Source Rock Depositional Processes in Different Marine ...

Source Rock Depositional Processes in Different Marine Settings: Examples from

North African Basins

Von der Fakultät für Georessourcen und Materialtechnik

der Rheinisch-Westfälischen Technischen Hochschule Aachen

zur Erlangung des akademischen Grades eines

Doktors der Naturwissenschaften

genehmigte Dissertation

vorgelegt von M.Sc.

Bandar Ismail Hassan Ghassal

aus Makkah, Saudi Arabien

Berichter: Univ.-Prof.Dr.rer.nat. Ralf Littke

AOR Dr.rer.nat. Sven Sindern

Tag der mündlichen Prüfung: 20. Juli 2017

(Ausschließlich für elektronische Veröffentlichung bestimmt):

Diese Dissertation ist auf den Internetseiten der Hochschulbibliothek online verfügbar

I

DECLARATION OF AUTHORSHIP

I certify that the thesis presented here is original and the result of my own investigations, except as acknowledged, and has not been submitted, either in part or whole, for a degree at this or any other University.

Aachen,

Bandar Ismail Ghassal

II

ACKNOWLEDGMENT

From the bottom of my heart, I would like to thank everyone who helped me to reach this

point of my education and career. Thank you very much, my mother, for being the

support and motivation who always drives me to succeed. Every success I reached or

will reach has your fingerprint on it. I would also like to sincerely express my gratitude

to my wife who sacrificed a lot for me to see me succeed and put my needs before hers.

Thank you for those beautiful paints that precedes Chapters 2-4. Thanks to my lovely kids

Jory and Rakan for being the hope especially in tough times. Your smiles and small

dreams made me work hard so you can be proud of your daddy! Big thank you to my

Sister Ghaddah and my brother Bassim who provided me with tremendous support

throughout my life. I hope your pieces of advice and help paid back. Thank you to the

great person who I wish he saw this day; My father who passed away when I was six years

old but left me with a golden reputation, tips and inspirations that paved the way for me

to be passionate to learn new things every day and to keep healthy relationships with

others.

Thank you very much for my employer Saudi Aramco for funding my Ph.D. program and

overcoming every obstacle that could have affected my studies. Special thanks to Mr.

Saleh Al Ammari, Dr. Sami Abdelbagi and Mrs. Aggie Copper from Saudi Aramco. Thank

you is a small expression that describes my appreciation. I would like to thank the person

whom I admire and who polished my academic and management skills, my advisor

Professor Ralf Littke for the fruitful Ph.D. program. It was an extraordinary experience

that went beyond only the thesis work but extended to teach in classes, advising Master

and Bachelor students, supervising the Rock-Eval laboratory and working on various

technical projects. Many thanks to Professor Sven Sindern who provided valuable

consultations in the XRF analyses and for being the second reviewer of this thesis. I am

very grateful to Dr. Bernard Krooß for his support and usual rich scientific discussions. I

learned a great deal from you. I would like to express my gratitude to Professor Jan

III

Schwarzbauer for his great help and valuable discussions in regards of the molecular

geochemistry field during my Ph.D. program. I sincerely appreciate all the support and

help given by my friend and one of my top coauthors Dr. Haytham El Atfy from the

Mansoura University, also for helping in the German abstract and providing the Nile Delta

and Western Desert wells. Many thanks to Dr. Victoria Sachse for the insightful

discussions and great support that helped me a lot during my program. It was a great

pleasure working with a very talented dedicated and professional technical group who I

enjoyed learning from. Thank you to Dipl.-Ing. Chemie Donka Macherey who helped in

preparing the microscopy samples. I extend my gratitude to Mrs. Kerstin Windeck for

making the carbon and sulfur measurements and Dipl.-Ing. Chemie Annette

Schneiderwind for helping in the molecular geochemical analysis. Special thanks to Mr.

Alexander Stock for helping in the sampling of the Tarfaya project core and to Miss Laura

Zeiger for helping in the German abstract. I would like to thank Ms. Diana Marcela Chaves

Saldaña and Mr. Jan Gronewald who assisted in the analysis of the same project. Many

thanks to Mr. Gregor Scholtysik for helping in the GPT-3 geochemical analysis. I thank the

micropaleontology group at the Kiel University very much for providing us with the core

samples from Tarfaya. Many thanks also to all coauthors and Editor in Chiefs who helped

in reviewing the three papers constituting major parts of my thesis.

Thank you God I did it!

IV

ABSTRACT

The current thesis assesses source rock characteristics in various shallow marine

settings using samples from the Nile Delta and Abu Gharadig basins in Egypt and the

Tarfaya Basin in Morocco. The methods include organic and inorganic geochemistry,

organic petrology, basin modeling, and palynology. The thesis comprises three main

studies. First, the Nile Delta Basin source rock potential is determined using organic

geochemistry and petrology as well as 1D basin modeling of two onshore wells. The Abu

Hammad-1 well located in the southeastern Nile Delta Basin hosts fair to good gas prone

source rocks within the Upper Jurassic and Lower Cretaceous section. The molecular

geochemical analyses indicate shallow marine depositional environment and mixed

marine and terrestrial organic matter. The burial and thermal numerical 1D model and

organic petrology results indicate thermally immature section. However, this Mesozoic

section is expected to have better potential and thermal maturity toward the northern

parts of the basin. The middle Miocene to Pleistocene section is examined in the

Matariya-1 well which is located in northeastern onshore Nile Delta Basin. It contains fair

gas prone source rocks in a middle Miocene lowstand wedge. This section has attained

onset oil generation stage. The great thickness of the section and proximity to the

reservoir facies upraise its source rock potential. The study recommends further

exploration in deep targets such as Mesozoic sections, especially in the offshore areas.

The second part of the thesis evaluates the source rock potential and paleoenvironment

of the Cenomanian to Santonian succession of the Bahariya and Abu Roash formations at

the GPT-3 well, Western Desert, Egypt. The study employed organic and inorganic

geochemical and palynological techniques. The results show that the succession

represents variable oxic shelf depositional environments with low organic matter

preservation excluding the Abu Roash “F” Member which shows two source rock facies.

The basal part of this member is rich in carbonate, TOC and marine organic matter. The

kerogen is relatively rich in organic sulfur (Sorg) due to the limited reactive Fe supply

upon deposition leading to excesses S incorporation into organic matter. The middle part

of the Abu Roash “F” Member is lean in organics and very rich in terrestrial elements (e.g.

V

Fe, Ti, Si) and associated with Botryococcus indicating sea regression. This facies overlain

by a suboxic marine oil prone source rock with lower Sorg contents. Both source rocks are

lower in Tmax as compared to the above and below sections implying thermal maturity

retardation possibly due to high liptinite contents, high pressures or lack of catalytic

elements. Moreover, two oil reservoirs were geochemically characterized. These findings

are vital for future hydrocarbon exploration and paleoenvironment reconstructions.

In the Tarfaya Basin, Cenomanian to Turonian source rocks are classified based on their

organic geochemical and petrological properties. The molecular geochemistry suggests

marine anoxic depositional environment with an extreme oxygen depletion attained at

the Cenomanian/Turonian boundary event (CTBE) associated with increased

cyanobacteria activities. The lower Cenomanian is characterized by higher silicate

contents compared to the rest of the section based on major elemental data. All samples

are dominated by submicroscopic organic matter. The lower Cenomanian is poor in

bituminite, whereas, the upper Cenomanian to Turonian samples show variable

bituminite contents. Furthermore, the samples show variable Sorg contents. The change

in organic matter type was controlled by early diagenetic kerogen sulfurization, which

depends on the interplay between S, Fe and organic matter, and upwelling processes. The

source rocks are classified into 1) low Sorg and moderately TOC-rich oil prone source

rocks (lower Cenomanian), 2) moderate Sorg and TOC-rich oil prone source rocks (upper

Cenomanian), 3) high Sorg and TOC-rich oil prone source rocks (Turonian) and 4) very

high Sorg and TOC-rich oil prone source rocks (CTBE). Types 2 to 4 will generate sulfur-

rich petroleum upon maturation or artificial oil shale retorting.

VI

ZUSAMMENFASSUNG

Diese Dissertation behandelt Edölmuttergesteine aus flach-marinen Sedimentfolgen des Nil-

Delta, des Abu-Gharadig Beckens in Ägypten und des Tarfaya Beckens in Marokko und ihre

charakteristischen Eigenschaften. Die Methoden umfassen organische und anorganische

Geochemie, organische Petrologie, Beckenmodellierung und Palynologie. Die Dissertation

umfasst drei Hauptkapitel. Zuerst wird das Muttergesteins-Potential von Proben aus dem

Nil-Delta mit Hilfe organischer Geochemie und Petrologie sowie der 1D-Beckenmodellierung

anhand zweier Onshore-Bohrungen bestimmt. Die Abu Hammad-1-Bohrung aus dem

südöstlichen Nil-Delta enthält mäßiggute bis gute Muttergesteine des Oberen Jura und der

Unterkreide. Die molekular-geochemischen Analysen zeigen ein flach-marines

Ablagerungsmilieu und den gemischten Eintrag von marinem und terrestrischem

organischen Material. Die thermische Reife ist gering. Allerdings wird erwartet, dass diese

Mesozoische Sektion in nördlichen Teilen des Beckens ein größeres Potential und eine

höhere thermische Reife aufweist. Der Abschnitt vom Mittleren Miozän bis zum Pleistozän

wurde anhand der Matariya-1-Bohrung untersucht, die aus dem nordöstlichen Onshore Nil-

Delta Becken stammt. Er enthält mäßiggute Muttergesteine im frühen Ölfenster. Die große

Mächtigkeit des Abschnitts und die Nähe zu geeigneten Reservoir-Gesteinen erhöhen jedoch

das Muttergesteins-Potenzial. Diese Studie empfiehlt eine weitere Exploration tieferer

Einheiten z.B. des Mesozoikums, vor allem in den Offshore-Gebieten.

Der zweite Teil der Dissertation beurteilt das Muttergestein-Potenzial und die

Paläoumweltbedingungen der Cenomanium-Santonium Schichtfolge der Bahariya- und Abu-

Roash Formationen aus der GPT-3-Bohrung aus der libyschen Wüste Ägyptens. Die

Ergebnisse zeigen, dass die Folge überwiegend, mit Ausnahme der Abu-Roash „F“

Subformation, das ein hohes Erdölbildungs-Potenzial besitzt, unter suboxischen bis oxischen

Bedingungenabgelagert wurde. Der Basalteil der Folge ist reich an Karbonat, TOC und

mariner organischer Substanz. Das Kerogen ist aufgrund der begrenzten Menge an reaktivem

Eisen während der Ablagerung relativ reich an organischem Schwefel (Sorg). Der mittlere Teil

des Abu-Roash „F“ Subformation ist arm an organischem Material und sehr reich an

terrestrischen Elementen (z.B. Fe, Ti, Si) und mit Botryococcus-Algen assoziiert, was eine

Regression des Meeres anzeigt. Diese Fazies wird von suboxisch abgelagerten, marinen

VII

Muttergesteinen mit niedrigeren Sorg-Anteilen überlagert. All diese Muttergesteine zeigen im

Vergleich zu den unter- und überlagernden Gesteinen niedrige thermische Reifen auf, was

eine thermische Reifungsverzögerung, möglicherweise aufgrund hoher Liptinitgehalte,

hoher Drücke oder wegen des Mangels an katalytischen Elementen, impliziert. Darüber

hinaus wurden aus dieser Bohrung zwei Öl-Reservoirs geochemisch charakterisiert. Diese

Erkenntnisse sind für zukünftige Kohlenwasserstoff-Explorationen und Paläoumwelt-

Rekonstruktionen von entscheidender Bedeutung.

Im Tarfaya Becken wurden Cenomanische bis Turonische Muttergesteine auf Grundlage

ihrer organischen geochemischen und petrologischen Eigenschaften klassifiziert. Die

Ergebnisse der molekularen Geochemie legen eine marin-anoxische Ablagerung nahe, die an

der Cenomanium/Turonium Grenze (CTBE) mit einer erhöhten Aktivität von

Cyanobakterien assoziiert war. Das Untere Cenomanium zeichnet sich durch höhere Silikat-

Gehalte im Vergleich zum Rest des Abschnitts aus. Alle Proben werden durch

submikroskopisch kleine organische Partikel dominiert. Das Untere Cenomanium ist arm an

Bituminit, während der Abschnitt vom Oberen Cenomanium bis zum Turonium variable

Bituminitgehalte zeigt. Darüber hinaus weisen die Proben variable Sorg-Gehalte auf. Die

Veränderung des Kerogentyps wurde durch eine frühzeitige diagenetische

Kerogenvulkanisation (Schwefel-Einbau) gesteuert, die von den Konzentrationen an S, Fe

und organischer Substanz in Zusammenhang mit Auftriebsprozessen abhängt. Die

Muttergesteine werden dementsprechend aufgrund ihres Kohlenwasserstoff-

Bildungspotenzials (HI-Werte), ihrer TOC-Gehalte und ihres Gehaltes an organischem

Schwefels in 4 Gruppen potentieller Erdölmuttergesteine unterteilt: 1) solche mit niedrigem

Sorg- und mittlerem TOC-Gehalt (Unteres Cenomanium), 2) solche mit moderatem Sorg- und

hohem TOC-Gehalt (Oberes Cenomanium), 3) solche mit gleichfalls hohem Sorg- und TOC-

Gehalt (Turonium) und jene mit sehr hohen Sorg- und hohen TOC-Gehalten (CTBE). Die

Gruppen 2 und 4 werden bei fortgeschrittener Reifung oder durch künstliche Ölextraktion

schwefelreiches Öl produzieren.

VIII

LIST OF ABBREVIATIONS

AOM Amorphous organic matter API American Petroleum Institute Corg Organic carbon CPI Carbon preference index CPPyGCMS Curie Point Pyrolysis Gas Chromatography Mass Spectrometry CTBE Cenomanian Turonian boundary event

GC-FID Gas Chromatography-Flame Ionization Detector GCMS Gas Chromatography-Mass Spectrometry HI Hydrogen Index OAE2 Oceanic anoxic event 2 OEP Odd over even predominance OI Oxygen Index Ph Phytane PI Production Index Pr Pristane S1 First flame ionization detector signal/peak of Rock-Eval 6 S2 Second flame ionization detector signal/peak of Rock-Eval 6 S3 The Infra-Red detector signal/peak of Rock-Eval 6

Sorg Organic sulfur TAR Terrestrial to aquatic ratio TIC Total inorganic carbon Tmax Rock-Eval temperature at maximum S2 yield TOC Total organic carbon TS Total sulfur UOM Unstructured organic matter from organic microscopy VRr Vitrinite reflectance at random orientations

IX

TABLE OF CONTENTS

DECLARATION OF AUTHORSHIP .......................................................................................................... I

ACKNOWLEDGMENT ..................................................................................................................................II

ABSTRACT ..................................................................................................................................................... IV

ZUSAMMENFASSUNG ............................................................................................................................... VI

LIST OF ABBREVIATIONS ................................................................................................................... VIII

TABLE OF CONTENTS .............................................................................................................................. IX

LIST OF TABLES ....................................................................................................................................... XIV

LIST OF FIGURES ....................................................................................................................................... XV

Chapter 1 | Introduction .......................................................................................................................... 1

1.1 Background ........................................................................................................................................ 1

1.2 General Remarks on Source Rock Depositional Settings ........................................... 2

1.3 Geological Setting of North Africa from Jurassic to Recent.................................... 4

1.3.1 Jurassic Period .......................................................................................................................... 5

1.3.2 Cretaceous Period ................................................................................................................... 6

1.3.3 Paleogene Period ..................................................................................................................... 7

1.3.4 Neogene Period ........................................................................................................................ 8

1.4 Source Rock Potential Overview of the Study Areas .................................................... 8

1.4.1 Source rock potential of Egypt .............................................................................................. 8

1.4.2 Source Rock Potential of Tarfaya Basin ............................................................................. 9

1.5 Research Objectives .................................................................................................................... 12

1.6 Thesis Outline ................................................................................................................................ 13

Chapter 2 | Source Rock Potential of the Middle Jurassic to Middle Pliocene, Onshore Nile Delta Basin, Egypt ....................................................................................................... 16

X

2.1 Abstract ............................................................................................................................................. 16

2.2 Introduction .................................................................................................................................... 17

2.3 Geological Setting ......................................................................................................................... 19

2.3.1 Tectonic setting ........................................................................................................................ 19

2.3.2 Stratigraphy ............................................................................................................................... 21

2.4 Samples and Methods .................................................................................................................... 23

2.4.1 Samples ........................................................................................................................................ 23

2.4.2 Elemental analysis .................................................................................................................. 24

2.4.3 Rock-Eval pyrolysis.................................................................................................................. 24

2.4.4 Organic petrography .............................................................................................................. 29

2.4.5 Source rock extraction and liquid chromatography .................................................. 29

2.4.6 GC-FID and GC-MS ................................................................................................................ 30

2.4.7 1D burial and thermal history modeling ........................................................................ 31

2.5 Results ................................................................................................................................................ 32


2.5.2 Rock-Eval analysis .................................................................................................................. 32


2.5.4 Molecular geochemistry ....................................................................................................... 36


2.6. Discussion ....................................................................................................................................... 44

2.6.1 Depositional environments ................................................................................................. 44


2.6.3 Source rock potential ............................................................................................................. 49

2.7 The Mesozoic and Miocene Source Rocks In the Nile Delta-An Overview ..... 52

XI

2.8 Conclusions ..................................................................................................................................... 55

Chapter 3 | Depositional Environment and Source Rock Potential of the Upper Cretaceous Succession, Abu Gharadig Basin, Northern Western Desert, Egypt: An Integrated Geochemical and Palynological Study .................................................................. 58

3.1 Abstract ............................................................................................................................................. 58

3.2 Introduction .................................................................................................................................... 59

3.3 Geologic Setting ............................................................................................................................. 61

3.4 Material and Methods ........................................................................................................... 64

3.4.1 Samples ....................................................................................................................................... 64


3.4.3 Rock-Eval pyrolysis ................................................................................................................ 68

3.4.4 Organic petrology .................................................................................................................... 68

3.4.5 Molecular organic geochemistry ....................................................................................... 69

3.4.6 Curie Point Pyrolysis-Gas Chromatography-Mass Spectrometry ........................ 69

3.4.7 Molecular geochemical parameters ................................................................................. 70

3.4.8 Palynology and palynofacies ............................................................................................... 71

3.5 Results ................................................................................................................................................ 71


3.5.2 Rock-Eval pyrolysis ................................................................................................................ 76


3.5.4 Molecular organic geochemistry ....................................................................................... 81

3.5.5 CPPyGCMS .................................................................................................................................. 85

3.5.6 Palynology and palynofacies analysis ............................................................................. 87

3.6 Discussion ........................................................................................................................................ 91

3.6.1 Age assignment ........................................................................................................................ 91

XII

3.6.2 Depositional environments ................................................................................................. 92

3.6.3 Source rock potential ........................................................................................................... 101

3.6.4 Reservoir geochemistry ...................................................................................................... 102

3.7 Conclusions ................................................................................................................................... 103

Chapter 4 | Depositional Environment and Source Rock Potential of Cenomanian and Turonian Sedimentary Rocks of the Tarfaya Basin, Southwest Morocco ...... 107

4.1 Abstract ........................................................................................................................................... 107

4.2 Introduction .................................................................................................................................. 108

4.3 Geological Setting ....................................................................................................................... 112

4.4 Samples and Methods .............................................................................................................. 114

4.4.1 Samples ..................................................................................................................................... 114

4.4.2 Elemental analysis ................................................................................................................ 114

4.4.3 Rock-Eval Pyrolysis .............................................................................................................. 116

4.4.4 Organic petrology .................................................................................................................. 117

4.4.5 Source rock extraction ........................................................................................................ 117

4.4.6 Gas Chromatography and Gas Chromatography-Mass Spectrometry .............. 118

4.4.7 Curie-Point Pyrolysis Gas Chromatography-Mass Spectrometry ....................... 118

4.4.8 Molecular geochemical parameters ............................................................................... 119

4.5 Results .............................................................................................................................................. 119

4.5.1 Elemental Analysis ................................................................................................................ 119

4.5.2 Rock-Eval Pyrolysis .............................................................................................................. 136

4.5.3 Organic Petrology .................................................................................................................. 138

4.5.4 Molecular Geochemistry ..................................................................................................... 142

4.5.5 Curie-Point-Pyrolysis Gas Chromatography-Mass Spectrometry ...................... 144

4.6 Discussion ...................................................................................................................................... 145

XIII

4.6.1 Depositional environment ................................................................................................. 145

4.6.2 Source rock potential and organic matter type ......................................................... 152

4.6.3 Kerogen diagenesis and properties ................................................................................ 154

4.7 Conclusions ................................................................................................................................... 155

Chapter 5 | Thesis General Discussion ........................................................................................ 157

5.1 Introduction .................................................................................................................................. 157

5.2 Studied Parameters .................................................................................................................. 157

5.3.1 Sedimentation systems and organic matter productivities .................................. 159

5.3.3 Bottom water conditions .................................................................................................... 161

5.3.5 Tmax and source rock properties ...................................................................................... 164

5.4 New Geochemical Proxies ...................................................................................................... 165

Chapter 6 | Conclusions ....................................................................................................................... 167

References .................................................................................................................................................. 170

Curriculum Vitae .................................................................................................................................... 187

XIV

LIST OF TABLES

Table 2-1 Rock-Eval 6 and elemental data of the Abu Hammad-1 and Matariya-1 wells. Units:

*(mgHC/gRock), ** (mgCO2/gRock), *** mgHC/gTOC, **** mgCO2/gTOC. ...................... 25

Table 2-2 Gas chromatography data of selected samples from the Abu Hammad-1 and

Matariya-1 wells. .......................................................................................................................................... 38

Table 2-3 Biomarker data of selected samples from the Abu Hammad-1 and Matariya-1 wells. ................................................................................................................................................................. 40

Table 3-1 Carbon, sulfur and Rock-Eval data of the Bahariya and Abu Roash formations, GPT-

3 well, north Western Desert, Egypt. * (mg HC/gRock), ** (mg CO2/gRock), ***

(mgHC/gTOC), **** (mgCO2/gTOC). .................................................................................................. 64

Table 3-2 Elemental data of selected samples using XRF analysis from the Abu Roash “F”, “E” and “G” members, GPT-3 well, north Western Desert, Egypt. ............................................ 74

Table 3-3 Biomarker data of selected samples from the Bahariya and Abu Roash formations, GPT-3 well, north Western Desert, Egypt. ................................................................ 83

Table 3-4 Curie Point Pyrolysis Gas chromatography mass spectrometry data of selected samples from The Abu Roash “F” Member, GPT-3 well, north Western Desert, Egypt. .. 86

Table 3-5 Palynofacies data of selected samples from the Bahariya and Abu Roash formations. AOM: amorphous organic matter. ................................................................................ 87

Table 4-1 Elemental and Rock-Eval 6 data. Units: *mgHC/Rock, **mgCO2/gRock, ***mgHC/gTOC, ****mgCO2/gTOC. T: Turonian, CT: CTBE, UC: Upper Cenomanian, LC: Lower Cenomanian A: Albian ............................................................................................................... 123

Table 4-2 XRF data of selected samples from each stratigraphic units. T: Turonian, CT:

CTBE, UC: Upper Cenomanian, LC: Lower Cenomanian. ........................................................... 135

Table 4-3 Maceral compositional analysis data. *: Calculated, submicroscopic organic matter. T: Turonian, CT: CTBE, UC: Upper Cenomanian, LC: Lower Cenomanian. .......... 140

Table 4-4 Molecular geochemistry data of the aliphatic fractions. ....................................... 143

Table 4-5 Total thiophenes/total benzenes data from CPPyGCMS data used as a proxy of Sorg/Corg ......................................................................................................................................................... 144

XV

LIST OF FIGURES

Fig. 1-1 Schematic diagram of common source rock depositional settings. Pink polygons are anoxic/oxygen minimum zones. ...................................................................................................... 4

Fig. 1-2 Paleogeographic reconstructions modified after Blaeky 2012. The yellow dot is for Morocco and the magenta dot is for Egypt. “Global Paleogeographic Maps © 2012 Colorado Plateau Geosystems Inc., used with permission from Ron Blakey”. ....................... 6

Fig. 1-3 Source rock potential traffic light map of the Tarfaya basin based on published data by Sachse et al., (2011, 2012, 2014), Ghassal et al., (2015) and Wenke (2014)....... 11

Fig. 1-4 Geothermal gradient map of the Tarfaya basin modified after Zarhloule (2003) and Ghassal et al. (2015) .......................................................................................................................... 11

Fig. 2-1 Nile Delta Basin map showing important structures, wells, and gas fields (modified after Abdel Aal et al. 2001; Shaaban et al. 2006). The gray shaded area represents basalt. ........................................................................................................................................ 19

Fig. 2-2 Generalized stratigraphic column of the Nile Delta Basin (modified after El Nady

2007; Guiraud and Bosworth 1999) ........................................................................................................ 22

Fig. 2-3 Depth plotted versus TOC, CaCO3, TS, HI, and Pr/Ph of the Abu Hammad-1 and Matariya-1 wells .......................................................................................................................................... 33

Fig. 2-4 TOC plotted versus TS (a) and CaCO3 (b) of the Abu Hammad-1 and Matariya-1 wells ................................................................................................................................................................. 34

Fig. 2-5 TOC plotted versus S2 of the investigated samples. ...................................................... 35

Fig. 2-6 Gas chromatographs of the saturated hydrocarbon fractions of the a) Kafr El Sheikh Formation, b) Qawasim Formation, c) Upper Sidi Salem Formation, d) Lower Sidi Salem Formation, e) Kharita Formation, f) Upper Alam El Bueib Formation, g) Lower Alam El Bueib Formation, h) Masajid Formation, and i) Khatatba Formation. Note that n-C17 and n-C20 are marked. ..................................................................................................................... 37

Fig. 2-7 Burial/thermal history diagrams of the a) Abu Hammad-1 and b) the Matariya-1 wells in the next page. ............................................................................................................................... 41

Fig. 2-8 Pr/n-C17 versus Ph/n-C18 for selected samples from the Abu Hammad-1 and Matariya-1 wells, in comparison to other published data. ......................................................... 46

Fig. 2-9 a) Cross section demonstrates Oligocene and Miocene stratigraphy at the eastern Nile Delta Basin (modified after Shaaban et al. 2006). B) Cross section shows Nile Delta

XVI

stratigraphy from the onshore to the offshore areas (modified after Abdel Aal et al. 2001). ............................................................................................................................................................................ 50

Fig. 2-10 HI versus OI of the samples from the Abu Hammad-1 and Matariya-1 wells. PFM-1 well data are published in Khaled et al. (2014). .......................................................................... 51

Fig. 2-11 TOC and HI map of the Matariya-1 well and published data of the Sidi Salem Formation source rock. Published data sources: Abu Madi-1, Abu Madi-3, Abadiya-1, Kafer El Shiekh-1, Abu Madi-1, and Abu Madi-3 (El Nady 2007); Sidi Salem-1 (El Nady and Harb 2010); AbuMadi-9 well (Keshta et al. 2012); and S.W. Bilqas-1, Port said-1, Qantara-1, and Port Fouad-1 (Shaaban et al. 2006). ..................................................................... 54

Fig. 3-1 a) A location map of the studied GPT-3 well and the main sedimentary basins in the north Western Desert, Egypt. B) Paleogeographic map at ~94 Ma of North Egypt and the surrounding areas (modified after Phillip, 2003)................................................................... 60

Fig. 3-2 Lithostratigraphic column of the GPT-3 well, north Western Desert, Egypt (after GPC, 1984). The associated biozones are after El Beialy et al. (2010). .................................. 63

Fig. 3-3 Total organic carbon (TOC), CaCO3, Total sulfur (TS) and Rock-Eval data versus depth, Bahariya and Abu Roash formations, GPT-3 well, north Western Desert, Egypt. The Abu Roash “F” source rocks are classified as Transgression phases I and II. * CaCO3 is calculated from total inorganic carbon. ............................................................................................. 72

Fig. 3-4 XRF elemental data of the Abu Roash “F” Member, GPT-3 well, north Western Desert, Egypt. ................................................................................................................................................ 73

Fig. 3-5 K/Al ratio versus (a) Si/Al ratio and (b) CaCO3 of selected samples from the Abu Roash “E”, “F” and “G” members, GPT-3 well, north Western Desert, Egypt showing possible depositional environment, climate and clay mineral composition. ...................... 75

Fig. 3-6 SiO2-5*Al2O3-2*Ca ternary diagram demonstrating lithological differences among the Abu Roash “E”, “F” and “G” samples, GPT-3 well, north Western Desert, Egypt. ........ 75

Fig. 3-7 Total organic carbon-iron-total sulfur ternary diagram of selected samples from Abu Roash “G”, “F” and “E” members, GPT-3 well, north Western Desert, Egypt. ............. 76

Fig. 3-8 CaCO3 versus total organic carbon (TOC), GPT-3 well, showing two distinctive trends. The samples of Abu Roash “F” have a positive trend, whereas samples from other rock units denote a weak negative relation. ..................................................................................... 77

Fig. 3-9 Total sulfur (TS) versus total organic carbon (TOC) showing the difference between the Abu Roash “F” Member and other studied rock units. The samples are classified into three groups which are 1) Abu Roash “F” Member Transgression-1:, 2) Abu Roash “F” Member Transgression-2: and 3) oxic/suboxic shelf: the samples from the rest of the geological units. Value%: CaCO3 calculated from total inorganic carbon. ............... 77

XVII

Fig. 3-10 Pseudo van Krevelen diagram of the studied rock units, GPT-3 well, north Western Desert, Egypt. Note that the high HI readings from the Abu Roash “D” samples are from a reservoir section. .................................................................................................................. 78

Fig. 3-11 Rock-Eval pyrograms and gas chromatograms of the Abu Roash “C” and “D” reservoirs as well as Abu Roash “F” source rock sections, GPT-3 well, north Western Desert, Egypt. ................................................................................................................................................ 79

Fig. 3-12 Organic petrography of the Abu Rash “F” samples under fluorescent light, GPT-3 well, north Western Desert, Egypt.................................................................................................... 80

Fig. 3-13 a) Total organic carbon (TOC) versus terrestrial to aquatic ratio (TAR). b) Pristane/phytane ratio versus steranes/hopanes ratio (str/hop), GPT-3 well, north Western Desert, Egypt. ............................................................................................................................. 82

Fig. 3-14 C27, C28 and C29 steranes ternary diagram of selected samples from the Bahariya and Abu Roash formations, GPT-3 well, north Western Desert, Egypt. ................................. 84

Fig. 3-15 C29 ββ/(αα+ββ) steranes versus C29 ααα20S/(20S+20R) steranes indicating maturity in the studied rock units, GPT-3 well, north Western Desert, Egypt. Please refer to Table 4 for sample assignment. ........................................................................................................ 84

Fig. 3-16 Curie-Point-Pyrolysis Gas Chromatography-Mass Spectrometry Chromatograms of representative samples from the Abu Roash “F” Member indicating a high organic sulfur contents in transgression phase-I, Abu Rash “F” Member, GPT-3 well, north Western Desert, Egypt. ................................................................................................................. 85

Fig. 3-17 Ali-Be-T ternary diagram (alaphitic- hydrocarbonsn-C6 to n-C14-Benzenes-Thiophenes) based on Curie-Point-Pyrolysis-Gas-chromatography-mass-spectrometer data of selected samples from the Abu Roash “F” source rocks, GPT-3 well, north Western Desert, Egypt. ................................................................................................................................................ 86

Fig. 3-18 APP ternary plot (Tyson, 1993) of selected samples from the Bahariya and Abu Roash formations, GPT-3 well, north Western Desert, Egypt. ................................................... 88

Fig. 3-19 Pristane (Pr)/n-C17 versus phytane (Ph)/n-C18 illustrating the organic matter type of selected samples from the studied rock units, GPT-3 well, north Western Desert, Egypt. ............................................................................................................................................................... 93

Fig. 3-20 Generalized depositional model of the Abu Roash “F” Member based on the current geochemical and palynological interpretation. ............................................................... 99

Fig. 4-1 Overview map of the Tarfaya Basin showing the location of the studied well (S-4) and some of the previously studied wells (modified after Michard et al., 2008). ...... 109

XVIII

Fig. 4-2 Cross section showing the extent of the onshore/offshore stratigraphy of the Tarfaya Basin (modified after Wenke, 2014), including Cap Juby well. Surface geology in the small map modified after Saadi et al. (1985). CJ: Cap Juby well. ..................................... 111

Fig. 4-3 Stratigraphic column representing the common lithologies in the Tarfaya Basin from coastal to deep marine areas (modified after Davison, 2005; Sehrt, 2014). ........... 115

Fig. 4-4 Depth plots TS, TOC, CaCO3 and TS/TOC ratio of all stratigraphic units. ........... 121

Fig. 4-5 Cross plots between CaCO3 versus TOC and TS. The correlation of CaCO3 and TOC relationship changes significantly from positive in the Lower Cenomanian to negative in the Turonian. The CaCO3 and TS correlations are always negative with variable regression coefficients. ........................................................................................................................... 133

Fig. 4-6 Elemental data versus depth shows increase in silicate and rutile forming elements with depth. It also shows a strong increase in P2O5 before the CTBE. .............. 134

Fig. 4-7 CaCO3 versus Fe2O3 and TiO2 Cross plots show inverse relationship in all studied intervals. ....................................................................................................................................................... 135

Fig. 4-8 Pseudo van Krevelen diagram of bulk Rock- Eval-6 samples of the various stratigraphic intervals. ............................................................................................................................ 137

Fig. 4-9 Rock-Eval HI, OI and Tmax versus depth plot. It shows the apparent difference between the Cenomanian to Turonian source rocks. On the basis of microscopic observations the Tmax shift is interpreted to be caused by a change in the organic facies rather than thermal maturity. .............................................................................................................. 138

Fig. 4-10 Micrograph of representative samples of each organofacies type and stratigraphic interva ................................................................................................................................ 139

Fig. 4-11 Organic matter volume vs. TOC weight percent. The samples that show very low visible organic matter were assigned as 0.2% for the sake of simplicity. .......................... 141

Fig. 4-12 Pr/C17 vs. Ph/C18 diagram suggests marine and thermally immature organic matter for all sample. The classification method is from Shanmungam (1985). ............. 142

Fig. 4-13 C27-C29 steranes ternary diagram indicates shallow open marine depositional environment. ............................................................................................................................................... 143

Fig. 4-14 TS versus TOC cross-plot shows that the majority of the Cenomanian to Turonian samples are plotted below the normal marine line of Berner (1984) unlike the majority of the Lower Cenomanian samples which plot above the line .............................. 150

XIX

Fig. 4-15 TS versus Fe shows that the majority of the samples from Cenomanian to Turonian are plotted above the Pyrite line indicating that the sulfur in theses samples is present in other forma than pyrite. ................................................................................................... 151

Fig. 4-16 OM-CaCO3-Silicates trinary diagram (modified after Littke, 1993) showing that the best organic preservation is achieved at CaCO3 concentration between 45 to 80%. .......................................................................................................................................................................... 153

Fig. 5-1List of the investigated terrigenous, biogenic and early diagenesis geochemical parameters. ................................................................................................................................................. 158

Fig. 5-2 Al2O3 versus K2O, TiO2, MnO and Fe2O3 cross-plots. Note the positive correlations indicating similar terrigenous origin. ............................................................................................... 158

Fig. 5-3 Geochemical conceptual model summarizing the differences between the three main depositional environments investigated in the current thesis. ................................... 160

Fig. 5-4 Carbonate-original organic matter-silicate diagram of selected samples from the Nile Delta (matariya-1 and Abu hammad-1 wells), The Abu Gharadig Basin (GPT-3 well) and the Tarfaya Basin (SON-4). ........................................................................................................... 161

Fig. 5-5 MnO versus a) oxygen index and b) Pr/Ph plots showing positive correlations of selected samples from the Tarfaya Basin (SON-4) and the Abu Gharadig Basin (GPT-3). .......................................................................................................................................................................... 162

Fig. 5-6 Oxygen Index versus thiophenes/benzenes ratio of selected samples from the Tarfaya Basin (SON-4) and the Abu Gharadig Basin (GPT-3). ................................................. 163

Fig. 5-7 Mn/S ratio versus hydrogen Index relationships illustrating positive correlation for the Abu Gharadig basin samples (GPT-3 well). ...................................................................... 163

Fig. 5-8 TiO2 versus S/Fe ratio relationship used as an example of the inverse relationship between terrigenous elements and S/Fe ratio. ................................................... 164

Fig. 5-9 Tmax versus Thiophenes/Benzenes ratio of selected samples from the Tarfaya (SON-4) and Abu Gharadig basins (GPT-3) showing tow clusters. ....................................... 165

Fig. 5-10 S/Fe versus Al2O3 ratios of selected samples from the Tarfaya and Abu Gharadig basins. ............................................................................................................................................................ 166

1

Chapter 1 | Introduction

1.1 Background

Source rock studies witnessed noteworthy developments after the shale gas/oil booms

in the United States, Europe, and China over the second decade of this Century. The

increased interest in the unconventional resources related to source rocks motivated

academia and industry to refine their assessment methods toward detailed

characterizations that surpass bulk evaluations. Thus, the integration of the variable

geological and petroleum engineering data and methodologies became leading research

trends influencing conventional and unconventional exploration strategies. First, they

enhance the understanding of source rock formation processes at different geological

settings which helps in predicting source rock facies in a regional context and therefore,

identifying and prioritizing new prospects. Moreover, they assist in distinguishing

productive zones and their hydrocarbon generative capabilities in vertical and spatial

distribution. These studies also have a significant influence on regional petroleum

exploration and paleoenvironmental reconstruction studies. The current work integrates

various organic and inorganic geochemical techniques with petrological, palynological

and basin modeling methods.

