Jubarte field production enhanced with wellbore ESP
1,200-hp subsea system installed
Marcos Pellegrini, Giovanni Colodette - Petrobras
Ignácio Martinez, Leandro Neves - Baker Hughes Centrilift
Through technological advances in ultra deepwater production, the highest horsepower-equipped electric submersible pump (ESP) to date was installed in the 1,400-m (4,593-ft) JUB-6 subsea well in the Jubarte field, offshore Brazil. The system is composed of a 1,200 hp motor and a pump capable of producing over 22,000 b/d of heavy oil (17º API). High flow rates and a longer subsea step-out were the drivers for selecting an ESP system as the artificial lift method for the project. Reliability is one of the main concerns of ESPs, and proper selection of the system for the application was critical for the run life of the equipment.
Operators and service companies are always searching for most cost-effective methods to produce deepwater reserves over the life of the field. Gas lift traditionally has been the preferred artificial lift method in offshore Brazil subsea applications with relatively short step-outs. But when high-flow production of heavy and viscous oil in a long step-out is needed, gas lift is not efficient. Electrical submersible pumping systems are the best option.
Jubarte field
The Jubarte field, in the northern part of the Campos basin, about 80 km (49.7 mi) offshore from the state of Espírito Santo, was discovered in January 2001. An extended well test was performed to evaluate drilling, completion, artificial lift technology, and to verify reserves. Then, Petrobras started Phase 1 production with FPSO P-34. Four wells were planned to produce around 60,000 b/d of oil. Two of the wells are produced using gas lift, the third one is an ESP installation on the seabed, and the fourth is a subsea ESP wellbore installation.
Well description
The subsea ESP well has a 7-in. (17.8-cm) production column (26 lb/ft, inside diameter (ID) 6.276-in.). The string is carbon steel except for the downhole safety valves (9% Cr), and the pup joint, crossover, and adjustable union above the safety valve (13% Cr). Long horizontal lengths, around 1,000 m (3,280 ft), were drilled to achieve a high productivity index. An open hole gravel pack (OHGP) was used for sand control.
Gas lift mandrels attach to the tubing string and provide back up artificial lift for the well. If the ESP fails, the gas lift will produce the well until the ESP is replaced.
The well is composed of a 13 5/8-in. (34.6-cm) casing that goes up to around 2,480 m (8,136 ft). The kickoff point (KOP) of the well is around 2,175 m (7,136 ft) from the surface. The ESP was installed at 0° from vertical and is encapsulated in a 10 3/4-in. (27.3-cm) flush joint. A 9 5/8-in. (24.4-cm) liner goes from 2,480 m (8,136 ft) up to 3,130 m (10,269 ft). At this point, the well is in the reservoir. The reservoir, drilled with an 8 1/2-in. (21.6-cm) hole in a 1,000-m (3,280-ft) horizontal section, was completed with a 7-in. (17.8-cm) gravel pack.
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Volume 68 Issue 7
July 2008
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