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Since the discovery of the giant Tupi-Lula pre-salt complex in the Santos Basin of Brazil, explorers have been integrating new seismic technology advances with the fundamentals of regional basin geology to extend the pre-salt play across the Atlantic margin into deep waters and below the salt off the west coast of Africa. In 2005, Petrobras drilled a wildcat well on the Parati prospect in the deep waters of the Santos Basin, and encountered condensate gas below a thick layer of salt. The following year, Petrobras and its partners, BG Group and Galp Energia, announced that the Tupi wildcat, drilled to 16,060 ft in almost 7,000 ft of water, flowed at 4,900 B/D of sweet 30°API crude oil, 0.7 sulphur content, and 6.6 MMcf/D gas on a ⅝-in choke. This confirmed that a new geologic play had been discovered below the salt. Over the next few years, exploration efforts continued in this new pre-salt play, resulting in additional discoveries in the Santos and to the north in the Campos and Espirito Santo basins.
Agencia Nacional do Petroleo (ANP) studies suggested that the charge and accumulation models for this new pre-salt cluster area of the Santos Basin contained reserves exceeding 30 billion bbl and possibly as large as 60 billion bbl of oil reserves. Though the thick layers of salt above the oil accumulations create challenges in seismic imaging and exploratory drilling, the salt has also served, through geologic time, as a superb seal that allows thick columns of oil to accumulate and be preserved.
Many exploration companies have already constructed regional geologic and plate tectonic models that recognize that these world-class pre-salt hydrocarbon accumulations off the east coast of Brazil may have counterparts on the conjugate margin of the Atlantic Basin in the deep waters offshore Congo, Gabon, Angola, and Namibia. A geologic model from Cobalt International shows a cross section of the Atlantic rift system that predicts similar geology between the two margins (Fig. 1).
Abstract In early 2002 Washington DC policy-makers suggested, that within a generation, Africa might supplant the Middle East as the United States most critically strategic energy supplier. This is a significant departure from the situation, which permeated the previous three decades when the Middle East was perceived as the singularly most important source of world energy. Such potential of Africa, if realized, would have a decided influence on future energy economics and geopolitics. Grandiose statements notwithstanding, is Africa (and in this context this implies the Sub-Saharan regions) at the brink of becoming an energy superpower? Does Africa have the potential reserves, production capability and capacity for such a role? This is not just an issue of geology but also one that touches on the rest of the development of the continent, its economic and political future. This paper presents an in-depth investigation of the true energy potential of Africa. One obvious focus is the potential of deep- and ultra-deep-water production, spanning almost the entire Western Coast of Africa. Areas of interest involve the deep waters off the Gulf of Guinea and the continental shelves and include the inland basins of Benin, Nigeria, Cameroon, Sao Tome and Principe, Equatorial Guinea, Gabon, Congo and Angola. We are proposing here a number of mechanisms of potential production and couplets of exploitation, i.e., optimum and likely ways to link producers with consumers, taking into account distances and hydrocarbon volumes and incorporating regional integration and co-operation. Finally, we are offering conclusions and recommendations that will enhance sustainable energy development in Africa, and continuous availability of uninterrupted global supply of oil and gas, which indeed will usher the era of Africa as an energy superpower. Introduction Indisputable estimates of oil and gas resources have always been difficult everywhere. One of the most frequent problems is the definition of hydrocarbon reserves, which has always generated classification problems and debates. The dynamic nature of classifying oil and gas resources is the reason for this confusion, a situation that causes considerable problems from economic to social and political when they are applied to entire countries and even continents. Oil and gas reserves as currently reported by conventional information sources such as trade journals appear to be almost always shortsighted and conservative to the extreme. As usual, the greatest cause of controversy in determining the quantities of oil and gas resources and reserves is the collision among hydrocarbons-in-place, potential reserves and proven reserves. If Africa, as we believe, is the next energy superpower, then an in-depth investigation is necessary for the understanding of its hydrocarbon potential. We will use in our analysis the term potential and this expresses both the probability and uncertainty that is inherent to this type of work. We have used a flowchart (Fig.A-1 in the Appendix), which illustrates this probability and uncertainty, and also shows the pathway and connectivity of resources and reserves classification. As should be expected, Hydrocarbon Resources, i.e., hydrocarbons-in-place are at the lowest level of the flowchart, while Proved Developed Producing (PDP) Reserves are at the top of the chart. As it is well understood in the petroleum industry, hydrocarbon resources and reserves have the ability to move from a lower potential level to a higher potential level as a result of: technological advancement, economies of scale and petroleum pricing. For example, some of the currently undiscovered hydrocarbon resources have the potential of becoming proven reserves in the near future if a series of activities happen or are likely to happen. Several factors influence the upward movement of petroleum resources, in the flow chart of Fig.A-1 in the Appendix:Geological (risk and complexity) Factor Political and Fiscal Environment Factor. Accessibility and Remoteness Factor Technological Factor Economic Factor - petroleum prices and adequate investments for exploration and production.