Many factors play roles in petroleum source rock deposition in marine and lacustrine

environments such as and the sea level changes or tectonic activities. The quality and

composition of the organic matter also depend on the proximity to the shoreline, the

bottom water oxygen contents, the origin and productivity of organic matter and the

interplay between the dissolved elements in the water and the organic matter. In this

chapter, the main marine source rock depositional settings, as well as the major climatic

and tectonic events that occurred in North Africa since the Mesozoic are discussed. This

is followed by a general overview of the common source rocks in Egypt and the Tarfaya

Basin located in Morocco. The chapter ends with the aims and the outline of the thesis.

2

1.2 General Remarks on Source Rock Depositional Settings

Source rocks are fine-grained carbonate or siliciclastics organic-rich sedimentary rocks

that are expected to generate fluid hydrocarbons when attaining elevated thermal

maturity levels (Littke et al., 1997; Tissot and Welte, 1984). The richness and quality of

source rocks are controlled by organic matter productivity, preservation, and

depositional conditions. The organic matter can be transported (allochthonous) or in situ

(autochthonous). The former is usually from a terrestrial origin whereas the latter is

from marine and terrestrial source (e.g. Bustin, 1988; Katz, 2012; Littke et al., 1997).

Extensive studies were carried out to understand the organic matter production,

preservation, and kerogen formation pathways in several depositional environments.

Deltas as terrestrial to marine transitional environments are characterized by mostly

high proportions of higher plant tissue (allochthonous) and smaller proportions of

aquatic algae (autochthonous) (Bustin, 1988; Littke et al., 1997; Tissot and Welte, 1984).

The deltaic environments include three main types which are river-dominated, wave-

dominated, and tide-dominated (Galloway 1975). They differ in their sediment supply

and types which significantly influence the depositional conditions. The typical examples

of prolific petroleum deltaic petroleum systems are 1) the Mississippi, 2) the Niger and

3) Mahakam deltas which represent the river-dominated type (e.g. Peters et al., 2000;

Michele et al., 1999). The Nile Delta, on the other hand, is classified as wave-dominated

type (Coe et al., 2003). The river-dominated system type is well understood compared to

the other types of deltas regarding petroleum potential.

The organic matters in river-dominated delta environments are subjected to many

factors that control their composition and quality. These factors may partially apply on

other types of deltas. Rivers transport terrigenous input that would constitute vitrinite,

inertinite, coal particles and fresh/brackish water algae. Rapid water circulation

increases the oxygen contents of the bottom water and organic matter oxidation. Due to

its low density, the liptinite macerals are attributed to selective transportation (Bustin,

1988). These processes indeed, will modify the Rock-Eval HI and OI values. These

3

characteristics differ outward from the delta front to more marine dominating organic

matter. Moreover, the interplay between fluvial and marine systems due to relative sea

level changes considerably alter the bottom water conditions and consequently the

organic matter types and qualities. Therefore, the Delta petroleum system is considered

one of the challenging systems to investigate. The current work selected the Nile Delta

Basin to address the organic matter richness and quality in wave-dominated delta

environments. Note that this kind of delta does not, commonly, favor source rock

deposition (Allen and Allen 2005). Thus, this thesis aims to explain the high hydrocarbon

potential found in the Nile delta basin in Chapter 2.

Marine source rocks are developed in three main settings which are oxygen minimum

zones along continental shelves, upwelling zones and silled/barred basins (Fig.1-1) (e.g.

Katz, 2012; Littke et al., 1993; Selley, 1998). Oxygen minimum zones are caused due to

oxygen consumption by decay of biomass and lack of circulation and photosynthesis in

deeper, dark water that omits oxygen resupply (Selley, 1998). The position of this zone

is highly dependent on the temperature and salinity of the marine water (Katz, 2012).

Source rock developments within upwelling zones account for almost half of the world

organic rich source rocks (Parrish, 1987). This is basically due to the remarkably high

biological productivity that outpaces the productivity of normal shelves by ~3 times

(Ryther, 1969; Koblentz-Mishke et al., 1970; Katz 2012). When global greenhouse

warming climate prevails, the alongshore winds move the marine coastal warm waters

allowing upwelling nutrient-rich water to replace it (Bakun, 1990) (Fig.1-1).

Consequently, the bioproductivity increases which leads later to high rate of deposition

of organic matter (Bakun, 1990; Parrish, 1987). The high productivity causes the bottom

water oxygen to decrease which creates favorable condition for organic matter

preservation (Parrish, 1987; Katz 2012). Note that the intensity of the upwelling process

lowers during cold climate (Bakun, 1990; Parrish, 1987). Due to wind direction variation

and the Coriolis Effect resulting from Earth rotation, upwelling zones are pronounced

along the western continental margins (e.g. Katz 2012).

4

The source rock development in barred basins occur principally due to density

stratifications where less saline, less dense water overlies the saline, denser water. This

process develops bottom water anoxia. The second mechanism is attributed to thermal

stratification where warm waters rests on cooler waters. The barred basins usually occur

in tropical regions where the wind stress and the change in seasonal temperature are

minimal (Gluyas and Swarbrick, 2013; Katz 2012).

Fig. 1-1 Schematic diagram of common source rock depositional settings. Pink polygons are anoxic/oxygen minimum zones.

1.3 Geological Setting of North Africa from Jurassic to Recent

North Africa acted as part of Gondwana supercontinent and the southern passive margin

of the Neotethys after the break-up of Pangea during the late Triassic Period (Berra and

Angiolini, 2014; Bosworth 1994; Golonka, 2007; Guiraud and Bosworth 1997; Guiraud et

al., 2005; Stampfli and Borel 2002). The northwestern African corner, however, was part

of the south North Atlantic region (e.g. Tarfaya basin). Since the early Jurassic, many

factors controlled the deposition of the Mesozoic to Cenozoic sedimentary sequence in

North Africa. These include global warming/cooling climates, oceanic anoxic events,

pronounced sea level changes, and major tectonic events such as Gondwana break-up,

the opening of the Atlantic Ocean, Jurassic rifting, and the opening of the Red Sea, the

5

Syrian arc event and Messinian Salinity Crisis. Fig.1-2 illustrates the tectonic evolution

from Jurassic to Neogene demonstrating the paleographic reconstruction of three time-

slices. A literature review is provided herein to address the major tectonic and climatic

factors that controlled basin formations. Then in the next chapters, a geological overview

of each basin is provided.

1.3.1 Jurassic Period

Major tectonic events played an important role in the development of North African

basins. Variable settings characterized the Liassic times. In the Eastern Mediterranean

region, active faulting took place in marine/marginal settings coeval with carbonates and

shallow marine sediment deposition. In the Tunisian/Algerian Sahara, marginal marine

settings prevailed and resulted in evaporite deposition. Moreover, active rifting occurred

in the Atlas basins, where some areas remained subaerial (Guiraud et al., 2005). The

extensional regime in North Africa is mainly related to the opening of the Central Atlantic

from the west and the drift of the Turkish-Apulian terrain in the North (Guiraud et al.,

1987). A period of sea transgression and E-W half graben development characterizes the

Middle Jurassic in Egypt. On the other hand, thermal subsidence occurred in the Central

Atlantic margin related to the opening of the Atlantic Ocean (Guiraud et al., 2005).

Moreover, the spreading of the Atlantic Ocean completely detached Africa from North

America (Berra and Angiolini, 2014). Many North African basins witnessed prolific

petroleum source rock deposition during the Middle Jurassic (e.g. Masajid Formation,

Egypt). Higher sea level prevailed during the Late Jurassic and rifting started in some

Western Desert basins such as the Abu Gharadig Basin. However, some of the Jurassic

deposits were eroded later during Upper Cretaceous and Cenozoic inversions (Guiraud

and Bosworth, 1999). Along the southwestern Moroccan Atlantic margin, regression

took place shifting the depositional environment to shallow marine facies (Hafid et al.,

2008). At the Jurassic- Cretaceous boundary major deformation occurred in the North

6

African basins related to the Cimmerian/Berriasian orogenic affecting also southeastern

Europe (Guiraud et al., 2005: Stampfli et al., 2001).

Fig. 1-2 Paleogeographic reconstructions modified after Blaeky 2012. The yellow dot is for Morocco and the magenta dot is for Egypt. “Global Paleogeographic Maps © 2012 Colorado Plateau Geosystems Inc., used with permission from Ron Blakey”.

1.3.2 Cretaceous Period

Active E-W/NW-SE rifting characterizes the Lower Cretaceous in North Africa

contemporaneously with the Arabian-Nubian Block separation from the South American

7

plate (Guiraud et al., 2005). During Aptain, the connection between the NeoTethys Ocean

and Central Atlantic was complete, and the sea level rose (Berra and Angiolini, 2014). The

rifting persisted in most North African basins till Santonian. Warm climate cycles

coexisted with highest recorded Phanerozoic sea transgressions which invaded

northwestern and central African basins during the Middle to Late Cretaceous and which

led to oceanic anoxic events (e.g. OAE2 and OAE3), (Fig.1-2) (Guiraud et al., 2005: Haq et

al, 1987). These periods witnessed intense organic carbon deposition and increased

bottom water anoxia (Jenkyns, 2010). Furthermore, widespread warm bottom waters

characterized the North Atlantic as well as the tropical oceans leading to positive δ13C

isotope excursions (Friedrich et al., 2012). Moreover, northern Egypt and southwestern

Morocco acted as carbonate platforms (Phillip et al., 2013). During Santonian, major

tectonic events took place including the ophiolite obduction in Oman, the change in poles

of rotation of the Atlantic Ocean and the Laramide phase of the Alpine orogeny. The later

were responsible for propagating major fold belts such as the Atlas chain and the Syrian

Arc in the Levant and Northern Egyptian basins (Guiraud and Bosworth 1997: Guiraud

et al., 1987; Tawadros, 2011). These movements caused regional unconformities

throughout the North African basins as will be discussed in the case of Northern Egypt in

the flowing chapters. Rejuvenation and acceleration of rifts spanned the Campanian to

Maastrichtian ages in North Africa with infrequent occurrences of magmatic activities

such as in offshore Libya (Guiraud and Bosworth, 1997, 1999).

1.3.3 Paleogene Period

A new E-W compressional tectonic phase occurred at the Maastrichtian-Paleocene

boundary that was responsible for accentuating the Santonian fold belts in northeastern

Africa (Guiraud and Bosworth, 1997). However, this shortening phase started earlier in

northwestern Africa such as in Algeria (Aris et al, 1998). Consequently, a significant

hiatus unconformity in the Tarfaya Basin occurred from Santonian to Pliocene (Davidson,

2005). A pronounced sea transgression occupied major parts of North Africa during the

Paleocene to Eocene times and deposited shallow marine sediments (Guiraud et al.,

2005). In the Eocene to Oligocene times, a compressional event evolved in North Africa

8

especially in the Maghrebian Atlas in northwestern Africa and the Syrian Arc in the

Eastern Mediterranean region (Guiraud and Bosworth, 1999; Guiraud et al., 2005). The

event was coeval with the opening of the Atlantic and Indian oceans and the movement

of Africa toward southern Eurasia and the gradual closure of NeoTethys (Berra and

Angiolini, 2014). Through the Early Oligocene, North Egypt witnessed high sea level

before maximum tectonic shortening of Syrian Arc that ceased the basin subsidence in

the Western Desert. On the other hand, the Tarfaya Basin area was uplifted due to the

orogeny affecting northwest Africa (see above) and created an erosional surface till the

Miocene (Ruiz et al., 2010; Wenke, 2014).

1.3.4 Neogene Period

The Miocene Epoch witnessed significant extensional and compressional tectonic events

that considerably affected Northeast Africa. These include the initiating of the Red Sea

rifting, the opening of the Gulf of Aqaba, and development of the River Nile (e.g. Bosworth

et al., 2005). Also, it witnessed variable sea level changes with a global sea level

regression leading to thick evaporites in the Messinian (Messinian Crises). The

Quaternary is characterized by widespread fluvial deposits (Guiraud et al., 2005).

1.4 Source Rock Potential Overview of the Study Areas

1.4.1 Source rock potential of Egypt

In Africa, Egypt is the largest non-OPEC oil producer and the second natural gas producer

(US Energy Administration Information, 2015). It comprises three main petroleum

provinces which are the Western Desert, Nile Delta and Gulf of Suze areas. It is worth

noting that the Red Sea and southern Egypt can also have petroleum potential but has

not been fully explored.

The Paleozoic source rocks, in general, are poorly understood, and about 40 wells in the

Western Desert penetrated the Precambrian or Paleozoic (Doloson et al., 2000). The

Silurian and Devonian successions host highly prolific petroleum systems in Libya and

Saudi Arabia (e.g. Macgregor, 1996; Mahmoud et al., 1992). This indicates that Egypt

could have equivalent prolific source rocks or migrated hydrocarbons from Libyan

9

basins. One of the Western Desert wells tested gas condensates in a Carboniferous

section, but no geochemical data was released for this gas (Doloson et al., 2000).

The Jurassic source rocks are better studied in the Western Desert than in the Nile Delta

and Gulf of Suez basins. The Jurassic source rocks in the Western Desert include the

Khatatba, Shaltut, Kharita and Masajid formations (e.g El Nady et al., 2015; Maky and

Saad, 2009; Shalaby et al., 2012). The Cretaceous source rocks in the Western Desert are

found in Alam El Bueib Formation, the “G”, “F” and “E” members of the Abu Roash

Formation as well as occasionally the Bahariya and Khoman formations (e.g. El Nady,

2016; Zobaa et al., 2011). In the Western Desert, the Miocene source rocks are less

common, but they can be found in Dabba and Moghra formations (Maky and Saad, 2009).

In the Nile Delta Basin, limited information is available on the Jurassic and Cretaceous

source rocks (Shaaban et al., 2006). The current work (chapter 2) shed lights on the

Jurassic and Lower Cretaceous potential source rocks. The Middle Miocene Sidi Salem

Formation contains one of the major source rocks of the basin (e.g. El Nady, 2007).

The Gulf of Suez hosts prolific source rocks within the Cretaceous Brown Limestone in

middle and northern areas (e.g. Robison, 1995) and excellent Miocene source rocks

within Rudeis and Kareem formations (e.g. El Atfy et al, 2014,). Along the Red Sea

coastline, organic-rich beds of the upper Cretaceous Dakhla and Duwi formations show

excellent source rock potential (e.g. El Kammar et al., 1990). Good Miocene source rock

qualities are expected along the Red Sea basins such as the source rocks found in Saudi

and Sudanese coastlines (e.g. Cole et al., 1995)

1.4.2 Source Rock Potential of Tarfaya Basin

The Tarfaya basin is considered one of the most important petroleum basins among

Moroccan petroleum provinces. (Dyni, 2006). In the following, the potential source rocks

of the Tarfaya basin are summarized (Fig, 1-3).

Outcrop samples within the Ordovician, Devonian, Carboniferous and Lower Cretaceous

except for the Albian have poor source rock potential. All of the samples are thermally

immature based on microscopic and pyrolysis results (Sachse et al., 2011). The samples

10

from the Ordovician, Devonian, Carboniferous and Lower Cretaceous have TOC values of

less than 0.50%. Geochemical evaluations of three onshore wells and outcrop samples

prove good to excellent petroleum source rock potential within the late Albian, Upper

Cretaceous and Eocene successions (Sachse et al., 2011, 2014). On the other hand, the

Albian source rocks show high quality in the coastal areas, and this diminishes toward

the eastern part of the basin. The difference is explained by changes in the depositional

environment from marine to non-marine to the eastern hinterland.

Cenomanian outcrop samples show variable petroleum source rock potential. Along the

present day coastline, the Cenomanian is rich in marine organic matter with TOC

contents averaging 4 and excellent kerogen quality attested by average HI values of 600

mgHC/g TOC (Sachse et al., 2011). Furthermore, the samples are lean in vitrinite and rich

in liptinite which suggests excellent oil prone source rocks. The overlying Upper

Cenomanian and the lower Turonian witnessed one of the most significant Oceanic

Anoxic Events in the Earth history (OAE 2) (Kolonic et al., 2002). The inland outcrop

samples from the Cenomanian/Turonian boundary are of a terrestrial or lagoonal

environment, whereas the well samples close to the coast represent fully marine

conditions (Sachse et al., 2011). The Coniacian and Santonian intervals partly represent

OAE 3 and are also rich in TOC having high HI values (Sachse et al., 2014). Several outcrop

samples from the Eocene show variable source rock qualities. The TOC ranges from 0.05

to 7.20 %, and HI varies from 89 to 694 mgHC/gTOC (Sachse et al., 2011).

Kinetic experiments on some of the Cretaceous samples indicate a temperature of an

onset of petroleum generation between 101-115 °C (Sachse et al., 2011). Therefore, these

samples if buried at an approximate depth of 4000 m will start to generate oil assuming

a geothermal gradient of 25 to 30 °C/km (Fig.1-4). Therefore, a great oil source potential

for the late Albian to the Eocene especially in the coastal and offshore areas is suggested.

In the coastal regions, maturity is not sufficient for petroleum generation, but the thick

sediments might act as oil shales for retorting. In some offshore areas, sufficient

temperature and maturity might be reached for petroleum generations. Figure. 1-3

summarizes the probability of source rock potential based on research work by Ghassal

11

et al. (2015). Further details on the petroleum systems of the Tarfaya Basin is given in

Chapter 4.

Fig. 1-3 Source rock potential traffic light map of the Tarfaya basin based on published data by Sachse et al., (2011, 2012, 2014), Ghassal et al., (2015) and Wenke (2014).

Fig. 1-4 Geothermal gradient map of the Tarfaya basin modified after Zarhloule (2003) and Ghassal et al. (2015)

12

1.5 Research Objectives

Hydrocarbon exploration strategic planning depends on many factors. From a geological

point of view, understanding the basin formation is essential to predict the source rock

reservoir and seal distributions. In the unconventional shale resources, detailed

characterization of organic matter richness, type and thermal maturity, as well as

porosity and permeability, is the key to determine their prospectivity. Organic

geochemistry is an essential subject that helps in reducing exploration risk from the

industrial perspective and a tool that assists in paleoenvironmental reconstruction

studies on the academic side. The thesis combines both perspectives and focuses on the

source rock characterization using conventional and new methods.

The general aim of the thesis is to provide common source rock characteristics of deltaic

and shallow marine environments and their expected hydrocarbon types using data from

three different basins which are the Nile Delta and Abu Gharadig basins in Egypt and the

Tarfaya Basin in southwestern Morocco. Under this topic, the research work investigates

the consequences of the interactions between organic matters and various elements in

the sea bottom using three different integrated approaches. The studied source rocks

cover a wide time span and variable source rock types. The study of each area was

designed specifically to suit their research goals but with emphasizing the general thesis

theme.

In the last few years, the Nile Delta Basin became a very appealing exploration target for

natural gas, yet it lacks a well-established organic geochemical inventory especially for

the Jurassic and Lower Cretaceous successions. Moreover, distribution of the source

rocks is not well documented. The present study aims to 1) characterize the source rock

potential and depositional environment using organic geochemical methods and 2)

model the burial and thermal history using organic petrography and 1D conceptual

modeling. At the end, a summary of the Nile Delta basin source rock potential will be

provided. This study attempts to highlight the source rock characteristics of a poorly

understood wave-dominated delta type.

13

The source rock characteristics in the Abu Gharadig Basin are also poorly understood.

Here, integrated organic and inorganic geochemical and palynofacies data were used to

determine source rock depositional environment and petroleum potential. The study

will examine the effects of the bottom water chemical composition and the interplay

between some elements and organic matter on the source rock quality. The last goal is to

pinpoint the depositional environment changes within Cenomanian to Santonian times

in the Abu Gharadig Basin.

The Tarfaya Cenomanian to Turonian source rocks in Morocco are famous oil shale

deposits. However, they lack detailed organic petrological and organic sulfur richness

information. The study aims to characterize the potential source rocks, then classify

them based on their microscopic features and organic sulfur contents.

Finally, the data of the three studies that represent different shallow marine

environments will be integrated. This will enable us to draw a broad picture of the

changes of source rock facies versus deposition proximity to shorelines. The data will be

retrieved from three different independent basins which should highlight the general

changes that can be applied to any basin avoiding local effects. The overview of the

variations in the source rock richness and quality from deltaic to outer shelf depositional

environments will help in studying frontier or poorly understood basins and executing

lower risk strategic exploration planning beyond the studied areas.

1.6 Thesis Outline

The current thesis comprises three different integrated studies followed by general

discussion and conclusions. The first study (Chapter 2) assesses the Jurassic, Lower

Cretaceous, and Miocene source rocks in the Nile Delta Basin using state of the art organic

geochemical and petrological methods integrated with 1D basin modeling. The study

provides new information about southern and northeastern Nile Delta Basin thermal and

burial histories as well as regional source rock characteristics. It was published in the

Arabian Journal of Geoscience in 2016.

14

The Second study (Chapter 3) uses an integrated geochemical and palynological

approach to investigate the paleoenvironment and source rock potential in the

Cenomanian to Santonian succession in the Abu Gharadig Basin in Egypt. It elucidates the

source rock properties of the Cenomanian-Turonian boundary section (Abu Rash “F”

Member) and highlights remarkable changes in lithologies and kerogen types within this

short geological period. The study area represents shallow marine/terrigenous shelf. It

was submitted to the International Journal of Coal Geology in 2017.

The last study (Chapter 4) aims to comprehensively characterize Cenomanian to

Turonian organic-rich oil shale deposits in the Tarfaya basin in southwest Morocco and

classifies it based on organic sulfur richness. This result is significant for scientific and

industrial communities as the organic sulfur-rich oil shale requires special treatment

upon retorting. This paper was published in a special issue entitled "Selected

contributions from the XIV ALAGO Congress" in Geologica Acta Journal in 2016.

Chapter 5 integrates data from these studies with other published data to highlight

possibly new parameters/proxies for assessing source rock quality at different

depositional settings. Finally, a general synopsis is provided at the end of the thesis in

Chapter 6.

15

An oil paint of an allochthonous coal particle in a Middle Jurassic Khatatba source rock sample. Artist: Esrraa Abunar

16

Chapter 2 | Source Rock Potential of the Middle Jurassic to Middle Pliocene, Onshore Nile Delta Basin, Egypt1

2.1 Abstract

Organic geochemical characterization of cutting samples from the Abu Hammad-

1 and Matariya-1 wells elucidates the depositional environment and source rock

potential of the Jurassic and Lower Cretaceous successions and the Middle

Miocene to Pleistocene section in the southern and eastern Nile Delta Basin. The

burial and thermal histories of the Mesozoic and Miocene sections were modeled

using 1D basin modeling based on input data from the two wells. This study

reveals fair to good gas-prone source rocks within the Upper Jurassic and Lower

Cretaceous sections with total organic carbon (TOC) averaging 2.7% and

hydrogen index (HI) up to 130 mg HC/g TOC. The pristane/n-C17 versus

phytane/n-C18 correlation suggests mixed marine and terrestrial organic matter

with predominant marine input. Burial and thermal history modeling reveals low

thermal maturity due to low heat flow and thin overburden. These source rocks

can generate gas in the western and northern parts of the basin where they are

situated at deeper settings. In contrast, the thick Middle Miocene shows fair source

rock quality (TOC averaging at 1.4%; HI maximizing at 183 mg HC/g TOC). The

quality decreases towards the younger section where terrestrial organic matter is

abundant. This section is similar to previously studied intervals in the eastern Nile

Delta Basin but differs from equivalents in the central parts where the quality is

1 Ghassal, B. I., El Atfy, H., Sachse, V., & Littke, R. (2016). Source rock potential of the Middle Jurassic to Middle Pliocene, onshore Nile Delta Basin, Egypt. Arabian Journal of Geosciences, 9 (20), 744.

17

better. Based on 1D modeling, the thick Middle Miocene source rocks just reached

the oil generation stage, but microbial gas, however, is possible.

2.2 Introduction

The Nile Delta Basin is considered as one of the most productive petroleum basins

in Egypt and the eastern Mediterranean region especially for gas resources and

constitutes approximately 60,000 km2 equally onshore and offshore (Fig. 2-1;

Barakat 2010). It is triangular in shape and is bounded by the Western Desert with

several subbasins such as Natrun and Abu Gharadig to the west and southwest,

Sinai to the east, and the deep Mediterranean to the north (Fig. 2-1). Petroleum

exploration activities started in the 1940s, which led to several gas and

condensate discoveries (Abdel Halim 1999; Shaaban et al. 2006). The basin even

gained greater interest after the recent super giant gas field discovery, Zohr field,

in offshore Nile Delta Basin in 2015 (Esestime et al. 2016). The majority of the

discovered gas and oil fields are located in the northern onshore and the offshore

areas, whereas in the central and southern onshore areas, there are no commercial

accumulations except for some small oil discoveries in 2006 in Messinian

reservoirs located in the vicinity of Mansoura City, e.g., El Tamad Field (Abdel Aal

et al. 2001; El Nady 2007; Leila M., personal communication). Generally, at least

three petroleum plays were identified, i.e., (i) oils sourced from the Late

Cretaceous/Paleogene found in Miocene/Oligocene reservoirs, (ii) thermogenic

gas in the Miocene sections, and (iii) biogenic gas in the Pliocene intervals (Abdel

Halim 1999; Abdel Aal et al. 2001; El Nady 2007; Khaled et al. 2014). Within the

basin, petroleum systems are not yet fully understood; for example, the Jurassic

and Cretaceous sections encompass key source rocks in the region such as in the

north Western Desert and Gulf of Suez basins, but very limited information is

available for equivalent units in the Nile Delta Basin due to limited penetration of

these sections (Shaaban et al. 2006). The southern areas were geochemically

18

poorly investigated so far compared to the northern areas, and most of the work

was on Miocene sections (Abdel Halim 1999).

The current study aims to investigate source rock potential of the Middle Jurassic

to Upper Cretaceous as well as the Middle Miocene to Middle Pliocene in the

southeastern and eastern Nile Delta Basin using samples from the Abu Hammad-

1 and Matariya-1 wells, respectively (Fig. 2-1). In addition, the organic

geochemical data will be used to investigate the depositional environment of these

intervals. Moreover, 1D basin models were constructed to quantify burial and

temperature history as well as maturation and petroleum generation and to

evaluate thermogenic gas potential of the assessed source rocks. Deltas are one of

the sedimentary settings that favor source rock deposition and classified into

three types: (1) fluvial dominated, (2) tide dominated, and (3) wave dominated

(Galloway 1975). The first two types are characterized by low energy and favor

source rock deposition more than the high-energy wave-dominated type (e.g., Nile

Delta) that lacks optimum source rock deposition and preservation conditions

(Allen and Allen 2005). Nevertheless, numerous gas fields have been discovered

regardless of the many unexplored sections (Fig. 2-1). Therefore, such integrated

study that combines organic geochemistry and burial and thermal history

modeling should provide a means for a better understanding of source rock

distribution and quality as well as maturity, which might help in future

exploration.

19

Fig. 2-1 Nile Delta Basin map showing important structures, wells, and gas fields (modified after Abdel Aal et al. 2001; Shaaban et al. 2006). The gray shaded area represents basalt.

2.3 Geological Setting

2.3.1 Tectonic setting

Northern Egypt is a part of the North African platform which extends from Morocco in

the west to Egypt in the East and was covered by the Neotethys since the Jurassic

(Kerdany and Cherif 1990). The Nile Delta Basin is one of the most important basins in

20

northern Egypt and situated between three major tectonic elements: the Red Sea Rift, the

African-Anatolian plate boundary, and the Syrian Arc. Moreover, the basin history was

altered by several tectonic events since the beginning of the Mesozoic, which influenced

the sediment distribution and facies and controlled the formation of structural elements

such as petroleum traps (Kerdany and Cherif 1990; Said 1990; Meshref 1990; Zaghloul

et al. 1999a). The Nile Delta Basin is subdivided into a southern block located on the

unstable shelf (where the study area is located) and a northern block situated on the

steeply faulted continental shelf (Fig. 2-1; Zaghloul et al. 1999b; Kerdany and Cherif

1990; Meshref 1990).

The opening of the Atlantic in the Early Jurassic resulted in two major sets of tectonic

elements in northern Egypt, which are north-northwest-trending folds with thrust faults

and left lateral east-northeast-trending strike-slip faults (Meshref 1990; Dolson et al.

2000; Abedl Aal et al. 2001). Later, sedimentation was affected by Upper

Cretaceous/Lower Eocene compression (Syrian Arc event: ENE-trending structures)

simultaneously with the closure of the Tethys (Kerdany and Cherif 1990; Zaghloul et al.

1999a) that was responsible for regional erosion. Several tectonic events during the

Tertiary including the Red Sea rifting, the opening of Gulf of Aqaba, the Baltim rift, and

the offshore Mediterranean Rosetta and Temsah faults rejuvenated the older structures

(Abedl Aal et al. 2001; Khaled et al. 2014). Rosetta and Temsah faults were activated

during Upper Cretaceous and Neogene times and resulted in the formation of anticlines

that followed those trends and trapped gas especially in the offshore area (Abedl Aal et

al. 2001; Khaled et al. 2014; Fig. 2-1). A period of NESW faulting occurred after the

Messianian event in the offshore, especially in the eastern area, and intersected the

anticlines (Dolson et al. 2000; Abedl Aal et al. 2001; Khaled et al. 2014). On the other

hand, fault movements were mostly pre-Messinian in the western part of the offshore

area (Abdel Aal et al. 2001). In general, the offshore area appears to be more complex in

terms of structures compared to the onshore area, especially towards the north.

21

2.3.2 Stratigraphy

The earliest known stratigraphic record in the Nile Delta Basin is assigned to the Middle

Triassic (Fig. 2-2). Due to the lack of outcrop or well penetration in the Nile Delta Basin,

the stratigraphy can only be inferred by regional paleogeographic interpretations. The

Triassic in the southern Nile Delta block was interpreted by Kerdany and Cherif (1990)

as a tidal flat deposit, whereas Guiraud and Bosworth (1999) suggest a carbonate

platform depositional environment in the south and deep marine environment in the

north. The Jurassic lithologies are variable, controlled by regional and local tectonic

events as well as eustatic sea-level changes (Keeley andWallis 1991; Shaaban et al. 2006).

Marine carbonate deposition predominates but is modulated by transgressive-regressive

cycles (Kerdany and Cherif 1990; Guiraud and Bosworth 1999). Outcrop and

sedimentological analysis reveals also swamp and lacustrine deposition along the former

coastline from northern Sinai to the Western Desert (Keeley and Wallis 1991). The

Jurassic stratigraphic units are the oldest penetrated sedimentary rocks and were

completely penetrated only in the Abu Hammad-1 well (Zaghloul et al. 1999b; El Nady

2007). Therefore, the lithology of the Jurassic in the Nile Delta Basin is still poorly

understood. The vicinity of the Abu Hammad-1 well area was probably a high in the

Upper Jurassic/Lower Cretaceous, which is represented by an unconformity identified in

seismics (Kerdany and Cherif 1990; Meshref 1990; Said 1990; Harms and Wray 1990).

Various depositional environments were inferred for the Lower Cretaceous that could

range from lagoonal to open shelf (Harms and Wray 1990; Zaghloul et al. 1999b). Crustal

extension in and between Arabia and Africa resulted in E-W-trending rifts in northern

Africa such as the Abu Gharadig Basin. At that time, a shallow marine environment

dominated the Nile Delta Basin (Bayoumi and Lotfy 1989; Guiraud and Maurin 1992;

Guiraud and Bosworth 1999). The depositional environment changed from open marine

in the Aptian to alternating marine and alluvial deposits in the Albian and back to open

marine during the Cenomanian and until the end of the Cretaceous (Said 1990; Guiraud

and Bosworth 1999).

22

Fig. 2-2 Generalized stratigraphic column of the Nile Delta Basin (modified after El Nady 2007; Guiraud and

Bosworth 1999)

23

The Upper Cretaceous to Eocene succession is not present or has not been penetrated in

most of the Nile Delta wells probably due to the Syrian Arc compressional tectonics that

resulted in erosion or non-deposition (Harms and Wray 1990). Thin sediments are

present in the Abu Hammad-1 well. Few wells penetrated the Oligocene, which shows

various lithologies from upper to middle slope deposits, open marine deposits, fluvial

clastics, and basalt (Harms and Wray 1990, Said 1990, Barakat 2010). Basalt occurs in

the subsurface of the southern Nile Delta Basin especially towards the west (Barber

1981; Meneisy 1990) as shown in Fig. 2-1. The Miocene sediments were mainly

controlled by structures related to the opening of the Red Sea and Gulf of Suez (Zaghloul

et al. 1999b). Since the Lower Miocene, the area of the Abu Hammad-1 well location has

been subaerially exposed (Said 1990). The sea level rose more prominently during the

Middle Miocene, and thus, the thicknesses of the Middle Miocene sediments are greater

compared to the Lower Miocene ones (Harms and Wray 1990; Zaghloul et al. 1999b).

Regression took place in the Upper Miocene and especially during the Messinian salinity

crisis (Guiraud and Bosworth 1999). Consequently, deposits of this time are nearly

absent in the southern Nile Delta Basin, and sandy shale lithologies covered the eastern

part of the basin (Said 1990; Zaghloul et al. 1999b). This also left a wide erosional surface

and Grand Canyon scale incised valleys (Barber 1981). Following this event, the Nile

River took its course due to the lowered Mediterranean Sea level (Said 1990). During the

Pliocene, marine transgression occurred and resulted in deposition of marine sediments

that filled the Messianian incised valleys (Ross and Uchupi 1977; Said 1990; Dolson et al.

2001). Then, the depositional system shifted to fluvial and fluviomarine deposits (Said

1990; Zaghloul et al. 1999a). The Pleistocene is mainly of fluvial sandy facies (Zaghloul et

al. 1999b). The common lithologies and the formation names are summarized in Fig. 2-2.

2.4 Samples and Methods

2.4.1 Samples

The study involves two petroleum exploration wells that are located in the eastern and

southern Nile Delta Basin (Fig. 2-1). The first well, Matariya-1, penetrated the

24

sedimentary succession from the Middle Miocene to Middle Pliocene with a total depth

of 4142 m. Twenty-five cutting samples covering an interval from 2284 to 4141m (Table

2-1) were investigated from this well. The second well is named Abu Hammad-1 and has

a total depth of 4283 m. The studied interval ranges from 1212 to 3537 m and is

represented by 16 cutting samples from the Middle Jurassic to Lower/Upper Cretaceous

interval. Each cutting sample represents 3 m of the drilled section, and the interval top

depth is listed in our tables or plotted in figures. All selected samples show a dark color

(usually dark brown).

2.4.2 Elemental analysis

The samples of the Matariya-1 and Abu Hammad-1 wells were analyzed for organic and

inorganic carbon contents using LiquiTOC II (Elementar Analysengeräte GmbH) that uses

IR absorption in a two-step measurement in a single run. In the presence of air, first,

organic and, later, inorganic carbon are converted into CO2. The total organic carbon

(TOC) is measured between 305 and 520 °C and the total inorganic carbon (TIC) is

measured between 520 and 1050 °C. The required amount of powdered sample is 100

mg.

Total sulfur (TS) contents were measured on a LECO S 200 sulfur analyzer (precision is

<5% and detection limit 0.001%) on 10 and 13 samples from the Matariya-1 and Abu

Hammad-1 wells, respectively (Table 2-1).

2.4.3 Rock-Eval pyrolysis

All samples were measured by Rock-Eval 6 for their source rock potential. The method is

described by Espitalié et al. (1985) and Peters (1986). The samples were pulverized to

fine powder that weighed between 45 and 100 mg based on their TOC richness. The

samples were placed in the Rock-Eval 6 instrument and then pyrolyzed at 300 °C for 3

min to generate the S1 peak followed by programmed pyrolysis with a heating rate of 25

°C/min up to 600 °C to generate the S2 peak. Both parameters have the unit of milligram

of hydrocarbons (HC) per gram of rock (mg HC/gRock).

25

Table 2-1 Rock-Eval 6 and elemental data of the Abu Hammad-1 and Matariya-1 wells. Units: *(mgHC/gRock), ** (mgCO2/gRock), *** mgHC/gTOC, ****

mgCO2/gTOC.

