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 southwestern 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

II

Abstract

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

IV

Kurzfassung

(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 AJ1 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 KWBildungspotenzial 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

VI

Kurzfassung

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

X

Table of Contents

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 5.3.1 Surface geochemical prospecting..................................................................................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 6.1.1 Surface geochemical prospecting..................................................................................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

XII

Table of Contents

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 7.1.1 Surface geochemical prospecting..................................................................................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

XIV

List of Figures

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 nearsurface 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

XVI

List of Figures

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

XVIII

List of Abbreviations

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).

2

2

Organic Geochemistry

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 Geochemistry

3

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

4

Organic Geochemistry

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

Organic Geochemistry

5

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.

6

Organic Geochemistry

0.01 0.01 1

HA “Humin”

10

CH + AA + FA L

Kerogen elemental analysis (atomic ratios) H/C

0.15

0.25

Type III Inherited bitumen HC (+N,S,O)

1000

Ro ~ 0.5

Kerogen

Type III Oil Gas

10000

Diagenesis

Type II

100

Depth [m]

O/C

0.4 0.6 0.8 1.0 1.2 1.40.05

0

Type II Carbon residue

20 40 60 80 100 0 20 40 60 80 100 Water content [weight-%] Composition of disseminated organic matter

Catagenesis Ro ~ 2.0

Metagenesis

Ro ~ 4.0 Metamorphism

0 1 2 3 4 5 Vitrinite reflectance [% in oil]

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

Organic Geochemistry

7

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 organicmatter-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

8

Organic Geochemistry

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.

Organic Geochemistry

2.5.1

9

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

10

Organic Geochemistry

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).

Organic Geochemistry

2.5.4

11

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 nonstructured (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

12

Organic Geochemistry

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:

δ

13

( C‰ =

13

C / 12 C

(

)

sample

13

−

12

(

C/ C

13

)

C / 12 C

)

PDB

⋅ 1000 ‰

Eq. 2.4

PDB

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:

δD ‰ =

(D / H )sample − (D / H )SMOW (D / H )SMOW

⋅ 1000 ‰

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 1974). The

12

12

C and

13

C species in the carbon compound (GALIMOV

C-12C bonds are ruptured more frequently than

12

C-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

13

C-12C bond (BRODSKY et al. 1959; SACKETT

Organic Geochemistry

13

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).

Marine

kerogen marine DIC and carbonates

marine higher plants marine organisms marine plankton

2°C

30°C

atm. CO2 cle

C4 cy

Terrestrial / Freshwater

cellulose Salt marsh plants & tropical grasses freshwater plankton river / lake DIC and carbonates

Diagenetic / Catagenetic

coal crude oil abiogenic methane thermogenic natural gas CR

-120

ycle C3 c

bulk plants

-60

MF -50

PDB standard

bacterial methane -40

δ 13C

-30

-20

-10

0

+10

(per mil vs. PDB)

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.

14

Organic Geochemistry

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

13

C,

13

C

(ABELSON and HOERING 1961; VOGLER 1980). As a result, lipids are relatively “light” (i.e. enriched in 13

12

C) and proteins and carbohydrates are relatively “heavy” (i.e. enriched in

C) (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,

12

C

(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

12

C. 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

12

C-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).

Organic Geochemistry

2.6.3

15

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”

12

C 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

16

Organic Geochemistry

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

12

C-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 13

C. 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

Organic Geochemistry

17

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:

k i = Ai ⋅ e

−

Ei R⋅T

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

18

Organic Geochemistry

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).

Greenriver Shale Type I

400 200 0 30 40 50 60 70 80 Activation energies [kcal/mole]

300

Paris Basin Type II

200 100

Xio [mg/g initial TOC]

600

Xio [mg/g initial TOC]

Xio [mg/g initial TOC]

800

0 30 40 50 60 70 80 Activation energies [kcal/mole]

100 80

Mahakam Delta Type III

60 40 20 0 30 40 50 60 70 80 Activation energies [kcal/mole]

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

Organic Geochemistry

19

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

20

Organic Geochemistry

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

3

21

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 southwestern 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 breakup 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

22

Geology of the Namibia and South African rifted continental margin

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

M M3 M 0 M42

G Walvis G

M7

M4 M0

M2

M2 M 0 M9 M4

M0

SO UT H

SO UT H

AF RI CA

Torres Arc h

AF RI CA

AM ER IC A

AM ER IC A

used an old line of weakness for its development (WILSON 1966).

G

Fracture Zone

Malvinas Plateau

Malvinas Plateau

Malvinas Plateau

Albian (100 Ma)

is Walvge Rid

AF RI CA

Rio Grande Rise

G

M2

M0

M M2 0 M7

M3

G

M2 M4

AM ER IC A

Torres Arc h

M4 M9

G

M4 M0

M2

M2 M 0 M7 M4

Fracture Zone

Aptian (115 Ma)

SO UT H

M M03

G

M0

M M42

G Walvis

AF RI CA

G

Torres Arc h

M4 M0

SO UT H

AM ER I

CA

Titonian - Berriasian (150 - 140 Ma)

Fracture Zone

Malvinas Plateau

Campanian (80 Ma)

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

Geology of the Namibia and South African rifted continental margin

23

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.

Niger Basin

Karoo Basins

AFRICA

Marginal Basins DSDP Sites

361

Ki b a ride

Paraná Basin

Fa

Valdez-Rawson Basin San Jorge Basin m

East Falkland Basin

361

ha gul

Mo c

Agulhas Basin Z sF

30 0

0m

Falkland Plateau 30 0 0

Magellanes Basin

200

Main Karoo Basin

Orange Basin

A a nd l k l

d

Kudu AJ-1

SOUTH ATLANTIC

Colorado Basin

Huab

Basin Luderitz Basin

Pelotas Basin

Salado Basin

Toscanini

Walvis Ridge Walvis

m

a mb

Namibe Basin

Iru

m

Santos Basin Rio Grande Rise

Mossamedes Basin

20 0

Basin

t el B e

ique

SOUTH Reconcavo Basin AMERICA Espirito Santo

Belt

Karoo Basin Congo Basin Benguela Basin

Pernambuco-Paraiba Basin Sergipe-Alagoas Basin

Campos Basin

Belt

Gabon Basin

Pontiguar Basin

m

Malvinas Basin

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

24

Geology of the Namibia and South African rifted continental margin

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).

Megasequences

Q Transitional Synrift II R Synrift I M

T

TRIASSIC PERMIAN

U L

W

A-J1

Basin and Range

Prerift

U

Kudu Synrift

N P

Drift

L Thermal sag

CRETACEOUS JURASSIC

Seismic Horizons

TERTIARY

Source Potential

Facies

Shelf clastics

Volcanics

Slope Clastics

Alluvial outwash clastics

Restricted marine shales oil source

Turbidites

Braided fluvial clastics

gas source

Open marine shales

Marginal marine sandstones

Figure 3.3: Stratigraphy and seismic horizons of the south-west African offshore, modified from Light et al. (1993b).

Geology of the Namibia and South African rifted continental margin

25

The Basin and Range megasequence is terminated by the Late Jurassic (i.e. KimmerdgianOxfordian, 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

PERMIAN

TRIASSIC

Aptian Barrem. Hauteriv. Valangin Berriasian

S

Kudu

Late Drift

2012/13-1

Lüderitz/ Orange Basin

Early Drift

Maastr. Campian Santonian Conianian Turonian Cenoman. Albian

Toscanini

Walvis Basin

Syn & SDRS

Paleocene

Onshore Huab/Etjo Areas

Prerift

Eocene

Paleog. Neogene TERTIARY

Oligocene

Early Late CRETACEOUS

Miocene

Walvis Ridge DSDP Boreholes

Age Pleist. Pliocene

S. Namibe Basin

PROTEROZOIC to E. CAMBIRAN

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

26

Geology of the Namibia and South African rifted continental margin

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

Geology of the Namibia and South African rifted continental margin

27

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

28

Geology of the Namibia and South African rifted continental margin

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 westwardprograding Orange River deltaic complex (MUNTINGH and BROWN 1993). Kudu 9A-1 0

Orange Basin

Walvis Ridge

Plio Mio Olig

50

100

Eoc Pal Maas Camp Sant Con Tur Cen Alb

0

100

m/Ma

Apt Barr Haut Val Berr Port

150

Kimm Oxf Call Bath

0

100

200

m/Ma

300

0

100

m/Ma

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-

Geology of the Namibia and South African rifted continental margin

29

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

30

Geology of the Namibia and South African rifted continental margin

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). 1 Flows

3

Dyke injection

2 Continental crust

Mantle

4 Sea level Spreading centre

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).

Geology of the Namibia and South African rifted continental margin

31

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 (O´CONNOR 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; O´CONNOR 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; O´CONNOR 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; O´CONNOR 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.

32

Geology of the Namibia and South African rifted continental margin

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

4

33

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).

34

Petroleum systems of the Namibian and South African rifted continental margin Petroleum System Events Geologic Time Scale

Source Rocks

Reservoir Rocks

Trap Seal Rocks Formation

Generation, Migration, Accumulation

Piacenzian Zanclean Messian Tortonian

Miocene

NEOGENE

Pliocene

QUARTERNARY

Serravallian Langhian Burlandigian

Late Middle

Chattian Rupelian Turbiditic

Priabonian Bartonian

reservoirs in

Lutetian transitional

Ypresian

Early

PALEOGENE

Aquatanian

Thanetian Selandinian Danian

Seal rocks DSDP 360, 361

sequence in Creatceous

Late

and Tertiary

Campanian Santonian Turonian

Cenomanian

Mature drift, north WR

Early Middle Late

Aptian Barremian Hauterivian Valanginian Berriasian Tithonian Kimmeridgian Oxfordian Callovian Bathonian

Transitional (Kudu/ DSDP 361) Synrift (AJ1)

Oil expulsion in the Kudu SR Fluvial sst (Ibuhbesi) Kudu reservoir

Transitional (Kudu)

Kudu

Synrift

DSDP 330 and 511

Bajocian Aalenian Toarcian Pliensbachian

Etjo

Sinemurian

Late

Botucatu/ Plateau sst.

Norian

EarlyMiddle

Landian

Late

Carnian

Kazanian

Anisian Olenekian Induan Tatarian

Kungurian Artinskian

Early

TRIASSIC

Mature drift

Rift basins

Hettangian Rhaetian

PERMIAN

sediment pile

Albian

Early

JURASSIC

CRETACEOUS

Maastrichtian

Sakmarian

Whitehill/Verbrande Berg Fm.

Gudaus Fm. Tsrabis Fm. Verbrande Berg Fm.

Asselian Dwyka Fm.

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).

Petroleum systems of the Namibian and South African rifted continental margin

4.2

35

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).

36 4.2.1.3

Petroleum systems of the Namibian and South African rifted continental margin 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.

Petroleum systems of the Namibian and South African rifted continental margin

4.2.3

37

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 southwestern 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

38

Petroleum systems of the Namibian and South African rifted continental margin

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).

Petroleum systems of the Namibian and South African rifted continental margin 9A-3

4 km 245

Wells hung on Top Oligocene datum

400

A = Early Eocene B = Late Eocene B BASE TERTIARY A

9A-1

7 km

9A-2

Not dated

Some Early Miocene

39

400

Depositional environment

480

Early Oligocene

710 780

795 810

Mid to outer shelf

830

1015

Early Campanian

1070

Upper slope

Late Santonian

Siltstone with limestone Interbedded clayand siltstone Claystone Limestone Sandstone Volcanics

3210

3253

3255

Late Conician 3455 Mid Turonian Cenomanian

3395

3405 3485

3493 3554

3528

Early-Late Albian

3643

3659

3825

Early Aptian

3809

3848

3978

4067

4089

Earliest Aptian

4132 4228

Reservoir Interval

Upper marine sand

2

Lower aeolian sand

1

2

4226

TD = 4526 m

Late Barremian

4252

1

2

TD = 4552 m

Upper slope

1230

1

? Early Barremian

Base of slope Abyssal / Base of slope Upper slope / outer shelf Possible equivalent source rock horizon to that in Bredasdorp Basin, offshore South Africa Depth in meters

TD = 4540 m

Figure 4.2: Stratigraphy and lithology of the Kudu wells, modified from BAGGULEY (1997).

40

Petroleum systems of the Namibian and South African rifted continental margin

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

Petroleum systems of the Namibian and South African rifted continental margin

41

(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

(http://www.namcor.com.na/exploration_history.htm).

and

seal

were

encountered

42

Methods

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).

KOH

H2O

P

E

D V3

C

P

E

V3

D

100 cm

C

Vacuum

B B

A

KOH

30

cm

A

50 cm

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), splitinjector and temperature program. Detection of the hydrocarbon gas was performed by two FIDs. Helium was used as carrier gas.

44

Methods

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 5.1.2.2

45

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 heatingup 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

46

Methods

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):

2 ( n − N ) + n2k 2 R= (n + N )2 + n 2 k 2

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

5.1.2.4

47

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

48

Methods

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 89011 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).

