This article presents an overview of clean coal technologies that promise to produce electricity with fewer emissions. The 600 MW John W. Turk Jr. power plant built by American Electric Power near Fulton is the first “ultra-supercritical” electric-generating clean coal unit in the U.S. Turk’s efficiency is 39 percent to 40 percent, versus about 35 percent for conventional plants. Turk burns roughly 11 percent less coal than a subcritical plant would need to produce the same amount of power. Less coal means fewer emissions, and what’s left – aside from carbon dioxide – is further reduced by the state-of-the-art emission control technologies. Another clean coal technology that has seen wider adoption is the circulating fluidized bed combustion (CFBC) technology. One of CFBS’ greatest advantages is that since the furnaces burn at low temperatures, it can use very low-quality fuel, such as waste piles left over from mining and even chicken litter.




A conveyor belt brings coal into the 600 MW John W. Turk Jr. plant in Arkansas, one of just a few ultra-supercritical power plants in the world. High temperature operation makes it very efficient.

Hard as it may be to believe, some people see pollution as a positive.

In 1913, for instance, John J. O’Connor Jr., an economist with the Mellon Institute of Industrial Research, observed, “Because of the important part that coal has played in the industrial development of Pittsburgh and because the coal has been so poorly burned that it has given off great quantities of black smoke, Pittsburghers have come to regard smoke as a sign of prosperity.”

But attitudes change, and in time smoke and soot were seen as a problem with coal that had to be cleaned up. The coal power industry responded with measures to reduce visible smoke and soot pouring out of industrial chimneys. A lot of other coal users, however, switched to cleaner-burning oil. Coal survived and remained dominant in the power industry, but lost its status as the ubiquitous fuel of American industry.

Today, pollution from coal is again a problem. It's not dark clouds of soot and smoke this time, but rather invisible emissions—toxins like mercury and sulfur dioxide and greenhouse gases such as carbon dioxide. Federal regulations now restrict the amount of toxins that coal plants can emit, and newly built power plants face strict carbon-emission limits. In June, the Environmental Protection Agency proposed carbon emission standards for the power industry that may make existing coal-fired thermal generating stations uneconomical. Before that, many older coal plants were already scheduled for retirement.

And just like a century ago, pollution concerns aren’t the only thing squeezing coal. A bonanza of clean-burning natural gas unlocked by hydraulic fracturing has utilities and merchant generators adding capacity via gas-fired boilers and turbines. Between 2014 and 2017, the power industry intends to add more than 22,500 MW of net gas-fired generating capacity; coal is scheduled to lose more than 21,000 MW of net capacity.

Stricter regulations and fierce competition from gas don’t necessarily spell the end of coal, but any new coal-fired power plants likely will be different from the fleet we have today. If coal power can be saved, it will be through so-called clean coal technologies that promise to produce electricity with fewer emissions.

Whether these technologies can compete in the market with natural gas and fulfill promises of pollution-free power remains to be seen.

In the flatlands of southwest Arkansas between Hope and Texarkana rises one of the new plants that the coal industry is pinning its hopes on. The 600 MW John W. Turk Jr. power plant built by American Electric Power near Fulton is the first “ultra-supercritical” electric-generating clean coal unit in the U.S. There are just a few in the world.

“Conventional, pulverized coal technology dominates the market,” said Howard Herzog, a senior research engineer at the Massachusetts Institute of Technology in Cambridge and head of its Energy Initiative, which focuses on clean coal. “Ultra-supercritical is just the most efficient subset of those plants.”

Conventional power plants start by grinding coal to the consistency of baby power. That coal is then blown into the boiler (or furnace), which is lined with water-filled tubes. The burning coal boils the water to produce steam, which turns turbines, which spin a generator, which produces electric power. One drawback is the energy it takes to boil the feedwater, since while water changes phase its temperature remains constant.

“A conventional sub-critical unit operates at 2,400 psig to 2,600 psig and at around 1,000 ̊F,” said Turk plant manager Tim Gross. “If you could go from water to steam—skipping the boiling period altogether—you’d save lots of energy.”

Plants that do just that operate at temperatures between 1,000 ̊F and 1,050 ̊F and at pressures above 3,500 psig. Under these conditions, water exists in a state that is neither liquid nor gas, but in a “supercritical” state that allows for the flash generation of steam without the energy-absorbing step of boiling. As a thermodynamic concept, supercritical steam generation has been around for many decades, but it wasn’t until the 1990s and early 2000s that carbon steel alloys were available that could handle those supercritical conditions.

But Turk is ultra-supercritical, which means even higher temperatures. “Turk's main steam is at 1,100 ̊F, and the reheat steam is at 1,125 ̊F,” Gross said. “The metallurgy wasn’t there for the long 15-year lifespan of a power plant. The integrity of the metal wouldn’t support those [ultra-supercritical] extremes of operation.”

Modern chromium- and nickel-based “super” steel alloys can withstand prolonged exposure to the brutal conditions without deforming. Turk's steam generator, steam turbine, and piping system all include components made of these metals.

