Tuesday 7th June
Session 1: Tectono-sedimentary Evolution and Structural History
All the offshore basins of Namibia have similar basement morphologies. However, sediment input from the South African Plateau has varied significantly into each basin through time such that the sequence isopach and morphology varies greatly both within and between basins. At the present time only three rivers are permanently connected to the South African Plateau: the Orange River in the south, and the Ugab and Kunene Rivers in the north. These rivers transported large amounts of sediment into the Atlantic.
The tectonics and structural history of the internal basins and the Atlantic margin play a fundamental role in controlling the deposition, burial and/or erosion and quality of the various elements of the petroleum system, as well as being the critical aspect of forming the hydrocarbon traps.
This session discusses the tectono-sedimentary history of the various Namibian basins through time, with emphasis on how this controls the supply of sediments, the distribution of source, reservoir and seal rocks, as well as the type of potential petroleum traps and their integrity through time.
Session 2: Petroleum Systems of Namibia
The petroleum system is a unifying concept that encompasses all the disparate elements and processes of petroleum geology. A petroleum system encompasses a pod of active source rock and all its genetically related oil and gas accumulations. It also includes all the geological elements (source, reservoir, seal and overburden rocks) and processes (trap formation, plus generation, expulsion, migration and accumulation of hydrocarbons) that are essential if an oil or gas accumulation is to exist. If all these elements are in place and the processes are understood to have occurred during the desired time and in the right space, with also a reasonable probability of an accumulation, then a petroleum system exists. There does not need to be a discovery.
Exploration wells drilled offshore Namibia demonstrate that all elements for a working petroleum system and hydrocarbon accumulations are present. Onshore, there are two vast Neoproterozoic/Early Cambrian Basins, the Owambo Basin in the country’s northern part, and the Nama Basin in the south. Both basins cover an area of over 460,000 km². Complex foreland basin architectures in both basins are as a result of the prominent Damara and Gariep Belts. Most of the drilled onshore exploration and stratigraphic wells were relatively shallow, and hardly tested the country’s full onshore potential. Superimposed on the Precambrian basins are a group of late Paleozoic to early Mesozoic, Karoo-aged basins dominantly of extensional character whose potential is only recently begun to be realized. An active petroleum system has recently been verified in this setting in northeast Namibia.
This session will discuss Namibia’s petroleum systems with a focus on how all the various components come together in both space and time to define both petroleum systems which are proven and those which may be possible.
Wednesday 8th June
Session 3: Source Rocks of Namibia
Source rocks are the most critical element of any petroleum system, and a rich source rock is needed to underpin any new hydrocarbon province. In Namibia to date, deep water marine source rocks have been sampled offshore in the Santonian-Cenomanian, but the only regionally proven source is the marine upper Barremian-Lower Aptian ‘Kudu Shale’. Potential source rocks may also occur deeper in early Cretaceous syn-rift basins.
Onshore, predicted deep depocentres and several source and reservoir lithologies observed in core and outcrops have attracted explorers, from small independents to majors. Continental sediments prevail in the Namibian Karoo basins with marine influence only having been demonstrated in the uppermost Carboniferous. The Permian strata contains not only coal seams, but also extensive organic shales. With Mesosaurus as an index fossil the Namibian black shales correlate well with similar shales across Gondwana, known as the Whitehill Formation in South Africa and as the Irati Shales in South America.
Techniques for mapping out the distribution of source rocks, both traditional and more novel ones such as mapping on seismic data using inversion/AVO products, are important for defining the limits of a petroleum system. The behaviour of source rocks during maturation is driven by their compositional characteristics, so this will also be a subject of focus.
This session will discuss the proven and potential source rocks of Namibia, their characteristics, burial history, hydrocarbon products and their proven / possible migration routes.
Session 4: Reservoirs of Namibia
There is a rich suite of reservoir rocks in Namibia that range in age from the Proterozoic through to the Tertiary, varying from sandstones to carbonates and which were deposited from desert to deep water environments. Below are some specific challenges that this session will attempt to address.