Water Flow (Paleopressure)

Geologic Heat Flow (Paleotemperature) Hydrodynamic 100

Solution Thermodynamic

Geochemical

Grid system for data storage and solutions

Maturity

10 1

1 2 Rm (%) Extract 10 100 1000

Rm (%)

Input

Deterministic Dynamic Model

0

Determinations Hydrocarbon yield calculations

0.5 1.0 1.5

Pc

J

J

Pb

JPw

Secondary migration determinations

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)

50 •

Methods 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.

52

5.2.5

Methods

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

WSW

Kudu

ENE

54

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).

Upper boundary

A 1

2

erosional truncation

3

toplap

concordance

Lower boundary

B 1

2

onlap

baselap

toplap

downlap

concordance

OVERLYING UNCONFORMITY

offlap

C onl ap

onlap downlap

3

truncation

UNDERLYING UNCONFORMITY

INTERNAL CONVERGENCE

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).

56

Methods

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 depositionalshoreline 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

wa

ott

om

tum da

accumulated sediment

Centre of the Earth

subsidence / uplift

eustacy

B

b te r

rel s e a a t iv e leve l

eustacy

a se

Water d ep t h

e fac sur

sea surface space available “accomodation”

A

57

water bottom

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).

58

Methods

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

Zb

S load S total

Sediments

t

Decompaction

sea level

Hw paleobathymetry Z0

(e)

Z ub

ZS Hw

Basement ZS

Time t (d)

(c)

initial basement depth

Zb

S tecto

Present (b) Water

Z0 0

Initial (a)

59

Unloading

basement depth

Z ub unloaded basement depth S total total subsidence (Zb- Z0)

S load subidence due to loading (Zub- Zb) S tecto tectonic subsidence (Zub- Z0)

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:

 ρ − ρw   T = d w  m  ρm − ρs 

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

60

Methods

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:

To =

t (1 − Φ z ) (1 − Φ O )

with Φ0: original depositional porosity, Φz: present Eq. 5.3 day porosity at depth z, t: present day sediment thickness

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):

TTS = d w + t S ⋅

(ρ s − ρ m ) − ∆S L (ρ w − ρ m )

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):

d (t ) = 2500 + 350t 0.5 m

d (t ) = 6400 − 3200 exp

 −t     62.8 

m

70 Ma since rifting

Eq. 5.5

after more than 20 Ma since rifting

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:

β −1 = 1 −

TTS ( ρ m − ρ w ) t c (ρ m − ρ c )

with tc: crustal thickness, ρw, ρs and ρm for densities Eq. 5.7 of water, sediment, and upper mantle, respectively, TTS: total tectonic subsidence

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

62

Methods

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.

q = −K

with q: heat flow, K: coefficient of thermal Eq. 5.8 conductivity, T: temperature at a given point in the medium and y: coordinate in the direction of the temperature variation

dT dy

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:

q=

K ⋅ Tm tc

t  2⋅ β  π  −τ  with K: thermal conductivity, Tm: temperature Eq. 5.9   1 sin e +   β   of the mantle, tc: crustal thickness, here π    assumed to be 125 km, β: stretching factor, t:  time since rifting, τ: thermal time constant (62.8 Ma)

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

Data pool 80° W

60° W

20° W

0°

20° E

40° E

20° S

2 1/ 6 86 01

0018665/6 0 0018663/4 0018655-60 0018647/8 0018651-54 0018649/50 0018647/8 0018645/6

Whitehill Kudu

Irati 0112801-9 + 0107550-79

0010907/8

40° S

Cruz del Sur0010909/10

ECL 89-011 DSDP 361

0010905/6 0010911/12 0010913-16 0010917-20

60° W

60° S

60° S

0112810-70 80° W

20° S

40° S

40° W

0° S

0° S

5.3

63

40° W

20° W

0°

20° E

40° E

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.

5.3.1

Surface geochemical prospecting

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) Colorado Basin, offshore Argentina, “Puerto Deseado” (2001) Malvinas Basin, offshore Argentina, Puerto Deseado” (2001) Offshore south-western Africa, Nausicaa IMAGES II (MD 105) cruise 1996 Offshore Argentina, Meteor cruises M29/1 (1994) and M46/3 (1999/2000)

Number of samples 39

Range of water depth [m] 88 - 4720

Maximum core length [m] 2.70

60

143 – 670

2.70

22

105 - 3606

39.65

16

2373 4777

14.66

Storage temperature [°C] not exceeding -20 not exceeding -20 +4 not exceeding 0

Sample provider Repsol-YPF, Argentina Repsol-YPF, Argentina University Bordeaux, France University Bremen, Germany

64

5.3.2

Methods

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

Kudu 9A-2 and 9A-3, offshore Namibia (kindly provided by Namcor, Namibia) DSDP 361, offshore South Africa (kindly provided by the Ocean Drilling Project) Whitehill, onshore Namibia (kindly provided by University Würzburg, Germany) Cruz del Sur, offshore Argentina (kindly provided by Repsol-YPF, Argentina) Irati Shale, onshore Brazil (kindly provided by Petrobras, Brazil)

38

ground cutting samples

24

core samples

24/4/24/6/20

5

outcrop samples

5/5/-/4/4

182

cutting samples

23/-/23/10/19

2

outcrop samples

2/2/2/2/2

5.3.3

Number of analysed samples TOC/TS/RockEval/Rr/δ13COM 38/-/38/6/36

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.

66

Results and Interpretation

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.

6.1.1

Surface geochemical prospecting

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.

CH4 [ppb*] C2H6 [ppb] C3H8 [ppb] C4H12 [ppb] C5H10 [ppb] CH4 [hc-%] C1/ (C2+C3) δ13CH4 [‰] δ13C2H6 [‰] δ13C3H8 [‰]

Colorado Basin, Argentina 1.6 to 73.5 (40) 0.1 to 6.4 (40) up to 3.5 (40) up to 2.6 (40) up to 1.1 (40) 61.1 to 96.6 (40) 1.9 to 38.0 (40) -50.5 to -33.4 (40) -39.9 to -27.1 (36)

Malvinas Basin, Argentina 9.9 to 126 (61) 1.4 to 6.1 (61) up to 2.2 (61) up to 1.7 (61) 90 to 98 (61) 10.9 to 53.6 (61) -55.3 to -37.3 (61) -34.3 to -28.1 (61)

SW Africa 3.9 ppb to 2973 (21) up to 113.6 (21) up to 69.6 (21) up to 79.7 (21) up to 245 (21) 62 to 100 (21) 2.6 to 54.3 (21) -77.0 to -31.5 (21) -35.2 to -22.6 (19) -19.4 and -20.9 (2)

Argentina, Meteor cruises 7.9 to 462.1 (15) 2.1 to 10.0 (15) 1.1 to 3.8 (15) up to 2.8 (15) 64.4 to 99.0 (15) 3 to 134 (15) -80.4 to -36.5 (15) -34.3 to -26.8 (15)

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

Results and Interpretation

67

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). 100000 Colorado Basin Malvinas Basin Africa Argentina (Meteor)

Bacterial Thermal

1000

x

10

ria

marine

i

l

m

100

est

C 1 /(C 2+C3 )

10000

i

ter r

A

n

g

1 -80

-100

-60

δ

13

-40

-20

C - Methane (‰)

C2+ [%]

B

0

10

20

30

40

50

-75.0

δ13C methane per mil PDB

-70

Colorado Malvinas Argentinien (Meteor) Africa

B

-65.0

B = microbial gas T = associated gas To = associated with oil (initial phase of formation) Tc = associated with condensate TT = non-associated TT (m) = marine nonassociated gas TT(h) = non-associated gas from NW German coals M = mixture of intermediate composition Md = deep migration Ms = shallow migration

-60 -55.0

M To

-50

Ms

-45.0

Tc

TT(m)

-40

Md -35.0

mixed source

-30 -25.0

TT(h)

-20 0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

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).

68

Results and Interpretation

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).

Results and Interpretation

69

-15 Colorado Basin Malvinas

-20

Argentina

terrestrial

Africa

Rr (%)

2.3 2.5

-30

1.5

-35

0.6

1

13

δ CMethane (‰)

-25

2

2

marine 1.5

Rr (%)

-40

1 0.6

-45 -50 -45

-40

-35

-30 -25 δ13CEthane (‰)

-20

-15

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.

70

6.1.2

Results and Interpretation

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 [%]

Kudu 9A-2 (BGR)

Tmax [°C]

S1 [mg HC/g rock]

0.9 to 2.3 (20)

417 to 556 (20)

0.15 to 0.56 (20)

Kudu 9A-2 (Soekor) Kudu 9A-3 (BGR) Kudu 9A-3 (Soekor) DSDP 361

1.0 to 3.3

449 to 520

1.1 to 2.0 (18) 1.0 to 2.0

Whitehill shale

0.2 to 2.0 (5)

Cruz del Sur

0.1 to 4.0 (23)

Irati shale

12.6 to 21.9 (2)

6.1.2.1

0.2 to 13.2 (24)

TS [%]

12.2 to 14.1 (4) up to 0.2 (5)

4.2, to 5.8 (2)

HI [mg HC/g TOC] 18 to 38 (20)

OI [mg CO2/g TOC]

PI

Rr [%]

δ13COM [‰]

63.9 to 157.7 (20)

0.3 to 0.5 (20)

1.22 to 1.78 (6)

-26.2 to 24.8 (20)

0.77 to 1.53

10 to 44

24.5 to 121.4

0.1 to 0.6

0.32 to 0.62 (18) 0.24 to 0.42

1.32 to 1.66 (18) 0.69 to 1.27

17 to 34 (18) 18 to 27

69.1 to 138.5 (18) 48.7 to 126.0

0.3 to 61.2 (24)

0.5 to 5.9 (24)

15 to 556 (24)

33 to 497 (24)

0.2 to 0.3 (18) 0.27 to 0.44 up to 0.1 (23)

S2 [mg HC/g rock] 0.21 to 0.71 (20)

S3 [mg CO2/g rock]

0.14 to 0.61

0.16 to 0.71

420 to 515 (18) 441 to 499

0.10 to 0.27 (18)

375 to 432 (24)

up to 1.1 (24)

0.12 to 0.31

1.15 to 1.75 (20)

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)

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)

0.03 to 0.33 (23) 0.06 to 0.04 (2)

-25.6 to 23.8 (18)

0.27 to 0.35

-28.1 to 23.0 (20)

1.2 to 3.5 (4) 0.32 to 0.67 (109 0.48 (2)

-24.4 to 18.6 (4) -26.2 to 20.2 (19) -23.8 to 20.6 (2)

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,

Results and Interpretation

71

0020831 and 0020869). TOC analyses by Western Atlas (STARLING 1994) shows additional samples with high TOC contents in the prerift section (figure 6.4). 18 Kudu 9A-2

16

Kudu 9A-3

Number of samples

14

DSDP 361 Cruz del Sur

12

Whitehill Irati

10 8 6 4 2 0

15 5 -2

5 -1

0 -1

-5

-2

-1

10

5

2

1

0

TOC [%]

Figure 6.3: Total organic carbon contents of samples from different locations offshore SW Africa and Argentina. TOC [%] 0

0,5

1

1,5

2

2,5

3

443 645 855

passive margin

1065 1275 1485 1695

Depth [m]

1905

post-rift

2115 2335 2555 2765 2973 3183 3393

syn-rift

3603 3813 3963

pre-rift

4173

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).

72

Results and Interpretation

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).

TOC [%] 0

1

2

3865

TOC [%] 3

4

0

1

2

3

4

3839

3875

3848

3885 3857 3918 3869

3927

3878

3939

3887

3957 4107

3899

4119

3908

4128

3917

4137

3929

4149

3938

4158

3947

4167 3959 4179 3968 4188 3977

4197

3989

4209

3998

4218

TOC [%] Soekor TOC [%] BGR

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:

HI =

S 2 ⋅ 100 TOC

Eq. 6.1

OI =

S 3 ⋅ 100 TOC

Eq. 6.2

PI =

S1 S1 + S 2

Eq. 6.3

Results and Interpretation

73

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.

I

Hydrogen Index (mg HC/g TOC)

900

Irati Kudu 9A-2 Kudu 9A-3 DSDP 361 Cruz del Sur

750

II

600

450

300

150

III 0 0

50

100

150

Oxygen Index (mg CO2/g TOC)

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.

74

Results and Interpretation

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.