Abstract Salt tectonics is characterized by two types of mechanical interactions, between brittle and ductile deformation and between deformation and sedimentation, respectively. Consequently, a broad spectrum of structures and, rather frequently, significant 3D complexities can result. In such settings, interpretations made from too local observations can easily be misleading. The purpose of this work is to point out the interest of basin-scale mechanical understanding of salt tectonics processes to provide reliable interpretations of structure development, even at local scales. These principles are illustrated by the Angolan margin. The 2D dynamics of the salt tectonics system can be defined by the conditions of salt flow imposed by the upslope and downslope basin boundaries, leading to a two sub-system organisation, extensional upslope and contractional downslope, respectively. However, the existence of contractional structures in the upslope domain is an obvious departure from the 2D basin-scale flow model. These " anomalies?? develop along lateral boundaries where a strong component of strike-slip shear is responsible for large block rotations. The observed contractional structures are a direct product of these block rotations. These 3D structural complexities likely result from a rejuvenation of the basal slope along a part of the margin. This example illustrates how a robust salt flow model at basin scale, with welldefined initial and boundary conditions, can contribute to the understanding of a non-conform sub-system. The results are sustained by maps of raft restoration and kinematic analysis. Introduction Salt tectonics is characterized by two types of mechanical interactions, between brittle and ductile deformation and between deformation and sedimentation, respectively. Consequently, a broad spectrum of structures and, rather frequently, significant 3D complexities can result. In such settings, interpretations made from too local observations can easily be misleading. The purpose of this work is to point out the interest of basin-scale mechanical understanding of salt tectonics processes to provide reliable interpretations of structure development, even at local scales. At regional scale, salt tectonics in the Angolan margin, Lower Congo and Kwanza basins, is driven by the combined effects of two major parameters that are the margin tilt and the sedimentary loading. Once created, as a result of lithosphere cooling after the continental break-up, the basal slope remains an efficient cause of gliding in a seaward direction. Synkinematic structures like, tilted blocks, rollovers, turtles, grabens and diapirs (Duval et al.,1992, Fort et al., 2004a) attest of the extensional regime upslope, whereas, downslope shortening lead to the formation of growth synclines/anticlines, pop-up structures, compressional diapirs, and salt nappes (Brun & Fort, 2004, Gottschalk et al., 2004). In response to the cylindricity of the margin, early deformation gave birth to structures trending almost parallel to the coastline. The deposition at regional scale of massive loading, so called Congo fan, also insure a salt mobilisation in a seaward direction from Oligocene to present day. However, the non-cylindricity of the sedimentary pile induces a lateral variation of the deformation in a NNW-SSE direction. This lateral segmentation of the margin is accommodated by transfer zones of ENE-WSW direction and raft rotation around vertical axes (Fort et al., 2004b). In response to gravity driven deformation, the basal salt layer is thinning upslope and thickening downslope. Thinning occurs by a combination of pure and simple shear below rollovers and rafts, whereas thickening results from shortening and salt flow in a downslope direction.
Total has agreed to acquire interests in two blocks in the offshore Kwanza Basin from Angola's state-owned Sonangol and has received an extension on its offshore Block 17 production licenses. In the acquisition from Sonangol, the French major will add a 50% interest in Block 20/11, located in 300–1,700 m of water in the central Kwanza Basin. Partners Sonangol and BP hold 20% and 30% of the block, respectively. Total will also add an 80% interest in Block 21/09, located in 1,600–1,800 m of water in the south-central Kwanza Basin. Sonangol holds the remaining interest.
As a result of a more aggressive exploration strategy, Total has recently entered many large blocks in new countries around the globe, often in frontier areas devoid of adapted seismic grid. Short contractual turnarounds, challenging environments, new play types, complex geology, cost containment, have lead to new exploration strategies and technological and organizational adaptations on the way geophysical surveys are designed, planned, processed and interpreted.In this paper, a couple of recent technologies are exemplified for surveys acquired or planned by Total in different environmental and geological settings.
These achievements to properly address new exploration challenges rely greatly on the technologies developed by geophysical contractors (new acquisition techniques and equipment, processing capabilities). However they have been made possible thanks to Total’s R&D realizations in developing proprietary softwares in seismic velocity model building, depth-imaging, modeling, and interpretation. Moreover, Total is one of the few E&P majors to have developed High Performance Computing1 (HPC) capabilities to serve its ambition as a leader in advanced and fast depth imaging.