The Petroleum Potential of the Passive Continental Margin of … · 2016. 5. 27. · Namibia and Brazil, respectively, and by samples from the Cruz del Sur well. Marine and terrestrial

The Petroleum Potential of the Passive

Continental Margin of South-Western Africa

– A Basin Modelling Study

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 Diplom-Geologin

Sabine Schmidt

aus Wilhelmshaven

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

Univ.-Prof. Dr. rer. nat. H. Stollhofen Prof. a.D. Dr. rer. nat. K. Hinz (BGR)

Tag der mündlichen Prüfung: 30. April 2004 Diese Dissertation ist auf den Internetseiten der Hochschulbibliothek online verfügbar.

Abstract I

Abstract

The passive continental margins of Namibia / South Africa and Argentina are virtually

unexplored although some potential is assumed and even proven by the Kudu gas field

offshore Namibia and the Ibhubesi gas field offshore South Africa. In the study at hand the

hydrocarbon potential of the continental margins of the southern South Atlantic Ocean is

assessed on the basis of petroleum geological investigations of near-surface sediments, source

rock samples and basin modelling.

Hydrocarbon gas desorbed from near-surface sediments from offshore Argentina and south-

western Africa utilised as a surface exploration technique found evidence for a marine source

rock actively generating hydrocarbons on both margins of the southern South Atlantic. The

maturity of this source rock deciphered from the stable carbon istotopic ratios of desorbed

hydrocarbon gas is distinctly higher at the African than at the Argentine continental margin.

This is in concordance with the pronounced maturity difference between the Argentine and

African continental margins seen in rocks from the Argentine Cruz del Sur and Namibian

Kudu wells. Thus, from the surface exploration a marine source rock is inferred to be active in

the southern South Atlantic which is in the gas window at the African margin and in the oil

window at the Argentine margin.

The source rock samples investigated in this study originate from different phases concerning

the opening of the South Atlantic Ocean. Lacustrine source rocks deposited during the

Permian prerift phase are represented by the Whitehill and Irati shale samples from onshore

Namibia and Brazil, respectively, and by samples from the Cruz del Sur well. Marine and

terrestrial source rocks of Barremian to Aptian age deposited during the drift phase of the

Atlantic opening are drilled in the wells Kudu 9A-2, Kudu 9A-3, DSDP 361 offshore South

Africa, and Cruz del Sur offshore Argentina. High petroleum generation potentials were

recognised for marine Aptian rocks from the DSDP 361 well, Neocominan and Paleozoic

rocks from the Cruz del Sur well and for Permian lacustrine Irati shale samples.

Based on well and seismic data from the Kudu gas field in the Orange Basin offshore

Namibia and constrained by the geochemical data, a 2D basin simulation study of the

hydrocarbon generation, migration and accumulation of the Kudu gas field was conducted

with PetroMod (IES, Germany). The Kudu gas field is characterised by predominantly dry gas

with minor condensate quantities. The reservoir is located at the feather edge of a basaltic

Abstract II

seaward dipping reflector sequence in predominantly aeolian sandstones. Remarkable about

the gas field is the fact that the reservoir is overlain by Aptian shales which act as seal and

source rock simultaneously. The 2D basin model confirms the possibility of downward

expulsion of hydrocarbons from the Aptian source shales in the underlying Aptian to

Barremian reservoir driven by the pressure gradient between the due to hydrocarbon

generation high pressured shale and the lower pressured permeable sandstone. After expulsion

during the Upper Cretaceous the hydrocarbons migrate buoyancy-driven in the carrier rock in

up-dip direction coastward. In the basin model hydrocarbons from basinward parts of the

source rock migrate towards the reservoir. Because of the greater distance to the coast the

terrestrial influence on those rocks is inferred to be of minor extend than in the drilled

proximal part. Thus, the filling of the reservoir with hydrocarbons from the terrestrial

influenced source rocks encountered in the Kudu wells as well as with hydrocarbons from

more basinward marine source rocks is inferred. This interpretation is corroberated by the

δ13C values of methane, ethane, and propane from the Kudu reservoir which argue for the

generation in a marine source rock. The maturity is estimated to approcimately 1.4 % Rr

which is not in concordance with today’s maturity measured at the Barremian and Aptian

shales drilled in the Kudu wells but with the modelled maturity at the time of petroleum

expulsion. The gas was found to be dry in spite of its moderate maturity which might hint at a

contribution of natural gas from oil to gas cracking induced by the high reservoir temperature

due to a high heat flow and deep burial. The Kudu condensate shows a high content in

aromatic compound thus indicating terrestrial input to the source rock. The condensate is thus

considered to possibly stem from more proximal part of the source rock.

The analyses of source rock samples from the southern South Atlantic reveal a certain

petroleum potential of Lower Cretaceous as well as Paleozoic source rocks. The potential of

the Aptian to Barremian source rocks is evidenced by the Kudu and the Ibhubesi field

offshore Namiba and South Africa, respectively. This potential is corroborated by the

presence of thermogenic hydrocarbons in near-surface sediments taken at the continental

margins of south-western African and Argentina. From the basin model downward expulsion

of petroleum from the Aptian and Barremian source rocks seems reasonable. Thus, further

reservoirs of the Kudu type might be present in the southern South Atlantic.

Kurzfassung III

Kurzfassung

Die Kontinentränder des südlichen Südatlantiks sind hinsichtlich ihres

Kohlenwasserstoff(KW)-Potenzials vergleichsweise wenig untersucht worden, obwohl bereits

durch die Erdgasfelder Kudu und Ibhubesi ein gewisses KW-Potenzial nachgewiesen ist.

Diese beiden Gasfelder befinden sich am afrikanischen Kontinentrand im namibischen bzw.

südafrikanischen Teil des Oranjebeckens (engl.: Orange Basin). Der westafrikanische

Kontinentrand südlich des Walfischrückens (engl.: Walvis Ridge) ist durch drei

Sedimentdepozentren gekennzeichnet, von denen das Oranjebecken das südlichste und

dasjenige mit der mächtigsten Sedimentmächtigkeit ist. Nördlich des Oranjebeckens befinden

sich das Lüderitz- und das Walfischbecken (engl.: Walvis Basin). Der afrikanische

Kontinentrand entstand im Zusammenhang mit der Öffnung des Südatlantiks und ist vor

allem durch mächtige kretazische Sedimente gekennzeichnet. Konjugierend zum

afrikanischen Kontinentrand stellt sich der argentinische Kontinentrand dar, an den sich

ebenfalls mehrere sedimentgefüllte Becken befinden.

In der vorliegenden Studie wurde das KW-Potenzial des afrikanischen Kontinentrandes unter

Einbeziehung von Ergebnissen vom konjugierenden argentinischen Kontinentrand mittels

geochemischer Untersuchungen an Muttergesteinsproben aus den Bohrungen Kudu 9A-2 und

9A-3 (Namibia), DSDP 361 (Südafrika), Cruz del Sur (Argentinien), aus Aufschlüssen in

Namibia und Brasilien und an Gas- und Kondensatproben aus dem Kudureservoir vor der

Küste Namibias evaluiert. Zusätzlich wurden Sedimentproben, genommen vor den Küsten

von Namibia, West-Südafrika und Argentinien, auf sorbierte Kohlenwasserstoffe (KWs)

untersucht, um Informationen über das KW-System des südlichen Südatlantiks zu erhalten.

Das Herzstück der vorliegenden Arbeit stellt eine zweidimensionale Beckensimulationsstudie

der KW-Bildung, -Migration und -Akkumulation des Kudugasfeldes durchgeführt mit der

Programmgruppe PetroMod (IES, Deutschland) dar.

Die Zusammensetzung des von den Sedimentproben desorbierten KW-Gases interpretiert

nach BERNER und FABER (1996) zeigt, dass an beiden Kontinenträndern des südlichen

Südatlantiks ein marines Muttergestein aktiv KWs generiert. Die Reife dieses

Muttergesteines, abgeschätzt aus den δ13C-Werten von Methan und Ethan, ist am

afrikanischen Kontinentrand mit 0,8 – 1,9 % Rr deutlich höher als am argentinischen

Kontinentrand, für den eine Reife von etwa 0,5 – 1,2 % Rr abgeschätzt wurde. Ein

vergleichbarer Reifeunterschied kann auch an Gesteinsproben aus den Kudubohrungen

Kurzfassung IV

(Namibia) und der Cruz del Sur Bohrung (Argentinien) festgestellt werden: Gesteine aus den

Kudubohrungen weisen in circa 4000 m eine Reife von etwa 1,7 % Rr auf, während in

derselben Tiefe in der Cruz del Sur Bohrung eine Reife von circa 0,7 % Rr angetroffen wird.

Die Muttergesteinsproben aus den verschiedenen Bohrungen und Aufschlüssen entstammen

verschiedenen Zeitaltern zwischen dem Paläozoikum und der Oberkreide. Sie lassen sich

zeitlich und lithologisch den verschiedenen tektonischen Phasen der Atlantiköffnung

zuordnen. Lakustrine Gesteine der Präriftphase sind durch die Proben vom permischen

Whitehill Shalte (Namibia) und permischen Irati Shale (Brasilien) und einige Proben aus dem

unteren Bereich der Bohrung Cruz del Sur repräsentiert. Sedimente der Riftphase (sind im

Südatlantik beispielsweise in einem Halbgraben vor der Küste Südafrikas mit der Bohrung A-

J1 erbohrt worden, standen aber für diese Studie nicht zur Verfügung. Proben von aptischen

und barremischen Gesteine mit marinem und terrestrischem organischen Material aus der

Driftphase, erbohrt in den Bohrungen Cruz del Sur, Kudu 9A-2 und 9A-3 sowie DSDP 361,

konnten verwendet werden. Vor allem die aptischen Gesteine aus der Bohrung DSDP 361, die

permischen Iratiproben, sowie oberjurassische bis unterkretazische und triassische Proben aus

der Cruz del Sur Bohrung weisen ein hohes KW-Bildungspotenzial auf. Die aptischen und

barremischen Gesteine der beiden Kudubohrungen hingegen sind durch ein geringes KW-

Bildungspotenzial gekennzeichnet, was sowohl mit dem großen Anteil an terrestrischer

organischer Substanz als auch auf die hohe Reife von ca. 1,7 % Rr zurückgeführt werden

kann. Der Gehalt an terrestrischer organischer Substanz, transportiert durch den Oranjefluss,

der Namibia bereits seit der Kreide entwässert und zur Bildung mächtiger Deltablagerungen

geführt hat, wird vermutlich in Richtung auf das Beckenzentrum abnehmen. Es wird davon

ausgegangen, dass die distalen Sedimente organisches Material besserer Qualität enthalten

und ein höheres KW-Bildungspotenzial aufweisen. Diese Vermutung wird durch die

zeitlichen Äquivalente dieser Gesteine vor der Küste Südafrikas erbohrt in DSDP 361, die ein

hohes bis sehr hohes KW-Bildungspotenzial haben, gestützt.

Das Erdgas, welches in dem Kudureservoir angetroffen wurde, weist eine stabile

Kohlenstoffisotopensignatur auf, die auf ein marines Muttergestein mit einer Reife von circa

1,2 bis 1,4 % Rr hindeutet. Es handelt sich um trockenes Gas (C1/∑Cn = 0.9797). Im

Vergleich zu den in den Kudubohrungen erbohrten aptischen Gesteinen wird aus der

Zusammensetzung des Gases eine um etwa 0.3 bis 0.5 % Rr geringere Muttergesteinsreife

abgeleitet. Dies deutet darauf hin, dass die Expulsion der KWs nicht rezent stattgefunden hat.

Aus dem Beckenmodell wird auf eine Expulsion der KWs aus dem Muttergestein in der

Oberkreide geschlossen. Zusätzlichen Einfluss auf die Isotopie des Gases könnte eine durch

Kurzfassung V

die hohen Reservoirtemperaturen sehr wahrscheinliche Umwandlung von Öl in Gas (engl.:

cracking) gehabt haben, da die thermische Umwandlung von Öl in Gas mit einem

Isotopeneffekt verbunden ist, der zu isotopisch „leichterem“ und damit scheinbar unreiferem

Gas führt. Die im Vergleich zur seiner Reife recht hohe Trockenheit des Gases ist in

Übereinstimmung mit einem Einfluss von „cracking“ auf die Gaszusammensetzung.

Das Reservoir des Kudugases befindet sich im oberen Bereich einer Sequenz aus seewärts

einfallenden Vulkaniten in vorwiegend äolischen Sanden in einer stratigraphischen Falle. Die

Sequenz von wechselgelagerten Vulkaniten und Sanden ist der Riftphase der

Atlantiköffunung zuzuordnen, welche im Südatlantik etwa ein oberjurassisches bis

unterkretazisches Alter aufweist. Das Reservoir wird durch aptische und barremische

Schiefertone abgedeckt, die gleichzeitig als Deckgestein für das Reservoir und als

Muttergestein für das Erdgas angenommen werden.

Außer dem Erdgas wurden im Reservoir auch geringe Kondensatmengen angetroffen, welche

einen hohen Gehalt an aromatischen KWs enthalten, was auf einen beträchtlichen Anteil an

terrestrischer organischer Substanz im Muttergestein hinweist. Die Reife, die für das

Muttergestein aus dem Heptanwert des Kondensates abgeleitet werden kann, beträgt circa

1 % Rr. Diese geringe Reife und vor allem die starke terrestrische Komponente des

Kondensates deuten auf ein anderes Muttergestein als das des Gases hin, welches eine

eindeutig marine Signatur aufweist. Gerade in einem deltaischen Environment, wie es in der

Umgebung des Kudugasfeldes angetroffen wird, kann von einer engen Verzahnung von

marinen und fluviatilen Sedimenten ausgegangen werden, aus denen die Bildung

unterschiedlicher KWs in direkter Nachbarschaft möglich ist.

Das 2D Modell der KW-Bildung, -Migration und -Akkumulation des Kudugasfeldes wurde

auf der Grundlage einer reflexionsseismischen Linie von 250 km Länge erstellt, welche das

Kudugasfeld in WSW-ENE-Richtung kreuzt. Die Interpretation der seismischen Linie beruht

auf dem Abgleich mit Daten aus den Kudubohrungen, die sich in wenigen Kilometer Abstand

von dem seismischen Profil befinden, sowie verschiedenen Literaturquellen. Die

Absenkungsgeschichte und die Wärmeflussgeschichte, die dem petroleumgeologischen

Modell zugrunde liegen, wurde ebenfalls mit Daten der Bohrungen Kudu 9A-2 und 9A-3

ergänzt mit Literaturdaten kalibriert. Das petroleumgeologische Modell zeigt eine

abwärtsgerichtete Expulsion von KWs aus den aptischen und barremischen Schiefertone in

das unterliegende Träger- und Speichergestein. Die sekundäre Migration dieser KWs findet

im Trägergestein auftriebsgesteuert in landwärtiger Richtung der Schichtung der Gesteine

Kurzfassung VI

folgend statt, wobei eine Migration von KWs von mehr beckenwärts gelegenen Positionen

beobachtet werden kann. Wie bereits beschrieben wird angenommen, dass der Anteil an

terrestrischer organischer Substanz in diesen beckenwärtigen Teilen des Reservoirs durch die

weitere Entfernung vom Land und dem Einfluss des Oranjeflusses geringer ist. Die Expulsion

der KWs findet zwischen 105 und 84 Ma statt. Zunächst kann eine Akkumulation von Öl im

Reservoir beobachtet werden, welches vor 84 Ma zu etwa 20 % mit Öl gefüllt ist. Gas

befindet sich zu diesem Zeitpunkt keines im Reservoir. Durch eine zunehmende Versenkung

der Muttergesteine und des Reservoirs in größere Tiefen durch hohe Sedimentationsraten in

der Oberkreide steigt die Temperatur im Reservoir von ca. 140 °C vor 84 Ma auf etwa 180 °C

vor 75 Ma an. Die Sättigung des Reservoirs mit Gas nimmt zu bis schließlich eine

Gassättigung von nahezu 100 % erreicht ist. Die Sättigung an Öl nimmt entsprechend ab. Eine

Umwandlung von Öl zu Gas ist denkbar und wird durch sowohl durch die Trockenheit und

das stabile Kohlenstoffisotopenverhältnis des Erdgases als auch durch eine Abnahme der

absoluten KW-Menge innerhalb der modellierten Sektion bestätigt, welche nur durch die

sekundäre Umwandlung von Öl in Gas zu erklären ist. Sekundäres „cracking“ ist ein Prozess,

bei dem längerkettige in kürzerkettige KWs und einen Kohlenstoffrest umgewandelt werden.

Diese Disproportionierungsreaktion führt zu einem Verlust an KWs im System. In der

verwendeten KW-Bildungskinetik nach QUIGLEY et al. (1987) wird ein Reduktionsfaktor

der KW-Menge von 0,45 für die Umwandlung von Öl in Gas verwendet und es kann darauf

geschlossen werden, dass ca. 19 % des Gases durch der Umwandlung von Öl zu Gas gebildet

wurden.

Die Untersuchung von Muttergesteinsproben von den Kontinenträndern des südlichen

Südatlantiks zeigt, dass sowohl unterkretazische als auch paläozoische Muttergesteine ein

beachtliches KW-Bildungspotenzial aufweisen. Das KW-Bildungspotenzial der aptischen und

barremischen Gesteine wird durch die Gasfunde des Kudu- und des Ibhubesifeldes bestätigt,

welche sich im Oranjebecken vor der Küste Namibias bzw. Südafrikas befinden. Die

Untersuchung von thermogenen KWs desorbiert von oberflächennahen Sedimenten von den

Kontinenträndern Südwestafrikas und Argentiniens zeigt ebenfalls, das im südlichen

Südatlanik aktive KWs generiert werden. Das erdölgeologische Beckenmodell verdeutlicht

die Möglichkeit einer Expulsion von KWs aus den aptischen und barremischen Gesteinen in

das unterliegende Träger – und Speichergestein und deren anschließende, auftriebsgesteuerte

landwärtige Migration. Es ist vorstellbar, dass weitere Reservoire vergleichbar dem

Kudugasfeld an den Kontinenträndern des südlichen Südatlantiks vorhanden sind, wobei am

afrikanischen Kontinentrand vermutlich eher Gas- als Ölfunde zu erwarten sind.

Acknowledgements VII

Acknowledgements

First of all, I am grateful to Prof. Dr. Ralf Littke, RWTH Aachen, for the supervision of the

study and the revision of the manuscript. The members of the committee, Dr. Harald

Stollhofen, RWTH Aachen, and Dr. Karl Hinz, BGR, are also thanked for revision of the

manuscript and for their readiness to discussion and questions.

Thanks are given to Dr. Bernhard Cramer for the time he spent in revising the manuscript and

helping with the present study. Dr. Peter Gerling is thanked for his efforts in acquiring data

and sample material for the study and his steady interest in its progress. Dr. Karl Hinz is

sincerely thanked for his readiness to help wherever he could, especially in preparing the

journey to Argentina. I also want to thank all my colleagues at the BGR who helped me

wherever they could and gave me a good time there. Special thanks go to Dr. Wolfgang Weiß

for the revision of micropaleontological data.

For the provision of sample material I am grateful to Dr. Roger Swart (Namcor), Mario

Werner (University Würzburg), Prof. Dr. Philippe Bertrand (University Bordeaux), Prof. Dr.

Horst D. Schulz, Dr. Monika Breitzke, Dr. Torsten Bickert (University Bremen) and Dr.

Eduardo Vaz dos Santos Neto (Petrobras). Many thanks go to Dr. Antonio Nevistic (YPF) and

Marcos Palisa for the cooperation concerning the sediment coring campaign in the Colorado

and Malvinas Basin, Argentina.

For five weeks of interesting geological and non-geological (carnival!) studies and for much

fun and cordiality I thank the members of the working group at RWTH Aachen.

Thanks go to my friends Michael Braun and Sonja Niderehe for spending much of their spare

time in proofreading the manuscript.

Heartily thanks I owe to Michael Braun for his steady encouragement, unshakeable trust in

me, and his patience with all my tempers during the final stage of the study (and with my

usual bad habits).

Last but not least I thank my family who made me what I am.

Table of Contents IX

Table of Contents

1. Scope of the Study..............................................................................................................1

2. Organic Geochemistry........................................................................................................2

2.1 Global Carbon Cycle........................................................................................................2

2.2 Accumulation of organic matter.......................................................................................3

2.3 Biochemical degradation of organic matter .....................................................................4

2.4 Diagenesis, catagenesis, and metagenesis of organic matter ...........................................5

2.4.1 Diagenesis: Kerogen formation.....................................................................................6

2.4.2 Catagenesis: Petroleum generation ...............................................................................7

2.4.3 Metagenesis and metamorphism: Late gas generation..................................................8

2.5 Source rocks .....................................................................................................................8

2.5.1 TOC content ..................................................................................................................9

2.5.2 Kerogen type .................................................................................................................9

2.5.3 Sulphur content .............................................................................................................10

2.5.4 Maceral analysis and vitrinite reflectance.....................................................................11

2.6 Isotope geochemistry .......................................................................................................11

2.6.1 Introduction ...................................................................................................................12

2.6.2 Isotope geochemistry of sedimentary organic matter ...................................................13

2.6.3 Isotopic composition of hydrocarbons ..........................................................................15

2.7 Surface prospecting geochemistry ...................................................................................16

2.8 Kinetic Theory..................................................................................................................17

2.9 Hydrocarbon migration and accumulation.......................................................................18

2.9.1 Primary migration: Expulsion .......................................................................................19

2.9.2 Secondary migration, accumulation..............................................................................20

3 Geology of the Namibian and South African continental margin.......................................21

3.1 Outline of the break-up of Gondwana and the subsequent evolution of the southwest

African continental margin.....................................................................................................21

3.2 Volcanic continental margin evolution ............................................................................29

3.3 Evolution of the Walvis Ridge and Rio Grande Rise.......................................................31

4 Petroleum systems in the South Atlantic Ocean .................................................................33

Table of Contents X

4.1. Introduction .....................................................................................................................33

4.2 The constituents of the petroleum systems in the South Atlantic Ocean.........................35

4.2.1 Source rocks ..................................................................................................................35

4.2.1.1 Prerift phase................................................................................................................35

4.2.1.2 Synrift phase...............................................................................................................35

4.2.1.3 Transitional to thermal sag phase...............................................................................36

4.2.2 Source rock maturation .................................................................................................36

4.2.3 Reservoir rocks, traps and seals ....................................................................................37

4.3 The petroleum system of the Kudu Field .........................................................................37

4.4 Exploration history of the South West African continental margin.................................40

5. Methods..............................................................................................................................42

5.1 Geochemical methods ......................................................................................................42

5.1.1 Surface geochemical prospecting..................................................................................42

5.1.2 Source rocks ..................................................................................................................44

5.1.2.1 Total organic carbon (TOC) and total sulphur (TS) content analysis........................44

5.1.2.2 Rock Eval pyrolysis ...................................................................................................45

5.1.2.2.1 Measurement of the parameters S1, S2, S3 and Tmax ................................................45

5.1.2.2.2 Reaction kinetics of hydrocarbon generation..........................................................45

5.1.2.3 Vitrinite Reflectance and maceral analyses ...............................................................46

5.1.2.4 Stable carbon isotopes of the source rocks ................................................................47

5.1.3 Analysis of the reservoir contents .................................................................................47

5.1.3.1 Natural gas from the Kudu reservoir..........................................................................47

5.1.3.2 Condensate from the Kudu reservoir .........................................................................47

5.2 Basin modelling................................................................................................................48

5.2.1 Definitions and input parameters ..................................................................................48

5.2.2 Heat flow history...........................................................................................................50

5.2.3 Surface water interface temperature..............................................................................50

5.2.4 Rock parameters related to heat distribution and transfer.............................................51

5.2.5 Porosity and permeability evolution .............................................................................52

5.2.6 Petroleum generation.....................................................................................................52

Table of Contents XI

5.2.7 Sensitivity analysis........................................................................................................53

5.2.8 Seismic interpretation....................................................................................................53

5.2.9 Subsidence analysis.......................................................................................................58

5.2.9.1 Passive margin evolution ...........................................................................................58

5.2.9.2 Backstripping .............................................................................................................58

5.2.9.3 Influence of the rifting process on the heat flow history of continental margins ......61

5.3 Data pool ..........................................................................................................................63


5.3.2 Source rocks ..................................................................................................................64

5.3.3 Reservoir contents .........................................................................................................64

5.3.4 Seismic ..........................................................................................................................65

5.3.5 Data reports ...................................................................................................................64

6. Results and interpretations .................................................................................................66

6.1 Geochemistry ...................................................................................................................66


6.1.2 Source rocks ..................................................................................................................70

6.1.2.1 Total organic carbon (TOC) and sulphur (S) content ................................................70

6.1.2.2 Rock Eval pyrolysis ...................................................................................................72

6.1.2.3 Vitrinite reflectance....................................................................................................74

6.1.2.4 Maceral analyses ........................................................................................................75

6.1.2.5 Stable carbon isotopes of sedimentary organic matter...............................................76

6.1.3 Petroleum generation kinetics of DSDP and Irati Shale samples .................................77

6.1.4 Reservoir contents of the Kudu reservoir......................................................................79

6.1.4.1 Natural gas..................................................................................................................79

6.1.4.2 Condensate .................................................................................................................81

6.2 Basin modelling study......................................................................................................83

6.2.1 Sequence stratigraphy of the Namibian and South African continental margin ...........83

6.2.2 Interpretation of the seismic section ECL 89 011.........................................................83

6.2.3 Estimation of the thickness of eroded strata .................................................................87

6.2.3.1 Estimation of the thickness of eroded strata using vitrinite reflectance profiles .......87

Table of Contents XII

6.2.3.2 Estimation of the thickness of eroded strata using Tmax profiles .............................89

6.2.3.3 Estimation of the thickness of eroded strata using reflection seismic cross-sections 90

6.2.4 Subsidence analysis.......................................................................................................90

6.2.5 1D model .......................................................................................................................92

6.2.6 Depth conversion...........................................................................................................93

6.2.7 Source rock definition ...................................................................................................93

6.2.8 2D model .......................................................................................................................94

6.2.9 Sedimentary history.......................................................................................................94

6.2.10 Petroleum generation, migration and accumulation....................................................99

6.2.11 Sensitivity analysis......................................................................................................103

7 Discussion ...........................................................................................................................105

7.1 Geochemistry ...................................................................................................................105


7.1.2 Geochemistry the reservoir contents of the Kudu gas field ..........................................106

7.1.2.1 Natural gas from the Kudu reservoir..........................................................................106

7.1.2.2 Condensate from the Kudu reservoir .........................................................................107

7.2 Basin modelling study......................................................................................................108

7.2.1 Seismic interpretation....................................................................................................108

7.2.2 Estimation of the thickness of eroded strata .................................................................108

7.2.3 Source rocks of the Kudu gas........................................................................................109

7.2.4 Petroleum generation, migration and accumulation......................................................110

7.3 The petroleum potential of the southern South Atlantic ..................................................111

8 Summary .............................................................................................................................113

9 References ...........................................................................................................................115

Appendix A ............................................................................................................................142

Appendix B ............................................................................................................................156

List of Figures XIII

List of Figures

Figure 2.1: The global carbon cycle, modified from TISSOT and WELTE (1984)..............2

Figure 2.2: Upwelling causing high biological productivity eventually leading to

deposition of organic rich sediments at continental margins, modified from

LITTKE and WELTE (1992)..............................................................................4

Figure 2.3: Evolution of organic matter during diagenesis, metagenesis and katagenesis,

modified from TISSOT and WELTE (1984). .....................................................6

Figure 2.4: Figure 2.4: Range of carbon isotopic ratios of different carbon-bearing

substances, modified from WHITICAR (1996b)................................................13

Figure 2.5: Typical distribution of activation energies for different kerogen types,

modified from TISSOT et al. (1987)...................................................................18

Figure 2.6: Hydrocarbon expulsion, migration and accumulation, modified from

TISSOT and WELTE (1984). .............................................................................19

Figure 3.1: Reconstruction of the opening of the South Atlantic Ocean, modified from

(RABINOWITZ and LABRECQUE 1979). .......................................................22

Figure 3.2: Structural framework of the south-western continental margin of Africa. .........23

Figure 3.3: Subdivision of the stratigraphy by seismic horizons in the South Atlantic,

modified from LIGHT et al. (1993a). .................................................................24

Figure 3.4: Stratigraphic columns modified from Namcor (information from the 3rd

licensing round 1999)..........................................................................................25

Figure 3.5: Sedimentation rates derived from commercial borehole records, modified

from RUST and SUMMERFIELD (1990)..........................................................28

Figure 3.6: Sketch of a volcanic margin, modified from LARSEN and SAUNDERS

(1998). .................................................................................................................30

Figure 3.7: Model for the emplacement of seaward dipping reflector sequences,

modified from MUTTER (1985). .......................................................................30

Figure 4.1: Petroleum system chart for the continental margin of south-western Africa,

compiled from MILLER (1992), BARTON et al. (1993), BRAY et al.

(1998), STOLLHOFEN (1999)...........................................................................34

Figure 4.2: Stratigraphy and lithology of the Kudu wells, modified from BAGGULEY

(1997). .................................................................................................................39

List of Figures XIV

Figure 5.1: Desorption line for degassing surface sediment samples after FABER and

STAHL (1983). ...................................................................................................42

Figure 5.2: Development of a deterministic basin model, modified from TISSOT and

WELTE (1984)....................................................................................................49

Figure 5.3: Effect of climate model and latitude on variations in mean annual sea surface

temperatures, modified from WYGRALA (1989, cited in BARKER 2000)......51

Figure 5.4: Seismic sections ECL 89 011 and ECL 89 011A................................................54

Figure 5.5: Relation of strata to boundaries of depositional systems (MITCHUM et al.

1977a,b)...............................................................................................................55

Figure 5.6: Changes in relative sea level (A) affect the amount of available

accommodation space (B), modified from POSAMENTIER et al. (1988) ........57

Figure 5.7: Delineation of the backstripping technique, modified from: (CÉLÉRIER

1988). ..................................................................................................................59

Figure 5.8: Compilation of the locations of source rock (dots) and sediment (stars) and

of the run of the seismic section ECL 89011. The petroleum samples were

taken in the Kudu gas field which is marked by the dot for source rock

samples. ...............................................................................................................63

Figure 6.1: Plots to characterise the source of the hydrocarbon gas desorbed from near-

surface sediments from offshore South Africa, Namibia and South America

after BERNARD (1978), SCHOELL (1983). .....................................................67

Figure 6.2: δ13CH4 and δ13C2H6 values used to deduce type and maturity of active source

rock after BERNER and FABER (1996). ...........................................................69

Figure 6.3: Total organic carbon contents of samples from different locations offshore

SW Africa and Argentina....................................................................................71

Figure 6.4: TOC contents of the Cruz del Sur samples - compilation of analyses data

surveyed by Western Atlas STARLING (1994) (black) and BGR (red). ...........71

Figure 6.5: Comparison of TOC contents measured by BGR and Soekor for samples

from the Aptian to Barremian source rock interval. ...........................................72

Figure 6.6: Hydrogen index versus oxygen index – modified van Krevelen diagram,

according to ESPITALIÉ et al. (1977)................................................................73

Figure 6.7: Vitrinite reflectance profile of the well Kudu 9A-2. For comparison are the

values for DSDP 361 included............................................................................75

List of Figures XV

Figure 6.8: Distribution of activation energies calculated by the BGR software for

selected source rock samples from the Irati shale and the DSDP 361 well. .......78

Figure 6.9: Diagnostic plots for the Kudu gas after BERNER and FABER (1996) and

SCHOELL (1983) for deciphering the type of source rock for the gas

desorbed from the near-surface sediments..........................................................80

Figure 6.10: Plots of δ13C values of ethane and propane plotted vs. that of methane in

order to deduce the maturity of the source rock of the Kudu gas after

BERNER and FABER (1996)............................................................................80

Figure 6.11: „Whole oil“ chromatogram of the analysis of a condensate sample from

well Kudu 5. .......................................................................................................81

Figure 6.12: Heptane - isoheptane value plot and pristane/n-C17 – phytane/n-C18 plot

point to a terrestrial influence on the source of the condensate after

THOMPSON (1983), SHANMUGAM (1985). .................................................82

Figure 6.13: Heptane value of the condensate indicates a source maturity of

approximately 1 % Rr after THOMPSON (1983). ............................................82

Figure 6.14: Linedrawing of the reflection seismic sections ECL 89 011 and ECL 89

011A. ..................................................................................................................84

Figure 6.15: Seaward tilting of the continental margin due to epeirogenic subsidence,

modified from RONA (1974).............................................................................86

Figure 6.16: Thickness of eroded strata estimated from vitrinite reflectance data of well

Kudu 9A-2..........................................................................................................88

Figure 6.17: Tmax data of the well Kudu 9A-2. ....................................................................89

Figure 6.18: Input data used for 1D modelling of Kudu 9A-2 (A) and calibration of the

1D model with vitrinite reflectance data from well Kudu 9A-2. .......................93

Figure 6.19: Sedimentary history of the seismic section through the Kudu gas field

offshore Namibia................................................................................................95

Figure 6.20: Burial history for different positions in the modelled section. A: Gridpoint 2 .98

Figure 6.21: Burial history for B: Gridpoint 43 near the Kudu well, C: Gridpoint 80. .........99

Figure 6.22: Expulsion time of petroleum from the source rock. ..........................................100

Figure 6.23: Expulsion time of petroleum from the source rock downward into the

reservoir..............................................................................................................100

Figure 6.24: Oil saturation of about 20 % in the reservoir at 84 Mabp. ................................101

List of Figures XVI

Figure 6.25: Temperature, vitrinite reflectance (VR) and transformation ratio evolution

at gridpoints 2 (green), 43 (blue) and 80 (orange) with time. ............................101

Figure 6.26: Comparison of the temperature field in models with different thermal

conductivities. In model A a thermal conductivity of 2 [W/m/K], in model B

a thermal conductivity of 1 [W/m/K] was chosen..............................................103

Figure 7.1: Comparison of the expulsion time calculated with kinetic datasets by

QUIGLEY et al. 1987 (A), TISSOT et al. 1987 (B) and according to the

results of the bulk kinetic of DSDP rock samples (this study, C)......................111

List of Tables XVII

List of Tables

Table 5.1: Compilation of the main information about the sediment samples used for

surface geochemical prospecting including among others information on

sample number, storage temperature and provider. .............................................63

Table 5.2: Compilation of the locations of source rock sampling, numbers and types of

source rock samples. Note that the ciphers in the last column indicate the

number of samples analysed with the geochemical techniques indicated in the

headline of the column. ........................................................................................64

Table 6.1: Ranges of hydrocarbon yield and stable carbon isotopic ratios of gaseous

hydrocarbons desorbed from near-surface sediments from offshore Namibia,

South Africa and Argentina (*1 ppb corresponds to 1E-9 g gas per g dry

sediment). The ciphers in brackets indicate the number of analyses. ..................66

Table 6.2: Compilation of the results of the analyses of source rock samples from

different locations. Note that the numbers in brackets behind the values

indicate the number of samples analysed. The values measured for the Kudu

wells in the framework of this study are marked with BGR, values marked

with Soekor are from DAVIES and SPUY (1988). .............................................70

Table 6.3: Results of the kinetic analyses of bulk RockEval pyrolysis data obtained with

Optkin (Vinci Technologies, France) and BGR house intern software. ..............77

Table 6.4: Molecular and isotopic composition of gas samples from the Kudu reservoir.

Analyses of samples A-13827 to A-14244 are extracted from (ANDRESEN

1992) and used for comparison purpose. .............................................................79

List of Abbreviations XVIII

List of Abbreviations

A frequency factor

BGR Federal Institute for Geosciences and Resources, Germany

BOPD barrels of oil per day

COB continent ocean boundary

DSDP Deep Sea Drilling Program

DST drill steam test

Ea activation energy

FID flame ionisation detector

GC gas chromatograph

GP grid point

HC hydrocarbon(s)

HI hydrogen index

KW(s) Kohlenwasserstoff(e) (German for: hydrocarbon)

LCB lower crustal body

LIP large igneous province

Ma millions of years

mbKB meters below kelly bushing

mbsf meters below seafloor

MMCFD millions cubic feet per day

MS mass spectrometer

NAMCOR National Oil Company, Namibia

OI oxygen index

PDB PeeDee Belemnite (standard for the δ13C notation)

SDRS seaward dipping reflector sequences

SOEKOR Petroleum Agency South Africa

SWI surface water interface

TD total depth

TOC total organic carbon (in %)

TCF trillion cubic feet

TCFG trillion cubic feet of gas

TS total sulphur (in %)

TTS total tectonic subsidence

YPF Yacimientos Petrolíferos Fiscales, Argentina

Scope of the Study 1

1 Scope of the Study

The study at hand deals with the hydrocarbon potential of the conjugate continental margins

of south-western Africa and Argentina. It was undertaken in the framework of a cooperation

of the Federal Institute for Geosciences and Natural Resources (BGR), Germany, and the

Institute of Geology and Geochemistry of Petroleum and Coal (LEK) at Aachen University

(RWTH), Germany. The main emphasis of the study is put on the African continental margin

because this study is in part a compliment to an earlier work which deals with the

hydrocarbon potential of the Argentine continental margin (SCHÜMANN 2002) and which

was also performed under the scope of the same collaboration.

The passive continental margins of Namibia / South Africa and Argentina are virtually

unexplored with regard to their hydrocarbon resources albeit some potential is assumed and

even proven by the Kudu gas field offshore Namibia and the Ibhubesi gas field offshore South

Africa. Both discoveries are located in the Orange Basin which features the highest postrift

sediment accumulation at the south-western African margin (DINGLE et al. 1983). Likewise,

hydrocarbon potential is assumed for the Walvis and Lüderitz Basin offshore southwest

Africa as well (JUNGSLAGER 1999). Thus, the question to be answered in this study is

whether the two gas discoveries in the Orange Basin are precedents or exceptions for the

geological setting of the southern South Atlantic.

This problem was approached by assessing the hydrocarbon potential of the southwest

African continental margin by geochemical analyses on source rocks from offshore Africa

and Argentina and from onshore Brazil and Namibia, and on natural gas and condensate

samples from the Kudu reservoir offshore Namibia. Additionally, hydrocarbon gas desorbed

from near-surface sediments sampled offshore Argentina and south-western Africa was

utilised as a surface exploration technique for deducing type and maturity of the actively

petroleum generating source rock in the South Atlantic. The geochemical information was

applied as boundary conditions in a 2D basin simulation study of hydrocarbon generation,

migration and accumulation. The simulation study is based on well and seismic data from the

Kudu gas field in the Orange Basin and was conducted with the software group PetroMod

(IES, Germany).

Organic Geochemistry 2

2 Organic Geochemistry

Literally, the term organic means “derived from living organisms”. Anyhow, the field of

organic geochemistry refers to all compounds consisting of carbon and hydrogen and their

derivatives (WADE 1999). Besides carbon and hydrogen, hydrocarbons can contain oxygen,

sulphur, nitrogen or other elements. Organic chemicals constitute about 95 % of all known

chemicals on earth (WADE 1999).

2.1 Global Carbon Cycle

Carbon is present on earth in many different modifications. One part of it is fixed

inorganically in carbonates and carbon dioxide. The other part which is the basis for organic

geochemical considerations is fixed in living and dead organisms, as organic residue in

sediments and in fossil fuels. In total, the earth’s crust contains about 9x1016 t of carbon

(HUNT 1972). The organic carbon passes through a primary carbon cycle in which organic

material is generated by fixation of carbon dioxide by plants and bacteria through

photosynthesis (figure 2.1).

Figure 2.1: The global carbon cycle, modified from TISSOT and WELTE (1984).

The duration of the first cycle is days to decades. This cycle is the basis for the food pyramid

and the evolution of higher forms of life. The residues of both, producers and consumers, are

partly reworked by decomposers and partly deposited in soils and sediments. The deposited


organic matter is the link to the second organic carbon cycle which has a run time of millions

of years. In the second cycle only 0.1 % of the carbon quantity of the first cycle are

incorporated. In spite of the low quantity of organic carbon this cycle is very important

because it constitutes all of the world’s fossil energy resources. The deposited organic matter

is profoundly altered in sediments and soils, part of it forming coal, kerogen, and petroleum.

Finally, the organic material reservoired as petroleum or fixed as organic matter in sediments

is metamorphosed and returns as carbon dioxide into the first cycle. On the average, only 2 %

of the organic carbon in sedimentary rocks ever become converted into the carbon in

petroleum, with only about 0.5 % of the petroleum becoming entrapped in reservoirs (HUNT

1972).

2.2 Accumulation of organic matter

Prerequisite for petroleum formation is abundance of organic matter in sediments at adequate

temperatures. Favourable conditions for the preservation of organic matter in sediments are

high biological productivity, intermediate sedimentation rates and anoxic conditions (DOW

1979; BARKER 1983).

