Since the advent of the shale boom, American oil producers have drilled both down and laterally beneath the earth’s surface. But now that the easiest-to-get crude has been extracted, these companies are testing the limits of their technology even further by boring more than 3 miles horizontally, increasing both operational risk and potential rewards.
One in five new wells in the Permian Basin of West Texas and New Mexico will rely on horizontal wells 3 miles or more underground by 2024, double the share this year and up from virtually zero just two years ago. according to research firm Rystad Energy. . American producers such as Pioneer Natural Resources Co. and Diamondback Energy Inc. they say the new technique will be key to future oil production for an American shale oil industry that is beginning to show its age.
Technical advances are based on the basic vertical wells that preceded the shale boom and the standard 2-mile lateral wells deployed in most fields today. But adding an extra horizontal mile, or more, ultimately means more complicated and expensive projects. For the most part, only the biggest players will be comfortable with such extreme drilling, giving the best-funded producers another leg up and possibly hastening the arrival of peak US oil.
“It’s a riskier game,” said Mike Holcomb, chief operating officer of Patterson-UTI Energy Inc., one of the largest U.S. contractors hired to drill longer wells. “If something happens and you lose a fullback, you’ve lost 3 miles of production versus 2.”
Following the widespread adoption of techniques such as fracking and lateral drilling in the early 2000s, US shale became the world’s main source of oil growth. Now that the best surface has been tapped, the shale patch is struggling to keep up. Some explorers trying to extract hard-to-reach hydrocarbons more efficiently go so far as to drill wells in zig-zag and U-turn patterns under miles of rock in hopes of making more money.
New techniques can sometimes lead to equipment failure: flexible pipes can sometimes break in the drilling process and bits can wear down deep below the earth’s surface. Also, if the oil pockets are not exactly where they were modeled, a 3 mile well is a more expensive expense for what could ultimately be a mistake. Proponents say longer wells promise lower fixed costs, better productivity and the ability to access oil that would otherwise have been out of reach.
“It’s a risk-reward decision, because if something bad happens at 18,000 feet, that’s a costly mistake,” Diamondback President Kaes Van’t Hof said on a call with analysts. The company has even gone sideways to the home of company boss Travis Stice. So far, he said, the results of the longer laterals have been positive. “The drilling guys can do it, there’s no doubt about it.”
Pioneer, the largest independent producer in the Permian, has an inventory of more than 1,000 future wells that run at least 15,000 feet horizontally, or about 2.8 miles, with some even exceeding 18,000 feet. That’s about 3.4 miles, or the length of 50 football fields. Longer horizontal wells generate more oil, cost less per lateral foot and require fewer vertical holes and fracking workers, Pioneer’s incoming president and chief executive Rich Dealy said at a conference in August.
The services, the indentured laborers of the oil patch, are mostly eager to take on this kind of risky, high-value work. An average 2-mile lateral well costs $6.5 million, compared to about $9 million for a 3-mile lateral well, according to Bernstein data. Pioneer and Diamondback did not say whether they have had any problems widening the laterals or how much they have spent, though Dealy said on the call that the roughly 3-mile laterals result in capital savings of 15% per foot. . Longer horizontals are particularly popular in the Marcellus Shale of the northeastern US, as well as in the Midland Basin of the Permian in Texas.
“It takes more horsepower on the surface to pump,” Thomas Johnston, chief operating officer of ShearFRAC, a drilling technology company. “And it costs more money to put in the casing of the well. So there are all these additional costs up front.”
US drillers have been looking for years for new ways to extract oil from a stagnant market, including production in more populated urban areas. Still, the sharp drop in output from U.S. shale wells is turning out to be worse than expected, forcing oil drillers to work even harder to keep output from falling, the firm said. Enverus research in its latest report.
“With cost inflation, wells are getting more expensive,” Rystad analyst Alexandre Ramos-Peon said. “The only way you can still make a fantastic profit out of this is by leveraging every known technique to get the most out of it.”
Not everyone is convinced. Last year, Bernstein analyst Bob Brackett published an investor note titled “Why I Don’t Like 3-Mile Laterals.” He argued that the cost savings of 5% per well is minor compared to the risk of productivity getting worse as the well gets longer. The third mile of a well suffers a 13% drop in production per foot, Brackett wrote in September 2022, and he said he has yet to see anything to alter his thesis.
“A company could show with real data that the cost savings from the well is greater than the productivity” that’s been lost, Brackett told Bloomberg News in August. “But no one has yet.”
For now, drillers continue to push outward, with some of Pioneer’s wells now approaching four miles. Time will tell how many more drillers can go.
“We would always say we’ll stop when the well tells us to,” said Holcomb, the Patterson-UTI executive with more than 40 years of oilfield experience. “And then over the years, we’ve learned as we’ve gone along and continued to push the boundaries.”
To contact the authors of this story:
Mitchell Ferman in Houston at mferman13@bloomberg.net
David Wethe in Houston at dwethe@bloomberg.net
