seifert et al. (1980), were re-analyzed and included in the
oil-source rock correlation. Source-specific differences between samples were based
on quantification of biomarker concentrations using GCMS and GCMS/MS profiles.
The resultant key biomarker ratios are listed in Table 4. For a full list of measured
parameters, refer to Appendix B-1.
All samples, except CO1 and 13AL31, contain tricyclic terpanes ranging from
C19 to C30 with a high relative abundance of extended side-chain tricyclic terpanes
(cheilanthanes) to pentacyclic triterpanes (hopanes) (Fig. 3). Oil sample CO1 has
relatively abundant cheilanthanes but low hopane concentrations, indicating higher
thermal maturity than the other samples. Rock extract 13AL31 lacks biomarkers (Fig.
3), confirming a postmature thermal maturity as suggested by Rock-Eval pyrolysis
(Tmax > 470 °C) and diamondoid concentrations (cracking estimate by QDA = 98%,
Table 5,). Thus, all oils and rock extracts, except CO1 and 13AL31, were subjected to
71
chemometric analysis following guidelines described in Peters et al. (2007) and Wang
et al. (2014) for consistency of results.
Fig. 4 shows two chemometric runs using identical HCA and PCA methods
and sets of biomarker ratios, applied to different sample sets. The first sample set (Fig.
4A, B) includes biomarker results for 40 North Slope oils published by Wang et al.
(2014) combined with current results for comparison of chemometric classifications of
genetically-distinct groups. The results display similar HCA (Fig. 4A) and PCA (Fig.
4B) grouping of the six previously-studied oil samples (NS13, SP1a, N1, KC4, F5a,
and M1) into calcareous and shaly Shublik families, and classify newly-acquired
samples within those groups. The second sample set (Fig. 4C, D) includes only results
from our current work. Most of the samples show similar genetic relationships to those
evident from two chemometric runs; however in the second scenario, oil sample F5
and rock extract PH08 cluster with the shaly Shublik group on HCA dendrogram (Fig.
4C). On the PCA scores plot (Fig. 4D), sample PH08 is an outlier, whereas sample
F5a indicates a mixed-oil type by plotting between the two groups. In the larger
sample set, the two Shublik families (Triassic) are distinct from other oil families
(Jurassic Kingak Shale, Cretaceous pebble shale unit, Cretaceous Hue-HRZ, and
Tertiary Canning Formation). In the smaller sample set composed of the two Shublik
families alone, the groups are less distinct, resulting in slightly-different hierarchical
clustering and principal component groupings.
Quantitative diamondoid analysis (QDA)
QDA was performed on all of the samples analyzed for biomarkers and results
are listed in Table 5. Fig. 5A shows no greater loss of 1- + 2-methyladamantanes
72
relative to 3- + 4-methyldiamantanes for most of the samples, which generally follow
the established trend line. This trend is unique and relatively constant for each source,
and is independent of oil cracking (Moldowan et al., 2015). Thus, both the shaly and
calcareous Shublik samples plot within the same source trend. Samples 207, 208, and
PH04 yield near zero concentrations and plot away from the trend line, suggesting
preferential evaporation of the more volatile compounds during storage. This is not
surprising since the saturate and aromatic fractions of previously analyzed extracts 207
and 208 were stored since 1980, and the core (sample PH04) was drilled and stored in
1987.
The plots of diamondoid (3- + 4- methyldiamantanes) vs. biomarker
(stigmastane) concentrations allows estimates the extent of oil cracking for the
samples without significant evaporative losses (Fig. 5B). The extract from sample
PH08 yields a high C29 ααα 20R stigmastane concentration (301.3 ppm) and the
smallest 3- + 4-methyldiamantanes concentration (7.4 ppm) among the calcareous
Shublik samples, suggesting absence of secondary thermal cracking. Thus, the 7.4
ppm value of PH08 is used as the “diamondoid baseline” in the formula of Dahl et al.
(1999) to estimate the extent of cracking for calcareous Shublik samples (Table 5).
The resulting cracking percentages for F5a, M1, KC4, and CO1 oils are 22, 47, 50,
and 75%, respectively. The highest maturity of CO1 oil (75% of cracking) among the
calcareous Shublik oils agrees with its high-maturity hopane signature detected from
the m/z 191 chromatogram of its saturate fraction (Fig. 3). Extract 13AL31 yielded
very high 3- + 4-methyldiamantane concentration (400 ppm) and the resulting
estimation of the extent of cracking at 98% (Table 5), confirms a postmature level of
73
thermal maturity predicted also by the absence of biomarkers and a high Tmax value
(475 °C).
QDA results for calcareous Shublik extracts (PH01 and PH09), and the shaly
Shublik extract (PH07) suggest that a high maturity charge infiltrated much of the
immature Phoenix-1 well core. Shaly Shublik oils N1 and NS13 yield very low 3- + 4-
methyldiamantane concentrations (4.5 and 4.6 ppm), which were used as a
“diamondoid baseline” for the extent of cracking estimation in the shaly Shublik
samples (Table 5). The calculated extent of cracking for sample SP1a is 33 %.
Measured 3- + 4-methyldiamantanes concentrations from Wang et al. (2014) are 3.18
and 3.37 ppm, and similar to the 4.5 and 4.6 ppm numbers measured here. However,
Wang et al. (2014) used the value of 10.6 ppm as the diamondoid baseline for the
whole suite of Shublik oil samples. Current work proposes separate baselines for
calcareous (7.4 ppm) and shaly (4.5 ppm) Shublik samples that affects estimates of the
secondary cracking. In addition, Chapter 1 shows the differences in timing of
hydrocarbon generation between samples PH07 and PH09 measured by from
petroleum generation kinetics. Based on measured kinetic parameters, shaly Shublik
sample (PH07) is predicted to generate hydrocarbons earlier than calcareous Shublik
samples (PH09), reaching 10%, 50% and 90% transformation at temperatures of
approximately 90 and 97 °C, respectively.
Quantitative extended diamondoid analysis (QEDA)
All oil samples (NS13, SP1a, N1, KC4, F5a, M1 and CO1) were subjected to
QEDA. Due to small sample sizes, the five Phoenix-1 extracts and the one Alcor-1
extract (13AL31) did not yield diamondoid concentrations sufficient for QEDA.
74
However, two additional samples (AL02 and AL03) were taken from the Alcor-1 core.
These biomarker-poor overmature Shublik samples correlate to end-member oil types
using QEDA. In addition, shaly Shublik oil samples SP1b, and two calcareous Shublik
oils MB13b and D1 from Wang et al. (2014) were subjected to QEDA to better
distinguish the end-member (Fig. 4A, B) and mixed-oil types suggested by
chemometrix (Fig. 4C, D).
Fig. 6 and Table 6 show QEDA results for the analyzed samples. In this study,
the two rock samples (AL02 and AL03) from the overmature Alcor-1 core were found
to be calcareous and shaly Shublik organofacies “end-members.” All of the shaly
Shublik oils (NS13, SP1a, SP1b, and N1) suggested by Wang et al. (2014) appear to
be mixtures with variable degree of mixing between end members. Sample NS13 is
the nearest to being an end-member among the analyzed shaly Shublik oils, whereas
sample N1 is the calcareous Shublik end-member oil sample. All of the proposed
calcareous Shublik oils plot very near (greyed out area on Fig. 6) the rock extract end-
member (AL02), displaying a much clearer QEDA signature and oil type than does
shaly Shublik oils. However, Sample AL03C most likely is not a “typical” Shublik
source rock, having a 97.8% carbonate content, which probably surpasses that for the
source rocks of any of the Shublik oils. We suppose the extreme carbonate content
results in a more extreme peak at Pentamantanes 1 and 3 (P1 and P3) compared to less
pronounced P1 and P3 peaks in the QEDA signatures of any of the oils.
Compound-specific isotope analysis of diamondoids (CSIA-D)
Moldowan et al. (2015) advised using CSIA-D in conjunction with QEDA for
the most reliable interpretations. Contrary to QEDA, CSIA-D of the analyzed oils and
75
rock extracts does not support calcareous versus shaly Shublik differentiation. The
similar CSIA-D signatures for all of the Shublik samples may suggest they all
originate from a similar organic matter (OM) source input (Fig. 7).
DISCUSSION
Organic matter input
A monoaromatic steroid biomarker ternary distribution plot was used to
determine OM source input (Fig. 8). The relative abundance of C27, C28, and C29
monoaromatic steroids in aromatic fraction were measured by GCMS since they
display no significant molecular ion, and therefore, cannot be analyzed by GCMS/MS.
Most of the samples plot in the overlap between the marine carbonate and non-marine
shale groups (Moldowan et al., 1985). The increasing proportion of C29 monoaromatic
steroids be an indication of an elevated supply of algal OM (Volkman, 1986, 2003).
This is also supported by the presence of C30 n-propylcholestanes (Fig. TBD) and C30
diasteranes. Both groups of compounds are diagnostic of marine Chrysophyte algae.
In addition, the abundant tricyclic terpanes in all of the analyzed samples (Fig.
3) suggest that unicellular green algae Tasmanites was a significant source constituent
during the deposition of the Shublik Formation (Aquino Neto et al., 1992). This is
supported by the widespread occurrence of Tasmanites reported in outcrops of the
Brooks Range believed to be Jurassic and possibly Triassic (Tourtelot and Tailleur,
1965; Burruss et al., 2008). The Tasmanites cysts are also dominant fossils in the
Botneheia Formation of Svalbard and in the correlative beds in the Barents Sea, key
Triassic petroleum source rocks of the circum-Arctic region (Vigran et al., 2008).
76
Four source rock extracts (PH01, PH07, PH08, and PH09) from Phoenix-1
core discussed in Chapter 1 display high HI values (634, 613, 564, and 759 mg HC/ g
TOC) with algal type I kerogens. Robison et al. (1996) also reported that kerogen
composition of the Shublik core in the Phoenix-1 well is mainly fluorescent
amorphous algal organic matter (amorphite), alginite, and exinite, with minor amounts
of non-fluorescent amorphite, vitrinite, and inertinite.
In conclusion, algal organic matter is dominant in both calcareous and shaly
Shublik organofacies and in biomarker (sterane and cheilanthane) evidence from the
oils. In addition, similar CSIA-D signatures (Fig. 7) and shared QDA source-related
trend (Fig. 5A) support a common OM source interpretation for both calcareous and
shaly Shublik samples.
Oil-source rock correlation
The C27 - C28 - C29 sterane and diasterane ternary plots are highly source-
specific and are used for oil-source rock correlation (Fig. 9; Peters at al., 2005). The
results support a distinction between calcareous and shaly Shublik oil families.
However, shaly Shublik oil sample N1 plots near the calcareous Shublik family, rather
than the shaly group. This distinction is more evident from diasterane distributions.
Rock extract PH07 correlates closely to shaly Shublik oils (NS13 and SP1a), whereas
the rest of the Phoenix-1 extracts plot within or near the area occupied by the
calcareous Shublik oil family. The two Prudhoe Bay extracts (207 and 208) are both
plotted within the calcareous group, which contradicts with chemometric analysis
predictions (Fig. 4).
77
Diasteranes/(dia + regular) C27 steranes and Ts/(Ts + Tm) depend on both
source and thermal maturity but can still be used to differentiate extract and oil
samples by their source rock depositional environment (Fig. 10; Moldowan et al.,
1994). The samples cluster according to oxicity and acidity of the depositional
environment, although the relative importance of lithology and oxicity remains
unknown (Peters et al., 2005). The Ts/(Ts+Tm) ratio is sensitive to clay-catalyzed
reactions, thus samples from anoxic the carbonate group have low Ts/(Ts+Tm) ratios
compared to anoxic shales (e.g., McKirdy et al., 1984). Similarly, diasteranes
(rearranged steranes) are low in clay-poor carbonate source rocks and related oils
(Peters et al., 2005). Low Ts/(Ts+Tm) of the shaly Shublik extract PH07 may be due
to low maturity. Oil sample CO1 was left out of this plot due to high thermal maturity,
which resulted in unreliable trisnorhopane and diasterane measurements.
Fig. 11 shows C24/C23 tricyclic terpane versus C29/(C29 + C30) hopane ratios
that also support separation of the Shublik into two genetically-distinct groups. Shaly
Shublik samples plot closer together, while calcareous samples have a wider spread.
All four peaks (C23, C24, C29, and C30) are among the largest on the m/z 191 (Fig. 3).
Although tricyclic terpanes are likely linked to Tasmanites, various tricyclic terpane
ratios are valuable for predicting source-rock depositional environments based on
measurements of many world-wide oils (Peters et al., 2005). Organic-rich carbonate
rocks and related oils usually show larger peak C29 relative to C30 hopane (e.g.
Zumberge, 1984). Elevated C29/(C29 + C30) hopane values are consistent with
calcareous Shublik source rock.
78
Prediction of source rock character from oil composition
Petroleum composition depends on the type of organic matter, lithology, and
redox conditions, as well as many secondary effects that include, but are not limited to
thermal maturation, migration, and biodegradation (Peters et al., 2005). Similar levels
of thermal maturity for extracts and oil samples allows for optimal chemometric
classification of samples into genetically-distinct groups, as well as for oil-source rock
correlation. Thus, distinguishing thermal maturity from organic matter input and
depositional environment effects on petroleum composition, including the biomarker
fingerprints, is critical for better results. The exception illustrated here comes from
diamondoid correlation methods. For example, very mature oil sample CO1 with very
low biomarker concentrations can be correlated with biomarker-rich oils KC4 and F5a
by QEDA (Figure 6). Although the source rocks and oils in this study vary in thermal
maturity, we focus the following discussion on key source-related parameters that
control differentiation of calcareous and shaly Shublik oil families and their mixtures.
Redox and salinity
The C31 to C35 homohopane distributions support subdivision of Shublik oil
samples into two genetically distinct families (Fig. 12). Both calcareous (KC4, M1,
F5a) and shaly (NS13 and SP1a) Shublik oils show similar enrichment in C35
homohopanes, typical of organic matter from anoxic depositional settings (Peters and
Moldowan, 1991). The regular stair-step progression of C31 - C35 homologs observed
on m/z191 is consistent with this interpretatation (Fig. 3). Samples N1 and F5 display
lower C35 homohopane indices consistent with suboxic bottom waters during
deposition. Except for the C32 homohopanes, the hopane distributions for N1 oil is
79
intermediate between the two groups, consistent with a mixture, as supported by other
geochemical data.
Gammacerane is commonly linked to water-column stratification due to
salinity during source-rock deposition (Sinninghe Damsté et al., 1995). Higher
gammacerane indices [gammacerane/(gammacerane + C30 hopane)] suggest a more
stratified water column during deposition of the clay-poor facies (Fig. 13).
Lithology
Biomarker analysis revealed that ratios of C22/C21, C24/C23, C24 tetracyclic
(Tet)/C26 tricyclic terpanes, C29/ C30 hopanes, diahopane index (C30* 17α-diahopane
/(C30* 17α-diahopane + 17α-hopane); Fig. 3), and diasteranes/(dia + regular) C27
steranes were the most useful for differentiating calcareous from shaly Shublik oil
families, as well as organofacies (Fig. 14). Both rearranged steranes (diasteranes) and
hopane (diahopane) form as a result of the clay-catalyzed rearrangement of biological
precursors during diagenesis (Rubinstein et al., 1975). Thus, low diasteranes/steranes
and diahopane index ratios indicate a clay-poor environment during diagenesis.
Conversely, higher values for these ratios suggest deposition under clay-rich
conditions.
Similarly, diamondoids are believed to result from this catalytic rearrangement
of organic precursors (such as multi-ringed terpenoids) on clay minerals during oil
generation (Dahl et al., 1999). QEDA analysis also supports the calcareous versus
shaly Shublik distinction, but additionally provides signature of rock end-members
and oil mixtures (Fig. 6). It is striking that “shaly” Shublik end member AL02 has
58.1 wt% carbonate and 7.7 wt% clay (Table 3), whereas “calcareous” Shublik end
80
member AL03 has 97.8 wt% carbonate and < 1 wt% clay, placing them both in the
category of “carbonate rocks.” In addition, shaly Shublik extract PH07 and three
calcareous extracts (PH01, PH08, and PH09) from the Phoenix-1 core have 25.3, 24.2,
30.2, and 38.5 wt% carbonate, respectively. All of these values are in the same range,
and there is no difference in carbonate content for the shaly Shublik end-member
PH07 (25.3 wt%). The 25 – 40 wt% range of the Phoenix-1 biomarker end-members is
drastically different from the Alcor-1 QEDA end-members (58 - 90 wt%). Clay
creates a more reactive setting for catalytic rearrangements of biomarkers and
diamondoids that affects composition of expelled petroleum. Thus, the presence or
absence of active clay minerals is more important than the carbonate content per se.
Some clays, such as montmorillonite, are very catalytically active and can act as a
super acid; while others like illite are not very acidic or catalytically active. Thus, a
small proportion of montmorillonite can show a greater effect than a large proportion
of illite (e.g., Wei et al., 2006).
CONCLUSIONS
Detailed geochemical analysis of Alaska North Slope rock extracts and oils
was performed to address differences in Shublik organofacies and their effect on
compositions of oil accumulations. This work confirms classification of the Shublik
Formation into two genetically-distinct organofacies and related oil families, and
reveals mixtures between the two. These important differences between samples are
based on the combined chemometric evaluation of multivariate biomarker data,
detailed comparison of mass-chromatograms, and individual biomarker ratios, coupled
with QEDA results.
81
These data indicate dominantly marine algal input for both organofacies
deposited under similar redox condition (anoxic to suboxic) in either clay-rich or clay-
poor depositional setting. However, the analyzed core samples show no apparent
correlation between carbonate and clay content and organofacies assignments. It is
suggested that presence of active clay minerals, most likely montmorillonite, during
the deposition of clay-enriched facies, played a major role in catalytic rearrangements
of biomarkers and diamondoids resulting in distinct oil signatures.
