An update on fuels from shale, and The Giant Toaster

This afternoon I was able to drop in on a talk by Jeremy Boak, who runs the Center for Oil Shale Technology and_Research (COSTAR) in Golden. He was speaking to the topic of “Finding Billions in Ancient Mud? Shale gas, shale-hosted oil and oil shale.” It is likely to become an increasingly contentious subject over the next few years as oil prices go higher, and the availability of the oils, kerogens and gases within the shales of the world become more economically viable. Jeremy drew attention to the annual Oil Shale Symposia that he has recently been chairing at Colorado School of Mines and which run each year. He provided the site where the papers from the last four of these Symposia are freely available. (The 29th, 28th, 27th and 26th Symposia, papers from the 30th, held in October, have not yet been posted).

His talk began with a review of the geology and the reality of the definition of the deposits – he quoted Walter Youngquist

"Bankers won’t invest a dime in organic mudstone, but find oil shale an entirely different matter.”

And then pointed out why the proper name is the mudstone, but that the MSM and bankers and those seeing their interest have been quite willing to allow the name change. Looking at numbers of around 1.5 trillion barrels of kerogen in the shales of Colorado, about 1.3 trillion in Utah, and 1.3 trillion in Wyoming, gives the United States in those states alone about 4 trillion barrels of oil. None of which, at present is being produced in any significant volume. However he noted that a production rate of 3 mbd is equivalent to a billion barrels a year (i.e. the current world production of around 87 mbd would be around 29 billion barrels a year). And a billion barrels is about the quantity of kerogen that can be found in one square mile of the basin. Normally reserves are only considered if the organic carbon content is about 30% (or roughly 70 gallons/ton).

The only places that are producing oil from the shale are currently in Estonia (with about 8,000 barrels a day); Brazil with about 4,000 barrels a day (bd), and China which is producing about 10,000 bd. However he also noted that China is building about 100 retorts a year to convert the kerogen to oil on the surface, and these retorts are located around China near significant deposits. (Typically the shale must be heated to over 300 degC before the kerogen will turn to oil, and be released from the rock – though the product of this treatment is generally thicker and quite heavy).

The potential for the continued production of liquid fossil fuels is encouraging other countries to take a serious look at developing their own resources. He cited Jordan, which is estimated to have 100 billion barrels, and testing is now going on in Morocco. However he cautioned that production levels would not rise rapidly and this could not be accepted, in the short term, as the answer to the coming shortages. He provided the following predictive plot (which I copied from an earlier talk), showing over a 60 year period the early development of conventional oil in the US against that of the tar sands of Canada, and the oil shales of the US.

(From Boak)

The hottest developments however are not in shale oil, but rather in shale gas. The most active search for which appears, at the moment to be in Poland. Conoco Phillips has apparently drilled two wells and is looking at a third, with over 900,000 acres now being leased. Not that the road to success in that county is predicted to be easy.

The talk moved on to describe the technological breakthroughs that have made oil and gas recovery from these shales possible. While part of this has been the ability to drill long horizontal holes, which is of relatively recent origin, the evolution of the multi-stage fracking process to put a multiplicity of cracks out from the well into the reservoir has been the real key. And hydrofracking has been developing and evolving for over 50 years.

It is that hydrofracking that has led to one of the more interesting novel approaches being developed by Exxon Mobil now in Colorado. While officially this is known as the Electro-frac process, almost everyone now is calling it the Giant Toaster.


Moving one step beyond the conventional horizontal drill, and then fracking of the rock, in the oil shale the fractures will be filled with a conductive material, so that, after the pressure is removed and the crack partially closes, the pressure squeezes this proppant , calcined coke and Portland cement, together to form a conductive sheet. By passing current through this (as in your toaster) the surrounding rock can slowly be brought up to temperature and then cooked slowly to transform the kerogen to oil.

Exxon Mobil are encouraged in this by the results that Shell have reported for their in-situ retorting (which I described in my series on oil shale – which are listed on the right hand side at the top of the BTE site). As I noted on the future of oil shale when Shell carried out their slow heating of the oil shale in-situ they were able to draw off a clear, golden oil which could easily be separated into gasoline, jet fuel and diesel.

The updates on the Exxon Mobil process show that they have been able to load the conductive material into the fractures as planned, and have been able to then run current through the material and heat the rock. They have not yet done the sustained higher temperature heating that will be required for full transition of the kerogen.

The Exxon-Mobil process has the benefit of being able to move the fractures further apart to some 125 ft spacing, over the 25 ft planned for the field tests of the Shell process.

The Future of Oil Shale

I have spent some time over the past few weeks writing about various different ways of producing oil from oil shale. While it is now about time that I move on to other topics, David Hagen was kind enough to post the website that gives access to the presentations from the Oil Shale Symposia that I mentioned at the beginning of this mini-series.

The papers from the 28th Symposium in 2008 illustrate that while the current price of oil may not currently justify the development of large oil shale operations, it can justify the investment of research dollars to seek better ways of producing oil from these fields. This is particularly true if one accepts one of the criteria that Exxon used to justify their ongoing interest, namely that they project that world energy demand will be 40% higher in 2030 than today, with more than 80% of that energy still being supplied by fossil fuels. Exxon believes that the oil from oil shale will play a significant role in that supply.

And so I am going to skip lightly through the papers, and highlight anything that catches my eye.

Exxon Mobil, for example, are looking into Electrofracking the shale. The idea of using electrical power directly to break rock has been around for some time. Erich Sarapuu wrote his doctoral dissertation on this in the 60’s as I recall, unfortunately before the internet made it easy to find much information, though he went on to form Electrofrac Corp. And there have been more recent papers. However it appears that by putting electrically conductive materials into the fractures and passing current through them, Exxon Mobil both limits the surface footprint, and the amount of material that has to be heated to achieve the transformation of the kerogen. Higher rock stress can apparently also lighten the oil produced, based on lab tests. Since the time of the Symposium, Exxon Mobil has run a successful field test at their Colony Mine site. but has been quoted as commenting:

ExxonMobil sees tantalizing prospects for shale: up to 162,000 barrels of oil per surface acre at a 50 percent recovery rate. The results suggest a 3-to-1 ratio of energy recovered over energy expended to obtain it, McGinn said...It appears ExxonMobil can make its process work using about 1.5 barrels of water for each barrel of oil produced, he said.
Even under the most optimistic of scenarios, ExxonMobil sees no production coming from oil shale for 10 to 24 years, McGinn said.

Exxon Mobil plan for oil production from oil shale

Shell have also reported that the ground conditions can change the quality of the oil produced, and that slower heating increases oil quality, while higher pressures increase the hydrogen content of the oil. Field tests confirmed the lab information. (And for those who wondered about the ability to make jet fuel from oil shale, they also added this table:

Jet fuel from oil shale (Courtesy of Shell and DoD) (the table has additional pages)

In contrast Chevron has looked at sending hot gases that are surface generated down and through induced fractures:

Chevron concept for oil shale development (NETL )

The U.S. Bureau of Mines did look at fragmenting the oil shale beds in place and then igniting them for an in-situ variation on the Ecoshale process I described last time (in the sense that the shale is heated within a geological retort).

