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New Coal Technologies

Museletter #197/September 2008

For coal, the future of both extraction and consumption depends on new technology. If successfully deployed, innovative technologies could enable the use of coal that is unminable by gasifying it underground; reduce coal's carbon emissions; or allow coal to take the place of natural gas or petroleum. Without them, coal simply may not have much of a future. Are these technologies close to development? Are they economical? Will they work?

The technologies discussed in this chapter go by some rather unwieldy names, and so we shall call them by their customary acronyms: Coal-to-Liquids (CTL), Underground Coal Gasification (UCG), Integrated Gasification Combined Cycle (IGCC), and Carbon Capture and Storage (CCS).

Many energy experts believe that these technologies may largely define the world's energy path for the next few decades.

Integrated Gasification Combined Cycle (IGCC)

Among these technologies, gasification of coal is a recurring theme. Once coal is reduced to a gas, the gas can be burned to turn a turbine to generate electricity, or it can be made into a liquid fuel, chemicals, or fertilizers. Carbon can be stripped from the gas and buried, thus reducing the climate impact from burning coal.

In most instances (with the exception of underground gasification, or UCG), gasification is accomplished in—of all things—a gasifier, into which coal, water, and air are fed. Heat and pressure reduce the coal to "synthesis gas" or "syngas"—a mixture of carbon monoxide and hydrogen, along with solid waste byproducts consisting of ash and slag, which can be used in making concrete or roadbeds.

The hot syngas must then be cleansed of contaminants including hydrogen sulfide, ammonia, mercury, and particulates) via heat exchangers, particulate filters, and quench chambers, which also cool the syngas to room temperature. A bed of charcoal captures over 90 percent of the syngas mercury (used charcoal is sent to a hazardous-waste landfill). Finally, sulfur impurities are separated out in acid gas removal units, which produce sulfuric acid or elemental sulfur that can be sold as byproducts.

An IGCC power plant then uses the syngas the way most coal is already used—to make electricity. The plant is called "Integrated" because syngas is produced in the plant itself, in a way that optimizes the product for its intended purpose. The "Combined Cycle" in the name refers to the use of gas in a turbine generator whose waste heat is passed to a steam turbine system. This way the energy of the syngas is used as fully and efficiently as possible.

Efficiency is important not only for its own sake (energy efficiency is almost always a good idea), but also because it is necessary from a cost standpoint: gasifying the coal is expensive, so if IGCC electricity is to be cost-competitive, savings must come from efficiency advantages elsewhere in the process. (It is also possible to capture waste heat from a conventional coal power plant; this is often done simply by piping hot air to commercial and residential buildings. The process, whether it uses coal or some other fuel, is called "cogeneration," or "combined heat and power," or CHP.)

The advantages of IGCC over conventional coal power plants include greater thermal efficiency (IGCC power plants use less coal and produce much lower emissions of carbon dioxide and other pollutants than conventional power plants) plus product flexibility: coal gasification enables the production of not only electricity, but a range of chemicals and by-products for industrial use (including transport fuels—see CTL below). IGCC is sometimes mentioned as a pathway to a hydrogen-centered economy, since syngas is a source of hydrogen. Last but hardly least, carbon capture and storage will be much easier and cheaper in IGCC plants than in regular coal power plants.

As of 2008 there are only two IGCC plants operating in the US, following the closure of one of the three demonstration plants constructed in the 1990s with the help of the Department of Energy Clean Coal Demonstration Project (Wabash River Power Station in West Terre Haute, Indiana; Polk Power Station in Tampa, Florida; and Pinon Pine in Reno, Nevada). The Reno demonstration project failed when researchers found that then-current IGCC technology would not work at more than 300 feet (100 meters) above sea level.

These first-generation IGCC plants generated less air pollution than regular coal power stations, but polluted water to a greater degree.

New-generation IGCC power plants in the US are in the planning and approval process and are being developed by Excelsior Energy, AEP, Duke Energy, and Southern Company. If successfully completed, these are expected to come online between 2012 and 2020.

