When Baker Hughes introduced its CENtigrade electrical submersible pumping (ESP) production system, the technology was designed to reduce equipment downtime and improve reliability issues. Left unaddressed, these issues can reduce the amount of oil recovered by operators and can increase operating expenses.

The system has proven very effective in steam-assisted gravity drainage (SAGD) wells in extreme conditions that require an ESP system. “We have seen a considerable adoption of the system globally, but the main region that has adopted our technology has been Canada for SAGD applications,” said Carlos Alberto Montilla, Artificial Lift Systems Heavy Oil and Geothermal Segment Manager at Baker Hughes.

Baker Hughes Centrilift CENtigrade Ultra Temperature (UT) ESP system won the production technology category of Hart Energy’s 2012 Meritorious Awards for Engineering Innovation.

As the first UT ESP system for SAGD wells, the technology can reliably operate at higher temperatures compared to conventional ESP systems and features an enhanced electrical insulation system. “One of the things that we’ve seen across a lot of the thermal recovery operations is that downhole temperatures tend to increase over time,” Montilla said. “Obviously, that has an impact on the overall reliability of the equipment.”

Additionally, the system can operate in applications with fluid temperatures up to 250 C (482 F), according to a Baker Hughes product release. Applications include thermal recovery producing wells; low flow wells where fluid velocity is insufficient to cool the motor; harsh wells with gas, sand or scale; and SAGD.

The technology remains viable and has not been eclipsed by newer applications. “What I have perceived is that operators are getting more comfortable with the technology as it and the industry have evolved,” he added. “We definitely see a lot more use than we used to see a few years back.”

The company constantly works on improving the system. “Due to the harsh conditions that are typical for this type of application, the internal components of the system have to be upgraded electrically, mechanically and chemically,” Montilla said. “That way it is a more robust system that is fit for purpose in this type of harsh application.”

In recent years, operators have introduced the concept of infill wells to the SAGD process. In SAGD pairs, a steam injection well is typically positioned above the producing well. On well pads with several SAGD pairs, a smaller-diameter infill well is positioned between the SAGD pairs. “The overall objective of this is to drill a less costly, smaller-diameter well while still getting the advantage of the nearby steam injection at a lower cost. Then the operator will try to recover as much as possible from that reservoir,” Montilla said.

To meet the needs of operators, Baker Hughes is in the process of releasing its system-compatible technology for infill wells. “The benefit of the system for infill wells is that it will allow operators to artificially lift oil from the infill wells that they drill,” he said.

In July, the company also introduced a newer version of its CENtigrade ESP motor, which is rated to a bottomhole temperature of 275 C (527 F). “Basically, what that means is it can potentially improve the reliability of SAGD operations,” Montilla said.

The company foresees the continued growth of the system to meet the needs of operators. “Considering that a high percentage of the recoverable reserves in the world are heavy oil, we expect to see an increased uptake in the market on thermal recovery processes and technology improvement for this particular area,” Montilla said.

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