An opportunity to re-evaluate the petroleum potential of the Douala/Kribi-Campo Basin, Cameroon

Abstract

The recently announced Cameroon licence round running until 29 June 2018 provides oil companies with a significant opportunity to acquire large swathes of acreage in the Douala/Kribi-Campo (DKC) and Rio Del Rey (RDR) Basins. The DKC Basin is divided into two sub-basins, the Douala Sub-basin in the north and the Kribi-Campo Sub-basin in the south. The RDR basin, situated at the toe of the Niger Delta (Figure 1), is a mature basin with significant infrastructure and production. In contrast, the DKC Basin, which is the focus of this paper, is relatively underexplored, yet there are marked grounds for optimism in its petroleum potential. The DKC Basin is separated from the RDR Basin by the Cameroon Volcanic Line (Figure 1) and is the northernmost basin formed during rifting and separation of the South Atlantic conjugate margins, a province harbouring prolific hydrocarbon accumulations. Exploration in the offshore Douala Sub-basin began in the 1960s but the first well drilled, Nyong Marine-1, was dry. It was not until the late 1970s, with the drilling of Sanaga Sud A-1 and the discovery of gas-condensate within the Aptian-Albian-aged Mundeck Formation, that exploration accelerated with the drilling of 11 discoveries in the Cretaceous, two with secondary Tertiary reservoirs. This exploration phase was primarily focused in the shallow water Kribi-Campo Sub-basin, targeting Cretaceous tilted fault-block plays, which also extend onshore, where oil is currently produced from the overlying Cretaceous Logbadjeck Formation in the Mvia Field (Figure 2). Despite the early success, production was not established until 1997 in the Ebome Field. Today, more than 1 million bbls of oil is produced annually from the Kribi-Campo Sub-basin (SNH Production Figures, 2016). The rest of the offshore DKC Basin is relatively underexplored with only 23 wells drilled in an area larger than 10,000 km2. Wells have targeted a range of reservoir intervals from the Miocene to Upper Cretaceous across a variety of stratigraphic, structural and combination traps (Figure 3). Upper Cretaceous reservoir-quality sands were penetrated by the hydrocarbon-bearing Sapele-1 well in the Etinde Exploration Block and Cheetah-1 in the Tilapia Block, although sands in the latter well were thinner than initially postulated. Strong oil shows were encountered in turbidite sands in well CM-1A in the Elombo Block. Beyond the shelf, deepwater wells Eboni-1 and Bamboo-1 (Elombo and Ntem Blocks) also targeted Upper Cretaceous sands but were water wet. Tertiary sands have been penetrated by a number of wells in the Tilapia Block, including Coco Marine-1 which flowed 34oAPI oil at a rate of 3000 bopd from the Paleocene. Oil, gas and condensate have all been recovered from various Miocene channel and fan sands across the basin, most notably from Noble’s successful YoYo discovery. This is an extension of the play behind the Yolanda-1 discovery and the producing Alen and Aseng Fields in Equatorial Guinea (Figure 2). Despite evidence for more than one working petroleum system (Tertiary and Cretaceous), hydrocarbons flowed to the surface in only a handful of wells outside the Kribi-Campo Sub-basin and the YoYo discovery looks on course to be put into production. The next phase of exploration in the Doula Sub-basin undoubtedly requires an understanding of the reasons behind this limited exploration drilling success. Previous operators have all suspected that there are challenges with source rock, timing of migration, and presence of reservoir, seal and trap but never consistently across all wells. Deciphering reasons for the apparent low well success requires a review of all exploration data in a regional geological context beyond the limits of individual blocks.