The principal drawback of IGCC technology is its high cost. The US Department of Energy has estimated a cost of $1491 per kilowatt of installed capacity in 2005 dollars for an IGCC plant, versus $1290 for a conventional pulverized coal station. (Electricity Market Module) However, the example of Excelsior Energy's Mesaba project (an IGCC plant in northern Minnesota slated to begin operation in 2012) suggests that a realistic figure might be in excess of $3,600 per kW. Operating costs are also high, likely to be up to double those of a conventional coal plant even without CCS technology being added on. Further, the Minnestota Department of Commerce has concluded that the pollution profile of the proposed Mesaba plant would not be substantially better than that of a standard coal power plant. (Testimony of Dr. Elion Amit, Minnesota Dept. of Commerce.) An analysis of the proposal for an IGCC plant in Delaware by Delmarva and a state consultant arrived at essentially the same conclusions.

The high-cost hurdle is perhaps reflected in the recent US Government revocation of support for its FutureGen low emissions coal gasification project, developed as a public-private partnership between the US Department of Energy and a non-profit consortium of 12 American and international energy companies. The proposed IGCC plant site at Mattoon, Illinois, had been selected after a hard-fought battle with two sites in Texas and another in Illinois.

Other countries have had somewhat better experiences with the technology. The 250 MW Buggenum plant in the Netherlands currently uses about 30 percent biomass feedstock as a supplement to coal (the Dutch government pays the plant's owner, NUON, an incentive fee to use the biomass). NUON is currently building another 1300 MW IGCC plant that will be commissioned in 2011. (www.nuon.com) Other refinery-based IGCC plants are operating in Puertollano, Spain (operated by Elcogas, startup in 1998) and Vresova in the Czech Republic (operated by Sokolovska Uhelna, startup in 1996); as well as several in Italy and Germany, and one in Portugal. More European IGCC power plants are being planned by Centrica in the UK, and by E.ON and RWE in Germany.

Japan has been operating an IGCC pilot plant since the early 1990s and commissioned a new demonstration plant in Nakaso in 2007.

While the high cost of IGCC is the biggest obstacle to its wider adoption, most energy executives recognize that carbon regulation is coming soon. Adding carbon capture, the cost of electricity from an IGCC plant would increase approximately 30 percent—slightly less of a percentage than for a natural gas plant and less than half the price increase for a pulverized coal power plant. This potential for cheaper carbon capture leads many analysts to view IGCC as an attractive choice to keep coal cost-competitive in a carbon-regulated world.

Nevertheless, there is no getting around the fact that the price of IGCC electricity is higher than electricity from a conventional coal plant, and adding carbon capture will increase that price still further. The future of IGCC hinges on these questions: Which will be a bigger issue, affordability of energy or carbon neutrality? Will carbon capture work as planned? Will it be scaleable? And when will it be ready for wide deployment? If energy affordability turns out to be society's more important concern, or if CCS technology cannot developed successfully and soon, the case for IGCC falls apart.

Coal to Liquids (CTL)

In the last few years, as world oil prices have gyrated upward to the point of seriously imperiling the world economy, farmers, truckers, airlines, and ordinary commuters have all felt the effects. The world's transport infrastructure is 95 percent dependent on liquid fuels; with time and investment, gasoline-powered cars can be replaced with electric vehicles, but for air travel, trucking, and shipping there are currently no large-scale alternatives to petroleum-based fuels.

One possible solution would be to turn coal into a synthetic liquid fuel to replace petroleum. Coal, after all, is still cheap and abundant, and the technology for liquefying it already exists.

The basic process for CTL was developed at the beginning of the 20th century and was used by Germany during World War II, when the Allies cut off access to petroleum imports. At its peak output period in 1944, Germany produced about 125,000 barrels of synthetic fuel daily from 25 CTL plants, meeting 90 percent of the nation's needs. South Africa's apartheid regime revived the process during the 1980s, when trade embargoes made oil scarce for that nation. The South African company Sasol is currently the world's only commercial producer of liquid fuels from coal, making about 150,000 barrels per day.

