Waterjetting 21c - collection in Gilsonite and steep seams

Picking up the debris from a waterjetting operation can be a more expensive part of the process than actually removing the material in the first place. This is particularly true where the material no longer has any inherent value, but is sufficiently toxic that it has to be collected and then properly disposed of. On the other hand, in most aspects of mining, it is the inherent value that is contained in that debris that makes the whole process worthwhile, and in this latter case requires that as much of the material be initially collected as possible. This can be difficult where, for example, gold particles are being produced, since these are heavy and naturally rapidly sink through the water to settle onto the floor where, if this is rough, they can then lie is natural traps that make it hard to re-elevate them and move them to a desired collector.

If one is to continue to move the particles there must be some mechanism that will continue to move the particles to the point that they can be collected. The very condition that makes it difficult to manually mine coal from steeply dipping beds also serves to carry coal and other minerals from those veins, once the material is broken free from the solid.

Consider, for example, the early mining of Gilsonite, which is a naturally occurring hydrocarbon found in thin vertical veins in places such as Utah. It is named after one of its first developers, Samuel H. Gilson.

Figure 1. Pieces of Gilsonite (Metroexpand )

The problem with mining this material is that the dust is very explosive, and remote, safer methods were needed to get men away from the mining process. In 1957 the major American company, American Gilsonite, turned to the use of hydraulic mining. At first the seam was mined using a series of horizontal lifts, with the washed out material and water being collected in drifts that carried it to a pumping station. However, because of the vertical seam, it was easier to used a drill, with lateral jets so that the rotating waterjets mined and flushed the material down into underlying drifts, where it could be collected.

Figure 2. Method for Mining Gilsonite.

By moving the mining tool along the vein the material could be mined out, without miners at the working face, and without the risks of explosion from the conventional mechanical mining methods.

A recent blimp trip over the Bonanza mine shows the results from years of the mining process, as the seam has been removed.

Figure 3. Mined out seam of Gilsonite at Bonanza, Utah. (J.S. and S.W. Aber)

More recently the mine has returned to a mechanical method for mining the material since the customer wanted a dry, rather than a wet product, and, with demand for the material rising, hopefully they will continue to operate safely – the material is now airlifted to the surface. Mining has been restricted to the top 500-ft of the vein.

The hydraulic mining process demonstrated here shows some of the advantages of the use of waterjets in that there are no workers in the mining area, and that the tool is able to remove the mineral without generating the sparks and explosive dust clouds that can be a danger otherwise.

Figure 4. German coal seam side view, showing thickness and angle of slope. (Benedum, W., Harzer, H., and Maurer, H., "The Development and Performance of two Hydromechanical Large Scale workings in the West German Coal Mining Industry," paper J2, Proc. 2nd Int. Symp. Jet Cutting Tech., BHRA.)

Coal mining has some of the same problems, and in Germany the idea was tried (in a slightly modified version) as a way of mining coal. Rather than operate from a drilling rig at the surface, holes were drilled along a very steeply dipping seam. The process was in two parts, evaluating whether it was better to start at the bottom and drill up, or to start at the top and drill down.

Figure 5. Methods tested for bore and mine coal recovery. (Benedum, W., Harzer, H., and Maurer, H., ibid.)

The method where the drill goes down, and then reams back up turns out to be the better approach. The reason for this is that the coal breaks out along natural planes, and these can produce coal pieces that are large enough to block the drilled hole through which all the material must pass, when drilling upwards. This is not a problem when drilling down, since the coal is falling through a much larger space (the mined out volume). This makes it a little more difficult to recover, since it is not confined where it falls into the lower drift. But, by adding a small monitor in the second drift, the broken coal can be lifted back into a slurry that can then be channeled into a flume, and carried away from the working area.

The process was effective, in that it showed that the coal could be mined from one drift to the next, using the method, but it was difficult, because of the varying conditions of the seam over its length, to make the connecting drill holes at an economic speed, and thus to mine the coal at an economic rate.

