Tectonic reconstructions made across the southern South Atlantic Ocean indicate a diversity of rift and drift basin characteristics on the conjugate margins that define them as different stratigraphic and structural entities. In terms of petroleum systems, the basins are not as unlike as some characteristics suggest. Given the lack of significant hydrocarbon discoveries to date south of the Walvis Ridge, doubts have been cast on the presence in this area of the prolific Lower Cretaceous lacustrine and marine source rock systems, which are well known in the Greater Campos Basin and offshore Angola. Oils and condensates from the basins south and north of the Walvis Ridge exhibit geochemical similarities suggesting that comparable source rock systems are present in both areas. The condensate geochemical analysis results from the Kudu Field in Namibia are compared with oils from marine and lacustrine sources in Brazil, indicating that the Kudu condensates are derived from at least two different source rocks. These results suggest that the underexplored basins offshore Namibia contain thermally mature Lower Cretaceous lacustrine and marine source rocks, offering a new frontier for petroleum exploration in Africa's southern South Atlantic.
References in the last pageThis study comprises a realistic view of the Petroleum Systems modeling in the Pre-Salt area of Santos Basin in the ultra-deep water region, comprising the recent giant oil and gas discoveries, which includes the Tupi (now named Lula and Cernambi Oil Fields), Iara, Jupiter and Guará. (Fig. 1). This area encompasses other several successfully tested prospects such as Bem-te-Vi, Carioca and Parati. Volumes are surprisingly large; may reach 18 Bbbls of reserves. The area encompasses also the recently certified reserves in ANP areas that can reach up to 15.5 BBOE (2C results from Gaffney, Cline & Associates). Such discoveries emphasize that in most areas of the ultra deep waters of the Brazilian Greater Campos Basin, localized in the Southern Margin of Brazil, exploration has just begun. Petroleum System in the Ultra-Deep area of Santos Basin is characterized as a unique due to the existence of a widespread and thick (up to 2,000m) salt sequence forming excellent seal, excellent source rocks, reservoirs carrier beds (for migration), traps, temperature conditions and timing. The salt sequence is one of the most important players acting not only as a perfect seal but also in the preservation of the liquid phase of the hydrocarbons and the permoporosity of the pre-salt carbonate reservoirs. The understanding of the salt movement through the time and the role of sealing and heat transfer properties through 2000 m of salt layer is a key point in the modeling processes.
The sedimentary basins of the South Atlantic have developed into one of the most active regions for petroleum exploration in the whole world. The increase of interest in the oil industry has resulted from the numerous recent giant to supergiant oil and gas discoveries along both the eastern and western continental margins of the South Atlantic in deep and ultradeep waters. The use of the petroleum system concept in the South Atlantic marginal basins provides an effective means of classifying and characterizing the diversity of the oil and gas systems, as well as, a means to aid in the selection of appropriate exploration analogs. The South Atlantic marginal basins also provide some of the best examples of how petroleum systems evolved through time with respect to both their levels of certainty and their areal and stratigraphic limits. An examination of the Orange and Santos basins, in Namibia and Brazil, respectively, provides examples of almost perfect analogs in terms of petroleum system. For example, lacustrine and marine source rocks, similar oil type, almost identical reservoir deposition environments, traps associated with basement highs and vertical migration pathways dominate in each of the basins, with normal faults networks providing the effective carrier. However, there are clear differences when Aptian salt layers are present in the Santos basin and absent in the Namibian basins. Also, differences are observed when thermal evolution is considered. Although no Aptian salt section is present in Namibian basins, and thermal maturity appears to be much higher in the Namibian coast, both basins share almost identical elements and processes of the petroleum system concept. In summary, the aim of this paper is to show how the petroleum system modeling, supported by geochemistry, allows a correlation between counterpart basins across the South Atlantic realm. DISCUSSIONThe evolution of the South Atlantic sedimentary basins provided the general conditions for the establishment of various petroleum systems. The formation of source rocks, reservoirs and traps are directly related and connected to the phases of the evolution of the passive continental margins ( Figure 1): pre-rift, syn-rift, transitional and thermal sag (drift) sequences (Mello, 1988, Mello et al, 1991.
Petroleum exploration along the West African and South American Equatorial Margin has led to important oil discoveries along both margins. Similar geochemical characteristics of these finds suggest analogous petroleum systems with enormous potential in the conjugate margin sedimentary basins. The Jubilee giant oil discovery offshore Ghana has an estimated recoverable reserve of about 600 million barrels. In the area that was once connected to the equatorial West African margin, but is now separated by the Atlantic Ocean, two discoveries have recently been announced. Tullow Oil announced the Zaedyus discovery offshore French Guinea, with 72m net oil pay in turbidite sandstones. Petrobras and BP announced the Pecem discovery in the northern Brazilian margin, with 140m of net pay in 2,129m water depth in the Ceará Basin. These discoveries appear to have a very similar geologic evolution, source rock facies, and oil types suggesting similar petroleum systems. Additionally, the integration of high resolution geochemical data from oils recovered from boreholes offshore the other basins along the South Atlantic Equatorial Margin has revealed four separate source rock systems: 1- an Aptian/Barremian calcareous black shale associated with a lacustrine brackish to saline anoxic environment; 2- a Late Aptian calcareous shale deposited in transitional environments, as indicated by oils found in the Ceará and Potiguar basins; 3- an Albian/Cenomanian/Turonian marine shale corresponding to an anoxic event widespread in the West African salt basins, particularly in the deep water settings of the Ghana and Angola continental margins. Similar oils have also been registered in the Foz do Amazonas Pará-Maranhão basins and in five ultra-deep water accumulations discovered recently (2011–2012) in the Sergipe Basin; 4- Paleocene-Eocene shales deposited in deltaic environments in the Niger Delta, the Amazon Cone, and Pará-Maranhão Basin. This work aims to restore these basins to their previous pre-breakup locations and to support new exploration efforts. Despite similarities shown above, simply matching discoveries in the conjugate margin basins, for example the Tano Basin offshore Ghana, with the Ceará Basin in northern Brazil, does not necessarily yield the entire story that may lead to a successful end. There is a great deal of contrasting sedimentary and structural development peculiarities from basin to basin and margin to margin. The application of a high-resolution petroleum system approach can lead to better exploration models for these basins and provide clues on the best strategy for drilling the new prospects that have been identified in the ultradeepwater regions of the South Atlantic Equatorial Margin.
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