Petroleum Geoscience of the West Africa Margin

Petroleum Geoscience of the West Africa Margin

31 March – 2 April 2014

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CONTENTS PAGE

Conference Programme Pages 3 - 6

Oral Presentation Abstracts Pages 7 – 106

Poster Presentation Abstracts Pages 107 - 109

Fire and Safety Information Pages 110 - 111

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PROGRAMME

Monday 31 March

08.30 Registration 09.00 Welcome – Teresa Sabato Ceraldi Session One: Regional and Megaregional Setting Session Chair Matt Warner 09.30 Keynote Speaker: Gérard Stampfli (Université de Lausanne) Global Plate Tectonic Model for the Last 600 Ma 10.00 Alexander Bump (BP) Tectonics of Rifting and Break-up in the Central Segment of the South Atlantic, Angola and Brazil 10.25 Gianreto Manatschal (University of Strasbourg) The Role of Hyperextension, Mantle Exhumation and Magmatic Processes in Shaping the South Atlantic Rifted Margins 10.50 Break 11.20 Duncan Macgregor (MacGeology Ltd) Controls on Drainage Systems across West Africa: Impact on Reservoir Prediction and Quality in Deepwater Plays 11.45 Mads Huuse (University of Manchester) Overburden Plumbing Systems as a Key to Hydrocarbon Exploration and Geohazards Assessment along the West African Margin 12.10 Stephen O’Connor (Ikon) Understanding the Pressure Regimes along the West Africa Margin and Their Implications for Prospectivity 12.35 Lunch Session Two: North West African Margin to Nigeria Session Chair Hannah Suttill 13.30 Keynote Speaker: Paul Dailly (Kosmos Energy) Cretaceous Fan Plays of the African Transform Margin 14.00 Jonathan Redfern (University of Manchester) Unraveling the Depositional History and Evolution of the Moroccan Atlantic Margin during the Early Cretaceous: Implications for Offshore Petroleum Systems 14.25 Antonio Martín-Monge (Repsol) An Unusual Proterozoic Petroleum Play In Western Africa: The Atar Group Carbonates (Taoudeni Basin, Mauritania) 14.50 Break 15.20 Matthew Taylor (Chariot Oil & Gas Limited) Clastic Bypass on the Atlantic Margin – Exploring for post-Salt Carbonates on the Shelf and Clastic Plays on the Slope and Basin 15.45 Allen Brown (Anadarko) The Campanian Quartz Claystone Conundrum of the Africa Transform Margin 16.10 Kathleen Gould (Neftex) 3D Modelling Offshore Ivorian Basin, African Equatorial Margin: Application of a Sequence Stratigraphic Framework in Regional Exploration Screening

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16.35 Nick Kusznir (University of Liverpool) Central and Equatorial Atlantic Ocean-Continent Transition Structure and Location from OCTek Gravity Inversion 17.00 Discussion Facilitators Matt Warner and Hannah Suttill 17.30 Wine Reception

Tuesday 1 April

08.30 Registration 09.00 Welcome Session Three: Nigeria to Gabon Session Chair Richard Hodgkinson 09.15 Keynote Speaker: Rob Crossley (Robertson UK Ltd) New Insights into the Tectono-Stratigraphy of Gabon 09.45 Steve Lawrence (ERCL) The Cameroon Volcanic Line (CVL) As A ‘COTL’ (‘Continental-Oceanic Tectonic Link’) and Its Influence on the Petroleum Endowment of the Douala Basin. 10.10 Neil Hodgson (Spectrum) Evolving Plays in Deep-water Gabon 10.35 Break 11.05 Byami Jolly (Imperial College London) The Interaction between Young Deepwater Channel Systems and Growing Thrusts and Folds, Toe- Thrust Region of the Deepwater Niger Delta 11.30 Onoriode Esegbue (Newcastle University) Diamondoid Hydrocarbons in Petroleum Fluids from the Niger Delta Indicate Co-Sourcing From a Deep Petroleum System 11.55 Israel Etobro (Plymouth University) Tectonic Inversion and Petroleum System Implications in the Passive Margin of Benin Basin, Southwestern Nigeria. 12.15 Lunch Session Four: Angola Session 1 Session Chair Teresa Sabato Ceraldi 13.40 Keynote Speaker: Alastair Fraser (Imperial College London) The Long and Winding Road: Oil Exploration Offshore Angola: Past, Present & Future 14.10 Brianne Alleyne (Maersk Oil) Rift, Sag, Salt:The Tectonic Evolution of the Central South Atlantic Oil Province 14.35 Anne McAfee (Core Laboratories) Rift-to-Drift Succession of the South Atlantic ‘Mature Margin’: Some Ambiguities and Anomalies Revealed by Revisiting the Rock Record 15.00 Break 15.30 Paola Ronchi (Eni E&P) Pre-Salt Carbonates in West Africa: Are the Analogues Enough To Understand Their Distribution? 15.55 Tako Koning (Gaffney, Cline & Associates) Brazil’s Deepwater Pre-Salt Oil Play as a Model for Pre-Salt Oil Exploration in Deepwater West Africa 16.20 Nicky White (University of Cambridge) Causes and Consequences of Long Wavelength Vertical Movements along the Angolan Margin 16.45 Discussion Facilitators Teresa Sabato Ceraldi and Richard Hodgkinson

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17.15 Wine Reception

Wednesday 2 April

08.30 Registration 09.00 Welcome Session Five: Angola Session 2 Session Chair Douglas Paton 09.15 Keynote Speaker: Mike Mayall (BP) Facies and Reservoir Types in Deepwater Slope Systems 09.45 Gemma Jones (Imperial College London) Ponded Fan Development and Evolution within a Salt-Controlled Mini-Basin, Offshore Angola 10.10 Paul Green (Geotrack International) The Tectonic Development of the Onshore Namibe Margin of Angola 10.35 Break 11.05 Leanne Cowie (University of Liverpool) OCT Structure, COB Location and Magmatic Type of the Southern Angolan Margin From Integrated Quantitative Analysis of Deep Seismic Reflection and Gravity Anomaly Data 11.30 Tako Koning (Gaffney, Cline & Associates) Fractured and Weathered Basement Reservoirs- an Overlooked High Risk but Potentially High Reward Oil & Gas Objective in West Africa 11.55 Christophe Serié (ConocoPhillips) Overburden Fluid Flow Analysis Offshore Angola: Implications for Petroleum Systems 12.20 Craig Koch (PGS) Regional Prospectivity of Offshore Namibia and the Angolan Namibe Basin 12.45 Lunch Session Six: Walvis Ridge to South West African Margin Session Chair Tim Goodwin 13.45 Keynote Speaker: Ian Davison (Earthmoves Ltd) Contrasting Extensional Styles North and South of the Walvis-Rio Grande Ridge, South Atlantic 14.15 Piet Lambregts (Shell) Exploring For Hydrocarbons in a Deepwater Boutique Basin: Orange Basin, South Africa 14.40 Neil Hodgson (Spectrum) De-Risking Source Rocks and Plays, Deep-Water Orange River Basin 15.05 Break 15.35 Douglas Paton (University of Leeds) Variations in the Structural and Volcanic Nature of the South West African Margin 16.00 Tobias Dalton (University of Leeds) Along Margin Variability of Gravity Collapse Structures in the Orange Basin 16.25 Closing Statement – Peter Dolan (Ophir Energy) 16.55 Closing Remarks & Finish

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POSTER PROGRAMME

1 Frank J Peel (University of Southampton) Inversion of the Internal Architecture of SDR Complexes to Derive Magma Supply Rate, Thickness of the SDR Pile, and an Estimate of Relative Palaeobathymetry 2 Duncan Macgregor (MacGeology Ltd) Controls on Drainage Systems across West Africa: Impact on Reservoir Prediction and Quality in Deepwater Plays 3 Mads Huuse (University of Manchester) Overburden Plumbing Systems as a Key to Hydrocarbon Exploration and Geohazards Assessment along the West African Margin 4 Nick Kusznir (University of Liverpool) Central and Equatorial Atlantic Ocean-Continent Transition Structure and Location from OCTek Gravity Inversion 5 Israel Etobro (Plymouth University) Tectonic Inversion and Petroleum System Implications in the Passive Margin of Benin Basin, Southwestern Nigeria 6 Paola Ronchi (Eni E&P) Pre-Salt Carbonates in West Africa: Are the Analogues Enough To Understand Their Distribution? 7 Tako Koning (Gaffney, Cline & Associates) Fractured and Weathered Basement Reservoirs- an Overlooked High Risk but Potentially High Reward Oil & Gas Objective in West Africa 8 Douglas Paton (University of Leeds) Variations in the Structural and Volcanic Nature of the South West African Margin

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Oral Presentation Abstracts (Presentation order)

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Monday 31 March Session One: Regional and Megaregional Setting

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Keynote Speaker: Global Plate Tectonic Model for the Last 600 Ma

G. M. Stampfli, Earth Sciences Institute (ISTE) Geopolis, UNIL, CH-1015 Lausanne

The new plate tectonic reconstruction model developed at UNIL (which in 2010 was sold by UNIL to Neftex Petroleum Consultants Ltd) is supported by a database including a wide range of constraints. With the permission of Neftex, this paper presents the model as it was before the transfer of ownership to Neftex. The global plate tectonic model starting at 600 Ma contains more than one thousand “geodynamic units” (GDU) defined on their present day geological history, and assembled as building stones to form terranes. Using the synthetic isochrones methodology (Stampfli and Borel 2002), plates were reconstructed by adding/removing material, along plate limits. Plate velocities were closely monitored as they represent major constraints in the kinematics of the involved terranes and continents, in conjunction with paleomagnetic data.

This was an iterative process where geological data were always put forwards, but at a certain stage the model is also becoming a predictive tool, enabling to make choices according to plate tectonic principles. The basic Wilson cycle had to be largely revised and expanded to include all possible plate interactions. Prevalent in the past were large-scale obduction of intra- oceanic arcs onto passive margins, transforming them into active margins (fig. 1); and also arc-arc collision processes trapping high pressure rocks into mélanges. Such processes are not found on the Earth in the present day.

The full global model is reached around 520 Ma, enabling the exact measure of oceanic versus continental areas from that time onward, as well as the ratio of old versus new oceanic crust. The long-term eustatic variations curve derived from a 3D version of the model is very similar to the generally accepted long-term curve from the literature. The curve largely depends on the many plate tectonics options that were discussed and chosen for these 600 Ma of Earth’s history.

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Large portions of the pre-2010 model have already been published, (see Stampfli et al. 2013 and references therein), and it is also used by Neftex as input to the Geodynamic Module for their Earth Model. On this example (fig. 2, from Vérard et al. 2011, Callovian to Hauterivian southern view, which is in part derivative from the Neftex Geodynamic Earth Model. © Neftex Petroleum Consultants Ltd. 2011), one can see that the oceanward subduction of a major back-arc along South-America generated enough slab pull to trigger the opening of the South- Atlantic ocean in connection with the Indian ocean opening.

References

Stampfli, G.M., Borel, G.D., 2002. A plate tectonic model for the Paleozoic and Mesozoic constrained by dynamic plate boundaries and restored synthetic oceanic isochrons. Earth and Planetary Science Letters 196, 17-33. Stampfli G.M., Hochard, C., Vérard, C., Wilhem, C., von Raumer J., 2013. The formation of Pangea. Tectonophysics 593, 1-19. Vérard, C., Flores, K.,Stampfli, G.M., 2011. Geodynamic Reconstructions of the South America– Antarctica Plate System. Journal of Geodynamics, 53, 43-60.

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Tectonics of Rifting and Break-up in the Central Segment of the South Atlantic, Angola and Brazil

Alex Bump1, Leslie Neal2, Sonja Spasojevic2, Teresa Sabato Ceraldi1

1BP, Chertsey Rd, Sunbury-on-Thames TW16 7LN, UK; 2BP, 580 Westlake Park Blvd, Houston, TX 77079, USA

On the basis of rift timing and sedimentary fill, the South Atlantic is historically divided into three parts, the Austral, Central and Equatorial segments. The Austral Segment is described as a volcanic margin, with flood basalts, thick seaward-dipping reflector (SDR) sequences, no salt and relatively early rifting and break-up. The Central Segment, extending from the Walvis Ridge/Rio Grande Rise northward to the Ascension Fracture Zone, is regarded as non- volcanic, with thick salt deposits and intermediate rift timing. Last, the Equatorial Segment is characterized as non-volcanic, with no salt, highly oblique rifting and relatively late timing. Though broadly correct, these descriptions break down in detail. Recent work on the Angolan margin suggests a somewhat gradational transition between the Austral and Central segments and more complicated progression of rifting. First, volcanism extends well into the Central Segment. The Parana flood basalts underlie the entire length of the Santos Basin and the time-equivalent Entendeka flood basalts are described along the margins of the conjugate Namibe and Benguela basins. SDRs are generally absent, but there are syn-rift onshore volcanics and undated ones observed on offshore magnetics and seismic at least as far north as the Kwanza and Campos basins. Similarly, salt is present through most of the Central Segment but pinches out on the African side well north of the Walvis Ridge. Pre-salt sediment thicknesses vary significantly along strike and across conjugate margins. Last, rift timing is significantly more complicated than previously reported. Within the limits of the dating, the onset of rifting appears relatively similar throughout the Central Segment, around 132Ma. The cessation of rifting is highly diachronous, however. On the proximal margins, active faulting appears to cease by 125Ma, while the more distal parts of the margin continue rifting for another ~20m.y., with the first oceanic crust forming sometime between 110 and 100Ma. Additionally, there is a well-reported failed spreading center in the Santos Basin, with an apparent ridge-jump toward Africa and the ultimate line of break-up.

These observations are united by a new model in which the rift is defined as a series of arcuate segments, with polarity flipping along strike, similar to the modern East African Rift. The southern end of the rift was influenced by the Tristan da Cuna hotspot, which created a halo of volcanism and relatively elevated topography. The onset of rifting was relatively uniform everywhere, but progressively focused toward the center of the rift and the line of eventual break-up. Oceanic spreading began in the middle of the Central segment and propagated along strike, even as the pre-existing spreading center in the Austral Segment was zippering northward. Ultimately, the tips of the two propagating ridges overlapped and the western one was abandoned, producing the apparent ridge-jump toward Africa.

The broad-brush division of the South Atlantic into three segments is a useful starting point, but focused exploration and progression of academic study both require a more detailed model that honors emerging observations. The work presented here is an attempt to make that next step toward a more realistic model.

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The Role of Hyperextension, Mantle Exhumation and Magmatic Processes in Shaping the South Atlantic Rifted Margins

Gianreto Manatschal, IPGS-EOST/University of Strasbourg-CNRS, 1 rue Blessig, F-67084 Strasbourg, France

Research into the formation of deep-water rifted margins is undergoing a paradigm shift. However, at present, little is known about the nature of basement, type and volume of magmatic rocks and the relative contributions of deformation, hydrothermal and magmatic processes associated with the formation of hyper-extended crust. It is also unclear, how far these processes control the depositional architecture and environments of the overlying syn- to post-tectonic sediments, their facies and diagenesis and the subsidence and thermal history. The main problem in understanding these processes is the access to pertinent geological and geophysical data sets. Finding answers to these questions is not only important for the understanding of how rifted margins form and breakup, but also to better evaluate petroleum systems in these frontier areas of hydrocarbon exploration.

In my presentation I will first review key observations made in hyperextended and exhumed mantle domains and will discuss the potential role of extensional structures in explaining extreme crustal thinning, mantle exhumation and lithospheric break-up. A particular focus in my presentation will be on the role of extensional detachment faults during final rifting. Although these structures are widely regarded as playing an important role, the question remains how important these structures are, when and how they form, how well they can account for geological and geophysical observations, how they interact with hydrothermal and magmatic systems and how they may control the overlying sedimentary architecture.

In a second part, I will explore, using published multi channel seismic sections, the relative role of hyperextension, mantle exhumation and magmatic processes during final rifting and lithospheric breakup along the South Atlantic. I will show that the extensional systems are more complex as previously proposed. These systems are often polyphase and are strongly linked with the bulk rheological evolution of the extending lithosphere that depends on the initial composition, thermal structure, the presence of fluids and magma. When, where and how the first magma comes into the lithosphere and how it interacts with the extensional systems may be a key to understand final breakup as well as to explain the variability of the rift structures observed in the distal margins of the South Atlantic. The discussion of how these different processes may interact in time and space and how they may control the final architecture of the South Atlantic rifted margins is the major subject of the talk.

