Master Thesis in Geosciences
The age of the source rock and its source facies for the migrated oil in rock samples from Novaya Zemlya
Ingi Thór Hallgrimson Kúld
The age of the source rock and its source facies for the migrated oil in rock samples from Novaya Zemlya
Ingi Thór Hallgrimson Kúld
Master Thesis in Geosciences Discipline: Petroleum Geology and Geophysics (PEGG) Department of Geosciences Faculty of Mathematics and Natural Sciences
UNIVERSITY OF OSLO June 2009 © Ingi Thór Hallgrimsson Kúld, 2009
Tutor(s): Dr. Dag A. Karlsen This work is published digitally through DUO – Digitale Utgivelser ved UiO http://www.duo.uio.no It is also catalogued in BIBSYS (http://www.bibsys.no/english )
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Acknowledgements
I would like to thank my tutor Dr. Dag A. Karlsen for all his guidance, help, support and useful discussions during the work of this study. I would also like to thank Kristian Backer– Owe and Jan Hendrik van Koeverden at the Department of Geosciences for all their technical help and guidance in the geochemistry laboratory, for all the useful discussions we had concerning the topics of the study and for guidance into the literature.
I would like to thank the Natural History Museum of the University of Oslo and in particular Hans Arne Nakrem for providing the samples from Novaya Zemlya.
Lundin Petroleum AS is acknowledged for the funds which allowed me to perform extensive studies of age specific biomarkers on the entire sample set.
I also would like to thank Baseline Resolution Inc. for the analysis of the samples that made this thesis work a possibility and especially I thank Mr. Stephen R. Palmer for his additional help.
At last, but not least, I would like to thank all my friends and fellow students at the Department of Geosciences and the ones closest to me for all their help and support during my study time at the University of Oslo.
Thank you all...
Oslo, June 2009
Ingi Thór Hallgrimsson Kúld
Abstract
In this work I have in detailed tried to determine the age of the source rock that is responsible for petroleum impregnation in onshore samples from Novaya Zemlya. I have worked with a selected set of 6 samples. Pilot investigations of nearly 90 year old rock samples of Devonian to Carboniferous age, sampled by Professor Olaf Holtedahl in 1921 from the archipelago of Novaya Zemlya, which spans on a regional scale some 500 km, has shown that several rock samples were impregnated with migrated bitumen, i.e. oil of surprisingly uniform maturity and organic facies in particular when bearing in mind the large lateral distances. While these samples were originally sampled for fossils, I found irrefutable proof of hydrocarbon migration episodes. The TOC and HI values of in-situ organic matter of the samples today reflect deep burial and overmature conditions, with values mostly in the range of 1 4.5 % of TOC and HI values in as low as 1–6. I conclude that the source rock potential of these rocks show a paleopotential realized possibly already during the Ural Novaya Zemlya – Permian Orogeny. Yet, extracts in the range of 0.37 2.83 mg/rock show on Iatroscan typically 48 70 % saturated hydrocarbons, 4 14 % aromatic hydrocarbons and 15 47 % polar compounds (resins plus asphaltenes). GC FID data show normal alkanes and “Unresolved Complex Mixture” (UCM) which reflects several migration episodes of oil into the “burned out carbonaceous/silty lithologies” with intermittent periods of biodegradation, and most likely water washing cf. low contents of aromatic hydrocarbons. Inferred source rock facies from GC FID and GC MS data reflect that the source rock is likely to be a marine shale with some influence of land plant derived organic matter, i.e. containing mainly kerogen type II, but with some type III. Land derived organic material is indicated by the occurrences of oleanane and heavy δ13 C stable carbon isotope ratios. The unknown hydrocarbon source rock is therefore suggested to be a distal, predominantly marine shale with organic matter of marine/planktonic origin deposited under anoxic to dysoxic conditions. Maturity inferences made from GC MS data suggest expulsion at maturities corresponding to the early oil window, this is based on terpane maturity parameter vs. the calculated vitrinite reflectivity and sterane maturity parameters. There are also evidences for a late, non biodegraded condensate migration event. The age of the source rock for the migrated petroleum was attempted determined by several age specific biomarkers from the data obtained by the GC MS and GC MS MS analysing methods. The biomarkers used in this study were; oleanane index (OI), C 28 /C 29 ratio, 24 nordiacholestane ratio (NDR), 24 norcholestane ratio (NCR) and
dinosterane ratio. These age specific biomarkers from different biota, angiosperm land plants and marine algae, have been shown to be advantageous in constraining the geologic age of a petroleum source. The biomarker data based on a number of age specific biomarkers, both individually and especially when used together, suggests strongly that a Cretaceous or even younger source rock i.e . Tertiary, must be considered in the eastern Barents Sea and possibly also in the Kara
Seas region. These results are based on the occurrences of oleanane and the high C28 /C 29 , 24 nordiacholestane and 24 norcholestane ratios, all indicating Cretaceous to Tertiary source rock ages. The existence of a source rock of Cretaceous or Tertiary age, as suggested by the biomarker data in this study, may add new potential ideas concerning petroleum systems in the Barents and Kara Seas, ideas which may help in future petroleum exploration in the area.
TABLE OF CONTENTS 1. Introduction ...... 5 1.1 Thesis objectives and background ...... 6
1.2 Petroleum systems and hydrocarbon plays ...... 7
1.3 Source rocks ...... 7
1.4 Reservoir rocks ...... 8
1.5 Biomarkers ...... 9
1.6 Aims and purpose of the study ...... 9
2. Geological framework ...... 10 2.1 The study area ...... 11
2.2 Regional geological settings ...... 11
2.2.1 Geological history of the Barents and Kara Seas ...... 14
2.2.2 Stratigraphic settings...... 16
2.2.3 Lithostratigraphy of Novaya Zemlya ...... 17
2.3 Hydrocarbon plays ...... 18
2.3.1 Source rocks ...... 19
2.3.2 Reservoir rocks, traps and seals ...... 19
3. Sample set ...... 22 3.1 The sample set ...... 23
3.1.1 120.611 Devonian limestone ...... 23
3.1.2 NZS 137 Carboniferous siltstone ...... 23
3.1.3 NZS 185 Carboniferous siltstone ...... 23
3.1.4 NZS 225 Permian shale ...... 24
3.1.5 NZS 255 Silurian shale ...... 24
3.1.6 NZV 232 Devonian shale ...... 24
3.1.7 7120/6 1 Oil from the Snøhvit field ...... 24
3.1.8 7122/7 1 Oil from the Goliat field ...... 24
3.1.9 7124/3 1 Oil from the Hammerfest Basin ...... 24
3.1.10 7124/4 1 Oil from the Hammerfest Basin ...... 24
3.1.11 7128/4 1 DST1 Oil from the Finnmark Platform ...... 25
3.1.12 7128/4 1 DST2 Oil from the Finnmark Platform ...... 25
3.1.13 7228/7 1A Oil from the Nordkapp Basin ...... 25
3.1.14 NSO 1 Oil from the Oseberg field ...... 25
4. Analytical methods ...... 28 4.1 Introduction ...... 29
4.2 Gas Chromatography ...... 29
4.2.1 The carrier gas ...... 30
4.2.2 The injector and column ...... 30
4.2.3 The detector ...... 30
4.3 Preparations of samples ...... 31
4.4 Molecular sieving ...... 32
4.5 Organic fraction separation ...... 33
4.6 Gas Chromatography Flame Ionizing Detector (GC FID) ...... 33
4.7 Gas Chromatography Mass Spectrometry (GC MS) ...... 34
4.8 Gas Chromatography Mass Spectrometry Mass Spectrometry (GC MS MS) ...... 36
5. Interpretation parameters ...... 37 5.1 GC FID data and interpretation ...... 38
5.1.1 Pristane/Phytane ...... 38
5.1.2 Pristane/n C17 and Phytane/n C18 ...... 39 5.2 GC MS data and interpretation ...... 40
5.2.1 Terpanes ...... 41
5.2.2 Steranes ...... 43
5.2.3 Triaromatic steroids ...... 45
5.2.4 Monoaromatic steroids...... 46
5.2.5 Phenanthrene and methylphenanthrene ...... 47
5.2.6 Methyl dibenzothiophene ...... 48
5.3 Age related parameters ...... 49
5.3.1 Oleanane Index (Oleanane / (Oleanane + C 30 αβ hopane)) ...... 49
5.3.2 %C 28 / %C 29 ββs steranes ...... 50
5.3.3 24 norcholestane biomarkers (C 26 steranes) ...... 51 5.3.4 Dinosterane ratio ((∑20R dinosteranes / (∑20R dinosteranes + 20R 3β methyl 24 ethylcholestane)) ...... 54
6. Results ...... 57 6.1 GC MS ...... 58
6.2 GC MS MS ...... 58
6.3 Chromatograms ...... 60
6.3.1 GC FID and GC MS chromatograms ...... 61
6.3.2 GC MS MS chromatograms ...... 67
7 Discussion ...... 73 7.1 Hydrocarbon generation potential ...... 74
7.2 Evidence for migrated hydrocarbons ...... 76
7.3 The organic fractions (saturated, aromatic and polar compounds) ...... 77
7.4 Origin and maturity of the migrated hydrocarbons ...... 79
7.5 Biodegradation ...... 84
7.6 Several generations of petroleum ...... 87
7.7 Age determination ...... 88
8 Conclusions...... 96 References ...... 100 APPENDIX ...... 112 Appendix A GC FID chromatograms ...... 112
Appendix B GC MS chromatograms ...... 127
Appendix C GC MS MS chromatograms ...... 233
Chapter 1. Introduction 5
1. Introduction
This chapter provides a short description to the background of this master thesis, why the topic is of interest and the objective of the thesis. Also I will give some background information on the main topics that will be addressed in this study. In chapter 2, I provide a summary of the geological settings of the study area and the sample set is described in chapter 3. A description of the analytical methods used in this study are presented in chapter 4, the parameters used to interpret the results of the analytical data will be presented in chapter 5 and the results of my work will be given in chapter 6. A general discussion will be presented in chapter 7 and finally, the conclusions of my work will be given in chapter 8. The outline of this chapter is as follows:
1.1 Thesis objectives and background 1.2 Petroleum systems and hydrocarbon plays 1.3 Source rocks 1.4 Reservoir rocks 1.5 Biomarkers 1.6 Aims and purpose of the study
Chapter 1. Introduction 6
1.1 Thesis objectives and background
All the 67 commercially drilled wells in the Barents Sea region contain residual oil saturation, live oil or gas (Ohm et al., 2008). The success rate is exceptional with every 3 rd well being a discovery but, however for several reasons, the prospectiveness of the Barents Sea has got a somewhat a negative ring to it. The petroleum exploration history in the Barents Sea region started in the 1970´s with geophysical investigations and in the early 1980´s, the first offshore well was drilled (Johansen et al., 1993; Doré, 1995). The Barents Sea covers an area of approximately 1.3 million km 2 (Worsley, 2008), roughly twice the size of the Norwegian North Sea (with the Norwegian sector alone ~ 245000 km 2) (Ohm et al., 2008) and the number of wells is to date low. In recent years the exploration in the Barents Sea has been focused in areas such as the Finnmark Platform, the Nordkapp and Hammerfest Basins and the Western Margin in the Norwegian sector where discoveries have been made mainly in the Hammerfest and Nordkapp Basins. Within the Russian sector, oil accumulations have been found offshore from the Timan Pechora Basin and major gas accumulations, the Stokmanovskaya and Ludlovskaya supergiant gas fields with other smaller fields that have been discovered, in the major sedimentary basins west of Novaya Zemlya. A large number of untested structures have been documented with seismic surveys in the disputed “grey” area between Norway and Russia (Doré, 1995) and with new play models and ideas on recognized and potentially new petroleum systems, the success rate of discovering commercial petroleum accumulations will likely increase in the Barents Sea (Ohm et al., 2008) The Barents Sea is an example of an overfilled basin with multiple source rocks intervals where the petroleum systems, or the “petroleum machinery”, along with the filling history of traps in the region is less well understood than in the North Sea and the Norwegian North Sea. Hydrocarbon occurrences and an oil seep have been recorded on onshore Novaya Zemlya and these discoveries can provide important new insight into the hydrocarbon potential of the adjacent offshore areas, the eastern Barents and Kara Seas (Howard et al., 2006; Guo et al., 2007). The area offshore the Novaya Zemlya is of great interest as it is considered among the best possibilities for future finds (e.g. Johansen et al., 1993; Doré, 1995; Scott et al., 2005; Howard et al., 2006) and therefore in depth organic geochemical analysis of any samples from onshore Novaya Zemlya is worth looking into. The samples of this study were collected by Professor Olaf Holtedahl in his journey to Novaya Zemlya in 1921. Petroleum geochemical analysis (GC FID, GC MS and GC MS MS) were performed Chapter 1. Introduction 7 on the sample set in order to determine source rock facies and the age of the source rock for migrated oil in the rock samples obtained by Olaf Holtedahl. By performing petroleum geochemical analysis on in-situ or migrated petroleum one can get a clearer picture of the petroleum systems by looking into the origin and migration of the petroleum.
1.2 Petroleum systems and hydrocarbon plays
A petroleum system is defined by Magoon and Dow (1994) as: “A petroleum system encompasses a pod of active source rock and all related oil and gas and includes all the essential elements and processes needed for oil and gas accumulations to exist. The essential elements are the source rock, reservoir rock, seal rock and overburden rock, and the processes include trap formation and the generation migration accumulation of petroleum. All essential elements must be placed in time and space such that the processes required to form a petroleum accumulation can occur”. A play or a hydrocarbon play is also defined by Magoon and Dow (1994) as: “The play is one or more prospects, and a prospect is a potential trap that must be evaluated to see if it contains commercial quantities of hydrocarbons”. The terminology for the petroleum system and plays, used in this study, will be in coherence with the terms used and described in detail by Magoon & Dow (1994).
1.3 Source rocks
A source rock is all sedimentary rocks that have the potential to, or have been producing petroleum (Tissot & Welte, 1984). An effective source rock is a source rock that is, or has been, producing petroleum and it is the maturity of the source rock that determines whether it has expelled petroleum or not. A source rock normally has a total organic carbon content (TOC) of ~ 0.5% in siliciclastic rocks, e.g. shales, and ~ 0.3% for carbonate rocks (North, 1985; Hunt, 1996). A sedimentary rock is affected by increasing temperature during increasing burial by the sedimentary overburden and this leads to alteration of the organic matter in the rock. The organic matter (OM) in the source rock starts to generate petroleum when it matures and this petroleum may migrate, following a migration path, to a reservoir rock. According to Hunt Chapter 1. Introduction 8
(1996), it is at this generative depth interval that the source rock has reached the “oil window”, which is usually defined at 80°C 140°C. At higher temperatures the source rock mainly generates gas until it reaches so high temperatures, with increasing depth, that it gets depleted with respect to hydrocarbon generation and ultimately the kerogen is converted to graphite. The environment in which the organic matter was deposited in and the type of the organic matter is defining the source rock facies. Source rock facies indicate what type of petroleum the source rock is capable of generating and by doing petrochemical analysis of oils and bitumen extracts using gas chromatography mass spectrometry (GC MS) and gas chromatography flame ionization detector (GC FID) one can discern the maturity and the source rock facies of oils. With this type of data and information, one can reconstruct the type of depositional environment that existed when the organic matter was deposited.
1.4 Reservoir rocks
Any rock that can contain economical quantities of petroleum (oil and/or gas) is a reservoir rock. The ability for a rock to be able to contain petroleum depends on mainly two elements, porosity and permeability, where the porosity in a reservoir rock ranges from 0 30% (Tissot & Welte, 1984). Reservoir rocks, where petroleum accumulations have been found, are mainly siliciclastic, i.e. sandstone reservoirs, or carbonate rocks. Reservoir rocks are fed by petroleum from the source rocks by migration. Therefore geochemical studies of migrated petroleum, found in reservoirs or a migration avenue, can provide information concerning the source rock that fed the reservoir rock and in this sense, a reservoir rock or a part of a migration channel represents a geochemical collection of information that can assist in the search for hydrocarbons.
Chapter 1. Introduction 9
1.5 Biomarkers
The study of biomarkers is one of the possible petroleum geochemical analyses available in evaluating the age and origin of the petroleum. Biomarkers are defined as molecules with a base structure that was inherited from a living organism and deposited in sediments with no or only small changes in their structure (Tissot & Welte, 1984). These organic compounds, or molecular fossils, are found in Holocene to Precambrian sedimentary deposits and can be related to specific chemical compounds produced in the biosphere (Holba et al., 1998b). The chemical structure derived from the biological origin is recognisable as the carbon skeleton of the organism is preserved during burial (Peters et al., 2005a). Less than 1% of the organic material that is deposited in the sediments is classified as biomarkers. With time and temperature increase due to burial, liquefied hydrocarbon compounds are generated from the organic material in the source rock. The generated liquefied hydrocarbons contain biomarker signatures that are typical for the preserved organic material in the source rock (Tissot & Welte, 1984). These biomarker signatures are often called the “fingerprints” of the source rock and it is these fingerprints that are of interest in this study as this may help in understanding the origin of migrated petroleum in the samples from Novaya Zemlya described in ch.3.
1.6 Aims and purpose of the study
In this study I will look into determining the age of the source rock for migrated petroleum in 6 samples from onshore Novaya Zemlya (see chapter 3) based on biomarker data obtained by GC MS and GC MS MS analysing methods (see chapter 4). This study builds on the ongoing PhD work of Jan Hendrik van Koeverden at the Department of Geosciences of the University of Oslo and aims to unravel the age of the source rock that generated this migrated petroleum with detailed analysis of age specific biomarkers from GC MS MS data. The work done on GC FID and GC MS data is performed to get a grasp of the main petroleum geochemical analytical methods used today and to compare my analysis of the data with the work done by van Koeverden et al. (submitted), i.e. to get an understanding of the maturity and source rock facies of the rocks that generated this migrated petroleum. In this study, more emphasize is put on the age determination due to time limits for the master thesis. Chapter 2. Geological framework 10
2. Geological framework
A summary of the geological framework and settings of the study area will be given here in this chapter. The outline of this chapter is as follows:
2.1 The study area 2.2 Regional geological settings 2.2.1 Geological history of the Barents and Kara Seas 2.2.2 Stratigraphic settings 2.2.3 Lithostratigraphy of Novaya Zemlya 2.3 Hydrocarbon plays 2.3.1 Source rocks 2.3.2 Reservoir rocks, traps and seals
Chapter 2. Geological framework 11
2.1 The study area
The study area considered in this thesis is the Novaya Zemlya area and the surrounding offshore areas, the Eastern Barents Sea and the Kara Sea. The Barents Sea Shelf stretches from the Arctic Ocean to the coasts of Norway and Russia and from the Norwegian Greenland Sea to Novaya Zemlya (Worsley, 2008) (figure 1). The Barents Sea is often divided into a western and an eastern part (Johansen et al., 1993) and the eastern part referred to as the Eastern Barents Sea or the Russian Barents Sea whereas the western part is referred to as the Western Barents Sea or the Norwegian Barents Sea. The Eastern Barents Shelf extends from the Baltic Shield to the Franz Josef Land archipelago and is often referred to as the East Barents Megatrough or basin (Baturin et al., 1991). The regional geological settings and the lithostratigraphy of the Eastern Barents Sea, Novaya Zemlya and the Kara Sea are given in detail in: e.g. Ustrickij (1977), Bonderev et al. (1973), Cherkesova (1979), Sobolev et al. (1985), Ziegler (1989), Johansen et al. (1993) and references therein, Doré (1995), Sobolev & Nakrem (1996) and Cherkesova et al. (2000) among others. Therefore, in this chapter I will only give a brief description of the geological settings, the structural geology and stratigraphy, of the Eastern Barents and the Kara Seas and a brief description of the relevant lithostratigraphy zones of Novaya Zemlya. The literature available for the Kara Sea is very limited but I will give an overview of the area from the available literature. I will not describe the Western Barents Sea in this study but for those interested, the regional geological settings and the lithostratigraphy of the Norwegian Barents Sea are given in detail in: e.g. Rønnevik et al. (1982), Gabrielsen et al. (1990), Knutsen & Vorren (1991), Johansen et al. (1993) and references therein and Worsley (2008) among others.
