PRAVAP 2 (Petrobras' strategic project for reservoir characterization) aims mainly technology acquisition and development in reservoir characterization. The project is based on a multidisciplinary approach, and the synergism between operational and research teams. New technologies are put together with others already consolidated. This paper presents some of the developments acquired and how they impact the field development and oil production. Introduction Petrobras has been developing its major offshore turbidite oil fields. Improved techniques for reservoir characterization and reservoir engineering (drilling, completion, and stimulation) are required to reduce risks and optimize investments, commonly high in offshore areas. The challenge for developing offshore deep water oil fields has led to a paradigm changing in the early 70's and 80's technology, mostly centered in closely-spaced vertical and deviated wells. The new scenario requires a reduced number of largely-spaced horizontal or multilateral wells. Additionally, some of the internal heterogeneities of turbidite reservoirs are still poorly understood. Facies are well described from cores, but scarce information is available from inter-well areas. Some characterization techniques are particularly indicated for improvement in well location, as refined maps for the reservoir top, well log resistivity modeling, and 3D reservoir modeling and visualization. Multidisciplinary team approach and integration of well, production, fluid and specially seismic data into an integrated model can improve reservoir characterization. Seismic must be intensively used, but special efforts on seismic processing is needed to eliminate noise and to recover high frequencies. High-resolution stratigraphy The Upper Albian Namorado Sandstone form part of an Upper Cretaceous to Lower Tertiary transgressive succession, which is characterized by onlapping, deepening-upward sedimentation throughout the eastern Brazilian margin. The Namorado turbidite reservoirs from the Albacora oilfield are confined to a NW-SE-oriented, 100-km-long, and 40-km-wide sag, which was established in a deep neritic to upper bathyal setting. These turbidites were probably following a tectonically induced depression in the slope related to the eastward tilting of the Campos Basin and resulting downslope flowage of underlying Aptian evaporites. Namorado Sandstone at Albacora field comprises two turbidite successions. The uppermost (Namorado I) is 0–12m thick, and the lowermost (Namorado II) is 28–107m thick. These two sand-rich successions are separated by a 11–17m thick succession of diamictites (debris flow deposits) and bioturbated calcilutites, marls and shales (background sedimentation). Thin (<3.4m) non-reservoir beds (diamictites, calcilutites, marls, and shales) are commonly interbedded with sandstones of Namorado II, comprising 14% of its total thickness. The turbidite reservoirs are composed mostly of unstratified, fine- to very fine-grained sandstones. Subordinate facies include unstratified, coarse- to medium-grained sandstones, and Tab, Tabc, Tbc, and Tc Bouma beds of fine- to very fine-grained sandstones. The sandy reservoirs are poorly sorted, and composed mainly of quartz, feldspar, and fragments of quartzofeldspathic, high-grade metamorphic rocks. Mud matrix includes 3-30% silt, and 1–6% clay. The average framework composition is Q59F38L03. Accessory components consist mainly of carbonate intraclasts (0–11%), and bioclasts (0-9%). Namorado Sandstone can be subdivided into 12 reservoir units (numbered 1 to 12 from oldest to youngest; Fig. 1), mostly on the basis of (1) thicker, widespread non-reservoir beds (marker beds A to D; Fig. 1), and (2) trends of grain size distribution.

shore Brazil are found in Oligocene/Miocene sand-rich turbidites of contrasting architectural types. Reservoirs are sand lobes with thickness of 50 m, width of 1-5 km wide, and length of 2-10 km that display compensation stacking patterns. The reservoirs show bright reflections in a single amplitude trough corresponding to a relative decrease in impedance. In the study area, turbidite successions have high structural dips and complex spatial distribution. Their individual geometries are very difficult to map using conventional 3-D data.Detailed mapping of the geometry of Campos Basin turbidite reservoirs is required to guide the drilling of high-cost horizontal and multilateral wells needed for development of deepwater fields. An interpreter needs more than conventional 3-D structural and stratigraphic seismic visualization techniques for identification of compensation stacking patterns. Our group adapted some conventional stratal surface visualization techniques for better 3-D delineation of turbidite reservoirs in seismic volumes. This was important because a single frequency-independent horizon for attribute slicing could not be recognized. Adaptations were combined with enhancements to common volume visualization techniques by adding topological reconstruction methodologies for delineating sand bodies. These procedures became necessary because current visualization techniques are based only on physical values of seismic samples. Our study finds turbidite attribute strengths within stacking patterns that generally have subtle or nonvisible differences.The 3-D seismic visualization methodology in this article has an adaptive approach that can be summarized as:Adaptive windows of seismic traveltime data are transformed to horizon slices to map different depositional subsystems. Each depositional subsystem becomes topographically detectable from slices derived from 3-D seismic attribute volumes. Studies of Recent age analogs and geologic models guide this procedure. Such an approach better visualizes high-order stratigraphic sequences and can isolate thin, discontinuous reservoirs within channel/levee and lobe systems.Petrobras has studied outcrops and seafloor sonar images from Campos Basin to get a better description of the geometry and heterogeneities of subsurface turbidite reservoirs. In particular, Machado et al. (1998) studied Carapebus Formation, which contains the main turbidite reservoirs. This formation is still being deposited. Using side-scan sonar images and swath bathymetry from the seafloor, they identified low-sinuosity braided channels, pebbly mudstones (debris flows), and sand-rich turbidites in troughs and lobes. This showed that sedimentary processes such as channel avulsion control the geometry of turbidites in flat regions. Analysis of these modern depositional systems allows recognition of important types of reservoir heterogeneities, which can be also found in older turbidite systems.Importance of understanding turbidite architectural types and reservoir models. Oligocene/Miocene sand-ri...

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