[Editors Note: This article was first published in 2005 in the US edition of the Daily Reckoning]
You wonât 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 youâll 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, youâll see the Book Cliffs geologic formation on your right. For miles and miles. Itâs a bleak landscape. Almost lunar. At first glance, itâs the kind of land youâd never want to explore, much less settle down in.
Oil Shale ReservesÂ : Americaâs Strategic Future
In the small world of geologists, though, the region is well-known. In fact, you might even say itâs the singleÂ most important patch of undeveloped, unloved, and desolate looking land in America. But youâd never guess this particular corner of the Great American Desert may play an integral role in Americaâs strategic future just by looking at it. Youâd 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 theÂ first white settlers found there, that tell you oilâs always been around the Rocky Mountains. Itâs justot always been easy to find. Itâs one thing to find oil that bubbles out of the ground in liquid form. Itâs 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 didnât 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 ReservesÂ : A Congressional Legacy
Most of the nationâs oil shale reserves rest under the control of the US government â 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 US Navy. Taft did so right away. The Navy was in the process of switching from coal burning ships to oil burning ships. And the US 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 US geared up for war with Japan and Germany.
Several of the oil fields set aside for the nationâs first strategic reserve, particularly Elk Hills in California,Â would go on to produce oil for the US 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. Thatâs 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.
âThe technical groundwork may be in place for a fundamental shift in oil shale economics,â the Rand Corporation recently declared. âAdvances 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.â
Estimated US oil shale reserves total an astonishing 1.5 trillion barrels of oil â or more than five times theÂ 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.
CanÂ Oil Shale Change The World?
America’s oil shale reserves are enormous, totalling at least 1.5Â trillion barrels of oil. Thatâs five times theÂ 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 goodÂ thing, weâd be doing it already, right? âOil shale is the fuel of the future, and always will be,â 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 US would instantly have the worldâs largest oil reserves. ImagineâŠhaving so much oil weâd 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.âs port to unload cheap Chinese goods, we might see oil tankers lined up waiting to export Americaâs tremendous oil bounty to the rest of the world. The entire geopolitical and economic map of the world would changeâŠand the companies in the vanguard of oil shale development might make hundreds of billions of dollars as they convert Americaâs 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 Westâs 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 US oil industry has lost nearly as many jobs in the last ten years as the automobile and steel industries.) And the energy locked in Coloradoâs vast shale deposits sat untouched and unrefined.
Oil Shale Technology â Old & New
Extracting oil from shaleÂ is no simple task. The earliest attempts to extract the oil utilized an environmentally unfriendly process known as âretorting.â 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:
âAfter 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).Â 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.Â 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?Â (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 âem.Â Yeah, right.Â I sure want that stuff blowinâ in my wind.)Â 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.â
But a new technology has emerged that may begin to tap the oil shaleâs 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 âin situâ mining, which heats the shale while itâs still in the ground, toÂ the point where the oil leaches from the rock. Shellâs Terry OâConnor described the breakthrough in testimony before Congress earlier this summer (And Congress may have an acute interest in the topic, since the US government controls 72% of all US oil shale acreage):
âSome 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 technologyâŠ
âMost 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.
âDuring 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 âcarbonâ in place in the subsurface.
âThe ICP process is clearly energy-intensive, as its driving force is the injection of heat into the subsurface.Â 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.
âHowever, 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.â
It may seem, as OâConner said, counter-intuitive to freeze the water around a shale deposit, and then heat up the contents within the deposit. Itâs energy-intensive. And itâs a lot of work. Whatâs more, thereâs 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 Bostonâs 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 OâConnerâs 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.
Itâs still early days in the oil shale fields of Colorado and Wyoming, but it looks to me like someoneâs gonna make a lot of money out there. Iâm working hard to discover how we outside investors can play along.
Shellâs Mahogany Ridge
Last week, I paid a visit to Royal Dutch Shellâs 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 realâŠor, at least, it soon will be.
After driving across a vast expanse of âNowhere,â Colorado, my brother and I met up with a few geologists from Shell. Of course itâs 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 isnât 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 doesnât know, or isnât 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, youâd 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 stickingÂ 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 doesnât know, or isnât saying, what the optimum size is for a each âpodâ or âcellâ. Thatâs what theyâll have to figure out at the next stageâŠand the picture with the dirt is a football field sized projectâŠ.where rather than creating the freeze-wall at 50 meters downâŠthey will do it at 1,000 ft. downâŠ. with 2,000 being the desired and necessary depth for commercial viability. Iâm not sure anyone has ever created a freeze-wall at that depthâŠ.neither is shell. But weâll find out. The oil itself that comes from the process looks likeâŠoil. 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, theyâre 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 acreâŠit wouldnât 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 Coloradoâs 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. Iâve 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, Shellâs in-situ process looks the mostÂ 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 keyÂ 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. Itâs going to take an external shock to the economy to really ratchet up interest and development of the nationâs energy reservesâŠsayâŠsomething like a nuclear Iran.
forÂ The Daily Reckoning