2.2 Regional geological settings
Novaya Zemlya is an archipelago in the Russian Barents Sea that is considered to be a northern extension of the Ural Mountains and a component of the Ural Taimyr orogeny (e.g. Ziegler, 1989; Otto & Bailey, 1995; Johansen et al., 1993, Sobolev & Nakrem, 1996). The Novaya Zemlya archipelago separates the Barents Sea to the west and the Kara Sea to the east of Novaya Zemlya (see figure 2 1). Major hydrocarbon discoveries have been made in the eastern Barents and Kara Seas (see figure 2 2), and therefore the Novaya Zemlya Chapter 2. Geological framework 12 archipelago provides the most proximal exposure to these hydrocarbon discoveries (e.g. Howard et al., 2006). The surrounding provinces are some of the most important and potential hydrocarbon provinces in the Arctic. These provinces are the Barents Sea, the Timan Pechora Basin, West Siberia and the Kara Sea (Johansen et., 1993; Doré, 1995; Scott et al., 2005; Howard et al., 2006).
Figure 2 1. Detailed overview map of Novaya Zemlya (A) and its position in the Arctic Ocean (B). The sample localities – given by Olaf Holtedahl – are indicated with corresponding names. Most samples originate from the western shore of the archipelago and all of the samples used in this study are from the Matotchkin Strait. Modified from van Koeverden et al. (submitted).
Chapter 2. Geological framework 13
Figure 2 2. Map of the Russian Barents and Kara Seas showing the principal oil and gas discoveries and undrilled prospects. From Doré (1995). Chapter 2. Geological framework 14
2.2.1 Geological history of the Barents and Kara Seas
The geological structure of the Barents Sea is made up by a complex mosaic of basins and platforms or highs (see figure 2 3) that where formed and deformed by major continental collisions and continental separation plus several phases of extension. The basement rocks in the Eastern Barents Sea are predominantly Baikalian in the south, Caledonian in the north and northwest and most likely a Precambrian basement is present in the northern platform areas (Johansen et al., 1993). The major deformation events are the formations of the Timanian (Late Precambrian), Caledonian (Late Silurian Early Devonian) and Uralian (Permian Earliest Triassic) Orogeny (Scotese, 1987; Johansen et al., 1993; Cocks & Torsvik, 2005; Gee, 2005; Buiter & Torsvik, 2007). The Timanian deformation phase occurred around 550 Ma when the Baltic Shield and terranes, including Novaya Zemlya and possible Franz Josef Land, collided and coalescence into one mass (Cocks & Torsvik, 2005). During the Ordovician Silurian, rifting occurred associated with the opening of the Uralian Ocean along the eastern margin of Baltica (Otto & Bailey, 1995; O´Leary et al., 2004). The Caledonian Orogeny resulted from the Late Silurian closure of the Iapetus Ocean when the Greenland margin of the Laurentian plate (Greenland, North America) and the western margin of the Baltic plate (Scandinavia, western Russia) collided forming the Laurasian continent (Scotese, 1987; Johansen et al., 1993; Cocks & Torsvik, 2005; Gee, 2005). In Early Middle Devonian times, rifting and extensional tectonic movements occurred in the Barents Sea region, representing the collapse of the Caledonian orogeny. The Carboniferous period was a quiet tectonic period in the Eastern Barents Sea but is the main graben formation period in the western region due to further rifting and collapse after the Caledonian orogeny (Otto & Bailey, 1995; Baturin et al., 1991; Johansen et al., 1993, O’Leary et al., 2004). The continent continent collision between the Laurasian continent and Western Siberia (Kazakhstan) in Permian to earliest Triassic times resulted in the formation the Uralian Orogeny and Novaya Zemlya (Scotese, 1987; Johansen et al., 1993; Brown & Echtler, 2005). This collision was the final element in the fusion of most of the world’s landmasses into a single supercontinent, Pangaea (Scotese, 1987). During the Late Permian and Early Triassic times extension was the main tectonic regime and the Early Triassic was the most active period tectonically in the East Barents Megabasin (Johansen et al., 1993) where extension took place in the East Barents Megabasin as a result of progressive break up of the Pangaea supercontinent (Otto & Bailey, 1995; Baturin et al., 1991; Johansen et al., 1993, O’Leary et al., 2004). Chapter 2. Geological framework 15
Figure 2 3. The main structural elements in the Barents Sea with their corresponding geological age. Modified from Worsley (2008).
In Late Jurassic to Early Cretaceous time the breakup of Pangaea continued mainly in the west Barents Sea and the final event that contributed in the formation of the Barents Sea in the western and northernmost areas is the opening of the Norwegian Greenland Sea and the Arctic Ocean (Johansen et al., 1993). The events described here above created the major rift basins, platforms and structural highs in the Barents Sea region. Chapter 2. Geological framework 16
The Kara Sea area on the eastern side of Novaya Zemlya is the offshore continuation of the Siberian Plate and the region consists of highs and basins, similar to the Barents Sea. Although the Kara Sea area underwent the same geological evolution as the Eastern Barents Megabasin, the origin and the geological history of the region is not completely understood (Howard et al., 2006; Vyssotski et al., 2006; Buiter & Torsvik, 2007).
2.2.2 Stratigraphic settings
The basins in the Eastern Barents Sea are relative deep and are mainly filled with Upper Paleozoic, Mesozoic and Cenozoic sediments (Baturin et al., 1991). The average sediment thickness in the basins is around 13 km (O´Leary et al., 2004; Bungum et al., 2005) with up to 15 20 km thickness in the South and North Barents Basins (Ivanova, 1997; Kirjuhina et al., 2007). In the Kara Sea the maximum thickness of the sedimentary cover is 5 7 km on the highs and 7 14 km in the deep basins (Ivanova & Karoun, 1996; Ivanova, 1998). Marine sedimentation dominated the depositional environment in the East Barents Megabasin during the Paleozoic with exception in the Late Paleozoic (Upper Permian) when deposition of more continental sediments took place locally in the syn and post orogenic collapse basins (Heafford, 1988; Johansen et al., 1993). The Paleozoic marine sediments are mainly composed of carbonates and evaporites in the entire region (Baturin et al., 1991; Johansen et al., 1993; Doré, 1995) with shallow marine shelf carbonate deposition and the formation of carbonate build ups in the Barents side of offshore Novaya Zemlya and more siliceous sedimentation further in the basins during Carboniferous times (Johansen et al., 1993; Guo et al., 2007). On the Kara Sea side of the Novaya Zemlya archipelago the Devonian and Carboniferous strata are made up of deep water slope and basin floor sediments, turbidites, shales, cherts and carbonate mudstones (Guo et al., 2007). In Mesozoic times large amounts of clastic sediments (sandstones and shales) were shed and deposited in the Eastern Barents Sea from the Uralian highlands to the east and from the from the Baltic Shield and other local sources (Baturin et al., 1991; Johansen et al., 1993; Doré, 1995). Marine conditions continued to prevail within the Megabasin throughout the Triassic while continental environments prevailed in the surrounding areas in Middle Triassic (i.e. the Kola Kanin Monocline, the Pechore Block, the near offshore area of Novaya Zemlya and partly the South Barents Basin) where prograding deltaic systems filled in the Megabasin. At the end of the Triassic a regression occurred with consequent erosion in the region. During Jurassic times the East Barents Megabasin continued to subside and continental and shallow marine deposition was Chapter 2. Geological framework 17 the characteristic deposition in the Early and Middle Jurassic. At the end of the Jurassic, deep marine deposition was widespread following a transgression in the Barents Shelf and the sedimentary sources continued to be the Baltic Shield and the Timan and Ural Mountains. The Cretaceous period was characterized by southward sediment progradation due to regional uplift in the northern areas and volcanic activity. The Cretaceous period is characterized by interbedded marine and continental rocks with considerable volumes of continental sandstones and siltstones. Dark grey shales characterize the basin areas while the shallower areas contain siltstones and fine grained sandstones interbedded with brown coal layers. The Cenozoic sedimentation is poorly preserved in the eastern and central areas of the Barents Sea where erosion has removed most of the sedimentary record, only thin deposits of intracratonic mudstone are preserved (Johansen et al., 1993).
2.2.3 Lithostratigraphy of Novaya Zemlya
The lithostratigraphy of Novaya Zemlya is given in detail in: e.g. Ustrickij (1977), Sobolev et al. (1985), Sobolev and Nakrem (1996) and Cherkesova et al. (2000). In van Koeverden et al. (submitted) there is a good summary of the lithostratigraphy of Novaya Zemlya based on the work of the authors mentioned above. I will only provide a very brief description, taken from the work of van Koeverden et al. (submitted), of the relevant formations for this study, the Gribovskaya, Kazarkinskaya and Krasnorechenskaya Formations of the central part of Novaya Zemlya (the Matotchkin Strait). The lithofacies zones of Novaya Zemlya are of Devonian to Late Permian age (see figure 2 4) and are divided into four settings based on their distinct basinal depositional environments: The North, West, South and Central East (van Koeverden et al., submitted). The Gribovskaya Formation is of Lower Devonian age (Lochkovian Pragian) and consists of carbonate beds (limestones) with an upward decreasing terrigenous influx and increasing amount of carbonate beds. The Kazarkinskaya Formation is of Carboniferous age (mid Bashkirian Asselian) and consists of black shales and chert. The Krasnorechenskaya Formation is of Lower Permian age (Kungurian) and consists of siltstones, black and dark grey mudstones and polymict sandstones.
Chapter 2. Geological framework 18
Figure 2 4. Lithostratigraphic scheme for the sampled units of the Novaya Zemlya archipelago that were sampled during the Novaya Zemlya expedition 1921. Units with bold names are represented by samples of van Koeverden et al. (submitted). For this study, samples from the Central part of the archipelago were processed (Gribovskaya, Kazarkinskaya and Krasnorechenskaya Fm). Modified from van Koeverden et al. (submitted).
2.3 Hydrocarbon plays
In the Russian Barents Sea there are defined three hydrocarbon plays within Paleozoic deposits according to Kirjuhina et al. (2007): pre Lower Franklin oil generating, Upper Devonian Lower Permian predominantly oil generating and Upper Permian predominantly gas generating. HC plays have also been proven in Triassic, Lower Middle Jurassic and Upper Jurassic deposits in the Barents Sea basin (Johansen et al., 1993; Doré, 1995; Kirjuhina et al., 2007) (figure 4) and in the Kara Sea four HC systems have been defined. The four HC systems in the Kara Sea are in Lower Middle Jurassic, Upper Jurassic, Lower Cretaceous and Upper Cretaceous deposits (Kirjuhina et al., 2007). The latest results obtained by van Koeverden et al. (submitted) suggest that there is a new and a previously undescribed petroleum system in the greater Barents Sea and the Kara Sea with a source rock of Cretaceous to Tertiary age. Chapter 2. Geological framework 19
2.3.1 Source rocks
There are multiple proven source rock intervals in the Barents Sea from the Upper Devonian to Cretaceous/Tertiary (Johansen et al., 1993; Doré, 1995; van Koeverden et al., submitted) (see figure 2 5) where the major source rocks for the hydrocarbons in the Barents and Kara seas are Permo Triassic/Triassic terrestrially dominated source rocks and Upper Jurassic marine shales (Johansen et al., 1993; Galimov et al., 2007). The oldest source rocks are the Domanik facies, shales and carbonates of Late Devonian to Early Carboniferous age that are the major source of the Timan Pechora petroleum discoveries. The Domanik facies consists of dark marine shales and carbonates and are high quality, oil prone source rock (Ulmishek, 1982; Johansen et al., 1993). Permian source rocks are Lower Permian evaporites that have some potential for oil generation on the Pechora Block and Upper Permian shales with mainly gas generating potential. Triassic and Lower Middle Jurassic source rocks are assumed to be the main source rocks for the major gas discoveries in the South Barents Basin (Johansen et al., 1993; Doré, 1995). The best quality and most widespread source rocks in the East Barents are the Upper Jurassic Bazhenov Fm and age equivalent marine shales within the Kara Sea (Johansen et al., 1993; Galimov et al., 2007). According to Galimov et al. (2007) the depositional and source rock environment are similar between the Russian Barents Sea and Kara Sea but significant differences are in the thermal evolutions of the basins and source rock quality. The Upper Jurassic Bazhenov source rock is immature in the Russian Barents Sea while the Triassic source rocks have expelled much of its gas prior to trap formation and the traps therefore collect the mature end product of the expulsion. In the Kara Sea the source rocks are interpreted to have matured coeval with, or post trap formation and that has allowed the capture of the full expulsion spectrum. According to the newly gained results from van Koeverden et al. (submitted) the youngest suggested expulsive source rocks in the Russian Barents and Kara Seas may be of Cretaceous to Tertiary age.
2.3.2 Reservoir rocks, traps and seals
In the Paleozoic plays of the onshore Timan Pechora Basin, the reservoir rocks are carbonates and clastic rocks of Ordovician to Permian age. In the offshore extension of the province extending into the South eastern Russian Barents Sea, hydrocarbon discoveries have been made in Carboniferous and Permian carbonates, mainly limestones and dolomites. The traps in the Paleozoic plays are generally within reef like organic build ups or bioherm Chapter 2. Geological framework 20 structures. The Triassic plays are found in Triassic and Uppermost Permian deltaic sandstones and contain fairly significant resources in the Russian Barents where the discoveries are mainly gas but also some oil. The traps are fault and dome structures with both structural and stratigraphic trap possibilities due to salt tectonic movements. The seals in the Triassic plays are intra Triassic shales with good initial sealing capacities. The main hydrocarbon resources in the Russian Barents Sea are contained within Jurassic reservoir rocks. The main reservoirs are Middle to Upper Jurassic marine sandstones where the traps are dome and fault structures but stratigraphic traps may also occur with pinch outs and onlaps onto paleo highs. The seals are Upper Jurassic and Cretaceous shales that sometimes act as super seals (Johansen et al., 1993; Doré, 1995). The most important reservoirs in the Kara Sea are Cretaceous sandstones where the traps are stratigraphic traps on the slopes of basins and drapes over older structural highs. The Lower Cretaceous shales make up the seals in these Cretaceous plays (Johansen et al., 1993).
Chapter 2. Geological framework 21
Figure 2 5. Graphical summary of proven and potential reservoir and source rocks in the Barents Sea. The left hand side shows the geological intervals referred to in the text and their approximate age. From Doré (1995). Chapter 3. Sample set 22
3. Sample set
The sample set of this study consists of 6 samples of extracted oils from the Central part of Novaya Zemlya (table 3 1), the Matotchkin Strait, (see figure 2 1), 7 oil samples from the Barents Sea (table 3 2.) and a NSO 1 Oseberg standard oil used as a reference point in the analytical work. The outline of this chapter is as follows:
3.1 The sample set 3.1.1 120.611 Devonian limestone 3.1.2 NZS 137 Carboniferous siltstone 3.1.3 NZS 187 Carboniferous siltstone 3.1.4 NZS 225 Permian shale 3.1.5 NZS 255 Silurian shale 3.1.6 NZV 232 Devonian shale 3.1.7 7120/6 1 Oil from the Snøhvit field 3.1.8 7122/7 1 Oil from Goliat field 3.1.9 7124/3 1 Oil from the Hammerfest Basin 3.1.10 7124/4 1 Oil from the Hammerfest Basin 3.1.11 7128/4 1 DST1 Oil from the Finnmark Platform 3.1.12 7128/4 1 DST2 Oil from the Finnmark Platform 3.1.13 7228/7 1A Oil form the Nordkapp Basin 3.1.14 NSO 1 Oil from the Oseberg field Chapter 3. Sample set 23
3.1 The sample set
The samples from Novaya Zemlya are part of the larger ongoing PhD project of Jan Hendrik van Koeverden at the Department of Geosciences of the University of Oslo. Jan Hendrik van Koeverden has performed extensive geochemical characterization of migrated petroleum in 24 sedimentary samples from Novaya Zemlya. The 6 samples used in this study were selected because they were of the best quality of the available samples, showed the best biomarker ratios and had the most distinguished chromatograms. These sedimentary samples were collected from several locations on Novaya Zemlya during the journey of Professor Olaf Holtedahl, from the University of Oslo, in 1921. The results of the expedition were given in 40 scientific reports (“Report of the Scientific Results of the Norwegian Expedition to Novaya Zemlya 1921”, Vol. 1 40) and numerous smaller reports (Holtedahl, 1922; 1924). There has not been done much work on the collected material, only the work by Nakrem et al. (1991), but the collection has been documented by Nakrem (1989) and Nakrem (2007). No prior organic geochemical work was performed on these samples before the work of van Koeverden et al. (submitted). The collection of these sedimentary samples is stored at the Natural History Museum of the University of Oslo.
3.1.1 120.611 Devonian limestone
This is an extracted oil sample from the Gribovskaya Fm. The sedimentary rock sample is a limestone, from the Wilczek Mountain in the Matotchkin Strait, and is of Lochkovian Emsian age of the Devonian Period.
3.1.2 NZS 137 Carboniferous siltstone
This is an extracted oil sample from the Kazarkinskaya Fm. The sedimentary rock sample is a siltstone, from the Gubina Bay in the Matotchkin Strait, and is of Gzhelian age of the Carboniferous Period.
3.1.3 NZS 185 Carboniferous siltstone
This is an extracted oil sample from the Kazarkinskaya Fm. The sedimentary rock sample is a siltstone, from the Bremer Mountains in the Matotchkin Strait, and is of Gzhelian age of the Carboniferous Period. Chapter 3. Sample set 24
3.1.4 NZS 225 Permian shale
This is an extracted oil sample from the Krasnorechenskaya Fm. The sedimentary rock sample is a shale, from the south western part of the Matotchkin Strait, and is of Kungurian age of the Permian Period.
3.1.5 NZS 255 Silurian shale
This is an extracted oil sample from the Matotchkin Strait. The sedimentary rock sample is a shale of Silurian age.
3.1.6 NZV 232 Devonian shale
This is an extracted oil sample from Krestovii Island in the Matotchkin Strait. The sedimentary rock sample is a shale of Devonian age.
The oil samples used are samples that were available at the Department of Geosciences and were chosen based on the location of the wells that these oils were encountered in. All of the petroleum samples are crude oils from wells drilled in the Norwegian Barents Sea and their localities are given in figure 3 1.
3.1.7 7120/6 1 Oil from the Snøhvit field
This is an oil sample taken from the Snøhvit field, in the Hammerfest Basin, from well 7120/6 1, during Drill Stem Test (DST) 2.
3.1.8 7122/7 1 Oil from the Goliat field
This is an oil sample taken from the Goliat field, in the Hammerfest Basin, from well 7122/7 1 at 1106 meters depth. ‘
3.1.9 7124/3 1 Oil from the Hammerfest Basin
This is an oil sample from the Hammerfest Basin, taken from well 7124/3 1 at 1298 meters depth.
3.1.10 7124/4 1 Oil from the Hammerfest Basin
This is an oil sample from the Hammerfest Basin, taken from well 7124/4 1 during DST3. Chapter 3. Sample set 25
3.1.11 7128/4 1 DST1 Oil from the Finnmark Platform
This is an oil sample from the Finnmark Platform, taken from well 7128/4 1 at the depth interval from 1592 1610 meters during DST1.
3.1.12 7128/4 1 DST2 Oil from the Finnmark Platform
This is an oil sample from the Finnmark Platform, taken from well 7128/4 1 at the depth interval from 1577 1586 meters during DST2.
3.1.13 7228/7 1A Oil from the Nordkapp Basin
This is an oil sample from the Nordkapp Basin, taken from well 7228/7 1A at 2091 meters depth.
3.1.14 NSO 1 Oil from the Oseberg field
This oil sample is the North Sea Oil (NSO) standard, taken from the Oseberg field on the Norwegian Continental Shelf (NOCS). This oil is a mid mature oil sourced from the Upper Jurassic Kimmeridge shale. This oil is used by the Norwegian Petroleum Directorate (NPD) as a reference standard to calibrate laboratory instruments before and after geochemical analysis (Weiss et al., 2000).
