Campos Basin: Reservoir Characterization and Management - Historical Overview and Future Challenges
Authors: Bruhn Carlos H.L. , Gomes José Adilson T. , Del Lucchese Cesar , Johann Paulo R.S. 
Published: October 2008

The first oil discovery in the Campos Basin dates from 1974, when the ninth well drilled found Albian carbonate reservoirs (Garoupa Field) under a water depth of 120 m. Oil production started on August 13th, 1977, from the Enchova Field, which produced to a semi submersible platform moored at a water depth of 124 m. This was the beginning of a successful history that led Petrobras to become a world leader company in petroleum exploration and production in deep and ultra-deep waters. Forty-one oilfields were found between 50 and 140 km off the Brazilian coast (under water depths between 80 and 2,400 m), which produce from a variety of reservoirs, including Neocomian fractured basalts, Barremian coquinas, early Albian calcarenites, and (mostly) late Albian to early Miocene siliciclastic turbidites. These reservoirs were responsible for an average oil production of 1.2 million bpd in the year 2002 (83% of the total Brazilian production), and they are expected to be producing 1.6 million bopd by the end of 2005. The cumulative oil production from the Campos Basin comprises 3.9 billion bbl, and the current proven oil reserves are 8.5 billion bbl (89% of total Brazilian reserves).

Deep and ultra-deep water giant fields started to be discovered only in 1984. There was a succession of large discoveries, including Albacora, Marlim, Albacora Leste, Marlim Sul, Barracuda, Caratinga, Roncador and, more recently, Jubarte and Cachalote. The development of these fields has continuously provided new challenges for the reservoir characterization and management in the Campos Basin. These fields are developed with fewer, horizontal and high angle wells, drilled into poorly consolidated reservoirs. The extensive use of 3D seismic as a reservoir characterization tool has optimized well location and allowed the reduction of geological risks. Integration of high-resolution stratigraphic analysis with 3D seismic inversion, geostatistic (stochastic) simulation of reservoir properties constrained by seismic, well log and core data, 3D visualization, and voxel-based automatic interpretation has guided the positioning of horizontal wells through thin (&lt; 10-15 m) reservoirs. Additionally, 3D visualization techniques have provided a new environment for teamwork, where seismic, well log, and core data are interpreted and added to detailed 3D geological models and, subsequently, to robust reservoir simulation models.

The deepwater subsea wells must be designed to allow high production rates (typically &gt;10,000-15,000 bopd), with lifetime completions to avoid costly interventions. In order to assure high productivity, pressure maintenance must be efficient; if water injection is planned, the hydraulic connectivity between injector and producer wells must be guaranteed by high-quality 3D seismic, well log correlation, and observed pressure profiles. Detailed studies have been made in order to define the distribution and number of wells, since the number of wells strongly affects the net present value of deepwater projects. Wells with expected oil recovery of less than 10-15 million bbl are not drilled in the beginning of the projects, and remain as future opportunities to increase oil production and recovery.