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Controls on Drainage Systems across West Africa: Impact on Reservoir Prediction and Quality in Deepwater Plays

Duncan Macgregor, MacGeology Ltd, Berkshire, UK

The recent history of deepwater plays in West Africa essentially comprises an expansion from the exploration of Cenozoic drainage systems into ‘hidden’ Cretaceous systems. There have been both successes and disappointments as exploration has moved to these older and deeper systems, with reservoir quality becoming an important issue. It is thus pertinent to review our understanding of the evolution of West African drainage systems and question whether we can realistically assess reservoir risk from hinterland studies.

The factors that control sediment supply, type and reservoir sorting are summarised in the chart below. Those that particularly impact reservoir composition and quality are in red.

Essentially a high sediment supply is required to fill the shelfal accommodation space and drive reservoirs through progradation into deepwater. This can be achieved through a combination of high erosion rates, which require the development of slopes through uplift and a wet climate, and focusing through drainage. The mineralogy of the sediment that is fed into deepwater is controlled by its initial provenance plus the degree of sorting to which it is subjected during transport, which is suggested from results to date to be favoured by longer rivers.

These controls are illustrated on a series of time slices illustrating an interpretation of the ever changing palaeotopography, palaeoclimatic and palaeodrainage development of the West African hinterland. Key points on each region are:

 In Namibia, there are key differences in the length of Late Cretaceous drainage systems and sediment provenances between the Orange Basin and Walvis Basin, the latter having shorter rivers that drained a volcanic-influenced hinterland. Cenozoic reservoir supply is lower due to aridity.  Between Angola and Gabon, the main depocentres may have been quite stable between the Late Cretaceous and Oligocene-Recent, although the relative volumes of sediment between these may have changed. These two peaks of sediment and reservoir supply are separated by an intervening period of low supply due to lower topography and dry climate in the Palaeogene. Angolan Cenozoic systems are heavily influenced by Oligocene uplift of the northern part of the South African plateau and respond in harmony with many East African depositional systems.

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 The Niger and Benue have dominated West African drainage systems and sedimentary volumes since the Palaeocene. The supposed reduction in coarse clastic content below top Oligocene could reflect a switch in sediment supply from the Benue to the western Niger system. Even so, this model would indicate some deeper reservoirs would be expected within the ‘Akata Shale’.  The predominant reservoir system in the Equatorial Margin is related to Late Cretaceous uplift and resulting drainage systems. This region has a favourable Basement provenance (the West African craton). The best exploration results seem to have been associated with the longer Cretaceous river systems which drain the craton, particularly a palaeo- Tano/Black Volta system.

 The Senegalese margin is likely supplied by the same uplifts and controls as the Equatorial Margin. Sediment supply on the margin north of here is dominated by the drainage of an Early Cretaceous uplift during a period of wet climate, a ‘mirror image’ to the systems on the conjugate Appalachian margin.

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Overburden Plumbing Systems as a Key to Hydrocarbon Exploration and Geohazards Assessment along the West African Margin

Mads Huuse1, Christophe Serié1,2, Anh Le Ngoc1,3, Uzochukwu Benjamin1 & Neil Hodgson4

1Basin Studies and Petroleum Geoscience Group, SEAES, The University of Manchester, UK 2Now at ConocoPhillips, Houston, USA 3Now at Hanoi University of Mining and Geology, Hanoi, Vietnam 4Spectrum ASA, Woking, UK

Petroleum systems in deep and ultra-deep water are becoming attractive in many parts of the world with particular interest along the West African margin where prolific source rocks and abundant trapping mechanisms have recently resulted in significant hydrocarbon discoveries. Other elements of the petroleum system such as burial history, hydrocarbon migration, and reservoir presence are much more variable leading to mixed exploration success along the margin. Depending on the degree of late-stage sedimentary loading, the West African margins range from passively buried to highly deformed, including thin-skinned salt/shale tectonics and salt diapirism, allowing hydrocarbon leakage to the overburden and eventually the seabed where geochemical sampling and satellite seepage slick detection can be employed (Fig. 1). Additional complications arise in areas of extensive post-rift igneous activity.

Deepwater settings along the West African margin are well imaged by excellent quality 2D and 3D seismic surveys providing unprecedented insights into the overburden plumbing systems, which supply the abundance of petroleum seepage observed along the margin. In this paper, we define overburden plumbing systems as the stock work of stratigraphic and non- stratigraphic (seal bypass systems) elements that control the migration of fluids within the overburden. We compare and contrast examples of overburden plumbing systems analysis in areas characterized by salt and shale tectonics with examples from relatively undeformed margins. In all cases a ‘soft’ Bottom-Simulating Reflection (BSR) has been identified at the base of the gas-hydrate stability zone and used to estimate shallow subsurface geothermal gradients. The estimated geotherms range from normal background (30-35°C/km) to geotherms elevated by the presence of salt diapirs (50-80°C/km), which may locally be further exacerbated by advection driven by lateral transfer of basinal fluids towards structural crests.

Fluid expulsion results in a plethora of seabed phenomena, including pockmarks, brine pools, authigenic carbonate mounds, gas hydrate pingos, mud- and asphalt volcanoes, commonly defined using 3D seismic data and multi-beam echosounders, and occasionally ground-truthed by sampling and optical imagery. Depending on the mix of sediment and fluids being expelled, these phenomena can provide valuable insights into the stratigraphy, geochemistry, subsurface pressure, and hydrocarbon potential of both frontier and more mature areas. Whilst building on time-honoured approaches and techniques, the direct integration of surface observation and sampling with subsurface plumbing systems analysis is currently under-utilized in industry. Considering the abundance and quality of the required data types now available along large parts of the West African margin, a more systematic approach and simultaneous analysis of the shallow subsurface for petroleum systems and shallow geohazards would enhance present and future exploration efforts along the margin.

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Fig.1. Schematic of fluid flow phenomena in passive margins undergoing gravity-driven deformation. The deep-water areas are characterized by the stability of clathrate hydrates below the seabed, which allows a local geotherm to be established. Additional complications arise around salt diapirs and when igneous intrusions are present. From Huuse et al. 2010 (Basin Research, 22, 342–360).

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Understanding the Pressure Regimes along the West Africa Margin and their Implications for Prospectivty

Steve O’Connor, Ikon Science

West Africa is one of the world’s most prolific hydrocarbon producing regions. The margin is also currently very active for exploration, with wells being planned or being drilled all the way from Morocco to Angola. Other notable focus areas have been Ghana, Mauritania and Cameroon. More recently Gabon has been put under the spot-light again. Focus has also moved to the deeper-water, and new Cretaceous plays are being targeted such as the pre-salt and Jurassic carbonates.

One of the key exploration risks along the margin is understanding the pressure regime. This clearly has proved problematical during the various phases of drilling in West Africa, as evidenced by the number of kicks taken, for instance, in the Niger Delta and Cameroon. This observation suggests that the pore pressure regime is not understood fully even in areas where existing well penetrations are present. We as a community are also drilling in wildcat settings where there is little well calibration and/or targeting new, unexplored plays, making the chance of pressure-related problems even higher.

Part of the complexity of pressure prediction along the margin is due to the highly variable lithology. In Morocco, for instance, Jurassic carbonates are proving exploration targets. These are frequently associated with taking drilling losses. Eocene carbonates are also present. Carbonates of Albian/Aptian age can be very well developed in Kwanza Basin, Angola for instance. In Gabon, throughout the offshore, drilling is below the Ezanga salt. In some areas the pre-salt Gamba reservoirs are normally pressured, in others, highly overpressured. In Mauritania, Cretaceous reservoirs in clastics have very variable pressure; the shale pressures are frequently much higher than their associated reservoir pressures. In the Niger Delta, the challenge is that due to the very deep drilling, the shales are very hot and secondary overpressure mechanisms are more likely. A similar issue exists for the Cretaceous along the entire margin, where results using seismic-based pressure prediction are variable at best. Finally, in Cameroon, the pressure regime appears particularly unpredictable, with many shallow kicks taken. Another variable is the amount of Tertiary loading with shales, and the change in tectonic styles along the margin i.e. compression, uplift and the presence of unconformities.

To this end, we present case study material from the margin, as well as use analogues from other basins such as the Gulf of Mexico, Red Sea, SE Asia and North Sea to help understand, for instance, possible carbonate and pre-salt pressures. These observations will benefit future drilling programmes but can also be used develop new exploration strategy. For instance, where reservoir pressures are less than encasing shales suggests pressure dissipation has occurred in the reservoirs. These pressure sinks allow enhanced primary migration and are associated with hydrodynamic trapping. In the Niger Delta deep-water, fields have tilted contacts and enhanced seal capacity where reservoirs have lost pressure.

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Monday 31 March Session Two: North West African Margin to Nigeria

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Keynote Speaker: Cretaceous Fan Plays of the African Transform Margin

Paul Dailly, Kosmos Energy, Dallas, TX

The tectonic evolution of the West African transform margin has resulted in rapidly varying subsidence, thermal and basin fill histories for each for sub-basin, causing considerable variations in how the hydrocarbon play elements stack. The discovery of the Jubilee Field in 2007 opened up the Late Cretaceous play and was followed by a large increase in exploration drilling activity throughout the margin. Since the Jubilee discovery in 2007, 39 exploration wells have been drilled along the margin resulting in 21 discoveries, but to date there is only one additional sanctioned development which is also located in the Tano Basin. A significant number of these exploration wells have encountered live hydrocarbons indicating the presence of an extensive working petroleum system throughout large parts of the transform margin, however limited commercial success to date beyond the Tano Basin appears to be associated with a combination of reservoir and trap/seal issues. The success of the play in the Tano Basin may be associated with its structural configuration which is strongly associated with a suite of NW trending extensional faults connecting the St. Paul and Romanche FZ’s and by NE oriented transpressional highs associated with movement on the transforms. This structural fabric creates intra-slope highs and lows and may help reduce bypass of the reservoir systems to the ultimate basin floor, as appears to have happened in many of the other transform basins. Trapping of the sands further up systems tract has helped to juxtapose good reservoir fairways with the part of the basin most likely to yield combination and pinch-out traps.

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Unraveling the Depositional History and Evolution of the Moroccan Atlantic Margin During the Early Cretaceous: Implications for Offshore Petroleum Systems

Jonathan Redfern1, Giovanni Bertotti2

1 North Africa Research Group, University of Manchester 2 TU Delft

Exploration areas along the Atlantic Seaboard offer significant reservoir potential in the undrilled deepwater areas offshore Morocco. The development of Early Cretaceous clastic sequences onshore (Fig 1.), with associated slope incision along the margin, together with the recognition of seismic attribute and reflector configurations in the deepwater licences, support the possibility of deep marine turbidites in this interval.

Early Cretaceous terrigenous sands are widespread offshore NW Africa. Age-equivalent coastal and deltaic successions of the Tan Tan Fm in Morocco, and outcrops along the coastal margin provide support for the presence of a clastic source for the turbidites, and potentially significant sediment input to this segment of the Atlantic Margin between the Berriasian - Albian. However a detailed understanding of the depositional facies, and the evolution of the margin through time is lacking.

Fig.1 Location of early Cretaceous outcrops and conceptual palaeogeography. Modified from Onhym

The subsidence and erosional history of the margins of the Atlantic passive margin are controlled by tectonics driving continental exhumation and erosion, following the appearance of oceanic crust in the Central Atlantic (passive margin stage) and prior to the onset of Atlas shortening. Recent data documents Middle Jurassic to Early Cretaceous exhumation and erosion in the High Atlas, the anti‐ Atlas and, further to the S, on the Reguibate shield, an elongated N‐ S area experiencing exhumation that partly coincides with the “West Moroccan Arch”. The area experiencing exhumation was flanked to the West by a domain of continuous subsidence, part of which is the Essaouira-Agadir basin.

The sediment eroded from the exhuming areas were routed by fluvial systems into a domain of continuous subsidence along the coastal and continental shelf, forming submarine deltas such as the Tan Tan delta, and shed further into the subsiding passive margin.

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The tectonics driving continental exhumation and erosion are poorly known. Recent work by Bertotti and co-authors have used low temperature geochronology to document 2-3km of exhumation and erosion of the Moroccan Mesata (Bertotti and Gouiza 2012) during the late Jurassic to Early Cretaceous. The mechanism for the vertical movement is uncertain. Lithospheric thinning models predict only 50-60% of the observed subsidence by post-rift thermal relaxation and <30-40% of the observed exhumation can be explained by processes related to the evolution of the Central Atlantic rifted margin. Syn-sedimentary structures in Middle Jurassic to Lower Cretaceous formations of the Essouira-Agadir basin range from m- scale folds and thrusts to km-scale sedimentary wedges. The structures systematically document coeval shortening generally oriented at high angle to the present margin.

Ongoing studies are characterizing the variability of the depositional setting and lithofacies within the Early Cretaceous section along the Atlantic margin. Improved dating will refine often poorly controlled stratigraphic relationships. The significance of key surfaces within the Cretaceous section will be important to correlate offshore, some of which indicate significant base level drops and optimum times for sediment delivery. The presence of extensive shallow marine intervals correlate well with the limited offshore well control. Interpretation indicates deltaic systems with extensive shoreface deposits but the detailed facies analysis, distribution and temporal evolution is still being developed. The new study will also undertake extensive petrographic work to aid characterization of the potential provenance of sediments transported offshore into deepwater.

Fig 2. Extensive cliff sections of Cretaceous continental red beds, Guezira Beach

Stacked continental red beds, with braided fluvial to alluvial sequences (Fig.2) suggest a potential high net sand content source for sand delivery into the basin, although their textural immaturity will clearly generate deepwater sands with a different reservoir character. Their distribution and overall depositional setting still needs to be assessed.

Understanding the controls on basin evolution, exhumation in the interior and drainage history, will help to reduce the risk in locating reservoirs offshore, and determining optimum location for best reservoir quality

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An Unusual Proterozoic Petroleum Play In Western Africa: The Atar Group Carbonates (Taoudeni Basin, Mauritania)

R. Baudino1, A. Martín-Monge1, L.M. Gairifo-Ferreira1, S. Haryono1, S. Soriano2, N. El Hafiz1, J. Hernán- Gómez1, I. Brisson1,4, G. Grammatico1,3, M. Ochoa1, R. Tocco1, M. Badalì1, B. Chacón1, R. Varadé1, H. Abdallah1

1Repsol Exploración, SA, Madrid, Spain. 2Repsol USA, Houston, USA. 3Presently at Dana Petroleum, Aberdeen, UK. 4Presently at YPF, SA, Buenos Aires, Argentina.

The Taoudeni Basin, one of the main structural units of the West Africa craton, is a poorly explored basin (Fig. 1). With an area of more than 1,800,000 km2, it is the largest sedimentary basin in Africa. It is well developed in Mauritania and Mali, and extends marginally into Algeria, Burkina Faso and Senegal. This intracratonic basin contains up to 5–6 km of Proterozoic to Mesozoic–Cenozoic sediments in its depocentre. Outcrops along its 1,100-kilometre-long northern edge allow studying the Proterozoic and Paleozoic succession of the basin, and identifying the main depositional cycles. The sediment infill is dominated by marine clastic sediments, but during the Mesoproterozoic, a thick stromatolitic unit with interbedded claystones and shales, the Atar Group, was deposited. The Atar Group constitutes the main petroleum play of the basin. The basin underwent several phases of deformation since the Proterozoic; the Hercynian orogeny defined its present configuration, and the subsequent Mesozoic subsidence was very low. During the Late Triassic to Early Jurassic times, the Taoudeni Basin suffered an intense phase of volcanic intrusion.

Figure 1: Geological map of the Taoudeni Basin with indication of the main sedimentary units, exploration wells drilled to date, and seismic coverage available in the Mauritanian portion. Orange outline is Repsol/RWE Dea acreage. Geological map modified from Callec et al. (2008).