In aquatic environments the main limiting factor to planktonic productivity is, besides light,

the availability of mineral nutrients, particularly nitrates, phosphates and silicates, which vary

greatly in concentration and tend to be short in supply in the euphotic zone (DEMAISON and

MOORE 1980b). Another source of organic matter in aquatic environments is the input of

terrestrial organic matter by rivers. Since terrestrial organic matter has undergone

considerable oxidation prior to its transport, it is usually hydrogen depleted and quite

refractory in nature (DEMAISON and MOORE 1980b).

Anoxic minima enhancing organic matter preservation exist due to oxygen consuming

(biochemical) processes. The positions of those minima depend on the ocean circulation

pattern (WYRTKI 1962). A classical example of anoxicity occurs on the shelf offshore South

West Africa (Namibia) in association with the Benguela Current (Figure 2.2). Here upwelling

nutrient-rich water from relatively shallow depths promotes the biological productivity thus

increasing the oxygen demand (DEMAISON and MOORE 1980b) and leading to a

progressive depletion of oxygen in the water below the photic zone (LITTKE and

SACHSENHOFER 1994). Consequently, high organic carbon concentrations in sediments

under the oxygen depleted zone can be detected. Prominent upwelling cells are situated


offshore the coasts of Northwest Africa, Southwest Africa, Peru, Northwest America and

Oman (LITTKE and SACHSENHOFER 1994). In the Walvis Bay offshore Southwest Africa,

free H2S has been encountered in the water of Walvis Bay indicating anaerobic sulphate

reduction. The upwelling in this region emerges from a combination of the cold coastal

Benguela Current and persistent offshore winds blowing in a northwestern direction. Shallow

surface water is skimmed off by the wind, permitting nutrient-rich water to ascend from a

depth of about 200 m (DEMAISON and MOORE 1980b). Many Cretaceous black shales

were obviously formed at sites of upwelling, consistent with the vigorous circulation patterns

that occurred during the Cretaceous.

Figure 2.2: Upwelling causing high biological productivity eventually leading to deposition of organic rich sediments at continental margins, modified from LITTKE and WELTE (1992).

2.3 Biochemical degradation of organic matter

Organic matter is thermodynamically unstable and tends to seek its lowest level of free energy

in any given environment immediately after the death of the organisms. Above all, it serves as

a source of energy and nutrients for living organisms (DEMAISON and MOORE 1980b).

Under aerobic conditions the organic matter is oxidised to CO2 and H2O.

(CH2O) + O2 → CO2 + H2O Eq. 2.1

After consumption of all available oxygen, anoxic conditions prevail. In this environment first

nitrates are used as electron acceptors by anaerobic bacteria.

(CH2O) + 4 NO3 → 6 CO2 + 6 H2O +2 N2 Eq. 2.2

After exhaustion of nitrate, sulphate is used as the oxidant.

(CH2O) + SO4 → CO2 + H2O + H2S Eq. 2.3


The last step in anaerobic metabolism is fermentation. Here carboxyl groups and organic

acids of the organic matter itself, or resulting from microbial breakdown, are employed as

electron acceptors. A special case of anaerobic fermentation is microbial methanogenesis

(CLAYPOOL and KAPLAN 1974). The methanogens occupy the terminal niche of the

anaerobic food web and produce methane in anaerobic and sulphate-depleted environments

via CO2 reduction or attacking acetate, formate or methanol (WOLFE 1971 in DEMAISON

and MOORE 1980). Usually, the microbes cease the gas generation because of high

temperature, reduction of their living space by compaction and shortage of food supply at

about 350 m (RICE and CLAYPOOL 1981). Microbial gas is “dry” gas (almost 100 %

methane) with very low δ13CH4 values, usually less than -55 ‰ (KLUSMAN 1993).

Anaerobic degradation is thermodynamically less efficient than aerobic decomposition

(CLAYPOOL and KAPLAN 1974). It results in a lipid-enriched and more reduced

(hydrogen-enriched) organic residue than aerobic degradation (FOREE and MCCARTY

1970; PELET and DEBYSER 1977; DIDYK et al. 1978). Moreover, under such conditions a

significant fraction of the preserved organic matter is made up by the remains of the microbial

biomass itself (LIJMBACH 1975). Additionally, the organic matter in anoxic environments is

exposed much shorter to the marine environment due to the lack of bioturbation (DEMAISON

and MOORE 1980b) which acts as a limiting factor to the diffusion of oxidants into the

sediment, hence microbial sulphate reduction is slowed down if not completely arrested. A

classical observation is the sulphate depletion in pore fluids (MANHEIM 1976). The size of

the particles and the water depth also affect the quality and quantity of the organic matter. The

longer the organic matter resides in the water column, the more it degrades (DEGENS and

MOPPER 1976).

2.4 Diagenesis, catagenesis, and metagenesis of organic matter

Deposited organic matter passes through five stages to be fossilised: Microbial degradation,

condensation, organic diagenesis, thermal alteration and organic metamorphism (HUNT

1974). Stages one to three occur during sediment diagenesis, whereas thermal alteration

occurs during catagenesis – the main phase of hydrocarbon generation – and organic

metamorphism parallels the metamorphism of the sediments (Figure 2.3). During this final

stage, the organic matter is degraded to carbon dioxide and returns to the first organic carbon

cycle.


0.010.01

1

10

100

1000

10000

Diagenesis

Catagenesis

Metagenesis

Dep

th [m

]

Water content [weight-%]

Vitrinite reflectance [% in oil]

Composition of disseminatedorganic matter

Inherited bitumen

HC (+N,S,O)

Ro ~ 0.5

Ro ~ 2.0

Ro ~ 4.0

0 20 40 60 80 100 0 20 40 60 80 100

0 1 2 3 4 5

Gas

Oil

Kerogen

“Humin”

HA FA

CH+AA+L

0.4 0.6 0.8 1.0 1.2 1.40.05 0.15 0.25

Metamorphism

Kerogen elemental analysis(atomic ratios)

H/C O/C

Type III

Type II

Type III

Type II

Carbonresidue

Figure 2.3: Evolution of organic matter during diagenesis, metagenesis and catagenesis, modified from TISSOT and WELTE (1984).

2.4.1 Diagenesis: Kerogen formation

The formation of kerogen in sediments results from the alteration of organic matter as it is

deposited and buried and thus exposed to a higher temperature. Recent organic rich sediments

consist of a mixture of microorganisms, minerals, dead organic material and a large amount of

water. By definition, kerogen is organic matter that is insoluble in organic solvents and acids

(DOW 1977a; DURAND and NICAISE 1980). The major chemical constituents of kerogen

are carbon, hydrogen, and oxygen, with minor amounts of nitrogen and sulphur (MCIVER

1967). Kerogen is to a great extend derived from macromolecules in the lipid or lignin-rich

fractions of biomass that form resistant parts of organisms as membranes, inner cell walls of

woody material, cuticles, spores, pollen etc (LITTKE and WELTE 1992). Mostly the plant

fragments are incorporated in sediments rather as particulates than dissolved organic matter.

Therefore, much of the kerogen is present as microscopically visible parts which are called

macerals (LITTKE and WELTE 1992). Part of the kerogen is completely restructured during

and before early diagenesis. This type of kerogen is microscopically classified as amorphous

or unstructured kerogen (TAYLOR et al. 1998). Bacterial and zooplankton biomass is, in

general, more labile than plant biomass and can therefore be preserved in large amounts only


under favourable environmental conditions (TAYLOR et al. 1998). During diagenesis

significant transformation of the organic matter occurs: Parts of the molecules are lost

(defunctionalisation), hydrogen is added (hydrogenation) or structural changes (isomerisation,

aromatisation) take place (LITTKE and WELTE 1992). Sulphate reduction is by far the most

important biochemical process occurring below the aerobic interval, especially in marine

environments which are characterised by high sulphate availability (TAYLOR et al. 1998).

Incorporation of sulphur into organic molecules takes place during the diagenesis in the upper

few meters of the sediment (LÜCKGE et al. 2002). Source of the sulphur is hydrogen

sulphide (H2S) which is produced in the uppermost sediments by sulphate-reducing organic-

matter-consuming bacteria in anoxic environments (LITTKE and WELTE 1992, LÜCKGE et

al. 2002). A loss of up to 70 % of the initial sedimentary organic carbon by bacterial sulphate

reduction was reported by LÜCKGE et al. (1999). The calculation of the original percentages

of organic matter before sulphate reduction occurred is explained in LITTKE et al. (1991).

At shallow depths, only small amounts of gaseous and liquid hydrocarbons are present, either

inherited from living organisms or formed during diagenesis by microbial activity. With

increasing time and temperature, heteroatomic bonds in kerogen are progressively broken,

which results in oxygen elimination from kerogen noticeable by CO2 and H2O formation

(DOW 1977a). The end of diagenesis of sedimentary organic matter is placed at a vitrinite

reflectance of about 0.5 % (TISSOT and WELTE 1984).

2.4.2 Catagenesis: Petroleum migration

During catagenesis, sediments are buried to depths of several kilometres in subsiding basins.

The burial results in further increase in temperature (~ 50 to 150 °C) and pressure (~30 to

150 MPa). Compaction of rocks, water expulsion and porosity and permeability decrease

continue. The organic matter changes by thermal alteration which involves the cracking of

large molecules to form small compounds (HUNT 1974). Thus, at first liquid petroleum is

produced from the kerogen by C-O and C-S bond breaking (BEHAR et al. 1995), while at

later stages wet gas and condensate are produced, all accompanied by large amounts of

methane. With increasing maturity the generation of gas from both kerogen (primary

cracking) and already generated but unexpelled oil (secondary cracking) increases by

breaking of carbon-carbon bonds (DOW 1977a; HORSFIELD et al. 1991; BEHAR et al.

1995). In oils primarily derived from immature sources, usually a considerable amount of

biomarkers (“molecular fossils”) can be observed. By the analysis of biomarkers, oil-source


correlations as well as the assessment of the depositional environment of the source rock and

the degree of maturation can be deducted.

The quantity and quality of petroleum formed during catagenesis is controlled by the

concentration, the type and the thermal maturity of the kerogen present in source beds (DOW

1977a). As a rule of thumb, approximately 3 to 4 km of burial are required for oil generation

and approximately 4 to 7 km for gas generation. Settings with higher heat flows need less

burial (DOW 1977b). With increasing temperature (depth) the kerogen gets progressively

enriched in carbon by becoming more condensed and aromatic, while the extractable fraction

(bitumen) gets enriched in hydrogen (BARKER 1983). After expulsion from the source rock,

the petroleum migrates driven by buoyancy, capillary pressure and hydrodynamics and can

finally accumulate as crude oil in a reservoir (WELTE and YUKLER 1981). The catagenesis

ends at a vitrinite reflectance of approximately 2.0 % Rr. During the consecutive evolution of

organic matter only gas is generated out of the kerogen.

2.4.3 Metagenesis and metamorphism: Late gas generation

The following two stages are called the metagenesis and the metamorphism stage. Minerals

are severely transformed by increasing temperatures and pressures. All organic matter at this

stage is composed of methane and a carbon residue in which some crystalline ordering begins

to develop. Coals are transformed into anthracite.

During metamorphism anthracite is transferred into metaanthracite, which has a vitrinite

reflectance of more than 4 % Rr. The constituents of the residual kerogen are converted into

graphitic carbon (BARKER 1983). Although methane is thermally stable, it is chemically

reactive at high temperatures and commercial reserves are not known in rocks with maturities

greater than 3.2 % Rr (DOW 1977a).

2.5 Source rocks

Source rocks are defined as rocks that are, may become, or have been able to generate

petroleum (TISSOT and WELTE 1984). The term source rock is applied irrespective of

whether the organic matter is mature or immature. Source rock quality is defined by amount

and type of kerogen and bitumen as well as its stage of maturity.


2.5.1 TOC content

Source rocks can be described in terms of their total organic carbon (TOC) content. However,

not the entire TOC is available to hydrocarbon generation because the conversion of organic

matter to hydrocarbons also depends upon the hydrogen balance, i.e. the convertibility of the

organic matter. Thus, the TOC content provides just an order of magnitude approximation of

the quantity of petroleum formed (DOW 1977a). The measured TOC is present as a soluble

(bitumen) and an insoluble (kerogen) portion. The carbon in the kerogen is present in reactive

and inert forms (COOLES et al. 1986). Reactive kerogen is composed of a labile (oil prone)

and a refractory (gas prone) fraction (CLAYTON 1991a). The inert carbon has no potential to

yield petroleum as it is largely devoid of hydrogen. A minimum TOC content for potential

source rocks to generate enough petroleum for expulsion to occur is difficult to estimate

because several factors besides the quantity are decisive. A threshold exists since a critical

hydrocarbon concentration in the source rock has to be reached before expulsion from the

rock is possible (DOW 1977a). Prior to expulsion the specific hydrocarbon adsorption

capacity of a source rock has to be satisfied. Moreover, sufficient hydrocarbons for the

movement of a pressure-driven hydrocarbon phase have to be available. Estimated minimum

TOC values are 0.3 % for carbonates and 0.5 % for shales. These minimum values apply only

to immature source rock samples because in rocks with an advanced maturity the initial TOC

content may have been almost three times as high, depending on the type of kerogen (DALY

1987).

2.5.2 Kerogen type

The type of kerogen varies referring to the composition of the original biological matter and

to the environmental conditions during diagenesis. Generally, lacustrine and marine organic

matter (kerogen types I and II) have much higher petroleum potential than terrestrial organic

matter (kerogen type III) which predominates on continental shelves, especially in areas

influenced by submarine fans (DOW 1977b; LITTKE and SACHSENHOFER 1994). Type IV

organic matter (residual type), with hydrogen indices lower than 50 mg HC/g TOC, is

composed of oxidised and reworked organic matter (OLUGBEMIRO 1997). Organic matter

in sediments below anoxic water is commonly more abundant and more lipid-rich than

organic matter below oxic water mainly because of the absence of benthonic scavenging

(DEMAISON and MOORE 1980b; KODINA and GALIMOV 1985). Potential oil source

beds are organic-rich sediments containing a kerogen type (mainly type I and II kerogen) that


is sufficiently hydrogen-rich for being mainly converted to oil during thermal maturation

(DEMAISON and MOORE 1980b). Transported terrestrial organic matter, oxidised aquatic

organic matter, and reworked organic mater can amount to about 3 % in marine sediments.

Yet, this organic matter mostly is hydrogen-poor and therefore without any significant oil

generating potential (TISSOT et al. 1974; DOW 1977a).

2.5.3 Sulphur content

The sulphur content in source rocks is related to the environmental conditions at the time of

the source rock deposition (DIDYK et al. 1978). In marine anoxic environments oxidation of

organic matter by microbial sulphate reduction is ubiquitous and the most important

geochemical process (HENRICHS and REEBURGH 1987). The reduced sulphur readily

combines with iron to form iron sulphides (BERNER and RAISWELL 1983; TISSOT and

WELTE 1984; DEAN and ARTHUR 1989). However, sulphur may combine also with

organic matter during diagenesis forming type II-S kerogens, which may yield high-sulphur

crude oils upon catagenesis (TISSOT and WELTE 1984) and differs in kinetic characteristics

from “normal” type II kerogens (BEHAR et al. 1997). The amount of sulphur fixed

organically depends on the quality and quantity of the organic matter (LÜCKGE et al. 2002).

In sediments from offshore Pakistan up to 60 % of the total sulphur content was found to be

bound organically by LÜCKGE et al. (2002). The sulphate reduction leads to a loss of organic

matter which is calculated after LALLIER-VERGÈS et al. (1993) with the “sulphate

reduction index” concept. Besides the consumption of organic matter the sulphurisation leads

to the formation of an organic residue which has a lower susceptibility to attack by sulphate

reducers and thus enhances preservation of organic matter in sediments (SINNINGHE

DAMSTÉ et al. 1989, 1990, 1998; LÜCKGE et al. 1996). The transformation of the organic

matter into non-metabolisable organic matter by sulphur incorporation causes the sulphate

reduction to cease although still rather hydrogen-rich organic matter is present (LÜCKGE et

al. 1996). The incorporation of sulphate into organic matter occurs primarily in the upper few

meters f the sediments (LÜCKGE et al. 2002). This can be seen by the TOC/TS ratios which

decrease continually due to bacterially mediated sulphate reduction in the upper few meters of

sediment (LÜCKGE et al. 1999). In general, low TOC/TS ratios typically are associated with

conditions more favourable for organic matter preservation (LEVENTHAL 1983).


2.5.4 Maceral analysis and vitrinite reflectance

Macerals are components of coals and kerogens and thus are comparable to the minerals

which form rocks (STACH et al. 1982; TAYLOR et al. 1998). Macerals are subdived

according to their reflectivity into three groups: vitrinite, liptinite and inertinite. From a

detailed investigation of the maceral composition, information about the depositional

environment of the respective sediment can be obtained.

The vitrinite group, including several individual vitrinite macerals, is principally derived from

higher land plants and is essentially made of the humified remains of lignin and cellulose of

cell walls (DOW 1977a). The vitrinite macerals are referred to as humic or structured organic

matter (BURGESS 1974 in Dow 1977a). In contrast, the liptinite (or exinite) group is

composed of relatively hydrogen-rich plant material like spores, cutins, resins, waxes, as well

as of the microbial degradation products of proteins and carbohydrates. Generally, it is non-

structured (with the exception of spores and cutins) and consists of indistinguishable masses

of organic debris (DOW 1977a). Inertinite macerals are composed of organic material, which

is oxidised prior to the incorporation into the sediment. The material is very low in hydrogen

and is characterised by condensed aromatic structures (STACH et al. 1982). In contrast to

vitrinites and liptinites, inertinites do not yield petroleum and therefore are often classified as

“dead carbon” (ERDMANN 1975 in DOW 1977b). From a detailed investigation of the

maceral composition of sediments, information about the depositional environment can be

obtained.

Vitrinite reflectance data belong to the most important calibration parameters for the

maturation history of organic matter and is considered the main parameter for determining the

maturity of sedimentary rocks (TEICHMÜLLER and TEICHMÜLLER 1958;

TEICHMÜLLER 1971; TEICHMÜLLER 1982; DURAND et al. 1986; TEICHMÜLLER

1987; OLUGBEMIRO and LIGOUIS 1999). Vitrinite reflectance evolution is much more

sensitive to small temperature changes than most inorganic mineral transformations,

irreversible, and not affected by intrastratal solutions or availability of ions (CASTANO and

SPARKS 1974). Vitrinite is the maceral most often used for rank determinations, because its

optical properties alter more uniformly during catagenesis than do those of the other maceral

groups. It can be used over the entire rank range from lignite to anthracite, and is one of the

most resistant and common constituents of kerogen and coal (DOW 1977a). Regarding

maturity measurements, the best results are obtained from coaly materials, which contain the


highest proportion of vitrinite. In general, the reflectivity increases with decreasing hydrogen

and/or oxygen content (DURAND et al. 1986; HUNT 1991).

2.6 Isotope geochemistry

2.6.1 Introduction

Carbon has two stable isotopes, 12C and 13C, which differ slightly in mass but have essentially

the same chemical properties (BARKER 1996). The variations of the relative amounts of the

stable isotopes in carbon-bearing materials give useful geochemical information. Usually, the

relative abundances of the isotopes are expressed in terms of δ13C values. The most

commonly used standard is the PDB (Peedee Belemnite) standard:

( ) ( )( ) 1000

///

‰ 1213

1213121313 ⋅

−=

PDB

PDBsample

CCCCCC

Cδ ‰ Eq. 2.4

Isotopic variations with respect to hydrogen and its heavier isotope deuterium are reported in

a similar way. The standard for hydrogen isotopic ratios is the SMOW (Standard Mean Ocean

Water) standard:

( ) ( )( ) 1000

///

‰ ⋅−

=SMOW

SMOWsample

HDHDHD

Dδ ‰ Eq. 2.5

According to HOEFS (1997), the distribution of isotopes between two substances or phases is

controlled by isotope exchange reactions or by kinetic processes. The kinetic effects are

connected to incomplete and irreversible reactions like evaporation, dissociation, and

biologically catalysed reactions (HOEFS 1997). In general, the isotope effects during both the

biosynthesis and the decomposition process of organic matter are believed to be determined

by differences in reaction rates of 12C and 13C species in the carbon compound (GALIMOV

1974). The 12C-12C bonds are ruptured more frequently than 12C-13C bonds (GALIMOV

1974). This is caused by the lowering of the molecule’s oscillation frequency and zero-point

energy by the substitution of a 13C atom for a 12C atom in a carbon molecule. Consequently,

greater energy is necessary to break a 13C-12C bond (BRODSKY et al. 1959; SACKETT


1968; SMITH et al. 1971; CLAYTON 1991a). Therefore, it follows that the energy difference

between these two types of isotopic bonds is more significant in organic molecules having a

low relative to high carbon-carbon bond dissociation energy (SACKETT 1968).

2.6.2 Isotope geochemistry of sedimentary organic matter

The distribution of carbon isotopes in kerogen depends on the original isotopic composition of

the organic matter source and on isotope fractionating processes during the formation of

kerogen and bitumen (GALIMOV 1974, figure 2.4).

thermogenicnatural gas

bacterial methane

crude oil

coal

PDBstandardD

iage

netic

/C

atag

enet

ic

kerogen

marine organisms

marine plankton

bulk plants

river / lake DIC and carbonates

marineDIC and

carbonates

Terr

estr

ial /

Fre

shw

ater

Mar

ine

atm. CO2

celluloseSalt marsh plants& tropical grasses

C cycle3

C c

ycle

4

freshwater plankton

δ C (per mil vs. PDB)13

-120 -60 -50 -40 -30 -20 -10 0 +10

CR MF

30°C2°C

marine higher plants

abiogenic methane

Figure 2.4: Range of carbon isotopic ratios of different carbon-bearing substances, modified from WHITICAR (1996b). 13C/12C ratios are expressed in δ-notation relative to the Pee Dee Belemnite (PDB) standard. EIE = Equilibrium Isotope Effect; DIC = dissolved inorganic carbon; CR = methanogenesis by carbonate reduction; MF = methanogenesis by methyl fermentation; C3 = Calvin cycle photosynthesis; C4 = Hatch-Slack photosynthesis cycle.


During diagenesis radical changes in the stable carbon isotopic composition of the organic

matter occur when the activity of microorganisms is greatest (KODINA and GALIMOV

1985), caused by kinetic effects and heterogeneous intermolecular isotope distribution. The

isotope distribution in biogenic molecules is directly related to their chemical structure

(GALIMOV 1980). Carbon of aliphatic chains and methoxyl groups is depleted in 13C,

whereas carbon of carbonyl, carboxyl, phenolic and amine groups is enriched in 13C

(ABELSON and HOERING 1961; VOGLER 1980). As a result, lipids are relatively “light”

(i.e. enriched in 12C) and proteins and carbohydrates are relatively “heavy” (i.e. enriched in 13C) (GALIMOV 1974; GALIMOV 1980). The isotope effects accompanying biochemical

and physiochemical transformations in the geological environment also influence the δ13C

value of kerogen (KODINA and GALIMOV 1985). Under anaerobic conditions lipids

accumulate preferentially because the main mechanism for splitting their aliphatic chains is

the oxidation of fatty acids, which is performed only by aerobic microorganisms

(GOTTSCHALK 1982; KODINA and GALIMOV 1985). The resulting organic matter

exhibits a “light” isotopic signature.

It was observed that terrestrial organic matter is enriched in the lighter isotope, 12C

(GALIMOV 1980) in comparison to marine plankton, with a difference of 5 to 10 ‰. This

distinction reflects the isotopic composition of the carbon source used for photosynthesis:

marine plants utilise carbonate complexes in seawater, whereas terrestrial plants use

atmospheric carbon dioxide with a lower δ13C. The difference is reduced in kerogen of

ancient sediment, but it still amounts to 3 to 5 % (GALIMOV 1980). During diagenesis there

is a slight but systematic enrichment in the lighter isotope 12C. This effect is a result of the

elimination of carboxylic and other functional groups and of an increasing polymerisation

(ABELSON and HOERING 1961). The first hydrocarbons generated show “light” δ13C

values. With progressive maturation the number of available 12C-12C bonds decreases. The

relative number of 13C-12C bonds broken in the carbonized material increases. Thus, the δ13C

values of the resulting gas become increasingly higher (less negative, SACKETT and

MENENDEZ 1972). As original CH3-groups come to be eventually exhausted, methane will

be generated from carbon of CH2- and CH-groups, i.e. isotopically heavier carbon

(GALIMOV 1974).


2.6.3 Isotopic composition of hydrocarbons

Natural gas can be derived from different sources (e.g. microorganisms or thermal

degradation of kerogen), and oil can be derived from different source rocks. Once generated,

all hydrocarbons are subjected to secondary influences (mixing, migration, oxidation etc.).

These different histories of origin and evolution influence the isotopic and molecular

composition of the hydrocarbons (SPIRO et al. 1983; WHITICAR 1994; BARKER 1999a).

To trace back the origin and secondary effects on the hydrocarbons, the molecular

composition and the stable carbon isotopic composition of the bulk hydrocarbons or of each

of its component can be investigated. This information can also be used for correlating

different hydrocarbons or hydrocarbons and their source rocks.

STAHL and CAREY (1975) were among the first to establish relationships between type and

maturity of source rocks and the stable carbon isotope composition of related hydrocarbon

gas. Further models for gas interpretation were established by STAHL et al. (1974),

BERNARD et al. (1976), JAMES (1983), SCHOELL (1983), CLAYTON (1991),

PRINZHOFER and HUC (1995), ROONEY et al. (1995), BERNER and FABER (1996),

CRAMER et al. (1998) and TANG et al. (2000), PATIENCE (2003). Immature natural gas is

commonly very “light” regarding its stable carbon isotope composition and gets continually

“heavier” with increasing maturity. In general, a considerable kinetic isotopic effect occurs

during natural gas formation (WHITICAR 1994; CRAMER et al. 1998). The isotopic

signature of the gas depends partly on the isotopic composition of the source, which leads to

the fact that usually gas from terrestrial source rocks is lighter than gas from marine source

rocks (GALIMOV 1980; WHITICAR 1994). However, the isotopic composition of organic

matter underlies several factors which might reduce or even annihilate this difference.

Changes in the isotopic composition of organic matter during the geological past

(SCHIDLOWSKI 2001) or the composition of the organic matter itself may change the

isotopic composition. An increase of the proportion of C4 plants with respect to C3 plants for

example would lead to an increase in the isotopic ratios of the terrestrial matter (KUMP and

ARTHUR 1999). Especially the generation of microbial methane results in significant isotope

fractionation. The δ13C of biogenic methane is about 30 to 50 % lower than that of the source

organic matter, i.e. the methane is enriched in the “lighter” 12C isotope (FUEX 1977,

SCHOELL 1980). Methane with a carbon isotope ratio lower than about –50 ‰ usually is

considered to have a microbial origin (FUEX 1977), but some overlap between carbon isotope

ratios of microbial and thermogenic methane from low mature source rocks exists (STAHL

1979). Thermogenic gas usually has δ13C values of approximately -55 to -20 ‰ (KLUSMAN


1993). A hint on the thermogenic origin of hydrocarbon gas is the presence of higher

homologues like ethane, propane, butane, pentane, because these gases are formed only in

traces due to microbial activity (BARKER 1999a). Additionally, fractionation of the stable

hydrogen isotopes 1H and D (2H, deuterium) occurs during microbial methane generation. The

hydrogen of the microbial methane is depleted in deuterium by 160 ‰ compared to the

deuterium concentration of the associated water which is the most likely source of hydrogen

(SCHOELL 1980).

Microbial oxidation of hydrocarbons causes the residual hydrocarbons to be depleted in

methane and the remaining methane to be isotopically heavier because bacteria prefer

metabolising methane as well as breaking 12C-12C bonds (COLEMAN et al. 1981; FABER

1987). Especially, sulphate-reducing bacteria are able to oxidise methane in the sulphate

reduction zone (WHITICAR 1996a; BOETIUS et al. 2000; ZHANG et al. 2002). Thereby, the

methane concentration is reduced to very low values and the residual methane is enriched in 13C. The δ13C value may reach -20 ‰ in the upper part of the sediment pile, as compared to -

80 or -90 ‰ in the methane-generation zone (DOOSE 1980 in TISSOT and WELTE 1984).

This should be kept in mind, when interpreting the origin and significance of small amounts

of hydrocarbon in near-surface sediments.

Oil generation is usually associated with a kinetic isotope effect, too. Because of the higher

molecular weight of the components, it is less pronounced than in natural gas. In general, oils

are approximately 1 to 3 ‰ “lighter” than the source rock (HOEFS 1997). The cracking of oil

also seems to be associated with kinetic effects (CLAYTON 1991b). During the cracking

process the gas, as well as the residual oil, gets progressively isotopically heavier until it

approaches the δ13C of the initial oil. Complication arise from the fact that pyrobitumen

(residues) are formed because of the lack of hydrogen which leads to a disproportionation

reaction (BLANC and CONNAN 1994). Cracking leads to an increase of the δ13C value of

the oil. According to CLAYTON (1991b), cracking of about 50 % of an oil results in an

increase of the δ13C value by about 1.5 ‰.

2.7 Surface prospecting geochemistry

The basic assumption for all surface prospecting geochemistry techniques (commonly termed

as “geochemical surface exploration”) is, that gaseous hydrocarbons migrate to the surface

from deep source rocks. Through this process high hydrocarbon concentrations can be created


in surface and near-surface sediments. These hydrocarbons can originate from the microbial

processing of organic matter or the thermal degradation of organic matter (BOTZ et al. 2002).

From the isotopic composition of these hydrocarbons their possible sources can be

distinguished and secondary processes such as gas mixing and hydrocarbon oxidation can be

recognised (SCHOELL 1980; WHITICAR and FABER 1986). The mechanism of this

vertical migration called “microseepage” is still not really understood although this is a

prerequisite for surface prospecting acceptance (KLUSMAN 1993). First research on this

topic was conducted by LAUBMEYER (1933), SOKOLOV (1938) and HORVITZ (1939).

An acid desorption technique was developed by HORVITZ (1954). Since then a lot of

investigations on this topic have been performed (STAHL et al. 1981; PHILP and CRISP

1982; FABER and STAHL 1984; WHITICAR et al. 1985; PRICE 1986; KLUSMAN 1993;

TÓTH 1996; FABER et al. 1997; SCHUMACHER 2000; WHITICAR 2002).

Gaseous hydrocarbons are thought to migrate from the deep subsurface to the sediment

surface and into the atmosphere (FABER et al. 1997). Because empirical relationships for the

composition of natural gas also hold for gas found in surface sediment it is assumed, that gas

does not undergo major compositional changes and isotopic fractionating during the passage

through the sedimentary column. So, the molecular and stable carbon isotopic composition of

this gas is used to deduce type and maturity of the active source rock in the subsurface

(FABER et al. 1997). The free gas present in the pores of near-surface sediments is supposed

to be of microbial origin whereas the hydrocarbon gas adsorbed on the mineral matrix is

thought to be thermogenic gas (FABER et al. 1997).

2.8 Kinetic Theory

Petroleum is generated through the primary cracking of kerogen or secondary cracking of oil

caused by the temperature rise during sediment burial. The degradation of kerogen can be

described by a series of n parallel chemical reactions (TISSOT 1969; CONNAN 1974). Each

chemical reaction obeys first-order kinetics which is characterised by the Arrhenius Law:

TRE

ii

i

eAk ⋅−

⋅= with ki:reaction rate constant of the compound i, Ai : frequency factor of the compound i, Ei : activation energy of the compound i, R: Boltzmann gas constant (8.134 Ws/mol/K), T: absolute temperature [K]

Eq. 2.6


Thus, petroleum generation from each given kerogen can be described with the frequency

factor, the number of chemical reactions and the distribution of the activation energies. The

kinetic approach indicates that the conversion of kerogen to oil and gas is more strongly

effected by temperature (exponential influence) than by time (linear influence, PHILIPPI

1965). The distribution of the activation energies is directly related to the chemical kerogen

composition and is therefore dependent on the kerogen type. Type I kerogens show an

extremely narrow activation energy distribution, whereas the distribution of type II kerogens

is much wider. Type III kerogens are characterised by the widest distribution of activation

energies (figure 2.5).

800

600

400

200

030 40 50 60 70 80

Activation energies [kcal/mole]

X [m

g/g

initi

al T

OC

]io

Greenriver ShaleType I

300

100

200

030 40 50 60 70 80

Activation energies [kcal/mole]

X [m

g/g

initi

al T

OC

]io

Paris BasinType II

60

40

20

030 40 50 60 70 80

Activation energies [kcal/mole]X

[mg/

g in

itial

TO

C]

io

Mahakam Delta

Type III80

100

Figure 2.5: Typical distribution of activation energies for different kerogen types, modified from TISSOT et al. (1987).

Until now, the kinetics of oil to gas cracking are not investigated to the same extent as that of

kerogen cracking (WAPLES 1998). In the basin simulation software package PetroMod (IES,

Germany) oil to gas cracking is modelled applying reaction kinetics by QUIGLEY et al.

(1987). This kinetic data set contains frequency factors and distributions of activation energies

for kerogen to oil and kerogen to gas conversion. Oil to gas cracking is modelled with this

data set by a single activation energy, a frequency factor and a reduction factor which

describes the reduction of the mass of organic matter because oil cracking is associated with a

disproportionation reaction leading to hydrocarbon gas and a carbon residue.

2.9 Hydrocarbon migration and accumulation

Petroleum accumulations are mostly found in highly porous and permeable rocks. The fact

that petroleum is not generated in place was recognised in the 1950’s (TISSOT 1987). A

compilation of arguments for the need of migration from a source to a reservoir can be found


in NORTH (1985). The migration of hydrocarbons is subdivided into primary migration

inside the source rock and secondary migration in the carrier rock (figure 2.6).

Figure 2.6: Hydrocarbon expulsion, migration and accumulation, modified from TISSOT and WELTE (1984).

2.9.1 Primary migration: Expulsion

Primary migration is defined as the liberation of hydrocarbons from the kerogen and the

motion of the hydrocarbons through the source rock (WELTE and YUKLER 1981). First,

separate petroleum phases form a discontinuous network, when hydrocarbons are generated in

source rocks in sufficient quantities to saturate the pore water and the adsorptive capacities of

the pore surfaces. Deeper burial increases the hydrocarbon concentration and the pressure

inside the source rock and drives on compaction, which tends to squeeze oil out of the rock.

The generation of further hydrocarbons may overpressure the system. Thus, a pressure

gradient from inside the source rock to its effective boundary is established. The pressure

gradient is greater than the hydrostatic gradient so that oil can be expelled downwards and out

of the bottom of the source rock, just as well as upwards and out of the top. Thus, it is

possible for a reservoir to lie directly under a source rock. Gas migrates in a slightly different

way because pressure relationships are different accounting for the compressibility of the gas


phase. Additionally, the gas molecules are smaller thus having a higher solubility in water.

Also diffusion can be a major transport mechanism (BARKER 1996).

The expulsion of hydrocarbons from source rocks is not complete. The expulsion efficiency

depends on the TOC content and the type of organic matter in the source rock . The higher the

organic matter content, the earlier the expulsion will start, and the higher the expulsion

percentage will be (LEYTHAEUSER et al. 1988). Very organic rich rocks expel more than

80 % of the generated bitumen (MACKENZIE et al. 1987; ESPITALIÉ et al. 1988; BURRUS

et al. 1996). If the rock does not generate enough bitumen to induce migration, no

hydrocarbons will be expelled, and with rising temperature the organic matter inside the rock

will be cracked to gas. The gas may be expelled later (due to the volume increase during

secondary cracking), so that a lean rock tends to be a gas source, regardless of the type of

organic matter it contains. Additionally, with respect to carrier beds, the stratigraphic

distribution of organic matter is also critical. Thick source units tend to have less effective

expulsion efficiencies than thinner source horizons interbedded with carrier beds

(LEYTHAEUSER et al. 1984).

2.9.2 Secondary migration, accumulation

Primary migration ends with the expulsion of hydrocarbons from the source rock. The flow of

hydrocarbons in carrier rocks is called secondary migration, which is controlled by buoyancy,

capillary pressure, and hydrodynamics. The mileage can amount to more than 100 km

horizontally and thousands of meters vertically (DEMAISON and HUIZINGA 1991).

Adequate conduits may be provided by laterally continuous permeable rock strata, by faults or

in some cases by unconformable surfaces, where permeability has developed. Buoyancy is the

main force acting on oil droplets in carrier beds and operates vertically upwards, so that oil

droplets will tend to move up. A drop may be stopped initially at a narrow constriction, but as

more oil accumulates below it, the pressure difference rises, until finally the oil moves

through. If the rising oil meets a rock, which has very small pores (i.e. shale) or is effectively

impermeable (e.g. evaporate or cemented carbonate), the pressure generated by buoyancy

may never become high enough to continue moving the oil upwards. The overlying rock is

then acting as a seal. In the case of downward expulsion the shale can act simultaneously as

source rock and shale, because the internal overpressure in the source rock due to

hydrocarbon generation is high enough to permit hydrocarbon motion through the rock.

Geology of the Namibia and South African rifted continental margin 21

3 Geology of the Namibian and South African rifted

continental margin

Passive continental margins develop at the junction of continental and oceanic crust within

plate interiors as a result of continental splitting either by rifting at sites of generation of new

ocean crust or by transform faulting. After splitting, the margins formed by predominantly

vertical tectonics. According to (BOTT 1980), the history of a rifted continental margin can

be subdivided into four stages:

• a rift valley stage which may involve thermal uplift and graben formation before

continental splitting (e.g. East African rift system and the Baikal rifts)

• a youthful stage lasting about 50 Ma after splitting of the continents. During this stage the

thermal effects of the split are strongly felt (e.g. Red Sea margins)

• a mature stage during which more subdued development starts

• a fracture stage when subduction starts, terminating the history as a passive margin.

In general, the time statements are reported unchanged in this story. For the modelling study,

the timescale of HAQ et al (1988) was chosen. The stratigraphic subdivision of the south-

western African continental margin is shown in fig. 3.3.

3.1 Outline of the break-up of Gondwana and the subsequent

evolution of the southwest African continental margin

The continental margins of south-western Africa and Argentina are rifted plate margins

underlain by pre- and synrift graben basins and covered by postrift or passive margin

sediments (BROAD and MILLS 1993). The formation of the margins resulted from the break-

up of the Gondwana supercontinent which originally comprised Africa, South America,

Antarctica, Madagascar, India and Australia at the end of the Precambrian/Cambrium

(DINGLE and SCRUTTON 1974; LAWVER et al. 1992). Following successive late

Carboniferous to Early Jurassic rifting episodes major intracontinental rift developed between

Africa and South America, in crust composed of granitic, metamorphic, and sedimentary

rocks ranging from Precambrian to Carboniferous to Permian age (EMERY et al. 1975;

GERRARD and SMITH 1983). Initiation of this Late Jurassic / early Cretaceous rifting in the

southern portion of the South Atlantic is estimated by e.g. ULIANA et al. (1989) and


STOLLHOFEN (1999) to occur at 160 Ma and by NÜRNBERG and MÜLLER (1991) at

150 Map. The opening of the South Atlantic was diachronous, rejuvenating from South to

North (e.g. RABINOWITZ 1976; RABINOWITZ and LABRECQUE 1979; AUSTIN and

UCHUPI 1982; EMERY and UCHUPI 1984; SIBUET et al. 1984a; HAWKESWORTH et al.

1992; figure 3.1) and occurring close to the Japetus Suture which is a hint that the new rift

used an old line of weakness for its development (WILSON 1966).

Figure 3.1: Reconstruction of the opening of the South Atlantic Ocean based on magnetic anomalies M0 to M9, modified from RABINOWITZ and LABRECQUE (1979).

Today, the south-western African offshore region is divided into four basins which essentially

record postrift geometries above earlier pre-South Atlantic rift structures. These basins are

termed from north to south: Namibe, Walvis, Lüderitz and Orange Basin (MILLER 1992,

figure 3.2). Initially, these basins were well defined and separated according to their basement

structure but since the Upper Cretaceous the basins are connected thus losing their

individuality (GERRARD and SMITH 1983). The Orange Basin in which the Kudu gas field,

the main focus of the study at hand, is located is underlain by several stacked rift basins of an

Titonian - Berriasian (150 - 140 Ma) Aptian (115 Ma)

Albian (100 Ma) Campanian (80 Ma)

Malvinas Plateau Malvinas Plateau

Malvinas Plateau Malvinas Plateau

SOUTH

AM

ERIC

A

AFRIC

A

SOUTH

AM

ERIC

A

AFRIC

A

SOUTH

AM

ERIC

A

AFRIC

A

SOUTH

AM

ERIC

A

AFRIC

A

Walvis

Torres Arch

Walvis

Torres Arch Torres ArchG

G

M3

M0

M2

M4 G

M0

M2

M4

M0

M7

M2

M4

M0

Fracture Zone Fracture Zone

Fracture Zone

G

M3

M0

M2

M4 G

M0

M2

M4

M0

M9

M2

M4

M0

M7 G

G

M3

M0

M2

M4G

M0

M2

M7

M2

M4

M0 M

9 G

M4

Rio Grande Rise

WalvisRidge


Early Cretaceous minimum age. The basin is filled with postrift Cretaceous siliciclastic rocks

ranging in age from late Hauterivian drift onset to Tertiary (BROWN et al. 1995). At least

8000 m of drift sequence sediments accumulated in the Orange Basin, which is by far the

largest drift sequence sediment thicknes along the southwest African margin.