Figure 6. Looking down to the lower drift from the upper, after mining, with all the coal removed. (Benedum et al ibid)

Note that in the above picture there is little roof collapse into the mined out cavity. This is either beneficial (since it allows all the coal to be removed) or it can be a disadvantage. Other than the safety factor of having a roof hang up until a very large area collapses at one time (where the air blast can do considerable damage), a continual roof collapse as the coal is mined can provide confinement for the water and, hopefully, enough restriction that the water will carry the coal to a collection point.

This was the idea behind the JPL coal mining worm that they proposed some years ago:

Figure 7. The JPL concept for a horizontal jet mining system (Miller, C.G., and Stephens, J.B., Coal Worm: A Remote Coal Extraction Concept, JPL Report 5010-7, December, 22, 1976, Jet Propulsion Laboratory, Pasadena, CA.)

Unfortunately when a coal mine roof collapse occurs the rock breaks into relatively large pieces so that the water can flow away through the pile, without being confined sufficiently to provide the needed motive force to move the coal to the collection point. For that, the system would still need a steeply dipping bed, and I’ll talk more of this and debris collection in future posts.

A new book and the temperatures in the Mountains

One of the many significant salient points that Donna Laframboise makes in her new book on the IPCC lies in the predilection of the IPCC authors to rely on computer modeling over factual data. I will probably have more to say on this in my planned review of the book (which so far is fascinating to read and damning in the details) once I finish it, but it does suggest that posts such as these on the actual variations in US temperatures over the past century will languish in outer darkness – oh, well!!

To recap where we are, after looking at the temperatures of the individual contiguous states of the American Union, I have started to look at regional changes and to compare them. A significant drop of around four degrees Fahrenheit that occurred between 1950 and 1965 along the Eastern Seaboard, and which inter alia led to a southern migration of the black-capped chickadee, has since been reversed in the warming of that region post-1965. In contrast in the middle of the country there has been sensibly no warming trend since 1895 (which might explain why the Governor of Texas finds it harder to believe in global warming, since his state hasn’t seen any).

Yet on the West Coast the trends show a relatively consistent increase in temperature since 1895. And so the next place to look is to see what happened in those states that lie along the Rockies and provide the mountainous barrier between the West and the Middle. In the following post I am going to derive this graph, and comment along the way as I get there.

Average variation in time for four regions of the country, with the results adjusted as shown to separate the curves, and show them in order (bottom to top) from West to East.

For this exercise I am going to include Montana, Idaho, Wyoming, Nevada, Utah, Colorado, Arizona and New Mexico . I have previously used both the homogenized data from the USHCN and the Time of Observation corrected (TOBS) data, with a preference for the latter since, as I noted with the individual state evaluations, it has shown a consistently better correlation across the states with latitude and elevation than the data after manipulation.

Combining first the average temperatures for the states, using the homogenized data, one gets a relatively flat curve, but one with a decided kick over the last thirty years, the sign that many consider the marker for Anthropogenic Global Warming.

Average of the state temperatures for the Mountain Region, averaging the values for the different states in the region.

However, before there is much comment on this, it should be noted (when this is compared with the figure above it) that that trend is not as clear in the four regions as I ultimately graphed them. But before getting to that let me just put up a set of comparison graphs, using the USHCN homogenized data, to show that the temperatures of the eight states that I looked at appear to vary relatively consistently. By setting them one above the other it should be easier to cross-compare.




These are relatively consistent, though they appear to smooth a bit with movement south, but to get back to that kick in the end of the plots. As you may know, and I have commented in the individual state plots, the USHCN data is “homogenized” from the raw data. When one takes the average of this “manipulation” and subtracts the Time of Observation corrected values from it, then one gets this curve as the average change made by the climate scientists in reporting the values for the stations in the evaluation (all 233 of them).

Difference between the average USHCN homogenized temperatures and the raw temperature averages, as corrected for time of observation (the TOBS values).

Given that, the rest of the analysis will go back to using the TOBS values. Firstly this changes the average a little:

Average temperatures for the Mountain states, using the Time of Observation corrected raw data.