Results and Interpretation

75

Vitrinite reflectance [%] 0.1

1

10

0

500

Kudu 9A-2 (Soekor) Kudu 9A-2 (BGR) 1000

DSDP 361

Depth [m]

1500

2000

2500

3000

3500

4000

4500

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

76

Results and Interpretation

(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

Results and Interpretation

77

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. Sample

0011277 0011280 0011281 0011287 0020719 0020720

Location

TOC [%]

DSDP 361, Cape Basin, South Africa DSDP 361, Cape Basin, South Africa DSDP 361, Cape Basin, South Africa DSDP 361, Cape Basin, South Africa Irati Shale, Brazil Irati Shale, Brazil

HI [mg hc/ g rock]

Activation Energy [kcal/mole] of Maximum Initial Petroleum Potential [mg/g TOC] Optkin BC

11.0

407

50

47

11.5

36

63

48

13.2

28

63

51

11.0

556

50

47

12.6

616

48

47

21.9

724

49

47

Range of Activation Energies [kcal/mole]

Arrhenius Factor [s-1]

Error Function (Optkin)

Optkin BGR 44 - 70

Optkin BGR 4.1E+13

0.333

40 - 52

3.4E+12

53 - 87

1.8E+17

44 - 53

5.1E+12

54 - 88

2.6E+17

45 - 56

2.8E+13

43 - 70

2.5E+13

43 - 57

2.4E+12

41 - 55 44 - 51 40 - 63 44 - 51

3.7E+12 2.3E+12 7.4E+12 2.3E+12

2.632 2.130 0.281 0.282 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

78

Results and Interpretation

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.

norm. gen. potential

0,4 0011277 (DSDP 361, Aptian) 0011287 (DSDP 361, Aptian) 0020719 (Irati, Permian) 0020720 (Irati, Permian) 0011280 (DSDP 361, Aptian) 0011281 (DSDP 361, Aptian)

0,3

0,2

0,1

0,0 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57

Ea (kcal/mol)

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

Results and Interpretation

79

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

0000907

A-13827

A-13852

A-14012

A-14244

(BGR)

(BGR)

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

0.5

0.0

0.0

0.0

1.5

0.0

0.0

0.0

2methyl-pentane [Vol-%] 3methyl-pentane

0.4

[Vol-%] Hexane [Vol-%] 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

δ C1

-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

13

80

Results and Interpretation C2+ [%] 0

100

Thermal m

marine i

10 1 -100

-80

x

i

n

g

-60

-40

δ 13 C - Methane (‰)

-20

δ13C methane per mil PDB

1000

Bacterial

ial

C1 /(C2 +C3)

10000

-70 Analysis BGR (2000) Analysis IFE (1992)

t er res tr

100000

10

20

30

40

50

B

-60

M To

-50

-40

Ms

TT(m) Md

Tc mixed source

-30 TT(h)

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 = nonassociated, 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).

Results and Interpretation

81

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).

n-C11

pA

n-C12

n-C10

160 140

n-C14

n-C13

Methylcyclohexane Toluol

10

20

30

n-C18 n-C19 n-C20 n-C21 n-C22 n-C23 n-C24 n-C25

20

Phytane

n-C16

n-C12

40

Pristane n-C 17

n-C15

60

n-C8

80

n-Heptane

100

n-C9

120

40

50

60 min

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 + 3Methylhexane + 1,cis-3-Dimethylcyclopentane + 1,trans-3-Dimethylcyclopentane + 1,trans-2-

82

Results and Interpretation

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

Results and Interpretation

83

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

84

Results and Interpretation

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.

Results and Interpretation

85

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 breakup 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 openmarine 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).

86

Results and Interpretation

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).

Results and Interpretation

87

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

88

Results and Interpretation

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.

Results and Interpretation 6.2.3.2

89

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.

90 6.2.3.3

Results and Interpretation Estimation of the thickness of eroded strata using reflection seismic crosssections

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

Results and Interpretation

91

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 d (t ) = (2500 + 350t 0.5 ) ⋅ 0.4 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.

92

Results and Interpretation

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

Results and Interpretation

93

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.

Mesozoic K

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

94

Results and Interpretation

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

Results and Interpretation

95

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.

Kudu 9A-2

Depth (m)

A 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

Temperature [°C] 0 - 25 25 - 50 50 - 75 75 - 100 100 - 125

125 - 150 150 - 175 175 - 200 200 - 225 225 - 250

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.

Kudu 9A-2

Depth (m)

B 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

Event 9 (117.5 - 115 Mabp): Deposition of Barremian sediments.

Kudu 9A-2

Depth (m)

C 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

Event 10 (115 - 114 Mabp): Deposition of the reservoir rock interval.

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

96

Results and Interpretation Kudu 9A-2

Depth (m)

D 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

Event 11 (114-112 Mabp): Deposition of the Barremian to Aptian source rock interval.

Depth (m)

E

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

Kudu 9A-2

250 km

Event 12 (112 - 102 Mabp): Deposition of Aptian to Albian sediments

Kudu 9A-2

Depth (m)

F 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

Event 13 (102 - 96 Mabp): Deposition of the Cenomanian rocks.

Kudu 9A-2

Depth (m)

G 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

Events 14 - 18 (96 - 93 Mabp): Erosion

Figure 6.19: Sedimentary history of the seismic section through the Kudu gas field offshore Namibia, continued.

Results and Interpretation Kudu 9A-2

H Depth (m)

97

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

Event 19 (93 - 88 Mabp): Deposition of Turonian rocks.

Kudu 9A-2

Depth (m)

I 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

103 °C

134 °C

125 °C 139 °C 140 °C 150 °C 143 °C 143 °C

Events 20 - 25 (88 - 84 Mabp): Deposition of Santonian sediments.

Kudu 9A-2

Depth (m)

J 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

126 °C 125 °C 158 °C

°C 175 °C 188 175 °C 182 °C

172 °C

158 °C

Event 26 (84 - 75 Mabp): Deposition of Campanian to Maastrichtian rocks.

Kudu 9A-2

Depth (m)

K 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

Events 27 - 29 (75 - 55 Mabp): Erosion

Figure 6.19: Sedimentary history of the seismic section through the Kudu gas field offshore Namibia, continued.

98

Results and Interpretation Kudu 9A-2

Depth (m)

L 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

0 km

250 km

122 °C

154 °C

186 °C

181 °C

151 °C 167 °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.

Depth (m)

M 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

GP 2

GP 43

GP 80

Events 33 - 36 (30 - 0 Mabp): Deposition of Tertiary and Quarternary sediments. State of the section today.

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.

A Burial History Overlay/Template

149 [Mabp]

130

120

Temperature

110

100

90

80

70

60

50

40

30

20

10

0

0 [m] 2000 3000 4000 5000 6000

Temperature [°C] 0 - 25

125 - 150

7000

25 - 50 50 - 75 75 - 100 100 - 125

150 - 175 175 - 200 200 - 225 225 - 250

8000 9431

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.

Results and Interpretation

99

B Burial History Overlay/Template

149 [Mabp]

130

120

Temperature

110

100

90

80

70

60

50

40

30

20

10

0

90

80

70

60

50

40

30

20

10

0

0 [m] 2000 3000 4000 5000 6000 7000 8000 9431

Temperature [°C] 0 - 25 25 - 50 50 - 75 75 - 100 100 - 125

125 - 150 150 - 175 175 - 200 200 - 225 225 - 250

C Burial History Overlay/Template

149 [Mabp]

130

120

Temperature

110

100

0 [m] 2000 3000 4000 5000 6000 7000 8000 9431

Temperature [°C] 0 - 25 25 - 50 50 - 75 75 - 100 100 - 125

125 - 150 150 - 175 175 - 200 200 - 225 225 - 250

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).

100

Results and Interpretation Kudu 9A-2 0

0 km

250 km

Depth (m)

1000 2000 3000 4000 5000 6000

84 Mabp 85 Mabp 85 Mabp 103 Mabp 79 Mabp 104 Mabp 98 Mabp 99 Mabp

86 Mabp

86 Mabp

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.

Depth (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.

Results and Interpretation

101

Kudu 9A-2

Depth (m)

0

0 km

250 km

1000 2000 3000 4000

0.04 0.170.24 0.25

0.21 0.04

0.04

5000 6000 7000

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

120

120

100

100

100

80

80

80

60

40

20

Time at Base [Ma]

120

Time at Base [Ma]

Time at Base [Ma]

fast burial of the section towards regions with higher temperatures take place (figure 6.25).

60

40

20

0 100

200

Temperature [°C]

300

40

20

0 0

60

0 0.1

1

VR [% Rr]

10

0

0.5

1

Transformation Ratio

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.

102

Results and Interpretation

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 %).

Results and Interpretation

6.2.11

103

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). Kudu 9A-2

A 0

0 km

250 km

Depth (m)

1000 2000 3000 Temperature [°C]

4000 5000 6000

B

0 - 25

125 - 150

25 - 50 50 - 75 75 - 100 100 - 125

150 - 175 175 - 200 200 - 225 225 - 250

Kudu 9A-2 0

0 km

250 km

Depth (m)

1000 2000 3000 4000 5000 6000 7000

Temperature [°C] 0 - 22 22 - 44 44 - 66 66 - 88 88 - 110 110 - 132 132 - 154 154 - 176 176 - 198 198 - 220

220 - 242 242 - 264 264 - 286 286 - 308 308 - 330 330 - 352 352 - 374 374 - 396 396 - 418 418 - 440

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.

104

Results and Interpretation

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

7

Discussion

7.1

Geochemistry

7.1.1

Surface geochemical prospecting

105

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

106

Discussion

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

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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 threedimensional 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

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Discussion

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

Kudu 9A-2

A 0

0 km

212 km

Depth (m)

1000 2000 3000

80 Ma

5000

B

86 Ma

84 Ma

4000 104 Ma

96 Ma

85 Ma

103 Ma

Kudu 9A-2 0

0 km

212 km

Depth (m)

1000 2000 3000 85 Ma

4000 88 Ma

5000

C

99 Ma

96 Ma

87 Ma

104 Ma

102 Ma

Kudu 9A-2 0

0 km

212 km

Depth (m)

1000 2000 3000 100 Ma

4000

85 Ma

5000 6000

103 Ma 88 Ma

106 Ma

105 Ma

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

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stratigraphic traps in the feather edge of the SDRS along the continental margin of southwestern 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

8

113

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

114

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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.

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References

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WILSON, J.T. (1966): Did the Atlantic close and then re-open? Nature 211 (5050), 676-681. WINTERER, E.L. (1980): Sedimentary facies on the rises and slopes of passive continental margins. Philosophical Transactions of the Royal Society of London 294, 169-176. WOLFE, R.S. (1971): Microbial formation of methane. In: Advances in Microbial Physiology 6, pp. 107-146. WYGRALA, B.P. (1988): Integrated computer-aided basin modeling applied to analysis of hydrocarbon generation history in a Northern Italian oil field. Organic Geochemistry 13 (1-3), 187-197. WYGRALA, B.P. (1989): Integrated study of an oil field in the southern Po basin, northern Italy. Dissertation, University of Köln. WYRTKI, K. (1962): The oxygen minima in relation to ocean circulation. Deep-Sea Research 9, 11-23. YUKLER, M.A. and C. MCELWEE (1976): Sensitivity analysis of groundwater flow systems. Transactions of the Geophysical Society of South Africa 57 (4), 248. ZHANG, C.L., Y. LI, J.D. WALL, L. LARSEN, R. SASSEN, Y. HUANG, Y. WANG, A. PEACOCK, D.C. WHITE, J. HORITA, and D.R. COLE. (2002): Lipid and carbon isotopic evidence of methane-oxidizing and sulfate-reducing bacteria in association with gas hydrates from the Gulf of Mexico. Geology 30 (3), 239-242.