Chapter 3. Sample set 26
Table 3 1. Sample list of the Novaya Zemlya samples with formation lithologies, age and location. Modified from van Koeverden et al. (submitted). Sample Nr Lithology Formation Formation age Main location Detailed locality Devonian 120.611 Limestone Gribovskaya (Lochkovian Emsian) Matotchkin Strait Wilczek Mountain NZS 137 Siltstone Kazarkinskaya Carboniferous (Gzhelian) Matotchkin Strait Gubina Bay (east. S.) NZS 185 Siltstone Kazarkinskaya Carboniferous (Gzhelian) Matotchkin Strait Bremer Mountains, shore NZS 225 Shale Krasnorechenskaya Permian (Kungurian) Matotchkin Strait South western (?) NZS 255 Shale Silurian (general) Matotchkin Strait Matotchkin Strait NZV 232 Shale Devonian (general) Matotchkin Strait Krestovii Island (eastern island)
Table 3 2. Sample list of the oil samples from the Norwegian Barents Sea. See figure 3 1 for location of the wells. Origin and Depth sample nr. from [m] Depth to [m] Type Fluid Locality 7120/6 1 DST2 oil Hammerfest Basin Snøhvit 7122/7 1 1106 oil Hammerfest Basin Goliat 7124/3 1 1298 oil Hammerfest Basin 7124/4 1 DST3 oil Hammerfest Basin 7128/4 1 1577 1586 DST2 oil Finnmark Platform 7128/4 1 1592 1610 DST1 oil Finnmark Platform 7228/7 1A 2091 oil Nordkapp Basin
Figure 3 1 (next page). Overview map of the Norwegian Barents Sea. Locations of the oil samples used in this study are indicated with red stars and well numbers. Modified from Gabrielsen et al. (1990) Chapter 3. Sample set 27
7228
7124 7128 7122 7120
Chapter 4. Analytical methods 28
4. Analytical methods
The analytical methods used in this study will be presented here in this chapter. The outline of this chapter is as follows:
4.1 Introduction 4.2 Gas chromatography 4.2.1 The carrier gas 4.2.2 The injector and column 4.2.3 The detector 4.3 Preparation of samples 4.4 Molecular sieving 4.5 Organic fraction separation 4.6 Gas Chromatography Flame Ionizing Detector (GC FID) 4.7 Gas Chromatography Mass Spectrometry (GC MS) 4.8 Gas Chromatography Mass Spectrometry Mass Spectrometry (GC MS MS)
Chapter 4. Analytical methods 29
4.1 Introduction
In order to determine the different types of biomarkers and their relative amounts in a crude oil or oil extract, petroleum geochemical analysis are carried out. In this study, petroleum geochemical analysis were carried out by GC FID, GC MS and GC MS MS methods on the extracted oils from the Novaya Zemlya samples and the crude oil samples to determine the different types of biomarkers and their relative amounts. In order to restrain the postulated Cretaceous to Tertiary source rock ages for the migrated petroleum in the Novaya Zemlya samples from van Koeverden et al. (submitted), more detailed analysis of age specific biomarkers from GC MS MS data were performed in this study that was financed by Lundin Petroleum . GC FID analysis were done on the saturated fractions of the oil extracts from Novaya Zemlya and the crude oil samples, GC MS analysis were carried out on both the saturated and aromatic fractions of all the samples and GC MS MS analysis were performed only on the saturated fractions of the samples. The GC FID and GC MS data is for getting a grasp of the main petroleum geochemical analytical methods used today and to get the basic organic geochemistry parameters concerning organic facies and maturity of the Novaya Zemlya migrated oil. This was done to put the samples from Novaya Zemlya into a geologic context. For this reason, oil samples from the Norwegian Barents Sea were also included as a reference set. The oil samples from the Norwegian Barents Sea were used for comparing the unknown Novaya Zemlya oil with oils belonging to known petroleum systems. The NSO Oseberg standard oil was used just as a reference in the analytical work.
4.2 Gas Chromatography
Gas Chromatography was first put in use in the 1950´s and is a technique that separates a complex mixture of organic compounds, like petroleum, into their individual molecular groups. By doing this separation it is possible to identify the compounds qualitatively and quantitatively. The main principle for boiling point chromatography is that the system has two phases, a stationary and a mobile phase. The stationary phase is where the substances are held back from further migration. The mobile phase is either gaseous or a liquid and the Chapter 4. Analytical methods 30 adsorbent is the solid substance that is retained in the solid phase. The separation is controlled by three properties; relative solubility, adsorption and volatility.
4.2.1 The carrier gas
The carrier gas in gas chromatography carries the soluble substances through the column in the chromatograph and in order for that, the gas must be inert, i.e. the gas cannot interact with the sample that is analysed. Nitrogen, helium and hydrogen gas is the commonly used gases. The choice of gas can influence how quickly the substances react, how they move through the column and how fast they reach the detector because the gas has an effect on the analysis time and the efficiency of the column. In order for that the speed of the gas into the chromatograph is correct, a control system or a flow controller is used to make sure that the right pressure value is used and can therefore always be changed and corrected when needed.
4.2.2 The injector and column
Where the sample is vaporized and introduced to the column is called the injector and the column is the stationary phase in gas chromatography. The samples that are to be analysed are injected, vaporised and transported through the column where some substances are absorbed in the injector and do therefore not flow through the column. The column is a spiral usually made of quartz and there are two types of columns:
• A packed bed column that is completely packed and its stationary phase are in granular forms and fill the column completely. These columns are hardly in use today.
• An open tubular capillary column usually has a small diameter where a coating on the inner tube wall acts as the stationary phase where the substances flow through the hole in the center of the column.
4.2.3 The detector
The detector measures the amounts of the reacts to the mass of analyte that comes out of the column after being separated. In Gas chromatography there are basically two principle detectors; using concentration dependent detectors or mass flow dependant detectors. Thermal conductivity detector (TCD) and flame ionization detector (FID) are the two most Chapter 4. Analytical methods 31 commonly used detectors today. TCD is the less linear of the two and measures the change in heat capacity in the detector as the analyte passes through. The advantage of using TCD is that it does not destroy the organic compound in the process. The FID, however, burns the organic compounds and therefore destroys the sample in the process but is the most sensitive detector available today and has a very large linear range. Figure 4 1 shows a typical gas chromatograph that is used to get information about the distribution of the individual molecular compounds.
Figure 4 1. Detailed view of a typical gas chromatograph used to separate complex mixture of compounds. Modified from Peters et al. (2005a).
4.3 Preparations of samples
In order to be able to do the analytical work on the sample set they had to be separated into their organic fractions, saturated, aromatic and polar compounds (see chapter 4.5). This separation was done following the procedures of Bastow et al. (2007). But before the samples were introduced to the separation method they had to be prepared first. The Novaya Zemlya samples used in this study were already extracted oils from sediment samples. In order to be able to separate the samples into their organic fractions, the solvent that the extracts was diluted with had to be changed as the solvent was dichloromethane (DCM) but had to be hexane in order for the separation to be successful. The samples were therefore evaporated almost to dryness with nitrogen gas and few drops of hexane were Chapter 4. Analytical methods 32 introduced to the solution. This was done a couple of times until it was certain that all of the DCM had been removed from the solution. The oil samples consisted of crude oils so in order to be able to run the analytical work they had to be diluted with a solvent. That was done by taking only 2 drops of the crude oil and dilute with 1 ml of cyclohexane. This solution had then to be sieved by molecular sieving product (see chapter 4.4) and evaporated down to a few drops to be used in the separation method.
4.4 Molecular sieving
Crude oils normally consist of a lot on n alkanes, or straight chain mono or di methylated saturated hydrocarbons, and in order to perform the analytical methods these have to be taken out of the solution. That is done by applying a molecular sieving product; a compound that is a synthetically made zeolite and chemically designed to remove the n alkanes. The molecular structure of the sieving product is designed in that way that it has channel like pores that absorbs or removes the n alkanes out of the solution. Bigger molecules will not fit into these pores or small openings and will therefore remain in the sample. The sample will therefore be enriched in biomarkers and the aromatic fraction will remain after separation of the molecular sieve from the sample. It is necessary to remove the n alkanes out of the solution, otherwise the n alkanes peaks would dominate and interfere with the other peaks in the chromatogram (Peters et al., 2005b). In this study 5Å UOP MHS2 420LC silica was used. The procedure of the molecular sieving was as follows: About 0.2 gram of molecular sieving was poured into a 15 ml glass; 3 ml of sample was then mixed together with the sieve with a Pasteur glass pipette. The samples were diluted and mixed thoroughly with about 2.5 ml cyclohexane by stirring with the pipette. Then the samples were centrifuged at 2000 rpm for 3 minutes in a Heraeus Sepatech Labofuge H until the molecular sieve was settled. The liquid samples were then taken out and poured into a new 15 ml glass with a pipette and reduced to about ¾ of its volume by flow of nitrogen. Finally, after evaporation, the samples were put in vials and sealed with a Teflon lined cap. Chapter 4. Analytical methods 33
4.5 Organic fraction separation
The separation method used in this study was done following the procedures of Bastow et al. (2007) with the exception that hexane was used as substitute for pentane as a solvent. The method uses disposable Pasteur pipettes and minimum amounts of solvents and silica gel to demonstrate that a complete separation of the saturated, aromatic and polar components from petroleum by using silica gel liquid chromatography. The fact that all the materials used are disposable, low cost and readily available and that the method is fast, accurate, requires minimum work up time, and results in only minor loss to evaporation makes this procedure, in many aspects, more practical than previously published methods.
4.6 Gas Chromatography Flame Ionizing Detector (GC FID)
The saturated fractions of the Novaya Zemlya samples and the un sieved solutions of the oil samples were analysed by GC FID. For the GC FID analysis a Varian Capillary Gas Chromatography Model 3800, with a 25 m long Hewlett Packard Ultra II Cross linked Methyl Silicone Gum Column with a 0.2 mm inner diameter and a film thickness of 0.33 m. The injector temperature was set to 330°C with nitrogen as the carrier gas and initial column temperature of 40°C and a hold time of 2°C min 1. The column temperature was increased with 4°C min 1 up to 325°C, which takes 75 minutes, where it was finally held for 20 min with a total run time of 95 minutes. The flame ionization detector (FID) reacts to everything that is of organic origin and is flammable. The sample is injected and vaporized before it is separated in the column where the stationary phase is dimethylpolysiloxane coating the inside of the thin column. Short chained molecules take less time to travel through the column than long chained molecule and therefore the compounds can be detected qualitatively and quantitatively. The signals which are produced from the FID are picked up by a computer and a chromatogram is produced. The X axis in a chromatogram represents increased time and temperature, while the Y axis represents the signal intensity, i.e. in form of height of peaks equal to relative amount, of the different components. Chapter 4. Analytical methods 34
Figure 4 2. Schematic overview of a GC FID instrument. Modified from Pedersen (2002).
4.7 Gas Chromatography Mass Spectrometry (GC MS)
The saturated and aromatic fractions of all the samples were analysed by GC MS analysis. For the GC MS analysis a Fisons Instruments MD800 GC MS system in SIM mode (Selected ion monitoring) with a 50 m long Chromopak CP SIL 5CB MS FS 50X.32(.40) WCOT fused silica type column with an inner diameter of 0.32 mm that contained a CP SIL 5CB Low Bleed/MS stationary phase. The column had an initial temperature of 80°C and was heated with 10°C min 1 up to 180°C and subsequently with 1.7°C min 1 to 316°C, where it finally was held for 30 min. The GC MS procedure combines gas chromatography and mass spectrometry to identify substances within a sample. The gas chromatograph is used to separate the compounds in the sample and the mass spectrometer is used to identify the compounds by ionization and mass analysis. The different molecules in petroleum have different properties, like boiling point, and that is why they can be separated and isolated as the molecules travel through the column. Because of the variations in size of the molecular shape and vapour pressure the molecules take different amount of time to move through the column and reach the detector at variable times, they can be evaluated individually. The time from when the injection is Chapter 4. Analytical methods 35 made until detection occurs, is called the retention time. When the different components come out of the column they are bombarded with a stream of electrons (normally 70EV) in the electron ionization unit inside the mass spectrometer. This bombardment cause the molecules to break into fragments and in some cases these fragments will be small, and in other the molecules will withstand the bombardment and retain more of their original shape and structure. The mass analyser is designed to separate and measure the mass of the ions by their mass to charge (m/z) ratio (Tran & Phillippe, 1993). The mass spectrum of the fragments contributes to their identification as each fragment composition is unique. The main functions of a typical GC MS are showed in figure 4 3 with short explanations of the functions.
Figure 4 3. A typical gas chromatograph/ mass spectrometer performs six functions (from left to right): (1) compound separation by gas chromatography; (2) transfer of separated compounds to the ionizing chamber of the mass spectrometer; (3) ionization and acceleration of the compounds down the flight tube; (4) mass analysis of the ions; (5) detection of the focused ions by the electron multiplier; and (6) acquisition, processing and display of the data by computer. The quadrupole mass analyser is an important component in quadrupole mass spectrometers. Mass analysis can be accomplished using four parallel quadrupole rods. By varying a combination of radiofrequency and direct currents within the rods, a beam of ions can be scanned, thus allowing only ions of a given mass to reach the detector at any moment during the scan. From Peters et al. (2005a).
Chapter 4. Analytical methods 36
4.8 Gas Chromatography Mass Spectrometry Mass Spectrometry (GC
MS MS)
Gas Chromatography – Mass Spectrometry – Mass Spectrometry (GC MS MS) was carried out on the saturated fraction of the samples by Baseline Resolution Inc., Texas, USA and financed by Lundin Petroleum. The analytical procedure performed by the Baseline analysts in order to get analyses on age specific biomarkers was as follows:
A volume of 0.2 µl of the MPLC (Medium Pressure Liquid Chromatography) prepared saturate fraction is injected, using a Hewlett Packard 7673 series injector, from the cool on column injector into a Hewlett Packard 5890 Series II GC System coupled to a VG AutoSpecQ mass spectrometer. A 60 meter DB 1 capillary gas chromatography column with a 1 meter deactivated silica pre column with a 0.25 mm inner diameter and a film thickness of 0.10 m is utilized for the analysis. Helium is used as carrier gas in constant pressure mode. The AutoSpecQ is operated in MRMQ EI+ mode at a resolution of 1000 on the magnet and a resolution of 1 on the Quad. Parent daughter paired ions are collected in a single time window from 0 to 105 minutes. The pairs collected are given in the accompanying table (differs for each experiment). The dwell time is set to 50 milliseconds for each ion with an interchannel time of 20 milliseconds. The analysed components are quantified relative to an external reference standard that uses an internal standard (5β Cholane) that is added to the fraction after the MPLC separation as the comparison peak. As a quality assurance, a standard sample with known ppm values of major components is run at the beginning and end of each queue of samples. These standards are averaged and a response factor calculated for the known components. Unknown components are assumed to have a response factor of 1. The concentration in ppm of each reported component analysed is then calculated using the response factors for that queue and reported. GC MS MS is based on so called parent – daughter relationships. In GC MS MS analysis complex organic molecules, called parents, are ionized in the ion source of the mass spectrometer and broken down into smaller charged ions, called daughters. By doing GC MS MS analysis it is possible to determine if the parent molecule of selected daughter ions (Peters et al., 2005a
Chapter 5. Interpretation parameters 37
5. Interpretation parameters
The interpretations of chromatograms from GC FID, GC MS and GC MS MS data are based on peak identification. The interpretation parameters used when interpreting GC FID, GC MS and GC MS MS data will be presented here in this chapter. The outline of this chapter is as follows:
5.1 GC FID interpretation 5.1.1 Pristane/Phytane
5.1.2 Pristane/n C17 and Phytane/n C18 5.2 GC MS interpretation 5.2.1 Terpanes 5.2.2 Steranes 5.2.3 Triaromatic steroids 5.2.4 Monoaromatic steroids 5.2.5 Phenanthrene and methylphenanthrene 5.2.6 Methyl dibenzothiophene 5.3 Age related parameters
5.3.1 Oleanane Index (Oleanane / (Oleanane + C 30 αβ hopane))
5.3.2 %C 28 / %C 29 ββs steranes
5.3.3 24 norcholestane biomarkers (C2 6 steranes) 5.3.4 Dinosterane ratio ((∑20R dinosteranes / (∑20R dinosteranes + 20R 3β methyl 24 ethylcholestane))
Chapter 5. Interpretation parameters 38
5.1 GC FID data and interpretation
The relevant compounds and their peaks that are to be identified from GC FID data will be presented here as GC FID analysis were carried out on the sample set. The main compounds from GC FID data that are of interest are pristane and phytane.
5.1.1 Pristane/Phytane
The most common types of isoprenoid isoalkanes are pristane and phytane. The most abundant source of isoprenoids is phytol, which is the side chain of chlorophyll, and the pristine and phytane compounds are derived from phytol (fig. 5 1). The amount of oxygen present during deposition of the source rock is indicated by this relation, i.e. the red ox potential of the source rock (Tissot & Welte, 1984). The depositional environment determines whether phytol transforms into pristane or phytane, and therefore the pristane/phytane ratio provides information about the depositional environment with respect to anoxic or oxic conditions. Under oxic conditions phytol transforms by oxidation to phytolic acid which is then decarboxylated, losing one carbon atom. Under reducing conditions, phytol is reduced directly to phytane, preserving the C 20 structure. Pristane and phytane are more predominant in anoxic environments (Welte & Waples, 1973) and with increasing maturity, the Pr/Ph ratio will increase since phytane is more unstable than pristine. The following intervals are used to describe the depositional environment; Pr/Ph > 1 indicate oxidizing or hyper saline, Pr/Ph < 1 indicate anoxic, carbonate or lacoustrine settings, Pr/Ph = 1.3 – 1.7 indicate marine oil, Pr/Ph → 2.5 indicate a marine environment with considerable amount of terrestrial input, Pr/Ph > 3 10 indicate coal. Chapter 5. Interpretation parameters 39
Figure 5 1. The diagenetic origin of pristane and phytane. From Peters et al. (2005b).
5.1.2 Pristane/n C17 and Phytane/n C18
The pristane/n C17 and phytane/n C18 ratios are used as a maturity parameter since their values decrease with increasing maturity. The values decrease with increasing maturity because the isoprenoids break down more rapidly than the n alkanes during increased source rock maturity since isoprenoids are thermally more unstable than n alkanes (Tissot et al., 1971). Low ratios therefore indicate a more mature sample and care need to be taken when interpreting this parameter as the Pr/n C17 and Ph/n C18 ratios are also affected by biodegradation, albeit in the opposite direction. Chapter 5. Interpretation parameters 40
m Volts n C13
300 Intensity
250
n C17 200 n C18
150 Pr
Ph 100
50
7 10 20 30 40 50 60 Retention time Minutes Figure 5 2. Chromatogram produced from GC GID from the standard NSO 1 sample in this study. The chromatogram is almost identical to the one found in the NIGOGA (The Norwegian Industry Guide to Organic Geochemical Analysis) (Weiss et al., 2000), the C 13 fraction is higher here but the other peaks are quite similar to the NIGOGA.
5.2 GC MS data and interpretation
The relevant compounds and their peaks that are most often identified from GC MS data, the mass/charge ratio for the different ions and what chemical group they belong to, are given in table 5 1. Most of the peaks that are identified are then used in evaluating maturity and facies parameters but some parameters can be used in age determination (see chapter 5.3). Chapter 5. Interpretation parameters 41
Table 5 1. The ion/mass ratios for the ions of interest for interpretation from GC MS data and the chemical compounds they belong to. SAT = saturated hydrocarbons, ARO = aromatic hydrocarbons and SARO = sulphur aromatic hydrocarbons. Ion/mass ratio Chemical compounds SAT SAT m/z = 191 Terpanes m/z = 217 Steranes m/z = 218 Steranes ARO m/z = 231 Triaromatic steroids m/z = 253 Monoaromatic steroids m/z = 178 Phenanthrene m/z = 192 Methylphenanthrenes SARO m/z = 198 Methyl dibenzothiophenes
5.2.1 Terpanes
Terpanes are a group of saturated hydrocarbons that are to be found on m/z = 191 (fig. 5 5). The relevant peak identification names of terpanes from m/z = 191are given in table 5 2. The structure of a tricyclic terpane is given in figure 5 3 and the structure of gammacerane is given in figure 5 4.