Additionally, we confirmed presence of both Shublik organofacies in the
Phoenix-1 core north of the Barrow Arch, and in the Alcor-1 core to the south. This
suggests both organofacies are present across the basin. Geographic distribution of
Shublik oil types can therefore be described as controlled by the interplay of clay
content and siliciclastic input during the deposition, basin geometry and burial history,
source rock maturity, lateral and vertical facies variability, and migration pathways.
ACKNOWLEDGMENTS
This study was supported by the Stanford Basin and Petroleum System
Modeling (BPSM) Industrial Affiliates Program. Special thanks are due to Ed and
Karen Duncan, and Great Bear Petroleum for granting access to the Alcor-1 Shublik
core, sampling permission, and funding this research. The authors thank Ken Bird for
his recommendations during this research, and for providing oil samples from the
Colville-1 well. We also thank Biomarker Technologies, Inc. for academic discount
and lab assistance, Agilent Technologies for access to MassHunter workstation
software, Infometrix, Inc. for Pirouette software academic package, and K-T
GeoServices, Inc. for providing academic discount on their services.
82
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Table 1. Summary of oil and rock samples analyzed in this study. Well names and Unique Well Identifier (UWI) are in compliance
with Alaska Geologic Materials Center Inventory. Rock extracts 207 and 208, and oil samples NS13, SP1a, SP1b, N1, KC4, F5a,
M1, MB13b, and D1 were previously analyzed by Seifert et al. (1980) and Wang et al. (2014) respectively. Previously published
sample names were utilized for consistency. Samples PH01, PH07, PH08, and PH09 were also discussed in Chapter 1.
Sample
ID
Sample type
Wang et al., (2014)
oil type Well name UWI Reservoir
Analyses performed
Biomarkers QDA QEDA
NS13 Oil Shaly Northstar Unit NS-13 50029230170000 Ivishak Fm. x x x
SP1a Oil Shaly OCS Y-0370 Sandpiper 1 55201000070000 Ivishak Fm. x x x
SP1b Oil Shaly OCS Y-0370 Sandpiper 1 55201000070000 Ivishak Fm. - - x
N1 Oil Shaly Nikaitchuq 1 50629231930000 Sag River Ss. x x x
F5a Oil Calcalerous Fiord 5 50103202920000 Nechelik Sand x x x
KC4 Oil Calcalerous Kuparuk Riv Unit 1C-04 50029205470000 Kuparuk Fm. x x x
M1 Oil Calcalerous OCS Y-0334 Mukluk 1 55231000010000 U. Kuparuk Ss. x x x
D1 Oil Calcalerous J W Dalton Test Well 1 50279200060000 Lisburne Gr - - x
MB13b Oil Calcalerous Mikkelsen Bay St 13-09-19 50029200550000 Lisburne Gr. - - x
CO1 Oil N/A Colville 1 50103100020000 Shublik Fm. x x x
207 Rock extract N/A Kuparuk St 7-11-12 50029200620000 Shublik Fm. x x -
208 Rock extract N/A W Kuparuk St 3-11-11 50029200140000 Shublik Fm. x x -
PH01 Rock extract N/A OCS Y-0338 Phoenix 1 55231000050000 Shublik Fm. x x -
PH07 Rock extract N/A OCS Y-0338 Phoenix 1 55231000050000 Shublik Fm. x x -
PH08 Rock extract N/A OCS Y-0338 Phoenix 1 55231000050000 Shublik Fm. x x -
PH09 Rock extract N/A OCS Y-0338 Phoenix 1 55231000050000 Shublik Fm. x x -
PH04 Oil extract N/A OCS Y-0338 Phoenix 1 55231000050000 Ivishak Fm. x x -
13AL31 Rock extract N/A Alcor 1 50223200260000 Shublik Fm. x x -
AL02 Rock extract N/A Alcor 1 50223200260000 Shublik Fm. - - x
AL03 Rock extract N/A Alcor 1 50223200260000 Shublik Fm. - - x
87
Table 2. Carbonate content, total organic carbon (TOC), and Rock-Eval pyrolysis results for source rock samples. TOC and
thermal alteration index (TAI) data for samples 207 and 208 are from Seifert et al. (1980).
Sample
ID
Depth
(m)
Carbonate
(wt.)
TOC
(wt.)
S1
(mg HC/g
rock)
S2
(mg HC/g
rock)
Tmax
(°C)
TAI HI
(mg HC/
g TOC)
OI
(mg HC/mg
CO2)
S1/TOC
(mg HC/ g
TOC)
PI Maturity
13AL31 3225.4 43.5 4.2 1.6 2.5 473 - 58.5 11.0 37.5 0.39 Postmature
AL02 3232.8 64.6 3.9 0.9 2.0 476 - 50.0 6.3 23.6 0.32 Postmature
AL03 3234.3 88.6 0.2 0.1 0.1 - - 47.0 68.4 51.3 0.52 Postmature
PH01 2459.7 24.2 4.3 2.2 27.2 432 - 634.3 11.7 51.0 0.07 Immature
PH07 2442.5 25.3 4.8 1.5 29.2 431 - 612.6 11.1 32.1 0.05 Immature
PH08 2413.9 30.2 3.1 1.0 17.4 431 - 564.4 14.2 32.0 0.05 Immature
PH09 2428.2 38.5 5.4 1.8 40.8 436 - 759.4 8.4 32.8 0.04 Immature
207 2743.2 - 2.9 - - - 2.8 - - - Peak
208 2743.2 - 4.4 - - - 2.7 - - - Peak
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Table 3. Whole rock and clay x-ray diffraction (XRD) mineralogy results.
Sample
ID
Quartz
(wt%)
K-feldspar
(wt%)
Plagioclase
(wt%)
Carbonates
Apatite
(wt%)
Pyrite
(wt%)
Gypsum
(wt%)
Clays
Calcite
(wt%)
Dolomite
(wt%)
Illite/Mica
(wt%)
Illite/Smectite
(wt%)
AL02 20.1 0.7 1.9 52.9 5.2 9.4 1.7 0.4 5.6 2.1
AL03 1.1 0 0 97.8 0 0 0.2 0 0.9 0
89
Table 4. Key biomarker characteristics of oils and rock extracts from the North Slope of Alaska.
Biomarker Ratio PH01 PH04 PH07 PH08 PH09 207 208 N1 NS13 SP1a F5a KC4 M1 CO1
C24/C23 tricyclic terpanes 0.36 0.51 1.24 0.61 0.68 0.79 0.78 0.79 0.80 0.80 0.58 0.57 0.53 0.62
C22/C21 tricyclic terpanes 0.31 0.86 0.39 0.31 0.51 0.38 0.39 0.53 0.36 0.38 0.86 0.85 0.95 0.82
C24 tetracyclic/C26 tricyclics 0.17 0.54 0.25 0.14 0.76 0.24 0.19 0.30 0.16 0.14 0.53 0.52 0.61 0.24
C29/C30 hopane 0.56 0.97 0.40 0.61 0.75 0.35 0.40 0.50 0.39 0.43 0.69 0.94 1.06 0.70
Diahopane Index 0.03 0.03 0.05 0.03 0.03 0.10 0.14 0.16 0.19 0.18 0.06 0.04 0.03 0.26
Ts/Tm 0.44 0.35 0.36 0.41 0.38 0.80 0.82 0.65 0.65 0.63 0.45 0.36 0.33 0.90
Gammacerane Index 0.07 0.06 0.02 0.01 0.03 0.03 0.02 0.03 0.02 0.02 0.03 0.04 0.05 0.05
Homohopane index 0.08 0.08 0.06 0.03 0.02 0.04 0.02 0.06 0.07 0.09 0.06 0.07 0.06 0.00
C31% 26.94 32.21 32.88 39.45 49.11 35.65 40.77 31.53 27.65 26.63 34.20 32.69 34.96 43.89
C32% 16.84 18.89 22.13 22.59 24.34 24.78 27.85 23.17 21.07 20.36 21.18 20.61 20.53 32.18
C33% 24.05 17.70 18.62 16.94 15.08 17.44 17.28 18.58 19.21 19.36 17.70 16.95 16.81 23.93
C34% 14.76 13.20 11.50 12.01 7.01 12.10 9.18 13.03 14.46 13.92 13.21 12.80 12.19 0.00
C35% 17.42 17.99 14.87 9.00 4.46 10.03 4.93 13.69 17.61 19.74 13.70 16.96 15.51 0.00
Ts/Tm 0.62 0.44 0.45 0.56 0.49 3.27 3.23 1.44 1.35 1.26 0.63 0.47 0.41 6.15
αββC27(20S+20R) / Total
αββ(20S+20R) (C27+C28+C29) 0.24 0.24 0.21 0.21 0.27 0.23 0.23 0.23 0.22 0.22 0.24 0.23 0.25 0.23
αββC28(20S+20R) / Total
αββ(20S+20R) (C27+C28+C29) 0.32 0.33 0.28 0.34 0.33 0.32 0.31 0.30 0.29 0.30 0.31 0.32 0.32 0.33
αββC29(20S+20R) / Total
αββ(20S+20R) (C27+C28+C29) 0.44 0.42 0.51 0.45 0.40 0.45 0.46 0.47 0.49 0.48 0.46 0.45 0.43 0.44
C27 diasteranes/(regulars+dias) 0.44 0.38 0.59 0.39 0.33 0.56 0.61 0.65 0.74 0.74 0.57 0.50 0.44 0.55
C28 diasteranes/(regulars+dias) 0.33 0.29 0.47 0.26 0.23 0.45 0.50 0.55 0.63 0.62 0.46 0.39 0.35 0.47
C29 diasteranes/(regulars+dias) 0.31 0.28 0.49 0.24 0.22 0.43 0.46 0.53 0.63 0.63 0.43 0.39 0.35 0.46
Total C27-C29
diasteranes/(regulars+dias) 0.35 0.31 0.51 0.28 0.26 0.47 0.52 0.57 0.66 0.65 0.48 0.42 0.37 0.49
%C27 (253) 0.26 0.36 0.21 0.23 0.31 0.23 0.26 0.30 0.28 0.29 0.30 0.34 0.37 0.30
%C28 (253) 0.28 0.25 0.28 0.28 0.31 0.27 0.28 0.28 0.28 0.29 0.30 0.29 0.25 0.27
%C29 (253) 0.46 0.39 0.50 0.49 0.38 0.50 0.47 0.43 0.43 0.42 0.40 0.37 0.37 0.43
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Table 5. Quantitative diamondoid analysis (QDA) results and calculated extent of oil
cracking for analyzed oil and rock samples.
Sample
ID
C29 ααα 20R
stigmastane
(ppm)
1- + 2-methyl
adamantanes
(ppm)
3- + 4-methyl
diamantanes
Cc (ppm)
Baseline
Co
(ppm)
Extent of cracking
(1 – (Co/Cc)) x 100
(%)
PH01 359.1 126.6 27.1 7.4 73
PH04 83.8 0.0 1.7 7.4 N/A
PH07 62.7 117.2 21.8 4.5 79
PH08 301.3 100.0 7.4 7.4 0
PH09 17.4 196.3 36.7 7.4 80
207 21.4 0.0 0.2 4.5 N/A
208 18.5 0.0 0.4 4.5 N/A
N1 11.2 54.0 4.5 4.5 0
NS13 12.6 91.7 4.6 4.5 0
SP1a 16.9 145.3 6.8 4.5 33
F5a 18.2 80.0 9.4 7.4 22
KC4 19.1 114.4 14.8 7.4 50
M1 9.2 90.4 14.0 7.4 47
CO1 5.7 93.4 29.6 7.4 75
13AL31 0.0 1493.2 400.0 7.4 98
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Table 6. Quantitative extended diamondoid analysis results.
Sample Sample
type HCA type Tria Tet-1 Tet-2 Tet-3 Pent-1 Pent-2 Pent-3 Pent-4 CHXM
MB13b Oil Calcareous 1 0.205 0.117 0.031 0.052 0.033 0.018 0.010 0.015
D1 Oil Calcareous 1 0.191 0.125 0.032 0.041 0.030 0.020 0.010 0.014
KC4 Oil Calcareous 1 0.131 0.096 0.024 0.027 0.018 0.017 0.007 0.007
M1 Oil Calcareous 1 0.168 0.105 0.028 0.035 0.025 0.016 0.008 0.011
F5a Oil Calcareous 1 0.137 0.089 0.026 0.032 0.021 0.013 0.007 0.009
NS13 Oil Shaly 1 0.054 0.049 0.015 0.009 0.008 0.009 0.003 0.003
N1 Oil Shaly 1 0.160 0.108 0.030 0.041 0.033 0.023 0.012 0.014
SP1a Oil Shaly 1 0.081 0.062 0.017 0.016 0.012 0.010 0.005 0.006
SP1b Oil Shaly 1 0.088 0.073 0.021 0.021 0.018 0.016 0.007 0.007
CO1 Oil N/A 1 0.150 0.095 0.025 0.029 0.023 0.014 0.008 0.008
AL03 Rock N/A 1 0.111 0.095 0.024 0.059 0.022 0.017 0.007 0.012
AL02 Rock N/A 1 0.037 0.046 0.017 0.008 0.004 0.005 0.002 0.002
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Figure 1. Generalized chronostratigraphic column of Arctic Alaska after Houseknecht
et al. (2012). Key petroleum source rocks are Shublik Formation (grey), Kingak Shale,
pebble shale unit, and Hue Shale, including the GRZ (gamma ray zone). LCU – Lower
Cretaceous Unconformity.
93
Figure 2. Map of part of Arctic Alaska showing the study area, sampled and
referenced data. Main producing oil field units (light grey) are located in the northern
part of the Central North Slope along the structural axis of the Barrow Arch (dashed
line). See table 1 for details on well names and locations for analyzed oil and rock
samples. Referenced published data are from Peters et al. (2006, 2008) and Wang et
al. (2014).
94
Figure 3. Comparison of terpane mass chromatograms (m/z 191) for all crude oil and
source rock extract samples.
95
Figure 4. A - Hierarchical cluster analysis (HCA) dendrogram, B - principal
components analysis (PCA) scores plot resulted from chemometric analysis of forty
North Slope oils published by Wang et al. (2014) combined with current results. C -
HCA, D - PCA results from current dataset alone.
96
Figure 5. Quantitative diamondoid analysis (QDA) results. A - The relationship
between concentrations of methyladamantanes and methyldiamantanes. Established
trend is unique and relatively constant for each source, and is independent of oil
cracking. B - The correlation between diamondoid (3- + 4- methyldiamantanes) and
biomarker (stigmastane) concentrations estimates the extent of oil cracking for
analyzed oils and rock extracts from the Shublik Formation.
97
Figure 6. Quantitative extended diamondoid analysis (QEDA) results for
distinguishing Shublik end member and mixed oil types, and oil-source rock
correlation. Concentrations of all the compounds are plotted relative to the triamantane
concentrations. The end-member oil samples assignment to shaly and calcareous oil
families was pre-determined by biomarker analysis.
98
Figure 7. Compound specific isotope analysis of diamondoids (CSIA-D) for
calcareous and shaly Shublik comparison. Data for sample D1* are from Wang et al.
(2014).
99
Figure 8. The ternary diagram shows the relative abundance of C27, C28, and C29
monoaromatic steroids in aromatic fraction of Shublik oils and extracts determined by
gas chromatography-mass spectrometry (GCMS). Labeled fields associated with
terrigenous, marine, and nonmarine (lacustrine) input are adopted from Moldowan et
al. (1985).
100
Figure 9. Ternary diagrams of C27, C28, and C29 sterane and diasterane are highly
source specific and support calcareous and shaly Shublik oil family distinctions.
101
Figure 10. Diasteranes/(Dia + regular) C27 steranes versus Ts/(Ts + Tm) plot supports
oil-source rock correlation, however it is partly dependent on thermal maturity and
depositional environment.
102
Figure 11. Distribution of tricyclic terpanes and hopanes for oil-source rock
correlation.
103
Figure 12. Homohopane distributions for six North Slope oils vary between
calcareous and shaly oil families.
104
Figure 13. Variations in homohopane and gammacerane indices indicate redox and
salinity stratification during source-rock deposition.
105
Figure 14. Representative lithology-related biomarker parameters support subdivision
into calcareous and shaly oil families.
106
CHAPTER 3
DEPOSITIONAL ENVIRONMENT AND CHEMOSTRATIGRAPHY OF
ORGANIC FACIES OF THE TRIASSIC SHUBLIK FORMATION,
ALASKA NORTH SLOPE
107
DEPOSITIONAL ENVIRONMENT AND CHEMOSTRATIGRAPHY OF
ORGANIC FACIES OF THE TRIASSIC SHUBLIK FORMATION, ALASKA
NORTH SLOPE
Inessa A. Yurchenko1, Kenneth J. Bird2, and Stephan A. Graham1
1Department of Geological Sciences, Stanford University, Stanford CA 94305, USA
2U.S. Geological Survey, Menlo Park CA 94025, USA, retired
ABSTRACT
The Middle to Upper Triassic Shublik Formation is a laterally and vertically
heterogeneous petroleum source rock that has been analyzed both in outcrop and in the
subsurface, and interpreted to have been deposited under fluctuating oceanic
upwelling conditions (Parrish, 1987; Kupecz, 1995; Parrish et al., 2001). Its organic-
rich intervals are often recognized by abundance of impressions and shells of
distinctive Triassic bivalves, although the origin of Shublik organofacies remains
somewhat controversial.
To understand main controls on organofacies distributions across the North
Slope, this study reviews and refines lithologic and paleoenvironmental interpretations
of the Shublik Formation, and incorporates the newly acquired detailed geochemical
analyses of two complete Shublik cores. Additionally, the recent study of mollusk
fauna of soft sediments from the upwelling-influenced shelf of Mauritania
(Northwestern Africa) is hereby proposed as a comparable modern analog for the
organic-rich Shublik facies, to our knowledge, for the first time. Multi-proxy study of
lihofacies and biomarker depositional proxies, combined with stochastic chemofacies
108
analysis, reveals that key controls on organic facies distribution in the Shublik
Formation result from a complex and dynamic interplay of sea level, detrital sediment
input, and local bathymetry and hydrodynamic conditions without requiring changes
in organic source inputs or redox conditions.
