Carbon Sequestration sites and their success

There are a number of questions on the ease with which carbon dioxide can be sequestered underground, and I alluded to some of them in yesterday’s post. That led me to a quick review of the status of the concept, and I thought I would pass on information from some of the papers that I looked at. Some of the different options that can be used for carbon dioxide injection underground are illustrated by a review of the Polish program.

Different options for carbon dioxide disposal underground.

Of these the use for enhancing oil recovery has, perhaps the longest history. Some sense of the work can, perhaps, be seen by looking at CO2 injection at the Cranfield site in Mississippi.


The site is in an oilfield that was discovered in 1943, and abandoned in 1966. Since that time, under the influence of a strong aquifer drive, it has returned to its original reservoir pressure. There is a layer of residual oil, under a gas cap..

Section through the Cranfield site

The site is actually a dome, folding in both directions, so that the residual oil forms a ring. It is a part of the Tuscaloosa Formation, which MIT has calculated should be able to retain some 10,000 million metric tons of CO2. Adjacent continuations in East Texas and the Gulf would add an additional 187,000 million tons of capacity. Validation of the performance of the test site would thus go a long way to answering some of the critics of the technology. Because of the limited volume of oil available, the project is also looking into injecting CO2 into the brine interval during the third phase of the program.

At Cranfield the CO2 has been injected continuously, starting in July 2008, at a rate of 500,000 tons per year. so that, as Professor Economides discussed, the injection pressure remains high. At present the analysis of the samples shows little change in the water chemistry as a result of the injection. Last November it became the fifth site in the world to store more than a million tons of CO2. Monitoring of the pressures as the third stage has begun, does show a pressure increase, although this may be injection rate sensitive.


Monitored pressures for Cranfield 3 (U of Texas)

A second site is being prepared in Alabama at the Citronelle oil field, near Mobile. Both carbon dioxide and water will be injected at that site, with the intent that the CO2 will allow an additional 15 to 20% increase in overall production from the field, before the site is left to sequester the CO2.

In the United States, CO2 injection has already helped recover nearly 1.5 billion barrels of oil from mature oil fields, yet the technology has not been deployed widely. It is estimated that nearly 400 billion barrels of oil still remain trapped in the ground. Funded through the D.O.E.'s Office of Fossil Energy, the primary goal of the Citronelle Plan is to demonstrate that remaining oil can be economically produced using CO2-EOR technology in untested areas of the United States, thereby reducing dependency on oil imports, providing domestic jobs, and preventing the release of CO2 into the atmosphere. . . . . . . When the 5-month injection is completed, incremental oil recovery is anticipated to be 60 percent greater than that of conventional secondary oil recovery by water flood. A recent study by Advanced Resources International of Arlington, Va., estimates that approximately 64 million additional barrels of oil could be recovered from the Citronelle Field by using this tertiary recovery method.

In the last Oil and Gas Journal survey (April 2008) they found 100 miscible ongoing CO2 projects and 5 immiscible ones, with enhanced oil production, at the beginning of 2008, running at 250,000 bd.
Costs for CO2 EOR have been given as $20.86 boe, divided out as follows:
* $3.68/boe for CO2.
* $5.72/boe for power and fuel.
* $3.34/boe for labor and overhead.
* $2.00/boe for equipment rental.
* $1.36/boe for chemicals.
* $3.05/boe for workovers.
* $1.71/boe for miscellaneous.

One of the Centers most active in the monitoring of CO2 plumes as they migrate from the wells out into the formation is at the University of Texas-Austin. Sue Hovorka, for example, monitored a CO2 plume migration after it was injected as part of a test in the Frio Blue sand, although in that test the injection was of the gas.

Several times a day during injection, trucks hauling 20-ton tanks of cold liquified CO2 arrive at the test site, where it is transferred to two 70-ton storage tanks. The CO2, which comes from a natural reservoir near a Mississippi salt dome, is transported most of the way by train.