Figure 5 3. Structure of a tricyclic terpane (Hunt, 1996). Figure 5 4. Structure of gammacerane (Hunt, 1996). Chapter 5. Interpretation parameters 42
Table 5 2. Triterpanes of m/z = 191 (Weiss et al., 2000). Peak Stereochemistry Name Composition
23/3 Tricyclic terpane C23 H42
24/3 Tricyclic terpane C24 C44
25/3 (17R/17S) Tricyclic terpane peak doublet C25 H46
24/4 Tetracyclic terpane C24 H42
28/3 Tricyclic terpane peak doublet C28 H48
29/3 Tricyclic terpane peak doublet C29 H50
27Ts 18α (H) 22,29,30 trisnorneohopane C27
27Tm 17α (H) 22,29,30 trisnorhopane C27
28αβ 17α(H), 21β(H) 28,30 bisnorhopane C28 H48
29αβ 17α(H), 21β(H) 30 norhopane C29
29Ts 18α (H)–30 norneohopane C30 H52
30d 15α methyl 17α (H) 27 diahopane C30 H52
29βα 17 β (H), 21 α (H) 30 normoretane C29 H50
O 18α(H)+18α oleanane C30 H52
30αβ 17α (H), 21β (H) hopane C30 H52
30βα 17β (H), 21α (H) moretane C30 H52
30G Gammacerane C30 H52
31αβ 22S 17α (H), 21β (H) 22 homohopane C31 H54
32αβ 22R 17α (H), 21β (H) 22 homohopane C31 H54
Chapter 5. Interpretation parameters 43
30αβ 30αβ Hopanoids Intensity
Tri and tetracyclic terpanes 29αβ
31αβ 29Ts 32αβ 27Ts 27Ts 30d 30d
30βα 27Tm 27Tm 29βα 29βα
23/3 24/3 24/4 29/3 25/3 28/3
Retention time Figure 5 5. Chromatogram of m/z 191 of the saturated fraction from the NSO 1 standard oil, providing source rock facies and maturity information.
5.2.2 Steranes
Steranes are a group of tetracyclic saturated hydrocarbons (one 5 ring and three 6 rings) and can be identified on m/z = 217 (figure 5 6) and 218 (fig. 5 7). The relevant peak identification names of steranes from m/z = 217 are given in table 5 3 and from m/z = 218 in table 5 4.
Table 5 3. Steranes visible in m/z = 217 (Weiss et al., 2000). Peak Stereochemistry Name Composition
27dβS 20S 13β(H), 17α(H), 20(S) cholestane (diasterane) C27 H12
27dβR 20R 13β(H), 17α(H), 20(R) cholestane (diasterane) C27 H48
29ααS 20S 24 ethyl 5α(H), 14α(H), 17α(H), 20(S) cholestane C29 H52
29ββR 20R 24 ethyl 5α(H), 14β(H), 17β(H), 20(R) cholestane C29 H52
29ββS 20S 24 ethyl 5α(H), 14β(H), 17β(H), 20(S) cholestane C29 H52
29ααR 20R 24 ethyl 5α(H), 14α (H), 17α(H), 20(R) cholestane C29 H52
Chapter 5. Interpretation parameters 44
Table 5 4. Steranes visible in m/z = 218 (Weiss et al., 2000). Peak Names
27ββS C27 regular sterane (5α(H), 14β(H), 17β(H), 20(S) cholestane) C28 regular sterane (24 methyl 5α(H), 14β(H), 17β(H), 20(S) 28ββS cholestane) C29 regular sterane (24 ethyl 5α(H), 14β(H), 17β(H), 20(S) 29ββS cholestane)
C27 steranes C27 diasteranes 27dβS 27dβS Intensity
C29 steranes 27dβS 27dβS C28 steranes 29ββR 29ββR 29ααR 29ααR 29ααS 29ααS 29ββS
Retention time Figure 5 6. Chromatogram of m/z = 217 of the saturated fraction from the NSO 1 standard oil, used to assess maturity as well as source rock facies. Chapter 5. Interpretation parameters 45
Intensity 27ββS 29ββS 28ββS
Retention time Figure 5 7. Chromatogram of m/z = 218 of the saturated fraction from the NSO 1 standard oil, mainly used to assess the % sterane composition in terms of C 27 /C 28 /C 29 steranes.
5.2.3 Triaromatic steroids
Triaromatic steroids are aromatic hydrocarbons that can be identified on m/z = 231 (fig. 5 8) and are very useful for maturity assessment. The relevant peak identification names of triaromatic steroids are given in table 5 5.
Table 5 5. ABC ring triaromatic steroid hydrocarbons visible in m/z = 231 (Weiss et al., 2000). Peak Substituent Name
R1 R2
a1 CH3 H C20 TA
g1 R(CH 3) C8H 17 RC 28 TA Chapter 5. Interpretation parameters 46
Intensity TA 28 RC TA 20 C
Retention time Figure 5 8. Chromatogram of m/z 231 of the aromatic fraction from the NSO 1 standard oil, indicating the moderate maturity of this oil by the low C 20 / (C 20 +C 28 ) ratio.
5.2.4 Monoaromatic steroids
Monoaromatic steroids are aromatic hydrocarbons that can be identified on m/z = 253 (fig. 5 9) and are assumed to be the precursors of the triaromatic steroids. The main use of monoaromatic steroids is for correlation (fingerprinting) and maturity assessment, comparing the ratio of triaromatic to monoaromatic steroids. The relevant peak identification names are given in table 5 6.
Table 5 6. C ring monoaromatic hydrocarbons visible in m/z = 253. H1 is also present in m/z 231 (Weiss et al., 2000). Peak Substituent Name
R1 R2 R3 R4
H1 α(H) CH 3 S(CH 3) C2H5 αSC 29 MA
H1 α(H) CH 3 R(CH 3) CH 3 αRC 28 MA
H1 β(H) CH 3 R(CH 3) C2H5 βRC 29 MA
H1 bCH 3 H R(CH 3) C2H5 βRC 29 DMA Chapter 5. Interpretation parameters 47
Intensity
H1
Retention time Figure 5 9. Chromatogram of m/z = 253 of the aromatic fraction from the NSO 1 standard oil.
5.2.5 Phenanthrene and methylphenanthrene
Phenanthrene and methylphenanthrene are aromatic hydrocarbons that can be identified on m/z = 178 and 192 (fig. 5 10). The main uses of these compounds are for maturity assessment. The relevant peak identification names are given in table 5 7.
Table 5 7. Polycyclic aromatic hydrocarbons and sulphur compounds visible in m/z = 178 and m/z = 192 of the aromatic fraction from NSO 1 (Weiss et al., 2000). Peak Name
P Phenanthrene
3 MP 3 methylphenanthrene
2 MP 2 methylphenanthrene
9 MP 9 methylphenanthrene
1 MP 1 methylphenanthrene Chapter 5. Interpretation parameters 48
P 9 MP
1 MP Intensity 3 MP
2 MP
Retention time Figure 5 10. Chromatogram of m/z = 178 and 192 of the aromatic fraction from the NSO 1 standard oil.
5.2.6 Methyl dibenzothiophene
Methyl dibenzothiophenes are sulphur aromatic hydrocarbons that can be identified on m/z = 198 (fig.5 11). The main use of these compounds is for maturity assessment and they respond better in the medium to low maturity range than do the phenanthrenes. The relevant peak identification names are given in table 5 8.
Table 5 8. Components visible in m/z = 198 (Weiss et al., 2000). Peak Name
4 MDBT 4 methyldibenzothiophene
1 MDBT 1 methyldibenzothiophene Chapter 5. Interpretation parameters 49
m/z= 198 Intensity 4 MDBT 4 MDBT 1 MDBT 1 MDBT
9 MP m/z= 192 1 MP
3 MP 2 MP
Retention time Figure 5 11. Chromatogram of m/z = 198 (above) and 192 (below) of the aromatic fraction from the NSO 1 standard oil. Comparison between sulphur aromatics and phenanthrenes is used to determine environment of deposition, see figure 7 7.
5.3 Age related parameters
As biota evolved during Phanerozoicum certain taxa of organism developed the use of specific organic compounds, e.g. oleanane in flowering plants, and that are these specific compounds that are used as age determine parameters. The age determining parameters which are used in this study will be explained here. The main focus is on GC MS and GC MS MS data, as the age specific biomarkers receive the most attention in the discussion. The parameters used are; the oleanane index, C 28 /C 29 sterane ratio, 24 norcholestane biomarkers
(C 26 steranes) and dinosterane ratio (C 30 methylsteranes).
5.3.1 Oleanane Index (Oleanane / (Oleanane + C 30 αβ hopane))
The oleanane index (Oleanane / (Oleanane+ C 30 αβ hopane)) was defined by Moldowan et al. (1994) as a useful parameter for source rock age determination. Values of 0.03 or higher indicate an Early Cretaceous or younger age and values above 0.2 point to Tertiary age. Oleanane is a biomarker for angiosperm plants and thus indicate a source age for the Chapter 5. Interpretation parameters 50 hydrocarbons to be Cretaceous or younger. In Early Cretaceous only occasional occurrences of angiosperm plants have been recorded and by the onset of Late Cretaceous they had began to dominate the flora. During the Tertiary a major increase in the oleanane concentration is recorded (Moldowan et al., 1994) and undisputed angiosperm plant fossils are unknown prior to the Early Cretaceous (Nytoft et al., 2002). The occurrences of oleanane in sediments were described by e.g. Ekweozor et al. (1979a, b); Ekweozor and Telnæs (1989); Moldowan et al. (1994).
5.3.2 %C28 / %C29 ββs steranes
The C28 /C 29 sterane ratio has been utilized by Grantham & Wakefield (1988) and Schwark & Empt (2006) to constrain the age of oils and source rocks. A steady increase in the ratio of
C28 over C 29 steranes with decreasing source age of an oil were reported by Grantham & Wakefield (1988) (fig.5 12). This reported increase is based on averaging over long time periods (50 Ma) and therefore give a rough indication of the geological source age. The more recent work of Schwark & Empt (2006) achieved a much better resolution as they used samples of precise locations in the stratigraphy, however, the C 28/C 29 sterane ratio have to be interpreted with care. For example, short episodic increase in the C 28 /C 29 sterane ratio are recorded by Schwark & Empt (2006) at extinction events as they are often associated with episodic increases in prasinophyte algae due to increase in bottom water anoxia.
The steady increase of the C 28 /C 29 sterane ratio over time is thought to mainly be caused by an increase of the amount of C 28 steranes rather than a decrease of the amount of C29 steranes.
The abundance of C 29 steranes in organic matter with terrigenous input and increased percentages of C28 steranes in lacoustrine influenced strata suggest that the increasing trend of the C 28 /C 29 sterane ratio over time is valid for purely marine rocks or oils sourced by marine strata (Huang & Meinschein, 1979). Grantham & Wakefield (1988) suggested that the diversification of phytoplankton in general, rather than a change of sterols in a particular species, caused the increase in the C 28 percentages and as such, thus indicates increasing complexity of marine phytoplankton assemblages. This increasing complexity is linked to the emergence of dinoflagellates and coccolithosperes at the end of the Paleozoic and the appearance of silicoflagellates and diatoms in the Late Cretaceous. Chapter 5. Interpretation parameters 51
Z
Figure 5 12. Geological distribution of important groups of phytoplankton compared to mean C 28 /C 29 ratio of marine source rock derived crude oils. Modified from Grantham & Wakefield (1988).
5.3.3 24 norcholestane biomarkers (C 26 steranes)
The use of 24 norcholestanes as age specific biomarker was first described by Holba et al.
(1998a, 1998b). 24 norcholestanes are C 26 steranes, i.e. saturated hydrocarbons, and have a steroid skeleton (Holba et al., 1998b). These compounds are generally comprising <1% of regular C 27 C29 steranes and the main major sources for 24 norcholestanes and their precursors, i.e. 24 norsterols, in sediments and petroleum are diatoms and dinoflagellates species (Rampen et al., 2007).
Two C 26 sterane ratios have been described by Holba et al. (1998a, 1998b) as useful biomarkers to identify source age of sediments or oils derived in particular from Cretaceous or younger rocks. These two ratios are the 24 nordiacholestane ratio (NDR) and the 24 norcholestane ratio (NCR). They are defined as follows: Chapter 5. Interpretation parameters 52
NDR = [1 + 2] [1 + 2 + 3 + 4] and
NCR = [5 + 6 + 7 + 8] [5 + 6 + 7 + 8 + 9 + 10 + 11 +12 + 13]
The NDR and NCR ratio are quantified by calculating the areas of peaks (or peak heights) in the m/z = 358 → 217 mass chromatogram showed in figure 5 14. The identification names of the relevant peaks of 24 norcholestane (1 13) are given in table 5 9 and the structure of the relevant steranes are showed in figure 5 13. The NDR and NCR ratios increase with decreasing geological age and are therefore a powerful tool for differentiating age of oils, especially when coupled to other age specific biomarkers like oleanane and dinosteranes (Holba et al., 1998a). Holba et al. (1998a, 1998b) showed that the ratios increase slightly in Jurassic oils, increase dramatically in Later Cretaceous oils and show another substantial second increase in Late Tertiary oils. The change in the ratios are due to elevated 24 nordiacholestanes and 24 norcholestanes in Cretaceous or younger oils and sediments compared to their 27 norcholesatnes analogues. The observed elevations of the ratios in the Jurassic and the Cretaceous are related to dinoflagellates expansion and dinoflagellates are considered to be the most likely source of 24 norsterols up to the middle Cretaceous (Rampen et al., 2007). Earlier studies (i.e. Tappan, 1980; Lipps, 1993; Stewart and Rothwell, 1993; Holba et al., 1998a, 1998b) did however, believed that the occurrence of diatoms in the Jurassic and associated species diversification in the Cretaceous was responsible for the elevated 24 norcholestane ratios. The observed increase in the Tertiary (Oligocene Miocene) is likely caused by diatom expansion (Rampen et al., 2007) and represents deposition of diatom rich siliceous source rocks (Holba et al., 1998a, 1998b). The results obtained by Holba et al. (1998a, 1998b) suggest that: NDR > 0.20 indicates a Jurassic or younger source NDR > 0.25 or NCR ≥ 0.40 indicates a Cretaceous or younger source NDR > 0.50 or NCR ≥ 0.60 indicates a Oligocene or younger source Chapter 5. Interpretation parameters 53
Lower NDR values than 0.20, according to Holba et al. (1998a, 1998b), indicate either a Jurassic or older age or a certain Cretaceous or younger environment that do not encourage diatom growth (e.g. warm water carbonate, deltaic and/or coaly, and some lacustrine depositional settings).
Figure 5 13. Structure of selected steranes. From Holba et al. (1998a).
6 3 4 1 7 9 5 8 10 11 2 12 13
Figure 5 14. Representative parent → daughter (m/z = 358 → 217) mass chromatogram of C 26 steranes for sample 120.611 given as an example of peak identification. See table 5 9 for peak identification names of 24 norcholestanes.
Chapter 5. Interpretation parameters 54
Table5 9. Identification of 24 norcholestane. Modified from Holba et al. (1998a) Peak Name 1 13β,17α,20 S 24 nordiacholestane 2 13β,17α,20 R 24 nordiacholestane 3 13β,17α,20 S 27 nordiacholestane 4 13β,17α,20 R 27 nordiacholestane 5 5α,14α,17α,20 S 24 norcholestane 6 5α,14β,17β,20 R 24 norcholestane 7 5α,14β,17β,20 S 24 norcholestane 8 5α,14α,17α,20 R 24 norcholestane 9 21 norcholestane 10 5α,14α,17α,20 S 27 norcholestane 11 5α,14β,17β,20 R 27 norcholestane 12 5α,14β,17β,20 S 27 norcholestane 13 5α,14α,17α,20 R 27 norcholestane
5.3.4 Dinosterane ratio ((∑20R dinosteranes / (∑20R dinosteranes + 20R 3β methyl 24 ethylcholestane))
The use of C 30 methylsteranes as potential age specific biomarkers has been described by e.g. Summons et al., 1987; Goodwin et al., 1988; Moldowan & Talyzina, 1998. The dinosterane ratio used by Baseline Resolution Inc. in their definition is in coherence with the dinosterane ratio that was defined by Moldowan et al. (1998) as: ∑20R dinosteranes / (∑20R dinosteranes + 20R 3β methyl 24 ethylcholestane). The definition used by Baseline Resolution Inc. is as follows: DS4aSS20R+DS4aSR20R+DS4aRR20R+DS4aRS20R/ (S303MaaaR+DS4aSS20R+ DS4aSR20R+DS4aRR20R+DS4aRS20R) The dinosterane ratio of Moldowan et al. (1998) was used by Holba et al. (1998a) and shown to be a useful parameter for source age determination. Very low values are expected for Paleozoic derived oils and high values for Triassic or younger derived oils (Summons et al., 1987; Moldowan et al., 1996, 1998). Dinosteranes are originated from sterols of dinoflagellates bearing a dinosterane carbon skeleton (Withers, 1987; Volkman et al., 1993) that had a bloom in the Late Triassic (Summons et al., 1992; Moldowan et al., 1996) (fig.5 12), hence the high values for Triassic or younger derived oils. Dinosteranes are saturated dinosteroids (Moldowan et al., 1998) that are A ring methylated steranes and in fact 4 methyl steranes (Summons & Capon, 1988, Chapter 5. Interpretation parameters 55
1991). The 4 methyl steranes that make up the dinosteranes used in the dinosterane ratio are the 4α, 23, 24 trimethylcholestanes. The dinosterane ratio also accounts for the presence of another C30 methylsterane, namely (20R) 3β methyl 24 ethylcholestane or (20R) 3β methylstigmastane. Microbial alkylation of 2 steranes are thought to result in the formation of 3 methylstigmastene whereas the 2 steranes are produced during diagenesis from common desmethylsterols (Summons & Capon, 1988, 1991; Dahl et al., 1992).
The C 30 methylsteranes are quantified by calculating the areas of peaks in the m/z = 414 → 231 mass chromatogram showed in figure 5 15. The identification names of the relevant peaks of C 30 methylsteranes are given in table 5 10 and the structure of dinosteranes and 3 β methyl 24 ethylcholestane are showed in figure 5 16.
5
3 1 4 2
Figure 5 15. Representative parent → daughter (m/z = 414 → 231) mass chromatogram of C 30 methylsteranes for sample NZS 137 given as an example of peak identification. See table 5 10 for peak identification names of C30 methylsteranes.
Table 5 10. Peak identification names and abbreviations of C 30 methylsteranes. Peak Name Abbreviation 1 4α,23S,24S trimethyl 20R cholestane DS4 αSS20R 2 4α,23S,24R trimethyl 20R cholestane DS4αSR20R 3 4α,23R,24R trimethyl 20R cholestane DS4αRR20R 4 4α,23R,24S trimethyl 20R cholestane DS4αRS20R 5 3β Methyl 5a,14a,17a stigmastane 20R S303MαααR
Chapter 5. Interpretation parameters 56
Figure 5 16. Structure of dinosterane (left) and 3 β methyl 24 ethylcholestane (right). Modified from Holba et al. (2003.)
Chapter 6. Results 57
6. Results
In this chapter, data collected from GC MS and GC MS MS analysis for the age determination of the Novaya Zemlya samples and GC MS MS analysis of the oil samples will be presented in forms of tables. The relevant chromatograms of the Novaya Zemlya samples from GC FID, GC MS and GC MS MS analysis will be presented at the end of this chapter. The chromatograms for the oil samples are given in the appendix as they will not be evaluated further in this study. The results presented here are the foundations for the discussion in next chapter (see chapter 7). The outline of this chapter is as follows:
6.1 GC MS 6.2 GC MS MS 6.3 Chromatograms 6.3.1 GC FID and GC MS chromatograms 6.3.2 GC MS MS chromatograms Chapter 6. Results 58
6.1 GC MS
Table 6 1 gives an overview of the analysed samples from GC MS and the parameters of interest. All values are based on measured heights of the different identified peaks in the chromatograms produced from the GC MS analysis (see chapter 6.3). The relevant parameters concerning facies, maturity and age determining biomarkers are then calculated from the measured peak heights.
