Summary
The Jubarte field, in the Campos Basin, Brazil, was discovered in January
2001. It is located approximately 80 km offshore from the State of Espírito
Santo, under water depths between 1,000 and 1,500 m, containing oil of 17°API
and viscosity of 14 cp at reservoir conditions.
This work presents a review of the artificial lift and flow assurance
aspects faced by PETROBRAS in the exploitation of Jubarte heavy oil, starting
from the features of the pilot phase. It details all the challenges posed and
innovations proposed and implemented for Phase 1 field development, as well as
expectations for the subsequent Phase 2.
Previous ESP Experiences and Applications
At the end of 1992, PETROBRAS discovered significant reserves of oil in deep
waters, in the Campos Basin, Rio de Janeiro. From these discoveries of new
research programs for developing new deepwater installation technology,
floating production unit systems had been considered for directly receiving
subsea satellite well and manifold production (Ribeiro et al. 2005).
The efficiency of an ESP system is not adversely affected by distance from
the well to the host platform, as is the case with other forms of artificial
lift. Tests have determined the feasibility of ESPs in subsea wells as far away
from the host platform as 20 km or greater. ESPs are highly efficient and
evolving ESP technology is enabling distant located wells to be tied back to a
host platform, making marginal and distant fields economic to exploit (Anderson
et al. 2001).
At that time it was concluded that the best production system alternative
for the RJS-221, the first subsea well installation of the world, was through
an ESP pump whose rotation of the electrical motor could be controlled by a
frequency variation driver (VSD). The RJS-221 ESP prototype system installation
approval came together with the signature of a Technological Cooperation
Agreement with six companies (Reda, Lasalle, Tronic, Pirelli, Cameron, and
Sade-Vigesa) in March of 1994. In October of 1994, an ESP operated for the
first time in a subsea well. This ESP, installed 1900 m below the sea soil in
the RJS-221 well, was controlled from the fixed Carapeba 1 platform, which was
located 500 m from the well. The oil was pumped through 15 kilometers of lines
from downhole to the Pargo platform, 13.5 km from the Carapeba 1 platform,
where it was joined with the oil lifted through the ESP method from other
platforms. The oil was flowing through the Carapeba 1 platform, acted as a
manifold, because no transference pumps were available in this platform
(Ribeiro et al. 2005).
A production level analysis comparing the gas-lift and the ESP method costs
over a 10-year period found non-failed operation for the gas-lift method over a
5-year period, and 2 years without failure for the ESP method. That analysis
demonstrated feasibility for the ESP method, especially for the Albacora field,
and that it was not only important to increase the non-failure operation time,
but also to reduce the intervention costs of the ESP system. This led to the
development of a new horizontal wet Xmas tree for the ESP installation of the
RJS-477 well (Mendonça 1997).
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
5 February 2007
- Meeting paper published:
30 April 2007
- Revised manuscript received:
24 October 2007
- Manuscript approved:
30 October 2007
- Version of record:
15 March 2008
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