During injection, the liquid CO2 is pumped through a heat exchanger, which warms it up to 21 degrees C (70 degrees F), converting it to a gas. Then it is pumped through the injection well head and a mile down the well. The CO2 enters the porous sandstone and brine through perforations in the well casing and spreads out in a plume.

She also described, briefly how the process was supposed to work.

Before the first tests, the scientists had predicted that an effect called residual saturation, caused by capillary forces, would cause the brine-filled pores in the stone to trap and hold about 20 percent CO2. The other 80 percent moves on to the next set of pores, and as it moves, it’s continuously diminished. In other words, the plume smears out. Hovorka said the effect is intuitive.

“It’s the same reason you can’t get grease off the stove,” she said. “You can’t wash it loose with water, you have to use soap.”

The 2004 test confirmed this prediction and now initial results from the 2006 test seem to reconfirm it. “It means we got the physics right,” said Hovorka. It also means she and her colleagues can predict the CO2-trapping ability of other sites before injection begins, a powerful and necessary tool for carbon sequestration to become a common practice.

Polish trials have looked at displacing natural gas with CO2 in a program that has been going on for over 12 years Part of the process at the Borzecin site was to inject the gas into the underlying aquifer beneath the natural gas pocket. The CO2 dissolves into the water and so the migration to the gas pocket occurs only very slowly, the gas is at 1,500 psi (just above the critical pressure) when it enters the reservoir). The gas displaces natural gas that had previously been dissolved in the aquifer, yielding about 60% of the injected volume of CO2, as natural gas from the production wells.

One event that this test showed, which perhaps Professor Economides had not considered is that the dissolved CO2 appears to have interacted with the water, over time, to form a carbonic acid, that ate into the carbonate rock, and increased the permeability of the formation, lowering the pressure required for injection, rather than, as he had anticipated, having it rise. The site has now accepted more than 1.4 million scm.

CO2 has also been tested as a means of displacing methane from unmined coal seams. The initial project was completed in 2005

During the project 203 tonnes of CO2 were supplied to the site and stored in tankers. The CO2 is taken from the tankers where it is already stored under pressure and then injected at the injection well (MS-3 well). The injection well was a new well drilled down to a depth of 1120m for the purpose of this pilot project. The target seams were thin coal layers that were bounded (above and below) by highly impermeable shales. The pre-existing coal bed methane (CBM) production well (MS-4) is 150m from the injection well. A tank by the production well stores the saline water which is a by-product. This is emptied and disposed of on a weekly basis. The produced gas (naturally - 97% methane, 2% CO2) is flared. Since December 2004 there has been a gradual rise in CO2 content of the produced gas, the latest figure is 8% which may represent breakthrough of injected CO2 at the production well.

Modeling of the process is not yet fully functional, and in contrast to the more conventional reservoirs for oil and natural gas, the large fracture patterns in coal, known as cleat, play a greater part in the performance of the coal beds and must be included in the analysis.

Nevertheless the tests of the different methods for storage, and use of CO2 injected into the ground have been successful. The most widely recognized, however, is that carried out by Statoil, with Sleipnir the most documented. By 2004 Sleipnir had been injecting CO2, which is produced at an unacceptable 9% in the natural gas extracted at the site, at a level of a million tons a year, since 1996. Because of the length of time that the injection had occurred it has been possible to map the migration of the CO2 over that time. The initial injection is at a depth of 1,000 m below sea level.


Pattern of CO2 injected flows from the injection well at Sleipnir after 3 years

If I read the plots correctly the injection point is aligned with the deepest point in the picture and the flow path is about 2 miles long on its greatest extent.

The site continues to be monitored, as injection continues, with migration being downward under the containment of the cap rock.

Seismic surveys of CO2 migration at Sleipnir

It is expected that the CO2 will slowly dissolve into the brine (over hundreds of years). The scale of the above is exaggerated vertically since the height of the plume is around 600 ft.

The success of the program has led to the Snohvit Project which again takes the CO2 from a natural gas supply (in this case at 5% CO2) and stores it underground.