Only six exploration wells have been drilled to date in the Taoudeni Basin, but its hydrocarbon prospectivity was already established in the early exploration period. The Abolag-1 well, drilled in 1974 by Texaco, flowed about 0.48 MMscf per day of gas (and possibly some condensate)

31 March – 1 April 2014 #WestAfrica14 Page 30 Petroleum Geoscience of the West Africa Margin from the Atar Group fractured carbonates. Abundant bitumen and other hydrocarbon evidences are widespread across the basin. The Atar Group sediments also contain black shales in the Touirist Formation, which constitute a world-class hydrocarbon source rock. These organic-rich intervals have excellent petroleum generative potentials, with TOC contents ranging from 5 to 25%, and contain oil-prone organic matter of predominantly bacterial origin.

All these data hold promise in the quest for economic accumulations of hydrocarbons. However, they are counterpoised by the uncertainties related to a long and multi-phased tectonic evolution, a complex thermal history with relatively young magmatism, and a potentially problematic reservoir. Carbonate reservoir quality is generally difficult to predict, moreover when dealing with such an ancient environment with a prolonged diagenetic history and no known modern analogue.

Various disciplines and techniques were integrated in the study of this unusual, high-risk play, including seismic interpretation, non-seismic geophysical methods, detailed outcrop description and sampling, shallow drilling, source rock characterization, rock and fluid analysis, surface geochemistry, thermal and maturity analysis, structural and sedimentological studies.

This fully-integrated multidisciplinary approach provides a prime example of work in petroleum exploration, and emphasizes the importance of integration in uncovering new critical knowledge in frontier areas. In this contribution, we will review the techniques used and the main results that allowed us to gain enough confidence to drill such a challenging target.

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Clastic Bypass on the Atlantic Margin – Exploring for Post-Salt Carbonates on the Shelf, and Clastic Plays on the Slope and in the Basin.

Matthew Taylor, Julia Kemper, Ian Thomas, Paul Ramsey and Juliet Crosby, Chariot Oil & Gas Limited

Post-salt exploration on the Atlantic margin has been successful in both carbonate and clastic plays on the shelf, and clastic targets which have predominated in the deepwater section. We show examples from around the African Atlantic margin where it appears that canyon controlled sediment bypass has allowed thick sands to be shed into the basin through a predominantly carbonate shelf edge.

Looking firstly in offshore Namibia, the few wells drilled to date indicate a dominantly carbonate shelf in Albian times passing up into a more clastic dominated sequence in the Upper Cretaceous and Tertiary with locally persisting carbonates on the shelf edge in the Upper Cretaceous. In these circumstances the deepwater siliciclastic sedimentation may be thought to be vulnerable to reservoir degradation due to reworking of the shelf edge carbonates. However, careful analysis of seismic and well data illustrates that the post Albian shelf edge carbonates are very localised buildups on promontories between existing deep canyon systems (Picture 1) that do not cut down to the carbonates of Albian age. Also, in Namibia, the hinterland includes Etendeka volcanics, but sedimentologic analysis of well samples shows that Etendeka volcanic derived clasts diminish significantly in the sediments from Albian times. This suggests that river systems have largely cut through the volcanic pile within 30 million years of their extrusion. As such, neither carbonate nor volcanic material is expected to be significantly reworked into late Cretaceous and younger deep marine sandstone systems associated with the canyons.

N S W E

Carbonate buildup

Picture1 Dip and Strike line through Shelf-edge Carbonate Buildup between incised Canyons

Moving north into the Central Atlantic, where Chariot has acreage in Mauritania and Morocco, this older (Triassic-Jurassic) basin is typically bounded by a carbonate shelf system in the Jurassic section that may extend up into the Lower Cretaceous and is generally succeeded by clastic dominated Upper Cretaceous and Tertiary sequences. Deepwater targets are typically Cretaceous to Tertiary age clastics that may have entered the deep basin from incised entry points that can downcut into the carbonate platform. Few of these fans have been tested by drilling to date except in Mauritania. Here Tertiary fan sands typically have good quality in terms of poroperm but the associated canyons appear to downcut only into the Cretaceous (e.g. Vear, 2005, fig. 7) and as such carbonate debris is probably minimal. In northern Mauritania there appears to be a gap in the Jurassic carbonate shelf (op. cit. fig. 4) and Cretaceous fan sands also appear to have reasonable or good poroperm characteristics.

In Morocco Chariot is focussed on exploring the shelf edge carbonate plays but also recognises a deepwater Cretaceous clastic play (Picture 2). Here, the primary Jurassic carbonate lead has unusually well developed build up geometries which may well be related to its location on the footwall to a landward hading extension fault. This effectively produced a bathymetric high isolated from the mainland and upon which bioherms could therefore develop uncontaminated by clastics, (Picture 3).

The deepwater Lower Cretaceous clastic play appears to be controlled by canyon systems down-cutting into the Jurassic platform and in these circumstances there may be concerns about shelf carbonates contaminating and downgrading the reservoir quality of the siliciclastics 31 March – 1 April 2014 #WestAfrica14 Page 33 Petroleum Geoscience of the West Africa Margin through the reworking of the carbonates. However, as clastics begin to dominate on the shelf from the Lower Cretaceous, the siliciclastics in the basin may be expected to be of better quality with little or no carbonate contamination.

Tertiary/Cretaceous Jurassic Platform SE NW Turbidite Fans Edge Carbonates 0km NORTHERN REGION

LOWER CRETACEOUS TERTIARY Buildup JURASSIC UPPER CRETACEOUS UPPER JURASSIC LWR-MID JURASSIC 5km OCEANIC LOWER JURASSIC CRUST TRIASSIC SW

10km Picture 2 Cartoon Section Across Carbonate Shelf and Adjacent Basin

Picture 3 Seismic (in Depth) Showing Buildup Geometries in the Jurassic Carbonates

In summary, Chariot has acquired data in a variety of locations along the African Atlantic margin where both clastic and carbonate plays are developed. Understanding the geological relationships of the basin and shelf is key to targeting optimal reservoirs in both deep water clastic plays and in shelf carbonates.

Reference. Vear, A. et al Deep Water Plays of the Mauritanian Continental Margin. Petroleum Geology Conference series 2005; v. 6; p. 1217-1232

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The Campanian Quartz Claystone Conundrum of the African Transform Margin

Scott Birkhead, Allen Brown, David McLean, Philip Towle, Howard White, Yafei Wu, Anadarko Petroleum Corporation

Since 2007, Anadarko Petroleum Corp. has participated in drilling over 65 deepwater wells (exploration, appraisal and development) along the African Transform Margin between Sierra Leone and Benin, a distance of over 1800 km (FIG. 1). Many of these wells encountered a 100m to 225m thick Mid to Lower Campanian section that has been described in the field as medium to dark grey, non-calcareous “claystone”. Similar descriptions have been reported under laboratory conditions. On wireline logs however, the sequence may be interpreted as porous sandstone with Gamma Ray readings averaging 30-40 API units but as low as 15 API. Neutron-Density responses are similar to what would be expected from relatively clean sandstones (FIG. 2 and 3). Total porosities are 15% or higher yet permeabilities are extremely low, on the order of 10-6 Darcy. A similar, but much thinner, quartz-dominated “claystone” has also been observed in the Santonian and Turonian. Several avenues of investigation were undertaken to help explain the origin of this unusual facies.

FIG. 1 Regional extent of this unusual ‘quartz claystone’ facies.

X-ray diffraction (XRD) indicates the interval is composed of 60% to 83% quartz with varying amounts of clay minerals. Laser particle size analyses (LPSA) show that this “quartz claystone” section typically consists of 50-70% clay-sized particles with very fine- to medium-grained silt making up most of the remainder. Very fine- to fine-grained sand makes up less than 4% of the total volume. MICP analysis of several wells indicates a high seal capacity potential of between 370m to 805m of oil column (FIG. 2 and 3). This is perplexing for a zone which on first pass log analysis indicates clean, porous quartz-rich sandstone.

FIG. 2 Example of low Gamma Ray zone described as claystone. 31 March – 1 April 2014 #WestAfrica14 Page 36 Petroleum Geoscience of the West Africa Margin

This “quartz claystone” facies has been observed in over 40 deep-water wells and was deposited in an upper to middle bathyal environment. This facies is preserved in the subsurface in extensive areas located between major Lower Campanian prograding channel- fan systems that are typically sand-rich. When present, these sand rich systems have effectively removed and/or hindered preservation of the “quartz claystone” facies. Also, this unique facies has not been observed in inboard locations characterized by delta dominated, shallower water deposition. What conclusions can be made from where this “quartz claystone” or “conundrum” facies is found, where it’s not found and why?

The origin of this “conundrum” facies was proposed earlier (Brown et al, AAPG ACE 2012) as aeolian with windblown, clay-size quartz originating from paleo-arid regions of central Africa. This aeolian source material could have blanketed a very large area depending on the intensity of thousands of dust storms over several million years. There are several modern day examples such as Saharan and Gobe Desert wind storms that can carry dust for hundreds to thousands of kilometers. It appears that inboard shallow water, delta dominated environments that introduced vast amounts of sand have diluted the aeolian fingerprint of the “conundrum” facies to the point where it’s not recognizable. Preservation of the “conundrum” facies in the deepwater can be very dramatic from presence to non-presence in terms of distance, primarily in the strike direction. Observations indicate that the “conundrum” facies has only been preserved when deposited in a deep water, hemipalagic environment away from major sand rich slope channel systems which completely obscure or remove the “conundrum” facies. There are examples where two wells just a few kilometers apart have vastly differently lithologies in the Lower Campanian, one being “quartz claystone” and the other being thick, reservoir quality sands.

Further studies however, particularly under high SEM magnification, indicate that a combination of processes may account for this unusual facies. At 40,000X magnification, euhedral quartz can be seen in the viewed samples. This suggests a possible ‘siliceous ooze’ origin. However, upon further magnification up to 128,000X (FESEM) from Ion Milled samples, discreet aggregates of apparent detrital quartz were observed. This suggests that an aeolian source still could be a major contributor to this facies in addition to a possible authigenic origin from silicia enriched seas. Regardless of the origin(s) of the “conundrum” facies, its’ uniqueness demonstrates the need to focus on detailed SWC analysis to validate petrophysical interpretationsas a reality check, especially for exploration in sparsely drilled areas.

FIG. 3 Another example of this facies w/SWC photo, SEM and thin section.

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3D Modelling Offshore Ivorian Basin, African Equatorial Margin: Application of a Sequence Stratigraphic Framework in Regional Exploration Screening

Kathleen Gould, Colin Saunders and Richard Martin, Neftex, 97 Jubilee Avenue, Milton Park, Abingdon, UK, OX14 4RY

We present a 3D Earth Model of the Ivorian Basin, within the Africa equatorial transform margin, and demonstrate its use for the rapid assessment of play potential. This region has an exciting recent exploration history and number of world-class discoveries. The still frontier nature of much of the margin make it an ideal candidate for a regional play evaluation.

Regional play evaluations demand the integration of large volumes of geoscience data from multiple sources, including wells, seismic and structure maps. This is best achieved through the complete integration of data, applications and products within the 3D environment. Recent advances in computer hardware and software, in particular Petrel 2012 from Schlumberger Information Solutions*, enables us to load and manipulate all the data required to build 3D geological models and offers an environment where all data and interpretations are fully integrated. This improves efficiencies and adds increased insight into the geological basis for petroleum system and play-fairway analyses.

The Ivorian Basin hosts several exciting discoveries in a number of plays, however hydrocarbons in commercial quantities withn Late Cretaceous deepwater sands, comparable to those in offshore Ghana, have not yet been achieved. By working in a 3D environment, we are able to explore the potential of the deep water by introducing sequence stratigraphy into the depth model to predict the location, lateral extent and stacking of deepwater sandstone reservoirs. The 3D model allows us to predict where potential reservoir quality may be compromised by deep burial, as well as define the regional extent of source rock facies by their level of maturity. This tectono-stratigraphic integration provides new insights into the known petroleum systems on the margin and high grades areas for further exploration.

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Central and Equatorial Atlantic Ocean-Continent Transition Structure and Location from OCTek Gravity Inversion

Nick Kusznir1,2, Andy Alvey2 & Alan Roberts2

1Earth and Ocean Sciences, University of Liverpool, Liverpool, L69 3BX, UK 2Badley Geoscience Ltd., Hundleby, Spilsby, Lincolnshire, PE23 5NB, UK

The determination of continent-ocean boundary (COB) location, ocean-continent transition (OCT) structure and magmatic type for the continent-ocean margins of the Central and Equatorial Atlantic, and the prediction of their heat-flow history, presents a substantial scientific and technical challenge common to all frontier deep-water hydrocarbon exploration. Using OCTek satellite gravity anomaly inversion, we have produced comprehensive regional maps of Moho depth, crustal thickness, continental lithosphere thinning and oceanic lithosphere distribution for this region and its West African continental margins. These results from gravity inversion provide estimates of OCT structure and COB location which are independent of magnetic isochrons. Crustal cross-sections using Moho depth from the OCTek gravity inversion allow continent-ocean transition structure to be determined (e.g. narrow versus wide) and also provide constraints on their magmatic type (magma poor, “normal” or magma rich).

Superposition of illuminated satellite gravity data onto crustal thickness maps from gravity inversion provides improved determination of pre‐ breakup conjugacy and post-breakup trajectory of the North and South American and West African margins. By restoring crustal thickness & continental lithosphere thinning to their initial post-breakup configuration we can show the geometry and segmentation of the rifted continental margins at their time of breakup, together with the location of highly-stretched failed breakup basins and rifted micro-continents. Restoration of crustal thickness maps for the Central Atlantic to the time of Jurassic breakup shows a string of isolated rift basins (and proto-ocean basins) directly comparable in scale and geometry with the Malawi-Rukwa-Tanganyika-Albert Lakes rift system of East Africa. These restorations indicate that the eastern Canary Islands of Fuerteventura and Lanzarote are underlain by continental crust located at the southern end of a continental sliver (micro- continent) extending northwards which was pulled out of the southern Moroccan continental margin. For the Equatorial Atlantic, crustal thickness mapping from gravity inversion clearly shows the partitioning of margins into oblique rift and transform segments and their conjugate margin relationship. Restorations of crustal basement thickness determined from gravity inversion show a set of isolated deep-water ocean basin and during early post-breakup times in the early Equatorial Atlantic.

Continental lithosphere thinning and post-breakup residual thicknesses of continental crust determined from gravity inversion have been used to predict the preservation of continental crustal radiogenic heat productivity and the transient lithosphere heat-flow contribution within thermally equilibrating rifted continental margin and oceanic lithosphere. The resulting crustal radiogenic productivity and lithosphere transient heat flow components, together with base lithosphere background heat-flow, are used to produce regional grids and maps top-basement heat-flow history. These maps and grids produced by OCTek gravity inversion provide valuable input to petroleum systems & basin modelling.

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Tuesday 1 April Session Three: Nigeria to Gabon

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Keynote Speaker: New Insights into the Tectono-Stratigraphy of Gabon

Rob Crossley1 , Victoria Cole1, Stephen McKenna2, Thomas Kubli2

1 Robertson UK Ltd 2 Addax Petroleum

Many of the wells in Gabon have historically targeted the Gamba sandstone, and commonly terminate either low in this sandy package or immediately below it. This level coincides with the Coniquet Formation, a package of inversion phase sediments which our new work shows is developed across much of Gabon. This unit can include reworked palynomorphs and recycled organic matter, giving ambiguous age indicators and thermal maturity values inherited from the syn-rift phase. Excluding these confusing data, a new collation of 489 wells paints a clearer picture of the tectono-stratigraphy of the Gabon margin.

Warp Phase: This phase is represented by the Kougoulou Group. It was re-defined to include the basal succession in the Gabon margin. The warp phase initially trapped alluvial sediments (M’Vone and Bilantem Formations) in their original valleys on the African surface. As subsidence continued, drainages were diverted into the line of the future rift and large shallow freshwater lakes fringed by alluvial plains developed (N’Dombo and M’Vily Formations). With continued subsidence and additional capture of drainage, these lakes coalesced into a shallow mega-lake that extended throughout Gabon (Grès de Base, Vanji and Kékélé Formations). The sands were deposited in fluvial, deltaic and shore-face settings, and are interbedded with thin coaly and lagoonal deposits. The result is a widely correlative sand-dominated sequence up to a few hundred metres thick forming a potential reservoir target, which extends across Gabon and into the Reconcavo Basin of Brazil.

