Oil Shale Reserves: Stinky Water, Sweet Oil
A Daily Reckoning White Paper Report
By Dan Denning

You won’t think much of Rio Blanco County if you ever drive through it. In fact, unless you take a right turn off Interstate-70 West at Rifle, head north on Railroad Avenue and then west on Government road to Colorado state highway number thirteen, odds are you’ll never even step foot in Rio Blanco County.

But even if you keep heading west toward Grand Junction, through the town of Parachute and the shuttered oil shale refineries from the 1970s, you’ll see the Book Cliffs geologic formation on your right. For miles and miles. It’s a bleak landscape. Almost lunar. At first glance, it’s the kind of land you’d never want to explore, much less settle down in.

Oil Shale Reserves : America’s Strategic Future

In the small world of geologists, though, the region is well-known. In fact, you might even say it’s the single
most important patch of undeveloped, unloved, and desolate looking land in America. But you’d never guess this particular corner of the Great American Desert may play an integral role in America’s strategic future just by looking at it. You’d never guess that the whole stretch of brown, red, and orange land contains enough recoverable oil and gas to make you forget about the Middle East for the rest of time.

There are places in Rio Blanco County like Stinking Water Creek, named after the smelly mix of oil and water the first white settlers found there, that tell you oil’s always been around the Rocky Mountains. It’s just not always been easy to find. It’s one thing to find oil that bubbles out of the ground in liquid form. It’s quite another to drill a thousand feet down, and encounter oil locked up tight inside a greasy rock.

The first seeping pools of oil were discovered in Western Colorado as far back as 1876, the year the state entered the Union. But exploration didn’t get serious until drillers settled in the town of Rangely in Rio Blanco County.

By 1903, thirteen different drillers had come and gone in Rangely. According to the local museum, the only six wells that actually struck oil were producing just two to ten barrels of oil a day. Hardly a Spindeltop, the gusher that launched the Texas oil-boom on January 10th, 1901, and immediately began producing 100,000 barrels per day.

The energy reserves of the Piceance Basin, upon which Rio Blanco County sits, contain massive petroleum reserves of a very unusual nature: Oil shale.

Oil Shale Reserves : A Congressional Legacy

Most of the nation’s oil shale reserves rest under the control of the U.S. government – a legacy of a 95-year old Congressional Act. In 1910, Congress passed the Pickett Act, which authorized President Taft to set aside oil- bearing land in California and Wyoming as potential sources of fuel for the U.S. Navy. Taft did so right away. The Navy was in the process of switching from coal burning ships to oil burning ships. And the U.S. military, conscious of the expanding role of America in the world, needed a dependable supply of fuel in case of a national emergency.

From 1910 to 1925 the Navy developed the Naval Petroleum and Oil Shale Reserves Program. The program became official in 1927 and President Roosevelt even expanded the scope of the program in 1942 as the U.S. geared up for war with Japan and Germany.

Several of the oil fields set aside for the nation’s first strategic reserve, particularly Elk Hills in California,
would go on to produce oil for the U.S. government. Elk Hills was eventually sold off to Occidental Petroleum for $3.65 billion in 1998 in the largest privatization in U.S. history. The shale reserves, however, still remain, locked 1,000 feet underground in the Colorado desert.

Unlocking The Future

The destruction of Hurricane Katrina shows the importance of a strategic petroleum reserve, or, more accurately, a strategic energy reserve. But the SPR in Louisiana only holds about 800 million barrels of emergency, enough to get the country through about 90 days of regular oil usage. That’s barely a band-aid for a country that faces a potential energy heart attack.

In other words, the future of oil shale may have finally arrived. Extracting oil from shale is no simple task, which is why the reserves remain almost completely undeveloped. But an emerging new technology promises to unlock the awesome potential of the oil shale.

“The technical groundwork may be in place for a fundamental shift in oil shale economics,” the Rand Corporation recently declared. “Advances in thermally conductive in-situ conversion may enable shale-derived oil to be competitive with crude oil at prices below $40 per barrel. If this becomes the case, oil shale development may soon occupy a very prominent position in the national energy agenda.”