142

Appendix A: Geochemistry

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 Propane [HC-%] [HC-%]

Propene [HC-%]

iButane [HC-%]

niButane Pentane [HC-%] [HC-%]

nPentane [HC-%]

Malvinas 1 Malvinas 3 Malvinas 4 Malvinas 5a Malvinas 6a Malvinas 7a Malvinas 8 Malvinas 9 Malvinas 10 Malvinas 11 Malvinas 12 Malvinas 13 Malvinas 14 Malvinas 15 Malvinas 16 Malvinas 17 Malvinas 18 Malvinas 19 Malvinas 20 Malvinas 21 Malvinas 22 Malvinas 23 Malvinas 24 Malvinas 25 Malvinas 26 Malvinas 27 Malvinas 28 Malvinas 29 Malvinas 30 Malvinas 31 Malvinas 32 Malvinas 33 Malvinas 34 Malvinas 35 Malvinas 36 Malvinas 37 Malvinas 38 Malvinas 39 Malvinas 40 Malvinas 41 Malvinas 42 Malvinas 43 Malvinas 44 Malvinas 45, 63 µm Malvinas 46

0112810 0112812 0112813 0112814 0112815 0112816 0112817 0112818 0112819 0112920 0112821 0112822 0112823 0112824 0112825 0112826 0112827 0112828 0112829 0112830 0112831 0112832 0112833 0112834 0112835 0112836 0112837 0112838 0112839 0112840 0112841 0112842 0112843 0112844 0112845 0112846 0112847 0112848 0112849 0112850 0112851 0112852 0112853 0112854 a 0112854 b 0112855

97.81 96.12 90.65 92.14 94.02 95.33 90.88 93.89 94.76 92.40 92.98 94.84 91.20 89.85 90.96 91.10 90.40 91.50 93.30 92.42 91.95 93.59 95.03 95.07 92.85 93.12 95.18 93.55 93.81 94.40 93.95 93.45 94.41 93.40 96.00 94.31 93.54 91.47 95.18 93.19 90.11 90.67 93.95 92.84

1.76 2.30 4.59 4.15 3.81 3.21 5.43 4.01 3.59 4.91 4.40 3.25 5.26 6.06 5.21 5.42 5.59 4.91 4.20 4.45 4.95 4.12 3.37 3.11 4.00 4.22 2.92 4.09 3.55 3.74 3.87 4.23 3.67 4.34 2.40 3.64 4.17 4.78 2.81 4.16 5.96 5.51 3.72 4.74

0.00 0.41 0.91 2.29 0.43 0.00 0.45 0.22 1.20 0.25 0.31 0.00 0.22 0.30 0.50 0.24 0.51 0.42 0.27 0.56 0.38 0.37 0.00 0.37 0.74 0.44 0.00 0.41 0.00 0.26 0.21 0.25 0.35 0.29 0.21 0.00 0.54 0.00 0.62 0.54 0.26 0.50 0.30 0.40

0.43 0.69 1.91 0.00 1.09 0.87 1.78 1.16 0.00 1.56 1.35 1.07 1.90 2.17 1.74 1.92 1.92 1.79 1.31 1.53 1.62 1.15 0.95 0.85 1.23 1.30 0.95 1.12 1.38 0.93 1.11 1.21 0.92 1.21 0.80 1.10 1.14 2.09 0.79 1.14 2.16 1.91 1.20 1.30

0.00 0.00 0.50 0.00 0.00 0.00 0.13 0.00 0.00 0.00 0.11 0.00 0.08 0.08 0.12 0.00 0.00 0.09 0.09 0.11 0.00 0.07 0.00 0.00 0.33 0.13 0.00 0.15 0.00 0.12 0.00 0.07 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.26 0.00 0.16 0.00 0.00

0.00 0.22 0.76 0.74 0.34 0.31 0.75 0.36 0.21 0.47 0.43 0.41 0.73 0.83 0.78 0.70 0.85 0.69 0.44 0.47 0.58 0.35 0.27 0.27 0.45 0.40 0.47 0.35 0.62 0.29 0.46 0.42 0.34 0.36 0.31 0.48 0.33 0.89 0.34 0.40 0.81 0.65 0.38 0.42

0.00 0.26 0.69 0.69 0.31 0.28 0.57 0.36 0.24 0.42 0.41 0.43 0.61 0.72 0.67 0.63 0.72 0.60 0.39 0.46 0.51 0.34 0.38 0.33 0.40 0.39 0.47 0.33 0.64 0.26 0.39 0.37 0.30 0.39 0.28 0.47 0.28 0.77 0.27 0.31 0.71 0.61 0.45 0.30

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

94.29

4.01

0.00

0.97

0.00

0.39

0.34

0.00

0.00

89.53

6.05

0.77

2.09

0.21

0.76

0.60

0.00

0.00

Appendix A: Geochemistry

143

Sample

Lab No.

Methane [HC-%]

Ethane [HC-%]

Ethene Propane [HC-%] [HC-%]

Propene [HC-%]

iButane [HC-%]

niButane Pentane [HC-%] [HC-%]

nPentane [HC-%]

Malvinas 46 New Malvinas 47 Malvinas 47 New Malvinas 49 Malvinas 50 Malvinas 51 Malvinas 52 Malvinas 53 Malvinas 54 Malvinas 55 Malvinas 56 Malvinas 58 Malvinas 59 Malvinas 60 Malvinas 61 BGR98-1 BGR98-2 BGR98-3 BGR98-4 BGR98-5 BGR98-6 BGR98-7 BGR98-8 BGR98-9 BGR98-10 Colorado 1 Colorado 2 Colorado 3 Colorado 4 Colorado 5 Colorado 6 Colorado 8 Colorado 9 Colorado 10 Colorado 11 Colorado 12 Colorado 13 Colorado 14 Colorado 17 Colorado 18 Colorado 20 Colorado 21 Colorado 22 Colorado 23 Colorado 24 Colorado 25, 63µm Colorado 26 Colorado 27 Colorado 28 Colorado 29 Colorado 30 Colorado S-1 Colorado S-2 Colorado S-3

0112856

94.97

3.30

0.00

0.95

0.00

0.45

0.33

0.00

0.00

0112857 0112858

94.00 92.04

3.73 4.95

0.49 0.85

1.06 1.38

0.11 0.00

0.31 0.45

0.30 0.33

0.00 0.00

0.00 0.00

0112859 0112860 0112861 0112862 0112863 0112864 0112865 0112866 0112867 0112868 0112869 0112870 0112808 0112801 0112802 0112803 0112804 0112805 0107579 0112806 0112809 0112807 0107550 0107551 0107552 0107553 0107554 0107555 0107556 0107557 0107558 0107559 0107560 0107561 0107562 0107563 0107564 0107565 0107566 0107567 0107568 0107569 0107570 a 0107570 b 0107571 0107572 0107573 0107574 0107575 0107576 0107577 0107578

92.04 94.30 93.24 93.93 95.59 94.41 93.98 98.17 97.45 95.03 94.21 94.77 95.14 94.61 94.94 94.18 89.29 95.12 93.61 92.83 94.61 96.59 61.08 87.74 95.17 91.60 94.09 65.46 96.29 93.82 94.08 95.37 95.23 96.20 96.64 85.77 94.55 94.80 91.57 91.73 95.91 94.79 92.75

4.95 3.22 4.20 3.64 2.75 3.92 3.35 1.41 1.92 3.26 3.52 3.11 2.49 3.25 2.55 4.69 3.31 2.91 3.48 4.01 2.76 2.61 23.82 7.15 3.25 4.22 3.02 5.00 2.60 3.56 3.36 3.00 2.92 2.29 2.01 3.46 3.42 3.57 5.19 4.65 2.66 3.18 4.29

0.85 0.00 0.30 0.35 0.41 0.00 0.26 0.00 0.00 0.41 0.53 0.00 1.48 0.74 1.52 1.13 5.48 0.82 0.56 1.03 0.93 0.00 1.95 2.46 1.04 1.67 1.17 25.74 0.00 0.79 0.76 0.44 0.53 0.31 0.32 6.99 0.00 0.39 2.52 1.74 0.39 0.72 0.00

1.38 1.23 1.40 1.16 0.76 1.00 1.36 0.42 0.63 0.81 0.96 1.24 0.89 0.72 0.31 0.00 0.00 0.61 0.97 1.13 0.79 0.79 8.89 1.59 0.54 1.55 0.84 2.80 0.53 0.96 1.14 0.58 0.65 0.52 0.54 0.00 0.97 0.58 0.00 1.32 0.58 0.69 1.62

0.00 0.00 0.00 0.12 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.25 0.69 0.00 1.92 0.25 0.00 0.33 0.33 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.45 0.71 0.44 0.40 0.25 0.33 0.55 0.00 0.00 0.22 0.34 0.49 0.00 0.18 0.00 0.00 0.00 0.16 0.40 0.35 0.26 0.00 1.76 0.55 0.00 0.31 0.29 0.62 0.21 0.29 0.24 0.24 0.23 0.23 0.14 0.26 0.44 0.15 0.26 0.19 0.18 0.23 0.40

0.33 0.54 0.42 0.39 0.24 0.33 0.49 0.00 0.00 0.27 0.44 0.40 0.00 0.25 0.00 0.00 0.00 0.13 0.47 0.31 0.32 0.00 2.50 0.51 0.00 0.44 0.34 0.38 0.17 0.30 0.44 0.23 0.23 0.28 0.15 3.52 0.45 0.31 0.37 0.38 0.18 0.15 0.50

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.21 0.00 0.00 0.00 0.00 0.00 0.00 0.13 0.13 0.00 0.15 0.18 0.00 0.13 0.12 0.10 0.12 0.00 0.00 0.14 0.09 0.00 0.11 0.24 0.30

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.29 0.00 0.00 0.00 0.00 0.00 0.00 0.07 0.13 0.00 0.06 0.11 0.00 0.00 0.09 0.07 0.10 0.00 0.17 0.06 0.00 0.00 0.00 0.00 0.15

92.92

4.39

0.27

1.31

0.00

0.42

0.38

0.21

0.11

95.97 93.58 94.57 95.23 95.06 94.62 93.27 94.02

2.56 3.77 3.45 2.81 2.96 3.00 3.46 3.34

0.40 0.86 0.62 0.65 0.40 0.89 0.48 1.06

0.54 1.06 0.72 0.87 0.78 0.72 1.16 0.86

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.24 0.26 0.18 0.19 0.32 0.24 0.47 0.32

0.18 0.26 0.19 0.17 0.31 0.24 0.58 0.19

0.08 0.13 0.13 0.07 0.12 0.07 0.36 0.22

0.04 0.08 0.14 0.00 0.05 0.22 0.21 0.00

144

Appendix A: Geochemistry

Sample

Lab No.

Methane [HC-%]

Ethane [HC-%]

Ethene Propane [HC-%] [HC-%]

Propene [HC-%]

iButane [HC-%]

niButane Pentane [HC-%] [HC-%]

nPentane [HC-%]

GeoB 6308-4 GeoB 6308-4 GeoB 6330-4 GeoB 6330-4 GeoB 2704-2 GeoB 2704-2 GeoB 2707-5 GeoB 2707-5 GeoB 2714-1 GeoB 2714-1 GeoB 2716-2 GeoB 2716-2 GeoB 2722-4 GeoB 2722-4 GeoB 2724-4 GeoB 2724-4

0010905 0010906 0010907 0010908 0010909 0010910 0010911 0010912 0010913 0010914 0010915 0010916 0010917 0010918 0010919 0010920

99.04 90.43 95.42 91.83 91.43 92.74 94.63 91.70 93.77 93.33 93.07 90.47 64.44 93.09 96.77

0.54 4.68 3.64 4.03 3.72 4.06 4.00 4.31 3.53 3.06 2.83 5.89 15.60 3.29 1.62

0.19 1.28 0.00 1.69 1.74 1.31 0.00 2.29 1.89 1.20 1.13 0.85 2.23 1.85 0.83

0.20 1.50 0.94 1.21 1.23 1.27 1.37 1.70 0.82 0.86 1.78 1.54 6.53 0.95 0.78

0.00 0.00 0.00 0.62 0.70 0.17 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.34 0.00 0.18 0.27 0.13 0.00 0.00 0.00 0.35 0.00 0.15 2.16 0.39 0.00

0.00 0.34 0.00 0.25 0.37 0.16 0.00 0.00 0.00 0.45 0.00 0.56 2.67 0.43 0.00

0.04 0.37 0.00 0.19 0.23 0.17 0.00 0.00 0.00 0.00 0.00 0.27 4.54 0.00 0.00

0.00 1.05 0.00 0.00 0.30 0.00 0.00 0.00 0.00 0.76 0.00 0.28 1.83 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

0018647

65.15

16.14

1.27

5.09

0.00

3.84

2.05

5.77

0.69

0018648

64.31

16.89

0.00

6.36

0.00

4.27

1.70

6.24

0.21

0018649

72.93

13.22

0.00

5.50

0.00

3.21

1.76

2.71

0.67

0018650

66.30

16.02

0.00

8.68

0.00

2.10

1.81

4.09

1.01

0018651

66.49

17.16

0.45

6.67

0.00

3.14

1.73

3.98

0.37

0018652

74.90

13.23

3.70

2.10

0.00

1.50

1.29

1.91

1.36

0018653

74.72

15.88

0.00

4.66

0.00

0.00

0.00

4.75

0.00

0018654

62.39

17.23

0.21

7.19

0.30

4.23

2.02

6.15

0.28

0018655

97.23

1.06

0.37

0.74

0.00

0.18

0.16

0.26

0.00

0018656

77.59

8.29

14.12

0.00

0.00

0.00

0.00

0.00

0.00

0018657

63.70

20.52

12.14

3.64

0.00

0.00

0.00

0.00

0.00

0018658

68.63

11.40

0.76

14.26

0.73

0.96

1.27

1.12

0.00

0018659

74.31

10.59

2.79

8.06

0.00

0.98

1.51

1.38

0.00

MD962080 0018646 (Aghulas), 21.31-21.73 m MD962083 (Saldanha), 0.30-0.72 m MD962083 (Saldanha), 26.30-26.72 m MD962084 (Olifants r.), 0.32-0.72 m MD962084 (Olifants r.), 34.61-35.13 m MD962085 (Orange r.), 34.99-35.37 m MD962085G( Orange r.), 0.30-0.72 m MD962099 (Orange r.), 0.30-0.72 m MD962099 (Orange r.), 34.60-35.02 m MD962087 (Lüderitz), 39.19-39.63 m MD962087G( Lüderitz), 0.39-1.00 m MD962098 (Lüderitz), 0.39-0.80 m MD962098 (Lüderitz), 31.79-32.10 m MD962086

Appendix A: Geochemistry Sample

(Lüderitz), 35.59-36.00 m MD962086G (Lüderitz), 0.29-0.70 m MD962088G (Walvis B.), 0.30-0.72 m MD962088 (Walvis B.), 1.70-2.12 m MD962096G (Walvis B.), 0.30-0.72 m MD962096 (Walvis B.), 28.70-29.12 m MD962095 (Walvis R.), 23.70-24.12 m MD962095G (Walvis R.), 0.30-0.72 m

145

Lab No.

