The number of drilled but uncompleted wells, or DUCs, has been rising steadily for nearly two years. Are costs keeping crews at bay? Are there enough crews to begin with? PBOG asked experts to explain why the backlog of well completions has become the biggest story in well completions.
By Tony Burke
The land game, as played by exploration and production companies in the Permian, has complex rules and myriad variations. Market conditions on a given day could push one company toward a lease, and another toward a purchase. Small parcels change hands as companies attempt to contiguously lump their parcels. An abnormally deep-flowing formation may be able to sustain a horizontal well at one depth and an entirely different well placed a few thousand feet deeper. Toss in the occasional oddity such as a 200-foot wide “right of way” railway easement cutting a swath through any number of different properties, and it’s easy to see how operating an E&P in a basin as hot as the Permian can get complicated, not to mention expensive.
Land is always going to be at a premium when the oil is flowing, and drilling has been on a steady rise since oil prices began their gradual recovery back in 2016. While the price of mineral rights, as well as surface rights, have regressed from the high-five-figure spike they saw last year, acreage is still commanding a strong price point.
The land game is an intricate and endlessly fascinating one, but is the price of land fluctuating to the point of impacting well completions, or drilling of any kind? Drilling activity and production are key metrics, but they are not the whole picture. Looking at the drilled but uncompleted well (DUC) count adds yet another set of factors, and some much-needed shading to the portrait.
“Lease terms give producers some flexibility once they spud a well,” said Bryan Livingston, CEO of Captial Alliance Corporation, referring to a disconnect between hurrying to drill wells, and not being required to commence production immediately. “You can buy some time on your leases by having drilled-but-uncompleted wells.”
Livingston also noted technological factors, saying, “As recompletion methods improve, the same wells can be viable for longer and longer while maintaining respectable production.”
While these items are more or less under the purviews of individual companies, there are also a number of external conditions that every company must deal with.
Sandy Fielden, Director of Research for the Commodities and Energy Group at Morningstar, Inc., cited figures from the Energy Information Administration (EIA) showing that the DUC count in the Permian has risen month over month, with no dips, every month since August 2016. Companies are drilling. We know this. But why are companies drilling and drilling and only adding to the DUC dossier?
There are a number of theories, summarized by Fielden as (a) too few completion crews; (b) trouble with reliable sand and water sourcing; (c) other logistical or transportation issues; and (d) companies waiting for the “right price point” before tapping their uncompleted wells.
Fielden, like others, has been quick to discount the “right price point” theory as oil prices have been well in excess of Permian breakeven levels for some time.
Tommy Taylor, Director of Oil and Gas Development at Fasken Oil and Ranch, Inc., added, “As a way of doing business I don’t know anybody [who] just says, ‘I’m just gonna [drill some wells and] hold them and wait for things to get better;’ That doesn’t work out all that well economically.”
Todd Bush, founder of Energent Group, saw things in a similar light, and chose to hold the magnifying glass up to a particular set of issues. “Sand, pressure pumping, and water. We view those as the three biggest constraints on the market,” he said.
“I think the drilling activity has picked up faster than the amount of horsepower available to go and complete those wells. Those constraints will definitely have an impact on the number of DUCs,” said Bush.
Fasken’s Taylor confirmed the shortage of frac crews and acknowledged the difficulty some companies have sourcing water and sand.
“There’s a certain amount of sand you’ve gotta source. And then when you frac the wells and you produce [water], you either have to have a system set up to recycle it or you’re going to have to dispose of it, but you’ll have to have something like a disposal well nearby or you’ll have to truck all that off and so all those issues come into play when you’re looking at doing a concentrated drilling program in one area,” said Taylor.
“We’ve got a single facility set up. We’ve got some pits, a double line of pits, and we bring our produced water in there, clean it up, and store it,” he said.
This facility, along with generating their own water supply from a combination of brackish and produced water, has allowed Fasken to manage its water concerns with relatively uncommon ease. As described by Taylor: “We were in that rare position where [we] had all the land together [contiguously].”
