Unusual Oils from Norway : Alternative petroleum systems?

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1

Unusual oils from Scandinavia

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Alternative petroleum systems?

by

Therese Simonsen

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Unusual oils from Scandinavia

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Alternative petroleum systems?

by

Therese Simonsen

Master Thesis in Geosciences

Discipline: Petroleum Geology and Geophysics Department of Geosciences

Faculty of Mathematics and Natural Sciences

UNIVERSITY OF OSLO

June, 2008

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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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Acknowledgement

This thesis was carried out at the Department of Geosciences, at the University of Oslo. I would like to thank my supervisor Dr. Dag A. Karlsen for his guidance, encouragement, help and support. I would also like to thank Kristian Backer-Owe for technical help in the lab and also for literary guidance during my thesis work. In addition, I would like to thank all my fellow students and friends at the University.

I also wish to thank my friends Rebecca, Sian and Ane. Thank you for the moral support during this study and for assistance in the final stages of finishing my thesis.

Most of all I would like to thank my parents and brother for being there for me and believing in me. You have always been supportive, in life, and during my years of studying. The moral support and constant encouragement have been a great help for me in the process of finishing my thesis.

Oslo, June 2008

Therese Simonsen

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Abstract

Geochemical analyses were conducted on twelve oils and bitumen. Beside the standard North Sea Oil (NSO-1), used as an analytical reference point, these oils and extracts represent some of the most unusual hydrocarbon samples from the Norwegian Offshore Continental Shelf (NOCS) and from onshore Scandinavia. The samples were subjected to standard geochemical techniques, i.e. Iatroscan Thin-Layer Chromatography Flame-Ionization Detection (TLC-FID), Gas Chromatography-Flame Ionization Detector (GC-FID) and Gas Chromatography-Mass Spectrometry (GC-MS).

Samples from the 4.5 km Embla field were found to have suffered from paleo-biodegradation signifying that the trap was at some time very shallow. The paleo-biodegraded oil is of non- Kimmeridge origin. Paleozoic oils from locations in Sweden, i.e. the oil from Siljan, the oil from cavities in orthoceras fossils from Österplana, and the oil sample from the Gävle sandstones are concluded to be sourced from the same source rock facies, differing mainly concerning levels of biodegradation related to their preservation in the sedimentary strata. It is concluded that the Siljan sample was generated not due to the meteorite impact as previously suggested, but rather preserved in the depression caused by the impact. The Siljan oil simply represents oil generated and migrating in the Caledonian foreland basin. This part of Sweden, where these oils occur, simply represent a foreland basin and oil is likely to have occurred all over this region, at places possibly resembling the Alberta Tar Sand system of today.

The Svarstad sample from the Oslo region displays the same geochemical genetic characteristics as found in the Siljan samples, but at significantly higher maturity and were as the Swedish samples most likely generated from the Alum Shale, but much closer to the orogenic centre. These samples therefore display the increasing maturity towards west and the Caledonian orogenic centre.

The three oil samples taken from offshore locations, i.e. the 2/2-5 (Central Graben), 25/-5 (Viking Graben) and 6609/11-1 (Helgelandsbassenget) samples, show geochemical characteristics very different to “Kimmeridge/Draupne/Spekk” derived oils. The Helgelandsbassenget sample represents an estuarine type of source rock, possible lacustrine, and could represent a possible new play in the Helgeland basin. Sample 25/5-5 must have

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been sourced from a carbonate source rock different from the Kimmeridge Shale and its equivalents. The 2/2-5 oil must represent a hypersaline source rock event, indicated by the presence of gammacerane.

The presence of these oils suggests that an alternative petroleum system exist in Northern Europe, and that it still could represent offshore alternative play scenarios. The existence of oil sourced from alternative source rock facies inferred by the atypical oils in this thesis study may add new potential ideas to future petroleum exploration in Northern Europe.

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1. Introduction

This chapter provides an overview of the topics and scope of this thesis. In order to address the main subjects that are brought to attention in this work, basic concepts will be addressed and explained in this introduction. The outline of this chapter follows this arrangement;

1.1 Scope of study

1.2 Evidence of Paleozoic source rocks

1.3 Source rocks and alteration of organic matter 1.4 The petroleum system

1.5 Reservoir rocks 1.6 Biomarkers

1.7 Overall purpose of study

1.1 Scope of study

The aim of this thesis is to shed light on the likelihood that there might exist Paleozoic oils on the Norwegian continental shelf. It is clear that the Mesozoic petroleum systems based on the world class Kimmeridge-aged Draupne or Spekk Fm. source rock (Barnard et al., 1981;

Cornford et al., 1998) are responsible for most of the oil and gas in commercial traps on the Norwegian Offshore Continental Shelf (NOCS). It is for these reasons that other petroleum systems have received little attention, and the few evidences discarded. Still, with the traditional and large structures becoming steadily depleted, there will be a need in the relative near future for an understanding of alternative petroleum systems.

It is for these reasons that this thesis work will look into the aspects of alternative and potential Paleozoic petroleums. A very few particular and highly “non-typical” petroleums have been encountered on the NOCS, these samples have earlier not been described in detail, and in this thesis emphasis is placed on sheding light on these petroleum samples and their potential source rock origin.

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2 With exception of the Embla field, which contains reservoir rocks of Devonian to Permian age (Knight et al., 1993), and with paleo-petroleum of Paleozoic age (pers. com. Dag Karlsen), very little is known about this topic, i.e. Paleozoic petroleum occurrences on the Norwegian shelf. It is likely that occurrences of petroleum similar to the Embla could exist elsewhere on the NOCS.

Initial work at the University of Oslo by The Geochemistry Program of my supervisor Dr.

Dag A. Karlsen and various Dr. Scient students, PhD students and cand.scient students, have been the first to discern traces of “other-than-normal-Kimmeridge/Spekk/Draupne-derived oils” in traps offshore Norway. In addition, the work of Dr. Pedersen in this group was the first to provide collective evidences specifically on onshore bitumen and oils from Sweden and the Oslo Graben. This thesis work tried to dig deeper into these matters and provided for the first time a comparison of these onshore and offshore evidences for Paleozoic petroleum systems of the past, with potential implications for the present. It is reasonable to believe that investigations into these topics, i.e. the source rock facies, the maturity and the genetic relationship between these few and scattered evidences of “alternatively-sourced oils” will be of great help in understanding the alternative petroleum systems found on the NOCS. Thus it is for these reasons that this thesis work will look into the aspect of alternative and potential Paleozoic petroleums.

