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Faculty of Applied Sc%#c8 anfl Engineering The Norwegian University of Science and Technology Trondheim, Norway ^

NTNU I Dr. philos. thesis DISCLAIMER

Portions of this document may be illegible in electronic image products. Images are produced from the best available original document. Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Sunil Bharat:

a thesis accepted by

The Faculty of Applied Earth Science and

Norwegian U niversity of Science and Technology (NTNU) Trondheim, Norway

for public defense in partial fulfillment of the requirements for the Norwegian academic degree

dr. philos

December, 1997 ISBN 82-7861-089-4 © by Sunil Bharati March 1998. Printed in Norway by Tapir, Trondheim. To my mother and father, for always hoping and tomy wife, for keeping that hope alive. Contents i

Contents

Preface ...... v Executive Summary ...... vii Chapter 1: Introduction 1 Chapter 2 : Paper 1 Identifying diverse oil families in the Greater Ekofisk area, North Sea. Bharati, Hall and Bjor0y - under submission. 2.1 Abstract ...... 7 2.2 Introduction ...... 8 2.3 Samples and methods ...... 8 2.4 Geological setting ...... 10 2.5 Maturity variations ...... 10 2.6 Source facies variations ...... 15 2.7 The Greater Ekofisk oil families ...... 20 2.8 Conclusions ...... 22 2.9 Acknowledgments 23 2.10 References ...... 23

Chapter 3: Paper 2 Geochemical evaluation of the Embla field, Norwegian Continental Shelf - 1: Occurrence and compositional variations of migrated hydrocarbons. Bharati, Hall, Wagle and Bjorpy - under submission. 3.1 Abstract ...... 25 3.2 Introduction ...... 26 3.3 Geological elements and field history ...... 27 3.4 Samples and methods ...... 31 3.5 Mineralogical composition of reservoir sandstones ...... 33 3.6 Abundance of migrated hydrocarbons ...... 34 3.7 Variations in composition across the field ...... 38 3.8 Molecular characteristics ...... 40 3.9 Discussion ...... 45 3.10 Summary and conclusions ...... 52 3.11 Acknowledgments ...... 53 3.12 References...... 53

Norwegian University of Science and Technology ii Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Chapter 4: Paper 3 Geochemical evaluation of the Embla field, Norwegian Continental Shelf - 2: Source, infilling , and intra-reservoir communication. Bharati, Hall, Wagle and Bjor0y - under submission. 4.1 Abstract ...... 55 4.2 Introduction ...... 56 4.3 Geological background ...... 56 4.4 Samples and methods ...... 57 4.5 Maturity of the Embla oils ...... 58 4.6 Source of the Embla oils ...... 64 4.7 Possible filling directions ...... 72 4.8 Trap boundaries and communication ...... 76 4.9 Field productivity: implications of OWC and bitumen occurrence .. 77 4.10 Summary and conclusions ...... 78 4.11 Acknowledgments ...... 79 4.12 References ...... 80

Chapter 5: Paper 4 Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf -1: Occurrence, development and morphotypes. Bharati - under submission. 5.1 Abstract ...... 83 5.2 Introduction ...... 84 5.3 Geological background ...... 85 5.4 Reservoir bitumen: the less understood phase ...... 87 5.5 Occurrence and types of bitumen in the Embla Field ...... 88 5.6 Morphotypes of Embla bitumen ...... 94 5.7 Minerals in inter-granular space ...... 100 5.8 Summary and conclusions 106 5.9 Acknowledgments ...... 106 5.10 References ...... 106

Chapter 6: Paper5 Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf -2: Chemistry, structure and origin. Bharati - under submission. 6.1 Abstract ...... 109 6.2 Introduction ...... 110 6.3 Geological background ...... 110 6.4 Samples and methods ...... 110 6.5 Embla solid bitumen composition ...... Ill 6.6 The nature of carbon in the Embla bitumens ...... 114 6.7 Internal structure of the bitumen phase 116 6.8 Timing of bitumen formation ...... 118 6.9 Causes of bitumen formation ...... 127 6.10 Paleo-oil emplacement and destruction in Embla: A hypothesis .... 131 6.11 Implications of solid bitumen in the Embla Field ...... 132

Doctoral Dissertation by Sunil Bharati, 1997 Contents iii

6.12 Summary and conclusions 133 6.13 Acknowledgments 133 6.14 References ...... 134

Chapter 7: Paper 6 Calibration and standardization of Iatroscan (TLC-FTD) using standards derived from crude oils. Bharati, R0stum and L0berg -1994, Organic Geochemistry, v. 22, p. 835-862. 7.1 Abstract ...... 141 7.2 Introduction ...... 142 7.3 Analytical procedures ...... 144 7.4 Results and discussion ...... 145 7.5 Summary and conclusions ...... 167 7.6 Acknowledgments 168 7.7 References ...... 168

Chapter 8 : Paper 7 A new based standard for Iatroscan analysis. Bharati, Patience, Mills and Hanesand -1997, Organic Geochemistry, v. 26, p. 49-57. 8.1 Abstract ...... 171 8.2 Introduction ...... 172 8.3 Analytical procedures ...... 172 8.4 Results and discussion ...... 173 8.5 Conclusions 179 8.6 References ...... 180

Chapter 9: Paper 8 Elucidation of the Alum Shale structure using a multi-disciplinary approach. Bharati, Patience, Latter, Standen and Poplett -1995, Organic Geochemistry, v. 23, p. 1043-1058. 9.1 Abstract ...... 181 9.2 Introduction ...... 182 9.3 Samples and geology 182 9.4 Analytical methods 184 9.5 Results ...... 185 9.6 Discussion ...... 193 9.7 Conclusions ...... 196 9.8 References ...... 196

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Norwegian University of Science and Technology

Preface v

Preface

Statistically, this is yet another of more than hundred doctoral theses submitted to the Norwegian University of Science and Technology (NTNU), however personally it is gratifying. Not just because this thesis represents a finished product, but because the road to this thesis was educating and it gave me an opportunity to make a contribution to science.

Petroleum is the principal source of energy and each one of us uses at least one of its derived products daily; and it is likely that petroleum will maintain this status well beyond the next decade. However, the net petroleum quantity is limited in nature and as our needs multiply, our efforts must be directed towards utilizing this resource efficiently and prudently. An oil explorationist has in addition, another paramount responsibility- that of finding more , particularly those which can be commercially developed. As most of the ‘easily ’ identifiable fields in the current petroleum provinces of the world have already been discovered, the current technology is directed more towards finding structures which were relatively ‘invisible* until now. Another strategy being pursued today is to re-define past discoveries using modem methods with a view to increasing their and improve recovery factor. Such a strategy requires a thorough understanding of the reservoir system, the migration pathways and the source of the oil in question. Undoubtedly, such an exercise demands a multi-disciplinary approach and application of new data.

The work reported in this thesis attempts to embrace this strategy using a wide variety of organic geochemical data. The studied field, Embla, has proven to be an excellent example to apply some of the newer ideas in Reservoir Geochemistry and has in addition provided a sample set, unique to the North Sea in many ways. Although the Embla Field is in one of the most prolific regions of the Norwegian Continental Shelf, the Central Graben, its petroleum population is significantly different from neighbouring fields in more than one way. It is my hope that the data generated and the conclusions reached in this study prove useful towards a better understanding of the migrated hydrocarbons and form an effective database to plan Embla’s future development. This was my ultimate goal of undertaking this work.

Achieving this goal has not been without impediments. While more than the last four years of work has been immensely educating and rewarding, it was not without setbacks and disappointments. Having a full-time job during this period (most of the reported work was done in my private time) and no formal supervisor for this study slowed the progress. Not being able to obtain proper and adequate funding and dependency on only private resources was also a major setback. Fortunately, partial funding was obtained from three sources - The

Norwegian University of Science and Technology vi Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Norwegian Research Council (NFR), Phillips Petroleum Co. Norway and Amoco Norway. To these organizations, I owe deepest thanks.

Philips Petroleum is especially thanked for providing samples and permission to publish. Its co-venturers, including Fina Exploration Norway SCA, Norske Agip AS, Elf Petroleum Norge AS, Norske Hydro Production AS, Statoil AS, Total Norge AS and Saga Petroleum AS are also acknowledged for permission. My employer, Geolab Nor, is also thanked for giving permission to pursue this study.. Last but not the least, I owe my gratitude to the Department of Geology & Mineral Resources Engineering, NTNU for providing office facilities for more than a year and constant support to complete my thesis.

Several people from various walks of life have played a major role in assisting me in one way or the other to complete the task I had undertaken. First and foremost, I thank my parents for making me capable of seeing this day and my wife, Sangeeta, who endured me uncondi ­ tionally. On the more professional front, my particular thanks to: Kare Vagle (Phillips Petroleum) for constant interest and discussions; Joe Curiale (Unocal, USA) for reviewing early drafts of papers 4 & 5, Richard Patience (Statoil) for reviewing early drafts of papers 2 & 3 and Chip Feazel (Phillips Petroleum) for final corrections; Peter B. Hall (Geolab Nor) for sharing my thoughts and introducing new ideas; Malvin Bjor0y (Geolab Nor), Girish Saigal and Idar Horstad (both Saga Petroleum) for several informal discussions and advice; Geolab Nor staff (several geochemical analyses), Kjell Muller and Morten Raanes (SEM), Prof. John Attard and Winfried Kuhn (NMR), Prof. Ragnvald H0ier and Sigmund Andersen (TEM), Ivar R0mme (XRD) for assistance in analyses. Several figures were drawn by Anne Irene Johannessen. I would also like to extend my sincere thanks to Prof. Elen Roaldset for providing the appropriate platform to complete my work and taking interest in my work.

I apologize to my daughter, Shipra, for all those missed weekends and evenings.

Last, thanks to planet Earth, for providing both rocks and oil !

Sunil Bharati Trondheim, Norway December, 1997

Doctoral Dissertation by Sunil Bharati, 1997 Executive Summary vii

Executive Summary

Based on geochemical analyses of a suite of 68 oils from 16 fields of the Greater Ekofisk area, Norwegian Continental Shelf, it became apparent that the Embla oils were outliers with respect to composition and maturity. While most Greater Ekofisk oils are emplaced in Cretaceous chalk reservoirs, the Embla oils besides being the most mature, are trapped in Paleozoic sandstones. In addition to the oils becoming steadily more mature from Hod and Valhall in the southeast to Albuskjell in the northwest, two principal source facies have played a major role with respect to regional generation. The one which has sourced majority of the Cretaceous chalk reservoired oils is isotopically light and the other which has sourced the pre- Cretaceous sandstone reservoired oils is isotopically heavy and anomalously enriched in isoprenoids.

A detailed investigation of the Embla reservoir and its petroleum population was carried out with the following objectives: evaluate migrated hydrocarbons with respect to composition, maturity, intra-reservoir communication, compartmentalization and filling history of the field; characterize, map and explain the presence of immobile solid reservoir bitumen phase (paleo- oil) and discuss its origin and implications on overall reservoir quality.

Wide-ranging geochemical investigations (XRD, RE, Iatroscan, GHM, GC, GC-MS, GC- IRMS, bulk isotopes etc.) using a suite of >900 core samples and six oils from Embla, revealed that the field is highly complex. The Embla reservoir, consisting of the Uppermost, Upper and Lower Sandstones of yet unknown ages, contains two distinct types of oil, A and B, although both the oils are very light. The Upper Sandstone, with well developed , is richer in hydrocarbons but also relatively non-homogenous, when compared to the Lower Sandstone. This, in all likelihood, is due to extensive asphaltene-rich solid bitumen in the latter. The two oil types differ slightly in composition and maturity, due to two kitchens feeding the reservoir, although both oils are highly mature. Compositionally, the signature of migrated petroleum changes both horizontally across the various traps and vertically with increasing depth. This is particularly evident in the Lower Sandstone traps LSI and LS2, where the relative non-hydrocarbon percentage increases dramatically with depth.

With regards to maturity, oil type A is slightly less mature than oil type B. This is based more on the aromatic hydrocarbon based maturity ratios than on biomarker based ratios, as the latter are considered less reliable due to high maturity of the oils. However, both oil populations have been generated by the ‘abnormal ’ Upper Jurassic organic facies, characterized by isotopically heavier n-alkanes and in particular, anomalous enrichment of isotopically very heavy isoprenoids. The

Norwegian University of Science and Technology viii Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea two oil charges are believed to have been from the west and/or north-west, where the kitchen for the Embla oils is estimated to lie. Minimal or no mixing of the two oil charges has taken place in the Embla reservoirs, suggesting that the individual traps have been well isolated prior to and since oil emplacement. Generation and migration of Embla oils from the east (of Skrubbe Fault) or locally occurring Upper Jurassic units is thought to be unlikely.

The data from the present study indicate that the Embla Field is highly compartmentalized and the individual fault blocks are not in communication, either laterally or vertically. The fact that during the last five years of production from Embla no pressure communication was observed, supports this finding. Perhaps this is also the reason why the oil-water contacts (OWC) occur at different depths in different traps, the difference being to the extent of about 200 m. The OWC is found to be shallowest (estimated ‘oil down to ’ 4325 m TVDSS) in well 21S (trap LSI) and deepest (+4548 m TVDSS) in well 26S (trap LS2); in wells 23S/27S (trap UM2) it is estimated to be in between (>4400 m TVDSS). The deep OWC in LS2 has serious implications with respect to future exploration and opens up the possibility of more oil occurring NW and SE of well 26S, provided the sand body with good reservoir properties extends in these directions.

Interference from oil-based mud contaminants is quite severe in nearly the entire suite, which has restricted detection of underlying differences in the Embla oil population. In particular, the abundance data is thought to have been most adversely affected. While this problem cannot be avoided in the case of Embla Field, it should not be overlooked or underestimated. Neither should this problem become the reason for discarding all data or not reaching rational conclusions which are based on established principles and previously published works. It was possible to establish the gross differences based on a combination of various techniques. The data from the present study suggests that the order of richness of various traps is: UM2 (richest), US2, UM1, LS3, LSI and LS2 (relatively least rich).

The lower part of the reservoir, particularly the Lower Sandstone, has a high content of solid reservoir bitumen (a condensed, insoluble and highly aromatic carbon phase). This very high TOC, black and vitreous phase is at the present day emplaced as an ‘oil cement’, reducing severely the bulk porosity and permeability of the host rock. Solid bitumen also represents the immobile and permanently lost phase of migrated hydrocarbons. Extensive NMR, SEM and TEM examination shows that a variety of morphotypes are present, each having unique topographical properties, which are controlled more by the pore space geometry than composition. The bitumen occurs in a variety of modes such as filled cavities, open vugs, veins, fractures, carpet and disseminated. Each habitat of occurrence is characterized by special and unique properties, which have become the basis of classifying the Embla bitumens into different morphotypes, namely 1) massive (consisting of types A, B & C), 2) spheroidal, 3) rosette, 4) foliated (types A & B), 5) zygotic, 6) vein, 7) carpet and 8) disseminated.

Doctoral Dissertation by Sunil Bharati, 1997 Executive Summary ix

Further investigation of the pore space and related diagenetic minerals showed that some minerals (barite and pyrite) are almost exclusively associated with the bitumen phase, perhaps representing the aqueous phase of petroleum. Its insolubility in organic solvents, low H/C ratio and high aromaticity indicate its condensed nature and large molecular size, although partially contradicting data is obtained by Py-GC. More than 30% of all carbon in the Embla bitumen is found to be aromatic ring carbon and aliphatic carbon is a minor component. Detailed examination of bitumen samples by SEM and TEM indicates that the process of bitumen solidification was slow, controlled and methodical and post-date all the major diagenetic events such as kaolinite precipitation and quartz cementation. The actual cause of bitumen formation is not entirely clear in the case of Embla, but deasphalting may have played an important role. While the original precursor of the solid bitumens is believed to have been a free-flowing and perhaps a ‘normal ’ oil, its immediate precursor is thought to have been a viscous phase, rich in asphaltic species and with limited mobility and limited labile components. The present oil population is not related to the solid bitumen and represents an entirely independent oil charge.

The top of the bitumen zone has been established in all five wells studied based on visual examination of cores and pyrolysate compositions. Apparently, the depth of bitumen occurrence is variable across the field and independent of oil water contacts and evidently the overall bitumen abundance increases with increasing depth. Solid reservoir bitumen occurrences are known to have detrimental effects on the overall reservoir properties. Proper understanding and mapping of the such occurrences and the geochemical assessment and filling history of the petroleum charge in the Embla Field has allowed a better understanding of the recoverable reserves and future field development and production strategy.

New calibration and analytical methods (Iatroscan analysis and carbon characterization by NMR) were also developed during the course of the study.

The TLC-FTD technique, using the Iatroscan instrument, has now become a widely used and reliable method for characterization of solvents extracts and crude oils. Due to limited reported research, a study was specifically aimed at identifying, separating, characterizing, testing and developing a standard, derived from crude oil(s), that is well suited for quantification purposes. This was performed successfully using a suite of 30 crude oils from world-wide basins, ranging in maturity and composition. Response factors calculated from crude oil based aliquots differed significantly from synthetically prepared standards, proving thereby a greater validity of the former. Subsequently, based on the established method and principles of the pilot study, a new Iatroscan calibration standard was made from the North Sea Oil-1 from the Oseberg field, as this oil was chosen by the Committee for the Norwegian Industry Guide to Organic Geochemical Analyses to serve as a standard for other analytical techniques. The composition of the gravimetrically prepared standard was kept comparable to

Norwegian University of Science and Technology X Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea the original oil. Employment of this standard by different laboratories has made the comparison of inter-laboratory Iatroscan analyses data more reliable.

The second method tested during the course of the study and prior to analysis of Embla samples, was characterization of organic carbon using 13C CP/MAS NMR technique. Using a suite of some Scandinavian , the nature of organic carbon was described with respect to gross aromaticity, various carbon types and functional groups present in the complex carbon structure. Describing and understanding the structural features of kerogen and naturally occurring asphaltic molecules has historically been a difficult subject and to an extent enigmatic, primarily due to analytical limitations to resolve the complex structures. The NMR technique, as used in the study, has allowed a greater latitude towards understanding and elucidating the structural elements that comprise kerogen and coals, or solid bitumen as in the case of Embla, by way of semi-quantitatively assessing the carbon-carbon, carbon- hydrogen and carbon-oxygen bonds.

Doctoral Dissertation by Sunil Bharati, 1997 Introduction 1

Chapter 1

Introduction

The North Sea, particularly the Central Graben, is the cornerstone of Norwegian . The Central Graben, which is endowed with several major oil fields, is also the region where Norwegian oil exploration activity was initiated in mid-60s, leading to discovery of the first Norwegian oil field, Ekofisk, in 1969 (Feazel et al., 1990). Despite the discovery of several major structures in the last three decades or so, active exploration for satellite fields and reassessment of proven structures using modem technologies continues today. This is important in the light of changed socio-economic conditions and increasing oil production costs. However, proper understanding of the sub-sea structures and the fluids contained therein requires synthesis of several types of data, which were regarded as independent of each other until a few years ago. In addition, newer types of data sets are now recognized to play a vital role in achieving a proper definition of oil & gas reservoirs. One such example is organic geochemical data, particularly from the pay-zones and reservoir sections.

While Organic Geochemistry as a science was well established in the 1950s, it was mostly in relation to source rocks (e.g. Hunt and Jamieson, 1956) and geared towards source potential and maturity. Its application to reservoirs and their fluids, however, is relatively recent with most of the pioneering work being done by England and co-workers (e.g. England and Mackenzie, 1989). Reservoir Geochemistry has since been tested and applied by several schools worldwide and is guided by one key observation that reservoir fluids (water and petroleum) are often compositionally heterogeneous, both laterally across the field and vertically down the reservoir. These variation trends can be, amongst other things, extrapolated to the kitchen areas where the oil population is believed to have been generated. Such an application gains significance particularly because wells are typically drilled in the structural highs and not the basinal areas where the source rocks may be located. Moreover, concepts such as a field’s filling history and migration pathways have become clearer with the introduction of modem geochemical databases.

It is with this background that the present study was undertaken using more than 1000 core samples from several wells and about 100 oils from several fields. The analytical techniques applied include screening (TOC, Rock Eval, Iatroscan, thermal extraction-pyrolysis-gas chromatography- TE-PY-GC, XRD), follow-up (liquid chromatography - MPLC, capillary gas chromatography - GC, gas chromatography-mass spectrometry - GC-MS, compound specific

Norwegian University of Science and Technology 2 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea isotope ratio-mass spectrometry - GC-IRMS, bulk 13C isotopes, elemental analysis, chemical degradation) and optical (stereo microscopy, scanning electron microscopy - SEM, transmission electron microscopy - TEM). The wide variety of this large geochemical database is presented in this thesis in the form of eight papers, three of which are already published and the rest are under submission.

The Greater Ekofisk region, with sixteen major oil fields, has been shown to comprise highly variable oil families. This variation has been attributed to both source facies (Northam, 1985; Forsberg et al., 1993) and maturity (Hughes et al., 1985; Bjor0y et al., 1994). As the number and variety of oil samples available from this area far exceeds those typically encountered, the Central Graben serves as a useful natural laboratory. However, most workers concentrated mainly on the Cretaceous Chalk reservoired oils from the area, as these are the principal pay- zones (Tor, Hod and Ekofisk Formations). Not much thought was given to the possibility of pre-Cretaceous plays, mainly due to their greater depth in most regions. The general conception was that if any petroleum was present in these deeper prospects, it would at best be gas or gas/condensate. This view changed sometime in the late 1980s with the discovery of oil in some Jurassic and pre-Jurassic clastic sequences.

Geochemical data on the pre-Cretaceous oils is scarce. It was with this idea that a pilot study was undertaken to identify the different oil families in the Greater Ekofisk region, with emphasis on comparison of Cretaceous Chalk reservoired oils to pre-Cretaceous sandstone reservoired oils. The findings are reported in Paper 1 “Identifying diverse oil families in the Greater Ekofisk area, Central Graben, Norwegian Continental Shelf’. While significant maturity variations within the Cretaceous oils was reported earlier (Hughes et al., 1985; Bjor0y et al., 1994), this paper addresses the issue from a slightly different perspective using GC-IRMS fingerprinting. This study also revealed how different the Jurassic and pre-Jurassic reservoired oils are from Cretaceous oils, from the point of view of not just maturity but also the source facies. This pilot study formed the basis of studying the pre-Cretaceous reservoired oils, particularly those from Embla where extensive coring was performed and which was considered to be structurally complex.

The Embla Field is the only major field in the Central Graben with pre-Cretaceous reservoirs. In addition, it has one of the deepest reservoirs of the region - exceeding 4 km. Several factors are responsible for undertaking a detailed geochemical evaluation of the Embla Field: a) it was relatively a new discovery, b) preliminary RFT data pointed towards the possibility of compartmentalization, c) extensive core samples were available, including from those wells which were only recently completed and d) it was different from neighbouring fields in most respects. The basic geochemical data with respect to richness and composition is presented in Paper 2 “Geochemical evaluation of the Embla field, Norwegian Continental Shelf - 1: Occurrence and compositional variations of migrated hydrocarbons ”. This paper also

Doctoral Dissertation by Simil Bharati, 1997 Introduction 3 covers the internal variations (laterally across the field and vertically down the reservoir) observed in the signature of migrated hydrocarbons. The geochemical data is interpreted in the light of available petro-physical data. As it was found that the migrated hydrocarbons in the reservoir units are heterogeneous, a closer look into their maturity and possible source variations was necessary. This aspect is addressed in Paper 3 “Geochemical evaluation of the Embla field, Norwegian Continental Shelf - 2: Source, infilling, and intra-reservoir communication ”. In addition, this paper also discusses interpreted compartmentalization and estimates the locations of oil-water contacts in various parts of the field based on geochemical data. Various oil-charge scenarios and their implications are presented in the light of available source rock data.

During the course of this study, another phenomenon was observed in sandstones of yet undetermined age comprising the Embla reservoirs: extensive occurrence of solid reservoir bitumen. Such an occurrence, particularly from the abundance point of view, has not yet been reported in the North Sea. Initially, it was thought to be and termed ‘pyrobitumen ’. All the cores were re-examined with an aim to obtain a clearer picture and to re-sample portions which were rich in solid bitumen. As this solid bitumen was insoluble in common organic solvents, its characterization became limited to bulk and optical methods. The preliminary examination of solid bitumen using mainly scanning electron microscopy (SEM) is presented in Paper 4 “Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf -1: Occurrence, development and morphotypes ”. This paper also discusses current beliefs about this less understood organic phase. Detailed examination of several samples from across the field reveal that this is not a randomly present phase, but occurs in a methodical manner and in a variety of forms, shapes and morphology. The sheer magnitude of its occurrence in Embla demanded a closer look with regards to its chemistry, structure and origin. These aspects, based mostly on available optical evidence and geological data are reported in Paper 5 “Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf -2: Chemistry, structure and origin ”. The bulk techniques used to understand this immobile migrated hydrocarbon phase included pyrolysis-gas chromatography (PY-GC), elemental analysis, nuclear magnetic resonance spectroscopy (NMR) and transmission electron microscopy (TEM). Several possible causes for its emplacement are discussed and a possible hypothesis on its origin presented, in light of observed evidence. Its implication on reservoir quality and its relationship to the present mobile (producible) oil phase is also discussed.

During the course of this study, some newly established methods in geochemistry were also utilized, namely Iatroscan and carbon type analysis using NMR. Although not directly related to the main Embla sample set, these findings are reported in the last three papers. Their relevance lies in the fact that data generated through these two techniques has proved to be of immense use in reaching the conclusions the main Embla study.

Norwegian University of Science and Technology 4 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

The TLC-FTD technique, using the Iatroscan instrument, which constitutes separation and quantification of a complex mixture such as crude oil or solvent extract, has recently become a widely used and reliable method in the oil industry. Therefore its correct calibration is of great importance, an aspect which was not adequately addressed. The first of the two papers on Iatroscan, Paper 6 “Calibration and standardization of Iatroscan (TLC-FID) using standards derived from crude oils ”, mainly aims to develop a standard for correct calibration of the instrument. This was achieved using a sample set of 30 crude oils from several basins of the world, covering a wide range in maturity, API gravity, source rock type, degree of biodegradation, reservoir rock type and composition. A reliable standard with a high degree of reproducibility was thus created. Immediately thereafter, the Committee for the Norwegian Industry Guide to Organic Geochemical Analyses (NIGOGA) decided that an oil from the Oseberg Field (NSO-1) be used as a standard for analytical techniques such as liquid chromatography, gas chromatography and gas chromatography-mass spectrometry. In light of this development, it was logical to develop the new Iatroscan standard based on the Oseberg oil. This is reported in the second Iatroscan related paper, Paper 7 “A new North Sea oil based standard for Iatroscan analysis ”. Since its development, the new Iatroscan standard has been recognized as the only 'officially accepted' standard for all Iatroscan analyses.

Paper 8 “Elucidation of the Alum Shale kerogen structure using a multi-disciplinary approach ” applies the technique of carbon-type analysis of kerogens proposed by Mann et al. (1991) and uses the Alum Shales from Sweden as a test case. This paper also demonstrates the practical utility and validity of integrating data obtained from a variety of analytical techniques to understand, elucidate and model kerogen* s complex chemical structure. Although this study is only peripherally related to the main substance of the thesis and used isolated kerogens from a Scandinavian source rock as the sample suite, the principles and methodology developed proved to be useful in understanding the nature of carbon of the Embla solid reservoir bitumens. This is paper is also included in this thesis for the sake of completion and to serve as a ready reference on this subject to readers.

As it has been attempted to make each of the eight papers complete by itself and independent of each other, each paper carries its own summary and conclusions. This thesis therefore has no common conclusion at the end.

Doctoral Dissertation by Sunil Bharati, 1997 Introduction 5

R eferences

Bjor0y, M., Hall, K. and Moe, R. P., 1994, Stable carbon isotope variation of n-alkanes in Central Graben oils, Organic Geochemistry, v. 22, p. 355-381.

England, W. A. and Mackenzie, A. S., 1989, Geochemistry of petroleum reservoirs: Geologische Rundschau, v. 78, p. 291-303.

Feazel, C. T., Knight, I. A. and Pekot, L. J., 1990, Ekofrsk Field-Norway, Central Graben, North Sea, in E. A. Beaumont and N. H. Foster, eds., Structural Traps IV, Treatise of , Am. Asso. of Pet. Geol., Tulsa: p. 1-26.

Forsberg, A., Gowers, M. B. and Holtar, E., 1993, Multi-disciplinary stratigraphic analysis of the Upper Jurassic strata of the Norwegian Central Trough, in A. M. Spencer, ed., Generation, accumulation and production of Europe ’s hydrocarbons HI: Springer-Verlag, Berlin, p. 45-58.

Hughes, W. B., Holba, A. G., Miller, D. E. and Richardson, J. S., 1985, Geochemistry of Greater Ekofisk oils, in B. M. Thomas et al„ eds., Petroleum Geochemistry in exploration of the Norwegian Shelf: Graham & Trotman, London, p. 75-92.

Hunt, J. M. and Jamieson, G. W., 1956, Oil and organic matter in source rocks of petroleum: AAPG Bulletin, v. 40, p. 477-488.

Mann, A. L., Patience, R. L. and Poplett, I. J. F., 1991, Determination of molecular structure of kerogens using 13C NMR spectroscopy: I. Effects of variation in kerogen type: Geochimica Cosmochimica Acta, v. 55, p. 2259-2268.

Northam, M. A., 1985, Correlation of northern North Sea oils: the different facies of their Jurassic source, in B. M. Thomas et al., eds., Petroleum Geochemistry in exploration of the Norwegian Shelf: Graham & Trotman, London, p. 93-99.

Norwegian University of Science and Technology 6 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Doctoral Dissertation by Sunil Bharati, 1997 Paper 1: Diverse oil families in the Greater Ekofisk area, Central Graben, Norway 7

Chapter 2 : Paper 1

Identifying diverse oil families in the Greater Ekofisk area, Central Graben, Norwegian Continental Shelf§

Sunil Bharati, Peter B. Hall and Malvin Bjor0y

Geolab Nor, N-7002 Trondheim, Norway

2.1 Abstract

The Central Graben in the North Sea is one of the most prolific petroleum basins of the world and the cradle of Norwegian petroleum exploration and production. The many oil and condensate fields that this area is endowed with, including Norway ’s first commercial field, Ekofisk, vary significantly with respect to petroleum composition and maturity. Using a sample suite of 68 oils from 16 oil fields in the Central Graben area, the main compositional and maturity differences between the Cretaceous chalk reservoired oils (found in majority of the fields) to pre-Cretaceous sandstone reservoired oils (Embla and wells 19R and 3X) have been exemplified. A wide-ranging geochemical database of whole oils (gas chromatography, bulk carbon isotopes, compound specific isotope ratios and biomarkers) was used to meet the objectives of the study. In addition to the oils becoming steadily more mature from Hod and Valhall in the southeast to Albuskjell in the northwest, two principal source facies have played a major role with respect to regional generation. The one which has sourced majority of the Cretaceous chalk reservoired oils is isotopically light (represented by the Edda oil end- member) and the other which has sourced the pre-Cretaceous sandstone reservoired oils is isotopically heavy and anomalously enriched in isoprenoids (represented by the 3X oil end- member). These data were also used to define the diverse oil families on a regional scale in the study area.

5 Manuscript under submission to Marine and Petroleum Geology

Norwegian University of Science and Technology 8 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

2.2 Introduction

The discovery of Groningen in 1959, the giant gas field in the Netherlands, triggered oil exploration in Norway and the first well in the North Sea was drilled a decade later (well 2/4- IX by Phillips Petroleum). Due to technical problems, this well was abandoned and a second well, the Phillips 2/4A-1X, was drilled immediately thereafter, which was the first discovery well of Norway (Feazel et al, 1990). Since then, the Central Graben in the North Sea has proved to be one of the most prolific petroleum basins of the world, with several giant discoveries. This is primarily due to thick sections of Upper Jurassic shales, which are considered to be the principal source of most petroleum systems in the region, being deeply buried in this region (Cooper and Barnard, 1984). Varying depths of burial and organic facies (Bailey et al., 1990) have generated oils differing from the composition and maturity point of view. This aspect has been addressed to some extent by Hughes et al. (1985) using a suite of 30 chalk reservoired Greater Ekofisk oils. Bjor0y et al. (1994) have also studied the Central Graben oils using primarily the GC-IRMS technique to conclude that internal differences occur within the Cretaceous chalk reservoired oils.

The objective of this paper, however, is mostly to highlight the differences between the Creta­ ceous chalk reservoired oils to pre-Cretaceous sandstone reservoired oils, in addition to identi­ fying the diversity of oil families with respect to composition and maturity in the Greater Ekofisk area. Only broad and regional properties and differences between the oils have been considered, as it is not the aim of this study to highlight the fine and subtle differences within a field, but discriminate one field from the other and model the oil families on a regional scale.

2.3 Samples and Analytical Methods

To meet the objectives of this study, we have used a suite of 68 oils from 16 oil fields (Table 1) - from Albuskjell in the north to Gert in the south, the latter being on the Norwegian-Danish border (Figure 1).

Topped oils were deasphaltened using excess (lOx by volume) n-hexane, filtered and separated into saturated and aromatic hydrocarbons and polar fractions using MPLC. Whole oil aliquots were analyzed by:

1) Capillary gas chromatography using a Perkin Elmer Sigma 2000 GC equipped with FED and FPD detectors and using a SE-54 column (25m, 0.20 mm i.d., 0.1 pm film thickness) under pre-programmed temperature conditions (initial -10 °C for 2 min, then to 300°C at 4°C/min, final hold time 15 min).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 1: Diverse oil families in the Greater Ekofisk area, Central Graben, Norway 9

Afcuskjen

Ekofisk

TommeBlen Gamma Ekofisk

EldfisJc Bravo

2/7-19R

Valhall EMBLA

Figure 1: Map showing the location of the Greater Ekofiskfields included in this study.

2) Stable carbon isotope ratio measurement using a VG SIRA 10 mass spectrometer. Combus ­ tion is performed by a Carlo Erba EA 1108 element analyzer (This analysis was also performed on saturated, aromatic and polar fractions). 3) Gas chromatography-isotope ratio-Mass spectrometry (GC-IRMS) using a VG Isochrom II system interfaced to a Dani 8510 gas chromatograph fitted with a OV-1 col umn (50m, 0.32 mm i.d.). The GC was operated under pre-programmed temperature conditions (initial 50 °C for 2 min, then to 300°C at 4°C/min, final hold time 20 min). Isotope ratio calculations were performed using CO2 as a reference gas. 4) Gas chromatography-Mass spectrometry (GC-MS) using a VG TS250 system interfaced to a HP 5890 gas chromatograph, the latter fitted with a SE 54 column (40m, 0.22 mm i.d.).

Norwegian University of Science and Technology 10 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

The GC was operated under pre-programmed temperature conditions (for saturated hydrocarbons: initial 45 °C to 150 °C at 35°C/min, then to 310°C at 2°C/min, final hold time 15 min; for aromatic hydrocarbons: initial 50 °C to 310 °C at 5°C/min, final hold time 15 min; for). The mass spectrometer is operated in electron impact (El) mode at 70 eV, a trap to current of 500 |iA and source temperature of 220°C. 5) A selected suite of saturated and aromatic hydrocarbon fractions (39) were also subjected to gas chromatography (GC). A Perkin Elmer 8320 equipped with an FED and an OV1 column (25 m, 0.25 mm i.d.) was used for the saturated hydrocarbons with a temperature program of 80-300°C at 4°C/min (final hold time 20 min). For the aromatic hydrocarbons, a Varian 3400 equipped with a split injector, FID and FPD and SE54 column (25 m, 0.25 mm i.d.) was used. The temperature program was 40-290°C at 4°C/min (final hold time 10 min).

2.4 Geological setting

This has been described in detail in several previous publications (e.g. Van den Bark and Thomas, 1981; Gowers and Saebpe, 1985; Fraser et al., 1993). Briefly, the Central Graben comprises of a series of en echelon normal and strike slip faults initiated in the Triassic period and active through the Mesozoic era. Graben subsidence continued during the Jurassic and Early Cretaceous periods, along with associated fault inversions thus creating local highs and basins. Halokinesis of thick Permian evaporites further complicated the structural and sedimentological evolution of the graben. Restricted basinal conditions which prevailed during the Late Jurassic period resulted in thick organic-rich shales (the Mandal / Farsund Formations), the major petroleum source for the area. Widespread basinal subsidence during the Late Cretaceous period accompanied by eustatic and climatic changes resulted in the deposition of more than 1000 m thick chalk sequences, the major reservoir of the region. Continued tectonic activity and ongoing halokinesis resulted in extensive remobilization, redistribution and reworking of the chalks into the graben. The Maastricht!an / Danian age Ekofisk and Tor Formations are the principal reservoir units of most of the oil fields in the Greater Ekofisk area.

2.5 Maturity variations

The API gravity of the Greater Ekofisk Cretaceous oils vary significantly - from about 31-35° in Hod and Valhall in the south to about 45-50° in Tommeliten and Albuskjell in the north (Hughes et al., 1985; Bjorpy et al., 1994). These workers have also shown that there exists a definite maturity trend in the Cretaceous reservoired oils across the region, although Bjor0y et al. (1994) have stressed that some of the observed differences in the traditional geochemical parameters are due to source facies differences.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 1: Diverse oil families in the Greater Ekofisk area, Central Graben, Norway 11

The pristane/nCn and phytane/nCig ratios can be useful to assess maturity if all the oils are sourced from the same source rock facies. However, different maturity trends will indicate differences in depositional environments (Le Tran and Phillipe, 1993).

Table 1: Oil samples from the Greater Ekofisk region used in this study. The symbol in the oil type column denotes the formation from which the sample has been obtained.

Field Well Code Type Field Well Code Type 1 No name * 2/7-19R 19R DST1 □ 35 Tommeliten Gamma ♦ 1/9-6 TG7 DST 4 § 2 No name * 2/7-3X 3X DST 18 n 36 Edda ♦ 2/7-4 ED1 DST 5 § 3 Embla * 2/7-20X EMI DST 1 # 37 Edda ♦ 2/7-5X ED2 DST 3" 4 Embla * 2/7-21S EM3 DST 1 # 38 Eldfisk Bravo ♦ 2/7B-12 EB1 P.S. * § 5 Embla * 2/7-21S EM2 DST 3# 39 Eldfisk Bravo ♦ 2/7B-12 EB2 P S. * § 6 Embla * 2/7-26S EM5 DST 1 # 40 Eldfisk Bravo ♦ 2/7B-12 EB3 P.S. * § 7 Embla * 2/7-26S EM4 DST 2# 41 Eldfisk Bravo ♦ 2/7B-12 EB4 P.S. * § 8 Embla * 2/7-27S EM6 DST 1 # 42 Eldfisk Bravo ♦ 2/7B-10 EB5 P.S.'§ 9 Albuskjell ♦ 1/6-1 AU DST 3* 43 Eldfisk Bravo ♦ 2/7B-12 EB6 P.S. * § 10 Albuskjell ♦ 1/6-3 AL2 DST 2* 44 Eldfisk Bravo ♦ 2/7B-3 EB7 PS." § 11 Albuskjell ♦ 1/6-A10 AL3 P.S.* 45 Eldfisk Bravo ♦ 2/7B-6 EBB P.S. * § 12 Albuskjell ♦ 1/6-A7 ALA P.S.* 46 Eldfisk Bravo ♦ 2/7B-6 EB9 P.S.*§ 13 Tor ♦ 2/5-2 TOI DST 2* 47 Eldfisk Bravo ♦ 2/7B-9 EB10 P S. * § 14 Tor 2/5-4 TQ2 DST 1 * 48 Eldfisk Bravo ♦ 2/7B-9 EB11 P S. * § 15 S.E. Tor ♦ 2/5-5 SCI DST 3* 49 Eldfisk Bravo ♦ 2/7B-9 EB12 P S. * § 16 S.E. Tor ♦ 2/5-7 ST2 DST2§ 50 Eldfisk Bravo ♦ 2/7B-9 EB13 P.S.*§ 17 Ekofisk ♦ 2/4-4AX EK1 DST 4 = 51 Eldfisk Bravo ♦ 2/7D-1B EB14 P.S.*§ 18 Ekofisk ♦ 2/4B-3A EK2 P.S.* 52 Eldfisk Alpha ♦ 2/7A-10 EA1 P.S.*§ 19 W. Ekofisk ♦ 2/4-5X WE1 P.S.* 53 Eldfisk Alpha ♦ 2/7A-11 EA2 P.S.§ 20 W. Ekofisk ♦ 2/4D-1B WE2 P.S.§ 54 Eldfisk Alpha ♦ 2/7A-16A EA3 P.S.*§ 21 Tommeliten Alpha ♦ 1/9-1 3M DST1B = 55 Eldfisk Alpha ♦ 2/7A-19 EA4 P.S.* 22 Tommeliten Alpha ♦ 1/9-1 TA2 DST 4* 56 Eldfisk Alpha ♦ 2/7A-2 EA5 P.S. = 23 Tommeliten Alpha ♦ 1/9-1 TA3 DST 5* 57 Eldfisk Alpha ♦ 2/7A-21 EA6 P.S.*§ 24 Tommeliten Alpha ♦ 1/9-1 TA4 DST 8 § 58 Eldfisk Alpha ♦ 2/7A-23 EA7 P.S. * § 25 Tommeliten Alpha ♦ 1/9-2 TA5 DST 1 * 59 Eldfisk Alpha ♦ 2/7A-26 EA8 P S. * § 26 Tommeliten Alpha ♦ 1/9-2 TA6 DST 2 § 60 Eldfisk Alpha ♦ 2/7A-29 EA9 P S. * § 27 Tommeliten Alpha ♦ 1/9-3 TA7 DST 3* 61 Eldfisk Alpha ♦ 2/7A-29 EA10 P.S. * § 28 Tommeliten Alpha ♦ 1/9-3 TAB DST 4 § 62 Valhall ♦ 2/11-1 VA1 DST 4* 29 Tommeliten Gamma ♦ 1/9-4 TG1 DST 1 * 63 Valhall ♦ 2/8-6 VA2 DST 2 = 30 Tommeliten Gamma ♦ 1/9-4 TG2 DST 2* 64 Valhall ♦ 2/8A-1 VA3 P.S. = 31 Tommeliten Gamma ♦ 1/9-4 TG3 DST 3 § 65 Valhall ♦ 2/8A-4 VA4 P.S.* 32 Tommeliten Gamma ♦ 1/9-4 TG4 DST 4§ 66 Hod ♦ 2/11-2 HD1 DST 2 = 33 Tommeliten Gamma ♦ 1/9-6 TG5 DST 2A * 67 Hod ♦ 2/11-6A HD2 DST 1 = 34 Tommeliten Gamma ♦ 1/9-6 TG6 DST 3* 68 Gert 2/12-1 @11 DST2

* pre-Cretaceous, sandstone reservoired oils, ♦ most data from Bjor0y et al. (1994) B - Jurassic, # - pre-Jurassic, * - Tor Fm., = - Hod Fm. and § - Ekofisk Fm.

In the case of the Greater Ekofisk oils, nearly all oils follow a single trend when these parameters are plotted (Figure 2), although in some fields such as Eldfisk Bravo, Tommeliten Alpha and Embla, there is a large internal spread. Accordingly, this may indicate that there is

Norwegian University of Science and Technology 12 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea one main source rock for these oils (with comparable relative distribution of isoprenoids and n-alkanes) if the observed spread is mainly due to maturity variations. The large spread within a field may be due to both maturity and source variations. Whether the discrimination between 3X and Edda oils (Figure 2) is due to maturity alone, will be seen later.

Phytane/nC18 Figure 2: Cross-plot of pristane/

GREATER EKOFISK OILS nCn versus phytane/ nCjs, calcu ­ lated from FID gas chromatograms of whole oil samples.

*19R *3X OEM AAL 0.4 • - ♦ TO OST • EK * WE + TA XTG oVA ■ HD TGT

Pristane / nC17

A better maturity-based discrimination is seen using the more reliable aromatic hydro carbons- based parameters (Figure 3a and b). These ratios have been used successfully earlier (Hall et al., 1985; Radke, 1987). Dimethylnaphthalene (DMNR) ratio (2,6 + 2,7 / 1,5 dimethylnaphthalenes) and methylphenanthrene (MP) based calculated reflectance (Rc = 0.6 MPI1 + 0.4, where 2MP/1MP < 2.65) are amongst the most reliable and widely used maturity parameters. The main observations in Figures 3a and b are two fold: 1) first, there is a clear trend in the maturity of the Greater Ekofisk Cretaceous oils, as noted by Bjor0y et al. (1994), in that the Hod and Valhall fields in the south contain least mature oils, followed by slightly more mature Eldfisk Alpha and Bravo and Ekofisk oils and finally most mature Albuskjell and Tommeliten Gamma oils in the north. This sequence of increasing DMNR and Rc values indicates different phases of hydrocarbon generation in Greater Ekofisk. The observed spread in the pristane/nC17 values in the Eldfisk Bravo population (but relatively constant DMNR) points supports the idea of different source facies feeding the field. Interestingly, the maturity of the pre-Cretaceous sandstone reservoired 3X oil is comparable to the least mature Cretaceous oils from Hod and Valhall. 2) the second and more important observation from this study ’s point of view is that while the other pre-Cretaceous oils (Embla and 19R) are very mature (in fact the 19R oil is the most mature in the entire suite), the trend

Doctoral Dissertation by Sunil Bharati, 1997 Paper I: Diverse oil families in the Greater Ekofisk area, Central Graben, Norway 13 of these oils is different compared to the general Cretaceous oils ’ trend. This might suggest that there are differences in the source facies sourcing these oils.

Dimethylnaphthalene Ratio (OMNR) Figure 3: a) Pristane/nCn, calcu ­

68 GREATER EKOFISK OILS lated from FID gas chromatograms of whole oil samples plotted against dimethylnaphthalene ratio, “Sea calculated from FPD gas 0E8 chromatograms of aromatic hydro ­ ED ED

★ 19R carbon fractions, b) methyl- *3X phenanthrene based calculated — OEM reflectance versus DMNR. a AL ♦ TO nST • EK * WE +TA XTG OVA <$> ■ HD TGT

Pristane / nC17

Dimethylnaphthalene ratio (DMNR)

68 GREATER EKOFISK OILS

Pre-Cretaceous Cretaceous Oils trend Oils trend

★ 19R

Calculated Reflectance (Rc)

The biomarker data of the Greater Ekofisk oils is in agreement with the above findings. The major triterpane (e.g. 17a trisnorhopane / 18a trisnomeohopane or Tm/Ts, C30 a|3 diahopane / hopane) and sterane (e.g. C27 diasterane/sterane, %Cag aPP / (aaa+aPP) ethylcholestane, %C29 acta 20S/20S+20R ethylcholestane) maturity ratios indicate similar trends when cross-

Norwegian University of Science and Technology 14 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea plotted. Two typical examples are shown in Figures 4 and 5. In both these cases, the Hod and Valhall oils are least mature (equivalent to top oil window maturity), followed by Ekofisk, Eldfisk Alpha, Eldfisk Bravo ( generation maturity, Edda (at or just past peak oil generation) and finally Albuskjell and Tommeliten Alpha (estimated near base oil window maturity).

C27 diasterane / sterane Figure 4:17 a trisnorhopane / 18a trisnomeohopane (Tm/Ts) ratio GREATER EKOFISK OILS calculated from m/z 191 frag- mentogram plotted against C27 diasterane/ sterane ratio calculated from m/z 217 fragmentogram.

★ 19R $>3X OEM A AL ♦ TO AST • EK * WE 0.4 “ - -TG XTA OVA ■ HO ▼ GT

C2717a/18a hopane (Tm/Ts)

%C29 app / (aaa+app) Figure 5: %C29 aj3j8 / (aaa+

GREATER EKOFISK OILS aj5j3) ethylcholestane plotted against %C29 aaa 20S/20S+20R

65 - ethylcholestane, both ratios calcu ­ -H- + -H® lated from m/z 217 fragmentogram.

55 - *19R

%C29 aaa 20S/20S+20R

Doctoral Dissertation by Stmil Bharati, 1997 Paper 1: Diverse oil families in the Greater Ekojisk area, Central Graben, Norway 15

With regards to the pre-Cretaceous sandstone reservoired oils, oil from 3X is least mature (estimated around peak oil generation stage, but more importantly perhaps only slightly less mature than the Edda oils) and the Embla and 19R oils are estimated to be beyond the oil window maturity i.e. in the condensate stage, as most of their data are either at maximum values or become unreliable due to small yields.

2.6 Source facies variations

Based on FED gas chromatograms of whole oils, it is clear that all the Greater Ekofisk oils have been generated in general from marine type II source rocks, as also noted by several previous workers (e.g. Cooper and Barnard, 1984; Hughes, 1985). A few other workers have postulated that differences occur within the Upper Jurassic source interval of the Central Graben, which account for slightly different oil compositions and their evolution with increasing maturity (e.g. Forsberg et al., 1993; Bjor0y et al, 1994; Bailey et al., 1990). Some exemplary chromatograms are shown in Figure 6, which illustrates this point. While the most obvious change with increasing maturity (a to d in Figure 6) is that the Cretaceous oils become lighter and more front-end biased, an important point of distinction between the Cretaceous and pre-Cretaceous oils is seen on comparing the oil from Edda (ED2) to the 3X oil, which are of comparable maturity. The 3X oil is anomalously rich in isoprenoids, which accounts for comparatively very high isoprenoids / n-alkane ratios (Figure 2). In addition, we believe that given the maturity of the other pre-Cretaceous oils (19R and Embla oils, base oil window to condensate stage), the pre-Cretaceous oils give higher isoprenoids/n-alkane ratios than expected.

Going by the minor variations in pristane / phytane ratios (mostly ranging 1.3 - 1.6) and limited carbon preference index (CPI) range (1.0 - 1.15), rather uniform depositional conditions of the source rocks seems likely. However, a plot of stable carbon isotopic compositions of saturated versus aromatic hydrocarbon fractions (Figure 7) shows a large but systematic variation in the Greater Ekofisk oils ’ data set. It has been shown that with increasing thermal maturity, 12C is depleted (Chung et al. 1981; Lewan 1983). However, maturity alone cannot explain the more than 4°/00 difference in 8 13C of the hydrocarbon fractions (Figure 7), as it is larger than reported as the maximum variation due to maturity in a single source rock (Chung et al., 1981). Therefore a significant part of the observed variation must be inherited from the source. As an example, it has been seen that the oils from Edda (EDI and ED2, Table 1) and well 2Z7-3X are of comparable maturity (roughly peak oil generation stage, Figures 3a and 5), the 3X oil being perhaps only slightly less mature. Nevertheless, the difference in 8 13C is about 3%o (Figure 7), which is considered to be too large to be due to maturity difference.

Norwegian University of Science and Technology

# 16 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Figure 6: Some exemplary whole oil FID gas chromatograms from the Greater Ekofisk area. On left are oils from isotopically light source facies, while on the right are oils from isotopically heavy facies. Maturity of oils increases from top to bottom. The numbers indicate the number of carbon atoms in n-alkane, e.g. 15 indicates n-pentadecane; Pr-pristane, Ph- phytane.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 1: Diverse oil families in the Greater Ekofisk area, Central Graben, Norway 17

Bjor0y et al (1994) have also made similar observations on comparing the more mature Ula Trend oils to Valhall and Eldfisk oils, the former being consistently richer in I2C. Another important point to note in Figure 7 is that, all the pre-Cretaceous sandstone reservoired oils are isotopically heavier (depleted in 12C) than the Cretaceous chalk reservoired oils. Its implication is discussed later.

d13C Aromatic Hydrocarbons Figure 7: S13C of saturated hydro ­ carbons plotted versus 8 13C of GREATER EKOFISK OILS aromatic hydrocarbon, obtained -25 - from isotope analysis of bulk fractions.

-26 -

•27 • • —— ■

•28 - * WE

OVA

d13C Saturated Hydrocarbons

2.6.1 Compound specific isotope analysis

This technique, using GC-IRMS, is very useful in highligh ting subtle differences which are otherwise ‘invisible’ within a sample set using a traditional geochemical approach. Its applica ­ tion has been demonstrated earlier (e.g. Bjor0y et al., 1991; 1994). Using isotope signatures of C5-30 n-alkanes, Bjor0y et al (1994) showed that many of the Greater Ekofisk Cretaceous chalk reservoired oils had a similar isotope profile despite differing maturities, suggesting thereby a single source facies. Some representative examples of such oils are shown in Figure 8, where the oil from Albuskjell is most mature and that from Hod least mature and the others (S. E. Tor, Eldfisk and Ekofisk) being intermediate (see Figures 3-5 for maturity trends). The general range of 8 13C for these oils in nCi^o range is -29 to -27%o, but far greater variation (almost - 34 to -24%o) in the lighter end due to varying maturity.

However, there were a few oils (for example from Valhall and Tor) which were anomalous, whose heavy isotopic signatures could not be explained by the observed maturity differences. These oils are apparently similar to the pre-Cretaceous sandstone reservoired oils, perhaps sourced mainly from the isotopically heavier facies, shown in Figure 9; however, as noted in

Norwegian University of Science and Technology 18 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea the previous section, unlike the other pre-Cretaceous oils, the Valhall and Tor oils do not have anomalously high isoprenoid content (Figure 2).

delta 13C Figure 8: Compound

Isotopically Light Oils specific 8 I3C plots of n- alkanes of Cretaceous reservoired oils sourced from isotopically light facies (cf. Table 1 for -26 - sample codes).

•27 — —

-28

Number of carbon atoms in n-alkane

delta 13C Figure 9: Compound Isotopically Heavy Oils specific 5 13 C plots of n- -25 - - alkanes of pre-Cretaceous

-&VA4 reservoired and two Cretaceous reservoired -26 - oils sourced from isoto ­ pically heavy facies (cf. Table 1 for sample codes).

-28 • —

Number of carbon atoms in n-alkane

In this group, oils from 19R and Embla are most mature (19R perhaps slightly more mature), while the oil from 3X (interpreted as the end- member representative of the isotopically heavy facies) is of lesser maturity (cf. Figures 3-5). When compared to the Cretaceous oils (Figure

Doctoral Dissertation by Sunil Bharati, 1997 Paper 1: Diverse oil families in the Greater Ekofisk area, Central Graben, Norway 19

8), the most striking difference is in 5 13C values in the nCig.go range, the pre-Cretaceous oils being heavier by almost 3°/oo for a given maturity (compare for example Albuskjell to Embla or Ekofisk to 3X).

Bjor0y et al. (1994) have also proposed that some of the oils from the Greater Ekofisk chalk fields contain a mixture of the two facies, thereby implying that both, the isotopically heavy and light source facies, have contributed to the present oil population in the reservoir. The contribution from each facies however varies for different fields, an aspect that makes data interpretation more difficult. Oils interpreted to be of mixed composition are plotted in Figure 10, along with the known end-members for reference, i.e. oil from 3X representing the isotopically heavy facies and oil from Edda representing the isotopically light facies, both these oils being of comparable maturity (cf. Figures 3-5). More oils from the Eldfisk Alpha and Bravo fields were analysed than any other field in the present study (Table 1). While each of these fields show systematic patterns in the isotopic signature (Bjor0y et al., 1994), there is also a large variation. While some oils (particularly from Alpha south - EAS) show minimal signs of mixing, the oils from Alpha north and Bravo exhibit signatures suggestive of mixing. The best and most convincing sample indicating a significant contribution from the isotopically heavy facies is EB8 (highlighted as a dotted plot in Figure 10).

delta 13C Figure 10: Compound Isotopically Mixed Oils «**ED2' -flight end-member specific 8 13C plots ofn- -25 -- alkanes of Cretaceous reservoired oils sourced from both isotopically -26 -- * Heavy end-member light and heavy facies. The heavy (3X) and -27 - light (Edda) end- members are also

-28 - shown for reference (cf. Table 1 for sample codes). -29 -

Number of carbon atoms in n-alkane

This oil is comparable to the Edda oil with respect to maturity (based on most gas chromatography and biomarkers based maturity parameters) and 8 13C values of light to medium range n-alkanes, but very heavy and similar to 3X oil towards the heavier end. In contrast, the other Eldfisk Bravo oil plotted (EB4) does not show equally large contribution

Norwegian University of Science and Technology 20 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea from the isotopically heavy facies, plotting nearly in between the two end-members. Other oils that are interpreted to be mixed are also shown, for example from Eldfisk Alpha north (BAN) and Tommeliten Gamma.