“Here in Midland we’re off of fresh water, one hundred percent. So one thing that was a big question in our minds was: If you frac these wells with this recycled ‘dishwater,’ [would that make for] just as good a well as if you frac’ed it with fresh water? And I think the answer’s ‘yes,’“ he said.
The Fasken set-up might not work for those with less-concentrated land holdings. ”I think a midstream company is going to be the answer for them,” said Taylor. “And I was down at NAPE [North American Prospect Expo] a couple weeks ago and I talked to several people and that’s exactly what they were doing. They were coming to town looking to put together water systems.”
“Our engineering manager, he always says two things,” added Taylor. “People and water, people and water. If you don’t have that, you’re out of business in this unconventional play.”
Speaking of people, the crews needed to frac and perform other completion-related duties are in high demand. According to Bush, the demand is about to bump into the ceiling of frac crew supply, if it hasn’t already. Wells are being left uncompleted for longer because, whether the E&Ps want to complete them or not, there aren’t enough crews to go around.
While the image of a bubble bursting usually comes with a negative connotation, in this case, the DUC count is overinflated, and will have to pop eventually. DUCs seem poised to become a focal point for many companies looking to reap the untapped well inventory.
Earlier in 2018, Paul Kuklinski, founder of Boston Energy Research, wrote that he expected the high DUC count to help reduce the overall capital needed to continue production growth in 2018. While he attributed the DUCs to the scarcity and high cost of frac crews, he expects completion levels to return to their pre-recession levels from 2014.
According to Bush, more than 7 million horsepower (in the form of hydraulic field equipment), is expected to come online in the next 12 to 18 months. This injection of equipment, provided the availability of crewmen to operate it, seems destined to put a dent in the DUC count.
Twelve to eighteen months sounds like a long time, and in the oil patch, a lot can change with an extended timeline. Bush sees the impending technological influx as not only a matter of cause, but a shakeup that will vault the oil industry into an even more efficient and sophisticated age.
“On the equipment side for pressure pumping in general, were going to see more focus on reliability,” said Bush. “Looking to increase reliability by a factor of ten, running longer without maintenance… Operators are expecting to see that kind of reliability and performance come through.”
“I know a couple of companies are rolling [higher efficiency equipment] out right now, so we should see some of these more efficient pumps in the next three to six months that can impact costs and efficiency for these service companies,” he said.
Improving over the latest round of improvements is nothing new to the oil and gas industry. According to Bryan Livingston, the wild ambition to achieve things that once seemed impossible can be as great a driving force for change as any. “Some of our clients are developing completion methods that could satisfy producer demands for laterals of 5000 meters or longer. We’re not there yet, but the theoretical length keeps going farther and farther,” he said.
Livinston postulated that technological advancements in coiled tubing that are already underway may allow extended laterals in excess of 10,000 meters become more than just a theoretical possibility.
“Reaching those theoretical limits are the kinds of challenges the industry is trying to wrestle with,” said Livingston.
Clearly, the swelling DUC count is one that touches on a great number of levels within the industry. People and water will always be paramount, but perhaps the patience shown by companies racking up DUCs in unprecedented quantities is a symptom of an evolving industry, now fully prepared to wait for, if not the “right price,” the right combination of efficient technology and labor availability. The United States is an exporter after all, performing on the global stage for the past two years, after a 40-year hiatus.
As with many occurrences in today’s oil industry, 2014’s recession will undoubtedly weigh heavy in the minds of many companies. According to Livingston, vicious boom-and-bust cycles are not a mandatory condition, and he feels that a sense of restraint has arisen from an industry that sees the potential for a less volatile business cycle. His optimism for the the maturation of the industry extends directly into the sector of well completions.
“We’re in a different world now. The discipline imposed by lower oil prices, means more pressure on producers and their vendors to bring the price of well completion down. It is a relentless process.”
Tony Burke is a freelance writer based in Abilene and a former editor of this magazine.