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Illinois Coal, part 2

Breaking up is hard to do

Making the FutureGen concept commercially viable will require new and improved technologies. To bring costs down, DOE is funding research to find better, cheaper ways to gasify coal and to separate and sequester the CO2.

a pilot-scale experimental gasification system that can separate hydrogen from carbon dioxide

An SIUC research team led by Wiltowski has been working to find more-efficient separation technologies. With funding from the Illinois Clean Coal Institute (ICCI) and from DOE through the General Electric Energy and Environmental Research Corporation, Wiltowski has been testing two designs on a proof-of-concept scale. One separates out CO2 after gasification; the other integrates gasification and separation in a single chamber. Both designs rely on a sequence of two chemical reactions.

Here's how it works, in a nutshell. In a reaction chamber, syngas and steam are passed through a bed of metal oxide particles. The carbon monoxide in the gas mixture grabs oxygen atoms from these particles, changing into CO2. The gas then flows through a bed of limestone or other calcium-oxide material, where a second reaction takes place: the CO2 combines with the calcium oxide, creating calcium carbonate.

Meanwhile, the hydrogen in the syngas reacts with these solids scarcely at all. With all of the carbon now bound up in solid form, the hydrogen flows as a virtually pure stream out of the reaction chamber.

Once the chamber is emptied of hydrogen, air is released into it to perform a neat recycling trick. Oxygen from the air resupplies the metal particles with oxygen atoms, regenerating them for another separation cycle. Oxygen from the air also converts the calcium carbonate back into calcium oxide and CO2. The CO2 is allowed to flow out of the chamber, and the whole set-up is ready for another batch of syngas.

To keep costs as low as possible, Wiltowski is modifying the metal and calcium oxide particles so that they can be reused for up to 100 separation/regeneration cycles without having to be replaced. In addition, his separation technology works at relatively low temperatures, industrially speaking.

To increase efficiency even more, he has designed a two-chamber system in which each chamber alternates in separating syngas and regenerating the oxide materials. By switching cycles between the two chambers, there's no down time--hydrogen and carbon dioxide are being produced by the system continuously.

Wiltowski's design has been tested on a small scale, and SIUC has filed patent applications on the design and on the chemical modifications to the oxide materials. Larger pilot testing and industrial demonstration of the system would take a lot more time and much more funding, Mead explains. But this concept, which he calls a "radical project," could pay off.

As he points out, General Electric, the industry partner in this research, recently bought the leading coal gasifier design from Texaco. "They're positioning themselves to be a huge part of coal-based energy systems," he says. "The ultimate effect of our research could be significant."

FutureGen, which DOE plans to have up and running in 10 years, will almost certainly use an existing, industry-tested gasifier with a separation unit added to it. Wiltowski's scheme could work in such a scenario. His work to integrate gasification and separation processes in a single reaction chamber also could bear fruit, but in the longer term, since it would take much longer for industry to test and adopt an entirely new gasification design.

At the Illinois Coal Development Park in Carterville, which SIUC co-administers, Wiltowski maintains several small-scale gasifiers, ranging from 6 inches to 6 feet high, in order to test new ideas quickly. "Most of the engineering problems you encounter [in scale-up] are in scaling from small to medium sizes, not medium to industrial sizes," he notes. The experimental set-up "enhances our capability to test new gasification concepts in initial pilot tests and then interest industry partners," Mead says.

Putting carbon back underground

Sequestration, a key part of the FutureGen project, means storing carbon dioxide underground--in oil or gas reservoirs, coal beds, very deep saltwater aquifers, or even under the ocean floor--so that it is stable and can't return to the atmosphere.

That purpose is new, but the practice of pumping carbon dioxide underground has been going on for decades. Energy companies buy CO2 extracted from underground sources (in other words, not byproduct CO2) and pump it into oil reservoirs to recover more oil. "You need some pressure for a fluid to flow," Harpalani explains, "and as you take oil out of the reservoir the pressure drops. Carbon dioxide provides the driving force to push the oil out."

Several sequestration pilot projects are already ongoing or planned in various other countries, according to Science magazine. The largest is by Norwegian oil company Statoil, which recovers natural gas from oil fields beneath the North Sea. Statoil has been separating CO2 from the gas and pumping about 1 million tons of it per year into rock strata more than 1,500 feet below the ocean floor. The process costs about $15 per ton of CO2 but saves the company a $55-per-ton tax that Norway imposes on CO2 emissions to help reduce global warming.

Scientists and the government want to make certain that sequestered CO2 will stay put. If it should filter up into freshwater aquifers, it could acidify groundwater sources used for drinking. And even though CO2 isn't toxic, sudden releases of large amounts of it can be literally suffocating in some conditions. For that reason, sequestration can be done only in geologically stable areas and relatively deep rock strata, reservoirs, or aquifers. Illinois State Geological Survey (ISGS) research indicates that some sites in the state, including deep coal beds in southeastern Illinois, may be suitable.

