Shale Summary

We heard it yesterday in the context of President Obama’s speech on energy—so it will become a catch-phrase. Bet on it. “We are the Saudi Arabia of Shale.” If wishes were horses then beggars would ride—and if rock flowed like water we’d be the Saudis of shale. The happy claim turns out to be a numbers game. Saudi Arabia’s oil reserves are put at 267 billion barrels. Never mind that serious people doubt that. Over against that, the estimated crude oil potential of shale deposits in the United States would yield 800 billion barrels. I have this number from the Energy Information Administration, so it must be true.

Where is it? Our shale deposits are located in three states, Colorado, Utah, and Wyoming. The richest deposits are on Federal lands in Northern Colorado. If you drew a triangle with Casper Wyoming, Denver Colorado, and Salt Lake City, Utah at its points, you would more or less enclose the area. To see for yourself...

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That’s the superficial location—meant literally. The oil shale is deeper down. Deposits here start at 1,000 feet (three-football field lengths plus below). The best deposits are 2,000 below the surface (more than a third of a mile deep). For this reason two methods of getting the oil out are on offer: in situ and ex situ. The first means digging down and establishing a processing facility deep underground in a man-made cave. The other means conventional mining of ore, lifting it, moving it by trucks to a surface processing plant, and extracting oil on the surface.

As it happens, in situ is the better way. It yields more oil, requires no transport, and huge waste disposal operations are unnecessary. The downside is that that you have to preheat the mountain, as it were, for a period of 18 to 24 months before production can begin. Preheat how? It must be done by employing electrical resistance or radio waves.

What is it? Oil shale is rock, sedimentary rock to be precise. The inset shows that it looks like. (The source is Wikipedia here, and the object on the rock is a hammer.) The useful part of it is kerogen, the organic portion of such rock. When the kerogen portion is high in such rock, it is called oil shale. Another way to put it is that oil shale is future oil. Our crude oil was formed when these formations sank deep enough, to be heated high enough (140-320°F; water boils at 212°F) to yield their oil. The process must take place in an absence of oxygen. Not all but most of the kerogen turns into liquid oil or flammable gas.

The ratios of kerogen to mineral are an important aspect of shale. Share of kerogen per ton of shale ranges from 23 down to 13 percent, meaning that 77 to 87 percent is mineral waste. Another interesting fact about shale oil—never mentioned in political speech—is that its hydrogen to carbon ratio is lower than that of crude. Data from Estonia (here)—the world’s largest shale oil extractor— indicates that shale oil has 9.8 percent hydrogen versus Brent crude at 13.3 percent. Brent crude is a light, sweet variety. Crude has 1.4 times more hydrogen. Numbers from other sources tend to be in this range too. This means that shale oil must be hydrogenated—pure hydrogen must be obtained and added to it—before it is equivalent to, ah, Saudi oil. The best source for hydrogen is natural gas by steam reforming. This is another high-temperature process (1292-2012°F), thus adding to the energy needed to get energy out. Shale oil is also sulfurous (“sour,” in trade jargon), and its processing requires desulfurization.

What is its EROEI? Those letters stand for energy return on energy invested—tat for tit, you might say. Per Wikipedia’s summary here, a 1984 study put EROEI to between .7 and 13.3. Royal Dutch Shell’s research program, using electrical heating of the sort used in in situ operations, suggested 3 to 4. Conventional oil extraction yields 5 units for every unit expended. It isn’t clear whether these ratios include secondary refining processes like hydrogenation and desulfurization. Probably not.

Another source (here) cites recent studies of low EROEI for surface processing, less than 1.5 out for 1 unit of energy expended (2006, 2007) and 1.9 to 2.5 for in situ (2007). Canadian experience in tar sands processing is 2 to 4, but tar sands are easier to handle and less energy-intensive. The sand kernel is surrounded by water; the wet kernel is then surrounded by bituminous oil. Separating oil from water takes less energy than separating oil directly adhering to a mineral substrate.

Worth noting here is that, economics aside, a positive EROEI is all that is required. The return on crude is also dropping. It used to be 100 for 1. Now it is 5 or thereabouts—3 in the United States and 10 in Saudi Arabia. But, for these very reasons, some people doubt claims of 3 to 4 for shale—arguing that, in that case, shale would already be a booming business. But economics may not be put aside—and may explain the lack of a shale bubble now or in the near-term.

What are the Problems? Surface processing lowers yields and increases costs. Mining of large masses of rock from significant depth is required. The rock must be crushed. The heat process is pyrolysis, thus heating in the absence of oxygen, thus in tight containers. Waste containment (the residues are high in Arsenic) and disposal is a requirement. Water use is 2 to 10 gallons per ton of oil shale processed according to the Bureau of Land Management in surface extraction mining and retorting operations.

In situ processes required long lead times (that 2-year pre-heat period). Groundwater contamination is a serious problem.

Massive capital requirements are involved with, at present, not altogether predictable results. Publicly-owned, operated development is unimaginable in our political environment, and private money will stay away from this one until somebody else besides Estonia proves it to be big and very profitable. When that time comes our Lords of Industry will wrap themselves in white robes, bind their heads in white scarves, and head for the water spots in the Med. But I’m not holding my breath.

And now a footnote on problems. Here is the concluding paragraph of a brief EIA paper on the subject. Read this remembering that the very best deposits in the U.S. are on Colorado Federal lands:

In addition, current regulations of the U.S. Bureau of Land Management require that any mineral production activity on leased Federal lands also produce any secondary minerals found in the same deposit. On Federal oil shale lands, deposits of nahcolite (a naturally occurring form of sodium bicarbonate, or baking soda) are intermixed with the oil shales. Relative to oil and other petroleum products, nahcolite is a low-value commodity, and its price would fall even further if its production increased significantly. Thus, co-production of nahcolite could increase the cost of producing oil shale significantly, while providing little revenue in return.