The new alloys require equally new welding techniques, including special “filler” materials and careful, precise preweld heating and post-weld cooling. Gross said the new steels and welding processes were the biggest challenges during plant construction. But the exotic materials have a direct pay-off.

“You increase efficiency by going to higher steam temperatures,” Herzog said. Turk's efficiency is 39 percent to 40 percent, versus about 35 percent for conventional plants. Turk burns roughly 11 percent less coal than a subcritical plant would need to produce the same amount of power.


NIFTY: The 260 MW Polk Power IGCC Station in Florida uses a multistep process to turn coal into a syngas suitable for burning in a highly efficient gas turbine.

Less coal means fewer emissions, and what's left—aside from carbon dioxide—is further reduced by state-of-the-art emissions control technologies. Gross said that Turk is “as tight as or tighter than any other plant in the U.S.”

And if one day the plant needs to capture its carbon dioxide emissions, the design allows for retrofits to accomplish that.

Ultra-supercritical plants are rare—another clean coal technology has seen wider adoption. The technology, circulating fluidized bed combustion, is found at 75 furnaces at 49 plants in the U.S., for a total capacity of 9,500 MW, according to Ventyx, an enterprise software provider for energy, mining, chemical, and other industries. There are hundreds more CFBC plants worldwide.

With CFBC, limestone (or some other sulfur-binding substance) and crushed coal are blown into a furnace by themselves or onto a bed of sand. Jets of hot air support the solids, allowing them to float on the hot air like a fluid, hence the adjective “fluidized.”

The solids rise, ignite, and burn slowly at temperatures just under 1,600 ̊F—low enough to prevent nitrogen oxides from forming. Not all the coal is burned on the first pass. Partly burned coal, ash, and other bed material are carried along with the flue gases until they reach a cyclone, which extracts the larger particles and returns them to the combustion chamber. Coal particles may recirculate dozens of times until they are completely combusted.

“The hot flue gas [travels] from the cyclone to heat transfer units external to the furnace—superheater, reheater, and economizer— which produce steam for power,” said Tim Fout, general engineer in the Systems Analysis Performance Division at the Department of Energy's National Energy Technology Laboratory. “The gases then flow to air preheating systems and additional environmental controls, if needed.”

One of CFB'S greatest advantages is that since the furnaces burn at low temperatures, it can use very low-quality fuel, such as waste piles left over from mining and even chicken litter.

The EPA's Mercury and Air Toxics Standards, which earlier this year withstood a legal challenge, calls for some 40 percent reductions in sulfur dioxide emissions and 90 percent reductions in mercury.

Unfortunately, CFBC offers no special magic when it comes to mercury; conventional mercury emissions technology will be needed to meet the MATS. The news is better for sulfur dioxides, though. Limestone in a CFB is a sorbent for sulfur dioxide. Dolomite is another. Thanks to the long times that the bed particles, including the limestone, remain in the furnace, as much as 95 percent of the sulfur dioxide produced by burning coal in a CFB can be captured.

For some people, that's clean enough. But if coal power is to thrive in a landscape where carbon dioxide is treated as pollution, then other technologies may be in order.

Gasification is one of those technologies. The process itself is centuries old. By the start of the 20th century, gas works were found in just about every major city, converting coal into a number of industrial products—coke, tar, ammonia, to name a few—by heating the mineral in a low-oxygen environment. Instead of burning, oxygen and steam reacted with the carbon to make a gas mixture that could feed other industrial processes or be piped to customers for lighting and heating purposes. This was the town gas of the “gaslight” era.

Natural gas supplanted town gas from coal, though gasification was still used to produce chemical feedstocks. In the 1990s, however, NETL helped fund some demonstration plants to test a technology called integrated gasification combined cycle, or IGCC.

One was the Polk Power IGCC Station in Mulberry, Fla. Tampa Electric started construction in 1994. “First fire” was in July 1996, and commercial operations began on Sept. 30, 1996.

Clean coal technologies promise to generate electricity while producing fewer emissions.



Polk's IGCC design—an “entrained-flow downward fire system”— is both complicated and ingenious. Power generation starts with two concurrent steps. The components of air are separated cryogenically, with oxygen sent in one direction and nitrogen in another. Meanwhile, coal and water are mixed into a slurry. Next, valves carefully meter the oxygen and the slurry as they enter the gasifier, which is about 35 feet tall and 15 feet in diameter. It operates at 375 psig and an average 2,500 ̊F.

“Partial combustion of the slurry and oxygen in the gasifier produces carbon monoxide and hydrogen,” said Mark Hornick, director of engineering and project management at Tampa Electric. “Both are fuel gases, and hydrogen is used as a fuel in the combustion turbine.”

It can’t go there yet: the 2,500 ̊F raw syngas from the gasifier is too hot to travel. It is also anything but pure, containing fly ash, chlorides, water, sulfur, and particulates. If that gunk went through the combustor to the gas turbine, it would “be like sand in an engine,” Hornick said. “A combustion turbine is like a jet engine bolted to the ground. You have to have clean fuel.”