SOUTHAMERICA

AFRICA

SOUTHATLANTIC

Karoo Basin

Paraná Basin

Niger Basin

GabonBasin

CongoBasin

BenguelaBasin

Main KarooBasin

MossamedesBasin

Kib

arid

e Be

lt

Irumde

Belt

Moc

ambi

que

Belt

NamibeBasin

WalvisRidgeRio Grande

Rise WalvisBasin

LuderitzBasin

OrangeBasin

Toscanini

Huab

Kudu

361 Agulhas Basin

AJ-1

Falkland Agulhas FZ

FalklandPlateau

Malvinas Basin

East Falkland

Basin

200 m

3000 m

3000 m

200

m

Karoo Basins

Marginal Basins

DSDP Sites361

PontiguarBasin

Pernambuco-Paraiba BasinSergipe-Alagoas Basin

Reconcavo Basin

Espirito Santo BasinCampos

Basin

SantosBasin

PelotasBasin

SaladoBasin

ColoradoBasin

Valdez-RawsonBasin

San JorgeBasin

MagellanesBasin

Figure 3.2: Structural framework of the south-western continental margin of Africa and south-western South America. The width of the South Atlantic is not to scale and was chosen arbitrarily in order to show both continental margins in one picture.

At the Argentine margin, the basins from north to south are termed Salado Basin, Colorado

Basin, Valdes Basin, Rawson Basin, San Jorge Basin, Magellanes Basin and Malvinas Basin

(URIEN and ZAMBRANO 1973; DINGLE et al. 1983; BROWN et al. 1995; URIEN et al.


1995, figure 3.2). In contrast to the southern African basins which all are elongated parallel to

the continental margin, the South American basins can be subdivided into different basin

types: Some of the basins are perpendicular to the continental margin (Colorado and Salado

Basin) and some do not reach the continental margin and are developed only on the

continental shelf (e.g. San Jorge and Valdes Basin). The Magellanes and Malvinas Basins

finally are true geosynclines according to URIEN and ZAMBRANO (1973).

At the South African continental margin, the opening of the South Atlantic is recorded by five

main tectono-stratigraphic sequences (figure 3.3): The Basin and Range or prerift

megasequence, the synrift I and II megasequences, the transitional and the thermal sag

megasequences (MASLANYI et al. 1992; LIGHT et al. 1993b).

Figure 3.3: Stratigraphy and seismic horizons of the south-west African offshore, modified from Light et al. (1993b).

Facies Megasequences

TERT

IARY

CR

ETA

CEO

US

JURASSIC

TRIASSIC

PERMIAN

U

M

UL

Sour

cePo

tent

ial

Seis

mic

Hor

izon

s

L

NPQ

R

T

W

Kudu

Shelf clastics

Open marine shales Marginal marine sandstones

Braided fluvial clastics

Alluvial outwash clastics

Volcanics

Slope Clastics

Turbidites

Restricted marine shalesoil source

gas source

Thermalsag

TransitionalSynrift II

Synrift I

Basinand

Range

A-J1

Drif

tPr

erift

Synr

ift


The Basin and Range megasequence is terminated by the Late Jurassic (i.e. Kimmerdgian-

Oxfordian, 155.5 Ma) angular rift onset unconformity (horizon T) marking the onset of the

synrift I megasequence (MASLANYI et al. 1992; LIGHT et al. 1993b). Stratigraphic

information from onshore and offshore Namibia is compiled in figure 3.4.

N SS. Namibe

BasinWalvis Ridge

Onshore Huab/Etjo

Areas

Walvis Basin

Lüderitz/OrangeBasin

DSDP Boreholes Toscanini 2012/13-1 KuduAgePleist.Pliocene

Miocene

Oligocene

Eocene

PaleoceneMaastr.CampianSantonianConianianTuronianCenoman.Albian

AptianBarrem.Hauteriv.ValanginBerriasian

TE

RT

IAR

YC

RE

TAC

EO

US

Early

Late

Pale

og.

Neo

gene

PER

MIA

NT

RIA

SSIC

PROTEROZOICto

E. CAMBIRAN

Late

Drif

tPr

erift

Syn

& S

DR

SEa

rlyD

rift

Figure 3.4: Stratigraphic columns modified from Namcor (information from the 3rd licensing round 1999). The colours in the figure indicate: green = shale; yellow = sand; pink = basement; blue = carbonates; purple = basalt; grey = hiatus; light green = ooze. The borders between the phases prerift to late drift indicated left of the stratigraphic columns are not sharp in time and vary along the continental margin. They are only shown for a rough orientation.

The Jurassic / Cretaceous rifting of the continental crust off South Africa formed several

grabens and half-grabens along a trend subparallel to the present coastline (LIGHT et al.

1993b). Predominantly, the block-faulted rift basins are filled with Lower Cretaceous alluvial

and fluvial sediments (LIGHT et al. 1993b; MUNTINGH 1993; MUNTINGH and BROWN

1993; JUNGSLAGER 1999) which rest unconformable on a prerift basement of Precambrian

to Paleozoic age, equivalent to the rift onset unconformity horizon T (FALVEY 1974;

GERRARD and SMITH 1983; MUNTINGH and BROWN 1993; BROWN et al. 1995).

Continental shales and sandstones have been encountered in the A-J1 well in a graben

offshore South Africa (BARTON et al. 1993). Volcanic rocks are also widespread, and


present within the rift basins (BARTON et al. 1993; MILLER 1998). The top of synrift I

megasequence (horizon R) complies with the Valanginian unconformity recognized in the

well Kudu 9A-3 between the Jurassic and the Valanginian gas sands (WICKENS and

MCLACHLAN 1990; BRAY et al. 1998).

According to GERRARD and SMITH (1983), this Valanginian unconformity represents the

break-up unconformity south of the Karasburg-Orange and south of the Salado-Orange

transform fault, respectively. In the northern part of the Namibian offshore a second synrift

event has been recognised, which is manifested by the Hauterivian-Barremian angular

unconformity (horizon Q, MASLANYI et al. 1992). This Valanginian / Hauterivian synrift

event was associated with widespread volcanism. The volcanics erupted at this time

correspond to the Etendeka and Paraná flood basalts and were emplaced during the last phases

of rifting and the initial stage of drifting (SIEDNER and MILLER 1968; GIDSKEHAUG et

al. 1975; PEATE et al. 1988). The Etendeka basalts are interpreted to correlate with the

Paraná flood basalt province of South Africa and have been dated to 133 to 132 Ma by

RENNE et al. (1996) whereas TURNER et al. (1994) indicated that the Paraná-Etendeka

continental flood basalts were erupted over 10 Ma between 137 and 127 Ma. As described by

LIGHT et al. (1993b) the R-Q interval corresponds to the synrift II megasequence and

includes the Etendeka flood basalts and the Twyfelfontein formation, which is characterised

by aeolian deposits (STOLLHOFEN 1999). This interval occurs in the northern part of the

Orange Basins and in the Walvis Basin. North of the Walvis Ridge it is absent.

Sea floor spreading started according to AUSTIN and UCHUPI (1982) with the formation of

magnetic anomaly M9 (126-121 Ma) south of the Orange River and with M4 (123-117 Ma)

north of the Orange River. STOLLHOFEN (1999) suggests that oceanic onset started at the

latest with seafloor anomaly M10 during Valanginian / Hauterivian times in the rift segment

south of the Karasburg/Orange transform and propagated as far northwards as the Walvis

Ridge, at the latest, with anomaly M4. EMERY and UCHUPI (1984) put the beginning of

sea-floor spreading near the southern end of the Cape Basin at 119 Ma when the Falkland

Plateau began to separate from southern Africa. According to GERRARD and SMITH

(1983), seafloor-spreading started south of Agulhas with anomaly M12 in the Middle

Valanginian, whereas after RABINOWITZ and LABRECQUE (1979) it began with anomaly

M13 in the Lower Valanginian. According to LARSON and PITMAN III (1972), the

continental drift phase in the South Atlantic was initiated between 110 and 85 Ma, probably

close to 110 Ma. BROWN et al. (1995) place the drift onset along the south-western margin


of the African plate at 117.5 Ma which is adopted for the present study. The Mid-Aptian

horizon P represents the break-up unconformity north of the Walvis Ridge. Break-up occurred

in the Lüderitz Basin in the Earliest Barremian and in the Walvis Basin in the Early Aptian

(CLEMSON et al. 1997).

The transitional megasequence (Hauterivian/Barremian to Mid-Aptian) represents the

beginning of thermal sagging of the passive margin of Namibia (LIGHT et al. 1992)

(MASLANYI et al. 1992). The margin experienced rapid upbuilding and outbuilding onto a

subsiding, tension-rifted basement (SIESSER et al. 1974). This succession, intersected by the

Kudu wells, shows a transition from continental deposits (basaltic-volcanic to aeolian-fluvial

sands) in the lower part to marine sediments in the upper part (WICKENS and

MCLACHLAN 1990; LIGHT et al. 1993a; MUNTINGH 1993; MILLER and CARSTENS

1994). Marine sedimentation began in Aptian times around Angola and even earlier at the

margin to the south (SIESSER et al. 1974; DINGLE 1993). Early drift sediments indicate

restricted marine conditions until the beginning of the main drifting phase in the Aptian

(DINGLE 1993).

During the thermal sag phase, which is divided into the Aptian to Turonian (horizons P – N in

figure 3.3) and the Turonian to base Tertiary (horizons N - L in figure 3.3) sequence, a

seaward progression of the base of slope and the base of rise can be observed (BRAY et al.

1998). Large amounts of sediments were supplied by the ancestral Orange, Olifant and Cuene

Rivers (MASLANYI et al. 1992; MUNTINGH and BROWN 1993; BROWN et al. 1995;

BRAY and LAWRENCE 1999). The Turonian to base Tertiary succession developed during

continued sagging and tilting of the continental margin (RONA 1974; LIGHT et al. 1993a).

The Upper Cretaceous is the period with the highest sedimentation rates (figure 3.5) during

the development of the continental margin (PATRIDGE and MAUD 1987).

These sediments are synsedimentary faulted and slumped (DINGLE and ROBSON 1992).

Turbidites are present in this interval (BOLLI et al. 1978b). Sapropelic, Lower to Middle

Aptian and Cenomanian / Turonian source rocks may occur within the succession south of the

Walvis Ridge (BROAD and MILLS 1993; BRAY et al. 1998). Offshore Namibia, the postrift

sedimentation is developed as a thick wedge of clastic sediments with an overall

progradational nature mainly due to the construction of large growth-faulted delta systems

during the mid to late Cretaceous (BRAY and LAWRENCE 1999). The subsidence of the

continental margin is highest between the Orange River and Cape Columbine south of the

Orange River. Here, up to 5.1 km of sediment was deposited from Aptian to Maastrichtian


times (DINGLE and ROBSON 1992). The subsidence of the Orange Basin was non-periodic,

presumable controlled by both thermal decay subsidence and loading by the westward-

prograding Orange River deltaic complex (MUNTINGH and BROWN 1993).

Figure 3.5: Sedimentation rates derived from commercial borehole records, modified from RUST and SUMMERFIELD (1990).

The Cenozoic succession in the Orange Basin displays sequences and bounding

unconformities lying mostly basinward of the youngest Cretaceous offlap break

(MUNTINGH and BROWN 1993). Today’s Orange River delta is at the northern end of the

Orange Basin. During the Neogene and Quarternary the Orange River delivered only 5 % of

its Cretaceous sediment amount. Therefore the post Palaeogene sedimentary layers are quite

thin (< 250 m, DINGLE and ROBSON 1992). The evolution of the outer continental margin

is influenced significantly by the position of the post rift depocentres, the climate of the

hinterland, the evolution of the deep water circulation and the drainage development of the

Orange River (DINGLE and ROBSON 1992). Late Miocene Antarctic Bottom Water

(AABW) might have eroded about 500 m of the post Eocene sediments in the vicinity of well

DSDP 361 (DINGLE and ROBSON 1992). The modern outer continental rise offshore south-

0

50

100

150

Plio

Mio

Olig

Eoc

PalMaasCampSantConTurCenAlbAptBarrHautValBerrPort

KimmOxfCallBath

0 100 200 300 0 100

Kudu 9A-1 Orange Basin Walvis Ridge

0 100

m/Ma m/Ma

m/Ma


western Africa was probably located in a zone of strong AABW currents, as is indicated by

Tertiary manganese nodules (DINGLE and ROBSON 1992).

3.2 Volcanic continental margin evolution

Rifted continental margins can be subdivided into non-volcanic and volcanic margins

(MUTTER et al. 1987, figure 3.6). Whether a volcanic margin develops or not is a

consequence of the relative magnitude of magmatism during break-up. This magnitude of

volcanism depends on the temperature and fluid content of the asthenosphere along the

incipient plate boundary and the dynamic history of the lithosphere during the synrift phase

(ELDHOLM et al. 1995). Together with continental flood basalts, oceanic plateaus and ocean

basin flood basalts, the volcanic margins constitute the main categories of transient large

igneous provinces (LIPs), characterised by voluminous emplacements of predominantly mafic

rocks over short time spans (ELDHOLM et al. 1995). Massive extrusive complexes along

rifted margins were first recognised along the Vöring and Lofoten margins off Norway by the

exceptionally smooth acoustic basement surface near the continent-ocean boundary

(TALWANI and ELDHOLM 1972), later by the existence of wedges of seaward dipping,

intrabasement reflectors below the acoustic basement (HINZ and WEBER 1975). According

to HINZ (1981), the distinct unconformity immediately above the wedges marks the onset of

sea-floor spreading in sensu stricto. The lithology of the seaward dipping reflector sequences

(SDRS) is still unknown at this time. MUTTER et al. (1982) suggested that the seaward

dipping wedge at the Norwegian coast could be accounted for by oceanic crustal accretion

because of its association with magnetic anomalies. BRAY and LAWRENCE (1999) found

the seaward dipping wedges at the African continental margin to consist of numerous

subaerially emplaced basalt flows and thin interbedded sedimentary layers. The SDRS (figure

3.7) are accounted for by MUTTER et al. (1988) to convective partial melting caused by

lateral temperature differences due to the rifting process. WHITE and MCKENZIE (1989)

propose that decompression melting and increased volcanism is due to passive rifting of a

mantle plume. CAMPBELL and GRIFFITHS (1990) and DUNCAN and RICHARDS (1991)

argue for a model of decompression melting within a rising plume head resulting in a rapid

and vigorous burst of volcanism. HINZ et al. (1999) suppose deep and sharp lithospheric

ruptures forming a fast propagating rift zone as mechanism for the transient excess melting by

decompression. The fast propagaton of the rifting at the Argentine margin argues against the


assumption of a plume involved in volcanic margin formation (pers. comm. Dr. K. Hinz,

Dr. D. Franke, BGR).

Lower continental crust

Figure 3.6: Sketch of an idealised volcanic margin, modified from LARSEN and SAUNDERS (1998).

Flows Dyke injectionContinental crust

Mantle

Sea levelSpreading centre

1 2

3 4

Figure 3.7: Model for the emplacement of seaward dipping reflector sequences, modified from MUTTER (1985). The evolution of the SDRS involve doming and dyke injection (1), successive emplacement of lava flows (1-4) which after cooling and loading with additional flows subside (2-4) and to dip in seaward direction (4).


During the opening of the South Atlantic Ocean, volcanism led to the formation of

widespread continental flood basalts - for example the Etendeka and Paraná flood basalt

provinces in Africa and South America - and of wide zones of seaward dipping seismic

reflection sequences (HINZ 1981; AUSTIN and UCHUPI 1982; GERRARD and SMITH

1983; ELDHOLM et al. 1995; GLADCZENKO et al. 1998; BAUER et al. 2000; JACKSON

et al. 2000). Originally, these SDRS were deposited in a subaerial to shallow marine

environments (MUTTER et al. 1982; ELDHOLM et al. 1995). Today the SDRS are located at

water depths of 200 to 4500 m. About 70 % of the continental margins of the Atlantic Ocean

are underlain by SDRS (PLANKE et al. 1999). The continental flood basalts of the Paraná

province and of the Etendeka province are supposed to be connected with the activity of the

Tristan da Cunha hot spot (OĆONNOR and DUNCAN 1990).

3.3 Evolution of the Walvis Ridge and Rio Grande Rise

The Walvis Ridge and Rio Grande Rise are aseismic ridges trending northeastward and

northwestward, respectively (FRANCHETEAU and PICHON 1972; DETRICK et al. 1977;

LINDEN 1980; SIBUET et al. 1984b; OĆONNOR and DUNCAN 1990, figure 3.1 and

figure 3.2). They were not axes of sea-floor spreading which is indicated by the fact that the

ridges run across the trend of the magnetic anomaly pattern (LADD et al. 1974). Minimum

water depths at the crest of the Walvis Ridge today amount to 1 km (LINDEN 1980). The

ridges are oceanic in origin (DETRICK et al. 1977; MOORE et al. 1983; ; SIBUET et al.

1984b; OĆONNOR and DUNCAN 1990).

Walvis Ridge and Rio Grande Rise formed at or near the Middle Atlantic Ridge in response to

the divergence of Africa and South America, possibly along transform faults or marginal

offsets (FRANCHETEAU and PICHON 1972; SIBUET et al. 1984b). It was suggested that

the Walvis Ridge and the Rio Grande Rise were generated by spreading plates moving

relative to the Tristan da Cunha hot spot (WILSON 1963; DIETZ and HOLDEN 1970;

MORGAN 1971; OĆONNOR and DUNCAN 1990). The spreading axis stayed in the

vicinity of the hot spot, causing volcanic rocks at both continental margins and being involved

in the formation of the Walvis Ridge – Rio Grande Rise volcanic system FRANCHETEAU

and PICHON (1972) and LABRECQUE et al. (1984) favour the relation of the Walvis and

Rio Grande Ridges to major fracture zones.


The geology of the South Atlantic continental margins is strikingly different north of the

Walvis Ridge Rio Grande Rise from that in the south. This is an effect of the earlier opening

of the southern sequences of the South Atlantic Ocean and of the profound influence the

Walvis Ridge and Rio Grande Rise had as a tectonic feature and as a physical barrier to both

oceanic and sediment circulation until approximately 80 Ma ( LEPICHON and HAYES 1971;

DINGLE and SCRUTTON 1974). The areas south of the Walvis Ridge and Rio Grande Rise

lack the presence of Cretaceous salt basins, which are important features north of the Walvis

Ridge (LEPICHON and HAYES 1971).

Petroleum systems of the Namibian and South African rifted continental margin 33

4 Petroleum systems of the Namibian and South African

rifted continental margin

4.1 Introduction

A petroleum system is defined by the essential elements and processes and all genetically

related hydrocarbons that occur in petroleum shows and accumulations whose provenance is a

single pod of active source rock (MAGOON 1988). Elements of the system are source rock,

migration route, reservoir rock, seal rock and trap. Processes are hydrocarbon generation,

migration, accumulation and preservation. The timing of the hydrocarbon generation is of

importance, which means that the trap has to be formed before and during petroleum

formation and migration (BIDDLE and WIELCHOWSKY 1994). Otherwise the

hydrocarbons will get lost from the petroleum system (MAGOON 1988).

The South Atlantic setting provides the general possibility for different petroleum systems

(figure 4.1): The formation of source rocks is connected to the phases of the evolution of the

passive continental margins: prerift, synrift, transitional and thermal sag (drift). During the

prerift and synrift phases predominantly lacustrine source rocks were deposited (BRAY et al.

1998; JUNGSLAGER 1999). The transitional phase is characterised by restricted marine

conditions allowing for the deposition of marine source rocks (TISSOT et al. 1980; BARTON

et al. 1993) but terrestrial organic matter transported by rivers can also be present in the

source rocks (TISSOT et al. 1980). During the thermal sag / drift phase, organic rich

sediments are deposited predominantly in upwelling areas due to the high biological

productivity of these regions (CALVERT and PRICE 1971; DEMAISON and MOORE

1980a; BARKER 1983). According to COWARD et al. (1999), about 80 % of the discovered

hydrocarbon reserves at both continental margins originate from the postrift and about 20 %

from the syn- and prerift section. Reservoir and seal rocks are widespread and several

stratigraphic traps have been encountered in the African and South American offshore

(BRAY et al. 1998; BAGGULEY and PROSSER 1999; BRAY and LAWRENCE 1999;

JUNGSLAGER 1999; BUSHNELL et al. 2000).


CRET

AC

EOU

SPA

LEO

GEN

EEa

rlyM

iddl

eLa

teEa

rlyLa

te

TithonianKimmeridgianOxfordianCallovianBathonian

BajocianAalenian

Toarcian

Pliensbachian

Sinemurian

Hettangian

Berriasian

HauterivianBarremianAptian

Albian

CenomanianTuronianSantonianCampanian

MaastrichtianDanianSelandinianThanetianYpresian

Lutetian

BartonianPriabonian

Rupelian

Chattian

Mio

cene

Plio

-ce

ne

Aquatanian

Burlandigian

Langhian

Serravallian

Messian

Tortonian

ZancleanPiacenzian

NEO

GEN

E

QUARTERNARY

GeologicTime Scale

PetroleumSystem Events Source

Rocks Seal RocksTrap

FormationGeneration, Migration,

AccumulationReservoir

RocksJU

RA

SSIC

Early

Mid

dle

Late

TRIA

SSIC

Early

Mid

dle

Late

PERM

IAN

Early

Late

Asselian

Sakmarian

Artinskian

Kungurian

Kazanian

TatarianTatarianInduanOlenekian

Anisian

Landian

Carnian

Norian

Rhaetian

Valanginian

Etjo

Whitehill/Ver-brande Berg Fm.

Synrift (AJ1)

Transitional (Kudu/

DSDP 361)

Mature drift, north WR

Transitional (Kudu)

Fluvial sst(Ibuhbesi)

Kudu reservoir

Tsrabis Fm.Verbrande Berg Fm.

Gudaus Fm.

Turbiditic

reservoirs in

transitional

sequence

Seal rocks

in Creatceous

and Tertiary

sediment pile

Botucatu/Plateau sst.

Dwyka Fm.

DSDP 330and 511

Rift basins

Oil expulsion in the Kudu SR

Kudu

DSDP 360, 361

Mature drift

Synrift

Figure 4.1: Petroleum system chart for the continental margin of south-western Africa, compiled from MILLER (1992), BARTON et al. (1993), BRAY et al. (1998), STOLLHOFEN (1999).


4.2 The constituents of the petroleum systems of the Namibian and

South African rifted continental margin

4.2.1 Source rocks

4.2.1.1 Prerift phase

The oldest rocks in the south-western African offshore region are carbonaceous shales and

coals of the Verbrande Berg Formation which reach 110 m in thickness in a Permo-Triassic

graben at the mouth of the Huab River in NW Namibia (ERLANK et al. 1984). Above this,

the Probeer Member in the Huab Basin, Namibia, the Whitehill shale in the Namibian Aranos

and the South African Karoo Basin and the Irati shale in Brazil contain potential source rocks

(ANDERSON and MCLACHLAN 1979; OELOFSEN 1987; MILLER 1992; VISSER 1992).

The Namibian Whitehill shale is characterised by lower TOC contents (max. 10 % TOC)

compared to its Brazilian equivalent, the Irati Shale (in parts more than 20 % TOC,

OELOFSEN 1987) and is partly riddled with dolerite sills and dykes which occur throughout

the Karoo Basin causing high maturity within the adjacent organic matter (HARGRAVES et

al. 1997). At the Argentine margin Permian lacustrine source rocks in the Colorado Basin in

the Cruz del Sur and Puelche wells have hydrogen indices of about 200 to 300 mg HC/g TOC

(KEELEY and LIGHT 1993; FRYKLUND et al. 1996; BUSHNELL et al. 2000).

4.2.1.2 Synrift phase

Jurassic to Neocomian source rock depocentres of both marine and lacustrine facies occur in

several isolated south-western Gondwana prerift or synrift grabens (TISSOT et al. 1980) as is

proven in well A-J1 in a halfgraben offshore South Africa (JUNGSLAGER 1999). Older

synrift source rocks with hydrogen indices up to 500 mg HC/g TOC were drilled in the

Colorado Basin by the wells Cruz del Sur and Puelche (LAFITTE 1994; STARLING 1994

both cited in SCHÜMANN 2002). On the Falkland Plateau marine source rocks with up to

5 % TOC were drilled in the wells DSDP 327, 330 and 511 (TISSOT et al. 1980).

Furthermore, lower Cretaceous lacustrine source rocks with good to very good hydrocarbon

source potential were encountered offshore Uruguay and offshore Brazil (PONTE et al. 1980;

ESTRELLA et al. 1984; MELLO et al. 1987; GUARDADO et al. 1989).


4.2.1.3 Transitional to thermal sag phase

Excellent Albian to Aptian immature marine source rocks were encountered in the DSDP 361

well in the Cape Basin offshore South Africa (BOLLI et al. 1978b; STEIN et al. 1986; BRAY

et al. 1998; JUNGSLAGER 1999). The rocks contain up to 20 % TOC of both marine and

terrestrial origin (BRAY et al. 1998). These shales are known to thicken and become more

deeply buried and thus more mature towards the present continental shelf of south-western

Africa (EMERY et al. 1975). According to JUNGSLAGER (1998), gas generated by the more

proximal and deeply buried correlatives of these oil-prone shales and from Barremian shales

charges the Albian discoveries off South Africa and the Kudu gas field off Namibia. Well

DSDP 364 north of the Walvis Ridge intersected Early to Middle Albian dark organic rich

shales containing type II kerogen with up to 29 % TOC and HI values up to

800 mg HC/g TOC (FORESMAN 1978; STEIN et al. 1986). In the San Jorge Basin,

Argentina, lacustrine Lower Cretaceous source rocks of the D-129 formation were found

(RODRIGUEZ and LITTKE 2001). Cenonamian to Coniacian organic rich shales with up to

4 % TOC were deposited in basins south of Walvis Ridge containing large quantities of

terrestrial organic matter leading to HI values below 100 mg HC/g TOC (HERBIN et al.

1987). North of the Walvis Ridge in the Angola Basin late Albian to Coniacian black shales

with up to 6.5 % TOC were found in well DSDP 530 (DEROO et al. 1984; STEIN 1986). In

the Corona Austral, Cruz del Sur and Puelche wells in the Colorado Basin Danian bathyal

potential source shales were drilled (BUSHNELL et al. 2000).

4.2.2 Source rock maturation

Vitrinite reflectance measurements from offshore south-western Africa are only available for

the Kudu and DSDP 361 wells. From the vitrinite reflectance in the Kudu wells the onset of

oil generation is inferred at approximately 1300 mbsf (DAVIES and VAN DER SPUY 1988).

The wet gas generation phase begins at 3500 mbsf and dry gas generation at 4500 mbsf

(DAVIES and VAN DER SPUY 1988). Present day geothermal gradient is about 35°C/km

derived from corrected bottom borehole temperatures (DAVIES and VAN DER SPUY 1988).

The Aptian source shales in the DSDP 361 well are immature to early mature between

approximately 1000 and 1300 m. The Cruz del Sur well in the Colorado Basin offshore

Argentina offers also vitrinite reflectance values. The rocks in the well are much lesser mature

with the Paleozoic rocks in about 4000 m depth being in the oil window.


4.2.3 Reservoir rocks, traps and seals

Fluvial, marine and aeolian reservoir rocks are supposed to have developed throughout the

stratigraphic column at both continental margins (MUNTINGH and BROWN 1993; ;

MILLER 1995; BUSHNELL et al. 2000). The stratigraphically deepest potential reservoir

rocks are fluvioglacial sandstones of the Permian Dwyka Formation (MILLER 1992). Above

this, distal facies equivalents of the Tsarabis sandstone have a certain reservoir potential if

well sorted (MILLER 1992). The fluvial Gudaus Member sandstones above the Probeer

Member are extremely well sorted, quartz rich and highly porous. They pinch out westwards

but finer grained facies equivalents can be expected offshore (MILLER 1992). Within the

Karoo sequence, the well sorted aeolian sandstones of the Early Jurassic Etjo Formation have

good reservoir potential (MILLER 1992). The Early Cretaceous Twyfelfontein Formation

which is characterised by aeolian sandstones was deposited in the synrift II sequence (LIGHT

et al. 1993b) and may have reservoir potential. On the Argentine margin upper Cretaceous

deltaic sand, uppermost Cretaceous marine sands and Oligocene sands have been proven in all

wells drilled on the Argentine continental shelf (KEELEY and LIGHT 1993). These reservoir

sands are either interbedded with or overlain by transgressive shales with the proven capacity

to trap petroleum within structural dip and fault traps and stratigraphic traps (KEELEY and

LIGHT 1993). At the African margin reservoirs and traps are also present in the drift section

(MILLER 1992; BARTON et al. 1993; BROAD and MILLS 1993; MUNTINGH 1993;

MILLER and CARSTENS 1994; MILLER 1998; BRAY and LAWRENCE 1999). Stacked

sand bodies deposited by gravity-driven deepwater processes provide reservoir potential

together with stratigraphically enhanced combination traps (BRAY and LAWRENCE 1999).

The reservoir rocks in the post-rift sequence comprise channel, fluvio-deltaic and marine

sandstones (BARTON et al. 1993). It has been argued that an Aptian-sourced and Upper

Cretaceous turbidite-reservoired oil system could be present in the undrilled distal, deeper

water growth-fault and toe-thrust belts (JUNGSLAGER 1998).

4.3 The petroleum system of the Kudu gas field

The Kudu gas field (approximately 3.7E+10 m3 gas) and the Ibhubesi gas field

(approximately 7.1E+11 m3gas) are the only commercial gas discoveries along the south-

western African continental margin. The reservoir interval in the Kudu 9A-2 (lowermost

interval in figure 4.2) well contains two source rock intervals, 90 and 140 m thick,

respectively (BENSON 1990; MILLER 1992). These shales were originally sapropelic, oil- to


gas-prone source rocks particularly those in the upper interval between P1 to P which contain

abundant amorphous but essentially woody organic matter (DAVIES and VAN DER SPUY

1993). The abundance of terrestrial material introduced by the paleo-Orange River delta is a

major factor influencing the quality of source rocks in the Kudu area (LIGHT and

SHIMUTWIKENI 1991). Their quality is thought to improve westwards because of the

decreasing influence of sedimentary organic matter introduced by rivers (DINGLE et al.

1983; LIGHT and SHIMUTWIKENI 1991; BARTON et al. 1993; BROAD and MILLS

1993). Palynofacies studies of the Kudu wells show the P2 to P1 interval to consist of layers

containing semi-amorphous organic matter that accumulated under quiescent, slightly

anaerobic conditions interbedded with layers containing structured terrestrial organic matter

which accumulated under more oxygenated bottom-water conditions (BENSON 1990). The

TOC content of the Kudu source rocks which have a thickness of 153 m in well Kudu 9A-3 is

approximately 2 % (DAVIES and VAN DER SPUY 1990; MILLER 1992). Because the

rocks are quite mature, the original TOC content was probably higher (DALY 1987). The gas

reservoir located in the feather edge of a seaward dipping reflector sequence is slightly

(11 MPa) overpressured (JUNGSLAGER 1999). The trap is of a stratigraphic pinch-out type

(JUNGSLAGER 1999). Two gas bearing sands of Barremian age were encountered within the

R-to-P-interval (WICKENS and MCLACHLAN 1990; JUNGSLAGER 1999). Permeability

of the upper marine gas sand (UGS) of the Kudu wells is very low throughout (WICKENS

and MCLACHLAN 1990). In the lower non-marine gas sand (LGS), permeability is good to

very good in wells Kudu 9A-1 and 9A-3 but very poor in Kudu 9A-2 (RIJSWIJCK and

STEYN 1990). Parts of the reservoir sands at 4400 m depth show porosities of about 12 %

and permeabilities of about 43 mD (JUNGSLAGER 1999). The main reservoir of the Kudu

gas is located in the LGS, which consists of middle-grained anhydritic sandstones with

interbedded terrestrial basalts and volcaniclastics (WICKENS and MCLACHLAN 1990).

Most probably the sandstones are aeolian in origin (WICKENS and MCLACHLAN 1990;

JUNGSLAGER 1999). The UGS consists of fine to middle-grained sandstones,

conglomerates, calcareous claystones, carbonates, siltstones and was most probably deposited

in a coastal environment (WICKENS and MCLACHLAN 1990). Both facies types (UGS and

LGS) are suggested to be widespread laterally (WICKENS and MCLACHLAN 1990).

Barremian and Aptian shales serve as source rocks and seal (BRAY et al. 1998). Thus, the

stratigraphic trap was built and sealed in the Cretaceous (BRAY et al. 1998).

Cenomanian / Turonian source rocks seem to be absent in the Kudu area (BRAY et al. 1998).


Figure 4.2: Stratigraphy and lithology of the Kudu wells, modified from BAGGULEY (1997).

Base of

slope

Abyssal/ Base

of slope

Upperslope /outershelf

Upp

er sl

ope

Upperslope

Mid tooutershelf

Depositionalenvironment

Not dated

Early Oligocene

Early Campanian

Late

San

toni

an

LateConician

Mid TuronianCenomanianEarly-Late

Albian

Earliest Aptian

Early Aptian

Late Barremian

? Early BarremianTD = 4540 mTD = 4552 mTD = 4526 m

42264228

4089

3848

3659

352834853405

4067

3809

3643

35543493

3395

3253 3210

1070

810795

480

710

Upper marine sand

Lower aeolian sandReservoirInterval

Siltstone with limestoneInterbedded clay-and siltstoneClaystoneLimestoneSandstoneVolcanics

780

1015

400

245

9A-3 9A-1 9A-27 km4 km

400

830

1230

3255

3455

3825

3978

4132

4252

Some EarlyMioceneWells hung on

Top Oligocene datum

BASE TERTIARY

A = Early EoceneB = Late Eocene

AB

Possible equivalent sourcerock horizon to that in Bredasdorp Basin, offshoreSouth AfricaDepth in meters

2

1

2

1 2

1


4.4 Exploration history of the South West African continental margin

The first commercial hydrocarbon discovery offshore Namibia and South Africa – the Kudu

gas field - was made by Chevron in 1974 (http://www.namcor.com.na/exploration

_history.htm) in the Namibian part of the Orange Basin. Strong gas shows were encountered

in the intervals 4228 to 4280 and 4319 to 4343 mbsl of the well Kudu 9A-1. Both reservoirs

horizons were slightly overpressured (JUNGSLAGER 1999). The upper marine to fluvial unit

revealed a poor potential, but the lower aeolian unit had high porosities (20 %) and appeared

permeable (WICKENS and MCLACHLAN 1990). The evaluation of both intervals by DST

(drill steam test) failed due to high reservoir pressure. In 1985, about 850 km of reflection

seismic data have been acquired in the Kudu area (http://www.namcor.com.na/

exploration_history.htm). The well Kudu 9A-2 was drilled in 1987 about 7.5 km north of well

Kudu 9A-1 (TD 4567 m) by SWAKOR, the predecessor company of the present Namibian

National Oil Company (NAMCOR). Gas was present in marine sandstones between 4303 and

4389 m but the reservoir was found to be tight (P < 10 %, K > 0.02 mD) which made

economic flow rates unlikely. The reservoir remained untested. In 1987, Soekor discovered

the A-K (Ibhubesi) gas field in the Orange Basin (http://www.petroleumagencysa.com/

press/petroleum_gazette _06_may_2002.htm). The natural gas is thought to have migrated

mainly via faults from Aptian source shales into the trap in Albian fluvial channel-fill

sandstones (BEN-AVRAHAM et al. 2002). Well Kudu 9A-3 was drilled in 1988 about

4.5 km southeast of Kudu 9A-1. A main gas bearing reservoir between 4474 and 4486 m with

gas flow rates of 2.2E+5 m3 gas per day and an upper aeolian interval between 4381 and

4440 m with flow rates of 1.1 E+6 m3 gas per day were found. The reservoir pressure was

54.3 and 53.6 MPa, respectively. The potential of the Kudu gas field was estimated with

respect to the first three wells to amount to at least 6.8 E+10 m3 (maximum case: 3.2

E+11 m3). Between 1989 and 1998 about 34,000 km of seismic was acquired in the offshore

area of Namibia. In addition, potential field, magnetic, and gravity data were gathered. In

2002, two additional wells were drilled in the Kudu area which did not confirm the expected

size of the gas field. Only 3.7 E+10 m3 of gas have been proven at Kudu

(http://www.gasandoil.com/goc/company/cna23484.htm). Thus, Shell withdrew from the

Kudu field, which is now held by Texaco Namibia (60 % share) and Energy Africa

(http://www.economist.com.na/2002/22nov/11-22-16.htm).

In 2002, an extension of the A-K (Ibhubesi) gas field offshore South Africa was found

(http://www.petroleumagencysa.com/press/petroleum_gazette__06_may_2002.htm). The gas

of this A-K field is stratigraphically trapped in an Albian fluvial play


(http://www.petroleumagencysa.com/Docs/expl-activities-03-03.pdf). The resource potential

calculated on the basis of drilling results may be in the order of approximately 7.1.1011 m3gas.

Sasol Petroleum has completed a study agreement over block 3A/4A (north of Saldanha

directly off the coast), and applied for this to be converted to a full exploration sublease. This

implies, that the results of its initial investigation were promising, with natural gas the most

likely to be found (http://www.nampower.com.na/NamPower/lpr_show.asp?r=156). Earlier in

the year 2002, Global Energy ceded 90 % of its prospecting sublease for the deep water

blocks 3B and 4B in South African waters west of blocks 3A/4A. Seismic data confirmed a

great oil potential in the blocks, and significant natural gas findings are secondary exploration

objectives (http://www.gasandoil.com/goc/company/cna23484.htm).

To date, 14 wells have been drilled offshore Namibia, including five in the Kudu gas field.

Further 34 wells were drilled offshore South Africa in the Orange Basin

(http://www.petroleumagencysa.com/press/petroleum_gazette__06_may_2002.htm). Outside

of the Orange Basin, further five wells that have been drilled, showing encouraging results in

that excellent reservoir sequences, source rocks and seal were encountered

(http://www.namcor.com.na/exploration_history.htm).

Methods 42

5 Methods

5.1 Geochemical methods

All geochemical analysis were conducted in the laboratories of the Federal Institute for Geosciences (BGR) with help of or through BGR laboratory personell.

5.1.1 Surface geochemical prospecting

The sediment samples were stored frozen or at least cooled (see table 5.1 for storage temperatures) until processing to avoid microbial hydrocarbon oxidation and natural degassing which could change the stable carbon isotope ratio and the molecular composition of the gas (FABER and STAHL 1983). About 200 g of sediment from the defrosted samples were strained with distilled water through a sieve with a mesh size of 63 µm. Thereby the free gas from the pore space which is mainly of microbial origin is removed (FABER et al. 1997). In general the sediment fraction smaller than 63 µm was used in the desorption procedure of hydrocarbon gas from the sediment matrix which was carried out in a desorption line as described by FABER and STAHL (1983, figure 5.1).

H O KOH

EP

V3

C

D

AB

Vacuum

50 cm

100

cm

30 cm

2 EP

V3CD

A

B

KOH

Figure 5.1: Desorption line for degassing surface sediment samples after FABER and STAHL (1983). On the left side the desorption line is schematically shown. The photo was taken by Mr. D. Panten.

Methods 43

If this fraction did not contain enough sedimentary material, the whole sample was used after

thoroughly washing with distilled water for free gas removal. In 6 cases the samples contained

virtually no sediment of the fraction smaller than 63 µm, and the fraction greater than 63 µm

was used instead (samples 0107571, 0112810, 0112812, 0112813, 0112864, 0112866). Two

samples contained enough material to process both fractions (0107570, 0112854). One sample

(0112811) consisted entirely of coarse gravel and could not be processed at all and two

samples got lost during the desorption procedure (0010905, 0018646).

A weighed portion of the sample was put into container A (figure 5.1), together with about

200 ml of distilled water. Afterwards, the apparatus was evacuated with a water jet pump. The

sample material was stirred throughout the following procedure to ensure full blending. 50 ml

of concentrated phosphoric acid (figure 5.1) was added to the sample which was heated

subsequently to the boiling temperature. The gaseous hydrocarbons are assumed to desorb

from the mineral matrix by this procedure (HORVITZ 1972; FABER and STAHL 1983).

Carbon dioxide from the decomposition of carbonates was fixed with 200 ml potassium lye

(figure 5.1, B) to prevent dilution of the hydrocarbon gas and to reduce the pressure inside the

apparatus. The pressure was measured with a pressure gauge. After the desorption procedure,

distilled water was filled into the apparatus to press the hydrocarbon gas towards a special gas

container (figure 5.1, D) for storage until mass spectrometric analyses. On its way towards the

sample container, the gas moved through the gas drying unit (figure 5.1, E). The gas used for

gas chromatographic analyses was extracted directly from the degassing apparatus with a

syringe at valve V (figure 5.1) and injected into the gas chromatograph. Parallel to this

procedure, an aliquot of each sample was weighed both wet and after drying in a drying oven

to determine its water content. The water content is used to calculate the gas quantity referred

to the dry rock.