Table 6 1. Results from GC MS analysis showing peak and parameter interpretations. See chromatograms (chapter 6.3) for detailed peak identification.
Sample C27 ββS C28 ββS C29 ββS C27 ββS C28 ββS C29 ββS Number (mm) (mm) (mm) [%] [%] [%] C28 /C 29 120.611 118 50 25 61 26 13 2. 00 NZS 137 120 73 63 47 29 25 1.16 NZS 185 116 54 51 52 24 23 1.06 NZS 225 121 56 45 55 25 20 1.24 NZS 255 125 73 69 47 27 26 1.06 NZV 232 122 53 47 55 24 21 1.13
Table 6 1 Cont. Results from GC MS analysis showing peak and parameter interpretations. See chromatograms (chapter 6.3) for detailed peak identification. Oleanane Index Sample 30αβ Number O (mm) (mm) Olea/(Olea+30αβ) 120611 43 132 0. 25 NZS 137 23 152 0.13 NZS 185 12 124 0.09 NZS 225 15 122 0.11 NZS 255 14 157 0.08 NZV 232 13 112 0.10
6.2 GC MS MS
Table 6 2 and 6 3 give an overview of the analysed samples from GC MS MS and the parameters of interest. All values are based on measured peak heights or quantified areas of the different identified peaks on the chromatograms produced from the GC MS MS analysis (see chapter 6.3). Chapter 6. Results 59
Table 6 2. Results from GC MS MS analysis of the Novaya Zemlya samples showing
the values of the parameters of interest. Notice higher values of the C28 /C 29 ratio and the oleanane index for all samples compared to the GC MS results in table 6 1. See chromatograms (chapter 6.3) for detailed peak identification. NM = not measurable. Dinosterane Oleanane Index 27ββS Sample Number NDR NCR ratio [%] 28ββS [%] 29ββS [%] C28 /C 29 Olea/(Olea+30αβ) 120.611 0.44 0.62 NM 55.9 30.1 14.1 2.13 0.31 NZS 137 0.28 0.41 0.26 47.6 31.1 21.3 1.46 0.21 NZS 185 0.24 0.41 0.37 47.4 28.9 23.7 1.22 0.15 NZS 225 0.26 0.42 0.35 56.4 27.1 16.5 1.64 0.18 NZS 255 0. 49 0. 46 0. 39 42. 9 31. 1 26. 0 1. 20 0. 15 NZV 232 0. 22 0. 41 0. 33 48. 5 28. 6 22. 9 1. 25 0. 17
Table 6 3. Results from GC MS MS analysis of the oil samples showing the values of
the parameters of interest. Notice much lower values of the C28 /C 29 ratio compared to the values for the Novaya Zemlya samples in table 6 1 and 6 2. The relevant chromatograms are given in the appendix. NM = not measurable. Dinosterane Oleanane Index Sample 27ββS 28ββS 29ββS Number NDR NCR ratio [%] [%] [%] C28 /C 29 Olea/(Olea+30αβ) 7120/6 1 0.21 0.35 0.32 31.4 26.1 42.5 0.61 NM 7122/7 1 0.22 0.37 NM 33.0 25.7 41.3 0.62 NM 7124/3 1 0. 23 0. 36 NM 36. 3 26. 7 37. 0 0. 72 NM 7124/4 1 0.21 0.36 NM 34.3 26.3 39.3 0.67 NM 7128/04 1 DST2 0.27 0.49 NM 46.3 21.5 32.2 0.67 NM 7128/04 1 DST1 0.31 0.43 NM 45.7 25.8 28.5 0.91 NM 7228/07 1A 0.26 0.45 NM 30.4 25.4 44.2 0.57 NM NSO 1 0.21 0.38 0.46 35.4 31.6 33.0 0.96 NM Chapter 6 60
6.3 Chromatograms
The relevant chromatograms from GC FID, GC MS and GC MS MS analysis will be presented here. Table 6 4 shows the peak identification names for GC FID and GC MS chromatograms and table 6 5 for GC MS MS chromatograms.
Table 6 4. Peak identification names for GC FID and GC MS chromatograms . Peak Component
n C17 n heptadecane Pr pristane
n C18 n octadecane Ph phytane UCM Unresolved Complex Mixture 23/3 23 tricyclic terpane 24/3 24 tricyclic terpane 25/3 25 tricyclic terpane peak doublet 28/3 28 tricyclic terpane peak doublet 29/3 29 tricyclic terpane peak doublet Ts 18(α) 22,29,30 trisnorneohopane Tm 17(α) 22,29,30 trisnorhopane 29αβ 17α(H),21β(H) 30 norhopane O 18α(H)+18α(H) oleanane 30αβ 17α(H),21β(H) hopane
C27 ββS 5α(H), 14β(H), 17β(H), 20(S) cholestane
C28 ββS 24 methyl 5α(H), 14β(H), 17β(H), 20(S) cholestane
C29 ββS 24 ethyl 5α(H), 14β(H), 17β(H), 20(S) cholestane
Chapter 6 61
6.3.1 GC FID and GC MS chromatograms
Novaya Zemlya samples 120.611
mVolts
80 120.611 SAT 20-Feb-2009 GC FID 120611S m/z =SIR 191 of 15 Channels EI+ 191.18 100 23/3 1.24e6 70 24 /3 60
50
40
% 30 25 /3 n C18
20 Ph n C17 10 Pr UCM 60 retention time 90
0
-8 10 20 30 40 50 60 5 rt Minutes 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000
120.611 SAT 20-Feb-2009 C27 steranes 120611S Ts SIR of 15 Channels EI+ m/z = 217 m/z = 191 191.18 100 2.95e5 120.611 SAT 20-Feb-2009 120611S SIR of 15 Channels EI+ 217.20 100 28 /3 29α β C27 diasteranes 4.18e5 30α β 29 /3 Tm
C28 steranes % %
O Homohopanes C29 steranes
21 rt 7 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000
120.611 SAT 20-Feb-2009 120611S m/zSIR = of 15 218Channels EI+ 218.20 100 4.97e5
C27 ββS
%
C28 ββS
C29 ββS
6 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 Figure 6 1. GC FID and the relevant GC MS mass chromatograms for sample 120.611. From top left to bottom right; GC FID, GC MS mass fragmentograms m/z = 191 (terpane biomarkers), m/z = 191 (60 90 min retention time), m/z = 217 and m/z = 218 (sterane biomarkers). Peak identifications are given in table 6 4. Chapter 6 62
NZS 137
mVolts
70 NZS-137 SAT 26-Feb-2009 GC FID NZS137S m/z = SIR191 of 15 Channels EI+ 191.18 n C18 100 60 23/3 1.02e6
n C17
50
40 Ph 30 Pr 24 /3 %
20
10 25 /3 60 retention time 90
0 UCM
-7 10 20 30 40 50 60 5 rt Minutes 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000
NZS-137 SAT 26-Feb-2009 NZS137S SIR of 15 Channels EI+ β 191.18 C steranes 100 30α 27 m/z = 1912.18e5 NZS-137 SAT m/z = 21726-Feb-2009 NZS137S SIR of 15 Channels EI+ 217.20 100 29α β 1.06e5
C27 diasteranes C28 steranes
29 /3 C29 steranes % Tm Homohopanes 28 /3 % Ts
O
24 rt 28 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000
NZS-137 SAT 26-Feb-2009 NZS137S m/z SIR= of 15218 Channels EI+ 218.20 100 1.23e5
C27 ββS
% C28 ββS
C29 ββS
22 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 Figure 6 2. GC FID and the relevant GC MS mass chromatograms for sample NZS 137. From top left to bottom right; GC FID, GC MS mass fragmentograms m/z = 191 (terpane biomarkers), m/z = 191 (60 90 min retention time), m/z = 217 and m/z = 218 (sterane biomarkers). Peak identifications are given in table 6 4. Chapter 6 63
NZS 185
m Volts
NZS-185 SAT 20-Feb-2009 NZS185S SIR of 15 Channels EI+ 191.18 100 23/3 GC FID m/z = 191 3.55e6 100 n C18
n C17 75 Ph
50 Pr % 24 /3
25 UCM 25 /3 60 retention time 90
0
-12 10 20 30 40 50 60 2 rt Minutes 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000
NZS-185 SAT 20-Feb-2009 C27 steranes NZS185S SIR of 15 Channels EI+ 191.18 100 29α β 7.04e5 m/z = 191 NZS-185 SAT m/z = 21720-Feb-2009 NZS185S SIR of 15 Channels EI+ 217.20 100 2.98e5 30α β
C27 diasteranes C28 steranes
% Ts Tm C steranes % 29 28 /3 29 /3 Homohopanes
O
9 rt 11 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000
NZS-185 SAT 20-Feb-2009 NZS185S SIR of 15 Channels EI+ m/z = 218218.20 100 3.67e5
C27 ββS
%
C28 ββS C29 ββS
8 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 Figure 6 3. GC FID and the relevant GC MS mass chromatograms for sample NZS 185. From top left to bottom right; GC FID, GC MS mass fragmentograms m/z = 191 (terpane biomarkers), m/z 191= (60 90 min retention time), m/z = 217 and m/z = 218 (sterane biomarkers). Peak identifications are given in table 6 4. Chapter 6 64
NZS 225
m Volts 100 n C18 GC FID NZS-225SAT m/z = 19126-Feb-2009 NZS225S SIR of 15 Channels EI+ 191.18 n C17 100 23/3 3.04e6 Ph 75
Pr
50
% 24 /3
25 UCM 25 /3 60 retention time 90
0
-9 10 20 30 40 50 2 rt Minutes 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000
NZS-225SAT 26-Feb-2009 NZS225S SIR of 15 Channels EI+ C27 steranes 191.18 100 β 29α 2.23e5 m/z = 191 NZS-225SAT m/z = 21726-Feb-2009 NZS225S SIR of 15 Channels EI+ 217.20 100 1.16e5 30α β C27 diasteranes
Ts Tm C28 steranes
% 28 /3 C29 steranes 29 /3 % Homohopanes
O
23 rt 24 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000
NZS-225SAT 26-Feb-2009 NZS225S m/zSIR of= 15 Channels218 EI+ 218.20 100 1.35e5
C27 ββS
%
C28 ββS
C29 ββS
19 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 Figure 6 4. GC FID and the relevant GC MS mass chromatograms for sample NZS 225. From top left to bottom right; GC FID, GC MS mass fragmentograms m/z = 191 (terpane biomarkers), m/z = 191 (60 90 min retention time), m/z = 217 and m/z = 218 (sterane biomarkers). Peak identifications are given in table 6 4. Chapter 6 65
NZS 255
mVolts
NZS-255 SAT 20-Feb-2009 NZS255S SIR of 15 Channels EI+ GC FID m/z = 191191.18 100 125 23/3 1.84e6
100
n C18
75
n C17 % 50 24 /3 Ph 25 Pr 25 /3 60 retention time 90 0 UCM
-14 10 20 30 40 50 60 3 rt Minutes 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000
NZS-255 SAT 20-Feb-2009 NZS255S SIR of 15 Channels EI+ 191.18 C27 steranes 100 m/z = 217 29α β 30α β m/z = 1913.33e5 NZS-255 SAT 20-Feb-2009 NZS255S SIR of 15 Channels EI+ 217.20 100 1.38e5
C27 diasteranes
C28 steranes Tm C29 steranes % 29 /3 Homohopanes % 28 /3 Ts
O
17 rt 22 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000
NZS-255 SAT 20-Feb-2009 NZS255S m/zSIR of= 15 Channels218 EI+ 218.20 100 1.61e5
C27 ββS
% C28 ββS C29 ββS
17 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 Figure 6 5. GC FID and the relevant GC MS mass chromatograms for sample NZS 255. From top left to bottom right; GC FID, GC MS mass fragmentograms m/z = 191 (terpane biomarkers), m/z = 191 (60 90 min retention time), m/z = 217 and m/z = 218 (sterane biomarkers). Peak identifications are given in table6 4. Chapter 6 66
NZV 232 n C18 mVolts Ph 250 n C17 NZV-232 SAT 26-Feb-2009 NZV232 SIR of 15 Channels EI+ 191.18 100 23/3 7.33e6 200 Pr
150
100 % 24 /3 50 UCM 25 /3 60 retention time 90 0
-22 10 20 30 40 50 60 1 rt Minutes 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000
NZV-232 SAT 26-Feb-2009 NZV232 SIR of 15 Channels EI+ 29α β 191.18 C27 diasteranes 100 4.62e5 NZV-232 SAT 26-Feb-2009 NZV232 C27 steranes SIR of 15 Channels EI+ 217.20 100 2.37e5
30α β Tm Ts C28 steranes % 28 /3 29 /3 % C29 steranes Homohopanes
O
10 rt 12 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000
NZV-232 SAT 26-Feb-2009 NZV232 SIR of 15 Channels EI+ 218.20 100 2.79e5
C27 ββS
%
C28 ββS
C29 ββS
10 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 Figure 6 6. GC FID and the relevant GC MS mass chromatograms for sample NZV 232. From top left to bottom right; GC FID, GC MS mass fragmentograms m/z = 191 (terpane biomarkers), m/z = 191 (60 90 min retention time), m/z = 217 and m/z = 218 (sterane biomarkers). Peak identifications are given in table 6 4.
Chapter 6 67
6.3.2 GC MS MS chromatograms
Novaya Zemlya samples 120.611
6 3 4 1 7 9 5 8 10 11 2 12 13
Figure 6 7. Representative parent → daughter (m/z = 358 → 217) mass chromatogram of C 26 steranes for sample 120.611. See table 5 9 for peak identification names of 24 norcholestanes.
5
1 3 2 4
Figure 6 8. Representative parent → daughter (m/z = 414 → 231) mass chromatogram of C 30 methylsteranes for sample 120.611. See table 5 10 for peak identification names of C 30 methylsteranes. The concentration of the dinosteranes was too low to be measured but the expected locations of the relevant peaks are shown. Chapter 6 68
NZS 137
9
3 10 13 4 11 12 8 6 7
1 2 5
Figure 6 9. Representative parent → daughter (m/z = 358 → 217) mass chromatogram of C 26 steranes for sample NZS 137. See table 5 9 for peak identification names of 24 norcholestanes.
5
1 3 2 4
Figure 6 10. Representative parent → daughter (m/z = 414 → 231) mass chromatogram of C 30 methylsteranes for sample NZS 137. See table 5 10 for peak identification names of C 30 methylsteranes. Chapter 6 69
NZS 185
9
11 13 10 3 4 12 6 7 8 1 2 5
Figure 6 11. Representative parent → daughter (m/z = 358 → 217) mass chromatogram of C 26 steranes for sample NZS 185. See table 5 9 for peak identification names of 24 norcholestanes.
5
1 3 2 4
Figure 6 12. Representative parent → daughter (m/z = 414 → 231) mass chromatogram of C 30 methylsteranes for sample NZS 185. See table 5 10 for peak identification names of C 30 methylsteranes.
Chapter 6 70
NZS 225
3 9 4
11 10 13 12
1 6 8 7 2 5
Figure 6 13. Representative parent → daughter (m/z = 358 → 217) mass chromatogram of C 26 steranes for sample NZS 225. See table 5 9 for peak identification names of 24 norcholestanes.
5
3 1 4 2
Figure 6 14. Representative parent → daughter (m/z = 414 → 231) mass chromatogram of C 30 methylsteranes for sample NZS 225. See table 5 10 for peak identification names of C 30 methylsteranes.
Chapter 6 71
NZS 255
9 1 4 3 10 11 13 2 5 8 12 6 7
Figure 6 15. Representative parent → daughter (m/z = 358 → 217) mass chromatogram of C 26 steranes for sample NZS 255. See table 5 9 for peak identification names of 24 norcholestanes.
5
3 1 2 4
Figure 6 16. Representative parent → daughter (m/z = 414 → 231) mass chromatogram of C 30 methylsteranes for sample NZS 255. See table 5 10 for peak identification names of C 30 methylsteranes.
Chapter 6 72
NZV 232
3
4 9 11 10 13 12 1 6 2 7 8 5
Figure 6 17. Representative parent → daughter (m/z = 358 → 217) mass chromatogram of C 26 steranes for sample NZV 232. See table 5 9 for peak identification names of 24 norcholestanes.
5
1 3 2 4
Figure 6 18. Representative parent → daughter (m/z = 414 → 231) mass chromatogram of C 30 methylsteranes for sample NZV 232. See table 5 10 for peak identification names of C 30 methylsteranes.
Chapter 7. Discussion 73
7 Discussion
In this chapter the results of van Koeverden et al. (submitted) from Iatroscan analysis, i.e. the generation potential, migrated hydrocarbons and organic fractions of the Novaya Zemlya samples, the origin and maturity of migrated hydrocarbons (depositional environment), biodegradation (sub surface degradation processes) of the source rock, evidence of several generations of petroleum based on the GC Fid and GC MS analysis and the age determination of the analysed samples from the GC MS and GC MS MS data will be discussed. A large part of this chapter (chap. 7.1 – 7.6) is based on the raw existing data from the ongoing PhD project of Jan Hendrik van Koeverden and the entirely new data on age specific biomarkers are presented here. The data for this discussion is presented in the form of tables and figures in the previous chapter and in this chapter. The outline of this chapter is as follows:
7.1 Hydrocarbon generation potential 7.2 Evidence for migrated hydrocarbons 7.3 The organic fractions (saturated, aromatic and polar hydrocarbons) 7.4 Origin and maturity of the migrated hydrocarbons 7.5 Biodegradation 7.6 Several generations of petroleum 7.7 Age determination
Chapter 7. Discussion 74
7.1 Hydrocarbon generation potential
The measured TOC (total organic carbon) content, hydrogen index (HI) and oxygen index (OI) from TOC and Rock Eval pyrolysis presented by van Koeverden et al. (submitted) of the 6 Novaya Zemlya samples considered in this study are given in table 7 1. The TOC values range from 0.63 to 4.55 %, where 0.5 % is accepted to be the lower limit for shale source rocks (North, 1985), and therefore all of the examined samples contain sufficient organic carbon for further investigations of petroleum potential.
Table 7 1. Total Organic Carbon (TOC) content, Hydrogen Index (HI) and Oxygen Index (OI) for the Novaya Zemlya samples. Sample TOC Number [%] HI OI 120.611 0.63 5 35 NZS 137 4.38 n.d. n.d. NZS 185 1.78 6 10 NZS 225 1.79 6 7 NZS 255 1.11 2 12 NZV 232 4.55 1 8
The hydrogen and oxygen indices range from 1 to 6 and 7 to 35, i.e. very low values, respectively (table 7 1 and figure 7 1), and thus indicate that the remaining kerogen is of type III or IV. The samples are depleted in both hydrogen and oxygen and the source rock potential of the samples is therefore very low in fact nil. These results indicate high maturities of the source rocks, i.e. that the initial source rock potential has been fully utilized as oil and/or gas has already been generated and expelled, but another possibility could also exist. The organic carbon could be so called non generative “dead carbon”, organic matter that has been re deposited and preserved. This would severely diminish the hydrocarbon potential due to e.g. oxidation during re deposition. The TOC can however, still be substantial but the results of Stemmerik and Mørk (1992) points to overmature conditions of the Novaya Zemlya strata. They measured vitrinite reflectance values for Upper Devonian and Carboniferous strata to be in the range of R0 = 1.9 to 4.0 % and for Lower Permian to Upper Permian to be in the range of R0 = 1.9 to 2.5 %. These results clearly indicate that very high maturities are the cause of the lack of remaining petroleum generation potential.
Chapter 7. Discussion 75
Figure 7 1. Modified Van Krevelen Diagram, cross plotting the hydrogen index (Hi) vs. the oxygen index (OI). Nearly no remaining hydrocarbon generation potential is indicated for the examined samples. Note the very low numbers for the samples from the Matotchkin Strait considered in this study. Modified from van Koeverden et al. (submitted).