The success of these projects, and the changes in conditions from the simple models initially assumed to the more complex considerations that have had to be undertaken as the storage has continued to accept high levels of CO2 in some cases, and only high injection rates in others, nevertheless combine to suggest that Professor Economides models may be overly conservative.

The Professors Economides and carbon sequestration

One of the problems in ensuring that there is sufficient energy available at some future date is that the supply, in virtually all cases, requires that a significant infrastructure is in place to deliver it. Thus, for those of us who have become used to having a light come on, when a switch is flicked, there needs to be some form of generator hidden at the other end of the wires to which the switch is connected. Stepping further back beyond the generator there must be some energy source, whether it be the sun’s rays; the wind blowing across the moors; or the fuel that fired the power station from which the electricity flowed.

Putting that infrastructure in place takes time. And the existing plant, over time, and even with good maintenance, will slowly decay and require replacement. At the same time just being able to generate power doesn’t necessarily allow me to flick the switch and see the computer screen as I type this. There has to be system, typically an electric grid of power cables, which carries the power to where it is needed. As Boone Pickens found out, putting wind turbines into West Texas was an exercise in futility, until such time as there is a network that will deliver the power to the folk that need it in East Texas, more than a few miles, and a few years of construction and permitting, away. As “just in time” manufacturing has grown as a cost control practice, so ordering large pieces of equipment carries with it longer delivery times, since the minerals must be mined, processed, produced, transported, made into parts and assembled, before the final product can be brought to a site and installed. The larger the facility, in many cases, the longer that process takes, and the more paperwork is likely going to be involved in the getting the installation into the ground. It is a lengthy process even when the need is generally recognized. If there is political opposition - regardless of merit – then you just added years to the delivery, construction and operational start times.

Power station construction is one of those things where the process is more likely to be beset with delays, than with dramatically earlier than scheduled delivery. And if the fuel comes out of the ground, whether coal, oil, natural gas or uranium, then delays can more critically compound, particularly at politically critical points, such as around election times.

I was thinking of this today, as I came across Chris Booker’s comments on the Conservative leadership views on electricity generation, at a time when the UK must, before long, have a General Election. Given that Britain must replace 14 of its current generating plants, under EU mandate, taking with them 40% of the current generating capacity of the country, he draws attention to the Conservative view that coal-fired power can only be allowed if there is full carbon capture and storage.

What makes it particularly interesting and relevant is that, after some 100 coal-fired power stations in the United States have been cancelled or postponed, we have folk such as the head of one of the largest generating companies in the Midwest virtually echoing the Conservative leader. And it is much the same position with the Department of Energy and the current Administration. Carbon sequestration is the also a current area for lots of research and planned development.

In October 2009, as part of President Obama’s stimulus package, the US invested $1.4 billion in 12 CCS demonstration projects. In December 2009, the US announced a further $979 million is to be invested in 3 further such projects. The same month the EU pledged over $1.4 billion towards building 12 CCS similar projects by 2015. The UK is also proposing to fund and bring online 4 CCS demonstration projects by 2020.

Now there has been the odd small problem with leakage at one of the few places that are actually carrying this out at present. Yet the current site at Sleipnir, has been injecting CO2 for years, though the gas it re-injects was initially a part of the natural gas mix that wells at the site produce.

Using a simple metallic tube measuring 50 centimetres (20 inches) in diameter, the platform operator, Norwegian oil and gas group StatoilHydro, has injected some 10 million tonnes of CO2 into a deep saline aquifer one kilometre (0.6 miles) under the sea.

"We bury every year the same amount of CO2 as emitted by 300,000 to 400,000 cars," said Helge Smaamo, the manager of the Sleipner rig, a structure so large that the 240 employees ride three-wheeled scooters to get around.

But that is not the concern that has been highlighted, nor is it the volumes of gas generated to run the compressors that drive the gas to liquid and up to the pressure at which it is injected. Rather it is the results of the pressure itself.

Last October Michael Economides and his wife presented a paper in Houston, that he has since abbreviated on his web site, and which Chris Booker has made reference to.

Simplistically he examines the relative volume, within an existing rock formation, that carbon dioxide can occupy, if it is injected into that rock and left there in storage. The number that he comes up with is 1% of the pore volume.