Estimated U.S. oil shale reserves total an astonishing 1.5 trillion barrels of oil – or more than five times the
stated reserves of Saudi Arabia. This energy bounty is simply too large to ignore any longer, assuming that the reserves are economically viable. And yet, oil shale lies far from the radar screen of most investors.

But we here at The Daily Reckoning are on the case. Just yesterday, I caught a first-hand glimpse of a cutting-edge oil shale project spearheaded by Shell. I trekked out to a barren moonscape in Colorado to tour the facility with Shell geologists. To summarize my findings, oil shale holds tremendous promise, but the technologies that promise to unlock this promise remain somewhat experimental. But sooner or later, the oil trapped in the shale of Colorado will flow to the surface. And when it does, it will enrich investors who arrive early to the scene.

Can Oil Shale Change The World?

America’s oil shale reserves are enormous, totaling at least 1.5 trillion barrels of oil. That’s five times the
reserves of Saudi Arabia! And yet, no one is producing commercial quantities of oil from these vast deposits. All that oil is still sitting right where God left it, buried under the vast landscapes of Colorado and Wyoming.

Obviously, there are some very real obstacles to oil production from shale. After all, if it was such a good
thing, we’d be doing it already, right? “Oil shale is the fuel of the future, and always will be,” goes a popular
saying in Western Colorado.

But what if we could safely and economically get our hands on all that oil? Imagine how the world might change. The U.S. would instantly have the world’s largest oil reserves. Imagine…having so much oil we’d never have to worry about Saudi Arabia again, or Hugo Chavez, or the mullahs in Tehran. And instead of ships lined up in L.A.’s port to unload cheap Chinese goods, we might see oil tankers lined up waiting to export America’s tremendous oil bounty to the rest of the world. The entire geopolitical and economic map of the world would change…and the companies in the vanguard of oil shale development might make hundreds of billions of dollars as they convert America’s untapped shale reserves into a brand new energy revolution.

Presidents Gerald Ford and Jimmy Carter may have been entertaining similar ambitions in the late 1970s when they encouraged and funded the development of the West’s shale deposits. A shale-boom ensued, although not much oil flowed. The government spent billions and so did Exxon Mobil. New boomtowns sprung up in Rifle, Parachute, Rangely, and Meeker here in Colorado.

And then came Black Monday. May 2, 1982. The day Exxon shut down its $5 billion Colony Oil Shale project. The refineries closed. The jobs left (the American oil industry has lost nearly as many jobs in the last ten years as the automobile and steel industries.) And the energy locked in Colorado’s vast shale deposits sat untouched and unrefined.

Oil Shale Technology – Old & New

Extracting oil from the shale is no simple task. The earliest attempts to extract the oil utilized an environmentally unfriendly process known as “retorting.” Stated simply, retorting required mining the shale, hauling it to a processing facility that crushed the rock into small chunks, then extracted a petroleum substance called kerogen, then upgraded the kerogen through a process of hydrogenation (which requires lots of water) and refined it into gasoline or jet fuel.

But the difficulties of retorting do not end there, as my colleague, Byron King explains:

“After you retort the rock to derive the kerogen (not oil), the heating process has desiccated the shale (OK, that means that it is dried out). Sad to say, the volume of desiccated shale that you have to dispose of is now greater than that of the hole from which you dug and mined it in the first place. Any takers for trainloads of dried, dusty, gunky shale residue, rife with low levels of heavy metal residue and other toxic, but now chemically-activated crap? (Well, it makes for enough crap that when it rains, the toxic stuff will leach out and contaminate all of the water supplies to which gravity can reach, which is essentially all of ‘em. Yeah, right. I sure want that stuff blowin’ in my wind.) Add up all of the capital investment to build the retorting mechanisms, cost of energy required, cost of water, costs of transport, costs of environmental compliance, costs of refining, and you have some relatively costly end-product.”

But a new technology has emerged that may begin to tap the oil shale’s potential. Royal Dutch Shell, in fact, has recently completed a demonstration project (The Mahogany Ridge project) in which it produced 1,400 barrels of oil from shale in the ground, without mining the shale at all.