INTRODUCTION
This work is built upon key results concluded from previous dissertation
chapters, but adds additional geologic and paleoenvironmental insight from core and
well log analysis in a regional stratigraphic context.
Chapter 1 thoroughly investigated vertical variations of source rock properties
in the Shublik core in the Phoenix-1 well (Fig. 1), and subdivided the Shublik section
into two non-source and four source-rock intervals based on the differences in
resource potential, lithofacies, chemofacies, and organofacies. Subsequently, Chapter
2 linked these organofacies to predicted “calcareous” and “shaly” Shublik oil families.
The analyzed core samples showed no apparent correlation between carbonate content
and organofacies assignments. Moreover, analysis of biomarkers revealed common
algal input for both organofacies/oil families and similar redox condition (anoxic to
suboxic) in either reactive clay-rich or clay-poor depositional settings, refining
previous designations of the more general assignments of shaly and calcareous facies.
Additionally, we confirmed presence of both Shublik organofacies in the Phoenix-1
core north of the Barrow Arch, and in the Alcor-1 core to the south, and suggested that
both organofacies are present across the basin.
Consequently, the main goals of this chapter are to understand how the newly-
proposed Shublik source-rock distribution model in the Phoenix-1 well relate to the
109
regional context and discuss what controls organofacies distributions across the North
Slope.
METHODOLOGY
This study focuses on geochemical and chemostratigraphic analysis of two
Shublik cores (Fig. 1) that are 65 miles apart.The Tenneco Phoenix-1 (OCS-Y-0338)
well, drilled on a structural feature northwest of the Prudhoe Bay field, recovered
continuous core through the Shublik Formation (~300 ft) that represents the most
detailed published core-based analysis of the Shublik Formation to date (Robison et
al., 1996). Samples from this core were analyzed for biomarker and diamondoid
analyses discussed in detail in Chapter 1. As part of the current work, this core was
viewed at the USGS Core Research Center and scanned at 1ft interval using a hand-
held XRF device.
The Merak-1 well, drilled by Great Bear Petroleum in 2012, cored the entire
Shublik Formation (~100 ft). The nearby Alcor-1 core used for diamondoid analysis of
Shublik end-members (samples AL02 and AL03) discussed in Chapter 2 is less than 2
miles away from Merak-1. Access to these Shublik cores was generously granted to
the Basin and Petroleum System Modeling Research Group at Stanford University by
Great Bear Petroleum. Both cores were scanned at 0.5 ft interval using a hand-held
XRF tracer and yielded similar results but both are drastically different from
observations in the Phoenix-1 core. Thus, for the purpose of this work, Alcor-1 and
Merak-1 Shublik cores are considered comparable and results of diamondoid analyses
are applied to the comparable intervals in the Merak-1 core.
110
Each core was scanned using Bruker Tracer IV-SD for data consistency. The
instrument settings for trace elements analysis are 40 kV, 14.3 mA, Al-Ti filter,
collection time of 60 seconds per sample. The setups for major elements analysis are
15 kV, 35 mA, 30 seconds per sample, with the vacuum pump (no filter). The current
method provides rapid and non-destructive measurements of major elements heavier
than sodium, and trace elements from barium to uranium. Quantification of elemental
concentrations was performed using matrix-specific calibration described in Rowe et
al. (2012). Note that the reference material set was developed for typical mudrock
analysis and all references have phosphorus concentrations less than 20 wt%, whereas
the Shublik Formation is a very phosphate-rich unit and its phosphorus content often
exceeds 20 wt%. Phosphorus content (wt%) for the selected sample set was also
measured using ICP and utilized to define the phosphorus calibration for proper
conversion of net count rates to concentration. A large number of samples was also
collected for carbonate content measurements based on sample weight difference
before and after acid treatment. The resulting carbonate content (wt. %) measurements
of collected samples were compared to calcium contents (wt. %) measured using non-
destructive XRF analysis for data validation.
In addition, we reviewed lithofacies described by Hulm (1999), and lithologic
units interpreted by Dingus (1984) from descriptions of Shublik cores (Fig. 1). We
investigated and adopted their correlations between cores to improve interpretations
between analyzed Phoenix-1 and Merak-1.
111
PREVIOUS WORK
Regional geologic setting
In the North Slope of Alaska, the stratigraphy is typically simplified by
dividing it into four tectono-stratigraphic sequences that reflect major phases of basin
evolution (Fig. 2A, Hubbard et al., 1987). The Franklinian sequence (Devonian and
older) consists of deformed and metamorphosed strata commonly referred to as
‘economic basement’ due to great burial and thermal maturity (Bird and Houseknecht,
2011). The Ellesmerian sequence (Mississippian to Jurassic) contains south-facing
(relative to present-day configuration) passive margin deposits that include nonmarine
to marine shelf siliciclastic and carbonate rocks (Bird and Houseknecht, 2011). The
Middle to Upper Triassic Shublik Formation lying near the top of this sequence is a
heterogeneous unit interpreted to have been deposited under fluctuating oceanic
upwelling conditions (Parrish, 1987; Kupecz, 1995; Parrish et al., 2001). The Shublik
Formation contains a characteristic set of lithologies that include calcareous,
glauconitic, phosphatic, organic-rich, and cherty facies, consistent with deposition in a
coastal upwelling zone (Parrish et al., 2001a,b).
The Beaufortian sequence (Jurassic and Lower Cretaceous) comprises
stratigraphically complex synrift deposits (Bird and Houseknecht, 2011). Rift-shoulder
uplift and subsequent subsidence of the rift margin lead to formation of the Barrow
Arch (Fig. 3), a regional structural high that later served as focal point for petroleum
migration and accumulation of the largest north Alaskan oil fields (Bird and
Houseknecht, 2011). However, Triassic and Lower Jurassic source rocks did not
generate hydrocarbons until Beaufortian and Brookian deposits provided sufficient
112
overburden for oil-window maturity. The Lower Cretaceous unconformity (LCU)
associated with the rift-shoulder uplift also played an important role in the genesis of
oil fields by providing migration pathways from mature source rock to sub- and supra-
unconformity reservoirs, as well as juxtaposition of overlying source and seal rocks
(Bird and Houseknecht, 2011). The overlying Cretaceous and Cenozoic Brookian
foreland basin sequence contains a thick siliciclastic succession derived from the
Brooks Range, which filled the Colville foreland basin. Some other petroleum source
rocks (e.g., Hue, GRZ, Torok, Seabee, and Canning Formations) and reservoir rocks
were deposited during this time.
Lithostratigraphy
The Middle to Upper Triassic Shublik Formation is a laterally and vertically
heterogeneous unit that has been described both in outcrop and in the subsurface. The
Shublik Formation is underlain by the fluvial Ivishak Sandstone and marine Eileen
Sandstone of the Sadlerochit Group and it underlies the shallow marine Sag River
Sandstone (Fig. 2A). Since theShublik Formation was first described by Leffingwell
(1919), mapped by Keller et al. (1961), and measured by Detterman (1970), it has
been divided into different facies, units, and zones.
Dingus (1984) studied 17 cored wells across the Prudhoe Bay field area and
divided the Shublik Formation into nine distinct units and one bed on the basis of well
log character and lithology (Fig. 2B). Parrish (1987) conducted facies analysis of the
Shublik Formation in three outcrops and 13 cores across the entire North Slope. As a
result, four distinct lithofacies were described as following: (1) - fossiliferous
sandstone or siltstone; (2) - glauconitic sandstone or siltstone; (3) - calcareous
113
mudstone or limestone with phosphate nodules; and (4) - black calcareous mudstone
or limestone, typically fossiliferous (Parrish, 1987). Kupecz (1995) subdivided the
Shublik Formation within the Prudhoe Bay field unit into four zones (from A to D)
based on their gamma-ray log signature (Fig. 2B). This zonation remains the most
widely-used subclassification of the Shublik Formation to date. These zones show
different gamma-ray log signatures, which reflect the lithologic contrast between
phosphatic sandstone (zone D), interlaminated black shale and limestone (zone C),
phosphorite and phosphatic carbonate (zone B), and interlaminated shale and
carbonate grainstone (zone A) (Kupecz, 1995). Hulm (1999) extended this
interpretation well beyond the Prudhoe Bay unit and into the National Petroleum
Reserve of Alaska (NPRA) area, and gave a detailed conventional core description for
10 wells that resulted in subdivision of the Shublik Formation into 12 depositional
facies (Fig. 2B). Facies stacking patterns were also discussed using sequence
stratigraphic approach. Parrish et al. (2001b) provided new core descriptions and
measured sections, and integrated this information with previously published data.
Kelly et al. (2007) conducted a detailed lithologic and geochemical study of the
Shublik Formation and the distal equivalent Otuk Formation from three outcrops in
order to provide a basis for understanding the lateral and vertical distribution of the
various facies. Some facies classification and core descriptions by Dingus (1984) and
Hulm (1999) were adopted and used for the purpose of this study.
Paleoenvironment
Middle and Late Triassic source rocks, with good to excellent source rock
potential and proved productivity, are the most widespread source rocks in the Arctic
114
(Spencer et al., 2011). During the Triassic Period, Northern Alaska, the Canadian
Arctic, Svalbard, the Barents Shelf, and the Russian Arctic were rimmed around the
margin of a large back-arc basin located between the landmasses of North America
and Eurasia, and opened up to the proto-Pacific Ocean (Fig. 4; Leith et al. 1993;
Spencer et al., 2011). Organic-rich sediments, with abundant phosphate and thin
coquina beds were deposited in an extensive region from the Barents Sea (Botneheia
Fm.) to the Sverdrup basin (Schei Point Group) in Arctic Canada to northern Alaska
(Shublik Fm.) (Leith et al., 1993; Mørk and Bjorøy, 1984; Parrish et al., 2001).
Despite similar lithologies, the depositional setting of these source rocks has been
disputed. The occasional meridional influenced, oceanic upwelling setting on an open
shelf is the current interpretation for the deposition of the Shublik Formation of Arctic
Alaska (Fig. 5; Dingus, 1984; Parrish et al., 2001; Hulm, 1999; Kelly et al., 2007;
Hutton, 2014). Subsequently, the Barents shelf and the Sverdrup Basin did not face an
open ocean, and were rather deposited in a shallow epicontinental sea and silled basin
settings (Mørk et al., 1982; Embry et al., 2002).
Fluctuations of sea level and its effects on Triassic deposition has been
extensively discussed in the literature, more recently using sequence stratigraphic
approaches (Dingus, 1984; Kupecz, 1995; Robison et al., 1996; Hulm, 1999; Kelly et
al., 2007, Hutton, 2014).
Sequence stratigraphy
Within the Prudhoe Bay Unit, Dingus (1984) showed that the Shublik
Formation represents a well-preserved transgressive-regressive shelf sequence.
Kupecz (1995) determined the Shublik Formation to represent a third-order sequence
115
(duration about 10 - 15 My) consisting of a thin basal transgressive lag followed by a
highstand systems tract consisting of two shallowing-upward parasequences. This
interpretation was applied within the Prudhoe Bay Unit (Kupecz, 1995). In the
offshore Phoenix-1 well, Robison et al. (1996) interpreted the Shublik to represent a
different third-order sequence by assigning the underlying Eileen Sandstone and lower
half of the Shublik Formation to the transgressive systems tract and the remaining
upper half of the Shublik to the highstand systems tract. Hulm (1999) re-evaluated and
expanded these earlier interpretations. He included the underlying Eileen Sandstone
and Ivishak Formation, and the overlying Sag River Sandstone, and subdivided this
interval into two third-order depositional sequences and the lowstand systems tract
(LST) and transgressive systems tract (TST) of a third (Fig. 2B). This remains the
most detailed (97 wells) subsurface sequence stratigraphic interpretation of the
Shublik Formation to date. Based on facies stacking patterns, Parrish et al. (2001)
concluded that siliclastic facies are most common during lowstand and transgression,
organic-rich facies are characteristic of transgression, and carbonate-rich facies are
more prevalent during highstand, whereas phosphatic facies occur along transgressive
and maximum flooding surfaces.
Kelly et al. (2007) applied Hulm’s interpretations to correlate to outcrop
exposures in the northeastern and central Brooks Range. Kelly et al. (2007) created a
sea level curve which implies three potential rises in sea level during the
Middle−Upper Triassic and postulates a fourth potential rise in sea level during the
Carnian. Hutton (2014) revised the sequence stratigraphic architecture and included an
additional fourth depositional sequence within the Middle-Upper Triassic sediments in
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northern Alaska in comparison to previous interpretations. We adapted Hulm’s
sequence stratigraphic interpretations developed for Phoenix-1 and Prudhoe Bay
cores.
Paleoecology
The faunal assemblage of organic-rich facies of the Shublik Formation reflects
a low species diversity with abundant individuals of the Late Triassic Pectinacea,
Halobia and Monotis (Dingus, 1984). Bioturbation and identifiable burrows are
common in Zone A of the upper Shublik Formation (Dingus, 1984; Hulm, 1999).
Dingus (1984) observed three unidentifiable calcareous foraminifera within analyzed
cores in the Prudhoe Bay Unit. In addition, Parrish (2001) reported that marine reptiles
are also common in the Shublik Formation and noted that one of the most striking
characteristics of the organic-rich facies is the abundance of impressions and shells of
Halobia. Blodgett and Bird (2002) analyzed the Shublik Formation in the Phoenix-1
well and reported oysters Gryphaea and Ladinian age bivalve Daonella frami, in
addition to Carnian age Halobia and Norian age monotid bivalves described in the
Prudhoe Bay cores.
Paleoenvironmental controls on distribution of Triassic bivalves
The Middle to Late Triassic bivalves were widely distributed across the
Tethys, Panthalassa, and Arctic seas, and occurred in a wide variety of marine facies
and water depths, but are most notable for their monospecific shell accumulations in
black, organic-rich shale facies typical of anoxic or dysoxic environments
(McRoberts, 2000; McRoberts, 2011). The evolutionary transition from Daonella to
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Halobia occurred near the Ladinian-Carnian boundary, and ecologic replacement of
Halobia by Monotis occurred during Early or Middle Norian (Dingus, 1984;
McRoberts, 2010). However, the mode of life for the Triassic flat clams is still
disputed. They have been interpreted as pseudoplanktonic, nektoplanktonic, epibenthic
chemosymbionts, and semi-infaunal mud-stickers among others (Fig. 6A). Based on
the morphology and distribution of the genuses Halobia and Daonella, the most
recently advocated living habitat is an epibenthic mode of life with likely planktonic
larval stages, explaining their wide dispersal (Fig. 6B; Schatz, 2005; McRoberts, 2010;
Bakke, 2017).
Schatz (2005) interpreted that daonellids were most likely epibenthic (living on
a substrate above the substrate surface), pleurothetic (resting on their sides),
opportunistic with regards to oxygen deficiency, and specialized for soupy, soft
substrates. He interpreted both flatness of clams and thinness of their shells as
adaptive features to dysoxic conditions. The flat, subcircular shells suggest a high
surface-to-volume ratio for higher rates of oxygen uptake by absorption and diffusion
of oxygen via surface tissues (Oschmann, 1993; Schatz, 2005). Calcite secretion under
dysoxic conditions takes more energy than under oxic conditions, thus secretion of an
extremely thin shell reduces oxygen consumption (Rhoads and Morse, 1971; Schatz,
2005). In addition, the use of lighter calcite (2.71 g/cm3) instead of aragonite (2.93
g/cm3) in their thin, flat shell allowed them to float on soft, soupy sediments (Schatz,
2005).
These bivalves were part of episodic, opportunistic palaeocommunities
described by Levinton (1970) as unstable populations that are not resource limited but
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primarily controlled by the physical, and not the biotic, environment. Major
constraints in the distribution of bivalves are water depth, substrate, temperature,
salinity, oxygenation, and oceanographical currents. Many of these Triassic flat clam
palaeocommunities are interpreted to have inhabited and dominated environments near
a threshold oxygen minimum boundary, which other shelly benthos found unsuitable.
The episodic nature of many of the shell beds suggests that Triassic flat clams also
appear to have exhibited low resistance to environmental perturbations but are resilient
in being able to recover quickly.
Vigran et al. (2008) published organic geochemical, palynological and
sedimentological data from the Middle Triassic dark shale of the Sassendalen Group
of Svalbard, suggesting that free-swimming larvae or bivalves living on the sea floor
experienced oxygen deficiency due to periodic Tasmanites algal blooms. Pelagic
juvenile bivalve larvae, when starting to grow shells, may have settled on the anoxic
sea bottom to form death assemblages.
RESULTS AND DISCUSSION
Phoenix-1 source-rock distribution model
The Shublik Formation in the Phoenix-1 well was subdivided into two non-
source and four source-rock intervals (SR-1 to SR-4) based on TOC and Rock-Eval
pyrolysis results, and distinctive geochemical, lithologic and chemostratigraphic
features (Fig. 7). Chapter 1 discusses TOC and Rock-Eval pyrolysis results of the
Phoenix-1 core in great detail (Fig. 7).
All source intervals display high average TOC (4.7 to 6.5 wt%) and average HI
(596 – 763 mg HC/ g TOC) values characteristic of Type I kerogen. However, only
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the SR-3 interval is defined by clay-rich organofacies confirmed by biomarker
analysis of sample PH07. The SR-1 and SR-4 intervals show similar elemental
composition (except P) to SR-3, but different lithofacies associations (Fig. 7). Interval
SR-2 has strikingly different elemental composition and is characterized by type via
clay-poor biomarker organofacies signatures; whereas, SR-1 shows similar to clay-
rich organofacies kinetics (measured by Masterson, 2001; Chapter 1). No kinetics
measurements were made in the SR-4 interval. Despite the difference in lithology and
kinetics, all three intervals (SR-1, SR-2, and SR-4) are defined by clay-poor biomarker
signatures. Additionally, it has been suggested that the presence of active clay
minerals, most likely montmorillonite, during the deposition, played a more important
role than carbonate and clay content of organofacies per se (Chapter 2).