Without government incentives, U.S. companies need another economic reason to invest in sequestration. Harpalani's research will help geologists determine if carbon dioxide can be sequestered in Illinois coal beds while simultaneously producing methane. His work is being funded by the ICCI, the National Science Foundation, and DOE through the ISGS.

Methane production is a fairly new idea for Illinois--scarcely any methane is produced in the state--and Harpalani's research indicates that it is a promising one.

"Other states have been getting methane out of coal for a long time," he says. "But in Illinois, no systematic study had been done" until a 2001 ISGS study indicating that significant amounts of methane exist in parts of the Illinois Basin (the coalfields that underlie some three-quarters of the state, plus much of southwestern Indiana and part of western Kentucky).

"Some of the sweet spots are in Southern Illinois," says Harpalani, who notes that some Illinois mines even have to stop production periodically to wait for excessive amounts of gas in the mine to vent.

Several years ago, as a faculty member at the University of Arizona, Harpalani worked with the only CO2 sequestration pilot study to date in the United States. The three-year project recovered additional methane from methane-producing coalfields in New Mexico.

"Normally if you're getting methane out of coal beds, you get only about 50 percent of it," Harpalani says. The pressure is too low at that point to recover the remainder.

For the pilot project, the company involved converted some of its extraction wells into injection wells. "Over three years they got the extra methane out, and the CO2 they pumped in, which was billions of cubic feet, never came back out," Harpalani says. "That suggests it's there permanently."

Data from the New Mexico study won't apply to Illinois because the coal type and coal depth are different here. So Harpalani and his graduate students are doing lab experiments with samples of Illinois coal under realistic field conditions of pressure and temperature. Their findings will help the ISGS choose sites and set parameters for field studies.

"My research is characterizing flow behavior and storage properties," says Harpalani. "How easily does carbon dioxide flow into the coal, and how long before flow becomes more difficult? Will it displace methane, and how much methane can we get out? What are the optimum injection pressure and rate of injection? Will the CO2 stay there permanently? And in the end, how much CO2 can be sequestered in a particular area?"

Flowing and sticking

Gas molecules containing carbon atoms will cling to the pores in coal, a phenomenon called adsorption. Methane adsorbs well to coal, which is why you find it in coal beds to begin with. But carbon dioxide molecules adsorbs even better. If CO2 is introduced into a coal sample, 98 percent of its molecules will adhere to the coal's pores.

Harpalani has found that Illinois coal has two to three times as much affinity for carbon dioxide as for methane. That differential is enough to enable injected carbon dioxide to displace methane, he says. CO2 in, methane out. And coal's affinity for carbon dioxide also means that sequestered CO2 should be stable. "The capacity of coal to hold onto CO2 is huge," he says.

Harpalani's lab studies also have found that the permeability of Illinois coal--the ease with which gas will flow through it--is sufficient for methane production and CO2 sequestration. The trick is finding a balance.

"Coal has fractures. If you put in CO2, the coal matrix swells and decreases the size of those fractures," Harpalani explains. Experiments in his lab show that low-pressure injection is the way to go with Illinois coal beds. "You don't want to [close up] the passage, so you keep the pressure low," he says. In addition, he says, "We want to put in less CO2 than what the coal can retain, for a safety margin."

magnification by an electron microscope shows the pores in coal

Using their lab data and ISGS data on gas content in portions of the Illinois Basin, Harpalani's team ran simulations to determine the potential for methane production with and without carbon dioxide injection. Without CO2, they found, about 40 percent of the methane at a given site could be recovered over about an eight-year period. With CO2 injection, 70 percent could be recovered. And the amount of CO2 that could be sequestered would be about three times the amount of methane recovered.

Pilot-scale field experiments will be needed to follow up the laboratory results and investigate safety. "Laboratory research alone won't establish safety," Harpalani says. "It establishes trends--parameters."

More work also still needs to be done on the properties of Illinois coal. Harpalani's research has now expanded to, of all things, having C-T scans done of Illinois coal samples to see the size, number, and spacing of fractures.

"We still don't know what kind of fracture characteristics Illinois coal has," he says. Until now, he has had only electron micrographs to study. These reveal a lot about coal structure, but only for one thin slice of coal at a time. A sequence of C-T scans will give Harpalani a 3-D picture.

A new ICCI grant will allow him to test an even more novel idea, one that--if it works--could handle carbon dioxide emissions from conventional coal-burning plants too. Coal combustion flue gas is only partly CO2; most of it is nitrogen. Separating the CO2 from the nitrogen in order to sequester it would be very energy-intensive.

Harpalani's idea is to use coal beds as a cheaper, natural filter instead. Nitrogen has little affinity for coal. If flue gas were injected, would the CO2 adsorb to the coal while allowing the nitrogen to simply pass through? Harpalani plans to find out.

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