SAN ANTONIO—Reducing costs is the main driver for the transition from mechanical to all-electric well stimulation fleets, according to Matthew Wilhoit, vice president and global head of Siemens’ unconventional oil and gas business.
“If you look at some of the biggest issues we are seeing right now, it’s around footprint of the site. It’s the power delivered at the site and emissions, fuel costs, etc. All of it focuses on improving completions costs, bringing production on sooner and more wells per year,” Wilhoit said during Hart Energy’s DUG Eagle Ford Conference & Exhibition in San Antonio.
An all-electric fleet replaces a diesel engine, transmission and pump with an electric motor.
“Now you have a drivetrain that needs maybe a couple $100 worth of maintenance per year versus the traditional diesel in the traditional mechanical drivetrain,” Wilhoit said. “So right there you have maybe a one-to-one cost exchange, but the savings on the maintenance is huge.”
Another driver is fuel cost.
With “The switch between diesel and natural gas, and in some cases if you can run off wellhead gas, you’re saving almost 90% in fuel,” Wilhoit said. “So that’s a game changer for these companies and as we look at who benefits there are the operators, the field service companies. It really depends on how you’re contracting. But there is enough savings there for everyone to save.”
An electric fleet also is safer, has fewer emissions and is quieter.
“In many cases you are operating in neighborhoods. You could go out to a site and have 20 diesel engines running and it’s quite loud,” Wilhoit said. “You could put up to five small gas turbines and we can have a conversation like this, and they are whisper quiet.”
In fact, lights are placed on the gas turbines to show they are operating. This also reduces the need to put up embankments and walls.
But, according to Wilhoit, the biggest obstacle to overcome for an all-electric fleet is understanding how the system works, how to design it and the costs associated with the fleet. He mentioned other concerns include the cost of gas turbines and the power to run the fleet.
Also on the panel, Sean Fitzgerald, a partner for Boomtown Oil, shared insights on Eagle Ford operations, specifically NPVs (net present value) versus EURs.
“Our philosophy is, certainly, you’re always trying to maximize NPV,” he said. “You have to look at it from a long-term perspective—not just one single well.”
Fitzgerald said too often he sees operators in the Eagle Ford or other plays come out and do what has been done before to make money instead of looking for new ways. The biggest step change for Boomtown was longer laterals and more proppant.
“We just finished three wells,” Fitzgerald said. “They are all over 7,500-ft lateral length.”
The company also increased the amount of proppant per foot from 1,100 pounds (lb) to 3,500 lb of sand for each wellbore, pumping at a rate of 80 to 90 barrels per minute, he added.
This, he said, is what generates the best EUR and making that step change to more proppant.
“As long as you are staying up to date with technology you’re always going to get a great NPV, and EUR is driving that NPV,” Fitzgerald added. “You really want to maximize that…and that’s how you’re going to get the best result.”
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