Abstract The clastic fill of the rifted grabens in the central South Atlantic includes several fields containing over 1 billion barrels of oil in place. The largest fields are mainly hosted by continental fluvial and aeolian sandstones deposited near the base of the rift, before rift topography was fully developed. Footwall erosion progressively eroded back the main fault scarps, and normal faults propagated through the footwall to create terraces along the rift borders. This increased the potential drainage area on the footwall, so eventually, large alluvial fans developed in the hanging wall along the main rift border faults. The basement clast-supported conglomerates scatter seismic energy; and on seismic data, the top of the fan can appear to be the intact crystalline basement. Even when drilled, the top of the fan can still be mistaken for true basement due to the large size of the clasts. Some important oil fields are hidden below these marginal alluvial fans, within prerift and early rift fluvial and eolian sandstones and in lacustrine turbidite sandstone reservoirs. It is suggested that more fields may be found in West Africa using the model of the sub-fan terrace play. The large amount of footwall denudation of dense basement rocks can lead to unloading of the adjacent basin, as well as the footwall, when the crust has a finite flexural strength. The resulting uplift and erosion produce an ‘End of Rift’ unconformity, and it is suggested this process is likely to have caused the so called ‘Breakup’ unconformity on continental margins, rather than this being due to initiation of ocean spreading.

Abstract This study focuses on a regional comparison of interpretations from selected 2D seismic transects between large salt and salt-free basins offshore southern Brazil (Espirito Santo basin, Campos basin, Santos basin, and Pelotas basin) and southwest Africa (Kwanza basin, Benguela basin, Namibe basin, and Walvis basin). Based on tectonostratigraphic analysis of megasequences and first-pass geometric reconstructions of synrift settings, including sedimentary decompaction and isostatic correction, it provides a comprehensive basin-to-basin documentation of the key geological parameters controlling asymmetries in basin evolution. The diversity in the tectonic and stratigraphic architecture of the conjugate margin basins reflects variations in the interplay of a number of controlling factors, of which the most important are: (A) the structural configuration of each margin segment at the time of break up; (B) the postbreakup subsidence/uplift history of the respective margin segment; (C) variations in the type, quantity, and distribution of margin sediment (including salt); (D) the evolution of the large salt basins during sag to postsag stages; and (E) sea-level changes.

Abstract There are many publications describing a thermal gravity anomaly associated with young oceanic crust at mid-ocean ridges. This anomaly is due to lateral density changes in the lithosphere resulting from temperature variations within the asthenosphere. The amplitude of this thermal Bouguer gravity anomaly can be as large as-300 milliGals at the location where new oceanic crust is formed and is easily observed in the gravity data. A detailed gravity model extending from the West African Craton across the Mid-Atlantic Ridge clearly shows this thermal gravity anomaly and its lateral extent. The model also clearly shows that there is no evidence of a thermal gravity anomaly at the rifted continental margin of the Kwanza basin, offshore Angola.

Abstract The South Atlantic presalt petroleum system has unique elements which are related to the basin bounding structural fabric, accommodation space and climatic conditions. The development of both high total organic carbon lacustrine source rocks and hypersaline/hyperal-kaline microbial carbonates requires sequestration of these basins from marine conditions. Sequestration is accomplished by an outer-high which was isostatically elevated by magmatic under-plating. This magmatic under-plating is occurs along the margin from the Santos Basin to the Espírito Santo Basin and the conjugate Kwanza Basin. Where the outer high is absent, such as in the Brazilian Pelotas Basin and Namibian basins, the presalt petroleum system fails to develop. In Gabon where under-plating and basin sequestration occurs, a Brazilian style presalt system fails to develop due to high clastic influx. Gabon lacks the microbial hypersaline carbonate reservoir. Similar Brazilian style presalt petroleum systems are likely however, to occur on other passive margins where similar structural styles create a sequestered basin. These basins should occur in regions which are transitional from classic volcanic margins to true nonvolcanic margins. Through better understanding of the Brazilian presalt geodynamic setting we can position ourselves to identify new basins with similar petroleum systems which have created the giant Brazilian presalt discoveries.