2.7 The Greater Ekofisk oil families

From the above results, it is clear that we are dealing with two principle types of source facies: 1) isotopically light and 2) isotopically heavy. The isotopically heavy facies can perhaps be further divided into two groups, namely one with anomalous isoprenoid enrichment and the other with normal isoprenoid content (comparable to isotopically light facies), unless the latter is due to mixing. Without doubt, several oil fields have been sourced from both the facies resulting in mixed signatures. However, broad discrimination between all the 16 fields of this study based on maturity, composition and isotopic signatures is possible and shown as a cartoon in Figure 11.

Figure 11: A graphical representation of the various oil families in the Greater Ekofisk area. Maturity is based on GC and GC-MS parameters and isotope signature is based on whole oil bulk measurements.

Light Whoile Oil bulk 513C Heavy

While the average maturity of an oil from a field has been estimated based on data presented in Figures 3-5 (and shown plotted on the oil window scale), the isotope signature is the average of bulk whole oil 8 13C measurements of all samples from that field (cf. Table 1). While the vertical separation between fields is entirely due to maturity, the horizontal separation is due to both maturity and source facies effects. This is due to the fact that the plotted isotope values are bulk values, which includes the light end components, these being more susceptible to maturity variations (Clayton, 1991). If for example, average values of just nC15+ n-alkanes are plotted (cf. Figures 7-9), the horizontal separation would be greater and primarily due to source effects.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 1: Diverse oil families in the Greater Ekofisk area, Central Graben, Norway 21

Ratios based on closely eluting minor (and not necessarily identified) compounds in between the major compounds, such as n-alkanes, during gas chromatography of whole oils have also been used to group oils, using star diagrams (Kaufman et al., 1990; Halpem, 1995). The choice of peaks for such an exercise is normally random, as long as the peak pairs are very closely eluting, thereby implying of comparable molecular size and boiling point. This approach was also employed using typical representative oils from each field. In cases where the entire field could not be represented by a single oil, two end-members were used (e.g. Eldfisk Alpha, Eldfisk Bravo, Embla and Tommeliten Alpha). The results of these 19 oils using 10 ratios (using peak heights of 20 compounds in the nCs-io range, of which 2 are unidentified) are shown in Figures 12a-d. The Edda oil is not included, as 3 of the 10 ratios could not be computed. All ratios were subsequently normalized to standardize the plotting scale.

All the pre-Cretaceous oils are plotted together (Figure 12a). The remaining Cretaceous oils have been grouped merely on the basis of similarity of the star shapes and field criterion (Figures 12b-d). Some systematic patterns can be seen in these plots. For example, 1) The star orientation of the pre-Cretaceous oils (except 3X) and the Cretaceous oils group 1 (except the outlier TA1) is roughly the same (NW-SE). All these oils are also most mature. 2) The star orientation of the Cretaceous oils groups 2 and 3 are roughly the same (NS). These oils are also amongst the least mature.

This general change (from NS to roughly NW-SE orientation) may be due to increasing maturity. Amongst the pre-Cretaceous oils, the 19R and Embla oils are similar while the 3X oil appears very different, mostly due to ratios 2, 4, 6 and 7. Thompson (1987) and Rovenskaya and Nemchencko (1992) have suggested that several light hydrocarbon components are affected by thermal maturation, for example ethylbenzene / p, m-xylene (this study ’s ratio 7). It is thus likely that the differences that we see between 3X and the rest are simply an artifact of 3X’s lower maturity. In the Cretaceous oils 1 group, oil TA1 is an outlier. This may be due to a different source as this oil is from the Hod Formation, while all the others are either from Tor or Ekofisk Formations (Table 1). With regards to VA4 oil in Cretaceous oils group 2, which is different than the rest, closer examination shows that the general star shape of VA4 is similar to the 3X oil. This is probably due to the fact that the Valhall oil has been mainly sourced by the isotopically heavy facies, as shown above.

There are also some inconsistencies in the star diagram based groupings which must be ment­ ioned. For example, the Tommeliten Gamma and Tor oils (TG5 and T02 respectively) were also shown to be have a major component sourced from the isotopically heavy facies. However, their star plots do not show any similarity to the 3X star. In summary, while several star diagram based observations can be logically explained in the context of other data, a few cannot be (unless the light hydrocarbons are mainly sourced by one facies and the heavier homologues by the other).

Norwegian University of Science and Technology

1 22 Mobile and immobile migrated hydrocarbons in the Embla Field North Sea

Pre-Cretaceous Oils R1 Cretaceous Oils 1 '' WE2

- - TA1

Cretaceous Oils 2

H01

Figure 12: Star diagrams based on gas chromatography of whole oils. The ten ratios (Rl- R10) used have been calculated using peak heights of closely eluting minor compounds.

2.8 Conclusions

Distinct differences are present between the pre-Cretaceous sandstone reservoired and Cretaceous chalk reservoired oils. This difference is not due to the petrophysical properties ’ differences between the two reservoirs types, but due to two distinctly different source facies sourcing these oils. The oil from 3X represents the heavy facies end-member and the Edda oil represents the lighter facies end-member, both oils being of comparable maturity but with about 37oo difference in their isotopic composition. While the pre-Cretaceous oils (3X, 19R and Embla) have been sourced by the isotopically heavy facies anomalously enriched in isoprenoids, most of the Cretaceous oils (Albuskjell, S. E. Tor, Ekofisk, Eldfisk Alpha south and Hod) have been sourced by isotopically lighter facies with a no rmal isoprenoid content.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 1: Diverse oil families in the Greater Ekofisk area, Central Graben, Norway 23

Some Cretaceous chalk fields have also been sourced by the heavier facies (Valhall and Tor), but the isoprenoid content in these oils is within the normal range. Based on compound specific isotope analyses, it can be concluded that some fields (Eldfisk Bravo, Eldfisk Alpha north and Tommeliten Gamma) contain mixed oils from the two facies. The degree of each facies’ contribution is variable.

2.9 Acknowledgments

Many thanks to Norwegian Research Council, Phillips Petroleum Co., Norway and Amoco Norway for partial financial assistance. The staff of Geolab Nor is thanked for assistance in geochemical analyses and the Department of Geology, Norwegian University of Science and Technology, Trondheim for support and encouragement

2.10 R eferences

Bailey, N. J. L., Burwood, R., and Harriman, G. E., 1990, Application of pyrolysate carbon isotope and biomarker technology to organofacies definition and oil correlation problems in North Sea basins, in B. Durand and F. Behar, eds., Advances in Organic Geochemistry 1989, Pergamon, Oxford, p. 1157-1172.

Bjor0y, M., Hall, K., Gillyon, P. and Jumeau, J., 1991, Carbon isotope variations in n-alkanes and isoprenoids in whole oils: Chemical Geology, v. 93, p. 13-20.

Bjor0y, M., Hall, K. and Moe, R. P., 1994, Stable carbon isotope variation of n-alkanes in Central Graben oils: Organic Geochemistry, v. 22, p. 355-381.

Chung, H. M., Brand, S. W. and Grizzle, P. L., 1981, Carbon isotope geochemistry of the Paleozoic oils from the Big Horn Basin: Geochimica Cosmochimica Acta, v. 45, p. 1803- 1815.

Clayton, C. J., 1991, Effect of maturity on carbon isotope ratios of oils and condensates: Organic Geochemistry, v. 17, p. 887-900.

Cooper, B. S. and Barnard, P. C., 1984, Source rocks and oils of the Central and Northern North Sea, in G. Demaisson and R. J. Munis, eds., Petroleum Geochemistry and Basin Evaluation, AAPG Memoirs 35, AAPG, Tulsa, p. 303-314.

Feazel, C. T., Knight, I. A. and Pekot, L. J., 1990, Ekofisk Field-Norway, Central Graben, North Sea, in E. A. Beaumont and N. H. Foster, eds., Structural Traps IV, Treatise of Petroleum Geology, Am. Asso. of Pet. Geol., Tulsa: p. 1-26.

Forsberg, A., Gowers, M. B. and Holtar, E., 1993, Multi-disciplinary stratigraphic analysis of the Upper Jurassic strata of the Norwegian Central trough, in A. M. Spencer, ed., Generation, Accu­ mulation and Production of Europe ’s hydrocarbons: Springer-Verlag, Berlin, p. 45-58.

Norwegian University of Science and Technology 24 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Fraser, A. J., Farnsworth, J. and Hodgson, N. A., 1993, Salt controls on basin evolution- Central North Sea, in A. M. Spencer, ed., Generation, Accumulation and Production of Europe ’s hydro­ carbons: Springer-Verlag, Berlin, p. 59-68.

Gowers, M. B. and Saeb0e, A., 1985, On the structural evolution of the Central Trough in the Norwegian and Danish sectors of the North Sea: Marine and Petroleum Geology, v. 2, p. 298- 318.

Hall, P. B., Schou, L. and Bjor0y, M., 1985, Aromatic hydrocarbon variations in North Sea wells, in B. M. Thomas, ed., Petroleum Geochemistry in Exploration of the Norwegian Shelf: Graham & Trotman, London, p. 293-301.

Halpem, H. I., 1995, Development and applications of light hydrocarbon based star diagrams: AAPG Bulletin, v. 79, p. 801-815. Hughes, W. B., Holba, A. G., Miller, D. E. and Richardson, J. S., 1985, Geochemistry of Greater Ekofisk oils, in B. M. Thomas et al., eds., Petroleum Geochemistry in exploration of the Norwegian Shelf: Graham & Trotman, London, p. 75-92.

Kaufman, R. L., Ahmed, A. S. and Elsinger, R. J., 1990, Gas chromatography as a development and production tool for fingerprinting oils from individual reservoirs; applications in the : PR 8824, in Proceedings of Gulf Coast Section of the Society of Economic Paleontolo­ gists and Mineralogists Foundation 9 th Annual Research Conference, p. 263-282.

Lewan, M. D., 1983, Effects of thermal maturation on stable organic carbon isotopes as determined by hydrous pyrolysis of Woodford shale: Geochimica Cosmochimica Acta, v. 47, p.1471-1479.

Le Tran, K. and Phillipe, B., 1993, Oil and rock extract analysis, in M. L. Bordenave , ed., Applied Petroleum Geochemistry: Edition , Paris, p. 72-394.

Radke, M., 1987, Organic Geochemistry of aromatic hydrocarbons, in J. Brooks and D. Welte, eds., Advances in Petroleum Geochemistry- Vol. 2: Academic Press, London, p. 141-208.

Rovenskaya, A. S. and Nemchencko, N. N., 1992, Prediction of hydrocarbons in the west Siberian basin: Bulletin Centres Research- Exploration & Production, Elf Aquitaine, v. 16, p. 285-318.

Thompson, K. F. M., 1987, Gas-condensate migration and oil fractionation in deltaic systems: Marine and Petroleum Geology, v. 5, p. 237-246.

Van den Bark, E. and Thomas, O. D., 1981, Ekofisk: first of the giant oil fields in Western Europe, AAPG Bulletin, v. 65, p. 2341-2363.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 25

Chapter 3 : Paper 2

Geochemical evaluation of the Embla field, Norwegian Continental Shelf -1: Occurrence and compositional variations of migrated hydrocarbons§

Sunil Bharati 1, Peter B. Hall Rare Vagle2 and Malvin Bjor0y1

l- Geolab Nor, 7002 Trondheim, Norway; 2- Phillips Petroleum Co., 4056 Tanager, Norway.

3.1 Abstract

The Embla Field, discovered in 1974 and located southwest of the Eldfisk Field, on the Grensen Nose in Block 2/7, has been investigated in detail through geochemical analyses, using 6 oils and 973 core samples from 8 exploratory wells drilled in the 1986-91 period. The study comprises two parts and focuses on petroleum ’s gross occurrence and compositional variations (part 1) and source, maturity and intra-reservoir communication (part 2) of the migrated hydrocarbons. The Embla Field is different from all the other neighbouring (Cretaceous chalk) fields in that its reservoirs are pre-Cretaceous sandstones and relatively most deeply buried. Oil-based mud, used during drilling all but one of the Embla wells, has adversely affected most geochemical data, particularly the abundance data. However, despite these limitations, gross differences are evident within the Embla oil population (both hori ­ zontally across the field and vertically down the reservoir) with respect to composition and richness. The Embla reservoir, consisting of the Upper and Lower Sandstones, contains two distinct types of oil, A and B, although both the oils are very light. The Upper Sandstone, with well developed porosity, is richer in hydrocarbons but also relatively non-homogenous, when compared to the Lower Sandstone. The lower part of the reservoir, particularly the Lower Sandstone, has a high content of solid reservoir bitumen, which significantly diminishes the overall reservoir properties. Relative productivity of some test intervals has been estimated by using the geochemical data of the present study.

* Manuscript under submission to Marine and Petroleum Geology

Norwegian University of Science and Technology 26 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

3.2 Introduction

Until about the early 1980s, the principal focus of explorationists, particularly those involved with geochemistry, was characterization of the rock matrix (petrophysical properties, depositional environments, diagenesis etc.) and practically no efforts were made to understand the fluids, particularly the one that is produced, namely oil. However, it is now commonly recognized that many petroleum reservoirs are heterogeneous, not only with respect to structural elements and petrophysical characteristics, but also composition, maturity and communication of the oil contained therein. While the former aspects have been historically identified and predicted using a variety of constantly evolving engineering and logging techniques, measuring the fluid’s chemical disparities and linking them to other geological data became the norm only in the last decade or so. Numerous studies have since focused on understanding how the properties, fate and variations of the organic constituents, namely oil and gas, affect heterogeneity (e.g. England et al., 1987; England, 1990). Several new methods have therefore been developed to meet the changing needs and applications in petroleum geochemistry (e.g. Bjorpy et al., 1990; Bjorpy et al., 1992; Horsfield and McLimans, 1984; Kaufman et al., 1990; Latter and Aplin, 1995 and references therein; Leythaeuser and Ruckheim, 1989). These techniques and approaches have been successfully used and reported in several fields and basins, particularly in the North Sea, for example in the Eldfisk Field, NOCS Block 2/7 (Stoddart et al., 1995; Hall et al., 1994; Bharati et al., 1997a).

In the Eldfisk Field, which lies east of the Skrubbe Fault and north-east of Embla (Figure 1), Hall et al. (1994) showed that in addition to the Eldfisk Alpha and Bravo structures containing petroleum of differing maturity, each structure contained sections rich in waxes which diminishes vertical homogeneity of the oil column. In addition they showed that the field was filled by two charges, each differing from the other in the stable carbon isotopic signature. Stoddart et al. (1995) estimated the probable filling time, process and direction of the field. Eldfisk Field is one of several oil-producing Paleocene/Cretaceous chalk fields in the Central Graben, North Sea, that contain oils less mature than pre-Cretaceous reservoired oils in the region, such as in Embla and well 2/7-19R (Bjorpy et al., 1994; Bharati et al., 1997a).

The objective of the present study is to conduct a detailed geochemical evaluation of the Paleozoic sandstone reservoir of the Embla Field, particularly the petroleum contained therein, in light of available geological data. In addition to basic characterization of hydrocarbons, this study aims at understanding the filling mechanisms of the field and defining intra-reservoir communication. While this paper assesses the gross occurrence and compositional variations of migrated hydrocarbons, both horizontally across the field and vertically down the reservoir, the second paper (Bharati et al., 1997b) addresses the aspects of source, maturity and compartmentalization of the migrated hydrocarbons.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 27

Figure 1: Location Map showing Block 2/7 in the Norwegian Continental Shelf (NOCS) and enlargement of the Embla Field with wells locations.

3.3 Geological elements and Field history

3.3.1 Regional setting

The Embla Field, an oil field, is located on the Grensen Nose in Block 2/7 to the south-west of the Eldfisk Field on the downthrown side of the Skrubbe Fault (Figure 1). Regional thickness variations in the Upper Permian and Mesozoic stratigraphic sections indicate that the Grensen Nose was part of the Mid-North Sea High until subsidence in the Central Graben occurred during the Late Cretaceous period (Gowers and Saebpe, 1985). Based on 3D seismic data, Sears et al. (1993) suggested that much of the basement framework in the Central Graben was created during the Caledonian orogeny which gave rise to NW-SE and NE-SW trending diffuse shear zones, and that subsequent reactivation along these existing basement lineaments occurred from Late Paleozoic to Cenozoic times. Fraser et al. (1993) suggested that the mobilization of the Permian salt underlying the Central Graben has played a pivotal role in

Norwegian University of Science and Technology 28 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea influencing patterns of structure and sedimentation, including the preservation of coarse clastic input to the basin in an arid continental environment.

3.3.2 Structure and Stratigraphy

The Embla Field has been interpreted as occurring in a westward dipping Paleozoic horst (Knight et al., 1993). The structure is a faulted dome with long axis of the field oriented northwest - southeast and bounded to the east by the Skrubbe Fault The field (about 19.4 km2 at Paleozoic unconformity, OWC at 4387 m, based on data from well 2/7-9, resulting in an oil column of 354 m in this well) consists of a trap formed by a combination of structural and stratigraphic elements. Intense faulting within the reservoir sections (based on both cores and seismic data interpretation) indicates that there is a risk of reservoir compartmentalization. Both RFT and DST production data indicate that horizontal and vertical barriers to fluid flow may exist, the latter also indicating horizontal flow barriers in the form of faults or stratigraphical discontinuities (Knight et al, 1993). Vertical flow barriers may include caliche layers, intercalated volcanic horizons and the lacustrine mudstones separating the Upper and Lower Sandstones (Knight et al., 1993). Petroleum properties also show some variations within the field, such as higher gas-oil ratios in the eastern fault block, suggesting that the more deeply buried source to the east may have contributed a greater gas component (Knight et al. 1993).

The pre-Cretaceous stratigraphy varies signifi cantly between wells in the Embla Field. However, well 2/7-26S has encountered the most complete sequence (Figure 2). The basement rhyolitic unit, possibly of Devonian age, is overlain by Lower Devonian mudstones, upon which rests the reservoir section. The Upper Jurassic Tyne Gp. unconformably overlies the Embla reservoir and only a very thin Mandal Fm. mudstone is present high on the structure. Table 1 summarizes the interpreted formation tops in the studied wells.

Table 1: Interpreted formation tops in meters TVDSS (rounded off to nearest meter, thickness in parentheses) in the Embla Field.. * indicates the formation in which the well was terminated.

Formation 20X 21S 23S 25S 26S 27S TyneGp. 4035 (36) 4034(12) 4115 (5) 4121(320) 4146(81) 4143 (6) Uppermost Sandstone 4071(1731.. ..Absent . 4120* ' Absent Absent 4149* Upper Sandstone Absent 4046(21) 4441 (12) 4227 (146) Upper Mudstone 4244(145) " 4# (111) 4453* V 4373(6). Lower Sandstone 4389 (65) 4178 (77) 4436(113) Lower Mudstone 4454* 42S5%7Q): . .4540.019). . _ Rhyolite 4525* 4648* Total Depth 4484 . 4688 4437 4528 4668 4423

Note : Except for Tyne Gp. (Upper Jurassic) all other formations are of Paleozoic age.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 29

Figure 2: Generalized DEPTH SUBSEA PERIOD EPOCH GROUP LITHOLOGY stratigraphy of well 2/7- Ox M 26S. HOLOCENE- CLAY QUARTERNARY ANHYDRITE PLEISTOCENE SAND

PUOCENE-

MIOCENE CLAYSTONE

ANHYDRITE

HORDALAND

ROGALAND

SHETLAND

CRETACEOUS

KNOLL MUDSTONE

UPPER SAND INDETERMINATE UNASSIGNED LOWER SAND UNASSIGNEO ■ DEVONIAN LATE MUDSTONE INTERMEDIATE UNASSIGNED VOLCANICS

333 Reservoir lithofacies and diagenesis

The age of the reservoir remains unknown as the sequence is barren of microfossils, but the current interpretation based on radiometric dating favours early Permian, Carboniferous and/or late Devonian (Knight et al., 1993). The reservoir consists of three major sandstone intervals (named as the Uppermost Sandstone, Upper Sandstone and Lower Sandstone) of braided fluvial and alluvial fan origin separated by a lacustrine mudstone-siltstone sequence (Figure 3). The Uppermost and Upper Sandstone, classified as a distal braided fluvial system, consists of fine to medium-grained sandstones with occasional quartz pebbles, generally well sorted with graded bedding in fining-upward cycles containing discontinuous clay laminae (average net porosity 14.8 %, permeability 0.05 - 10 mD, Knight et al. 1993). The Lower Sandstone unit, interpreted as a channel fill system, can be divided into a lower section consisting of stacked debris flows and an upper section consisting of braided pebbly sandstone with thin volcanic intercalations (average net porosity 11.3 %, permeability 0.05 - 100 mD, Knight et al. 1993). The Lower Sandstone is significantly coarser than the Upper Sandstone, and has significantly higher permeability than the Upper Sandstone.

Norwegian University of Science and Technology 30 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

The reservoir has experienced a complex diagenetic history with repeated periods of porosity loss and enhancement (Knight et al. 1993). Most of the effective porosity is secondary in origin, in the form of intra-granular and mouldic pores due to partial and total grain dissolution respectively. Minerals observed in fractures in cores have been interpreted as indicating periodic invasions of hydrothermal fluids into the reservoir (Knight et al. 1993). A residual bitumen is prominent in some sections of the wells. The most significant occurrences (that can be seen by the naked eye) are in wells 2/7-26S and 2/7-20X, particularly in the lower part of the Lower Sandstone; in 2Z7-21S. Abundant bitumen also occurs in a thin interval of rhyolite beneath the reservoir (Bharati, 1997).

23S/27S

I Uppermost I

if/-- DST*1 ...... 1 I Uppermost!

D$T#1 DST«2[ DST#1 I

Figure 3: Generalized cross-section (roughly NW-SE) of the Embla Field below the base Cretaceous unconformity (solid bars = cored intervals, open bars = DST intervals; distances between the wells are at sub-sea level).

The total net thickness of the reservoir section varies from more than 317 m in 2/7-23 S to 98 m in 2/7-21S. The Uppermost Sandstone is very well developed in wells 23S/27S and 20X (317 and 173 mrespectively), but absent in the other wells. The Upper Sandstone is 146 min well 26S, but due to erosional truncation only 21 m in well 21S and absent in the others (Figure 3). The Upper Sandstone is most extensively cored in well 26S (solid bars on the right hand side of each well in Figure 3). The Lower Sandstone is well developed in 3 wells and varies from 113 m in 26S to 65 min 2/7-20X (in the center of the structure). Wells 20X, 21S and 26S were drilled through

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 31 the base of the Lower Sandstone, while wells 23S/27S were terminated within the Uppermost Sandstone (Figure 3). Present day reservoir temperature is 160°C and initial pressure recorded was 841 bar. The reservoir is considered to be undersaturated with oil (API 42°) and variable GOR (329 Sm3/Sm3, 1900 Scf/stb in the eastern block and 276 Sm3/Sm3 (1550 Scf/stb) in the western block).

For simplicity, the Embla reservoir (shown as a cross-section in Figure 3) has been divided into 7 sub-traps - two in the Uppermost Sandstone (namely UM1 and UM2), two in the Upper Sandstone (namely US1 and US2) and three in the Lower Sandstone (namely LSI, LS2 and LS3, schematically shown as an inset in Figure 3), with the two sandstones being separated by a thick mudstone section. Another major consideration in horizontally defining these sub-traps is the presence of faults within the Embla structure (Figure 1).

3.3.4 Exploration history

Well 2/7-09, drilled in 1974, discovered oil in the pre-Jurassic sandstones. The oil yield in this sandstone, later identified as the Upper Sandstone interval of Embla, was only 36 Sm3 /day (-200 stock tank barrels of oil/day - STBOPD). This was considered to be low and a productivity of about 320 Sm3 /day (-2000 STBOPD) was calculated to be possible for this sandstone. The next well, 2/7-20X, was drilled in 1986 on an upthrown fault block from 2/7-09. DST flow rates of 566 Sm3 /day (-3500 STBOPD) were recorded from the Upper Sandstone (test intervals shown as open bars on the left hand side of each well in Figure 3). Well 2/7-21S was drilled in 1989 to test the south-easterly continuation of the Upper Sandstone. This well was deviated to the target location at base Cretaceous, 1.2 kilometers south-east of the 20X wellhead. A DST of the Lower Sandstone yielded up to 785 Sm3 /day (-5200 STBOPD), while a commingled test of both Upper and Lower Sandstones yielded 1236 Sm3 /day. Well 2/7-23S was also drilled in 1989 to test the northern continuation of the field. This well was deviated to the target location at base Cretaceous, 1.2 kilometers north of the 20X wellhead. No tests could be performed due to technical problems. In 1990/91, well 2/7-25S was drilled to a target location to the south-east (i.e. beyond 2/7-21S), 2 kilometers from 2/7-20X. No reservoir was encountered, only -400 meters of fine elastics of mostly Upper Jurassic age. Well 2/7-26S was drilled in 1991 to test the western fault block from the 2/7-20X wellhead to the target location 350 m south of 2/7-09. The well has similar stratigraphy to 2/7-20X. However, the sandstones have lower permeability than in the other wells. DSTs proved only 223 Sm3 /day. Well 2/7-27S was drilled to a target location very close to 2/7-23S, predominantly to perform a DST of the Lower Sandstone as this could not be done in well 23S; a flow of 3660 STBOPD was recorded.

3.4 Samples and methods

Due to the prognosed geological and other complexities (Knigh t et al., 1993), extensive coring was planned and carried out , resulting in a total recovery of 732 m of conventional core,

Norwegian University of Science and Technology 32 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea mostly covering the reservoir sections in 6 wells. All the geochemical analyses (Table 2) were performed according to the procedures specified in the Norwegian Industry Guide to Organic Geochemical Analyses (1993). Mineralogical composition of sandstones was established by XRD analysis on a selected suite of 25 powdered whole rock samples, covering the entire Upper and Lower Sandstone intervals.

Screening analyses (Total organic carbon and Rock Eval pyrolysis) were performed roughly every 2 m in every well to obtain a general picture of migrated hydrocarbon richness and source rock potential. Based on these results, a large suite of samples was characterized in detail using Iatroscan (Bharati et al., 1994) to obtain mainly bulk compositional data of the migrated hydrocarbons, in terms of both absolute and relative abundance of the 4 principal fractions, namely saturated and aromatic hydrocarbons, resins 1 and resins 2 (this being similar to asphaltenes). Concurrent to Iatroscan analysis, a new Iatroscan calibration method was developed using a suite of natural crude oils (Bharati et al., 1994).

Detailed molecular characterization was achieved by thermal extraction-pyrolysis-GC using GeoFina Hydrocarbon Meter (GHM, Bjorpy et al., 1992) on powdered rock samples and gas chromatography (GC) of saturated and aromatic hydrocarbon (HC) fractions (obtained as a result of solvent extraction followed by liquid chromatography, MPLC). In addition to the reservoir section, several samples from potential source rocks were also analyzed from two other wells (2/7-24 and 2/7-28). Table 2 summarizes the sampling and analytical details.

Table 2: Details of samples analyzed from the Embla Field, block NOCS 2/7. Wells 20X, 21S, 23S, 25S, 26S and 27S cover the reservoir sections (Uppermost, Upper and Lower Sandstones, all core samples) while wells 24 and 28 contain mainly potential source rocks (claystone cores and cuttings).

Well No. Screening 1 Iatroscan 2 TE-PY-GC 3 MPLC/GC 4 20X 54 45 21 8 21S 68 67 22 8 23S 140 - 140 10 24 16 16 .. 10. . 7 25S 35 35 19 15 26S - 609 219 160 20 _ 27S 37 37 11 7 28 13 13 : 9 5 Total 972 320 392 80

2- Comprises lithology description, Rock Eval and TOC. 2- Quantitative TLC-FID. 3 - Thermal extraction-pyrolysis-gas chromatography. 4 - Liquid chromatography of maltenes / capillary gas chromatography of saturated and aromatic hydrocarbons.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 33

3.5 Mineralogical composition of reservoir sandstones

Based on XRD analysis results of a limited number of samples (for example only one sample from the Upper Sandstone in trap US1), differences between the Uppermost/Upper and Lower Sandstones are evident with respect to mineralogical composition (Figure 4). In general, the quartz percentage is much lower in the Upper Sandstone, typically 50-60%) as compared to the Lower Sandstone (typically >70%). But the most striking feature is the high percentage of kaolinite (up to about 30% and conspicuously more abundant in the Upper Sandstone as compared to the Lower Sandstone, Figure 4) and only trace amounts of illite, despite the depth of the reservoir (> 4 km). This indicates that no kaolinite dissolution resulting in illite precipitation could take place due to lack of potassium in the system, either from outside or locally through feldspar dissolution. No feldspar is present in any of the samples and siderite, pyrite and anhydrite are present only in trace amounts. Fe-dolomite / ankerite is present only in some samples (up to over 40%), but absent in most of the samples; however, maximum dolomite was detected in the Lower Sandstone of wells 23S and 26S.

Figure 4: Relative percentages of the major minerals detected in samples from the Uppermost and Upper Sandstones (top) and the Lower Sandstone (bottom ) as determined by XRD. n = number of samples (in each trap). See Figure 3 for trap codes.

Quartz Kaolinite Illite Dolomite Siderite Pyrite Anhydrite MINERAL

Norwegian University of Science and Technology 34 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

3.6 Abundance of Migrated Hydrocarbons

3.6.1 Mud contamination problem

Except for one well (27S) all the other wells of the main Embla structure (20X, 21S, 23S, 25S and 26S) were drilled using oil based mud (OEM), the primary organic additive being diesel. No mud sample was available for analysis, thereby limiting our knowledge about the chemical composition of the additives. Under reservoir conditions (high pressure and temperature), drill mud is known to penetrate the host rock and therefore has the potential of adversely affecting subsequent organic geochemical analyses and the data obtained therefrom. Hydrocarbons are generally found in the high porosity zones of the reservoir section and these are also the zones which tend to be most affected by mud penetration. Analyses such as Rock Eval, Iatroscan, extraction and gas chromatography are particularly prone to adverse effects. It is also easier to detect contamination in compositional data than in abundance (richness) data.

In our case, samples available for the study were only from the reservoir interval and no ‘baseline’ sample was available to throw some light on the extent of contamination. However, to minimize the problem, samples were collected only from the center of the core where mud penetration is expected to be minimal. As porosity and hydrocarbon richness vary from well to well and down a given well, estimating any standard value for contamination would be erroneous and misleading. While this problem cannot be avoided in the case of Embla Field, it should not be overlooked or underestimated. Neither should this problem become the reason for discarding all data or not reaching rational conclusions which are based on established principles and previously published works. We have exercised caution and borne this fact in mind while interpreting the geochemical data and have attempted to mention this in the relevant portions of the text. Wherever possible, we have also tried to highlight the problem by comparing samples, particularly from wells 23S and 27S.

3.6.2 Uppermost Sandstone

This section is well developed in only three wells (20X and 23S/27S), but core samples are available only from 23S and 27S. Trap UM2 (represented by well 23S) is laterally separated from trap UM1 trap in the south by faults. In general, the free hydrocarbon abundance is higher in 23S than 27S, clearly (overestimated) due to oil-based mud contamination in the former (well 27S was drilled using water based mud unlike all other wells). The degree of contamination, however, varies from sample to sample, depending on the inherent petrophysical properties. While the free hydrocarbon content varies about 2-4 mg/g rock in 27S, it is generally above 10 mg/g rock in 23S with a few exceptions (Figure 5). The top 60 m or so of the analyzed section is relatively depleted (around 5 mg HC/g rock), although in absolute terms it is rich. Two zones namely, 4559 - 4619 m and 4672 - 4703 m, are exceptionally rich in migrated hydrocarbons. These zones also have the highest relative porosity (8-12 %, Figure 5) as compared to typical

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 35 porosity of 4-8 %, particularly in poor zones such as 4491 - 4499 m and 4546 - 4557 m Except for such tight zones, no major barriers in UM2 are indicated. No core samples are available from well 20X in trap UM1, but the Uppermost Sandstone was tested in this well and a main drawdown flow of 3560 STBOPD was recorded.

Depth (MD m) TRAP US1 (Well 21S) Figure 5: Abundance of migrated hydrocarbons (based on Rock Eval ’s SI) and porosity development in the Uppermost and Upper Sandstone. Double arrows in the center = poor and tight zones; solid bars = perforated zones for testing.

3 6 9 12 5 10 15 20 25 S1 (mg HC/g rock) Porosity (H)

Depth (MD m) TRAP UM2 (Well 23S) Depth (MD m) TRAP US2 (Well 2BS) 44701------4390-1 ------

4415- 4520-

4440-

4570-

4465-

4620-

4490-

4515-

■fTTrTTJTTTTJTTT ' I ' 1 ' I ' ' 1 I ' i rpr» ■ 11 m 111111 j 111 0 5 10 15 20 2= 8 12 16 20 10 20 30 40 10 15 20 25 S1 (mg HC/g rock) Porosity (%) SI (mg HC/g rock) Porosity (%)

Norwegian University of Science and Technology 36 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

3.6.3 Upper Sandstone

This section is best represented in well 26S and to a lesser extent in 21S, and therefore the majority of the findings are based on samples from these two wells. In trap US2, which is bounded by faults on all sides (Figure 1) and represented by well 26S, there is a rhythmic distribution of porosity in that, while the average porosity is 10-15 %, there are alternating zones (consisting of braided stream mudstones) with relatively lower porosity (around 5%). There are also some ash layers present. As seen in Figure 5, this change accounts for relatively lower migrated hydrocarbon (HC) content in these lower porosity zones (4397 - 4404 m, 4418 - 4427 m, 4448 - 4456 m, 4460 - 4470 m and 4515 - 4517 m; the 4460 - 4470 m interval is predominantly siltstone). In addition to the indicated intervals (Figure 5), the DST # 2 in well 26S included 4311 - 4315 and 4387 - 4390 m intervals. While the average hydrocarbon content in well 26S in the richer (and more porous) sections is about 15-20 mg HC/g rock, it decreases to about 3-5 mg HC/g rock in the poorer sections. In absolute terms, however, the latter figure is also regarded as good. With regards to trap US1, both the reservoir development and sample coverage are rather poor in well 21S (Figure 5; the indicated test interval is only part of the actual DST # 3 interval in the Upper Sandstone - 4309 - 4339 m). Nevertheless, the average porosity (10-15 %) and the migrated hydrocarbon content (6-15 mg HC/g rock) are in gross agreement with those of the 26S well, perhaps indicative of some degree of reservoir uniformity in the Upper Sandstone section. All richness data quoted may be only partially valid due to possible mud contamination.

3.6.4 Lower Sandstone

As in the case of the Upper Sandstone in well 26S (trap US2), the Lower Sandstone (trap LS3) is also bounded by faults on all sides and vertically separated from trap US2 by a 63 m thick mud­ stone section. Only the lower half of LS2 was cored, although nearly the entire section was perfo­ rated and tested. The overall petroleum abundance in this trap is rich and varies from about 5-10 mg/g rock in the upper part (4669 - 4711 m), but decreases to about 2-5 mg/g rock in the lower part (4711 - 4724 m). While there is little variation in the migrated HC abundance in LS2, there are three major zones which are relatively tight (4690 - 4699,4702 - 4706 and 4715 - 4724 m), as compared to the remaining interval which correspond to higher (7-10%, Figure 6). Two intervals, namely 4607 - 4653 and 4660 - 4698 m, were perforated and tested in LS2. However the richest zones (with respect to hydrocarbon abundance) detected in this study in LS2 are 4669 - 4689, 4699 - 4702 and 4706 - 4711 m, with the first interval being the most productive. No geochemical core data are available for the upper half of the trap, corresponding to the perforated interval 4607 - 4653 m, but based on data from the core of lower half of the trap, the upper and the lower halves are probably similar. In addition to the indicated intervals (Figure 6), the DST # 1 in well 26S included 4607 - 4653 and 4660 - 4698 m intervals.

The free hydrocarbon content in LSI is generally in the 9-12 mg/g rock range in the upper part (4457 - 4575 m in 21S), which is considered to be rich, but the content steadily decreases with

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 37 increasing depth (just about 1 mg HC/g rock in the 4650 - 4695 m interval, Figure 6). This also corresponds with the porosity variations, with typical porosity in the upper part of 21S being 7 - 14%, but decreases (2 - 5%) with increasing depth. In addition, the overall hydrocarbon content decreases from trap LSI in the south to trap LS2 northwards, again with corresponding decrease in porosity to 3-7%. The 2 cored intervals of 20X in trap LS2 (one at the top and one at the bottom of the Lower Sandstone) are both rich in solid bitumen occurrences (Bharati, 1997) but highly depleted in detectable migrated hydrocarbons (typically only 0.5 - 1 mg HC/g rock). Average porosity is 1-5% with a few exceptions, this being perhaps related to high content of solid bitumen. In addition to the indicated intervals (Figure 6), the DST # 2 in well 21S included 4448 - 4520 m interval.

Depth (MD m) TRAP LS3 (Well 26S) Depth (MD m) TRAP LS1 (Well 21S) 4457 ■«------

4675-

4685"

4695-

4705"

4715-

5 10 15 2 4 6 8 10 12 14 3 6 9 12 15 10 15 20 25 S1 (mg HC/g rock) Porosity (%) SI (mg HC/g rock) Porosity (%)

Figure 6: Abundance of migrated hydrocarbons (based on Rock Eval ’s SI) and porosity development in the Lower Sandstone. Double arrows in the center = poor and tight zones ; solid bars = perforated zones for testing. The indicated perforated intervals in 23S are extrapolated from well 27S test (DST #1).

Norwegian University of Science and Technology 38 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

3.7 V ariations in hydrocarbon composition across the field

3.7.1 Uppermost Sandstone

Very limited data are available in this section to monitor compositional variations as no core samples are available from trap UM1. In addition, as no Iatroscan data are available for well 23S. Data from well 27S are used instead to exemplify UM2, keeping in mind the limited number of samples due to lesser core coverage (Figure 7). The general hydrocarbon content is about 80%, most of it being saturated hydrocarbons, but with conspicuous thin zones in the entire analyzed interval consisting of non-hydrocarbon (asphaltenic) rich layers. This feature is also seen in LS2 (well 26S), particularly in the lower half (which is known to contain solid reservoir bitumen, Bharati, 1997), below 4625 m (Figure 8).

Depth (MD m) TRAP US2 (Well 26S) Depth (MD m) TRAP UM2 (Well 27S)

Relative % SAT/ARO Ratio Relative % SAT/ARO Ratio

Figure 7: Composition of migrated petroleum in the Uppermost and Upper Sandstone shown as relative percentages of hydrocarbons (HC), resins (RES) and asphaltenes (ASP) as determined by Iatroscan. The yield of saturated hydrocarbons relative to aromatic hydrocarbons is shown as a ratio (SAT/ARO).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 39

3.7.2 Upper Sandstone

Unlike abundance and porosity, no rhythmic nature is observed with respect to petroleum composition in well 26S, representing trap US2 (Figure 7). In general, hydrocarbons comprise more than 90% of the total extractable organic matter (EOM) content, the remainder being non-hydrocarbons (NHC) in which resins and asphaltenes occur roughly in equal quantities. As indicated by the very high (typically >20) saturated : aromatic hydrocarbons ratio (SAT/ARO, relative percentage of saturated hydrocarbons / aromatic hydrocarbons), the major portion of the hydrocarbons are saturated while only 2-4% are aromatic. However, saturated hydrocarbon yield is prone to be affected by OEM cont amination and therefore the actual difference may not be so large, but we believe that the major trends are probably not so severely affected; nevertheless the factor of limited reliability of the results must be kept in mind. Some zones are anomalously enriched in non-hydrocarbons, particularly asphaltenes, the most prominent being the siltstone interval from 4460 - 4470 m (Figure 7). Such intervals are relatively rich in aromatic HCs too, as indicated by signif icantly lowered SAT/ARO ratio (2-5) and on closer examination it can be seen that these intervals are also the poorest with respect to abundance and porosity (cf. Figure 5). Trap US1, on the other hand, is significantly different with respect to EOM composition in that only about 40-60% of the total is hydrocarbons with SAT/ARO ratio of around 4. So, unlike in trap US2, EOM in trap US1 contains significant quantities of resins and asphaltenes (Figure 7).

3.7.3 Lower Sandstone

The composition of EOM in the Lower Sandstone is highl y variable, both down the hole and across the field. While nearly 85-95% of EOM in trap LS3 consists of hydrocarbons (SAT/ARO ratio ranges, 10-20, OEM effects as in the Upper Sandstone), some layers are particularly asphaltenic and relatively rich in aromatic hydrocarbon moieties (Figure 8). However, the vertical compositional change of the Lower Sandstone down the hole is best seen in traps LSI and LS2 represented by wells 21S and 20X respectively. In both these wells, the overall hydrocarbon content falls drastically with increasing depth from about 40-60% to <15%. The fraction which correspondingly increases is the high molecular weight asphaltenic material. This increase in the non-hydrocarbon content is also substantiated by relative increase in the aromatic hydrocarbons at the cost of saturated counterparts (fall in SAT/ARO ratio from 4-6 to <1, Figure 8). Comparing this to petroleum abundance data (cf. Figure 6), particularly in well 21S, it becomes clear that the increase in asphaltenic content is concurrent with overall decrease in abundance. In well 20X, apparently, the entire Lower Sandstone zone (poor in migrated hydrocarbons in the first place) consists predominantly (up to 80%) of non- hydrocarbons (Figure 8) and this supports the high amount of solid bitumen found here.

Norwegian University of Science and Technology 40 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Depth (MD m) TRAP LS3 (Well 26S) Depth (MD m) TRAP LS1 (Well 21S) 4457 r

4705--

4715-

20 40 60 80 5 10 0 20 40 60 80 0 2 4 6 8 10 Relative % SAT/ARO Ratio Relative % SAT/ARO Ratio Depth (MD m) TRAP LS2 (Well 20X) 4390

4400

4404

4408

4412 4492~

4497 =

4502

4507 U

4512 E 0 20 40 60 80 0 1 2 3 Relative % SAT/ARO Ratio

Figure 8: Composition of migrated petroleum in the Lower Sandstone shown as relative percentages of hydrocarbons (HC), resins (RES) and asphaltenes (ASP) as determined by Iatroscan. The yield of saturated hydrocarbons relative to aromatic hydrocarbons is shown as a ratio (SAT/ARO).

3.8 Molecular characteristics

All core samples, except those from well 27S, are contaminated by oil-based mud (OBM) additives to variable extent and therefore distinguishing between real and cont aminant features in some samples is difficult Problems associated with OBM contamination have recently received

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 41

some attention (Graas et al., 1997). Due to this, the usefulness of some techniques is limited, but compositional variations which are considered to be real can be detected. Gas chromatography of the saturated and aromatic hydrocarbon fractions has particularly proved to be of little use due to the saturated hydrocarbon being drastically affected by OEM contamination and practically no major compounds being detected in the aromatic hydrocarbon fraction. In addition, only a limited number of samples were subjected to gas chromatography (Table 2). Thermal extraction gas chromatograms (TE-GC) and pyrolysis-gas chromatograms (PY-GC, Bjor0y et al., 1992) have therefore been used to highlight the main compositional variations in the cores. A typical example of the effects of oil based mud (OEM) contamination (this sample is poor in migra ted hydrocarbons) is shown in Figure 9;. The dominant signature visible in the nCiz-n region is due to additives in the OEM and masks the in-situ n-hydrocarbon signature. A few organic components from OEM apparently adsorb to the mineral surfaces, that are sometimes difficult to extract thermally, and are released during pyrolysis, as seen in Figure 9b. Fortunately, the in-situ migrated hydrocarbon signature overrides the OEM effects if the samples are rich (discussed below).

OBMccntamhaSon

i 15 jjijuJjiiiu-JbuAju_

Figure 9: Exemplary (a) thermal extraction gas chromatogram (TE-GC) and (b) pyrolysis gas chromatogram (PY-GC) of a sample severely contaminated by oil-based mud (OBM).

3.8.1 Uppermost and Upper Sandstone

As OBM contamination (the narrow envelope from nC# to nCig , cf. Figure 9) remains a dominant feature in majority of the TE-GCs (common compounds present in OBM and in-situ hydrocarbons co-elute), the real migrated hydrocarbon signature becomes maned (Figure lOa-c) and difficult to interpret However, the in-situ hydrocarbons (nCig and higher) are detected in several samples, in some cases up to nC#. Another significant feature of most of the TE-GCs is the large ‘hump ’ consisting of unresolved material (mostly aromatic, branched and cyclic hydro ­ carbons and non-hydrocarbons); part of the hump, however, represents contribution from OBM. With regards to pyrolysate signatures, dominance of n-alkene/alkane homology (in the n-hydro- carbon doublets in the PY-GC traces, the first peak of the doublet is n-alkene and the second

Norwegian University of Science and Technology

TT '■’.0 42 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Thermal Extracts Pyrolysates

Figure 10: TE-GC (left) and PY-GC (right) signatures from the Upper Sandstone traps US1 and US2 and Uppermost Sandstone trap UM2. Peak identification: To - toluene, Xy - xylene, numbers indicate the number of carbon atoms in a straight chain; e.g. 15 is n-heptadecane in TE-GC traces and n-heptadecene /heptadecane doublet in the PY-GC traces, Pr - pristane and Ph - phytane.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 43 peak is the corresponding n-alkane) from C4 to about C20 is clear, in some cases strong and in others relatively weak, depending on the total asphaltene content (Figure lOd-f). Although n- alkanes with more than 20-22 carbon atoms are detectable, they are only a minor component. This is a fairly short range of pyrolysis products and typical of a light oil or condensate (Bjor0y et al., 1992). In a few cases, some OEM cont aminants are detected even in the PY-GC trace, where these contaminants were not able to be totally thermally extracted (Figure lOf).

The results of trap UM2 are interesting from another point of view; while both wells 23S and 27S are practically at the same location, well 23S was drilled using OEM and well 27S was not. Thus, comparing similar data from the two wells makes it possible to understand the extent of OEM contamination. In general, the TE-GC and PY-GC data remain grossly similar down to about 4330 m TVDSS (true vertical depth, sub-sea) and typical traces are shown in Figure 11a and d. Although the thermal extracts are affected by OEM to varying degrees, presence of migrated hydrocarbons is clearly evident. PY-GC signatures are nearly barren of any detectable compounds. However, on comparing data from the 27S well, the real and truly representative thermal extract signatures are seen (Figure lib) with a domin ant gaussian distribution of n-alkanes (nCis - nCgs). Clearly, contaminants from OEM severely impair the in-situ signature. While the thermal extract composition remains grossly the same in the samples below 4330 mTVDSS, the pyrolysate composition changes dramatically (Figure Ilf) in that a strong n-hydrocarbon homology (as commonly obtained from mature type II source rocks) becomes a common feature, which is the result of asphaltenic material in the sample (solid bitumen) cracking at elevated temperatures (550°C), although no solid bitumen is seen in the 23S cores, unlike Lower Sandstone cores of wells 20X, 21S and 26S.

3.8.2 Lower Sandstone

TE-GCs of the two traps LSI and LS2 (wells 21S and 20X respectively) are fairly similar and show similar changes with increasing depth. The top portion of the Lower Sandstone in these two wells shows a comparable and unimodal distribution of n-alkanes in the thermal extracts from nCw to nCgot with the maximum relative intensity occurring between nCie in and nCzo (Figure 12a). The difference in maxima may be related to porosity/permeability variations (e.g. higher porosity in well 21S leading to greater loss of low molecular weight hydrocarbons). The pyrolysate signatures of these two samples are also comparable, consisting predominantly of n- alkene/alkane homologies (doublets) from C4 to about C20 and only n-alkanes (singlets) from C20 to at least C25. Despite the fact that the entire Lower Sandstone interval in well 20X is poor in migrated hydrocarbons and dominantly consisting non-hydrocarbons, it is surprising to see the ‘oil ’ like TE-GC signatures in the upper part samples (4396 -4411 m).

In contrast, the cores from the lower half of the Lower Sandstone in trap LSI (including Devonian mudstone and rhyolite intervals of well 21S) exhibit one vital difference with regards to thermal extract composition when compared to the upper half. The lower half samples are

Norwegian University of Science and Technology 44 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Middle UM2

Bottom UM2

Thermal Extracts Pyrolysates

Figure 11: TE-GC (left) and PY-GC (right) signatures from the Uppermost Sandstone trap UM2. a) and d): from the upper part of well 23S (drilled using OBM); b) and e):from the upper part of well 27S (drilled using water based mud), c) and f) signatures representing the zone below 4330 m.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 45 significantly depleted in migrated hydrocarbons; consequently the OBM contamination becomes prominent and the thermal extracts consist of a narrower range of in-situ n-alkanes (Figure 12b). However, no major difference is observed with respect to the pyrolysate composition (Figure 12e) and even the lower half pyrolysales are characterized by a relatively narrow range of products (C4 to about C20). However, a major change in pyrolysate composition is seen horizontally across in trap LS3 (well 26S) where a rich distribution of heavier moieties is apparent (Figure 12f), perhaps indicating thermal degradation of asphaltenes or pyrobitumen contained in these samples. The thermal extract, on the other hand, clearly shows presence of presence of migrated hydrocarbons in trap LS3 (Figure 12c).

3.9 Discussion

Having presented all relevant abundance and compositional data with regards to the Embla sandstone core samples, it is quite clear that there exist variations, potentially large, in both respects. What is not clear with certainty, due to apparent OBM contamination, is the extent of these variations and the percentage by which, for example the richness data, have been affected. Nevertheless, based on the observed data and inherent limitations, an attempt has been made to synthesize the results and view them, on a field scale.

3.9.1 Comparison of the Uppermost Sandstone traps UM1 and UM2

Traps UM1 (well 20X) and UM2 (well 23S) are relatively shallow and contain no obvious solid bitumen development is seen. However, there are chemical indications below 4330 m in 23S that microscopic solid bitumen is present in the samples. Since the pyrolysate composition of most solid bitumens is similar, it is likely that the bitumen is disseminated throughout most of the cores in the lower parts of the Uppermost Sandstone in wells 23S/27S. The change in pyrolysis products between the upper and lower parts of the Uppermost Sandstone may also mark a change from more productive oil interval to less productive bitumen-filled intervals, which occurs at different depths in different wells.

Another interesting comparison shown in Figure 13 is the effect of OBM contamination on the saturated hydrocarbon GC signatures. While the core sample from well 27S shows the real in-situ signature and composition of hydrocarbons in trap UM2 (a gaussian distribution and n-alkanes traceable up to nCae, pristane:phytane ~1, Figure 13g), the 23S core sample from the same region has a far larger unresolved hump, a much weaker n-alkane homology and even an altered pris- tane:phytane ratio (Figure 13h), these being due to organic mud additives penetrating the host rock and replacing the in-situ hydrocarbons.

3.9.2 Comparison of the Upper Sandstone traps US1 and US2

Trap US2, which is relatively more important in the present context due to extensive data available, is bounded by faults on all sides and therefore may not be in communication with

Norwegian University of Science and Technology Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Thermal Extracts Pyrolysates

Figure 12: TE-GC (left) and PY-GC (right) signatures from the Lower Sandstone traps LSI upper part (top), LS2 lower part (middle) and LS3 (bottom).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 47 either trap TJM1 in the east or trap UM2 in the north, the faults probably serving as effective horizontal flow barriers. The overall abundance of migrated hydrocarbons and porosity development across the Upper Sandstone traps is comparable (typically 10-15 mg HC/g rock), but clear differences exist with regards to the composition, particularly between traps US1 and US2 (hydrocarbons are only 40-60% in the former and >90% in the latter, OBM effects?). Trap US2 has several tight zones with intercalating high porosity (10-15%) zones rich in free, extractable (and producible) hydrocarbons. In general, there is a slight decrease in petroleum abundance and porosity in this trap with increasing depth, but the richest intervals are apparent (Figure 5). DST # 2 in trap US2 consisted of seven intervals covering the entire Upper Sandstone.

In well 26S, the logger ’s depth was about 13 m deeper than the driller’s depth, the latter being the same as measured depths in our case. Taking this anomaly into account, the relative productivity from various perforated intervals is estimated (Table 3). Based on the available data of this study, it seems that although there exist some compositional differences, the entire Uppermost and Upper Sandstone interval contains migrated hydrocarbons and in practice can be considered as a pay-zone, discounting the obvious tight and poor zones.

Table 3: Correlation of intervals rich in migrated hydrocarbons (Driller’s depth) as estimated by geochemical evaluation to actual perforated intervals (Logger ’s depth) in the Upper Sandstone of trap US2 (represented by well 26S).

Perforated Corresponding interval rich Estimated Relative Interval (m) in Migrated hydrocarbons Productivity 4311-4315 Not detected Poor 4387-4390 Not detected Poor 4396 - 4404 Not detected Poor ,4413-4422_,, ...... 4405^4418 ...... 4435 - 4454 4427 - 4448 . . High 4478-4521 4465 - 4495 & 4501 - 4515 High 4527 - 4540 4518 - 4533 High

Based on saturated hydrocarbon and whole oil compositions, the Uppermost Sandstone DST #1 from 20X and Upper sandstone DST # 3 from 21S (trap US1) are very similar, but they vary slightly when compared to Upper Sandstone DST #2 from 26S (trap US2) in that while all are light-end biased (the US2 oil more strongly), the US2 oil from 26S is relatively lighter (Figure 13, Table 4). This and other minor differences may be maturity related (discussed in Bharati et al., 1997b). Given the similarity of oils from traps UM1 and US1 and considering the up-dip position of US1, the oil in US1 may represent a spill-over from trap UM1 after UM1 was saturated.

Norwegian University of Science and Technology 48 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Figure 13: Composition of whole oils obtained from DST as determined by whole oilGC and satura­ ted hydrocarbon fractions from selected core samples. Whole oil from traps a) US2, b) UM1 and c) LSI. d) saturated HC fraction from trap LS2 (lower part of well 20X). Whole oil from traps e) LS3 and f) UM2. Saturated HC fraction from traps g) UM2 (upper part) of well 27S and h) UM2 (upper part) of well 23S (oilbased mud used during drilling). Peak identification: numbers indicate the number of carbon atoms in n-alkane; e.g. 15 indicates n-heptadecane. Pr - pristane and Ph - phytane.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 49

3.9.3 Comparison of the Lower Sandstone traps LSI, LS2and LS3

As with the Upper Sandstone, the three traps in the Lower Sandstone are separated from each other by faults, which have a potential of functioning as barriers to lateral communication with the adjacent traps. In addition, the Lower Sandstone is separated from the Uppermost or Upper Sandstone by a thick mudstone sequence thus impeding vertical communication. Traps LSI, LS2 and LS3 occur at different depths with LS3 being most deeply buried (about 258 m TVDSS deeper with respect to LSI, Figure 3).

Table 4: Selected geochemical data of Embla oils from various sandstone intervals.

Sandstone —> Uppermost Upper * Lower Trap -> UM1 UM2 US2 US1/LS1* LSI LS3 Well/DST -> 20X/M 27Sf#l 265/#2 215/#3 2 JS/#i 265/#7 % Saturated HCs 76.40 81.12 79.61 77.26 76.72 86.48 % Aromatic HCs 17.49 14,88 A. "16.96 10.52 % Non-HCs 6.09 4.00 4.08 5.57 6.33 3.01 SAT/ARO "437 " "&45"" "4.87 _ 4J50" 432 ' 832 Pristane/Phytane 1.26 1.48 1.34 1.32 1.32 1.43 Pristane/nCj7 0.43 0.44 0.50 0.45 <148 0.61 Phytane/nCig 0.39 0.35 0.44 0.39 0.41 0.48 CPI" " .UX) . 1.02 1.09 1. 103 103 L16 Isoheptane ratio 2.97 2.81 2.75 2.65 2.47 5.19 MPX/EB ratio ' 4.00 ~ &7b 3.82 3.60 3.23 438 * commingled test consisting ofDST #2 interval in the upper part of the Lower Sandstone and the new Upper Sandstone interval (cf. Figure 3forDST intervals).

Geochemical data suggests that, with increasing depth, there is a decrease in migr ated hydrocarbon abundance. The cored interval in well 26S is in the lower half and is also the zone with solid bitumen occurrences. Although the major portion of the EOM is saturated hydrocarbons (generally around 80%) and non-hydrocarbons form only a minor percentage, trap LS2 is tighter and less permeable than trap US2 due to extensive solid bitumen, which has permanently destroyed substantial porosity and permeability. Consequently, the reservoir capacity (current pore volume) and thereby net hydrocarbons in place is also reduced. This is particularly evident (cf. Figures 6 and 7) on comparing traps LSI (well 21S, 4650 - 4693 m) and LS2 (well 20X, both the cored intervals 4396 - 4411 and 4492 - 4510 m) to LS3 (well 26S, the entire cored interval 4669 - 4726 m, but particularly below 4690 m). The relatively low flow recorded during DST in these intervals support this observation (500 BOPD in DST # 1 of well 21S and 332 BOPD in DST # 1 of well 26S). It is therefore conceivable that the Lower Sandstone in 20X will also yield similar production rates (no DST conducted).