The problem that they identify (with computer models) is that as the carbon dioxide (which has been compressed under pressure so that it is delivered and stored as a liquid) is injected at a relatively steady rate, it flows into a formation where there is already some pre-existing fluid. Thus as the new fluid is pushed into the rock, in the reverse of the process that happens when oil flows out of the rock into the well, the driving pressure must increase to move the CO2 away from the well. This injection pressure must continue to build, over time, to keep the fluids moving, but it can only displace some of the existing fluid, and some it has to compress. Achieving the compression by increasing pressure has a couple of serious snags. The first is that fluid at low pressures is virtually incompressible, and the second is that to achieve it the pressures must therefore be increased significantly to, and above, the levels that the rock can easily stand.

What do I mean by that, well if you remember back to one of the tech talks, I mentioned that we can crack a rock by raising the pressure in the well above the strength of the surrounding rock. We do that to create paths that the oil can flow out through, into the well, driven by the pressure differential between the fluid in the rock, and the pressure in the well, that we lower after fracturing the well. We lower the pressures because we don’t want the crack to continue growing. If it did then it could easily grow through the reservoir rock, and then up through the cap rock that is holding the oil (or gas) confined within the reservoir rock. Once we crack through that cap rock, then the reservoir isn’t a reservoir any longer, since it has a leak path, through which the CO2 can escape.

As a result we can only inject CO2 into that reservoir until the pressure in the well starts to approach the fracture pressure of the rock. But we don’t start at zero pressure, we have to start at the existing pressure of the fluid in the rock, and it is only in the difference between these two pressures that we can drive the CO2 into the rock. And that range, the Economides have calculated, will only allow a 1% change in fluid volume before the pressure gets too excessive.

Now I have to add two caveats to this argument – the first is that it does not hold when the liquid is injected into a reservoir where the fluid is still oil, since CO2 will merge into the oil, lowering its viscocity, and this has been used previously to enhance oil recovery (EOR) and get perhaps another 10% production out of formations where it is feasible. And even when the oil can’t be recovered, it can accommodate larger levels of injection that that forecast.

The other point is that there is nothing that stops the site from extracting the contained fluid (generally water, though often brackish) to allow the CO2 to displace it, at a lower pressure (which could be considered as a reverse water flood). It may be a bit more expensive, but at least it would reduce the volume of space that would be needed from the huge areas that the Professors Economides currently anticipate would make carbon injection infeasible.

I suppose someone will realize that, after a bit, but in the meantime while the debate continues, and the example sites fail to yield reassuring results, the power stations are not being built, and the future needs of both the UK and the USA hang further in the balance.

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.

Temperatures in the Mountains - the Colorado data

Today I am going to look at the temperature data for Colorado, since last week we looked at the data from Kansas, and the correlation with longitude was growing, but could not just be explained by a change in height. The procedure starts off the same as that for the initial post, in that I am going to take data from the US Historical Climatology Network compare it with the GISS data for Colorado, (which I reference later) and then see if I can draw some conclusions from the data. I want to have a hypothesis to test against the data, and since the land rises in the West, and it gets cooler, the hypothesis this week is that there is a relationship that we can derive between average temperature and height above sea level. There is a subsidiary corollary to this, which is that this will explain the changes in temperature with longitude.

So to begin we find the data for the weather stations for Colorado. There are 24 of these, and so I begin by generating the table that I described in the first post of this series. This lists the site with its geographic location and leaves a space for the population. Under that I put the average annual temperature data for that site from 1895 to 2008. (and since I am writing this as I do it, there will now be a pause . . . .)

And there is a slight problem – in 1896 there is no temperature data for Telluride. Hmm! How to handle this? Well looking at the averages that for 1896 is on average 0.6 deg above that for the stations in the rest of the state. Telluride, on average is 9.54 degrees below the average for the state. So if I take the average for the state for 1896 and subtract 9.54 I get 37.1 degrees. If I take the average for Telluride and add 0.6 degrees I get 37.17 degrees. So it seems fair to insert a temperature of 37.135 degrees for Telluride for 1896 – which I did to complete the initial table.

