Is The EIA Overestimating The U.S. Shale Boom?

By Zainab Calcuttawala 

“The EIA is assuming that productivity of individual wells will continue to rise as a result of improvements in technology,” MIT researcher Justin B. Montgomery told World Oil. “This compounds year after year, like interest, so the further out in the future the wells are drilled, the more that they are being overestimated.”

Instead, lukewarm oil prices have forced oil majors to drill only in easy-to-access areas, located mostly in the Eagle Ford and Permian basins in Texas, and the Bakken formation in North Dakota. This has led to an exaggerated increase in the number of active wells, and a hyperbolized narrative of growth in the shale industry, the study says.

“The same forecasting methods are used in other plays in the U.S., and the same dynamic is likely to be present,” Montgomery added.

Margaret Coleman, the Energy Information Administration’s chief of oil, gas and biofuels exploration and production analysis, said the “study raised valid points” and offered insights for more accurate analysis of domestic fossil fuel forecasting. Part of the blame can be attributed to an information gap in data available to the EIA team, she added.

Many shale wells lack key pieces of data tracked down by the MIT team, meaning EIA projections over-emphasized geological and capital assumptions as well as technological developments to estimate the shale industry’s growth. Of course, there have been some advances in drill head technology, mapping software, and hydraulic fracking, but that is just one part of the puzzle.

 “It’s really hard to bet against the ability of the industry to improve and get more out of the rock,” Manuj Nikhanj, co-CEO of RS Energy Group, told World Oil. Three years of oil prices have forced oil and gas majors worldwide to get creative to lower costs and avoid bankruptcies. Mass firings and empty offices pushed multinationals to operate on a leaner human resources diet, utilizing robots and merging job descriptions to keep the companies functional.

But the U.S. shale boom’s story is different. Its initial crash correlated deeply with the 2014 price burst, but its rise continued despite efforts by the global oil producing community to curb international output to battle a glut. A barrel price in the $40–$50 range still gave shale producers enough cushion to drill, even as foreign producers with expensive offshore and onshore operations struggled.

Output in the Bakken tripled from 2012 to mid-2015, the MIT data shows. But this boost related to oil major’s systematic abandonment of tough-to-drill spots in favor of more lucrative acreage. American shale companies were not allowed to export their crude prior to 2016. This meant that oil output from the U.S. was not directly contributing to the global oversupply. Still, the new production boosted inventories and lowered the size and frequency of crude orders by American refineries. Soon, the low-hanging fruit will have been picked.

“There certainly could be some validity to getting a rosier forecast because right now, the industry is working sweet spots,” Penn State hydrogeologist Dave Yoxtheimer said. “When that’s all played out, they’re going to have to go to the tier-two acreage, which isn’t going to be as productive.”

The slowdown has already begun in the Northeast’s Marcellus basin and in the Permian. Wells in the two prime shale drilling sites have lost between 10 to 20 percent of their output since a peak last fall, but barrel prices have been riding an upward trajectory for most of 2017, meaning the last resort “tier-two” acreage could remain profitable for at least the next couple of years.

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