Shale Sham in the Making

A very revealing article (ht to Brigitte) appeared on Foreign Policy In Focus (link) on January 10, “The Great Oil Swindle: Scaling the Peak of Fossil Fuel Scarcity,” by Nafeez Masaddeq Ahmed. In very abbreviated summary: (1) a rash of articles dismissing the reality of fossil fuel production peaking is misguided hype based on overstating shale resources and understating the costs of their recovery; (2) some studies projecting future supplies contain highly fudged data; (3) detailed data, some buried at the bottom of overly optimistic reports, show that Peak Oil is already upon us; (4) shale gas is turning out to be much more costly to produce; wells have a sharply dipping rate of productivity, in the range of 40 percent per annum; and (5) therefore a shale bust is developing while all the news is about the shale boom. Anyone following this subject closely should read the story. It is professionally done and full of revealing detail.

A look at shale as a resource, and the technology of its recovery, is presented on this blog here.

Shale Oil and Gas: The Years They Add

The real hot topic in energy these days is not wind or solar. It is shale. By way of an example, today’s New York Times carries a story titled “The Energy Picture, Redrawn.” The focus is on shale oil and on shale gas respectively. As is usual in such coverage, the broader context provided by current reserves and trends in consumption are not highlighted at all. The graphics suggest, instead, plenty of both for a long time to come.

By way of a useful footnote to news coverage, I’ve undertaken to calculate for you just how long current proven reserves will last and how much longer the fossil age will last assuming that projected shale reserves actually pan out.

Here is a graphic that tells the tale. After that I’ll tell you how I did it.

What we see here is that without exploitation of global shale oil reserves, oil will run out by 2037. If we succeed in exploiting all reserves of shale oil, we get another 44 years and the world runs out of oil in 2081. The same for natural gas. Current conventional world gas reserves now are seen to last longer (until 2048), but exploiting all shale gas will only extend gas use by 25 years, to 2073.

What I did was to assemble three categories data: (1) current reserve estimates; I chose the World Oil estimates (link) because they are the highest. On the oil side these already include some portions but not all Canadian tar sands—which are not part of the shale of projection. (2) I obtained shale oil reserves from this Wikipedia compilation and shale gas estimates from the Energy Information Administration (link). (3) I obtained oil and gas consumption estimates from the EIA (link, link). For oil I calculated the consumption growth trend from 1982 through 2008; I extended that trend into the future. The growth is at a rate of 1.4 percent a year in barrels. For gas, the EIA provided forward estimates out to 2035; the growth here is at a rate of 1.6 percent a year, measured in trillions of cubit feet. These I extended at the same rate into future years as well.

Having a projected consumption out through 2100, I calculated, first, how rapidly known reserves would be consumed. Next, I added shale reserves to current reserves and did the calculation once again. The results are charted above.

Part of the down-side of loudly cheering shale reserves is that it lets the public fall back into an easy slumber—of ignorance. Shale is not a long-term solution. First of all, both resources will cost a lot more to exploit than crude oil and natural gas. Exploitation will have huge environmental consequences. And current estimates may well be optimistic.

The next two graphics show the same relationships in quantitative forms, the first for oil, the second for gas.

Shale Hoopla — Careful!

A New York Times headline today says “Geologists Sharply Cut Estimate of Shale Gas.” The reference is to a press release by the U.S. Geological Survey (link) dated August 23, 2011. The first two paragraphs of that press release state:

The Marcellus Shale contains about 84 trillion cubic feet of undiscovered, technically recoverable natural gas and 3.4 billion barrels of undiscovered, technically recoverable natural gas liquids according to a new assessment by the U. S. Geological Survey (USGS).

These gas estimates are significantly more than the last USGS assessment of the Marcellus Shale in the Appalachian Basin in 2002, which estimated a mean of about 2 trillion cubic feet of gas (TCF) and 0.01 billion barrels of natural gas liquids.

This certainly sounds like a huge increase in shale gas estimates, indeed like an 82 TCF increase between 2002 and 2011. The same press release, however, actually references the 2002 report. And if you follow their link (here), you find the following text under Resource Summary:

The USGS assessed undiscovered conventional oil and gas and undiscovered continuous (unconventional) gas. The USGS estimated a mean of 70.2 trillion cubic feet of gas (TCFG), a mean of 54 million barrels of oil (MMBO), and a mean of 872 million barrels of total natural gas liquids (MMBNGL).

The 2 trillion in this year’s release has turned into 70.2 TCF. Was that “2 trillion” a typo. In the 2002 report, furthermore, a detailed table also repeats the numbers with many more decimal points. We still have an increase between 2002 and 2011, but it is an increase of 13.8 TCF not an increase of 82 TCF.

So why does the New York Times headline a sharp cut in shale gas estimates? Well, the Times points at a July 2011 report by the Energy Information Administration in which that agency shows shale gas reserves in the Marcellus Shale of 410 trillion cubic feet. The Times reporter then quotes an EIA official (Philip Budzik) saying that the EIA will sharply revise its estimate downward. The casual reader will wrongly conclude that the EIA has been grossly inflating its numbers and that Budzik, an operations research analyst—not an agency spokesman—knows what he is talking about. The article also mentions testimony by the EIA’s acting director, Howard K. Gruenspecht, defending the EIA’s methods before Congress this July; why wasn’t Gruenspecht interviewed?