Rift Phase: As faulting became more important, many hundreds of metres of freshwater lacustrine mudstone were deposited. This phase included good quality oil-prone source facies and continued for several million years (Kissenda, Lucina and Melania Formations). In the latter stages, rotation of fault blocks was accompanied by deposition of major fluvial channel sands in a mud-rich setting (Dentale Formation), representing deposition from a major north to south flowing river system.

Inversion Phase: In central Gabon, fault blocks including the Lambarene Horst were uplifted by hundreds to thousands of metres, and tectonically linked grabens in the north subsided by similar amounts. Other fault blocks further south in the rift floor, and the flank of the rift beyond the basin margin, were also uplifted. The deposits resulting from this event include conglomeratic sands and muds (Coniquet Formation) and are generally only a few metres to tens of metres thick but are many hundreds of metres thick within the grabens. Much of southern Gabon represented a bypass zone for thinly-spread basement-derived gravels sourced from the eastern flank of the rift.

Sag Phase: The conglomeratic sediments are overlain by a transgressive coastal sequence comprising diachronous sand-dominated clastics (Gamba Formation). These are typically described as beach sand, but include sabkha, fluvio-deltaic, beach and shoreface facies. With increasing transgression, these clastics are overlain by mudstones, minor limestones and dolomitic carbonate (Vembo Formation), before deposition of a regressive sequence of evaporitic sabkha sediments including gypsum, halite, K-salts and Mg-salts (Ezanga Formation).

Evidence of marine waters is first detected in the graben systems associated with the inversion phase and becomes increasingly abundant through the transgressive pre-salt sequences of the sag phase. At all levels the biota indicate a restricted setting where marine waters were subjected to major fluctuations in salinity.

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The Cameroon Volcanic Line (CVL) As A ‘COTL’ (‘Continent-Ocean Tectonic Link’) and Its Influence on the Petroleum Endowment of the Douala Basin

S. R. Lawrence1, O. X. Jackson2 and A. Beach3

1 ERCL 2 Glencore Exploration 3 Exploration Outcomes

The Cameroon Volcanic Line (CVL) is a 1200km-long NE-SW-trending linear belt of volcanic islands and seamounts extending from onshore Cameroon (i.e. on continental crust) across the Gulf of Guinea on oceanic crust to the island of Pagalu (Annobon). Volcanic ages (oldest recorded offshore is 31Ma on Principe) are much younger than the underlying oceanic crust (Albian). In this way the CVL can be viewed as a re-activated segment of a more extensive volcanic line that extends to St. Helena a further 2100km to the south-west.

Previous studies (e.g. Myers and Rosendahl 1991) have hinted at a tectonic component to the formation of the CVL. The following observations support the idea of significant tectonic activity:

1. Cretaceous sediments (?Turonian) cropping out on Bioko Island (see Villalta and Assens 1967).

2. Upper Eocene-Oligocene sediments encountered within 250m of the surface on Sao Tome Island in the Ubabudo-1 corehole.

3. Lithified sandstones of unknown age cropping out on Sao Tome Island (Hedberg 1969).

4. Myers and Rosendahl’s (1991) recognition of crustal uplift/buckling and the so-called ‘uplift unconformity’ on Project Probe seismic data.

5. The asymmetry of the uplift displayed on Project Probe seismic data e.g. across Sao Tome (Myers and Rosendahl 1991).

6. Deformation of oceanic crust seen on Project Probe seismic data e.g. northern end of Line 29 (Myers et al. 1998).

We have rationalised the tectonics associated with the CVL from our interpretation of 2D and 3D seismic datasets across the Douala Basin as follows:

 Uplift/inversion of the volcanic centres (positioned astride fracture zones) marked by Myers and Rosendahl’s ‘uplift unconformity’ at near Base Miocene.

 Deformation of oceanic crust and overlying sedimentary section by long-wavelength buckling and short-wavelength re-activation of fracture zone faults.

We have synthesised these observations into a model for the formation of the CVL. This invokes a tectonic link between the Ascension Fracture Zone (AFZ) and the continental shear-zone system of the Central African Shear Zone (CASZ) forming what we call a Continent-Ocean Tectonic Link (or ‘COTL’). This builds on ideas for the re-activation of the CVL linked to stress release via the AFZ proposed by Fairhead & Binks (1991) and Fairhead & Wilson (2005).

We propose that a ‘mega-jog’ was activated along the original CVL by sinistral strike-slip movement between the two master structures. Along the jog-zone the oceanic fracture zones were rendered leaky by dilation giving rise to rejuvenated volcanism. The volcanics are the obvious manifestation of this early tectonic phase although there may have been extensional reactivation of fracture-zone faults during this phase.

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The compressional tectonics can be explained by a reversal of the regional stress field to dextral strike-slip and inversion of the jog-zone. This has lead to the tectonic uplift of the volcanic centres by inversion of ‘old’ (Cretaceous) extensional fracture-zone faults. Oceanic crust deformation has also taken place away from the volcanic centres along re-activated fracture-zone faults in the transpressional northern part of the system straddling the continent- ocean boundary (COB) here called the Bioko Deformation Zone. Stratigraphic relationships indicate that this first significant compressional phase took place in the Early Miocene.

The timings of these key events in the history of the re-activated CVL and ‘COTL’ development are consistent with marked changes in relative motion of Africa with respect to Eurasia at 37Ma (‘Pyrenean’) and 22Ma. In the Fairhead and Binks model the re-activational stresses emanate from the Mid-Atlantic Ridge. We propose that these stresses link-up, across the COB, with movement on the CAFZ induced by the ‘far-field’ effects of Alpine collision, thus creating the ‘COTL’. It is possible that from the Late Eocene the status quo stress regime along the CVL is the dilationary sinistral field explaining the varying ages of volcanicity. This is interrupted by key episodes of Alpine collision effecting a ‘locking’ of the system (can be visualised as a reversal) resulting in tectonic inversion.

In addition to the tectonic effects described above, flexural moat development as a consequence of volcanic loading is proposed to explain the thickening of the pre-uplift sequence around the volcanic centres. This would have commenced soon after the initiation of the CVL re-activation and before Early Miocene compression meaning that the moat section was inverted together with the volcanic centres.

Implicit in the proposed model is that CVL re-activation and ‘COTL’ development was intrinsic to the evolution of the Douala Basin from at least early Tertiary times. The petroleum endowment can be partly attributed to the unique set of conditions imposed by ‘COTL’ development. Structures have formed by inversion around volcanic centres and folding/faulting along the Bioko Deformation Zone. Multiple source rock and reservoir intervals occur over a wide stratigraphic range in ‘pre-moat’, ‘moat’ and ‘post-uplift’ mega-sequences. Moat development and volcanically-elevated heat flow along the CVL increases the maturity of pre- moat and moat source rocks and since there was no sub-aerial erosion and cooling, hydrocarbon generation continued uninterruptedly subsequent to early Miocene inversion/deformation.

References De Villalta, J. F. and Assens, J. 1967. Hallazgo de un ammonites cretacico en la isla volcanic de Fernando Poo (Guinea ecuatorial Espanola). Acta Geologica Hispanica, 11, no. 5, pp. 117-118. Fairhead, J. D. and Binks, R. M. 1991. Differential opening of the Central and South Atlantic Oceans and the oprning of the West African rift system. Tectonphysics, 187, pp. 191-203. Fairhead, J. D. and Wilson, M. 2005. Plate tectonic processes in the South Atlantic Ocean: Do we need deep mantle plumes. Special Paper Geol. Soc. Am. 388, pp. 537-553. Hedberg, J. D. 1969. A geological analysis of the Cameroon trend. Ph.D. Thesis, Princeton Univ. 188p. Meyers, J. B. and Rosendahl, B. R. 1991. Seismic reflection character of the Cameroon volcanic line: Evidence for uplifted oceanic crust. Geology, 19, pp. 1072-1076. Meyers, J. B., Rosendahl, B. R. et al. 1998. Deep-imaging seismic and gravity results from the offshore Cameroon Volcanic Line, and speculation of African hotlines. Tectonophysics, 284, pp. 31-63.

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Evolving Plays In Deep-Water Gabon

Neil Hodgson and Anongporn Intawong, Spectrum Multi-Client UK, Dukes Court, Duke Street, Woking, Surrey, GU21 5BH, United Kingdom

Historical exploration success in Gabon comprises two distinct play fairways; a post-salt system in the north and a pre-salt system in the south. The northern post-salt play is dominated by Cenomanian/Turonian sourced oil in either Ogooue river delta clastics draped over salt diapirs, or Albian aged carbonates in intra-salt pods or rafts. The southern sub-salt play comprises syn-rift fluvial and sag-phase shallow marine sands charged by lacustrine source rocks in fault bounded structural traps.

Recently, successful extension of this southern, pre-salt play from the shelf into moderately deep water (ca 1700m) of the slope, has fomented new exploration interest in deeper-water Gabon. The phase of the liquid in this discovery and the potential for the presence of this play- fairway across the whole southern salt basin, is discussed.

A striking difference exists between the post-salt sequences of north and south Gabon. Whilst the Ogooue River provides dip-provenanced clastics the northern basin, a similarly positioned sediment source is lacking in the southern basin, and instead clastics are strike-provenanced from the Congo fan. Unlike the north, this generates stratigraphic closures as the up-slope pinch-out is assured. However, the few tests of this play to-date have been unsuccessful in large part due to lack of charge. In the southern salt basin, the thinned post-salt section appears not to have a working Cenomanian/Turonian source, and surprisingly there is no charge from pre-salt source either. This is a curious observation as in many South-Atlantic salt basins, grounded pods or “salt-welds” provide migration paths between the pre and post salt sequences, and these are abundant in South Gabon. Possible causation for this is discussed, with relation to the behaviour of salt in this southern basin.

However, a Congo fan play can be found in Gabon – out beyond the salt basin. The characterization of this play, including oil source, reservoir and potential traps are discussed, and we propose that this ultra-deep-water play will provide an intriguing future oil exploration target on this margin.

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The Interaction between Young Deepwater Channel Systems and Growing Thrusts and Folds, Toe-Thrust Region of the Deepwater Niger Delta

Byami A. Jolly, Lidia Lonergan & Alexander Whittaker, Department of Earth Science and Engineering, Imperial College London, SW7 2AZ, England, UK

Structures found in the “toe-thrust” region of gravity-driven systems such as the Niger Delta, exert a significant control on sediment gravity flows because they create and determine the location and configuration of sediment depocentres and transport systems. However, to fully understand the interaction between sediment gravity flows and seabed topography we need to evaluate and quantify the geomorphic response of submarine channels to faulting in such areas which in turn, will provide better insight into the distribution of reservoir facies in those settings.

This study combines seismic and geomorphic techniques to quantitatively investigate how the growth of thrust-related folds has influenced the pathways of Plio-Pleistocene deepwater channel systems in the Niger Delta. We first mapped folds and thrusts from 3D seismic data, and used this data to reconstruct the history of fold growth. We then used the seabed seismic horizon and the depth-to-base of channel cut-and-fill sequences horizons to build 50m resolution Digital Elevation Models (DEM) in Arc-GIS. From the DEMs, we extracted channel long-profiles across growing structures for both the modern (active) channels and the associated containers (entire cut-and-fill sequences) including channel systems that have been abandoned. We measured channel geometry at regular intervals along the channel length to evaluate system response to tectonic perturbation; and how these affect the distribution of reservoir facies.

Deformation started between 12.8 and 9.5 Ma and is expressed as both fault-propagation and detachment folds. Many of the thrusts are still actively growing and influencing the pathways of modern seabed channels. Growth rate of thrust-related structures with active seabed relief that affect seabed channels pathways is c. 15m/Myr. However, the detachment folds are able to cause channel diversion at a lower growth rate.

The bathymetric long profiles of these channels are relatively linear with concavities that range from -0.0 to 0. and average gradient of c. 0.9 o. The profiles are characterized by knickpoints that occur near mapped structures and therefore appear to respond to variations in substrate uplift rate. Channel incision across growing structures that has led to the development of knickpoints along the channel pathway, is achieved through enhanced bed shear stress-driven incision (up to 200 Pa) and flow velocity (up to 5 m s-1). This increase in channel incision is the geomorphic expression of having higher slopes, but in most cases, the channel widths remains fairly constant. Comparison of structural uplift since 1.7 Ma, and channel incision over an equivalent period, showed that some of these channels are able to keep pace with the time-integrated uplift since 1.7 Ma; and may have reached a topographic steady-state with respect to this structural uplift. However, some of the channels have yet to reach topographic steady-state because of a number of factors which include recent change in gradient caused by structural uplift, and the impact of active channel diversion by growing structures.

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Diamondoid Hydrocarbons in Petroleum Fluids from the Niger Delta Indicate Co- Sourcing From a Deep Petroleum System

Onoriode Esegbue1, Martin Jones1, Pim van Bergen2 and Sadat Kolonic3

1School of Civil Engineering and Geosciences, Newcastle University. UK. 2Shell UK Ltd, Aberdeen, UK. 3Shell Petroleum Development Company of Nigeria.

The Niger Delta petroleum system is one of the world’s most prolific hydrocarbon provinces, yet the origin of the vast amounts of oil and gas found in numerous (sub-)basins across the Delta remains contested. Two principle source rocks, the Miocene and Eocene mixed type II/III, respectively, are often reported to be the origins of the Tertiary reservoired oils of the Delta, although contributions from a deeper Cretaceous source have also been suggested but not proven to date. This study uses petroleum geochemical techniques, including biomarker and diamondoid hydrocarbon analyses, to provide further information on the hydrocarbon sources and post-generation alteration process that affected these large oil accumulations in the Delta. A total of 148 oil samples from more than 30 oil fields onshore Niger Delta were analysed for their SARA contents and used gas chromatography (GC) and GC-mass spectrometry. In addition, 47 samples were studied using GC isotope-ratio mass spectrometry to yield a detailed organic geochemical characterisation.

The hydrocarbon biomarkers imply inputs from various organic matter sources, from terrestrial to marine. They allow no clear correlation to a single source rock but rather imply mixed contributions, including those from various potential source ages. To help resolve the complex petroleum mixture, diamondoid hydrocarbon parameters were used for the first time on these Tertiary reservoir hosted oils. This was to investigate source, maturity and biodegradation effects and to allow cross-correlations. The diamondoid abundances and distributions support the hypothesis of a sub-delta Type II marine source that produced oil which was later thermally cracked and then biodegraded and finally mixed with oil of lower maturities in the reservoirs. Mixing of oils in the basin is further supported by the presence of demethylated hopanes in light oils from several of the reservoirs that have complete ranges of n-alkanes. Statistical principal component analyses of eight diamondoid correlation parameters indicate that the suspected highly mature, deep seated sourced oils are from the same genetic family.

Three oil families can be broadly identified from the oil samples analysed in this study:

 Family A is the highly cracked oil from a Type II marine shale and is mostly biodegraded. Based on geochemical results this oil contributes about 90% of the oil accumulations in some fields,  Family B is a Type II marine shale sourced oil from the Akata Formation which has contributed a higher percentage to the accumulations than that of the Family C oils,  Family C oils, are probably more Type III sourced oils from shales inter-bedded in the Agbada formation and are of lower maturity than the other two.

Biomarker contamination during migration appears an important process in this complex geological setting and as such would potentially yield erroneous interpretations based on standalone routine geochemical analyses. Future geochemical interpretations should treat the Niger Delta oils as potentially mixtures of oils of variable maturities from different sources, often with the most important source biomarkers depleted because of the extent of thermal cracking.

Key words: Niger Delta, petroleum systems, maturity, biomarkers, diamondoids, sub-delta.

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Tectonic Inversion and Petroleum System Implications in the Passive Margin of Benin Basin, Southwestern Nigeria

Etobro, Israel Abiodun Aruoriwo1,2, Watkinson, Matthew1, Anderson, Mark1

1School of Geography, Earth and Environmental Sciences, Plymouth University, Plymouth.PL4 8AA United Kingdom. 2Department of Geology, Delta State University, PMB 01, Abraka. Delta State Nigeria.