Molecular hydrocarbon gas compositions for all samples except samples 112801 to 0112870

were measured with a Siemens Sichromat 2 gas chromatograph (GC) using two 50 m glass

columns with 0.32 mm inner diameter – one OV 1 pre column and one main column coated

with KCl deactivated Al2O3. Nitrogen was used as carrier gas. The hydrocarbons were

detected with one flame ionisation detector (FID). The samples 112801 to 0112870 were

analysed with a Varian CP-3800 gas chromatograph using a column switching system (three

capillary columns: one Silicaplot, 30 m x 0.32 mm, two CP-Sil 5 CB, 30 m x 0.32 mm), split-

injector and temperature program. Detection of the hydrocarbon gas was performed by two

FIDs. Helium was used as carrier gas.

Methods 44

The stable carbon isotopic composition of the gas samples (δ13C values of methane and - if

present in sufficiently large amounts - ethane and propane) was measured with a Finnigan

Mat 252 mass spectrometer (Thermo Finnigan, USA). The hydrocarbon gas was separated

into its compounds by an online gas chromatograph with Poropak column (6 ft x 1/8”),

transformed at 1050 °C to CO2 in a copper oxide oven and then directly injected into the mass

spectrometer. The precision for this analysis was about 0.5 ‰.

5.1.2 Source rocks

The source potential of rocks from different locations onshore Namibia and Brazil and

offshore Namibia, South Africa and Argentina was evaluated by total organic carbon (TOC)

content analysis, Rock-Eval pyrolysis, vitrinite reflectance measurements and maceral

analyses. Due to the varying quantity and quality of the samples, and organisational reasons,

not all samples have been investigated with all methods. Especially the cutting samples from

the Cruz del Sur well were of bad quality showing great inhomogeneity and high contents of

artificial materials like rust and plastic. Some of the samples seem to have been mixed

and / or contaminated with material of other samples: For example, two different samples

(sample 0020731, 2418 m and sample 0020886, 4191 m) contain exactly the same clay stone

particles (pers. com. J. Koch, BGR).

5.1.2.1 Total organic carbon (TOC) and total sulphur (TS) content analysis

TOC and TS contents were determined with a conventional carbon analyser CS - 400

(LECO, USA): The pulverised samples were weighed in ceramic containers and decarbonised

afterwards with 2n hydrochloric acid. The samples were dried on a heater at 60 °C overnight

to ensure complete evaporation of the acid (no decarbonisation and drying for TS analysis).

Tungsten trioxide and iron chips were added to the samples to increase the reaction

temperature in order to expedite the chemical reaction. The samples were burnt in an

induction oven at 2000 °C in a pure oxygen atmosphere. During combustion, the target

elements carbon or sulphur oxidised to form CO2 and SO2, respectively. The evolved gases

were then swept through individual carbon and sulphur detection cells for measurement. The

amount of gas formed is compared to the weight of rock, and the weight percent of organic

carbon and sulphur, respectively, is calculated.

Methods 45

5.1.2.2 Rock-Eval pyrolysis

5.1.2.2.1 Measurement of the parameters S1, S2, S3 and Tmax

In the present study a conventional Rock-Eval 6 (Vinci Technologies, France) was used. For

pyrolysis about 100 to 150 mg pulverised rock is heated in an inert atmosphere first

isothermally at 300°C for three minutes and then heated up linearly at a heating rate of

25 °C/min to 650 °C (for 14 minutes). During the isothermal phase the hydrocarbons already

generated in the subsurface are released from the sample (S1 peak). During the linear heating-

up phase thermal breakdown of the kerogen produces additional hydrocarbons (S2 peak). The

CO2 portion released from the kerogen is recorded as S3 peak. From the S2 and S3 values, the

hydrogen and oxygen indices, respectively, are calculated which correlate to the hydrogen and

oxygen content of the rocks (ESPITALIÉ et al. 1985). The Tmax value is the temperature

during the heating-up at which the rate of hydrocarbon generation reaches its maximum. Tmax

is used as a kerogen type dependent maturation parameter (ESPITALIÉ et al. 1985; PETERS

and MOLDOWAN 1993).

No samples from the Whitehill Shale outcrops were pyrolysed, because of their high maturity

and low TOC content. Most of the carbon in these samples was already converted into “dead

carbon” by a phase of high temperature introduced during dolerite intrusions. Some of the

samples from the well Kudu 9A-2 were reanalysed after decarbonisation with diluted

hydrochloric acid (samples 9936989, 9936990, 9936996, 9937000, 9937004) and after

kerogen concentration with hydrofluoric and hydrochloric acid (samples 9936989, 9937000).

The decarbonisation and kerogen concentration were conducted to achieve a better ratio

between organic matter and sample amount in order to optimise the Rock-Eval signal.

5.1.2.2.2 Reaction kinetics of hydrocarbon generation

In order to obtain reaction kinetic models on selected source rock samples, bulk pyrolysis

experiments were conducted using a conventional Rock-Eval 6 (Vinci Technologies, France).

The standard temperature program for these reaction kinetic investigations (three minutes of

isothermal heating at 300 °C and then heating-up to 650 °C) was used with heating rates of 1,

5, 10 and 25 K/min. Activation energies and Arrhenius factors were determined from the bulk

pyrolysis data using the Optkin 1 software (Vinci Technologies, France) and a BGR internal

kinetic analysis program. The determination involves the searching of the minimum of an

error function defined as the mean square residual of the model result versus the experimental

Methods 46

measurements (BEHAR et al. 1992). The Kudu samples could not be used for pyrolysis

studies because of their high maturity and their low TOC content and HI value which are at

least partly the effect of the high maturity (DALY 1987).

5.1.2.3 Vitrinite Reflectance and maceral analyses

Maceral analysis and vitrinite reflectance measurements were conducted according to

ISO 7404 and DIN 22020, respectively. The samples for vitrinite reflectance measurements

and maceral analysis were crushed and embedded in synthetic resin to form a particulate

block. The Kudu samples were only available already pulverised so that the kerogen was

concentrated using hydrochloric and hydrofluoric acid and the freeze-dried concentrate was

mounted in resin. The polished resin blocks were used for the analysis. The vitrinite

reflectance was measured with a Microscope photometer (Leica, Germany) with oil

immersion objectives and was expressed when the incident light is perpendicular to the

polished section, by the Fresnel-Beer’s formula (STACH et al. 1982, TAYLOR et al. 1998):

( )( ) 222

222

knNnknNnR

+++−

= with n: refractive index of the material, k: absorption index of the material, N: refractive index of the immersion medium at the wavelength of the incident light

Eq. 5.1

Since N, n and k vary with the wavelength, normalised measurements were made with

monochromatic light at 546 nm. The refraction index N of the oil (type 518 C, according to

ISO 8036/1, ZEISS, Germany) was 1.517 at 23 °C. Calibration standards were used according

to ISO 7404. Because both reflectance and anisotropy of vitrinite increase with maturation it

is important to state whether the random or the maximum reflectivity is determined (DOW

1977a). The measurement of the random vitrinite reflectance values (Rr %) was conducted

according to DIN 22020 part 5 (difference: measurement with polariser) and ISO 7404,

respectively. According to ISO 7404, at least 100 measurements per sample are required to

get a reliable result. None of the samples contained sufficient particles to get the required

number of measurements. Therefore, the results of the vitrinite reflectance measurements

have to be considered rather estimations than exact values. The micropetrographic description

of the organic matter was conducted under a microscope 500-times magnified (lens 50 times).

Fluorescence was observed with blue light stimulation.

Methods 47

5.1.2.4 Stable carbon isotopes of the source rocks

For the analysis of the stable carbon isotopic composition, the pulverised samples were

weighted into small silver crucibles in which decarbonisation with 2n hydrochloric acid was

conducted. The samples were dried in a drying oven at 70 °C for about four hours. Afterwards

the crucibles were folded up until they were small enough to fit the apertures of the isotope

mass spectrometer. The samples in the crucibles were combusted by 1650 °C under oxygen in

a NC 2500 elemental analyzer (Carlo Erba, Italy) which is interfaced to the Delta Plus mass

spectrometer (Thermo Finnigan, USA) allowing for online analysis of C and N isotopes in

organic materials. As carrier gas He 5.0 (purity 99.999 %) was used. Precision for these

analyses was 0.2 ‰.

5.1.3 Analysis of the reservoir contents

5.1.3.1 Natural gas from the Kudu reservoir

The molecular composition of the natural gas was measured with a Siemens Sichromat 2 gas

chromatograph (GC) using two 50 m glass columns with 0.32 mm inner diameter – one OV 1

pre column and one main column coated with KCl deactivated Al2O3. Nitrogen was used as

carrier gas. Before analysis of the isotopic composition the hydrocarbons had to be separated

by preparative gas chromatography. This was conducted with a Porapak Q column (6 ft x

1/8”). Helium was used as carrier gas for this procedure. The separated hydrocarbons were

oxidise to CO2 in copper oxide oven and recondensated in a quartz tube. Then they were

converted to water and reduced by zinc to elemental hydrogen in a quartz tube (DUMKE et al.

1989). The isotopic composition was measured with a MAT 251 (Thermo Finnigan, USA) for

carbon isotopes and with MAT Delta S (Thermo Finnigan) for hydrogen isotopes. The

precision is 0.1 ‰ for carbon and 1.0 ‰ for hydrogen.

5.1.3.2 Condensate from the Kudu reservoir

The condensate was analyzed with an HP 6890 gas chromatograph (Hewlett Packard, USA)

equipped with a CP-Sil 5 CB Low Bleed / MS column (30 m x 0.25 mm, 0.25 µm film) using

a temperature program in the range of 80 to 295 °C and a split method. The sample was

diluted to 4 % with dichlormethane. The bulk stable carbon isotopic value of the samples was

Methods 48

measured with a Delta XL (Thermo Finnigan, USA). The samples were combusted at 1650 °C

under oxygen in a NC 2500 elemental analyzer (Carlo Erba, Italy). The precision for this type

of analysis was 0.3 ‰.

5.2 Basin modelling

Basin modelling is used to understand and reconstruct the geological and thermal evolution of

a sedimentary basin (WELTE and YALCIN 1988; BURRUS et al. 1991; LITTKE et al. 1994;

BARKER 1999b). The basin model integrates the geochemical, geophysical and geological

basin properties from which oil and gas generation and migration as well as the temperature

and pressure evolution in a basin can be calculated (WELTE and YUKLER 1981;

WYGRALA 1988). In the study at hand the basin simulation software PetroMod 2D (IES,

Germany) was used for modelling the petroleum history of the Kudu gas field located in the

Orange Basin offshore Namibia. Basis of the study are the reflection seismic lines ECL 89-

011 and ECL 89-011A. Well control for the basin model is provided by the wells 9A-1, 9A-2

and 9A-3 drilled in the Kudu gas field (BENSON 1990; DAVIES and VAN DER SPUY

1990; ERLANK et al. 1990; MCMILLAN 1990; RIJSWIJCK and STEYN 1990; WICKENS

and MCLACHLAN 1990; DAVIES and VAN DER SPUY 1993; BAGGULEY 1997). The

general principles of basin modelling are summarised among others by WELTE and

YÜKLER (1980), WELTE and YUKLER (1981), WELTE et al. (1997) and references

therein.

5.2.1 Definitions and input parameters

The prerequisite for basin modelling is the translation of logical and consistent geological

concepts into numerical form (WELTE and YALCIN 1988). The computer simulation

requires the quantification of all defining parameters. The integration of all relevant

geological, geochemical and geophysical data to comprehend the real system is called

conceptual model (WELTE and YUKLER 1981). In order to process the basin development

by the simulator, it has to be subdivided into a discrete, uninterrupted sequence of events

(geochronologic units, WYGRALA 1988). Each event represents a time span, during which

one of the three basic geological processes deposition, erosion or hiatus occurs (WYGRALA

1988). Different geological processes can occur in various parts of the basin at the same time.

Methods 49

Layers are defined as physically existing sedimentary units at a certain time which may be

eroded during a later erosional event (WYGRALA 1988). Each layer is deposited during one

single event.

Basic data for the assessment of the petroleum generation potential of a basin are the regional

geology, identifying the source rock, assessment of type, quantity and maturity of the organic

matter, the heat flow with its variation through time, generation, migration and accumulation

of petroleum, thermodynamics and hydrodynamics (figure 5.2).

Geologic

Hydrodynamic

Thermodynamic

Geochemical

Input SolutionDeterministic

DynamicModel

Water Flow(Paleopressure)

Heat Flow(Paleotemperature)

Maturity

Determinations

Hydrocarbonyieldcalculations

Secondary migrationdeterminations

Grid systemfor data storageand solutions

100

10

11 20

R (%)Extract

m

0.5

1.51.0

10 100 1000

PcPb

Pw

R (

%)

m

Figure 5.2: Development of a deterministic basin model, modified from TISSOT and WELTE (1984).

The following input parameters have to be quantified or specified for each layer:

• The structural setting of the research area (present and original thicknesses of the

layers, faults)

• The physical and chemical features of each layer (lithologies, present porosities and

cementation or fracturing behaviour, permeabilities, compressibilities, TOC)

• The physical and thermal boundary conditions of the sedimentary sequence (present

and paleo bathymetry, sediment / water interface temperatures, and paleo heat flow)

Methods 50

• The physical and thermal properties of the lithologies, fluids and organic material (a

data base of default values for common material is included in PetroMod)

• Additional data, which is required for calibrating the key wells, like maturity

indicators (e.g. vitrinite reflectance data). These measured values are not used as direct

input data but are important calibration parameters in the key wells.

The main input parameters used in this study are compiled in appendix B.

5.2.2 Heat flow history

Because of the strong dependence of hydrocarbon generation on time and temperature, the

heat flow during basin evolution is one of the most important constraints for modelling

hydrocarbon generation (PHILIPPI 1965; TISSOT and WELTE 1984). Paleo heat flow ranges

can be assessed in a first approximation by interpreting tectonic processes in the history of the

basin (ALLEN and ALLEN 1990). For continental margins at the time of rifting, high heat

flow values of 100 to 170 mW/m2 (COCHRAN 1981) which decrease exponentially towards

values typical for passive margin settings between 40 and 65 mW/m2 (ALLEN and ALLEN

1990) can be assumed. The calibration of the heat flow history is usually done using

temperature sensitive parameters like vitrinite reflectance or Tmax measurements

(TEICHMÜLLER 1971; TEICHMÜLLER 1982; PETERS 1986). Often 1D models are

calculated first to built a conclusive heat flow history. In the present study a 1D model of the

well Kudu 9A-2 was built and calibrated with vitrinite reflectance data from the well. The

reaction kinetic algorithm EASY % Ro (SWEENEY and BURNHAM 1990) was used to

compute the evolution of vitrinite reflectance with depth for the comparison with the

measured data. The model was calculated with PetroMod 1D Express (IES, Germany).

5.2.3 Surface water interface temperature

The surface water interface (SWI) temperature is the upper boundary condition for heat

transport in the basin, because variations in the mean annual surface temperature penetrate

deeply into the crust (BARKER 2000). An increase of the surface temperature from 10 to

20 °C may reduce the depth of the oil window by about 0.5 km (BARKER 2000). Today, the

maximum difference between mean annual surface temperatures on earth is 50 °C, which is

therefore the amount by which the surface temperature can theoretically vary induced by

Methods 51

climate change and continental drifting (BARKER 2000). Paleo annual mean surface

temperatures are read in PetroMod from global paleotemperature distribution maps and are

corrected for the effects of water depth, basin type and global ocean current pattern.

(WYGRALA 1989 cited in BARKER 2000, figure 5.3).

Figure 5.3: Effect of climate model and latitude on variations in mean annual sea surface temperatures, modified from WYGRALA (1989, cited in BARKER 2000). The inflected lines represent the isotherms through time at the corresponding latitude. The lines are labeled by temperature in °C. The dotted line indicate the evolution of the SWI temperature for the study area.

5.2.4 Rock parameters related to heat distribution and transfer

The thermal conductivity can be defined by the relationship between heat flow and thermal

gradient. The bulk thermal conductivity of a rock consists of the conductivity of the rock

matrix as well as the conductivity of the pore fillings. It depends strongly on the mineralogy,

porosity and the grain size, shape and arrangement of the rock (BRIGAUD et al. 1990). Most

sedimentary rocks are anisotropic with higher horizontal than vertical thermal conductivity

values. The specific heat is the ratio of entered heat to the heat capacity, which again is the

product of the sample mass and the temperature difference. The heat capacity defines the

number of joules required to heat a body by 1 °C. The bulk value of the specific heat is

calculated in PetroMod as the geometric average of the compound values.

Methods 52

5.2.5 Porosity and permeability evolution

Apart from its role as an indicator for the state of compaction the porosity is the most

important factor controlling the thermal properties of sediments, as the pore contents (i.e.

fluid or gas) have lower thermal conductivities and heat capacities than the rock matrix. Most

of the matrix properties, such as thermal conductivities, heat capacities, densities, and

elasticity of plastic modules, strongly depend on rock porosity. Additionally, the geometrical

description of basin layers and elements is directly connected with the porosity changes of the

rock. The present geometry of the geological section is obtained from seismic interpretations,

borehole measurements or well log data. A ‘decompaction’ routine is integrated in PetroMod

to reconstruct the initial sediment thickness of each layer from present day data. The

permeability describes the ability of sediments to transmit fluids and / or gases. Flow rate is

also a function of the hydraulic head difference in a completely saturated unit volume and of

the viscosity of the fluid or gas. Anisotropy of permeability is especially pronounced in

shales, where the ratio of horizontal to vertical permeability easily exceeds 10. This

anisotropy can have a controlling effect on flow direction. However, the overriding factor in

fluid transport is the fluid potential gradient. The flow of hydrocarbons is usually upwards due

to buoyancy, but occasionally it can be downwards, e.g. from compacting shales into

underlying, more porous units. For a special volume element, compressibility is defined as the

relative volume change due to the temporal change of an external stress. In the basin

modelling software PetroMod it is assumed, that the solid material is ideally rigid and the

fluids are immiscible and incompressible. Thus the element volume only changes when the

porosity decreases. On a logarithmic compressibility scale a linear dependency on porosity is

assumed.

5.2.6 Petroleum generation

The conversion of kerogen to oil and gas is controlled by reaction kinetic processes, which are

temperature and time dependent (PHILIPPI 1965; TISSOT and WELTE 1984). Therefore, the

temperature history is calculated in PetroMod as a continuous temperature record through

time in a source rock in order to calculate the specific hydrocarbon yield for oil and gas. The

initial potential is given by the hydrogen index HI of ESPITALIÉ et al. (1985).

Each hydrocarbon formation reaction is described in PetroMod by a set of activation energies,

a frequency factor, and an initial petroleum generation potential. It is assumed that kerogen

Methods 53

and oil as the initial products can consist of different components which react with different

reaction rates. During the simulation it must be dealt with a multi component system, because

oil, gas and water are present at the same time (WELTE and YUKLER 1981).

5.2.7 Sensitivity analysis

The term sensitivity analysis is defined by YUKLER and MCELWEE (1976) as the study of

the system’s response towards disturbances. In modelling dynamic systems where many basin

properties cannot be measured directly but can only be inferred from geophysical methods or

regional geological knowledge inaccuracies have to be faced (YUKLER and MCELWEE

1976; WELTE and YUKLER 1981). Additionally, basin simulation involves setting up a

model of a real system which requires certain simplifications and assumptions thus leading to

errors in the conceptual and later in the mathematical model (WELTE and YUKLER 1981).

From the physical and physicochemical model of the geological processes the relative effects

of the variation in the data can be analysed and the sensitivities of the results – a crucial point

if data is difficult to quantify – can be evaluated (WELTE and YUKLER 1981). Sensitivity

analysis aids in the computation of such errors (YUKLER and MCELWEE 1976).

5.2.8 Seismic interpretation

The basin modelling study of the petroleum system of the Kudu gas field offshore Namibia

was carried out on the basis of the reflection seismic sections ECL 89-011 and ECL 89-011A

(figure 5.4). The combined line is 250 km long and runs approximately in WSW-ENE

direction between latitudes 28° and 29° S. It starts in shallow water of less than 100 m depth

about 10 km off the coastline and ends in water depths of about 2700 m. More than half of the

section runs through water shallower than 250 m. At a distance of approximately 170 km

from the coast the relatively broad shelf passes over into the continental slope where the water

depth increases rapidly. Near shotpoint 1975 of profile ECL 89-011 (approximately 150 km

off the coast) it passes the Kudu gas field. Well Kudu 9A-3 lies approximately 2 km to the

south, well Kudu 9A-2 approximately 10 km to the north of the seismic section. To resolve

the depositional history of the postrift development of the Namibian continental margin at the

position of the Kudu gas field the basic concepts of sequence stratigraphy were used to

interpret the seismic data.

Methods 54

ENE

WSW

Kud

u

Figure 5.4: Seismic sections ECL 89-011 and ECL 89-011A. Note that the sections are displayed in reflection time.

Methods 55

Sequence stratigraphy is essentially “the geological approach to the stratigraphic

interpretation of seismic data” (VAIL and MITCHUM 1977) enabling stratigraphic

relationships and depositional processes to be inferred from the seismic reflection record.

According to VAIL (1977) and MITCHUM (1977), depositional sequences are defined as

relatively conformable successions of genetically related strata bound at the top and at the

bottom by unconformities and their correlative conformities. The seismic surfaces which form

the upper and lower boundaries of depositional sequences are characterised by different

reflection termination patterns (figure 5.5).

offlap

downlap

toplap

onlaponlap

OVERLYING UNCONFORMITY

UNDERLYING UNCONFORMITY

INTERNALCONVERGENCE

truncation

Upper boundary

Lower boundary

toplap

downlap concordanceonlap

concordanceerosional truncation

baselap

A

B

C

1

1

2

2

3

3

Figure 5.5: Relation of strata to boundaries of depositional systems: A1 Erosional truncation, A2 Toplap: initially inclined strata at top of given surface terminate against upper boundary mainly as result of nondeposition, A3 Top-concordance: relation in which strata at top of given sequence do not terminate against upper boundary, B1 Onlap: at base of sequence initially horizontal strata terminate progressively against initially inclined surface or initially inclined strata terminate updip progressively against surface of greater initial inclination, B2: Downlap: at base of sequence initially inclined strata terminate downdip progressively against initially horizontal of inclined surface, B3: base concordance: strata at base of sequence do not terminate against lower boundary, C: Seismic stratigraphic reflection terminations within an idealised seismic sequence (MITCHUM et al. 1977a; MITCHUM et al. 1977b).

Methods 56

The upper boundary can be defined by toplap or erosional truncation. The lower boundaries

are characterised by onlap or downlap termination patterns (MITCHUM et al. 1977a). Both,

the upper and lower boundaries of depositional sequences may also be concordant with the

overlying and underlying strata, respectively. Inwards the sequences show internal

convergence and offlap patterns. Each sequence is inferred to have been deposited during one

cycle of relative sea level change (POSAMENTIER et al. 1988). Relative sea level change is

measured between the sea surface and a datum (POSAMENTIER et al. 1988) and is the

product of changing rates of tectonic subsidence and eustatic sea level cycles of different

frequencies and magnitudes (POSAMENTIER et al. 1988; MITCHUM and VANWAGONER

1991). These two factors control the amount of accommodation space available for sediment

deposition (POSAMENTIER et al. 1988, figure 5.6). Changes in vertical accommodation

space are described in terms of sea level fall, rise and stand still whereas changes in horizontal

accommodation space may be described in terms of regression, transgression and stationary

shoreline. New accommodation space is created during transgressional phases

(POSAMENTIER et al. 1988). The associated reflection termination pattern is characterised

by onlaps. If no new accommodation space is created, no sedimentary record can be

deposited. Thus, a hiatus is formed which might result in an unconformity if the hiatus

encompasses a significant interval of geologic time (MITCHUM et al. 1977a). If the sea level

falls below the sediment surface, erosion can occur resulting in the formation of a type 1

sequence boundary (unconformity), which is associated with stream rejuvenation and incision

at the base (POSAMENTIER et al. 1988). Type 2 sequence boundaries are formed when the

rate of eustatic sea level fall is less than the rate of basin subsidence at the depositional-

shoreline break, so that no relative fall in sea level occurs (VANWAGONER et al. 1988). The

resulting type 2 sequence will be characterised by a shelf margin system tract instead of a low

stand system tract (POSAMENTIER et al. 1988). Regressional phases are characterised by

downlap reflection termination patterns which can be found on the maximum flooding

surface, the upper boundary of the transgressive system tract (VAIL 1987). The amount of

sediment input determines whether the shoreline advances, retreats or stays stationary during

relative sea level rise (VAIL et al. 1977). If coastal toplap is observed a standstill of relative

sea level can be inferred because vertical accommodation space has remained stationary.

Coastal onlap indicates a rise in relative sea level whereas truncation occurs due to fall in

relative sea level (VAIL et al. 1977).

Methods 57

Centre of the Earth

sea su

rface

water bottom

Waterdepth relativesea level

datum

accumulatedsedimenteu

stac

ysea surface

eust

acy

subs

iden

ce /

uplif

t

water bottom

spac

e av

aila

ble

“acc

omod

atio

n”

A

B

Figure 5.6: Changes in relative sea level (A) affect the amount of available accommodation space (B), modified from POSAMENTIER et al. (1988).

The sequences are chronostratigraphically significant and deposited during a given interval of

geologic time limited by the ages of sequence boundaries (VANWAGONER et al. 1988). The

definition of sequences may aid the subdivision of the seismic data into packages of

genetically related strata of depositional sequences which enables the depositional history of a

sedimentary basin or continental margin to be unravelled (BROWN and FISHER 1977;

MITCHUM et al. 1977a). Thus, in the absence of detailed, absolute, biostratigraphic

information, a relative time framework can be established (WHITTAKER et al. 1991;

POSAMENTIER 1996). Third-order sequences - the fundamental units of sequence

stratigraphy with a cyclicity between 0.5 – 5.0 Ma - are stacked to form second-order eustatic

cycles with durations of 9-10 Ma bounded by major eustatic falls (VAIL et al. 1991). The

second-order supersequences can be grouped into supersequences sets with durations of

approximately 30 Ma (VAIL et al. 1991).

Methods 58

5.2.9 Subsidence analysis

5.2.9.1 Passive margin evolution

Passive continental margins are characterised by strong subsidence induced by the stretching

of the lithosphere which can lead to basin formation if the initial thickness of the crust is more

than 18 km (MCKENZIE 1978). Substantially thinner crust will lead to elevation of the crust.

The subsidence can lead to the formation of more than 15 km thick sediment accumulations

beneath the outer shelf and slope. The subsidence of a sedimentary basin is composed of:

• flexural subsidence which is induced by the loading of the lithospheric plate which reacts

elastically by bending down below and beside the burden. The higher the rigidity of the

lithosphere the shallower and broader the basin will get in contrast to a deep small basin

on a weak lithospheric plate.

• thermal cooling and contraction of the lithosphere following uplift and subaerial erosion

(SLEEP 1971) or rapid stretching of the lithosphere (MCKENZIE 1978) at the time of

initial rifting or crustal stretching or necking due either to regional extension

(ARTEMJEV and ARTYUSHKOV 1971).

• oceanward creep of lower continental crustal material accompanied by wedge subsidence

in the brittle layer above (BOTT 1971).

• deep crustal metamorphism leading to an increase in the overall density of the crust

(FALVEY 1974).

The main types of subsidence are the isostatic response to stretching and thinning of the crust

and lithosphere during the synrift phase, cooling and thickening of the lithosphere. Mainly

during the postrift stage and sediment loading both during the synrift and the postrift phase

(BOTT 1992).

5.2.9.2 Backstripping

The analysis of the subsidence of a continental margin includes the observation of the

stratigraphic profile, regarding for compaction, paleo water depths, fluctuating sea level and

sediment loading. This technique is called backstripping and is used to isolate the tectonic

component of the subsidence from the isostatic response of the lithosphere to sediment load

(WATTS and RYAN 1976, figure 5.7).

Methods 59

Base-ment

Sedi

men

tsW

ater

Present

t

ZHw

S

Decompaction

Zb

Zub

S loa

d Sto

tal

Unloading

S tec

to

Time tInitial(a) (b) (c) (d) (e)

ZS

Hw

Zb

S load

S total

S tecto

Zub

sea levelpaleobathymetry

basement depthunloaded basement depth

Z0

0

Z0 initial basement depth total subsidence (Z - Z )

subidence due to loading (Z - Z )

tectonic subsidence (Z - Z )

0b

bub

0ub

Figure 5.7: Delineation of the backstripping technique, modified from: CÉLÉRIER (1988) (a) initial situation (b) present situation: one horizon is named t which corresponds to a depositional depth Hw (c) situation at time t considering sea level change Zs (d) correction for compaction (e) correction for loading: the resulting basement depth Zub is directly comparable to simple geodynamic models prediction.

Sediment and water loading cause subsidence and the augmentation of available

accommodation space through the isostatic response of the lithosphere to the loading. In the

local isostatic or Airy model for every 1.0 km of sediment deposited, the basement subsides

about 0.6 km. Thus, the total sediment accumulation due to sediment loading is limited to

about 2½ times the water depth. The maximum sediment thickness T that can accumulate at

water depth dw is given by JEFFREYS (1962) through:

−−

=sm

wmwdT

ρρρρ

with dw: water depth, ρw, ρs and ρm: densities of water, sediment, and upper mantle, respectively

Eq. 5.2

The response of the lithosphere to loading effects was calculated in the present study

according to the Airy model which involves vertical movements only. In a flexural model the

strength of the lithosphere (which is assumed to be zero for the Airy model) leads to

Methods 60

subsidence not below but also beside the load. The higher the strength of the lithosphere the

broader and shallower the basin which forms by the isostatic response will be (WATTS and

RYAN 1976). At correcting for the sediment-induced subsidence variable sediment densities

and compaction effects have to be taken into account because today’s sediment thicknesses

and porosities observed in boreholes and outcrops do no correspond to the initial sediment

properties at the time of deposition. Increasing burial compaction of the sediments results in

reduction of the sediment thickness and porosity and increase of the sediment density. The

original sediment thickness To at the time of deposition can be calculated according to:

( )( )O

zo

tTΦ−Φ−

=11

with Φ0: original depositional porosity, Φz: present day porosity at depth z, t: present day sediment thickness

Eq. 5.3

Since the original porosities of the studied sediments are not known they have to be estimated

using porosity curves to correct the present day sediment thickness for compaction effects.

The paleobathymetry and fluctuations of sea level also have to be taken into account. The

total tectonic subsidence TTS or uplift is obtained by adding the present day water depth (that

is the unfilled part of the basin) to the cumulative backstrip. This is the final depth the basin

would have subsided to in the absence of sediment loading (STEWART et al. 2000;

GREVEMEYER and FLUEH 2000):

( )( ) L

mw

msSw StdTTS ∆−

−−

⋅+=ρρρρ

with dw: water depth, ts: sediment thickness, dc: corrected depth, ρw, ρs and ρm for densities of water, sediment, and upper mantle, respectively, ∆SL: change in sea level

Eq. 5.4

The occurrence of tectonic subsidence can be attributed to different reasons: (DAVIS and

LISTER 1974 and PARSONS and SCLATER 1977) recognised an empirical relationship

between the age of the ocean floor and its depth below sea level. PARSONS and SCLATER

(1977) propose simple equations for the calculation of the ocean floor depth (not considering

the effects of sedimentation):

( ) mttd 5.03502500 +=

( ) mtdt

−

−= 8.62exp32006400

70 Ma since rifting after more than 20 Ma since rifting

Eq. 5.5

Eq. 5.6

Methods 61

In this equation the initial subsidence of newly formed oceanic crust is set to 2500 m.

According to MCKENZIE (1978) and KEEN et al. (1981), subsidence can be caused by

stretching and thinning of the crust. Stretching across a rifted margin will result in a transition

from unmodified continental lithosphere to oceanic lithosphere where stretching is large. The

stretching and thinning of the crust causes hot asthenospheric material to well up which leads

to a thermal disequilibrium. The more stretching, the more thinning, heating and overall

tectonic subsidence will occur. The stretching factor β is defined after STEWART et al.

(2000) by:

( )( )cmc

wm

tTTS

ρρρρ

β−−

−=− 11

with tc: crustal thickness, ρw, ρs and ρm for densities of water, sediment, and upper mantle, respectively, TTS: total tectonic subsidence

Eq. 5.7

In this model crust and lower lithosphere are assumed to extend uniformly. This results in a

density excess above the depth of the initial base of the crust before rifting and a density

deficiency below the initial base of the crust thus causing initial subsidence followed by

thermal subsidence as the plate cools, contracts and thickens after cessation of rifting as

temperature equilibrium is achieved again. The subsidence through stretching of the crust

occurs over a large area (MCKENZIE 1978). After KEEN et al. (1981) the initial subsidence

through the isostatic response of the thinned and heated lithosphere to density changes is

about 2660 m. Together thermal and initial subsidence constitute the tectonic subsidence

which is opposed to the subsidence caused by isostatic response of the lithosphere to loading

by sediments and water.

The model used in the study at hand for calculating subsidence and heat flow assumes pure

shear rifting (MCKENZIE 1978; MUTTER et al. 1982). It involves rapid stretching of

continental lithosphere, which produces thinning and passive upwelling of hot asthenosphere.

Other authors infer simple shear rifting for the South Atlantic Ocean (WERNICKE 1985;

LISTER et al. 1986; LIGHT et al. 1993b).

5.2.9.3 Influence of the rifting process on the heat flow history of continental

margins

The temperature distribution of the Earth reflects the inputs and outputs of heat. The transfer

of heat can be achieved by conduction, convection and radiation. In the lithosphere heat is

Methods 62

transported primarily through conduction, whereas in the mantle convection of heat from the

Earth’s deep interior is dominant (ALLEN and ALLEN 1990). The fundamental relation for

conductive heat transport is given by the Fourier´s law.

yTKq

dd

−=

with q: heat flow, K: coefficient of thermal conductivity, T: temperature at a given point in the medium and y: coordinate in the direction of the temperature variation

Eq. 5.8

With known thermal conductivities the heatflux can be calculated from temperature

measurements in wells (ALLEN and ALLEN 1990).

The stretching of the lithosphere results in thinning and heating of the crust because of

passively upwelling asthenosphere. In order to re-establish the thermal equilibrium, the crust

subsides and cools by predominantly vertical conductional heat transfer (MCKENZIE 1978;

ROWLEY and SAHAGIAN 1986), that is, heat is conducted from the lower lithosphere or

crust towards the surface. At the beginning of the process, heat flow is high and decreases

asymptotic to a final value. Approximately after 60 Ma the heat flow values caused by

different amounts of stretching differ only slightly. The heat flow q referring to different

amounts of stretching can be calculated according to:

⋅+

⋅=

−τ

βπ

πβ t

c

m etTK

q sin21

with K: thermal conductivity, Tm: temperature of the mantle, tc: crustal thickness, here assumed to be 125 km, β: stretching factor, t: time since rifting, τ: thermal time constant (62.8 Ma)

Eq. 5.9

From the equation 5.9 it can be seen that the heat flow depends strongly on the stretching of

the crust during rifting. The higher the stretching factor the higher the heat flow immediately

after rifting.

Methods 63

5.3 Data pool

Figure 5.8: Compilation of the locations of source rock (dots) and sediment (stars) and of the location of the seismic section ECL 89011. Petroleum samples are from the Kudu reservoir which is marked by the dot for source rock samples. The big stars at the Argentine margin mark the area in which sediment samples were taken in the Colorado and Malvinas Basin.


Near surface sediment samples were taken offshore Argentina, Namibia and South Africa

during several research cruises. A total of 137 samples were available – 22 from offshore SW

Africa and 115 from offshore Argentina. For a compilation of the information on the near

surface samples see table 5.1.

Table 5.1: Compilation of the main information about the sediment samples used for surface geochemical prospecting including among others information on sample number, storage temperature and provider.

Sampling location, research cruise (year)

Number of samples

Range of water depth [m]

Maximum core length [m]

Storage temperature [°C]

Sample provider

Colorado Basin, offshore Argentina, “Puerto Deseado” (2001)

39 88 - 4720 2.70 not exceeding -20

Repsol-YPF, Argentina

Malvinas Basin, offshore Argentina, Puerto Deseado” (2001)

60 143 – 670 2.70 not exceeding -20

Repsol-YPF, Argentina

Offshore south-western Africa, Nausicaa IMAGES II (MD 105) cruise 1996

22 105 - 3606 39.65 +4 University Bordeaux, France

Offshore Argentina, Meteor cruises M29/1 (1994) and M46/3 (1999/2000)

16 2373 - 4777

14.66 not exceeding 0

University Bremen, Germany

Cruz del SurIrati

DSDP 361

KuduWhitehill

ECL 89-0110018645/6

0018647/80018649/50

0018665/60018663/4

0018647/8

0018

661/2

0018655-600018651-54

0010909/100010905/6

0010911/120010913-160010907/8

0010917-20

0112810-70

0112801-9 +0107550-79

20° E0°20° W40° W60° W80° W 40° E

40° S

20° S

60° S

0° S 20° E0°20° W40° W60° W80° W 40° E

40° S20° S

60° S0° S

Cruz del SurIrati

DSDP 361

KuduWhitehill

ECL 89-0110018645/6

0018647/80018649/50

0018665/60018663/4

0018647/8

0018

661/2

0018655-600018651-54

0010909/100010905/6

0010911/120010913-160010907/8

0010917-20

0112810-70

0112801-9 +0107550-79

20° E0°20° W40° W60° W80° W 40° E

40° S

20° S

60° S

0° S 20° E0°20° W40° W60° W80° W 40° E

40° S20° S

60° S0° S

Methods 64

5.3.2 Source rocks

For the evaluation of the hydrocarbon generation potential of the conjugate continental

margins of Argentina and SW Africa 251 rock samples from outcrops and wells offshore

Namibia, South Africa and Argentina were available (table 5.2):

Table 5.2: Compilation of the locations of source rock sampling, numbers and types of source rock samples. Note that the ciphers in the last column indicate the number of samples analysed with the geochemical techniques indicated in the headline of the column.

Well/Outcrop Number of samples

Type of sample Number of analysed samples TOC/TS/Rock-Eval/Rr/δ13COM

Kudu 9A-2 and 9A-3, offshore Namibia (kindly provided by Namcor, Namibia)

38 ground cutting samples

38/-/38/6/36

DSDP 361, offshore South Africa (kindly provided by the Ocean Drilling Project)

24 core samples 24/4/24/6/20

Whitehill, onshore Namibia (kindly provided by University Würzburg, Germany)

5 outcrop samples 5/5/-/4/4

Cruz del Sur, offshore Argentina (kindly provided by Repsol-YPF, Argentina)

182 cutting samples 23/-/23/10/19

Irati Shale, onshore Brazil (kindly provided by Petrobras, Brazil)

2 outcrop samples 2/2/2/2/2

5.3.3 Reservoir hydrocarbons

One condensate and two gas samples from the Kudu reservoir offshore Namibia which is

located in the northern portion of the Orange basin near the South African border were kindly

provided by Namcor.

5.3.4 Seismic

The reflection seismic sections ECL 89-011 and ECL 89-011A were kindly provided by

Namcor, Namibia.

5.3.5 Data reports

Analytical results of four additional gas samples from the Kudu gas field were available

(ANDRESEN 1992). The report was prepared by the Institutt for Energiteknikk, Norway.

Additionally, a geochemical report on the Kudu 9A-2 and Kudu 9A-3 wells was available

Methods 65

(DAVIES and VAN DER SPUY 1988). The report contains results from total organic carbon

(TOC), Rock-Eval, calcimetry, vitrinite reflectance, sporinite fluorescence and maceral

analyses. Excerpts of a geochemical report on the Cruz del Sur cutting samples and on

micropaleontological reports on the Cruz del Sur and Kudu wells were kindly made available

by Namcor. From the Cruz del Sur well analyses data on source rocks were made available by

YPF.

Results and Interpretation 66

6 Results and interpretations

6.1 Geochemistry

The results of the geochemical analyses on near-surface sediments, source rocks and natural

gas and condensate samples from the Kudu gas field are compiled in Appendix A.


Hydrocarbon gas was desorbed from 137 surface sediment samples taken during several

research cruises offshore Argentina, Namibia and South Africa. The gas was analysed

concerning its molecular and stable carbon isotopic composition (table 6.1). The free gas in

the pore space was removed further to the desorption procedure because it is thought to be of

predominantly microbial origin (FABER 1987; KLUSMAN 1993; FABER et al. 1997).

Table 6.1: Ranges of hydrocarbon yield and stable carbon isotopic ratios of gaseous hydrocarbons desorbed from near-surface sediments from offshore Namibia, South Africa and Argentina (*1 ppb corresponds to 1.10-9 g gas per g dry sediment). The ciphers in brackets indicate the number of analyses.