The change in the slope of the curve drops the rise in temperature per century from 1.7 deg F to 1.08 deg F.

However this curve was obtained by just averaging the average state temperatures, there are varying numbers of stations and varying areas for the different states. When one weights the value by the relative number of stations in the state (equivalent to averaging all the stations in the region), then one gets:

Average temperatures for the Mountain states, using the Time of Observation corrected raw data and averaging the 233 stations in the region.

In each state, the area that each station “covers” (i.e. the area of the state divided by the number of stations) varies from 8,500 sq miles in Nevada, to 2,123 sq miles in Utah. To try and account for this I have weighted the state values by the areas of the states, and this gives this plot:

Average temperatures for the Mountain states, using the Time of Observation corrected raw data and weighting the state averages by the area of the state.

With this plot the steadily increasing temperature suggested in the USHCN plot does not appear as evident, and the temperatures since about 1990 seem relatively steady.

So how do the regional values now compare?

Comparison of average temperatures for the different regions of the United States (as I have defined them)

Obviously the mountain temperatures are lower than those of the other regions given that there is a fall in temperature with elevation. For the combined region this looks like this:

Variation in state temperature as a function of average station elevation in the state.

The r-squared value is much lower for this than it is for the individual stations in the region, and so I will have to look at the effects of latitude, elevation and population separately.

But to conclude I wanted to see how the temperature patterns changed across the country, and the overlay of the regional temperatures made that a little difficult to see, so I “shifted” the curves by adding and subtracting temperatures from each set, so that the comparison of shapes could be made, and that is where we came in:

Average variation in time for four regions of the country, with the results adjusted as shown to separate the curves, and show them in order (bottom to top) from West to East.

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.

Charcoal, Oil Shale and the Ecoshale process in Utah

If you drive West from St Louis (as I did Thursday after my check-up*) you will occasionally hit a pocket of air that smells a little sweet, and a little burnt. It is the product from the charcoal kilns up near Vienna, one of the larger centers for making charcoal in the country. Apart from its use in making barbeque, charcoal has other beneficial uses, and it is projected that it has been used over many millennia. Modern consumption in the United States runs around 375,000 tons.

To really simplify the technology for making the fuel (which may become a unique post at some future point)

Making charcoal from poor-quality timber and sawmill waste is a process that has changed little in centuries.
Before it becomes dimensional lumber, every log harvested in the Ozarks first must be sawed square. The bark covered slabs produced by that first cut become the raw material for charcoal briquettes. Seasoned hardwood is sealed in an air-tight enclosure and allowed to burn with the barest minimum of air. Just like in a woodstove with the damper closed, the wood slowly turns to almost pure carbon as its lighter, more volatile components are driven off by heat. This process, called pyrolysis, can occur in a pile of wood buried in a hole in the ground or inside a metal or concrete box called a Missouri-type charcoal kiln. For years, making charcoal was one of the few sources of income for people in the Ozarks.

In the modern, larger scale version of that process the sawdust or waste wood is treated in something that looks like a refinery:

Modern charcoal plant at Bell,MO (MO DNR )

However, in the earlier times the kilns were made up with earthen and turf walls to seal in the charcoal as it cooked. And it is that technology that I want to return to today in another post on Oil Shale, in this case discussing the EcoShale project in Utah.

The Ecoshale project is being promoted as a new approach to obtaining oil from the shales of Utah. The company proposing this “In-Capsule” process had a fair-sized booth at the MinExpo meeting in Las Vegas a couple of years ago, that drew my attention. I stopped by and watched the video (twice) picked up literature, and talked to one of the folks at the booth. Since there is considerable oil (well actually kerogen) locked up in the shale (perhaps as much as 1 million bbl/acre it is worth seeing what they have planned. I will include a few thoughts as I go through the process.

Those in the UK might want to visit Ian West’s site which gives some history to shale burning in the UK.

