Electrical submersible pumps are a cost-effective way of improving flow rate in mature oil fields. Statoil’s Halvard Bjørkesett explains how new developments in this technology look set to improve the economic viability of deep-sea wells.
With many formerly abundant oilfields approaching maturity, the industry has a challenge on its hands. Oil companies, attempting to recover hydrocarbons from ever-deeper wells, are faced with the twin obstacles of dwindling reserves and soaring costs. The big question is whether technological innovation can keep pace with demand, ensuring the continued profitability of reservoirs as the more accessible oil is depleted.
The Gulf of Mexico is a case in point. Dotted with rigs along its eastern and central perimeter, this deepwater basin is believed to contain more untapped reserves than anywhere else on the planet. The industry has invested heavily in the region; there are around 50,000 wells here, of which the most recently installed are thousands of feet deep. It has been suggested that, when it comes to US domestic production, deep-sea drilling in such areas represents the best hope for the future.
Of course, ambitious engineering requires ambitious equipment, and the race is on to develop reliable and effective pumps. Far below the ocean surface, both the temperature and the pressure are high. Any apparatus that can function at such depths needs to be powerful and remarkably robust, as well as cost-efficient to install.
With several projects underway in the Gulf of Mexico, Statoil is currently working with its vendors to introduce electrical submersible pumps (ESPs) to its rigs. A forceful means of artificial lift, ESPs have been around for many decades, but until recently were prohibitively expensive. Only over the past few years have they developed a reputation as a cost-effective alternative to vertical turbine and positive displacement pumps.
Halvard Bjørkesett, lead advisor of well technology at Statoil, is clear about the economic impetus: “In the Gulf of Mexico, typical intervention costs for changing the pump with today’s technology can be around $50 million. We want to be able to perform this operation at a cost of less than half that, say $15-20 million. The pumps should last longer before we have to change them, and the way we go about it will be more efficient, more robust and less costly. Those are our main drivers.”
An ESP is a centrifugal pump, operating in a vertical or deviated position. It consists of a downhole pump, a protector, an electrical motor and an electric power cable, along with a variety of other components. It is fully submerged in fluid, and works by spinning its impellers on the shaft.
The pressure at the bottom of the well is reduced, creating an additional drawdown and boosting production by forcing the fluids under high pressure to the surface. In many cases, this pump does more than just improve flow rate – it may well be the only way that any oil can be recovered.
“If you need a lift option, you have to look at the reservoir conditions and what is available on the platform,” says Bjørkesett. “Alternative methods can be considered, but the deepwater wells in the Gulf of Mexico will require downhole ESPs.”
The hallmark of these pumps is their versatility and ability to boost production. The technology has been used for purposes as diverse as slurry pumping and aquarium filters, and in the case of multiple-stage pumps, is ideally suited to recovering hydrocarbons. These pumps function well in harsh downhole conditions, and are unfazed by corrosive contaminants, heavy oil and elevated temperatures. Statoil established its ESP team in 2009. Along with its main vendors the company undertook studies with the aim of improving the technology. Keenly aware of the need for more resilient equipment, it plans on installing technologically enhanced ESPs in the Gulf of Mexico by 2016.
“We have steps in place, starting from next year, in which we will try out this new technology,” says Bjørkesett. “We will begin with the easier wells and then move on towards our final goal. We also have potential wells in other places, like the North Sea, that might need this kind of innovation in the future.”
New and improved
Although ESPs are not in themselves new, these developments represent a significant upgrade. “Everything is based on existing technologies,” says Bjørkesett. “It is a question of making the equipment more robust, and ensuring it lasts longer before it breaks down. We also want to develop new techniques to make interventions less costly.”
The pumps’ high costs, when used in offshore applications, were related to their relatively short lifespans, and high installation and intervention costs. The improved ESP systems will be operated and maintained along the same lines as they are today. Although new methods will be required to run the equipment, the pumps will not take much looking after while in the rig itself. “When there’s a failure in a pump,” says Bjørkesett, “it will be shipped back to base and the analysis will be done there.”
The full impact of this new development remains to be seen, but one thing is clear – the new enhanced ESPs bode well for the future. Many ultra-deepwater fields are, in essence, marginal – it is imperative that oil companies find cost-effective ways to boost the production stream. This technology ought to result in a significant improvement in flow rate.
With around 100,000 systems in operation globally, ESPs are already the fastest-growing oil lifting system across the world, and the pumps look set to become still more prevalent. As their defects are ironed out and their run-times extended, they will surely be incorporated into ever more challenging applications, opening up possibilities previously unimaginable to the industry.
This article appears in the latest issue of World Expro