Table 2-1 continued

Sample

Number Well Name Depth Formation Age TOC TIC CaCO3 TS TOC/TS S1 S2 S3 Tmax HI OI VR

(m) (%) (%) (%) (%) * * ** °C *** **** (%)

15/190 Matariya-1 2284 Kafr El

Sheikh M. Pliocene

0.51 0.42 3.49 0.06 0.30 1.21

15/191 Matariya-1 2311 Kafr El

Sheikh M. Pliocene

0.29 0.53 4.42 0.07 0.27 1.15

15/192 Matariya-1 2368 Qawasim U. Miocene 0.57 0.37 3.09 0.06 0.36 1.28 416 63 225


15/194 atariya-1 2503 Qawasim U. Miocene 0.50 0.24 2.01 0.04 0.33 1.29 412 65 258 0.48


15/196 Matariya-1 2629 Qawasim U. Miocene 0.71 0.33 2.73 1.09 0.66 0.10 0.60 1.27 415 84 178


15/198 Matariya-1 3113 Qawasim U. Miocene 1.28 1.11 9.28 0.98 1.31 0.15 0.89 1.30 428 69 101


15/200 Matariya-1 3362 Sidi Salem M. Miocene 1.06 0.35 2.93 0.86 1.24 0.07 0.55 1.28 434 52 120

26

Table 2-1 continued

Sample


(m) (%) (%) (%) (%) * * ** °C *** **** (%)


15/202 Matariya-1 3443 Sidi Salem M. Miocene 1.03 0.28 2.32 0.15 0.63 1.22 428 61 119



15/205 Matariya-1 3560 Sidi Salem M. Miocene 1.17 0.29 2.38 0.07 0.61 1.28 429 53 109 0.53






15/211 Matariya-1 4002 Sidi Salem M. Miocene 1.70 0.88 7.32 0.89 1.91 0.95 2.31 1.11

15/212 Matariya-1 4035 Sidi Salem M. Miocene 1.11 0.71 5.93 1.10 1.01 0.36 1.29 1.13


15/214 Matariya-1 4141 Sidi Salem M. Miocene 1.38 0.62 5.20 0.92 2.52 1.25 423 183 90 0.66

27

Table 2-1 continued

Sample


(m) (%) (%) (%) (%) * * ** °C *** **** (%)

15/215 Abu

Hammad-1 1212

Kharita U. Cretaceous

0.36 11.56 96.34 0.78 0.47 0.09 0.26 1.21 428 70 331

15/216 Abu

Hammad-1 1242


0.79 3.02 25.15 0.70 1.13 0.11 0.63 1.25 421 80 159

15/217 Abu

Hammad-1 1362


0.58 10.95 91.28 0.99 0.59 0.24 0.36 1.09

15/218 Abu

Hammad-1 1461

Alam El-

Bueib L. Cretaceous

1.67 1.94 16.18 0.67 1.74 1.26 427 104 76

14/1350 Abu

Hammad-1 1605

Alam El-

Bueib L. Cretaceous

3.56 0.51 4.23 2.11 1.69 0.49 4.62 1.54 422 130 43 0.42

14/1351 Abu

Hammad-1 1794

Alam El-

Bueib L. Cretaceous

3.46 0.23 1.96 1.26 2.74 0.25 2.65 1.69 426 77 49

15/221 Abu

Hammad-1 1803

Alam El-

Bueib L. Cretaceous

3.88 0.31 2.62 0.98 3.96 0.52 2.78 1.32 429 72 34

15/222 Abu

Hammad-1 1947

Alam El-

Bueib L. Cretaceous

3.18 0.22 1.85 2.23 1.43 0.38 1.45 1.64 423 46 51 0.47

15/223 Abu

Hammad-1 1965 Masajid U. Jurassic

1.74 3.14 26.17 1.18 1.47 2.44 2.22 1.17 428 128 67

28

Table 2-1 continued

Sample


(m) (%) (%) (%) (%) * * ** °C *** **** (%)

15/224 Abu


1.18 1.26 10.46 1.35 0.87 0.29 1.10 1.32 427 93 112

14/1352 Abu


0.58 4.78 39.80 1.20 0.48 0.07 0.59 1.48 422 102 256

15/226 Abu

Hammad-1 2379 Khatatba M. Jurassic

0.63 7.44 61.98 0.20 0.71 1.39 432 113 222

15/227 Abu


0.66 6.13 51.06 0.92 0.71 0.09 0.58 1.14 429 89 174

14/1353 Abu


0.53 3.02 25.14 0.82 0.65 0.07 0.65 1.53 426 121 287 0.63

15/229 Abu


0.57 3.99 33.25 0.84 0.68 0.05 0.41 1.29 434 73 228

15/230 Abu


0.51 5.27 43.93 0.04 0.33 1.33 433 64 262 0.71

29

During this pyrolysis process, CO2 is also released from kerogen via thermal cracking. An

aliquot of the pyrolysis gas is trapped and released later to quantify CO2 at an IR detector

(S3 peak, mg CO2/g rock). Tmax is another important parameter which represents the

pyrolysis oven temperature of the maximum kerogen conversion. Other essential

parameters are hydrogen index (HI) which is S2 / TOC (mg HC/g TOC), oxygen index (OI)

which is S3 / TOC (mgCO2/g TOC), and production index (PI) which is S1/(S1 + S2). All

pyrograms were checked carefully to ensure the presence of excellent Gaussian-type

peaks that are almost symmetrical to provide meaningful data. Therefore, Tmax values

of 5 bad S2 peaks out of 41 samples were omitted.

2.4.4 Organic petrography

Four samples were selected from each well for organic petrology and vitrinite reflectance

measurements, following the method described by Taylor et al. (1998). The samples

were embedded in a 10:3 mixture of epoxy resin (Araldite®XW396) and hardener

(Araldite® XW397) and dried at 37 °C for at least 12 h. The sample surfaces were then

ground flat and polished as described by Sachse et al. (2012). Vitrinite reflectance

measurements were performed in a dark room using a Zeiss Axio Imager microscope for

incident light equipped with a tungsten-halogen lamp (12 V, 100 W), a ×50/0.85 Epiplan-

Neofluar oil immersion objective, and a 546-nm filter and yttrium-aluminum-garnet

(YAG; 0.889%) as standard. It was attempted to measure reflectance on a minimum of 50

vitrinite particles per sample. The measurements were processed using the DISKUS

Fossil software (Technisches Büro Carl H. Hilgers).

2.4.5 Source rock extraction and liquid chromatography

Six samples from the Matariya-1 well and eight samples from the Abu Hammad-1 well

were selected for molecular organic geochemical analyses. Aliquots of 3–4 g of powdered

source rock samples were extracted, respectively. Fifty milliliters of dichloromethane

(DCM) was added to each sample, and the mixtures were agitated in an ultrasonic bath

for 15 min. Then, each mixture was stirred overnight at room temperature and agitated

30

again in an ultrasonic bath for 15 min. After filtration, activated copper powder was

added to remove elemental sulfur. The raw extracts were separated using a liquid

chromatography on a micro column (Baker, filled with 2 g of silica gel 40 mm).

Fractionation separated the raw extracts into three fractions of increasing polarity using

n-pentane (5 ml), n-pentane/ DCM40/60 v/v (5 ml), and methanol (5 ml), respectively.

The first fraction represents the aliphatic hydrocarbons, whereas the second contained

the aromatic hydrocarbons and the last fraction has more polar compounds.

2.4.6 GC-FID and GC-MS

The aliphatic fractions were analyzed by gas chromatography flame ionization detector

(GC-FID) using a Fisons Instruments GC 8000 series equipped with a flame ionization

detector and a Zebron ZB-1HT Inferno fused silica column (30 m × 0.25-mm internal

diameter (i.d.); film thickness 0.25 μm, Phenomenex®). Each sample was diluted with

approximately 100 ml of DCM, and 1 μl of this solution was injected into a split/splitless

injector at 270 °C and a splitless time of 60 s. Hydrogen was used as a carrier gas with a

velocity of 45 cm/s. The initial temperature was 80 °C and held for 3 min; then, the

temperature increased at a rate of 10 °C/min to reach 300 °C and held for 20 min. The

GC-mass spectrometry (GC-MS) analyses were performed on a Finnigan MAT 95 mass

spectrometer linked to a Hewlett Packard Series II 5890 GC, which was equipped also

with a Zebron ZB-1HT Inferno fused silica column (30 m × 0.25-mm i.d.; film thickness

0.25 μm, Phenomenex®). The carrier gas was He with a velocity of 33 cm/s. The

temperature program started at 80 °C for 3 min; then, the temperature increased at a rate

of 5 °C/min to reach 310 °C. The spectrometer was operated in electron impact ionization

(EI*) mode with an ionization energy of 70 eV and a source temperature of 200 °C. The

scanning range was from m/z 35 to 700 in low-resolution mode.

All biomarker ratios were calculated on the base of peak integration of specific ion

chromatograms. For alkanes, the ion chromatograms of m/z 57 were used. Hopane and

steranes ratios were calculated using m/z 191 and m/z 217 chromatograms,

respectively. All homologue groups were verified by their specific molecular ions.

31

Individual isomers were identified by comparing their elution order with those of

published data (e.g., Peters et al. 2005).

2.4.7 1D burial and thermal history modeling

The PetroMod 1D basin modeling software (version 2014.1, Schlumberger) was used to

construct burial and thermal history models of the Abu Hammad-1 and Matariya-1 wells.

The conceptual models were constrained by present-day information on the geological

setting and basin evolution based, e.g., on the work by Harms and Wray (1990).

Information on lithologies and their depositional ages was adopted from drilling reports.

The paleowater depth (PWD) was estimated based on the biostratigraphic data from

drilling reports. The sediment/water interface temperature (SWIT) was calculated for

latitude 32°, North Africa, based on Wygrala (1988). Borehole temperature and thermal

maturity data served as calibration parameters. The EASY %Ro algorithm (Sweeney and

Burnham 1990) was used for calculation of vitrinite reflectance.

To assess the burial histories of the two well locations, different scenarios were tested in

order to model the thermal regime. As this is highly dependent on the amount of

paleothicknesses (erosion) and assigned basal heat flow values, initially, a basic scenario

was constructed using a current basal heat flow of 38.3 mW/m2 (±7) for the eastern Nile

Delta Basin which was published by Eckstein (1978). This low value is in the expected

range for Precambrian foreland basins. In a next step, further scenarios were created

with heat flow values of 31.3, 38.3, and 45.3 mW/m2. Slightly higher heat flow values

were assigned for the Jurassic. Thereafter, these models were validated using calibration

data (VRr data and borehole temperature data). Three major erosion/hiatus events were

assigned for the Late Jurassic, for the Late Cretaceous to Early Eocene, and for the

Miocene in both wells. The first event was triggered by a major Neotethys sea-level drop

and the tilting of the unstable shelf (Keeley 1994). The second erosion event/hiatus was

caused by compressional tectonics (Syrian Arc Event), which affected the Nile Delta Basin

(Harms and Wray 1990). The latest erosion event was deduced for the end of the Middle

Miocene and the Messinian crisis event (Barber 1981; Harms and Wray 1990. In order to

32

get information on the dynamics of petroleum generation, the source rock kinetics for

kerogen type III (F) published by Pepper and Corvi (1995) was used.

2.5 Results


The Middle Jurassic Khatatba Formation has an average carbonate (calculated as CaCO3)

content of 43.1% and shows low TOC and TS contents of 0.6 and 0.9% on average,

respectively (all data and ranges in Table 2-1; Fig. 2-3). In the Masajid Formation, the TOC

and TS values are slightly higher at 1.2%. The formation is relatively low in carbonate

(25.5%). The Lower Cretaceous Alam El Bueib Formation has the highest TOC and TS

contents with values averaging 3.15 and 1.7%, respectively. Carbonate content is low at

5.3%. The uppermost investigated interval is the Albian Kharita Formation that shows

very low TOC and TS averages of 0.6 and 0.8%, respectively, whereas carbonate is high

(average of 70.9%; Table 2-1;Fig.2-4). The Sidi Salem Formation in the Matariya-1 well

shows generally low carbonate contents (average of 4.9%) and moderate TS (0.98%) and

TOC (1.5%). Similar values were measured in the overlying Qawasim Formation (Table

2-1). Only two samples from the Kafr El Sheikh Formation were investigated showing low

carbonate and TOC values (Table 2-1).

2.5.2 Rock-Eval analysis

In the Abu Hammad-1 well, only the uppermost two samples of the Masajid and Alam El

Bueib Formations show source rock quality with S2 and HI averages of 2.37 mg HC/g

rock and 93 mg HC/g TOC, respectively. This interval shows relatively high OI values of

62 mg CO2/g TOC. Tmax is low and averages 426 °C. Apart from this interval, the

investigated section shows poor S2 values, although HI values are partly at values close

to 100 mg HC/g TOC (Table 2-1; Fig. 2-5).

The Matariya-1 well shows variable source rock qualities in the Sidi Salem and the

deepest two samples from the Qawasim Formation. This interval has an average S2 and

33

HI of 1.28 mg HC/g rock and 88 mg HC/g TOC, respectively. The OI values are high

(average of 97 mg CO2/g TOC) and Tmax is low (average of 426 °C; Table 2-1).

Fig. 2-3 Depth plotted versus TOC, CaCO3, TS, HI, and Pr/Ph of the Abu Hammad-1 and Matariya-1 wells

34

Fig. 2-4 TOC plotted versus TS (a) and CaCO3 (b) of the Abu Hammad-1 and Matariya-1 wells

35

Fig. 2-5 TOC plotted versus S2 of the investigated samples.


All samples from the Abu Hammad-1 well are dominated by vitrinite and inertinite

macerals. The vitrinite reflectance (VR) measurements revealed a wide reflectance range,

but only the lower values were considered, as they present the indigenous particles.

Mean values range between 0.42 and 0.71% (Table 2-1).

The samples from the Khatatba Formation contain small vitrinite particles (usually 5 to

20 μm) as well as inertinite and framboidal pyrite of variable size. Sample 14/1353

(depth 2502 m) contains a larger coal particle that is composed of vitrinite, inertinite,

and streaks of liptinite with weak brownish fluorescence. This coal particle has an

exceptional, high vitrinite reflectance of 1.13%. The Alam El Bueib Formation samples

also show a dominance of vitrinite and inertinite. In total, there are more organic

particles and framboidal pyrites than in the Khatatba Formation. Vitrinites occasionally

contain framboidal or euhedral pyrites. Sample 14/1350 (depth 1605 m) contains a large

36

particle of telovitrinite (VRr 0.37, close to the average of the sample which is 0.42).

Similarly, the samples from the Matariya-1 well are dominated by terrestrial macerals.

Vitrinite reflectance ranges from 0.48 to 0.66%. The vitrinite particles are usually very

small (5 to 10 μm).

Samples from both wells show very small and rare liptinite particles under fluorescent

light. Parts of the (liptinitic) organic matter might be submicroscopic, but due to the low

HI values, we do not expect any large submicroscopic percentages of hydrogen-rich

kerogen.

All samples were carefully checked for drilling fluid contamination and appeared to be

almost clean of contamination by small coal particles from either caving or drilling fluid.

These rare coal particles attributed to caving or contamination have a very low

reflectance (~0.2%). The measured VR values are in principal agreement with Rock-Eval

Tmax values (Table 2-1; Hartkopf-Fröder et al. 2015).

2.5.4 Molecular geochemistry

Only samples that exhibit high TOC contents were used for molecular geochemistry. The

source rock extracts from the Middle Jurassic Khatatba Formation show high abundance

of n-C15 to n-C22 alkanes (Fig. 2-6) and Pr (pristane)/Ph (phytane) ratios of 1.1 on average

(Table 2-2). In contrast, the Upper Jurassic Masajid Formation (one sample only, Table 2-

2) shows maxima both for n-C31 and n-C33 as well as n-C15 to n-C22 alkanes. This sample

has a low Pr/Ph value of 0.76 and a high carbon preference index of 1.76 (Table 2-2).

Three samples of the TOC-rich Lower Cretaceous Alam El Bueib Formation were

analyzed. Alkanes are abundant in the range of n-C15 to n-C22 with long chain alkanes

increasing towards the younger section (Fig. 2-6). The Pr/Ph ratio varies between 0.92

and 1.12. The Alam El Bueib Formation demonstrates very low terrestrial to aquatic ratio

(TAR) ((n-C25 + n-C27 + n-C29 /(n-C15 + n-C17 + n-C19)) that does not exceed 1.11, and CPI

ranges between 0.88 and 1.02 (Table 2-2).

37

Fig. 2-6 Gas chromatographs of the saturated hydrocarbon fractions of the a) Kafr El Sheikh Formation, b) Qawasim Formation, c) Upper Sidi Salem Formation, d) Lower Sidi Salem Formation, e) Kharita Formation, f) Upper Alam El Bueib Formation, g) Lower Alam El Bueib Formation, h) Masajid Formation, and i) Khatatba Formation. Note that n-C17 and n-C20 are marked.

38

Table 2-2 Gas chromatography data of selected samples from the Abu Hammad-1 and Matariya-1 wells.

Sample

Number Well name Depth Formation Age Pr/Ph Pr/n-C17 Ph/n-C18 TAR CPI OEP

(m)

15/190 Matariya-1 2284 Kafer El Sheikh M. Pliocene 2.00 1.80 1.89

15/197 Matariya-1 2659 Qawasim U. Miocene 1.45 1.48 1.57

15/204 Matariya-1 3527 Sidi Salem M. Miocene 4.44 3.24 1.96 0.78 1.10 1.05

14/1355 Matariya-1 3626 Sidi Salem M. Miocene 3.23 5.11 2.05 0.81 0.88

15/212 Matariya-1 4035 Sidi Salem M. Miocene 1.65 2.32 2.27 0.06 0.99 1.03

15/214 Matariya-1 4141 Sidi Salem M. Miocene 1.40 2.04 2.21 1.17 1.16

15/216 Abu Hammad-1 1242 Kharita U. Cretaceous 1.31 1.07 1.03

15/218 Abu Hammad-1 1461 Alam El Bueib L. Cretaceous 1.12 1.13 1.12 0.11 0.88 0.97



15/224 Abu Hammad-1 2016 Massajid U. Jurassic 0.76 0.76 0.88 0.80 1.76 1.38

15/226 Abu Hammad-1 2379 Khatatba M. Jurassic 1.23 1.03 0.93



39

Ts/Tm ranges from 0.51 to 0.73, and the gammacerane index (gammacerane /

(gammacerane + C30 hopane)) decreases from 0.81 to 0.34 towards the younger section.

The 17α-diahopane/18α-hopane (C30*/C29 Ts) is relatively high and ranges from 1.35 to

5.34. The molecular geochemistry characteristics of the Kharita Formation were assessed

based on only one sample due to lean TOC content. The sample shows a high abundance

of n-C14 to n-C22 alkanes. The GC data of four samples from the Middle Miocene Sidi Salem

Formation from the Matariya-1 well show an increase of Pr/Ph ratio from 1.4 to 4.4

towards the younger sections (Table 2-1; Fig. 2-3). The deeper and older samples show

abundant n-C14 to n-C20 alkanes and long chain n-alkanes in very low concentration. On

the other hand, the upper two samples show a bimodal n-alkane distribution (Fig. 2-6).

The samples show a low abundance of gammacerane, whereas oleanane is present (Table

2-3).

The Pr/Ph ratio is low in the Upper Miocene Qawasim Formation, slightly increasing

towards the Middle Pliocene Kafr El Sheikh Formation (Table 2-1; Fig. 2-3). Furthermore,

these samples show abundant short-chain alkanes that range from n-C15 to n-C18.


Numerical basin modeling was conducted to reconstruct the burial and thermal histories

of both wells using borehole temperature data and measured vitrinite reflectance as

calibration parameters (Fig. 2-7a, b). The analysis revealed that a best fit between the

modeled and measured data is achieved using a recent basal heat flow value of 35 and

38.3 mW/m2 in the Abu Hammad-1 and Matariya-1 wells, respectively, which is close to

the heat flow values reported by Eckstein (1978) for the eastern onshore Nile Delta. The

model used a heat flow of 50 mW/m2 during the Lower Jurassic decreasing gradually to

the present-day value, which was reached at the end of the Jurassic (Fig. 2-7a).

40

Table 2-3 Biomarker data of selected samples from the Abu Hammad-1 and Matariya-1 wells.

Sample

Number Well name Depth Formation

Gam/(Gam+

C30Hop) Ts/Tm Ol/(Ol+C30Hop)

(C29*Ts)/

C29H

C29H/

C30H

C30*/

C29Ts

C31H

22S/(22S+22R)

C33H

22S/(22S+2

2R)

Ts/(Ts+

Tm)

C30M/

C30H

(m)

15/204 Matariya-1 3527 Sidi Salem 0.05 0.68 0.07 0.16 0.92 1.60 0.58 0.58 0.41 0.21




15/216 Abu Hammad-1 1242 Kharita

15/218 Abu Hammad-1 1461 Alam El

Bueib 0.34 0.60 0.33 0.70

1.35 0.32 0.37 0.68


Bueib 0.37 0.51 0.14 0.68

5.34 0.49 0.34 0.40


Bueib 0.81 0.73 0.22 0.70

3.52 0.48 0.42 0.47

15/224 Abu Hammad-1 2016 Massajid 0.36 0.96 0.50 0.78 2.29 0.51 0.49 0.70

41

Fig. 2-7 Burial/thermal history diagrams of the a) Abu Hammad-1 and b) the Matariya-1 wells in the next page.

A)

42

Fig. 2-7 Continued – b) Burial/thermal history diagrams of the Matariya-1 wells.

B)

43

In the area of the Abu Hammad-1 well, a fast deposition of carbonates occurred during

the Lower Jurassic followed by sedimentation of carbonates and clastics until the end of

the Jurassic. An unconformity surface separates the Jurassic from the overlaying layers

with a minor anticipated erosion. This is followed by the deposition of the Alam El Bueib

Formation due to sea level rise. This formation contains eight alternating sandstone and

shale intervals that comprise the source rock sections. These sediments were further

buried, but burial was interrupted in the Late Cretaceous when approx. 500 m was

eroded. Moderate uplift occurred during the Early Paleocene till the Eocene. Deposition

of continental sandstones, interbedded with two thin layers of basalt, started again in the

Oligocene. The sea-level drop favored the rapid deposition of shallow marine clastics of

Lower and Lower-Middle Miocene age, leading to the maximum burial depth of about

4780 m. No further significant burial took place since that time. At present day, the base

of the Alam El Bueib Formation reaches temperatures of 65 °C and a vitrinite reflectance

of 0.47% VRr.

The burial and temperature history for Matariya-1 well is described for the example of

the Sidi Salem Formation, consisting of two source rock intervals interbedded with

sandstone beds. During its first phase of deep burial in the Miocene, the base of the

formation reached temperatures of 48 °C. The deposition of this formation ended with

an erosion event lasting about 2 Ma (Harms and Wray 1990) and created an

unconformity surface. One thousand meters of erosion was assigned to this event. The

erosion was followed by the deposition of the Qawasim Formation that is characterized

by alternating sandstone and shale lithologies with a source rock interval, which

constitutes its base. A thin anhydrite layer rests on the Qawasim Formation representing

the Messinian crisis event and is followed by a short period of erosion. The following

deposition of the very thick siliciclastic rocks of the Kafr El Sheikh Formation

considerably influenced the thermal maturity in this part of the basin. Thinner,

alternating sandstones and shales of the Wastani, Mit Ghamr, and Baltim formations rest

conformably on the Kafr El Sheikh Formation and led to a deepest burial of 4179 m.

44

Maximum temperature of 114 °C is reached at present day for the Sidi Salem Formation.

The calculated vitrinite reflectance for the Sidi Salem source rock is 0.65% at a depth of

2142 m.

2.6. Discussion

2.6.1 Depositional environments

Elemental and biomarker data were used to investigate the depositional environment

during the Middle Jurassic to Lower Cretaceous and Middle Miocene to Middle Pliocene

times.

2.6.1.1 Middle Jurassic to Lower Cretaceous at Abu Hammad-1 well

The Middle Jurassic Khatatba Formation in the Abu Hammad-1 well vicinity was

deposited in pro-delta to shelf environments (Keeley and Massoud 1998; Keeley and

Wallis 1991). According to the well lithology description, the formation is dominated by

carbonate mixed with siliciclastic sediments. The investigated samples have carbonate

(CaCO3) contents in the range of 33 to 66% supporting the lithology descriptions. In the

TOC vs TS diagram, the samples plot above the normal marine line (Berner 1984), which

is usually regarded as indication of oxygen-free bottom waters during deposition (Fig. 2-

4), i.e., reducing conditions. However, this might not be correct here, because organic

matter content is low (less than 4%, less than 2% for most samples) and sulfur content

is quite low as well, if compared to other marine shales. Oxygenated bottom waters are

also indicated by the Rock-Eval data, i.e., low HI and moderate to high OI values. The

occurrence of large pyrite crystals in some samples indicates a late diagenetic

thermochemical sulfate reduction in addition to bacterial sulfate reduction. The Pr/Ph

ratio is used as another indicator of depositional environment that allows to distinguish

oils and source rocks deposited in more or less oxic bottom-water conditions (Brooks et

al. 1969; Didyk et al. 1978; ten Haven et al. 1987; Powell 1987). Pr/Ph values lower than

1.0 indicate anoxic conditions (Didyk et al. 1978). The samples from the Khatatba

Formation show an average Pr/Ph ratio of 1.1 indicating marginally suboxic conditions.

45

In this formation, the most abundant n-alkanes occur between n-C15 and n-C22 indicating

a strong contribution of marine organic matter. On the other hand, the very low

contribution of alginite as compared to vitrinite and inertinite and low HI values indicate

a predominance of terrestrial organic matter or a strong degradation and poor

preservation of marine-derived organic matter. The lack of long-chain n-alkanes, which

are usually typical of terrestrial organic matter, might be due to slightly higher maturity

and cracking of these long-chain hydrocarbons or due to impregnation by oil from a

deeper source. In any case, the presence of large vitrinite particles indicates a nearshore

environment. This conclusion is supported by the interpretation of Ibrahim et al. (1997),

who suggested a continental shelf environment for the Khatatba Formation, which agrees

with the regional geological interpretations. The terrestrial organic matter might be

sourced from deltas or swamps in the south located along the Jurassic shorelines. The

coal particle in the Khatatba sample indicates the presence of coal deposits prior to the

Jurassic that were eroded and transported to the shelf. The relationship between Pr/n-

C17 versus Ph/n-C18 (Fig. 2-8) is also used to determine the depositional environment and

thermal maturity (Peters et al. 2005). The data suggest a suboxic regime for the Middle

Jurassic Khatatba Formation.

The Upper Jurassic Masajid Formation consists of interbedded limestones and shales

deposited during a period of sea-level fall and northward tilting of the unstable shelf,

which influenced the thickness and lithologies (Keeley 1994). TS values and TS/TOC

ratios are high, indicating fully marine depositional conditions. Low–moderate HI values

of about 100 mg HC/g TOC (Fig. 2-3) indicate poor organic matter preservation or

terrestrial organic matter deposition. One sample from the Masajid Formation shows a

high odd/even predominance value of 1.4, pronounced n-C31 and n-C33 abundance, and

bimodal n-alkane distribution (Table 2-2; Fig. 2-6), indicating indeed the presence of a

mixture of terrigenous and marine algal organic matter (Moldowan et al., 1985). The high

C30*/C29 Ts ratio indicates oxic to suboxic bottom-water conditions during deposition

(Peters et al., 2005), supporting the previous conclusion on a poor organic matter

preservation (Fig. 2-8). The Jurassic period witnessed lacustrine and coal swamp

46

conditions on the coastal belt that extends from northern Sinai to the Western Desert

(Kerdany and Cherif 1990; Keeley and Wallis 1991). Therefore, it is reasonable to assume

a nearshore marine facies with terrestrial organic matter input.

Fig. 2-8 Pr/n-C17 versus Ph/n-C18 for selected samples from the Abu Hammad-1 and Matariya-1 wells, in comparison to other published data.

The Lower Cretaceous Alam El Bueib Formation in the Abu Hammad-1 well is dominated

by siliciclastics lithologies with occasional carbonate intervals, deposited at low–

moderate sedimentation rates (Fig. 2-7a). Regional geological studies suggest that the

southern Nile Delta Basin was dominated by carbonate layers, whereas the northern

parts were dominated by siliciclastics during the Lower Cretaceous (Keeley 1994; Keeley

and Massoud 1998; Keeley and Wallis 1991). This does not fully agree with our data

suggesting siliciclastic deposition also in the south at Abu Hammad-1 well location (Figs.

2-1 and 2-3). The Alam El Bueib Formation source rock samples show the highest TOC

values of all formations studied, as well as quite high TS values, but low–moderate HI

values of about 100 mg HC/g TOC. Correlation between S2 and TOC is poor (Fig. 2-5).

These data suggest that the organic matter was deposited in a marine setting, but organic

matter preservation was poor. Terrestrial organic matter is present, but probably to a

0.01 0.10 1.00 10.00

Ph/nC18

0.01

0.10

1.00

10.00

Pr/

nC

17

Oxidising

Reducing

Biodegraded/immature

Early mature

Mature

Terrestrial organic matter

Mixed sources

Marine organic matter

Well Matariya-1 Abu Hammad-1 Abu Madi-1Abu Madi-3Abu Madi-5EG-ND-1EG-ND-2EG-ND-3EG-ND-TNW-5PFM SE-1Sidi Salem-1Temsah-3

FormationEl Wastani FormationKafer El Sheikh FormationAbu Madi FormationQawasim Formation Wakar FormationSidi Salem FormationMoghra ForamtionKharita FormationAlam El-Bueib FormationMasajid ForamtionKhatatba Formation

47

lesser extent than during the Jurassic; this is indicated by low abundance of long-chain n-

alkanes, especially in the lower part of the section (Fig. 2-6). Towards the top, more long-

chain n-alkanes occur, possibly due to higher terrestrial organic matter contribution.

Pr/Ph values of 0.9–1.1 are very close to the typical values of marine shale (Peters et al.

2005). The Pr/n-C17 versus Ph/n-C18 relationship indicates suboxic depositional

conditions (Fig. 2-8), and the high C30*/C29 Ts ratio indicates oxic to suboxic bottom-

water conditions (Table 2-3).

The Kharita Formation shows low TOC values, but the highest CaCO3 contents compared

to the other Mesozoic formations, which is in accordance with lithology descriptions.

High abundance of n-alkane n-C14 to n-C22 and very low abundance of long-chain n-

alkanes indicate that a marine depositional environment and geochemical data suggest

oxic to suboxic bottom-water conditions (Fig. 2-8).

2.6.1.2 Middle Miocene to Middle Pliocene at the Matariya-1 well

The Sidi Salem Formation in the Matariyah-1 well is a low-stand wedge as interpreted in

a seismic line by Shaaban et al. (2006). The formation constitutes shale with interbedded

sandstone intervals (Fig. 2-7b). The samples, which are rich in silicates, plot above the

normal marine line (Berner 1984) with poor correlation. This indicates either anoxic

bottom water or—more likely—diagenetic sulfate delivery intensifying sulfate reduction

and pyrite formation. Moderate positive correlations between CaCO3 and TOC and HI are

observed. This implies an enhanced organic matter preservation during periods of

enhanced carbonate deposition, probably due to the input of more marine organic

matter. A poor correlation coefficient was calculated between TOC and S2 indicating a

non-homogenous source rock interval (Fig. 2-5). Moreover, wide ranges of vitrinite

reflectance for each sample were observed indicating contribution of much

allochthonous organic matter. The section was probably deposited in high-energy

conditions with oxic bottom water facilitating decay of labile, marine organic matter.

Pr/Ph ratios higher than 3 also indicate terrigenous organic matter deposition in an oxic

environment (Peters et al. 2005).

48

The increase in the Pr/Ph ratio from 1.4 to 4.4 towards the younger sections could

indicate a shallowing up delta sequence within the low-stand wedge (Table 2-2; Fig. 2-

3). The n-alkane distribution supports this conclusion as the two bottom samples are

dominated by n-C14 to n-C20 alkanes and have a very low abundance of the high-molecular

weight compounds indicating marine organic matter input. In contrast, the upper two

samples show a bimodal n-alkane distribution in the ranges of n-C14 to n-C18 and from n-

C21 to n-C33 indicating strong contribution from terrigenous organic matter (Fig. 2-6). The

Pr/n-C17 versus Ph/n-C18 diagram (Fig. 2-8) also illustrates a trend from marine to

terrigenous organic matter. Similarly, the HI correlates negatively with the Pr/Ph ratio

supporting the assumption of an increase in oxicity and terrigenous organic matter input

over time. Harms and Wray (1990) suggested a shallowing upward trend during the

Middle Miocene in the vicinity of the Matariya-1 well, which is supported by the

molecular geochemical data. The samples also show relatively high C30*/C29 Ts ratios

indicating oxic to suboxic conditions (Table 2-3). Oleanane is a biomarker most likely

derived from angiosperms that has not been reported widely prior to the Early

Cretaceous (Moldowan et al. 1994; Das and Mahato 1983; Doyle and Hicky 1976),

although we are aware about the presence of angiosperm-like pollen from the Triassic

(e.g., Hochuli and Feist-Burkhardt 2013). Therefore, it is used as biomarker for

angiosperms based on the oleanane index (oleanane/C30 hopane) (Peters et al. 2005).

The samples from the Sidi Salem Formation are characterized by fair presence of

oleanane (Table 2-2).

The Pr/Ph ratio lowers again in the Upper Miocene Qawasim Formation and then slightly

increases in the Middle Pliocene Kafr El Sheikh Formation (Table 2-2; Fig. 2-3).

Furthermore, the samples show strong indication of marine organic matter contribution,

i.e., abundant short-chain alkanes (n-C15 to n-C18). Similarly, the Pr/n-C17 versus Ph/n-C18

relationship indicates presence of marine organic matter (Table 2-2; Fig. 2-7). The

elevated Pr/Ph ratios (1.4 to 2.0) indicate suboxic to oxygenated conditions. Except for

the two bottom samples of the Qawasim Formation, the analyzed section is poor in TOC

and HI, indicating poor preservation of labile marine organic matter.

49


Limited information is so far available on the burial history of the Mesozoic succession in

the southeastern Nile Delta Basin. Thus, basin modeling of the Abu Hammad-1 well

provides novel information on the thermal and burial histories. The model reveals a low

thermal maturity for the Khatatba source rocks. The main factors responsible for this low

thermal maturity are (1) the very low heat flow in the basin and (2) long periods of non-

deposition or erosion that reduced the thickness of the overburden.

On the other hand, the Matariya-1 well model aims to explain the lack of gas fields in the

eastern offshore Nile Delta. It shows the significant effects of the Middle/Upper Miocene

erosional event that ceased further thermal maturation of the source rocks. It should be

noted that erosional thickness increases to the south (Harms and Wray 1990) and

diminished to the north where more late gas generation can be expected. High

sedimentation rates of the Kafr El Sheikh Formation appear to be restricted to the

northern part of the basin as apparent in the regional cross sections (Fig. 2-9a). No gas

or oil expulsion is expected to occur in the Matariya-1 well source rocks even when using

a high heat-flow history scenario (Fig. 2-7b), which might explain the poor Miocene gas

occurrence in the eastern Nile Delta Basin.

2.6.3 Source rock potential

2.6.3.1 Abu Hammad-1 well

Some samples show moderate to high TOC values (up to 4%) in the interval between

1461 and 2016 m including two samples from the Upper Jurassic Masajid Formation and

five samples from the Lower Cretaceous Alam El Bueib Formation (Table 2-1; Fig. 2-3).

However, these samples show relatively low HI values ranging from 46 to 130 mg HC/g

TOC revealing in view of the low thermal maturity dominance of mixed type III/IV

kerogen without oil generation potential and with poor to moderate gas generation

potential (Fig. 2-10). This conclusion is supported by microscopic data revealing

dominance of vitrinite, inertinite, and coaly particles. The interval is thermally

50

Fig. 2-9 a) Cross section demonstrates Oligocene and Miocene stratigraphy at the eastern Nile Delta Basin (modified after Shaaban et al. 2006). B) Cross section shows Nile Delta stratigraphy from the onshore to the offshore areas (modified after Abdel Aal et al. 2001).

a

b

51

Fig. 2-10 HI versus OI of the samples from the Abu Hammad-1 and Matariya-1 wells. PFM-1 well data are published in Khaled et al. (2014).

immature as indicated by the low vitrinite reflectance (VR) and Tmax values (Table 2-1;

Fig. 2-11). Biomarker maturity parameters indicate variable and partly enhanced

thermal maturity (Table 2-3). In particular, Ts / (Ts + Tm) values are quite uniform and

values are in agreement with an early oil window maturity. Whereas this ratio seems to

work well in the studied sections, other biomarker maturity parameters show a lot of

scatter, being possibly strongly influenced by lithology. Combining the thermal maturity

data with results of Rock-Eval pyrolysis and thickness, the immature source rock interval

might have a moderate gas generation potential due to its thickness of more than 500 m.

However, more samples need to be measured, in particular with respect to TOC within

this sequence to verify this conclusion. Based on well lithology logs (Fig. 2-7a), this

interval includes sandstones that could act as potential reservoirs.

2.6.3.2 Matariya-1 well

Based on TOC and Rock-Eval data, only the section from 3113 to 4141 m in the Middle

Miocene Sidi Salem Formation and lower parts of the Upper Miocene Qawasim Formation

0 100 200 300

OI (mg/gTOC)

0

100

200

300

400

500

600

700

800

900

HI (m

g/g

TO

C)

Type I

Type II

Type III

Type III/IVWell Matariya-1 Abu Hammad-1 Abu Madi-9

Kafer El Sheikh FormationAbu Madi FormationQawasim Formation Sidi Salem FormationKharita FormationAlam El-Bueib FormationMasajid ForamtionKhatatba Formation

52

show a fair to good gas source rock potential with dominance of mixed type III/IV

kerogen (Table 1; Fig. 2-10).

VR and Tmax results suggest low thermal maturity with the lower part reaching the onset

of oil generation thermal maturity stage (Table 1; Fig. 2-7b). Microscopic investigations

reveal a dominance of vitrinite and inertinite assemblages, which supports the Rock-Eval

data (Figs. 2-5 and 2-10). The lack of long-chain n-alkanes may be attributed to very low

maturity here: in this case, the long-chain hydrocarbons are not yet released from fatty

acids. The Sidi Salem Formation and Qawasim Formation have alternating shale and

sandstone lithologies with thicker shale intervals within the Sidi Salem Formation. This

might indicate short migration distances from source to reservoir within this section. A

gas show was reported in one of the sandstone intervals in the Sidi Salem Formation.