Bureau of Mines test at Rock Springs (NETL )

And I have previously written about the paper on the ground freezing test that Shell has carried out:

Shell freezing test

There is work being done by Total (who slipped in a comment that oil supply may peak before 2015. They see the world potential supply from oil shale as being measured in trillions of barrels of oil. They are collaborating with Petrobras in surface retorting programs and along with other companies encouraged by the Jordanian government evaluating deposits in Jordan, which is also examining microwave heating and Morocco. They are collaborating with Independent Energy Partner on geothermal fuel cells for in-situ heating and looking at downhole radio-frequency heating. There has been a subsequent paper on the Moroccan oil shale development.

The use of radio frequency heating was described, with the Bechtel/Parsons conclusion that the process could yield an EROI of greater than 3. And the potential for using wind energy to power the microwaves was advanced.

The program being developed by EGL where the heating is supplied around the outside of a series of wells was also included.

Representation of the EGL plan

There is a report available on unconventional fuels that looks at oil shale, transmitted in December 2008. There was also, from August of that year, a complimentary list of companies carrying out research into oil shale and tar sands.

The Power Engineering Institute in Moscow discussed some of the work being done in Russia on both their deposits and those in other parts of the world. The Narva thermal refinery in Estonia has, for example, increased production to over a million barrels exporting about 40% of the product. The plant uses ash as a pre-heating step, and used automobile tires as part of the feed stock. A better list of some of the oil shale projects can be found at the Oil Shale Association.

One thing is clear from perusing both the Proceedings and the additional papers that I have chased up to try and update some of the information. The Oil Shale resource around the world will become an increasingly viable one as the price and availability of conventional oil become more of a strain on the world and individual nations. This is being recognized by countries such as Jordan, China and, Thailand. Plans range from continued examinations of more exotic methods for oil recovery, to the more conventional mining and surface retorting. The level of activity appears to be rising again, and thus while the continuous posting on the topic will now halt, I will come back to the subject intermittently in the future. It is a comment on the perceived future scarcity of conventional oil, that this subject is receiving so much attention.

Using heat to refine kerogen from oil shale

One of the problems with the oil (kerogen) in oil shale is that it is not mature enough (i.e. close enough to being an oil) that it will easily flow through the rock. In earlier parts of this particular theme I have written about mining the rock and then heating it in retorts as a way of transforming the kerogen and recovering it for use. I have also, somewhat tongue in cheek, discussed using nuclear weapons to heat the rock so that the transformation can take place without moving the rock, while breaking the rock at the same time, and the unlikely potential for burning some of the oil within the deposit to power the transformation of the rest. While it might work in a heavy oil sand, is not likely to be realistically practical for the finer grained shales. But there are ways of adding somewhat less heat to the rock than using a nuclear bomb, and that will be the topic for today.

This is a continuation of the technical posts that I usually write on Sundays, but I am trying to catch up after the eye problem, and so will try and get the last one or two posts on the immediate topic of oil shale up within the next week, before moving on to a new set of subjects..

While I am largely going to bypass the use of nuclear power (apart from that of providing electrical power) in this piece, the potential use of nuclear power to heat penetrators that allow rapid drilling of weak rock has been partially demonstrated. As I have mentioned previously , Los Alamos National Lab, in looking at different methods for drilling, had come up with the idea of using a small nuclear reactor to provide sufficient heat to a ceramic probe that it would melt its way into the ground, pushing the molten rock to one side, and providing a glass lining to the resulting tunnel.

By the way, this has not been used to create the network of tunnels under this country in an idea beloved of some, it has been demonstrated. Not with a nuclear source, but with more conventional heating, Los Alamos drilled drainage holes at the Tyuoni pueblo plaza for drainage in 1973. A total of eight drainage holes were drilled at this archeological site in the Bandelier National Monument.

The first significant step in the Subterrene technology transfer program occurred when eight water drainage holes were melted with a field demonstration unit at the Rainbow House and Tyuonyi archaeological ruins at Bandelier National Monument in New Mexico in cooperation with the National Park Service,, By utilizing a consolidation penetrator, the required glass-lined drainage holes were made without creating debris or endangering the ruins from mechanical vibrations.

At around the same time Dr George Clark, at what was then the University of Missouri-Rolla (now Missouri University of Science and Technology) had used ceramic electrical heaters in rock to raise rock temperatures enough to fracture and break out blocks of granite.

Field tests have therefore been able to take rock up to temperatures that are high enough to melt rock, using electrical heaters placed in holes in the rock. Which is a good introduction to the Mahogany Project in which Shell have been using electrical heaters to heat oil shale in place, to high enough temperatures that the kerogen transforms into a light oil. The investigation has been going on for some 25 years starting in the laboratory, and has progressed through an initial field trial.

Small holes are drilled down through the rock to house the electric heating coils, which slowly raise the temperature of the rock to between 600 and 750 deg F, at which temperature the kerogen will convert, depending on what is there, to a mixture of light oil and natural gas. These fuels can be recovered by drilling conventional wells into the rock, with typical depths at the test site being in the 1,000 to 2,000 ft depths.

The Shell Mahogany Technology

The field trial placed heaters in a grid over a 30 ft by 40 ft test area and found that a third of the volume produced was natural gas was produced from the lower grade layers of the shale above the layers with the highest concentrations of kerogen (the Mahogany layer) which produced the light oil.

Array of heaters at a Shell test site

A total of 1,700 barrels of the light oil was recovered during the test period.

Production from the Shell test wells in oil shale

While the Bureau of Land Management has approved further sites for tests, the program is waiting to see what happens to the price of oil to determine whether or not the program will be sufficiently economically viable to move forward. At present this decision is anticipated to be in the middle of this decade, by which time it may be a little clearer whether the Cornucopians or some of the rest of us have been more accurate in our predictions on the future availability of sufficient oil to meet global demands at an affordable price. But it is the level of that affordable price that will decide whether the oil shale program is viable.

The costs of the project will not just have to cover the heating of the rock. One of the problems with the site is that there is some migration of water through the rock, and this can create two problems. The first is that it pulls heat away from the transformation process and the second is that it can interfere in the overall process itself. To stop the water flow (and concurrently the risk of transformed oil and gas migrating away from the collector wells) Shell has been looking into building an ice wall around the site to hold the water back.

Ground freezing is growing more popular as a tool for dealing with water underground. It has been used, for example, to stabilize the ground while the Boston Big Dig (the Central Artery/Tunnel project) was built and in stabilizing the ground for some of the underground stations in the London Tube network (including the collapse of one of the excavations). It has been used to hold back the water while uranium ore was mined at MacArthur River. Simply described, a dual pipe system is placed in vertical holes, and a freezing solution (usually a brine) is circulated through them, lowering the temperature of the rock to the point that the water freezes. Since the lowered temperature is distributed around the holes, there is no need to intersect any of the fractures, or voids, and the frozen water also helps to strengthen the rock where needed.