Norwegian University of Science and Technology 50 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

No DST was conducted in the Lower Sandstone of 20X, so comparison of the compositions of traps LSI and LS2 is restricted to DST # 1 and 2 from well 21S (LSI) and the saturated hydrocarbon composition of 20X (LS2) core samples. When compared to the DST # 1 oil of UM1 (Figure 13b), the LSI oil signature (Figure 13c) is nearly identical, as is the 20X saturated GC signature (of a core chip, Figure 13d). Geochemical parameters such as pristane : phytane ratio, CPI etc. of the 20X saturated hydrocarbon fractions are also similar to the LSI oil (Table 4).

Figure 14: Enlargement of whole oil GC traces (nCio to nCjs) from traps LSI (top) and LS2 (bottom) represen­ ting the two oil types, A and B respectively. I to P represent the peak pairs in the nCio .17 range used to highlight the compositional differences through star diagrams. nCll, nC15, Pr and Ph are undecane, pentadecane, prist­ ane and phytane peaks respectively.

rC11

Based on n-alkanes distribution, all the Embla reservoir oil samples are grossly similar (all are light oils), except for some minor differences which may be maturity related (addressed in the Bharati et al, 1997a), but source related organic facies differences must be examined. While the major components of the oils (n-alkanes) do not exhibit and permit large discrimination, closer examination of the minor components which occur nearly at the baseline of the chromatograms present a better and distinct picture of possible compositional variations (Figure 14). Using such minor components, star diagrams have been successfully used to highlight such differences

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 51

(Kaufman et al., 1990; Halpem, 1995). In the case of Embla oils, 32 peaks were chosen in the nC? - nCn range and ratios calculated.

Apparently, subtle compositional differences occur in the Embla oils, particularly with respect to relative abundance of these components. On plotting the calculated ratios as star diagrams (Figure 15, shown as two plots to make interpretation easier), the six Embla DST oils plot as two distinct populations (two different star shapes) - type ‘A’ consisting of oils from traps US1 and LSI and type ‘B’ consisting of oils from traps US2, LS2 and LS3. While each of the oil types consist of oils closely related to each other, it seems that the Embla reservoir consists of two oil- type end-members: type ‘A’ represented by DST # lof well 20X (trap US1) and type ‘B’ represented by the DST #1 oil of well 26S (trap LS2). In the case of oils from traps US2 and LS3, while both are very similar to the type ‘B’ end-member, half the ratios (C, D, E, F, G, K, M and N) tend to be biased towards the type ‘A’ values. This suggests that the US2 and LS3 oils while grossly being type ‘B\ have in addition a minor component of type ‘A* oil. Despite the known similarity in maturity of all the Embla oils, these data indicate that two different sources may be involved, possibly with different drainage areas. This aspect is discussed further in Bharati et al. (1997b).

Increasing C number

TRAPS US1/LS1

TRAP LS2

TRAP US2

TRAP LS3

Figure 15: Oil correlation star diagrams of the six Embla oils. Two distinct oil types are apparent, type ‘A’ in traps US1, UM1.LS1 and LS2 shown as a dark band and type ‘B’ in traps US2, LS3 and UM2. Oils in traps LSI and LS2 are interpreted to be the end-members.

The observation that DST # 1 from well 26S is different from the others, particularly with respect to oils from wells 20X and 21S, is also supported by the findings of Li and Larter (unpublished results) based on their pyrrolic nitrogen studies of the Embla oils. Apparently, unlike the other

Norwegian University of Science and Technology 52 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea oils, 26S DST # 1 is enriched in methyl- and dimethylcarbazoles and depleted in benzocarbazoles, Based on this and other related organic nitrogen data, they concluded that this was due to this oil being derived from a different kitchen. Another significant aspect with respect to abundance and compositional variations in the Lower Sandstone is that, irrespective of absolute richness differences, the deepest samples analyzed in 26S (base of LS2) and 23S (not the base of UM2) are oil bearing. This is however not true in the case of trap LS1. While only the 4457 - 4576 m MD zone in 21S seems to be oil bearing, the entire Lower Sandstone in 20X is devoid of any ‘producible ’ hydrocarbons, although the top 15 m or so give residual oil signatures.

3.10 Summary and Conclusions

The Embla Field, a NW-SE oriented field of about 19.4 km2 at top Paleozoic, consists of three reservoir units, the Uppermost, Upper and Lower Sandstones, separated vertically by a thick mudstone facies. In addition, the reservoir section is intensely faulted, causing high risk for compartmentalization, a feature partially evident in the EFT and DST data. Due to the known geological complexities, extensive coring was conducted which served as a good database for detailed geochemical assessment. Evidently, both hydrocarbon abundance and compositional variations, generally agreeing with the petrophysical disparities, are present in the Embla Field. In addition to periodic invasions of hydrothermal fluids into the reservoir causing repeated periods of porosity loss and enhancement, there is a significant solid reservoir bitumen in the Lower Sandstone. The Upper Sandstone in well 26S, rich in migrated hydrocarbons and with higher porosity, is apparently more ‘rhythmic ’ and non-homogenous with respect to hydrocarbon richness and composition, as compared to the Lower Sandstone. However, the migrated petroleum in the Upper Sandstone is richer in hydrocarbons relative to non-hydrocarbons, when compared to the Lower Sandstone petroleum. This, in all likelihood, is due to extensive asphaltene-rich solid bitumen in the latter. Compositionally, the signature of migrated petroleum changes both horizontally across the various traps and vertically with increasing depth. This is particularly evident in the Lower Sandstone traps LSI and LS2, where the relative non- hydrocarbon percentage increases dramatically with depth. Interference from oil-based mud contaminants is quite severe in nearly the entire core sample suite, which has restricted detection of underlying differences in the Embla oil population. Nevertheless, it was possible to establish the gross differences based on a combination of various techniques. The data from the present study suggests that the order of richness of various traps is: UM2 (richest), US2, UM1, LS3, LSI and LS2 (relatively least rich). However, it must be borne in mind that data from trap LS2 are far less numerous and do not represent the entire trap vertically.

In addition, there are indications that the identified principal traps may not be in co mmunication with each other and represent two different oil populations. Also, the compositional and molecular variations that we see may be related to maturity and/or different source facies. These aspects, amongst others, are addressed in the second paper on the geochemical evaluation of the Embla Field (Bharati et al., 1997b).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 2: Embla Geochemistry: Occurrence & compositional variations of migrated HCs 53

3.11 Acknowledgments

SB thanks Norwegian Research Council, Phillips Petroleum Co. Norway and Amoco Norway for part financial assistance. The staff of Geolab Nor is thanked for assistance in geochemical analyses and the Department of Geology, Norwegian University of Science and Technology, Trondheim for logistics and encouragement Comments made by Richard Patience, Statoil and Chip Feazel, Phillips Petroleum on earlier drafts improved the quality of this manuscript. The authors acknowledge the following for permission to publish the paper. Phillips Petroleum Co. Norway and co-venturers, including Fina Exploration Norway S.C.A., Norsk Agip AS, Elf Petroleum Norge AS, Norsk Hydro Production AS, Statoil AS, TOTAL Norge AS and Saga Petroleum AS. The authors further acknowledge that the interpretations and conclusions presented herein do not necessarily reflect the opinions of the co-venturers.

3.12 R eferences

Bharati, S., 1997, Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf -1: Occurrence, development and morphotypes: AAPG Bulletin, (under submission).

Bharati, S., Rpstum, G. R. and L0berg, R., 1994, Calibration and standardization of Iatroscan (1LC-FID) using standards derived from crude oils, Organic Geochemistry, v. 22, p. 835-862.

Bharati, S., Hall, P. B. and Bjorpy, M„ 1997a, Identifying diverse oil families in the Greater Ekofisk area, Central Graben, Norwegian Continental Shelf: Marine and Petroleum Geology, (under submission).

Bharati, S., Hall, P. B., Vagle, K. and Bjor0y, M., 1997b, Geochemical evaluation of the Embla Field, Norwegian Continental Shelf- 2: Source, infilling , compartmentalization and intra- reservoir communication: Marine and Petroleum Geology, (under submission).

Bjor0y, M., Hall, K. and Jameau, J., 1990, Stable carbon isotope ratio analysis on single comp ­ ounds in crude oils by direct GC-isotope analysis: Trends in Analytical Chemistry, v. 9, p. 331- 337.

Bjor0y, M., Hall, K., Hall, P. B. and Leplat, P., 1992, Detailed hydrocarbon analyzer for well site and laboratory use: Marine and Petroleum Geology, v. 9, p. 648-665.

Bjor0y, M., Hall, K. and Moe, R. P., 1994, Stable carbon isotope variation of n-alkanes in Central Graben oils, Organic Geochemistry, v. 22, p. 355-381.

England, W. A., Mackenzie, A. S., Mann, D. M. and Quigley, T. M., 1987, The movement and entrapment of petroleum in the subsurface: Journal of Geological Society, v. 144, p. 327-347.

England, W. A., 1990, The organic geochemistry of petroleum reservoirs: Organic Geochemistry, v. 16, p. 415-425.

Norwegian University of Science and Technology 54 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Fraser, A. J., Farnsworth, J. and Hodgson, N. A., 1993, Salt controls on basin evolution- Central North Sea, in A. M. Spencer, ed., Generation, Accumulation and Production of Europe ’s hydro ­ carbons: Springer-Verlag, Berlin, p. 59-68.

Gowers, M. B. and Sasbpe, A., 1985, On the structural evolution of the Central Trough in the Norwegian and Danish sectors of the North Sea: Marine and Petroleum Geology, v. 2, p. 298- 318.

Graas, G. V., Dahlgren, S., Mills, N. and Sollie, F., 1997, The effects of drilling mud contamination on the quality of geological measurements: The 18 th International Meeting on Organic Geochemistry 1997 Abstracts, Maastricht.

Hall, P. B., Stoddart, D., Bjor0y, M., Larter, S. R. and Brasher, J. E., 1994, Detection of petroleum heterogeneity in Eldfisk and satellite fields using thermal extraction, pyrolysis-GC, GC-MS and isotope techniques: Organic Geochemistry, v. 22, p. 383-402.

Halpem, H. I., 1995, Development and applications of light hydrocarbon based star diagrams: AAPG Bulletin, v. 79, p. 801-815.

Horsfield, B. and McLimans, R. K., 1984, Geothermometry and geochemistry of aqueous and oil-bearing fluid inclusions from Fateh field, Dubai: Organic Geochemistry, v. 6, p. 733-740.

Kaufman, R. L., Ahmed, A. S. and Elsinger, R. 1,1990, Gas chromatography as a development and production tool for fingerprinting oils from individual reservoirs; applications in the Gulf of Mexico: PR 8824, in Proceedings of Gulf Coast Section of the Society of Economic Paleontolo­ gists and Mineralogists Foundation 9 th Annual Research Conference, p. 263-282.

Knight, I. A., Allen, L. R., Copiel, J., Jacobs, L. and Scanlan, M. J., 1993, The Embla Field, in J. R. Parker, ed., Petroleum Geology of Northwest Europe: The Geological Society, London, p. 1433-1444.

Larter, S. R. and Aplin, A. C., 1995, Reservoir geochemistry: methods, applications and opportu­ nities, in J. M. Cubitt and W. A. England, eds., The geochemistry of reservoirs: Geological Society Special Publication 86, p. 5-32.

Leythaeuser, D. and Ruckheim, J., 1989, Heterogeneity of oil composition within a reservoir as a reflectance of accumulation history: Geochimica et Cosmochimica Acta, v. 53, p. 2119-2123.

Norwegian Industry Guide to Organic Geochemical Analyses, 1993, Joint report by Statoil, Norsk Hydro, Saga Petroleum, IKU, Geolab Nor and the Norwegian Petroleum Directorate.

Sears, R. A., Harbury, A. R., Protoy, A. J. G. and Stewart, D. J., 1993, Structural styles from the Central Graben in the UK and Norway, in J. R. Parker, ed., Petroleum geology of northwest Europe: The Geological Society, London, p. 1231-1243.

Stoddart, D. P., Hall, P. B., Larter, S. R., Brasher, J., Li, M. and Bjor0y, M., 1995, The reservoir geochemistry of the Eldfisk Field, Norwegian North Sea, in J. M. Cubitt and W. A. England, eds., The geochemistry of reservoirs: Geological Society Special Publication 86, p. 257-279.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 55

Chapter 4: Paper 3

Geochemical evaluation of the Embla field, Norwegian Continental Shelf - 2: Source, infilling, compartmentalisation and intra-reservoir communication §

Sunil Bharati \ Peter B. Hall \ Rare Vagle2 and Malvin Bjorpy1

Geolab Nor, 7002 Trondheim, Norway; 2- Phillips Petroleum Co., 4056 Tanager, Norway.

4.1 Abstract

In this paper, the second part of a larger study on geochemical evaluation of the migrated hydrocarbons in the Embla Field, the aspects of source, maturity, intra-reservoir communi­ cation (compartmentalisation) and filling history are reported. Based on the known geological complexities (extensive faulting) and DST and RFT pressure data, it was suspected that the potential of compartmentalisation in the Embla Field was high. It was seen in the first part that the Embla field consists of two distinct oil populations, type A and B. In addition to the two oil types differing slightly in composition, type A oil is slightly less mature than type B oil, although both types are of base oil-window to condensate window maturity. By integrating all geochemical and petrophysical data, trap boundaries and positions of oil-water contacts and solid bitumen zones have been estimated in various parts of the field. Various Upper Jurassic source facies are examined in light of the available data of this study and possible source kitchens suggested. By incorporating neighbouring well data, various field charging scenarios are discussed and filling directions suggested for Embla. As two different sources are interpreted to have charged the Embla Field, the aspect of post-emplacement mixing is also considered. The implications of discontinuous oil-water contact and solid reservoir bitumen occurrence on overall field productivity and future exploration and development are reviewed. 5

5 Manuscript under submission to Marine and Petroleum Geology

Norwegian University of Science and Technology 56 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

4.2 Introduction

This is the second of the two papers on geochemical evaluation of the Embla Field. The first paper (Bharati et al., 1997a) assessed the occurrence and compositional variations of migrated hydrocarbons in the main reservoir units of the Embla Field, namely the Paleozoic Upper and Lower Sandstones. This paper addresses the aspects of source, maturity and compartmentalization of the migrated hydrocarbons, both mobile that can be produced and immobile, solid bitumen that cannot be produced. In addition, an attempt is made to postulate the filling history of the reservoir. Geochemical appraisal of petroleum reservoirs with respect to fluid molecular characteristics (oil composition and maturity or water composition) has recently been carried out on some fields of the North Sea (e.g. Horstad et al., 1990; Larter et al., 1991; Smalley at al., 1992; Hall et al., 1994; Mason et al., 1995). Most of these studies have utilized chemical data of oils such as compositional and maturity variations, physical properties etc. from different parts of the field to assess heterogeneity and barriers to fluid flow, and to link these geochemical observations to geological data to address regional migration routes and the filling history of the field. The fact that geochemical disparities are present and can be monitored in an oil population of a field is largely developed from the earlier works of England et al. (1987) and England and Mackenzie (1989), and is based on the principle that lateral compositional variations in particular, acquired during the oil emplacement process, are likely to be retained in the petroleum systems despite diffusive or density-driven mixing, which attempt to establish equilibrium in the reservoir.

In the case of Embla evidently, both hydrocarbon abundance and compositional variations correspond well with the petrophysical disparities, discounting for apparent oil based mud (OMB) contamination (Bharati et al., 1997a). The Uppermost and Upper Sandstones, which have higher porosity, are rich in migrated hydrocarbons and are apparently more ‘rhythmic ’ and non- homogenous with respect to richness and composition, compared to the Lower Sandstone. How ­ ever, the migrated petroleum in the Upper Sandstone is richer in hydrocarbons relative to non- hydrocarbons, compared to the Lower Sandstone petroleum. This, in all likelihood, is partially due to extensive asphaltene-rich solid bitumen in the latter. Compositionally, the signature of migrated petroleum changes both horizontally across the various traps and vertically down the reservoir. This is particularly evident in the Lower Sandstone traps LSI and LS2, where the relative non-hydrocarbon percentage increases dramatically with depth. Interference from oil- based mud contaminants is quite severe in nearly the entire core sample suite; however, it is possible to establish the gross variations within the Embla reservoir.

4.3 Geological background

This has been covered in detail in Bharati et al, 1997a, but briefly the Embla Field, a NW-SE oriented field of about 19.4 km2 at top Paleozoic, consists of three reservoir units, the Uppermost

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 57 sandstone (defined by traps UM1 in well 20X and UM2 in wells 23S/27S), Upper Sandstone (traps US1 in well 21S and US2 in well 26S) and Lower Sandstone (traps LSI in well 21S, LS2 in well 20X and LS3 in well 26S), separated vertically by a thick mudstone facies. The reservoir section is intensely faulted, potentially causing compartmentalisation, a feature which was suspected on evaluating the RFT and DST data. Due to the known geological complexities, extensive coring was conducted which served as a good database for detailed geochemical assessment In addition to periodic invasions of hydrothermal fluids into the reservoir, causing repeated periods of porosity loss and enhancement (Knight et at, 1993), there is considerable of solid reservoir bitumen in the Lower Sandstone.

4.4 Samples and Methods

Of the initial suite of 973 samples from the Embla field (Bharati et al, 1997a), a selected sample set was subjected to detailed analyses (Table 1), covering all the traps and taking into account all the variations or similarities observed.

Table 1: Details of number of samples analysed from the Embla Field, block NOCS 2/7. Wells 20X, 21S, 23S, 25S, 26S and 27S cover the reservoir sections (Upper and Lower Sandstones, all core samples) while wells 24 and 28 contain mainly potential source rocks (claystone cores and cuttings).

Well No. GHM-MS 1 GC-MS 2 Bulk 813 C 3 GC-IRMS 4

20X 13 8 8 — 21S . 14. _ , 8 8 23S 29 10 10 - 24 5 .7...... 7 — 25S 11 15 15 - ...... 26S____ ...... 64.. , .20 _ .. _ . 20. _ - 27S 4 7 7 - 28 5 5 5 — Oils - 6 6 6 Total 145 gri 86 6

7- Thermal extraction - mass spectrometry. 2- Gas chromatography - mass spectrometry. 3 - 8 I3C of bulk separated fractions (saturated and aromatic HCs, resins and asphaltenes). 4 - Compound specific gas chromatography - isotope ratio - mass spectrometry.

In addition, several oil samples from surrounding oil fields (Eldfisk Alpha, Eldfisk Bravo, Albuskjell, 2/7-19R, 2/7-3X) were analysed for comparison and correlation. All analyses were performed according to procedures specified in the Norwegian Industry Guide to Organic Geochemical Analyses (1993). In addition to the reservoir section, several potential source

Norwegian University of Science and Technology 58 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea rocks samples were also analysed from three wells (2/7-24, 2/7-28 and 2/6-3). Thermal extraction - Mass spectrometry (GHM-MS) (Bjorpy et al., 1991) was performed directly on bulk powdered rock samples to obtain biomarker data. Conventional gas chromatography - mass spectrometry (GC-MS) was also performed on a lesser number of samples using separated hydrocarbon fractions (obtained by liquid chromatography) to obtain additional biomarker data. Bulk 8 13C measurements were performed on all the 4 separated fractions (saturated and aromatic hydrocarbons, resins and asphaltenes) and EOM to assess the source and maturity variations in the migrated petroleum. Last, gas chromatography - isotope ratio - mass spectrometry (GC-IRMS) was performed on all six oil samples to highlight the subtle differences among the oils due to either maturity or source (Bjor0y et al., 1990; Bjor0y et al., 1994; Bharati et al., 1997b), which otherwise would have been difficult to establish by the above analytical techniques.

4.5 Maturity of the Embla oils

Given the gross composition of the Embla oils (light condensate-like oils, Bharati et al, 1997a), the likelihood of these being highly mature must be examined, in addition to characterizing the source facies of these oils. Thompson (1987) used gasoline range and light hydrocarbon based ratios (from whole oil gas chromatography) to characterize, define and distinguish oil populations with respect to paraffinicity (n-heptane/methylcyclohexane), aromaticity (e.g. toluene/n-heptane and meta + para-xylene/n-octane) and normali ty (n- heptane/isoheptane). In addition, Rovenskaya and Nemchencko (1992) used the meta + para- xylene/ethylbenzene ratio as a maturity indicator.

m,p-Xylene / Ethylbenzene Ratio Figure 1: Maturity based light hydrocarbon ratios to highlight XUM2 □US2 the internal differences within the +USVLS1 Embla reservoir. Eldfisk and

Albuskiell Albuskjell data (after Bharati et al., 1997b) and well 19R (DST #1) are included for comparison. Eldfisk

3 - —

isoheptane Ratio

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 59

Based on these ratios, Embla oils are apparently more mature than the Eldfisk oils, but less mature than the Jurassic oil (DST #1) from well 2/7-19R (located about 8 km west of Embla, Figure 1). Within the Embla oil population, the oil from trap LS2 (268/ DST #1) is an outlier, perhaps indicating its higher maturity than the others. Toluene/n-heptane and n-heptane/methyl cyclohexane ratios are affected by source maturity and reservoir alteration processes such as evaporative fractionation, biodegradation, water washing etc. (Thompson, 1987) and, in the case of the Embla oils, maturity is possibly the overriding factor, although minor spread away from the maturity trend may be source facies related (Figure 2).

Toluene / n-heptane Figure 2: A cross-plot of light TRAP hydrocarbon ratios that are XUU2 OUS2 affected by both maturity and +US1/LS1 post-reservoiring secondary processes.

Albuskjell

Eldfisk

i ' '—l 1 1—'—'—i—'—'—'—r~~i—1—'—'—'— 0 0.5 1 1.5 2 n-Heptane / methyl cyclohexane

Maturity estimation based on the sterane and teipane parameters is not feasible in the case of Embla for two reasons: either because these parameters are not accurately measurable (due to low concentrations) or the parameters have reached their maximum values. This is particularly evident on comparing the m/z 163 mass fragmentograms of the Embla oil samples to Cretaceous Chalk reservoired Eldfisk oils (Figure 3); the Embla oil con tains dominantly steranes (mostly C27- 29 diasteranes) whereas the Eldfisk oil has in addition, a significant hopane content This is likely due to higher maturity of the Embla oils, as hopanes (particularly the ap hopanes) are thermally degraded before the steranes and only relatively more thermally stable hopanes such as C27.29 neohopanes and C30 diahopane remain (Moldowan et al., 1991). In addition, sterane parameters in particular can show a decrease beyond a certain maturity level, and Waples and Machihara (1991) suggest that the most useful ratio (%Cag acta 20S/20S+20R) is only effective in the 0.4 - 0.8% Ro range.

Norwegian University of Science and Technology 60 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Steranes a) Embla Oil-m/z163 b) Eldfisk Oil-m/z163

Hopanes Hopaoes

Figure 3: Examples ofm/z 163 mass chromatograms representing (a) Embla oils and (b) an Eldfisk oil for comparison.

In the case of Embla oils, the dominant terpanes are the most thermally stable C27-29 neohopanes (so-called Ts compounds) and C29.31 diahopanes. The C29.35 ot|3 hopanes, ubiquitous in oil window mature Upper Jurassic source rocks and oils, are virtually absent The maturity of these oils is therefore considered to be base oil window to condensate window. Steranes of the Embla oils are dominated by C27 and C29 diasteranes and C21-22 short side-chained steranes. The abundance of C27 diasteranes is greater than C29 compounds. All the normal sterane maturity parameters have reached their maximum values and may even yield spuriously low values. Regular steranes, particularly acta compounds, are present in only trace amounts, again typical of very high maturity oils. Therefore, while such parameters show that Embla oils are more mature than other Greater Ekofisk oils, they fail to distinguish between the Embla oils.

However, aromatic hydrocarbon based maturity parameters are relatively more useful. For example, based on a plot of two aromatic maturity parameters, dimethyl naphthalene ratio (DMNR, Hall et al., 1985) and methyl phenanthrene index (MPI 1, Radke, 1988), a range of maturities is evident for the Embla oils (Figure 4), although all the Embla oils are very mature, as noted above (Rc > 0.9%, Table 2). Compared to the Embla oils, the Eldfisk and Albuskjell oils are of much lower maturity (Bjorpy et al., 1994; Bharati et al., 1997b). However, the Jurassic oil from well 19R is more mature than the Embla oils. A closer examination of methyl dibenzothiophene (MDBT) based maturity ratios (Table 2, Figure 4b) shows that the oils in traps LS2 and UM2 (DST #1 from 26S and 27S respectively) are more mature than the oils in traps UM1 and LSI (oil from US2 also plots close to UM2 and LSI; this may be an analytical error). Based on distinct compositional differences noted in the minor compounds (essentially non n- alkanes) using star diagrams (Kaufman et al., 1990), Bharati et al. (1997a) have shown that the Embla Field consists of two discrete oil populations - type ‘A’ (traps US1, LSI, UM1 and LS2) and type ‘B’ (traps US2, LS3 and UM2).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling , and intra-reservoir communication 61

Dimethylnaphthalene Ratio Figure 4: (a) Methylphenanthrene index (MPI 1) against dimethyl-naphthalene ratio (DMNR) and (b) 4/1 Methyl dibenzothiophene (4/1 MDBT) Albuskjell against 3+2/1 Methyl dibenzo ­

3 " 'Eldfisk-Bravo - thiophene (3+2/1 MDBT) maturity parameters obtained by gas chromatography of oils. For comparison and correlation, data for potential source rocks (wells 2/7-24, 255 and 28) are plotted in

1 - — (a). Eldfis : Alpha Well 24 Well 28

Methylphenanthrene Index

3+2/1 Methyl dibenzothiophene Ratio 100 TRAP XUM2 □ US2 +US1/LSI ▼ LSI ALS3 *19R X A to * +

t"

Albuskjell

Eldfisk

0.1 0.1 1 10 4/1 Methyl dibenzothiophene Ratio

Fine internal differences within the Embla oil population are also reflected in the overall distri­ bution of hopanes. For example, while the hopane deficiency is common to all Embla oils when compared to the Eldfisk oils, minor differences due to maturity and/or source are present, as seen in m/z 191 and 217 mass chromatograms. For example, 29Ts is significantly higher in type ‘A’, 27aS diasterane relative to 28[5S diasterane higher in type ‘B* and 27PR relative to 29pS diasterane higher in type ‘ B’ (Figure 5).

Norwegian University of Science and Technology 62 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Embla Type ‘A’

EmblaType ‘B’

Eldfis

m/z 191 m/z217

Figure 5: M/z 191 (left) and 217 (right) mass fragmentograms showing the triterpane and sterane compositions in Embla type ‘A’ (top) and ‘B’ (middle) oils and the Eldfisk oil (bottom) for comparison.. Peak identifications: 27Ts - 18a trisnomeohopane , 27Tm - 17a trisnorhopane, 30afi - a/3 hopane, 27d/3S - 20S j8a diacholestane, 29dpS - 20S Pa 24-ethyl diacholestane and 29aaR - 20R aaa 24-ethyl cholestane .

The higher thermal maturity of Embla oils, particularly in relation to Eldfisk oils, is also evident from aromatic biomarkers (Radke, 1988); for example high 3+2/9+1 methyl phenanthrene ratio

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 63

(based on m/z 192, a ratio value of about 1 indicates base oil window maturity), high 2,6 + 2,7/ 1,5-dimethyl naphthalene ratio (based on m/z 156, a ratio value greater than 2 indicates high maturity) and high 3+2/1 methyl dibenzothiophene (based on m/z 198, a ratio value of 2-3 indicates base oil window) for the Embla oils (Table 2). Closer examination of these ratios also reveals that, compared to oils from traps LSI, LS2 and UM1 and US2, the ratios are generally much higher (indicating relatively higher maturity) for oils from traps LS3, US2 and UM2, with trap LS3 oil being most different

Table 2: Selected maturity related geochemical data of Embla oils based on gas chromatography (upper half) and gas chromatography-mass spectrometry (lower half).

Up per Sandstone Lower Sandstone Trap —> UM1 US2 US1/LS1* LSI** LS2 UM2 Well/DST-+ 20X/#1 265/#2 21S/#3 21S/#1 26S/#1 27S/#1 Dimethyl naphthalene 3.38 3.09 2.77 3.18 4.34 3.65 ratio (DMNR) Methyl phenanthrene 0.99 0.98 0.89 0.9 1.21 1.11 Index(MPI) . Calculated Vitrinite 6.99 0.99 0.93 0.94 1.13 1.07 reflectance (% Rc) 3+2/1 methyldibenzo- 5,9 6,10 8.0 5.0 14.03 14.01 thiophene (MDBTX_ 4/1 methyldibenzo- 41 39.8 80 35 64.19 39.2 thiophene (MDBT) 29af3,/30aphopanes,„, .... 1.24 ..... 0.85 0.68 0.96 1.63 24/3 / 30ap hopane 3.41 2.52 2.66 2.99 5.56 >10 Cz/Cy diasteranes „ „ 2.16 .... __L77 1.9 1.84 3+2/9+1 methyl- 1.35 1.34 0.99 1.07 1.35 1.49 phenanthrene 2,6+2,7/1,5 dimethyl- 7/20 5.80 4.57 6.14 10.36 6.30 naphthalene...... 3+2/1 methyldibenzo- 3.77 6.50 3.58 3.13 7.00 5.44 thiophene * co-mingled test consisting ofDST #2 interval in the upper part of the Lower Sandstone and the new Upper Sandstone interval. ** test interval includes part of Lower Mudstone section.

Estimation of the petroleum maturity in the core samples is more difficult due to an additional factor of oil-based mud (OEM) impregnation causing even lower biomarker yields. This has particularly limited the employment of common hopane maturity parameters such as Tm/Ts and 30d/ 30d+30pa. Majority from sterane ratios is also affected by the same problem. Again, aromatic hydrocarbon based data have proved to be useful. For example, a cross-plot of dimethylnaphthalene ratio (DMNR) and methyl phenanthrene ratio (Kvaldheim et al., 1987) indicates that there is a generally increasing maturity trend from trap LSI (well 21S ) on the crest, to traps LS2 and UM2 (wells 26S in the west and 23S/27S in the north respectively), although

Norwegian University of Science and Technology 64 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea the data for individual wells are fairly widespread (Figure 6). This in general agreement with the observed maturity trend based on the oil data (Figure 4).

3+2/1 Methyl phenanthrene Ratio Figure 6: Aromatic hydrocarbons based maturity parameters, calculated from gas chromato ­ graphy data of core samples. Although the samples from well 27S belong to trap LS3, they have been plotted separately, as this is the only well in Embla which was not drilled using oil-based mud (OBM). All the other samples are affected by OBM contamination to varying degrees. Source rock Eldfisk data from well 24 are also plotted for comparison.

Dimethyl naphthalene ratio

4.6 Source of the Embla oils

Based on the above observations, the source of the Embla oils must be very mature, nearly at the base of the oil-window for type II kerogens. In addition, the fact that the oils in traps LS2, US2 and UM2 are slightly different from the others in composition (Bharati et al, 1997a) and warrants closer examination. A simple source facies (pristane/nCn) against maturity (dimethylnaphthalene ratio) cross-plot (Figure 7) underlines this difference. While all the Embla oils plot outside the main Greater Ekofisk trend, oil from trap LS2 is an outlier, suggesting that this oil (in well 26S Lower Sandstone) was generated by a different source facies with higher maturity than the others.

In addition, oils from traps UM1, LSI and US1 group more closely together and oil from UM2 is intermediate (Figure 7). However, stable carbon isotope (8 13C) data for n-alkanes and branched alkanes (obtained from GC-IRMS) clearly reiterate that there are two different oil populations in the Embla field (Figure 8) - Type ‘A’ oil in traps US1 and LSI (well 21S) and trap UM1 (well 20X) with identical isotopic signatures and Type ‘B’ in traps US2, LS2 and UM2 (wells 26S and 23S/27S); this is the same grouping as that obtained by star diagrams (Bharati et al., 1997a). The most marked difference is in the low molecular weight range (C5-15), in that type ‘B’ oils are significantly heavier than type ‘A’ oils, an indication of type ‘B’ oils being more mature. Isotopic signatures of n-alkanes heavier than about nCao are comparable for both the oil types. Perhaps the

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 65 oils from traps US1/LS1 (in well 21S) and trap LS2 (in well 26S) truly represent two different source facies, but the observed difference could also be due to different maturities. As the isotopic signature of US2 and UM2 oils is somewhat intermediate, these traps may have had a minor contribution of type ‘A’ oil.

Figure 7: Pristane/nCn (a source facies related parameter) vs. DMNR (maturity related para ­ meter) of Embla and Eldfisk/ Albuskjell oils for comparison. Both have different trends with increasing maturity. Trap LS2 sample continues to plot as an outlier.

The Upper Jurassic dark grey to black claystone sequence, the principal source rock in the Central Graben (Cayley, 1987; Cooper and Barnard, 1984) is extensively developed across the Skrubbe Fault east of the Embla dome (1791 and 159 m Mandal + Farsund Fms. in wells 2/7-24 and 2/7-28 respectively and 278 m Haugesund Fm. in 2/7-28). Wells 24 and 28 (located E-SE and N-NE respectively with respect to Embla) are less than 2 km from the Embla dome but are separated from the Embla dome by a major salt wall (Roberts et al., 1990). In addition, the Upper Jurassic Tyne Gp. is well developed on the eastern flank of the Embla dome (ca 320 m thick Mandal + Farsund Fms. in 2/7-25S, Bharati et al, 1997), but is also found as a thinner unit in the other Embla wells (20X, 21S, 23S, 26S and 27S). The Upper Jurassic sequence is quite deeply buried in wells 24 and 28 (Table 3), but most buried within the Embla dome (about 4120 m in 25S), although the depth of burial increases northwestward within the Embla dome. Lack of a good sample set from within the Embla dome limits the evaluation of the Upper Jurassic source rocks to wells 24 and 28, although it is unlikely that hydrocarbons generated in these areas could have migrated to the Embla reservoir through the salt wall.

Norwegian University of Science and Technology 66 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

1 o o Jj E z

Figure 8: GC-IRMS based 813C data for individual alkanes in oils from the Embla Field. In branched alkanes: I - iso; 2, 3, 4- position of methyl group; M - methyl; DM - dimethyl; C4 indicates the number of carbon atoms in the parent molecule, e.g. iC4 - iso-propane, 3.6DMC8 - 3,6-dimethyloctane.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 67

In addition, there is a significant difference in the Upper Jurassic facies of wells 24 and 28 (dark grey to black claystones) and well 25S (claystone + sandstone + brecciated material). Therefore, evidence for the source of hydrocarbons in pre-Jurassic sandstones of the Embla field is based mostly on wells 24 and 28 and is only circumstantial.

Table 3: Selected richness, potential and maturity related geochemical data of the potential source rocks (Upper Jurassic Tyne Group) based on Rock Eval, latroscan and saturated / aromatic hydrocarbons gas chromatography. All data given as average values. Number of samples in each case is given in parentheses.

Parameter Well —> 2/7-24 2/7-25S 2/7-28 Major lithology dark grey-black brownish grey dark grey-black Claystone Claystone * Claystone Net thickness (mTVD)...... _ -1791 .... -320 Y . r-437...... Depth of occurrence (mTVDSS) 3173-4964 4120-4324 3296-3753 TOC(%) 1-9.4(49. ___ 1,7(5)...... 14.2O0) . Hydrogen index (mg HC/g TOC) 91-499(46) 63(9 473 (10) Petroleumpotential (tngHC/g rock) 4-81.(46) 27(5) . 8009 Tmax (°C) 413 - 472(46) 429 (5) 447 (10) Extractable organic matter (mg/g rock) _ 3.9:5,1901) .36.82(5) 41^2(9) % Hydrocarbons in EOM 24-66 (11) 92.6 (5) 36.1 (9) Saturated / Aromatic HC ratio _...... n-sjofL &29(9) _ _ % Non-hydrocarbons in EOM 34-76 (11) 7.4(5) 63.9 (9) Pristane/Phytaneratio ...... „ W-WGL. 0-73 (%). .. _ 120(3) ... Pristane / nCn ratio 0.35-0.57(4) 0.49 (2) 0^ (3) PbyMs./nWatw ...... _ &30-P%#.. 0 48 (2) ...... 058 (3) ...... Carbon preference index (CPI) 0.99 -1.08 (4) 1.14(3) Vitrinite reflectance Ro (%) 0.98 -1.05 (4) 0.88 (2) 0.81 (3)

* includes intercalated sandstone and brecciated material.

The Upper Jurassic section in wells 24 and 28 is generally very rich in organic matter (Table 3) and with a very rich petroleum potential, as a major portion of this section is within the oil window. In well 24, the Mandal Fm. and the upper part of the Farsund Fm. (3150 - 4444 m) is relatively the richest section, typically con taining 4 - 10% organic carbon resulting in very rich petroleum potential (up to 81 mg hydrocarbons/g rock). Hydrogen indices of about 200 - 500 mg hydrocarbons/g TOC suggest a type II kerogen. The lower portion of Farsund Fm. in well 24 (below 4444 m) is relatively poor but with moderate petroleum potential (<10 mg hydrocarbons /g rock). In well 28, however, a much greater variation is present While the upper portion of the Farsund Fm. (3289 - 3342 m) is less rich (TOC 5 - 8%, hydrogen index 241-385 mg hydrocarbons/g TOC, petroleum potential 8-36 mg hydrocarbons/g rock), the lower portion of Farsund Fm. (3366 - 3446 m) is very rich (TOC 10 - 22%, hydrogen index 443-758 mg

Norwegian University of Science and Technology 68 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea hydrocarbons/g TOC, petroleum potential 55 - 131 mg hydrocarbons/g rock). The Haugesund Fm in well 28, with a total thickness of 278 m, is also very rich in organic carbon (4 - 13% TOC) with a rich petroleum potential (20 - 71 mg hydrocarbons/g rock) and high hydrogen indices (278 - 684 mg hydrocarbons/g TOC). Clearly, there is a major organic facies change occurring vertically down and horizontally between the wells. However, very high EOM yields, as also indicated by high SI yields during Rock Eval pyrolysis, suggest active generation taking place in the Upper Jurassic sections of these wells at the present time.

Thermal extract and pyrolysate compositions clearly indicate an oil prone source rock and grossly type II marine kerogen in the Mandal Fm., the upper part of Farsund Fm. and the Haugesund Fm (Figure 9), with some minor differences (higher aromatic hydrocarbon species for instance) in some samples due to increased terrestrial organic matter input Typically, a strong homology of n-alkene /n-alkane doublets extending up to nC# is present and aromatic hydrocarbons are less prominent in the pyrolysates, a signature quite typical of oil-prone mature, marine type II kerogens (Bjor0y et al., 1992), but in the deeper section the pyrolysates are richer in lighter components due to higher maturity (close to the base of oil-window - 1.0% Ro equivalent). The deepest samples generate mostly gaseous components, suggesting that most of the potential has been realized and only residual kerogen is present, this feature being more evident in well 24.

The thermal extracts are rich in n-alkanes with variable amounts of aromatic and branched hydro ­ carbons and the signatures indicate in-situ, active generation. Pristanezphytane ratio ranges 1.0 - 1.5 and the pristaneznCn and phytaneznCig ratios are generally within the ranges 0.34 - 0.47 and 0.31 - 0.40 respectively, indicating that the hydrocarbons have been generated in-situ from mature marine kerogen. However, the lower part of the Farsund Fm in well 24, which is also poorer in TOC, is quite different and with a higher terrestrial input (type n/E3 kerogen) and consequently lower oil potential. In the case of well 28, the deeply buried Haugesund Fm is still rich in organic carbon with high hydrogen indices, indicating that a significant portion of the generative potential is unrealized.

The most conspicuous compositional difference, however, is seen in the very high TOC interval (3366 - 3446 m) in the lower half of the Farsund Fm in well 28. Its thermal extracts have signifi ­ cantly higher abundance of light hydrocarbons and isoprenoids (Figure 9). Pristane/nCn and phytane/nCig, for instance, are also consequently higher (0.63 and 0.81 respectively). The pyro­ lysate signatures of these samples also show high abundance of tentatively identified isoprenoids, including prist-l-ene, most probably due to anomalous enrichment of algal/ bacterial organic matter (Freeman et al., 1990; Summo ns and Powell, 1987). Thus, in comparison to the previous ‘normal ’ Upper Jurassic facies, the 3366 - 3446 m interval represents an ‘abnormal ’ isoprenoid- rich facies.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 69

Thermal Extracts Pyrolysates

Figure 9: Representative thermal extract chromatograms (TE-GC) and pyrograms (PY-GC) of the potential source rocks, a, b) Upper Jurassic Tyne Gp.- Mandal Fm. And c, d) Farsund (upper part) and Haugesund Fms. in wells 2/7-24 and 28. Peak identification: T - toluene, X - xylene, the numbers indicate the number of carbon atoms in a straight chain; e.g. 15 indicates n-heptadeccme in TE-GC traces and the position of n-heptadecene/heptadecane doublet in the PY-GC traces, Pr-pristane, Ph-phytane and P-prist-l-ene. V are isoprenoid pyrolysis products.

Comparison of some key biomarker parameters from the Upper Jurassic source rocks (normal facies) and Embla’s migrated petroleum data (Table 4) suggests that the Embla oils may not have been generated by these source rocks, considering particularly the source facies dependent para­ meters such as 29oc|l /30ajJ, 30d /30ajl, 28a(3 /30aj3 or C27 /C29 diasteranes, although most of these parameters are also influenced by maturity (Peters and Moldovan, 1993).

On the other hand, other source facies dependent parameters such as the abundance of pristane and phytane isoprenoids (also in relation to nCn and nCig respectively) and the 8 13C isotopic signatures of the Embla oils are comparable to the source rock data (Figure 10). However, while the pristane/nCn and phytane/nCig ratios of the Embla oils (generally 0.3 - 0.8) indicate high maturity, they should have been lower than the observed values given the base oil

Norwegian University of Science and Technology

w :####' 70 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea window maturity of the oils; unless the facies that generated these oils was unusually rich in isoprenoids, such as the 3366 - 3446 m ‘abnormal ’ facies of well 28.

Table 4: Comparison of various Upper Jurassic source intervals (wells 24 and 28) and the two Embla oil types with respect to organic facies* and thermal maturity using biomarker data The ‘abnormal ’ FarsundFm. refers to the isoprenoid-rich interval.

Parameter Mandal + Up. ‘Abnormal ’ Haugesund Embla type Embla type Farsund Fms. Farsund Fm. Fm. ‘A’oil ‘B’ oil 27Tm/27Ts 0.61 1.05 0.32 - 0.09? 29ocp/30aP* 0.45 053 0.41 0.96 1.24 30d / 30ap * 0.05 0.03 0.22 2.48 2.94 28ocp/30ap* 0.02 0.05 0.06 053? - 24/3/30ap 0.04 0.05 0.17 3.02 4.04 %32apS 59.69 60.62 6050 - - 27dpS/27dj3S+27aaR 0.68 0.54 0.82 0.89 0.92 %20S C29 steranes 49.50 4753 54.71 58.25- 53.72 C27 / C29 diasteranes * 1.06 0.76 1.30 2.04 1.84 0.68 % aPP C29 steranes 0.53 059 . 0.60 0.65

While most of the Upper Jurassic section is past peak oil generation and up to the base oil window maturity (Table 3), the source rock in question (the ‘abnormal ’ facies) has not reached base oil window maturity in the analysed wells. Finally, in addition to the similar isotopic data, pristane:phytane ratios of the Embla oils (1.26 - 1.42, Bharati et al, 1997a) are comparable to those of the Upper Jurassic source rocks (1.20 - 1.51). Clearly, there is some discrepancy in the biomarker and other data of the present study. Similar discrepancy, but between biomarker and carbon isotope data, was also observed in several North Sea oils by Northam (1985). However, comparison of the Upper Jurassic terpane and sterane fingerprints (Figure 11) with the Embla oils (Figure 5) reveals signif icant differences.

The sterane distribution of the ‘abnormal ’ facies at maturities less than about 0.7% Ro equivalent is distinctly different from the ‘no rmal’ facies (Figure 11). The main differences are in the relative abundance of diasteranes and app steranes to regular ocaa steranes. At the same maturity level, the ‘abnormal ’ facies has less diasteranes and more app steranes relative to the regular ocaa steranes than the ‘normal ’ facies. This is pronounced at lower maturities (i.e. < 0.6% Ro) and becomes less pronounced with increasing maturity. Examples of the ‘abnormal ’ facies at high maturity are difficult to identify (they might be present in wells NOCS 2/7-15, 2/6-2 and 2/5-6 in the north, unpublished results) since all the highly mature samples which we have evaluated show similar sterane and hopane fingerprints, i.e. like those seen in the ‘no rmal’ facies at high maturity.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 71

Phytane/nC18 Figure 10: Comparison of a) pristane / nCn and phytane / ■ UM1 XUM2 nCis ratios and b) S 13C of ' OUS2 0.8 - - +US3 saturated and aromatic hydro ­ ■ TLS1 carbons of core samples from the . A LS3 O Wen 24 Embla reservoir and source . . »Well 28 rocks from wells 24 and 28. Well 27S core samples (which belong to trap LS3) are plotted separately to highlight the effects of OBM on core samples.

0 0.2 0.4 0.6 0.8 1 Pristane/nC17

d13C Aromatic Hydrocarbons

-26------

LSI(Up.hall)

-28 * -

d13C Saturated Hydrocarbons

Forsberg et al. (1993) identified several intervals of the Upper Jurassic Farsund and Haugesund Fms. of the Central Graben which are very organic rich (with TOC > 10% and Rock Eval S2 reaching or exceeding 50 mg HC/g rock) and have low sonic velocities. These organic rich inter­ vals occur in their sequence ‘B’ which does not correlate with the classical stratigraphy used in the area; for instance the top of ‘B’ occurs within the Haugesund Fm. of well NOCS 2/8-3 and within the Farsund Fm. of well 2/7-3. Very organic rich horizons have been identified in this study in wells 2/7- 28 and 2/6-3 and thin sections of other wells. Some of these organic rich

Norwegian University of Science and Technology 72 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea sections have hydrocarbon compositions differed from the ‘normal ’ organic rich Upper Jurassic (i.e. as found in the Mandal Fm.). The most distinct differences are that, unlike the ‘normal ’ facies, hydrocarbons in the ‘abnormal ’ facies are isotopically heavy and acyclic isoprenoids are both very abundant and isotopically extremely heavy. Isotopically heavy isoprenoids in other source rocks have been used to indicate specific source org anisms, e.g. photosynthetic bacteria (Summons and Powell, 1987 - for isoprenoids coupled to a ring) or algae (Freeman et al., 1990). Other features of this ‘abnormal ’ facies, at low maturity (i.e. < peak oil) are presence of gammacerene as a minor component and low diasterane/regular sterane ratios, high app/aaa and higher content of short side chains. At higher maturities, the biomarker differences probably become less marked but we have no definite examples to demonstrate this.

In addition to Forsberg et al.’s (1993) observation about distinctly different and traceable Upper Jurassic source sequences, Northam (1985) has also noted that, while the majority of Central Graben oils were generated by the Upper Jurassic Kimmeridge clay or equivalent, different organic facies of this common source occur in the basin. Therefore, the most likely source of the Embla oils based on isotopic composition and relative isoprenoidm-alkane ratios (given that these oils are very mature) is the one in which the ‘abnormal ’ facies dominates, such as the lower portion of the Farsund Fm. (3366-3446 m) in well 28. Unfortunately, the high maturity of the Embla oils (base oil window to condensate window) makes it impossible to correlate confidently the steranes and hopanes to any particular facies. This is because at high maturity, the controlling factors on hopane and sterane abundance are expulsion processes and thermal effects rather than source type (Sofer, 1988).

4.7 Possible Filling Directions

Taking into consideration all source rock and migrated hydrocarbon evidence, four different scenarios with respect to generation emerge.

4.7.1 The Feda Graben kitchen

Despite excellent Upper Jurassic data from wells 24 and 28 in the Feda Graben (thick sections, rich potential, type II marine kerogen, oil window maturity, active generation at the present time), the unlikelihood of the generated oil migrating through the salt wall and the Skrubbe Fault into Embla must be kept in mind. The deep Jurassic section of the Feda Graben has also been proposed as a possible source of the Embla oils, particularly for the early oil charge which was later cracked to residual bitumen (Knight et al., 1993). In addition, it was proposed that the Eldfisk field was filled from the west via the Skrubbe fault before the fault was sealed (Hall et al., 1994; Stoddart et al., 1995). It can therefore be envisaged that the Skrubbe fault may have served as a conduit even for Embla, perhaps accounting for only part of the total charge. However, this possibility is further weakened by the fact that the ‘abnormal ’ facies in this area has (based on well 28 data) not attained the required base oil window maturity to have generated the Embla oils (Figure 12).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 73

a b

Z76PS 29ooR

27Ts 2Hm

■ pi. .11 —i i*.. J. i , f i, -i». »-it illJLlLu.

m/z191 m/z217

Figure 11: Exemplary terpane (m/z 191, left) and sterane (m/z 217, right) mass fragmentograms of Upper Jurassic potential source rocks. Top- Farsund Fm. ‘normal ’ organic facies (3348 - 3393 m); middle- Farsund Fm. ‘abnormal ’ organic facies (3417 - 3476 m); bottom- Haugesund Fm. Peak identifications: 27Ts - 18a trisnomeohopane , 27Tm - 17a trisnorhopane, 30oft - oft hopane, 27df5S - 20S fia diacholestane, 29df3S - 2OS f$a 24-ethyl diacholestane and 29aaR - 20R aaa 24-ethyl cholestane.

Norwegian University of Science and Technology 74 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

4.7.2 The local Embla kitchen

In the event that the thin Upper Jurassic sections found in the Embla wells 20X, 21S, 23S, 26S and 27S were equally rich in type II organic matter (and rich in isotopically heavy isoprenoids) and reached peak oil generation in the past, significant quantities of petroleum may have been generated that could have been locally trapped in various Embla pre-Jurassic sandstones. However, due to poor sample control and scarce data, this option remains inconclusive. In addition, it has been noted by Bharati et al. (1997a) that the Embla reservoir comprises two distinct oil populations. It is unlikely that a sufficient source facies change would occur within the Embla dome to account for the observed compositional difference (Figure 12).

4.7.3 The deep Embla kitchen The Upper Jurassic of the eastern flank of the Embla structure (immediately west of the Skrubbe Fault and north-west of well 25S), an area where the Upper Jurassic is deeply buried, in fact more deeply than in well 25S, could have (had) some generation potential. Limited volume of this claystone (see Figure 1) may also be undermine this possibility. However, as no samples or data are available to test, this option remains a speculation (Figure 12).

4.7.4 The western / northwestern kitchen

This may well be most important, especially in the light of documented compositional (Bharati et al, 1997a) and maturity differences within the Embla oil population. In this case, at least two sources likely fed the Embla reservoirs (from 2-3 km west of Embla or 10 km NW of Embla and north of Ebba), particularly in trap LS2 and US2 (well 26S, Figure 12). In his study of the generation and migration patterns of the central North Sea, Cayley (1987) has shown the occurrence of deeply buried Upper Jurassic source rocks in the late oil/wet gas window, west / north-west of Embla. Moreover, he observed that in the case of most Jurassic reservoired hydrocarbons, the drainage areas are large in the deep graben (averaging >250 sq. km.) and more limited in the graben margins (averaging 50-60 sq. km.).

Although there is limited data to fully assess the composition of the hydrocarbons in the Upper Jurassic shales surrounding Embla, it has been shown that the Embla oils are most probably from the isotopically heavy (i.e. depleted in 12C), isoprenoid-rich ‘abnormal ’ source facies of the Upper Jurassic section, rather than the more ‘normal ’ and typical marine Upper Jurassic rocks of the Central Graben (isotopically lighter and with less abundant isoprenoid content). A clear differentiation between isoprenoid-rich and -poor oil sources is gained using an aromatic maturity parameter (DMNR) versus a source + maturity parameter (pristane/nCn, Figure 7), which clearly shows that the Embla oils (and Jurassic reservoired oils) lie in a separate maturity trend than most of the Cretaceous chalk-reservoired oils. In addition, the Embla oils are more mature than any of the chalk-reservoired oils. The maturity of the source kitchen(s) of the Embla oils is close to 1% Ro or more, while in the case of most of the Chalk-reservoired oils it is less than 1% Ro (Figure 4). Furthermore, a trend of increasing maturity can be seen, from 25S in the south-east to

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 75

Figure 12: Three scenarios of interpreted oil charge movement and filling directions in the Embla Field. Figures on top show the limits of the Embla Field at base-Cretaceous while figures at the bottom are simplified and schematic cross-sections of the Embla reservoir units (cf. Figure 13). Open arrows indicate type ‘A’ oil and the solid arrows represent type ‘B’ oil.

26S/27S in the north-west, from both core and oil data. Based on these observations and the preceding discussion, we propose the most likely filling scenario shown in Figure 12. The field was filled by two charges from the west and/or north-west The two charges (type ‘A’ and type ‘B’ oils) were from separate source kitchens, possibly with different drainage areas, with the type ’B’ oil kitchen being slightly more mature and differing slightly in the organic facies. However, the organic facies of both the kitchens consists of isotopically heavy n-alkanes and is anomalously rich in isotopically heavy isoprenoids. The points of entry of types ‘A’ and ‘B’ oils are probably traps LSI and LS2 respectively (Figure 12). Based on the compositional and maturity characteristics of the pre-Jurassic reservoired oil from well 19R (west of Embla), it is possible that this was in the migration pathway and was filled after the Embla field was saturated.

Norwegian University of Science and Technology 76 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

4.8 Trap Boundaries and communication

Based on the 5 exploration wells drilled on the Embla dome (cf. Figure 12) and which penetrate the Upper and Lower Sandstone reservoir section, six principal (UM2, US2, UM1, LS3, LSI and US1) and one minor (LS2) traps were defined, based mostly on the structural elements (faults) of the dome (cf. Figure 13), but also on geochemical characteristics. Geochemical data show that there are two distinct oil composition populations (Bharati et al., 1997a), which also vary slightly in maturity. Within each of the oil populations, there are weak maturity trends. Each of the traps is isolated with respect to horizontal flow (faults) and vertical flow (mudstone section), thus making them independent compartments. In this section, we attempt to address the trap boundaries and assess the inter-trap or intra-reservoir communication.

23S/27S

I Uppermost I -i

: :(Uppermost]

0ST#1 DSTS1

DST81

Figure 13: Generalized cross-section (roughly NW-SE) of the Embla Field below the base Cretaceous unconformity. Solid bars on the right of each well indicate cored intervals while the open bars on the left indicate perforated intervals for production testing. The bottom left inset is a simplified graphical representation of the Embla Reservoir units. Interpreted oil- water contacts (OWC) and base of bitumen-free zone are also indicated.

The horizontal barrier (the mudstone section sandwiched between the Upper and Lower Sand­ stones) is present in all the wells, although its thickness varies. However, mudstone samples from three wells (21S, 23S and 26S) show no presence of migrated hydrocarbons, although minor in-

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 77 situ generated bitumen is present This clearly suggests that the migrated hydrocarbons are not ‘leaking through* from below and that the Upper and Lower Sandstone are well isolated from each other. Of all the faults at base Cretaceous level in the Embla dome which compartmentalize the field, two NW-SE trending faults are most dominant (cf. Figure 12): one is the Skrabbe Fault which defines the eastern limit of Embla, and the other in the center which divides Embla into two halves. This latter NW-SE fault almost certainly serves as efficient barrier to horizontal flow, given the observed compositional and maturity variations seen in traps US2/LS2 (west of the fault) and UM1/LS1 (east of the fault). In addition, there are several roughly E-W trending faults adding complexity. Some of these are certainly serving as barriers, such as the one between wells 23S and 20X (different oil types in traps UM1 and UM2). It is therefore conceivable that Embla is effectively compartmentalized and little or no communication exists between the defined traps UM1 and UM2 in the Uppermost Sandstone, US1 and US2 in the Upper Sandstone and LSI, LS2 and LS3 in the Lower Sandstone. During the last five years of production, no pressure communication has been observed between the various fault blocks.

