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).
