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 13 th , 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 (<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 >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 r...

Successions of Early Eocene coarse‐grained turbidites up to 400 m thick fill fault‐controlled canyons along the eastern Brazilian continental margin. They form part of a Late Albian to Early Eocene transgressive succession characterized by onlapping, deepening‐upward sedimentation. In the Lagoa Parda oil field (Regência Canyon, Espírito Santo Basin) the turbidite facies consist mostly of unstratified conglomerate and sandstone, with interbedded bioturbated mudstone and thin‐bedded, stratified sandstone. Within the main Regência Canyon, the coarser grained facies occur within 38 deeply incised channels. The fills are 9 to >50 m thick, 210 to >1050 m wide and >1 km long. The finer grained facies build asymmetrical levees that are higher and thicker on the left side (looking downstream) of their channels, probably as an effect of the Coriolis force (to the left in the Southern Hemisphere). Nine levee successions up to 50 m thick are associated with the 20 youngest channels. The deposits filling the low‐sinuosity Lagoa Parda channels record successive channel abandonment through relatively rapid avulsions. Avulsions of unleveed channels took place randomly, but channels with well‐developed levees show preferential avulsion to the right (looking downstream), opposite to the direction of preferential levee growth.Lagoa Parda channels can be grouped into three complexes 20–100 m thick. These complexes have an estimated duration of about 140 000 years. It is suggested that control of the development of individual channel complexes was related to variation in sediment supply, in turn probably related to climatic changes. The deposition of each channel complex would have followed an increase in sediment supply into the Regência Canyon through delta/fan‐delta and littoral drift systems, which in turn would have responded to phases of higher denudation rates in the high‐relief, ancestral coastal ranges of south‐eastern Brazil.Overall, the three Lagoa Parda channel complexes form a turbidite succession characterized by channel fills that become narrower, thinner and finer grained upward. These trends were induced mostly by a longer term (>400 000 years) decrease in sediment supply, which in turn resulted from the combined effects of a long‐term (second‐order) trend of sea‐level rise, and the decreasing fault activity at the basin margin and source area.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract

Coniacian to Lower Maastrichtian coarse-grained turbidites fill intra-slope, fault-controlled canyons in the Campos Basin, offshore Brazil. They form part of an Upper AIhian to Lower Paleocene transgressive succession characterized by onlapping, deepening-upward sedimentation throughout the eastern Brazilian margin. In the Carapeba and Pargo (CRP-PG) oil fidds the turbidites consist mainly (> 95%) of graded beds without any other sedimentary structures. Individual beds are up to 12 m thick and are composed of small pebble-< 2 cm) to granule-rich sandstones, and medium to very coarse sandstones. The finer-grained portions of these graded beds show better sorting and higher porosity, and these characteristics can be recognized in density logs. Use of 92 density logs calibrated with 13 cores permitted the mapping of 198 coarse-grained turbidites in the CRP-PG turbidite system. The turbidites form eight thinning-and fining-upward facies successions, some bounded by regional unconformities or local erosion surfaces. The successions are 27-140 m thick and contain 7-58 turbidites. Their durations are estimated to be between 0.4-.0.9 m.y. They form 1-12 km wide, tabular or linguoid sandstone bodies in which the younger or more distal turbidites become finer-grained, thinner-bedded, and more discontinuous upsection and downcanyon. The successions are stacked in an overall retrogradational pattern for at least 20 km, recording the backfilling of the CRP-PG canyon.Turbidites in the CRP-PG area were probably deposited during falls of relative sea level that punctuated the overall transgressive setting of the late Cretaceous and early Tertiary. There is a mismatch between the number of successions (eight) and the number of time-equivalent third-order fluctuations of relative sea level (four and part of a fifth; Haq et al 1988), suggesting that eustatic sea level fluctuation was not the dominant control on most of the successions. Cross sections and isopach maps of the successions do not suggest internal channeling, and a channel-fill origin for the fining-and thinning-upward successions seems unlikely. We therefore suggest that episodic tectonic reactivation in the uplifted Precambrian source area, and faulted basin margin, led to relatively abrupt increases in the volume of sediment supplied to the head of the canyon across a narrow shelf. Steady denudation and decreasing supply of sediment led to formation of the fining-and thinning-upward successions.

Petrobras found almost 100 hydrocarbon accumulations in the Campos and Santos basins, between 50 and 300 km off the Brazilian coast (under water depths from 80 to 2,400 m), which produce from very different types of reservoirs, including mostly (1) pre-salt coquinas and microbialites, (2) post-salt calcarenites, and (3) post-salt siliciclastic turbidites. These different types of reservoirs, containing also different types of hydrocarbons and contaminants provided many challenges for their production development, related to distinct tools and workflows for reservoir (static/dynamic) characterization and management, seismic reservoir characterization and monitoring, recovery methods (water injection, WAG, etc.), well spacing, well types and geometries, subsea systems, and processing capacity of production units. Since the first oil and gas discoveries in the Campos (1974) and Santos (1979) basins, Petrobras continuously moved to aggressive exploration and production from shallow- to deep- and ultra-deep waters. During the last 40 years, the activities of reservoir characterization and management have also continuously evolved. Four major phases can be depicted: (1) shallow water fields developed with a large number of vertical or deviated wells (e.g. Namorado, and Pampo, Campos Basin); (2) deep water fields, still developed with a large number of wells, but now combining vertical/deviated and horizontal wells (e.g. Marlim and Albacora, Campos Basin); (3) deep to ultra-deep water, post-salt fields, containing light to heavy oil (13-31 °API) in siliciclastic turbidites and carbonates, developed with a relatively small number of mostly horizontal wells (e.g. Marlim Sul, and Barracuda, Campos Basin); (4) ultra-deep water, pre-salt fields with very thick (up to 400-500 m), light oil (27-30 °API) carbonate reservoirs, developed with largely-spaced vertical and deviated wells (e.g. Lula, and Buzios, Santos Basin).

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