Methane [HC-%]

Ethane [HC-%]

Ethene Propane [HC-%] [HC-%]

Propene [HC-%]

iButane [HC-%]

niButane Pentane [HC-%] [HC-%]

nPentane [HC-%]

0018660

69.24

8.97

11.70

5.64

0.00

1.53

2.93

0.00

0.00

0018661

100.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0018662

100.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0018663

100.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0018664

68.28

12.87

0.00

7.40

0.00

3.52

1.76

3.47

0.00

0018665

80.12

7.95

0.00

5.85

0.00

1.81

1.36

2.01

0.00

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]

Malvinas 1 Malvinas 3 Malvinas 4 Malvinas 5a Malvinas 6a Malvinas 7a Malvinas 8 Malvinas 9 Malvinas 10 Malvinas 11 Malvinas 12 Malvinas 13 Malvinas 14 Malvinas 15 Malvinas 16 Malvinas 17 Malvinas 18 Malvinas 19 Malvinas 20 Malvinas 21 Malvinas 22 Malvinas 23 Malvinas 24 Malvinas 25 Malvinas 26 Malvinas 27 Malvinas 28

0112810 0112812 0112813 0112814 0112815 0112816 0112817 0112818 0112819 0112920 0112821 0112822 0112823 0112824 0112825 0112826 0112827 0112828 0112829 0112830 0112831 0112832 0112833 0112834 0112835 0112836 0112837

43.52 26.76 16.45 19.38 42.74 51.71 76.62 52.82 95.51 59.43 75.18 35.99 76.71 91.17 53.74 73.82 56.80 66.53 74.15 39.07 39.17 60.20 29.05 31.28 35.75 47.27 23.62

1.47 1.20 1.56 1.64 3.25 3.27 8.59 4.23 6.79 5.92 6.67 2.31 8.30 11.52 5.77 8.23 6.58 6.70 6.26 3.52 3.96 4.97 1.93 1.92 2.89 4.01 1.36

0.00 0.20 0.29 0.84 0.34 0.00 0.67 0.22 2.11 0.28 0.45 0.00 0.33 0.53 0.52 0.33 0.56 0.54 0.38 0.41 0.29 0.42 0.00 0.21 0.50 0.39 0.00

0.52 0.53 0.95 0.00 1.37 1.29 4.14 1.79 0.00 2.76 3.01 1.11 4.38 6.05 2.83 4.28 3.32 3.57 2.87 1.78 1.90 2.04 0.80 0.77 1.30 1.81 0.65

0.00 0.00 0.24 0.00 0.00 0.00 0.28 0.00 0.00 0.00 0.23 0.00 0.17 0.20 0.19 0.00 0.00 0.17 0.18 0.12 0.00 0.12 0.00 0.00 0.33 0.18 0.00

i-Butane n-Butane i[ppb] Pentane [ppb] [ppb] 0.00 0.00 0.00 0.22 0.26 0.00 0.50 0.45 0.00 0.56 0.53 0.00 0.55 0.50 0.00 0.61 0.55 0.00 2.29 1.75 0.00 0.73 0.74 0.00 0.77 0.87 0.00 1.09 0.97 0.00 1.27 1.20 0.00 0.56 0.59 0.00 2.22 1.87 0.00 3.06 2.65 0.00 1.67 1.44 0.00 2.06 1.84 0.00 1.94 1.65 0.00 1.82 1.58 0.00 1.25 1.13 0.00 0.72 0.71 0.00 0.89 0.79 0.00 0.82 0.79 0.00 0.30 0.42 0.00 0.32 0.39 0.00 0.63 0.55 0.00 0.74 0.71 0.00 0.43 0.42 0.00

nPentane[p pb] 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

146

Appendix A: Geochemistry

Sample

Lab No.

Methane [ppb]

Ethane [ppb]

Ethene [ppb]

Propane [ppb]

Propene [ppb]

Malvinas 29 Malvinas 30 Malvinas 31 Malvinas 32 Malvinas 33 Malvinas 34 Malvinas 35 Malvinas 36 Malvinas 37 Malvinas 38 Malvinas 39 Malvinas 40 Malvinas 41 Malvinas 42 Malvinas 43 Malvinas 44 Malvinas 45, 63 µm Malvinas 46 Malvinas 46New Malvinas 47 Malvinas 47New Malvinas 49 Malvinas 50 Malvinas 51 Malvinas 52 Malvinas 53 Malvinas 54 Malvinas 55 Malvinas 56 Malvinas 58 Malvinas 59 Malvinas 60 Malvinas 61 BGR98-1 BGR98-2 BGR98-3 BGR98-4 BGR98-5 BGR98-6 BGR98-7 BGR98-8 BGR98-9 BGR98-10 Colorado 1 Colorado 2 Colorado 3 Colorado 4 Colorado 5 Colorado 6 Colorado 8 Colorado 9 Colorado 10 Colorado 11 Colorado 12 Colorado 13 Colorado 14

0112838 0112839 0112840 0112841 0112842 0112843 0112844 0112845 0112846 0112847 0112848 0112849 0112850 0112851 0112852 0112853 0112854 a 0112854 b 0112855 0112856

44.50 15.47 67.18 52.52 97.07 41.72 51.09 44.28 26.51 35.77 11.04 25.06 27.72 55.49 72.21 37.47 31.63

3.65 1.10 4.99 4.05 8.24 3.04 4.45 2.08 1.92 2.99 1.08 1.39 2.32 6.88 8.22 2.78 3.03

0.34 0.00 0.32 0.20 0.45 0.27 0.28 0.17 0.00 0.36 0.00 0.29 0.28 0.28 0.70 0.21 0.24

1.46 0.63 1.83 1.71 3.45 1.12 1.82 1.01 0.85 1.20 0.69 0.57 0.93 3.66 4.19 1.31 1.21

0.19 0.00 0.23 0.00 0.18 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.20 0.00 0.33 0.00 0.00

i-Butane n-Butane i[ppb] Pentane [ppb] [ppb] 0.61 0.57 0.00 0.37 0.38 0.00 0.74 0.66 0.00 0.94 0.80 0.00 1.58 1.41 0.00 0.55 0.48 0.00 0.71 0.78 0.00 0.52 0.47 0.00 0.49 0.47 0.00 0.46 0.39 0.00 0.39 0.34 0.00 0.32 0.25 0.00 0.43 0.34 0.00 1.80 1.57 0.00 1.87 1.75 0.00 0.55 0.65 0.00 0.52 0.37 0.00

nPentane[p pb] 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

125.57

10.00

0.00

3.56

0.00

1.88

1.63

0.00

0.00

44.68 27.69

5.66 1.81

0.67 0.00

2.86 0.76

0.27 0.00

1.38 0.48

1.09 0.35

0.00 0.00

0.00 0.00

0112857 0112858

46.70 23.91

3.48 2.41

0.42 0.39

1.45 0.98

0.14 0.00

0.55 0.42

0.54 0.31

0.00 0.00

0.00 0.00

0112859 0112860 0112861 0112862 0112863 0112864 0112865 0112866 0112867 0112868 0112869 0112870 0112808 0112801 0112802 0112803 0112804 0112805 0107579 0112806 0112809 0112807 0107550 0107551 0107552 0107553 0107554 0107555 0107556 0107557 0107558 0107559 0107560 0107561 0107562

27.48 9.89 49.09 54.57 36.09 33.86 46.76 32.11 22.17 39.29 23.96 22.80 12.98 30.66 10.75 4.40 4.62 21.57 29.62 27.17 23.37 13.44 5.70 5.16 18.83 34.14 16.91 3.52 19.77 15.11 4.08 19.33 24.05 15.62 29.96

2.77 0.63 4.15 3.97 1.95 2.63 3.13 0.87 0.82 2.53 1.68 1.40 0.64 1.97 0.54 0.41 0.32 1.24 2.07 2.20 1.28 0.68 4.17 0.79 1.21 2.95 1.02 0.50 1.00 1.07 0.27 1.14 1.38 0.70 1.17

0.45 0.00 0.27 0.36 0.27 0.00 0.23 0.00 0.00 0.30 0.24 0.00 0.35 0.42 0.30 0.09 0.50 0.33 0.31 0.53 0.40 0.00 0.32 0.25 0.36 1.09 0.37 2.42 0.00 0.22 0.06 0.16 0.24 0.09 0.17

1.13 0.35 2.03 1.85 0.79 0.99 1.87 0.38 0.39 0.93 0.67 0.82 0.34 0.64 0.10 0.00 0.00 0.38 0.85 0.91 0.53 0.30 2.28 0.26 0.29 1.59 0.41 0.41 0.30 0.42 0.14 0.32 0.45 0.23 0.46

0.00 0.00 0.00 0.19 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.21 0.20 0.00 0.26 0.15 0.00 0.25 0.22 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.48 0.27 0.85 0.84 0.34 0.43 0.98 0.00 0.00 0.32 0.32 0.42 0.00 0.21 0.00 0.00 0.00 0.13 0.46 0.37 0.23 0.00 0.60 0.12 0.00 0.41 0.19 0.12 0.15 0.17 0.04 0.18 0.21 0.14 0.16

0.35 0.20 0.80 0.83 0.33 0.43 0.89 0.00 0.00 0.40 0.40 0.34 0.00 0.29 0.00 0.00 0.00 0.11 0.54 0.33 0.29 0.00 0.85 0.11 0.00 0.60 0.22 0.07 0.13 0.18 0.07 0.17 0.21 0.16 0.16

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.50 0.00 0.00 0.00 0.24 1.00 0.70 0.52 0.00 1.44 0.23 0.00 1.01 0.41 0.19 0.28 0.34 0.11 0.35 0.42 0.30 0.32

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.29 0.00 0.00 0.00 0.00 0.00 0.00 0.22 0.10 0.00 0.13 0.13 0.00 0.12 0.14 0.07 0.16

Appendix A: Geochemistry

147

Sample

Lab No.

Methane [ppb]

Ethane [ppb]

Ethene [ppb]

Propane [ppb]

Propene [ppb]

Colorado 17 Colorado 18 Colorado 20 Colorado 21 Colorado 22 Colorado 23 Colorado 24 Colorado 25, 63µm Colorado 26 Colorado 27 Colorado 28 Colorado 29 Colorado 30 Colorado S-1 Colorado S-2 Colorado S-3 GeoB 6308-4 GeoB 6308-4 GeoB 6330-4 GeoB 6330-4 GeoB 2704-2 GeoB 2704-2 GeoB 2707-5 GeoB 2707-5 GeoB 2714-1 GeoB 2714-1 GeoB 2716-2 GeoB 2716-2 GeoB 2722-4 GeoB 2722-4 GeoB 2724-4 GeoB 2724-4

0107563 0107564 0107565 0107566 0107567 0107568 0107569 0107570 a 0107570 b 0107571 0107572 0107573 0107574 0107575 0107576 0107577 0107578 0010905 0010906 0010907 0010908 0010909 0010910 0010911 0010912 0010913 0010914 0010915 0010916 0010917 0010918 0010919 0010920

1.57 19.52 10.42 5.76 22.00 20.99 11.97 73.48

0.12 1.32 0.74 0.61 2.09 1.09 0.75 6.37

0.22 0.00 0.07 0.28 0.73 0.15 0.16 0.00

0.00 0.55 0.17 0.00 0.87 0.35 0.24 3.52

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

i-Butane n-Butane i[ppb] Pentane [ppb] [ppb] 0.02 0.23 0.25 0.33 0.34 0.67 0.06 0.12 0.18 0.06 0.08 0.14 0.16 0.33 0.49 0.14 0.14 0.28 0.10 0.07 0.17 1.16 1.43 2.59

42.70

3.78

0.22

1.65

0.00

0.70

0.63

1.33

0.43

18.59 23.18 11.07 39.26 47.28 21.61 30.17 43.69

0.93 1.75 0.76 2.17 2.76 1.28 2.10 2.91

0.14 0.37 0.13 0.47 0.35 0.36 0.27 0.86

0.29 0.72 0.23 0.99 1.07 0.45 1.03 1.10

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

0.17 0.24 0.07 0.28 0.58 0.20 0.55 0.53

0.12 0.23 0.08 0.26 0.56 0.20 0.68 0.32

0.29 0.47 0.16 0.54 1.13 0.40 1.23 0.85

0.03 0.15 0.07 0.14 0.27 0.07 0.53 0.45

462.1 49.4 51.2 83.9 63.6 53.8 51.5 40.1 47.4 91.0 37.1 82.2 7.9 66.4

18.6 2.0 2.1 3.4 2.6 2.2 2.3 1.6 1.9 3.7 1.5 3.3 0.4 2.7

1.6 1.4 0.0 2.5 2.2 1.2 0.0 2.2 1.7 1.9 0.9 0.9 0.6 3.3

2.7 2.6 1.1 2.8 2.4 1.8 2.3 2.6 1.2 2.1 2.2 2.5 2.8 2.7

0.0 0.0 0.0 0.8 0.8 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.8 0.0 0.6 0.7 0.2 0.0 0.0 0.0 1.1 0.0 0.3 1.2 1.5

0.0 0.8 0.0 0.8 1.0 0.3 0.0 0.0 0.0 1.4 0.0 1.2 1.5 1.6

0.9 1.0 0.0 0.7 0.7 0.4 0.0 0.0 0.0 0.0 0.0 0.7 3.1 0.0

0.0 2.9 0.0 0.0 1.0 0.0 0.0 0.0 0.0 3.0 0.0 0.7 1.3 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

26.44

12.28

0.90

5.69

0.00

5.65

3.01

10.54

1.26

MD962083 0018648 (Saldanha), 26.30-26.72 m

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 0018650 (Olifants r.), 34.61-35.13 m MD962085 0018651 (Orange r.), 34.99-35.37 m MD962085G 0018652 (Orange r.), 0.30-0.72 m

58.35

26.44

0.00

21.02

0.00

6.68

5.77

16.20

3.98

56.07

27.13

0.67

15.47

0.00

9.61

5.28

15.11

1.39

13.07

4.33

1.13

1.01

0.00

0.95

0.82

1.50

1.07

MD962080 0018646 (Aghulas), 21.31-21.73 m MD962083 0018647 (Saldanha), 0.30-0.72 m

nPentane[p pb] 0.00 0.00 0.07 0.03 0.00 0.11 0.13 1.06

148

Appendix A: Geochemistry

Sample

Lab No.

