The Gimboa Field, which came on stream from April 2009, has produced different reservoir fluids compared with the fluid initialization model developed before production. The early exploration well only discovered highly biodegraded heavy oils (low API) in the field. Although some normal black oils (high API) were initialized in some reservoir segments based on the fluid samples taken during drilling of injection wells, the existence of large amount of non-biodegraded black oil had been underestimated before starting of production.
The EOS fluid characterization was developed with good accuracy for limited initial reservoir fluid samples. All the initial reservoir fluid samples were taken from the same geological region. This made it difficult to have a reliable estimation of fluid distributions in other reservoir regions. Different ways to initialize the reservoir fluids have significant impacts for estimation of reservoir fluid in place, the expected drawdown pressure between the water injection wells and the producing wells, water injection speed and volume, the required gas handling capacity and finally the recovery factor.
Drilling of water injectors and producers provided an opportunity to collect more reservoir fluid samples from other parts of the reservoir. Integration of available PVT, pressure gradients, and geochemistry data from the Gimboa Field provided an updated estimation of the reservoir fluids in different reservoirs. An API tracking black oil model has been selected to describe lateral fluid variation. Uncertainty is discussed as a lesson learned from this field for the later design of sampling programs for similar fields.
This paper provides an insight into the importance of fluid initialization for compositional varied reservoirs. Integration of multidiscipline data is an efficient way to reduce uncertainty in fluid initialization.
Introduction
Block 4 is located at the southern margin of the lower Congo Basin in Angola. Fig. 1 shows the location of the Block 4. The Gimboa Field is about 85 km offshore and located in deepwater. The field was discovered in 2004 and it is the major accumulation discovered to date in Block 4. Gimboa first oil was in April 2009. More detailed field information can be found in the OTC paper by Carvalho et al. in 2009. This paper will focus on PVT and fluid issues in the Gimboa Field.
The reservoirs consist of unconsolidated sands of Upper Miocene age. Three different reservoir intervals were encountered in the discovery well (Splay, Main Channel Complex and Basal Channel). The Main Channel Complex and the Basal Channel are overlying and in direct communication. These two channel systems constitute parts of the same reservoir unit. The combination of these two systems is labeled as the Lower Reservoir. The Splay system has a separate fluid and pressure system and is termed the Upper Reservoir.
Fig. 2 shows both the Upper Reservoir and Lower Reservoir, together with the well locations. The discovery well was well 4–41-1 in 2004, which penetrated both reservoirs. Eight MDT reservoir fluid samples were collected from the well. The EOS fluid characterization work conducted in 2005 was based on the fluid samples only from the discovery well. Starting from 2007, more reservoir fluid samples have been taken from drilling of injection and production wells (WIU-02 and PL02).