Colorado Basin, Argentina

Malvinas Basin, Argentina

SW Africa Argentina, Meteor cruises

CH4 [ppb*] 1.6 to 73.5 (40) 9.9 to 126 (61) 3.9 ppb to 2973 (21) 7.9 to 462.1 (15) C2H6 [ppb] 0.1 to 6.4 (40) 1.4 to 6.1 (61) up to 113.6 (21) 2.1 to 10.0 (15) C3H8 [ppb] up to 3.5 (40) up to 2.2 (61) up to 69.6 (21) 1.1 to 3.8 (15) C4H12 [ppb] up to 2.6 (40) up to 1.7 (61) up to 79.7 (21) up to 2.8 (15) C5H10 [ppb] up to 1.1 (40) up to 245 (21) CH4 [hc-%] 61.1 to 96.6 (40) 90 to 98 (61) 62 to 100 (21) 64.4 to 99.0 (15) C1/ (C2+C3) 1.9 to 38.0 (40) 10.9 to 53.6 (61) 2.6 to 54.3 (21) 3 to 134 (15) δ13CH4 [‰] -50.5 to -33.4 (40) -55.3 to -37.3 (61) -77.0 to -31.5 (21) -80.4 to -36.5 (15) δ13C2H6 [‰] -39.9 to -27.1 (36) -34.3 to -28.1 (61) -35.2 to -22.6 (19) -34.3 to -26.8 (15) δ13C3H8 [‰] -19.4 and -20.9 (2)

The Argentine samples show an average methane yield of 42.6 ppb, ethane yield of 3.0 ppb

and propane yield of 1.4 ppb. The African samples contain on the average 237 ppb methane,

16.1 ppb ethane and 10.0 ppb propane. The average hydrocarbon yield of the African samples

is higher than that of the Argentine because the samples 0018655, 0018661 and 0018662

contain large quantities of methane. Without considering these three samples the mean

methane yield of the African samples is similar to that at the Argentine continental margin

(43.0 ppb). The ethane and propane yields are significantly higher (18.3 ppb ethane, 11.1 ppb


propane). This difference is also reflected by the mean volume ratio C1/(C2+C3) which

amounts to 22 for Argentine and to 7 for Africa samples. The δ13C values of the desorbed

methane offshore Argentina have an average of –41.6 ‰, the δ13C2H6 of -31.9 ‰. The

methane desorbed from African sediments show average δ13C values of -41.4 ‰, the ethane

of -26.6 ‰. Because of the small gas quantities δ13C values could only be measured for

propane on two samples from offshore Africa (samples 0018648 and 0018654). The

molecular composition (expressed as the volume ratio C1/(C2 + C3)) is plotted against the δ13C

value of methane in a diagnostic plot in order to trace back the origin of the gas (figure 6.1a).

-75.0

-65.0

-55.0

-45.0

-35.0

-25.0

0.00 5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00 45.00 50.00

ColoradoMalvinasArgentinien (Meteor)Africa

Colorado BasinMalvinas BasinAfricaArgentina (Meteor)

100000

1

10

100

1000

10000

-100 -80 -60 -40 -20

Thermal

Bacterial

C/(C

+C)

12

3

marine

C - Methane (‰)δ 13

m

ix

i n g

terres

trial

Colorado BasinMalvinas BasinAfricaArgentina (Meteor)

100000

1

10

100

1000

10000

-100 -80 -60 -40 -20

Thermal

Bacterial

C/(C

+C)

12

3

marine


m

ix

i n g

terres

trial

100000

1

10

100

1000

10000

-100 -80 -60 -40 -20

Thermal

Bacterial

C/(C

+C)

12

3C

/(C+C

)1

23

marine

C - Methane (‰)δ 13 C - Methane (‰)δ 13

m

ix

i n g

terres

trial

B = microbial gasT = associated gasTo = associated with oil (initial phase of formation)

Tc =

TT = non-associatedTT (m) = marine non- associated gasTT(h) = non-associated gas from NW German coals

Md = deep migrationMs = shallow migration

associated with condensate

M = mixture of intermediate composition

-20

-30

-40

-50

-60

-70 B

M

Tc

To

δ13C

met

hane

per

mil

PDB

0 20 30 504010

TT(m)

TT(h)

mixed source

Md

Ms

C2+ [%]

A

B

Figure 6.1: Plots to characterise the source of the hydrocarbon gas desorbed from near-surface sediments from offshore South Africa, Namibia and South America after BERNARD (1978), SCHOELL (1983).


The samples from offshore Africa are wetter than those form the Argentine margin showing

lower methane fractions (lower C1/(C2+C3) ratio). In a plot of the sum of C2+ components

versus the δ13C of methane (SCHOELL 1983, figure 6.1b) the samples from offshore Africa

plot near the field for condensate associated gas. From the Bernard plot (Figure 6.1a) it is

supposed that most of the gas samples are of thermogenic origin. Some of the samples,

however, have significantly lower δ13C values (samples 0010906, 0010920 (Argentina)

0018655, 0018661, 0018662 (Africa), 0112845 and 0112849 (Argentina, Malvinas)).

Methane with δ13C values lower than about –50 ‰ is considered to be microbial in origin

(FUEX 1977) but this value is an empirical one. There is some overlap with methane from

low mature marine source rocks (STAHL 1979). Thus, because the samples 0112845 and

0112849 from the Malvinas basin contain 4.0 % and 4.8 % higher hydrocarbons, respectively,

they are considered to be of thermogenic origin or at least a mixture of microbial and

thermogenic gas. Samples 0018661, 0018662 and 0018663 are characterised by 100 %

methane. These samples can not be plotted in the Bernard plot (division by zero) but in the

plot C2+ versus δ13Cmethane according to (SCHOELL 1983, figure 6.1b). The absence of higher

hydrocarbons in the samples 0018661 and 0018662 together with their low δ13C (-68.6 and

-77.0 ‰) as well as their position in the “Schoell plot” suggest a microbial origin of the gas.

Sample 0018663 shows a δ13C value typical for thermogenic gas (-35.2 ‰). Because of the

very low hydrocarbon concentration in this sample (8.8 ppb methane) the concentrations of

the higher hydrocarbons might be too low to be detected. During the measurement of this

sample the base line fluctuated quite much thus it was hard to differentiate between noise and

peaks. The remaining five samples with low δ13C values contain 1.0 to 4.8 % higher

hydrocarbons. Thus an admixing of a certain portion of thermogenic hydrocarbons is inferred

because higher hydrocarbons form by microbes only in traces (FUEX 1977). All other

samples plot clearly in the Bernard plot in the field of thermogenic gas generated from a

marine source rock. Further information concerning the source rock can be deduced from

plots of the δ13C values of the methane and ethane (figure 6.2).


0.6

1

2.3

2

1.5

2.5

2

0.6 1

1.5

-50

-45

-40

-35

-30

-25

-20

-15

-45 -40 -35 -30 -25 -20 -15

Colorado Basin

Malvinas

Argentina

Africaδ13

CM

etha

ne (‰

)

δ13CEthane (‰)

Rr (%)

marine

terrestrial

Rr (%)

Figure 6.2: δ13CH4 and δ13C2H6 values used to deduce type and maturity of active source rock after BERNER and FABER (1996). The maturity lines in the plot are calibrated for type II kerogen with the average value of the Aptian to Barremian source rocks from the Kudu gas field.

Most of the data plot in the vicinity of the maturation line of a type II kerogen. This confirms

the assumption drawn from the Bernard plot (figure 6.1) that a marine source rock could be

the source of the hydrocarbon gas found in the near-surface sediments. The maturity of this

source rock derived from figure 6.2 is significantly higher at the African margin

(0.8 - 1.9 % Rr) than at the South American margin (0.5 – 1.2 % Rr). The position of the

maturation lines in the diagram depends on the stable carbon isotopic values assumed for type

II and III kerogen. In the present study the average δ13C value of the Aptian shales from the

Kudu wells (-25.5 ‰) was chosen for calibrating the marine maturation line according to

BERNER and FABER (1996). The terrestrial maturation line was calibrated using an

estimated δ13C value of -28.5 ‰ because terrestrial source rocks are assumed to be 3 to 5 ‰

“lighter” than marine source rocks (GALIMOV 1980). The absolute maturity values vary with

the stable carbon isotopic value assumed for the source rocks.

Displacement of data points from the trend of the maturation line might result from mixing

with microbial methane which would shift the data points to positions below the maturation

line. Admixing of terrestrial gas as well as minor extents of methane oxidation would displace

the data points upwards.


6.1.2 Source rocks

Table 6.2: Compilation of the results of the analyses of source rock samples from different locations. Note that the numbers in brackets behind the values indicate the number of samples analysed. The values measured for the Kudu wells in the framework of this study are marked with BGR, values marked with Soekor are from DAVIES and VAN DER SPUY (1988).

Sample location

TOC [%]

TS [%]

Tmax [°C]

S1 [mg HC/g rock]

S2 [mg HC/g rock]

S3 [mg CO2/g rock]

HI [mg HC/g TOC]

OI [mg CO2/g TOC]

PI Rr [%]

δ13COM [‰]

Kudu 9A-2 (BGR)

0.9 to 2.3 (20)

417 to 556 (20)

0.15 to 0.56 (20)

0.21 to 0.71 (20)

1.15 to 1.75 (20)

18 to 38 (20)

63.9 to 157.7 (20)

0.3 to 0.5 (20)

1.22 to 1.78 (6)

-26.2 to -24.8 (20)

Kudu 9A-2 (Soekor)

1.0 to 3.3

449 to 520

0.14 to 0.61

0.16 to 0.71

0.77 to 1.53

10 to 44

24.5 to 121.4

0.1 to 0.6

Kudu 9A-3 (BGR)

1.1 to 2.0 (18)

420 to 515 (18)

0.10 to 0.27 (18)

0.32 to 0.62 (18)

1.32 to 1.66 (18)

17 to 34 (18)

69.1 to 138.5 (18)

0.2 to 0.3 (18)

-25.6 to -23.8 (18)

Kudu 9A-3 (Soekor)

1.0 to 2.0

441 to 499

0.12 to 0.31

0.24 to 0.42

0.69 to 1.27

18 to 27

48.7 to 126.0

0.27 to 0.44

DSDP 361

0.2 to 13.2 (24)

12.2 to 14.1 (4)

375 to 432 (24)

up to 1.1 (24)

0.3 to 61.2 (24)

0.5 to 5.9 (24)

15 to 556 (24)

33 to 497 (24)

up to 0.1 (23)

0.27 to 0.35

-28.1 to -23.0 (20)

Whitehill shale

0.2 to 2.0 (5)

up to 0.2 (5)

1.2 to 3.5 (4)

-24.4 to -18.6 (4)

Cruz del Sur

0.1 to 4.0 (23)

403 to 449 (23)

up to 1.3 (23)

0.2 to 21.6 (23)

0.6 to 4.1 (23)

66 to 539 (23)

29 to 939 (23)

0.03 to 0.33 (23)

0.32 to 0.67 (109

-26.2 to -20.2 (19)

Irati shale 12.6 to 21.9 (2)

4.2, to 5.8 (2)

424 to 425 (2)

4.8 to 7.2 (2)

77.7 to 158.3 (2)

1.0 to 2.7 (2)

616 to 724 (2)

23 to 47 (2)

0.06 to 0.04 (2)

0.48 (2)

-23.8 to 20.6 (2)

6.1.2.1 Total organic carbon (TOC) and sulphur (S) content

The range of the TOC content of the analysed samples varies widely. Especially samples from

the DSDP 361 well and from the Irati shale outcrop contain large quantities of organic matter

(figure 6.3). The samples from these locations also have the highest mean TOC content with

4.2 and 17.2 % TOC, respectively. The lowest mean TOC show the Cruz del Sur and

Whitehill shale samples with 0.9 and 1.0 % TOC, respectively. The samples from the Kudu

well have mean TOC contents of 1.5 and 1.7 % TOC for well 9A-2 and 9A-3. In spite of the

low mean TOC value some of the Valangininan-Kimmeridgian samples from the Cruz del Sur

well have a higher TOC content of up to 4.0 % (samples 0020740, 0020748, 0020799,


0020831 and 0020869). TOC analyses by Western Atlas (STARLING 1994) shows additional

samples with high TOC contents in the prerift section (figure 6.4).

Figure 6.3: Total organic carbon contents of samples from different locations offshore SW Africa and Argentina.

Figure 6.4: TOC contents of the Cruz del Sur samples - compilation of analyses data surveyed by Western Atlas (STARLING 1994) (black) and BGR (grey).

0

2

4

6

8

10

12

14

16

18

0 - 1

1 - 2

2 - 5

5 - 10

10 - 15

15 - 25

TOC [%]

Num

ber

of sa

mpl

esKudu 9A-2Kudu 9A-3DSDP 361Cruz del SurWhitehillIrati

0 0,5 1 1,5 2 2,5 3443

645

855

1065

1275

1485

1695

1905

2115

2335

2555

2765

2973

3183

3393

3603

3813

3963

4173

Dep

th [m

]

TOC [%]

pre-rift

passive margin

post-rift

syn-rift


The Kudu wells on the other hand all have no more than 2.3 % TOC. The analyses of

DAVIES and VAN DER SPUY (1988) for the Kudu samples are in general agreement

withthe BGR measurement (figure 6.5).

Figure 6.5: Comparison of TOC contents measured by BGR and Soekor for samples from the Aptian to Barremian source rock interval.

6.1.2.2 Rock Eval pyrolysis

The parameters S1, S2, S3 and Tmax were measured on 84 rock samples with a conventional

Rock Eval 6 machine. The hydrogen, oxygen and production indices were calculated from the

S1, S2, S3 and TOC values according to the following equations:

TOCSHI 1002 ⋅= Eq. 6.1

TOCS

OI1003 ⋅= Eq. 6.2

21

1

SSSPI+

= Eq. 6.3

0 1 2 3 4

3865

3875

3885

3918

3927

3939

3957

4107

4119

4128

4137

4149

4158

4167

4179

4188

4197

4209

4218

TOC [%]

TOC [%] SoekorTOC [%] BGR

0 1 2 3 4

3839

3848

3857

3869

3878

3887

3899

3908

3917

3929

3938

3947

3959

3968

3977

3989

3998

TOC [%]


Because the samples have not been decarbonised prior to analysis the S3 values (and hence the

oxygen indices) might be too high due to CO2 added from disintegration of thermally instable

carbonates (pers. com. G. Scheeder, BGR). The samples 9937003 from well Kudu 9A-2 and

9937013 from 9A-3 were excluded because they are supposed to be contaminated by artificial

hydrocarbons (mud samples). The Whitehill samples were not analysed because of their high

maturity and low TOC content.

Especially the Rock Eval pyrolysis of the rock samples shows that some rocks with

hydrocarbon potential are present in the southern South Atlantic. The Irati shale samples show

the highest hydrogen indices (up to 724 mg HC/g TOC) and therefore the highest petroleum

potential. According to the modified van Krevelen diagram (figure 6.6) the samples are

characterised by type I-II kerogen.

IratiKudu 9A-2Kudu 9A-3DSDP 361Cruz del Sur

0 50 100 150

150

0

300

450

600

750

900

Oxygen Index (mg CO2/g TOC)

Hyd

roge

nIn

dex

(mg

HC

/g T

OC

)

III

II

I

IratiKudu 9A-2Kudu 9A-3DSDP 361Cruz del Sur

0 50 100 150

150

0

300

450

600

750

900

Oxygen Index (mg CO2/g TOC)

Hyd

roge

nIn

dex

(mg

HC

/g T

OC

)

III

II

I

Figure 6.6: Hydrogen index versus oxygen index – modified van Krevelen diagram according to ESPITALIÉ et al. (1977). The lines in the diagram indicate the evolution lines of the different kerogen types with increasing maturity (top to bottom and right to left.


Some of the Aptian shale samples from the DSDP 361 well show also high petroleum

generation potential with up to 556 mg HC/g TOC. They contain type II kerogen. Valanginian

to Hauterivian rock samples from the Cruz del Sur well also show moderate petroleum

generation potential and type II kerogen. Those samples have hydrogen indices of up to

539 mg HC/g TOC and TOC values of up to 4.0 % TOC. The Kudu samples have maximum

hydrogen indices of 38 mg HC/g TOC. This indicates a very low if any petroleum generation

potential. The oxygen index is especially high for most of the Kudu samples. This might be

caused by the high carbonate content of the samples from the deeper part of the well

(DAVIES and VAN DER SPUY 1990).

The production index is the ratio of generated hydrocarbons to those that can be generated and

can be used as a maturity indicator if migration is limited. The samples from the Kudu wells

show the highest maturity with production indices up to 0.5. This is in line with the findings

of the Tmax measurements which indicate that most of the Kudu samples are within the gas

window because according to (ESPITALIÉ et al. 1985) the oil window starts for type II

kerogen at Tmax values above 430 to 435 °C and the gas window at Tmax values above 450 to

455 °C. This higher maturity could in part account for the low petroleum potential indicated

by the hydrogen index because a major portion of initial potential could have already been

realised. Compared to the Kudu samples the samples from the Irati shale, the DSDP 361 well

and part of the samples from the Cruz del Sur well are considered immature both regarding

the Tmax values as well as the production indices.

6.1.2.3 Vitrinite reflectance

Vitrinite reflectance values were measured for selected samples from the different locations

(Tab. 6.2). The vitrinite reflectance values for the Whitehill shale samples were difficult to

measure. A strong thermal influence by dolerite intrusion on the samples is quite likely. The

value range of above 1.2 to 3.5 % Rr is quite high. Apart from the heavily thermal influenced

Whitehill samples, the Kudu samples are the most mature samples (figure 6.7) as also

indicated by the hydrogen indices, production indices and Tmax values. The samples are

currently in the gas window. The samples from the DSDP 361 well, the Cruz del Sur well and

the Irati shale are immature to low mature. This is in good agreement with the findings of the

Tmax measurements.


0

500

1000

1500

2000

2500

3000

3500

4000

4500

0.1 1 10

Vitrinite reflectance [%]

Dep

th [m

]

Kudu 9A-2 (Soekor)

Kudu 9A-2 (BGR)

DSDP 361

Figure 6.7: Vitrinite reflectance profile of the well Kudu 9A-2. For comparison, the values for DSDP 361 are included.

6.1.2.4 Maceral analyses

Maceral analyses on samples from the Kudu well show that bituminite is the main component

of the organic matter for samples above horizon P1 (two samples). Below P1 the main

component is inertodetrinite (redeposited debris showing no cell structure, STACH et al.

1982). This is in good agreement with DAVIES and VAN DER SPUY (1988) who report that

the percentage of amorphous organic matter lies between 65 to 100 % for samples between

3835 and 4167 mbsl in well 9A-2. They infer the presence of oil-prone kerogen in the P1 to P

interval and that the amorphous material below horizon P1 was derived from degraded

terrestrial material (Benson (1988) cited in DAVIES and VAN DER SPUY (1988)). The

maceral analyses show the presence of oil-prone kerogen as well as terrestrial influence on the

rocks.

Maceral analyses on samples from the DSDP 361 well show that they all are bituminous. Two

of the Aptian samples (0011281 and 0011287) are characterised as oil shales of type II

kerogen. These samples contain 80 % amorphous organic matter. Sample 0011281 is coaly

showing type III-IV kerogen with 44 % vitrinite and 51 % inertinite. The fifth sample


(0011292) shows type II-III kerogen with 40 % amorphous organic matter, 20 % vitrinite and

20 % inertinite. Especially the oil shales are characterised by TOC contents above 10 % and

high hydrocarbon indices indicating high petroleum generation potential.

The samples 0020719 and 0020720 originate from an Irati oil shale outcrop in Brazil.

According to Rock Eval parameters (OI-HI plot) and maceral analyses the samples contain

type I to II kerogen.

The samples 0011277 and 0011287 are characterised by maceral analyses as oil shales. They

contain high proportions of bituminite (80 %) and low proportions of vitrinite (0.1 %) and

intertinite (5 and 1 %, respectively). Kerogen type II is indicated for these samples.

The samples from the Irati shale are characterised by high portions of amorphous organic

matter. Liptinite, inertinite, vitrinite and bitumen are present as secondary compounds. These

samples are also characterised by high petroleum generation potential.

The Whitehill shale samples show condensed bituminous substances. Due to the high maturity

of the samples the reflection of those particles is similar to that of vitrinite and can be used to

estimate the maturity of the sample (per. com. W. Hiltmann, BGR).

The maceral analyses on samples from the Cruz del Sur well is of minor significance because

of the poor quality of the samples. The samples contain large quantities of rust and other

artificial materials. The dark silty to clayey particles in the samples were collected for maceral

and vitrinite reflectance analyses. These particles contain 30 to 60 % liptinite, 10 to 40 %

vitrinite and 10 to 60 % inertinite.

6.1.2.5 Stable carbon isotopes of sedimentary organic matter

The stable carbon isotope values range from -26.2 to -23.8 ‰ for the Kudu samples with an

average of -25.4 ‰, from -28.1 to -23.0 ‰ with an average value of -24.9 ‰ for the DSDP

361 samples, from -23.8 and -20.6 ‰ for the Irati samples, from -24.4 to 18.6 ‰ (average

-21.0 ‰) for the Whitehill samples and from -26.2 to -20.2 ‰ (average -24.4 ‰) for the Cruz

del Sur samples. The organic matter in the samples from the Paleozoic Whitehill and Irati

shale is characterised by substantially higher δ13C values than that in the Cretaceous samples

from the Kudu and DSDP wells. The Irati shale is known to show variable and unusual δ13C

values because of the special setting in the huge epicontinental basin (pers. comm. E. vas dos

Santos Neto, Petrobras). A similar setting is here inferred for the Whitehill shale samples. The


variation in the δ13C of the organic matter from the Kudu wells, the DSDP wells and the Cruz

del Sur wells could be induced by the fluctuation of the amount of input of terrestrial matter

which is “lighter” than marine organic matter due to transgressive and regressive cycles

(GALIMOV 1980; PASLEY et al. 1991).

6.1.3 Petroleum generation kinetics of DSDP and Irati Shale samples

Bulk pyrolysis experiments were conducted using a conventional RockEval 6. The Rock Eval

data were analysed using Optkin 1 (Vinci Technologies, France) and a BGR in-house kinetic

data analysing program (table 6.3). Both programs calculate reaction kinetics according to the

same mathematical algorithm. A significant difference between both programs is, however,

that Optkin 1 does not use the real temperature data but recalculates the time temperature

evolution. In addition, Optkin 1 does not have many options for varying parameters for the

kinetic calculations.

Table 6.3: Results of the kinetic analyses of bulk RockEval pyrolysis data obtained with Optkin (Vinci Technologies, France) and BGR intern software.

Activation Energy [kcal/mole] of Maximum Initial Petroleum Potential [mg/g TOC]

Range of Activation Energies [kcal/mole]

Arrhenius Factor [s-1]

Optkin Optkin

Sample Location TOC [%]

HI [mg hc/ g rock]

Optkin BC BGR BGR

Error Function (Optkin)

44 - 70 4.1E+13 0011277 DSDP 361, Cape Basin, South Africa

11.0 407 50 47

40 - 52 3.4E+12

0.333


11.5 36 63 48

44 - 53 5.1E+12

2.632


13.2 28 63 51

45 - 56 2.8E+13

2.130


11.0 556 50 47

43 - 57 2.4E+12

0.281

41 - 55 3.7E+12 0020719 Irati Shale, Brazil

12.6 616 48 47 44 - 51 2.3E+12

0.282

40 - 63 7.4E+12 0020720 Irati Shale, Brazil

21.9 724 49 47 44 - 51 2.3E+12

0.338

From the Arrhenius factors and the distribution of the activation energies three groups can be

differentiated among the studied samples (figure 6.8). The first group (samples 0011280 and

0011281, DSDP 361) is characterised by very low hydrogen indices (below


40 mg HC/g TOC). The Arrhenius factors obtained with Optkin 1 are comparably high (table

6.3). Those obtained with the BGR program are three to four orders of magnitude lower. The

samples show a wide and slightly asymmetric distribution of the hydrocarbon generation rate

which was modelled with Optkin only moderately well indicated by high error functions.

From the wide distribution of activation energies, the findings of the maceral analyses

(001281) and the HI values the samples are interpreted to contain type III kerogen.

The second group of samples (0011277 and 0011287, DSDP 361) is characterised by a much

narrower distributions of activation energies, a lower Arrhenius factors and lower activation

energies at the maximum petroleum generation potential. From their geochemistry (macerals,

HI, TOC) those samples are interpreted to contain type II kerogen.

The samples of the third group (0020719 and 0020720, Irati) show slightly lower Arrhenius

factors, lower (Optkin) to similar (BGR) activation energies at the maximum initial petroleum

generation potential and the narrowest distribution of activation energies. These samples

contain type I-II kerogen.

Figure 6.8: Distribution of activation energies calculated by the BGR software for selected source rock samples from the Irati shale and the DSDP 361 well.

Due to the high starting temperature (300 °C) at the beginning of the pyrolysis some

difficulties in analysing the data occurred. Error functions of Optkin for the coaly samples

0011280 and 0011281 as well as graphical comparisons of measured and calculated values

0,0

0,1

0,2

0,3

0,4

40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57

Ea (kcal/mol)

norm

. gen

. pot

entia

l

0011277 (DSDP 361, Aptian) 0011287 (DSDP 361, Aptian) 0020719 (Irati, Permian)0020720 (Irati, Permian)0011280 (DSDP 361, Aptian) 0011281 (DSDP 361, Aptian)


indicate a bad adjustment of the modelled to the generated data. In the following these data

will be neglected.

6.1.4 Reservoir hydrocarbons of the Kudu reservoir

6.1.4.1 Natural gas

Two gas samples from the Kudu reservoir were analysed. The results of these measurements

were compared with those of (ANDRESEN 1992; table 6.4)

Table 6.4: Molecular and isotopic composition of gas samples from the Kudu reservoir. Analyses of samples A-13827 to A-14244 are extracted from ANDRESEN (1992) and used for comparison purpose.

0000906

(BGR)

0000907

(BGR)

A-13827 A-13852 A-14012 A-14244

Methane [Vol-%] 96.8 96.8 86.9 94.5 87.1 94.4

Ethane [Vol-%] 1.7 1.8 1.4 2.3 1.3 2.4

Propane [Vol-%] 0.2 0.2 0.1 0.4 0.1 0.4

iso-Butane [Vol-%] 0.0 0.0 0.0 0.1 0.0 0.1

Butane [Vol-%] 0.0 0.0 0.0 0.1 0.0 0.1

2methyl-pentane

[Vol-%]

0.5 0.0 0.0 0.0

3methyl-pentane

[Vol-%]

0.4

Hexane [Vol-%] 1.5 0.0 0.0 0.0

Nitrogen [Vol-%] 0.9 0.9 9.1 2.5 11.5 2.5

C2+ 2.0 2.1 4.0 3.0 1.4 3.1

iC4/n-C4 1.0 1.0 0.3 1.0 0.5 1.0

C1/(C2+C3) 50.9 48.6 55.2 34.7 62.4 33.7

C2+C3 1.9 1.99 1.6 2.7 1.4 2.8

δ13C1 -36.7 -36.7 -37.1 -37.9 -37.0 -37.6

δ13C2 -28.2 -27.9

δ13C3 -22.6 -22.6

δCO2 -12.3 -11.9

δD -150 -152 -142.2 -135.4 -145.8 -144.4


100000

1

10

100

1000

10000

-100 -80 -60 -40 -20

Thermal

Bacterial

/(C+C

marine


mi

xi n g

terres

trial

100000

1

10

100

1000

10000

-100 -80 -60 -40 -20

Thermal

Bacterial

/(C+C

3C

/(C+C

)1

2

marine

C - Methane (‰)δ 13C - Methane (‰)δ 13

mi

xi n g

terres

trial

Analysis BGR (2000)Analysis IFE (1992)

-30

-40

-50

-60

-70 B

M

Tc

To

δ13C

met

hane

per

mil

PDB

C2+ [%]

0 20 30 504010

TT(m)

TT(h)

mixed source

Md

Ms

Figure 6.9: Diagnostic plots for the Kudu gas after BERNER and FABER (1996) (left hand side) and SCHOELL (1983) (right hand side) for deciphering the type of source rock for the gas desorbed from the near-surface sediments. B = microbial gas, T = associated gas, To = associated with oil (initial phase of formation), Tc = associated with condensate, TT = non-associated, TT (m) = marine non-associated gas, TT(h) = non-associated gas from NW German coals, M = mixture of intermediate composition, Md = deep migration, Ms = shallow migration.

Figure 6.10: Plots of δ13C values of ethane and propane plotted vs. that of methane in order to deduce the maturity of the source rock of the Kudu natural gas after BERNER and FABER (1996).


From the diagnostic plots (figures 6.9 and 6.10) it is inferred that a) the gas stems from a

marine source rock, b), c) the maturity is about 1.1 - 1.4 % Rr which is less than the maturity

measured on the source rocks (1.8 % Rr) and d) the methane is a “not associated” (with oil or

condensate) gas.

6.1.4.2 Condensate

Minor quantities of condensate have been encountered in the Kudu Reservoir. The condensate

shows a unimodal distribution of n-alkanes, with the peak n-alkane occurring at n-C11 (figure

6.11). Biomarkers could only be detected in traces. The relatively high concentration of

aromatic components indicates terrestrial input to the source rock. This is confirmed by

heptane and isoheptane values and the pristane/n-C17 and phytane/n-C18 values (THOMPSON

1983; SHANMUGAM 1985, figure 6.12).

pA

160

140

120

100

80

60

40

2010 20 30 40 50 60 min

n-C1

2

n-C

13

n-C

11

n-C

10

n-C

9

n-C

8

n-C

12

n-C

14

n-C

15

n-C

16

n-C

17

n-C

18

n-C

19

n-C

20

n-C2

1

n-C

22

n-C2

3

n-C

24

n-C

25

n-C

20n-

C20

n-C

20

Tolu

ol

n-H

epta

neM

ethy

lcyc

lohe

xane

Phyt

ane

Prist

ane

Figure 6.11: „Whole oil“ chromatogram of the analysis of a condensate sample from well Kudu 5.

The heptane and the isoheptane values are the principle indices of paraffinicity (THOMPSON

1983, Heptane value = (2-Methylhexane + 3-Methylhexane) / (1,cis-3-Dimethylcyclopentane

+ 1,trans-3-Dimethylcyclopentane + 1,trans-2-Dimethylcyclopentane), Isoheptane value =

100.0 x n-Heptane / (Cyclohexane + 2-Methylhexane + 1,1-Dimethylcyclopentane + 3-

Methylhexane + 1,cis-3-Dimethylcyclopentane + 1,trans-3-Dimethylcyclopentane + 1,trans-2-


Dimethylcyclopentane + n-Heptane) + Methylcyclohexane)). Moreover, the heptane value

indicates a source maturity of approximately 1.05 % Rr (figure 6.13). The bulk carbon isotope

ratio of the condensate is -24.5 ‰. This value is approximately 1 ‰ heavier (more positive)

than the average value of the organic matter in the Aptian and the Barremian source rocks

drilled in the Kudu wells (-25.5 ‰).

Figure 6.12: Heptane - isoheptane value plot and pristane/n-C17 – phytane/n-C18 plot point to a terrestrial influence on the source of the condensate after SHANMUGAM (1985, left hand side) and THOMPSON (1983, right hand side).

Figure 6.13: Heptane value of the condensate indicates a source maturity of approximately 1 % Rr after THOMPSON (1983).

Although such a relation is untypical, oil-to-condensate cracking could create this

„inversion“(CLAYTON 1991b). Basis assumption for this explanation is that the condensate


was generated from the source rock sampled in the Kudu wells. The low maturity, high

terrestrial content and high carbon isotope ratio of the condensate favour the hypothesis that

the condensate was generated by another source rock which is not drilled in the Kudu wells

and has migrated laterally into the reservoir.

6.2 Basin modelling study

6.2.1 Sequence stratigraphy of the Namibian and South African continental

margin

The sequence stratigraphic and chronostratigraphic framework of MUNTINGH (1993) and

BROWN et al. (1995) was used to date the major horizons identified in the reflection seismic

section ECL 89-011 and ECL 89-011A (Figure 6.14) according to the time scale of HAQ et

al. (1988). Well control was provided by the wells Kudu 9A-2 and 9A-3 near shotpoint 1975

of section ECL 89-011. The sequences of 4th, 3rd and 2nd order in the postrift sediments in the

Orange Basin offshore South Africa between 126 and 67 Mabp dated by MUNTINGH and

BROWN (1993) and BROWN et al. (1995) are compiled in appendix B.

6.2.2 Interpretation of the seismic section ECL 89 011

The Precambrian to Palaeozoic basement (MUNTINGH and BROWN 1993; BROWN et al.

1995) which is characterised by a chaotic reflection pattern with only few coherent seismic

reflectors, reaches up to less than one second two-way-traveltime (TWT) in the eastern part of

the section. Towards the western part of the section the basement descends to more than six

seconds TWT finally vanishing under four wedges of seaward dipping reflector sequences

(the term sequence in this context is not to mix up with the stratigraphic term “sequence”

introduced by MITCHUM et al. (1977a) and VAIL (1977)). The seaward dipping reflector

sequences were interpreted to belong to the synrift phase of the Atlantic opening

(NÜRNBERG and MÜLLER 1991; STEWART et al. 2000) and are thus dated as Upper

Jurassic to Lower Cretaceous (133 to 124 Mabp, chapter 3, figure 6.14). In the eastern part of

the section two half grabens can be seen clearly in the upper part of the basement. These

grabens are interpreted to be filled with synrift sediments similar to the setting found in the


Figure 6.14: Linedrawing of the reflection seismic sections ECL 89-011 and ECL 89-011A. The Kudu reservoir is marked in the line drawing.


A-J1 graben offshore South Africa (BARTON et al. 1993; BROAD and MILLS 1993;

JUNGSLAGER 1999; BEN-AVRAHAM et al. 2002). The top of the basement is marked by

the Jurassic rift onset unconformity, the top of the SDRS by the Lower Cretaceous drift onset

unconformity (HINZ 1981) lapping onto the rift onset unconformity. The drift onset or break-

up unconformity (unconformity 6At1) is dated to 117.5 Ma ( MUNTINGH and BROWN

1993; BROWN et al. 1995).

After the emplacement of the basement and the seaward dipping reflector sequences a period

of non-deposition and most likely erosion is assumed. Because of its irrelevance to modelling

the post-rift Cretaceous petroleum system this erosion was not integrated into the 2D basin

model. On top of the basement and the SDRS, a thick Cretaceous and Cenozoic sedimentary

succession was deposited. The sediments are interpreted to be of Lower Cretaceous to

probably Quaternary age. In the Kudu well no Quaternary sediments have been encountered

but Holocene sediments on the sea floor of Orange banks have been reported by MCMILLAN

(1987) (cited in MCMILLAN 1990). The most prominent unconformities within the

sedimentary pile are of Cenomanian (15At1 = 93 Mabp) and Base Tertiary (16Dt1 = 65 Ma)

age. Both unconformities are associated with major erosions as reconstructed in the Kudu

wells (MCMILLAN 1990).

Further, a Mid Aptian unconformity (13At1 = 112 Mabp) associated with the onset of open-

marine circulation throughout the southern Atlantic across the Walvis Ridge - Rio Grande

Rise barrier was observed (BROWN et al. 1995; JUNGSLAGER 1999). This unconformity

was not modelled explicitly because it intersects with the Cenomanian erosional event in the

western part of the section with which it was merged. The thickness of sediments missing

through erosion in the Uppermost Cretaceous was estimated to about 400 to 500 m (see

chapter 6.2.3). The sedimentary record missing at the Cenomanian / Turonian unconformity is

large with respect to time but less pronounced regarding sediment thickness because the

Cenomanian sediments are supposed to represent a condensed section (MCMILLAN 1990).

The thickness of the Upper Cretaceous sediments compared to that of the Lower Cretaceous

and Cenozoic sediments is noticeable greater. The highest sedimentation rates are observed

for the uppermost Cretaceous (see chapter 3) which is characterised in the vicinity of the

Kudu wells by complex structures. This structure is interpreted as a growth fault roll-over

structure (BAGGULEY 1997). Growth faulting and slumping are widespread phenomena in

the south-western African offshore (LIGHT et al. 1993b).


A large share of the sediments cored at the continental margin shows evidence of transport by

turbidity currents, debris flows, or other essentially down-slope mechanisms (WINTERER

1980). Slump structures are especially common at drill sites located on the upper continental

rise (WINTERER 1980). No slumping is observed in the Tertiary succession of the

investigated seismic section, which is characterised by pronounced progradational stacking

patterns (figure 6.12). At the Argentine margin the Cenozoic sediment pile is much thicker

than that of Cretaceous age (SCHÜMANN 2002). The sea floor of the seismic section is a

predominantly smooth continuous reflector lacking erosional canyons, which are abundant at

the Argentine continental margin (SCHÜMANN 2002). Anyhow, submarine erosion could

have taken place after the establishment of open-marine conditions in the Aptian. According

to HEEZEN et al. (1966), bottom water velocities on the continental shelf almost always

exceed those required for the erosion and transportation of silt and clay. In the eastern part of

the section, Cretaceous reflectors run oblique towards the sea floor where they are truncated.

In contrast, the Tertiary reflectors onlap on the Base Tertiary unconformity. It is assumed that

seaward tilting of the margin during the Cretaceous occurred due to continued sagging of the

margin and due to sediment loading (figure 6.15).

Figure 6.15: Seaward tilting of the continental margin due to epeirogenic subsidence, modified from RONA (1974).


Thus, the Cretaceous sediments at the landward end of the section were lifted up whereas the

seaward portion of the section subsided. The major erosional event in the Upper

Cretaceous / Tertiary associated with the Base Tertiary unconformity truncated those

horizons.

Faults are recognised in the seismic section, which displace the rift onset unconformity to

minor extents. Those faults are associated with extensional movements during the rifting

process. More pronounced are the normal faults bounding the synrift half graben, which are

also related to the rifting process. In the postrift sediments a large number of faults are

present, which offset the sediments only very slightly. These faults are marked in figure 6.14

in principle. The small displacement amounts associated with the faults indicate smaller fault

length than marked in the linedrawing for better visibility. Major disturbance of the

sedimentary strata is observed in the Upper Cretaceous postrift sediments related to the

growth fault structure. Here a major listric fault is present which is the slide plain for the

downward movement of sediments above the fault plane. Because of the in general minor

displacement amounts and short length of the faults in the seismic section, they were not

supposed to provide major pathways for petroleum migration. Thus, no faults were included

into the basin modelling study which shortens the computing time considerably.

6.2.3 Estimation of the thickness of eroded strata

Petroleum generation depends strongly on the temperature of the source rock interval. This

temperature is a result of the basal heat flow, the heat generation from radiogenic elements,

and the burial depth. Therefore, the estimation of the thickness of eroded strata is an important

issue in basin modelling. Different approaches were used to conduct this task.

6.2.3.1 Estimation of the thickness of eroded strata using vitrinite reflectance

profiles

Vitrinite reflectance of unaltered organic matter at the time of deposition has a reflection of

about 0.20 % Rr (DOW 1977a). Higher reflectance values at the present day surface point to

erosion of the upper part of the section. To estimate the thickness of strata missing on top of

the section the trend in the vitrinite reflectance profile can be extended towards the minimum

vitrinite reflectance value. The vertical distance between zero depth and the intersection point

of the trend line with 0.20 % Rr indicates the thickness of eroded strata (figure 6.16). Abrupt


increases in the trend of the vitrinite reflectance indicate unconformities during the

sedimentation history in the same way (DOW 1977a). A general vitrinite reflectance trend

was assumed for the values from Kudu 9A-2 (logarithmic regression line with R2 = 0.90). The

extension of this trend towards the value 0.20 % Rr yields a value of missing sediments of

approximately 400 m (figure 6.16). This value coincides with the amount of eroded strata in

the Upper Cretaceous indicated by MCMILLAN (1990). In the DSDP 361 well offshore Cape

Town erosion of several hundred meters is assumed by BOLLI et al. (1975).

Figure 6.16: Thickness of eroded strata estimated from vitrinite reflectance data of well Kudu 9A-2.


6.2.3.2 Estimation of the thickness of eroded strata using Tmax profiles

Similar to vitrinite reflectance data, Tmax values (predominantly of type II and III kerogen)

imply information on the maturity of organic matter. Major jumps in a Tmax versus depth

profile may indicate hiatus, erosion, and uplift events. A general trend was assumed for the

data from the well Kudu 9A-2 (linear regression line, R2=0.90) thereby neglecting the data

points below 3400 m which scatter widely. In the upper part of the profile an offset can be

observed in the depth interval 760 – 850 mbsl (figure 6.17). This temperature step may be

associated with the Base Tertiary unconformity (horizon L at 830 mbsl).

Figure 6.17: Tmax data of the well Kudu 9A-2.