Until now I have largely, in the recent posts on oil shale, focused on the thicker layers of oil shale in Colorado, but there are places in Utah where the oil shale near the surface is more than 10 ft thick, and where the shale will yield more than 25 gal/ton. With prices of oil fluctuating, the grade at which production becomes possibly economic will vary, but for the following discussion I am going to assume that a ton of ore will yield about ¾ of a barrel of oil. I will also assume, for simplicity, that a ton of shale occupies 14 cu. ft. before it is mined. The plans for the project, at the time of the MineExpo presentation, were that it would be scaled to produce 30,000 barrels of oil per day, at an anticipated cost of roughly $3 billion. This has now been split into plans for a 9,500 bd commercial project prior to that larger operation. Red Leaf, the company, holds leases to 17,000 acres of this shale (with an overall average of 25 gal/ton, ranging up to 70 gal/ton).

Typical surface oil shale site in Utah (Red Leaf )

General overview of the site

The first thing that happens at a site is that the overburden, and shale that doesn’t have a high enough oil content is removed and stored for site remediation after the process is over. (I am going to use oil to describe the hydrocarbon content, ‘cos it’s shorter to write than kerogen. ) This will require a significant area, since the volume of rock being uncovered every day is going to be large. There are going to be three operations going on at one time, in order to make the process work. The first is the removal of the overburden, the second is the preparation of a site to act as a retort, and the third is the mining of the oil shale and the building of the retort. The retort is then left in place to “cook” the oil/kerogen over a period of some 90 days, before the site is reclaimed. Retort preparation will take place in a space where the shale has already been taken out. (This requires the initial removal of an additional volume of shale that has to be set aside and stored to give the space for the first retort to be put in place.) This is because the underlying bed must be prepared, and the infrastructure for the retorting has to be put into place.

To get just a little ahead of myself, the process of retorting the shale involves mining the shale, and then building the broken rock into a crushed zone, through which pipes have been placed, that will carry natural gas to heat the rock. The rock is then covered with a thick layer of an impermeable rock (for simplicity I am going to assume a crushed claystone) that will act as a seal. In this way the shale is encapsulated, and as the heat from the gas works then so, as with the wood in the charcoal kiln, the rock is processed, the hydrocarbons driven off, and collected in drainage tubes that are interspersed through the layer.

Schematic of the Ecoshale process

If we look at the operations required for the full 30,000 bd operation. The mining of the shale will require some 40,000 tons of rock to be mined and moved every day for production, as well as the removal of the overlying rock from the next batch down the strip. This is equal to around 560,000 cu ft of rock. For the sake of discussion, if the strip being mined is 50 ft wide and the shale seam is 35 ft high, this will require that each day the mine will move a panel that is 320 ft long. However this isn’t all the rock that is required. Because before the shale that is mined can be placed in the retort zone, a layer of clay will be placed over the pit section in order to give an impermeable barrier below the shale to stop contamination of the underlying rock and any water that it contains. This layer is going to have to be very thick, since the oil shale above it is going to be heated to the point that it releases the oil. This takes a temperature of 900 deg. At that temperature the clay will bake and becomes very brittle, so the clay layer must be thick enough to allow for this and allow enough temperature drop to leave the lowest layer still flexible enough to act as a seal. Let’s assume for now that this is going to need a layer that is 3 ft thick. (I’ll come back to this later.) In a recent test of the process the seal provided also included a plastic sheet as well as bentonite. (Presentation slide 19).

Once this clay has been placed (and it should slope at about 5 degrees toward the open face to allow for effective drainage), then the mined shale can be placed on top of it. Drainage pipes are placed near the bottom of the shale layer, then more shale is added, and a heating set of pipes is laid across the shale. These pipes are connected at the back of the day’s pile, so that the gas that will pass through them will also move back through the pile and back to the face of the pile for collection. More collection pipes are then placed as the pile rises and is flattened over the recovery site. The pile will be considerably higher than the mined area since, in mining the shale it also “bulks” in volume by about 60%. The reason for this is that the pieces no longer fit exactly together. Think about a jigsaw puzzle. When the puzzle is made it only occupies a small area of the table, but when all the pieces first come out of the box they fill a much bigger space, because of all the empty space around each bit, and that the pieces are all separate. It is the same thing for rock. (Some of those internal spaces will be filled as the shale heats and degrades, so that the pile may collapse a little during the heating process). Thus the pile that will be made will be have to fit into the same “footprint”, i.e the 50 ft deep, 320 ft long shape it came out of, but will now be 56 ft high. With the underlying clay layer this will make the pile some 59 ft high at this point. (And require about a thousand tons of clay a day)

