This paper describes field experience and lessons learned from scale control
operations in a deepwater subsea development in the Campos Basin, Brazil;
specifically, from bullheading scale-inhibitor squeezes from the FPSO host,
along the production flowlines, into four low-watercut, horizontal subsea
wells, completed with sand control.
The relatively small number of high-cost, highly productive wells, coupled
with a very high barium-sulfate scaling tendency upon breakthrough of injection
water, meant that not only was effective scale management critical to achieve
high hydrocarbon recovery, but even wells at low water cuts were deemed to be
at sufficient risk to require squeeze application.
Use of conventional, water based squeezes have been known to cause
significant damage to productivity in low-watercut wells, including those
showing a fines-migration tendency, as was the case here. Hence, on the basis
of risk mitigation, supported by an extensive program of laboratory testing, it
was decided that for the initial treatments, only the mainflush would be water
based, with a mutual-solvent preflush and marine-diesel overflush.
Other key challenges associated with treating from the host included the
remote location of the wells, the potential to form hydrates, the cleanliness
of the lines along which the treatment would pass, the achievement of effective
placement over a long producing interval, as well as the need to deploy the
chemical package via a support vessel adjacent to the FPSO. All had to be
managed because of the high cost and low availability of a deepwater rig that
could deploy the treatments directly to the subsea wellheads.
This paper will explore in detail the issues associated with
inhibitor-squeeze deployment in deepwater, subsea fields, many of which are
currently being developed in the Campos basin, Gulf of Mexico, and West Africa,
and are a good example of best-practice sharing from another oil basin.
Fields Description. The fields are located 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 pre-packed
screens, located centrally in the reservoir and four deviated water injectors
at the flanks. The six production wells are located on two production manifolds
and the four injection wells on a single injection manifold.
Field Y is 5 km to the 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.
Both fields produce to the same FPSO, which has a production capacity of
81,000 BOPD and a storage capacity of 1.2 million barrels of oil. A third party
operates the FPSO.
The field came on stream in August 2003. Initial average production was some
60 kbpd but this dropped to 50 kbpd by early 2005 because of early breakthrough
of injection water and well impairment.
The reservoir temperature is approximately 90°C. Scale formation has been a
production issue in these fields as they are supported by injection of
seawater, which is incompatible with the formation brines that contain up to
180 mg/l barium and up to 300 mg/l strontium ions. Wells with seawater
breakthrough are scale squeezed using 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
Table 1 shows the typical formation brine chemistry for both fields.
Injection-quality seawater has been used to maintain reservoir pressure and
improved fluid sweep within most of the reservoir units over the life of the
field. Figs. 1 and 2 show the maximum predicted mass of sulfate scales
associated with injection-water breakthrough under reservoir conditions as a
function of the fraction of seawater in the produced water; Figs. 3 and 4 show
the corresponding supersaturation values. There is no calcium sulfate tendency
for any mixing ratio.
It is clear that barium sulfate is the most significant predicted scale type
present in terms of both mass of scale and supersaturation. Observation of
scale samples recovered from the field supports these predictions with barium
sulfate being more prevalent than either strontium sulfate or calcium carbonate
in the suspended particulates observed in produced water and in scale samples
recovered from wells. Significant amounts of calcium carbonate particulates
have only been observed from one well in Field Y.
© 2007. Society of Petroleum Engineers
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- Original manuscript received:
26 June 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
15 January 2007
- Manuscript approved:
25 April 2007
- Version of record:
20 November 2007