Instead, Shell utilized a process called “in situ” mining, which heats the shale while it’s still in the ground, to
the point where the oil leaches from the rock. Shell’s Terry O’Connor described the breakthrough in testimony before Congress earlier this summer (And Congress may have an acute interest in the topic, since the U.S. government controls 72% of all U.S. oil shale acreage):

“Some 23 years ago, Shell commenced laboratory and field research on a promising in ground conversion and recovery process. This technology is called the In-situ Conversion Process, or ICP. In 1996, Shell successfully carried out its first small field test on its privately owned Mahogany property in Rio Blanco County, Colorado some 200 miles west of Denver. Since then, Shell has carried out four additional related field tests at nearby sites. The most recent test was carried out over the past several months and produced in excess of 1,400 barrels of light oil plus associated gas from a very small test plot using the ICP technology…

“Most of the petroleum products we consume today are derived from conventional oil fields that produce oil and gas that have been naturally matured in the subsurface by being subjected to heat and pressure over very long periods of time. In general terms, the In-situ Conversion Process (ICP) accelerates this natural process of oil and gas maturation by literally tens of millions of years. This is accomplished by slow sub-surface heating of petroleum source rock containing kerogen, the precursor to oil and gas. This acceleration of natural processes is achieved by drilling holes into the resource, inserting electric resistance heaters into those heater holes and heating the subsurface to around 650-700F, over a 3 to 4 year period.

“During this time, very dense oil and gas is expelled from the kerogen and undergoes a series of changes. These changes include the shearing of lighter components from the dense carbon compounds, concentration of available hydrogen into these lighter compounds, and changing of phase of those lighter, more hydrogen rich compounds from liquid to gas. In gaseous phase, these lighter fractions are now far more mobile and can move in the subsurface through existing or induced fractures to conventional producing wells from which they are brought to the surface. The process results in the production of about 65 to 70% of the original “carbon” in place in the subsurface.

“The ICP process is clearly energy-intensive, as its driving force is the injection of heat into the subsurface.
However, for each unit of energy used to generate power to provide heat for the ICP process, when calculated on a life cycle basis, about 3.5 units of energy are produced and treated for sales to the consumer market. This energy efficiency compares favorably with many conventional heavy oil fields that for decades have used steam injection to help coax more oil out of the reservoir. The produced hydrocarbon mix is very different from traditional crude oils. It is much lighter and contains almost no heavy ends.

“However, because the ICP process occurs below ground, special care must be taken to keep the products of the process from escaping into groundwater flows. Shell has adapted a long recognized and established mining and construction ice wall technology to isolate the active ICP area and thus accomplish these objectives and to safe guard the environment. For years, freezing of groundwater to form a subsurface ice barrier has been used to isolate areas being tunneled and to reduce natural water flows into mines. Shell has successfully tested the freezing technology and determined that the development of a freeze wall prevents the loss of contaminants from the heated zone.”

It may seem, as O’Conner said, counter-intuitive to freeze the water around a shale deposit, and then heat up the contents within the deposit. It’s energy-intensive. And it’s a lot of work. What’s more, there’s no proof yet it can work on a commercial scale.

Yet both technologies, the freeze wall and the heating of shale, have been proven in the field to work. The freeze wall was used most recently in Boston’s Big Dig project. It was also used to prevent ground water from seeping into the salt caverns at the Strategic Petroleum reserve in Weeks Island, LA.

But still, you may be wondering, does it really make sense to heat the ground up a thousand feet down for three or four years and wait? Of course it does. In case you missed O’Conner’s math, Shell could harvest up to a million barrels per acre, or a billion barrels per square mile, on an area covering over a thousand square miles.

It’s still early days in the oil shale fields of Colorado and Wyoming, but it looks to me like someone’s gonna make a lot of money out there. I’m working hard to discover how we outside investors can play along.

Shell’s Mahogany Ridge

Last week, I paid a visit to Royal Dutch Shell’s oil shale project in Colorado. The visit left me with more questions than answers, but I came away from the place with the sense that this opportunity is very real…or, at least, it soon will be.

After driving across a vast expanse of “Nowhere,” Colorado, my brother and I met up with a few geologists from Shell. Of course it’s just those large, unpopulated tracts of high desert that make the area so appealing from a geopolitical point of view. Tapping into the oil shale 2,000 feet underground isn’t going to bother too many people. And there are no spotted owls around either. If the technology to turn shale into oil works, the entire area will become a new American boom patch.