This study reveals that the Late Jurassic-Early Cretaceous Benin Basin within the Gulf of Guinea has experienced at least two phases of localised tectonic inversion in the (i) mid- Cretaceous (Aptian) and (ii) Late Cretaceous (Santonian). The fault geometry associated with the Aptian event suggests that a low angle thrust fault prevailed. This was restricted to inversion of syn-rift half-grabens immediately post-dating rifting. A syn-inversion sequence developed, marked by divergent growth strata. This succession has not been drilled, but seismic facies suggest that they are characterised by low to high amplitude of continuous to discontinuous reflectors. The Santonian inversion appears to be more pronounced long-lived and less localised, since it prevailed until the Latest Maastrichtian. Its growth strata consist of coarsening upward sequence of coarse-grained sandstones and shales. Structures associated with both phases of inversion can be confused for syn-rift or differential compaction-related folding.

Recognising inversion is important when considering petroleum system risks and opportunities especially in less prospect basins such as the Benin Basin. Most of the initial extensional structures (roll-over anticlines) were already in place before the maturation of the source rock (Early Cretaceous shale deposits) in this basin. Syn-rift sequences comprising of shale and sandstone units of the Ise Formation and the later post-rift Albian shale and carbonate units could serve as good petroleum systems in this basin. A later Santonian compressional inversion probably exhumed the potential reservoir rock to a shallow depth where biodegradation could have affected the accumulated hydrocarbons in this basin. Another effect of the tectonic inversion in the offshore Benin Basin is the erosion of early deposited shale seal subsequent to uplifting. The Santonian event which seems to control the deposition of Cenozoic sediments as it created depressions where canyons were feeding into the offshore parts of this basin and hence a future petroleum play in the offshore Benin Basin.A good understanding of these subtle tectonic inversion events is therefore required in order to limit the risks in overall hydrocarbon prospectivity in this basin.

Other studies (Benkhelil et al., 1998; Briggs et al., 2009; Warren, 2009) have proposed that contractional tectonics affected the Nigerian Atlantic margin region during the Santonian. This study demonstrates that these effects were more widespread, both in time and geographic distribution, and provides important age constraints on the timing of this tectonic deformation.

References

Benkhelil, J., Mascle, J. and Guiraud, M. (1998) 'Sedimentary and structural characteristics of the Cretaceous along Cote d'Ivoire-Ghana Transform Margin and in the Benue Trough : A comparison', Mascle, J., Lohmam, G.P. and Moullade, M. (eds.). Proc. Ocean Drilling Programme,Scientific Results,. College Station, Texas, pp. 93-99. Briggs, S. E., Davies, R. J., Cartwright, J. and Morgan, R. (2009) 'Thrusting in oceanic crust during continental drift offshore Niger Delta, equatorial Africa'. Tectonics, 28 (1). pp TC1004. Warren, M. J., (2009) ‘Tectonic inversion and petroleum system implications in the rifts of Central Africa’. Frontier Innovations, Calgary Alberta: CSPG CSEG CWES Convention; pp. 461-464.

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Tuesday 1 April Session Four: Angola Session 1

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Keynote Speaker: The Long and Winding Road Oil Exploration Offshore Angola: Past, Present & Future

Prof. Alastair Fraser, Imperial College London

Offshore Angola has to date delivered recoverable reserves in excess of 20 billion barrels of oil equivalent. This has been encountered in two distinct play systems: the Upper Cretaceous Pinda carbonates sourced by Lower Creatceous lacustrine mudstones and Tertiary deepwater slope turbidite sands sourced by underlying Upper Cretaceous marine mudstones.

Initial discoveries were made in the Pinda carbonates in shallow water offshore Cabinda during the 1980s. A move into deepwater in the mid 1990s to explore a possible extension of the play in a more distal setting, instead resulted in the discovery of the Tertiary turbidite play most notably in Block 17 at Girassol. An extension of the Girassol play into Block 18 to the south will be used to describe how high quality 3D seismic data coupled with a detailed analysis of rock properties led to an unprecedented 6 successes out of 6 wells in the block, including the giant Plutonio discovery.

The shallow Tertiary play having been largely explored, industry is turning once more to the carbonate play potential - this time in deepwater. The equivalent pre-salt carbonate play that has been so prolific in the Santos Basin of offshore Brazil on the conjugate margin is a key target with a recent significant discovery announced by Cobalt Energy at Cameia in Block 21. Given this and renewed interest in the post salt Pinda, it would seem that the Angola offshore success story is set to continue for some time to come.

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Rift, Sag, Salt: The Tectonic Evolution of the Central South Atlantic Oil Province

Dave Quirk, Brianne Alleyne, Matt Howe, Eva Willerslev, Michael Hertle, James Kiely, Anders Madsen, Jakob Kofoed, Madeleine Raven, John Karlo, Niels Schødt, Maersk Oil, Copenhagen

The rifted margins of Gabon, Congo, Angola and Brazil contain significant volumes of oil and gas trapped above and beneath late Aptian salt. The richness of the province owes its origin to a number of tectonic, eustatic and climatic factors which we will illustrate with a plate tectonic reconstruction supported by seismic data, well information and basin modeling.

After a major outpouring of flood basalts, the main phase of continent rifting occurred during the Barremian (~130-123 Ma). Approximately 450 km of extension is recorded in the basins of South Kwanza, Benguela, Campos and Santos basins where the crust was softened and underplated as a result of a mantle plume. Dynamic uplift from the plume meant the amount of syn-rift strata is around 1000 m less than expected. South and north of here, where the crust was colder, seafloor spreading started during the Barremian at ~50 mm/year, a rate which has remained relatively constant to present day.

In the central region, we show that seafloor spreading started by the early Aptian (123 Ma), 10 million years earlier than some published models. The mid-oceanic ridge was initially sub- aerial, marked by an outer volcanic high along both margins. Inboard of the highs, rapid subsidence or sag occurred as the dynamic uplift effect of the plume waned and thermal subsidence set in, leading to margin-wide lakes in what was a semi-arid climate. Outboard of the highs, a narrow ocean developed that fed seawater to the lakes so that they became increasingly saline: organic- and carbonate-rich to start with and ending as salt basins. Marine restriction was enhanced by a late Aptian global sea-level fall. Also, volcanism and hydrothermal activity influenced the basins both prior to and after break up.

At the start of the Albian, accompanied by a global sea-level rise, marine circulation was established throughout the central South Atlantic region as the rifted margins continued to subside and tilt oceanwards. This was accompanied by wholesale flow (drainage) of salt in a seaward direction, recorded by extensional rafting up-dip and by contraction and inflation down-dip, the salt silled by the outer volcanic highs. Salt is a relatively heavy sediment in the first few thousand metres of burial so salt flow resulted in isostatic rebound where it had drained away and significant amounts of additional subsidence due to loading where it collected. This enhanced the tilt of the passive margins, in turn causing more salt to flow in a loopback process.

Two additional properties of salt have influenced the pre-salt play: 1) its high thermal conductivity and 2) its impermeability down to burial depths of around 3 km and thereafter a theoretical change to relatively high permeability which would have facilitated basin de- watering and a reduction of overpressure in the pre-salt sediments.

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Rift-to-Drift Succession of the South Atlantic ‘Mature Margin’: Some Ambiguities and Anomalies Revealed by Revisiting the Rock Record.

Anne McAfee1, Paul Frame2, Marcelle BouDagher-Fadel3 & Luisa Man1

1Core Laboratories, Integrated Reservoir Solutions, Redhill, Surrey, RH1 2LW, UK 2Independent Consultant (now retired) 3University College London.

The recent resurgent exploration effort along the South Atlantic Margin has yielded interesting new insights and ideas on the rift to drift evolution of the basins along the West African Margin, from Angola to Equatorial Guinea. This ‘mature’ segment of the Atlantic Margin has experienced a long history of exploration and discovery and the numerous wells drilled throughout the past five decades have generated a valuable legacy of sub-surface rock and well log data. In the light of proliferating crustal-scale seismic studies across the margin, it is enlightening, if not imperative, to revisit this rich rock record to provide ‘ground truth’ observations on the tectono-stratigraphic evolution of these West African Basins.

Evaluation of the full drilled succession in 100+ wells along the West African margin, tied to data from previous regional basin studies across the Brazilian conjugate margin (Santos to Sergipe-Alagoas Basins), allows us to highlight some interesting rock-based geological observations which provide clues to the syn-rift and early post-rift evolution of the South Atlantic Margin. Some of these observations, which are based on analysis of core and cuttings material, support new seismic-based assertions, but others spotlight ambiguities and anomalies within published regional models.

Within the Pre-Salt succession, sedimentological and petrographical analysis of core material from the Kwanza Basin syn-rift volcanic deposits reveals a range of textures indicative of magma-sediment mingling, suggesting that magma was forcibly intruded into contemporaneous wet lake sediments. Fragmentation caused by rapid quenching of the hot magma created a network of branching ‘vents’ which dissect the feldspar-rich volcanic layers and are filled with carbonate, silica and clay minerals. The sediments which host the highly ‘mingled’ volcanic beds include silty and carbonate lake facies interpreted to be of Neocomian to early Barremian age, however, local interbeds of unaltered ‘pure basalt’ also present within the cored succession are isotopically dated as Aptian in age. These observations suggest multiple episodes of magma intrusion during the syn-rift and early post-rift evolution of the basin and combined with paleogeographic mapping of volcanic rock types across the region, leads to the conclusion that deep-seated fault systems acted as ‘feeder conduits’ for magmatic material and hydrothermal fluids in the Kwanza Basin.

Within the Post-Salt succession, new stratigraphic analysis of cuttings material reveals that a thick succession of Early to Mid Aptian marine sediments is present above the salt in the Kwanza Basin, characterized by a suite of abundant planktonic forams, including species which became extinct at the mid Aptian unconformity (e.g. Hedbergella sigali). These revised, foram- based, ages for the Post-Salt (Binga/Lower Pinda) succession indicates that salt deposition terminated prior to the mid-Aptian in this part of the South Atlantic Margin. In contrast, further north along the Gabon-Congo margin the salt is directly overlain by a succession characterized by Ticinella spp. fauna (Madiela Formation), indicating a Latest Aptian to Albian age for the base of the fully marine Post-Salt succession here. These Ticinella spp. fauna are also recognized within the studied Kwanza Basin wells, but they occur hundreds of metres above the top salt, providing further evidence of an additional depositional package preserved within the Mid to Late Aptian succession here. These observations suggest that the ‘Aptian Salt Basin’ was composed of a series of sub-basins, probably segmented by persistent ?basement- involved topographic elements. Our paleogeographic mapping suggests that the Ambriz Arch may have formed a topographic barrier, preventing northward transgression of fully marine waters until Late Aptian times. South of this barrier, a thick succession of siliciclastic sediments

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Pre-Salt Carbonates In West Africa: Are The Analogues Enough To Understand Their Distribution?

Paola Ronchi, Stefano Dalla, Alfredo Frixa. Eni E&P, Italy.

The continental carbonates of the Lower Cretaceous of the South Atlantic margins have been recognised for years, but only after the great oil discovery of Tupi (2007), did they attract the attention of companies and academies. The pre-salt reservoir of West Africa has being exploited since early seventies in the Congo Basin and recent discoveries are reported also in the Kwanza Basin, raising expectations about a replica of the giant discoveries of the Brazilian Santos Basin.

The continental carbonate system includes a high variability of depositional environments, from subaqueous to subaerial ones, corresponding to a large spectrum of sedimentary facies. This variability was tackled by studying recent and fossil analogues of lacustrine and subaerial deposits (travertine and tufa) in different settings. These studies pointed out the influence of abiotic and biological-induced carbonate precipitation in various climatic and geological contexts, and provided information on the controlling parameters of the lacustrine/subaerial carbonate growth, revealing surprisingly similar aspects among facies belonging to different environments. These analogue studies highlighted that lateral and vertical facies variability is accompanied by an irregular distribution of reservoir quality.

Moreover, the diagenetic overprint was proven a key factor in determining the subsurface reservoir characteristics. Various diagenetic processes control the reservoir quality: low cementation/low compaction allowed the preservation of the primary porosity in granular facies, while karst, silicification and dolomitization produced an efficient secondary porous system.

The South Atlantic pre-salt system may encompass many of the single analogue case histories, from lacustrine to possible travertine deposits, all are proven or expected. In fact, a great variety of the main controlling parameters of carbonate development such as background morphologies, drainage pattern, basin water chemistry, volcanic presence and distribution, subsidence rate, hydrocarbon and hydrothermal vents are seen. Moreover, periodical influx or marine flooding in the lacustrine terraced system may have occurred locally, further complicating the depositional setting. An integrated study which takes into consideration the interplay of the various parameters in a geodynamic context would result in a predictive model for the pre-salt carbonate distribution in the West Africa margin.

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Brazil’s Deepwater Pre-Salt Oil Play as a Model for Pre-Salt Oil Exploration in Deepwater West Africa

Tako Koning, Gaffney, Cline & Associates, Luanda, Angola,

The deepwater pre-salt oil play in Brazil has captured the attention of petroleum geoscientists worldwide. Since South America and West Africa were juxtaposed during the Cretaceous prior to continental separation, there is much commonality between the geology of both areas. Accordingly, when the mega-giant Tupi oil field (now renamed Lula after President Lula) was discovered in 2006, not surprisingly West Africa’s pre-salt sedimentary sequences became the focus of intense interest by the oil industry.

The objective of this presentation is to review public domain geological, geophysical and reservoir data of some of Brazil’s major pre-salt discoveries including Lula, Iracema, Libra, Franco, Sapinhoa, Iara and Carioca. Also discussed are some of the huge technical and logistics challenges associated with producing Brazil’s pre-salt fields including the need to deal with significant volumes of CO2.

Lula Oil Field Tupi (now Lula) was discovered in 2006 in 2,170 meters of water depth and was Brazil’s first super-giant oil field. The reservoirs consist of heterogeneous Cretaceous-age microbial carbonates located beneath 2,000 meters of salt. The reserves of Lula and the adjacent Iracema area to the northwest holds an estimated 8.3 billion barrels of oil equivalent of potentially recoverable resources. Petrobras operates the field on behalf of partners BG Group and Petrogal Brasil. After the discovery was made, an extended well test was carried out beginning in May, 2009 and continued for 18 months in order to provide information on the reservoir connectivity in the Lula field. Two FPSOs (floating production storage & offloading), Lula pilot and Lula NE are currently producing the Lula field.

From the beginning of the project, there were no intentions to vent or flare CO2 from Lula. Currently Lula gas is exported through a gas pipeline and two additional routes are planned. All CO2 is stripped from the gas stream and re-injected back into the reservoir.

In a presentation in 2013 to the Society of Petroleum Engineers at the SPE annual convention held in New Orleans, to illustrate the size of the Lula field, Petrobras showed a map of the Lula field pointing out that it is 44 miles long and 25 miles wide, superimposed over the greater New Orleans area.

The wells in Lula have the potential to produce up to 25,000 bopd (barrels of oil per day) but Petrobras is limiting the production to 13,000 bopd due to gas output restrictions.

Petrobras has been conducting extensive geological evaluations in all of the pre-salt fields to increase its understanding of the pre-salt reservoirs. Over 500 meters of core has been recovered from the pre-salt. Petrobras also plans to use advanced flow monitoring and the extended use of 4D seismic through the deployment of seismic nodes to detect changes in the reservoirs over time.

Libra Oil Field Petrobras, on behalf of the Brazilian regulator Agencia Nacional do Petroleo (ANP) discovered Libra in 2010. The discovery well intersected a continuous oil column of 325 meters carbonate rocks below the salt. Test results indicated good quality light oil with 27 degree API. In October, 2013 Petrobras (40%), Shell (20%), Total (20%), CNPC (10%) and CNOOC (10%) were awarded a 35-year production sharing contract to develop the super-giant Libra field. According to ANP, Libra has the potential of 8 to 12 billion barrels of recoverable oil resources and a total gross peak oil production which could reach 1.4 million bopd. The Libra field is the largest pre-salt oil discovery to date in the prolific Santos Basin. The field is located 170 km off the coast of Rio de Janeiro. It covers an area of 1,550 square kilometres in water depths of 2,000 meters.