For the Mahogany Project test, which began in 2007, the freezing liquid was ammonia, and the test used a pattern of 157 holes drilled eight-feet apart, to a depth of 1,800 ft. The test removed the groundwater from within the well, but did not heat the rock to produce the oil and gas.

It will be interesting to see how this project turns out. It has been suggested that the technology would need a dedicated power source of some 1.2 gigawatts, in order to yield a production of 100,000 bd. Shell estimates it will yield 3-4 energy units for every unit consumed.

Layout of freezing pipes for the Shell Mahogany tests.

As usual with these technical posts, they can only briefly outline a process, if something is not clear please ask in comments, or if there is more information available, we all gain from reading of it.

Producing oil shale by burning it in place

This is part of the continuing series that I have been writing about oil shale. And, while I just digressed in talking about using nuclear devices to break the rock and heat it, the key problems that those posts highlighted remain, the first was that the oil is not really oil and won’t flow to the well, and the second is that there are no easy paths for the oil to flow though, even if it could. And this creates a problem when it comes to getting the kerogen (or oil for simplicity) separated from the rock around it. As I said in the first post on this topic, the oil can be separated in a retort, after being mined. The retorting can be self-energized and, by heating the oil it can be transformed into a form of bitumen that can then be further refined into a commercial grade And if you think it is easy, there is this quote I found at Econbrowser, that might give you some perspective. He quotes Bubba, of Belly of the Beast:

If you heat this shale to 700 degrees F you will turn this organic carbon (kerogen) into the nastiest, stinkiest, gooiest, pile of oil-like crap that you can imagine. Then if you send it through the gnarliest oil refinery on the planet you can make this s*** into transportation fuel. In the mean time you have created all kinds of nasty byproducts, have polluted the air and groundwater of wherever you have extracted it.

Mining shale and then processing out the oil is, therefore, fairly expensive, both in terms of energy, and hard dollars. At the same time, once the oil is extracted, the spent shale has to be disposed of. That costs more money. Considering all these potential expenses and potential problems, it is therefore not surprising, from the beginning, that the idea of trying to create the initial retort in the rock, and making that transition to oil in-place looked as though it might be a winner.


There has been considerable technical success in recent times in getting natural gas from the tight shale around the country, but natural gas is, comparatively, easy to extract if some additional cracks are artificially driven through the rock to create the needed permeability.

Unfortunately that only potentially treats one of the problems with the oil shale. The other is that the oil will not move, even if the cracks are there, unless it is heated to the point that it will either vaporize, or transform into a flowable hydrocarbon. And this takes a lot of heat. Thus the attraction of having a nuclear device to create a cavity, radically fracture the rock around the cavity, and generate enough heat to start an underground fire, that could be sustained, and controlled, by adding additional air, and from which the oil could be released.

OK so accepting that we can't use nuke's can we do this another way? Because of space and time I’m going to talk of the more conventional retorting today, based on the idea of doing most of the processing of the oil in place. Why do we need to do that? Well it gets very expensive to mine and move that rock from the deeper deposits, and though it has been and is being done for metal ores, their costs are still much higher than that of oil.

If we can process the rock in place, so that the oil is heated sufficiently, then we save the transportation costs. So what will we need? For the more conventional approach we still need some sort of cavity in which to start the fire, and to allow it to spread. Then there has to be air fed to the fire to keep it going (and this will require that boreholes be drilled down into the area to sustain the air flow). And then there has to be some way of getting the mobilized oil out of the ground, so that it all doesn't end up being burned down there.

It is an idea that has been suggested for a number of different energy sources. And it is why I included a post on in-situ combustion processes at the beginning of this series. The first dealt with burning coal in place, and then I wrote about the THAI process that is being investigated in Canada for producing the heavy oil in the sands above Fort McMurray.

It might be helpful to insert a slight digression here. In a normal oil refinery, the heavy oils, or residuum, that come out of the bottom of the initial fractionating column have almost no light hydrocarbons left in them, and so are sent to a a Coker, where at a temperature of around 1200 degrees, the final hydrocarbons are driven off, and cracked into lighter fractions, leaving the carbon residue known as coke (or petroleum coke to distinguish it from that made from coal). From my youth I can tell you that coke is a much harder fuel to start burning than conventional coal, since it no longer has any volatiles left in it. Thus, for example, even after the intensity of the fires in the Kuwaiti oil field, coke was deposited around the burning wells and required barrels of C-4 to break it up, so that the fire fighters could reach the top of the well, put out the fire, and replace the fixtures. The reason that I mention this is that Petrobank are burning this coke to provide the heat for the reactions. And from the modifications from the first test to the second have found that the process needs a lot of air be supplied to the burning zone to sustain the fire - over the full face of the burn. I'll come back to that in a bit.

The situation with the oil shale is a little more complex than for oil sand, since the structure of the rock is tighter than the sands in Alberta, and the oil has to be heated to a significantly higher temperature before it will transition and move. The first underground experiments were carried out by Sinclair, in 1953 and 1954. (So we are back to paper references -see Ref 1 at the end). In those days drilling technology wasn't as advanced and so, for the first experiments, they drilled a hole near the outcrop of the shale, and then created a crack from the well to the outcrop by pressurizing air in the well until the rock fractures (a simple variant on hydrofracing a well). By adding sand the crack can be propped open so that air can get into it. It took a couple of tries to get it working, but they were able to start fires in the oil shale at the well, and then by continuously pumping down air, carry the fire along the crack. The heat of the fire changed the kerogen to oil, in the same way as with the retort, and oil was seen coming out of the crack at the outcrop. The rock around the well was, however, fairly fractured from being near the outcrop, so that air passage to encourage the flame to progress, was possible. It is worth quoting some of the conclusions to that work:

Under field conditions - particularly if the operation requires high pressures - volumetric conformance and thermal efficiency can differ significantly from model predictions. The burning zone probably will expand to more closely follow the retorting isotherm and shorten heat transfer distances. In addition, convection may become significant. To illustrate, shale retorted under simulated overburden pressures in the laboratory does not spall or crack as it does at low pressure. Instead, a consolidated rock having high porosity and low permeability remains after pyrolysis of the kerogen. Bulk volume is greater than in the un-retorted state. It is possible that some of the injected air will move through this permeable matrix of spent shale to more fully utilize the fuel content of the spent shale and accelerate heat transfer to raw shale over the rates computed from the mathematical model.

Coring of the oil shale as a precursor to the aborted nuclear shot at Rio Blanco (Ref. 2) showed that at depth the shale appeared to have considerable jointing, which would be a real help in any in-situ retorting method, as Socony anticipated (Ref. 3). When looked at under a microscope the retorted shale also had a number of voids, left by the volatized kerogen, that provided some permeability to the shale (Ref. 4).