Microbial gas generation seems to be more probable than thermogenic gas generation in

view of the temperatures reached.

2.7 The Mesozoic and Miocene Source Rocks In the Nile Delta-An Overview

The current work reveals that the Jurassic and Cretaceous sections can encompass

potential gas-prone source rocks that extend to the north and to the west at deeper

settings (Abdel Aal et al. 2001; Barakat 2010) (e.g., Fig. 2-9b). In the far south, the Jurassic

source rock is expected to be coal bearing or terrestrial dominated, although little

geochemical or petrological data are available. Towards the north, shelf and delta

settings are expected with dominance of transported and more strongly degraded

terrestrial organic matter mixed with aquatic organic matter, which is strongly degraded

due to (partly) oxic depositional conditions. An example of this type is found in the Upper

Jurassic to Lower Cretaceous source rock section in the Abu Hammad-1 well. Further to

the north, better source rock qualities are anticipated similar to the prolific oil-prone

source rocks in the northern Western Desert and North Sinai basins. However, this needs

to be confirmed by drilling. Moreover, mixed oil and gas-prone source rocks were

53

reported in the Khatatba and Alam El Bueib formations with marginal to fair source rock

quality in the Sindy-1, Mit Ghamr-1, and Monaga-1 wells (Fig. 2-1; Hassaan et al. 2012).

Another important element is that the Oligocene basalt covers the southwestern part of

the Nile Delta Basin (Fig. 2-1), which could have influenced the thermal history of this

area and consequently the hydrocarbon generation if present in great thickness and near

source rock intervals. Additionally, the Upper Cretaceous includes key source rocks in

the region especially in the Western Desert Basin (El Diasty and Moldowan 2012; El Nady

et al. 2015). Thus, the Mesozoic could include one of the regional key petroleum source

rocks in the Nile Delta Basin and further investigation is highly recommended.

According to seismic interpretation adopted by Abdel Aal et al. (2001), the Cretaceous

succession in the offshore area can be deeper than 8000 m suggesting advanced thermal

maturity and hydrocarbon generation in relatively recent times (Fig. 2-10). The 1D basin

models suggest that the lithology, the sedimentation rates, and the amount of erosion are

key factors in controlling the basin’s thermal evolution especially since the heat flow

remained low perhaps with exception of regions with basaltic flows. Clearly, areas close

to major tectonic faults or fractures could attain higher thermal maturity than those

observed in this assessment. This would be related to hydrothermal fluids that can locally

affect temperature and maturation. The Oligocene was not investigated in this study, yet

it could contain a prolific gas-prone source both in the northeastern onshore and offshore

Nile Delta Basin (Hassaan et al. 2012). Villinski (2013) found potential source rocks in

Oligocene turbidite deposits that have disseminated terrestrial organic matter with

relatively fair quality (TOC 1–2% and HI of 150–300 mg HC/gTOC) in the offshore Nile

Delta Basin. This observation is somewhat similar to the source rock characteristics of

the Sidi Salem Formation (Fig. 2-3a).

TOC and HI of the Sidi Salem Formation have been mapped (Fig. 2-11) based on data from

this study and other published data. The Miocene source rocks in the Matariya-1 well are

of greater richness and quality compared to the Miocene source rocks evaluated in the

eastern Nile Delta Basin by Shaaban et al. (2006) but showed similar data compared to

54

Upper Miocene samples studied by Keshta et al. (2012) and El Nady (2007) in the central

parts of the basin. On the other hand, the Sidi Salem Formation shows excellent quality

towards the central and west-central Nile Delta Basin with HI exceeding 400 mg HC/g

TOC (El Nady 2007) as shown in Fig. 2-11.

Fig. 2-11 TOC and HI map of the Matariya-1 well and published data of the Sidi Salem Formation source rock. Published data sources: Abu Madi-1, Abu Madi-3, Abadiya-1, Kafer El Shiekh-1, Abu Madi-1, and Abu Madi-3 (El Nady 2007); Sidi Salem-1 (El Nady and Harb 2010); AbuMadi-9 well (Keshta et al. 2012); and S.W. Bilqas-1, Port said-1, Qantara-1, and Port Fouad-1 (Shaaban et al. 2006).

The Pr/Ph ratios of the Sidi Salem Formation in the Matariya-1 well were compared with

the published data in the region to better understand the depositional environment on a

regional scale. The Sidi Salem Formation in the Abu Madi-1 well, located in the

northeastern-central Nile Delta Basin, shows slightly lower Pr/Ph ratios ranging from 0.7

to 2.2 (El Nady and Harb 2010) indicating, on average, more reducing bottom-water

55

conditions. A higher sea level is also assumed and more marine and less terrestrial

organic matter. Figure 8 shows that the Sidi Salem Formation in the Matariya-1 well

differs with respect to Pr/n-C17 versus Ph/n-C18 values from the regional data, which

were collected from northern onshore and offshore areas (Fig. 2-1). This might also

indicate that the eastern Nile Delta contains a different, more terrestrial-influenced

source rock facies. The Sidi Salem Formation gains its importance as source rock due to

its thickness of several hundreds or even up to 1000 m and from being adjacent to

reservoir rocks.

2.8 Conclusions

In the Abu Hammad-1 well, the best source rock section is found in the Lower Cretaceous

Alam El Bueib Formation that is dominated by silicate lithology. It mainly contains

terrestrial and degraded marine organic matter having a significant gas generation

potential but probably almost no oil generation potential. The biomarker and elemental

data suggest a nearshore marine depositional environment with oxic bottom water.

The 1D burial and thermal history models reveal low source rock thermal maturity and

no significant thermal hydrocarbon generation. This is due to thin overburden and low

heat flows. In contrast, significant gas generation from the Mesozoic source rocks is

expected to occur in the northern Nile Delta Basin where they are deeply buried. Limited

previous work has been conducted on this interval, but the current study shows that the

Upper Jurassic and Lower Cretaceous can be an important source rock in the Nile Delta

Basin due to its great thickness and the association with reservoir intervals.

In the Matariya-1 well, the Middle Miocene Sidi Salem and lower part of the Lower

Miocene Qawasim Formation show moderate source rock quality. The source rock

interval is dominated by terrestrial organic matter indicating gas-prone kerogen. The

source rock is immature to very early mature with respect to oil generation. Burial and

thermal history models prove that the maximum temperatures were attained in the

Quaternary.

56

The Miocene data were evaluated in a regional context. The central Nile Delta Basin

appears to have better source rock quality compared to the eastern Nile Delta Basin

where the Matariya-1 well is located. This is perhaps due to shallower water conditions

in the eastern Nile Delta Basin during the Middle Miocene time. The Miocene source rock

interval is very thick and interbedded with sandstones, making it an interesting

petroleum play, e.g., for microbial gas.

57

An oil paint of a Microforaminiferal test lining found in a Cenomanian/Turonian sample, Abu Gharadig Basin, GPT-3, Egypt. Artist: Esrraa Abunar

58

Chapter 3 | Depositional Environment and Source Rock Potential of the Upper Cretaceous Succession, Abu Gharadig Basin, Northern Western Desert, Egypt: An Integrated Geochemical and Palynological Study

3.1 Abstract

The Abu Gharadig Basin in the north Western Desert, Egypt is among the most important

petroleum provinces in Egypt. Here, Cenomanian to Santonian rocks of Bahariya

Formation and Abu Roash A-G members from the GPT-3 well were investigated for their

depositional environment, kerogen quality, petroleum generation potential and thermal

maturity by geochemical, petrological and palynological methods. The sediments of the

Bahariya and Abu Roash formations excluding the Abu Roash "F" Member represent

variable shallow marine environments with poor organic matter preservation, whereas

there is an excellent preservation in the Abu Roash “F” Member. The basal part of this

member is characterized by anoxic, carbonate-rich depositional conditions, high TOC

values up to 7%, high HI up to 700 mgHC/gRock and liptinite dominated organic matters.

Depletion of iron leads to sulfur incorporation into organic matter which is reflected in

their high thiophene/Benzene ratio. Above, sediments are enriched in “terrestrial

elements” Fe, Si, Ti, as well as K and Mn. This pattern and the occurrence of the

fresh/brackish water algae Botryococcus suggests a regression phase during deposition.

The upper part of the Abu Roash "F" Member is again characterized by fully marine,

suboxic conditions and a lower thiophene/Benzene ratio. The source rock section

demonstrates lower thermal maturity compared to the above and below sections based

on all microscopic, pyrolysis and biomarker data. This indicates thermal maturity

retardation/suppression most likely due to liptinite enrichments as indicated by the

geochemical and palynological data. The source rock heterogeneity indicates relatively

shallow marine environment where the changes in bottom water conditions are very

sensitive to sea level fluctuations. Residual oil characterization reveals two reservoir

compartments, which are in the Abu Roash “D” and “C” members.

59

3.2 Introduction

Few attempts were carried out to investigate the depositional environment during the

Cenomanian/Turonian Boundary Event (CTBE) in the Western Desert basins using

integrated geochemical and palynological techniques (e.g. El Beialy et al., 2010; Zobaa et

al., 2011). Moreover, the source rock character and oil origin in the Cretaceous succession

is poorly understood, although several oil fields exist. The Abu Gharadig Basin is located

in the central part of the north Western Desert between the Qattara Depression to the

west, the Qattara High to the north and the Gindi and South Abu Gharadig basins to the

east and south, respectively (Fig. 3-1A). It is one of the oldest producing basins in the

Western Desert, which witnessed the first oil discovery in 1970 at the Khalda field (Awad,

1985; Younes, 2012). Moreover, the basin became more appealing after the recent oil

discovery in the Abu Roash “C” Member in the El Salmiya Field (Beach Energy, 2014). The

basin mainly produces oil and gas from Jurassic and Cretaceous plays (Awad, 1985). The

studied well is located in the GPT field that was discovered in 1983 and commenced

production in 1990 (Abdel-Rahman, 2013).

The proven source, reservoir and seal rocks found in the Abu Gharadig Basin are mainly

within the Jurassic and Cretaceous section (Awad, 1985; Bakr, 2009; El Diasty and

Moldowan 2012; Abdel-Rahman, 2013; El Nady and Harb, 2015; El Nady and El-Naggar,

2016). The Masajid and Khatatba formations are the most common Jurassic source rocks

which, represent mostly marine oil-prone facies with occasional non-marine facies

within the Khatatba Formation (Shalaby et al., 2012). Furthermore, potential marine

source rocks are found in the Lower Cretaceous Alam El Bueib Formation and mixed

marine and terrestrial source rocks within the Bahariya Formation. The best source rock

facies are in the “F” Member of the Abu Roash Formation that was deposited during the

Oceanic Anoxic Event 2 (OAE2; El Beialy et al., 2010; Zobaa et al., 2011), which is a global

phenomenon responsible for world class source rock deposits in several regions around

the world during the Cenomanian/Turonian boundary (Jenkyns, 2010). Other members

show variable source rock qualities within the basin.

60

Fig. 3-1 a) A location map of the studied GPT-3 well and the main sedimentary basins in the north Western Desert, Egypt. B) Paleogeographic map at ~94 Ma of North Egypt and the surrounding areas (modified after Phillip, 2003).

For example, oil-prone source rocks were reported at the base of the Khoman Formation

in different parts of the basin (Shahin et al., 1986). The best reservoir qualities were

encountered in the Bahariya and Abu Roash formations. The main reservoirs in the GPT

field produce gas from the Bahariya and Khoman formations as well as the “B” and “D”

members of the Abu Roash Formation (Abdel Rahman, 2013). Jurassic reservoirs are

poorly studied and understood, but it can be assumed that part of the Khatatba

Formation has good reservoir quality (Ahmed, 2008). The seals in Abu Gharadig Basin

61

are mainly shales and tight carbonates (El Ayouty, 1990). The source rocks for the oil and

gas are still debated and range from non-marine to marine, possibly due to the presence

of mixed sources (El Diasty and Moldowan 2012; El Nady and Harb, 2015; El Nady and

El-Naggar, 2016).

In summary, the Upper Cretaceous Bahariya and Abu Roash formations contain a

complete petroleum system in the basin. Using an integrated approach, the present study

intends to fill research gaps and provide new data on paleoenvironmental conditions and

source rock development during Cenomanian to Santonian times. In addition,

maturation, petroleum generation and the origin of the hydrocarbon accumulations in

the western Abu Gharadig Basin are discussed, based on new data and previous studies.

3.3 Geologic Setting

The Abu Gharadig Basin is a Mesozoic E-W trending elliptical extensional basin where

rifting started during the Upper Jurassic, contemporaneously with the opening of the

Neotethys and deep crustal extensional movements that affected North Egypt (Awad,

1984; Bayoumi and Lofty, 1989). The basin is structurally controlled by two E-W

bounding listric faults located at the southern and northern boundaries, which resulted

in subsidence during the Cretaceous with faster rates in the northern part. The slow

subsidence rate at the southern boundary resulted in an asymmetrical basin shape

(Awad, 1984; Bayoumi and Lotfy, 1989). The maximum subsidence and augmentation of

the basin was attained during the Turonian coeval with high global sea level (Bayoumi

and Lotfy, 1989; Haq et al., 1988). Nevertheless, the Abu Gharadig Basin acted as a

shallow marine to terrigenous shelf during this period (Philip, 2003; Fig. 3-1B). Some

areas remained subaerial such as the major part of the Qattara High that bounds the basin

from the north (Said, 1990; Fig. 3-1B). The extension then ceased due to a compressional

tectonic phase during the Upper Cretaceous, i.e. the Laramide phase during the Alpine

Orogeny and the Syrian Arc tectonic movements (Awad, 1984; Keely, 1994; Guiraud and

Bosworth, 1997; Kerdany and Cherif, 1999; Azab, 2014). This resulted in elevation along

the eastern boundary of the Abu Gharadig Basin (Kattaniya Inversion) that separated the

62

Abu Gharadig from the Faiyum Basin (Awad, 1984; Fig. 3-1A). Moreover, the

compressional stress was responsible for the basin tilting and NE-SW folding (Said,

1990). These asymmetric anticlines are plunging towards the NE and intersected by a

series of NW trending extensional faults (Azab, 2014).

The Bahariya Formation (Fig. 3-2) is early Cenomanian in age and witnessed

considerable changes in its depositional facies toward the younger section from fluvial to

estuarine to lagoonal sediments (Dominik, 1985). With respect to lithology, it varies from

cross-bedded coarse grained sandstone at the base to fossiliferous or sandy dolomite at

the top (Awad, 1984; Hantar, 1990). In the north Western Desert, the formation was

deposited in a nearshore inner shelf environment (Said 1990; Abdel Kireem et al., 1996).

Conversely in the south, the formation was deposited in fluvial to estuarine settings (Said,

1990). In the southern vicinity of the studied GPT-3 well (GPTSW-7 well, Fig. 3-1A), a

shallow marine to fluvio-deltaic setting is suggested (El Beialy et al., 2008). The formation

is dominated by terrestrial palynomorphs that can constitute up to 80 % of the bulk

kerogen (Abdel Kireem et al., 1996; El Beialy et al., 2008; El Atfy, 2011).

The overlying Abu Roash Formation (Fig. 3-2) consists of upper Cenomanian to Coniacian

deposits that rest conformably on the Bahariya Formation (Ahmed, 2008; El Beialy et al.,

2008). It represents periods of marine transgression/regression cycles and comprises

seven members, named “A” to “G” from top to bottom (Said, 1990). The Abu Roash “G”

Member is late Cenomanian in age and was deposited in a shallow marine setting (Abdel-

Kireem et al., 1996) that witnessed fresh water incursions (El Atfy et al., 2017). This

member shows for organic matter a positive δ13C isotope excursion towards the

overlying Abu Roash “F” Member (Zobaa et al., 2011). It constitutes interbedded

carbonate and clastic lithologies (Fig. 3-2). The Abu Roash “F” Member is upper

Cenomanian/lower Turonian in age deposited in a shallow marine setting (Abdel-Kireem

et al., 1996; El Beialy et al., 2010; Zobaa et al., 2011). It is composed mostly of carbonate

interbedded with shale (Abdel-Kireem et al., 1996; Hantar, 1990; El Beialy et al., 2010; El

Atfy, 2011). The basal part is characterized by a positive δ13C isotope excursion reflecting

the OAE2 phenomenon (Zobaa et al., 2011).

63

Fig. 3-2 Lithostratigraphic column of the GPT-3 well, north Western Desert, Egypt (after GPC, 1984). The associated biozones are after El Beialy et al. (2010).

64

The Abu Roash “E” to “B” members are Turonian in age but differ in lithology and

depositional environments. The regressive Abu Roash “E” is dominated by clastic

lithologies and can act as a reservoir (Ahmed, 2008). Previous palynological studies

reported the dominance of the fresh water green algae Pediastrum at the lowermost Abu

Roash “E” Member, which indicates sea level drop and increased influence of terrestrial

organic matter (e.g. Abdel-Kireem et al., 1996; Zobaa et al., 2011). The “D” and “B”

members were deposited in periods of sea transgression marked by carbonates unlike

the “C” Member characterized by clastic facies of a regressive habitat (Hantar, 1990;

Ahmed, 2008). The Abu Roash “A” Member was deposited during the Coniacian when

major sea transgression prevailed (Said, 1990; Ahmed 2008) in a shallow water, clastic

middle shelf environment (Abdel-Kireem et al., 1996).

3.4 Material and Methods

3.4.1 Samples

A total of 88 cuttings and 12 core samples from the Bahariya and Abu Roash formations

were collected from the GPT-3 well (Table 3-1). The well is located in the GPT field in the

southern Abu Gharadig Basin (28° 36’ 41.300” E, 29° 36’ 10.600” N) and reached a total

depth of 2295 m in the Kharita Formation. The investigated section ranges in depth from

1413 to 1986 m.

Table 3-1 Carbon, sulfur and Rock-Eval data of the Bahariya and Abu Roash formations, GPT-3 well, north

Western Desert, Egypt. * (mg HC/gRock), ** (mg CO2/gRock), *** (mgHC/gTOC), **** (mgCO2/gTOC).

Table 3-1 Continued (* (mg HC/gRock), ** (mg CO2/gRock), *** (mgHC/gTOC), **** (mgCO2/gTOC))

Sample No.

Sample type

Depth Rock Unit TOC CaCO3 TS S1 S2 S3 Tmax PI HI OI

(m) (%) (%) (%) * * ** °C *** ****

15/400 Cuttings 1413-1416 Abu Roash "A" 1.30 26.50 1.13 0.12 1.06 3.25 431 0.10 82 249

15/401 Cuttings 1422-1425 Abu Roash "A" 1.25 33.10 0.11 0.85 2.79 430 0.11 68 223






65


Sample No.

Sample type


(m) (%) (%) (%) * * ** °C *** ****









15/415 Cuttings 1548-1551 Abu Roash "B" 0.81 66.55 0.86 0.17 1.06 1.85 432 0.13 131 228

15/416 Cuttings 1557-1560 Abu Roash "B" 0.78 67.38 0.16 0.93 1.94 432 0.15

15/417 Cuttings 1566-1569 Abu Roash "B" 0.78 90.01 0.39 1.62 1.79 430 0.20 209 230








15/425 Cuttings 1638-1641 Abu Roash "C" 1.01 50.31 0.13 0.80 2.28 430 0.14 79 226

15/426 Cuttings 1647-1650 Abu Roash "C" 1.36 29.53 1.52 0.15 0.89 2.92 428 0.14 66 214

15/427 Cuttings 1656-1659 Abu Roash "C" 1.24 23.69 1.54 0.13 0.86 2.81 427 0.14 69 226

15/483 Core 1670 Abu Roash "C" 0.37 12.39 0.73 0.45 0.64 0.45 0.41

15/484 Core 1671 Abu Roash "C" 0.27 1.47 0.11 0.34 0.40 426 0.23 129 149


15/486 Core 1678 Abu Roash "C" 0.73 0.69 0.21 0.81 0.22 426 0.21 111 31


15/430 Cuttings 1701-1704 Abu Roash "D" 0.96 68.63 0.16 0.87 2.00 433 0.15 91 209

15/431 Cuttings 1710-1713 Abu Roash "D" 1.03 52.81 1.01 0.15 1.04 2.05 433 0.13 101 199







15/487 Core 1771 Abu Roash "D" 0.53 1.12 0.06 0.27 0.88 0.35 433 0.24 167 66

15/488 Core 1772 Abu Roash "D" 0.32 96.08 0.12 0.38 0.63 433 0.24 119 198

15/438 Cuttings 1773-1774 Abu Roash "D" 1.21 34.73 1.31 0.15 1.03 1.79 431 0.13 85 148

66


Sample No.

Sample type


(m) (%) (%) (%) * * ** °C *** ****

15/490 Core 1777 Abu Roash "D" 0.32 112.0

0 0.15 0.50 0.26 432 0.23 157 81

15/491 Core 1781 Abu Roash "D" 1.37 110.5

0 5.94 12.18 0.44 0.33 887 32


15/492 Core 1785 Abu Roash "D" 1.19 113.9

9 5.82 5.24 0.33 0.53 442 28

15/493 Core 1787 Abu Roash "D" 1.57 110.3

1 5.82 7.03 0.62 0.45 447 39



15/442 Cuttings 1821-1824 Abu Roash "E" 1.26 39.23 0.11 1.07 2.36 434 0.09 85 187

15/443 Cuttings 1830-1833 Abu Roash "E" 1.41 27.32 1.75 0.12 1.03 2.81 431 0.11 73 199

15/444 Cuttings 1839-1842 Abu Roash "E" 1.39 14.94 0.09 0.83 2.85 433 0.09



15/447 Cuttings 1866-1869 Abu Roash "E" 1.06 25.35 0.09 0.66 2.56 432 0.11




15/451 Cuttings 1911-1914 Abu Roash "E" 1.40 11.35 1.34 0.11 0.82 2.90 428 0.12






15/455 Cuttings 1965-1968 Abu Roash "F" 1.79 30.66 1.26 0.21 2.83 2.27 430 0.07 158 127

15/495 Core 1974 Abu Roash "F" 4.00 100.8

7 0.27 2.43 26.21 1.53 424 0.08 655 38


15/496 Core 1976 Abu Roash "F" 0.32 2.22 0.54 0.10 0.40 0.34 425 127 109

15/497 Core 1977 Abu Roash "F" 0.18 55.87 0.32 0.08 0.33 3.40 166

15/498 Core 1978 Abu Roash "F" 5.87 91.80 1.69 3.11 40.33 1.48 423 0.07 687 25

15/499 Core 1979 Abu Roash "F" 4.37 102.8

2 0.40 2.41 27.13 1.98 421 0.08 621 45


15/458 Cuttings 1995-1998 Abu Roash "G" 1.91 27.00 1.62 0.15 2.25 2.56 428 0.06 118 134


15/460 Cuttings 2015-2018 Abu Roash "G" 1.23 8.20 0.12 0.82 1.89 429 0.13 66 154


67


Sample No.

Sample type


(m) (%) (%) (%) * * ** °C *** ****











15/472 Cuttings 2142-2145 Baharyia 1.63 15.42 0.25 1.38 2.94 431 0.15 85 180

15/473 Cuttings 2151-2154 Baharyia 1.65 9.86 1.12 0.19 1.32 3.14 431 0.13 80 190



15/476 Cuttings 2187-2190 Baharyia 1.18 6.17 0.08 0.89 1.56 436 0.08

15/477 Cuttings 2196-2199 Baharyia 1.95 1.56 0.95 0.23 1.84 2.20 435 0.11




15/481 Cuttings 2232-2235 Baharyia 1.54 10.42 0.11 1.02 2.30 434 0.10

15/482 Cuttings 2235-2238 Baharyia 1.42 35.27 1.18 0.14 0.99 1.72 434 0.12


All samples were assessed for their organic (TOC) and inorganic carbon (TIC) using a

LiquiTOC II (Elementar Analysengeräte GmbH). The method burns the samples in the

presence of oxygen. TOC is recorded at temperatures up to 550 °C and TIC at higher

temperatures up to 1050 °C. CaCO3 in weight percent was calculated utilizing the

equation: CaCO3=TIC*8.333. Note that this calculation could lead to overestimation of

CaCO3 contents (by up to 8%) if dolomite is present instead of calcite which; occurs in

some of the Abu Roash members. One sample (15/497) containing a significant amount

of siderite was treated with hydrochloric acid before analysis. This is because siderite

68

decomposes at lower temperatures than other common carbonate minerals which can

lead to wrong, elevated TOC values.

A total of 42 samples were measured for total sulfur content (TS) using a LECO S200

sulfur analyzer (precision is <5% and detection limit 0.001%). Ten samples were

analyzed for their major elemental composition using energy dispersive x-ray

fluorescence spectrometry (Spectro XLab2000). The analytical technique is described in

Ghassal et al. (2016). The elements Si, Fe, Ti, K, P, Cr were normalized to Al, whereas Mg

and Mn were normalized to Ca and S, respectively.


All samples were measured using a Rock-Eval 6 Pyrolyzer. The analytical and

interpretation methods are described in Espitalié et al. (1985) and Peters (1986). For

each sample, an aliquot of 100 mg of pulverized rock was used. In the absence of oxygen,

the samples are heated first to 300°C (held for 3 minutes) and then to 650°C at a heating

rate of 25°C/minute. Released hydrocarbons are detected and quantified at a flame

ionization detector (FID). The first peak (S1, 300 °C) represents the thermovaporized

hydrocarbons whereas the second peak (S2) represents the thermally cracked

hydrocarbons. During the pyrolysis part of the released gas is trapped and later released.

On this gas, carbon dioxide is quantified at an infrared detector (S3). The S1 and S2 peaks

are recorded as mg HC/g rock and the S3 peak as mg CO2/gRock. The temperature at

which the highest S2 yield is reached is called Tmax (temperature of maximum pyrolysis

yield). Other useful parameters are calculated from these parameters. The Hydrogen

Index (HI) is S2/TOC and has the unit of mgHC/gTOC. Conformably Oxygen Index (OI) is

S3/TOC and has the unit of mgCO2/gTOC. Production Index (PI) is S1/(S1+S2). All

pyrograms were carefully checked for contamination and appeared to be clean.

3.4.4 Organic petrology

Four core samples from the Abu Roash “F” Member were examined for vitrinite

reflectance and maceral composition following standard procedures (Taylor et al., 1998).

69

The preparation technique and microscopic equipment used are described in detail in

Sachse et al. (2012).

3.4.5 Molecular organic geochemistry

Solvent extractions of 14 samples were conducted using DIONEX ASE 150 (Thermo

Scientific). The samples were extracted by dichloromethane (DCM). Afterwards, each

extract was fractionated into 6 fractions following the method described by

Schwarzbauer et al. (2000). The fractions roughly represent aliphatic, monoaromatic,

diaromatic, polyaromatic hydrocarbons as well as semi-polars and polar organic

molecules.

A total of 14 aliphatic fractions were analyzed by gas chromatography using a Fisons

Instruments GC 8000 series equipped with a flame ionization detector and with a Zebron

ZB-1 HT Inferno fused silica column (30 m x 0.25 mm i.d.; film thickness 0.25 µm,

Phenomenex®). Each sample was diluted in 50-100 ml of DCM before injection. Only 1 µl

of this solution was injected into a splitless injector at 270 °C and with a splitless time of

60 s. Helium was used as a carrier gas with a gas velocity of 35 cm/s. The temperature

program started at 80 °C, held for 3 minutes; then the temperature increased at a rate of

10 °C/minute to reach 300 °C remaining constant for 20 minutes. The samples were then

analyzed on a Finnigan MAT 95 mass spectrometer connected to a Hewlett Packard

Series II 5890 GC, which was equipped with a similar GC column and carrier gas with a

velocity of 33 cm/s. The GC run started at 80 °C, held for 3 minutes; then the temperature

increased to 310 °C at a rate of 5 °C/minute. The spectrometer was operated in electron

ionization (EI*) mode with an ionization energy of 70 eV and a source temperature of 200

°C. The scanning range was from m/z 35 to 700 in low resolution mode.

3.4.6 Curie Point Pyrolysis-Gas Chromatography-Mass Spectrometry

Six samples from the Abu Roash “F” Member were measured by Curie Point Pyrolysis Gas

Chromatography Mass Spectrometry (CPPyGCMS). An aliquot of approximately 3-10 mg

of powdered rock was collected in hand-made metal crucibles with a Curie Point

temperature of 650 °C. The crucible is inserted in a glass inlet, which is then placed in a

70

CP pyrolyzer (Fischer GSG CPP 1040 PSC) and pyrolyzed at 650 °C for 10s. The pyrolyzer

was coupled to a GC-MS system (Fisons GC 8000; Thermoquest MD 800). It was equipped

with a 30 m non-polar GC capillary column (Zebron ZB-5, 0.25 mm I.D., 0.25 µm film

thickness). The pyrolysis products were trapped behind the injector using a

cryofocussing trap (−70 °C) prior to GC-MS analysis. The GC-MS analyses were conducted

using He as a carrier gas with a velocity of 35 cm/s. The oven temperature started at 40

°C, held for 3 minutes and then increased at a rate of 3 °C/minute to reach 310 °C to be

held for 20 minutes. Molecular masses were scanned from m/z 35 to 550.

3.4.7 Molecular geochemical parameters

All biomarker ratios were calculated on the base of peak area integration above baseline

of specific ion chromatograms. Chromatograms of m/z 57 were used for alkanes, 191 for

hopane compounds and 217 for steranes. The studied homologue groups were validated

by their specific molecular ions whereas individual isomers were recognized by their

elution order compared to published data (e.g. Peters et al., 2005).

The calculated biomarker ratio were:

1) pristane/phytane ratio (Pr/Ph),

2) pristane/n-C17 and phytane/n-C18 ratios,

3) Terrestrial to Aquatic ratio (TAR) = n-C27+ n-C29+ n-C31/ n-C15+ n-C17+ n-C18,

4) 22,29,30-trisnorneohopane (Ts)/ 22,29,30-trisnorhopane (Tm), i.e. (Ts/Tm),

5) 17a(H),21b(H)-30-norhopane/ 17a(H),21b(H)-hopane, i.e. C29/C30 Hop,

6) 17a(H),21b(H)-29-homohopane (22R)/ 17a(H),21b(H)-hopane, i.e. C31R/C30Hop,

7) C29 ββ/(αα+ββ) steranes,

8) C29 ααα20S/(20S+20R) steranes and

71

9) total steranes/total hopanes (str/hop) ratios.

As a proxy for the organic sulfur content, the thiophene/benzene ratio was calculated

from CPPyGCMS results. The thiophene derivatives selected in the equation are:

methylthiophenes (2 isomers, m/z 98), dimethylthiophenes (4 isomers, m/z 112) and

trimethylthiophenes (3 isomers, m/z 126). The benzene derivatives utilized in the

equation consisted of: toluene (m/z 92), xylenes (3 isomers, m/z 106) and

trimethylbenzenes (2 isomers, m/z 120). The ratio was first introduced by Ghassal et al.

(2016).

3.4.8 Palynology and palynofacies

Ten core and 10 cutting samples were investigated palynologically from the Bahariya

Formation (3 cutting samples), Abu Roash “G” (1 cutting sample), Abu Roash “F” (3 core

and 1 cutting samples), Abu Roash “E” (2 cutting samples), Abu Roash “D” (3 core

samples), Abu Roash “C” (4 core samples) and Abu Roash “A” (3 cutting samples). An

aliquot of approximately 15–20 g of each sample was prepared for the analysis following

the standard extraction techniques including HCl–HF treatment (e.g. El Atfy et al., 2014).

3.5 Results


The Bahariya Formation shows a low fluctuation in TOC with an average of 1.4 %. It has

low CaCO3 contents not exceeding 10% except for the bottom sample (Fig. 3-3) and is

characterized by a moderate TS average of 1.2 %. The Abu Roash “G” Member nearly

shares the same TOC and TS values, but has partly higher CaCO3 contents that range from

3 to 30 % (Table 3-1; Fig.3-3). The overlying Abu Roash “F” Member is most enriched in

TOC among the studied units with an average value of 3.7 %. It reveals a significant

oscillation in CaCO3 contents that range from 1 to almost 100 %. The samples show TS

average values of 0.8 % with high variability (Fig. 3-3). The XRF analyses cover the Abu

Roash “F” Member and the contacts to the adjacent members (Table 3-2; Fig. 3-4). The

Si/Al, Fe/Al, Ti/Al, K/Al, P/Al and Mg/Ca values are low to moderate at the base of the

72

Abu Roash “F” interval. In particular Si/Al, K/Al and Mg/Ca increase above (regressional

phase in Fig. 3-4) then decreasing above to moderate values.

The Si/Al ratio points to a variation of the silicate (clay, feldspar) to quartz ratio. On the

other hand, K/Al ratio is used to indicate clay mineral composition (Weaver, 1989;

Niebuhr, 2005) where high values denote illite enrichment and consequently an arid and

warm climate and low values indicate kaolinite/smectite assemblages related to a

humid/semi-arid warm climate (Aquit et al., 2016, Niebuhr, 2005). Here, absence of

feldspar minerals are assumed due to the expected negligible contents compared to clay

minerals in the evaluated marine marlstone/shale. However, this can be determined using X-

Ray diffraction or petrographic microscopy methods which have not been conducted in this

study due to the limited sample amount and the small grain size.

Fig. 3-3 Total organic carbon (TOC), CaCO3, Total sulfur (TS) and Rock-Eval data versus depth, Bahariya and Abu Roash formations, GPT-3 well, north Western Desert, Egypt. The Abu Roash “F” source rocks are classified as Transgression phases I and II. * CaCO3 is calculated from total inorganic carbon.

0 1 2 3 4 5 6

TOC (%)

0 1 2 3

TS (%)

0 50 100

CaCO3 (%)*

0 400 800

HI (mgHC/gTOC)

420 430 440

T-max (°C)

0.0 0.5 1.0

PI

1400

1600

1800

2000

2200

Dep

th (

m)

Phase

Reservoir

Transgression phase-II

Regression phase

Transgression phase-I

Rock Unit

Abu Roash "A"

Abu Roash "B"

Abu Roash "C"

Abu Roash "D"

Abu Roash "E"

Abu Roash "F"

Abu Roash "G"

Baharyia

73

Fig. 3-4 XRF elemental data of the Abu Roash “F” Member, GPT-3 well, north Western Desert, Egypt.

74

Table 3-2 Elemental data of selected samples using XRF analysis from the Abu Roash “F”, “E” and “G” members, GPT-3 well, north Western Desert, Egypt.

Sample No. Formation Depositional Phase Si/Al Fe/Al Ti/Al K/Al P/Al Cr/Al Mg/Ca Mn/S

14/1344 Abu Roash "E" 2.34 0.60 0.06 0.10 0.01 0.001 0.13 0.07

15/455 Abu Roash "F" Transgression phase-II 2.52 0.54 0.06 0.14 0.02 0.001 0.04 0.07



15/496 Abu Roash "F" Regression phase 3.08 0.44 0.18 0.11 0.06 0.002 0.26 0.37

15/497 Abu Roash "F" Regression phase 2.19 7.89 0.08 0.08 0.05 0.002 0.87 19.46

15/498 Abu Roash "F" Transgression phase-I 1.23 0.97 0.01 0.00 0.03 0.002 0.00 0.01

15/499 Abu Roash "F" Transgression phase-I 0.56 0.08 0.00 0.00 0.05 0.001 0.00 0.71

15/459 Abu Roash "G" 2.83 0.66 0.06 0.11 0.02 0.002 0.12 0.15

15/460 Abu Roash "G" 2.72 0.52 0.06 0.11 0.01 0.001 0.13 0.04

The K/Al ratio is plotted against Si/Al ratio and CaCO3 (Fig. 3-5). The samples from the

Abu Roash F-G members show generally low K/Al ratio (<0.15) yet two groups were

identified. The first group is rich in CaCO3 and poor in K/Al and Si/Al and the second

group is moderate to poor in CaCO3 and shows higher K/Al and Si/Al ratios.

Figure 3-6 is a ternary diagram of SiO2-Al2O3-CaO utilized to determine shale/marlstone

composition presuming that shale is composed predominantly of quartz, clay minerals

and carbonate (Brumsack, 1988). To separate the data points in the plot, the CaO and

Al2O3 values were multiplied by factors of 2 and 5, respectively. The samples generally

follow the average marine shale trend (Wedepol, 1970) with variable carbonate contents

except for few samples.

The Fe-TOC-TS ternary diagram (Fig. 3-7) is used to interpret the depositional

environment conditions. Samples that plot along the pyrite line (TS/Fe =1.5) indicate that

almost all S is fixed in pyrite. Samples plotting below the line indicate the presence of

other forms of sulfur (e.g. organic sulfur) and samples that plot above the line indicate Fe

bearing minerals in addition to pyrite (Dean and Arthur, 1989). Samples from the basal

part of the Abu Roash “F” plot along the pyrite line unlike the other samples that show

lower TS/Fe ratios.

75

Fig. 3-5 K/Al ratio versus (a) Si/Al ratio and (b) CaCO3 of selected samples from the Abu Roash “E”, “F” and “G” members, GPT-3 well, north Western Desert, Egypt showing possible depositional environment, climate and clay mineral composition.

Fig. 3-6 SiO2-5*Al2O3-2*Ca ternary diagram demonstrating lithological differences among the Abu Roash “E”, “F” and “G” samples, GPT-3 well, north Western Desert, Egypt.