4.9 Field Productivity : Implications of OWC and Bitumen Occurrence

Bharati et al. (1997a) noted that the upper part of trap LSI (core # 4,5 & 6 in well 21S) is clearly oil-bearing, down to at least 4580 m MD, confirmed by DST # 2 results (5200 STBOPD). However, the 4650 - 4693 m cored interval (core # 7,8 & 9) is definitely not oil-bearing. This places the oil-water contact (OWC) in 21S between 4580 and 4650 m MD (4290 - 4359 m TVDSS). In well 20X, none of the Lower Sandstone cored sections (core # 2 & 3 at top- 4372- 4386 m TVDSS; and core # 4 at bottom- 4467-4485 m TVDSS) are rich in migrated hydrocarbons (generally 0.2 - 1 mg hydrocarbons/g rock) and typically more than 70% of the total EOM is composed of non-hydrocarbons; this section therefore is comparable to the 4650 - 4693 m section (core # 7,8 & 9) of well 21S, despite indications of minor oil staining in the 4397 - 4411 m section (4372 - 4386 m TVDSS) in the former, based on TE-GC and saturated hydrocarbon GC; perhaps this represents a transitional zone. Placing the OWC accurately is therefore difficult in traps LSI and LS2. In such a case, using the term ‘oil down to ’ may perhaps be more appropriate. Accordingly, it is estimated that oil extends down to about 4325 m TVDSS in well 21S and at the most down to 4370 m TVDSS in well 20X..

With regards to trap US2, except for some tight zones, the entire Upper Sandstone is oil-bearing (Bharati et al., 1997a) and this is confirmed by DST # 2 results (2611 STBOPD). The Lower Sandstone trap LS2 is relatively poor, but still considered to be an oil-bearing zone; but lower porosity (4-10%) and permeability result in lower flow (332 STBOPD) during DST. Although the overall reservoir properties deteriorate with depth in the Lower Sandstone, particularly below 4690 m MD, no clear indications are seen of water-bearing or non-oil bearing samples. The Embla dome is divided into two halves by a major NW-SE trending fault, with the western block downthrown (Figure 12). Well 26S (traps US2 and LS2) is the only well on the western half while all the other wells are in the eastern half. The OWC in trap LS2 may therefore be deeper

Norwegian University of Science and Technology 78 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea than the prognosed base of the Lower Sandstone in 26S (4549 m TVDSS), as shown in Figure 13. This has very serious implications with respect to future exploration in the western half of the field, provided it is established that the sand body continues NW and SE of 26S.

In trap UM2, the deepest core sample analysed (4718 m MD) is oil-bearing and no different than the samples above (Bharati et al., 1997a). The OWC in this trap is therefore deeper than about 4400 m TVDSS.

Geochemical data therefore indicate different depths for OWC in different traps, suggesting dis­ continuous OWC across the various fault blocks of the Embla field (Figure 13). This hypothesis is further strengthened by the fact that no pressure communication has been observed across the different fault blocks during the past about five years of production.

Bitumen occurrence is quite independent of the OWC in each of the traps. Bharati et al. (1997a) established accurately the depths at which a bitumen zone starts in wells 20X, 23S and 26S, while circumstantial evidence was found in well 21S. The top of the bitumen zone in 23S and 26S is at 4301 and 4344 m TVDSS respectively. In well 20X, while solid reservoir bitumen can be visually identified from 4469 m TVDSS, chemical data suggest that minor bitumen exists in the entire Lower Sandstone. Similarly, while cores # 4,5 & 6 (4282 - 4291 m TVDSS) in well 21S are bitumen free, cores # 7, 8 & 9 (4359 - 4379 m TVDSS) are bitumen bearing. Thus the 4291 - 4359 m zone could contain some bitumen. Based on well 26S data, the top of the bitumen zone in wells 20X and 21S can be extrapolated to about 4344 m TVDSS (Figure 13). Clearly, the Upper Sandstone is bitumen free in all the wells, but the Lower Sandstone is significantly affected; the entire Lower Sandstone section in wells 20X and 26S is within the bitumen zone, while the bottom halves in wells 21S and 23S are in the bitumen zone. Solid reservoir bitumen development has a detrimental effect on the general productivity of a field (porosity loss, drastic reduction in permeability, narrowing of pore throats, inhibiting of oil mobility etc., Bharati, 1997b; Lomando, 1992). This is the reason why we get such low flow rates (322 and 500 STBOPD) in wells 26S (DST #1) and 21S (DST # 1), rather than these sections being in the water zone. This observation strengthens (and explains) the hypothesis that the OWC in trap LS2 may actually be deeper than the rest of the field. Detailed description on the occurrence, composition and implications of solid reservoir bitumen of the Embla Field is covered elsewhere (Bharati, 1997a,b).

4.10 Summary and Conclusions

The Embla Field, comprising of three reservoir units (Uppermost, Upper and Lower Sandstones) separated by a thick mudstone unit, contains two different oil populations (type A & B), differing slightly in composition and maturity. While both oil types are of base oil-window to condensate window maturity and more mature than any of the chalk reservoired Greater Ekofisk oils, minor internal maturity trends are evident within Embla. This is based more on the aromatic

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 79 hydrocarbon based maturity ratios than on biomarker based ratios, as the latter are. considered less reliable Embla due to high maturity of the oils. However, both oil populations have been gene­ rated by the ‘abnormal ’ Upper Jurassic organic facies, characterized by isotopically heavier n- alkanes and in particular, anomalous enrichment of isotopically very heavy isoprenoids. The two oil charges are believed to have been from the west and/or north-west, where the kitchen for the Embla oils is estimated to lie. Minimal or no mixing of the two oil charges has taken place in the Embla reservoirs, suggesting that the individual traps have been well isolated prior to and since oil emplacement Generation and migration of Embla oils from the east (of Skrabbe Fault) or locally occurring Upper Jurassic units is thought to be unlikely.

The data from the present study indicate that the Embla Field is highly compartmentalized and the individual fault blocks are not in communication. The fact that during the last five years of production from Embla no pressure communication was observed supports this finding. Perhaps this is also the reason why the oil-water contacts (OWC) occur at different depths in different traps, the difference being to the extent of about 200 m. The OWC is found to be shallowest (estimated ‘oil down to ’ 4325 m TVDSS) in trap LSI and deepest (+4548 m TVDSS) in trap LS2; in trap UM2 it is estimated to be in between (>4400 m TVDSS). The deep OWC in LS2 has serious implications with respect to future exploration and opens up the possibility of more oil occurring NW and SE of well 26S, provided the sand body with good reservoir properties extends in these directions.

Residual solid reservoir bitumen occurrence is quite independent of the OWC and so also the base of the bitumen-free zone is continuous across Embla. Although solid bitumen is easily recognizable in several wells and samples, only chemical evidence exists in some cases. The permanent reservoir damage caused by bitumen (significant reduction in porosity, permeability and net reservoiring capacity) is thought to be the main cause of low flow rates recorded during some of the Lower Sandstone DSTs.

4.11 Acknowledgments

SB thanks Norwegian Research Council, Phillips Petroleum Co. Norway and Amoco Norway for part financial assistance. The staff of Geolab Nor is thanked for assistance in geochemical analyses and the Department of Geology, Norwegian University of Science and Technology, Trondheim for logistics and encouragement Co mments made by Richard Patience, Statoil and Chip Feazel, Phillips Petroleum on earlier drafts improved the quality of this manuscript The authors acknowledge the following for permission to publish the paper Phillips Petroleum Co. Norway and co-venturers, including Fina Exploration Norway S.CA., Norsk Agip AS, Elf Petroleum Norge AS, Norsk Hydro Production AS, Statoil AS, TOTAL Norge AS and Saga Petroleum AS. The authors further acknowledge that the interpretations and conclusions presented herein do not necessarily reflect the opinions of the co-venturers.

Norwegian University of Science and Technology 80 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

4.12 References

Bharati, S., 1997a, Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf - 1: Occurrence, development and morphotypes: AAPG Bulletin, (under submission).

Bharati, S., 1997b, Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf - 2: Chemistry, structure and origin: AAPG Bulletin, (under submission).

Bharati, S., Hall, P. B., Vagle, K. and Bjor0y, M., 1997a, Geochemical evaluation of the Embla Field, Norwegian Continental Shelf- 1: Occurrence and compositional variations of migrated hydrocarbons: Marine and Petroleum Geology, (under submission).

Bharati, S., Hall, P. B. and Bjor0y, M., 1997b, Identifying diverse oil families in the Greater Ekofisk area, Central Graben, Norwegian Continental Shelf: Marine and Petroleum Geology, (under submission).

Bjor0y, M., Hall, K., Hall, P. B., Leplat, P. and L0berg, R., 1991, Biomarker analysis of oils and source rocks using a thermal extraction-GC-MS: Chemical Geology, v. 93, p. 1-11.

Bjor0y, M., Hall, K. and Jameau, J., 1990, Stable carbon isotope ratio analysis on single comp ­ ounds in crude oils by direct GC-isotope analysis: Trends in Analytical Chemistry, v. 9, p. 331- 337.

Bjor0y, M., Hall, K. and Hall, P. B., 1992, Detailed hydrocarbon analyzer for well site and laboratory use: Marine and Petroleum Geology, v. 9, p. 648-665.

Bjor0y, M., Hall, K. and Moe, R. P., 1994, Stable carbon isotope variation of n-alkanes in Central Graben oils, Organic Geochemistry, v. 22, p. 355-381.

Cayley, G. T., 1987, Hydrocarbon migration in the central North Sea, in J. Brooks and K. Glennie, eds., Petroleum geology of north-west Europe, Graham & Trotman, London, p. 549- 555.

Cooper, B. S. and Barnard, P. C., 1984, Source rocks and oils of the Central and Northern North Sea, in G. Demaisson and R. J. Murris, eds., Petroleum Geochemistry and Basin Evaluation, AAPG Memoirs 35, AAPG, Tulsa, p. 303-314.

England, W. A. and Mackenzie, A. S., 1989, Geochemistry of petroleum reservoirs: Geologische Rundschau, v. 78, p. 291-303.

England, W. A., Mackenzie, A. S., Mann, D. M. and Quigley, T. M., 1987, The movement and entrapment of petroleum in the subsurface: Journal of Geological Society, v. 144, p. 327-347.

Forsberg, A., Gowers, M. B. and Holtar, E., 1993, Multi-disciplinary stratigraphic analysis of the Upper Jurassic strata of the Norwegian Central Trough, in A. M. Spencer, ed., Generation, accumulation and production of Europe ’s hydrocarbons HI: Springer-Verlag, Berlin, p. 45-58.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 3: Embla Geochemistry: Source, infilling, and intra-reservoir communication 81

Freeman, K. H„ Hayes, J. M., Trendel, J. M. and Albrecht, P., 1990, Evidence from carbon isotope measurements for diverse origins of sedimentary hydrocarbons: Nature, v. 343, p. 254- 256.

Hall, P. B., Schou, L. and Bjor0y, M., 1985, Aromatic hydrocarbon variations in North Sea wells, in B. M. Thomas, ed., Petroleum Geochemistry in Exploration of the Norwegian Shelf: Graham & Trotman, London, p. 293-301.

Hall, P. B., Stoddart, D., Bjor0y, M., Barter, S. R. and Brasher, J. E., 1994, Detection of petroleum heterogeneity in Eldfisk and satellite fields using thermal extraction, pyrolysis-GC, GC-MS and isotope techniques: Organic Geochemistry, v. 22, p. 383-402.

Horstad, I., Barter, S. R., Dypvik, H., Aagaard, P., Bj0mvik, A. M., Johansen, P. E. and Ericksen, S., 1990, Degradation and maturity controls on oil field petroleum column heterogeneity in the Gulfaks field, Norwegian North Sea: Organic Geochemistry, v. 16, p. 497-510.

Kaufman, R. L., Ahmed, A. S. and Elsinger, R. J., 1990, Gas chromatography as a development and production tool for fingerprinting oils from individual reservoirs; applications in the Gulf of Mexico: PR 8824, in Proceedings of Gulf Coast Section of the Society of Economic Paleontolo­ gists and Mineralogists Foundation 9 th Annual Research Conference, p. 263-282.

Knight, I. A., Allen, L. R„ Copiel, J., Jacobs, L. and Scanlan, M. J., 1993, The Embla Field: , in J. R. Parker, ed., Petroleum Geology of Northwest Europe: The Geological Society, London, p. 1433-1444.

Kvaldheim, O. M., Christy, A. A., Telnaes, N. and Bjorseth, A., 1987, Maturity determination of organic matter in coals using the methyl-phenanthrene distribution: Geochimica et Cosmo- chimica Acta, v. 51, p. 1883-1888.

Barter, S. R., Bj0rlykke, K. O., Karlsen, D. A., Nedkvitne, T., Eglington, T., Johansen, P. E., Leythaeuser, D„ Mason, P. C., Mitchell, A. W. and Newcombe, G. A., 1991, Determination of petroleum accumulation histories: examples from the Ula field, Central Graben, Norwegian North Sea, in A. T. Buller, E. Berg, O. Hjelmeland, J. Kleppe, O. Torsaeter and J. O. Aasen, eds., North Sea oil & gas reservoirs, Graham & Trotman , London, p. 319-330.

Lomando, A. J., 1992, The influence of solid reservoir bitumen on reservoir quality: AAPG Bulletin, v. 76, p. 1137-1152.

Mason, P. C., Burwood, R. and Mycke, B., 1995, The reservoir geochemistry and petroleum charging histories of Paleogene-reservoired fields in the Outer Witch Ground Graben, in J. M. Cubitt and W. A. England, eds., The geochemistry of reservoirs: Geological Society Special Publication 86, p. 281-301.

Moldowan, J. M., Fago, F. J., Carlson, R. M. K., Schoell, M., Young, D. C., van Duyne, G., Cardy, J., Pillinger, C. T. and Watt, D. S., 1991, Rearranged hopanes in sediments and petroleum: Geochimica et Cosmochimica Acta, v. 55, p. 3333-3353.

Norwegian University of Science and Technology 82 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Northam, M. A., 1985, Correlation of northern North Sea oils: the different facies of their Jurassic source, in B. M. Thomas et al., eds., Petroleum Geochemistry in exploration of the Norwegian Shelf: Graham & Trotman, London, p. 93-99.

Norwegian Industry Guide to Organic Geochemical Analyses, 1993, Joint report by Statoil, Norsk Hydro, Saga Petroleum, IKU, Geolab Nor and the Norwegian Petroleum Directorate.

Peters, K. E. and Moldovan, J. M., 1993, The Biomarker Guide; Interpreting molecular fossils in petroleum and ancient sediments: Pentice Hall, New Jersey.

Radke, M., 1988, Application of aromatic compounds as maturity indicators in source rocks and crude oils: Marine and Petroleum Geology, v. 5, p. 224-236.

Roberts, A. M., Price, J. D. and Olsen, T. S., 1990, Late Jurassic half graben control on the siting and structure of hydrocarbon accumulations: UK/Norwegian Central Graben, in R. F. P. Hardman and J. Brooks, eds., Tectonic events responsible for Britain’s oil and gas reserves, Geological Society Special Publication 55, London, p. 229-257.

Rovenskaya, A. S. and Nemchencko, N. N., 1992, Prediction of hydrocarbons in the west Siberian basin: Bulletin Centres Research- Exploration & Production, Elf Aquitaine, v. 16, p. 285-318.

Smalley, P. C., L0n0y, A. and Raheim, A., 1992, Spatial 87 Sr/86 Sr variations in formation water and calcite from the Ekofisk chalk oil field: Implications for reservoir connectivity and fluid composition: Applied Geochemistry, v. 3, p. 341-350.

Sofer, Z., 1988, Biomarkers and carbon isotopes of oils in the Jurassic Smackover Trend of the Gulf Coast States, USA: Organic Geochemistry, v. 12, p. 421-432.

Stoddart, D. P., Hall P. B., Larter, S. R., Brasher, J., Li, M. and Bjor0y, M., 1995, The reservoir geochemistry of the Eldfisk Field, Norwegian North Sea, in J. M. Cubitt and W. A. England, eds., The geochemistry of reservoirs: Geological Society Special Publication 86, p. 257-279.

Summo ns, R ,E. and Powell, T. G., 1987, Identification of aryl isoprenoids in source rocks and crude oils: Biological markers for the green sulphur bacteria: Geochimica Cosmochimica Acta, v. 51, p. 557-566.

Thompson, K. F. M., 1987, Gas-condensate migration and oil fractionation in deltaic systems: Marine and Petroleum Geology, v. 5, p. 237-246.

Waples, D. W. and Machihara, T., 1991, Biomarkers for - A practical guide to the application of steranes and triterpanes in petroleum geology: AAPG Methods in exploration nr. 9, pp 91.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 83

Chapter 5: Paper 4

Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf -1: Occurrence, development and morphotypes §

Sunil Bharati

Geolab Nor, N-7002 Trondheim, Norway

5.1 Abstract

Geochemical evaluation of the Embla Field, North Sea, revealed that solid reservoir bitumen is quite widespread in the reservoir pre-Jurassic sandstones, particularly in the lower half of the pay-zone. As solid reservoir bitumen, irrespective of the cause of its formation, has serious and often adverse implications with respect to reservoir quality and overall field productivity, a detailed study was undertaken of this immobile migrated hydrocarbon phase and is reported in two parts. Due to Embla bitumen’s widespread occurrence, its optical characterisation ranged from a centimeter to nanometer scale, using conventional stereo microscopy and scanning electron microscopy respectively. In addition to uneven distribution of solid bitumen in the Embla Field, its mode and frequency of occurrence seems to change with depth. Examination of a variety of sandstone samples (from cavities, fractures, veins, vugs etc.) shows that solid bitumen in Embla occurs in several forms and habitats, each with different surface and topographical features. Based on this, eight different morphotypes (massive, spheroidal, rosette, foliated, zygotic, vein, carpet and disseminated) are identified and described. In addition, bitumen’s occurrence is discussed in relation to all the major minerals observed in the inter-granular space.

5 Manuscript under submission to AAPG Bulletin

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h 84 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

5.2 Introduction

Solid bitumen, either pre-oil or post-oil, resulting from solidification of once liquid and mobile petroleum, has been observed in natural geological systems and reported almost since the mm of the century (White, 1899; Bailey, 1927). However, in earlier years, attention was mainly focused on surface or near surface deposits due to interests in mining bitumen. Later, on the advent of sub-surface oil exploration, solid bitumen was observed in both siliciclastic and carbonate reservoir rocks. Over the years, this essentially immobile petroleum phase has been described, in addition to solid bitumen, as migrabitumen, pyrobitumen, dead oil, , solid hydrocarbons etc. Because solid reservoir bitumen has several adverse effects on overall reservoir quality and producibility, it has of late inculcated added interest among explorationists. Several studies have been reported on its geochemical characteristics such as composition and maturity (Rogers et al., 1974; Hunt, 1978; Curiale, 1986), origin (Curiale, 1986; Sassen, 1988; George et al., 1994), microscopic properties (Rizer, 1987, Landis and Castano, 1994) and recently on its influence on overall reservoir quality (Dixon et al., 1989; George et al., 1994; Lomando, 1992). Despite this attention to reservoir solid bitumen and its implications on field productivity, our understanding of its origin, its accurate delineation in the field and its actual sub-surface behaviour remains limited. Lomando (1992) has observed that when present, reservoir bitumen can have as much control on reservoir quality as carbonate and silica cements or authigenic clays. An aspect that must be added to this is that if present, it represents a unique and specific geological event in the diagenetic history of the sedimentary sequence; and therefore it has potential as a link between regional oil generation/migration and local diagenetic history.

In this study, extensive solid reservoir bitumen in a deep pre-Jurassic sandstone reservoir in the Norwegian North Sea is examined. This is also apparently the first major solid reservoir bitumen occurrence reported in the region (the term ‘pyrobitumen ’ is deliberately not used in this article as it indicates heat-related phenomena and may be misleading). The study focuses on geochemical and optical assessment of residual solid reservoir bitumen found in the Embla Field, Norwegian Continental Shelf, and comprises two parts.

This paper describes the gross occurrence, development and different morphotypes of solid bitumen observed in the Embla reservoir, while the second paper (Bharati, 1997) addresses the chemical and structural aspects of this unique and immobile migrated hydrocarbon phase. In addition, the second paper discusses the various possible origins in light of the optical and chemical data obtained. The scale of observation in the study ranges from several centimeters (in hand specimens) to tens of nanometers (under SEM) and finally a few angstroms (under TEM).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 85

5.3 Geological background

This has been covered in detail elsewhere (Bharati et al, 1997a; Knight et al, 1993) but some aspects which are relevant in the present context are briefly covered here. The Embla Field, interpreted as occurring in a westward dipping Paleozoic horst (Knight et al., 1993), is located on the Grensen Nose in Block 2/7 southwest of the Eldfisk Field on the downthrown side of the Skrubbe Fault, a Late Jurassic normal fault which was reactivated as an inverted fault during Late Cretaceous (Figure 1). It is a NW-SE oriented field of about 19.4 km2 at base Cretaceous. The pre-Cretaceous stratigraphy varies significantly between wells in the Embla Field. The basement rhyolitic unit, possibly of Early Devonian age, is overlain by Upper Devonian mud­ stones, upon which rests the reservoir section.

Figure I: Location Map showing Block 2/7 in the Norwegian Continental Shelf (NOCS) and enlargement of the Embla Field showing the locations of the wells included in this study.

The reservoir section comprises three major pre-Jurassic sandstone intervals, the Uppermost, Upper and Lower Sandstones (Figure 2), of braided fluvial and alluvial fan origin, separated by

Norwegian University of Science and Technology 86 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea an intervening mndstone/siltstone sequence deposited in a floodplain/ lacustrine setting. The age of the reservoir remains unknown as the sequence is barren of microfossils, but the current interpretation based on radiometric dating favours Early Permian, Carboniferous and/or late Devonian (Knight et al., 1992). The Upper Jurassic Tyne Gp. unconformably overlies the Embla reservoir and only a very thin Mandal Fm. mudstone is present high on the structure.

For simplicity, the Embla reservoir (shown as a cross-section in Figure 2) has been divided into 7 sub-traps - two in the Uppermost Sandstone (namely UM1 and UM2), two in the Upper Sandstone (namely US1 and US2) and three in the Lower Sandstone (namely LSI, LS2 and LS3, schematically shown as an inset in Figure 3), with the two sandstones being separated by a thick mudstone section. Another major consideration in horizontally defining these sub-traps is the presence of faults within the Embla structure (Figure 1).

-[Uppermost]

I Uppermost!

0ST#1 {_ DSTJM

ti 1 -

Figure 2: Generalized cross-section (roughly NW-SE) of the Embla Field below the base Cretaceous unconformity (solid bars = cored intervals, open bars = DST intervals; distances between the wells are at sub-sea level). Interpreted oil-water contacts (OWC) and base of bitumen-free zone are also indicated.

The total net thickness of the reservoir section varies from more than 317 min 2/7-23S to only about 98 min 2/7-21S. The Uppermost Sandstone is very well developed in wells 23S/27S and 20X (317 and 173 m respectively), but absent in the other wells. The Upper Sandstone is 146 m

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 87

in well 26S, but due to erosional truncation only 21 m in well 21S and absent in the others. The Lower Sandstone is well developed in 3 wells and varies from 113 min well 26S to 65 min well 20X in the center of the dome. Wells 20X, 21S and 26S were drilled through the base of the Lower Sandstone, while wells 23S/27S were terminated within the Uppermost Sandstone (Figure 3). Present day reservoir temperature is 160°C and initial pressure recorded was 841 bar. The reservoir is considered to be under-saturated with oil (API 42°) and variable GOR (329 Sm3/Sm3, 1900 Scf/stb in the eastern block and 276 Sm3/Sm3 (1550 Scf/stb) in the western block).

The reservoir section is intensely faulted (Figure 1) potentially causing compartmentalisation, a feature which was suspected on evaluating the RFT and DST data and established later by geochemical assessment (Bharati et al., 1997b). Due to the known geological complexities, extensive coring was conducted which provided a good database for detailed geochemical assessment In addition to periodic invasions of hydrothermal fluids into the reservoir causing repeated periods of porosity loss and enhancement (Knight et al., 1992), signifi cant solid reservoir bitumen formed in the Lower Sand. The present study includes core samples from five exploration wells (NOCS 2/7-20X, -21S, -23S, -26S and -27S, Figure 2) which have penetrated the reservoir units. Host rocks and isolated solid bitumen samples (chips and polished thin sections) were examined by naked eye, stereo microscope, petrographical microscope and scanning electron microscope (SEM).

5.4 Reservoir bitumen : the less understood phase

Solid bitumens have been classified as ‘pre-oil ’ or ‘post-oil ’ by Curiale (1986) depending on the thermal maturity of the source rock and indirectly, the solid bitumen’s proximity to its source rock. He has argued that such a differentiation overrides earlier classical generic schemes (e.g. Hunt et al., 1954; Meyer and de Witt, 1990) because it takes into account the thermal state of the source rock and migration distance of the expelled oil. While this approach is logical for petroliferous basins and provides a way to differentiate from ‘bitumens’ associated with metal ore deposits (Parnell et al, 1993 and references therein), we still need to appreciate and incorporate the related processes (of origin) in our usage.

In the petroleum exploration context, solid reservoir bitumen can therefore be best defined as ‘essentially immobile migrated petroleum which solidified from an originally mobile and free- flowing oil-phase due to one or more post-emplacement alteration processes ’. As mentioned earlier, the solid reservoir bitumen phase has been described in several ways over the past few years, such as migrabitumen, pyrobitumen, dead oil, asphalt, solid hydrocarbons etc. However, the emphasis on the term ‘solid ’ and the process of ‘solidification ’ must also be made, as it will allow us to distinguish it from the commonly employed phrase - reservoir bitumen, a term used for the fraction obtained on solvent extraction. In addition, its inherent property of being ‘totally immobile ’ and fixed is of prime importance. In my opinion, it will be useful not to use the term ‘pyrobitumen ’ for any solid reservoir bitumen observed, unless it is established that

Norwegian University of Science and Technology 88 Mobile and. immobile migrated hydrocarbons in the Embla Field, North Sea heat, in one form or the other, played a vital role in its formation. For example, it would be meaningless to term a solid reservoir bitumen known to have formed due to biodegradation followed by devolatilization as pyrobitumen. Curiale (1986) has also rightly pointed out that since the advent of modem geochemical methods, our attention today is not only on the origin of such materials, but also on their role and effects on petroliferous basins. While underlining the severity of the effects of solid reservoir bitumen formation, Lomando (1992) observed that the impact includes filling pores (reducing effective porosity), restricting pore throats (reducing permeability) and changing wettability.

Keeping all these factors in mind, a simple term such as ‘oil cement’ or ‘cemented oil ’ would suffice, in line with commonly used terminologies, namely quartz cement or carbonate cement. The various forms of oil cements could be envisaged as biodegraded oil cement or irradiated oil cement etc., which would throw light on their origin. By proposing the term oil cement, it is not intended to add yet another synonym, but to streamline its usage. Of course, the above is applicable (and intended) only for systems (Curiale’s (1986) post-oil category).

5.5 Occurrence and types of Bitumen in the Embla Field

While reservoir bitumen is rare in the Uppermost and Upper Sandstones, extensive bitumen is seen in the Lower Sandstone of the Embla Field. Based on extensive geochemical analyses of core samples, Bharati et al. (1997b) established the exact depth at which bitumen occurs in three of the five wells, namely 23S/27S (4301 m TVDSS) and 26S (4344 m TVDSS). An estimate (4344 m TVDSS) was made in wells 20X and 21S based on partial evidence (above 4372 m TVDSS in 20X and between 4291 - 4359 m TVDSS in 21S) and neighbouring well core data. The base of bitumen-free zone was established by a combination of visual examination of cored sections and chemical composition of pyrolysates (PY-GC). Apparently, the base of the bitumen free zone is not continuous across the field (Figure 2) and is inde­ pendent of the oil-water contact (Bharati et al., 1997b). Well 26S is the only well where solid bitumen occurs in the Upper Sandstone.

Figure 3: (following page) Examples of the various modes of occurrences of the solid reservoir bitumen, seen in core hand specimens from the Embla Field, Cavity bitumen, as seen a) in a cross-section, b) along a fracture and c) with extensive barite (arrow) association, d) Carpet bitumen, e) Disseminated bitumen (from well 23S).f) Fracture bitumen (arrow), g) Vein bitumen, h) sample split along the vein, i) Another example of a fracture bitumen, j) Vug bitumen. Scale bar = 2 cm.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 89

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m. 90 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Another important feature of the Embla solid reservoir bitumen is that, from the depth when the bitumen is first observed, it increases in abundance, distribution frequency and net volume with increasing depth. There are indications that even the mode of occurrence changes from disseminated at shallower depths to large vugs, cavities and fractures filled with solid bitumen deeper in the field.

Examination of Embla core (hand) samples from the different wells shows that bitumen occurs in a variety of forms (Figure 3). Based on this, the Embla solid bitumens are classified and the assigned names are based on the modes of occurrences.

5.5.1 Cavity bitumen

This is most easily noticed (due to its sheer dimensions), quite abundant and generally occurs in the deeper parts of the field. It is seen only in the coarse-moderate grain sandstones of wells 20X, 21S and 26S (most extensive in 26S) as filled, solid, black and vitreous bitumen mass, in cavities ranging 2-3 mm to up to 5 cm across (Figure 3a). The cavities, especially large cavities, are random-shaped and angular with sharp boundaries and comers, suggesting that these were formed early, but post-compaction and possibly a result of tectonic activity. Criss­ crossing bitumen healed fractures starting from and ending in the bitumen-filled cavities are abundant and a co mmon feature and are believed to have served as ‘feeders’ to the cavity. Splitting a sample along a fracture and across a cavity reveals that most of the fracture plane is lined by a thin sheet of bitumen, while the ‘cavity bitumen’ occurs as a solid mass (Figure 3b). Except for very few exceptions, cavity bitumens are invariably associated with barite (Figures 3a and c).

In polished thin-sections, black and opaque bitumen exhibiting no special optical properties is easily recognizable. Cavity bitumens in particular, show distinctive contraction fractures (Figure 4a), which pinch out at the ends and are believed to be formed by reduction in volume of the original petroleum phase (removal of lighter components and gas) during solidification. Some of these contraction fractures are healed by barite (Figure 4c), the latter exhibiting distinctive extinction under stage rotation. The contact between the bitumen and barite is sharp.

5.5.2 Vein bitumen

This type is less abundant (perhaps due to difficulty in detection), nevertheless it is observed in all wells. Veins up to 34 cm in length and 2 mm in width were observed in cores (part of a vein shown in Figure 3g), which pinch out at one end and continue out of the core at the other. By and large, bitumen healed veins are isolated entities with limited or no inter-connection, although a single vein dividing into two veins was observed. On splitting the sandstone along a vein (Figure 3h) to expose the bitumen phase, it is apparent that the rock wall(s) is(are) lined by black and vitreous bitumen, with which barite is commonly associated (white spots in

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 91

Figure 4: Different modes of bitumen (Bi) occurrences in polished thin sections, seen as a black phase, a) Cavity bitumen, b) Vein bitumen, c) Cavity bitumen associated with barite (Ba), d) Fracture bitumen (arrow), e) Disseminated bitumen and j) Carpet bitumen (thick white arrows). Ep = epoxy, Ka - kaolinite and Qd = detrital quartz grain. Scale bar in (e) is 100 p, all others 500 p..

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■P, '.'fv 92 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Figure 3h). In thin sections, vein bitumen clearly differs from cavity bitumen in that the latter has sharp contacts with the host rock and gives a ‘river-like’ appearance (Figure 4b). The barite phase essentially occurs in contraction fractures of bitumen, but more importantly it does not continue into the host rock.

5.5.3 Fracture bitumen

This type is more commonly seen in highly brecciated sandstone sections (Figures 3i and f), but also in other sections which are fractured less extensively. Except for the visible black colour, it has no other distinctive appearance in hand specimens and is readily recognizable as randomly oriented, criss-crossing and inter-connected healed fractures in thin sections (Figure 4d). The width of bitumen-healed fractures rarely exceeds about 200 (X.

5.5.4 Disseminated bitumen

This type is restricted to the upper part of the bitumen zone of Embla (cf. Figure 2) and is most extensive in well 23S. It is not recognizable as a distinct phase in hand specimens, except for blackish colouration of the inter-granular material, as seen in the conglomeratic sandstone of well 23S (Figure 3e). Even at high magnification in thin section, the bitumen phase is not recognizable (Figure 4e), except for dense dark brown to black material in the pore space, the latter feature being totally absent in bitumen-free zone samples.

5.5.5 Carpet bitumen

This is more rare and randomly seen in all sections of the wells, but is essentially restricted to fine-grained, but not necessarily low porosity, sandstone facies. It occurs as a thin sheet of tiny black particles along certain planes of weakness (micro-fractures?) and gives a powdery appearance in hand-specimens (Figure 3d). In thin sections, it differs from dissipated bitumen in that larger (generally up to about 100 p.) and relatively easily distinguishable black bitumen- rich areas are seen (Figure 4f).

5.5.6 Vug bitumen

This is most rare, possibly restricted to fine grained sandstone facies and occurs as wall lining in open vugs. It differs from cavity bitumen in that unlike cavity bitumen, which completely fills all available cavity volume, in the case of vug bitumen, a significant portion of the vug volume (towards the center) remains open (Figure 3j). In addition, the shape of vugs is very different to cavities described above, in that the former are rounded and elongated in cross section, pointing more towards being solution vugs rather than caused by tectonic activity.

Clearly, solid reservoir bitumen in the Embla Field occurs in a variety of modes, each habitat differing from the other with respect to overall shape, volume, size, frequency, depth of occur ­ rence and host rock characteristics, the last factor perhaps of greater importance than is

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 93

Figure 5: Morphotypes of Embla solid reservoir bitumens: Massive a) type ‘A’, b) type ‘B’,c) type ‘C\ d) Spheroidal and e) Rosette (details of the bottom flat and circular part is shown in (f)from a different angle).

Norwegian University of Science and Technology 94 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea apparent. With so many variables determining the resulting bitumen types described above, it is likely that there may even be other factors unique to each type than simply differing physical forms on a macro scale, such as chemical properties, internal structure, origin, cause of emplacement and even micro-scale physical differences. The micro-scale physical characteristics are examined in this paper. The other factors are covered in the second part of this work (Bharati, 1997).

Scanning electron microscopy (SEM) is a useful tool to study the topographical features and elemental composition of mineral phases in geological samples (e.g. Pye and Krinsley, 1984; Trewin, 1988) and it has also been used successfully in the past to characterize the carbon-rich organic phase in sedimentary rocks, mostly kerogens and coals (e.g. Belin, 1992; Bishop et al., 1992) but also solid bitumen (e.g. Lomando, 1992; George et al., 1994).

In the case of Embla samples, in addition to polished thin sections, whole rock chips (pre­ washed with dichloromethane : , 93:7 vol/vol) and untreated, randomly mounted solid bitumen particles were studied using SEM (JEOL JXA-8900M for microprobe analysis and elemental mapping; JEOL JSM-840 for topographical studies). Solid bitumen particles from all possible modes of occurrence (cavity, vug, fracture and vein) were physically removed from core samples to examine differences, if any. Solid bitumen was easily identified by microprobe analysis equipped with a light element detector, as this organic phase contains (in addition to relatively insignificant quantities of hydrogen, nitrogen, sulphur and oxygen) only carbon from the SEM point of view.

5.6 Morphotypes of Embla bitumen

Some workers have tried to classify and name various bitumens based on features seen under SEM. For example, based on topographical features, Lomando (1992) described six different morphotypes of solid bitumen, namely droplet, carpet, peanut brittle (Jurassic Smackover Formation), vesicular (Cretaceous sandstones of West Africa), digitate (Devonian, Western Alberta) and pore cast. George et al. (1994), on the other hand, have classified their bitumen suite from McArthur Basin (northern Australia) into five ‘types ’ (I - V) based on the mode of occurrence. In the present investigation, I have attempted to take into account both criteria, i.e., mode of occurrence as well as topographical features. Apparently, distinct differences are present in the topographical features of bitumens from different modes (Figures 5 and 6). These are classified and named based on their appearance, and described in detail below.

5.6.1 Massive bitumen

This (Figure 5a-c) is found mostly in cavities, but also to a much lesser extent in the rock mass where a (bitumen filled) cavity is not equally obvious. It is characterized by distinct conchoidal fractures which in some cases are very strong (massive type ‘A’, Figure 5a), in

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 95

Figure 6: Morphotypes of Embla solid reservoir bitumens (contd.): Foliated a) type ‘A’ with planar folia, b) type ‘B’ with non-planar folia, c) Zygotic, d) Zygotic- transitional, e) vein and f) Carpet.

Norwegian University of Science and Technology 96 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea others moderate (massive type ‘B\ Figure 5b) or weak (massive type ‘C\ Figure 5c). It is possible that the bitumen surface (failure surface) seen in these figures is actually along the contraction fractures seen in thin sections. In between the ‘ridges ’ caused by conchoidal fracturing, the surface is smooth and unstructured.

5.6.2 Spheroidal bitumen

This (Figure 5d) is also found in cavities and vugs and is characterized by a distinct spherical / globular shape. It is however possible that this too is essentially a massive type, but with very strong and peculiar conchoidal fractures which result in a spherical shape when physical stress is applied (such as the one caused by breaking).

5.6.3 Rosette bitumen

This type (Figure 5e), found in vugs, resembles in some manner spheroidal bitumen, but differs by its ‘flowery ’ shape. More importantly, one side of the bitumen particle (probably the bottom) is different to the remaining body, in that it is flat, and an outward radial pattern is seen. Examining this face in detail (Figure 5f) shows that radiating from almost a perfect circular and flat area, which could be the point of attachment to the host rock, the bitumen particle extends outwards in all directions. It is thus likely that the top surface seen in Figure 5e is the outermost limit of bitumen lining the vug wall.

5.6.4 Foliated bitumen

This type, found in small cavities, fractures and possibly veins, is very different from massive bitumen in that the foliated bitumen does not exhibit any conchoidal fractures, although it is massive in nature. The unique property of foliated bitumen is that it consists of a cluster of parallel folia, either planar in nature (foliated type ‘A’, Figure 6a) or non-planar (foliated type ‘B’, Figure 6b). Several transitions between types A and B are expected to be present, but were not observed.

5.6.5 Zygotic bitumen

This type (Figure 6c), found in rock matrix, perhaps in small (< 1 mm) cavities has a characteristic ‘basket of eggs ’ appearance with similar sized and ellipsoidal bitumen bodies clustered in an outer bitumen shell. This feature in some cases is only seen moderately (Figure 6d), but at the same time it appears that this may be related to foliated type ‘B’ bitumen. Comparing the shapes of the foliated type ‘B’ bitumen and zygotic bitumen shell (figures 6c and d respectively), it seems possible that the foliated bitumen core consists of ‘zygotic ’ bitumen bodies.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 97

Figure 7: General view of cavity, disseminated and carpet bitumens in thin sections as seen using SEM. a) cavity bitumen at 100X, c) disseminated bitumen at 100X and e) carpet bitumen. Areas marked in a, c and e are enlarged in b, d and f respectively and were used for elemental mapping.

Norwegian University of Science and Technology 98 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

5.6.6 Vein bitumen

This type (Figure 6e), exhibits a very different outer surface than any of the previously described morphotypes. The top outer surface observed, in all probability, is the negative mould of the rock surface, rather than a freshly broken surface of bitumen as was the case of massive bitumens described above. The general shape (rounded in one direction and elongated in the other) is indicative of the limited space available (except along the long axis of the vein) for bitumen emplacement, unlike cavities and vugs. ‘Mud cracks’ like contraction fractures in the bitumen phase are clearly visible (note the continuous contraction fracture along the spine of the vein).

5.6.7 Carpet bitumen

This (Figure 6f) is typical of relatively fine-grained sandstones facies without any major cavities and vugs, and is difficult to locate; perhaps it is rare too. Unlike the types described above, this morphotype occurs as a thin sheet (estimated thickness <10 |i) over the rock matrix. As seen in Figure 6f, a carpet of fine grained bitumen (in the upper half) covers books of kaolinite which are exposed in the lower half of the photo.

5.6.8 Disseminated bitumen

This was most difficult to identify using the standard topographic or elemental analysis set up. Samples suspected of containing disseminated bitumen (especially in well 23S as shown in Figure 3e) failed to give any strong carbon signal for any identifiable particles in the pore space, despite a weak but consistent carbon signal in the background. It seemed therefore that the bitumen present in these samples (which was suspected from the pyrolysate compositions, Bharati et al., 1997b; see also part 2 of this work, Bharati, 1997), must be particulate and dispersed all over the pore space. Detailed and careful elemental mapping of an inter-granular (detrital quartz) area was therefore performed using thin sections to establish whether any carbon was present (and where). However, to test whether the technique would work, a known cavity bitumen was mapped first for 8 elements aimed specifically at identifying all the major mineral phases: C - for bitumen, Si - for quartz and kaolinite, Al - for kaolinite, Ba - for barite, S - for barite and pyrite, Fe - for pyrite, Ca - for carbonates and K - for feldspars. These mapped areas (a and b - cavity, c and d - dissipated and e and f carpet bitumen) are shown in

Figure 8: (following page) False colour images of elemental mapping for carbon (C), silicon (Si), aluminium (Al), barium (Ba), sulphur (S), iron (Fe), calcium (Ca) and potassium (K) of an area containing cavity bitumen (cf. Figure 7b). Bottom colour bars indicate the signal intensity for each element. The bottom right image is a composite indicating the main phases, namely bitumen (Bi, black), detrital quartz (Qd, green), barite (Ba, white) and kaolinite (Ka, red/yellow).

Doctoral Dissertation by Stmil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 99

Norwegian University of Science and Technology 100 Mobile and immobile migrated hydrocarbons in the Etnbla Field, North Sea

Figure 7, the general area with several detrital quartz grains and inter-granular pore space in small magnification and the details of the mapped pore space in large magnification. As seen in the elemental maps of the cavity bitumen (Figure 8), areas occupied by bitumen, quartz, kaolinite and barite are successfully detected and mapped in the test area containing cavity bitumen. False colours are automatically assigned depending on the signal intensities (white strongest and black weakest), although the absolute values of each element’s scale vary. Later, without changing the calibration, particularly from the point of view of detecting carbon, a new area was mapped (Figure 7d), suspected to contain disseminated bitumen.

The inter-granular space between the three quartz detrital grains (measuring roughly 300x200 p.) evidently contains a significant area enriched in carbon, occurring with equal frequency in the entire inter-granular space (Figure 9). Interestingly, the areas rich in carbon do not contain kaolinite, suggesting that most of the disseminated bitumen is dispersed between the books of kaolinite. No barite or pyrite is present in this mapped area. Similar elemental mapping was also performed successfully in a sample containing carpet bitumen (cf. Figures 7e-f) to confirm the presence of carbon.

Microprobe analysis of the other bitumen types did not give any information other than that all types consist of carbon; hence from the elemental composition (as detected by SEM) point of view, all morphotypes are alike. Consequently, the various morphotypes seen in the Embla Field, may actually be attributes of the shape, volume and size of the pore space that the petroleum phase occupied before solidification. However, this does not explain why for instance, conchoidal fractures are so strongly seen in some and foliation in others or why some morphotypes contain ellipsoidal bitumen bodies in the core and others don ’t (differing stress fields during solidification?). Clearly, other factors played an influential role during solid bitumen formation. Defining areas in the field and zones down the wells which may be rich in a given bitumen morphotype is thought to be useful, but was not possible in the present study due to limited sample control and cost constraints.

5.7 Minerals in inter-granular space

It is clear from the evidence presented that solid bitumen is an important and major phase in the inter-granular space of the Embla reservoir sandstones. However, in order to understand the possible reasons for bitumen development and emplacement in the Embla Field, it is

Figure 9: (following page ) False colour images of elemental mapping for carbon (C), silicon (Si), aluminium (Al), barium (Ba), sulphur (S), iron (Fe), calcium (Ca) and potassium (K) of an area containing disseminated bitumen (cf. Figure 7d). Bottom colour bars indicate the signal intensity for each element. The bottom right image is a composite indicating the main phases, namely bitumen (black/dark blue), detrital quartz (Qd, red) and kaolinite (Ka, yellow).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 101

Norwegian University of Science and Technology 102 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

imperative to characterize the nature of the entire inter-granular space and not just the carbon phase in it. This includes minerals, cement and present-day porosity. XRD analyses have shown that the Embla reservoir sandstones contain, in addition to quartz (50-70%), kaolinite as the dominant clay mineral (up to 35%) and illite only in trace amounts despite the depth of the reservoir (4 km +; Bharati et al., 1997a). In addition, no feldspar is present and siderite, pyrite and anhydrite are present in trace amounts; ankerite/dolomite is mostly absent, but in some samples from the Lower Sandstone, it is as high as 40% (Bharati et al., 1997a). In the following section, the nature of inter-granular space is examined using SEM, in light of these findings.

5.7.1 Clay minerals

Kaolinite, as XRD analysis indicates (Bharati et al., 1997a), is very widespread and the only authigenic clay mineral readily observed in all samples. It occurs as well developed pseudo- hexagonal plates in curved vermicular stacks (Figure 10a). The hexagonal plates are only partially etched, indicating that kaolinite has remained fresh and generally unaltered. In some relatively fine-grained and tight sandstones however, which are rich in bitumen-healed fractures and veins, the kaolinite phase seems to be closely associated only with the bitumen phase as large clusters and not with the remaining host rock, which seems nearly barren of kaolinite (Figure 10b). This is intriguing from the point of view of diagenesis of the host rock and its subsequent porosity preservation. Illite, which greatly reduces the permeability of a sandstone, is very rare and difficult to find in the samples. However, some examples of ran­ domly oriented and intertwined wiry/fibrous illite were observed (Figure 10c) which indicate only partial (and early stage) illitization. Smectite is the rarest form in the Embla sandstones and is only occasionally found as a thin mixed clay layer (Figure lOd). In any case, had smectite been present in the system as an early diagenetic product, it would have readily converted into illite during burial. Bjprlykke et al. (1992) have noted that the absence of early diagenetic smectite may indicate low silica content in the pore water due to low contents of amorphous silica or volcanic fragments. Near absence of illite in the Embla reservoir sandstones may also be indicative of early oil emplacement. This is discussed further in the second part of this paper (Bharati, 1997).

5.7.2 Authigenic/overgrowth quartz

This is a common feature in most samples and is considered as one of the major mineral phases in the pore-space. It occurs generally as intermediate, but occasionally in advanced stage of quartz overgrowth cementation (Figure lOe), filling a sig nificant portion of the total porosity. In some cases, quartz overgrowths are in contact with adjacent euhedral quartz overgrowths, showing how advanced the quartz cementation stage is.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 103

Figure 10: Mineral phases in the inter-granular space of sandstones as seen using SEM. a) Kaolinite in a rock chip, b) Kaolinite in thin section, closely associated with bitumen (black area), c) Illite, d) Smectite, e) Authigenic quartz andf) Ankerite/dolomite.

Norwegian University of Science and Technology

Jito v, 104 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

5.7.3 Ankerite/Dolomite

This is rare in most samples, but readily seen in others as euhedral rhombic crystals (Figure lOf). Bharati et al. (1997a) noted that while typically the overall ankerite/dolomite content is very low in most samples, some samples have anomalously high content (up to over 40%).

No other major mineral phases are apparently present in the pore-space. However, some mineral phases are almost exclusively associated with solid bitumen, such as:

5.7.4 Pyrite

In general, pyrite was detected only in trace amounts in the reservoir sandstones, but in samples which have obvious bitumen occurrences, it was relatively more abundant (Bharati et al., 1997a). SEM examination of thin sections show that pyrite invariably occurs within or in immediate vicinity of the bitumen phase (Figure 11a and b) and is most commonly observed associated with bitumen-healed fractures, veins and smaller cavities as circular masses (framboids?), typically 100-500 pm across. Interestingly, while pyrite is common and in some cases extensive in the bitumen phase, it is nearly absent or at best rare in the host rock. Numerous studies have been reported on organically bound sulphur in kerogens, asphaltenes and oils (Orr and Damste, 1990 and references therein) and although far fewer, even on elemental sulphur in crude oils, but none on the association of mineral pyrite with migrated hydrocarbons. This aspect is elaborated further in part 2 of this paper (Bharati, 1997).

5.7.5 Barite

As mentioned earlier, barite is commonly found within the bitumen phase, mostly filling bitumen’s contraction fractures. This form appears to be massive and interconnected (Figure 11c), similar to hydrothermal vein filling s. In addition, barite is also found as perfect orthorhombic prismatic crystals embedded in the bitumen mass (Figure lid). No association of the two barite forms was found. The fact that prismatic euhedral barite is found as inclusions in the bitumen mass indicates that the crystals were formed before bitumen solidification.

Other minor and rarely seen mineral phases such as halite (Figure lie, could be from sea water but could also be authigenic given the close proximity of Embla to salt diapirs) and an unknown mineral phase (occurring as a thin sheet over bitumen, Figure 1 If) was also seen. These, however, are not considered to have any bearing on the present study.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 105

Figure 11: Mineral phases exclusively associated with bitumen, a) Pyrite (Py), occurring here along a bitumen-healed vein (Bi), b) enlargement of the marked area in (a), c) Massive barite (Ba), occurring in bitumen cooling/contraction fractures, d) Crystalline barite, occurring embedded in the bitumen mass, e) Halite and f) An unknown mineral (seen rarely) occurring as a thin sheet over bitumen.

Norwegian University of Science and Technology 106 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

5.8 Summary and conclusions

The Embla Field reservoirs consist of pre-Jurassic sandstones, and has a significant solid bitumen development in its reservoir, particularly in the Lower Sandstone. However, bitumen is not found in the entire reservoir column. The top of the bitumen zone has been established in all five wells studied based on visual examination of cores and pyrolysate compositions. Apparently, the depth of bitumen occurrence is variable across the field and evidently the overall bitumen abundance increases with increasing depth. The bitumen occurs as a solid, black and vitreous phase in a variety of modes such as filled cavities, open vugs, veins, fractures, carpet and disseminated. Each habitat of occurrence is characterized by special and unique properties, which have become the basis of classifying the Embla bitumens into different morphotypes, namely 1) massive (consisting of types A, B & C), 2) spheroidal, 3) rosette, 4) foliated (types A & B), 5) zygotic, 6) vein, 7) carpet and 8) dissipated. Elemental mapping proved to be vital in recognizing dissipated bitumen. Microprobe analysis of the other bitumen morphotypes does not provide any additional useful information other than that all types primarily consist of carbon. It is therefore possible that the various morphotypes seen in the Embla Field, may actually be attributes of the shape, volume and size of the pore space that the petroleum phase occupied before solidification. However, this hypothesis cannot explain some of the vital differences observed between the morphotypes. It is therefore believed that there may be some other factors, yet unknown, that played an influential role during solid bitumen formation. This aspect, in addition to chemical composition, internal structure and timing of emplacement, is addressed in the second part of this work.

5.9 Acknowledgments

Many thanks to Phillips Petroleum Co. Norway for providing the samples and co-venturers, including Fina Exploration Norway S.C.A., Norsk Agip AS, Elf Petroleum Norge AS, Norsk Hydro Production AS, Statoil AS, TOTAL Norge AS and Saga Petroleum AS for permission to publish. Thanks also to the Norwegian Research Council (NFR), Phillips Petroleum and Amoco Norway for partial financial assistance. The Department of Geology, Norwegian University of Science and Technology, Trondheim is thanked for support and encouragement Help from Morten Raanes and Kjell Muller, SINTEF in operating the SEMs is acknowledged. The manuscript benefited greatly from comments made by Joe Curiale, Unocal, on an earlier draft Kare Vagle, Phillips, Norway is particularly thanked for taking constant interest and discussing my results, which has improved the quality of this work.

5.10 References

Bailey, E. M., 1927, The chemistry and technology of the oil shales, in Oil shales of Lothians: Memoirs of the Geological Survey, Scotland, p. 159-172.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 4: Embla reservoir bitumen: Occurrence, development and morphotypes 107

Belin, S., 1992, Application of backscattered electron imagin g to the study of source rock microtextures: Organic Geochemistry, v. 18, p. 333-346.

Bharati, S., 1997, Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf -2: Chemistry, structure and origin: AAPG Bulletin, (under submission).

Bharati, S., Hall, P. B., Vagle, K. and Bjor0y, M., 1997a, Geochemical evaluation of the Embla field, Norwegian Continental Shelf -1: Occurrence and compositional variations of migrated hydrocarbons: Marine and Petroleum Geology, (under submission).

Bharati, S., Hall, P. B., Vagle, K. and Bjor0y, M., 1997b, Geochemical evaluation of the Embla field, Norwegian Continental Shelf - 2: Source, infilling, compartmentalisation and intra-reservoir communication: Marine and Petroleum Geology, (under submission).

Bishop, A. N., Kearsley A. T. and Patience, R. L., 1992, Analysis of sedimentary organic materials by scanning electron microscopy: the application of backscattered electron imagery and light element x-ray microanalysis: Organic Geochemistry, v. 18, p. 431-446.

Bj0rlykke, K., Nedkvitne, T., Ramm, M. and Saigal, G. C., 1992, Diagenetic processes in the Brent Group (Middle Jurassic) reservoirs of the North Sea: an overview, in, A. C. Morton, R. S. Hazeldine, M. R. Giles and S. Brown (eds.), Geology of the Brent Group: Geological Society Special Publication No. 61, London; p. 263-287.

Curiale, J. A., 1986, Origin of solid bitumens, with emphasis on biological marker results, in D. Leythaeuser and J. Rullkotter (eds.), Advances in Organic Geochemistry 1985, p. 559-580.

Dixon, S. A., Summers, D. M. and Surdham, R. C., 1989, Diagenesis and preservation of porosity in the Norphlet Formation (Upper Jurassic), southern Alabama: AAPG Bulletin, v. 73, p. 707-724.

George, S. C., Llorca, S. M. and Hamilton, P. J., 1994, An integrated approach for determining the origin of solid bitumens in the McArthur Basin, northern Australia: Organic Geochemistry, v. 21, p. 235-248.

Hunt, J. M., 1978, Characterization of bitumens and coals: AAPG Bulletin, v. 62, p. 301-303.

Hunt, J. M., Stewart F. and Dickey, P. A., 1954, Origin of hydrocarbons of Unita Basin, Utah: AAPG Bulletin, v. 38, p. 1671-1698.

Knight, I. A., Allen, L. Copiel, R. J., Jacobs, L. and Scanlan, M. J., 1993, The Embla Field, in J. R. Parker, ed., Petroleum Geology of Northwest Europe: The Geological Society, London, p. 1433-1444.

Landis, C. R. and Castano, J. R., 1994, Maturation and bulk chemical properties of a suite of solid hydrocarbons: Organic Geochemistry, v. 22, p. 137-149.

Lomando, A. J., 1992, The influence of solid reservoir bitumen on reservoir quality: AAPG Bulletin, v. 76, p. 1137-1152.

Norwegian University of Science and Technology 108 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Meyer, R. F. and de Witt, W., 1990, Definition and world resources of natural bitumens: US Geological Survey Bulletin 1944, p. 1-14.

Orr, W. L. and Damste, J. S. S., 1990, Geochemistry of sulphur in petroleum systems, in W.L. Orr and C. M. White (eds.), Geochemistry of sulphur in fossil fuels: ACS symposium series 429, Washington, p. 2-29.

Parnell, J., Kucha, H. and Landais, P., 1993, Bitumens in ore deposits: Berlin, Springer- Verlag, 520p.

Pye, K. and Krinsley, D. H., 1984, Petrographic examination of sedimentary rocks in the SEM using backscattered electron detectors: Journal of Sedimentary Petrology, v. 54, p. 877-888.

Rizer, C. L. T., 1987, Some optical characteristics of solid bitumen in visual kerogen prepara ­ tions: Organic Geochemistry, v. 11, p. 385-392.

Rogers, M. A., McAlary, J. D. and Bailey, N. J. L., 1974, Significance of reservoir bitumens to thermal maturation studies, Western Canada: AAPG Bulletin, v. 58, p. 1806-1824.

Sassen, R., 1988, Geochemical and carbon isotopic studies of crude oil destruction, bitumen precipitation and sulphate reduction in the deep Smackover Formation: Organic Geochemistry, v. 12, p. 351-361.

Trewin, N. H., 1988, Use of scanning electron microscope in sedimentology, in M. E. Tucker (ed.) Techniques in sedimentology, Oxford, Blackwell, p. 229-273.

White, I. C., 1899, Origin of grahamite; Geological Society of America Bulletin, v. 10, p. 277- 284.