These observations show no apparent correlation, making it hard to depict
what controls organic facies distribution. The following points come to mind:
(1) Chemometic analysis in Chapter 2 (Fig. 4C) revealed that rock extract PH08 of
SR-1 may cluster with either clay-rich or clay-poor groups depending on the scenario,
or whether the rest of the samples cluster within the defined groups;
(2) The effect of migrated hydrocarbons on biomarker signatures of indigenous
bitumen of analyzed samples may have been underestimated, leading to misleading
results; and
(3) Lithologic descriptions of the core are limited to what can be observed with a
naked eye or a hand lens.
In order to further analyze what controls vertical variability in organofacies
and lithofacies, the following quantitative work has been done and is summarized on
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Figs. 8 - 12. Variation of TOC and Rock-Eval pyrolysis peak S2 in different lithofacies
is shown on Fig. 8. Most samples collected from parallel-laminated claystone; wavy-
laminated, fossiliferous claystone and siltstone; and bioclastic, argillaceous
wackestone facies, display good petroleum potential the Phoenix-1 core. Fig. 9
compares total carbonate, total clay, illite, mica, and smectite clay mineral contents
measured via x-ray diffraction (XRD) analysis to contents of selected elements (Ca,
Al, Si, K) measured using a hand-held XRF. Note that Phoenix-1 carbonate and clay
mineral content data were taken from a USGS public data set, and not measured by the
author. Calcium measurements by hand-held XRF appear to have excellent correlation
with carbonate content, and provide a much higher resolution record. Al, K, and to a
lesser extent K seem to show good correlation with total clay content, as well as with
separate clay minerals. Fig. 10 displays representative core photos of defined source
rock intervals (SR-1 to SR-4) in the Phoenix-1 core.
A multicomponent statistical analysis has been applied to produce
chemofacies. A hierarchical cluster analysis (HCA) dendrogram resulted from
chemometric analysis of XRF data from Phoenix-1 core (359 measurements) and is
shown on Fig. 11. Results are validated using conventional geologic description of the
core. Results show that the Shublik Formation can be effectively subdivided into
chemofacies that are in agreement with lithofacies and even organofacies. Results are
validated using conventional geologic description of the core, and eleven samples of
known lithofacies analyzed in Chapter 1 were used as control points.
Further, the variation of selected major and trace elements were analyzed by
chemofacies (linked to organofacies end-members) (Fig. 12). This summary plot
121
includes Ca as carbonate proxy, Si and Al as detrital deposition proxies. Si is usually
associated with coarse grains, and Al is associated with finer grains. Enrichment of K
and Fe is common in clay-rich layers. Phosphorus and sulfur content are phosphate
and sulfur enrichment indicators; and molybdenum and nickel as proxies for reducing
conditions and productivity, respectively.
Regional maturity and thickness variations
In order to understand how the newly proposed Shublik source-rock
distribution model in the Phoenix-1 well relates to the regional context, it is important
to understand thickness and maturity variation tends across the North Slope. Regional
structure and isopach maps of the Shublik Formation are shown on Figs. 13 and 14.
Geochemical analysis from Chapter 2 provided important points of control for
understanding regional trends in Shublik maturity, showing a general increase in
maturity down the southern flank of the Barrow arch. Due to significant maturity
difference between the immature Phoenix-1, mature Prudhoe Bay and postmature
Merak-1 cores, only relative changes in vertical variability of TOC will be emphasized
in further source-rock distribution model discussions.
Merak-1 source-rock distribution model
Analysis performed on the Merak-1 core is similar to the one described for the
Phoenix-1, and is summarized on Figs.15 - 19. The key difference is that the
multicomponent statistical analysis was applied to the combined Phoenix-1 and
Merak-1 dataset (564 measurements for each element). Fig. 11 displays general
agreement between core-derived lithofacies and XRF-derived chemofacies, but
122
revealed and quantified some noticeable differences between the two cores.
Calcareous chemofaceis-7 are dominant in the Merak-1, and are minor in the Phoenix-
1. In contrast, chemofacies-6 of the Phoenix-1 are absent in the Merak-1 core.
Analysis of selected major and trace elements and their variation between the
chemofacies (linked to organofacies end-members) (Fig. 19). This summary plot
shows noticeably higher concentrations of Al, K, Th (fine grained detrital input, clay
minerals proxies) for all three chemofacies (1-3) linked to wavy-laminated claystone
lithofacies related to clay-rich organofacies. This also shows differences in
productivity, redox, and sulfur proxies (Ni, Mo, S) between wavy-laminated claystone
lithofacies of Merak-1 (chemofacies 3) and Phoenix-1 (chemofacies 1) clay-rich
organofacies end-members.
Prudhoe Bay source-rock distribution model (PBU U-13 Sohio Term Well B)
Dingus (1984), Kupecz (1995), and Hulm (1999), published information on
Prudhoe Bay Shublik cores compiled here into a source-rock distribution model.
Correlation between Dingus’ and Hulm’ Shublik subdivisions is summarized on Fig.
2B. Kupecz (1995) published detailed TOC distribution for the Sohio Term Well B
(PBU U-13), displayed on Fig. 20A, located near cores, lithologically described by
Dingus (1984) and Hulm (1999). In addition, Dingus (1984) reported gradual
thickness changes within units of the Shublik Formation suggesting a relatively stable
depositional environment within the Prudhoe Bay. This allowed for correlation
between TOC and described lithostratigarphic units, using characteristic log patterns
and zonal subdivisions from the Prudhoe Bay Unit Common Database.
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There are two source rock intervals with elevated TOC values displayed on
Fig. 20A. They were both described as similar black, organic-rich, high-TOC, high-HI
marine shale full of Halobia and Monotis bivalves (Figure 9). The top thicker interval
described by Dingus (1984) as calcareous mudstone unit (CMU) correlates to wavy-
laminated, fossiliferous claystone and siltstone facies from Hulm’s classification
(1999). Fig. 20B shows core photograph of wavy-laminated, fossiliferous claystone
and siltstone facies and Halobia sp. impressions along the bedding plane in a
correlative interval in the PBU TR 23 18-11-12 (9907 ft depth) from Hulm (1999).
This looks very similar to the observations we made in the Phoenix-1 and Mrak-1
cores (Fig. 20C, D).
Thus, we see the same distinct organic-rich lithofacies in all three viewed
models, but with different facies stacking and variable thickness. A more detailed
analyses of facies stacking and isopach patterns is needed for more specific
interpretations. However, a review of published stratigraphic correlations by Dingus
(1984), and Hulm (1999) across the Prudhoe Bay area illustrates gradual trends of
laterally persistent units with occasional facies changes. Overall, in the vicinity of
Prudhoe Bay, the Shublik Formation was likely deposited on a broad relatively
shallow and stable shelf with the shoreline and a source of siliclastics to the east (Fig.
21). In general, sediment thickened to the west, with an associated decrease in grain
size and an increase in the amount of limestone.
Modern analog
Coastal upwelling regimes associated with eastern boundary currents are the
most biologically productive ecosystems in the ocean and function under extremely
124
variable conditions (Capone and Hutchins, 2013). The modern California and Peru
current systems in the Pacific, along with the Canary and Benguela current systems in
the Atlantic, are well-known examples of such systems (Fig. 22). Their equatorward
winds lead to the offshore transport of surface water, allowing cold, nutrient-rich
water to upwell. This provides supplies of nitrate, phosphate and silicate for
phytoplankton blooms that consume much of the inorganic carbon through
photosynthesis, ultimately leading to the depletion of oxygen in the underlying water
column and sediments (Capone and Hutchins, 2013).
However, modern analogs of infaunal bivalve-dominated carbonates are rare.
Such modern systems received noticeably less attention than coral reef habitats,
leading to difficulty in recognizing comparable deposits in the sedimentary record. We
propose that the recent study of mollusk fauna of soft sediments from the upwelling-
influenced shelf of Mauritania (northwestern Africa) by Michel et al. (2011a, b) is a
comparable modern analog for the organic-rich Shublik facies with abundant
impressions and shells of Triassic flat clams.
The narrow (~30 miles) continental shelf of northwest Africa broadens to a
width of 90 miles offshore of northern Mauritania to the Golfe d’Arguin (Fig. 23).
Upwelled cold nutrient-rich waters push onto the wide Mauritanian shelf, favoring
carbonate production dominated by bivalves and foraminifers (Fig. 22B). Benthic
photosynthetic biota are absent, with suspension- and deposit-feeding benthic biota
dominant over the shelf. This suggests the importance of planktonic blooms to the
high productivity of the Mauritanian waters. This is confirmed by high chlorophyll α
concentrations (Fig. 22A) indicative of eutrophic conditions that suppress
125
phototrophic benthic organisms. The upwelling occurs year-round, displaying seasonal
variability related to latitudinal movements of trade winds. This results in open-shelf
sedimentation under high water-energy conditions. Sediments are provided to the
system by eolian dust input from the Sahara, resulting in a mixed carbonate -
siliciclastic sedimentary system.
The carbonate content in the sediments of the Golfe d’Arguin ranges from 35
to 93%, with carbonate-dominated area in the wide northern part, where carbonate
content reaches values up to 70 - 93%. With increasing water depth, carbonate
contents decrease (from 70% to 50%) before increasing again between 100 and 200
mwd (meters water depth) to 80%. This sedimentation pattern is reflected by the
overall north - south trend from coarse-grained, carbonate-dominated sediments in the
north, to fine-grained, siliciclastic-dominated deposits in the south (Michel et al.
2009). The sedimentary facies in the Golfe d’Arguin form a facies mosaic (patches on
the shelf) rather than bathymetrically-defined depositional belts (Fig. 23). Depth
zonation, however, is introduced by the ecological requirements of the mollusk
assemblages, but lacks photic-related zonation, because most of the benthic carbonate-
secreting organisms are aphotic.
Michel et al. (2011 a,b) described five sedimentary facies (F1 - F5; Fig. 23)
among seafloor sediments as defined by a statistical analysis based on grain size,
carbonate content, and grain association. The bioclastic composition of the five facies
is similar throughout, dominated by shells and fragments of bivalves and foraminiferal
tests. Thus, the facies arrangement reflects the interaction between: (1) carbonate
production, controlled by the biology and ecology of the carbonate-secreting biota
126
(e.g., the large portion of centimeter-size Donax burnupi shells present in the northern
shallow part of the Golfe d’Arguin; F1, F2, and F3), and (2) hydrodynamics and
bathymetry, which influence dispersion and distribution of the carbonate and
noncarbonate sediments (e.g., greater contents of mud and fine-grained sand in the
southern part of the Golfe d’Arguin; F4 and F5; Fig. 23).
The siliciclastic - bivalve - foraminifer muddy facies (F5; Fig.23) show lowest
carbonate content, ranging from 39 to 56%. This facies is characterized by high mud
content, very poor to moderate sorting, and a bivalve- and foraminifer-dominated
biota. This mud-rich facies is present in the southernmost part of the study area, on the
mid (20 – 50 mwd) to outer shelf (> 50 mwd) (Fig. 23) and are proposed as
comparable modern analog for the organic-rich Shublik facies abundant in
impressions and shells of halobiids.
Mollusks reflect the muddy substrate (e.g., Nuculana bicuspidata and Tellina
compressa). The ecological requirements of the dominant species clearly indicate
water depths of < 60 m for the locus of production (taphocoenosis T3; Michel et al.,
2011b). Nuculana bicuspidata is an infaunal bivalve with a low mobility that lives
close to the sediment-water interface in organic-rich, fine-grained material (cf. Rhoads
et al., 1972). This species is well adapted to the highly productive study area where
large quantities of organic matter are produced and deposited on the seafloor. The
occurrence of the bivalves Anodontia sp., Myrtea spinifera, and Thyasira flexuosa is
interpreted to be related to low-oxygen conditions, which suggest high organic-matter
concentrations in the fine-grained sediments.
127
SUMMARY
Based on the available evidence, the organic-rich facies distribution of the
Middle-Upper Triassic Shublik Formation of Arctic Alaska depends on the
depositional environment. These depositional environment controls result from a
complex and dynamic interplay of physical, chemical and biological factors. During
Shublik deposition, an upwelling-influenced open shelf resulted in high nutrient
supply that stimulated algal blooms, leading to high net organic productivity, reduced
water transparency, oxygen deficiency, and water column stratification (Fig. 24).
Evidence of such eutrophic conditions is indicated by the lack of photic benthic
organisms, bioturbation and trace fossils, and dominance of the monospecific light-
independent epibenthic bivalves. The flat, subcircular, thin shells of these carbonate-
secreting organisms allowed them to adapt to dysoxic conditions, and float on soft,
soupy, muddy substrate. Seasonal change in algal blooms, sedimentation of organic
matter, and detrital components, is likely responsible for deposition of parallel and
wavy laminations observed in the core that consist of couplets of light carbonate-rich
laminae and dark organic-rich laminae. The episodic nature of many of the shell beds
suggests their low resistance to environmental changes, but ability to recover quickly.
The clay-rich organofacies with abundant bivalves occurred on a broad mid to
outer shelf, and was deposited when organic productivity at times overlapped with
periods of increased siliciclastic input controlled by changes in sea level and local
sediment dispersal systems, and therefore was more spatially and temporally localized
than the widespread clay-poor facies. The overall organic-rich facies distribution in
the Shublik Formation can, therefore, be described by the interplay of sea level,
128
detrital sediment input, local bathymetry and hydrodynamic conditions without
requiring changes in organic source input or redox conditions.
129
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6380(96)00023-X.
Schatz, W., 2005, Palaeoecology of the Triassic black shale bivalve Daonella - New
insights into an old controversy: Palaeogeography, Palaeoclimatology,
Palaeoecology, v. 216, p. 189–201, doi: 10.1016/j.palaeo.2004.11.002.
Spencer, A.M., Embry, A.F., Gautier, D.L., Stoupakova, A. V., and Sørensen, K.,
2011, Chapter 1 An overview of the petroleum geology of the Arctic:
Geological Society, London, Memoirs, v. 35, p. 1–15, doi: 10.1144/M35.1.
Vigran, J.O., Mørk, A., Forsberg, A.W., Weiss, H.M., and Weitschat, W., 2008,
Tasmanites algae - Contributors to the Middle Triassic hydrocarbon source
rocks of Svalbard and the Barents Shelf: Polar Research, v. 27, p. 360–371,
doi: 10.1111/j.1751-8369.2008.00084.x.
Wang, Y., Peters, K.E., Moldowan, J.M., Bird, K.J., and Magoon, L.B., 2014,
Cracking, mixing, and geochemical correlation of crude oils, North Slope,
Alaska: AAPG Bulletin, v. 98, p. 1235–1267, doi: 10.1306/01081412197.
133
Figure 1. Map of part of Arctic Alaska showing study area, sampled and referenced
data. Main producing oil field units (light grey) are located in the northern part of the
Central North Slope along the structural axis of the Barrow Arch (dashed line).
134
Figure 2. A - Generalized chronostratigraphic column of norther Alaska after
Houseknecht et al. (2012). LCU – lower cretaceous unconformity. B – Comparison
among previously described lithostratigraphic divisions of the Shublik Formation in
the Prudhoe Bay Unit. Zones (A-D) are based on well log picks in the Prudhoe Bay
Unit Common Database (Kupecz, 1995).
135
Figure 3. Schematic cross section from Brooks Range to the Beaufort Sea through
several oil and gas fields. Location of cross section is shown in Figure 1. Modified
slightly from Bird and Houseknecht (2011), Bird and Bader (1987).
136
Figure 4. Middle Triassic (245 -240 My) palaeogeographic map showing approximate
location of the Phoenix-1 and Merak-1 cores, modified from Ron Blakey and the
Colorado Plateau Geosystems, Inc.
137
A
B
Figure 5. A - Schematic reconstruction showing oceanic upwelling setting on an open
shelf (south-facing relative to current configuration) during deposition of the Triassic
Shublik Formation (Modified from Parrish et al., 2001). B - Lateral distribution of
upwelling related facies of the Shublik Formation and its distal equivalents (Modified
from Kelly et al., 2007).
138
A
B
Figure 6. A – Summary of disputed life habits of halobiids (form Schatz (2005)). A)
semi-infaunal mud-stickers, B) epibenthic chemosymbionts, C) nektoplankton, D)
byssally attached pseudoplankton. From Schatz (2005). B - Epibenthic, pleurothetic
(resting on their sides) mode of life for daonellids proposed by Schatz (2005).
139
Figure 7. Subdivision of the Shublik Formation into two non-source and four source intervals based on TOC and Rock-Eval
pyrolysis results, distinctive geochemical, lithologic and chemostratigraphic features. For detailed discussion refer to Chapter 1.
140
Figure 8. Variation of TOC and Rock-Eval pyrolysis peak S2 in different lithofacies.
Most samples collected from parallel-laminated claystone; wavy-laminated,
fossiliferous claystone and siltstone; and bioclastic, argillaceous wackestone facies,
display good petroleum potential. The box plots conveniently display the distribution
of data based on the five number summary: minimum, first quartile, median, third
quartile, and maximum.
141
Figure 9. Comparison of variations in mineralogical (XRD) and elemental (XRF) composition of the Shublik Formation in the
Phoenix-1 core. XRD data are from USGS Core Research Center well catalog (library number E9210).
142
Figure 10. Representative core photos of defined source rock intervals (SR-1 to SR-4) in the Phoenix-1 core.
143
Figure 11. Hierarchical cluster analysis (HCA) dendrogram resulted from
chemometric analysis of XRF data from Phoenix-1 core (359 measurements).