The fact that CTL has been developed for use only twice, and both times in a situation where access to regular petroleum had been cut off, suggests that the economics are unfavorable. An April 2008 article in Oil and Gas Journal ("GTL, CTL Finding Roles in Global Energy Supply") noted that, based on Sasol's experience, it currently costs about $67 to $82 to make a barrel of CTL fuel, depending on coal and water prices. Given that oil prices are now far above that range, the growth of interest in CTL is predictable. But building coal liquefaction plants is also costly—about $25,000 per barrel of installed production capacity as of 2005 according to the National Academies, though projects currently under construction appear to be aiming to spend up to $120,000 per barrel of capacity. (Producing Liquid Fuels from Coal; but compare this to American Clean Coal Fuels's investment of $3.6 billion in a plant designed produce only 30,000 barrels per day Liquefied-coal industry gains energy)

Often, discussions about the economics of CTL turn on the question, How high does the oil price have to rise in order to CTL to be competitive? Back in 2006, one source calculated that CTL could compete with $40 oil (The World's Biggest Investors Moving into CTL). But since then, as oil prices have surpassed that level, rising infrastructure costs have marked up the estimated price tag for producing CTL fuels. This ratcheting effect will likely continue: as the price of oil goes up, the cost of building and running CTL plants will rise as well. Ongoing hikes in the price of coal must be factored in additionally. Altogether, then, the cost-competitiveness of CTL cannot be defined by a couple of static numbers; the break-even price is a moving target—and usually it moves the wrong way to make this technology attractive.

From an energy standpoint, the process only makes sense if liquid fuels are at a premium for qualities other than their energy content, because coal turned into electricity at high efficiency will power electric vehicles three times as far as liquid fuel made from an equivalent amount of coal will push a combustion-engined vehicle.

Since large or swift electric aircraft are impracticable, the aviation industry (including military aviation) will need liquid fuels even after those fuels' prices have risen far above those of other energy sources on a per-BTU basis, so this is likely a long-term market for CTL fuels.

Two different CTL technologies are being considered. The process used by the Nazis and by Sasol is called indirect CTL; it entails gasifying the coal at high pressure and temperature, then using the Fischer-Tropsch process to synthesize a liquid fuel from the syngas. This first process is sometimes also known as "coal gas-to-liquids" or "coal GTL." Shenhua in China is working on a different process, direct CTL, that bypasses the gasification stage.

One drawback for both processes is the fact that CTL will entail carbon emissions. In the case of indirect CTL, much of the carbon in the coal could be captured at the gasification stage and then sequestered, though this would add significantly to the already high cost of the finished fuel. However, even if this were done, CO2 would still be emitted when the liquid fuel is burned.

A 2007 GAO study on Peak Oil (www.gao.gov) identified significant problems with CTL:

This fuel is commercially produced outside the United States, but none of the production facilities are considered profitable. DOE reported that high capital investments—both in money and time—deter the commercial development of coal GTL in the United States. Specifically, DOE estimates that construction of a coal GTL conversion plant could cost up to $3.5 billion and would require at least 5 to 6 years to construct. Furthermore, potential investors are deterred from this investment because of the risks associated with the lengthy, uncertain, and costly regulatory process required to build such a facility. An expert at DOE also expressed concern that the infrastructure required to produce or transport coal may be insufficient. For example, the rail network for transporting western coal is already operating at full capacity and, owing to safety and environmental concerns there is significant uncertainty about the feasibility of expanding the production capabilities of eastern coal mines.