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Franco Oil Field In November, 2013 ANP increased its estimates of the Franco field from 3 billion barrels of oil reserves to 5 billion barrels. Eight wells have been drilled to date on the Franco field.

Pre-salt Oil Production Brazil’s currently produces 0,000 bopd from pre-salt reservoirs in the Santos and Campos Basins. The entire volume of pre-salt oil produced to date amounts to 250 million barrels. Brazil’s total oil production is currently 2.1 million bopd. Accordingly, had Lula not been discovered and had the follow-up pre-salt fields not been discovered, then Brazil’s current oil production would have declined to 1.7 million bopd. Currently Brazil’s oil consumption is met by its current oil production but had Lula not been discovered, Brazil would now be a net oil importer which would have had a major impact on its balance of trade.

Petrobras expects that Brazil will produce from the pre-salt 1 million barrels bopd by 2017 and to increase this to 2.1 million bopd by 2020.

West Africa Petroleum explorers are now keenly watching to see if Brazil’s success will be replicated in West Africa. Certainly some of the initial pre-salt drilling in Angola has been encouraging with Maersk in 2011 testing 3,000 bopd from its Azul-1 well and in 2013 Cobalt International Exploration testing 5,000 bopd from the Cameia-1 well and announcing that the well had the capacity to flow at 20,000 bopd. Also encouraging has been the very recent announcement by Total that the Diaman-1 well, the first well to explore in the pre-salt of deepwater Gabon, encountered up to 55 meters of gas pay in pre-salt sandstones thus confirming the existence of a working petroleum system.

Major pre-salt drilling programs will be carried out in West Africa in 2014 and 2015, especially in Angola’s deepwater Kwanza Basin and this will conclusively reveal if Brazil’s pre-salt successes will be replicated in West Africa.

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Causes and Consequences of Long Wavelength Vertical Movements along the Angolan Margin

Nicky White and Mark Hoggard, University of Cambridge

It is widely accepted that convective circulation of the mantle generates transient vertical motions at the Earth's surface. This so-called dynamic topography plays an under-appreciated, but crucial, role in the evolution of accommodation space, structural configuration, and basal heatflow at passive margins with important implications for hydrocarbon generation and migration. In order to measure dynamic topography along a passive margin, we exploit the well-established relationship between seafloor subsidence and plate age. This relationship enables us to map present-day residual depth anomalies for the oldest oceanic crust which abuts any given passive margin. In this way, the spatial variation of dynamic topography can be measured. A global analysis of old oceanic crust shows that dynamic topography varies between +/-1 km with wavelengths of 1000s of kilometers. Along the West African margin, our analysis captures two full wavelengths of dynamic topography which correlate very well with long wavelength free-air gravity anomalies. Offshore Liberia, there is negligible dynamic topography. Near Ghana, we record up to 750 m of negative dynamic topography which gradually increases to 800 m of positive dynamic topography at the Cameroon volcanic line. Further south, the Gabon margin is drawn down by nearly 1 km with a gradual rise to 1 km of dynamic support offshore Angola. This Angolan dome has a diameter of 1000 km and intersects the coastline. Eroded topset deposits, the existence of emergent marine terraces and disequilibrated river profiles all demonstrate that the Angolan dome was generated during Neogene times. The growth of this gigantic feature has had a profound effect upon the development of the Angolan passive margin.

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Wednesday 2 April Session Five: Angola Session 2

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Keynote Speaker: Facies and Reservoir Types in Deepwater Slope Systems

Mike Mayall, BP, Chertsey Road, Sunbury on Thames, Middlesex, TW16 7LN, UK.

Slope systems where contemporaneous structural activity, through faults, shale or salt diapirs, has created variable sea floor topography inevitably results in a highly complex distribution of reservoir facies. Although there is a degree of uniqueness in each slope system there are number of recurring seismic scale depositional elements which are critical to understanding reservoir distribution and type. These are ‘sheet sands’, channel complex systems, and mass transport complexes.

Sheet sands are simply defined as typically 10-40m thick, kilometres wide and usually show as a single seismic reflection event. In details these often contain channels of different types and within this broad group of facies there seem to be two main types of sheets.

Single channel axis. This form of sheet has a single channel axis, which is usually a few hundred metres wide, with sandy levees that thin and wedge away from the axis. The channel axis can be mud or sand filled. These systems can be found anywhere on the slope but are perhaps most common in the upper part of the slope.

Multiple channel axis. Detail mapping and amplitude extraction from this type of sheet reveals multiple small channels each a hundred metres to less than tens of metres wide. The channels commonly branch downstream and cross each other within the limits of the vertical seismic resolution. Downstream the branching channels become smaller, harder to resolve ad pass laterally into more a homogenous character. Comparison with outcrop studies indicate that these are channelized sheets passing downstream into amalgamated sheets. These systems were usually deposited as depositional lobes at breaks of slope and/or within ponded basins.

Channels. Channels can be a range of scales but the most prolific reservoirs are formed in large channel complex systems which are typically 1-3km wide and 100-200m thick. Within the channel complex system, it is usually possible to map two to four channel complexes. At the seismic scale further divisions into basal lags, axis and margin facies is usually possible in most seismic data. Identifying even these basic components of channel complexes can take us a long way in evaluating prospectivity or development options.

Channel complex systems are very sensitive to changes in sea floor topography created by underlying tectonics. The adaption of the form of the channel complex system, and the stacking patterns of the channel complexes within it, are dependent on a number of factors. These include the size of the structure on the sea floor, the orientation of the structure compared to regional palaeoslope, the timing of the formation of the topography and the erosive power of the channels. The response patterns to these interacting factors include deflection of the channels, diversion, offset stacking and deep incision. Each of these has a profound impact on the distribution of reservoir facies within the channel complex system.

Mass Transport Complexes (MTC’s) MTC’s are generally readily identifiable on most seismic data. Local MTC’s usually show classic extension at the head and compressional features at the toe. More extensive MTC’s are typically chaotic or dim on seismic. The two important characteristics of MTC’s are the irregular topography on the top which can pond sand or divert channels and erosion at the base of the complex which is very variable. Where erosion is deep the impact on the underlying sediments is usually obvious. However in many cases the erosion is subtle but can have an important influence on the distribution of reservoir when it is cutting into thin sheet sands.

Different slope systems generally have variable percentages of these three main components, sheet sands, channels and MTC’s, and these commonly change in time and space. Recognising

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Ponded Fan Development and Evolution within a Salt-Controlled Mini-Basin, Offshore Angola

Gemma Jones1, Lidia Lonergan1 and Mike Mayall2

1Imperial College London, Prince Consort Road, London, SW7 2BP 2 BP, Chertsey Road, Sunbury on Thames, Middlesex, TW16 7LN, UK

A succession of four deepwater fan lobe complexes deposited within a salt-controlled mini- basin have been imaged in unprecedented detail using a high resolution three-dimensional (3D) dataset, offshore Angola. The relatively shallow depth of the sediments (approximately 850 m beneath the seabed), coupled with the high resolution of the 3D seismic data (high frequency content, 2 ms vertical sample rate and a bin-size of 6.25 m) allows the plan-view morphology of the fan lobe complexes to be imaged in exceptional detail using amplitude extractions and frequency decomposition. Examining the fan lobe complex on slices made at approximately 25 m vertical separation through the stratigraphy shows how the growth is controlled by both autogenic events within the sedimentary system and allogenic events external to the sedimentary system.

The ponded interval was deposited over a period of approximately 0.8 Ma and consists of four discrete packages, each of which contains at least one lobe complex. There is a systematic change in the shape and orientation of the lobe complexes through time: the two older lobe complexes are oriented broadly north-south and are up to 10 km long by 5 km wide, whereas the youngest lobe complexes are orientated southeast-northwest and have a rounder shape (9 km long by 8 km wide). The gradual north to south movement of the main feeder channel entry point and the distinct change in the lobe complex orientation is attributed to growth of the basin-bounding salt structures.

Figure 1 Fan lobe complex imaged using a root mean squared (RMS) amplitude extraction across a variable window (maximum thickness 25 m) shown (a) uninterpreted and (b) interpreted with the lobe complex (orange), lobes (yellow) and channels (pink) highlighted. The present day salt diapir locations are also highlighted in light pink along with a normal fault, active at the time of lobe complex deposition (white), modified from Jones et al. (2012).

Each fan lobe complex is composed of multiple individual lobes which are formed of a trunk channel and a diverging network of smaller distributary channels commonly fringed by a high amplitude band (Figure 1). The lobes are on average 1.6 km long by 1.3 km wide and are fed by trunk channels which range from 60 – 200 m wide, with thicknesses up to 15 m. These trunk channels branch into distributary channels with widths of less than 30 m. Variation in lobe shape and spatial location is driven by both allogenic and autogenic events, with lobes 31 March – 1 April 2014 #WestAfrica14 Page 76 Petroleum Geoscience of the West Africa Margin responding to topographic growth along the edge of the basin and as well as inherited seabed relief generated by previous lobe growth. Compensational stacking of the lobes is observed where lobes develop in topographic lows between older lobes. In areas where lobe development is constrained by structural growth along the edge of the basin the lobes become elongated and divert away from the growing topography. Where changes in topographic relief are highest, along the edge of the basin and on the downthrown side of a normal fault, the distributary channels within the lobes amalgamate.

Fan complex systems of similar scales have been described in detail in outcrops and in unconfined settings on the seafloor but this is the first study to describe these systems in such detail in the subsurface; resolving the individual lobes and lobe elements within a ponded intra- slope basin. These high resolution plan-view images link the fine-scale sedimentological studies that have been carried out on fan lobe complexes and sheet sands for the past twenty years with less well resolved seismically imaged fan systems. The sheet sands described in outcrop studies can be correlated with features seen in the plan-view amplitude extraction maps: we record densely channelised lobes (channelised sheet facies) passing laterally into more branched, thinner channels and lobe elements (channelised and amalgamated sheets) then terminating in a high amplitude fringe (amalgamated and layered sheets). These features are often hard to link spatially in outcrop settings where only dispersed sections are available but this unique dataset allows the linkages between these facies to be explored. Bridging this gap between outcrop resolution and seismic resolution is important when thinking about reservoir properties; if we can identify features at a seismic scale and link these to properties we have recorded from outcrop studies then this allows a much more thorough understanding of the potential reservoir characteristics. This new Angolan example can be used as a unique analogue to enhance the understanding of reservoir heterogeneities within deepwater fan systems in ponded basins throughout the world.

Reference: Jones G., Mayall M., and L. Lonergan, 2012, Contrasting depositional styles on a slope system and their control by salt tectonics - through-going channels, ponded fans and mass transport complexes., 32nd Annual GCSSEPM Foundation Bob F. Perkins Research Conference “New Understanding of the Petroleum Systems of Continental Margins of the World”’, Pages: 0 -533

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The Tectonic Development of the Onshore Namibe Margin of Angola

Paul F. Green1, Heike Gröger2, Vladimir Machado3 1Geotrack International Pty Ltd, West Brunswick, Victoria, AUSTRALIA 2Statoil ASA, Forusbeen 50, 4035 Stavanger, Norway 3Sonangol Pesquisa & Produção,Luanda, Angola

A growing body of evidence suggests that the evolution of some “passive” margins is anything but passive (see e.g. Paton, 2012). In contrast to simple models in which offshore basins continuously subside while onshore margins are permanently uplifted, recent studies of a number of margins suggest that offshore basins experience uplift and erosion while onshore elevated margins have undergone post-rift subsidence and have been uplifted more recently (see e.g. Japsen et al 2012a,b).

In this study, apatite fission track analysis (AFTA®) data in samples of outcropping Cretaceous sandstones and crystalline basement from the Namibe margin of Angola have been used to assess the tectonic development of the margin. Locations span the region from the coast to the inland Great Escarpment of Angola, at elevations from close to sea level up to ~1600 metres above sea level.

Apatite fission track ages vary between 137 Ma and 294 Ma, and mean track lengths between 10.7 and 13.2 microns, with longer mean lengths generally in samples with younger ages. The results reveal a number of key regional paleo-thermal episodes. Basement samples cooled below ~110°C in the Late Carboniferous-Early Permian (320-285 Ma), and subsequently from around 100°C in the Early Jurassic (195-180 Ma). Both these episodes are recognised across wide regions of southern Africa and are interpreted as representing periods of exhumation linked to regional tectonics.

Sedimentary units deposited along the margin in the Early and Late Cretaceous were derived from provenance terrains which had undergone major cooling shortly prior to deposition of these sediments, most likely resulting from uplift and erosion of basin margins during rifting and breakup.

Contemporaneous with an angular unconformity in the Late Cretaceous sediments, further cooling took place in the Late Cretaceous (85-80 Ma), with peak paleotemperatures in this episode increasing westwards towards the margin. Cooling at this time is also recognised over much of southern Africa and is well documented in Namibia (Raab et al. 2002, 2005). Late Cretaceous cooling is likely to reflect exhumation, although the increase towards the coast in the Late Cretaceous episode may reflect an increased heat flow around the margin.

A final phase of cooling related to uplift and erosion occurred during the Cenozoic and resulted in development of the present-day topography. Geomorphological data together with river longitudinal profile analysis suggests significant Cenozoic erosion along the Benguela and Kwanza basin coast, while along the Namibe basin the Cenozoic event was less significant. The summit of the inland escarpment may not have been covered by sediment at this time, or was perhaps covered by only a thin veneer.

The combination of these events defines an episodic development for the Namibe margin of Angola. These observations, together with similar results from a number of other margins (e.g. Green et al., 2011, 2013; Japsen et al., 2005, 2006, 2009, 2013), show that existing models for passive margin development do not accurately reproduce observed behaviour, and require significant revision. As demonstrated in a previous study in the Kwanza Basin (Machado, 2007; 2012), the last (Cenozoic) erosion event of the Namibe hinterland may have had a significant influence on hydrocarbon generation, expulsion and migration in the offshore basin.

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References

Green, P.F., Duddy, I.R. and Malan, J. 2011. AFTA data show that the southern margin of Africa was buried by Early Cretaceous sediments prior to the onset of regional exhumation. PESGB/HGS Africa Meeting, extended abstract. Green, P.F., Duddy, I.R., Japsen, P., Bonow, J, and Chalmers, J.A. 2013. The tectonic development of Africa’s elevated passive continental margins and implications for exploration. PESGB/HGS Africa Meeting, extended abstract. Japsen, P., Green, P.F. & Chalmers, J.A. 2005. Separation of Palaeogene and Neogene uplift on Nuussuaq, West Greenland, Journal of the Geological Society (London) 162, 299–314. Japsen, P., Bonow, J.M., Green, P.F., Chalmers, J.A. & Lidmar-Bergström, K. 2006. Elevated passive continental margins: Long-term highs or Neogene uplifts? New evidence from West Greenland. Earth and Planetary Science Letters 248, 315–324 Japsen, P., Bonow, J.M., Green, P.F., Chalmers, J.A. & Lidmar-Bergström, K. 2009. Formation, uplift and dissection of planation surfaces at passive continental margins – a new approach. Earth Surface Processes and Landforms 34, 683–699. Japsen, P., Bonow, J.M., Green, P.F., Cobbold, P.R., Chiossi, D., Lilletveit, R., Magnavita, L.P. & Pedreira, A. 2012a. Episodic burial and exhumation in NE Brazil after opening of the South Atlantic. Bulletin of the Geological Society of America 124, 800–816. Japsen, P., Chalmers, J.A., Green, P.F. & Bonow, J.M. 2012b. Elevated passive continental margins: Not rift shoulders but expressions of episodic post-rift burial and exhumation. Global & Planetary Change, 90–91, 73–86. Japsen, P., Green, P.F., Bonow. J.M., Nielsen, T.F.D. and Chalmers, J.A., 2013. From volcanic plains to glaciated peaks: Burial, uplift and exhumation history of southern East Greenland after opening of the NE Atlantic. Global and Planetary Change (in press). Machado, V. 2007. Sand provenance, diagenesis and hydrocarbon charge history of the Kwanza Basin, Angola. A thesis presented for the degree of Doctor of Philosophy at the University of Aberdeen (UK). Machado, V. 2012. Tectonothermal Events Constrained from AFTA: Implications for Sedimentation and Basin Evolution. SPE-Angola Section. Paton, D.A. 2012. Post-rift deformation of the North East and South Atlantic margins: are passive margins really passive? In: Busby, C.A. & Azor, A. (eds): Tectonics of sedimentary basins: Recent advances, 249–269. Blackwell Publishing Ltd. Raab, M.J., Brown, R.W., Gallagher, K., Carter, A. and Weber, K. 2002. Late Cretaceous reactivation of major crustal shear zones in northern Namibia: constraints from apatite fission track analysis. Tectonophysics, vol. 349, p. 75–92. Raab, M.J., Brown, R.W., Gallagher, K., Weber, K. and Gleadow, A.J.W. 2005. Denudational and thermal history of the Early Cretaceous Brandberg and Okenyenya igneous complexes on Namibia’s passive margin. Tectonics, vol. 24, TC3006, doi:10.1029/2004TC001688.

