Summary
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.
Introduction
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.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
10 December 2004
- Meeting paper published:
2 February 2005
- Manuscript approved:
5 March 2006
- Version of record:
20 November 2006
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