China stands poised to invest in CTL technology soonest and on the largest scale. (see chapter on Coal in China). In Canada, Alter NRG Corp. has proposed a CTL project that will use the company's coal reserves in the Fox Creek Area of Alberta as a feedstock to produce synthetic diesel fuel and naphtha. The project, with a targeted production capacity of 40,000 barrels per day, will require an investment of approximately C$4.5 billion. Alter NRG Proposing Canada’s First Coal-to-Liquids Project

In the US, the Air Force is offering a pilot site for a CTL project at a base in Montana. Funding will come from the private sector, but the Air Force will guarantee purchase of the fuel at a price that guarantees a profit. The Defense Department is working on plans to eventually fuel much of the Air Force fleet with a mixture of CTL fuel and traditional kerosene, and has already tested several planes on synthetic fuels. Each CTL refinery will cost about as much as an aircraft carrier, and use about as much steel for its construction.

In addition, CONSOL corporation is planning a CTL plant in West Virginia, with startup slated for 2012. The goal is to annually produce 720,000 metric tonnes of methanol that can be used as feedstock for the chemical industry, as well as about 100 million gallons of liquid vehicle fuel (or about 7,000 barrels per day). DKRW, founded by four former employees of Enron, is developing a liquefied coal plant near Medicine Bow, Wyo., with a planned startup date of 2013. And American Clean Coal Fuels is investing $3.6 billion in a plant in Oakland, Ill., with plans to produce 30,000 barrels of fuel per day and a startup in 2012 or 2013.

Currently, while development of CTL enjoys bipartisan political support in the US, European countries are slower to endorse the technology because of its climate implications.

Underground Coal Gasification (UCG)

UCG offers an alternative to conventional coal mining for some resources that are otherwise not commercially viable to extract. The basic process consists of drilling one well into the coal for the injection of air or oxygen, and another to bring the resulting gas to surface, and then initiating underground combustion. Often the natural permeability of the coal is too low to allow the gas to pass through it, and various methods must be used to fracture the coal. A recent variation on the method involves drilling dedicated inseam boreholes and a moveable injection point, using technology adapted from the oil and gas industry.

Once the gas has been withdrawn, it can be purified and used to produce chemicals or liquid motor fuels, or to generate electricity.

In 1868, Sir William Siemens was the first to propose gasifying waste and unminable coal in place, without having first to extract it from mines. An initial experiment along these lines began in Co. Durham (UK) in 1912; however, work was left incomplete at the commencement of World War I and no further UCG efforts were undertaken in Western Europe until after World War II.

Meanwhile, however, the USSR began UCG research in the 1930s, leading to industrial-scale implementation in the 1950s and '60s at several coal sites. Soviet interest in the technology subsequently declined after the discovery of extensive and cheap natural gas resources; today only one site in Uzbekistan is still operational.

Renewed European interest in UCG emerged between the years 1944 and 1959 due to energy shortages. Research focused on gasification of coal in thin seams and at shallow depth. Though an attempt was made to develop a commercial pilot plant in Newman Spinney in the UK in 1958, all European UCG work stopped during the 1960s due to falling energy prices.

The US started an experimental UCG program in 1972, building on Russian experience, and European interest was rekindled in 1989 when the European Working Group on UCG recommended a series of trials to evaluate commercial feasibility. The trials took place in Spain, the UK, and Belgium, with mixed results.

More recently, Australia conducted a trial lasting from 1999 to 2003, and has plans for a commercial startup in the immediate future; and China initiated several UCG trials, of which 16 are ongoing.

Some highly inflated claims have been made regarding the potential of this technology to turn a large proportion of coal resources into reserves. However, the reality is that UCG is only practical if coal seams possess special properties. They must be between 300 and 1900 feet (100 and 600 meters) underground (preferably more than 1000 feet), with a seam thickness of more than 15 feet (5 meters). There must be minimal discontinuities in the seam, and no good water aquifers close by. The coal itself must have ash content less than 60 percent. Altogether, this description applies to only a small portion of the world's coal reserves. The World Energy Council estimates that UCG will increase economically recoverable reserves by only 600 million tons, adding to the current world total of 847,488 million tons of official booked reserves (WEC 2007).