Methane [ppb]

Ethane [ppb]

Ethene [ppb]

Propane [ppb]

Propene [ppb]

MD962099 (Orange r.), 0.30-0.72 m MD962099 (Orange r.), 34.60-35.02 m MD962087 (Lüderitz), 39.19-39.63 m MD962087G (Lüderitz), 0.39-1.00 m MD962098 (Lüderitz), 0.39-0.80 m MD962098 (Lüderitz), 31.79-32.10 m MD962086 (Lüderitz), 35.59-36.00 m MD962086G (Lüderitz), 0.29-0.70 m MD962088G (Walvis B.), 0.30-0.72 m MD962088 (Walvis B.), 1.70-2.12 m MD962096G (Walvis B.), 0.30-0.72 m MD962096 (Walvis B.), 28.70-29.12 m MD962095 (Walvis R.), 23.70-24.12 m MD962095G (Walvis R.), 0.30-0.72 m

0018653

13.73

5.47

0.00

2.35

0.00

i-Butane n-Butane i[ppb] Pentane [ppb] [ppb] 0.00 0.00 3.93

nPentane[p pb] 0.00

0018654

219.37

113.58

1.31

69.57

2.81

53.96

25.70

97.24

4.35

0018655

484.59

9.87

3.27

10.09

0.00

3.31

2.84

5.86

0.00

0018656

16.83

3.37

5.36

0.00

0.00

0.00

0.00

0.00

0.00

0018657

3.91

2.79

1.95

0.72

0.00

0.00

0.00

0.00

0.00

0018658

42.85

13.35

0.83

24.49

1.20

2.17

2.89

3.14

0.00

0018659

64.68

17.41

4.28

0.00

0.00

3.10

4.71

5.33

0.00

0018660

7.47

1.83

2.22

1.68

0.00

0.60

1.13

0.00

6.68

0018661

741.71

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0018662

2972.94

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0018663

8.79

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0018664

16.61

5.87

0.00

4.95

0.00

3.10

1.55

3.79

0.00

0018665

25.81

4.80

0.00

5.19

0.00

2.12

1.59

2.92

0.00

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 Malvinas 3 Malvinas 4 Malvinas 5a Malvinas 6a Malvinas 7a Malvinas 8 Malvinas 9 Malvinas 10

0112810 0112812 0112813 0112814 0112815 0112816 0112817 0112818 0112819

0.98 0.96 0.91 0.92 0.94 0.95 0.91 0.94 0.95

44.6 32.2 13.9 22.2 19.2 23.4 12.6 18.2 26.4

2.19 4.83 12.25 10.72 7.26 5.85 11.75 7.55 6.14

-38.3 -37.8 -39.7 -41.4 -40.7 -40.3 -41.8 -41.0 -40.5

-33.0 -32.2 -29.7 -31.6 -31.8 -31.3 -30.3 -28.1 -31.2

Appendix A: Geochemistry

149

Sample

Lab - No.

Vol-ratio C1/sum Cn-%

Vol-ratio C1/(C2+C3)

C2+ [ppb]

δ13-Methane [‰]

δ13-Ethane [‰]

Malvinas 11 Malvinas 12 Malvinas 13 Malvinas 14 Malvinas 15 Malvinas 16 Malvinas 17 Malvinas 18 Malvinas 19 Malvinas 20 Malvinas 21 Malvinas 22 Malvinas 23 Malvinas 24 Malvinas 25 Malvinas 26

0112920 0112821 0112822 0112823 0112824 0112825 0112826 0112827 0112828 0112829 0112830 0112831 0112832 0112833 0112834 0112835

0.92 0.93 0.95 0.91 0.90 0.91 0.91 0.90 0.92 0.93 0.92 0.92 0.94 0.95 0.95 0.93

14.3 16.2 26.4 12.7 10.9 13.1 12.4 12.0 13.7 16.9 15.5 14.0 17.7 22.0 24.0 17.7

9.37 8.70 6.84 11.48 13.26 11.94 11.55 12.75 11.08 8.36 9.44 10.22 7.80 6.28 6.12 8.84

-41.2 -40.3 -40.4 -41.0 -41.3 -41.4 -41.1 -41.7 -40.8 -40.0 -40.2 -40.1 -42.0 -40.4 -40.1 -41.2

-31.5 -31.2 -31.7 -30.8 -30.4 -31.5 -31.4 -30.9 -30.7 -30.7 -32.2 -31.5 -31.5 -31.6 -31.4 -33.7

Malvinas 27 Malvinas 28 Malvinas 29 Malvinas 30 Malvinas 31 Malvinas 32 Malvinas 33 Malvinas 34 Malvinas 35 Malvinas 36 Malvinas 37 Malvinas 38 Malvinas 39 Malvinas 40 Malvinas 41 Malvinas 42 Malvinas 43 Malvinas 44 Malvinas 45, 63 µm

0112836 0112837 0112838 0112839 0112840 0112841 0112842 0112843 0112844 0112845 0112846 0112847 0112848 0112849 0112850 0112851 0112852 0112853 0112854a 0112854b

0.93 0.95 0.94 0.94 0.94 0.94 0.93 0.94 0.93 0.96 0.94 0.94 0.91 0.95 0.93 0.90 0.91 0.94 0.93 0.94

16.9 24.6 18.0 19.0 20.2 18.9 17.2 20.5 16.8 30.0 19.9 17.6 13.3 26.4 17.6 11.1 12.2 19.1 15.4 18.9

8.45 6.71 7.82 8.70 6.69 7.76 8.13 6.87 8.11 4.00 7.58 7.69 11.86 4.82 8.23 12.91 11.84 7.71 8.61 7.16

-40.5 -40.2 -40.3 -40.4 -41.0 -40.8 -39.2 -42.6 -42.6 -55.3 -41.1 -41.6 -41.6 -52.4 -43.9 -41.8 -41.6 -42.1 -40.8 -40.7

-32.2 -31.1 -32.0 -30.7 -30.1 -30.9 -30.7 -33.0 -32.7 -33.9 -31.4 -34.3 -31.3 -32.9 -31.9 -32.2 -33.1 -32.4 -30.3 -28.6

Malvinas 46 Malvinas 46New Malvinas 47 Malvinas 47New Malvinas 49 Malvinas 50 Malvinas 51 Malvinas 52 Malvinas 53 Malvinas 54 Malvinas 55 Malvinas 56 Malvinas 58

0112855 0112856 0112857 0112858 0112859 0112860 0112861 0112862 0112863 0112864 0112865 0112866 0112867

0.90 0.95 0.94 0.92 0.92 0.94 0.93 0.94 0.96 0.94 0.94 0.98 0.97

11.0 22.4 19.6 14.5 14.5 21.2 16.6 19.6 27.2 19.2 19.9 53.6 38.3

13.20 6.61 7.21 9.50 9.50 8.20 8.49 7.66 5.38 6.92 8.10 1.83 2.55

-43.8 -43.1 -44.2 -41.3 -42.5 -41.5 -41.3 -41.0 -40.4 -41.9 -40.5 -37.3 -39.4

-31.9 -31.9 -32.1 -32.5 -32.8 -33.0 -30.5 -30.9 -31.1 -32.7 -32.8 -31.0 -31.2

150

Appendix A: Geochemistry

Sample

Lab - No.

Vol-ratio C1/sum Cn-%

Vol-ratio C1/(C2+C3)

C2+ [ppb]

δ13-Methane [‰]

δ13-Ethane [‰]

Malvinas 59 Malvinas 60 Malvinas 61 BGR98-1 BGR98-2 BGR98-3 BGR98-4 BGR98-5 BGR98-6 BGR98-7 BGR98-8 BGR98-9 BGR98-10 Colorado 1 Colorado 2 Colorado 3

0112868 0112869 0112870 0112808 0112801 0112802 0112803 0112804 0112805 0107579 0112806 0112809 0112807 0107550 0107551 0107552

0.95 0.94 0.95 0.95 0.95 0.95 0.94 0.89 0.95 0.94 0.93 0.95 0.97 0.61 0.88 0.95

23.3 21.0 21.8 28.1 23.8 33.2 20.1 27.0 27.1 21.0 18.0 26.7 28.4 1.9 10.0 25.1

5.94 7.34 6.99 1.33 4.74 1.14 0.50 1.08 2.81 6.95 6.01 3.99 0.98 11.09 1.98 1.86

-41.4 -40.1 -39.9 -39.0 -38.3 -38.4 -36.7 -36.6 -38.1 -42.9 -40.7 -38.8 -39.2 -50.5 -47.5 -40.3

-32.4 -31.3 -31.3 -31.5 -30.3 -32.9 -33.2 -30.9 -30.0

Colorado 4 Colorado 5 Colorado 6 Colorado 8 Colorado 9 Colorado 10 Colorado 11 Colorado 12 Colorado 13 Colorado 14 Colorado 17 Colorado 18 Colorado 20 Colorado 21 Colorado 22 Colorado 23 Colorado 24 Colorado 25, 63µm Colorado 26

0107553 0107554 0107555 0107556 0107557 0107558 0107559 0107560 0107561 0107562 0107563 0107564 0107565 0107566 0107567 0107568 0107569 0107570a 0107570b 0107571

0.92 0.94 0.65 0.96 0.94 0.94 0.95 0.95 0.96 0.97 0.86 0.95 0.95 0.92 0.92 0.96 0.95 0.93 0.93 0.96

15.9 24.4 8.4 30.7 20.8 20.9 26.6 26.7 34.3 38.0 24.8 21.6 22.9 17.7 15.4 29.7 24.4 15.7 16.3 30.9

8.99 3.24 3.92 2.32 2.97 0.78 2.78 3.56 2.05 3.06 1.09 4.03 1.64 1.35 5.16 2.55 1.80 19.25 10.30 2.26

-40.1 -36.9 -46.5 -38.3 -38.0 -42.1 -39.1 -39.2 -38.7 -44.4 -33.4 -41.9 -36.5 -42.4 -42.4 -37.7 -42.5 -40.0 -39.5 -41.1

-37.5 -32.2 -29.9 -36.2 -32.0 -33.0 -32.3 -31.6 -31.1 -32.8

Colorado 27 Colorado 28 Colorado 29 Colorado 30 Colorado S-1 Colorado S-2 Colorado S-3 GeoB 6308-4 GeoB 6308-4 GeoB 6330-4 GeoB 6330-4 GeoB 2704-2 GeoB 2704-2

0107572 0107573 0107574 0107575 0107576 0107577 0107578 0010905 0010906 0010907 0010908 0010909 0010910

0.94 0.95 0.95 0.95 0.95 0.93 0.94

19.4 22.7 25.8 25.4 25.4 20.2 22.4

4.49 1.73 5.38 7.96 3.59 7.93 7.88

-39.4 -38.7 -40.4 -40.9 -43.6 -49.5 -40.7

-33.6 -33.2 -35.2 -33.0 -36.9 -34.2 -34.6

0.99 0.90 0.95 0.92 0.91

133.84 14.63 20.83 17.52 18.47

0.97 9.56 4.58 8.17 8.56

-80.4 -41.9 -39.7 -40.1 -39.1

-30.6 -31.2 -29.5 -30.1 -32.0

-33.9 -32.8 -31.8 -27.1 -32.4 -39.9

-32.1 -36.4 -29.4 -36.0 -29.8 -33.0 -33.8

Appendix A: Geochemistry

151

Sample

Lab - No.