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Chapter 6: Paper 5

Solid reservoir bitumen in the Embla Field, Norwegian Continental Shelf -2: Chemistry, structure and origin§

Sunil Bharati

Geolab Nor, N-7002 Trondheim, Norway

6.1 Abstract

Solid reservoir bitumen, which was found to be extensive in the Embla Field, particularly in the lower portion of the pre-Jurassic sandstone pay-zone, occurs in a variety of modes resulting in eight recognizable morphotypes, as described in the first part of this study. This paper focuses, in addition to its chemical composition, on the internal structure and possible mode of origin. As this unique immobile migrated hydrocarbon phase is insoluble in common organic solvents, its chemical characterisation was limited to pyrolysis-gas chromatography and other bulk chemical methods such as NMR and elemental analysis. This carbon-rich phase (TOC up to 62%) is depleted in hydrogen (H/C 0.8-0.9) and enriched in aromatic hydrocarbon structures (fa 68%), but gives contradictory PY-GC signature which indicates labile moieties present in the bitumen mass. Examination using SEM shows the presence of some systematic and partially ordered internal structure. Based on the various solid bitumen features observed, particularly in relation to the inorganic minerals occurring in the pore-space, the relative timing of bitumen’s emplacement is estimated. Various known causes of bitumen formation are discussed and the most likely scenario in the case of Embla presented. Its implication on reservoir quality and its relationship to the present mobile (producible) oil phase is also discussed.

5 Manuscript under submission to AAPG Bulletin

Norwegian University of Science and Technology 110 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

6.2 Introduction

This is the second of two papers on geochemical and optical assessment of residual solid reservoir bitumen found in the Embla Field, Norwegian Continental Shelf (Note: the term ‘pyrobitumen’ is deliberately not used in this article as it indicates heat-related phenomenon and therefore may be misleading). The first paper assessed the gross occurrence, development and different morphotypes of solid bitumen observed in the Embla reservoir, while this paper addresses the chemical and structural aspects of this unique and immobile migrated hydrocarbon phase in the main reservoir units of the Embla Field, namely the pre-Jurassic Upper and Lower Sand.

Previous studies have attributed solid bitumen to result from one or more of three principal oil alteration processes outlined by Tissot and Welte (1984): biodegradation (e.g. Deroo et al., 1977; Connan, 1984), thermal alteration (e.g. Raymond and Murchisson, 1988) and deasphalting (e.g. Dahl and Speers, 1985). In the present paper, these and several other processes are discussed in an attempt to evaluate their validity and explain the observed form, texture and structure of the Embla bitumens.

63 Geological background

This has been covered in detail in the first paper on the geochemical evaluation of the Embla Field (Bharati et al, 1997a) and to some extent in part 1 of this paper (Bharad,1997). Briefly, the Embla Field, a NW-SE oriented field of about 19.4 km2 at base Cretaceous, consists of three pre-Jurassic reservoir units, the Uppermost, Upper and Lower Sandstone separated vertically by a thick mudstone facies. The reservoir section is intensely faulted potentially causing compartmen- talisation, a feature which was suspected when evaluating the RFT and DST data. Due to the known geological complexities, extensive coring was conducted (Knigh t et al., 1992) which provided a good database for detailed geochemical assessment. In addition to periodic invasions of hydrothermal fluids into the reservoir causing repeated periods of porosity loss and enhancement, there is significant solid reservoir bitumen formed in the Lower Sandstone.

6.4 Samples and Methods

Pure solid bitumen aliquots were obtained by physically scraping bitumen mostly from cavities, vugs and veins in core samples of three wells, namely NOGS 2/7-20X, -21S and - 26S, using a scalpel and a diamond-tipped electrical vibrator. These were subsequently analyzed for (in dichloromethane : methanol (93:7 v/v), total organic carbon (TOC) using LEGO CR12 instrument and composition (PY-GC using GHM instrument and bulk 8 13C using VG SIRA 10 instrument). In addition, bitumen aliquots were analysed for elemental composition (C, H, N, S and O) using EA 1110 element analyzer and U and Th using neutron activation) and gross aromaticity and carbon types using solid state 13C NMR on a Bruker

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 111

MSL 300 instrument. Whole rock portions rich in bitumens as well as pure bitumen aliquots were analysed for biomarker composition using GHM-MS. Whole rock polished thin sections and slices covering the entire reservoir column were used for petrological and fluid inclusions analyses respectively. Solid bitumen and whole rock samples were also examined using SEM (JEOL JSM-840) to understand mineral inter-relationships and bitumen structure. Bitumen’s internal structure was also studied using high resolution TEM (Philips CM 30).

6.5 EMBLA SOLID BITUMEN COMPOSITION

Of the 27 allochthonous solid bitumens described by Curiale (1986), only 5 have atomic H/C < 0.90 (3 of them being impsonites) and all but one sample suite, namely uraniferous nodules from Kiowa County, Oklahoma (consisting of 5 samples), are partially or wholly solvent extractable. However, it must be noted that the three impsonites (two are from Page, Oklahoma) had negligible solubility (0.5 - 2.7 %). The fact that the majority of Curiale’s (1986) solid bitumen suite is soluble, allowed extensive chemical characterisation of the bitumen phase via gas chromatography and mass spectrometry. The solid bitumen aliquots recovered from the Embla sandstone cores are insoluble in common organic solvents, thus severely limiting chemical characterisation of this organic phase using similar geochemical techniques. However, some key parameters necessary to define and understand the carbon phase could be measured (Table 1).

Insolubility of the studied solid bitumens clearly points towards the large molecular size and a high degree of alteration/cross-linking, although it remains an organic carbon-rich phase (comparable to some coals); but its low hydrogen indices and high Tmax suggest that it is not presently very labile and represents a severely (thermally?) degraded material. This is confirmed by high reflectance obtained (up to 1.27%) in oil immersion. Based on the classification proposed by Cornelius (1987) and the atomic H/C and O/C ratios obtained for the Embla bitumens, these could be classified as epi-impsonite, a bitumen phase with one of the lowest H/C, the only other bitumen with lower H/C being Shungite (H/C about 0.1). The strong possibility that the present bitumen phase resulted from a ‘normal ’ migrated hydrocarbon phase is indicated by the bulk carbon isotopic values (-25.35 to -27.74) slightly heavier than the typical (post Jurassic) North Sea oils (Hughes et al., 1985; Bjor0y et al., 1994, Bharati et al., 1997c). Northam (1985) has also noted, based on carbon isotope profiling, that the 8 i3C value of the residuum resulting from, for example oil cracking, becomes slightly (2-3

%o PDB) heavier as compared to the original whole oil. In comparison to most of the conventional crude oils (H/C about 1.9), heavy oils (H/C about 1.6) or asphalt (H/C about 1.4, Cornelius, 1987), the Embla bitumens with H/C of 0.77-0.90 represent a highly degraded stage of migrated hydrocarbons.

Pyrolysis-gas chromatography using GHM provides very useful data in elucidating the chemical composition and measuring the degree of present lability. Interestingly, the thermal

Norwegian University of Science and Technology Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

20X/Host rock

26S/Host rock

20X/Bitumen

26S/Bitumen,

Thermal Extracts Pyrolysates

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 113 extracts (Figures la and b) and pyrolysate signatures (Figures le and f ) of bitumen-free host rocks from wells 20X, 21S (in the central block, Figures la and e), 23S (in the northern block) and well 26S (located in the western block, Figures lb and f) are very similar (see Figure 1 in Bharati, (1997) for well locations).

Table 1: Selected physical and chemical properties of untreated solid reservoir bitumen isolated (physically from cores, using a scalpel) from the Embla reservoir sandstones.

Parameter Value Nr. of samples Colour and appearance (in host rock) Black, vitreous 18 Solubility (in dicMoromethane:methanol, 93 :7 v/v) Insoluble 5 Total organic carbon (TOC) (%) 40 - 62.5 6 Hydrogen index (mg HC/g TOC) ...... 124-154 _ 6 Tmax (°C) 468 - 473 6 Reflectance (oil immersion, %) 114- 1.27 6 Atomic H/C 0.77 - 0.90 3 Atomic O/C 0.03-0.05 3 Atomic S/C 0.01 - 0.04 3 Atomic N/C 0.01 - 0.04 3 Ash content (weight %) 42-66 3 Uraniumcontent (ppm) __ 15-4.2______8 Thorium content (ppm) <50 - <100 8 B#momatidty(%). ______.. _ 65-68% 3 Major carbon types ArC, ArCC, CH2 3 S13C(%o PDB) -25.35 to -27.74 12

However, the composition of bitumen pyrolysates from wells 20X or 21S (Figure lg) are very different when compared to those from well 26S (Figure lh), although the signatures from well 23S are comparable to those from 20X/21S. The most striking difference between the 20X/21S and 26S bitumen pyrolysates (Figures lg and h respectively) is in the type of chemical moieties released on pyrolysis.

The bitumen samples from wells 20X and 21S have a greater abundance of labile components, traceable up to nCgs, and a very strong homology of n-alkene/n-alkane doublets - a signature very similar to that obtained from a type II kerogen (Barter and Senftie, 1985;

Figure 1: (previous page) Thermal extract (left) and pyrolysate (right) signatures of bitumen- free host rocks (a and e from well 20X, b and f from well 26S) and bitumen samples (c and g from well 20X, d and h from well 26S). Peak identification: To - toluene, Xy - xylene, the numbers indicate the number of carbon atoms in a straight chain; e.g. 15 indicates n- heptadecane in TE-GC traces and the position of n-heptadecene Jheptadecane doublet in the PY-GC traces, Pr - pristane and Ph - phytane.

Norwegian University of Science and Technology 114 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Bjor0y et al, 1992). In contrast, the 26S bitumens lack all of the above characteristics and instead produce mainly only gaseous and medium range compounds with n-alkanes being comparatively insignificant, a signature comparable to that from type HE/TV kerogen. This difference is not believed to be attributable to any difference in bitumen morphotype (as described by Bharati, 1997), but related more to the location of the well and preservation history of the bitumen phase in the given fault block. In the case of wells 23S and 27S, in which no bitumen could be seen either by naked eye or under the microscope, presence of disseminated bitumen was confirmed by elemental mapping (Bharati, 1997). In these wells, while the thermal extract signatures remain essentially the same down the wells (Figures 2a-c), the pyrolysate signatures change dramatically in samples from the bitumen-free zone to deeper bitumen zone (Figures 2d-f). By and large, the pyrolysate signature of dissipated bitumen is qualitatively comparable to the 20X and 21S bitumen samples.

However, irrespective of the internal compositional differences between the bitumens from different locations, the common fact that all bitumen samples release components as seen in the PY-GC signatures is in itself somewhat surprising, especially if compared to Curiale’s (1986) pyrograms of the insoluble bitumens. In addition, the signatures are in some contradiction to bulk pyrolysis and particularly elemental (H/C) data. Any sedimentary organic material with an H/C of 0.8 or so would generally not be expected to produce a signature such as in Figure lg. It is therefore imperative to elucidate and understand as to why this carbon mass, initially thought to be nearly inert, gives contradictory data and whether labile components are actually present. Direct analysis of solid bitumen to assess biomarker composition (using GHM-MS) proved futile as no biomarkers were detected in the samples.

6.6 The nature of carbon in the Embla bitumens

Several studies have been conducted in which bulk aromaticity (fa ) of natural organic matter such as kerogen and solid bitumens has been measured using solid state 13C CP/MAS NMR (e.g. Hatcher et al., 1981; Miknis et al., 1982; Soil! et al., 1985; Curiale, 1986). Recently, new and far more enumerated applications of NMR were developed by Mann et al. (1991) and Patience et al. (1991), whereby in addition to conventional fa determination, it allowed quantitative estimation of individual carbon types that make up the sample’s molecular structure. This technique was successfully employed to characterize the complex nature of organic carbon in natural geological systems such as kerogens (Bharati et al., 1995). In the present study, the methods and principles originally developed and employed for the study of kerogens were utilized (with modifications) to characterize solid reservoir bitumens from Embla, in order to predict the individual chemical moieties that make up the bitumen mass.

Apart from the fact that the Embla bitumens have a gross aromaticity of 65-68%, more than 30% of all carbon is found to be aromatic ring carbon (benzene =15%, naphthalene = 11% and

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 115

Bitumen-free Zone

Transition Zone

Bitumen Zone

Thermal Extracts Pyrolysates

Figure 2: Typical thermal extract (left) and pyrolysate (right) signatures of bitumen-free zone (a, d), transition zone (b, e) and dissipated bitumen bearing zone (c,f)from well 23S (trap UM2). Peak identification: To - toluene, Xy - xylene, the numbers indicate the number of carbon atoms in a straight chain; e.g. 15 indicates n-heptadecane in TE-GC traces and the position of n-heptadecene / heptadecane doublet in the PY-GC traces, Pr - pristane and Ph - phytane.

Norwegian University cf Science and Technology 116 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea phenanthrene/ anthracene == 5%) in addition to about 35% other aromatic carbon (Figure 3). The estimates of 2-ring naphthalene and 3-ring anthracene/ phenanthrene were made on the basis of bridgehead carbon amount. Of the aliphatic carbon types, methylene carbon (both rigid and mobile CH2) is the dominant type (about 10%), suggesting that most of the aliphatic carbon may be present in form of short alkyl chains (ethyl to butyl), particularly in light of the fact that about 3% of the carbon is aliphatic methyl (CH3), the end member of an alkyl chain. All the other aliphatic carbon types are present in sub-equal quantities (ca 2-4 % each, Figure 3). NMR data are in agreement with the elemental analysis data and confirm the condensed and highly aromatic nature (high molecular weight) of the Embla bitumen mass (but perhaps contradicts the pyrolysis data).

Relative % Figure 3: Results of NMR analysis

Aromatic Species Sample B of isolated pure bitumen fraction. Gross Aromaticity Relative percentages of the major 65% aromatic moieties (hatched bars) and aliphatic moieties (open bars) Aliphatic Species are calculated from the deconvo ­ lution of the NMR spectrum, based on chemical shift of each carbon type.

Carbon Type

6.7 Internal structure of the bitumen phase

The Embla bitumens, which have been classified into several morphotypes (Bharati, 1997), show distinct differences in the topographical features from different modes of occurrences (cavities, vugs, veins and fractures). However, equally clear and discrete differences are not observed in the internal structure of different morphotypes, although some bitumen masses (extracted from cavities) show very interesting structural features when observed using a SEM (Figures 4 and 5). In cross-sections (most probably along a contraction fracture), some massive bitumen masses exhibit a systematic, outwardly radial ‘growth ring ’ pattern (Figure 4a) which on higher magnification shows that the ‘rings ’ or zonations are successive and equi- spaced (about 1-1.5 |xm apart, Figure 4b). Further magnification (down to nm level, Figures 4c and d) reveals another interesting aspect, namely the granular constitution of the bitumen

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 117

Figure 4: Internal structures observed in the Embla bitumens using SEM. a) general view of a massive bitumen cross-section (wall) exhibiting ‘growth ring ’ pattern. The arrow points to the area enlarged in b) and the marked area in b) is enlarged in c) and d). e) Enlargement of a foliated bitumen surface showing thinner folia f) general view of a freshly broken massive bitumen surface, enlargements of which are shown in Figure 5.

Norwegian University of Science and Technology W BE! 118 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea mass. A significant point to note is the uniformity in size of the individual granules (mostly ranging 80-100 nm). No compositional difference could be established between the dark grey and light grey zones, but any compositional differences that might be present (which in all probability would be differing N, S or O contents and/or the form in which these are bonded) are beyond the detection capabilities of a SEM. In the case of foliated bitumen, individual folium apparently consist of a bundle of thinner parallel folia (Figure 4e), each of these sub­ folium again consisting of even thinner folia. These features suggest that the formation of bitumen was slow, progressive and layer after layer.

High resolution TEM analysis was performed to examine the micotextural and structural fea­ tures, particularly to understand the distribution of the basic structural units (BSU). Similar work has been reported earlier for asphaltenes (Bonnamy et al., 1987), coal (Ross et al., 1991) and bitumen (Cordal et al., 1990). In the present study, an attempt has been made to apply this technique to solid reservoir bitumen from Embla using 002 dark field images. Transmission electron micrographs show local molecular orientation (LMO) domains, about 30A across, in the BSUs with weak planar preferred orientation. However, the gross degree of order (of the aromatic ring stacks) is considered to be poor, but uniformly compact and the solid bitumen carbon phase appears to be turbostratic in nature. Turbostratic carbon is essentially hard, non ­ graphic and baked carbon with small pores, usually quite uniformly distributed and intercon ­ nected and the plate alignment is short-range and the crystallites are much smaller (Murdi, 1996). Selected area electron diffraction (SAED) patterns clearly show broad and complete 002 rings and indicate the bitumen’s amorphous, but weakly ordered nature.

With regards to freshly broken cross-sectional surface features (ffactographs), two unrelated examples were observed. A general view of one is shown in Figure 4f. Further magnification (Figures 5a-c) reveals that the bitumen mass consists of several parallel horizontal layers (Figure 5a) which are cross-connected by equi-spaced and thinner vertical layers (Figure 5b). The horizontal layers on the other hand consist of a bundle of thinner horizontal layers (Figure 5c). Clearly, the process of bitumen formation must have been slow for such systematic and recurrent features to be developed. The second example (Figures 5d-f) exhibits the ductile nature of the bitumen mass very clearly. The fracture, which is across a bitumen particle (Figure 5d) shows on enlargement the classic dimpled pattern of fine, equiaxed ductile shear; this is very similar in nature and appearance to ductile shear rupture obtained in the titanium alloy T1-6A1-4V (ASM Metals Handbook, 1992, page 447). Such fracture surfaces are produced when the shearing is slow.

6.8 Timing of bitumen formation

In order to address and understand the processes involved which led to the formation of solid bitumen in the Embla reservoir, it is imperative to first establish the relative timing of

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 119

Figure 5: Internal structures observed in the Embla bitumens using SEM (contd.). a) enlargement of the area shown by the arrow in Figure 4f. b) and c) are enlargements of different areas from a) to show details of the horizontal and vertical layers respectively, d) example of another freshly broken bitumen surface - general view. The arrow points to the area enlarged in e). The marked area in e) is enlarged inf).

Norwegian University of Science and Technology 120 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea formation of the major mineralogical phases observed in the inter-granular space (paleo- porosity) in relation to each other, particularly with respect to bitumen. Burial history and diagenesis play a crucial role in the evolution of the paleo and present petrophysical properties of the pre-Jurassic reservoir sandstones. Realistic burial / temperature history modeling were not performed in the Embla field successfully due to several limitations, such as: 1) unknown exact age of the reservoir, 2) discontinuity and / or irregular present-day layer thickness, 3) several unconfirmities and thickness of eroded sections unknown (presently only about 400 m sediments to account for about 160 Ma), and 4) no neighbouring well data available to make analogues or pseudo-wells. However, petrological and SEM observations have helped in understanding the sequence of major geological events.

6.8.1 Diagenetic considerations

In general, the Embla reservoir sandstones are fine to medium grained (occasionally conglo­ meratic) with moderate to good sorting (Figure 6a). Quartz cementation is generally extensive and is reasonably advanced locally in a few zones, as overgrowth quartz (OG); forming Y- junctions commonly observed. However, locally in some zones, authigenic quartz is totally absent due to either hematitic cement (Figure 6c) or the presence of a thin dirty clay layer over detrital grains (Figure 6d) preventing quartz overgrowth. Kaolinite is very well developed, fresh in appearance and occurs as densely packed vermicular books (occasionally as feldspathic pseudomorphs). Poikilotopic calcite cement exhibiting strong zonation is observed sporadically. K-feldspar and illite are absent or, at best, very rare.

Absence of any feldspar and illite in the Embla sandstones indicate two important events: 1) feldspar dissolution, which took place early and in an open system due to meteoric water flushing, was total and kaolinite precipitation continued until the supply of A1 was eliminated; at this stage the sediments are not expected to have been buried more than about 2 km. 2) either the system was then closed preventing circulation of meteoric waters which could bring in K, an essential component for illite formation, OR illite formation was arrested due to early oil emplacement

Figure 6: (following page ) Petro-micrographs of the Embla reservoir sandstones, a) typical sandstone from a bitumen-free zone, blue epoxy indicates porosity, b) similar sandstone from a dissipated bitumen-bearing zone. Note the reduced porosity, c) view of relatively rare sandstone with hematitic cement (restricted to well 26S). d) example of sandstone with dirty clay coating over detrital quartz grains; inset is enlargement of a typical grain surface with brownish clay coating, e) overgrowth quartz seen engulfing books of kaolinite (shown by arrows), f) relationship of poikilotopic calcite cement, quartz cement and bitumen, g) a large mass of kaolinite occurring totally within the bitumen phase, h) black bitumen occurring in kaolinite ’s inter-book micro-porosity (shown by arrows). Abbreviations : Bi - bitumen, Qd - detrital quartz, Qc - quartz cement, Ka - kaolinite. Scale bars : a, b, c, d, e, g and h = 500 pm, f= 200 pm and inset in d) 100 pm.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 121

Norwegian University of Science and Technology

•1^:1 I m 122 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Sommer (1978), while studying the Brent Group sandstones from the North Sea argued that authigenic illite would be formed during oil and water migration but not after oil emplacement into the reservoirs. An observation supporting this hypothesis was made by Thomas (1986) that in the Statfjord Formation and Brent Group of the Heimdal Field in the Viking Graben, North Sea, illite was much more abundant below the oil-water contact than above. With respect to the closed system possibility, it has been shown earlier that authigenic illite forms primarily by dissolution of kaolinite and K-feldspar when present together (Bjprlykke, 1983), generally in the temperature regime of 130-140°C (Ehrenberg and Nadeau, 1989). In the absence of K-feldspar, however, kaolinite is stable to much higher temperatures, as would be the case in Embla. In the Hild Field, where the K-feldspar concentration is very low, kaolinite is still stable and illitization has not taken place even at temperatures of about 150-160°C (Lpnpy et al., 1986). Illitization may thus also depend on locally available sources of K+ (few meters scale) and therefore not totally controlled by the import of K+ from distant sources, as noted by Bjprlykke et al. (1992). In the case of Embla, non-availability of a local K source for illitization seems to be overriding, although other factors which hindered illite formation (such as oil emplacement) may have played an additional role.

Although quantitative data with respect to quartz cement in the Embla sandstones is not available in the present study, and despite the locally observed rather advanced stage of quartz cementation, it is surprising to observe high porosity (generally 10-15% in the Upper Sandstone and 8-12% in the Lower Sandstone, Bharati et al., 1997a) still preserved in these sandstones. As quartz cementation played a decisive role in porosity reduction in Embla, the fact that high porosity (than would be expected) is still preserved implies that more extensive cementation was hindered by some factor. This factor may well be emplacement of the paleo- oil just before or during the initial phases of quartz cementation, as suggested by several workers (e.g. Sommer, 1978; Robinson and Gluyas, 1992). However, it must be remembered that other factors such as the thin coating of detrital quartz grains by clayey/ chloritic material (Figure 6d) have played an important role in porosity preservation, but only locally. Similar phenomenon has been documented by several workers (e.g. Heald and Larese, 1974), including in the deep reservoirs of the North Sea (Ehrenberg, 1993). However, no micro ­ crystalline quartz coating, which is also known to inhibit quartz cementation as reported by Aase et al. (1996) in the Ula and Gyda oil fields, North Sea, was observed in the Embla sandstones.

6.8.2 Mineral inter-relationships

Abundant examples of overgrowth (OG) quartz engulfing books of kaolinite are seen in thin sections (Figure 6e). Excellent examples are seen under the SEM too (Figures 8a and b), which clearly show that kaolinite pre-dates quartz cement. In fact, the trace amounts of illite also pre-date OG quartz, as the latter engulf illite too (Figure 7c). Optically continuous poikilotopic calcite cement was formed after quartz cementation was completed (see the

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 123

Figure 7: SEM views of the major mineral phases in relation to each other, a) OG quartz engulfing kaolinite books, b) another excellent example (a cross section through a detrital quartz grain and the overgrowth) of quartz cement engulfing kaolinite, c) OG quartz partially engulfing fibrous and hairy illite, d) solid bitumen deposited on a detrital quartz grain surface and through which OG quartz protrude outwards, e) a kaolinite mass partially engulfed by solid bitumen; marked area is enlarged inf) to show the bitumen phase within kaolinite ’s inter-book micro-porosity. Abbreviations: Ka - kaolinite, Qc - quartz cement, Qd - detrital quartz, II - illite, Bi- bitumen.

Norwegian University of Science and Technology 124 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea contact between calcite and quartz cements and calcite cement and detrital quartz in Figure 6f), but before any bitumen was emplaced, as bitumen is found sandwiched between calcite cement and quartz (Figure 6f). The evidence of bitumen being emplaced after quartz cementation was complete, is seen in Figure 7d, where bitumen is seen as a thick layer over detrital quartz on which overgrowth had occurred. In addition, contraction features in the bitumen phase are clearly visible in the form of micro-fractures. Examples of bitumen engulfing kaolinite masses are also abundant (Figures 8e and f), confirming early kaolinite precipitation (pre-dating bitumen). Another feature evident in Figures 8e and f and 6h is that bitumen is present in kaolinite ’s inter-book micro-porosity, pointing towards the high mobility of the petroleum phase (paleo-oil) before solidifying (into bitumen).

Pyrite, which is nearly absent in the host rock and was observed to be associated only with the bitumen phase (Bharati, 1997), is found deposited in-situ on solidified bitumen (Figures 9a and b) as amorphous rounded masses (framboidal ?), indicating formation of pyrite after bitumen was solidified and bitumen serving as a preferred nucleadon site. Unlike studies focusing on organic sulphur compounds, examples of which are numerous (Damste and De Leeuw, 1990 and references therein; Orr and Damste, 1990 and references therein), association of mineral pyrite and migrated hydrocarbons is rarely discussed (e.g. Parnell et al., 1994). In the case of Embla solid bitumens, whether the observed pyrite was formed at the cost of organic sulphur compounds or is a result of reaction between iron monosulphide precursor and H2S is difficult to establish. The former would be true in case the reservoir contained H2S and reactive Fe was readily available, as this reaction would preferably precede the reaction with organic compounds. This Fe could not have been from Fe-bearing feldspar, as we know that all feldspar was dissolved to from kaolinite early in the diagenetic history; and most Fe resulting from feldspar dissolution would have been removed by meteoric waters as the system was open at this stage. On the other hand, sulphate (possibly also iron?) could have been brought into the system at a later stage by associated groundwater and could have easily been reduced to H2S at high temperatures through thermochemical sulphate reduction mechanism, as proposed by Orr (1974) and shown by Sassen (1988).

Another major mineral phase associated only with solid bitumen is barite and this occurs in two different forms. Crystalline barite (perfect orthorhombic prismatic elongated parallel to a axis - about 500 pm long, Figure 8c) is found completely embedded within the bitumen mass, which indicates that barite crystallization was completed before bitumen was solidified. In fact, a mould of a barite crystal was also observed (Figure 8d), perhaps resulting from a barite crystal being knocked off during sample preparation. Unlike previously observed aspects such as contraction fractures or bitumen surrounding OG quartz etc., which are relatively partial or indirect indications, this is the most convincing and direct evidence clearly verifying that the present solid bitumen phase (now immobile and fixed) was at one stage mobile and free flowing (perhaps even a normal oil). In contrast, another form of barite (amorphous, vein

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 125

Figure 8: SEM views of the major mineral phases in relation to each other (contdL .). a) amorphous and massive pyrite deposited on solidified bitumen; the central portion is enlarged in b) exposing the pyrite-free inner bitumen core, c) perfect orthorhombic barite crystal embedded in the bitumen mass, d) a barite crystal mould left behind in the bitumen mass, e) vein barite filling a contraction/cooling fracture in bitumen, f) same field as in e) but in BSI mode to highlight the atomic number contrast between carbon and barium. Abbreviations : Py - pyrite, Bi - bitumen, Ba - barite.

Norwegian University of Science and Technology

: % 126 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea filling) is also found in the contraction fractures of bitumen (Figures 9e and f). As the micro- fractures in bitumen were a consequence of contraction due to volume reduction and loss of light components, these were formed concurrent with solidification. Any mineral phase sealing these fractures must therefore post-date bitumen formation.

Most studies of barite formation have focused on more massive accumulations, such as concretions, bedded barite and ore deposits (e.g. Lange et al., 1983; Graber and Chafetz, 1990). Very few studies address authigenic barite found as a common accessory mineral in sandstones (e.g. Breit et al., 1990), although it has the potential to be used to understand diagenetic conditions. No studies have been reported relating barite to migrated hydrocarbons. However, in the case of Embla, barite is almost exclusively associated with solid bitumen and not present in the host sandstone. Otherwise barite as pore-filling cement or poikilotopic cement or replacement of detrital grains would have been observed in the host sandstone (not seen in the present study), as observed by Breit et al. (1990) in the Late Jurassic Morrison Formation in Colorado Plateau. Both Ba and sulphate could have been derived from the subjacent evaporite (east of Skrubbe fault, cf. Figure 1 in Bharati, 1997), provided the solutions bearing these moved upward along the fault and laterally into permeable sandstones. This implies that the Skrubbe fault was not a sealing fault, a feature which, if true, has overriding implications with respect to reservoir infilling . In any case, it is clear that as euhedral barite immediately preceded bitumen solidification, vein barite infilling must therefore have proceeded immediately thereafter, and may not be an artifact of, for example, mud additives during drilling.

More importantly, the presence of both pyrite and barite in the same system, supposedly formed in a comparable geological time-frame, raises another significant question. Unlike pyrite, which would form under reducing conditions, barite is formed under oxidizing conditions. In addition, the fact that pyrite and barite are associated primarily within the bitumen phase and are absent in the host rock suggests that their precursors were either part of or associated with the paleo-oil or were a result of the paleo-oil destruction / bitumen formation process. An extension of both these hypotheses is that iron, barium and sulphur (sulphate?) were already present in the paleo-oil system in some form. In my opinion, neither pyrite nor barite could be a result of any hydrothermal fluid activity in the rock, otherwise these should have been present in equal amounts in the host rock too. This is not seen in the present study (Figure 11, Bharati, 1997). Parnell et al. (1994) suggested that hydrocarbon bearing fluids contain a major aqueous component capable of transporting inorganic species. One likely scenario in the case of Embla could be that the migrated hydrocarbon charge contained an aqueous component, which was capable of retaining reactive ions needed for mineralization, such as SO4 -, Fe++ and Ba**. Subsequent to oil emplacement, the following sequence of reactions could have occurred:

Doctoral Dissertation by Sunil Bharati, 1997 PaperS: Embla reservoir bitumen: Chemistry, structure and origin 127 i) pre-bitumen solidification, at relatively stable conditions Ba"1"1" + SO4*" —» BaSO# (euhedral barite) ...... (1) ii) post-bitumen solidification and formation of contraction fractures Ba++ + S04- —» BaSC>4 (vein barite) (2)

S04" + 1.33 (CH2) + 0.66 H20 -> H2S + 1.33 C02 + 2 0ET ...... (3)

Fe++ + 2H2S -> 2 H2 + FeS2 (pyrite) ...... (4)

Equation (3) above is adapted from Orr (1974) and represents the net reaction, involving a series of more primitive reactions, where H2S acts as both a catalyst and a reaction product. Therefore such thermochemical sulphate reduction by organic matter (in this case light gases) can initiate with even small amounts of H2S.

Considering the above evidences, the following post-depositional sequence of events is believed to have occurred: 1) (Total) feldspar dissolution / kaolinite precipitation, 2) insignificant illitizadon, 3) quartz cementation, 4) paleo-oil emplacement, 5) euhedral barite formation, 6) paleo-oil destruction / solid bitumen formation, 7) vein barite infilling, 8) amorphous pyrite deposition and finally 9) present day oil emplacement.

6.9 Causes of bitumen formation

Curiale (1986) has, in his assessment of a suite of 27 solid bitumens, ascribed their origin mainlyto biodegradation and post-sourcing thermal alteration, in light of the original thermal state of their source rock. Several other studies have been reported which link solid bitumen formation to these processes ( e.g. Lomando, 1992; George et al., 1994). George et al. (1994) in addition have suggested that solid bitumen formation is related to secondary porosity generation in sandstones. Solid bitumens not related to deep burial or any external heating are also known (cf. gilsonites, which are sourced from Eocene Green River Formation, Utah, Tissot et al., 1978). In the case of Embla reservoir solid bitumen, however, considering all the available data and the geological facts that are not available, it is difficult to elaborate on and accurately assess the possible cause(s) of bitumen formation or to build on any one possibility. Nevertheless, the feasibility of important crude oil alteration processes is discussed below individually. To be able to properly address this aspect, however, the following facts about Embla solid bitumen, based on available data, must be borne in mind:

1) Solid reservoir bitumen is not found in the entire reservoir column and is mostly restricted to the lower part of the reservoir, and the overall bitumen abundance and size of individual bitumen bodies increase with depth.

Norwegian University of Science and Technology 128 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

2) The depth at which bitumen starts to occur in the Embla field is different in different fault blocks / wells, perhaps indicating that some faults were reactivated post-bituminization. 3) The mode in which bitumen starts to occur is different in different fault blocks, but it appears that in the shallower depths, microscopic dissipated bitumen is most common. 4) Eight different bitumen morphotypes have been recognized, each having discrete topographical features, but grossly similar composition. The different morphotypes may be attributes of (and result from) the shape, volume and size of the pore space that the petroleum phase occupied before solidification. 5) The immobile petroleum phase represented by solid bitumen today was (perhaps) in the geologic past a very mobile and free-flowing oil phase and there are indications that it may even have been a ‘normal ’ oil phase comparable to other North Sea oils (but not necessarily Jurassic sourced). 6) In general, most chemical data suggest that Embla solid bitumen is a highly condensed and aromatic carbon mass (epi-impsonite), but PY-GC data of some samples indicates presence of some labile components. 7) Pyrite and barite are associated almost exclusively with the bitumen phase and are conspi ­ cuously relatively absent elsewhere in the host rock. 8) Embla bitumen is amorphous, but several systematic / orderly features are present that point towards some methodical process of formation. 9) Data indicate that the paleo-oil phase, represented by solid bitumen today, was entrapped early, perhaps in the Paleocene/Eocene period. The entrapped paleo oil could have then leaked as a result of tectonic activity during Miocene (inversion). 10) In all likelihood, the present oil population (light-medium oil, API gravity 42°) is unrelated to solid bitumen and was reservoired after solid bitumen was formed.

6.9.1 Commonly recognized causes of petroleum alteration

Local heating, for example via igneous intrusions (sills, dikes and larger plutons), is widely known to heat the neighbouring sediments rapidly and to accelerate the process of thermal maturation of organic matter such as kerogen (Simoneit et al., 1981; Gilbert et al., 1985; Clayton and Bostick, 1986; Raymond and Murchisson, 1988). In case bitumen or migrated liquid hydrocarbons are present, these will also be signifi cantly altered or completely destroyed depending upon the extent and proximity of the heat source. While dikes are commonly from a few centimeters to a few meters thick, a large percentage of sills are typically over 50 m thick (Shiant Isles sill - 150 m, Palisades sill - 300 m; Hughes, 1982). Bishop and Abbott (1995) suggest that the extent of thermal alteration is 70-140% of the intrusion thickness. In the case of Embla, if an igneous intrusion is present at all, it should be a sill below the Lower Sandstone in the western fault block (well 26S) where bituminization is most severe and extensive. Given the thickness of the bitumen zone (>250 m), the intrusion must be at least 200-300 m thick. However, no known igneous intrusion of this magnitude is present below or in the vicinity of the Embla structure which could have caused destruction of

Doctoral Dissertation by Sunil Bharati, 1997 PaperS: Embla reservoir bitumen: Chemistry, structure and origin 129 the oil phase / formation of solid bitumen. Moreover, bitumen formation due to such heating would be rapid, contra the slow and methodical formation suggested for the Embla bitumens.

Irradiation from primary radioactive minerals (e.g. uraninite, monazite), is also known to cause thermal degradation of organic matter (kerogen or oils) over geologic times (Rouzuad et al., 1980, Curiale et al., 1983). Cortial et al. (1990) suggest that solid bitumen is derived from thermal alteration of crude oil due to closely associated uraninite ores in the 2000 Ma years old Francevillian Series of Gabon. However, although they conclude ‘massive precipitation of uranium’ and show, using TEM, carbon particles entirely invaded by uraninite crystals, they report a uranium content of 10 ppm or less in their original samples; this is comparable to average uranium content in most sedimentary rocks. Another similar study (Oh et al., 1990) presents more convincing data in this respect (reported U content in kerogens 45-543 ppm). In the case of Embla however (host rock age estimated between 245-360 Ma), both uranium (1.5- 4.2 ppm) and thorium are in insignificant quantities (Table 1) in isolated bitumens as well as host sandstone, to be able to explain such dimensions of bitumen occurrence.

In the recent years, much work has been directed towards the kinetics of petroleum formation, expulsion and destruction (e.g. lingerer et al., 1988; Burnham and Braun, 1990; Horsfield et al., 1992; Pepper and Dodd, 1995) and it is now clear that the two interdependent variables affected by burial (i.e. time and temperature) and heating rates are of paramount importance. With regard to thermal cracking of oil, which is a frequently cited mechanism of solid bitumen formation (e.g. Curiale, 1986; Levine et al., 1991), it follows that for an oil-pool to undergo metagenetic cracking (as would be the case with Embla bitumens), the reservoir sediments must be buried rapidly to significant depths after oil-emplacement and remain deeply buried until all original oil is converted to gas-condensate / gas (may escape from the system) and pyrobitumen (retained in the system), as seen in the Smackover Formation, Mississippi Salt basin (Sassen, 1988). No such direct burial evidence is available for Embla.

Based on extrapolation of closed-system programmed temperature pyrolysis experimental data to natural geological heating conditions, Horsfield et al. (1992) estimated that the onset of gas generation as a result of oil cracking would occur between 160°C and 190°C. Similarly, Pepper and Dodd (1995) in their extensive coverage of this phenomenon suggest that no oil- cracking occurs up to 174°C, possibly even as high as 195°C. However, both studies conclude that pyrobitumen is a significant product of the process, in addition to methane. Pepper and Dodd (1995) are of the view that in-reservoir cracking has received undue importance in the past and in addition suggest that the kinetics of the cracking process are highly dependent on both the initial hydrogen index of the source rock and the composition of the ieservoired oil. In the light of this discussion, for a no rmal oil population to be first reservoired and then completely cracked to produce the solid bitumen that we see today in Embla, this would require first a significant uplift of sediments from about 4 km, then oil emplacement and then

Norwegian University of Science and Technology 130 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea rapid re-burial again (to a temperature regime of about 205°C) to cause bituminization. No such burial history evidence is available at present. Alternatively, thermal cracking could occur locally due to heat not related to burial, but as discussed above no such known heat source exists in or around Embla.

Biodegradation is one of the most common causes of oil-pool destruction and estimated more than 20% of all world reserves has been affected by microbial degradation. Specific physico ­ chemical conditions are required for effective biodegradation to occur such as continuous circulation of meteoric waters to ensure oxygen and nutrients replenishment, maximum temperature of about 80°C (typically 20° to 60-75°C), presence of hydrocarbons and microbes etc. (Connan, 1984). The effects of biodegradation are also generally well established and predictable, the most co mmon ones being reduction in the overall saturated hydrocarbons content, consequently relative increase in polar compounds (increase in sulphur and nitrogen) and in general oils become heavier and more viscous (but not solid). Several case studies with varying degree of biodegradation have been reported (e.g. Deroo et al. 1977; Williams et al., 1986; Michael et al., 1989; Horstad et al., 1992). Tricyclic terpanes are considered to be most resistant to microbial degradation (Connan, 1984). In contrast, the Embla solid bitumens are not anomalously rich in sulphur and nitrogen (Table 1), devoid of any biomarkers and 8 13C is not heavy (Table 1). Moreover, even for any biodegradation to occur, especially extremely extensive as would be the case with Embla paleo-oil, the reservoir sediments would be required to be uplifted to significantly shallower depths, evidence for which is not presently seen. Last, as solid bitumen in Embla is confined to deeper portions of the reservoir, it follows that the present bitumen-free zone could not have been occupied by paleo-oil, but a thick gas- cap, otherwise signs of solid bitumen (if it was a result of biodegradation) should have been present in the entire reservoir column.

The processes of deasphalting and gravitational segregation of reservoired oil have also been subjects of discussion (Evans et al., 1971; Hirschberg, 1984; Dahl and Speers, 1985), although the mechanisms are not yet fully understood. While deasphalting requires considerable quantities of dissolved gas in the oil pool, gravitational segregation is achieved by diffusive movements of molecules of varying size in a tall oil column (Evans et al., 1971). While both these processes would result in the sinking of heavier asphaltic molecules to the bottom of the reservoir, resulting in, for example, -mats, they still cannot account for solid reservoir bitumens. Moreover, most tar-mat occurrences (e.g. Wilhelms and Larter, 1994 and references therein) are known to be from a few centimeters to a few meters in thickness with compositionally sharply defined zones, unlike a broad and discontinuous >250 m bitumen zone in Embla. However, Rogers et al. (1974) demonstrated that reservoir bitumens (asphaltene precipitates) formed by deasphalting have carbon isotopic ratios similar to the original oil, whereas residues formed by thermal alteration have significantly heavier ratios. The Embla bitumens do not have particularly heavy ratios (Table 1) and are within the normal

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 131 ratios for most North Sea oils. Therefore, deasphalting, in some form, may be somewhat important in the case of Embla.

Therefore despite several known processes, as discussed above, which can significantly alter an oil pool with respect to composition and physical properties, none of these processes can fully and convincingly explain the observed features in the Embla solid bitumens. Perhaps it is the missing pre-Jurassic geological and diagenetic history that holds the key, or it may be combination of two or more of the above processes. To assert anything more in this regard, although important, would be speculation and unfounded at this juncture. However, a hypothesis which meets most (but not all) requirements and explains most (but not all) features is proposed, with the hope that further thinking on this line might one day provide the right answer. While the original precursor of the Embla solid bitumens is believed to have been a ‘normal ’ mobile oil, the immediate precursor is most likely to have been a viscous and asphaltic phase with limited mobility. This is the key to the proposed model.

6.10 Paleo -oil emplacement and destruction in Embla : A hypothesis

The paleo-oil charge was introduced into the Embla reservoir at an intermediate diagenetic stage, possibly concurrent with the onset of quartz cementation at a depth more than about 3 km. The paleo-oil, possibly representing the first stage migration, is thought to have been aromatic-intermediate in composition (sulphur > 1%, relatively rich in resins and asphaltenes, Tissot and Welte, 1984), but mobile enough to enter the inter-kaolinite book microporosity; it is possible, however, that oil saturation was low and dissolved gas content was high. Such an oil could be generated from a marine source rock deposited in a reducing environment and the high resin/asphaltene content could be due to immaturity of the oil.

Subsequent tectonism (uplift and subsidence) could have re-defined the pore geometry (secondary large scale cavities, fractures etc. finding place) of the reservoir system As the system was closed and being continuously buried, signifi cant overpressures developed. Reservoir overpressure and a long history of petroleum emplacement may also be the reason for the high porosity preservation that we see today. Subsequent uplift and release of stress via faulting possibly caused separation of solution gas which formed a thick gas cap; and leakage of entrapped hydrocarbons, not necessarily in that order. Leakage, on the other hand, could be selective with hydrocarbons being lost preferably over higher molecular weight asphaltic species, causing therefore the residue to be resin/asphalt rich. Concurrently, the separating gas phase initiated deasphalting, and continuous burial resulted in even more gas being generated resulting in further displacement of a signifi cant portion of the oil col umn. Alternatively, the gas-flushing could have occurred as a second-stage migr ation into the system causing deasphalting.

Norwegian University of Science and Technology 132 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

In either case, the paleo gas-oil contact (GOC) could well be imagined to be at about the currently measured base of the bitumen-free zone. At this stage, the oil below the GOC is believed to have been very viscous and enriched in resin/asphalt species. The process of euhedral barite formation could also have started around this time. The reservoir system remained buried at this level (estimated about 4.5 km or greater) and exposed to high temperature regime causing further loss of light components (formation of contraction fractures) and solidification. The process of thermochemical sulphate reduction started around this time resulting in pyrite deposition. The gas-cap gas and solid bitumen’s associated light components leaked from the system, making the reservoir rock available once again for oil accumulation. We see this in form of post-Jurassic pooling of the present day oil population.

6.11 Implications of solid bitumen in the Embla Field

Based on the findings of Bharati et al. (1997a), evidently both hydrocarbon abundance and compositional variations present in the Embla Field correspond well with the petrophysical disparities. The Upper Sandstone, which has higher porosity, is rich in migrated hydrocarbons and is apparently more rhythmic and non-homogenous with respect to richness and composition, as compared to the Lower Sandstone. However, the migrated petroleum in the Upper Sandstone is richer in hydrocarbons relative to non-hydrocarbons, when compared to the Lower Sandstone petroleum. This, in all likelihood, is due to extensive asphaltene-rich solid bitumen development in the latter. Compositionally, the signature of migrated petroleum changes both horizontally across the various traps and vertically down the reservoir. This is particularly true in the Lower Sand traps LSI and LS2, where the relative non-hydrocarbon percentage increases dramatically with depth.

Solid bitumen in the Embla Field represents a lost and completely unrecoverable portion of the migrated hydrocarbons. Apart from the obvious deterioration of the reservoir quality with regard to permanently lost porosity, narrowing of pore throats and signifi cant, decrease in permeability in the bitumen zone, the formation and presence of solid bitumen has other important implications. Due to its very nature, composition and despite cement-like characteristics, both porosity (via neutron logs for example) and net ‘pay ’ (via resistivity logs for example) are overestimated. In addition to known heterogeneity and compartmentalization (Bharati et al., 1997b), this phase adds to the complexity of the reservoir with regards to optimal development of the field. Unfortunately, examination of rock material is the only reliable method, so far, to map in detail the occurrence of solid reservoir bitumen. This means that the presently understood extent of bitumen zone in the Embla Field may be underestimated, given the number and locations of samples studied. While the Lower Sandstone trap in well 26S (LS2) is clearly very poor, the prospects of the Lower Sandstone in well 20X fault block (trap LS2) in the center of the field (which was not tested) remains questionable. More so, despite the OWC in trap US2 being interpreted to be deeper than the deepest core sample analysed (Bharati et al., 1997b), the productivity of the lower 100 m thick

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 133 reservoir column (of the total about 200+ m, cf. Figure 2, Bharati, 1997) which lies in the bitumen zone, may be significantly lower than the upper bitumen-free zone. Unfortunately, this is difficult to establish from DST, as the test interval covered nearly the entire zone together.

6.12 Summary & Conclusions

The Embla bitumens have been classified into 8 different morphotypes based on textural and topographical features as observed by SEM and may be attributes of the shape, volume and size of the primary or secondary pore space that the petroleum phase occupied before solidification. This very high TOC, black and vitreous phase is at the present day emplaced as an ‘oil cement’, reducing severely the bulk porosity and permeability of the host rock. Its insolubility in organic solvents, low H/C ratio and high aromaticity indicate its condensed nature and large molecular size, although partially contradicting data is obtained by Py-GC. More than 30% of all carbon in the Embla bitumen is found to be aromatic ring carbon and aliphatic carbon is a minor component. Detailed examination of bitumen samples by SEM and TEM indicate that the process of bitumen solidification was slow, controlled and methodical and post-date all the major diagenetic events such as kaolinite precipitation and quartz cementation. The barite and pyrite mineral phases, exclusively associated with bitumen, are believed to represent the aqueous component of the migrated hydrocarbons.

The actual cause of bitumen formation is not entirely clear in the case of Embla, but deasphalting may have played an important role (certainly not exclusively), at least in providing the immediate precursor to solid bitumen. While the original precursor of the solid bitumens is believed to have been a free-flowing and perhaps a ‘normal ’ oil, its immediate precursor is thought to have been a viscous and asphaltic species rich phase with limited mobility and limited labile components. The present oil population is not related to the solid bitumen and represents an entirely independent oil charge.

6.13 Acknowledgments

Many thanks to Phillips Petroleum Co. Norway for providing the samples and co-venturers, including Fina Exploration Norway S.C.A., Norsk Agjp AS, Elf Petroleum Norge AS, Norsk Hydro Production AS, Statoil AS, TOTAL Norge AS and Saga Petroleum AS for permission to publish. Thanks also to Norwegian Research Council, Phillips Petroleum and Amoco Norway for partial financial assistance. The Department of Geology, Norwegian University of Science and Technology (NTNU), Trondheim is thanked for support and encouragement. The following are gratefully acknowledged for assistance in conducting analyses: Morten Raanes and Kjell Muller, SINTEF for SEMs, Prof. John Attard and Winfried Kuln, MR Center, SINTEF for NMR and Prof. Ragnvald H0ier and Sigmund Andersen, Dept, of Physics, NTNU for TEM. The manuscript benefited greatly from comments made by Joe Curiale,

Norwegian University of Science and Technology

■V; W: ■ A. 134 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Unocal, USA on an earlier draft. Kare Vagle, Phillips, Norway is particularly thanked for taking constant interest in my work and discussing my results openly, which has improved the quality of this work.

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Parnell, J., Carey, P. F. and Botrell, S. H., 1994, The occurrence of authigenic minerals in solid bitumens: Journal of Sedimentary Research, v. A64, p. 95-100.

Norwegian University of Science and Technology 138 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Patience, R. L., Mann, A. L. and Poplett, I. J. F., 1991, Determination of molecular structure of kerogens using 13C NMR spectroscopy: I. Effects of thermal maturation on kerogens from marine sediments: Geochimica et Cosmochimica Acta, v. 56, p. 2725-2742.

Pepper, A. S. and Dodd, T. A., 1995, Simple kinetic models of petroleum formation. Part II: oil-gas cracking: Marine and Petroleum Geology, v. 12, p. 321-340.

Raymond, A. C. and Murchisson, D. G., 1988, Effect of volcanic activity on level of organic maturation in Carboniferous rocks of East Fife, Midland Valley of Scotland: Fuel, v. 67, p. 1164-1166.

Robinson, A. and Gluyas, J., 1992, Duration of quartz cementation in sandstones, North Sea and Haltenbanken basins: Marine and Petroleum Geology, v. 9, p. 324-327.

Rogers, M. A., McAlary, J. D. and Bailey, N. J. L., 1974, Significance of reservoir bitumens to thermal maturation studies, Western Canada basin: AAPG Bulletin, v. 58, p. 1806-1824.

Ross, J. V., Bustin, R. M. and Rouzaud, J. N., 1991, Graphitization of high rank coals- the role of shear strain: experimental considerations: Organic Geochemistry, v. 17, p. 585-596.

Rouzuad, J. N., Oberlin, A. and Trichet, J., 1980, Interaction of uranium and organic matter in uraniferous sediments, in A. G. Douglas and J.R. Maxwell (eds.), Advances in Organic Geo ­ chemistry 1979: Oxford, Pergamon Press, p. 505-516.

Sassen, R., 1988, Geochemical and carbon isotopic studies of crude oil destruction, bitumen precipitation and sulphate reduction in the deep Smackover Formation: Organic Geochemistry, v. 12, p. 351-361.

Simoneit, B. R. T., Brenner, S., Peters, K. E. and Kaplan, I. R., 1981, Thermal alteration of Cretaceous black shale by diabase intrusions in the eastern Atiantic-II. Effects on bitumen and kerogen: Geochimica Cosmochimica Acta, v. 45, p. 1581-1602.

Solli, H., Schou, L., Krane, J., Skjetne, T. and Leplat, P., 1985, Characterisation of sedimentary organic matter using nuclear magnetic resonance and pyrolysis techniques, in B. M. Thomas, ed., Petroleum Geochemistry in Exploration of the Norwegian Shelf: London, Graham & Trotman, p. 309-317.

Sommer, F., 1978, Diagenesis of Jurassic sandstones in the Viking Graben: Journal of the Geological Society, v. 135, p. 63-67.

Thomas, M., 1986, Diagenetic sequences and K/Ar dating in Jurassic sandstones, Central Viking Graben: Effects on reservoir properties: Clay Minerals, v. 21, p. 695-710.

Tissot, B. P., Deroo, B. G. and Hood, A., 1978, Geochemical study of the Unita basin: formation of petroleum from the Green River Formation: Geochimica et Cosmochimica Acta, v. 42, p. 1469-1485.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 5: Embla reservoir bitumen: Chemistry, structure and origin 139

Tissot, B. P. and Welte, D. H., 1984, Petroleum formation and occurrence: Berlin, Springer- Verlag, p. 699.

Ungerer, P., Behar, F., Villalba, M., Heum, O. R. and Audibert, A., 1988, Kinetic modeling of oil cracking, in L. Matavelli and L. Novelli, (eds.), Advances in Organic Geochemistry 1987: Oxford, Pergamon Press, p. 857-868.

Wilhelms, A. and Larter, S. R., 1994, Origin of tar-mats in petroleum reservoirs. Part I: introduction and case studies, Marine and Petroleum Geology, v. 11, p. 418-443.

Williams, J. A., Bjor0y, M., Dolcater, D. L. and Winters, J. C., 1986, Biodegradation in South Texas Eocene oils- effects and aromatics and biomarkers, Organic Geochemistry, v. 10. P. 451-461.

Norwegian University of Science and Technology 140 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Doctoral Dissertation by Sunil Bharati, 1997 Paper 6: Calibration and standardization oflatroscan 141

Chapter 7: Paper 6

Calibration and standardisation of Iatroscan (TLC-FID) using standards derived from crude oils

Sunil Bharati, Geir Arne R0stum and Rita L0berg

Geolab Nor, N-7002, Trondheim, Norway

Advances in Organic Geochemistry 1993 Org. Geochem. Vol. 22, No. 3-5, pp. 835-862, 1994 Pergaraon Copyright © 1994 Elsevier Science Ltd 0146-6380(94)00086-7 Printed in Great Britain. All rights reserved 0146-6380/94 S7.00 + 0.00

Calibration and standardization of Iatroscan (TLC-FID) using standards derived from crude oils

Sunil Bharati , G hr Arne Rgstum and Rita Loberg Geolab Nor, P.O. Box 5740 Fossegrenda. 7002 Trondheim, Norway

Abstract—The TLC-FID technique, using the Iatroscan instrument, which constitutes separation and quantification of a complex mixture into various compound classes, has recently become a widely used and reliable method for characterisation of solvent extracts (particularly from reservoir rocks) and crude oils. However, there has been only limited reported research conducted aimed at calibration of the instrument and usage of standards which are relevant to the petroleum industry. This study is specifically aimed at identifying, separating, characterising, testing and developing standards, derived from natural crude oil(s), that are well suited and chromatographically pure for quantification purposes. A sample set comprising of over 30 crude oils from various basins of the world was used. The oils range widely in maturity, API gravity (8-46°), source rock type, degree of biodegradation, reservoir rock type and relative compositions. Whole oils, maltenes and asphaltenes were initially screened using Iatroscan. The process to identify suitable saturated hydrocarbons, aromatic hydrocarbons, polars and asphaltenes for the purpose of making the standard(s) included MPLC, gas chromatography, column chromatography and preparative thin-layer chromatography. Only about half the oils separate into 4 ‘clean* fractions (saturated and aromatic hydrocarbons, resins and asphaltenes) resulting in 4 well defined peaks. Analysis of the maltenes and asphaltenes shows that neither of the fractions is free of the other fraction. Pure fractions of saturated and aromatic hydrocarbons, resins and asphaltene were isolated using a combination of various analytical techniques and standards prepared. Compositional variations between the different fractions was established using GC, Py-GC and GC-MS. Several synthetic standards were prepared and tested for comparison and the implication of their use discussed. The Iatroscan TLC-FID instrument was calibrated using data from naturally derived fractions/standard mixtures and a mathematical model developed that could be used as the basis for calibration.

Key words —Iatroscan TLC-FID, petroleum, calibration, response factors, analytical accuracy, model, natural standards, synthetic standards, oil fractions

Norwegian University of Science and Technology 142 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Advances In Organic Geochemistry 1993 Org. Ceochem. Vol. 22, No. 3-5, pp. 835-862, 1994 Pergamon Copyright © 1994 Elsevier Science Ltd 0146-6380(94)00086-7 Printed in Great Britain. All rights reserved 0146-6380/94 S7.00 + 0.00

Calibration and standardization of Iatroscan (TLC-FID) using standards derived from crude oils

Sunil B ha rati , G eir Arne Rostum and Rita Loberg Geolab Nor, P.O. Box 5740 Fossegrenda, 7002 Trondheim, Norway

Abstract—The TLC-FID technique, using the Iatroscan instrument, which constitutes separation and quantification of a complex mixture into various compound classes, has recently become a widely used and reliable method for characterisation of solvent extracts (particularly from reservoir rocks) and crude oils. However, there has been only limited reported research conducted aimed at calibration of the instrument and usage of standards which are relevant to the petroleum industry. This study is specifically aimed at identifying, separating, characterising, testing and developing standards, derived from natural crude oil(s), that are well suited and chromatographically pure for quantification purposes. A sample set comprising of over 30 crude oils from various basins of the world was used. The oils range widely in maturity, API gravity (8-46"), source rock type, degree of biodegradation, reservoir rock type and relative compositions. Whole oils, maltenes and asphaltenes were initially screened using Iatroscan. The process to identify suitable saturated hydrocarbons, aromatic hydrocarbons, polars and asphaltenes for the purpose of making the standard(s) included MPLC, gas chromatography, column chromatography and preparative thin-layer chromatography. Only about half the oils separate into 4 ‘clean’ fractions (saturated and aromatic hydrocarbons, resins and asphaltenes) resulting in 4 well defined peaks. Analysis of the maltenes and asphaltenes shows that neither of the fractions is free of the other fraction. Pure fractions of saturated and aromatic hydrocarbons, resins and asphaltene were isolated using a combination of various analytical techniques and standards prepared. Compositional variations between the different fractions was established using GC, Py-GC and GC-MS. Several synthetic standards were prepared and tested for comparison and the implication of their use discussed. The Iatroscan TLC-FID instrument was calibrated using data from naturally derived fractions/standard mixtures and a mathematical model developed that could be used as the basis for calibration.