Resulted chemofacies were successfully correlated to lithofacies and organofacies
using eleven samples of known lithologies analyzed in Chapter 1 as control points.
144
Figure 12. Variation of selected major and trace elements by chemofacies in the
Phoenix-1 well. The four source rock samples with TOC > 2 wt% and related
chemofacies are outlined. The box plots display the distribution of data based on the
five number summary: minimum, first quartile, median, third quartile, and maximum.
145
Figure 13. Regional structural map of the top of the Shublik Formation. Rock-Eval pyrolysis and biomarker analysis of analyzed
samples provided important points of control for understanding regional trends in Shublik maturity.
146
Figure 14. Regional isopach map based on well control illustrates total thickness distribution of the Shublik Formation.
147
Figure 15. TOC and selected major and trace elements variations in the Merak-1 core. Gray shaded intervals show intervals with
elevated TOC values.
148
Figure 16. Comparison of variations in mineralogical (XRD) and elemental (XRF) composition of the Shublik Formation in the
Merak-1 core.
149
Figure 17. Representative core photographs of Merak-1 core intervals with elevated TOC values.
150
Figure 18. Hierarchical cluster analysis (HCA) dendrogram resulted from
chemometric analysis of XRF data from both Phoenix-1 and Merak-1 core (564
measurements). Resulted chemofacies were correlated to lithofacies (where possible)
using samples of known lithologies analyzed in Chapter 1 as control points.
151
Figure 19. Variation of selected major and trace elements by chemofacies in the
combined dataset of Merak-1 and Phoenix-1 measurements. Source rock samples with
TOC > 2 wt% and related chemofacies are outlined. The box plots display the
distribution of data based on the five number summary: minimum, first quartile,
median, third quartile, and maximum.
152
Figure 20. A – TOC variation in PBU U-13 well from Kupecz (1995). Organic rich
interval are highlighted in grey. B - Core photograph of wavy-laminated, fossiliferous
claystone and siltstone facies and Halobia sp. impressions along the bedding plane in
a correlative interval in the PBU TR 23 18-11-12 (9907 ft depth) from Hulm (1999).
Note that the core is deviated and that land surface is toward the upper left corner. C –
Representative core photograph of wavy-laminated, fossiliferous claystone and
siltstone facies in the Phoenix-1 core. D - Representative core photograph of wavy-
laminated, fossiliferous claystone and Halobia sp. impressions along the bedding
plane in the Merak-1 core.
153
Figure 21. Stratigraphic cross-section across the Prudhoe Bay unit area based on conventional core descriptions and sequence
stratigraphic framework from Hulm (1999). For well locations refer to Fig. 14.
154
A
B
Figure 22. A - Locations of the California, Peru, Canary and Benguela coastal
upwelling systems (white ovals) on a global satellite data on ocean chlorophyll α from
Capone and Hutchins (2013). Also shown are close-up views of seasonal chlorophyll
α concentrations in upwelling-supported phytoplankton blooms in the Golfe d’Arguin
(Canary system) from Michel et al. (2011a). B - Schematic model of environmental
conditions leading to the bivalve-dominated carbonate production of the northern
Mauritanian shelf (Golfe d’Arguin) from Michel et al. (2011a).
155
Figure 23. Bivalve facies distribution on the northern Mauritanian shelf (Golfe
d’Arguin) from Michel et al. (2011b).
156
Figure 24. Schematic diagram of the organic-rich Shublik facies abundant in
monospecific accumulations of Triassic flat clams typical of anoxic to dysoxic
environments.
157
APPENDIX A: SUPPLEMENTARY MATERIAL FOR CHAPTER 1
Summary of Contents
APPENDIX A-1: Compiled dataset of total organic carbon and Rock-Eval pyrolysis
results for Phoenix-1 core analyzed in this study.
APPENDIX A-2: Biomarker analysis results.
APPENDIX A-3: XRF analysis results for Phoenix-1 Shublik core.
158
Appendix A-1: Compiled dataset of total organic carbon and Rock-Eval pyrolysis results for Phoenix-1 core analyzed in this study.
Sample
ID
Depth (m)
TOC (wt%)
S1 (mg HC/g
rock)
S2 (mg HC/g
rock)
S3 (mg CO2/g
rock)
Tmax (°C)
HI (mg HC/ g
TOC)
OI (mg CO2/g
TOC)
S2/S3 (mg HC/mg
CO2)
S1/TOC (mg HC/ g
TOC)
PI (S1/(S1
+S2))
Data
Source
PH01 2459.7 4.3 2.2 27 0.5 432 634 12 54 51 0.07 This work
PH02 2445.4 1.1 0.6 5 0.3 434 432 31 14 57 0.12 This work
PH03 2431.9 0.6 0.4 2 0.3 434 384 58 7 68 0.15 This work
PH05 2456.3 1.8 1.2 9 0.5 431 479 28 17 66 0.12 This work
PH06 2452.2 1.8 0.8 8 0.4 431 430 25 17 44 0.09 This work
PH07 2442.5 4.8 1.5 29 0.5 431 613 11 55 32 0.05 This work
PH08 2413.9 3.1 1.0 17 0.4 431 564 14 40 32 0.05 This work
PH09 2428.2 5.4 1.8 41 0.5 436 759 8 91 33 0.04 This work
PH11 2383.2 1.3 1.2 5 0.4 433 404 32 13 94 0.19 This work
PH12 2410.8 1.1 0.4 3 0.4 431 296 34 9 37 0.11 This work
PH13 2396.1 1.3 2.3 6 0.4 432 419 31 13 177 0.30 This work
12 2387.8 5.4 1.3 35 0.5 427 645 9 76 24 0.04 Masterson, 2001
13 2408.9 1.7 2.8 9 0.4 420 540 20 26 165 0.24 Masterson, 2001
14 2417.7 7.0 3.3 53 0.3 428 754 4 196 47 0.06 Masterson, 2001
15 2433.9 5.9 1.6 39 0.4 427 663 7 93 27 0.04 Masterson, 2001
16 2381.5 2.18 2.2 9 0.5 445 407 25 16 103 0.20 Robison et al., 1996
17 2383.2 3.56 2.2 12 0.7 438 345 19 18 62 0.15 Robison et al., 1996
18 2385.4 1.53 1.2 2 0.6 438 151 36 4 78 0.34 Robison et al., 1996
19 2387.7 2.34 1.5 11 0.6 438 476 27 18 66 0.12 Robison et al., 1996
20 2389.6 2.46 2.0 9 0.5 437 366 22 17 81 0.18 Robison et al., 1996
21 2391.9 1.69 1.7 5 0.6 436 294 37 8 99 0.25 Robison et al., 1996
22 2392.6 1.91 2.2 5 0.6 440 287 30 9 116 0.29 Robison et al., 1996
23 2394.3 1.58 1.5 2 0.8 435 145 48 3 93 0.39 Robison et al., 1996
24 2395.1 2.77 3.3 7 0.7 446 245 25 10 118 0.32 Robison et al., 1996
25 2397.2 1.39 0.9 2 0.7 447 155 48 3 61 0.28 Robison et al., 1996
26 2398.9 1.36 2.0 4 0.6 446 262 43 6 147 0.36 Robison et al., 1996
27 2400.7 4.19 2.4 17 0.7 434 413 16 25 57 0.12 Robison et al., 1996
28 2402.2 1.26 0.3 2 0.3 459 132 21 6 26 0.17 Robison et al., 1996
29 2406.0 1.58 0.2 1 0.7 - 85 41 2 15 0.15 Robison et al., 1996
30 2407.1 1.61 0.3 2 0.8 448 128 51 3 17 0.12 Robison et al., 1996
31 2408.5 1.61 0.5 2 1.0 453 131 61 2 34 0.20 Robison et al., 1996
32 2411.9 6.5 3.1 39 1.5 439 599 23 26 48 0.07 Robison et al., 1996
33 2413.5 5.77 2.4 49 1.3 447 840 22 39 41 0.05 Robison et al., 1996
34 2415.4 7.43 3.5 59 0.5 438 798 7 110 47 0.06 Robison et al., 1996
159
35 2417.2 1.41 4.9 14 0.4 434 965 26 37 350 0.27 Robison et al., 1996
36 2417.6 4.25 1.9 32 0.6 434 764 14 55 45 0.06 Robison et al., 1996
37 2417.9 6.63 3.0 59 0.3 439 884 4 217 45 0.05 Robison et al., 1996
38 2420.5 8.94 3.9 75 0.6 438 841 6 134 44 0.05 Robison et al., 1996
39 2422.1 8.97 3.3 74 0.4 441 820 4 199 36 0.04 Robison et al., 1996
40 2422.2 4.25 5.0 37 0.6 434 865 13 67 118 0.12 Robison et al., 1996
41 2423.2 2.77 2.3 16 0.5 436 580 19 30 82 0.12 Robison et al., 1996
42 2424.1 1.25 0.5 2 0.4 438 196 32 6 38 0.16 Robison et al., 1996
43 2425.5 7.44 1.6 50 0.4 441 670 6 119 22 0.03 Robison et al., 1996
44 2428.2 6.21 1.3 36 0.5 443 579 8 71 20 0.03 Robison et al., 1996
45 2430.0 5.58 1.3 43 0.6 442 771 11 68 23 0.03 Robison et al., 1996
46 2430.7 1.43 0.3 3 0.4 439 229 29 8 20 0.08 Robison et al., 1996
47 2430.8 2.08 0.4 11 0.4 440 508 18 29 19 0.04 Robison et al., 1996
48 2431.2 7.44 1.5 55 0.6 440 744 8 89 21 0.03 Robison et al., 1996
49 2433.6 1.87 0.4 10 0.7 431 523 39 13 21 0.04 Robison et al., 1996
50 2436.1 3.07 0.6 18 0.6 438 590 19 32 19 0.03 Robison et al., 1996
51 2437.0 3.16 0.7 17 0.8 432 532 25 21 23 0.04 Robison et al., 1996
52 2438.8 6.48 1.8 39 1.2 433 595 18 33 27 0.04 Robison et al., 1996
53 2440.3 5.03 1.3 27 0.9 436 531 17 30 26 0.05 Robison et al., 1996
54 2442.1 6.84 1.9 45 1.0 439 662 15 44 27 0.04 Robison et al., 1996
55 2442.6 5.28 1.8 35 1.1 442 657 22 30 34 0.05 Robison et al., 1996
56 2444.7 1.05 0.3 2 1.1 431 166 102 2 32 0.16 Robison et al., 1996
57 2445.5 2.85 0.5 1 1.0 - 29 34 1 18 0.39 Robison et al., 1996
58 2446.6 3.06 1.4 21 0.2 438 689 6 111 46 0.06 Robison et al., 1996
59 2447.4 0.5 0.2 1 0.2 - 154 46 3 42 0.21 Robison et al., 1996
60 2449.1 1.62 2.3 6 0.4 432 382 26 14 144 0.27 Robison et al., 1996
61 2449.9 3.42 1.9 26 0.6 435 765 17 45 56 0.07 Robison et al., 1996
62 2450.5 0.99 0.6 4 0.6 435 377 59 6 65 0.15 Robison et al., 1996
63 2450.6 2.66 1.3 13 0.5 438 485 19 25 50 0.09 Robison et al., 1996
64 2453.5 2.88 1.5 18 0.6 435 636 20 31 53 0.08 Robison et al., 1996
65 2455.1 3.93 2.0 24 0.5 444 606 13 47 50 0.08 Robison et al., 1996
66 2457.0 8.57 3.5 61 0.6 451 716 7 97 41 0.05 Robison et al., 1996
67 2457.8 3.26 1.6 18 0.3 444 566 8 71 49 0.08 Robison et al., 1996
68 2458.7 10.04 2.0 29 0.4 445 287 4 69 20 0.06 Robison et al., 1996
69 2459.7 9.07 3.9 63 0.6 442 690 7 101 42 0.06 Robison et al., 1996
70 2461.2 6.78 4.7 48 0.4 444 712 6 110 69 0.09 Robison et al., 1996
71 2462.2 10.2 4.9 67 0.3 442 661 3 198 48 0.07 Robison et al., 1996
72 2462.5 2.6 2.8 13 0.4 442 517 15 34 106 0.17 Robison et al., 1996
160
Appendix A-2: Biomarker analysis results.
Biomarker Ratio PH01 PH02 PH03 PH05 PH06 PH07 PH08 PH09 PH11 PH12 PH13
Steranes and Diasteranes (m/z 217, 218)
%C27 αββ S (218) 0.32 0.30 0.32 0.33 0.34 0.29 0.29 0.37 0.34 0.33 0.31
%C28 αββ S (218) 0.27 0.25 0.27 0.28 0.28 0.24 0.29 0.27 0.27 0.26 0.28
%C29 αββ S (218) 0.41 0.45 0.41 0.39 0.37 0.47 0.41 0.36 0.39 0.41 0.41
%C27 ααα R (217) 0.33 0.32 0.34 0.35 0.35 0.32 0.30 0.39 0.37 0.34 0.36
%C28 ααα R (217) 0.28 0.27 0.27 0.28 0.28 0.26 0.30 0.26 0.26 0.25 0.26
%C29 ααα R (217) 0.40 0.41 0.39 0.37 0.36 0.42 0.40 0.35 0.36 0.41 0.38
S/(S+R) (C29 ααα) (217) 0.47 0.52 0.52 0.45 0.51 0.52 0.51 0.52 0.46 0.43 0.47
ββS/(ββS+ααR) (C29) (217) 0.36 0.56 0.56 0.36 0.42 0.56 0.35 0.54 0.53 0.29 0.51
(C21+C22)/(C21+C22+C27+
C28+C29) ααα (20R) (217)
0.10 0.37 0.44 0.28 0.28 0.35 0.10 0.66 0.63 0.15 0.54
C27/C29 (αββ S) (218) 0.77 0.67 0.79 0.86 0.91 0.61 0.72 1.02 0.89 0.81 0.76
C28/C29 (αββ S) (218) 0.65 0.56 0.65 0.73 0.76 0.51 0.72 0.73 0.70 0.64 0.68
Diaster/(Dia+ster)(C27) (217) 0.29 0.40 0.30 0.29 0.32 0.42 0.24 0.23 0.29 0.23 0.29
Terpanes (m/z 191)
Gammacerane/Hopane 0.19 0.12 0.12 0.13 0.10 0.12 0.07 0.07 0.11 0.05 0.12
C29/C30 Hopane 0.56 0.48 0.72 0.84 0.68 0.40 0.61 0.75 1.02 0.87 1.04
Bisnorhopane/Hopane 0.03 0.04 0.04 0.05 0.03 0.03 0.02 0.03 0.07 0.03 0.07
Diahopane/(Diahopane+
Hopane)
0.03 0.04 0.03 0.04 0.03 0.05 0.03 0.03 0.03 0.05 0.03
Moretane/Hopane 0.13 0.07 0.07 0.11 0.10 0.07 0.12 0.07 0.08 0.20 0.08
25-nor-hopane/hopane 0.02 0.01 0.01 0.02 0.01 0.01 0.00 0.01 0.03 0.00 0.03
Ts/(Ts+Tm) trisnorhopanes 0.37 0.30 0.31 0.32 0.32 0.30 0.35 0.32 0.29 0.35 0.29
C29Ts/(C29Ts+C29Tm
Hopanes)
0.25 0.27 0.20 0.17 0.20 0.32 0.21 0.22 0.13 0.27 0.13
H32 S/(R+S) Homohopanes 0.60 0.61 0.61 0.60 0.61 0.61 0.60 0.61 0.60 0.59 0.60
H35/(H34+H35) Homohopanes 0.44 0.48 0.48 0.45 0.38 0.47 0.33 0.30 0.48 0.33 0.48