As mentioned, the Geochemistry Program at the University of Oslo has during the last 20 years from time to time come across a very few particular and highly “non-typical”

petroleums that have been encountered on the NOCS. These samples have earlier not been described in detail, and in this thesis emphasis is placed on sheding light on these petroleum samples and their geochemical characteristics.

Paleozoic source rocks are found many places and there are reasons to believe that we will find these rocks also on the NOCS. If indeed such petroleum systems exist, the same source rocks might be present, e.g. in the offshore of southern Norway and up along the coast and into the Barents Sea, and that such rocks may constitute a secondary source for oil and gas besides the Kimmeridge/Draupne system.

Furthermore it is likely that Paleozoic source rocks, as known from onshore Scandinavia, are generating petroleum on the Norwegian continental shelf in regions where the Kimmeridge-

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3 aged Draupne/Spekk formation is immature. This thesis work will look into the geochemistry of some non-typical Kimmeridge-derived oils from both onshore and offshore Norway and Scandinavia, compare these and try to elaborate on potential existence of Paleozoic oil in traps along the shelf.

1.2 Evidences of Paleozoic rocks in Scandinavia

Paleozoic oils are known to be present in Paleozoic rocks in Scandinavia, Poland and in the Baltic states, and have also been sampled, analysed and in many cases produced from these places. Although Paleozoic source rocks are known, for example the well known Alum shale, oils are not so common. The distribution of known Paleozoic outcrops in the Baltic States and Scandinavian area are shown in Fig. 1.1. It is clear from this figure that Paleozoic sediments, and oils plus bitumen, are occurring at places where they have been preserved from erosion.

Figure 1.1. Southern Scandinavia and the Baltic region. The blue and red dotted line show the Baltic basin and the black spots indicate Paleozoic outcrops (modified from Pedersen et al., 2007).

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4 In both Sweden and Norway, oil stains, bitumen and oil seeps have been known to exist in Paleozoic rocks. Samples in this sample set are from onshore and offshore Norway and onshore Sweden. At various locations in the southern part of Norway there are evidences of existing oil and gas in Permian volcanic intrusive rocks (Dons, 1975). In 1862, the famous geologist Theodor Kjerulf noticed petroliferous smells in Upper Ordovician limestones in Ringerike in Oslo Graben.

Paleozoic oils are discovered at several locations in Sweden. In Ordovician carbonate mounds at Siljan, black oil is discovered (Auton, 1983; Vlierboom et al., 1986), and in Gävle, Sweden, bitumen and oils are found in Precambrian sandstones (Pedersen et al., 2007). The sample set of this thesis have samples from both locations.

One of the hypotheses for the Siljan oil is that is was generated as a result of a meteor impact which struck at the end of the Devonian time (Vlierboom et al., 1986). The generation of heat as a result of the impact is suggested for being responsible for generation and expulsion of the Siljan oil. This is one of the issues that this thesis work aims to look into. It may be added that also in the Northern Poland, Cambrian rocks are known to contain petroleum (Scleicher et al., 1998), and in the Baltic States from Cambrian sandstones, Ordovician-, and Silurian carbonates (Ulmishek, 1990; Brangulis et al., 1992). It is assumed that the petroleum found in Paleozoic rocks in Scandinavia, Poland and the Baltic States are from marine source rocks (Pedersen et al., 2007). The most widespread Paleozoic source rock that we have in this region is the Alum shale from Upper Cambrian-lower Ordovician.

In total, it is estimated that about a 3-4 km thick pile of Paleozoic sediments was deposited in Scandinavia, and Silurian sediments represent most of this (Zeck et al., 1988; Olaussen et al., 1994). On the NOCS the Embla field is the first and only field producing mixed Jurassic and Paleozoic oil.

1.3 Source rocks and alteration of organic matter

According to Tissot and Welte (1984), all sedimentary rocks that have the potential to, or have been producing petroleum, are source rocks. Traditionally a total organic carbon content (TOC) of 0.5% in case of silisiclastic rocks e.g. shales, and 0.3% for carbonates has also been

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5 used as a criteria for a source rock. A source rock that is, or has been, producing petroleum is called an effective source rock. The maturity of the source rock determines whether it has expelled petroleum or not (Hunt, 1996).

The increase of sediment overburden will cause an increase in temperature and therefore alteration of the organic matter captured in the rock. When the organic matter in the source rocks matures it starts to liverate petroleum. Gradually the source rock starts to expel petroleum and a minor part of this petroleum may follow a migration path to a reservoir rock.

At this generative depth interval we say that the source rock has reached the so-called oil window, which is usually placed at 80ºC-140ºC (Hunt, 1996). Source rock facies refer to the environment in which the organic matter has been deposited in and the type of organic matter.

Knowledge of source rock facies indicate what type of oil the source rock may develop. If studying migrated petroleum, one could retrieve information not only about the maturity of the source rock, but also concerning the source rock facies, that is to reconstruct the type of depositional system that existed when the organic matter (OM) was laid down.

Analyses of oil and bitumen extracts using gas chromatography-mass spectrometry (GC-MS) and gas chromatography-flame ionization detector (GC-FID), can discern the maturity and source rock facies of oils. Similarly, i.e. data that will provide information concerning source rock type and source rock facies.

1.4 The petroleum system

A petroleum system constitutes all necessary elements needed for petroleum to exist (Magoon and Dow, 1994). Source rock, reservoir rock and trap are all necessary elements in a complete petroleum system. An essential factor of a successfully developed petroleum system is timing.

When a mature source rock starts to expel organic matter into the reservoir rock, it is crucial that there is a trap to capture the petroleum. Therefore it is essential that all elements are present within a suitable time frame. An example of a successful petroleum system is the Mesozoic petroleum system mentioned above which source most oil and gas accumulations on the NOCS.

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6 Indirectly we can say that observed oil stains and bitumen can be interpreted as proof of a paleo petroleum system. In Fig. 1.2 illustrating an event chart for the Skagerrak region, it is indicated that there have been two critical moments for petroleum preservation, in the Devonian-Silurian, and in the Triassic. It is possible that petroleum might have accumulated at two periods, but preservation in traps for 400 and 200 M.Y. poses an immense risk factor.

Figure 1.2. Petroleum system event chart, Skagerrak (modified from Pedersen et al., 2007).

1.5 Reservoir rocks

A reservoir rock is a rock which can contain economical values of petroleum. This depends mainly on two elements, porosity and permeability. Porosity usually ranges from 0 to 30%

(Tissot and Welte, 1978). The majority of petroleum accumulations are found in clastic rocks.