Thus while UCG projects are expanding and the technology is headed for wider deployment, it is unlikely to dramatically increase the amount of coal that can be extracted and used worldwide.

Carbon Capture and Storage (CCS)

The world demands growing quantities of energy, and developing countries especially need cheap energy. At the same time, the world faces a climate Armageddon due in great part to the effects from the burning of our cheapest and most abundant fossil energy resource, coal. To many energy experts there seems to be only one way out of this impasse: capture the carbon from coal and bury it, while continuing to benefit from coal's cheap, abundant energy.

For the coal industry, which is concerned that coal is being cast as the major climate villain, this is a way to make their product look ecologically acceptable. For mainstream environmental organizations, CCS offers a strategy to reduce climate impacts without having to call for painful reductions in coal consumption and thus in all likelihood a reduction in both total energy use and economic growth—a politically untenable position. The Intergovernmental Panel on Climate Change (IPCC) is also supportive, suggesting that CCS could someday provide up to 55 percent of the emissions reduction needed to avoid the worst effects of global warming.

With endorsement from both the coal industry and climate scientists, there is little wonder that CCS is being embraced by policy makers. Wealthier countries (the US, Australia, Europe, Japan) are committed to advancing the technology with public funds, with the hope that as CCS gets cheaper with frequent application, it will become affordable by poorer countries like India and China. In early 2008, the Group of Eight (G-8) energy ministers, meeting in Japan, called for the launch of 20 large-scale CCS demonstration projects globally by 2010.

There are three different types of CCS technologies in development: Post-combustion, pre-combustion, and oxyfuel combustion.

In post-combustion, the CO2 is removed after coal is burned in conventional power plants. The technology is well understood but expensive to deploy.

In pre-combustion, the coal is partially oxidized in a gasifier (see IGCC, above); then the resulting syngas, consisting of carbon monoxide (CO) and hydrogen (H2), is transformed into carbon dioxide (CO2) and H2. The CO2 can be captured relatively easily prior to the combustion of the H2—which can also be used for industrial processes or to fuel transportation.

In Oxy-fuel combustion, coal is burned in oxygen instead of air. To limit flame temperatures to the levels of conventional combustion, cooled flue gas (consisting of CO2 and water vapor) is re-circulated and injected into the combustion chamber. The water vapor is collected via condensation, leaving an almost pure stream of CO2 to be collected, transported, and stored. This method results in the highest percentage of carbon being captured from the fuel; however, the initial step of separating oxygen from air requires considerable energy, and so final electricity costs from such a system are likely to be high. A different version of this method, called chemical looping combustion (CLC), is currently being researched. It uses metal oxide particles as an oxygen carrier; these react with coal to make CO2 and water vapor before being circulated to a second stage where they react with air, producing heat and regenerated metal oxide particles.

After CO2 is captured, it must be transported to suitable storage sites. This will almost certainly be accomplished via pipeline. There are already approximately 4,000 miles (5,800 km) of CO2 pipelines in the United States currently being used to carry carbon dioxide to oilfields where it is injected to force oil toward boreholes to maintain production levels when natural pressure wanes. However, the market for CO2 is limited and is destined to shrink in coming decades as depletion gradually forces the oil industry into retirement. Moreover, in the meantime, the burning of additional oil derived from CO2-enhanced recovery methods will offset much or all of the reduction in CO2 emissions that is achieved at the power plant, so this method of storage will not help much with climate mitigation efforts.

If and when carbon is captured on a large scale, power producers will have to pay for both CO2 transport and storage. Transport will require the construction of thousands of miles of pipelines, and storage will require drilling and other infrastructure investments.

The main forms of permanent storage for captured CO2 currently under discussion include gaseous storage in various deep geological formations (including saline formations and exhausted gas fields), liquid storage in the ocean, and solid storage by reaction of CO2 with metal oxides to produce stable carbonates.