C24 Tetracyclic/Hopane 0.04 0.09 0.12 0.15 0.09 0.07 0.03 0.18 0.21 0.09 0.18
C24 Tetracyclic/C26
Tricyclics
0.17 0.30 0.41 0.35 0.39 0.25 0.14 0.76 0.63 0.38 0.58
C23/C24 Tricyclic terpanes 2.96 1.06 1.27 2.54 2.34 0.89 1.75 1.58 2.11 2.60 2.00
C19/(C19+C23) Tricyclic
terpanes
0.03 0.06 0.05 0.05 0.06 0.06 0.02 0.09 0.08 0.10 0.05
C26/C25 Tricyclic terpanes 0.64 0.49 0.60 0.74 0.64 0.43 0.70 0.57 0.71 0.77 0.72
(C28+C29 Tricyclics)/Ts
[ETR]
5.01 5.80 4.11 4.19 2.98 5.36 3.84 1.60 3.42 1.86 3.67
Homohopane index (HHI) 0.08 0.07 0.07 0.07 0.04 0.06 0.03 0.02 0.07 0.04 0.07
(C28+C29
Tricyclics)/Ts+C28+C29 Tric)
0.83 0.85 0.80 0.81 0.75 0.84 0.79 0.61 0.77 0.65 0.79
C26 tricyclic/Ts 1.41 1.57 1.38 1.70 1.17 1.41 1.53 0.87 1.44 0.86 1.44
C31R/C30 hopane 0.27 0.38 0.40 0.33 0.30 0.38 0.42 0.31 0.39 0.43 0.40
C22/C21 tricyclic terpane 0.31 0.46 0.61 0.56 0.46 0.39 0.31 0.51 0.86 0.37 0.95
C24/C23 tricyclic terpane 0.35 0.98 0.82 0.41 0.45 1.18 0.60 0.66 0.50 0.40 0.52
C31 22S+R ppm 633.7 404.2 347.4 171.7 337.8 482.5 1176 160.9 290.9 312.3 404.5
C32 22S+R ppm 396.1 273.8 223.9 101.7 185.9 324.8 673.8 79.73 170.3 174.3 250.7
C33 22S+R ppm 565.6 237.6 185.7 101.3 174.2 273.2 505.1 49.40 142.3 152.8 210.3
C34 22S+R ppm 347.2 153.1 131.2 75.81 102.3 168.8 358.3 22.97 100.8 108.7 158.2
C35 22S+R ppm 409.7 211.3 176.2 93.13 93.97 218.3 268.3 14.62 138.5 79.74 218.9
Total C31-C35 ppm 2352 1279 1064. 543.7 893.8 1467 2982 327.6 842.8 827.9 1242
C31% 26.94 31.58 32.64 31.59 37.80 32.88 39.45 49.11 34.51 37.73 32.55
C32% 16.84 21.39 21.03 18.71 20.75 22.13 22.59 24.34 20.21 21.06 20.17
C33% 24.05 18.56 17.44 18.63 19.49 18.62 16.94 15.08 16.89 18.46 16.93
C34% 14.76 11.96 12.33 13.94 11.44 11.50 12.01 7.01 11.96 13.13 12.73
C35% 17.42 16.51 16.55 17.13 10.51 14.87 9.00 4.46 16.43 9.63 17.62
Total C31-C35 % 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0
Ts/Tm 0.62 0.45 0.46 0.49 0.49 0.45 0.56 0.49 0.43 0.56 0.43
161
Gammacerane/C30H 0.10 0.06 0.06 0.07 0.05 0.06 0.04 0.03 0.06 0.03 0.06
Gammacerane/C31 22R 0.36 0.17 0.15 0.20 0.16 0.16 0.09 0.11 0.15 0.06 0.15
C35/C34 (22S) 1.24 1.52 1.44 1.30 1.00 1.42 0.75 0.69 1.47 0.78 1.49
C29/C30 0.40 0.35 0.51 0.60 0.49 0.28 0.44 0.54 0.73 0.62 0.74
C24 Tetracyclic/C26
Tricyclics
0.27 0.49 0.67 0.58 0.63 0.41 0.22 1.23 1.02 0.62 0.94
C30*/C29Ts 0.15 0.23 0.18 0.23 0.15 0.26 0.19 0.12 0.21 0.16 0.21
C20/C19 7.19 6.53 6.87 6.90 5.79 6.82 10.75 5.91 5.07 4.18 6.38
GCMS/MS
Terrestrial Tricyclic Diterpanes
Rim /
(Rim+Pim+Ros+Isopim)
0.29 0.26 0.27 0.26 0.32 0.22 0.24 0.23 0.21 0.23 0.20
Pim /
(Rim+Pim+Ros+Isopim)
0.18 0.22 0.19 0.19 0.21 0.26 0.24 0.20 0.20 0.19 0.25
Ros /
(Rim+Pim+Ros+Isopim)
0.24 0.21 0.26 0.26 0.23 0.17 0.21 0.26 0.22 0.23 0.26
Isopim /
(Rim+Pim+Ros+Isopim)
0.30 0.31 0.27 0.29 0.24 0.35 0.31 0.32 0.37 0.35 0.29
Hopane Ratios
Ts/Tm 0.44 0.36 0.37 0.37 0.38 0.36 0.41 0.38 0.34 0.41 0.34
17β/17α-22,29,30-TNH 0.05 0.04 0.04 0.05 0.05 0.04 0.05 0.04 0.05 0.05 0.05
25-norhop/Hop 0.00 0.01 0.02 0.02 0.01 0.01 0.00 0.01 0.03 0.01 0.03
C29Ts/29 Hop 0.25 0.28 0.21 0.19 0.22 0.34 0.24 0.24 0.14 0.23 0.14
C29/C30 Hop 0.28 0.26 0.34 0.37 0.33 0.22 0.30 0.36 0.43 0.39 0.42
Diahopane Index 0.03 0.05 0.04 0.05 0.03 0.05 0.03 0.03 0.05 0.05 0.04
Methylsterane Ratios
C30-4α-methylstigmastane/
stigmastane
0.01 0.01 0.01 0.01 0.01 0.02 0.03 0.01 0.01 0.02 0.01
C30-3β methylstigmastane/
stigmastane
0.01 0.05 0.05 0.01 0.02 0.05 0.05 0.05 0.03 0.03 0.03
C30-4α/(4α + 3β)--
methylstigmastane
0.40 0.17 0.19 0.35 0.31 0.24 0.39 0.16 0.25 0.43 0.32
Dinosterane Ratio 0.28 0.24 0.22 0.26 0.32 0.23 0.49 0.27 0.35 0.49 0.34
Miscellaneous Ratios
Gammacerane Index 0.07 0.03 0.04 0.05 0.04 0.02 0.01 0.03 0.05 0.01 0.05
Tetracyclic Polyprenoid
Ratio [TPP]
0.06 0.04 0.03 0.03 0.04 0.04 0.08 0.02 0.03 0.03 0.04
C24/C23 tricyclic terpane 0.36 1.00 0.84 0.43 0.45 1.24 0.61 0.68 0.50 0.40 0.54
C29Ts/ C30 Dia 3.78 2.73 3.55 2.54 3.86 2.47 3.73 5.33 2.49 3.93 2.79
Sterane Ratios
Total C27/Total
(C27+C28+C29)
0.21 0.20 0.22 0.23 0.23 0.20 0.19 0.26 0.24 0.22 0.23
Total C28/Total
(C27+C28+C29)
0.32 0.29 0.30 0.33 0.34 0.28 0.33 0.34 0.31 0.29 0.30
Total C29/Total
(C27+C28+C29)
0.47 0.51 0.48 0.45 0.43 0.52 0.48 0.41 0.46 0.48 0.48
Total C30/Total
(C27+C28+C29+C30)
0.08 0.06 0.06 0.07 0.06 0.06 0.07 0.04 0.07 0.05 0.06
C27 ααα 20S/(20S+20R) 0.47 0.48 0.48 0.44 0.47 0.48 0.46 0.48 0.43 0.46 0.44
C27 αββ/(αββ+ααα) 0.40 0.65 0.66 0.38 0.48 0.65 0.40 0.65 0.60 0.29 0.57
C28 ααα 20S/(20S+20R) 0.48 0.54 0.54 0.48 0.55 0.55 0.50 0.55 0.50 0.47 0.50
C28 αββ/(αββ+ααα) 0.36 0.62 0.62 0.36 0.42 0.61 0.37 0.60 0.58 0.29 0.57
C29 ααα 20S/(20S+20R) 0.52 0.60 0.59 0.48 0.56 0.59 0.55 0.59 0.54 0.48 0.51
C29 αββ/(αββ+ααα) 0.34 0.59 0.60 0.32 0.38 0.60 0.34 0.59 0.53 0.23 0.52
C30 ααα 20S/(20S+20R) 0.31 0.40 0.41 0.29 0.35 0.45 0.35 0.39 0.31 0.29 0.33
C30 αββ/(αββ+ααα) 0.43 0.72 0.67 0.38 0.47 0.71 0.43 0.65 0.66 0.31 0.63
aββ C27(20S+20R) / Total
αββ(20S+20R)(C27+C28+C29)
0.24 0.22 0.23 0.24 0.27 0.21 0.21 0.27 0.25 0.25 0.24
αββ C28(20S+20R) / Total
αββ(20S+20R)(C27+C28+C29)
0.32 0.29 0.30 0.34 0.35 0.28 0.34 0.33 0.32 0.33 0.31
162
αββ C29(20S+20R) / Total
αββ(20S+20R)(C27+C28+C29)
0.44 0.49 0.47 0.41 0.39 0.51 0.45 0.40 0.43 0.42 0.45
ααα C27(20R) / Total
ααα(20R)(C27+C28+C29)
0.21 0.22 0.22 0.23 0.24 0.21 0.20 0.27 0.25 0.22 0.24
ααα C28(20R) / Total
ααα(20R)(C27+C28+C29)
0.33 0.29 0.31 0.32 0.33 0.29 0.34 0.34 0.30 0.28 0.28
ααα C29(20R) / Total
ααα(20R)(C27+C28+C29)
0.46 0.49 0.46 0.46 0.43 0.50 0.47 0.39 0.45 0.50 0.48
Total Regular Steranes 6440 1623 1162 1470 1899 1534 5107 413 621 2125 945
Total Regular Steranes +
Diasteranes
9872 3149 1737 2256 3148 3115 7119 555 954 2878 1429
Diasterane Ratios
24-nordiacholestane Ratio
[24-NDR]
0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.14 0.14 0.14
C27/(C27+C28+C29) βα-
diasteranes
0.31 0.28 0.32 0.32 0.34 0.27 0.31 0.37 0.32 0.34 0.30
C28/(C27+C28+C29) βα-
diasteranes
0.29 0.26 0.28 0.29 0.29 0.25 0.30 0.30 0.28 0.26 0.28
C29/(C27+C28+C29) βα-
diasteranes
0.40 0.46 0.40 0.39 0.37 0.48 0.39 0.34 0.41 0.40 0.42
C30/(C27+C28+C29+C30) βα-
diasteranes
0.06 0.04 0.04 0.05 0.05 0.04 0.05 0.03 0.04 0.04 0.05
C27 diasteranes/ (reg+dias) 0.44 0.56 0.42 0.43 0.49 0.59 0.39 0.33 0.42 0.35 0.41
C28 diasteranes/ (reg+dias) 0.33 0.46 0.31 0.32 0.36 0.47 0.26 0.23 0.32 0.24 0.32
C29 diasteranes/ (reg+dias) 0.31 0.46 0.29 0.32 0.36 0.49 0.24 0.22 0.32 0.23 0.31
C30 diasteranes/(reg+dias) 0.29 0.37 0.26 0.28 0.35 0.42 0.22 0.22 0.26 0.21 0.26
Total C27-C29
diasteranes/(reg+dias)
0.35 0.48 0.33 0.35 0.40 0.51 0.28 0.26 0.35 0.26 0.34
Total Diasteranes 3432 1526 575 786 1249 1581 2012 142 332 754 484
Monoaromatic Steroids
%C27 (253) 0.26 0.24 0.28 0.31 0.28 0.21 0.23 0.31 0.39 0.27 0.40
%C28 (253) 0.28 0.28 0.31 0.26 0.30 0.28 0.28 0.31 0.26 0.26 0.25
%C29 (253) 0.46 0.48 0.40 0.43 0.41 0.50 0.49 0.38 0.35 0.47 0.36
C21/(C21 + C29) 0.06 0.09 0.13 0.20 0.15 0.06 0.08 0.22 0.32 0.16 0.29
(C21+C22)/(C21+C22+C27+C28
+C29)
0.06 0.09 0.13 0.18 0.14 0.07 0.09 0.21 0.25 0.16 0.22
Desmethyl Triaromatic Steroids
C28/(C26+C27+C28) 0.46 0.47 0.42 0.41 0.41 0.49 0.49 0.38 0.35 0.45 0.36
C26S/(C26S + C28S) 0.33 0.29 0.34 0.38 0.38 0.27 0.31 0.39 0.48 0.36 0.47
C27R/(C27R + C28R) 0.40 0.41 0.46 0.44 0.45 0.39 0.37 0.49 0.47 0.40 0.46
DMD3/C28S 0.02 0.05 0.05 0.03 0.04 0.05 0.07 0.05 0.03 0.06 0.03
DMD6/C28R 0.02 0.05 0.05 0.03 0.04 0.05 0.07 0.05 0.03 0.08 0.03
Methyl Triaromatic Steroids
3-/(3- + 4-methylstigmastane
20R)
0.49 0.51 0.60 0.49 0.51 0.48 0.39 0.65 0.55 0.45 0.56
(D3 + D4 + D5 + D6)/(D3-6
+ 4-methylstigmastane 20R)
0.72 0.77 0.79 0.76 0.79 0.78 0.82 0.82 0.80 0.81 0.79
(D3 + D4 + D5 + D6)/(D3-6
+ 3-methylstigmastane 20R)
0.73 0.76 0.71 0.76 0.78 0.79 0.88 0.71 0.76 0.84 0.74
DMD3/C28 20R 0.03 0.05 0.06 0.04 0.05 0.06 0.07 0.06 0.04 0.07 0.04
163
Appendix A-3: XRF analysis results for Phoenix-1 Shublik core.
Depth
(m)
Si
(wt%)
Ca
(wt%)
P
(wt%)
Al
(wt%)
Fe
(wt%)
S
(wt%)
Mo
(ppm)
V
(ppm)
Ni
(ppm)
2376.7 29.4 2.8 0.08 1.9 1.9 2.4 3 241 15
2377.9 24.6 5.9 0.14 1.1 1.5 2.3 4 184 26
2378.2 22.1 9.2 0.07 1.7 1.8 0.6 0 200 27
2378.5 23.0 6.9 0.05 1.4 2.2 0.5 4 267 13
2378.8 18.5 9.0 0.05 1.1 1.4 0.5 1 206 7
2379.1 18.5 7.3 0.06 2.4 3.6 0.8 2 247 44
2379.5 7.4 26.9 0.01 0.3 1.0 0.3 2 115 8
2379.7 16.2 14.8 0.03 1.1 1.6 0.7 1 110 10
2380.0 13.6 18.2 0.08 0.9 1.6 0.5 1 121 15
2380.3 16.4 12.4 0.07 1.8 2.1 0.8 0 92 17
2380.5 15.8 7.5 0.04 1.6 2.1 0.8 3 116 13
2380.9 14.1 18.3 0.06 0.8 1.3 0.5 0 80 10
2381.3 10.1 21.5 0.05 0.7 1.6 0.9 0 89 12
2381.6 15.9 11.7 0.13 2.5 2.1 1.8 7 0 35
2381.9 18.7 11.4 0.09 1.6 1.9 0.7 0 181 6
2382.1 5.3 29.1 0.00 0.5 0.8 0.3 0 59 17
2382.5 7.8 24.1 0.02 0.5 1.0 0.4 0 100 12
2382.8 19.1 12.5 0.06 1.6 1.0 0.6 0 160 13
2383.1 14.3 18.7 0.03 1.2 1.1 0.6 0 111 19
2383.2 10.3 15.7 0.01 1.5 1.6 0.7 2 51 26
2383.4 7.3 26.5 0.02 1.2 1.2 0.5 0 64 18
2383.7 8.8 16.0 0.24 1.4 9.0 6.8 3 136 25
2384.0 7.5 25.0 0.00 0.7 0.9 0.4 0 80 14
2384.3 10.8 20.3 0.08 1.2 1.0 0.7 0 90 17
2384.6 11.0 22.7 0.04 0.4 0.9 0.4 0 83 10
2384.9 8.7 26.8 0.04 0.6 1.0 0.4 0 94 10
2385.2 10.8 23.8 0.05 0.6 0.9 0.4 2 117 13
2385.5 9.0 22.8 0.04 0.8 1.4 0.6 0 68 16
2385.8 12.1 20.8 0.04 0.7 1.1 0.5 6 100 14
2386.1 10.4 22.0 0.04 0.8 1.0 0.6 0 91 19
2386.4 11.2 22.8 0.04 0.6 0.9 0.6 2 90 7
2386.7 11.6 21.2 0.05 0.5 1.0 0.5 0 63 9
2387.0 6.6 28.4 0.00 0.3 0.5 0.4 0 72 3
2387.3 7.7 23.6 0.02 0.3 0.8 0.3 0 82 8
2387.7 19.6 11.0 0.06 0.8 0.9 0.5 0 103 6
2388.0 16.5 9.4 0.04 0.6 0.8 0.4 5 135 16
2388.3 9.7 22.9 0.03 0.7 1.0 0.4 0 89 11
2388.5 11.4 19.6 0.04 0.5 1.0 0.4 0 55 17
2388.9 19.1 5.8 0.04 0.9 0.8 0.4 10 154 16
2389.2 18.3 9.1 0.05 0.5 0.8 0.4 4 130 10
2389.5 22.6 7.5 0.08 1.1 1.2 0.9 6 97 17
2389.8 18.6 13.4 0.05 0.8 1.0 0.5 2 101 14
2390.1 12.0 16.5 0.01 0.3 0.9 0.3 3 90 11
2390.4 12.7 18.4 0.02 0.4 1.0 0.3 0 92 5
2390.7 19.4 13.6 0.06 1.0 1.1 0.4 2 94 13
2391.0 20.9 4.4 0.03 0.9 1.2 0.5 1 157 11
2391.3 25.1 5.8 0.05 1.4 1.5 0.7 1 135 14
2391.6 28.3 3.0 0.07 3.2 1.6 0.9 0 150 20
2391.9 20.3 3.1 0.03 1.4 1.4 0.6 0 122 14
2392.2 16.4 1.6 0.06 5.0 3.3 3.7 12 212 76
164
2393.0 13.3 15.9 0.02 0.6 1.0 0.3 0 83 12
2393.1 26.4 6.4 0.05 1.1 0.9 0.6 2 168 15
2393.4 21.7 9.9 0.06 1.3 1.0 0.7 1 102 15
2393.7 24.7 8.1 0.05 1.1 0.9 1.1 1 154 23
2394.1 17.0 14.5 0.05 1.1 1.1 0.8 7 54 15
2394.4 15.1 18.3 0.04 1.2 1.2 0.6 1 87 18
2394.7 12.1 21.3 0.01 0.4 0.9 0.7 0 103 8
2395.0 22.0 6.2 0.03 1.0 0.8 0.6 5 142 21
2395.3 14.3 13.7 0.03 0.6 0.8 0.5 3 90 13
2395.6 27.7 5.2 0.07 1.6 1.1 1.0 0 143 20
2395.9 25.2 4.6 0.04 1.3 0.8 0.9 2 152 14
2396.1 21.3 6.5 0.02 0.7 0.7 0.4 2 134 10
2396.2 24.5 7.3 0.06 0.9 0.8 0.7 5 144 27
2396.5 24.8 9.1 0.05 0.9 0.8 0.6 1 112 9
2396.8 27.7 5.4 0.04 1.7 1.3 0.7 5 139 14
2397.1 10.5 19.4 0.03 0.6 1.0 0.5 2 70 14
2397.4 16.0 14.2 0.04 1.0 1.4 0.6 0 68 16
2397.7 19.8 9.1 0.03 1.3 1.5 0.9 2 108 21
2398.0 23.8 5.9 0.03 1.6 1.0 0.7 6 133 15
2398.3 27.8 4.3 0.08 2.3 1.8 1.5 5 137 24
2398.6 15.7 11.8 0.04 0.7 1.4 0.7 1 97 21