The next step, then, for the syngas is a byzantine, multi-step journey through the plant involving various coolers and mechanical and chemical scrubbers. Along the way, up to 15 percent of the heat energy from the hot syngas gets recovered. By journey's end, the syngas reaches ambient temperature and perfect purity, and it's ready to enter the combustor to drive the gas turbine.

And the nitrogen? This wholly non-combustible gas also plays a vital role in power generation.

“The biggest challenge with coal gasification is that it produces one-third of the BTUs that natural gas does,” said Hornick. “The nitrogen from the air separation unit goes through the combustion turbine. The additional mass flow from the nitrogen produces power. But because it's introduced right at the combustion chamber, it also moderates the peak flame temperature. Nitrogen oxide production is very strongly related to the combustion temperature. By using that nitrogen, we lower that peak flame temperature and therefore have lower emissions of nitrogen oxides.”

After exiting the turbine, the still-hot gases are sent to a heat recovery system to produce steam to power a second turbine. Between the two turbines, 260 MW is generated, and at higher efficiency than a conventional plant. But IGCCs are not as efficient as combined cycle gas turbines running on natural gas. That's because some of the coal's energy is needed to run the gasification process. Depending on the type of coal and the specifics of the plant, efficiencies can run anywhere between 38 and 43 percent.

On paper, it makes for a nifty process. But a look at the sporadically updated DOE Gasification Database indicates that nearly all proposed IGCC plants in the U.S. have been indefinitely delayed or canceled. The two currently active American IGCC projects, Duke Energy's Edwardsport Plant in Indiana and Southern Company's Kemper Plant in Mississippi, have encountered not only repeated delays but also cost overruns.

Southern Company's initial cost estimate for the Kemper plant was $2.97 billion; by 2013, the price had ballooned to $5.04 billion. The plant's start date, originally scheduled for May 2014, has been pushed back to December.

Edwardsport's cost estimate ran from an initial $1.9 billion to the latest figure of $3.5 billion. The plant “fired up” for just six days in June 2013, and then intermittently for the rest of that year. In February 2104, it briefly started up again, though power production was less than 1 percent of capacity. As of May, the plant was not operating.

Kemper and Edwardsport's problems aren’t unusual. A 2013 report from the International Energy Agency's Clean Coal Centre described typical IGCC problems—plant complexity, high expenditures, equipment and materials costs, market risks from natural gas, and up to five years of shake-down and troubleshooting.



“IGCC needs a long wait before it's commercially viable,” said Sowmya Srinivasan, an energy analyst for U.K.-based Global Data.

MIT's Herzog agrees. “Experiences with gasification plants haven’t been great,” he said. “I don’t see people going to gasification unless it's cogeneration with electricity.”

An IGCC plant may produce less carbon dioxide than most other coal-fired power plants, but it could still emit a lot. Ultimately, the solution for coal power plants may be to divert greenhouse gas emissions before they enter the atmosphere and lock them away, which is colloquially known as carbon capture and storage.

In some ways CCS is like natural gas production in reverse. The carbon dioxide stream is compressed and pumped down a pipe to a deep geological stratum under an impervious layer. In theory, the gas would stay locked down there pretty much forever.

“CCS has been tried and tested in a segmented fashion for enhanced oil recovery,” said Srinivasan. “But large-scale implementation of the technology for power production has never been done.” One plant intended to demonstrate the technology, called Future-Gen, has yet to get off the drawing boards.

In the oil and gas industry, “the streams coming out are relatively pure carbon dioxide,” said Richard Esposito, an engineer and geologist with Southern Company who also works closely with the Southeast Regional Carbon Sequestration Partnership program, funded by the U.S. Department of Energy. “In the power industry, you have to pull the carbon dioxide out of the flue gas,” he said. “Only 6 percent to 8 percent of the stream is carbon dioxide.” The rest is made up of the chemicals in the air that the coal was combusted in: mainly nitrogen, but also oxygen and some trace components.

Burying carbon dioxide isn’t so simple, either. According to Esposito, a power plant could emit up to five million tons of carbon dioxide a year for 40 to 50 years. That's up to 250 million tons of the gas from one power plant. You’d need a big carbon sink for that, and sometimes, there just isn’t one.

The Southeast Regional Carbon Sequestration Partnership program is one of seven similar partnerships in the United States and Canada. Its goal is to find and investigate suitable, safe geological formations for long-term carbon dioxide storage. “Saline reservoirs and oil and gas fields are probably the best,” Esposito said. “They provide relatively low-risk storage.”

The ability to monitor stored carbon dioxide is critical. “You monitor the pressure and temperature in the reservoir,” Esposito said. “Get a baseline, inject the carbon dioxide and watch the pressure rise. But you don’t want to see any increase in pressure in the reservoirs above.” Monitoring also includes seismic profiling and the resulting predictive models.

“CCS still has a lot of unproven technology,” Srinivasan said. “Governments are keen on it, but power companies are backing away.”

That statement could apply to clean coal technology in general, and so could this one: “If it were economical and technically feasible,” said Dan Aschenbach, senior vice president of global project and infrastructure finance at Moody's Investment Service, “there would be people lining up to do it.”