Big Fracking Deal? Or No Fracking Way?

A new piece in Nature, published along with a thoughtful editorial comment, asks whether the great expectations for “100 years” of natural gas supplies might be overstated.

Not long ago I posted on how the Energy Information Agency’s projections for renewable energy have been consistently, laughably, off the mark.
The EIA is also the agency that makes the grandiose predictions for natural gas.

Just askin’…

Nature:

To provide rigorous and transparent forecasts of shale-gas production, a team of a dozen geoscientists, petroleum engineers and economists at the University of Texas at Austin has spent more than three years on a systematic set of studies of the major shale plays. The research was funded by a US$1.5-million grant from the Alfred P. Sloan Foundation in New York City, and has been appearing gradually in academic journals^{1, 2, 3, 4, 5} and conference presentations. That work is the “most authoritative” in this area so far, says Weijermars.

If natural-gas prices were to follow the scenario that the EIA used in its 2014 annual report, the Texas team forecasts that production from the big four plays would peak in 2020, and decline from then on. By 2030, these plays would be producing only about half as much as in the EIA’s reference case. Even the agency’s most conservative scenarios seem to be higher than the Texas team’s forecasts. “Obviously they do not agree very well with the EIA results,” says Patzek.

The main difference between the Texas and EIA forecasts may come down to how fine-grained each assessment is. The EIA breaks up each shale play by county, calculating an average well productivity for that area. But counties often cover more than 1,000 square kilometres, large enough to hold thousands of horizontal fracked wells. The Texas team, by contrast, splits each play into blocks of one square mile (2.6 square kilometres) — a resolution at least 20 times finer than the EIA’s.

Resolution matters because each play has sweet spots that yield a lot of gas, and large areas where wells are less productive. Companies try to target the sweet spots first, so wells drilled in the future may be less productive than current ones. The EIA’s model so far has assumed that future wells will be at least as productive as past wells in the same county. But this approach, Patzek argues, “leads to results that are way too optimistic”.

The high resolution of the Texas studies allows their model to distinguish the sweet spots from the marginal areas. As a result, says study co-leader Scott Tinker, a geoscientist at the University of Texas at Austin, “we’ve been able to say, better than in the past, what a future well would look like”.

The Texas and EIA studies also differ in how they estimate the total number of wells that could be economically drilled in each play. The EIA does not explicitly state that number, but its analysis seems to require more wells than the Texas assessment, which excludes areas where drilling would be difficult, such as under lakes or major cities. These features of the model were chosen to “mimic reality”, Tinker says, and were based on team members’ long experience in the petroleum industry.

Nature Editorial:

The EIA projects that production will rise by more than 50% over the next quarter of a century, and perhaps beyond, with shale formations supplying much of that increase. But such optimism contrasts with forecasts developed by a team of specialists at the University of Texas, which is analysing the geological conditions using data at much higher resolution than the EIA’s. The Texas team projects that gas production from four of the most productive formations will peak in the coming years and then quickly decline. If that pattern holds for other formations that the team has not yet analysed, it could mean much less natural gas in the United States’ future.

Like all energy forecasts, the lower projections from the Texas team could turn out to be inaccurate. Technological advances in the next few decades could open up more resources at lower costs, driving US production even higher than the EIA has predicted. But it is also possible that the Texas forecasts are too high, and that gas production will fall off even faster than the team suggests.

I’ve posted in the past about the internal contradictions of the fracking industry, which is looking more and more like a classic bubble.

Like fracking for  natural gas, the oil shale revolution of the last decade has relied on expensive technology to crack, squeeze and/or cook petroleum out of difficult to reach deposits.  Both of these industries rely on certain price assumptions for their  future profitability.

USAToday:

Surging oil and gas production is nudging the nation closer to energy independence. But new research suggests the boom could peter out long before the United States reaches this decades-old goal.

Many wells behind the energy gush are quickly losing productivity, and some areas could hit peak levels sooner than the U.S. government expects, according to analyses presented last week at a Geological Society of America meeting in Denver.