Now to get the data from GISS, and here there is another surprise – I have checked the list that Chiefio gives 3 times and still can only find Grand Junction as a site in Colorado, even though the GISS site lists some 33 sites with data, of which a fair number also appear on the USHCN list. So I will just use this as the sole GISS site for Colorado. Getting the data from GISS and correcting it for scale (from Centigrade to Fahrenheit), then I run the table, and the next surprise of the evening. The GISS site is, on average over the 114 year period 6.65 degrees warmer than the state average. Plotting the average difference over that time interval


Now there is only one GISS station, but this is rather a large amount warmer for the state according to GISS than the state average would suggest. It has, however, been declining slightly, but steadily over the years. As for the state temperature as a whole, that has been increasing, though the pattern is a bit strange.


So now I go to enter the population, and not being a Colorado native I had been wondering where the Denver data was, and apparently it is hiding behind the Cheesman file. (That being a suburb of Denver apparently with a Park). So do I use the suburb population 8,201 or that of Denver itself – 598,707? Given that the area has a high population density, I am going to use the Denver number.

And then there is the problem of finding Hermit, CO – fortunately the weather station information includes the co-ordinates (since I didn’t have a great deal of success with a Google search) and this allows me to use Google Earth to go to the co-ordinates and find that it is at Hermit Lakes, which is in Creede, population 377. Putting all those together, there really are a lot of small communities in Colorado, so I’ll use a normal (rather than a log) plot of the information.


And with this having a lot of data at the smaller end of the scale (and recognizing that we have yet to go to a state with large populations) there is some correlation to a log relationship. And changes in small populations could have a greater significant effect. (Which is what I had said earlier, and which is now being also being written about by Professor Roy Spencer.

Interesting where there weren’t any large mountains (i.e. Missouri) there was a good correlation with latitude, but in Colorado that is not as evident:


And instead, where further East there was no correlation with longitude, in Colorado it is very pronounced:


So the question is, can this all be explained by the changes due to height above sea level, or elevation?


I don’t think that there can be any doubt of the correlation. So now we have two – where there is not a large change in elevation (Missouri) there is a strong correlation with latitude, but when the stations are at a higher altitude, then there is a strong correlation with elevation. And the starting hypothesis, this time, is seen to be correct.

One wonders how it would be if we normalized the data to account for both elevation and latitude. Given the lateness of the hour I won’t do that tonight, but given that GISS gives the locations for the centers of the states, maybe I will adjust the data to that location based on the linear relationships and see what that produces, and how much variation it takes out. But I’ll do that later in the week (we have been beset by server problems today, and I would like to get this out before I get hit with another).

As demand rises, can oil supply keep up?

Liquid hydrocarbons provide the fuel for the vast majority of the vehicles that carry us to and fro over the course of a day. The latest edition on the TWIP comments, in looking at the future of vehicles through the eyes of the Annual Energy Outlook, released this month, that:

the market share of alternative vehicles will increase to 49 percent of new vehicle sales by 2035 due to the combination of more stringent corporate average fuel economy standards, the renewable fuel standard and higher fuel prices (See Figure 1). However, with continuing improvements in the fuel economy over time, conventional gasoline-powered vehicles are projected to retain the majority of sales.

Figure 1 looks like this:

EIA projects for vehicle fleet changes in future years (EIA)

But the projection carries with it some inherent assumptions about the continued availability of those fuels, both here and in the other countries around the world. And in some of those growth is expected to be such that, by 2035, countries such as China will have more vehicles on the road that the USA. Last year the Chinese car industry overtook that of the United States, and just recently Saudi Arabia began selling more oil to China than it does to the United States. Sales to the US averaged about 2,000 bd below 1 mbd last year, while those to China just crossed that significant marker. Similarly Russia, the country that now leads the world in crude production, increased its sales to China so that it now supplies around 7.8% of total Chinese crude imports. (Through last October this amounted to around 100 million barrels of oil for the year).