2398.9 18.1 14.9 0.05 1.2 1.1 0.4 2 87 10
2399.2 12.3 16.6 0.03 0.4 0.9 0.4 1 102 8
2399.5 18.1 10.9 0.02 0.8 0.9 0.6 0 110 13
2399.8 22.1 4.9 0.32 3.2 2.4 3.5 7 154 50
2400.1 6.5 28.0 0.03 0.8 0.8 0.5 0 48 11
2400.5 5.4 29.1 0.05 0.8 0.8 0.6 4 89 5
2400.8 8.1 19.2 0.09 2.4 1.7 3.7 8 125 53
2401.1 16.6 9.5 0.05 2.8 2.1 1.7 1 141 25
2401.4 9.7 11.2 0.07 1.4 2.9 2.8 2 99 25
2401.7 5.2 26.3 0.03 0.6 2.2 0.7 1 88 21
2402.0 22.7 7.4 0.03 2.8 0.9 0.3 0 615 11
2402.3 24.7 3.3 0.02 3.7 0.9 0.7 3 360 12
2402.6 22.1 3.6 0.02 2.9 1.7 1.0 0 224 28
2402.9 20.8 5.9 0.09 4.0 3.4 3.4 4 192 39
2403.2 19.5 11.5 0.04 2.6 2.1 0.8 4 135 40
2403.5 20.1 6.5 0.05 5.1 1.8 1.1 0 192 52
2403.8 16.4 10.4 0.05 3.7 3.3 1.6 5 100 48
2404.1 16.6 11.5 0.05 3.6 2.2 1.7 0 73 30
2404.7 22.0 4.4 0.04 5.7 1.3 1.0 0 203 21
2405.0 20.0 10.6 0.04 2.2 1.5 1.3 1 142 20
2405.3 21.9 5.1 0.02 4.7 1.2 0.7 0 195 34
2405.6 17.7 8.5 0.05 4.3 1.6 2.2 0 148 42
2405.8 15.1 7.4 0.01 3.3 1.4 0.4 2 119 34
2405.9 19.2 6.4 0.05 4.9 2.1 3.2 0 145 41
2406.2 19.6 7.2 0.02 5.4 1.6 0.4 2 102 46
2406.5 15.8 8.3 0.06 5.4 4.6 2.0 0 129 44
2406.6 7.6 24.0 0.02 2.2 0.9 0.8 0 49 13
2406.9 7.4 23.7 0.00 2.3 1.0 0.6 1 34 6
2407.2 15.5 11.4 0.09 3.0 4.4 3.2 1 57 27
2407.5 19.8 5.7 0.07 4.2 3.1 3.4 0 179 42
2407.8 18.5 8.7 0.09 2.6 4.8 2.4 0 210 42
2408.0 16.9 9.6 0.12 2.2 5.4 4.6 1 168 39
165
2408.2 20.3 3.1 0.06 3.4 5.4 2.2 0 305 44
2408.4 25.3 4.5 0.06 2.1 1.6 0.5 0 366 32
2408.7 10.1 20.0 75.77 1.6 0.7 0.0 0 128 29
2409.0 9.2 22.7 106.71 1.5 0.6 0.0 2 103 10
2409.0 17.7 11.9 0.11 3.0 2.3 1.5 79 114 59
2409.3 18.8 9.5 0.13 2.0 3.4 3.7 9 120 27
2409.6 11.3 16.0 0.16 1.5 3.8 3.3 81 92 49
2409.9 22.2 5.1 0.11 4.6 2.0 2.5 16 135 38
2410.2 19.8 2.7 0.06 6.7 2.2 3.3 27 204 89
2410.5 21.8 6.0 0.16 4.0 2.7 2.0 5 86 44
2410.8 10.6 14.6 0.06 0.9 2.6 1.2 56 84 52
2411.1 15.0 9.3 0.28 4.4 3.2 4.2 17 63 48
2411.2 18.0 7.2 0.26 3.9 3.4 2.3 31 61 59
2411.4 17.4 10.9 0.34 3.4 2.5 1.7 10 68 50
2411.5 15.1 13.8 0.28 2.2 2.7 3.0 19 94 35
2411.7 17.3 6.1 0.14 5.1 3.2 3.2 3 95 49
2412.0 17.3 9.2 0.11 4.2 2.5 2.5 7 65 48
2412.3 16.9 8.6 0.47 4.2 1.6 0.9 8 38 75
2412.6 10.6 18.0 0.11 2.2 1.8 1.4 9 38 56
2412.7 15.6 12.8 0.30 3.3 1.8 1.6 19 73 61
2412.9 12.7 14.9 0.45 2.4 2.7 1.7 10 69 50
2413.0 16.2 7.5 0.17 4.9 2.7 2.7 8 53 89
2413.3 11.9 14.8 1.97 2.0 2.0 1.4 2 38 69
2413.6 14.6 7.5 0.28 3.9 2.7 2.2 8 68 65
2413.9 16.9 6.0 0.60 4.5 2.1 1.3 2 85 81
2413.9 14.8 5.8 0.24 3.9 2.3 1.2 1 30 57
2414.1 15.3 9.9 1.66 4.0 2.4 2.8 0 57 73
2414.3 4.7 24.2 40.99 1.6 1.6 0.3 1 83 55
2414.5 12.4 13.7 2.50 2.9 2.9 2.8 4 72 50
2414.8 14.8 13.0 1.67 3.0 1.8 1.2 12 30 64
2415.1 10.3 17.4 10.88 3.0 1.4 0.8 0 57 78
2415.4 15.7 8.0 0.28 4.3 1.7 2.7 28 85 148
2415.7 16.2 9.1 0.37 4.4 2.5 2.7 18 51 119
2416.0 17.4 9.2 0.14 4.1 1.6 1.4 18 30 68
2416.3 13.2 14.8 1.27 3.1 1.6 2.2 4 37 67
2416.6 16.4 8.2 1.45 4.8 1.7 1.5 5 91 123
2416.9 15.7 9.0 0.27 4.2 2.0 2.9 12 57 102
2417.2 5.3 29.3 0.66 0.6 0.7 0.6 0 79 16
2417.2 3.9 27.4 38.75 1.1 1.5 0.2 3 91 36
2417.5 10.1 21.1 1.23 1.6 0.9 0.5 1 79 37
2417.6 13.9 12.1 0.78 3.1 2.8 2.5 27 71 65
2417.8 16.4 9.5 0.20 4.7 1.8 1.6 14 62 88
2418.1 5.7 29.7 0.52 0.8 0.8 0.7 6 87 19
2418.4 6.8 26.0 6.91 1.3 0.7 0.1 6 91 50
2418.5 17.9 6.4 0.87 5.2 1.9 3.4 93 128 95
2418.7 4.2 29.7 0.69 0.7 0.7 0.5 0 68 17
2419.0 18.8 6.0 0.37 5.5 1.7 2.2 25 129 132
2419.3 5.5 23.8 7.83 1.5 2.4 2.0 14 86 54
2419.4 16.1 5.6 0.31 5.0 2.2 6.2 26 208 127
2419.6 13.7 12.3 1.40 3.9 2.4 1.9 5 33 98
2419.7 4.0 31.4 7.14 0.8 0.7 0.3 1 74 38
2419.9 14.7 9.9 5.06 4.6 3.5 3.5 14 106 126
2420.0 3.2 28.7 173.74 1.7 1.1 0.0 0 104 24
166
2420.3 17.0 5.8 0.79 5.1 3.2 3.7 15 177 80
2420.4 15.9 7.0 0.45 4.9 2.6 4.4 40 312 201
2420.5 4.8 26.9 21.70 1.5 1.4 0.5 0 84 45
2420.6 18.3 4.5 0.15 6.0 2.1 3.2 29 264 164
2420.9 11.0 17.9 2.14 2.8 2.0 1.6 8 52 68
2420.9 14.6 10.5 1.02 4.2 2.5 2.9 26 94 153
2421.2 4.1 32.5 0.43 0.8 0.8 0.7 1 67 23
2421.5 16.0 8.7 0.35 5.2 2.4 4.4 13 182 232
2421.8 15.1 8.1 1.97 4.8 2.0 3.3 2 127 180
2421.8 4.2 28.5 24.94 1.0 1.0 0.0 0 81 20
2422.0 14.7 7.8 0.25 4.8 2.6 7.0 13 95 141
2422.1 7.9 23.2 3.48 1.7 1.4 0.8 0 61 41
2422.4 6.1 27.1 0.15 1.2 0.8 0.6 0 63 26
2422.7 2.9 34.0 0.36 0.4 0.6 0.5 0 70 26
2423.0 7.2 26.1 0.49 1.5 1.3 1.1 13 96 63
2423.1 6.7 25.7 1.03 1.7 1.2 0.8 10 72 64
2423.3 2.9 33.0 0.29 0.4 0.4 0.4 0 60 14
2423.6 2.9 33.1 0.15 0.3 0.3 0.3 0 69 15
2423.9 1.6 34.3 0.04 0.0 0.3 0.5 0 70 23
2424.2 2.2 34.2 0.39 0.2 0.3 0.3 0 79 16
2424.5 1.7 34.5 2.96 0.1 0.3 0.0 0 73 17
2424.8 3.0 34.3 8.59 0.6 0.4 0.0 0 95 65
2425.1 15.4 13.4 2.12 2.4 1.2 1.9 22 131 65
2425.2 6.4 27.5 4.29 0.9 0.6 0.3 0 77 17
2425.4 13.7 15.4 2.48 2.3 1.5 1.1 0 83 69
2425.8 5.0 27.3 0.02 0.7 0.6 0.4 4 50 13
2426.0 4.7 28.8 30.29 1.2 1.5 0.5 8 87 50
2426.1 18.3 8.8 0.13 4.2 1.7 2.4 18 81 91
2426.4 3.4 31.3 0.35 0.3 0.4 0.3 3 61 3
2426.7 14.7 10.8 0.49 3.5 1.7 5.3 10 90 76
2427.0 14.7 12.0 0.26 3.1 1.5 3.3 3 78 57
2427.3 8.1 19.4 6.18 1.3 0.8 0.6 10 98 54
2427.6 3.6 29.8 0.72 0.3 0.4 0.2 0 69 15
2427.9 11.8 16.0 0.76 2.4 1.2 1.7 8 59 83
2428.2 15.8 11.7 0.40 3.6 1.5 4.0 6 104 95
2428.3 11.7 11.4 0.50 2.3 1.2 2.1 7 101 106
2428.5 6.2 26.6 3.33 0.8 0.7 0.5 7 71 45
2428.8 4.5 29.1 0.01 0.8 0.6 0.4 2 62 16
2429.1 5.0 25.2 0.10 1.1 0.8 0.7 3 0 25
2429.4 6.7 24.6 0.38 1.1 0.7 1.2 3 95 70
2429.7 11.3 15.2 0.54 2.4 1.2 2.0 6 78 111
2430.0 9.5 18.9 0.33 1.9 1.1 1.2 9 79 101
2430.3 4.6 29.1 0.01 0.9 1.0 0.7 3 56 27
2430.6 4.0 31.3 0.04 0.6 0.7 0.8 7 66 17
2430.9 15.5 12.2 0.54 3.5 1.7 4.0 7 116 98
2431.2 6.2 26.8 0.45 1.2 0.7 1.2 5 75 77
2431.5 3.4 30.1 0.92 0.6 0.6 0.7 5 57 53
2431.8 2.9 32.2 0.03 0.4 0.4 0.4 4 63 12
2431.9 1.8 29.2 0.14 0.0 0.4 0.2 10 71 6
2432.2 4.8 25.4 0.42 0.9 0.8 0.8 5 66 55
2432.5 2.6 27.5 0.07 0.3 0.4 0.5 6 74 61
2432.8 2.5 31.0 1.42 0.3 0.3 0.2 4 72 24
2433.1 2.6 28.0 0.02 0.1 0.5 0.5 11 56 34
167
2433.4 1.5 34.4 0.00 0.0 0.3 0.2 5 60 5
2433.7 15.8 13.0 0.10 2.2 2.0 2.3 49 82 93
2434.0 1.7 41.7 0.00 0.1 0.3 0.3 3 78 7
2434.3 16.7 4.6 0.21 4.9 4.4 8.6 181 387 525
2434.3 11.3 20.9 0.10 0.9 1.0 1.0 8 100 56
2434.6 2.3 33.5 0.00 0.1 0.4 0.3 5 73 10
2434.9 7.3 25.5 0.23 0.5 0.7 0.7 26 76 63
2435.0 3.9 25.9 0.22 0.7 0.8 5.6 40 78 176
2435.2 3.9 28.9 0.24 0.8 0.7 6.0 6 64 83
2435.5 6.2 28.3 0.17 0.5 0.5 0.8 8 70 48
2435.8 1.9 31.2 0.01 0.1 0.3 1.2 6 73 11
2436.1 1.9 32.4 0.00 0.1 0.4 0.4 5 60 0
2436.4 1.7 32.5 0.00 0.0 0.3 0.2 1 59 0
2436.7 10.0 19.1 0.13 2.4 1.8 2.0 18 58 119
2437.0 15.3 12.6 0.15 2.3 2.0 3.8 28 72 80
2437.3 15.4 11.1 0.14 3.7 3.0 4.6 49 114 119
2437.6 5.5 28.3 0.07 1.0 0.9 0.8 14 70 44
2437.9 9.3 20.5 0.16 2.0 1.6 2.7 29 107 117
2438.2 6.7 27.7 0.13 1.0 0.8 1.0 21 85 50
2438.6 11.9 16.3 0.27 2.8 2.4 4.1 123 156 434
2438.9 6.9 27.8 0.09 1.4 1.1 1.2 31 116 87
2439.2 11.6 15.7 0.21 2.5 2.1 4.3 106 125 243
2439.5 13.6 11.6 0.18 3.5 2.5 5.0 104 142 197
2439.8 9.7 22.0 0.17 1.4 1.1 1.4 52 70 131
2440.1 13.9 12.1 0.18 2.7 2.4 4.0 71 114 151
2440.4 14.3 10.9 0.21 3.9 2.8 5.2 64 104 115
2440.7 16.0 9.4 0.17 4.5 3.3 5.3 32 95 83
2441.0 5.7 29.6 0.03 1.2 1.1 0.9 6 60 19
2441.3 14.5 9.7 0.16 4.2 2.9 5.4 75 126 132
2441.6 12.4 10.9 0.29 3.4 3.0 8.0 99 119 358
2441.9 15.0 11.1 0.13 4.0 3.0 3.8 33 67 98
2442.2 11.4 20.2 0.11 1.8 1.6 1.5 18 78 95
2442.5 12.3 7.3 0.04 3.4 3.3 2.0 31 83 108
2442.8 12.7 10.4 0.26 3.3 3.2 8.1 35 94 113
2443.1 14.4 7.6 0.18 4.9 3.7 7.5 35 62 85
2443.4 4.2 31.0 0.02 0.9 1.0 1.3 7 65 17
2443.7 13.6 11.5 0.20 3.5 3.0 6.1 35 64 96
2444.0 16.0 7.8 0.24 4.0 3.0 7.2 38 96 92
2444.3 12.8 8.4 0.30 3.6 3.0 9.9 29 92 75
2444.6 16.0 12.1 0.17 2.8 1.7 2.4 12 59 50
2445.0 4.9 28.8 0.06 0.6 0.5 0.5 9 52 5
2445.3 9.3 22.6 0.03 0.9 0.6 0.4 0 44 10
2445.4 6.4 21.4 0.02 0.4 0.6 0.3 0 60 5
2445.6 6.6 26.9 0.08 0.5 0.5 0.5 0 66 5
2445.9 2.1 31.7 0.00 0.1 0.3 0.3 0 61 3
2446.2 7.6 27.0 0.02 0.3 0.5 0.4 0 46 8
2446.4 14.2 6.2 0.30 2.9 4.1 10.2 6 81 56
2446.8 15.5 5.2 0.27 3.4 4.6 9.5 0 101 75
2447.1 17.5 7.3 2.03 2.3 2.8 5.7 2 107 67
2447.4 18.1 4.3 0.13 5.0 1.8 6.9 0 118 22
2447.7 14.0 15.5 8.91 1.8 1.3 0.2 0 70 26
2448.0 20.8 12.0 2.35 0.9 0.6 0.4 6 171 12
2448.3 18.9 13.7 1.16 1.1 0.9 0.5 5 117 21
168
2448.6 15.7 16.1 0.98 0.6 0.6 0.3 5 130 6
2448.9 13.5 18.9 0.67 0.5 0.4 0.3 4 131 6
2449.2 19.9 10.0 1.84 1.7 0.9 0.5 186 180 53
2449.5 4.6 30.3 0.40 0.4 0.4 0.3 4 78 12
2449.8 18.7 8.2 0.35 2.5 1.4 2.2 32 148 56
2450.1 7.8 25.3 0.85 1.0 0.7 0.4 0 51 19
2450.5 3.8 31.6 0.10 0.3 0.4 0.3 3 57 7
2450.7 3.7 31.2 0.00 0.5 0.5 0.4 5 76 8
2451.0 12.1 9.6 0.11 2.4 1.5 2.7 27 82 54
2451.4 6.9 25.0 0.12 0.6 0.7 0.6 19 76 30
2451.7 2.0 32.3 0.00 0.1 0.4 0.3 7 71 10
2452.0 2.2 31.7 0.00 0.1 0.4 0.4 4 75 12
2452.2 2.9 25.9 0.00 0.2 0.5 0.4 3 57 19
2452.2 7.8 19.8 0.05 0.8 0.9 0.6 10 112 23
2452.3 9.3 17.3 0.10 1.9 1.2 2.2 21 127 50
2452.3 9.8 18.8 0.12 1.8 1.2 1.9 19 127 43
2452.3 6.5 16.4 0.03 0.5 0.8 0.7 29 89 85
2452.4 7.5 23.9 0.69 0.9 0.7 0.6 17 114 66
2452.4 6.1 23.2 0.02 0.3 0.6 0.4 9 88 17
2452.5 6.0 27.4 0.03 0.6 0.7 0.5 16 61 31
2452.5 5.2 30.7 0.08 1.7 0.6 0.7 6 65 13
2452.6 3.2 29.6 0.10 0.2 0.5 0.3 7 67 29
2452.6 2.6 30.6 0.00 0.2 0.4 0.3 3 70 8
2452.7 3.6 28.8 1.14 0.3 0.6 0.3 21 82 28
2452.8 13.7 9.5 0.11 2.7 1.4 1.7 32 246 61
2452.8 10.9 9.4 0.16 2.4 1.5 2.6 58 256 97
2452.9 13.3 13.9 0.35 2.2 1.1 1.7 86 152 148
2452.9 12.8 7.4 0.05 2.9 1.8 2.7 95 395 156
2453.0 5.9 14.1 0.03 0.8 1.0 1.0 45 145 106
2452.7 11.9 13.5 0.11 1.1 0.9 0.8 19 134 27
2453.2 2.9 27.4 0.00 0.3 0.4 0.3 2 49 6
2453.5 12.1 17.5 0.15 1.9 1.2 2.7 28 120 30
2453.8 12.3 18.4 14.88 2.2 0.9 0.2 23 102 34
2454.1 15.8 9.4 0.15 3.0 2.1 5.5 61 80 106
2454.4 12.9 7.4 0.10 2.5 2.3 4.1 39 94 54
2454.7 12.4 13.4 0.09 3.2 2.4 2.7 115 86 154
2455.0 11.1 9.2 0.26 3.6 3.2 10.5 135 187 180
2455.3 13.2 13.6 4.23 1.4 1.0 1.0 15 144 56
2455.6 6.5 25.8 11.26 0.9 0.5 0.0 0 98 23
2455.9 6.1 26.1 0.30 0.8 0.7 0.5 22 97 37
2456.2 12.1 16.2 19.24 1.9 0.8 0.0 1 87 35
2456.3 13.4 12.4 3.90 1.5 1.0 0.1 58 125 113
2456.5 14.2 9.6 0.73 2.5 1.7 4.7 51 218 94
2456.8 10.9 17.2 18.25 1.7 0.9 0.3 6 122 26
2457.1 6.9 23.5 2.55 1.0 0.8 0.9 13 96 41
2457.5 9.9 21.9 7.57 1.4 0.8 0.3 3 105 28
2457.8 8.9 12.3 0.56 2.1 1.9 10.5 36 184 85
2458.1 15.9 7.8 0.18 4.2 2.9 3.9 40 342 141
2458.4 19.7 7.2 0.16 3.5 2.4 2.5 54 188 116
2458.7 18.5 8.4 0.38 3.5 2.1 3.7 23 177 61
2459.0 14.5 7.8 0.25 3.3 2.9 7.5 60 236 178
2459.3 19.5 6.9 0.11 4.8 2.4 2.0 20 161 61
2459.6 14.4 9.2 0.58 3.4 2.2 9.2 33 175 85
169
2459.7 18.7 5.7 0.17 2.6 1.9 1.0 25 221 80
2459.9 17.0 8.2 0.46 2.5 1.7 5.5 19 140 40
2460.2 16.2 9.9 0.37 3.8 2.3 4.5 21 170 71
2460.5 16.5 8.2 0.14 4.6 2.1 2.5 43 239 78
2460.8 14.1 7.9 0.24 3.6 2.3 5.9 49 279 129
2461.1 13.3 9.1 0.32 2.3 1.6 6.3 22 177 70
2461.4 12.3 15.6 0.36 1.6 0.9 4.4 9 89 14
2461.7 6.7 18.4 0.34 1.0 1.0 7.5 7 74 11
2462.6 20.8 6.1 6.27 2.7 1.5 5.0 45 268 46
2462.7 17.0 7.7 9.76 1.5 0.7 4.8 15 192 21
2462.9 19.9 8.0 14.68 1.5 0.9 3.6 21 172 26
2463.2 26.1 4.2 3.43 1.3 0.7 3.6 6 220 19
2463.6 8.4 13.9 52.63 0.7 0.4 0.0 0 143 21
170
APPENDIX B: SUPPLEMENTARY MATERIAL FOR CHAPTER 2
Appendix B-1: Biomarker analysis results.