“It’s a temporary bonanza,” says J. David Hughes, an energy expert at the Post Carbon Institute, a research group focused on sustainability. He studied two of the nation’s largest shale rock formations, now the source of huge amounts of oil and gas, and said they could start declining as early as 2016 or 2017.

The reason: “sweet spots” — small areas with the highest yields. Hughes says these spots simply don’t last long. Unless more wells are drilled, the Bakken shale of North Dakota and Montana loses 44% of its production after a year and the Eagle Ford shale of Texas, 34%. Most of the nation’s major shale regions produce both oil and gas.

“You have to keep drilling more and more just to maintain production,” says Hughes, adding this can become too costly to be profitable. He notes oil production in the Bakken, which skyrocketed between 2008 and 2012, has already started to slow down and Eagle’s Ford may soon follow. The U.S. Energy Information Administration (EIA) projects both shale plays will hit their oil peak in 2020, declining afterward.

The article goes on to quote Charles Hall – who was also a speaker at the conference.

Taking a similarly pessimistic view is Charles Hall, professor at the State University of New York, Syracuse and author of Energy and the Wealth of Nations. His analysis of Bakken production, now accounting for nearly a third of all U.S. oil from shale, found almost all its oil comes from just a few “sweet spots.” He also cited EIA data that show gas production has been falling since mid-2012 in the Barnett of Texas and the Haynesville of Texas and Louisiana.

Business Week:

Chesapeake Energy’s (CHK) Serenity 1-3H well near Oklahoma City came in as a gusher in 2009, pumping more than 1,200 barrels of oil a day and kicking off a rush to drill that extended into Kansas. Now the well produces less than 100 barrels a day, state records show. Serenity’s swift decline sheds light on a dirty secret of the oil boom: It may not last. Shale wells start strong and fade fast, and producers are drilling at a breakneck pace to hold output steady. In the fields, this incessant need to drill is known as the Red Queen, after the character in Through the Looking-Glass who tells Alice, “It takes all the running you can do, to keep in the same place.”

The U.S. is producing 7.8 million barrels of oil a day, more than it has in a quarter-century. Crude from shale formations has cut reliance on imports and put the U.S. closer to energy independence than it’s been since 1989. The International Energy Agency predicted last year that the U.S. would overtake Saudi Arabia by 2020 as the world’s largest producer.

Whether current production can hold up is the subject of debate. David Hughes, a geoscientist and president of Global Sustainability Research, has examined the life span of shale wells. “The Red Queen syndrome just gets worse and worse and worse,” he says. “The higher production goes, the more wells you need to offset the decline.”

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In North Dakota’s Bakken shale, a well formally known as Robert Heuer 1-17R put out 2,358 barrels in May 2004, when it went live. The output proved there was money to be made drilling in the Bakken and kicked off an oil rush in North Dakota. Continental Resources (CLR), the well’s operator, built a monument to it. Production declined 69 percent in the first year. “I look at shale as more of a retirement party than a revolution,” says Art Berman, a petroleum geologist who spent 20 years with what was then Amoco and now runs his own firm, Labyrinth Consulting Services, in Sugar Land, Tex. “It’s the last gasp.”

The Telegraph:

The rise of US shale is similar to the dotcom boom of the late Nineties and will cause many companies to fail, one of Russia’s top oil executives has warned.

Leonid Fedun, vice-president of Lukoil, Russia’s second-largest oil producer, believes that with the price of Brent crude and WTI at multi-year lows, fracking companies will struggle to make fracking profitable.

These fears were given extra weight on Thursday after Opec’s members agreed to leave oil production quotas unchanged, sending oil prices plummeting.

Some believe Opec, which controls the majority of the world’s oil output, is threatened by the emergence of US shale and is trying to force many American drilling companies out of business.

“In 2016, when Opec completes this objective of cleaning up the American marginal market, the oil price will start growing again,” Mr Fedun told Bloomberg.