Key words —Iatroscan TLC-FID, petroleum, calibration, response factors, analytical accuracy, model, natural standards, synthetic standards, oil fractions

INTRODUCTION previous work involving the use of the TLC-FID technique using Iatroscan have relied upon synthetic The TLC-FID technique, using the Iatroscan instru­ compounds as standards to accomplish quantification. ment, is fast becoming a widely practised and reliable There are even lesser reported studies specifically method for qualitative and quantitative characteriz­ aimed at developing natural standards (standards ation of solvent extracts (particularly from reservoir derived from natural crude oils or extracts) which are rocks) and crude oils. TLC-FID generally constitutes well suited and chromatographically pure during separation of a complex mixture, such as EOM or TLC for the purpose of calibrating the Iatroscan crude oil into compound classes. Depending upon the TLC-FID instrument. Poirier et al. (1984), for ex­ chromatographic requirement and the sensitivity of ample, have used natural extract fractions to calculate the instrument, a natural organic mixture, such as a the relative response and Parish and Ackman (1985) crude oil, is typically separated into 3, 4 or even 5 have addressed the problem of calibration. In addition, fractions, each fraction itself, however, being a com ­ different laboratories have different preferences with plex mixture, though essentially all components of a regards to the choice of synthetic compounds that fraction are of similar polarity and belong to the same they employ as standards. All these factors result in compound class. Recently, there have been some poor and inaccurate inter-laboratory comparison of publications highlighting the practicality and applica ­ data. tion of Iatroscan in the petroleum industry (Goutx The present study is specifically aimed at identify­ et al., 1990; Karlsen and Larter, 1989, 1991; Poirier ing, separating, characterising, testing and developing et al., 1984; Ray et al., 1982; Selucky, 1983; standards, derived from natural crude oil(s), that are Yamamoto, 1988). However, these studies have well suited, easily accessible and chromatographically limited focus towards calibration of the instrument pure, that can be applied to Iatroscan and which are and standardization of elutionary procedures. Most relevant to the petroleum industry. The term ‘natural

Doctoral Dissertation by Sunil Bharati, 1997 I

Su n il Bharati e ta l. • •

*

14 32

Gravity

10.7 11.4 17.4 29.9 30.2 3I./6 33.5 34 cu8 20.6 23.7 28.4 ca 34.2 37.1 38.6 39.5 ca 20.8 22.1 23.4 24 24.5 26.8 27.5 42.3 43.2 44.2 44.6 45 46 API Deltaic Deltaic

Age/Type

Cretaceous/Marine Jurassic/Marine Jurassic/Marine Jurassic?/Hypcrsalinc? Jurassic/Marine Jurassic/Marine Jurassic/Marine Jurassic/Marine Jurassic/Marine Jurassic/Marine Jurassic/Marine Jurassic/Marine Cretaceous/Lacustrine Jurassic/Marine Cretaceous/Lacustrine Jurassic/Marine Cretaceous/Lacustrine Oligoccnc/Marine Cretaceous/Lacustrine Oligoccnc/Marine Jurassic/Marine

Source

L. L. L. Miocene/Marine L. L. U. L. U. U. L. U. U. U. L. U. L. U. U. U. U. — — U. Permian/Fluvial Permian/Fluvial — — — — Gravity)

API

Sandstone

Sandstone

increasing

to Agc/Lithology

Jurassic/Sandstone Jurassic/Sandstone

Jurassic/Sandstone Jurassic/Argi. Cretaceous/Sandstone Cretaceous/Sandstone Crelaceous/Sandstonc Cretaceous/Sandstone Cretaceous/Sandstone Cretaceous/Carbonate Jurassic/Sandstone Cretaceous/Sandstone Jurassic/Silty Cretaceous/Sandstone Cretaceous/Sandstone Cretaceous/Sandstone Cretaceous/Sandstone Crelaceous/Sandstonc Cretaceous/Sandstone Crelaceous/Sandstonc Crelaceous/Sandstonc Jurassic/Sandstone Jurassic/Sandstone

according Reservoir U. U. Mioccnc/Shalc L. U. L. L. L. U. U. L. L. L. ___ L. U. L. M-U. M-U. L. U. U. M. U. M. Permian/Sandstone Triassic/Dolomite Tertiary/Sandstone Triassic/Sandstone Tertiary/Sandstone Jurassic/Sandstone

{listed

tables.

study and

the text

in Graben

Maria estimates. the

Fourtecns in

Fourtecns used Platform Platform

Browse to Viking Browse visual

West/Congo West/Congo South/Congo North/Congo

Graben Graben

Field/Basin Jacinto/Maranon samples Jacinto/Maranon

relative referred

oil

San Monterey/Santa Helm/Broad Malongo Hcldcr/Broad Malongo Matzen/Vicnna Ruhlcmoor-Valendis Malongo Matzen/Vicnna Dorissa/Maranon Malongo Eich/Konigsgartcn Midgard/Sklinnubanken Tsagaanels Jibaro/Maranon Shiviyacu/Maranon San Haltcnbankcn Selmo-Batman Central Shiviyacu/Maranon Patroclus/Enomanga Troll/Horda TroII/Horda Snorrc/N. Challis/N. Jabiru/N. Adcrkiaa/Vienna Central Tirrawarru/Coopcr are of

numbers

quoted Details

oil

I.

as

Data

Table same Europe Europe

Africa Africa Africa Africa

America Asia Europe Europe

the

Europe Europe Europe Europe Europe Europe Europe Europe Europe Europe

W. W. Europe W. America America America America America America N.

W. available.

not S. S. S. S. S. S.

Location not

are

I Mongolia, U.S.A., Netherlands, Peru, Peru, Peru, Peru, Ai.strlaia Norway, Norway, Angola, Netherlands, Peru, Austria, Norway, Norway, Norway, Angola, Austria, Norway, Peru, Norway, Austria, Australia Australia Angola, Germany, Turkey, Angola, Germany, Australia oils

these

column

for in

Code

data

1-04 5-07 7-28 2-05 3-06 4-27 6-08 8-09 9-30 10-10 il-il 12-12 13-13 14-26 15-03 16-31 17-14 18-15 19-25 20-16 26-21 27-22 28-23 29-24 30-01 31-02 21-17 22-29 23-18 24-19 25-20 numbers

Sample Gravity

serial

API

1 The 5 7 2 3 4 6 8 9

No. 16 18 10 II 12 13 14 IS 17 19 20 26 27 28 29 30 31 21 22 23 24 25

S. •Actual Note:

Norwegian University o f Science and Technology

& 18 144 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatroscan 837

standards’ includes the four principle fractions of collected and processed either using an integrator or, crude oil/solvent extract viz. saturated hydrocarbons, as in our case, using a data acquisition system such aromatic hydrocarbons, resins and asphaltenes. For as Multichrom v2. Raw data is automatically con ­ this purpose, a sample set comprising 31 crude oils verted into mg/g rock units and relative percentages from various basins/fields (onshore and offshore) of (see later). Although no whole rocks were analysed the world (North America, South America, Europe, in the present study, the additional procedure related West Africa, Asia and Australia) was used (Table 1, to their analyses is included in Appendix 1 for the oils listed according to increasing API gravity). The benefit of the readers. oils range widely in (1) maturity (low maturity to high The oils were deasphaltened using n-pentane, ex­ maturity, but not condensate stage), (2) API gravity cept in the case of asphaltene solubility experiments. (8'-46 =), (3) source rock type (marine clastic, marine Four samples were selected for asphaltene solubility carbonate, lacustrine, saline), (4) degree of bio ­ tests (oils 5, 10, 16 and 19, which cover a wide range degradation (none to strong), (5) reservoir rock type of API gravity) and each of these oils were subjected (sandstone, siltstone and carbonate) and (6) relative to asphaltene precipitation using six different solvents compositions. The final objective is to successfully viz. n-pentane (which is normally used), n-hexane, isolate one fraction each of saturated hydrocarbons, n-heptane, n-octane, n-nonane and n-decane. The aromatic hydrocarbons, NSO compounds and purpose was to monitor the dependence, if any, of asphaltenes, pure from the TLC-FID point of view, asphaltene composition on the solvent chain length, and gravimetrically prepare standards for Iatroscan which also implies increasing boiling point of the calibration. In addition, an attempt has been made solvent. In addition, our intention was to investigate to refine the existing procedure for analysis, which and review the compositions of asphaltenes result­ includes a mathematical model to determine effective ing from precipitation using solvents other than response factors and their relationships, which can be n-pentane, and to establish whether an asphaltene easily and readily employed by other users. fraction can be obtained through conventional precipitation method which is the same or close to ANALYTICAL PROCEDURES the asphaltene fraction defined by TbC-FID. Such a fraction would be expected to result in only one peak Whole oil samples and individual fractions were on analysis using the Iatroscan, following the normal analysed by Iatroscan at several stages during the elution procedure. course of the study. The following procedure for Maltenes were separated into fractions (saturated Iatroscan analysis (using Iatroscan MK-5) was found and aromatic hydrocarbons and polars) using MPbC to be most suitable for analyses of a variety of as described by Radke et al. (1980) (each of the oils samples and therefore recommended for general use was analysed with one parallel to increase the amount (see also Karlsen and barter, 1989). In the case of of resulting fractions). However, one significant devi­ oils, 4-5 mg of whole oil is accurately weighed into ation from the routine method was during collection a 2 ml GC glass vial, 0.5 ml of solvent added and of the fractions. As the purpose in the present study the vial sealed. After being dissolved in the solvent, was to obtain pure fractions using MPbC and not oils can be analysed immediately. Prior to sample quantification, the initial and final cuts (about 10% spotting, the chromarods (quartz Sill, silica gel each) of each of the fractions (saturated and aromatic powder coated) are first activated by passing through hydrocarbons and resins) were discarded (which are the FID flame (in the normal analysis mode —30 s/ normally collected) by closely monitoring the RI scan). 2 pi sample is then spotted (using a 2 pi syringe) detector in the case of saturated hydrocarbons and using preferably an auto-spotter (SES 3202/IS-01) u.v. detector in the case of aromatic hydrocarbons. and continuously blowing the spot with nitrogen or This was done to ensure that minimal amounts of un­ air to accomplish immediate drying and prevent band­ wanted components are present in a fraction. Selected spreading. This results in sharper and narrower peaks. saturated and aromatic hydrocarbon fractions were The development tanks containing the solvents are characterised by gas chromatography, while selected lined with chromatographic paper on the inside back polar and asphaltene fractions were characterised by and side walls, from top to bottom. The following pyrolysis-gas chromatography. The purity of the elution procedure is used: 35 min in n -hexane (to two hydrocarbon fractions was tested using gas separate saturated hydrocarbons), air dry for 2 min, chromatography-mass spectrometry, while the com ­ 14 min in toluene (to separate aromatic hydrocarbons), position of the selected resin and asphaltene fractions air dry for 2 min, 4 min in dichlorometane : methanol, was established using pyrolysis-gas chromatography- 93:7 v/v (to separate resins) and finally 90s at 60°C. mass spectrometry. The procedures followed were Asphaltenes are retained at the spotting point. If it is according to the Norwegian Industry Guide (1993). intended to separate mono- and diaromatic hydro ­ However, the selection of ions for GC-MS was made carbons from poly-aromatic hydrocarbons (Karlsen keeping in mind the primary objective of major con ­ and barter, 1991) then insert the step of elution using taminant identification. As the analysis was carried cyclo-hexane for 14 min before eluting with toluene out in high resolution mode, the number of ions was for 8 min. The samples are analysed and the data restricted to 10. However, in separate runs, a few ions

Doctoral Dissertation by Sunil Bharati, 1997 Paper 6: Calibration and standardization oflatroscan 145

838 Sunil Bharati et al.

characteristic for biomarkers were also detected. The silica with F254 fluorescence activator). The elution ions specified during GC-MS are listed in Appendix 2. procedure employed was the same as that of Iatroscan. Similarly, the ions for Py-GC-MS were selected in The zone separation was checked using a u.v. detector such a way so as to indicate the presence of saturated at 254 nm wavelength (cf. Plate 1) and portions with hydrocarbons, aromatic hydrocarbons (mono-, di- different fractions scrapped using a spatula. The 4 and poly-aromatic) and the sulphur bearing thio ­ silica gel fractions were then extracted using phenes. Additionally, the selected masses would also DCM:MeOH (93:7 v/v), weighed and analysed by indicate the type of hydrocarbons that have the maxi­ Iatroscan. mum tendency to be retained in the polar fraction. No significance was placed on masses specific to com ­ RESULTS AND DISCUSSION monly known biomarkers as these are not expected to occur in these fractions, although m/z 163, 231 Composition of oils , asphaltenes and maltenes and 253 were included to get a general picture of Preliminary screening of all oils using Iatroscan their presence. The list of the masses specified during (Table 2) shows that the composition of the oils is Py-GC-MS is presented in Appendix 3. highly variable, as is their total hydrocarbon (satur­ In addition, whole oil samples and selected resin ated and aromatic) content. The relative percentage fractions were analysed using preparative thin-layer of saturated hydrocarbons varies from about 3 to chromatography (PTLC), the main objective of this 82%, aromatic hydrocarbons vary from about 13 to being to purify the resin fractions by separating out 54%, resins vary from about 2 to 46% and asphalt­ aromatic hydrocarbons from the resins. The oils and enes vary from about 0.1 to 26% (Table 2). Never­ resin fractions from MPLC were first dissolved in di- theless, hydrocarbons are dominant in all the oils, chloromethane and spotted along a straight line (as varying from about 76 to 98%, except for one oil a band) on a ready-made TLC plate (Merck DC-A1 which has a total hydrocarbon content of only 42% foil coated with silica gel 60, gel thickness 0.2 mm, relative to resins and asphaltenes. The quality of

10cm

Plate. 1. On left are the results of TLC development of various fractions from MPLC (saturated hydrocarbons —SAT, aromatic hydrocarbons —ARO, resins—NSO and asphaltene—ASP and whole oil— EOM). On right is the TLC development of the MPLC resin fraction, which splits into 2 zones— resins and aromatics. Zone 1 marks the line of sample spotting, where the asphaltenes are also retained, Zone 2 is resins. Zone 3 is aromatic hydrocarbons and Zone 4 is saturated hydrocarbons which cannot be detected by fluorescence.

Norwegian University of Science and Technology

T 146 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatroscan 839

Table 2. Relative percentages of separated fractions by Iatroscan Table 3. Relative percentages of separated fractions by Iatroscan from whole oils from asphaltenes Sat Aro Total Total Sat Aro Total Total HC HC Resins Asph HC Polars HC HC Resins Asph HC Polars Oil No. % % % % % % Oil No. % % % % •/. % 1 72.8 25.3 1.6 0.3 98.1 1.9 1 40.0 50.0 10.0 40.0 60.0 2 82.2 13.9 1.6 2.3 96.1 3.9 2 64.7 35.3 100.0 3 77.3 21.1 1.3 0.3 98.4 1.6 3 15.4 28.8 55.8 15.4 84.6 4 62.3 19.3 11.8 6.6 81.6 18.4 4 11.5 17.4 71.1 11.5 88.5 5 19.7 39.7 15.9 24.7 59.4 40.6 5 71.4 28.6 100.0 6 23.7 38.8 10.9 26.6 62.5 37.5 6 5.1 4.9 90.0 5.1 94.9 7 34.1 54.2 8.0 3.7 88.3 11.7 7 32.4 67.6 100.0 8 34.2 42.8 8.7 14.3 77.0 23.0 8 100.0 100.0 9 44.6 45.2 6.5 3.7 89.8 10.2 9 37.8 62.2 100.0 10 46.4 40.5 6.7 6.4 86.9 13.1 10 32.8 67.2 100.0 11 49.8 42.3 7.2 0.7 92.1 7.9 11 49.5 50.5 100.0 12 33.4 44.3 17.6 4.7 77.7 22.3 12 14.8 10.3 34.0 40.9 25.1 74.9 13 53.0 42.2 3.5 1.3 95.2 4.8 13 49.2 50.8 100.0 14 64.3 31.1 3.7 0.9 95.4 4.6 14 45.0 55.0 100.0 15 58.3 34.8 5.4 1.5 93.1 6.9 15 37.4 62.6 100.0 16 56.2 34.2 6.8 2.8 90.4 9.6 16 6.4 19.9 73.7 6.4 93.6 17 56.5 37.4 4.7 1.4 93,9 6.1 17 42.7 57.3 100.0 18 62.5 31.1 5.0 1.4 93.6 6.4 18 25.9 9.6 41.2 23.3 35.5 64.5 19 70.0 25.7 2.3 2.0 95,7 4.3 19 27.3 72.7 100.0 20 61.3 35.4 2.9 0.4 96.7 3.3 20 53.3 16.4 26.6 3.7 69.7 30.3 21 78.5 20.0 1.4 0.1 98.5 1.5 21 32.4 56.8 10.8 32.4 67.6 22 78.3 19.3 2.2 0.2 92.6 2.4 22 53.7 35.2 11.1 53.7 46.7 23 59.3 35.7 4.5 0.5 95.0 5.0 23 17.0 59.1 23.9 17.0 83.0 24 76.3 22.2 1.2 0.3 98.5 1.5 24 100.0 100.0 25 47.5 44.2 6.1 2.2 91.7 8.3 25 8.9 9.6 30.6 50.9 18.5 81.5 26 57.0 37.3 5.3 0.4 94.3 5.7 26 45.5 54.5 100.0 27 2.9 39.3 46.5 11.3 42.2 57.8 27 — — — 100.0 — 100.0 28 56.8 19.4 12.7 11.1 76.2 23.8 29 42.6 33.5 18.3 5.6 76.1 23.9 30 66.4 22.6 10.1 0.9 89.0 11.0 31 50.1 33.2 13.9 2.8 83.3 16.7 individual fractions in these oils to separate into distinct groups within the given time for separation (35 and 14 min for hydrocarbons and 4 min for non ­ chromatography is generally good with the 4 fractions hydrocarbons), and the restricted length available for (saturated hydrocarbons, aromatic hydrocarbons, separation/elution (10 cm). resins and asphaltenes) giving 4 prominent peaks Deasphalting of oils shows that except for a few [Fig. 1(a)], except in a few cases where a continuum oils, most oils contain asphaltenes in the range 1-4% between the two hydrocarbon fractions [Fig. 1(b)] by weight. However, in case of several oils, a sub­ or a continuum between the two non-hydrocarbons stantial portion of the asphaltene remained locked [Fig. 1(c)] fractions is present. This is attributable to within the filter and was impossible to remove even the composition of these oils and the inability of the by repeated washing using either dicholoromethane

Fig. 1. TLC-F1D chromatograms of whole oils, (a) A typical oil sample with 4 prominent peaks representing 4 major components viz. saturated hydrocarbons (SAT), aromatic hydrocarbons (ARO), resins (POL) and asphaltenes (ASPH). (b) An oil sample with a continuum between the 2 hydrocarbon fractions, SAT and ARO. (c) An oil sample with a continuum between the 2 non-hydrocarbon fractions, POL and ASPH.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 6: Calibration and standardization oflatroscan 147

840 Sunil Bharati et a!.

0 10 0 10 0 10 abed Fig. 2. TLC-FID chromatograms of asphaltenes, (a) An asphaltene fraction containing significant amounts of hydrocarbons (SAT and ARO). (b) A typical asphaltene fraction consisting mainly of resins (POL) and asphaltenes (ASPH). (c) Chromatogram of an asphaltene with least amount of other components, (d) A typical asphaltene from low API gravity oils, exhibiting a strong continuum between the 2 non-hydrocarbon components, POL and ASPH.

or dichloromethane : methanol (93:7 v/v). This loss then it would mean that the fraction resulting from is even more significant for oils rich in asphaltenes conventional pentane precipitation, which we com­ (more than 10% by weight) such as oils 4, 5, 6, 8, 10 monly refer to as asphaltene, is compositionally and 27. The analysis of asphaltenes using Iatroscan the same as the asphaltene defined by the Iatroscan (Table 3) shows that none of the pentane precipitated technique. Apparently, asphaltenes precipitated by asphaltene fractions result in pure “asphaltene” n-pentane are compositionally different to the frac­ fractions from the TLC-FID point of view, as also tion defined as asphaltene by Iatroscan. The pentane documented earlier (Karlsen and barter, 1991). Several precipitated asphaltene nearly always consists of two of the asphaltene fractions analysed (such as from oils principle fractions —resins and asphaltenes (Table 3). 1,2,3,20,21,22,23 and 24) give a misleading picture It must also be noted that accurate integration of (Table 3) due to very low absolute concentrations the resin and asphaltene peaks from Iatroscan is of all the components and therefore their data are not possible in the case of some samples due to the considered to be insignificant/unreliable. However, in several others, the asphaltene precipitated by Table 4. Relative percentages of separated fractions by Iatroscan «-pentane from oils such as 4, 6, 12, 16, 18 and 25, from mallenes continue to retain substantial amounts of hydro ­ Sat Aro Resins Asph Total Total carbons, and their chromatograms show up to 4 Oil No. HC HC HC Polars distinct peaks [e.g. Fig. 2(a)]. It seems though that 1 77.6 20.4 1.7 0.3 98.0 2.0 2 87.6 10.1 1.8 0.5 97.7 2.3 saturated hydrocarbons have a greater tendency of 3 78.7 19.9 IJ 0.1 98.6 1.4 being retained in the pentane precipitated asphaltenes, 4 54.7 9J 16.4 19.6 64.0 36.0 relative to aromatic hydrocarbons (Table 3). In most 5 24.7 48.8 16.4 19.6 64.0 36.0 6 28.9 57.9 12.9 0.3 86.8 13.2 of the samples, however, the pentane precipitated 7 30.9 54.8 13.4 0.9 85.7 14.3 asphaltene splits into mainly resins and asphaltenes, 8 40.0 49.9 9.5 0.6 89.9 10.1 9 42.5 45.3 11.6 0.6 87.8 12.2 as shown in Fig. 2(b). In none of the samples did 10 49.6 41.5 8.4 0.5 91.1 8.9 the pentane precipitated asphaltene fraction result in 11 54.2 35.1 10.4 0.3 89.3 10.7 only one (asphaltene) peak [example with the most 12 34.0 43.0 19.5 3.5 77.0 23.0 13 58.1 32.6 8.8 0.5 90.7 9.3 prominent asphaltene peak relative to resins is shown 14 69.9 22.9 6.7 0.5 92.8 7.2 in Fig. 2(c)]. Iatroscan separation of asphaltenes from 15 61.2 31.5 6.7 0.6 92.7 7.3 nearly all of the low API gravity oils, which are also 16 58.8 28.4 10.4 2.4 87.2 12.8 17 58.2 33.5 7.7 0.6 91.7 8.3 generally the richest in asphaltenes (Table 3), results 18 62.7 28.4 8.3 0.6 91.1 8.9 in a continuum between the resins and asphaltenes 19 74.4 20.9 4.2 0.5 95.3 4.7 20 73.8 20.6 5.1 0.5 94.4 5.6 [e.g. Fig. 2(d)]. This is indicative of either compos ­ 21 82.2 15.5 2.0 0.3 97.7 2.3 itional similarity between the resins and asphaltenes 22 83.5 12.0 3.4 1.1 95.5 4.5 of these oils or inability of the components to separate, 23 64.5 30.0 4.4 1.1 94.5 5.5 24 71.0 16.5 3.5 9.0 78.5 12.5 as no overloading of samples occurred. 25 52.9 37.0 7.8 2.3 89.9 10.1 Had the pentane precipitated asphaltene fraction 26 82.6 13.9 2.9 0.6 96.5 3.5 resulted in only one peak on analysis using Iatroscan, 27 — 37.9 59.6 2.5 37.9 62.1

Norwegian University of Science and Technology 148 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatroscan 841

0 10 0 10 8 b c d Fig. 3. TLC-FID chromatograms of maltenes. (a) A typical maltene fraction, rich in hydrocarbon components SAT and ARO. (b) A maltene fraction with a dominant saturated hydrocarbon peak (SAT), (c) A maltene fraction with a dominant aromatic hydrocarbon peak (ARO). (d) A maltene fraction with significant amounts of non-hydrocarbons present (POL and ASPH).

continuum, and the data therefore can be quite (174°C) and consequently limited capacity of the erroneous. Based on the results and the above rota-vapour to remove the solvent. considerations, asphaltenes from oils 4, 5, 7, 8, 10, 16 From the qualitative point of view, both the and 19 are thought to have the best potential for use asphaltenes and maltenes of each oil are composition- as standards. ally very similar, resulting in nearly identical TLC- Iatroscan analysis of maltenes (Table 4) show that FID chromatograms for a given oil, for all solvents hydrocarbons are the most abundant species, typically between 90 and 98% and generally over 77% of the total maltene fraction [Fig. 3(a)], except for one Table 5. Asphaltene solubility experiment: gravimetric weights of resulting maltenes and asphaltenes using different solvents sample (sample 27). The composition of the hydro ­ Oil Asp Mall Asp Malt Loss carbons however, is highly variable with saturated Sample (mg) (mg) (mg) <%) (%) (%) hydrocarbons occurring in the range of about Pentane 25-81% [Fig. 3(b) shows a sample rich in saturated Oil 5 47.3 8.1 33.8 17.12 71.46 11.42 hydrocarbons] with one exception (no saturated Oil 10 45.8 4.1 36.8 8.95 80.35 10.70 Oil 16 45.5 1.0 37.4 2.2 82.20 15.60 hydrocarbons detected in sample 27) and aromatic Oil 19 47.7 0.9 34.0 1.89 71.28 26.83 hydrocarbons ranging about 10-57% of the total Hexane content [Fig. 3(c) shows a sample rich in aromatic Oil 5 48.1 9.5 34.1 19.75 70.89 9.36 hydrocarbons]. Resins or polar compounds are in Oil 10 41.9 3.3 35.9 7.88 85.68 6.44 Oil 16 51.5 0.3 43.5 0.58 84.47 14.95 most cases minor components (generally 1-8%) but Oil 19 49.5 0.8 37.5 1.62 75.76 22.62 occur in larger amounts in a few samples (10-16%) Heptane [Fig. 3(d) shows a sample rich in resins]. One exception Oil 5 55.8 11.4 40.2 20.43 72.04 7.53 is sample 27 which contains about 59% resins. Oil 10 46.6 3.7 39.1 7.94 83.91 8.15 Oil 16 59.0 0.5 50.0 0.85 84.75 14.40 Asphaltenes, which ideally should not be detected Oil 19 49.6 0.7 13.9* 1.41 — — in maltenes, occur in all maltenes although their percentage is small—ranging about 0.1-3%, with Oil 5 41.7 8.1 21.5 19.42 51.56 29.02 3 exceptions (oils 4, 5 and 24). Oil 10 61.0 4.5 50.4 7.38 82.62 10.0 Oil 16 51.2 0.3 41.0 0.59 80.08 19.33 Asphaltene solubility lest Oil 19 48.7 1.1 14.9* 2.26 — — Nonane Table 5 shows the results of the asphaltene solu­ Oil 5 61.2 12.5 37.5 20.42 61.27 18.31 bility experiment and the amount of asphaltene yields Oil 10 45.2 29.8 35.8+ 79.20 Oil 16 53.5 3.6 42.1 6.73 78.69 14.58 by using 6 different solvents. Apparently, there is little Oil 19 48.6 0.5 32.9 1.03 67.70 31.27 change in the relative yields of asphaltenes from each of the 4 oils when different solvents are used; this Oil 5 51.4 108.3+ 143.5+ is also true for maltenes [Fig. 4(a-d)]. Data for Oil 10 46.5 36.6+ 267.5+ Oil 16 47.3 2.2 95.3+ 4.65 n-decane is incomplete/erroneous due to difficulties Oil 19 48.8 6.3 98.5+ 12.91 — — encountered during solvent evaporation, these being •Loss during separating asphaltene from oil. attributable to very high boiling point of n -decane t Impossible to evaporate the solvent completely.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 6: Calibration and standardization qflatroscan 149

842 Sunil Bharati et at.

(a) SAMPLE 5 (c) SAMPLE 16

---♦ ~— — *♦ —

♦ Asphaltene ■ Maltene

SAMPLE 10 SAMPLE 19

80 —~ ♦ — — -----♦

40 —

20 -

Carbon atoms in solvent (n-alkane) Fig. 4. Relative percentages of asphaltene and maltene yields for 4 different oils (samples 5, 10, 16 and 19) on deasphaltening using n-pentane, n-hexane, n-heptane, n-octane, n-nonane and n-decane.

except n-decane. Maltenes resulting from n-pentane material (Table 6), even after the solvent removal up to n-nonane contain mainly hydrocarbons, but procedure [Fig. 5(b)]. This effect is also noticed in the also noticeable amounts of resins and asphaltenes case of asphaltenes, as asphaltenes resulting from [Fig. 5(a)], In the case of n-decane, significant amount n-pentane up to n-nonane precipitation are nearly of the solvent is apparently retained with the sample free of any saturated hydrocarbons [Fig. 5(c)] while

0 10 0 10 bed Fig. 5. Iatroscan analysis of maltene and asphaltene fractions resulting from deasphaltening of oils using various solvents. Typical chromatograms showing (a) representative maltene of n-pentane to n-nonane precipitation, (b) maltene of n-decane precipitation, (c) representative asphaltene of n-pentane to n-nonane precipitation and (d) asphaltene of n-decane precipitation.

Norwegian University of Science and Technology 150 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatrcscan 843

Table 6. Asphaltene solubility experiment: results of TLC-FID analyses of mallcnc and asphaltene fractions— relative percentages of separated fractions Maltenes Asphaltenes Sample Sat% Aro% Pot% Asp% Sat% Aro% Pol% Asp% Pentane Oil 5 24.8 62.7 11.9 0.6 26.6 73.4 Oil 10 46.7 49.9 3.3 0.1 45.6 54.4 Oil 16 58.8 33.0 7.5 0.7 52.9 47.1 Oil 19 71.6 24.5 3.8 0.1 — — 50.6 49.4 Hexane Oil 5 24.8 63.4 11.3 0.6 27.4 75.8 Oil 10 44.9 49.5 5.2 0.4 37.1 62.9 Oil 16 55.9 35.4 7.7 1.0 68.6 31.4 Oil 19 69.0 27.1 3.7 0.2 — — 54.1 45.9 Heptane Oil 5 24.7 65.8 9.2 0.4 24.2 75.8 Oil 10 47.2 48.2 4.4 0.2 32.7 67.3 Oil 16 55.2 36.3 7.6 0.9 78.4 21.6 Oil 19 74.8 20.2 4.8 0.2 — — 66.1 33.9

Oil5 27.7 57.4 14.6 0.3 4.0 10.5 28.5 57.0 Oil 10 41.6 53.4 4.8 0.2 40.2 59.8 Oil 16 56.0 35.1 8.1 0.8 82.5 17.5 Oil 19 73.0 20.3 6.5 0.2 — — 68.1 31.9 Nonane OilS 21.7 63.3 14.6 0.4 32.8 67.2 Oil 10 45.1 49.1 5.3 0.4 45.1 54.9 Oil 16 58.6 30.9 9.5 1.0 75.0 25.0 Oil 19 72.5 23.0 4.2 0.3 — — 55.8 44.2

OilS 68.2 27.6 3.8 0.3 51.5 15.7 32.8 Oil 10 71.6 26.1 2.1 0.2 70.8 8.7 10.5 10.0 Oil 16 87.5 9.4 2.6 0.5 78.3 9.4 11.2 11.1 Oil 19 86.1 12.7 1.1 0.1 73.9 — 16.0 10.1

the asphaltene fraction resulting from n -decane has a 22 and 30) were selected for fresh deasphalting and conspicuous saturated hydrocarbon peak [Fig. 5(d)]. separation of maltenes into fractions using MPLC Apparently, no significant compositional differences (Radke et al., 1980). The selection was made on the are obtained by using solvents other than that basis that at least about two “clean and pure” (from normally used (n -pentane), except for n -decane. In TLC-FID point of view) fractions each of saturated any case, this exercise was not helpful in obtaining hydrocarbons, aromatic hydrocarbons, resins and a “purer” asphaltene fraction from the TLC-FID asphaltenes would be obtained from these oils. The point of view. compositions of the oils and the relative percentages of the various fractions are shown in Table 7, Conventional MPLC separation although one must bear in mind that the data of Based on the results obtained from whole oil Table 7 are not completely representative of the true and maltene analyses, 7 samples (oils 1, 5, 7, 16, 19, composition, due to discarding of the initial and final

Table 7. Composition and relative percentages of chromatographic fractions from MPLC Oil Sat Pol Asp Total Loss* Loss* Sal Pot Asp Sample (mg) (mg) (mg) (mg) (mg) (mg) (mg) (%) (%) <%) (%) (%) Oil 1 94.6 34.9 18.0 0.9 13.0 66.8 27.8 29.4 52.2 27.0 1.3 19.5 la 101.8 39.9 13.8 1.1 7.0 61.8 40.0 39.3 64.5 22.4 1.8 11.3 Oil 5 91.8 15.6 19.8 13.5 22.0 70.9 20.9 22.8 22.1 27.9 19.0 31.0 5a 104.9 21.5 23.4 15.5 25.1 85.5 19.4 18.5 25.1 27.4 18.1 29.4 Oil 7 107.2 38.1 23.9 15.0 9.8 86.8 20.4 19.0 43.9 27.5 17.3 11.3 7a 109.3 32.4 27.9 14.6 11.4 86.3 23.0 21.0 37.6 32.3 16.9 13.2 Oil 16 93.4 41.9 17.9 9.8 1.5 71.1 22.3 23.9 58.9 25.2 13.8 2.1 16a 105.3 47.3 19.7 14.1 2.1 83.2 22.1 21.0 56.8 23.8 16.9 2.5 Oil 19 95.7 52.4 13.4 3.6 1.8 71.2 24.5 25.6 73.6 18.8 5.1 2.5 19a 97.2 54.5 13.4 3.0 3.6 74.5 22.7 23.4 73.2 18.0 4.0 4.8 Oil 22 96.3 49.8 7.8 1.8 1.4 60.8 35.5 36.9 81.9 12.8 3.0 2.3 22a 98.1 49.8 7.8 2.1 1.4 61.1 37.0 37.7 81.5 12.8 3.4 2.3 Oil 30 111.5 515 18.9 15.6 3.1 90.1 21.4 19.2 58.3 21.0 17.3 3.4 30a 126.7 59.4 26.1 19.1 3.7 108.2 18.45 14.6 54.9 24.1 17.6 3.4 •The loss indicated includes the inherent loss related to the MPLC technique (estimated 5-10%) +Ioss due to discardation of 10% each of the initial and final cuts of the saturated and aromatic hydrocarbon and resin fractions (cf. analytical procedures).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 6: Calibration and standardization oflatroscan 151

844 Sunil Bharati el al.

Table 8. Results of TLC-F1D analysis of chromatographic fractions clean and contain insignificant or no aromatic hydro ­ from MPLC: relative percentages of separated fractions carbons and/or resins as impurities [an example Sat Aro Pol Asp shown in Fig. 6(a)]. In the case of oils 16, 19 and Sample (%) MPLC fraction (%) <%) (%) 22, where 99-100% of the material is reported as Saturated Oil I 99.0 0.5 0.5 — hydrocarbons Oil 5 94.0 5.3 0.7 — saturated hydrocarbons, there seems to be a substan­ Oil 7 67.4 32.3 0.3 — tial portion of saturated hydrocarbons which tends to Oil 16 99.7 0.3 elute in the aromatic hydrocarbon region, the latter Oil 19 100.0 Oil 22 100.0 being “dragged ” forward as shown in Fig. 6(b). The Oil 30 81.8 15.9 2.3 — dragged material is suspected to be mainly saturated, Aromatic Oil 1 7.1 91.8 1.1 — but weakly aromatic in nature, possibly involving hydrocarbons Oil 5 — 98.0 1.9 0.1 compounds such as alkyl with long alkyl Oil 7 — 98.3 1.7 Oil 16 97.6 2.4 chains. In some of the saturated hydrocarbon frac­ Oil 19 99.5 0.5 tions, however, there is a distinct separation into Oil 22 99.2 0.8 saturated and supposedly “weakly aromatic” saturated Oil 30 1.1 96.9 2.0 — hydrocarbon portions (oils 7 and 30) [Fig. 6(c)]. Resins Oil 1 63.9 36.1 ___ OilS 68.2 31.8 — Aromatic hydrocarbon fractions from MPLC are Oil 7 70.3 29.7 relatively free of saturated hydrocarbons, except Oil 16 61.7 38.3 for oils 1 and 30 where minor amounts of saturated Oil 19 64.3 35.7 Oil 22 48.4 51.6 hydrocarbons can be observed (Table 8). However, Oil 30 — 66.7 33.3 — all the aromatic hydrocarbon fractions obtained by Asphaltenes Oil 1 40.1 52.9 6.7 0.3 MPLC contain minor amounts of resins (0.5-2%) OilS 100.0 [Fig. 7(a)]. In the case of resins obtained by MPLC, Oil 7 15.7 19.6 51.8 12.9 Oil 16 54.2 45.8 all the fractions split into two distinct peaks during Oil 19 56.2 43.8 Iatroscan analysis, with one eluting as an aromatic Oil 22 76.2 16.0 7.5 0.3 Oil 30 — 31.6 — 68.4 hydrocarbon peak and the other as the resin peak [Fig. 7(b)]. As this bimodality occurred in all fractions and the qualitative results for all the resin fractions cuts of each fraction (cf. analytical procedure for are very similar, it is believed that this is either due MPLC). Nevertheless, some general and relative to the separation procedure adopted during MPLC, differences in the oil compositions are apparent. Oils where the elution of aromatic hydrocarbons may not 1, 7, 16, 19, 22 and 30 are relatively rich in hydro ­ be complete, or that some of the aromatic hydro ­ carbons; oils 5,1, 16 and 30 are rich in resins; while carbon and resin species are closely related with oils 1, 5 and 7 are rich in asphaltenes. The purity of respect to their structure and polarity. If the latter is all the resulting fractions (7 samples each of saturated true, then clearly the small differences in their physical hydrocarbon, aromatic hydrocarbon, resin and properties are detected by TLC-FID elution, but asphaltene fractions) was established using Iatroscan, apparently not by the MPLC elution procedure. the results of which are presented in Table 8. Except The results for the asphaltene fractions are of vari­ for the saturated fractions from oils 5, 7 and 30, able quality (Table 8). In most cases, the contamin ­ the other saturated hydrocarbon fractions are rather ation is rather significant in form of minor amounts

a b c Fig. 6. Iatroscan analysis of saturated hydrocarbon fractions obtained by MPLC separation, (a) A pure saturated hydrocarbon fraction, (b) Saturated hydrocarbons slightly contaminated by aromatic hydro ­ carbons. (c) Saturated hydrocarbons contaminated by "weakly aromatic ” compounds.

Norwegian University of Science and Technology 152 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatroscan 845

Fig. 7. Examples showing TLC-F1D chromatograms of (a) a pure aromatic hydrocarbon, (b) a typical resin and (c) a relatively pure asphaltene fraction.

of hydrocarbons or resins. However, asphaltene frac­ More importantly, the principle resin peak does not tions from oils 5, 19 and 30 are rich in asphaltenes, split into 2 components and the resulting fraction as also noted earlier, the latter two being contamin ­ is considered to be clean and uncontaminated. The ated by resins. One asphaltene however, apparently second fraction (NSO-ARO), however, also contains gives good results (oil 5) and as seen in Fig. 7(c), a dominant component, apparently resins but which no hydrocarbons or resins seem to be present as should to be of a different composition, and some contaminants. hydrocarbons [Fig. 8(b)]. Nevertheless, this exercise suggests that the resin fraction resulting from MPLC Preparative thin-layer chromatography (PTLC) and which splits into two distinct components on As noted above, all the resin fractions resulting Iatroscan analysis, can be further separated into two from MPLC separation split into two peaks on fractions on a preparative scale, as shown in Plate 1. Iatroscan analysis, one peak indicative of aromatic For comparison, the results of TLC separation of all hydrocarbons and the other of resins. The selected the fractions and whole oil using a TLC plate are also resin fractions for preparative TLC were from oils 5 shown in Plate 1. and 16, and each resin fraction resulted in 2 fractions Subsequent separation of all oils using preparative (aromatic hydrocarbons or NSO-ARO and “pure” TLC plates and the same elution procedure as resins or NSO-NSO). The resulting pure resin employed in Iatroscan, shows that the four principle fraction (NSO-NSO) is characterised by a dominant fractions separate well and the u.v. detector (254 resin peak and a minor asphaltene peak [Fig. 8(a)]. and 356 nm) showed three distinct zones contain ­ ing aromatic hydrocarbons, resins and asphaltenes (saturated hydrocarbons do not fluoresce) (Plate 1). Analysis of the four principle fractions from MPLC showed that the saturated hydrocarbons separated into two zones —one of major saturated hydrocarbons and one of minor aromatic hydrocarbons. The aromatic hydrocarbons separate into two fractions — one major aromatic hydrocarbons and one minor resins, and perhaps one minor saturated hydrocarbon zone, but this is difficult to establish as saturated hydrocarbons are not possible to detect on a u.v. detector. The resin fraction clearly separates into 2 equally dominant fractions —aromatic hydrocarbons and resins. Finally, the asphaltenes separate into mainly asphaltenes and minor resins, aromatic hydro ­ carbons and probably minor amounts of saturated hydrocarbons. Composition and purity of the separated fractions Fig. 8. Iatroscan analysis of the separated resin fractions using preparative-TLC. (a) The pure resin fraction Gas chromatography of the 5 saturated hydro ­ (NSO-NSO) and (b) an impure resin fraction (NSO-ARO). carbon fractions (from oils 1, 5, 16, 19 and 30) which

Doctoral Dissertation by Sunil Bharati, 1997 I GC of Saturated Hydrocarbons 6 On S

> 1000

E 100

80 - S unil

B harati Time (minutes) Time (minutes)

el

t a .

S Cc

ijjJlA A A .A A M *i 20 30 40 50 Time (minutes) Fig. 9. Gas chromatograms of selected saturated hydrocarbon fractions from oil I (a), 5 (b). 16 (c) and 19 (d). Calibration and standardization of latroscan S (d).

22

and

(c)

(minutes) (minutes)

19

(b), Time

Time 16

(a),

7

oil

from

fractions

Hydrocarbons

hydrocarbon Aromatic

of

QC aromatic

selected

of

(minutes) (minutes)

chromatograms

Gas Time Time

I0.

Fig. -

390 420 160 480

E c £

Doctoral Dissertation by Sunil Bharati, 1997 Paper 6„• Calibration and standardization oflatroscan 155

848 Sunil Bharati et al.

were thought to have the best potential of being used (a) Saturated Hydrocarbons as standards indicates that there are significant differ­ ences in the composition and maturity of these oils. Oil 1 [Fig. 9(a)] is relatively rich in lighter n-alkane Intensity type components, probably due to its slightly higher 0 Maximum maturity; oil 5 [Fig. 9(b)] is moderate to strongly □ General biodegraded; oil 16 [Fig. 9(c)] is unusually rich in isoprenoids relative to the n-alkanes (probably to do with an unusual source); oil 19 [Fig. 9(d)] is relatively rich in heavier n -alkane components with n-C15 being the most abundant alkane; and oil 30 is mildly biodegraded. The isoprenoid content in oil 19 is also higher, indicating a lower maturity, though not as 77 83 91 97 99 106 134 142 163 183 high a content as in oil 16. Gas chromatography of the 4 aromatic hydro ­ Aromatic Hydrocarbons carbon fractions which were thought to have best potential of being used as standards also indicates significant compositional differences. Oil 7 [Fig. 10(a)] is biodegraded and is depleted in diaromatic hydro ­ carbons; oil 16 [Fig. 10(b)] is very rich in diaromatic- and depleted in triaromatic hydrocarbons; while oils 19 [Fig. 10(c)] and 22 [Fig. 10(d)] are relatively rich in diaromatic, but also have significant triaromatic hydrocarbon moieties. In addition, oil 19 is more mature than oil 22 (indicative from the higher 2- methylnaphthalene/l-methylnaphthalene ratio in oil 77 83 91 97 99 106 134 142 163 183 19). FPD traces of the 4 aromatic hydrocarbon fractions show that only oils 7 and 16 contain traces of dibenzothiophene, with an apparent difference in Fig. 11. Summarized results of GC-MS analysis of the maturity between the two. hydrocarbon fractions. Relative maximum intensities of It is important to understand as to which of 10 major ions in (a) saturated hydrocarbon fraction and the aromatic hydrocarbon species have the greatest (b) aromatic hydrocarbon fraction. tendency to be retained as contaminants in the saturated hydrocarbon fraction and vice-versa. This various types of molecules present in the fraction. semi-quantitative and qualitative assessment was Apparently, Cl-benzene, the basic aromatic ring achieved by analysing selected saturated and aromatic structure with a methyl group, seems to be the most hydrocarbon fractions using the GC-MS technique. abundant aromatic hydrocarbon species present. The objective of semi-quantitative assessment and The aromatic hydrocarbon fraction on the other contaminant identification was especially significant hand is dominated by short-chain methylated in light of the conventional methods adopted for benzenes, but relatively smaller amounts of some C4- separating fractions (MPLC). Therefore the alkylbenzene are also present. Amongst the saturated purest/least contaminated saturated and aromatic hydrocarbon species, n-alkanes and isoprenoids seem hydrocarbon fractions amongst all the oils considered to be nearly equally distributed [Fig. 11(b)], in addi­ in the study, were chosen for this exercise. tion to methyl cyclic alkanes (m/z 97). Unlike the The saturated hydrocarbon fraction is rich in n- saturated hydrocarbon fraction, which contains alkanes, but the cyclo-alkane moieties are evidently practically no dibenzothiophenes, the aromatic also abundant (m/z 83 and 97), although long hydrocarbon fraction retains some dibenzothiophene chains of alkylbenzenes are also detected in m/z 83 moieties, this being observed in the m/z 198 frag­ [Fig. 11(a)]. In addition, isoprenoids are also present mentogram. On comparing Figs 11(a) and 11(b), it in significant proportions. However, based on m/z 91 seems that the aromatic hydrocarbons have a greater and 106, alkylbenzenes are not present in large tendency to retain saturated hydrocarbon species amounts, contrary to expectations as alkylbenzenes than vice-versa. However, the limitations of this with long chains were thought to be the most likely observation must be borne in mind, as the conclusion contaminants in the saturated hydrocarbon fraction. is based on the analysis of only two samples. These observations are apparent in Fig. 11(a), where The 2 asphaltenes selected for making the the absolute intensities of the 10 major ions are standards differ significantly in the composition of plotted. The figure shows the maximum intensity in a their thermal extracts. While oil 5 is strongly bio­ fragmentogram and the general (most common) in­ degraded [Fig. 12(a)], oil 19 has a bimodal distribution tensity in that fragmentogram. This semi-quantitative of n-alkanes [Fig. 12(b)], Their pyrolysates, however, approach indicates the relative abundances of the are quite similar in composition [Figs 12(c) and (d)]

Norwegian University of Science and Technology Calibration and standardization of Iatroscan asphaltene

of

Pyrolysatc

19.

oil

so (b)

and

(minutes) Asphaltenes 5

40 of oil

Time (a)

30 PY-GC from

asphaltene

of

19.

extract oil

(d)

and Thermal

5

oil

(c)

asphaltenes.

from 2

of

60

pyrolysates

SO and

Asphaltenes (minutes)

40 of extracts

Time

30 TE-GC thermal of

chromatograms

Gas

12

Fig.

Doctoral Dissertation by Sunil Bharati, 1997 Paper

TIC of Resins TIC of Asphaltenes

: 6

Calibration

and

standardization

oflatroscan

25 30 35 50 65 60 65 60 65 Time (minutes)

Time (minutes)

10 15 20 26 30 35 40 46 50 55 60 65 70 10 15 20 25 30 35 40 45 50 66 60 65 70 Time (minutes) Time (minutes) Fig. 13. Results of PY-GC-MS analysis of resins and asphaltenes. Total Ion Chromatograms (TIC) of (a) resin from oil 16, (b) resin from oil 22,

(c) asphaltene from oil 5 and (d) asphaltene from oil 16. Peak identification: V—toluene; ▼—n-hydrocarbon doublets; ♦—alkylcyclohcxancs; 157 ■—methylphenanthrcne; #—alkylnaphthalcncs; J—nC18 doublet; —internal standard. 4 158 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatroscan 851

and are indicative of a marine source. Py-GC of Ion Chromatograms (TIC) of the two asphaltene resins did not give any conclusive results. fractions are shown in Figs 13(c) and (d). Py-GC-MS of selected resin and asphaltene Identification, isolation and purification of selected fractions allowed to assess the presence of any hydro ­ fractions for standard carbons, if any, that might have been retained in these fractions after MPLC separation. The resin fraction Based on the findings this far, 4 oils covering of oil 16 contains only traces of n -hydrocarbons, as practically the entire API gravity range, were selected is indicative by the generally imperceptible homology for re-separation into fractions. Preliminary analyses in mjz 97 and 99, although m/z 99 does exhibit indicated that one or more of these oils could be presence of some n-alkanes. Alkylbenzenes are successfully used to isolate pure fractions, which present, but are believed to occur in small amounts. could be further used to calibrate Iatroscan via Alkylnaphthalenes are more prominent relative to prepared standards. Four parallels of each of the four alkyl-phenanthrenes. Dibenzothiophenes and other oils, oil 5, oil 16, oil 19 and oil 22, were subjected to substituted derivatives are also present. No significant MPLC in order to get large amounts of each fraction biomarkers were recorded. Compared to the resin from each oil. At this stage, we had 4 fractions x 4 from oil 16, the resin fraction from oil 22 is much parallels for each oil. Each of the four fractions more depleted in most of the hydrocarbon species, from these oils were later mixed and re-run through although the latter contains a stronger n-alkane the MPLC system to purify and clean the fractions. homology, as observed in m/z 99, perhaps indicative This ultimately resulted in one large portion each of of the presence of more saturated hydrocarbons. saturated hydrocarbon, aromatic hydrocarbon, resin Most alkylbenzenes are of low molecular weight and asphaltene fractions for each of the 4 oils. On and are not interpreted to be significant. The results analyzing these fractions using the Iatroscan, it was for other ions are similar, but these compounds found that the aromatic fraction of all the oils was are present in low concentrations. The Total Ion contaminated by substantial amounts of resin species, Chromatograms (TIC) of the two resin fractions are a problem which had also been observed earlier. The shown in Figs 13(a) and (b). 4 aromatic hydrocarbon fractions were run through The 2 asphaltenes seem to be considerably different MPLC twice more to remove the resins. in composition. While oil 5 asphaltene is rich in short- The typical TLC-FID chromatograms of the final and medium-length alkyl chains, oil 16 asphaltene pure fractions (saturate and aromatic hydrocarbons, is depleted in these moieties (mjz 97 and 99). Oil 5 resins and asphaltenes) used in Iatroscan calibration asphaltene is also relatively rich in alkylbenzenes. and the standard are shown in Figs 14(a-d). Clearly, Alkylnaphthalenes, however, seem to be equally the fractions are uncontaminated with only traces of prominent in both the asphaltenes, in contrast to unwanted components. However, as the four saturated alkylphenanthrenes which are more conspicuous in hydrocarbon and aromatic hydrocarbon fractions the oil 5 asphaltene. Dibenzothiophenes are depleted differed significantly from each other with respect to in oil 16 asphaltene relative to oil 5 asphaltene. These density and composition, individual response factors results perhaps indicate that oil 16 may be generally were calculated to see if the response factors were richer in branched/cyclo hydrocarbons. The Total affected by these parameters. Each of the fractions

M j t= J l 0 10 0 10 abed Fig. 14. TLC-FID chromatograms of "pure” isolated fractions obtained by a combination of repeated MPLC and preparative-TLC. (a) Saturated hydrocarbons, (b) aromatic hydrocarbons, (c) resins and (d) asphaltenes.

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852 Sunil Bharati ei at.

(a) Saturated HC (C) Resins

3.0

(d) Asphaltenes

Sample amount (pi) Fig. 15. Dependence of calculated response factors of Iatroscan on oil's composition and density. Plot of response factor versus sample amount from 4 different oils for (a) saturated hydrocarbons, (b) aromatic hydrocarbons, (c) resins and (d) asphaltenes.

of the four oils (one heavy —API gravity around 10°, As seen in Fig. 15(a), the response factors of the two medium—API gravity around 30° and one light four saturated hydrocarbon fractions vary signifi ­ —API gravity more than 40°) were analysed by cantly (from about 2000 to 4500). Closer examination Iatroscan 3-5 times, using different sample amounts of the results reveals that the variation is not random, each time (0.5-5 pi of the same solution), and but is controlled by at least two factors. Saturated response factors calculated in each case using the hydrocarbons from the heavy oil have the greatest equation shown below. response factor, while those from a light oil have the Response factor (RJ = least. Compositionally, the saturated hydrocarbons from the heavy oil are strongly biodegraded, those Peak area (A )/Samp!e amount (A/) from the first medium oil (plotted as solid squares) The results are shown in Figs 15(a-d). are very rich in isoprenoids, those of the second Dietz (1967) has shown earlier that relative sensi­ medium oil are rich in medium to heavy range tivity for the flame ionization detector (FID) is quite n-alkanes and lastly those from the light oil are rich different for hydrocarbons and non-hydrocarbons. in low molecular weight n-alkanes (cf. Fig. 9). While most straight chain, branched and cyclo alkanes In case of the aromatic hydrocarbons [Fig. 15(b)], have similar FID sensitivities (close to 1.0), aro ­ the variation in response factor is from about 4000 matic hydrocarbons tend to be very slightly lower for the lightest oil to about 6500 for the heaviest oil. (0.98-1.02). However, non-hydrocarbons (resins and With regards to the compositional variation between asphaltenes), which have heteroatoms such as N, S the four aromatic hydrocarbons, the heavy oil is bio­ and O, have much lower FID sensitivities and the degraded, as noted above, the first medium oil (plotted values vary appreciably. Alcohols, for example, vary as solid squares) is richer in alkylnaphthalenes relative from 0.23 to 0.85; acids, from 0.01 to 0.65 etc. (Dietz, to triaromatics, while the second medium oil and the 1967). The variation in the sensitivity value depends light oil are relatively rich in triaromatics (cf. Fig. 10). mainly on type of compound, number of heteroatoms, In case of the resins and asphaltenes, the trend is molecular weight etc. (Dietz, 1967; Drushel, 1983). opposite to those of the two hydrocarbon groups

Norwegian University of Science and Technology 160 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatroscan

Response Factor (Thousands)

Light Oil Medium Oil Heavy Oil

* SAT HC ARO HC S NSO *ASP

API Gravity C) Fig. 16. Relationship of oil density (API gravity) and Iatroscan detector response (Response factor) for the 4 principle fractions of oil viz. saturated hydrocarbons, aromatic hydrocarbons, resins and asphaltenes. The API gravity is inversely proportional to detector response in case of the 2 hydrocarbon fractions (as indicated by the negative slope of the 2 solid linear regression trends) and directly proportional in case of the 2 non-hydrocarbon fractions (as indicated by the positive slope of the 2 dashed linear regression trends).