The samples from Novaya Zemlya are surface samples that were taken mostly for palaeontological purposes by Olav Holtedahl and therefore these samples might have been altered to some extent by weathering ( i.e. Fischer et al., 2007). It is not certain if the specimens were selected with the lowest possible degree of weathering and it also must be taken into account that it cannot be inferred from Rock Eval pyrolysis alone whether the hydrocarbon potential was present at an earlier time. Therefore additional in depth analysis needs to be done before the hydrocarbon potential of the analysed strata is extrapolated into the adjacent basinal areas. Still, the samples are overmature and the low HI and OI can only be due to this fact. Chapter 7. Discussion 76
7.2 Evidence for migrated hydrocarbons
The results obtained by van Koeverden et al. (submitted) from Rock Eval analysis of the samples (table 7 2) from Novaya Zemlya indicate that the hydrocarbons found are in fact migrated petroleum. The PI values are very high for the sample set reaching up to 0.93 for
NZV 232, while the TOC (table 7 1) and the S 2 values (table 7 2) are generally low, which points to unusual processes. The production indices (PI) (table 7 2) are very high and a PI of more than 0.4 indicate migrated petroleum, a migration avenue or a discovery in many case studies. Thus it is clear that migration of externally generated allochthonous hydrocarbons into the area of the analysed strata is the most likely reason for the elevated PI values.
Table 7 2. Results from Rock Eval analysis.
Sample S1 [mg HC/g S2 [mg HC/g S3 [mg HC/g Number rock rock rock PI 120.611 0.21 0.03 0.22 0.88 NZS 137 0.22 n.d. n.d. n.d. NZS 185 0.36 0.1 0.18 0.78 NZS 225 0.37 0.1 0.12 0.79 NZS 255 0.24 0.02 0.13 0.92 NZV 232 0.8 0.06 0.36 0.93
Generation and migration of the petroleum at or near to Novaya Zemlya are more likely to have occurred from the Kara Sea rather than the Barents Sea according to van Koeverden et al. (submitted). They base that idea on the fact that significant longer migration distances would have to be covered, if originated from the Barents Sea, and also that the in between lying Admiralty High constitute an obstacle to migration from the Barents Sea. They add, however, that a contribution from the Barents Sea side cannot be excluded, and one must remember that the geometric relationship in the past could have been different from that of today. Chapter 7. Discussion 77
7.3 The organic fractions (saturated, aromatic and polar compounds)
The percentages and distributions of the organic fractions, saturated hydrocarbons, aromatic hydrocarbons and polar compounds, i.e. resins and asphaltenes, determined by van Koeverden et al. (submitted) are given in table 7 3 and figure 7 3. These percentages of the organic fractions of extracts or oils are often used for correlation purposes. The results show that all the samples contain a low percentage of aromatic hydrocarbons (< 20%) which may be related to removal of water soluble aromatics by water washing with a more varied distribution of the saturated and polar components.
Table 7 3. Organic fractions of the analysed samples. Sample SAT ARO POL Total extract Number [%] [%] [%] SAT/ARO [mg/g rock] 120.611 68 5 27 14.7 0.37 NZS 137 63 4 33 15.8 0.50 NZS 185 64 10 25 6.2 1.38 NZS 225 62 9 29 6.8 1.31 NZS 255 48 5 47 10.7 0.71 NZV 232 71 14 15 5.1 2.83
Figure 7 3. Distribution of saturated, aromatic and polar (NSO) compounds of the rock extracts. The low amount (< 20%) of aromatic compounds is observed in all samples. Clear regional differences in the composition are not apparent. The large variability in the percentage of saturated hydrocarbons and polar compounds is mainly attributed to different levels of water washing and biodegradation. From van Koeverden et al. (submitted).
Chapter 7. Discussion 78
The variability of the amount saturated hydrocarbons can have different reasons. Surface samples with variation in the amount of saturated hydrocarbons, like these in this sample set from Novaya Zemlya, should not be used for e.g. correlation purposes without double checking with other parameters like biomarkers or stable carbon isotopes. This is because any kind of bacterial activity, sub surface biodegradation or weathering processes, will preferably deplete n alkanes and saturated hydrocarbons before attacking other compound classes. The ratio of saturated to aromatic hydrocarbons is often applied to assess the maturity of the related source rock during preceding hydrocarbon generation and expulsion ( e.g. primary migration). The extracted hydrocarbons of the Novaya Zemlya samples are assumed migrated and not generated in-situ. This results in the saturated to aromatic ratio giving information about the maturity of the corresponding source rock that generated the hydrocarbons and not the maturity of the analysed rock sample itself. The ratios of saturated to aromatic hydrocarbons are very high because of the low percentage of aromatic hydrocarbons (table 7 3). This ratio increases with maturity of a petroleum and the high ratios of the sample set therefore match with the findings from the pyrolysis analyses of the in-situ kerogen (see chapter 7.1). The results of van Koeverden et al. (submitted) show that the samples from the Matotchkin Strait and the Serebryanka Fjord locations (in the southern and central parts of Novaya Zemlya) have a slightly higher maturity then the rest of their analysed samples. Those results indicate that the thermal stress has been higher in the southern and central parts of the greater Novaya Zemlya region, including the adjacent sedimentary basins in the Barents and Kara Seas. These areas presumably contain the source rock from which the migrated hydrocarbons originate. The migration is however, assumed to have occurred either in distinct phases with in between degradational phases or continuously with accompanying biodegradation over a longer time. The ratio of saturated to aromatic hydrocarbons is very likely to have been influenced by different migration episodes of oils from possibly different source strata plus n alkane depleting biodegradation and associated water washing. These results should therefore be interpreted with care.
Chapter 7. Discussion 79
7.4 Origin and maturity of the migrated hydrocarbons
The results for the analysed samples used for maturity and depositional environment indications are given in table 7 4 and 7 5 and figures 7 4 to 7 9.
Table 7 4. GC FID and GC MS data for the analysed samples and δ13 C stable carbon isotope ratios from Iatroscan analysis by van Koeverden et al. (submitted) used for maturity and depositional environment indications. Sample MDBTs / δ13 C [‰] Number Pr/n C17 Ph/n C18 Pr/Ph MPs Ts/(Ts+Tm) %Rc extract 120.611 1.47 1.17 0.30 0.16 0.61 0.77 26.20 NZS 137 0.78 0.61 1.16 0.47 0.39 0.63 26.93 NZS 185 0.67 0.70 0.87 0.29 0.50 0.56 27.03 NZS 225 0.57 0.72 0.74 0.30 0.47 0.58 27.62 NZS 255 0.28 0.23 0.78 0.25 0.36 0.60 27.32 NZV 232 0.93 1.08 1.01 0.45 0.46 0.53 27.54
The ratios of pristane to the n-C17 alkane and phytane to the n-C18 alkane are often plotted in a logarithmic plot after Shanmugan (1985) (fig. 7 4). This plot suggests a marine shale with some influence of land plant derived organic matter as the source rock for the migrated hydrocarbons, containing a kerogen type II or III for all the analysed samples. The shift along the 45°axis seen in the plot is obviously due to biodegradation.
The C 27 , C 28 and C 29 ββ S steranes ratios (table 7 3) are plotted in a triangular plot (fig. 7 5) to indicate the depositional environment of the source rock (Huang & Meinshein, 1979; Shanmugan, 1985). This plot suggests a source rock containing only open marine organic matter. No lacustrine or terrigenous influence is indicated as the entire sample set plot in the lower most left corner. This implies an entirely marine source rock for the migrated hydrocarbons. However, there are evidences that contradict a purely marine source. Figure 7 4 suggests an organic matter with type II/III kerogen for the source rock, δ13 C stable carbon isotope ratios as heavy as 25.47 ‰ recorded in Iatroscan analysis by van Koeverden et al. (submitted) (fig. 7 6) and the occurrence of oleanane (fig. 6 1 to 6 6) in all the analysed samples indicates organic matter derived from land plants. Chapter 7. Discussion 80
Figure 7 4. Double logarithmic display of the ratios of pristane to the n-C17 alkane and phytane to the n-C18 alkane. Samples from the northern locations show more uniform values, while the southern locations (i.e., Matotchkin Strait) display a larger spread in biodegradation and maturity. Modified from van Koeverden et al. (submitted).
Figure 7 5. Ternary plot of the C 27 , C 28 and C 29 ββ S steranes (table 7 3), recorded on the m/z = 218 mass fragmentogram. No lacustrine or terrigenous influence is visible, inferring an entirely marine source rock. Modified from van Koeverden et al. (submitted).
Chapter 7. Discussion 81
The pristane/phytane ratio vs. δ13 C isotope ratios (e.g. Chung et al., 1992) are plotted together (fig. 7 6) to aid facies assessments. The δ13 C values for the analysed sample set are c. 2 ‰ heavier than for the North Sea oils reported by Chung et al. (1992). A marine source rock with only minor but different contributions of land plant derived organic matter is indicated as the range of which the parameters plot in is rather small and because of the heavier δ13 C values.
Figure 7 6. Cross plot of the pristane/phytane ratio vs. δ13 C values of the bulk extracts. From van Koeverden et al. (submitted).
The ratio of pristane / phytane (Pr/Ph) vs. the sum of methyldibenzothiphenes (MDBT) / the sum of methyl phenanthrenes (MP) (Hughes et al., 1995; Radke et a., 2001) are plotted together (fig. 7 7) to indicate the depositional facies of the source rock. This plot indicates a uniform source facies with no major input of terrigenous organic matter. All of the samples plot in the lower most left corner, in the fields of marine (anoxic) and marine facies. All the analysed samples have a recorded MDBT/MP ratio below 1 that indicates a carbonate free depositional environment (Hughes et al., 1995; Radke et al., 2001). There have been discussions about a possible Paleozoic carbonate source for the Western Barents Sea, but according to the results of van Koeverden et al. (submitted) there has not been found any indications for a carbonate source for the Novaya Zemlya samples. They have therefore Chapter 7. Discussion 82 restricted the hitherto unknown hydrocarbon source rock to a distal predominantly marine shale with organic matter of marine/planktonic origin deposited under anoxic to dysoxic conditions.
Figure 7 7. Cross plot of the ratios of pristane / phytane (Pr/Ph) vs. the sum of methyldibenzothiphenes (MDBT) / the sum of methyl phenanthrenes (MP) (Hughes et al., 1995; Radke et al., 2001). No influence from terrigenous or carbonate source rocks are indicated. All samples plot in the lowermost left fields, termed marine (anoxic) and marine. Hughes et al. (1995) initially called these fields lacustrine and marine/lacustrine, respectively. Since no other indicator for lacustrine influence can be found anywhere else in the data set, it is assumed that the very low Pr/Ph ratios are caused by strongly anoxic conditions during deposition and not freshwater organic matter. From van Koeverden et al. (submitted).
Maturity parameters can be seen on the plots in figures 7 4, 7 8 and 7 9. The plot in figure 7 4 shows a small variation in the maturity of the individual samples but does not directly indicate the different stages of maturity like the other plots in figure 7 8 and 7 9 do. The ratios of the terpane maturity parameter Ts/(Ts+Tm) vs. the calculated vitrinite reflectance (R c) are plotted together to rate advanced maturities (Seifert & Moldowan, 1978; Waples & Machiara, 1991; Radke, 1988). Both parameters in this plot indicates maturities corresponding to the early oil window or slightly below where the onset of the oil window is assumed to be at R o = 0.55 % and the end of it at R o = 1.30 %. These parameters are used together as the terpane parameter experiences full conversion at the end of the oil window and can therefore be indicative of the maturity corresponding to the defined oil window. Chapter 7. Discussion 83
These results should, albeit, interpreted with care as the samples show high amounts of tricyclic terpanes (figures 6 1 to 6 6). The terpane maturity parameter is most reliable when the hydrocarbons are from a common source rock (like evidences suggest for this data set) but the Ts/(Ts+Tm) values can be influenced by the coelution of Ts and Tm with tricyclic and tetracyclic terpanes. This would lead to a common peak on the m/z 191 mass chromatograms but as can be seen on figures 6 1 to 6 6 that is not the case in these samples.
The sterane maturity parameters C 29 20S/(20S + 20R) and C 29 ββ/(ββ/αα) (Seifert & Moldowan, 1986; Peters et al., 2005b) (table 7 5) plotted in figure 7 9 show maturities indicative of lower oil window for the migrated petroleum. At vitrinite reflectivity of R o = 0.9%, which represents mid oil window, both these sterane parameters their equilibrium. The
C29 20S/(20S + 20R) parameter has an equilibrium value of c. 0.53 to 0.55 and the
C29 ββ/(ββ/αα) parameter an equilibrium value of 0.68 to 0.71 at R o = 0.9%. Therefore, both these parameters also indicate a maturity for the data set in the lower oil window as most of the samples have values below the equilibrium values (table 7 5).
Figure 7 8. Cross plot of the ratios of 18 α(H) 22,29,30 trisnorneophane (Ts) and 17 α(H) 22,29,30 trisnorhopane (Tm) (Seifert & Moldowan, 1978; Waples & Machiara, 1991) vs. the calculated vitrinite reflection R c (Radke, 1988). The transition zone from immaturity into the lower oil window is indicated. All samples show approximately lower oil window maturity. From van Koeverden et al. (submitted). Chapter 7. Discussion 84
Table 7 5. Sterane ratios of the analysed samples. Sample Number 20S/(20S+20R) ββ/(ββ+αα) 120.611 0.56 0.58 NZS 137 0.50 0.57 NZS 185 0.53 0.58 NZS 225 0.52 0.58 NZS 255 0.49 0.55 NZV 232 0.52 0.58
Figure 7 9. Cross plot of the ratios of C 29 αααS/(C 29 αααS+C 29 ααR) steranes (20S/R) vs. C 29 ββ/(C 29 ββ+C 29 αα) steranes (ββ/αα) after Seifert and Moldowan (1986). The intervals of maximum conversion for the corresponding parameters are indicated. Increased 20S/R values may in this case be due to biodegradation of hydrocarbons, because the initial biological 20R isomer is preferably degraded through bacterial activity. This causes the samples to leave the linear maturity trend. From van Koeverden et al. (submitted).
7.5 Biodegradation
Biodegradation is the affect of bacterial activity on petroleum in that bacteria destroys the known patterns of typical alkane, isoprenoid and biomarkers from crude oils and source rocks. Biodegradation occurs under the following conditions; due to access to meteoric water Chapter 7. Discussion 85 with dissolved oxygen, water temperature below 70 80°C and in absence of hydrogen sulphide, H 2S (Milner et al., 1977; Connan, 1984; Ahsan, 1993). The results of biodegradation are the loss of long chained and unbranced components, like n alkanes which are most susceptible to biodegradation. This is followed by the removal of iso and anteiso alkanes, acyclic isoprenoids, steranes, terpanes, aromatics and finally polycyclic aromatics (Winters & Williams, 1969; Evans et al., 1971; Bailey et al., 1973; Chosson et al., 1992; Moldowan et al., 1992; Killops & Killops, 1993; Wenger & Isaksen, 2002; Head et al., 2003). The effect of biodegradation is easily recognisable with all the major n alkane components missing and the characteristic appearance of a hump, the unresolved complex mixture (UCM). The UCM consists of products of the biodegradation and bio resistant compounds (Peters et al., 1999). All the samples in the sample set show evidence of biodegradation. This can be seen on the GC FID data (figs. 6 1 to 6 6 and fig. 7 10) where the Unresolved Complex Mixture (UCM) is apparent and the reduced n alkanes.
m Volts 250 n alkanes are
200 missing
150
100
50 UCM hump
0
-22 10 20 30 40 50 60 Minutes Figure 7 10. GC FID of sample NZV 232 showing clear evidence of biodegradation, the UCM hump and lack of n alkanes. The arrow indicates the area with missing n alkanes.
The results also show evidence of varying degrees of biodegradation. This is based on the maturity/biodegradation classification (fig. 7 4) which is much less uniform than the corresponding facies classification. As they assume a relatively uniform maturity they suggest that the variability on the maturity/biodegradation classification is mainly due to varying degrees of biodegradation. Chapter 7. Discussion 86
The samples also show signs for levels of more severe biodegradation. The notable dominance of tricyclic terpanes (Andres & Robinson, 1971) visible in the m/z = 191 mass chromatograms (fig. 6 1 to 6 6) is a clear evidence of that. The tricyclic terpanes have a relatively high robustness towards biodegradation, show high alteration and removal properties comparable to diasteranes. The dominance of tricyclic terpanes, which corresponds to a level of 9 on the scale of Hunt (1996) (table 7 6) or a level of 8 on the scale of Wenger & Isaksen (2002), therefore indicate severe biodegradation.
Table 7 6. The compositional changes during different stages of biodegradation and the extent of biodegradation. Modified from Hunt (1996). Level or rank Compositional changes Extent of biodegradation
1. n Alkanes C 1 to C 15 depleted Minor
2. Over 90% C 1 to C35 n alkanes gone Light 3. Isoalkanes, including isoprenoids, attacked; Moderate Alkylcyclohexanes and alkylbenzenes removed 4. Isoprenoid alkanes and methylnaphthalenes Moderate removed
5. C14 C16 bicyclic alkanes removed Extensive 6. 25 norhopane may be formed; steranes attacked Heavy with the smallest molecules first 7. Steranes gone; diasteranes unaffected Heavy 8. Hopanes attacked Very heavy 9. Hopanes gone; diasteranes attacked. Oleanane, Severe tricyclic terpanes and aromatic steroids survive 10. Diasteranes and tricyclic terpanes destroyed; Extreme aromatic steroids attacked; vandyl porphryins survive
Another parameter that shows signs, in this data set, of higher levels of biodegradation is the elevated percentage of C 29 ααα S steranes (table 7 5 and fig. 7 9). The ratio of
C29 αααS/(C 29 αααS+C 29 ααR) steranes (20S/(20S+20R) exceeds the equilibrium level of 55%, attainable by maturation of hydrocarbons alone in some of the samples of including sample 120.611, which also points to higher levels of biodegradation. The increased 20S/R values are due to biodegradation of hydrocarbons, because the initial biological 20R isomer is preferably degraded through bacterial activity (Seifert et al., 1984; Peters et al., 2005b). This alteration of steranes indicates extensive to severe levels of biodegradation.
Chapter 7. Discussion 87
7.6 Several generations of petroleum
According to the discussion in the preceding sections, evidence points to several migration and degradation events in the Novaya Zemlya samples. These evidences include the presence of both large amounts of UCM and short to medium chain length n alkanes at the same time. The presence of n alkanes most likely represents a recharge of petroleum into the system because, otherwise, they would have been degraded during the biodegradation event that is evident through the presence of the UCM. These n alkanes have arrived after the bacterial activity had stopped and thus indicate different charges of hydrocarbons. This therefore, also points to generation , migration and biodegradation events of regional significance. The low amounts of aromatic hydrocarbons in the samples suggest biodegradation associated with water washing. Increased levels of tricyclic terpanes, as mentioned earlier, are often attributed to high maturity ( e.g. van Graas, 1990). However, as the maturity for the sample set is determined to correspond to the lower oil window, the observed high levels of tricyclic terpanes are likely to be inherited from an earlier charge of oil rather than the one for which these maturities apply. It is, however, unclear whether the signature of increased 20S/R values, discussed above, originated from the same time as the described enrichment of the tricyclic terpanes or if it generates from a different degradation event. There are evidences for a final oil charge which suffered no recognisable degradation at all. This is indicated by the apparently unaltered spectrum of n alkanes. The presences of an undisturbed range of easily degradable n alkanes are even more remarkable due to the fact that the analysed samples are outcrop samples and this reflects the tight nature of these lithologies. The fact that only n alkanes up to n C25 can be seen on the GC FID chromatograms (fig. 6 1 to 6 6) suggests that the ungraded charge consists of a light oil or condensate. This is suggested by the visible range of biomarkers indicating the 33 αβ hopanes to be the largest homohopanes present. In addition, the C 27 homologues dominate the sterane spectrum (fig. 6 1 to 6 6 and fig. 7 5) and this point to undegraded oil because of the susceptibility of the C 27 steranes to biodegradation (Moldowan & Seifert, 1984). Therefore, based on these facts described above, one may exclude that a single and temporally limited charge of petroleum that contributed to these migrated hydrocarbons and I therefore conclude that the extracts are the remains of several episodes of migration and biodegradation with the last phase being a condensate. Chapter 7. Discussion 88
7.7 Age determination
The age determination of the sample set was attempted by looking at individual age specific biomarkers that give a suggested source age as well as looking at them together to get an even clearer indication of the age of the likely source. The use of age specific biomarkers and especially if used together have been proven to be very useful and powerful tools to differentiate the age of petroleum. The oleanane index uses the occurrence of oleanane as an indicator for source ages of hydrocarbons for an early Cretaceous or younger source as oleanane is a biomarker for angiosperm plants (Moldowan et al., 1994). Angiosperm plants had a major bloom during the Tertiary giving rise to high oleanane concentrations (Moldowan et al., 1994) as seen in the values for samples 120.611 and NZS 137. Nytoft et el. (2002) showed that undisputed angiosperm plant fossils are unknown prior to the Early Cretaceous, however Moldowan et al. (1994) did report two exceptions of identified oleanane in older samples. One was in a Middle Jurassic siltstone from western Siberia and the other in a Carboniferous (Pennsylvanian) coal ball. The oleanane index works best when the source is rather homogeneous as is likely the case for this sample set. The occurrence of oleanane is not in coelution with lupane as was reported by Nytoft et al. (2002) as this is a concern since oleanane tends to coelute with other components. These facts, and the higher measured oleanane indexes from GS MS MS analysis supports consideration that the occurrence of oleanane is a valid age determination parameter in this case.