Soon after we arrived, the geologists escorted us around the facility, chatting all the while about the successes and challenges of their venture.

The two trickiest aspects of oil shale development, as the geologists and engineers explained, are heating the shale to extreme temperatures, while simultaneously surrounding the heated area with a subterranean ice wall. Shell doesn’t know, or isn’t saying, which part of the project will be the most challenging. If you were about to change the world by making it economic to tap into as much as 2 trillion barrels of oil under the Colorado plateau, you’d be pretty careful about showing your competitors how you were going to do it.

First, anything that heats up rock around it to around 600 or 700 degrees Fahrenheit has to conduct electrically generated heat well. The most conductive metals on the Periodic Table of Elements are, in order, silver, copper, and gold. Naturally, the number of heaters you put in a place affects the amount of time it takes to turn the shale goo into API 34 crude. The more heaters, the more cost, though.

And given the fact that Shell does not know yet if the heaters will be recoverable, you can see that sticking
silver, copper, or gold heaters 2000 meters underground and then leaving them there once the kerogen has been pumped has a serious effect on the economics of your operation.

At the moment, Shell is not sure what the optimal size of production zones ought to be. The big issue here is how big can a freeze-wall be to be effective and freezing the groundwater surrounding a shale deposit? The test projects, as you can see, were quite small. Shell doesn’t know, or isn’t saying, what the optimum size is for a each “pod” or “cell”. That’s what they’ll have to figure out at the next stage…and the picture with the dirt is a football field sized project….where rather than creating the freeze-wall at 50 meters down…they will do it at 1,000 ft. down…. with 2,000 being the desired and necessary depth for commercial viability. I’m not sure anyone has ever created a freeze-wall at that depth….neither is shell. But we’ll find out. The oil itself that comes from the process looks like…oil. No heavy refining needed.

Shell thinks the whole thing is economic at a crude price of $30. So barring a major reversal of geopolitical trends, they’re forging ahead.

Since the Bureau of Land Management owns about 80% of the oil shale acreage in Colorado, there is no investment play on private companies that might own land with rich shale deposits. Although, if Shell and the DOE are right that you can recover a million barrels of oil per acre…it wouldn’t take much land to make a man rich out here.

Oil Shale: Testing Public Lands

The Bureau of Land Management recently received ten applications (by eight companies) for a pilot program to develop Colorado’s shale reserves. The program allows the companies access to public lands for the purpose of testing shale-extraction technologies. You see below an interesting mix of large, publicly traded oil giants and small, privately held innovators.

• Natural Soda, Inc. of Rifle, Colorado.
• EGL Resources Inc. of Midland, Texas.
• Salt Lake City-based Kennecott Exploration Company.
• Independent Energy Partners of Denver, Colorado
• Denver-based Phoenix Wyoming, Inc.
• Chevron Shale Oil Company.
• Exxon Mobil Corporation.
• Shell Frontier Oil and Gas Inc

There is dispute within the industry over how long, if ever, demonstration extraction technologies can become commercially viable. I’ve spoken with some of the smaller companies that have applied for leases from the BLM. Some of them will have to raise money to conduct the project. And some of them have been less than forthcoming about how exactly their extraction technology is different or better than previous methods.

How will it all unfold? Well, for starters, it could all utterly fail. To me, Shell’s in-situ process looks the most
promising. It also makes the most sense economically. There may be a better, less energy-intensive way to heat up the ground than what Shell has come up with. But Shell, Chevron, and Exxon Mobil clearly have the resources to scoop up any private or small firm that makes a breakthrough.

And there are a host of smaller firms involved with the refining and drilling process that figure to play a key
role in the development of the industry, should that development pick up pace.

The Energy Policy Act of 2005, otherwise known as a listless piece of legislation without any strategic vision, does, at least, make provision for encouraging research into the development of shale. But government works slow, when it works at all. It’s going to take an external shock to the economy to really ratchet up interest and development of the nation’s energy reserves…say…something like a nuclear Iran.

Dan Denning
for The Daily Reckoning

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