Oil and gas companies tap DUC inventories to boost production at lower costs
The nation still has a lot of energy in the bank, but not as much as it did a year ago.
Data published monthly by the U.S. Energy Information Administration shows a tally of drilled, but uncompleted (DUC) wells across the Lower 48 in June stood at 7,659.
That’s less than the 8,248 drilled, uncompleted wells the agency counted the same month in 2019.
Steve Agee, an economist and dean of the Meinders School of Business at Oklahoma City University, said drilled but uncompleted wells represent a piggy bank of sorts that energy companies can draw upon during lean times to keep production totals from entering a tailspin.
While companies sometimes are required to keep drilling new wells to avoid losing leases, they often have contractual leeway that gives them time to bring wells to production, he explained.
“Drilled, uncompleted wells are like savings accounts,” Agee said. “I would expect to see numbers of those declining across the nation, given the prices that energy companies are getting for oil and gas because of reduced demand.
“Those factors combined are resulting in fewer wells getting drilled,” he continued. “To bring more production online, it would be much less expensive for a company to go to a previously drilled, uncompleted well and complete it than it would be to drill something new.”
The reduction is particularly noticeable in the Anadarko Basin, where the agency reports the number of DUC wells in June was just 710, compared with 939 a year earlier.
Significant year-over-year drops in DUC wells also were observed by the agency in the Eagle Ford Shale and Permian Basin fields.
Analysts often look at DUC numbers to evaluate industry trends.
This week, the issue was explored by Enverus, an on-demand software and data analytics company that follows the oil and gas industry.
The point of Enverus’ presentation was to discuss how proprietary data it provides its customers could help them anticipate where most likely areas for future drilling and completion activities might occur.
Its presentation also highlighted other trends the company observed that led two of its analysts to make some interesting predictions.
One was that it expects cumulative production rates from horizontal wells will fall back to 2008 levels (about 5 million barrels daily) by 2025.
The company observed today’s horizontal wells have average lateral lengths of about 8,500 feet (the longest yet) as operators spread apart coordinated projects and opt for simultaneous completions of multiple wells.
That trend moves exploration and production companies away from past trends of undertaking more tightly-spaced development efforts with sequential well completions that revealed disappointing results.
Both Sarp Ozkan, Enverus’ director of energy analysis, and Jeremy Hornell, a technical advisor with the company, said they expect at least some drilling will continue in top-tier acreages across several plays while completions of previously drilled wells also could happen in those same areas if prices improve enough.
They observed there have been some dramatic recent increases in DUC well counts in most major basins, but not the Anadarko.
Companies with presences in multiple basins have chosen to invest their money elsewhere because of more attractive rates of return, Ozkan said.
“Our primary focus here was to show you … how combining our basin studies with DUC locations provides you with insight into where we expect things to go in the short-term,” Hornell said.