Geological storage, also known as geo-sequestration, involves injecting carbon dioxide directly into oilfields, gasfields, saline formations, unminable coal seams, and saline-filled basalt formations. Several pilot programs are testing the long-term storage of CO2 in non-oil producing geologic formations.

Unminable coal seams can be used to store CO2, which adsorbs to the surface of coal; however, only coal beds with adequate permeability will work for this purpose. There is a potential side benefit: as CO2 is absorbed, coal releases previously absorbed methane, which can be recovered and sold to offset a portion of the cost of the CO2 storage (however, methane burned or released into the atmosphere means added carbon emissions).

Saline formations containing highly mineralized brines have been used for storage of chemical waste in a few cases. These have a large potential storage volume and are commonly found, so the distances over which CO2 would have to be transported could be minimized. However, relatively little is known about these formations on an individual basis, so each would have to be explored and evaluated, adding to costs.

Ocean storage could be accomplished by "dissolution"—injecting CO2 by ship or pipeline to depths of 1000 meters or more, where the CO2 would subsequently dissolve; by "lake" deposition, where CO2 would be deposited directly onto the sea floor at depths greater than 3000 m, where CO2 is denser than water and would form a "lake" that presumably would remain stable for a long time; by conversion of CO2 to bicarbonates (using limestone); or by storing the CO2 in solid clathrates (also known as methane hydrates) already existing on the ocean floor. The environmental impacts of oceanic storage are likely to be negative (the oceans are already suffering from acidification as a result of elevated atmospheric CO2 levels), but not enough experiments have been performed on a large enough scale to indicate just how bad those impacts would be.

Mineral storage, by reacting naturally occurring magnesium and calcium containing minerals with CO2 to form carbonates would produce a stable material. The raw materials are abundant. However, the process is slow under ambient temperatures and pressures; speeding up the process would require large energy inputs.

Will sequestered CO2 leak back into the environment, and at what rate? The IPCC has assessed the risks, and concludes that for well-selected, -designed, and -managed geological storage sites, 99 percent of CO2 would likely be retained for over 1000 years. With ocean storage, CO2 retention would depend on depth, with 30–85 percent retained after 500 years for depths 1000–3000 meters. Mineral storage would not pose any leakage risks. However, liability issues regarding leaked CO2 are already being explored, with Texas leading the way having passed a bill assuming state liability and asserting the doctrine of sovereign immunity (in effect, no carbon leakage lawsuit in Texas could ever be litigated).

The biggest problems with implementing CCS are the added cost for electricity production, the long lead-time for widespread application of the technology, and the sheer scale of the undertaking.

Capturing and storing carbon will require up-front investment in new infrastructure (including pipelines), and it will also increase operating costs at power plants. These higher costs will inevitably be passed along via high electricity rates. The GAO predicts that electricity from pre-combustion clean coal plants will cost up to 78 percent more than electricity from conventional coal plants, not counting carbon pricing. Adding CCS technology to existing plants (post-combustion) would be still more expensive.

This added financial cost conceals an arguably even more important energy cost from CCS: capturing, moving, and storing CO2 will require energy, making the process of producing electricity from coal less energy-efficient, even as the energy content of coal being mined is declining. For example, the IPCC estimates that a power plant using mineral storage would need 60 to 180 percent more energy than a power plant without CCS; thus, if this storage strategy were adopted, consumption of coal would need to more than double (in all likelihood) in order for society to realize an equivalent energy benefit.