6.2.3.3 Estimation of the thickness of eroded strata using reflection seismic cross-

sections

In addition to vitrinite reflectance and Tmax values, missing strata can also be reconstructed

from reflection seismic sections. Usually, the truncated horizon is reconstructed parallel to the

underlying horizon, assuming that the sediment package was of uniform thickness before the

erosional event if a slowing down of the sedimentation rate towards the top before uplift and

erosion took place this would blur the estimation of the eroded thickness. In the seismic

section investigated in the present study the Base Tertiary unconformity is very pronounced

which conincides with the above mentioned findings. Another major unconformity at the

location of the Kudu wells is the Turonian unconformity. Because the Turonian is a

condensed section it is supposed that the thickness of sediments missing is negligible with

respect to the history evolution of the section.

6.2.4 Subsidence analysis

The subsidence history was reconstructed for two positions in the studied reflection seismic

section. This is important for the reconstruction of the tilting of the margin which exerts

influence on the direction of hydrocarbon migration. Additionally, the heat flow history is

combined with the subsidence history because stretching of crust is associated with changes in

the heat distribution. In spite of the differences between both the Argentine and Namibian

margin the existence of seaward dipping reflector sequences at both continental margins argue

against the simple shear model which would favour the generation of SDRS at only one

continental margin (pers. com. Dr. K. Hinz, BGR).

The exceptional high exposure of the African plate, which is often inferred as argument for

simple shear rifting, might be explained instead to result from the alteration in tectonic style

of the African plate at about 30 Ma (BURKE 1996). According to BOND (1978) and BOND

(1979) Africa rose significantly relative to North and South America, Europe and Australia

during the Tertiary.

For the calculation of the paleo water depth the western end of the section was assumed in a

first approximation to be underlain by oceanic crust. However, this holds not fully true

because the definition of the continent ocean boundary (COB) is given by different authors as

follows: The COB of BARTON et al. (1993) and BROWN et al. (1995) coincides with M4

whose age is indicated with 117.5 Ma (LARSON and HILDE 1975; AUSTIN and UCHUPI


1982) to 126 or 127 Ma (RABINOWITZ 1976; NÜRNBERG and MÜLLER 1991).

GRADSTEIN et al. (1994) and JACKSON et al. (2000) place it at magnetic anomaly G,

which is interpreted as magnetic edge-effect anomaly separating oceanic from continental

basement. GLADCZENKO et al. (1997) place the COB at the seaward termination of the rift

unconformity or where the deepest (i.e. oldest) seaward dipping reflector unit disappears at

depth. JACKSON et al. (2000) argue that the most oceanward SDRS separates stretched

continental and true oceanic crust which is concordant with the COB of GLADCZENKO et

al. (1997). The seismic section investigated in the present study displays the shelf and part of

the slope of a continental margin with in seaward direction increasingly stretched continental

lithosphere gradually giving way to the SDRS. Considering the criteria for the COB listed

above it is unlikely that the investigated section displays genuine oceanic crust at all.

Therefore, the equations of PARSONS and SCLATER (1977) to calculate basement depths

with time are supposed to be not fully applicable. Instead, an attenuated form of the

PARSONS and SCLATER (1977) subsidence curve for oceanic lithosphere was used because

no decoupling of oceanic and continental lithosphere was supposed to occur (CHARPAL et

al. 1978). The water depth at the western end was assumed to increase during the following

history of the margin with ( ) 4.0)3502500( 5.0 ⋅+= ttd m modified from PARSONS and

SCLATER (1977). The total tectonic subsidence calculated after equation 5.4 for the western

end of the section is approximately 4000 m assuming mean densities of 2750 kg/m3

(continental crust), 3300 kg/m3 (asthenosphere) and 1030 kg/m3 (sea water), respectively.

With the result from the TTS calculation a stretching factor β of 1.8 was calculated from

equation 5.6. At the position of well Kudu 9A-3 total tectonic subsidence was calculated to be

about 2100 m, which corresponds to a stretching factor β of 1.3. Stretching of the lithosphere

by factors of 1.8 and 1.3 would result in an initial subsidence of 1850 m and 960 m,

respectively (MCKENZIE 1978). These calculated initial subsidence values are supposed to

be too high because the depositional environment at the time of formation of the seaward

dipping reflector sequences is supposed to be a subaerial to shallow marine setting during the

synrift sequence (MUTTER et al. 1982; GLADCZENKO et al. 1998). In addition,the revision

of the micropaleontological study of (MCMILLAN 1990) by Dr. W. Weiß (BGR) supposes

significantly shallower water of only 400 m at most of the Barremian/Aptian boundary as

well. The paleo water depth of the lowermost interval in the Kudu 9A-1 well (undatable

interval, probably of Barremian to Hauterivian age) is inferred to be even lower with about

50 m which is consistent with the depositional environment assumed for the SDRS.


The heat flow calculated from the stretching factors according to equation 5.8 amounts to

71 mW/m2 for the western end of the seismic section and to 52 mW/m2 at the Kudu well for

the time of rifting and to 39 and 36 mW/m2, respectively, for the recent heat flow. Obviously

those heat flow values are too low regarding the values found at the continental margin of

South West Africa today. Heat flow values from onshore Namibia lie between 55 to

92 mW/m2 (BALLARD and POLLACK 1987) and between 30 and 140 mW/m2 offshore

south-western Africa (POLLACK et al. 1991; POLLACK et al. 1993). An average heat flow

of about 60 mW/m2 is assumed.

This discrepancy may be caused in part by the characteristics of volcanic margins. According

to ROBERTS et al. (1984) and ELDHOLM (1991); volcanic margins show evidence of initial

uplift or non-subsidence in contrast to non-volcanic margins which are characterised by rapid

initial subsidence. Today the African continent is underlain by several hot spots causing the

continent to drift only at very slow rates and to be elevated with respect to the other

continents. The heat flow might also be influenced by the emplacement of large volumes of

volcanics. Another hypothesis is introduced by ROBERTS et al. (1984) to explain the

elevated heat flow values in comparison to those calculated according to PARSONS and

SCLATER (1977) at the western margin of Rockall Plateau and involves the vicinity to the

Icelandic plume. As shown by BURKE (1996), the African plate today is underlain by 17 hot

spots.

6.2.5 1D model

The heat flow history which is one of the most sensitive parameters for petroleum generation,

was in a first approximation calibrated with a 1D model of the well Kudu 9A-2 with

PetroMod 1D Express (IES, Germany) on the basis of the lithologic and stratigraphic

framework of MCMILLAN (1990) because 1D models are much easier and faster to calculate

than 2D models (figure 6.18).

Due to the fact that the calculated heat flow values from the subsidence model were

substantially too low to fit the measured vitrinite reflectance values, the recent heat flow

values from the study area and the average heat flow values assumed for the rifting period

average values for rifting continental margins (ALLEN and ALLEN 1990) were chosen for

the respective period of margin evolution. Calibration of the heat flow values was conducted

with measured vitrinite reflectance data from the well Kudu 9A-2. The best-fit heat flow

history starts with a heat flow value of 130 mW/m2 at the time of rifting which decrease


exponentially to 62 mW/m2 for the passive margin. Because of effects like lateral fluid and

heat transfer, modification of the heat flow history of the 1D model may be necessary in the

2D model.

MesozoicK

Cenozoic

Figure 6.18: Input data used for 1D modelling of Kudu 9A-2 (A) and calibration of the 1D model with vitrinite reflectance data from well Kudu 9A-2.

6.2.6 Depth conversion

The seismic sections ECL 89-011 and ECL 89-011A were recorded in two-way traveltime.

Thus the interpreted horizons (figure 6.14) were converted to depth using interval velocities

from the literature (BAUER et al. 2000) and sonic log data from the Kudu gas field (DAVIES

and VAN DER SPUY 1990). The velocities are compiled in Appendix B.

6.2.7 Source rock definition

Aptian to Barremian shales are assumed as source rocks for the Kudu gas field (LIGHT and

SHIMUTWIKENI 1991; DAVIES and VAN DER SPUY 1993; MILLER and CARSTENS

1994; BRAY et al. 1998; JUNGSLAGER 1999). In the basin modelling study the initial TOC

contents of the rocks were assumed to amount to 5 %. TOC contents actually measured at

rock samples from the Kudu 9A-2 and 9A-3 wells amount to 2.3 % at most. Because of the

high maturity of the rocks (1.8 % Rr), which could have lead to organic matter loss during

maturation (CORNFORD 1994; DALY 1987), the higher value for TOC was chosen for


modelling. Additionally, it was inferred that values similar to the high TOC contents (in part

beyond 10 % TOC) found for Aptian samples from the DSDP 361 well in the Cape Basin

might be present downdip of the Kudu wells. The hydrocarbon generation potential in form of

the hydrogen index was for the same reasons inferred to be essentially higher than found for

the Kudu samples. In analogy to values measured on samples from the DSDP 361 well a HI

of 550 mg HC/g TOC was assumed.

6.2.8 2D model

Basin modelling involves the construction of models from real basins. This implies

simplifications of the original. In the study at hand no faults in the postrift section were

included because none of the faults recognised in the seismic was considered to be

pronounced enough to constitute viable hydrocarbon fairways. Furthermore, the synrift

grabens in the basement were not included in the model because no contribution to the Kudu

petroleum system was expected. The lithology of the Kudu wells is very much dominated by

shales with few thin intercalated layers of carbonates and sands (BAGGULEY 1997). These

thin strata were not included in the basin model as well as the basaltic layers at the base of the

well, which are interpreted to belong to the feather edge of a SDRS (JUNGSLAGER 1999).

Facies change from the shore to the basin centre is supposed but because of the lack of

detailed information no facies change was included into the model except for the reservoir

interval, which is known to constitute a pinch-out trap.

6.2.9 Sedimentary history

The basis of the model of the petroleum generation, migration and accumulation of the Kudu

gas field offshore Namibia carried out with the petroleum modelling software package

PetroMod (IES, Germany) is the seismic section ECL 89011/A. The seismic was interpreted

using the sequence stratigraphic framework of MUNTINGH and BROWN (1993) and

BROWN et al. (1995) and well data from the Kudu boreholes 9A-2 and 9A-3. The

sedimentation history was unravelled using seismic interpretation, reconstruction of eroded

strata, paleobathymetric information and reconstructions from the Kudu wells (figures 6.19,

6.20, 6.21).

The postrift sedimentation was interpreted to start in the Barremian after the break-up

unconformity. Until the Aptian unconformity continual sedimentation took place. In the


Upper Cretaceous – especially in the Santonian - very high sedimentation rates were observed

which lead to the formation of the large growth fault structure in the vicinity of the Kudu gas

field. During the uppermost Cretaceous and lower Tertiary, erosion took place which removed

about 400 m of sediment. The estimation of the amount of eroded strata is presented in

chapter 6.2.3. Afterwards only minor sedimentation took place.

0 km 250 km

Dep

th (m

)

Event 1 - 8 (200 - 177.5 Mabp): Deposition of basement rocks and SDRS. This is the starting position for the deposition of the postrift sedimentary succession.

700080009000

10000

50006000

30004000

10002000

0

Temperature [°C]0 - 25

25 - 5050 - 7575 - 100

100 - 125

125 - 150150 - 175175 - 200200 - 225225 - 250

A Kudu 9A-2

0 km 250 km

Dep

th (m

)

0100020003000400050006000700080009000

10000Event 9 (117.5 - 115 Mabp): Deposition of Barremian sediments.

B Kudu 9A-2

0 km 250 km

Dep

th (m

)

0100020003000400050006000700080009000

10000Event 10 (115 - 114 Mabp): Deposition of the reservoir rock interval.

C Kudu 9A-2

Figure 6.19: Sedimentary history of the seismic section through the Kudu gas field offshore Namibia.


0 km 250 kmD

epth

(m)

700080009000

10000

50006000

30004000

10002000

0

Event 11 (114-112 Mabp): Deposition of the Barremian to Aptian source rock interval.

D Kudu 9A-2

0 km 250 km

Dep

th (m

)

0100020003000400050006000700080009000

10000

Event 12 (112 - 102 Mabp): Deposition of Aptian to Albian sediments

E Kudu 9A-2

0 km 250 km

Dep

th (m

)

0100020003000400050006000700080009000

10000Event 13 (102 - 96 Mabp): Deposition of the Cenomanian rocks.

F Kudu 9A-2

0 km 250 km

Dep

th (m

)

0100020003000400050006000700080009000

10000Events 14 - 18 (96 - 93 Mabp): Erosion

G Kudu 9A-2

Figure 6.19: Sedimentary history of the seismic section through the Kudu gas field offshore Namibia, continued.


0 km 250 kmD

epth

(m)

700080009000

10000

50006000

30004000

10002000

0

Event 19 (93 - 88 Mabp): Deposition of Turonian rocks.

H Kudu 9A-2

0 km 250 km

Dep

th (m

)

0100020003000400050006000700080009000

10000

103 °C134 °C 150 °C

125 °C 143 °C 139 °C140 °C 143 °C

Events 20 - 25 (88 - 84 Mabp): Deposition of Santonian sediments.

I Kudu 9A-2

0 km 250 km

Dep

th (m

)

700080009000

10000

50006000

30004000

10002000

0

126 °C 125 °C 158 °C 188 °C175 °C 172 °C 158 °C

182 °C175 °C

Event 26 (84 - 75 Mabp): Deposition of Campanian to Maastrichtian rocks.

J Kudu 9A-2

0 km 250 km

Dep

th (m

)

700080009000

10000

50006000

30004000

10002000

0

Events 27 - 29 (75 - 55 Mabp): Erosion

K Kudu 9A-2

Figure 6.19: Sedimentary history of the seismic section through the Kudu gas field offshore Namibia, continued.


0 km 250 kmD

epth

(m)

0100020003000400050006000700080009000

10000

122 °C 154 °C 181 °C 186 °C167 °C

151 °C 151 °C 143 °C

Events 30- 32 (55 - 30 Mabp): Deposition of Tertiary sediments. The temperature in the reservoir is indicated which is well above 180 °C in the vicinity of the Kudu well.

L Kudu 9A-2

Dep

th (m

)

0100020003000400050006000700080009000

10000

Events 33 - 36 (30 - 0 Mabp): Deposition of Tertiary and Quarternary sediments. State of the section today.

M GP 80GP 43GP 2

Figure 6.19: Sedimentary history of the seismic section through the Kudu gas field offshore Namibia, continued. Note that the red lines in image M indicate the position of grid points (GP) 2, 43 and 80.

130 120 110 100 90 80 70 60 50 40 30


25 - 5050 - 7575 - 100

100 - 125

125 - 150150 - 175175 - 200200 - 225225 - 250

149 [Mabp]

Burial History Overlay/Template Temperature

20 10 0

0[m]

2000

3000

4000

5000

6000

7000

8000

9431

A

Figure 6.20: Burial history for different positions in the modelled section. A: grid point 2. For the position of the grid points see figure 6.19 M.


130 120 110 100 90 80 70 60 50 40 30


25 - 5050 - 7575 - 100

100 - 125

125 - 150150 - 175175 - 200200 - 225225 - 250

149 [Mabp]


20 10 0

0[m]

2000

3000

4000

5000

6000

7000

8000

9431

B

130 120 110 100 90 80 70 60 50 40 30


25 - 5050 - 7575 - 100

100 - 125

125 - 150150 - 175175 - 200200 - 225225 - 250

149 [Mabp]


20 10 0

0[m]

2000

3000

4000

5000

6000

7000

8000

9431

C

Figure 6.21: Burial history for B: grid point 43 near the Kudu well and C: grid point 80. For the position of the grid point see figure 6.19 M.

6.2.10 Petroleum generation, migration and accumulation

The basin modelling software PetroMod contains various kerogen type specific kinetic data

sets for modelling petroleum generation. These datasets differ concerning the Arrhenius

factors and distribution of activation energies. Additionally not all data sets provide activation

energies for as well the conversion of kerogen to oil, kerogen to gas and for oil to gas.

Therefore, the kerogen type II specific kinetics of QUIGLEY et al. (1987) was used which

provides kinetic data for kerogen to oil, kerogen to gas and oil to gas conversion.

According to the basin model the hydrocarbon expulsion takes place between 105 and

84 Mabp depending on the thickness of the overburden at the respective location in the

section (figure 6.22).


0 km 250 kmD

epth

(m)

5000

6000

3000

4000

1000

2000

0

79 Mabp98 Mabp 99 Mabp

104 Mabp103 Mabp

85 Mabp85 Mabp

84 Mabp86 Mabp

86 Mabp

Kudu 9A-2

Figure 6.22: Expulsion time of petroleum from the source rock.

From the models it can be deduced that upward as well as downward expulsion of petroleum

from the Aptian to Barremian source rocks occurs (figure 6.23). In the case of downward

expulsion the shales act as source and seal simultaneously.

Dep

th (m

)

75 km 80 km 85 km

2600

2800

3000

Figure 6.23: Expulsion of petroleum from the source rock downward into the carrier rock.

In the carrier rocks the oil migrates buoyancy-driven upward and updip. Oil accumulates in

the recent Kudu reservoir filling it at 84 Mabp to approximately 20 % (figure 6.24). No gas is

present at this time in the reservoir.


0 km 250 kmD

epth

(m)

0

1000

2000

3000

4000

5000

6000

7000

0.04 0.250.170.24

0.210.04

0.04

Kudu 9A-2

Figure 6.24: Oil saturation of about 20 % in the reseroir at 84 Ma.

The maturity of the source rocks lies with 0.5 to 0.8 % Rr clearly within the oil window

during the Lower Cretaceous. Due to the high sedimentation rates in the Upper Cretaceous

fast burial of the section towards regions with higher temperatures take place (figure 6.25).

0

20

40

60

80

100

120

0 100 200 300

Temperature [°C]

Tim

e at

Bas

e [M

a]

0

20

40

60

80

100

120

0.1 1 10VR [% Rr]

Tim

e at

Bas

e [M

a]

0

20

40

60

80

100

120

0 0.5 1

Transformation Ratio

Tim

e at

Bas

e [M

a]

Figure 6.25: Temperature, vitrinite reflectance (VR) and transformation ratio evolution at gridpoints 2 (green), 43 (blue) and 80 (orange) with time. The positions of the gridpoints are indicated in figure 6.19 M.


The maturity of the source rocks increased due to this burial to 0.8 to 1.4 % Rr, whereby the

maturity in the central part of the section is higher (about 1.3 to 1.4 % Rr) than in the eastern

and western parts.

Gas can be found in the carrier rock after that burial but oil is also present. The temperature

increased in the deepest reservoir parts from 140 °C at 84 Mabp (figure 6.19 I) to above

180 °C at 75 Ma (figure 6.19 J). The temperature stayed high in the reservoir until today and

ranges between 140 and 180 °C. The transformation ratio of the source rock increased at

84 Ma from values not exceeding 0.4 to values above 0.9. During subsequent burial the

remaining oil vanishes almost completely from the carrier rock and the reservoir. Today

almost no oil is left in the reservoir and carrier rock which instead is filled to nearly 100 %

with gas. From these observations it is inferred that oil to gas cracking could have occurred in

the reservoir. This is supported by the presence of minor quantities of pyrobitumen in the

reservoir (DAVIES and VAN DER SPUY 1993). According to BLANC and CONNAN

(1994), a mean value of 150 °C as the upper limit for oil occurrence is often given. From the

distribution of the different types of hydrocarbons during the basin evolution the occurrence

of oil to gas cracking is also supported. After a loss of about 5 mass-% (mass-% refers to the

initial hydrocarbon mass in the section) of the sum of hydrocarbons (kerogen, gas, oil) present

in the section by the erosional events connected to the Aptian and Cenomanian

unconformities which lead to erosion of part of the source rock, additional reduction of the

total hydrocarbon content of the section by 23.2 % of the initial hydrocarbon occurs during

the burial of the source. In the kinetics by QUIGLEY et al. (1987) a reduction factor of 0.45 is

assumed for oil to gas cracking which means that 1.00 g of oil yields 0.45 g of gas during

cracking. Thus a loss of 23.2 % hydrocarbons from the section corresponds to about 19.0 %

gas produced by oil-cracking. According to the model, about 22.8 % of the initial

hydrocarbon content of the section today is still present as oil. This oil can be found dispersed

in the marginal carrier parts because the maturity of the source rock is lower in these parts due

to less overburden. In the reservoir of the Kudu gas field the pore space is filled with gas to

nearly 100 %. This gas equals about 15 % of the initial hydrocarbon content. About 22.6 % of

the initial hydrocarbon content flows as oil or gas out of the section, partly at the top of the

section (19.0 %), partly at the left side of the section (3.6 %).


6.2.11 Sensitivity analysis

A large portion of input data into the 2D model had to be approximated and estimated based

on a thin data base. Therefore, sensitivity analyses of the model are necessary. Those analyses

involve the variation of input parameters in order to evaluate their impact on modelling results

(YUKLER and MCELWEE 1976).

As petroleum generation depends strongly on temperature evolution in a basin, the heat flow

history is one of the most sensitive parameters in basin modelling. Increasing the heat flow

leads to earlier maturation of organic matter, earlier hydrocarbon generation and expulsion.

Regarding the time of trap formation the timing of hydrocarbon generation and expulsion can

be critical.

In this context, the thermal conductivity of the rocks is also important. Lowering the thermal

conductivity leads to increased temperatures and maturities in the sedimentary pile. Vice

versa, the increase in thermal conductivity of the rocks leads to a decrease in temperature and

thermal maturity (figure 6.26).

0 km 250 km

Dep

th (m

)

6000

00 km

Dep

th (m

)

5000

3000

4000

1000

2000

0

Kudu 9A-2


25 - 5050 - 7575 - 100

100 - 125

125 - 150150 - 175175 - 200200 - 225225 - 250

A

0 km 250 km

Dep

th (m

)

6000

00 km

Dep

th (m

)

5000

3000

4000

1000

2000

0

Kudu 9A-2


22 - 4444 - 6666 - 8888 - 110

220 - 242242 - 264264 - 286286 - 308308 - 330

110 - 132132 - 154154 - 176176 - 198198 - 220

330 - 352352 - 374374 - 396396 - 418418 - 440

7000

B

Figure 6.26: Comparison of the temperature field in models with different thermal conductivities. In model A a thermal conductivity of 2 [W/m/K], in model B a thermal conductivity of 1 [W/m/K] was chosen.


Because the model is calibrated with temperature sensitive vitrinite reflectance data, heat flow

values at given thermal properties of the rocks can not be changed arbitrarily. Thus changes in

thermal rock properties enforce variation in heat flow values and vice versa. Normally, the

thermal conductivity is chosen in accordance to the rock type present in the basin. The effect

of both the thermal rock parameters and the heat flow is predominantly on the timing of

petroleum formation. It is supposed that inaccuracies in estimating these parameters are only

of minor importance at the African margin because the trap hosting the Kudu gas was build

very early (sealed in the Aptian). The amount of hydrocarbons generated is mainly controlled

by the TOC content and the petroleum generation potential of the source section.

The petroleum generation kinetic also influences the timing of petroleum generation. The

higher the activation energies the later the hydrocarbon generation occurs. Additionally, the

distribution of activation energies exerts influence on the size of the depth (temperature)

interval in which the conversion of kerogen to hydrocarbons occurs. For comparison purpose

additional basin models were calculated with the kerogen type II specific kinetic data set of

TISSOT et al. (1987) and models using a bulk kinetic dataset for the sample 0011287 from

well DSDP 361. The bulk kinetic dataset provides only parameters for the conversion of

kerogen to petroleum with no further subdivision into gas and oil because no component

specific detection could be conducted during the pyrolysis experiments which were the basis

for this dataset. With the kinetic dataset from the DSDP 361 samples the conversion of

kerogen to oil was modelled having in mind that during the pyrolysis not only oil was

generated. Thus the comparison with models calculated with this kinetic dataset refers only to

the timing of petroleum formation in general neither regarding the type of petroleum (oil, gas)

nor its way of formation (kerogen or oil cracking). The conversion of kerogen to

hydrocarbons is completed in the models with the DSDP kinetic somewhat earlier than in the

models with the kinetic by TISSOT et al. (1987) and QUIGLEY et al. (1987). Again it is

supposed that the timing of the petroleum generation is of minor importance in the case of the

Kudu gas field because the trap formed during the source rock deposition. Another major

difference is between the models calculated with the kinetic dataset of QUIGLEY et al.

(1987) and TISSOT et al. (1987) regarding the gas generation. The kinetic of TISSOT et al.

(1987) does not provide data for the conversion reaction of kerogen to gas. Thus the only way

of gas formation is oil cracking. Thereby a very sharp transition from an oil-filled reservoir

(about 20 to 30 % oil) at 84 Mapb to a gas-filled reservoir (about 95 % gas) at 75 Ma can be

observed.

Discussion 105

7 Discussion

7.1 Geochemistry


Hydrocarbon gas was desorbed from near surface sediments sampled offshore Argentina and

offshore south-western Africa in order to deduce information on the petroleum system of the

southern South Atlantic from the molecular and isotopic parameters of the gas. From the

diagnostic plots (figures 6.9 and 6.10) it was deduced that a marine source rock is active at

both margins of the southern South Atlantic and that the maturity of this marine source rock is

significantly higher at the African (0.8 - 1.9 % Rr) than at the Argentine margin (0.5 –

1.2 % Rr, cf. chapter 6.1.1). This maturity difference coincides with the different maturities

found at rock samples from wells offshore Argentina and Namibia: In samples from the Cruz

del Sur well offshore Argentina a maturity of less than 0.7 % Rr was observed at depths of

more than 4000 m whereas Kudu 9A-2 rock samples from the same depth have maturities of

about 1.7 % Rr. This maturity difference mirrors the different heat flow and burial histories of

the south-west African and Argentine margin. Thus, it is supposed that equivalents of the

same source rock could be active at the African and at the Argentine margin.

A major argument against using surface geochemical investigations is the fact that the

mechanism transferring the hydrocarbon gas into near-surface sediments is not understood up

to now (KLUSMAN 1993; SCHUMACHER 2000). On the other hand a lot of examples show

that the application of surface geochemical techniques considerably improved the exploration

for hydrocarbons (HORVITZ 1972; KVENVOLDEN and FIELD 1981; PHILP and CRISP

1982; FABER and STAHL 1984; PRICE 1986; KLUSMAN 1993; MELLO et al. 1996;

FABER et al. 1997; SCHUMACHER 2000). Thus it is supposed that with careful sampling

and interpretation of data the investigation of sorbed hydrocarbons could provide useful

information for exploratory use although there are some interpretation difficulties: One

problem is the occurrence of microbial methane in the surface-near gas samples. Usually this

problem can be solved easily by considering the stable carbon isotope ratios. Methane with a

carbon isotope ratio lower than about -50 ‰ usually is considered to be of microbial origin

(FUEX 1977). Whereas some overlap in the δ13C with methane from low mature marine

source rocks exists (STAHL 1979), the presence of higher homologues like ethane, propane,

butane and pentane is a hint to thermogenic gas because these gases are formed only in traces

Discussion 106

microbially (BARKER 1999a). This is reflected in the ratio C1/(C1-C5) which is usually

greater than 0.99 in microbial gas (RICE and CLAYPOOL 1981). In special cases microbial

methane might be difficult to distinguish from thermogenic methane because sulphate

reducing bacteria outcompete methanogens for carbon substrates forcing them to use

substrates with unusual heavy stable carbon isotope ratios (OREMLAND and MARAIS 1983;

WHITICAR 1996a). The resulting methane would be unusually heavy concerning its stable

carbon signature (OREMLAND and MARAIS 1983). Therefore, at least one sample per

location was taken in the deepest part of the cores below the sulphate reduction zone if

possible. Another problem complicating the interpretation of surface geochemical data is

microbial oxidation of hydrocarbons or gas loss due to degassing of the samples (FABER and

STAHL 1983). Both processes may alter the molecular as well as the isotopic composition of

the hydrocarbons (FABER and STAHL 1983). It was found by FABER and STAHL (1984)

that storing the samples frozen or at least cooled could help minimising this effect. Oxidation

affects mostly methane which is oxidised preferentially by microbes (FABER 1987). The

microbes prefer the light methane so that the remaining methane will be much heavier

(FABER and STAHL 1983; OREMLAND and MARAIS 1983). The hydrocarbon yield also

has to be considered in interpreting the data. ABRAMS (1996) stated that samples with

hydrocarbon yields below 50 ppb do not provide reliable information on their origin. About

54 of the samples from offshore Argentina and south-western Africa meet this criterion. The

comparison of samples with more than 50 ppb hydrocarbon yield and those with a smaller

yield show no systematic difference. Thus, the samples with less than 50 ppb hydrocarbon

yield were also applied in the interpretation.

7.1.2 Geochemistry of the reservoir hydrocarbons of the Kudu gas field

7.1.2.1 Natural gas from the Kudu reservoir

From the stable carbon isotope signature and the molecular composition of the natural gas of

the Kudu gas field, a marine source rock with a maturity of about 1.1 to 1.4 % Rr is inferred

(figure 6.10). This finding coincides with the maturity of the Aptian source rocks at the time

of major petroleum production (between 84 and 75 Mabp) according to the 2D basin model

(cf. chapter 6.2.10). Therefore it is supposed that the natural gas mirrors the maturity of the

source rock during hydrocarbon expulsion. In interpreting source rock maturity from natural

gas features it has to be considered that maturity values deduced from the isotope signal of

Discussion 107

natural gas are not unambiguous: In interpreting the maturity of the source rock from the

natural gas of the Kudu gas it has to be considered that the plot of BERNER and FABER

(1996) accounts for instantaneous gas. Reservoir filling, however, can be associated with

long-time accumulation of hydrocarbons. The instantaneous gas generated at each time step

from the progressively maturating source would be heavier than the instantaneous gas

generated the time step earlier and heavier than the accumulated hydrocarbons (ROONEY et

al. 1995; CRAMER et al. 2001). The higher the percentage of non-reservoired early gas is the

heavier the remaining gas will be (PATIENCE 2003). Therefore leads a long accumulation

period for the natural gas in the reservoir to an underestimation of the maturity of the source

rock after the model of BERNER and FABER (1996). Another effect influencing the maturity

estimation is the alteration of the isotope signal of the natural gas by oil to gas cracking.

Because cracking is associated with a kinetic effect “lighter” hydrocarbons would be

generated by secondary cracking (CLAYTON 1991b). This would also lead to a lower than

the actual source rock maturity estimation from the diagnostic plots. The kinetic isotope effect

would be greatest for methane because of its lowest mole mass (SACKETT 1968). Thus the

data in figure 6.10a should plot above and in figure 6.10b below the maturation line. This is

actually the case but the amount of deviation from the maturation line is quite large and even

larger for ethane than for methane. Furthermore, it has to be considered that for the maturity

deduction from the stable carbon isotopic values of methane, ethane and propane the

maturation lines have to be calibrated to the stable carbon isotopic value of the source rock

(BERNER et al. 1995; BERNER and FABER 1996). In the present study the average δ13COM

(-25.5 ‰) for the samples from the Kudu wells was chosen for calibration of the type II

kerogen maturation line. Assuming that the portion of marine organic matter in the source

rock might increase basinward (BARKER 1983) the isotopic value further offshore could be

somewhat higher (less negative) because the δ13C of marine organic matter usually is less

negative than that of terrestrial organic matter (GALIMOV 1980). In this case using the

isotope values from the Kudu well would lead to an overestimation of the maturity deduced

from figure 6.10.

7.1.2.2 Condensate from the Kudu reservoir

The high content of aromatic compounds in the condensate points to a mixed organic source

(figures 6.11 and 6.12). The maturity of the source rock deduced from the heptane value of

the condensate is about 1.0 % Rr (figure 6.13) which is considerably lower than the maturity

Discussion 108

derived from δ13C values of natural gas components and measured on the rocks from the

Kudu wells. According to the plots of the Kudu natural gas parameters after SCHOELL

(1983, figure 6.9) the natural gas is not associated with oil or condensate. This contradicts the

presence of the condensate in the Kudu reservoir. Thus it is supposed that the condensate

might have been generated in place from the more proximal and thus more terrestrial source

rock portion in contrast to the gas which is inferred to stem from a more basinward portion of

the source rock. Some lateral differences in the composition of the source rock could be

inferred from the fact that the ancent Orange River delta provides the possibility of

interfingering of rocks with marine or terrestrial organic matter.

7.2 Basin modelling study

7.2.1 Seismic interpretation

The basin modelling study for the Kudu gas field is based on a reflection seismic line which

was interpreted and dated according to published sequence stratigraphic data (MUNTINGH

and BROWN 1993; BROWN et al. 1995;. Due to the fact that only one single seismic section

was available no comparison between adjacent sections could be made. Especially in the

interpretation of the complex sedimentary structures in the Upper Cretaceous a great deal of

uncertainty is caused by the lack of additional seismic data. Especially the interpretation of

complex sedimentary structures require seismic sections along and across strike in order to

develop a spatial image of the structures. Especially oblique cutting angles through three-

dimensional structures of the two-dimensional seismic section complicate the interpretation..

The consistency of the interpretation could not be verified by intersecting seismic lines.

7.2.2 Estimation of the thickness of eroded strata

The estimation of the thickness of strata eroded at the Base Tertiary unconformity at the Kudu

well 9A-2 yields quite similar values (about 400 m) for the different methods used (see

chapter 6.2.3). This value is in good accordance with the thicknesses inferred by

MCMILLAN (1990). According to BOLLI et al. (1975) and BOLLI et al. (1978a) a similar

thickness of sediments is missing in the DSDP 361 well offshore South Africa. More difficult

and less constraint is the estimation of the thicknesses of strata missing in the section east and

west of the well where no further well control was available. Changes in the thickness of the

Discussion 109

eroded strata perpendicular to the margin were estimated according to the relief of the

underlying horizon. This method implies inaccuracies in reconstructing the thickness of

eroded strata which could influence the timing of the maturation of organic matter. The

thickness of eroded strata missing at the Turonian unconformity which can clearly be seen in

the seismic record was difficult to estimate because no vitrinite reflectance and Tmax data were

available for this section. It is inferred that the Turonian is a condensed section which implies

that the amount of sediments missing should be small (MCMILLAN 1990).

7.2.3 Source rocks of the Kudu gas

The Barremian to Aptian rocks drilled in the Kudu wells are supposed to be the source rocks

for the Kudu natural gas in spite of the comparable low TOC content of 2.3 % at most, the

low hydrogen index values and the portion of terrestrial organic matter present (DAVIES and

VAN DER SPUY 1990; DAVIES and VAN DER SPUY 1993; BRAY et al. 1998;

JUNGSLAGER 1998). Due to the maturity of about 1.7 % Rr of the rocks sampled in the

Kudu wells 9A-2 and 9A-3 part of the initial organic matter was already converted to

petroleum (DALY 1987). Although the natural gas from the Kudu reservoir shows a marine

signature the origin of the gas from these shales is a reasonable assumption because the

terrestrial fraction in a proximal position is explained by sediment input from the Orange

River which drained the Namibian interior since the Lower Cretaceous (DINGLE and

SCRUTTON 1974; BARTON et al. 1993; DINGLE 1993; MUNTINGH and BROWN 1993;

BROWN et al. 1995). The source quality of the rocks may improve basinward as shown by

the Aptian rocks from the DSDP 361 well offshore Cape Town which contain good quality

type II kerogen (JUNGSLAGER 1999). Such source rocks are supposed to be widespread in

the south-western African offshore (BRAY et al. 1998). Questionably about this model is the

fact that the Aptian and Barremian rocks act as source and seal simultaneously which implies

that during hc expulsion a change from a water wet to an oil wet system occurs. The capillary

pressure necessary for re-entering of petroleum into the rock being much higher for water wet

systems which might reduce the seal quality of the oil wet rocks. Nevertheless, examples of

rocks acting as source and seal simultaneously are known (NORTH 1985).

Another possible source rock occurring in the south-western African offshore is of Paleozoic

age. High petroleum potential has been proven for lacustrine shales of the Irati shale and

Whitehill shale (SILVA and CORNFORD 1985; VISSER 1992; PORADA et al. 1994). For

instance, live-oil seeps have been found onshore Namibia which are geochemically linked to

Discussion 110

the Whitehill formation (BRAY et al. 1998). Furthermore, Neocomian source rocks from the

synrift phase of the opening of the South Atlantic are proven in the Hauterivian A-J1

halfgraben offshore South Africa ( JUNGSLAGER 1999; BEN-AVRAHAM et al. 2002).

From the seismic interpretation sedimentary layers intercalated in the SDRS can not be ruled

out (SCHÜMANN 2002) which might be capable of petroleum generation but those rocks

would feature even higher maturities than the rocks from the Kudu wells because they are

buried more deeply and were exposed to high temperatures due to the vicinity to the SDRS

forming volcanism. This is in disagreement with the maturity derived from the natural gas. A

source rock from the synrift phase is also ruled out because no halfgrabens underlying the

reservoir could be seen in the seismic section through the Kudu gas which would be able to

supply hydrocarbons to the reservoir. Downdip migration of petroleum from grabens further

coastwards can also be ruled out because the buoyancy of petroleum controls secondary

migration which always leads to upwardly migration.

7.2.4 Petroleum generation, migration and accumulation

For the basin modelling study of the Kudu gas field offshore Namibia the kinetic data set of

QUIGLEY et al. (1987) was chosen because it provided data for the conversion of kerogen to

oil, to gas and of oil to gas. The kinetic calculated from bulk pyrolysis experiments on

samples from DSDP 361 (see chapter 6.1.2.6) well could only provide kinetic data for the

conversion of kerogen to oil, the kinetic data set of TISSOT et al. (1987) lacks the parameters

for kerogen to gas conversion. These data sets were used for a rough comparison of the timing

of oil generation and expulsion. From the results it is obvious that differences in the timing of

petroleum generation and expulsion exist between the different kinetics (figure 7.1). Because

the timing of trap formation is favourable at the Namibian continental margin the lack of a

sophisticated specific kinetic data set of the Kudu source rock is thought to be of minor

importance to the modelling results.

The results of a basin modelling study depend to a major extend on the quality of the input

parameters. In the present study only little data was available thus the results have to be

considered as qualitatively (WELTE and YUKLER 1981). Therefore, no absolute

hydrocarbon quantities can be derived from the present study. Besides, the design of 2D

models of petroleum generation, migration and accumulation implies that the estimation of

absolute hydrocarbon quantities is difficult because only petroleum migration in the image

plane can be considered.

Discussion 111

0 km 212 km

Dep

th (m

)

5000

3000

4000

1000

2000

0

Kudu 9A-2

80 Ma103 Ma

104 Ma

84 Ma

85 Ma

86 Ma 96 Ma

0 km 212 km

Dep

th (m

)

5000

3000

4000

1000

2000

0

Kudu 9A-2

80 Ma103 Ma

104 Ma

84 Ma

85 Ma

86 Ma 96 Ma

Dep

th (m

)

5000

3000

4000

1000

2000

0

Kudu 9A-2

87 Ma 102 Ma104 Ma

88 Ma

85 Ma 96 Ma 99 Ma

0 km 212 km

Dep

th (m

)

5000

3000

4000

1000

2000

0

Kudu 9A-2

88 Ma 105 Ma106 Ma

103 Ma

85 Ma100 Ma

6000

A

B

C

212 km0 km

Figure 7.1: Comparison of the expulsion time calculated with kinetic datasets by QUIGLEY et al. 1987 (A), TISSOT et al. 1987 (B) and according to the results of the bulk kinetic of DSDP rock samples (this study, C).

7.2.5 The petroleum potential of the southern South Atlantic

In the Kudu gas field offshore Namibia and in the Ibhubesi gas field offshore South Africa

natural gas sourced from Barremian to Aptian source rocks was discovered. Equivalents of

this source rock are widespread at the southwest African continental margin (BROAD and

MILLS 1993; JUNGSLAGER 1999). According to the surface geochemical prospecting a

marine source rock is present at both continental margins of the southern South Atlantic. On

the basis of the present study it is assumed that further petroleum might be present in

Discussion 112

stratigraphic traps in the feather edge of the SDRS along the continental margin of south-

western Africa. Because of the high heat flow at the African margin and because of the

sediment thickness in the Orange Basin the probability of gas discoveries is greater than that

for oil discoveries. Lower maturities of these rocks and thus a higher probability for oil are

supposed for the Walvis and Luderitz Basin because lower sedimentary thicknesses are

encountered here. According to the surface geochemical prospecting, however, the likelihood

for gas is higher even in the Luderitz and Walvis Basin with maturities derived from the

surface geochemical prospecting above 1.2 % Rr.

The natural gas of the Ibhubesi field is thought to have migrated mainly via faults from the

source shales into the trap in Albian fluvial channel-fill sandstones (BEN-AVRAHAM et al.

2002). This discovery supports the source quality of the Aptian shales and points out the

possibility of reservoirs in other than the SDRS setting. For the Kudu gas field this stands for

the possibility of the portion of petroleum expelled upward from the source rocks trapped in

channel-fill sediments.