Well sorted sand with spherical grains, such as beach-sand, is an example of a potentially good reservoir rock that would have great reservoir characteristics. Source rocks “feed”

reservoir rocks, thus one affect the other. Geochemical studies of reservoir oil indicate what type of oil it is, e.g. heavy or light, highly mature or less mature, and will also disclose something about the source rock which fed it. Reservoirs are not only of direct economical significance but are also of great importance as they somehow represent a geochemical collection of information which helps researchers and employees in the oil industry in the search for oil.

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7 1.6 Biomarkers

Biomarkers, biologically marker compounds, are linked with biological precursor compounds and through diagenesis and catagenesis their skeleton compositions are preserved (Killops et.

al., 1993). Organic matter in the source rock will be altered with increased time and temperature, and will generate buoyant hydrocarbons and liberate biomarkers. It is commonly said that the biomarker composition represents a “fingerprint” and as such represent an important factor when studying oil compositions.

Biomarkers can provide information about the origin of the oil, quality and maturity of the source rock which expelled it. Different depositional facies give rise to different assemblages of biomarkers, and an increase in thermal stress will cause stable carbon isotopic fractionation of gas and oil. When analysing petroleum and reservoir rock extracts, biomarker analysis makes it possible to predict the degree of source rock burial, and the environment in which it was deposited. This can also help to differentiate between petroleum systems of an investigated area. Biomarkers only represent a small part of petroleum, about one percent or less, but are yet an important analytical tool.

1.7 Overall purpose of study and specific aims

In this thesis emphasis is made on investigation of a set of Paleozoic and unknown oil samples which display some unique geochemical characterisations, divergent from the typical Kimmeridge which is so well known. Included are some specific offshore oils, from well 2/2- 5 and 25/5-5 and an extract of migrated oil from sandstones in well 6609/11-1 (Helgelandsbassenget) as all of these display characteristics departing from standard North Sea “Kimmeridge shale derived oils and condensates”.

Geochemical analysis will be discussed, and samples compared also partly to “Normal Oils”

from Haltenbanken, The Norwegian Sea, using NOCS as a reference frame. Analytically, the samples are investigated using geochemical techniques such as Iatroscan TLC-FID, GC-FID and GC-MS. Main emphasis is placed on molecular characterization concerning organic facies, maturity and correlation between the samples i.e. GC-FID and GC-MS work.

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8 The task of this thesis will be to illustrate differences and similarities between these oils in respect of maturity, organic facies and biodegradation, plus to outline potential source rock affinity. This thesis work will aim to point out the specific characteristics of these samples and what we may deduce about their source rock affinity, maturity and potentially the post expulsion history. And if possible also to go one step further concerning possible mode of generation and likely time of generation for the Swedish and Oslo Graben samples.

The main target concerning the offshore samples is their geochemical characteristics as their potential source rocks are basically totally unknown. Thus for these samples, one may only tentatively indicate an age of the source rock based on a specific facies signature e.g. a hyper saline facies could tentatively be suggested to be Permian. More detailed conclusions may not be reached in this master thesis which is strictly limited with respect to available time, but it is clear that even this pilot work could improve our understanding of the possible organic depositional source rock affinity of these samples.

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Chapter 2 Sample set

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2. Sample set

This chapter will give a short description of the samples in the data set, and provide a map (Fig. 2.3 on p. 13) showing locations of where they are taken from. Samples in this study are from various locations in Scandinavia. Samples from Embla 1, 2 and 3, 2/2-5, 25/-5 and 6609/11-1 are taken offshore, while samples from Siljan, Österplana, Gävle, Svarstad and Agardhbukta are taken from onshore locations.

2.1 5SO-1

This sample is the North Sea Oil Standard, and is from the Oseberg field, on the NOCS. It is used by the Norwegian Petroleum Directorate. It is a well known standard used to calibrate laboratory instruments before running geochemical analyses (Weiss et al., 2000). In later chapters this sample will be referred to as NSO-1.

Sample 5ame Sample location 1 NSO-1 Oseberg field, Norway 2 Embla 1 Embla field, Norway 3 Embla 2 Embla field, Norway 4 Embla 3 Embla field, Norway 5 Siljan Siljan, Sweden 6 Österplana Österplana, Sweden

7 Gävle Gävle, Sweden

8 Svarstad Svarstad, Norway

9 25/5-5 Southern part of the NOCS 10 2/2-5 Southern part of the NOCS 11 Agardhbukta Agardhbukta, Svalbard 12 6609/11-1 Haltenbanken basin, Norway

Table 2.1. The complete sample set. For sample location see Fig. 2.3.

NOCS=Norwegian Offshore Continental Shelf.

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10 2.2 Embla 1

This is an oil sample taken from the Embla field, the most southern part on the NOCS, from well 2/7-16S at 4686 meters depth. In later chapters this sample will be referred to as Embla 1.

2.3 Embla 2

This is an oil sample taken from the Embla field, the most southern part of the NOCS, from well 2/7-23S at 4698 meters depth. In later chapters this sample will be referred to as Embla 2.

2.4 Embla 3

This is an oil sample taken from the Embla field, the most southern part of the NOCS, from well 2/7-25S at 4794 meters depth. In later chapters this sample will be referred to as Embla 3.

2.5 Siljan

Sample 5 is an oil sample taken from an oil stain in Siljan, Sweden. It is extracted from sealed inclusions and amygdules in Ordovician limestone (Pedersen et al., 2007). In later chapters this sample will be referred to as Siljan.

Figure 2.1. Siljan sample - arrow indicating oil stain in an Ordovician Limestone (Pedersen et al., 2007).

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11 2.6 Österplana

Sample 6 is an oil seep extract taken from onshore Österplana, Sweden. It was collected from large amygdules in an Ordovician Orthoceras fossil (Pedersen et al., 2007). Some of these samples are characterized by being black viscous oil, but some freshly cut voids in the fossil flow oil (Pedersen et al., 2007). In later chapters this sample will be referred to as Österplana.

2.7 Gävle

This oil sample is taken from Gävle, Sweden, from Precambrian sandstones. It was characterized by being black, viscous and opaque (Pedersen et al., 2007). In later chapters this sample will be referred to as Gävle.

2.8 Svarstad

Sample 8 is an oil sample taken from an oil stain in a carbonate rock of Upper Ordovician age in Tyrifjorden, Oslo. It is extracted from sealed inclusions and amygdules in rock samples. It is characterized by being a translucent, light-yellow (light oil), volatile liquid. In later chapters this sample will be referred to as Svarstad.

2.9 Well 25/5-5

Sample 9 is an oil sample taken from well 25/5-5, which was drilled in 1995 by Elf Petroleum.

The target was Paleocene turbiditic sands and petroleum was found in the Heimdal formation.