Vol-ratio C1/sum Cn-%

Vol-ratio C1/(C2+C3)

C2+ [ppb]

δ13-Methane [‰]

δ13-Ethane [‰]

GeoB 2707-5 GeoB 2707-5 GeoB 2714-1 GeoB 2714-1 GeoB 2716-2 GeoB 2716-2 GeoB 2722-4 GeoB 2722-4 GeoB 2724-4 GeoB 2724-4 MD962080 (Aghulas), 0.31-0.83 m MD962080 (Aghulas), 21.31-21.73 m MD962083 (Saldanha), 0.30-0.72 m MD962083 (Saldanha), 26.30-26.72 m MD962084 (Olifants r.), 0.32-0.72 m MD962084 (Olifants r.), 34.61-35.13 m MD962085 (Orange r.), 34.99-35.37 m MD962085G(Orange r.), 0.30-0.72 m MD962099 (Orange r.), 0.30-0.72 m MD962099 (Orange r.), 34.60-35.02 m MD962087 (Lüderitz), 39.19-39.63 m MD962087G(Lüderitz), 0.39-1.00 m MD962098 (Lüderitz), 0.39-0.80 m MD962098 (Lüderitz), 31.79-32.10 m MD962086 (Lüderitz), 35.59-36.00 m MD962086G(Lüderitz), 0.29-0.70 m MD962088G (Walvis B.), 0.30-0.72 m MD962088 (Walvis B.), 1.70-2.12 m MD962096G(Walvis B.), 0.30-0.72 m MD962096 (Walvis B.), 28.70-29.12 m MD962095 (Walvis R.), 23.70-24.12 m MD962095G(Walvis R.), 0.30-0.72 m

0010911 0010912 0010913 0010914 0010915 0010916 0010917 0010918 0010919 0010920 0018645

0.93 0.95 0.92 0.94 0.93 0.94 0.90 0.64 0.93 0.97 0.68

17.40 17.62 15.26 21.56 23.81 20.19 12.18 2.91 21.96 40.32 3.07

7.27 5.37 8.30 6.24 6.68 5.74 9.54 35.56 6.91 3.23 31.93

-39.1 -39.9 -41.0 -41.6 -44.1 -39.9 -39.7 -36.5 -41.4 -71.2 -33.63

-30.7 -30.5 -30.0 -30.5 -30.2 -32.4 -29.0 -26.8 -34.3 -33.1 -22.63

0018647

0.65

3.07

34.85

-35.47

-23.97

0018648

0.64

2.77

35.69

-32.73

-23.19

0018649

0.73

3.90

27.07

-41.96

-25.94

0018650

0.66

2.68

33.70

-34.08

-23.56

0018651

0.66

2.79

33.51

-33.75

-23.86

0018652

0.75

4.89

25.10

-38.19

-28.16

0018653

0.75

3.64

25.28

-39.55

-24.57

0018654

0.62

2.55

37.61

-33.89

-25.37

0018655

0.97

54.25

2.77

-62.49

-25.96

0018656

0.78

9.36

22.41

-39.51

-26.28

0018657

0.30

2.64

36.30

-43.15

-31.43

0018658

0.69

2.67

30.50

-36.78

-23.87

0018659

0.81

3.98

25.31

-31.48

-25.21

0018660

0.61

4.74

30.77

-35.70

-28.53

0018661

1.00

0.00

-68.57

0018662

1.00

0.00

-77.01

0018663

1.00

0.00

-35.23

-33.75

0018664

0.68

3.37

29.02

-35.86

-26.63

0018665

0.80

5.80

18.99

-36.68

-26.56

0018666

0.45

5.19

22.70

-43.94

-35.24

0018646

152

Appendix A: Geochemistry

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 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-2 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 Kudu 9A-3 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361

Lab.-No. 9936986 9936987 9936988 9936989 9936990 9936991 9936992 9936993 9936994 9936995 9936996 9936997 9936998 9936999 9937000 9937001 9937002 9937003 9937004 9937005 9937006 9937007 9937008 9937009 9937010 9937011 9937012 9937013 9937014 9937015 9937016 9937017 9937018 9937019 9937020 9937021 9937022 9937023 0011269 0011270 0011271 0011272 0011273 0011274 0011275 0011276

Stratigraphy Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Late Barremian Late Barremian Late Barremian Late Barremian Late Barremian Late Barremian Late Barremian Mud Late Barremian Late Barremian Late Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Mud Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Early Aptian Upper Cretaceous Upper Cretaceous L. Albian to Up. Aptian L. Albian to Up. Aptian L. Albian to Up. Aptian L. Albian to Up. Aptian L. Albian to Up. Aptian L. Albian to Up. Aptian

Latitude 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°29'01.13''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 28°34'54.41''S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S

Longitude 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°34'27.07''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 14°35'54.90''E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E

Depth [mbsf] 3865-70 3875-80 3885-90 3918-21 3927-30 3939-42 3957-60 4107-10 4119-22 4128-31 4137-40 4149-52 4158-61 4167-70 4179-82 4188-91 4197-00 4209-12 4218-21 3839-42 3848-51 3857-60 3869-72 3878-81 3887-90 3899-02 3908-11 3917-20 3929-32 3938-41 3947-50 3959-62 3968-71 3977-80 3989-92 3998-01 577.73-75 767.24-26 957.28-30 1008.15-17 1035.18-19 1039.55-57 1052.40-42 1065.10-12

Appendix A: Geochemistry

Well DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 DSDP 361 Irati Irati Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Cruz del Sur Whitehill

Lab.-No. 0011277 0011278 0011279 0011280 0011281 0011282 0011283 0011284 0011285 0011286 0011287 0011288 0011289 0011290 0011291 0011292 0020719 0020720 0020723 0020725 0020728 0020731 0020733 0020740 0020748 0020753 0020761 0020764 0020772 0020781 0020787 0020789 0020793 0020799 0020805 0020815 0020818 0020820 0020831 0020836 0020839 0020847 0020856 0020864 0020869 0020875 0020886 0020887 0020894 0020902 0190107

Stratigraphy Aptian, Lower ? Aptian, Lower ? Aptian, Lower ? Aptian Aptian Aptian, Lower ? Aptian Aptian Aptian Aptian Aptian Aptian Aptian Aptian Aptian Aptian Permian Permian

Alb

Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Valangin-Kimmeridge Trias (Pre-Rift) Trias (Pre-Rift) Trias (Pre-Rift) Trias (Pre-Rift) Trias (Pre-Rift) Permian

Latitude 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 35°03.97'S 25.875°S 25.875°S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S 40°56.05'05.931''S S 26° 28,82'

153

Longitude 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 15°26.91'E 50.405°W 50.405°W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W 57°17'26.348''W E 18° 18,92'

Depth [mbsf] 1068.72-74 1082.32-33 1088.92-94 1099.75-77 1106.54-56 1117.29-30 1127.20-21 1145.20-21 1147.28-30 1166.69-70 1182.71-72 1201.98-99 1223.34-35 1257.55-57 1267.14-15 1286.09-10 outcrop outcrop 1850 2135 2150 2418 2958 2982 3012 3024 3102 3114 3168 3195 3252 3348 3366 3396 3426 3456 3471 3477 3510 3525 3534 3558 3585 3609 3636 3822 4191 4194 4242 4272 outcrop

154

Well Whitehill Whitehill Whitehill Whitehill

Appendix A: Geochemistry

Lab.-No. 0190108 0190109 0190110 0190111

Stratigraphy Permian Permian Permian

Latitude S 26° 28,05' S 26° 28,05' S 28° 35,15' S 28° 14,13'

Longitude E 18° 18,45' E 18° 18,45' E 17° 34,47' E 17° 39,69'

Depth [mbsf] outcrop outcrop outcrop 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 [%]

Kudu 9A-2, offshore Namibia 9936986 1.5 9936987 1.7 9936988 1.7 9936989 2.1 9936990 2.0

S1 [mg HC/g rock]

S2 [mg HC/g rock]

S3 [mg CO2/g rock]

HI [mg HC/g TOC]

Tmax [°C]

OI [mg CO2/g TOC]

Vitrinite Reflectance [% Rr]

δ13 COM [‰]

0.4 0.4 0.4 0.6 0.5

0.6 0.6 0.6 0.7 0.7

1.3 1.4 1.3 1.5 1.5

439 442 451 455 457

38 35 34 33 34

88 83 73 71 73

1.22-1.33

-25.3 -26.0 -25.7 -25.7 -25.9

9936991 2.1 9936992 2.3 9936993 0.9 9936994 1.1 9936995 0.9 9936996 1.1 9936997 1.4 9936998 1.7 9936999 1.6 9937000 1.3 9937001 1.5 9937002 1.5 9937003 1.2 9937004 1.1 9937005 1.4 Kudu 9A-3, offshore Namibia 9937006 1.9 9937007 1.3 9937008 1.4 9937009 1.9 9937010 1.8 9937011 1.8 9937012 2.0 9937013 1.8 9937014 1.9 9937015 1.8 9937016 1.8 9937017 1.8

0.5 0.5 0.2 0.2 0.2 0.2 0.2 0.3 0.2 0.2 0.2 0.2 0.5 0.2 0.2

0.7 0.7 0.3 0.3 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 1.1 0.4 0.4

1.5 1.5 1.2 1.4 1.2 1.5 1.5 1.3 1.7 1.6 1.5 1.7 4.0 1.8 1.6

462 453 417 451 556 517 524 539 527 535 532 525 408 517 520

33 31 31 24 23 28 22 18 20 20 18 21 86 32 26

73 64 129 127 125 139 105 78 105 122 101 110 328 158 111

1.28

-26.2 -25.6 -26.1 -25.8 -25.1 -25.5 -25.8 -25.9 -25.7 -25.5 -25.2 -24.8

0.1 0.2 0.2 0.3 0.2 0.2 0.3 0.5 0.3 0.3 0.2 0.2

0.3 0.4 0.4 0.5 0.5 0.5 0.6 2.0 0.5 0.6 0.5 0.5

1.6 1.3 1.4 1.3 1.4 1.4 1.4 5.9 1.9 1.5 1.5 1.5

437 438 450 433 462 433 429 420 470 429 506 436

17 32 31 27 26 27 31 108 27 32 26 26

84 106 101 69 76 77 73 324 99 85 81 88

-24.8 -25.0 -24.8 -24.7 -24.8 -25.0 -25.2

9937018 9937019 9937020 9937021 9937022

0.1 0.2 0.2 0.2 0.2

0.4 0.5 0.4 0.5 0.5

1.3 1.4 1.7 1.5 1.4

459 442 465 437 515

34 26 22 25 23

107 80 98 79 71

-25.5 -25.5 -25.4 -25.2 -24.8

1.2 1.7 1.7 1.9 2.0

1.62

1.78 1.77

1.75

-25.5 -25.2

-25.3 -25.4 -25.5 -25.6

Appendix A: Geochemistry Lab.-No.