TOC values in the Abu Roash “E” – “A” members are moderate except for a few samples

at the bottom of the “D” Member, which are oil-stained cores (Table 3-1). The TS average

values increase again in the Abu Roash “E” (1.3 %) and similarly in the Abu Roash “C” (1.3

%) and “A” (1.2 %) members while being lower in the Abu Roash “D” (0.8 %) and “B” (0.7

%) members (Table 3-1, Fig. 3-3).

76

Fig. 3-7 Total organic carbon-iron-total sulfur ternary diagram of selected samples from Abu Roash “G”, “F” and “E” members, GPT-3 well, north Western Desert, Egypt.

The carbonate content shows significant fluctuation between almost 0 and almost 100

%, which are most probably related to palaeoenvironmental conditions, i.e. climate

and/or transgressional/regressional cycles with carbonate-rich Abu Roash “D” and “B”

members possibly representing sea level highstands and warm climate.

Interestingly, the Abu Roash “F” Member shows a positive relation between TOC and

carbonate, whereas all other units display generally a decrease in TOC with increasing

carbonate content (Fig. 3-8). Similarly, the Abu Roash “F” Member shows a different

trend as compared to the other rock units with respect to the TS versus TOC relationship

(Fig.3-9).


The Abu Roash “F” Member shows the highest S1 and S2 values ranging from 0.08 to 3.11

mgHC/gRock and 0.33 to 40.33 mgHC/gRock, respectively (Table 3-1). This member also

shows high though variable HI values that reach 687 mgHC/gTOC and OI ranges from 25

to 127 mgCO2/gTOC (Fig. 3-10).

77

Fig. 3-8 CaCO3 versus total organic carbon (TOC), GPT-3 well, showing two distinctive trends. The samples of Abu Roash “F” have a positive trend, whereas samples from other rock units denote a weak negative relation.

Fig. 3-9 Total sulfur (TS) versus total organic carbon (TOC) showing the difference between the Abu Roash “F” Member and other studied rock units. The samples are classified into three groups which are 1) Abu Roash “F” Member Transgression-1:, 2) Abu Roash “F” Member Transgression-2: and 3) oxic/suboxic shelf: the samples from the rest of the geological units. Value%: CaCO3 calculated from total inorganic carbon.

78

The Tmax is relatively low and averages 424 °C (Fig. 3-3). This data is indicative of a high

quality petroleum source rock at low thermal maturity level. The quality is much lower

in the other rock units (Fig. 3-10). PI was used to distinguish between reservoir and non-

reservoir samples. Three oil-stained core samples in the Abu Roash “D” Member show PI

values higher than 0.30 (Fig. 3-3), and also other parts of the Abu Roash B-D sequence

show abnormally high PI values (in view of the low thermal maturity) indicating oil

staining. Pyrograms of oil-stained samples (Fig. 3-11) indicate that part of the S2 peak in

these samples is also due to oil staining.

Fig. 3-10 Pseudo van Krevelen diagram of the studied rock units, GPT-3 well, north Western Desert, Egypt. Note that the high HI readings from the Abu Roash “D” samples are from a reservoir section.

79

Fig. 3-11 Rock-Eval pyrograms and gas chromatograms of the Abu Roash “C” and “D” reservoirs as well as Abu Roash “F” source rock sections, GPT-3 well, north Western Desert, Egypt.


Vitrinite reflectance was measured on three core samples from the Abu Roash “F”

Member; one additional sample contained no vitrinite. The samples show values between

0.42- 0.43% within the depth interval from 1974 to 1979 m (Fig. 3-12). The vitrinite

80

particles are rare and small in size. Under fluorescent light the samples show a

dominance of liptinite in two different forms: Liptodetrinite (granular, often with a

diameter <5 µm) and lamalginite (elongated, often with a diameter >5 µm) with virtual

absence of telalginite (well preserved large algal particles; Taylor et al., 1998; Fig. 3-9).

Furthermore, they show strong yellowish fluorescent background implying presence of

submicroscopic organic matter within the mineral ground mass. The samples also

contain larger foraminifera (~25 µm) in fair abundance. One additional sample

representing a siderite layer (15/497) shows no organic matter (Fig. 3-12).

Fig. 3-12 Organic petrography of the Abu

Rash “F” samples under fluorescent light,

GPT-3 well, north Western Desert, Egypt.

81

3.5.4 Molecular organic geochemistry

The majority of the analyzed samples range in Pr/Ph ratio from 0.8 to 1.1 with few

exceptions (Table 3-3). Representative chromatograms of reservoir and source rock

sections are shown in Fig. 3-11. The Bahariya Formation sample shows a bi-modal n-

alkane distribution whereas the Abu Roash “G” sample shows abundant n-C15 to n-C20

alkanes with fair presence of long-chain n-alkanes up to n-C33. The Abu Roash “F” and “E”

samples show a similar distribution. From the Abu Roash “D” Member three oil-stained

cores and one cutting sample were investigated. The three core samples are believed to

be from a reservoir section as they have high PI values based on Rock-Eval analysis

(Table 1, Fig. 3-3). These samples show low concentrations of n-alkanes < n-C21 with a

gradual increase in long-chained n-alkanes abundance towards the deeper samples. The

cutting sample (sample no. 15/431; depth 1710 m) shows a different distribution with

the most abundant alkanes found between n-C14 and n-C24. One Abu Roash “C” sample

was retrieved from a reservoir section showing a bi-modal n-alkane distribution with

high concentration of long-chain n-alkanes. The second sample is believed to originate

from a non-reservoir section illustrating predominance of n-C16 to n-C20 with fair

presence of long-chained n-alkanes up to n-C30. The Abu Roash “B” and “A” samples show

a predominance of short-chain n-alkanes between n-C16 and n-C20.

The Terrestrial to Aquatic Ratio (TAR) discriminates the Abu Rash “F” Member from the

other samples that show higher values. Similarly, the Abu Rosh “F” samples have a higher

str/hop ratio as compared to the low values of samples from the other members (Fig. 3-

13).

Generally, all samples demonstrate similar C27, C28 and C29 sterane compositions with the

exception of the two samples from the Abu Roash “D” Member and Bahariya Formation.

Both show slightly higher abundance of C27 steranes (Fig. 3-14). Samples from the Abu

Roash “F” Member show low C29 ββ/(αα+ββ) steranes ratios compared to the other rock

units that range from 0.24 to 0.28, whereas the oil-stained core samples from the Abu

Roash “D” Member show the highest values from 0.54 to 0.55.

82

A similar trend is observed for the C29 ααα20S/(20S+20R) steranes ratio with the

exception of the Abu Roash “C” sample that shows a high value (Fig.3-15). The Ts/Tm

ratio varies strongly between 0.24 and 2.16. The Bahariya and Abu Roash “F” source rock

members show lowest values. The C31R/C30 Hop ratio decreases slightly towards the

younger section but the values are always above 0.25 (Table 3-3). The biomarker

maturity parameters support the information derived from the Tmax values that denote

lower values for the Abu Roash “F” samples than the other rock units (Fig.3-3).

Fig. 3-13 a) Total organic carbon (TOC) versus terrestrial to aquatic ratio (TAR). b) Pristane/phytane ratio versus steranes/hopanes ratio (str/hop), GPT-3 well, north Western Desert, Egypt.

83

Table 3-3 Biomarker data of selected samples from the Bahariya and Abu Roash formations, GPT-3 well, north Western Desert, Egypt.

Sample Formation Sample Type Pr/Ph Pr/C17 Ph/C18 TAR Ts/Tm C29/C30 Hop C31R/C30Hop str/hop

15/400 Abu Roash "A" Source Rock 1.10 0.61 0.82 0.15 1.37 0.80 0.40 0.32

15/418 Abu Roash "B" Source Rock 0.98 2.09 1.83 1.29 0.71 0.31 0.33

15/426 Abu Roash "C" Source Rock 0.70 0.71 1.04 0.11 1.73 0.92 0.45 0.22

15/483 Abu Roash "C" Reservoir 1.37 1.66 1.40 0.51 0.76 0.34 0.32

15/431 Abu Roash "D" Source Rock 1.00 1.34 1.26 0.25 0.64 1.05 0.47 0.25

15/491 Abu Roash "D" Reservoir 0.89 1.60 1.78 0.80 1.05 0.26 0.42



15/445 Abu Roash "E" Source Rock 1.41 1.32 1.50 0.32 0.24 0.86 0.33 0.17

15/495 Abu Roash "F" Source Rock 1.24 1.72 1.38 0.01 0.27 0.96 0.39 0.72



15/462 Abu Roash "G" Source Rock 1.28 1.37 1.48 0.23 2.16 1.13 0.39 0.20

15/480 Baharyia Source Rock 1.79 1.24 1.07 0.14 0.33 1.34 0.29 0.16

84

Fig. 3-14 C27, C28 and C29 steranes ternary diagram of selected samples from the Bahariya and Abu Roash formations, GPT-3 well, north Western Desert, Egypt.

Fig. 3-15 C29 ββ/(αα+ββ) steranes versus C29 ααα20S/(20S+20R) steranes indicating maturity in the studied rock units, GPT-3 well, north Western Desert, Egypt. Please refer to Table 4 for sample assignment.

0

10

20

30

40

50

60

70

80

90

100

C28

ste

ran

es (%

)

0102030405060708090100

C27 steranes (%)

0

10

20

30

40

50

60

70

80

90

100

C29 steran

es (%)

Plankton and algae

Open Marine

Shallow marine or coastal

Deltaic-terrigenous

Tertiary coals

Uncommon

Geological Unites

Abu Roash "A"

Abu Roash "B"

Abu Roash "C"

Abu Roash "D"

Abu Roash "E"

Abu Roash "F"

Abu Roash "G"

Baharyia

85

3.5.5 CPPyGCMS

The samples from the basal Abu Roash “F” Member are characterized by a high

concentration of thiophene and light n-alkane compounds. Conversely, the upper

samples are enriched in n-alkane and benzene compounds and relatively poor in

thiophenes (Fig. 3-16). The thiophene/benzene ratio is highly variable within the Abu

Roash “F” source rocks (Table 3-4). Values are quite high at the base (transgression phase

I) and much lower in the samples above, indicating the presence of more organic sulfur

in the deeper and older samples of this member (Fig. 3-17). These samples are also

characterized by high carbonate contents (Table 3-1).

Fig. 3-16 Curie-Point-Pyrolysis Gas Chromatography-Mass Spectrometry Chromatograms of representative samples from the Abu Roash “F” Member indicating a high organic sulfur contents in transgression phase-I, Abu Rash “F” Member, GPT-3 well, north Western Desert, Egypt.

86

Fig. 3-17 Ali-Be-T ternary diagram (alaphitic- hydrocarbonsn-C6 to n-C14-Benzenes-Thiophenes) based on Curie-Point-Pyrolysis-Gas-chromatography-mass-spectrometer data of selected samples from the Abu Roash “F” source rocks, GPT-3 well, north Western Desert, Egypt.

Table 3-4 Curie Point Pyrolysis Gas chromatography mass spectrometry data of selected samples from The Abu Roash “F” Member, GPT-3 well, north Western Desert, Egypt.

Sample Deposional Phase Depth Thiophenes/Benzenes Thiophenes Benzenes n-C6 to n-C14

(m) (%) (%) (%)

15/455 Transgression phase-II 1965 14.14 24.51 61.34

15/496 Regression phase 1975 0.17 12.52 27.63 59.85

15/497 Regression phase 1977 0.02

15/498 Transgression phase-I 1978 3.58 48.55 5.47 45.98



87

3.5.6 Palynology and palynofacies analysis

The distribution of palynofacies particles is summarized in Table 3-5 and Figure 3-18.

The Bahariya Formation palynomorphs are mostly terrestrial except for a minor marine

contribution of dinocysts and microforaminiferal linings. The recorded pollen and spore

taxa include Classopollis brasiliensis, Integritetradites porosus, Cretacaeiporites

densimurus, Afropollis jardinus, Afropollis kahramanensis, Crybelosporites pannuceus and

Ephedripites spp. and a single record of the megaspore Ariadnaesporites. Marine

palynomorphs include dinocysts such as Subtilisphaera spp., Florentinia spp.,

Clesitosphaeridium spp., Circulodinium distinctum, Cribroperidinium sp., Dinopterygium

cladoides and Cribroperidinium spp. in addition to microforaminiferal linings. Freshwater

algae are represented by Pediastrum and Botryococcus. A single specimen of scolecodonts

in sample 15/474 was recorded.

Table 3-5 Palynofacies data of selected samples from the Bahariya and Abu Roash formations. AOM: amorphous organic matter.

Sample No.

Rock Unit Depth (m) AOM (%) Phytoclasts (%) Palynomorphs (%)

15/400 Abu Roash "A" 1413 60 30 10

15/409 Abu Roash "A" 1494 95 4 1

15/413 Abu Roash "A" 1530 94 5 1

15/483 Abu Roash "C" 1670 33 77 0

15/484 Abu Roash "C" 1671 30 78 2

15/428 Abu Roash "C" 1672 31 77 2

15/486 Abu Roash "C" 1675 0 90 10

15/487 Abu Roash "D" 1771 8 85 7

15/488 Abu Roash "D" 1772 80 5 15

15/489 Abu Roash "D" 1776 20 75 5

15/443 Abu Roash "E" 1830 45 40 5

15/446 Abu Roash "E" 1956 88 9 3

15/495 Abu Roash "F" 1973 30 60 10

15/496 Abu Roash "F" 1976 5 85 10

15/497 Abu Roash "F" 1977 0 80 20

15/457 Abu Roash "F" 1983 94 4 2

15/465 Abu Roash "G" 2089 0 90 10

15/472 Bahariya 2142 60 45 5

15/474 Bahariya 2169 80 18 2

15/482 Bahariya 2232 79 19 2

88

The Abu Roash “G” Member was palynologically investigated in one sample. Phytoclasts

are mainly lath-shaped woods, tracheids and cuticles. Similar to the Bahariya Formation,

palynomorphs are mostly terrestrial except for a minor marine contribution. The

recorded taxa are dominated by Afropollis and some trilete spores such as Crybelosporites

pannuceus and Cicatricosisporites spp. In addition, taxa like Afropollis jardinus, Afropollis

kahramanensis, Retimonocolpites variplicatus, Retimonocolpites spp., Dichastopollenites

dunveganensis, Monocolpopollenites spp., Inaperturopollenites spp., Ephedripites spp. and

a single record of the megaspore Ariadnaesporites are reported.

Fig. 3-18 APP ternary plot (Tyson, 1993) of selected samples from the Bahariya and Abu Roash formations, GPT-3 well, north Western Desert, Egypt.

The Abu Roash “F” Member was studied palynologically based on 4 samples (Table 3-5).

The sample from the basal part (transgression phase-I) is dominated by amorphous

organic matter (AOM) that is fine granular, yellow to gray marine amorphous masses,

89

presumably of algal or cyanobacterial origin. Phytoclasts are mostly opaques from the

middle part (regression phase-I) with some visible cuticles, wood and tracheid particles.

Palynomorphs are the most diversified group and contain mainly marine elements

diluted in some intervals with non-marine counterparts. Palynomorphs retrieved from

basal part (15/457) are composed exclusively of smooth, baggy-form leiospherids. On

the other hand, the siderite rich sample (15/497) contains miscellaneous palynomorphs

such as microforaminiferal linings, fungal palynomorphs and Cholorophyceaen algae

including Pediastrum and Botryococcus, in addition to Reyrea polymorpha (Incertae

sedis). Spore taxa are represented mainly by trilete spores such as Crybelosporites

pannuceus. Gymnosperm pollens include Araucariacites australis, Inaperturopollenites

spp., Ephedripites jansonii, Ephedripites spp. and Eucommiidites troedsonii. Angiosperms

comprise Droseridites senonicus, Afropollis spp. Foveotricolpites giganteus,

Foveotricolpites gigantoreticulatus, Tetracolpites sp., Tricolpites spp., Proteacidites sp. and

Cretacaeiporites polygonalis. Marine palynomorphs are Michrystridium (acritarchs) and

dinocysts Coronifera albertii, Florentinia spp., Spiniferites ramosus multibrevis,

Spiniferites spp. and some other unidentified forms. The overlying sample (15/496)

contains rare non-marine palynomorphs (trilete spores, gymnosperms such as

Ephedripites spp. and Eucommiidites troedsonii and some angiosperms). Marine elements

are microforaminiferal linings, acritarchs (Michrystridium) and dinocysts assigned to

Circulodinium distinctum, Coronifera albertii, Spiniferites ramosus multibrevis, Spiniferites

spp. and Cribroperidinium spp. In addition, Botryococcus has been also recorded. Finally,

sample 15/495 contains minor non-marine palynomorphs (trilete spores and

Ephedripites spp.). Marine elements are microforaminiferal linings and dinocysts

assigned to Oligosphaeridium pulcherrimum, Spiniferites ramosus multibrevis, Spiniferites

spp., Coronifera albertii, Cribroperidinium spp. and Florentinia spp.

The Abu Roash “E” Member phytoclasts are mainly lath-shaped woods, tracheids and

cuticles. Palynomorphs are mostly terrestrial except for a minor marine dinocysts

contribution. The recorded non-marine taxa are Ephedripites ambiguus, Ephedripites

http://fossilworks.org/bridge.pl?a=taxonInfo&taxon_no=322101

http://dinoflaj.smu.ca/wiki/Florentinia_abjuncta

http://fossilworks.org/bridge.pl?a=taxonInfo&taxon_no=322101

http://dinoflaj.smu.ca/wiki/Florentinia_abjuncta

90

spp., Eucommiidites spp., Retimonocolpites spp. and Dichastopollenites ghazalatensis, in

addition to Botryococcus.

The Abu Roash “D” Member phytoclasts are mainly biodegraded and comprise cuticles,

woods including tracheids. The AOM including resin are sheet-like and of pale gray color

and strongly invaded by pyrite. Palynomorphs are mostly marine except for sample

15/487, which contains some trilete spores (as Leptolepidites psarosus), Araucariacites

australis, Ephedripites spp., Afropollis, triporate pollen and Reyrea polymorpha in addition

to some fungal palynomorphs. Marine elements include mainly microforaminiferal

linings and dinocyst taxa assigned to Cribroperidinium edwardsii, Cribroperidinium spp.,

Trichodinium castanea and Cleistosphaerdium spp.

On the other hand, the Abu Roash “C” Member phytoclasts are composed of cuticles,

woods including tracheids, which are predominantly brown and jellified; some of them

are charred and thus opaque. Sample 15/486 is rich in palynomorphs and contains a

diverse group of taxa. These taxa are mainly non-marine palynomorphs including trilete

spores. Gymnosperms include Araucariacites australis and Ephedripites spp. and

angiosperms Afropollis kahramanensis, Stellatopolis, Cretacaeiporites scabratus and

Integritetradites porosus. Moreover, a single record of Botryococcus and a scolecodont

have been reported. The upper three samples are poor in palynomorphs except for

phytoclasts and AOM. Sample 15/484 and 15/486 contain rare dinocysts and a single

specimen of a scolecodont in sample 15/486. Few specimens of Afropollis, Proteacidites

and Ephedripites pollen and spores containing Crybelosporites pannuceus and

Cicatricosisporites spp. are recorded.

The Abu Roash “A” Member palynomorphs are mostly marine except for a minor

terrestrial contribution of spores and pollen. The recorded dinocysts comprise

Dinogymnium, Chattangiella and Subtilisphaera. Sporomorphs include trilete spores and

pollen taxa assigned to Droseridites senonicus, Foveotricolpites giganteus, Foveotricolpites

gigantoreticulatus, Afropollis spp., Araucariacites australis and Cycadopites spp.

Freshwater algae are represented by a single record of Pediastrum in the sample 15/400.

91

3.6 Discussion

3.6.1 Age assignment

Although the number of Bahariya samples in the studied well is limited, the recorded taxa

(e.g. Afropollis jardinus and Classopollis) are closely similar to previously retrieved

assemblages in the same basin (e.g. GPTSW-7; El Beialy et al., 2010). Hence, the Bahariya

Formation has been palynologically dated as lower to middle Cenomanian (Fig. 3-2).

The Abu Roash Formation shows a low diversity but stratigraphically important taxa are

recorded. These include Droseridites senonicus, which is a key stratigraphic marker taxon

in the Coniacian–Santonian of West Africa (Jardiné and Magloire, 1965; Jan du Chêne et

al., 1978), and Turonian–Santonian of Angola Basin, intertropical Africa and Sudan

(Morgan, 1978; Lawal and Moullade, 1986; Salard-Cheboldaeff, 1990; Kaska, 1989;

Awad, 1994). In southern Egypt, it has been previously reported from the Coniacian–

Santonian of the Aswan area (Sultan, 1985). Subsequently it has been reported from

Turonian–Santonian (Schrank and Ibrahim, 1995; Ibrahim and Abdel-Kireem 1997;

Ibrahim et al., 2009; El Beialy et al., 2010) of the Western Desert, Egypt and from the Gulf

of Suez (El Diasty et al., 2104). Dinogymnium vozzhennikovae was first described from the

Turonian of Siberia (Lentin and Vozzhennikova, 1990). Subsequent records are reported

from the late Turonian of northern and southern hemispheres (Williams et al., 1993;

Schrank and Ibrahim, 1995; El Beialy et al., 2010). In addition, the co/occurrence of

Ephedripites ambiguus–Ephedripites multicostatus–Foveotricolpites giganteus–

Foveotricolpites gigantoreticulatus assemblage zone has been considered as an indication

of early Turonian age as reported from the GPTSW-7 well from the same basin (El Beialy

et al., 2010). Moreover, the presence of A. kahramanensis in the Abu Roash “G” Member

was described for the first time from the early–late Cenomanian of Egypt by Schrank and

Ibrahim (1995) and El Beialy et al. (2010). From the above discussion, it is possible to

date this assemblage from the Abu Roash Formation as middle/upper Cenomanian–

Santonian (Fig. 3-2). The recovered assemblages are closely similar to those described

from the GPTSW-7 well within the same field, and hence follow the zonation scheme of

El Beialy et al. (2010) (Fig. 3-2).

92

3.6.2 Depositional environments

3.6.2.1 Bahariya Formation

The Bahariya Formation shows considerable variation in lithology in the Western Desert

as discussed above. The analyzed section from 2142 to 2238 m has fair TOC, low

carbonate contents and moderate TS values. The relationship between TOC and CaCO3

(Figs. 3-8, 3-9) is typical of shallow marine carbonate-rich environments where organic

carbon content is positively correlated with silicate and negatively with carbonate (Bou

Daher et al., 2015). In such environments, terrestrial-derived nutrients probably enhance

bioproductivity leading to the observed trend. TS/TOC ratios are quite high as compared

to normal marine conditions. This is probably due to migrated and converted

hydrocarbons as can be implied from relatively high PI values for immature source rocks

(>0.1) (Table. 3-1). These TOC versus TS and CaCO3 relationships are similar for all

samples except for the Abu Roash “F” Member that show distinctive trends.

Further information is derived from molecular geochemistry. A representative sample

was selected for biomarker analysis showing a bi-modal n-alkane distribution. Pr/Ph

value is 1.8 indicating suboxic to oxic conditions (Didyk et al. 1978). Moreover, the

relationship between Pr/n-C17 versus Ph/n-C18 can be used to determine the organic

matter type (Peters et al. 2005). Data suggest mixed marine and terrestrial organic

matter in this case (Fig. 3-19). The very low str/hop ratio indicates microbially reworked

terrestrial organic matter (Tissot and Welte, 1984). This is in accordance with

palynological data that emphasize the existence of terrestrial palynomorphs and

fresh/brackish water algae. However, the samples also show high proportions of AOM

relative to phytoclasts and palynomorphs suggesting a somewhat distal setting (Tyson,

1993; Fig. 3-18). This contradicts the geochemical and palynological evidences, although

the AOM is sometimes of terrestrial origin. It is believed that reworked allochthonous

organic matter or degraded marine organic matter can be considered as a source of AOM

and not preserved marine algae. This is possible due to the proximity to the shoreline

and the effect of turbidity currents that can transport terrestrial organic matter and

dilute the autochthonous marine ones. Moreover, the high sedimentation rates and

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microbial activities at the shallow marine settings increase the oxygen level that

intensifies the organic matter degradation. The low density of the alginite is responsible

for selective transportation (Bustin, 1988). This fits with the elemental and molecular

geochemical interpretation.

The foregoing discussion indicates that the Bahariya Formation was deposited in a

proximal, suboxic to oxic shallow marine to deltaic environment where an admixture of

terrestrial and marine organic matter has occurred. The interpretation agrees with

previously studied sections in the western Abu Gharadig Basin (e.g. El Beialy et al., 2008,

2010; El Atfy, 2011).

Fig. 3-19 Pristane (Pr)/n-C17 versus phytane (Ph)/n-C18 illustrating the organic matter type of selected samples from the studied rock units, GPT-3 well, north Western Desert, Egypt.

3.6.2.2 Abu Roash “G” Member

A period of a regional sea regression characterizes the Abu Roash “G” deposition (Abdel-

Kireem et al., 1996). This explains the enrichment in silicates, the low carbonate contents

and the high content of detrital elements (e.g. Fe, Al, Ti and K) (Fig. 3-4). Variability in

TOC and elemental data are small indicating steady depositional environment conditions.

0.01 0.10 1.00 10.00

Ph/nC18

0.01

0.10

1.00

10.00

Pr/

nC

17

Oxidising

Reducing

Biodegraded/immature

Early mature

Mature

Terrestrial organic matter

Mixed sources

Marine organic matter

TypeReservoirSource Rock

Rock UnitAbu Roash "A"Abu Roash "B"Abu Roash "C"Abu Roash "D"Abu Roash "E"Abu Roash "F"Abu Roash "G"Baharyia

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The samples are characterized by low to moderate TS and moderate TOC contents, which

follow the oxic/suboxic shelf trend discussed above. The relationships between TOC, Fe

and TS of a representative sample indicate an Fe-enriched environment (Fig. 3-7) of a

shallow marine oxic to suboxic depositional habitat. The sample also has relatively

moderate K/Al indicating an arid warm climate (Fig. 3-5).

One sample was investigated for molecular geochemistry and shows a Pr/Ph ratio of 1.2

indicating suboxic marine conditions (Table 3-3). The moderate TAR value of 0.23

indicates mixed marine and terrestrial organic matter input. Similarly, the Pr/n-C17

versus Ph/n-C18 reveals a mixed marine and terrestrial organic matter origin (Fig. 3-19).

One other sample (15/465) shows a palynofacies assemblage suggesting proximal shelf

deposition as shown in the AAP diagram (Fig. 3-18). No evidence of fresh water incursion

was reported in this well as is the case in the southern part (El Beialy et al., 2010; GPTSW-

7 well; Fig. 3-1a), which would indicate more distal conditions to the north. However,

more samples should be studied to confirm such a regional trend.

3.6.2.3 Abu Roash “F” Member

Due to its importance as source rock, the Abu Roash “F” has been investigated with

additional techniques. First, the member was subdivided based on elemental

composition into three depositional phases which are 1) transgression phase-I (1978-

1986 m), regression phase-I (1976-1977 m) and transgression phase-II (1965-1975 m)

(Fig. 3-4).

Transgression phase-I starts at the bottom of the Abu Roash “F” Member and includes

samples 14/998, 14/499 and 15/457 (8 m thick). This phase, which hosts the CTBE, is

distinguished by high TOC, low TS and detrital elements. Moreover, it is enriched in

carbonate with very low Mg/Ca ratios indicating prevalence of aragonite/calcite. The

studied samples have TOC/TS ratios exceeding 2.8 and are located below the normal

marine line (Berner, 1984; Fig. 9). Moreover, the samples plot along the pyrite line (Fig.

3-7) indicating anoxic conditions and revealing that the system was not rich in surplus

sulfur as the majority of sulfur was apparently fixed in pyrite with fair excess sulfur. Due

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to the limited Fe availability, excess sulfur was incorporated into kerogen (Fig. 3-17;

Lückge et al., 1996; Ghassal et al., 2016). This is quite common in such carbonate-rich

environments, where the low iron content limits pyrite formation (e.g. Ghassal et al,

2016; Figs. 7, 8). This is in general accordance with the moderate to high

thiophene/benzene ratio implying moderate organic sulfur concentrations (Fig. 17,

Table 4). The sulfur incorporation might destroy the primary morphology of the organic

matter through (vulcanization; Taylor et al., 1998); furthermore conditions for

preservation of otherwise labile (amorphous; unstructured) organic matter were

favorable. The organic petrology data of these samples reveal dominance of marine

alginite kerogen and high proportions of submicroscopic unstructured organic matter

(UOM) indicating good preservation (Fig. 3-12).

This interval also displays low Mn/S ratios indicating anoxic bottom water conditions

(Aquit et al., 2016). The lowest Mn/S ratio within the Abu Roash “F” Member is found at

the top of transgression-I phase indicating most anoxic conditions prior to the advent of

the ensuing regressive phase (Fig. 3-4). On the other hand, P/Al increases strongly

reaching high values in the lower part of this depositional phase. This might indicate

anoxic bottom waters (Calvert et al., 1996). März et al. (2008) suggested that ratios

higher than 0.4 might indicate anoxic, non-sulfidic conditions. Only in the uppermost

sample of the transgression phase-I, the ratio drops to lower values (Fig. 3-4). The

samples show low K/Al and Si/Al ratios inferring dominance of kaolinite and/or smectite

in the silicate mineralogical assemblages associated with the carbonate rich deposits,

which implies a humid warm climate (Fig. 3-5). Similar conclusion can be deduced from

in the SiO2-Al2O3-CaO relationship (Fig. 3-6) indicating variable, partly high carbonate

contents.

Two samples were investigated for biomarker characteristics. Pr/Ph ratios close to 1.0

indicate oxygen-depleted bottom water conditions (Table 3-3). The marine nature of the

samples is supported by the predominance of n-C14 to n-C20 in the extracts indicating

marine organic matter. Moreover, the lower abundance of the longer n-alkane (n-C21+)

might indicate low terrigenous input, which is in accordance with organic petrographic

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data (Fig. 3-11), although the Pr/n-C17 versus Ph/n-C18 relationship suggests mixed

marine and terrigenous organic matter (Fig. 19). The samples C31R/C30 Hop ratio exceeds

1.0 typical of carbonate lithology, which is obvious from the elemental data. The C27-C29

steranes diagram (Fig. 3-14) indicates an open/shallow marine depositional

environment and palynofacies of one sample at 1983 m confirms a distal suboxic-anoxic

basin (Fig. 3-18; Table 3-5).

A change in the lithology and TOC content is observed for the regression phase (1 m

thick) (Fig. 3-6). The bottom sample is enriched in siderite and shows no visible organic

matter (Fig. 12). The palynofacies investigation reveals dominating opaque phytoclasts

over palynomorphs and no AOM, indicating oxic shelf depositional environment (Fig. 3-

18). This sample contains microforaminiferal linings indicative of a shallow marine

environment in addition to the chlorococcale algae Pediastrum and Botryococcus, which

inhabit fresh/brackish water environments. The sample contains Foveotricolpites

giganteus and Foveotricolpites gigantoreticulatus that have not been evolved prior to the

Turonian. This rather confirms the age assignment and gives some credibility to the

occurrence of a short and rapid sea regressive phase in the Abu Gharadig basin or

probably north Western Desert during the early Turonian. Moreover, the examined

sample (15/497; 1977 m) denotes oxic shelf assemblages based on palynofacies data

(Fig. 3-18). Cyanobacteria rarely outpace identifiable fossilized remains yet they played

a major role during the OAEs (Kuypers et al., 2004). Cyanobacterial blooms can also

promote siderite formation due to riverine input at shallow water (Köhler et al., 2013).

Biotic siderite formation can occur in slightly acidic to neutral (pH ~5-7) and reducing

(Eh<0) conditions, which contradicts earlier interpretations (Sánchez-Román et al.,

2014). Alternatively, siderite might represent a concretion that has formed inside the

sediments during early diagenesis with the iron being sourced from terrigenous input

during regression. More work is needed on other cores from the same stratigraphic

interval to verify these hypotheses, because here only a single sample of this

extraordinary type was present. The overlying sample (15/496; 1976 m) is rich in

detrital elements and of similar palynofacies despite the smaller proportion of AOM. It

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also contains more marine palynomorphs indicating slight sea level rise yet shallow oxic

water. Both samples show a similar TOC-Fe-TS relationship with Fe-domination

indicating limited sulfate reduction possibly due to freshwater influence and thus limited

sulfate availability (Fig. 3-7). The two samples show relatively high Ti/Al ratio, which

indicate a nearshore environment (Niebuhr, 2005). The K/Al versus Si/Al plot indicates

illite contribution hinting towards a semi-arid to arid warm climate (Aquit et al., 2016,

Niebuhr, 2005).

The last interval in the Abu Roash “F” is transgression phase-II. The TOC increases again

in this interval to reach a maximum at 1974 m, where the carbonate content is close to

100 %. The increase in TOC and CaCO3 is associated with a decrease in the TS values. The

samples show very low thiophenes/benzenes values indicating low sulfur incorporation

into organic matter (Table 4). This reveals a higher contribution of detrital iron (Fig. 3-

7). The more oxic environment as compared to transgression phase-I is reflected in the

lower HI values (Table 1). In addition, samples from transgression phase-II are richer in

phytoclasts than those encountered in phase-I, indicating more oxic conditions. Organic

petrology reveals that the samples are dominated by marine alginite and AOM associated

with foraminifera (Fig. 3-12). The predominance of AOM associated with small

proportions of visible alginite and minor terrestrial organic matter are common

components of upwelling zone sediments (Littke and Sachsenhofer, 1994; Lückge et al.,

1996; Ghassal et al., 2016). A wide range of n-alkanes is present up to n-C33 denoting

mixed marine and terrigenous organic matter. This is supported by the Pr/Ph ratio

reaching up to 1.3. This value is higher than the one observed in samples from

transgression phase-I supporting the above explained differences in bottom water

conditions during deposition.

In summary, Abu Roast F Member represents the best source rock in the study area

which, was deposited during the late Cenomanian and early Turonian. However, as

compared to other CTBE black shales (Kolonic et al. 2002; Ghassal et al., 2016), there is a

significant terrestrial influence and a considerable variability with respect to organic

facies and kerogen characteristics with the best source rocks present at the base. This

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was probably triggered by a rather shallow marine deposition, where transgressions and

regressions affected lithofacies much stronger than at a deeper setting. Both

transgression phases share the same TOC versus TS and CaCO3 relationship, which are

unique to the Abu Roash “F” Member and completely different from the pattern of all

rocks above and below (Figs. 3-8, 3-9, 3-20).

3.6.2.4 Abu Roash “E” Member

The Abu Roash “E” Member was deposited during a period of sea regression, which was

responsible for shallow marine deposits. In the investigated section, this member is

characterized by relatively low carbonate contents, much silicates and moderate TOC

values. Elemental data reveal presence of illite (based on K/Al ratio) indicating a warm

semi-arid to arid climate upon deposition (Fig. 3-5). Moreover, the samples are relatively

rich in Fe indicating terrestrial input and oxic depositional environment (Fig. 3-7).

A Pr/Ph value of 1.5 indicates a suboxic/oxic environment (Table 3-3) and the C27-C29

steranes and C31R/C30 Hop ratio a marine depositional environment (Table 3: Fig. 3-14).

The C31R/C30 Hop reveals a silicate lithology, which is in agreement with the elemental

analysis. In conclusion, it is evident that the Abu Roash “E” Member was deposited in

shallow suboxic/oxic bottom water conditions.

Four samples were selected for organic geochemistry; three are from an impregnated

reservoir section (PI= 0.3-0.5) (Fig. 3-3). The Pr/n-C17 versus Ph/n-C18 indicates a mixed

marine and terrestrial organic matter (Fig. 3-19). The C31R/C30 Hop of 1.05 also suggests

a carbonate lithology in accordance with elemental data (Table 3-3). The palynological

results suggest shallow marine conditions, based on the occurrence of a mixed marine

and terrestrial palynofacies. Palynofacies is dominated by AOM in carbonates, but

different in the siliciclastics.

3.6.2.6 Abu Roash “C” Member

The Abu Roash “C” Member witnessed a recent oil discovery in the vicinity of the GPT

field but was not reported as a producing reservoir in the study area. The member

includes a sandy section overlain by a more carbonate-rich interval (Fig. 3-2).

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Fig. 3-20 Generalized depositional model of the Abu Roash “F” Member based on the current geochemical and palynological interpretation.

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The sandy section shows predominance of terrestrial palynomorphs. The presence of

fresh/brackish water algae Botryococcus and marine scolecodonts indicates a change in

the depositional regime from deeper in the Abu Roash “D” to shallower in the Abu Roash

“C”. In the overlying samples, the palynomorph content decreases with dominant non-

marine phytoclasts associated with fair proportions of AOM. This indicates further

regression and/or increasing terrigenous input. Moreover, the APP ternary diagram

(Tyson, 1993) suggests proximal to marginal shelf settings (Fig. 3-18). The sandy section

is also characterized by low TS and TOC values indicating oxic bottom water conditions.

Biomarker data for the indigenous sample (one other sample contains migrated oil;

PI=0.4) suggests predominance of marine organic matter input (Figs. 3-13a, 3-19) and a

marine depositional environment (Fig. 3-14).

3.6.2.7 Abu Roash “B” Member

High carbonate contents and marginal TOC values characterize the Abu Roash “B”

Member. This member acts as gas reservoir in the GPT field, but there is no information

regarding the reservoir quality in this well. Most samples from this member consist

mainly of carbonate (> 85%) with low TOC and TS giving rise to oxic conditions (Figs. 3-

7, 3-8).