It is the presence, or absence of cracks, voids and other passages that the controls the success of conventional in-situ retorting of oil shale. Cyclic hydro-fracing or air fracing of the shale can induce a series of fractures around a well bore at depth, but these are going to be relatively narrow. There is not the mobility within the structure that one gets from the oil sands. Further the environment has to be heated to a much higher temperature to induce transition first to the bitumen and then to the crude. In the tight rock that exists under pressure at depth, the only path that air has to the fire is from boreholes drilled to that depth. (In contrast with close-to-surface conditions where ground fracturing will open cracks to the surface). With the cracks being relatively narrow the air that must be supplied to the fire must be at a relatively high pressure, and in considerable volumes.

Without an underground cavity, into which some of the rock can displace, or a means for removing some of the rock to allow multiple fractures of the shale, and fracture opening to allow air access, starting and sustaining a large underground fire will be a significant undertaking.

Unfortunately also "Lean shale tends to be brittle, fracturing under stress, while rich shale tends to be tough and resilient, resisting fracture by bending, and tending to yield plastically under stress." (Ref. 5) This is going to make it harder to grow the cracks where we need them to be.

The other problem with in-situ retorting is controlling the flame front to go where you want it. It is hard to control where the fractures go underground, and the path that the air takes, to make sure that all the shale is retorted, so much more air has to be pumped underground than might be needed otherwise. And this is where it gets frustrating because, though it may only take 260 Btu to raise a lb of shale to 900 degF, (Ref. 6) and that can come from the carbon content of the shale (the coke above), getting enough air there and having somewhere for the released oil and gas to go can take a lot more energy.

For example if two wells are drilled, say 500 ft apart, and a crack run between them, then the air to the burning front, and the flow from it, is gong to be limited by the width of the crack. These processes are relatively slow. A model of the process (Ref. 7) has shown that it can take 10 years for the front to move from one well to the next. During that time air has to be continuous injected, and the volume of air required, for a barrel of oil recovered can be calculated.

Depending on the temperature at which the air was injected (since it shouldn't cool the fire) it can take between 24,000 scf (standard cubic feet) and 86,000 scf/bbl. To get that air into the fire effectively it would have to be pumped into the well at 2,500 psi. (A conventional air compressor runs at around 120 psi). To generate a flow of 50,000 barrels a day was found to require an air compressor system run at 272,000 horsepower. To cut a longer story short, this turns out not be economic, at 1968 costs.

Hmm! Well I am not quite finished, but perhaps this explains in part why Shell are using heaters, rather than fire. I will have a short discussion of that, next time.

Ref. 1 Grant B.F. "Retorting Oil Shale Underground - Problems and Possibilities", 1st Oil Shale Symposium, CSM, 1964.

Ref. 2 Stanfield K.E. "Progress Report on Bureau of Mines - Atomic Energy Commission Corehole, Rio Blanco Country, Colorado", 3rd Oil Shale Symposium, CSM, 1966. 

Ref. 3 Sandberg C.R., "Method for recovery of hydrocarbons by in situ heating of oil shale", US Patent 3,205,942, 1965.

Ref. 4 Hill G.R. and Dougan P. "The characteristics of a low temperature in-situ shale oil", 4th Oil Shale Symposium, CSM, 1967.

Ref. 5 Budd C.H. McLamore T.T., and Gray K.E. "Microscopic examination of mechanically deformed oil shale," 42nd Petr. Engrs Fall Mtg, SPE 1826, 1967.

Ref. 6 Carpenter H.C. and Sohns H.W. "Application of above ground retorting cariable to in situ oil shale processing", 5th Oil Shale Symposium , CSM 1968.

Ref. 7 Barnes A.L. and Ellington R.T. "A Look at in situ oil shale retorting methods based on limited heat transfer contact surfaces", 5th Oil Shale Symposium, CSM, 1968.

Test results from nuclear stimulation of oil and gas reservoirs

Hmmm! Well the tone of some the comments on my last post -dealing with nuclear development of oil shale,, both recently and when I initially posted it on TOD helps illustrate one of the points that I want to make in this, a continuation in the posts on oil shale. The tone was quite negative, in general, with a number of folk being disturbed at my even bringing it up. It points to the fact that, as a political reality (bearing in mind that I try to stick to technical matters in this series) the use of nuclear adjustment to the local geology is not likely going to be popular. As tstreet noted after the original post, there is an article in the Colorado Constitution (article XXVI) that he helped put in there.

Section 1. Nuclear detonations prohibited exceptions. No nuclear explosive device may be detonated or placed in the ground for the purpose of detonation in this state except in accordance with this article. (Adopted by the People, November 5, 1974. Effective upon proclamation of the Governor, December 20, 1974.)

Section 2. Election required. Before the emplacement of any nuclear explosive device in the ground in this state, the detonation of that device shall first have been approved by the voters through enactment of an initiated or referred measure authorizing that detonation, such measure having been ordered, proposed, submitted to the voters, and approved as provided in section 1 of article V of this constitution. (Adopted by the People, November 5, 1974 Effective upon proclamation of the Governor, December 20, 1974.)

While I did not know about that as I initially planned this series, I had intended just to point out that the unhappiness of just one Senator with a nuclear program (and I was thinking of Senator Reid and Yucca Mountain) can delay and ultimately kill its implementation. In this case it is likely that there would be at least eight senators opposing, and I think the point is made. However, since I do think it is useful for folk to know these things, I thought I would continue with the rest of the story from a technical point of view. Particularly since the use of nuclear energy for excavation has recently been revisited by WIRED magazine.


Following the debates about the potential benefits that might occur from the use of nuclear explosives it was decided to see if it would work in three test detonations, that were given the names Gasbuggy ; Rulison and Rio Blanco.

The Gasbuggy shot, in 1967 used a 29 KT device at a depth of a 4,240 ft deep shaft, and created a cavity that was 80 ft wide and 335 ft tall, when one included the chimney. It also fractured the light shale around the opening. Anticipated dimensions were 165 ft with a 350 ft chimney.

The Rulison shot, in 1969, used a 43 KT device at a depth of 8,426 ft. it produced a cavity that was 152 ft wide, with a fracture zone that extends some 200 ft into the surrounding sandstone. (Predicted size was 160 ft with a 300 ft chimney). It is interesting to note that contractors have sought to drill near that shot, in order to extract gas from the shale. They were initially restricted to drilling no closer than half a mile. That was back in 2004, but interest in drilling at the site has continued. In the latest development Noble Energy Production is planning on drilling some 78 wells near the site, with DOE apparently having plans to drill closer than the half-mile imposition, though the wells planned in this case are all more than 1.5 miles from the site. The County Commissioners are not amused And, lest there be some concern for gas released at the time, let me quote from the article.

All the gas freed by the nuclear blast was produced and burned off at the surface, Bennetts said. The radioactivity at the site wasn't high to begin with, and since has decreased to below background levels, he said.

The blast formed a sealed cavity underground, according to state and federal authorities. "Even if you drilled a well into that cavity again, there's very little radioactivity remaining to be produced," Bennetts said.

There was some measure of the gas produced

Following the blast, in 1970 and 1971, the companies burned off, or "flared," 430 million cubic feet of gas into the open sky. The commission said that the level of radioactivity in the air surrounding the site did not exceed normal background levels.