[Figs 15(c) and (d)]. Unlike the hydrocarbons, the nearly parallel to each other, although unlike the response factors of the heavy oil fractions are lower hydrocarbons their response factors increase with than those of their lighter counterparts. The signifi ­ increasing API gravity. cance of this reversal is not exactly clear, but it is As response factors cannot be calculated for every suspected that it may be related to lower carbon and unit of the API gravity, and there is no unique hydrogen contents/greater ionization efficiency of the response factor for a given fraction either, the whole components in the heavier oil ’s resin and asphaltene suite of oils has been divided into three principle types fractions. for simplicity—heavy (API gravity 10-24°), medium (API gravity 24-35°) and light (API gravity 35° and Calibration of Iatroscan and testing of prepared above). The American Petroleum Institute defines an as heavy if it has an API gravity of 20° or lower. Clearly, the present results indicate that there However, in our case (Fig. 16), the response factor of cannot be one unique response factor for a given the polar fraction is lower than that of the saturated fraction to calibrate Iatroscan. Parrish and Ackman hydrocarbon fraction until about 24°, but then crosses (1985) had also observed variations in the Iatroscan ’s over and is subsequently greater than the saturated FID response, on analysing marine lipids. It is hydrocarbons. This point was therefore taken as the controlled to a large extent by the oil ’s API gravity boundary between the heavy and medium oils. It is (which can be expressed mathematically) and the not known, however, whether this fact is of any gross composition of the fraction (which is a subjective significance or not. Considering the results plotted in aspect and cannot be expressed mathematically). In Fig. 16, it is assumed that if each of the 4 fractions Fig. 16, the API gravity of the 4 oils is plotted against have 3 different response factors according to the type the average response factor of each of the 4 fractions of oil (one each for heavy, medium and light oils), of each of the 4 oils. The variation of the response calibration of Iatroscan will be reasonably good. The factors in case of each of the four fractions is mathematical model developed to derive these factors more apparent here. While the calculated response is exemplified below. factors decrease with increasing API gravity for the The slopes of the two hydrocarbon trends are two hydrocarbons, it increases for the two non- negative while those of the two non-hydrocarbons hydrocarbon fractions. Moreover, there is a remark­ are positive. Ideally (typically for single synthetic able similarity between the two hydrocarbon fractions compounds and theoretically for a mixture of similar as regards to their response factor progression with compounds), increasing API gravity (the two linear regression R' = A/M (1) trends—solid lines are parallel to each other). Similarly, the linear regression trends of the two non ­ where = response factor, A = peak area, M - hydrocarbon fractions (the two dotted lines) progress sample amount.

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Fig. 17. TLC-FID chromatograms of prepared standards, (a) A natural standard based on a medium oil (Standard A), (b) A natural standard based on a light oil (Standard B). (c) A synthetic standard comprising several synthetic components (GEOS).

But in the present case, The correction constants can be obtained for each Rc = A/M + C, (2) fraction through linear regression, using the slope of the trend and the applicable a in equations (5), (6), where C =f(o), a being the API gravity of the oil. (7) and (8). An example for saturated hydrocarbons This is similar to the linear regression equation is shown below: y = a + bx (3) C,(SAt)= —53.3 x 17= —906 where a is a constant and b is the slope. where 17 is the assumed representative of the a Range .'. equation (2) can be written as [10.24]. Re^A/M+bxo (4) CysAT) = —53.3 x 29= —1546 The derived equations for the 4 components in where 29 is the assumed representative of the a Range Fig. 16 are: 124.351 Saturated hydrocarbons. CjtsA-n = -53.3 x 42 = -2238 R&sat ) — 5292 + (—53.3 x

Norwegian University of Science and Technology 162 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of latroscan 855

Table 9. (a) Calculated correction constants (C) Standard A Sat Aro Pol Asp Fraction C, -906 -804 588 1127 C. -1546 -1371 1003 1923 O SAT C, -2238 -1987 1453 2785 x ARO ♦ POL (b) Calculated response factors (Re) A ASP Sat Pol Asp Heavy oil (£,„) 4386 6524 5981 10908 Medium oi H^ m) 3746 5957 6396 11704 Light oil (RcL) 3054 5341 6846 12566 Average (Bulk) (%*) 3729 5941 6408 11726

relationship of the response factors to each other is more likely to remain the same, if the same standard is used to calibrate the instrument. Therefore, for Standard B other users, the 2 tables below (Table 10) could be used to extrapolate the response factors from the given standard, which is based on a medium oil. The relationships in Table 10(a) below are derived directly from the data in Table 9(b). A closer examin­ ation of these relationships reveals that in relation to the medium oil values, both the hydrocarbon fractions of heavy and light oils have a rather constant relation­ ship (1.17 to 1.1 times and 0.82 to 0.9 times respect­ ively) and both the non-hydrocarbon fractions of heavy and light oils also have a constant relationship 0.5 1.0 1.5 2.0 2.5 3.0 (0.93 times 1.07 times respectively). This further Sample Amount (jil) strengthens the interpretation that these variations are not random, but are controlled by distinct factors). Fig. 18. Calibration curves for the 2 natural standards. A and B. (a) Plot of sample amount versus peak area of the The user may utilise either Table 10(a) or 10(b) to 4 individual components of Standard A. (b) Plot of sample extrapolate response factors from the given medium amount versus peak area of the 4 individual components of oil based standard. Standard A. Standard B. Note the linearity of peak-area progression Two standards have been prepared using topped with increasing sample amount in case of each component oils, for calibrating latroscan and subsequent use. in both the standards. The strength of the solutions in both cases was aimed in the range 10-15 mg oil/ml solvent, as it has been Standard A is primarily made from a medium oil found through experience that this is the ideal range and is rich in polars and asphaltenes. In contrast, to ensure adequate individual component amounts, Standard B is primarily from a light oil and contains good separation and to avoid overloading. The minor polars and practically no asphaltenes. The solvent chosen to dissolve the standards was toluene chromatograms of these two standards are shown instead of commonly used dichloromethane, due to in Figs 17(a-b). These two standards were analysed toluene ’s greater stability (higher boiling point) under by latroscan using 5 parallels, with different sample ambient conditions. amounts each time. The sample amount varied from 0.5 to 3/xI in each case. Calibration curves were Table 10. (a) Relationship of response factors (Rc) of a fraction with drawn and are shown in Figs 18(a-b), where it can be respect to medium oil observed that the peak area progression is rather Sat Aro Pol Asp Heavy oil (R uw Polars 26794 26177 6396 4.09(19.14) Asphaltenes 10645 10599 11704 0.90(4.2) Saturated HC y % Aromatic HC l.49x l.59y 1.75z Standard B Polars 1.36x 1.71y 2.24z Saturated HC 42018 45537 3054 14.91 (84.96) Asphaltenes 2.49x 3.l2y 4.1 Iz Aromatic HC 10266 10022 5341 1.88(10.71) Polars 4284 5100 6846 0.74(4.22) x is the user's calculated response factor for saturated hydrocarbon Asphaltenes 236 312 12566 0.02(0.11) fraction based on prepared Standard A.

Doctoral Dissertation by Sunil Bharati, 1997 Table 12. List of compounds used to prepare various synthetic standards. The figures indicate the percentage of the compound used in a standard Standard Name Compound SATI MODI I POLY l POLY2 AROI NSOI NS02 NS03 NS04 NS05 NS06 NS07 NS08 NS09 NSOIO NSOll NSOI2 NSOI3 NSOI4 ASP:

1. Hexadecanc 41.4 2. Docosane 26.9 3. Hcxacosanc 19.7 4. Triaconlanc 5.5 5. Hexalriaconlane 3.8 S

6. 2,3-dimcthylnaphthalcnc 12.1 8.3 il n u 7. M-dicyclohcxylbenzcne 39.8 27.1

B

8. Naphthalene 24.1 16.4 j t a r a h 9. Biphenylene 7.5 5.1 10. 2-mcthylnaphthalene 16.5 11.3

el

II. 1,3-dimelhylanthracenc 49.6 al. 12. Phcnanthrcnc 50.4 100 31.8

I 13. Thenoic acid 20.2 46.8 28.6 38.5 25.6 14. Dibcnzolhiophcnc 12.7 29.5 26.7 15. l-benzothiophcnc 9.8 23.7 17.8 I 16. Stearic acid 20.1 15.7 19.6 13.1 33.6 100 17. Stearyl alcohol 18.2 22.5 21.7 14.5 33.1 100 75 18. Stearamidc 19.0 12.8 20.1 13.4 33.3 100

19. Bcrbcrinc sulphate 71.4 55.5 49 33.4 25 25 100

8$ 164 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatroscan 857

consistent in the case of all the four principle frac­ Saturated hydrocarbons. Squalane is the most tions —saturated hydrocarbons, aromatic hydrocar ­ commonly used synthetic compound for the purpose bons, polars and asphaltenes. of calibration and quantification of saturated hydro ­ Corrected peak areas, based on linear regression, carbons. We, however, chose to use a mixture of were used to calculate the fraction amounts. The 5 different n-alkanes ranging widely in the carbon response factors used to derive the individual com ­ chain-length (nC16 to nC36) to prepare the saturated ponent amounts are derived from Table 9(b). The hydrocarbon standard, SAT1 (Table 12). The TLC- case for 2 p\ sample amounts for both the standards FID chromatogram is shown in Fig. 19(a). Iatroscan is shown below in Table 11 and taken as correct, analysis of SAT1 gave very good results with one as this is the sample amount (sample dissolved in dominant peak. This was therefore the only standard solvent) that is applied on the chromarods. made for saturated hydrocarbons. Aromatic hydrocarbons. The standard for mono- Synthetic standards and diaromatic hydrocarbons (MODI1), which was a Table 12 shows the details of the synthetic mixture of 5 compounds (Table 12), resulted in one standards (total 21 basic standards) prepared in the sharp peak on Iatroscan analysis [Fig. 19(b)]. In present study. One basic criterion that was followed addition, a combination of MODI 1 components and while making these standards was that in each a poly-aromatic hydrocarbon (phenanthrene) (AROl) standard, the distribution of components should be resulted in two well defined peaks on Iatroscan as close as possible to the distribution commonly analysis [Fig. 19(c)]. encountered in the natural samples. A total of 19 Asphaltene. The criteria for selecting a compound compounds, most of which occur naturally in solvent which could serve as a natural asphaltene equivalent extracts and/or crude oils, was chosen with objective were simple: (1) the molecule should be large, (2) the of obtaining response factors as close as possible to molecule should be polar, (3) the molecule should con­ natural mixtures. The first stage in synthetic standard tain nitrogen, sulphur and oxygen. Berberine sulphate analysis included mainly establishing the correct (MW = 822, formula = CWH42N20,5S) was selected combination of various compounds which are and the standard ASP1 and ASP2 (a much diluted compatible with each other in a solution. This was version of ASP1) analysed by Iatroscan. The results therefore a more qualitative objective. The second were good with one dominant peak at the spotting stage consisted of making a mixture of all the point [Fig. 19(d)]. compatible compounds, with at least one compound Resins. Making the right synthetic standard for representative of each of the principle fraction type, resins was the most difficult task in the entire syn­ and calibrating Iatroscan and deriving the response thetic standard study. Up to 14 different mixtures factors. The qualitative assessment and compound (Table 12) had to be made to reach the right com ­ compatibility findings are described below for each position of the resin standard. Initially, the criteria fraction type. was to include at least one compound containing

5

C Jrr^i C . . 1 10 cm 0 10 cm 0 a b C d Fig. 19. TLC-FID chromatograms of synthetic standards, (a) Synthetic standard SAT1, comprising 5 n-alkanes with varying carbon chain-length (C16-C36). (b) Synthetic standard MODI1, comprising 5 different mono- and diaromatic hydrocarbon components, (c) Synthetic standard AROl, comprising MODI1 and a poly-aromatic hydrocarbon (phenanthrene). (d) Synthetic standard ASP I, comprising a single compound, berberine sulphate, which is thought to be comparable to a natural asphaltene molecule with regards to polarity and elution characteristics during chromatography.

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10 cm 0 10 cm 0 10 cm b C d

10 cm o io cm 0 10 0 10 cm e f h Fig. 20. Results of Iatroscan analysis of the various synthetic resin standards. TLC-F1D chromatograms of (a) NSOl, comprising 6 different components, including 2 acids, an alcohol, an amide and 2 thiophenes, (b) NS02, comprising 3 components- thenoic acid and 2 thiophenes, (c) NSOS, comprising ASPl and CIS acid, alcohol and amide, (d) NS06, comprising thenoic acid and Cl8 —acid, alcohol and amide, (e) NS07, comprising NSQ6 and ASP1. (f) NSOS, comprising only the 3 CIS components —acid, alcohol and amide, (g) NSOl 1, comprising only CIS amide and (h) NS014, comprising CIS amide and bcrberinc sulphate (ASP1).

nitrogen, sulphur and oxygen and at the same time, NS06 and NS07 were analysed, but contrary to maintaining the individual molecular weight low. expectations NS06 resulted in two peaks [Fig. 20(d)] NSOl standard was made, but on analysis, the and NS07 in three peaks [Fig. 20(e)). This clearly mixture split into three peaks with one peak eluting indicated that the combination of stearic acid, stearyl as an aromatic hydrocarbon [Fig. 20(a)). NS02 alcohol and stearamide is also not compatible. This (made to identify the incompatible component) split was evident from NSOS analysis [Fig. 20(f)], where into two distinct components [Fig. 20(b)] and there­ three components gave three peaks. NS09, NSO10 fore abandoned. NS03, NS04 and NSOS, which and NSOl 1 were analysed to identify the incompat ­ consisted of similar compounds mixed with berberine ible component. All the three gave reasonably good sulphate, and which were expected to give 2 peaks single peaks, but stearamide [Fig. 20(g)] seemed to be each, gave variable results. While NS03 resulted in most consistent in its retention time. A combination two peaks, thenoic acid did not elute as much as it of these three components with berberine sulphate should have; NS04 gave only one peak; and NSOS (NS012, NS013 and NS014) confirmed that stear­ seemed to have worked well with the combined CIS- amide was most compatible with the asphaltene acid, alcohol and amide peak separating very well component, berberine sulphate [Fig. 20(h)], from the berberine sulphate peak [Fig. 20(c)). This led This concluded the qualitative and compatibility us to believe that perhaps the two benzothiophenes assessment of the selected synthetic compounds and are the problematic components. To ascertain this, the final standard mixture GE03, which comprised

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Calibration and standardization of Iatroscan 859

Table 13. Calibration results of the Synthetic Standard GE03 {based on 10 parallels of 2pl) Mean Area Amount Amount Fraction Area SD (%) (%) (pgi Saturated Hydrocarbons 14727 962 37.51 41.8 4.32 3409 Mono + Diaromatic Hydrocarbons 4842 399 12.72 24.5 2.532 1912 Poly-aromatic Hydrocarbons 3917 282 9.98 9.3 0.96 4080 Resin 8035 688 21.13 14.7 1.52 5286 Asphaltene 6961 531 18.79 9.6 0.996 6989

SAT I, AROl, NSOl I and ASP2 was analysed. The use the bulk response factors CR,B) and calculate the resulting TLC-FID chromatogram is shown in Fig. fraction amounts (Amount 2). The fraction amounts 17(c). Clearly, the 13 compounds used in GE03 are resulting by employing ReB in Case 1 should be quite compatible and stable in each other ’s presence, with close to the actual values of the standards calculated one peak each of saturated hydrocarbons, mono- using Rat, and which are shown in Table 11. This + diaromatic hydrocarbons, polyaromatic hydro ­ is because are closest to RM. Next, the response carbons, resins and asphaltene. The new GE03, factors for light oil (i?cL) are used and the fraction which was subsequently made using fresh chemicals amounts calculated (Amount 3). Finally, the response with the purpose of calibrating Iatroscan and deriv­ factors derived from the GE03 synthetic standard ing response factors, comprised of the following: (Rcs from Table 13) are used and the individual saturated hydrocarbons 40%, aromatic hydrocar ­ fraction amounts calculated (Amount 4). The results bons 35%, resin component 15% and asphaltene are presented below in Table 14. component 10%. Ten parallels of 2pi spotting were From Table 14 the following conclusion can be analysed to establish reproducibility and obtain opti ­ made. The first general effect of using a single set of mum peak areas. Table 13 above summarizes the bulk response factors is that the quantity of fractions findings. The implications of the calculated response in heavy oils are overestimated and those in light oils factors from synthetic standards (R^) are discussed are underestimated. This means, for example, that the in the next section. concentration of a heavy oil solution is reported as 21.43 and 13.69 mg/ml instead of 19.55 and 11.89 mg/ Validity of oil type dependent calculated response ml respectively, an overestimate of about 10-12%. factors Likewise, the light oil solution which should have a The calculated response factors as shown in concentration of 24.37 and 16.32 mg/ml is reported as Table 9(b) apparently indicate potentially large 21.43 and 13.69 mg/ml respectively, an underestimate differences in the resulting quantitative data when of about 12%. In addition, it must be borne in mind these factors are used. It is intended in this section that even the figures quoted in the above table are to demonstrate the actual differences that will be likely to be slightly erroneous (say about ±5%) and obtained if only a single set of bulk response factors therefore the true error due to use of bulk response are used instead of calculated response factors with factors could be in the range of about 18%, which is oil type dependence. The test is performed for heavy undoubtedly a high percentage. and light oils' response factors, keeping the average However, the relative percentages are less affected bulk response factors constant. In the first case, we and tend to remain rather constant, except in the assume that Standards A and B are heavy oils and use case of saturated hydrocarbons where the variation the corrected areas to calculate the fraction amounts is about +9% for Standard A, which is relatively using the heavy oil response factors i.e. and this depleted in saturated hydrocarbons, and +3% for will give Amount 1 for both the standards. Next we Standard B, which is rich in saturated hydrocarbons.

Table 14. Comparison of quantitative data obtained by using different response factors (R^, Rea> RcL and R&) and Standards A & B peak data Area Amount 1 Amount 2 Amount 3 Amount 4 Fraction mVs PH%) *== M(%) pk %> Res p\(%) Case 1: Standard A data Sat. HC 48332 4386 11.02(56) 3729 12.96(60) 3054 15.83(65) 3409 14.18(51) Aro. HC 20727 6524 3.18(16) 5941 3.49(16) 5341 3.88(16) 2996* 6.92(25) Polars 26177 5981 4.38(22) 6408 4.08(19) 6846 3.82(16) 5286 4.95(18) Asphalt. 10599 10908 0.97(5) 11726 0.90(4) 12566 0.84(3) 6989 1.52(6) Total 19.55 (99) 21.43(99) 24.37(100) 27.57(100) Case Z* Standard B data Sat. HC 45537 4386 10.38 (81) 3729 12.21 (83) 3054 14.91 (85) 3409 13.36(75) Aro. HC 10022 6524 1.54(12) 5941 1.69(11) 5341 1.88(11) 2996* 3.34(19) Polars 5100 5981 0.85(7) 6408 0.80(5) 6846 0.74(4) . 5286 0.96(5) Asphalt. 312 10908 0.03(0) 11726 0.02(0) 12566 0.02(0) 6989 0.04(0) Total 12.80(100) 14.72(99) 17.55(100) 17.70(100) Note: Response factor types: = heavy oil, Rc6 = bulk (average). R,L = light oil and R& = synthetic standard. •Average of mono + diaromatic and poly-aromatic hydrocarbons.

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Oils with high proportions of polars are also likely to This inability is believed to be primarily due to their be adversely affected with the variation being about inherent composition. However, a few oils covering a ±8 %. wide API gravity range were found to be suitable and Assuming that most oils would fall in the category were later used to calibrate Iatroscan and prepare of medium oils, the use of bulk response factors will standards. As expected, the most problematic frac­ most commonly not bring about any significant tions were the non-hydrocarbons, due to mainly two change in the quantitative data. On the other hand, reasons. One reason was the limited amounts of these the use of bulk response factors, would result in an fractions obtained from the oils, and second being the underestimation of saturated hydrocarbons in heavy- difficulty in obtaining pure, uncontaminated fractions. and hydrocarbon-depleted oils which could be This problem was eventually minimised through crucial. Similarly, an overestimation of saturated repeated separation and parallel analyses. hydrocarbons in hydrocarbon depleted light oils is A major finding of this study is that the response also critical, though this case is less likely to occur. factors of the separated fractions from oil are not With regard to the use of bulk response factors in unique for all oils, but are instead greatly dependent the analysis of solvent extracts from reservoir rocks, on the composition of the fraction and the API gravity the degree of inaccuracy should be minimal as the of the oil. It will therefore be highly erroneous to use majority of the extracts would in any case fall in the a single response factor for, say saturated hydro ­ category of medium oils. This is, however, not equally carbons, without taking into account the API gravity applicable to extracts from source rocks, as source of the oil. For the sake of simplicity, a set of 3 rocks are much more likely to be rich in high molecular response factors for each of the 4 fractions, have been weight non-hydrocarbon species, such extracts being derived which are suitable for heavy oils, medium oils comparable to low API gravity oils. In general, and light oils, these being defined as RcH, R^M and therefore, the use of bulk response factors for rock &L- extracts could be substantially erroneous, since for Examples of two standards, A (rich in polars and rock extracts it is not only the relative percentage asphaltenes) and B (lean in polars and asphaltenes data that is important, but also the net yield data. nearly absent), have been prepared through this study Yields obtained by using response factors derived for use in the petroleum industry. A mathematical from synthetic standards (R^) are even more model has been developed to derive response factors erroneous than those obtained by using bulk response and their relationships to the given standard have factors. The net saturated hydrocarbon yield is grossly been described. These can be readily employed by overestimated for heavy and medium oils (28 and different Iatroscan users. The use of these standards 9% respectively), while slightly underestimated for and the proposed mathematical model will ensure light oil. Aromatic hydrocarbons are most adversely realistic inter-laboratory data comparison and affected by using R^.The net yield is almost doubled, standardization of the Iatroscan technique in the irrespective of the type of oil, and this is the principle petroleum industry. reason for highly erroneous relative percentages. Based on the results obtained in the present study Resins are overestimated for all types of oils, the and bearing in mind the various limitations/problems medium and low API gravity samples being the most encountered, we recommend the following: affected. Asphaltenes are also highly overestimated (up to 80% for light oils), despite employing a large 1. Further work must be performed to better molecule such as berberine sulphate as an asphaltene understand the dependability of response factors standard. Apparently, the response of berberine on API gravity and composition of the oil. sulphate is closer to the natural aromatic hydro ­ More data points are required in this paper ’s carbon fraction from a light oil. All these factors Figs 16 and 17, to make the proposed model contribute to the highly inaccurate relative percent­ better and subsequently derive more reliable ages for a given extract or oil sample, regardless and correct response factors. This will require of its composition and API gravity, if synthetic further MPLC separations of oils, GC of standards response factors are used for calibration hydrocarbon fractions and Iatroscan analyses. and quantification. 2. The concentration of the solution that will be used to spot samples on the chromarods must SUMMARY AND CONCLUSIONS be 10-15 mg oil/ml solvent, to ensure good chromatography and avoid overloading. In the Of the 31 oils world wide that were used in the case of whole rocks, SI data from Rock-Eval study, only a few were found suitable for the purpose should be used to determine the rock weight, of preparing standards and calibrating the Iatroscan but if nothing is known then 3g should be TLC-FID instrument. For the remaining oils, the dissolved in 5 ml solvent. primary reason for not qualifying as Iatroscan Stan­ 3. An amount of 2 pi solvent containing the dard precursors was their inability to separate into 4 sample should be spotted on the rod as a general distinct and clean fractions, which were chromato- practice, preferably using an auto-spotter, to graphically pure from the TLC-FID point of view. avoid band-spreading and to ensure good

Norwegian University of Science and Technology 168 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Calibration and standardization of Iatroscan 861

chromatography. Blowing the spotting point pp. 77-85. Norwegian Petroleum Society, Graham & Trotman, London. continuously using nitrogen has been found Karlsen D. and barter S. (1991) Analysis of petroleum to be very effective in quickly removing the fractions by TLC-FID—applications to petroleum solvent, and should be routinely practised. reservoir description. Org. Geochem. 17, 603-617. 4. As n-pentane precipitated asphaltene fraction Norwegian Industry Guide to Organic Geochemical is compositionally not at all comparable to the Analyses (1993) 3rd edition. Jointly published by Statoil, Norsk Hydro, Saga Petroleum, Geolab Nor, IKU and fraction hitherto referred to as asphaltene in the Norwegian Petroleum Directorate. TLC-FID technique, we propose the use of Poirier M. A., Rahimi P. and Ahmed S. M. (1984) Quanti­ the terms Resin 1 for resins (synonymous to the tative analysis of coal derived liquids residues by TLC resin or NSO fraction from MPLC) and Resin 2 with flame ionisation detection. J. Chromatogr. Sci. 22, 116-119. for the fraction hitherto referred to as asphaltene Radke M„ Willsch H. and Welle D. H. (1980) Preparative in the TLC-FID technique. Resin 2 will therefore hydrocarbon group type determination by automated essentially comprise of heavier, high molecular medium pressure liquid chromatography. Anal. Chem. 56, weight and large molecules of NSO compounds, 2538-2546. relative to Resin 1. Adoption of the terms Resin Ray J. E„ Oliver K. M. and Wainwright J. C. (1982) The application of the Iatroscan TLC technique to the analysis 1 and Resin 2 will also minimize confusion when of fossil fuels. In Pelroanalysis 81, IP Symposium, the quantitative data from MPLC is compared London, 361-388. Heyden and Son, London. to quantitative data from Iatroscan. Selucky M. L. (1983) Quantitative analysis of coal derived 5. Synthetic compounds should not be used as liquids by thin layer chromatography with flame ionisation detection. Anal. Chem. 55, 141-143. standards for quantification purposes, as Yamamoto Y. (1988) Analysis of heavy oils by thin-layer response factors derived from them result in chromatography with flame ionisation detection. Sekiyu highly erroneous data for real samples. Gakkaishi 31, 351-362. 6. Natural standards (such as the prepared Stan­ dards A and B of the present study) should be used for calibration and subsequently should be routinely analysed (say once a fortnight or APPENDIX 1 after every 100 analyses) and the individual response factors updated accordingly, as the Whole rock (cuttings, core-chips, side wall cores) is crushed response/sensitivity of any FID alters with time using either a mill or a pestle and mortar to fine particle size. If the sample is a shale, then the particle size should be and usage. 65 pm or finer. If the sample is a loosely packed sandstone, 7. Bulk response factors must not be used as these then it is sufficient that all the individual sand grains are free are likely to give erroneous results. Different and finer crushing does not improve the results. About 2 g response factors for heavy oils, medium oils of whole rock is accurately weighed in a 8 ml glass vial with screw cap (cap with a Teflon lining inside), and 2.0 ml of and light oils must be used instead, which can solvent (dichloromethane : methanol, 93:7 v/v) is added and be easily calculated and applied by the users. the vial sealed immediately. The sample is allowed to be extracted for 48-72 h (preferably 72 h if the sample is a shale), with vigorous agitation 4-5 times a day. If the rock Acknowledgements —Many thanks to the following oil is very rich in EOM (the colour is dark brown), then an companies (arranged in alphabetical order) for oil samples: additional 1 ml solvent can be added after one day. After BEB Erdgas und Erdol GmbH, BHP Petroleum Pty. Ltd, this stage, the procedure is the same as in the case of oils. Chevron/Cabinda Company Limited, Mobil Turkey, Norsk Hydro, OMV Aktiengcsellschaft, Corporation of Peru, SANTOS Ltd, Saga Petroleum a/s, Unocal Netherlands B.V., Geolab Nor; and Norsk Hydro, Saga Petroleum a/s, and Statoil for financial APPENDIX 2 support. F. Behar and D. Karlsen are thanked for critical List of Ions Specified During GC-MS of Saturated comments and improving the quality of the manuscript. and Aromatic Hydrocarbons m/z Compound REFERENCES 1- 77 —benzene 2. 83 —cyclo-alkanes Dietz W. A. (1967) Response factors for gas chromato- 3. 91 —Cl-alkylbenzcnes graphic analyses. J. Gas Chromatogr. 5, 68-71. 4. 97 —rt-alkcnes/mclhylcyclic-hexancs Dmshel H. V. (1983) Needs of the chromatographer — 5. 99 —n-alkanes detectors. 7. Chromatogr . Sci. 21, 375-384. 6. 106 —alkylbcnzcnes Gout* M., Germ C. and Bertrand J. C. (1990) An applica- 7. 134 —C4-alkylbcnzcncs tion of Iatroscan thin-layer chromatography with flame 8. 142 —mcthylnaphthalenes ionization detection —lipid classes of microorganisms as 9. 163 —tcrpancs biomarkers in the marine environment. In Advances in 10. 183 —isoprenoids Organic Geochemistry 1989 (Edited by Durand B. and It. 177 —dcmcthylatcd triterpanes Behar F), pp. 1231-1237. Pergamon Press, Oxford. 12. 191 —triterpanes Karlsen D. and Latter S. (1989) A rapid correlation method 13. 198 —dibenzothiophenes for petroleum population mapping within individual 14. 217 —slerancs petroleum reservoirs: applications to petroleum reservoir 15. 231 —triaromatic steranes description. In Correlation in Hydrocarbon Exploration, 16 253 —mono-aromatic steranes

Doctoral Dissertation by Sunil Bharati, 1997 Paper 6: Calibration and standardization oflatroscan 169

862 Sunil Bharati et at.

APPENDIX 3 6. 134 —C4-atkyIbenzcncs 7. 142 —mcthylnaphthalenes List of Ions Specified During PY-GC-MS of Resins 8. 156 —C2-naphthalene$ and Asphaltenes 9. 163 —terpanes 10. 170 —C3-naphtha!cncs miz Compound 11. 192 —methylphenantbrcnes I. 77 —benzene 12. 198 —dibenzothlophenes 2. 91 —Cl-benzcnc (toluene) 13. 206 —C2-phenanthrenes 3. 97 —n-alkenes 14. 212 —C2-dibcnzothiophenes 4. 99 —w-alkanes 15. 231 —triaromatic stcranes 5. 106 —alkylbenzenes 16. 253 —mono-aromatic stcranes

Norwegian University of Science and Technology 170 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Doctoral Dissertation by Sunil Bharati, 1997 Paper 7: A New North Sea oil based standard for Iatroscan 171

Chapter 8: Paper 7

A new North Sea oil-based standard for Iatroscan analysis

Sunil Bharati \ Richard Patience 2, Nigel Mills 3 and Trend Hanesand 4

1 - Geolab Nor, N-7002, Trondheim, Norway 2 - Statoil, N-4035 Stavanger, Norway 3 - Saga Petroleum, Sandvika, Norway 4 - Norsk Hydro, Oslo, Norway

Org. Geochem. Vol. 26, No. 1/2, pp. 49-57. 1997 Pergamon © 1997 Elsevier Science Ltd All rights reserved. Printed in Great Britain PH: 50146-6380(96)00152-0 0146-6380/97 sn.oo + o.oo

A new North Sea oil-based standard for Iatroscan analysis

SUNIL BHARATI1, RICHARD PATIENCE", NIGEL MILLS’ and TROND HANESAND4 'Geolab Nor, P.B. 5740 Fosscgrenda, N-7002 Trondheim, Norway, "Statoil, N-4035 Stavanger, Norway, ’Saga Petroleum, P.B. 490, N-1301 Sandvika, Norway and 'Norsk Hydro, P.B. 200, N-1321 Stabekk, Norway

Abstract—The TLC-F1D technique using the Iatroscan is a fast and cost-effective way to obtain quan ­ titative data on the composition of crude oils and solvent extracts of rocks. However, its accuracy depends on correct calibration of the instrument using standards based on crude oil, since the use of synthetic standards had resulted in erroneous response factors. In the present study, a North Sea deas-- phaltcncd oil from the Oseberg field (NSO-1) was fingerprinted and separated into saturated hydrocar ­ bons, aromatic hydrocarbons and polars on a large scale, using preparative TLC. These fractions were later mixed to provide a standard, which was used to calibrate Iatroscan and monitor the responses of the individual fractions. This standard has been shown to be stable for routine use and will, if adopted, render inter-laboratory data comparisons more reliable. © 1997 Elsevier Science Ltd

Key words —Iatroscan response factors, standard for Iatroscan, Oseberg oil, preparative TLC

Norwegian University of Science and Technology 172 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Org. Geochem. Vol. 26, No. 1/2, pp. 49-57, 1997 Pergamon 0 1997 Elsevier Science Ltd All rights reserved. Printed in Great Britain PII: 80146-6380(96)00152-0 0M6-6380/97 $17.00 + o.oo

A new North Sea oil-based standard for Iatroscan analysis

SUNIL BHARATI', RICHARD PATIENCE2, NIGEL MILLS’ and TROND HANESAND* 'Geolab Nor, P.B. 5740 Fossegrenda, N-7002 Trondheim, Norway, ’Statoil, N-4035 Stavanger, Norway, ’Saga Petroleum, P.B. 490, N-1301 Sandvika, Norway and ‘Norsk Hydro, P.B. 200, N-1321 Stabekk, Norway

Abstract—The TLC-FID technique using the Iatroscan is a fast and cost-effective way to obtain quan ­ titative data on the composition of crude oils and solvent extracts of rocks. However, its accuracy depends on correct calibration of the instrument using standards based on crude oil, since the use of synthetic standards had resulted in erroneous response factors. In the present study, a North Sea deas- phaltened oil from the Oseberg field (NSO-I) was fingerprinted and separated into saturated hydrocar ­ bons, aromatic hydrocarbons and polars on a large scale, using preparative TLC. These fractions were later mixed to provide a standard, which was used to calibrate Iatroscan and monitor the responses of the individual fractions. This standard has been shown to be stable for routine use and will, if adopted, render inter-laboratory data comparisons more reliable. © 1997 Elsevier Science Ltd

Key words —Iatroscan response factors, standard for Iatroscan, Oseberg oil, preparative TLC

INTRODUCTION pounds were isolated using preparative TLC (PTLC) with the aim of preparing a standard mix­ The thin-layer chromatography-flame ionization ture for calibrating Iatroscan. Deasphaltened oil detection (TLC-FID) technique using the Iatroscan was used in this study, as specified in the instrument is now recognized as an efficient, fast Norwegian Industry Guide to Organic Geochemical and cost-effective way to obtain quantitative data Analyses (1993). Each isolated fraction was purified on the composition of crude oils and solvent by PTLC, then tested for purity using TLC-FID extracts (Ray et al., 1982; Karlsen and Latter, 1989; and gas chromatography, prior to mixing. Each Bharati et al., 1994). Sampling for analysis can be fraction was individually calibrated so that its easily performed on a millimetre to meter scale to Iatroscan response factor could be applied routi ­ map lateral and vertical heterogeneity in a well, nely. A standard was then prepared for other users, field or reservoir unit. Complex organic mixtures by mixing weighed amounts of the separated frac­ such as crude oils, or solvent extracts of sediments tions. are easily separated into 3, 4 or 5 compound classes, depending on the objectives of the study, each compound class having, however, a different ANALYTICAL PROCEDURES response factor. Previous studies (Bharati et al., 1994) indicated Topped and deasphaltened oil (2.135 g) was sep­ that if synthetic standards were employed to cali­ arated by PTLC using 10 plates (Merck; 1 mm silica brate the Iatroscan instrument, the resulting re­ gel with 254 nm fluorescence activator). About sponse factors were not satisfactory which 200 mg of sample was applied to each plate and suggested that only crude oil based standards eluted successively with n-hexane (45 min), toluene should be used for quantification. In the light of (23 min) and dichloromethane/methanol (93:7 v/v, this, it was logical to develop a new Iatroscan stan­ 3 min) affording saturated hydrocarbons (Rf 0.64- dard based on the oil (selected by the Committee 0.87), aromatic hydrocarbons (Rf 0.47-0.62) and for the Norwegian Industry Guide to Organic polar compounds (Rf 0.25-0.38). Fractions were Geochemical Analyses) from the Oseberg field, scraped from the plate and recovered by extracting North Sea, (called North Sea Oil-1) to serve as a with dichloromethane/methanol (93:7 v/v), then standard for other analytical techniques such as analysed using the Iatroscan as described by liquid chromatography, gas chromatography and Bharati et al. (1994). Further purification of the gas chromatography-mass spectrometry. fractions (ARO 1 and POL 1) was done by repeat In our study, the North Sea Oil-1 (NSO-1) was PTLC analysis which gave fractions ARO 2 and fingerprinted to understand the basic characteristics POL 2, respectively. of the oil and more importantly, saturated hydro ­ Quality control at a molecular level of the two carbons, aromatic hydrocarbons and polar com ­ hydrocarbon fractions was performed using gas

Doctoral Dissertation by Sunil Bharati, 1997 Paper 7: A New North Sea oil based standard for Iatroscan 173

50 Sunil Bharati et at.

Whole oil-NSO-1

c U

E 800 y =

5 700 y r,

400 -

300 t I I SO Time (minutes)

Fig. 1. Gas chromatogram of NSO-1 (whole oil) on a column (40 m; i.d. 0.25 mm, film thickness 0.3 pm) coated with SE 54, temperature programmed from —10 to 300°C at 4°C/min, final hold at 300°C for 20 min. Peak identification example: nC6 denotes normal hexane.

chromatography (GC). Whole oil GC was per­ cessing. The samples were analysed in multiple ion formed in conjunction with GC-MS for basic detection mode (MID) with a scan cycle time of ap­ characterization and fingerprinting. GC-MS was proximately 1.1 s. Although GC-MS analysis was performed on saturated and aromatic hydrocarbons not performed quantitatively, the amounts of satu­ using a VG TS250 mass-spectrometer interfaced to rated and aromatic hydrocarbon samples injected a HP 5890 GC. The GC was fitted with a fused were similar, so that the variations in the signal silica SE 54 column (40 m, i.d. 0.25 mm, film thick­ intensities are easily comparable. ness 0.3 pm) directly into the ion source. Carrier gas was helium. The GC oven was programmed from 45-150°C at 35°C/min, after which the rate RESULTS AND DISCUSSION was 5°C/min up to 310°C, where the column was NSO-1, with an API gravity of 32.8°, is a mature held isothermally for 15 min. The MS was operated oil from a marine source rock with a low content of in electron impact (El) mode at 70 eV, a trap cur­ terrestrially derived organic matter (OM). The com­ rent of 500 pA and a source temperature of 220°C. position of the oil is dominated by light- and med­ The data system used was a VGPDP11/73 for ium-range hydrocarbons, with the overall n-alkane acquiring data and a Vax station 3100 for peak pro ­ distribution being distinctly light-end biased (Fig. 1).

Table 1. Selected geochemical parameters of NSCM based on gas chromatographic analysis of the saturated and aromatic hydrocarbons Parameter Value 1 Pristane/nC17 0.51 2 Pristane/phytanc (Pr/Ph) 1.56 3 Phytane/nClB 0.39 4 Carbon Preference Index (CPI) 1.10 5 nC17/nC17 + nC27 0.91 6 Dimethylnaphthalene ratio (DMNR) 1.79 7 2/1 •methylphenanthrenc (2/1MP) 0.94 8 Methylphenanthrene index (MPI) 0.70 9 Calculated vitrinite reflectance (/y 0.82 10 Dibenzothiophene/phenanthrene (DBT/P) 0J8 11 4/1-metbyIdibenzotiiiophene (4/1MDBT) 3.60 12 3 + 2/1-metbyldibenzo thiophene (3 + 2/1MDBT) 0.91

Norwegian University of Science and Technology 174 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

NSO-I-Saturated fraction m/z 191 3.1E6. 2.9E6 2.8E6 2.6E6

• 2.2E6

% 50 -I.5E6

-UE6 9.2B5 7.7E5 •6.2B5 •4.6E5 -3.1B5

0.0E0 45:00 50:00 55:00 1:00:00 1:05:00 1:10:00 1:15:00 1:20:00 1:25:00 1:30:00 1:35:00 1:40:00 Time

NSO-l-Saturated fraction m/z 217

5.9E5 5.5B5 5.2E5 4.9E5 4.6E5 4.2E5 3.9E5 3.6E5 % 50- 3.3E5 2.9E5 2.6E5 2.3E5 .2.0E5 -1.6E5 -1.3E5

-6.5E4

•O.OEO 50:00 1:00:00 1:05:00 1:10:00 1:15:00 1:25:00

Fig. 2. (a) Tritcrpane distribution (m/z 191) and (b) stcrane distribution (m/z 217) in NSO-1. Both the fragmcntograms are obtained by GC-MS analysis of the saturated hydrocarbon fraction. Identification of important peaks: (a) In m/z 191: A, 18a(H>22 t29,30-trisnomeohopanc (Ts); B, 17o(H)-22^9,30-trisnorho- pane (Tm); Z, 17o(H) t21^(H)-28,30*bisnorhopane; C, 17«(H),210(H)-3O-norhopane; D, 17^(H)^la(H> 30-norhopane; E, 17o(H),21/?(H)-hopanc; F, 17/?(H),21a(H)-hopane; JI, 17a(H),2l/J(H)t22S-bishomoho- pane; J2, 17oc(H) k21^(H)>22J?-bishomohopane; and Q, C24H44tricyclic terpane. (b) In m/z 217: a, 13/7(H),l 7o(H),20(.S)-diacbolestane; b, 130(H),17o(H),2(W-diacholc$tane; c, 13e(H),170(H),2O(S)-dia- cholestane; d, 13o(H), 170(H),2O(/?)-diacholestane; h, 24-ethyt-130(H),17o(H),2O(S)-diacholestane; k, 24- ethyl-130(H), 17o(H),20(Jt)-diacholestane; !, 24-ethy!-13o(H),170(H),2O(Jt>diacholestane; n, 24-cthyl- I3o(H),170(H),2O(S>diacholestane; q, 24-cthyl-5o(H),14«(H), 17a(H),20(S)-cholestane; r, 24-ethyl- 5o(H), 140(H), 170(H),20(A)-cholestane; s, 24-ethyl-So(H), 140(H), 170(H),2O(S)

Doctoral Dissertation by Sunil Bharati, 1997 Paper 7: A New North Sea oil based standard for Iatroscan 175

52 Sunil Bharati el at.

Table 2. Selected geochemical parameters based on tritcrpane and Parameter Value 1 17e(H)-22,29.30-trisnorhopane/18a(H)-22,29,30-tranomeohopanc (Tm/Ts) 0.85 2 17e(H),21/i(H)-30-norhopanc/17ir(H) 12I/l(H)-hopane 0.45 3 15a-mcthyM7a(H)-27-norhopane/17a(H),21/?(H)-hopanc 0.09 4 CuHutricyclic terpane/17a(H),21/J{H)-hopane 0.03 5 17^(H)^la(H)*30*norhopane + 17^(H)21a(H>hopanc/17e(H)2iP(H)-30-norhopane + !7a(H)21/l(H)-hopane 0.15 6 17a(H),21^(H),22S/I7a(HWI«H)22K + 225-bishomohopane 57.96 7 13P(H).17a(H),20(S>diacholestane/13^(H).17a(HU0(S)-diacholcstanc + 5a(H),!4a(H),17e(H),20yi)-cho!cstanc 0.78 8 % 24ethyl-5a(H),14a(H),17a(H)^0(S)-cholestane 46.10 9 X 27 diasteranes/X 29 diasterancs 0.92 10 % 24^thyl 5a(H).l4f(H).17f(H)jO(A) and 20(SKholestane 61.0

A predominantly marine OM source for the oil is were reproducible, giving uniform FID responses. indicated by the low pristane to phytane ratio (Pr/ Analysis of the saturated hydrocarbons fraction Ph) and the low carbon preference index (CPI) with varying amounts of sample (ca. 3-44 pg) gave values (Table 1). The triterpane and sterane distri­ a correlation coefficient of 0.998 (n = 15, Fig. 4a). butions (Fig. 2) and the parameters derived from Similar analyses of the aromatic hydrocarbons frac­ these data (Table 2), also clearly indicate a predo ­ tion (ca. 7-86 pg) gave a correlation coefficient of minantly marine OM source of NSO-1. 0.997 (n = 15), while the polar fraction (ca. 1- 30 pg) gave a correlation coefficient of 0.998 Separation of NSO-1 maltene fraction (n = 17) on linear regression (Fig. 4b and c, re­ Examination of a developed PTLC plate at spectively). These results clearly indicate the stab­ 254 nm clearly revealed the separated fractions. ility of the responses of each of the fractions: Table 3 shows the yields of the three fractions. Fig. 4(b) also shows the percentage of the total Analysis by TLC-FID showed that the SAT 1 frac­ area eluting as polars in the various aromatic hy­ tion was virtually pure (Fig. 3). The ARO 1 fraction drocarbon analyses. Apparently, power regression was, however, contaminated with polar compounds of the peak area that elutes as polars shows that (about 11% by weight), whilst the POL 1 fraction the relative amount of sample material eluting as was relatively clean, but split into two closely elut­ “polars ” decreases with increasing sample amount ing peaks. However, a second round of PTLC using applied. The reason and significance of this is not ARO 1 and POL 1 fractions removed much of the entirely clear. In general, the relative peak area elut­ unwanted material in each of these fractions, result­ ing as polars is about 6-10% of the total ARO 2 ing in much purer fractions, ARO 2 and POL 2, re­ fraction (when the injection consists of about 20- spectively (Fig. 3). The SAT 1 and POL 2 fractions 82 pg), which should be seen as an addition to the were, as a result of further PTLC separation, nearly actual area due to the POL 2 fraction in the mixed 100% pure, but about 10% of ARO 2 continued to standard (see the next section). consist of polar material which was impossible to Gas chromatographic analyses of the two hydro­ remove even after two further purification steps by carbon fractions (Figs 5 and 6) do not give any in­ PTLC. dication of cross-contamination. Analyses by GC-MS of SAT 1 and ARO 2, indi­ Analysis of the isolated fractions cated only trace levels of contamination, based on Iatroscan analyses of the three fractions (SAT 1, fragmentograms m/z 57, 91, 92, 99, 106, 142, 191, ARO 2 and POL 2) which were to be used to pre­ 198, 217 and 253. While the saturated hydrocarbons pare the standard mixture showed that the results fraction has only traces of alkylbenzenes, the arc-

Table 3. Yields of various fractions from the total amount of 2.135 g maltene spotted on 10 PTLC plates. Only the SAT 1, ARO 2 and POL 2 fractions were used in the standard mixture Fraction Yield (mg) Rr Yield (%) 1 Saturated HC (SAT 1) 1191.2 0.64-0.87 59.10 2 Aromatic HC (ARO 1) 747.7 0.75-0.99 (purified further) 3 Aromatic HC (ARO 2) 651.6 0.75-0.99 3233 4 Polars (main) (POL 1) 50.6 0.67-1 (purified further) 5 Polars (main) (POL 2) 36.0 0.67-1 1.79 6 SAT/ARO boundary 69.6 nd 3.45 7 ARO/POL boundary 20.6 nd 1.02 8 Polars (secondary) 24.6 nd 121 9 Spot (material not eluted) 22.0 — 1.09 Total quantified 2015.6 100.00 nd, not

Norwegian University of Science and Technology 176 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

A new North Sea oil-based standard for Iatroscan analysis 53

SAT 1 ARO 2 POL 2

cm cm cm (a) (b) (c)

Fig. 3. TLC-FID chromatograms of the separated and pure fractions from PTLC; (a) saturated hydro ­ carbons (SAT 1), (b) aromatic hydrocarbons (ARO 2) and (c) polar compounds (POL 2). These frac­ tions were subsequently used to prepare the standard mixture.

matte hydrocarbons fraction is dominated by alkyl- This suggests that in the 10 repeat analyses, while benzenes (signal intensity 42 times stronger than in there was about 6% variation in the actual amounts the saturated hydrocarbons) and alkylnaphthalenes quantified, there is much less variation in the rela­ (signal intensity more than 100 times stronger than tive percentages of the fractions, indicating human in the saturated hydrocarbons); only traces of n- error during sample application, rather than the alkanes, triterpanes and steranes were detected in reproducibility of the Iatroscan. With regard to the the aromatic hydrocarbon fraction. amounts quantified in the standard mixture, the saturated hydrocarbons were calculated to be Preparation of the standard 20.63 pg in a 2-p\ injection, compared with the theoretically calculated 20.46 pg. The aromatic As a result of 10 repeat analyses of the NSO-1 hydrocarbons are slightly underestimated (reported maltene fraction by Iatroscan, the percentages of as 8.89 pg compared with the theoretically calcu­ saturated and aromatic hydrocarbons and polar lated 9.84 pg) and the polar compounds are over ­ compounds were found to be 59, 31.2 and 9.8, re­ spectively (Fig. 7a). Accordingly, a standard was estimated (reported as 2.?1 pg compared with the prepared by weighing the PTLC fractions to give a theoretically calculated 0.96 pg). Closer examination mixture with a roughly similar composition, of these variations reveals that this is due to the namely: 65.46% SAT 1, 31.47% ARO 2 and 3.07% contribution of ARO 2 to the polars. POL 2 (Fig. 7b). The reason for using such a low It has been shown that, depending on the amount amount of POL 2 was the limited quantity obtained applied, some of the ARO 2 fraction elutes as (Table 3). With the prepared standard having a polars. It is also known that the total amount of concentration of 15.63 pg/pl, a typical injection of the ARO 2 fraction in a 2-pl injection is 9.84 pg. 2 pi will theoretically contain 31.26 pg maltene, con ­ Using the power regression equation, it is estimated sisting of 20.46 pg saturated hydrocarbons, 9.84 pg that for this amount, about 11% of the total aro ­ aromatic hydrocarbons and 0.96 pg polars. matic area will elute as polars, indicating that the Repeat analyses of the prepared standard mixture area reported for aromatic hydrocarbons (55460) (Fig. 7b and Table 4) show that the standard devi­ represents only 89% of the total area or 89% of ation in the actual amounts is greater (6, 6.7 and 9.84 pg, which is 8.75 pg. This calculated amount 7.7%, respectively) than the standard deviation in (8.75 pg) is close to the actual aromatic hydro ­ the compositional percentages (1.8, 4.8 and 7.3). carbon amount reported for the prepared standard

Doctoral Dissertation by Sunil Bharati, 1997 Paper 7: A New North Sea oil based standard for Iatroscan 177

54 Sunil Bhaiati et al.

(a) Calibration of saturated hydrocarbons 250 ♦ SAT 1

200

150

100

80

2 6 10 14 18 22 26 30 34 38 42 46

(b) Calibration of aromatic hydrocarbons

♦ Polar area * Total ARO 2 area * Polar area % 500-

500-

-10 a 300- T ....

18 26 34 42 50 58 66

(c) Calibration of polar compounds

POL 2 250-

200- -

11 13 15 17 19 21 23 25 27 29 31 Amount applied (#ig)

Fig. 4. Cross-plots of sample amount vs. corresponding FID response, (a) Saturated hydrocarbon frac­ tion (SAT 1). Fifteen samples were analysed with varying amounts (3.2-44.66 pg). The resulting re­ sponse factor using the equation y *=* a + bx is 4017. (b) Aromatic hydrocarbon fraction (ARO 2). Fifteen samples were analysed with varying amounts (7.6-85.66 pg). The resulting response factor using the equation y = a + bx is 6235. (c) Polar compounds (POL 2). Seventeen samples were analysed with varying amounts (1.2-30 pg). The resulting response factor using the equation y =* a + bx is 8352.

Norwegian University of Science and Technology 178 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

A new North Sea oil-based standard for Iatroscan analysis 55

SAT 1-NSO-l

■5 600

Time (minutes) Fig. 5. Gas chromatogram of saturated hydrocarbon fraction (SAT 1) on a column (25 m; i.d. 0.25 mm, film thickness 0.3 /ml) coated with OV1, temperature programmed from 80-300°C at 4°C/min and held at 300°C for 20 min. Peak identification example: nCu denotes normal penladecanc.

ARO 2-NSO-l

360 -

> 280

g 240

Time (minutes)

Fig. 6. Gas chromatogram of aromatic hydrocarbon fraction (ARO 2) on a column (40 m; i.d. 0.25 mm, film thickness 0.3 pm) coated with SE 54, temperature programmed from 40-290°C at 4°C/ min and held at 290°C for 20 min. GC equipped with both FID and FPD detectors. Peak identification key to isomers: MN, mcthylnaphthalene; EN, ethylnaphthalene; DMN, dimethylnaphthalene; TMN, trimethylnaphthalene; P, phenanthrene and MP, methylphcnanthrene. The numerical prefixes denote the position of the alkyl group.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 7: A New North Sea oil based standard for Iatroscan 179

56 Sunil Bharati et at.

(a) (b) Fig. 7. TLC-FID chromatogram of (a) NSO-1 maltene and (b) the gravimetrically prepared standard using the separated fractions obtained by PTLC. The percentages of saturated hydrocarbons, aromatic hydrocarbons and polars are 59, 31.2 and 9.8, respectively in NSO-1 maltene and 65, 28 and 7, respect­ ively in the gravimetrically prepared standard.

(8.89 pg). Had all of the 9.84 pg eluted as aromatic 7.0% polars (reported as 2.21 pg), all with a 2-pl hydrocarbons, the area would have been 62315. injection. Therefore, in the total area of 18569 reported for CONCLUSIONS the polars in the prepared standard, a significant portion (6855) is due to material from the AR02 The standard mixture of saturated and aromatic fraction eluting as polars. Therefore, despite the hydrocarbons and polar compounds prepared from fact that the theoretical percentages of SAT 1, the maltene fraction of the Oseberg oil NSO-1, has been shown to give reproducible results and can be ARO 2 and POL 2 in the prepared standard are considered as a normal oil from the North Sea, and 65.46, 31.47 and 3.07, respectively, during analysis, can be easily and successfully employed to calibrate the standard’s composition obtained will be: the Iatroscan. In addition, the composition of the 65.0% saturated hydrocarbon (reported as prepared standard is close to the actual composition 20.63 pg), of the maltene fraction of Oseberg oil. Further, on 28.0% aromatic hydrocarbon (reported as TLC-FID analysis, the composition of the prepared 8.89 pg) and standard mixture is found to be nearly the same as

Table 4. Results of 10 repeat Iatroscan analyses of the prepared standard using the same amount (2 pi) each time. The response factors used are 4017, 6235 and 8352 for saturated hydrocarbons, aromatic hydrocarbons and polars, respectively, these being the new response factors based on the standard mixture prepared from the NSCM maltene

Saturated hydrocarbons Aromatic hydrocarbons Polars

Peak area Pg (%> Peak area Pg (%) Peak area Pg <%)

Mean 82876 20.63 (65) 55460 8.89 (28) 18569 Z21 (7) SD 4976 1.24 (1.15) 3733 . 0.60 (135) 1382 0.17 (0.51) SD (•/,) 6 6 (1.8) 6.7 6.7 (4.8) 7.4 7.7 (73)

Norwegian University of Science and Technology 180 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

A new North Sea oil-based standard for Iatroscan analysis 57

its theoretically calculated composition, when the Organic Geochemistry 1993 (Edited by Telntes N„ Graas response factors calculated from the three individ­ G. and 0ygard K.), Org. Geochem. 22, 835-862. ual fractions are used. Pergamon, Oxford. Karlscn D. and Latter S. (1989) A rapid correlation Employment of this standard by different labora ­ method for petroleum population mapping within indi­ tories will make the comparison of inter-laboratory vidual petroleum reservoirs: applications to petroleum Iatroscan analyses more reliable; now even more reservoir description. Correlation in Hydrocarbon important since Norwegian oil companies and the Exploration, pp. 77-85. Norwegian Petroleum Society, Norwegian Petroleum Directorate have decided to Graham and Trotman, London. use quantified crude oil and extract compositional Ray J. E., Oliver K. M. and Wainwright J. C. (1982) The application of the Iatroscan TLC technique to the data from Iatroscan rather than from MPLC. analysis of fossil fuels. In Petroanalysis 81, IP Symposium, London, pp. 361-388. Hcyden and Son, London. REFERENCES The Norwegian Industry Guide to Organic Geochemical Bharati S„ Rerstum G. and Lorbcrg R. (1994) Calibration Analyses, 3rd edition, 1993 (A joint publication by and standardization of Iatroscan (TLC-FID) using Statoil, Saga Petroleum, Norsk Hydro, IKU, Geolab standards derived from crude oils. In Advances in Nor and the Norwegian Petroleum Directorate).

OG 26/1-2—C

Doctoral Dissertation by Sunil Bharati, 1997 Paper 8: Elucidation of the Alum Shale kerogen structure 181

Chapter 9: Paper 8

Elucidation of the Alum Shale kerogen structure using a multi­ disciplinary approach

Sunil Bharati \ Richard Patience 2, Steve Larter 3, Guy Standen 4 and Iain Poplett 5

1 - Geolab Nor, N-7002, Trondheim, Norway 2 - Statoil, N-4035 Stavanger, Norway 3 - NRG, Drummond Building, University of Newcastle, U.K. 4 - School of Chemistry, University of Bristol, U.K. 5 - BP Research, Sunbury on Thames, U.K.