3.6.2.8 Abu Roash “A” Member

The Abu Roash “A” Member was deposited during a transgressive phase (Said, 1990;

Ahmed 2008). It is characterized by fair TOC and CaCO3 contents the latter decreasing

towards the top of the section from 45 % to 26 %. Three samples were opted for

palynofaices assessment. The lower two samples are characterized by distal sub-anoxic

basin palynofacies. This varies in the upper sample to a proximal suboxic-anoxic shelf

assemblage (Fig. 3-18). Furthermore, the upper sample contains freshwater algae

indicating sea regression and an increase of terrigenous input at the end of the Santonian.

This regressive phase could have happened subsequent to the sea transgression that

started earlier during the deposition of the basal part of the Abu Roash “A” Member.

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Biomarker data indicate mixed terrestrial-marine organic matter and a marine

siliciclastic environment. However, in view of the low TOC values and the tendency of the

members above the Abu Roash “F” source rock to be impregnated by migrated oil,

biomarker data should be treated cautiously.

As noticed, the normal marine ratio defined by Berner (1984) was shifted for all

sediments excluding the Abu Roash “F” Member to higher values (Fig. 3-9). This is

possibly due to migrated hydrocarbons that reacted with pore water sulfate due to

biologically driven sulfate reduction, leading to high sulfide (pyrite) contents. The

migrating hydrocarbons in the section are indicated by continuously elevated PI values,

which are higher than would be expected in thermally immature samples. However, PI

values also depend on type of organic matter.

3.6.3 Source rock potential

Excellent source rocks characterize the Abu Roash “F” Member. Two kerogen types are

distinguished: transgression phase-I is characterized by relatively high

thiophenes/benzenes ratio (1.9-10.8), a maximum TOC of 5.9% and an average HI of 564

mgHC/gTOC indicating type IIS kerogen (Figs. 3-3, 3-10, 3-17). This source rock is

expected to produce high sulfur oil upon expulsion (Fig. 3-17). The second kerogen type

II-III belongs to transgression phase-II which has a low thiophenes/benzenes ratio (0.8),

TOC maximum value of 4.0 % and HI average of 355 mgHC/gTOC. This organofacies is

expected to yield low-sulfur oil (Fig. 3-17). The analyzed source rocks show low thermal

maturity, which is supported by vitrinite reflectance, Tmax values and numerous

biomarker parameters (Fig. 3-3; Table 3). Note that the transgression phase-I has lower

Tmax values compared to the other facies, which is attributed to kerogen type IIS (Pepper

and Corvi, 1995). In general, the source rock section shows thermal maturity retardation

or suppression based on Tmax and other biomarker maturity parameters (Figs. 3-3, 3-

15). The retardation points to lower reaction rates during thermochemical alteration,

possibly due to overpressure effects. Suppression/retardation of specific reactions in

source rocks has been described before and related to high liptinite content or presence

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of bitumen and hydrogen-rich vitrinite (Carr, 2000). From the data here presented, it is

quite obvious that there is an effect on a variety of different and independent parameters,

leading to lower maturity values, e.g. with respect to Rock-Eval data and various

molecular geochemical parameters that all indicate suppression in the best source rock

interval, the Abu Roash “F” Member, which is characterized by high HI values, high

sterane/hopane ratios and high liptinite contents.

The source rock heterogeneity of the Abu Roash “F” Member makes any oil to source rock

correlation challenging in the Abu Gharadig Basin.

3.6.4 Reservoir geochemistry

Two oil reservoirs are identified in this well, namely the Abu Roash “C” and “D”, which

can be distinguished by PI values above 0.16 (Fig. 3-3). Based on the relationship

between C29 ββ/(αα+ββ) and C29 ααα20S/(20S+20R) steranes (Fig. 3-15), the samples

from the two reservoirs differ in thermal maturity and composition. The Abu Roash “C”

samples have Pr/Ph ratio of 1.3 and C29/C30 Hop value of 0.8 indicating a clastic source

rock. The oil was derived from mixed kerogen Type-II/III based on the Pr/n-C17 versus

Ph/n-C18 (Fig. 3-19).

The Abu Roash “C” residual oil differs from its counterpart in the Abu Roash “D” oil, as

the latter lost its light n-alkanes due to biodegradation or evaporation (Fig. 3-11). The

presence of long-chain n-alkanes increases with depth indicating heavier oil towards the

bottom. The Abu Roash “D” samples have Pr/Ph ranging from 0.8-1.1 indicating a marine

source rock with negligible terrigenous input, i.e. type II kerogen (Table 3-3).

Furthermore, the samples have C29/C30 Hop and C31R/C30 Hop values denoting a marine

siliciclastic source (Table 3-3). These residual oils have a high maturity compared to the

source rocks in the same well (Fig. 3-15), which outlines that they have to come from

deeper lying kitchen areas in central Abu Gharadig Basin of the Western Desert, probably

towards the north (Fig. 3-1).

Two factors make the correlation between the Abu Roash “F” source rock and the studied

residual oils ambiguous. First, the heterogeneity of the source rocks as discussed before

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and second the biodegradation of the residual oil. Therefore, further detailed

geochemical studies, especially on samples from the more central (deeper) part of the

basin are highly desirable as well as studies on Jurassic source rocks.

3.7 Conclusions

The current study provides new insights on the depositional environmental in the north

Western Desert, Egypt, from the Cenomanian to the Santonian, as well as on the

petroleum source rock potential of the Abu Rash “F” Member and residual oils in the Abu

Rash “C” and “D” members.

Two general bottom water conditions are identified based on TOC, TS and CaCO3

relationships. The samples from the Bahariya and Abu Roash formations with the

exception of the Abu Roash "F" Member have marginal TOC and similar trends in the TOC

versus TS and CaCO3 relationships. Although the samples differ in lithology and

depositional environment, they have been deposited in oxygen-depleted but not anoxic

conditions in rather shallow water. The normal marine ratio defined by Berner (1984)

was shifted for these sediments to higher TS/TOC ratios possibly due to migrated

hydrocarbons that reacted with pore water sulfate due to biologically driven sulfate

reduction, leading to high sulfide (pyrite) contents. The high amount of migrating

hydrocarbons in the section is proven by continuously quite high PI values, which are

much higher than would be expected in view of the low thermal maturity.

In contrast to the rest of the sediments, the Abu Roash “F” Member shows a positive

relation between TOC and CaCO3 as well as TS. It represents a period of anoxic or strongly

oxygen-depleted bottom waters with enhanced preservation of organic matter, which is

reflected in high HI values. Three depositional phases have been identified as follows:

1- Transgression phase-I: It is characterized by anoxic bottom water conditions,

leading to sediments that are rich in TOC, carbonate and S and partly poor in Fe

and other detrital elements. This favored sulfur incorporation into organic matter.

Sediments of this phase appear to be deposited in more humid climate compared

to the other rock units based on illite/smectite ratio.

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2- Regression phase-I: It witnessed sea level fall and fresh water incursions including

acidification of the waters and heavy mineral deposition as interpreted from the

richness in siderite, rutile, detrital elements and Mn. Moreover the samples

yielded fresh/brackish water algae Botryococcus, but also marine palynomorphs.

This phase contains Foveotricolpites giganteus and Foveotricolpites

gigantoreticulatus that assign it to the early Turonian age.

3- Transgression phase-II: It is rich in TOC, deposited in suboxic conditions and also

shows relatively higher detrital element concentrations as compared to

transgression phase-I which impeded sulfur incorporation into kerogen. The

palynological investigation reveals the occurrence of marine and non-marine

species.

The differences between the two transgressive phases in the depositional environment

resulted in the formation of two source rock types. Both source rocks are immature with

oil generative potential. However, transgression phase-I source rock contains kerogen

type-IIS, which yields high sulfur oil, whereas transgression phase-II contains kerogen

type-II/III which generates sweet oil with minor gas upon expulsion. The strong

influence of sea level fluctuations on the sediments during the late Cenomanian to early

Turonian could be a local phenomenon in the Abu Grading Basin due to low water depth

as compared to other deeper sites.

Interestingly, a variety of independent Rock-Eval and biomarker maturity parameters all

reveal lower thermal maturity for the Abu Roash “F” source rock interval as compared to

sediments above and below. This finding suggests retardation/supersession of

maturation processes in oil-prone source rocks, but could be also due to presence of

migrated bitumen of enhanced maturity, i.e. from deeper source rocks, in all formation except

for the Abu Roash “F” Member.

The residual oils of the Abu Roash “C” and “D” reservoirs reveal two different

compartments. The Abu Roash “D” residual oils are affected either by biodegradation or

evaporation. They also show heavier chemical composition with depth. The Abu Roash

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“C” residual oil shows a bi-modal n-alkane distribution and lighter chemical composition

relative to the Abu Rash “D” residual oils. Correlations with source rocks are elusive due

to the quality of the residual oil samples and source rock heterogeneity.

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An oil paint of a bituminite particle found in a Cenomanian/Turonian sample, Tarfaya Sondage-4, Morocco. Artist: Esrraa Abunar

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Chapter 4 | Depositional Environment and Source Rock Potential of Cenomanian and Turonian Sedimentary Rocks of the Tarfaya Basin, Southwest Morocco 2

4.1 Abstract

Detailed organic and inorganic geochemical analyses were used to assess the

depositional environment and source rock potential of the Cenomanian and Turonian oil

shale deposits in the Tarfaya Basin. This study is based on core samples from the Tarfaya

Sondage-4 well that penetrated over 300m of Mid Cretaceous organic matter-rich

deposits. A total of 242 samples were analyzed for total organic and inorganic carbon and

selected samples for total sulfur and major elements as well as for organic petrology,

Rock-Eval pyrolysis, Curie-Point-pyrolysis-gas chromatography-Mass-Spectrometry and

molecular geochemistry of solvent extracts. Based on major elements the lower

Cenomanian differs from the other intervals by higher silicate and lower carbonate

contents. Moreover, the molecular geochemistry suggests anoxic bottom marine water

conditions during the Cenomanian-Turonian Boundary Event (CTBE; Oceanic Anoxic

Event 2: OAE2). As a proxy for the Sorg/Corg ratio, the ratio total thiophenes/total

benzenes compounds was calculated from pyrolysate compositions. The results suggest

that Sorg/Corg is low in the lower Cenomanian, moderate in the upper Cenomanian, very

high in the CTBE (Cenomanian-Turonian Boundary Event) and high in the Turonian

samples. Rock-Eval data reveal that the lower Cenomanian is a moderately organic

carbon-rich source rock with good potential to generate oil and gas upon thermal

maturation. On the other hand, the samples from the upper Cenomanian to Turonian

2 Ghassal, B. I., Littke, R., Sachse, V., Sindern, S., & Schwarzbauer, J. (2016). Depositional Environment and Source Rock Potential of Upper Albian to Turonian sedimentary rocks of the Tarfaya Basin, Southwest Morocco. Geologica Acta, 14(4), 419-441.

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exhibit higher organic carbon content and can be classified as oil-prone source rocks.

Based on Tmax data, all rocks are thermally immature.

The microscopic investigations suggest dominance of submicroscopic organic matter in

all samples and different contents of bituminite and alginite. The lower Cenomanian

samples have little visible organic matter and no bituminite. The upper Cenomanian and

CTBE samples are poor in bituminite and have rare visible organic matter, whereas the

Turonian samples change from bituminite-fair to bituminite-rich and to higher

percentages of visible organic matter towards the younger interval. These differences in

the organic matter type are attributed to i) early diagenetic kerogen sulfurization and ii)

the upwelling depositional environment. Moreover, kerogen sulfurization was controlled

by the relationship between carbonate, iron and sulfur as well as the organic matter.

Thus, the organic carbon-rich deposits can be grouped into: i) low Sorg and moderately

organic matter-rich oil prone source rocks, ii) moderate Sorg and organic-carbon-rich oil

prone source rocks, iii) high Sorg and organic carbon-rich oil prone source rocks and iv)

very high Sorg and organic carbon-rich oil prone source rocks, the latter representing the

CTBE interval. Types 2 to 4 will generate sulfur-rich petroleum upon maturation or

artificial oil shale retorting. This integrated organic and inorganic approach sheds light

on the various processes leading to the development of the world-class oil shales

deposited through the Cenomanian to Turonian. In addition, this study shows how the

changes in the depositional environment might have controlled kerogen sulfurization

and organic matter preservation and structure. This detailed approach provides a better

understanding on source rock development during the Cenomanian to Turonian in a

global context, as many of the geochemical features were identified worldwide for

deposits related to OAE2.

4.2 Introduction

The Tarfaya Basin is located in southwest Morocco, south of the Anti-Atlas with the

Reguibat massif in the east, the Mauritanides Mountains in the south and the Atlantic

Ocean abyssal plain in the west (Fig. 4-1). It is considered as one of the main petroleum

basins along the eastern Atlantic coast and belongs to the major oil shale deposits in

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Morocco (Dyni, 2006). Exploration activities for conventional oil increased during the

1960s and early 1970s when several wells encountered gas and oil shows. This led to an

offshore heavy oil discovery in the Jurassic play (SUBSEAIQ, 2014), ie. the Cap Juby field.

In the 1980s, Shell assessed the Upper Cretaceous (Cenomanian/Turonian) succession in

the onshore part of the basin for open pit oil shale mining; however, the deposits were

regarded as non-commercial at that time (Lüning et al., 2004).

Fig. 4-1 Overview map of the Tarfaya Basin showing the location of the studied well (S-4) and some of the

previously studied wells (modified after Michard et al., 2008).

The estimated total oil shale resource of the Tarfaya Basin is 86 billion tons with an

average thickness of the mineable deposits of 20m (Dyni, 2006) and Total Organic

Carbon content (TOC) of up to 20% for the Cenomanian (Kolonic et al., 2002; Sachse et

al., 2011, 2012, 2014). Based on a well correlation (Michard et al., 2008) and an

interpreted seismic line (Wenke, 2014; Fig. 4-2), the offshore basin differs from the

110

onshore part, as in the offshore area a thick Tertiary succession and Triassic salt domes

were identified (Fig. 4-2). This finding essentially increased the chance of finding more

thermogenic oil and gas accumulations in the offshore area, where sufficient maturation

of source rocks can be expected. In addition, the Canary hotspot is situated in direct

vicinity to the Tarfaya Basin and might have affected heat flow leading to mature

Cretaceous source rocks (see Neumaier et al., 2015), if this rocks are present on the

offshore area.

Several potential reservoirs were discussed in the literature but according to offshore

well data gas and oil are present in the Jurassic and Lower Cretaceous (Morabet et al.,

1998). The single oil discovery, Cap Juby, contains low and high API (American Petroleum

Institute) gravity oil in the Lower and Middle Jurassic, respectively. Source to oil

geochemical correlations suggested carbonate-rich source rocks for these oils (Morabet

et al., 1998). Potential seals are distributed throughout the pre-, syn- and post-rift

sections with shaly and evaporatic lithologies; accordingly sealing capacity is not

regarded as limiting factor for hydrocarbon accumulations. The source rock

characteristics in the Tarfaya Basin were assessed in detail by Kolonic et al. (2002),

Lüning et al. (2004) and Sachse et al. (2011, 2012, and 2014) based on outcrops and

onshore wells (Fig. 4-1). Outcrop samples from the Devonian, Carboniferous, Jurassic and

Lower Cretaceous showed poor source rock potential (Sachse, 2011). However, results

published by Enachescu et al. (2010) indicated that the offshore oil in the Tarfaya Basin

was sourced by Jurassic marly facies with TOC values ranging from 1.47 to 2.49%. On the

other hand, the Upper Cretaceous embraces the highest source rock quality compared to

the other stratigraphic sections in the basin. The Cenomanian and Turonian outcrop

(Sachse et al., 2011) and core samples (Kolonic et al., 2002; Sachse et al., 2012, 2014) are

characterized as excellent immature oil prone source rocks, based on high values of TOC

and Hydrogen Index (HI) and low to moderate values of Tmax and vitrinite reflectance.

They are characterized by high Total Sulfur content (TS) but only moderate TS/TOC ratio

(Kolonic, et al., 2002; Sachse et al., 2011, 2012, 2014).

111

Fig. 4-2 Cross section showing the extent of the onshore/offshore stratigraphy of the Tarfaya Basin (modified after Wenke, 2014), including Cap Juby

well. Surface geology in the small map modified after Saadi et al. (1985). CJ: Cap Juby well.

112

Outcrop samples from the Coniacian, Santonian, Campanian and Eocene show similar

hydrocarbon richness, maturity and generative potential (Sachse et al., 2014).

The first objective of this study is to assess the source rock potential in the Cenomanian

and Turonian using new core samples from SONDAGE-4 well, drilled in 2009 (Fig. 4-1).

In addition, the study intends to determine the depositional environment as well as

associated processes that led to the preservation of organic matter during the

Cenomanian to Turonian times using a variety of organic and inorganic geochemical and

petrographic techniques. In particular the change of organic facies through time is

investigated in detail and visualized by petrographic sections. In addition, the results of

this study are relevant to better understand the extent (time and space) and intensity of

Oceanic Anoxic Event 2 (OAE2), and its relation to source rock deposition. Finally, the

paper classifies the investigated source rocks based on several criteria that could be

useful for both scientific and industrial communities.

4.3 Geological Setting

The Tarfaya Basin is one of the Mid Atlantic rift basins along the northwestern African

margin. Extension started in Late Permian to Early Jurassic times as a sag basin (Wenke

et al., 2011) leading to major faulting and northeast oriented half grabens (Lancelot and

Winterer, 1980; Hafid et al., 2008). The first synrift units of the Triassic were

characterized by terrigenous clastics that were deposited in an alluvial environment

followed by basaltic extrusives and doloritic sills (Lancelot and Winterer, 1980). Triassic

salt was only observed in the northwestern part of the offshore Tarfaya Basin (Lancelot

and Winterer, 1980; Hafid et. al., 2008). In the Early Jurassic, major transgressions

switched the basin to a marine system (Wenke et al., 2011). Carbonates and evaporites

were deposited at the beginning of the Early Jurassic along the Moroccan margin.

Moreover, the Early Jurassic witnessed tectonic instability due to the initiation of

continental drifting (Lancelot andWinterer, 1980). This tectonic setting was responsible

for the development of carbonate ramps in the Early- to Mid-Jurassic followed by

regressive marine siliciclastic environments. Transgression occurred again in the early

Late Jurassic and led to the deposition of open marine carbonates (Wenke et al., 2011;

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Hafid et al., 2008). The depositional environment changed in the Middle Jurassic giving

rise to carbonate platforms and build-ups (Wenke et al., 2011). Regression took place

again in the Late Jurassic/Early Cretaceous, shifting the depositional environment to

lagoonal and deltaic (Hafid et al., 2008). The basin at this time included two depositional

environments: deltaic facies dominated the northern area and prograded to the NNE,

whereas the northwestern and southern areas encountered outer shelf carbonates to

fine-grained clastic deposits (Wenke et al., 2011). The Lower Cretaceous is composed of

shales, sandstones and shelly limestones with occasional organic matter-rich units and

can reach a thickness of up to 1700m (Einsele and Wiedmann, 1982; Morabet et al.,

1998). The Albian witnessed sea level fluctuations and is characterized by variable

lithologies from open marine carbonates to silty clays and marls (Lancelot and Winterer,

1980; Einsele and Wiedmann, 1982; Wenke et al., 2011). Furthermore, deep sea drilling

penetrated organic rich beds in the northern offshore basin (Einsele and Wiedmann,

1982). Several transgressive-regressive cycles might have occurred in the

Albian/Cenomanian, Cenomanian/Turonian and Santonian/Campanian (Kolonic et al.,

2002). The highest organic carbon content is thought to be associated with these

transgressions (Morabaet et al., 1998). The greatest sea level rise occurred coeval with

the OAE2, the Cenomanian/Turonian Boundary Event (CTBE) (Schlanger and Jenkyns,

1976; Jenkyns, 1980). This major transgression affected North Africa all the way to the

Sahara platform (Lancelot and Winterer, 1980) leading to deposition of organic matter-

rich clays and marls in a nutrient-rich warm water environment (Erbacher et al., 1996;

Kolonic et al., 2002). Sachse et al. (2014) pointed out that the influence of reduced oxygen

content due to lower oxygen solubility in water at high temperature triggered the organic

matter preservation. The uppermost Cenomanian as well as the Turonian succession are

laminated unlike the lower Cenomanian and Lower Cretaceous (Einsele and Wiedmann,

1982).

A major unconformity exists between the late Santonian and the Paleogene (Lancelot and

Winterer, 1980; Hafid et al., 2008; Wenke et al., 2011). The Upper Cretaceous is thin or

missing and unevenly distributed in the shallow water areas as shown in Figure 4-2.

114

Interestingly, most of the Upper Cretaceous sediments are also eroded or undrilled in the

Tarfaya deep water area. Another important transgression occurred in the Eocene

resulting in upwelling and related high surface water productivity leading to deposition

of organic matter-rich units (Sachse et al., 2014). This was followed by a time of non-

deposition during the Early Oligocene (Lancelot and Winterer, 1980). Furthermore, the

uplift of the Canary island volcanic region during the Miocene shifted the depocenter

towards the abyssal part of the basin (Kuhnt et al., 2009). Finally, the latest stratigraphic

section recorded in the Tarfaya is the Miocene Moghrebian Formation (Kolonic et al.,

2002). Figure 4-2 is a cross section representing the distribution of the various

stratigraphic units in the onshore and offshore areas. The most common lithologies are

summarized in a generalized stratigraphic column (Fig. 4-3).

4.4 Samples and Methods

4.4.1 Samples

A total of 242 core samples were collected from Tarfaya Sondage-4. The well was drilled

in 2009, located 40km east of Tarfaya (N27º59’46.4’’, W12º32’40.6’’) as part of a drilling

campaign in order to recover the Miocene to Albian sequences. The borehole has a total

depth of 350.20m with 100% sediment recovery. It penetrated 21.00m of the Miocene

Moghrabien Formation, 79.00m of the Turonian, and 15.06m covering the CTBE interval,

163.04m of the upper Cenomanian and 72.1m of the lower Cenomanian and Albian

section. The CTBE in this well was described in Schönfeld et al. (2015) where C isotope

excursions were discussed. The boundary between the Lower and upper Cenomanian

was tentatively based on changes in geochemical features. Detailed sedimentological and

micropaleontological studies on the same well are currently conducted by the marine

micropaleontology group at Christian-Albrechts University, Kiel, Germany. The two

deepest samples were assigned to the Albian, but they are not discussed in detail due to

their small number.


For geochemical analysis, all samples were powdered, whereas small pieces were

preserved for microscopic studies. All samples were analyzed for Total Organic and

115

Inorganic Carbon (TOC and TIC) using a LiquiTOC II (Elementar Analysengeräte GmbH).

The analytical method is described in Bou Daher et al. (2015). The CaCO3 proportion was

calculated using the equation: CaCO3=inorganic carbon x 8.333. This calculation has to be

used with caution as it will result in overestimation of carbonate contents (by up to 8%)

if dolomite is present instead of calcite.

Fig. 4-3 Stratigraphic column representing the common lithologies in the Tarfaya Basin from coastal to deep marine areas (modified after Davison, 2005; Sehrt, 2014).

TS was measured on 162 samples: 15 samples from the lower Cenomanian, 44 from the

upper Cenomanian, 83 from the interval comprising the CTBE and 20 from the Turonian.

TS was measured using a LECO S 200 sulfur analyzer (precision is <5% and detection

limit 0.001%).

116

Based on CaCO3 and TS values as well as pyrolysis data, 20 samples were selected for

determination of major element concentrations: 5 from the lower Cenomanian, 6 from

the upper Cenomanian, 5 from the CTBE and 4 from the Turonian. Approximately 2g of

powdered rock of each sample was put overnight into an oven at 105°C to dry. Then, the

samples were weighed and placed in an oven at 1000°C for 2 hours for loss of ignition

(LOI) process. After that, the samples were left to cool in moisture-free atmosphere and

weighed again to calculate the loss on ignition.

Next, the samples were mixed with a Li-tetraborate/Limetaborate mixture (FX-X65,

Fluxana, Kleve, Germany) with a ratio of 0.5g/5g. The mixture was fused at 1150°C to

create a glass disc to be used for major element analysis by energy dispersive X-ray

fluorescence spectrometry (Spectro XLab2000). The system has a Pd-tube operated at

acceleration voltages between 15 and 40kV and currents between 6 and 12.0mA.

Secondary targets of Co, Ti and Al were used for signal enhancement. A fundamental

parameter procedure was applied for data computation. The precision of major element

determination was <0.9%.

4.4.3 Rock-Eval Pyrolysis

Rock-Eval pyrolysis analyses were conducted on 99 core samples to characterize their

source rock potential using a Rock-Eval 6. The method is described in Espitalié et al.

(1985) and Peters (1986). Samples cover the lower Cenomanian (14), upper Cenomanian

(19), the CTBE interval (38) and Turonian (26). Various parameters were used from

Rock-Eval data. S1 (mgHC/gRock) represents the free hydrocarbons and S2

(mgHC/gRock) represents the non-soluble hydrocarbons with organic solvents (mostly

kerogen). S3 represents the CO2 released from hydrocarbon during pyrolysis

(mgCO2/gRock). Hydrogen Index (HI; S2/TOC; mgHC/gTOC) and Oxygen Index (OI;

S3/TOC; mgCO2/gTOC) were calculated as common parameters to describe the quality

of the source rock with respect to petroleum generation. Finally, the Production Index

(PI) has been calculated as follows: S1/(S1+S2).

All pyrograms were checked carefully for good S2 peak developments for quality control.

Note that none of the Rock-Eval samples have TOC lower than 0.5% or S2 lower than

117

1.5mgHC/gRock. Therefore, values of all parameters including Tmax and HI are believed

to be accurate.

4.4.4 Organic petrology

Maceral counting was performed on 32 samples to investigate the organic petrological

changes through the studied interval. 4 samples were from the lower Cenomanian, 6 from

the upper Cenomanian, 14 from the CTBE and 8 from the Turonian. The petrological

study used the methods described by Taylor et al. (1998). The bulk samples were cut and

embedded pendicular to bedding, in a 10:3 mixture of epoxy resin (Araldite® XW396),

and hardener (Araldite® XW397) and dried at 37°C for at least 12 hours. The sample

surfaces were then grinded and polished as described in detail by Sachse et al. (2012).

On each bulk sample a total of at least 500 maceral counts were performed. Counting was

performed both in incident white light (for vitrinite and inertinite, and also pyrite) and

in a fluorescent light mode (for bituminite, telalginite, lamalginite, and liptodetrinite)

along transects perpendicular to bedding.

The percentage of each category (as OM volume-% of whole rock) was calculated and

finally the percentages of all macerals were determinated. The maceral percentages were

compared with the volume percentage of organic matter based on TOC-content. This

estimation is based on the equation introduced by Littke (1993) which is:

TOC (wt%) = (ρOM/ρrock) x (C%/100) x OM (vol.%)

Where C% is the carbon content of the Organic Matter (OM). The difference between the

calculated OM from the equation and the counting should correspond to the amount of

submicroscopic OM.

4.4.5 Source rock extraction

For a total of 24 source rocks, aliquots of 3 to 7g of powdered samples were extracted. To

each sample, 50mL of dichloromethane (DCM) were added and agitated in an ultrasonic

bath for 15 minutes. Thereafter, the solution was stirred overnight at room temperature.

Then, the solution was agitated again in an ultrasonic bath for 15 minutes.

118

After filtration, copper powder was added to remove elemental sulfur. Using a liquid

chromatography micro column (Baker, filled with 2g of silica gel 40mm), the raw extracts

were separated into 6 fractions of increasing polarity using n-pentane (5ml), n-

pentane/DCM 95/5 v/v (8.5ml), n-pentane/ DCM 90/10 v/v (5ml), n-pentane/DCM

40/60 v/v (5ml), DCM (5ml) and methanol (5ml), respectively. The fractionation method

is described in detail in Schwarzbauer et al. (2000). For Gas Chromatography-Mass

Spectrometry (GC-MS) analyses the first fraction containing the aliphatic hydrocarbons

was used.

4.4.6 Gas Chromatography and Gas Chromatography-Mass Spectrometry

The aliphatic fractions were analyzed by gas chromatography using a Fisons Instruments

GC 8000 series equipped with a flame ionization detector and a Zebron ZB-1 HT Inferno

fused silica column (30m x0.25mm internal diameter (i.d.); film thickness 0.25μm,

Phenomenex®). Each sample was concentrated to approximately 25-50μL prior to

injection. 1μL was injected into a split/splitless injector at 270°C and with a splitless time

of 60s. Helium was utilized as a carrier gas with a gas velocity of 35cm/s. The

temperature program started at 80°C, held for 3 minutes; then the temperature increased

at a rate of 10°C/minute to reach 300°C remaining constant for 20 minutes. The aliphatic

fractions were further analyzed on a Finnigan MAT 95 mass spectrometer connected to

a Hewlett Packard Series II 5890 GC which was equipped with a similar GC column. The

carrier gas was He with a gas velocity of 33cm/s. The GC run started at 80°C, held for 3

minutes; then the temperature increased to 310°C at a rate of 5°C/minute. The

spectrometer was operated in Electron Ionization (EI*) mode with an ionization energy

of 70eV and a source temperature of 200°C. The scanning range was from m/z 35 to 700

in low resolution mode.

4.4.7 Curie-Point Pyrolysis Gas Chromatography-Mass Spectrometry

A total of 18 samples (4 from the lower Cenomanian, 4 from the upper Cenomanian, 4

from the CTBE interval and 6 from the Turonian) were selected for Curie-Point pyrolysis

coupled to a GC-MS system (CP-PyGC-MS), based on TOC and TS contents. Metal crucibles

with Curie Point temperature of 650°C were made in the lab. Then, each crucible was

119

filled with 3 to 10mg of powered sample. The crucible was inserted in a glass inlet which

was then placed in a CP pyrolyzer (Fischer GSG CPP 1040 PSC) and pyrolyzed at 650°C

for 10s. The pyrolyzer was coupled up to a GC-MS system (Fisons GC 8000; Thermoquest

MD 800). It was equipped with a 30m non-polar GC capillary column (Zebron ZB-5,

0.25mm i.d., 0.25μm film thickness). The pyrolysis products were trapped behind the

injector using a cryofocussing trap (-70°C) prior to the GC-MS analyses. The GC-MS

analyses were conducted using He as carrier gas (velocity 35cm/s) and 40°C as starting

oven temperature held for 3 minutes. Then the oven temperature increased at a rate of

3°C/minute to reach 310°C held for 20 minutes. Molecular masses were scanned from

m/z 35 to 550.

4.4.8 Molecular geochemical parameters

All biomarker ratios were calculated on the base of peak integration of specific ion

chromatograms. For alkanes such as n-C17, n-C18, pristane and phytane ion

chromatograms of m/z 57 were used. Hopanes and methylated derivatives were

determined with m/z 191 and 205, respectively. C27, C28 and C29 steranes were measured

at m/z 217 trace but checked with the ion chromatograms of the molecular ions. In

summary, the following biomarker ratios were calculated: pristane/phytane (Pr/Ph),

pristane/n-C17 and phytane/n-C18 ratios, as well as methylated hopanes/total hopanes

and steranes/hopanes ratios. As a proxy for the ratio of organic sulfur to organic carbon

the thiophene/benzene ratio was calculated (thiophenes/benzenes). The thiophene

derivatives considered in the equation were: methylthiophenes (2 isomers, m/z 98),

dimethylthiophenes (4 isomers, m/z 112) and trimethylthiophenes (3 isomers, m/z

126). The benzene derivatives used in the equation were: toluene (m/z 92), xylenes (3

isomers, m/z 106) and trimethylbenzenes (2 isomers, m/z 120).

4.5 Results

4.5.1 Elemental Analysis

Variable TOC content was found throughout the analyzed section (Table 4-1; Fig. 4-4)

ranging from 0.72 to 4.54% in the lower Cenomanian. The upper Cenomanian samples

show higher values increasing towards the CTBE interval with an average of 5.50%. The

120

CTBE interval between 100 and 115m depth shows strong fluctuations between 1.71 and

15.44% with highest values towards the top and an average of 8%. Similarly the Turonian

section is characterized by high TOC values ranging from 1.69 to 15.36% and decreasing

towards the top (Fig. 4-4).

TS content generally increases from the bottom to the top of the analyzed section (Fig. 4-

4). The lower Cenomanian shows the lowest TS content with an average of 0.8% and

values varying between 0.4 and 1.5%, whereas the upper Cenomanian samples average

1.3% and range from slightly less than 1% to 2.2% with highest values towards the CTBE.

The CTBE samples show strong fluctuations in sulfur with highest values towards the top

(4.3%) and average value of 1.5%. The Turonian is also characterized by a high TS

average of 1.9%. The carbonate content oscillates rapidly and appears to have a

relationship with the TOC and TS contents (Table 4-1; Fig. 4-4). The lower Cenomanian

samples have relatively low to moderate CaCO3 content, compared to the younger

intervals, with an average of 41%. The upper Cenomanian samples on the other hand

start with moderate carbonate content which increases toward the CTBE to exceed 60%

on average.

The CTBE and Turonian samples are very rich in carbonate with an average of more than

68%. However, these stratigraphic levels also have five narrow low CaCO3 intervals

(<50%). In general, the samples show an inverse correlation between CaCO3 and TS. The

same holds true for the CaCO3 vs. TOC relationship with the exception of the lower

Cenomanian (Fig. 4-5).

The Fe2O3, SiO2, Al2O3, K2O and TiO2 contents increase with well depth, reaching highest

values within the lower Cenomanian (Table 4-2; Fig. 4-6) whereas CaO, SO3 and LOI

generally decrease with depth. Fe2O3 ranges from 2.8 to 5.1% in the lower Cenomanian

and from 1.0 to 4.8% in the upper Cenomanian. A lower range is found in the samples

representing the CTBE (0.1 to 3.6%). The Turonian has an even narrower range from 0.1

to 1.5%. The Fe2O3 and TiO2 show a negative relationship when they are plotted against

CaCO3 (Fig. 4-7), which is in line with the decrease of CaO with depth. MnO is very low

throughout the well and does not exceed 0.04%. MgO is relatively low but exceeds 3% in

121

three samples (53.52m, 129.04m and 187.92m). The overall high Ca/Mg ratio indicates

that carbonates are mainly present as calcite/aragonite and not as dolomite. Accordingly

the calculation of calcium carbonate content from total inorganic carbon (see elemental

analysis method section) is valid for almost all samples. P2O5 shows high values only at

168.00m (1.5%) and at 220.57m (1.8%). More details are given in Figure 4-6 and Table

4-2.

Fig. 4-4 Depth plots TS, TOC, CaCO3 and TS/TOC ratio of all stratigraphic units.

