This paper describes field experience and lessons learned from
bullhead-deployed scale-control operations in a deepwater subsea development in
the Campos basin, Brazil; specifically, this paper is about deploying such
treatments from the floating production, storage, and offloading (FPSO) host,
along the production flowlines, and into four low-water-cut, horizontal, subsea
wells completed with sand control.
The relatively small number of high-cost, highly productive wells, coupled
with a very high barium sulfate (BaSO4) scaling tendency upon
breakthrough of injection water, meant that not only was effective downhole
scale management critical to achieve high hydrocarbon recovery, but that even
wells at low water cuts were deemed to be at sufficient risk to require squeeze
Initial bullheaded scale treatments comprised three "hybrid"
treatments: a mutual-solvent preflush, a water-based main flush, and a diesel
overflush. As water-production rates rose, so did the treatment volumes
required. To improve the logistics of these treatments and to mitigate issues
that arise from poor injectivity of diesel in these wells, core studies were
conducted to investigate the option of changing the overflush fluid from marine
diesel to injection-quality seawater. This change also introduced the
possibility of forming a gas-hydrate plug during shut-in, but this was managed
by use of a thermodynamic hydrate inhibitor and by replacing the flowline
contents to flashed crude during the shut-in period. Both the operational
aspects and the response of the wells to the modified treatments will be
compared with those previously deployed in terms of, in particular, the
injectivity of the wells during treatment and well-treatment cleanup rates and
The core studies also highlighted a formation-damage mechanism caused by
incompatibility between the mutual solvent and the produced oil; this required
modification of the treatment.
The fields are in the Campos basin offshore Brazil, approximately 145 km
east of Macae, on the present-day continental slope, in water depths ranging
from 700 to 850 m.
Development of Field X comprises six horizontal producers, gravel-packed
with prepacked screens and located centrally in the reservoir, and four
deviated water injectors at the flanks. The six production wells are on two
production manifolds, and the four injection wells are on a single injection
Field Y is 5 km northwest of Field X and was developed in a similar manner,
with two horizontal producers completed as in Field X producing to one manifold
and two deviated water injectors tied back to another manifold.
Both fields produce to the same FPSO host, which has a production capacity
of approximately 80,000 BOPD and a storage capacity of 1.2 million BO.
The field came on stream in August 2003. Initial average production was
60,000 B/D, but this dropped to 50,000 B/D by early 2005 because of early
breakthrough of injection water and because of well impairment.
The reservoir temperature is approximately 90°C. Scale formation has been a
production issue in these fields because they are supported by injection of
seawater, which is incompatible with the formation brines that contain up to
180 mg/L of barium and up to 300 mg/L of strontium ions (Table 1). The
sulfate-scaling tendencies of the produced water are presented in Figs. 1
through 4 (Bogaert et al. 2007). Wells with seawater breakthrough are scale
squeezed with a phosphate ester scale inhibitor to control sulfate-and
carbonate-scale formation within the wells and flowlines; additional inhibitor
is injected to the produced fluids once they reach the topside facilities.
© 2008. Society of Petroleum Engineers
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- Original manuscript received:
7 March 2007
- Meeting paper published:
30 May 2007
- Revised manuscript received:
31 December 2007
- Manuscript approved:
8 January 2008
- Version of record:
15 November 2008