HOUSTON—E&P companies in the Permian Basin are seeing production growth as they pursue long laterals and optimized completions, but they are also experiencing growing pains and keeping eyes on what could be the next challenge.
Dan Westcott, president of Legacy Reserves, described it as a game of Whack-A-Mole.
“One problem arises. You go and smash it, and another one comes up,” said Westcott, who was among a trio of speakers on a panel during RBN Energy’s recent PermiCon. “But you can’t grow an industry this quick without having constraints.”
While producers in the largest oil field in the U.S. are not seeing frac crew or equipment constraints like in past years, takeaway capacity constraints continue to affect some operators eagerly awaiting the completion of pipeline projects. Longer term most in the basin are paying attention to decline curves, given the nature of shale plays, as production grows.
Oil production in the Permian is expected to increase by 31,000 barrels per day to about 3.5 million barrels per day in October, while gas production is expected to rise by 239 million cubic feet per day to 11.8 billion cubic feet per day, according to the U.S. Energy Information Administration’s (EIA) latest Drilling Productivity Report.
Discussions about the relationship between parent and child wells are taking place continuously across the basin, panelists said. With hundreds of thousands of wells drilled in the basin, cross-well communication during hydraulic fracturing has become a top concern as infill drilling and frac stages rise, threatening production levels or damage to offset wells.
“What we’ve seen and I think operators will continue to see is frack interference, and then as you come in and drill infill wells you see a degradation to the parent type curve,” said Stephanie Reed, senior vice president, land, for Parsley Energy. “We model that.”
But she said Parsley, which has about 210,000 net acres in the Permian, is in a different position than some other operators because of its wide span across the basin. The company doesn’t have to immediately drill infill wells, which might have a 15% to20% degradation of type curve to the parent well, she said.
“We actually have a long runway before we think that we’ll see that degradation. But it is something that operators are seeing in the Permian Basin,” she said. “It’s something that we talk about quite often just because people” wonder whether production in the Permian will be replicated.
Other panelists agreed that decline curves and interference are two areas on which to keep a watch.
“Rather than having a parent and a child, we’ll drill four or eight wells at a given time and depending on the area maybe more than that. But we do see frack interference. … It is something that we need to deal with,” Westcott said. “I think that will lead to operators stepping back and making broader discussions about where they are going next and how to maximize not a well, not a flashy press release, but full-cycle economics.”
All About DUCs
Another hot topic of discussion for Permian producers have centered on drilled but uncompleted wells (DUCs). As of August, there were 3,680 DUCs in the Permian Basin, up from 3,419 in July, according to the EIA.
A report released recently by energy consultancy Wood Mackenzie stated that U.S. shale operators could unlock cash if it didn’t tie up cash in so many DUC wells.
But not all operators are building DUCs amid infrastructure constraints.
“Parsley is probably not in the camp of building any kind of a DUC bank,” Reed said, adding a large portion of the cash flow of a well is spread across the well’s entire life. “So you won’t see us artificially build a DUC bank, and we really don’t feel the near-term prices will discourage us from completing wells.”
However, she said, “from a business perspective if it makes sense to slightly defer a completion a month or so we absolutely may but not artificially build a DUC bank.”
Westcott added that Legacy is “not in the camp where we’re speculating about when to bring on wells.” The company, which converted from an upstream MLP to a C corp., builds DUCs; however, the build is a function of working capital—“the difference in drilling an entire pad and coming back and fracking it.”
But growing the rig count by nearly 500 rigs in the Permian is impossible to do without increasing the DUC count, he added, because “the pads are getting bigger, the wells per pad are getting bigger and that’s naturally going to lead to working capital.”
Talk on a reoccurring concern in the basin surfaced again during the conference, with pipeline capacity strained as production increases.
So how are Permian producers responding? It’s a question that is on everybody’s mind today, said Kevin Lafferty, senior vice president of E&P for Devon Energy.
“There isn’t one thing that is tripping everybody up,” Lafferty said, calling the issue producer, midstream provider and takeaway specific and one that involves contracts that have, or haven’t, been in place for years. “It has to do with capacity. It has to do with your hedging programs. So there isn’t just one thing that’s going to impact everybody.”
He pointed out that infrastructure constraints and low regional prices have caused some producers to build DUCs, while others have shifted capital to other basins.
“Now for Devon we have put ourselves in a great position. For all of 2018 between our hedging program and between our firm capacity on oil that we had, we are effectively 90% protected on price,” Lafferty said. “We’re not impacted to any great extent by the differentials flowing out. We have space, and we have capacity. … We have all of our NGL arrangements in place, takeaway out of the basin. We have frac capacity at Mont Belvieu,” which he called a luxury.
“Coming out of the downturn our supply chain group did a great job of locking in contracts and taking advantage of a lower price cost structure,” he added, noting the company locked in a certain percentage of rigs and spreads, de-bundled and moved into regional sand. Plus, the Oklahoma-based company—which has Permian operations focused on the Delaware Basin in southeastern New Mexico—recycles about 80% of its water.
The inability to move barrels combined with rising costs could be a blow to some.
But “We have margins in the barrels that we’re getting. And so what you’re going to see from Devon is that when others are having to [make] other choices and move to different parts of their portfolio, you’re actually going to see us lean into Permian because we put ourselves in a great spot, and it’s the best returns that we have,” Lafferty said.
Velda Addison can be reached at firstname.lastname@example.org.