TOC [%] S [%]

S1 [mg HC/g rock]

S2 [mg HC/g rock]

S3 [mg CO2/g rock]

Tmax [°C]

155

HI [mg HC/g TOC]

OI [mg CO2/g TOC]

9937023 1.1 DSDP 361, offshore South Africa 0011269 0.7

0.1

0.3

1.6

514

29

138

0.0

0.3

1.4

425

40

197

0011270 0011271 0011272

0.1 1.3 3.3

0.0 0.1 0.2

0.3 1.5 4.1

0.7 1.2 1.6

375 432 408

170 119 125

497 93 49

0011273 0011274 0011275 0011276 0011277

4.4 2.4 3.0 4.2 11.0

12.2

0.2 0.1 0.1 0.2 1.1

3.5 1.4 1.3 10.1 44.8

2.3 1.1 1.9 2.1 3.7

407 393 413 421 407

80 58 45 242 407

52 45 63 49 33

0011278 0011279 0011280

3.2 1.2 11.5

12.6

0.1 0.0 0.3

6.2 0.3 4.2

2.0 0.6 5.8

425 412 415

193 24 36

61 50 51

0011281

13.2

13.5

0.3

3.8

5.9

411

28

45

0011282 0011283 0011284 0011285 0011286 0011287

2.7 3.1 5.3 1.5 3.0 11.0

14.1

0.1 0.1 0.4 0.1 0.1 1.1

0.4 1.8 11.3 0.6 1.6 61.2

1.2 2.0 2.1 0.8 1.2 5.0

412 409 409 413 414 417

15 57 211 43 52 556

43 65 40 52 40 45

0011288 0011289 0011290 0011291 0011292

3.5 2.3 0.3 4.1 3.7

0.1 0.1 0.0 0.2 0.3

1.7 0.5 0.4 3.2 2.4

1.4 0.9 0.5 1.3 1.6

417 413 431 411 409

48 20 112 79 64

40 39 149 33 43

4.8 7.2

77.7 158.3

1.0 2.7

424 425

616 724

23 47

Irati Shale, onshore Brazil 0020719 12.6 4.2 0020720 21.9 5.8 Cruz del Sur, offshore Argentina 0020723 0020725 0020728 0.4 0020731 0020733 0020740 2.2 0020748 4.0 0020753 0.8 0020761 1.2 0020764 1.8 0020772 0020781 0.3 0020787 0.3 0020789 0020793 0.8

Vitrinite Reflectance [% Rr]

δ13 COM [‰] -23.8

0.35 (+0.10.15)

0.3 (+0.10.15)

0.27 (+0.10.15)

-24.1

-25.0 -26.6 -24.6 -23.1 -23.3 -26.0 -28.1 -25.5 -23.6

0.29 (+0.10.15)

-24.0 -23.9 -25.7 -25.7

0.3 (+0.10.15)

-25.1 -26.4 -25.0 -23.0

0.31 (+0.10.15) 0.50 0.50

-24.8 -25.5

-23.8 -20.6

0.32 0.63 0.1

0.5

0.7

424

103

148

-25.6 0.56 0.52

0.6 1.3 0.1 0.2 0.2

9.1 21.6 1.1 1.1 1.6

1.4 1.2 1.9 1.3 1.4

425 426 431 439 437

409 539 132 96 91

65 29 244 115 77

-20.2 -22.8 -23.8 -24.0 0.49

0.1 0.1

0.2 0.3

2.9 1.4

439 437

71 121

939 516

-23.9 0.60

0.1

1.1

3.4

444

137

429

-25.0

156 Lab.-No.

Appendix A: Geochemistry TOC [%] S [%]

0020799 0020805 0020815 0020818 0020820 0020831 0020836 0020839 0020847 0020856 0020864 0020869 0020875 0020886 0020887 0020894

S1 [mg HC/g rock]

1.2 0.3 0.5

S2 [mg HC/g rock]

0.2 0.1 0.1

S3 [mg CO2/g rock]

2.7 0.2 0.5

3.3 2.7 4.1

Tmax [°C]

HI [mg HC/g TOC] 447 439 440

OI [mg CO2/g TOC]

220 82 98

δ13 COM [‰]

Vitrinite Reflectance [% Rr]

271 931 860

-26.1 -23.6 0.47

0.5 1.4 0.8 0.9

0.0 0.1 0.1 0.1

0.3 2.9 1.8 1.5

3.7 3.3 2.5 3.0

438 445 444 444

67 207 224 170

774 233 301 326

-23.9 -24.2 -25.9 -24.5 0.46

0.8 0.8 1.4 0.5

0.1 0.1 0.2 0.1

0.8 1.3 3.9 0.3

3.7 2.7 2.3 2.9

441 445 449 440

101 158 290 66

450 335 168 610

-24.9 -24.5 -23.5 -25.2 0.67

0.1 0.4

0.1 0.1

0020894 0020902 0.3 Whitehill Shale, onshore Namibia 0190107 0.84 0.02 0190108 0.67 0.00 0190109 1.52 0.03 0190110 1.98 0.15 0190111 0.18 0.01

0.7 0.5

0.6 1.2

403 442

532 113

459 287

-25.9 0.56

0.1

0.8

1.0

446

292

347

-26.2 1.3 3.5 about 3.1 above 1.2

-24.4 -21.5 -19.4 -18.6

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) Methane [%] Ethane [%] Propane [%] iso-Butane [%] Butane [%] i-Pentane [%] n-Pentane [%] 2methyl-pentane [%] 3methyl-pentane [%] Hexane [%] iso-Heptane [%] Nitrogen [%] C2+ iC4/nC4

0000907 (BGR) 96.8 1.7 0.2 0.0 0.0 0.0 0.0

A-13827 96.8 1.8 0.2 0.0 0.0 0.0 0.0

A-13852

A-14012

A-14244

86.9 1.4 0.1 0.0 0.0

94.5 2.3 0.4 0.1 0.1

87.1 1.3 0.1 0.0 0.0

94.4 2.4 0.4 0.1 0.1

0.5

0.0

0.0

0.0

1.5

0.0

0.0

0.0

9.1 4.0 0.3

2.5 3.0 1.0

11.5 1.4 0.5

2.5 3.1 1.0

0.4

0.0

0.0

0.9 2.0 1.0

0.9 2.1 1.0

Appendix A: Geochemistry 0000906 (BGR) C1/(C2+C3) C2+C3 δ13C1 δ13C2 δ13C3 δCO2 δD

0000907 (BGR)

A-13827

A-13852

157 A-14012

A-14244

50.9 1.9

48.6 1.99

55.2 1.6

34.7 2.7

62.4 1.4

33.7 2.8

-36.7 -28.2 -22.6 -12.3 -150

-36.7 -27.9 -22.6 -11.9 -152

-37.1

-37.9

-37.0

-37.6

-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 13

δ C Benzol/Toluol Benzol/Cyclohexan Benzol/Heptane Cyclohexan/Heptane Toluol/Octan Methylcyclohexan/Toluol Pristane/nC17 Phytane/nC18

0000909 -24.5 0.29 1.07 0.85 0.79 1.31 0.68 0.27 0.15

0000910 -24.5

-24.6

158

Appendix B: Basin Modelling

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) 1A,B 2A 2B 2C 2D 2E 3A 3B 4A 4B 4C 4D 4E 5A 5B 5C 7A 7B 7C 7D 7E 7F 8A 8B 8C 8D 8E 8F 9A 9B 9C

(126.00-121.50) (121.50-121.30) (121.30-121.10) (121.10-120.90) (120.90-120.70) (120.70-120.50) (120.50-120.15) (120.15-119.85) (119.50-119.30) (119.30-119.10) (119.10-118.90) (118.90-118.70) (118.70-118.50) (118.50-117.15) (117.15-117.85) (117.85-117-50) (116.00-115.90) (115.09-115.82) (115.82-115.74) (115.74-115.66) (115.66-115.58) (115.58-115.50) (115.50-115.40) (115.40-115.32) (115.32-115.34) (115.34-115.16) (115.16-115.08 (115.08-115.00) (115.00-114.93) (114.93-114.80) (114.80-114.67)

9D 9E 9F 10A 10B 10C 10D 10E 10F 11A 11B 11C 11D 11E 12A 12B 12C 12D 12E 14B 14C 14D 14H 14I 14J 15C 15D 15E 21A 21B

(114.67-114.54) (114.54-114.41) (114.41-114.28) (114.28-114.15) (114.15-114.02) (114.02-113.89) (113.89-113.76) (113.76-113.63) (113.63-113.50) (113.50-113.35) (113.35-113.20) (113.20-113.05) (113.05-112.90) (112.90-112.75) (112.75-112.60) (112.60-112.45) (112.45-112.30) (112.30-112.15) (112.15-112.00) (110.50-99.50) (100.00-99.50) (99.50-99.00) (95.50.94.75) (94.76-94.00) (93.50-93.00) (90.50-90.35) (90.35-90.15) (90.15-90.00) (68.00-67.50) (67.50-67.00)

3rd-order (fundamental) sequences (composed of 4thorder parasequences) 6A 13A 13B 13C 13D 13E 13F 13G 14A 14E 14F 14G 15A 15B 16A 16B 16C 16D 16E 17A 17B 18A 19A 20A 22A

(117.5-116.0) (112.0-109.5) (109.5-108.5) (108.5-107.5) (107.5-106.0) (106.0-105.0) (105.0-104.5) (104.5-103.0) (103.0-100.5) (99.0-98.0) (98.0-96.5) (96.5-95.5) (93.0-91.0) (91.0-90.5) (90.0-88.5) (88.5-87.5) (87.5-85.0) (85.0-83.0) (83.0-80.0) (80.0-79.0) (79.0-77.5) (77.5-75.0) (75.0-71.0) (71.0-68.0) (67.0)

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 13, 14, 15-16 (112.0-80.0)

Appendix B: Basin Modelling

159

Table B.2: Compilation of the events defined for the basin simulation study including time, interval velocity and heat flow assignment. EventNo. 36 35 34 33 32 31 30 29 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1

Event name Hiatus Quarternary Tertiary 5 Tertiary 4 Tertiary 3 Tertiary 2 Tertiary 1 Hiatus Erosion Erosion Campanian / Maastrichtian Santonian 6 Santonian 5 Santonian 4 Santonian 3 Santonian 2 Santonian 1 Turonian Erosion Erosion Erosion Erosion Erosion Cenomanian Aptian / Albian Source Rock Reservoir Barremian Hiatus Hiatus SDR wegde 4 SDR wedge 3 SDR wedge 2 SDR wedge 1 Basementtop Basement

Time at base [Mabp] 5.00 10.00 20.00 30.00 40.00 50.00 55.00 62.90 68.73 75.00 84.00 84.80 85.00 85.50 86.50 87.00 88.00 93.00 93.54 94.29 94.91 95.41 96.00 102.00 112.00 114.00 115.00 117.50 120.00 124.00 126.00 128.00 131.00 133.00 150.00 200.00

Intervalvelocity [m/s]

2100 2100 2100 2100 2100 2100

2370 2370 2370 3200 3370 3370 3370 3370

4000 4155 4500 4500 4500

5400 5600 5800 6000 6500 7000

Heat flow [mW/m2] 62.0 62.1 62.2 62.4 62.6 62.8 63.0 63.2 63.7 64.3 65.0 65.0 65.4 65.4 65.4 65.9 65.9 67.2 67.2 67.4 68.0 68.0 68.7 71.7 80.0 94.3 99.3 130.0 130.0 130.0 130.0 130.0 130.0 130.0 130.0 130.0

160

Appendix B: Basin Modelling

Table B.3: Lithological input parameter for the 2D basin model. Thermal conductivity at 20 °C [W/m/K] Thermal conductivity at 100 °C [W/m/K] Heat Capacity at 20 °C Heat Capacity at 100 °C Density [kg/m3] Initial Porosity [%] Permeability at 5 % Porosity [log mD] Permeability at 75 % Porosity [log mD] Anisotropy permeability [log] Anisotropy thermal conductivity Migration Saturation Radioactive heat source [HSU] Diffusion coefficient

Shale 1.98

Shale silty 2.05

Sand 3.12

Shale sandy 2.32

Basalt 2.20

1.91

1.94

2.64

2.12

1.95

0.213 0.258

2.10 0.25

0.178 0.209

0.205 0.248

0.200 0.220

2680 65 -5.50

2677 62 -5.35

2660 42 -2.00

2674 57 -4.50

2750 5 -16.00

-1.00

-0.70

0.00

0.00

-16.00

2.5

2.3

1.5

2.2

1.0

1.50

1.40

1.10

1.40

1.00

0.05 0

0.05 0

0.02 0

0.05 0

0.05 10

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]

Kerogen → Oil

500

1.99E+26

Kerogen → Gas

Oil → Gas

100

1.00

5.77E+31

3.16E+26

Activation Energy Factor [kcal/mole] 1.00

1.00

54.94

Redcuction Factor

Activation Energy [kcal/mole]

Generation Factor [%]

46 47 48 49 50 51 52 53

0.003 0.027 0.124 0.284 0.323 0.182 0.051 0.007

58 61 64 67 70 73 76

0.008 0.074 0.269 0.383 0.215 0.047 0.004

1.00

1.00

0.45

Appendix B: Basin Modelling

161

Table B.4b: Kinetic input parameters for calculation of petroleum generation according to TISSOT et al. 1988. Reaction Type

Total Potential [mg/gTOC]

Frequency Factor [1/Ma]

Kerogen → Oil

492

2.87E+27

Kerogen → Gas Oil → Gas

Activation Energy Factor [kcal/mole] 1.00

Redcuction Factor

Activation Energy [kcal/mole]

Generation Factor [%]

40 48 50 52 54 56 58 60 62

0.014 0.010 0.057 0.555 0.293 0.045 0.012 0.008 0.006

1.00

1.00

1.00E+00

1.00

1.00

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

Total Potential [mg/gTOC]

Frequency Factor [1/Ma]

Kerogen → Oil

556

7.56E+25

Kerogen → Gas Oil → Gas

Activation Energy Factor [kcal/mole] 1.00

Redcuction Factor

Activation Energy [kcal/mole]

Generation Factor [%]

43 45 46 47 48 49 50 51 52 53 56 57

0.030 0.070 0.210 0.270 0.210 0.100 0.040 0.020 0.020 0.010 0.010 0.010

1.00

1.00

1.0E+00

1.00

1.00

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: Geologiestudium: Gymnasium: Orientierungsstufe: Grundschule:

2000 – 2004, RWTH Aachen 1993 – 1999, Universität Kiel, Abschluss Diplom 1986 – 1993, Max-Plank-Schule, Wilhelmshaven, Abschluss Abitur 1984 – 1986, OS Heppens, Wilhelmshaven 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