Summary

113

8 Summary

The present study deals with the petroleum potential of the continental margins of the

southern South Atlantic. Main emphasis is put on the Namibian continental margin, especially

on the Kudu gas field, which is one of only two commercial hydrocarbon discoveries in the

south-western African offshore. For evaluating the petroleum potential of the south-western

African margin source rock samples from offshore Namibia, South Africa and Argentina and

onshore Brazil and Namibia were investigated. Additionally near-surface sediments were

sampled offshore southwestern Africa and Argentina for desorbtion of gaseous hydrocarbons

for surface exploration purpose. The δ13C values of methane and ethane desorbed from these

sediments point to a marine source rock with a distinctly higher maturity at the African than at

the South American continental margin. In general the maturity of rocks at the Argentine

margin is lower compared to the African continental margin hinting on a distinctly lower heat

flow at the Argentine continental margin. Thus it is possible that the hydrocarbon gas found in

near-surface sediments at both continental margins originates from equivalents of the same

marine source rock which is in the gas window at the African and in the oil window at the

Argentine margin.

The Kudu gas field was investigated using 2D basin modelling techniques with the modelling

software PetroMod (IES, Germany). The Kudu reservoir contains dry gas and little quantities

of condensate and was encountered in predominantely aeolian sandstones in the upper part of

a Late Jurassic to Lower Cretaceous seaward dipping reflector sequence. From the 2D basin

modelling study of the petroleum generation, migration and accumulation it is concluded that

the gas in the Kudu Field is sourced from Aptian to Barremian shales which overly the

reservoir and carrier rock. The oil expulsion from the source rocks in the Kudu field started in

the Lower Cretaceous but the main parts of the source rocks expelled petroleum in the Upper

Cretaceous. Partly the petroleum was expelled downwards into the underlying sandstones and

moved buoyancy-driven upwards coastward into the stratigraphic pinch-out trap. Due to high

sedimentation rates and subsequent deeper burial in the Upper Cretaceous the reservoir

temperatures increased sufficiently to allow for oil to gas cracking. From the stable carbon

isotopic signature of the natural gas found in the Kudu Field a marine source rock is inferred.

Because the Aptian and Barremian shales contain a considerable amount of terrestrial organic

matter in a proximal position due to the sediment input from the Orange River updip

migration of hydrocarbons from a more basinward position is inferred. The maturity deduced

from the stable carbon isotope composition of methane in the Kudu natural gas is about

Summary

114

1.4 % Rr which is about 0.3 % Rr less than the present day maturity of the Aptian shales

drilled in the Kudu wells but approximates the modelled maturity of the Aptian shales during

the period of oil expulsion.

In the Kudu gas field offshore Namibia and in the Ibhubesi gas field offshore South Africa

natural gas sourced from Barremian to Aptian source rocks was discovered. Equivalents of

this source rock are widespread at the southwest African continental margin. Further

petroleum accumulations might be stratigraphically trapped in the feather edge of the SDRS

along the continental margin of south-western Africa. Because of the high heat flow at the

African margin and because of the sediment thickness in the Orange Basin the probability of

gas discoveries is greater than that for oil discoveries. Lower maturities of these rocks are

supposed for the Walvis and Luderitz Basin because lower sedimentary thicknesses are

encountered thus enhancing the probability of oil discoveries in these areas. According to the

surface geochemical prospecting, however, the likelihood for gas is higher even in the

Luderitz and Walvis Basin with maturities derived from the surface geochemical prospecting

above 1.2 % Rr.

The natural gas of the Ibhubesi field is thought to have migrated mainly via faults from the

source shales into the trap in Albian fluvial channel-fill sandstones. This discovery supports

the source quality of the Aptian shales and points out the possibility of reservoirs in other than

the SDRS setting. For the Kudu gas field this stands for the possibility of the portion of

petroleum expelled upward from the source rocks as can be seen in the model of the Kudu gas

field being trapped in channel-fill sediments.

References 115

9 References

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Appendix A: Geochemistry 142

Appendix A: Geochemistry

Surface geochemical prospecting

Table A.1: Compilation of the measurements on the gaseous hydrocarbons desorbed from near-surface sediments offshore southwestern Africa and Argentina. Results given in HC-%. Sample

Lab No. Methane [HC-%]

Ethane [HC-%]

Ethene [HC-%]

Propane [HC-%]

Propene [HC-%]

i-Butane [HC-%]

n-Butane [HC-%]

i-Pentane [HC-%]

n-Pentane [HC-%]

Malvinas 1 0112810 97.81 1.76 0.00 0.43 0.00 0.00 0.00 0.00 0.00 Malvinas 3 0112812 96.12 2.30 0.41 0.69 0.00 0.22 0.26 0.00 0.00 Malvinas 4 0112813 90.65 4.59 0.91 1.91 0.50 0.76 0.69 0.00 0.00 Malvinas 5a 0112814 92.14 4.15 2.29 0.00 0.00 0.74 0.69 0.00 0.00 Malvinas 6a 0112815 94.02 3.81 0.43 1.09 0.00 0.34 0.31 0.00 0.00 Malvinas 7a 0112816 95.33 3.21 0.00 0.87 0.00 0.31 0.28 0.00 0.00 Malvinas 8 0112817 90.88 5.43 0.45 1.78 0.13 0.75 0.57 0.00 0.00 Malvinas 9 0112818 93.89 4.01 0.22 1.16 0.00 0.36 0.36 0.00 0.00 Malvinas 10 0112819 94.76 3.59 1.20 0.00 0.00 0.21 0.24 0.00 0.00 Malvinas 11 0112920 92.40 4.91 0.25 1.56 0.00 0.47 0.42 0.00 0.00 Malvinas 12 0112821 92.98 4.40 0.31 1.35 0.11 0.43 0.41 0.00 0.00 Malvinas 13 0112822 94.84 3.25 0.00 1.07 0.00 0.41 0.43 0.00 0.00 Malvinas 14 0112823 91.20 5.26 0.22 1.90 0.08 0.73 0.61 0.00 0.00 Malvinas 15 0112824 89.85 6.06 0.30 2.17 0.08 0.83 0.72 0.00 0.00 Malvinas 16 0112825 90.96 5.21 0.50 1.74 0.12 0.78 0.67 0.00 0.00 Malvinas 17 0112826 91.10 5.42 0.24 1.92 0.00 0.70 0.63 0.00 0.00 Malvinas 18 0112827 90.40 5.59 0.51 1.92 0.00 0.85 0.72 0.00 0.00 Malvinas 19 0112828 91.50 4.91 0.42 1.79 0.09 0.69 0.60 0.00 0.00 Malvinas 20 0112829 93.30 4.20 0.27 1.31 0.09 0.44 0.39 0.00 0.00 Malvinas 21 0112830 92.42 4.45 0.56 1.53 0.11 0.47 0.46 0.00 0.00 Malvinas 22 0112831 91.95 4.95 0.38 1.62 0.00 0.58 0.51 0.00 0.00 Malvinas 23 0112832 93.59 4.12 0.37 1.15 0.07 0.35 0.34 0.00 0.00 Malvinas 24 0112833 95.03 3.37 0.00 0.95 0.00 0.27 0.38 0.00 0.00 Malvinas 25 0112834 95.07 3.11 0.37 0.85 0.00 0.27 0.33 0.00 0.00 Malvinas 26 0112835 92.85 4.00 0.74 1.23 0.33 0.45 0.40 0.00 0.00 Malvinas 27 0112836 93.12 4.22 0.44 1.30 0.13 0.40 0.39 0.00 0.00 Malvinas 28 0112837 95.18 2.92 0.00 0.95 0.00 0.47 0.47 0.00 0.00 Malvinas 29 0112838 93.55 4.09 0.41 1.12 0.15 0.35 0.33 0.00 0.00 Malvinas 30 0112839 93.81 3.55 0.00 1.38 0.00 0.62 0.64 0.00 0.00 Malvinas 31 0112840 94.40 3.74 0.26 0.93 0.12 0.29 0.26 0.00 0.00 Malvinas 32 0112841 93.95 3.87 0.21 1.11 0.00 0.46 0.39 0.00 0.00 Malvinas 33 0112842 93.45 4.23 0.25 1.21 0.07 0.42 0.37 0.00 0.00 Malvinas 34 0112843 94.41 3.67 0.35 0.92 0.00 0.34 0.30 0.00 0.00 Malvinas 35 0112844 93.40 4.34 0.29 1.21 0.00 0.36 0.39 0.00 0.00 Malvinas 36 0112845 96.00 2.40 0.21 0.80 0.00 0.31 0.28 0.00 0.00 Malvinas 37 0112846 94.31 3.64 0.00 1.10 0.00 0.48 0.47 0.00 0.00 Malvinas 38 0112847 93.54 4.17 0.54 1.14 0.00 0.33 0.28 0.00 0.00 Malvinas 39 0112848 91.47 4.78 0.00 2.09 0.00 0.89 0.77 0.00 0.00 Malvinas 40 0112849 95.18 2.81 0.62 0.79 0.00 0.34 0.27 0.00 0.00 Malvinas 41 0112850 93.19 4.16 0.54 1.14 0.26 0.40 0.31 0.00 0.00 Malvinas 42 0112851 90.11 5.96 0.26 2.16 0.00 0.81 0.71 0.00 0.00 Malvinas 43 0112852 90.67 5.51 0.50 1.91 0.16 0.65 0.61 0.00 0.00 Malvinas 44 0112853 93.95 3.72 0.30 1.20 0.00 0.38 0.45 0.00 0.00 Malvinas 45, <63 µm

0112854a

92.84 4.74 0.40 1.30 0.00 0.42 0.30 0.00 0.00

Malvinas 45, >63 µm

0112854b

94.29 4.01 0.00 0.97 0.00 0.39 0.34 0.00 0.00

Malvinas 46 0112855 89.53 6.05 0.77 2.09 0.21 0.76 0.60 0.00 0.00


Sample


Ethane [HC-%]

Ethene [HC-%]

Propane [HC-%]

Propene [HC-%]

i-Butane [HC-%]

n-Butane [HC-%]

i-Pentane [HC-%]

n-Pentane [HC-%]

Malvinas 46 New

0112856 94.97 3.30 0.00 0.95 0.00 0.45 0.33 0.00 0.00

Malvinas 47 0112857 94.00 3.73 0.49 1.06 0.11 0.31 0.30 0.00 0.00 Malvinas 47 New

0112858 92.04 4.95 0.85 1.38 0.00 0.45 0.33 0.00 0.00

Malvinas 49 0112859 92.04 4.95 0.85 1.38 0.00 0.45 0.33 0.00 0.00 Malvinas 50 0112860 94.30 3.22 0.00 1.23 0.00 0.71 0.54 0.00 0.00 Malvinas 51 0112861 93.24 4.20 0.30 1.40 0.00 0.44 0.42 0.00 0.00 Malvinas 52 0112862 93.93 3.64 0.35 1.16 0.12 0.40 0.39 0.00 0.00 Malvinas 53 0112863 95.59 2.75 0.41 0.76 0.00 0.25 0.24 0.00 0.00 Malvinas 54 0112864 94.41 3.92 0.00 1.00 0.00 0.33 0.33 0.00 0.00 Malvinas 55 0112865 93.98 3.35 0.26 1.36 0.00 0.55 0.49 0.00 0.00 Malvinas 56 0112866 98.17 1.41 0.00 0.42 0.00 0.00 0.00 0.00 0.00 Malvinas 58 0112867 97.45 1.92 0.00 0.63 0.00 0.00 0.00 0.00 0.00 Malvinas 59 0112868 95.03 3.26 0.41 0.81 0.00 0.22 0.27 0.00 0.00 Malvinas 60 0112869 94.21 3.52 0.53 0.96 0.00 0.34 0.44 0.00 0.00 Malvinas 61 0112870 94.77 3.11 0.00 1.24 0.00 0.49 0.40 0.00 0.00 BGR98-1 0112808 95.14 2.49 1.48 0.89 0.00 0.00 0.00 0.00 0.00 BGR98-2 0112801 94.61 3.25 0.74 0.72 0.25 0.18 0.25 0.00 0.00 BGR98-3 0112802 94.94 2.55 1.52 0.31 0.69 0.00 0.00 0.00 0.00 BGR98-4 0112803 94.18 4.69 1.13 0.00 0.00 0.00 0.00 0.00 0.00 BGR98-5 0112804 89.29 3.31 5.48 0.00 1.92 0.00 0.00 0.00 0.00 BGR98-6 0112805 95.12 2.91 0.82 0.61 0.25 0.16 0.13 0.00 0.00 BGR98-7 0107579 93.61 3.48 0.56 0.97 0.00 0.40 0.47 0.21 0.29 BGR98-8 0112806 92.83 4.01 1.03 1.13 0.33 0.35 0.31 0.00 0.00 BGR98-9 0112809 94.61 2.76 0.93 0.79 0.33 0.26 0.32 0.00 0.00 BGR98-10 0112807 96.59 2.61 0.00 0.79 0.00 0.00 0.00 0.00 0.00 Colorado 1 0107550 61.08 23.82 1.95 8.89 0.00 1.76 2.50 0.00 0.00 Colorado 2 0107551 87.74 7.15 2.46 1.59 0.00 0.55 0.51 0.00 0.00 Colorado 3 0107552 95.17 3.25 1.04 0.54 0.00 0.00 0.00 0.00 0.00 Colorado 4 0107553 91.60 4.22 1.67 1.55 0.00 0.31 0.44 0.13 0.07 Colorado 5 0107554 94.09 3.02 1.17 0.84 0.00 0.29 0.34 0.13 0.13 Colorado 6 0107555 65.46 5.00 25.74 2.80 0.00 0.62 0.38 0.00 0.00 Colorado 8 0107556 96.29 2.60 0.00 0.53 0.00 0.21 0.17 0.15 0.06 Colorado 9 0107557 93.82 3.56 0.79 0.96 0.00 0.29 0.30 0.18 0.11 Colorado 10 0107558 94.08 3.36 0.76 1.14 0.00 0.24 0.44 0.00 0.00 Colorado 11 0107559 95.37 3.00 0.44 0.58 0.00 0.24 0.23 0.13 0.00 Colorado 12 0107560 95.23 2.92 0.53 0.65 0.00 0.23 0.23 0.12 0.09 Colorado 13 0107561 96.20 2.29 0.31 0.52 0.00 0.23 0.28 0.10 0.07 Colorado 14 0107562 96.64 2.01 0.32 0.54 0.00 0.14 0.15 0.12 0.10 Colorado 17 0107563 85.77 3.46 6.99 0.00 0.00 0.26 3.52 0.00 0.00 Colorado 18 0107564 94.55 3.42 0.00 0.97 0.00 0.44 0.45 0.00 0.17 Colorado 20 0107565 94.80 3.57 0.39 0.58 0.00 0.15 0.31 0.14 0.06 Colorado 21 0107566 91.57 5.19 2.52 0.00 0.00 0.26 0.37 0.09 0.00 Colorado 22 0107567 91.73 4.65 1.74 1.32 0.00 0.19 0.38 0.00 0.00 Colorado 23 0107568 95.91 2.66 0.39 0.58 0.00 0.18 0.18 0.11 0.00 Colorado 24 0107569 94.79 3.18 0.72 0.69 0.00 0.23 0.15 0.24 0.00 Colorado 25, <63µm

0107570a

92.75 4.29 0.00 1.62 0.00 0.40 0.50 0.30 0.15

Colorado 25, >63µm

0107570b

92.92 4.39 0.27 1.31 0.00 0.42 0.38 0.21 0.11

Colorado 26 0107571 95.97 2.56 0.40 0.54 0.00 0.24 0.18 0.08 0.04 Colorado 27 0107572 93.58 3.77 0.86 1.06 0.00 0.26 0.26 0.13 0.08 Colorado 28 0107573 94.57 3.45 0.62 0.72 0.00 0.18 0.19 0.13 0.14 Colorado 29 0107574 95.23 2.81 0.65 0.87 0.00 0.19 0.17 0.07 0.00 Colorado 30 0107575 95.06 2.96 0.40 0.78 0.00 0.32 0.31 0.12 0.05 Colorado S-1 0107576 94.62 3.00 0.89 0.72 0.00 0.24 0.24 0.07 0.22 Colorado S-2 0107577 93.27 3.46 0.48 1.16 0.00 0.47 0.58 0.36 0.21 Colorado S-3 0107578 94.02 3.34 1.06 0.86 0.00 0.32 0.19 0.22 0.00


Sample


Ethane [HC-%]

Ethene [HC-%]

Propane [HC-%]

Propene [HC-%]

i-Butane [HC-%]

n-Butane [HC-%]

i-Pentane [HC-%]

n-Pentane [HC-%]

GeoB 6308-4 0010905 GeoB 6308-4 0010906 99.04 0.54 0.19 0.20 0.00 0.00 0.00 0.04 0.00 GeoB 6330-4 0010907 90.43 4.68 1.28 1.50 0.00 0.34 0.34 0.37 1.05 GeoB 6330-4 0010908 95.42 3.64 0.00 0.94 0.00 0.00 0.00 0.00 0.00 GeoB 2704-2 0010909 91.83 4.03 1.69 1.21 0.62 0.18 0.25 0.19 0.00 GeoB 2704-2 0010910 91.43 3.72 1.74 1.23 0.70 0.27 0.37 0.23 0.30 GeoB 2707-5 0010911 92.74 4.06 1.31 1.27 0.17 0.13 0.16 0.17 0.00 GeoB 2707-5 0010912 94.63 4.00 0.00 1.37 0.00 0.00 0.00 0.00 0.00 GeoB 2714-1 0010913 91.70 4.31 2.29 1.70 0.00 0.00 0.00 0.00 0.00 GeoB 2714-1 0010914 93.77 3.53 1.89 0.82 0.00 0.00 0.00 0.00 0.00 GeoB 2716-2 0010915 93.33 3.06 1.20 0.86 0.00 0.35 0.45 0.00 0.76 GeoB 2716-2 0010916 93.07 2.83 1.13 1.78 0.00 0.00 0.00 0.00 0.00 GeoB 2722-4 0010917 90.47 5.89 0.85 1.54 0.00 0.15 0.56 0.27 0.28 GeoB 2722-4 0010918 64.44 15.60 2.23 6.53 0.00 2.16 2.67 4.54 1.83 GeoB 2724-4 0010919 93.09 3.29 1.85 0.95 0.00 0.39 0.43 0.00 0.00 GeoB 2724-4 0010920 96.77 1.62 0.83 0.78 0.00 0.00 0.00 0.00 0.00

MD962080 (Aghulas), 0.31-0.83 m

0018645 68.07 16.06 0.61 6.10 0.00 2.79 1.83 3.95 0.60

MD962080 (Aghulas), 21.31-21.73 m

0018646

MD962083 (Saldanha), 0.30-0.72 m

0018647 65.15 16.14 1.27 5.09 0.00 3.84 2.05 5.77 0.69

MD962083 (Saldanha), 26.30-26.72 m

0018648 64.31 16.89 0.00 6.36 0.00 4.27 1.70 6.24 0.21

MD962084 (Olifants r.), 0.32-0.72 m

0018649 72.93 13.22 0.00 5.50 0.00 3.21 1.76 2.71 0.67

MD962084 (Olifants r.),34.61-35.13 m

0018650 66.30 16.02 0.00 8.68 0.00 2.10 1.81 4.09 1.01

MD962085 (Orange r.), 34.99-35.37 m

0018651 66.49 17.16 0.45 6.67 0.00 3.14 1.73 3.98 0.37

MD962085G(Orange r.), 0.30-0.72 m

0018652 74.90 13.23 3.70 2.10 0.00 1.50 1.29 1.91 1.36

MD962099 (Orange r.), 0.30-0.72 m

0018653 74.72 15.88 0.00 4.66 0.00 0.00 0.00 4.75 0.00

MD962099 (Orange r.), 34.60-35.02 m

0018654 62.39 17.23 0.21 7.19 0.30 4.23 2.02 6.15 0.28

MD962087 (Lüderitz), 39.19-39.63 m

0018655 97.23 1.06 0.37 0.74 0.00 0.18 0.16 0.26 0.00

MD962087G(Lüderitz), 0.39-1.00 m

0018656 77.59 8.29 14.12 0.00 0.00 0.00 0.00 0.00 0.00

MD962098 (Lüderitz), 0.39-0.80 m

0018657 63.70 20.52 12.14 3.64 0.00 0.00 0.00 0.00 0.00

MD962098 (Lüderitz), 31.79-32.10 m

0018658 68.63 11.40 0.76 14.26 0.73 0.96 1.27 1.12 0.00

MD962086 0018659 74.31 10.59 2.79 8.06 0.00 0.98 1.51 1.38 0.00


Sample


Ethane [HC-%]

Ethene [HC-%]

Propane [HC-%]

Propene [HC-%]

i-Butane [HC-%]

n-Butane [HC-%]

i-Pentane [HC-%]

n-Pentane [HC-%]

(Lüderitz), 35.59-36.00 m MD962086G (Lüderitz), 0.29-0.70 m

0018660 69.24 8.97 11.70 5.64 0.00 1.53 2.93 0.00 0.00

MD962088G (Walvis B.), 0.30-0.72 m

0018661 100.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

MD962088 (Walvis B.), 1.70-2.12 m

0018662 100.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

MD962096G (Walvis B.), 0.30-0.72 m

0018663 100.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

MD962096 (Walvis B.), 28.70-29.12 m

0018664 68.28 12.87 0.00 7.40 0.00 3.52 1.76 3.47 0.00

MD962095 (Walvis R.), 23.70-24.12 m

0018665 80.12 7.95 0.00 5.85 0.00 1.81 1.36 2.01 0.00

MD962095G (Walvis R.), 0.30-0.72 m

0018666 77.30 13.28 7.82 1.60 0.00 0.00 0.00 0.00 0.00

Table A.2: Compilation of the measurements on the gaseous hydrocarbons desorbed from near-surface sediments offshore southwestern Africa and Argentina. Results given in ppb. Sample

Lab No. Methane [ppb]

Ethane [ppb]

Ethene [ppb]

Propane [ppb]

Propene [ppb]

i-Butane [ppb]

n-Butane[ppb]

i-Pentane[ppb]

n-Pentane[ppb]

Malvinas 1 0112810 43.52 1.47 0.00 0.52 0.00 0.00 0.00 0.00 0.00 Malvinas 3 0112812 26.76 1.20 0.20 0.53 0.00 0.22 0.26 0.00 0.00 Malvinas 4 0112813 16.45 1.56 0.29 0.95 0.24 0.50 0.45 0.00 0.00 Malvinas 5a 0112814 19.38 1.64 0.84 0.00 0.00 0.56 0.53 0.00 0.00 Malvinas 6a 0112815 42.74 3.25 0.34 1.37 0.00 0.55 0.50 0.00 0.00 Malvinas 7a 0112816 51.71 3.27 0.00 1.29 0.00 0.61 0.55 0.00 0.00 Malvinas 8 0112817 76.62 8.59 0.67 4.14 0.28 2.29 1.75 0.00 0.00 Malvinas 9 0112818 52.82 4.23 0.22 1.79 0.00 0.73 0.74 0.00 0.00 Malvinas 10 0112819 95.51 6.79 2.11 0.00 0.00 0.77 0.87 0.00 0.00 Malvinas 11 0112920 59.43 5.92 0.28 2.76 0.00 1.09 0.97 0.00 0.00 Malvinas 12 0112821 75.18 6.67 0.45 3.01 0.23 1.27 1.20 0.00 0.00 Malvinas 13 0112822 35.99 2.31 0.00 1.11 0.00 0.56 0.59 0.00 0.00 Malvinas 14 0112823 76.71 8.30 0.33 4.38 0.17 2.22 1.87 0.00 0.00 Malvinas 15 0112824 91.17 11.52 0.53 6.05 0.20 3.06 2.65 0.00 0.00 Malvinas 16 0112825 53.74 5.77 0.52 2.83 0.19 1.67 1.44 0.00 0.00 Malvinas 17 0112826 73.82 8.23 0.33 4.28 0.00 2.06 1.84 0.00 0.00 Malvinas 18 0112827 56.80 6.58 0.56 3.32 0.00 1.94 1.65 0.00 0.00 Malvinas 19 0112828 66.53 6.70 0.54 3.57 0.17 1.82 1.58 0.00 0.00 Malvinas 20 0112829 74.15 6.26 0.38 2.87 0.18 1.25 1.13 0.00 0.00 Malvinas 21 0112830 39.07 3.52 0.41 1.78 0.12 0.72 0.71 0.00 0.00 Malvinas 22 0112831 39.17 3.96 0.29 1.90 0.00 0.89 0.79 0.00 0.00 Malvinas 23 0112832 60.20 4.97 0.42 2.04 0.12 0.82 0.79 0.00 0.00 Malvinas 24 0112833 29.05 1.93 0.00 0.80 0.00 0.30 0.42 0.00 0.00 Malvinas 25 0112834 31.28 1.92 0.21 0.77 0.00 0.32 0.39 0.00 0.00 Malvinas 26 0112835 35.75 2.89 0.50 1.30 0.33 0.63 0.55 0.00 0.00 Malvinas 27 0112836 47.27 4.01 0.39 1.81 0.18 0.74 0.71 0.00 0.00 Malvinas 28 0112837 23.62 1.36 0.00 0.65 0.00 0.43 0.42 0.00 0.00


Sample


Ethane [ppb]

Ethene [ppb]

Propane [ppb]

Propene [ppb]

i-Butane [ppb]

n-Butane[ppb]

i-Pentane[ppb]

n-Pentane[ppb]

Malvinas 29 0112838 44.50 3.65 0.34 1.46 0.19 0.61 0.57 0.00 0.00 Malvinas 30 0112839 15.47 1.10 0.00 0.63 0.00 0.37 0.38 0.00 0.00 Malvinas 31 0112840 67.18 4.99 0.32 1.83 0.23 0.74 0.66 0.00 0.00 Malvinas 32 0112841 52.52 4.05 0.20 1.71 0.00 0.94 0.80 0.00 0.00 Malvinas 33 0112842 97.07 8.24 0.45 3.45 0.18 1.58 1.41 0.00 0.00 Malvinas 34 0112843 41.72 3.04 0.27 1.12 0.00 0.55 0.48 0.00 0.00 Malvinas 35 0112844 51.09 4.45 0.28 1.82 0.00 0.71 0.78 0.00 0.00 Malvinas 36 0112845 44.28 2.08 0.17 1.01 0.00 0.52 0.47 0.00 0.00 Malvinas 37 0112846 26.51 1.92 0.00 0.85 0.00 0.49 0.47 0.00 0.00 Malvinas 38 0112847 35.77 2.99 0.36 1.20 0.00 0.46 0.39 0.00 0.00 Malvinas 39 0112848 11.04 1.08 0.00 0.69 0.00 0.39 0.34 0.00 0.00 Malvinas 40 0112849 25.06 1.39 0.29 0.57 0.00 0.32 0.25 0.00 0.00 Malvinas 41 0112850 27.72 2.32 0.28 0.93 0.20 0.43 0.34 0.00 0.00 Malvinas 42 0112851 55.49 6.88 0.28 3.66 0.00 1.80 1.57 0.00 0.00 Malvinas 43 0112852 72.21 8.22 0.70 4.19 0.33 1.87 1.75 0.00 0.00 Malvinas 44 0112853 37.47 2.78 0.21 1.31 0.00 0.55 0.65 0.00 0.00 Malvinas 45, <63 µm

0112854a

31.63 3.03 0.24 1.21 0.00 0.52 0.37 0.00 0.00

Malvinas 45, >63 µm

0112854b

125.57 10.00 0.00 3.56 0.00 1.88 1.63 0.00 0.00

Malvinas 46 0112855 44.68 5.66 0.67 2.86 0.27 1.38 1.09 0.00 0.00 Malvinas 46New

0112856 27.69 1.81 0.00 0.76 0.00 0.48 0.35 0.00 0.00

Malvinas 47 0112857 46.70 3.48 0.42 1.45 0.14 0.55 0.54 0.00 0.00 Malvinas 47New

0112858 23.91 2.41 0.39 0.98 0.00 0.42 0.31 0.00 0.00

Malvinas 49 0112859 27.48 2.77 0.45 1.13 0.00 0.48 0.35 0.00 0.00 Malvinas 50 0112860 9.89 0.63 0.00 0.35 0.00 0.27 0.20 0.00 0.00 Malvinas 51 0112861 49.09 4.15 0.27 2.03 0.00 0.85 0.80 0.00 0.00 Malvinas 52 0112862 54.57 3.97 0.36 1.85 0.19 0.84 0.83 0.00 0.00 Malvinas 53 0112863 36.09 1.95 0.27 0.79 0.00 0.34 0.33 0.00 0.00 Malvinas 54 0112864 33.86 2.63 0.00 0.99 0.00 0.43 0.43 0.00 0.00 Malvinas 55 0112865 46.76 3.13 0.23 1.87 0.00 0.98 0.89 0.00 0.00 Malvinas 56 0112866 32.11 0.87 0.00 0.38 0.00 0.00 0.00 0.00 0.00 Malvinas 58 0112867 22.17 0.82 0.00 0.39 0.00 0.00 0.00 0.00 0.00 Malvinas 59 0112868 39.29 2.53 0.30 0.93 0.00 0.32 0.40 0.00 0.00 Malvinas 60 0112869 23.96 1.68 0.24 0.67 0.00 0.32 0.40 0.00 0.00 Malvinas 61 0112870 22.80 1.40 0.00 0.82 0.00 0.42 0.34 0.00 0.00 BGR98-1 0112808 12.98 0.64 0.35 0.34 0.00 0.00 0.00 0.00 0.00 BGR98-2 0112801 30.66 1.97 0.42 0.64 0.21 0.21 0.29 0.50 0.00 BGR98-3 0112802 10.75 0.54 0.30 0.10 0.20 0.00 0.00 0.00 0.00 BGR98-4 0112803 4.40 0.41 0.09 0.00 0.00 0.00 0.00 0.00 0.00 BGR98-5 0112804 4.62 0.32 0.50 0.00 0.26 0.00 0.00 0.00 0.00 BGR98-6 0112805 21.57 1.24 0.33 0.38 0.15 0.13 0.11 0.24 0.00 BGR98-7 0107579 29.62 2.07 0.31 0.85 0.00 0.46 0.54 1.00 0.29 BGR98-8 0112806 27.17 2.20 0.53 0.91 0.25 0.37 0.33 0.70 0.00 BGR98-9 0112809 23.37 1.28 0.40 0.53 0.22 0.23 0.29 0.52 0.00 BGR98-10 0112807 13.44 0.68 0.00 0.30 0.00 0.00 0.00 0.00 0.00 Colorado 1 0107550 5.70 4.17 0.32 2.28 0.00 0.60 0.85 1.44 0.00 Colorado 2 0107551 5.16 0.79 0.25 0.26 0.00 0.12 0.11 0.23 0.00 Colorado 3 0107552 18.83 1.21 0.36 0.29 0.00 0.00 0.00 0.00 0.00 Colorado 4 0107553 34.14 2.95 1.09 1.59 0.00 0.41 0.60 1.01 0.22 Colorado 5 0107554 16.91 1.02 0.37 0.41 0.00 0.19 0.22 0.41 0.10 Colorado 6 0107555 3.52 0.50 2.42 0.41 0.00 0.12 0.07 0.19 0.00 Colorado 8 0107556 19.77 1.00 0.00 0.30 0.00 0.15 0.13 0.28 0.13 Colorado 9 0107557 15.11 1.07 0.22 0.42 0.00 0.17 0.18 0.34 0.13 Colorado 10 0107558 4.08 0.27 0.06 0.14 0.00 0.04 0.07 0.11 0.00 Colorado 11 0107559 19.33 1.14 0.16 0.32 0.00 0.18 0.17 0.35 0.12 Colorado 12 0107560 24.05 1.38 0.24 0.45 0.00 0.21 0.21 0.42 0.14 Colorado 13 0107561 15.62 0.70 0.09 0.23 0.00 0.14 0.16 0.30 0.07 Colorado 14 0107562 29.96 1.17 0.17 0.46 0.00 0.16 0.16 0.32 0.16


Sample


Ethane [ppb]

Ethene [ppb]

Propane [ppb]

Propene [ppb]

i-Butane [ppb]

n-Butane[ppb]

i-Pentane[ppb]

n-Pentane[ppb]

Colorado 17 0107563 1.57 0.12 0.22 0.00 0.00 0.02 0.23 0.25 0.00 Colorado 18 0107564 19.52 1.32 0.00 0.55 0.00 0.33 0.34 0.67 0.00 Colorado 20 0107565 10.42 0.74 0.07 0.17 0.00 0.06 0.12 0.18 0.07 Colorado 21 0107566 5.76 0.61 0.28 0.00 0.00 0.06 0.08 0.14 0.03 Colorado 22 0107567 22.00 2.09 0.73 0.87 0.00 0.16 0.33 0.49 0.00 Colorado 23 0107568 20.99 1.09 0.15 0.35 0.00 0.14 0.14 0.28 0.11 Colorado 24 0107569 11.97 0.75 0.16 0.24 0.00 0.10 0.07 0.17 0.13 Colorado 25, <63µm

0107570a

73.48 6.37 0.00 3.52 0.00 1.16 1.43 2.59 1.06

Colorado 25, >63µm

0107570b

42.70 3.78 0.22 1.65 0.00 0.70 0.63 1.33 0.43

Colorado 26 0107571 18.59 0.93 0.14 0.29 0.00 0.17 0.12 0.29 0.03 Colorado 27 0107572 23.18 1.75 0.37 0.72 0.00 0.24 0.23 0.47 0.15 Colorado 28 0107573 11.07 0.76 0.13 0.23 0.00 0.07 0.08 0.16 0.07 Colorado 29 0107574 39.26 2.17 0.47 0.99 0.00 0.28 0.26 0.54 0.14 Colorado 30 0107575 47.28 2.76 0.35 1.07 0.00 0.58 0.56 1.13 0.27 Colorado S-1 0107576 21.61 1.28 0.36 0.45 0.00 0.20 0.20 0.40 0.07 Colorado S-2 0107577 30.17 2.10 0.27 1.03 0.00 0.55 0.68 1.23 0.53 Colorado S-3 0107578 43.69 2.91 0.86 1.10 0.00 0.53 0.32 0.85 0.45 GeoB 6308-4 0010905 GeoB 6308-4 0010906 GeoB 6330-4 0010907 462.1 18.6 1.6 2.7 0.0 0.0 0.0 0.9 0.0 GeoB 6330-4 0010908 49.4 2.0 1.4 2.6 0.0 0.8 0.8 1.0 2.9 GeoB 2704-2 0010909 51.2 2.1 0.0 1.1 0.0 0.0 0.0 0.0 0.0 GeoB 2704-2 0010910 83.9 3.4 2.5 2.8 0.8 0.6 0.8 0.7 0.0 GeoB 2707-5 0010911 63.6 2.6 2.2 2.4 0.8 0.7 1.0 0.7 1.0 GeoB 2707-5 0010912 53.8 2.2 1.2 1.8 0.1 0.2 0.3 0.4 0.0 GeoB 2714-1 0010913 51.5 2.3 0.0 2.3 0.0 0.0 0.0 0.0 0.0 GeoB 2714-1 0010914 40.1 1.6 2.2 2.6 0.0 0.0 0.0 0.0 0.0 GeoB 2716-2 0010915 47.4 1.9 1.7 1.2 0.0 0.0 0.0 0.0 0.0 GeoB 2716-2 0010916 91.0 3.7 1.9 2.1 0.0 1.1 1.4 0.0 3.0 GeoB 2722-4 0010917 37.1 1.5 0.9 2.2 0.0 0.0 0.0 0.0 0.0 GeoB 2722-4 0010918 82.2 3.3 0.9 2.5 0.0 0.3 1.2 0.7 0.7 GeoB 2724-4 0010919 7.9 0.4 0.6 2.8 0.0 1.2 1.5 3.1 1.3 GeoB 2724-4 0010920 66.4 2.7 3.3 2.7 0.0 1.5 1.6 0.0 0.0

MD962080 (Aghulas), 0.31-0.83 m

0018645 56.29 24.90 0.88 13.87 0.00 8.37 5.49 14.69 2.23

MD962080 (Aghulas), 21.31-21.73 m

0018646

MD962083 (Saldanha), 0.30-0.72 m

0018647 26.44 12.28 0.90 5.69 0.00 5.65 3.01 10.54 1.26

MD962083 (Saldanha), 26.30-26.72 m

0018648 111.32 54.83 0.00 30.29 0.00 26.80 10.69 48.58 1.67

MD962084 (Olifants r.), 0.32-0.72 m

0018649 13.41 4.56 0.00 2.78 0.00 2.14 1.18 2.24 0.55

MD962084 (Olifants r.), 34.61-35.13 m

0018650 58.35 26.44 0.00 21.02 0.00 6.68 5.77 16.20 3.98

MD962085 (Orange r.), 34.99-35.37 m

0018651 56.07 27.13 0.67 15.47 0.00 9.61 5.28 15.11 1.39

MD962085G (Orange r.), 0.30-0.72 m

0018652 13.07 4.33 1.13 1.01 0.00 0.95 0.82 1.50 1.07


Sample


Ethane [ppb]

Ethene [ppb]

Propane [ppb]

Propene [ppb]

i-Butane [ppb]

n-Butane[ppb]

i-Pentane[ppb]

n-Pentane[ppb]

MD962099 (Orange r.), 0.30-0.72 m

0018653 13.73 5.47 0.00 2.35 0.00 0.00 0.00 3.93 0.00

MD962099 (Orange r.), 34.60-35.02 m

0018654 219.37 113.58 1.31 69.57 2.81 53.96 25.70 97.24 4.35

MD962087 (Lüderitz), 39.19-39.63 m

0018655 484.59 9.87 3.27 10.09 0.00 3.31 2.84 5.86 0.00

MD962087G (Lüderitz), 0.39-1.00 m

0018656 16.83 3.37 5.36 0.00 0.00 0.00 0.00 0.00 0.00

MD962098 (Lüderitz), 0.39-0.80 m

0018657 3.91 2.79 1.95 0.72 0.00 0.00 0.00 0.00 0.00

MD962098 (Lüderitz), 31.79-32.10 m

0018658 42.85 13.35 0.83 24.49 1.20 2.17 2.89 3.14 0.00

MD962086 (Lüderitz), 35.59-36.00 m

0018659 64.68 17.41 4.28 0.00 0.00 3.10 4.71 5.33 0.00

MD962086G (Lüderitz), 0.29-0.70 m

0018660 7.47 1.83 2.22 1.68 0.00 0.60 1.13 0.00 6.68

MD962088G (Walvis B.), 0.30-0.72 m

0018661 741.71 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

MD962088 (Walvis B.), 1.70-2.12 m

0018662 2972.94 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

MD962096G (Walvis B.), 0.30-0.72 m

0018663 8.79 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

MD962096 (Walvis B.), 28.70-29.12 m

0018664 16.61 5.87 0.00 4.95 0.00 3.10 1.55 3.79 0.00

MD962095 (Walvis R.), 23.70-24.12 m

0018665 25.81 4.80 0.00 5.19 0.00 2.12 1.59 2.92 0.00

MD962095G (Walvis R.), 0.30-0.72 m

0018666 19.38 6.29 3.45 1.11 0.00 0.00 0.00 0.00 0.00

Table A.3: Compilation of some important gas ratios and the stable carbon isotope values for methane and ethane of the desorbed gas. Sample

Lab - No.

Vol-ratio C1/sum Cn-%

Vol-ratio C1/(C2+C3)

C2+ [ppb] δ13-Methane [‰]

δ13-Ethane [‰]

Malvinas 1 0112810 0.98 44.6 2.19 -38.3 -33.0 Malvinas 3 0112812 0.96 32.2 4.83 -37.8 -32.2 Malvinas 4 0112813 0.91 13.9 12.25 -39.7 -29.7 Malvinas 5a 0112814 0.92 22.2 10.72 -41.4 -31.6 Malvinas 6a 0112815 0.94 19.2 7.26 -40.7 -31.8 Malvinas 7a 0112816 0.95 23.4 5.85 -40.3 -31.3 Malvinas 8 0112817 0.91 12.6 11.75 -41.8 -30.3 Malvinas 9 0112818 0.94 18.2 7.55 -41.0 -28.1 Malvinas 10 0112819 0.95 26.4 6.14 -40.5 -31.2


Sample

Lab - No.




