Analyst challenges predictions for Western oil booms
North Dakota and Texas fields could be at a fraction of current productivity by 2040, says a new report.
Spurred by hydraulic fracturing, the deep shale fields of North Dakota’s Bakken and Texas’s Eagle Ford are collectively producing two and a half million barrels of oil per day. By some measures, the boom appears to be turning to glut. Last week, the spot price of crude fell to under $80 per barrel, its lowest price in more than three years. The nationwide average price of unleaded gasoline has followed suit, dropping to $2.95 per gallon, prices not seen since the end of 2010.
While drivers and other energy consumers rejoice, oil executives fear that plummeting crude oil prices signal missteps similar to those made by the natural gas industry in recent years – as unchecked production and its attendant lower oil prices erode their bottom line.
But north of the U.S. border, noted Canadian energy analyst David Hughes says that even if the drilling could somehow continue, the bounty simply will not last.
Last month, Hughes released “Drilling Deeper,” a report he authored for Santa Rosa-based Post Carbon Institute, scrutinizing the U.S.’s two largest oil booms in the Bakken and Eagle Ford fields. By examining industry data, Hughes projects that the booms in both fields will peak before 2020 and, by 2040, will be producing at a tiny fraction of their current levels. “[If] the future of U.S. oil and natural gas production depends on resources in the country's deep shale deposits, as the Energy Department contends, we are in for a big disappointment in the longer term," Hughes said in a press release.
The fundamental problem, Hughes explains, is the ephemeral nature of the average deep shale oil well, which declines in production by 83 percent after three years. This, Hughes explains, translates to an annual decline rate in the Bakken and Eagle Ford fields of over 40 percent. (The Bakken and Eagle Ford, he says, are not unique in this regard. All shale oil plays are afflicted with steep decline curves.)
To maintain production, oil producers must rapidly drill new wells to offset the decline. Last year, Hughes points out, drillers in North Dakota had to drill roughly 1,400 wells just to offset the Bakken’s steep losses and keep production flat from the previous year. Instead, oil producers punched 2,000 wells into the prairie. In essence, those "additional" 600 wells account for the Bakken's eye-popping production increases.
But the drilling frenzy cannot continue unabated. In addition to the high capital costs (about $8-$10 million per well, by most estimates), Hughes notes that nearly 9 out of every 10 barrels of oil produced in the Bakken comes from a relatively small “sweet spot,” comprising 4 of the 15 counties that make up the field. As drillers are forced into poorer sections of the play, production will inevitably dip, though the costs of drilling the wells will remain the same.
The new report follows another study Hughes released for Post Carbon last December. “Drilling California: A Reality Check,” refuted findings released in 2010 by the Energy Information Administration stating that California’s Monterey shale, an oil-bearing formation underlying a large portion of the Central Valley, contained as much as 15.4 billion barrels of oil. (For comparison, that is about four times the amount of oil the EIA projected for the Bakken in the same report.)
By taking a closer look at the EIA’s figures, Hughes traced the numbers back to Occidental Petroleum, one of the largest players in the Monterey shale. In addition to representing a possible conflict of interest, Hughes noted that the numbers simply didn’t compute. “My estimate of recoverable oil is less than 10 percent of what they were saying,” he told me.
At first, domestic energy boosters balked at Hughes’s findings. Then they scrambled to re-evaluate their own work. Within months of the release of his report, the EIA backtracked on its assessment, dropping its estimate in the Monterey from 15.4 billion to 500 million barrels – a downgrade of 95 percent.
In July, on assignment for High Country News, I had a chance to visit Hughes at his home on the remote and beautiful Cortes Island, off the western coast of British Columbia. We walked the island’s beaches and discussed his 32 years working for the Geological Survey of Canada, his work on U.S. shale resources, and what he sees as a future defined by energy scarcity. Keep an eye out for my profile of the data hound in an upcoming print issue.
Jeremy Miller is a contributing editor to High Country News. He writes from Northern California.