Drainage pipes on bentonite at the bottom of the test retort (Red Leaf)

By going through this process the mine is creating a “use once” retort that encapsulates the spent shale, and collects the retorted products without some of the disadvantages of a more conventional retort. These include (from the brochure) protection of groundwater, lack of need to sequester tailings, and obviation of the problems of retort clogging and moisture retention within the retort.

Now the mine has to seal the retort to keep the retorting heat within the shale and not to let it, or the gas and oil generated out. So a cap will be placed over the broken shale and, for the same arguments as above we will assume for now this is also going to be about 3 ft thick. (I hope it doesn’t rain much in this part of Utah. The impact of water on clay/shale at 900 degC is spectacular, since the clay shatters explosively and is easily eroded).

Collapsed cavity where high-temperature overlying shale fragmented and “blew out” after being hit by a water stream. (site in Montana)

This will take the pile up to 62 ft high, which is quite a bit higher than the original 35 ft. It is interesting that the brochure suggests that this will be a “low temperature, stationary heating” given that the initial temperatures to liberate the shale have been documented (as noted above) at 900 degC. And my memory suggested that that number also cropped up in my conversation at the booth. It will also have to have a front panel of a sealing rock and clay placed over the face of the section, in order to complete the capsule.

Representation of encapsulation

Now the heating pipes are connected to a natural gas burner that will feed the hot gases into the heating pipes, gradually bringing the shale up to the temperature where the transformed oil can flow to the collection pipes, and any gas produced can also be collected. The booth spokesman told me that they anticipate that the natural gas needed can be collected on site, and that the heating will take a total of 90 days to heat the shale to the point that all the hydrocarbon content has been recovered. That means that the retort section of the mine will be roughly (90 days at 320 ft per day) 5.5 miles long.

After retorting is complete, the heating element will be disconnected and the shale and overlying clay allowed to cool. It will then be covered with the initial overlying rock that will be restored to roughly original contour, and the ground fertilized, seeded, and the ground cover re-established.

While the brochure cites the approbation of the Governor of Utah, the commendation for the project was written at the time that the price of oil was some $120 a barrel, so we may have to wait a short while until it gets back to that level before the project starts to take off.

By December 2008 the project was reported to have invested some $15 million in research and development of the process. They are currently in development of a large-scale pilot demonstration. Information on the web site, however, is a little sparse concerning current progress, through oil was apparently produced in November 2009.

Ecoshale's synthetic product has properties rated by the American Petroleum Institute (API) as 39 condensate oil and between 34 and 35 prompt oil with no fines, or impurities, in the oil.

Based on the test study, Nelson projects full-production at 30,000 barrels a day would cost $20.21 per barrel, not including transportation.

My concerns with this come in the transition from a single retort which can be built to quite high standards, to the operation of even a smaller continuously operating system, where there are likely to be considerably more and larger problems with operation than appear evident at this stage in the process.

* My thanks again to those concerned after my eye problem arose, the surgeon told me yesterday, 3 weeks after it happened, that I now am back to 20/20 vision – albeit using glasses. I remain highly impressed with what modern surgery can achieve.

Utah Temperatures and Colorado UHI

This is now the fourth in an originally unplanned series looking at the differences between GISS and USHCN average temperatures and some trends in the data that are not necessarily obvious when one only looks at global data. Tracking Westward from Colorado, Utah has the next set of temperature data that I will look at, and I will also comment on Anthony Watts note on Colorado UHI , which he posted since my post on that state.