Biomarker Ratio PH01 PH04 PH07 PH08 PH09 207 208 N1 NS13 SP1a F5a
Steranes and Diasteranes (m/z 217, 218)
%C27 αββS (218) 0.32 0.33 0.29 0.29 0.37 0.32 0.32 0.32 0.29 0.30 0.33
%C28 αββS (218) 0.27 0.28 0.24 0.29 0.27 0.28 0.28 0.28 0.29 0.29 0.28
%C29 αββS (218) 0.41 0.39 0.47 0.41 0.36 0.40 0.40 0.40 0.42 0.41 0.39
%C27 αααR (217) 0.33 0.36 0.32 0.30 0.39 0.34 0.37 0.36 0.35 0.36 0.36
%C28 αααR (217) 0.28 0.27 0.26 0.30 0.26 0.30 0.30 0.29 0.30 0.30 0.28
%C29 αααR (217) 0.40 0.37 0.42 0.40 0.35 0.36 0.33 0.35 0.35 0.34 0.36
S/(S+R) (C29 ααα) (217) 0.47 0.47 0.52 0.51 0.52 0.53 0.55 0.55 0.56 0.56 0.51
ββS/(ββS+ααR) (C29) (217) 0.36 0.44 0.56 0.35 0.54 0.61 0.62 0.62 0.62 0.62 0.56
(C21+C22)/(C21+C22+C27+C28+C29) 0.10 0.42 0.35 0.10 0.66 0.47 0.43 0.52 0.37 0.37 0.50
C27/C29 (αββS) (218) 0.77 0.86 0.61 0.72 1.02 0.79 0.80 0.79 0.71 0.72 0.84
C28/C29 (ααββS) (218) 0.65 0.72 0.51 0.72 0.73 0.69 0.69 0.71 0.69 0.71 0.72
Diaster/(Diaster+ster) (C27) (217) 0.29 0.25 0.42 0.24 0.23 0.40 0.44 0.48 0.52 0.52 0.38
Terpanes (m/z 191)
Gammacerane/Hopane 0.19 0.12 0.12 0.07 0.07 0.09 0.13 0.12 0.17 0.22 0.08
C29/C30 Hopane 0.56 0.97 0.40 0.61 0.75 0.35 0.40 0.50 0.39 0.43 0.69
Bisnorhopane/Hopane 0.03 0.06 0.03 0.02 0.03 0.02 0.03 0.04 0.03 0.04 0.04
Diahopane/(Diahopane+Hopane) 0.03 0.03 0.05 0.03 0.03 0.10 0.14 0.16 0.19 0.18 0.06
Moretane/Hopane 0.13 0.08 0.07 0.12 0.07 0.09 0.11 0.08 0.09 0.10 0.09
25-nor-hopane/hopane 0.02 0.03 0.01 0.00 0.01 0.00 0.00 0.02 0.00 0.00 0.02
Ts/(Ts+Tm) trisnorhopanes 0.37 0.30 0.30 0.35 0.32 0.76 0.76 0.58 0.56 0.55 0.38
C29Ts/(C29Ts+C29Tm Hopanes) 0.25 0.15 0.32 0.21 0.22 0.41 0.45 0.33 0.36 0.33 0.19
H32 S/(R+S) Homohopanes 0.60 0.60 0.61 0.60 0.61 0.60 0.60 0.59 0.60 0.61 0.59
H35/(H34+H35) Homohopanes 0.44 0.48 0.47 0.33 0.30 0.36 0.27 0.41 0.45 0.49 0.41
C24 Tetracyclic/Hopane 0.04 0.19 0.07 0.03 0.18 0.06 0.09 0.15 0.09 0.10 0.11
171
C24 Tetracyclic/C26 Tricyclics 0.17 0.54 0.25 0.14 0.76 0.24 0.19 0.30 0.16 0.14 0.53
C23/C24 Tricyclic terpanes 2.96 2.03 0.89 1.75 1.58 1.39 1.30 1.32 1.30 1.34 1.84
C19/(C19+C23) Tricyclic terpanes 0.03 0.05 0.06 0.02 0.09 0.06 0.07 0.07 0.07 0.06 0.07
C26/C25 Tricyclic terpanes 0.64 0.76 0.43 0.70 0.57 0.85 0.86 0.75 0.72 0.72 0.76
(C28+C29 Tricyclics)/Ts [ETR] 5.01 4.23 5.36 3.84 1.60 1.69 2.86 3.97 7.16 8.87 2.82
Homohopane index (HHI) 0.08 0.08 0.06 0.03 0.02 0.04 0.02 0.06 0.07 0.09 0.06
(C28+C29 Tricyclics)/Ts+C28+C29 Tric) 0.83 0.81 0.84 0.79 0.61 0.63 0.74 0.80 0.88 0.90 0.74
GCMS/MS
%C27 (253) 0.26 0.36 0.21 0.23 0.31 0.23 0.26 0.30 0.28 0.29 0.30
%C28 (253) 0.28 0.25 0.28 0.28 0.31 0.27 0.28 0.28 0.28 0.29 0.30
%C29 (253) 0.46 0.39 0.50 0.49 0.38 0.50 0.47 0.43 0.43 0.42 0.40
C21/(C21 + C29) 0.06 0.19 0.06 0.08 0.22 0.20 0.22 0.38 0.34 0.36 0.27
(C21+C22)/(C21+C22+C27+C28+C29) 0.06 0.16 0.07 0.09 0.21 0.20 0.20 0.33 0.30 0.31 0.21
C28/(C26+C27+C28) 0.46 0.41 0.49 0.49 0.38 0.58 0.59 0.55 0.57 0.57 0.44
C26S/(C26S + C28S) 0.33 0.41 0.27 0.31 0.39 0.18 0.17 0.20 0.18 0.18 0.35
C27R/(C27R + C28R) 0.40 0.43 0.39 0.37 0.49 0.33 0.33 0.38 0.37 0.37 0.43
DMD3/C28S 0.02 0.02 0.05 0.07 0.05 0.05 0.05 0.05 0.04 0.04 0.05
DMD6/C28R 0.02 0.02 0.05 0.07 0.05 0.06 0.07 0.05 0.03 0.03 0.03
3-/(3- + 4-methylstigmastane 20R) 0.49 0.54 0.48 0.39 0.65 0.56 0.53 0.59 0.56 0.57 0.53
(D3 + D4 + D5 + D6)/(D3-6 + 4-
methylstigmastane 20R) 0.72 0.73 0.78 0.82 0.82 0.80 0.81 0.78 0.75 0.72 0.82
(D3 + D4 + D5 + D6)/(D3-6 + 3-
methylstigmastane 20R) 0.73 0.70 0.79 0.88 0.71 0.76 0.79 0.71 0.70 0.67 0.81
Terrestrial Tricyclic Diterpanes
Rim / (Rim+Pim+Ros+Isopim) 0.29 0.22 0.22 0.24 0.23 0.21 0.23 0.24 0.20 0.18 0.23
Pim / (Rim+Pim+Ros+Isopim) 0.18 0.20 0.26 0.24 0.20 0.20 0.25 0.28 0.26 0.30 0.29
Ros / (Rim+Pim+Ros+Isopim) 0.24 0.27 0.17 0.21 0.26 0.26 0.23 0.24 0.27 0.28 0.30
Isopim / (Rim+Pim+Ros+Isopim) 0.30 0.32 0.35 0.31 0.32 0.33 0.30 0.23 0.28 0.24 0.18
Ts/Tm 0.44 0.35 0.36 0.41 0.38 0.80 0.82 0.65 0.65 0.63 0.45
17β/17α-22,29,30-TNH 0.05 0.05 0.04 0.05 0.04 0.05 0.05 0.05 0.05 0.06 0.05
172
Sterane Ratios
Total C27/Total (C27+C28+C29) 0.21 0.23 0.20 0.19 0.26 0.22 0.22 0.22 0.21 0.20 0.22
Total C28/Total (C27+C28+C29) 0.32 0.31 0.28 0.33 0.34 0.32 0.31 0.30 0.29 0.30 0.31
Total C29/Total (C27+C28+C29) 0.47 0.46 0.52 0.48 0.41 0.47 0.47 0.49 0.50 0.50 0.47
Total C30/Total (C27+C28+C29+C30) 0.08 0.07 0.06 0.07 0.04 0.07 0.07 0.06 0.07 0.06 0.07
C27 ααα 20S/(20S+20R) 0.47 0.44 0.48 0.46 0.48 0.48 0.50 0.50 0.49 0.46 0.42
C27 αββ/(αββ+ααα) 0.40 0.47 0.65 0.40 0.65 0.72 0.71 0.70 0.70 0.73 0.66
C28 ααα 20S/(20S+20R) 0.48 0.47 0.55 0.50 0.55 0.52 0.53 0.57 0.54 0.58 0.50
C28 αββ/(αββ+ααα) 0.36 0.48 0.61 0.37 0.60 0.67 0.67 0.68 0.67 0.68 0.62
C29 ααα 20S/(20S+20R) 0.52 0.51 0.59 0.55 0.59 0.61 0.59 0.62 0.63 0.62 0.56
C29 αββ/(αββ+ααα) 0.34 0.42 0.60 0.34 0.59 0.64 0.65 0.64 0.64 0.64 0.61
C30 ααα 20S/(20S+20R) 0.31 0.30 0.45 0.35 0.39 0.38 0.38 0.41 0.42 0.38 0.36
C30 αββ/(αββ+ααα) 0.43 0.53 0.71 0.43 0.65 0.77 0.77 0.74 0.78 0.75 0.69
αββC27(20S+20R) / Total
αββ(20S+20R)(C27+C28+C29) 0.24 0.24 0.21 0.21 0.27 0.23 0.23 0.23 0.22 0.22 0.24
αββC28(20S+20R) / Total
αββ(20S+20R)(C27+C28+C29) 0.32 0.33 0.28 0.34 0.33 0.32 0.31 0.30 0.29 0.30 0.31
αββC29(20S+20R) / Total
αββ(20S+20R)(C27+C28+C29) 0.44 0.42 0.51 0.45 0.40 0.45 0.46 0.47 0.49 0.48 0.46
αααC27(20R) / Total
ααα(20R)(C27+C28+C29) 0.21 0.24 0.21 0.20 0.27 0.21 0.22 0.23 0.22 0.21 0.24
αααC28(20R) / Total
ααα(20R)(C27+C28+C29) 0.33 0.30 0.29 0.34 0.34 0.34 0.32 0.29 0.31 0.30 0.31
αααC29(20R) / Total
ααα(20R)(C27+C28+C29) 0.46 0.46 0.50 0.47 0.39 0.45 0.46 0.48 0.47 0.49 0.44
Total Regular Steranes 6439 1598 1533 5107 413 1586 1630 383 353 512 451
Total Regular Steranes + Diasteranes 9872 2322 3114 7119 555 2990 3362 892 1042 1475 863
Diasterane Ratios
24-nordiacholestane Ratio [24-NDR] 0.08 0.08 0.08 0.08 0.08 0.14 0.14 0.14 0.14 0.14 0.14
C27/(C27+C28+C29) βα-diasteranes 0.31 0.32 0.27 0.31 0.37 0.31 0.32 0.31 0.30 0.29 0.32
173
C28/(C27+C28+C29) βα-diasteranes 0.29 0.29 0.25 0.30 0.30 0.29 0.29 0.28 0.26 0.25 0.29
C29/(C27+C28+C29) βα-diasteranes 0.40 0.40 0.48 0.39 0.34 0.40 0.39 0.42 0.45 0.45 0.39
C30/(C27+C28+C29+C30) βα-diasteranes 0.06 0.05 0.04 0.05 0.03 0.04 0.04 0.04 0.04 0.04 0.05
C27 diasteranes/(regulars+dias) 0.44 0.38 0.59 0.39 0.33 0.56 0.61 0.65 0.74 0.74 0.57
C28 diasteranes/(regulars+dias) 0.33 0.29 0.47 0.26 0.23 0.45 0.50 0.55 0.63 0.62 0.46
C29 diasteranes/(regulars+dias) 0.31 0.28 0.49 0.24 0.22 0.43 0.46 0.53 0.63 0.63 0.43
C30 diasteranes/(regulars+dias) 0.29 0.24 0.42 0.22 0.22 0.36 0.41 0.45 0.52 0.53 0.39
Total C27-C29 diasteranes/(regulars+dias) 0.35 0.31 0.51 0.28 0.26 0.47 0.52 0.57 0.66 0.65 0.48
Total Diasteranes 3432 723 1581 2012 141 1403 1732 508 689 962 412
C30-4α-methylstigmastane/stigmastane 0.01 0.01 0.02 0.03 0.01 0.03 0.02 0.02 0.01 0.02 0.02
C30-3β-methylstigmastane/stigmastane 0.01 0.02 0.05 0.05 0.05 0.06 0.06 0.04 0.04 0.03 0.04
C30-4α/(4α + 3β)--methylstigmastane 0.40 0.25 0.24 0.39 0.16 0.30 0.24 0.28 0.26 0.34 0.29
Dinosterane Ratio 0.28 0.31 0.23 0.49 0.27 0.28 0.28 0.43 0.34 0.21 0.25
Gammacerane Index 0.07 0.06 0.02 0.01 0.03 0.03 0.02 0.03 0.02 0.02 0.03