• Challenges exist in identifying the inventory of DUC wells.
  • Operators are still completing more wells solo rather than as batch completions.
  • Per-stage pricing in well stimulation is moving incrementally higher.

If it looks like a DUC, walks like a DUC and quacks like a DUC, is it still a drilled but uncompleted well?

Drilled but uncompleted (DUC) wells have been the talk of the industry since 2015. Everyone knows DUC wells are out there; certainly E&P companies tell us so. But few can tell us how many DUC wells exist industrywide. There are DUC wells, and there are abnormal DUC wells—and those numbers differ. The first is the inventory of wells that are a normal part of the drilling and completion cycle. A single rig generates enough new wells to keep two completion crews busy so there is a natural delay in well completion.

Abnormal DUC wells occur over and above the natural drilling and completion cycle. With pad drilling, all wells are drilled before the rig moves off and the completion crew moves in. Crews complete wells at the rate of six to seven stages per 24 hours on plug-and-perf operations and can spend 30 days on a fourwell pad, which means the normal course of completion can exceed 90 days between the first well drilled and the final well completed. That’s when the clock starts on abnormal DUC wells.

Evidence for the general state of confusion for DUC wells is found in the variety of estimates extant. Numbers range from 2,300 (abnormal DUC wells) to 8,400 (all DUC wells). For perspective, the land drilling industry in the Lower 48 generated about 7,000 horizontal laterals over the one-year period ending Sept. 30. Depending on which number one accepts, the estimated DUC backlog implies an inventory that ranges from four to 14 months of backlog in completion activity.

In September the U.S. Energy Information Administration (EIA) debuted its own DUC estimate as a companion to its Drilling Productivity Index. The EIA estimates there are 5,000 total DUC wells. The good news is the inventory is falling. The bad news is the inventory represents a 10-month DUC supply over and above current drilling and completion levels.

The industry might be batch-drilling wells on pads as a standard operating procedure, and the number of wells per pad might be rising, but the pace of batch completions is not following suit. Reports from oilfield service providers as part of Hart Energy’s Heard in the Field survey program indicate zipper fracture share varies by region. Zipper fracture share is higher in Appalachia, for example, but lower in hard-hit oily markets like the Eagle Ford or Bakken shales.

Zipper fractures serve as a proxy for batch completions. A share lower than 50% implies rising DUC inventory. For the first three quarters in 2016, a composite share of zipper fractures nationwide has been stalled at 45%. Individual regional reports indicate the DUC inventory follows the ebb and flow of commodity price, with operators getting more active on completing DUC wells as oil approaches $50 and losing momentum when oil drops below $45.

The good news is that zipper fractures provide a 10% to 15% reduction in cycle time for horizontal completions, and that might hasten the rate at which the industry works through the backlog, assuming commodity prices cooperate.

A combination of crowd-sourced information and estimates from the EIA’s DUC report suggests there are about 100 well stimulation crews working nationwide. A definitive number remains a challenge since crews and equipment are working interchangeably across regions. EIA data indicate crew count in the major tight formation plays peaked at 285 in late 2014.

There has been gradual incremental increase in well stimulation pricing, partly because service providers are no longer pursuing predatory discounting. Additionally, some bulk materials such as 100 mesh sand are in tight supply in areas like the Permian Basin, supporting a modest increase in per-stage pricing. It indicates recovery is closer.

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