With electrical submersible pump (ESP) systems failing more often than operators liked in unconventional wells, much research and development has aimed to make ESPs that last longer. That requires addressing the basic fact that the pumps are deployed in conditions that are constantly evolving.
“Unconventional wells are dynamic. They change. They can change daily,” as Nathan Holland, product line director for artificial lift at Baker Hughes, puts it.
Challenges range from installing ESPs in highly deviated wells without damaging them, to dealing with a steep production decline, to coping with gas slugs and the changing production mix that might call for several different ESP systems over the course of a year for a single well.
“We wanted to provide a solution that is a well lifecycle solution,” Holland says. “As we’ve gained experience in this well environment — declining production, more gassy, deviated wells — we’ve learned there are some important things you have to do.”
One focus was on simply ensuring the ESP system was installed without being damaged.
“First off, you need to protect the equipment, and protect it when you’re installing it.”
The solution was to shroud the ESP system within casing so it wouldn’t be damaged on installation in wells with a tight bend radius in the curve section of the wellbore. The shroud — a solution previously used for motor cooling — provides a buffer between the ESP system and the actual well casing.
“If you’re going into a well, a deviated well, and you rub against the casing, now that shroud takes that force instead of the ESP system. We virtually eliminated ESP damage when going into the well,” Holland says.
For a 7-inch cased well, Baker Hughes runs its 400 series ESP equipment, which has a 4-inch outer diameter (OD), inside a 5 1/2-inch shroud. For a 5 1/2-inch cased well, the company runs its 300 series ESP equipment, which has a 3.75-inch OD, inside a 4 1/2-inch shroud.
Operators favour wells with smaller casing sizes for drilling efficiencies and well stability. “We’re monitoring casing sizes,” Holland says. “If well constructions continue to get smaller, we will need to adapt this technology to fit in there.”
Once the ESP system is in the well, it must stand up to gas slugs and a changing production stream.
“Once the well gets to a certain bottom hole pressure, there seems to be more gas than what we saw originally,” he explains. “In the lateral section, there are undulations. As you de-liquefy that reservoir, more gas is released and it builds up on the high side of the undulations.”
The resulting gas slug breaks free and moves up the wellbore, displacing the fluid stream and interrupting production.
“That’s a different environment than an ESP has had to deal with before,” Holland says. “That’s not the ideal environment for an ESP.”
The first step in addressing the gas slugs was to look at how the intake of the system was oriented.
“As you make the curve into the lateral, the liquid in gas can get violent. It’s disruptive. It’s foamy. It’s hard to produce,” he says. “We developed gas-mitigation equipment designed to sit in the deviated or horizontal section of the wellbore. This Gas Avoider pump intake uses gravity cup technology to orient the intake of the tool. This effectively closes off the intake on the high side of the tool, directing gas up the casing while the fluid continues to flow on the low side of the tool and into the pump.”
Protective cover
That worked for a while, he says, but ultimately Baker Hughes decided to change the environment of the ESP by fully encapsulating it.
“Creating an artificial well inside of the well — that is how we started to think of CENesis PHASE,” he says.
With CENesis PHASE, the gas slug doesn’t interrupt production because the slugs are lighter than oil and water and continue up the wellbore while the fluid flows into the shroud to create a reservoir of fluid for the ESP. The gas slug never enters the ESP.
“You create a mini-reservoir in the casing system, producing the liquids that were trapped inside the shroud system” while the gas slug bypasses the ESP system, he says.
The shroud can vary in length. The service company studies field and analog well data to extrapolate how long the slugs usually are and then designs a shrouding system long enough to protect the ESP system.
As the ESP works to handle the liquid in the shroud reservoir, heat generates, and the motor needs to be cooled. A recirculation system comprising a series of capillary lines routes past the motor to cool it.
Baker Hughes monitors and remotely controls the ESPs with its AMBIT service. MaxRate software, used with the Electrospeed Advantage variable speed drives in the company’s ESPs, mitigates production interference due to high gas content by automatically purging accumulated gas and controlling the draw down rate.
Holland says Baker Hughes has used solids mitigation tools like desanders and sand guards to ensure CENesis PHASE “doesn’t become a sand collection point.”
Case history
To date, Baker Hughes has deployed CENesis PHASE in over 1000 wells around the United States, and Holland says the technology is applicable anywhere prone to gas slugging.
The first installed system ran for more than three years. It replaced a system in which the mean time between failures was less than one year.
A well in Oklahoma that has 7 1/2-inch casing had been on gas lift for a long time, but the operator was unable to draw the well down to the desired bottom hole pressure. When other wells in the field were brought to that desired bottom hole pressure, gas slugging ensued. The well was “an ideal candidate” for the technology, Holland says.
Production records showed that bigger and longer slugs would appear at the target bottom hole pressure. With the deployment of CENesis PHASE the operator was able to decrease the bottom hole pressure from 683 psi to 150 psi. Oil production increased by 19% and gas increased by 43%, and the ESP run life increased by 73%.
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