Direct Carbon Fuel Cells

Fuel cells, consuming hydrogen and air, are often touted as the ultimate chemical power source. Aside from the difficulty of storing hydrogen, however, they have a basic problem. The reaction H2 + 1/2O2 to H2O causes a reduction in the number of gas molecules. This reduces entropy so, by the second law, entropy must increase elsewhere. As a result, no hydrogen/oxygen fuel cell can convert 100% of the chemical energy of the fuel into electrical energy. Worse, the maximum efficiency declines with increasing temperature. The maximum efficiency of a solid oxide fuel cell (SOFC) burning hydrogen at 1000 C is only 3/4 that of one operating at room temperature. This is a shame, since high temperature operation reduces the need for expensive electrocatalysts. You can get some of the waste heat back with a bottoming cycle, but that adds cost and complexity.

What's needed is a fuel that produces one gas molecule for each oxygen molecule consumed. And there is such a fuel -- carbon. The maximum theoretical efficiency of a fuel cell oxidizing carbon to CO2 is close to 100%, even at elevated temperature. You have to avoid the reaction of C and CO2 to form carbon monoxide, but that's not too hard below 1000 C.

The first such direct carbon fuel cell was built more than a century ago, in 1896, by William Jacques. No one could duplicate his results for four decades (possibly due to role of the titanium impurities in the steel he used for the cathode), but now there is an active research program exploring several different electrolyte chemistries. DOE has been conducting periodic workshops on DCFCs showing the progress in the field.

The results so far are promising. Maximum efficiency in the lab is in the mid-80%s, and practical efficiencies in the range of 70-75% (about twice that of coal-fired steam plants) appear possible. Areal power densities have been achieved in the lab that are good enough for practical application. A DCFC plant, unlike an IGCC or molten carbonate fuel cell plant, does not require bottoming cycles. Nor would it require precious metal electrocatalysts, like low temperature fuel cells. The capital cost per kW of a DCFC may be less than that of a conventional steam plant of the same capacity. As an added bonus, the carbon dioxide from a DCFC comes off in a relatively pure stream, so it will be easier to sequester than the CO2 from a conventional plant, which is mixed with nitrogen, argon, and unconsumed oxygen. NOx and SOx emissions are negligible. Mercury emissions can be largely eliminated.

What's the catch? You'd want a DCFC to burn coal, but coal is loaded with non-combustible stuff. So, it's necessary to clean the ash out of the coal before using it as fuel. This appears to be a solvable problem, with several different approaches (mechanical separation, digestion of silicates with fluorosilic acid, cleaning with organic solvents at elevated temperature) being considered. The cleaner the carbon, the less often the electrolyte will have to be changed. Fortunately, cheap electrolytes like sodium/potassium carbonate appear to work.

I'm wondering if it would be possible to design a system where the electrolyte also acts as a CO2 sink. That is, add a component that irreversibly binds to CO2, and flow the electrolyte through the stack, disposing of the mineralized CO2 by burial. It might also be possible to combine coal cleaning with side processing steps to extract useful elements from the ash.

Chemical Looping Combustion

One of the proposed ways of dealing with global warming is the capture of CO2 at stationary powerplants, with the gas being injected into wells, deep aquifers, or even (after liquifaction) into the deep ocean.

The showstopper here is the cost of separating CO2 from the flue gases. Existing techniques led to estimates of this taking perhaps 1/3 of the energy roduced by the powerplant, raising the cost significantly.

Several groups are now looking at a new technology for this problem, called chemical looping combustion, or CLC. Here, combustion is separated into two phases. In the first, particles containing a transition metal oxide (typically an oxide of Fe, Mn, Cu, Co, or Ni) is reduced by a fuel gas, either to another oxide or to the base metal. In the second phase, the metal is reoxidized with air. The oxide particles are recirculated between the two fluidized bed reactors in which these reactions occur.

Because the air and fuel never mix, no nitrogen is mixed into the combustion products of the fuel. For a hydrocarbon fuel, the exhaust of the combustion reactor is CO2, water, and unburned fuel. This gas is cooled, compressed, and the CO2 liquified; any unburned fuel gas is recirculated to be burned again (or bled off to the other reactor for disposal to the atmosphere).

How efficient is this? Calculations show the system can achieve overall efficiency on natural gas of better than 54%; this is reduced by about 2% if the cost of compressing/liquifying the CO2 is included. The high efficiency is in part due to a reduced irreversibility of combustion, and also due to the lack of a separation stage to remove nitrogen from either air or the flue gases. The cost estimates appear reasonable; with lab measurements of fluid bed erosion rates the cost of separating a ton of CO2 is less than 1 euro.