MACIEL,W.B., C. DEL LUCCHESE JR., C.A.G.CORÁ and A.C.C.PINTO - Petrobras E&P, Brazil, Rio De Janeiro
Abstract: Campos Basin Deep Water Turbidites: Field Development and Reservoir Management Issues
The Campos Basin is located in southeastern Brazil, offshore Rio de Janeiro state. The basin covers an area of about 100,000 km2, from the coast to the 3400 m isobath, and contains a maximum sedimentary thickness of about 10 km. Campos Basin evolution from the Lower Cretaceous to recent can be divided into three tectonic stages: (1) Rift, which comprises Neocomian basalts and lacustrine deposits; (2) Transitional, which includes evaporites and associated siliciclastic deposits developed during the Aptian; and (3) Marine represented by Albian carbonates at the base, overlain by two siliciclastic sequences: a transgressive (Upper Albian to Lower Tertiary) and a regressive (Lower Tertiary to present). Thick turbidite reservoirs have been deposited within the Marine Stage.These extensive submarine deposits were sourced by organic-rich lacustrine mudrocks deposited within the Rift Stage. The main controls of the turbidite deposits were sea level fluctuations, salt movement and tectonic activity in the source area. The main deposits are found in the following sections: (1) Upper Albian; (2) Cenomanian/Turonian; (3) Turonian to Maastrichtian; (4) Eocene; and (5) Lower Oligocene to Lower Miocene. Some reservoir features are more common in one chronostratigraphic group than another, but very different reservoirs are found within the same group. Salt tectonics has imprinted characteristics on the basin that differentiates the present day shallower water reservoirs from the deeper ones. In the transgressive sequence, thick turbidite reservoirs were deposited in fault-defined structural troughs. In the regressive sequence, the amplitude of the structures in deep waters increased, generating more extensive turbidite reservoirs. Therefore, the size of the structures has led the operational - exploratory and production - frontiers to deeper water depths. Thus, the exploratory frontier of the basin has been limited mainly by drilling and production technological barriers.
The first well in the Campos Basin was drilled in 1971. In 1977 the first well was put into production.At that time, just 53 wells had been drilled over a large area, hence, few rock and fluid analyses were available. The production of this well marked the beginning of Petrobras early production systems in the Campos Basin. The aim of an early production system was to obtain reservoir information through fluid production, and evaluate production potentials, drive mechanisms, reservoir architectures and sand production to allow the designing of the definitive system. Data was also used to specify equipment for sub-sea completion. In the 80's, the discovery of three fields at 100 m water depths and with very low solubility ratios (around 30m3/m3) led to the first large offshore project. In these particular fields the use of six fixed platforms with ESP (Electrical Submersible Pump) as the artificial lifting method was determined. At the same time, other shallow water fields were developed with submarine completions since they had been considered marginal fields. From the mid 80's on, new fields were discovered at increasingly deeper water depths, and Petrobras continued to use floating units. By the end of the 1980's, larger fields were being developed at water depths above 600m. Roncador, an Upper-Cretaceous reservoir field, the most recent giant in Campos Basin deep waters, was discovered by Petrobras in 1996.This field was put on stream in early 1999 with a 150,000 bpd capacity floating production unit.
Deep water projects have as a common feature the highly capital intensive character. Therefore, projects require high productivity wells and high ultimate recovery. The coupling of these two objectives demands the application of sophisticated technology. Most of Brazilian turbidite reservoirs have strong stratigraphic and sedimentological control both in terms of trapping and reservoir architecture. Water injection is usually applied in Campos Basin deep water projects; it has required consistent geological input to achieve the expected sweep efficiency and reservoir pressure maintenance. Hence, the geoscientists have been particularly involved on provide plausible reservoir static models to feed reservoir flow simulators in order to produce consistent development plans and reservoir management strategies. For the deep water fields, the high quality of 3D seismic has always been an important tool for allowing consistent field appraisal, development and production monitoring. Reservoir focused seismic acquisition, processing and novel inversion techniques have promoted a dramatic increase in the amount and also in the quality of information traditionally available for E&P staffs. Moreover, disciplines as sedimentology, high-frequency genetic and/or sequence stratigraphy, 3D stochastic modelling, reservoir geochemistry and reservoir-focused structural geology together with 3D visualization softwares are technologies currently being used and pursuit to handle the available data set, managing to incorporate more plausible, realistic and reliable geological models into the flow simulation models and volumetrics estimations. The use of horizontal wells, multi-lateral wells and extended reach wells are technological resources that have been implemented more and more into deep water projects. Intelligent completion of deep water wells is an example of technology that is still being pursued to allow better production monitoring. Pressure down hole gouges (PDG) have been considered very useful tools for obtaining reservoir dynamics information in the early stages of developement, together with more traditional reservoir tools as WFTs, DSTs and PVT analysis.
The reservoir properties of the different turbidite plays directly affect the field recovery factor. A quality index, which comprises relevant reservoir characteristics, was defined and calculated for the main Campos basin reservoirs. A good correlation was obtained between this index and the ultimate recovery factor of the reservoirs. This correlation has been useful to estimate reserves of exploratory prospects and to compare results obtained with reservoir simulation.
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