Pre-salt carbonate reservoirs from Santos Basin represent a great opportunity and probably the most important recent oil discovery. Tupi area (estimated to have recoverable volume of 5 to 8 bboe), which is the most known amongst several other leads in the cluster, is going to be a great insight for the production project. From the production point of view, this new frontier has technological challenges that are being addressed by PETROBRAS and partners. Special attention is being dedicated to anticipate solutions to potential problems. This will require a balance between innovative and field proven solutions. This paper addresses the most critical points, where Petrobras is making a great R&D effort, which are: Well technology, where casing stability, well cost and productivity are addressed, in a scenario of water depths beyond 2,200m, target depths greater than 5,000m, crossing salt layers that can reach 2,000m in thickness. Poorly known microbial carbonate reservoir, heterogeneous in vertical profile, spread over very large areas, with wettability concerns, requiring careful evaluation of the performance of the waterflooding method and EOR. Wax deposition, due to low temperature in the ocean bottom, imposing limitations to the subsea layout. Gas processing and exporting technologies concerning environmental issues: CO2 compact removal units aiming the minimization of emissions to the atmosphere. Production units placed in more than 2,000m water depth, with oceanic conditions quite severe and dealing with high CO2 content stream. These challenges deserve all Petrobras attention, but also count with the confidence in achieving good technological solutions, supported by the history of successful developments of the company. Introduction The history of success built by Petrobras in deep water Brazilian coast - mainly Campos Basin - was largely supported by successive discoveries of heavy oil in turbidite sandstones, step by step towards gradually deeper and deeper water depths (Carminatti et al., 2009). The Pre-salt discoveries of Santos Basin represent discovery of huge volumes of light oil (28 to 30 degrees API), with high gas content, in a very short time span, close the most important consuming centers in Southeastern Brazil, and formation tests in the first wells have presented very high flow rates with no indication of barriers. All are excellent news, although PETROBRAS and partners recognize that the Pre-salt of Santos Basin represents a challenging scenario: ultra-deep water (greater then 2,000 meters), deep carbonate reservoirs (deeper than 5,000 meters), spread over very large areas, with high gas-oil ratio (GOR in Tupi area greater than 200 m3/m3), CO2 content (8-12% in Tupi), high-pressure and low temperature, laying immediately bellow a thick salt layer (more than 2,000 meters of salt), located around 300 km from the coast, with oceanic conditions more severe than Campos Basin. This scenario demands using sometimes present day technology in the limit, and other times, adaption and development of technologies specific for such conditions. This paper addresses the most critical points to the development of production in the Pre-salt of Santos Basin, where Petrobras is making an R&D effort to develop and qualify new technologies, including well technology, reservoir technology, flow assurance, gas processing and exporting technologies, and production units. Additionally, the paper discusses briefly how PETROBRAS has organized its structure to face these technological challenges, including the creation of a technological program - PROSAL - focused on Pre-salt objectives.
Since the discovery of the Garoupa Field in the Campos Basin, Rio de Janeiro, Brazil, in 1973, Petrobras has been moving to deeper waters. Subsea engineering and well technologies have been developed and applied to overcome the environmental restrictions. Today more than 50% of Brazil's oil production comes from fields located offshore in water depths over 1,000 m. In this scenario, the Marlim Complex - which comprises the Marlim, Marlim Sul and Marlim Leste fields - plays an important role. Discovered in 1985, the Marlim Field started production in 1991, with a pilot system comprising 7 wells connected to a semi-submersible unit moored in a water depth of 600 m. Currently, the field production is about 85,000 m3/d (535,000 bpd), with 60 producers and 32 water injectors connected to 7 floating production units. As with other Campos Basin turbidites, the Oligocene/Miocene reservoir of Marlim Field presents 3 outstanding characteristics: predictability, from seismic data and geological modeling, excellent petrophysical properties and good hydraulic connectivity. The extensive use of 3D seismics as a reservoir characterization tool allows the reduction of risks and the optimization of well locations. Additionally, 3D visualization techniques provide a new environment for teamwork, where seismic data is interpreted and input into detailed reservoir simulation models. Among the deep water well technologies employed to develop the Marlim Complex it is worth mention: slender wells, high rate well design, horizontal and high angle wells in unconsolidated sands, efficient low cost sand control mechanisms, selective frac-pack with isolation between zones, pressure downhole gauges (PDG's), new techniques for the connection of flowlines and X-mas trees, subsea multiphase pumping and special techniques to remove paraffin in the flowlines. However, new developments are required, such as extended reach wells, selective completion in gravel-packed wells, isolation inside horizontal gravel-packed wells with External Casing Packers (ECP's), smart completion and improved recovery techniques for viscous oil. Much has been learned during the planning and development of the Marlim Field and this knowledge is currently being applied in the development of Marlim Sul and Marlim Leste fields. Some important points must always be observed:the development plans must be defined by using optimization techniques considering the geological risks;the number of wells of the initial development plan must be defined through a detailed optimization study, considering economic indicators, oil recovery and risks;the wells must be designed to allow high production rates, with "rest of life" completions, as simple as possible;the sand control mechanisms must be simple, efficient and low cost,the seismic resolution or the production data analysis must be of sufficient quality to guarantee that there will be good hydraulic connectivity between the producers and the corresponding injectors;the pipelines and risers must be designed to avoid bottle-necks or conditions for deposition of wax or hydrates andthe reservoir management and particularly the water injection system management must be made with an integrated teamwork approach. In this paper we present some aspects of the reservoir engineering and of the development plan of the Marlim Field and briefly discuss how this experience is being used in the development of the neighboring Marlim Sul and Marlim Leste fields. Introduction The Marlim Complex comprises 3 giant deepwater oil fields - Marlim, Marlim Sul and Marlim Leste - located in the Campos Basin, 110 km offshore Rio de Janeiro, Brazil (Fig. 1). Besides the geographic location, these fields have other similarities: the main reservoirs are turbidites of Oligocene/Miocene age; 3D seismic data allows accurate prediction of the reservoir occurrence; rock characteristics are excellent; relative permeabilities are favorable to water injection and well productivities are very high.
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