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The great geological success in OGX's oil prospecting at the Albian-Cenomanian carbonate shelf on the southern Campos basin involves at least three different geologic components: (1) the appropriate geographic position of the traps within a low geopressure zone, away from the high pressure oil kitchen (external rift) and beyond the most prolific oil carrier bed of the Campos basin–the Cabo Frio fault system (Papa Terra, Maromba, Polvo and Peregrino oil fields and all of the discoveries made by OGX); (2) the Late Cretaceous and mainly early Tertiary magmatic events that contributed to the generation of an intensive and extensive high secondary porosity and increased permeability by thermobaric effects on the carbonate rocks; and (3) the presence of a high energy carbonate depositional system in the Quissamã Formation (Albian) and Imbetiba Formation (Cenomanian), which involves lateral accretion [e.g., Pipeline (1-OGX-2A-RJS well), Waimea (1-OGX-3-RJS well), Etna (1-OGX-6-RJS well), Fuji (1-OGX-8-RJS well), Illimani (1-OGX-28D-RJS well), Peró (1-OGX-14-RJS well), and Tamborá (1-OGX-52-RJS well)] and vertical stacking [e.g., Waikiki (1-OGX-25-RJS well)] of thickening and shoaling upward carbonate depositional cycles.

The oil accumulations in the Quissamã Formation are well defined by logs and pressure data (Pipeline, Etna, Illimani, Fuji, Waimea and Tambora wells) and are typically related to five tilted fault block trends (faults strike direction northeast/southwest), subparallel to the Cabo Frio fault system, all of which are filled to the spill-point, and each has a different oil/ water contacts. As a general rule the antithetic faults act as the major controlling seal for the oil accumulations in these three-way dip closure structures.

The last successfully tested exploration model was a stratigraphic-structural trap formed by the updip pinch out of prograding carbonate shoals in the Imbetiba Formation relative to regional structural dip. This was drilled by the 1-OGX-14-RJS well (Peró Prospect) with an oil column of approximately 60 m based on pressures and well log data.

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