The Bonga field located in deep water off the Nigerian coast needs pressure support to effectively recover the hydrocarbons. The strategy is to inject 300k bwpd seawater from the start of oil production. During the field development in 1999 it was concluded that Bonga was expected to suffer from reservoir souring, and that mitigation would be necessary. Initial data gathering indicated that the expected H2S content resulting from reservoir souring was not expected to exceed 50 ppm(v) in the gas phase. Initially nano-filtration to reduce the sulphate level in the seawater was identified to mitigate reservoir souring but due to the high CAPEX costs it was dropped and as there were no other proven mitigation techniques available, it was decided to operate without mitigation. The strategy for this project was to let the reservoir sour and handle the H2S with sour service materials and scavenging facilities topside. The facilities were designed to handle a maximum level of 50 ppm(v) H2S. As detailed design progressed and more field data became available, doubts were raised on the suitability of this approach. The strategy to let the reservoir sour and handle the H2S at surface was re-evaluated in 2003. It was found that H2S levels are likely to exceed 50 ppm(v). Since then a new strategy with mitigation was adopted. Several operators had verified that nitrate injection is an effective mitigation technique to control H2S development. However, to date the main application for nitrate had been the reduction of H2S in already sour fields and the experience for the use of nitrate from the start of the water injection scheme was limited. This paper presents a detailed evaluation of the potential for reservoir souring due to biogenic reservoir souring in the Bonga field, and work done to predict H2S levels. The paper will also focus on the selection of nitrate as a mitigation method. Introduction The Bonga field (Figure 1) lies on the continental slope in the southern part of the Niger Delta some 120 km offshore, South West of Warri in Nigeria with water depths ranging from 950 m to 1500 m. The reservoirs are Lower Upper Miocene in age, and are interpreted as stratigraphically / structurally trapped mud rich unconfined turbidite systems in a mid-lower slope setting. The reservoirs are composed of fine-grained amalgamated channel sands derived from the shelf margin to the northeast. The main 702 reservoir, which is expected to deliver over half of the recoverable reserves, is comprised of amalgamated turbidite channels. The other reservoirs are stacked either above (690) or below (710/740, 803), and are generally less well amalgamated. Net reservoir thickness is generally less than 100 ft. Measured sand porosities range from 20–37% and are generally associated with high (multi-Darcy) permeabilities. Seawater injection for pressure maintenance and sweep is key to the success of the Bonga development. A total of sixteen wells (nine oil producers and seven water injectors) were drilled during the Bonga Phase 1 drilling campaign. All fluids produced will be processed on an FPSO situated centrally in the field and oil is directly loaded to tankers (Figure 2). The associated gas will be exported through pipelines. Water will be processed to appropriate standards and disposed of overboard.
The Bonga field, located in deep water off the Nigerian coast, needs pressure support to effectively recover hydrocarbons. The strategy is to inject 300,000 BWPD of seawater from the start of oil production. During the field development in 1999, it was concluded that Bonga was expected to suffer from reservoir souring and that mitigation would be necessary.Initial data gathering indicated that the H 2 S content resulting from reservoir souring was not expected to exceed 50 parts per million(volume-based) [ppm(v)] in the gas phase. Initially nanofiltration to reduce the sulfate level in the seawater was identified to mitigate reservoir souring, but because of the high capitalexpenditure (CAPEX) costs, it was dropped and, because there were no other proven mitigation techniques available, it was decided to operate without mitigation. The strategy for this project was to let the reservoir sour and handle the H 2 S with sour-service materials and scavenging facilities topside. The facilities were designed to handle a maximum level of 50-ppm(v) H 2 S.As detailed design progressed and more field data became available, doubts were raised on the suitability of this approach. The strategy to let the reservoir sour and handle the H 2 S at surface was re-evaluated in 2003. It was found that H 2 S levels are likely to exceed 50 ppm(v). Since then, a new strategy with mitigation was adopted. Several operators had verified that nitrate injection is an effective mitigation technique to control H 2 S development. However, to date, the main application for nitrate had been the reduction of H 2 S in already-sour fields, and the experience for the use of nitrate from the start of the water-injection scheme was limited.This paper presents a detailed evaluation of the potential for reservoir souring resulting from biogenic reservoir souring in the Bonga field and the work done to predict H 2 S levels. The paper focuses on the selection of nitrate as a mitigation method. Reservoir-Souring Potential in BongaThere is uncertainty about the expected severity of reservoir souring in Bonga because there is no detailed information available for the produced-water composition from the main reservoir to be
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