There is a new pipeline that is being constructed to help those exports, with the goal of increasing sales from their current 6% of Russian exports to between 20 and 25%.

After many years of discussions, the construction of the pipeline started in April 2006. The ESPO was supposed to connect Tayshet (in the Irkutsk oblast) with the Kozmino port on the Pacific Ocean. The new oil pipeline is intended to stimulate the development of a new oil production centre in Eastern Siberia, which is particularly important in view of the expected decline in production from the Western Siberian fields and in the Urals-Volga region. The ESPO's total length will be 4857 km and it will have an annual capacity of 80 million tons. The first section between Tayshet and Skovorodino (Amur oblast) has a capacity of 30 million tons.

Initially, oil will be transported from Skovorodino to Kozmino by rail. The second phase of the project (to 2014–2015) will see the construction of the pipeline section to the terminal in Kozmino (50 million tons) and the expansion of the first section’s capacity to 80 million tons. Moreover, a branch connecting the ESPO with China's Daqing has been under construction since April 2009; it is expected to start transporting 15 million tons a year in 2011 (with an option of extending the capacity to 30 million tons).

Russia’s Energy Strategy through 2030 does not see a shift from fossil fuels to alternative energy until after 2022.

Now these projections of growth, and the fuel supplies required to meet them are predicated on there being enough, relatively economically viable, supplies of crude to meet that demand. There are the occasional troubling signs that this might not be the case.

JoulesBurn has one of his usual, incisive and informative posts on The Oil Drum today discussing his latest analysis of information from the satellite view of the recent Saudi addition at Haradh. This, the third addition to the program of extraction from the Southern tip of the large Ghawar field, is being produced, and bragged about by the Saudi, at a level of 300,000 bd. But as Joules has spotted, and pointed out, there are a lot more production wells that have been drilled into that field in recent years than Saudi Aramco have been admitting to, and their placement suggests that they are being needed to maintain production from wells that might not have been able to sustain the original targets.

Now that could be a problem, and Ace has commented that this could signify that Aramco might not be able to sustain more than 8.35 mbd this year, and expects a decline next year.

Into this picture now increasingly steps the slowly growing global economy. And as it seasonally happens US demand for gasoline is beginning the steady increase that normally occurs between now and mid-summer, with the concomitant increases in price.

US Demand curve from TWIP (March 3, 2010 )

Turning to the vehicle miles travelled data for last November the numbers were positive across the entire country, with an average increase of 1.4% over the previous November. (This is in contrast with the October figures where the overall had shown a drop of 0.7%, the first drop in 5 months). The rolling 12-month total, because of that, reached a plateau, though I expect that it will return to upward progress next month, perhaps beginning to exceed the driving done in 2004.

Rolling 12-month total of vehicle miles driven in the USA through November 2009. (FHWA )

The endurance of University data records - be discouraged

Much has been made of the destruction or loss of data from the files of the Climate Research Unit (CRU) of the University of East Anglia. Dr Phil Jones, The Director until this all became public, did not do himself much benefit with his remarks before the Commons Select Committee in the UK, that is looking into the Climategate matter. Destroying the raw data, or not making it available, so that all that one can use is the modified and gridded data, means that there are no checks that the adjusted data has been properly derived. But the destruction of research data is not only encouraged in some institutions, it is mandated by regulation. It is, however, a point that a lot of folk may have missed. So I thought I would mention this since I suspect that it affects much more than just the data at my own University.

I retired from the University last Friday, and have spent today throwing away about 80% of the material in one of the three offices that, transiently, it has been stored in. (It happened that in recent months the three folk who had worked with me on many of my research programs also retired, and so their records were boxed and collectively stored with mine until they could be sorted). We worked through file after file, with data going back to the first experiments that I had run some 40-years ago when I came to this place as a very junior Assistant Professor. That data was still on graph paper, with hand-plotted curves. It went into the trash barrels. As did many of the journals that I had paid large chunks of money for over the years, and almost all of the correspondence dealing with the millions of dollars of contracts that I have managed during my term here.


