EAGE Sub-Saharan Africa Energy Forum

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Prospect E resides in the undrilled western Panel E of Bombadil Field in a deep-offshore West African basin. Bombadil Field produces from a mid-Miocene channel complex. Normal fault separated panels D and E show reservoir juxtaposition and a clear DHI event suggesting an OWC in panel E.

The main risk for Prospect E is fluid quality due to observed biodegradation resulting in high viscosities and disappointing production in Bombadil D Field.

The fluid distribution in panel D indicates an abnormal viscosity trend which cannot be explained by biodegradation processes alone. Evidence of extreme gas stripping correlates with high viscosity fluids and coincides with a spectacular gas chimney observed directly above the crest of panel D. Despite pressure continuity and an absence of barriers, viscosity variations inside panel D suggest transitory fluid disequilibrium.

Bombadil Field has experienced a very complex history. Fluid properties are controlled by its charge history, competing biodegradation and gas stripping processes. Bombadil Field’s fluids consist of a mixture of biodegraded and fresh recharged oil in various quantities which improves oil quality.

Detailed geological mapping, seismic analysis combined with fluid geochemistry, and PVT data is integrated in a cohesive geological model which enables viscosity prediction at prospect E.

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Large portions of the African Atlantic margin and its conjugate in Brazil have witnessed significant petroleum exploration and production over the last century. However, for the past 50 years, only one gas field has been discovered in Namibia (1974), which proved economically unviable for production at the time. There have been intermittent periods of exploration, but it wasn’t until February 2022 when the next new discovery was announced by NAMCOR alongside Shell in their Graff-1 Well in the Orange Basin. In the same month, another substantial discovery was made by TotalEnergies in their Venus-1 well, sparking increased interest in Namibia. Both wells proved an oil-mature source, in contrast to gas found in the Kudu Field. More oil discoveries will be needed to support development hundreds of kilometres offshore, in 2 to 3 km of water depths.

The appetite for deepwater exploration in high-risk, high-reward scenarios has significantly increased, particularly focusing on deeper stratigraphic intervals (Cretaceous) in the distal parts of the basins and in close proximity to the source rocks to minimize the risks associated with long-distance hydrocarbon migration. We have identified similar leads within the Aptian-Albian and Santonian-Campanian ages, extending through the deep-water Lüderitz and Walvis basins.

Shell entered the Orange Basin block PEL 0039 early 2014 based on the identification of the large Barremian Cullinan carbonate prospect, located on top of an SDR outboard high, which was initially mapped on a wide 2D seismic grid. The prospect was interpreted to be overlain by the Aptian source rock (Kudu shale) and a thick sequence of deepwater shales. The Cullinan structure is a 4-way closure formed by both the underlying volcanic SDR sequence, and post-depositional erosion. Initial interpretation of the prospect on 2D showed distinctive carbonate features, which were comparable to some known global analogues.

The Cullinan evaluation journey spans over 10 years. In late 2014 Shell acquired a 2520 km2 3D seismic over the prospect. Subsequent detailed 3D evaluation invalidated some of the initial 2D observations, and it was concluded that the prospect was a high-risk, high reward opportunity, with presence of effective reservoir as the main risk. In 2017, Shell started focusing on Cretaceous clastic plays and the JV decided to acquire new 3D surveys over these plays in 2018 and 2019 and matured several clastic prospects for drilling. The Cullinan prospect stayed in the background, with some detailed reprocessing, geological studies and analogue studies being carried out. This work failed to further reduce the risk on the prospect, and it was concluded that only an exploration well could de-risk it further. The drilling success of the clastic plays in PEL 0039, and the start of an extended drilling campaign late 2022, offered the opportunity to test the Cullinan prospect efficiently and it was finally drilled in June/July 2023. The well failed to find commercial HC volumes, however provided encouraging results indicating a working petroleum system in the previously untested northern area of the license. Further evaluation of the Cullinan-1X results is currently ongoing.

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