Rio Blanco, shot in 1973, was made up of a series of 3 30-KT devices stacked up the shaft, at a depth of 7,000 ft, with the devices actually at 5,840; 6,230 and 6,670 ft. Each device created a cavity that was some 120 ft in diameter, and about 250 ft high. (Against predictions of a 140 ft diameter with a 300 ft chimney.) Fractures from the explosions extended about 200 ft into the rock around the shaft.

The production of gas from the shots was reported to be less than had been anticipated and the levels of radiation higher, so that while the volume of gas that could have been collected "would have been commercially viable," that only held true had the gas been uncontaminated. It was not.

Interestingly there have also been tests of this technology in the Former Soviet Union and when I wrote about gas fires in Turkmenistan there was a comment by Syndroma who posted pictures of devices, which I am reposting here. Also noting

As to extinguishing of gas fountains: 1 in Turkmenistan, 2 in Uzbekistan, 1 in Ukraine (objective not achieved). Also in Ukraine, there was 0.3 kt explosion to alter the geology of coal mine, to make it safer for the miners. Objective achieved. Later, coal was extracted up to 70 meters from the chamber. No excess radioactivity detected.

Of ~150 peaceful explosion only 4 turned out "nasty" (contamination of the surface).

Soviet weapons that could be used in gas and oil well stimulation (from Wonderful Russia via Syndroma)

Syndroma also posted pictures of the result of three shots to generate a trench which I am also moving here. This was the model of the crater:

And this was the resulting crater that was achieved.

Results of the excavation when 3 nuclear devices were used to excavate a trench in the Soviet Union (Syndroma) (You can see the site on Google Earth at 61 18 16.93, 56 35 55.77)

There is more information on the Soviet Program here.

However our purpose is to look at the development of reserves and their contribution to the marketplace within the foreseeable future. Particularly within the next fifteen years, when we can assume that the shortages of supply will become evident, it can, I think, be realistically assumed that there can be no use of nuclear devices to enhance oil shale recovery out West.

At the same time, the toughness of the rock its strength and behavior under mechanical attack make machine mining of the shale a likely impracticality on a sufficient scale to produce perhaps much more than 100,000 barrels a day within that time frame. That judgment on my part is based also on the need to regenerate the capital for the program, reconstruct the facilities and get through all the necessary paperwork.

There are alternate methods for mining the material, including those that are used in conventional metal mining of large-scale surface and underground deposits. However, the mining of something that can generate high levels of potentially explosive gases, if very large scale fracturing and blasting is undertaken, creates levels of risk that will make development of such plans a lengthy process if carried out underground. The mining of Gilsonite for example, was only realistically achieved when the hydrocarbon was mined using high pressure waterjets. But the strength of the oil shale makes the conventional use of that technique impractical - even if it were allowable, which is conjectural.

With these prospects being diminished, the only likely potential for oil shale to have a significant impact in the next fifteen years is likely to be either through some smaller scale in-situ retorting or possibly through a surface mining approach . I will discuss these in the next two posts on the subject.

Nuclear weapons and oil shale

There is a distinct possibility that we will see the global supply of oil begin to decline within the next decade. In fact the drop may come significantly quicker than some have previously predicted. As Dr. James Schlesinger, the first Secretary of Energy once noted, the American public operates in either Complacent or Panic mode. Given that we may soon reach the latter condition it could be that we may need access to all that oil locked up in the oil shale somewhat sooner than Shell might get it out (and I'll cover that in a later post). The Administration should, therefore, have a crash plan available in case that need becomes critical. This post is written in that vein. Now before I get into the piece that follows I should explain that I don't hold any particular animus towards the states of Colorado, Utah, Wyoming or Idaho and so when I start talking about disposing of nuclear weapons in those states by making use of them it should be taken as merely a technical discussion (grin).

The need for a relatively rapidly available resource to allow us to continue being able to supply the worlds needs for oil, even as it increases into the future, will require some fairly rapid and agile production of resources, and as I noted in the first post of this series, with some 2 trillion extractable barrels of oil locked up in the oil shales of the above four states, there lies a potential answer to the problem. But conventional means for extraction, particularly the levels of capital required, and other issues that I will discuss later, make it unlikely that these normal means will produce any significant impact on the gap in economic supply that will develop in the near future. The use of nuclear explosives has the potential to solve that problem. And to explain, rather simply how this might be done (as with the other techie talks), I will explain how, conceptually, this might be achieved.

The papers that I am going to take the concepts from were given at the second and third oil shale symposia and are listed at the end of the post. They describe the application of results from over 150 underground nuclear detonations which were carried out as the United States sought to find peaceful uses for nuclear explosives as part of the Plowshare Program. I will also be using 1960's costs since these were used in the papers.

To set the stage, as I have described earlier, the Western oil shales occur in rock with almost no permeability, and the kerogen that is in the rock will, under normal conditions stay there, rather than flowing even when it has the chance. So if the oil (kerogen) is to be recovered two things will be needed. The first is a way of massively fracturing the rock, and the second is the maintenance of some level of heating to liquefy the oil, and then to keep it flowing. Large scale fracture of the rock will, in turn, require the application of massive levels of energy, and here nuclear explosives are in a class of their own. Explosive yields are usually given in kilotons, where a kiloton has the effective energy in a thousand tons of TNT. (A ton of TNT has an energy content of 4,184 Megajoules). At the same time the devices themselves are relatively small. A 250 KT device would be around 20 inches in diameter and about two to four times that long. The cost to place it, and the device itself, was estimated to be around $500,000 in 1965.

The oil shale layers are about 2,000 ft thick, and under an additional cover of 1,000 ft of overlying rock (overburden to mining engineers). If a 250 KT device was placed at the bottom of the shale layer, therefore, and detonated, it could be expected to create a cavity that would be around 400 ft in diameter. Much of the radioactive material generated (anticipated to be tritium) would be fused into the wall of the cavity, or caught in the gas that could be drawn off and collected through the boreholes subsequently used to take advantage of the blast.

The shockwave from the event is anticipated to create damaging surface motion to a distance of 2 miles or so, and be substantially disturbing to 6 miles, however, for our purpose, in the immediate vicinity of the blast it will induce significant fractures in the surrounding, and overlying rock. This will cause the rock immediately over the blasted cavity to collapse, and to fall in until a chimney of broken rock has been formed. This chimney will grow upwards until the bulking of the rock as it breaks (that gain of 60% I mentioned last post) fills the space available. For the 250 KT shot this chimney is estimated to be around 1,000 ft high. Experience suggests that the blocks will break into pieces up to 3-ft in size, though the collapse and internal fracturing may increase their ignition potential. The rock surrounding the cavity will, for a distance of around 3-cavity diameters be fractured with a permeability of up to 1 darcy. (The Ghawar field in Saudi Arabia has an average permeability of 617 millidarcies). Beyond that range, and out to about 6 to 8 radii the rock will continue to be fractured, but with fractures more widely spaced and less useful.