At the Paleocene Våle formation the well was terminated and stopped for any further oil production. In later chapters this sample will be referred to as 25/5-5.

Figure 2.2. Österplana sample - arrow indicating oil seep in an Ordovician Orthoceras fossil (Pedersen et al., 2007).

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12 2.10 Well 2/2-5

Well 2/2-5 is located in block 2/1, south of the Gyda field, on the NOCS. It was drilled and discovered by Saga Petroleum in 1991. The purpose was to test a reservoir within a salt- induced anticline in the Upper Jurassic Ula Formation (Pedersen et al., 2006). Oil was discovered in this formation but after well testing it was plugged and abandoned for any further oil production. In later chapters this sample will be referred to as 2/2-5.

2.11 Agardhbukta

Sample 11 is an oil seep extract trapped in a drusy cavity taken from a fault zone onshore in Agardhbukta, Svalbard, in shales from the Botenheia formation. In later chapters this sample will be referred to as Agardhbukta.

2.12 Well 6609/11-1

Sample 12 is an oil sample taken from Helgelandsbassenget in the Haltenbanken region, off the west coast of Norway. It is taken from a coarse sandstone core impregnated with bitumen (Karlsen et al., 1995). The core was taken from well number 6609/11-1 at 2561 meters depth, and the core was dark stained with bitumen. In later chapters this sample will be referred to as Helgelandsbassenget.

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2/2-5

Embla field

Figure 2.3. Map of Scandinavia and sample locations (Oljedirektoratet, 2007). The black dotted line outlines the boundary for the NOCS.

Helgelandsbassenget

SVALBARD

Siljan

Österplana Gävle Agardhbukta

SWEDE5

5ORWAY

Svarstad 25/5-5

5SO -1

5ORTH SEA

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14

3. Analytical methods

This chapter will explain analytical methods used in this thesis. The outline of this chapter follows this arrangement:

3.1 Introduction to chromatography 3.2 Sample preparation

3.3 Iatroscan-Thin layer chromatography-Flame Ionization detector (TLC-FID) 3.4 Gas chromatography-Flame ionization detector (GC-FID)

3.5 Molecular Sieving

3.6 Gas chromatography-Mass spectrometry (GC-MS)

To determine the different types of biomarkers and their relative amounts in a crude oil or extract, a sample is subjected to one or more of these following analytical procedures; TLC- FID, GC-FID or GC-MS. For simplicity geochemical parameters are divided into two groups:

• Main parameters describing the whole sample. Normally percentage distribution of saturated hydrocarbons, aromatic hydrocarbons, and polar compounds. Thin Layer Chromatography-Flame Ionization Detection (TLC-FID) is used for this purpose.

• Specific description which describes the sample on a molecular level, i.e. information about biomarkers. Gas Chromatography-Mass Spectrometry, (GC-MS) and Gas Chromatography-Flame Ionization Detector (GC-FID) are used for this purpose.

These chromatographic techniques make it possible to identify molecular compounds. The North Sea oil (NSO-1) from the Norwegian Petroleum Directorate (NPD) is often used as a reference oil, and as also been used for that purpose in this analytical work. The reference oil is from the Oseberg field where the source rock is the Upper Jurassic Draupne Fm.

(equivalent to the Kimmeridge Clay Fm.) (Dahl and Speers, 1985).

3.1 Introduction to chromatography

Chromatography is a technique which separates a complex mixture of organic compounds like gas or oil into individual molecular types. Separation makes it possible to identify

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Chapter 3 Analytical methods

15 compounds qualitative and quantitative. This unique way of separation was first put in use in the 1950’s and is a very popular technique when performing separation. Chromatography is popular because it is easy to use, fast and relatively non-expensive. Chromatography separates a substance from a complex composition, and the results are very precise. The main principle for boiling point chromatography is that the system has two phases. One is stationary and is where substances are held back from further migration. The other one is the mobile phase and is either gaseous or liquid. The adsorbent is the solid substance that is retained in the solid phase. There are three properties which controls separation; relative solubility, adsorption and volatility.

3.1.1 The carrier gas

In gas chromatography the gas carries soluble substances through the column in the chromatograph. The gas must be inert, which means that it cannot interact with the sample that is analyzed. Commonly used gases are nitrogen, helium and hydrogen. Use of hydrogen requires special precautions and it can explode if leaking out into the room. This makes it difficult to use. Helium is expensive but is very pure with little contamination, while nitrogen is both inexpensive and safe to use. The carrier gas has an effect on the analysis-time and the efficiency of the column. Thus, the choice of gas can influence how quickly substances react, how they move through the column and how fast they reach the detector. Gas is transported from the cylinder into the chromatograph by a given pressure, which can always be changed and corrected. Normally the pressure is about 2-3 kg/cm² (bar). A control-system/flow- controller makes sure that the right pressure-value and speed of the gas into chromatograph are correct.

3.1.2 Injector and column

The injector is where the sample is vaporized and introduced into the column. The column is what we call the stationary phase in gas chromatography. Samples are injected, vaporized and transported through the column. Some substances are absorbed in the injector and do not flow through the column. Temperature must to be tuned accordingly to what substance we expect

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16 to separate and it must be high enough so that samples vaporize right away. The column looks like a spiral and is usually made of quartz. There are two types of columns:

The packed bed column is completely packed and its stationary phase is in granular form and fills the column completely, but is rarely in use today.

The open tubular capillary column usually has a small diameter where a coating on the inner tube wall acts as the stationary phase. Substances flow through the hole in the center of the column.

3.1.3 Detector

Separation of components takes place in the column and the detector measures the different substances as they come off it. There are different ways of detecting these substances. We separate between concentration-dependent-detectors and mass-flow-dependant detectors. The two most commonly used detectors are thermal-conductivity (TCD) and flame-ionization (FID). TCD measures the changes in heat in the detectors as the analyte passes through, and does not destroy organic compounds in the process. On the other hand, this is the least precise measurement. The oil samples in this work were analyzed by an FID. Although the minor disadvantage is that samples are destroyed in the process as the organic compounds burn in the FID, it is the most accurate detector.

3.2 Sample preparation

About 30 mg oil-sample was transferred in to 2 ml bottles with teflon lined plastic cork. It was diluted with 1 ml dichloromethane. Following the samples was analysed by three different methods, Iatroscan TLC-FID, GC-MS and GC-FID.