According to a December 2006 GAO report, "[the Department of Energy] and industry have not demonstrated the technological feasibility of the long-term storage of carbon dioxide captured by a large-scale, coal-based power plant," and the DOE doesn't expect to have demonstrated the feasibility for at least a decade. While several CCS research sites are likely to be operating within a few years, widespread commercial application of the technology is not likely until 2035 at the earliest (in US Senate testimony, Dr. Mark Myers, head of the US Geological Survey, forecast that widespread use of CCS could be possible "in the 2045 timeframe)". Richard Bell : Wanna Bet the Farm on Carbon Capture and Sequestration? By this time, US and world coal production will be headed downhill (assuming the EWG analysis is correct). Thus society will be burdened simultaneously with four new interlinked costs and risks with regard to coal:

  • The need for substantial investment in new CCS technology,
  • Higher coal prices and shortages due to depletion,
  • Higher electricity generating costs due to the use of IGCC and CCS, and
  • Lower electricity generation efficiencies due to the use of CCS, requiring more coal to produce an equivalent amount of electricity.

On top of these economic and energy concerns there is the practical matter of the sheer scale of the enterprise being proposed. The amount of CO2 that would have to be moved is staggering.

Total world annual carbon dioxide production from the consumption and flaring of fossil fuels amounted to 28.2 billion metric tonnes in 2005. Of this, about 40 percent or 11.4 billion metric tonnes came from the burning of coal. (World Energy Overview: 1995-2005)

Leaving open the question of which carbon storage method is chosen (though assuming that mineral storage is ruled out for reasons of cost), and assuming that the CO2 is liquefied and stored at a temperature of 0º C (32ºF) and a pressure of 200 atmospheres (2940 pounds per square inch), the density of the liquid would be 1050 kilograms per cubic meter. This is slightly higher than the density of water (1000 kg per cubic meter).

Thus the volume of liquid carbon dioxide that would need to be buried every year would be equal to 11,400 billion kg divided by 1050 kg per cubic meter, which is 10.9 billion cubic meters, or 10.9 cubic kilometers. To put this in perspective: World annual coal production is over 5 billion metric tonnes, which equates to only about 4 cubic kilometers. World annual total ore mined in all mining operations is 17 billion tonnes (Mining Explained). World annual total earth moved (for mining and construction, etc.) is estimated at 30-35 billion tonnes (HUMAN IMPACTS ON THE LANDSCAPE). Assuming the average density of the earth moved was 2500 kg per cubic meter, this equates to 30 trillion kg divided by 2500 kg per cubic meter, or 12 cubic kilometers (compared to 10.9 cubic kilometers of CO2 from coal needing to be sequestered). Within the larger CCS discussion, this information is a useful supplement to calculations of dollars per ton or dollars per kilowatt-hour. (Thanks to David Roberts for these calculations: Coal Cant.)

A close look at the daunting economic, technical, and infrastructural challenges to implementing CCS coal leads inevitably to the conclusion that coal can be cheap or "clean" (relatively speaking), but not both. And if coal is about to get much more expensive anyway due to depletion and transport issues, then most nations are likely to deem the added cost required to make coal "clean" to be one burden too many.

Conclusions

Given plenty of cheap available energy, technology can work wonders. It is understandable that our society has fetishized technology, given the spectacular societal changes it has wrought in the past century. In the last twenty years alone, computers, cell phones, and a suite of other digital communications technologies have created industries and fortunes, altered our habits, and morphed our vocabulary. The evolution of computers has been subject to Moore's Law, according to which processor speed, memory capacity, and even the resolution of digital cameras are expected to double every two years. It is tempting to extrapolate these rapid developments in communication technologies to the fields of transportation and energy production. But in these areas technological change is slower and more expensive, and more obviously dependent on continued consumption of non-renewable resources such as oil, natural gas, coal, and iron ore.

Each of the coal technologies surveyed here holds promise for addressing one problem or another. None of them is a magic bullet that can overcome long-term production declines of either coal or other fossil fuels due to the depletion of high-grade resources; nor can any of them, even if successfully deployed, truly make coal environmentally benign. All are expensive in economic terms; only IGCC, with its greater efficiencies, avoids also imposing new energy costs on society.

Time will tell which if any of these technologies is deployed on a large scale. Meanwhile, one truism remains: Investing in new coal technologies means increasing our societal dependence on coal, and therefore exacerbating our collective vulnerability to inevitable coal supply problems.

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