Use of Nitrate to Mitigate Reservoir Souring in Bonga Deepwater Development Offshore Nigeria
- Cor Kuijvenhoven (Shell) | Jean-Christophe Noirot (Shell Nigeria E&P Co. Ltd.) | Andrew M. Bostock (Dana Petroleum PLC) | Dave Chappell (Shell International Exploration & Production) | Arfan Khan (Shell Nigeria E&P Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2006
- Document Type
- Journal Paper
- 467 - 474
- 2006. Society of Petroleum Engineers
- 5.5 Reservoir Simulation, 4.6 Natural Gas, 5.4.10 Microbial Methods, 5.4.1 Waterflooding, 4.5 Offshore Facilities and Subsea Systems, 1.1 Well Planning, 4.1.9 Heavy Oil Upgrading, 6.5.2 Water use, produced water discharge and disposal, 3 Production and Well Operations, 1.6 Drilling Operations, 4.1.2 Separation and Treating, 5.6.9 Production Forecasting, 5.2 Reservoir Fluid Dynamics, 1.2.3 Rock properties, 4.2.3 Materials and Corrosion, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.5.3 Floating Production Systems, 2.4.3 Sand/Solids Control, 4.2 Pipelines, Flowlines and Risers, 5.1.1 Exploration, Development, Structural Geology
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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 H2S 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 capital-expenditure (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 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 resulting from biogenic reservoir souring in the Bonga field and the work done to predict H2S levels. The paper focuses on the selection of nitrate as a mitigation method.
The Bonga field (Fig. 1) lies on the continental slope in the southern part of the Niger Delta, some 120 km offshore, southwest of Warri, in Nigeria, with water depths ranging from 950 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 more than half of the recoverable reserves, comprises 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 to 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 16 wells (nine oil producers and seven water injectors) were drilled during the Bonga Phase 1 drilling campaign. All fluids produced were processed on a floating production, storage, and offloading (FPSO) facility situated centrally in the field, and oil was loaded directly to tankers (Fig. 2). The associated gas was exported through pipelines. Water was processed to appropriate standards and disposed of overboard.
Since the beginning of the project, reservoir souring has been identified as an area of concern in Bonga. Reservoir (e.g., mineralogy, temperature, pH, and pressure) and fluid characteristics (e.g., composition) were recognized to be favorable to sulfate-reducing-bacteria (SRB) activity. With more samples collected and analyzed, the reservoir-souring potential has been recently re-evaluated and mitigation techniques have been upgraded on the basis of new technology developments. This paper presents the work conducted to determine the souring potential of the field, with most of the focus on the 702 reservoir, and will introduce the revised mitigation techniques being implemented.
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