Ort. Ctockm. VoL 23. No. 11 12. pp. 1043-1058. 1995 Copyright f 1996 Elsevier Science Ltd Printed in Great Britain. All rights reserved 0146-6380 95 S9.50 - 0.00

Elucidation of the Alum Shale kerogen structure using a multi-disciplinary approach

SUNIL BHARATI'. RICHARD L. PATIENCE-*. STEVE R. LARTER.'' GUY STANDENt and IAIN J. F. POPLETP 'Geolab Nor. PO Box 5740 Fossegrcnda. 7002. Trondheim. Norway. :BP Research. Chertsey Road. Sunburv on Thames. Middlesex TW16 7LN. U.K. 'NRG. Drummond Building. The University. Newcastle upon Tyne NE1 7RU. U.K_. 'Organic Geochemistry Unit. School of Chemistry. University of Bristol. Bristol BS8 ITS. U.K.

(Received 28 February 1994: returned for revision 7 July 1995: accepted 30 November 1995 1

Abstract—The significance and validity of integrating data obtained from a variety of analytical techniques to understand, elucidate and model kerogen's complex chemical structure is reported here using degradative (open and closed system pyrolysis, chemical oxidation), non-degradative (l*C CP'MAS NMR) and optical (incident white light and blue light) methods. Seven Cambrian Alum Shale samples, ranging in maturity from immature to post-mature with respect to petroleum generation, were studied and were chosen for their simple geological history, uniform organic matter type and high organic carbon content. The Alum Shale kerogens. which primarily consist of algal organic matter, liberate low molecular weight gaseous and aromatic compounds on pyrolysis and give mostly branched dicarboxylic adds on chemical oxidation. "C NMR spectroscopy shows that the Alum Shale kerogens arc anomalously rich in oxygen-bearing functional groups (such as C * O. ArCO. CHO. CH.O). most of which apparently remain intact within the kerogen macro-molecule (KMM) through the diagenetic and catageoetic stages. Fragments released by different degradative techniques are quantified and the aromatidty (f«). O/C and relative proportions of various carbon types estimated by l$C NMR. A synthesis of these data has allowed us to better understand the chemistry of the Alum Shale kerogen. Copyright © 1996 Elsevier Science Ltd

Key words —kerogen structure. pyrolysis-GC. chemical oxidation. nC NMR, aromaticity. Alum Shale

Norwegian University of Science and Technology 182 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Org. Grochrm. Vo!. 23. No 11 12. pp. 1043-1058. 1995 Copyright C 1996 Elsevier Science Ltd Pergamon 0146-6380(95)00089-5 Printed m Great Britain. All rights reserved 0146-6380 95 S9.50 - 0.00

Elucidation of the Alum Shale kerogen structure using a multi-disciplinary approach

SUNIL BHARATI1. RICHARD L. PATIENCE-*. STEVE R. LARTER.1 GUY STANDEN4 and IAIN J. F. POPLETT 'Geolab Nor. PO Box 5740 Fossegrenda. 7002. Trondheim. Norway. :BP Research. Chcrtsey Road. Sunbury on Thames. MiddlesexTW16 7LN. U.K. ’NRG. Drummond Building. The University. Newcastle upon Tyne NE1 7RU. U.K.. ’Organic Geochemistry Unit. School of Chemistry. University of Bristol. Bristol BS8 ITS. U.K.

tReceived 28 February 1994: relumed for revision 7 July 1995: accepted 50 November 1995 1

Abstract—The significance and validity of integrating data obtained from a variety of analytical techniques to understand, elucidate and model kerogen's complex chemical structure is reported here using degradauve (open and closed system pyrolysis, chemical oxidation), non-degradativc f’C CP'MAS NMR) and optical (incident white light and blue light) methods. Seven Cambrian Alum Shale samples, ranging in maturity from immature to post-mature with respect to petroleum generation, were studied and were chosen for their simple geological history, uniform organic matter type and high organic carbon content. The Alum Shale kerogens. which primarily consist of algal organic matter, liberate low molecular weight gaseous and aromatic compounds on pyrolysis and give mostly branched dicarboxylic acids on chemical oxidation. "C NMR spectroscopy shows that the Alum Shale kerogens are anomalously rich in oxygen-bearing functional groups (such asC « O. ArCO. CHO, CH,0). most of which apparently remain intact within the kerogen macro-molecule (KMM) through the diagcnetic and catagcnetic stages. Fragments released by different degradative techniques are quantified and the aromaticity (f.). 01C and relative proportions of various carbon types estimated by l’C NMR. A synthesis of these data has allowed us to better understand the chemistry of the Alum Shale kerogen. Copyright © 1996 Elsevier Science Ltd

Key words —kerogen structure. pyrolysis-GC. chemical oxidation. "C NMR. aromaticity. Alum Shale

INTRODUCTION than one technique. While their work throws new Several studies have been conducted in the past, using light on essential differences between different a variety of techniques, aimed at elucidating the kerogen types, our understanding of kerogen's structure of kerogens. The most common degradative complex chemical structure is still restricted, partly techniques have been chemical degradation (e.g. due to the size and complexity of the kerogen Simoneit and Burlingame. 1973; Vitorovic. 1980; macromolecules and because models developed using Mycke and Michaelis. 1986) and pyrolysis (e.g. one set of samples may not apply to other samples of Latter and Douglas. 1982). Non-degradative tech­ similar kerogen 'type'. niques included infrared spectroscopy (e.g. Robin In this paper, we have applied a variety of and Rouxhet, 1976; Rouxhet et al.. 1980). nuclear techniques, such as pyrolysis-gas chromatography, magnetic resonance (e.g. Miknis et al., 1982; Solli ”C CP/MAS NMR and chemical degradation, to et al., 1985; Mann et a/.. 1991) and electron investigate the Cambrian Alum Shales from southern microscopy (e.g. Oberlin et al., 1974. 1980). While Sweden and Norway. This shale (Andersson et al., such studies have made a significant contribution to 1985) is interesting from the point of view of its our understanding of the kerogen macromolecule, simple geological history (Thickpenny, 1987), uni­ there remains a lot that is not known about its form organic matter type (Bharati, 1989; Bharati and structure, primarily because most of these studies Larter. 1991) and unusual chemistry (Dahl et al., have attempted to address the problem based on a 1988; Lewan and Buchardt, 1989; Bharati et al., 1992; single technique resulting in a narrow and incomplete Horsfield et al., 1992). The sample suite used in this understanding. Behar and Vandenbroucke (1987) study is from southern Sweden and Norway. however proposed structural models of the three principal kerogen types based on data from more SAMPLES AND GEOLOGY The present study used seven outcrop samples (2 •Present address: Statoil. 4035 Stavanger, Norway. tPresent address: 7 New Row. Tanyard Lane. Steyning, W. samples are from the same location) of Alum Shale Sussex. UK. (Late Cambrian) (Fig. 1). It consists of a black

Doctoral Dissertation by Sunil Bharati, 1997 Paper 8: Elucidation of the Alum Shale kerogen structure 183

1044 Sunil Bharati el el.

NORWAY SWEDEN

Stockholm •'

Gats berg Gotland

Legend

1. Pilstorp 2. GoMSter 3. Kvamtorp 4 . Trolmen Cambro-SUurtan 5. Rokstorp sediments 6. KrekHng Malmo\ I Cambrian AX*n Shale .Bornholm

Cambrian Alum Shales In Southern Scandinavia

Fig. 1. Map of southern Scandinavia showing the Alum Shale Formation exposures and the locations of the samples included in the present study.

laminated shale and mudstone facies, 10-60 m thick, to maximize uniformity in sample age and organic with large amounts of organic matter (typically facies. The Alum Shale, which is today found 10-12% TOC). The unit represents a long period of as erosional outliers in several parts of Scandinavia very slow epi-continental deposition (3-10 mm /1000 (Fig. 1), is not at present a recognized petroleum years; Thickpcnny, 1987) in a paleo-basinal area of source rock, although its exploitation dates back perhaps several thousand square kilometres; it is to the beginning of this century (Andersson et al., uniquely enriched in trace elements, especially 1985). More details about the geology of the uranium and vanadium (Andersson et al., 1985). The Alum Shale and of the samples studied can be found formation rests on the Balto-Scandian Platform in Andersson et al. (1985) and Bharati (1989) (a gneissic Precambrian basement), that was an area respectively. of great stability during the Late Cambrian Some Alum Shale outliers in southern Sweden are (Andersson et al., 1985). The samples used in this capped by Permian dolerite sills (present thickness study are restricted to the Peltura scarabaeoides up to ca. 60 m; Dahlman and Gee, 1977), for example (Westergird, 1922) stratigraphic zone (2-9 m thick) in the Billingen area (location 5 in Fig. 1). The

Norwegian University of Science and Technology 184 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Elucidation of the Alum Shale kerogen structure 1045

Table 1 Screening analyses data for the Alum Shales Sample Location Sample TOC HI 01 HC ■ V : Ro bit ; : Vol F * Vol. NF ' Matuntx * number code 1 I'.i tppmi (•-.) Cel (*et 1 Gosseter GOS-2-86 22 439 10 1.05 8" 0.36 28 3 Immature Palstorp PALO-86 12 402 16 1.01 130 0.25 19 5 Immature 3 Gosseter GOS-5-86 15 329 19 ixr 110 0.34 0 6 Immature 4 Trolmen TR-6 12 269 35 0.98 68 0.41 12 Earlx mature 5 Kvamtorp K5-86 19 22? 23 0.99 113 0.34 23 20 Earlx mature 6 Rokstorp SK-3-86 13 152 7 0 76 58 0 45 1 12 Late mature Krekling KR-21 12 0 5 0.08 4.83 0 32 Post mature 'See Fig. I. Samples 1 and 3 arc from the same location. -"From Bharati (19891. 'From Horsfield ct at. (19931. 1 Volume of fluorescing macerals ' Volume of non-fluorcscmg maccrals as related lo total rock volume (Bharati and Barter. 19911. • Estimated with respect to oil generation for Type II kerogcns.

thermal influence of these dolerite sills has probably achieved using a Micro PDP 11 53 (Digital) and VG's been variable in different areas, although no attempt Multichrom v3.4 software. Quantitation used peak was made in the present study to describe this areas related to the peak area of the internal variation. standard. The samples discussed in this paper are from southern Sweden (Palstorp. Gosseter. Kvamtorp. Solid state L‘C CP'MAS NMR Trolmen and Rokstorp) and Norway (Krekling) Measurements were made using a Broker MSL 300 (Fig. 1). As the age of the Alum Shale proscribes the instrument at 75.47 MHz. An independent f. (f, is the presence of higher plant derived vitrinite. maturation degree of aromaticity) measurement was made from was based on bituminite reflectance which varied standard CP/MAS spectra recorded at 25.47 MHz on from 0.3 to about 4.0% (Bharati and Latter. 1991). a Broker MSL 100 spectrometer, to check the carbon The Pilstorp and Gosseter samples are thermally type analysis. A detailed description of this technique immature, the Trolmen and Kvamtorp samples are is given by Mann et al. (1991). Briefly, average early mature, while the Rokstorp sample has a base molecular structures were obtained by a carbon "type" of oil-window maturity. The organic matter in the analysis technique that involved the fitting of the Oslo area (the Krekling sample) is graphitic in nature simulated spectrum to the dipolar dephased spec­ and is over-mature (Table I). trum. and then the deconvolution of the standard CP/MAS spectrum into individual carbon type ANALYTICAL METHODS resonances (Appendix 1). using chemical shift data obtained from standard compounds. All chemical Total organic carbon (TOC) was measured using a shifts were measured relative to the methine carbon LECO CR12 carbon analyzer. Samples were pow ­ resonance of solid adamantane. which is 38.56 ppm dered. treated with 10% HC1 to remove carbonate relative to TMS. The distribution of each chemical carbon, washed with distilled water and oven dried shift histogram for every carbon type was subjected (60:C. 12 h). Bulk pyrolysis, using powdered whole to a moment analysis to yield a mean chemical shift rock aliquots, was performed using Rock-Eval as described by Espitalie et al. (1977). Kerogen and a median width. The individual carbon types applied in the carbon concentrates were prepared by treatment of the type analysis of "C NMR spectra (Appendix 1) are sample with 37% HC1 followed by 48% HF. based on the model developed by Mann et al. (1991) Quantitative-pyrolysis —gos chromatography (Q-Py- of carbon types likely to be present in coals and GCi kcrogens and uses about 140 reference compounds identified from the literature (e.g. Bremser et al., The kerogen concentrates were ultrasonically 1981). Criteria for selection and subsequent treatment extracted with DCM'MeOH (93:7 v/v) prior to of chemical shifts are described in Trewhella et al. pyrolysis. Poly para-t-butyl styrene was used as (1986), as are the limitations of this approach. The internal standard (1% by weight). A known amount distribution of each chemical shift histogram for of standard was added to an accurately weighed every carbon type was subjected to a moment analysis kerogen sample suspended in a solvent and to yield a mean chemical shift and a median width. ultrasonically mixed before Q-Py-GC analysis The additional carbon types were given a chemical (barter and Senftle, 1985) using a Varian 3700 gas shift from the updated data-base and a median width chromatograph equipped with a CDS 100 pyrolyser. equal to those of similar groups. The chemical shift A DB-1 bonded phase column (length = 30 m; distribution was assumed to be Gaussian. l.D. = 250 pm: film thickness = 1 pm) was tempera­ ture programmed from —50 C (held at —50" for Ruthenium tetroxide oxidation 5 min) to 300"C at a rate of 4'C/min (held at 300"C for 15 min) using helium as carrier gas. Pyrolysis was The oxidation was carried out according to carried out at 800"C for 20 s. Data acquisition, Standen and Eglinton (1992). A sample of kerogen processing, peak integration and quantitation were (10-25 mg) was mixed with acetonitrile/chloroform

Doctoral Dissertation by Sunil Bharati, 1997 Paper 8: Elucidation of the Alum Shale kerogen structure 185

1046 Sunil Bharati ei at.

(2:1: 0.3 ml. containing 2.5 mg Ru (IV) oxide) and to the average value of organic carbon in source rocks water. Five internal standards ((I) d, succinic acid. (2) (2.16% in shales and 0.67% in carbonates) (Tissot 1.1 -cyclohexanediacetic acid. (3) n-octadccylsuccinic and Welle. 1984). Optical analysis of the Alum Shales acid. (4) 1.2). 30 min) at a rate of 4:C/min. Hydrogen was used as The changes in the fluorescence properties of carrier gas and nitrogen as the make-up gas. alginites. the progressive fall in HI (Table 1) Data were acquired using a Minichrom Data accompanied by a progressive increase in the System (v 1.51 software) and quantification was bituminite reflectance (‘R. Bit* in Table 1) support accomplished using peak area integration in relation this conclusion. to n-octadecylsuccinic acid. Peaks were identified by The Alum Shale solvent extract yields are rather gas chromatography-mass spectrometry using a low compared with other rich source rocks contain ­ Varian 3400 GC interfaced to a Finnigan Mat TSQ ing Type II kerogen. The extracts are depleted in 70 mass spectrometer (ionizing energy 70 eV; ion hydrocarbons, with resins and asphaltenes typically source temperature 150"C: I scan s for m:z 50-550). comprising more than 75% of the total extract An ICIS data system was used to acquire and process (Bharati, 1989). The hydrocarbon extracts contain the information. Identification and quantification of almost double the amount of aromatic hydrocarbons, compounds used the procedure of Boucher et at. compared with saturated hydrocarbon (Bharati. (1990). 1989). These findings differ from those of Tissot and Welle (1984) for other mature source rocks Microscopy containing Type II kerogens and are in general Whole rock samples were mounted (parallel and agreement with the results reported by Dahl et al. perpendicular to bedding) in epoxy blocks and (1988) and Lewan and Buchardt (1989). polished using Struer's Planapol;Pcdamax-2. The Quantitatice-prrolvsis-gas chromatography (Q-Py- samples were examined with a Zeiss Photomicro ­ OCJ scope III. linked to an HP 9816S computer. Reflectance measurements were made (oil immersion) This method was used to obtain data on compound at 546 nm wavelength. The data were acquired and types liberated on pyrolysis. A typical pyrogram processed using the Zeiss Coflex software. Fluor ­ resulting from 800'C flash pyrolysis of an Alum Shale escence was measured using blue light excitation kerogen (sample 1) is shown in Fig. 2 while Table 2 (395-440 nm) and spectral measurements were made summarizes pyrolysis data for all samples. All the using a continuous grating interference filter from 400 kerogens release, qualitatively, very similar py- to 700 nm. rolysates, resulting in similar pyrogram fingerprints, irrespective of thermal maturity and hydrogen RESULTS content, except for the post-mature sample 7, which is nearly graphitized and which has a hydrogen index Organic matter input and maturity of 0 mg HC/g TOC (Table 1). The seven Alum Shale samples have TOC values Gases (Ci-Cj) dominate the pyrolysates with ranging from 10% to 22% (Table 1). This contrasts methane, ethane and ethene being most abundant

Norwegian University of Science and Technology 186 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Elucidation of the Alum Shale kcrogen structure 1047

2000-1 C1C2 1800-

1600"

1400*

1200- 1000-

Retention time (minutes) Fig. 2. A typical 800 C flash pyrolysis chromatogram of Alum Shale kerogen. Identification of peaks: C1C2 = methane + ethane: C4 = n-propane: CS = n-pentanc: B = benzene: T = toluene: C8 = n-octane: STY = styrene: C3B = C3-alkvlbenzenc: S = internal standard: 2MN — 2-methylnaphlhalcnc: 1MN = 1- mcthylnaphthalcne.

(Fig. 2 and Fig. 3a). In the oil fraction (C._). the than n-Cio in the oil fraction occur only in pyrolysate is relatively enriched in low molecular insignificant amounts. The abundance of branched weight compounds with aromatic hydrocarbons and cyclic alkancs/alkenes is far more conspicuous in (mainly alkylbenzcnes and alkylnaphthalenes) occur­ the oil fraction than are the paraffins, although the ring in substantial quantities (about 10-15 and former are still in far lower concentrations than the 3-6 mg/g TOC respectively: Table 2. Fig. 3b). There alkylbenzcnes (Table 2 and Fig. 2). The average is no dominant n-alkanc-ene homology in the oil gas/oil ratio (equivalent to GOR). calculated as the fraction: in fact, concentrations heavier than n-Cio total Ci-C< yield divided by the total C<. yield, for were so low that accurate peak integration was not the Alum Shale pyrolysates generally is 0.50 or possible. Hangers el al. (1994) reported the yield of higher, except for sample 7 (Table 2). This is very alkylbenzcnes from the Kimmeridgc Blackstone high for algal Type II kerogens. which normally Band kerogen (Type II) to be about 15 mg/g TOC yield low (~0.2) gas oil ratios from pyrolysates using Py-GC. Type I kerogen (Guttenberg) gave a (Bharati. 1989). This consistency in the pyrolysates is lower alkylbcnzcne yield (about 8 mg/g TOC) and a surprising, given the changes in the kerogens sulphur-rich Type II-S kerogen (Monterey) a higher maturity levels and suggests little change in their yield (about 18 mg/g TOC). This suggests that for chemical composition while realizing that the Alum Shale kerogens. it is perhaps the lack of identified components represent only about 10-15% n-alkanes/encs that is the more significant and of the TOC. exceptional, rather than the apparent large amounts The only major change observed in the pyrolysates of alkylbenzcnes (see Fig. 2). Other paraffins lighter is yields which decrease with decreasing kerogen

Table 2. Quantitative pyrolysis (Q-Py-GC) summary data in mg-g TOC and relative percentage (in brackets) Sample A <%) B (%> C(%) DC/.) E (%) F<%> G (•/.) H (%) I* Je K* L* M* 1 52.0(34) 39.5(26) 9.3 (6) 8.2(5) 20.7(14) 15.1(10) 4.2 (3) 3.8(2) 99.7 23.0 107.5 188.6 0.57 2 54.1 (39) 33.4(25) 8.6(6) 5.3(4) 16.0(12) 11.6(8) 3.1(2) 5.9(4) 92.8 20.6 100.7 201.4 0.50 3 60.7(37) 41.0(25) 10.1 (6) 7.7(5) 21.7(13) 14.2(8) 4.4(3) 5.8(3) 109.4 24.4 118.2 210.7 0.56 4 54.3 (32) 41.8(25) 13.0(8) 8.8 (5) 24.9(15) 16.1 (10) 4.0(2) 4.6(3) 104.9 24.7 129.6 259.0 0.50 5 66.4(35) 53.6 28) 14.2(7) 7.0(4) 25-203) 17.0(9) 4.2(2) 4.6(2) 127.0 25.9 155.0 276.3 0.56 6 35.3 (37) 23.5(25) 6.2(6) 4.6 (5) 11.3 02) 8.6(9) 2.0(2) 3.4(4) 63.3 14.0 76.4 124.3 0.61 7 1.2(23) 0.7(14) 0.2(4) 0.2(4) 0.3(5) 1.4(25) 0.3(5) 1.1(20) 2.2 2.8 8.4 21.7 0.39 Explanation for columns: A * methane + ethane + ethene: B — n-hydrocarbons (C3-C5): C — branched hydrocarbons (gas fraction): D ■ n-hydrocarbons (C6-C10); E-branched hydrocarbons + NSOs .(oil fraction): F - benzene + alkylbcnzcne: G»indene + alkylindenes: H — naphthalene + alkylnaphthalenes: I — £ n-hydrocarbons (n-alkanes + n-alkenes. Ci-C10): J ■ E aromatic hydrocarbons (benzenes + tndenes + naphthalenes): K * total gas (C1-C5): L — total oil

Doctoral Dissertation by Sunil Bharati, 1997 Paper 8: Elucidation of the Alum Shale kerogen structure 187

1048 Sunil Bharati el at.

a: Aliphatic, Branched and Non-hydrocarbons

mg/g TOC Gofl

□ C1C2 EC3-10n-HC 0NHC«BHC ♦GOB

b: Aromatic hydrocarbons

mgtg TOC GOB

□Al.bOT BAUnd DAl.nip *B«n A kid XNjp ♦GOB

Fig. 3. Behaviour of aliphatic hydrocarbons, non-hydrocarbons and branched hydrocarbons (top) and aromatic hydrocarbons (bottom) resulting from the pyrolysis of Alum Shale kerogens of increasing maturity (sample I—immature to sample 7—post-mature). Identification of species: CIC2 " methane + ethene + ethane: C3-10 n-HC = C>w n-hydrocarbons: NHC + BHC = non-hydro- carbons + branched hydrocarbons: GOR — Gas:oil ratio: Al.bcn = alkylbcnzcnes: Al.ind = alkylindencs: Al.nap — alkylnaphthalenes: Ben = benzene: Ind = indenc: Nap = naphthalene.

hydrogen content, implying increasing thermal (1985) noted that alginites generate n-alkane/ene-rich maturity. The pyrolysate composition is very unusual or in some cases mixed n-, branched or cyclic for Type 11 algal-dominated marine kerogens, and alkane/ene-rich pyrolysatcs. Sporinites, like , contrasts strongly with other typical Type II marine generate aromatic pyrolysatcs dominated by alkyl- kerogens such as the Toarcian Shales of the Paris benzenes. alkylnaphthalenes and alkylphenols, Basin (e.g. Tissot and Welte, 1984; Bharati, 1989). whereas Type II marine kerogens generally produce Latter and Douglas (1980) and Latter and Senftle long chain n-alkanes/enes (Latter and Senftle, 1985).

Norwegian University of Science and Technology Doctoral 188

Dissertation

by Tabic 3. NMR data for selected Alum Shale kerogens (see Appendix I for explanation of symbols)

Sunil 2352 SSS-- *333

Bharati,

Elucidation

I I i

Mobile I? i

a 1997

and

of

the

immobile Alum

Shale (Horsfield Nevertheless, data) which (Tegelaar Antrim. alginite. heterogeneous artificial data pyrolysis elevated in of hydrocarbon-rich and NMR Type higher similar slight Appendix effected. close aromatic degrees implying higher to ArCO, ("graphitized"). a CHO the 1 since lished and CHxO carbon average). remains oxygen-containing (with more analyses the oxygen ratio Kerogens (ArCC with et only

kerogens

migrated

The and Sample result, al., Oxygen-containing Aromatic this chemical

other

above

kerogen organic

the ArCO

for

similar and samples difference

fresh

ArCH closely II to

and Spectroscopy list are will 1992).

results), 2 than

study)

in CHO

content relative (Table types

an symbols maturation,

(Table of

& kerogens (Fig.

constant (immature) Tasmanian (Bharati,

O/C

a moieties).

that produce of and "aquatic" carbon

which aquatic 1. Other

type

et

1,2

CHxO. hydrocarbons

7 ArCH) for immature

pyrite

structure reduce In deposited expected

aromaticity l5 the

matter

This > carbon composition and

f. al..

resemble C

(post-mature)

type 2.

which, such and in

to

inertinitic Noble. ratios the general,

ArCC) that

but values 4). 3). II between various cannot

Table

atom are

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Sea Paper 8: Elucidation of the Alum Shale kerogen structure 189

1050 Sunil Bharati et at.

Table 4 Elemental dau for the kerogen samples from chemical shift data, thus a number of ratios Sample H C oc H C: Aliphatic carbon have been calculated (Table 3). in order to infer 1 1.1(1 0.15* 1.05 82.9 support for rings or chains. The ratios (Patience 2 1.26 0.155 1.01 68.1 et at.. 1992) are explained below. 4 1 13 0.166 0.9$ 41.2 6 1.01 0.114 0.76 364 CH; CH*al: this is the sum of all methylene groups n.d. n.d 0 0$ 0 divided by the methyl groups attached to other alkyl n.d = no dau. Ratios from NMR data.- From elemental analysis carbon atoms (i.e. the methyl in toluene would not be (after Horsfield et at.. 1991). mg g rock (calculated! (after included here, but comes under CH-ar). This gives an Horsficld et at.. 1991 1. approximate idea of chain length (in qualitative terms only) as the higher the value, the longer the average 1992). even though a terrestrial source is impossible chain length is likely to be. Unfortunately, it can also given their age and given petrographic observations mean a high proportion of ring methylenes, not chain of abundant alginites (Bharati and Latter. 1991). methylenes. It is subject to measurement error, since However, they do not have the high ArCO values CH.al is usually small and the smaller the value, the (5-10%) [see above] associated with coals (Mann higher the relative error. ei a!.. 1991). CH:r CH;m: this is the ratio of rigid (CH.-r) to Sample 6 (late mature) differs from the above 3 mobile (CH;m) methylenes (in NMR terms). All samples in that it has a much higher f, value (Table 3) cyclohexyl ring methylenes are rigid, as are many and higher ArCAC and slightly higher ArCH values chain methylenes, the latter depending on the mode indicating that the aromatic structure is relatively of "packing" of the chains, or on chain length (shorter more condensed and less alkylated. Despite this chains, especially cross-links, are more likely to be increased condensation. ArCH is still greater than rigid). Therefore, an increase in this ratio can mean ArCAC. and the aromatic structure is not as either an increase in rings relative to chains or a condensed as "normal" aquatic kcrogens (Fig. 4). In different packing arrangement for the chains, or fact, samples 1. 2 and 4 have aromatic structures shorter/cross-linking chains. which are similarly condensed to coals, whilst sample CH;rnvCH;{C2): this is the ratio of rigid and 6 is intermediate between coals and "normal* aquatic mobile methylenes (CH-rm) relative to methylene kerogens (Fig. 4 and Mann ei al.. 1991). Otherwise, adjacent to a terminal methyl (CH=(C2)). This should sample 6 differs from other aquatic kerogens in give similar information to CHi/CHjal. It is also exactly the same ways as the less mature Alum Shales subject to error in that CH:(C2) can have a small (see below). value. Alkyl carbon types (C. CH. CH;. CH>ar and CH.ICH: The ratio of methylenes to methines will CHtal). In all of our kerogens analyzed to date, the be low when the kerogen contains either abundant dominant alkyl carbon type is CH;. In this respect, acyclic isoprenoids or other branched chain com ­ the Alum Shale kerogens do not differ from the other pounds. or abundant fused alicyclic ring systems (e.g. aquatic kerogens (Table 3). NMR cannot distinguish steranes.'hopancs). In both cases, it indicates a between acyclic ("chain") and alicyclic ("ring") carbons reduction in the relative abundances of n-alkanes. For the Alum Shale kerogens. the two parameters with consistently large differences compared to other

S*mpi$ Type aquatic kerogens are CH-r/CH:tn (very much higher) lets B inert * Alum Shales and CH:/CH (much lower) (Fig. 5). These trends are internally consistent, although there is more than one explanation for the differences. Firstly, the Alum Shale kerogens could be enriched in rigidly packed branched chain compounds (this would explain both ratios); secondly, there could be a greater abundance of fused alicyclic (ring) compounds (this also explains both ratios); thirdly, there may be shorter and/or cross-linked chains (rigidimobiie ratio goes up) combined with either of the first two possibilities. These possibilities will be discussed later in the light

AromebeHy (It) (%} of the data from chemical degradation. In summary, the four Alum Shale kerogens Fig. 4. Degree of aromatic ring condensation (ArCAC.'fa) versus aromaticity (fa) for the Alum Shale kerogens and analysed 1, 2, 4 and 6 are unique. Compared to other representative kerogen types. The dotted line is the "normal" aquatic kerogens, they have higher than linear regression trend for the aquatic kerogens. the thin average O/C ratios (Table 4) and higher concen ­ solid line for coals and the dashed line for the inert kerogens. trations of oxygen-containing functional group Note that the Alum Shales (solid stars) plot at or near the concentrations (except ArCO). The aromatic struc­ regression trend for coals. Data considered for aquatic kerogens. coals and inert kerogens are unpublished ture resembles that of coals, i.e. a greater abundance (Patience). of protonated rings and less ring junction carbon.

Norwegian University of Science and Technology 190 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Elucidation of the Alum Shale kcrogen structure 1051

Rim Chemical degradation Chemical degradation was used to obtain struc­ tural information on the aliphatic portion of the kerogens. Oxidative degradation converts the kero ­ gen into soluble, identifiable and structurally significant fragments, the amount of conversion depending on the inherent properties of individual kerogens. Generally, an oxidizing agent attacks kerogen at. or next to. carbon atoms bearing a functional group. Oxidation of kerogen with RuO, results essentially in (1) degradation of aromatic rings (toluene for instance will convert into acetic acid + CO:). (2) Conversion of alcohols into alde­ Ktogtn Typ• hydes. ketones or acids (depending on the position of Fig. 5. Relative abundances of CH:r'CH:m and CH.-'CH in the OH group). (3) Conversion of aldehydes into the Alum Shale Icerogens (average of samples 1. 2.4 and 6) acids. (4) Conversion of alk-l-enes into aldehydes and other representative kerogen types based on NMR and,or ketones. However, aliphatic and alicyclic analysis. Aquatic kerogens represent Types Id-11: coals portions remain intact. Acids are therefore the most represent Type III kerogen: inert material represents Type IV kerogen. Data considered for aquatic kerogens. coals and important products from the point of view of kerogen inert kerogens is unpublished. structure reconstruction. These reactions have been reviewed by Standen (1992). In the present study, a total of 91 compounds were except that the Alum Shales' phenolic content (and identified and quantified after RuO, oxidation: they the degree of aromaticity) is too low for coals. The accounted for roughly 99% of the total integrated alkyl structure is characterized by an unusual peak area. A typical chromatogram is shown in combination of mostly rigid methylenes, which are Fig. 6. The quantified data normalized to TOC present in lower than normal abundance relative to and also in relative percentages are presented in ‘branching" (ring or chain) carbons (CH). The fifth Table 5 and graphically in Fig. 7 for the seven sample (sample 7) is so graphitizcd that no direct Alum Shale kerogens. Identification (Table 6) of structural information could be obtained. individual acids and their isomers was achieved using

5

2- 400-

Retention time (minutes) Fig. 6. A typical chromatogram (expanded along the time axis to show the major jieaks) of the organic material resulting from ruthenium tetroxidc oxidation of the Alum Shale kerogens. Identification of peaks: I = methylpentanoic acid. 2 = hexanoic acid. 3 = butanedioic acid. 4 - methylbutanedtoic add 5 = pcntanedioic add + octanoic add. 6 = dimethylbutanedioic add. 7 = methylbutanedtoic acid. 8 - nonanoic add. 9 = hcxanedioic add. 10 = mcthylhexancdioic acid. 11 = hcptancdioic add. 12 = methylheptancdioic acid. 13 = octanedioic add. 14 = nonanedioic acid. 15-decanedioicacid. 16 = undccanedioic add + pristane. 17 = hcxadccanoic add (palmitic add) and 18 = octadecanoic add (stearic add).

Doctoral Dissertation by Sunil Bharati, 1997 Paper 8: Elucidation of the Alum Shale kerogen structure 191

1052 Sunil Bharati et at.

Table 5 Abundance of compounds liberated b> the ~ Alum Shale kerogens b> RuOl otidalion Values in both mg g TOC and *» lin brackets i NMA BMA NDA BDA ARA ALI Sample mg g TOC Co) mg g TOCCo) mg g TOC Col Ratio 1 Rauo 2 Ratio 3 Ratio 4 Ratio 5 1 2".l (14) 16.0(08) 66 4(35) 68.6(37) 5." (3) 3.5 (2) 0.41 1.70 0.97 0.29 0 19 16.4(14) 10.1 (08) 40.6 (34) 44.5(3") 4.9 (4) 2.9(2) 040 1.61 0.91 0.29 0 19 3 25.3(131 1".2(I0) 57.8(33) 65 9(3") 6.5(4) 3.7(2) 044 1.4? 0.88 0.30 0.21 4 19.9(15) 13.7(10) 48." (36) 45.3 (33) 54(4) 2.4(2) 0.41 1.45 1.0" 0.29 0.23 < 22.4(15) 16 " (11) 38.9(26) 58.5(40) -"(<) 3.1 (2) 0.58 1.34 0.66 0.3" 0.22 6 23.6(1") 20.0(15) 364(26) 48.3(35) 3.3 (2) 5.4(4) 0.65 1.18 0 75 0.39 0.29 14.61351 9.5(22) 8.1 (19) 6.6(16) 1.0(2: 2 1 (5) 1.79 1.53 1.22 0.60 0.59 Explanation for columns: NMA « normal monocarboxs lie acids: BN1A - branched monocarboxvlic aads lalll: NDA = normal dicarboxxlic acids. BDA - branched dicarbovlic acids lalll. ARA = alkxl mono-aromaiics IDA and TA1: ALI = normal alkanes, ratio I = NMA NDA: ratio 2 = NMA BMA: ratio 3 = NDA BDA. ratio 4 = NMA NMA 4- NDA: ratio 5 = BMA BMA - BDA

target compound analysis (TCAl and reverse library product. Differences between the samples with search of GC-MS data (Boucher et al.. 1990). All the respect to the relative distribution of constituents are compounds fall in six major categories, which are: I) insignificant apd no major change in the trend is normal monocarboxylic acids (NMA). 2) branched observed between branched monocarboxylic acids monocarboxvlic acids (BMA). 3) normal dicarboxylic substituted with one. or two. methyl groups with acids (NDA). 4) branched dicarboxylic acids (BDA). increasing maturity. 5) monoaromatic di- + tricarboxylic acids (ARA) Normal dicarboxylic acids (NDA). These com ­ and 6) normal aliphatic hydrocarbons (ALI). pounds. resulting from chemical degradation of the All samples yielded similar constituents in compar ­ Alum Shale kerogens are second in abundance able proportions, suggesting consistency in the (generally 26-35%) (Table 5). Despite their greater aliphatic portion of Alum Shale kcrogens. irrespec­ abundance with respect to the monocarboxylic acids, tive of location: this accords with the lack of variation the two are similar, in that the NDA distribution is in the pyrolysates. Clearly, four of the categories also characterized by relative high abundances of low- NMA. BMA. NDA and BDA dominate the molecular weight diacids ( < Ci2). in contrast to other products, accounting for more than 90% of the total marine kerogen samples. Additionally, except for an yield (Table 5). Amongst these four acid types, the apparent fall in the yield, there is no other major dicarboxylic acids and especially the branched difference between the samples of varying maturity dicarboxylic acids, occur in greater quantities in (Table 5). Another striking feature of the distribution nearly the entire maturity range (Fig. 7). Only in the is the sharp fall in the yield of NDAs longer than C» post-mature sample (sample 7). are the two (Fig. 8c). indeed, those with 10 or more carbon atoms monocarboxylic acids. NMA and BMA. more occur in insignificant quantities compared to the abundant. lighter counterparts. Pentanedioic and hexanedioic Normal monocarboxylic acids {NMA). This group acids (peaks 5 and 9 respectively in Fig. 6) are the of compounds typically represent 13-17% of the total predominant NDA's. acid product. Their distribution (Fig. 8a) is typically Branched dicarboxylic acids (BDA). These are characterised by relatively high abundances of low important compounds, as far as the chemical molecular weight acids (derived from < Ci: alkyl degradation of the Alum Shales is concerned, and chains), compared to other marine kerogens plus occur in largest quantities —typically 33-40% of the abundant palmitic and stearic acid. There is a sharp total content (Table 5). In samples 1. 2. 3 and 4, the fall in abundance of NMAs with more than 9 carbon relative concentrations of BDA and NDA are atoms, after which there is an even-carbon number comparable: their distributions, and changes due to predominance. The distribution of components in the maturity, arc similar to other acid fractions i.e. BDAs NMA group is comparable in all samples, irrespective too are characterized by low molecular weight of maturity (Fig. 8a). compounds, with very few differences between the Branched monocarboxylic acids (BMA). The samples (Fig. 8d). Methylbutanedioic acid (peak 4 in distribution of branched monocarboxylic acids Fig. 6) consistently occurs in largest quantity in all (Fig. 8b) is very similar to that of NMAs in that it the samples, except in sample 7. A significant feature is characterized by relatively high abundances of low of the BDA distribution is that compounds with a molecular weight acids (C,-C«) compared to other methyl branch are at least twice as abundant as their marine kerogens. No BMA was detected with more dimethyl (or ethyl) counterparts (e.g. methylbutane ­ than 9 carbon atoms in a chain. Methylpcnianoic dioic acid » dimethylbutanedioic acid and so on) acid is the most abundant acid, with one of the (Fig. 8d). However, the overall abundance of both isomers being prominent (more than 50%) (peak 1 in methyl- and dimethyl branched acids systematically Fig. 6). A striking feature is that the abundance of falls with increasing carbon number. methylpcnianoic acid seems to increase with increas­ The normal aliphatic hydrocarbons (ALI) and the ing maturity (Fig. 8b), suggesting that a pentyl chain monoaromatic di- and tri-carboxylic acids (ARA) may be relatively a more important generation comprise about 2-5% and 5-7%, respectively

Norwegian University of Science and Technology 192 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Elucidation of the Alum Shale kcrogen structure 1053

Mi* Bi* NO* B* «*0 *Ut Bit BU SOI lOi *e»7fc»

TOC f

Mi*Bi*NO*BW*mO*lKBilBi2B)l KB HO* BJA *HO *Ut Bil AdiTjf

m&BTOC

, BOA AHO ALK MM MC *01 *0* AcHTyp* Fig. 7. Absolute yields in mg/g TOC of the principle add types in the 7 oxidized Alum Shale kcrogens. Abbreviations used are: NMA = normal carboxylic adds: BMA = branched carboxylic acids; NDA * normal dicarboxylic adds; BDA = branched dicarboxylic adds; ARO = alkyl mono-aromatics; ALK = normal alkanes: BM l » mono-alkyl monocarboxylic adds; BM2 = di-alkyl monocarboxylic acids; GDI = mono-alkyl dicarboxylic acids; BD2 =* di-alkyl dicarboxylic acids. Hatched bars indicate acid types which are not discussed separately in the text.

Doctoral Dissertation by Sunil Bharati, 1997 Paper 8: Elucidation of the Alum Shale kerogen structure 193

1054 Sunil Bharati ei at.

Table 6. List of branched monocarboxvlic and dicarboxxlic acids isomers identified and quantified using TCA and reverse library search, during RuO* oxidation of Alum Shale kerogens Normal acids detected and identified are not listed below, but monocarboxvlic acids ranged from hexanoic through hexacosanoic acids and dicarboxxlic acids ranged from butanedioic through hcxadecancdioic acids. (For an explanation of abbreviations of the parent groups, refer to Fig. 8) Parent Group Isomers Branched nwnoiurhuwhc acids IBM A i Mec; 2-. 5- and 4-methvlpentanoic acid ElC5 2-cthxlpentanoic acid and 1 unspecified DiMcC5 2.2-. 2.4. and 3.5-dimeihylpcntanoic acid MeC6 2* and 3-methvlhexanoic acid and 1 unspecified DiMeC6 2.4- and 3.3-dimethylhexanoic acid DiMeC 2.4- and 3.3-dimcthylheptanoic acid DiMeCS 2.6- dtmeihyloctanoic acid DiMcC9 2.6- dimcthx Inonanoic acid Branched dicarho.whc acids (BDA l McC4 3-methylbutanedioic acid DiMeC4 2.2- dimethylbutanedtoic acid and 1 unspecified MeC5 3 and 2-methylpentanedioic acid DiMeCS 3.3- and 2J-dtmethylpentanedtoic acid and 1 unspecified MeC6 2- and 3-methx Ihexanedioic acid and 1 unspecified DiMeC6 2.4- and 3.3-dimethvlhexanedioic acid MeO 2-. 3-. 4- and 5-methylheptanedioic acid DiMeC? 3.4- dimethylheptanedioic acid MeC8 2- and 3-methx loctanedioic add and 1 unspecified

(Table 5) of the total oxidation products and are not coherent, general picture of the chemical composition believed to be of any significance. Only normal of the Alum Shale kerogens. both at immature and C.o-Cii (not Cu) alkanes were identified and more mature stages. quantified. At the relatively immature stage represented by- In summary. RuO, oxidation data provides the sample 1. ”C NMR data show that the kerogen has following information: (a) the structures released are a higher degree of aromaticity (f, = 44.5%). com ­ predominantly of low molecular weight, whether pared to normal marine kerogens (f, = 27 to 33%: normal or branched compounds: (b) dicarboxylic Patience et al., 1992). Furthermore, both NMR and acids arc more abundant than monocarboxylic acids: Py-GC (open and closed systems) analyses indicate (c) the branched acids arc relatively abundant that the aromatic part of the structure consists largely compared to the normal acids and the carbon number of monoaromatic and to a lesser extent diaromatic distribution is not compatible with an origin from moieties (the former nearly twice as abundant than fused cyclohexylaromatic compounds: (d) the distri­ the latter). The solvent extracts are also relatively butions of compounds within the four compound enriched in aromatic hydrocarbons (Bharati, 1989). classes show distinct (not readily explicable) patterns, NMR also demonstrates that the kerogen contains which change little as the samples become increas­ an unusually high proportion of carbon atoms ingly mature: (c) the relative abundance of the bonded to oxygen (C = O, COOR, CHO and dicarboxylic acids as a group decreases with sample CHxO. particularly the latter two) and that these maturity unlike the monocarboxylic acids: (f) no elements represent an atypical distribution of cyclic acids were identified: (g) no acyclic isoprenoid oxygen-containing functional groups, not attribu­ acids were identified; (h) the distributions observed table to oxidation of the organic matter during are somewhat atypical as compared to other marine deposition or by weathering at outcrop. In addition. kerogens analyzed previously (Standen. 1992): (i) the ArCH species are more abundant than ArCAC, average yield of identifiable components is about implying benzenoid structures are more abundant 15% with respect to TOC, indicating only partial than naphthalenes. Surprisingly, given the deposi- kerogen degradation. tional model for the Alum Shale (low sedimentation rate in an epicontinental basin. Thickpenny, 1987), no sulphur-containing compounds were found in the DISCUSSION pyrolysates. The aliphatic part of the structure of sample 1 Chemistry of the Alum Shale kerogens consists (from chemical degradation, NMR and The data presented above and elsewhere (Bharati, Py-GC) of short, n- and branched alkyl chains 1989: Bharati and Larter. 1991; Bharati et at., 1992 (typically 1-6 carbon atoms but generally not and Horsfield et al., 1992), derives from various exceeding 10 carbon atoms). A high proportion of the techniques, namely: three pyrolysis methods (Rock- aliphatic chains appear to be cross-linked as the Eval, flash pyrolysis-GC and closed vessel pyrolysis); abundance of branched components is much higher extract analysis: fluorescence microscopy; solid state than in normal marine kerogens, although acyclic "C NMR and ruthenium tetroxide oxidation. This isoprenoid structures are much reduced. The low section attempts to integrate these data to give a more abundance of longer chain n-alkyl acids indicates

Norwegian University of Science and Technology 194 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Elucidation of the Alum Shale kerogen structure

MeCS OUMCS OU«C7 OiUtCa OWC9 BtenebeP AaP Type Acid Type fCeroon Number!

McC4 OiMdOA M.CS OUtoCS M.C8 CKUCS M»C7 IXU.C7 UeC» Brtnched Add Type Add Type (Csrbon Number) Fig 8. Relative abundances of major individual species of (a) normal monocarboxylic adds (NMA). (b) branched monocarboxylic adds (BMA). (c) normal dicarboxylic adds (NDA) and (d) branched dicarboxylic adds (BDA). Note the high abundance of palmitic add and stcanc acid m the NMA figure. Explanation of abbreviations in the branched add types: Me, El and DiMc stand for methyl, ethyl and dimethyl respectively and indicate the type of alkyl group attached to the acid. C5. <-6. C7. t-8 ana ty represent the length of the carbon chain m the parent ion. So MeCS would mean mcthylpentanotc acid. For the number of isomers in each of the branched add types, see Table 6.

why n-alkanes/cnes are not generated in significant escence to no visible range fluorescence without the amounts on pyrolysis. The chemistry of sample 1 is, orange/dark orange transition (Bharati and Latter, therefore, completely atypical of other marine 1991)), and closed vessel pyrolysis, where ‘inert’ kerogens, even though fluorescence studies show kerogen (i.e. non-convertible by Rock-Eval and flash abundant well-preserved algal organic matter with Py —GC) appeared to be formed in substantial ‘characteristic* yellow fluorescence. Although proportions (Horsfield et al., 1992). The small samples 2 and 4 are more mature than sample 1 proportion of aliphatic structures in the immature (Bharati and Latter, 1991), their chemical structures Alum Shale kerogen remains essentially unchanged are to all intents and purposes, similar to that of the with maturation, in that its yield from pyrolysis and latter. chemical degradation remains near constant irrespec­ The more mature sample 6 shows a relatively small tive of the sample ’s maturation state. increase in aromaticity compared to samples 1,2 and Overmature sample 7 appears to consist entirely of 4, from NMR analysis, but the flash pyrolysates are inert kerogen, with a sufficiently hydrogen-depleted qualitatively similar. However, there appears to be a structure such that no data could be obtained from significant increase in aromatic ring condensation NMR and very little from pyrolysis. This also helps during maturation, as suggested by Horsfield el al. to support the concept of a kerogen structure (1992). This is also demonstrated by NMR data, containing mono- and diaromatic rings when fluorescence microscopy (conversion of yellow fluor ­ immature, but which subsequently condenses on

Doctoral Dissertation by Sunil Bharati, 1997 Paper 8: Elucidation of the Alum Shale kerogen structure 195

1056 Sunil Bharati el at.

thermal maturation. Only the peripheral and recognizable maccrals. However, our present under­ non-fused kerogen sub-structures may then continue standing of marine algae, from the point of view of to generate (the same distribution of) products. kerogen geochemistry is largely based on post-Cam ­ These observations lead us to propose that the brian shales. Possibly the chemistry of the biota that dominant features of the Alum Shale kerogen existed in the Cambrian sea in which Alum Shales macro-molecule (KMM) include (a) fairly abundant were deposited was highly unusual, unparalleled in primary mono-aromatic rings (f„ = 42-57%). linked subsequent geological epochs, as suggested earlier by together in such a way so as to result in "easy" Bharati and Latter (1991). These shales were condensation, (b) an aliphatic structure consisting of deposited in very stable conditions and have not short branched alkyl and to a lesser extent n-alkyl experienced any major tectonic movements, except chains, (c) high proportions of oxygen occur in the perhaps on a minor scale in the Oslo region. They form of aliphatic alcohols, ethers and some esters and have not been deeply buried and arc thought to have carboxyl compounds. These three principle types are been at or near the surface through geological times believed to be linked together to form the KMM. (Andcrsson et al.. 1985: Thickpenny. 1987). The such that short alkyl chains arc perhaps linked, via sediments probably originated from the surrounding ether or ester groups. This possibility seems to satisfy metamorphicvolcanic areas which were rich in most of our data. metals, especially uranium which is present in the The similarity of the data obtained using different Alum Shales in anomalously high concentration (up analytical methods, irrespective of the location and to several hundred ppm) (Andcrsson et al.. 1985: maturity of the sample in an estimated 2000 sq.km. Lewan and Buchardt. 1989: Bharati. 1989: Buchardt Alum Shale basin, suggests that the KMM consists of and Lewan. 1990). Lewan and Buchardt (1989) chemically similar sub-units from the periphery to the suggested that the organic matter in the Alum Shale core. With progressive thermal degradation, part of is damaged due to radiation, and that radiation has this sub-unit is released and the remainder undergoes caused intense cross-linking of alkyl chains. How ­ internal reorganization such that the initially ever. Horsfield et al. (1992) found no good ‘producible" (labile) components ultimately become correlation between Alum Shale kerogen properties involatile, an observation made during simulated and uranium contents suggesting radiation damage maturation of the least mature Alum Shale kerogen was not the sole factor. (Horsfield et at.. 1992). Ring condensation, and an Some of the results of this study (high abundance increase in aromaticity, are perhaps processes closely of cross-linked short alkyl chains, low abundance of associated only with late/extreme maturation in the long n-alkyl chains) may be explained by the case of the Alum Shales, in contrast to other marine radiation hypothesis, while several others (high sediments (Patience et at ., 1992). While oxidation and oxygen content, absence of thiophenes, high aro ­ pyrolysis indicate minor chemical changes prior to maticity. extensive formation of "dead" carbon on the onset of high maturity, petrography indicates maturation) are perhaps due to the unusual chemistry distinct progressive physical changes, such as an of the Alum Shale algae and its subsequent diagenesis increase in bitumen reflectance and decrease in (Bharati and Latter. 1991 and Horsfield et al.. 1992). alginite fluorescence intensity. Interestingly, the overall pyrolysatc composition of Pelet (1980) has suggested that a major part of a the Cerdanya kerogen from the Tertiary Catalan kerogen's oxygen is lost during diagenesis, while the lacustrine oil shale as reported by Sinninghe Damstc hydrogen content mainly decreases during the et al. (1993) and Hangers et al. (1994). is remarkably catagenesis stage. However, the data obtained for the similar to the Alum Shale pyrolysatc composition. Alum Shale kerogens suggest that most of the Due to only minor differences observed in the oxygen remains intact within the KMM. even as alkylbenzene distribution in Cerdanya and Alum products are generated and expelled with increasing Shale pyrolysates. Hangers et al. (1994) deemed it maturity. This is unusual, keeping in mind the unlikely that radiation-induced aromatization played chemical models suggested for Type I. II and III an important role in the development of Alum Shale kerogens by Behar and Vandenbroucke (1987). It kerogen. On the other hand, the existence of biota seems that with increasing maturity, the overall with unique and/or unexplained compositions (aro ­ chemistry of the Alum Shales and sub-unit structures matic biopolymers) has been observed, as for the remains the same, except for the more condensed freshwater algae Pediastrum (Sinninghe Damste nature and reduced size of the individual building et al.. 1993) and Gloeocapsomorpha derived alginite blocks. (Fowler, 1992). Thus, the precursors of Alum Shale alginite might have been markedly different in Possible origin and fate of the Alum Shale kerogens composition from those in other Cambrian seas, or Perhaps these differences between the Alum Shale in later geological periods. In any case, this study and "typical" Type II kerogens relate to the origin of presents other chemical peculiarities associated with the former. Given the Cambrian age of the Alum the Alum Shale kerogen which are not readily Shale, a terrestrial organic contribution can be ruled explained by Lewan and Buchardt's (1989) hypoth ­ out. Marine algae are the only petrographically esis.

Norwegian University of Science and Technology 196 Mobile and immobile migrated hydrocarbons in the Embla Field, North Sea

Elucidation of the Alum Shale kerogen structure

Buchardt B. and Lewan M. D. (1990) Reflectance of CONCLUSIONS utnnitc like macerals as a thermal maturity index The Alum Shale kerogen has been shown to be in the Cambro-Ordovician Alum Shale of Southern unusual with respect to composition and maturation Scandinavia. AAPG Bull. 74, 394-406. Dahl J.. Hallberg R. and Kaplan 1. R. (19881 Effects of products, but it must be borne in mind that our irradiation from uranium decay on extractable organic knowledge and data about classical 'Type II" matter in the Alum Shales of Sweden. Org. Geochem. 12. kerogens. and alginites. is largely based upon 559-571. post-Ordovician (.generally Mesozoic) land-plant Dahlman B. and Gee D. G. (19*7) Ovcrsikt over organic matter, the only exception being the Billingen-Falbvgdens geologi. bil.l i Betonkande ai Billingenutredningen-Statensoficntliga utredmnar 1977.4". Ordovician kukersites. Results of the present study 219-255. Stockholm, lndustndepartcmentct. suggest to us the possibility that the principal Espitalie J.. Laporte J. L.. Madoc M.. Marquis F.. biological input to the Cambrian Alum Shales is Lepat P. and Pavlet J. (1977) Mcthodc rapide de different from that of 'normal" alginites because of caractcrisation des roches meres, de leur potential the gross amount, and composition, of the generated petrolier et de leur degre d evolution. Inst. Fr. Pet. Ret. 32. 23-43. petroleum. While some aspects of the kerogen Fowler M. G. (1992) The influence of Gloeocapsomorpha structure may be explained by radiation damage of pr'tsca on the organic geochemistry of oils and the primary organic matter, several other features are organic-rich rocks of Late Ordovician age from Canada. probably related to an alternative chemistry of the In Early Organic Evolution: Implications tor Mineral and Energy Resources (Edited by Schidlowski M.) Spnnger- biota (algae) that existed in the Alum Shale basin Verlag. Berlin. 336-356. during Cambrian times. Hangers W. A.. Sinninghe Damste J. S. and De LceuwJ. W. This study also demonstrates the need to develop (1994) Geochemical significance of alkylbenzene distn- further analytical techniques, particularly related to butions in flash pyrolysates of kerogens. coals and asphaltenes. Geochim. Cosmochim. Acta 58. 1759- high resolution optical methods, selective kerogen 1775. pruning and ways to isolate pruned fractions for Horsfield B.. Bharati S.. Lamer S. R.. Leistner F.. Littkc R.. further chemical characterisation. Only then can Schenk H. J. and Dypvik H. (1992) On the atypical more 'complete' data on kerogens be generated to petroleum generating characteristics of alginite in Ihe enable us to derive any viable and true structural and Cambrian Alum Shale. In Early Organic Evolution: Implications for Mineral and Energy Resources (Edited by molecular models of the kerogen macro-molecule. Schidlowski M.) Springer. Berlin. 257-266. Lamer S. R. and Douglas A. G. (1980) A pyrolysis-gas Associate Editor —J. S. Sinnmghe Damste # chromatographic method for kerogen typing. In Advances in Organic Geochemistry 1979 (Edited by Acknowledgements —SB thanks Professor H. Dypvik Douglas A. G. and Maxwell J. R.) Pergamon Press. (Department of Geology. University of Oslo) for providing London. 579-584. the samples. SB and SL thank BP Norway for financial Lamer S. R. and Douglas A. G. (1982) Pyrolysis methods support. GS thanks BP and NERC for a CASE studentship. in Organic Geochemistry: An Overview. J. Anal. Appl. Walter Michaelis and an anonymous referee are thanked for Pvrolvsis 4, 1-19. suggestions to improve the quality of the paper. Lamer S. R. and Senftle J. T. (1985) Improved kerogen typing for petroleum source rock analysis. Nature 318, 277-280. REFERENCES Lewan M. D. and Buchardt B. (1989) Irradiation of organic Andersson A.. Dahlman B.. Gee D. G. and SnSlI S. matter by uranium decay in the Alum Shale. Sweden. 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APPENDIX I Description of the carbon types quantified by NMR. in terms of functionality, structure and symbol used (Patience et a!.. 1992). FUNCTIONALITY STRUCTURE SYMBOL

OH '.w o o CARBONYL

CARBOXYL - E3-OOR/H COOR

PHENOL (6P° AlCO

BRANCHED AROMATIC AlCC

BRDGEHEAO AlC*C AROMATIC m PROTONATEO AlCH AROMATIC

OXY-METHINE CHO

OXY-METHYLENE c-TO-o —C/H CH.0 0 OXY-METHYL 1 CH.0

QUATERNARY C ALIPHATIC c-gj-c c METH1NE V CH METHYLENE (CJ) c-TO-ch , CH,(C2)

METHYLENE c-ro-c CH.

ALIPHATIC METHYL /CH-® CH.ll

AROMATIC METHYL igr 03 CH,irom

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