Potential reservoir rock horizons include the Proterozoic Nosib, Otavi and Mulden Groups. The Nosib Group includes interbedded marine and continental clastics with minor carbonates. The Otavi Group is believed to be a self-sourcing carbonate system, and is primarily dominated by shallow marine carbonates, with lesser amounts of interbedded sandstones and shales. Potential in the Karoo section remains to be evaluated.
In the pre-break up section of the Atlantic Margin predicting the presence of sandstone and carbonates reservoirs in a section dominated by volcanics.
The distribution of the Lower Aptian to Lower Albian carbonates and where good reservoir quality is likely to be found.
The facies and distribution of deep-water sandstone reservoirs, often beautifully imaged by 3D seismic data, but can reservoir quality and hydrocarbon fill be predicted? The effects of bottom currents and contourite deposits on the reservoirs.
This session will discuss and focus in on some of the critical aspects of these reservoirs and their depositional systems to help predict where they are deposited and how good the reservoir quality will be.
Thursday 9th June
Session 5: Seals and Traps of Namibia
Seals are key elements of any petroleum system. Their importance is usually overlooked during the evaluation of the potential hydrocarbon accumulation. The effectiveness of seals depends on several factors. The most important is the thickness, continuity, and high capillary entry pressure. The typical lithology of seals in Namibia includes shale, silt, salt, and anhydrite formations. In terms of their architecture, they can be created by vertical lithological stratifications and lateral lithological variation or porosity degradation. Additionally, faults and fractures can act as seals by impeding fluid flow. In the Arabian Peninsula, potential seals include deformation bands, and hydrodynamically-aided stratigraphic and fault rocks.
Assessment of seals using a rigorous strategy is vital in the appraisal phase. However, production and injection-related activities might alter seals hydrocarbon retention characteristics, and therefore, must be incorporated in all stages of the field development plans.
Over 50 years of exploration offshore Namibia and more onshore, has yielded one gas discovery at Kudu, recovery of an encouraging light, sweet oil sample using a wireline tool at Wingat-1 and encouraging hydrocarbon shows in the recent drilling campaign onshore. Despite this, large and small companies continue to believe that Namibia holds all the ingredients to become a successful oil and gas production province, as the previous sessions have demonstrated. Examples of different trapping styles will be presented, with an emphasis on learning lessons from failures in the past and predicting the potential successes of the future.
This session discusses challenges confronted in the evaluation of seal capacity and best practices for the assessment of seal quality in Namibia with emphasis on case studies from different reservoir rock types.
It will also re-visit previous exploration campaigns and examine the reasons for no commercial production being established to date and then will predict which current and future campaigns will lead to commercial success and a bright future for Namibia.
Session 6: Prospectivity of Syn-rift Plays Offshore Namibia
Rift basins are well-known as prolific hydrocarbon-bearing provinces worldwide. Structural development plays a huge role in the occurrence and distribution of hydrocarbons within rifts, including the character of the basin fill.
Syn-rift plays stem from a complex interplay between tectonics and sedimentation rate. Tectonically derived topography is the primary control on the sedimentary processes which result in facies and stratigraphic distribution of source rocks, reservoir rocks and seals in syn-rift successions.
Commonly, the seismic expression of different syn-rift units gives an indication about the different stages of rift evolution and associated depositional systems. The stratigraphy of many continental rift basins show a vertical transition from an early fluvial, shallow lake or shallow marine succession to a deep lake or deep marine succession, when the rate of fault displacement is relatively low and sedimentation keeps pace with subsidence. As rifting continues, the rate of fault displacement increases markedly and sedimentation cannot keep pace with subsidence, this is known as the rift climax stage. On seismic section, the rift climax system is characterized by an increased amount of aggradations, together with the development of divergent forms related to continued tilting of the hanging wall during deposition. During the late syn-rift phase, the sediment supply is outpaced the rate of tectonic/fault-controlled subsidence, resulting into the deposition of well sorted coarser clastics which would act as good reservoir.
This session will discuss the prospectivity of the syn-rift succession offshore Namibia’s margin, which has not yet been penetrated by any exploration wells, however similarities can be seen in structural architecture and seismic facies with some of the typical rift basin success cases, such as the AJ graben in the Orange Basin, South Africa, where oil was discovered in 1988. By comparing them to different field analogues from various sedimentary basins this will aid in better understanding their impact on exploration.