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OCT Structure, COB Location and Magmatic Type of the Southern Angolan Margin From Integrated Quantitative Analysis of Deep Seismic Reflection and Gravity Anomaly Data

Leanne Cowie1, Nick Kusznir1,2 and Brian Horn3

1Earth and Ocean Sciences, University of Liverpool, Liverpool, L69 3BX, UK 2Badley Geoscience Ltd., Hundleby, Spilsby, Lincolnshire, PE23 5NB, UK 3ION Geophysical / GX Technologies, Houston, Texas, USA

Knowledge of the structure of the ocean-continent transition (OCT) and the location of the continent-ocean boundary (COB) are of critical importance for predicting heat-flow history and evaluating petroleum systems in deep-water frontier exploration. The OCT structure, COB location and magmatic type of the southern Angolan rifted continental margin is greatly debated; exhumed and serpentinised mantle have been reported at this margin. Integrated quantitative analysis of deep seismic reflection and gravity anomaly data has been applied to the southern Angolan rifted continental margin in order to determine OCT structure, COB location and magmatic type using ION-GXT Congo-Span deep long-offset seismic reflection data.

The integrated work-flow and quantitative analytical techniques consist of: (i) gravity anomaly inversion, incorporating a lithosphere thermal gravity anomaly correction, which is used to determine Moho depth, crustal basement thickness and continental lithosphere thinning. Sediment thicknesses and horizon depths have been derived from ION-GXT deep seismic reflection data; (ii) Residual Depth Anomaly (RDA) analysis which is used to investigate OCT bathymetric anomalies with respect to expected oceanic values. This includes flexural backstripping to produce bathymetry corrected for sediment loading; (iii) subsidence analysis which is used to determine the distribution of continental lithosphere thinning. The combined interpretation of these independent quantitative measurements is used to determine OCT structure, COB location and margin magmatic type. This integrated approach has been validated on the Iberian margin where ODP drilling provides ground-truth of OCT crustal structure, COB location and magmatic type.

In addition, a new joint inversion technique, using deep seismic reflection and gravity anomaly data, has been developed has been applied to the ION-GXT deep seismic reflection data on the southern Angolan margin. The joint inversion method solves for coincident seismic and gravity Moho in the time domain and determines the lateral variations in crustal basement density and velocity. It provides validation of crustal basement thickness interpreted from deep long-offset seismic reflection data and is used to help further constrain basement type.

Integrated quantitative analysis (gravity anomaly inversion, RDA and subsidence analysis) along the southern Angolan margin ION-GXT CS1-2400 profile has been used to determine OCT structure and COB location. Analysis suggests that exhumed mantle, corresponding to a magma poor margin, is absent beneath the allochthonous salt. The thickness of earliest oceanic crust, derived from gravity and deep seismic reflection data is approximately 7km. Joint inversion shows a contrast in density and seismic velocity between oceanic and continental crustal basement consistent with the location of the COB derived from integrated quantitative analysis.

The thickness and composition of crustal basement are critical elements in the control of hydrocarbon maturation in deep-water rifted continental margin settings; radiogenic heat- productivity from remaining continental basement contributes significantly to hydrocarbon maturation. Predicted crustal basement thickness and composition across the OCT are used to constrain the distribution of crustal radiogenic heat-productivity which together with continental lithosphere thinning derived from gravity inversion and subsidence analysis are used to predict heat-flow history across the OCT.

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Fractured and Weathered Basement Reservoirs- An Overlooked High Risk but Potentially High Reward Oil & Gas Objective in West Africa

Tako Koning, Gaffney, Cline & Associates, Luanda, Angola,

Fractured and weathered basement rocks are important oil and gas reservoirs in various basins in the worldwide including Viet Nam, Indonesia, China, former USSR, Libya and Venezuela. This author has followed this subject very closely for 30 years since working in the early 19 0’s as a development geologist on the Beruk Northeast basement oil field in Central Sumatra, Indonesia. Over the years, he has been involved in evaluating other such fields worldwide. He has published papers on this subject and also has given many presentations on basement oil and gas fields at international conferences and symposiums. He hereby shares his knowledge and experience.

There has been no oil or gas production in West Africa from fractured or weathered basement reservoirs except for a small oil pool in onshore Cabinda, Angola.. However, very few wells have been taken deep enough into basement to evaluate its potential since the traditional mindset of explorationists has been that basement can not contain economic volumes of oil or gas.

About 600,000 barrels of oil was produced in the early 1970’s from fractured basement in a small oil pool in the Central Block, onshore Cabinda, Angola. This was a single-well oil pool sorrounded by dry holes (refer to modified map from SOCO’s 200 website) . Due to civil war security issues in onshore Cabinda (1975 – 2002), the basement play was not followed up. However, the potential certainly exists elsewhere in Angola and other areas including Congo DRC, Congo (Brazzaville) and Gabon where rich Bucomazi lacustrine oil source rocks lay on the flanks of basement highs or overlay them.

The review of geological data in West Africa often shows that the basement in many blocks has been totally unevaluated. In Angola, for example, it is evident that basement has been minimally evaluated. In offshore Cabinda, a number of basement highs underlying producing oil fields have not been evaluated by drilling. Similarly, in offshore Block 2, Lower Congo Basin, very few wells were drilled into basement and in offshore Block 3 no wells penetrated basement.

Since until now there have been no commercial discoveries of oil and gas in basement in West Africa, except for the small oil pool in Cabinda, one must look at analogues elsewhere worldwide as examples of successful, commercial basement oil and gas fields. These analogues then serve as models to be targeted in exploring for basement in West Africa.

Select Analogues 1.) Viet Nam Most of Viet Nam’s oil production is from fractured granite basement in the Cuu Long basin with six major oil fields producing primarily from basement. Overlying and adjacent Oligocene lacustrine shales generated the oil which migrated into the fractured basement. The Bach Ho (White Tiger) is a giant field with recoverable reserves of 1.0 – 1.4 billion barrels of oil. Other fields include Rong, Rang Dong, Ruby and Su Tu Den with oil reserves ranging from 100 to 400 million barrels.

The Ca Ngu Vang (CNV) field, discovered in 2002 is the deepest oil-bearing structure in the basin, where the top of basement is at a depth of 3,700 meters. Indeed, the SOCO-operated CNV-3X well was the longest measured depth well drilled in Viet Nam (6,123 meters) with over 2,000 meters of basement penetrated in a near-horizontal well emplacement and was tested at 13,040 boepd (barrels of oil equivalent per day).

2.) China The Dongshenpu field, onshore central China is an example of a Chinese “buried hill” basement oil field. This field was discovered in 19 and the reservoir consists of

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PreCambrian granites, granulites, diabases and hornblendic metamorphics. The rocks have no primary porosity but the porous reservoirs are due to weathering and fracturing. The discovery well tested at 1,570 bopd and subsequent development drilling has proven the oil column to be 400 meters thick.

3.) Indonesia To date in Indonesia, oil production from basement rocks has been minimal but major gas discoveries in South Sumatra including the giant-size Suban gas field have been made in pre-Tertiary basement reservoirs. Gas reserves in basement are estimated in the range of 5 TCF (trillion cubic feet). This has led to further exploration for gas in basement due to the need for more gas as the Indonesia economy continues to rapidly expand.

The largest basement oil pool in Indonesia is the Tanjung oil field in Kalimantan. This field has produced over 70 million barrels of oil from overlying Eocene sandstones and conglomerates but it has also produced over 20 million barrels of oil from pre-Tertiary basement rocks including weathered volcanic, pyroclastics and metasediments.

4.) North Africa Major gas reserves have been found in basement reservoirs in Libya and Algeria. Oil has been produced from basement reservoirs in the Egypt’s offshore Zeit Bay field, Gulf of Suez.

Best Practices for Exploring & Producing Basement Reservoirs

Best practices include the following:

1.) Production wells should be drilled near-perpendicular to the dominant fracture system.

2.) Exploration wells should also be drilled highly deviated rather than vertical in order to optimally intersect the dominant fracture systems.

3.) Highly focused 3D seismic such as CBM (Controlled Beam Migration) is needed to define the fracture systems in basement.

4.) Extensive core coverage is necessary to provide critically important information on the lithologies and reservoir parameters. Some of the cores should also be radiometrically age dated in order for the geologists to understand the complexities of the basement reservoirs they are dealing with. Development wells must be sufficiently deep to fully drain the reservoir.

5.) Exploration wells should not just “tag” into the top of basement. Rather they should be drilled 100 – 200 meters into the basement in order to fully evaluate it. Development wells must be sufficiently deep to fully drain the reservoir. For example wells in the La Paz field, Venezuela which produces from basement were typically drilled 500 meters into the basement. In a general sense, fractured granites and quartzites are the optimum reservoirs. Weathered “rotten” granites can also be excellent reservoirs as can be observed in outcrop in tropical areas. Rocks such as schists and gneisses are less attractive since they are ductile and tend to “smear” and not fracture when subjected to tectonic stress. The high mafic content of schists also negates the creation of secondary porosity by weathering. Likewise, granites and quartzites are more likely to provide attractive, highly porous “granite wash” sands whereas eroded schists do not produce such good reservoirs.

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Overburden Fluid Flow Analysis Offshore Angola: Implications for Petroleum Systems

Christophe Serié1 & Mads Huuse2

1 ConocoPhillips, Houston, USA 2 SEAES, The University of Manchester, Manchester, UK

As exploration is moving into frontier deep-water areas, high-quality 3D seismic datasets are becoming available in areas where very little information previously existed, allowing a transformation of our understanding of deepwater continental margins, both in terms of their geological evolution, but also in terms of their fluid plumbing systems, which are intimately linked with their prospectivity (e.g. Huuse et al. 2010; Anka et al. (eds) 2012).

An integrated 3D seismic and geochemical characterization of fluid flow phenomena in the southern Kwanza Basin have helped to 1) bring new insight with regard to shallow fluid flow phenomena along the Angolan margin; 2) implement and improve the shallow fluid flow analysis workflow; and 3) define further developments needed to strengthen the significance of shallow fluid flow studies with regard to petroleum system analysis and hydrocarbon prospectivity in deep-water settings in West Africa and beyond (Serié 2013). Detailed integration of seismic, surface geochemistry and surface slick analysis revealed varied and abundant fluid flow phenomena compared to previous studies along the Angolan continental margin. This presentation documents the plethora of overburden fluid flow phenomena found along the Angolan margin and places these in their tectono-stratigraphic context to highlight their significance for petroleum exploration in both relatively mature and frontier settings.

We outline an iterative workflow to document and interpret fluid flow phenomena along continental margins based on the integration of seismic, surface geochemistry and satellite seepage slick data. Seismic interpretation provides information of the tectono-stratigraphic framework, defining the presence of source rock, aquifer, sealing units, as well as structural deformation and igneous activity. Detailed interpretation of seismic scale fluid flow phenomena helps to define the occurrence and intensity of past and present fluid flow phenomena characterized by seep-related seafloor features (pockmarks, gas hydrate, gas hydrate pingos, authigenic carbonates, chemosynthetic communities, mud volcanoes, asphalt volcanoes), as well as shallow fluid flow phenomena such as direct hydrocarbon indicators, bottom simulating reflection (BSR), hydrocarbon-related diagenetic zones (HRDZs), pipes/chimneys, polygonal faults, diagenetic fronts, sediment injections, volcanic intrusion).

Surface geochemistry and satellite surface slicks are used to differentiate shallow fluid expulsion associated with shallow processes (dewatering and biogenic hydrocarbon) from fluids derived via deeply rooted plumbing systems. This constrains the fluid plumbing system as defined by the 3D occurrence of stratigraphic carriers and seal bypass system through time. The lessons learned in the Congo and Kwanza basins help to address long-standing issues regarding the migration of fluids through the hydrate stability zone, manifestations of fluid flow with and without polygonally faulted substrates, the petroleum significance of pockmarks, and other fluid expulsion phenomena. These lessons can be transported both to frontier areas of the West African margin and many other basins across the globe, particularly those associated with gravity and salt tectonics.

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References Anka, Z., Gay, A., Berndt, C. (eds) 2012. Hydrocarbon leakage through focused fluid flow systems in continental margins. Marine Geology, 332-334, 1-234. Huuse, M., Jackson, C.A., Van Rensbergen, P., Davies, R.J., Flemings, P.B. & Dixon, R.J. 2010. Subsurface sediment remobilization and fluid flow in sedimentary basins: An overview. Basin Research, 22(4), 342-360. Serié, C. 2013.Geophysical and geochemical characterization of fluid flow phenomena in the southern Kwanza Basin, offshore Angola: implications for petroleum systems analysis and hydrocarbon prospectivity in deep-water settings. PhD thesis. University of Manchester, UK.

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Regional Prospectivity of offshore Namibia and the Angolan Namibe Basin

Craig Koch and Pat Coole, PGS, Weybridge, UK

Introduction The offshore deepwater basins of Namibia and Angola hold tremendous hydrocarbon potential. These last offshore frontier areas of West Africa have seen a huge demand for high quality, detailed and innovative seismic data which can be set in a regional context, in order to assist in the exploration, understanding and de-risking of these potentially prolific hydrocarbon provinces.

In an effort to better understand the potential petroleum systems of offshore Namibia and the Angolan Namibe Basin, PGS has recently acquired three 2D surveys using the GeoStreamer® dual-sensor broadband towed streamer system, in association with Sonangol and Namcor (Figure 1). These surveys are: (1) In 2011, 12,700 km regional 2D of the Angolan Namibe, Benguela and Kwanza basins; (2) In 2012, 10,000 km regional 2D focused in deep-water Namibia, and (3) in 2013, 5,000 line kilometers Namibian blocks 2112B, 2113 A&B and 2413B.

These data give more accurate seismic imaging of structures, thus improving the regional understanding of tectonic evolution, structure and geology, providing new insights regarding the prospectivity of these basins, which will be summarised in this paper.

Figure 1 – Location of the Namibe and Namibian basins showing PGS 2D data coverage

Regional & Petroleum Geology

Namibia and the Namibe Basin have similar geological histories, controlled largely by the opening of the South Atlantic in the Early Cretaceous. The volcanic Walvis Ridge separates the two regions and controlled sedimentation to the north during rifting.

The syn-rift stage of both areas is typified by a series of asymmetrical horst and graben basins, in which thick sequences of fluvial-lacustrine sediments were deposited in narrow deep lakes. In analogous formations in the conjugate margins of South America, burial of algal blooms and plant detritus, along with anoxic bottom waters lead to the formation of high quality source rock.

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Reservoir rocks range from conglomerates and sandstones shed locally from uplifted horst blocks to lacustrine and fluviatile sandstones.

As active rifting ceased in the Early Cretaceous, the early post-rift, or sag phase was characterised by the deposition of continental, fluvial and transgressive lagoonal rocks. The Walvis Ridge controlled sedimentation to the north during this period; repeated cycles of marine incursions across the ridge into a restricted basin led to a thick evaporite sequence. Although this salt is widespread across West Africa, it thins into the Namibe Basin and is absent from Namibia, where open marine conditions prevailed earlier than to the north. 2-5 km of post-rift sediments overlay the syn-rift sections along this margin (Figure 2), while volcanic centres are common in the Namibe Basin and are associated with the early post-rift stage.