Abstract It is widely known that, in order to model tectonic processes accurately, 3D approaches are required. However, due to the greater numerical challenges and much enhanced costs, most commercially available software packages only offer two-dimensional or “pseudo three-dimensional” (2.5-D) applications to simplify the underlying mathematics. In the 2.5-D approach, the third dimension is generally created by a mere orthogonal projection of a single section in two directions at a certain distance from its original position. Yet, despite creating a 3D space, lateral variations in the subsurface are ignored and the resulting model often remains an oversimplification that often does not represent natural observations. A particular problem is given in sedimentary basins containing salt. The fluidlike behavior of salt over geological times requires true 3D models to allow for in- and out-of section salt flow and to preserve both the salt mass and its volume. None of this can be achieved in 2D or 2.5-D, respectively. Evaluation of evolutionary models derived from 2D restoration must therefore consider the associated geometric simplifications.

Abstract In West Africa, the presalt is an established play since the 1950s. Even so, only recently has the expectations for a potential extension of the Brazilian Santos/ Campos basins proven presalt carbonate play boosted spectacular interest in the Kwanza basin (south Angola). The “Sag carbonate Play” has gained most of the attention and promises to be the real “sweet spot” of future presalt exploration, at least in Angola. Moreover, new technologies and ideas allow us to reexamine the great complexity of the presalt play on the historically explored trend (onshore and in conventional waters) along the whole West African margin.

Abstract Offshore Angola is a world-class petroleum province with oil production in excess of 2 million barrels per day in 2008. Exploration activity in the offshore commenced in earnest in the early 1990s, with the contractual terms permitting only the production of oil. There is no provision for the production of gas. However, there have been several discoveries of associated and non-associated gas, by accident, in the search for oil. Gas will play a significant role in the future of Angola. A new gas business is emerging. Demand from a new liquefied natural gas (LNG) plant, the emerging Soyo industrial complex and the growing domestic and industrial sectors have created a business environment whereby near-term gas exploration, development and production is a critical need for the future of Angola. What is the gas resource potential of Angola: from mature basins to new frontiers? Is there potential for new giant gas fields? Conceivably, there are multiple petroleum system opportunities. This paper provides some insights into the petroleum geoscience exploration efforts being made by Angola's national gas company, Sonangol Gas Natural. The focus of this paper will be on the exploration for non-associated gas. The associated gas potential of Angola is relatively well known and will not be discussed. Sonangol Gas Natural has an extensive offshore seismic and well database. This is characterized by a series of merged, high-quality 3D seismic surveys that facilitate the application of the most advanced technologies. In excess of 130 offshore wells have encountered gas at multiple stratigraphic levels. However, the interior basins are a truly frontier province and data are limited to a regional gravity and magnetic dataset and surface rock outcrops. The conventional thermogenic petroleum systems of the offshore and the adjacent onshore Lower Congo, Kwanza/Benguela and Namibe basins are relatively well known. These comprise a Late Cretaceous and Cenozoic post-salt petroleum system, and an Early Cretaceous and Late Jurassic pre-salt petroleum system. The primary emphasis of the exploration effort in these basins is to better understand and to delineate the gas kitchens for the known source horizons, for example Malembo, Iabe (post-Aptian salt) and Bucomazi (pre-Aptian salt) formations. Biogenic gas plays constitute an unconventional petroleum system that requires different exploration concepts from those of conventional thermogenic petroleum systems. The principal challenges are to identify palaeo-gas hydrates, reservoired in Miocene clastics, to define the biogenic gas fairway and to evaluate the play elements of reservoir, trap and seal. The geological conditions necessary to establish a biogenic gas play in the deepwater and ultra-deepwater will be examined. The interior Owambo, Okawango and Kassanje Basins have no proven petroleum systems. However, some new play concepts of Neoproterozoic age will be presented using possible analogues worldwide. The future demand for gas will increase globally. New developments in LNG will change the world of gas. Angola will be a key player.