A steady increase in the C 28 /C 29 sterane ratio with decreasing source age of oils were reported by Grantham & Wakefield (1988) and high ratios have been used to differentiate the age of oils and source rocks (Grantham & Wakefield, 1988; Schwark & Empt, 2006). This trend is due to an increase in the amount of C 28 steranes over C 29 steranes with time due to the emergence of dinoflagellates and coccolithosperes at the end of the Paleozoic and the appearance of silicoflagellates and diatoms in the Late Cretaceous (Grantham & Wakefield.
1988). The C28 /C 29 sterane ratio is assumed to be valid for purely marine rocks or oils sourced by marine strata (Huang & Meinschein, 1979). Therefore, as the hitherto unknown hydrocarbon source rock has been tentatively restricted by to a distal predominantly marine shale with organic matter of marine/planktonic origin, the use of the C28 /C 29 sterane ratio to constrain the source age has to be considered a valid application. Chapter 7. Discussion 89
The C 28 /C 29 ratios of the Novaya Zemlya samples are significantly higher (table 6 1 and 6 2) than compared to the values of the oil samples, where the most prolific source rock in the Hammerfest Basin is the Upper Jurassic Hekkingen Fm (Ohm et al., 2008) and the NSO 1 reference oil where the Upper Jurassic Kimmeridge Clay is the source rock. This clearly suggests a younger source for the Novaya Zemlya than that of the reference oil samples.
Oleanane Index
% C28 / % C29 ββs steranes Figure 7 11.Cross plot of the oleanane index (oleanane / (oleanane + C 30 αβ hopane)) (Moldowan et al., 1994) vs. the ratio of the percentage of C 28 ββS steranes to C 29 ββS steranes (Grantham & Wakefield, 1988; Schwark & Empt, 2006) from the GC MS results (table 6 1). This novel diagram facilitates the determination of the age of hydrocarbons, suggesting ages as young as Tertiary for the sample set. The reference oil samples do not have a measurable oleanane index and cannot therefore be plotted. The age limits for the sterane ratio are inferred from Grantham & Wakefield (1988, figure 4); the ones for the oleanane index are taken from Moldowan et al. (1994). Original diagram modified from van Koeverden et al. (submitted).
The use of the oleanane index and the C28 /C 29 sterane ratio in a common plot for the sample set (figures 7 11 and 7 12) show a very good constraint and grouping of the samples by suggested source age. The data from the GC MS analysis suggest a source age as young as Tertiary for sample 120.611 while the rest of the samples have suggested source age of Jurassic or younger (fig. 7 11). The more accurate GS MS MS analysis gives even higher values of both parameters (fig. 7 12) indicating that samples 120.611 and NZS 137 have a Tertiary source age. Sample NZS 225 now has a Cretaceous or younger source age while the rest of the samples still have a suggested source age of Jurassic or younger but have moved closer to the Cretaceous/Tertiary boundaries. Chapter 7. Discussion 90
Oleanane Index
% C28 / % C29 ββs steranes Figure 7 12. Cross plot of the oleanane index (oleanane / (oleanane + C 30 αβ hopane)) (Moldowan et al., 1994) vs. the ratio of the percentage of C 28 ββS steranes to C 29 ββS steranes (Grantham & Wakefield, 1988; Schwark & Empt, 2006) from the GC MS MS results (table 6 2). Notice higher values of both parameters for all samples compared to figure 7 11 suggesting even younger trends than gained from the less accurate GC MS data. This novel diagram facilitates the determination of the age of hydrocarbons, suggesting ages as young as Tertiary for the sample set. The reference oil samples do not have a measurable oleanane index and cannot therefore be plotted. The age limits for the sterane ratio are inferred from Grantham & Wakefield (1988, figure 4); the ones for the oleanane index are taken from Moldowan et al. (1994). Original diagram modified from van Koeverden et al. (submitted).
The 24 nordiacholestane ratio (NDR) and the 24 norcholestane ratio (NCR) have been described as useful biomarkers to identify source age of sediments or oils derived from Cretaceous or younger siliciclastic rocks (Holba et al., 1998a, 1998b). These ratios are powerful tools in differentiating the age and organic facies of oils because they are very systematic with geological age and are very useful when coupled with other age specific biomarkers. The ratios increase slightly in Jurassic samples and show a dramatic increase for both Cretaceous and Tertiary age organic matter (Holba et al., 1998a, 1998b). These increases in the 24 nordiacholestane and 24 norcholestane ratio in the Jurassic and Cretaceous are due to dinoflagellates expansion and the increase in the Tertiary is due to diatom expansion (Rampen et al., 2007). Holba et al. (1998a) showed that minor anomalous increase in the NDR and NCR may be caused by moderate to heavy biodegradation or low maturity in oils or source rocks. This has to be considered and thought of in this study as the sample set has been demonstrated to have been affected by some degree of biodegradation Chapter 7. Discussion 91 and as the extracts in general are of low maturity corresponding to the early oil window (see previous discussion). The NDR and NCR values for the Novaya Zemlya samples are shown in figures 7 13 and 7 14. The NDR and NCR values are higher in most of the samples compared to those of the known Jurassic derived oil samples (table 6 2 and 6 3), from the Hammerfest Basin and the NSO 1, showing that the Novaya Zemlya samples most likely have younger source age. The NDR suggests a Jurassic or younger source age for samples NZS 185 and NZV 232 while the other samples have a suggested source age of Cretaceous or younger. The NCR suggests a source age of Cretaceous or younger for all the samples except for sample 120.611 which has a suggested source age of Oligocene or younger. The value for sample 120.611 is only 0.01 above the limit to be classified as Oligocene or younger but it has to be considered that these ratios are facies dependent and can give a minor increase in biodegraded samples. It is therefore a possibility that sample 120.611 is showing a slightly enhanced value and, that the sample could, for these reasons, be classified within the Cretaceous or younger boundaries based on these observations.
Nordiacholestane Ratio (NDR) 24
Geologic Age (Ma) Figure 7 13. Cross plot of the 24 Nordiacholestane Ratio (NDR) (Holba et al., 1998a) vs. geologic age. The black whole lines outline the area which is regarded as the typical range of ratios for oils with age. The black dashed lines mark the representative NDR values for Jurassic or younger oils (>0.20), Cretaceous and younger oils (>0.25) and Oligocene and younger oils (>0.50). The black arrows indicate the age range of the possible source. Samples 120.611, NZS 137, NZS 225, NZS 255 have a suggested source age of Cretaceous or younger while NZS 185 and NZV 232 have a suggested source age of Jurassic or younger. The reference oil samples 7128/04 1 DST1, 7128/04 1 DST2 and 7228/07 1A have a suggested source age of Cretaceous or younger while the other oil samples have a Jurassic or younger suggested age. Original diagram modified from Holba et al. (1998a, 1998b). Chapter 7. Discussion 92
Norcholestane Ratio (NCR) 24
Geologic Age (Ma) Figure 7 14. Cross plot of the 24 Norcholestane Ratio (NCR) (Holba et al., 1998a ) vs. geologic age. The black whole lines outline the area which is regarded as the typical range of ratios for oils with age. The black dashed lines mark the representative NDR values for Jurassic or younger oils (>0.30), Cretaceous and younger oils (>0.40) and Oligocene and younger oils (>0.60). The black arrows indicate the age range of the source. Samples NZS 137, NZS 185 and NZV 232 all plot at the same spot and along with NZS 225 and NZS 255 have a suggested source age of Cretaceous or younger. Sample 120.611 has a suggested age of Oligocene or younger. The reference oil samples 7128/04 1 DST1, 7128/04 1 DST2 and 7228/07 1A have a suggested source age of Cretaceous or younger while the other oil samples have a Jurassic or younger suggested age. Original diagram modified from Holba et al. (1998a, 1998b).
The use of NDR and NCR coupled with other age specific biomarkers, the oleanane index (figures 7 15 and 7 16) and dinosterane ratio (figures 7 17 and 7 18) show, however, that the use of these ratios are valid age determination parameters as the age specific biomarkers from different biota, angiosperm land plants and marine algae, are advantageous in constraining the geologic age of the petroleum source. Any potential increases from the main trend in the NDR and NCR ratios of this sample set due to biodegradation or low maturity are therefore only considered minor as only one sample shows anomalously increased NCR. The cross plots of the oleanane index vs. the 24 Nordiacholestane ratio (NDR) from the GC MS MS data in figure 7 15 constrains the suggested source ages of samples 120.611 and NZS 137 to be Tertiary or younger while the rest of the sample are constrained to a Cretaceous or younger source age. The oleanane index is expected to be very high in Tertiary derived oils and moderate to low in Cretaceous or younger samples and generally zero in older geological samples (Moldowan et al., 1994) therefore one can exclude suggested Jurassic age by the NDR and constrain it to a younger age. Chapter 7. Discussion 93
Oleanane Index (OI)
24 Nordiacholestane Ratio (NDR) Figure 7 15. Cross plot of two age specific indicators, oleanane index (OI) vs. 24 Nordiacholestane (NDR) (Holba et al., 1998a) from GC MS MS data showing separation and grouping of the analysed samples by source age. The black dashed line represents the OI value of 0.2 that differentiates between Cretaceous and Tertiary derived oils while the light brown lines mark the representative NDR values for Jurassic or younger oils (>0.20), Cretaceous and younger oils (>0.25) and Oligocene and younger oils (>0.50). Samples 120.611 and NZS 137 have a suggested source age of Tertiary while the other samples have a constrained age of Cretaceous or younger. The suggestion of a Jurassic source can be excluded by the oleanane index. Original diagram modified from Holba et al. (1998a).
The cross plots of the oleanane index given by the GC MS MS data vs. the 24 Norcholestane Ratio (NCR) in figure 7 16 gives a suggested source age of Oligocene or younger for sample 120.611, sample NZS 137 has a suggested source age of Tertiary or younger, while the rest of the sample set has a suggested source age of Cretaceous or younger. Based on the indicated source age of Oligocene or younger from the NCR for sample 120.611 and the results of the cross plots of the NCR vs. the different age specific biomarkers there are at least clear indications of a Tertiary source age while it would be difficult to find further support for such a young source age as of Oligocene or younger. Chapter 7. Discussion 94
Oleanane Index (OI)
24 Norcholestane Ratio (NCR) Figure 7 16. Cross plot of the age specific indicators, oleanane index (OI) (Moldowan et al., 1994) data vs. 24 Norcholestane Ratio (NCR) (Holba et al., 1998a) from GC MS MS showing separation and grouping of the analysed samples by source age. The black dashed line represents the OI value of 0.2 that differentiates between Cretaceous and Tertiary derived oils while the light brown lines mark the representative NDR values for Jurassic or younger oils (>0,30), Cretaceous and younger oils (>0.40) and Oligocene and younger oils (>0.60). Sample 120.611 has a suggested source age of Oligocene or younger, sample NZS 137 has a suggested source age of Tertiary or younger, while the rest of the sample set has a suggested source age of Cretaceous or younger. Modified from Holba et al. (1998a).
The cross plots of the dinosterane ratio (Dino) vs. the NDR and NCR in figures 7 17 and 7 18 give the same suggested source ages as from the NDR and NCR as the dinosterane ratio does not constrain these results any further. High dinosterane ratios are expected for Triassic and younger derived oils while very low values are expected for Paleozoic and older derived oils (Summons et al., 1987; Moldowan et al., 1996, 1998). All the samples therefore have a suggested source age of Triassic or younger based on the dinosterane ratio. The dinosterane ratio is therefore most useful in grouping oils together by source age rather than constraining the source age further, at least in this case for the present data set. Chapter 7. Discussion 95
Dinosteraneratio (Dino)
24 Nordiacholestane Ratio (NDR) Figure 7 17. Cross plot of the dinosterane ratio (Dino) (Moldowan et al., 1998) vs. 24 Nordiacholestane Ratio (NDR) (Holba et al., 1998a) showing separation and grouping of the analysed samples by source age. High dinosterane ratio is expected for Triassic and younger derived oils while low values are expected for Paleozoic and older derived oils. The light brown lines mark the representative NDR values for Jurassic or younger oils (>0.20), Cretaceous and younger oils (>0.25) and Oligocene and younger oils (>0.50). All the samples have the same source age as suggested from the NDR as the dinosterane ratio does not constrain the source age further. Sample 120.611 does not have a measurable dinosterane ratio and is therefore not plotted. Only oil samples 7120/6 1 and NSO 1 have a measurable dinosterane ratio. Original diagram modified from Holba et al.(1998a).
Dinosteraneratio (Dino)
24 Norcholestane Ratio (NCR) Figure 7 18. Cross plot of the dinosterane ratio (Dino) (Moldowan et al., 1998) vs. 24 Norcholestane Ratio (NCR) (Holba et al., 1998a), showing separation and grouping of the analysed samples by source age. High dinosterane ratio is expected for Triassic and younger derived oils while low values are expected for Paleozoic and older derived oils. The light brown lines mark the representative NDR values for Jurassic or younger oils (>0.30), Cretaceous and younger oils (>0.40) and Oligocene and younger oils (>0.60). All the samples have the same source age as suggested from the NDR as the dinosterane ratio does not constrain the source age further. Sample 120.611 does not have a measurable dinosterane ratio and is therefore not plotted. Only oil samples 7120/6 1 and NSO 1 have a measurable dinosterane ratio. Original diagram modified from Holba et al. (1998a). Chapter 8. Conclusions 96
8 Conclusions
6 extracted oil samples from the Matotchkin Strait in Novaya Zemlya have been examined by gas chromatography – flame ionizing detector (GC FID), gas chromatography – mass spectrometry (GC MS) and gas chromatography – mass spectrometry – mass spectrometry (GC MS MS) analysis in order to determine their source rock facies and their source age based on age specific biomarkers.
The source rock facies for this sample set is inferred from GC FID and GC MS data to reflect a marine shale with some influence of land plant derived organic matter as the source rock for the migrated hydrocarbons is inferred to contain basically kerogen type II, with some type III. The land derived organic material is reflected by the occurrences of oleanane and from the heavy δ13 C stable carbon isotope ratios. Maturity indications from GC MS data correspond to the early oil window, this based on terpane maturity parameter vs. the calculated vitrinite reflectivity and sterane maturity parameters.
A possible source rock age of Cretaceous or younger for this sample set is suggested based on the occurrences of oleanane and high C 28 /C 29 ratios given by the GC MS data. More detailed data and measurements based on GC MS MS data result in even higher values for the oleanane index and the C28 /C 29 ratio, suggesting samples 120.611 and NZS 137 to have a Tertiary source age. Sample NZS 225 is indicated to have a Cretaceous or younger source age, while the rest of the samples (NZS 185, NZS 255 and NZV 232) have a suggested source age of Jurassic or younger, but these samples have moved closer to the Cretaceous/Tertiary boundaries, as compared to classification based on GC MS. The much more accurate data gained from GC MS MS data compared to those from GC MS analysis therefore give strong evidences to suggest that a source age of Cretaceous or younger is indeed correct.
Other age specific biomarkers from GC MS MS data were also considered and coupled together to restrict the possible source age. High values of 24 nordiacholestane ratio (NDR) and 24 norcholestane ratio (NCR) were observed, suggesting source ages from Jurassic or Chapter 8. Conclusions 97 younger, Cretaceous or younger to as young as Oligocene or younger. The obtained results of an Oligocene or younger source from the NCR for sample 120.611 is doubted as the value is just on the boundary between Cretaceous or younger and Oligocene or younger source age. This is also doubted because the samples have suffered some biodegradation and show evidence of low maturity as biodegradation and low maturity have been showed to possibly give minor increase in the NDR and NCR. A more likely source age of Cretaceous or younger is therefore suggested. The use of NDR and NCR coupled with other age specific biomarkers, the oleanane index and dinosterane ratio show that using age specific biomarkers from different biota, angiosperm land plants and marine algae, are advantageous in constraining the geologic age of the petroleum source. The cross plots of NDR and NCR vs. oleanane index constrain the suggested source age to Tertiary or younger for samples 120.611 and NZS 137 and Cretaceous or younger for the other 4 samples.
By coupling the oleanane index and the NDR/NCR it is possible to exclude a possible source age of Jurassic or younger as suggested by the NDR due to the fact that the oleanane index is expected to be generally zero in older samples than Cretaceous. The occurrence of oleanane alone, in the samples therefore contradicts a possible source age of Jurassic age. The cross plot of the dinosterane ratio and the NDR/NCR does not constrain the suggested source age any further as high dinosterane ratio is expected in Triassic or younger derived oils while low values are expected in Paleozoic derived oils. All the samples are therefore concluded to have a suggested source age of Triassic or younger from the dinosterane ratio, but the other age specific biomarkers constrain the age further to a suggested Cretaceous or younger, even a Tertiary source.
