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Abstract

The Carapeba Field reservoirs, located in Campos Basin, offshore southeastern Brazil, consist of sand-rich deep-water deposits formed by amalgamated turbiditic channels, whose properties were modeled using subsurface and outcrop-analog information. Outcrop analogs have been found in the Eocene Annot Sandstone, of southern France. The main geological inputs to the reservoir modeling process include: (1) recognition of main intrareservoir stratigraphic units, (2) determination of facies continuity and connectivity, and (3) determination of shale (permeability barrier) continuity. The recognition, both in the outcrops and at the subsurface, of two hierarchical levels of intra-reservoir stratigraphic units, which are interpreted to represent the products of 4th- and 5th-order sea-level cycles, and are possible to correlate at typical offshore interwell distances, is particularly relevant to reduce flow-unit scale stratigraphic uncertainty. Facies continuity has been estimated using outcrop data calibrated to cores, well-logs, and production data. Outcrop facies continuity is used to guide facies extrapolation in the subsurface 3D model, resulting in more realistic permeability structures. Shale continuity, which is a major factor controlling fluid movement within the reservoir, is mainly resultant, in these high-energy sand-rich turbidite systems, of the frequency and intensity of erosional processes. Most shales show continuity of several hundred meters or more, with erosive “windows” appearing locally. In these areas, permeable vertical pathways connect adjacent units. Nevertheless, overlapping of semi-continuous beds causes a general tendency of lowering effective vertical permeability. The final subsurface 3D model, showing reduced effective vertical permeability and moderate horizontal anisotropy, is quite different from what is conventionally expected for sand-rich turbidite reservoirs.

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