Tu

ron

ian

T

uro

nia

n

CT

BE

122

Fig. 4-4 continued.

up

per

Cen

om

ania

n

low

er C

eno

man

ian

123

Table 4-1 Elemental and Rock-Eval 6 data. Units: *mgHC/Rock, **mgCO2/gRock, ***mgHC/gTOC, ****mgCO2/gTOC. T: Turonian, CT: CTBE, UC: Upper Cenomanian, LC: Lower Cenomanian A: Albian

Table 4-1 continued

sample Depth Age TOC CaCO3 S TS/TOC Original OM Silicates S1 S2 S3 Tmax HI OI

[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/1047 24.06 T 5.56 78.75

14/1048 24.7 T 4.77 88.25

14/1049 26.22 T 6.50 66.32

14/1050 26.56 T 9.02 68.82

14/1051 27.67 T 6.39 83.31

14/1052 28.6 T 5.30 86.16 1.11 0.21 8.03 5.81 0.73 39.48 1.55 411 745 29

14/1053 29.66 T 8.45 46.53

14/1054 30.7 T 7.22 45.36

14/1055 31.61 T 8.45 70.85

14/1056 32.5 T 8.07 76.18

14/1057 33.42 T 5.62 55.22

14/1058 34.6 T 7.32 62.80

14/1059 35.52 T 7.89 67.89

14/1060 36.81 T 10.68 56.48

14/1061 37.61 T 9.75 56.29

14/1062 38.57 T 2.19 95.66

14/1063 39.71 T 8.18 79.60

14/1064 40.47 T 2.31 87.07

14/1065 41.38 T 1.69 92.22 0.49 0.29 2.72 5.06 0.10 13.36 1.34 409 790 79

14/1066 42.57 T 5.28 78.25

14/1067 43.6 T 8.54 58.47

14/1068 44.75 T 2.49 89.25

124

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/1069 45.53 T 14.19 60.24 2.55 0.18 21.05 18.71 2.72 95.56 3.39 412 673 24

14/1070 46.62 T 4.14 60.59

14/1071 47.63 T 4.89 75.56

14/1072 48.63 T 6.00 76.16

14/1073 49.6 T 10.89 51.98 2.62 0.24 16.89 31.13 1.81 81.34 3.36 410 747 31

14/1074 50.68 T 7.23 54.76

14/1075 51.69 T 8.44 53.80

14/1076 52.8 T 8.49 46.51

14/1077 53.52 T 7.13 56.91 2.41 0.34 11.84 31.24 1.01 48.75 1.65 412 684 23

14/1078 54.73 T 9.84 47.31

14/1079 56.09 T 13.34 41.14 2.73 0.20 20.16 38.70 2.25 92.94 3.48 410 697 26

14/1080 57.07 T 11.54 45.65

14/1081 57.5 T 8.00 73.37 1.75 0.22 12.22 14.41 0.89 54.43 1.61 414 680 20

14/1082 58.04 T 7.92 65.57 1.19 51.92 1.59 413 656 20

14/1083 59.15 T 7.10 56.08 0.92 48.44 1.55 408 682 22

14/1084 60.23 T 3.05 61.71 0.25 20.70 1.58 410 679 52

14/1085 61.4 T 1.85 87.42 0.72 0.39 3.17 9.41 0.14 14.66 1.28 410 792 69

14/1086 62.05 T 7.18 42.18 0.98 50.79 1.49 413 709 21

14/1087 62.86 T 6.40 45.60 0.62 42.40 1.64 413 662 26

14/1088 64.07 T 3.07 91.07 0.41 23.05 1.65 409 751 54

14/1089 65.02 T 9.99 52.79 2.03 0.20 15.08 32.13 1.30 72.51 3.17 410 726 32

14/1090 66.125 T 11.65 67.31

14/1091 67.105 T 3.79 71.19

14/1092 68.13 T 5.27 75.29

14/1093 69.04 T 7.42 64.85 1.72 0.23 11.43 23.72 1.06 51.66 1.56 412 696 21

125

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/1094 70.14 T 7.54 53.97

14/1095 71.02 T 7.55 54.75

14/1096 72.1 T 10.24 49.25

14/1097 73.24 T 9.28 55.47 2.28 0.25 14.45 30.08 1.33 70.10 2.99 410 755 32

14/1098 74.06 T 7.58 47.74

14/1099 75.09 T 9.57 46.09 2.58 0.27 15.15 38.75 1.17 70.79 3.05 410 740 32

14/1100 76.32 T 13.81 52.39

14/1101 77.11 T 8.87 56.45 1.98 0.22 13.60 29.95 1.23 71.49 3.05 410 806 34

14/1102 78.31 T 3.34 85.79

14/1103 79.27 T 14.92 52.26

14/1104 80.04 T 12.27 56.88

14/1105 80.08 T 11.18 60.41 2.03 0.18 16.62 22.97 1.86 86.11 3.09 412 770 28

14/1106 82.26 T 3.02 90.98

14/1107 83.16 T 16.69 67.15

14/1108 84.28 T 17.72 50.71

14/1109 85.15 T 12.61 66.79 1.97 0.16 18.37 14.84 1.96 91.00 3.00 415 722 24

14/1110 85.95 T 9.78 74.79

14/1111 87.13 T 9.47 84.79

14/1112 88.01 T 3.60 93.72

14/1113 88.7 T 2.63 99.86 0.34 0.13 0.29 22.00 1.23 413 836 47

14/1114 89.81 T 11.59 71.99

14/1115 91.32 T 13.06 74.41

14/1116 92.5 T 8.21 84.53

14/1117 93.2 T 7.91 80.33 1.32 0.17 11.62 8.05 1.00 51.41 1.54 412 650 19

14/1118 94.45 T 11.04 52.93 2.68 0.24 17.16 29.91 1.51 82.47 3.02 414 747 27

126

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/1119 95.37 T 18.00 65.22

14/1120 96.41 T 15.97 28.83

14/1121 97.46 T 15.36 69.32 2.50 0.16 22.50 8.18 2.37 101.19 3.15 412 659 21

14/1122 98.545 T 6.71 79.44

14/1123 99.3 T 4.56 90.17

14/1124 99.98 T 12.20 71.24 2.34 0.19 18.26 10.50 1.65 82.99 3.11 408 680 26

14/697 100.09 CT 12.00 70.77 1.86 0.15 17.46 11.77 2.09 82.09 3.04 407 684 25

14/698 100.305 CT 12.79 70.36 2.46 0.19 19.15 10.48

14/699 100.49 CT 18.44 53.86

14/700 100.68 CT 9.73 58.03 2.26 0.23 15.01 26.96 1.13 65.37 2.75 411 672 28

14/695 100.69 CT 12.63 47.58 3.53 0.28 20.14 32.27 1.18 79.32 2.84 412 628 23

14/696 100.91 CT 11.49 63.26 2.40 0.21 17.43 19.31

14/782 100.92 CT 15.44 39.39 4.34 0.28 24.66 35.94 1.88 94.11 3.10 410 609 20

14/701 101.11 CT 12.12 65.34 2.87 0.24 18.76 15.90

14/702 101.3 CT 11.52 61.42 2.54 0.22 17.62 20.95

14/703 101.49 CT 14.13 66.76 2.19 0.16 20.58 12.66

14/783 101.67 CT 12.59 63.63 1.70 0.14 18.05 18.32 2.17 89.47 2.87 412 711 23

14/704 101.7 CT 13.23 62.61

14/705 101.89 CT 14.19 73.82 1.90 0.13 20.33 5.85

14/706 102.09 CT 12.13 76.56

14/707 102.32 CT 8.29 76.61 1.52 0.18 12.34 11.05

14/784 102.44 CT 7.62 70.52 1.22 0.16 11.13 18.35 1.12 53.95 1.50 413 708 20

14/708 102.53 CT 7.45 67.50 1.35 0.18 11.07 21.43 0.62 46.76 1.62 416 627 22

14/709 102.73 CT 6.74 78.45 1.15 0.17 9.93 11.62

14/711 103.21 CT 4.43 85.65 1.20 0.27 7.03 7.32 0.48 31.38 1.45 415 708 33

127

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/712 103.42 CT 4.71 94.69 0.80 0.17

14/713 103.61 CT 5.50 80.02 1.62 0.29 8.86 11.12 0.58 37.61 1.52 413 684 28

14/785 103.66 CT 6.27 79.40 0.91 0.15 9.07 11.53 0.95 46.55 1.53 412 742 24

14/714 103.81 CT 5.86 95.13 0.89 0.15

14/786 103.97 CT 9.29 60.11 1.69 0.18 13.80 26.09 1.59 81.09 2.96 411 873 32

14/715 104.02 CT 11.71 75.38 1.68 0.14 16.89 7.73 1.84 94.67 2.94 413 674 21

14/716 104.21 CT 14.04 68.54 2.87 0.20 21.22 10.24

14/717 104.4 CT 12.71 77.58 1.80 0.14 18.32 4.10

14/718 104.59 CT 8.05 82.63 1.05 0.13 11.50 5.87 1.11 59.82 3.01 414 743 37

14/719 104.78 CT 7.15 86.62 0.73 0.10 9.99 3.39

14/720 104.98 CT 3.56 94.55 0.52 0.15 5.15 0.30 0.44 27.46 1.60 414 771 45

14/721 105.18 CT 1.90 108.28 0.32 0.17

14/722 105.39 CT 5.11 96.35 0.77 0.15

14/723 105.62 CT 8.04 67.61 1.20 0.15 11.66 20.73 1.13 61.59 3.14 411 766 39

14/787 105.62 CT 8.86 71.44 1.14 0.13 12.64 15.93

14/724 105.83 CT 6.83 89.76 1.05 0.15 9.94 0.30

14/725 106.04 CT 2.62 100.10 0.54 0.21

14/726 106.28 CT 6.77 68.43 1.02 0.15 9.82 21.75 0.91 50.00 1.74 415 738 26

14/788 106.43 CT 7.22 58.00 1.31 0.18 10.73 31.27 0.88 50.33 1.51 412 697 21

14/727 106.45 CT 7.88 61.48 2.18 0.28 12.56 25.96

14/728 106.63 CT 10.01 65.34 1.79 0.18 14.85 19.81

14/729 106.83 CT 7.44 65.41 1.47 0.20 11.18 23.41 1.06 53.89 1.75 417 725 24

14/730 107.04 CT 6.68 70.22 1.08 0.16 9.77 20.01

14/731 107.24 CT 6.45 58.18 1.38 0.21 9.81 32.01 0.92 48.51 1.73 416 752 27

14/732 107.47 CT 5.98 63.62 1.88 0.31 9.77 26.60

128

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/789 107.64 CT 5.48 66.07 1.50 0.27 8.71 25.22 0.59 41.41 1.51 413 756 28

14/733 107.67 CT 5.57 67.18 1.56 0.28 8.88 23.93 0.74 43.65 1.72 414 784 31

14/790 107.92 CT 9.22 70.61 1.21 0.13 13.18 16.22

14/734 108.18 CT 5.82 81.87 0.81 0.14 8.37 9.76

14/735 108.38 CT 4.23 83.10 0.67 0.16 6.17 10.73 0.62 35.42 1.70 413 837 40

14/736 108.58 CT 3.20 96.56 0.37 0.12

14/737 108.8 CT 10.41 62.52 1.52 0.15 15.05 22.43 1.85 82.60 3.25 412 794 31

14/738 109 CT 11.37 65.81 1.91 0.17 16.71 17.48

14/791 109.19 CT 8.37 51.27 1.83 0.22 12.78 35.95 1.09 67.46 3.00 412 806 36

14/739 109.22 CT 6.64 52.24 1.93 0.29 10.68 37.09

14/740 109.42 CT 5.72 57.37 1.36 0.24 8.85 33.77 0.60 36.22 1.47 413 634 26

14/741 109.64 CT 3.81 75.65 1.13 0.30 6.15 18.20

14/742 109.85 CT 4.31 68.26 1.07 0.25 6.72 25.02 0.59 36.87 1.78 414 856 41

14/743 109.9 CT 3.81 76.95 0.70 0.18 5.68 17.38

14/744 110.1 CT 9.40 53.24 1.50 0.16 13.73 33.03 1.07 61.34 2.61 419 653 28

14/745 110.31 CT 9.75 64.00 1.96 0.20 14.70 21.30

14/792 110.48 CT 8.71 53.98 1.80 0.21 13.19 32.83 1.09 65.42 2.85 413 751 33

14/746 110.51 CT 7.82 51.01 1.75 0.22 11.99 37.01 1.11 56.35 1.77 416 721 23

14/747 110.68 CT 10.39 61.81 2.00 0.19 15.56 22.63

14/748 110.92 CT 9.09 63.91 1.68 0.18 13.54 22.54 1.69 76.70 3.27 407 844 36

14/749 111.18 CT 7.05 74.87 1.46 0.21 10.68 14.45

14/793 111.34 CT 10.04 62.87 1.45 0.14 14.50 22.63 1.68 78.17 3.14 411 778 31

14/750 111.42 CT 9.34 61.11 1.76 0.19 13.95 24.94 1.12 63.10 2.79 414 676 30

14/751 111.66 CT 8.67 74.44 1.20 0.14 12.46 13.10

14/752 111.88 CT 4.77 88.82 0.81 0.17 7.03 4.14

129

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/753 112.08 CT 4.48 80.79 0.89 0.20 6.74 12.46 0.53 32.54 1.40 414 726 31

14/794 112.19 CT 8.74 61.28 1.31 0.15 12.68 26.05 1.02 67.11 2.88 411 768 33

14/755 112.56 CT 4.63 90.51 0.72 0.15 6.74 2.74

14/756 112.76 CT 4.32 91.43 0.61 0.14 6.22 2.34

14/757 112.95 CT 10.70 41.46 2.28 0.21 16.27 42.27

14/758 113.21 CT 10.14 1.97 0.19 1.30 72.17 2.67 412 712 26

14/759 113.41 CT 9.72 52.39 1.92 0.20 14.61 33.00

14/795 113.51 CT 8.82 62.31 1.43 0.16 12.91 24.79 1.07 68.60 2.99 412 778 34

14/760 113.58 CT 8.84 65.89 1.71 0.19 13.25 20.86

14/761 113.82 CT 8.04 73.92 1.41 0.18 11.89 14.19

14/762 114.02 CT 2.81 93.45 0.43 0.15 4.08 2.46

14/763 114.22 CT 1.71 100.14 0.28 0.17

14/764 114.42 CT 7.00 80.86 1.35 0.19 10.48 8.66

14/765 114.64 CT 12.74 49.60 2.13 0.17 18.73 31.67

14/766 114.82 CT 6.03 1.44 0.24 0.63 43.21 1.48 417 716 25

14/767 115.06 CT 4.93 68.28 1.18 0.24 7.65 24.06

14/584 115.17 UC 4.41 67.67 1.16 0.26 6.95 25.37 0.46 34.32 1.55 415 779 35

14/585 116.11 UC 7.24 64.91 1.58 0.22 11.05 24.03

14/586 117.03 UC 7.47 47.98 1.77 0.24 11.57 40.45 0.90 51.61 1.60 414 691 21

14/587 118.18 UC 8.13 64.40 1.56 0.19 12.17 23.43

14/588 118.9 UC 7.29 47.53 2.17 0.30 11.77 40.70 0.84 48.85 1.86 416 670 26

14/589 120.42 UC 3.04 80.05 0.76 0.25 4.75 15.21

14/590 121.18 UC 6.21 63.31 1.00 0.16 9.08 27.61 0.94 46.25 1.46 416 745 24

14/591 122 UC 4.76 59.46 1.09 0.23 7.32 33.21

14/592 123.25 UC 5.42 65.06 0.95 0.18 8.02 26.92

130

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/593 124.05 UC 8.19 60.63 1.30 0.16 11.96 27.41 1.26 65.12 2.87 415 795 35

14/595 126.155 UC 6.23 55.81 1.04 0.17 9.16 35.04 0.86 46.43 1.47 412 745 24

14/596 127.205 UC 6.84 45.69 1.48 0.22 10.43 43.88

14/598 129.04 UC 4.23 58.23 1.65 0.39 7.26 34.50

14/599 130.28 UC 6.40 56.68 1.92 0.30 10.36 32.96 0.73 44.89 1.50 418 701 23

14/600 131.13 UC 5.24 53.37 1.34 0.26 8.21 38.42

14/601 132.29 UC 5.27 69.61 0.94 0.18 7.82 22.57

14/602 133.36 UC 6.46 43.42 1.92 0.30 10.44 46.14

14/603 134.27 UC 7.55 64.54 1.39 0.18 11.24 24.22

14/604 135.26 UC 6.11 77.37 0.75 0.12 8.67 13.96

14/605 136.17 UC 5.09 56.37 1.17 0.23 7.84 35.79 0.46 36.26 1.46 414 712 29

14/606 137.09 UC 7.81 37.17 1.72 0.22 11.94 50.89

14/607 138.44 UC 2.24 78.56 1.27 0.57 4.30 17.14

14/608 139 UC 5.65 65.77 1.27 0.22 8.67 25.56

14/609 139.96 UC 3.96 85.16 0.62 0.16 5.77 9.07

14/610 141.22 UC 5.71 66.87 1.35 0.24 8.83 24.29

14/611 142.32 UC 8.10 46.28 1.35 0.17 11.90 41.82 1.94 63.80 2.97 417 788 37

14/796 142.7 UC 7.76 56.08 1.63 0.21 11.78 32.14

14/612 143.22 UC 4.13 54.76 1.35 0.33 6.81 38.42

14/613 144.48 UC 7.70 70.92 1.24 0.16 11.26 17.82

14/614 145.46 UC 3.84 77.66 0.77 0.20 5.78 16.56

14/615 146.63 UC 7.03 63.41 1.14 0.16 10.29 26.30

14/616 147.66 UC 5.11 39.77 1.28 0.25 7.98 52.24

14/617 148.43 UC 5.29 43.96 1.37 0.26 8.32 47.72 0.54 35.56 1.49 414 673 28

14/618 149.52 UC 6.07 35.47 1.44 0.24 9.40 55.13

131

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/619 150.23 UC 4.40 79.04 0.75 0.17 6.48 14.48

14/621 154 UC 4.04 78.09 5.19 16.73

14/622 156.33 UC 4.39 74.58 5.63 19.79

14/623 158.11 UC 4.80 63.56 0.87 0.18 7.12 29.32 0.99 35.91 1.47 415 749 31

14/624 160.12 UC 3.64

14/625 162.35 UC 3.73

14/628 168 UC 5.35 45.48 2.01 0.38 9.12 45.40 0.48 35.18 1.62 414 657 30

14/631 174.59 UC 2.56

14/632 176.31 UC 7.88

14/633 178.3 UC 4.78 55.43 1.10 0.23 7.36 37.21 0.54 32.36 1.56 416 677 33

14/638 187.92 UC 2.98 35.01 1.87 0.63 5.92 59.07 0.20 16.19 1.39 427 543 47

14/643 198.69 UC 3.39 25.97 1.06 0.31 5.54 68.49 0.40 22.20 1.54 420 654 46

14/644 200.69 UC 2.68 41.14 3.43 55.43

14/645 202.13 UC 4.10 41.49 5.26 53.25

14/647 206.83 UC 4.99

14/648 208.5 UC 4.91 55.27 0.94 0.19 7.35 37.38 0.40 31.47 1.43 422 641 29

14/649 210.42 UC 5.63

14/653 218.74 UC 5.42 36.64 1.05 0.19 8.12 55.24 0.47 34.04 1.66 418 628 31

14/658 228.07 LS 2.70 56.70 0.67 0.25 4.21 39.09 0.30 18.11 1.58 416 672 59

14/663 238.58 LS 2.36 49.85 0.70 0.29 3.81 46.34 0.21 12.37 1.45 425 524 62

14/668 248.26 LS 1.50 28.84 1.23 0.82 3.30 67.85 0.26 4.44 1.21 424 295 81

14/673 258.24 LS 2.12 51.54 0.55 0.26 3.32 45.13 0.13 9.95 1.53 425 471 72

14/678 268.5 LS 4.36 40.85 0.87 0.20 6.58 52.58 0.28 18.11 1.67 423 415 38

14/684 280.1 LS 1.38 20.82 0.42 0.30 2.24 76.94 0.08 4.41 1.58 427 319 114

14/689 290.23 LS 2.02 17.21 0.95 0.47 3.66 79.14 0.14 7.87 1.52 422 389 75

132

Table 4-1 continued


[m] (%) (%) (%) (%) (%) * * ** (°C) *** ****

14/694 300.2 LS 1.85 40.04 0.71 0.38 3.17 56.80 0.11 6.43 1.46 423 347 79

14/768 305.3 LS 1.86 50.47 0.53 0.29 2.99 46.55 0.11 7.42 1.19 424 398 64

14/770 315.14 LS 3.04 37.00 3.90 59.11 0.23 21.17 1.39 417 697 46

14/771 320.34 LS 4.54 73.29 0.70 0.15 6.60 20.11 0.47 29.05 1.49 417 640 33

14/772 325.77 LS 2.54 29.22 0.94 0.37 4.31 66.47 0.16 12.71 1.43 423 501 57

14/774 335.33 LS 0.82 37.84 0.55 1.67 60.49 0.06 1.51 1.27 424 208 176

14/776 345.055 LS 3.09 20.05 1.55 0.50 5.70 74.25 0.14 11.22 1.52 424 363 49

14/777 350.03 A 4.19 54.60 0.67 0.16 6.12 39.29 0.31 25.83 1.54 418 617 37

14/778 350.19 A 6.37 53.35 1.07 0.17 9.36 37.29 0.57 40.06 2.01 420 629 31

133

Fig. 4-5 Cross plots between CaCO3 versus TOC and TS. The correlation of CaCO3 and TOC relationship changes significantly from positive in the Lower Cenomanian to negative in the Turonian. The CaCO3 and TS correlations are always negative with variable regression coefficients.

134

Fig. 4-6 Elemental data versus depth shows increase in silicate and rutile forming elements with depth. It also shows a strong increase in P2O5 before the CTBE.

135

Fig. 4-7 CaCO3 versus Fe2O3 and TiO2 Cross plots show inverse relationship in all studied intervals.

Table 4-2 XRF data of selected samples from each stratigraphic units. T: Turonian, CT: CTBE, UC: Upper

Cenomanian, LC: Lower Cenomanian.

Table 4-2 Continued

Sample Depth Age SiO2 Fe2O3 TiO2 Al2O3 MnO MgO CaO Na2O K2O P2O5 Cr2O3

(m) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%)

14/1077 53.52 T 23.25 1.48 0.20 2.95 0.02 4.07 28.45 0.23 0.30 0.01

14/1113 88.70 T 3.78 0.10 0.02 0.01 0.33 52.19

14/1117 93.20 T 5.54 0.31 0.04 0.20 0.01 0.39 46.08

14/1118 94.45 T 19.98 1.55 0.09 2.12 0.01 0.30 33.28 0.24 0.33 0.01

14/782 100.92 CT 14.18 3.64 0.31 4.98 0.02 0.20 27.82 0.36 0.04

14/784 102.44 CT 9.58 0.54 0.06 1.20 0.01 0.25 43.39 0.00

14/794 112.19 CT 19.94 1.07 0.19 3.10 0.01 0.47 34.99 0.17 0.01

14 763 114.22 CT 6.91 0.11 0.02 0.34 0.02 0.55 73.64 0.08 0.01 0.11 0.01

14/766 114.82 CT 27.04 1.42 0.27 3.81 0.02 0.73 31.82 0.46 0.10 0.02

14/587 118.18 UC 13.57 1.20 0.11 2.07 0.01 0.32 39.47 0.06 0.01 0.06 0.01

14/598 129.04 UC 25.04 2.54 0.30 4.22 0.02 3.22 30.04 0.07 0.27 0.44 0.01

14/619 150.23 UC 12.67 0.99 0.12 1.81 0.02 0.94 42.91 0.06 0.01 0.06 0.01

14/628 168.00 UC 20.59 1.83 0.27 4.74 0.02 0.98 34.56 0.23 0.81 1.46 0.02

14/638 187.92 UC 30.10 4.82 0.41 9.12 0.04 4.65 19.07 0.08 3.09 0.20 0.02

136

Table 4-2 Continued

Sample Depth Age SiO2 Fe2O3 TiO2 Al2O3 MnO MgO CaO Na2O K2O P2O5 Cr2O3

(m) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%)

14/654 220.57 LC 27.18 1.38 0.39 4.47 0.02 0.85 45.86 0.08 0.45 1.78 0.02

14/668 248.26 LC 48.34 4.47 0.61 6.82 0.02 2.01 16.07 0.60 1.18 0.31 0.02

14/678 268.50 LC 23.92 3.09 0.40 10.09 0.03 1.48 28.49 0.29 0.65 0.23 0.01

14/768 305.30 LC 25.25 4.15 0.35 7.74 0.04 2.44 27.76 0.06 1.59 0.23 0.01

14/772 325.77 LC 45.55 2.84 0.52 6.93 0.03 1.73 19.34 0.06 2.02 0.17 0.01

14/776 345.06 LC 42.14 5.15 0.52 12.64 0.02 1.92 13.62 1.10 1.97 0.21 0.03

4.5.2 Rock-Eval Pyrolysis

Generally two groups can be distinguished along the analyzed sections (Table 4-1; Fig. 4-

8). The first group includes the majority of the lower Cenomanian samples, which show

moderate to high HI values (208–543mgHC/gTOC) whereas the rest of the samples

compose the second group displaying high to very high HI values of more than

600mgHC/g TOC. The Lower Cenomanian reveals the highest OI compared to the other

stratigraphic intervals, ranging from 32 to 176mgCO2/gTOC and averaging

67mgCO2/gTOC. Tmax is low with an average of 420ºC (Fig. 4-8). Most samples plot

between Kerogen type II and III when using the pseudo van Krevelen diagram (van

Krevelen, 1950; Peters, 1986) (Fig.4-8). The upper Cenomanian samples are

characterized by low S1 values, similar to the lower Cenomanian, but clearly higher S2

values averaging 38.7mgHC/g rock. Moreover, the OI and Tmax average 32mgCO2/gTOC

and 416ºC, respectively. Higher S1 and S2 values are observed in the CTBE samples

(average of 1mgHC/g rock and 55mgHC/g rock, respectively), whereas Tmax values are

low with an average of 412ºC. The thick Turonian section is also composed of sediments

having high HI, S1 and S2 values. S2 decreases toward the younger sediments and Tmax

averages 411ºC (Fig.4-9). Most of the samples plot between Kerogen type I and II in the

pseudo van Krevelen diagram (Fig.4-8)

137

Fig. 4-8 Pseudo van Krevelen diagram of bulk Rock- Eval-6 samples of the various stratigraphic intervals.

0

100

200

300

400

500

600

700

800

900

1000

0 20 40 60 80 100 120 140 160 180 200

Hy

dro

gen

In

dex

[m

g H

C/g

TO

C]

Oxygen Index [mg CO2/g TOC]

Turonian

CTBE

Upper Cenomanian

Lower Cenomanian

Type I

Type II

Type III

138

Fig. 4-9 Rock-Eval HI, OI and Tmax versus depth plot. It shows the apparent difference between the Cenomanian to Turonian source rocks. On the basis of microscopic observations the Tmax shift is interpreted to be caused by a change in the organic facies rather than thermal maturity.

4.5.3 Organic Petrology

The maceral counting reveals at least 4 different organic facies all dominated by marine

organic matter (Table 4-3; Fig. 4-10). All samples show a dominance of submicroscopic

Unstructured Organic Matter (UOM) with alginites/liptodetrinites constituting the

majority of the visible macerals (Figs. 4-10; 4-11). These macerals show strong yellow

fluorescence and are classified based on their morphology: i) litptodetrinite (granular

particle usually of less than 5μm in length), ii) lamalginite (thin elongated particles) and

iii) telalginite (well preserved oval algal particles that originate from large colonial or

thick walled unicellular algae; Hutton 1987, Senftle et al., 1993; Taylor et al., 1998).

139

Fig. 4-10 Micrograph of representative samples of each organofacies type and stratigraphic interval.

140

Table 4-3 Maceral compositional analysis data. *: Calculated, submicroscopic organic matter. T: Turonian, CT: CTBE, UC: Upper Cenomanian, LC: Lower Cenomanian.

Sample Depth Age TOC Liptodetrinite Lamalginite Telalginite Bituminite II UOM *

(m) (wt. %) (vol.%) (vol.%) (vol.%) (vol.%) (vol.%)

14/1052 28.6 T 5.30 1.47 0.47 0.07 3.89 11.30

14/1069 45.53 T 14.19 0.57 1.78 0.09 6.98 36.64

14/1079 56.09 T 13.34 1.37 0.70 0.09 7.88 33.27

14/1089 65.02 T 9.99 0.42 0.80 0.05 7.92 23.24

14/1099 75.09 T 9.57 1.32 0.54 0.04 8.44 20.71

14/1109 85.15 T 12.61 2.22 0.63 0.04 9.16 28.89

14/1121 97.46 T 15.36 3.40 1.43 0.05 1.18 43.83

14/1124 99.98 T 12.20 2.89 1.45 0.13 1.64 33.49

14/782 100.92 CT 15.44 1.36 1.09 0.08 0.42 47.19

14/704 101.7 CT 13.23 0.00 0.00 0.00 0.00 42.95

14/783 101.67 CT 12.59 0.78 0.63 0.00 1.37 38.09

14/784 102.44 CT 7.62 0.69 0.76 0.09 1.40 21.79

14/785 103.66 CT 6.27 0.00 0.00 0.00 0.00 20.37

14/786 103.97 CT 9.29 0.15 0.21 0.05 0.67 29.07

14/787 105.62 CT 8.86 0.00 0.00 0.00 0.00 28.77

14/788 106.43 CT 7.22 0.00 0.00 0.00 0.00 23.45

14/789 107.64 CT 5.48 0.00 0.00 0.00 0.00 17.81

14/790 107.92 CT 9.22 0.00 0.00 0.00 0.00 29.95

14/791 109.19 CT 8.37 0.00 0.00 0.00 0.00 27.17

14/792 110.48 CT 8.71 0.00 0.00 0.00 0.00 28.28

14/793 111.34 CT 10.04 0.00 0.00 0.00 0.00 32.60

14/795 113.51 CT 8.82 0.00 0.00 0.00 0.00 28.62

14/585 116.11 UC 7.24 0.92 0.78 0.09 0.73 20.97

14/590 121.18 UC 6.21 0.00 0.00 0.00 0.00 20.15

14/623 158.11 UC 4.80 0.00 0.00 0.00 0.00 15.57

14/633 178.3 UC 4.78 0.00 0.00 0.00 0.00 15.52

14/648 208.5 UC 4.91 0.00 0.00 0.00 0.00 15.94

14/658 228.07 UC 2.70 0.00 0.00 0.00 0.00 8.75

14/673 258.24 LC 2.12 0.00 0.00 0.00 0.00 6.87

14/689 290.23 LC 2.02 0.00 0.00 0.00 0.00 6.56

14/771 320.34 LC 4.54 0.00 0.00 0.00 0.00 14.73

141

Fig. 4-11 Organic matter volume vs. TOC weight percent. The samples that show very low visible organic matter were assigned as 0.2% for the sake of simplicity.

Bituminite differs from alginite by the lack of recognized shape and reddish to dark

brown fluorescence (Teichmüller and Ottenjann, 1977; Taylor et al., 1998). Bituminite

occurs in form of lenses of irregular shape (bituminite I) and as matrix bituminite which

mergers with the groundmass (bituminite II) both showing a dark, reddish florescence

(Creaney, 1980; Taylor et al., 1998). In this study bituminite II constitutes the major

bituminite maceral. UOM is present to a great extent in a form that cannot be recognized

by incident light microscopy, ie. size is smaller than 1μm. The strong fluorescence of the

groundmass indicates the presence of this submicroscopic organic matter. The lower

Cenomanian differs from the younger samples in the lack of bituminite (Fig. 4-10). It

shows a strong bright yellow fluorescing ground mass. The Turonian samples are

moderate in reddish groundmass and have nearly no visible organic matter. Similar

characteristics are found in the samples representing the CTBE, but with more reddish

groundmass and bituminite. The Turonian samples are enriched in bituminite, with rapid

increase towards younger samples. Similarly the alginite macerals are most abundant in

the younger samples. Vitrinite and inertinite are very rare throughout the investigated

section with a relative increase in the lower Cenomanian samples. But even combined

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they do not exceed 1vol-%. In summary, the microscopic observation classifies the source

rock into 4 types which are: i) bituminite-free source rock with yellowish fluorescing

submicroscopic OM (characterizes the lower Cenomanian), ii) bituminite-fair source

rock with rare alginite and weak reddish fluorescing submicroscopic OM (characterizes

the upper Cenomanian to lower Turonian), iii) source rock with no visible OM

(characterizes few samples representing the CTBE), and iv) bituminite-rich with fair

visible OM and strong reddish fluorescing submicroscopic OM.

4.5.4 Molecular Geochemistry

Almost all samples analyzed showed pristane and phytane predominance over the

adjacent n-alkanes. The samples representing the CTBE show elevated n-C16 to n-C19 and

low pristane/phytane (Pr/Ph) ratios, lower than in the other intervals (Fig. 4-12). The

samples also show the elevated concentrations of methylated hopanes (C1-Hop) that

coelute with non-methylated hopanes, and a fair percentage of C1-Hop that averages

~20% (of total hopanes) decreasing towards the younger samples (Table 4-5). The C27,

C28 and C29 steranes show similar characteristics and equal proportions for all samples,

plotting within a narrow area (Fig. 4-13). The C28/C29 steranes ratio varies slightly

throughout the section but never exceeds 1.05. All samples show sterane/hopane ratios

greater than 1% except for two samples at the top of the section.

Fig. 4-12 Pr/C17 vs. Ph/C18

diagram suggests marine and thermally immature organic matter for all sample. The classification method is from Shanmungam (1985).

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Fig. 4-13 C27-C29 steranes ternary diagram indicates shallow open marine depositional environment.

Table 4-4 Molecular geochemistry data of the aliphatic fractions.

Table 4-4 Continued

Sample Depth Age Ster/Hop Pr/Ph C28/C29str Pr/n-C17 Ph/n-C18 M-Hop/total Hop

14/1099 75.09 T 1.06 0.36 0.66 2.82 9.40 0.31

14/1119 95.37 T 1.30 0.55 0.54 4.37 9.05 0.29

14/782 100.92 CT 0.66 0.71 0.72 6.45 8.99 0.23

14/783 101.67 CT 0.90 0.85 0.86 4.55 6.71 0.17

14/784 102.44 CT 1.13 0.66 0.90 9.82 15.27 0.18

14/785 103.66 CT 1.49 0.88 0.84 8.61 7.10 0.21

14/786 103.97 CT 1.61 0.56 0.75 5.54 11.62 0.17

14/787 105.62 CT 1.22 0.63 0.97 6.05 10.60 0.25

14/788 106.43 CT 1.99 0.45 1.05 6.14 12.16 0.22

14/789 107.64 CT 1.70 0.55 0.83 5.75 9.89 0.25

14/790 107.92 CT 1.49 0.39 0.85 4.26 7.75 0.21

14/791 109.19 CT 1.62 0.37 0.93 5.59 9.39 0.25

14/792 110.48 CT 1.26 0.33 0.92 4.34 10.59 0.27

14/794 112.19 CT 1.17 0.37 1.06 4.34 10.10 0.26

14/795 113.51 CT 1.26 0.34 0.84 5.59 10.80 0.29

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Table 4-4 Continued

Sample Depth Age Ster/Hop Pr/Ph C28/C29str Pr/n-C17 Ph/n-C18 M-Hop/total Hop

14/586 117.03 UC 1.08 0.46 0.80 4.27 10.51 0.27

14/590 121.18 UC 1.41 0.45 0.93 3.80 10.00 0.30

14/593 124.05 UC 1.20 0.54 1.01 7.15 14.26 0.32

14/653 218.74 UC 1.40 0.77 1.08 4.11 8.29 0.32

14/658 228.07 LC 0.66 1.19 3.30 6.90

14/663 238.58 LC 0.98 1.29 0.90 3.82 4.75 0.35

14/673 258.24 LC 0.74 1.20 4.57 6.57

4.5.5 Curie-Point-Pyrolysis Gas Chromatography-Mass Spectrometry

All samples show an elevated abundance of thiophenes (Table 4-5). The

thiophenes/benzenes ratio shows very low values for the lower Cenomanian (0.98) then

it increases to peak during the CTBE (8.06) and decreases slightly throughout the

Turonian with values above 5.00.

Table 4-5 Total thiophenes/total benzenes data from CPPyGCMS data used as a proxy of Sorg/Corg

Sample Depth (m) Age Total thiophenes/Total benzenes

14/1077 53.52 Turonian 5.54

14/1085 61.40 Turonian 4.35

14/1105 80.08 Turonian 8.18

14/1113 88.70 Turonian 5.12

14/1117 93.20 Turonian 6.26

14/1118 94.45 Turonian 7.06

14/782 100.92 CTBE 5.30

14/705 101.89 CTBE 8.06

14/715 104.02 CTBE 5.35

14/598 129.04 upper Cenomanian 3.81




14/673 258.24 lower Cenomanian 3.76




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4.6 Discussion

4.6.1 Depositional environment

Organic petrology investigation clearly reveals that the samples are dominated by UOM

and liptinite macerals indicating an aquatic, marine environment. The major element

data reveal that the lower Cenomanian is rich in silicate minerals and rutile combined

with elevated Fe2O3, SiO2, Al2O3, K2O and TiO2 concentrations indicating more

terrigenous input as compared to the overlying, younger units which are carbonate-

dominated (Fig. 4-6). All samples, especially those representing the CTBE are poor in

MnO, indicating anoxic bottom water conditions (Calvert and Pedersen, 1993; Aquit et

al., 2013 Moreover, phosphorous deposition decreases during increasing anoxic bottom

water conditions. Simultaneously the increased availability of phosphorus in the upper

water column increases the productivity which further results in declining the bottom

water oxygen (Calvert et al., 1996). Phosphorus usually peaks before the onset of an OAE

and retains to its background values after the end of the event (Mort et al., 2007; Jenkyns,

2010). In this well, phosphorous shows elevated values prior to, very low value within

and slightly elevated values above the CTBE supporting the previously described

hypothesis (Fig. 4-6). Similar observations of elevated P concentrations were found by

Mort (2006) in the Cenomanian of the Mohammed Plage section (Mpl; Fig. 4-1) and by

Nederbragt et al. (2004) in the S13 well. Elevated P concentrations prior to the onset of

the OAE2 are characteristic of equatorial shelves of the Mid-Cretaceous Proto-Atlantic

Ocean as suggested by Kraal et al. (2010). These regional data are in accordance with the

results in the current study.

Molecular geochemistry data provides excellent environmental indicators. Various

different parameters have been used. Pristane (Pr) and phytane (Ph) are two of the most

prominent isoprenoids in petroleum samples that originate partly from the phytol side

chain of chlorophyll a (Brooks et al., 1969; Powell and McKirdy, 1973; Didyk et al., 1978).

Depending on the oxygen availability the diagenesis of phytol leads either to pristane

under more oxic conditions or to phytane under more anoxic conditions (Koopmans et

al., 1999; Peters et al., 2005). Therefore, the Pr/Ph ratio has been widely used to

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characterize the depositional environment (Brooks et al., 1969; Didyk et al., 1978; ten

Haven et al., 1987; Powell, 1988). Pr/Ph ratios lower than 1.0 usually indicate anoxic,

marine carbonate lithology and values from 1.0 to 1.5 marine shale lithology. Values

higher than 2 indicate deltaic shales or terrestrial environments (Peters et al., 2005).

Furthermore, the correlation between the Pr/n-C17 and Ph/n-C18 is used to indicate in

more detail kerogen types, depositional environments, thermal maturity and

biodegradation (Peters et al., 2005). n-Alkane distribution can also be indicative of

organic matter input. For example, high abundance of n-C15 to n-C21 (at low thermal

maturity) indicates marine algae and high abundance of n-C25- n-C31 indicates vascular

plant inputs (Yunker et al., 2005). Using these molecular indicators the following sample

characterizations can be deduced. The lower Cenomanian samples show Pr/Ph ~1

indicating marine shales and probably more oxic conditions compared to the other

samples in this study (Table 4-4). These samples have a TOC of ~2%, HI values of about

500mgHC/TOC and relatively high OI values. Sample 14/653 from the lower/upper

Cenomanian boundary shows Pr/Ph lower than 1.0 indicating a change in the

depositional environment. All these data suggest that a marine siliclastic depositional

environment dominated in the lower Cenomanian, which later shifted to a more

carbonate-dominated system. This is in agreement with the elemental data discussed

before.

