The Trend in Drilling Horizontal Wells Is Longer, Faster, Cheaper
The trend toward drilling longer horizontal wells is growing with lateral lengths of 3 miles reached.
In the Permian Basin, horizontal wells with 3-mile-long laterals are becoming routine.
Last year 18% of the wells in the play were in the 15,000-ft range, up from only 4% in 2017. The average is approaching 10,000 ft, according to a Rystad Energy study that shows drilling in the Permian is setting records if measured by the total number of feet drilled per year.
“The Permian is now entering a 3-mile-lateral era. Such long wells were viewed as inferior for their high finding and development costs in some deeper zones just a few years ago, but modern equipment and completion methods allow extended-reach wells to spread across the entire basin,” said Artem Abramov, head of shale research at Rystad.
Increasingly, the laterals seem to come in two sizes: 10,000 ft and 15,000 ft. On a recent research trip to Midland to meet with drillers, Richard Spears, vice president of Spears and Associates, an oilfield market data firm, said he heard so much about the cost advantages of 15,000-ft wells, he had to ask why anyone was drilling shorter ones.
“The universal answer was that the 15,000-ft lateral was the most capital-efficient, meaning you got a lot of reservoir exposure at a lower cost than with a 10,000-ft lateral, but many times the lease lines did not allow for a lateral greater than 10,000 ft,” he said.
The trend toward long laterals began in the Marcellus and is spreading in the Permian where operators are taking advantage of major gains in drilling and completions operations.
The biggest operator in the Permian, Pioneer Natural Resources, has been a major proponent of longer laterals. Rystad said 19% of Pioneer’s wells had laterals longer than 12,500 ft in the Permian in 2020–2021.
It drilled 12 three-mile wells in 2021 and planned to double that total this year, “if not a bit more,” said J.D. Hall, executive vice president for operations at Pioneer, during a recent earnings call. “We see these as being a huge value-adder to our program.”
Soon after ConocoPhillips closed the deal to buy Shell’s acreage in the Permian on 1 December 2021, its team began applying its drilling and completions methods there. When it comes to cost cutting, Tim Leach, executive vice president of Lower 48 at ConocoPhillips, said their “biggest opportunity in the near term is transitioning from 1-mile wells to 2-mile wells.”
And they are going longer. “In the southern Midland Basin, we just completed a drilling project that included several 3-mile and one 3½-mile lateral that we drilled in record time and have been very pleased with the results and the production from that,” Leach said during a recent earnings call.
Doing more of these long laterals will require some swapping and trading with adjoining lease holders because 15,000-ft laterals require “big, blocky acreage blocks,” he said. “The good news is that this is a win-win for both parties. Everybody wants to be able to drill longer laterals where they have bigger interest in their own operations.”
What About Production?
Longer laterals can significantly cut costs, but are those added feet also productive?
Rystad forecast—based on the distribution of expected completion activity by county, landing zone, and well design—that the average productivity of new Permian wells seems to track the well length. Between 2019 and 2022, the average well output was up from about 850 to 1,000 BOE/D, and the average lateral length rose from 8,500 to 10,000 ft.
When the Norwegian data and consulting firm compared the results of companies doing 2- and 3-mile-long laterals in comparable rock with similar completions, they found the production per foot for longer laterals sometimes falls short.
“Our conclusion so far was that many of them were able to maintain productivity per foot, but we also recorded some cases with 10 to 20% degradation in productivity per foot for 3-mile laterals,” Abramov said.
Those estimates were based on the first 3 to 6 months of production. He said that “most likely, degradation in EUR [estimated ultimate recovery] will be less pronounced as 3-mile laterals exhibit even longer flowback period and shallower decline rates.”
Even if the lower rate has a lingering effect, the 15 to 20% reduction in drilling and completion costs offers an economic argument for going longer.
Those savings are a product of faster drilling and completion methods. A Rystad chart shows that at the peak of the drilling boom in 2014, about 300 rigs drilled less than 20 million ft of lateral in a year, while last year fewer than 300 rigs drilled nearly 46 million ft.
Diamondback Energy offered some details about its drilling and completion savings during a recent earnings call.
“We've decreased the number of days it takes to drill from spud to total depth by nearly 30% this year alone. And we're now drilling 2-mile laterals in roughly 10 days in the Midland Basin,” said Travis Stice, the company’s CEO. On the completion side they are fracturing two wells at the same time by doing simul-fracs.
“We've transitioned the majority of our completion crews to simul-frac operations and are now completing wells in the Midland Basin nearly 70% faster than when we were utilizing the traditional zipper frac design,” Stice said.
Others are adopting the method, but not at the same pace as Diamondback which expects to complete about 90% of its wells using the method this year.
“Simul-fracs already account for about 10% market share in the Permian and we think it might grow to 20% as more and more operators are testing them on large projects. This trend definitely goes together with the shift towards longer laterals,” Abramov said.