US upstream industry relying on longer lateral drilling to boost cash flows



Lower returns/foot while more hydrocarbons/well

Breakeven decreases with longer laterals

Could become industry standard in future

Article continues below Advertisement...

At a time when squeezing out more oil and gas for less money is a priority for upstream producers, longer laterals are giving a competitive edge in unconventional basins in the US, producing more hydrocarbons per foot drilled.

Laterals – the horizontal portion of a well, – have become longer and longer in the last 15 years. Drilling out 15,000 feet, or nearly three miles horizontally reduces the number of wells companies need to drill to achieve their production goals, and does it at increasingly lower costs.

As producers keep a tight rein on capital expenses to boost cash flows, they have found it unnecessary, for instance, to drill two wells to 6,000 vertical foot depths, and then take the well sideways for one mile, when a single vertical well can be drilled with a horizontal leg extending two or three miles.

That saves drilling time, cuts surface equipment requirements and cuts downtime to move rigs and crews.

“In the US industry, everything is based on dollars per foot,” Neil Bird, product director for drilling equipment and information provider Enteq, said. “It’s boe economics, really.”

Improved breakevens

According to Daryl Koo, head of oil asset intelligence for energy consultancy Enverus, in the core Wolfcamp-A formation, the breakeven WTI price of a well decreases from $38/b to $34.50/b when going from 5,000 foot to 10,000 foot laterals.

“Though we didn’t model a 15,000-foot case given it’s still an emerging design, I’d expect the breakeven price to further decrease to around $31-$33/b, assuming no major issues with production or cost performance,” Koo said.

Upstream operators during Q1 conference calls viewed the incremental economics favorably – especially at current WTI prices well above $60/b.

Comstock CEO Miles Jay Allison said his company has drilled wells to 13,000 feet-plus earlier this year but plans to drill even further out.

“If we can extend our average well to 13,000- to 15,000 feet … the economics make a lot more sense,” Allison said during the company’s Q1 conference call. “We don’t see a lot of issues in the drilling of it, and we’ve been able to complete these pretty consistently.”

John Lambuth, executive vice president-exploration for Cimarex Energy, said his company intends to launch a three-mile development “soon” in Culberson County, West Texas, and is looking at several areas in the Anadarko Basin similarly for three-mile developments.

Cimarex believes the incremental production uplift received would be “much more beneficial” than the associated costs, Lambuth said.

Occidental Petroleum CEO Vicki Hollub said her company has drilled “one or two” 15,000-foot laterals, although the company has racked up numbers of laterals greater than 10,000 feet.

“It really depends on the reservoir and … your full infill development plan, how you intend to complete it and what kind of artificial lift you intend to use,” Hollub said.

Laterals of 15,000 feet could become as common in a few years as 10,000 footers are today, some experts say.

“In a lot of applications, 20,000 feet will become the norm as well,” Enteq’s Bird said. “The technology will evolve to make sure it can be consistently delivered.”

Diminishing returns

Production and cost data from major plays like the Permian and Bakken suggest technical challenges of 15,000 foot laterals are largely overcome and horizontals around that length are the preferred development strategy, experts say.

But even as more oil and gas is procured per well with plus-sized laterals, increases come at diminishing returns, Rene Santos, manager of supply for S&P Global Platts Analytics, said.

Using a hypothetical example, Santos explained that between a 7,000 foot and a 10,000 foot lateral, the production increase might be around 400 b/d of oil or 0.133 b/d per each additional foot drilled.

However, the increased production from taking a lateral to 13,0000 feet versus 10,000 feet may be only about 275 b/d or 0.092 b/d per each additional foot.

“The 13,000 foot lateral is more economical than a 10,000 foot lateral, but you get less incremental production for each additional foot drilled,” Santos said.

One potential solution is drilling multilateral wells – more than one lateral for each single well – and fracking each of the laterals, he added. While some companies have experimented with this technology it appears to be in the early stages.

Acreage constraints

Lack of “blocky” acreage is one of the biggest constraints to longer laterals – companies may simply not have enough contiguous lands to extend wells out for three miles or so.

In other cases, a geological formation into which super laterals are drilled may simply “pinch out” as its productive geology thins. And sometimes, regulatory surface constraints may limit the ability to drill additional footage.

Also, “operators may have difficulties keeping long-lateral wells within the target zone if it is thin and the subsurface varies greatly within a short distance, [which would] reduce well productivity and economics,” Enverus said in an email. “Maintaining stimulation effectiveness at the toe of the well can also be challenging at extreme lengths” of 15,000 feet and longer.

“Longer” laterals initially referred to wells 6,000-7,000 feet instead of 3,000-4,000 feet. Later, companies judiciously extended laterals to a now-typical 9,000-10,000 feet. But companies have experimented with longer laterals, and in the last few years industry began extending horizontals out to 15,000 feet.

In 2017 Eclipse , an Appalachian upstream operator, drilled a 3.7-mile lateral well called Great Scott, besting its own previous 3.5-mile record.

Later that year, ExxonMobil drilled a much-heralded lateral also over three miles in the Bakken Shale of North Dakota. Both companies made headlines at the time and set the stage for companies to longer lateral lengths.

In fact, executives for Pioneer Natural Resources suggested one motive for the company’s back-to-back acquisitions earlier this year of Parsley Energy and DoublePoint Energy was procuring the adjacent land tracts to be able to drill longer wells.

Pioneer has not yet assessed all its newly acquired acreage from the two transactions, so longer laterals may begin later in 2021 and “more likely” in 2022, Rich Dealy, Pioneer’s president and chief operating officer, said.

“That’s something we have to continue to do over … the next few months,” Dealy said. “We surround all that acreage.”


Starr Spencer


Gary Gentile


Natural Gas, 

Source: Platts


Please enter your comment!
Please enter your name here