Utah has a different topography in that while in Colorado as we head West the land rises, in Utah that is no longer the case. So for the hypothesis of the week I will assume that while there will be a correlation with elevation, that there will be none with longitude. Let’s see if I’m correct. And while there was little correlation with latitude in Colorado, because of the strong effect of elevation and the wide range it covered, I am going to hypothesize that we will see a significant effect of latitude again, even though the elevation is considerably higher.

As usual I am writing this as I carry out the tabulation, and so I begin, following the initial procedure, by going to the USHCN web site and, yikes, there are 40 weather stations listed for Utah. OK, there will be a slight pause while I enter all these into the data table . . . . 40 stations, mutter, mutter).


Hmm! And we have the same problem of missing data that showed up in Colorado, but with more stations. For some stations there is no data in specific years before 1900. Well I am going to apply the same procedure as I did for Colorado and calculate an assumed temperature for those sites. First is Blanding, for which there is no temperature for 1896. Blanding is, on average at 51.15 deg, 2.8 deg warmer than the rest of the state. If that year the average temp was 47.5 deg, then Blanding should be at 50.3 degrees. If the average temperature for 1896 was, at 47.5 degrees, 0.8 degrees below the average annual temp, and the annual temp for Blanding is 51.15 deg, then the temp in 1896 would be 50.35 deg. Taking the average of these gives 50.33 deg, which is what I insert.

I follow the same procedure to calculate the temperatures for Bluff in 1895, 1896, 1896, and 1898; Farmington in 1895; Morgan Power in 1895; Snake Creek in 1895; (if you get the table these values are marked in red.)

Again checking on Chiefio’s list of the GISS stations. I find only one station out of the stations in Utah, that has survived the cut is the one in Salt Lake City. So I go to get the GISS data for that station.

Adjusting the tabulation to calculate averages for the different numbers of USHCN and GISS stations reveals that the GISS station reads 4 degrees higher than the state average from the USHCN stations.

Looking for the populations of the different cities and towns, Deseret is now apparently preferably called Delta. Modena, UT is also not on the city-data file, and so I got the population of 35 from Century 21. The population for Snake River Powerhouse also requires a little detective work, and two communities have merged to form Midway, and so I will use that number. And for Zion National Park I used Springdale.

And so all the data is in the table and what do we find? First of all, looking at the primary hypothesis of the day:


There is realistically no correlation here, so the first hypothesis is apparently valid.


As with the Colorado data, this again suggests that the trend that we saw with the Kansas data in regard to longitude was really a reflection of the increasing height above sea level. And at the high elevations, looking at latitude, there is a trend:


Not as strong as elevation, given the widely carrying heights of the stations around the state, but it is still there.

In regard to the population distribution, Utah is a state with a large number of small communities , which also have weather stations, so I shrunk the scale of the plot shown to below 10,000 population:


And the log correlation still shows.

In terms of the standard deviation plot that I have calculated for all the states so far:


There has been a slight increase in scatter over the years, (which would validate Anthony Watts observation on station quality) though it is not at a significant level (which I have set at an r-squared of 0.05).
However Utah is a state that has seen a warming over the years:


But the growth of the small communities, relative to the single GISS station in Utah, and the sensitivity of temperature more to the growth of small communities, means that the difference between the GISS and USHCN averages has declined over the years, due to the makeup of the USHCN average.


Which brings me back to Anthony Watts recent post on Colorado data. What he and Stephen Goddard have done is to look at the relative population growths of Boulder, and Ft Collins in Colorado.

Growth in relative populations of Boulder and Ft Collins in Colorado

Now, taking the data that I had discussed last Saturday, it was fairly easy to pull out the data for Ft Collins and Boulder and find the difference, and plot it against time:



I have taken it back a little further than WUMT, since I had the data, but the two curves are otherwise the same. And it does show the effect of the Urban Heat Island, from the point of view that the most significant change between the two towns has been their relative growth.

And so it continues, perhaps next week we will look at Nevada?

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.

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.