Thus, if the entire area is to be treated, then shots would need to be fired around 3 - 4 cavity radii apart in order to maximize the break-up of the rock. (Say for our hypothetical model this would be around 750 ft). By drilling sets of 5 shot holes to create individual retorts, and grouping these in sets of four, to create a "plant," we could create a production operation for the recovery of the oil. Depending on whether the intent is to optimize the fragmentation of the rock, or the fracturing of the surrounding rock with the patterns, some 240,000,000 to 1,000,000,000 cubic feet of rock will be broken per shot, at a cost of $0.015 to $0.05 per ton.

Which brings up the second advantage of nuclear explosives. About 2.5 months after the shot the temperature at the wall of the cavity will still be around 1,000 degrees F, and some 11 months after the shot it will be around 180 degrees. Since the only place for this heat to go is into the surrounding rock, it will cook the kerogen in the vicinity into oil, with, at the sustaining temperature, a low enough viscosity that it will flow into any adjacent collection point.

And it is here that the advances of the past 40-years come into play, since oil drilling is now capable of drilling a "bottle brush" collection pattern under the cavity in order to access and collect the oil (and some water) as it drains down through the fractures. However drilling will also be required to feed air into the chimney and to turn it into a large-scale retort to complete the transition of the kerogen in the vicinity to oil, and to mobilize it. Based on USBM experiments, some 75-90% of the oil in the shale can be recovered from such an in-situ retort. Where necessary some of the gas produced may also be used, in the later stages of the upward progression of the fire front, to enhance the strength of the fire front and to ensure that it continues to move up through the shale, not only in the chimney, but then also into the overlying and surrounding rock. (The fire can be controlled to either burn up or down what now becomes an extremely large retort).

Using this technique and applying it to each of the plants, that I have just described, it is anticipated that each plant, which would cover an area about a mile in diameter, would produce some 450 million barrels of oil over twelve years, at a production rate per day of 100,000 barrels, assuming a 75% recovery of the oil over the 2,000 ft interval. It is anticipated that with a feed of around 3,000 cfm/ton of air at 50 psi, that the flame front could progress at a speed of between 1 and 2 ft per day. In 1965 dollars, it was anticipated that the operation could make a profit if the oil were then sold to a refinery at a cost of $1.50 a barrel. Oil recovery would, however, be controlled by the quantity of oil in each "retort" layer, and, by the nature of the operation, all the oil would be anticipated to be recovered but at the rate controlled by the layers as they produced. However the process is considered economic for oil shale at grades above 15 gallons/ton with thicknesses of greater than 400 ft.

So just think, when we talk about "the nuclear option" in future, we may have an entirely different concept in mind (/grin).

(Note that, for consistency I changed some of the numbers to reflect use in the 2,000 ft shale column, rather than the 1,000 ft used in some of the example calculations in the papers).
Reference papers for this post are:
M.A. Lekas and H.C. Carpenter "Fracturing Oil Shale with Nuclear Explosives for In-Situ Retorting", 2nd Symposium on Oil Shale, CSM, 1965.
H.F. Coffer and E.R. Spiess "Commercial Applications of Nuclear Explosives, the Answer to Oil Shale?", 3rd Symposium on Oil Shale, CSM, 1966.
M.E. Lekas "Economics of Producing Shale Oil, the Nuclear In-Situ Retorting Method," 3rd Symposium on Oil Shale, CSM, 1966.

Conventional Mining of Oil Shale

So, there we have all this oil, sitting in these nice thick oil shale beds out West and just waiting to turn some local in Colorado into the next "world's richest person". All they have to do is to figure out how to get the oil out of the ground cheaply enough to make money from it. (And if you remember from the last post on the subject there are over 2,000 patents on ways to do this - if it were that simple there would not be nearly that many). Congress thinks so too, since the Energy Policy Act of 2005 called oil shale a strategically important domestic resource (pdf file). More recently, there is currently a House bill in Committee governing oil shale development.

What's the big deal? Drill a hole down there and it flows it - isn't that how you get oil out of the ground? Well not in this case. As I said last time the oil is really a waxy kerogen that does not want to flow at all. And there is also a problem with the rock. About 40 years ago a guy called Brace (Ref 1 - sorry I can’t find these on the internet) found that the cracks in a rock are related to the size of the grains of the material that make up the rock. A rock with large grains has large cracks, and this gives it a permeability, which is the joining of these cracks to give a path through which oil (or water or gas) can flow through the rock. It also gives the rock its porosity, which are the holes in the rock into which the oil can collect. Unfortunately the grain size of the average particle in oil shale is around 5.8 microns. This is about a tenth of the thickness of a human hair, medium human hair being about 60 - 90 microns wide. As a result the typical oil shale has very poor porosity, and it is only when it has a high oil content (above 50 gallons/ton) that permeability can be easily measured (Ref 2) , below 20 gal/ton it becomes very difficult, because it is so small. The average grade is around 25 gal/ton.

The simple message from those numbers is that oil will not normally flow into any holes that are drilled into oil shale. So where do we go from here? Well it you won't go to the mountain, then the mountain must come to you. In other words, let's mine the oil shale, bring it to the surface, and then get the oil out of it.

That’s what they do in Canada with the oil sands, and these beds are thicker. In fact the layers are thick enough so that they can be mined by a number of different ways , including surface mining, what we call room and pillar mining, and then by a third method that I will, for now, call sub-level stoping. Remember that we need to break the rock down into pieces no bigger than 3-inches in size for the retorts.

Union Oil (now Unocal) used the room and pillar method for their mine at Parachute Creek, where mining interest had, for a while, been growing again. Room and pillar mining was also used for the Colony Mine, which was the largest project in hand back in the 1980's . Since there have been a number of reasons suggested for the closing of that project, it might be appropriate to ask you to remember the words I quoted from Harold Carver last week.

What is needed is assurance that shale oil production will face a stable economic environment in which it can share in the spectrum of raw materials for our future energy needs.

. And then read on:

Tosco's interest in the Colony project was sold in 1979, and again in 1980, to Exxon Company for the Colony II development. Exxon planned to invest up to $5 billion in a planned 47,000 bpd plant using a Tosco retort design. After spending more than $1 billion, Exxon announced on May 2, 1982, that it was closing the project and laying off 2,200 workers. . . . . . The economic incentive for producing oil shale has long been tied to the price of crude oil. The highest price that crude oil ever reached -- $87/bbl (2005 dollars) -- occurred in January 1981. Exxon's decision to cancel its Colony oil shale project came a year and half later, after prices began to decline and newly discovered, less-costly-to-produce reserves came online. . . . . oil had become plentiful, with about 8 to 10 million barrels per day in excess worldwide capacity, and the trend in rising oil prices had reversed after early 1981.

The failure, in short, at that time became one due to economics, rather than technology.

