U.S. shale developers have been on a relentless chase to drill for oil as cheaply as possible. With plenty of cash in their pockets and a hunch that they might soon exhaust their best inventory in the prolific Permian Basin, some companies have been shifting their focus to making sure they get every last drop of crude they can get out of what they have. That could mean higher costs today.
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Producers have done a great job of maximizing initial production. U.S. land and offshore productivity—measured as the amount of oil produced in the first 12 months per foot drilled—has been on a steady upward trajectory since 2007, according to data from Enverus.
U.S. onshore and offshore wells that have been producing for 12 months since August 2022 were 59% more productive compared with those that were drilled five years earlier, the data show. Those gains have been driven by improvements in seismic technology and mapping, longer wells and the amount of fracking fluid used, according to Jason Brown, economist at the Kansas City Fed.
It is unclear how long productivity gains can continue at this pace. There may be a limit on how long lateral wells can get, for example. Not only does the lengthening of a well require more contiguous land, but the longer wells get, the trickier it is to service them, according to Mark Chapman, senior vice president of oil-field services intelligence at Enverus.
Meanwhile, efficiency gains have stalled. Speed of drilling has peaked at around 1,400 feet a day in the Midland side of the Permian Basin, according to Chapman. And capital efficiency over the life of a development has been somewhat stagnant in recent years and has declined more recently because of rising oil-field service costs.
A niggling concern for U.S. shale has been that, while the industry has gotten very good at extracting oil, it has come at the cost of leaving some in the ground. If underground shale layers were analogous to a milkshake, the traditional method—known as best-bench development—involved extracting through just one or a few straws first in a section and then coming back later for more. While that yielded initial wells that were very productive, the problem was that the later wells were significantly less productive.
Cube development, also known as co-development, aims to fix that problem. It involves sticking multiple straws all around the figurative milkshake before extraction. While producers have been using that method for many years, there were trials and errors on how those wells were spaced. The clear benefit is that, done correctly, producers can expect to extract more oil overall.
“Broadly speaking, most believe cube development yields higher total oil recovery than best-bench-first,” Stephen Sagriff, senior vice president of intelligence at Enverus wrote in an email. Sagriff noted that about 60% of all development in the Permian has been under a cube-style development over the past few years.
Exxon Mobil is a vocal proponent: In its earnings call in October, the company estimated that its cube-development method is yielding 30%-50% higher net present value compared to a competitor using the best-bench approach in Martin County, Texas. It was also part of Exxon’s rationale for buying Pioneer Natural Resources. Exxon figures it can extract more hydrocarbons out of Pioneer’s acreage using its own cube-development method.
Investors aren’t totally sold on those lofty projections, especially because the oil major isn’t seen as the best shale developer. Others using the approach include Diamondback Energy, which has been shifting to co-development since 2019. Diamondback went from drilling an average of about three wells per project in 2015 to 10 in 2019 and about 24 as of today, according to its investor presentation this month.
The downside of cube development is that it costs more upfront, takes longer until production and involves substantial risk. In cube development, well spacing has to get quite dense in order for a producer to really maximize the amount of oil from the life of the development. But place the wells a little too close, and that productivity potential dramatically declines.
As Tom Loughrey, president of energy analytics company FLOW Partners, puts it: Optimizing recovery means a producer has to get “fairly close to the edge” of the point at which ultimate oil recovery suddenly drops off a cliff. This was what happened to some earlier cube projects, which failed to produce hydrocarbons as predicted because the wells weren’t spaced far apart enough.
Not everyone buys the premise that cube development is ultimately more capital efficient over the life of a development. What is clear, though, is that only developers with deep pockets, patience and some risk tolerance can try it out. It may also require a different kind of investor base. Loughrey notes that when Pioneer Natural Resources’ wells started getting denser at the beginning of 2022, “Wall Street didn’t like it,” and that the company subsequently started spacing their wells farther apart. He believes that Exxon is able to take on cube development because its investor base includes more thematic investors who aren’t as laser-focused on quarter-by-quarter improvements in capital efficiency.
That some of the largest Permian developers are pursuing a capital-heavy, somewhat risky method suggests they are less confident about the number of gushers left in the shale patch and more confident about their investors’ patience.
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