Figure 2 - GeoStreamer® dip line, Namibia (fast track time migration, 2013)

Recent Activity The Namibe Basin has only one exploration well, Sintezneftegaz’s post-salt Kunene-1 in Namibia block 1711 discovered gas in 200 . Just to the north of the Namibe Basin, Cobalt’s recent discoveries in Angola Blocks 20 and 21 have proven the great potential of pre-salt sediments fuelling the search for prospects at this level in other nearby basins. In Namibia, a flurry of exploration in the mid-1990s led to several dry wells being drilled and the gas discovery of Kudu Field. This has been followed in the last few years by a new phase of activity, which includes wells by HRT and Chariot which proved the existence of mature middle Cretaceous source rocks. Several further wells are planned for 2014.

Conclusions Depth-migrated GeoStreamer® seismic has improved the imaging of syn-rift and post-rift structures, enabling more confident identification and mapping of prospects. The improved imaging and resolution provided by this type of seismic acquisition significantly de-risks exploration in frontier areas, something that is of significant importance where well costs are extremely high.

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Wednesday 2 April Session Six: Walvis Ridge to South West African Margin

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Keynote Speaker: Contrasting Extensional Styles North and South of the Walvis-Rio Grande Ridge, South Atlantic

Ian Davison, Earthmoves Ltd., Camberley, Surrey GU15 2EF, UK

The South Atlantic was affected by a major volcanism ca. 139-130 Ma which is interpreted to have been caused by the Parana-Etendeka plume. The plume was centred close to the Walvis Ridge intersection with the African coastline and appears to have been channelled southward along the Atlantic margin, where thick 7> km seaward dipping reflector (SDR) sequences dominate the African and South American margins. In contrast, North of the Walvis Ridge there are no seaward dipping reflectors, although basalts at base rift level extend 1000 km northward to the Kwanza Basin.

Deep seismic imaging along the south Brazilian-Argentine margin indicates that the crystalline crust thins to approximately 17 km (β=2), before seaward dipping reflectors are developed. The SDRs zone is around 100 km in width (measured E-W) and the SDRs are so thick (>7km vertical thickness) that the crust below them is interpreted as effectively new oceanic crust as it must be very injected by sills and dykes. Therefore, we interpret the ocean-continent boundary as the landward edge where the SDRs reach 6 km vertical thickness. Near the plume head, SDRs can reach up to 18 km vertical thickness in Pelotas, where a super-volcano complex was erupted. Along the South American margin upper crustal extension (ca. β =1.1 measured from fault heave) is much less than total crustal extension (β =2, measured from crustal thickness on seismic sections where moho is clearly imaged). South of Walvis crustal extension began in the Permian and continued into the Jurassic in rifts which are poorly defined in the African margin, but are clearly oriented ESE to WSW in Argentina and Uruguay. The Early Cretaceous Atlantic margin rifts cross-cut the Karoo rifts and are parallel to the N-S trending margin, with only two or three 10-15 km wide, 1-3 km deep, isolated half-graben produced along the South Atlantic rift zone immediately landward of the SDRs (Fig. 1b). Similar small isolated graben are present on the African margin (e.g. the J-1 graben in the Orange Basin). The accommodation space created by crustal extension is mainly filled by underplated intrusions and extruded lavas – the SDRs; rather than by clastic sediment-filled rifts. The SDRs have been drilled in Pelotas and Namibia and are composed of red sub-aerial basalts in the first 400 m, but there is no data on the deeper section, so it is still not clear whether they are all volcanic material. The top of the SDRs is smooth but the base is very irregular with a relief of 5-10 km. The maximum dip of the reflectors reaches 40° where they are steepest at the seaward tips. Some authors have suggested that curved nature of the SDRs is due to listric faults at their seaward terminations, but there is no evidence for fault surfaces on the seismic sections. We interpret the curved seaward dipping shape to be due to collapse of the basalt lid above large magma chambers Hence, the potential for syn-rift source rocks is very limited to a few isolated graben.

Crustal extension to the north of the Walvis-Rio Grande Ridge produced two distinct stratal sequences: rift and sag. Wide margins are characterised by syn-rift half graben reaching a maximum vertical thickness of around 4 km, which are laterally continuous across the margin. The overlying extensional Early Aptian sag phase reaches up to 6 km thick in Africa (Fig. 1a). This sag has only a maximum thickness of 2 km in Brazil. The contrast in sag thickness suggests that lower crustal extension was favoured on the African margin, due to the low-angle west-dipping shear zones in the West Congolian Fold Belt. An extensional sag phase has not been identified South of the Walvis Ridge. In the Kwanza and Congo basins, seismic refraction and reflection data indicate the crystalline crust is thinned by a β factor of 6 over a 100-150 km wide zone. This extreme crustal thinning, produced a wide area of continual half graben favourable for widespread syn-rift source rock development; whereas the areally limited small Atlantic rifts south of Walvis are not conducive to syn-rift source development.

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Exploring For Hydrocarbons in a Deepwater Boutique Basin: Orange Basin, South Africa

Piet Lambregts, Pieter Huver and Sanne Dekker, Shell Upstream International Exploration.

The southwest margin of South Africa is a divergent plate margin with rift basins underlying post-rift passive margin clastic sedimentary sequences (see Fig.1). Rifting started in the Late Jurassic during the initial opening of the proto-Atlantic. The rift basins are filled with Neocomian terrestrial and lacustrine deposits, inter-bedded with volcanic rocks. Large rift shoulders that have been resolved on gravity and magnetic data may have influenced later siliciclastic sediment deposition. Late re-activation of the rift basins is inferred from minor folding and fault offsets of the early drift/post-rift sequences. Movement appears to have ceased by latest Aptian times, during which time the regional Apto-Albian source rock blanketed most of the Orange Basin. Thermal modeling suggests that these source rocks should be oil mature at the western margin of the basin.

Cretaceous basin-floor and toe-of-slope fans have been deposited immediately above the regional Albian-Aptian source rock, and may be analogous to recent discoveries along the West African Transform Margin. Slope channel complexes, feeding these fans, have also been recognised on seismic.

The post-rift reactivation accentuates one of the most prominent features in the area, a broad NW-SE trending basement high known as the Marginal Ridge. Historically this has delineated the westernmost extent of syn-rift sediments in the Orange Basin, with the outboard area interpreted as oceanic crust. Structural variations along the crest of the Marginal Ridge localize potential leads, forming 4-way closures on draping lower Cretaceous turbidite fans, or large 3- way stratigraphic traps.

Shell was granted an Exploration Right on a large (37,000 km2) and very immature block in February 2012, covering the outboard margin of the Orange Basin. The block contained only 15 2D lines, and Shell embarked on an aggressive seismic data acquisition program. End 2013 the block was covered by an additional 8,000 km2 of 3D and 10,000 km of regional 2D data. The prospectivity in the block is clearly separated into two distinct areas: i) the NE corner, that is on trend with the Marginal Ridge, and is now covered by 3D seismic and ii) outboard acreage interpreted to be on oceanic crust, covered by the new regional 2D data set.

Play types identified in the block include structural closures on the Marginal Ridge, Cretaceous stratigraphic traps associated with basin floor or slope fans, and amalgamated slope-channel reservoirs and incised valley fill deposits, that are supported by AVO. The main prospect is Aardwolf (Fig. 2), which is the largest closure in the outboard Orange Basin. At present evaluation on the new 2D and 3D seismic data is ongoing.

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K-A2

Aardwolf

BFF Rift Clastics & volcanics

Fig. 1: Schematic cross-section through the Orange Basin. Modified from PASA. Figure 2: Schematic cross-section of the Orange Basin (modified after PASA)

3

Fig. 2: Seismic depth section through the Aardwolf prospect

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De-Risking Source Rocks and Plays, Deep-Water Orange River Basin

Anongporn Intawong and Neil Hodgson, Spectrum Multi-Client UK, Dukes Court, Duke Street, Woking, Surrey, GU21 5BH, United Kingdom

During the last four decades, hydrocarbon exploration in the offshore Orange River Basin has yielded the discovery of two large natural gas reserves: the 1.3 TCF Kudu gas field off Namibia and the 540 BCF Ibhubesi gas field off South Africa. These two fields are strikingly different accumulations.

The Kudu field is located in the transition between the syn-rift graben systems of the shelf and the Seaward Dipping Reflectors (SDRs) of the Outer High. Both the complex reservoir diagenesis and the charge mechanism of Kudu are unpredictable and resistant to seismic derisking; making the Kudu play challenging to chase. On the other hand, the Albian channel and fan sands comprising the Ibhubesi gas field have good porosities (16-25%) and display bright amplitudes that are readily recognised on seismic data. The field is charged from Aptian organic mudstone of the slope and shelf margin, where it lies below a thick clastic wedge. Out- board of the shelf edge this Aptian source is buried beneath a reduced overburden, promising an oil charge for Late Cretaceous clastic reservoirs in deep-water plays.

Indeed, the acquisition of an extensive seismic dataset in 2012 and 2013 offshore Namibia and South Africa has facilitated the evaluation of source maturity distribution for both the Early Aptian and Cenomanian-Turonian source rocks along this margin. Seismic data is conflated with evidence from the four wells targeting non-Kudu plays on this margin drilled in 2012-2013, and we show that a significant de-risking of the great diversity of exploration plays on this margin has occurred.

New stratigraphic and structural plays in the Orange River Basin are proposed, such as those associated with the prism’s shale-detached gravity slide. Here, maturation of the Cenomanian- Turonian source rock precipitated basal decollement generating a panoply of extensional and compressional structures containing clastics, underlain themselves by the Aptian source rock. The first steps commencing exploration of deep-water Orange River Basin has already significantly de-risked plays, both here and elsewhere on the Namibian to South African margin, demonstrating the presence of a highly attractive exploration province.

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Variations in the Structural and Volcanic Nature of the South West African Margin

Paton, D.A1., Mohammed, M1,2., Dalton, T. 1, Mortimer, E. 1, Collier, R.E.L.I. 1, Hodgson, N. 3

1 Basin Structure Group, School of Earth and Environment, University of Leeds, UK. 2 Department of Petroleum Reservoir Engineering, Mosul, Iraq 3 Spectrum, Dukes Court, Woking, UK.

There is increasing focus on understanding the mechanisms by which continental lithosphere extends during the final stages of continental break up into the oceanic lithosphere. The South West African Margin of Namibia and South Africa presents an exceptional area to study both the structural evolution of the break up process and the intimate association with rift related volcanic processes.

We present a regional structural framework that extends over 1000 km from the southern portion of Southern South Africa into the Namibian margin, for the first time encompassing newly acquired data covering the deep-water portions of the Orange Basin. Seismic interpretation of basin-wide data is coupled to gravity and magnetic data and well data to provide an integrated understanding of the margin configuration. This enables us to map out, in detail, the rift architecture in its entirety and also to consider the distribution of volcanics along the margin. Through this integrated approach we can address some of the fundamental questions associated with the break-up evolution of this margin, including: fault geometry and evolution of spatial and temporal rift basins; the interplay of volcanics, seaward dipping reflections and oceanic crust; the role of transforms on margin segmentation and break up; and the nature of the oceanic-continental transition zone.

In addition to providing a revised model for the break evolution of the margin, we also the implications for our understanding of margin evolution more broadly.

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Along Margin Variability of Gravity Collapse Structures in the Orange Basin

Dalton, T. 1, Paton, D.A1., Mohammed, M1,2., Collier, R.E.L.I. 1, Hodgson, N. 3

1 Basin Structure Group, School of Earth and Environment, University of Leeds, UK. 2 Department of Petroleum Reservoir Engineering, Mosul, Iraq 3 Spectrum, Dukes Court, Woking, UK.

The gravity collapse structures of the Namibian and South African Orange Basin on the South West African margin are some of the best imaged examples globally of this important passive margin process. The overall geometry of these features is understood and commonly invokes a tripartite configuration that includes up-dip extensional domain, a transitional domain and a down-dip compressional domain with a common detachment underlying the system.

This study present a detailed structural analysis of both the spatial and temporal evolution of the collapse structures along this margin. Firstly, we demonstrate the geometry and kinematic evolution of the systems. In particular we focus on the variability of the structures by describing features such as: portions of the system that have multiple detachments; the variation in mis- balance between extension and compression; the role of oblique structures; the temporal evolution of faults within the system. Secondly, we consider the along margin variation. Through detailed mapping, correlated to biostratigraphic data, we demonstrate that the 3 gravity collapse structures that are most evident are intimately related to the erosional unconformities observed in the inboard portion of the margin although are of different ages. By combing the structural analysis with age constraints we present a model that explains the spatial and temporal evolution of the system; this enables us to discuss the likely causes of the collapse structures. Not only does this provide insights into the evolution of this particular margin, it is likely that these processes are present on other parts of the South Atlantic margin, although the signature elsewhere may be masked by the presence of salt.

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Poster Presentation Abstracts

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Inversion of the Internal Architecture of SDR Complexes to Derive Magma Supply Rate, Thickness of the SDR Pile, And an Estimate of Relative Palaeobathymetry

Frank J Peel, National Oceanography Centre, University of Southampton Waterfront Campus, European Way, Southampton SO14 3ZH, United Kingdom

1 SDR complexes in the South Atlantic The southern segment of the West African margin in Namibia and South Africa is a volcanic- rich rift and it is dominated by SDR (seaward-dipping reflector) complexes. This presentation offers a forward-modelled simulation of the geometries seen on seismic data from the orange Basin of South Africa.

2 The internal fabric of SDR complexes The internal architecture of SDR complexes is clearly discernable on modern 2D seismic reflection profiles. This presentation considers SDR complexes which have a consistent oceanward vergence and which represent a continuous unidirectional growth sequence. In some examples, the internal fabric consists of a simple uniform wedging/fanning pattern, but more commonly there is a distinctive architecture consisting of stacked packages with different shape (different in length, thickness, taper angle, and rate of taper change). These stack to form consistent and coherent patterns. The individual packages are interpreted to be the product of discrete episodes of volcanic outpouring.

3 Establishing a shape function to describe the individual packages The first step in the analysis was to create a mathematical model for the shapes of the individual packages within the SDR complex. These are observed to vary in shape within a consistent spectrum such that the lower-volume packages have both a smaller initial thickness t0 and a more rapid exponential decay with distance. A function relating t0 to the decay was created by visual match to the observed shapes. By this means a single number value of t0 can represent the shape and volume of an individual package.

Variation in shape of the individual packages within an SDR complex

4 Creating a synthetic SDR stratigraphy Assuming a constant rate of plate separation during SDR creation, and a constant time interval per individual SDR package, we can create a synthetic SDR complex by stacking a suite of modelled packages with constant offset. The shape factor for each package is adjusted to obtain a match of the synthetic stratal geometry to an observed example. An initial proof of concept trial was made using sections from the Orange Basin of South Africa; however the model is not basin-specific and in principle should be applicable globally.

This complete model now provides an estimate of the extruded volume of igneous material per unit of time.

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Synthetic SDR architecture. The model assumes 1D isostatic equilibrium, with uniform density of the SDR complex and of the material beneath it. Model development is in early stages; flexural rigidity and no thermal subsidence are not yet considered.

If the geological model is valid, and the geometric model is approximately correct, the matched synthetic stratigraphy provides a model not just of the seismically imaged upper portion of the section, but also of the complete system down to the bottom of the erupted layer. The predicted total thickness of this layer varies significantly in thickness in the oceanward direction. The total thickness at one point represents the aggregate of many different flow packages. We may consider taking this analysis one step further. Because the SDR complex is mostly composed of volcanic flows, it is likely to be of uniform composition, and because these flows do not undergo significant depth-dependent compaction, the whole complex is likely to be of relatively uniform density. Assuming one-dimensional isostatic equilibrium (i.e. ignoring the flexural strength), and further assuming that the material beneath the SDR complex does not vary laterally in density, we can predict the relative topography of the top of the pile. Comparison of predicted vs. observed topography provides an independent check on the validity of the model.

This project is in early stages but the results to date indicate:

1. The method does appear to give a reasonable simulation of the gross stratal patterns seen in real-world SDR complexes 2. Where the predicted surface topography of the top-SDR surface can be compared with a seismically observed top-surface topography, the two appear to be in proportional agreement 3. This gives us some confidence that the approach may be valid, and that it may be refined to provide an independent estimate of the initial bathymetry on top of SDR complexes.

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