In this First Break article from September 2024, Felicia Winter (TGS), Tiago Cunha, Marianne Nuzzo and David Gardiner (IGI Ltd.) present the results of a basin petroleum systems model investigation combined with a surface seep geochemistry survey to address the key exploration risks of source presence and maturity.
Introduction
In 2014 a new spotlight was thrown on the Mauritania, Senegal, Guinea Bissau and Republic of Guinea (MSGBC) offshore region with the FAN-1 discovery in Senegal. This was very quickly followed by the successful drilling of SNE-1 (now Sangomar Field). Continued exploration success yielded multiple commercial gas discoveries, such as Tortue-1, Yakaar-1 and Orca-1, but exploration activities have subsequently slowed down. In 2024 a new wildcat well will be drilled in deep-water Guinea Bissau, Atum-1 by Apus, reigniting exploration interest in this potentially prolific petroleum province. This study aims to address one of the key exploration risks of the margin, source presence and maturity.
Tectonic reconstructions demonstrate that prior to break-up in the mid-Cretaceous and the opening of the central Atlantic, the southern MSGBC Basin was juxtaposed against the prolific Demerara Plateau Guyana-Suriname margin, with the deposition of major Jurassic and Cretaceous source rock intervals. No more than 200 km separated the coastlines of modern-day Guinea and Suriname (Nemčok et al., 2016). The palaeo-tectonic reconstructions indicate that the deepwater MSGBC and Guyana-Suriname basins formed an axis where marine circulation was restricted, which is likely to have enabled preservation of organic matter on the seafloor to form world-class marine source rock intervals from the Barremian to Turonian. Early Jurassic syn-rift lacustrine and late Jurassic carbonate source rocks are also likely to be present in the MSGBC platform areas.
Several of these source rock intervals have been proven by the drill bit in the MSGBC offshore basins in both exploration and Deep Sea Drilling Project (DSDP) wells, with the older sources inferred from biomarker and isotopic compositions of discovered oils and gases. Their presence is relevant since the borehole locations are at the shelf edge in a classic passive margin setting where there is connectivity of environments across the shelf/slope. Despite that, one of the main exploration risks is still perceived to be source rock presence and maturity, and timing of hydrocarbon generation. The overall objective of this study is to integrate geochemistry results obtained from gravity and piston cores in 2020 with regional structural mapping, well information and heat flow studies, to build an integrated Basin and Petroleum Systems Model (BPSM).
Figure 1 - Data coverage of Phase 1 and 2 of the study, including regional 2D seismic offshore Senegal, The Gambia, AGC, and Guinea and the multibeam and seafloor sampling (MB&SS) data (light blue polygon). For confidentiality reasons, core locations within the MB&SS have been replaced with a ‘heatmap’ showing density of sample locations across the campaign area. Black polygons A-D signify main structural domains in the MSGBC basin across the margin.
The regional thermal subsidence of this passive margin basin during the Albian to late Cretaceous period was accompanied by the deposition of interbedded shales and sands, and localised carbonates. Organic-rich marine shales, deposited in the Barremian to Albian, are the probable source for the Senegalese discovery Fan-1, which charged Albian-aged sands with 28° API oil (Clayburn, 2017). The younger Turonian and Cenomanian section exhibits additional source potential, proven by DSDP westwards in the deep oceanic basin (e.g., DSDP 367) and by exploration wells on the platform. Additionally, there are further data pertinent to demonstrating source rock presence and maturity, in the form of a multibeam and seafloor sampling survey conducted in 2020 (blue polygon in Figure 1).
Read the full article here.