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17 3.3 Iatroscan-Thin Layer Chromatography-Flame Ionization Detection (TLC-FID)

Oil and reservoir extract consist of different compound groups, i.e. hydrocarbons, a bonding between hydrogen, carbon and non-hydrocarbons i.e. resins and asphaltenes. The TLC-FID provides a rapid distribution of the main components of the sample, i.e. saturated hydrocarbons, aromatic hydrocarbons and polar components. The variation between these compounds can be used to characterize the petroleum populations in the reservoir (Bhullar et al., 2000). Purpose is to achieve a quantitative measurement of the components in the sample.

Fig. 3.1 shows a schematic overview of a TLC-FID.

A TLC-FID analysis can help indicate which samples are most suitable for a GC-MS analysis.

It can identify samples which are polluted, for instance by diesel or other drilling fluids. A TLC-FID analysis provides a rapid and accurate method of defining the saturated hydrocarbons, aromatic hydrocarbons and the polar fraction (Karlsen and Larter., 1989).

Samples were analyzed by an Iatroscan MK-5 model coupled with a flame ionization detector (FID) connected to an electronic integrator (Perkin-Elmer LCI-100). The electronic integrator calculates the total quantity of the different compounds in the different extracts. All samples were applied onto the chromarod on a fixed point. In total there were 10 samples analysed in one run, whereas one of them was a blank test and the other one a NSO-1 sample. To separate the compounds, solvents of different polarities were employed. The rods were put in a solvent of normal-hexane for 35 minutes, followed by air drying. This solvent allows the saturated components to creep up to the uppermost part of the rod. Then the rods were put in toulene for six minutes, followed by air drying for 90 seconds (at 60°C). This allowed aromatic hydrocarbons to move towards the middle part of the rods. The polar compounds were to be found on the lowermost part of the rods. As mentioned in the beginning of this chapter, a TLC-FID analysis gives you an overview of the main three fractions, i.e. saturated hydrocarbons, aromatic hydrocarbons, and polar compounds (resins and asphaltenes). Fig. 3.1 shows a schematic overview of an Iatroscan TLC-FID.

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Figure 3.1. Key elements of the TLC-FID method (modified from Tran and Phillippe, 1993).

3.4 Gas Chromatography–Flame Ionization Detector (GC-FID)

The flame-ionization detector (FID) reacts to everything of organic origin and is flammable.

Before separation in the column, the sample is injected and evaporized. The stationary phase is dimethylpolysiloxane coating the inside the thin column. Short chained molecules take less time to travel through the column than long-chained molecules. The mobile phase is an inert gas, as mentioned in 3.1.1, Nitrogen (N₂) or Hydrogen (H₂). One run in the GC-FID takes 95 minutes, whereas several intervals in between are set for different temperatures. The first 75 minutes is spent to heat the column from 40- to 325º C, and upon reaching that, the temperature is stable for about 20 minutes. Signals produced from the FID are picked up by a computer and when properly prepared a chromatogram is printed out. X-axis in a chromatogram represents increased time and temperature, while Y-axis represents signal

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19 intensity, i.e. in form of height of peaks equal to relative amount, of the different components.

Fig. 3.2 shows a schematic overview of a GC-FID.

The purpose of a GC-FID analysis is to get a specific description of molecular compounds.

Parameters include following:

• Carbon Preference Index (CPI)

• Pristane/n-C17

• Phytane/n-C₁₈

• Pristane/Phytane (Pr/Ph)

Figure 3.2. Schematic overview of the GC-FID instrument (modified from Pedersen, 2002).

3.5 Molecular sieving

Molecular sieving is done primarily to remove the n-alkanes. Removal of the polar fraction is a “side effect”. A major proportion of petroleum consists of n-alkanes, and they will interfere with the signals from the biomarkers if they are present in the sample during GC-MS analysis.

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20 Thus, by removal of the n-alkanes, the biomarker signal will not be disturbed and reliable results will be produced. Before GC-MS analysis, the process of molecular sieving was used in order to remove n-alkanes, resins and asphaltenes from the samples (Pedersen et al., 2006).

The molecular sieve is a special compound, and in this geochemical study a zeolite called silicate was used. The molecules in the sieve have channel-like pores and the long-chained n- alkanes will fit into this structure and be trapped. The bigger molecules will not enter these small openings and will therefore remain in the sample. When separating the molecular sieve from the sample the biomarkers and aromatic fractions will remain. After this process, the sample will be enriched in biomarkers and aromatic fractions and fully depleted in n-alkanes.

In this study 5Å UOP MHS2-4120LC silica was used.

About 0.18 gram of molecular sieve was poured into a 15 ml glass. 3 ml of sample was mixed together with the sieve. For this purpose a pipette was used. The samples were diluted with about 2.5 ml cyclohexane. After stirring the vial was centrifuged at 2000 rpm for three minutes in a Heraeus Sepatech Labofuge H. until the sieve was settled. Samples were poured into a new 15 ml glass and by a flow of nitrogen the solvent was reduced to ¾ of its volume.

After the final evaporation, sample were put in vials and sealed with teflon-lined cap.

3.6 Gas Chromatography-Mass Spectrometry (GC-MS)

The GC-MS procedure combines gas chromatography and mass spectrometry to identify substances within a sample. It consists of two main components; the gas chromatograph for compound separation and a mass spectrometer using ionization and mass analysis for identification. Molecules in oil and gas hold different properties, like boiling points, and this is the reason for the separation as the molecules travel through the column. As the molecules take different amount of time to move through the column, because of their variation in reference to size and vapour pressure, they reach the detector at variable times. When isolated, components can be evaluated individually. The greater the concentration is, the bigger the signal will be. The time from when the injection is made to when detection occurs, is called the retention time. Before introducing samples to the GC-MS all n-alkanes are removed by molecular sieving. The purpose is to get a stronger biomarker signal.

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21

Figure 3.3. Schematic overview of the GC-MS instrument (modified from Pedersen, 2002).

As each component elute from the column, it will enter an electron ionization unit inside the mass spectrometer. Here they will be bombarded with a stream of electrons (normally 70 EV) which will cause the molecule to break into fragments. In some cases these fragments will be small, and in other the molecules will withstand the bombardment and retain more of its original shape and structure. The mass analyser is generally designed to separate and measure the mass of ions by use of their mass-to-charge (m/z) ratio (Tran and Phillippe, 1993).

Steroids (steranes) are for example found to have a major fragment with m/z=217. Each fragment composition is unique, so its mass spectrum contributes to identification. In this thesis chosen fragment ions have received the attention, according to their importance when interpreted organic facies and maturity of the oils. Fig. 3.3 shows a schematic overview of a GC-MS.