I am working with the University Archivists, and they and a couple of students helped me work through many of the files, and did most of the actual disposal. We have done some pretty interesting things over the years (I was incredibly fortunate to be involved in many of the activities that changed my discipline from an academic curiosity into something that impacts, in one way or another, many peoples lives every day). But not much of that is being kept.

A treatment for skin cancer that discriminates between healthy and diseased tissue – save the patent – the rest into the trash. Cleaning the Statue of Freedom atop the Capitol building in Washington, save the proposal, the final report and one paper. The rest – into the trash.

You might think that I am being deliberately destructive, but this is what the regulations require. For those as incredulous as I was, until last week, here is the information:



Notice that the applicable dates are for three years back. In other words three years after I get a contract or grant I am supposed to archive the proposal, report and the sample of data (the paper that I mentioned earlier), and then four years later I am supposed to destroy all the research data. Hope the sanctions are not too onerous, since, until today I had kept everything. Now much of it lies in grey trash bags stacked down a hallway.

I actually got a bit annoyed about this last week, and it was then that this all came to my attention. As it happened when my pension was calculated (ours is based on length of service) the record did not show that I worked for part of 1997. Now I knew that I had, but if I (or actually the Center staff) had followed University rules, rather than what I had wanted, then there would have been no other record against which to compare the facts relative to the records that are in the Central Personnel Office. Given, however, that we had kept the records, the copy was found, sent up and the matter was straightened out within about an hour. (However, since a large number of boxes have recently left for the incinerator I don’t believe that my replacement as Director has continued my cautionary practice).

In the past the Center has been audited, and had, on another occasion to defend a set of experiments that were investigated by a government agency. In the first case I found a record from a period that I suppose I should have had destroyed that showed that the audit inquiry was misinformed, and in the other I was able to supply all the documentation required (foregoing that it took several full weeks of several individuals time to copy – this being before much of our information was stored digitally). As a result, and based on that information, the inquiry was discontinued.

The amount of space that is needed to store digital records is trivial against the bookcases of material that have just gone into the trash. But storing the material only in digital form has some risks. I have just finished a comprehensive review of one of our programs, requiring data that was stored digitally back in about 1987. I cannot open the files for any of the information. I can’t find readers that will read some of the disc storage that I recorded it on. (And where I made copies of the files and transferred them, the current versions of the software won’t read files from that far back). It wasn’t in this case too much of a problem since, in violation of policy, I had the paper copies and just scanned them in to get what I needed (and created a digital copy), but those paper copies will be in those grey bags next week.

There are problems with data storage. If I had kept the written records, then when I vacate the room, then the books will go onto a bookcase in the hall for the students who want them to help themselves (my colleagues already have), a small amount of material will go home, some will go to the Archives, but the majority will burn, or be landfilled. Because the person who follows me into that space has their own research and documentation, which they will put into the bookcases that I am vacating. There is not enough room to store the material. We used to use microfiche to do that – I haven’t seen anyone use one of those readers in years, I stopped when ours broke.

The Federal Government and the National Labs are no different. I was on a National Panel which needed some information on a project from one of the National Labs and we wrote for it. It was about 15-years after the experiments. They no longer held the data, and there was no-one there that we could talk to about the work. (Which was one of those supposedly crazy ideas that folk go out and try, and bless my socks, this one worked, and might have been helpful if we could have found out more).

So while I continue to think that it is madness to be spending the amount that we are on research into the possible problems of the greenhouse gases without a more robust set of raw data that everyone agrees has integrity and that has been compiled in a way that is logical and transparent, I have to point out that the protocols governing records at Universities are not supportive of my position. Not that this makes me feel any better, rather the reverse. And there are many, many research programs that do not have that level of visibility.

I used to joke in my class that disasters happen in about 20-year cycles, because nobody read anything that was older than that, and thus missed some less-than obvious design features, which became forgotten until their lack led to disaster. But I had not realized that the data was all gone. And in the digital age, if it isn't on the web who knows where to look for it.

Troubling thoughts!

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.