The results of this study made it clear that one must consider possible Cretaceous or younger, even Tertiary, source rocks based on a number of age specific biomarkers, both individually and as used in combination, concerning in the eastern Barents and the Kara Seas region. A further study of the same age specific biomarkers that were used in this study is recommended for the remaining 18 samples from the study of van Koeverden et al. (submitted) as the next step to investigate if the same results will also be obtained for the rest of the total 24 Novaya Zemlya samples with implications for also nearby regions. Chapter 8. Conclusions 98
A summary of the age determination of the sample set is given in table 8 1 showing the suggested source ages of each age specific parameter and the most likely source age for the sample set. Chapter 8. Conclusion 99
Table 8 1. Summary of the age determination of the sample set showing the suggested source ages of each age specific parameter and the most likely source age for the sample set. Sample Number 120.611 NZS 137 NZS 185 NZS 225 NZS 255 NZV 232 OI / 1 (C 28 /C 29 ) from Jurassic/Cretaceous Jurassic/Cretaceous/ Jurassic/Cretaceous Jurassic/Cretaceous Jurassic/Cretaceous GC MS Tertiary /Tertiary Tertiary /Tertiary /Tertiary /Tertiary OI / 2 (C 28 /C 29 ) from Jurassic/Cretaceous/ Jurassic/Cretaceous Jurassic/Cretaceous GC MS MS Tertiary Tertiary Tertiary Cretaceous/Tertiary /Tertiary /Tertiary Cretaceous Cretaceous or Cretaceous or Cretaceous or NDR or younger younger Jurassic or younger younger younger Jurassic or younger Oligocene Cretaceous or Cretaceous or Cretaceous or Cretaceous or Cretaceous or NCR or younger younger younger younger younger younger Dinosterane Triassic or ratio (Dino) younger Triassic or younger Triassic or younger Triassic or younger Triassic or younger Triassic or younger Cretaceous or Cretaceous or Cretaceous or Cretaceous or OI / NDR Tertiary Tertiary younger younger younger younger Oligocene Cretaceous or Cretaceous or Cretaceous or Cretaceous or OI / NCR or younger Tertiary younger younger younger younger Cretaceous or Cretaceous or Cretaceous or Dino / NDR NM younger Jurassic or younger younger younger Jurassic or younger Cretaceous or Cretaceous or Cretaceous or Cretaceous or Cretaceous or Dino / NCR NM younger younger younger younger younger Most likely Cretaceous or Cretaceous or Cretaceous or Cretaceous or source age Tertiary Tertiary younger younger younger younger
Referances 100
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APPENDIX
Appendix A GC FID chromatograms
113
120.611
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70
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-8 10 20 30 40 50 60 Minutes 114
NZS 137
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-7 10 20 30 40 50 60 Minutes 115
NZS 185
m Volts
100
75
50
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-12 10 20 30 40 50 60 Minutes 116
NZS 225
m Volts 100
75
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-9 10 20 30 40 50 Minutes 117
NZS 255
m Volts
125
100
75
50
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-14 10 20 30 40 50 60 Minutes 118
NZV 232
m Volts 250
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-22 10 20 30 40 50 60 Minutes 119
7120/6 1
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-26 10 20 30 40 50 60 70 Minutes 120
7122/7 1
m Volts
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-25 10 20 30 40 50 60 70 Minutes 121
7124/3 1
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-29 10 20 30 40 50 60 70 Minutes 122
7124/4 1
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100
75
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-16 10 20 30 40 50 60 70 Minutes 123
7128/4 1 DST1
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-37 10 20 30 40 50 60 70 Minutes 124
7128/4 1 DST2
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-34 10 20 30 40 50 60 70 Minutes 125
7228/7 1
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NSO 1
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Appendix B GC MS chromatograms
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120.611 SAT 20-Feb-2009 120611S SIR of 15 Channels EI+ 191.18 100 1.24e6
%
5 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 129
120.611 SAT 20-Feb-2009 120611S SIR of 15 Channels EI+ 191.18 100 2.95e5
%
21 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 130
120.611 SAT 20-Feb-2009 120611S SIR of 15 Channels EI+ 217.20 100 4.18e5
%
7 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 131
120.611 SAT 20-Feb-2009 120611S SIR of 15 Channels EI+ 218.20 100 4.97e5
%
6 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 132
120.611 ARO 04-Mar-2009 120611A SIR of 14 Channels EI+ 231.12 100 4.36e4
%
57 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 133
120.611 ARO 04-Mar-2009 120611A SIR of 14 Channels EI+ 253.20 100 3.97e4
%
67 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 134
120.611 ARO 04-Mar-2009 120611A SIR of 14 Channels EI+ 253.20+192.09 100 2.21e5
%
26 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 135
120.611 ARO 04-Mar-2009 120611A SIR of 14 Channels EI+ 198.05 100 7.94e4
%
38 120611A SIR of 14 Channels EI+ 192.09 100 1.92e5
%
15 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 136
NZS-137 SAT 26-Feb-2009 NZS137S SIR of 15 Channels EI+ 191.18 100 1.02e6
%
5 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 137
NZS-137 SAT 26-Feb-2009 NZS137S SIR of 15 Channels EI+ 191.18 100 2.18e5
%
24 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 138
NZS-137 SAT 26-Feb-2009 NZS137S SIR of 15 Channels EI+ 217.20 100 1.06e5
%
28 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 139
NZS-137 SAT 26-Feb-2009 NZS137S SIR of 15 Channels EI+ 218.20 100 1.23e5
%
22 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 140
NZS-137 ARO 04-Mar-2009 NZS137A SIR of 14 Channels EI+ 231.12 100 3.50e4
%
72 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 141
NZS-137 ARO 04-Mar-2009 NZS137A SIR of 14 Channels EI+ 253.20 100 3.08e4
%
86 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 142
NZS-137 ARO 04-Mar-2009 NZS137A SIR of 14 Channels EI+ 178.08+192.09 100 1.66e5
%
42 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 143
NZS-137 ARO 04-Mar-2009 NZS137A SIR of 14 Channels EI+ 198.05 100 1.29e5
%
23 NZS137A SIR of 14 Channels EI+ 192.09 100 6.90e4
%
43 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 144
NZS-185 SAT 20-Feb-2009 NZS185S SIR of 15 Channels EI+ 191.18 100 3.55e6
%
2 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 145
NZS-185 SAT 20-Feb-2009 NZS185S SIR of 15 Channels EI+ 191.18 100 7.04e5
%
9 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 146
NZS-185 SAT 20-Feb-2009 NZS185S SIR of 15 Channels EI+ 217.20 100 2.98e5
%
11 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 147
NZS-185 SAT 20-Feb-2009 NZS185S SIR of 15 Channels EI+ 218.20 100 3.67e5
%
8 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 148
NZS-185 ARO 04-Mar-2009 NZS185A SIR of 14 Channels EI+ 231.12 100 1.01e5
%
26 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 149
NZS-185 ARO 04-Mar-2009 NZS185A SIR of 14 Channels EI+ 253.20 100 4.83e4
%
57 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 150
NZS-185 ARO 04-Mar-2009 NZS185A SIR of 14 Channels EI+ 178.08+192.09 100 2.51e6
%
4 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 151
NZS-185 ARO 04-Mar-2009 NZS185A SIR of 14 Channels EI+ 198.05 100 3.81e5
%
11 NZS185A SIR of 14 Channels EI+ 192.09 100 6.66e5
%
5 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 152
NZS-225SAT 26-Feb-2009 NZS225S SIR of 15 Channels EI+ 191.18 100 3.04e6
%
2 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 153
NZS-225SAT 26-Feb-2009 NZS225S SIR of 15 Channels EI+ 191.18 100 2.23e5
%
23 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 154
NZS-225SAT 26-Feb-2009 NZS225S SIR of 15 Channels EI+ 217.20 100 1.16e5
%
24 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 155
NZS-225SAT 26-Feb-2009 NZS225S SIR of 15 Channels EI+ 218.20 100 1.35e5
%
19 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 156
NZS-225 ARO 04-Mar-2009 NZS225A SIR of 14 Channels EI+ 231.12 100 6.42e4
%
39 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 157
NZS-225 ARO 04-Mar-2009 NZS225A SIR of 14 Channels EI+ 253.20 100 3.76e4
%
70 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 158
NZS-225 ARO 04-Mar-2009 NZS225A SIR of 14 Channels EI+ 178.08+192.09 100 4.64e6
%
2 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 159
NZS-225 ARO 04-Mar-2009 NZS225A SIR of 14 Channels EI+ 198.05 100 5.58e5
%
8 NZS225A SIR of 14 Channels EI+ 192.09 100 1.23e6
%
3 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 160
NZS-255 SAT 20-Feb-2009 NZS255S SIR of 15 Channels EI+ 191.18 100 1.84e6
%
3 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 161
NZS-255 SAT 20-Feb-2009 NZS255S SIR of 15 Channels EI+ 191.18 100 3.33e5
%
17 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 162
NZS-255 SAT 20-Feb-2009 NZS255S SIR of 15 Channels EI+ 217.20 100 1.38e5
%
22 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 163
NZS-255 SAT 20-Feb-2009 NZS255S SIR of 15 Channels EI+ 218.20 100 1.61e5
%
17 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 164
NZS-255 ARO 04-Mar-2009 NZS255A SIR of 14 Channels EI+ 231.12 100 7.08e4
%
36 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 165
NZS-255 ARO 04-Mar-2009 NZS255A SIR of 14 Channels EI+ 253.20 100 5.38e4
%
50 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 166
NZS-255 ARO 04-Mar-2009 NZS255A SIR of 14 Channels EI+ 178.08+192.09 100 2.98e6
%
3 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 167
NZS-255 ARO 04-Mar-2009 NZS255A SIR of 14 Channels EI+ 198.05 100 4.17e5
%
9 NZS255A SIR of 14 Channels EI+ 192.09 100 8.10e5
%
4 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 168
NZV-232 SAT 26-Feb-2009 NZV232 SIR of 15 Channels EI+ 191.18 100 7.33e6
%
1 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 169
NZV-232 SAT 26-Feb-2009 NZV232 SIR of 15 Channels EI+ 191.18 100 4.62e5
%
10 rt 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 84.000 86.000 88.000 90.000 170
NZV-232 SAT 26-Feb-2009 NZV232 SIR of 15 Channels EI+ 217.20 100 2.37e5
%
12 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 171
NZV-232 SAT 26-Feb-2009 NZV232 SIR of 15 Channels EI+ 218.20 100 2.79e5
%
10 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 172
NZV-232 ARO 05-Mar-2009 NZV232A SIR of 14 Channels EI+ 231.12 100 1.53e5
%
17 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 173
NZV-232 ARO 05-Mar-2009 NZV232A SIR of 14 Channels EI+ 253.20 100 6.18e4
%
44 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 174
NZV-232 ARO 05-Mar-2009 NZV232A SIR of 14 Channels EI+ 178.08+192.09 100 2.61e7
%
1 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 175
NZV-232 ARO 05-Mar-2009 NZV232A SIR of 14 Channels EI+ 198.05 100 2.27e6
%
4 NZV232A SIR of 14 Channels EI+ 192.09 100 3.65e6
%
1 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 176
7120/6-1 DST2 SAT 27-Feb-2009 20-6-1S SIR of 15 Channels EI+ 191.18 100 7.89e5
%
6 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 177
7120/6-1 DST2 SAT 27-Feb-2009 20-6-1S SIR of 15 Channels EI+ 217.20 100 2.06e5
%
16 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 178
7120/6-1 DST2 SAT 27-Feb-2009 20-6-1S SIR of 15 Channels EI+ 218.20 100 1.72e5
%
17 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 179
7120/6-1 DST-2 ARO 05-Mar-2009 20-6-1A SIR of 14 Channels EI+ 231.12 100 6.32e4
%
46 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 180
7120/6-1 DST-2 ARO 05-Mar-2009 20-6-1A SIR of 14 Channels EI+ 253.20 100 8.06e4
%
37 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 181
7120/6-1 DST-2 ARO 05-Mar-2009 20-6-1A SIR of 14 Channels EI+ 178.08+192.09 100 5.27e5
%
15 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 182
7120/6-1 DST-2 ARO 05-Mar-2009 20-6-1A SIR of 14 Channels EI+ 198.05 100 2.19e5
%
15 20-6-1A SIR of 14 Channels EI+ 192.09 100 4.01e5
%
7 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 183
7122/7-1 1106,0m SAT 21-Feb-2009 22-7-1S SIR of 15 Channels EI+ 191.18 100 3.99e5
%
10 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 184
7122/7-1 1106,0m SAT 21-Feb-2009 22-7-1S SIR of 15 Channels EI+ 217.20 100 9.98e4
%
29 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 185
7122/7-1 1106,0m SAT 21-Feb-2009 22-7-1S SIR of 15 Channels EI+ 218.20 100 7.61e4
%
36 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 186
7122/7-1 1106,0m SAT 21-Feb-2009 22-7-1S SIR of 15 Channels EI+ 218.20 100 7.61e4
%
36 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 187
7122/7-1 1106,0m ARO 05-Mar-2009 22-7-1A SIR of 14 Channels EI+ 231.12 100 4.36e4
%
61 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 188
7122/7-1 1106,0m ARO 05-Mar-2009 22-7-1A SIR of 14 Channels EI+ 253.20 100 6.73e4
%
41 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 189
7122/7-1 1106,0m ARO 05-Mar-2009 22-7-1A SIR of 14 Channels EI+ 178.08+192.09 100 1.95e5
%
37 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 190
7122/7-1 1106,0m ARO 05-Mar-2009 22-7-1A SIR of 14 Channels EI+ 198.05 100 1.24e5
%
25 22-7-1A SIR of 14 Channels EI+ 192.09 100 1.10e5
%
27 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 191
7124/3-1 1298m SAT 27-Feb-2009 24-3-1S SIR of 15 Channels EI+ 191.18 100 2.50e5
%
14 rt 40.000 50.000 60.000 70.000 80.000 90.000 100.000 192
7124/3-1 1298m SAT 27-Feb-2009 24-3-1S SIR of 15 Channels EI+ 217.20 100 7.03e4
%
39 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 193
7124/3-1 1298m SAT 27-Feb-2009 24-3-1S SIR of 15 Channels EI+ 218.20 100 5.49e4
%
48 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 194
7124/3-1 1298m ARO 05-Mar-2009 24-3-1A SIR of 14 Channels EI+ 231.12 100 6.80e4
%
42 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 195
7124/3-1 1298m ARO 05-Mar-2009 24-3-1A SIR of 14 Channels EI+ 253.20 100 1.27e5
%
22 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 196
7124/3-1 1298m ARO 05-Mar-2009 24-3-1A SIR of 14 Channels EI+ 178.08+192.09 100 3.47e5
%
24 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 197
7124/3-1 1298m ARO 05-Mar-2009 24-3-1A SIR of 14 Channels EI+ 198.05 100 2.30e5
%
15 24-3-1A SIR of 14 Channels EI+ 192.09 100 2.00e5
%
15 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 198
7124/4-1 DST-3 SAT 21-Feb-2009 24-4-1S SIR of 15 Channels EI+ 191.18 100 4.28e5
%
9 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 199
7124/4-1 DST-3 SAT 21-Feb-2009 24-4-1S SIR of 15 Channels EI+ 217.20 100 1.17e5
%
25 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 200
7124/4-1 DST-3 SAT 21-Feb-2009 24-4-1S SIR of 15 Channels EI+ 218.20 100 9.58e4
%
29 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 201
7124/4-1 DST-3 ARO 05-Mar-2009 24-4-1A SIR of 14 Channels EI+ 231.12 100 3.65e4
%
73 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 202
7124/4-1 DST-3 ARO 05-Mar-2009 24-4-1A SIR of 14 Channels EI+ 253.20 100 4.53e4
%
60 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 203
7124/4-1 DST-3 ARO 05-Mar-2009 24-4-1A SIR of 14 Channels EI+ 253.20+192.09 100 1.46e5
%
39 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 204
7124/4-1 DST-3 ARO 05-Mar-2009 24-4-1A SIR of 14 Channels EI+ 198.05 100 6.69e4
%
43 24-4-1A SIR of 14 Channels EI+ 192.09 100 1.16e5
%
25 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 205
7128/04-1 1592-1610m SAT RUN2 26-Feb-2009 4-1DST1S SIR of 15 Channels EI+ 191.18 100 1.23e5
%
34 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 206
7128/04-1 1592-1610m SAT RUN2 26-Feb-2009 4-1DST1S SIR of 15 Channels EI+ 217.20 100 4.43e4
%
60 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 207
7128/04-1 1592-1610m SAT RUN2 26-Feb-2009 4-1DST1S SIR of 15 Channels EI+ 218.20 100 3.72e4
%
69 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 208
7128/04-1 DST1 ARO 18-Mar-2009 DST1A SIR of 14 Channels EI+ 231.12 100 3.51e4
%
74 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 209
7128/04-1 DST1 ARO 18-Mar-2009 DST1A SIR of 14 Channels EI+ 253.20 100 3.40e4
%
82 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 210
7128/04-1 DST1 ARO 18-Mar-2009 DST1A SIR of 14 Channels EI+ 178.08+192.09 100 2.80e5
%
30 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 211
7128/04-1 DST1 ARO 18-Mar-2009 DST1A SIR of 14 Channels EI+ 198.05 100 1.42e5
%
23 DST1A SIR of 14 Channels EI+ 192.09 100 1.49e5
%
21 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 212
7128/04-1 DST2 SAT2 18-Mar-2009 DST2S2 SIR of 15 Channels EI+ 191.18 100 8.69e4
%
46 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 213
7128/04-1 DST2 SAT2 18-Mar-2009 DST2S2 SIR of 15 Channels EI+ 217.20 100 4.51e4
%
60 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 214
7128/04-1 DST2 SAT2 18-Mar-2009 DST2S2 SIR of 15 Channels EI+ 218.20 100 3.57e4
%
72 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 215
7128/04-1 DST2 ARO 18-Mar-2009 DST2A SIR of 14 Channels EI+ 231.12 100 3.65e4
%
71 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 216
7128/04-1 DST2 ARO 18-Mar-2009 DST2A SIR of 14 Channels EI+ 253.20 100 3.56e4
%
78 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 217
7128/04-1 DST2 ARO 18-Mar-2009 DST2A SIR of 14 Channels EI+ 178.08+192.09 100 3.12e5
%
28 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 218
7128/04-1 DST2 ARO 18-Mar-2009 DST2A SIR of 14 Channels EI+ 198.05 100 1.65e5
%
20 DST2A SIR of 14 Channels EI+ 192.09 100 1.67e5
%
18 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 219
7228/07-1 2091,1m SAT 20-Feb-2009 28-7-1S SIR of 15 Channels EI+ 191.18 100 1.43e5
%
32 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 220
7228/07-1 2091,1m SAT 20-Feb-2009 28-7-1S SIR of 15 Channels EI+ 217.20 100 4.96e4
%
58 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 221
7228/07-1 2091,1m SAT 20-Feb-2009 28-7-1S SIR of 15 Channels EI+ 218.20 100 3.66e4
%
73 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 222
7228-07-1 2091,1m ARO 05-Mar-2009 28-7-1A SIR of 14 Channels EI+ 231.12 100 3.10e4
%
83 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 223
7228-07-1 2091,1m ARO 05-Mar-2009 28-7-1A SIR of 14 Channels EI+ 253.20 100 3.31e4
%
81 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 224
7228-07-1 2091,1m ARO 05-Mar-2009 28-7-1A SIR of 14 Channels EI+ 178.08+192.09 100 1.32e5
%
52 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 225
7228-07-1 2091,1m ARO 05-Mar-2009 28-7-1A SIR of 14 Channels EI+ 198.05 100 9.75e4
%
31 28-7-1A SIR of 14 Channels EI+ 192.09 100 6.80e4
%
44 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 226
NSO-1 Oseberg 27-Feb-2009 NSO-1 SIR of 15 Channels EI+ 191.18 100 3.23e5
%
12 rt 45.000 50.000 55.000 60.000 65.000 70.000 75.000 80.000 85.000 90.000 95.000 100.000 105.000 227
NSO-1 Oseberg 27-Feb-2009 NSO-1 SIR of 15 Channels EI+ 217.20 100 1.01e5
%
30 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 228
NSO-1 Oseberg 27-Feb-2009 NSO-1 SIR of 15 Channels EI+ 218.20 100 7.29e4
%
38 rt 58.000 60.000 62.000 64.000 66.000 68.000 70.000 72.000 74.000 76.000 78.000 80.000 82.000 229
NSO-1 Oseberg ARO 05-Mar-2009 NSO-1A SIR of 14 Channels EI+ 231.12 100 1.01e5
%
31 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 230
NSO-1 Oseberg ARO 05-Mar-2009 NSO-1A SIR of 14 Channels EI+ 253.20 100 1.27e5
%
24 rt 50.000 52.500 55.000 57.500 60.000 62.500 65.000 67.500 70.000 72.500 75.000 77.500 80.000 82.500 85.000 231
NSO-1 Oseberg ARO 05-Mar-2009 NSO-1A SIR of 14 Channels EI+ 178.08+192.09 100 2.71e5
%
29 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000 232
NSO-1 Oseberg ARO 05-Mar-2009 NSO-1A SIR of 14 Channels EI+ 198.05 100 1.51e5
%
23 NSO-1A SIR of 14 Channels EI+ 192.09 100 1.90e5
%
16 rt 22.000 23.000 24.000 25.000 26.000 27.000 28.000 29.000 30.000 31.000 32.000 33.000 34.000 35.000
233
Appendix C GC MS MS chromatograms 234
120.611
235
NZS 137
236
NZS 185
237
NZS 225
238
NZS 255
239
NZV 232
240
7120/6 1
241
7122/7 1
242
7124/3 1
243
7124/4 1
244
7128/4 1 DST1
245
7128/4 1 DST2
246
7228/7 1
247
NSO 1