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22

4. Maturity and facies parameters

This chapter will explain the different maturity and facies parameters which are used in this thesis. The main focus will be on the GC-MS data, as the biomarkers receive the most attention in the discussion. The final subchapter of this chapter will explain the different parameters which were used for the discussion. The outline of this chapter follows this arrangement:

4.1 Iatroscan TLC-FID 4.2 GC-FID

4.3 GC-MS

4.1 Iatroscan TLC-FID

Iatroscan TLC-FID offers a rapid and exact method for quantifying the gross components of oils and extracts. The technique has been used to analyse large reservoirs and results have been successful (Karlsen et al., 1991).

Analyses of petroleum fraction are used to separate oils and extracts into fractions with different polarities. An Iatroscan TLC-FID analysis makes it possible to commit the quantitative relation between the three main components of the oil. These three components are saturated hydrocarbons, aromatic hydrocarbons and polar compounds, and make up 100%

of the oil components. Most oils are made up of all three components and due to type and maturity this percentage varies. These values allow us to say something about the oils type and maturity. Retrieving valuable percentages based on a GC-FID chromatogram demand only simple measurements and basic calculations. Values for each peak are already given on the printed chromatogram and the only affliction is being able to pick the right peaks for identification. The first peak seen at about 9 cm on the scale in Fig. 4.1 and 4.2 and also the last peak at about 1 cm on the scale, are only the start and finish of the chromatogram, and do not represent any real compound values. An Iatroscan TLF-FID analysis is simple to apply and results are easy to interpret.

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Chapter 4 Maturity and facies parameters

23

Figure 4.1. Analysis of petroleum fractions by Iatroscan TLC-FID. Separation and quantification of fractions for sample Embla 2. Peaks on this figure are identified as SAT=saturated hydrocarbons, ARO= aromatic hydrocarbons and POL= polar compounds.

Figure 4.2. Analysis of petroleum fractions by Iatroscan TLC-FID. Separation and quantification of fractions for the standard NSO-1 sample. Percentages are calculated based on retention time and mg/ml of the different fractions. Peaks on this figure are identified as SAT= saturated hydrocarbons, ARO= aromatic hydrocarbons and POL= polar compounds.

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24 4.2 GC-FID

4.2.1 Pristane/n-C₁₇ and Phytane/n-C₁₈

Pr/n-C₁₇ and Ph/n-C₁₈ are often used as a maturity indicator since their values decrease with increasing maturity. Isoprenoids break down more rapidly than n-alkanes during increased source rock maturity, and a low ratio will therefore indicate a more mature sample.

Isoprenoids are thermally more unstable than n-alkanes (Tissot et al., 1971). One should be aware that this parameter should be interpreted with caution since Pr/n-C₁₇ and Ph/n-C₁₈ ratios are also affected by biodegradation.

Figure 4.3. The diagentic origin of pristane and phytane (Peters et al., 2005).

4.2.2 Pristane/Phytane

Pristane and phytane are the most common type of isoprenoid isoalkanes. They are derived from phytol, which is a side chain of chlorophyll, and is the most abundant source of isoprenoid (Tissot and Welte, 1978). This relation indicates the red-ox potential of the source rock, i.e. the amount of oxygen present during deposition (Tissot and Welte, 1984). Whether phytol is transformed into pristane or phytane is determined by the depositional environment.

If oxygen is not present during deposition, phytane is formed. Thus, pristane/phytane provides information about the depositional environment with respect to anoxic- or oxic conditions, and following intervals help describe them; Pr/Ph>1 indicate oxidizing or hypersaline, Pr/Ph<1 indicates anoxic, carbonate- or lacustrine setting, 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. Since phytane is more unstable than pristane, the Pr/Ph will increase with increased maturity. As suggested by Welte and Waples (1973), pristane and phytane are more predominant in anoxic environments.

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25

10 20 30 40 50 60 70

0 10 20 30 40 50 60 70 80 90

n-C17

n-C18

pr

ph

4.3 GC-MS

For simplicity, the mass/charge ratio for the different ions that were observed in this thesis, and what chemical group they belong to, are divided into groups and presented in table 4.1.

There are seven chemical groups shown in this table representing saturated and aromatic hydrocarbons.

Ion/mass ratio Type

m/z = 191 Terpanes SAT

m/z = 217 Steranes m/z = 218 Steranes

m/z = 231 Triaromatic steroids ARO

m/z = 253 Monoaromatic steroids m/z = 178 Phenanthrene

m/z = 192 Methylphenanthrenes m/z = 198 Methyl-dibenzothiophenes

Table 4.1. Showing ion/mass ratios for ions used in this thesis and what chemical group they belong to. SAT=Saturated hydrocarbons and ARO=Aromatic hydrocarbons.

Retention time Figure 4.4 Chromatogram produced from GC-GID from the standard NSO-1 sample.

Intemsity

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26 4.3.1 Terpanes

Terpanes are a group of saturated hydrocarbons and the identified peaks be found on m/z=191 (Fig. 4.7). Table 4.2 explains what the identified peaks represent.

Peak Stereochemistry 5ame Composition

23/3 Tricyclic terpane C23H42

24/3 Tricyclic terpane C24C44

25/3 (17R/17S) Tricyclic terpane C25H46

24/4 Tetracyclic terpane C24H42

27Ts 18α (H)-22,29,30-trisnorneohopane C27

27Tm 17α (H)-22,29,30-trisnorhopane C27

28αβ 17α(H), 21β(H)-28,30-bisnorhopane C28H48

29αβ 17α(H), 21β(H)-30 norhopane C29

29Ts 18α (H)–30-norneohopane C30H52

30d 15α-methyl-17α (H)-27-diahopane C30H52

29βα 17β (H), 21α (H)-30-normoretane C29H50

30αβ 17α (H), 21β (H)-hopane C30H52

30βα 17β (H), 21α (H)-moretane C30H52

30G Gammacerane

31αβ 22S 17α (H), 21β (H)-22-homohopane C31H54

32αβ 22R 17α (H), 21β (H)-22-homohopane C31H54

Table 4.2. Triterpanes of m/z=191 (Weiss et al., 2000).

Figure 4.6. Structure of gammacerane (Hunt, 1996.) Figure 4.5. Structure of a tricylic terpane (Hunt, 1996).