Using a machine to mine the oil shale poses some problems, since it is much stronger than, for example, the tar sands of Alberta, that can be scooped up with a shovel. Rather the rock has a strength that goes down as oil content goes up to a value of about 13,000 psi with an oil grade of 30 gal/ton, at which point it stabilizes even as the grade continues to increase. This means that the openings for mining can be quite large, as they need to be to achieve the tonnages planned. And there are ways to make them larger.

Rooms mined with the rock were some 55-ft wide, with 58-ft pillars. It also means that the machines to grind the rock from the solid will need, either to be jet-assisted, or of relatively large size. One of the first proposed (for you EROI fans) was designed to produce 17,500 tons per 2-shift day, with an oil content of 40 gal/ton, and with 6.5 operating hours in a shift. Machine power requirements would be 37,500 kwh per working day (Ref. 3).

The advantage of the large mining machines, over drill and blast methods, which remain the most common practice, is that the operation is continuous, with rock being carried away by conveyors, and production need not stop to ventilate away the products from the use of explosives. On the other hand the use of explosives to fragment the rock does provide a relatively effective way to fracture it (though with less size control). One of the questions that I have always had, though, in doing EROI on explosive use is whether to count the energy input as that required to make the explosive, or that liberated when it is set off.

In the days when the industry was last planned, the throughput for single plants was considered to be on the order of 100,000 tons/day. A ton occupies 16 cubic feet (Ref 4) and so if the mine is 30 ft high, a cubic foot of floor space would have 2 tons of rock on it. This would translate into having to mine 2.5 acres of rock per day. The point has been made, however, that underground mining of layers of rock one slice at a time down through the deposit would be inefficient and energy intensive. Further that it would be restricted only to mining the high grade layers.

The matter of mining, by underground methods, the rich, deep oil shale beds in the center of the basin probably needs little consideration because better methods of producing the resource appear to be at hand. If our civilization has any conscience and if it has any regard for posterity it cannot give serious consideration to any method of production of shale oil from the center of the basin that does not result in substantially complete recovery. Our civilization has passed the stage in which it can kill the whole buffalo merely to consume the tongue and liver as was done in this area less than a century ago.

What he is arguing against is the intent to set up the mine to mine out the rich layers, so that when our grand-children have to mine the rest they must work in the dangerous conditions of a partially mined volume, with only the poorest grades of shale as a reward.

In contrast he argues that the area should be strip-mined since even with a 1,000 ft cover, the thickness of the oil shale would justify the process as a means of recovering the entire volume of oil from the deposit. Part of the problem comes, of course, not only from the fact that a hole a mile in diameter and 3,000 ft deep has been created, but that also all the material that has been mined, has to be stored before being returned. And this is one of the significant problems that mining the deposit either by strip mining or by underground mining generates, that of the waste volumes and condition.

For a long time mining has used some of the waste rock that has been mined to pump back into the mine and fill the holes left. By mixing a small amount of cement with the rock powder it can be made strong enough that the rest of the valuable ore can be mined, and the roof is held up by the newly placed columns. However, when you mine and mill the rock it is broken into small pieces. These bulk in volume by about 60% on average, over the original volume of the rock, and so even with the use of the mine to put back some of the rock there will be about 40% of it left for disposal somewhere else. (Note that this does not include the thermal swelling that occurs when the rock is heated - I will get to that in a couple of posts).

But it should be pointed out that there is already some 50-odd years of experience in dealing with this waste in the area, and while I am not familiar with the problems and their solution, the general mining practice with waste fills is ultimately to cover and seed them so that there is a binding vegetation - unfortunately this, as with some of the other parts of the extraction process, requires considerable water, and that is an issue that we haven't reached yet. But, on the other hand, we don't seem to hear much about the piles that already exist.

Again I am going to pause here, since the post may otherwise get too long, but next time I will talk a little bit about the nuclear option, which might otherwise be forgot.
Ref. 1 Brace W.F. "Dependence of Fracture Strength of Rocks on Grain Size," 4th Symposium on Rock Mechanics, Penn State, 1961,

Ref. 2 Thorne H.M. "Bureau of Mines Oil-Shale Research", First Symposium on Oil Shale, CSM, 1964.

Ref. 3 Hamilton W.H. "Preliminary Design and Evaluation of the Alkirk Oil Shale Miner," Proc. 2nd Annual Symposium on Oil Shale, CSM, 1965.

Ref. 4 Ertl T. "Mining Colorado Oil Shale", Proc. 2nd Annual Symposium on Oil Shale, CSM, 1965.

Oil Shale, a future source of oil?

One of the large numbers that is often quoted in response to the concerns that some of us express over future energy supplies relates to the amount of oil that is present in oil shale. However, there seems to be a general consensus among many that write about world energy, that the 2 trillion barrels of oil potentially available out of the 4 trillion barrels locked in the United States oil shales are not, at the present time, a realistic source of supply. So for the next couple or more weeks these weekly tech talks will be discussing oil shale. The Federal Government is reviewing the leasing process for these lands, and so it might be timely.

After an eleven year hiatus, Colorado School of Mines reactivated their annual Oil Shale Symposia in 2006, and has been hosting them since then, with the last one being held last October. And the resource is not quite the nonentity that it may at first appear.

Japan started oil production at Fushun in 1929, and developed, in less than ten years, the world's largest oil shale industry. Shale oil was a principal source of fuels for Japan during World War II. Fushun production continued to expand under Communist China and may be 40,000 bpd presently.

That quote was from a paper in 1964, more recently the USGS have noted an annual production of around 415,000 barrels. it is therefore justifiable to take a little closer look at this whole issue and try to explain some of the technical state of affairs, point out a little of the disingenuousness of some of the statements that have been made, but largely leave the political discussion to others. I will largely, at least initially, deal with deposits in the USA, though there has been a significant industry in Estonia since 1916, though the deposits are anticipated to be exhausted within the next 30 years.


Unfortunately the last time that a serious look was taken at the US resource was back in the 1970's and 1980's, when at one time, under the Project Independence Blueprint, a shale oil production target of 1 million barrels of oil per day was projected, in line with President Ford's State-of-the-Union Message of 1975. That program, in turn, was based on the considerable amount of research that had been carried out, both in the US, and abroad, and on an initial evaluation of practical means to meet the target. But before one looks at that target, and its feasibility, perhaps it is better to look a little more closely at the information which led up to the prediction.

To begin with, while the basic definition of an oil shale suggests the fine-grained rock that is often called shale, and implies it is impregnated with oil, that might be easily recovered, Unfortunately, in most cases the rock is not a shale, and the organic material that it contains is not yet an oil that will not run out, or separate out with normal treatment. It has been described as a precursor to oil, in that, it was initially formed in the same way, but has not undergone the natural high-temperature and pressure regimes of deep burial in the earth that are needed to turn it into oil. (However, if additional kerogen were to be added to the shale it would through time more likely end up as a coal). The material is known as a kerogen, and to date the most successful methods of removing it from the rock has been to heat the rock until the contents volatize, and then to condense the hydrocarbons back out (in the same fashion that one cracks the oil in a refinery - though there are some significant differences that I will get to later). However, since the initial natural process was not carried as far as with oil, then the amount of energy that is required is generally greater. The greatest deposits of interest are those found in relatively thick deposits around the point where Wyoming, Colorado, Utah, and Idaho come together.