P30 Pick Points

Half-a-dozen or so stories of interest:

Moving to undo some of the last actions of the Bush Administration Interior Secretary Salazar has cancelled the lease agreements that had earlier been approved (but then delayed when the government did not cash the checks) in Utah for oil and natural gas. At the same time, in Wyoming some sales are proceeding, while other leases have been withdrawn at the Governor’s request.

Adding additional numbers to the costs for drilling wells in the gas shales, Encore Acquisition have stated that their goal this year, in the Bakken, is to reduce costs from $5 million per well to $4 million. They are also planning refracs of some of the wells. These are done some 9 – 18 months after initial completion, and at a cost of $500,000 each can increase reserves by up to 80,000 boe. Over in the Woodford, Newfield Exploration have lowered (on a lateral foot basis) the cost of drilling wells by some 38% and are hoping to continue this trend by drilling longer wells (out to 5,000 ft from 4,436 ft last year and 2,700 ft in 2007.) Lease rates in the Marcellus were reported to be up to $4,000 an acre and 17.5% royalty, prior to the slackening of demand.

Public relations in the Barnett still appear to be becoming more difficult, as an application for a compressor station has just been withdrawn. Without the dramatic reductions in well costs, and without an increase in gas prices unlikely in the present glut of gas, the current economics of many operations are being further questioned by Arthur Berman.

Royal Dutch Shell said that the cost of producing oil from the oil sands of Alberta rose to $38 a barrel last year. Their production dropped last year to 80,000 bd falling 7,000 bd from 2007, while costs rose by $9 a barrel. More than $60 billion worth of projects have now been delayed, including the expansion of the Shell output to 250,000 bd, which was scheduled for next year. Meanwhile Marathon has written down the $1.4 billion cost of its oil sand operation. Canadian Oil Sands trust, the largest shareholder in Syncrude Canada cut its dividend 80% because of the drop in oil prices. Meanwhile BP and Husky have not yet gone forward with their investment on the Sunrise assets in Alberta. Yet the prospects are such that a firm that specializes in the construction side of the development has just been taken over by Aecon. They, however, do not have to deal with the stronger environmental rules that are now being applied to the tailings ponds.

Merrill Lynch says non-OPEC oil production has peaked, expecting that such production will be in the 49-50 mbd range by next year, while the IEA were predicting last summer that the peak would be next year at around 51 mbd. The Merrill Lynch projection is based on an increase in field decline rates which they set at 4.5% against the IEA figure of 4.2%. The IEA recognizes that the decline rate will rise to 4.7% in the next seven years, but this will slow, not stop increases in production. In contrast ML argue that some of the decline will come from the loss in capital availability and this will carry decline above 5% (and perhaps as high as 6%). Should this happen then within a year oil prices will be back where they were earlier last year. A year ago CERA were saying that a 4.5% rate was typical but they were saying this as rumors and reports of figures already above 5% were starting to circulate.

It looks as though Croatia is going to be the next meal for Gazprom as plans for the Pan European Pipeline start to collapse, and their experts head off to Moscow. With Nabucco also still not having enough gas commitment to be viable and Gazprom is making promises to Turkey about providing natural gas their dominance becomes more evident. With the upcoming North and South Stream deliveries giving Russia the chance to provide for 50% of Western European gas needs (up from the current 25%), the only question becomes where does Gazprom get all the money to fund these developments? It must find $10 billion in debt payments by the end of July, and just lost up to $2 billion in the dispute with Ukraine. As a result they are sweetening their stock offers, even as their production of natural gas falls 14% y-o-y . On the other hand, as deliveries through the Baku-Tblitsi-Ceyhan rise, those through the Baku-Novorossisk pipeline are falling.

Over at the European Tribune Luis has just finished his 3-part review of the plan to Secure the Energy Future of the EU, with earlier posts on the Action Plan and an Introduction. Given the outreaching hand of Gazprom, it is worth getting to know this background, before it gets more serious.

More stories can be found at The Energy Bulletin and Drumbeat at The Oil Drum