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27 4.3.2 Steranes

Peak Stereochemistry 5ame Composition

27dβS 20S 13β(H), 17α(H), 20(S)-cholestane (diasterane) C27H12

27dβR 20R 13β(H), 17α(H), 20(R)-cholestane (diasterane) C27H48

29ααS 20S 24-ethyl-5α(H), 14α(H), 17α(H), 20(S)-cholestane C29H52

29ββR 20R 24-ethyl-5α(H), 14β(H), 17β(H), 20(R)-cholestane C29H52

29ββS 20S 24-ethyl-5α(H), 14β(H), 17β(H), 20(S)-cholestane C29H52

29ααR 20R 24-ethyl-5α(H), 14α (H), 17α(H), 20(R)-cholestane C29H52

Peak 5ame

27ββS C27 regular sterane (5α(H), 14β(H), 17β(H), 20(S)-cholestane)

28ββS C28 regular sterane (24-methyl-5α(H), 14β(H), 17β(H), 20(S)-cholestane) 29ββS C29 regular sterane (24-ethyl-5α(H), 14β(H), 17β(H), 20(S)-cholestane)

30d

28αβ

Table 4.4. Steranes of m/z=218 (Weiss et al., 2000).

Table 4.3. Steranes of m/z=217 (Weiss et al., 2000).

30αβ

Tetracyclic terpanes

Homohopanes

Figure 4.7. Chromatogram of m/z=191 of the saturated fraction from NSO-1.

Retention time

Intensity 29βα 30βα 32αβ

31αβ

29αβ

27Tm27Ts

29/3 v

28/3

24/4

25/3

24/3

23/3 29Ts

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28

27ββS

Figure 4.9. Chromatogram of m/z=218 of the saturated fraction from NSO-1.

Retention time

Intensity

C29-steranes

Figure 4.8.Chromatogram of m/z=217 of the saturated fraction from NSO-1.

Retention time

Intensity

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29 4.3.3 Triaromatic steroids

Triaromatic steroids are aromatic hydrocarbons and can be found on m/z=231 (Fig. 4.10).

Table 4.5 explains what the identified peaks represent.

Peak Substituents 5ame

R₁ R₂

a1 CH3 H C20TA

g1 R(CH3) C8H17 RC28TA

Figure 4.11. Position of substituents in monoaromatic steroid hydrocarbons (Weiss et al., 2000).

Table 4.5. ABC-ring triaromatic steroid hydrocarbons of m/z=231 (Weiss et al., 2000).

Retention time Figure 4.10. Chromatogram of m/z=231 of the aromatic fraction from NSO-1.

Intensity

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30 4.3.4 Monoaromatic steroids

Monoaromatic steroids are aromatic hydrocarbons and can be found on m/z=253 (Fig. 4.12).

Table 4.6 explains what the identified peaks represent.

Peak Substituents 5ame

R1 R2 R3 R4

H1 α(H) CH3 S(CH3) C2H5 αSC₂₉MA

H1 α(H) CH3 R(CH3) CH3 αRC28MA

H1 β(H) CH3 R(CH3) C2H5 βRC29MA

H1 β(H) H R(CH3) C3H5 βRC29MA

Table 4.6 C-ring monoaromatic steroid hydrocarbon of m/z=253.

(Weiss et al., 2000).

H1

Figure 4.12. Chromatogram of m/z= 253 of the aromatic fraction from NSO-1.

Retention time

Intensity

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31 4.3.5 Phenanthrene and methylphenanthrene

Phenanthrene and methylphenanthrene are aromatic hydrocarbons and can be found on m/z=178 and 192 (Fig. 4.13). Maturity calculations are based on measured peak heights for phenanthrene and methylphenanthrenes (Peters et al., 2005). Table 4.7 explains what the identified peaks represent.

Peak 5ame

P Phenanthrene

3-MP 3-methylphenanthrene 2-MP 2-methylphenanthrene 9-MP 9-methylphenanthrene 1-MP 1-methylphenanthrene

Table 4.7. Polycyclic aromatic hydrocarbons and sulphur compounds of m/z=178 and m/z=192 of the aromatic fraction from NSO-1 (Weiss et al., 2000).

2-MP 1-MP

3-MP 9-MP

P

Figure 4.13. Chromatogram of m/z=178 and 192 of the aromatic fraction from NSO-1.

Retention time

Intensity

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32 4.3.6 Methyl-dibenzothiophene

Methyl-dibenzothiophenes are aromatic hydrocarbons and can be found on m/z=198 (Fig.

4.14). Maturity is based on measured peak heights for 4-MBDT and 1-MBDT. Big height differences for these peaks indicate high maturities (Peters et al., 2005). Table 4.8 shows what the identified peaks represent.

Peak 5ame

4-MDBT 4-methyldibenzothiophene 1-MDBT 1-methyldibenzothiophene

Table 4.8. Components of m/z = 198 (Weiss et al., 2000).

m/z= 198

m/z= 192

4-MDBT 1-MDBT

Retention time

Intensity

Figure 4.14. Chromatogram of m/z= 198 and 192 of the aromatic fraction from NSO-1.

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33 5umber Identification

1 18α (H)-trisnorneohopane/(18α (H)-trisnorneohopane+17α (H)-trisnorhopane)=Ts/(Ts+Tm). (Seifert and Moldowan, 1978; Mackenzie, 1984).

2 Diahopane/(diahopane+normoretane) (Cornford et al., 1986). Diahopane=hopane x (Moldowan et al., 1991).

3 22S/(22S+22R) of C3117α(H), 21β(H)-hopanes (Mackenzie et al., 1980).

4 C30-hopane/(C30-hopane C30-moretane) (Mackenzie et al., 1985).

5 29Ts/(29Ts+norhopane) (Moldowan et al., 1991).

6 Bisnorhopane/(bisnorhopane+norhopane) (Wilhelms and Larter., 1994).

7 C23-C29tricyclic terpanes/C30 αβ-hopane (modified from Mello et al., 1988).

8 C24tetra cyclic terpanes/C30αβ-hopane (Mello et al., 1988).

9 Hopane/sterane from the C30αβ-hopane and regular C29 sterane (Mackenzie et al., 1984).

10 ββ/(ββ+αα) of C29 (20R+20S) sterane isomer (Mackenzie et al., 1980).

11 20S/(20S+20R) of C295α(H), 14α(H), 17α(H) steranes (Mackenzie et al., 1980).

12 Diasterane/(diasterane + regular sterane) (Mackenzie et al., 1985).

13 % C27of C27+C28+C29ββ-steranes (Mackenzie et al., 1985).

14 % C28 of C27+C28+C29 ββ-steranes (Mackenzie et al., 1985).

15 % C29of C27+C28+C29ββ-steranes (Mackenzie et al., 1985).

