Houston — The dramatic jump in productivity seen in the early days of the US shale oil boom may be waning, but is likely not over, according to analysts, who expect efficiencies, at least for some plays, to edge higher in 2020.
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While productivity is expected to climb, drilling has slowed, and thus shale production gains are expected to slow. In the Delaware Basin in West Texas, for instance, S&P Global Platts Analytics expects crude output to average 1.5 million b/d in December 2020, up 15% on the year. That's down from a 16% gain in December 2019, and a 57% gain in December 2018.
Wells have become increasingly larger as E&P companies have drilled longer laterals, or horizontal legs, and used more proppant – sand and/or water that keep fractures open and facilitate oil and gas flow to the surface.
But in some places, operators are beginning to push up against the limits of how much shale they can deliver without some startling new technology breakthrough, experts say.
Some claim productivity has even taken a step backwards, at least in some areas.
In some areas, "we're actually seeing productivity degradation," Sarp Ozkan, director of energy analytics for Enverus, formerly known as DrillingInfo, said.
As the industry moved from testing to development mode in the oil patch, the biggest challenge was how to extract the most oil from each well. That was particularly true in the Permian Basin of West Texas/New Mexico where at least a dozen geological subsurface horizons exist, each requiring a unique recipe to maximize oil yields.
In 2014, operators were forced to innovate rapidly to combat a sharp drop in oil prices from $100/b to barely half that level by year-end.
Since then, the industry experienced a "considerable jump" of about 50% higher initial well production (IP) rates, especially in the Permian, Ozkan said
Previously, companies drilled one or two wells on a unit to satisfy leasing terms, with superior results. At the same time, to boost economics, operators tried to fit the most wells into the least amount of acreage, called downspacing.
But returning to a site with just a few wells and later drilling six or a dozen wells much closer together on it may make the new wells "a lot less productive," said Ozkan.
'A FINITE MILKSHAKE'
"It's like they're sucking a finite milkshake," he added. "When you put more straws in the cup, each straw starts competing for more milk" – that is, each well struggles to rake in more oil than the offset wells nearby, he said.
That has caused some plays such as the STACK in Oklahoma to show year-over-year productivity degradation. For example, Concho Resources said in October its Permian big Dominator project did not meet earlier expectations because of too-tight spacing between wells.
Laredo Petroleum told investors about a year ago it had begun upspacing Permian wells at its Yellow Rose project — placing wells farther apart, not closer together. By August, Yellow Rose had outperformed a tightly-spaced offset well package for cumulative oil per foot by more than 30%, Jason Pigott, then Laredo president and now CEO, said in a quarterly call that month.
Not only did results of wider spacing confirm Laredo's expectation that 2019 well productivities would show "significant" increases versus 2018, but also "significant productivity improvements" versus more tightly spaced offset wells throughout its acreage, Piggot said.
As production growth has faded in favor of cash flows, US oil operators dropped rigs throughout the past year. Productivity growth also reduced the need for some rigs.
As operators try to squeeze more operational and financial oomph from each dollar spent and study IP rates and decline curves to measure well efficiencies, a simpler metric of production gained per well brought online is also a "powerful gauge," S&P Global Platts Analytics analyst Andrew Cooper said.
Eagle Ford efficiency has fallen roughly 7% year on year as of the second quarter of 2019, according to Cooper. The Delaware play in Texas was down 5% over the same period, although efficiencies in the Delaware New Mexico play were up 23% using the same metrics, Cooper said.
"[Those figures show] why operators are flocking to the western half of the Permian," Cooper said.
PERMIAN, BAKKEN EFFICIENCIES STILL RISING
Moreover, improvements, at least in the Permian and Bakken Shale of North Dakota where efficiencies are still rising, will continue for at least another year.
"Likely in 2021-2022 we will see efficiencies or production per well stabilize and flatten due to limited core acreage remaining," he said.
On the other hand, what's happening with shale productivity often lies in the definition, Anexandre Ramos-Peon, senior analyst for shale at Rystad Energy, said.
"The classical way to define it is production ... in the first two to three months," Ramos-Peon said. But since some operators really "cherry pick" the way they represent their production. Some release outputs of the first 24 hours or 30 days, so reported numbers are not comparative.
Also, some operators deliberately cut back peak output to produce more down the road. And well laterals, or horizontal legs, are getting longer -- from about 5,000 or 6,000 feet in 2014, to 9,000 or 10,000 feet currently -- and thus reap more oil per well.
Ramos-Peon conceded many Eagle Ford wells have not been as good as before. But oil prices are lower too – around $56.44/b in Q3 2019 versus $69.43/b in Q3 2018, so operators might target different areas away from the sweet spots, unwilling to produce their best oil into a lower-priced market.
Thus, "there is no one number that fits all sorts of metrics," Ramos-Peon said. On the other hand, "initial production rates of 90- and 180 days have kept growing every month."
In October, Rystad in a report said, after studying months of production data, that the average well each month in the Permian was slightly more productive than its counterpart drilled three to six months before.
"In the Bakken, Eagle Ford and DJ Basin [in Colorado], well productivity is observed at or close to all-time highs as of 1H 2019," the report said.