In the upper Cenomanian, Pr/Ph ratios decrease significantly towards the CTBE to

descend below 0.32 within it. Higher values occur at the end of the CTBE but remain

below 0.8, indicating strong anoxic conditions during the CTBE (Table 4-4), which

support the OAE theory (i.e. Jenkyns, 2010; Sachse et al., 2014). The correlation between

Pr/n-C17 and Ph/n-C18 also indicates the presence of marine organic matter as well as

anoxic bottom water conditions (Fig. 4-12). All samples are also characterized by

dominance of n-C16 to n-C19 indicating a major contribution from algae (Cranwell et al.,

1987). Pr and Ph occur at higher concentrations than the n-alkanes, which could indicate

either biodegradation or very low thermal maturity (Fig. 4-12). Biodegradation is

possible as the samples were taken from relatively shallow depth between 24 and 350m.

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Furthermore, the geothermal gradient in the Tarfaya Basin is 25°C/km (Zarhloule, 2003)

and the average surface temperature is ~19°C implying that the samples are exposed to

temperatures of 19 to 27°C. Additionally, the water table in the basin is presently at a

depth of approximately 30m (Zarhloule, 2003) and could act as a supplier for nutrients.

These conditions favor biodegradation. However, biodegradation is not severe as the n-

alkanes are preserved in relatively high abundance and only a small proportion of

unresolved complex organic material was observed (Hedges et al., 2000). Sachse et al.

(2014) made similar observations of high abundance of Pr and Ph in samples from the

younger OAE3 interval in the Tarfaya Basin. Cenomanian and Turonian outcrop samples

from the current well vicinity is also similar to the samples in this study, but with more

terrigenous characteristics. A reason for this might be the fact that the outcrop samples

represent a more proximal area than the samples in this study. Kolonic et al. (2002) and

Kuypers et al. (2004; S13 well) (Fig. 4-1) briefly discussed the Pr and Ph geochemistry as

well and obtained results similar to those of the CTBE samples in this study. Based on

their conclusions and in combination with the new results presented in this study, a low

thermal maturity is seen as the most probable explanation for the high Pr/n-C17 and

Ph/n-C18 ratios. An alternative is the contribution of N2-fixing cyanobacteria that contain

chlorophyll a (Ohkouchi et al., 2006; Ricci et al., 2014; see below). The last possible

explanation for this phenomenon is that kerogen sulfurization and associated chemical

reactions at early diagenesis led to the elevation of phytane and accordingly the pristane

High ratios of steranes to hopanes indicate marine organic matter predominance (Peters

et al., 2005). The CTBE samples have sterane/hopane ratios greater than 1.0 indicating

dominance of marine algae. This supports the results of the maceral analysis, which show

a dominance of alginite, but it should be noted that the major part of the organic matter

is submicroscopic. C27-C29 steranes provide another useful tool to obtain information on

the depositional environment and source of kerogen (Fig. 4-13). High abundance of C28

usually characterizes marine samples (Peters, et al., 2005). Our data indicate that the

source rocks were deposited in an open to shallow marine/coastal environment and

agrees with results from Sachse et al. (2011) for outcrop samples from the Cenomanian

and Turonian.

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Methylated hopanes are used as biomarkers for oxygen-producing and N2-fixing

cyanobacteria and thus the methylated hopanes/hopanes ratio is regarded as a good

environmental indicator (Summons et al., 1999; Kuypers et al., 2004b; Peters et al., 2005;

Ricci et al., 2014). The cyanobacteria are a diverse group of prokaryotes and contain

chlorophyll a, generating oxygen by photosynthesis (Ohkouchi et al., 2006; Ricci et al.,

2014). They have no common microscopically identifiable fossils but only molecular ones

(Kuypers et al., 2004b). Many of them have the ability to fix N2 (Ohkouchi et al., 2006).

Moreover, Kuypers et al. (2004b) and Jenkyns (2010) proposed that cyanobacteria

played a major role in the nitrogen cycle and suggested that cyanobacteria were key

players during the Cretaceous. Very low methylated hopanes concentrations (<2.0% of

total hopanes) typify the samples up to the Jurassic with few exceptions. In contrast, the

CTBE samples and the samples from the underlying and overlying Cretaceous units from

well SONDAGE-4 show high ratios of methylated hopanes/hopanes indicating

concentrations up to 20% (Table MG) which are in line with earlier studies on Cretaceous

black shales (Kuypers et al., 2004a).

Translating these ratios into a percentage contribution of cyanobacteria is certainly

difficult and only vague. In view of the sterane/hopane ratios (Table 4-4), n-alkane

pattern, and isoprenoid/n-alkane ratios (Fig. 4-12), and the high HI values of Rock-Eval

pyrolysis we can assume that marine phytoplankton was the major contributor to the

organic matter, but that both bacteria and cyanobacteria provided additional important

pools of the total organic matter, whereas terrigenous contribution was small, which is

also supported by microscopic observations (Fig. 4-10).

Under anoxic depositional environment, sulfate reducing bacteria obtain energy by

oxidizing organic compounds and reducing SO4-2 to yield HS-1, HCO3-1 and remaining non-

metabolizable organic matter (Leventhal, 1982; Schulze and Mooney, 1993). These

organic residues will constitute the preserved organic carbon in the sediments upon

burial (Morse and Berner, 1995). The resulting HS-1 in combination with Fe from pore

water or clay will form pyrite (Leventhal, 1982; Berner and Raiswell, 1983; Berner, 1984;

Raiswell and Berner, 1986; Dean and Arthur 1989; Schulze and Mooney 1993; Morse and

149

Berner, 1995; Leventhal, 1995). The ratio between the preserved organic carbon and

total sulfur (TOC/TS) is used to determine the palaeo-depositional environment (Berner,

1984). Sediments deposited under normal marine conditions (oxic water and typical

ocean water salinity) will have a TOC/TS ratio of about ~2.8. Higher and lower values

characterize lacustrine and euxinic depositional environments, respectively (Berner,

1984), but iron limited carbonate-dominated depositional environments with high

organic carbon percentages can also lead to low TOC/TS ratios (Bou Daher et al., 2014,

2015). However, several factors that control the organic carbon and pyrite formation

need to be taken into considerations before using the methods based on Berner (1984).

These factors are: i) the presence of metabolizable versus nonmetabolizable organic

matter (type of organic matter), ii) the portion of organic matter that metabolizes

through sulfate reduction, iii) the portion of reduced sulfide that is oxidized and not

converted to pyrite, iv) the availability and reactivity of reactive detrital iron minerals

that react with excess hydrogen sulfide in the system to create pyrite, and v) the

sedimentation rate (Leventhal, 1982; Berner and Raiswell, 1983; Berner, 1984; Raiswell

and Berner, 1986; Littke et al., 1991; Schulze and Mooney 1993; Canfield, 1994;

Leventhal, 1995; Morse and Berner, 1995). In highly calcareous sediments the amount of

detrital iron minerals is very limited which results in forming less pyrite than it is

expected under normal marine conditions even at high organic carbon contents (Berner,

1984; Raiswell and Berner, 1986; Dean and Arthur, 1989; Bou Daher et al., 2015).

Moreover, at high sedimentation rates, the bottom water oxygen content has negligible

influence on organic carbon preservation whereas at low rates only euxinic, oxygen-free

bottom water conditions allow for excellent preservation (Canfield, 1994). In the Tarfaya

samples, TS generally correlates positively with TOC (Fig. 4-14). Most of the samples plot

below the normal marine trend line (Berner, 1984) except the samples low in carbonate

content, in particular the lower Cenomanian samples. This is similar to other marine,

carbonate-rich successions, where the detrital iron supply was limited and thus less

pyrite formed (Kolonic et al., 2002; Sachse et al., 2011; Bou Daher et al., 2015).

150

Fig. 4-14 TS versus TOC cross-plot shows that the majority of the Cenomanian to Turonian samples are plotted below the normal marine line of Berner (1984) unlike the majority of the Lower Cenomanian samples which plot above the line

To further explore the relationship between Fe, TS and TOC, the relationship between

sulfur and iron content is displayed in Figure 4-15. The TS to Fe stoichiometric ratio is

1.15 and plotted as “pyrite line” (Worthmann et al., 1999). The samples of the lower

Cenomanian have excess of Fe which holds also true for one of the upper Cenomanian

samples (Fig. 15). All younger samples either plot close to the pyrite line or have excess

of sulfur indicating the presence of other forms of sulfur such as organic sulfur. This

conclusion is supported by the high thiophenes/benzenes ratio derived from the CP-Py-

GC-MS data characterizing in particular the CTBE samples (Table 4-5). All samples from

the CTBE show no visible organic matter (Fig. 4-11) possibly indicating that conversion

of organic matter into sulfur-bearing kerogen went along with a physical degradation and

loss of biogenic morphology of organic particles.

In the process of forming pyrite, 2 moles of organic carbon is required to form one mole

of reduced sulfur (Dean and Arthur, 1989; Littke et al., 1991). This means that the original

organic carbon content was higher before sulfate reduction, which can be easily deduced

from sulfur values versus depth profiles within young, marine sediments: at the

sediment/water interface, TOC/TS is very high reaching a quite stable value close to 2.8

only at the base of the sulfate reduction zone within the sediments (Littke et al., 1997).

151

In order to obtain the original organic carbon (before sulfate reduction) the following

equation was introduced by Littke (1993):

TOCoriginal= TOC+2S *Mc/Ms

Where the Mc and Ms are the molecular weight of carbon and sulfur respectively.

Subsequently the values of original weight percent of organic matter can be determined

using:

OM= TOCorignal * 100/COM

Where COM is the carbon content of organic matter.

Fig. 4-15 TS versus Fe shows that the majority of the samples from Cenomanian to Turonian are plotted above the Pyrite line indicating that the sulfur in theses samples is present in other forma than pyrite.

Using this value along with the carbonate content we can calculate the silicate content by

subtracting the sum of the organic matter and carbonate from 100. Thus the

synsedimentary system of petroleum source rocks can be represented based on the three

major components in a triangular plot (Fig. 4-16). Limitations of this method are

discussed in Littke (1993).

A negative correlation is observed in carbonate-rich samples (CaCO3>70%) between

CaCO3 and TOC (Fig. 4-16; see also Fig. 4-5), especially for the CTBE and Turonian. This

may occur because in a carbonate-dominated environment, enhanced silicate content

152

goes along with enhanced nutrient supply and thus bioproductivity leading to higher

organic matter. In contrast, the low-carbonate lower Cenomanian samples show a

positive correlation between CaCO3 and TOC, similar to younger, Santonian samples from

the Tarfaya Basin (Sachse et al., 2014), indicating that during this episode (lower

Cenomanian), nutrient supply was not a limiting factor for organic matter accumulation

(see Kuhnt et al., 1997).

4.6.2 Source rock potential and organic matter type

Various geochemical techniques were used to evaluate the oil shale and petroleum

source rock potential for the samples from the Cenomanian and Turonian, following

guidelines on usage of Rock-Eval pyrolysis data by Peters (1986). However, based on

Rock-Eval parameters a differentiation between kerogen type II and kerogen type IIS is

not possible. Hence, the CPPyGCMS data provide a useful tool to define the kerogen more

precisely and to assess the kerogen Sorg/Corg ratio. The lower Cenomanian samples show

very good source rock richness and quality yet the least source rock potential and organic

matter quality among the other sections (Figs. 4-4; 4-9). In particular, the section

between 315.0 and 345m shows very good source rock richness and quality with

potential for generating oil at higher maturity. Two samples were analyzed by CP-PY-GC-

MS showing low Sorg/Corg ratios. Moreover, the majority of the investigated samples show

a lack of bituminite, predominance of UOM associated with alginite and rare vitrinite and

inertinite (Fig. 4-10). This indicates along with the Rock-Eval data that these samples

contain kerogen type-II with some of the lower Cenomanian samples containing mixed

types II/III (Fig. 4-8). In addition, the Sorg/Corg are low compared to the younger sections.

All maturity parameters suggest that these source rocks are immature.

The upper Cenomanian source rocks have an even greater source rock potential than the

lower Cenomanian especially toward the CTBE showing higher TOC and HI values (Figs.

4; 9). With respect to mineralogy, the Cenomanian gently shifts from silicate- to

carbonate predominance with highest OM richness occurring when the carbonate

content is between 45% and 80% (Fig. 4-16). The samples evaluated by microscopy show

that the majority of the organic matter is unstructured with rarely visible liptinite

153

macerals (Fig. 4-11). The samples also show a presence of bituminite matrix in fair

abundance (Fig. 4-10C). Pyrolysis data suggest strong presence of thiophenic sulfur

compounds compared to the lower Cenomanian indicating the presence of considerable

amounts of organic sulfur, i.e. kerogen Type IIS. Based on Tmax and molecular

geochemistry these samples are immature.

The Turonian samples are similar to those of the CTBE, but with somewhat lower Sorg.

They also differ from the CTBE in organic matter type especially in the younger interval

(Turonian), where a high amount of bituminite is observed as well as alginite (Fig. 4-

10A).

Fig. 4-16 OM-CaCO3-Silicates trinary diagram (modified after Littke, 1993) showing that the best organic preservation is achieved at CaCO3 concentration between 45 to 80%.

Oil generation potential of the entire sequence is very high, with a tendency of sulfur-rich

oil being generated especially within the CTBE. Sulfur-rich kerogen is known to generate

first petroleum at lower temperatures than sulfur-poor kerogen (Pepper and Corvi,

1995). In comparison with literature data compiled in Wenke (2014) for the on-offshore

Tarfaya Basin, the sample set supports the excellent source rock potential of the Late

Cretaceous. Increasing amounts of OM were measured in the onshore area, whilst very

high amounts have not been reported for the offshore area (Wenke, 2014). TOC values

average 3% and HI values of 140-400mgHC/gRock were published (Wenke, 2014).

154

Moderate-high values of 0.8 to 4% TOC were measured on the shelf (HI 150-

400mgHC/gRock), and up to 6% on the slope (Wenke, 2014). The CTBE source rocks are

globally distributed and studied in great detail in North Africa and Mid-Atlantic regions

(e.g. Herbin et al., 1986; Schlanger et al., 1987; Foster et al., 2004; Lüning et al., 2004;

Jenkyns, 2010). All of the above mentioned studied locations exhibited high TOC values

within wide ranges based on the depositional environmental conditions. Limited

information is available on the kerogen sulfurization during the CTBE, but TS

enrichments were recorded widely during this time.

Two Albian samples show an excellent source rock potential (Table 4-1). Due to the low

number of samples only Rock-Eval and TOC analyses were conducted with no further

geochemical investigation. Nevertheless, the available data support the general idea of

an Albian source rock in the Tarfaya Basin. Wenke (2014) related the increasing source

rock potential during the Albian to the termination of the TanTan Delta. This also matches

with results of Sachse et al. (2011), who identified the Albian source rock further onshore

as being only of marginal quality (low TOC and HI). Thus, a high variation of organic

matter quantity and quality based on the spatial and temporal distribution of the Albian

deposits can be assumed.

4.6.3 Kerogen diagenesis and properties

The formation and preservation of kerogen results from two main pathways which are:

i) the selective preservation and ii) degradation-recondensation pathways (Largeau and

Derenne, 1993). The first pathway is based on the existence of the insoluble and non-

hydrolysable macromolecules in the outer walls of the original species (Derenne et al.,

1992) that is resistant to microbial and chemical alteration at the diagenesis stage. The

second pathway for kerogen formation is a complete restructuring of the organic matter

due to degradation followed by recondensation (Welte, 1972; Tissot and Welte, 1984;

Largeau and Derenne, 1993; Taylor et al., 1998). The lack of resistant macromolecules

will result in the formation of the unstructured organic matter (UOM) (Largeau and

Derenne, 1993). One essential mechanism destroying the morphology of organic matter

is the early diagenetic vulcanization process which is related to sulfur incorporation into

155

the organic matter (Taylor et al., 1998). Moreover, cyanobacteria through selective

preservation pathway could result in UOM (Pacton et al., 2006). The samples from the

upper Turonian to Cenomanian show high Sorg/Corg values and high proportions of

amorphous kerogen with extreme abundance in the samples representing the CTBE.

These samples have high Sorg/Corg values and lower amorphous kerogen abundance in

the upper section, indicating early diagenetic reactions between sulfur and organic

matter. De Leeuw and Sinninghe-Damsté (1990) showed that reaction between H2S or

HSx - with phytolesters or phytol will result in thiol which will react with the

functionalities of other compounds to produce larger materials. This process saves

phytol precursors from degradation in the upper part of the sediments. With increasing

diagenesis the C-S bonds are cleaved and phytane is generated after hydrogenation of

intermediate phytenes and phytadienes.

Littke and Sachsenhofer (1994) showed that source rocks from upwelling areas are

generally characterized by dominance of UOM associated with small particles of alginite

and rare terrestrial organic matter. This hypothesis fits perfectly the studied samples

which are clearly dominated by submicroscopic organic matter.

4.7 Conclusions

Rock-Eval and elemental analysis results reveal excellent source rock potential for the

entire, thick lower Cenomanian to Turonian section. Based on Rock-Eval evaluation,

there are two main groups of source rocks which are i) moderately high in TOC and HI,

comprising the lower Cenomanian and ii) high in TOC and HI from the upper Cenomanian

to Turonian.

Organic matter characterization based on molecular geochemistry shows a marine origin

for the organic matter in the Cenomanian to Turonian samples. This is supported by

microscopic analysis that suggested predominance of UOM associated with alginite and

rare vitrinite and inertinite. The samples show different levels of kerogen sulfurization

depending on the depositional environment. Therefore, the samples are classified based

on the organic sulfur content as i) Sorg-rich (Sorg/Corg =5-8), i.e. the CTBE and Turonian

156

samples, ii) Sorg-moderately rich (Sorg/Corg ~3.5), i.e. the Upper Cenomanian and iii) Sorg-

poor (Sorg/Corg <1), i.e. the lower Cenomanian.

The upper Cenomanian to Turonian are characterized by relatively high carbonate

content and the samples from the lower Cenomanian are characterized by high silicate

content. The highest organic matter content is found when the carbonate content is

between 50 to 80 %. All samples were deposited under anoxic conditions with the highest

oxygen depletion occurring during the CTBE based on biomarker data, coupled with high

sea water temperatures.

Samples younger than the silicate-rich lower Cenomanian interval are expected to

generate sulfur-rich oil. In conclusion, the integrated study elucidates possible processes

leading to the source rock development and kerogen formation within the Cenomanian

and Turonian section. Furthermore, it supports the idea of an Albian source rock

potential in the Tarfaya Basin, which seems, however, relatively local. The study

investigated the relative organic sulfur enrichment which is of great importance, e.g. for

the oil shale retorting. Further quantitative analyses are highly recommended on this

aspect.

157

Chapter 5

Chapter 6 | Thesis General Discussion

5.1 Introduction

The previous three studies elucidated variable source rock types in three different

shallow marine settings. This chapter attempts to combine the data from these studies to

assess the changes in source rock depositional environments from proximal to distal

settings. The investigation is based on three main controlling factors that determine the

source rock characteristics. These factors are terrigenous and biogenic fluxes and

diagenetic processes. The results will be summarized in a conceptual geochemical model.

The second aim of the current investigation is to find new relationships between

elemental data and organic matter types, productivity and preservation which

potentially will lead to a better prediction of source rocks facies in petroleum basins.

5.2 Studied Parameters

The parameters are classified into three types which are terrigenous, biogenic and

diagenetic proxies (Fig. 5-1). To verify the terrigenous origin of the investigated

elements, they were plotted against Al2O3. The elements that positively correlated with

Al2O3 are considered terrigenous and include TiO2, Fe2O3, K2O and MnO (Fig. 5-2). The

biogenic parameters indicate organic fluxes to the ocean bottom. They include TOC, HI,

OI, Tmax, and CaCO3. The SiO2 can be from terrigenous or biogenic inputs. Therefore, it is

excluded from the comparisons. The diagenetic process parameters correspond to ratios

or proxies that indicate reactions that occur due to various bottom water conditions.

They include Pristane/Phytane, thiophenes/benzenes, S/Fe and Mn/S ratios.

158

Fig. 6-1List of the investigated terrigenous, biogenic and early diagenesis geochemical parameters.

Fig. 6-2 Al2O3 versus K2O, TiO2, MnO and Fe2O3 cross-plots. Note the positive correlations indicating similar terrigenous origin.

Terrigenous

Al2O3

Fe2O3

K2O

TiO2

MnO

Biogenic

TOC

CaCO3

HI

Tmax

OI

Early diagenesis

S/Fe

Pr/Ph

Thiophenes/Benzenes

Mn/S

159

5.3.1 Sedimentation systems and organic matter productivities

The ternary diagram by Littke (1993) (CaCO3-OM-Silicates) is used to indicate the

difference in the organic matter richness at variable carbonate-silicates ratios. A detailed

explanation of the concept is provided in Chapter 4. The Nile Delta samples which

represent a proximal depositional setting (Group-A; Fig. 5-3) show low carbonate

contents as typical of fluvial-deltaic settings. This setting is characterized by TOC values

range from ~ 0.5 to 3.5%. On the other hand, the Abu Gharadig Basin excluding the Abu

Roash “F” Member showed almost constant original organic matter contents with

variable carbonate concentrations. Group-B samples, which represent more distal

marine settings, illustrate an increasing trend of original organic matter proportion

toward the carbonate corner meaning that the silicate sedimentation dilutes the TOC and

carbonate contents. They have TOC values not exceeding 4%. Group-C samples, which

were deposited at more distal setting, witnessed a pronounced organic matter

productivity that characterizes the samples containing CaCO3 from 40-80%. The samples

with CaCO3 higher than 80% represent lower organic matter productivity probably due

to a lack of terrigenous-derived nutrients. The samples from this group usually have TOC

contents higher than 6%.

160

Fig. 6-3 Geochemical conceptual model summarizing the differences between the three main depositional environments investigated in the current thesis.

161

Fig. 6-4 Carbonate-original organic matter-silicate diagram of selected samples from the Nile Delta (matariya-1 and Abu

hammad-1 wells), The Abu Gharadig Basin (GPT-3 well) and the Tarfaya Basin (SON-4).

5.3.3 Bottom water conditions

As discussed previously in Chapter 1, the oxygen contents of the bottom water play an

essential role in organic matter preservation. These contents vary throughout the

continental shelf depending upon bathymetry, sea level, and climate. In the following, the

consequences of the bottom water oxicity variation is attested using various parameters

from the above. Only Groups B-C are included in this analysis.

At the sea bottom, Mn reduction increases the pore water oxygen contents and

consequently dominates the organic matter oxidation (Tribovillard et al., 2006). This

could explain the positive correlation between MnO and OI values (Fig. 5-5a) which

classifies the samples into two groups (Group-B, C; Fig.5-3). Group-C is low in MnO

contents and has OI values under 80 mgCO2/gTOC. Following the same trend, Group-B

0

10

20

30

40

50

60

70

80

90

100

Ori

gin

al O

rgan

ic M

att

er (%

)

0102030405060708090100

Carbonates (%)

0

10

20

30

40

50

60

70

80

90

100

Silicate

s (%)

Well

Matariya-1

Abu Hammad-1

GPT-3

SON-4

Rock Unit

Abu Roash "A"

Abu Roash "B"

Abu Roash "C"

Abu Roash "D"

Abu Roash "E"

Abu Roash "F"

Abu Roash "G"

Baharyia

Sidi Salem Formation

Alam El-Bueib Formation

Masajid Foramtion

Turonian

CT

upper Cenomanian

lower Cenomanian

Albian

162

shows higher MnO contents and OI values. The positive correlation implies that the

increase in OI index is, to a large extent, related to organic matter oxidations. However,

the effect of terrigenous input on elevating the OI values cannot be ruled out. This further

supported by the positive correlation between MnO and Pr/Ph (Fig. 5-5b) and the

negative correlation between the OI and Thiophenes/benzenes ratio (Fig. 5-6) implying

more oxygen containing organic compounds. Group-C has HI values greater than 600

mgHC/gTOC whereas Group-B has lower values denoting better preservation in the

absence of MnO. To conclude, the bottom water oxicity was apparently higher in Group-

B settings compared to the Group-C.

Fig. 6-5 MnO versus a) oxygen index and b) Pr/Ph plots showing positive correlations of selected samples from the Tarfaya Basin (SON-4) and the Abu Gharadig Basin (GPT-3).

In the HI versus Mn/S diagram, differences between the two groups are observed (Fig. 5-

7). Group-C has very low Mn/S ratio values indicating highly anoxic conditions. The Abu

Gharadig Basin samples from Group-B shows a positive correlation. This might represent

a deposition in stratified water column just below the O2-H2S boundary where Mn

concentration is high due to active cycling between the sediment-water interface and the

water column (Tribovillard et al., 2006). The stratification can be related to riverine

inputs that increase the Mn contents and modify the salinity in the upper layer. This

raises a question if the HI versus Mn/S diagram is a potential depositional environment

proxy to indicate marine water stratification.

a

0.00 0.02 0.04

MnO (%)

0.0

0.5

1.0

1.5

Pr/

Ph

WellGPT-3SON-4

Rock UnitAbu Roash "F"CT

0.00 0.02 0.04 0.06 0.08 0.10

MnO (%)

0

50

100

150

200

OI (

mg

CO

2/g

TO

C)

WellGPT-3SON-4

Rock UnitAbu Roash "E"Abu Roash "F"Abu Roash "G"TuronianCTupper Cenomanianlower Cenomanian

b

163

Fig. 6-6 Oxygen Index versus thiophenes/benzenes ratio of selected samples from the Tarfaya Basin (SON-4) and the Abu Gharadig Basin (GPT-3).

Fig. 6-7 Mn/S ratio versus hydrogen Index relationships illustrating positive correlation for the Abu Gharadig basin samples (GPT-3 well).

0 100 200

OI (mgCO2/gTOC)

0

2

4

6

8

10

Th

iop

hen

es/b

en

zen

es

WellGPT-3SON-4

Rock UnitAbu Roash "F"TuronianCTupper Cenomanianlower Cenomanian

0.0 0.2 0.4 0.6 0.8 1.0

Mn/S

0

200

400

600

800

HI (m

gH

C/g

TO

C)

WellGPT-3SON-4


164

The bottom water oxicity is also evaluated using the S/Fe ratio. Values higher than 1.15

indicate oxygen-depleted bottom water conditions and lower values point to higher

oxygen concentrations. The samples having S/Fe from 0.86 to 0.57 indicate suboxic

conditions. Lower values are attributed to oxic conditions (Dean and Arthur, 1989). The

S/Fe ratio has similar inverse relationships with TiO2, Al2O3, and MnO contents. The shift

in the trend occurs at S/Fe values of 0.67 (Fig. 5-8). This value is used as the boundary

between the suboxic and anoxic condition. Samples with S/Fe values between 0.67 and

0.57 represents suboxic marine settings with a fair abundance of terrigenous elements

(Group-B; Fig. 5-3). On the other hand, the samples with S/Fe ratio higher than 0.67

represents anoxic settings of Group-C.

Fig. 6-8 TiO2 versus S/Fe ratio relationship used as an example of the inverse relationship between terrigenous elements and S/Fe ratio.

5.3.5 Tmax and source rock properties

The samples in this study are similar in the thermal maturity yet have a broad range of

Tmax values. Therefore, the changes in Tmax values correspond mostly to organic matter

type. The Tmax has an inverse relationship with TOC which can be related to the organic

matter type or/and richness. As discussed previously, the low TOC samples are from

shallower marine settings where oxidation and dilution by terrestrial inputs of organic

0.0 0.5 1.0 1.5 2.0 2.5 3.0

TiO2 (%)

0

1

2

3

4

5

S/F

e

WellGPT-3SON-4


165

matter are higher than what is anticipated in deeper settings. Moreover, higher

contribution of terrestrial organic matter is expected in shallow marine deltaic

environments. Kerogen sulfurization takes place in anoxic conditions at deeper settings

only away from the terrestrial reactive Fe. In the thiophenes/benzenes ratio versus Tmax

correlation, two clusters are observed which represent Group-B and C (Fig. 5-9). The

samples from Group-C have thiophenes/benzenes ratio higher than 3 and Tmax values

range from 410 to 415°C. In contrast, the samples from Group-B have lower

thiophenes/benzenes ratios, and range in Tmax from 420 to 430°C. These differences in

Tmax values distinguish immature Type-II from Type-IIS kerogens. From the preceding

discussion, we can conclude that at similar thermal maturity, the Tmax values are

expected to be higher in shallow marine sediments then decrease towards deeper

settings. The results can be used to start rescaling the thermal maturity spectrum both in

kerogen type-II and –IIS.

Fig. 6-9 Tmax versus Thiophenes/Benzenes ratio of selected samples from the Tarfaya (SON-4) and Abu Gharadig basins (GPT-3) showing tow clusters.

5.4 New Geochemical Proxies

The Al2O3/TOC ratio is used as a proxy to indicate terrigenous inputs (Isaksen and Bohacs

2012). High values indicate more proximally setting and higher terrigenous dilution. The

S/Fe ratio has an inverse relationship with TOC/Al2O3 (Fig. 5-10) similar to the S/Fe

405 410 415 420 425 430 435 440

T-max (°C)

0

2

4

6

8

10

12

Th

iop

hen

s/B

en

zen

s

Well

GPT-3

SON-4

Rock Unit

Abu Roash "F"

Turonian

CT

upper Cenomanian

lower Cenomanian

166

versus terrigenous parameters discussed above. This indicates that the organic matter

oxidation becomes rapidly active when the S/Fe is lower than 0.67. Similar relationships

are found between the S/Fe versus MnO/TOC and TiO2/TOC. More work has to be

conducted to confirm these relationships which can be very useful for paleoenvironment

reconstruction. For example, the TOC/Al2O3 can be determined from petrophysical well-

logs. Thus, if the Al2O3/TOC ratio is determined from well-log of tens of wells in a basin,

the paleo-oxygen minimum zone can be mapped. The same holds true for the MnO/TOC

and TiO2/TOC versus S/Fe relationships. More samples need to be included to strengthen

this argument. The results of this study have implications for paleoenvironmental

reconstructions, basin and geological modeling.

Fig. 6-10 S/Fe versus Al2O3 ratios of selected samples from the Tarfaya and Abu Gharadig basins.

Al2O3/TOC

167

Chapter 7 | Conclusions

Source rock characterizations and depositional environment assessments were

conducted on samples from three basins representing variable shallow marine

settings. In the Nile Delta Basin, the Abu Hammad-1 well hosts siliciclastics gas

prone source rocks within the Lower Cretaceous Alam El Bueib Formation. It

encompasses kerogen Type-III with a minor contribution of degraded marine

organic matter. The biomarker and elemental data reveal a nearshore marine

depositional environment with oxic to suboxic bottom water. The 1D burial and

thermal history models indicate low thermal maturity and no significant thermal

hydrocarbon generation due to thin overburden and low heat flow. In contrast,

significant gas generation from the Mesozoic source rocks is expected to occur in

the northern Nile Delta Basin at deeper settings. In the Matariya-1 well, the Middle

Miocene Sidi Salem Formation and the lower part of the lower Miocene Qawasim

Formation illustrate moderate source rock quality. The source rock interval is

dominated by kerogen Type-III indicating gas-prone kerogen. Burial and thermal

history models prove that the maximum temperatures were attained in the

Quaternary where the basal part reached the onset oil maturity stage. The central

Nile Delta Basin appears to have better source rock quality compared to the

eastern part. This is perhaps due to shallower water conditions in the eastern Nile

Delta Basin during the Middle Miocene. The Miocene source rock intervals are

thick and interbedded with reservoir facies, making the migration pathway short

which inhibits hydrocarbon losses due to migration. The Middle Miocene

petroleum play has great potential for microbial and thermogenic gas.

168

The study of the Cenomanian to the Santonian succession at the GPT-3 well located

in the Abu Gharadig Basin identified two general bottom water conditions based

on TOC, TS, and CaCO3 relationships. Apart from the Abu Roash "F" Member, the

Bahariya Formation and the other members of Abu Roash Formation have

marginal TOC and similar trends in the TOC versus TS and CaCO3 relationships.

Geochemical and palynological data suggest that these rock units were deposited

in suboxic conditions in rather shallow water. The normal marine line defined by

Berner (1984) was shifted for these sediments to higher TS/TOC ratios probably

as a result of interactions between migrated hydrocarbons and pore water sulfate

due to biologically driven sulfate reduction, leading to high pyrite contents. The

Abu Roash “F” Member shows a positive relation between TOC and CaCO3 as well

as TS. It represents a period of fluctuating anoxic bottom water conditions and

enhanced preservation of organic matter. It comprises two sea transgression

phases separated by a sea regression. Transgression phase-I sediments were

deposited in anoxic bottom water conditions, leading to sediments rich in TOC,

CaCO3 and S and partly poor in Fe and other detrital elements. On the other hand,

regression phase witnessed sea level fall and fresh water incursions as can be

deduced from high contents of siderite, rutile, detrital elements and Mn. The

sediments contain fresh/brackish water algae Botryococcus, but also marine

palynomorphs. Moreover, transgression phase-II sediments are moderately rich

in TOC and higher in detrital element concentrations compared the sediment from

the first transgression. The sediments were deposited in suboxic conditions

somewhat poor Sorg. The palynological investigation reveals the occurrence of

marine and non-marine species. Transgression phase-I source rock contains

kerogen Type-IIS which yields high sulfur oil, whereas transgression phase-II

contains kerogen Types-II/III which generates sweet oil with minor gas upon

expulsion. Variable independent thermal maturity parameters indicate lower

169

thermal maturity for the Abu Roash “F” source rock interval compared to

sediments above and below. This finding suggests retardation/suppression of

maturation processes in oil-prone source rocks. The residual oils of the Abu Roash

“C” and “D” reservoirs reveal two different compartments. The Abu Roash “D”

residual oils are affected either by biodegradation or evaporation. In contrast, the

Abu Roash “C” residual oil shows a bi-modal n-alkane distribution and more short-

chain copounds. Correlations with source rocks are difficult due to the quality of

the residual oil samples and source rock heterogeneity.

In the Tarfaya Basin, the various organic geochemical analyses disclose excellent

source rock potential for the entire, thick Cenomanian to Turonian section. The

lower Cenomanian source rock is moderately high in TOC and HI and rich in

silicate. In contrary, the upper Cenomanian to Turonian source rocks are high in

TOC, HI and carbonate contents. Molecular geochemical data indicate a marine

origin for the organic matter for all samples. This is supported by microscopic

analysis that suggested a predominance of unstructured organic matter

associated with alginite and rare vitrinite and inertinite. The highest organic

matter content is found when the carbonate content is between 50 to 80 %. All

samples were deposited under anoxic conditions with the highest oxygen

depletion occurring during the CTBE based on biomarker data, coupled with high

sea water temperatures. The sediments show different kerogen sulfurization

levels depending on the depositional environment conditions. They are classified

based on the Sorg content as i) Sorg-rich (Sorg/Corg =5-8), i.e. the CTBE and Turonian

samples, ii) Sorg-moderately rich (Sorg/Corg ~3.5), i.e. the Upper Cenomanian and

iii) Sorg-poor (Sorg/Corg <1), i.e. the lower Cenomanian. Samples younger than the

silicate-rich lower Cenomanian interval is expected to generate sulfur-rich oil. The

study investigated the relative Sorg enrichment which is of great importance, e.g.

for the oil shale retorting.

170

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Curriculum Vitae

Bandar Ismail Ghassal

Email: [email protected]

Date of birth: 13.June.1982

Marital status; married

Work Experience

2005-Present Petroleum geochemist at Saudi Aramco EXPEC Advanced Research Center

June 2004-May 2005 Assistant Geologist at Petro-Hunt Middle East Ltd., Saudi Arabia

June –August 2003 Mine geologist trainee at Maaden, Mahed Ad Dahab Gold Mine, Saudi Arabia

Education Since 2013 PhD student at RWTH Aachen University, Germany

2008-2010 MSc from University of Utah, United states of America

2000-2004 BSc from King Abdulaziz University, Saudi Arabia

Volunteering experience 2011 2011 SPE YP SAS organizing committee member

2009-2010 Secretary of Society of Economic geologist, University of Utah student chapter

2009-2010 University of Utah international ambassador

2008-2010 Cultural activity coordinator of the Saudi Student Club at the University of Utah

Publications

El Atfy, H., Brocke, R., Uhl, D., Ghassal, B., Stock, A. T., & Littke, R. (2014). Source rock potential and paleoenvironment of the Miocene Rudeis and Kareem formations, Gulf of Suez, Egypt: An integrated palynofacies and organic geochemical approach. International Journal of Coal Geology, 131, 326-343. Ghassal, B. I., Littke, R., Sachse, V., Sindern, S., & Schwarzbauer, J. (2016). Depositional Environment and Source Rock Potential of Upper Albian to Turonian sedimentary rocks of the Tarfaya Basin, Southwest Morocco. Geologica Acta, 14(4), 419-441. Ghassal, B. I., El Atfy, H., Sachse, V., & Littke, R. (2016). Source rock potential of the Middle Jurassic to Middle Pliocene, onshore Nile Delta Basin, Egypt. Arabian Journal of Geosciences, 9(20), 744.

mailto:[email protected]

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