From Donnell, 1st Oil Shale Symposium, 1964.Location of the major oil shale deposits. A section through the lettered points in the above figure gives:

Note that the scale for the vertical section is in feet.

The darker band shown is known as the Mahogany zone in which the Mahogany bed some 100 - 200 ft thick, is considered to be the richest layer, and is a marker for the deposit.

In oil shale from the Mahogany zone of the Green River Formation in Colorado, the ratio of oil yield to organic matter (weight percent) is 0.659; the ratio of oil yield to organic carbon (weight percent) is 0.818; the ratio of organic matter (weight percent) to oil yield (gallons per ton) is 0.580, and the ratio of organic carbon (weight percent) to oil yield (gallons per ton) is 0.467.

Shale oil has been used as a fuel source in a number of countries around the world, over the past 150 years, but only become of economic significance in the 1920's, as noted above. There have been over two thousand patents issued describing different ways to separate what, for convenience, I will call oil, from the shale (similarly called). Only a few have, however, been demonstrated, and later in this series of posts I will explain some of the peculiar problems that arise in retorting oil shale. But, as an illustration of the type of process that could be used, I will describe the Gas Combustion Process, as developed by the US Bureau of Mines for one of its original experiments. I thought it would be useful to describe this in a little detail, since it points out some of the potential benefits that can come from retorting the material.

Early Oil Shale Processing Retort (DOE )

The retort can be simply thought of as a vertical pipe with the raw shale fed into the top. As it moves down through the retort it passes through four zones. At the top of the retort the shale is cold, and the gasses rising from the lower parts of the process, mix with this shale. This has two effects, it pre-heats the shale as it drops into the next zone, while at the same time the oil is condensed into a mist, and the product gasses are cooled. (They are both then collected as they leave the retort). As the shale continues to move down the retort it reaches, about half-way down, a series of ports that inject air mixed with a portion of the produced gas that has been collected (call this the dilution gas). These two combine to cause ignition and to raise the temperature of the shale (to between 700 and 950 degrees F) so that the hydrocarbon contents vaporize and create the oil and gas combination that rises up out of the retort. The shale residue, continues down the retort, where it is now used to pre-heat a second supply of the collected gas (known as the recycled gas) that is moving up into the retorting zone. This cools the shale as it heats the gas, and the shale residue can then be collected and moved away. By using this form of heat transfer during the process a relatively high thermal efficiency can be achieved, and the retort can produce about 90% of the original oil in the shale, as well as a secondary volume of gas, beyond that needed to energize the retort. The retort has been shown able to handle shale particles ranging in size from 0.25-inch to 3-inch. By design it is possible to make sure that the oil mist that is the major product does not condense onto the shale particles that are being fed into the retort. You may note that this separation process does not require any additional external fuel, nor the addition of water to the process.

Using a slightly different method Union Oil Company ran a demonstration plant that ran at rates up to 1200 tons/day, using oil shale from the Piceance Basin. The crude produced was "a waxy, intermediate gravity, high nitrogen and intermediate sulfur crude" where the wax was removed and separately cracked, and the sulfur and nitrogen levels lowered before it could be considered a "commercial shale oil" with properties similar to that of a high quality Utah crude. A feed of crude shale oil at 26,900 b/d would yield 25,000 bd of commercial shale oil, and 500 t of green coke. The oil could then be cracked into 380 bd of lpg; 13,635 bd of gasoline; 1,300 bd of stove oil; 6,700 bd of diesel and 590 bd of fuel oil.

As I said at the beginning of the post, there is an awful lot of oil shale in the United States, the beds can reach up to 2,000 ft thick, and the oil content can reach 90 gallons/ton. Unfortunately these do not occur at the same time. Rather the highest grade is found in relatively narrow layers in the Uinta Basin, although the oil-shale sequence in the area can be up to 1,200 ft. And unfortunately not all the oil in the shale is made up of the same material, or has the same sort of properties. This can lead both to difficulties in mining and in retorting.

I will discuss those, and the issue of in-situ retorting, and some of its problems in the next post. But, given what happened, it is perhaps appropriate to close this first post with a comment by Harold Carver of Union at the first symposium.

It should be quite obvious that if imports to the coastal states and from Canada suddenly increase disproportionately after a shale industry is started, the embryo shale industry would be placed in a severe competitive bind. Unlimited cheap foreign crude imports would make shale oil as well as a large percentage of domestic crude oil production non-competitive. What is needed is assurance that shale oil production will face a stable economic environment in which it can share in the spectrum of raw materials for our future energy needs.

Given what happened later that was quite visionary.

P59. Pick Points

Some of the oil that is being held in tanks near the Mt Redoubt volcano is to be removed by a tanker this weekend The tanks are protected by an earthen dam, that is still holding, but the tanker will remove about 840,000 gallons of the 3.1 million gallons that is held in each of the two storage tanks.

The amount of oil that is held (as kerogen) in the oil shale of the Piceance Basin in Colorado may be more than 50% greater than at first thought, according to the latest U.S. G. S. figures. However it is still not that easy to extract, and while the Department of the Interior is encouraging research and development of concepts for extraction, they are not encouraging development of the leases, as yet. Shell, for example, is now testing the freeze wall concept for keeping water from the refractory zone during the heating of shale in place to convert and extract the oil. General Synfuels International have announced a breakthrough in extracting the energy through gasification they have also secured a parcel of land, and are acquiring the components to build a production prototype with testing next year.

Predictive production numbers from Mexico have been dropped an additional 30,000 bd, down to 2.72 mbd. This will, in turn force a cut in exports, which cut may reach 18% next year with overall production falling below 2.5 mbd, and exports falling below 1.125 mbd. This implies a drop of 245,000 bd and the question, since most of that comes to the United States, is where will the volume come from to make up the loss? Export levels for this year are already below prediction. In order to raise money for more investment in production Pemex has sold $712 million in new bonds. And while the company promises more investment, and new wells for Cantarell the overall prognosis does not look good, as the company continues to fail to meet targets.

In the continuing saga of the wind farm projected to be built where Senator Kennedy sails, the Interior Department is promising a ruling on Cape Wind. The project has seen numerous challenges as it has moved forward, which led to publication of a book, (which I reviewed over on TOD). The ruling is anticipated to come about in a couple of months, with the implication of the Secretary’s remarks being that the project may be allowed to move ahead. In the UK there are plans for a new wind farm off Norfolk, capable of generating 315 MW. Construction is slated to start early this summer, with production from the 88 turbines anticipated to start coming ashore in 2011. British plans do not, however, seem to be keeping up with earlier predictions in terms of the volume of renewable energy that will be available to meet targets. And there has been some heated debate in Dekalb county, outside Chicago about plans for a 133 turbine farm to be installed near the Windy City.

The predictions for Hurricane activity in the Gulf have been lowered to only 13 named storms this year. Only 3 – 4 of these should reach major strength.