δ13-Ethane [‰]

Malvinas 11 0112920 0.92 14.3 9.37 -41.2 -31.5 Malvinas 12 0112821 0.93 16.2 8.70 -40.3 -31.2 Malvinas 13 0112822 0.95 26.4 6.84 -40.4 -31.7 Malvinas 14 0112823 0.91 12.7 11.48 -41.0 -30.8 Malvinas 15 0112824 0.90 10.9 13.26 -41.3 -30.4 Malvinas 16 0112825 0.91 13.1 11.94 -41.4 -31.5 Malvinas 17 0112826 0.91 12.4 11.55 -41.1 -31.4 Malvinas 18 0112827 0.90 12.0 12.75 -41.7 -30.9 Malvinas 19 0112828 0.92 13.7 11.08 -40.8 -30.7 Malvinas 20 0112829 0.93 16.9 8.36 -40.0 -30.7 Malvinas 21 0112830 0.92 15.5 9.44 -40.2 -32.2 Malvinas 22 0112831 0.92 14.0 10.22 -40.1 -31.5 Malvinas 23 0112832 0.94 17.7 7.80 -42.0 -31.5 Malvinas 24 0112833 0.95 22.0 6.28 -40.4 -31.6 Malvinas 25 0112834 0.95 24.0 6.12 -40.1 -31.4 Malvinas 26 0112835 0.93 17.7 8.84 -41.2 -33.7 Malvinas 27 0112836 0.93 16.9 8.45 -40.5 -32.2 Malvinas 28 0112837 0.95 24.6 6.71 -40.2 -31.1 Malvinas 29 0112838 0.94 18.0 7.82 -40.3 -32.0 Malvinas 30 0112839 0.94 19.0 8.70 -40.4 -30.7 Malvinas 31 0112840 0.94 20.2 6.69 -41.0 -30.1 Malvinas 32 0112841 0.94 18.9 7.76 -40.8 -30.9 Malvinas 33 0112842 0.93 17.2 8.13 -39.2 -30.7 Malvinas 34 0112843 0.94 20.5 6.87 -42.6 -33.0 Malvinas 35 0112844 0.93 16.8 8.11 -42.6 -32.7 Malvinas 36 0112845 0.96 30.0 4.00 -55.3 -33.9 Malvinas 37 0112846 0.94 19.9 7.58 -41.1 -31.4 Malvinas 38 0112847 0.94 17.6 7.69 -41.6 -34.3 Malvinas 39 0112848 0.91 13.3 11.86 -41.6 -31.3 Malvinas 40 0112849 0.95 26.4 4.82 -52.4 -32.9 Malvinas 41 0112850 0.93 17.6 8.23 -43.9 -31.9 Malvinas 42 0112851 0.90 11.1 12.91 -41.8 -32.2 Malvinas 43 0112852 0.91 12.2 11.84 -41.6 -33.1 Malvinas 44 0112853 0.94 19.1 7.71 -42.1 -32.4 Malvinas 45, <63 µm 0112854a 0.93 15.4 8.61 -40.8 -30.3 Malvinas 45, >63 µm 0112854b 0.94 18.9 7.16 -40.7 -28.6 Malvinas 46 0112855 0.90 11.0 13.20 -43.8 -31.9 Malvinas 46New 0112856 0.95 22.4 6.61 -43.1 -31.9 Malvinas 47 0112857 0.94 19.6 7.21 -44.2 -32.1 Malvinas 47New 0112858 0.92 14.5 9.50 -41.3 -32.5 Malvinas 49 0112859 0.92 14.5 9.50 -42.5 -32.8 Malvinas 50 0112860 0.94 21.2 8.20 -41.5 -33.0 Malvinas 51 0112861 0.93 16.6 8.49 -41.3 -30.5 Malvinas 52 0112862 0.94 19.6 7.66 -41.0 -30.9 Malvinas 53 0112863 0.96 27.2 5.38 -40.4 -31.1 Malvinas 54 0112864 0.94 19.2 6.92 -41.9 -32.7 Malvinas 55 0112865 0.94 19.9 8.10 -40.5 -32.8 Malvinas 56 0112866 0.98 53.6 1.83 -37.3 -31.0 Malvinas 58 0112867 0.97 38.3 2.55 -39.4 -31.2


Sample

Lab - No.




δ13-Ethane [‰]

Malvinas 59 0112868 0.95 23.3 5.94 -41.4 -32.4 Malvinas 60 0112869 0.94 21.0 7.34 -40.1 -31.3 Malvinas 61 0112870 0.95 21.8 6.99 -39.9 -31.3 BGR98-1 0112808 0.95 28.1 1.33 -39.0 -31.5 BGR98-2 0112801 0.95 23.8 4.74 -38.3 -30.3 BGR98-3 0112802 0.95 33.2 1.14 -38.4 -32.9 BGR98-4 0112803 0.94 20.1 0.50 -36.7 -33.2 BGR98-5 0112804 0.89 27.0 1.08 -36.6 -30.9 BGR98-6 0112805 0.95 27.1 2.81 -38.1 -30.0 BGR98-7 0107579 0.94 21.0 6.95 -42.9 BGR98-8 0112806 0.93 18.0 6.01 -40.7 -33.9 BGR98-9 0112809 0.95 26.7 3.99 -38.8 -32.8 BGR98-10 0112807 0.97 28.4 0.98 -39.2 -31.8 Colorado 1 0107550 0.61 1.9 11.09 -50.5 -27.1 Colorado 2 0107551 0.88 10.0 1.98 -47.5 -32.4 Colorado 3 0107552 0.95 25.1 1.86 -40.3 -39.9 Colorado 4 0107553 0.92 15.9 8.99 -40.1 -37.5 Colorado 5 0107554 0.94 24.4 3.24 -36.9 -32.2 Colorado 6 0107555 0.65 8.4 3.92 -46.5 -29.9 Colorado 8 0107556 0.96 30.7 2.32 -38.3 -36.2 Colorado 9 0107557 0.94 20.8 2.97 -38.0 -32.0 Colorado 10 0107558 0.94 20.9 0.78 -42.1 -33.0 Colorado 11 0107559 0.95 26.6 2.78 -39.1 -32.3 Colorado 12 0107560 0.95 26.7 3.56 -39.2 -31.6 Colorado 13 0107561 0.96 34.3 2.05 -38.7 -31.1 Colorado 14 0107562 0.97 38.0 3.06 -44.4 -32.8 Colorado 17 0107563 0.86 24.8 1.09 -33.4 Colorado 18 0107564 0.95 21.6 4.03 -41.9 Colorado 20 0107565 0.95 22.9 1.64 -36.5 -32.1 Colorado 21 0107566 0.92 17.7 1.35 -42.4 -36.4 Colorado 22 0107567 0.92 15.4 5.16 -42.4 Colorado 23 0107568 0.96 29.7 2.55 -37.7 -29.4 Colorado 24 0107569 0.95 24.4 1.80 -42.5 -36.0 Colorado 25, <63µm 0107570a 0.93 15.7 19.25 -40.0 -29.8 Colorado 25, >63µm 0107570b 0.93 16.3 10.30 -39.5 -33.0 Colorado 26 0107571 0.96 30.9 2.26 -41.1 -33.8 Colorado 27 0107572 0.94 19.4 4.49 -39.4 -33.6 Colorado 28 0107573 0.95 22.7 1.73 -38.7 -33.2 Colorado 29 0107574 0.95 25.8 5.38 -40.4 -35.2 Colorado 30 0107575 0.95 25.4 7.96 -40.9 -33.0 Colorado S-1 0107576 0.95 25.4 3.59 -43.6 -36.9 Colorado S-2 0107577 0.93 20.2 7.93 -49.5 -34.2 Colorado S-3 0107578 0.94 22.4 7.88 -40.7 -34.6 GeoB 6308-4 0010905 GeoB 6308-4 0010906 0.99 133.84 0.97 -80.4 -30.6 GeoB 6330-4 0010907 0.90 14.63 9.56 -41.9 -31.2 GeoB 6330-4 0010908 0.95 20.83 4.58 -39.7 -29.5 GeoB 2704-2 0010909 0.92 17.52 8.17 -40.1 -30.1 GeoB 2704-2 0010910 0.91 18.47 8.56 -39.1 -32.0


Sample

Lab - No.




δ13-Ethane [‰]

GeoB 2707-5 0010911 0.93 17.40 7.27 -39.1 -30.7 GeoB 2707-5 0010912 0.95 17.62 5.37 -39.9 -30.5 GeoB 2714-1 0010913 0.92 15.26 8.30 -41.0 -30.0 GeoB 2714-1 0010914 0.94 21.56 6.24 -41.6 -30.5 GeoB 2716-2 0010915 0.93 23.81 6.68 -44.1 -30.2 GeoB 2716-2 0010916 0.94 20.19 5.74 -39.9 -32.4 GeoB 2722-4 0010917 0.90 12.18 9.54 -39.7 -29.0 GeoB 2722-4 0010918 0.64 2.91 35.56 -36.5 -26.8 GeoB 2724-4 0010919 0.93 21.96 6.91 -41.4 -34.3 GeoB 2724-4 0010920 0.97 40.32 3.23 -71.2 -33.1 MD962080 (Aghulas), 0.31-0.83 m

0018645 0.68 3.07 31.93 -33.63 -22.63

MD962080 (Aghulas), 21.31-21.73 m

0018646

MD962083 (Saldanha), 0.30-0.72 m

0018647 0.65 3.07 34.85 -35.47 -23.97

MD962083 (Saldanha), 26.30-26.72 m

0018648 0.64 2.77 35.69 -32.73 -23.19

MD962084 (Olifants r.), 0.32-0.72 m

0018649 0.73 3.90 27.07 -41.96 -25.94

MD962084 (Olifants r.), 34.61-35.13 m

0018650 0.66 2.68 33.70 -34.08 -23.56

MD962085 (Orange r.), 34.99-35.37 m

0018651 0.66 2.79 33.51 -33.75 -23.86

MD962085G(Orange r.), 0.30-0.72 m

0018652 0.75 4.89 25.10 -38.19 -28.16

MD962099 (Orange r.), 0.30-0.72 m

0018653 0.75 3.64 25.28 -39.55 -24.57

MD962099 (Orange r.), 34.60-35.02 m

0018654 0.62 2.55 37.61 -33.89 -25.37

MD962087 (Lüderitz), 39.19-39.63 m

0018655 0.97 54.25 2.77 -62.49 -25.96

MD962087G(Lüderitz), 0.39-1.00 m

0018656 0.78 9.36 22.41 -39.51 -26.28

MD962098 (Lüderitz), 0.39-0.80 m

0018657 0.30 2.64 36.30 -43.15 -31.43

MD962098 (Lüderitz), 31.79-32.10 m

0018658 0.69 2.67 30.50 -36.78 -23.87

MD962086 (Lüderitz), 35.59-36.00 m

0018659 0.81 3.98 25.31 -31.48 -25.21

MD962086G(Lüderitz), 0.29-0.70 m

0018660 0.61 4.74 30.77 -35.70 -28.53

MD962088G (Walvis B.), 0.30-0.72 m

0018661 1.00 0.00 -68.57

MD962088 (Walvis B.), 1.70-2.12 m

0018662 1.00 0.00 -77.01

MD962096G(Walvis B.), 0.30-0.72 m

0018663 1.00 0.00 -35.23 -33.75

MD962096 (Walvis B.), 28.70-29.12 m

0018664 0.68 3.37 29.02 -35.86 -26.63

MD962095 (Walvis R.), 23.70-24.12 m

0018665 0.80 5.80 18.99 -36.68 -26.56

MD962095G(Walvis R.), 0.30-0.72 m

0018666 0.45 5.19 22.70 -43.94 -35.24


Source rock data

Table A.4a: Compilation of the sampling position and depth and stratigraphy of source rock samples from offshore Namiba, South Africa, Argentina and onshore Namibia and Brazil.

Well Lab.-No. Stratigraphy Latitude Longitude Depth [mbsf] Kudu 9A-2 9936986 Early Aptian 28°29'01.13''S 14°34'27.07''E 3865-70 Kudu 9A-2 9936987 Early Aptian 28°29'01.13''S 14°34'27.07''E 3875-80 Kudu 9A-2 9936988 Early Aptian 28°29'01.13''S 14°34'27.07''E 3885-90 Kudu 9A-2 9936989 Early Aptian 28°29'01.13''S 14°34'27.07''E 3918-21 Kudu 9A-2 9936990 Early Aptian 28°29'01.13''S 14°34'27.07''E 3927-30 Kudu 9A-2 9936991 Early Aptian 28°29'01.13''S 14°34'27.07''E 3939-42 Kudu 9A-2 9936992 Early Aptian 28°29'01.13''S 14°34'27.07''E 3957-60 Kudu 9A-2 9936993 Early Aptian 28°29'01.13''S 14°34'27.07''E 4107-10 Kudu 9A-2 9936994 Early Aptian 28°29'01.13''S 14°34'27.07''E 4119-22 Kudu 9A-2 9936995 Early Aptian 28°29'01.13''S 14°34'27.07''E 4128-31 Kudu 9A-2 9936996 Late Barremian 28°29'01.13''S 14°34'27.07''E 4137-40 Kudu 9A-2 9936997 Late Barremian 28°29'01.13''S 14°34'27.07''E 4149-52 Kudu 9A-2 9936998 Late Barremian 28°29'01.13''S 14°34'27.07''E 4158-61 Kudu 9A-2 9936999 Late Barremian 28°29'01.13''S 14°34'27.07''E 4167-70 Kudu 9A-2 9937000 Late Barremian 28°29'01.13''S 14°34'27.07''E 4179-82 Kudu 9A-2 9937001 Late Barremian 28°29'01.13''S 14°34'27.07''E 4188-91 Kudu 9A-2 9937002 Late Barremian 28°29'01.13''S 14°34'27.07''E 4197-00 Kudu 9A-2 9937003 Mud 28°29'01.13''S 14°34'27.07''E Kudu 9A-2 9937004 Late Barremian 28°29'01.13''S 14°34'27.07''E 4209-12 Kudu 9A-2 9937005 Late Barremian 28°29'01.13''S 14°34'27.07''E 4218-21 Kudu 9A-3 9937006 Late Aptian 28°34'54.41''S 14°35'54.90''E 3839-42 Kudu 9A-3 9937007 Early Aptian 28°34'54.41''S 14°35'54.90''E 3848-51 Kudu 9A-3 9937008 Early Aptian 28°34'54.41''S 14°35'54.90''E 3857-60 Kudu 9A-3 9937009 Early Aptian 28°34'54.41''S 14°35'54.90''E 3869-72 Kudu 9A-3 9937010 Early Aptian 28°34'54.41''S 14°35'54.90''E 3878-81 Kudu 9A-3 9937011 Early Aptian 28°34'54.41''S 14°35'54.90''E 3887-90 Kudu 9A-3 9937012 Early Aptian 28°34'54.41''S 14°35'54.90''E 3899-02 Kudu 9A-3 9937013 Mud 28°34'54.41''S 14°35'54.90''E Kudu 9A-3 9937014 Early Aptian 28°34'54.41''S 14°35'54.90''E 3908-11 Kudu 9A-3 9937015 Early Aptian 28°34'54.41''S 14°35'54.90''E 3917-20 Kudu 9A-3 9937016 Early Aptian 28°34'54.41''S 14°35'54.90''E 3929-32 Kudu 9A-3 9937017 Early Aptian 28°34'54.41''S 14°35'54.90''E 3938-41 Kudu 9A-3 9937018 Early Aptian 28°34'54.41''S 14°35'54.90''E 3947-50 Kudu 9A-3 9937019 Early Aptian 28°34'54.41''S 14°35'54.90''E 3959-62 Kudu 9A-3 9937020 Early Aptian 28°34'54.41''S 14°35'54.90''E 3968-71 Kudu 9A-3 9937021 Early Aptian 28°34'54.41''S 14°35'54.90''E 3977-80 Kudu 9A-3 9937022 Early Aptian 28°34'54.41''S 14°35'54.90''E 3989-92 Kudu 9A-3 9937023 Early Aptian 28°34'54.41''S 14°35'54.90''E 3998-01 DSDP 361 0011269 Upper Cretaceous 35°03.97'S 15°26.91'E 577.73-75 DSDP 361 0011270 Upper Cretaceous 35°03.97'S 15°26.91'E 767.24-26 DSDP 361 0011271 L. Albian to Up. Aptian 35°03.97'S 15°26.91'E 957.28-30 DSDP 361 0011272 L. Albian to Up. Aptian 35°03.97'S 15°26.91'E 1008.15-17 DSDP 361 0011273 L. Albian to Up. Aptian 35°03.97'S 15°26.91'E 1035.18-19 DSDP 361 0011274 L. Albian to Up. Aptian 35°03.97'S 15°26.91'E 1039.55-57 DSDP 361 0011275 L. Albian to Up. Aptian 35°03.97'S 15°26.91'E 1052.40-42 DSDP 361 0011276 L. Albian to Up. Aptian 35°03.97'S 15°26.91'E 1065.10-12


Well Lab.-No. Stratigraphy Latitude Longitude Depth [mbsf] DSDP 361 0011277 Aptian, Lower ? 35°03.97'S 15°26.91'E 1068.72-74 DSDP 361 0011278 Aptian, Lower ? 35°03.97'S 15°26.91'E 1082.32-33 DSDP 361 0011279 Aptian, Lower ? 35°03.97'S 15°26.91'E 1088.92-94 DSDP 361 0011280 Aptian 35°03.97'S 15°26.91'E 1099.75-77 DSDP 361 0011281 Aptian 35°03.97'S 15°26.91'E 1106.54-56 DSDP 361 0011282 Aptian, Lower ? 35°03.97'S 15°26.91'E 1117.29-30 DSDP 361 0011283 Aptian 35°03.97'S 15°26.91'E 1127.20-21 DSDP 361 0011284 Aptian 35°03.97'S 15°26.91'E 1145.20-21 DSDP 361 0011285 Aptian 35°03.97'S 15°26.91'E 1147.28-30 DSDP 361 0011286 Aptian 35°03.97'S 15°26.91'E 1166.69-70 DSDP 361 0011287 Aptian 35°03.97'S 15°26.91'E 1182.71-72 DSDP 361 0011288 Aptian 35°03.97'S 15°26.91'E 1201.98-99 DSDP 361 0011289 Aptian 35°03.97'S 15°26.91'E 1223.34-35 DSDP 361 0011290 Aptian 35°03.97'S 15°26.91'E 1257.55-57 DSDP 361 0011291 Aptian 35°03.97'S 15°26.91'E 1267.14-15 DSDP 361 0011292 Aptian 35°03.97'S 15°26.91'E 1286.09-10 Irati 0020719 Permian 25.875°S 50.405°W outcrop Irati 0020720 Permian 25.875°S 50.405°W outcrop Cruz del Sur 0020723 40°56.05'05.931''S 57°17'26.348''W 1850Cruz del Sur 0020725 40°56.05'05.931''S 57°17'26.348''W 2135Cruz del Sur 0020728 Alb 40°56.05'05.931''S 57°17'26.348''W 2150Cruz del Sur 0020731 40°56.05'05.931''S 57°17'26.348''W 2418Cruz del Sur 0020733 40°56.05'05.931''S 57°17'26.348''W 2958Cruz del Sur 0020740 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 2982Cruz del Sur 0020748 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3012Cruz del Sur 0020753 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3024Cruz del Sur 0020761 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3102Cruz del Sur 0020764 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3114Cruz del Sur 0020772 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3168Cruz del Sur 0020781 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3195Cruz del Sur 0020787 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3252Cruz del Sur 0020789 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3348Cruz del Sur 0020793 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3366Cruz del Sur 0020799 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3396Cruz del Sur 0020805 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3426Cruz del Sur 0020815 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3456Cruz del Sur 0020818 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3471Cruz del Sur 0020820 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3477Cruz del Sur 0020831 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3510Cruz del Sur 0020836 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3525Cruz del Sur 0020839 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3534Cruz del Sur 0020847 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3558Cruz del Sur 0020856 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3585Cruz del Sur 0020864 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3609Cruz del Sur 0020869 Valangin-Kimmeridge 40°56.05'05.931''S 57°17'26.348''W 3636Cruz del Sur 0020875 Trias (Pre-Rift) 40°56.05'05.931''S 57°17'26.348''W 3822Cruz del Sur 0020886 Trias (Pre-Rift) 40°56.05'05.931''S 57°17'26.348''W 4191Cruz del Sur 0020887 Trias (Pre-Rift) 40°56.05'05.931''S 57°17'26.348''W 4194Cruz del Sur 0020894 Trias (Pre-Rift) 40°56.05'05.931''S 57°17'26.348''W 4242Cruz del Sur 0020902 Trias (Pre-Rift) 40°56.05'05.931''S 57°17'26.348''W 4272Whitehill 0190107 Permian S 26° 28,82' E 18° 18,92' outcrop


Well Lab.-No. Stratigraphy Latitude Longitude Depth [mbsf] Whitehill 0190108 Permian S 26° 28,05' E 18° 18,45' outcrop Whitehill 0190109 Permian S 26° 28,05' E 18° 18,45' outcrop Whitehill 0190110 Permian S 28° 35,15' E 17° 34,47' outcrop Whitehill 0190111 S 28° 14,13' E 17° 39,69' outcrop Table A.4a: Compilation of results of analyses on source rocks from offshore Namiba, South Africa, Argentina and onshore Namibia and Brazil. Lab.-No. TOC [%] S [%] S1 [mg

HC/g rock]

S2 [mg HC/g rock]

S3 [mg CO2/g rock]

Tmax [°C]

HI [mg HC/g TOC]

OI [mg CO2/g TOC]

Vitrinite Reflec-tance [% Rr]

δ13 COM [‰]

Kudu 9A-2, offshore Namibia 9936986 1.5 0.4 0.6 1.3 439 38 88 1.22-1.33 -25.39936987 1.7 0.4 0.6 1.4 442 35 83 -26.09936988 1.7 0.4 0.6 1.3 451 34 73 -25.79936989 2.1 0.6 0.7 1.5 455 33 71 -25.79936990 2.0 0.5 0.7 1.5 457 34 73 -25.99936991 2.1 0.5 0.7 1.5 462 33 73 1.28 -26.29936992 2.3 0.5 0.7 1.5 453 31 64 -25.69936993 0.9 0.2 0.3 1.2 417 31 129 1.62 -26.19936994 1.1 0.2 0.3 1.4 451 24 127 -25.89936995 0.9 0.2 0.2 1.2 556 23 125 -25.19936996 1.1 0.2 0.3 1.5 517 28 139 -25.59936997 1.4 0.2 0.3 1.5 524 22 105 -25.89936998 1.7 0.3 0.3 1.3 539 18 78 -25.99936999 1.6 0.2 0.3 1.7 527 20 105 1.78 -25.79937000 1.3 0.2 0.3 1.6 535 20 122 1.77 -25.59937001 1.5 0.2 0.3 1.5 532 18 101 -25.29937002 1.5 0.2 0.3 1.7 525 21 110 -24.89937003 1.2 0.5 1.1 4.0 408 86 328 9937004 1.1 0.2 0.4 1.8 517 32 158 -25.59937005 1.4 0.2 0.4 1.6 520 26 111 1.75 -25.2Kudu 9A-3, offshore Namibia 9937006 1.9 0.1 0.3 1.6 437 17 84 -24.89937007 1.3 0.2 0.4 1.3 438 32 106 -25.09937008 1.4 0.2 0.4 1.4 450 31 101 -24.89937009 1.9 0.3 0.5 1.3 433 27 69 -24.79937010 1.8 0.2 0.5 1.4 462 26 76 -24.89937011 1.8 0.2 0.5 1.4 433 27 77 -25.09937012 2.0 0.3 0.6 1.4 429 31 73 -25.29937013 1.8 0.5 2.0 5.9 420 108 324 9937014 1.9 0.3 0.5 1.9 470 27 99 -25.39937015 1.8 0.3 0.6 1.5 429 32 85 -25.49937016 1.8 0.2 0.5 1.5 506 26 81 -25.59937017 1.8 0.2 0.5 1.5 436 26 88 -25.69937018 1.2 0.1 0.4 1.3 459 34 107 -25.59937019 1.7 0.2 0.5 1.4 442 26 80 -25.59937020 1.7 0.2 0.4 1.7 465 22 98 -25.49937021 1.9 0.2 0.5 1.5 437 25 79 -25.29937022 2.0 0.2 0.5 1.4 515 23 71 -24.8


Lab.-No. TOC [%] S [%] S1 [mg HC/g rock]

S2 [mg HC/g rock]

S3 [mg CO2/g rock]

Tmax [°C]

HI [mg HC/g TOC]

OI [mg CO2/g TOC]


δ13 COM [‰]

9937023 1.1 0.1 0.3 1.6 514 29 138 -23.8DSDP 361, offshore South Africa 0011269 0.7 0.0 0.3 1.4 425 40 197 0.35 (+0.1-

0.15) -24.1

0011270 0.1 0.0 0.3 0.7 375 170 497 0011271 1.3 0.1 1.5 1.2 432 119 93 -25.00011272 3.3 0.2 4.1 1.6 408 125 49 0.3 (+0.1-

0.15) -26.6

0011273 4.4 0.2 3.5 2.3 407 80 52 -24.60011274 2.4 0.1 1.4 1.1 393 58 45 -23.10011275 3.0 0.1 1.3 1.9 413 45 63 -23.30011276 4.2 0.2 10.1 2.1 421 242 49 -26.00011277 11.0 12.2 1.1 44.8 3.7 407 407 33 0.27 (+0.1-

0.15) -28.1

0011278 3.2 0.1 6.2 2.0 425 193 61 -25.50011279 1.2 0.0 0.3 0.6 412 24 50 0011280 11.5 12.6 0.3 4.2 5.8 415 36 51 -23.60011281 13.2 13.5 0.3 3.8 5.9 411 28 45 0.29 (+0.1-

0.15) -24.0

0011282 2.7 0.1 0.4 1.2 412 15 43 -23.90011283 3.1 0.1 1.8 2.0 409 57 65 -25.70011284 5.3 0.4 11.3 2.1 409 211 40 -25.70011285 1.5 0.1 0.6 0.8 413 43 52 0011286 3.0 0.1 1.6 1.2 414 52 40 -25.10011287 11.0 14.1 1.1 61.2 5.0 417 556 45 0.3 (+0.1-

0.15) -26.4

0011288 3.5 0.1 1.7 1.4 417 48 40 -25.00011289 2.3 0.1 0.5 0.9 413 20 39 -23.00011290 0.3 0.0 0.4 0.5 431 112 149 0011291 4.1 0.2 3.2 1.3 411 79 33 -24.80011292 3.7 0.3 2.4 1.6 409 64 43 0.31 (+0.1-

0.15) -25.5

Irati Shale, onshore Brazil 0020719 12.6 4.2 4.8 77.7 1.0 424 616 23 0.50 -23.80020720 21.9 5.8 7.2 158.3 2.7 425 724 47 0.50 -20.6Cruz del Sur, offshore Argentina 0020723 0.32 0020725 0.63 0020728 0.4 0.1 0.5 0.7 424 103 148 -25.60020731 0.56 0020733 0.52 0020740 2.2 0.6 9.1 1.4 425 409 65 0020748 4.0 1.3 21.6 1.2 426 539 29 -20.20020753 0.8 0.1 1.1 1.9 431 132 244 -22.80020761 1.2 0.2 1.1 1.3 439 96 115 -23.80020764 1.8 0.2 1.6 1.4 437 91 77 -24.00020772 0.49 0020781 0.3 0.1 0.2 2.9 439 71 939 -23.90020787 0.3 0.1 0.3 1.4 437 121 516 0020789 0.60 0020793 0.8 0.1 1.1 3.4 444 137 429 -25.0


Lab.-No. TOC [%] S [%] S1 [mg HC/g rock]

S2 [mg HC/g rock]

S3 [mg CO2/g rock]

Tmax [°C]

HI [mg HC/g TOC]

OI [mg CO2/g TOC]


δ13 COM [‰]

0020799 1.2 0.2 2.7 3.3 447 220 271 -26.10020805 0.3 0.1 0.2 2.7 439 82 931 0020815 0.5 0.1 0.5 4.1 440 98 860 -23.60020818 0.47 0020820 0.5 0.0 0.3 3.7 438 67 774 -23.90020831 1.4 0.1 2.9 3.3 445 207 233 -24.20020836 0.8 0.1 1.8 2.5 444 224 301 -25.90020839 0.9 0.1 1.5 3.0 444 170 326 -24.50020847 0.46 0020856 0.8 0.1 0.8 3.7 441 101 450 -24.90020864 0.8 0.1 1.3 2.7 445 158 335 -24.50020869 1.4 0.2 3.9 2.3 449 290 168 -23.50020875 0.5 0.1 0.3 2.9 440 66 610 -25.20020886 0.67 0020887 0.1 0.1 0.7 0.6 403 532 459 0020894 0.4 0.1 0.5 1.2 442 113 287 -25.90020894 0.56 0020902 0.3 0.1 0.8 1.0 446 292 347 -26.2Whitehill Shale, onshore Namibia 0190107 0.84 0.02 1.3 -24.40190108 0.67 0.00 3.5 -21.50190109 1.52 0.03 about 3.1 -19.40190110 1.98 0.15 above 1.2 -18.60190111 0.18 0.01

Kudu reservoir contents

Table A.5: Results of the analysis of the Kudu natural gas. For comparison purpose the results of the analysis by (ANDRESEN 1992) are also given. 0000906

(BGR) 0000907 (BGR)

A-13827 A-13852 A-14012 A-14244

Methane [%] 96.8 96.8 86.9 94.5 87.1 94.4Ethane [%] 1.7 1.8 1.4 2.3 1.3 2.4Propane [%] 0.2 0.2 0.1 0.4 0.1 0.4iso-Butane [%] 0.0 0.0 0.0 0.1 0.0 0.1Butane [%] 0.0 0.0 0.0 0.1 0.0 0.1i-Pentane [%] 0.0 0.0 n-Pentane [%] 0.0 0.0 2methyl-pentane [%]

0.5 0.0 0.0 0.0

3methyl-pentane [%]

0.4

Hexane [%] 1.5 0.0 0.0 0.0iso-Heptane [%] 0.0 0.0 Nitrogen [%] 0.9 0.9 9.1 2.5 11.5 2.5C2+ 2.0 2.1 4.0 3.0 1.4 3.1iC4/nC4 1.0 1.0 0.3 1.0 0.5 1.0


0000906 (BGR)

0000907 (BGR)

A-13827 A-13852 A-14012 A-14244

C1/(C2+C3) 50.9 48.6 55.2 34.7 62.4 33.7C2+C3 1.9 1.99 1.6 2.7 1.4 2.8δ13C1 -36.7 -36.7 -37.1 -37.9 -37.0 -37.6δ13C2 -28.2 -27.9 δ13C3 -22.6 -22.6 δCO2 -12.3 -11.9 δD -150 -152 -142.2 -135.4 -145.8 -144.4

Table A.6: Compilation of the analyses on the Kudu condensate. Samples numbers 0000908, 0000909 and 0000910 indicate aliquots of the same condensate sample.

0000908 0000909 0000910 δ 13 C -24.5 -24.5 -24.6 Benzol/Toluol 0.29 Benzol/Cyclohexan 1.07 Benzol/Heptane 0.85 Cyclohexan/Heptane 0.79 Toluol/Octan 1.31 Methylcyclohexan/Toluol 0.68 Pristane/nC17 0.27 Phytane/nC18 0.15

Appendix B: Basin Modelling 158

Appendix B: Basin Modelling

Table B.1: Compilation of third- and second-order sequences in the postrift sediments of the Orange basin as defined by (BROWN et al. 1995). The alphanumerical nomenclature for the sequences developed by (BROWN et al. 1995) is not purely hierarchical but represents an empirical system comprising various orders (MUNTINGH and BROWN 1993). Dating the unconformities relies on Soekor’s microfossil interpretation (MUNTINGH and BROWN 1993).

4th-order (simple) sequences (composed of 5th-order parasequences)

3rd-order (fundamental) sequences (composed of 4th-order parasequences)

3rd-order composite sequences and component 4th-order sequence sets 1A-B (126.0-121.5) 2A-E (121.5-102.5) 3A-C (120.5-119.5) 4A-E (119.5-118.5) 5A-C (118.5-117.5) 7-8 (116.0-115.0) 9-10 (115.0-113.5) 11-12 (113.5-112.0) 14B-D (100.5-99.0) 14H-I (99.5-94.0) 14J-K (94.0-93.0) 15C-E (90.5-90.0) 21A-B (68.0-67.0)

2nd-order supersequences 1-5 (126.0-117.5) 6-12 (117.5-112.0) 13 (112.0-103.0) 14 (103.0-93.0) 15-16 (93.0-80.0) 17-20 (80.0-68.0)

Supersequences and component 2nd-order supersequences

1A,B (126.00-121.50) 2A (121.50-121.30) 2B (121.30-121.10) 2C (121.10-120.90) 2D (120.90-120.70) 2E (120.70-120.50) 3A (120.50-120.15) 3B (120.15-119.85) 4A (119.50-119.30) 4B (119.30-119.10) 4C (119.10-118.90) 4D (118.90-118.70) 4E (118.70-118.50) 5A (118.50-117.15) 5B (117.15-117.85) 5C (117.85-117-50) 7A (116.00-115.90) 7B (115.09-115.82) 7C (115.82-115.74) 7D (115.74-115.66) 7E (115.66-115.58) 7F (115.58-115.50) 8A (115.50-115.40) 8B (115.40-115.32) 8C (115.32-115.34) 8D (115.34-115.16) 8E (115.16-115.08 8F (115.08-115.00) 9A (115.00-114.93) 9B (114.93-114.80) 9C (114.80-114.67)

9D (114.67-114.54) 9E (114.54-114.41) 9F (114.41-114.28) 10A (114.28-114.15) 10B (114.15-114.02) 10C (114.02-113.89) 10D (113.89-113.76) 10E (113.76-113.63) 10F (113.63-113.50) 11A (113.50-113.35) 11B (113.35-113.20) 11C (113.20-113.05) 11D (113.05-112.90) 11E (112.90-112.75) 12A (112.75-112.60) 12B (112.60-112.45) 12C (112.45-112.30) 12D (112.30-112.15) 12E (112.15-112.00) 14B (110.50-99.50) 14C (100.00-99.50) 14D (99.50-99.00) 14H (95.50.94.75) 14I (94.76-94.00) 14J (93.50-93.00) 15C (90.50-90.35) 15D (90.35-90.15) 15E (90.15-90.00) 21A (68.00-67.50) 21B (67.50-67.00)

6A (117.5-116.0) 13A (112.0-109.5) 13B (109.5-108.5) 13C (108.5-107.5) 13D (107.5-106.0) 13E (106.0-105.0) 13F (105.0-104.5) 13G (104.5-103.0) 14A (103.0-100.5) 14E (99.0-98.0) 14F (98.0-96.5) 14G (96.5-95.5) 15A (93.0-91.0) 15B (91.0-90.5) 16A (90.0-88.5) 16B (88.5-87.5) 16C (87.5-85.0) 16D (85.0-83.0) 16E (83.0-80.0) 17A (80.0-79.0) 17B (79.0-77.5) 18A (77.5-75.0) 19A (75.0-71.0) 20A (71.0-68.0) 22A (67.0)

13, 14, 15-16 (112.0-80.0)


Table B.2: Compilation of the events defined for the basin simulation study including time, interval velocity and heat flow assignment.

Event-No.

Event name Time at base [Mabp] Intervalvelocity [m/s] Heat flow [mW/m2]

36 Hiatus 5.00 62.035 Quarternary 10.00 2100 62.134 Tertiary 5 20.00 2100 62.233 Tertiary 4 30.00 2100 62.432 Tertiary 3 40.00 2100 62.631 Tertiary 2 50.00 2100 62.830 Tertiary 1 55.00 2100 63.029 Hiatus 62.90 63.228 Erosion 68.73 63.727 Erosion 75.00 64.326 Campanian / Maastrichtian 84.00 2370 65.025 Santonian 6 84.80 2370 65.024 Santonian 5 85.00 2370 65.423 Santonian 4 85.50 3200 65.422 Santonian 3 86.50 3370 65.421 Santonian 2 87.00 3370 65.920 Santonian 1 88.00 3370 65.919 Turonian 93.00 3370 67.218 Erosion 93.54 67.217 Erosion 94.29 67.416 Erosion 94.91 68.015 Erosion 95.41 68.014 Erosion 96.00 68.713 Cenomanian 102.00 4000 71.712 Aptian / Albian 112.00 4155 80.011 Source Rock 114.00 4500 94.310 Reservoir 115.00 4500 99.39 Barremian 117.50 4500 130.08 Hiatus 120.00 130.07 Hiatus 124.00 130.06 SDR wegde 4 126.00 5400 130.05 SDR wedge 3 128.00 5600 130.04 SDR wedge 2 131.00 5800 130.03 SDR wedge 1 133.00 6000 130.02 Basementtop 150.00 6500 130.01 Basement 200.00 7000 130.0


Table B.3: Lithological input parameter for the 2D basin model.

Shale Shale silty Sand Shale sandy Basalt Thermal conductivity at 20 °C [W/m/K]

1.98 2.05 3.12 2.32 2.20

Thermal conductivity at 100 °C [W/m/K]

1.91 1.94 2.64 2.12 1.95

Heat Capacity at 20 °C 0.213 2.10 0.178 0.205 0.200 Heat Capacity at 100 °C

0.258 0.25 0.209 0.248 0.220

Density [kg/m3] 2680 2677 2660 2674 2750 Initial Porosity [%] 65 62 42 57 5 Permeability at 5 % Porosity [log mD]

-5.50 -5.35 -2.00 -4.50 -16.00

Permeability at 75 % Porosity [log mD]

-1.00 -0.70 0.00 0.00 -16.00

Anisotropy permeability [log]

2.5 2.3 1.5 2.2 1.0

Anisotropy thermal conductivity

1.50 1.40 1.10 1.40 1.00

Migration Saturation 0.05 0.05 0.02 0.05 0.05 Radioactive heat source [HSU]

0 0 0 0 10

Diffusion coefficient 7.85 14.50 110.00 38.50 40.00 Table B.4a: Kinetic input parameters for calculation of petroleum generation according to QUIGLEY et al. 1987.

Reaction Type

Total Potential [mg/gTOC]

Frequency Factor [1/Ma]

Activation Energy Factor [kcal/mole]

Redcuction Factor

Activation Energy [kcal/mole]

Generation Factor [%]

Kerogen → Oil

500 1.99E+26 1.00 1.00

46 0.003 47 0.027 48 0.124 49 0.284 50 0.323 51 0.182 52 0.051 53 0.007 Kerogen → Gas

100 5.77E+31 1.00 1.00

58 0.008 61 0.074 64 0.269 67 0.383 70 0.215 73 0.047 76 0.004 Oil → Gas 1.00 3.16E+26 54.94 0.45


Table B.4b: Kinetic input parameters for calculation of petroleum generation according to TISSOT et al. 1988.

Reaction Type




Redcuction Factor



Kerogen → Oil

492 2.87E+27 1.00 1.00

40 0.014 48 0.010 50 0.057 52 0.555 54 0.293 56 0.045 58 0.012 60 0.008 62 0.006 Kerogen → Gas

1.00 1.00E+00 1.00 1.00

Oil → Gas 0.00 9.47E+27 57.00 0.45 Table B.4c: Kinetic input parameters for calculation of petroleum generation according to the bulk pyrolysis data from well DSDP 361. Reaction Type




Redcuction Factor



Kerogen → Oil

556 7.56E+25 1.00 1.00

43 0.030 45 0.070 46 0.210 47 0.270 48 0.210 49 0.100 50 0.040 51 0.020 52 0.020 53 0.010 56 0.010 57 0.010 Kerogen → Gas

1.00 1.0E+00 1.00 1.00

Oil → Gas 1.00 1.0E+00 1.00 1.00

Curriculum Vitae Sabine Schmidt Geburtsdatum: 02.03.1974 Geburtsort: Wilhelmshaven Familienstand: ledig Staatsangehörigkeit: deutsch

Ausbildung Promotion: 2000 – 2004, RWTH Aachen Geologiestudium: 1993 – 1999, Universität Kiel, Abschluss Diplom Gymnasium: 1986 – 1993, Max-Plank-Schule, Wilhelmshaven, Abschluss Abitur Orientierungsstufe: 1984 – 1986, OS Heppens, Wilhelmshaven Grundschule: 1980 – 1984, Mühlenwegschule, Wilhelmshaven

Beruflicher Werdegang Gastwissenschaftlerin, Juli 2003 bis Juni 2004

EniTecnologie, San Donato Milanese, Italien

Schwerpunkte: Geochemie, Risikoabschätzung Schwefelwasserstoff in Kohlenwasserstoffreservoiren

Wissenschaftliche Angestellte, November 2001 bis April 2003 Rheinisch Westfälische Technische Hochschule Aachen

Schwerpunkte: Beckenmodellierung, organische Geochemie Dissertation: The Petroleum Potential of the Passive Continental Margins of the Southern South Atlantic Ocean – A Basin Modelling Study – in Zusammenarbeit mit BGR Hannover

Doktorvater: Prof. Dr. Ralf Littke, RWTH Aachen

Wissenschaftliche Angestellte, Mai 2000 bis Oktober 2001 Bundesanstalt für Geowissenschaften und Rohstoffe, Hannover

Schwerpunkte: Geochemische Untersuchungen an Muttergesteinen, Gas- und Kondensatproben und Kohlenwasserstoffgasen desorbiert von Oberflächensedimenten, Beckenmodellierung

Angestellte, August 1999 bis April 2000 Geologisches Büro ALKO GmbH, Kiel

Schwerpunkte: Hydrogeologie, Baugrunduntersuchungen, Altlastensanierungen

Documents

The Petroleum Potential of the Passive Continental Margin of … · 2016. 5. 27. · Namibia and Brazil, respectively, and by samples from the Cruz del Sur well. Marine and terrestrial