16 C20/ (C20+C28) triaromatic steroids (TA) (Mackenzie et al., 1985).

17 C28 TA/(C28TA+C29MA) (Peters and Moldowan., 1993).

18 Methylphenanthrene ratio, MPR (Radke et al., 1982b).

19 Methylphenanthrene index 1, MPI 1 (Radke et al., 1982a).

20 Methylphenanthrene distribution factor (F1 or MPDF) (Kvalheim et al., 1987).

21 Methyldibenzothiophene ratio, MDR (Radke., 1988).

22 Calculated vitrinite reflectivity, Rm(1)=1.1*log10 MPR+0.95 (Radke., 1988).

23 Calculated vitrinite reflectivity, %Rc=0.6*MPI 1+0.4 (Radke and Welte., 1983).

24 Calculated vitrinite reflectivity, %Ro=2.242*MPDF-0.166 (Kvalheim et al., 1987).

25 Calculated vitrinite reflectivity, Rm(2)= 0.073*MDR+0.51 (Radke., 1988).

26 3-methylphenanthrene/4-methyldibenzotiophene (Radke et al., 2001).

27 MDBTs/MPs (Radke et al., 2001).

Table 4.9. Table is explaining the different peaks represented in the chromatograms (Weiss et al., 2000).

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34 4.3.7 Explanation of parameters

Following parameters have been used for figures and discussions in this thesis. All parameters are listed in table 4.9.

Parameters from m/z=191 Parameter 1: Ts/(Ts+Tm)

Ts (C27 18α(H) trisnorneohopane) and Tm (C27 17α(H) trisnorhopane) represents peak 27dβS and 27dβS in m/z=191 (Fig. 4.7 on p. 27). An increase in thermal maturation will cause Ts to increase, and as Tm is more unstable, Tm will decrease. This maturity parameter was defined by Seifert and Moldowan (1978) and is best fit for immature, mature and over- mature oils with maximum ratio of 1.0 (Peters and Moldowan, 1993).

Parameter 3: 22S/(22S+22R)

Parameter 3 is 22S/(22S+22R) of C₃₁ 17α(H), 21β(H)-hopanes and represent peak 31αβS and 31αβR (Mackenzie et al., 1980) seen on m/z=191 (Fig. 4.7 on p. 27). Peak 31αβS and 31αβR are two isomers of C₃₁hopane and they represent a ratio which is useful for maturity indication. This parameter is often used for immature to early mature oils of an early stage in the oil window, and the value has its maximum at 0.6, where at this point the oil has reached top maturation.

Parameter 5: 29Ts/(29Ts+norhopane)

Parameter 5 is a ratio between 29Ts (peak 29Ts) and norhopane (peak 29αβ) seen on m/z=

191 (Fig. 4.7 on p. 27). It was introduced by Moldowan et al., (1991) and is used for maturity indication. 29Ts have higher stability than norhopane and thus this ratio will increase with increased thermal maturity (Hughes et al., 1985).

Parameter 6: Bisnorhopane/(bisnorhopane+norhopane)

Parameter 6 is a ratio between bisnorhopane and norhopane and represents peaks 28αβ and 29αβ in m/z=191 (Fig. 4.7 on p. 27). It is a facies parameter where bisnorhopane is assumed to indicate anoxic conditions (Peters and Moldowan, 1993). As bisorhopane breaks down more easily than norhopane, the ratio of the two will decrease with increased thermal maturity.

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35 Parameter 9: hopane/sterane

This is a facies parameter introduced by Mackenzie et al., (1984) where hopane represent peak 30αβ in m/z=191 (Fig. 4.7 on p. 27) and sterane represents peaks 29ααS, 29ββR, 29ββS and 29ααR in m/z=217 (Fig. 4.8 on p. 28). Steranes are derived from plants and animals while hopane derives from bacteria.

Parameters from m/z=217

Parameter 10: ββ/(ββ+αα) of C29 (20R+20S)

This is a maturity parameter where ββ represents peaks 29ββR and 29ββS in m/z=217 and αα represents peaks 29ααS and 29ααR (Fig. 4.8 on p. 28). It was introduced by Mackenzie et al., (1980). ββ seems to mature faster than αα so this ratio will decrease with increased thermal maturity. Maximum equilibrium is reached at the value of 0.67-0.71 (Seifert and Moldovan, 1986).

Parameter 11: 20S/(20S+20R) of C29 5α(H), 14α(H), 17α(H)

This is a maturity parameter where 20S represent peak 29ααS and 20R represents peak 29ααS in m/z=217 (Fig. 4.8 on p. 28). Equilibrium is reached in the middle of the oil window, at about 0.52– 0.55 (Seifert and Moldowan, 1986). This parameter can also be affected by facies and biodegradation.

Parameter 12: diasteranes/(diasteranes+regular steranes)

This is both a maturity and facies parameters introduced by Mackenzie et al., (1985) where diasteranes represent peaks 27dβS and 27dβR, and regular steranes represent peaks 29ααS, 29ββR, 29ββS and 29ααR in m/z=217 (Fig. 4.8 on p. 28). Diasteranes present silisiclastic rocks.

Parameters from m/z=218

Parameter 13: % C₂₇ of C₂₇+C₂₈+C₂₉–ββ steranes

This parameter represents peaks 27ββS, 28ββS and 29ββS in m/z=218 (Fig. 4. 9 on p. 28) and a percentage average of these three peaks is calculated. This is a facies parameter which is used to identify different depositional environments. 27ββS indicates a marine planktonic environment, 28ββS indicates a lacustrine environment, and 29ββS indicates a terrestrial influenced environment.

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36 Parameters from m/z=198 and 192

Parameter 21: Methyldibenzothiophene ratio, MDR

This is a maturity parameter where MDR represents both peak 4-MDBT and 1-MDBT in m/z=198 (Fig. 4.14 on p. 32). MDR=4-MDBT /1-MDBT (Radke, 1988).

Parameter 24: Ro= 2.242*MPDF–0.166

Calculated vitrinite reflection calculated from parameter 21, MDR, is a maturity pararameter.

This parameter was introduced by Kvalheim et al., (1987).

Parameter 25: Rm=0.073*MDR+0.51

Calculates vitrinite reflection calculated from parameter 21, MDR, is maturity parameter. This parameter was introduced by Radke et al., (1988).

Unusual Oils from Norway : Alternative petroleum systems?

Unusual oils from Scandinavia

-

Alternative petroleum systems?

Therese Simonsen

Unusual oils from Scandinavia

-

Alternative petroleum systems?

Therese Simonsen

Master Thesis in Geosciences

Discipline: Petroleum Geology and Geophysics Department of Geosciences

Faculty of Mathematics and Natural Sciences

UNIVERSITY OF OSLO

June, 2008

Acknowledgement

Abstract

Contents

1. Introduction

2. Sample set

3. Analytical methods

4. Maturity and facies parameters