Abstract

Campos basin reservoirs are responsible for an average oil production of 1.2 million bpd (83.5 % of Brazil's total production) with a forecast of 1.6 million bopd by the end of 2005.

This production comes from forty-one oilfields located between 50 to 140 km off the Brazilian coast (under water depths from 80 to 2.400 m) displaying a variety of reservoirs including Neocomian fractured basalts, Barremian coquinas, Early Albian calcarenites and late Albian to early Miocene siliciclastic turbidites (most frequently)(1).

Scaling risk for new fields is usually assessed in time as an input in the development phase of field projects. In order to guarantee a reliable formation water sample, from appraisal or development wells, a protocol was created based on data from twenty-six bottom-hole samplings. Correlations between produced fluid volume, porosity and permeability of the reservoir and the contamination degree were determined and used to define the minimum time of pumping necessary to have non contaminated samples.

This paper outlines the scaling tendency of the main fields from Campos Basin, based on the chemical composition of the waters and its association with the reservoir types. Scale risk of the fields is an important tool to be considered on the development phase project to support the decisions related to the appropriate technology to be adopted.

Introduction

Campos Basin occupies an area of 115,000 km2, located in southeastern Brazil offshore of the states of Rio de Janeiro and Espirito Santo (Fig.1). The first oil discovery dates from 1974 and came from Albian carbonate reservoirs (Garoupa field) under a water depth of 120 m. Oil production started three years later from Enchova field which has the same reservoir as Garoupa field. To date, forty-one important fields were discovered between 50 to 140km off the Brazillian coast under water depths of 80 to 2,400 m. The first reservoir discoveries in shallow waters comprised fractured basalts, coquinas and calcarenites/calcirudites. Siliciclastic turbidites contain some reserves in shallow waters, but the reserves with the greater importance lie in the deep and ultra-deep water oilfields reservoirs. Currently, the Campos Basin production from those fields is about 1,200,000 bpd (190,779 m3/d). The fields have been developed using 32 production systems (14 Fixed Platforms, 18 Floating Production Platforms). Some of these are giant fields, and are located in deep water environment: Roncador, Albacora, East Albacora and Marlim complex. Marlim complex further comprises 3 deepwater giant oil fields - Marlim, Marlim Sul and Marlim Leste. Besides the geographic location, these fields have other similarities: the main reservoirs are turbidities 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(2).

Water injection has been used to support pressure and maximize oil recovery in some of the fields. Therefore, the reservoir recovery method is seawater injection, mainly into the oil leg in most of the giant fields.

Since the original formation water in each reservoir has different composition, good planning is necessary to deal with a large volume of produced water - a mixture of injection and formation water. Scale formation may occur as a consequence of the incompatibility between the Barium and Strontium ions in formation water and the high concentration of sulfate ions in the injected seawater.

In this deep water scenario, it is important to perform a scale risk analysis in the project phase of the field, since the selected techniques to avoid scale formation can impact the economics of the project.

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