In the early 2000s the context of the pre-salt formations was conceptual geological models of possible oil bearing reservoirs underneath a thick salt layer, many technical challenges, uncertainties and risks. Past only eight years from first discovery (2006), there are nine production systems, FPSOs, in operation, reaching an average oil rate of more than 700 thousand barrels per day and a cumulative production greater than 400 million barrels of oil, through 34 production wells. To optimize recovery, the first desulfated sea water and gas injectors were started. But these impressive numbers cannot be taken from granted: although nature has revealed prolific reservoirs, much experience, talent, planning and perseverance were necessary. The first articles addressing the pre-salt fields had a focus on the technical challenges faced on first years: the heterogeneous nature of the microbial carbonate reservoir, the 2,000 m salt layer and drilling concerns associated, the variable CO2 content and compositional grading in the reservoir fluids, flow assurance issues and special demands concerning subsea engineering, well construction and processing plant. The main drivers and development strategies were also established: staged development, based on extended well tests (EWTs), multi well production pilots and definitive systems prioritizing the standardization of well projects and production systems. Now, challenges and plans are rewarding the efforts, as depicted by the concrete production numbers achieved to date. In this text, a historical perspective of the pre-salt exploration and development is presented, emphasizing the previous unknowns and uncertainties and how they were treated in order to attain the results. As we still have a lot to learn, since we are just on the beginning of the development of this extraordinary petroleum province, a look to the future and the present efforts on optimization are also commented.

This paper describes how Petrobras is assessing the realistic pre-salt potential of the Santos Basin, offshore Brazil, in water depths between 1,900 and 2,400m (6,230 and 7,870ft). Three integrated ultra fast-track projects were planned to start production of the giant pre-salt reservoirs in an area known as Tupi. The carbonate reservoirs in this area contain an estimated recoverable volume between 0.8 and 1.27 billion m3 (5 and 8 billion barrels) of a 28o API crude, with high GOR and a CO2 content in the dissolved gas of 8-12% vol. They are located below a 2,000m (6,560 ft) salt layer, in vertical depths around 5,000 m (16,400 ft) from the sea level. Besides the good expectations based on the seismic interpretation and geologic modeling, the two wells drilled in the area presented good productivities in the well tests, pushing Petrobras and its partners to implement the fast track production projects. The objective of the three projects is to obtain relevant reservoir and production data, to support the design phase of the remaining production units of the full field development [1]. First, the Extended Well Test, EWT, which comprises the sequential connection of two sub-sea wells to a turret moored FPSO, scheduled to start production in April 2009, will be shown. Second, the paper will cover an eight well Pilot System (five producers, two water-alternating-gas injectors and one water injector), using a spread moored FPSO, with flexibilities to be expanded in the future to become its first production module. First oil of the Pilot Phase is scheduled for late 2010. The third project is a 216km (134mi) long, 457mm (18in) OD diameter gas pipeline, from the Tupi area to the Mexilhão platform, in shallow waters. From Mexilhão, the export gas will be sent to the Caraguatatuba onshore gas plant, through an 864mm (34in) OD multiphase pipeline. The paper also addresses the main technical challenges, such as drilling of complex wells with intelligent completions, qualification of ultra-deepwater risers, flow assurance through long subsea flowlines, and CO2 capture and sequestration. INTRODUCTION The Tupi Area is part of the original exploratory block BM-S-11, located in the central portion of the Santos Basin, offshore the Rio de Janeiro State, at approximately 290 km (180 mi) from the coast, under water depths around 2,200 m. It represents one of the most important offshore production frontiers in the World [2]. The BM-S-11 block has the following working interest among its partners: Petrobras (operator - 65%), BG (25%) and GALP (10%). After the declaration of discovery in 2006, filed with the Brazilian Petroleum Agency, ANP, the consortium holds its remaining area, known as the RJS-628 evaluation plan area, depicted in Fig. 1. The first well drilled in the block was the RJS-628, completed in August 2006. The well was designed to test the carbonate section of a reservoir of the Aptian age. It found hydrocarbon bearing reservoirs in carbonates of microbial origin, named SAG reservoir. A secondary microbialite reservoir, named RIFT reservoir, was also found. Both reservoirs are located below a thick layer of salt that occurs regionally in this portion of the basin. Because of this, these reservoirs were classified as pre-salt reservoirs. The well was tested and produced, after an acid stimulation and with the choke constrained, 378 m3/d (2,380 bpd) of a 28o API crude oil, with a GOR of approximately 220 m3/m3 (1,240 scf/bbl).

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).

This paper describes the current studies to define alternatives for the geological storage of the CO2 present in the associated gas to be produced from the Pre-salt reservoirs of the Santos Basin, Brazil. Recent hydrocarbon discoveries in Santos Basin, offshore Brazil, in the so-called pre-salt reservoirs, brought many challenges for the production development (Beltrao et al., 2009). The reservoirs are heterogeneous microbialite carbonates, located below up to 2,000 m salt layer thickness, in water depths of 2,200 m. The oil is a 28 – 30°API, with GOR higher than 200 m3/m3. Besides the unique environment, one additional challenge is the variable CO2 content in the associated gas. The sustainable hydrocarbon production from the pre-salt reservoirs will, then, require, in line with Petrobras and its partners' vision, avoiding emissions of the CO2 produced together with the hydrocarbon. The task that would be difficult for onshore oil fields reaches unparalleled complexity in the subsea completion deep water production scenario. Some alternatives are under study for the CO2 capture and storage: reinjection in the producing reservoirs, in salt caves, in salt water aquifers, in depleted gas reservoirs and even transportation and use of the CO2 for industrial purposes. Although still in the early stages of development, work done so far paved the way for robust and sustainable gas processing and CO2 separation, compression and reinjection in secure sub surface geological horizons. The current analysis indicate that the best alternative seems to be the reinjection in the oil producing reservoirs, with a good perspective of enhanced oil recovery by the association of gas and water injection in the Water Alternating Gas (WAG) process.

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.