The Times reporter might have read both the USGS and the EIA reports with a little more care. He would have discovered (1) that the USGS release actually reports a large increase, but in a subcategory of shale gas, clearly labeled “undiscovered, technically recoverable,” as shown above; (2) that the USGS release might contain an error, and (3) that in the EIA report, where that 410 trillion figure is shown, the EIA clearly states that that number includes 56 TCF of “undiscovered resources estimated by the USGS.” This means that the EIA was only counting a part (56 TCF) of the USGS’s now 84 TCF figure, not all of it, and that the 410 trillion includes a lot of other categories of shale gas (see the note on top of page 5 of the EIA report (link)). The conclusion is that Mr. Budzik might have misspoken and that EIA will probably increase rather than decrease its shale gas estimate in the future. Many a slip twixt journalism’s cup and lip. Alas, it is stories in the “newspaper of record” that build the hype that forms our precious public opinion.

You wonder where that Marcellus Shale region is? Well, here is a map of it, from the EIA’s 2011 report:

The Mystery of Rising Oil Reserves

On its web page showing world crude oil reserves (link), the Energy Information Administration shows a link to what it labels an Important Note. Here is that note in full:

Reserve estimates for oil, natural gas, and coal are very difficult to develop. The Energy Information Administration (EIA) develops estimates of reserves of oil, natural gas, and coal for the United States but does not attempt to develop estimates for foreign countries. As a convenience to the public, EIA makes available foreign fuel reserve estimates from other sources, but it does not certify these data. Please carefully note the sources of the data when using and citing estimates of foreign fuel reserves. [Typography as in the original.]

The note becomes significant when you look at the second table referenced there—the source of my data for the following graphic. A word or two about second chart I want to talk about. The curve on it shows total world crude reserves (1981-2009) in billions of barrels, right axis. The rest of the chart shows percent change in reserves in each of seven world regions. Thanks to some huge changes here and there, which is my actual focus today, these data are hard to see. To help you interpret the second chart better, I am first showing an enlargement of its first five years here:

In 1981 we have data for all regions except the Middle East; the Middle East neither added to nor lost reserves. The first blue bar is North America. Its reserves increased by 18.2 percent. The last region is Asia and Oceania; its reserves went up by 2 percent. Note that in 1982—and all following years, Eurasia’s reserves did not change; hence its bar is not visible. Notice that in 1983 the North American reserves registered a negative change; they fell 11.2 percent. Europe’s reserves declined by 7.3 percent. Identical data are shown in the second chart but for the period 1981-2009. Now for the second graphic. If you want to study the regions more closely, the link provided above will get you the data. Here I’m interested in the pattern, and especially unusual growth in selected years.

The most telling feature of this chart is that world reserves in actual barrels have had two major increases, the first in 1988-1990, the next in 2003. And going with these changes are a few large up-spikes in the regional estimates of proven reserves, along with smaller upticks. The BIG one, in 2003, is by North America. But when you look closer, you discover that the source of it is Canada. Between 2002 and 2003, Canada suddenly discovered 175 billion barrels of crude. Wow! Where was I in 2003 not to have heard the news? It must have fanned the globe like a wildfire! Or maybe I’d read the EIA’s Important Note already and just ignored the news? Something like that. In 2002 Canada had reserves of 4.9 billion barrels of crude. In 2003 it decided that its shale oil deposits ought to have some respect. They put them on the books officially. Now when I see the words “crude oil,” I think of gushers, wells, stuff that flows. I don’t think of rock. To see how far shale rock is from oil in your car, see this post here.

This then led me to investigate other interesting new spikes and up-ticks on this chart. They make you wonder. Indeed they cause you to want to read that EIA note again—wishing it said more. But international politeness causes EIA to murmur, almost inaudibly. Here then some annotations to the massive table from which the graph was wrought.

• Ticks in 1981-1982 in North America came from Mexico. It added 25.7 billion barrels to its reserves in those years. The North American dip in 1983 (see first table) was also a Mexican revision.
• In 1985, Kuwait improved its reserves in one year by 26 billion barrels.
• In 1988 Iraq (this is still Saddam Hussein’s time), discovered 52.9 billion barrels it had overlooked until then.
• That must have troubled the Saudis. In 1990 they upped their reserves by 85 billion barrels. Take that, Saddam!
• In 2003, alongside the Canadian miracle, Lithuania also kicked up its reserves 11.4 billion. I wonder if that’s also shale. I’ll have to look. Just did. Yes it is.
• In 2007, Kazakhstan found 21 billion, and I suspect some rocks there too, but I haven’t looked.
• The last notable discovery came in Venezuela, in 2009. The country upped its crude reserves by 14.2 billion barrels. Well, that one gives me a little less concern than the others—either that or paranoia is fatiguing.

In any case, thanks for that Important Note, EIA. Hard numbers are always hard to come by, but, as advertisers firmly believe, false hope is better than none. And based on that, folks, why should you worry? Reserves are going up, up, up—even as our draw down grows by ever mightier leaps every year. Up, up, and away! Deep sigh. Thank the Lord for those infinitely fertile wells.

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...

View a Map

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.